Surface Operations in Petroleum Production II

Developments in Petroleum Science, 19B

surface operations in petroleum production, I I

DEVELOPMENTS IN PETROLEUM SCIENCE Advisory Editor: G.V. Chilingarian

Volumes 1 , 3 , 4 , 7 and 13 are out of print.

2. W.H.FERTL

5.

6. D.W. PEACEMAN

8. L.P.DAKE

9. K.MAGARA

ABNORMAL FORMATION PRESSURES

OIL SHALE

FUNDAMENTALS OF NUMERICAL RESERVOIR SIMULATION

FUNDAMENTALS OF RESERVOIR ENGINEERING

COMPACTION AND FLUID MIGRATION

DECONVOLUTION OF GEOPHYSICAL TIME SERIES IN T H E EXPLORATION FOR OIL AND NATURAL GAS

11. DRILLING AND DRILLING FLUIDS

12. T.D. VAN GOLF-RACHT FUNDAMENTALS OF FRACTURED RESERVOIR ENGINEERING

14. G. MOZES (Editor) PARAFFIN PRODUCTS

T.F. YEN and G.V. CHILINGARIAN (Editors)

10. M.T. SILVIA and E.A. ROBINSON

G.V. CHILINGARIAN and P. VORABUTR

15A O.SERRA FUNDAMENTALS OF WELL-LOG INTERPRETATION 1. THE ACQUISITION OF LOGGING DATA

15B O.SERRA FUNDAMENTALS OF WELL-LOG INTERPRETATION 2. T H E INTERPRETATION OF LOGGING DATA

16. R.E. CHAPMAN PETROLEUMGEOLOGY

17A E.C. DONALDSON G.V. CHILINGARIAN and T.F. YEN (Editors) ENHANCED OIL RECOVEF~Y, I FUNDAMENTALS AND ANALYSES

18A A.P. SZILAS PRODUCTION AND TRANSPORT OF OIL AND GAS A. FLOW MECHANICS AND PRODUCTION second completely revised edition

18B A.P. SZILAS PRODUCTION AND TRANSPORT OF OIL AND GAS €3. GATHERING AND TRANSPORTATION iecond completely revised edition

19A

19B

20. A.J. DIKKERS

21. W.F. RAMIREZ

22.

23. J. HAGOORT

24. W. LITTMANN

25.

26. D.MADER

G.V. CHILINGARIAN J.O. ROBERTSON Jr. and S. KUMAR

G.V. CHILINGARIAN J.O. ROBERTSON Jr . and S. KUMAR SURFACE OPERATIONS IN PBTROLEUM PRODUCTION, I

SURFACE OPERATIONS IN P~TROLEUM PRODUCTION, 11

GEOLOGY IN PETROLEUM PRODUCTION

APPLICATION OF OPTIMAL CONTROL THEORY TO ENHANCED OIL RECOVERY

MICROBIAL ENHANCED d I L RECOVERY

FUNDAMENTALS OF GAS RESERVOIR ENGINEERING

POLYMER FLOODING N.K. BAIBAKOV and A.R. GARUSHEV

THERMAL METHODS OF PETROLEUM PRODUCTION

HYDRAULIC PROPPANT FRACTURING AND GRAVEL PACKING

E.C. DONALDSON G.V. CHILINGARIAN and T.F. YEN (Editors)

Developments in Petroleum Science, 19B

surface operations in petroleum production, II

G.V. CHILINGARIAN Petroleum Engineering Department, University of Southern California, University Park, Los Angeles, CA 90089-121 1, U.S.A.

J.O. ROBERTSON, Jr. Earth Engineering, Inc., 4244 Live Oak St., Cudahy, CA 90201, U.S.A.

S. KUMAR Petroleum Engineering Department, University of Southern California, Los Angeles, CA 90089-121 1, U.S.A.

Associate Editors:

T.A. BERTNESS and C.M. BEESON Petroleum Engineering Department, University of Southern California, Los Angeles, CA 90089-1211, U.S.A.

with contributions from:

M.Y. Al-Bassam A. Ali Azun C.M. Beeson T.A. Bertness J.D. Brady D.D. Coleman E.C. Donaldson J.P. Fanaritis

ELSEVIER - Amsterdam

W.F. Fertl W.B. Hatcher L.J. Kemp K.M. Sasseen T.R. Sifferman J.R. Solum C. Thibault C.C. Wright

Oxford - New York - Tokyo 1989

ELSEVIER SCIENCE PUBLISHERS B.V. Sara Burgerhartstraat 25 P.O. Box 211,1000 AE Amsterdam, The Netherlands

Distributors for the United States and Canada:

ELSEVIER SCIENCE PUBLISHING COMPANY INC. 655, Avenue of the Americas New York, NY 10010, U.S.A.

ISBN 0-444-42677-9 (Vol. 19B) ISBN 0-444-41625-0 (Series)

0 Elsevier Science Publishers B.V., 1989

All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior written permission of the publisher, Elsevier Science Publishers B.V./ Physical Sciences & Engineering Division, P.O. Box 330,1000 AH Amsterdam, The Netherlands.

Special regulations for readers in the U.S.A. - This publication has been registered with the CO- pyright Clearance Center Inc. (CCC), Salem, Massachusetts. Information can be obtained from the CCC about conditions under which photocopies of parts of this publication may be made in the USA. All other copyright questions, including photocopying outside of the USA, should be referred to the publisher.

No responsibility is assumed by the Publisher for any injury and/or damage to persons or property as a matter of products liability, negligence or otherwise, or from any use or operation of any methods, products, instructions or ideas contained in the material herein.

Printed in The Netherlands

Dedicated to

Cornelius J. Pings

J. Robert Fluor 11

C. M. Browning

Provost, University of Southern California

Vice President, Fluor Corporation

President, Atlas Wireline Services Western A tlas International

and

Our parents Klavdia and Varos Chilingarian John and Roberta Robertson Kundan La1 and Indra Rani Goyal

and

to Dan K. Adamson for his outstanding contributions to the Society of Petroleum Engineers

VI

CONTRIBUTORS

M.Y. AL-BASSAM A. ALI AZUN

C.M. BEESON

T.A. BERTNESS

J.D. BRADY

G.V. CHILINGARIAN

D.D. COLEMAN

E.C. DONALDSON

J.P. FANARITIS

W.B. HATCHER L.J. KEMP S. KUMAR

J.O. ROBERTSON, JR.

K.M. SASSEEN

T.R. SIFFERMAN

J.R. SOLUM

C. THIBAULT

C.C. WRIGHT

Getty Oil Co., P.O. Box 1, Mina Saud, State of Kuwait Mobil Exploration Mediterranean, Inc., Cinnah Cad. No. 1, Cankaya, Ankara, Turkey Petroleum Engineering Department, University of Southern California, Los Angeles, CA 90089-1211, U.S.A. Petroleum Engineering Department, University of Southern California, Los Angeles, CA 90089-1211, U.S.A. (also: Consultant, 14827 La Cuarte Street, Whit- tier, CA 90605, U.S.A.) Andersen 2000 Inc., 306 Dividend Drive, Peachtree City, GA 30269, U.S.A. Petroleum Engineering Department, University of Southern California, Los Angeles, CA 90089-1211, U.S.A. Illinois State Geological Survey, 615 E. Peabody Drive, Champaign, IL 61820, U.S.A. Petroleum & Geology Engineering, University of Oklahoma, Norman, OK 73019, U.S.A. Struthers Wells Corporation, P.O. Box 8, Warren, PA 16365, U.S.A. Texaco U.S.A., P.O. Bin H, Taft, CA 93268, U.S.A. Southern California Gas Co., Los Angeles, California Petroleum Engineering Department, University of Southern California, Los Angeles, CA 90089-1211, U.S.A. Earth Engineering, Inc., 4244 Live Oak Street, Cudahy, CA 90201, U.S.A. HTI-Superior, Inc., P.O. Box 3908, Santa Fe Springs, CA 90670, U.S.A. Mobil Research and Development Corporation, Box 900 Field Research Lab, Dallas, TX 75221, U.S.A. Solum Oil Tool Corporation, 2750 Rose Ave., Long Beach, CA 90806, U.S.A. Claude Thibault Int., P.O. Box 9231, Newport Beach, CA 92658, U.S.A. Consulting Engineer, Calle Aldebarren 365, Frac- cionamiento Benton, Los Pinos, Tijuana, C.P. 22630, Baja California, Mexico

VII

PREFACE

This second volume of Surface Operations in Petroleum Production was designed by the editors to complement, and amplify, the first volume. The first volume was devoted to several aspects of oilfield technology: (a) the physical and chemical properties of reservoir fluids, (b) surface equipment used for separation and accumulation of fluids, (c) natural gas and natural gas liquids, (d) oil and gas transport, (e) design of flowing well systems, (f) well testing, (g) production logging, and (h) fluid pumping operations. This two-volume comprehensive treatise on modern oilfield technology provides a complete reference for field managers, engineers, and technical consultants. These two volumes also can serve the academic needs for advanced studies of petroleum production engineering.

Volume I1 has been organized to present a detailed theoretical and practical exposition of surface oilfield practices, which include gas flow rate measurement, cementing, fracturing, acidizing, and gravel packing. In today’s era of specialization, these operations are generally left to the province of service companies, denying field engineers’ and company managers’ direct detailed knowledge of the specific surface and subsurface operations. This book presents a comprehensive analysis which may be used by field engineers to analyze technical problems, specify the required surface and subsurface operations, and closely supervise the service company’s work and post treatment operation of the well.

Another subject which has great economic consequences in all oilfields is corrosion of equipment in the field. Corrosion is a relentless, continuous economic loss that may, superficially, appear as an almost inconsequential problem but can accelerate into a large loss of equipment and production efficiency if the causes are not recognized and curtailed in time to retard the process of corrosion. This book presents a comprehensive analysis of the theory of corrosion in the oilfield and methods that have proven to be effective for the retardation, or elimination, of corrosion. Quality control of injection waters is covered next.

Three final topics complete Volume 11: (1) Offshore technology is presented with reference to onshore oilfield operations making this a very lucid presentation for field engineers who do not have practical knowledge of offshore technology and tend to view this as an entirely different field of endeavor. (2) Pollution control is an area of oilfield management that has assumed widespread importance because of (a) the encroachment of urban populations into and near oilfields in many parts of the world, and (b) the strict enforcement of pollution control laws that has developed to abate pollution from all industrial enterprises. (3) The final chapter treats the subject of underground storage of gas and oil which, for example, is important for

VIII

cities in cold climates that must be assured of fuel supplies during the winter months. Underground fuel storage and retrieval is an active area of oilfield production management that utilizes the technology presented in this entire treatise on surface operations.

Finally, the technology of testing petroleum products and sample experiments for junior or senior petroleum engineering students are presented in this volume.

Changes in oilfield technology develop gradually from current practices and developing needs; therefore, this two-volume treatise will serve for many years as the standard reference of oilfield surface operations for managers, engineers, consultants, and teachers in the petroleum industry.

Erle C. Donaldson University of Oklahoma

Norman, Oklahoma

IX

CONTENTS

CONTRIBUTORS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VI

PREFACE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . VII

Chapter 1. INTRODUCTION G.V. Chilinganan, J.O. Robertson, Jr. and C. Thibault with Appendix by D.D. Coleman

Chokes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 6

Subsidence . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6 Sample prob . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

Solution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Appendix 1. 9 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Throttling effect (gas condensate) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chapter 2. FLOW RATE MEASUREMENT T.R. Sifferman with Appendix by L.J. Kemp and G.V. Chilinganan

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 13

Definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Main types of meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Accuracy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Rangeabili ty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Repeatability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14 Linearity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

. . . . . . . . . . . . . . . . . . . . . . . . . . . . 15 Turbine meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Readout devices, 21

Orifice meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

Orifice meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Turbinemeters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27 Positive displacement meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Volumetric flow rate of gases . . . . . . . . . . . . . . . . . . . . . . . . .

Vortex shedding meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28 Other types of flow rate mea t . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Mass flow rate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Special flow meters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Simple equations for measuring weight flow rates for gases and liq Sample problems and questions . . . . . . . . . . . . . . . . . . . . . . . . . . Appendix 2. I-Development of orifice metering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Two-phase systems . . . . . . . . . . . . . . . . . . . . . . . 30

33

Definition of orifice meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34 History . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

X

Operation of orifice meter . . . . . . . . . . . . . . Description of orifice meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fundamentals of measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Outline of basic laws for ideal gases, 48-Deviations from the Ideal Gas Law, 49-Basic flow formula (q = C’fi), 50-Orifice flow constant (C’ ) , 51

Computation of volumes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Specific gravity and temperature determinations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Specific gravity, 56-Temperature of flowing gas, 57-Interpreting the recorded temperature value, 57

Significant figures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Subsequent changes of coefficients . . . . . . . . Calculation of ( C ) for nonstandard internal-diameter meter run . . . . . . . . . . . . . . . . . . . . . .

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Example, 58

35 37 48

53 56

57 57 58

58

Chapter 3. THE MANUFACTURE, CHEMISTRY AND CLASSIFICATION OF OILWELL CE- MENTS AND ADDITIVES J.O. Robertson, Jr., G.V. Chilinganan and S. Kumar

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61 . . . . . . . . . . . . . . . . . . . . 61

Classification of oilwell cements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

. . . . . . . . . . . . . . . . . . . . 64 Pozzolan-line cements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 Resin or plastic cements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 Diesel oil cements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65

Expanding cements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66 Latexcement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Calcium aluminate cements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Low-density cement (Spherelite TM) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Permafrost cement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68

. . . . . . . . . . . . . . . . . . . . . . . 68 Accelerators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Light-weight additives . . .

. . . . . . . . . . . . 69 Cement retarders Lost circulation a . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69 Friction reducers

Specialty oilwell cements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

Gypsum cements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

Cementing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73

Primary oilwell cementing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 Waiting-on-cement time (W . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

Surface and subsurface cementing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 Cement pumping equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78 Cement mixing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Oilwell cementing practice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Recirculating systems, 81-Batch mixing, 82

X I

Subsurface cementing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Casing-cementing heads, 86-Cementing plugs, 86- Floating and guiding equipment, 86 -Stage-cementing tools, 89-Casing centralizers, 93-Casing scratchers, 93-Cement baskets and external casing packers, 99

Acknowledgements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chapter 4. FRACTURING J.O. Robertson, Jr., G.V. Chilingarian and S. Kumar

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

General criteria of well . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mechanics of hydraulic fracturing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Early history . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Hydraulic fracturing process variables . . . . Rock mechanics considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fracture geometry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fracture inclination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fracture initiation Fracture area Fracturing fluid coefficient . . . . . . . . . . . . . . . . . . . . . . . . . . .

Oil-base fluids . . . Water-base fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acid-base fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gelled acids . . . . . . . . . . . . . . . . . . . . . . . . . . . Acidemulsions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Chemically retarded acids . . . . . . . . . . . . . . . . . . . . . . . . . . . . Aqueousfoams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Propping agents for hydraulic fracturing . . . . . . . . . . Mechanical equipment for hydraulic fracturing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Pump equipment . . . . . . . . . . . . . . . . . . . . . . . . Proportioning equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Metering and control equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Bulk-handling equipment . . . . . . . . . . . . . . . . . . Surface equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Fracturing fluids and additives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . Sample questions and problems . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Calculate, 157 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chapter 5. ACIDIZING OILWELLS J.O. Robertson, Jr. and G.V. Chilinganan

Historical use of acids in oilwells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Acidtypes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . : . . . . . .

Carbonate oil reservoirs . Sandstone reservoirs . . . .

Purpose of oilwell acidizing . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Desired properties of oilwell acids . . . . . . . . . . . . . . .

. . . . . . . .

83

99 99

101 101 106 108 108 109 113 115 116 119 123 125 128 129 133 133 133 134 134 134 143 143 146 147 150 150 152 155 155 155

157

161 162 163 165 167 169

Acidizing treatments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Oilwell acid additives

Surfactants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 116

Diverting agents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180

Fracture acidization-design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189

Chapter 6. GRAVEL PACKING W.B. Hatcher, G.V. Chilingarian and J.R. Solum

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sand production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gravel selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192

Gravel sizing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 192 Gravel quality . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 197

Gravel-packing fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203 Screening, 197-Gravel shape, 198-Gravel solubility, 199-Gravel strength, 203

Low-viscosity carrier fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203 High-viscosity carrier fluids . . . . . . . . . Medium- or intermediate-viscosity carrier fluids . . . . . . . . Foam or low-density carrier fluids . . . . .

Screen or liner selection. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 204 Methods of gravel-packing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 205

Openhole gravel packs . . . . . . . . . . . . . . . . . . . . . . . . . . Cased-hole gravel packing . . . . . . . . . . . . . . . . . . . . . . .

"Single-stage'' method, 206-"Two-stage method, 206 Deviatedwells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Gravel-packing tools and equipment . . . . . . . . . . .

Blender . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211

. . . . . . . . . . . . . 211

Crossover tool . Port collar . . . . . . . . . . . . . . . . . . . 215

Chapter 7. STEAM ENHANCED OIL RECOVERY J.P. Fanaritis and G.V. Chilingarian

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . General data pertaining to steam injection . . . . . . . . . . . . . . . . . . .

Enhanced oil recovery classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Secondary production technique, 222-Tertiary pro- Primary production technique, 2

duction technique, 222 Steam injection mechanisms . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Steam injection performance data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Well depth, 224-Permeability, 224-Average injection rate, 226- Recovery, 226-Cumulative oil/steam ratio, 226

Friction loss effect on steam temperature, 228-Surface rad heat losses, 229-Heat losses to surrounding formations, 234

Wellbore and formation heat losses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . , 229- Wellbore

Steam injection techniques Cyclic steam injection Steamflooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Recent development in steam injection techniques . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Steam additives . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hotplate steam injection process . . . . . . . . . . . . . . . . . . . . . . . . Fracture-assisted steamflood process . . . . . . . . . . .

Introduction to equipment designs

. . . . . . . . . . . . _ . . _ _ _ . . . _ _ . . . . . . . . . _ _ _ . .

Equipment designs for steam injection projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Steam generator design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tube side flow design, 249-Suggested velocities in coils, 250-Radiant section design, 252 -Radiant tubewall temperature, 256-Convection section design, 258- Steam generator thermal efficiency, 259-Feedwater deaeration, 260-Two-phase pressure drop, 261-Steam quality measurement instrumentation, 261-Low NO, burners, 264

Feedwater treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Turbidity of feedwater, 265-Oil content, 265-Dissolved gases in feedwater, kalinity of feedwater, 266-Silica content in feedwater, 266-Metal contaminants in feedwater, 266-pH of feedwater, 266-Total hardness of feedwater, 267

Flue gas scrubbers . . . . . . . . . . . . . . . Low-temperature economizers

Casing vent systems . . . . . . . . . Downhole steam generators

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

High-temperature thermal packers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Solid-fuel-fired oilfield steam generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Sampleproblems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References and bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chapter 8. CORROSION IN DRILLING AND PRODUCING OPERATIONS T.A. Bertness, G.V. Chilingarian and M. Al-Bassam

Introduction

Corrosive agents in drilling and producing operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Electrochemical corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chemistry of corrosion and ele

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Definition of corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Requirements for electrochemical corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Components of electrochemical corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Actual electrode potentials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . e force series. . . . . . . . . . . . . . . . . . . .

221 221 222

222 224

221

238 238 240 244 244 245 246 246 246 247

264

267 210 271 272 272 274 276 276

283 283 283 284 284 286 287 287

XIV

Galvanic series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corrosion of steel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Types of corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Forms of cracking in drilling and producing environments . . . . . . . . . . . . . . .

Hydrogen embrittlement (sulfide cracking) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Corrosion fatigue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hydrogen blistering, 293

Corrodants in drilling and production fluids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Hydrogen sulfide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Carbondioxide __.............___.....____.....____.......t............

Alkalinity (pH) of environment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cathodic protection Role of bacteria in corrosion Corrosion in gas-condensate wells Inhibitors and passivators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sample problems

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Problem8-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Problem8-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Problem8-3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Problem8-4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Problem8-5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Solution, 312

Solution, 312

Solution, 313

Solution, 313

Solution, 314 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

References . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chapter 9. WATER QUALITY FOR SUBSURFACE INJECTION C.C. Wright and G.V. Chilinganan

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Injection suitability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Clay swelling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Formation and deposition of insoluble material in the formation . . . . . . . . . . . . . . . . . . . . . Increase in oil saturation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Suspended solids . . . Movement of formati . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sources of suspended solids . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Calcium carbonate scale . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Sulfate scales . . . . . . . . . . . . .

Some causes of waterflood corrosion . . . . . . . Carbon dioxide, 329- Hydrogen sulfide, 329- 330-Bacterial corrosion, 331

. . . . . . _ _ . . . . _ . . _ . . . . . . . . . . . . . .

Scale . . . _ _ _ . . . . _ _ . . _ _ _ _ _ . . _ _ . . . . . . . _ _ _ _ . . _ _ . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . _ . _ . . . . . . _ _ . . _ _ _ . . . . . . _ _ . .

Use of sea water for injection purposes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Characteristics of sea water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Dissolved oxygen, 332-Calcium carbonate saturation, 333-pH of sea water, 333-High sulfate ion content, 333-Magnesium ion, 333-Marine life, 334-Seasonal changes in composition of sea water, 334-Oil content, 334

289 289 290 292 292

294 296 296 297 301 302 303 306 307 310 311 311

312

313

313

314

315 316

319 319 320 320 322 323 324 324 325 326 327 327 329

332 332

xv

Selection of water intake location . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Shallow well in sea water aquifer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Intake from near-shore area .

. . . . . . . . . . . . Design of water intake . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fine screen Chlorination . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Filtration

Oxygen scavenging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Stabilization of sea water

Biocidal treatment of sea water . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Dissolved oxygen . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . pH change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Total iron count increase . . . . . . . .

Total bacteria . . . . . . . . . . . . . . . . . . . . . . . .

filter count test (total bacteria), 343

Insulated corrosion coupons, 343-Noninsulated corrosion coupons, 344-Exposure time of corrosion coupons, 344

Corrosion coupons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Significance of various tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Reporting of test data

Oilremoval . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Removal of solids (filtration)

Preparation of water for su . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Gravity separation, 355-Flotation, 356

Slow sand filters, 358-Rapid sand filters, 358-High-rate rapid sand filters, 358-Di- atomaceous earth filters, 360- Selection of diatomite, 362

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Removal of dissolved gases . . . . . . . . . . . . _ _ . . _ _ . . . . . . . . . . . . Aeration . . . . . . . . . . . . . . . . . . . . .

Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . Separators

Aggressiveness of the waters . . . . . . . . . . . . . . .

Filtration equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equipment considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Volume and origin of suspended material to be removed, 364 . . . . . . . . . . . . . . . . . . . . . . .

Value of space on which facilities are to be located . . . . . . . . . . . . . . . . . . .

Clarification, 366-1114 tion filters, 367

n systems, 366-Filter-aid filters and in-line floccula-

Degassing equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Deaeration equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Chemical miwing and feed equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Sample questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

334 334 335 335 335 336 336 336 336 337 337 338 338 338 339 339 340 340 340 341 341 342

343

344 352 352 353 353

357

363 363 363 363 364

365 365 366

367 367 368 368 369

XVI

Chapter 10. OFFSHORE TECHNOLOGY S. Kumar and G.V. Chilinganan

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore production facilities . . . . . . . . . . . . . . Offshore exploration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . _ . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Artificial islands . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Gravel islands, 380-Artificial ice islands, 380

Fixed-bottom mounted type platforms, 382-Floating-buoyant-type platforms, 389 Offshore platforms . . . . . . . . . . . . . . . . . . . . . . . _ _ _ . . . . _ . . _ . . . . . . . .

Platform installation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Platform selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Platform construction steps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Satellite well production system, 403-Semisubmersible production system, spheric chamber production system, 405-Subsea atmospheric system (SAS), 405-Emon’s subsea production system (SPS), 406

Sea-floor templates, 398-Mooring systems, 401

Subsea production systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Design considerations . . . . . . . Earthquake design criteria

Pile capacity . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Wind and wave forces . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Examplelo-I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Solution, 413 Offshore transportation methods . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Underwater pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tankers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore tanker loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Combined storage and tanker loading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Sample questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Offshore storage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . .

Chapter 11. POLLUTION CONTROL K.M. Sasseen, G.V. Chilingarian and J.D. Brady

_ _ _ . . . . . . _ . . _ . _ _ . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Chemical treatment .

Caustic soda, 44-Soda ash, 446

Nitrogen oxides control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Catalytic reduction, 449-Ammonia injection, 449-Burner modification, 450

Casing vent gas collection systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

373 374 379 319

381

396 398

401 403

407 409 409 412 41 3

414 414 415 41 5 417 417 418 41 8

42 1 422 423 424 425 429 431 431 433 436 441

447 449

450

XVII

Produced water treatment and disposal . . . . . . . . . . . . . . . . . . . . . . . . . 451

Sample problems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 453 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 452

. . . . . . . . . . . . . . . . . . . . Sample problem 11-1 . . . . .

Sample problem 11-2 . . . . . . . . . . . . . . . . Solution, 453

Field data, 454-Determine, References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 454

Chapter 12. UNDERGROUND STORAGE OF GAS AND OIL A. Ali Azun, G.V. Chilingarian and S. Kumar

Introduction . . . . . . . . . . . . . . . . . . . . . . . Storage of gas in depleted gas and o Storage in aquifers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 458

. . . . . . . .

. . . . . . . 459

Creation of cavity and cavern design . . . . . . . . . . . . . . . . . . . . . . . . . . . . 461 Design specifications of Eminence Salt Dome. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 463 Leach-fill procedure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 463 Measurement of cavities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 468 Advantages of storing natural gas in salt domes . . . . . . . . . . . . . . . . . . . . . . . . 469

Mined caverns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 470 Storage in caviti nuclear explosions . . . . . . . . . . . . . . . . . . . . . . . Sample questions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 472

Appendix A. TECHNOLOGY OF TESTING PETROLEUM PRODUCTS AND SAMPLE EXPERI- MENTS G.V. Chilingarian, J.O. Robertson, Jr. and C.M. Beeson

Some theoretical considerations of distillation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Solution type equilibrium diagrams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Sample problem A-1, 476-Solution, 477

Sample problem A-2, 478-Solution, 478 Raoult's and Dalton's laws . . . . . . . . . . . . . . . . . . . . . . .

Fractionation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Layer type and eutectic type equilibrium diagrams . . . . . . . . . . . . . . . . . . . . . . . . . . . . Tests on fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Gravity (Hydrometer) (ASTM D 1898-80) . . . . . . . . . . . . . . . . . . . . . . . . .

Vapor pressure (Reid) (ASTM D 323-82) . . . . . . . .

Key points, 483-The weight and volume re1 484--Questions, 484

Key points, 484-Sample problem A-3, 484-Solution (approximate), 485-Sample problem A-4, 485-Solution, 485-Questions, 485

Knock properties of gasoline (ASTM D 909-83; D 2623-83; D 2699-83; D 2700-83; D

Tetraethyl lead in gasoline (1 mate) (ASTM D 2541-82) . . . . . . . . . . . . . . . . . . . . . .

Fisher TEL-meter . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

hips of two-component systems,

. . . . . . . . . . . . . . . . . . . . . . . . .

2885-83; D 2886-83) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Key points, 487 . . . . . . . . . . . . . . . . . . . . . .

475 476

478

479 481

482 483 483

484

485 486

487

XVIIl

Contamination of fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Questions, 488

Doctortest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Mercaptan sulfur test (D 1323-62) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Key points, 489 Water-tolerance of aviation fuels .

Mechanism of filter plugging, Thermal value of fuel oil (D 240-76; D 1405-64; D 2382-83) . . . . . . . . . . . . . . . . . . . .

Key points, 491-Sample problem A-5, 491-Solution, 491-Question, 491

Method of testing, 492-Key points, 492-Questions, 492

Key points, 493-Questions, 494

Key points, 494


Questions, 495

. . . . . . . . . . . . . . . . . . . . . . . . . . . .

Gum content (ASTM 381-80) . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Aniline point (D 611-82) and aniline- gravity constant . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Fluorescent-Indicator Adsorption (FIA) test (D 1319-83; also see D 936-83) .

Sulfur content (Lamp) (ASTM D 1266-80) (also see D 129-64). . . . . . . . . . .

Corrosion (Copper strip, 212O F) (ASTM D 130-83) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Lubrication . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Cooling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Cleaning . . . . . . . . . . . . . . . . . . . . . . . . . .

Sealing . . . . . . . . . . . . . . . . . . .

Viscosity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

. . . . . . . . . . . . . . .

. . . . . . . . . . . . . . . . . . . . . . . . . Tests on lubricating oils . . . . . . . . . . . . . . . . .

Viscosity index (ASTM D 2270-79) . . . . . . . . . . . . . . . . . . Flash and fire tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .




Color of lubricating oils and petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Cloud and pour points (ASTM D 97-66; also see D 2500-81) . . . . . . . . . . . . . . . . . . . . . . . .

Dilution of crankcase oil (ASTM D 322-80) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Precipitation number of lubricating oils (ASTM D 91-81) . . . . . . . . . . . . . . . . . . . . . . . . . .

Questions, 501 Carbon residue (D 189-81; D 524-81) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Key point, 501 Ash content (ASTM D 482-80; D 874-82) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Key points, 502-Question, 502 Neutralization number (D 664-81) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Questions, 502 Saponification number (ASTM D 94-80) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Key points, 503-Questions, 503 Sulfur (bomb) (ASTM D 1552-83) . . . . . . . . . . . . . . . . . . .

Key points, 503 Corrosion test of lubricating oils (copper strip at 212O F). . . . . . . . . . . . . . . . .

Classification and requirements of lubricating greases . . . . . . . . . . . . . . . . . . . . . . . . . . Penetration of lubricating greases (D 217-82) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Dropping point of grease (D 127-63) . . . . . . . . . . . . . . . . . Key points, 505

Key points, 505

487

488 489

489

491

491

492

494

494

495

495 495 496 496 496 496 496 497 498

499

499

500 501

501

501

502

502

503

504 504 505

505

XIX

Orsat gas analysis . . . . . . . . . . . . . Method of analysis . . . . . . . .

Carbon dioxide, 505-Unsaturated hydrocarbons, 506-Carbon monoxide, 506- Hydro- gen, 506-Methane and ethane, 506-Nitrogeq 506-Combinations of combustibles, 506 -Introduction of gas sample, 506-Size of gas sample, 507-Number of passes, 507-Sample problem A-6 (Orsat analysis), 507-Sample problem A-7, 508-Solution, 508

Freezing point tests . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Freezing point of fuels (ASTM D 2386-67) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Lowering of freezing point . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Key point, 508

Sample problem A-8, 509-Solution, 509-Sample pr 9-Solu Charcoal test for gasoline content of natural gas . . . . . . . . . . . . . . . Sample experiments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Experiment A-1: Distillation of gasoline, kerosine and benzene by Engler Flask (ASTM D 86-82; D 216-77) . . . . . . . . . . . . . . . . . .

Instructions, 511 -Results, 51 1 -Questions, 51 1

Instructions, 512-Results, 512-Questions, 512

Instructions, 512-Data, 512-Questions, 512--Instructions, 513-Questions, 513

Experiment A-2: Distillation of crude oil with Hemple Column (ASTM D 285-62) . . . . . . . . .

Experiment A-3: Gravity by hydrometer and vapor pressure by the Reid Bomb . . . . . . . . . . .

Experiment A-4: Water in petroleum by distillation and water and sediments in petroleum by centrifugation (ASTM D 1796-83; D 4007-81; D 4006-81) . . . . . . . . . . .

Instructions, 5 13 -Results, 513- Questions, 5 13 -Instructions, 5 13 - tions, 513

Instructions, 514-Results, 514-Questions, 514 Experiment A-5: Viscosity by Saybolt viscosimeter (ASTM D 88) . . . . . . . . . . . . . . . . . . . . .

Experiment A-6: Flash and fire points by tag closed tester, by open cup, and by Pensky-Martens tester . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Instructions, 514--Results, 514-Questions, 515-1nstructions, 515-Results, 515-Ques- tions, 515-1nstructions, 515

Instructions, 515-Results, 516-Questions, 516--Instructions, 516--Results, 516-Ques- tions, 516





Experiment A-7: Color of lube oil and cloud and pour points . . . . . . .

Experiment A-8: Dilution of crankcase oil (ASTM D 322) . . . . . . . . .

Experiment A-9: Orsat analysis of a mixture containing oxygen . . . . . . . . . . . . . . . . . . . . . .

Experiment A 10: Orsat analysis of gas mixture containing an olefin . . . . . . . . . . . . . . . . . . .

Experiment A-11: Orsat analysis of a mixture containing hydrogen and carbon monoxide

Experiment A-12: Solidifying point of benzene (ASTM D 852) and determination of molecular weight from lowering of freezing point of benzene . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

Experiment A-13: Corrosion-electromotive series and galvanic corrosion . . . . Instructions, 5 18 -Results, 5 18 -Questions, 5 18

Questions, 519 References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

505 505

508 508

508

510 511

511

512

512

513

514

514

515

516

517

517

517

518

518

520

xx

Appendix B. CONVERSION OF UNITS J.O. Robertson, Jr. and G.V. Chilinganan

Theoretical aspects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 521 Example 1: Dynamic viscosity conversion factor . . . . . . . . . . . . . . . . . . . . . . . . . . . . 521

Conversion factors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 524

References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 541

Example 2: Determination of multicomponent conversion consta . . . . . . . . . . . . . . . . . 522

Temperature conversion formulas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 541

References Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 543 SubjectIndex . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 551

Chapter I

INTRODUCTION

GEORGE V. CHILINGARIAN, JOHN 0. ROBERTSON Jr. AND CLAUDE THIBAULT WITH APPENDIX BY D.D. COLEMAN

In the first volume of this two-volume book, the writers covered the following subjects: (1) overview of surface production equipment, (2) properties of hydrocarbons, (3) oil and gas separation, (4) chemical resolution of petroleum emulsions, ( 5 ) electrical resolution of petroleum emulsions, (6) vapor recovery, (7) natural gas and natural gas liquids, (8) oil and gas transport, (9) design of flowing well systems, (10) well testing, (11) production logging, (12) gas lift, (13) plunger lift, (14) sucker rod pumping, (15) hydraulic lift, and (16) electrical submersible pumps.

In the second (present) volume the writers discuss: (2) gas measurements, (3) cementing, (4) fracturing, (5) acidizing, (6) gravel packing, (7) thermal recovery, (8) fundamentals of corrosion, (9) water quality control for subsurface injection, (10) offshore technology, (11) pollution control, and (1 2) underground storage of oil and gas. In addition, technology of testing petroleum products and suggested experiments are presented in Appendix A, whereas conversion factors are covered in Appendix B.

Although the completion program of a well is thoroughly planned prior to the drilling, the actual completion (selection and use of completion fluids, replacement of BOP valves by the Christmas tree, cementing, perforation, gravel packing, etc.) is performed after the well testing. The evaluation of the well potential to produce oil and/or gas starts when the drilling rig is still located over the wellbore and the production string (last casing string) is yet not lowered into position. The results of well testing, which evaluates the reservoir characteristics (bottomhole pressure and temperature, permeability, porosity, irreducible fluid saturation, etc.), enable the petroleum engineer to determine the proper well completion program for this particular well. The reader is referred to an excellent treatment of this subject by Craft et al. (1962) and Allen and Roberts (1978).

Upon perforation, drillstem test (DST) is often performed. As pointed out in Chapter 10, Vol. 1, this test can be performed in either open or cased wellbores.

A production test can be periodically made during the life of the well to determine: (1) the type of fluids being produced from the various productive intervals, (2) the time of initiation of artificial lift or the efficiency of the artificial lift system already in use, and (3) the potential of enhanced oil recovery (EOR) or the effect of existing EOR process on the reservoir.

2

The term “production” refers to that phase of operations which involves the production of well fluids (oil, water, and gas) to the surface and their treatment, prior to the transportation through pipelines (or by tanks) to the refinery. An excellent treatment of this subject can be found in Allen and Roberts (1982). The classical work of Sivalls (1977) should be consulted by all engineers involved in the separation of oil and gas.

Recent advances in offshore oil and gas pipeline technology have been presented by De la Mare (1985).

CHOKES

One of the more misunderstood subjects in petroleum operations is “choke” performance. The most commonly used type of choke is the “wellhead” choke (see Figs. 1-1 and 1-2). As a safety measure, especially in offshore operations, a choke is installed downhole (bean). Small variations in the downstream pressure (e.g., due to a dump separator) should not affect the tubing-head pressure (ptf, ptbg, or THP). Consequently, the fluid velocity through the choke should be greater than the speed of sound, which is achieved if the THP is at least twice as high as the average flowline pressure. Theoretically, the tubing-head pressure, p,,,(psia), is approximately equal to:

GAUGE VALVE

-TOP CONNECTION

SWAB VALVE (FLOWLINE VALVE)

FLOW FITTING- [SEE N O T E p ~ i w n q

WING CHOKE I 1

CHOKE WING VALVE

(FLOWLINE VALVE) LINE VALVE)

LINE VALVE)

Fig. 1-1. Location of a choke on a typical Christmas tree. (Courtesy of Sii Willis, Division of Smith International, Inc.)

ESD VALVE - FIRE LOOP 8 ESD SYSTEM

"MANUMATIC' AG-MHA SURFACE

SAFETY VALVE

- ACTUATOR CONTROL PRESS.

INSTRUMENT PRESS.

777777777 PNEUMATIC SUPPLY 3 3 PRESS. 3 3

@ d v)

0

Fig. 1-2a. (For explanation see p. 4). W

A

SYMBOLS - API 14C

'* LSH High Level Sensor

'* LSL @ Low Level Sensor

''LSHL @ High/Low Level Sensor

** PSH High Pressure Sensor

** PSL Low Pressure Sensor

** PSHL HighlLow Pressure Sensor

** FSV Check Valve

Pressure Relief or Safety Valve

'* PSE Rupture Disc

** TSE Fusible Material

0 Wellhead Surface

**ssv +&)+ Safety Valve

0’ ** BDV & Blowdown Valve

*& SDV Shutdown Valve

High Temperature Sensor

** TSH

* API 14D, 2nd Edition, Nov. 1978, Used with permission of API ** API 14C, 2nd Edition, Jan. 1978, Used with permission of API

Fig. 1-2 (continued) b. Location of a choke on an offshore production platform (safety shut-in system). (Courtesy of Axelson, Inc., a Subsidiary of U.S. Industries, Inc.)

5

6

where GLR = gas/liquid ratio in Mcf/bbl, q, = gross liquid production rate in bbl/day, C = constant ( = 600 for units presented in this equation), and d , =

diameter of the choke in 1/64 in. units. Gilbert (1954) developed the following equation for the Ten Section Field in California ( ptbg is in psig):

ptbg = 435(GLR)0’546(ql)/(dc)1’89

The severity of choke distortion due to (1) gas cutting, (2) sand cutting, and (3) asphalt and/or waste deposition can be checked by using production data and eqs. 1-1 and 1-2. Equation 1-1 should yield a value of 600 for C, whereas eq. 1-2 should yield a value of about 435 for C.

One can also use Gilbert's nomogram (Fig. 1-3) for solving choke problems. The nomogram is entered at the top of left-hand chart (bbl/day). Upon dropping vertically to a given gas/liquid ratio (Mcf/bbl), one moves horizontally to the heavy line on the right-hand chart (10/64 in. bean size). Then moving vertically to the existing bean size, one can read the ptbg(7'HP) at the left-hand ordinate of the right-hand chart. Equation 1-1 gives almost the same answer.

The reader is referred to Nind's (1981) book entitled Principles of Oil Well Production for a detailed treatment of choke performance. This book belongs on the bookshelf of all petroleum engineers.

Throttling effect (gas condensate)

The Joule-Thomson (throttling) effect is an irreversible adiabatic process which occurs by using pressure-reducing choke on a high-pressure gas condensate stream. The heat content of the gas remains constant across the choke, as the pressure and temperature of the gas stream are reduced (see Katz et al., 1959). These chokes are mounted at the inlet of the high-pressure separator to remove the hydrates which form downstream of the choke due to the reduction of temperature and pressure. Hydrates [methane (CH, . 7H20), ethane (C,H,. 8H20), propane (C,H,. 18H20), and carbon dioxide (C02.7H20)] are blown into the separator and fall to the settling section. Liquid heating coils located at the bottom of the separator melt the hydrates. For comprehensive treatment of the subject, the reader is referred to the excellent book by Ikoku (1984), entitled Natural Gas Production Engineering.

SUBSIDENCE

In many areas, upon production of oil and gas with consequent reduction in pore pressure, pp, the grain-to-grain (effective) pressure, p,, increases. The latter causes compaction of both clays and sands, with consequent subsidence of the land. This can cause serious damages to the surface structures and subsurface installations. Consequently, it is imperative to develop techniques for predicting subsidence-prone areas. One such tentative method was proposed by Chilingarian et al. (1985), using shale resistivity ratio, rsh = [ R,,(normal)/R,,(observed)] (see Fig. 1-4). This ratio is

7

I

w - t -

....... .

. . . . . . . . . . . . . . .

\

n -

-. .‘a,. Ib)

. . . . . .

SHORT NORMAL R E S I S T I V I T Y RSh -+

Fig. 1-4. An example of a shale resistivity profile. Numbers designate the resistivity ratio: (a) rSH < 1.5, not prone to subsidence, (b) rSH = 1.5-2.9, slightly prone to subsidence, (c) rsH = 2.9-4.0, strongly subsidence prone, and (d) rSH 2 4.0, extremely prone to subsidence. (After Chilingarian et al.. 1985; Courtesy of Energy Sources.)

a good indicator of undercompaction and was correlated with compressibilities of unconsolidated sands associated with undercompacted shales. The use of other formation evaluation logs, such as sonic logs, is also recommended.

In subsidence areas, studied by Sawabini et al. (1974) and Chilingarian et al. (1985), the effective pore volume compressibilities of unconsolidated sands

ranged from 1 x l o p 3 to 1 x psi-’, whereas bulk volume compressibilities

ranged from 5 X psi-’, in the 0 to 4000 psi effective pressure range (that is, pe = p t -pp, where pt is the total overburden pressure and pp is the pore pressure; effective pressure, pe, is sometimes called grain-to-grain stress, pg ). Resistivity ratio, rSh, of associated shales ranged from 2 to 4. A considerable amount of statistical and experimental research work, however, needs to be done in this area.

The reader is referred to a comprehensive treatment of the subject by Rieke and Chilingarian (1974), Sawabini et al. (1974) and Chilingarian and Wolf (1975, 1976).

to 4 X

SAMPLE PROBLEMS AND QUESTIONS

(1) Determine ptbg(THP) given the following information: q = 150 bbl/day (gross), GLR = 800 cu ft/bbl, and d, (bean size) = 16/64 in.

8

(2) Give and discuss various formulas used for determining bulk and pore volume compressibilities.

(3) Plot bulk compressibility ( cb) versus effective pressure ( p , ) on log-log paper given the following experimental data on saturated montmorillonite clay. Uniaxial compaction apparatus (thick-walled cylinder with two pistons) was used.

Pressure Moisture content (water) (Psi) (Sa dry weight basis)

1000 50 2000 5000

10,000 30,000 40,000 60,000

100,000 190,000 200,000

45 37 32 22 20 18 14 11 8

(4) In a subsiding area with a thick sand-shale sequence, does shale or sand compact more? Explain, with presentation of factual data.

( 5 ) ' Determine the time necessary to fill a cylindrical tank (10 ft high and 5 ft in diameter) shown in the figure below (Fig. 1-5). Water flows into the tank at a rate of 1.25 cu ft/sec. A 3-in. hole is open at the bottom of the tank.

- I .. I I,-

Fig. 1-5. Schematic diagram for solving sample problem (5).

' The help extended by Serge Y. Baghdikian is greatly appreciated the writers.

9

Solution.

( Q , - Q 2 ) d t = A dh

Integrating:

where t = time in seconds, A , = 77/4(5)’ = 19.635 ft2, Q, = 1.25 ft3/sec, Q, = A2V2 = A2J28k = (3/12)2~/4(J2 X 32.2 X h ) = 0.3939fi, g = gravitational acceleration, 32.2 ft/sec2, H = 10 ft, and h = head of water above the bottom hole in ft. Thus:

t = L1’[19.635/(1.25 - 0.3939fi)I dh = 49.845I1’dh/(3.173 - fi) 0

Solving, t = 24 min 45 sec.

APPENDIX 1.1-GEOCHEMICAL FINGERPRINTING O F NATURAL GAS

DENNIS D. COLEMAN

Distinguishing natural gases from different sources is of critical importance to the petroleum industry and to the general public. Gas which migrates from gas or oil wells, pipelines, or storage reservoirs can result in a significant loss to the owner or, under some circumstances, can reach the surface or enter public water supplies and result in hazardous situations. In other cases, gas whch is thought to be a migrated gas is, in fact, naturally occurring (native) gas. It is, therefore, of prime importance to be able to distinguish gases from different sources. Geochemical fingerprinting provides a method of identifying the source of natural gas.

Most commercial deposits of natural gas were formed by thermal decomposition of buried organic material. The composition of natural gas is a function of the type of organic material from whch it was formed, the pressure and temperature conditions which existed at the time of formation, and any changes which have occurred as a result of migration or mixing with gas from other sources. Because of the many variables involved in the formation of natural gas, it is very unlikely that gases from two different sources will have identical compositions. The “geochemical fingerprint” of the gas can, therefore, be used for its identification.

10

Distinguishing natural gases from different sources may sometimes be accomplished using only chemical analyses of the gas. This method is complicated, however, by the fact that due to differences in the size, mass, and solubility of the different chemical constituents, the chemical composition of natural gas can change as it migrates. A more definitive method for distinguishing between natural gases which were derived from different sources is the use of isotopic analysis (see Coleman et al., 1977; Fuex, 1977; Stahl, 1977; and Schoell, 1980).

Isotopes are different forms of the same element, differing only in the number of neutrons within their nuclei and thus their mass. Carbon, for example, has three naturally occurring isotopes, carbon-12, carbon-13, and carbon-14. Carbon-14 is a radioactive isotope formed in the upper atmosphere by cosmic rays. Carbon-14 is not present in petroleum or petroleum gases but is present in recent bacterial gases. Hydrogen also has three natural isotopes, protium (hydrogen-l), deuterium (hydrogen-2), and tritium (hydrogen-3). Protium and deuterium are stable isotopes and tritium is a cosmogenic isotope.

The two stable isotopes of carbon, carbon-12 (”C) , and carbon-13 (I3C), are present in all organic materials and have average abundances of 98.9 and 1.1%, respectively. These two isotopes of carbon undergo the same chemical reactions, but because of the small difference in mass, the reaction rates are sometimes slightly different. As a result, the relative proportions of carbon-12 and carbon-13 may not be exactly the same in the reaction products as they were in the source materials. For example, the formation of methane by the thermocatalytic decomposition of organic material results in methane wluch is depleted in carbon-13 (or enriched in carbon-12) relative to the original organic material. Once methane is formed, however, its carbon isotopic composition, or l3 C/I2 C ratio, is relatively unaffected by most natural processes.

The carbon isotopic composition of methane in natural gas is a function of the nature of the source material and the conditions under which it was formed. Unlike the chemical composition of natural gas, the isotopic composition is relatively unaffected by migration (Sackett, 1968; Stahl and Carey, 1975; Coleman et al., 1977; Fuex, 1980; Reitsema et al., 1981; Schoell, 1983). Consequently, the isotopic composition of methane provides a reliable “fingerprint” for distinguishing natural gases from different sources.

Coleman et al. (1977) demonstrated that carbon isotope analyses could be used to distinguish between storage gas and shallow biogenic methane when, due to migra- tional changes, chemical analyses could not distinguish between the two. In later studies (Coleman, 1979, 1985), isotopic analysis was effectively used to identify storage gas which had migrated to nearby oil wells. In recent unpublished studies, it has been shown that the carbon isotopic composition of ethane and the hydrogen isotopic composition of methane can also be used to distinguish between storage gas and native gas.

In distinguishing gases from different sources, one must first establish the compositional range of gases of known sources (for example, storage gases and native gases) and determine which chemical and isotopic parameters best differenti-

11

ate these sources. Gases from unknown sources may then be classified as one type or the other (or as a mixture) based on their chemical and isotopic compositions. In some cases it is even possible to determine the relative proportions of two gases present in a mixture.

REFERENCES

Allen, T.O. and Roberts, A.P., 1978. Production Operations: Well Completions, Workover, and Stimula- tion, Vol. 1. Oil and Gas Consultants International, Tulsa, Okla., 225 pp.

Allen, T.O. and Roberts, A.P., 1982. Production Operations: Well Completions, Workover, and Stimulu- tion, Vol. 2. Oil and Gas Consultants International, Inc., Tulsa, Okla., 250 pp.

Chilingarian. G.V. and Wolf, K.H., 1975. Compaction of Coarse-Grained Sediments, I (Developments in Sedimentology, 18A). Elsevier, Amsterdam, 552 pp.

Chilingarian, G.V. and Wolf, K.H., 1976. Compaction of Coarse-Grained Sediments, I1 (Developments in Sedimentology, 18B). Elsevier, Amsterdam, 808 pp.

Chilingarian, G.V., Yen, T.F. and Fertl, W.H., 1985. New method of predicting subsidence and subsidence-prone areas. Energy Sources, 8(1): 77-78.

Coleman, D.D., 1979. The use of isotope ratios to determine the source of natural gas above gas storage reseruoirs. Paper presented at the Am. Gas Assoc. Oper. Sect. Meet., New Orleans.

Coleman, D.D., 1985. Applications of geochemistry to the production, storage, and utilization of natural gas. Paper presented at the Am. Assoc. Pet. Geol. Annu. Meet., New Orleans.

Coleman, D.D., Meents, W.F., Liu, C.L. and Keogh, R.A., 1977. Isotopic identification of lenkage gas from underground storage reservoirs ~a progress report. Ill. State Geol. Surv. Ill. Pet., 10 pp.

Craft, B.C., Holden, W.R. and Graves Jr., E.D., 1962. Well Design; Drilling and Production. Prentice-Hall, Englewood Cliffs, N.J., 368 pp.

Fuex, A.N., 1977. The use of stable carbon isotopes in hydrocarbon exploration. J. Geochem. Explor., 7: 155-188.

Fuex, A.N., 1980. Experimental evidence against an appreciable isotopic fractionation of methane during migration. Phys. Chem. Earth, 12: 725-732.

Gilbert, W.E., 1954. Flowing and gas-lift performance. API Drill. Prod. Pract.. p. 126. Ikoku, Chi U., 1984. Natural Gas and Production Engineering. Wiley, New York, N.Y., 517 pp. Katz, D.L., Cornell, D., Kobayashi, R., Poettmann, F.H., Vary, J.A., Elenblaas, J.R. and Weinaug, C.F.,

Mare, De la, R.F. (Editor), 1985. Advances in Offshore Oil and Gas Pipeline Technology. Gulf, Houston,

Nind, T.E.W., 1981. Principles of Oil Well Production. McGraw-Hill, New York, N.Y., 2nd ed., 391 pp. Reitsema, R.H., Kaltenbach, A.J. and Lindberg, F.A., 1981. Source and migration of light hydrocarbons

Rieke 111, H.H. and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments (Developments in

Sackett, W.M., 1968. Carbon isotope composition of natural methane occurrences. Am. Assoc. Pet. Geol.

Sawabini, C.T., Chilingar, G.V. and Allen, D.R., 1974. Compressibility of unconsolidated arkosic oil

Schoell, M., 1980. The hydrogen and carbon isotopic composition of methane from natural gases of

Schoell, M., 1983. Isotope techniques for tracing migration of gases in sedimentary basins. J. Geol. Soc.,

Sivalls, C.R., 1977. Fundamentals of Oil and Gas Separation. Proc. Gas Cond. Conf., Univ. Oklahoma,

1959. Handbook of Natural Gas Engineering. McGraw-Hill, New York, N.Y., 802 pp.

Tex., 383 pp.

indicated by carbon isotopic ratios. Am. Assoc. Pet. Geol., 65(9): 1536-1542.

Sedimentology, 16). Elsevier, Amsterdam, 424 pp.

Bull., 52: 853-857.

sands. SOC. Pet. Eng. J . , 14(3): 132-138.

various origins. Geochim. Cosmochim. Acta, 44: 649-661.

140(3): 415-422.

Norman, Okla.

12

Stahl, W., 1977. Carbon and nitrogen isotopes in hydrocarbon research and exploration. Chem. Geol., 20:

Stahl, W. and Carey, B.D., 1975. Source rock identification by isotope analyses of natural gases from 121-149.

fields in the Val Verde and Delaware basins, West Texas. Chem. Geol., 16: 257-267.

13

Chapter 2

FLOW RATE MEASUREMENTS

THOMAS R. SIFFERMAN WITH APPENDIX BY L.J. KEMP AND GEORGE V. CHILINGARIAN

INTRODUCTION

Main types of meters

The main types of flow rate meters in the oil industry include the turbine meter, the positive displacement meter, and the orifice meter. The first two types are typically selected for liquid flow rate measurement, whereas the orifice meter is used primarily for gases. Both the turbine meter and positive displacement meter, however, can be used for gases, and the orifice meter can also measure liquid flow rates.

The turbine meter measures flow rate (instantaneous or cumulative) by converting liquid velocity into rotational velocity. A turbine (a propeller-like device) rotates on a shaft. The speed of the turbine is proportional to the linear velocity (or flow rate) of the fluid moving through the meter. The speed of the turbine is measured as pulses that give the instantaneous flow rate. The pulses can also be accumulated to give the total or cumulative flow rate.

A positive displacement meter measures instantaneous or cumulative flow rate by counting the number of “ volumes” through the meter. The “ volume” is based on a selected geometry so that a constant, exact amount of fluid is trapped for each count of the meter.

The orifice meter is a differential pressure device that produces a flow rate that is proportional to the square root of the pressure drop across the orifice. Physically, the device involves an orifice plate, pressure taps, and a holder for the orifice plate. A transducer, transmitter, or recorder converts the differential pressure into an indication of flow rate.

DEFINITIONS

In order to have a common base for comparison of meters, definitions for accuracy, rangeability, repeatability, and linearity are presented below. Often accuracy and linearity are interchanged, or linearity is quoted for a specified accuracy band.

Accuracy

Accuracy is a measure of the ability of a flowmeter to indicate the actual flow rate within a specified flow rate range. It is the difference between the actual and

14

measured flow rates divided by the actual flow rate. For a 100 gpm (gal/min) flowmeter, a k l % of full scale accuracy would mean the measured flow rate is within k l % gpm of the actual flow rate at any flow rate; i.e., 9-11 at 10 gpm, 49-51 at 50 gpm, and 99-101 at 100 gpm. On the other hand, + I% of reading means that the flowmeter is within kO.1 gpm at 10 gpm, f0.5 gpm at 50 gpm, and k1 gprn at 100 gpm, i.e., 9.9-10.1 at 10 gpm, 49.5-50.5 at 50 gpm, and 99-101 at 100 gpm. The percent of reading, therefore, gives much better results throughout the range, except for the full-scale readings where the results are the same.

The accuracy expressed as the percent of full scale (flow rate) is usually used for orifice meters, magnetic flowmeters, and variable-area meters. The accuracy expressed as the percent of actual reading is normally used for positive displacement and turbine meters. Some meters, such as mass flow meters, may use either, both, or a combination of these two methods of expressing accuracy in their specifications.

Rangeability

Rangeability is the ratio, at the specified accuracy, of the maximum flow rate to the minimum flow rate. It is usually reported as x : 1, where x is the maximum limit divided by the minimum limit. If the maximum flow rate is 100 gpm and the minimum is 10 gpm, the rangeability would be 10: 1. It is important to know not only the rangeability, but also the flow rate range over which it applies. One company could quote a 10: 1 rangeability (3-30 gprn), whereas another company could quote 15 : 1, just by decreasing the lower limit by 1 gpm (now 2-30 gprn). A more dramatic change, of course, would be 3-45 gprn for the 15 : 1 rangeability.

Repeatubility

Repeatability is the ability of a meter to reproduce the same measured readings for identical flow conditions over a period of time. It is, therefore, sometimes called the reproducibility and is generally expressed as the maximum difference between measured readings. Repeatability can be expressed as a percent of full scale flow rate. An instrument may have a very good repeatability, but a lower overall accuracy. If the flowmeter operates over a small range of flow rates, however, the high repeatability can be used to give very good indications of actual flow rate.

Linearity

Linearity is a measure of the deviation of the calibration curve from a straight line. It is usually specified over a given flow rate range or at a given flow rate. Inasmuch as linearity can be reported as a percent of full scale flow rate, it is important to note the conditions. Sometimes, the flow rate range is given over which the flow meter remains withm stated linearity limits. Actually, a flowmeter could have a good linearity, but a poor accuracy. That is, its calibration curve could be linear but shifted (offset) higher or lower than the correct actual readings.

15

VOLUMETRIC FLOW RATE MEASUREMENT OF LIQUIDS

Liquids are typically measured using a turbine meter or a positive displacement meter. Turbine meters allow easy automation and, therefore, have been used for many years, primarily for waterflood projects. Positive displacement meters have traditionally been used for fluids having varying or high viscosities, such as crude oil, but have not usually been adapted to automation.

Turbine meters can be used for both liquids and gases, but are used primarily for liquids, with most applications in the waterflood area. These meters are not necessarily ultra-accurate, about 1 %, in different configurations, but t h s is more than adequate for waterflood applications. Actually, higher accuracy, which is not required in most oilfield applications, is available from some of the manufacturers. The turbine flow meter (Figs. 2-1 and 2-2) typically works by converting the linear velocity and momentum into a tangential thrust, or force, whch then rotates the turbine or “propeller”.

The rotary vane type of positive displacement flowmeter is used extensively in the oilfield on separators for both water and crude oil flow rates. Another major usage is for waterflooding, which is also served by turbine flowmeters. The rotary vane type of flowmeter works by trapping a volume of fluid in a rotating vane segment made up by vanes, or other deflectors, that move in and out. The output then typically drives a mechanical counter to give cumulative (“ totalized”) and/or instantaneous flow rates. This meter can also be coupled magnetically, or by other means, to various systems for data display and automation purposes. Schematic diagrams and photographs are shown on Fig. 2-3.

Other types of rotating positive displacement meters include the oval-gear meter and the fluted rotor. These also trap definite volumes of fluid and transmit that fluid through the flow meter as shown in Fig. 2-4.

Orifice meters can also be used for liquid flow rate measurements. Typically, however, they are more difficult to adapt to automation purposes and have been used more for gas flow measurements. Most of the discussion on the positive displacement flow meters in this chapter involves the rotary vane type of meter. Nutating disc and piston meters, however, also can be used for positive displacement volumetric flow rate measurements. These are discussed later.

Turbine meters

Turbine meters are typically used in waterflood operations and for measuring low-viscosity oil flow. Inasmuch as ultra-accurate flow rates are not generally required for waterflood usage, the nominal f 1.0% accuracy is satisfactory, especially because these turbine meters have f0.05% of flow rate repeatability. Better quality and hgher priced meters are available from the same manufacturers (0.25 or 0.5% accuracy, f 0.02% repeatability). Rangeability is typically 10 : 1 (see Fig. 2-5), although the range is often extended to higher and lower flow rates with different linearity specifications. Typical upper temperature limits range from 100 O F to

16

Fig. 2-1. Turbine flowmeter. (Courtesy of Halliburton Services.)

17

Fig. 2-2. Cross-section of turbine flowmeter. (Courtesy of Halliburton Services.)

225 OF; meters with an upper temperature limit of 850 F are available. Sizes range from 3/8 in. to 24 in. with most of the economical waterflood meters being in the smaller sizes. The 1-in. size is typically in the 6-60 gpm range, although some companies quote linear flow ranges from 4 to 60 gpm, 5-50, 6-75, or 8-88 gpm. The 24-in. units handle up to 40,000 gpm in the normal range. Working pressures up to 7500 psi are available in the smaller sizes, with 1440 psi (600# ANSI) being available in the largest sizes. (See Table 2-1.)

Positive displacement meters

Positive displacement meters, used in oil production and transportation, range in size from 1/2 in. to 16 in. Flow rates from less than 1 gpm to almost 9000 gpm can be measured. Units with temperature and pressure ratings up to 450 O F and 5000 psi

18

DRIVE COUPLING -CLOCKWISE

LOOKING AT END OF COUPLl

BRIDGE BRIDGE SEALS

ROTOR BLADE

Fig. 2-3. Rotary vane type of positive displacement flowmeter. (Courtesy of 1 7 1 Barton and Tokheim Corporation.)

are available. The linearity, repeatability, and accuracy specifications depend on the geometry of the meter, viscosity, and operating temperature and pressure. Lineari- ties of k0.15% of maximum flow rate and repeatabilities of f0.05% are possible. Accuracies of kO.25% and f0.5% are available, although an accuracy of 0.1% at a rangeability of 200 : 1 is quoted for one reciprocating piston meter.

19

Fig. 2-4. Oval-gear meter. (Courtesy of Brooks Instrument Division.)

Typical rotary vane meters range in size from 1 to 3 in. (see Table 2-11). The rangeability is typically 10: 1 (6-60 gpm or 9-90 gpm), although meters with rangeability greater than 16 : 1 (15-250 gpm) are manufactured. Maximum temperatures are often in the 200-300 O F range.

The oval gear meters usually have a rangeability less than 10 : 1 for continuous service, but over 80 : 1 for non-continuous applications. Their repeatability can be *0.05% or higher, with *0.25% accuracy and +OS% linearity.

TABLE 2-1

Sizes, linear flow ranges, and nominal calibration factors of various waterflood turbine meters (After Halliburton Services)

~

Size Linear flow range

(in.) kpm)

Nominal calibration factor (pulses/gal)

3/8 1 2 4 8

0.3- 3 5 - 50

40 - 400 100 -1200 350 -3500

20,000 870 55 29

3

N 0

Fig. 2-5. Pressure drop curves for turbine flowmeters. (Courtesy of Halliburton Services.)

21

TABLE 2-11

Specifications of various rotary vane positive displacement meters (After ITT Barton Floco Flow Meters)

Size Flow rate range Pressure Temperature

1 6- 60 500/2500/500U 180 F 2 6- 60 500/2500/5000 180 OF 2 ” 15-250 500/2500 300 F 3 9- 90 500/2500/5000 180°F 3 a 15-250 500/2500 300 O F

a Higher accuracy, flow rate, and temperature model.

(in.) (gpm) (Psi) (OF)

The piston meters can be of the oscillating (rotating) or reciprocating types. Reciprocating piston units can be ultra-accurate, as indicated earlier, while still having excellent rangeability.

3% at a flow rate of only 3 gpm.

One 1-in. mutating disc (disk) is accurate to within

Readout devices Positive displacement (PD) meters and turbine meters can usually produce pulses

that are directly proportional to flow rate. The signal is then converted to a totalized and, often, an instantaneous flow rate. The PD meters can also use mechanical drives with register counters. Orifice meters, however, require the conversion from a pressure differential to a mechanical or electrical output. Also, the flow rate is proportional to the square root of the response, which complicates the data reduction.

The blades in a turbine meter cut lines of magnetic force produced by the magnetic pickup unit. The resulting electrical pulses are then transmitted to electronic instrumentation to indicate, totalize, record, and/or control flow rate. Analog and digital instrumentation is available. Results are usually given in standard engineering units, such as gallons or barrels.

Special options, which require additional measurement and processing devices, can compensate for temperature and pressure effects or can compute the energy change in Btu’s per unit volume of flowing hydrocarbons.

Most positive displacement meters use direct mechanical drives involving gears to indicate totalized flow; however, some companies use magnetic couplings. There are also two kinds of pulse systems: (1) In one system the rotor revolutions are counted by means of magnetic fields, somewhat like a turbine meter. (2) The other method involves a direct link to the output shaft that generates a pulse with a dry reed switch, with a microswitch, or photoelectrically.

In the case of orifice meters, two pressures (upstream and downstream of orifice) must be sensed and converted to flow rate. Mechanical devices involve the mercury type and the dry bellows recorders. They typically record the static pressure

22

downstream of the orifice and the differential pressure across the orifice. Electrical (electronic) devices include pressure transmitters (or transducers).

Orifice meters

Although orifice meters can be used for liquid measurements, they are primarily used for gas measurements. The principles are discussed in detail in the following section on the use of orifice meters for determining gas flow rates. Basically, Bernoulli’s equation is used to convert pressure head to velocity head. Velocity can then be determined at a known cross-section of the orifice, which in turn is converted to a flow rate. In the case of gas flow, calculations become more complicated because of compressibility effects.

VOLUMETRIC FLOW RATE OF GASES

Orifice meters have traditionally been used for determining gas flow rates, whereas turbine meters and positive displacement meters have been used for determining liquid flow rates. Turbine meters and the positive displacement meters, however, can also be used for gas flow measurements. The vortex shedding flow meters have recently been used for both gases and liquids, but predominantly for gas flow measurements.

Orifice meters

Orifice meters convert a pressure head to a velocity head in order to obtain the flow rate at a particular cross-section. Due to the compressibility of the gas, there is a correction factor for the compressibility. Other correction factors are also presented here. Orifice meters are more difficult to adapt to automation and, therefore, other devices, such as a turbine meter, have been used in their place.

Orifice meters have been the traditional device for measuring the flow rate of gases, but are not used as much for liquid flow measurement. The orifice meter, in fact, is still “one of the most important and widely used” flowmeters (F and P General Catalog, p. 1329), even though technology has provided some new sophisticated instrumentation. Advantages include its “simple, rugged, and reliable” (Daniel Basic Fundamentals by Kendall, p. 6) construction. Although they have limited rangeability (typically 3 : l), orifice meters are relatively inexpensive and have good accuracy for most gas metering applications.

A typical meter system consists of a concentric, square-edged orifice plate, a fitting that holds the orifice plate and provides taps for differential pressure measurement, and a pressure measuring-recording device. A meter tube provides an orifice fitting, the orifice plate, and both the upstream and downstream piping in one complete package.

23

ECCENTRIC

- SEGMENT A1

- OUARTER-ROUND

Fig. 2-6. Various types of orifice meter plates. (Courtesy of Daniel Industries, Inc.)

In addition to having the hole concentric (centered) in the orifice plate, the orifice can be eccentric (off center) or segmental (part of a circle) as shown in Fig. 2-6. The two latter types are often used when there are solids in the flow stream, such as in dirty gases or slurries. For a square-edged orifice, a square, sharp edge faces the flow, whereas the downstream edge is tapered (beveled). For high-velocity fluids, a quadrant (quarter-circle) edge or conic (conical) entry orifice can be selected. Both of these concentric orifice devices have a square edge downstream with a rounded radius or a conical taper facing upstream.

The fitting that holds the orifice plate and provides pressure tap locations can be as simple as orifice flanges (Fig. 2-7). It can be as sophisticated as a double chamber, however, where the orifice plate can be changed under pressure, without interrupting the flow (see Fig. 2-8). The intermediate fitting is shown in Fig. 2-9. It allows the orifice plate to be quickly changed without breaking open the pipe. This eliminates liquid spillage and pipe movement due to spreading flanges. Inasmuch as the design of these single chamber devices does not allow the orifice plate to be changed under pressure, a bypass line or pressure release (depressurizing) is necessary.

Pressure taps can be of the flange, pipe, vena contracta, or corner design. Pressure taps, however, are generally of the flange type, where the pressure is

24

Bar I

Fig. 2-7. Orifice plate holder. (“Simplex”, courtesy of Daniel Industries, Inc.)

measured one inch from the upstream face plate and one inch from the downstream face of the orifice plate (see Fig. 2-10). The other common type is the pipe tap, shown in Fig. 2-11. Pipe taps are located 2: pipe diameters (ID’S) upstream and 8 pipe diameters downstream (where the pressure recovery is maximum). This allows a smaller meter run to be used for the same flow rate, but requires location tolerances ten times those for flange taps. The vena contracta is the location of the minimum cross-sectional area of flow, where the minimum pressure and maximum velocity occur.

The pressure taps, shown in Fig. 2-12, are located one pipe diameter (ID) upstream and at the vena contracta downstream. Although these taps give a greater pressure drop that results in better accuracy, the downstream location varies between 0.9 and 0.3 pipe diameters for beta ratios (orifice diameter divided by the pipe ID) ranging from 0.1 to 0.8 (Taylor Instruments “Flow Data”, p. 50). They are, therefore, usually used for fairly constant flow rates. Finally, corner taps (see Fig. 2-13) are located immediately adjacent to the upstream and downstream faces of the orifice plate. They are used primarily in Europe.

The term orifice meter commonly designates a flow meter that uses an orifice plate. It should be noted, however, that flow nozzles, flow tubes, and venturi meters are also classified as obstruction or differential head (pressure) meters and, sometimes, referred to as “orifice meters”. According to Bernoulli’s equation, the square

25

Fig. 2-8. Senior orifice fitting. (Courtesy of Daniel Industries, Inc.)

Fig. 2-9. Junior orifice fitting. (Courtesy of Daniel Industries, Inc.)

26

Fig. 2-10. Flange-type pressure taps. (Courtesy of Grove Valve and Regulator Company.)

Fig. 2-11. Pipe pressure taps. (After hchards, 1947, p. 15.)

Fig. 2-12. Vena contracta taps. (After Richards, 1947, p. 14.)

n

f h

Fig. 2-12. Vena contracta taps. (After Richards, 1947, p. 14.)

27

Fig. 2-13. Corner pressure taps. (After Richards, 1947, p. 13.)

root of the differential pressure is proportional to the velocity, and hence, the flow rate (see Appendix 2.1).

Turbine meters

The turbine meter principles were described in the earlier section on liquid flow rate measurements. In the past, there was very little incentive for measuring gas rates due to its low cost. With the increase in prices, however, gas flow-rate

A stagnation zone is located between the shedding body and the sensing vane. The location or attachment of this zone is controlled by vortex shedding. A significant flow around the shedding bodx opposite the side which has the vortex, goes between the shedding body and the sensing vane. The flow then goes through the opening in the sensing vane, resulting in a torque on that body This oscillating torque is brought to the outside of the meter body through a torque-tube assembly and is sensed externally

The V3 flowrneter incorporates advanced fluid mechanics techniques which combine vortex shedding with fluidics (the Coanda effect), resulting in superb operating characteristics.

Fig. 2-14. Principles of vortex shedding meters. (Courtesy of Fischer and Porter Co.)

28

measurement has become more important; therefore, turbine meters have been, and are being, developed in order to give automated accurate measurement of gas flow rates. Positive displacement meters have been used in residential locations, but have not received widespread usage in the oilfields.

Positive displacement meters

Many positive displacement meters used to measure gas flow are on distribution lines. They typically measure the cumulative volume of gas through the line and operate on the same principle as for liquid flow. Positive displacement meters measure a given volume for each cycle or revolution.

Vortex shedding meters

The vortex shedding principle is used primarily for gas measurements, but can also be used for liquid flow rate measurement. It involves measuring the vortex shed behind a body of a certain shape (shown in Fig. 2-14) and then inferring the flow rates from this information. These type of meters have been used more often for gases than for liquids. Some manufacturers, however, claim the use of the same flow device for both liquids and gases (see Fig. 2-15), whereas others have separate units.

Fig. 2-15. Vortex flow meter for fluids. (Fischer and Porter Series 10LV3000 vortex flowmeters.)

29

OTHER TYPES OF FLOW RATE MEASUREMENT

Mass flow rate, two-phase flow rate and miscellaneous/or special flow rate meters are covered in t h s section. Mass flow rate is sometimes of greater value than volumetric flow rate. Two-phase flow of liquid-liquid, gas-liquid, solid-liquid, or solid-gas is important in the petroleum industry. Special or miscellaneous flowmeters utilize magnetic and ultrasonic flow measurement techniques.

Muss flow rate

Mass flow rate can be measured by various devices. The mass flow rate can be obtained by direct measurement or by measuring volumetric flow rate and then calculating the mass flow rate based on density information. Direct methods include vibrating tubes (see Fig. 2-16) and heat transfer (often cooling). Densities can be

Fig. 2-16. Mass flowmeter. (Courtesy of Micromotion, Inc.)

30

provided by temperature and pressure compensation, by radiation attenuation, or by other methods.

Two-phase systems

Although it is generally better to measure each phase separately in two-phase flow, it is not always possible. When it is necessary to measure the flow rate of a two-phase stream, most techniques only give approximate values.

Special flow meters

Although magnetic flow measurements provide obstructionless flow, the fluid has to be electrically conductive; therefore, magnetic techniques will not work in all oil systems, unless the oil is the dispersed phase.

Fig. 2-17. Magnetic flowmeter. (Courtesy of Fischer and Porter, 81000a, 10D1475, Mini Mag.)

31

Magnetic flowmeters are also called electromagnetic flowmeters. As indicated earlier, they can only measure the flow rate of electrically conductive fluids such as water, acids, frac fluids, and water-base and oil-in-water emulsion drilling fluids. They will not work with some oil systems, where oil is the continuous phase. The magnetic flowmeters have good accuracy, low pressure loss (low head loss due to friction), good rangeability, and the capability for difficult-to-handle fluids such as acids, slurries, and viscous liquids. Inasmuch as the meter is non-intrusive, it does not disturb the flow (see Fig. 2-17). Accuracies of f0.5% of rate are often quoted for typical velocities, which range from 1 ft/sec to 30 ft/sec. At lower velocities, the accuracy is 0.005 ft/sec. Rangeabilities of 30 : 1 are typical, with meters having rangeability of 50 : 1 being available. Temperature ranges from 0 to 360 F and pressure ratings up to 740 psi are possible.

Meters range in size from 0.1 to 18 in., with flow rates ranging from less than 0.1 gpm to more than 100,000 gpm.

Continuous Ultrasonic signal is frequency (doppler) shifted by reflections from entrained particles/bubbles moving with the flow stream. Computed volumetric flow rate is dependent and variable with liquid's sonic velocity, temperature, particle size and concentration precluding predictable and stable computation in many applications.

@

Difference of transmission time of sonic pulses in upstream vs. downstream direction is directly proportional to flow velocity. Volumetric flow rate is computed independent of liquidk sonic properties and includes compensation for flow profile.

Fig. 2-18. Comparison of two ultrasonic flow measurement principles. (Courtesy of Controlotron Corporation.) (a) Doppler shift. (b) Pulse time difference.

69

32

Ultrasonic meters have recently been used in oilfields due to their non-intrusive nature. There are difficulties with these systems, however, such as effects from gas bubbles, solids, etc. There are basically two different principles: (1) Doppler and (2) transmitted energy. The Doppler technique utilizes the reflections of the energy off particles (see Fig. 2-18.a), whereas the other transmits energy across the flow stream from one transducer to the other (see Fig. 2-18.b).

SIMPLE EQUATIONS FOR MEASURING WEIGHT FLOW RATES FOR GASES A N D LIQUIDS

American Gas Association (1956) proposed the following equation for measuring flow rate of gases using orifice meter.

W, = 1.0618 F b F , Y f i (2-1)

where: W, is the weight flow rate in lb/hr, Fb is the basic orifice factor, F, = Reynolds number factor, Y is the expansion factor, h , is the differential pressure in inches of water, and y, = specific weight of flowing gas in lb/cu ft .

For natural gas liquids, Foxboro (1961) proposed the following simplified equation:

W, = 68,045 Sdi\jh,SG,

where: W, is the weight rate of flow of liquid in lbjday, S is the constant based on the bore of the orifice and internal diameter of the metering tube, di is the inside diameter (ID) of tube in inches, h , is the differential pressure in inches of water, and S G , is the specific gravity of flowing liquid.

Excellent discussion of the subject together with orifice meter tables necessary for calculations were presented by Ikoku (1984).

SAMPLE PROBLEMS A N D QUESTIONS

(1) Determine the flow rate of gas in lb/hr using 1.5-in. orifice meter at 60°F and 14.7 psia, given the following data: h , = 25 in. of water, di = 3.438 in. (ID), SG, = specific gravity of gas (with respect to air = 1) = 0.72, and Tf = 80°F; ps =

(static pressure upstream) = 40 psig (Consult Ikoku (1984) for various factors). ( 2 ) Define the following components of the orifice flow constant: C': Fb, F,, Y ,

(3) Sketch three types of orifice plates and briefly outline the advantages of each. (4) Briefly describe the operation of a pneumatic integrator. (5) Describe steps in proper selection of an orifice meter. (6) List uncertainties in flow measurements. (7) Air flows through a 6-in. by 3-in. Venturi meter. The gage pressure is 30

Yl, Y,, Ym, Fpb, &, F g r F p v , F m , 4, and F a .

33

lb/in.’ and the temperature is 60 F at the base of the meter. Differential manometer shows a reading of 7 in. of mercury and the barometric pressure is 14.70 psi. Calculate the flow rate.

APPENDIX 2.1-DEVELOPMENT OF ORIFICE METERING ’ L.J. KEMP and GEORGE V. CHILINGARIAN

History

The first record of the use of orifices for the measurement of fluids in a closed conduit was left by Giovanni B. Venturi, an Italian physicist, who in 1797 did some work that led to the development of the Venturi meter by Clemons Herschel in 1886. Apparently, the first orifice meter to be used in the measurement of gas was installed near Columbus, Ohio, about 1890 and was designed by Professor Robinson of Ohio State University.

About 1903, T.R. Weymouth began a series of tests in Pennsylvania which led to the publication of coefficients for orifice meters with flange taps. At about the same time, E.O. Hickstein made a similar series of tests in Joplin, Missouri, from which data were developed for the calculation of coefficients for orifice meters with pipe taps. At this time, differentials were still measured as instantaneous readings observed at regular intervals on glass tube water manometers. It was not until a mercury manometer had been developed into a recording differential gauge, that the orifice meter became feasible for commercial use.

A great deal of research and experimental work was conducted by the American Gas Association and the American Society of Mechanical Engineers between 1924 and 1935 in developing (1) better data from whch orifice meter coefficients could be calculated, and (2) better standards for the construction of orifice meters. The summary of this work was published in 1935, as a joint report by the two participating organizations (see AGA-ASME, 1935). This report is the basis for almost all present-day orifice meter measurement. In the same year, bulletins containing only the material pertinent to the measurement of natural gas by orifice meters were published (AGA, 1935; CNGA, 1935).

In 1941, the California Natural Gasoline Association ’ (CNGA, 1941) published the data necessary for the determination of the coefficient for the measurement of natural gas by the orifice meter, and in 1947 (CNGA, 1947), the data to cover supercompressibility for pressures in excess of 500 lb (psig).

In 1955, further data (AGA, 1955) were made available; and in 1956 a couple of earlier bulletins were combined and brought up to date (CNGA, 1956), and

’ This Appendix represents Chapter 7 in “Surface Operations in Petroleum Production” by G.V. Chilingar and C.M. Beeson (1968). * California Natural Gasoline Association’s Board officially changed the name of the Association to Western Gas Processors and Oil Refiners Association on June 14, 1966.

34

augmented by data on pressures ranging from 500 to 3000 lb and for meter runs up to 30 in. in diameter. The latter were developed from tests at Refugio, Texas, performed under the combined auspices of the American Gas Association and the American Society of Mechanical Engineers. These tests were initiated because the phenomenal expansion of the natural gas industry brought about the great networks of very high-pressure and large-diameter transmission lines.

The U.S. Bureau of Mines has been conducting tests at Amarillo, Texas, for the development of data for the calculation of coefficients, using eccentric and segmental orifices. These are used primarily where it is necessary to measure fluids that are dirty or gases that are wet. The National Bureau of Standards also has conducted extensive tests to determine appropriate installation specifications for orifice meters in view of various pratices of measurement.

Considerable work has been done by the American Gas Association (AGA, 1962) reverifying the validity, and extending the scope, of their former work on supercompressibility, and developing a set of formulas for the calculation of correction factors. The CNGA (1963) has published the formulas and methods for computer application of large orifice meter volume calculations.

Definition of orifice meter

An orifice meter is a conduit and restriction to produce a pressure drop owing to a change in velocity of the fluid. The roughest forms are probably a valve or an elbow.

Figure 2.1-1 shows an elbow meter that is actually used for measurement. The best and most expensive orifice meter is the Venturi meter. Between these two extremes are many other kinds incorporating many different shapes, but the better

U

Fig. 2.1-1. Diagrammatic sketch of elbow meter

35

Concentric Eccenlric Segrnentol

Fig. 2.1-2. Types of orifice plates

the nozzles and plate-type orifices. The latter, because of their ease of duplication and simple construction, have become almost the standard in commercial orifice meter measurement. The most common of the plate-type orifices are the thin sharp-edged concentric orifice plates (Fig. 2.1-2), which are used almost universally in the measurement of natural gas. The eccentric and the segmental orifice plates (Fig. 2.1-2) are used when entrained liquids are present.

Operation of orifice meter

Figure 2.1-3 shows a conduit with a number of water-column pressure taps and a restriction in the form of a plate with an orifice. If one assumes that the conduit is filled with a liquid at rest under sufficient pressure so that the liquid would rise to the top of the first column, then it would also stand at the top of all the other columns. Now, if a downstream valve is opened and a fixed rate of flow established under perfect flow conditions, the height of the water standing in each of the columns would be reduced according to a pattern similar to that indicated by the darkened areas in the columns. The darkened segment of the column would then represent the static pressure head existing at that point in the conduit. The unfilled

Pipe Diameters

Mercury --

Differential

Fig. 2.1-3. Principle of flow measurement.

5

36

portion of the column would represent the velocity pressure head plus the loss in pressure due to friction. The total pressure in the first column can be expressed as being equal to the total pressure in any subsequent column in the following manner (also see Appendix 1.1 in Chapter 1 of Vol. I):

where p l / y = pressure head (static) at a given point in ft, V,’/2g = velocity head at the same point in ft, Z = potential head in ft ( Z , = Z,), H = total head in ft, h,, = head loss due to friction in ft, and y = specific weight of flowing fluid in lb/cu ft.

The preceding equation is an expression of Bernoulli’s Theorem. Inasmuch as for any reasonable range of flow of a given fluid the value of hlf between any two points across and close to the orifice meter should remain relatively constant and, with a well-constructed metering set up, should be relatively small in comparison with the velocity pressure, the difference between the static pressure as indicated by any two columns will represent primarily the difference in the velocity pressures. This differential pressure, therefore, is directly proportional to the square of the velocity and can be used to measure rates of flow. Figure 2.1-4 shows a diagrammatic sketch of a standard “flange tap” type orifice meter. On all meters of this type, the differential take-offs are located 1 in. upstream and 1 in. downstream of the orifice plate. This locates the downstream tap very close to the uena contracta as shown in Fig. 2.1-4. These flange tap meters were used almost exclusively in the Pacific Coastal areas. Principally there are two other standard types of take-offs or taps used in orifice measurement work. The first one is the “corner tap” where the take-offs are immediately adjacent to the plate face. This type is used primarily in

Fig. 2.1-4. Diagrammatic sketch of flange tap type orifice meter.

37

Europe. The second is the “pipe tap” wherein the take-offs are located 2; diameters upstream and 8 diameters downstream. Pipe tap meters were used primarily in the central and eastern portions of the United States.

Figure 2.1-3 shows that there is a considerable difference in the indicated differential velocity heads for a given flow rate with the different types of taps. The corner and flange taps give a considerably greater differential than do the pipe taps for the same rate of flow. For this reason, it is extremely important that the data used for calculation of the orifice meter coefficient be selected on the basis of the differential taps being used.

Description of orifice meter

The basic principle of the orifice meter is to produce as near-ideal conditions of concentric turbulent flow as possible. The meter consists of an upstream tube and a downstream tube connected by an orifice plate fitting. Originally, these tubes were made extremely long in order to produce the best possible concentric flow condition. This sometimes resulted in meters being as much as 35-40 ft in length. Later, by the use of straightening vanes (Fig. 2.1-5) and very accurately bored tubes, the over-all length of the meter was considerably reduced and a standard 3-in. orifice meter is now only approximately 6 ft in length.

The orifice meter fittings, which connect the upstream and downstream tubes, are designed so that the orifice plate will be properly positioned in the run and so that it can be removed without disturbing the runs. These fittings are of two general types. The first one is called a “junior fitting” (Fig. 2.1-6). With t h s fitting it is necessary to by-pass the flow of gas around the meter runs or shut it off and bleed the gas

Fig. 2.1-5. Straightening vanes, pin and flange types. (Courtesy of Daniel Industries, Inc., Houston, Texas.)

38

Fig. 2.1-6. Cutaway of a junior orifice plate fitting. (Courtesy of Daniel Industries, lnc., Houston, Texas.)

remaining in the meter runs to the atmosphere, before the plate can be removed. Bleeding this amount of gas sometimes poses a problem, particularly in closely-built areas. Even where a solid by-pass is used, there is always a hazard in the by-pass operation that the flow may be interrupted accidentally and in many cases this can cause serious or very hazardous problems. Because these plates must frequently be removed to check the condition of the edge of the orifice and to see that there is no

Fig. 2.1-7. Senior orifice plate fitting. (Courtesy of Daniel Industries, Inc., Houston, Texas.)

39

dirt buildup on the plate, a better method was desirable. As a result, the “senior orifice fitting” (Fig. 2.1-7) was developed. With this type, the plate can be cranked into the upper chamber, which is outside and sealed from the meter run by a sliding valve. The small amount of gas in the upper chamber is then bled to the atmosphere and the plate removed. It is not necessary to interrupt, nor is it possible to

Fig. 2.1-8. (a) Cutaway of differential mercury manometer, and (b) details of float and stuffing box assembly. (Courtesy of American Meter Co., Fullerton, California.)

40

accidentally interrupt, the flow. A solid by-pass is not required and usually considerable time is saved on each inspection.

So far, the two variables which are necessary for determining measurement have only been shown as instantaneous readings on a water column. For the purposes of measurement, it is necessary that these be recorded so that the calculated volumes may be computed. The first method of doing this was the development of the mercury manometer into a recording differential gauge. A cutaway view of the manometer and float assembly sections for a gauge of this type is shown in Fig. 2.1-8. By connecting the high and low side taps to the high and low side pots in the gauge, a mercury differential manometer is formed. As the differential pressure changes, the mercury level in the low-side pot changes and the float moves up or down. As this float changes position, it imparts a rotary motion to the pen-arm shaft. This pen-arm shaft extends through a stuffing box in the wall of the low-side pot and into the case of the gauge. The stuffing box seals the pressure within the pot and prevents leakage of gas. A pen arm fastened to the outboard end of this shaft then records the differential pressure on a chart within the gauge case. The recorded

I

Fig. 2.1-9. Typical orifice meter chart and recording. (Courtesy of Graphic Controls Corporation, Buffalo. New York.)

41

CENTER ROD

LEVER __

Fig. 2.1-10. Cutaway of bellows section of dry type of differential recording gauge. (Courtesy of American Meter Co., Fullerton, California.)

differential of a typical flow pattern is shown as a weaving line on the chart (Fig. 2.1-9). The smoother line on the chart represents the static pressure. This static pressure is recorded by a pen arm fastened to a pressure element which is installed in the differential recording gauge case. The connection to the pressure element is made from the low-side pot and represents the static pressure existing at the downstream tap on the meter run, which is the tap that is normally used. The upstream tap could be used, however, provided that the proper data is incorporated into the coefficient to take into account.

Another recording differential gauge-known as the bellows type- has been developed next. Figure 2.1-10 shows a cut of the body of this type of gauge. Any change of differential pressure between the two chambers causes a movement of the bellows to a new position of equilibrium. The movement of the bellows imparts a motion to a pen-arm shaft, which protrudes through a stuffing box in the chamber wall into the gauge case. The pen arm then records the differential pressure on the chart. All of the parts within the case of this type of differential gauge are identical with those used for the mercury-type gauge. The bellows within these gauges contain oil, and the flow of the oil from one side to the other can be regulated by the dampening screw. These gauges have one distinct advantage over the mercury gauge in that they do not have to be installed perfectly level.

In either of these two types of gauges, the differential and static pressures are recorded on a chart, and it remains necessary to calculate the amount of gas used,

42

from the chart. The chart (Fig. 2.1-9) is divided by a scale that runs from “0” at the center to “lo” at the outer edge, and it is a square-root scale. Therefore, a flow change of one chart unit is equal to about in. of pen travel on the chart between 2 and 3, and the same rate of flow change is equal to almost an inch of pen travel on the chart between 9 and 10. One can readily see that the accuracy of recording and calculation from the chart is greatly reduced at the very low ranges. For meters where the flow drops below 3 on the chart for any appreciable amount of time, a second recording differential gauge can be set in parallel with the standard (whch is probably a 50-in. or 100-in. gauge), where the differential at 10 on the chart is equal to 50 in. or 100 in. of water. Ths second gauge, known as a 10-in. because the differential at 10 on the chart is equal to 10 in. of water, actually enlarges the portion of the 50-in. or 100-in. chart between “0” and approximately “4” to the full scale. This is done by using a different set of mercury pots, or a different arrangement with the linkage, so that a given displacement of mercury, or a given linkage movement, causes a much greater movement of the recording pen. Where square-root charts are used, the charts would be identical on both gauges, but different coefficients would be used, which would take into consideration the difference in the manner in which the flow is indicated on the charts.

If the rate of flow for a given meter increases to where the differential pen travels off the upper limit of the chart, a large orifice plate would then be installed in the meter so that the reading would again be recorded on the chart. The coefficient

Fig. 2.1-11. Automatic chart changer. (Courtesy of American Meter Co., Fullerton, California.)

43

Fig. 2.1-12. Orifice meter chart planimeters. (Courtesy of American Meter Co., Fullerton, California (a); and the Foxboro Co., Foxboro, Massachusetts (b).) D and F are key tracing components.

44

would then be changed to take care of the difference in the recorded data. If, on the other hand, there is an appreciable change in the metering pressure so that the pen actuated by the static pressure element ranges off the chart, a higher range pressure element would be installed in the differential gauge to bring the recording back within the range of the chart. Again, the coefficient would be changed to reflect this change in recording.

In other words, where square-root charts are used, the same chart can be used for all the different ranges of metering pressures and flow rates possible with any given meter. This is not true for direct reading gauges, whch require special charts for each different static and differential pressure range.

Once the recording has been completed, it is necessary that the chart be removed and a new one installed. As the location of the meters may be quite a distance from the office, this chart-changing function can become quite expensive. For this reason accuracy often is sacrificed by using 7-day rotation charts in place of 24-hour rotation charts. The development of automatic chart changers made this no longer necessary for they allow loading of several charts at one time. The charts then change automatically and thus, seven 24-hour rotation charts can be picked up with a trip to the meter once a week. One type of automatic chart changer is shown in Fig. 2.1-11.

To compute the volume of gas measured by the meter, it is necessary to calculate and convert the recorded data from the chart into gas volume measured. This can be done by visual reading of the chart. By this method, small segments of the

Fig. 2.1-13. Mechanical chart integrator. (Courtesy of Flow Measurement Co., Inc., Tulsa, Oklahoma.)

45

differential would be averaged from the chart by sight. The static pressure for the equivalent period of time would then be averaged visually from the chart, and these two values multiplied together. These values would be accumulated for the entire chart, and then multiplied by the coefficient to get the actual volume of gas measured. This, however, is a very slow process.

Where fairly good regulation can be maintained so that a constant static pressure is achieved, then an ordinary planimeter can be used to compute the differential value from the chart. This value multiplied by the static pressure and the coefficient will give the measured volume. Special planimeters (Fig. 2.1-12) were developed whch were somewhat easier to use because they were designed for use with the circular chart.

To take care of all types of applications and to save time, a special type of integrator-known as the McGaughy-was developed. One of these is shown in

Fig. 2.1-14. Electroscanner (automatic chart scanner); schematic diagram showing optical scanning system and the optional output systems. (Courtesy of UGC Instruments, Inc., Shreveport, Louisiana.)

46

Fig. 2.1-15. Pneumatic orifice Foxboro, Massachusetts.)

meter

(a)

integrator (a)

ITn"C4NT

(b)

n I"=

t ,I ,a 1,R I Y I I L "

and schematic (b). (Courtesy of the Foxboro Co.,

Fig. 2.1-13. The chart is placed on t h s machine, and the operator simultaneously traces both the differential and static recordings on the chart. The integrator continuously multiplies these two values, records them on a counter, and the total for the chart can then be multiplied by the coefficient to get the measured volume. One operator using this machine can do work equivalent to that done by approxi-

Fig. 2.1-16. Electrical orifice meter integrator. (Courtesy of American Meter Co., Fullerton, California.)

47

Fig. 2.1-17. (a) Mechanical add-on orifice meter integrator and (b) cutaway. (Courtesy of Barton Instruments, Monterey Park, California; and Kingman-White, Inc., Placentia, California.)

mately seven or eight people doing the same operation by sight reading. Even with these expensive machines, the collecting of charts (24-hour; 48-hour; or 7-day) and their integration was still a time-consuming operation.

An automatic “scanner” was then developed, which uses an electro-optical scanning section and an electronic computing section. The operator places the chart on the turntable, presses the “start” button, and the most difficult chart can be automatically read in ten seconds. This has tremendously speeded up the chart reading operation and increased the accuracy by eliminating operator error. A schematic drawing is included as Fig. 2.1-14.

Improved models of integrating differential meters and computers were then developed. The integrators automatically multiply the differential and static pressures mechanically at the meter and accumulate the products on a counter. The computers perform the same functions electronically. If these were to be developed to the point that they were reliable and accurate enough for commercial measurement, they would make possible the elimination of the chart collection and manual integrating functions. A Foxboro pneumatic integrator is shown in Fig. 2.1-15, whereas Fig. 2.1-16 shows an American Meter Company Vareco electric-driven integrator. Figure 2.1-17 shows a Kingman-White unit that has been added to the existing Burton differential gauge. The integrating mechanism is shown by the cutaway. A Daniel Industries flow computer is shown in Fig. 2.1-18.

48

Fundamentals of measurement

Outline of basic laws for ideal gases (A) Basic relationship The combined pressure-volume- temperature relationship (expressed in terms of

energy) is

p V = n R T

where R = gas constant for perfect gas, n = number of moles of gas, T = absolute temperature, p = absolute pressure, and V = volume.

EXTRACTOR

T

FLOW RATE INDICATOR

Fig. 2.1-18. (a) Orifice meter computer and (b) schematic. (Courtesy of Daniel Industries, Inc., Houston, Texas.)

49

(B) Boyle’s Law- V is inversely proportional to p The volume ( V ) occupied by a given mass of gas varies inversely with the

absolute pressure ( p ) if the temperature is not allowed to change. Figure 2.1-19 illustrates the principle of Boyle’s Law. The first cylinder shows a

volume V, of gas at atmospheric or an absolute pressure of 14.73 lb/in2. If this pressure is increased to 29.46 lb/in2 absolute, then the volume would be decreased to one-half of its original volume.

(C) Charles’ Law- V is directly proportional to T, The volume ( V ) of a given mass of gas is directly proportional to the absolute

temperature (T,) if the pressure is fixed. The first cylinder shows (Fig. 2.1-20) a volume of gas V, at 60 O F or 520 O absolute. If the temperature is raised to 580 O F or 1040 O absolute ( OR), then the volume Vb would be equal to 2Va.

(0) Dalton’s Law-Partial pressures Each gas of a mixture of gases exerts a partial pressure equal to the pressure

which the same mass of the gas would exert if it were present alone in the given space at the same temperature. Essentially, the law implies independence of action of the molecules of a mixture.

(E) Auogudro’s Law-Molecular weights Under the same conditions of temperature and pressure, equal volumes of all

gases contain the same number of molecules. (F) Henly’s Law- Solubility of gases At any specified temperature, the mass of gas which will dissolve in a given liquid

(G) Raoult’s Law-Vapor pressure The vapor pressure of a component of a solution is directly proportional to its

molal concentration in the solution and to the vapor pressure of the substance in a pure state at the specified temperature.

Deviations from the Ideal Gas Law Actually, gases do not behave according to the ideal gas laws, because in the

formulatih of these laws the fraction of the total volume of a gas, which is actually

is proportional to the partial pressure of the gas in contact with the solution.

Fig. 2.1-19. Illustration of Boyle’s law.

50

460 t 580 - 1040 520 460+60 v, -=2v vb=v, ~-

Fig. 2.1-20. Illustration of Charles’ law.

occupied by the molecules themselves, has been neglected as well as the potential energy effects that the molecules have on each other. If these factors were taken into consideration, more complex and more accurate equations would result. Inasmuch as it is yet too difficult to take care of these factors exactly on theoretical grounds, the attempt has been made by many workers to do so empirically, that is, on the basis of experimental tests. Of the many equations which have been suggested, those of van der Waals or Beattie and Bridgeman are the best known.

The phenomenon described above is often referred to as the supercompressibility of gases. For actual gases, the volume will decrease more than the amount indicated by Boyle’s Law, because as the distance between the gas molecules becomes smaller their attraction for each other becomes an increasingly important factor and brings them even closer together. At very high pressures the repellant forces of the molecules come into play and tend to reverse the effect.

When a gas expands, the converse is true, and a greater volume results than would be indicated by Boyle’s Law. This is known as “ superexpansibility”.

An analog to the supercompressibility effect is shown in Fig. 2.1-21. If a spring has a force of 14.73 Ib acting on it and the length is d , it can be so designed that a force of 29.46 Ib would decrease this length to d/2. Now, if a set of magnets were added in the right set of schematics and d is great enough for their attractive force to be negligible, then the length would remain d as shown in the top illustration. When the additional 14.73 lb are added and the distance d/2 is small enough for their attraction to become a factor, then the spring will be compressed by a distance somewhat greater than d/2 due to the attracting force of the magnets.

Basic flow formula (q = C �Jhp) In this equation, p represents the static, or line pressure, as measured at the

downstream tap of the orifice meter and h is the differential pressure. As shown in

51

Deflection Proportional to External Force

Deflection Proportional to Attrmtive and External Force

Fig. 2.1-21. Illustration of the effect of supercompressibility.

Fig. 2.1-22, an increase of the line pressure from 14.73 1b/im2 absolute to 29.46 1b/h2 absolute has a double effect on the flowing volume. The higher pressure makes the gas heavier so that less volume flows through the orifice; but inasmuch as that which does flow has been compressed by a factor of two due to doubling of the absolute pressure, the combined result is that the flow in standard cubic feet has been increased to 141% of the original.

Orifice flow constant (C') Because the basic flow formula appears to be so simple, one may wonder where

all these laws become involved in the measurement calculations. The orifice flow constant, C', can be expressed as follows to show its most important components:

C'= Fb X Fpb X F& X M X &, X FR X Fpv X FG X FT X I X CR X 4 X FM

A\\\\\\\\\\\\\\\\\\\\? pi = 14.7~ I QI = Flowing Volume 1 I p7 = 2p, = 29.46# I Q2 = Flowing Volume 2 = 1.41 QI I

Fig. 2.1-22. Effect of pressure on volumetric rate of flow.

52

G = l

The derivation of some of these factors is very complex. Actually, several factors can be determined only by very extensive tests and experimentation, from which tables of data have been accumulated so that a value may be obtained. The definition of the factors in the above equation are as follows:

Fb is the basic orificeflow factor. This is dependent upon the location of the taps, the internal diameter of the run, and the size of the orifice.

Fpb is the pressure base factor. Most locales use 14.73 lb/in.2 as a standard base. This is the pressure base adopted by the American Gas Association for its standard, which represents atmospheric pressure at sea level. This factor is a direct application of Boyle's Law in the correction for this difference in base.

Cb is the temperature base factor. Temperature of 60 F is almost universally used as the base temperature in calculating gas measured by orifice meters. If it was desired to calculate the measurement, however, on some other contract temperature base, t h s factor would be used in a direct application of Charles' Law to correct for this change.

M is the M factor. This is the correction applied because of the use of a square root chart.

F, is the specific gravity factor. This is the factor that is used to correct for changes in the specific gravity. With a given force being applied on a gas, a larger quantity of light-weight gas can be pushed through an orifice than that of a heavier gas. Inasmuch as the flow varies according to the square root law and as shown in Fig. 2.1-23, twice as much gas having a specific gravity of 0.25 will flow through the orifice as there will of gas having a specific gravity of 1.0: FG = p.

FT is the flowing temperature factor. The flowing temperature has two effects on the volume. A higher temperature means a lighter gas so the flow will increase. The higher temperature causes the gas to expand which reduces the flow. As shown in Fig. 2.1-24, a temperature increase from 520 to 1040"R causes the weight to be one-half what it was before, so the volume is increased by the square root of 2.

Q 1

F . = G

\\\\\\\\\\\\\\\\\\\\\\\\\\\\\

G1z.25 Q X F,= 2Q

A\\\\\\\\\\\\\\\\\\\\\\\\\\\ - d Y

Fig. 2.1-23. Effect of specific gravity on volumetric rate of flow.

53

Fig. 2.1-24. Effect of temperature on volumetric rate of flow.

When this is corrected to the temperature base of 520 O , the volume is reduced by one-half. Thus, as a result of doubling the absolute temperature, the flow in standard cubic feet is actually reduced to 70.7% of Q,.

FR is the Reynolds number factor. This dimensionless factor is dependent upon the viscosity ( p ) , density (p), and velocity of the gas (V), and the pipe diameter (D): FR = VDp/p.

Fe2 is the expansion factor. Unlike fluids, when a gas flows through an orifice, the change in velocity and pressure is accompanied by a change in the density. This expansion of the gas is taken into account by the expansion factor, which is a function of the differential pressure, the absolute pressure, the diameter of the pipe, the diameter of the orifice, and the type of taps.

Fpv is the superexpansibility factor. This factor corrects for the fact that gases do not follow the ideal gas laws. It varies with the temperature, pressure, and specific gravity.

I is the integration instrument factor. This factor converts the machine read-out values into units compatible with the flow equation. It is 0.4472 for the McGaughy integrator and 0.2400 for the UGC Instruments electroscanner.

CR is the clock rotation factor. This converts the chart rotation factor back to that for a 24-h rotation chart which is used as one. Thus, for a 48-h chart the factor is 2, for a 72-h chart the factor is 3, for a 7-day chart the factor is 7, etc.

Fa is the orifice plate expansion factor. This compensates for the expansion and contraction of the orifice plate at high and low temperatures.

FM is the manometer factor. This is used with mercury differential gauges and compensates for the column of compressed gas opposite the mercury leg. Usually this is not considered for pressures below 500 psia.

Computation of volumes

After the differential pressure, static pressure, and temperature data at the field location have been recorded on charts, the latter must be picked up and taken to some location for processing. For standard gauges this requires trips to the field

54

location once a day, every other day, every third day, or once a week, depending on the chart rotation.

With the advent of automatic chart changers this is no longer necessary. Charts for several days may be loaded at one time. At the completion of recording, the chart automatically changes and several fully recorded charts may be picked up at one time. T h s saves much chart changing time and allows more accurate chart recording because faster rotating charts are economically feasible.

At the central chart processing locations, the charts are integrated or scanned to obtain chart units per period of operation (usually 24 h). These chart units must then be converted to volume by use of the proper basic orifice coefficient and all the related factors. The most proficient manner of doing this is by programming the rather complex calculations on a computer. The California Natural Gasoline Associ- ation has outlined (CNGA, 1963) formulas and procedures which may be used to facilitate this operation.

For those who do not have enough charts to make this economical or because of the unavailability of a computer, a manual calculation of the coefficient [utilizing table values for the various factors obtained from references such as AGA (1955) and CNGA (1947, 1956)] must be made. The purpose of this section is to review the various factors that are used in the manual calculation of an orifice meter gas coefficient and to show how these factors, when used in a standard sequence, allow an efficient procedure of coefficient calculation. The procedures are developed to require a minimum of recalculation when changes in temperature, specific gravity, and supercompressibility occur.

It should be noted that the factor tables in the bulletins (see references) are in the same order as the factor arrangement in the coefficient formula. To expedite coefficient calculation it is advantageous to use a coefficient record form which is designed to be used in the same order.

In order to show how the factor tables are used in the manual computation of a gas coefficient, the appropriate factors from the tables in TS-561 (CNGA, 1956) have been posted on a typical coefficient record card, as shown by Table 2.1-1, in the recommended sequence to compute the following problem:

(1) Meter size = 4 in.; internal diameter = 4.026 in. (2) Connections=flange; gauge connections 1 in. above and 1 in. below the

(3) Chart rotation = 72 h. (4) h,-square root differential reading = 6.0. This value is obtained by averag-

ing the differential readings of several charts prior to the date of the coefficient change. The h , values are read to the nearest whole number and averaged to the nearest tenth.

(5) pSz-Square root chart static reading= 7.40. This value is obtained by averaging the static reading of several charts prior to the date of the coefficient change. The ps , values are read to the nearest tenth and averaged to the nearest hundredth.

(6) Line and orifice = 4 in. (line) x 2.500 in. (orifice) (size of the orifice meter

orifice plate.

TABLE 2.1-1

Coefficient record form and recorded sample data of a 4-in. meter

Meter No. 1000 Remarks: Source of gravity Size 4" Connections: Flange Clock: 72 hr W.L.A. Sta.

Source of temperature

Meter No. 1000

Date h , h / p , Ext. Line and Gauge range C X ( M ) ( M I ) C X ( M I ) X Gauge press. C X ( M I ) X Sp. gr. Temp. C' Comp. CK

- - effective group orifice ( M I ) (FeZFR) (Fez FR FpV -- - psz beta S group C Fe2 FR E P V FGFT

0.631 65 - -

6.0 0.4 I 4X2.500 lOO/SO" 1316.0 40 -~ - 1-30-58 7.40 0.62 (3) 1387.2 0.9487 1.004 1321.3 1.004 1326.6 1.255 1664.9 K C

56

run); and orifice /3 = 0.62. p( = d / D , and termed beta) is the ratio of the diameter of the orifice to the diameter of the meter run. When using flange connected meters, the best measurement is attained with orifice plates having ratios between 0.15 and 0.70.

(7) C = 1387.2. The basic coefficient for a 4 X 2.500-in. orifice (CNGA, 1956, table 321).

(8) Gauge range = 100 lb/50 in., M = square root chart factor = 0.7071 (CNGA, 1956, table 303).

(9) Chart reading method = Rockwell integrator 72-h combined M I factor. I = J100/500 x 100/500 = 0.4472 integration factor for square root charts. MI(72 h) = 0.7071 X 0.4472 X 3 = 0.9487.

(10) F,,-Expansion factor is a function of h , = 6.0, p,, = 7.40, and p = 0.62. (11) FR-Reynolds number factor is also a function of h,, p,,, and p. Combined

( Fe, x FR) = 1.004 (CNGA, 1956, table 330). (12) Fpv-Superexpansibility factor is a function of static pressure, specific

gravity and temperature of the gas. p , , = 7.40 = 40 lb gauge pressure; sp gr = 0.631; flow temperature = 65 OF, and thus Fpv = 1.004 (CNGA, 1956, tables 331 and 335).

(13) FG-(Specific gravity = 0.631). This is one of the most variable of the factors used. It corrects for the specific gravity variation of the gas.

(14) FT-(Flowing gas temperature = 65 OF). This factor corrects for the temperature change in the flowing gas. The combined factors of FG and FT = 1.255 (CNGA, 1956, table 342).

Product of the factors (see Table 2.1-1, coefficient record form)

C X MI X ( F , 2 X F R ) X Fpv X ( F G X F T ) = C ’ (1387.2) x(0.9487) x (1.004) X(1.004) X (1.255) = (1664.9)

Specific gravity and temperature determinations

In the computation of the coefficient, the most variable are the specific gravity and the flowing temperature values. Following are various typical methods by which these values are determined.

Specific gravity

record. (1) Recording gravitometer piped directly to the meter run provides a continuous

(2) Gas sample tanks. (a) Accumulative proportional sample-gas enters the tank only when there is flow through the meter and at a rate proportional to the flow. Usually this is a weekly gas sample. (b) Continuous time weighted sample-gas enters the tank continuously at a uniform rate proportional to time. Usually this is a weekly gas sample. (c) Spot sample-operator fills the tank manually.

(3) Portable specific gravity devices. Using these instruments, spot tests of gas are made in the field.

(4) Source sample-data from one location used by several meters measuring gas from the same or representative sources.

In all cases of gas sampling, great care should be taken to ensure a good sample by adequate purging of the sample tank; or using known initial tank volume and eliminating it through calculations after determination of collected sample volume.

Temperature of flowing gas (1) Recording temperature gauges on the meter. (2) Temporary recording gauge on the meter. (3) Meters with the same temperature characteristic using a base temperature

(4) Ground temperature. (5) Spot temperature with stem thermometer.

location.

Interpreting the recorded temperature value (1) Only flowing temperature should be used. ( 2 ) Large volume-usually no atmospheric influence. (3) Small volume- influenced by atmospheric conditions. (4) After regulators-gas cooled by expansion. ( 5 ) After compressors-gas heated by compression.

Significant figures

(A) When computing orifice coefficients, all computations should be carried to five significant figures.

(B) The number of significant figures given in the tables should be used in all cases.

(C) To determine the last significant figure in any computation, all calculations are carried to one place beyond the number of significant figures desired. When the next figure beyond the desired significant figure is 5 or more, 1 should be added to the last significant figure.

Subsequent changes of coefficients

On a periodic frequency, provided that the orifice plate has not been changed, the coefficients will be changed if the values of the factors change to the extent as follows: (1) h,-More than two units. Example: 4.0-7.0. (2) ps2-More than one unit. Example: 6.0-8.0. (3) Specific gravity-More than 0.005. Example: 0.630-0.636. (4) Average temperature-More than 4" F. Example: 65-70.

Some coefficients are changed on a regular weekly basis and others on a monthly

58

basis, depending upon the volume of gas measured through the meter. (These subsequent changes were made by the Southern California Gas Company before converting to computer calculation. Such procedures may vary in accordance with the standard practices of each company.)

Calculation of (C) for nonstandard internal-diameter meter run

When the internal diameter of the meter run varies from the standard diameter used in the C tables by the per cent allowable in table XII, p. 71, of CNGA (1956), the value of C should be calculated by the formula C = d 2 Z L using L and Z values from CNGA (1956, pp. 88-89, tables 803 and 804). L = Ko/Ko(4) and Z = 338.2 = coefficient of a 4-in. meter having the same /3 value.

Example

where KO = coefficient of the required meter and

Calculation of C for a 6 (5.955 in. internal diameter) X 3.500 in. orifice.

= 0.588 3.500 5.955

/3= -

Maximum allowable tolerance for 6.065 standard run with /3 of 0.59 = 1.3%. Meter run of 5.955 in. diameter = 1.8% variation from standard; therefore, the

Computation of orifice meter gas coefficients. The value of C can be calculated standard C in the tables should not be used.

as follows:

C = d 2 Z L = 12.25 X 218.1 X 0.9985 = 2667.7 d 2 = 12.25; Z = 218.1 (table 804, p. 89); and L = 0.9985 (table 803, p. 88).

The standard coefficient for 6.065-in. diameter X 3.500 in. orifice = 2654.9.

C value of 5.955 in. dia. = 2667.7 C value of 6.065 in. dia. = 2654.9

Difference = 12.8 = + 0.5%

REFERENCES

AGA, 1935. The Gas Measurement Report No. 2. Natural Gas Department of the American Gas

AGA, 1955. Orifice Metering ofNaturul gas, Report No. 3. Gas Measurement Committee of the American

AGA, 1962. Manual for the Determination of Supercompressibility Factors for Natural Gas. American Gas

AGA, 1965. Gas Engineer’s Handbook. Industrial Press, New York, N.Y. AGA-ASME, 1935. History of Orifice Meters and the Calibration, Construction, and Operation of Orifices

for Metering, joint report by American Gas Association and American Society of Mechanical Engineers, New York, N.Y.

Association, New York, N.Y.

Gas Association, New York, N.Y.

Association, New York, N.Y.

59

Bean, H.S., 1967. Flow measurement, Part I : the expanding field of fluid metering. Mech. Eng., April:

Bean, H.S. (Editor), 1971. Fluid Meters. ASME, New York, N.Y., 6th ed. Brooks, Instrument Division, 1978. Brooks - Oval Flowmeters. Statesboro, Geo., 24 pp. CE Invalco, 1980. Turbine Flowmeters. Tulsa, Okla., 16 pp. CE Invalco, 1982. Flow Measurement. Tulsa, Okla., 28 pp. CNGA, 1935. Bull. TS 353. California Natural Gasoline Association, Long Beach, Calif. CNGA, 1941. Bull. TS 402. California Natural Gasoline Association, Long Beach, Calif. CNGA, 1947. Tentative Standard Procedure for the Determination of Superexpansibility and Manometer

Factors Used in Measurement of Natural Gas by Orifice Meter at Pressures in Excess of 500 p i g . Bull. TS 461. California Natural Gasoline Association, Long Beach, Calif.

CNGA, 1956. Tentative Standard Procedures for the Measurement of Natural Gas with Orifice Meters. Bull. TS 561. California Natural Gasoline Association, Long Beach, Calif. [This bulletin combines TS 353 (1935) and TS 402 (1941) with new material added].

CNGA, 1963. Tentatiue Standard for the Application of Gas Measurement Procedures to Computer Usage. Bull. T S 622. California Natural Gasoline Association, Long Beach, Calif.

Chilingar, G.V. and Beeson, C.M., 1968. Surface Operations in Petroleum Production. Am. Elsevier, New York, N.Y., 397 pp.

Controlotron, 1984. Clamp-on Flowmeters. Controlotron Corp., Hauppage, New York, N.Y., 4 pp. Cook, N.H. and Rabinowicz, E., 1963. Physical Measurement and Analysis. Addison Wesley, Reading,

Daniel Industries, Inc., 1979. Daniel Orifice Fittings. Houston, Tex., 8 pp. Daniel Industries, Inc., 1981. Flow Products Division. Houston, Tex., 32 pp. Daniel Industries, Inc., 1982. Orifice Plates and Plate Sealing Units (Catalog 500). Houston, Tex., 8 pp. Diehl, J.C., 1955. Orifice Meter Constants, Handbook E-2. American Meter Company, Fullerton, Calif. Fischer and Porter, 1981. Mini-Mag (foldout), Warminster, Pa., 16 pp. Fischer and Porter, 1982. The New Vortex Flowmeter, Warminster, Pa., 3, 12 pp. Foxboro Co., 1961. Principles and Practices of Flow Meter Engineering. Foxboro, Mass., 8th ed. Gas Processors Suppliers Association (NGPSA), 1972. Engineering Data Book., Tulsa, Okla. Grove Valve and Regulator Company, 1983. QF Orifice Fittings. Grove, Houston, Tex., 8 pp. Halliburton Services, 1981. Special Product Division General Catalog (8 sections). Duncan, Okla. Ikoku, Chi U., 1984. Natural Gas and Production Engineering. Wiley, New York, N.Y., 517 pp. I'M Barton, 1980. Floco Series F Positive Displacement Meters. International Telephone and Telegraph

Katz, D.L., Cornell, D., Kobayashi, R., Poettmann, F.H., Vary, J.A., Elenbaas, J.R. and Weinaug, C.F.,

Kern, R., 1975. How to size flowmeters. Chem. Eng., Mar.: 161-168. Kerr, T.H. (Chairman), 1935. The History of Orifice Meters and the Calibration. Construction, and

Operation of Orifices for Metering (including all data from researchers used in the preparation of the report). AGA-ASME Orifice Coefficient Committee. Boulder, Co.

36-38.

Mass.

Corp., City of Industry, Calif.

1959. Handbook of Natural Gas Engineering. McGraw-Hill, New York, N.Y., 802 pp.

Micromotion, Inc., 1981. The Micromotion Flow Meter. Boulder, Co., 8 pp. Miller, T.E. and Small, H.. 1982. Thermal pulse time-of-flight liquid flow meters. Anal. Chem., 54(6):

Petroleum Extension Service, 1972. Field Handling of Natural Gas. Univ. Texas Press, Austin, Tex. Powers, J., 1979. Flowmeters selection guide. Chem. Process., Oct.: 79-85. Richards, E.C., 1947. Principles and Operation of Differential Meters. Brown Instrument Company,

Philadelphia, Pa., 177 pp. Sandford, J., 1976. What you should know about flow monitoring devices. Instrum. Control Syst., Sept.:

25-32. Spink, L.K., 1958. Principles and Practice of Flow Meter Engineering. The Foxboro Company, Foxboro,

Mass., 8th ed. Templeton, W.J., 1979. Practical Concerns in Metering Fluids from Production Operations, SPE 7802.

Production Operations Symp., SOC. Petrol. Engrs. of AIME, Oklahoma City, Okla., Feb. 25-27, pp. 45-50.

907-910.

Terrell, C.E. and Bean, H.S., 1963. AGA Gas Measurement Manual. New York, N.Y. Tokheim Corporation, 1978. Metering Systems - Engineering Data (10 sections). Fort Wayne, Ind.

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Chapter 3

THE MANUFACTURE, CHEMISTRY AND CLASSIFICATION OF OILWELL CEMENTS AND ADDITIVES

JOHN 0. ROBERTSON Jr., GEORGE V. CHILINGARIAN and SANJAY KUMAR

INTRODUCTION

In 1824, Joseph Aspdin was granted a patent for an artifical cement produced by burning a blend of limestone (CaCO,) and clay. The manufactured product was called “ portland cement” because Aspdin felt it resembled the stone quarried on the Isle of Portland off the coast of England. Portland cement hardens to a set mass when mixed with water (hydraulic product). Blanks and Kennedy (1955) presented a detailed information on the manufacture and materials utilized in the preparation of portland cements (see also Taylor, 1964).

The first case of the use of cement slurries in the United States was in 1903, 43 years after the drilling of Drake’s well. Frank F. Hill of the Union Oil Company is credited with mixing and dumping (by means of a bailer) a slurry of 50 sacks of neat portland cement to shut-off downhole water just above an oil sand in the Lompoc Field in California, U.S.A. (API, 1948). The cement was drilled out of the wellbore and the well was placed successfully on production after 28 days. Controlling or reducing produced water in this manner for oil wells in California quickly spread to other parts of the world.

Dump bailer and tubing placement techniques for cement were improved by the development of a two-plug cementing method, which was introduced into the California fields in 1909 by A.A. Perkin (Tough, 1918). Much of todays oilwell cement technology is based on the Perkin’s technique of cement displacement. The patent issued to Perluns specified the use of two plugs. Later court rulings, however, extended the patent to include any barrier that prevents the cement from mixing with contaminants in front or behind the cement.

The Perkins Co. was primarily a California company, whereas Earle P. Hallibur- ton formed a company in Oklahoma to serve the Hewitt Field, Carter County, Oklahoma. Other companies also were formed to handle the increasing need to solve water problems in oil wells.

CHEMISTRY AND CHARACTERISTICS OF OILWELL CEMENTS

In a broad sense, the word cement denotes any kind of adhesive, whereas in the building industry it denotes a substance utilized to bind together sand and broken

62

stone (or other forms of aggregates) into a solid mass. Concrete, mortars, and various kinds of asbestos-cement products are produced in this manner (see Taylor, 1964).

Hydraulic cement was used to construct early Roman marine docks and facilities found in the Mediterranean area. Such materials were composed of silicate residues from volcanic eruptions blended with lime and water (see Taylor, 1964).

The cement composition is often referred to as hydraulic because cement hydrates when mixed with water (into a paste). Then it sets and hardens as a result of chemical reactions between the water and compounds present in the cement. The setting and hardening times do not depend on drying out of the paste, nor do they depend on processes such as reaction with atmospheric CO,. Setting and hardening occur not only in the presence of air, but also if cement is placed in water. Inasmuch as the final product has a low permeability and is nearly insoluble in water, under normal conditions, water does not destroy the hardened material (see Taylor, 1964).

The thick slurry, called “paste”, is formed by mixing a hydraulic cement, rock aggregate, and water in such proportions that will insure setting (see Taylor, 1.964). The term paste is also used to denote the resultant material at all stages of setting and hardening. The initial stiffening stage, which usually occurs within a few hours after mixing the paste, is called setting, whereas hardening is the stage of development of strength, which slowly increases over a period of time after the mixing and

Fig. 3-1. Four stages in the setting and hardening of Portland cement: simplified diagrammatic representation of the possible sequence of changes. (a) Dispersion of unreacted clinker grains in water. (b) After a few minutes: hydration products eat into and grow out from the surface of each grain. (c) After a few hours: the coatings of different clinker grains have begun to join up, the gel thus becoming continuous (setting). (d) After a few days: further development of the gel has occurred (hardening). (After Taylor, 1964, p. 21, fig. 6; courtesy of Academic Press, Inc.)

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setting of the paste. At ordinary temperatures, portland cement gains strength quickly during the first 48 hours. Strength then slowly increases for periods of up to two years after the mixing. Hydration reactions is a collective term for the reactions that cause setting and hardening. The term curing refers to leaving the paste undisturbed during setting and hardening stages. It can be carried out under various conditions, i.e., in air, under water, or in saturated steam. In the absence of rock aggregate, cement mixed with water is called neat cement paste.

Taylor (1964, p. 4) pointed out that the manufacture of portland type cements involves heating to partial fusion of (1) limestone, (2) clay, (3) iron, and (4) aluminates (see Fig. 3-1). The resulting clinker is then ground and mixed with a small amount (a few percent) of gypsum. The clinker contains four main phases: (1) tricalcium aluminate, (2) P-dicalcium silicate, (3) tricalcium aluminate, and (4) ferrite solid solution (Taylor, 1964, p. 4). The resistance to high temperature and sulfates and the rate of hardening are determined by the relative proportions of the constituents of the clinker and the particle size (fineness of grinding).

CLASSIFICATION OF OILWELL CEMENTS

In the petroleum industry, the portland cement is manufactured to meet specific chemical and physical standards set up by the API (American Petroleum Institute). They are published in the API Standards 10A “Specifications for Oil-well Cements and Cement Additives” (API, 1960). The following standards were described by Smith (1976) for various cements:

Class A : Class A cement is intended for use from surface to a depth of 6000 ft if special properties are not required for the mix. This class of cement is similar to an ASTM C150, Type I cement.

Class B: Class B cement is intended for use from surface to a depth of 6000 ft, when the wellbore conditions require a moderate to high sulfate-resistant mix. Many companies manufacture moderate and high sulfate-resistant mixes. This class of cement is similar to an ASTM C150, Type I1 cement.

Class C: Class C cement is intended for use from surface to a depth of 6000 ft, when conditions require high early strength. This class is available as a moderate or high sulfate-resistant mix.

Class D: Class D cement is intended for use at depths ranging from 6000 to 10,000 ft, where moderately high temperatures and pressures exist in the wellbore. This class of cement is available as a moderate or high sulfate-resistant mix.

Class E : Class E cement is intended for use at depths ranging from 10,000 to 14,000 ft, where high temperatures and pressures exist in the wellbore. This class of cement is available as a moderate or high sulfate-resistant mix.

Class F: Class F cement is intended for use at depths ranging from 10,000 to 16,000 ft, where extremely high temperatures and pressures exist in the wellbore. Ths class of cement is available as a high sulfate-resistant mix.

Class G: Class G cement is intended for use as a basic cement from surface to a

64

depth of 8000 ft as manufactured. On using accelerators and retarders, this cement can be easily modified to be used at a wide range of depths and temperatures. Except calcium sulfate, water, or both, no other materials can be interground or blended with the clinker during the manufacture of Class G cement. This class of cement is available as a moderate or high sulfate-resistant mix.

Class H : Class H cement is intended for use as a basic cement from the surface to a depth of 8000 f t as manufactured. Accelerators and retarders enable its use at a wide range of depths and temperatures. Except calcium sulfate, water, or both, no other materials can be interground or blended with the clinker during manufacture of Class H cement. It is available as a moderate sulfate-resistant mix.

SPECIALTY OILWELL CEMENTS

Smith (1976, p. 9) described a variety of cements, modified by the addition of additives, which do not fall in any specific API or ASTM classification. These materials may or may not be sold under a recognized specification and their quality and uniformity are generally controlled by the supplier. They include: (1) pozzolanic-portland cements, (2) pozzolan-lime cements, (3) resin or plastic cements, (4) gypsum cements, ( 5 ) diesel oil cements, (6) expanding cements, (7) refractory cements, (8) latex cements, and (9) cement for permafrost environments (Smith, 1976). In addition, a few cements have been developed for use in geothermal wells (Rieke and Chilingar, 1982; Shryock, 1982).

Extensive research work is being conducted on identifying, evaluating, and selecting high-temperature well cementing materials. These include: (1) PC containing crosslinked mixtures of styrene (St); acrylonitrile (ACN); and acrylamide (As), (2) organosiloxanes, and (3) portland cement combined with silica sand and vinyl-type monomers, such as methacrylate (MMA) and St, to form PC.

As pointed out by Shryock (1982, p. 313), cements exhibiting strength retrogres- sion contain two hydration products: calcium hydroxide and dicalcium silicate alpha-hydrate. To eliminate the retrogressive characteristic at high temperatures, a finely-divided silica is added to portland cements (30-60% by weight of the cement). The “silica flour” initially reacts with Ca(0H) to form dicalcium silicate alpha-hydrate, which converts to tobermorite at elevated temperatures (Shryock, 1982, p. 31 3). The tobermorite group of calcium silicate hydrates provides the temperature stability, i.e., high compressive strength and low cement permeability are maintained at high temperatures.

Pozzolanic cements

Pozzolans include any siliceous material (processed or unprocessed) that in the presence of lime and water develops cementing qualities. They can be divided into natural (mostly of volcanic origin) and artificial pozzolans. The artificial pozzolans are mainly obtained by the heat treatment of natural materials such as clays, shales, and certain siliceous rocks (Smith, 1976).

65

Fly ash, which is a combustion by-product of coal, is widely used as a pozzolan. It is covered by the API and ASTM specifications.

Calcium hydroxide, wluch is liberated upon hydration of portland cement, does not contribute to strength or water-tightness and can be removed by leachng. In the presence of fly ash, however, it combines with the calcium hydroxide, contributing to both strength and water tightness (Smith, 1976). Depending upon the source, specific gravity of fly ash varies from 2.3 to 2.7, compared with the specific gravity of 3.1-3.2 for portland cements. This explains the lower specific gravity of a pozzolan cement slurry than that of slurries of similar consistency prepared with portland cement.

Pozzolun-lime cements

Pozzolan-lime or silica-lime cements are mixtures of fly ash (silica), hydrated lime, and small quantities of calcium chloride (Smith, 1956). Various forms of calcium silicate form upon hydration with water. Inasmuch as at low temperatures the reactions are slower than similar reactions in portland cements, pozzolan-lime cements are generally recommended for primary cementing at temperatures above 140 F. According to Smith (1956), the merits of this type of cement include (1) ease of retardation, (2) light weight, (3) economy, and (4) strength stability at high temperatures.

Resin or plastic cements

Resin and plastic cements are used for squeezing perforations, selectively plugging open holes, and cementing waste-disposal wells. They are usually mixtures of water, liquid resins, and a catalyst blended with an API Class A, B, G, or H cement. When pressure is applied to the slurry, the resin phase may be squeezed into a permeable zone, forming a seal within the formation. These cements, which are used in wells in relatively small volumes, are effective at temperatures ranging from 60 O

to 200°F (Smith, 1976, p. 11).

Diesel oil cements

Diesel oil cement slurries are used when it is necessary to control water in drilling or producing wells (Hower and Montgomery, 1953a). Diesel oil cements, which are composed of API Class A, B, G, or H cement mixed in diesel oil or kerosene with a surface-active agent, have unlimited pumping times and will not set unless placed in a water-bearing zone. In the latter case, the slurry absorbs water and sets to a hard, dense cement (Smith, 1976, p. 12). Surfactant reduces the amount of the oil which is needed to wet the cement particles. The reaction or thickening time is extended on using anionic surfactant. This enables additional penetration into the formation. Diesel oil cement can be used to (1) combat certain lost-circulation problems, (2) repair casing leaks, (3) plug channels behind the pipe, and (4) control slurry

66

penetration (Hower and Montgomery, 195313). Its primary use, however, is that of shutting off water.

Gypsum cements

According to Smith (1976, p. 12), gypsum cements are often used for remedial cementing work. They are available as (1) a hemihydrate form of gypsum (CaSO, .

H,O), and (2) gypsum (hemihydrate) containing a pondered resin additive (Smith, 1976, p. 12). Gypsum cement has (1) capacity to set rapidly, (2) high early strength, and (3) positive expansion (= 0.3%). In order to produce thixotropic properties, gypsum cements are blended with API Class A, G or H cement in 8-10% concentration. This combination minimizes fall-back after placement and is particularly useful in shallow wells (Smith, 1976, p. 12). Gypsum cements are sometimes mixed with equal volumes of portland cements to form a permanent plugging material in the case of lost circulation. Inasmuch as such blends have very rapid setting properties and could set prematurely during placement, they should be used cautiously (Smith, 1976). Gypsum is usually considered a temporary plugging material unless it is placed downhole where there is no moving water, because of its solubility.

Expanding cements

In certain cases, it is desirable to use a cement that expands against the filter cake and pipe (see Lafuma, 1952; Hansen, 1963). This expansion is caused by the reactions which are similar to the process described in the cementing literature as Ettringite, which is the crystal-forming process that takes place between the tricalcium aluminate component in portland cement and sulfates (Lafuma, 1952). According to Smith (1976, p. 13), the formula of commercial expanding cements is: 3CaO.Al20,.3CaS0,.32H,O. They are prepared by adding an anhydrous calcium sulfoaluminate (4Ca0.3Al ,O,.SO,), lime (CaO), and calcium sulfate (CaSO,). Jour- nal of American Concrete Institute has described three types of commercial expanding cement: (1) Type K-the calcium sulfoaluminate component is blended with a portland cement. The linear expansion due to the hydration reaction is approximately 0.05-0.20% (Klein and Troxell, 1958). (2) Type S-a high C,A cement, which is similar to API Class A cement, with approximately 10-15% gypsum, expansion characteristics of which are similar to those of Type K cement (Portland Cement Association). (3) Type M-small quantities of refractory cement are added to portland cement to produce expansive forces.

Smith (1976) listed several other formulations of expanding cement: (1) API Class A portland cement containing a 5-10% of the hemihydrate forms of gypsum (Newman, 1960), (2) API Class A, G, or H cement containing from 5% to saturation of NaC1, with expansion being caused by the chlorosilicate reactions, and (3) pozzolan cements-expansive forces are created due to the formation of sulfoaluminate crystals when the alkali reacts with the Class A, G, or H cement.

61

The expansive force must be measured shortly after the cement sets (base reference) and then at various time intervals until the maximum expansion is reached. Hydraulic bonding tests are also used to evaluate the crystal growth of these cements (Smith, 1976, p. 13).

Latex cement

Smith (1976) pointed out that latex cement is a blend of API Class A, G, or H cement with either a liquid or a powdered latex, which may be polyvinyl acetate, polyvinyl chloride, or butadiene styrene emulsion. Approximately 1 gal of liquid latex is added per sack of cement. Latex reduces the permeability of cement and improves the bonding strength of cement. Inasmuch as latex in powdered form does not freeze, it can be dry blended with cement before transportation to the wellsite (Smith, 1976).

Calcium aluminate cements

Calcium aluminate cements (refractory) are high-alumina cements prepared by blending limestone with bauxite (aluminum ore) and then heating the mixture in a reverberatory open hearth furnace until it is liquefied (Newman, 1960). Smith (1976) pointed out that the composition of these cements differs from those of portland cements, because bauxite is used instead of clay or shale. These refractory cements contain approximately 40% lime (CaO) and small amounts of silica and iron. The high early strength and greater resistance to high temperatures and to attack by corrosive chemicals is due to the formation of calcium aluminate (Smith, 1976, p. 14).

In the in-situ combustion wells, where temperatures may range from 750" to 2000 O F during the burning process, one can use these cements. These high-alumina cements can be either accelerated or retarded. The retardation characteristics, however, differ from those of portland cements. Inasmuch as the addition of portland cement to a refractory cement causes a flash set, they should be stored separately (Smith, 1976, p. 14).

Low-density cement (Spherelite TM)

Spherelite cement additive (Halliburton Services, 1979) provides a means of preparing 9-12 lb/gal light-weight cement slurries. Adequate compressive strength is achieved in a minimum period of time, which is true even if the cement is cured under relatively low temperatures. The spherelite additive consist of hollow, inorganic spheres, which are competent up to 6000 psi total exposure pressure (Halliburton Services, 1979).

Ultra-low density grouting mixtures (7.8-8.8 lb/gal) can be prepared with high-alumina cement that will yield = 200 psi compressive strength in 24 hr at 65 O F (Halliburton Services, 1979).

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Permafrost cement

There are ice-bearing formations in the Arctic areas that extend to depths of up to 3000 ft. In some areas they can be described as frozen earth, whereas in others as glacier-like ice blocks (Maier et al., 1971). As a result, cement of conductor and surface casing in permafrost areas presents many problems. Usually one should use a quick-setting, low-heat-of-hydration cement that will not generate heat and melt the permafrost (Smith, 1976).

Gypsum-cement blends and refractory cement blends have been used very successfully for such low-temperature conditions (see Morris, 1970). In cementing surface pipe, gypsum-cement slurries are usually designed for two to four hours of pumpability; however, their strength development is quite rapid and varies little at temperatures between 20 O and 80 O F (Smith, 1976, p. 14). These cement blends can be retarded or accelerated, setting at 15 O F below freezing.

ADDITIVES FOR OILWELL CEMENTS

Smith (1976, p. 16) pointed out that there are over 40 additives which are used with various API Classes of cement to provide optimum slurry characteristics for most downhole blends of cement.

The cement additives may be classified into the following basic groupings: (1) accelerators, (2) heavy-weight additives, (3) light-weight additives, (4) retarders, (5) filtration-control agents, (6) lost-circulation control agents, (7) friction reducers, and (8) specialty materials.

Accelerators

Accelerators are used to shorten the “set” time (Farris, 1946; Bearden and Lane, 1961a, b). Cement slurries in shallow, low-temperature wells often use an accelerator to shorten the thickening time and increase the early bonding strength of the cement. Accelerators can reduce the cost by decreasing the period of “stand-by” time required while the cement sets-up and gains the strength required to hold the casing in primary cementation work. They are also used in the case of remedial work where a short set time is desired to shorten the time the cement is required to be held in position prior to setting up. Common additives include 2-4% (by weight of cement) CaCl,, 1.5-5.0% NaCl (or 3-10% by weight of water), and 20-100% of hemihydrate forms of calcium sulfate (plaster of Paris) (Smith, 1976). Other accelerators discussed by Smith (1976, pp. 17-18) are sodium silicate (Na,SiO,) and sea water, which contains up to 23,000 ppm of chlorides.

Light - weigh t additives

When prepared from API Class cement, neat cement slurries typically have a weight of about 15 lb/gal or higher. Inasmuch as many formations can not support

69

long cement columns having such a high density, materials are often added to the cement to lighten the density of the cement slurry (Coffer et al., 1954; and Dumbauld et al., 1956). The side benefits include (1) the reduction of the overall cost of the slurry, (2) increase in the yield, and (3) reduction of the filter loss. Inasmuch as fresh water has a specific weight of about 8.33 lb/gal, the weight of a cement slurry can be reduced by adding water. The specific weight of cement slurries can also be reduced by adding solids of a low specific gravity or by the addition of both water and these solids (Smith, 1976, p. 19). Solids commonly utilized include: (1) bentonite; 2-16% by weight of the cement, (2) diatomaceous earth, 10-40% by weight of the cement, (3) gilsonite, about 10-50 lb/sack of cement, (4) expanded perlite, 5-20 lb/sack of cement, ( 5 ) artificial pozzolan (fly ash) up to 74 lb/sack of cement, and (6) sodium silicate, 1-7.5 lb/sack of cement. In general, the higher concentrations of additive reduce the compressive strength and thickening time of the slurry. Water and bentonite also lower the resistance to chemical attack by formation waters (Smith, 1976, p. 20).

Heauy-weight additives

Cement slurries of high density are prepared when it is necessary to offset abnormally high formation pressures. Generally, the additives added to the slurry in order to increase its specific weight have a specific gravity of 4.5-5.0. Hematite is the most widely used heavy additive, because of having a specific gravity of 5.02 and the best physical requirements. In general, 4-104% by weight of hematite (sp.gr. =

5.02), 10-100% by weight of barite (sp.gr. = 4.23), 5-25% by weight of sand (sp.gr. = 2.65), 5-16% of salt (sp.gr. = 2.16-2.17), or 5-100% of illmenite (iron-titanium oxide), can be used to increase the slurry density (Smith, 1976, p. 23).

Cement retarders

When wells are drilled to a depth of 6000 ft or deeper, bottomhole temperatures encountered are in excess of 170 O F. Inasmuch as at these high temperatures cement sets up quickly, retarders are added to slow down the setting time. As a general rule, retarders are required below a depth of 8000 ft. The retarder must be compatible with the cement and the additives in cement. Commonly utilized retarders include lignins, gums, starches, weak organic acids, and cellulose derivatives (carboxymethyl hydroxyethyl cellulose-CMHEC). The percentage of these chemicals that must be added ranges from 0.1 to 2.5% by weight of cement. Salt is also utilized in concentrations ranging from 14 to 16 lb/sack of cement (Smith, 1976, p. 23).

Lost circulation additives

Smith (1976, p. 24) pointed out that there are two basic steps to combat lost circulation problems: (1) reduction of the slurry density, and (2) addition of a bridging or plugging material (see Wieland et al., 1969).

70

Perlite, which is a bridging agent, has been used successfully to prevent lost circulation. Perlites weigh 8-10 lb/ft3 (dry), occur in particle sizes of 4-40 mesh (U.S. Series), and are cellular, which allows them to absorb water under pressure (Shryock, 1982, p. 314). In order to keep perlite particles evenly dispersed thoughout the slurry, it is necessary to use 2-4% bentonite (by weight of the total cement). According to Shryock (1982, p. 314), the most commonly used composition is: 1 ft3 (94 lb) of cement plus 1 ft3 (8 lb) of perlite, with 40% silica flour and 2% bentonite (by weight of cement). The normal amount of mixing water with 1 ft3 of perlite per sack of cement is 1.46 ft3. This results in an inhole slurry specific weight of 104 lb/ft3 and a slurry volume of 2.28 ft3/sack of cement.

Friction reducers or cement dispersants

Additives are often required to improve the flow properties of slurries. A dispersed slurry generally has a lower viscosity and can be pumped in turbulent conditions with a lower pump pressure, thereby reducing the horsepower required to displace the cement (see Brice and Holmes, 1964). Smith (1976, p. 25) pointed out that dispersants also lower the yield point and gel strength of the slurry. Common dispersants are polymers and NaC1, which are used at lower reservoir temperatures. Calcium lignosulfonates (organic acid blends) are used at higher reservoir temperatures.

Filtration-control additives

In controlling the filter loss of cement slurries, Smith (1976, p. 24) pointed out that it must be lowered by use of additives to (1) prevent premature dehydration or loss of water to the porous zones adjacent to the displaced cement, (2) protection of water-sensitive formations that can be plugged or damaged by the filtrate solutions, and (3) improvement of squeeze-type cementing. The 30-min API filter loss for a neat slurry of API Class G or H cement is in excess of 1000 cm3.

The two most common additives are organic polymers (cellulose) and friction reducers (Smith, 1976, p. 25). The high-molecular-weight cellulose compounds are used in concentrations of 0.5-1.5% by weight of cement, sometimes requiring higher volumes of water to maintain the desired slurry viscosity. In order to control filter loss, dispersants (friction reducers) are commonly added to cement slurries. They disperse and pack the cement particles, thus making the cement slurry more dense (Smith, 1976, p. 25).

OILWELL CEMENT STANDARDS OUTSIDE OF THE UNITED STATES

The American Petroleum Institute, Halliburton Co., and CEMBUREAU (Paris) presented tables (Tables 3-1 and 3-11) as an aid in the selection of locally available

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TABLE 3-1

Properties of various types of cement used in U.S.A. (Courtesy of the Halliburton Services)

Properties of API classes of cement

Class A Class C Classes Classes G and H D and E

Specific gravity (average) 3.14 3.14 3.15 3.16 Surface area (range); (cm2/g) 1500-1900 2000-2800 1400-1700 1200-1600 Weight per sack (Ib) 94 94 94 94 Bulk volume (cu ft/sack) 1 1 1 1 Absolute volume (gal/sack) 3.6 3.6 3.58 3.57

Properties of neat slurries

Portland High early API API Retarded strength Class G Class H

Water (gal/API) 5.19 6.32 4.97 4.29 4.29 Slurry weight (lb/gal) 15.6 14.8 15.8 16.5 16.5 Slurry volume (cu ft/sack) 1.18 1.33 1.14 1.05 1.05

Temperature Pressure ( O F ) (Psi)

60 80 95 110 140 170 200

0 0

800 1600 3000 3000 3000

Typical compressive strength (psi) at 24 hr

615 780 440 325 1470 1870 1185 1065 2085 2015 2540 2110 2925 2705 2915 2525 5050 3560 4200 3160 3045 5920 3710 4830 4485 4150

5110 4575 4775

a

a

a a

Typical compressive strength (psi) at 72 hr

60 80 95 110 140 170 200

0 2870 2535 - - 4130 3935 - - 0

800 4670 4105 - -

1600 5840 4780 - - 3000 6550 4960 - 7125 4000 3000 6210 4460 5685 7310 5425 3000 7360 9900 5920

a

a

a a

Depth Temperature ( F) High-pressure thickening time (hr : min.)

(ft) Static Circulating

2000 110 91 4:00+ 4:00+ 3:00+ 3:57 4000 140 103 3 : 36 3:lO 2:30 3:20 4:00+ 6000 170 113 2:25 2:06 2: 10 1 : 57 4:00+ 8000 200 125 1:40a 1:37a 1 :44 1:40 4:00+

a

a Not generally recommended at this temperature.

v N

TABLE 3-11

Equivalent cement classifications in various countries (Courtesy of CEMBUREAU)

International Australia Canada France Japan United Kingdom West Germany designation

oc Type A, Normal CPA-250 Ordinary Ordinary Portland 2375

RHC Type B, High High Early CPA-400 Rapid Hardening Rapid Hardening -

HSC - - - - - 2450 LHC Type C, Low - - Medium Low Low Heat Portland -

SRC - Sulfate - - Sulfate Resisting 2275

Ordinary Portland CPA-325 Portland (B.S. 12: 1958)

Early Strength Strength CPA-500 Portland

Heat of Heat Portland (B.S. 1370 1958) Hydration

Resisting Portland (B.S. 4027: 1955)

AEC - - - - - - Designation of Standards AS A2 CSA A5 NF P15-302 JIS R5210 (B.S. 12; 1370; 4027) DIN 1164 Year Published 1963 1961 1964 1964 1958and1966 1969

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cements in countries outside the United States. For several cements, additional classifications were required, which have been included in the table (see Smith, 1976, for additional details).

CEMENTING OPERATIONS

Oilwell cementing practice

Regulatory bodies, which require drilling and completion of oil and gas wells in such a manner as to prevent the escape of oil, gas, or formation waters from one geologic strata to another, have been established in practically every oil-producing country. The pollution of fresh-water sands is of prime concern. There are also regulations, particularly in the U.S.A., on: (1) establishing the minimum quantities of cement to be placed in the wellbore above the producing zone, (2) methods of segregating producing zones, (3) protection of surface areas, (4) testing of cement jobs, ( 5 ) squeezing, plugging, and testing cementing plugs, (6) determining waiting- on-cement job (WOC), and (7) methods of setting casing.

Most cementation operations can be defined as either primary or secondary. Primary cementing operations are those that pertain to the cementing job after installation of casing in the wellbore and laying of bottomhole plugs. Secondary operations include squeeze cementing and other similar remedial cementing operations. Squeeze cementing can be defined as follows: squeezing (forcing) of a cement slurry into pores, vugs, fractures, etc. of a formation, to acheve a seal between the formation and casing.

Primary oilwell cementing

The important functions of primary cementing are: (1) to allow segregation of formations behind the well casing (to prevent movement of fluids between different zones), (2) to give additional support to the casing in the wellbore to protect it from shock loads, (3) to retard corrosion of the casing in the wellbore by minimizing contact between formation fluids and outside surface of the pipe, (4) to prevent blowouts, and (5) to seal off lost-circulation (thef) zones.

Primary cement jobs are usually performed by pumping the slurry down through the tubing or casing and up around the outside of the casing in the wellbore-casing annulus. Figure 3-2 illustrates the typical procedure for a single-stage primary cement job. Gatlin (1960) showed a normal displacement cement operation: Neat cement is introduced in a dry form into a hopper, where it is mixed with a turbulent water stream by a high-velocity jet mixer. Cement slurry is then pumped down in-between two plugs which have wiping fins. Plugs are placed in the system immediately after and before the cement slurry while it is being pumped down the tubing. The bottom plug stops upon reachng the float collar. The pressure increases behind the plug until the hollow rubber plug ruptures. T h s allows cement to pass

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Fig. 3-2. Typical surface and subsurface primary cementing operations. (Courtesy of the Halliburton Services.)

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NORMAL TWO INNER OUTSIDE MULTIPLE

METHOD CEMENTING CEMENTING CEMENTING DISPLACEMENT STAGE STRING CEMENTING STRING

Fig. 3-3. Types of cement displacement operations. (Courtesy of the Halliburton Services.)

through the ruptured rubber plug, float collar, guide shoe and up the annular space between the wellbore and casing. Pumping of cement slurry is stopped when the solid top plug seats on top of the .float collar. The pumps are shut-in and the cement slurry is permitted to set-up. Below the float collar, the casing is left full of cement. If required, however, it can be drilled out later.

There are numerous variations of primary cementing techniques in use (Fig. 3-3). Cementation of large-diameter casing, when tubing (or drillpipe) is used in order to permit the use of smaller-diameter plugs and other equipment, is called inner string cementing. This reduces the cementing time, volume of cement necessary to pump the plug, and amount of cement that must be drilled out. This technique utilizes a modified float collar together with sealing adapters on the drillpipe, and cementing is done through the drillpipe, which has been “stabbed” into modified float collar. Cement mixing is continued until cement returns to the surface (Shryock, 1982, p. 323). Thus, when the drillpipe plug is released, only the cement present in the drillpipe is released to the sump.

In normal displacement techniques, the cement is displaced through the tubing and/or casing. If a primary cementing job is performed in two or more stages, it is called stage cementing. The latter is used in wells requiring long columns of cement and in the presence of weak formations which cannot support the hydrostatic head of the cement column while cementing. A combination of plugs and baffles enables the stage collar to be manipulated hydraulically, shutting off access to the casing below this collar and opening ports in the collar so that fluid can be circulated from this point to the surface (see Shryock, 1962, p. 322). After allowing sufficient time for the first-stage cement to set, cement circulation is performed through these ports back to the next stage or to the surface.

Liner cementing is similar to the casing cementing method; however, the technique used to get the cement in place is different. As soon as the liner is in place, the cement slurry is circulated down the drillpipe out of the liner and, then, up the outside of the liner. Just as in the casing string, plugs are used to prevent mixing of

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the drilling fluid and cement in the liner. As pointed out by Shryock (1982, p. 323), the liner plug, whch is installed prior to running the liner in the hole, has an opening that allows passage of the cement slurry. A drillpipe plug is released from the surface at the proper time. It displaces the cement slurry from the drillpipe and upon seating in the liner plug forces the latter down the liner displacing the slurry into the annulus. After completion of the cementing job, the drillpipe is picked up two to three stands above the liner top and the excess cement is reversed out of the hole. The remaining cement on the liner top is later drilled out (Shryock, 1982, p. 323).

When seal is not achieved during the primary casing or liner job, cement is squeezed out into the voids-squeeze cementing. This involves pumping cement through the drillpipe, which is attached to a squeeze packer set in the casing above the liner lap, for example.

If cement is pumped through a small-diameter tubing between casing and open hole or between casing strings, which is commonly used on conductor or surface casing where the top of the cement must reach the surface, it is called outside cementing. Or cement can be pumped simply down the annulus.

In reverse circulation cementing, the slurry is pumped down the annulus, displacing the mud in the wellbore through the casing. It can be used when pumping the cement slurry in turbulent flow conditions is not possible without breakmg down the weak zones above the casing shoe.

In order to obtain a more uniform sheath of cement around the casing, whch may be impossible by using conventional displacement methods, one can use delayed setting cementing.

The downhole and surface cementing equipment vary in type and design. Cementing technique chosen depends on depth, pressure, formation temperature, lithology, and the type of casing string being cemented.

Waiting-on-cement time (WOC)

Waiting-on-cement time (WOC) is commonly determined by the local, state, and federal regulations, which should be checked. In the absence of rules, the WOC time selected should permit enough time for the cement to gain sufficient strength to: (1) anchor the casing and withstand the shock of subsequent operations, (2) seal permeable and thef zones, and (3) confine fracture pressures. The WOC time can be as short as 4-6 hrs under warm conditions, using densified cements (API Class A, G or H) and a 2-3% CaCl,. It depends upon the (1) class of cement, ( 2 ) additives in the cement, (3) required time for placement, (4) temperature, and (5) pressure. It is usually desirable to have a minimum compressive strength of 500 psi before drilling cement out of the casing is initiated. It is commonly recommended to (1) run a cement bond log, (2) perforate, or (3) stimulate the well 24-72 hrs after placement of the cement (or upon reaching a compressive strength of 2000 psi). A pressure test of the casing is required in some areas, e.g., in Texas, U.S.A., whereas

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in others, e g , California, U.S.A., a production test is required to determine whether the cementing job was successful or not.

Slurry density

Slurry density must be continually monitored in order to control the relative amounts of water, cement, and additives used and to insure maintenance of the correct water/solids ratio. Cement slurry density must be about the same as that of the drilling fluid in the wellbore. As pointed out by Gatlin (1960), this will minimize the chances for lost circulation or blowouts, which could occur during the placement of the cement slurry. As mentioned before, a common material for decreasing the cement slurry density is montmorillonite clay, commonly referred to by petroleum engineers as gel. This reduction in density is mainly due to the high degree of swelling of montmorillonite (smectite) clays in water. The content of a particular additive in a cement slurry is expressed as a weight percent of the dry cement. Gatlin (1960) presented the practical units whch are used in cement calculations.

The cement volume used is expressed in terms of sacks of cement, even though in most cases bulk cement is delivered to the wellsite: 1 sack = 94 lb = 1 ft3 bulk volume. Inasmuch as the specific gravity of portland cement is equal to 3.14, a sack of cement contains 0.048 ft3 [ = 94/(3.14 X 62.4)] of cement. Cement porosity is equal to 52%. In computing the cement volume, the volumes and weights of various components are assumed to be additive. Gallons per sack are used to express water/cement ratios. For example, if 6 gallons of water per sack of cement are used, the slurry volume is equal to: (6/7.48) + 0.48 = 1.28 ft3/sack of cement (where 7.48 gal = 1 ft3) The specific weight of this slurry can be calculated as follows:

Y,V, + Y C K = YSK (3-1)

where yw = specific weight of water, V, = volume of water, yc = specific weight of cement, V, = volume of cement, y, = specific weight of slurry, and V, = volume of slurry. Upon rearranging:

Y s = ( Y W V W + Y c v , I/ v, (3-2)

Thus, y, = [(62.4 x 6/7.48) + (3.14 x 62.4 X 0.48)]/[0.48 + (6/7.48)] = 112.39 lb/cu ft or 13.49 lb/gal. On adding 6% bentonite (by weight of cement), having a sp.gr. of 2.7, to the slurry and increasing the water/cement ratio to 8.0 gal/sack, the new slurry volume can be calculated as follows:

V,+V,+v,=v, (3-3)

where V, = volume of bentonite. Assuming additive weights:

wt, + wt, + wt, = wt, (3-4)

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where wt, = weight of bentonite, wt, = weight of water, wtc = weight of cement, and wt, = weight of slurry. Thus:

= [(0.06 x 94)/(2.7 x 62.4)] + (8.0/7.48) + 0.48 = 1.58 ft3/sack.

The new specific weight of cement slurry is equal to:

[(0.06 x 94) + (1 x 94) + (8 X 8.33)]/(1.58 X 7.48) = 14.07 lb/ft3 or 1.7 lb/gal

Due to the fact that aeration affects the density measurements, samples of cement slurry should be obtained from a special manifold on the discharge side of the pump and not from the mixing container. Inasmuch as the last portion of cement slurry is placed around the casing shoe, great care must be exercised to insure that it meets required weight specifications. In order to provide higher strength around the casing shoe (point), cement slurries are often mixed with a lower amount of water toward the end of the job.

SURFACE AND SUBSURFACE CEMENTING EQUIPMENT

Cement pumping equipment

Cement pumping units, which can be mounted on a truck, trailer, skid, or ship, are operated at varying rates and intermittently at high pressure. These units must (1) have the lowest practical weight/horsepower ratio, (2) be capable of high horsepower input and output over wide torque limits, and (3) lend themselves to be easily transported from one site to another. The cement pumping units usually are powered by either internal-combustion engines or electric motors (see Figs. 3-4 and 3-5). They may be manifolded with two or three pumps. In the case of low-pressure systems, a centrifugal pump can be used for mixing and two positive displacement pumps can be used for displacing. High-pressure systems may use one pump for mixing, while the other is used for displacing (Halliburton, 1970).

Although cementing pumps commonly have to operate at pressures as high as 20,000 psi, most cementing work requires maximum pressure lower than 5000 psi.

The volume of cement to be pumped, anticipated pressures, and well depth determine the number of required trucks for mixing the cement and displacing it downhole. Low-pressure units are required for surface casing and conductor cementing, whereas two or more trucks are required for primary cementation of intermediate or production casing. Cement slurries are generally pumped into the

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Standard Twin HT-400 Cementing Unit.

Standard Twin HT-400 Cementing Trailer.

Fig. 3-4. Truck and trailer mounted cementing units. (Courtesy of the Halliburton Services.)

casing at the highest possible rates dictated by the capacity of the mixing unit (20-50 sacks per minute) (Halliburton, 1970; also see API, 1974).

Cement mixing equipment

The mixing system of any cementing unit proportions and blends the dry cement with the water (carrier fluid). The jet mixer shown in Fig. 3-6 is one of the most widely used mixers. As shown in this figure, the mixer consists of a funnel-shaped hopper, a mixer bowl, discharge line, mixing tub, and water supply lines. The mixer operates by forcing a stream of water through a jet into a bowl, in which cement

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SCHEMATIC OF JET MIXER

Fig. 3-5. Schematic of the jet cement mixer showing the working parts. (Courtesy of the Halliburton Services.)

from the hopper mixes with water. Then the resulting slurry is discharged into a discharge line and, finally, into a sump tub from which the slurry is pumped into the well by the cementing pumps. The volume of water forced through the jet and the

u WATER n DRY CEMENT

CEMENT SLURRY CEMENT HOPPER

JELL BREAKER1

OTARY JET TUB SCREEN

DR” CEMENT

CEMENT SLUIIR”

DISPLACEMENT PUMP SUCTION

Fig. 3-6. Jet cement mixing operation. (Courtesy of the Halliburton Services.)

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amount of cement introduced into the hopper while mixing, control the mixing speed. A bypass line can supply extra water into the bowl discharge line for lowering the specific weight of slurry by increasing the water/cement ratio. Depend- ing on the rate of feeding of cement and water/cement ratio, mixing pressures may range from 150 psi for low-pressure systems to 500 psi for high-pressure systems (Halliburton, 1970). For an excellent discussion of the subject see Smith (1976).

Recirculating systems The recirculating mixer (Fig. 3-7) is designed for mixing hgh-density slurries.

Fig. 3-7. A recirculating mixer. (Courtesy of the Halliburton Services.)

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WATER

Fig. 3-8. Batch mixing system. (Courtesy of the Halliburton Services.)

Basically it is a pressurized jet mixer with a larger mixing tub capacity. As pointed out by Smith (1976, p. 61), the system uses recirculated slurry and water to partially mix and discharge the slurry into the tub. The in-tub eductor adds additional energy and improves mixing, whereas additional shear is provided by the recirculating pump and agitation jets. It is used basically to provide uniform cement slurries having densities as high as 22 lb/gal, pumping as slowly as 0.5 bbl/min.

Batch mixing The pneumatic and mechanical types of batch mixers were often used to blend a

large volume of cement slurry at the surface conditions before it is moved into the well (Fig. 3-8). The pneumatic systems, however, are no longer being used in the U.S.A. The mechanical mixers are relatively simple to use and enable an engineer to

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TABLE 3-111

Mixing rates and densities for various slurries using jet mixers and recirculating mixers (After Smith, 1976, table 7.6, p. 62; courtesy of the Society of Petroleum Engineers of AIME)

Jet mixer Recirculating mixer

Mixing Slurry Mixing Slurry rate density rate density

(bbl/min) ( lb /g4 (bbl/min) (lb/gal)

Densified and 2-5 16-20 0-6

Neat slurries 2-8 15-17 0-8 High-water-ratio

weighted slurries

slurries 2-14 11-15 0-12

16-22

14-18

11-15

prepare a specific volume of slurry having the exact physical requirements before it is displaced downhole (Halliburton, 1970). The ranges of mixing rates and slurry densities for two different types of mixers are presented in Table 3-111.

Subsurface cementing equipment

Many types of subsurface equipment are used today in oilwell cementing. Table 3-IV illustrates the wide variety of equipment available to aid cementing operations. This equipment has been developed through the years by operators and manufacturers to assist the operator in cementing operations. Specifications covering such equipment are quite variable and are limited. A general description of these

Fig. 3-9. Guide shoes: (a) with no ports; (b) with down jet type ports; (c) Type “ M Texas Patter (short) shoe-open end. (Courtesy of the Halliburton Services.)

00 P

TABLE 3-IV

Summary of cementing equipment and mechanical aids (After Smith, 1976, table 6.2, p. 56; courtesy of the Society of Petroleum Engineers of AIME)

Equipment Function or Application Placement

Floating equipment Guide shoes

Float collars

To guide casing into well To minimize derrick strain To prevent cement flowback To create pressure differentials to improve

To catch cementing plugs

First joint of casing

One joint above shoe in wells less than 6000 ft deep; two to three joints above shoe in wells

bond deeper than 6000 f t

Automatic fillup equipment Automatic fillup float shoes

Differential fillup float shoes

Same as those of ordinary float shoes and collars; also to control hydrostatic pressure in annulus while casing is being run

Same as for ordinary float shoes and collars and collars

and collars

Formation packer tools Formation packer shoes

Formation packer collars

Stage-cementing tools Two-stage tools Three-stage tools

To protect lower zones by expanding during cementing

To cement two or more sections in separate stages

First joint of casing

As hole requirements dictate

Based on critical zones and formation fracture gradients

Plug containers Quick-opening containers Continuous cementing heads

Cementing plugs Top and bottom wiper plugs Ball plugs Latch-down plugs

Casing centralizers Various types

Scratchers (wall cleaners) Rotating scratchers

Reciprocating scratchers

Bridge plugs Wireline bridge plugs Tubing bridge plugs

Special equipment Cementing baskets and

external packers

To hold cementing plugs in casing string until plugs are released

To act as a mechanical space between mud and cement (bottom plug) and between cement and displacement fluid (top plug)

To center casing in hole or provide minimum standoff to improve distribution of cement in annulus and prevent differential sticking

To remove mud cake and circulatable mud

To aid in creating turbulence To improve cement bond

from wellbore

To plug permanently or temporarily in open hole or casing

In setting casing or line, to help weak formations support the cement column unit it sets.

To joint of casing at surface of well

Between well fluids and cement

In a straight hole one per joint through and 200 ft above and below pay zones; one per every three joints in open hole to be cemented

deviation In a crooked hole: variable, depending on hole

Through producing formations and 50-100 ft above. (Pipe should be rotated 15-20 rpm.)

Same as for rotating scratchers. (Pipe should be reciprocated 10-15 ft off bottom.)

In well on wireline, on tubing, or below retrievable squeezing packers

Below stage tools or where weak formations exist down hole

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mechanical aids (see Smith, 1976, Chapter 6, for greater details) is presented in this section.

Casing- cemen ting heads Cementing heads (or plug containers) provide a connection from cementing and

rig-pump lines to a casing string and hold one or two plugs. The plugs may be released (one ahead and one behind the cement slurry) from the container during the cementing operation without interruption of pumping, in the case of continuous cementing head.

Cementing plugs In order to prevent contamination of cement slurry by the drilling fluid and

vice-versa, the bottom plug is pumped ahead of the slurry. When released from its container, this plug wipes the mud from the casing wall as it moves down. Differential pressure ruptures a diaphragm on top of the plug, as it reaches the float collar, allowing the cement slurry to move through the plug and floating equipment and up the annular space between the hole and casing. The top cementing plug reduces the possibility of contamination of (or channeling with) cementing slurry by the displacing fluid and gives rise to a pressure buildup in the casing. The top cementing plug is landed on the float shoe or float collar. As pointed out by Smith (1976, p. 53), whereas conventional wiper plugs are more widely used, other available designs for primary cementing include balls, wooden plugs, sub-sea plugs, and tear-drop or latch-down devices.

Floating and guiding equipment The plain guide shoe and the combination guide and float shoe are the two types

of guide shoes in use (Craft et al., 1962). The guide shoe (Fig. 3-9), which is run on the bottom of the casing string, is used mainly for guiding the casing into the borehole with all of its sidewall irregularities. The combination float and guide shoe includes a back-pressure valve and a side discharge. This valve prevents the cement from flowing back into the casing from the wellbore-casing annulus after cement placement. An automatic fillup float shoe is shown in Fig. 3-10.

The float collar (Fig. 3-11), which is generally run one or more joints above the casing shoe, contains a back-pressure valve similar to the one of the float shoe (Craft et al., 1962; Baker Oil Tools, Inc., 1974; Halliburton Services, 1974). In addition to serving as floating equipment, the float collar also provides a seat for the wiper plugs. The spacing between the float collar and shoe controls the amount of cement fill left inside the casing. Consequently, it provides for the storage of the tail-end of the displaced cement, which often is contaminated by the displacing fluids. The less contaminated cement is thus left above the shoe for a better cement job.

87

Fig. 3-10. Automatic fillup float shoe: (a) valve open for running in hole; and (b) valve closed to prevent back-flow of cement once placed. (Courtesy of the Halliburton Services.)

Fig. 3-11. Float collars: (a) Flow control collar; (b) concrete baffle collar; and (c) Type “E” float collar. (Courtesy of the Halliburton Services.)

88

FIGURE 1 FIGURE 2 FIGURE 3 FIGURE 4

DISPLACING CEMENT FOR FIRST STAGE

DROPPING OPENING

PLUG

DISPLACING CEMENT FOR

SECOND STAGE

MULTIPLE STAGE

CEMENTER CLOSED

Fig. 3-12. Multiple-stage cementing operations showing downhole cementing equipment and free-falling plug for cementing a wellbore in two stages. (Courtesy of the Halliburton Services.)

89

Stage-cementing tools Multiple-stage cementing tools must be used in cases when it is desirable to

cement two or three sections behnd the casing. Smith (1976) pointed out that stage cementing (Fig. 3-12) usually reduces drilling fluid contamination and decreases the possibility of formation breakdown, that often causes lost circulation (Halliburton Services, 1974).

Smith (1976, p. 51) pointed out that as the casing is run into the borehole, stage

I ,-Cement -,

Mud Coring

I (1 b

Fig. 3-13. Schematic diagram: (a) an improperly centered casing in the wellbore along with mud cake that has not been removed from the walls of the wellbore; and (b) a properly centered casing in the wellbore where the mud cake has been removed with scratchers and held securely by centralizers.

Fig. 3-14. Variety of centralizer design: (a) centralizer equipped with vanes or blades; (b) slim-hole type design; and (c) standard design. (Courtesy of the Halliburton Services.)

90

tools are installed at a specific point in the casing string. Upon placing the cement around the bottom of the casing, which constitutes the first stage, the tool can be opened hydraulically either (1) with a plug pumped down the casing or (2) with a free-falling opening plug dropped down the casing. Cement can be circulated through the outside ports when the tool is opened. A closing plug closes a sleeve over the side port upon placement of all the cement slurry. Primary advantage of this method (see Halliburton, 1974) lies in the fact that the shutoff plug used in the first stage prevents overdisplacement of the first-stage cement. In cases where the cement must be placed in the annular space from the bottom of the casing up to or above the stage tool, the displacement stage-cementing method can be used. In deep or deviated holes, in whch too much time is needed for a free-falling plug to reach the tool, t h s method is often used.

Fig. 3-15. Centralizer with internal blades to reduce channeling of cement by increasing turbulent action of cement in wellbore-casing annulus. (Courtesy of Solum Oil Tool Co.)

91

Fig. 3-16. Use of casing centralizers and scratchers on typical casing string run into wellbore for primary cementing operations. (Courtesy of the Halliburton Services.)

92

Fig. 3-17. Variety of design for rotating scratchers: (a) cable type; (b) piano wire type; and (c) rotating blade type scratchers attached to casing. (Courtesy of the Solum Oil Tool Co. and the Halliburton Services.)

93

Casing centralizers The effectiveness of the seal between wellbore and casing is determined in a large

measure by the uniformity of the cement sheath around the pipe (Fig. 3-13). Generally, the pipe is in contact with the wall of the borehole at several places, because most holes are not straight. In order to keep the casing away from the walls of the borehole, centralizers are used (Figs. 3-14, 3-15 and 3-16). Although there is an agreement among investigators as to the need to centralize the casing to obtain a better cement job (Goins, 1971), there is some disagreement as to how frequently centralizers should be placed. The design of centralizers varies widely with vendors and for different hole applications. The API specifications (API, 1960b; API Standards 10B) insure minimum strength requirements based upon (1) restoring force and ( 2 ) starting force (Table 3-V).

Casing scratchers Scratchers, whch are mechanical devices that are attached to the casing, remove

filter cake (mostly loose) from the walls of the borehole and help distribute cement around the casing (Figs. 3-17 and 3-18). They are attached to the outside of the casing (either welded or attached with limit clamps) and act on the wellbore as the casing is run into the borehole. Further action is obtained when the casing is either

Fig. 3-18. Variety of designs for reciprocating scratchers: (a) reciprocating wall cleaner with piano wire to scratch wellbore; (b) reciprocating bundled wire scratcher; and (c) reciprocating cable wall cleaner. These scratchers are placed approximately 20 ft apart and reciprocated every 30 ft. (Courtesy of the Solum Oil Tool Co. and the Halliburton Services.)

Fig. 3-19. Cement basket. (Courtesy of Solum Oil Tool Co.)

TABLE 3-V

API casing centralizer specifications (After American Petroleum Institute, 1960a, API Standards 10D)

(1) Minimum centralizer restoring force

Casing size Weight of medium- Minimum

(in.) weight casing (lb/ft) restoring force (lb)

4; 11.6 464 5 13.0 520 5 ; 15.5 620

6; 24.0 960 7 26.0 1040 7; 26.4 1056

9; 40.0 1600

8; 36.0 1440

10 : 51.0 1020

13; 61 .O 1220 16 65.0 1300 20 94.0 1300

(2) Starting force: maximum force should be less than the weight of a joint of 40-ft casing between centralizers

95

Cement Basket

Fig. 3-20. (a) Placement of cementing baskets, stage collars, and centralizers on the casing string used for primary cementing operation where weak or porous sands occur in the interval to be cemented. (b) Cementing basket. (Courtesy of the Halliburton Services.)

96

Fig. 3-21. Schematic of an external casing packer. (Courtesy of Lynes Inc.)

97

rotated or reciprocated. Scratchers are specifically designed for either type of action (see Smith, 1976, for additional details).

Fig. 3-22a. For explanation see p. 98.

98

Fig. 3-22. (continued). Multiple uses of a casing packer. in cementing and well completion operations. ECP = external casing packer \(Courtesy of Lynes, Inc.)

99

Cement baskets and external casing packers Cement baskets (Figs. 3-19 and 3-20) and external packers (Fig. 3-21 and 3-22)

are used in cases where weak (and porous) formations need help to support the cement column until the occurrence of initial set. Baskets are often installed over casing collars or mounted between limit clamps. External casing packers are placed where desired in the casing string as the casing is lowered into the wellbore. The packers are expanded before initiation of cementing (Baker Oil Tools, 1974).

ACKNOWLEDGEMENTS

The authors are greatly indebted to Halliburton Services and Dwight K. Smith whose help was invaluable in carrying this work to completion. Dr. Smith is one of the foremost experts on cementing in the World.

REFERENCES

American Petroleum Institute, 1948. California’s Oil. API, Dallas, Tex., 12 pp. American Petroleum Institute, 1959, Oil- Well Cementing Practices in the United States. API, Dallas, Tex.,

American Petroleum Institute, 1960a. API Specifications for Oil- Well Cements and Cement Additives, API

American Petroleum Institute, 1960b. API Recommended Practice for Testing Oil- Well Cements and

American Petroleum Institute, 1974. Specifications for Oil- Well Cements and Cement Additives, API

Baker Oil Tools Inc., 1974. Technical Sales Catalog. Houston, Tex. Bearden, W.G. and Lane, R.D:, 1961a. You can engineer cementing operations to eliminate wasteful

Bearden, W.G. and Lane, R.D., 1961b. Engineered cementing operations to eliminate wasteful WOC

Blanks, R.F. and Kennedy, H.B., 1955. The Technology of Cement and Concrete. Wiley, New York, N.Y.,

Brice Jr., J.W. and Holmes, B.C., 1964. Engineered casing cementing programs using turbulent flow

Byron Jackson Inc., 1979. Applied Engineering Cementing, Vol. I: 2nd printing, 102 pp. CEMBUREAU, 1967. Cement Standards of the World- Portland Cement and its Derioatiues. Pans. Coffer, H.F., Reynolds, J.J. and Clark Jr., R.C., 1954. A ten-pound cement slurry for oil wells. Trans.

Craft, B.C., Holden, W.R. and Graves Jr., E.D., 1962. Well Design: Drilling and Production. Prentice-Hall,

Dumbauld, G.K., Brooks Jr., F.A., Morgan, B.E. and Binkley, G.W., 1956. A lightweight, low-water-loss,

Fams, R.F., 1946. Method of determining waiting-on-cement time. Trans. AIME, 165: 175-188. Gatlin, C., 1960. Petroleum Engineering: Drilling and Well Completions. Prentice Hall, Englewood Cliffs,

Gibbs, M.A., 1965. Prima? and Remedial Cementing in Fractured Formations. In: Southwestern

297 pp.

STD 10A. API, Dallas, Tex., pp. 4-7.

Cement Additiues, API RP 10B. API, Dallas, Tex., pp. 2-3.

Standards 10A. API, New York, N.Y., 19th ed.

WOC time. Oil Gas J., July 3: 104.

time. Drill. Prod. Pract., API , p. 17.

pp. 1-64.

techniques. J. Pet. Tech., 16(5): 503-508.

Soc. Pet. Eng. AIME, 201: 146-148.

Englewood Cliffs, N.J., pp. 158-255.

oil-emulsion cement for use in oil wells. J. Pet. Tech., 8(5) : 99-104.

N.J., pp. 269-329.

Petroleum Short Course, Texas Technical College, Lubbock, Tex., 1965, pp. 22-23.

100

Goins Jr., W.C., 1971. Selected items of interest in drilling technology. J. Pet. Tech., 23(7): 857-862. Halliburton Oil Well Cementing Company, 1970. Halliburton Oil Well Cement Manual. Halliburton,

Halliburton Oil Well Cementing Company, 1974. Technical Services Catalog No. 37. Halliburton,

Halliburton Services, 1979. ShereliteTM low-density cement. Cem. Tech. Data, C-1263 (Rev.). Hansen, W.C., 1963. Crystal growth as a source of expansion in Portland-cement concrete. Proc. ASTM,

Howard, G.C. and Clark, J.B., 1948. Factors to be considered in obtaining proper cementing of casing.

Hower, W.F. and Montgomery, P.C., 1953a. New slurry effective for control of unwanted water. Oil Gas

Hower, W.F. and Montgomery, P.C., 1953b. New squeeze-cementing mixture. Oil Gas J. , 52(24): 136. Klein, A. and Troxell, G.E., 1958. Studies of calcium sulfoaluminate admixtures for expansive cements.

Lafuma, H., 1952. Expansive cements. Proc. 3rd In?. Symp. Chem. Cement, London, p. 581. Maier, L.F., Carter, M.A., Cunningham, W.C. and Bosky, T.G., 1971. Cementing practices in cold

environments. J. Pet. Tech., 23(10): 1215-1220. Morgan, B.E. and Dumbauld, G.K., 1954. Bentonite cement proving successful in permanent-type

squeeze operations. World Oil, Nov.: 220. Morris, E.F., 1970. Evaluation of Cement Systems for Permafrost. Annu. Fall. Meet., SOC. Pet. Eng.

AIME, Denver, Colo., Feb. 15-19. Newman, K., 1960. The design of concrete mixes with high alumina cement. The Reinf: Concr. Reu., 5

(Mar.). Rieke, H.H. and Chilingar, G.V., 1982. Casing and tubular design concepts. In: L.M. Edwards, G.V.

Chilingar, H.H. Rieke 111 and W.H. Fertl (Editors), Handbook of Geothermal Energy, Gulf, Houston, Tex., pp. 261-309.

Shryock, S.H., 1982. Geothermal cementing. In: L.M. Edwards, G.V. Chilingar, H.H. Rieke 111 and W.H. Fertl (Editors), Handbook of Geothermal Energy, Gulf, Houston, Tex., pp. 310-325.

Slagle, K.A., 1962. Rheological design of cementing operations. J. Pet. Tech., 3: 323-328. Smith, D.K., 1956. A new material for deep well cementing. J. Pet. Tech., 8(3): 59-63. Smith, D.K., 1966. Well cementing method. U.S. Patent No. 3, 227, 213, Jan. 4. Smith, D.K., 1976. Cementing (Henry L. Doherty Series, Monogr., 4) AIME, Dallas, Tex., 184 pp. Snyder, RE. and Suman Jr., G.O., 1979. High-pressure Well Completions Handbook. World Oil, Houston,

Suman Jr., G.O. and Ellis, R.C., 1977. Cementing Handbook (Including Casing Handling Procedures).

Taylor, F.B., 1941. Acidizing before cementing helps form effective bottom-hole water block. Oil Weekly,

Taylor, H.F.W. (Editor), 1964. The Chemistry of Cements, Vol. I. Academic Press, London, 460 pp. Tough, F.B., 1918. Method of shutting off water in oil and gas wells. U.S. Bur. Mines Bull., 163 (also Pet.

Tech., 46: 122). White, F.L., 1952. Setting cements in below freezing conditions. Pet. Eng., Part I (Aug.): B7; Part I1

(Sept.): B59. Wieland, D.R., Calvert, D.G. and Spangle, L.B., 1969. Design of Special Cement Systems for Areas with

Low Fracture Gradients. API Southwest. Dist. Div. Prod. Spring Meet., Lubbock, Tex., March 12-14.

Duncan, Okla.

Duncan, Okla.

63: 932-945.

Drill. Prod. Pract., API, pp. 257-272.

J . , 52(24).

Proc. ASTM, 58: 986-1008.

Tex., 72 pp.

World Oil, Houston, Tex., 13: 73 pp.

102: 17.

101

Chapter 4

FRACTURING

JOHN 0. ROBERTSON Jr., GEORGE V. CHILINGARIAN and SANJAY KUMAR

INTRODUCTION

Hydraulic fracturing has played a major role in increasing the oil and gas reserves. Veatch (1983a) reported that 35-40% of all currently drilled wells in the U.S.A. are hydraulically fractured. As a result of fracturing treatments, there has been an increase of economically producible U.S.A. petroleum reserves by 25-35%. This constitutes an increase of over 8 billion barrels of oil.

Oil and gas are displaced to the wellbore by several means after the well is drilled: (1) fluid expansion, (2) natural or artificial fluid displacement, (3) gravity drainage, (4) capillary expulsion, and (5) compaction of sediments and rocks. The various processes may work together or independently to drive the hydrocarbons into the wellbore through existing flow channels. In many wells, the production rates may be commercially insufficient either because of wellbore damage during drilling or very low formation permeabilities, which do not permit the hydrocarbons to drain into the wellbore at a sufficiently high rate.

In hydraulic fracturing, fluid is injected until the fluid pressure overcomes the stresses inherent in the rock or is greater than the forces holding the rock together. This causes the rock to split apart (rupture), forming a fracture. Fracturing fluid must be pumped into the fracture rapidly enough to hold the fracture open and allow the propping agent (e.g., sand) carried by the fluid to enter the fracture and hold it open. In some cases, a propping material is not used. If there is no propping agent present to hold the walls of the fracture apart, however, the fracture walls can close or “heal”. Fracturing creates new and larger flow channels through the damaged zones, around the wellbore. Fractures then extend out into the undamaged portions of the reservoir and may also connect the preexisting natural fractures and microfractures to the wellbore. In tight reservoirs, fractures create a much larger drainage surface area.

Early history

Between 1890 and 1950, the oil industry all over the world often used liquid, and later solidified, nitroglycerin to stimulate petroleum wells by creating fractures in the wellbore by the use of explosions (Hurst, 1953). Use of explosives was limited by the extreme hazards associated with handling of the unstable materials (Howard

102

5

p=PRESS. AT BOTTOM OF INJECTION WELL.pS1

Fig. 4-1. Water injection test, Hole 14; shot with 17.75 lb solidified nitroglycerin loaded 2.96 Ib/ft in 2-1/2 in. X 6 f t shell. (After Grant et al., 1950; courtesy of Drill. and Prod. Pruc., A P I . )

and Fast, 1970). The fracturing of the wellbore as a result of the explosions often resulted in spectacular increases in fluid production. An example of the type of improvement experienced is shown in Fig. 4-1. Grant et al. (1950) conducted a series of shallow well tests to study the effect of “well shooting” on the relationship between water injection rate and injection pressure. Figure 4-1 illustrates the direct benefits of stimulation as shown by the increased ability of the formation to take up more water at a much lower injection pressure.

Well stimulation with a high explosive charge became less popular after 1950 when the oil industry found that commercial fracturing treatments could accomplish the same results without the problems of (1) major postshooting wellbore cleanup operations, (2) damage to the casing, and (3) exposing personnel to the dangers of severe injury while handling dangerous explosives. Stanolind Oil and Gas Company (later Pan American Petroleum Corporation and then AMOCO) announced its hydraulic fracturing process in 1948. Farris (1946; in: Howard and Fast, 1970) studied the relationship between observed well performance and treating pressures. In review of 115 cement squeeze jobs in the Louisiana-Texas Gulf Coast area, U.S.A., Farris prepared a graph (Fig. 4-2) showing that the “breakdown” pressure is equal to the fracturing pressure (i.e., the pressure necessary to overcome the tensile or compressive strength) plus the effective overburden pressure. A similar study in the Oklahoma, North Texas, and New Mexico areas is shown in Fig. 4-3. Howard and Fast (1970) constructed Fig. 4-4 using data published by Grebe (1943), Dickey and Andersen (1945), and Yuster and Calhoun (1945). Howard and Fast (1970)

103

16,000 I I ,I MAXIMUMI

14,000

t 12,000

w Y lO.000

Y

5 8,000 0

Y

6,000

0

2 4,000

8 IL

2.000

0

OEPTH -THOUSbNDS OF FEET

Fig. 4-2. Formation breakdown pressures. (After R.F. Farris, 1946, in: 6; courtesy of the Society of Petroleum Engineers.)

Howard and Fast, 1970, fig. 1.6, p.

noted that the values fell within the extrapolated portion of the curves based upon formation breakdown field data.

A hydraulic fracture treatment for the Klepper No. 1 gas well, Hugoton gas field, Grant County, western Kansas, U.S.A., in 1947 is one of the earliest descriptions of the first attempts to hydraulically fracture wells. This well was completed and produced gas from four limestone horizons between 2340 and 2580 ft. Howard and Fast (1970) described the following treatment for this well:

Fig. 4-3. Comparison of various estimates of overburden pressures. (After Farris, Fast, 1970, fig. 1.10, p. 7; courtesy of the Society of Petroleum Engineers.)

1946, in: Howard and

104

Fig. 4-4. Comparison of various estimates of effective overburden pressure gradients. (After Howard and Fast, 1970, fig. 1.17, p. 8; courtesy of the Society of Petroleum Engineers.)

A centrifugal pump was used for mixing the gasoline-base napalm gel fracturing fluid. Fluid was injected with a positive-displacement high-pressure pump into the wellbore. All equipment was kept away (150 ft apart) from the well and mixing area due to high fire hazards.

The treatment consisted of four separated treatments-one on each gas-producing horizon. Each horizon was treated with 1000 gal of napalm-thickened gasoline followed by 2000 gal of gasoline containing 1% of an amine gel breaker.

Tests indicated that the treatment did alter the relative producing characteristics of the four gas-producing zones. Inasmuch as the deliverability of gas from these zones did not significantly improve, the attempt to stimulate the well was considered unsuccessful.

The technology associated with fracturing has improved with time. The first treatments consisted of injecting small volumes of fluid (200-400 gal) mixed with sand (1/2 lb/gal), injected at rates of 2-4 bbl/min (Halliburton, 1976). As

4 0

32

24

16

B

1950 1958 1966 1974

Fig. 4-5. Trend of average fracture treatments in the United States. (Courtesy of the Halliburton Co., 1976, fig. 2.1, p. 5.)

105

100

80 z E 60

s 40 ; 20 ' 1950 1954 1958 1962 1966 1970 1974

YEAR

Fig. 4-6. Trends in the use of oil-base and aqueous-base fracturing fluids. (Courtesy of the Halliburton Co., 1976, fig. 2.2, p. 5.)

operators experimented with larger, higher-injection-rate type jobs, more sustained production increases were noted. Gradually, the job sizes and injection rates began to increase. In the latter part of 1952, use of refined petroleum residuals and heavier crude oils became popular (Halliburton, 1976, p.5). As a result, treatment became more economical and the treatment trend curve has risen steadily since then. In 1974, treatments averaged about 40,000 gal with 42,000 lbs of sand, i.e., a sand/fluid ratio of approximately 1.1 lb/gal. Figures 4-5, 4-6 and 4-7 illustrate the changes that took place between 1950 and 1974 for fracturing technique.

The use of acids along with a wide variety of fracture fluids and proppants have been developed to cover a wide range of low-temperature (shallow) to high-temperature (deep) reservoirs. Hydraulic fracturing is often used as a well stimulation technique for both (1) improving damaged matrix permeability surrounding the wellbore, and (2) creating deep-penetrating fractures for fluid flow from deep within the producing formation. The latter dramatically increases the surface drainage area for the wellbore.

As pointed out by Halliburton Co. (1976), the success of a fracturing treatment heavily depends upon reliability of pumping and blending equipment. The blender or proportioner transfers the fracturing fluid from the storage area to the high-pressure pumping equipment (Fig. 4-8). A uniform mixture of chemicals and propping agent is added to the fluid, as it passes through the blender. Uniform mixture must be maintained regardless of the injection rates and volumes. Proportioning equipment

YEAR

Fig. 4-7. Evolution of fracturing techniques. (Courtesy of the Halliburton Co., 1976, fig. 2.3, p. 5.) I = Volume of fluid; 2 = injection rate; 3 = hydraulic horsepower.

106

BASIC FLUID

PUMP B

DRY CHEMICAL PROPORTIONER

FRACTURING FLUID SUPPLY PUMP

/

AGITAT OR

SAND OR SACK

BASIC FLUID

CONTROL

SAND BULK OR SACK CHEMICAL METERING

PUMP A ja pi� A J

CHEMICAL METERING Rr PUMP B

/ I 1 ,--FLOWMETER &% 4 SAND-FLUID MIXTURE TO PUMP TRUCK

/ STABILIZER

PRESSURIZER PUMP

Fig. 4-8. Schematic diagram of sand proportioner which permits: (1) continuous operation as long as supplied by fracturing ingredients, (2) maintaining constant ratio of materials within narrow limits regardless of injection rates, and (3) instantaneous variation of the sand/fluid ratio, either higher or lower, by manipulation of a simple control. (Courtesy of the Halliburton Co., 1976, fig. 1.9, p. 4.)

can alter the concentration of chemicals and propping agents during the job as dictated by the treatment requirements.

GENERAL CRITERIA OF WELL SELECTION

Maly and Morton (1951), Clark, J.B. et al. (1952), and Clark, R.C. et al. (1953) pointed out that most formations can be fractured. Not all formations, however, respond similarly (increase in production) as a result of fracturing. In general, formations that have been classified as medium to hard appear to give better results. Possibly, this may be due to “healing” and/or proppant embedment in the case of softer formations. Limestones, dolomites, well-cemented sandstones, and con- glomerates are potential candidates for fracture treatment. In general, softer formations such as unconsolidated sandstones are poor candidates.

Prior to selecting a well for a hydraulic fracturing treatment, the petroleum engineer must establish that the reservoir contains sufficient fluids along with the pressure to produce at rates high enough to cover the cost of the treatment. Generally, better results (larger and more sustained production increases) are obtained from fracturing if treatments are made early in the life of the field (Howard and Fast, 1970). Comparison of gross and net fluid production rates should be compared whenever possible with those of nearby wells. Potential candidates are those wells which show a significantly lower production.

107

At .hours ,o

4600

3400 1 I I 1oo,oO0 10.000 1000 100

(t+At)/A t

Fig. 4-9. Pressure buildup showing effect of wellbore damage and after-production. (After Matthews, 1961, fig. 4, p. 863; courtesy of the Society of Petroleum Engineers.)

Initially, the reasons for the low productivity of a well must be established. Some wells may only require a well wash or chemical stimulation treatment instead of the more costly fracturing treatment. The following methods are used in examining the formation and determining ability of a well to produce fluids: (1) comparison of its production to those of other wells in the area, and (2) evaluation of formation pressure buildup data. The extent of wellbore damage can be determined by examining the pressure versus [(time + A r ) / A r ] curve (Fig. 4-9). High production dechne rate can indicate wellbore damage and, consequently, a good candidate for fracturing treatment. On the other hand, in the case of a flat production decline curve, whch indicates good drainage, the well is not a good candidate for fracturing treatment. Obviously, one can expect a greater percentage production increase from “tighter” (low-permeability) formations, because the fracturing treatment increases the wellbore drainage surface area, thus permitting more fluids to migrate into the wellbore (see Fig. 4-10).

On considering a candidate for fracture treatment, previous experience with wells in the surrounding area should always be examined carefully, i.e., the fracturing method used and its effect on well production. New techniques, larger-sized treatments, and/or improvements in treating materials should be considered in order to improve the results of earlier jobs, which might not have been entirely successful .

Condition of the candidate well itself is also a very important factor. Inasmuch as the pressures within the wellbore are likely to be high, the casing and associated well-equipment must be in good condition and have a sufficient pressure rating to handle the fracture treatment. Bottomhole treating pressures of 1 psi/ft of vertical depth should be anticipated. It is also important to insure that the generated fracture system is not extended into the water-bearing zones. Vertical fractures should not be allowed to extend into either the gas or water zones above or below the producing horizon. The treatment should not affect either the GOR or WOR.

108

7 . 7

c VI

I c C 0

- a

14

12

10

a

t

L

L

C

k =formation D!rmeabilitv. md ' L/re =-l.O L = frac length from welldore. ft w =propped frac width. in. ki =permeability of proppant. md wki =conductivity of fracture. md-in. re =drainage radius of well, ft J =productivity index after fracturing

I I Curves based on 40-acre sDacinz h 3-in. wellbore radius. I Scaling factors must be used fo;other well spacings.

I I

103 lo’ 105 1 0 6

Perrnea bility contrast, wk, /k

Fig. 4-10. Effect of (1) permeability contrast between fracture and formation, and (2) fracturing length on the expected increase of productivity index in a hydraulically fractured well. Curves are based upon 40-acre spacing and 3-in. wellbore radius. Scaling factors must be used for other well spacings (see Table 4-1). (After McGuire and Sikora, 1960; courtesy of the Society of Petroleum Engineers. Also see Allen and Roberts, 1982, p. 125.)

Howard and Fast (1970) pointed out that the key to proper selection of a good candidate well for hydraulic fracturing is determination of the cause for its low productivity. This enables treatment of the cause and not the symptom.

MECHANICS OF HYDRAULIC FRACTURING

Hydraulic fracturing process variables

The variables that affect the stimulation process, can be grouped into three basic categories: (1) controllable by engineering design, (2) non-controllable by engineering design, and ( 3 ) with limited controllability. Theoretically, the parameters of group ( 3 ) may be controllable; however, limitations imposed by prior operating procedures may limit the range of variation possible. The pumping rate during the treatment is such an example. It may be limited due to the wellbore dimensions whch can cause excessive pressure loss at high flow rates.

A review of the past hydraulic fracture treatments indicates the following reasons for failure of stimulation treatments (Republic Geothermal, Inc., 1979): (1) the generated fractures were not confined to the targeted interval of treatment, (2)

109

communication of fracture fluid at the wellbore produced stimulation of the non-targeted interval, (3) premature termination of the stimulation treatment, (4) an incorrect selection of proppant, (5 ) insufficient volume of proppant, (6) the fracture fluid was incompatible with the formation fluids, (7) an improper perforation program, and/or (8) incomplete returns of treating fluids. In the case of successful treatments, the following common procedures were noted: (1) use of water as a fracturing fluid, (2) overdisplacement, at a low rate, to help minimize back production of proppant, (3) use of spacers to help reduce proppant concentration and, thus, reduce the possibility of a screenout, (4) reduced pumping rates near the end of the treatment tends to enhance proppant packing and conductivity, ( 5 ) energizing the last portion of the injected fluid speeds cleanup and improves productivity, and (6) use of a surfactant for lowering the surface and interfacial tension has helped to reduce fracturing fluid recovery from the formation. Before designing a fracture treatment, both the successes and the failures of similar treatments must be examined for nearby wells. Inasmuch as much equipment and materials are involved, the cost of failure is high.

Rock mechanic considerations

An excellent treatment of the mechanical behavior of rocks was presented by Halliburton Co. (1976) and Craft et al. (1962). Competent rocks behave as elastic and brittle materials over certain ranges of conditions. Dimensions of a rock change when stressed either in tension or compression. The term “strain” refers to these dimensional changes. The ratio of lateral strain to axial strain of an elastic material is known as Poisson’s ratio, v. This ratio ranges from 0.05 to 0.45 for most rocks, averaging 0.2.

The ratio of stress to strain, referred to as the modulus of elasticity or Young’s modulus, E , is another fundamental rock property. Average values range from 0.5 x lo6 (lightly consolidated sandstones) to 13 X lo6 (denser limestone or dolomite). Rocks which behave elastically up to some limiting stress, rupture or fail in a tensile or shear failure depending upon the direction of the stress. The plane of shear failure depends upon the direction of the stress and is located at an angle to the axis of stress. The internal angle of friction, which is related to the axis of stress, ranges from 35” to 0” . A typical value of internal angle of friction for many competent rocks is about 30 ”.

If a rock cylinder, S, having a radius, r , is stressed by a force, F (Fig. 4-11), the stress, u, is equal to the force divided by the cross-sectional area of the cylinder:

0 = F/.rrr2 (4-1)

The direction of this stress is parallel to the z-axis and, therefore, may be referred to as a,. In this case, there is no stress in the x or y direction as no force is applied in that direction. The rock will shear if the stress along any axis exceeds the strength of the rock along that axis.

Compressive or tensile stresses of any magnitude can be generated by changing

110

DENSITY, g/cm3

Fig. 4-11. Variation of shale bulk densities with depth in sedimentary basins. I = methane-saturated clastic sedimentary rock (probable minimum density) (after McCulloh, 1967, p. A19), 2 = mudstone-Po Valley Basin, Italy (after Storer, 1959), 3 = average Gulf Coast shale densities; values derived from geophysical data (after Dickinson, 1953, p. 427), 4 = average Gulf Coast shale densities derived from density logs and formation samples (after Eaton, 1969), 5 = Motatan-1-Maracaibo Basin, Venezuela (after Dallmus, 1958, p. 916), 6 = Gorgeteg No. 1-Hungary; calculated wet density values (after Skeels, 1943), 7 = Pennsylvanian and Permian dry shale density values, Oklahoma and Texas; Athy's adjusted curve (after Dallmus, 1958, p. 913), 8 = Las Ollas-1-eastern Venezuela (after Dallmus, 1958, p. 918). (See Rieke and Chilingarian, 1974, p. 34.)

the direction or magnitude of force on the rock cylinder. Because of lithological variations, stresses can vary in magnitude and/or direction from point to point in the rock.

In order to calculate the total stress on a reservoir rock, the pore pressure must be taken into consideration. The total stress is the sum of the intergranular stress in the rock and the stress or pressure exerted by the formation fluid (pore pressure). The total vertical stress (overburden load) in a formation at any depth is equal to the pressure exerted by the weight of the fluid-saturated rock overlying the formation. Jakosky (1950) reviewed the work of many investigators and noted that rock densities vary from 2.0 g/cc at shallow depths to approximately 2.6 g/cc at depths of 10,000 ft (also see Fig. 4-11). Using an average density of 144 lb/cu ft, the vertical stresses may be estimated by using a pressure gradient of 1 psi/ft. As a result of this overburden, the vertical force tends to deform the rock laterally. Inasmuch as the rock is contained by the surrounding rock, however, the vertical force results in a horizontal stress

' Compressive stress is usually designated by a plus sign, whereas tensile stress has a negative sign. Thus, theoretically stress can have values ranging from + w to - w, whereas the lowest possible pressure is zero.

111

6,” HORIZONTAL FRACTURE I (CASE I )

FRACTURE PLANE

VERTICAL FRACTURE (CASE Ill)

HI R

VERTICAL FRACTURE (CASE It)

&HI > 6 V > 6 H,

Fig. 4-12. Effect of relative magnitude of principal stresses on fracture orientation. (After Fertl and Chilingarian, 1978, fig. A-4, p. 301; courtesy of Elsevier Science Publishers.)

Fractures initiate and extend in a plane perpendicular to the least principle stress (Fig. 4-12) when the pressure exceeds the strength of the rock. Once the fracture has been initiated, fluid enters the fracture and the fluid pressure is applied directly to the fracture faces. This reduces the stress concentration about the wellbore. The pressure required to hold the fracture open is equal to the opposing stress perpendicular to the fracture plane. The fracture will continue to extend away from the wellbore as long as the pressure at the tip or leading edge of the fracture is above the strength of the rock. Inasmuch as there is fluid friction loss in the fracture, there is a resultant pressure drop in the fluid between the wellbore and tip of the fracture.

The rock cylinder shown in Fig. 4-13 is deformed by the applied force. Inasmuch as the original length, L , of the cylinder is compressed by an amount, AL, the deformed length is ( L - A L) . Dimensionless strain, c, is equal to:

( L - A L ) - L - AL E = - - -~

L L (4-2)

Strains in different directions in the same body may have different values at different points. The strain in the z direction is equal to:

AL L

E = - - z (4-3)

The radius of the rock cylinder changes from r to ( Y + Ar) upon application of force F

( r + A r ) - r - A r _ - E x = E y = r r (4-4)

112

Fig. 4-13. Schematic of a rock cylinder showing deformation as a result of applied force F. (Courtesy of the Halliburton Co., fig. 4.1, p. 9.)

In an elastic material, the strain is linearly proportional to the induced stress:

(4-5) 1 E

€ = = -a,

where the constant, E , is the Young’s modulus of the material. If the weight of the overburden (a, = p , = y,h, where p , is the overburden pressure in lb/ft2, y, = specific weight of rock in lb/ft3, and h = depth of burial in ft) is the only force acting in an isotropic, homogeneous and linearly elastic formation, then the stresses in the x and y directions (a, and up) are equal to:

where v is Poisson’s ratio. Young’s modulus has dimensions of force per unit area (e.g., lb/in? ), whereas Poisson’s ratio is dimensionless. Poisson’s ratio for consolidated sedimentary rocks ranges from 0.18 to 0.27 (Birch et al., 1942), whereas the horizontal compressive stress ranges from 0.22 to 0.37 psi/ft of depth. According to Harrison et al. (1954), the soft shales and unconsolidated sands found in the Gulf Coast area of the U.S.A. appear to be in a plastic state of stress and possess horizontal stresses in excess of 0.37. In the absence of external forces, the horizontal stress is always less than the vertical stress.

According to Hubbert and Willis (1957), in areas of normal faulting the least stress is horizontal and ranges from 1/2 to 1/3 of the effective pressure of the overburden. The greatest stress is approximately vertical and is equal to the effective pressure of the overburden. In areas with thrust faulting and folding, on the other hand, the greatest stress is horizontal (2-3 times the overburden pressure) and the least stress is vertical (equal to the effective overburden pressure).

In rock mechanics, it is assumed that rocks are isotropic, homogeneous and

113

elastic. Although this is not true, for many rocks the above equations give a reasonable approximation of the actual values (see Halliburton, 1976).

The magnitude of the force that rocks can bear without failure depends upon the type of force, i.e., compressive or tensile. Inasmuch as the compression strength is 10-100 times that of the tensile strength, rocks break perpendicular to the axis of tensile force. When a rock fails as a result of compressive force, it does not exhibit a clean break or fracture. Instead the rock crumbles yielding a crushed material of irregular shapes and sizes. Due to lithological heterogeneities of rocks, the strength is measured many times on different samples and averaged to yield a representative value.

Fracture geometry

The results of hydraulic fracturing treatment depends upon the geometry of the created fracture. In the case of horizontal fractures this means width (separation distance of the two fracture faces) and radius. For vertical fractures this refers to width, length (lateral dimension) and height (vertical dimension). The volume of fluid injected into the fracture, rate of fluid flow along the fracture length, and rate of fluid leak-off into the formation along the fracture face affect the geometry of the generated fracture.

The volume of fluid that stays in the fracture and extends it, V,, is equal to the total volume of the fluid injected, V,, minus the volume of the fluid that leaks off, V,, i.e., V, = (V, - V,). The V, volume is equal to the product of the injection rate, q,, of the surface pumps, and time, t , less the volume of fluid that leaks off during the fracture treatment, V,:

v , = q i t - V, (4-7)

The term "volume efficiency", E,, for a fracture fluid is the ratio of the fluid injected into the fracture, V,, divided by the total volume of fluid injected, V,:

E,=(V,/V,:) (4-8)

The fluid pumped inside the wellbore and out into the fracture must overcome the frictional forces of movement over the fracture faces. The frictional losses due to the fluid flow create a pressure drop between the wellbore and the fracture tip, Ap, . Christianovich and Zheltov (1955) pointed out that this drop in pressure plays an important role in the computation of geometry of the fracture. The fluid does not occupy the entire length of the hydraulic fracture. The tip of the fracture has a cusp-like shape and does not contain fluid. Thus, if xo is the wetted length of a vertical fracture, then A p , can be calculated using Daneshy's (1973) formula:

' A.A. Daneshy is one of the foremost and greatly respected experts on fracturing in the world.

114

Fig. 4-14. Schematic diagram showing cross-section of a fracture with "leak-off". (Courtesy of the Halliburton Co., 1976, fig. 5.1, p. 16.)

where n' = flow behavior index (power-law model), K ' = absolute consistency (power-law model), and q ( x ) and w ( x ) denote the flow rate and fracture width, respectively, at a point along the fracture length. The power-law constants n' and K ' can be used to determine the apparent viscosity pa (cP):

pa=47.917K'(P)"'-' (4-10)

where shear rate, P, is typically equal to: -) = 40.464 q / w 2 h , where q = volumetric rate of flow (bbl/min), w = fracture width (in.), and h = fracture height (ft). (See Halliburton Co., 1976; and Chilingarian and Vorabutr, 1983.) Assuming that uy is the least in-situ principal stress (Fig. 4-14), then the treatment pressure of a hydraulic fracture, pf, can be calculated from the following formula (Halliburton, 1976):

Pf = uy + APC (4-11)

The fluid pressure at the surface is computed by adding to pf the frictional losses due to flow in the wellbore, tubing, and through the perforations, and subtracting

Fig. 4-15. Typical relationship between fluid loss from fracturing fluid and time. (Courtesy of the Halliburton Co., 1976, fig. 5.2, p. 16.)

115

from it the pressure head due to the vertical column of treating fluid from the surface to the fracture depth. The value of A p , does not include the influence of a propping agent present in the treatment fluid (Halliburton, 1976).

The "leak-off" volume is part of the fluid in contact with the formation fracture faces which penetrates into the formation pores. This lost fluid does not help extend the fracture. The results of a typical fluid-loss test conducted in a laboratory are presented in Fig. 4-15. The fluid-loss volume versus time curve exhibits two parts: (1) generation of a filter cake on the surface of the fracture; and (2) "leak-off'' through the filter cake. Fluid loss is controlled in the field by the addition of fluid-loss additives to the fracturing fluid. These additives decrease the permeability of the filter cake on the fracture face and, thus, slow down the rate of fluid loss. The fracture dimensions decrease with increasing leak-off rates.

Fracture inclination

Allen and Roberts (1982) pointed out that knowledge of the direction or inclination of a fracture is desirable in order to: (1) estimate the increase in post-fracturing productivity, (2) determine whether multiple fracturing is feasible or

Fracture BOnomho'e propagation pressure

Fracture

closure pressure

Horizontal Vertical matrix

Reservoir

@ Sand Y = 0.30. E = 3 x lo6 -

@ Shale Y = 0.33, E = 4 Y lo6

Fig. 4-16. Pressures, stresses, and rock properties involved in vertical fracture propagation. (After Allen and Roberts, 1982, fig. 5 , p. 119; courtesy of the Oil and Gas Consultants International, Inc.)

116

not, and (3) avoid extension of fractures into areas where they are not desired. Figure 4-16 illustrates the pressures, stresses, and other rock properties involved in vertical fracture propagation about a wellbore. The inclination of horizontal or vertical fractures in sedimentary rocks can affect “leak-off” during fracture operations. The productivity ratio of the fractured well after fracturing is also affected because the fracture angle controls the zones which are opened to the wellbore. Usually, the fracture plane tends to be vertical when the fracture gradient is < 0.7 psi/ft. Horizontal fractures occur when the fracture gradient is > 1.0 psi/ft. Pressure in the fracture must exceed the pore pressure by an amount equal to the minimum effective rock matrix stress in order to hold the fracture open after initiation. This pressure is often called “closure” pressure.

Vertical fractures tend to extend further into the formation than horizontal fractures. It is important to mention here that the writers in their experience have not observed horizontal fractures. The length and width of a fracture depends upon the existence and location of barriers above and below the fractured zone. Inasmuch as horizontal stresses are higher in shales than in the producing sandstone zone, the length of a fracture increases, whereas its height does not. Barriers less than 10 f t in thickness are usually not restrictive, whereas barriers > 25 f t are restrictive. In carbonate reservoirs, anhydrites, like shales, can form impermeable barriers.

Fracture initiation

Continuous monitoring of pressure enables evaluation of the progress of a fracture treatment. As shown in Fig. 4-17, the fracture initiation may be observed on a pressure-versus-time curve by a sudden drop in borehole fluid pressure, which is accompanied by an increase in the injection rate. The surface treating pressure, pwh, is equal:

P w h = P b h + ‘pc + ‘pf -k ‘ P p f - p h (4-12)

where p b h = bottomhole treating pressure, A p , = pressure loss due to fluid flow in

INJECTION RATE

z -

TIME - Fig. 4-17. Idealized pressure and injection rate during a hydraulic fracturing treatment. (After Daneshy, 3973b, fig. 1, p. 17; courtesy of the Petroleum Engineer.)

117

Fig. 4-18. Schematic showing location of pressure losses in a fracturing treatment. (Courtesy of the Halliburton Co., 1976, fig. 9.1, p. 42.)

the wellbore between the wellhead and perforations, Appf = pressure loss through the perforations, ph = hydrostatic pressure due to the weight of the column of fluid between the injection pump and perforations, and Ap, = pressure losses due to fluid flow in the fracture between the wellbore and tip of the fracture (see Fig. 4-18).

FLOW RATE THROUGH PERFORATION - BPM

Fig. 4-19. Relationship between the pressure differential and flow rate through perforations of different sizes. Water contains 1-1/2 Ib sand per gal. (After Howard and Fast, 1970, fig. 7.10, p. 104; courtesy of the Society of Petroleum Engineers.)

118

SAND-POUNDS PER GALLON

Fig. 4-20. Effect of sand concentration on friction pressure. (Courtesy of the Dow Chemical Company.)

The friction losses in eq. 4-12 can be estimated by using Figs. 4-19 through 4-26. The hydraulic horsepower, H p , necessary to move fluid is determined by the fluid

injection rate, qi, in bbl/min, and the surface treating pressure, pwh, in psi, at which the fluid is being pumped:

H p = 0.0245pw,,qi (4-13)

The wellhead pressure, pwh, can be increased by using ball sealers and diverting agents. The total number of pumps required for a hydraulic treatment can be determined from the flow rate of each pump and the maximum H p required.

One of the properties determining the type of fracturing fluid to be selected is its friction loss properties. The principal source of friction loss during fluid injection is that in the tubing, due to the skin friction of the flowing fluid against the pipe wall. Head loss due to friction, h , , in ft-lb/lb or in ft of fluid flowing is equal to f ( / / d ) ( V,2/2g), where f = friction factor, / = length of pipe in ft, d = diameter of pipe in ft, V = fluid velocity in the pipe in ft/s, and g = gravitational acceleration (= 32.2 ft/s ). Friction factor is a function of the Reynolds number, N,, which is 4

119

Fig. 4-21. Correction of friction loss for changes in specific gravity. (Courtesy of the Dow Chemical Company.)

equal to V,dp/p, where p = density of the fluid flowing (= specific weight, y, in lb/ft3 divided by the gravitational acceleration, g ) , and p = fluid viscosity. At some critical velocity, the flow changes from a laminar to a turbulent type of flow.

Fracture area

The following equation relates the rate of leakoff, q l ( t ) (cu ft/min), to the velocity perpendicular to the fracture, u (ft/min), and the fracture area (one face), A (ft2):

q l ( t ) = 2Jb l ( ' )u ( t ) dA (4-14)

where t = total pumping time (min), and dA = element of the fracture area formed at time 6, where 6 = time required for the fluid to reach a given point (min). Thus

120

F L O W RATE - BPM

Fig. 4-22. Friction pressure of water-base fluids in 2-7/8411. OD tubing, 6.5 lb/ft. (Courtesy of the Dow Chemical Company.)

( t - 8 ) = time interval during which fluid escapes (leaks off) at any particular point (min). Inasmuch as A is a function of time:

d A = - d8 (Y j Thus eq. 4-14 can be presented as follows:

q 1 ( t ) = 2 i ' u ( t - 8 ) (3 - d8

(4-15)

(4-16)

121

1000 900 800 700

CODE ADDITIVE/1000 GAL VISCOSITY ICPI

I NONE I 600

500 I MODlflED G U M GUM IIOI) 7 - 3 MODIFIED G U M GUM 12011 16 I MODIFIED G U M GUM l l O X ) 65 - I MODIFIED G U M GUM (6011 130

400

6 MODIFIED G U M GUM l8OX) ZIC

1 2 3 4 5 6 7 8 9 1 0 2 0 30 40 50 60 80 100 FLOW RATE - BPM

Fig. 4-23. Friction pressure of water-base fluids in 4-1/2411. OD casing, 11.6 lb/ft. (Courtesy of the Dow Chemical Company.)

The fracture volume will increase at the following rate:

qt = w(dA/dt) (4-17)

where qf = part of the liquid which extends the fracture [ qf = (4 t - 4,), where qt = total injection rate (ft3/min), and w = fracture width (ft)]. Thus:

(4-18)

122

Fig. 4-24. Friction pressure of water-base fluids in 7-in. OD casing, 23 lb/ft. (Courtesy of the Dow Chemical Company.)

Carter (1957) solved the latter equation for A at any time, A ( [ ) , by means of Laplace transformation, assuming that qi is constant and the equation for u ( t ) is known:

(4-19)

where x = 2 C a / w , C = fracturing-fluid coefficient in ft/& and erfc(x) = the complementary error function of (x), the values of which have been calculated and

123

3 4 5 6 7 8 9 1 0

Polymer (Friction Reducer) (2.5) 3.0 Guar (Friction Reducer) (10) 8.5 - Guar (Friction Reducer) (40) 65.0 Acid Retarded with a Natural Gum 5.0

1 1 3 4 5 6 7 8 V l O 10 30 40 60 80

FLOW RATE - BPM

1000

9 W

8W

700

6W

500

ux)

3w

ZW

IW ?O

10

0

10

I0

10

10

0

0 ,

Fig. 4-25. Friction pressure of acid-base fluids in a 2-7/8411. OD EUE tubing, 6.5 lb/ft. (Courtesy of the Dow Chemical Company.)

are presented in tables in several books (e.g., see excellent treatment by Craft et al., 1962, chapter 8, pp. 499-500).

Fracturing fluid coefficient

As shown by Craft et al. (1962, p. 502), the velocity of leak-off perpendicular to the fracture wall, v (ft/min), is equal to:

v = C"/fi (4-20)

124

Fig. 4-26. Friction pressure of oil-base fluids in a 2-7/8411. OD EUE tubing, 6.5 lb/ft. (Courtesy of the Dow Chemical Company.)

where fracturing fluid coefficient C, is in f t / G . It is equal to:

C, = 0.0469( kAp+/p)’” (4-21)

where k = effective formation permeability to the fracturing fluid (d), A p = pressure differential across the fracture face (psi), + = formation porosity (fraction), and p = viscosity of fracturing fluid at formation temperature (cP). A p = ( Fg X 0) - pw,, where Fg = fracture pressure gradient (psi/ft), D = depth of fracturing (ft), and p,, reservoir pressure (psi).

125

FRACTURING FLUIDS AND ADDITIVES

The fracturing fluids used in early treatments consisted of crude and refined oils, because of possible detrimental aspects of contacting a hydrocarbon reservoir with water (Burnham et al., 1980). Subsequent experience with the appropriate additives (e.g., clay control materials and surfactants) showed that most reservoirs can be treated using an aqueous fluid.

The fracturing fluid (1) opens and extends a fracture hydraulically, and (2) transports and distributes the proppant along the fracture. The properties of this fluid are of utmost importance. There is a low efficiency in hydraulic wedging and extending of the fracture in the case of rapid leakoff of fracturing fluids into the surrounding formation (Veatch, 1983a). Fluid leakoff may damage the formation, reducing the wellbore matrix permeability by blocking the pore channels. Internal fracturing pressure and the proppant agent transporting characteristics can be controlled by adjustment of the fracture fluid viscosity. Inasmuch as the fluid may react with the formation and/or the proppant within the fracture itself, proper selection of the fracturing fluid is critical. Obviously, the cost of the fluid is also of great importance. Temperature and pressure at which the treatment takes place, which may determine the ability of a particular type of fluid to perform, must also be considered in the final selection of the fluid.

Veatch (198313) listed the following requirements in the selection of a fracturing fluid: (1) low fluid loss to achieve designed penetration with minimum fluid volumes, (2) sufficient effective viscosity to create the necessary fracture width and to transport and distribute the proppant in the fracture as required, (3) no excessive fraction in the fricture, (4) good temperature stability at reservoir temperatures, (5) good fluid shear stability, (6) minimal damaging effects to the formation matrix permeability, (7) minimal plugging effects on fracture conductivity, (8) low friction loss in the pipe, (9) good post-treatment breaking characteristics, (10) good post-treatment cleanup and flowback behavior, and (11) low cost.

The fracturing fluid lost to the formation opposite the fracture face decreases the relative permeability to the oil and/or gas and, thus, decreases the formation post-treatment deliverability. Fracture fluid invasion may also cause the reduction of matrix permeability as a result of the swelling of clays in the formation. The degree of damage is dependent upon the initial permeability, content and type of formation clay, and type of fracturing fluid.

Liquid and solid residues are left behind in the fracture by the fracturing fluid. If the fracture face is softened by the fluid, proppant embedment will result in the reduction of fracture-surface permeability. The effect of effective stress on fracture conductivity already shows the degree of damage. A gentle slope of the curve in Figs. 4-27 and 4-28 indicates the packing of the proppants with increasing stress. For the three samples shown, points B, C, and D represent the stabilized fracture conductivity with no fracturing fluid damage, whereas points B', C', and D’ represent the lowest fracture conductivity equal to or greater than that of packed fractures at the same applied stresses. The following factors reduce fracture conduc-

126

m E

> k ?

n 2 102-

z 0

w E 3 + V 4 rY L L

EFFECTIVE STRESS, p s i

Fig. 4-27. Fracture conductivity versus effective stress for a Devonian shale, Martin County, Kentucky. (After Republic Geothermal, Inc., 1980, fig. 1, p. 1-7; courtesy of the U.S. Department of Energy.) Depth = 3028 ft, test temperature = 24O C (75 O F ) , proppant = 20-40 mesh sand, proppant distribution = packed layer, 0.3 Ib/ft2.

EFFECTIVE STRESS, MPe

5 10 15 2 0 in3L I I I I

VIRGIN SAMPLE

I

LAYER

lO lo L I000 moo 3000

EFFECTIVE STRESS, p s i

Fig. 4-28. Fracture conductivity versus effective stress for Medina sandstone in New York. (After Republic Geothermal, Inc., 1980, fig. 1, p. 1-7; courtesy of the US. Department of Energy.) Depth = 4022 f t , test temperature = 24O C (75 OF), proppant = 20-40 mesh sand, proppant distribution = packed layer, 0.3 lb/ft2.

127

TABLE 4-1

Scaling factors for productivity estimates (see Fig. 4-10) (After McGuire and Sikora, 1960; courtesy of the Society of Petroleum Engineers)

Well Drainage ( w k , / k ) ( J / J O 1

(acres) (ft)

spacing radii

20 467 1.42 1.05 40 660 1 .00 1.00 80 933 0.71 0.95 160 1320 0.50 0.91 320 1867 0.35 0.87 640 2640 0.25 0.84

For other spacing ( A ) and radii:

wk,/k = J4o/A 3.095

J/Jo =

log(0.472)( r e / r w )

tivity (Republic Geothermal, Inc., 1979): (1) packing of a proppant which is predominant in fully-packed layers, (2) proppant embedment due to softening of fracture face, (3) proppant crushing which is predominant in a partial layer, (4)

TABLE 4-11

Commonly used fracturing fluid systems (After Veatch, 1983b, table I, p. 854; courtesy of the Society of Petroleum Engineers)

Water-base polymer solutions of Natural guar gum (guar) a

Hydroxypropyl guar (HPG) a

Hydroxyethyl cellulose (HEC) Carboxymethyl hydroxyethyl cellulose (CMHEC) a

Polymer water-in-oil emulsions 2/3 hydrocarbon + 1/3 water-base polymer solution

Gelled hydrocarbons Petroleum distillate, diesel, kerosene, crude oil

Gelled alcohol (methanol) Gelled CO, Gelled acid (HCl) Aqueous foams

Water phase: guar, HPG solutions Gas phase: nitrogen, CO,

a Can be crosslinked to increase viscosity. Petroleum distillate, diesel, kerosene, crude oil. Usually guar or HPG.

128

fracture fluid residue clogging of channels in packed layers, (5) clogging of channels due to release of fines, and (6) clay flocculation especially at proppant embedment locations.

The various types of fluid systems used for fracturing treatment are listed in Table 4-11. Additives are added to the fluid (see Table 4-111) for controlling its properties. According to Veatch (1983b), the selection of the type of fracturing fluid should be based upon the following variables: (1) formation temperature, (2) fluid temperature profile, (3) the length of time the fluid will remain in the fracture, (4) proposed treatment volume and pumping rates, (5) type of lithology (sandstone, dolomite, limestone, etc.), (6) fluid loss, (7) formation sensitivity to fluids, (8) clay content and type, (9) reservoir pressure, (10) pumping pressure, (11) pipe-friction losses, (12) type(s) and quantity of proppant, and (13) fluid breaking requirements.

Oil-base fluids

Gasoline, kerosene, diesel oil, or crude oil thickened by napalm (an aluminum fatty acid salt), an alkali metal, or aluminum carboxylate were the first fluids used in hydraulic fracturing operations (Minich, 1945). The gelling increased the viscosity of the fluid and helped reduce the fluid loss while injecting the material into the formation. Later, when the gel broke, the viscosity was reduced and fluid flowed freely back into the wellbore. This also improved the ability of the oil-base fluid to carry proppants. The use of carboxylate salts resulted in improved fluids using aluminum orthophosphates (Pellegrini and Strange, 1961; and Crawford et al., 1973). The gelled oil was often followed by a viscous refined oil, such as API No. 5 and No. 6 residual fuel oil, lease crude oil, fatty acid-soap gels, and, finally, by emulsions and acid-base fluids (Howard and Fast, 1970, p.51).

Fluid-loss-control additives should (see Howard and Fast, 1970, p.51): (1) be required in small concentrations, (2) be easily produced back from the formation upon completion of the treatment, (3) be relatively inert and/or compatible with the formation fluids, and (4) not cause emulsions that might hamper surface treatment and shipping of the produced crude oil. Alkaline earth salt of a sulfonated alkylbenzene was found to help reduce the. fluid loss of lease crude oil systems, refined oils, and emulsions (Brown and Landers, 1957; Phansalkar et al., 1962). Gilsonite, asphalts and blown asphalt have also been used to reduce the fluid loss (Steward and Coulter, 1959).

Friction reducing additives often used in oil-base fracture fluids are (1) fatty acid soap-oil gel, and (2) high-molecular-weight hydrocarbon polymer. The fatty acid soap-oil, while reducing the friction of the system, also tends to increase the fracture fluid viscosity. Aluminum orthophosphate fluids enhance temperature stability and frictional drag reduction (Burnham et al., 1980). This additive can control the viscosity of the fracture fluid at temperatures of up to 225 OF (107 O C). At higher temperatures, the gelled hydrocarbons are presently inferior to aqueous fluids in their ability to handle propping agents. The biggest problem seems to be the lack of thixotropic properties.

129

Temperature ("C) 10 30 50 70 90 110 121.1

10,000

2 30 6ol OL 50

i 4

Aluminum Phosphate

,> 100 150 200 250--Time (hrs) at 250°F - -

1 9,000

5.000

4.000 2 3,000 & 2,000

1,000

I

Temperature ( O F ) 0 0 5 1 0 1 5 2 0

Fig. 4-29. Viscosity profile comparison for kerosene containing an aluminum phosphate thickener with and without delayed aluminum phosphate. (After Burnham et al., 1980, fig. 2, p. 218; courtesy of the Society of Petroleum Engineers.)

Baker et al. (1970) proposed the formation of association colloids after proper dispersion of alkali metal or aluminum carboxylates in nonpolar media. Burnham et al. (1980) described several successful fracture treatments using a "delayed" aluminum phosphate as the gelling agent with HST's of 190-285 OF (88-141" C). The delayed gelling agent dissolves completely in the fluid at 150OF (66"C), resulting in high viscosities in the fracture with only moderate viscosities at the surface (Fig. 4-29).

The oil-base fracturing fluids are particularly useful where the formation is (1) water sensitive, due to a significant clay content in the reservoir matrix that will swell when contacted by waters containing different concentrations and/or types of ions, or (2) water soluble. Serious problems may arise, however, if the oil-base fracturing fluid forms emulsions in the reservoir rock pores. This will reduce the matrix permeability to fluid flow. Oils could be re-used when produced back from the formation.

Water-base fluids

Water is the most commonly used fracturing fluid due to its low cost and availability. The gelling agents used in most aqueous fracturing fluids are polymeric hydrophilic chemicals. The most common classes of polymers used in fracturing fluids are gum guar (Fig. 4-30), gum guar derivatives (Fig. 4-31), cellulose derivatives (Fig. 4-32), polyacrylamides (Fig. 4-33), and partially hydrolized polyacrylamides (Root, 1966). Water-base system can be economically designed through the addition of additives to handle a wide range of formation types, depths, pressures, and temperatures. In the earlier days of fracture treatment, water-base fluids were thought to be harmful for oil formations and were not commonly used. In 1965,

130

REPEATING UNIT FOR GUAR POLYMER n = 400-630

r 1

Fig. 4-30. Repeating unit for guar gum. n = 400-600. (Courtesy of the Halliburton Co., 1976, fig. 12.1, p. 46.)

REPEATING UNIT FOR GUAR DERIVATIVE R=H OR HYDROXYALKYL GROUP

n - 400-600

1

Fig. 4-31. Repeating unit for guar derivative R=H or hydroxyalkyl group. n = 400-600. (Courtesy of the Halliburton Co., 1976, fig. 12.2, p. 47.)

REPEATING UNIT FOR CELLULOSE DERIVATIVE R=H,

HYDROXYALKYL, OR CARBOXYMETHYL n - 3-4M

Fig. 4-32. Repeating unit for cellulose derivative R=H, hydroxyalkyl, or carboxymethyl. n = 3-4M. (Courtesy of the Halliburton Co., 1976, fig. 12.3, p. 47.)

131

Fig. 4-33. Repeating unit for polyacrylamide R=NH, or 0- Na+. n =15-250M. (Courtesy of the Halliburton Co., 1976, fig. 12.4, p. 47.)

Black and Hower (1965) noted that two-thirds of the wells were being fractured with water-base fracturing fluids. Today the percentage is probably around 80%. The advantages of water-base fracturing fluids over other systems include: (1) reduced fire hazard during treatment, (2) availability of water in large quantities in most areas, (3) generally low cost of obtaining water when compared to other fluids, (4) ease of mixing additives in a water-base system compared to that €or other types of fluids, ( 5 ) generally lower viscosities for water-base systems which result in lower pumping pressures, and (6) higher specific weight of water as compared to that of oil or other fluids, which yields a higher hydraulic head on the formation to be fractured. This reduces the actual cost of the operation because of lower pump pressures (or lower horsepower) required to produce the desired downhole pressures. Operators often experience a 20-30% drop in cost after switching from oil-base to water-base systems. In addition, it is easy to chemically modify the properties of water.

Ousterhout and Hall (1961) described the action of friction-reducing agents on water-base systems as a suppression of fluid turbulence. The presence of a small amount of high-molecular-weight linear polymer (Fig. 4-32), such as polyacrylamide, reduces the swirling and eddying when the fluid is in motion and thus reduces the turbulence of the fluid. Consequently, the friction-reducing material extends the range of laminar flow to higher velocities.

“Surfactants” (surface-active agents) are commonly-used additives in water-base systems. They reduce the interfacial tension and resistance to the fluid flow back from the formation, after treatment. Obviously, the initial type of wettability (oil-wet, water-wet, or mixed) of the formation must be known. In addition, control of interfacial tensions can help reduce (or limit) generation of foam in the presence of gas. Bernard et al. (1965) pointed out that generation of foam in the pore and flow channels can reduce the flow capacity of the fluid, which reduces the effectiveness of the treatment. In the case of gas well stimulation, McLeod and Coulter (1966) pointed out that addition of 10-20% alcohol results in reduction of the interfacial tensions and improvement of the fracturing fluid penetration into the reservoir. Economic considerations (i.e., high cost of alcohol), however, limits this application.

132 ::m 300

0 : 200 ’ 100

-

0 I 2

TIME, hr

Fig. 4-34. Relationship between viscosity and time of a crosslinked fluid at 250 OF. Initial viscosity is at room temperature. (After Horton, 1982, fig. 1, p. 76; courtesy of Drilling.)

Gum guar is one of the more widely used additives for salt- and fresh-water systems. The gum will hydrate readily and thicken the fluid, increasing the viscosity and decreasing the fluid loss of the fluid. Gum guar can be dissolved in a slightly alkaline solution without increasing its viscosity on addition of borax. In general, the lower the pH, the thicker the gel and the hgher the viscosity of the fluid. Gum guar and hydroxypropyl guar (HPG) can be crosslinked for greater viscosity and a higher temperature tolerance (Veatch, 1983b). Temperature stability has been increased by the addition of oxygen scavengers (e.g., thiosulfate salts and methanol).

Fracture fluids that are stable under high temperatures are required in fracture treatment of deeper wells. The temperature in deeper wells ranges from 300 to 350 O F and most fracture fluids are only marginally stable under these conditions (Horton, 1982, p. 75). Much research is currently being conducted on fluids up to 700°F to stimulate geothermal wells. The two fluid systems utilized today are the “crosslinked” and the “gelled two-stage”. The crosslinked fracture fluid is generated by use of a polymer. A crosslinked system does not pour readily and has a near gello-like consistency, which is caused by the chemical reaction of certain polymer chains-they become interconnected and thcken the fluid (Horton, 1982, p.75). The high viscosity enables the fluid to carry heavy loads of proppant. Upon encounter- ing hgh temperatures, the chemical bonding of the crosslinked system is destroyed by heat, as shown in Fig. 4-34.

; ;;:py-j 0

1 % 50

00 I 2

TIME, h r

Fig. 4-35. Relationship between viscosity and time (two-stage reaction) at 300 F, as the fluid is being pumped downhole. Initial viscosity is at room temperature. (After Horton, 1982, fig. 2, p. 76; courtesy of Drilling.)

133

The two-stage system, also referred to as “polymer loading”, is more resilient and less sensitive to temperatures. It is prepared initially as a gel at the surface. Dry polymer (secondary “inhibited” gelling agent) is then added to the fluid as it is being pumped downhole. This secondary gelling agent does not generate additional viscosity under ambient or surface conditions. Upon being heated to a temperature of around 300 OF, however, the polymer reacts chemically and increases the viscosity of the fluid. Figure 4-35 shows variation of viscosity with time for a two-stage fluid.

Acid-base fluids

Acid-base fluids have similar properties to those of water-base systems. Im- portant factors which are considered in designing a fracture treatment are viscosity, friction loss, and fluid loss. Acid-base fluids require control of the pH (concentration of acid) and how the acid reaction might be modified by the presence of additives which are used to modify the properties of fracturing fluid. As with water-base systems, gum guar is often used to control friction of fluid, viscosity, and fluid loss. Gum guar is not stable in concentrations of hydrochloric acid above 15%. In general, it is only effective at low temperatures. Polyacrylamides rather than gum guar are used to control these properties at hgher temperatures.

Howard and Fast (1970, p. 54) pointed out that fluid-loss control is difficult because of the action of the acid on the formation and on the fluid-loss-control agent. Two types of agents are often used to control the fluid loss: (1) synthetic polymers that remain stable and swell in acid, and (2) blends of acid-resistant gums, silica flour. and oil-soluble resins.

Gelled acids

A gel or thickened acid is generally prepared by using natural gums such as gum guar or gum karaya. Synthetic polymers and cellulose derivatives are more expensive and so are considered economically noncompetitive (Howard and Fast, 1970, p. 54). The gelled acid fills the main fractures and, thus, results in a deeper penetration. The high cost and lack of stability at temperatures above 100 O C have resulted in the loss of popularity.

Acid emulsions

Acid-in-oil emulsions with a 60-90% aqueous, internal acid phase are often used in wells with high temperatures because of their stability (Howard and Fast, 1970, p. 54). The emulsifier selected is typically a mixture of nitrogen-based organic compounds and non-ionic surfactant-type materials. The system is designed so that the emulsifier makes the emulsion stable at surface conditions. When the emulsion is heated to formation temperatures, however, the emulsion breaks down. At high temperatures, the emulsifier is either adsorbed on the rocks and/or is broken down. Popularity of acid emulsion treatments is due to the fact that they can be used in

134

high-temperature wells and slow reaction rate which results in a deeper fracture penetration. The primary disadvantages of acid emulsions are high viscosities and high friction losses.

Chemically retarded acids

Knox et al. (1964) pointed out several advantages of chemically retarded acid as a fracturing fluid. They discussed the addition of surfactants to retard the acid reaction on carbonate rocks (limestones and dolomites). According to Knox et al. (1964), the most effective surfactants for this are the anionics such as alkyl phosphate, alkyl sulfonate and alkyl taurate. These materials make the surface of the water-wet carbonate rock oil-wet, preventing the water phase (containing the acid) to contact the surface of the rock. The problem arises, however, if the carbonate rock in situ is originally oil-wet. In such cases surfactants may not be necessary. Howard and Fast (1970) pointed out that alkyl sulfonate is the most economic material for use in retarding acids. This retardation permits the acid to be transported further from the wellbore before it reacts with the rocks, thus increasing the depth of live acid penetration.

Aqueous foams

Aqueous foams usually exhibit excellent “postfracture cleanup” characteristics when used in stimulating abnormally low-pressured reservoirs or those reservoirs that present postfracture cleanup problems.

Typically, the fluid consists of 20% water and 80% gaseous nitrogen. The relative proportions of these components can be varied depending upon the viscosity required of the foam. Surfactant in the amount of 0.5-1.0% is added to stabilize the foam. The viscosity is a function of content by volume of nitrogen. For example, if 80% of the foam consists of nitrogen, the fluid is called an 0.80-quality foam. lnasmuch as the foam is compressible, the quality on the surface is different from that in the fracture at the bottom of the well at hgh pressures. Consequently, use of foam systems is generally limited to low-pressure reservoirs (Veatch, 1983b).

The advantages of the foam are (1) hgh viscosity, (2) very good proppant suspending and carrying capabilities, and (3) a very low fluid loss. Consequently, the foams have greatest application in fracturing of gas wells where fluid retention can be a problem in regaining permeability to gas after treatment. The small content of water in foams is a disadvantage at low injection rates as it is difficult for this water to carry proppants prior to the making of the foam.

PROPPING AGENTS FOR HYDRAULIC FRACTURING

The fracturing fluid cracks or fractures the formation and then holds it open until the pressure is reduced. The two walls or faces of the fracture will close or “heal” as

135

FLUID PROPPING AGENT

PROPPING AGENT

I

Fig. 4-36. Schematic diagram of a fracture with proppant. (Courtesy of the Halliburton Co., 1976, fig. 1.6, p. 3.)

the pressure is reduced unless the fracture contains some particulate matter such as "spalled-off" rocks, sand, or other type of proppant (Republic Geothermal, Inc., 1979). Figure 4-36 shows a schematic of a propped fracture. The layer of sand can range from a mono- to multilayer system as shown in Fig. 4-37.

Proppants are selected upon evaluation of the following attributes: (1) strength, ( 2 ) high permeability retention of the proppant pack under loading, (3) cohesive- ness, (4) low cost, and (5) chemical stability over a long period of time. The major problem with sand, which has been the most popular type of proppant in fracturing treatments, is that it is brittle and tends to crush under high loads. Fines broken off the sand can plug the newly-created fractures and damage surface equipment (such as valves and tubular goods) as the fluids are produced back. Some proppants tend to deform over time when a load is placed upon them, which can result in a decreased permeability for the new fracture channel over time. The ideal proppant is one which will (1) fully support the closure stress or earth overburden that is imposed upon it, (2) remain permeable during the life of the production operations, (3) be chemically inert and non-reactive to the fluids produced through it, and (4) have a unit cost low enough to make the treatment economic (Republic Geothermal, Inc., 1979).

A larger grain size for the proppant pack provides a more permeable pack under low closure stress conditions and can be used in shallow wells. Dirty formations or those subject to significant fines migration are poor candidates for large-size sand proppant packs. The fines from the formation, over time, tend to invade the sand proppant pack causing partial plugging and rapid reduction in fluid permeability. In these cases, a smaller-sized sand proppant pack which can resist the invasion of

I PROPPANT DISTRIBUTION I MULTILAYER

PARTIAL MONOLAYER

MONOLAYER

Fig. 4-37. Various types of proppant distribution. (Courtesy of the Halliburton Co., 1976, fig. 1.7, p. 3.)

136

0.6

2 0.4

WElEHT X RETAINED OW

2 0.04 L t 0.02-

0 2 4 6 8 1 0

OVERBURDEN STRESS, 1.000 P S I

Fig. 4-38. Effect of particle size on fracture conductivity. Grains of uniform size distribute the load more evenly and withstand higher stresses. (After Republic Geothermal, Inc., 1979, fig. 4, p. 10; courtesy of the Republic Geothermal, Inc.)

fines from the formation would be a better choice. The larger grain sizes are generally not considered in deeper wells due to crushing and placement problems. As shown in Figs. 4-38 and 4-39, particle size distribution and proppant quality are important factors when considering a sand mixture for fractures with a higher overburden stress (deeper). tures and tend to settle out

The larger-sized, heavier proppants require wide frac- quickly.

I A. 20/40,0.7 R, < O . I X FELDSPARS

8. 20/40.0.6 R, 3 - 6 X FELDSPARS

OVERBURDEN STRESS, 1.000pri

Fig. 4-39. Effect of proppant quality on conductivity. These curves represent sand containing feldspars as impurities. Fines tend to reduce permeability of proppant packs under closure stresses. (After Republic Geothermal, Inc., 1979, fig. 5 , p. 10; courtesy of the Republic Geothermal, Inc.) R = roundness ( Krumbein).

137

t ?

% I I

6 LAYERS 5 LAYERS

4

Y

MU LTI LAYER PARTIAL I MONOLAYER ~ I

Fig. 4-40. Effect of particle concentration on fracture conductivity. (After Republic Geothermal, Inc., 1979, fig. 2, p. 7; courtesy of the Republic Geothermal, Inc.)

Much laboratory study was done in the 1960’s on the use of partial monolayer proppant packs (see Fig. 4-37). Spacers (inert or dissolvable particles) were mixed in with the proppant in order to sparsely space the proppant throughout the fracture. Theoretically, this has the very desirable effect of allowing flow or production to return through an open channel in the hydraulically created fracture. Figure 4-40 illustrates the effect of proppant concentration on fracture conductivity. The area open to flow is shown in Fig. 4-37. Unfortunately, the use of monolayer or partial monolayer of proppants, although possible in the laboratory, is difficult to achieve under field conditions.

Specific weight is another physical property that can be extremely important under certain well conditions and is associated with proppant transport problems. The factors that affect the proppant transport are velocity, viscosity, specific weight of fluid, and size and specific gravity of propping agents. To place a proppant, a fracture fluid must (1) create a fracture of sufficient width for particle-size placement, (2) maintain sufficient fluid velocity within the fracture to carry the proppant to the desired distance away from the wellbore, and (3) maintain sufficient fluid viscosity to carry the proppant for displacement to the point desired (Republic Geothermal, Inc., 1979). Heavy proppants are more difficult to suspend and transport in the fracture. Although high-density and viscous fluids may transport the proppant in the wellbore, they may have difficulty in moving the proppant through the fractures where fluid movement is slow. The selection of proppant will thus govern the type of fracturing fluid (and its additives) that can be used to carry the proppant.

Figure 4-41 shows the effect of closure stress on the permeability of various mesh sands, depending on the roundness factor of the sand grains. The stresses appear to be more evenly distributed throughout the sand pack when the grains are better rounded and are of about the same size (better sorted).

In general, brittle or “crushable” particles used as proppants are approximately spherical-crystalline (sand) or amorphous (glass) materials. These particles have moderate to high strength when a singlk particle is loaded between flat plates (monolayer), but have a much lower strength when point-loaded in a multilayer pack. Figure 4-42 shows the permeability of various-sized sand packs at a closure

138

e 04

0.2 3

0

cr 0 0 6 2 004 5 A 20l40. 0 7 R

‘ ‘ ‘0 2 4 6 8 10

OVERBURDEN STRESS, 1000 P S I

Fig. 4-41. Effect of roundness of proppant on fracture conductivity. In the case of uniformly-rounded grains, stresses are more evenly distributed and the grains resist a higher load before failure. (After Republic Geothermal, Inc., 1979, fig. 6, p. 15; courtesy of the Republic Geothermal, Inc.) R = roundness ( Krumbein).

stress of 2000 psi. The closure stress is equal to the fracture gradient times depth minus the bottomhole pressure. The smaller the size of a proppant, the lower the permeability of a pack. Figure 4-43 illustrates the decrease of permeability with time.

The availability and low unit cost of sand have made sand the most popular of all propping materials. Sand is brittle and tends to crush under heavy loads. Table 4-IV lists minimum and maximum specifications for sand used as proppant. It is important to meet these specifications, because a small percentage of fines can significantly reduce the permeability of the sand pack.

Glass beads were once thought to be the strongest proppant available. The glass beads packed well because they were spherical and well sorted. Under high temperatures and in contact with brine solutions, however, they are sensitive to stress cracking and crumble to a fine powder under closure stress. Studies by Cooke

‘? I .6 x

; 1.2

5 0.8

f 0.0

>

- m 2 04 a:

0.04 0.06 0.08 0.00 0.02

MEAN PROPPANT DIAMETER, in.

Fig. 4-42. Relationship between permeability and mean proppant diameter of “Heart of Texas” sand at 2000 psi closure stress. (After Republic Geothermal, Inc., 1979, fig. 7, p. 16; courtesy of the Republic Geothermal, Inc.)

139

Fig. 4-43. Correction of instantaneous permeability to permeability after one year exposure to stress. (After Republic Geothermal, Inc., 1979, fig. 9, p. 22; courtesy of the Republic Geothermal, Inc.)

(1973), as shown in Fig. 4-44, demonstrated the problems occurring when using glass beads. This along with their high cost has reduced the use of glass beads as a propping agent.

TABLE 4-111

Typical functions or types of additives available for fracturing fluid systems (After Veatch, 1983b, table 2, p. 854; courtesy of the Society of Petroleum Engineers)

Antifoaming agents Bacteria control agents Breakers for reducing viscosity Buffers Clay stabilizing agents Crosslinking or chelating agents (activators) Demulsifying agents Dispersing agents Emulsifying agents Flow diverting or flow blocking agents Fluid-loss control agents Foaming agents Friction reducing agents Gypsum inhibitors pH control agents Scale idubitors Sequestering agents Sludge inhibitors Surfactants Temperature stabilizing agents Water-blockage control agents

140

BRINE i STRESS, 1000 psi

2

Fig. 4-44. Relationship between permeability and stress for glass beads using oil and brine. (After Cooke, 1976; courtesy of the Society of Petroleum Engineers.)

Walnut shells were found to be useful in shallow applications where the closure stresses were not too high. Walnut hulls deform because they are composed of cellulitic materials. In deeper and, thus, warmer applications, the walnut hulls would degrade and disintegrate. The use of ground walnut hulls continued throughout the 1950’s and early 1960’s when many new products began to appear.

In the 1960’s, extra strong proppants were tested, both in the laboratory and in the field, such as aluminum pellets and steel pellets. Their main disadvantages were: (1) high density, ( 2 ) susceptibility to corrosion under acidic environment found in the producing formation, and (3) high unit cost.

The new types of proppants introduced in the 1970’s included aluminum and brass coated glass beads, exotic plastics, garnet and other forms of aluminum oxide, and ceramic pieces or pellets. Due to the cost of manufacturing, however, they were not economical. Two new products were developed by Exxon Production Research: (1) sintered bauxite, produced by sintering many small pieces of bauxite together into a round proppant, and (2) resin-coated sand. Fairly uniform-sized particles of bauxite have very lugh strength and are resistant to most acids. The resin coatings (thermosetting plastic) on sand gave full protection to the propping material against corrosive fluid environment in the well. It also helped to spread the loading of the pack by deformation and kept the sand from crushing or breaking. Zirconium oxide (ceramic particles) introduced from Europe is a very strong proppant. The cost and availability, however, present a problem. Figure 4-45 shows the relationship between permeability of several propping agents and closure pressure.

Sintered bauxite is manufactured by sintering bauxite ore into fine-grained particles having a specific gravity in the range of 3.4-3.8. It is manufactured in a range of sizes. When subjected to high pressures, the fine-grained structure of the sintered bauxite particles enables the particles to deform, rather than crush. The particles resist crushing when placed in a multilayer propping pattern, even when exposed to brine solutions. Purified aluminum oxide, which has a hardness of nine, is another strong material that had been used as a proppant.

141

' 0 2 4 6 8 1 0 APPLIED STRESS ~ 1000 psi

Fig. 4-45. Relationship between permeability and applied stress for various proppants. (After Republic Geothermal, Inc., 1979, fig. 37, p. 66; courtesy of the Republic Geothermal, Inc.)

Many of the properties of proppants are compared in Table 4-IV. Cost of proppants based on data available in 1980 is presented in Table 4-V for purposes of comparison only. Inasmuch as the cost of proppant constitutes a significant portion

TABLE 4-IV

Normal frac sand specifications (type: well-rounded, single-grain, medium-to-coarse, white or colored quartz having high particle strength) (After Republic Geothermal, Inc., 1979, table I, p. 10; courtesy of Republic Geothermal, Inc.)

Minimum Maximum

Silica content (wt W) Size distribution

wt S within specified range wt W passing specified coarser

screen but not passing specified finer screen

Roundness: ratio of radii a Sphericity Soft particle content (wt W ) Silt and clay content (wt S)

98.0 80. 80.0

99.0 0.6 0.85 0.50 0.10

100.0

90.0

100.0 0.8 0.89 0.10

none

a Roundness is defined as the ratio of the average radius of curvature of the several comers to the radius of curvature of the largest inscribed circle on the projected sand grain image. Sphericity is defined as the cube root of the ratio of particle volume to circumscribed sphere volume.

142

TABLE 4-V

Comparison of proppant properties (After Republic Geothermal, Inc., 1979, table 111, p. 70; courtesy of Republic Geothermal, Inc.)

Super sand Sand Glass beads Bauxite pellets

Proppant strength

Permeabili ty retention under closure stress Low temperature I l m i t S

High temperature limits

Self- cohesion Minimizes embedment cost

Excellent to 10,000 psi (69 MPa) closure stress

Excellent, no

fines plugging by

130OF (54.4OC) minimum (Natural or artifical) 500 F (250 C)

Excellent

Yes

Intermediate

Good below 4000 psi (27.6 MPa) Poor above 4000 psi (27.6 MPa) closure stress Fair, partial plugging with crushed sand

None

Silica solubility above 300 F (148.7 O C) None

No

Low

Excellent below 5000 psi (34.5 MPa) Poor above 5000 psi (34.5 MPa) closure stress Fair, partial plugging with crushed beads

None

Silica solubility above 300 F (148.7 C) None

No

High

Excellent to 10,000 psi (69 MPa) closure stress

Good to excellent

None

Not known

None

No

High

TABLE 4-VI

Comparison of propping agents for fracturing (After Republic Geothermal, Inc., 1979, table IV, p. 79; courtesy of Republic Geothermal, Inc.)

Material Specific Unit cost per pound gravity (SG) Actual Adjusted for SG

Sand Walnut hulls High-strength glass beads Aluminum pellets Oil-soluble spacer Iron or steel shot Super sand Sintered bauxite

2.65 1.28 2.65 2.65 1.10 7.82 2.6 3.65

1.0 11.0 24.0 37.0 40.0 7.5 4.7

15

1 .o 5.3

24.0 37.0 16.6 22.0 4.6

20.7

143

of the total cost of fracture treatment, use of large quantities of proppant results in large expenditures. Consequently, sand should be used whenever possible to keep costs down. Combinations of sand and glass beads were believed to give a high permeability at large closure stresses. Test runs by the Republic Geothermal, Inc. (1979), however, indicated that a mixture of 9 parts sand and 1 part glass beads has a lower permeability than sand alone.

AcFracTM PR is a thermosetting phenolic resin-coated sand (20/40 mesh white silica) suited for fracturing operations involving intermediate closure pressures of 5000 to 10,000 psi (Acme Resin, 1983). When the tough resin is properly cured in the fracture, crushing and embedment is decreased. This resin, which is thermally stable up to 450 O F and under conventional acidizing treatments, is insoluble in common solvents, brines, and oils.

MECHANICAL EQUIPMENT FOR HYDRAULIC FRACTURING

After selecting the type and volume of fracturing fluid, proppants, and additives, mechanical equipment necessary for fracturing must be considered. In early treatments (around 1949), the equipment available had been that designed for cementing and acidizing work. The available engines ranged from 75 to 125 HHP (hydraulic horsepower). There was continued demand for increased pump rates at higher operating pressures, which stimulated development of present-day equipment. All components of the mechanical equipment perform as a system.

Pump equipment

Figure 4-7 shows the change in pumping rates and injection volumes from 1950 through 1974. In the 1950’s, fracture treatments were simple, consisting of a few pump trucks, jet mixer, and storage tanks (see Fig. 4-46). A manually-operated, diesel-powered truck pumping unit typical of the late 1960’s is presented in Fig. 4-47. These fracturing units were equipped with the displacement pumps having a variety of plunger sizes. This enabled attainment of injection rates of 42 bbl/min and pumping pressures as high as 20,000 psi (Howard and Fast, 1970, p. 120).

The success of the hydraulic fracturing process depends upon the ability of pumps to handle various fluids containing propping agents at high rates and pressures. As indicated in Fig. 4-45, the trend is toward greater fracture treatment volumes and pressures. Pumps generally used for fracturing services are horizontal, single-acting plunger type units. The pumps mounted on the truck in Fig. 4-47 are designed to provide 600-750 BHP (brake horsepower). The pumps can be fitted with fluid ends having a 3- to 7-3/4-in.-diameter plunger and typically have an 8-in. stroke. These pumps are produced in left-hand and right-hand power end models. Pumps can be mounted on trailer units as shown in Fig. 4-48.

144

-c- PUMP JET M I X E R

MIXING TUB

1r

DISPLACEMENT

TRUCK

m

FROM 3 R D TRUCK

Fig. 4-46. Well hookup using service company equipment. (After Howard and Fast, 1970, fig. 8.2, p. 118; courtesy of the Society of Petroleum Engineers.)

Pressure and volume requirements for hydraulic fracturing vary from treatment to treatment, based upon volume of fluid and propping agent to be pumped. The hydraulic horsepower, Hp, can be calculated as follows:

Hp = C’PqiGsp (4-22)

where C‘ = conversion constant depending upon units of qi: 0.0005834 if qi is in gal/min or 0.02451 if qi is in bbl/min, qi = actual volumetric rate of injection, and Gsp = specific gravity of fluid.

To determine the actual rate of injection, qi, the theoretical rate is reduced by the volumetric efficiency of the pump (Howard and Fast, 1970, p.122):

qi = ( ~ p )( ~ s ) ( ~p )( P V ~ >( V E ) (4-23)

Fig. 4-47. High-pressure, high-injection-rate, truck-mounted pumping equipment used in 1967 (manual control). (After Howard and Fast, 1970, fig. 8.6, p. 120; courtesy of the Society of Petroleum Engineers and the Halliburton Services, Inc.)

145

Fig. 4-48. High-pressure, high-volume fracturing pumping unit, diesel engine. (Courtesy of the Hallibur- ton Services, Inc.)

where A , = cross-sectional area of pump, in?, L, = length of pump stroke, in., N, = number of pump plungers, Prpm = pump revolutions per minute, and VE =

volumetric pump efficiency.

Engine - 600 ehp

Ratlor

10. 0.815 5. 2.40 9. 1 0 0 4. 2 9 4 8 1 2 5 3 3 6 8 7 1 5 6 2 4 6 0 6. 1.96 L. 5 76

-

Pump--4 8n Trlplex. 8 10 slmhe: 8.6:l Remarks:

86% (werage) M E . 100% V. E.

I I 2 3

VOLUMETRIC RATE- B B L I M I N

Fig. 4-49. Relationship between volumetric rate of flow and pressure. (After Howard and Fast, 1970, fig. 8.11, p. 123; courtesy of the Society of Petroleum Engineers.)

146

ENGINE SPEED - RPM

Fig. 4-50. Torque and power curves for 600-hp diesel engine. (After Howard and Fast, 1970, fig. 8.12, p. 123; courtesy of the Society of Petroleum Engineers.)

Figure 4-49 shows speed-torque-horsepower range for a 600-hp engine, driving a 4-in. plunger, 8-in. stroke, triplex pump through a 10-speed transmission. This curve, available from service companies, shows the pump pressure-volumetric capabilities through various transmission ranges. The engine horsepower versus engine speed and torque versus engine speed curves must be availabe (Fig. 4-50) to calculate this data. The maximum volumetric rate and maximum pressure capabilities for a given transmission speed can be calculated based on this information. Similar plots can be prepared for gasoline engines, gas turbines, and electric motors and pumps.

Proportioning equipment

Proportioning equipment is used to accurately meter and mix the fracturing fluid, propping agent, and chemicals from several supply sources. Proportioning may be accomplished by several methods. Generally, the fluid is moved by a positive displacement gear pump into a mixing tank. Centrifugal pumps can also be used. Propping agents and chemicals are metered into the mixing tank at the same time and agitated (see Fig. 4-51). The mixture is then pumped by the pressurizer to the suction manifold of the pump truck. The speed at whch the materials are mixed must be varied, whereas the speed of pumps pressurizing the high-pressure-rate pumps is usually held constant. Relationship between the volumetric rate of flow

147 FRACTURING FLUID

PROPORTIONING

PRESSURIZER

Fig. 4-51. (a) Schematic diagram of sand fluid proportioner. (After Howard and Fast, 1970, fig. 8.14, p. 125; courtesy of the Society of Petroleum Engineers.) (b) Trailer-mounted sand-fluid proportioning unit. (Courtesy of the Halliburton Services, Co.)

and maximum pressure for a reciprocating pump for plungers having different sizes is presented in Fig. 4-52. Maximum pressure, pm, is equal to:

P m = Lp/* p (4-24)

where L, = the plunger load furnished by the power end of the pump and A,, =

plunger area. A trailer-mounted proportioner is shown in Fig. 4-53.

Metering and control equipment

In fracturing treatment, the control of volume and pressures at all times during the treatment is critical. Metering and control devices provide control and continu-

148

20

I8

16

I 14

I2

g . J

Y s 10

Y

$ 6

9 4

2

0 00 PRESSURE-PSI

Fig. 4-52. Relationship between volumetric rate of flow and pressure of a reciprocating pump @-in. triplex) with various plunger sizes (based on same plunger load and same hhp output). (After Howard and Fast, 1970, fig. 8.13, p. 125; courtesy of the Society of Petroleum Engineers.)

ous record of the flow rate and pressure during the treatment. The most commonly used meters are flow-type, density-type, and fracture-parameter. Remote control devices enable control and monitoring of fracturing job at a distance from the equipment.

A popular type of flow meter to monitor volumetric rate of flow of liquids is shown in Fig. 4-53. As fluid flows through the meter, it strikes the rotor blades,

Fig. 4-53. Flow meter cutaway. (After Howard and Fast, 1970, fig. 8.18, p. 128; courtesy of the Society of Petroleum Engineers.)

149

Fig. 4-54. Gamma-ray absorption-type fluid density meter. (After Howard and Fast, 1970, fig. 8.23, p. 129; courtesy of the Society of Petroleum Engineers.)

spinning the rotor. The speed at which the rotor turns is directly proportional to the volume of fluid passing through the meter.

The density meter measures the density of the fluid passing through it. Density is a measure of the volume of sand or proppant present in the fluid. Excessive amounts of proppant in the fluid could cause bridging in the wellbore or fracture. This could prevent further injection of proppant. Insufficient amount of proppant in the fluid may permit the fracture to close. The gamma-ray density meter measures the density of the fluid and proppant (Fig. 4-54). Gamma-ray counter and gamma-ray source are placed on the opposite sides of a pipe through which the fluid containing proppant is being pumped. The proppant fluid ratio, PFR, in lb/bbl is equal to:

(4-25)

where ym = specific weight of the proppant plus fluid mixture, lb/gal, yf = specific weight of fluid, lb/gal, and 22.075 = specific weight of sand, lb/gal.

Fig. 4-55. Fracture monitor. (After Howard and Fast, 1970, fig. 8.23, p. 129; courtesy of the Society of Petroleum Engineers.)

150

The density meter provides a continuous monitoring of the proppant-fluid mixture. By connecting the meter to the supply of proppant and fluid with pneumatic controllers and control valves, the addition of proppant to the fluid is automatically controlled.

The fracture-parameter meter, which is a portable instrument, provides a remote indication of injection rate, fluid density, total volume of fluid, and wellhead pressure (Fig. 4-55). All information is usually recorded on charts.

Bulk-handling equipment

Bulk-handling equipment is used to reduce the cost of handling large volumes of material required for the fracturing treatment. Typical equipment to handle proppants are dump trucks and pneumatic tanks mounted on trucks (Fig. 4-56). This equipment solves the problem of manually handling bulky materials and the problem of providing constant supply to the proportioner and other equipment. Tank trucks carry both liquids and many of the chemicals required for the treatment.

Surface equipment

The suction systems set up to deliver materials to the proportioners vary from area to area, depending on the type of fluid or proppant used, etc. The fluid can be stored in: (1) earthen pits, (2) truck transports, and/or (3) fixed storage tanks having various capacities and designs. A flexible hose between the proportioner and

Fig. 4-56. Propping agent transport unit, 35,OOO-lb capacity, pneumatic. (After Howard and Fast, 1970, fig. 8.26, p. 131; courtesy of the Society of Petroleum Engineers.)

151

L E A S E ROAD

I

Fig. 4-57. Typical equipment layout for massive frac operation. (After Schlottman et al., 1981, fig. 17; courtesy of the Society of Petroleum Engineers.)

the fluid source constitutes the standard suction manifolding. Several different systems can be set up because the handling of various fluids, proppants, and chemicals can be quite different. Figure 4-57 demonstrates the variety of equipment that is required for a large fracturing operation. Each system has an independent monitoring system so that full control of each product can be maintained.

Pressure, injection rate, type of fluid, number of pumps, and sand/fluid ratio govern the configuration of the system and the size of piping used. As pointed out by Howard and Fast (1970, p. 131), in order to minimize the erosion of piping caused by sand-fluid slurries, pumping rates should be kept below 40 ft/s. The yield pressure must be at least two times the working pressure of the discharge lines for pressures below 10,000 psi. If the working pressure is greater than 10,000 psi, the yield pressure should be one and one half times the working pressure. In order to combat the fatigue forces encountered in the pipe hook-ups, steel tubing with high

152

Fig. 4-58. Wellhead manifold check-valve. (After Howard and Fast, 1970, fig. 8.29, p. 132; courtesy of the Society of Petroleum Engineers.)

resistance to impact must be used. As a safety feature, in case pipes do rupture, check valves are installed in the discharge system. They are placed as close to the fracturing wellhead as possible to provide the maximum protection (Howard and Fast, 1970, p. 132).

In order to meet the requirements for hydraulic fracturing, special wellhead manifolds have been developed (Fig. 4-58). The manifolds connect the tubing or casing to the discharge lines carrying the fracturing fluids and proppants from the pumps. As shown in Fig. 4-58, check-valves are placed at each inlet connection of the manifold for safety purposes. The cast steel manifold shown is rated at 10,000 psi pressure.

NUCLEAR FRACTURING '

Considerable research by both governmental agencies and several major U.S.A. oil companies has focused on the potential application of nuclear energy for fracturing tight reservoir rocks containing vast hydrocarbon reserves. The worldwide abundance of non-productive or low-productive oil and gas reservoirs, and extensive tar sand and oil shale deposits provide the necessary incentive to develop technical and economically feasible methods for increasing the ultimate recovery of these valuable hydrocarbon resources using in-situ recovery processes.

' By Walter Fertl and George V. Chilinganan.

153

The feasibility of nuclear fracturing has been demonstrated in several field tests in the U.S.A. (Gnome test and Gasbuggy, Rulison, and Rio Blanco projects) and other countries. Factors frequently involved are of a technical, economical, political, environmental, and emotional nature.

From a technical standpoint, the major difference between hydraulic and nuclear fracturing lies in the fact that whereas a hydraulic fracturing treatment normally creates a simple fracture, nuclear fracturing forms a cavity of several hundred feet in diameter with a multitude of fractures radiating from it into the otherwise tight reservoir rock. The result is a very large effective wellbore radius (Atkinson and Lekas, 1963) which should allow high production rates. Oil shales and tar sands could be retorted in situ and the hydrocarbon resources removed in gaseous or liquid form, thereby eliminating the need for mining operations. If in-situ thermal recovery processes, however, are considered, which are to be conducted through a

d I

! I CAVITY I 1 RADIUS

RADIUS OF PERMEABLE ZONE

Fig. 4-59. Schematic presentation of a typical post-shot environment using nuclear fracturing. (After Fertl and Chilingarian, 1978, in: Chilingarian and Yen, 1978, fig. A-6, p. 304; courtesy of Elsevier Science Publishers. Also see Boardman et al., 1964.)

154

TABLE 4-VII

Estimated volume of increased permeability for nuclear explosions in reservoir rock (After Coffer et al., 1964; courtesy of USAEC)

Yield (in Kt) at Cavity Depth of Height of Volume of gross scaled depth of radius burial permeable permeability burial (ft) (ft) (ft) zone increase

(ft) (acre-ft) Kt f t

10 800 450

100 800 450

500 800 450

1000 800 450

96 110 167 196 252 290 299 346

1720 970

3720 2100 6350 3600 8000 4500

540 620 940

1110 1420 1640 1690 1950

2.1 x l o 3 3.2 x l o 3 1.1 x 104 1.8 x 104 3.8 x l o 4 5.9 x 104 6 . 4 ~ 1 0 ~ 1 . 0 ~ 1 0 ~

fracture system, the hydraulic fracturing techniques appear to be more advantageous than the nuclear mass rubbling process.

Furthermore, in areas where the effectiveness of hydraulic fracturing has been well established, nuclear fracturing cannot compete because of its high cost. Guidelines for reservoir characteristics desired in the case of nuclear fracturing include low reservoir permeability, massive zones bounded by thick impermeable formations, gas-bearing reservoirs, and low-viscosity oil deposits.

Basically, a nuclear detonation in a wellbore creates a cavity resulting from the vaporization of the rock and its saturating fluids. Fracture system radiates from this cavity into the formation. Rock collapse into the cavity forms a chimney-rubble zone, with most of the molten material and radioactive fission products concentrated in the bottom of these zones (Atkinson, 1964). A schematic presentation of a typical post-shot environment resulting from a contained underground nuclear explosion is illustrated in Fig. 4-59.

Studies of several contained underground nuclear explosions showed that the nuclear devices have yielded a rather consistent model of the geometric features. Mathematical relationshps have been developed for calculating specific characteristics of the post-shot geometry as a function of the yield of the nuclear device, depth of burial, and type of formation (Boardman et al., 1964; Bray et al., 1965).

Table 4-VII shows (1) the variation in cavity radius, (2) the volume of rock (in acre-feet) in which there is a drastic permeability increase, and (3) height of the created permeable zone as a function of yield at the depth of burial of 450 and 800 ft. Although these data are only qualitative, they do show how these parameters are expected to vary.

For detailed treatment of fracturing, the reader is referred to the classical work of Howard and Fast (1970) and excellent treatment of the subject by Craft et al. (1962) and Halliburton Company (1976).

155

SAMPLE QUESTIONS AND PROBLEMS ’ Questions

(1) What are the uses of hydraulic fracturing? Explain each one in detail. (2) Explain why the production increases as a result of a hydraulic fracturing

(3) What are the factors that should be considered in selecting wells for a

(4) Define the “fracturing fluid coefficient”. What are the components for the

(5) What are the properties that a fracturing fluid should possess? (6) List and discuss the factors that affect the selection of a fracturing fluid for a

particular well. (7) List the types of fracturing fluids used in the industry. Discuss the advantages

and disadvantages of each. (8) What is the function of the propping agent? List the types of agents used in

the industry. Why are glass beads not used in fracture treatments today? (9) List the factors that should be considered in selection of a proppant. What

additives would you consider if the fracture fluid was water and the temperature was 250 O F .

(10) What are the steps in a hydraulic fracturing treatment? Explain each one in detail.

treatment.

fracturing treatment?

“composite fracturing coefficient” as defined by Smith (1965)?

Problems

(1) The following equation is a mass balance which states that the rate of fluid injection is equal to the rate of the fluid loss from the fracture to the formation plus the rate of volume increase of the fracture itself:

dA

Assuming u ( t ) = C/fi and qi = constant, show by using Laplace transform that the fracture area is given by:

A( t ) = * [ exp( G)2 2 c r X erfc( 7 2cfi 1 + 7 4cfi - 11

4TC2

(This equation is often referred to as “Carter’s Equation”.) (2) Show that the productivity ratio (PR) defined as kavg/k, where k is the

permeability of the unfractured formation and kavg is the average permeability of

’ The help extended by M. Parlar in preparing this section is greatly appreciated.

156

I-

Fig. 4.1-1. (a) Sample problem (2).

a

(b) Sample problem (3 ) .

TIME

the fractured formation, is given by:

Hint: Use Darcy’s law for radial flow in parallel beds to find the average permeability of the fractured zone and for the radial flow in beds in series to find the average permeability of the fractured formation (Reference: Craft et al., 1962).

( 3 ) The following pressure history was recorded during a hydraulic fracturing treatment of the sandstone formation at 10,000 ft - see Fig. 4.1-lb.

(a) What is the fracture initiation pressure? (b) What is the instantaneous shut-in pressure? (c) Calculate the frictional pressure gradient. (d) If the specific gravity (at average well temperature) of the fracturing fluid

(e) What is the bottomhole treating pressure (fracture propagation pressure)? (f) What would be the pressure on the proppant immediately after the fracture

treatment if the formation pressure is 5000 psi? (h) If the bottomhole flowing pressure is 3500 psi during production, what is

the pressure on the proppant? (4) A 7000-ft well is to be stimulated by hydraulic fracturing. The following

information is available: Formation permeability to fracturing fluid = 2 md, formation porosity fractional = 0.22, fracturing fluid viscosity at reservoir conditions = 5 cP, formation fluid compressibility = 5 X lo-’ psi-’, viscosity of reservoir fluid = 10 cP, fracturing gradient = 0.7 psi/ft, formation pressure = 3750 psi, injection rate =

20 bbl/min, total injection volume = 20,000 gal, and the fracture width = 0.1 in.

is 1.1, what is the fracture gradient?

157

The filtration data for the fracturing fluid is as follows:

vr t

(cc)

12 1 22 4 30 9 51 25 55 30

Calculate : (a) Fracture area using Carter’s Equation. (b) Fracture penetration assuming a single vertical fracture extending from the

wellbore out equally in both directions, with a vertical extent of 50 ft.

REFERENCES

Acme Resin, 1983. AcFrac C R Curable Resin Coated Sand Proppant. Technical Data, 3/83-2, ACME Resin, Forest Park, Illinois, 16 pp.

Allen, T.O. and Roberts, A.P., 1982. Production Operations. Vol. 2, Oil and Gas Consultants Inc., Tulsa, Okla., 2nd Ed., pp. 113-169.

Atkinson, C.H., 1964. Subsurface fracturing from shoal nuclear deronation. Rep. PNE 3001, USAEC- USMB, 18 pp.

Atkinson, C.H. and Lekas, M.A., 1963. Atomic-age fracturing may soon open up stubborn reservoirs. Oil Gas J., 61(48): 154-156.

Baker, H.R., Bolster, R.N., Leach, P.B. and Little, R.C., 1970. Association colloids in nonaqueous fluids. I & EC Prod. Res. Deu., 9(12): 541.

Bernard, G.G., Holm, L.W. and Jacobs, W.L., 1965. Effect of foam on trapped gas saturation and on permeability of porous media to water. SOC. Pet. Eng. J., 5(Dec.): 295-300.

Birch, F., Schairer, J.F. and Spicer, H.C., 1942. Handbook of Physical Constants. Geol. SOC. Am. Spec. Pap., 36, p. 16.

Black, H.N. and Hower, W.E., 1965. Advantageous use of potassium chloride water for fracturing water-sensitiue formations. Pap. 851 - 39-F, presented at Mid-Continent Distr. Meet., API Div. Prod. Meet., Wichita, Kans., Mar. 31-Apr. 2.

Boardman, C.R., Rabb, D.D. and McArthur, R.D., 1964. Contained nuclear detonations in porous media -geologic factors in cavity and chimney formation. In: Engineering with Nuclear Explosives, USAEC

Bray, B.G., Knutson, C.F., Wahl, H.A. and Dew, J.N., 1965. Economics of contained nuclear explosions

Brown, J.L. and Landers, M.M., 1957. US. Patent No. 2,779,735 (Jan. 29). Burnham, J.W., Harris, L.E. and McDaniel, B.W., 1980. Developments in hydrocarbon fluids for

Carter, R.D., 1957. Derivation of the general equation for estimating the extent of the fractured area.

Chilingarian, G.V. and Yen. T.F., 1978. Bitumens, Asphalts and Tar Sands. (Developments in Petroleum

Chilingarian, G.V. and Vorabutr, P., 1981. Drilling and Drilling Fluids. Elsevier, Amsterdam, 767 pp. Chilinganan, G.V. and Vorabutr, P., 1983. Drilling and Drilling Fluids. (Developments in Petroleum

TID 7695; pp. 109-126.

applied to petroleum reservoir stimulations. J. Per. Technol., 17(10): 1145-1152.

high-temperature fracturing. J. Pet. Technol., 32(2): 217-220.

Drill. Prod. Pract., pp. 261-268.

Science, 7). Elsevier, Amsterdam, 331 pp.

Science, 11.) Elsevier, Amsterdam, 801 pp. (updated textbook edition.)

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Christianovich, S.A. and Zheltov, Y.P., 1955. Formation of vertical fractures by means of highly viscous

Clark, J.B., Fast, C.R. and Howard, G.C., 1952. A multiple-fracturing process for increasing productivity

Clark, R.C., Freeman, H.G., Bolstead, J.H. and Coffer, H.F., 1953. Application of hydraulic fracturing to

Coffer, H.F., Bray, B.G. and Knutson, C.F., 1964. Application of nuclear explosives to increase effective

Cooke, C.E., 1973. Conductivity of fracture proppants in multiple layers. J. Pet. Technol., 9: 1101-1107

Cooke, D., 1976. Hydraulic fracturing with a high strength proppant. SPE Paper 6213 presented at 1976

Craft, B.C., Holden, W.R. and Graves Jr., E.D.,' 1962. Well Design, Drilling and Production. Prentice-Hall,

Crawford, D.L., Earl, R.B. and Monroe, R.F., 1973. Friction reducing and gelling agent for organic

Daneshy, A.A., 1973a. On the design of vertical hydraulic fractures.' J. Pet. Technol., 25(1): 83-97. Daneshy, A.A., 1973b. Mechanics and direction of hydraulic fracturing. Pet. Eng., Oct.: 17-24. Dickey, P.A. and Andersen, K.H., 1945. Behavior of water input wells-Part 4. Oil Wkly, Dec. 10. Dowell Div. of Dow Chemical Co., 1965. Frac Guide Data Book. Dow Chemical Company, Tulsa, Okla. Farris, R.F., 1946. Unpublished report, Pan American Petroleum Corporation, Tulsa, Okla. In: G.C.

Howard and C.R. Fast, Hydraulic Fracturing (Henry L. Doherty Ser., Monogr. 2). Soc. Pet. Eng. AIME, New York, Dallas, p. 10.

Fertl, W.H. and Chilinganan, G.V., 1978. Fracturing. In: G.V. Chilinganan and T.F. Yen (Editors), Bitumens Asphalts and Tar Sands. Elsevier, Amsterdam, pp. 296-306.

Frick, T.C. and Taylor, R.W., 1962. Petroleum Production Handbook. Vol. 2. McGraw-Hill, New York, N.Y., p. 47.

Grant, B.F., Duvall, W.I., Obert, L., Rough, R.L. and Atchison, T.C., 1950. Research on shooting oil and gas wells. Drill. Prod. Pract. API, p. 303.

Grebe, J.J., 1943. Tools and aims of research. Chem. Eng. News, 21(23): 2004. Halliburton Co., 1976. Hydraulic Fracturing. Halliburton Co., Duncan, Okla., 53 pp. Harrison, E., Kieschnick, W.F., Jr. and McGuire, W.J., 1954. The mechanics of fracture induction and

Horton, R.L., 1982. Fracturing fluids for high-temperature reservoirs. Drilling, Dec.: 72-78. Howard, G.C. and Fast, C.R., 1970. Hydraulic Fracturing. (Henry L. Doherty Ser., Monogr., 2). Soc. Pet.

Hubbert, M.K. and Willis, D.G., 1957. Mechanics of hydraulic fracturing. Trans. AIME, 210: 153-166. Hurst, W., 1953. Establishment of the skin effect and its impediment to fluid-flow into a well bore. Pet.

Knox, J.A., Lasater, R.M. and Dill, W.P., 1964. A New Concept in Acidizing Utilizing Chemical

Langnes, G.L., Robertson Jr., J.O. and Chilingar, G.V., 1972. Secondary Recovery and Carbonate

Maly, J.W. and Morton, T.E., 1951. Selection and evaluation of wells for hydrafrac treatment. Oil Gas J. ,

Matthews, C.S., 1961. Analysis of pressure build-up and flow test data. J. Pet. Technol., 13(9): 862-870. McGuire, W.J. and Sikora, V.J., 1960. The effect of vertical fractures on well productivity. Trans. AIME,

219: 401-403. McLeod, H.O. and Coulter, A.W., 1966. The Use of Alcohol in Gas Well Stimulation. Paper SPE 1633,

presented at SPE Third Annu. East. Reg. Meet., Columbus, Ohio, Nov. 10-11. Minich, A,, 1945. Bodying agent for liquid hydrocarbons. U S . Patent No. 2,390,609. Muskat. M., 1949. Physical Principles of Oil Production. McGraw-Hill, New York, N.Y., 1st ed., 922 pp. Ousterhout, R.S. and Hall, C.D., 1961. Reduction of friction loss in fracturing operations. J . Pet.

liquid. Proc. Fourth World Pet. Congr., 2: 579-586.

of wells. Drilling Prod. Pract., API, p. 104.

the stimulation of oil and gas production. Drill. Prod. Pract., API , p. 113.

well diameters. Eng. Nucl. Explos., USAEC TID 7695: 269-288.

(Also in: Trans. AIME, 255).

Fall AIME-SPE Meet., New Orleans, La., Oct. 1946, 5 pp.

Englewood Cliffs, N.J., 571 pp.

liquids. U.S. Patent No. 3, 757, 864.

extension. Trans. AIME, 201: 254-255.

Eng. AIME, New York, Dallas, 210 pp.

Eng., 10: B-6.

Retardation. Paper SPE 975, presented at 39th Annu. Fall Meet., Houston, Tex., Oct. 11-14.

Reservoirs. Elsevier, Amsterdam, 304 pp.

52: 126.

Technol., 13(3): 217-222.

159

Pellegrini Jr., J.P. and Strange, H.O., 1961. Synthetic oil containing a rare metal diester phosphate. U.S.

Phansalker, A.K., Roebuck, A.H. and Scott, J.B., 1962. U.S. Patent No. 3,046,222 (July 24). Republic Geothermal, Inc., 1979. Fracturing Proppants and Their Properties. Prepared for US. Dep.

Energy, Contract No. DE-AC32-79AL10563, Santa Fe Springs, Calif. Republic Geothermal, Inc., 1980. Geothermal Reservoir Well Stimulation Program - TechnologV Trans-

fer- Vol. I . Prepared for U.S. Dep. Energy, Contract No. DEAC32-79AL10563, Santa Fe Springs, Calif.

Rieke 111, H.H. and Chilingarian, G.V., 1974. Compaction of Argillaceous Sediments. (Developments in Sedimentology, 16.) Elsevier, Amsterdam, 424 pp.

Root, R.L., 1966. U.S. Paieni No. 3,254,719 (June 7). Schlottman, B.W., Miller, W.K. and Lueders, R.K., 1981. Massive Hydraulic Fracture Design for the East

Texas Cotton Valley Sanak. 56th Annu. Fall Meet., SOC. Pet. Eng. AIME, San Antonio, Tex., Oct. 5-7, SPE 10133, 8 pp.

Smith, J.E., 1965. Design of Hydraulic Fracture Treatments. SPE 1286, presented at SPE 40th Annu. Fall Meet., Denver, Co., Oct. 3-6.

Stewart, J.B. and Coulter, A.W., 1959. Increased fracturing efficiency by fluid loss control. Pet. Eng., June: B-43.

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Veatch, R.W., 1983a. Overview of current hydraulic fracturing design and treatment technology-Part I. Trans. AIME, 275: 677-687.

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Patent No. 2,983,678.


161

Chapter 5

ACIDIZING OILWELLS

JOHN 0. ROBERTSON Jr. and GEORGE V. CHILINGARIAN

HISTORICAL USE OF ACIDS IN OILWELLS

Williams et al. (1979) noted that the first acid treatments for oilwells were likely performed in 1895. Herman Frasch, a chemist at Standard Oil Co.’s Solar Refinery of Lima, Ohio, is credited with developing the concept for acidizing oilwells. Herman Frasch and his close friend John Van Dyke, manager of the Solar Refinery, obtained many of the early patents for acidizing oilwells and worked closely in developing the concepts still used today (see Putman, 1933, and Frasch, 1896).

The Frasch patent proposed the use of a reagent (hydrochloric acid) that reacts with limestone to produce carbon dioxide (gas) and calcium chloride (salt that is soluble in water), which are later removed from the formation as the well fluids are produced. The Van Dyke process, using sulfuric acid, produced insoluble salt (calcium sulfate) which is capable of plugging the pores and pore throats of the formation. Williams et al. (1979) noted that these pioneers conceived the acidizing process as a means to increase fluid production in oilwells for the Lima, Ohio, area, which at that time accounted for one-thrd of the domestic oil production of the United States (see Hidy and Hidy, 1955). Their first recorded acid treatment was made on August 10, 1895. The experiment had reasonably good success and the oil production for the well they treated increased by 300%, whereas gas production increased by over 400%. Although the process was recorded in literature several times over the next few years, the use of acid as a production stimulation tool decreased until little evidence of acidizing could be found in literature over the next 30 years (Williams et al., 1979, p. 2).

The next significant use of acid in oilwells did not take place until 1928 in Oklahoma by the Gypsy Oil Co., which was a subsidiary of Gulf Oil Co. (Williams et al., 1979). The problem successfully solved was the removal of oilfield scale from pipe and well equipment (Chapman, 1933). An inhibitor was used with the acid similar to that used in steel mills to protect the iron from corrosion. Decline in oil prices and high cost of acid made this type of treatment less economic and once again acidizing fell into disuse (Chapman, 1933).

The “modern era” of acidizing is directly traced to the experiences of Pure Oil Co. and Dow Chemical Co. (Williams et al., 1979). On February 11, 1932, a Pure Oil Co. well, located in Chippewa Township, Isabella County, Michigan, was treated with 500 gal of hydrochloric acid. The acid was brought to the wellsite by a wooden tank (36 in. in diameter and 12 f t long) mounted on a wagon. Two gallons

162

of arsenic inkbitor were added to the acid to reduce the corrosion of the tubing and other well equipment. About half of the acid was siphoned into the tubing, followed by 6 bbl of oil, and allowed to stand over-night. The well was swabbed the following morning and the remainder of acid was siphoned into the tubing, being diluted by the oil flush. The limestone formation responded as the oil production increased from 0 to 16 bbl/D (Newcombe, 1933). Interest in acidizing spread quickly resulting in the growth of several companies to provide acidizing services. Compa- nies originating during this era include Dowell Inc. (1932), Oil Maker’s Co. (1932), Chemical Process Co. (1932), and Williams Brothers Treating Corp. (1932). Halli- burton Oil Well Cementing Co. entered the acidizing market in 1935 (Williams et al., 1979, p. 2).

Jesse Russell Wilson, who was workmg for the Standard Oil Co. of Indiana, filed a patent on March 16, 1933, for treating a sandstone formation with a hydrofluoric acid (Wilson, 1935). During the same time period, A.M. McPherson, unaware of Wilson’s work, proposed t h s method to the Halliburton Co. and started working for the company. A well belonging to the King Royalty Co., Archer County, Texas, was treated by the Halliburton Co. on May 3, 1933, with a mixture of hydrochloric and hydrofluoric acids. The results were disappointing because the acid dissolved the calcareous matrix and cementing material of the sandstone and left the wellbore filled with a large quantity of unconsolidated sand. Consequently, the Halliburton Co. discontinued work along this line and did not commercially offer hydrofluoric-hydrochloric acid mixtures until the middle 1950’s (Williams et al., 1979, p. 3). Dowell offered a product known as “mud acid” in the 1940’s which was composed of hydrofluoric and hydrochloric acids. The intent of t h s product was to dissolve the filter cake formed from the drilling fluid in the wellbore during the rotary drilling process.

Since the mid 1930’s, advancements in the science of oilwell acidizing have been mainly in the use of additives to improve acid performance and handle a wide range of problems. Great strides have been made in the development of (1) surfactants to reduce emulsion formation, improve wettability of rock by acid, to speed cleanup, and prevent sludge formation, (2) inhibitors to reduce corrosion, (3) buffering agents to control pH, (4) retarders to retard reaction rates, (5) friction reducers, (6) fluid loss additives to reduce fluid loss from hydraulically induced fracture to the formation, and (7) complexing agents to prevent the precipitation of iron hydroxides.

PURPOSE OF OILWELL ACIDIZING

The primary purpose of acidizing an oilwell is to increase fluid production by improving the drainage efficiency of the reservoir rock around the wellbore. Acidiz- ing is particularly applicable to those oilwells producing from carbonate formations (dolomites and limestones) or clastics in which the cementing material is composed of carbonates. When forced out into the flow channels of the formation through

163

natural or induced fractures, acid dissolves a portion of the channel. This increases the cross-sectional area of the channel and, thus, increases the permeability and porosity of the reservoir rock in the vicinity of the wellbore. Inasmuch as approximately 50% of the reservoir energy to move fluids is expended within a radius of a few feet from the wellbore (Muskat, 1949), the increase in permeability about the well, created by acidization, increases the rate of fluid flow into the well. The cost of acidization is thus offset by the increase in oil and/or gas production.

ACID TYPES

An acid is a chemical compound containing hydrogen which is capable of being replaced by positive elements or radicals to form salts. Many types of acids, which are used in acid stimulation of oilwells, fall into two major categories-organic and inorganic (Harp and Dobbs, 1967, p. 1).

TABLE 5-LA

Acid properties

Acid type Formula Acid properties

Formula Molarity Specific Ionization Concentrated weight gravity for acids aqueous

in water solutions

(25 C) (% wt)

Mineral type acids Carbonic O=C(OH) , Hydrochloric HCl Hydrofluoric HF Nitric HNO, Nitrous HNO, Phosphoric H , PO,

Sulfurous H,SO,

Sulfuric *,SO,

Organic type acids Acetic CH, (COOH) Citric (CO0H)CH ,C(OH)

(COOH) CH,COOH-H,O

Formic H( COOH) Oxalic HO,C(CO, )H

46.03

36.47 20.01 63.02 41.02 98.00

82.08

98.08

60.05 192.12

46.03 90.04

12.0 1.18 28.9 1.17

18.0 1.84

17.5 1.05 - -

4.45x10-’(KIA) -

5 x10-” ( K 2 A ) strong acid 36.5-38 strong acid 48-51 strong acid -

7.516 X l o r 3 (KIA) 85 4.5 x ~ o - ~ ( K , ) -

6.34 xlO-* ( K 2 A ) 1.7 x10-, ( K I A ) - 5 X10-6(K2A) strong acid 95-98

1.754X10-5 ( K A ) 99-100 7.45 x ~ o - ~ ( K , , ) - 1.73 X ~ O - ~ ( K , ~ ) 4.02 xio-’ ( K ~ ~ )

5.18 X ~ O - ~ ( K , ~ )

1 . 7 7 2 ~ 1 0 - ~ ( K A ) -

3.8 xlO-, ( K I A ) -

164

TABLE 5-1.B

Conversion formulae for solutions having concentrations expressed in various ways (After CRC Handbook of Chemistry and Physics, p. D-154)

Concentration of 8ol”te-

SOUGHT

A

N

c:

M

F

A = Weight per cent of salute B = Molecular weight of solvent E = Moleeular weipht of solute F = Grams of solute per liter of solution

G = Molslity M = Molarity N = Mole fraction R = Density of solution grams per cc

A

-

A E

A 100 - A

~

E + B IOOOA

E(100 - A )

10R X A E

104R

__

Concentration of solute-GIVEN

N I G

IOON X E IOOG X E N X E + (1 - N ) E 1 1000 t G X E

lOOON B - N X B I -

lOOOR X N IOOOR X G N X E i- (1 - N ) E 1 - E X

IOOOR X N ?( E IOOOR X G X E N X F . + I I - N ) B 1 1 0 0 0 + G X E

M

E E 10R

B X M hl(B - E ) + IOOOR

______ ioooni

IOOOR - (M X E)

-

M X E

F

F 10R -

B X F F(B - E ) + IOOOR X E

F E -

Organic acids are derivatives of hydrocarbons containing one or more carboxyl groups (-COOH). These compounds are acidic due to the ionization potential of hydrogen of the carboxyl group:

CH,COOH + H 2 0 a CH,COO- + H+ + H 2 0 (5-1)

Inasmuch as organic acids ionize slowly, they are considered to have a lower “strength”. An acid’s “strength”, or ability to react as an acid, is measured by an ionization constant. The ionization constant is higher as the acid is more highly ionized (Table 5-LA). Several organic acids commonly used in oilwell treatment are formic (HCOOH), acetic (CH,COOH), oxalic, and citric.

Inorganic acids are derived from mineral sources. In general, they have a greater “strength” (Table 5-1) and are less expensive to prepare than similar organic acids. Most mineral acids are capable of being rapidly and highly ionized, and by definition are considered strong acids. Inorganic acids commonly used in treating oilwells are hydrochloric, sulfuric, nitric, phosphoric, and sulfamic (HS0,NH2) (Williams et al., 1979). Powdered acids (sulfamic and chloroacetic) have only limited use in well stimulation. Usually they are mixed with water at or near the wellsite. The main advantage of these expensive acids is their portability to remote locations.

Acid mixtures (acetic + hydrochloric, formic + hydrochloric, formic + hydrofluoric) have been designed mainly to exploit the dissolving power economics of hydrochloric acid and also to obtain the lower corrosivity of organic acids (Williams et al., 1979, p. 11). The latter is critical particularly at high temperatures when corrosion inhibition costs are great.

165

DESIRED PROPERTIES OF OILWELL ACIDS

Each type of acid has its own peculiar chemical and physical properties. The type of acid selected for stimulation of a particular oilwell would depend upon: (1) rock-dissolving capacity of acid, (2) spending time of acid, (3) solubility of reaction products, (4) amount and pattern of metal corrosion, (5) compatibility of acid with reservoir fluids, (6) density and viscosity of spent fluids, and (7) etching pattern after acidizing (see Harp and Dobbs, 1967).

“ Rock-dissolving capacity” refers to the volume of rock that can be dissolved by the acid. The increase in fluid conductivity of a flow channel is dependent upon the quantity of rock dissolved from the surface of that flow channel. Harp and Dobbs (1967) have shown that the conductivity of a fracture will vary as the cube of the fracture width:

c, = 4.5 x 1 0 ~ ~ ~ (5-2)

where C, = fracture conductivity (darcy-ft) and w = fracture width (in.). A fracture having a width of 0.002 in. has a conductivity of 0.036 darcy-ft, whereas a fracture having a width of 0.2 in. has a conductivity of 36,000 darcy-ft.

“Spending time” refers to the time required for an acid to expend 85-90% of its initial “strength” (dissolving capacity). After that, the acid reaction is very slow due to acid dilution. It is desirable to have a spending time high enough so that the acid can be pushed away as far as possible from the wellbore into the formation before it is spent. If the acid spends itself only a few inches from the wellbore, the improved conductivity of flow channels will also end at that point. Acids with a longer spending time offer a better opportunity for obtaining maximum and uniform conductivity and deeper penetration of etched flow channels. This is of utmost importance where it is necessary to create flow channels through a zone around the wellbore damaged by the drilling fluid filtrate, etc. (“damaged zone”).

Four major reaction products, i.e., water, carbon dioxide, and calcium and magnesium salts of that acid, are produced upon reaction of acid with reservoir rock. The first two reaction products do not pose problems because they are produced later along with the formation fluids. On the other hand, insoluble salts can precipitate and plug the formation pore channels and/or fractures. Thus, a prerequisite for any acid to be used is that the reaction salts must be soluble. Solubility of salts varies with temperature and the quantity of similar salts already dissolved in the brine. An additional problem arises when the acid-reaction salts react with other ions present in the formation waters to form insoluble salts.

An acid by its very nature will react with various metals, such as iron, as shown by the following reaction:

2HC1+ Fe -+ FeCl + H (5-3)

This process is often called “acid corrosion”. For most acids, a chemical inhibitor

166

must be added to the acid solution to aid in retarding the corrosion process. In the case of many of these inhibitors, a protective thin film forms on the metal surface. This chemical film, which serves as a barrier between the reactive acid and the metal, tends to break down at high formation temperatures. Chemical acid corrosion inhibitors, however, do not provide 100% protection from corrosion for long periods of time. As pointed out by Harp and Dobbs (1967, p. 2), a certain critical volume of inhibitor-bearing acid must flow past the metal surface before a layer of inhibitor is deposited, decreasing the corrosion rate. Emulsions can form on agitating a mixture of oil, water, and acid. If formed in flow channels, these emulsions (1) will increase the pressure gradient required to move fluids in those channels, (2) will increase fluid viscosity, (3) may plug formation pore channels, and (4) will cause a well-fluid clean-up problem. Reaction between acid and oil, especially in the case of concentrated HCI (28% and higher), may also result in the formation of sludges (precipitation of asphaltenes, etc.) in the flow channels, which may result in plugging of the channels. Surfactants can be used to combat the problems of emulsification and formation of sludges. Properly selected acid must produce the least amount of emulsification and sludge, which can be economically controlled (Harp and Dobbs, 1967).

As pointed out by Harp and Dobbs (1967, p. 3), the density and viscosity of spent acid water increase with increasing concentration of the initial acid. They increase proportionally with the relative strength of the acid type used, because increased quantities of calcium and magnesium salts are formed and dissolved in the spent acid water. The increase in density of spent fluid in the case of (1) higher concentrations of acid and/or (2) using higher ionizing (stronger) acids could create some difficulty during the recovery of treating fluids (Harp and Dobbs, 1967, p. 3). Some wells, which might otherwise flow after treatment, could require swabbing and may experience delayed returns because the reservoir pressure is insufficient to displace the higher density water. For example, in a 15,000-ft hole a difference in hydrostatic head for spent 15% HC1 and spent 28% HC1 would amount to 990 psi (Harp and Dobbs, 1967, p. 3). Whenever possible, one would prefer an acid which produces the maximum amount of carbon dioxide and only a moderate amount of reaction salts (Harp and Dobbs, 1967, p. 3).

The chemical dissolution of the formation rock by the action of acids is called etching. In general, stronger acids and acids of higher concentration (1) produce better etched flow channels with higher conductivities, (2) tend to channel or etch more erratically, and (3) are more effective in reservoirs containing very small amounts of dispersed insoluble fines. The choice of acid as far as etchability is concerned depends upon the nature and etchability characteristics of the individual reservoir rock (Harp and Dobbs, 1967, p. 4). Pillar-pocket type of etchng results in the case of carbonate rocks which are heterogeneous, because solubilities of limestone (CaCO,), dolomite [CaMg(CO,),], dolomitic limestones, and calcitic dolomites, that may all occur in the same formation, are different. Solubility usually decreases with increasing content of MgCO,. Kinetic models for reaction of acids with formation minerals are presented in Table 5-11. As pointed out by Williams et

167

TABLE 5-11

Kinetic models for acidizing reactions (After Williams et al., 1979, p. 20, table of Petroleum Engineers of AIME; for original references see Williams et al.,

Kinetic Model Reaction (Reference) Parametric Value

I. Calcium carbonate hydrochloric acid, CaCO, + HCI

rHCl = (Nierodeand Williams'l

m 6" = 1.51 x l o 5 AE = 13.1 kcallgm-moi

= 0.2, 5, = cexp ( - 1 E l R T )

2 Calciumcarbonate- rHo = -z,'c,,," m = 0 6 3 hydrochloric acid, (Lund e l a/ '1 f; = pexp(-1E/RJl

= 5 66 x 10' 5 = 15kcallgm-mol CaCO, + HCI

3. Dolomitehydrochloricacld, rHC, = -(,'(c,,,l" m = RTI(1 - aT)x,,; CaMg(CO.,l, + HCI (Lundel (,' = 6"exp(-1E/RTl

1 E = 22.5 kcallgm-mol

a = 2 x 10-'"K-l; 5" = 9.4 x 1010

x,,,=3.2 kcallgm-mol 4. Microclinehydrochloric r K = (,'ll+K~,,,~~l cllF' '' 6,' = pexpl-LEIRTl

and hydrofluoric mixtures (Fogleref K = K"exp(-AE,/RJl (K,, ,,Nan ,,Si,.,Ca,, ,Jb = 20.5 Al, AISi:O,+HCI +HF 6: = 27.7

AE = +9.2 kcallgm-mol AE, = - 1.2 kcallgm-mot

5. Albite-hydrochloricand rXs = .$'I1 + Kc,,,Ic,,, (; = 5"exp(-AE/RT) hydrofluoric acid mixtures (Lund eta/.6) K = K" exp l - I E , / R T l INa K Si Ca,., Al, 9")7~AfS708")$ H d + HF

1 E = 7 . 8 kcaligm-mol A€, = -1.1 kcallgm-mol

6. Vitreous sil ica- rMF = -f,'cwr hydrofluoric acid, IBlumberg'I SiO,(amorphousl + HF

7. Vitreous silica-

8. Vitreous silica-

rHF = - e'cHr

rHF = - f,'cHF

hydrofluoric acid ( Blumberg and SiO,(amorphousl + HF Stavrinou I

hydrofluoric acid (Blumbergand SiO,(amOrphouSI + HF Stavrinou'l

9. Vitreous silica- rHF = -&'c,, hydrofluoric acid (Mowrey9) SiO,(amorphousl- HF

10 Pyrex glass- = - 4'cH, hydrofluoric acid (Glover and G ~ i n ' ~ 1 Pyrex glass contains" SiO - 8 1 wei h t percent Na,b - 4 we& percent A 0 2 weight percent B:O: I 13 weight percent

(; = gexpI-A-ElRTl AE = kcaligm mol p = 12 Ocmisec

f,' = 7 . 1 6 ~ 1 0 - ~ c m / s e c a t 3 2 5°C

&' = 5 . 3 5 ~ iO-'cmisecat32.5"C

5' = 8 . 4 ~ lO-*cmIsec at 30°C 4' = 3.4x10-5cm1secat44"C &' = 4 . 3 9 ~ 10-5cmlsecat 70°C

exp( - 1EIRT l tE 1 c 7 5 kcaligm-mol p = 1 . 7 8 ~ 10'

4.1; courtesy of the Society 1979, p.19-28)

Notes

Freundlich isotherm describes adsorption equilibria and therefore the surface IS heterogeneous

The rate is in terms of moles of potassium dissolved per square centimeter per second Two temperature levels were reported Additional data are required to verify activation energies The rate 1s in terms of the rate of Na- dissolution Two temperature levels were studied and additional data are required to be certain that the temperature dependence of the rate expression is correct Measurement made using differential thermal analysis Surface area determined by BET method

Surface area determined by BET method

Surface area determined by BET method.

The addition of HCI had no effect on reaction rate. Arrhenius plot was not valid.

Area measured as external superficial area. Did not study influence of HCI concentration

(All concentrations are expressed in gram-moles per cubic centimeter and all rates are moles prcduced per square Centimeter per second )

al. (1979), more research is needed to define fully the concentration and temperature dependence of the reactions.

CARBONATE OIL RESERVOIRS

In the early days, acid was introduced into the wellbore by simple dumping of raw hydrochloric acid down the casing without a subsequent application of pressure

168

(acid soak). Carbonate formations, which demonstrate good response to acidizing, comprised (1) limestones, (2) dolomites, (3) dolomitic limestones, and (4) calcitic dolomites. The latter two contain CaCO,, MgCO,, and CaMg(CO,), in various proportions. The chemical equation for the reaction between hydrochloric acid and limestone is as follows:

2HC1 + CaCO, - CaC1, + H 2 0 + CO, (2 x 36.47) (100.09) (110.99) (18.02) (44.01)

(5-4)

The numbers under the chemical formulas represent the molecular weights of the compounds and, therefore, the relative weights of substances which react or are formed as products or reaction. Thus, 73 lb of hydrochloric acid reacts with 100 lb of calcium carbonate to form 111 lb of calcium chloride, 18 lb of water and 44 lb of carbon dioxide. Commercially available acid is diluted with water and has 35% HCl by weight. At this strength, 1000 gal of HC1 will dissolve approximately 4710 lb of CaCO,. The most frequent concentration of HC1 used is 15%, but concentrations ranging from 3% to 32% have been used for stimulation. Hydrochloric acid has a specific gravity of 1.075 at 20°C. In 1000 gal of 15% by weight of HC1, there are 1344.8 Ib (= 1000 X 8.34 X 1.057 X 0.15) of hydrochloric acid. Tlvs volume of acid would react with 1842.2 lb [ = (184.3/146) x 1344.81 of limestone. On assuming that the average density for limestone is 170 lb/ft3, 10.84 f t3 of limestone will be dissolved by the acid.

The reaction of hydrochloric acid with dolomite is similar to that with limestone, except for the formation of magnesium chloride salt as shown in the following equation:

4HC1 + CaMg(CO,), - CaC1, + MgCl, + 2H20 + 2c0, ( 5 - 5 ) (4 X 36.47) (184.3) (110.99) (95.3) (2 X 18.02) (2 X 44.01)

The reaction products are either water soluble or gaseous. Hydrochloric acid has the greatest dissolving power for carbonate formations

followed by formic acid and then acetic acid. Inasmuch as in carbonate reservoirs, under reservoir conditions, organic acids do not react to completion with either limestone or dolomite, a given volume of acid will dissolve less rock than that indicated by the chemical equations (Williams et al., 1979, p. 14). In order to determine the correct volume of acid required, one can use Table 5-111 which presents the fraction of acid that reacts before chemical equilibrium is reached at the reaction conditions (ile., formation temperature and pressure and concentration of reaction products). 1 '

In Table 5-111, j3 is defined as the weight (or mass) of rock dissolved per unit weight (or mass) of acid reacted:

169

TABLE 5-111

Dissolving power of various acids (After Williams et al., 1979, p. 13, table 3.4; courtesy of the Society of Petroleum Engineers of AIME)

X t 5 10 15 30

plu0** Percent Percent Percent Percent ~- -~ ~~~ ~

~~ Limestone (CaCO,, calcite: praco., = 2.71 grnicc) Hydrochloric(HC1) 1.37 0.026 0.053 0.082 0.175 Formic (HCOOH) 1.09 0.020 0.041 0.062 0.129 Acetic (CHJOOH) 0.83 0.016 0.031 0.047 0.096

~- Dolomite - ICaMg(CO,,),: pl.ah,re,c'0,,2 = 2.87 gmiccl Hvdrochloric 1.27 0.023 0.046 0.071 0.152 Formic 1.00 o.oi8 0.036 0.054 0.112 Acetic 0.77 0.014 0.027 0.041 0.083

*Data fororganicacids have not been correctedforequilibrium

I* o,,,,, mass rock dissolved r,iass pure acid reacted

ix = -volume rockdissolved volumeacid solution reacted

where M,,, = molecular weight of mineral, S, = stoichiometric coefficient of mineral, Ma = molecular weight of acid, and Sa = stoichiometric coefficient of acid.

In the case of pure limestone and 100% hydrochloric acid, the dissolving power, plo0 = 100.09 X 1/36.47 X 2 = 1.372 (wt of rock dissolved/wt of acid reacted).

In the case of 15% by weight HC1, the dissolving power, PIS, is equal to: P I S = p,,,,, x 0.15 = 0.206.

In terms of volume of rock dissolved per volume of acid reacted, the dissolving power, X , is equal to:

X = (sp. gr. acid x P)/sp. gr. carbonate (5-7)

For example, in the case of 15% HC1 solution (sp. gr. = 1.07) and pure limestone (sp. gr. = 2.71), X,, = 1.07 X 0.206/2.71 = 0.082 (volume of acid dissolved/volume of acid reacted).

Porosity of the rock is not included in these calculations. Also, inasmuch as organic acids do not react completely, the acid will dissolve less rock than is indicated in Table 5-111.

SANDSTONE RESERVOIRS

Acidizing treatments in sandstone formations normally employ a mixture of hydrochloric and hydrofluoric acids (Williams et al., 1979, p. 16). The primary purpose of acidizing sandstone formations is to dissolve the fine particles such as clays that plug the flow channels of the formation near the wellbore. These fines are

170

often introduced into the formation during the drilling operations from the drilling fluid. Clays present in the formation may also swell upon contact with a mud-filtrate or water that has a different concentration of ions from that of the original formation water. For example, if Na/Ca ratio of mud filtrate is higher than the Na/Ca ratio of the formation water, clays can be converted to Na-base clays which swell more than Ca-base clays.

As pointed out by Williams et al. (1979, p. 16), the chemical reactions between the hydrofluoric acid and silica or calcite in the rock matrix are comparatively simple, whereas the reactions with clays and/or feldspars are complex. Thus, chemical formulas such as those used in carbonate reactions are not easily developed. Williams et al. (1979, p. 16) have presented the following equations for the reactions of hydrofluoric acid and various minerals which are found in sandstone reservoirs:

Reaction with silica:

SiO, + 4HF + SiF, + 2H,O

SiF, + 2HF + H,SiF6

Reaction with silicates (feldspar or clays):

Na,SiO, + 8HF + SiF, + 4NaF + 4H,O

2NaF + SiF, + Na ,SiF6

2HF + SiF, + H,SiF6

(5-8)

(5-9)

(5-10)

(5-11)

(5-12)

Reaction with calcite:

CaCO, + 2HF + CaF, + H,O + CO, (5-13)

The dissolving power of hydrofluoric acid can thus be computed as in the case of carbonates. Hydrochloric acid is not appreciably reactive with sand and clay minerals and, therefore, is not included in the dissolving-power calculations. In a study of the complex reactions involved in sandstone acidizing, Labrid (1975) found that for silica, the main product of the reaction is fluorsilicic acid accompanied by a small amount of colloidal silica. In the first stage, feldspar and clay solubilization takes place by a uniform alteration of its crystalline lattice. This is followed by a progressive extraction of aluminum from the lattice in the form of fluorinated complexes. Williams et al. (1979, p. 17) pointed out that at least seven fluorine complexes of aluminum (from A1,F;- to A1F2+ are thought to be formed by the contact of hydrofluoric acid with clay minerals.

171

DISTANCE FROM WELLBORE-

Fig. 5-1. Precipitation zone in sandstone acidizing. (After Labrid, 1975, modified by Williams et al., 1979, fig. 3.5, p. 18; courtesy of the Society of Petroleum Engineers of AIME.)

Labrid (1975) developed a model for the dynamics of equilibrium in the sandstone acidizing process. As shown in Fig. 5-1, near the wellbore, HF and HC1 provide a solubilizing environment for the formation materials. In the zone de- lineated by the cross-hatching in Fig. 5-1, the solubility of silica compounds [assumed to be Si(OH,)] is exceeded, resulting in precipitation. Fluoraluminates precipitate farther downstream, with dissipation of the reactant HF. When sandstone is first contacted with HF, permeability reductions occur as a result of the precipitation of silica and fluoraluminates (see Labrid, 1975). Williams et al. (1979, p. 18) have suggested that this mechanism along with a reduction of permeability due to mechanical effects may be responsible for the permeability drop.

ACIDIZING TREATMENTS

The two main benefits of acidizing are (1) dissolution of foreign or formation materials in the wellbore that may be plugging or partially blocking the flow channels through which the formation fluids are flowing, and (2) enlargement of the formation flow channels, which increases the permeability near the wellbore. The increase in well fluid productivity after treatment is the measure of success for an acid job. It depends upon (1) correct recognition of subsurface problems that are causing restriction in the flow of fluids into the wellbore, and (2) selection of the proper acidization plan (acid type and volume to be used along with proper additives). There are four broad categories of acid treatment for oil wellbores: (1) acid soak or acid washing, ( 2 ) matrix acidizing, (3) acidizing through pre-existing fractures, and (4) high-pressure acidizing (acid fracturing; see Williams et al., 1979, for a detailed treatment).

Acid soak or acid washing

Acid washing is a process of removing scales from the oilwell or opening up of perforations. The acid can be placed (spotted) into the wellbore at a desired position and allowed to react with the scale (or formation), or it is circulated back and forth across the casing perforations or formation face. The intent of this type of treatment is to clean the surfaces of the wellbore and equipment by acid reaction without

172

penetrating into the formation near the wellbore. The tools can vary from simple equipment, such as tubing to spot a small quantity of acid in the wellbore, to complex tools which enable circulation of acid within the wellbore. Circulation of acid within the wellbore is used to accelerate the dissolution process by increasing the transfer rate of unspent acid to the wellbore surface and/or formation face (Williams et al., 1979, p. 5) .

Matrix acidizing

Matrix acidizing consists of injecting acid into the flow channels of the formation (intergranular porosity, intragranular porosity, and/or vugs) at a pressure below that which could cause fracturing. This technique is designed to radially penetrate the formation near the wellbore, enlarging the flow channels and dissolving the particles that might be plugging the pore spaces. This technique is useful where formation damage due to the swelling of clay particles in pore channels with consequent plugging has occurred. The plugging of formation could also occur as a result of penetration of drilling solids into the formation. This method is also used where high-pressure injection could create fractures that would break natural flow barriers, such as shale, that must be maintained to prevent water or gas production.

Williams et al. (1979) listed the following reservoir or well conditions that are necessary to obtain successful “matrix” acidizing results: (1) adequate natural permeability must have existed to produce the fluids prior to damage of the reservoir, (2) some degree of formation damage must be present, (3) sufficient reservoir pressure must be present to force these hydrocarbons to the wellbore, and (4) hydrocarbons must exist in sufficient quantity for economic production. The second condition is often difficult to evaluate quantitatively. It is ideal to determine the wellbore damage from pressure buildup data. If such pressure data is not available, however, other parameters may provide possible evidence of damage, such as production anomalies. The first requirement is important because many matrix acidizing failures are attributed to the lack of adequate initial in-situ permeability to produce sufficient fluids. Acid fracture treatment under high pressure must be considered in the latter case, as discussed in the following section. Even after meeting the above requirements, some reservoirs do not exhibit successful results after acidizing, because of improper reactions of acids with the formation fluids and/or rock or precipitation of byproducts causing plugging. Proper selection of acid (strength and type) and its additives together with proper placement of acid can prevent or minimize these problems.

The production increase by matrix acidizing is due to the total or partial removal of the damaged zone near the wellbore. It can be estimated if the radius of the damaged zone, its permeability, and the original in-situ formation permeability are known. Pressure buildup data enables estimation of this information. Williams et al. (1979, p. 5 ) showed a method of estimating the productivity improvement possible by using matrix acidizing. They considered the simplified radial system as shown in Figs. 5-2 and 5-3: a zone of reduced permeability, k, , extends from the wellbore

173

Fig. 5-2. Schematic of a damaged well in a bounded reservoir. (Modified after Williams et al., 1979, fig. 2.1, p. 6; courtesy of the Society of Petroleum Engineers of AIME.)

radius, r,, to a radius r,; formation has a constant permeability, k , to the drainage radius, re, which is equal to 1/2 of the well spacing. The productivity ratio, J,/J,, is equal to (Muskat, 1946):

where Fk = the permeability ratio (k , /k ) , J, is the undamaged formation productivity, and J, is the productivity of the damaged well. Relationship between the

DEPTH OF DAMAGED ZONE ( rs - r w I , i n .

Fig. 5-3. Production loss caused by formation damage (radial flow). (Modified after Williams et al., 1979, fig. 2.2, p. 6; courtesy of the Society of Petroleum Engineers of AIME.)

174

depth of damaged zone (r , - r,) and JJJ, ratio for various values of k , / k is shown in Fig. 5-3 for values of (r, - r,) ranging from 0 to 12 inches for a well having a drainage radius, re, of 660 ft. For example, if the damaged zone extends 10 in. into the formation and the permeability ratio is 0.1, then the JJJ, will only be 0.4. If acidizing will remove all of this damage, there will be a 2.5-fold increase in production rate (see Williams et al., 1979, p. 6).

In matrix acidizing of carbonate reservoirs, HC1 is normally utilized. Large and sinuous flow channels, commonly referred to as “wormholes”, are created because of the high rate of reaction of acid with the limestone or dolomite. These channels start at the casing perforation, penetrating from a few inches to several feet into the formation depending upon the volume and rate of acid injected. In matrix acidizing of carbonates, therefore, acid tends to treat only the damaged portions of the reservoir near the wellbore. Consequently, no significant stimulation is created above that achieved by the removal of the wellbore damage (Williams et al., 1979, p. 7)-

High-pressure acidizing

In high-pressure acidizing (with fracturing), acid is injected into the formation at a pressure high enough to fracture the formation or open existing fractures. Stimulation is significant only if the newly-formed, highly conductive fracture remains open after treatment. The main purpose of this technique is to create flow paths into the undamaged portions of the reservoir formation and thus increase the drainage surface area into the wellbore (Williams et al., 1979, chapter 2). It is the most widely used acidizing technique for stimulating carbonate reservoirs (limestones and dolomites). According to Williams et al. (1979, p. 7), a pad of fluid is injected into the formation at a rate higher than that which the reservoir matrix will accept. When the pressure exceeds the compressive earth stresses and the rock‘s tensile strength, the rock fails by fracturing. The fracture length and width increase with continued fluid injection. Further injection of acid into the wellbore and then into the fracture further widens the fracture by dissolving the carbonates. In order for the treatment to be successful, the widened fracture must remain open after the pressure is reduced and the well is placed back on production.

OILWELL ACID ADDITIVES

As mentioned previously, certain chemicals are added to commercial acids (1) to reduce emulsification of acid and other fluids in the formation, (2) to alter the rock surface wettability to improve the acid attack or to achieve better cleanup, (3) to reduce friction drop through tubing and other well equipment, (4) to divert acid flow from one zone to another, (5) to tie up ions in soluble ion complexes so that they do not precipitate and form insoluble salts, (6) to avoid the sludging of certain highly asphaltic oils, (7) to reduce the rate of fluid loss from the fracture into the matrix, and (8) to reduce the acid attack on metallic equipment.

175

Corrosion inhibitors

In acid corrosion, metallic iron goes into solution at anodic sites and electrons are liberated at cathodic sites, reducing hydrogen ions to form gaseous hydrogen (Williams et al., 1979, p. 92). A corrosion inhibitor reduces the acid reaction rate at the cathodic site, anodic site, or both. An anodic type inhibitor functions by sharing electrons of its molecules with anodic sites on the metal surface. This makes the surfaces more noble. In the case of cathodic type of inhibitor, a protective film forms on the metal surface by attachment of the cationic inhibitor to the cathodic area through electrostatic attraction. The effectiveness of inhibitors is a function of their ability to form and maintain a film on the iron surface. As pointed out by Williams et al. (1979, p. 92), an important factor limiting the effectiveness is hgh temperature, because at higher temperatures the acid corrosion rate increases, whereas the ability of the inhibitor to adsorb on the metal surface decreases. In general, at temperatures above 250 O F , effective inhibitors for strong acids are very expensive and hard to formulate.

As pointed out by Harp and Dobbs (1967, p. 7), hydrochloric acid is the most corrosive (on ferrous metals) of all commonly used acids for stimulation of oilwells. With increasing temperature and/or concentration of acid, the acid reaction on the metal becomes more rapid. Some organic corrosion inhibitors can protect tubular

d E!

1000

I I

CONDITIONS

A C I D 15% HCI M E T A L T Y P E N-80 EXPOSURE TIME 24 HOURS AG IT A T I0 N 130 R P M

- INHIBITOR CONC. 0.1 VOL. %

10 1 I

100 150 200

TEMPERATURE - "F

Fig. 5-4. Relationship between the temperature and corrosion rate. (After McDougall, 1969, fig. 4, p. 32; courtesy of the Materials Protection.)

176

goods for up to 24 hrs at 300 O F using 15% HC1. In the case of 28% HC1 at 210 ” F, protection cannot be provided for more than six hours. New inhibitors for use with strong acids and capable of long-term metallic protection must be developed for deep or high-temperature wells. Hydrochloric acid usually etches in a “pitting” or a “roughmg” pattern on tubular goods (Harp and Dobbs, 1967, p. 7).

Williams et al. (1979, p. 95) stated that the selection of an inhibitor type and its concentration can be done only after the following facts concerning treating and well conditions have been established: (1) type of tubular goods, (2) duration of acid-pipe contact, (3) maximum pipe temperature, and (4) type and concentration of acid. It is assumed that a loss of 0.02 lb/sq-ft of metallic area can be tolerated if there is no pitting. Arsenic inhibitors, which historically have been used for high-temperature wells have the following disadvantages: (1) arsenic is a dangerous poison, (2) arsenic compounds are relatively ineffective if HC1 concentration is above 17%, (3) arsenic compounds are ineffective in the presence of hydrogen sulfide, and (4) arsenic can poison catalysts used in the refineries. Figure 5-4 shows the effect of temperature on the effectiveness of an inhibitor. While not as effective as arsenic, some organic inhibitors can be used at temperatures up to 250°F. Expensive systems such as combined organic-inorganic inhbitor systems can be designed for temperatures up to 400 O F . For example, inhibition extender potassium iodide is effective.

Mutual solvents

Materials that have appreciable solubility in both oil and water are called mutual solvents. They include alcohols, aldehydes, ketones, and ethers. In oilfield applications, ethylene glycol monobutyl ether (EGMBE) is frequently used in sandstone acidizing as a mutual solvent. It also reduces interfacial tension between oil and water and acts as a solvent to solubilize oil in water. Sutton and Lasater (1972) found that the use of a mutual solvent reduces the adsorption of surface-active materials on the formation solids. Hall (1975) found that the addition of a mutual solvent increased the depth of penetration of the surfactant in laboratory tests (sand packs). Dunlap (1966) described the use of EGMBE (preflushing before HC1 injection) in a carbonate reservoir. The EGMBE improves the effectiveness of the acid treatment acting as a formation cleaner and oil remover. (See Williams et al., 1979, for a detailed treatment of the subject.)

Surfactants

Williams et al. (1979, p. 95) pointed out that surface-active agents are used in oilwell acid treatments to (1) reduce interfacial tension, (2) demulsify acid-oil emulsions, (3) alter formation wettability, (4) prevent sludge formation in the case of concentrated acids (28% HC1 or higher), and/or (5) speed cleanup. Cationic surfactants (organic amines and salts of quaternary amines) and nonionic surfactants (polyoxyethylated alkylphenols) are often added as a demulsifying agent to

117

minimize the development of formation fluid blocks by acid-spent acid-crude oil emulsions. Alkyl aryl sulfonate (anionic) or ethoxylated alkylphenol (nonionic) surfactants in concentrations of 0.1-0.5% by volume can be used to reduce the interfacial tension between acid or spent acid and oil phase (LST acid, i.e., low-surface-tension acid). In theory, the reduced surface tension aids in increasing the acid’s spreading ability on the surfaces of oil- or water-wet rocks. In addition, the lower surface tension facilitates the commingling of live or spent acid with the formation waters resulting in more efficient removal of fluids (Halliburton, 1965). Hall (1975) noted that adsorption of the surfactants on rocks near the wellbore limits their effectiveness in the field. In California (U.S.A.), the Rocky Mountain States (U.S.A.), Canada, and other areas, anti-sludge agents are required during acidizing formations with heavy oils, containing high concentrations of asphaltic materials. Surface active agents such as fatty acids, alkylphenols, and certain oil-soluble surfactants are sometimes effective. It is strongly recommended to determine the type of asphaltine present in the crude oil and actually test the effectiveness of the surfactant in the laboratory using the field crude oil.

Friction reducers

Normally, friction reducers are polymers that convert the Newtonian fluid possessing constant viscosity at all shear rates, to a non-Newtonian fluid, with

I0

FLOW RATE, BBL PER MIN

Fig. 5-5. Relationship between the flow rate and friction pressure drop through a 2-7/8-in. tubing using various concentrations of polymer. (After Williams et al., 1979, p. 96, fig. 11.8; courtesy of the Society of Petroleum Engineers of AIME.)

178

TABLE 5-IV

Friction reducers (After Williams et al., 1979, p. 97, table 11.1; courtesy of the Society of Petroleum Engineers of AIME)

Fluid type Generic

Water-based pad Guar

classification of additive

Polyacrylamide Cellulose

Oil-based pad Polyisobutylene Fatty acids Crosslinked organic polymers

Acid Guar Gum karaya Polyacrylamide Cellulose

viscosity varying with shear rate. Addition of polymer to the acid mixture will reduce the fluid’s frictional pressure drop through well tubing. T h s drop in pressure, in turn, reduces the horsepower required to pump the acid mixture at a specified rate or to pump the acid at the maximum allowable rate as the surface pressure is maintained below a fixed limit. Figure 5-5 shows a typical relationship between the friction pressure and flow rate through a Z7/,-in. tubing with various concentrations of polymer. With increasing polymer content, the friction pressure is decreased. The concentration of polymers used varies from 1 to 20 lb/1000 gal of fluid (Williams et al., 1979, p. 97). Table 5-IV lists many of the common additives used for friction reduction.

Acid .fluid-loss additives

Fluid-loss reduction additives are added to reduce the rate of fluid loss from the acid mixture in the induced fracture to the formation. Longer and wider fractures result on reducing the rate of fluid loss from the acid mixture while generating hydraulically induced fractures. Generally, fluid-loss reduction additives are composed of two agents: (1) inert, solid particles that can enter the formation pores, bridging near the fracture surface (Fig. 5-6.a), and (2) gelatinous material that plugs the formation pores (Fig. 5-6.b; Williams et al., 1979, p. 98). Commonly used fluid-loss additives are listed in Table 5-V.

Crowe (1971) listed the following limitations associated with fluid-loss additives: (1) The fluid-loss additive deposited from the fluid pad is effective only for a short time once it is contacted by an acid that does not contain an effective fluid-loss additive. (2) It is difficult to attain the same degree of fluid-loss control with an acid

179

A. SOLID PARTICLES ENTER AND BRIDGE IN PORES

FRACTURE SURFACE 3-

PORES 3 - r - p FOR MATlON

6. SOLID ADDITIVE GELATINOUS MATERIAL PLUGS PORES IN

Fig. 5-6. Behavior of typical fluid-loss additives. (After Williams et al., 1979, p. 97, fig. 11.9; courtesy of the Society of Petroleum Engineers of AIME.)

as with an inert fluid, because acid (reaction) destroys the matrix on which the filter cake is being deposited. (3) Acid reacts with all the polymeric additives used to control fluid loss, particularly at high temperatures. (4) Most fluid-loss additives cannot effectively seal formation fractures or vugs that may be intersected by the hydraulically induced fracture.

TABLE 5-V

Commonly used fluid-loss additives (After Williams et al., 1979, p. 98, table 11.2; courtesy of the Society of Petroleum Engmeers of AIME)

Hydrocarbon pad

Acid

Fluid type Solid additives Gelatinous additives

Aqueous pad Silica flour Guar Calcium carbonate Cellulose Organic polymer Polyacrylamide Inert solid coated with guar-type material

Inert solid coated with organic sulfonate

Acid-swellable solid Organic resin Silica flour Organic polymers

Guar Karaya Cellulose Polyacrylamide Polyvinyl alcohol

180

Diverting agents

A diverting agent is used to obtain maximum stimulation in a wellbore by diverting the injected fluids from a lower-pressure interval to a higher-pressure one by temporarily plugging the lower-pressure interval. When used in matrix acidizing, diverting agents are designed to bridge at the wellbore formation face by plugging off the pores of the lower-pressure intervals first, followed by the plugging of sequentially higher-pressure intervals as they begin to take fluid. Diverting agents used for matrix acidizing include solid organic acids, finely divided inert organic resins, deformable solids, acid-swellable polymers, mixtures of waxes and oil-soluble polymers, and mixtures of water-soluble polymers (gum guar, gum karaya, cellulose, polyacrylamide, etc.) and inert solids (silica flour, calcium carbonate, rock salt, and oil-soluble resins; Williams et al., 1979, p. 99). These diverting agents often can be used to divert acid flow from intervals of higher permeability to those of lower permeability without damaging the formation. The ideal quantity of agent to use would be that which just reduces the flow into the higher-permeability zone so that

N O D I V E R T I N G A G E N T

W E L L N O . 1 2 3 4 6 3 1 2 3 2 1 2

(19) (8 l

\ / \ 1 - FIELD A B C

Fig. 5-7. Comparative field results of fracturing with wax-polymer and other diverting agents. (After Gallus and Pye, 1969, p. 503, fig. 10; courtesy of the Society of Petroleum Engineers of AIME.)

181

it is equal to the flow into the lower-permeability interval. As pointed out by Williams (1979, p. 99), use of the excessive amount of additive will drastically reduce injectivity into all zones.

An effective diverting agent in acid fracturing must bridge either at the perforations or immediately upon entering the fracture (Williams et al., 1979). The bridge formed in this fashion must have a low permeability and be strong enough to stand up under a differential pressure of several hundred psi. Upon completion of the

TABLE 5-VI

Comparison of various iron-sequestering agents (After Williams et al., 1979, p. 102, table 11.3; adapted from Smith et al., 1968; courtesy of the Society of Petroleum Engineers of AIME)

Sequestering agent Advantages Disadvantages Amount a

(lb)

Citric acid

Citric acid-acetic acid mixture

Lactic acid

Acetic acid

Gluconic acid

Tetrasodium salt of ethylene diamine tetracetic acid (EDTA)

Trisodium salt of nitrilo triacetic acid (NTA)

Effective at temperatures of up to 200 F

Very effective at lower temperatures

Little chance of calcium lactate precipitation if excessive quantities are used

No problem from possible precipitation as calcium acetate

Little chance of calcium gluconate precipitation

Large quantities may be used without precipitation of calcium salt. Effective at temperatures up to at least 200 F

May be used in considerable excess without precipitation as calcium salt. Ef- fective up to at least 200 F

Will precipitate as calcium citrate when excess quantities are used

When indicated amount is used, calcium citrate will precipitate unless at least 2000 ppm Fe3+ is present in spent acid. Efficiency decreases rapidly at temperatures above 150 F

Not very effective above 100 F

Effective only to about 160 F

Effective only up to about 150OF. Expensive on a cost-performance basis

More expensive to use than many other agents

Less expensive than EDTA, but still more expensive than citric acid.

175

50 (citric acid) 87 (acetic acid)

190 (at 75 F)

435

350

296

250

a Amount required in 100 gal of 15% HCl acid to sequester 5000 ppm Fe3+ for a minimum of 2 days at 150 F.

182

treatment, the diverting agent must be easily removed from the fracture or perforations when the well is returned to production. Data are presented in Fig. 5-7 comparing the performance of several proppants. Additional information on acid fracturing and proppants is presented in Chapter 4.

Complexing agents

The complexing agent is used to tie-up ions such as Fe3+ before they can precipitate. When appreciable quantities of iron in the ferric ionization state (Fe3+), as opposed to the more typical ferrous state (Fe2'), are dissolved by the acid, iron precipitates in the flow channels and permeability reduction can occur when the pH returns to 7. Sources of iron include (1) corrosion products found on the walls of casing and other tubular goods, (2) pipe scale, and (3) iron in a mineralized form found in the formation (Williams et al., 1979). The precipitation of ferric hydroxide can be prevented by adding certain complexing or sequestering agents to the acid. Several organic acids (citric, lactic, acetic, and gluconic) and derivatives [ethylene diamine tetracetic acid (EDTA) and nitrilo triacetic acid (NTA)] were reviewed by Smith et al. (1968). Table 5-VI has been adapted from the studies by Smith et al. (1968) by Williams et al. (1979). Each agent has its own advantages and limitations with cost and performance widely varying.

Cleanup additives

In low-pressure reservoirs where a problem is anticipated in removing the spent acid, the addition of gaseous nitrogen, alcohols, or surfactants can be considered (Foshee and Hurst, 1965; Howard and Fast, 1970). Nitrogen can be added so that when the wellbore pressure is reduced after the acid treatment, the nitrogen will expand and help to push the spent acid out of the flow channels along with the production. Alcohols are sometimes added to help to lower the interfacial tension between the spent acid and formation fluids (McLeod and Coulter, 1966). Adding alcohol to acid is most useful in very low-permeability, shally gas reservoirs, where it is difficult to remove water from the formation (Williams et al., 1979).

OILFIELD ACID TREATMENT DESIGN

Matrix acidizing

In matrix acidizing, natural permeability is restored around the wellbore by a reactive acid flowing through the pores of the rock matrix, with injected acid pressure being lower than that of the formation fracturing gradient. If the acid penetrates the pores uniformly, the permeability will increase as a result of the pore enlargement. If fractures are opened, the entire interval may not be treated. According to Halliburton (1971, personal communication), a large percentage of

183

PERCENT HCI

Fig. 5-8. Effect of concentration of hydrochloric acid on reaction and spending rates. Reactivity reaches a maximum at a concentration of 24-25%. (Courtesy of A.R. Hendrickson of the Dowel1 Division of the Dow Chemical Co.)

matrix acid treatments are conducted at injection rates which are too high. The rate of injection is dependent upon the thckness and permeability of the formation treated. As a general rule, the maximum injection rate should not exceed 0.1 bbl/min/ft of treated interval. Low injection rates must be used in order to concentrate the acid reaction in the damaged zone around the wellbore. The productivity increases as a result of removal of wellbore damage. Usually, low initial injection rates are recommended, and the core tests with acid must be conducted prior to field tests to determine the optimum rates. Generally, the volume of acid is limited to less than 100-200 gal/ft of treating interval. If there is a good distribution of acid and damage is shallow, only 10-25 gal/ft may be required (Hendrick- son, 1972, p. 325).

Spending time of the acid determines the depth of acid penetration into the formation. The acid reaction rate decreases as the acid is spent. The radius of penetration of unspent acid is a function of the acid velocity in the formation and the spending time of acid. The latter depends on the volume and strength of the acid (Fig. 5-8), specific surface area of the formation, porosity, pressure, and temperature. If the injection rate remains constant and the spending time does not change from one increment of the acid to the next, additional injected acid entering the flow channels will not penetrate much deeper than the first acid increment. Instead, it will enlarge the existing flow channels. The acid velocity in the formation

184

decreases as a result. Enlargement of pores also results in the reduction of the surface/volume ratio. These two effects are opposite in significance.

The following assumptions are made in evaluating a matrix acid treatment (Craft et al., 1962, p. 538): (1) the pores are of uniform size, (2) the formation is homogeneous, (3) the acid penetration is uniform and radial, (4) uniform decline in reaction rate with decreasing acid concentration, and ( 5 ) uniform decrease in the weight of formation dissolved per increment of distance penetrated until the acid is completely spent. The volume of acid injected is equal to the pore volume invaded (see Craft et al., 1962, p. 538):

qit = T@h( r,’ - r:’) (5-15)

where qi = acid injection rate, bbl/min, t = spending time of acid, sec, r, = radial distance of penetration until acid is spent, ft, @ = fractional porosity, r, = wellbore radius, ft, h = formation thickness, ft.

In order to acheve greater penetration during matrix acidizing, it is necessary to decrease the reaction rate (increase the spending time) and/or increase the rate of injection. Solving for r,:

r, = [ (0.0936 qit/T@h) + r:]1’2 (5-16)

The spending time for several different acids is presented in Table 5-VII. Hendrick- son et al. (1960) found that for most acids the spending time is less than 15 sec, because of large specific surface area of reservoir rocks. Table 5-VIII shows various required injection rates computed by Hendrickson et al. (1960) for a carbonate formation. Craft et al. (1962, p. 540) pointed out that inasmuch as spending time is affected by many variables, it should be determined by laboratory tests for each particular formation to be treated. In tight formations, acidizing at pressures lower than fracturing pressures will result in an increase in permeability only in the vicinity of the wellbore. Consequently, matrix acidizing is applicable for overcoming formation damage only.

The most important variable, which must be determined prior to acidizing, is the volume of acid to be used in a particular stimulation job. In most cases, however, the optimum volume of acid required cannot be determined accurately. This is critical because insufficient volumes of acid may cause damage to a sandstone formation, for example. In the case of excessive volumes of acid, cementing materials in the sandstones can be dissolved, resulting in damage through the collapse of pore structure and thus, incurring additional costs. Acid volumes required for optimum treatment are determined by the following variables: (1) porosity, (2) specific surface area of rock, (3) chemical composition of the formation, (4) thickness of the formation interval to be treated, (5 ) mineralogy and the minerals distribution within the rock, (6) rock strength, (7) extent and type of wellbore damage, (8) acid type, (9) acid strength, (10) treatment rate, (11) pressure, and (12) formation temperature. Direct laboratory tests must be made to determine

185

TABLE 5-VII

Different acidizing solutions (After Hendrickson, 1972, table 1, p. 312, in: Chilingar et al., 1972; courtesy of the American Elsevier)

Concentration (%) Pounds of Relative reaction and type of acid CaCO, equivalent to time a

1000 gal of acid

7.5 HCl 15 HCl 28 HCl 36 HCI 10 Formic 10 Acetic 15 Acetic

14 HCl

14 Acetic

8 90 1840 3610 4860

910 710

1065

2420

2380

1700

0.7 1.0 6.0

12.0 5.0

12.0 18.0

6.0

12.0

18.0

a Approximate time for acid reaction to be completed (“spent”) to an equivalent strength of 1.5% HCl solution. Comparative values will vary depending on reaction conditions.

the required optimum acid volumes. Information obtained from other acid treatments in the nearby areas and in similar formations should also be used. In the case of absence of such information and laboratory test results, acid volumes around 100-200 gal/ft of treated interval can be used (rule of thumb).

The following formula is recommended by the writers for the determination of

TABLE 5-VIII

Injection rates and bottomhole differential pressures required to produce different depth of penetration during matrix acidizing (After Hendrickson et al., 1960, p. 17, table 1; courtesy of the Society of Petroleum Engineers of AIME)

Desired penetration {ft) indicated formation permeabilities

Necessary minimum injection rate and pressure differential at

5 md 100 md

0.5

1

5

0.56 bbl/min/ft 0.26 bbl/min/ft 26,800 psi 624 psi 1.7 bbl/min/ft 0.17 bbl/min/ft 117,000 psi 2710 psi - 14.2 bbl/min/ft

94,000 psi

186

surface area per unit of pore volume, sp, of consolidated rocks in cm2/cm3 (Chilingar et al., 1963):

(5-17)

where F = formation resistivity factor, k = permeability in md, and @ = fractional porosity of the rock.

For unconsolidated sands, Langnes et al. (1972, p. 247) proposed the following formula for determining the surface area per unit of bulk volume, sb, in cm2/cm3:

sb = 5650 ( @ 3 / k ) 0 ’ 5 (5-18)

where @ = the fractional porosity and k = permeability in darcys.

FRACTURE ACIDIZATION-DESIGN

As pointed out by Williams et al. (1979, p. 53) in their excellent monograph, the selection of the first candidate well is an important step in designing an acid fracturing treatment. In a particular reservoir, the first selected well should give the greatest productivity increase with minimal down-side risk. A reservoir study, including pressure buildup tests, are required, therefore, so that a proper acid fracture treatment can be designed and priority list for stimulation established. Much of the material on the design of the fracture treatment has been included in Chapter 4 entitled “Fracturing”. The design of an acid fracture treatment involves the following steps: (1) selection of fracturing fluid to be used as pad, injection rate, etc., (2) determination of formation rock and fluid properties, (3) prediction of the fracture geometry, (4) prediction of distance of acid penetration of the fracturing fluid and acid, ( 5 ) prediction of the fracture conductivity, (6) prediction of stimulation ratio, and (7) a thorough economic study (see Williams et al., 1979). If improvement in the production occurs in a reasonable payout time, job can be considered successful.

If propping agents are used in fracture acidizing, they limit the injection rates to some extent, and the distance penetrated by the acid before it is spent is less. Formation heterogeneity (differences in composition, solubility, and reaction rate) usually causes irregularities on the face of the acidized fracture. This prevents the fracture from closing completely (“healing”) when the pressure is released. As a result of fracturing, the surface area into whch the fluids enter the wellbore is greatly increased.

Widening the preexisting fractures by acidizing results in a decrease in the surface area (i.e, surface area per unit of grain, bulk, or pore volume). As a result, spending time of the acid is increased with consequent increase in the penetration distance of acid before it is spent.

187

SAMPLE QUESTIONS AND PROBLEMS '

(1) List the types of acids used in well stimulation operations. Explain the

(2) What are the applications of acids in oilfield operations? Discuss in detail. (3) List and discuss the main types of acidizing techniques. (4) Explain the sources of well damage in detail. (5) What kind of acid is used most widely in treating carbonate formations?

Explain why. Give typical acid-carbonate reactions. (6) Explain why hydrochloric acid alune is rarely used in treating sandstones (it is

used only when sandstone has a high calcite content). What type of acid is most widely used in sandstone acidizing? Give typical reactions.

(7) Discuss the factors that affect the acid penetration distance in an acid-fracturing treatment.

(8) What are the steps in designing a successful acid fracturing treatment? Explain each one in detail.

(9) What are the purposes of using additives in acidizing operations? Name at least three additives for each purpose.

(10) List and discuss the factors that should be considered in economic evaluation of acidizing treatments.

(11) Calculate the surface area per unit of pore volume of a carbonate rock having porosity of 15%, permeability of 8 md, and cementation factor (m) of 2. Use different equations and compare the results.

(12) What effect does enlargement of pores have on acid velocity and on surface/volume ratio? Are these effects opposite in significance or not? Explain!

(13) How much deeper would later increments of acid penetrate before being spent? Why?

(14) On using stronger acid, does spending time increase or decrease? Why? (15) Is the spending time of the acid lower or higher in the case of lower specific

surface area? Why? (16) Is sludge formation more or less likely with stronger acid? Why? How can it

be prevented? (17) How are acid volumes and pumping rates determined for acidizing oper-

ations. (18) During matrix acidizing, what promotes formation of small-diameter

wormholes. (19) A skin factor of + 6 was calculated from a pressure buildup test conducted

in a 6000-ft deep oilwell. The formation is known to be an arkosic sandstone having 25 ft net thickness. Average formation permeability was calculated to be 40 md, and

advantages and disadvantages of each one.

' The help extended by Mehmet Parlar in preparing this section is indeed greatly appreciated by the writers.

188

the formation temperature is known to be 200 O F . Engineers decided to stimulate this well by an acid treatment. The following information is also available: (1) Oil viscosity at reservoir conditions = 5 cP; ( 2 ) well drainage area= 20 acres; (3) fracture gradient at current reservoir pressure is estimated to be 0.7 psi/ft; (4) the overburden pressure gradient = 1.0 psi/ft; ( 5 ) the wellbore radius = 4.5 in.; and (6) current reservoir pressure = 2000 psi. (Consult Craft et al., 1962.) Determine:

0.57 cP, without fracturing the formation.

pressure gradient of the acid is 0.465 psi/ft? Neglect the frictional losses.

estimated to be 11 in.

(a) The maximum injection rate that can be used if the acid viscosity at 200 O F is

(b) The maximum surface injection pressure without fracturing if the hydrostatic

(c) Volume (in gallons) of mud acid required if the radius of damaged zone is

(d) Volume of acid (15% HC1) required for preflush? (e) The increase in productivity due to acidizing if the well is tested again after

the stimulation job and the skin factor is calculated to be - 2 . ( f ) What would have been the stimulated/natural permeability ratio if the acid

has increased the permeability out to a distance of 6.5 in. from the wellbore. (g) The maximum depth of permeability increase if the total mud acid volume to

be used is economically limited to 5000 gal. (h) The stimulated/damaged permeability ratio, if the skin factor after acidizing

is -2 [assume same conditions as in (g)]. (i) The skin factor after acidizing, if the production rate has been increased by a

factor of 2 as a result of acidizing [assume same conditions as in (g)]. (20) Matrix acidizing is used in treating a dolomite formation. The following

information is available: (1) formation depth = 7000 ft, (2) net formation thickness = 25 ft, (3) formation permeability = 20 md, (4) porosity = 0.13, ( 5 ) fracture gradient = 0.65 psi/ft, (6) the current reservoir pressure = 2500 psi, (7) overburden pressure gradient = 1.0 psi/ft, (8) well drainage area = 40 acres, (9) the wellbore radius = 3 in., (10) acid viscosity at reservoir temperature = 0.5 cP, and (11) hydrostatic pressure gradient of the acid = 0.45 psi/ft. Determine:

(a) The maximum injection rate that can be used without fracturing the formation.

(b) The maximum surface injection pressure that can be applied without fracturing the formation. Neglect the frictional losses.

(c) The distance of acid penetration until it is spent, assuming an injection of 100 gal of 15% HC1 per foot of treated interval at an injection rate of 90% of the maximum. Acid spending time = 20 sec.

(d) The weight of dolomite treated by the acid. (e) The acid penetration distance under the conditions of question (c), if the acid

( f ) The hydraulic horsepower required, if the frictional pressure loss is-psi/ft. (21) A zone is going to be stimulated by matrix acidizing using acid having a

specific gravity of 1.09. Calculate the maximum allowable surface pressure if the

spending time is retarded to 40 sec.

189

frictional pressure drop is 600 psi and the fracture gradient is 1.0 psi/ft. Depth of the treated zone = 9000 ft.

(22) A 50-ft producing section of pure limestone with a porosity of 0.18 has been acidized to increase the matrix permeability. The well radius is 6 in. Determine:

(a) How many gallons of 16.5% HCI (spending time = 15 sec and sp. gr. = 1.075) would dissolve 900 Ib of limestone?

(b) What would be the pumping rate in bbl/min for this acid to penetrate a radial distance of 1.5 ft before it is spent.

(c) If the producing section contains 90 preexisting fractures at the wellbore, the average width of the fractures is 0.005 in., and the spending time is 50 sec, calculate the depth of penetration of the unspent acid.

(23) Determine the approximate spending time of an acid given the following: (a) Fracture width, w = 0.005 in. (b) Channel or openhole diameter, d = 0.01 in. (c) Relative spending time of acid, c, = 1.0 sec. (d) Formation temperature, T = 150 O F .

REFERENCES

Chapman, M.E., 1933. Some of the theoretical and practical aspects of the acid treatment of limestone

Chilingar, G.V., Main, R. and Sinnokrot, A,, 1963. Relationship between porosity, permeability, and

Chilingar, G.V., Mannon, R.W. and Rieke 111, H.H., 1972. Oil and Gas Production from Carbonate Rocks.

Craft, B.C., Holden, W.R. and Graves Jr., E.D., 1962. Well Design: Drilling and Production. Prentice-Hall,

CRC, 1980-1981. Handbook of Chemistry and Physics. CRC Press, Inc., Boca Raton, Florida. Crowe, C.W., 1971. Evaluation of Oil Soluble Resin Mixtures as Diverting Agents for Matrix Acidizing.

SPE Paper No. 3505, presented at the SPE-AIME 46th Annu. Fall Meet., New Orleans, Oct. 3-6. Dunlap, P.M., 1966. Acidizing subterranean formations. U.S. Patent No. 3,254,7I8 (June 7). Foshee, W.C. and Hurst, R.E., 1965. Improvement of well stimulation fluids by including a gas phase. J.

Frasch, H., 1896. Increasing the flow of oil wells. U S . Patent No. 556,669 (Mar. 17). Gallus, J.P. and Pye, D.S., 1969. Deformable diverting agent for improved well stimulation. J. Pet.

Technol., 21(4): 497-504 (also in Trans. AZME, 246: 497-504). Hall, B.E., 1975. The effect of mutual solvents on adsorption in sandstone acidizing. J . Pet. Technol.,

27(12): 1439-1442. Harp, L.J. and Dobbs, J.B., 1967. The Family of Acids Used in Reservoir Stimulation, The Western

Company, Fort Worth, Tex., 16 pp. Hendrickson, A.R., 1972. Stimulation of carbonate reservoirs. In: G.V. Chilingar, R.W. Mannon and

H.H. Rieke 111 (Editors), Oil and Gas Production from Carbonate Rocks. American Elsevier, New York, N.Y., pp. 309-339.

Hendrickson, A.R., Hurst, R.E. and Wieland, D.R., 1960. Engineered guide for planning acidizing treatments based on specific reservoir characteristics. Trans. AZME, 219: 16-23.

Hendrickson, A.R., Rosene, R.B. and Wieland, D.R., 1960. Acid Reaction Parameters and Reservoir Characteristics Used in the Design of Acid Treatments. ACS paper, presented at the ACS 137th Natl. Meet., Cleveland, Ohio, Apr. 5-14.

wells. Oil Gas J. , Oct. 12: 10.

surface areas of sediments. J. Sediment. Petrol., 33(3): 759-765.

American Elsevier, New York, N.Y., 408 pp.

Englewood Cliffs, N.J., pp. 536-546.

Pet. Tech., 17 (7): 768-772.

190

Hidy, R.W. and Hidy, M.E., 1955. Pioneering in Big Business - History of Standard Oil Company (New

Howard, G.C. and Fast, C.R., 1970. Hydraulic Fracturing. Monograph Series. (Henry L. Doherty Ser.,

Labrid, J.C., 1975. Thermodynamics and kinetics aspects of argillaceous sandstone acidizing. Soc. Pet.

Langnes, G.L., Robertson Jr., J.O. and Chilingar, G.V., 1972. Secondary Recovery and Carbonate

McDougall, L.A., 1969. Corrosion inhibitors for high temperature acid applications. Muter. Prot., 8(8):

McLeod, H.O. and Coulter, A.W., 1966. The Use of Alcohol in Gas Well Stimulation. SPEpaper No. 1663,

McLeod, H.O., McGinty, J.E. and Smith, C.F., 1966. Alcoholic acid speeds clean-up in sandstones. Pet.

Muskat, M., 1946. The Flow of Homogeneous Fluids through Porous Media. McGraw-Hill, Ann Arbor,

Newcombe, R.B., 1933. Acid treatment for increasing oil production. Oil Weekly, May 29: 19. Putman, S.W., 1933. Development of acid treatment of oil wells involves careful study of problems of

each. Oil Gas J. , Feb. 23: 8. Smith, C.T., Crowe, C.W. and Nolan 111, T.J., 1968. Secondary Deposition of Iron Compounds Following

Acidizing Treatments. SPE Paper No. 2358, presented at the SPE-AIME East. Reg. Meet., Charleston, W.Va., Nov. 7-8.

Sutton, G.D. and Lasater, R.M., 1912. Aspects of Acid Additive Selection in Sandstone Acidizing. SPE Paper No. 4114, presented at SPE-AIME 47th Annu. Fall Meet., San Antonio, Tex., Oct 8-11.

Williams, B.B., Gidley, J.L. and Schechter, R.S., 1979. Acidizing Fundamentals. (Henry L. Doherty Ser., Monogr. 6). S.P.E. of A.I.M.E., Dallas, Tex., 124 pp.

Wilson, J.R., 1935. Well treatment. U.S. Patent No. 1,990,969 (Feb. 12).

Jersey) 1882-1911. Harper, New York, N.Y., 156 pp.

Monogr. 2). SOC. Pet. Eng. of AIME, Dallas, Tex., 203 pp.

Eng. J . , 15(2): 117-128.

Reseruoirs. American Elsevier, New York, N.Y., 304 pp..

31-32.

presented at the SPE-AIME Eastern Reg. Meet., Columbus, Ohio, Nov. 11-12.

Eng., 38(2): 66-70.

Mich., 763 pp.

191

Chapter 6

GRAVEL PACKING

W.B. HATCHER, GEORGE V. CHILINGARIAN and JAMES R. SOLUM

IN T R 0 DUCT I 0 N

Sand production is an operational problem that occurs in many wells that are producing from unconsolidated formations. If left unchecked, this problem can result in high operating expenses and may even require the abandonment of a producing well. If a well is a frequent sander, then many hours of hoist time are required in order to bail the sand from the well. Additional costs are incurred due to lost production during downtime and erosion that occurs as a result of sand production. In addition, with large amounts of sand production the liner or casing may collapse.

Gravel packing is a mechanical means of controlling sand production. If properly designed and applied, this completion technique can provide adequate sand control throughout the life of a well. In order to obtain an effective gravel-packed completion, it is essential that the pack be properly designed using the proper gravel, screen, carrier fluid, and placement technique.

SAND PRODUCTION

As pointed out by Allen and Roberts (1982, p. 3 9 , sand production is usually associated with shallow formations of Tertiary age. It is important to note, however, that the problem can be encountered at almost any depth. The production of sand is related to formation strength, flow stability, viscous drag forces, and pressure drop into the wellbore.

Formation strength is dependent upon the degree to which cementation has occurred during diagenesis. Both water and steam have the capability of dissolving cementing material. If a steamflood or waterflood is to be initiated in a consolidated sandstone reservoir, therefore, it is advisable to plan ahead and consider completing producing wells with provisions for sand control. It is also possible for cementation to break down as a result of compaction due to fluid depletion (decrease in pore pressure).

Viscous drag forces are related to flowrate and viscosity.

192

GRAVEL SELECTION

Choosing the proper gravel is of utmost importance in obtaining an effective gravel pack. Both gravel size and quality should be considered in designing a gravel pack.

Gravel sizing

In order to determine the optimum gravel size, it is essential to conduct sand sieve analysis on representative formation samples. Sieve analysis from conventional cores is preferable; however, sidewall core samples can also be used. If no cores are available, then sand samples from perforation washing, bailing, or produced sands can be used.

Early work in sand control relied upon sand bridging to occur in order for sand to be excluded. Coberly (1937) concluded that “spherical grains form stable bridges on openings larger than the diameter of the grain, the ratio being two for rectangular openings and three for circular openings.” Coberly also concluded that in sands of varying grain size, the larger sand grains have the greatest influence on sand bridging and should, therefore, be used for sizing determinations. Although Coberly’s work applied specifically to sizing screens for sand control, the concept of sand bridging has also been used in determining the size of gravel.

Under conditions that typically exist downhole, it is very unlikely for stable sand bridges to form. Two-phase flow, varying production rates, pressure washing, cyclic steam stimulation, gas expansion, and pressure transients induced by artificial lift systems can all prevent stable sand bridges from forming. Currently, the most common gravel-pack design criteria is based upon absolute stoppage of sand at the sand-gravel interface. According to Saucier (1974, p. 211), sizing a gravel based upon absolute stoppage, with a gravel/sand size ratio of between 5 and 6, will provide the greatest sand control without a reduction in gravel-pack permeability (see Fig. 6-1).

In order to properly size a gravel pack with absolute stoppage of sand, it is important to distinguish between formation sand or matrix and fines that flow with the formation fluid. Fines should not be prevented from migrating into the wellbore. Otherwise the fines would continually plug the formation near the wellbore as the fluid flows into the well. A reduction in permeability near the wellbore (skin damage) would then occur and the well’s productivity would be greatly reduced.

Common practice is to design a gravel pack such that 90% by weight of all solids will be retained at the sand-gravel interface. To design a gravel pack based upon this criterion, it is necessary that the pore throats within the gravel pack be smaller than the 90-percentile sand-grain size.

The median pore throat size of a gravel pack is dependent not only upon the gravel size, but alsO upon the paclung arrangement and the grain shape. This concept is illustrated in Figs. 6-2 through Fig. 6-4, which show that packs consisting of uniform spherical grains have more consistent pore throat sizes than do packs of

1 .o

0 0.8- n .- - ._

m P)

: a Y 2 0.6-

!% E

.c 0.4-

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m m - .- .- c

0

(u > 0

c

.- +-

: 'i5 0.2-

a" .- 0 c

0

3

m I I I I /H---'

I I I /'

I / /' I

I /

than required to within gravel pack, I / I / I/ 1

/ I / I

/ I ' I

Gravel smaller Sand bridges 1 / Unrestricted

retain formation sand, less than maximum productivity realized

sand movement through gravel pack

reducing productivity

---/

I I I I I

I I I I I I I ; I : I

I I I I I I I I I I I I I I I 1 I I 0 2 4 6 8 10 12 14 16 18

Fig. 6-1. Effect of the ratio of median gravel size to the median sand size on gravel-pack permeability. (After Graham et al., 1959, and Saucier, 1974, modified by Patton and Abbot, 1982, p. 87, and Allen and Roberts, 1982, p. 39.)

194

CUBIC PACKING ORTHORHOMEIC PACK IN G

TETRAGONAL PACKING RHOMOEOHEDRAL PACK I NG

Fig. 6-2. The four close packings of equal prolate spheroids when the major axes lie in the planes of the layers. (After Allen, 1969, as illustrated in Chilingarian and Wolf, 1976, p. 149; courtesy of Geological Magazine.)

non-spherical grains. In a pack of uniform spherical grains, the pore throat size varies inversely with the degree of compaction. A cubic packing is the loosest packing arrangement of uniform spheres with a porosity of approximately 48% and a pore throat diameter of 0.4142 times the gravel-grain diameter. In comparison, a rhombohedral pack (hexagonal) has a porosity of 26% and a pore throat size of 0.1547 times the gravel-grain diameter (Coberly, 1937). The pore size, therefore, is reduced 2.68 times by aclueving rhombohedral packing.

In actual borehole conditions, the packing arrangement is a random combination of numerous packing geometries. According to Allen (in: Chilingarian and Wolf, 1976, p. 149), a haphazard packing of uniform spheres has a concentration of grains, C [C is defined as (space occupied by solids)/(total space)], ranging from 0.60 to 0.64. This corresponds to a porosity range between 36 and 40%.

Obtaining a tight gravel pack (i.e., low-porosity) is desirable. Such packs are less likely to have large void spaces and are not as prone to compact after the well is put on production. Should compaction occur after placement, then a void would be

@@B@ PLAN

ELEVATION PLAN ELEVATION PLAN

ELEVATION PLAN

Fig. 6-3. The five open packings of equal prolate spheroids. (After Allen, 1969, as illustrated in Chilingarian and Wolf, 1976, p. 150; courtesy of Geological Magazine.)

195

A

I

I

M

r - - - - - - - i

J

N

G

K

0

D

r - - - - - - - i

H

L

P

Fig. 6-4. Diagrammatical representation of particle arrangement and packing density in clean gravels (A-N) and in those with a matrix (0-P). Loose packing is illustrated in C, E, F, G , and I. (After Hails, 1976, in: Chilingarian and Wolf, 1976, p. 448; courtesy of Elsevier Science Publishers.)

created at the top of the pack after gravel settles. In addition, a tight pack can utilize a larger gravel in order to achieve the same degree of sand control as a loose pack. Various placement techniques are available that are designed to obtain a tight pack, one being vibration of the pack. These techniques are discussed later in this chapter.

Due to the varying grain size distributions of gravels and formation sands, and the random packing arrangements of gravel, it is necessary to rely on some empirical means by which to determine the optimum gravel size. Two of the more popular methods that are in use today are those proposed by Schwartz (1969) and Saucier (1974). Both of these methods use sand sieve analysis data in sizing the gravel, the same as used earlier by Hill (1941).

In referring to sieve analysis data, the ten-percentile point sand size ( D l 0 ) is defined as that point on the sand size distribution curve which corresponds to the size mesh opening through which 90% by weight of the sand can pass through (see Fig. 6-5). The size of 10% by weight of the sand is equal to or is larger than the

196

SIZE, in

Fig. 6-5. Examples of sand sieve analysis.

ten-percentile sand size. In a similar manner, the forty-, fifty-, and ninety-percentile sizes can be determined.

According to Hill (1941), one of the earliest works on gravel/sand size ratios had success with a 5 to a maximum of 8 (ratio of the ten-percentile sand size to the ten-percentile gravel size). In over 4000 wells in Venezuela there was a good sand control using an average of 6 times the ten-percentile sand size (Landreth, 1969).

According to Schwartz (1969), the gravel/sand size ratio is dependent upon the uniformity coefficient of the sand and the expected flowrate of the well. Schwartz defined the uniformity coefficient (c) as the ratio of the forty-percentile sand size (Om) to the ninety-percentile sand size (D90):

= (O40 )/( O 9 0 ) (6-1)

If the uniformity coefficient is less than 5 (uniform sand) and the flow velocity is less than 0.05 ft/sec, then the following gravel/sand size ratio should be used:

D,, gravel/D,, sand = 6 (6-2)

If the uniformity coefficient is greater than 5 (non-uniform sand) and/or the flow velocity is greater than 0.05 ft/sec, then the following gravel/sand size ratio should be used:

Dm gravel/D4, sand = 6 (6-3)

In calculating the flow velocity, it should be assumed that only half of the perforations are open to flow.

According to Saucier (1975), a gravel/sand size ratio of between 5 and 6 should be used with the ratio being based upon the respective fifty-percentile ( D50) values, regardless of uniformity of sand grain size or flowrate.

197

Any method used should also take into consideration previous experience in a particular area and formation. Many factors such as tightness of pack, pack thickness, flow rate, accuracy of core data, shape of gravel, and proper gravel screening will all have an effect on the degree to which sand production is controlled.

Gravel quality

Maintaining good quality control of the gravel that is used for gravel packing is an important aspect in obtaining an optimum completion. Proper gravel screening, grain shape, gravel solubility, and gravel strength should all be considered when choosing a gravel. The A.P.I. has established standard specifications for gravel size and shape.

Screening As pointed out by Boulet (1979, p. 165), gravels are generally poorly sized at the

time that they arrive at the well location. In 51 gravel samples that were tested in Boulet’s study, an average of 11.5 weight percent was undersized, with 10 samples having greater than 20 weight percent of the gravel being undersized. The reason for gravel undersizing is (1) the initial weakness of gravel and its breaking during transport (weakness could be a result of natural fractures in grains or conglomerate

80 I I 0 10 20 30 40 50 60 70 00 90 100

PERCENT OUT OF GAUGE MATERIAL

Fig. 6-6. Permeability variations with out-of-gauge gravels. (After Boulet, 1979, p. 167; courtesy of the Society of Petroleum Engineers.)

198

I000

500

m

250- J m 4 w I IY W

-

a 100-

50

grains), and (2) lack of quality control by the gravel suppliers. Tests indicate that out-of-gauge gravel causes a reduction in gravel-pack permeability (see Fig. 6-6).

To minimize the occurrence of out-of-gauge gravel, the following preventative steps should be taken: (1) Strict quality control by the gravel suppliers, and (2) rescreening the gravel at the wellsite.

I

-

-

SUB-ROUNDEC A ANGULAR -

0 40/60

Gravel shape The shape of the gravel grains also has an effect upon the productivity of a

gravel-packed well as well as the ability of gravel to control the production of sand. Suman (1975, p. 31) noted a minor effect of gravel angularity on permeability (reduction) (see Fig. 6-7). It was speculated, however, that the higher permeability in the case of spherical grains may have been due to the smoothness of the glass bead surfaces that were used in these experiments.

According to Gulati and Maly (1975), angular gravel is not as prone to sand invasion, because bridges are more likely to form; however, spherical gravel forms a more consistent pack. Inasmuch as current gravel-packing theory is based upon absolute stoppage of sand, sand bridges are not generally required. A consistent gravel pack is, on the other hand, desirable and consequently spherical gravel is preferable. In addition, an angular gravel has a much greater tendency to become wedged into perforation slots and cause plugging. Krumbein and Sloss (1951) have

35L L I

0010 0020 00400060 010

MEDIAN GRAIN DIAMETER, in

Fig. 6-7. Permeability of gravel packs as a function of grain size and angularity. Angularity has a minor effect. Higher permeabilities of UCAR Pac (glass beads) is likely due to smoothness of particle surfaces. (After Suman, 1975, p. 30; courtesy of Gulf Publishing Co.)

199

0.9

0.7

0.5

.- 2 0.3 0

a, r Cl [/)

._ L

0.1 0.3 0.5 0.7 0.9

Roundness

Fig. 6-8. Visual chart for estimating roundness and sphericity of sand grains. (After Krumbein and Sloss, 1951, p. 81; also in Krumbein and Sloss, 1963, figs. 4-10, p. 111; courtesy of W.H. Freeman and Co.)

developed a chart to classify grains on the basis of sphericity and roundness (see Fig. 6-8).

Gravel solubility It is extremely important that the material used in gravel packing is stable under

the conditions to which it is exposed downhole. Wellbore conditions can be extremely harsh and an initially effective gravel pack may be ruined due to gravel dissolution.

As determined by Cheung (1985), most materials that are commonly used for gravel paclung are not significantly soluble in HC1 acid. The solubility of these materials ranged from less than 1% for Ottawa and Heart of Texas sands to 1.8% for sintered bauxite. All of the tested materials, however, did exhlbit higher solubility in HC1-HF acid. The gravel solubility of these materials increased with hgher HF concentrations and longer exposure times (see Figs. 6-9 and 6-10). Twenty-four-hour dissolution rates in 7.5% HC1-1.5% HF ranged from 4% for Ottawa sand to 20% for sintered bauxite and 96% for low-density bauxite. Due to their high solubilities in HCI-HF acid, bauxitic materials should not be used in wells that are expected to be treated with this acid.

200

2o r

Acid Contact Time (Hour)

Fig. 6-9. Gravel solubility in 7.5% HCl-1.5% H F acid at 150 O F . (After Cheung, 1985, p. 870; courtesy of the Society of Petroleum Engineers.)

As pointed out by Reed (1980), Underdown and Kamalendu Das (1983), and Watkins et al. (1985), siliceous gravel has been found to be soluble in steam. According to Reed (1980), gravel solubility increases with increasing temperature and pH. As can be seen from Table 6-1, at pH levels above 11 rapid increases in gravel solubility occur. Reed noted that generator effluent has typically high pH due to the presence of bicarbonate ions in the generator feedwater. The bicarbonate ions decompose into CO, (vapor) and OH- anions (liquid) and, therefore, raise the pH of effluent.

TABLE 6-1

Quartz dissolution at various temperatures and pH during flow of water; pH was adjusted with NaOH (After Reed, 1980, p. 943; courtesy of the Society of Petroleum Engineers)

Temperature Si concentration in effluent a (mg Si/l)

( “ C ) (OF) PH 7 PH 9 pH 10 pH 11 pH 12

23 73 < 1.0 < 1.0 < 1.0 < 1.0 < 1.0 93 200 < 1.0 < 1.0 < 1.0 4.3 19.7

177 350 6.0 3.4 4.9 42.7 1120 260 5 00 53 69 65 189 1920

a Flowed at 3 ml/min through 2.5-cm diameter by 7.6-cm long pack of 10-20 mesh “Heart of Texas” quartz sand.

201

100-

ao -

p 60- 2 > - ._ 0 Y C

Y 2 40-

0 4 8 12 16 20 24 Acid Contact Time (Hour)

Fig. 6-10. Gravel solubility in 12% HC1-3% HF acid at 15O0F. (After Cheung, 1985, p. 870; courtesy of the Society of Petroleum Engineers.)

Underdown and Kamalendu Das (1983) have compared the steam solubility of siliceous gravel with that of sintered bauxite and resin-coated sand. When exposed to 500 O F water for 72-192 hrs, siliceous gravel samples had significant weight loss (> 30%) at all pH values tested (see Table 6-11). In comparison, sintered bauxite was stable, with less than 4% weight loss, when exposed to 560-600 O F water with a pH of 11 for 72 hrs (see Table 6-111). Resin-coated sand was found to be stable at pH levels of 9 and below; however, at a pH of 11 significant weight loss (> 25%) occurred (see Table 6-IV).

Some operators have been using sintered bauxite to gravel pack thermal wells. This man-made material, which has good thermal stability, typically has a minimum of 0.8 sphericity and roundness and does not generate fines during pumping or transporting (Carborundum, 1983). Sintered bauxite is, however, quite expensive and rather soluble in HC1-HF acid. Another disadvantage lies in the fact that if high pH steam is injected into a well that is completed with a sintered bauxite gravel pack, it is likely that the siliceous formation sand will be dissolved by the steam and the sintered bauxite will be pushed into the voids that are created by dissolution.

202

TABLE 6-11

Weight loss of siliceous material (After Underdown and Kamalendu Das, 1983, p. 202)

Sample Temperature Time PH Weight loss (OF) (W (8, wt/wt)

Ottawa sand 540-580 192 7 31.9 16/20 U.S. mesh 500-540 72 9 38.5

500-540 72 11 46.1

Venezuelan sand 12/18 U.S. mesh 530-570 72 11 56.0

TABLE 6-111

Weight loss of bauxitic material (After Underdown and Kamalendu Das, 1983, p. 202)

Sample Temperature Time PH Weight loss ( O F ) (hr) (%. wt/wt)

Sin tered bauxite 560-600 72 7 0.7 20/40 US. mesh 560-600 72 9 1.3

560-600 72 11 3.5

High alumina beads 560-600 72 7 2.3 20/40 US. mesh 560-600 72 9 2.4

560-600 12 11 3.7

In an effort to reduce gravel dissolution by steam, Watkins et al. (1985) suggested adding ammonium salt to the generator feedwater. The ammonium ions decompose during steam generation and give off hydrogen ions. The hydrogen ions reduce the alkalinity of the effluent. The addition of ammonium salts to generator feedwater reduced the effluent pH from 11 to values between 9 and 10. The silica dissolution was found to be reduced by 94%.

TABLE 6-IV

Weight loss of resin-coated sand (After Underdown and Kamalendu Das, 1983, p. 202)

Temperature Time PH Weight loss a (OF) (hr) (W, wt/wt)

480-500 72 7 0.5 470-500 12 9 1.6 470-500 72 11 25.8 520-570 72 11 24.3

a 20/40 U.S. mesh

203

Gravel strength During the gravel packing operation, the gravel can be subjected to many

crushing forces as it passes through the pumps and crossover tool ports and impinges against the casing. The hardest non-fractured gravel available, therefore, should be used. It is extremely important to take all preventive steps to insure that the gravel does not breakup under these conditions, because the grain size and shape will be altered and fines will be generated.

GRAVEL-PACKING FLUIDS

Choice of the proper gravel-packing fluid is an extremely important aspect in the design of a gravel pack. As with any completion fluid, it is essential that the fluid be clean and compatible with the formation rocks, minerals and fluids. All completion-fluid system equipment should be thoroughly cleaned prior to gravel packing. Additionally, the completion fluid should be filtered to remove all solids that are larger than 2 pm. If it is necessary to add solids to increase viscosity and fluid density, or to control fluid loss, then these solids must be capable of being easily removed by either dissolving in the formation fluids or by being acidized. In addition, if viscosifiers are added, a breaker should be added that will return the viscosity to that of water within 24 hrs. Fluids not requiring breakers or solids are the most desirable gravel packing fluids.

Borden et al. (1982) have classified water-base carrier fluids into four major categories.

Low-viscosity carrier fluids

Included in low-viscosity carrier fluids are water, brine, oil, diesel, and gas oil. Small amounts of HEC or other polymers can be added to aqueous-base fluids to increase fluid viscosity up to 100 cP. Low-viscosity fluids can carry up to five pounds of gravel per gallon of fluid, depending on the type of surface pumping equipment used. With standard surface blending equipment, the average is one pound of gravel per gallon of fluid, because the gravel must go through the pump. The lower the viscosity of the fluid, the better the compaction of the gravel. At high viscosity, the grains will be separated temporarily. Eventually, the grains will settle to expose the upper portion of the liner and so defeat the purpose of the pack. The compaction percentage is directly proportional to the free-falling velocity of the gravel in the carrier fluid. The average free falling velocity of US. 12-16 gravel in water is 32.4 ft/min, whereas with U.S. 6-8 gravel the average is 46.6 ft/min (Wright and Solum, 1967).

High-viscosity carrier fluids

The high-viscosity carrier fluids are composed of water solutions with added polymer or cross-linked polymer. These fluids are capable of carrying up to 15 lb of

204

gravel per gal of fluid and, therefore, require much less fluid. The high viscosity reduces fluid loss, and fines do not have a tendency to migrate towards the perforations and cause plugging (Borden et al., 1982). These fluids do, however, exhibit a significant amount of gravel settling or poor compaction after placement, which can cause voids in the pack and a loss of sand control (Elson et al., 1984).

Medium- or intermediate-viscosity carrier fluids

Medium- or intermediate-viscosity carrier fluids typically have viscosities ranging from 300-400 cP. In the case of these fluids, perforation plugging by fines usually does not present problems (Borden et al., 1982). Tests indicate that medium-viscosity fluids should be used in all high-angle gravel-packing operations (Elson et al., 1984).

Foam or low-density carrier fluids

Elson and Anderson (1982) have investigated the use of foam as a carrier fluid for gravel-packing operations. Foam has a low density, high apparent viscosity, high lifting capacity, and a relatively low cost. These characteristics make foam a desirable carrier fluid, especially in low-pressured zones that are prone to lose circulation and in water-sensitive formations. Lost circulation is much less likely to occur with foam due to the reduced hydrostatic pressure. Formation damage in water-sensitive formations is greatly reduced, because the zone is exposed to much lower volume of water. When foam is used as a carrier fluid, liner centralizers should be used sparingly because they can induce packing irregularities.

SCREEN OR LINER SELECTION

A screen or slotted liner is placed inside the wellbore to retain the gravel between them and the formation (or casing) and to allow the flow of fluids into the wellbore. The width of the slots must be narrow enough to prevent the gravel from passing through them. Coberly (1937) recommended that the slot width be twice the largest grain diameter and, therefore, he relied upon the occurrence of bridging. Inasmuch as sand bridges are not usually stable under typical downhole conditions, this sizing method is not advisable. Absolute stoppage of gravel is necessary and the slots should be sized smaller than the smallest gravel size. On an average, the difference in size should be 0.015 in. to retain all the gravel in place. The overall average open area should be approximately 2% of the surface area of the liner. This figure may vary according to the production expected (Wright and Solum, 1967).

A gravel pack liner is simply a casing with slots that have been cut into it. The slots are cut vertical to prevent any significant reduction in pipe strength. Slotted liners are usually much less expensive than wire-wrapped screens and less prone to damage when running into the wellbore. There is, however, a limitation as to how

205

small the liner perforations can be made, because they have to be cut into the pipe. Usually, the smallest size of the liner slots ranges from 0.12 to 0.015 in.

Wire-wrapped screens cost approximately three times as much as the slotted liners, but they do offer some advantages over liners. These screens are typically made of stainless steel and are corrosion and erosion resistant. Depending upon the pipe size, a wire-wrapped screen can have up to fifteen times more area open to flow than a slotted liner. Screens can be manufactured with much smaller slot widths than liners (as small as 0.002 in.) and, in some instances, can control sand production without a gravel pack behind them if the formation is able to form a bridge. This sand control technique is used in recompletions when it is difficult or impossible to gravel pack.

METHODS OF GRAVEL-PACKING

Openhole gravel pucks

In an openhole gravel pack, casing is set above the productive interval. The hole is then underreamed across the productive zone and a liner or screen is set in this interval. Gravel is then placed between the open hole and the liner or screen (see Fig. 6-11). If properly designed, this completion method provides a high degree of sand control and maximum productivity because restrictive perforations are not used. Proper placement of gravel is of utmost importance.

The underreaming involves the use of a hole opener or underreamer. This device has cutter arms that can be hydraulically extended from the body of the tool once

Fig. 6-11. Schematic diagram of a gravel pack in underreamed open hole.

206

the tool is below the casing shoe. The wellbore diameter can be increased up to approximately two-fold by underreaming. By increasing the hole diameter, a thicker gravel pack is obtained which will result in better sand control and greater productivity. It is recommended that the gravel pack thickness in openhole gravel- packed completions be at least 2 in. (Borden et al., 1982). The average thickness used is 3 in. and the liner should be positioned by centering devices installed through its full length to make sure that it is concentrically located in the hole (Wright and Solum, 1967).

Cased-hole gravel packing

According to Saucier (1974), it is extremely important that the perforation tunnels be filled with gravel and not formation sand. Perforations act to restrict the flow of fluids into the wellbore. Any additional restrictions that are incurred by having perforation tunnels filled with formation sand can cause large pressure drops through the perforations with a resulting decrease in productivity. To insure that all perforations and perforation tunnels are open, it is advisable to wash the perforations with a circulation washer tool prior to gravel packing (see Figs. 6-12.A,B).

Cased-hole gravel packs can be placed in either a “single-stage’’ or a “ two-stage’’ operation (Suman, 1975). Either method is aimed at a tight pack in the liner-casing annulus and in the perforation tunnels. In all cased-hole gravel packs, it is recommended that the gravel annulus be 3/4 in. thick (Borden et al., 1982).

“Single stage” method In “single-stage’’ cased-hole gravel packing, gravel is pumped into the liner-cas-

ing annulus either through a crossover tool or down the casing-workstring annulus. Periodically, the flow of returns should be restricted, thereby forcing flow out of the perforations. Inasmuch as flow out of the perforations is required, it is necessary that the carrier fluid be able to leak-off into the formation. This can cause formation damage. If liner vibration is used during the gravel packing, leak-off into the formation can be eliminated or minimized (Solum, 1984).

“Two -stage ’’ method “TWO-stage’’ gravel packing involves packing the perforation tunnels and the

liner-casing annulus in separate operations. The perforation tunnels can either be packed using a squeeze packer or by using an open-ended tubing squeeze method. An open-ended tubing squeeze involves running open-ended tubing into the wellbore opposite the perforations. Gravel is then pumped down the tubing and pressure is held against the tubing-casing annulus. Reciprocation of the tubing string may aid in forcing gravel into the perforations (Borden et al., 1982). Vibration can also be used (Solum, 1984).

After the perforations have been packed, the liner or screen is run into the wellbore. The annulus can then be gravel packed by either reverse circulating gravel slurry down the annulus with returns coming up the tubing, or the gravel slurry can be pumped down the tubing and through a crossover tool with returns coming up the annulus. The most frequently used method is “ single-stage”.

201

Fig. 6-12. A. Circulation washer tool. (Courtesy of Solum Oil Tool Corporation.)

208

FIRST PASS Downward jetting action picks u p sand and re - turns it through annulus. Cleans up inside casing.

SECOND PASS One full turn to left at tool closes downward jet and washing takes place th rough side jets, as shown.

WITHDRAWAL When washing i s complete, one fu l l t u rn to r i g h t a t t o o l reopens downward jet. Tool i s then pulled dry.

Fig. 6-12. B. Operation of circulation washer. (Courtesy of Solum Oil Tool Corporation.)

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DEVIATED WELLS

Gravel packing highly-deviated wells requires additional design considerations to increase the chances of obtaining a successful completion (Maly et al., 1974; Gruesbeck et al., 1979; Shryock, 1980; and Elson et al., 1984). According to Maly et al. (1974), packing efficiency decreases drastically in wells that are deviated beyond 60' (see Fig. 6-13). Laboratory tests indicate that the problem in deviated well is due to the formation of gravel dunes as it is being packed. As the dune forms, the carrier fluid flows preferentially into the tailpipe-liner annulus and deposit additional gravel on the dune. As this process continues, a sand-off will eventually occur (Elson et al., 1984). In an effort to eliminate the gravel dunes, Solum (1984) used liner vibration which prevented their formation and in all tests there were no sand-offs or bridging.

Several investigators have concluded that restricting the flow of fluids into the tailpipe-liner annulus will improve gravel placement in highly-deviated wells (Maly et al., 1974; Gruesbeck et al., 1979; Shryock, 1980; and Elson et al., 1984). Maly et al. (1974) suggested that this flow could be restricted by either placing a tight bladder seal inside the screen or by placing deformable baffles along the tailpipe. In long liners, this proved impractical due to the high packing pressures. Shryock (1980) recommended restricting flow into the tailpipe-liner annulus by having a tailpipe OD/liner ID ratio of 0.8 or greater.

GRAVEL-PACKING TOOLS AND EQUIPMENT

Blender

The blender is used to combine gravel and carrier fluid in a specified ratio and pump the slurry downhole. The gravel is fed into the blender tank by a screw or

\CONVENTIONAL \\TOOLS --

’0 A 30 60 90 120

HOLE ANGLE, DEGREES FROM VERTICAL

Fig. 6-13. Effect of hole angle on gravel packing efficiency with and without unipack for a one-pass pack in a l/lO-scale laboratory model. Conditions: equivalent flow rate-130-150 gal/min; fluid-tap water; gravel concentration-2-4 lb/gal. (After Maly et al., 1974, p. 22; courtesy of the Society of Petroleum Engineers.)

210

FLUlDlGRAVEL ClSE CONTROL VELlFLUlD MIX

CENTRIFUGAL

VEL PASSES

CENTRIFUGAL PUMP AND

VALVES FROM MUD TANKS TRIPLEX PUMP

Fig. 6-14. Conventional gravel blending unit. Gravel breakup occurs when fluid and gravel are mixed in the tank and pass through centrifugal pump and triplex pump valves before injection into the well. (Courtesy of Solum Oil Tool Corporation.)

bucket conveyor. The carrier fluid is also pumped at a controlled rate into the blender tank (see Fig. 6-14). This unit mixes the fluid and gravel in the tank by use of a centrifugal pump. The gravel/fluid ratios are controlled by the conveyor rate of

Fig. 6-15. Cylinder-type gravel-packing method. There is no control of (1) fluid/gravel ratio and (2) fluid velocity. (Courtesy of Solum Oil Tool Corporation.)

211

gravel input; however, gravel crushing occurs as the slurry passes through the centrifugal and triplex pumps.

Gravel pots

Gravel pots can also be used to mix carrier fluid and gravel and inject the slurry into the wellbore. This system utilizes two pressure vessels that can be filled with gravel from a hopper through a sealable top port. Once the gravel is placed in the vessel, the top port is sealed and fluid pressure is applied to the vessel. Gravel is then gravity drained into the fluid stream by opening a valve at the bottom of the vessel as the pressure is maintained in the vessel. As one pot is draining gravel, the second one is filled with gravel. As the slurry does not pass through any pumps, gravel crushing is minimized. It should be noted, however, that the system has the disadvantage of not being able to control gravel/fluid ratios (see Fig. 6-15).

Positive-injection gravel blending unit

Positive-injection gravel blender was developed by Solum Oil Tool Corporation in order to have accurate gravel/fluid ratio control and not crush the gravel. This is accomplished by adding the gravel at a controlled rate on the downstream side of the centrifugal and triplex pumps (see Fig. 6-16). The unit is reported to induce no gravel crushing, whereas conventional blenders crush an average of 17.5% of the gravel (Solum, 1983; see Fig. 6-17).

Surface equipment

The normal gravel-injection equipment flow pattern at the wellsite is shown in Fig. 6-18. One important function of the surface equipment is to filter all the fluid just before it is mixed with the gravel. The filtering system should be located between the fluid storage tank and the blending unit; this insures filtration of solids down to 2 pm in size. Often, the storage tanks are contaminated, thereby contaminating the pre-filtered fluid.

The instrumentation and schematic of the fluid-gravel flow pattern with after- the-pump injection is shown in Fig. 6-19. The basic gauges to control the surface operation of the gravel are (1) meter (bbl/min), (2) ratiometer (reading in lb/gal), and (3) a discharge pressure gauge (reading in psi). These instruments, receiving their data from the various components, as shown in Fig. 6-19, enable the blending operator to have complete control of the gravel-packing operation.

Crossover tool

A crossover tool is a device that is attached between the bottom of the working string (drillpipe or tubing) and the top of the liner or screen during the gravel-packing operation. The device allows for the slurry to be pumped down the working

21 2

GRAVELIFLUID RATIOMETER

ID

FROM MUD TANKS TO SHAKER SCREEN ,NJECTION

CHAMBER

Fig. 6-16. Schematic diagram of a positive-injection gravel blending unit. Accurate ratiometer controls fluid/gravel ratio. Gravel is not broken by passing through mixing tank, centrifugal pump, and triplex pump valves. (Courtesy of Solum Oil Tool Corporation.)

Fig. 6-17. Photograph of positive-injection gravel-blending unit. (Courtesy of Solum Oil Tool Corpora- tion.)

213

INJECT10 N CHAMBER

-WELLHEAD

Fig. 6-18. Wellsite fluid and gravel flow pattern. Gravel is injected after the pump. (Courtesy of Solum Oil Tool Corporation.)

string and then out the crossover ports into the openhole-liner or casing-liner annulus. Fluid returns then pass through the slots in the liner back into the wellbore. The fluid returns travel up the washpipe and then back through the

FLUID TANK

8 B L I M I N METER

GRAVEL INJECTION MOTOR OR RAM

DISCHARGE PRESSURE

GAUGE (PSI1

GRAVELlFLUlD DISCHARGE

TO WELL

Fig. 6-19. Basic instrumentation schematic for fluid and gravel control by blender operator. Gravel/fluid ratios can be controlled very accurately. (Courtesy of Solum Oil Tool Corporation.)

214

Fig. 6-20. Crossover tool. (Courtesy of Solurn Oil Tool Corporation.)

crossover, which directs the returns into the casing-working string annulus (see Fig.

Shryock (1979) has identified the crossover port as an area where gravel crushing occurs. The gravel shattering was determined to be due to high velocity impingement against the casing as the slurry exits the crossover ports. If the crossover ports are located opposite open hole, then erosion and mixing of formation material and gravel is likely to occur. By increasing the size or number of crossover ports, the stream velocity of the slurry as it exits the ports is reduced. This reduction in velocity minimizes gravel shattering and wellbore erosion.

The writers have also noticed stress cracking from gravel impingement on the steel surface at the base of the crossover port. According to Solum (1983), a minimum of 8% gravel crushing occurs as gravel strikes this steel surface at normal pumping rates. Solum Oil Tool Corporation has developed a crossover tool that has a 3-in. resilient rubber cushion at the base of the crossover. It is reported that this tool reduces gravel breakup to less than 1%.

6-20).

215

Port collar

When run in the liner string, a port collar provides access to the annulus between the liner and the open hole or casing. The port normally remains in the closed position; however, it can be opened by rotating the inner sleeve with port collar operating springs or dogs. T h s port allows for additional gravel to be placed in the pack if insufficient amount of gravel was placed during the initial packing operation. Some operators attempt to repack the well after its first steam stimulation.

Port collars are also used when completing a well with two zones that are to be gravel packed separately with a section of cemented casing between the two zones (see Fig. 6-21).

Fig. 6-21. Port collar. (Courtesy of Solum Oil Tool Corporation.)

216

Unipack tool

The unipack is a gravel-packing tool that has been developed by researchers at Union Oil Company (Maly and Robinson, 1972) for use in deviated wells. This tool has a series of baffles that are attached to the washpipe. These baffles act to restrict flow in the wash pipe-liner annulus and keep flow in the outer liner-open hole annulus. This prevents dunes from growing to the point of occurrence of premature screenout. Test results indicate that this tool tends to improve the gravel-packed completions in deviated wells if the liners are not too long.

Liner vibrator

The Solum Rotary Compactor is a tool that vibrates the liner during gravel- packing operations. To operate the tool, the workmg string is rotated by the rotary table of the drilling rig. This rotational energy is converted into a vibration at 60-ft spacings along the liner. Laboratory and field tests indicate that vibration can result in a 15-25% denser or tighter pack (Solum, 1984). The tighter pack provides a better sand control and considerably reduces the problem of after-pack settling.

Some operators reverse the flow of the carrier fluid in the case of occurrence of a premature pack-off. This procedure is conducted in an attempt to breakdown any bridges. This practice has been found to mix formation sand with the gravel and fluff the pack into a looser arrangement (Shryock, 1979; Shryock et al., 1979; and Solum, 1984). Vibration of the liner prevents bridges from occurring and eliminates the need to reverse circulate.

EVALUATION OF GRAVEL PACK

Several methods are currently available to evaluate the placement of a gravel pack. The most widely used method involves comparing the actual volume of gravel placed with the theoretical volume. In calculating the theoretical volume, it is advisable to use a caliper log to account for changes in the wellbore radius. This procedure can be deceptive, however, as sometimes washouts occur after the caliper log has been run or a washout can extend beyond the reach of the caliper arm.

Neal (1983) suggested using a compensated neutron log, nuclear fluid density log, or a dual-spaced gamma-ray log to evaluate gravel placement. All of these logging techniques involve running the log in the subject well after the gravel-pack hardware has been placed in the wellbore, but before the gravel is pumped. A subsequent log is run after the well has been gravel packed and the two logs are then compared. The comparison should indicate where gravel was actually placed. There are also

’ Trademark registered.

217

gravel-pack density logs available that are run after the gravel is placed. They indicate gravel voids and the top of the gravel.

ADDITIONAL DESIGN CONSIDERATIONS

Borden et al. (1982, p. 100) has noted some additional considerations in designing an optimum gravel-packed completion. These considerations include the following:

(1) Blank pipe is eliminated between sections of gravel. Otherwise, the gravel slurry would not be able to dehydrate properly and voids or after-pack settling may occur.

(2) Rathole volume is kept to a minimum, because leakoff will not occur in the rathole and voids may be created.

(3) The gravel pack thickness should be at least two inches for openhole completions and 3/4 in. for cased-hole completions.

(4) Gravel pack-formation sand mixing must be avoided. If possible, crossover ports must not be placed opposite open hole as they may cause erosion. If this can not be avoided, then port exit velocities must be maintained below 4 ft/sec.

(5) In wells that are deviated less than 60°, a reserve of gravel must be provided by running additional liner above the completed interval. As settling or dissolution occurs, the gravel in this reserve will fill any created voids.

SUMMARY OF THE BASIC FACTORS THAT DETERMINE AN EFFECTIVE GRAVEL PACK

The basic factors that determine an effective gravel pack can be summarized as

(1) Selection of proper gravel size. (2) Use of a packing fluid free of solids. (3) Proper relationship between the size of perforations and gravel size. (4) The cleanliness of the face of producing formation. (5) Gravel/fluid ratio. (6) Compaction of the gravel.

follows:

SAMPLE PROBLEMS AND QUESTIONS

(1) Using the following sand sieve analysis data, plot cumulative weight percentage versus the log of opening size. Determine the optimum gravel size using both the Saucier and the Schwartz methods:

218

Opening Sample weight (in.) (g) 0.065 0.046 0.0328 0.0232 0.0164 0.0116 0.0082 0.0058 0.0041 0.0029 0.0000

0.1 0.1 0.1 0.5 3.2 7.5 7.7 5 .O 1.9 1.3 2.2

(2) If a gravel with a median grain diameter of 0.025 in. is required to achieve adequate sand control in a well with a cubic packing, what median gravel diameter would give the same degree of sand control if packing is rhombohedral?

(3) Describe common gravel pack design criteria for sand control. (4) What is the age of formations which are usually associated with sand

production? ( 5 ) Distinguish between the pore size distribution resulting from the cubic

packing and the rhombohedral (hexagonal) packing. Which one is ideal for sand control?

(6) Formation sieve analysis showed the uniformity coefficient to be 3.48 and the flow velocity is 0.006 ft/sec. Using work by Schwartz (1969), determine the average size of gravel required for this formation. The 10-percentile sand size is 0.011 in. and the 40-percentile sand size is 0.003 in.

(7) If average gravel diameter is 0.55 in., what is the average pore throat diameter of the gravel pack in (1) cubic packing and (2) in rhombohedral packing (hexagonal)?

(8) What additive has been found to reduce silica dissolution by approximately 94%?

(9) Describe the most desirable type of gravel packing fluid. What is the minimum size of solids that should be filtered out?

(10) While steaming a well, the bottomhole temperature is 495 O F and the pH is 11. If resin-coated sand is used, what would be the approximate weight percent loss of sand using 20/40 U.S. mesh gravel?

(11) If the smallest gravel grain used in gravel packing of the well is 0.045 in. in size, what is the size of liner slots that should be used?

(12) In an openhole gravel pack, what should the average thickness of the pack be and how should the liner be positioned?

(13) What type of surface gravel packing equipment should one use in order to achieve (1) good control of the gravel/fluid ratios and (2) the minimum breakup of the placed gravel?

219

(14) With a single-stage gravel packing method, what technique is available to reduce formation damage due to the leak-off into the formation?

(15) What should viscosity (give range) of fluid be in order to achieve the best compaction of the gravel grains, and what is the compaction percentage proportional to?

(16) What type of carrier fluid should be used in a well having a lost-circulation problem?

(17) How can after-pack settling be prevented when gravel packing? (18) With liner vibrations spaced every 60 ft inside the slotted or wire-wrapped

(19) What basic gauges are used to control the surface handling of the gravel? (20) What type of system has been developed to reduce gravel breakup in the

gravel crossover tool? What percentage reduction in crushing can be achieved for gravel striking the steel?

(21) What is the best method to evaluate gravel placement after gravel packing?

liner, how much denser would the pack be?

REFERENCES

Allen, J.R.L., 1969. Notes towards a theory of concentration of solids in natural sands. Geol. Mag., 106:

Allen, T.O. and Roberts, A.P., 1982. Production Operations, Vol. 2. Oil and Gas Consultants Int., Tulsa,

Borden, T.F., Elson, T.D. and Millhone, R.S., 1982. State-of-the-Art Gravel Packing for 1982. Proc. Am.

Boulet, D.P., 1979. Gravel for sand control: A study of quality control. J. Per. Technol., 31(2): 164-168. Carborundum Company, 1983. Sintered Bauxite for Sand Control Applications. Carborundum, Dallas,

Cheung, S.K., 1985. Effect of Acids on Gravels and Proppants. Proc. SOC. Pet. Eng., 55th Annu. Calif. Reg.

Chilingarian, G.V. and Wolf, K.H., 1976. Compaction of Coarse-Grained Sediments, 11. Elsevier, Amster-

Coberly, C.J., 1937. Selection of screen openings for unconsolidated sands. API Drill. Prod. Pract. :

Elson, T.D. and Anderson, G.W., 1982. Foam Gravel Packing. Proc. SOC. Pet. Eng., 53rd Annu. Calif. Reg. Meet., Ventura, Calif., Mar. 23-25, SOC. Pet. Eng., 11013: 33-42.

Elson, T.D., Darlington, R.H. and Mantooth, M.A., 1984. High-angle gravel-pack completion studies. J. Pet. Technol. 36(1): 69-78.

Graham, J.W., Monaghan, P.H. and Osoba, J.S., 1959. Influence of propping sand wettability or productivity of hydraulically fractured oil wells. Trans. AIME, 216: 324.

Gruesbeck, C., Salathiel, W.M. and Echols, E.E., 1979. Design of gravel packs in deviated wellbores. J. Pet. Technol., 27(1): 109-115.

Gulati, M.S. and Maly, G.P., 1975. Thin-section and permeability studies call for smaller gravels in gravel packing. J. Pet. Technol., 27(1): 107.

Hails, J.R., 1976. Compaction and diagenesis of very coarse-grained sediments, pp. 445-473. In: G.V. Chilingarian and K.H. Wolf (Editors), Compaction of Coarse-Grained Sediments, ZZ (Developments in Sedimentology, 18B). Elsener, Amsterdam, pp. 445-473.

Hill, K.E., 1941. Factors affecting the use of gravel in oil wells. APZ Drill. Prod. Pract., pp. 134-143. Krumbein, W.C. and Sloss, L.L., 1951. Stratigraphy and Sedimentation. W.H. Freeman and Co., San

309-321.

Okla., pp. 35-62.

Pet. Inst., Pac. Joint Chapter Meet., Ventura, Calif., Oct. 12-14, pp. 95-116.

Tex., 2 pp.

Meet., Bakersfield, Calif., Mar. 27-29, SOC. Pet. Eng. Pap., 13842: 863-870.

dam, 808 pp.

189-201.

Francisco, Calif., 497 pp.

220

Krumbein, W.C. and Sloss, L.L., 1963. Stratigraphy and Sedimentation. Freeman, San Francisco, Calif.,

Landreth, T.C., 1969. Gravel packing for sand control. Can. Pet., Sept.: 8-13. Maly, G.P. and Robinson, J.P., 1972. Apparattu for Gravel Packing Inclined Wells. U.S. Patent No.

Maly, G.P., Robinson, J.P. and Laurie, A.M., 1974. New gravel pack tool for improving pack placement.

Neal, M.R., 1983. Gravel pack evaluation. J. Pet. Technol., 35(10): 1611-1616. Patton, D.L. and Abbott, W.A., 1982. Well Completions and Workouers: The Systems Approach. Energy

Reed, M.G., 1980. Gravel pack and formation sandstone dissolution during steam injection. J. Pet.

Saucier, R.J., 1974. Considerations in gravel pack design. J. Pet. Technol., 26(2): 205-212. Schwartz, D.H., 1969. Successful sand control design for high rate oil and water wells. J. Pet. Technol.,

Shryock, S.G., 1979. Tests show methods for improved gravel packing. World Oil, 1, Aug.: 55-58. Shryock, S.G., 1980. Gravel Packing Studies in a Fullscale Deviated Model Wellbore. In: 55th Annu. Meet.

SPE-AIME, Dallas, Tex., Sept. 21-24, SPE Reprint 9421. Shryock, S.G., Dunlap, R.G. and Millhone, R.S., 1979. Preliminary results from full-scale gravel-packing

studies. J. Pet. Technol., 31(6): 669-675. Solum, J.R., 1984. A New Technique in Sand Control Using Liner Vibration with Gravel Packing. In:

Formation Damage Control Symp., Bakersfield, Calif., Feb. 13-14, SPE Pap. 12479, pp. 79-90. Solum Oil Tool Corp., 1983. Completion Methodology for Peak Production. Signal Hill, Calif. Suman Jr., G.O., 1975. World Oil's Sand Control Handbook. Gulf, Houston, Tex., 57 pp. Underdown, D.R. and Das Kamalendu, 1983. Stability of Gravel Packing Materials for Thermal Wells.

In: Proc. Int. Symp. Oil Field Geothermal Chem., Denver, Colo., June 1-3, pp. 199-204. Watkins, D.R., Kalfayan, L.J., Watanabe, D.J. and Holm, J.A., 1985. Preventing Gravel Pack and

Formation Dissolution During Steam Injection. Proc. SPE 55th Annu. Calif. Reg. Meet., Bakersfield, Calif., Mar. 27-29, SPE Pap. 13660, pp. 665-674.

Wright, K.A. and Solum, J.R., 1967. Principles of Gravel Compaction for Oil and Water Well Sand Exclusions. In: Lone Star Water Well Drill. Assoc. Annu. Conv., Austin, Tex.

2nd ed.

3,637,010; Jan. 25.

J. Pet. Technol., 26(1): 19-24.

Publications, Dallas, Tex., pp. 84-91.

Technol., 32(6): 941-949.

21(9): 1193-1198.

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Chapter 7

STEAM ENHANCED OIL RECOVERY

J.P. FANARITIS and GEORGE V. CHILINGARIAN (EDITOR)

INTRODUCTION

Two third of al[ the petroleum discovered worldwide to date is still in the ground, and much of this in-place oil cannot be recovered by conventional primary production methods. It is particularly difficult to achieve high recovery efficiencies in heavy oil reservoirs, and even more so in tar sand deposits which are presently receiving increasing attention as potential major sources of liquid hydrocarbons. As a result of the relatively low primary production recovery efficiency in many large heavy oil reservoirs, enhanced oil recovery techniques which have the potential of significantly improving oil yields from proven reservoirs are assuming increasing importance.

Of the various enhanced oil recovery techniques currently being employed in heavy oil reservoirs and tar sand deposits, steam injection is the most widely used, the most efficient process available today. The steam injection process presently accounts for the production of well over 500,000 bbl/D of heavy oil worldwide, and this production rate can be anticipated to increase markedly in the future with expanded utilization of the process in the United States, Canada, Venezuela, Indonesia, the Soviet Union, and the People’s Republic of China. Steam injection presently accounts for the production of approximately 300,000 bbl/D in the United States, 15,000 bbl/D in Western Canada, and 250,000 bbl/D in Venezuela. There is also developing interest in applying the steam injection technique to light oil reservoirs to improve oil recovery efficiency, particularly reservoirs containing highly parafhic crude oils.

It is the objective of this section to provide some general data related to the steam injection process, more specific information on the two types of steam injection techniques which are in current use, and a brief coverage of some ancillary factors related to the steam injection process. The reader should consider this section as an introduction to the steam injection process, and utilize the references for more detailed information on specific aspects of steam injection technology.

GENERAL DATA PERTAINING TO STEAM INJECTION

General data pertaining to the steam injection process is presented here in order to provide the reader with an overview of the potential applications of the technology, and a working knowledge of the mechanics of steam injection.

222

Enhanced oil recovery classification

Most enhanced oil recovery techniques can be classified as secondary or tertiary, depending at whch stage of the producing life of a heavy oil reservoir they are applied. Steam injection is unique among enhanced oil recovery techniques in that it can qualify as a primary, secondary, or tertiary enhanced oil recovery process, depending on the particular application in which it is being used. This will become apparent when the following varying conditions under which steam injection has been successfully applied are considered:

(1) Primary production technique The hydrocarbons found in tar sand deposits have a gravity around minus 2"

API and have viscosities ranging from 100,000 to 2,000,000 CP (Britton et al., 1982). In addition, tar sands have essentially no formation pressure. As a result, the hydrocarbons cannot be recovered by conventional primary production methods. A number of projects are currently in operation in which steam injection is being used to produce hydrocarbon liquids from tar sand deposits. In this application, steam injection becomes a primary production technique.

(2) Secondary production technique Heavy crude oils in the range of 10-25" API can be partially extracted by

conventional primary production techniques; however, the oil recovery efficiency is generally relatively low. Experience in California, U.S.A., indicates that roughly 10-15% of the oil in-place is the maximum which can be recovered from heavy oil reservoirs by primary production methods. When steam injection follows the primary production cycle in this application, it is classified as a secondary production technique.

(3) Tertiary production technique In certain reservoirs, particularly with the lighter grades of crude oil, a secondary

enhanced oil recovery technique such as waterflooding is employed when the rate of oil recovery by primary production has dropped off. After improved oil recovery by the secondary technique drops off, in certain instances, steam injection has been used to further stimulate the rate of crude oil recovery. In this instance, steam injection would properly be classified as a tertiary production technique because it follows the preceding two production methods.

As previously described, steam injection is a versatile tool for improving the recovery effectiveness from heavy oil reservoirs and tar sand deposits. It can be applied at various stages in the producing cycle of a reservoir, depending on the gravity of the oil and the structure of the formation.

Steam injection mechanisms

Steam injection is unique among enhanced oil recovery techniques in that it functions through several mechanisms to improve the oil recovery efficiency. This

223

TEMPERATURE, ' C

TEMPERATURE, OF

Fig. 7-1. Typical relationship between heavy oil viscosity and temperature. (After Buckles, 1979; courtesy of the Society of Petroleum Engineers of AIME.)

ability of steam injection to enhance the recovery efficiency of heavy crude oil through multiple mechanisms significantly increases the range of crude oil properties and types of formations in which t h s enhanced oil recovery technique can be applied efficiently.

A study of how steam injection performs in improving the recovery efficiency of heavy crude oil in-place shows the following basic factors as being influential:

(1) The heat released to the formation by the high-pressure injected steam sharply reduces the viscosity of the heavy crude oil. As a result, the improved flowing characteristics of the crude oil allow it to flow more readily to the producing wells from whxh it is pumped to the surface. Figures 7-1 and 7-2 show the effect of temperature on the viscosity of typical heavy crude oils.

(2) The steam is injected into the formation at the maximum possible pressure, commensurate with the depth of the injection well, in order to provide the maximum temperature at the bottom of the hole. Thus the high-pressure steam serves as a driving force to push the crude oil to the production wellbore.

(3) The condensate, which is formed as the injected steam releases its latent heat of vaporization to the strata, serves to act as a hot waterflood to displace crude oil in the direction of the production wellbore. (4) The heat provided by the high-pressure injected steam vaporizes light ends

from the heavy crude oil, and the vaporized light ends have the effect of building up a pressure in the formation as a result of the volume increase which results from the formation of the vapor. This pressure buildup in the formation also acts as a driving force to push crude oil toward the production wellbore. In addition, the vaporized

224

TEMPERATURE, O F

Fig. 7-2. Interrelationship among viscosity, temperature, and gravity of heavy oils. (After Buckles, 1979; courtesy of the Society of Petroleum Engineers of AIME.)

light ends mix with the heavy crude oil and tend to exert a viscosity-lowering effect. Unquestionably, the crude oil viscosity reduction resulting from the heat pro-

vided by the high-pressure injection steam is the major factor contributing to the success of steam injection as an enhanced oil recovery technique. The other listed factors, however, are influential in various degrees in improving oil recovery efficiency, and combine with the crude oil viscosity reduction to make steam injection the leading enhanced oil recovery process in use throughout the world.

Steam injection performance data

Typical strata and performance data for a number of typical operating steam injection projects is presented in Table 7-1. This data has been assembled from personal discussions with the field operators and fragmentary published data. The table is of interest in that it shows a number of elements essential in the evaluation of reservoirs for the application of thermal enhanced oil recovery through steam injection. The pertinent elements are discussed individually in order to give the reader a better insight into the requirements for a successful steam injection project.

(1) Well depth Most heavy oil reservoirs are at relatively shallow depths of less than 2500 ft,

although well depths of over 5500 ft are being subjected to steam injection in the Far East. Heat losses through the casing become excessive for well depths of over 2500 ft, and insulated downhole tubing must be used to maintain reasonable economics in deeper wells. Heat loss is covered in more detail in a later section.

(2) Permeability Permeability is the measure of tightness of a formation, and the units of measure

TABLE 7-1

Typical data on steam injection projects

Location

Mount Poso, California Cat Canyon, California Duri Field, Sumatra Kern River, California South Belridge, California Pence River, Alberta Cold Lake, Alberta

Depth Porosity Permeability Oil Oil Primary Average Total Recovery Cumulative (ft) (W) (mD) saturation gravity production injection oil rate (W OIP) oil/steam

1800 33 2500 31 525 37 705 35

1100 35 1800 28 1500 35

15,000 58 5000 65 6400 62 7600 52 3000 76 1050 17 1500 60

(OAPI) (W IOIP) rate (BOPD) ratio (BWPD/well) (bbl/bbl)

16 35 2000 13,000 60 0.18 9 12 500 250 43 0.25

22 10 1000 34,000 58 6.10 14 13 600 1490 63 0.17 13 9 600 3200 26 0.28 9 - 1500 3500 50 0.25

10 - 1500 5000 20 0.40

226

TABLE 7-11

Estimated World reserves of heavy crude oil and tar sands in millions of barrels (After R.F. Meyer, Dec. 15, 1982, personal communication)

Medium crude oil, 20-25 API

Canada U.S.A. Central America South America Europe Africa Middle East U.S.S.R./Asia Totals

119 2271

108 8376

154 4197

32,759 660

48,644 -

Heavy crude oil, Tar sands less than 20 API

69 333,010 2254 2512 331 -

5654 100,012 134 -

89 175 3528 -

97 16 12,756 435,725 -

are millidarcies (mD). The higher the permeability of a formation, the greater the number and width of passageways for steam to flow through. For example, Pennsylvania oil sands which have very low permeabilities in the range of 10 md, are not good candidates for the steam injection process. A high permeability is a prerequisite for the successful application of thermal enhanced oil recovery by the steam injection technique.

(3) Average injection rate It is the usual practice to inject as much steam into an injection well as the well

will accept, in order to heat the subsurface strata as rapidly as possible. The injection rate is normally given in barrels of water equivalent per day (BWPD). The rate at which a well accepts steam is generally dictated by the permeability, the formation thickness, the oil saturation, and the pressure of the injection steam. The maximum pressure of the injection steam is largely established by the depth of the injection well. It is desirable to inject steam at as high a pressure as possible in order to increase the temperature of the steam, and maximize the driving force for heat transfer to the oil strata. The maximum steam pressure cannot be greater than the weight of the overburden at the injection depth; otherwise, the steam pressure will cause fracturing and eruptions.

(4) Recovery The recovery of oil from a given reservoir is measured in terms of the percentage

of the original oil in-place (OIP), which has been recovered through primary production and thermal enhanced oil recovery. The projects listed are on-going, and the percentage recovery figures shown are as of late 1980.

(5) Cumulative oiE/steam ratio The cumulative oil/steam ratio column in Table 7-1 indicates the amount of

221

injection steam required to produce a given amount of crude oil at each of the listed fields. At Mount Poso, for example, it requires 5.56 barrels of water equivalent to produce one barrel of crude oil. Stated in different terms, one barrel of oil must be burned in a steam generator to make the steam required to produce 2.57 barrels of crude oil through the steam injection technique, giving a net gain of 1.57 barrels of crude oil. This installation would have to be classed as being at the lower economic limit for a steam injection project.

The South Belridge, California, installation is somewhat more typical of economically attractive steam injection projects in that it requires 3.57 barrels of water equivalent to produce one barrel of crude oil. Converted to different terms, this installation would burn one barrel of oil in the steam generator to produce 4 barrels of crude oil through steam injection, thus yielding a net gain of 3 barrels of crude oil.

These figures are based on oilfield steam generators having a thermal efficiency of 82% based on the net heating value of the fuel. As an average for steam injection projects, one may assume that out of every three barrels of crude oil produced by steam injection, one barrel must be burned in the oilfield steam generator to produce the injection steam. Similarly, it has been established that a cumulative oil/steam ratio below 0.25 is seldom economically attractive.

Wellbore and formation heat losses

Steam is an efficient medium for heating the subsurface strata and the reservoir fluids contained therein, because much of the energy available in the steam is in the form of latent heat which it releases at constant temperature as it condenses upon contacting the relatively cold subsurface strata. This release of large portions of the heat contained in the steam with no change in temperature provides the maximum driving force for transferring heat to the subsurface strata in the minimum time, thus accelerating the enhanced recovery of crude oil.

The overall thermal efficiency of a steam injection project as measured by the total energy expended to produce a barrel of crude oil can be significantly influenced by the percentage of the heat available in the steam at the outlet of the steam generator which is delivered to the oil-bearing subsurface strata. There are several areas of heat and energy loss whch serve to reduce both the temperature of the steam and the amount of useful heat delivered by the steam to the oil-bearing strata:

(1) Friction losses in the aboveground transmission piping and downhole injection tubing reduce the steam temperature.

(2) Radiation losses from surface steam transmission piping. (3) Radiation losses from the downhole injection tubing through the casing to

(4) Radiation losses from the top and bottom planes of the oil-bearing formation

Each of the above energy and heat losses are individually discussed here.

the subsurface strata.

to the adjacent strata.

228

Friction loss effect on steam temperature The temperature of the steam introduced to the oil-bearing stratum is always

lower than the steam temperature at the outlet of the oilfield steam generator, because of the friction losses experienced in the intervening piping. The temperature of saturated steam is a direct function of the pressure as can be determined from any handbook. Depending on the length of the surface steam transmission piping and the depth of the injection well, the piping friction losses can represent 10-50% of the steam pressure developed at the outlet of the steam generator. Thus, if steam at a pressure of 1500 psia is generated at the outlet of the oilfield steam generator and the pressure is reduced to 1000 psia at the injection point by piping friction losses, the temperature of the steam must have been reduced from 596OF at the point of generation to 545OF at the point where it is injected into the oil-bearing stratum. The loss in steam temperature reduces the driving force for heat transfer from the steam to the oil-bearing stratum, and increases the length of time which is required to heat the oil-bearing formation.

In modern steam injection practice, it is conventional to generate 80%-quality steam for transmission to the injection wells. The reasons for this practice are discussed at length in the section of Equipment Designs. This means that friction loss calculations for the surface transmission piping must be based on two-phase flow, which involves a fairly complex calculation. The friction losses in the surface steam transmission piping for 85%-quality steam may be approximated from the Fig. 7-3.

4 W I- m

I I I I: 1.0 I( 10.0 I

Fig. 7-3. Chart for approximate determination of pressure drop of 85%-quality steam flowing in steel pipes.

229

Surface radiation losses The larger steam injection projects generally have extensive surface steam trans-

mission piping systems to transport the steam from a group of oilfield steam generators to multiple injection wells. There are several sites in California, U.S.A., for example, where the steam is transported over several miles. The surface transmission piping may or may not be insulated, depending on the climatic conditions and relative economics of each site. In any event, both friction losses and radiation losses are experienced in the surface transmission piping, and these losses serve to reduce both the temperature and the quality of the steam. The radiation losses from insulated or uninsulated surface steam transmission piping can readily be determined for any pipe size, climatic condition, and steam temperature by procedures available in standard handbooks. Typical radiation loss values are given in Table 7-111.

Wellbore heat losses Heat losses from the downhole injection tubing may represent a significant

economic factor on a steam injection project, particularly in applications involving deep wells or in wells in which the steam injection rates are quite low. A sharp reduction in the steam quality between the wellhead and the point where the steam is actually injected into the oil-bearing stratum is possible as a result of heat losses

TABLE 7-111

Heat loss rates in bare and insulated steel pipe (After Ramey, 1965)

Insulation Conditions Heat loss, surface area, at inside temperature of (Btu/hr-ft 2 ,

200°F 400°F 600°F

Bare steel pipe Still air, 0 " F Still air, 100 " F 10-mph wind, 0 " F 10-mph wind, 100 O F

40-mph wind, 0 " F 40-mph wind, 100 " F

540 1500 3120 210 990 2250

1010 2540 4680 440 1710 3500

1620 4120 7440 700 2760 5650

Magnesia pipe insulation, air temperature = 80 O F

Heat loss, at inside temperature of (Btu/hr-ft ')

200°F 400°F 600°F 800°F

Standard on 3-in. pipe 50 150 270 440

1; in. on 6-in. pipe 64 186 335 497

Standard on 6-in. pipe 71 232 417 620 1 f in. on 3-in. pipe 40 115 207 330

3 in. on 3-in. pipe 24 75 135 200 3 in. on 6-in. pipe 40 116 207 322

230

from the downhole injection tubing to the surrounding subsurface rock formation. This subject, which is critical in enhanced oil recovery operations, has received extensive attention in the technical literature. For in-depth coverage of the subject, one should consult Rubinshtein (1959), Ramey (1962, 1965), Avdonin (1964, 1969), Leutwyler and Bigelow (1964), Leutwyler (1965), Satter (1965), Willhite (1966), Greer and Shryock (1967), Willhite and Dietrich (1967), Erlougher (1968), Traynor (1980).

Steam may be injected down the casing, but is is usual practice to inject the steam through the tubing which is centered in the casing. The annulus between the casing and the tubing is sealed by a high-temperature thermal packer located slightly above the point where the steam is injected into the oil-bearing stratum. The purpose of the thermal packer is to stop the backflow of steam through the annulus to the atmosphere.

The calculation of heat losses from the steam as it flows downward between the wellhead and the point where it is injected into the oil-bearing stratum is a complex process. The injection tubing is heated to the steam temperature and transfers heat to the casing by radiation, convection, and conduction. The casing, in turn, transfers heat continuously to the surrounding strata. The result is a continuing flow of heat from the steam to the strata, which, in turn, reduce the amount of heat available to be delivered to the oil-bearing formation. Inasmuch as the heat loss is directly proportional to the length of the injection downhole tubing, the heat loss effect becomes more critical in the deeper wells. Similarly, inasmuch as the heat loss is primarily a function of steam temperature rather than steam quantity flowing through the injection tubing, the percentage of heat loss increases inversely with the rate of steam injection in a given well. Thus, for a given steam temperature, the percentage of heat which is lost to the strata increases as the quantity of injection steam decreases.

A simplified approach to the calculation of wellbore heat loss is based on an assumption that steam temperature over the length of the downhole injection tubing is constant. This is not strictly accurate in that the steam temperature is reduced because of the pressure decrease resulting from the friction loss through the injection tubing. The simplified approach incorporates calculation of conduction and radiation of heat from the injection tubing to the casing, q,+c, and conduction of heat from the casing to the surrounding strata, qcPs:

and

231

where: 4 k,, k, , a

ri, roc = outside radius of casing, ft;

roi E = effective emissivity of tubing and casing (about 0.6); u

T, T, T, T,, T,,

= heat loss per unit of injection tubing length; = thermal conductivity of the annulus fluid, Btu/hr -ft - O F ; = thermal conductivity of the earth, Btu/hr -ft - O F ; = thermal diffusivity of the earth, ft2/hr (Table 7-IV); = inside radius of casing, ft;

= outside radius of injection tubing, ft;

= Stefan-Boltzmann constant, 0.1713 X lo-*; = temperature of the steam, O F ; = temperature of the casing, O F ; = temperature of the earth, O F ; = temperature of the steam, "F absolute; and = temperature of the casing, O F absolute.

The above two equations can be solved for the casing temperature and the heat loss per unit of injection tubing length, 4. Once the loss of heat per foot of injection tubing 4 has been established, the total heat loss from the injection tubing can be determined by multiplying q by the total length of injecting tubing. From the total heat loss figure, the deterioration in steam quality from the wellhead to the

TABLE 7-IV

Rock thermal properties (After Somerton, 1958)

Density Specific heat Thermal conductivity Thermal diffusivity, (lb/cu ft) (Btu/lb- F) (Btu/hr-ft- F) (ft */hr)

Dry rocks Sandstone 130 Silty sand 119 Siltstone 120 Shale 145 Limestone 137 Sand (fine) 102 Sand (coarse) 109

Water-saturated rocks Sandstone 142 Silty sand 132 Silts tone 132 Shale 149 Limestone 149 Sand (fine) 126 Sand (coarse) 130

0.183 0.202 0.204 0.192 0.202 0.183 0.183

0.252 0.288 0.276 0.213 0.266 0.339 0.315

0.507 (0.40) 0.396 0.603 0.983 0.362 0.322

1.592

(1.5) (1.51) 0.975 2.050 1.590 1.775

0.0213 (0.01 67) 0.0162 0.0216 0.0355 0.0194 0.0161

0.0445 (0.0394) (0.0414) 0.0307 0.0517 0.0372 0.0433

Values in parentheses are estimated.

232

I e- W 0

Y 0

e- W W U

, + W I

a

m a m m

s e- w I

6 8 10 10

STEAM INJECTION RATE, L B / H R x lo3

Fig. 7-4. Interrelationship among heat loss to the formation, steam injection rate, and pressure. (After Satter, 1965; courtesy of the Society of Petroleum Engineers of AIME.)

point where the steam is injected into the oil-bearing stratum can be readily determined from any steam table (see Farouq Ali, 1966, and Pacheco and Farouq Ali, 1972).

The simplified procedure for determining wellbore heat losses described above has a number of limitations, but should prove satisfactory for approximate heat loss evaluations. The primary limitation is the assumption of a constant steam temperature over the full length of the injection tubing. The accuracy of the heat loss determination can be increased significantly by breaking up the total length of the injection tubing into increments, and adjusting the steam temperature in each increment for the friction loss effect on the temperature experienced in that increment. Figure 7-4 provides an approximate picture of wellbore heat losses as a function of steam injection pressure and injection rate.

The interest in applying the steam injection technique to deeper wells plus the accelerating rise in the cost of fuels has promoted intensive development in means to reduce wellbore heat losses. The result has been development of reliable insulated

233

LT 5400- . 3 C 4800-

1

3 4200-

s

6000 = O 0 8

3600-

3000-

2400-

1800-

1200-

600 -

I

0.5 1.0 1.5 2.0 2.5 3.0

WELL DEPTH, FT I 1 0 3

Fig. 7-5. Wellbore heat losses using insulated and uninsulated injection tubing. (After Davis and Fanaritis, 1982; courtesy of The Oil and Gas Journal.)

injection tubing, which reduces heat losses and minimizes thermal stresses in the casing induced by high casing temperatures. Figure 7-5 shows a comparison of heat losses from insulated and uninsulated tubing over a range of well depths (Davis and Fanaritis, 1982). Table 7-V shows comparative heat losses with insulated and

TABLE 7-V

Comparative heat losses with insulated and uninsulated tubing in a location in Alberta, Canada (2300-ft deep well, 80%-quality steam at 2000 psig and 635 OF; 600 bbl/D water equivalent injection rate; steam drive) (after Traynor, 1980)

Injection through Injection through uninsulated tubing insulated tubing

Heat at wellhead, Btu/hr 9,174,940 9,174,940 Heat at reservoir, Btu/hr 7,217,069 8,945,884 Heat differential in reservoir, Btu/hr 0 1,728,815 Casing temperature, OF 465 108 Steam quality at reservoir, '% 32 74 Heat loss, X 21.3 2.5

234

I A. P R E S T R E S S E D I ~

COLLAR T U B I N G CASING

S T E E L BUSHING INSULATION \ - C O R D I E R I T E CENTRALIZER R I N G S

Fig. 7-6. Two different designs of insulated downhole tubing. (After Davis and Fanaritis, 1982; courtesy of The Oil and Gas Journal.)

uninsulated tubing on a specific project. Two typical types of insulated downhole injection tubing, whch are currently in use, are shown in Fig. 7-6.

Heat losses to surrounding formations Every oil-bearing stratum regardless of its thickness, is surrounded by non-oil-

bearing rock with which it is in direct contact. Heat is transmitted by conduction from the oil-bearing stratum into which steam is being injected to the non-oil-bearing rock, from both the top and bottom planes of contact. Heat lost from the oil-bearing stratum to the surrounding non-oil-bearing rock is not productive in increasing the recovery of crude oil in a steam injection project, and thus its impact must be evaluated as it affects the project economics. Inasmuch as the area of the contact planes between the oil-bearing stratum and the surrounding rocks remains constant regardless of the thickness of the oil-bearing formation, it becomes obvious that the percentage of total injected heat which is lost from the upper and lower planes of the oil-bearing stratum varies inversely with the thickness of the oil-bearing formation.

235

As noted previously, steam is an efficient heating medium in that much of its energy is contained in the latent heat of vaporization, which is released with no change in temperature as steam condenses upon contact with the oil-bearing stratum. As a result, the heated stratum can be assumed to be at a constant temperature T,, which is equal to the steam temperature. This assumption forms the basis for a simplified treatment of heat losses to the surrounding formations during a steam injection cycle (Marx and Langenheim, 1959).

On assuming a constant steam injection rate and a uniform thickness of oil-bearing stratum, the bulk volume of the steamed zone, V,, at time t is equal to:

The heat injection rate qi is given by the following formula:

q i = (350/24)i,[h,+J;L,-c,(T,- 321)] (7-4)

Dimensionless time t , is equal to:

and the F, factor is a function of dimensionless time as follows:

1

where: c w = specific heat of water, Btu/lb- OF; 6 = Marx-Langenheim function from Table 7-VI; f, = mass friction; ht = total formation thckness, ft; hw

' S

khoh Lv Mob M, (2, t = time, days; t , = dimensionless time; T, = temperature of the reservoir, OF; r, = temperature of the saturated steam, O F; v, = bulk volume steamed, ft3; and erfc = complementary error function.

= enthalpy of saturated water, Btu/lb; = injection rate of wet steam measured as water, BFD; = thermal conductivity of overburden, Btu/hr-ft- OF; = latent heat of vaporization, Btu/lb; = heat capacity of overburden, Btu/ft3- O F ; = heat capacity of fluid-saturated rock, Btu/ft3- O F ; = heat injection rate, Btu/hr;

(7-6)

236

The above discussion shows that the heat losses from the oil-bearing stratum through its top and bottom planes to the adjacent formations is dependent totally on t,; in other words, the percentage heat losses increase directly with time and inversely with the square of the oil-bearing formation thickness. The heat loss as a function of these two variables is shown typically in Fig. 7-7. The above correlation shows that it is uneconomical to apply steam injection to relatively thin oil-bearing formations because too high a percentage of the heat would be lost to the adjacent strata.

For projects involving high-pressure steam injection, thin oil-bearing formations, or low steam quality, the Mandl and Volek (1969) correlation provides a more accurate determination of the steamed zone volume. This correlation is based on the assumption that, after a certain critical time, the latent heat available in the injection steam is barely sufficient to make up the heat losses to the adjacent

TABLE 7-VI

Marx-Langenheim functions

rD F2 Fl ‘D F2 4 ‘D

0.0000 1.00000 0.00000 0.58 0.50271 0.36206 0.0001 0.0002 0.0003 0.0004 0.0005 0.0006 0.0007 0.0008 0.0009 0.001 0.002 0.003 0.004 0.005 0.006 0.007 0.008 0.009 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08

0.98882 0.98424 0.98075 0.97783 0.97526 0.97295 0.97083 0.96887 0.96703 0.96529 0.95147 0.94108 0.93245 0.92496 0.91826 0.91218 0.90657 0.90135 0.89646 0.85848 0.83160 0.80902 0.79033 0.77412 0.75964 0.74655

0.00010 0.00020 0.00030 0.00039 0.00049 0.00059 0.00069 0.00078 0.00088 0.00098 0.00193 0.00288 0.00382 0.00475 0.00567 0.00658 0.00749 0.00840 0.00930 0.01806 0.02650 0.03470 0.04269 0.05051 0.05818 0.06571

0.60 0.62 0.64 0.66 0.68 0.70 0.72 0.74 0.76 0.78 0.80 0.82 0.84 0.86 0.88 0.90 0.92 0.94 0.96 0.98 1 .o 1.05 1.10 1.15 1.20 1.25

0.49802 0.49349 0.48910 0.48484 0.48071 0.47670 0.47281 0.46902 0.46 5 3 3 0.46174 0.45825 0.45484 0.45152 0.44827 0.44511 0.44202 0.43900 0.43605 0.43317 0.43034 0.42758 0.42093 0.41461 0.40859 0.40285 0.39736

0.37206 0.38198 0.39180 0.40154 0.41120 0.42077 0.43027 0.43969 0.44903 0.45803 0.46750 0.47663 0.48569 0.49469 0.50362 0.51250 0.52131 0.53006 0.53875 0.54738 0.55596 0.57717 0.59806 0.61864 0.63892 0.65893

~

2.6 2.7 2.8 2.9 3.0 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8 3.9 4.0 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 5.0 5.2 5.4

4 0.30411 0.29963 0.29535 0.29126 0.28734 0.28358 0.27996 0.27649 0.27314 0.26992 0.26681 0.26380 0.26090 0.25810 0.25538 0.25275 0.25021 0.24774 0.24534 0.24381 0.24075 0.23856 0.23642 0.23434 0.2 3 2 3 2 0.22843 0.22474

1.12356 1.15375 1.18349 1.21282 1.24175 1.27029 1.29847 1.32629 1.35377 1.38092 1.40775 1.43428 1.46052 1.48647 1.51214 1.53755 1.56270 1.58759 1.61225 1.63667 1.66086 1.68482 1.70857 1.73212 1.75545 1.80153 1.84686

237

TABLE 7-VI (continued)

t D F 2 1 4 ' t D F2 Fl t D F2 F,

0.09 0.1 0.12 0.14 0.16 0.18 0.20 0.22 0.24 0.26 0.28 0.30 0.32 0.34 0.36 0.38 0.40 0.42 0.44 0.46 0.48 0.50 0.52 0.54 0.56

0.73460 0.72358 0.73079 0.68637 0.67079 0.65668 0.64379 0.63191 0.62091 0.61065 0.60105 0.59202 0.58305 0.57545 0.56781 0.56054 0.55361 0.54699 0.54066 0.53459 0.5 2 8 7 6 0.52316 0.51776 0.51257 0.50755

0.07311 0.08040 0.09467 0.10857 0.12214 0.13541 0.14841 0.16117 0.17370 0.18601 0.19813 0.21006 0.22181 0.23340 0.24483 0.25612 0.26726 0.27826 0.28914 0.29989 0.31052 0.32104 0.33145 0.34175 0.35195

1.30 1.35 1.40 1.45 1.50 1.55 1.60 1.65 1.70 1.75 1.80 1.85 1.90 1.95 2.00 2.05 2.10 2.15 2.20 2.25 2.30 2.35 2.40 2.45 2.50

0.39211 0.38709 0.38226 0.37762 0.37317 0.3 6 8 8 7 0.36473 0.36074 0.3 5 6 8 8 0.35315 0.34955 0.34606 0.34267 0.33939 0.33621 0.33311 0.33011 0.32719 0.32435 0.32159 0.31890 0.31627 0.31372 0.31123 0.30880

0.67866 0.69814 0.71738 0.73637 0.75514 0.77369 0.79203 0.81017 0.82811 0.84586 0.86343 0.88032 0.89803 0.91509 0.93198 0.94871 0.96529 0.98172 0.99801 1.01416 1.03017 1.04605 1.06180 1.07742 1.09292

5.6 5.8 6.0 6.2 6.4 6.6 6.8 7.0 7.2 7.4 7.6 7.8 8.0 8.2 8.4 8.6 8.8 9.0 9.2 9.4 9.6 9.8

10.0

0.22123 0.21788 0.21470 0.21165 0.20875 0.02597 0.20330 0.20076 0.19832 0.19598 0.19374 0.19159 0.18952 0.18755 0.18565 0.18383 0.18208 0.18041 0.17881 0.17727 0.17580 0.17440 0.17306

1.89146 1.93538 1.98765 2.02129 2.06334 2.10482 2.14576 2.18617 2.22608 2.26550 2.30496 2.34298 2.38106 2.41873 2.45600 2.49289 2.52940 2.56555 2.60135 2.63682 2.67196 2.70679 2.741 3 1

' Fl = e'D erfc t , + 2 tD/r - 1; F2 = e'D erfc tD . This table is used in conjunction with eqs. 7-3, 7-4, J - r J- 7-5, and 7-6.

I . I

OIL-BEARING FORMATION THICKNESS. 5 F T 10

T I M E , TOTAL D A Y S

Fig. 7-7. Cumulative heat losses from the oil-bearing formation to the adjacent strata as a function of time and formation thckness. (After Leutwyler, 1965; courtesy of the Society of Petroleum Engineers of AIME.)

238

formations plus raising the temperature level of the newly penetrated formations to the steam temperature. Up to the critical time, heat transfer from the steam front is conductive, whereas subsequently it becomes both conductive and convective. Myhill and Stegemeier (1978) provided convenient charts for determination of the volume of the steamed zone for any given set of conditions.

Steam displacement is not necessarily frontal in many viscous oil reservoirs subjected to steam injection. Gravity override by the steam may result in only the upper part of an oil-bearing formation being contacted for a period of time, which will affect the determination of the steamed zone in the early stages of the project. With time, the steamed zone thckness will gradually grow downward in the formation to eventually achieve the predicted steamed zone volume.

STEAM INJECTION TECHNIQUES

Steam injection at the present time is applied through two different techniques: cyclic or continuous flooding. Each technique has economic and operating advantages over the other in specific applications, and selection of the steam injection technique to be used should only be made after a thorough economic evaluation of the project characteristics.

Cyclic steam injection

Cyclic steam injection, as the name implies, involves alternating cycles of injecting steam and producing oil from the same well (Fig. 7-8). It is primarily a stimulation technique that, through a viscosity reduction of viscous crude oil and wellbore cleanup effects, assists natural reservoir energy in creating crude oil flow to the wellbore. In certain instances, cyclic steam injection may be used as a prelude to a continuous steamflood to clean out the oil-bearing strata in what will become the

I I I I I I I I 1

T I M E , MONTHS

Fig. 7-8. Typical performance (oil production) of a well using cyclic steam injection. (After Adams and Khan, 1969; courtesy of the Society of Petroleum Engineers of AIME.)

239

injection well for the steamflood. Generally, cyclic steam injection is used until the oil production becomes marginal, and then the project is converted to a continuous s teamflood.

The first step in a cyclic steam project is to inject steam into a well for a period which may last from one to several weeks, depending on the formation thickness, the oil saturation, and the number of previous injection cycles which have been performed. Following completion of the injection of the predetermined amount of steam, the well is closed-in and a soak period of possibly one week is allowed. This enables the transfer of heat by conduction through a greater portion of the oil-bearing formation. After a sufficient soaking period, a pump is lowered into the well and production of oil is started. Oil production continues until the rate of recovery reaches an uneconomic level, at which point the whole process is repeated.

The response to cyclic steam injection can vary considerably with different types of reservoirs. In California, U.S.A., where generally there are thick, steeply dipping oil-bearing sand structures, gravity drainage is prevalent and many steam injection cycles are effective as heated, reduced-viscosity oil continues to flow down by gravity to the producer. Multiple steam injection cycles are common, with as many as 42 steam injection cycles on a single well having been reported.

For relatively flat oil-bearing strata, the gravity drainage effect is much less pronounced, and the driving force for movement of the crude oil to the production well is the energy supplied by the injection steam. The number of economic steam injection cycles which can be applied to a flat oil-bearing structure is generally much lower than that in a steeply-dipping reservoir.

Regardless of the type of reservoir involved, cyclic steam injection generally becomes less efficient with each successive cycle because heat penetration further from the point of injection is required after extraction of the oil closest to the producer. Figure 7-8 depicts the declining recovery curve over a three-cycle injection. Both peak and average oil production rates tend to decrease with each succeeding injection cycle, and increasing amounts of injection steam are required.

During the initial steam injection cycle, up to 30 barrels of oil are recovered per barrel of water injected as steam, which is equivalent to an oil-to-water ratio of 30 to 1. Generally a cyclic steam injection project is considered to have become marginal when this ratio starts to approach 0.22 which is equivalent to one barrel of oil recovered for every 4.55 barrels of water injected as steam. At this point, the cost of the fuel burned in the steam generator plus the other site operating costs tend to approach the value of the net oil recovery.

The parameters of the cyclic steam injection process are quite complex, and no reliable mathematical treatments for predicting crude oil recovery have been developed. A number of simplified approaches have been proposed in the literature for determining the time-dependent oil recovery rate from a cyclic steam stimulation. The reader is referred to the following references for a more detailed treatment of the subject: Towson and Boberg (1967), Boberg and Lantz (1966), De Haan and Schenk (1969).

The most difficult value to determine in a cyclic steam stimulation project is the

240

Qoh temperature of the heated zone as a function of time. The stimulation ratio, -

may be determined by the following formula: Q,

where: poc = oil viscosity in the cold formation, cP; poh = oil viscosity in the heated formation, cP; Q,, = oil production rate prior to steam stimulation, bbl/D; QOh = oil production rate following steam stimulation, bbl/D; re = drainage radius, ft; rh r, = well radius, ft.

to the following form:

= heated zone average radius, ft; and

For very high cold oil viscosities, the stimulation ratio equation may be reduced

In other words, the stimulation ratio or percentage of increase in oil production with cyclic steam stimulation in formations having highly viscous oil depends primarily on the radius of the heated zone. It is for this reason that highly viscous oil-bearing deposits require more steam per stimulation cycle than do more normal heavy oil deposits. In the former, the drainage radius is essentially equal to the heated zone radius and basically independent of the well spacing.

The calculation of the stimulation ratio is difficult because of reservoir rock parameters and other factors which can affect the uniform distribution of steam through the oil-bearing stratum. Among these factors are: (1) bypassing of steam through crevices and fractures in the formation, ( 2 ) relative permeability hysteresis, ( 3 ) gravity segregation of the steam, and (4) formation fracturing during the steam injection cycle. The effect of temperature on relative permeabilities of oil and water is presented in Fig. 7-9.

Steamflooding

Steamflooding, or steam drive as it is frequently termed, is a process very similar to waterflooding. A basic difference between the two processes is that steam provides both thermal and mechanical energy to enhance the recovery of viscous crude oils, whereas cold water as typically used in a waterflood can only provide mechanical energy.

In a steamflood, a suitable pattern of injection wells surrounded by production wells is selected, with the pattern largely dependent on the geology of the formation

241

WATER SATURATION, %

Fig. 7-9. Effect of temperature on relative permeabilities of oil and water. (After Weinbrandt et al., 1975; courtesy of the Society of Petroleum Engineers of AIME.)

Fig. 7-10. Schematic diagram of a typical continuous steam injection project arrangement.

242

to be flooded. Typically 5, 7-, and 9-spot patterns are being used with injection wells driving the crude oil to producing wells. Figure 7-10 shows a typical steamflood layout.

Steam is continuously injected into the selected injection wells and drives the crude oil to the producing wells surrounding the injection wells in a sweeping pattern through the oil-bearing stratum. Ideally, the injected steam forms a steam saturated zone around the injection wells as schematically shown in Fig. 7-11. The temperature of the steam-saturated zone approaches the temperature of the injection steam. As the steam penetrates the oil-bearing stratum away from the point of injection, there is a reduction in temperature as steam continues to expand as a result of the decrease in pressure. At some distance from the injection well, the steam condenses and forms a hot water bank. This distance is a direct function of the initial steam temperature and the rate of pressure changes with distance from the point of injection. The hot-water bank continues to flow toward the producing wells, giving up heat to the stratum in its forward movement and pushing the oil ahead of it.

Steamflood oil recovery is dependent on several factors. Probably most influential in the recovery process is the hot-water flood zone where the water at elevated temperatures provides (1) heat to reduce the oil viscosity, and (2) displacement volume to force the oil ahead of it toward the producing wells. The largest oil saturation reduction is generally achieved in the hot waterflood zone as a result of crude oil swelling, reduced crude oil viscosity, improved formation permeability on expansion with temperature increase, and the displacement effect of the hot water.

In the steam-invaded zone, the oil saturation is reduced by the combined effects

I N J E C T

WET S a PRODUCE

OIL A N D WATER S T E A M ZONE COLD RESERVOIR -

Fig. 7-11. Schematic diagram of reservoir heating by steam injection. (Modified after Marx and Langenheim, 1959.)

243

of gas drive, viscosity reduction, steam distillation, and solvent extraction. The gas (steam) drive effect is usually important, and steam distillation can contribute significantly to the improved delivery of certain crudes.

The actual operation of a steamflood seldom follows the ideal pattern. When steam is initially injected, it seeks the flow path of least resistance and forms a finger-like channel through this flow path to the producing wells. With time and continued steam injection, the steam finger, being less dense than the oil, moves upward in the oil-bearing stratum and blankets the oil. The gravity override by the steam results in sweeping of the upper portion of the oil-bearing stratum by steam and the lower portion by hot water, thus giving rise to nonuniform vertical oil extraction efficiencies.

Gravity overrides are aggravated by the presence of a gas zone in the formation (Farouq Ali and Meldau, 1979). Injection of the steam at the bottom of the oil-bearing strata may be effective in reducing override severity, but this is only recommended for highly homogeneous reservoirs and those devoid of a bottom-water zone. In multilayered formations, steam injection should be applied at multiple vertical intervals to ensure uniform distribution throughout the oil-bearing stratum.

It is frequently desirable to conduct one cyclic steam injection run on the producing wells in a steamflood pattern prior to initiation of the steamflood. This is done in order to reduce the resistance to flow which would be imposed by the cold oil near the producing wells when oil movement is initiated in the oil-bearing stratum by the steamflood.

Using the steam injection process, the major portion of crude oil is currently being produced by the steamflood technique. Use of the technique, however, does not automatically ensure an economically justifiable project. The application of steamflooding of a given reservoir should only be considered after a thorough evaluation of the geology of the formation, and the various factors required for a successful steamflood project. Table 7-1 lists several steam injection projects and the formation characteristics. Of importance are reservoir depth, reservoir pressure, thickness of the oil-bearing stratum, permeability, oil saturation, and the crude oil gravity. The presence of a primary or secondary gas cap tends to aggravate gravity override, but may enhance a real coverage and rapid heating of the crude oil. This can be particularly effective in thin sands. The effect of a bottom-water zone on steamflooding depends in large measure on the properties of the reservoir rock and the fluids, and the type of flooding scheme employed. The bottom-water zone can serve as a bypass for the injection steam, or it can be used to achieve steam penetration and the improved conductance of heat into the reservoir.

Oil recovery from a steamflood project may be predicted from computer models, scaled physical models as shown in Fig. 7-10, numerical simulation, and published correlations. For more detailed coverage of oil recovery prediction methods on a steamflood project, the reader is referred to Gottfried (1965), Farouq Ali (1966, 1970, 1981), Flock et al. (1967), Davies et al. (1968), Fairfield (1968), Adams and Khan (1969), Shutler (1970), Moss (1974), Bursell and Pittman (1975), Neuman (1975), Cook (1977), Crookston et al. (1977), Ferrer and Farouq Ali (1977), Myhill

244

and Stegemeier (1978), O’Dell and Rogers (1978), Gomaa (1980), Jones (1980). Extensive studies have shown that ultimate oil recovery from a steamflood

project in many cases depends on the volume of the reservoir which is steamed (Myhill and Stegemeier, 1978). Thus production near the end of the steamflood can be estimated from the following equation:

where:

Np F

h , h , Soi Sorsi V, + = fractional porosity.

It is necessary to estimate the value of F, which varies from 70 to 100% for most applications (Myhill and Stegemeier, 1978). Jones (198Q) used field test data to develop approximate values of F as a function of the mass of steam injected.

In general, steamflooding has been found to be a very effective enhanced oil recovery technique when applied to the suitable reservoirs and conducted properly. There are examples where as much as 75% of the oil in-place has been recovered from a reservoir, and the average recovery of the oil in-place has been in the 45-55% range. Considering that only 10-15% of the oil in-place can typically be recovered in heavy oil reservoirs by primary production methods, it is obvious that steamflooding can be a valuable tool in the production of viscous crude oils.

= cumulative oil recovered, bbl; = ratio of actual to theoretical oil production, fraction; = net oil-bearing sand thckness, ft; = total formation thckness, f t ; = initial oil saturation, fraction; = saturation following steamflooding, fraction; = bulk volume steamed, ft3; and

RECENT DEVELOPMENT IN STEAM INJECTION TECHNIQUES

As the application of steam injection to the enhanced recovery of heavy crude oils has expanded in recent years, there have been a number of developments designed to increase the recovery ratio and economics of the process.

Steam additives

Even though steamflooding is the most successful of all enhanced oil recovery processes, its efficiency could be further improved if certain problem areas could be overcome. Gravity override, or the tendency of steam to heat the upper portion of an oil-bearing formation in preference to the lower portion, results in poor areal and vertical sweep efficiencies which limit the recovery of crude oil. An additional problem is the premature breakthrough of the injected steam to the producing wells creating steam bypass channels, with consequent loss of effective use of the bypass

245

steam in increasing oil production. If the steam could be forced to contact more of the reservoir and if the steam channeling could be minimized, the oil recovery efficiency of steam injection could be markedly improved.

Experimental tests are underway involving the injection of a steam foam solution and a steam foam encapsulated in a polymer gel to solve the above problems. Preliminary results with injection of in-situ steam foams indicate that this technique can alter the steam injection profiles to prevent excessive steam channeling. Prom- ising preliminary results have also been achieved relative to improvements in both areal and vertical sweep efficiencies using steam foam injection (Eson and O’Nesky, 1982).

Hotplate steam injection process

Cornell Heavy Oil Process, Inc. is proposing a process which mixes mining operation and horizontal steam injection in a system designed to recover 75% of the crude oil in-place, according to the developer. A trial installation is located near Bakersfield, California (Oil and Gus Journal, 1982).

The hotplate EOR method uses cyclic steam injection into a heavy-oil-bearing formation in a hub and spoke pattern from lateral wells. The wells are drilled from a cavern excavated in an unconsolidated oil sand at a depth of 500 ft. It is assumed that the thermal efficiency of the project will be greatly improved by exposing all of

Fig. 7-12. The Fracture Assisted Steamflood Technology Process (FAST) as developed and patented by Conoco for extraction of tar from tar sands.

246

the formation to the steam front via the lateral wells. The economics of this process as compared to conventional steam injection techniques will not be determined for several years.

Fracture-assisted steamflood process

The Fracture-Assisted Steamflood Process (FAST Process) has been developed and patented by Conoco for application on its Street Ranch tar sand extraction plant located near Uvalde, Texas. As shown in Fig. 7-12 the process consists of hydraulically fracturing the formation in the horizontal plane at several predetermined locations, and then holding the fractures open by the injection of high- pressure steam. This technique provides heating from both sides of fractures of selected thicknesses of tar sand formation and greatly expedites the rate of heating of the formation.

The particular tar for whch the FAST process was developed is one of the most viscous, dense, sulfur-laden hydrocarbons known to exist anywhere in the world (Britton et al., 1982). It has an API gravity of -2", a pour point of 180"F, and an extrapolated viscosity of 20 X lo6 cP at the reservoir temperature of 95 OF. Testing is still underway to determine the economics and recovery efficiency of the FAST process in t h s difficult steam injection application.

tQUIPMENT DESIGNS FOR STEAM INJECTION PROJECTS

Introduction to equipment designs

The initiation of steam injection as a commercial enhanced oil recovery technique created a need for the development of supporting equipment capable of meeting the unusual requirements of the process. Suitable prototypical designs were quickly developed as the need materialized in the early 1960's in the United States, and the original designs have been continuously improved and expanded in capability in the subsequent years to meet changing operational requirements and increasingly more stringent environmental standards.

The single most critical component in a steam injection enhanced oil recovery project is the steam generator, which must be capable of operating under far more difficult conditions than those required of the traditional process, i.e., electric utility boilers. A steam generator designed for use on steam injection applications must meet the following minimum performance requirements:

(I) Generate steam at pressures ranging from 300 to 2500 psia. (2) Use cold feedwater containing up to 8000 ppm of total dissolved solids. (3) Operate fully unattended for reasonable periods of time. (4) Be relatively portable so that it may be readily moved from one location to

( 5 ) Respond to rapid heat load or steam pressure demands. another.

241

(6) Suitable for outdoor installation. (7) Easy to service and maintain by oilfield personnel. (8) Avoid construction that would place it in a boiler classification. As a result of the above requirements, the forced circulation, once-through design

of steam generator was developed, and remains the predominant design used on steam injection projects throughout the world. The original basic design has proven hghly successful in this demanding application, with over 20 years of successful performance history.

Other equipment components, whch have to be developed or modified from existing designs to meet the specific requirements of steam injection projects, include the following that are described in some detail here:

(1) Steam quality measurement instrumentation. (2) Low NO, burners. (3) Feedwater treatment. (4) Flue gas scrubbers. ( 5 ) Low-temperature economizers. (6) High-temperature thermal packers. (7) Casing vent systems. (8) Downhole steam generators. (9) Solid or waste liquid fuel-fired steam generators.

Steam generator design

In order to successfully generate high-pressure steam from feedwater containing high total dissolved solids, the concept was evolved of using a once-through, water tube type of steam generator based on process furnace design principles of relatively low radiant heat fluxes and uniform radiant section heat distribution. Integral in the original design concept was the idea of softening the feedwater containing high total dissolved solids to essentially zero hardness, and leaving sufficient water in the effluent stream from the steam generator to maintain the concentrated solids in solution. The basic design concept is utilized in varying degrees in most of the oilfield steam generators used worldwide on steam injection enhanced oil recovery projects (see Fig. 7-13).

In general, oilfield steam generators are designed to produce about 80%-quality steam, thus leaving about 20% of the feedwater as a liquid at the steam generator outlet to maintain the concentrated solids in solution. The value of 80%-quality steam was arbitrarily selected as a conservative value at the time the original oilfield steam generator design was developed in the United States. In feedwater containing total dissolved solids in the range of 500-2500 ppm, the steam quality can be safely increased to possibly 90% without jeopardizing performance. With feedwater containing total dissolved solids over about 8000 ppm, it is recommended that the steam quality be maintained at a maximum of 80%.

Tests have been conducted in a one million Btu/hr pilot plant steam generator with feedwater containing 14,000-22,500 ppm total dissolved solids to determine

248

Fig. 7-13. A trailer-mounted 25-MMBtu/hr oilfield steam generator with ion exchange water softener. (Courtesy of Struthers Thermo-Flood Corporation.)

both the water softener effectiveness and the ability of this type of steam generator to accept feedwater having extremely high solids content (Elias et al., 1980). The tests showed that no solids deposition on the tube walls or tube corrosion were experienced when generating 73%-quality steam at 2256 psig outlet pressure from feedwater containing 22,500 ppm total dissolved solids. The effluent liquid in this instance contained over 83,000 ppm of dissolved solids.

There are certain steam injection installations where the operators have a preference for injecting 100%-quality steam. The once-through 80%-quality steam generator can still be used in these instances by installing a steam-water separator on the outlet of the steam generator. Thermal efficiency can be maintained at an acceptable value by exchanging heat between the hot liquid separated from the steam generator discharge and the feedwater. In the majority of steam injection projects, the 80%-quality steam is injected into the formation, because the hot water contains an appreciable amount of energy and adds to the displacement volume of the injection stream.

In the design and operation of oilfield steam generators, a number of important factors must be considered and incorporated into the design in order to ensure satisfactory performance. These factors are discussed in this chapter as a guide to the reader in evaluating competitive steam generator designs.

249

Tube side flow design In the design of steam generators producing 80%-quality steam from feedwater

containing high total dissolved solids, it is essential to avoid conditions under which the liquid film on the tube wall can be totally vaporized and deposit the solids it is carrying in solution on the tube wall. Solids deposition on a localized area of a tube will impose a high resistance to heat transfer due to the low thermal conductivity of the solids, and result in a rise in the tube wall temperature. On a typical oilfield steam generator, a 0.125-in. solids deposit 011 the inside wall of a radiant tube will increase the tube wall temperature by about 235 O F . It becomes apparent that any significant solid deposition can quickly lead to a tube rupture as a result of overheating.

The two major factors that can affect liquid dryout and solids deposition on the inside wall of a radiant tube are (1) the heat flux to which the tube is subjected, and (2) the flow regime in which the steam-water mixture is operating. These two factors are interrelated and have an equal impact on satisfactory steam generator performance.

The heat flux in the radiant section, which is discussed in greater detail in a subsequent section, is restricted to values ranging from 10-20% of those used in conventional boilers. The reason for the restricted heat flux is the lack of any liquid

Fig. 7-14. A 50-MMBtu/hr oilfield steam generator design to bum high-sulfur content fuel gases. (Courtesy of Struthers Thermo-Flood Corporation.)

250

recirculation to increase the liquid volume in the tubes and ensure full wetting of the tube walls. In an oilfield steam generator operating at 1500 psia, the tube volume occupied by vapor at the midpoint in the radiant section is over 88% as compared to roughly 23% in a conventional boiler. The much higher percentage of tube volume occupied by the vapor in an oilfield steam generator and the high total dissolved solids content in the liquid dictate the use of much lower rates of heat input to the radiant tubes than are acceptable in conventional power boilers.

The other major consideration in the tube side design is to ensure that the steam-water mixture in the radiant section is operating in the proper flow regime, as determined by the tube diameter and mass velocity through the tubes, the percentage of vapor at any point, and the relative vapor and liquid densities (Tong, 1965). Fully annular flow with uniform liquid film thickness over the total internal periphery of the tubes is ideal. Unfortunately, the gravity effect acting on mixed- phase flow in horizontal tubes results in a reduced liquid film thickness in the upper quadrant of the tubes. Thus the heat flux in the upper tube quadrant must be less than that required to totally vaporize the reduced film thickness; otherwise, solids deposition will inevitably take place. It is interesting to note that, because of the high vapor velocities employed in oilfield steam generators, the steam heat transfer film coefficients achieved are adequate to maintain tube wall temperatures at a safe level. Only when a thin liquid film on the tube wall is totally vaporized by an excessive rate of heat input, would solids deposition occur on the tube wall with resultant potential tube failure.

Suggested velocities in coils Oilfield steam generators are normally required to operate over a wide range of

heat absorption rates, feedwater flow rates, and outlet steam pressures. Experience has indicated the necessity of operating within certain minimum and maximum liquid and vapor velocities in order to avoid overheating of the steam generator tubes, or erosion of the tubes from high-velocity 80%-quality steam. Suggested velocity values for use in the design of once-through oilfield steam generators are as follows:

It is suggested that the minimum mass velocity through the steam generator tubes should not be less than 90 lb/ft2-sec. This is equivalent to a minimum linear velocity of 1.44 ft/sec with cold water. Any lower value throughput has the potential of depositing solids on the tubes, with resulting tube failure.

It is suggested that the maximum inlet liquid mass velocity through the steam generator tubes should not exceed 562 lb/ft2-sec, which is equivalent to a linear velocity of 9 ft/sec. Higher velocities may cause tube and/or U-bend erosion.

The maximum 80%-quality steam velocity leaving the steam generator should not exceed a reasonable value to minimize the potential for erosion from the high-velocity liquid droplets carried by the vapor. The specific volume of the 80%-quality

(1) Minimum feedwater flow rate

(2) Maximum feedwater flow rate

(3) Maximum steam exit velocity

25 1

steam for determining the velocity may be calculated as follows:

u = x u s + ( l - x ) u w (7-10)

where: u = specific volume of 80%-quality steam, ft3/lb; x = fraction of steam; us = specific volume of steam at the operating conditions, ft3/lb; and u, = specific volume of water at the operating conditions, ft3/lb.

Table 7-VII shows suggested maximum 80%-quality steam flow rates of a reasonable outlet velocity through various pipe sizes and over a range of pressures. It should be noted that caution should be exercised in operating an oilfield steam generator designed for 2500 psia at its full heat input rating, but at a much lower discharge pressure, because the suggested maximum outlet velocity may be exceeded. For a 50-million-Btu/hr steam generator designed for 2500 psia operating pressure and provided with 3-in. schedule 160 IPS tubing, the maximum recommended flow rate at 500 psia operating pressure would be 25,500 lb/hr as compared to the normal flow rate of approximately 52,000 lb/hr at the steam generator design conditions.

TABLE 7-VII

Suggested maximum flow rates for once-through oilfield steam generators

Nominal A.S.A. Flow rate (lb/hr) pipe size schedule

2 in. 40 15,800 29,300 31,600 32,300 2 in. 80 13,900 25,800 27,800 28,400 2 in. 160 10,500 19,500 21,100 21,500 2 ; in. 40 22,500 41,800 45,100 46,100

2f in. 80 20,000 36,900 39,900 40,800

2f in. 160 16,700 30,900 33,400 34,100 3 in. 40 34,800 64,500 69,500 71,100 3 in. 80 31,100 57,600 62,100 63,500 3 in. 160 25,500 47,200 50,900 52,100 34 in. 40 46,500 86,200 92,900 95,100

3; in. 80 43,700 77,500 83,600 85,500 4 in. 40 62,500 110,900 119,700 122,400 4 in. 80 54,100 100,300 108,100 110,500 4 in. 160 43,700 80,900 87,300 89,300

500 psia 1000 psia 1500 psia 2500 psia

Based on a reasonable outlet mixture velocity to minimize potential for erosion of the pipe and/or U-bends. The values shown are suggested maximum flow rates and are generally not approached in commercial oilfield steam generators because of friction loss considerations.

252

Once-through oilfield steam generators are normally designed for tube side pressure drops in the range of 100-300 psia. Most of the friction loss through the steam generator is experienced in the latter half of the radiant coil where the steam volume is high.

Radiant section design The proper design of the radiant section of a once-through oilfield steam

generator is the single most important factor in assuring a satisfactory performance. The radiant section not only absorbs about 65-68% of the total heat transferred to the feedwater, but also transfers heat to tubes containing a hgh volume of steam and operates under the highest thermal driving force present at any point in the steam generator. In a satisfactory design, it is essential to use relatively low heat fluxes, and take special precautions to insure the maximum uniformity of heat distribution. The importance of these factors is discussed in the following para- graphs (see Fig. 7-15).

The radiant heat flux is measured in Btu/ft2-hr, and is determined by dividing the total heat absorbed in the radiant section by the radiant heat transfer surface. The calculation method used in establishing the percentage of heat released by the combustion of the fuel, which is absorbed in the radiant section, is treated in detail

R A D I A T I N G PLANE

REFRACTOR

..........................

Fig. 7-15. Heat flux around the circumference of a tube in a single row subjected to radiant heat from one side. (After Sutherland, 1961; courtesy of the American Institute of Chemical Engineers.)

253

Fig. 7-16. A 25-MM Btu/hr oilfield steam generator trailer mounted and provided with weather protection for operation under severe winter conditions. (Courtesy of Struthers Thermo-Flood Corpora- tion.)

by Wimpress (1963, 1978). In current oilfield steam generator design, radiant heat fluxes in the 15,000-20,000 Btu/ft2-hr range are conventional, with corresponding flue gas temperatures (exiting the radiant section) of 1550-1730 F.

As shown in Fig. 7-17, the effectiveness of radiant tubes in absorbing energy from the flame varies significantly with the specific radiant coil configuration used. In modern practice, it is conventional to arrange a single row of radiant tubes with a (center-to-center spacing; tube nominal diameter) ratio of 2. The figure indicates an absorption effectiveness of about 67% for this arrangement as compared to a black body. A staggered double row of radiant tubes would reduce the radiation escaping to the refractory, but would result in a heat flux on the front row of tubes roughly 2.4 times as high as that on the secondary row. Thus, the second row of tubes is highly inefficient as heat transfer surface and is seldom used.

Of importance to the designer is the uniformity of heat distribution to the radiant tubes, because any heat flux above the average results in an increase in both tube wall temperature and the possibility of total vaporization of the liquid film at the

254

W

3 + m

+ u W

U W

a 2 W LT ow

0 ROW

0 2 3 4

TUBE SPACING TO D I A M E T E R R A T I O

Fig. 7-17. Relative effectiveness of different tube arrangements in radiant heat absorption. (After Sutherland, 1961; courtesy of the American Institute of Chemical Engineers.)

point of maximum heat input intensity. Radiant tubes fired from one side in an end-fired steam generator are subject to both peripheral and longitudinal variations in heat flux. Table 7-VIII illustrates the approximate peripheral heat flux distribution for the following coil arrangement:

(1) center-to-center spacing of tubes is two times the nominal tube diameter; (2) tubes are exposed to direct radiant heat from only one side; and (3) distance from radiant tube centerline to the refractory is one nominal tube

diameter. As shown in Table 7-VIII, the front of a tube facing the flame envelope receives

all of its heat by direct radiation, whereas the back portion of the tube receives all of its heat by reradiation from the refractory. According to Table 7-VIII, which is based strictly on radiation theory, the front face of the tube would receive 3.2 times the amount of heat which is transferred to the back face of the tube. In actual practice, this variation in heat flux is significantly reduced because of heat conductance from the front to the back of the tube through the tube wall, and by the turbulence of the flowing stream. Nevertheless, it is important that the variation in peripheral heat distribution be recognized so that excessively high tube metal

255

TABLE 7-VIII

Peripheral heat flux distribution for radiant tubes 13233,4

Point No. Peripheral heat distribution ratio

Direct Reradiation Total

1 1 .oo 0 1 .oo 2 0.918 0 0.918 3 0.676 0.027 0.703 4 0.336 0.115 0.451

5 6 7 8

9 10 11 12

0.080 0 0 0

0.080 0.336 0.676 0.918

0.232 0.315 0.342 0.315

0.232 0.115 0.027 0

0.312 0.315 0.342 0.315

0.312 0.451 0.703 0.918

’ Point No. locations are shown in Fig. 7-15. Center-to-center spacing of tubes is two times the nominal tube diameter. Tubes exposed to direct radiant heat from one side only. Tube centerline is spaced 1.5 nominal tube diameters from the refractory.

temperatures are not experienced on the front face of the tubes. The peripheral heat distribution problem is particularly severe in waterwall steam generator designs in whch all of the radiant heat is adsorbed on the front face of the tubes exposed to the flame envelope.

Most oilfield steam generators are fired from one end only, which introduces a longitudinal variation in heat flux over the length of the radiant tubes. With present burner designs incorporating two-stage combustion to reduce NO, formation, and with burners designed to produce relatively long, small-diameter flames, the maximum longitudinal heat flux is achieved at about 45% of the horizontal tube length as measured from the burner end. For this reason, the ratio of radiant coil diameter to radiant tube length is important in minimizing the longitudinal variation in heat flux. The first several feet of the flame envelope has relatively low radiation intensity until combustion is complete and the temperature of the flame envelope has been reduced by the heat extracted by the radiant tubes, with a resulting lower thermal driving force to transfer heat to the radiant tubes. It is recommended that the ratio of radiant tube length to coil diameter should not exceed 4 to 1 for oilfield steam generators fired from one end only.

In a well-designed oilfield steam generator, the maximum local heat flux in the radiant section should not exceed the average heat flux by more than 78%. This percentage represents the combined variations in both peripheral and longitudinal heat flux distributions. The susceptibility of the steam generator to total vaporization of the liquid film and resultant deposition of solids must be evaluated on the

256

basis of the maximum point heat flux calculated for the specific design under consideration.

The heat release in Btu/ft3-hr acheved in the radiant section is also an important consideration in the design of successful oilfield steam generators. The heat release is calculated as follows:

A E X V

H = - (7-11)

where: H = heat released per unit of combustion volume, Btu/ft3-hr; A = total heat absorption for whch the steam generator is designed, Btu/hr; E = net thermal efficiency of the steam generator, %; and V = combustion volume measured inside the radiant coil, ft3.

The heat release represents an experience factor for evaluating the suitability of a radiant section for a given performance. It is both a measure of the longitudinal heat flux distribution, which will be achieved, and the susceptibility of the design to direct flame impingement on the radiant tubes. Experience has shown that heat release values of 15,000-42,000 Btu/ft3-hr are satisfactory for oilfield steam generators, provided the limitation of radiant coil diameter to radiant tube length of 4 to l is also observed.

Radiant tubewall temperature The tubewall temperature experienced in the radiant section of an oilfield steam

generator is a function of the rate of heat absorption from the flame, the thickness of the tubewall, and the rate of heat removal by the water or steam-water mixture flowing inside the tube. The rate of radiant heat absorption is a function of flame temperature, radiation characteristics of the fuel, tubewall temperature, and physical location of the tube with respect to the flame envelope. In order to calculate the maximum tubewall temperature, it is essential to use maximum local heat flux.

The maximum outside tube skin metal temperature may be determined as follows:

R h

AT, = -

R x t A T - -

2 - K ,

(7-12)

(7-13)

and

R X f

= Kr (7-14)

251

Fig. 7-18. View of a pyramid-type convection section installed horizontally to reduce unit height. (Courtesy of Struthers Thermo-Flood Corporation.)

where: AT, = temperature rise across the tube side fluid film, O F ;

AT, = temperature rise across the tubewall, F; AT, = temperature rise across the scale, F; R h = film coefficient of the water or water-steam mixture corrected to the

r = tubewall thckness, in.; K , = thermal conductivity of tube, Btu/ft2-hr- O F-in.; f = scale thickness on tube wall, in.; and Kf = thermal conductivity of the scale, Btu/ft2-hr- O F-in.

The three temperature rises as calculated above are added to the main body temperature of the flowing stream to give the maximum outside tubeskin temperature.

It is obvious from the above formulas that the rate at which heat is removed from the tube is an important factor in establishing the maximum tubewall temperature.

= maximum point heat flux, Btu/ft*-hr;

outside tube diameter, Btu/ft2-hr- F;

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TABLE 7-IX

Thermal conductivity of metals ' (Courtesy of TEMA Standards, 6th ed., 1978)

Temperature Thermal conductivity (Btu/ft2-hr- F-in.)

(OF) Steel Carbon- 1% Chrome- 2-1/4% Chrome- 1/2% MO 1/28 MO 1% MO

200 300 400

500 600 700

800 900

360 348 324 348 336 324 336 324 312

324 312 300 312 300 288 300 300 288

288 288 276 216 216 252

300 288 216

276 264 264

252 252

~~ ~~

' Use values of 8-12 for thermal conductivity of scale or deposited solids.

I t is for this reason that a once-through oilfield steam generator, with a high volumetric percentage of steam in the radiant coil, requires a much more conservative radiant section design than do conventional boilers with high water recirculation ratios. The effect of any significant solids deposition on the tubewall temperature also becomes apparent from the above formulas. Table 7-IX shows thermal conductivities for typical tube materials used in oilfield steam generators.

Convection section design Most oilfield steam generator designs currently available incorporate convection

sections to improve the overall thermal efficiency of the steam generators. Inlet feedwater temperatures vary from 60 to 210"F, depending on whether or not produced water is used and the type of water treatment employed. In any event, the inlet feedwater temperature is generally at a sufficiently low level to allow efficient heat recovery in the convection section without resorting to the preheating of combustion air.

Most convection sections are of the cross-flow, straight-tube type with several rows of bare shock tubes followed by multiple rows of extended surface tubes. The two conventional types are (1) a rectangular design of uniform cross-section designed to produce a uniform flue gas mass velocity, and (2) a tapered design of variable cross-section designed to produce essentially a uniform linear velocity through the convection section. The latter design, classified as a tapered or pyramid convection section, has been proven in extensive field testing to increase the length of time between cleanouts of the convection section when firing the steam generators with the heavier crude oils (see Fig. 7-18).

In the case of steam generators fired with heavy crude oils, metallic salts contained in the crude oil and soot, which is formed in the combustion process, tend to accumulate on the convection tubes, gradually reducing the heat transfer. Thus, a

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TABLE 7-X

Estimated flue gas dewpoints ' (after Monrad, 1932)

Sulfur content SO, in flue gases SO3 content Estimated flue gas (wt %) ( P P 4 iwt dewpoint ( F)

0.1 0.25 0.5 0.75 1.00 1.50 2.00 2.50 3 .oo

3.86 9.65

19.29 28.94 38.58 57.87 77.16 96.45

115.74

0.00039 0.00097 0.00193 0.00289 0.00386 0.00579 0.00772 0.00965 0.01157

247 263 274 283 288 296 303 307 310

' Table is based on the use of 10% excess air for combustion and 2.5% of the sulfur being converted to so,.

convection section whch cools the flue gases to 400 O F when it is clean, may only cool the flue gases to 600-650°F after 8-10 weeks of full-load operation. It has become conventional practice in California to shutdown a steam generator when the exit flue gas temperature reaches the 600°F level, in order to water wash it for a period of several hours to clean the outside of the tubes. The pyramid convection section has been shown to increase the time between water washngs by roughly 60% over that required for a uniform cross-section design; however, it does require a higher draft loss and increased combustion blower horsepower.

When oilfield steam generators are fired with sulfur-bearing oils, it is essential to design the convection sections in such a manner that no metal surfaces are below the dew point of the SO,-bearing flue gases. In typical oilfield steam generators, about 3.5% of the sulfur in the fuel is converted into SO, during the combustion process. The presence of SO, in the flue gases sharply elevates the flue gas dew point over that which would be experienced with no sulfur in the fuel. Table 7-X shows calculated flue gas dew points with various concentrations of SO,. Because of the dew point elevation problem, when firing with sulfur-bearing fuels, most oilfield steam generators are provided with feedwater preheaters designed to preheat feedwater to at least 200 OF. This is accomplished by exchanging heat between water at some intermediate point in the convection section and the feedwater in a double-pipe heat exchanger.

Steam generator thermal efficiency The thermal efficiency of an oilfield steam generator is determined by dividing

the total heat added to the feedwater between the steam generator inlet and outlet nozzles by the heat released by the burner. The heat used in preheating the fuel oil and in generating atomizing steam for the burner is lost as far as energy transferred to the feedwater is concerned, and should not be included in the efficiency

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Fig. 7-19. Chart for approximate determination of oilfield steam generator heating requirements.

calculation. Similarly, the heat lost from the steam generator to the atmosphere should not be included in the net steam generator thermal efficiency determination. Relationship between the enthalpy and steam quality is presented in Fig. 7-19.

It has become standard practice to specify the thermal efficiency of oilfield steam generators on the basis of the lower heating value (LHV) of the fuel. Figures 7-20 and 7-21 show the relationships between the oilfield steam generator net thermal efficiency and flue gas temperature for typical gas and oil fuels at two different excess air ratios. An allowance of 1.5% for the steam generator radiation loss to the atmosphere has been included in the natural gas chart. An allowance of 1.75% for (1) the steam generator radiation loss to the atmosphere, (2) the heat required to preheat the fuel oil, and (3) the heat necessary to generate the fuel oil atomizing steam, has been included in the fuel oil chart. Most oilfield steam generators are designed for operation with 10% excess air and a stack temperature of about 400°F with a clean convection section. The heat loss from bare pipe to the atmosphere in still air, with wind velocity correction factor, is shown in Fig. 7-22.

Feedwater deaeration In order to prevent corrosion of the tubing, it is recommended that feedwater to

once-through oilfield steam generators be deaerated to reduce the oxygen content

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92

91.

90

89

5 88

i

w u 8 7

2 86

U

85

4

: 8 4

I

t- W

t- 8 3

82

81

8 C

79

7E

Fig. 7-20. Relationship between the thermal efficiency and flue gas temperature of natural gas-fired steam generators. The efficiency is based on the lower heating value (LHV) of the gas, and includes an allowance of 1.5% for steam generator setting loss to the atmosphere.

down to less than 0.01 ppm. Both chemical oxygen scavenging and steam deaeration have been used successfully to remove dissolved oxygen from the feedwater. Selection of the deaeration method to be used generally is dictated by the size of the steam injection project and by personal preference.

Two-phase pressure drop Most once-through oilfield steam generators are designed for a substantial

tube-side pressure drop of between inlet and outlet nozzles varying between 100 and 300 psi, depending on the size of steam generator. The high pressure drop is a result of the relatively high two-phase flow velocities for which this type of steam generator is designed in order to ensure good heat transfer and adequate cooling of the tubewalls. Figure 7-3 allows the approximate determination of pressure drop of 85%-quality steam flowing in tubes. About 90% of the pressure drop through a once-through oilfield steam generator is experienced in the two-phase flow region.

Steam quality measurement instrumentation The development of the once-through, 80%-quality steam generator produced a

need for a convenient and rapid method of determining the quality of the steam

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Fig. 7-21. Relationship between the net thermal efficiency and flue gas temperature of oil-fired steam gcnerators. The efficiency is based on the lower heating value (LHV) of the oil, and includes an allowance of 1.5% for steam generator setting loss to the atmosphere.

0 100 200 300 400 500 600 700 800

TEMPERATURE DIFFERENCE BETWEEN PIPE WALL AND AMBIENT A I R , O F

Fig. 7-22. Heat loss from bare pipe to the atmosphere in still air with wind velocity correction factor.

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whch is being produced by the steam generator. The need was particularly critical because exit steam quality determination is the principal guide for the operator in establishing the burner firing rate in relationship to the feedwater flow rate.

The primary method, which has been in use since the early 1960's for measuring steam quality on oilfield steam generators, has been the determination of the increase in salinity of the water. A small separator is used to remove a sample of liquid from the steam-water mixture leaving the steam generator. The sample is cooled before it is depressurized so as to prevent flashing and additional concentration, and then its conductance is measured by a standard salinity meter. By comparing the conductance of the sample removed from the steam generator outlet with the conductance of the feedwater, one can immediately establish the increase in salinity which has occurred. A fivefold increase in salinity would indicate 80%-quality steam.

In recent years, advanced continuous steam quality measurement systems utilizing microprocessors have been developed and are in commercial use. Figure 7-23

DUST PROOF CONSOLE

1 I C AL I E R ATORS

r - - - - - - - I

STEAM GENERATOR SYSTEM FT FLOW T R A N S M I T T E R - STEAM QUALITY MEASUREMENT SYSTEM PT PRESSURE T R A N S M I T T E R

A+- A I R S I G N A L P/A P R E S S U R E / A N A L O G CONVERTER

* D I G I T A L S I G N A L A / D ANALOG-TO/FROM-DIGITAL CONVERTER

.+Ir- O R I F I C E ASSEMBLY

P/A D IFF E R E N T I A L PRESSURE -TO -AN A LOG ANALOG S I G N A L

Fig. 7-23. A typical continuous steam quality measurement system for 50- to 85%-quality steam.

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shows the arrangement of such a system. The quality measurement is made by determining the two-phase flow pressure drop across a calibrated orifice plate in accordance with field test data established by Collins and Gacesa (1971). The microprocessor is programmed to correct for variations in steam pressure and temperature. The microprocessor can also be programmed to perform a number of control functions based on the continuously measured steam quality. A number of larger steam injection projects in the United States and Canada are now using this arrangement for continuous steam quality measurement.

Low -NO, burners The increasingly more stringent limitations on emissions of oxides of nitrogen

being implemented in the United States have forced oilfield steam generator manufacturers to develop techniques whereby the units will perform satisfactorily with significantly reduced NO, emissions. The problem of reducing NO, emissions is particularly difficult when burning heavy crude oil with a high fixed nitrogen content.

Several methods have been used to reduce NO, emission levels by oilfield steam generators:

(1) Ammonia injection into the flue gases leaving the radiant section of a steam generator.

(2) Use of improved excess air control systems to reduce oxygen levels in flue gas to between 1.0 and 1.5%.

(3) Flue gas recirculation to reduce the flame temperature. (4) Catalytic conversion of NO, to free nitrogen and water. ( 5 ) Utilization of two-stage combustion burners designed to operate in a reduc-

ing mode, followed by final oxidation of the fuel to complete the combustion. Conventional oilfield steam generators without any provisions for NO, reduction

and firing crude oil with up to 0.8% fuel-bound nitrogen will produce flue gases containing 225-380 ppm of NO,. With any of the above methods, NO, emissions in the flue gases can be reduced to 125 ppm or lower.

At the present time, the most widely used method for reducing oilfield steam generator NO, emissions is the recently developed low-NO, burner as supplied by several burner manufacturers. The low-NO, burner is designed to perform the combustion in two stages. The first stage of combustion is performed in a reducing or neutral atmosphere in order to decrease NO, formation. The combustion is then completed in a second stage, following the introduction of additional air to increase the oxygen level in the flue gases to between 1.0 and 1.5%.

Feedwater treatment

Whereas once-through oilfield steam generators can accept feedwater of much lower overall quality than would be considered suitable for use in conventional high-pressure power boilers, there are still certain quality requirements which must be met in order to insure satisfactory operation. Feedwater treatment procedures

265

have become particularly important in recent years, because oilfield steam generators have been required to operate on produced or recycled water which has been pumped out of producing wells with the oil and then separated from the oil. The trend toward the use of produced water as feedwater for oilfield steam generators has been accelerated for two reasons:

(1) Many steam injection projects are located in relatively arid areas where high volumes of feedwater are not available.

(2 ) The difficulty of disposing of high-salinity brines which are separated from the crude oil.

As steam is injected into a formation and condenses upon flowing through it, the condensate leaches solids out of the formation and builds up a heavy concentration of total dissolved solids. It is estimated that the average concentration of total dissolved solids in the feedwater of oilfield steam generators currently in use in California, U.S.A., may be in excess of 3500 ppm, with some steam generators operating on feedwater containing as hgh as 7500 ppm of total dissolved solids. Several factors must be considered in preparing feedwater for use in oilfield steam generators.

Turbidity of feedwater Suspended solids such as clays, silt, and corrosion products may be present in the

feedwater. These suspended solids may foul the ion exchange water softener, or may bake on the tubes of the steam generator giving rise to a film having a resistance to heat transfer. In order to avoid operating problems, the feedwater to an oilfield steam generator must be free of turbidity. Removal of suspended solids is typically accomplished by settling, coagulation, and filtration.

Oil content Any significant oil content in the oilfield steam generator feedwater can lead to

tube failure as a result of the oil forming a hard asphaltic scale on the tubewall and retarding heat transfer to the water-steam mixture. In addition, oil can be especially troublesome in the fouling of the ion exchange resins used in the water softeners.

Oil is a likely contaminant in produced water or any oilfield waste water which may be used as a steam generator feedwater. Generally, its removal requires skimming and filtration with coagulation. If anthracite filters are used, they will probably have to be frequently backwashed with hot caustic to prevent excessive fouling. Regardless of the oil removal procedure used, maximum reliability in steam generator performance requires that the oil content of the feedwater must not exceed 1-2 ppm.

Dissolved gases in feedwater Dissolved gases such as oxygen or hydrogen sulfide can be extremely corrosive at

the high metal temperatures at which oilfield steam generator tubes operate. Oxygen may be removed by steam deaeration or by using scavenging chemicals such as sodium sulfite and hydrazine. In certain instances, oilfield steam generator oper-

266

ators are deaerating the feedwater with steam, followed by the addition of chemical scavenging agents to remove the residual traces of oxygen. It is recommended that the oxygen content of the feedwater must not exceed 0.01 ppm in order to prevent corrosive attack of the tubes.

If hydrogen sulfide is present in the feedwater, it is generally removed in a steam deaeration step. If steam deaeration is not used, then chlorination of the feedwater may be used to reduce the hydrogen sulfide content of the feedwater.

Alkalinity I of feedwater The alkalinity of the feedwater, which is primarily the result of the presence of

carbonates, may be influenced by the addition of hydroxides and sulfites. Although excessive hydroxide alkalinity can contribute to caustic embrittlement, moderate alkalinity levels help control corrosion and serve to maintain silica solubility. At temperatures at which most oilfield steam generators operate, carbonates and hydroxides are deposited forming scale in the presence of Ca2+ or Mg2+ or other divalent cations such as Sr2+ and Ba2+.

Silica content in feedwater The principal problem associated with silica in once-through 80%-quality steam

generators consists of maintaining its solubility in the water. Silica solubility is strongly influenced by the alkalinity of the feedwater. The alkalinity level in ppm should always be maintained at a minimum of three times the silica content of the feedwater. Satisfactory oilfield steam generator performance with silica contents up to 200 ppm is possible in the absence of scaling ions.

Metal contaminants in feedwater Iron is frequently present in steam generator feedwater in the reduced (ferrous)

soluble form. Aluminum and manganese are sometimes present in small amounts. These constituents are similar to the hardness ions (Ca2+ and Mg2+) in the problems that they can create in a once-through oilfield steam generator. They will precipitate to form hydroxide scale at the high pH of feedwater, and will also combine with the silica to form silicate scale.

The metallic contaminants may also be present in the feedwater as the insoluble hydrous oxides, which may deposit on the tubewalls of the steam generator. The hydrous oxides may also coat the resins used in the ion exchange water softeners. These constituents should be removed from the feedwater to the lowest practical limit.

p H of feedwater Acceptable oilfield steam generator operation has been obtained at feedwater pH

levels of 7-12. Lower values could lead to acidic corrosion. whereas values to 13 or

The alkalinity is defined as the total content of the bicarbonate, carbonate, and hydroxide ions.

261

above indicate excessive hydroxide alkalinity with both caustic corrosion and possible caustic embrit tlement.

Total hardness of feedwater The basic design concept of the once-through, 80%-quality steam generator is

based on the use of feedwater having less than 1 ppm of hardness '. All of the solids (TDS) must be fully soluble in the feedwater, and must remain fully soluble in the residual liquid after 80% of the feedwater has been converted to steam. This type of steam generator is capable of handling feedwater with a very high total dissolved solids content as long as the solids are in a form which will not deposit on the walls of the steam generator tubes.

The most widely used feedwater softening method for steam injection applications is ion exchange by which calcium and magnesium ions are replaced by sodium ions. Most ion exchange water softeners consist of two sets of primary and polishng softeners, with one set operating and one set either in the process of being regenerated with brine or in ready standby condition. Ion exchange water softeners have the ability to remove all positively-charged ions (cations). T h s type of water softener is capable of handling feedwater with up to approximately 6000 ppm of total dissolved solids without requiring excessive regeneration.

When feedwaters containing between 6000 and 10,000 ppm total dissolved solids are to be used in once-through, 80%-quality steam generators, it is normal practice to use ion exchange softeners followed by carboxylic softeners in order to reduce the hardness to 1 ppm. The high cost of acids or caustic required to regenerate the resins used in a carboxylic softener, can be significantly reduced by removing much of the hardness in ion exchange softeners. If the feedwater contains in excess of 10,000 ppm of total dissolved solids, it becomes almost mandatory to use only the carboxylic softeners.

Flue gas scrubbers

Many once-through, 80%-quality oilfield steam generators are fired with sulfur- bearing crude oil, and the sulfur in the fuel is converted to sulfur dioxide and sulfur trioxide in the combustion process. In areas such as California, U.S.A., where strict flue gas emissions regulations are in effect, means must be provided to reduce the content of sulfur compounds before the flue gases can be released to the atmosphere (see Fig. 7-24).

A typical 50 MMBtu/hr oilfield steam generator fired with crude oil containing 1.1% by weight of sulfur will consume 3247 lb/hr of fuel having a lower heating value of 17,500 Btu/lb. The 35.72 lb of sulfur contained in the fuel will be converted to approximately 69.3 lb/hr of SO, and 2.68 lb/hr of SO,. If the unit is operated at 10% excess air, the combustion would produce 52,926 lb/hr of flue

' Hardness is defined as the total content of the calcium and magnesium ions present in the water.

268

Fig. 7-24. A 50-MMBtu/hr oilfield steam generator burning high-sulfur crude oil and provided with a horizontal flue gas scrubber. (Courtesy of Struthers Thermo-Flood Corporation.)

gases, and the concentration of SO, compounds in the flue gases would be 1360 PPm-

After sulfur dioxide has been discharged to the atmosphere, it can quickly oxidize to sulfur trioxide and produce “acid rain”, which is, a primary environmental concern. In addition, sulfur dioxide has an adverse effect on the respiratory system and on plant life, even prior to its conversion to sulfur trioxide. For this reason, flue gas scrubbers must be used in conjunction with oilfield steam generators, which are fired with sulfur-bearing fuels and are located in areas where stringent emission standards are in effect.

A number of flue gas scrubber designs are in use on oilfield steam generators in California, U.S.A., where stringent SO, emission limits are in effect. One design involves the use of a double-alkali-solution to absorb the sulfur compounds from the flue gases and produce water-soluble reaction products. This type of system utilizes either sodium hydroxide or soda ash as the makeup chemical, and then uses slaked lime [Ca(OH),] in a secondary reaction loop to precipitate calcium sulfite dihydrate (CaSO, .2H,O) while simultaneously regenerating the absorption solu-

269

Fig. 7-25. View of multiple 50-MMBtu/hr oilfield steam generators having stacks manifolded into a common flue gas duct and discharging into a single flue gas scrubber. (Courtesy of Struthers Thermo-Flood Corporation.)

tion. Because of the relatively hgh capital cost associated with the secondary chemical reactor, the slaked lime handling equipment, and the vacuum filtration system necessary to operate a double-alkali process, this type of scrubber normally can be justified only when multiple oilfield steam generators are manifolded together to produce a large single source of SO, (Fig. 7-25).

Where sulfur dioxide sources of possibly less than 12,000 lb/D are available, it becomes economically more attractive to use a non-regenerative type of scrubbing system, utilizing either soda ash or sodium hydroxide as the makeup chemical. This type of system is operated in almost the same manner as the absorption step in the double-alkali process. Rather than regenerating the liquid from the scrubbing process, however, the spent liquid is simply discarded. T h s minimizes the capital cost and the amount of operator attention required. The operating costs for the non-regenerative scrubbing system often become much lower than would be the case with double-alkali systems. Such systems are used extensively for all but projects having a large concentration of oilfield steam generators in one area.

The maximum theoretical sulfur dioxide removal efficiency for any given flue gas scrubbing system is dictated by the partial pressure of sulfur dioxide over the scrubbing solution at an equilibrium temperature lying between that of the scrubbing liquid and that of the saturated gas stream. As an example, if the content of

270

sulfur dioxide over a given scrubbing solution is 30 ppm by volume, and the scrubbing unit is mechanically capable of achieving true equilibrium conditions between the gas and the liquid at its discharge, it would be possible to achieve 90% collection efficiency or greater only with an inlet sulfur dioxide concentration of not less than 300 ppm by volume. In other words, the sulfur dioxide concentration in the exit gases is established by the equilibrium conditions for the system, and the sulfur dioxide removal efficiency becomes simply a function of the sulfur dioxide concentration in the gases entering the scrubber.

Low-temperature economizers

The minimum exit flue gas temperature from an oilfield steam generator is primarily a function of the flue gas initial dew point. For steam generators fired with sulfur-bearing fuels, the dew point may range from 260 to 340"F, depending on the sulfur content of the fuel and the percentage of excess air at which the burner is operated. Care must be exercised in the design of the steam generator convection section in that condensation can occur on metal surfaces which are colder than the flue gas initial dew point, even though the main body flue gas temperature is well above the dew point. For this reason, most oilfield steam generators, which are fired with sulfur-bearing crude oil, are designed for flue gas temperatures of 400°F entering the stacks (see Fig. 7-26).

Fig. 7-26. View of a 50-MMBtu/hr oilfield steam generator with a low-temperature convection section discharging into a horizontal flue gas scrubber. (Courtesy of Struthers Thermo-Flood Corporation.)

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The rapidly escalating cost of fuels has generated a considerable interest in increasing the net thermal efficiency of oilfield steam generators by extracting more heat from the flue gases before they are discharged to the atmosphere. As a result, a low-temperature economizer designed to cool the flue gases to within about 50 OF of the inlet feedwater temperature is commercially available, and a number of such units are in successful operation of oilfield steam generators in California, U.S.A.

The low-temperature economizer is designed to cool SOx-bearing flue gases well below the dew point, and is of alloy or plastic coated steel construction to resist the corrosive action of the acidic condensate. Field tests have shown the condensate to have a pH of approximately 2.4. The low-temperature economizer is so arranged that acid condensate cannot drain back into the regular convection section of the steam generator which is provided with carbon steel tubes. The low-temperature economizer can be provided as an integral component of a new oilfield steam generator, or can be added on to an existing steam generator.

If an oilfield steam generator is fired with 15O-API crude oil having a lower heating value of 17,500 Btu/lb and the burner is controlled to 10% excess air, the net thermal efficiency of the steam generator with a 400 O F stack temperature would be about 9096, based on the lower heating value of the fuel. If the flue gases are further cooled to 150 O F by a low-temperature economizer, the steam generator net thermal efficiency would be increased by approximately 6%.

The use of a low-temperature economizer also has the following advantages when the system incorporates a flue gas scrubber:

(1) Reduction in scrubber size, as cooling of the flue gases results in their volume reduction.

(2) Significant reduction in the amount of scrubber water, lost as vapor in the flue gases leaving the scrubber as a result of removal of the temperature quenching burden placed on the scrubber by 400 O F gases.

(3) Reduction in the SO, concentration in the flue gases entering the scrubber.

High-temperature thermal packers

A packer is designed to seal the annulus between the injection tubing and the casing at a point immediately above the zone where steam is introduced into the oil-bearing stratum. The function of the packer is to prevent the escape of steam and oil vapors to the atmosphere through the annulus.

Packers are required to be expandable when they are properly positioned so that they may form a relatively tight seal against both the casing and the steam injection tube. They must also be collapsable, so that they may be opened and the injection tube withdrawn. The use of high-temperature and high-pressure steam as required on the deeper wells, ranging from 2500 to 5400 ft in depth, has forced the development of thermal packers capable of withstanding the much more severe operating conditions to which they may be exposed. Several satisfactory designs are currently available for the higher-temperature applications.

212

Casing vent systems

In a typical steam displacement installation, steam breakthrough occurs in six to twelve months after the initiation of steam injection. This phenomenon results from the channeling of high-pressure steam (injected into the oil-bearing formation) through the intervening strata to a producing well. With the breakdown of steam flow resistance between injector and producer wells, pressures as high as 30 psig may be developed in the producing well casing. This pressure has the undesirable effect of inhibiting the flow of reservoir fluids into the wellbore, thereby decreasing oil production. Producers have resolved the casing pressure buildup problem in the past by simply opening the casing valve, and venting the continuous vapor flow into the atmosphere.

In recent years, it has become common practice to install casing vent gathering systems on steam injection projects for two basic reasons:

(1) Vapors vented from a well casing are typically composed of 95% steam and 5% condensible hydrocarbons. The light hydrocarbons present in a casing vent system represent considerable value and justify recovery.

(2) Increasingly stringent emission regulations restrict the release of significant volumes of hydrocarbon vapors to the atmosphere.

The most cost-effective technique for recovery of the hydrocarbon vapors is to collect them in a piping system and condense them at a central point. In many respects, a casing vapor recovery system is similar to a natural gas gathering system. The basic concept of moving a gas through piping by utilizing the wellhead pressure is identical. There are, however, certain factors peculiar to casing vent collection systems which distinguish them from other piping networks.

Casing vent collection piping is normally laid directly on the ground because there is no need for insulation. In laying out the piping system, low spots in which condensate can accumulate should be avoided. Condensate accumulation in low spots can restrict the carrying capacity of the piping system, and undulations exceeding ten feet, in which condensate can collect, may actually create an undesirable backpressure on the casing. A preferred arrangement is to provide gas-liquid separators at the low points in the pipeline system, and then to carry the piping on a continuous uphill grade to the highest point in the system where the condensers should be located. With this type of arrangement, condensate flows continuously downhill to the vapor-liquid separators countercurrently to the vapor flowing from the wellheads to the condensing equipment.

Either air-cooled or water-cooled condensers may be used for this service. Where the steam generator feedwater is at a sufficiently low temperature, it makes an ideal coolant for the casing vent condensers.

Downhole steam generators

The application of the steam injection technique for enhanced oil recovery to wells over 2500 ft in depth has recently received increasing consideration. One

273

TORCH IGNITOR , TL ,AIR

S T E A M AND PRODUCTS OF C O M B U S T I O N

Fig. 7-27. Typical downhole steam generator.

concern relative to injection of steam in deep wells is the high rate of heat loss from the injection tubing to the subsurface strata. One solution to the deep well heat loss problem is to use surface oilfield steam generators in conjunction with insulated downhole tubing. This arrangement is in commercial use and has proven successful.

Recently, a large development effort has been concentrated on the production of a downhole steam generator which can produce steam near the point where it is injected into the formation and thus avoid the heat losses when transporting steam from the surface to a depth of several thousand feet (see Fig. 7-27). Two basic downhole steam generator designs have evolved from this development effort:

(1) A design in which the steam and products of combustion are intimately mixed and injected into the formation.

(2) A design in which the steam and products of combustion are kept separate, with the steam being injected into the formation and the products of combustion being transported to the surface and discharged into the atmosphere.

Whereas some experimental work has been performed using downhole steam generators to inject steam into actual wells, there are at this time no installations

214

which can be considered commercial. Of the two basic designs, the one in which the steam and the products of combustion are intimately mixed appears to be the more promising.

At the present time, there appears to be a number of economic and operational drawbacks to downhole steam generators, which may be partially or totally resolved with continuing development work.

(1) Need for expensive fuels such as natural gas, naphtha, or light oil. (2) Both fuel and combustion air or oxygen must be compressed to the injection

pressure, which requires a very large horsepower for the compressors, particularly at injection pressures of 2000-2500 psia.

( 3 ) The partial pressure reduction effect of the combustion products mixed with the feedwater would result in a steam temperature of 600 O F at 2500 psia generation pressure, or 68 F lower than the saturation temperature of steam at 2500 psia. This would reduce the thermal driving force for transferring heat from the steam to the formation.

(4) On cyclic injection projects, the downhole steam generator must be removed for each production cycle.

The downhole steam generator appears to show promise with a continuing development effort; however, at this time it does not appear to be either economically or operationally suitable for large-scale commercial use.

Solid-fuel-fired oilfield steam generators

The single highest operating cost on a steam injection project is the cost of the fuel to be burned in the steam generator to produce the injection steam. For example, a 50 MMBtu/hr oilfield steam generator operating 24 hr a day for 330 days per year would consume approximately 80,000 barrels of oil as fuel. Priced at $28 per barrel, the annual fuel cost would be in the range of $2,240,000.

In order to reduce the cost of generating injection steam, various designs of oilfield steam generators capable of using solid or waste liquid fuels have been under investigation for some time. One commercial 50 MMBtu/hr oilfield steam generator utilizing a circulating fluidized bed combustion system has been installed in the United States, and has operated successfully for approximately two years. The unit is installed on a tar sand project, and is generating 50,000 lb/hr of steam at 2240 psia (see Fig. 7-28).

The one solid-fuel-fired oilfield steam generator which is in operation has been successfully fired with lignite, coal, or petroleum coke. The unit incorporates two-stage combustion to reduce the formation of NO, and utilizes limestone addition for sulfur capture. It has fully met all environmental emission standards when burning any of the three fuels for whch it was designed.

The commercialization of solid- or waste liquid-fired oilfield steam generators has the potential of appreciably improving the economics of heavy crude oil or tar recovery by the steam injection process. This type of oilfield steam generator would

215

Fig. 7-28. A fluidized bed combustion steam generator designed to burn coal, lignite, or petroleum coke, and having a steam generating capacity of 50,000 lb/hr at 80% quality. (Courtesy of Struthers Thermo-Flood Corporation.)

appear to offer special advantages in applications where heavy crude oil or tar upgrading, with resultant production of petroleum coke, is performed in the producing fields before the crude is pumped to a refinery. The substitution of solid or waste fuels for the lease crude oil, conventionally burned in oilfield steam generators, not only provides a substantial saving in the cost of producing steam, but makes available all of the crude oil produced by the steam injection process to be refined into finished products, rather than necessitating the burning of roughly 30% of the produced crude oil to generate the injection steam.

This chapter has been designed to provide the reader with some of the basic fundamentals which are involved in the steam injection process as it is applied in the thermal enhanced recovery of viscous crude oils. The chapter also includes a discussion of the design parameters involved in equipment used in the processing of feedwater for oilfield steam generators and the steam generators used to produce the injection steam. An extensive bibliography has been included to permit the reader to investigate in greater depth any aspect of the subject matter in this chapter in which he may have a specific interest.

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SAMPLE PROBLEMS

(1) Determine the percentage of heat loss from the downhole tubing to the surrounding strata when injecting 12,000 lb/hr of 80%-quality steam at 1000 psia pressure through 1500 ft of 3.5-in. OD tubing installed in 6-3/4-in. ID by 7-3/4411. OD casing. Assume the average temperature of the earth over the full depth of the well to be 135 OF.

(2) Determine the heat loss from 2000 ft of 4-1/2-in. OD aboveground uninsulated transmission piping having 20,000 lb/hr of 80%-quality steam at 1500 psia pressure flowing through it. Assume an ambient air temperature of 90°F and a wind velocity of 15 mph. Also determine the quality of the steam at the end of the transmission piping.

(3) Determine the friction loss for 50,000 lb/hr of 85%-quality steam at 1500 psia pressure flowing through 1200 ft of 4-in. schedule 40 steel pipe. The pipe contains thirty 90 O short radius cells and ten 180 O short radius return bends.

(4) Determine the maximum point heat flux on a tube exposed to radiant heat and subjected to an average heat flux of 16,500 Btu/ft3-hr. Also determine the minimum point heat flux to which the same tube will be subjected.

(5) If a once-through steam generator is dual fuel fired with both natural gas and crude oil, determine the relative thermal efficiencies for each fuel if the excess air is 10% and the flue gas temperature is 380 OF for both fuels.

(6) Assuming a steam generator is fired with a crude oil containing 1.5% by weight sulfur and the excess air is controlled at lo%, determine the approximate dew point temperature of the flue gases.

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Wilson, L.R. and Root, P.J., 1966. Cost comparison of reservoir heating using steam or air. J. Pet. Technol., 18(2): 233-239.

Wimpress, R.N., 1963. Rating fired heaters. Hydrocarbon Proc. Pet. Ref., 42(10): 115-126. Wimpress, R.N., 1978. Generalized method predicts fired-heater performance. Chem. Eng., 85(12):

Wu, C.H., 1977. A Critical Review of Steamflood Mechanisms. SPE 6550, presented at SPE-AIME 47th

Yoelin, S.D., 1971. The TM sand steam stimulation project. J. Pet. Technol., 23(8): 987-994 (Trans.

95-102.

Annu. Calif. Reg. Meet., Bakersfield, Calif., Apr. 13-15, 8 pp.

AIME, 251).

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Chapter 8

CORROSION IN DRILLING AND PRODUCING OPERATIONS

T.A. BERTNESS, GEORGE V. CHILINGARIAN and MOAYED AL-BASSAM

INTRODUCTION

In 1978, the National Bureau of Standards reported to the U.S. Congress that the cost of corrosion in the U.S.A. in 1975 was 70 billion dollars plus or minus 30%, and that about 15% of this loss was avoidable. This economic loss represented about 4% of the gross national product.

The principles of corrosion must be understood in order to effectively select materials and to design, fabricate, and utilize metal structures for the optimum economic life of facilities and safety in operation.

Corrosion in various forms is the major cause of drillpipe failures which add significantly to drilling costs. The trends toward (1) drilling of deeper wells, (2) use of higher strength steels, (3) presence of higher stresses, and (4) use of lower pH drilling fluids contribute to increased susceptibility of metals to failure due to corrosion.

Corrosion is the principal cause of damage to metals in wells and production facilities. Corrosion damage results in costly maintenance of these facilities (repairs and replacements) and the loss of production.

Definition of corrosion

Corrosion is defined as the chemical degradation of metals by reaction with the environment. The destruction of metals by corrosion occurs by: (a) direct chemical attack at elevated temperatures (500+"F) in a dry environment, and (b) by electrochemical processes at lower temperatures in a water-wet or moist environment.

Corrosion attacks metals in drilling and producing operations through electrochemical processes in the presence of electrolytes and corrosive agents in drilling, completion, packer, and produced fluids.

CORROSIVE AGENTS IN DRILLING AND PRODUCING OPERATIONS

The components in fluids which promote the corrosion of steel in drilling and producing operations are oxygen, carbon dioxide, hydrogen sulfide, salts, and organic acids. Destruction of metals is influenced by various physical and chemical factors which localize and increase corrosion damage.

284

The conditions which promote corrosion include: (a) Energy differences in the form of stress gradients or chemical reactivities

(b) Differences in concentration of salts or other corrodants in the electrolytic

(c) Differences in the amount of deposits, either solid or liquid, on the metal

(d) Temperature gradients over the surface of the metal in contact with a

(e) Compositional differences in the metal surface.

across the metal surface in contact with a corrosive solution.

solutions.

surfaces, which are insoluble in the electrolytic solutions.

corrosive solution.

REQUIREMENTS FOR ELECTROCHEMICAL CORROSION

Corrosion continues provided electrically conductive metal and solution circuits are available to bring corrodants to the anodic and cathodic sites.

Four conditions must be present to complete the electrochemical reactions and corrosion circuit:

(1) Presence of a driving force or electrical potential. Difference in reaction potentials at two sites on the metal surface must be sufficient to drive electrons through the metal, surface films, and liquid components of the corrosion circuit.

( 2 ) Presence of an electrolyte. Corrosion occurs only when the circuit between anodic and cathodic sites is completed by an electrolyte present in water.

(3) Presence of both anodic and cathodic sites. Anodic and cathodic areas must be present to support the simultaneous oxidation and reduction reactions at the metal-liquid interface. Metal at the anode ionizes.

(4) Presence of an external conductor. A complete electron-electrolytic circuit between anodes and cathodes of the metal through (a) the metal surface films, (b) surrounding environment, and (c) fluid-solid interfaces is necessary for the con- tinuance of corrosion.

In the environment surrounding the metal, the presence of water provides conducting paths for both corrodants and corrosion products. The corrodant may be a dissolved gas, liquid, or solid. The corrosion products may be ions in solution, which are removed from the metal surface, ions precipitated as various salts on metal surfaces, and hydrogen gas.

ELECTROCHEMICAL CORROSION

The conditions needed to promote many types of corrosion can be found in most industrial facilities. The basic electrochemical reactions, which occur simultaneously at the cathodic and anodic areas of metal causing many forms of corrosion damage, are as follows:

(1) At the cathode, the hydrogen (or acid) ion (H+) removes electrons from the

285

cathodic surfaces to form hydrogen gas (H,): 2e- + 2H+ --j 2H0 -+ H, (in acidic solution). If oxygen is present, electrons are removed from the metal by reduction of oxygen: (a) 4e- + 0, + 4H+ + 2H,O (in acidic solution), and (b) 4e- + 2H,O + 0, + 40H- (in neutral or alkaline solution).

(2) At the anode, a metal ion ( e g , Fez+) is released from its structural position in the metal through loss of the bonding electrons and passes into solution in the water as soluble iron, or reacts with another component of the environment to form scale. The principal reaction is:

Thermodynamic data indicate that the corrosion process in many environments of interest should proceed at very high rates of reaction. Fortunately, experience shows that the corrosion process behaves differently. Studies have shown that as the process proceeds, an increase in concentration of the corrosion products develops rapidly at the cathodic and anodic areas. These products at the metal surfaces serve as barriers that tend to retard the corrosion rate. The reacting components of the environment may be depleted locally, which further tends to reduce the total corrosion rate.

The potential differences between the cathodic and anodic areas decrease as corrosion proceeds. This reduction in potential difference between the electrodes upon current flow is termed polarization. The potential of the anodic reaction approaches that of the cathode, and the potential of the anodic reaction approaches that of the anode. Electrode polarization by corrosion is caused by (1) changing the surface concentration of metal ions, (2) adsorption of hydrogen at cathodic areas, (3) discharge of hydroxyl ions at anodes, or (4) increasing the resistance of the electrolyte and films of metal-reaction products on the metal surface.

Changes (increase or decrease) in the amount of these resistances by the introduction of materials or electrical energy into the system will change the corrosion currents and corrosion rate.

A practical method to control corrosion is through cathodic protection, whereby polarization of the structure to be protected is accomplished by supplying an external current to the corroding metal. Polarization of the cathode is forced beyond the corrosion potential. The effect of the external current is to eliminate the potential differences between anodic and cathodic areas on the corroding metal. Removal of the potential differences stops local corrosion action. Cathodic protection operates most efficiently in systems under cathodic control, i.e., where cathodic reactions control the corrosion rate.

Materials may cause an increase in polarization and retard corrosion by absorbing on the surface of the metals and thereby changing the nature of the surface. Such materials act as inhibitors to the corrosion process. On the other hand, some materials may reduce polarization and assist corrosion. These materials, called depolarizers, either assist or replace the original reactions and prevent the buildup of original reaction products.

286

Oxygen is the principal depolarizer which aids corrosion in the destruction of metal. Oxygen tends to reduce the polarization or resistance, which normally develops at the cathodic areas, with the accumulation of hydrogen at these electrodes. The cathodic reaction with hydrogen ion is replaced by a reaction in whch electrons at the cathodic areas are removed by oxygen and water to form hydroxyl ions (OH-) or water:

0, + 2H,O + 4e- - 40H- (in neutral and alkaline solutions) (8-2)

and

0, + 4H' + 4e- + 2H,O (in acid solution) (8-3)

Polarization of an electrode surface reduces the total current and corrosion rate. Though the rate of metal loss is reduced by polarization, equipment failures may increase if incomplete polarization occurs at the anodes. For example, inadequate anodic corrosion inhibitor will reduce the effective areas of the anodic surfaces and thus localize the loss of metal at the remaining anodes. This will result in severe pitting and destruction of metal.

Resistances to the corrosion process generally do not develop to the same degree at the anodic and cathodic areas. These resistances reduce the corrosion rate, whch is controlled by the slowest step in the corrosion process. Electrochemical corrosion comprises a series of reactions and material transport to and from the metal surfaces. Complete understanding of corrosion and corrosion control in a particular environment requires knowledge of each reaction which occurs at the anodic and cathodic areas.

Components of electrochemical corrosion

The various components which are involved in the process of corrosion of metal are: (1) the metal, (2) the films of hydrogen gas and metal corrosion products, (3) liquid and gaseous environment, and (4) the several interfaces between these components. Metal is a composite of atoms which are arranged in a symmetrical lattice structure. These atoms may be considered as particles which are held in an ordered arrangement in a lattice structure by bonding electrons. These electrons, which are in constant movement about the charged particles, move readily throughout the lattice structure of metal when an electric potential is applied to the system. If bonding electrons are removed from their orbit about the particle center, the resulting cation will no longer be held in the metal's crystalline structure and can enter the electrolyte solution. Electrochemical corrosion is simply the process of freeing these cations from their organized lattice structure by the removal of the bonding electrons. Inasmuch as certain of the lattice electrons move readily within the metal under the influence of electrical potentials, the locations on the surface of the metal from which the cations escape and the locations from which the electrons

287

are removed from the metal need not be and generally are not the same. Corrosion will not occur unless electrons are removed from some portion of a metal structure.

All metals are polycrystalline with each crystal having random orientation with respect to the next crystal. The metal atoms in each crystal are oriented in a crystal lattice in a consistent pattern. The pattern gives rise to differences in spacing and, therefore, differences in cohesive energy between the particles, whch may cause preferred corrosion attack. At the crystal boundaries the lattices are distorted, giving rise to preferred corrosion attack. In the manufacture and processing of metals, in order to gain desirable physical properties both the composition and shape of the crystals may be made nonuniform, distorted, or preferably oriented. This may increase the susceptibility of the metal to corrosion attack. Undistorted single crystals of metals experience comparatively little or no corrosion under the same conditions which may destroy commercial pieces of the same metal. Compositional changes in metal alloy crystals and crystal boundaries, which are present in steels and alloys, can promote hghly localized corrosion.

CHEMISTRY OF CORROSION AND ELECTROMOTIVE FORCE SERIES

Oxidation takes place when a given substance loses electrons or a share of its electrons. On the other hand, reduction occurs when there is a gain in electrons by a substance. A substance that yields electrons to somethmg else is called a reducing agent, whereas the substance which gains electrons is termed an oxidizing agent. Thus, electrons are always transferred from the reducing agent to the oxidizing agent. In the example below, two electrons are transferred from metallic iron to cupric ion:

Feo + Cu2+ + Fe2+ + Cuo metallic cupric ferrous metallic

iron ion ion copper

(8-4)

The emf series is presented in Table 8-1; potentials given are those between the elements in their standard state at 25°C and their ions at unit activity in the solution at 25°C. A plus (+) sign for E o shows that, for the above conditions, the reduced form of the reactant is a better reducing agent than H,. On the other hand, a negative (-) sign indicates that the oxidized form of the reactant is a better oxidizing agent than H+. Thus, in general, any ion is a better oxidizing agent than the ions above it.

Actual electrode potentials

In the emf series, each metal will reduce (or displace from solution) the ion of any metal below it in the series, providing all of the materials have unit activities. The activity of a pure metal in contact with a solution does not change with the

288

TABLE 8-1

Electromotive force series

Electrode reaction Standard electrode potential,

Li = Li+ +e- + 3.05 K = K+ +e- + 2.922 Ca = CaZ+ +2e- + 2.87 N a = N a + + e - +2.712 Mg = Mg2+ + 2e- + 2.375 Be = Be2+ + 2e- + 1.85 A1 = A13+ + 3e- + 1.67 Mn = Mn2+ +2e- + 1.029 Zn = Znz+ +2e- + 0.762 Cr = c r 3 + +3e- + 0.74 Ga = Ga3+ + 3e- +0.53 Fe = Fez+ +2e- + 0.440 Cd = Cd2+ +2e- + 0.402 III = In3+ +3e- + 0.340 T1= Tlc + e- + 0.336 Co = Co2+ +2e- f0.277

+ 0.250 sn=Sn2++2e- +0.136 Pb = Pb2' + 2e- + 0.126

E o in Volts, 25°C

Ni = NiZ+ +2e-

H Z = 2 H + + 2 e - 0.000 cu = Cu'+ +2e- - 0.345 Cu = Cu+ + e- - 0.522 2Hg = Hgi+ + 2e- - 0.789 Ag = Ag+ +e- -0.800 Pd = PdZ+ + 2e- - 0.987 Hg = Hg2+ + 2e- - 0.854

Au = Au3+ + 3e- Au = Au+ +e-

Pt = Pt2+ +2e- ca. -1.2 -1.50 - 1.68

environment. The activity of an ion, however, changes with concentration, and the activity of a gas changes with partial pressure.

An electrode reaction, in which a metal M is oxidized to its ion M"+, liberating n electrons, may be represented by the relation: M = M"+ + ne-. The actual electrode potential of this reaction may be calculated from the standard electrode potential by use of the following expression:

RT E = E o - - In( M " + )

nF ( 8 - 5 )

where E = actual electrode potential at the given concentration (Volts), E o =

standard electrode potential (Volts), R = universal gas constant; 8.315 Volt

289

TABLE 8-11

Variation in actual electrode potentials of iron and cadmium with change in concentration of the ions

Reaction Activity (moles/kg water)

1 0.1 0.01 0.001

Actual electrode potential (Volts)

Fe=Fe2++2e- + 0.440 + 0.470 + 0.499 + 0.529 Cd = Cd2+ + 2e- + 0.402 + 0.431 + 0.461 + 0.490

Coulombs/"K, T = absolute temperature (OK), n = number of electrons transferred, F = the Faraday, 96,500 Coulombs, and M"+ = concentration of metal ions.

At 25"C, 3.303 RT/F = 0.05915 and the formula becomes:

The actual electrode potential for a given environment may be computed from the above relation. Table 8-11 shows how the actual electrode potentials of iron and cadmium vary with change in concentration of the ions.

It is apparent from Table 8-11 that iron will reduce cadmium when their ion concentrations are equal, but the reverse holds true when the concentration of cadmium ion becomes sufficiently lower than that of the ferrous ion.

It is well to note that the standard electrode potentials are a part of the more general standard oxidation-reduction potentials. Textbooks on physical chemistry also contain a general expression for calculating the actual oxidation-reduction potential from the standard oxidation-reduction potential.

GALVANIC SERIES

Dissimilar metals exposed to electrolytes exhibit different potentials or tendencies to go into solution or react with the environment. T h s behavior is recorded in tabulations in which metals and alloys are listed in order of increasing resistance to corrosion in a particular environment. Coupling of dissimilar metals in an electrolyte will cause destruction of the more reactive metal, which acts as an anode, and provides protection for the less reactive metal, which acts as a cathode.

CORROSION OF STEEL

In most corrosion problems, the important differences in reaction potentials are not those between dissimilar metals, but are those whch exist between separate areas interspersed over all the surface of a single metal. These potential differences

290

result from local chemical or physical differences within or on the metal, such as variations in grain structure, stresses, and scale, inclusions in the metal, grain boundaries, and scratches or other surface condition. Steel is an alloy of pure iron and small amounts of carbon present as Fe,C with trace amounts of other elements. Iron carbide (Fe,C) is cathodic with respect to iron.

Inasmuch as in typical corrosion of steel anodic and cathodic areas lie side by side on the metal surface, in effect it is covered with both positive and negative sites. During corrosion, the anodes and cathodes of metals may interchange frequently.

TYPES OF CORROSION

Numerous types of metal destruction can result from the corrosion process, which are listed under the following classes of corrosion:

(1) Uniform attack. The entire area of the metal corrodes uniformly resulting in thinning of the metal. This often occurs to drillpipe, but usually is the least damaging of different types of corrosive attacks. Uniform rusting of iron and tarnishing of silver are examples of this form of corrosion attack.

(2) Crevice corrosion. This is an example of localized attack in the shielded areas of metal assemblies, such as pipes and collars, rod pins and boxes, tubing, and drillpipe joints. Crevice corrosion is caused by concentration differences of a corrodant over a metal surface. Electrochemical potential differences result in selective crevice or pitting corrosion attack.

Oxygen dissolved in drilling fluid promotes crevice and pitting attack of metal in the shielded areas of a drillstring and is the common cause of washouts and destruction under rubber pipe protectors.

(3) Pitting corrosion. Pitting is often localized in a crevice but can also occur on clean metal surfaces in a corrosive environment. An example of this type of corrosion attack is the corrosion of steel in high-velocity sea water, low-pH aerated brines, or drilling fluids. Upon formation of a pit, corrosion continues as in a crevice but, usually, at an accelerated rate.

(4) Galvanic or two-metal corrosion. Galvanic corrosion may occur when two different metals are in contact in a corrosive environment. The attack is usually localized near the point of contact.

( 5 ) Intergranular corrosion. Metal is preferentially attacked along the grain boundaries. Improper heat treatment of alloys or high-temperature exposure may cause precipitation of materials or non-homogeneity of the metal structure at the grain boundaries, which results in preferential attack.

Weld decay is a form of intergranular attack. The attack occurs in a narrow band on each side of the weld owing to sensitizing or changes in the grain structure due to welding. Appropriate heat treating or metal selection can prevent the weld decay.

Ring worm corrosion is a selective attack which forms a groove around the pipe near the box or the external upset end. This type of selective attack is avoided by annealing the entire pipe after the upset is formed.

291

(6) Selective leaching. One component of an alloy is removed by the corrosion process. An example of this type of corrosion is the selective corrosion of zinc in brass.

(7) Erosion-corrosion. The combination of erosion and corrosion results in severe localized attack of metal. Damage appears as a smooth groove or hole in the metal, such as in a washout of drillpipe or tubing. The washout is initiated by pitting in a crevice which penetrates the steel. The erosion-corrosion process completes the metal destruction.

The erosion process removes protective films from the metal and exposes clean metal surface to the corrosive environment. This accelerates the corrosion process.

Impingement attack is a form of erosion-corrosion process, which occurs after the breakdown of protective films. High velocities and presence of abrasive suspended material and the corrodants in drilling and produced fluids contribute to t h s destructive process.

The combination of wear and corrosion may also remove protective surface films and accelerate localized attack by corrosion. This form of corrosion is often overlooked or recognized as being due to the wear. The use of inhibitors can often control this form of metal destruction. For example, inhibitors are used extensively for protection of downhole pumping equipment in oil wells.

(8) Cavitation corrosion. Cavitation damage results in a sponge-like appearance with deep pits in the metal surface. The destruction may be caused by purely mechanical effects in which pulsating pressures cause vaporization with formation and collapse of the bubbles at the metal surface. The mechanical working of the metal surface causes destruction, which is amplified in a corrosive environment. This type of corrosion attack, examples of which are found in pumps, may be prevented by increasing the suction head on the pumping equipment. A net positive suction head should always be maintained not only to prevent cavitation damage, but also to prevent possible suction of air into the flow stream. The latter can aggravate corrosion in many environments.

(9) Corrosion due to variation in fluid flow. Velocity differences and turbulence of fluid flow over the metal surface cause localized corrosion. In addition to the combined effects of erosion and corrosion, variation in fluid flow can cause differences in concentrations of corrodants and depolarizers, which may result in selective attack of metals. For example, selective attack of metal occurs under the areas which are shielded by deposits from corrosion, i.e., scale, wax, bacteria, and sediments, in pipelines and vessels.

(10) Stress corrosion. Stress-corrosion cracking of metals is produced by the combined action of corrosion and tensile stress. The term stress-corrosion cracking often is applied to all cracking that is related to stress and corrosion: (1) stress-corrosion cracking, (2) hydrogen embrittlement and blistering, (3) sulfide cracking, (4) corrosion fatigue, ( 5 ) stress alloying, and (6) caustic embrittlement.

Although stress-corrosion cracking can occur in most alloys, the corrodants whch promote stress cracking may differ and be few in number for each alloy. Cracking can occur in both acidic and alkaline environments, usually in the presence of chlorides and/or oxygen.

2 92

Stress cracking of metals can occur quickly with exposure to specific corrodants, and the time to failure is shortened by: (1) concentration of specific corrodants, (2) increase in stress, and (3) increase in strength and hardness of steel.

Stress-corrosion cracking slowly produces a network of cracks that penetrate metal at right angles to the tensile stress. The anodic reaction ( M + M 2 + + 2e-) extends the cracks across the lines of tensile stress. The effect is to reduce the cross-sectional area of the metal and to raise the tensile stress to a point of failure.

FORMS OF CRACKING IN DRILLING AND PRODUCING ENVIRONMENTS

Hydrogen embrittlement (sulfide cracking) and corrosion fatigue are two forms of cracking which are associated with drilling and producing environments.

Hydrogen embrittlement (sulfide cracking)

Hydrogen embrittlement occurs as a sudden cracking of metal, caused by the entrapment of hydrogen within the lattice structure. The cracking of the metal may proceed in a stepwise rupturing manner.

The corrosion process in an acid environment produces atomic hydrogen:

Fe + 2H+ + Fez+ + 2H0 (atoms) (8-7)

Fe - 2e- -+ Fez+ (anode) (8-8)

2H+ + 2e- + 2H0 (cathode) (8-9)

Some of the hydrogen atoms, which are formed in the cathodic reaction, penetrate the metal to form molecular hydrogen. The remaining hydrogen atoms combine to form molecules of hydrogen gas at the metal surface. The adsorption of hydrogen atoms by the metal causes a loss in ductility and cracking of high-strength steels.

Materials, which interfere with the pairing of atoms of hydrogen to form hydrogen gas at cathodic areas of metal, enhance the penetration of atomic hydrogen into the steel. Hydrogen sulfide in drilling fluids supplies sulfide ions which prevent the pairing of hydrogen atoms to form hydrogen gas. Thus, the penetration of atomic hydrogen into steels is promoted by the presence of hydrogen sulfide.

The time to failure by hydrogen embrittlement is shortened by increasing (1) concentration of hydrogen sulfide, (2) stress, and (3) strength and hardness of steel. This behavior is illustrated by Hudgins et al. (1966) in Figs. 8-1 and 8-2.

The embrittlement (sulfide stress cracking) occurs generally in steels with yield strengths above 90,000 psi or above Rockwell C-20-22 hardness. Lower-strength steels are not subject to sulfide stress cracking; however, they are subject to hydrogen blistering.

293

15 - Applied stresses Expressed as%ol yield deformation

M Y Week Month I c I ,

Hydrogen blistering Hydrogen penetration of low-strength steels may cause blistering, which appears

as bumps on the metal surface. The hydrogen atoms form hydrogen molecules at points of defect in the metal. The hydrogen gas cannot penetrate into nor escape

40

35

30

v IX

m- 2 5

P I" 2 0

VI

c 0

1 5

10

0.1 ppm 0

OOY Week Month Yea

0.5 1 5 10 50 100 500 1000 5000 1 I l l l l l i I I I l l ! l I l I + ! l 1 ~ 1 l l i j I 1 I 1 I I i 1 I S " '

Time to tailure , hours

000

Fig. 8-2. Relationship (approximate) between hardness and time to failure for carbon steels in 5% NaCl solution containing various concentrations of H,S. Stress level = 130% of yield deformation. (After Hudgins, 1969, p. 43, fig. 2; courtesy of Materials Protection.)

Fig. 8-1. Relationship (approximate) between hardness and time to failure at different applied stresses, expressed as percentage of yield deformation, for carbon steels in 5% NaCl solutions containing 3000 ppm H,S. (After Hudgins, 1969, p. 42, fig. 1; courtesy of Materials Protection.)

294

.; 6 0 Q

0 0

9 4 0

m In

* L

2 2 0

0

\ N o n - c o r r o s i v e e n v i r o n m e n t

\ ' \\ '\ \

\\ ". Corrosive '\ environment '\\, --- -- ---_ --- -\

I I I I

l o 4 lo5 lo6 lo7 Cycles for f a i l u r e ( N )

Fig. 8-3. Relationship between endurance strength of steel stress and number of cycles needed for the occurrence of failure in corrosive and non-corrosive environments. (After Bertness, 1957, p. 131, fig. 1; courtesy of Division of Production, American Petroleum Institute.)

from the crystalline structure. The pressure of hydrogen gas increases sufficiently to part the metal, create a void, and raise a blister on the steel surface.

Corrosion fatigue

Cyclic stresses at hgh levels cause fatigue failures of metal. In a corrosive environment, the progress of fatigue failure is accelerated by electrochemical corrosion. Corrosion fatigue is the combined action of corrosion and fatigue (cyclic stressing), which results in early fracture of metal. Corrosion fatigue is the principal cause of drillpipe and pumping rod failures. By establishing limits to the stresses repeatedly applied to metal, failure by fatigue in a non-corrosive environment can be avoided. The endurance limit is the maximum cyclic stress level which can be applied to a metal without a fatigue failure.

In an environment with continued corrosion, instead of exhibiting an endurance limit, metal will fail due to the growth of corrosion fatigue cracks. The time to failure or number of stress cycles necessary to cause failure is decreased with increasing severity of corrosive environment and level of stress as illustrated in Fig. 8-3.

Corrosion fatigue is enhanced by corrodants in a corrosive environment that cause pitting of steel, such as oxygen and the acid gases (H,S and CO,), which are often present in drilling and produced fluids. Increasing the strength of steels will not improve the resistance to corrosion fatigue. Instead it may shorten the cycles to failure. High-strength steels are more susceptible to pitting than the low-strength 5 t eels.

Notches, such as the ones caused by tongs or slips, and corrosion under protectors will accelerate corrosion fatigue failure. The relationship of fatigue to environment, tensile strength, and surface condition of steel is illustrated in Fig. 8-4.

295

TENSILE STRENGTH 1,000 psi

Fig. 8-4. Relationshp between endurance limit and tensile strength for polished, notched, and corroding specimens (applied to ordinary corrodible steels). (After Battelle Memorial Institute, 1949, p. 78, fig. 93; courtesy of John Wiley and Sons, Inc.)

Corrosion fatigue is the principal cause of damage to the rod strings of pumping wells. Failures of rod strings are aggravated by mechanical abuse which localizes and accelerates corrosive attack. 1mp:oper assembly of the rod strings and high lifting and pump pounding stresses contribute to accelerated failure of the equipment.

The calculations and dynamometer determinations of maximum and minimum rod string stresses, and the selection, operation and maintenance of subsurface pumps were presented by Zaba (1962) and American Petroleum Institute (RP 11L, 1977; RP 11AR, 1983). The proper selection of material and handling and use of rod strings and subsurface pumps are essential to preventative maintenance and mitigation of corrosion fatigue failures.

296

Inhibitors, which reduce corrosion and the entry of corrosion-generated hydrogen into the rods, can reduce the frequency of corrosion fatigue failures provided stress is within a reasonable range. Examples of field tests of inhibitors for control of corrosion fatigue are discussed by Martin (1980, 1983).

CORRODANTS IN DRILLING AND PRODUCTION FLUIDS

Corrodants in drilling and produced fluids include oxygen, hydrogen sulfide, and carbon dioxide.

Oxygen

Oxygen dissolved in drilling fluids is the major cause of drillpipe corrosion. As a depolarizer and electron acceptor in cathodic reactions, oxygen accelerates the anodic destruction of metal. The high-velocity flow of drilling fluids over the surfaces of drillpipe continues to supply oxygen to the metal and is destructive at concentrations as low as 5 ppb.

The presence of oxygen magnifies the corrosive effects of the acid gases (H,S and CO,). The inhibition of corrosion which is promoted by oxygen is difficult to achieve and is not practical in the drilling fluid system.

Removal of oxygen from the drilling fluid by physical deaeration, followed by chemical removal of residual oxygen, is recommended.

Oxygen corrosion of drillpipe occurs while the pipe is out of the hole. Pitting can develop rapidly under particles of mud solids which are left on the pipe. Pits provide the sites for further local attack of the drillpipe while it is in service. Proper cleaning with fresh water for the removal of salts and mud solids is recommended.

Cleaned drillpipe should be sprayed with a protective coating prior to storage. The control of corrosion in water-handling facilities requires the complete

exclusion and removal of oxygen from the water throughout the facilities. Oilfield brines usually exhibit an oxygen demand that should react with dissolved oxygen in the water. Unfortunately the brines usually contain soluble organics which interfere with the reaction. Oxygen scavengers with appropriate catalysts are usually required for the complete removal of oxygen from the waters.

Oxygen enters the produced brines by exposure to air through open tank hatches, pump seals, flotation and filtration systems, and other points throughout water-handling facilities. Oxygen can enter produced fluids in low-pressure pumping wells and in gas- and oil-gathering systems.

The strong depolarizing properties of oxygen create localized attack of metal at the areas of lower oxygen concentration, such as in crevices, pits, and in areas under deposits on the metal. Even in trace quantities, oxygen in brines can create severe pitting of metal.

Inhibition of oxygen-induced corrosion in production facilities has been difficult to attain. Corrosion control effort should be directed to both the exclusion of

291

oxygen from production and water handling facilities and the complete removal of oxygen from oilfield waters.

The methods used to remove dissolved oxygen from water are either mechanical or chemical.

Mechanical methods are useful in reducing dissolved oxygen to values less than 1 ppm. The water is then treated chemically for complete removal of oxygen. The most common mechanical method used in the oilfield to strip dissolved oxygen from water is by countercurrent flow of water with oxygen-free gas through a trayed stripping column. The process was described by Weeter (1965). Oxygen content can be reduced economically by vacuum deaerators to about 0.3 ppm. According to Cron and Marsh (1983, p. 1037), vacuum is best obtained by the use of two steam injectors in series.

Chemical scavengers for the removal of oxygen are sodium sulfite, bisulfites, hydrazine, and sulfur dioxide:

Na,SO, + i0, + Na,S04

N,H4 + 0, + N, + 2H20

(8-10)

(8-11)

and

SO, + $0, + H,O + H,SO, (8-12)

The reaction rates are complex in many water systems and are affected by temperature, pH, hydrogen sulfide, and the presence of catalysts. Snavely and Blaunt (1969) have shown that hydrazine is not sufficiently reactive for scavenging 0, at ambient temperatures, except in the presence of Cu2+. The rate of reaction between oxygen and sulfite ion is also greatly increased in the presence of catalysts (Cu2+ and Co2').

Although stoichometrically 8 ppm of Na,SO, are required to react with 1 ppm of dissolved oxygen, in actual practice 10 pprn are used. In the case of hydrazine, 1 ppm is required to scavenge 1 ppm of oxygen.

Many of the natural waters and oilfield brines contain materials which interfere with the reaction of oxygen scavengers. Each water should be tested to establish the oxygen reaction rate with selected scavengers and catalysts. The treatment must be sufficient to completely remove 0, from the water prior to distribution to water disposal, injection facilities, or to steam generators.

It is recommended that a polarographic oxygen sensor be used for rapid and accurate studies of oxygen scavenger reaction rates, as described by Snavely and Blaunt (1969) and Snavely (1971).

Hydrogen sulfide

Hydrogen sulfide is most damaging to drillpipe and well and production facilities by promoting sulfide cracking or embrittlement as discussed in the stress corrosion

298

32

>I 28

E

2 2 4 m

X

0 2 2 0 . ‘A 0

5 1 6 .-

: 1 2

: e

$ 4

. _ c 0 L c

n

L

?

c

I 1 I I I I I I

0 300 600 900 1 2 0 0 1500 1 8 0 0 2 1 0 0 2400 2700

Dissolved h y d r o g e n sulf ide , PPm

Fig. 8-5. Corrosive action of hydrogen sulfide on steel in distilled water at S O O F . (After Watkins and Wright, 1953, p. B-55, fig. 5; courtesy of the Petroleum Engineer.) mpy = mils per year = [wt. loss (mg)]/[ SG (or g/cm3) X 16.387 (cm3/cu in.) x area (sq in.) X yr (days/365)]; in the case of steel coupons having SG of 7.86, the formula can be simplified: mpy = [wt. loss (mg)X68.33]/[area (sq in.)^ hrs exposed].

section. General corrosion attack by hydrogen sulfide is also significant and is influenced by the presence of carbon dioxide, oxygen, and salts. The nature of the attack on metal is related to the alloy composition and strength of steel.

The corrosion of mild steel in distilled water containing hydrogen sulfide was illustrated by Watkins and Wright (1953). (See Fig. 8-5.)

The data in Fig. 8-5 indicates that high concentrations of hydrogen sulfide may act to inhibit corrosion of mild steel. High concentrations of hydrogen sulfide are catastrophc, however, in the case of high-strength steels, producing rapid embrittlement.

The influence of hydrogen sulfide, brine, and carbon dioxide mixtures upon corrosion rates of mild steel is illustrated by Meyer et al. (1958) in Fig. 8-6.

Obviously, the removal of the dissolved gases (oxygen, hydrogen sulfide, and carbon dioxide) from drilling and produced fluids is an important step in minimizing corrosion damage to steel.

The primary object of removing hydrogen sulfide from drilling fluids is the safety of personnel, because H,S is extremely toxic. The limit for repeated exposure is 10 ppm. Exposure to concentrations of 800+ ppm may result in death. Drilling fluids must, therefore, be treated to neutralize hydrogen sulfide gas as it enters the fluid by flow from the formation or from the drilled cuttings.

299

160

150

140

130

120

11 0

a E 100

y 90 2

x

Bo

70 ._ : b v 60

50

4 0

30

2 0

10

0

test I A H2S - distilled water

test n 0 H2S - brine

test m 0 H2S - C02 - brine

branch corrosion product

1 kansite tarnish

2 kansite scole

3 pyrrhotite, pyrite scole

0 10 2 0 30 4 0 50 60 70 80 90 100 110 120 130 140 1 Tlme -days

0

Fig. 8-6. Corrosion rates of 1020 mild steel from tests I, 11, and I11 in mixtures of hydrogen sulfide, carbon dioxide, and brine. (Modified after Meyer et al., 1958, p. 113t, fig. 7; courtesy of “Corrosion”.)

If presence of hydrogen sulfide is expected, the pH of drilling fluid should be held above 10. The reactions with caustic soda are as follows:

pH = 7.0: H2S + NaOH + NaHS + H 2 0 (8-13)

and

pH = 9.5: NaHS + NaOH + Na,S + H,O (8-14)

Hydrogen sulfide scavengers are also added to drilling fluids for the purpose of pretreatment or removal of this gas. These materials include (1) zinc carbonate, zinc chromate, and oxides of zinc, ( 2 ) iron oxide, and (3) copper carbonate. Copper carbonate should not be used for the purpose of pretreatment nor in excess of the sulfide requirement due to the possible corrosive effects.

Ironite@ Sponge@, which is the product of a reaction (controlled oxidation) using highly reactive, specially formulated chemical-grade iron powder as the raw material, can be used as an H2S scavenger. It consists mainly of Fe,O, and is characterized

300

by a high surface area (10 m2/kg or approximately 50,000 sq ft/lb). The specific gravity of the dry material is around 4.5-4.6 g/cm3, and particle size ranges from 1.5 to 50.0 pm, with 90% being between 2 and 20 pm. Inasmuch as the material retains very little magnetism, it is not attracted to drillpipe or casing.

Ironite Sponge reacts with H,S according to the following equations:

Fe,04 + 4H2S + 3FeS + 4H20 + S (8-15)

FeS + S + FeS, (8-16)

and

Fe,04 + 6H,S -+ 3FeS, + 4H20 + 2H, (8-17)

Reactions 8-15 and 8-16 predominate in basic environment, whereas reaction 8-17 occurs in acidic environment. One pound of this material (0.453 kg) reacts with 0.7 lb (0.318 kg) of H,S.

The speed of reaction can be expressed by the following equation:

dS,/dt = - 3000 X ( S , ) , X ( H+)l'06 X ( I ) (8-18)

where S, = total dissolved sulfides in filtrate, ppm, t = time, min, H+ = hydrogen ion concentration, moles/l, and I = Ironite Sponge concentration, lb/bbl (0.351 X

Replacement of water-base drilling fluids with oil-base systems, provides protection to the drillpipe by eliminating the electrolyte which is essential to corrosion. The oil-base systems contain some emulsified water, alkalinity of which must be maintained.

The hydrogen sulfide gas, which is carried by the oil-base drilling fluid, must be removed by gas separators and vacuum degassers. The removed gases must then be neutralized for the protection of personnel.

Hydrogen sulfide causes failures of production equipment by acid attack and hydrogen penetration of steel, which results in blistering and cracking as discussed in the stress corrosion section. Hydrogen sulfide forms iron sulfide scale, which is cathodic to the metal and promotes localized attack under the scale and the penetration of hydrogen into the metal.

The control of corrosion in H,S environments requires: (1) the proper selection of materials including the use of low-hardness steels with a maximum hardness of Rockwell C-22, (2) the application of inhibitors, and (3) the complete exclusion and removal of oxygen from waters in petroleum production.

The transmission of sour or acid gases should be preceded by drying to a dewpoint, which is below the minimum temperature of exposure within the facilities.

k / m 3 >.

301

' O c 6 0 -

5 0 -

>, a

I 1 I I

0 100 200 300 400 500

Partial pressure of carbon dioxide , psia

Fig. 8-7. Relationship between corrosion rate of steel and partial pressure of CO,. (After Rhodes and Clark, 1936; courtesy of Industrial and Engineering Chemistry.)

Carbon dioxide

Carbon dioxide is present in most formation fluids as a component of formation gases and in solution in water and oil. Carbon dioxide dissolves in water and forms carbonic acid:

CO, + H,O + H,CO, (8-19)

H,CO, + H t + HCO; (8-20)

(8-21)

As the partial pressure of carbon dioxide increases, more acid ions are formed and the water becomes more corrosive. The relationship of the partial pressure of carbon dioxide and the corrosion rate of steel is illustrated in Fig. 8-7.

The release of carbon dioxide from solution in produced waters by reduction of pressure often results in the deposition of carbonate scales. Uneven deposition creates selective attack of the metal. Carbon dioxide corrosion usually appears as a smooth or uniform attack of steel. Unfortunately, the addition of low concentrations of oxygen or hydrogen sulfide greatly accelerates the corrosive effects of carbon dioxide, which results in aggravated pitting attack.

The pitting penetration rate may be 10 or more times the general corrosion rate.

302

ALKALINITY (pH) OF ENVIRONMENT

The pH or hydrogen activity of water influences the corrosion rate of steel. The effect of pH on the corrosion of steel is dependent upon metal composition, stresses, oxygen concentration, and the type of acid which controls the pH.

The effect of pH on corrosion of steel in water containing 5 ppm of oxygen is shown in Fig. 8-8.

In a high alkaline range, the corrosion reaction is under anodic control and proceeds at high rates:

0, + Fe - 2e- + Fe0;- (8-22)

In the neutral range and in mild alkaline solutions, the corrosion rate is under cathodic control, whch provides some corrosion protection. Ferrous hydroxide, which provides a protective layer on the metal surface, forms in this environment. The actual corrosion rate is dependent upon the diffusion of oxygen to the metal surface. Corrosion increases with increasing oxygen concentration and abrasion and in the presence of turbulent, high-velocity flow, which is often imposed on the drillpipe.

In the acid pH range, corrosion is under anodic control and the metal composition influences the corrosion rate extensively. Trace elements in steel and stresses affect the corrosion damage.

0.009 I I

L 0.008 ; Q c I

I

0" 0.007 1’ E

x 1: 0.006

. I m I

0.005 c I

- - - I

I .

.-

I I , I / , , , , >

1 4 1 3 1 2 11 1 0 9 8 7 6 5 4 3 2

PH

Fig. 8-8. Effect of pH on corrosion of mild steel. (Modified after Whitman et al., 1924; also see Uhlig, 1948, p. 129, fig. 2; courtesy of Industrial and Engineering Chemistry.)

303

10

9 -

8 -

7 -

6 -

11 I I

-

l a5 4 -

3 -

2 -

b

-

0

1700-1900 ppm total sulfide in 5% NaCl All rings Rc 33tlstressed tO115%YD

lo 0 yo I I I 1 -

Fig. 8-9. Relationship between pH and time to failure. (After Hudgins, 1969, p. 43, fig. 3; courtesy of Materials Protecrion , National Association of Corrosion Engineers.)

The type of acid in solution determines the pH at which corrosion increases rapidly with the evolution of hydrogen gas. As shown in Fig. 8-8, hydrogen evolution starts at a pH near 4, with corrosion accelerating as pH is reduced. Hydrogen evolution at a pH of about 4 occurs in the presence of strongly dissociated acids.

Carbonic acid from the solution of carbon dioxide reacts with iron at a pH of 6 with the evolution of hydrogen gas, causing severe corrosion. This illustrates the importance of pH control throughout the circulating mud system where carbon dioxide is present.

Relationship of failure by embrittlement (sulfide cracking) and pH is illustrated in Fig. 8-9.

Figures 8-8 and 8-9 illustrate the importance of pH influence on the rate of corrosion. The most important corrosion control measure is to remove oxygen, carbon dioxide, and hydrogen sulfide (soluble gases) from the drilling and production fluids. The effectiveness of both corrosion inhibitors and pH is enhanced by the removal of soluble gases.

CATHODIC PROTECTION

Cathodic protection is not a practical method for the control of corrosion of drillpipe or the internal surfaces of well casings. Cathodic protection, however, is applied successfully for the corrosion control of external surfaces of casings, pipelines, and offshore structures, and the interiors of tanks and vessels.

The first step in the control of external casing corrosion is to provide a complete

304

I Polarization I I I I I

I ’ I ‘I

CURRENT ( I I

Fig. 8-10. Diagram illustrating theory of cathodic protection. I” = current required to produce complete cathodic protection. Current must exceed equilibrium corrosion current, I ’, to provide any protection. Corrosion will cease when the flow of cathodic current (I�) increases cathodic polarization to the open circuit potential ( E A ) of the anode as shown at point A .

cement sheath and bond between the pipe and the formation over all external areas of the casing strings. This practice is essential to the successful well completions.

Cathodic protection involves supplying electrons to the metal to make the corrosion potential more negative. Complete protection is achieved when all the surface area of the metal acts as a cathode in the particular environment.

The increase in electronegative potential can be achieved by use of sacrificial anodes (magnesium, aluminum, and zinc) or by an impressed direct current. The potentials required for protection differ with the environment and the electrochemical reactions which are involved. For example, Blaunt (1970) noted that iron corroding in neutral aerated soil has a reduction potential of 0.579 V. The potential is limited by the activity and solubility of ferrous hydroxide. If iron is exposed to H,S in oxygen-free environment, the potential is increased to 0.712 V and is controlled by the solubility of ferrous sulfide.

Measurements of potential are made by use of reference half cells. The copper-copper sulfate half cell is widely used for potential measurements of pipe in soils. The criteria for protection of iron with this half cell is - 0.85 V in aerated soil and -0.98 V in an H,S system.

The theory of cathodic protection is illustrated in Fig. 8-10. As shown in Fig. 8-10, the polarization of the cathodic areas of steel must be extended until the potential E, of the cathodic surfaces reaches the potential EA of the anodic surfaces. The current which is applied in cathodic protection (I�) must exceed the equilibrium corrosion current (1�) of the metal in its corrosive environment without cathodic protection.

The current density requirements to maintain protective potentials will vary with the environment. Pipe in soil or water, and vessel and tank interiors may develop

305

protective resistances on the surfaces by an increase in pH and the precipitation of scales with the application of cathodic protection.

The current density required for cathodic protection is related to the velocity and supply of corrodants to the metal surface. For example, protective potential can be achieved in a calm sea water environment with 3-5 mA/ft*, whereas 70 mA/ft2 or more is required in the high-velocity waters of Cook Inlet in Alaska, as noted by Bertness and Blaunt (1969).

In general, the current density required for cathodic protection of steel structures in sea water ranges from about 5 to 80 mA/sq ft. In the mud zone, a current density of only 1-4 mA/sq f t is required (Cron and Marsh, 1983, p. 1039).

Galvanic type of cathodic protection involves use of “sacrificial” anodes, such as aluminum and magnesium. Cathodic protection current is generated when these anodes are coupled to steel and are immersed in the same electrolyte, e.g., sea water. These anodes are consumed upon generation of current, as electrons resulting from the oxidation of aluminum are forced into the steel, which is below aluminum in an electromotive series. Zinc, tin, mercury and indium are used as alloying elements of aluminum anodes, which are typically cast on 2-in. steel pipe cores for use on offshore platforms. These 300- to 800-lb anodes are attached by welding during the construction of the platform, and are commonly designed to last as long as twenty years (see Cron and Marsh, 1983, p. 1039).

In the case of impressed-current cathodic protection, alternating current is converted to direct current by rectifiers. As compared to the galvanic cathodic protection, electrical current is purchased as needed and fewer anodes are used. In addition, renovation and repairs are not as difficult as the replacement of an entire galvanic system (Cron and Marsh, 1983, p. 1039).

The disadvantage of impressed-current system is the delay in initiating cathodic protection after the placement of platform on the seafloor.

In cathodically protecting offshore pipelines, sacrificial anodes (e.g., zinc) can be placed in the form of bracelets along the pipeline at certain intervals. A newly-developed aluminum alloy is also operative in mud. Larger sacrificial anodes can also be placed alongside the pipe and connected to the pipe with a cable. Cron and Marsh (1983, p. 1037) pointed out that insulation is an economical practice and should be used universally except when flowlines are incorporated into a cathodic-protection system (e.g., on offshore platforms). Decision as to whether to use cathodic protection or not is reached after studying the leak frequency curve and logs, expected well life, and leak repair costs. Typically, protection cost is around US $0.25/yr/sq ft of surface allowing for installation, maintenance, and operating costs.

Cron and Marsh (1983, p. 1036) clearly showed that in pipelines, casings, etc. the log of cumulative leaks is sometimes a linear function of time. Cathodic protection can be used only for preventing the external corrosion of casing and not the internal corrosion.

In the case of mooring chain links, much corrosion can be prevented through use of a cathodic protection. Individual links, however, must be bonded to a cable for

306

electrical continuity. As pointed out by Cron and Marsh (1983, p. 1041), aluminum anodes in sufficient number attached to the buoy can protect both the chain and the buoy.

Because of the differences in availability of dissolved oxygen, long cell action may be set up between the lower parts of the casing (and the surface flowlines) and upper parts of the casing. Thus, it is indispensable either to apply cathodic protection to surface structures as well as to the casing or to insulate the casing completely from large surface structures.

Comprehensive monitoring of potential of cathodic-protected structures is required to maintain effective control of corrosion.

Polarization tests are recommended for determining the current requirements for complete protection of well casings and pipelines as discussed by Kubit (1968).

ROLE OF BACTERIA IN CORROSION

The influence of sulfate-reducing bacteria in the corrosion process has been the subject of extensive investigations. The subject is complex and the reader is referred to the comprehensive treatment of the subject by Davis (1967). (Also see Chilingar and Beeson, 1969.)

Microbial corrosion has not been significant in the corrosion of drillpipe. Sulfate-reducing bacteria have produced serious corrosion to well casings as reported by Doig and Wachter (1951). Pitting occurred on the external surfaces of the casing where drilling fluid was present between the casing and the wall of the hole. The low pH of the mud and the presence of organic nutrients were favorable for the growth of sulfate-reducing bacteria.

The pH favorable for bacterial growth ranges from 5 to 9. Bacteria will thrive in areas of stagnant flow even in high-pH systems, however, provided other requirements, i.e., temperature and contents of organic nutrients, salts, and oxygen, are satisfied.

Sulfate-reducing bacteria are anaerobic and thrive only in the absence of oxygen. In an aerated system, oxygen is depleted in stagnant areas, e g , along the walls of mud pits and behind casing. This allows the sulfate-reducing bacteria to grow. Equation can be presented as follows:

H2S0, + 8H + bacteria + H2S + 4H20 (8-23)

Thus, hydrogen atoms formed at cathodic areas of metals are removed and are utilized to reduce sulfates to sulfides. The end products are live bacteria and corroded iron.

The bacterial attack of organic additives of drilling fluids may result in excessive use of mud chemicals and a rapid reduction of pH. The mud will become more corrosive under these conditions. Thus, bacteria must be controlled by the use of high pH (e.g., 10.5) or bactericides.

307

Bacteria in producing operations can contribute to corrosion, plugging of injection wells, and fouling of flowlines and water-handling facilities. Most oilfield waters contain soluble organics which can be utilized by bacteria. Bacteria including sulfate reducers can be cultured from most produced waters and waters in waterflood projects.

Sulfate-reducing bacteria can be abundant and yet not be active in depolarization of the corrosion process. Sulfate-reducing bacteria preferentially utilize organics, which usually are abundant in oilfield waters rather than nacent (atomic) hydrogen. The hydrogen sulfide produced by bacteria, however, causes severe pitting in the same manner as naturally-occurring hydrogen sulfide.

Oxygen in trace amounts in water facilities with sulfate-reducing bacteria will accelerate the pitting attack and must be removed completely.

Years of investigation of anaerobic corrosion by Starkey (1958) did not disclose serious bacterial corrosion in the presence of sulfate-reducing bacteria.

The injection of waters which contain sulfate ion, such as sea water, can change sweet corrosion condition in the reservoir into a sour one. For example, the Wilmington oil field in California, U.S.A., initially produced sweet oil and gas. The conditions became sour following the injection of sea water. Hydrogen sulfide content in the produced gas increased from an average of trace amounts to about 1000 ppm, with progress of the waterflood.

Sulfate-reducing bacteria can thrive in water filter systems. The large surface areas in filter beds are sites for bacterial growth. The bacteria can generate H,S, which is carried with the water into the distribution system. This results in corrosion and contamination of the water and facilities downstream of the filters.

The filter backwash cycles should incorporate thorough cleaning with detergents, bactericides, chlorine, or steam to maintain water quality.

CORROSION IN GAS-CONDENSATE WELLS

Corrosion in gas-condensate wells presents serious problems which cannot be predicted accurately. A rigorous corrosion control program, with conscientious monitoring of equipment condition and failures, properties of produced fluids, and corrosion rates, is required to maintain corrosion control.

Analysis of the problem by NGAA (1953) and the NACE Committee on Condensate Well Corrosion (1958) provided a few guidelines for control of corrosion. The NGAA (1953) statistical studies showed that corrosion was likely in condensate wells with (1) depths greater than 5000 ft, (2) bottomhole temperatures above 160"F, (3) bottomhole pressures above 1500 psi, and (4) CO, partial pressures above 30 psi.

As the gas wells were drilled deeper (greater than = 10,000 ft), the corrosion problem became more complex. As a result of laboratory and field studies, Hilliard (1980) has noted that the effects of gas composition, pressure, temperature, velocity, and composition of produced water modify the simple relationshps between these

werq

m PY

coTro5

3

2

I

luting rote

CORROSION RATE AS FUNCTION OF BRINE PRODUCTION

Gas Production Range 0.4 - 0.7 MMcft/D

0 prior l o inhibition

inhibiled KP- 153

mP),

' I

,'SLOPE = KG= a06 /

/ /

/

0

/ SLOPE = 0.01

, brine production

0 * ' 10 20 30 4 0 50 60 bbl/MMcft

Gas Production Range 1.5- 3 MMcftAI

1 / 1

I sL I I I

i 3 I

I I I I

.OPE =

E l 5 I / I INHIBI'

brine production - 10 20 30 40 50 60 bbVMMcft

W

$2

Fig. 8-11. Relationship between corrosion rate and brine production. (After Gatzke and Hausler, 1983, fig. 1; courtesy of National Association of Corrosion Engineers.)

309

0.6

0.4

0.2

0.1

0.06

0.04

0.m

0.01

KG mwMMef+

H20 bbl

prior to inhibition

E L 0 I

Gas Roducth MMcft/O I -

1 2 3 4 5 6

Fig. 8-12. Relationship between corrosion rate and gas production. (After Gatzke and Hausler, 1983, fig. 3; courtesy of the National Association of Corrosion Engineers.)

factors and the corrosion of steel. For example, corrosion due to CO, decreases at high temperatures due to a passivation effect. Temperature has not been related clearly to the CO, partial pressure, composition of water, or other properties at t h s time. Hydrogen sulfide at low concentrations reactivates the corrosion.

Presence of water or electrolyte in contact with metal is essential for corrosion to proceed. Water may contact tubing in a gas well from the bottom to the wellhead or be present in a limited area within the well as a result of condensation of vapor. Corrosion in deep gas wells is difficult to monitor except by iron count, caliper logs, and inspection. Corrosion monitoring at the surface does not reveal behavior whch is representative of conditions within the well.

Gatzke and Hausler (1983) described an empirical relationship between corrosion rate and production rates of water and gas. The corrosion rates are derived from iron counts and the interior areas of tubing. Figures 8-11 and 8-12 illustrate the relationship between corrosion rate and brine and gas productions.

Adequate placement of corrosion inhibitors in deep hot gas wells is complicated by problems of evaporation of carrier fluid and removal of inhibitor by the flow of produced condensate and gas. Methods of inhibitor application are:

(1) Squeezing of inhibitor into the formation, which may impair well produc-

310

tivity.

deep wells. (2) Batch treatment down the tubing, which may not reach the corrosive areas in

(3) Continuous injection of inhibitor through a separate line to bottom. The continuous injection method with appropriate inhibitor and carrier fluid is

the most effective procedure. A detailed discussion of corrosion characteristics and control practices in deep hot gas wells was presented by Annand (1981).

INHIBITORS AND PASSIVATORS

An inhibitor is a chemical substance or a mixture which effectively decreases corrosion when added to an environment (usually in small concentration). A passivator, on the other hand, is an inhibitor which appreciably changes the potential of a metal to a more cathodic or noble value.

Anodic inhibitors for iron in water are soluble hydroxides, chromates, phos- phates, carbonates, and silicates. These substances increase anodic polarization, probably by helping to form (or to repair) a protective film on the metal surface.

Cathodic inhibitors for iron partially immersed in water are magnesium, zinc, and nickel salts. As 0, is reduced at cathodic areas, the pH is increased, resulting in the precipitation of Mg(OH),, Zn(OH),, or Ni(OH), over the cathodic surface as a fairly adherent porous deposit. Thus the reaction is slowed down because 0, must diffuse through these deposits in order to reach the cathodic surfaces. In waters containing CO,, the calcium salts act similarly by precipitating CaCO, on the cathodic areas as a result of increasing pH.

An insufficient concentration of an anodic inhibitor in a system that is under cathodic control intensifies the attack on small, localized areas. This results in pitting and early perforation. The required concentration of anodic inhibitor depends on the concentrations of ions such as chloride or sulfate, which interfere with the formation of passivating films. Other factors which are considered in determining the required concentration include: (1) agitation of the liquid, (2) the composition of the environment, (3) stresses in the metal, (4) composition of the metal, ( 5 ) contact with dissimilar metal, and (6) temperature.

Certain inhibitors change the electrochemical potential of a metal to more cathodic or noble value. These inhibitors are called passivators, and they are frequently anodic inhibitors. The cathodic inhibitors are not likely to act as passivators. The iron will stay bright indefinitely in water containing a sufficient amount of chromate (anodic inhibitor).

The pigments which are used in priming paints usually contain passivators. For example, zinc chromate is a pigment which is soluble enough in water and diffuses through the paint film bringing a small concentration of chromate ions, CrO:--, to the metal surface. An appreciably less soluble chromate, such as lead chromate, does not have this property.

The chromate ions form a thin protective film on the surface. This film is composed of an insoluble iron compound such as iron chromate or a ferric-chromic

311

oxide mixture. According to the electron configuration theory, the chromate ions form an adsorbed layer on iron. This film absorbs and shares electrons of the surface iron atoms and satisfies secondary valence forces; however, it does not disrupt the metal lattice. Thus, the metal surface becomes less reactive and more noble in the galvanic series.

Sodium nitrite (NaNO,) is used as a passivator in oil pipelines and renders the iron several tenths of a volt more noble than it was originally. The nitrite ion is oxidizing in nature and, therefore, acts like chromates or other oxidizing passivators to reduce corrosion.

Organic inhibitors are used for corrosion control in most producing operations. Generally the inhibitor affects both the anodic and cathodic reactions by adsorption on the metal surface.

The use of electrochemical methods to evaluate corrosion inhibitors under laboratory and field conditions is discussed by Martin (1979, 1982).

The reader is referred to the excellent discussion of fundamentals of inhibitors by Hackerman and Snavely (1971).

SAMPLE PROBLEMS ‘

Problem 8-1

A plant engineer has a problem of protecting the inside of a water tank from corrosion, by “cathodic protection”. The tank is a vertical cylinder 10 ft high and 8 ft in diameter. This tank contains water to a depth of 8 ft. The engineer installed suitable anodes in the tank and connected it to the negative terminal of a rectifier output. By inspection, water analysis, and former experience, he determined that a total current of 5.06 A would stop the corrosion. Assuming that this current would equal the sum of all corrosion currents (local cell currents) due to corrosion, and if cathodic protection were not applied, what would be the tank life in years? The original tank wall thickness is 0.300 in. and the tank has to be scrapped when the wall thickness is reduced to 0.200 in. Both the tank bottom and walls in contact with the water are being corroded.

Assume uniform corrosion and that iron corrodes as Fe -+ Fe2+ + 2e-.

The charge on an electron is 1.59 x C (C = A X sec). One ampere flowing for one second dissolves anodically, or deposits cathodically, 1.11800 mg of silver. Avogadro’s number = 6.06 X

Density of steel = 7.8 g/cc.

’ Courtesy of Professor J.S. Smatko, formerly of Chemical Engineering Department, University of Southern California, Los Angeles, California.

312

Solution : Amount of steel corroded:

o‘loo 0.419 ft3. (a) Bottom of tank = V, = 7 X - =

(b) Sides = V, = (2 x T x 4) X - o.loo x 8 = 1.676 ft3.

(c) Total volume corroded = V, + V, = 0.419 + 1.676 = 2.095 ft3. (d) Total weight of steel corroded = 2.095 X 28,400 X 7.8 = 465,000 g. One Faraday (= 96,500 C) will corrode 1 g equ of a metal. Amount corroded = 465,000 g. 1 g equ of iron = 55.85/2. Current = 5.06 A = 5.06 C/sec.

Duration of corrosion = 465’000

365 x 24) = 10 yrs.

T X 82 12

12

96’500 = 31.8 x lo7 sec = 31.8 x lo7 (1/3600 x (55.85/2) X 5.06

Problem 8-2

A steel water tank was to be protected by “cathodic protection” with DC current applied so that the tank would have negative polarity. The tank was 12 ft tall, open at the top, and was 10 ft in diameter. The wall thickness was 0.38 in. The practical life of the tank was considered at an end when any part reached 0.18 in. in thickness. The current flow was adjusted so that 0.05 A/ft2 was impressed.

Accidentally, connections were made backwards and the tank was made anodic (deliberately corroded). The error was not noted for 2 yrs, the blame going to an imperfect system and corrosive solutions. Assuming that the reaction is Fe + Fe2+ + 2e- at 100% efficiency and that 26.8 A-hr are capable of dissolving 27.93 g of iron, how much iron dissolved in 2 yrs? What was the wall thickness after 2 yrs? What fraction of the tank’s life was used up?

Solution: Wall area (wetted) = 1 0 ~ X 12 = 377 ft2. Area of tank bottom = T X 5 2 = 78.54 ft2. Total area = 377 + 78.54 = 455.54 ft2. Specific weight of Fe = 7.8 X 62.4 = 490 Ib/ft3.

454 X 26.8 Electrochemical equivalent of Fe =

2 yrs = 2 x 24 x 365 = 17,500 hrs. Current flow = 455.54 X 0.05 = 22.78 A. A-hr in 2 yrs = 22.78 X 17,500 = 398,000.

398’000 1000

Fe dissolved =

Thickness loss = 12 X 1.868/455.54 = 0.0492 in. Fractional life loss = (0.0492 X 100)/(0.38 - 0.18) = 24.6%. Wall thickness after 2 years = 0.380 - 0.0492 = 0.331 in.

27’93 ‘Oo0 = 2.297 lb/1000 A-hr.

2.297 = 915 lb or 915/490 = 1.868 ft3.

313

Problem 8-3

A sacrificial magnesium anode is used to protect a section of a steel gas pipeline. It weighs 70 Ib and must be replaced when the remaining magnesium reaches 10 Ib in weight. During the protection job, only one-half of the magnesium corrodes in such a way as to deliver current to the pipe. The other half is self-corroded without any benefit to the pipe. How long would this anode last, if 3 A flow continuously? Atomic weight of Mg = 24.32. 1 Faraday = 96,500 C = 26.8 A-hr.

Solution :

Wt. loss of anode usefully = ___ - - 30 lb or 30 X 454 = 13,550 g.

Corrosion reaction: Mg + Mg2+ -t 2e- 1 Faraday = 96,500 C = 26.8 A-hr and is the electricity produced by 1 g equ of

70 - 10 2

usefully corroding Mg.

Amount of g equ corroded = = 1114. 13,550

24.32/2 A-hr = 26.8 X 1114 = 29,900. hr/year = 24 x 365 = 8760. Life = 29,900/(8760 X 3) = 1.13 yrs.

Problem 8-4

A steel vessel has a 0.5-in. thick wall. During use, it corrodes. Its internal area is 40 ft2. Assuming a uniform corrosion rate, the following facts are to be noted: The plant chemist found that the product, processed in the vessel, contained 1.0 g of Fe(OH), in 150 gal of solution processed during each run; 24 runs per day were made. Steel has a density of 7.7 g/cc. Find the corrosion rate expressed as mg/m2/day (m.m.d.), also as in. penetration per year (i.p.y.). What is the life of this vessel if it is considered worn out when the average wall thickness reaches 0.375 in?

Solution: Area = 40 X 0.0929 = 3.72 m2. Fe(OH), produced per day = 1.0 x 24 = 24 g. Wall thickness loss = 0.5 - 0.375 = 0.125 in. or 0.125 X 2.54 = 0.318 cm. Mol wt. Fe(OH), = 106.85.

Fe metal loss/day = - 55'85 X 24 = 12.55 g/day. 106.85

12'55 'Oo0 = 3375 mg/m2/day. 3.72

Corrosion rate =

Wt. loss/year = 12.55 x 365 = 4580 g/year. 4580

VOI. loss/year = 7 = 595 cm3.

= 0.016 cm or - o.016 - - 0.0063 i.p.y. 2.54

595 1 . 1

Thickness loss/year =

0.125 Life = - = 19.85 yrs.

0.0063

3.72 x 104

314

Problem 8-5

A coated and wrapped steel pipeline (500-miles long) having 18-in 0.d. is to be protected by cathodic protection. Sacrificial magnesium anodes are used to supply the electric current. The specific resistivity of the soil is 1000 f2-cm. The anodes are grouped in stations, each station having 5 anodes weighing 17 lb each. The 5 anodes of each station are “planted” on 10-ft centers in a string paralleling the pipeline, and 10 ft away from the pipeline. Under these conditions a current density of 0.01 mA/ft2 of pipe surface is obtained. The anode stations are placed 2 miles apart; and the anodes in each station are connected in parallel with 10 PVC (polyvinyl chloride) covered copper wire. These clusters are then connected by a 4 PVC covered copper cable to a welded stud on the pipe. Each anode is surrounded by a backfill composed of 5% Na,SO,, 20% bentonite clay, and 75% gypsum. Installation costs per mA-yr equal magnesium costs per mA-yr; magnesium costs $0.55/lb. Assuming that only one-half of the planted magnesium actually yields useful current for protection, find:

(a) Current flow per station. (b) Life of installation. (c) Magnesium weight loss per station per year. (d) Cost of installation. (e) Cost of protection per ft2 of pipe per year.

Solution : Number of stations = 500/2 - 1 = 249. Wt. of Mg per station = 5 X 17 = 85 lb. Total weight of Mg for pipeline = 85 X 249 = 21,164 lb. Total cost for Mg = 21,165 X 0.55 = $11,640.75. Area of pipe protected by one station = 1.5 X 3.1416 X 5280 X 2 = 49,800 ft2. Current per station = 49,800 X 0.01 = 498 mA. Electricity generated per year = 498 x 24 x 365 = 4365 x lo3 mA-hr or 4365 A-hr.

Inasmuch as 26.8 A-hr are produced by 24.32/2 g of Mg at 100% efficiency, then electrochemically useful Mg = 4365 X 24.32/26.8 X 2 = 1980 g/station or 5.72 lb/ station.

Actually, twice as much magnesium corrodes per year; therefore, the lifetime =

85/2 X 5.72 = 7.41 yrs. Actual weight loss/station/year = 2 X 1980 = 3960 g or 2 X 5.72 = 11.44 lb. There are two possible interpretations concerning installation costs per year: (a) If installation cost is equal to the cost of Mg effective in producing current

only, it would be $11,640.75/2 = $5,820.37. Installation cost + Mg cost = 5,820.37 + 11,640.75 = $17,461.12.

(b) If installation cost is equal to the total cost of Mg used, then it would be $1 1,640.75. Installation cost + Mg cost = 11,640.75 + 11,640.75 = $23,281.50. Interest charges, maintenance cost, overhead, and inspection costs should be added to the above figures.

315

- - 17,461.12 X 100 49,800 x 250 x 7.41

According to (a): yearly costs/ft2 of pipe =

0.019c/ft 2/year.

= 0.025c/ft2/year. 23,281.50 X 100

49,800 X 250 X 7.41 According to (b):

SAMPLE QUESTIONS AND PROBLEMS

(1) List and explain four main types of corrosion. (2) List the most important factors in oil- and gas-well corrosion. (3) Define an “inhibitor” and a “passivator”. (4) What factors determine the concentration of required inhibitors? (5) Explain why the chromate inhibitors stop corrosion. Would they work in the

presence of reducing agents and why? Describe the effect of abrasion on corrosion. Briefly discuss the economics of cathodic protection. What is the corrosion test plate or “coupon”? How would you recognize “sour corrosion”? How would you recognize “sweet corrosion”? List 5 main subdivisions of corrosion. List 5 methods of preventing corrosion. Describe in detail the role played by the bacteria (aerobic and anaerobic) in

corrosion, including iron organisms. (14) List the corrosion problems encountered in condensate wells. (15) Draw a schematic diagram of Fe corrosion caused by moisture in an

atmospheric environment properly labeling important areas and showing equations. (16) List 3 types of corrosion in water and 2 treatments or means of preventing

or minimizing each. (17) Complete the following equations:

Eo of Ca = +2.87, A1 = + 1.67, Na = +2.71, and Cu = -0.522 V.

(18) List 10 factors influencing corrosion: 5 factors associated mainly with the

(19) Describe methods of controlling the corrosion of casing and tubing. (20) What happens in an aqueous solution when Mg2+ + Hg + ?

metal and 5 factors, with the environment.

E0 (v> Mg = Mg2+ + 2e-

Hg = Hg2+ + 2e-

+ 2.375

-0.854

316

(21) Calculate Eo for Fe --f Fe3+ + 3e

Fe --f Fe2+ + 2e- Eo = 0.440 volts

Fe2+ + Fe3+ + e- Eo = -0.771 volts

(22) What is the life of 700-lb aluminum anode which generates a current of 5.1 A in seawater? Galvanic efficiency = 94%.

REFERENCES

American Petroleum Institute, 1977. Design Calculations for Sucker Rod Pumping Systems,, API RP 11L, Dallas, Tex., 24 pp.

American Petroleum Institute, 1983. API Recommended Practice for Care and Use of Subsurface Pumps. API RP l lAR, Dallas, Tex., 41 pp.

Annand, R.R., 1981. Corrosion Characteristics and Control in Deep, Hot Gar Wells. Southwestern Petroleum Short Course.

Battelle Memorial Institute, 1949. Prevention of the Failure of Metals under Repeated Stress. Wiley, New York, N.Y., 295 pp.

Bertness, T.A., 1957. Reduction of failures caused by corrosion in pumping wells. API Drilling Prod. Pract., 37:129-135.

Bertness, T.A. and Blaunt, F.E., 1969. Corrosion control of platform in Cook Inlet, Alaska. Offshore Technology Conference, Paper No. OTC 1049, SOC. Pet. Eng. A.I.M.E., May 18-21, Houston, Tex., 8

PP. Blaunt, F.E., 1970. Fundamentals of cathodic protection. In: Proc. Corrosion Course, Univ. Oklahoma,

Sept. 14-16. Chilingar, G.V. and Beeson, C.M., 1969. Surface Operations in Petroleum Production. Am. Elsevier, New

York, N.Y., 397 pp. Cron, C.J. and Marsh, G.A., 1983. Overview of economic and engineering aspects of corrosion in oil and

gas production. J. Per. Tech., 35(6):1033-1041. Davis, J.B., 1967. Petroleum Microbiology. Elsevier, Amsterdam, 604 pp. Doig, K. and Wachter, A.P., 1951. Bacterial casing corrosion in the Ventura Field. Corrosion, 7:221-224. Dean, H.J., 1977. Avoiding drilling and completion corrosion. Pet. Eng., 10(9):23-28. Fontana, M.G. and Greene, N.D., 1967. Corrosion Engineering. McGraw-Hill, New York, N.Y., 391 pp. Gatzke, L.K. and Hausler, R.H., 1983. Gas well corrosion inhibition with KP 223/KP 250. NACE Annu.

Hackerman, N. and Snavely, E.S., 1971. Fundamentals of inhibitors. In: NACE Basic Corrosion Course.

Hilliard, H.M., 1980. Corrosion control in Cotton Valley production. SOC. Pet. Eng. Cotton Valley Symp.,

Hudgins, C.M., 1969. A review of corrosion problems in the petroleum industry. Muter. Prot., 8(1):

Hudgins, C.M., McGlasson, R.L., Mehdizadeh, P. and Rosborough, W.M., 1966. Hydrogen sulfide

Ironite Products Co., 1979. Hydrogen Sulfide Control. 41 pp. Kubit, R.W., 1968. E log I - Relationship to polarization. Paper No. 20, Conf. NACE, Cleveland, Ohio,

Martin, R.L., 1979. Potentiodynamic polarization studies in the field. Muter. Perform., 18(3):41-50. Martin, R.L., 1980. Inhibition of corrosion fatigue of oil well sucker rod strings. Muter. Perform.,

Conf., April 18-22, Anaheim, Calif.

NACE, Houston, Tex., (9): 1-25.

SPE 9062, Tyler, Tex., May 21, 4 pp.

41-47.

cracking of carbon and alloy steels. Corrosion, 22(8):238-251.

13 PP.

19(6): 20-23.

317

Martin, R.L., 1982. Use of electrochemical methoh to evaluate corrosion inhibitors under laboratory and

Martin, R.L., 1983. Diagnosis and inhibition of corrosion fatigue and oxygen influenced corrosion.

May, P.D., 1978. Hydrogen sulfide control. Drilling-DCW, April. Meyer, F.H., Rigs, O.L., McGlasson, R.L. and Sudbury, J.D., 1958. Corrosion products of mild steel in

hydrogen sulfide environments. Corrosion, 14(2):109-115. N.A.C.E. (National Association of Corrosion Engineers), 1979. Corrosion Control in Petroleum Produc-

tion. N.A.C.E. TPC Publ. No. 5: 101 pp. N.G.A.A. (Natural Gasoline Association of America), 1953. Condensate Well Corrosion. N.G.A.A., Tulsa,

Okla., 203 pp. Ray, J.D., Randall, B.V. and Parker, J.C., 1978. Use of reactive iron oxide to remove H2S from drilling

fluid. 53rd Annu. Fall Tech. Conf. SOC. Pet. Eng. AIME, Oct. 1-3, Houston, Tex., 4 pp. Rhodes, F.H. and Clark, J.M., 1936. Corrosion of metals by water and carbon dioxide under pressure.

Znd. Eng. Chem., 28(9):1078-1079. Simpson, J.P., 1979. A new approach to oil-base muds for lower-cost drilling. J. Pet. Tech., 31(5):643-650. Snavely, E.S., 1971. Chemical removal of oxygen from natural waters. J. Pet. Tech., 23(4):443-446. Snavely, E.S. and Blaunt, F.E., 1969. Rates of reaction of dissolved oxygen with scavengers in sweet and

Staehle, R.W., 1978. $70 billion plus or minus $21 billion. Corrosion, 34(6):1-3 (editorial). Starkey, R.L., 1958. The general physiology of the sulfate-reducing bacteria in relation to corrosion.

Uhlig, H.H. (Editor), 1948. The Corrosion Handbook. Wiley, New York, N.Y., 1188 pp. Uhlig, H.H., 1965. Corrosion and Corrosion Control. Wiley, New York, N.Y., 3rd ed., 371 pp. Watkins, J.W. and Wright, J., 1953. Corrosive action on steel by gases dissolved in water. Pet. Eng.,

Wendt, R.P., 1979a. The Kinetics of Zronite" Spongea H2S Reactions. Pet. Div. Am. Soc. Mech. Eng.,

Wendt, R.P., 1979b. Control of hydrogen sulfide by alkalinity may be dangerous to your health. Pet.

Wendt, R.P., 1979c. Alkalinity control of H,S in muds is not always safe. World Oil, 188(2):60-61. Whitman, W., Russell, R. and Altieri, V., 1924. Ind. Eng. Chem., 16:665. Weeter, R.F., 1965. Desorption of oxygen from water using natural gas for countercurrent stripping. J.

Zaba, J., 1962. Modern Oil- Well Pumping. The Petroleum Publishing Company, Tulsa, Okla., 145 pp.

field conditions. U.M.I.S.T. Conf. on Electrochemical Techniques, Manchester.

Muter. Perform., 32(9):41-50.

sour brines. Corrosion, 25(10):397-404.

Prod. Mon ., 22( 8) : 12-30.

25(12):50-57.

Energy Technol. Conf., Houston, Tex., Nov. 5-9, 1978, 7 pp.

Eng. Znternat., 51(6):66-74.

Pet. Tech., 17(5):515-520.


319

Chapter 9

WATER QUALITY FOR SUBSURFACE INJECTION

CHARLES C. WRIGHT and GEORGE V. CHILINGARIAN

INTRODUCTION

There has been a rapid growth in the utilization of water for secondary recovery purposes. In 1981, about 40% of the oil production in the United states was by waterflooding. It is estimated that by 1990, 50% of the oil production will be by waterflooding.

There is a rough rule of thumb that ten barrels of water must be injected into the formation for each barrel of oil produced. Using this rule, one comes up with a staggering total for the volume of water to be injected into the formations. This rapid increase in water injection is focusing attention upon water quality for subsurface injection.

This chapter is devoted to setting standards for water quality, means by which standards may be met, and the problems arising during the handling of water.

The objective of water treatment was stated simply by Hockaday (1958) as follows: “The major consideration of water quality for subsurface injection is that the water must be only good enough to enable the water injection program to be carried out to completion at a minimum cost.” This means simply that the water must have a quality which enables injection of the water into the subsurface formation at the desired injection rate without prohibitive pressures. In addition, water must not cause more corrosion than can be economically tolerated during the time necessary to recover the oil. Thus, water quality control is concerned mainly with: (1) injection suitability, and (2) corrosion control.

Unfortunately, these main considerations are interrelated in many ways and cannot be dealt with separately. This is discussed in detail in subsequent sections.

Detailed specifications are important in order to maintain a given water quality necessary for the completion of a specific project.

In setting water quality specifications, one must be careful not to lose sight of the primary purpose of the water quality control, because unnecessarily high standards result in extra cost without compensating return.

INJECTION SUITABILITY

Injection suitability of water means that the desired volume of water can be forced into the subsurface formation at economical pressures.

320

Rising injection pressures may be caused by one or more of the following causes: (1) Fill-up of the formation (filling up of void spaces). (2) Swelling of formation clays, resulting in decreased permeability. (3) Formation and deposition of insoluble material in the formation. (4) Increase in oil saturation, resulting in decreased permeability to water. ( 5 ) Movement of formation fines caused by solubilization of cementing agents.

The fines subsequently lodge in restrictions in pore channels, causing a reduction in permeability.

(6) The presence of suspended solids in the water, which either lodge in restrictions in pore channels or strain out on the formation face and, thus, cause a reduction in permeability.

The first cause is outside the purview of thw chapter, but it must be remembered, because rising pressures do not have to be caused by water quality. The remaining causes are dealt with in detail.

Clay swelling

There probably is more misinformation about clay swelling in reservoir rocks than on any other phase of water injection. This situation has arisen because of the following:

(1) Each species of clay mineral reacts to a different degree with foreign waters. (2) The degree of swelling of a clay mineral is a function of the following (Grim,

1962): (a) the total ionic strength of the water, (b) the relative ratio of monovalent cations to divalent cations, (c) the pH of the water, (d) the specific cations present, and (e) the presence of polar organic compounds.

(3) The rate of change from high ionic strength to low ionic strength water (Crawford, 1966).

(4) The analytical determination of the presence of clay minerals and their residence time in a reservoir rock is not a simple determination (Morris et al., 1959; Hewitt, 1963).

Mobile fines give rise to the same reduction in permeability as the swelling of clays (Hewitt, 1963).

The work of Von Engelhardt and Tunn (1955, see Fig. 9-1) shows the effect of varying salinity on three basic clay types. Sodium montmorillonite causes the greatest reduction in permeability because it exhibits greatest swelling, whereas sodium-illite and sodium-kaolinite cause far less reduction in permeability as the salinity of the flooding water is decreased.

Formation and deposition of insoluble material in the formation

Jones and Neil (1960) and Jones (1964) showed the importance of making salinity reduction change in steps of not greater than tenfold dilution, even though hardness is maintained at 10% of the sodium ion (Table 9-1).

Jones (in: Crawford, 1966) stated that minimum clay swelling ocurs if at least

321

W a & 100 s f V

5 3

0 0 In z yr)

0 I- t.

_t

-

7 5

t_

m a 5 0 W E K W P LL 0

-

8 >- 2 5

t 2 m a 5 a W 0 0

W

0

SODIUM K

L L l N l T E

100,000

-LONITE

200,000

SODIUM CHLORIDE, MG/L

Fig. 9-1. Effect of saline waters on permeability of quartz sand containing 4% clay. (After Von Engelhardt and Tunn, 1955.)

10% of the salts in solution consists of divalent cation salts. Sometimes as little as 5% is effective in inhibiting clay swelling. This is true even if the water is fresh.

The two mechanisms by which insoluble material may be formed and deposited within the formation are: (1) the reaction of injection water with formation water to

TABLE 9-1

Effect of salinity of water on permeability of sandstone core

Series Water Core permeability (md) Sodium chloride Calcium chloride

(PPm) ( P P 4

1 52,600 5260 526 263 105

2 52,600 105

5500 550 55 27 11

5500 11

225 235 215 220 21 5 220 40

322

3

form precipitates, and (2) a time-dependent reaction withn the injection water, which results in formation of insoluble material after the water has entered the formation.

These mechanisms are not important when formation permeability is high. If the precipitates are deposited sufficiently far from the wellbore, there may be only a negligible effect on injectivity due to the radial dispersion, which governs. On the other hand, a low-permeability formation may be damaged by these mechanisms because the deposition will take place at or near the wellbore face.

Increase in oil saturation

The main concern with oil entering the formation lies in its extreme effect on water permeability in the regions of low oil saturation. Typical relative permeability curves are presented in Fig. 9-2.

Increased oil saturation around the wellbore in a water injection well is far more common than usually realized (Table 9-11). This additional oil may have one or more of the following origins: (1) oil suspended in water used in waterflooding, ( 2 ) plunger lubricating oil, ( 3 ) oil carrier used with treating chemical, (4) formation oil entering during periods of backflow, (5) oil used as oil blanket to exclude air, and (6) oil removed from tubing or piping which was used in a producing operation and transferred to injection operations.

It is important to ascertain the source of oil entering a water injection well, as it may be possible to prevent its entry. As mentioned before, the main concern with oil

323

TABLE 9-11

Cumulative volumes of oil entering injection well with injection rate of 1000 barrels per day a

Oil content Period of time in water 1 day 1 month 1 year 5 years (PPm)

1 10

100

0.048 gal 1.4 gal 18 gal 2.1 bbl 0.48 gal 14 gal 180 gal 21 bbl 4.8 gal 140 gal 1800 gal 210 bbl

a Assumptions: Specific gravity of water = 1.02 g / d ; sp. gr. of oil = 0.9 g / d .

entering the formation lies in its extreme effect on water permeability in the regions of low oil saturation (Fig. 9-2).

Field experience in some areas indicates that 20-30 ppm of oil can be tolerated in the injection water (Amstutz, 1956). Other areas show rising injection pressures whenever any oil is allowed to reach the formation in the injection wells. Operating procedures should be established, which will result in the smallest possible amount of oil entering the injection well (Lewelling and Kaplan, 1959).

Plunger lubricating oil has been found entering the water at about 0.02 ppm concentration from a well-maintained pump. T h s best-case condition, however, does not apply all the time. It is common to find several gallons of plunger lubricating oil in the pipe downstream of the positive displacement pump after it has been on stream a number of months. Overlubrication, improperly fitted wipers, worn wipers, and similar causes allow more oil to enter the water.

Suspended solids

Suspended solids are defined as material suspended in the water as compared with the dissolved solids which are in true solution in the water.

Among the many materials found as suspended solids in water are: (1) oil, ( 2 ) clay, (3) silt, (4) sand, ( 5 ) algae, (6) scale, (7) corrosion products: (a) iron sulfide, and (b) iron hydroxide, (8) bacteria, (9) bacterial growths, and (10) incompatible chemicals. (See Cerini et al., 1946; Amstutz, 1956; and Wright, 1965.)

Several different schemes can be used in classifying suspended solids. The classic classification is: (1) inorganic material (non-hydrocarbons), and (2) organic material (hydrocarbons). This classification is convenient because the differentiation is easily made by determining the solubility of the material in a powerful hydrocarbon solvent.

Suspended solids can be classified into: (1) adherent, and (2) nonadherent. Although t h s classification is hard to apply, it enables one to determine how harmful the suspended solids may be.

Adherent solids are defined as those materials which either stick to solid surfaces

324

on contact, such as oil, or form a coating over solid surfaces, such as scale. This classification is very valuable in water quality determinations, because the amount of adherent solid deposits is directly proportional to the amount of material available to form deposits. Using this criterion, one can classify the suspended solids as follows:

(1) Adherent solids: (a) oil, and (b) scale. (2) Nonadherent solids: (a) silt, and (b) sand. (3) Either adherent or nonadherent solids, depending upon composition and

circumstances: (a) clay, (b) algae, (c) corrosion products, (d) bacteria, (e) bacterial growth, and ( f ) incompatible chemicals.

Movement of formation fines

Pore channels in reservoir rocks are tortuous and irregular in size along their length. Frequently, formation fines (mineral fragments, crystals, clays, etc.) are loosely cemented to the walls of pore channels. Any change which disturbs this cementation may allow these particles to travel down the pore channel until they reach a restriction. If particles lodge in the restriction, permeability is reduced. The cumulative effect of movement of many particles is a drastic loss in injectivity.

Some of the causes of destruction of cementation of formation fines are: (1) significant changes in the salinity of water, either increase or decrease, (2) change in pH, and (3) excessive injection rates.

Sources of suspended solids

Some of the sources of suspended solids include: (1) failure of sand control measures in water supply wells, (2) overtreatment with chemicals, (3) a chemical incompatible with the water or with another chemical in use in the water, (4) air leakage into a closed system, yielding iron hydroxide and aerobic bacteria, (5) commingling of incompatible waters, (6) overloading or improper operation of wash tanks where the water supply is produced water, resulting in excessive oil in the water, (7) post-flocculation after filtration, and (8) filter breakthrough.

Suspended solids may cause the following problems: (1) suspended solids are the raw materials for the formation of deposits on the interior surfaces of a system, (2) suspended solids may be large enough to plug pore channels, causing a decrease in permeability and a consequent increase in pressure or decrease in injected volume, and (3) in due time, suspended solids, large enough to be strained out of the water by the porous formation face, will build a filter cake and reduce the permeability, leading to either pressure increases or injected volume decreases.

Adherent solids are the greatest offenders in all three cases. Nonadherent solids, however, also are very detrimental if accompanied by enough adherent solids to glue them together. It is often stated that suspended solids are not detrimental if they are small enough in size to enter the formation (Amstutz, 1956). This observation is valid only if no adherent solids are present.

325

TABLE 9-111

Cumulative volume of suspended solids a

Suspended solids concentration in 15.5-lb/ft liner injection water (PP@

Height of fill in ft after one year in 5 1/2 in.

500 bbl/day 1000 bbl/day 2500 bbl/day

1 5

10

5.3 26.2 52.5

10.5 52.3

105

26.3 131 263

a Assumptions: (1) None of the solids enter the formation. (2) Solids have a specific gravity of 2.5 g/ml. (3) Solids settle to a porosity of 40%.

An appreciation for the cumulative volume of suspended solids in a liner if none of the solids enter the formation may be gained by looking at Table 9-111. This is the extreme case, however. Injectivity falloff occurs long before fill heights occur, as noted for 2500 bbl/day injection rate in Table 9-111. The factors which determine the ability of the suspended solids to enter the formation include: (1) the size of the pores and pore channels in the formation, (2) the size distribution of the suspended solids, (3) the tendency of the suspended solids to agglomerate, and (4) the presence of oil, grease, or film-forming chemicals, whch bind or glue the suspended solids together.

If suspended solids consisting solely of sand are strained out on the formation face, they cause no loss of injectivity until the formation face is appreciably covered by fill. On the other hand, if suspended solids consisting of clay and silt are strained out on the formation face, they form a filter cake, causing very serious loss of injectivity. Suspended solids consisting of fine silt and heavy oil have the same effect as clay and silt.

The best generalization that can be made about suspended solids is that the fewer solids there are in the water, the better the water. If at all possible, the water should be kept completely free of particular matter, unless it is known that the solids can enter the formation and no adherent solids are present. In the absence of information to the contrary, it should always be assumed that suspended solids will be screened out on the rock face and, thus, cause an increase in injection pressures (Baker, 1958; Spencer and Harding, 1959).

SCALE

The term scale refers to an adherent solid deposited on a surface. The following forms of scale are possible in water injection systems, depending upon circumstances :

3 26

Cause of scale formation Chemical name Mineral name

(1) Loss of dissolved gases Calcium carbonate

(2) Solution of gases Ferric hydroxide Ferrous sulfide

(3) Commingling of waters Barium sulfate Strontium sulfate Calcium sulfate Calcium carbonate

(4) Heating without Calcium carbonate evaporation

Calcium sulfate Mixed iron oxide

Ferrous ferricyanide (5) Incompatible chemicals Calcium phosphate

Calcite, aragonite Goethite Amorphous iron sulfide Barite Celestite Gypsum Calcite, aragonite Calcite, aragonite Gypsum, anhydrite Magnetite Hydroxyapatite

Scales may be found at any point in a water injection system. It is a good generalization that prevention of scale formation is the wisest procedure. Carbonate, hydroxide, oxide, and sulfide scales may be removed by acidizing, whereas sulfate, phosphate, and ferricyanide scales are not soluble in acid. They are very difficult, if not impossible, to remove by means other than mechanical.

Calcium carbonate scale

Calcium carbonate scaling is a function of pH, temperature, ionic strength of the solution, the calcium ion concentration, and the bicarbonate ion concentration. The chemistry of calcium carbonate deposition can be shown by the following formulas:

HZCO, = CO, Carbonic acid Carbon dioxide H+ + HCO; Hydrogen ion Bicarbonate ion

Hydrogen ion Carbonate ion Ca(HC0, 1 2 = CaCO, Calcium bicarbonate Calcium carbonate

Calcium ion Carbonate ion

H+ + c0;-

Ca2+ + c0:-

+ H,O (9-1)

= H,CO, (9-2)

= HCO, (9-3)

+ H,CO, (9-4)

= CaCO, (9-5)

Water

Carbonic acid

Bicarbonate ion

Carbonic acid

Calcium carbonate

Any action wluch causes eqs. 9-1, 9-2, 9-4, and 9-5 to shift to the right may cause the deposition of calcium carbonate. The following may cause one or more of the equilibria to shift to the right: (1) an increase in temperature, (2) a loss of dissolved carbon dioxide, and (3) an increase in pH.

321

Stiff and Davis (1952) have greatly extended the excellent early work of Langelier (1946) on the stability index of waters with regard to their tendency to deposit calcium carbonate scale. The stability index ( S I ) is defined as follows:

SI = pH - pCa - pAlk - K

where pCa = - log(Ca2+), pAlk = - log(Alkalinity), and K is the ionic activity at a particular temperature. A positive stability index denotes a corrosive tendency. The stability index predicts the future behavior of the water. No estimate, however, can be made of past scaling.

Calcium carbonate scale formation may be prevented by any one of the following actions:

(1) Lowering of the pH until the stability index becomes zero or slightly negative. (2) Adding an effective scale inhibitor. (3) Removing the calcium ion by any one of the following means: (a) ion

exchange, if fresh water, (b) precipitation, (c) chelation, and (d) dilution to below the solubility limit.

Sulfate scales

The sulfate scales wluch occur in waterflood operations are as follows: (1) barium sulfate, (2) calcium sulfate (anhydrite or gypsum), and (3) strontium sulfate.

These three types of scales are normally caused by commingling of two waters: one containing sulfate ion and the other containing barium, strontium, or calcium ion. Calcium sulfate scale also may occur when temperatures are raised sufficiently to decrease the solubility of calcium sulfate to the point where precipitation occurs.

Prevention of sulfate scales in the first case normally is done by not mixing incompatible waters. When this cannot be avoided, one may follow one of the following procedures: (1) allowing precipitation, and then filtering off precipitate, (2) adding a scale inhibitor, (3) removing the barium, strontium, or calcium ion by ion exchange, if a fresh water, (4) chelating the barium, strontium, or calcium ion, and (5) diluting the offending ion to below solubility limit.

CORROSION

Corrosion is a costly item in waterflooding and must be dealt with immediately when detected. The onset of corrosion is usually insidious and the operator is lulled into a false sense of security.

One must understand the causes of corrosion in order to prevent it or stop it after it has started. It is relatively easy to protect a new, clean system, whereas it may be very difficult, if not impossible, to protect a corroded, dirty system, because protective chemicals seldom can penetrate deposits or enter deep pits filled with corrosion products. Corrosion in waterflooding operations is caused by: (1) galvanic action, (2) stray currents, (3) dissolved gases, and (4) bacterial action. Any mecha-

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Fig. 9-3. Schematic of metal surface showing arrangement of local action cells. Grains in contact with grain boundary metal. (After Unz, 1960.)

nism for corrosion or any combination of mechanisms, including all, may be present in a given water system at the same time.

All corrosion is electrochemical in nature, regardless of the mechanism involved, i.e., there must be a cathode and an anode. The following reactions are basic to the corrosion of iron:

(1) Cathode reaction: H+ + &HI - e-. (2) Anode reaction: Fe + Fe2+ + 2e-. The basic principles applying to all corrosion in water systems can be sum-

marized as follows: (1) The metal cannot corrode unless the aqueous environment is in contact with the metal. (2) Conditions in the aqueous environment must allow the cathode and the anode reactions to proceed. (3) It is not necessary for the cathode to be of a different composition (metal) to the anode. (4) The cathode and the anode must be electrically connected by a conductive solid.

It is customary to refer to the cathode and the anode as a cell. The types of corrosion cells in a water system are as follows (Unz, 1960):

(1) Dissimilar electrode cells. Dissimilar electrode cells are considered galvanic cells where dissimilar metals are joined together. There are dissimilar areas of the metal brought about by heat treatment or other processes, grains in contact with grain boundary metal, or even one metal crystal in contact with another metal crystal of different orientation (Barnard, 1959; Baumann and La-Frenz, 1963; also see Fig. 9-3.)

(2) Concentration cells. The concentration cell occurs when the same metal or two pieces of the same metal electrically connected together are immersed in electrolytes having different composition.

The following are the two types of concentration cells: (a) The first and most important concentration cell is the differential aeration cell

in which the difference in oxygen concentration produces a potential difference.

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(b) The second one is known as the salt concentration cell in which a difference in electrolyte (salt) concentration produces a potential difference.

(3) Differential temperature cells. The differential temperature cell occurs whenever the electrolyte in the cathode cell is at a different temperature than the electrolyte in the anode cell. Boilers and heat exchangers are typical examples of this type of cell.

Some causes of waterflood corrosion

The two basic principles of corrosion can be stated as follows: (1) Metal cannot corrode unless the aqueous environment is in contact with the metal. ( 2 ) Conditions in the aqueous environment must allow cathode and anode electrode reactions to proceed.

Galvanic corrosion (contact of dissimilar metals) is not considered here (see Chapter 8 on corrosion). The effects of dissolved gases, carbon dioxide, hydrogen sulfide, and oxygen on corrosion in a waterflood system are discussed below.

Carbon dioxide Carbon dioxide is the most common or prevalent cause of corrosion in a

waterflood system. Carbon dioxide dissolved in water gives rise to bicarbonates and, with increasing pH, to carbonates.

A solution saturated with carbon dioxide, at equilibrium with carbon dioxide in the atmosphere, has a pH of approximately 4.2. A solution of sodium bicarbonate has a pH of approximately 8.5, whereas a solution of sodium carbonate has a pH of approximately 10.5 to 11.

The action of carbon dioxide upon metal is primarily an acid attack with or without pitting. There is also an indirect relationship between carbon dioxide and corrosion, however, in that loss of carbon dioxide from a solution allows calcium carbonate scale to form with the attendant danger of establishment of differential concentration cells and/or anaerobic bacterial growth (within or underneath the scale).

At any given pH, dissolved carbon dioxide causes significantly more corrosion than a mineral acid, such as hydrochloric or sulfuric acid. This is due to the availability of more acid at that pH from the nonionized carbonic acid present, which replaces that consumed by the corrosion process. In the case of hydrochloric acid, there is no undissociated acid to draw upon.

Hydrogen sulfide In the direct attack of metal by hydrogen sulfide in fresh water, a protective

tarnish film of mackinawite (Milton, 1966) ages and grows with the availability of hydrogen sulfide to the formation of crystallites of pyrrhotite (Fe,S,). This is followed by increasing corrosion and pitting. In brine solutions, the hydrogen sulfide results in mackinawite film growing slowly and the corrosion rate increasing with time. Later, as the film becomes thick, the corrosion rate slows down as a layer of pyrite (FeS,) is formed.

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An indirect danger is that hydrogen sulfide causes depolarization of the cathode, owing to precipitation of ferrous sulfide.

Saturation with carbon dioxide, as well as with hydrogen sulfide, retards the development of the mackinawite tarnish and scale, resulting in lower corrosion rates. In contrast, as the mackinawite scale thickens in the absence of carbon dioxide, even higher corrosion rates result. There is a considerable amount of variation in corrosion rates with hydrogen sulfide depending upon the corrosion product. The nature of the corrosion product is influenced by the electrolyte composition.

Oxygen Oxygen is a prevalent, most serious cause of waterflood corrosion. The corrosion

rate caused by oxygen increases with increasing salinity until a level of approximately 1% NaCl is reached. Above this salt concentration, the corrosion rate falls off directly as the solubility of oxygen decreases with increasing salt concentration. Thus, the reduction in corrosion rate is caused by the reduction in the amount of available oxygen, and not by passivation. Similar effects are noted with other types of salt solutions.

The corrosion rate in the pH range of 4-10, is governed by the diffusion of oxygen to the surface of the metal through the oxide or hydroxide film. The barrier to diffusion is the ferrous hydroxide, which is continuously supplied by corrosion as i t is taking place. Under this layer of ferrous hydroxide, the approximate pH is 9.5 (the pH of a saturated solution of ferrous hydroxide). The ferrous hydroxide is dissolved below a pH of 4 and the metal surface is placed in direct contact with the electrolyte. In these low pH ranges, there is rapid corrosion, because of hydrogen evolution and oxygen depolarization. The corrosion rate drops sharply above a pH of 10, because of passivation in the presence of oxygen and alkali.

Interactions of the gases According to Dalton’s law of partial pressures, the total pressure by a mixture of

gases is equal to the sum of the partial pressures of each of the constituent gases. The partial pressure is defined as the pressure each gas would exert if it alone occupied the volume of the mixture at the same temperature.

Henry’s law applies in conjunction with Dalton’s law. The mass of a gas dissolved by a given volume of solvent at constant temperature is proportional to the pressure of the gas with which it is in equilibrium.

Owing to its higher absorption coefficient, oxygen occurs in the dissolved gases in water at a significantly higher ratio than in the air with which the water is in equlibrium. Both carbon dioxide and hydrogen sulfide, however, are far more soluble in water than oxygen.

Generally speaking, the gases are less soluble in aqueous solutions of electrolytes than in distilled water. This is known as the salting out effect. The salting out effect of a given salt is almost independent of the nature of the gas. Generally, the salting effect of an ion from a dissolved salt is larger, the greater the charge the ion carries and the smaller the size of the ion.

In the preceding discussion on solubility of oxygen and gases in water, equi-

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librium is assumed to be brought about by agitation. In the case of quiescent water, as in a tank, diffusion is the governing factor and it may be relatively rapid. Oxygen may be introduced into the water by diffusion alone when the surface of the water in the tank is in contact with air.

It is frequently stated that: “Air is excluded by the use of an oil blanket on top of the water.” Unfortunately, oxygen has a reasonable diffusion rate through oil. Oxygen can pass through the interface into the water, although at a slower rate than if the water were in contact with the air directly. Furthermore, often the oil blanket will be transported to the injection well.

It is important to note that the corrosion rate of carbonic acid is reduced by the addition of small amounts of hydrogen sulfide, owing to the formation of a uniform film of mackinawite over the metal surface. As the hydrogen sulfide concentration is increased, large crystallites appear on the surface. The number of crystallites increases with increasing hydrogen sulfide concentration until the entire surface is covered. These crystallites are believed to be an initial layer of pyrrhotite (Fe,S,) overlain by pyrite (FeS,). Generally, only mackinawite is expected to occur in brine.

Bacterial corrosion Finally, corrosion is caused by bacterial mechanisms. Bacterial growth may be

responsible for accelerating oxygen corrosion by the establishment of differential aeration cells. Bacterial growth may cause the depolarization of the differential aeration cells leading to much more violent corrosion. This is particularly true in the case of sulfate-reducing bacteria, as the hydrogen sulfide formed by the metabolic activity can depolarize one-half of the cell by precipitation of ferrous ion as ferrous sulfide. Bacteria can depolarize the other half of the cell by removing the hydrogen evolved.

In the absence of dissolved oxygen, bacterial corrosion proceeds whenever environmental conditions are favorable and an infection has been established. The corrosion rate tends to be slow initially. Gradually, the corrosion rate accelerates with time, as the bacterial growth alters the environment to a more favorable set of conditions for growth under deposits or slime. Bacterial corrosion is typically characterized by extreme pitting and corrosion products consisting of mixed iron oxides and iron sulfides.

Unfortunately, as mentioned earlier, the entry of air into an otherwise anaerobic system containing bacterial growth causes an additive corrosion. The corrosion, due to the air, is being accelerated by the bacterial growth, depolarizing the actual concentration cells. This results in far more violent corrosion than is expected from the air alone or from the bacterial growth alone.

A brief summary of the causes of corrosion in a waterflood system was presented here. Actually, many factors lead to the establishment of the differential concentration cells, such as the formation of deposits and scales. Nonetheless, these cells are not formed unless the environmental conditions are conducive and the dissolved gases are present.

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USE OF SEA WATER FOR INJECTION PURPOSES

Sea water is chosen as the injection fluid for one or more of the following reasons: (1) sea water is the only available water; ( 2 ) sea water is the only available brine; (3) sea water is less expensive than alternate sources of water.

Sea water rarely can be used as taken from the sea. Extensive processing is necessary to avoid future failure. Sea water while easily injectable into almost all formations can mean expensive lifting costs later. Sweet oil fields have been converted to sour oil fields simply by supplying sulfate ion to the ever-present sulfate-reducing bacteria. The resulting sulfide production in the oil formation means that at some piont in the future the produced gas must be sweetened before sale. Corrosion will be accelerated in the producing wells due to the presence of increasing amounts of hydrogen sulfide.

Most sweet production is associated with water that contains barium and strontium ions. If they are present in more than trace amounts, formation of barium sulfate and/or strontium sulfate scale is possible in the producing wells and facilities. Prevention of these scales requires continuous chemical treatment, which is costly.

Where alternate sources of water are available, the costs of sea water must include these hidden costs that will show up later on the oil production side of the operation. To do otherwise will be to invite financial disaster.

Characteristics of sea water

The composition of sea water is not uniform around the world, as shown by a few examples of the extremes below:

Location Total dissolved solids

(mg/l)

Open ocean 33,000 Indian Ocean 35,000 Persian or Arabian Gulf 42,000-44,000 A site on Saudi Arabian coast W of Bahrain 56,000 Half Moon Bay, Saudi Arabia 67,000

Similar examples can be cited elsewhere in tropical or semitropical areas where extensive solar evaporation occurs and there is limited replenishment from the open ocean.

There are some characteristics of sea water that are the same regardless of location: (1) oxygenated, usually near saturation, (2) at or exceeding calcium carbonate saturation, (3) neutral or alkaline pH, (4) high sulfate ion content, ( 5 ) high magnesium ion content, (6) contains living organisms ranging from unicellular to plants and fish, (7) shows seasonal changes in quality, and (8) may contail oil.

Dissolved oxygen The dissolved oxygen content of sea water can be dependent upon location of the

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intake in the water column. Sea water at the surface may be saturated and even supersaturated in oxygen due to wave action, whereas deeper in the column the sea water may be well below saturation or still near saturation depending on the presence or absence of mixing currents. Sea water taken right at the bottom may be substantially depleted of dissolved oxygen due to reaction with the organic matter that rains down from above.

Decision as to where in the water column it is best to position the intake should be taken only after sampling from top to bottom under all expected conditions.

Calcium carbonate saturation Sea water in tropical and semitropical areas is at the saturation point with respect

to calcium carbonate and may even show supersaturation for samples at or reasonably near the surface.

Any operation that is peformed on sea water such as pumping, will cause a temperature rise. Serious consideration must be given to either stabilizing the sea water by lowering the pH or to adding a scale inhibitor to prevent the formation of calcium carbonate scale.

p H of sea water Sea water is neutral or slightly alkaline in the open ocean, whereas near the shore

or in evaporation basins in tropical or semitropical areas it has higher values of pH, particularly in the summer (pH of 8.1-8.2 is not uncommon). These higher pH values may give trouble in the treatment of sea water. The pH has a decided influence on the efficiency of chlorination as well as the rate of reaction of oxygen with sulfite ion (in the oxygen scavenging stage).

High sulfate ion content Sea water, while primarily a chloride brine, has an appreciable sulfate ion

content. Normal sea water has around 2400 mg/l sulfate ion, whereas sulfate content of concentrated sea water from tropical or semitropical areas can reach 4800

As mentioned earlier, the sulfate ion provides an environment for the growth of sulfate-reducing bacteria. In addition, the sulfate ion promotes the formation of barium and/or strontium sulfate scales in producing wells when breakthrough occurs in formations containing barium and/or strontium ion.

The high sulfate ion content also precludes the use of certain treating chemicals, because they are soluble in sodium chloride brines but insoluble when significant amounts of sulfate ion are present.

mg/l.

Magnesium ion The magnesium ion in sea water is present in far greater concentration than the

calcium ion. The magnesium hardness must be taken into consideration under some conditions. The magnesium ion will exchange for sodium ion on the clays (if present) in the injection formation. The magnesium hardness may affect solubility of some treating chemicals.

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Marine life Sea water is an environment of scarcity but it still has sufficient nutrients to

permit some growth of marine organisms. The growth can be very prolific if there is organic contamination in the nearby area. Marine growth includes anaerobic to aerobic bacteria, attachment organisms, shellfish, algae, plankton, and fish.

Shellfish growth can be sufficient to plug large-diameter pipes if growth is permitted. Growth has been measured in inches per year.

Seaweed also should not be ignored. At certain times of the year, seaweed has been known to plug traveling screens at some locations.

Seasonal changes in composition of sea water Sea water composition is significantly influenced by the time of the year

(seasonal). Changes that are encountered include: (1) temperature cycles from winter to summer, (2) variation of dissolved oxygen (cycles) with temperature, although, not a direct relationship as might be expected from solubility limits, ( 3 ) possible blooming of the algae, (4) possible occurrence of red tide with absence of oxygen, ( 5 ) planktonic organisms suddenly can greatly increase apparent solids content in sea water (Mitchell and Finch, 1978), and (6) storms can greatly increase suspended solids.

Oil content It is very common to find small amounts of dispersed hydrocarbons in sea water.

These dispersed hydrocarbons are usually the heavy ends which are agglomerating solids.

Oil contents can be quite high when the location is near shipping lanes. Hopefully, with the increased emphasis on not discharging tank bottoms, this source of pollution should decrease.

There is always the possibility of an oil slick in the event of a major tank discharge or accident. Normal practice is simply to shut down the intake until the oil is gone.

SELECTION OF WATER INTAKE LOCATION

There are three main types of intakes: (1) shallow well into a sea water aquifer, (2) intake from shore, and (3) offshore intake.

The freedom of choice as to the type of sea water intake is usually non-existent due to the location of the project. Where the possibility of choice exists, a study should be made to determine the most economic choice.

Shallow well in sea water aquifer

Water supply wells drilled into a prolific shallow sea water aquifer can offer significant advantages where possible. Properly completed shallow wells will pro-

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duce water essentially free of both dissolved oxygen and suspended solids. This eliminates the need for the installation of deaeration and filtration facilities and offers substantial savings in both capital investment and operating costs. It is essential to complete these supply wells in such a manner that the casing-tubing annulus can be sealed to prevent air entry (Wright, 1972).

Intake from near-shore area

An intake from near-shore area requires considerable investigation of local conditions prior to selection of the exact site in order to prevent future problems. Some of the elements of the investigations are: (1) subsea contours, (2) shore-line currents, (3) tide extremes, (4) effects of storms, ( 5 ) character of ocean bottom, and (6) cleanliness of water versus position in water column.

The following example shows that compromises have to be made due to local conditions:

A large waterflood in South America has its sea water intake located in the mud flat area of a large bay. The intake is out of water at low tide. Inasmuch as pumping can be conducted only between mid-tide and high-tide, the intake is shut-in one-half of the time. The water from the intake is pumped into large storage pits onshore so as to provide sufficient water for continuous operation of the treatment plant. The reasons behind t h s type of operation were:

(1) Extending the intake trestle to deep water would have cost more than onshore storage.

( 2 ) Moving the intake location to an area where the mud flats did not exist would have increased pipeline cost to the field more than the cost of onshore storage and intermittent intake operation.

Offshore intake

Platform operation which necessitates an offshore intake greatly simplifies the preliminary investigations because there are only two main considerations:

(1) The water must be sampled from top to bottom of the water column to ascertain where the cleanest water can be obtained during the maximum amount of time.

( 2 ) The intake must be located upstream from the waste discharges from the platform (sanitary, kitchen, drilling fluid, etc.) as much of the time as possible. It is important to check influence of currents, tides and storms.

DESIGN OF WATER INTAKE

The purpose of the intake is to insure that the cleanest possible water is continuously supplied to the treatment plant. The elements of a good intake facility are: (1) trash screen, ( 2 ) fine screen, and (3) chlorination.

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Trash screen

The trash screen can be as simple as parallel bars spaced to prevent entry of large fish and trash. Large facilities are usually equipped with traveling rakes to remove the trash so that a dam does not build up.

Fine screen

The fine screen is used to remove seaweed, fish, and small trash. These substances can blind the filter or foul the deaerator. The fine screen can be as simple as a wire-wound section of perforated pipe for a small-volume platform intake. Large shore-based installations usually have large-diameter rotating drum screens with high-pressure jet washers to continuously clean the screen. Units are installed in multiples with at least one spare, so that one may shut down for maintenance without shutting down the entire operation.

Units must be sized to handle the maximum amount of solids which could be encountered and still deliver the maximum amount of water that the treatment plant requires.

Materials of construction are quite important because the environment is the worst possible, i.e., intermittent submergence with full wetting in aerated saline water followed by full aeration. Any crevices present will set the stage for crevice corrosion if the metal is susceptible.

Chlorination

The purpose of chlorination is to prevent the growth or attachment of marine organisms. In the absence of chlorination, algae and shellfish grow on the submerged surfaces. Shellfish growth can be of the order of several inches per year and can be costly to control if allowed to become established.

Chlorination, which can be accomplished by either adding chlorine or by adding hypochlorite (generated separately or in-line), can be either continuous or intermittent. Daily high-concentration slugs are common, although the preferred treatment is a continuous low-level dosage.

Chlorination is not as simple as it would appear when dealing with sea water in warm climates. There is a pH effect that limits the effectiveness of chlorine due to the ionization constant of hypochlorite.

Filtration

A design decision must be made whether to filter before or after deaeration. There are advantages and disadvantages of using either method.

The advantage of filtering before deaeration is that the deaerator will receive only clean water and, therefore, will not foul as quickly. Thus a maximum deaerator effectiveness will be maintained for a much longer time.

The advantage of deaerating first is that the filters will be exposed only to

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oxygen-free water and, therefore, will not need to be lined and cathodically protected. Furthermore, there should be minimum deterioration of water quality downstream of the filters because oxygen is not present to cause corrosion.

Deaeration of sea water

Deaeration of sea water is essential because oxygen is the major cause of corrosion in any sea water operation. Removal of all of the dissolved oxygen enables operation with a bare steel system.

Deaeration can be accomplished by the following methods: (1) chemical treatment, (2) vacuum deaeration, and (3) countercurrent gas stripping.

Vacuum deaeration and countercurrent gas stripping are normally followed by scavenging of the residual oxygen traces by chemical means. Oxygen traces will be present unless the water temperature is high enough to permit complete deaeration.

Chemical treatment is normally the choice for very small and for temporary systems. Vacuum deaeration is the preferred method when sweet gas is not available or has a high value.

Countercurrent gas stripping is usually the simplest and most economical method when sweet gas is available. One system, however, exists that utilizes nitrogen obtained on site from a cryogenics plant that throws away the oxygen. It was the economic choice in one case described by Matheney (1980), because the size of the installation was large enough to make the cryogenics plant economic.

Oxygen scavenging

Oxygen scavenging is done by reacting residual oxygen with sulfite ion in the presence of a suitable catalyst. The sulfite ion can be supplied in several different forms:

(1) Sodium sulfite is the preferred and most economical form when dry material is required for mixing on location.

(2) Potassium sulfite has been the preferred form when sulfite solutions are shipped due to the higher solubility of potassium salts permitting a higher concentration product.

(3) Ammonium bisulfite has become the preferred form recently because of its far greater stability in stock solution form. The low pH of strong ammonium bisulfite solution inhbits the reaction of oxygen with the stock solution. (4) Sulfur dioxide has recently become popular wherever available in small

cylinders. One large sea water treatment plant receives molten sulfur and burns it to produce sulfur dioxide on site, for use in scavenging oxygen and for pH adjustment in scale control.

Normally, cobalt is the best catalyst for the sulfite ion-oxygen reaction. At times, however, there is sufficient ferrous ion present in the sea water to catalyze the reaction. It is often found that chlorination of the sea water (to stop marine growth) releases natural catalysts and, therefore, no catalyst addition is necessary. Reaction

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times can also be influenced by the pH of the water. This influence should be carefully examined, therefore, because it may affect the sequence of chemical treatment.

Stabilization of sea water

Sea water is normally considered to have neutral pH. In tropical areas due to heavy evaporation in some basins and bays, however, the pH can be as high as 8.2.

Calcium carbonate in sea water is at or near saturation, whereas in tropical areas at the surface and in evaporation basins supersaturation can occur. Thus, sea water must be treated to prevent the formation of calcium carbonate scale. All the processing that is done to sea water to prepare it for injection and the injection process itself contribute to a rise in temperature which, in turn, causes the sea water to become more unstable.

Stabilization can be achieved by lowering the pH slightly. Sulfur dioxide, carbon dioxide and sulfuric acid have been used for this purpose. Alternatively, scale inhibition can be employed. Common practice is to employ a scale inhibitor until the injection wells have been cooled down by sufficient water injection to permit the control of scale by slight lowering of the pH.

Temperature of sea water

It should be remembered that the temperature of sea water will be nearly constant only if taken from deep zones (+300 ft) away from the coast. The temperature of surface waters and waters in shallow coastal areas can change substantially from winter to summer.

In any event, the temperature of sea water is significantly below that of practically all petroliferous formations. Thus, the injection of sea water will result in cooling of the formation, which will reduce oil recoveries by raising the viscosity of the oil. Another effect is the reduced amount of sea water that can be injected as compared to hot well water, due to the higher viscosity of sea water caused by the lower temperature.

Biocidal treatment of sea water

After deaeration and oxygen scavenging, sea water will be free of chlorine. Consequently, some form of biocidal treatment will be necessary.

There are several methods of controlling microorganisms, including surfactants, pigging, acidizing, and bactericidal treatment. Microorganisms grow on surfaces and do not constitute a problem in free flowing water. Thus, any means of keeping all of the interior walls of the system clean will control microorganisms.

The preferred method is to use routine pigging and weekly to semiweekly slug treatments by an effective bactericide. Where water temperatures are very low, such as in the North Sea, time between slug treatments can be extended significantly.

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The keys to successful microbiological control are: (1) routine pigging, (2) routine monitoring of growth of microorganisms, and (3) regular use of a bactericide compatible with sea water.

It is important to point out that culture media made up in accordance with API RP 38 (API, 1965) rarely gives satisfactory results if used to evaluate sea water. It is necessary to substitute actual sea water for the synthetic brine in API RP 38 in order to obtain satisfactory sensitivity.

Corrosion inhibition

In the case of sea water, corrosion inhibitors are not required. Inasmuch as the pH of sea water is either neutral or slightly basic, in the absence of oxygen and biological growth the corrosion rate will be very low (usually 1 mpy or less).

Inasmuch as sea water is hghly conductive, galvanic corrosion will occur unless care is taken to prevent the use of improper metallurgy. Crevice corrosion will be common in susceptible areas due to growth of anaerobic bacteria shielded from treatments.

In conclusion it can be stated that there are enough differences between sea water and oilfield waters that care must be taken in both the design and operation of a sea water injection system. In order to avoid a costly system, the peculiarities of sea water must be considered in the basic design (including metallurgy).

TEST METHODS USED IN WATERFLOODING OPERATIONS

The following test methods are used in waterflooding operations:

Test Method

Dissolved oxygen method

Membrane filter test PH

Total sulfides

Iron count Sulfate-reducing bacteria

Aerobic plate count

Direct microscopic count Salinity Geochemical analysis

Membrane-shielded electrode, ASTM D 888-81 (ASTM, 1982b) Glass electrode, ASTM Method D 1293-78 (ASTM, 1982b) 0.45-pm membrane filter, 4-ft waterhead (Wright and Cloninger, 1963) 0.45-pm membrane filter, 20-psi waterhead (NACE Stan- dard TM 01-73, 1973) Methylene blue method with preconcentration to 1/10 volume (APHA, 1980). API RP 45, Second Ed., Analysis of oil field waters (API, 1968). API RP 38, with modification that oil field water is substituted for distilled water and salt (API, 1965). API RP 38, with modification that oil field water is substituted for distilled water and salt (API, 1965). API RP 38 (API, 1965). Mohr method (APHA, 1980). API RP 45, Analysis of oil field waters (APJ, 1968).

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Dissolved oxygen

Until about 1963, dissolved oxygen could not be measured with confidence below 0.12 ppm in sea water systems. At that time, a dissolved oxygen meter became available with a probable accuracy of 0.05 ppm.

Due to improvements in techniques, however, at the present time it is possible to connect the meter to a recorder and continuously record the oxygen content of the water. The reasons of the importance of the oxygen content of the water include:

(1) Oxygen in the water stimulates bacterial growth even when bactericides are being used. Often the bactericide must be fed to the system at significantly higher treatment levels to restore control, even though the oxygen entry has been eliminated.

( 2 ) The corrosion inhibitors in use are not capable of protecting against oxygen corrosion. Corrosion by oxygen is greatly accelerated by the presence of dissolved salt.

(3) Dissolved oxygen may cause serious corrosion in the anaerobic areas under deposits or scale, because of development of differential aeration cells.

Schaschl and Marsh (1963) stated that “Isolated steel corroding by local cell action in well-aerated soil of low resistivity is a potential cathode for long cell action. If such steel is connected to steel in poorly aerated soil, long cell action will occur; the anodic steel will supply electrons to the cathodic steel. The net result is that the steel in the deaerated zone will corrode faster than if it is isolated, and it will cathodically protect the cathodic steel. Thus, if long cell action occurs under this circumstance, the local cell action corrosion rate at the aerated zone is suppressed. This and other effects of long cell action on local cells have been discussed by Pope.

A pebble or a piece of wood in contact with steel in an aerated zone can set up a vigorous long cell in which the adjacent steel is the cathode and the steel area under the foreign object is the anode. With a low anode/cathode area ratio, corrosion rate at the anodic area can be extremely high, particularly if the drained soil mechanism is operating at the cathodic area.”

p H change

The pH changes seldom are significant in the portion of the waterflood water available for testing. The pH changes are important, however, because an increase in pH results in an increased tendency to deposit calcium carbonate scale.

A decrease in pH is rare, but occurs in the case of existence of an unusual combination of factors, allowing prolific growth of sulfur-oxidizing bacteria. These bacteria convert hydrogen sulfide into sulfuric acid.

The membrane filter test

The membrane filter test (Wright and Cloninger, 1963; Barkman and Davidson, 1972; NACE, 1973) is designed to determine the amount and type of solids suspended in the water. The filter retains all solids larger than 0.45 pm and

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practically all solids larger than 0.2 pm. The solids collected usually are comprised of one or more of the following categories: (1) silt, (2) clay, (3) oil (usually plunger lubricating oil), (4) insoluble chemicals, (5) bacteria, (6 ) ferric hydroxide (precipitated due to air entry), (7) ferrous sulfide (corrosion product), and (8) calcium carbonate (scale).

The rate of water flow through the membrane is measured and the slope of flow rate-versus-time line is determined. The slope is a mathematical expression of the rate at which the membrane filter is plugged. The filter has a permeability of about 13 md (= millidarcys), which is usually very low in comparison with the permeability of formations that are being waterflooded. Changes in the slope allow one to detect changes in the suspended solids in the water. The test is a very sensitive one, and, usually, these data give the first warning that something has happened in the system.

An interpretation is made only after analyzing the solids collected on the filter. The results are then compared with the history of the waterflood operation. The physical nature of the solids has considerable influence on the plugging rate; e.g., a few milligrams of oil as discrete droplets will not plug the filter, whereas the same amount of oil dispersed as a film over the other solids will result in plugging. Similarly, the degree of dispersion of iron oxide will affect the degree of plugging. Hydroxides of iron plug the membrane quickly. The amount and nature of solids in the water are influenced by the following: (1) flow velocity, (2) presence or absence of organic binders, such as oil, film-forming chemicals, and slime, (3) bacterial growth, (4) temperature, and (5) air entry into the system.

Total iron count increase

The iron count increase is a measure of the amount of iron that has gone into solution. The total iron count increase measures not only the iron in solution, but also the iron in suspension, such as ferric hydroxide and ferrous sulfide. The iron count increase is not a reliable indicator, because much of the iron lost due to corrosion accumulates in deposits along the walls of the pipe. When iron count increases are large, trouble is to be expected.

Sulfate-reducing bacteria

Sulfate-reducing bacteria can be found growing under a wide variety of conditions. The salinity and temperature ranges are quite extreme. If secondary evidence suggests the presence of sulfate-reducing bacteria, one should either treat the system as if they were present or seek the services of a competent microbiologist experienced in working with sulfate-reducing bacteria.

Sulfate-reducing bacteria have been discussed with total sulfides. One is concerned with the actual counting of the bacteria, as contrasted with a measurement of one of their metabolic products, hydrogen sulfide. Present culturing techniques should be improved, because only a fraction of the live bacteria is counted. Thus,

342

the determined number of sulfate-reducing bacteria in a sample shows only the minimum number present. There may be many more. Inasmuch as the bacteria thrive only on surfaces, the bacteria counted in the water are only those eroded with deposits from the surfaces of the system or those traveling through the system.

Postgate in a monograph entitled “The Sulfate-Reducing Bacteria” (Postgate, 1979) stated that there are two well established genera of sulfate-reducing bacteria, each with several members. Postgate’s classification may be summarized as follows:

Sulfate-reducing bacteria

Spore formers Non-spore formers

Desulfotomaculum nigrificans orientis ruminis antarticum acetoxidans

Desulfouibrio desulfiricans uulgaris salexigens africanus baculatus

g i g a thermophilis

Sulfate-reducing bacteria constitute a potential problem in any system. Bacteria can double their numbers every 20 min under favorable conditions. Thus, any increase in numbers of sulfate-reducing bacteria across the system gives a strong danger signal, as the bacteria can get out of control quickly.

Total bacteria

Aerobic plate count (total bacteria) Aerobic plate counts are made even if one is dealing with oxygen-free systems.

Most of the bacteria in waterfloods are facultative bacteria capable of growing under air-free or aerobic conditions. Many laboratories culture the bacteria under aerobic conditions because this is the simpler way.

The reasons for the concern for the presence of total bacteria are as follows: (1) Higher levels of bactericides are needed to kill sulfate-reducing bacteria in the

(2) The decay of total bacteria constitutes food for sulfate-reducing bacteria,

(3) A layer of aerobic bacterial growth constitutes an excellent screen in an

(4) Bacterial growth can establish differential concentration cells giving rise to

presence of significant numbers of other bacteria.

giving a more favorable environment for bacterial growth.

otherwise hostile environment, allowing sulfate-reducing bacteria to thrive.

pitting.

Deep agar test (total bacteria) Total bacteria determined by deep agar test, are the bacteria other than sulfide-

producing ones growing in deep agar tubes. These bacteria are counted easily and require no additional setup. One is concerned with total bacteria determined by

343

deep agar test and total bacteria determined by aerobic plate counts for the same reasons. Total bacteria are most likely facultative aerobes, which require a low oxygen content for their rapid growth.

Membrane filter count test (total bacteria) Water is filtered through a membrane filter in the membrane filter count test.

The bacteria collected on the filter are fixed, stained, and counted under a microscope. This technique is used periodically to check the culturing techniques. The number of bacteria is compared with that grown in culture media.

Iron bacteria are identified and counted separately in the membrane filter test, because they do not grow in the culturing tests. Iron bacteria are undesirable because their long, filament-like bodies mat together, forming an organic deposit wherever they lodge in a system. This organic deposit constitutes an excellent environment for sulfate-reducing bacteria as well as setting up differential concentration cells.

Corrosion coupons

Insulated corrosion coupons Corrosion coupons are installed at selected locations adjacent to injection wells.

An effort is made to install them at the lowest volume injection wells furthest from the plant. These coupons are 3/4 X 3 X 1/8 in. in size and are prepared from cold-rolled ANSI 1018 or 1020 mild steel. Thus, they represent an infinitesimal percentage of the surface exposed in the system. For details concerning the preparation of corrosion coupons one should consult ASTM Method G1-72 (ASTM, 1982a) and NACE Recommended Practice 07-75 (NACE, 1975).

Inasmuch as the insulated coupon is electrically insulated from the system, theoretically its corrosion rate is related only to the corrosivity of the water. Experience has shown, however, that the corrosion attack on the insulated coupon in a dirty system is similar in type and rate to that on the noninsulated coupon. Evidence indicates that the electrical insulation is nullified by a conductive film, which is probably associated with bacterial growth.

Corrosion coupons show significantly higher corrosion rates than adjacent spools or tubing. Probably, the following factors are involved:

(1) The mild steel coupon is more susceptible to corrosion than the alloy steel used in the system.

(2) The coupon is a clean specimen freshly installed in a dirty system. It is exposed for a relatively short time and, therefore, the initial corrosion is magnified by use of the time multiplier.

( 3 ) The method of exposing the coupon by placing it in the center of the pipe causes a zone of turbulence. The effect of this turbulence is unknown. It is known, however, that the amount and nature of the deposits on a coupon are not the same as those found on the pipe walls. The coupon has a thinner deposit, probably because of both high velocity of water and short exposure time. The deposit tends to be high in organic matter and low in solids content.

344

Noninsulated corrosion coupons The same comments apply to the noninsulated coupons as to the insulated

coupons. The noninsulated coupon is electrically connected to the system. Thus, a galvanic cell is deliberately set up with the high probabiliy that the noninsulated coupon is anodic to the system. It should be recognized that the corrosion rate obtained is not representative of the system.

Pitting corrosion appears first on the noninsulated coupon, probably because the galvanic cell set-up provides an ideal environment for bacterial growth. The trend of the results of successive tests is carefully examined: the lower the corrosion rate on the noninsulated coupon, the better protected the system is.

Exposure time of corrosion coupons Exposure periods of 30, 60, and 90 days are recommended in the case of

corrosion coupons. Thirty-day exposure period enables the quick correction of problems of air entry, low pH, and gross bacterial contamination, which give large to excessive corrosion rates in 30 days.

Sixty- and ninety-day exposure periods enable detection of pitting corrosion in a relatively clean system, which shows low corrosion rates without pitting on 30-day exposure. Detection of the long-term pitting enables implementation of corrective action before significant damage is done.

Significance of various tests

In the conventional approach to water quality and corrosion control testing, use is made of many tests as described above. Some of these results are direct indications of factors affecting corrosion, whereas others give indirect indications:

Direct indicators Indirect indicators ~~~~ ~ ~ ~~

(a) Corrosion coupons (b) Iron count increase (c) Dissolved oxygen (d) Polarization probes

(a) Total sulfide increase (b) pH and Eh changes (c) Membrane filter tests (d) Cultured corrosion coupons (e) Bacterial counts:

(I) Sulfate-reducing (2) Aerobic plate count (3) Total bacteria (4) Membrane filter direct microscopic test

Indirect indicators deal with changes in the water, with the exception of cultured corrosion coupons. These changes in the water are caused or influenced by the environment at or near the metal surface-water interface. An understanding of what is measured and how that variable is influenced by the system enables one to interpret the test better.

345

TABLE 9-IV

Values of the individual tests

Test Measurement Significance

Direct measurement of corrosion Polarization probes Corrosion rate

Pitting tendency

Corrosion coupons Insulated Corrosion rate

Pit frequency Pit depth

Pit frequency Pit depth

Noninsulated Corrosion rate

Cultured Corrosion rate Pit frequency Pit depth

Indirect rneasuremeni of corrosion Iron count increase Soluble and insoluble iron salts

in the water

Direct measurement of bacterial growth Bacterial counts Sulfate reducers

Total bacteria, deep agar

Aerobic plate count

Direct microscopic count

Indirect measurement of bacterial growth Total sulfide increase in the water.

Soluble and insoluble sulfide salts

Pessimistic if allowed to become coated with deposits. Pessimistic if allowed to become coated with deposits.

Believed to be pessimistic Believed to be pessimistic Believed to be pessimistic Not a measure of system corrosion, but a measure of galvanic corrosion and bacterial depolarization. Not a measure of system corrosion, but a measure of the presence and activity of corrosion causing or accelerating bacterial growth.

An averaging of iron losses between the two points where measurements are made, diminished by the amount of insoluble iron deposited on the walls of the pipe.

Represent the populations in the water, but only suggest that bacteria are growing in the deposits. A negative answer is not conclusive.

The sulfide comes from bacterial reduction of sulfate ion. Amount of sulfide is related to the amount of bacterial activity and extent of infection. Answer is somewhat optimistic, due to precipitation of sulfide in deposits as ferrous sulfide.

346

TABLE 9-IV (continued)

Test Measurement Significance

Redox potential Eh change

Tests relating to the environment Dissolved oxygen Oxygen

Membrane filter test

Slope Amount of solids Composition of solids

Test is an averaging of sulfide generated between the two points sampled. Average measurement of all bacterial activity between the two points sampled. It is influenced by all bacteria, not just sulfate-reducers. Detects air entry in a closed system.

Determines the oxygen content to 0.01 ppm in the water at the point of sampling. Determines amount of solids and their probable tendency to cause deposits.

Water tests, to be meaningful, must measure the changes that have occurred in the water. The assumption that the water source is uniform and uncontaminated can be dangerous. The values of the various tests can be summarized as shown in Table

Originally, the iron count was expressed solely as parts per million of iron found in the water. Later, one looked at the increase in iron count across the system. This method was better, but needed to be improved. Then iron count increases were expressed as pounds per day per 1000 sq ft of metal surface exposed to the water. This permitted one to make direct comparison between portions of a system and between systems. A better way of expressing the rating, however, is as mils/year

9-IV.

TABLE 9-V

Comparison of iron count units

Iron count increase Corrosion rate Rating (lb/day/1000 sq ft) (mils/year)

0 0.001-0.017 0.012-0.11 0.12-0.59 0.60-1.1 1.2

0 0.01-0.09 0.10-0.99 1.00-4.9 5.0-9.9

10.0

None Very low Low Moderate High Excessive

347

TABLE 9-VI

Revised rating chart of sulfide increase

Sulfide increase (lb/day/1000 sq ft)

Equivalent deposit thickness (in.)

Rating

0 0.001 0.002-0.004 0.005-0.009 0.01-0.019 0.02 and over

0 0.0072 0.014-0.028 0.036-0.065 0.072-0.137 0.14 and thicker

None Very low Low Moderate Large Excessive

corrosion rate. The comparison of two different ways of expressing iron counts is shown in Table 9-V.

All iron count increases should be expressed as mils/year corrosion rate. This enables a direct understanding of the magnitude of the increase.

Originally, the total sulfides were expressed as parts per million sulfides in the water. Later, engineers examined the increase in total sulfides across the system. This technique was better, but it still needed to be improved, as did the iron count increases. Much later, total sulfide increases were expressed as pounds per day per 1000 sq f t of surface. T h s permitted one to make direct comparison between portions of a system and between systems. As in iron counts, pounds of sulfides per day per 1000 sq ft was used as a unit. A considerable amount of introspection, followed by literature study, led to the concept that sulfate-reducing bacteria cannot thrive without having space in which to grow. This space is provided only by deposits.

Deposit thickness was then related to bacterial populations and to probable rate of sulfide generation. This resulted in the conversion of sulfide increases to probable deposit thickness. Probable deposit thickness is a term that can be visualized and, therefore, carries more meaning to the petroleum engineer (Table 9-VI).

The use of rating chart for sulfide increases presented in Table 9-VI is based on the assumption that essentially all the sulfide generated in the system is released to the water. This assumption is fairly reliable when there is no oil in the system to coat and bond ferrous sulfide to the pipe. It is also assumed that strong film-forming chemicals, such as the nitrogenous corrosion inhibitors and bactericides, are absent.

When a film former and/or oil is present, much of the ferrous sulfide created in a system is plated out as deposits. In no case investigated to date have all the sulfides been plated out, some sulfides always remaining in the water. The sulfide is present as colloidal ferrous sulfide or an excess of sulfide over and above that required to tie up the ferrous ion.

A sharp increase in total sulfides may be expected whenever chemical treatment is changed and earlier deposits are stripped off the walls of the pipe. The degree to

W P a3

TABLE 9-VII

Waterflood rating chart (Wright, 1963; Collins and Wright, 1982)

Rating 1 2 3 5 10 20

Total sulfide (S) increases: equivalent deposit thickness, inches Iron-count (Fe) increases: equivalent mils/ year Increase in sulfate- reducing bacteria, colonies/ml

Increase in total bacteria count (B), colonies/sq ft/day Corrosion rate, 30 days, insulated coupon mils/year ( MP Y ) Pit depth, 30 days, insulated coupon, mils Pit frequency, 30 days, insulated coupon, pits/sq in. Permeability (k) of filter cake, md Suspended solids (SS) increase, mg/sq ft/day

S < 0.007 none

Fe < 0.01 none

none

B < 10'

neghgible MPY < 0.01

none 0 none 0

none k > 4 excellent SS < 170 excellent

0.007 < S < 0.014 very low

0.01 < Fe < 0.1 very low

sporadic random appearance questionable 107 < B < 108

very low 0.01 < MPY < 0.1

very low 1 shallow 1

very low 4 > k > 0.4 very good 170 < SS < 350 very good

0.014 < S < 0.035 low moderate

0.035 < S < 0.072

0.1 < Fe < 1.0 low moderate

1.0 < Fe < 5

absent present more times more times than present than absent acceptable moderate lo8 < B < lo9 lo9 < B < 10"

low moderate 0.1 < MPY < 1 1 < MPY < 5

low 2-3 minor

moderate 4-5 moderate ...

L 5

low moderate 0.4 > k > 0.04 acceptable moderate 350 < SS < 520 acceptable moderate

0.04 > k > 0.004

520 < SS < 870

0.072 < S < 0.14 large

5 < F e < 1 0 large

always present

large 10" < B < 10"

1-9/ml

large 5 < MPY < l o

high 6-10

4

high 0.004 > k > 0.0004 fair 870 < SS < 1300 fair

S z 0.14 excessive

Fe > 10 excessive

greater than 9 col/ml

excessive B > 10"

excessive MPY > 10

excessive 10 + excessive 5+

excessive k < 0.0004 poor SS > 1300 excessive

349

which this occurs is a function of the nature of the bonding material and the ability of the new treatment to disrupt the bond.

A similar study was made of total bacteria, because the problem with bacteria counts is that the number obtained can not be visualized in terms of field application.

It must be remembered that the bacteria that are counted in a water sample represent the sum of two components: (1) the bacteria entering the system and traveling through, and (2) the bacteria eroded off the walls of the pipe from actively-growing deposits. Thus, to obtain an insight into the significance of a bacteria count one must translate the number of colonies per milliliter into a universally usable number. Increase in the number of colonies per square foot of interior pipe surface, which is a useful measure, can be expressed as follows: Increase in number of colonies/sq ft/day = (increase in bacteria colonies/ml)(bbl/day water)(607, 200) : (diameter, in.)(length, ft).

The increase in bacteria expressed as number of colonies per square foot of surface has the same limitations as iron counts and sulfide increases, i.e., assuming uniform conditions between the two points sampled. Localized hot spot conditions cannot be detected except by sampling at closer distances along the systems.

High numbers of general bacteria colonies per square foot of surface has the same significance as a thick average deposit thickness, as determined by using the sulfide increase test. Simply stated, it means that the system is dirty. Remedial measures can be the same as those in the case of high sulfide increases.

The rationale for developing the numerical rating for increase in bacteria per sq ft per day is as follows:

The industry yardstick for numbers of general bacteria that do or do not constitute a problem was developed some twenty years ago. It was determined that there was no loss of injectivity in a waterflood when the general bacteria counts were 10,000 colonies per milliliter or lower. When the general bacteria counts became 100,000 colonies per milliliter or larger, there was loss of injectivity. This observation has become the rule of thumb for most oil-field personnel.

In preparing a classification, a flow rate of 3 ft/sec was assumed in a 6-in. diameter injection line one mile long. The assumptions are reasonable because the end result is in several orders of magnitude, whereas any errors in the assumptions would be substantially less than one order of magnitude (see Table 9-VII).

The waterflood rating chart (Table 9-VII) was developed to enable interpretation of the test data, which are usually determined during waterfloods. This chart appears to be the first attempt to ascribe ratings. Although there has been very little opposition to the chart in the industry, opinions vary considerably as to the range under each rating. One can categorize the tests as shown in the following outline: (1) Measurement of actual corrosion:

Direct Indirect

(a) Corrosion rate, insulated coupon (b) Pit depth, insulated (c) Pit frequency, insulated

(a) Iron count increase

350

(2) Measurement of factors leading to corrosion:

Direct Indirect

(a) Polarization probe (b) Sulfate-reducing bacteria

(a) Total bacterial count (b) Total sulfide increase (c) Direct microscopic count (d) Dissolved oxygen

( 3 ) Direct measurement of actual loss of injectivity: Well injectivity

(4) Measurement of factors leading to loss of injectivity:

Direct Indirect

(a) Membrane filter slope (a) Aerobic plate count (flow rate-versus-time line)

(b) Filtered solids (b) Total bacteria, deep agar (c) Direct microscopic count (d) Dissolved oxygen

Relative importance of the various tests is presented in Table 9-VIII. One can see that there are two kinds of tests: (1) those that measure actual corrosion, and ( 2 ) those that measure the environment conducive to corrosion.

'TABLE 9-VIII

Relative value of tests a

Test Corrosion Ability of test indicator to predict

future corrosion ~

Dissolved oxygen Polarization probe

Corrosion rate Pitting rate

Corrosion coupons Corrosion rate Pit depth Pit frequency

Iron count increase Sulfate-reducing bacteria 'Total bacteria Total sulfide increase Membrane filtration slope (flow rate-versus-time line) Filtered solids

1

1 1

5

5 5

5 3

a Scale : 1 = best.

351

TABLE 9-IX

Significance of various tests

Test Remarks

Membrane filtration test Slope of flow rate-versus-time line

Filtered solids

Total bacterial count

Total sulfide increase

Corrosion coupons

Measures the plugging ability of solids; it is directly related to their ability to form deposits Measures the amount of solids in the water available to form deposits When the count is above 10,000 per ml, there is a strong probability of slime growth Measures the activity of sulfate-reducing bacteria in deposits and indirectly gives the thickness of deposits The presence and amount of deposit on the coupon is related to the presence and amount of deposits in the system

No system is safe unless results of all tests are favorable. The system is rated as “reasonable” or “in trouble”, depending upon whether present time or the future is considered. Often a system requires two to three months to fudy respond to a certain action. The crux of the problem is that one is trying to interpret tests run at the wellhead and predict the nature of conditions in the injection well.

On examining the results of various tests, one may reach the following conclusions: (1) If deposits and/or scale are building up at the wellhead, they are building up in the well. (2) If bacterial growth is occurring at the wellhead, it is occurring in the well. (3) If corrosion is occurring at the wellhead, corrosion is occurring in the well. (4) If oxygen is present in the water at the wellhead, corrosion is occurring in the well.

Usually, one is restricted to malung measurements at the wellhead where the water has only traversed 10% of the system. One must, therefore, infer, interpret, or guess what the actual conditions in the well are. A trend, with time, toward conditions conducive to corrosion is bad, even if the actual values are low. In addition, conditions such as deposit and/or scale formation that cannot easily be reversed must be prevented.

Bacterial growth can be controlled easily in the absence of deposits and/or scale. In addition, corrosion inhibitors perform best when the system is clean. Conse- quently, in interpreting the test results, one must give considerable weight to any test indicating the buildup of deposits. The tests presented in Table 9-IX give some clues as to the existing conditions. The tests indicating corrosion and deposit buildup are the most significant.

Possibly, one could minimize the interpretative difficulties by making determinations on surfaces exposed in the system. It may be practical to expose a surface for 30 days or longer, remove it from the system, and make the following determinations: (1) amount of deposit, (2) nature of deposit, and (3) composition of deposit (water, hydrocarbons, and nonhydrocarbons).

352

Summary

The significance of various tests can be summarized as follows: (1) The insulated coupon test directly measures corrosion. The disadvantage of

this test is that it represents only the conditions present at that one location, which is an infinitesimal fraction of the surface area of the system.

(2) Noninsulated and cultured coupons tests elucidate the mechanism of corrosion by providing a more favorable environment for corrosion.

(3) Dissolved oxygen and total sulfide increase tests directly measure factors which cause or accelerate corrosion. The dissolved oxygen test is direct and realistic. The sulfide increase test can be optimistic, due to the binding of sulfides in the deposits as ferrous sulfide.

(4) Two tests measure bacterial growth in the system. The bacterial counts represent only those bacteria eroded away from deposits. Thus, a negative answer is always questionable. The redox potential change is an averaging test, which indirectly indicates the amount of total bacterial activity between two points or indicates air entry in a closed system. This test is reliable in the presence of large differences, but is not reliable when small differences exist.

( 5 ) The membrane filter test measures the amount and kind of solids in the water. Proper interpretation of this test allows the correction of conditions which cause deposition, before significant deposits are formed.

There are many useful tests, but their quantitative significance is hard to determine, because most of the tests are indirect measurements of processes taking place in the system and only partially measure the dynamics at the metal surface-water interface.

Inasmuch as one is measuring the change that has occurred in the water, it must be determined where the change took place. Conceivably the following alternatives are possible: (1) The entire system between sampling points contributed uniformly to the change. (2) Only 10% or less is responsible for the change, and 90% or more of the system between the sample points did not contribute to the change.

Under these circumstances, a given change can be interpreted as catastrophic or negligible in nature, depending upon whether one assumes that 10% or less of the system or the entire system caused the change. Interpretation of water tests, therefore, is fraught with many apparent contradictions between predictions and actual field results.

Reporting of test data

An immediate verbal report of test data is made whenever conditions warrant correction. A written report of the findings, together with recommendations, is made as soon as the laboratory phase of the testing is completed, except the test for sulfate-reducing bacteria. The latter report includes preliminary bacterial counts after one or two weeks of incubation. Final bacterial counts are made at the conclusion of four weeks of incubation, as prescribed in API RP 38 (1965).

353

Test data are plotted on time series graphs. This graphical presentation is examined monthly and enables a quick detection of trends. This is very valuable, because if water is sampled only once a month, erroneous conclusions can be reached if judgement is based on analysis of a single sample.

PREPARATION OF WATER FOR SUBSURFACE INJECTION

There is a limited choice in deciding how to prepare a water for subsurface injection, because the nature of the effluent has a decided bearing on the problem. The choice is very limited in specific instances. Some treatment processes (see Wright and Davies, 1966) are common to all sources of water, whereas others are peculiar to one or more sources. Figure 9-4 is a schematic of a typical Mid-Conti- nent waterflood installation. The major treatment processes for water injection are as follows: (1) oil removal, (2) gas removal, and (3) solids removal. All other treatment processes are subsidiary to these main processes.

Oil removal

Oil removal is basic to all treatment processes involving oil field water, although the necessary completeness of oil removal may vary widely. There is an economic limit or dividing line for each lease when the amount of oil removal for the value of the oil recovered ceases to be profitable.

The ease of removing oil from water is greatly influenced by chemical treatment and the physical handling of the oil-water mixture before it reaches the injection water system. Frequently, the operator may make a minor change in the chemical treatment or the physical handling of the oil-water mixture before it reaches the injection water facility. This change may result in a considerable increase in the cost of operating the injection water facility.

The treatment and handling of oil and water from the point where they leave the formation to the ultimate injection of the water must be viewed as an integrated process. All changes, mechanical or chemical, must be reviewed for their total effect on the system, not just the immediate problem at hand. The following examples illustrate the need for integrated approach:

(1) Overtreatment of producing wells with certain types of scale inhibitors will stabilize the dispersion of oil in water, malung oil removal in the injection water system more difficult.

(2) Certain types of corrosion inhibitors act as oil-in-water emulsifying agents and will cause oil-in-water emulsions to appear in the injection water facility when used in slug treatments.

(3) Some emulsion breakers used today, which give rise to very clean oil, produce very stable oil-in-water emulsions in the injection water facility.

There are three practical methods of removing oil from water, each one having its distinct place in water treatment: gravity separation, flotation, and filtration.

W v, P

FW.K.0.

TT TREATER

SUB-SURFACE WATER INJECTION SYSTEM

w . s 57- w.

w s . w No. 2

- -___ --EL -

RAW WATER TANK

1000

4 3 9 BACKWASU I

TANK I500

TO DISTRIBUTION I20 INJ WELLS)

TANK

INJ WELL

PRODUCTION PROFITS, INC. I DALLAS, TEXAS

Fig. 9-4. Schematic of a typical Mid-Continent waterflood installation. (Courtesy of Production Profits, Inc.)

355

0.11.

0.10

... i 0

> !I > a $ 0.09 2 LL u W a 111

-

I

- 5 0.08 + ?

E a

>

> [L 0

u w

VI n I

a06

0.05 60 80 100 120

TEMPER ATU R E O F

/

Fig. 9-5. Effect of temperature on specific gravity difference between water and oil.

Gravity separation In gravity separation, the oil and water mixture is allowed to separate into two

distinct phases, owing to the difference in specific gravity between the oil and water. This process, which is highly effective with low-specific-gravity oils (high "API) ', becomes less effective or even impossible with high-specific-gravity oils (low "API).

The separation is significantly aided by temperature. Temperature reduces the viscosity of the dispersion medium (water) and further increases the specific gravity

"API = (141.5,’~~. gr. at 60OF)- 131.5.

356

differential between the oil and water (Fig. 9-5). The less the specific gravity difference between the oil and the water, the lower the rising velocity of oil and, therefore, the longer the residence time required in the separator.

The subject of gravity separation has been covered in detail in an API manual in 1963 (API, 1963). The following references should be consulted when the engineer is dealing with tanks, API gravity separators, or open ponds, because the principles are the same in all cases: API (1951), Ingersoll (1951), Johnston and Campbell (1957), and Brunsmann et al. (1962). Usually, utilization of these principles gives a high degree of success in oil removal. The causes of difficulty of oil removal in the unusual case may be the presence of emulsions or the lack of sufficient specific gravity difference between oil and water. When the gravity separator does not give the desired degree of oil removal or it is not feasible or economical to use a properly-designed gravity separator, one must use the flotation principle.

Flotation There are two distinct types of flotation processes in use today: dissolved gas

flotation and froth flotation. Froth flotation is an adaptation of a beneficiation process long used in the

mining industry. Froth flotation requires the addition of a chemical to stabilize the froth, whch is mechanically formed by “beating” air or gas into the water. Froth flotation is less sensitive to overloading than dissolved gas flotation; however, it has other shortcomings. These may limit the application of froth flotation to a specific system and field trials are highly recommended.

Aside from the manner in which the gas bubbles are formed in the water, the two types of flotation processes are similar. Dissolved gas flotation is a process in which gases are dissolved into the water under pressure. Upon subsequent release of pressure, the evolving bubbles become attached to particulate matter and/or oil, and float them to the surface where they may be skimmed off (Katz, 1958, 1960; Simonsen, 1962; API, 1963).

Flotation is a highly efficient method of removing suspended oil from water when the load is less than 100 ppm and emulsions do not exist. Increasing amounts of oil are left in the water as the incoming load increases. The flotation process has the following shortcomings: (1) emulsions are seldom resolved, (2) suspended solids may interfere with oil removal, (3) high incoming oil contents give rise to more oil in the output, and (4) the process is very sensitive to (a) velocity or throughput, (b) gas/water ratio, and (c) recycle ratio.

When the flotation cell is overloaded or when emulsions are present and cannot be prevented by remedial measures upstream, one must use supplementary chemical treatment with the flotation cell. Certain clays are good adsorbents of oil. Adding these clays as a slurry to the flotation cell, followed by a polyelectrolyte, results in a very clear water discharge. Alum, alone or with coagulant aids, also helps an overloaded flotation cell or one receiving emulsions.

The chemical theory, which is the older conventional theory, assumes that (a) the colloids are aggregates of defined chemical structure, (b) the primary charge of

357

colloid particles arises from the ionization of complex inorganic groups present on the surfaces of the dispersed particles, and (c) the destabilization of colloids is due to the chemical interactions, such as complex formation and proton transfer. This chemical theory, however, does not explain all the processes that take place during coagulation. As a result, a newer theory has been developed called the “physical theory” ’. This theory emphasizes the concept of the electrical double layer and the significance of predominantly physical factors, such as counter ion adsorption, reduction of zeta potential, and ion pair formation in the destabilization of colloids. It has aided significantly in the interpretation of coagulation mechanisms and in control of coagulation techniques, and has practically replaced and superseded the older chemical theory (Black, 1948,1960; Stumm and Morgan, 1962; Riddick, 1964; Hudson, 1965).

Filtration is necessary when the last traces of oil must be removed from the water and when gravity separation and/or flotation are inadequate. Filtration is also used when solids must be removed.

Removal of solids (filtration)

Filtration must be viewed as a clean-up or “polishing” operation, as it is not economical for removal of large amounts of solids or oil from water. The choice of a filter is based upon the following factors: (1) quality of effluent desired, ( 2 ) amount of suspended solids, (3) nature of suspended solids, (4) capital cost versus operational cost, ( 5 ) space available, (6) weight of installation (offshore platform loading considerations), (7) flexibility of operation desired, (8) salvage value, (9) degree of mobility of equipment desired, (10) variability in quality of incoming water, and (1 1) degree of reliability of operation required.

Conley (1965) has presented an excellent discussion on the interrelation of the various components of a water treatment plant, showing how to determine the optimum treatment practice and optimum sizing of the various components for greatest economy.

The classic concept of water filtration is the use of the slow sand filter in which a layer of solids (filter cake) is built up on the top layer of sand. This layer is known as the “Schmutzdecke”. (It is composed of the solids causing the turbidity in the water and bacterial growth). The filter cake concept applies only to the slow sand filter. The rapid sand filters build a collected solids zone inside the top layers of the filter media.

Until recently all domestic water plant installations have had sand filters, either slow or rapid. A revolution in water filtration has occurred in the last four decades. This revolution had its origin in the need for mobile treatment plants for use by the armed forces during World War 11. Portable diatomaceous earth filters were devised and used extensively by the armed forces. In recent years the utility of these diatomaceous earth filters has led to a determined assault on the problems of water

’ A more appropriate name will be “physicochemical theory”

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filtration. In recent years more papers have been published on water filtration and coagulation than on any other phase of water treatment.

The following filters are being used at the present time: (1) slow sand filters, ( 2 ) rapid sand filters; (a) gravity sand filters; (b) pressure sand filters, and (3) d’ iatoma- ceous earth filters. Each filter has its proper place in water treatment.

Slow sand filters The slow sand filter has been superseded by the rapid sand filter in all new

installations built in recent years, because the slow sand filter requires very large surface area for its operation, is inflexible, and is not backwashable. Regeneration of the filter bed requires physical removal of the top layer of sand with the “Schmutz- decke”, which is done with shovels.

Rapid sand filters Rapid sand filters are divided into two main types: (1) gravity and (2) pressure

filters. The principles of the two types of filters are identical. The pressure filter is operated at elevated pressures, thus prolonging the filter cycle and/or increasing the rate of flow of water through the filter. Gravity filters are commonly operated at 2 GPM/sq ft ’, whereas pressure filters are opearted at 3 GPM/sq ft and higher.

The rapid sand filter is operated with clarification ahead of the filter. This step reduces the load on the filter, allowing longer filter runs and high quality effluent at higher flow rates. Rapid sand filters have a layer of sand on layers of graded gravel and do not utilize a “Schmutzdecke” layer for the filtration action. Instead, the particulate matter is adsorbed on the sand in the layers below the surface. A considerable amount of support for the adsorption of solids causing turbidity as the predominant removal mechanism of rapid sand filters was gained from the report of O’Melia and Crapps (1964) in their study on the chemical aspects of filtration.

Rapid sand filters are customarily operated with sand on top of a graded gravel bed. A considerable amount of interest, however, has been shown in some areas in the use of sized coal in place of sand. Coal has the advantage of lower density, occupying greater volume per unit weight, and, more important, requiring lower velocity of the backwash water to suspend the coal bed during the washmg or scrubbing cycle. Coal, however, is soft and abrades rapidly, with reduction in particle size. This results in losses during the backwash cycle and, consequently, coal replacement is much more frequent than that of sand.

A skid-mounted bank of three high-rate rapid sand filters ready for shipment to the field is presented in Fig. 9-6. Figure 9-7 is a cutaway drawing of a hgh-rate rapid sand filter showing the internals and the media. Figure 9-8 shows the inlet distributor, whereas Fig. 9-9 shows the bottom drain collector for a high-rate rapid sand filter. The openings are spaced to obtain an equal flow through each.

High-rate rapid sand filters High-rate rapid sand filters have been developed in the 1960’s (Udwin, 1971).

’ GPM or gpm = gallons per minute; 1 gal = 0.003785 cu m = 3785.43 cu cm.

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Fig. 9-6. Skid-mounted bank of three high-rate rapid sand filters. (Courtesy of Serck Baker, Inc.)

Rates exceeding 10 gal/min/sq ft with effluent quality of less than 0.2 mg/l of suspended solids are not uncommon. The high filtration rate is achieved by optimizing inlet and discharge header flows in order to obtain uniform flow through the entire filter bed. Dual-media beds are common and some triple-media beds are in use.

Dual-media may consist of coal on top of sand or coal on top of garnet. Triple-media beds consist of all three, i.e., coal, sand, and garnet. A combination of particle size and specific gravity serves to adjust the mass of the particles of each media so that minimal intermixing of the layers takes place during backwashing. The use of multiple media permits either higher bed loadings or longer filter runs. Normally, the coarsest particles are at the inlet of the filter bed.

Other types of high-rate rapid sand filters have been developed and promoted. A popular type is the upflow filter in which the inlet is at the bottom and the flow of water is up through the bed. Whereas advantages are claimed for upflow filters, one must be aware of their sensitivity to hydraulic shock, which can cause unloading of collected solids into the filter effluent. In another type of filter, the inlet is at the center, with flow occurring both upwards and downwards from the middle of the bed.

It is strongly advised that filters be purchased based on either field trial or

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Fig. 9-7. Cutaway drawing of a high-rate rapid sand filter. (Courtesy of Serck Baker, Inc.)

performance under identical circumstances. There have been too many failures when filters were purchased on the basis of “specifications” only, without trial.

Diatomaceous earth filters Diatomaceous earth filters consist of a screen or screens upon which a founda-

tion of cellulose fibers and diatomaceous earth is laid (called “ precoat”). Once the precoating is in place and functioning, water filtration is commenced with a continuous addition of diatomaceous earth slurry called filter aid, body feed, or slurry feed. Whereas diatomaceous earth is the customary choice, expanded perlite is preferred in some areas, owing to its local availability or availability at a lower price than diatomaceous earth. A task group of the American Water Works

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Fig. 9-8. Inlet distributor for a high-rate rapid sand filter. (Courtesy of Serck Baker, Inc.)

Fig. 9-9. Bottom drain collector for a high-rate rapid sand filter. (Courtesy of Serck Baker, Inc.)

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Association led by Baumann (1965) prepared a report on diatomite filters, with many references. This report covers in detail the design, installation, and operation of diatomite filters in large-scale plants. It should be consulted for general background information.

Baumann and LaFrenz (1963) reported on the extreme need for optimizing filter design, as water production costs can be four to five times higher than necessary if other than optimum conditions are used for flow rate, terminal head loss, and body feed. Automatic operation proved to be most economical for all waters and plant siLes. Maintenance of an automated plant, however, can be a problem if qualified personnel are not readily available.

In a paper presented by Bell (1962), a considerable amount of information is made available about various aspects of design relating to hydraulic velocities, septum considerations, adequacy of filter cleaning, precoating technique, and principles of continuous slurry feeding. This paper should be consulted when designing a diatomite filter.

Selection of diatomite Several grades of diatomite are available for use as a filter aid. The principal

difference among the various grades of diatomite is particle size distribution, which causes the difference in filtration properties. The finest size filter aid, which gives the lowest flow rate, is used for removing tight emulsions and ultrafine colloids. The coarsest grade of diatomite (high flow rate), on the other hand, produces water of good clarity when the “ turbidity” is due to relatively coarse particles.

The common shortcoming of inadequately prepared diatomaceous earth is short filter cycles, resulting from the rapid buildup in filtration pressure. The final selection of a filter aid should be made only on the basis of field trials, inasmuch as one is striving to optimize the following variables: filtration pressure, filter effluent clarity, filter cycle time, and rate of flow through the filter.

When diatomaceous earth filters are properly run, they deliver hgh-quality water. One can routinely obtain filtered water having 0.2 ppm suspended solids. Unfortunately, it is very easy to plug wells on using improperly operated diatomaceous earth filters. Some of the causes of filter failure are as follows:

(1) Leaving open the line to hgh-pressure pumps when backwashng and precoating filter. As a result, large amounts of fiber and diatomaceous earth are injected into the wells.

(2) Dropping off of the filter cake and precoat from the screen, in whole or in part, owing to temporary shutdown of the filter or to a momentary pressure surge. Subsequent operation of the filter results in all slurry feed and all suspended solids going through the filter into the high-pressure pumps and/or into the wells.

(3) Inadequate precoating of the screens which may leave holes in the precoating. This results in the same condition as described in (2), but to a lesser degree.

(4) Leaving a backwash valve open, partially or completely, after backwashing the filter. This results in partial or complete bypassing of the filter. This is worse than having no filter at all, because, in addition to bypassing the filter, filter aid is supplied continuously to the water.

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( 5 ) Mechanical damage to the septum allowing precoat and body feed to pass through.

Frequently, it is advisable to install strainers or in-line filters downstream of a diatomaceous earth filter to prevent mistakes or problems which could result in plugging of wells.

REMOVAL OF DISSOLVED GASES

In addition to oil and solids removal, sometimes dissolved gases also must be removed. The commonly encountered dissolved gases and resulting problems are as follows:

Gas: Problem:

(I) Hydrogen sulfide

(2) Oxygen (3) Carbon dioxide

Corrosion, precipitation of iron sulfide Corrosion, bacterial growth Corrosion

Undesirable dissolved gases may be removed from water by (1) aeration, by spraying or cascading, (2) vacuum degassing, (3) countercurrent gas stripping, and (4) chemical treatment, in the case of presence of oxygen or low amounts of hydrogen sulfide. The choice of the specific method is determined by the amount of contaminant and economics.

Aeration

Spreading water in order to create large surface areas for contact with air may release unwanted gases, such as carbon dioxide and hydrogen sulfide, and take on less objectionable gases, such as oxygen. The equipment to be used may be slat-type cooling towers, spray nozzles, or high-speed breakers to achieve mechanical division.

EQUIPMENT CONSIDERATIONS

Equipment required for the collection, treatment, and distribution of injection water for oilfields is a major consideration when determining the economic feasibility of various processes. Inasmuch as the water is usually aggressive and may require treatment with aggressive chemicals, careful consideration should be given to the use of corrosion-resistant materials, low-maintenance operations, and to a fairly high degree of automation for reduction of plant upsets and operating labor costs.

Pipelines

Pipelines in the past have been normally made of bare steel. Massive replacements and/or hgh maintenace costs of bare steel pipelines have led many operators

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to alternatives. Some have concluded that properly treating the water requires more commitment than they or their personnel are willing to give. Thus, they have decided that pipelines must be made from a corrosion-resistant material, having resistance greater than that of steel. The following altenatives have been used:

(a) Internally plastic lined steel pipeline with special attention to joints. (b) Fiberglass reinforced plastic pipe, prefabricated and joined in the field. (c) Plastic pipelines, such as PVC, may be satisfactory if the temperature of

produced water is low, the pipelines are not subject to external or internal shock, and the pressures are low.

(d) Cement-asbestos pipelines, whch are resistant to corrosion if made of type-5 cement and are autoclave-cured. In special cases, the pipelines may be epoxy lined. Again there is a pressure limitation.

(e) Cement-lined pipe. In general, consideration should be given to the convenience of rapid dismantling

and relocation of the lines, as in the case of cement-asbestos pipelines, to the types of epoxies and plastics to be used based on actual tests with the fluids handled, and to the requirements and costs of additional facilities, such as cathodic protection of steel pipelines. External corrosion of pipelines is covered in Chapter 17.

The design of the pipeline should take into consideration: (a) the possibility of hydraulic shock and surge, which may rupture the pipeline, (b) the venting of air pockets, (c) methods of testing for leaks, (d) the use of cleanout pigs for the removal of scale and other fouling materials, and (e) the use of surface-mounted pipelines with attendant expansion problems versus buried and restrained pipelines. Many instances of hydraulic rupture of steel pipelines are known where an inadequate analysis of pipeline transients was made during the design phase. Cases are also known where thermal expansion has caused inadequately buried pipelines to liter- ally jump out of the ground.

Separators

The type of separators selected depends upon the origin and volume of suspended materials to be removed, the aggressiveness of the waters, and the value of the land on which they are to be located.

Volume and origin of suspended material to be removed Normally, when the waters are to be injected for secondary recovery, the content

of suspended solids must be low, in some cases below 0.2 ppm. When produced waters are combined with sea water, a heavy precipitate of barium sulfate may be formed. The settling of t h s precipitate may require a large sedimentation pond with up to 72 hr retention time. This will also enable gravity separation of oil suspensions.

Sedimentation ponds are made of reinforced concrete having sufficient depth to allow a reasonable collection of sediment before being taken out of service for cleaning. Generally, two or more separate ponds should be provided so that when

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one is removed from service (less than 5% of the time), the other may carry the throughput at an increased velocity, at a reduced rate, or a combination of both.

The retention time may be varied and can be determined by a maze of two or more baffles within a single pond, so that their arrangement can be changed for different lengths of retention time as conditions vary. The ponds should be made of corrosion-resistant concrete, such as type-5, or sulfate-resistant concrete when using sea water. For additional protection, the ponds should be lined with a coal-tar epoxy or similar coating. Current environmental regulations should be consulted as special linings and other requirements may be specified to eliminate the possibility of ground-water contamination. Bottoms of the ponds should be designed so that the greatest depth is at the point of maximum precipitation and, when ponds are drained, the sediment can be hydraulically flushed out to a sludge pond.

The internal baffles guiding the flow through a number of passes can be built of wood or similar low-cost material, which need not support a hydraulic load, because the level is equalized on all sides. Oil, which gravitates to the surface, can be skimmed near the end of the flow path by a continuous adjustable-height gravity skimmer.

It may be necessary to prevent algae formation. This can be accomplished by blocking out the passage of sunlight into the sedimentation basin. One method is to have interlocking, opaque, polyfoam, plastic panels, which float on the surface and can be easily removed for pond maintenance purposes. In cases where entrained gases must be released or waters from different sources must be mixed before entering the sedimentation pond, the use of gravity cooling tower, wood-slat type aerators, and eduction type mixing nozzles may be considered.

Standard API separators should be considered when a lengthy time period is not required for settlement and separation, a closed system is desirable, and the land area is costly. There are standard models for various conditions made by a number of manufacturers. The materials used in construction, however, should be carefully considered as to their resistance to corrosion.

Aggressiveness of the waters

Inasmuch as all waters, including distilled water, have some degree of corrosiveness, a major economic consideration is the choice of materials in pumps, pipes, valves, fittings, tanks, filters, etc. One must take into account the desired life of the facility, changing conditions affecting the aggressiveness of the water, and the chemical treatment of the water for corrosion control in comparison to the increased cost of using more corrosion-resistant materials.

Value of space on which facilities are to be located

An additional consideration in facility design is the value or limited area of the land or space on which it is to be located. In some cases, sedimentation ponds may be planned on a multilevel basis instead of being spread over a large, single-level

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area. This also holds true for pumping and filtration equipment. The equipment may be placed below grade as well as on-grade and stacked for multilevel operation. This is a major consideration for offshore structures where platform loading is critical.

Filtration equipment

Dependable filtration for the removal of suspended solids from water before injection is most important, particularly for reservoirs which have low permeability. The filtering process is most often upset when large blocks of solids are carried through, with subsequent reduction in efficiency. In general, the trend is toward more completely automated systems where differential flows and pressures are measured and, at predetermined levels, the filters are backwashed or recharged as often as necessary to maintain the desired quality of effluent. Generally, filtration systems are of three types: (1) clarification systems, (2) in-line flocculation systems, and (3) filter-aid filters.

Clarification Clarification systems include flocculation, decantation, sedimentation, and sand-

bed filtration. Basically, they are the same as those used in filtration of domestic water in municipal plants. They are always necessary when the amount of suspended solids is high, 15 ppm or above, as these quantities of solids impose an impractical economic load on the in-line flocculation or filter-aid type filters. Clarification type filtration may be used when the reduction of suspended solids content is not extremely critical, with the effluent having more than 1 ppm. Usually, these facilities consist of reinforced concrete basins. The water is passed (1) through compartments, where chemicals are added in subsequent stations for flocculation and decantation, (2) through basins for sedimentation, and ( 3 ) into gravity sand beds or other media filters.

These systems should have parallel chambers and, particularly, filters, so that one section can be removed from service and one filter regenerated at a time, while the system operates at slightly reduced rates. The sand filters should be automatically backwashed on demand, based on differential pressure through the bed. A number of manufacturers build complete fittings and appurtenances for these systems. One disadvantage of this system is that it is open throughout and subject to oxygen uptake, which later must be removed by deaeration and chemical scavenging. Pipes and fittings may be constructed from conventional cast iron, but the trend is toward use of fiberglass epoxy or plastic materials throughout.

In-line flocculation systems In-line flocculation technique was developed with progress in the state of the art

of high-rate rapid sand filters. It has been found that filter media alone will only remove particles down to about 20 pm in size. A polyelectrolyte is required to remove finer particles. A coagulant and/or polyelectrolyte is added to the water a short distance upstream of the filter to gather and/or attach the suspended solids to

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the filter media. Although shorter filter cycles result, the capital and operating costs of clarification facilities are eliminated. This system works well when the solids loading is low. The benefits become questionable when filter cycles drop to significantly less than twelve hours. One must plan for the worst case and not the average solids loading, in order to prevent plant shutdowns during high loadings.

Filter-aid filters and in-line flocculation filters Filter-aid or in-line flocculation filters are considered essential for maintaining a

closed system from source water to injection well and also for any system requiring injection water with less than 1 ppm of suspended solids. As mentioned before, when the source water has a high turbidity, the removal of the majority of suspended solids should be done by means other than these filters.

The following should be taken into consideration in designing filter-aid filters: (a) The source and quality of filter aid are important considerations. Generally

diatomaceous earth and perlite are the two media available. The life of the filter cake varies greatly, depending upon product quality.

(b) The sizing of the filters depends upon the total throughput and the total amount of solids to be removed. The solids affect the life of the filter cake and must be evaluated, in order to obtain reasonable backwashing cycles.

(c) Shells, piping, and fittings are generally made of stainless steel, although plastic or rubber linings are economically feasible for the interior shell of large units. Filter frames may be of metal mesh. Hard rubber or plastic cores are becoming more popular, however, owing to their lower cost and lack of distortion. Metal screens, on which diatomaceous earth cake is formed, are being replaced by a finely-woven plastic cloth, wluch is relatively inexpensive and comparatively easy to replace in the field.

(d) There is a trend toward complete automation which, most likely, will preclude upsets from human error.

(e) As a positive control on solids breakthrough in the filter system, a positive-stop (i.e., in-line) filter should be installed on the downstream side of the system. General equipment selection (two or more filters, the optimum being three) should be such that one filter can be taken out for backwash, while the remaining one can carry the same or slightly reduced total throughput at temporarily increased flow rates per square foot of filter area. The optimum rate for filtration is presently accepted as about 2 GPM/sq ft, although manufacturers are considering high-rate filters with filtration rate of 20 GPM/sq ft.

DEGASSING EQUIPMENT

Deaeration equipment

The dissolved oxygen content of many waters for injection is far above the limits whch should be maintained for control of corrosion. The most feasible method of

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removing this dissolved oxygen down to the limits, where effective treatment can be completed by chemical scavengers, is by passing the water through a deaeration column. Materials in the column for all wetted surfaces must be resistant to the corrosive atmosphere.

The interior shell of the column should be lined with a plastic material, whereas the trays and appurtenances should be constructed from stainless steel. The two or more trays are packed with Raschig rings made from a ceramic or plastic material, creating the desired dispersion of water into large surface areas.

Oxygen removal may be accomplished by vacuum pumps exhausting from the top of the column, and creating a negative pressure for flashoff of the oxygen. When sweet field gas is available, it can be used as an upward counterflow to the water. Gas will scrub the oxygen and carry it out of the top of the column to a flare point or where gas can be used. This column also can serve as a small-capacity surge tank between the supply to the filters and the discharge to the injection pumps. Level controls should be provided to throttle the inlet or outlet and maintain a liquid level within a predetermined range. Again, consideration should be given to providing two or more deaerating columns so that one can be removed for service and repairs, while the others are operating at increased throughput.

Generally, the deaerator reduces the dissolved oxygen content to 0.5 ppm or less. Following the deaerator with a chemical scavenger, the oxygen content can be reduced to 0.01 ppm or less, resulting in excellent corrosion control. Air should not be allowed to enter the system beyond this point. In addition, all vessels, such as chemical mixing tanks or surge tanks, must be blanketed with an oxygen-free gas.

Chemical mixing and feed equipment

All chemicals used in treating the water, i.e., bactericides, oxygen scavengers, alum, polyelectrolytes, bentonites, etc., should be provided with a mix hopper having a transfer arrangement to a feed tank. In the case of sodium sulfite, the tanks should be closed and blanketed to prevent oxygen contamination. All chemicals should be fed into the system through a variable metering-type injection pump.

Materials selected should be corrosion resistant to chemicals in concentrated and dilute states, which sometimes differ and should be determined prior to construction.

Discharge lines from sources of certain chemicals, such as alum, polyelectrolytes, and bentonite, should have outlets to a number of water treatment chambers so that the progressive feed can be varied to meet operating conditions. In general, all equipment should be constructed from a combination of chemical-resistant plastic and stainless steel.

SAMPLE QUESTIONS

(1) List requirements for injection waters. (2) Describe a test for testing plugging characteristics.

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(3) Describe methods used in removing the suspended matter. (4) Describe four methods of treating unstable water in waterflooding. ( 5 ) Show, by a chemical equation and any necessary explanation, why calcium

(6) Show, by a chemical equation and any necessary explanation, why the

(7) What is meant by the expression: “chemically unstable water”? (8) Write a balanced chemical equation illustrating the type of unstableness

(9) What is “surfactant” and list three major types of surfactants, giving exam-

(10) In waterflooding you encountered “chemically” unstable water. How would

(11) List the three main factors to be considered prior to initiating a waterflood

(12) What are the primary differences between surface waters and deep well

(13) List 4 types of plugging and 2 treatments or means of preventing or

(14) Give Langelier’s stability index ( S I ) , identifying each term. (15) Explain what the following SI values indicate: -2, 0, and +3. (16) In addition to the parameters in the equation what influences SI? (17) Should Ca/Na ratio of injection water be higher or lower than Ca/Na ratio

carbonate often precipitates during the production of oilfield waters.

aeration of water may cause the precipitation of iron hydroxide.

caused by the reduction of pressure in oilfield waters.

ples.

you prevent CaCO, and Mg(OH), precipitation?

project.

waters?

minimizing each.

of formation water? Why?

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API, 1965. Recommended Practice for Biological Analysis of Water Flood Injection Water, RP 38. American Petroleum Institute, New York, N.Y., 2nd ed., 7 pp.

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Baker, O.E., 1958. Current research and future developments of flooding water quality control. In: A Digest of the Proceedings of the Short Course - Water Quality Control for Subsurface Injection. Univ. Oklahoma, Norman, Okla.

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Pope, R., 1948. Application of cathodic protection. In: H.H. Uhlig (Editor), The Corrosion Handbook. Wiley, New York, N.Y., pp. 935-950.

Postgate, J.R., 1979. The Sulphate-Reducing Bacteria. Cambridge UNv. Press, Cambridge, 151 pp. Riddick, T.M., 1964. Role of the zeta potential in coagulation involving hydrous oxides. Technical

Schaschl, E. and Marsh, G.A., 1963. Some new views on soil corrosion. Mater. Prot., 2(2): 8-17. Simonsen, R.N., 1962. Oil removal by air flotation at Sohi0 Refinery. Oil Gus J., 60(21): 146-154. Spencer, 0.1. and Harding, R.W., 1959. Secondary Recooety of Oil, Penn. State Univ., University Park,

Stiff, H.A. and Davis, L.E., 1952. A method for determining the tendency of oilfield waters to deposit

Stumm, W. and Morgan, J.J., 1962. Chemical aspects of coagulation. J. Am. Water Works Assoc., 54:

Udwin, E., 1971. High rate water filtration. Plant Eng., 25(Sept. 30)(0ct. 28). Unz, M., 1960. Insulating properties of cement mortar coatings. Corrosion, 16(7): 343-353. Von Engelhardt, W. and Tunn, W.L., 1955. The flow of fluids through sandstones. Ill. Geol. Suru. Circ.,

194: 16 pp. (translated by P.A. Witherspoon). Also in: Heidelb. Beitr. Mineral. Petrogr., 1954, 4: 12-25.

Wright, C.C., 1963. Rating water quality and corrosion control in waterfloods. Oil Gas J., 61(20): 154-157.

Wright, C.C., 1965. Chemical compatibility. Prod. Mon., 29(6): 19-21. Wright, C.C. and Cloninger, D.K., 1963. The membrane filter - a good tool for water quality testing.

Wright, C.C. and Davies, D.W., 1966. The disposal of oilfield waste water. Prod. Mon., 30(9): 14-17;

Wright, C.C., 1972. Corrosion control in large volume pumping brine wells. Mater. Prot. Perform., 11:

Association of the Pulp and Paper Industry, 47: 171-179.

Pa, 2nd ed., 516 pp.

calcium carbonate. Trans. AIME, Pet. Diu., 195: 213-216.

971-974.

Western Regional NACE Meet., Anaheim, Calif., Sept. 26, 1963, 36 pp.

22-24.

23-26.


373

Chapter I 0

OFFSHORE TECHNOLOGY

SANJAY KUMAR and GEORGE V. CHILINGARIAN

INTRODUCTION

The first over-water drilling for oil took place along the California Coast in the early 1900's, utilizing piers extending from the beach. Subsequently, wells were drilled from structures in inland lakes, e.g., Lake Maracaibo in Venezuela. The oil industry moved into the marshes of South Louisiana in the early 1930's.

In 1947, following World War 11, the first fixed platform for -drilling and production out of sight of land was constructed off the Louisiana Coast in the Gulf of Mexico in 20 ft of water. In 1955, a platform was constructed in approximately 100 ft of water. Platform construction was extended to approximately 285 ft (87 m) by 1965, and to 474 ft (144 m) by 1975. In 1976, the Exxon Hondo platform, located in the Santa Barbara Channel off the coast of California, was set in a water depth of 850 ft (260 m); whereas in 1978 offshore installation was completed for the COGNAC fixed platform in 1025 ft (312 m) of water in the Gulf of Mexico (Fig. 10-1).

YEAR -

300 850 f t

(? IC

Fig. 10-1. Offshore platform development.

374

Today about 12.5 million barrels per day, or about 22% of the worldwide oil production, is produced offshore (Ellers, 1982). Many of these locations are out of sight of land. An entirely new and innovative technology has made this possible. Self-contained, mobile drilling rigs have been developed. Gigantic platforms capable of resisting waves as high as 100 ft, weighing more than anything ever moved by man, and standing in water depths exceeding a thousand feet have been successfully designed. To help build and install such structures, semisubmersible derrick barges have been built that can lift 5,000 tons in the open sea. A whole new underwater production technology has been conceived by man that holds great promise for the future.

Offshore technology is at the forefront of the many disciplines that are involved. As the search for oil takes the industry further and further into the great oceans, many as yet undeveloped techniques will be required to meet the challenges. So far, approximately 10,000 structures have been constructed offshore. Worldwide, however, there are only about 2,000 platforms which could be classed as major structures. Most of these structures are steel, pile-supported, jacket-type platforms.

OFFSHORE EXPLORATION

During the initial stages, offshore exploration involves seismic surveys. Seismic ships about 100 ft long, with sophisticated scientific equipment on board, and a capability of surveying about 2000 miles a month are generally used (Ranney, 1979). This is followed by engineering and environmental feasibility studies. Offshore exploratory wells are then drilled to prove or disprove the existence of oil and/or gas in commercial quantities. After logging and possibly testing, these wells are plugged and abandoned.

Figure 10-2 outlines a typical chronological order of events during the exploratory phase. Obviously, if during any stage the exploration study shows an unfavorable trend, the area is abandoned.

As shown in Table 10-1, various offshore exploratory drilling techniques are available; these are applicable within the range of water depths indicated.

The island-type drilling site is discussed later. The bottom-supported submersible platform is generally limited to an operational water depth of 80 ft, or up to 150 ft in some cases. Vertically fixed members connect the drilling platform to a large lower hull. This hull is flooded at the drilling site in order to lower the unit to the seabed. During towage, the lower column section is designed to provide sufficient buoyancy to aid the tugs.

Submersible rigs are very stable. They are severely limited, however, by their relatively shallow operational depths and poor mobility. Consequently, as drilling activities move into deeper waters, their applicability will decrease (Ranney, 1979).

The jackup rig represents an improved version of the fixed (stationary) bottom- supported submersible structure. It comprises a floating, barge-like hull that supports a platform on which the drilling equipment and other facilities are mounted.

375

(FAVORABLE GEOLOGY)

1 SEISMIC SURVEY I

ENGINEERING AND ENVIRONMENTAL FEASIBILITY

c NO A I JYES

PRE-LEASE SALE I ENVIRONMENTAL IMPACT HEARING I I I I I I

ABANDON NO THIS AREA

I L I

1 1

START FIELD DEVELOPMENT

i I FIRST PRODUCTION 1

2 - 5 YEARS

! 3 - 6 YEARS

I

I I YEAR

t- 2 YEARS

I

t I - 3 YEARS

J- 4 - 6 YEARS

_L

Fig. 10-2. Typical sequence of events in offshore operations. (Modified after Baker, 1981.)

The slightly slanted legs can be lowered (for drilling) or raised (during towout) by hydraulic or pneumatic jacks through the leg slots provided in the hull (Fig. 10-3). The legs tower above the hull during towing operation. Once over a drillsite, the legs

TABLE 10-1 Comparison of offshore exploratory drilling techniques (Modified after US. Maritime Administration, 1977)

Method Stabiliy

(1) Island (expendable) excellent

(2) Submersible

(3) Jackup (posted barge)

excellent

excellent

(4) Ship shape fair

( 5 ) Semisubmersible good

Mobility Dept limitations

none shallow water, up to

poor 150 ft (maximum) 80 f t

fair 300 ft. Two-stage type up to 600 ft

excellent 600-1500 ft. Newer units up to 3000 ft

good Minimum 100 ft water depth. Usually 600- 1000 ft. Newer types up to 3000 ft

376

Fig. 10-3. A jackup drilling rig for offshore exploration. (After Kash et al., 1973, p. 40; courtesy of the University of Oklahoma Press.)

are lowered by the jacks until they reach the seafloor. Jacking is continued beyond this point to raise the platform sufficiently so that the working area is out of reach of the waves expected in the area. The jackup rig is subsequently anchored to the ocean floor by driving piling through the tubes in the legs. If the seafloor is relatively soft, it may be better to use legs with wide flat bottoms (mats) to distribute the rig load over a wider area. Jackup rigs provide excellent stability as well as a relatively improved mobility. New two-stage units are being developed to extend operations in water depths up to 600 ft (Ranney, 1979). Jackup rigs have a minimum area exposed to waves and can be easily designed to withstand hurricanes and storms. Beyond a water depth of 40 ft, the jackup rig is cheaper than a submersible rig.

The disadvantages of jackup rigs are: (1) it is difficult to tow, (2) it is sensitive to waves when first going on or off location, (3) the legs must be removed for long

377

tows, (4) it has a poor underway (during transport) safety record, (5) its moving parts are subject to failure and require maintenance and repair, (6) it is limited to water depths of about 300 ft (or 600 ft).

The slup-shape type of units are of two lunds: drillbarges and drillships. They have openings in their hull for the drillstring and are generally selfcontained, requiring little or no assistance from supply vessels. The operating depth is limited only by the mooring requirements. In deeper waters, computer-controlled motion compensators, sensitive to sensors located at the well opening on the seafloor and at the ship bottom, are used for holding the ship in position. This type of s h ~ p is known as the dynamic-positioned type (Fig. 10-4).

TRANSMITTER 2

Fig. 10-4. A dynamically positioned deepwater drill ship. (After Kash et al., 1973, p. 38; courtesy of the University of Oklahoma Press.)

378

There are stability problems induced by waves and surface motions, restricting their use in rough seas (Ranney, 1979). Underwater BOP'S (blow-out preventers) and marine riser are required. Drillbarges and drillships, however, have excellent mobility and are generally less expensive than semisubmersibles.

The newest and most sophisticated type of drilling platform is the semisubmersible rig. It provides the best overall capability and is the best-suited drilling facility in severe weather environments.

- 7- Fig. 10-5. Semisubmersible drilling rig for offshore exploration. (After Kash et al., 1973 p. 41; courtesy of the University of Oklahoma Press.)

379

The semisubmersible rig (Fig. 10-5) consists essentially of a platform deck supported by columns connected to hollow underwater displacement hulls. These hulls are flooded on site. The semisubmersibles may be towed on location, or they may even be self-propelled requiring no towing. Although most units are positioned with mooring systems, some may have dynamic positioning systems (Ranney, 1979).

Semisubmersibles offer the advantages of good stability, good survival capacity in rough weather, and good variable capacity while drilling. They are, however, somewhat difficult to tow, difficult to anchor, are quite expensive, and require the use of underwater BOP’S and marine riser.

OFFSHORE PRODUCTION FACILITIES

The numerous designs which have been developed to successfully meet the challenge of producing oil offshore can be broadly classified into (1) island type, (2) platforms (fixed, semisubmersible, tension-leg, etc.), and (3) fully submerged production systems. The physical environment (weather conditions: winds, waves, etc.), water depth, oil quantity and type, method of exploitation, geographic location, etc. determine the type and strength of the structure required.

Artificial islands

Man-made islands are technically and economically more attractive for drilling and production activities in shallow waters. Island technology was developed in the Canadian Beaufort Sea, where 17 islands have been constructed so far. The first island, “Immerk”, was built in 10 ft of water in 1972. The latest, completed in 1979, is in 63 ft of water. Most of these islands have been constructed by Esso Resources Canada (ERC), the Canadian affiliate of Exxon (Jahns, 1980).

The artificial island technology developed in response to the unique and excep- tionally difficult operating challenge in the Arctic shelf containing large amounts of oil and gas. One of the most persistent problems is the sea ice that covers the Arctic seas (Beaufort, Chukchi, and Bering seas) for periods of up to almost 10 months on the average in the Beaufort Sea. Moreover, this ice pack may be mobile.

The offshore conditions in the Arctic vary with the time of the year. In winter, the relatively immobile ice (“fast ice”) extends to as much as 50 miles from shore where waters are shallow. This distance is less in places where bottom slopes are steeper. In summer, the fast ice breaks up and a “shore lead” of open water develops, which varies in width depending upon the location and weather conditions. Beyond the fast ice or shore lead, pack ice is always present having average thickness of 10 ft, covering various fractions of sea surface (Fitch and Jones, 1976).

Inasmuch as the forces produced by the pack ice mass in response to winds and currents are tremendous, it is difficult and uneconomical to use concrete or steel platforms.

3 80

Submerged facilities are also impractical, because the natural ice islands sometimes extend as much as 100 ft deep. For continuous operation, therefore, it may be feasible to use artificial islands, which would protect offshore drilling and production equipment from ice and waves. The desired shape of the island is roughly that of a right cylinder, because t h s gives the lowest surface/volume ratio.

Artificial islands offer a very distinct advantage of allowing drilling (and production) activities to be conducted in essentially the same manner as on land. They are stable gravity structures that resist lateral ice loads because of their large weight. Islands can be made of any size and are easily adapted to site-specific design parameters. Exploratory islands also are amenable to extension to any size if a discovery is made.

Currently, the economic limit for islands is placed at around 80 ft of water depth. Two types of artificial islands exist: (1) gravel islands, and (2) the artificial ice islands.

Gravel islands The gravel island is built upward from the seafloor to provide a stable base for

the drilling rig and to protect it from the crushing forces of the Arctic ice pack. These islands are made by dredging and filling in with gravel during the summer. In arctic areas it is possible to truck the gravel over the ice to the site during winter and dump the gravel through a hole excavated in the ice sheet. This latter technique is markedly cheaper, but is obviously applicable only to the Arctic areas. Lightweight vehicles are used to drill holes through the ice into the water below. The water is then lifted and spread out onto the surface where it freezes. When the ice pack is thick enough to support the heavy construction equipment, the sea ice cutting operations are begun. Ice blocks are cut out and trucked away. Several hundred thousand tons of gravel are then trucked in from onshore and dumped into the excavated area to build up the island (Corporon, 1983).

Gravel islands appear to have minimal impact on the environment, both during construction and after the islands have been completed (Wright, 1977). Most of these islands have been made for exploratory purposes and once abandoned, they disappear gradually by natural erosion without any harmful environmental effects. The THUMS consortium has built development islands off the coast at Long Beach, California. These were built by placing sand and concrete around the periphery and pouring gravel in the middle through huge inclined gravel pipes. These islands are quite permanent.

Artifical ice islands Artificial ice islands are still in the experimental phase in the Arctic regions.

Union Oil drilled an exploration well in the winter of 1976-1977 from a grounded ice island built in 9 ft of water in the Harrison Bay (Anonymous, 1977) about 50 miles west of Prudhoe Bay. Construction was begun in early November of 1976. The ice surface was repeatedly flooded with sea water, gradually thckening the ice and

381

eventually grounding it to form a platform for the drilling activity. The ice island was vacated by mid-April and it melted and disappeared in early July of 1977.

Exxon, in collaboration with Mobil, Phillips, and Sohio, has conducted a prototype experiment (1978). They constructed a large (1200 ft in diameter) experimental ice island in 10 ft of water north of Prudhoe Bay (Jahns, 1980).

Ice islands lack the stability of gravel islands. They are low-weight and relatively thin and, therefore, need to be protected against the lateral movement of the surrounding ice. Union Oil accomplished this by constructing and maintaining an 11-ft wide moat (ditch) around the island and thereby isolating it from the surrounding ice sheet. The Exxon experiment studied the rate of deterioration of the ice island during the spring break-up of ice. There is a need to develop some kind of melt protection technique to preserve the island for a second winter drilling season (Jahns, 1980).

Offshore platforms

Offshore platforms enable drilling, production, processing, and workover activities to be carried on using conventional above-water procedures. Inasmuch as platforms are installed in open water to resist the forces encountered in a marine environment, specialized techniques have been developed for their design and construction. These techniques, however, largely represent improvements in the existing technology, with relatively few new ideas or concepts. For example, the idea of skirt pile, which is used in most deep-water structures and was first applied to an offshore structure in 1955, had originally been patented in the 19th century. The highly publicized gravity structure is also not new: one of the first platforms off California was a gravity structure, which has been in service for over 20 years. The guyed tower concept, which is currently being considered for extension into deep water, was patented before the turn of the century. It was seriously studied in 1950 by one of the major oil companies as a method to extend operations to 100 ft of water. The vertically-moored or tension leg platform was conceived before World War I1 as a seadrome (floating airport) to allow refueling of aircraft between the U.S.A. and Europe. Although many of the ideas are old, present-day technology was necessary before they could find practical application. The developments in offshore platforms are presented in Fig. 10-1.

Offshore platforms consist broadly of two components: (1) the drilling and operating facilities, often known as the topsides, and (2) the supporting structure and the foundation. The topside comprises the drilling rigs, oil and gas processing facilities, transportation pumps, utilities, living quarters for the workers, and, in cases where tanker transport is used, sufficient storage area. The supporting structure involves an intricate design to ensure platform endurance against winds, waves, currents, marine corrosion, and possible seismic disturbances. The impact of waves is almost always the major design force to be accounted for, except in structures along the West Coast of the U.S.A., where seismic forces are the major concern (Ellers, 1982).

382

Although platforms may be constructed of either steel or concrete, the former traditionally enjoys some advantages over the latter. Because of economic considerations, steel structures are preferred in water depths less than 300 ft. Concrete structures have the following advantages (Enright, 1976):

(1) Storage is available in the gravity-type structures. ( 2 ) There are fewer problems with corrosion or possible fatigue (concrete

strengthens with age for about twenty years). (3) Installation on site is faster and less hazardous than in the case of a steel

platform jacket, which must be tipped in and piled down. (4) Inspection is much easier, because instead of inspecting a large number of

small members in the case of steel, the engineer has to inspect just a few in the case of concrete.

The guiding factor in the selection of construction material is the condition of sea-bottom. Steel is preferred in the case of a soft and unstable bottom or where conditions are not uniform. Because of difficulty in driving piles, a hard and stable bottom is well suited for concrete structures but not for steel.

Fixed-bottom mounted type platforms Because of improvements in offshore piling methods, there is a renewed interest

in piled steel platforms. The fixed structures have established a foothold in shallow water and are likely to retain their applicability in this area. They are suitable in water depths up to 1000 ft (300 m) and include the (1) template-jacket, (2) tower or self floater type, and (3) gravity-type platforms.

( I ) Templute-jucket-type platform. Template-jacket-type platforms are the earliest structures developed for offshore activities and still outnumber any other platform type. Thousands of these have been installed to date.

This structure consists of a series of steel frames that are fabricated onshore, transported to location by flat barges and tipped into place by derrick barges. The structure is upended and then pinned to the sea-bottom with piles driven through steel sleeves provided in the structure. The structure is fabricated onshore flat on its side, skidded onto a special launch barge, and transported to the ocean site.

The chief advantages of jacket-type platform (see Fig. 10-6) are (1) the ease of fabrication, ( 2 ) ease of installation, and (3) the resistance to storm and earthquake loads. Fabrication is easier because: (1) relatively small members are used, (2) a large portion of the built-in buoyancy is eliminated, (3) no internal stiffeners, etc. are required, and (4) yard mobilization requirements for fabrication are minimal.

Installation is easier because smaller conventional barges can be used. The upending of the jacket is simple. There is no entrapped water, and the structure consists of small members having a smaller total mass. Inasmuch as earthquake loads are proportional to mass, the jacket platform is more resistant to seismic forces. Additional earthquake resistance is provided by the structure redundancy, i.e., there are many members and the structure remains intact even in the case of failure of some of these structural members.

There are two major disadvantages of the jacket-type structure: (1) the structure

383

i

.-

Fig. 10-6. A fixed-leg jacket platform. (Courtesy of McDermott, Inc.)

384

- -

STEP I STEP 2 STEP 3

f

STEP 4 STEP 5 STEP 6

Fig. 10-7. Installation of the template-jacket platform by launching. (Courtesy of McDermott, Inc.)

is fixed and immobile; once launched, it is not possible to reverse the launch, and (2) it is unstable until the piles are actually driven into the ocean floor. A sudden storm at the time of or prior to the initiation of the pile driving, could easily knock the structure over.

(2) Tower (or self-floater) platform. Tower platforms represent the newer generation of the jacket platforms. The tower platform is fabricated in much the same way as the jacket platform, but with hollow jacket members. The structure is provided with enough built-in buoyancy to enable it to float horizontally and towed to location like a ship with tow ships. It thus requires no launch barges, which is a significant advantage in view of the high cost, frequent unavailability, and limited capacity of launch barges. Once on location, the structure is tipped into place by controlled flooding, upended and, finally, fastened to the seafloor by piles.

The tower-type platform is really a hybrid between fixed and buoyant (compliant) types of platforms: a universal joint near the ocean floor permits the tower to tilt and sway (oscillate) with the wind, current, and wave forces. At the same time, it is secured to the seafloor by piles and shares many of the characteristics of fixed structures.

In order to prevent excessive tilting of the tower, buoyancy chambers are provided near the water surface. Various configurations of these buoyancy tanks have been designed; however, the most common one consists of four tanks at the top of the structure on the four limbs and one near the base. A buoyant force must

385

be provided to minimize displacement of the tower during severe storm conditions and to limit the motions during platform operation in calmer weather.

The tower platform has multiple well capability, with each production string being contained within a conductor and supported by a bowl at the base near the ocean floor. As a result, tower platforms do not experience any vertical stress. At the top, bottom, and the intermediate regions, the conductors are laterally supported by guides to hold them in the desired vertical position and minimize bending as the tower sways. This gives rise to horizontal stress components that add to the overturning moment. Well casings are permitted to bend elastically with the swaying of the tower. The base of the structure is secured to the seafloor by piles. In order to counter the huge uplift force provided by the buoyancy tanks, a ballast tank is employed. It serves an additional purpose of providing buoyancy to support the lower end of the tower during tow-out.

The tower-type platform has the following advantages: (1) launch barge is not required, (2) liquid storage is possible in its large legs, and (3) the platform has fewer braces and relatively larger members. These large members are more ice-resistant, which is advantageous in ice environments.

There are, however, the inherent disadvantages of: (1) increased towing time, usually about twice that for the jacket platform; this is important to consider for long distance tows, (2) higher steel requirements for a given depth because internal bracings, etc. are required, (3) lack of redundancy, i.e., the whole structure collapses due to the failure of even a single critical member, and (4) the need for a dry dock or launchway.

The Magnus steel-template self-floater jacket platform (Fig. 10-8) represents the state of the art in this class of platforms. It is currently being fabricated by the British Petroleum Company Ltd. for its North Sea operations and is scheduled to be fully operational by 1985. This platform has been designed with buoyant legs tipped with “mud mats” to control their penetration into the seafloor. It also has piles that can be driven from the surface rather than underwater (Ellers, 1982). The installation for this platform is shown in Fig. 10-9.

The difficulties encountered in installing huge offshore structures in deep water and under unfavorable weather and sea-bottom conditions led to the development of the pileless gravity platform. The first gravity platform, Hazel, was installed in the Santa Barbara Channel, California. About 20 very large gravity structures, of concrete construction, have been built and erected in the North Sea by Norwegian, British, and French contractors in the past dozen years (Ellers, 1982). Only two gravity platforms, of steel construction, have been placed in U.S.A. waters.

The gravity platform has a cellular base that houses several hollow ballast tanks (Fig. 10-10). These tanks, which are filled with sea water to provide gravity to lower the base to the seafloor, are towed to the location from a dry dock. The entire deck section (topside) is prefabricated and mounted on ballasted barges. On removing the ballast, the entire topside unit is lifted and then towed to a deep-water site where the base has already been towed. The base is kept submerged with the columns

(3) Gruoity platform.

386

T

I 1 I I I I

Fig. 10-8. The Magnus steel-template jacket platform. American, Inc.)

(After Ellers, 1982, p. 41; courtesy of Scientific

protruding at a suitable elevation above the level of the water. The topside is maneuvered into position over the columns of the base (generally 3 or 4 columns are used), sufficient ballast is removed from the base to support the topside, and the

1981 1980

FIRST OIL PRODUCTION

Fig. 10-9. Installation of the Magnus platform. (After Ellers, 1982, p. 46-47; courtesy of Screntrfc Amerrcan, Inc.) W

4 m

388

SEA FLOOR 472 FEE?

Fig. 10-10. The Statfjord B gravity-concrete platform in the North Sea. (After Ellers, 1982, p. 40; courtesy of Scientific American, Inc.)

two structures are connected with heavy steel rods. These rods are tensioned and grouted to provide a singular structure. The finished gravity platform structure is then towed slowly onto location, where the base is again ballasted to lower the structure to the seabed (see Fig. 10-11).

Gravity structures require a firm seafloor to support their enormous weight. When the 899,000-ton (the world’s heaviest platform) Statfjord B gravity platform was lowered onto the North Sea floor, it released the water in the underlying sediments. This free water had to be drained out by drilling shallow wells from the utility shaft (Ellers, 1982).

Gravity platforms offer an enormous storage capacity, which is a big advantage if pipelines are unavailable and tankers are the means of transporting the oil onshore. Another advantage is that, in principle, they can be almost immediately made ready for drilling activities after being towed out and installed. The biggest disadvantage is

389

Fig. 10-10 (b) A fixed steel gravity platform. (After Jones, 1981, p. 21; courtesy of Graham and Trotman Ltd., London.)

the high capital cost. These structures can only be built where sheltered deep-water locations (lakes, fjords, etc.) exist and highly sophisticated design and fabrication facilities are simultaneously available. In addition, the gravity platform is limited to areas where the seafloor is very firm.

Flouting-buoyant-type platforms The floating-buoyant-type structures, also known as compliant structures, repre-

sent the fundamental shift in the design of offshore production facilities from fixed to floating type of structures. The overall concept is that of a buoyant platform, which is free to sway with the currents and is moored over subsea wellheads with the production risers, serving as the vital link between the wellhead and the platform. These structures will be mostly used in water depths greater than 1000 ft.

1978 1979

1980 STATFJORD B

FIRST OIL PRODUCTION

1982

W

Fig. 10-11. A typical gravity platform installation sequence-the Statfjord B platform. (After Ellers, 1982, p. 46-47; courtesy of Scientific American, Inc.)

391

The two types of feasible buoyant structures are: (1) the guyed tower, and (2) the tension-leg platform. Semisubmersibles can also be converted into production platforms; however, they are very sensitive to topside loading. This is as well true of the other buoyant-type structures to some extent. The latter, however, are generally larger and rest on the seafloor, which provides additional support, and therefore, can support the required production facilities.

The guyed tower is a slender-trussed structure that rests on the seafloor, with guylines holding the structure in place. The tower transmits the primarily vertical gravity loads imposed by the drilling and production equipment mounted on the surface decks to the seafloor. There are two ways of providing support for the tower at the seafloor. One is by the conventional piled foundation. The second means of anchoring the guyed tower is by pure gravity: the base is implanted in the seafloor using a vertical bearing foundation consisting of a truss-reinforced stiffened shell called the “spud can”. In the latter case, long-term settling of the tower can be a problem. This is avoided by preloading the structure during installation. In the final stages of tower installation when the tower has been installed in an upright position, the spud can is artificially forced into the ocean bottom until the desired load-carrying capability is reached. Drilling mud is pumped into the spud can in order to achieve this purpose; thereafter, the mud is pumped out. The well conductors penetrate through the spud can.

The guyed tower (Fig. 10-12) is a relatively simple structure and is not difficult to fabricate. It is not very heavy and its movement (sway) is within satisfactory limits. Horizontal support for the guyed tower is provided by 12-24 wire-rope, synthetic material, or chain-type cables called guylines (Dunn, 1980). These guylines are secured on one end to the bridge strands arranged symmetrically around the tower by means of pairs of wedge-type Lucker clamps. The guylines run downward from these bridge strands to the fairleads kept about 50 ft below the mean water level so that they are below the keel of passing vessels. Through these fairleads, the guylines run further on to clump weights on the seafloor. Beyond the clump weights, the guylines run to either anchor piles or to conventional drag anchors.

The cable tension is controlled through the Lucker clamps and a hydraulic jacking system. The tower is designed to give a maximum tilt of 2” or less during expected storm conditions. In moderate seas, the clump weights remain on the seafloor and keep the guylines in a taut condition. Under extreme storm conditions, the design-allowable tower oscillations may be exceeded, and once they become too large, the clumps will gradually lift off the seafloor, softening the guying system and further endangering the structure.

The guyed tower is simpler and cheaper to construct and requires only conventional fabrication equipment and techniques. Its installation, however, is quite sophisticated and complex, particularly with respect to the guylines, clumps, and anchor piles (Anonymous, 1981). The guyed tower also is relatively cost-insensitive to increased water depth. There are, however, some cost increases with depth: mooring costs and maintenance costs increase with water depth and remoteness.

Fig. 10-13 shows the installation of the guyed tower-type Lena platform in the

(1) Guyed tower.

392

SEA FLOOR 1.000 FEET

Fig. 10-12. The guyed tower-Exxon’s “Lena” platform. American, Inc.)

(After Ellers, 1982, p. 41; courtesy of Scientific

393

Fig. 10-13. Tension-leg platform-Conoco’s Hutton platform. (After Ellers, 1982, p. 44; courtesy of Scientific American, Inc.)

394

Gulf of Mexico. This platform, which is being built for Exxon by Brown and Root Inc. will stand in about a 1000 ft of water and will be the first such structure. Production activities were proposed to begin in 1984. Exxon has already tested a prototype in 250 ft of water.

As is evident from Fig. 10-13, the guyed tower is launched sideways instead of lengthwise into the ocean. It is then upended, placed on bottom, and the guylines are installed. The tower structure is designed to be self-floating.

The tension-leg platform (TLP) consists of a buoyant, semisubmersible, triangular- or rectangular-shaped structure held in-place by vertical tension cables attached to the dead-weight anchors. The desired buoyancy is provided by submerged flotation cylinders designed to minimize the effects of weather and wave conditions. The subsea wellhead system is connected through risers to the structure. The TLP has the following advantages:

(1) Favorable motion response and stability characteristics: there is not much need to compensate for normal floating conditions offshore. This permits the use of land-type drilling equipment and surface completions.

(2) The cost is almost independent of depth, the only incremental cost with depth being that of longer tension-leg cables. Thus, it offers distinct cost advantages in deep waters.

(2) Tension-leg platform.

(3) The structure has a minimal response to earthquakes. (4) The TLP is easy to install and easy to move to another location; for example,

in a case where delineation wells indicate that the platform should be located in a different position.

( 5 ) The same basic platform can be outfitted for different applications. Field development time is also reduced, because it is possible to fabricate the platform before field discovery, i.e., before knowing the actual water depth and other design criteria.

(6) It is possible to complete the wells either at the ocean bottom or on the surface.

(7) The TLP offers a larger overall production capacity as compared to conventional floating production platforms.

The TLP has two main structural elements: (a) the floating hull, which is similar to a semisubmersible drilling rig but is much larger, and (b) the vertical array of highly-tensioned tethers at each corner. The floating hull is designed with a careful balance between the buoyancy and the freeboard (the part of the hull above water) in order to handle extreme troughs as well as crests (Ellers, 1982). The tethers or cables, made either of high tensile-strength steel tubes or wire ropes, are designed to hold the floating hull down with a tension such that they do not become slack even in the trough of the maximum wave expected (usually, this is taken to be the maximum wave expected to occur once every hundred years). The platform remains virtually horizontal under wave action. The lateral excursions are controlled by the design of the tethers. To anchor the system to the seabed, either piled templates or gravity units can be used (similar to the guyed tower).

The offshore industry has exhibited a great interest in the TLP. Designs have

Fig. 10-14. Tension-leg platform installation. (After Ellers, 1982, p. 46-47; courtesy of Scientific American, Inc.)

W W wl

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been proposed by Amoco, Gulf Oil Co., Fluor Subsea Services, Conoco, and others. Conoco’s Hutton platform (Fig. 10-13) for the British sector of the North Sea is currently the only commercial tension-leg platform. The proposed installation sequence is shown in Fig. 10-14. Before this platform is installed, a drilling template is placed on the seafloor within the perimeters of the tether foundations. The TLP hull, constructed in a dry dock, is moved to a deep water mating site where it is submerged in order to install the topside on it (similar to a gravity platform). This assembly is then towed to site, submerged so as to connect the tendons (tethers) to the preset foundations, and finally deballasted to tension the tethers.

Although technically the TLP is a floater, it is considered as a fixed platform because of being permanently tied to the seafloor. It is also designed to minimize the influence of tides, winds, and wave forces, the effect of whch is not the same as on conventional mobile ships or semisubmersibles.

The TLP is directly applicable to deep waters where two types of completions are possible: (a) subsea trees and manifolded production risers, and (b) tie-back risers (extended wellhead casing strings) and conventional surface trees. The TLP has the following major subsystems:

(A) Mooring system: Because of the magnitude of the forces involved and their direction, the mooring system for a TLP requires specialized components which include: (a) Four seabed mooring templates. (b) Anchor connector located at the bottom of each tension leg. This provides an automatic mechanical latch to secure each tension leg to the template. (c) Tension legs (three or more). (d) Cross-load bearing at the top of each tension leg. This allows angular movement of the tension leg below the TLP and also cushions any side loads imposed by TLP movements. (e) The tension leg tensioner system, consisting of a motion compensator and acces- sories for maintaining precise tension.

(B) Drilling system: Drilling system includes the template assembly, through which the wells are drilled. Some of the wells may be predrilled using a conventional floating drilling vessel, i.e., drillship or semisubmersible.

(C) Production system: After the wells are drilled, instead of installing completion trees, the template wells are tied back to the TLP through a production riser. This constitutes the tieback system. Sales risers are also required for off-loading processed crude and natural gas through subsea pipelines.

Platform installation

The primary construction “ tool” used in the installation of offshore platforms has been the floating crane or “derrick barge”. The first derrick barges in general use that were built specifically for the offshore industry were 250-ton capacity, revolving cranes mounted on non-self-propelled, barge-type hulls. The size of this equipment became larger with time. For many years, the 500-600-ton capacity derrick barge was the standard. These barges, which were satisfactory for most operating conditions throughout the world, have been effectively used in the construction of hundreds of offshore platforms. With the initiation of construction

397

in the North Sea, larger and more serviceable equipment that could operate during the more severe weather conditions became more desirable. Several ships with very large crane capacity were converted to derrick ships. In many cases, the different wave response to the shipshape hulls did improve working performance over that of derrick barges. The new generation of semisubmersible derrick barges, which are used now, offers considerable improvement in the ability to work in more hostile environments (Lee, 1981).

The main structural component of a typical fixed steel platform is the jacket, or lower unit. This jacket extends from the ocean floor to above the water surface. The legs (or columns) are open pipe members. Tubular bracing members interconnect these legs to make the jacket a single rigid structural unit space frame. Piles are driven through the legs of the jacket into the ocean floor. The jacket serves as a driving guide during pile installation, and as a structural unit to resist horizontal loads from wind, waves, and currents. For use in shallow water, the jacket is completely fabricated in one piece, carried to location on a cargo barge, and picked up and set on bottom by a derrick barge.

For use in deeper water, the most frequently used installation technique for jackets has been launchmg from a barge at the location (Fig. 10-7). The launch barge must be of sufficient size for marine stability, and of adequate strength tu

support the weight of the jacket during tipping. After the jackets are launched, they must be up-ended (rotated) from the horizontal to a vertical attitude. With the shallow-water jackets, this is usually accomplished by lifting. Because of the magnitude of the loads, deep-water jackets must be rotated and set on bottom essentially by controlled flooding. This requires more sophisticated flooding and venting systems, with appropriate backups, which must be carefully designed and fabricated. For successful installation of the larger jackets, model tests and detailed operational instruction, including contingency plans, are essential.

After the jacket has been set on the ocean bottom, it is leveled and piling are stabbed through the jacket legs. When the piling has been driven to the proper penetration, the deck unit, or units, are lifted into place and set on the top of the piling. The connections between the deck leg and the piling, as well as between the piling and jacket, can then be made and all other operations necessary to complete the structure can be performed. After this “ weld-out’’ process, the drilling rig and/or any other packaged equipment modules are set on the structure. This method of construction has been developed to best utilize the capabilities of offshore construction equipment and to minimize erection time at the location. The critical period between launch and “weld-out’’ must be kept to a minimum (Lee, 1981).

The concept of a self-floating jacket is a viable alternative when deep-water jackets are too heavy for available launching equipment. Self-floating jackets have been used about two dozen times compared to hundreds of barge-launched jackets. The self-flotation structure is characterized by legs which have a sufficiently large diameter so that adequate “built-in” buoyancy is provided. This enables the jacket to float at a relatively shallow draft. Because this buoyancy is built into the jacket (rather than into the launch barge), more steel is usually required. In addition, the

398

extra wave and current forces on the larger legs require increased structural strength, resulting in heavier framing and, possibly, additional piling. Fabrication of the larger legs is more complex and, therefore, more expensive. These factors, plus the additional control system necessary for up-ending and sinking, have tended to make self-flotation structures more expensive. In some instances, other considerations, such as unavailability of launching equipment or utilization of the large legs to protect wells from ice forces, have justified the use of a self-floating platform. It is doubtful that a self-flotation jacket has ever been selected purely on the basis of economics of the structure alone (Lee, 1981).

Platform selection

Selection of the type of platform depends on several factors: (1) The depth of water, (2) sea conditions and environment, (3) production life of the wells, (4) cost of the platform system, (5) availability of dry docks for launching, and (6) the distance from the shore. There are other considerations that may determine the choice. A close examination of the features of the various types of platforms reveals some of these factors.

Figure 10-15 shows the relationship between cost and depth for the common types of platforms. Decisions are most often based on cost considerations. Projected water depth capabilities for various platforms are outlined in Fig. 10-16.

Seufloor templates Templates provide both the guide for drilling operations and a structural base for

the subsea completion equipment (production risers and supports, pipes, valves,

I I I I I I

GUYED TOWER

8 LEG JACKET- A

~

L 8

2

n W _I 1

m z -

I00 500 1000 1500 2000 2500

WATER DEPTH, f t

Fig. 10-15. A comparison of the design, fabrication, and installation cost of platforms (excluding topside equipment and facilities) as a function of water depth. (After Dunn, 1980, fig. 1, p. 27; courtesy of the National Academy of Sciences.)

399

NON A R C T I C

I’ 5.000

FIXED LEG t-

L

I i-

W 13

n

U w I- s

‘ I I A R C T I C

I CONICAL STRUCTURES

ACTUAL INSTALLATIONS GRAVEL

0 GUYED TOWER A TENSION LEG PLATFORM

lo 1950 60 10 80 90 2003 Y E A R

Fig. 10-16. Industry platform water depth capability projection. (After Geer, 1980, p. 9; courtesy of the National Academy of Sciences.)

etc.). Templates can be deployed over the ocean floor for single or multiple wells. A cluster of wells can be directionally drilled through a template from a semisubmersible platform. The template structure is easy to fabricate and its low profile minimizes the effects of exposure to waves and currents.

In the integrated template structure, the manifold and wells are permanently attached to the template. The template structure is submerged and installed in a single piece with the wellhead chambers, manifold chamber, and all other internal equipment built-in (Fig. 10-17a). The wellhead chambers are initially installed to enable drilling through them; they are later completed for production facilities by setting the Christmas tree, piping connections, etc. by underwater operations. T h s template type bypasses the risks involved in installation and connection underwater and is particularly suited to depths of 2000 ft or greater (English, 1980).

The modular template (Fig. 10-17b), on the other hand, is installed without the wellhead or manifold chambers in place. The wellhead chambers are set in place as desired. Usually, the wellhead chambers are installed as the wells are drilled and completed. Finally, the manifold chamber is run and set. Each well is individually connected to the production manifold by an extendable conduit. This concept offers the following advantages:

(1) Drilling can be initiated before the wellhead and manifold chambers have been fabricated. Thus, the template structure installed for the initial well is minimal.

(2) The basic template can be expanded in the event of subsequent production development by simply adding on as many wellhead and manifold chambers as required.

400

Fig. 10-17. Multiwell templates: (a) integrated type, and (b) modular type. (After English, 1980, p. 69; courtesy of Pergamon Press Ltd, Oxford, England.)

401

+PENDANT LINE

ANCHOR

Fig. 10-18. A chain-wire mooring system. Wireline = 400 ft. (Modified after Sellars, 1981.)

(3) Each well can operate independently of other wells. Hence, repairs are easy

(4) The modular arrangement of the Christmas tree and production manifold

The major problems with templates in general are: (1) the launch is irreversible,

and production monitoring is simpler.

permits replacement of one without disturbing the other.

and (2) templates are unstable until piles are driven.

Mooring systems The basic objective of providing a mooring system is to keep the horizontal

movement of the drilling or production unit caused by wind, waves, and currents within prescribed limits. As a rule of thumb, the maximum horizontal movement should not exceed 2-3% of the water depth (Collipp, 1972). The components of a mooring system are: (1) chain and/or wireline, (2) anchors, and (3) winches.

Mooring lines transmit force to the ocean bottom through anchors. A typical chain-wire mooring system is shown in Fig. 10-18. In addition to the chain wire system, there is an all-wire mooring line.

The interaction of mooring line length and weight with the forces involved is of utmost importance in analyzing a mooring system. Tables have been developed for aiding the solution involving cumbersome calculations for singlepoint and multi- point mooring systems. These generalized tables are independent of water depth or mooring line size. Figure 10-19 shows the various configurations of mooring lines which may be solved using these tabulated relationships (Collipp, 1972).

Platform construction steps

The construction and installation of offshore facilities are usually done concur- rently. Two basic approaches for the construction of drilling and production platforms are: (1) piece by piece and (2) modular. The following facilities must be designed: (a) process equipment, (b) water treating and injection equipment, (c) gas compressors, (d) utilities, and (e) living quarters.

402

1. SLACK

L I M I T I N G

2. SLACK CASE

3. TRAN S I T ION

CASE

I

4. TAUT CASE

1 5 . TAUT

L I M I T l N G 1 C A S E

Fig. 10-19. Classification of mooring line geometries. (After Collipp, 1972, p. 45; courtesy of Energy Communications, Inc., Dallas, Texas.)

The design is usually computer-aided. It involves the development of a model (a trial configuration), analysis and evaluation of the model, and subsequent adjustments and improvisations to meet the design criteria as well as to provide the best overall economy. Programs have been developed for all the aspects of marine

403

structure design and the additional requirements for oil and gas production and transportation. The following steps are followed during design: (1) preparation of the process flow diagram, (2) determination of equipment layouts, (3) integration into the structural module, (4) building a model, and (5) preparation of detailed drawings. Drawings are then used in the construction of the platform.

SUBSEA PRODUCTION SYSTEMS

The foremost problem facing the petroleum industry at present is the production of oil and gas in deep water. The cost of the systems designed for the shallower depths increase exponentially with an increase in water depth. During the past few years there has been a significant increase in the number of subsea completions worldwide. Nearly half of the existing 250 active subsea completions have been installed in 1979-1980.

Subsea production systems consist essentially of wells completed on the seafloor and connected by flowlines and controls to a surface facility. The basic requirements of a deep-water subsea system as visualized by the Mobil-NAR group (Crosby, 1972a, b) are as follows: (1) All components must be compatible. (2) Must be able to handle any type of production and must be usable at any depth with minor modifications. (3) Must be adaptable to complete automation. (4) Must be applicable in any area of the world and at any distance from the shore. ( 5 ) Must be compatible with any drilling program or type of drilling equipment. (6) Must be surface oriented with as little manual assistance as possible. (7) Must have minimum number of components.

The subsea systems that have been proposed to date include: (1) satellite well production system, (2) semisubmersible production system, (3) one atmospheric chamber production system, (4) subsea atmospheric system (SAS), and ( 5 ) Exxon's subsea production system (SPS).

(1) Satellite well production system The important components of the satellite well system are: (a) subsea wellhead

system ', (b) subsea production trees ', (c) subsea flowlines, (d) controls, (e) integral production riser system, and (f) subsea manifold.

In a satellite well system, several individual wells produce through individual flowlines to a gathering manifold with a floating facility above it, or directly to a fixed production facility in shallow water (Gray, 1981).

The subsea wellhead equipment in deeper waters includes (1) the guidelineless landing structure (GLS), which is installed on the seafloor, and (2) the guidelineless reentry assembly (GRA), which features a large funnel for guidance of all drilling equipment, BOP stack, and later the subsea tree into the well.

The guidelineless type used for deeper waters.

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The deep-water production trees are designed for operation and maintenance with minimum reliance on reentry procedures, because of limited access by divers at such depths. The modifications over the shallower-water production trees include a large funneled reentry structure for re-establishing the tree running tool and completion-workover riser prior to retrieving the tree or performing wireline work (Gray, 1981).

A subsea manifold template serves as a central gathering point for production from all satellite wells. It also directs fluids up to the floating production facility through a production riser system. In systems using through flowline (TFL) techniques, TFL selectors permit each tree to be serviced individually without interrupting production from other trees in the system (Crosby, 1972a).

Well spacing permitting, the advantage of the satellite well system is that several drilling vessels can work simultaneously. This is useful where the reservoir is a really large one, or the producing formation is too shallow to be directionally drilled, as is necessary with a template cluster.

(2) Semisubmersible production system Semisubmersible production system consists of satellite wells connected to a

central manifold located directly under a semisubmersible production platform.

SEMISUBMERSIBLE PRODUCTION SYSTEM

PRODUCTION FACILITIES

SHUTrLE TANKER . a n

Fig. 10-20. A semisubmersible production system. (After Mason, 1980, p. 108; courtesy of the National Academy of Sciences.)

405

Production risers carry the total fluid up to the platform, whereas the sales lines carry the fluid to a periodic tanker loading point or pipeline systems (Fig. 10-20).

All seafloor equipment is surface-controlled. The semisubmersible system is a converted drilling rig, moored on location. T h s system is under successful operation at the Argyll Field in the North Sea since 1975 in a water depth of 250 ft. The semisubmersible was chosen here because the field reserves were not sufficient. Since that time, however, additional reserves have been discovered.

(3) One-atmospheric chamber production system In one-atmospheric chamber production system, production from satellite wells is

directed to multiple manifold centers that are connected, in turn, to the base of a single-point mooring production riser (Fig. 10-21). The production riser carries the fluid up to the production facilities on a tanker where the oil is separated, stabilized, and stored (Mason, 1980). Transport tankers dock alongside this production-storage tanker.

In cases where pipeline transport is used and storage is, therefore, not required, support process facilities other than a tanker may be used.

(4) Subsea atmospheric system (SAS) Subsea atmospheric system was developed by Mobil Oil Co. in the mid 1960’s. It

is a hybrid system where the subsea trees on the wells, which were drilled through

ONE ATMOSPHERE CHAMBER PRODUCTION SYSTEM

SERVICE VESSEL STORAQE PRODUCTION VESSEL \ I

MAN TRANSFER BELL-

PRODUCTION RISER

Fig. 10-21. One-atmosphere chamber production system. (After Mason, 1980, fig. 11, p. 111; courtesy of the National Academy of Sciences.)

406

SAS PRODUCTION SYSTEM

PRODUCTION RISER

SUPPORT VESSEL

Fig. 10-22. An SAS production system. (After Mason, 1980, fig. 12, p. 113; courtesy of the National Academy of Sciences.)

subsea templates, are connected to manifolds that are, in turn, connected to the production riser. The manifolds are housed in large chambers, the lower section of which is inert gas at one atmosphere. The upper part of the chamber is maintained at one atmosphere with breatheable air, to enable manned inspection-repair.

A prototype SAS (Fig. 10-22) was installed in the Gulf of Mexico in 1972. Thereafter, this system has demonstrated its feasibility in water depths up to 1500 ft (Mason, 1980).

(5) Exxon’s subsea production system (SPS) This system (Fig. 10-23) uses many of the sub-assemblies of the deep water

satellite well production system (Eckerfield, 1976): (1) wellhead system, (2) subsea trees, (3) flowline connections, (4) TFL selectors, (5) controls, (6) manifolding, and (7) production riser systems. The unique sub-assemblies are: (8) template bases and (9) plumbing modules.

The template bases include the GLS, primary template structure, cantilever base structures, and cantilever flowline modules. The procedures for installation are similar to a single deep-water satellite wellhead. The GLS is installed on the ocean floor to provide initial support and levelling of the primary template structure. With the latter in place, cantilever base structures are run for guidance of the conductors and wellhead housings for the subsea wells. The cantilever flowline structures are run next to provide connection points for satellite wells.

407

SUBSEA PRODUCTION SYSTEM (SPS)

*SERVICE BOAT

MANIPULATOR-

PRODUCTION PRODUCTION

VESSEL

MANIPULATOR

WELL TEMPLATE

Fig. 10-23. Subsea production system (SPS). (After Mason, 1980, p. 114; courtesy of the National Academy of Sciences.)

The retrievable plumbing module, connected to the primary template structure, provides plumbing and connection points for service and injection lines, production lines, control lines, annulus lines, etc. These lines direct flow and control signals from the manifold to the subsea trees (Gray, 1981). The modular template well system has the following advantages:

(1) The system can be installed in a relatively small area. (2) The system can be installed in a building block fashion by the drilling vessel,

because all components can be sized to suit the rig-handling limitations. (3) The system can accomodate a much larger number of wells than the satellite

system. (4) In the case of closely clustered wells, a greater number of wells can be

produced to a single vessel. Exxon started the development of this system in 1968. The three-well prototype

was installed in the Gulf of Mexico during 1974 to 1978 time period and has demonstrated SPS capability in water depths up to 2000 ft and more.

DESIGN CONSIDERATIONS

An offshore platform must be structurally adequate for both operational and environmental loading, and must be practical to construct. As part of the overall system, the platform must be cost effective and provide a satisfactory return on the

408

investment. The design of an offshore platform involves consideration of all of these factors. Aesthetic or architectural considerations are generally unimportant in designing an offshore platform. The overall concept is influenced as much by methods of fabrication and installation as it is by the applied operational and environmental loadings (Lee, 1981).

Before designing an offshore platform, it is necessary to determine the foundation conditions at the site and to predict the environmental conditions, such as wind, wave, current, ice, and earthquake. In some areas of the world, such as the North Sea, the environmental loading criteria are established by governmental agencies, and must be used by designers on the same basis as building codes are applied in other industries. In other areas, however, the design criteria for environmental loads are established by the owner on the basis of risk evaluation. As pointed out by Lee (1981), this evaluation must take into account protection of life, protection of the environment, the projected useful life of the facility, and economic considerations. Generally, it is not practical to design for the absolute maximum possible occurrence, but rather for some less severe condition more likely to occur during the life of the structure. It is normal practice to use the “recurrence interval” as a means of identifying the selected criteria. The structure is then designed for particular conditions likely to be equaled or exceeded in the selected time period. For instance, the 100-year storm is not the storm predicted to occur once every century in the entire area. It is the storm which is projected to have a 1% chance of occurring each year and passing close enough to the location to subject the platform to forces equal to or exceeding the selected design criteria.

In addition to establishing the environmental design criteria, the basis of the design must also be established. The traditional specifications developed for other types of structures do not apply to all phases of structures in an open-sea environment. To help fill this void, the American Petroleum Institute, Division of Standardization, formed the API Offshore Committee with the intention to develop advisory standards for assistance to the industry. The RP 2A is the result of their effort. It provides recommendations and guidance to designers to supplement existing design aids. The American Welding Society also made a substantial contribution by publishing the Structural Welding Code D1.l. Chapter 10 of this code provides design guidance for structural welding of tubular members and joints.

Very broadly speaking, an offshore platform is subject to the following forces: (A) Operational forces, which include: (1) Structure weight, i.e., the weight of the platform jacket-body, the decks, piles,

grouts, buoyancy chambers, etc. (2) Equipment weight, which consists of the weight of the drilling and production

equipment, and other infrastructure mounted on the basic platform. (3) Operating loads, which are imposed during operating conditions. They

include the loads due to drilling fluid, water, produced fluids, injection fluids, anchors, etc.

(4) Wellhead loads, which include those of casing, tubing, wellheads, etc. In subsea completions where wellheads are completed on the seafloor, these are replaced by the load due to production riser, etc.

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(B) Environmental forces Environmental forces are forces beyond the control of the designer or operator

and for which estimates must be made and allowance provided in the design. These forces are difficult to assess and the criteria applied are:

(1) Waves: height, period, wave energy, etc. (2) Currents: the velocity at the surface. (3) Winds: wind velocities are ascertained for two conditions: (a) steady winds

(4) Earthquakes: magnitude. Some of these general design criteria for offshore platforms are discussed below.

It must, however, be realized that the exhaustive API standards are to be consulted in any design work.

and (b) sudden sharp gusts.

Earthquake design criteria

In designing for earthquake damage prevention, the following requirements should be satisfied: (a) Structural damage must be avoided in the event of shaking for which there is a significant probability of occurrence during the life of the structure. The earthquake spectrum is scaled to reflect an acceleration equal to kg (g is the acceleration due to gravity and k is a constant depending upon the location), which is the level of acceleration having a particular recurrence interval. (b) Safety against collapse must be provided in the event of the strongest potential shaking. In order to achieve this, the level of acceleration approximating the maximum potential shakmg expected near a causative fault should be used. (c) Structure must have sufficient ductility to undergo plastic straining without loss of structural integrity. For this, the structure is designed to accomodate without collapse a deformation twice the low-level earthquake or 1.25 times the deformation resulting from the lugh-level earthquake, whichever is greater.

Wind and wave forces

Although the winds and waves acting on an offshore structure during a storm are not regular and periodic, a common approach is to design a structure for specified wind speed, wave height, and wave period. This criterion is a “50-year storm” or a “100-year storm” which refers to the worst wind and wave conditions one would expect in any 50- or 100-year period. Usual engineering practices have led to platform designs for the 100-year storm. A 400-year storm, however, is generally used in analysis, implying a probability of exceedence of only 0.25% per year.

The design criterion is modified somewhat by water depths also. For example, an offshore structure would normally be designed for more severe wind and wave conditions in 1000 ft of water than in 500 ft of water.

The severe storm crest elevation is derived from analyses of historical oceano- graphic and meteorological data and their statistical treatment. Determination of wave height, storm tide, and wind velocity form a part of this study.

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In addition to the extreme wave loading condition, dynamic analyses of the platform are performed for both severe-storm waves and repetitive storms. For severe-storm waves, transient analyses are used in which the time response of the structure is calculated from a wave profile containing the design wave. Response to sea states of repetitive storms is calculated in the frequency domain.

Winds blowing over the water surface generate waves. In general, the average wave is higher and longer with the higher wind velocity, the longer the fetch over which the wind blows, and the longer the time it blows. Waves still under the action of the winds that created them are called “wind waves” of the “sea”. They are forced waves rather than free waves and are variable in their direction of advance. These waves are irregular in the direction of propagation because of the variations in the direction of the winds. The water surface is quite turbulent and a current is created at the water’s surface due to wind shear (Brown, 1975).

The characteristics of waves become somewhat different after they leave the area in which they are generated. They become smoother and lose their rough appearance because of the disappearance of the multitude of smaller waves on top of the bigger ones, and the whitecaps and spray. The waves are known as “swells’’ when running free of the storm. Swells gradually lose their energy and become lower in height. The longer waves, which travel faster and generally outdistance the storm, are often called “forerunners of storms”. They reach the coast before the main body of waves (Brown, 1975).

The combined effects of wind and wave are normally treated as quasistatic forces. This is valid in most cases, particularly if care is taken in determining the “worst case” loading. Normally a “gust factor” is applied to the wind loading to account for the effects of velocity and direction changes in the wind (Brown, 1975).

The wind forces are proportional to the square of the wind velocity and are directly proportional to the exposed area. Other factors which affect the wind forces are the shape of the exposed areas and height above sea level. Wind velocity at height y (5 ) is equal to (see Graff, 1981, p. 67):

vy = v, ($)”” (10-1)

where V, = wind velocity at some reference height H (usually 10 m above a reference water depth (water surface) and l / n = an exponent usually assumed to be between 1/13 and 1/7 depending upon relative distance from land, sea state, and duration of the design wind velocity (API, 1979). It is around 1/13 for gusts and 1/8 for sustained winds in the open ocean. The wind force normal to an area can be calculated as follows (American Bureau of Shipping, 1980, 3.5.2):

F, = 0.00338 C&V?A, (10-2)

where: F, = force acting perpendicular to the area A,,, lb, A , = exposed area

41 1

normal to the direction of the wind, ft’, c), = height coefficient = (15/30)~/’, h =

height above water, ft, C, = shape coefficient (varies from 0.5 for cylindrical shapes to 1.5 for open structural steelwork), V = wind velocity, kn, V, = wind velocity (kn) normal to the area A, (V, = V sin a), and a = the angle between the direction of the wind and the exposed surface.

The force acting on the area in the direction of the wind, 5, is equal to:

F y = 0.00338 C,C,V’(sin C X ) ~ A , (10-3)

Using metric units, i.e., if F, is in kg, A, is in m2, and V is in m/sec, eq. 10-2 becomes:

The total wind force acting on a structure is determined by summing up the effects of wind forces acting on the separate areas of the structure. The wind force, however, is relatively insignificant in most cases.

The force of a wave on a structure is dependent upon the velocity and acceleration of the water moving past it. The accelerations and velocities of the water particles due to wave action are a function of the distance from the crest and of depth. At the wave crest, the velocity is maximum and the acceleration is zero. The accelerations and velocities are calculated using different wave theories depending on water depth and height of the wave. The total wave force, F,, per unit length (lb/ft; N/m) is equal to the sum of inertial and drag forces (API, 1979; American Bureau of Shpping, 1980):

where C, = inertia (or mass) shape factor, ranging from 1.0 for cylinders to 2.0 for structural steel shapes, C, = drag shape factor (or drag coefficient), ranging from 0.5 for cylinders to 1.5 for structural steel shapes, d = diameter of the structural member (usually cylindrical) or the pile, ft (m), y = specific weight of sea water, lb/ft3 (N/m3), g = gravitational acceleration, ft/sec2 (m/sec’), u = horizontal water particle velocity normal to the structural element, ft/sec (m/sec), 1 u I =

absolute value of u, ft/sec (m/sec), and du/dt = horizontal water particle acceleration, ft/sec’ (m/sec2).

Usually the velocity of both the wave as well as the currents is included in u. The range of the values of C D and C, underscore the importance of rounded shapes which produce lesser drag forces and an open construction with as little area exposed to the wave action as possible. The dimensionless inertial and drag coefficients used in the Morison et al. (1950) expression are 2.0 and 0.7, respectively.

The maximum force on any submerged member occurs where the resultant of the velocity and acceleration forces is maximum. This occurs slightly ahead of the crest. The total force that the structure experiences is the sum of the forces on its

412

individual members and depends upon the location of the wave crest with respect to the major structural members. In order to determine the maximum total force on a structure, the wave crest is stepped through the structure and total forces are calculated for a number of wave crest locations.

Pile capucity

Inasmuch as piles support the total structure, the support mechanism may be analyzed as being twofold: (1) support at the bottom end of the pile and (2) support from the sides of the cylindrical pile due to friction between the pile and the soil. The maximum support at the pile end, Qp, is equal to qAp (lb; kN) and the maximum support from the sediment surrounding the pile, Q,, is equal to fA,, where A , = pile end area, ft2 (m2), A , = surface area of pile in contact with the sediments (excluding the bottom end), ft2 (m2), q = unit end bearing capacity, i.e., maximum load that can be supported per unit area at the pile end, lb/ft2 (kPa), and f = unit skin friction capacity, i.e., amount of sediment-pile adhesion, lb/ft2(kPa). Thus, the total support Q is equal to (API, 1979, p. 30; American Bureau of Shipping, 1980, p. 81):

Q = Qp + Q, = qAp +fA, (10-6)

It is evident from the foregoing discussion that the unit bearing capacity q has to be evaluated before an engineer can approximate the pile capacity. The API (1969) RP2A defines the various parameters as shown in Fig. 10-24.

In the case of sand or silt, the unit skin friction f (lb/ft2; kPa) is equal to (API, 1979, p. 30):

f = Kp, tan 6 (10-7)

where p o = the effective overburden pressure = specific weight of sediment X pile depth, lb/ft2 (kPa), K = coefficient of lateral earth pressure, and 6 = angle of sediment friction on pile wall, degrees. For piles driven in oversize holes, K ranges from 0.1 to 0.4, whereas for piles driven in undersize holes, K ranges from 0.4 to 0.7. In the case of open-end driven steel pipe piles, K is around 0.7 for compressive loads and 0.5 for tensile loads.

For clays, the empirically established value of f from load tests is equal to:

f = k c (10-8)

where c = cohesive shear strength, and k < 1 (usually k = i). The unit end bearing capacity of deep piles in clay, q (lb/ft2; kPa), is equal to:

q = cN, (10-9)

413

IN CLAY

where q CNC + yD c = undrained shear strength

= effective unit weight Nc = bearing capacity factor

= 6 to 9 IN SAND and SILT

q = yDNq + 0.3yBNy where Nq and N, are bearing capacity factors

which depend on angle of internal friction, +

clean sand 35" 40 40 silty sand 30" 20 20 sandy silt 25" 12 10 silt 20" 8 4

BEARING CAPACITY OF FOOTINGS

_ _ _ _ + Nq N,

fmod!f,ed from API RP ZA, I9691

Fig. 10-24. Bearing capacity of footings. (Modified after API 1969, RP 2A.)

where c=cohesive strength determined from the in situ strength profile, and N, = bearing capacity factor commonly assumed to be equal to 9.

The unit end bearing capacity of deep piles in sand, q (lb/ft2; kPa), is equal to:

4 = PON, (10-10)

where po = the overburden pressure, lb/ft2 (kPa), and N, = bearing capacity factor for deep circular base. For detailed treatment of the subject, the reader is referred to API (1979) and Graff (1981).

Example 10-1

Given B (width or diameter of the pile) = 20 ft, D (depth of burial) = 10 ft, y (specific weight) = 100 lb/ft3, and if the sediment is known to be sandy silt, determine the unit bearing capacity, and the bearing capacity of the pile neglecting f.

Solution: Using Fig. 10-24, for a sandy silt, $I (angle of internal friction)= 25", Nq

(bearing capacity factor) = 12, and N,, (bearing capacity factor) = 10. The unit

bearing capacity is determined by using the following equation: q = yDN,+

414

0.3 yBN, = (100)(10)(12) + (0.3)(100)(20)(10) = 12000 + 6000 = 18,000 lb/ft2. Ne- glecting f and assuming a circular cross-section, the bearing capacity Q is equal to:

Q = qAp = (18,000)( m/4 B 2 ) = (18,000)( m/4)(20)’ = 5,657,000 lb = 2829 tons.

OFFSHORE TRANSPORTATION METHODS

The marked increase in oil and gas production in submerged areas has resulted in a rapid development of marine transportation technology. Transportation is accomplished with pipelines and tankers. In order to handle irregular production, new offshore and onshore storage and loading facilities have been developed. Legislation against oil spills gave rise to more innovative and realistic designs.

Underwater pipelines

Pipelines are usually preferred because they are simpler, cleaner, and have lower operating costs. They are more economical if the production level is high and distance from shore is not excessive (see Fig. 10-25). Laying a pipeline underwater is more complicated than on land. Some of the techniques used can be summarized as follows :

(1) The Bottom Pull Method. In the case of the bottom pull method, pipe is fabricated onshore in one or more sections, launched into the water, and then pulled along the bottom into its final position by means of a winch. The distance of the pull is limited by the power of the winch, the allowable pipe tension, and the weight of the line. Because of limited space on the launchway, the pipe must be divided into several sections. Thus, the pull is interrupted for tie-ins. This method is used mainly for narrow water crossings and relatively short pipelines (Lamb, 1972).

Min. Production for

a

0 Distance from shore (miles) -

Fig. 10-25. Transportation system selection-a typical relationship. (Modified after Sellars, 1981.)

41 5

(2) Flotation method. In the case of flotation method, the pipe joints are first welded into a number of long strings onshore. Pontoons are attached to provide buoyancy and the strings are towed section by section, into position. A tie-in barge holds together the ends of the two sections that have to be tied in. Pontoons are released systematically to lower the pipe to the bottom (Lamb, 1972).

Although the flotation method overcomes the length limitations of the bottom pull method, it is highly vulnerable to rough or even moderately rough seas. It is ideal for long lines in protected waters.

(3) Reeled pipe method. The pipeline can be laid by the reel method if it is relatively short and of small diameter. The pipe is fabricated into a continuous length and spooled into a large-diameter reel. The line is laid much like a cable by simply unspooling it from a mooring barge. Tension is applied to limit sag, especially in deep water. The advantages include: (1) rapid installation speed and, consequently, lower sensitivity to weather, and (2) the possibility of advance testing of the pipeline (Lamb, 1972). The main limitations of the reel method are mainly due to the pipe deformations resulting from coiling and uncoiling.

(4) Lay barge method. In the case of lay barge method, pipe joints are welded on the barge, which is equipped with an assembly line type of arrangement for this purpose. The barge moves ahead periodically and each joint progresses through several stages of welding, radiography, and coating. Then pipe joint is lowered into the water over a stinger that allows it to reach the seafloor without undue stress on the pipe. The stinger, which is a ramp extending at a controlled angle from the barge to almost sea-bottom, also limits the sag in the pipe (Lamb, 1972).

The lay barge method is limited by (1) the downtime requirements in rougher seas, (2) tensioner capacity, (3) barge mooring system capability, and (4) the ability of the pipe to withstand the loads incurred during installation as it passes over the stinger (Lochridge, 1980).

Tankers

Subsea pipelines are normally used to transport crude oil from offshore-production facilities to onshore-storage terminals and thereon to the refining facilities. As the industry moved further offshore and into areas that presented serious techno- logical and economical challenges for the installation of subsea pipelines, conventional tanker transportation techniques were modified considerably to serve as a viable alternative.

Although tanker transport is a fairly routine procedure, it requires careful design and planning. The tanker transport process is intimately related to the type of offshore storage (fixed or floating), the loading facilities (both offshore and onshore), etc.

Offshore storage

The fixed storage types, which were some of the earliest to be developed, include the Khazzan tanks, Ekofisk tanks, and the Condeep structure (Fig. 10-26). The

416

FIXED TYPES

B 1. KHAZZAN

4. DUBAl

1 2. EKOFISK

FLOATING TYPES

5. PAZARGAD

3. CONDEEP

6. SPAR

Fig. 10-26. Offshore storage types. (After Coleman, 1980, p. 158; courtesy of the National Academy of Sciences.)

Khazzan tanks, installed in the Persian Gulf, are steel structures of the shape shown, fixed to the seafloor by piles. They are 270 f t in diameter and 205 f t tall. The Ekofisk tanks in the North Sea are 302 ft in diameter, prestressed concrete storage tanks designed to withstand the rough conditions in the North Sea. They were built in nine modules and towed to location. The Condeep design consists of 19 vertical 66 ft in diameter reinforced concrete cylinders, 16 of which are 154 f t high. They provide a very high oil storage capacity.

The floating-type storage units are essentially barges and tankers that have been converted to storage units. Dubai Petroleum used spread moored tanker forebodies

- 1. CALM

FLOATING

2. ELSBM 3. SALM -1

FIXED OR MOORED

4. SALM -2 5. ALP 6. SPAR

Fig. 10-27. Offshore tanker loading systems; single-point moorings (SPM). (After Coleman, 1980, P. 160; courtesy of the National Academy of Sciences.)

417

for storage. Pazargad, designed and built by Mobil, is a barge moored by a single buoy mooring system. The SPAR type is a vertical floating storage tank with a six leg catenary mooring. It is quite stable in even rough seas.

Offshore tanker loading

Two concepts have emerged in the area of offshore tanker loading. One is the single-point mooring (SPM), which was developed for areas with directionally variant environmental forces (wind, waves and currents). The other is the single- anchor leg mooring (SALM), which was developed by Exxon to handle larger tankers (Fig. 10-27). The former (SPM) use spread mooring, whereas the latter (SALM) are attached to a base on the seabed by a single anchor chain or leg. Another system called SPAR combines storage and offloading capabilities provided by a retractable loading boom.

Combined storage and tanker loading

The single buoy storage (SBS) consists of a modified CALM and a storage tanker and is useful for smaller shuttle tankers. The SALS (single-anchor leg storage) is a storage tanker moored by a rigid yoke to a SALM structure, and is suitable for small to large shuttle tankers. The SPAR structure can accomodate small to medium-sized tankers.

Mobil Oil Co. has developed the loading-mooring-storage (LMS) system for handling very large crude oil carriers (VLCC) that can operate in severe environmental conditions. SCOTBUOY consists of vertical concrete cylinders moored to the seafloor. The details of these systems are beyond the scope of this chapter and the original references may be referred to for a complete discussion (Coleman, 1980; Jones, 1981; and others).

EXISTING

1. SES (TUNISIA) 2. SALS (MALAYSIA) 3. SPAR (BRENT)

NEW DESIGNS

4. Lms 5. SCOTEUOY

Fig. 10-28. Combined storage and tanker loading facilities. (After Coleman, 1980, p. 163; courtesy of the National Academy of Sciences.)

41 8

SAMPLE QUESTIONS

(1) List and briefly describe the different types of offshore structures. (2) Discuss the (1) advantages and (2) disadvantages of Template, Tower and

(3) Justify the statement that “the Tension leg platforms have the brightest

(4) Where are the subsea production systems advantageous to use? ( 5 ) Discuss the important operational and environmental forces on an offshore

Guyline platform types.

future”.

structure.

REFERENCES

American Bureau of Shipping, 1980. Rules /or Building and Classing Mobile Offshore Drilling Units. Am. Bur. Shipping, New York, N.Y.

American Petroleum Institute, 1969, 1979, 1982. Recommended Practice /or Planning, Designing and Constructing Fixed Offshore Platform. API RP 2A, American Petroleum Institute, Washington, D.C., 33 pp. (Also Supplement No. 1).

Anonymous, 1977. Union’s Beaufort Sea ice island success. Oil Gas J., 75 (28): 42-43. Anonymous, 1981. Safety and Offshore Oil. National Academy Press, Washington, D.C., 331 pp. Baker, W., 1981. Offshore exploration. Lecture given at the University of Southern California, Los

Angeles, Calif., Sept. 9. Brown, D.A., 1975. A study of the multiple aspects of construction of a drilling vessel. Thesis. Univ.

South Calif., 46 pp. Clark, J., Zinn, J. and Terrell, C., 1978. Environmental Planning /or Offshore Oil and Gas, Volume I:

Recovery Technology. Conservation Foundation, Washington, D.C. Coleman, D.M., 1980. Offshore storage, tanker loading, floating facilities. In: Outer Continental Shelf

Frontier Technology, Proc. Symp. National Academy of Sciences, Washington, D.C., pp. 155-172. Collipp, B.G., 1972. Analyzing mooring line catenaries. In: Offshore Technology. Energy Communica-

tions, Dallas, Tex., 202 pp. Corporon, W., 1983. Technology for tackling Alaska’s oil. Exxon U.S.A. Q. Mag., 22 (1): 17-21. Cowan, R. and Horton, E.H., 1983. The buoyant tower, new deepwater drilling and production concept,

Part 11, modern production risers. Pet. Eng. Int., (2): 36-56. Crosby, G., 1972a. Pacific deep water drilling techniques perfected. In: Offshore Technology. Energy

Communications, Dallas, Tex., 202 pp. Crosby, G., 1972b. Mobil engineers’ new deep water system. In: Offshore Technology. Energy Communi-

cations, Dallas, Tex., 202 pp. Dunn, F.P., 1980. Deepwater drilling and production platforms in non-Arctic areas. In: Outer Continen-

tal Sherf Frontier Technology, Proc. Symp. National Academy of Sciences, Washington, D.C., pp. 25-40.

Eckerfield, R.J., 1976. Sea-floor template speeds development drilling. In: Offsore Platforms and Pipelining, PennWell, Tulsa, Okla.

Ellers, F.S., 1982. Advanced offshore oil platforms. Sci. Am., 264 (Apr.; 4): 38-49. English, J.G., 1980. The one-atmosphere manifold centre. In: L. Atteraas, F. Frydenbo, B. Hatlestad and

T. Hopen (Editors), Proc. Int. Conf Underwater Technology, Offsore Petroleum, Bergen, April 14-16, Pergamon, Oxford, pp. 53-72.

Enright, R.J., 1976. Steel or concrete platforms for the North Sea-or neither? In: Offshore Platforms and Pipelining. PennWell, Tulsa, Okla.

Fitch, J.L. and Jones, L.G., 1976. Artificial ice islands could cut Arctic costs. In: Offshore Platforms and Pipelining. PennWell, Tulsa, Okla.

419

Geer, R.L., 1980. Introduction. In: Outer Continental Shelf Frontier Technology, Proc. Symp. National

Graff, W.J., 1981. Introduction to Offshore Structures. Gulf, Houston, Tex. Gray, D.J., 1981. Deep water subsea production systems. Lecture given at the University of Southern

California, Los Angeles, Calif. Guy, A.L., 1976. Platform for 850 feet of water nears the construction phase. In: Offshore Platforms and

Pipelining. PennWell, Tulsa, Okla. Hams, L.M., 1972. Deepwater Floating Drilling Operations. PennWell, (formerly Petroleum Publ. Co.),

Tulsa, Okla., 272 pp. Jahns, H.O., 1980. Arctic platforms. In: Outer Continental Shelf Frontier Technology. Proc. Symp.

National Academy of Sciences, Washington, D.C., pp. 41-71. Jones, M.E., 1981. Deepwater Oil Production and Manned Underwater Structures. Graham and Trotman,

London, 245 pp. Kash, D.E., White, I.L., Bergey, K.H., Charlock, M.A., Devine, M.D., Leonard, R.L., Salomon, S.N. and

Young, H.W., 1973. Energy Under the Oceans: A Technology Assessment of Outer Continental Shelf Oil and Gas Operations. University of Oklahoma Press, Norman, Okla., 378 pp.

Kennedy, J.L., 1976. New types of gravity platforms near completion. In: Offshore Platforms and Pipelining. PennWell, Tulsa, Okla.

Lamb, M.J., 1972. Designing, laying and maintaining underwater pipelines. In: Offshore Technology. Energy Communications, Dallas, Tex., 202 pp.

Lee, G.C., 1981. Fixed drilling and production platforms design and construction considerations. Lecture given at the University of Southern California, Los Angeles, Calif.

Lochridge, J.C., 1980. Deep water pipelines, In: Outer Continental Shelf Frontier Technology. Proc. Symp. National Academy of Sciences, Washington, D.C., pp. 123-154.

Mason, J.P., 1980. Subsea production systems. In: Outer Continental Shelf Frontier Technology, Proc. Symp. National Academy of Sciences, Washington, D.C., pp. 95-122.

McNabb, D., 1976. Guyed tower platform design nearing offshore test in Gulf of Mexico. In: Offshore Platforms and Pipelining. PennWell, Tulsa, Okla.

Morrison, J.R., OBrian, M.P., Johnson, J.W. and Schaaf, S.A., 1950. The force exerted by surfaces waves on piles. Trans. AIME, 189: 149-154.

Ranney, M.W., 1979. Offshore Oil Technology - Recent Developments. Noyes Data Corporation, Park Ridge, N.J., 399 pp.

Sellars, C., 1981. Offshore pipelines. Lecture given at the University of Southern California, Los Angeles, Calif.

U.S. Maritime Administration, 1977. A Technology Assessment of Offshore Industry. The United States Offshore Industry. Current Status, Trends and Forecast 1976-2000, Vol. I. The United States Offshore Industry, Washington, D.C.

Walker, R.W., 1972. Seafloor template completions for deep hostile water. In: Offshore Technology. Energy Communications, Dallas, Tex., 202 pp.

Wright, D.C. (coordinator), 1977. Artificial Islands in the Beaufort Sea - A Review of Potential Environ- mental Impacts. Fisheries and Marine Service, Environmental Secretariat, Canada.

Academy Science, Washington, D.C., pp. 1-12.


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Chapter I 1

POLLUTION CONTROL

K.M. SASSEEN, GEORGE V. CHILINGARIAN and JACK D. BRADY

INTRODUCTION

The petroleum and production engineers of today, in addition to their proficiency in and the understanding of the many facets of oil and gas treatment systems, must also become knowledgeable regarding the control of pollution- both water and air. Although there are many industrial related types of water and air pollution, this chapter is devoted to oilfield operations. Many regulations issued by Federal and State agencies, especially during the last twenty years, outlined necessary steps to control pollution. Production waters no longer can be discharged into open fields, streams, uncontrolled earthen sumps, etc. In many areas, the requirement for better pollution controls brought about the design improvement of systems for the recovery and reuse of water for steam injection and waterflood operations, etc.

Most liquid waste in the oilfield, produced by surface operations, results directly from produced water which must be separated from the crude oil. This water typically contains relatively high concentrations of dissolved sodium chloride, dissolved hardness (calcium and magnesium carbonates), suspended solids, and emulsified oils.

The common source points of oilfield contaminated waters, from oilwell production gathering systems, are as follows:

(1) Production dehydration facilities: (a) freewater knockout vessels, (b) water-oil-gas separators, (c) washtanks, (d) heater treaters, and (e) shipping tanks. Most of the above facilities are equipped with automated electronic sensing controls to establish an oil-water interface for the direct removal of production water into downstream wastewater cleaning systems for further treatment.

(2) Spills from collection systems. (3) Water drains from storage tanks and from test-sample operations. (4) Steam generator combustion gas (sulphur dioxide) removal by scrubber water

systems. (5) Rain runoff waters from oil storage tank areas, oil treating areas, and oil

loading-shipping areas. The primary sources of pollutants from surface operations are thermal stimula-

tion processes in secondary and tertiary oil recovery. To a lesser extent, sulfide and mercaptan emissions are produced at the wellhead and must be controlled. The most active pollution control activities have taken place in the California (U.S.A.) heavy crude oil fields. Similar programs are now being instituted in the Alberta

422

(Canada) heavy crude oil fields and will be introduced in the near future in Venezuela, Indonesia, and some of the Rocky Mountain (U.S.A.) production zones.

There are basically two reasons that the California oilfields have been most active in pollution control activities to date. First, the state of California has some of the most stringent air and water pollution control requirements of any region in the world. Second, thermal stimulation of heavy crude oil production has been most widely applied in California. All of the pollution control techniques discussed in this chapter are currently being practiced in California.

The pollutants of concern are sulfur dioxide (SO,), nitrogen oxides (NO,), particulate emissions, gaseous hydrocarbons, carbon monoxide (CO), hydrogen sulfide (H2S), mercaptans (R2S), acidic and alkaline waste liquids, water contaminated with high levels of dissolved solids, water contaminated with oil, and water contaminated with suspended solids.

Sulfur dioxide is produced by combustion of fuel containing sulfur. The major sulfur dioxide producers in the oilfields are oil-fired steam generators used in steamflood operations, oil-fired emulsion treaters (“heater-treaters”), direct-fired heaters, and packaged boilers used for process heating purposes. These devices are also the primary nitrogen oxide producers. Nitrogen oxides are also produced by internal combustion engines used with oilwell pumps, pipeline pumps, and compressor stations. Turbine-driven compressors and pumps also produce nitrogen oxides. Particulate emissions are produced by oil-fired equipment and by site-grading operations, unpaved road use, and natural processes including wind erosion of surface soil and landslides. Gaseous hydrocarbons are produced from incomplete combustion in oil-fired equipment and from evaporative losses from storage tanks. In addition, in steamflood operations, any steam which is vented from the well casing carries with it volatile hydrocarbons. Carbon monoxide can be produced from oil-fired equipment; however, these emissions, from properly adjusted equipment, are so small as to be virtually negligible in oilfield surface operations. Hydrogen sulfide and mercaptans can be produced from storage operations for crude oil and from gas vents from the well casing.

WATER TREATMENT

In order to prevent pollution of vital natural resources, all wastewaters must be purified prior to disposal, which requires special technology and process equipment. Water treatment capability is an essential requirement of most production unit facilities. Generally, there are certain impurities that must be removed or neutralized to improve the quality of water (1) for reuse, (2) to meet the disposal requirements for water well injectivity, or (3) to meet the disposal effluent standards set by the regional water quality control board.

Through long and continuing research and development programs, the petroleum industry has found useful purposes for recycled wastewater. Water produced in the development of hydrocarbons is usually treated to certain specifications, depending

423

upon the oilfield location, and then reinjected into deep reservoirs for disposal purposes. At other locations, water is often treated for reinjection back into the producing formations for pressure maintenance and secondary recovery operations. Produced water may also be treated and used as feed water in steam generators.

A multiplicity of considerations are involved in solving the water pollution problems, in which the water quality is related to specific industrial or other process systems requirements. The water qualities and standards that must be met are not fixed and are subject to changes with changing environment as it affects the elements. Sometimes, after the approval of a new process or system that yields a higher degree of water quality than before, standards are upgraded because of the development of new technology, for example. In the case of wastewaters, the water quality parameters that are evaluated include: (1) the BOD (biochemical oxygen demand), which quantifies the biodegradable organic matter content, (2) the oil content, (3) the COD (chemical oxygen demand) that defines the total organic matter content, (4) suspended solids content, (5) total solids content, (6) pH (alkalinity or acidity), (7) nitrogen and phosphorus contents, and (8) heavy metals and inorganic solids contents.

Obviously, the oilfield water treatment operations are primarily concerned with oil content and TSS (total suspended solids content). If the effluent water must be discharged into the ocean or a lake, or diverted to a sanitation district plant, instead of injection into an oilfield water disposal well, then additional requirements such as BOD and pH must be evaluated.

Contaminants

Suspended free contaminants which may consist of both settleable (e.g., fine- grained sand particles having oil film) and floatable material (mainly free oil), are held in suspension in water by turbulence. These suspensions can usually be removed by gravity separation within a surgetank or receiving watertank, for example, that allows reduction of velocity and provides retention of settled material. The methods of removal of free floating oil droplets after gravity separation and the settleable sand particles are discussed within the equipment process sections.

Entrained contaminants consist of floatable and settleable material, which is dispersed and sometimes tightly emulsified in the water. The following processes are used to remove entrained contaminants: (1) retention, (2) chemical treatment, (3) coalescence, (4) air-gas flotation, and (5) filtration.

Dissolved contaminants, which comprise organic and inorganic groups, include substances that are extremely detrimental to the environment. Organic compounds are resistant to biological oxidation. Inorganic dissolved solids which must be controlled if wastewater is to be reused, can be removed by (1) precipitation, (2) ion exchange, (3) reverse osmosis, (4) distillation and ( 5 ) electrodialysis. Typical oilfield water treatment, however, does not include any of these treatment systems. In certain cases, a particular sludge, resulting from oilfield water treatment operations,

424

could contain a critical heavy metals content that would prohibit local typical disposal means and necessitate special handling.

When oilfield waters are to be reused, dissolved oxygen is considered as a contaminant, e.g., in the case of a waterflood operation. Dissolved oxygen must be removed to reduce the corrosion. Oxygen reduction can be accomplished by gas stripping, vacuum stripping, and/or chemical oxidation.

Before deep-well water injection (waterflood), the wastewater must be treated to control the content of materials that would cause damage to the injection apparatus and piping or cause plugging of the formation. The treatment may include (1) the removal of suspended solids, oil, biological growths, dissolved gases, and precipita- ble ions, and ( 2 ) the control of pH (acidity or alkalinity).

Thus, the disposal means of oilfield wastewaters can be summarized as follows: (1) injection into a porous subsurface stratum, after minimal water treatment, within the oilfield drilling-production area (disposal wells), (2) reuse of the wastewater, after complex water treatment, as feed water to a steam generator facility within the production area, (3) transferring the wastewaters, after minimal water treatment, to a central cooperative plant, receiving variable in composition wastewaters from different companies, for further treatment to satisfy local regulatory agency disposal requirements, (4) reinjection of the wastewaters, after complex water treatment, into the producing formation (waterflood or combination water-CO, injection operation), and (5) disposal into a large body of water (ocean, inlet, bay, river, or gulf) after strict compliance with the local regulatory agency effluent standards.

WASTEWATER TREATMENT DESIGN

The basic design phases of an oilfield wastewater treatment system are: (1)

(1) Collection section collection and primary separation, ( 2 ) main treating, and (3) polishing.

The collection phase consists of a surgetank, which receives incoming variable flow wastewaters from freewater knockout vessels and oil dehydration facilities. This tank provides a system to handle surge capacity and, by gravity separation, the means to collect and return free oil back to the dehydration facility. The range of the oil content in water entering the surgetank might range from 200 to 2000 ppm (parts per million, mg/l). The reduction in the oil content might range from 40 to 70%, depending on the temperature, gravity of the oil, and viscosity of the oil as they affect settling velocity obeying Stokes’ Law. The contaminants (including settleable sand) that can be removed by gravity separation are eliminated in surgetank prior to the more elaborate treatment.

The main treating section consists of that part of any wastewater treating system whch is designed to reduce the content of contaminants or remove the oil and oily sand particulate contaminants that are present in a tight, stable oil-in-water emulsion. Ths treating section may consist of pumps, pressure vessels, a dissolved air (or

( 2 ) Main treating section

425

gas) flotation cell unit (DAF), an induced air (or gas) flotation cell unit (IAF), plate separators, precipitators, coalescers, chemical tanks, mixers, and chemical injection pumps. One or more of these components may be combined.

Dissolved air flotation, which is an efficient component in many systems, is an integral component in a wastewater treating system when the water contains (1) suspended solids, (2) entrained and immiscible oily waters, and/or (3) generally organic or inorganic solid contaminants that can be made to float.

Chemical treatment often enhances the mechanical and physical processes. This may include: (1) pH adjustment for emulsion breaking, (2) the addition of a preflocculating agent for the formation of microgranulation, and/or (3) agglomerating chemicals (polyelectrolytes).

The polishing section is the part of the system that is designed to remove final remaining traces of oil or solids from the water of the main treating section which has low content of solids and oil (a few ppm). Often the injection water with less than 1 ppm of suspended solids and oil is required in waterflooding. This phase of treatment usually requires a bank of sand filters (pressure vessels) that are filled with various types of sand media, in variable gradients. The downflow principle is often utilized and commonly two filters are “on-stream”, while a third unit is “on standby” (after the backwash cycle completion) ready to go on the line. These units are usually automated through a programmer for all of the sequential operations. The backwash mode might be initiated by a pressure differential sensing control or, as often is the case, a preset time function is programmed.

In some cases, a fourth phase of water treatment may include a water softening plant operation to purify filtered water for reuse as feed water for steam generators.

(3) Polishing section

Air flotation

Air flotation is a process by which suspended solids, globules of oil and grease, and other contaminating particles are separated from the wastewater and lifted to the liquid surface by the buoyant force of minute air bubbles, to form a floating agglomeration.

The two basic types of air flotation are: (1) induced air flotation and (2) dissolved air flotation.

(1) In induced air flotation type, sometimes referred to as dispersed air flotation, a dispersion of air (gas) is produced in water by means of a high mechanical shear, using a propeller-like mechanism through an eductor chamber. The air (gas) is self induced by a specially designed dispersing mechanism. A rotor forces the water through the eductor-like tube disperser openings. Thus, a negative pressure is created in the air-filled eductor tube that pulls the air downward into the water, resulting in an intimate mixing of the air with the water. Suspended solids and oil, whch become attached to these finely disseminated air (gas) bubbles, are carried to the top surface of the water and removed as floating material by a skimming mechanism. Usually, there are four separate flotation compartments, in series, as

426

one integral unit. Each one of these flotation compartments has a rotor-disperser system. The flow of water must pass through each compartment, in series, for progressive and efficient removal of solids and oil into isolated collection boxes.

(2 ) In the dissolved air flotation type, a multitude of small air microbubbles is produced in the water to be treated. Air (gas) is dissolved in the water under a pressure of three to four times the atmospheric pressure. There are two types of dissolved air (gas) flotation systems: (a) Full-flow pressurization system introduces air (gas) to be dissolved into 100% of the total (untreated) influent water. (b) A partial pressurization system usually is designed to recycle (side stream out of the unit) approximately 30% of the total inflow of water as a pressurized air-saturated water, which is mixed (blended within the unit) with the incoming water by various methods.

The fully pressurized dissolved air (gas) flotation system is often used for oilfield water treatment, to remove entrained and suspended solid contaminants. The system consists of a pressurizing pump, where a measurable amount of air (gas) is injected into the suction side of the pump. The untreated water and air are thoroughly mixed by the action of the pump impeller and the flow is routed into a pressure retention tank (45 psig), which provides air-water contact time to achieve saturation. The wastewater is then released through a back-pressure valve into the suction side of the pump. The untreated water and air are thoroughly mixed by the action of the pump impeller and the flow is routed into a pressure retention tank (45 psig), which provides air-water contact time to achieve saturation. The wastewater is then released through a back-pressure valve into the main flotation cell (back to atmospheric pressure), where the microbubbles are released due to the reduced pressure and adsorb to the suspended oil globules or solids. This reduces the effective specific gravity of the oil globules and solid particles and causes them to move upward, into a float pad, to be skimmed away.

Dissolved air (gas) flotation accelerates the gravity separation of oil globules, as illustrated by Stokes’ law:

(11-1)

where: V = rate of rise or fall of the particle, g = gravitational acceleration, pf =

density of the fluid, pp = density of the particle, d = diameter of the particle, and p = viscosity of the fluid.

Two of the above variables that are affected by air (gas) flotation are particle density and particle diameter.

The relationship between the velocity of air bubbles rising in water and their size is illustrated in Fig. 11-1.

The air (gas) bubbles, 60-90 pm in diameter, which normally carry a slight anionic charge, collide with oil globules and suspended solid particles and become attached to them by adhesion, adsorption, or entrapment. As a result of the attachment of these fine bubbles, the effective specific weight of the resulting agglomerates of particles and air decreases and their effective diameter increases.

427

I 20 30 4050 : Bubble size, microns

Fig. 11-1. Relationship between the velocity of air bubbles rising in tap water and size of bubbles. Velocity was calculated using Stokes' law. (After Vrablik, 1960, p. 743; courtesy of Purdue Industrial Waste Conference.)

Fig. 11-2. Relationship between the solubility of air in distilled water and temperature. (After Handbook of Chemistry and Physics, 1956, 36th edition, p. 1609; courtesy of CRC Press.)

428

Inasmuch as the specific gravity of these agglomerates (particles and air) is less than that of water, they rise to the surface to form a float pat. The latter is continuously removed by rotating skimmer blades. The relationship between the solubility of air and the temperature of water is shown in Fig. 11-2.

I’rtripitation of the gas on the solid or

liqriid 1iti:isc Solid particle or

oil globule

Collision of rising gas bubble and suspended

phase

4

Contxct angle

Rising air tjribble Gas 1~iit)I)le has

grown as pressure is released

l’loc structure

ririrlci fol1ll:l t 1011

Rising gas hnbble

Gas bubtiles :ire trn pljcd wit ti in the floc

or in siirf:ire irregularities

Gas bubble

(c)

Fig. 11-3. Three processes of minute air bubble attachment on suspended phase in dissolved air flotation. (a) Adhesion of a gas bubble to a suspended liquid or solid phase. (b) The trapping of gas bubbles in a floc structure as the gas bubbles rise. (c) The absorption and adsorption of gas bubbles in a floc structure as the floc structure is formed. (After Vrablik, 1960, p. 743; modified from illustration of Nemerow, 1963, p. 82, courtesy of Addison-Wesley Publishing Company, Inc.)

429

According to Vrablik (1960), who made extensive studies on the action of gas bubbles in air flotation, there are three processes involved: (1) adhesion of a gas bubble to a suspended liquid or solid phase, and (2) trapping of gas bubbles in a floc structure as the gas bubbles rise, and absorption and adsorption of gas bubbles in a floc structure as the floc structure is formed. These three processes are illustrated in Fig. 11-3.

Operation of a flotation system

A typical full pressurization-dissolved air flotation cell operation is illustrated in Fig. 11-4. Influent wastewater, with entrained oil particles and suspended solids, enters the surgetank from the dehydration system (heater treater or washtank) and other subnatant water returns (e.g., pits and sumps).

In addition to being utilized as a surge control tank (variable in-flow) surgetank is used to remove any free floating oil that can readily be skimmed from the surface. The automatic oil skimmer (AOS) operation is discussed later.

The main process charge pump (constant flow rate) takes suction from the surgetank to charge the flotation cell with pressurized air (gas) injected flow. A liquid level controller maintains the liquid level within the surgetank by throttling a recycle control valve (diaphragm operated), to control the flow from the flotation cell recycle flowline. By using this recycle method, ongoing flow balance is maintained, because produced water flow is variable and the system can handle from as low as 20% up to 100% of the maximum design flow.

Full-stream pressure mixing begins at the suction side of the main process charge pump, in order to mix and drive the proper amount of air or gas into solution. Approximate amount of air or gas necessary to inject is 3% of the total pump flow volume, or 2 scf/min for a 500-GPM pump flow.

The air-gas injection assembly, which prepares the gas for proper mixing, consists of two ejectors and a rotameter (for the measurement of the flow rate).

The discharge flow from the process charge pump, after proper dispersion of gas, enters the retention tank where the bubbles are collapsed under three to four atmospheres of pressure and are driven into true solution. The back-pressure regulator maintains the desired operating pressure.

The gas-saturated solution, with gas bubbles approaching 90 pm in size, is then released through the back-pressure regulator into the center coagulation tube of the cylindrical flotation cell (atmospheric conditions). Quiescent flotation occurs on the top surface, which produces an oil-tight floc that is removed by a top double-bladed skimming arm. This arm skims the floc up onto a ramp, into the oil sludge box, to flow into a sludge tank for further concentration of the sludge. The double-bladed skimming arm within a cylindrical tank flotation cell offers the most efficient means to remove the flocculated material at the surface, because of the direct immersion contact of the skimming blades in almost all of the top surface.

The type and characteristics of the oil floc sometimes varies with the type of chemical treatment upstream of the unit. The same drive shaft also rotates a bottom

ST SURGE TANK MP MAIN PROCESS PUMP RT RETENTION TANK FC FLOTATION CELL BPR BACK PRESSURE REGULATOR LLC- I LIQUID LEVEL CONTROLLER

VDU VARlDRlVE UNIT SGR SPEED GEAR REDUCER CB CONTROL BOOT GI AIR INJECTOR ASSEMBLY AOS AUTOMATIC OIL SKIMMER

PRODUCTION 5 DEHYDRATION

SYSTEM ST

HTI SUPERIOR INC

- .o

CHEMICAL INJECTION 0-2177

c 0 E

P w 0

Fig. 11-4. Schematic flow diagram of dissolved-air flotation cell. (Courtesy of HTI Superior, Inc., a Berry Industries Company.)

43 1

grit scraper arm for the separate removal of settleable solids from the grit collecting box at the bottom of the flotation cell.

In order for the clean water to reach the effluent outlet nozzle, the flow is directed to the special baffled collection section of the coagulation tube bottom. An outside boot with a Fisher liquid level controller actuates a level control valve to maintain the flotation cell water level approximately one inch below the top of the oil sludge box. The clean water effluent discharge, controlled as above, then flows to the receiving line system or a filtration plant for further polishing treatment.

Basic chemical is usually injected downstream of the charge pump and the secondary polyelectrolyte chemical is injected at the flotation cell inlet nozzle.

Ancillary equipment

The sludgetank is utilized for the collection and further concentration of the oil sludge from the flotation cell. The sludgetank is designed for vacuum truck haul-away and disposal.

The automatic oil skimmer (AOS), which is designed to lift oil vertically without pumping (Fig. 11-5), is used on wastewater clarifier tanks, sumps, and almost any system requiring oil removal from water as part of a water cleaning operation. The automatic oil skimmer is designed (1) to remove free floating oil from the surface of the water, (2) for continuous 24 hr/day operation, (3) to utilize a variable speed drive explosion-proof motor to vary the rotation speed of the belt for light or heavy oil pads, and (4) to remove oil at any operating level in the tank, from low to h g h variable levels.

The skimmer utilizes a continuously rotating belt that has affinity for oil. The belt rotates in the water and continuously removes oil from the surface of the water, causing the oil to migrate to the belt.

Oil that comes into contact with the belt adheres to the belt surface and is carried to the wiper trough. At the wiper trough, the oil is removed from each side of the belt surface by dual wiper blades, and moved into an oil reservoir. The recovered oil is then returned to an oil collection system.

Chemical treatment is usually a necessary supplement to oilfield wastewater treatment systems. Occasionally, the process equipment can be used without chemicals to meet a certain water effluent requirement. There are many different chemicals available for the testing and sampling of polluted wastewater.

Water sampling and testing

Prior to the selection of equipment and the design of an oilfield wastewater (produced water) treatment system, it is necessary to collect and test water samples. Commonly, a qualified laboratory analyzes the average of many collected influent samples, in order to determine the oil content (ppm; ether extraction method), the total suspended solids (TSS, ppm), the pH, and the content of various anions, cations, organic matter, etc. While the official test is being completed, onsite jar

-CLEATED ROTARY BELT DRUM

VARIABLE SPEED DRIVE MOTOR ~ - (EXPLOSION PROOF)

SKIMMED OIL OUTLET ----

H T I SUPERIOR

I I "" I I _.I. ..

. . " I ~~,

-.-- -~ VAPOR TIGHT 9 SKIMMER HOUSING

,- SPECIAL SKIMMING BELT (AFFINITY FOR OIL) VARIABLE LENGTH TO ACCOMMODATE ANY LIQUID LEVEL

Fig. 11-5. Schematic diagram of an automatic oil skimmer. (Courtesy of HTI Superior, Inc:, a Berry Industries Company.)

433

testing of the influent water samples is conducted utilizing various flocculants and polymers. This produces valuable information for the design of the total chemical treatment system.

Jar testing is accomplished by dividing a representative sample of the water to be treated into a dozen or more one-liter or two-liter jars. Individual flocculants and polyelectrolytes are tested in numbered or otherwise identified test jars, first with singular chemical doses followed by various combinations. In each step, after a thorough shaking, the following information is recorded: (1) separation of contaminants (if any), (2 ) if separation occurs, is the reaction fast or slow, (3) does the separation produce clear and bright clarified water or not, (4) do some particles still remain dispersed after separation or not, (5) whether the agglomeration of contaminants sink to the bottom or float to the surface, and (6) if the floating matter is produced as a result of chemical reaction, it is necessary to determine how long the float pad will remain tight and stable: one hour after separation, one day, or several days.

The dosage of the various flocculants and polyelectrolytes was not mentioned, because the basic jar test procedure is known as “hot-shotting” the chemical. It is an elimination process, whereby quantitative analysis of the various selected chemicals would follow (usually under finite control) in the laboratory and, sometimes, completed in the field.

Over the past twenty-five years of treating oilfield and other industrial wastewaters, the authors have observed that once a few good chemicals have been selected from jar testing a particular water, seldom do they fail to produce equal or better results in the full-scale operation of the process equipment. By utilizing available standard syringes, preparing a 10% solution of a chemical as manufactured, and then diluting that same solution again 10 to 1, a reasonable jobsite analysis can be completed with one- or two-liter samples, to estimate the amount of chemical in ppm (parts per million) necessary for injection. With this information, an estimated range of the amount of chemical required per day (quarts or gallons) for the total design flow, can be determined for each chemical. This is followed by a cost comparison of one chemical with another. Subsequently trial of selected chemicals is made upon “start-up” of the completed water treatment system, followed by fine “tuning” to accomplish the required effluent quality.

CHEMICAL TREATMENT

As stated previously, chemical treatment systems for oilfield waters are designed to complement various wastewater treatment equipment systems for the removal of oil globules, entrained oil contaminants, and oil-wet suspended solids. The efficiency of chemical removal process depends on: (1) the concentration of suspended oil, (2 ) the particle diameter, (3) charges on particles and degree of hydration, and (4) contaminant ratios. The introduction of chemicals improves the efficiency of the collisions between particles to enhance the aggregation.

434

SUSPENDED SOLIDS RANGE

COLLOIDAL CLAY COLOR VIRUS

EMULSIONS BACTERIA

ALGAE FLOC

ANGSTROMS I 10 102 103 lo4 lo5 lo6 10’ MICRONS 10-410-3 1 0 7 10-1 I 10 102 103

MACROCOLLOIDAL RANGE

Fig. 11-6. Size ranges for various suspended solid materials. (After Reilly, 1972, p. 89, fig. 2; courtesy of Plant Engineering.)

The concentration is a measure of the distance between the particles. Particle diameters in the range of 25-75 pm, which are considered large, can readily be removed by flotation systems, with minimal amount of chemical treatment. Very fine suspended particles that do not settle or rise are classified within the colloidal group. They are sometimes more difficult to remove. Figure 11-6 illustrates a suspended solids size range for various materials.

According to Reilly (1972), the four major factors that affect colloidal solids removal are: (1) destabilization, (2) microfloc formation, (3) agglomeration, and (4) physical entrapment (see Fig. 11-7). In order for the coalescence of colloids to take

COAGULATION I + - t

z o = f-c =@ t MICROFDC MICROFWC

CHARGE NEUTRALIZATION DESTABI LlZATlON

COLLOID

CATIONIC POLYMER DESTABILIZED COLLOID

FLOCCULATION

Fig. 11-7. Various steps in removing colloidal particles, coagulation and flocculation. (After Reilly, 1972, p. 91, fig. 3 ; courtesy of PIunr Engineering.)

435

place, the interparticle repulsion forces must be neutralized. Thus, cationic chemicals can be used to decrease the net negative charge on particles and thereby cause destabilization.

Coagulation is a chemicophysical process wherein collisions between colloidal particles and coagulating chemicals result in the eventual formation of agglomerates. As noted above, most suspended solids are negatively charged. Thus, by introducing a chemical coagulant with an ionic charge opposite to that of the contaminant, neutralization of charges takes place to produce spongy masses called flocs.

Chemical coagulants often used are inorganic coagulants, such as (1) alum or various types of clays, (2) inorganics, such as metal salts of calcium, aluminum and iron, and (3) numerous organic polyelectrolytes, either natural or synthetic. Syn- thetic organic polyelectrolytes are divided into cationic, anionic, and nonionic.

Flocculation consists of mechanical entrapment of the agglomerated particles by adsorption onto the flocs formed with coagulant chemicals and also by molecular bridging of the individual molecules of the coagulants. It includes macrofloc formation caused by agglomeration and microfloc formation resulting from the interparticle bridging.

Coagulant aids are of considerable assistance in the coagulation process. They act as “bridgers” in that they mechanically stick floc particles together. Many polyelectrolytes are now classified as coagulant aids.

The wide acceptability of the many synthetic organic polyelectrolytes as high-performance products is a result of their hgh molecular weight and the variety of ionizable groups that can be placed along the polymer chain. Nonionic and anionic polyacrylamides are compared in Fig. 11-8. Because of the uncoiling phenomenon of the anionic materials, their chain lengths are larger than the nonionic material and are, therefore, more effective as a bridging agent (coagulant aid) when charge neutralization is not an important factor in suspended solids removal.

Pollution control is a necessary and costly program for production operations. With careful planning and design, a system can be installed to produce a quality effluent and the recovery of usable process water is sometimes possible.

NONlONlC POLYACRYLAMIDE

@ &pL&yA+

AVAILABLE CHAIN LENGTH

BOTH PRODUCTS HAVE APPROXIMATELY THE SAME MOLECULAR WEIGHT

ANIONIC POLYACRYLAMDE

Fig. 11-8. Comparison of nonionic and anionic polyacrylamides. (After Reilly, 1972, fig. 4, p. 91; courtesy of Plant Engineering.)

436

STEAMFLOOD EMISSIONS

Most steamflood operations utilize a packaged oil-fired or gas-fired stem generator with a capacity of either 25 MMBtu/hr or 50 MMBtu/hr. These steam generators typically burn crude oil or gas from the field in which they are being used to make 80% quality steam for injection into the oil formation. When oil is burned, sulfur dioxide, particulate matter (and resultant visible emissions), oxides of nitrogen, sulfates, carbon monoxide, and unburned hydrocarbons are produced. When gas is used as the fuel, the emissions are limited to oxides of nitrogen. Of these pollutants, only four represent significant emission problems and two are indis- tinguishable from an emission control point of view.

Assuming that the steam generators are operated with adequate excess air, carbon monoxide can be eliminated as an emission of concern and unburned hydrocarbons are present in such small concentrations that they are of no concern either. Sulfur dioxide and sulfate emissions are produced simultaneously during combustion of sulfur in the fuel and these two pollutants can be considered as a single emission control problem.

Sulfur contained in the fuel for a steam generator is oxidized to sulfur dioxide. One pound of sulfur in the fuel generates two pounds of sulfur dioxide in the gas stream. A typical 50 MMBtu/hr steam generator, burning 3400 lb/hr of 1.1% (wt) sulfur crude oil, will produce about 75 lb/hr of sulfur dioxide in the exhaust gas. Further oxidation of sulfur dioxide to SO, in the steam generator is dependent upon excess air rate, burner temperature, and the concentration of trace metals in the steam generator fuel which catalyze this oxidation reaction. The amount of sulfur dioxide converted to SO, is very small in an oil-fired steam generator. The SO, concentration is typically about 0.3% (wt) of the sulfur dioxide.

After sulfur dioxide has been emitted from the steam generator, it can oxidize slowly to SO, in the atmosphere. The primary environmental concern is that it is then precipitated out of the atmosphere as “acid rain”. As a point of clarification, sulfate (SO:-) is not the same as SO, (which is properly called sulfur trioxide). Most regulations, however, consider both of these to be sulfates from a regulatory point of view. Specific emission regulations exist for SO, but, at the moment, SO, and SO:- are not normally regulated separately.

Table 11-1 has been prepared to indicate the magnitude of SO, emissions from various-sized oil burners at various fuel sulfur levels. Many new regulations require operators to offset the SO, emissions from a new oil-fired source and scrubber. This is done to reduce pollution in an area considered already too polluted. As an example, in Kern County, California, some operators must design for a 1.2 to 1 offset. Two obvious techniques are available. First, the operator may reduce the sulfur content of the fuel used in one existing oil-fired source, to offset emissions from new oil-fired sources. Second, the operator may scrub emissions from an existing oil-fired source. As an example, if the operator plans to install three (3) new 50 MMBtu steam generators firing 1.0% sulfur fuel and equipped with 95% efficient SO, scrubbers, he must offset 3 x 91.8 x 1.2 = 330.48 lb/day of SO, from “other

TABLE 11-1

Sulfur dioxide emissions from uncontrolled and controlled oil-fired steam generators and other oil-burning sources, assuming 146,500 Btu/gal oil at maximum firing rates

Fuel oil consumed (MM Btu/hr)

Uncontrolled SO, emissions (lb/D)

0.8% (wt) 1.0% (wt) 2.0% (wt) 4.0% (wt) 0.8% (wt) 1.0% (wt) 2.0% (wt) 4.0% (wt)

Scrubber SO, emissions at 95% calculations (lb/D)

10 294 361 134 1468 14.7 18.4 36.8 13.6 18 529 661 1322 2644 26.5 33.0 66.0 132.0 22 588 134 1468 2936 29.4 36.1 13.4 146.8 25 134 918 1836 3162 36.1 45.9 91.8 183.6 50 1469 1836 3612 1344 13.5 91.8 183.6 361.2

100 2938 3612 7344 14688 146.9 183.6 361.2 734.4

P W 4

438

sources”. If he already operates one other 50 MMBtu steam generator near the new units, which burns the same 1% sulfur fuel, he could fire that existing generator with 0.1% sulfur diesel fuel and make available 1,652 lb/day of SO, offsets. After the 330.48 lbs/day of offsets are used for the new generators, he could either “bank” the remaining 1,321.5 lb/day of offsets for future use, or offer them for sale to other producers who do not have available offsets (and sell them at a price which would compensate him for his added operating cost for the diesel fuel).

The operator could also scrub emissions from the existing generator at 95% efficiency, giving him 1,744.2 lb/day of SO, offsets. Again, the residual offsets could be “banked” or sold.

Particulate matter produced in an oil-fired heater exhaust gas stream results primarily from ash in the fuel oil. In addition, ambient dust, taken in by the combustion air fan, also produces particulate emissions in the exhaust gas stream. Sulfur dioxide which converts to SO, in the oil-fired source is also detected as particulate matter. Finally, particulate emissions are sometimes generated by improper fuel/air ratios which result in unburned carbon or unburned hydrocarbons in the exhaust gas stream. Normally, if the burner is operated with inadequate excess air, the exhaust gas will be black and sooty, which indicates unburned carbon in the exhaust gas. This condition will often be observed during startup of a steam generator when the burner flame is not up to temperature and the fuel is not completely combusted. If this condition is allowed to persist for any substantial period of time, it can result in a dangerous operating condition, because the unburned carbon is quite finely divided and can create a dust explosion if ignited by the addition of more oxygen and a spark or flame.

As combustion air is increased to slightly greater than stoichiometric conditions, particulate emissions are reduced to a minimum level and, in most cases, visible emissions almost completely disappear. If the fuel contains a substantial concentration of non-combustible ash, visible emissions may be produced, even at optimum excess air conditions. If there is any substantial concentration of silicon, vanadium, or nickel in the fuel, the metallic oxides which are produced by combustion of the fuel, and the subsequent oxidation of the metallic contaminants by the excess oxygen present, produce submicron particulate matter, which has high light reflec- tivity and can create noticeable visible emissions even in extremely small concentrations. The effect of metallic oxides on particle size distribution can easily be seen in Fig. 11-9. Without metallic oxides, the concentration of submicron particulate matter is 5% by weight of the total particulate matter. With metallic oxides, the concentration of submicron particulate matter can reach 92% (wt). In general, the smaller the particle size, the more visible are the emissions.

If the excess air rate is increased to a level where oxygen in the exhaust gas stream exceeds about 6%, visible emissions will again be noticed at the exhaust stack. These emissions are primarily unburned hydrocarbons and often have a blue “haze” appearance at the exhaust, At even higher excess air rates, these unburned hydrocarbons exist together with partially combusted hydrocarbons to give a brownish smoke in the exhaust gas stream.

439

CUMULATIVE % LESS THAN STATED SIZE

Fig. 11-9. Aerodynamic mass size distribution for oil-fired burner flyash using oil, with and without trace metal contamination.

From an air pollution control point-of-view, the unburned carbon which is produced as a result of inadequate combustion air in the oil-burning source, is a relatively large particulate matter which can be scrubbed out of the gas stream in almost any conventional scrubbing system. Metallic oxides produced during optimum burner operation can also be scrubbed from the gas stream, but because of their extremely small particle size, may require extremely high differential pressures to make significant reductions possible. As the excess air feed rate increases beyond optimum levels, the unburned hydrocarbon aerosols are often extremely small and again require significant energy levels to control. Fortunately, most fuels do not produce large concentrations of highly visible particulate matter. Therefore, most oil-fired sources operated at optimum combustion air rates, will produce invisible or nearly invisible exhaust gas streams, which not only comply with visible emission regulations, but also with the most stringent particulate regulations. Most oil-fired sources can be “tuned up” to bring particulate and visible emissions into compliance with regulation levels. In those rare instances where, because of fuel composition, they cannot be adjusted to comply with these regulations, scrubbing systems can be designed to bring them into compliance. If offset regulations exist, particulate collection systems must also be considered.

Uncontrolled emissions of particulate matter from oil-fired sources operating under optimum firing conditions generally fall in the range of 0.05-0.08 g/scf. For a 50 MMBtu/hr oil-fired unit, burning 3400 lb/hr of fuel, this works out to be between about 5.3 and 8.5 lb/hr of particulate emissions. Scrubber performance on these emissions is discussed in this chapter.

Nitrogen oxides are produced in oil-fired equipment by oxidation of nitrogen from two different sources. These sources are chemically-bound nitrogen in the fuel

440

and atmospheric nitrogen in the makeup air. Both NO and NO, are produced in the burner flame at temperatures above about 2000 O F. These are collectively referred to as NO,. The predominant nitrogen oxide present in the exhaust gas is NO (nitric oxide). Nitrogen dioxide (NO,) is commonly produced in concentrations of between 0.5 and 10% (wt) of the NO emissions. Oxidation of nitrogen is a very complex reaction. Very little is known about the actual production mechanism. The concentrations of NO and NO, reported as NO,, however, depend upon the burner temperature, the concentration of chemically-bound nitrogen in the fuel, and the excess air rate. At first glance, one might theorize that the nitrogen oxides produced in the exhaust gas from an oil-fired source are derived entirely from nitrogen bound in the fuel. The dependence upon excess air rate might then simply be the tempering effect which excess air has on the flame temperature at the burner. Such is not the case, however. Natural gas-fired burners, containing no nitrogen in the fuel, often produce higher concentrations of nitrogen oxide emissions than do oil-fired burners, which burn oil containing bound nitrogen. This is true presumably because higher temperatures are maintained in the gas flame. In addition, most oil-fired burners produce nitrogen oxide emissions, which are in excess of those theoretically possible, based on chemically-bound nitrogen in the fuel.

The high-temperature oxidation of elemental nitrogen to NO, using atmospheric nitrogen as the source, is called fixation. Unlike sulfur dioxide formation reactions, nitrogen oxide production mechanisms can be significantly affected by burner operation. Unfortunately, peak nitrogen oxide emissions are commonly observed when the burner operates at optimum firing conditions. If the burner is operated with inadequate excess air, nitrogen oxide formation is reduced, but fuel combustion efficiency is adversely affected and particulate emissions (with attendant visible emissions) increase dramatically. At excessive combustion air rates, nitrogen oxide production is again reduced, because the excessive air rates temper the high temperature zones in the burner flame and minimize conditions for nitrogen oxide formation. Unfortunately, heat is then wasted to elevate the temperature of this excess air and, again, efficiency of the oil-fired equipment suffers. In addition, particulate emissions again increase, and sulfur dioxide conversion to SO, also increases in the oil-fired units.

A variety of techniques have been investigated for reducing nitrogen oxide emissions from fossil fuel-fired burners. Some of these techniques have been successful in achieving reductions of more than 50%. Once the NO is discharged from the steam generator, it converts, at cooler atmospheric temperatures, to NO,, which is probably the most insidious of all air pollutants. It is toxic, extremely corrosive, and has severe detrimental effects on the respiratory system. Furthermore, it is a known precursor to formation of photochemical smog. It serves as an energy trap by absorbing sunlight to form nitric oxide and atomic oxygen:

NO, + A + NO + 0 (11-2)

The atomic oxygen is very reactive, forming ozone with oxygen and initiating a

441

number of secondary photochemical chain reactions with volatile hydrocarbons in the atmosphere.

Sulfur dioxide control

Initial efforts to control sulfur dioxide emissions from fossil fuel-fired equipment were made in England when sulfur dioxide, mixed with “London fog”, created sulfuric acid clouds, which resulted in a number of deaths among London residents in the 1940’s. Very active sulfur dioxide control programs are now underway in the United States, Canada, Japan and Germany. In the United States, the primary attention has been given to coal-fired utility plants. In Germany and in Canada, attention has been directed primarily to coal-burning sources. For about 25 years, sulfur dioxide control technology has improved and has now developed to a point where very successful commercial installations have been made on a number of utility and industrial boilers.

Because of the availability of lime and limestone in most areas in the United States where coal is used as a fuel for utility plants, most sulfur dioxide removal systems have involved lime or limestone as the reactant for the SO2. Scaling problems in the scrubbers, tanks and piping are often encountered due to the insolubility of calcium sulfite and sulfate, which are the reaction products. Very difficult materials handling problems also result from use of lime or limestone slurries for absorption of sulfur dioxide. As a result, much attention has been given to development of sodium hydroxide or sodium carbonate-based systems, which use water soluble absorbers and keep the calcium out of the scrubbing loop. The most successful of the water soluble absorption systems is the double alkali process (Brady and Legatski, 1978). This system utilizes either sodium hydroxide or soda ash as a makeup chemical, but then utilizes slaked lime Ca(OH), in a secondary reaction loop to precipitate calcium sulfite dihydrate (CaSO, - 2 H,O), while simultaneously regenerating the absorption solution. Only small quantities of the relatively expensive sodium hydroxide or soda ash are required to act as makeup chemicals for sodium salts, which are dragged out of the solution as entrainment in the filter cake. This system has been highly successful in controlling emissions from both oil- and coal-fired industrial and utility sources. One such system has been installed on multiple steam generators in the oilfields (Sachtschale, 1980).

When very small combustion sources are considered for sulfur dioxide removal, as in the case of individual oilfield heaters, the lime and limestone scrubbing systems are simply not economically feasible because of the capital and operating costs of the materials handling equipment required to produce slurries of either lime or limestone. In addition, because the oil-fired systems in the oilfields are operated unattended, slurry systems are not adequately reliable, due to pipe and nozzle pluggage and extreme sensitivity to operating conditions, to prevent scale formation. The “toothpaste-like” waste product is also difficult to handle and very expensive to dispose of.

Because of the high capital cost associated with the secondary chemical reactor,

442

the slaked lime handling equipment, and the vacuum filtration system necessary to operate a double alkali process, this process can only be considered where multiple oil-fired systems are banked together to produce a single source of sulfur dioxide of greater than about 12,000 lb/day.

Where sulfur dioxide sources of less than 12,000 lb/day exist, it becomes economically more attractive to use a “single-pass’’ scrubbing system, utilizing either soda ash or sodium hydroxide as the makeup chemical. These systems are operated in almost the same fashion as the absorption step in the double alkali process. Rather than regenerating the liquid from the scrubbing process, however, the liquid is simply disposed of. This minimizes capital cost and operator attention required. The operating costs are thus lower than would be the case with a double alkali process on such small emission sources.

Table 11-11 shows the various sulfur dioxide removal techniques which have been used on fossil fuel-fired combustion sources. Although the absorption mechanisms for the double alkali, lime and limestone processes differ substantially, the end products are quite similar. As can be seen in reviewing Table 11-11, the concentrated single-pass scrubbing system (Brady, 1979) utilizes chemistry almost identical to the double alkali chemistry in the absorption step. As Table 11-11 also shows, however, two different modes of absorption are used by different manufacturers in absorption systems for steam generators. In one case, sulfur dioxide is absorbed into a relatively high-pH solution containing some free sodium hydroxide or free sodium carbonate. In the other case, sulfur dioxide is absorbed into a sodium sulfite solution to make sodium bisulfite. The sodium hydroxide or soda ash added to the scrubbing system then converts the sodium bisulfite back to sodium sulfite. The sulfite-bisulfite system is an excellent buffer system. If sufficient quantities of sulfite and bisulfite are dissolved in the absorption solution, the pH of the absorption solution remains relatively constant, regardless of inlet sulfur dioxide concentration. If, on the other hand, the high-pH absorption solution is used, the system is no longer a buffer system and the pH changes are dramatic with changes in sulfur dioxide concentration at the inlet.

The pH of a given solution is important in predicting collection efficiency for SO,. The dilute and concentrated systems in Table 11-11, however, differ greatly in absorption efficiency, even at the same pH. In addition to pH, another important consideration in determining SO, removal efficiency is the ionic strength of the solution (a method of expressing the total soluble ionic species in the scrubbing solution). Ionic strength increases as the concentration of sodium sulfite, bisulfite and sulfate dissolved in the scrubbing solution goes up. The efficiency of a given sulfur dioxide removal system is dependent upon the pH of the scrubbing solution, the total ionic strength, the inlet sulfur dioxide concentration, and the design of the scrubbing unit.

The maximum theoretical efficiency, which can be achieved at any given system, is dictated by the partial pressure of sulfur dioxide over the scrubbing solution at equilibrium temperature between the scrubbing liquid and the saturated gas stream. As an example, if the partial pressure of sulfur dioxide over a given scrubbing

443

TABLE 11-11

The chemistry of various sulfur dioxide control processes

DOUBLE ALKALI Absorption solution

Discharge from scrubber

Absorption reactions

Regeneration reactions

Overall

Waste product

LIMESTONE SLURRY SYSTEM Absorption slurry



Overall

Waste product

Na,SO, +NaHSO, +Na,SO, + H 2 0 pH = 6.2-6.8

Na,SO, +NaHSO, +Na,SO,+H,O pH = 6.1-6.7

SO, +Na,SO, +H,O + 2 NaHSO, Na,SO, + i02 + Na,SO,

Ca(OH), +Na,SO, -+ CaSO, + 2 NaOH 2 NaOHf2 NaHSO, + 2 Na,SO, + 2 H,O

Ca(OH), + 2 NaHSO, -+ CaSO, + 2 Na,SO, + 2 H,O

CaS0,.2 H,O (in dry filter cake form)

CaCO, + CaSO, + CaSO, + H,O pH = 5.8-6.5

CaCO, + CaSO, + CaSO, + H,O pH = 5.4-6.2

SO, + H,O + H,SO, H,SO, + CaCO, --t CaSO, + CO, T + H,O

CaCO, + SO, + CaSO, + CO, 1

thick paste form I CaS0,.2 H,O CaSO, . xH ,O

LIME SLURRY SYSTEM Absorption slurty



Overall

Waste product

Ca(OH), + CaSO, + CaSO, + H,O pH = 7-8

Ca(OH), + CaSO, + CaSO, + Ca(HSO,), + H,O pH = 4.9-5.4

SO, + H 2 0 - H,SO, H,SO, +CaSO, -+ Ca(HSO,), Ca(HSO,), +Ca(OH), -+ 2 CaSO, + 2 H,O

SO, + Ca(0H) , -+ CaSO, + H,O

thck paste form CaS03.2 H,O CaSO, . xH,O I

DILUTE SODA ASH OR SODIUM HYDROXIDE SINGLE PASS SYSTEM Absorption solution NaOH or Na,C03 +Na,SO, +Na2S0, +H,O

pH = 8-10

444

TABLE 11-11 (continued)

Discharge from scrubber Na,SO, +NaHSO, +Na,S04 +H,O pH = 4-5

SO, + 2 NaOH + Na,SO, + H,O or SO, +Na,CO, + Na,SO, +CO, f and SO, + Na,SO, + H,O + 2 NaHSO, Na,SO, + :02 + Na,SO,


Waste product Na,SO, +NaHSO, +Na,S04 +H,O in dilute (less than 5% dissolved solids) solution

CONCENTRATED SODA ASH OR SODIUM HYDROXIDE SINGLE PASS SYSTEM Absorption solution Na,SO, +NaHSO, +Na,S04 +H,O

pH = 6.2-6.9

Discharge from scrubber Na2S0, +NaHSO, +Na,SO, + H 2 0 pH = 6.0-6.8

SO, +Na,SO, +H,O + 2 NaHSO, Na,SO, + ;O2 + Na2S04


Chemical addition

-Waste product

NaOH+NaHSO, + Na,SO, +H,O Na,CO, + 2 NaHSO, + 2 Na,SO, + CO, t + H,O

Na,SO, +NaSHO, +Na2S04 +H,O in concentrated (greater than 5% dissolved solids) solution

solution is 30 ppm (vol), and the scrubbing unit is mechanically capable of achieving equilibrium conditions between the gas and the liquid at its discharge, it would be possible to achieve 90% collection efficiency or greater only on inlet sulfur dioxide concentrations of not less than 300 ppm (vol).

Ninety-five percent efficiency could be achieved only on inlet gas streams with an SO, concentration in excess of 600 ppm (vol) (Sachtschale, 1980). Likewise, 97% collection efficiency could be achieved only on inlet gas streams having a sulfur dioxide concentration in excess of 1000 ppm (vol). Thus, while a given scrubbing system may, in fact, be 90, 95, or 97% efficient under given operating conditions, if the inlet sulfur dioxide concentration is not sufficiently high, the scrubber may not achieve the advertised efficiency levels. It is far easier to reduce a 1000 ppm SO, concentration to 50 ppm (95% collection) than it is to reduce a 200 ppm SO, concentration to 10 ppm (95% collection). Figure 11-10 shows actual SO, vapor pressure measurements at equilibrium conditions over a typical scrubbing solution at various sulfite/bisulfite molar ratios.

An equally important design consideration is the quantity of removed sulfur dioxide which can be discharged from the scrubbing system in a given unit volume

445

SULFITE-BlSULFlTE MOLAR RATIO IN SOLUTION

Fig. 11-10. Measured equilibrium SO, concentrations over aqueous solutions of sodium sulfite, bisulfite and sulfate at 130°F and an ionic strength of 4.6.

of liquid. If the concentration of reacted sulfur dioxide is extremely high in the scrubbing solution, the amount of waste liquid which has to be disposed of from the scrubbing unit is minimized. High concentrations of dissolved salts are beneficial in minimizing disposal problems from these scrubbing systems and also enhance the buffer capability of the scrubbing solutions. In addition, the high dissolved solids levels allow maintenance of minimum scrubbing liquid inventories and minimum scrubbing liquid flow rates. As the ionic strength increases for a given sulfite-to-bisulfite ratio, the partial pressure of sulfur dioxide over that solution also increases. This means that at constant pH, increasing ionic strength causes reduced SO, collection efficiency. Thus, it is necessary to pick an optimum scrubbing solution which enables the proper collection efficiency, while minimizing waste disposal rate.

Chemical consumption by a given scrubbing system is also of importance in determining operating costs for such a system. In general, the higher the concentration of sodium bisulfite in the waste liquid stream, the lower the chemical consumption for a given removal of sulfur dioxide. This can be seen by reviewing the chemical reactions which occur in the scrubber:

Caustic soda NaOH + SO, -+ NaHSO,(sodium bisulfite) 2 NaOH + SO, + Na,SO,(sodium sulfite) + H,O

(11-3) (11-4)

(The sulfite requires twice as much NaOH as the bisulfite for the same SO, removal)

446

Soda ash Na,CO, + 2 SO, + H,O + 2 NaHSO, + CO, Na,CO, + SO, += Na,SO, + CO,

(11-5) (11-6)

Unfortunately, high sodium bisulfite concentrations result in relatively low sulfur dioxide collection efficiencies. A caustic consumption rate of 0.5 Ib NaOH per Ib SO, removed may be achieved, but if the exhaust stack is tested, it will not be in compliance with regulation SO, levels. One technique which has been widely used by scrubbing system suppliers in sulfur dioxide removal applications other than oilfield burners, is a two-stage scrubbing system where the gas stream is first contacted with a solution containing substantial concentrations of sodium bisulfite at pH’s in the range of 4-6. The gas stream is then passed into a second stage where it is contacted with a higher pH scrubbing solution. In the first stage, only a small amount of sulfur dioxide is removed, but this sulfur dioxide is absorbed by sodium sulfite, which would have otherwise been disposed of without being reacted. Therefore, chemical utilization is maximized. When the gas is then contacted with the more alkaline scrubbing solution in the second stage, it is still possible to acheve the same collection efficiency which would result in a single stage system utilizing a higher pH scrubbing solution. Unfortunately, the two-stage process is not particularly attractive for oil-fueled systems in the oilfields for three reasons. First, the acidic waste liquid is difficult to dispose of because it attacks mild steel tanks and even corrodes stainless steel tanks. Second, the waste liquid has a sufficiently high sulfur dioxide vapor pressure to create secondary SO, emissions at its point of disposal. These secondary emissions will be regulated in the future. Finally, and of greatest importance, is the fact that virtually all of the makeup water used in the scrubbing systems contains some soluble chlorides. Chlorides are corrosive to the 300 series stainless steels, even in neutral solutions. The corrosion rates increase exponentially as the acidity of the scrubbing solutions increase. Acidic sodium bisulfite solutions, containing chlorides, therefore, will cause accelerated corrosion of the scrubber, the piping and the liquid recirculation system. The increased chemical utilization is seldom of sufficient benefit to compensate for these negative factors. Furthermore, if the system is operated with a two-stage absorption configuration, the operator’s attention required to maintain optimum operating conditions is greatly increased and system’s reliability is compromised.

A variety of scrubbing systems are available for use on oil-fired heaters. The mechanical operation of these scrubbers differs greatly. A common characteristic of all sulfur dioxide removal scrubbers is that they must make available to the gas stream a sufficient surface area of scrubbing liquid to allow adequate mass transfer for removal of the sulfur dioxide from the gas stream. The most common techniques are to distribute the liquid (1) in the gas stream as small liquid droplets or ( 2 ) over extended surfaces in the scrubber. This can be done by forcing the scrubbing liquid through a high-pressure nozzle, atomizing the scrubbing liquid with steam or air pressure, atomizing the scrubbing liquid by introducing it into a high-velocity gas stream, or cascading the scrubbing liquid across baffles and/or packing material

447

which have a high surface area, relative to the volume which they occupy. All of these techniques can be made to work in scrubbing systems for oil-fired sources. One such scrubber, designed for oil-field portability, is shown in Fig. 11-11.

Particulate emission control

Particulate emissions from an oil-fired source can usually be brought into compliance with regulatory requirements by relatively simple combustion adjustments. Proper fuel-to-air ratios will insure complete combustion of the fuel and will minimize particulate emissions. Conditions do arise, however, even at optimum firing conditions, where because of either an inability to maintain proper fuel-to-air ratios or an excessive concentration of metallic oxide contaminants in the exhaust gas stream, visible emissions are produced which do not comply with regulatory requirements. When this condition develops, there are three techniques which can be considered for collection of particulate matter. The first is to increase the energy consumption of the sulfur dioxide scrubbing system to a level which will achieve adequate collection of particulate material. This normally requires installation of a venturi scrubber. It is important to distinguish between a venturi scrubber and an ejector or jet-ejector type scrubber. A venturi scrubber is one which utilizes either a forced draft or induced draft fan to create a high velocity through the venturi section to achieve the necessary impaction of particulate matter on liquid droplets in

Fig. 11-11. For explanation see p. 448.

448

Fig. 11-11 (continued). Sulfur dioxide and particulate scrubbing system for oilfield use on a 50 MMBtu/hr steam generator. (Courtesy of Struthers-Anderson Pollution Control System.)

the scrubber. In a venturi scrubber, scrubbing liquid pressure is relatively low and most of the energy is devoted to the induced draft or forced draft fan which accelerates the gas. The venturi scrubbers typically operate at differential pressures of between 6 and 60 in. W.G. For the most severe particulate matter collection problems with oil-fired systems, a 60-in. W.G. differential pressure may, in fact, be required.

Ejector scrubbers, using either steam or water at extremely high velocity and pressure through a restricted throat section in the scrubber, utilize either hydraulic energy or a combination of hydraulic and thermal energy to accelerate the collection liquid droplets sufficiently to impact on the dust particles. Frictional losses in these

449

systems are greater than in a conventional venturi scrubber and, as a result, for the same collection efficiency, these systems require somewhat higher total energy consumptions. Furthermore, because of the necessity to recirculate the scrubbing solution, particulate matter collects in the scrubbing solution and, at the very high velocities created by the high differential pressures across the nozzles, nozzle abrasion becomes a significant maintenance factor.

As the need for extremely high collecting particulate material efficiencies becomes more acute, oil-fired equipment operators can consider both electrostatic precipitators and filtration systems as alternate collection devices.

Nitrogen oxides control

Three general techniques are available for reducing NO, emissions: (1) Catalytic reduction, (2) ammonia injection, and (3) burner and combustion

modification.

Catalytic reduction Catalytic converters, which have been fitted on automobile exhaust systems,

utilize expensive rare metal catalysts to convert NO, to elemental nitrogen and elemental oxygen. It is necessary to use unleaded fuel to prevent catalyst poisoning in these systems. The oil producers are not in a position to use a metallic contaminant-free fuel for oil-fired equipment. Thus, any of the conventional catalysts used for NO, reduction would be poisoned by the metallic contaminants in the fuels for this equipment. Furthermore, there have been no selective catalytic reduction units perfected for use in small industrial oil-fired plants. The primary reason is that the catalyst cost would be extremely high and catalyst life would be expected to be short. Another problem with the catalytic systems is that they require temperatures in excess of 600"F, and in some cases up to 1000"F, to operate properly. The normal convection section discharge gas temperature from oil-fired equipment falls between 400 and 500 OF, and any higher temperature would result in uneconomical operating conditions in the heaters. Catalytic reduction does not hold any significant promise for oil-fired heaters in the oilfields. For internal combustion engines in the oilfield, however, catalytic converters are widely used and are effective.

Ammonia injection Ammonia injection into the convective heat transfer section of an oil- or gas-fired

burner can reduce NO, formation. Tests have been done with ammonia injection in the oilfields (Robinson, 1977). Ammonia is injected downstream of the flame zone and acts as a reducing agent for NO. The reduction reaction is a gas phase homogeneous reaction, which takes place within a narrow temperature range of between 1650°F and 1900°F. Nitric oxide is converted to elemental nitrogen and water. Laboratory tests have resulted in NO, reductions of up to 80%. The oilfield tests indicated reduction efficiencies of about 62% under ideal conditions. Substan-

450

tial ammonia concentrations were necessary, however, to achieve these reduction levels. Exit gas ammonia concentrations were about half of the NO, concentration in ppm (vol) at the maximum NO, reductions. Because the ammonia can then react with sulfur dioxide in the convection section, there is concern about plugging of the convection section with ammonium sulfate when this excess ammonia is present in the gas stream. It does appear, however, that this process can operate reliably at a 50% NO, reduction level or greater.

Burner modification Low NO, burners are basically devices which attempt to eliminate hot spots in

the flame. Different methods of excess air injection, different methods of creating turbulence in the flame zone, and recirculation of hot flue gas into the burner zone have all been tried. NO, reductions of approximately 35-60% can be achieved. At present, the low NO, burners are probably the most reasonably priced NO, reduction devices.

Casing vent gas collection systems

Where steam injection is used for enhanced oil recovery, producing wells will often venksteam back to the surface. If the well casing is vented directly to the atmosphere, after the steam has dissipated in the ambient air, a residual blue aerosol forms. This aerosol consists of volatile hydrocarbons which, at steam temperature, were predominantly gas phase compounds but whch, after cooling down in the ambient air, become light oil aerosols. This oil is of value to the oil producer as product and is considered a pollutant by the regulatory agencies because it can contribute to photochemical smog formation. For this reason, oil producers must collect the vent gas streams from each of the oil wells, cool these gas streams sufficiently to condense the oils from them, and separate the oil and water which forms. Both air- and water-cooled heat exchangers have been used for this purpose. The steam is simply condensed back to water, the oil simultaneously condenses and floats on the water, and the mixture can be taken to an oil-water separator. Occasionally, an emulsion will form and the emulsion may have to again be heated slightly to produce proper oil-water separation.

In a number of locations, reduced sulfur compounds can be present in the casing vent gas. Gaseous sulfides may be encountered simultaneously with steam emissions from steamflood operations or they will sometimes be produced from sour gas vented from the hydrocarbon subsurface formation. The reduced sulfur compounds typically take the form of hydrogen sulfide (H2S) or mercaptans (organic sulfides). In relatively low concentrations, these sulfides can be scrubbed from the gas stream using simple caustic soda scrubbers. The reactions between sodium hydroxide and hydrogen sulfide produce sodium sulfide. As long as the liquid waste from the scrubbing system remains alkaline, the sodium sulfide remains relatively stable. However, if this waste liquid is contacted with any acidic liquid, causing the pH of the mixture to drop below 7.0, hydrogen sulfide emissions will be reemitted to the

451

TABLE 11-111

Removal processes for hydrogen sulfide

Name Reaction

Girbotol Phenolate ' Phosphate Sodium carbonate

Seaboard Lime Iron oxide Caustic soda

(vacuum)

Ironite sponge

2 RNH, +H,S % (RNH3),S NaOC,H, +H2S % NaHS+C,H,OH K,PO, +H,S% KHS+K,HPO,

Na,CO, +H,S @ NaHCO, +NaHS Na,CO, + H,S fi NaHCO, + NaHS Ca(OH), +H,S + CaS+2 H,O FeO+H,S + FeS+H,O 2 NaOH+H,S + Na,S+2 H 2 0

F e , 0 4 + 4 H , S + 3 F e S + 4 H , 0 + S

FeS + S + FeS, Fe,04 + 6 H,S + 3 FeS, +4 H , 0 + 2 H,

' Regenerated by steaming. Regenerated by vacuum steaming. Regenerated by air blowing.

atmosphere. To prevent this from occurring, it is quite common to use a strong oxidant in the scrubbing solution to oxidize the collected sulfide to sulfate. Once the sulfate has been formed, it remains stable in aqueous solution and is not affected by contact with acidic liquids. The most common oxidant for this application is sodium hypochlorite (NaOC1) (also see Table 11-111).

When hydrogen sulfide concentrations exceed about 50 ppm (vol), it is common to use an amine solution with both monoethanolamine or diethanolamine present to absorb the hydrogen sulfide from the gas stream, take the sulfide-rich amine solution and steam strip the sulfide from it in a concentrated gas stream, and then cool and reuse the amine solution for absorption again. This is done in a closed loop system where the waste gas enters and exits the absorber and a concentrated gas stream of hydrogen sulfide is produced out of the steam stripper. This concentrated hydrogen sulfide gas is then typically flared to burn the reduced sulfur compounds to sulfur dioxide. In some instances, a small sulfur dioxide scrubber must then be used to absorb the sulfur dioxide from the reduced sulfur compound incinerators. In California, there are an increasing number of oil-fired steam generators whch are being used to burn sulfide-rich gases from amine absorption systems to simultaneously produce heat and to eliminate the sulfide gas problem. Exhaust gases from these steam generators must then be scrubbed for sulfur dioxide emissions.

Produced water treatment and disposal

Where steam or water flood techniques are used for oil production, the produced oil is mixed with significant quantities of produced water. In many steam flood

452

operations, the oil is emulsified with the water. Most regulatory agencies prohibit disposal of the water, even after oil removal, to natural streams and rivers adjacent to the oil fields, unless total suspended solids are reduced to extremely low levels and dissolved solids are also minimal. Most oil producers try to reuse the produced water, as a result. If the water is emulsified with oil, it is first taken through a free water knockout system and then to a heater-treater. After it leaves the heater-treater, it is commonly taken to an oil-water separator. The water becomes relatively oil-free at this point and is then taken through water softeners to reduce hardness and to make the water reuseable in steamflood applications.

The produced water frequently contains high concentrations of sodium chloride. There is no recognized technique for chloride removal other than reverse osmosis and/or distillation. Neither of these techniques is feasible for the large volumes of water which must be processed in the oilfields. Therefore, it is often necessary to dispose of some of this produced water to prevent the sodium chloride concentration from building to an intolerable level. Disposal can take two forms. It can be injected into a subsurface formation which does not communicate with potable water. It can also be taken to a liquid waste disposal site which has an impermeable liner which prevents the chloride containing produced water from communicating with any potable water source. Water is often in relatively short supply in the oilfields. Some producers are giving serious consideration to casing their wells with high nickel alloys and providing non-metallic surface piping to allow use of these higher chloride liquids without corrosive effect on both surface and subsurface equipment, for reinjection into the wells.

Summary I

In oilfield surface operations, pollution control becomes a serious consideration when utilizing steamflood techniques for secondary and tertiary recovery. The three most highly regulated emissions have been sulfur dioxide, nitrogen oxides, and particulate matter. Techniques are available for reducing these emissions to regulation levels in the oilfields. In these same oilfields, produced water presents a significant challenge to the oil companies to comply with water pollution control requirements.

For sulfur dioxide removal, liquid scrubbing systems are used. Nitrogen oxides are controlled using catalytic techniques, ammonia injection or burner modifications. Particulate matter is commonly collected in the same scrubber which absorbs sulfur dioxide, but secondary particulate removal devices may also be used, including bag houses and electrostatic precipitators. Hydrocarbon emissions are produced at the wellhead in steamflood operations. These are controlled by condensing the steam, cooling the gas stream, and condensing the organics out of the gas stream for recovery. Finally, sulfides and mercaptans may be produced along with crude oil

By J.D. Brady

453

and may be treated by simple alkaline scrubbing solution absorption or by more complex amine absorption and steam stripping techniques. Equipment is available to the oilfield operator to accomplish all of this necessary pollution control in surf ace operations.

SAMPLE PROBLEMS

Sample problem I 1-1

In the flotation equipment presented below (Fig. 11-12) gas is intimately mixed

(a) Determine: (1) The weight of pollutant handled per day, if the flotation unit processes 12,000

(2) The horsepower necessary to drive the pump at an overall pump and motor

(b) Draw a diagram of a system to maintain the proper liquid level in the tank. (c) List all the other methods that are commonly used in pollution control.

with polluted wastewater in order to remove the sludge prior to disposal.

bbl/day of water containing 90 ppm of sludge.

efficiency of 70%.

Solution : (a-1)

Volume of pollutant = 90 X

Weight of pollutant = 350 X 1.08 = 378 lb/day.

X 12,000 = 1.08 bbl/day. Specific weight of water = 350 Ib/bbl. Thus:

(a-2) Total dynamic head (TDH) = 900 - 8 = 892 psig. Total dynamic head = 892 X 2.31 = 2061 ft. Flow rate = 12,000 : 34.3 = 35 gal/min (GPM).

Hydraulic horsepower = (TDH X GPM X sp. gr.) : 3960 = (2061 X 350 X 1) : 3960

Brake horsepower = hydraulic horsepower : efficiency = 182 : 0.70 = 260 HP.

Assuming sp. gr. = 1,

= 182 HP.

SLUDGE ,Jxqdgr~ (AIR)

8 psig

900 psig POLLUTED WATER

12. 000 b b l l d a y

Fig. 11-12. Schematic diagram of a flotation equipment-Sample Problem 11-1

454

Fig. 11-13, Schematic diagram of a system for maintaining the proper liquid level in the tank-Sample Problem 11-1.

A liquid level controller (LLC) is installed on the outside of the tank within the required level range of operation. The controller is normally supplied with a 20-psig air supply. Through proper linkage, the float (within the LLC) will transmit 3-5 psig output air signal to the liquid level control valve (LLCV) diaphragm, which will throttle the opening of the valve and thereby maintain the required liquid level, as shown below (Fig. 11-13). (c)

(1) Gravity settling tanks, (2) primary skimming tanks, (3) lagooning, (4) clari- fiers, ( 5 ) centrifuging, (6) filtration, (7) sedimentation tanks, and (8) chemical treatment tanks.

Sample problem I 1-2

It is required to design a chemical injection system for a water treatment plant.

Field data (1) 20,000 bbl/day of water to be treated through a dissolved air flotation cell. (2) Field testing indicates a requirement of 20 ppm of a 6% solution mix of a dry

(3) A second chemical requirement downstream of the flocculant clay injection, is clay flocculant, 1/2 lb/gal of water mix.

5 ppm of a liquid polymer.

Determine: (1) How many lb of dry clay per day will be required. (2) How many gallons per day of the liquid polymer will be required.

REFERENCES

Brady, J.D. and Legatski, L.K., 1978. Improved process for separating sulfur oxides from gas streams. U.S. Patent No. 3,989,797.

Brady, J.D., 1979. Emission control for oil fired steam generators. In: Struthers-Andersen Seminar on New Developments in Oilfeld Steam Generators. Rep. 79-900101. Bakersfield, Calif., Nov. 1979, 47 pp.

Nemerow, N.L., 1963. Theories and Practices of Industrial Waste Treatment. Addison-Wesley, Reading,

Reilly, P.B., 1972. Wastewater treatment for removal of suspended solids. Plant Eng., May 18: 88-91. 557 pp.

455

Robinson, J.M., 1977. Thermal DeNO, Demonstration Program. Steam Generator 42, KVB 21100-751.

Sachtschale, J.R., 1980. Experience with dual alkali scrubber systems in oilfield operations. In: Pacific

Vrablik, E.R., 1960. Fundamental principles of dissolved-air flotation of industrial wastes. In: Proc. 14th

KVB Engineering. Inc., Tustin, Calif.

Coast Joint Chapter Meeting, A P I , Bakersfield, California, Oct. 1980.

Purdue Ind. Waste Con$, May 1960, p. 743.


457

Chapter 12

UNDERGROUND STORAGE OF GAS AND OIL

A. ALI AZUN. GEORGE V. CHILINGARIAN and SANJAY KUMAR

INTRODUCTION

Over the past two decades, growth in the oil and gas industry has been tremendous. Moving from crisis to crisis, the industry has emerged as a vital and prestigious area of human endeavor. Every industry has some kind of inventory control. The equivalent of that in the oil and gas industry is the underground storage of oil and gas. The system, however, is vastly more complicated, because one is dealing with natural and not man-made systems.

As of today, underground storage of gas almost completely overshadows storage of any other fluid in the earth. The underground storage of gases is intended for meeting the requirements of peak consumption periods during the cold season and as an emergency supply (see Dreyer, 1972).

The possibilities of underground storage are diverse and close attention is being directed towards storage of materials that fall primarily into either one of the following categories:

(1) Materials which involve handling of very large volumes, e.g., gas, oil, and water.

( 2 ) Dangerous and hazardous materials, which include nuclear, toxic, and chemical wastes.

Storage serves as a buffer between production and demand and, thus, fulfills a very valuable role. To date, underground storage has proven to be the most economical storage system for gas all over the world. Danger of fire and/or explosion is at a minimum, and the system can handle virtually any volume. Infrastructural facilities required are minimal, inasmuch as existing piping systems in the field can be employed. Manpower requirements are also minimal.

In 1956, Chilingar showed a definite cost advantage of storing aviation fuels in salt caverns. He also showed that the effect of salt and impurities (1-5%) on properties of stored fuels is minimal (also see Chilingar, 1959).

The technology involved in storing liquids underground is quite similar to that involved in petroleum exploration and exploitation. Knowledge in the fields of geology, logging, reservoir engineering, and production engineering is required. A very brief description of the various types of underground storage systems is presented in this chapter.

458

STORAGE OF GAS IN DEPLETED GAS AND OIL FIELDS

In the earlier days, a nearly depleted gas field was routinely used for storing natural gas by allowing it to flow into a gas-bearing formation in summer so that gas would be available when needed in the winter (Katz and Coats, 1968). This was indeed a minute operation when compared with the present full repressurization of gas fields each summer and a withdrawal of 50-70% of gas during the winter. Essential data for the storage operation, i.e., pressure behavior, capacity, achievable withdrawal rates, etc., are known from the production history of the reservoirs. Only slight volumes of cushion gas are necessary for the first fill and, usually, the reservoir still contains sufficient quantities of gas depending on the degree of depletion. Depending on the relative permeabilities, the utilizable volumes of working gas constitute about 30-50% of the total gas (gas remaining after depletion plus that injected into the formation) (Lindemann and Carlson, 1981).

In 1968, Katz and Coats stated that the problems of converting depleted gas fields to gas storage begin with the mechanical refurbishing of wells and field lines to withstand the pressures over a long period of time. The operating pressure required for storage may be above that existing during gas production, because the flow rates required to meet peak loads and empty the storage field in the winter are much higher than those used in normal production practice. Generally, additional wells may be required for this purpose.

If new fields are discovered in an area where gas storage is possible, they might be developed with appropriate field gathering lines and well structures suited for contemplated pressure levels and flow rates for storage operations.

Some oil fields also can be used for gas storage. Many complications arise in this case, however, because the quantity of oil recovered depends upon operating methods and the unrecovered oil remains in depleted oil fields. Of utmost importance is the gravity of the crude oil in the reservoir, because this determines the amount of oil stripped by the gas under equilibrium conditions. A light-hydrocarbon recovery plant may be required to strip the gas from the storage reservoir of the propane and heavier constituents absorbed from the oil in the reservoir.

STORAGE IN AQUIFERS

Aquifers are porous formations, the pore space of which is filled with water. Thus, the water has to be driven away from the gas injection well as the pressure is increased. As pointed out by Katz and Coats (1968), the development of aquifers for underground storage includes locating of the underground structure. The quality of the caprock is determined first by examining and testing the cores. The plasticity of the rock is of utmost importance, because it determines the degree of fracturing. The next step is the testing of caprock by pumping water to determine whether a pressure differential across the caprock causes water movement through it or not. Upon locating the structure and after all signs point to an impermeable caprock,

459

STORAGE

Fig. 12-1. Pump testing of caprock. (After Katz and Coats, 1968, fig. 1-11, p. 18; courtesy of Ulrich Books, Inc., Ann Arbor, Michigan.)

pilot gas injections are made to initiate a gas bubble and further test the caprock (Fig. 12-1). Such gas injections employ pressures above the initial aquifer pressure in order to move the water. Two to four years are required to initiate the development of a gas storage reservoir and the complete project may eventually take ten years or more.

Aquifer storage fields operate like normal gas fields which have comparable degree of water drive. Sometimes, poor caprocks permit gas migration upward resulting in gas collection at shallower strata. Although it is possible to operate successfully even if gas leaks through the caprock of the aquifer storage reservoir, it is preferable to have no leaks. Lealung gas, which is collected in the upper strata, can be allowed to accumulate and be produced in the winter time.

STORAGE IN SALT CAVERNS

Salt caverns, which are used for the storage of gas, are prepared by means of solution mining of caverns in salt deposits (see Lindemann and Carlson, 1981).

Salt formations might be considered as almost ideal for the location of storage caverns, because they fulfill the requirements of being impermeable, stable, and economical better than other types of rocks (Dreyer, 1972, p. 390). The underground caverns in salt deposits have also proven to be adequately safe. Any damages due to suberosion or even due to the rise of salt may be fully excluded. The safety aspect of the caverns depends only on the methods used in production and on the characteristics of the surrounding rocks (Dreyer, 1972, p. 391).

As noted by Querio et al. (1981), salt domes are large underground salt formations created by geologic processes spanning millions of years. About 30 million years ago, the weight of the accumulated sediments had reached the point where downward pressure on the salt caused the less-dense salt to deform and flow upward toward the surface (Fig. 12-2). As the salt passed up through the overlying sediments, long, finger-like projections (called salt domes) developed. When a

460

End of Mid-Tertiary-30 Million Years Ago

EB SALT MESOZOIC 0 EARLY TERTIARY !3 GULF WATER

Fig. 12-2. Sediments deposited above salt beds formed in the Gulf of Mexico. (After Querio et al., 1981, fig. 2; courtesy of the Society of Petroleum Engineers of AIME.)

buoyant equilibrium was reached between the salt and the sediments, the salt eventually stopped moving upward (Fig. 12-3).

Salt domes have different shapes and sizes. They exist in cone-shape, mushroom- shape, spherical, spinose, table-topped, and vertical forms. The cores of salt domes in the U.S.A. are essentially circular in plan, usually ranging from to 2: miles in diameter.

According to Allen (1971, 1972), a solution-mined salt cavern for storing natural gas was first used in 1961 when the Southeastern Michigan Gas. Co. leased, from

Formation of Salt Dome-Present Time

Fig. 12-3. Upward movement of projections formed by salt domes. (After Querio et al., 1981, fig. 3 ; courtesy of the Society of Petroleum Engineers of AIME.)

461

the Morton Salt Co., and converted an abandoned salt cavern formed by routine brine production. After conversion, this cavern, near Marysville, Michigan, had a working capacity of about 341 MMcf of gas at a wellhead pressure of 1100 psia and a minimum line pressure of 150 psia.

Requirements for salt cavity storage

Detailed geologic and mineralogic information is particularly important in the case of salt deposits, because if useful potassium salt deposits are present, their exploitation may be made impossible by the creation of storage caverns (Dreyer, 1972, p. 391).

As stated by Bays (1963), the requirements for creating storage in a salt bed are: (1) satisfactory roof or caprock conditions, (2) sufficient depth, and (3) salt section of sufficient thickness and purity.

For leaching and brine utilization, the purity of the salt is the main concern. The presence of impurities might result in lack of pressure seals, due to the healing quality of sodium chloride crystals under overburden pressure.

In 1972, Allen studied the Eminence Salt Dome, Covington County, Mississippi. For this particular salt deposit, the following requirements were met:

(1) A seismic survey of the dome indicated sufficient salt section for the creation of caverns and for their future enlargement.

(2) Salt was relatively shallow, with the top of the dome only about 2400 f t below the surface.

(3) There was an adequate supply of fresh water for salt leaching (solutioning). (4) Brine-disposal wells could be completed in formations on the flank of the

( 5 ) Enough land was available for all the necessary surface facilities. (6) The dome was near the pipeline.

dome.

This is a good example of an analysis and evaluation of a proposed salt cavern, carried out before the actual design.

Creation of cavity and cavern design

In simple terms, creation of cavity involves pumping fresh water into the well for dissolving the salt. Placing the tubing strings in the right place to control the shape of the cavity is the most crucial operation during the creation of a cavity. Dissolu- tion of salt depends primarily on pump capacity.

Mathney (1951) and Kaufman (1960) have stated that it takes 6.0 bbl of water per 1 bbl of salt and recommend a round number of 6.3 bbl of water to generate 1 bbl of storage space. This ratio of 6.3 gives rise to a brine of 25.6% (wt) of salt using a density of 2.16 g/cm3 for solid salt and zero porosity. At 60 OF, saturated brine contains 24.6% NaC1, whereas at 122" F saturated brine contains 26.9% salt. Initial water injection at high rates results in unsaturated brine. During a field operation with a 500-ft layer, essentially saturated brine was obtained after the cavity reached

462

A

SUMP

BLANKET

Fig. 12-4. Three-dimensional simulation model. (After Querio et al., 1981, fig. 5; courtesy of the Society of Petroleum Engineers of AIME.)

1300 bbl in size, with water rates ranging from 3000 to 5000 bbl/D. According to Querio et al. (1981), cavern design for a solution-mining system

(leaching) is based on calculations using a three-dimensional model and considering non-homogeneous salt (Fig. 12-4). The major criteria governing the design of caverns made by the leaching process are cavern stability, system hydraulics, and salt leaching rate. Of primary concern is stability, which is evaluated by two ratios:

0VERB.U R DE N

Fig. 12-5. Nomenclature for judging cavern stability. (After Querio et al., 1981, fig. 6; courtesy of the Society of Petroleum Engineers of AIME.)

463

(1) The ratio of salt roof thckness ( S ) to cavern diameter (D)-the S / D ratio is a very important measure of stability (Fig. 12-5). Inasmuch as structural stability of most caverns is provided by salt, the thicker the salt cover over the cavern relative to its roof span, the more stable is the roof.

(2) The P / D ratio is the second measure used in evaluating cavern stability in the case of numerous caverns being located in the same salt mass. This ratio indicates the amount of salt remaining between caverns (i.e., the salt pillar, P ) relative to the cavern diameter ( D ) . Inasmuch as the overburden originally held up by the excavated salt must now be borne by the remaining pillar, the average pillar stress increases. With increasing size of pillars, the pillar stress is lower and there is a decreasing tendency of the pillars to yield. The hydraulic pressure in the cavern partly balances the overburden stress.

Design specifications of Eminence Salt Dome

The design specifications established for the Eminence Salt Dome caverns (two) in Covington County, Mississippi (see Fig. 12-6), were as follows (Allen, 1972):

Number of wells Cavern interval (ft) Maximum storage pressure (psia) Minimum storage pressure (psia) Minimum deliverability per well (MMscf/D) Production casing size (in.) Total gas storage volume (MMscf) Cushion gas volume (MMscf) Usable (top) gas volume (MMscf)

2 5700-6700 3950 1275 375

2920 920

2000

13-3/8

The formation temperature was 170°F and specific gravity of gas was equal to 0.587.

While the surface facilities were being designed and the equipment was being ordered, two fresh-water wells and one brine-disposal well were drilled and tested. The fresh-water wells were drilled approximately 600 ft into a massive fresh-water aquifer. They were equipped with seven-stage turbine pumps driven by 150-HP, vertical, hollow-shaft electric motors. Each well could produce 1000 gal/min of fresh water (Fig. 12-7).

Leach-fill procedure

According to Querio et al. (1981), the purpose of the leach-fill procedure is to provide maximum oil storage rates and yet maintain safeguards in controlling and monitoring the operation. First, one or more wells are drilled into the salt. Each well is equipped with concentric casings for the leaching process. An oil-brine interface is established at the planned roof elevation before leaching begins, to protect the

464

SOLUTION WELL D. 1

SOLLITION YELL NO. 2

FRESH WATER WELL D. 2

SEh LEVEL

/ ::L ::::: LLLLL

LLLLLLi LLLLLL, LLLLLLL

&LLLLL, -LLLLL, LLLLL

LLLLl LLLL

:::::::

:::' .-LLL

-1.000

-2.000

-3.000

-0.wo

-5.000

-6,OW

-7.000

-8.000

-9,000

-1o.oM)

-11 .Ooo

-12,000

-13.000

-14.000

Fig. 12-6. Profile of a salt dome. (After Allen, 1972, fig. 1, p. 1301; courtesy of the Society of Petroleum Engineers of AIME.)

cavern roof from being leached. The fresh water is pumped down the inside casing, whereas brine flows to the surface through the outermost casing (Fig. 12-8). The leach-fill procedure consists of five major stages, with cavern depressurization and sonar surveys following each stage. The actual leached configuration is carefully determined periodically and adjustments are made from time to time to develop the cavern, as closely as possible, to the computerized design. The oil-brine interface depth is measured regularly to check the cavern design, during its development.

Querio et al. (1981) described the steps during a leach-fill process as follows: (1) The first major step is sump development (Fig. 12-9). A total volume of 1

million bbl is typically required to hold the estimated 5% insoluble residue (salt impurities) that will settle to the bottom during cavern enlargement. This space must be created in advance and, once filled, cannot be counted as oil storage space. As mentioned previously, to protect the cavern roof from leaching, an oil-brine interface is established.

465

Fig. 12-7. Operating cycle of Eminence Dome storage caverns. (After Allen, 1972, fig. 2, p. 1301; courtesy of the Society of Petroleum Engineers of AIME.)

RAW WATER-

BRINE -

BLANKET?' . . . . . _ . .

52 y

CAVERN SUMP

Fig. 12-8. Schematic diagram of direct leaching. (After Queno et al., 1981, fig. 7; courtesy of the Society of Petroleum Engineers of AIME.)

466

2700 T T

3000c I I I I

35001 4000

I

i I I

Fig. 12-9. Sump development in a cavern. (After Querio et al., 1981, fig. 8; courtesy of the Society of Petroleum Engineers of AIME.)

(2) Upon completion of the sump stage, leaching is stopped and the cavern is depressurized. The first one of the six cavern sonar surveys is then made.

(3) The third step is chimney leaching. The leaching strings are repositioned and the oil-brine interface is reset at the cavern roof. Chimney is created by using direct leaching. After depressurizing the cavern, the second sonar survey is made.

(4) Roof development follows chimney leaching. Leaching strings are repositioned, and the oil-brine interface is again established at the cavern roof. Direct leaching is continued. As the fresh water dissolves the salt, a brine-filled cavern begins to form in the salt dome. Oil injection and roof development proceed in increments to give optimum control over the roof's shape. After each incremental volume is created, oil is injected to lower the oil-brine contact level.

( 5 ) Indirect leaching is begun after the roof development (Fig. 12-10). Leachmg strings are repositioned. During indirect leaching, the fresh water is pumped down

461

BRINE

ZIP

BLANKET

Schematic For Indirect Leaching

CAVERNSUMP

Fig. 12-10. Schematic of indirect leaching. (After Querio et al., 1981, fig. 9; courtesy of the Society of Petroleum Engineers of AIME.)

2700

3000

3500

4000

4500

5000

5200

Fig. 12-11. An oil-filled cavern. (After Querio et al., 1981, fig. 10; courtesy of the Society of Petroleum Engineers of AIME.)

468

the outermost casing and the displaced brine reaches the surface up through the innermost casing. Simultaneously, oil is injected to fill the upper portion of the cavern. Oil-brine interface is regularly monitored after oil injection. Cavern growth is controlled by (a) varying the depth of water injection and brine withdrawal in the two casings, and (b) changing the rate or method of water injection.

(6) Suspended casing is used to inject the displacement water into the bottom of the cavern, after the cavern is leached. As a result, the diameter at the bottom increases more rapidly during cycling than at the top (Fig. 12-11).

Measurement of cavities

Myers (1963) and other investigators have concluded that caliper measurements can be made of the cavity shape during the initial solution operations. Sonar measurements can map the extent of the solution, when the size is greater (Fig. 12-12).

As pointed out by Katz and Coats (1968), the shape and diameter of salt caverns are of great importance to underground storage operators. Equilibrium pressure data have been used to calculate average cavern diameter in several anchor wells. This is accomplished by suspending injection operations at given intervals and carefully bleeding the tubing pressure to zero. The depth to the LP-gas-brine contact, h , in feet can be determined from the following equation (Katz and Coats, 1968; see Fig. 12-13):

P 0.434( G, - Gg)

h = (12-1)

Fig. 12-12. Schematic diagram of sonar caliper survey. (After Myers, 1963; courtesy of Northern Ohio Geological Society.)

469

Fig. 12-13. Diagram for equilibrium pressure calibration. (After Branyan, 1966, p. 147; courtesy of World Oil.)

where p = casing pressure, psi, G , = specific gravity of brine, and Gg = specific gravity of LP-gas. Or, for the incremental part of the cavern:

AP A h = 0.434( G b - G,)

(12-2)

Then, the average cavern radius, r (in ft), for that part of the cavern can be calculated for any interval by using the following equation (Katz and Coats, 1968, p. 386):

r = 0.206,/- (12-3)

where A h = vertical height filled during interval, ft, and A Q = gallons of LP-gas injected during interval.

Advantages of storing natural gas in salt domes

Lindemann and Carlson (1981) described some advantages of storing natural gas

(1) In the case of increasing requirement, the capacity of a cavern storage can be in salt domes:

gradually increased (extension).

470

(2) The individual volume of the caverns and, thus, the working gas volume of the entire storage can be specified and fixed in the design.

(3) The working pressure range and the working volume of gas are dependent on the depth of the salt reservoir; however, they can be adapted to the requirements within a wide range, particularly in the case of salt domes.

(4) Injection and withdrawal rates are design parameters and are solely dependent on the aboveground installations (compressor and dehydration units), and not on the relative permeabilities and friction pressure losses in the porous matrix.

MINED CAVERNS

Mined caverns are usually used to store propane and butane in the absence of underlying salt layers in an area. As noted by Katz and Coats (1968), underground mining operations for coal, salt, limestone, etc. are common (Fig. 12-14). The steps involved in developing a mined cavern can be summarized as follows:

(1) Obtaining geological and mineralogical information by coring the zone being considered for use.

(2) Conducting the mining operation. (3) Equipping the mine for storage purposes. Bedrock or pre-glacial layers must be present in the case of mined caverns. Depth

should be as shallow as possible because of cost considerations. The structural strength to avoid subsidence and the hydraulic pressures at depths, however, must

T U R A L G R O U N D

STATIC WATER T A B L E

300 F E E T

ROCK F O R M A T I O N IMPERVIOUS M A S S I V E STRUCTURALLY SOUND INERT

I Fig. 12-14. Illustration of mined cavern storage. (After Scisson, 1960; courtesy of NGPA.)

471

Fig. 12-15. Mining cavities as gas storage. (After Dreyer, 1972, fig. 121, p. 386; courtesy of Trans Tech Publ.)

exceed the storage pressure. The suitable rocks for mined cavities are unfractured shale, dense limestone, dense dolomite, and granite. The mining operation consists of drilling the mine shaft followed by the removal of rock in a pillar and room-type of operation. The absence or presence of water in such mines is of utmost importance, because it indicates the degree of communication between the mine

COMPRESSOR STATION,

DEHYDRATION SYSTEM 6 MEASUREMENT,

scRuaaERs ETC.

I

- _ - - - - - PRIMARY GAS INJECTION R WITHDRAWAL WELL - - - - - - - - - - - - - - -

Fig. 12-16. Gas storage in a reservoir created by a nuclear explosion. (After Anon., 1967; courtesy of Project Ketch PNE 1200 participants.)

412

cavity and the surrounding water-saturated rocks. Generally, cavities in salt-bearing rocks are preferred (Fig. 12-15).

STORAGE IN CAVITIES PRODUCED BY NUCLEAR EXPLOSIONS

In certain types of rocks, which are unsuitable for storage, the cracks created by a nuclear explosion may propagate far into the virgin rock. According to Dreyer (1972), in granite rocks the fissuring in horizontal direction will reach twice the radius of the spherical cavity, three times the radius in the roof area, and about half of the radius around the bottom. The extent and the effects of underground nuclear explosions may thus be predicted (Dreyer, 1972, p. 389): (1) The diameter and the height of the loosened area, (2) the quantity of rock melted by the explosion, and (3) the extent of shocks both above and underground (Fig. 12-16). The application of nuclear explosives in mining enables creation of large caverns and permits the exploitation of low-quality ores, which could not be developed by conventional mining methods, because of prohibitive costs. Underground explosions become more economical as the size of a project increases. At the present time, the application of nuclear explosives is limited to very large deposits with several million tons of ore. Sometimes, in the case of irregularly-shaped deposits, it is advantageous to loosen up the deposit with a single explosion. Caverns created as a result of the removal of the ore may be used for storage purposes. In order to permit exploitation of all the deposits, several nuclear explosions may be necessary (Dreyer, 1972, p. 390).

SAMPLE QUESTIONS

(1) What are the different types of underground storage methods available?

(2) Describe the important parameters that have to be evaluated before imple-

(3) How is the cavern size controlled in a solution-mining process? (4) For modelling a solution-mined cavity design, what reservoir, salt, and

Discuss their applicability.

menting an underground storage project.

injection water properties must be established?

REFERENCES

Allen, K., 1971. Eminence Dome-Natural-Gas Storage in Salt Comes ofAge. 46th Annu. Fall Meet., SOC. Pet. Eng. AIME, New Orleans, SPE 3569, Oct. 3-6. (Also, 1972, J. Pet. Tech., 24(11): 1299-1301.)

Anon., 1967. Project Ketch PNE 1200 of Columbia Gas System Service Corp., AEC, San Francisco. UNv. of Calif., Livermore, and U.S. Bureau of Mines.

Bays, A.C., 1963. Use of Salt Solution Cavities for Underground Storage. In: Symp. Salt, North. Ohio Geol. SOC., Cleveland, Ohio.

473

Branyan, S.G., 1966. How anchor recovers 97% of LPG stored underground. World Oil (Prod. Sect.),

Chilingarian, G.V., 1956. Geological aspects of storing aviation fuels in salt domes and salt beds. Pet.

Chilingarian, G.V., 1959. Effect of seawater on properties of liquid hydrocarbons. Am. Assoc. Pet. Geol.

Dreyer, W., 1972. The Science of Rock Mechanics. Trans Tech, Clausthal-Zellerfeld, 501 pp. Katz, D.L. and Coats, K.H., 1968. Underground Storage of Fluids. Ulrich’s, Ann Arbor, Michigan, 575

Kaufman, D.W., 1960. Sodium Chloride (Am. Chem. SOC. Monogr. Ser., 145). Reinhold, New York, N.Y. Lindemann, W.B.N. and Carlson, U., 1981. The Underground Natural Gas Storage in the F.R. Germany as

a Result of the Increasing Energy Demand. In: 56th Annu. Fall Meet., SOC. Pet. Eng. AIME, San Antonio, Tex., SPE 10168.

142(2): 147.

News L. USAF Pub]., February: 3, 7, 8.

Bull., 43(2): 2860-2861.

PP.

Matheny, F., 1951. Underground Storage of Liquefied Petroleum Gases. Proc. NGPA. Myers, A.J., 1963. Sonar Measurements of Brine Cavity Shapes. In: Symp. Salt, North. Ohio Geol. SOC.,

Cleveland, Ohio, p. 346. Querio, C.W., Steiner, M.E. and Durnell, W.E., 1981. Expansion of Solution Cavern Storage Technology.

In: 56th Annu. Fall Meet., Oct. 5-7, SOC. Pet. Eng. AIME, San Antonio, Tex., SPE 10167, 6 pp. Scisson, S.E., 1960. Planning for Mined Underground Storage. In: Proc. 39th Annu. Conv. NGAA. Proc.

NGPA, p. 36.


475

Appendix A

TECHNOLOGY OF TESTING PETROLEUM PRODUCTS AND SAMPLE EXPERIMENTS

GEORGE V. CHILINGARIAN, JOHN 0. ROBERTSON Jr. and C.M. BEESON

SOME THEORETICAL CONSIDERATIONS OF DISTILLATION

Distillation is used as a general research tool and as a control and specification test for petroleum products. Consequently, the basic principles and theory behind distillation are of considerable importance. The distillation test for crude petroleum products is indicative of the approximate yield and quality of some finished products which may be obtained from the crude oil.

In a distillation test, the liquid under test is vaporized and a set of figures recorded which indicate the relationshp between temperature in the distilling vessel and quantities of liquefied distillate. The distillation test is applicable to products which are vaporized in the course of their use; however, it also serves for identification and classification of other products.

Petroleum products are complex mixtures of hydrocarbons containing large numbers of individual compounds. When these mixtures are boiled, the vapor given off at any instant is only slightly less complex than the liquid and is usually subjected to some sort of treatment, which simplifies its composition, before it passes into the condenser. This treatment (referred to as fractionation, rectifica- tion, dephlegmation, etc.) involves decreasing the proportion of the less volatile constituents in the vapor. Fractionation may be achieved (1) by partial condensation, which liquefies more of the high-boiling than of the low-boiling hydrocarbons, (2) by allowing the vapor to come in contact with a countercurrent of distillate maintained at its boiling point, or (3) by a combination of the foregoing two processes.

A large proportion of the more common laboratory distillation methods involves a certain degree of fractionation, which is in general incidental and is due to the cooling of the vapors in the necks of the distilling flasks. This fractionation is achieved chiefly by partial condensation; however, there is also a certain amount of contact between the reflux current of the condensed distillate and the rising current of vapor. This general method of distillation does not furnish exact information concerning the true boiling points of the constituents comprising a petroleum product. If properly standardized as to details of apparatus and procedure, however, it can be made to yield results that are closely reproducible. These methods have the added advantage of simplicity and convenience, and though subject to theoretical objections, are the most important types used by the petroleum industry. For products encountered in the petroleum industry, the A.S.T.M. Standard Method of Test for Distillation of Gasoline, Faphtha, Kerosine, and Similar Petroleum Products (D 86) is almost universally used in the United States. This method involves a moderate degree of fractionation because of the condensation and reflux in the neck of the flask.

The operation of the distillation depends upon the fact that materials differ in their vapor pressure at a given pressure. Consequently, when a solution or a mixture of two or more volatile substances is boiled, the vapor coming off first has a greater proportion of the substance of high vapor pressure than the proportion of the same component in the original solution. The distillate (material whch has been vaporized and condensed) is richer in the more volatile component, whereas the residue (liquid left in the flask) is poorer in that same component. As distillation proceeds, the composition of the residue becomes progressively lower in the more volatile material and, therefore, richer in the higher boiling point components.

476

Solution type equilibrium diagrams

The basic data of any distillation problem are the equilibria between the liquid and vapor phases of the system to be subjected to distillation. The examples presented in this section are only for two-component systems. If the original charge in the flask has only two components, it is called a “binary” mixture; if there are three components, a “ternary” mixture; and if more than three components, a “multicomponent” system. A boiling-point diagram may be obtained experimentally for a binary system.

Figure A-1 represents the boiling point and equilibrium composition relationships, at constant pressure, of all mixtures of benzene (B.P. = 80 ” C) and toluene (B.P. = 110 C). Benzene is the more volatile fluid. In such a diagram, temperatures are plotted as ordinates and the compositions as abscissas. The resulting diagram consists of two curves, the ends of which coincide. Any point (such as point y ) on the upper curve has for its abscissa the composition of vapor that will just begin to condense (called the dew point) at the temperature given by its ordinate and will give a liquid of composition ( d ) . For example, a mixture containing 65 mole % benzene will have a dew point of 94O C and the composition of the first drop of liquid will be 43 mole B benzene and 57 mole % toluene. If a liquid of composition ( d ) is taken and heated to 94°C (point x on the lower curve), the liquid would have the composition ( e ) . Two points (such as x and y ) on the same horizontal line represent compositions of liquid and vapor in equilibrium with each other at the temperature given by the horizontal line through them. For all points above the top curve, such as point ( a ) , the mixture is entirely vapor, whereas for all points below the bottom curve, such as point ( b ) , the mixture is completely liquid. For any point between the two curves, such as point (c ) , the system consists partly of liquid and partly of vapor. The relative proportions of these two phases for any point such as point ( c ) can be calculated by means of the “lever principle”. For example, the relative proportion of vapor (of composition e ) will be gwen by the ratio of the length cx to the total length xy. The relative amount of liquid (of composition d ) , on the other hand, will be given by the ratio of cy to xy (at temperature of point c).

Sampie problem A - l (Refer to Fig. A-1)

each component in the vapor and liquid phases? Given a mixture of 30 moles of benzene and 70 moles of toluene at 100 ” C. What is the amount of

MOLE PER CENT TOLUENE 100 80 60 40 20 0 -

85 -

0 20 40 60 80 100

MOLE PER CENT BENZENE

Fig. A-1. Vapor-liquid equilibrium diagram for mixtures of benzene and toluene at a pressure of one atmosphere.

477

MOLE PER CENT BENZENE

Fig. A-2. Vapor-liquid equilibrium diagram for mixtures of benzene and ethanol at a pressure of one atmosphere.

Solution : The amount of vapor is equal to:

[ (30 - 26)/(45 - 26)] x 100 = 21 moles

and its composition will be 45% benzene and 55% toluene. The amount of liquid will be 100-21 = 79 moles, and its composition will be 26% benzene and 74% toluene. The actual amount of the components in each phase will be: (1) Benzene in liquid = 79 moles X 0.26 (2) Toluene in liquid = 79 moles X 0.74 (3) Benzene in vapor = 21 moles X 0.45 (4) Toluene in vapor = 21 moles X 0.55

= 20.6 moles. = 58.4 moles. = 9.4 moles. = 11.6 moles.

100.0 moles

In less ideal solutions, the boiling point curves become less symmetrical. In some cases, the departure from ideal behavior is so great that the curves exhibit actual minima as shown in Fig. A-2 and maxima as shown in Fig. A-3. These types of solutions are often referred to as “constant-boiling mixtures” or “azeotropic solutions”. The mixture of hydrochloric acid and water has been studied extensively, and inasmuch as the composition of the constant-boiling mixture is easily reproducible, it is used as a standard in quantitative analysis. If any solution of the hydrochloric acid is boiled for a sufficient time under a pressure of one atmosphere, the temperature will gradually rise to 108.6OC and remain

Lz

W

MOLE PER CENT CHLOROFORM

Fig. A-3. Vapor-liquid equilibrium diagram for mixtures of acetone and chloroform at a pressure of one atmosphere.

478

stationary. The mixture boiling at this constant temperature will contain 22.2% hydrochloric acid by weight. The maximum in the boiling point curve of hydrochloric acid-water solution is due to the ionization of hydrochloric acid.

Raoult's and DaltonS laws

For special cases it is possible to compute the boiling-point diagram, over certain ranges of temperature, from the vapor pressure data of the pure components. These calculations are based upon Raoult's law, which applies to a few mixtures of all possible concentrations. Raoult's law states that at any particular constant temperature, the partial pressure of any one component of a mixture is equal to the mole fraction of that component multiplied by its vapor pressure in the pure state at the temperature of the liquid:

P I = P O X (A-1)

where pl = partial pressure of a component in the liquid phase, P o = vapor pressure of the component in the pure state, and x = mole fraction of the component in the liquid phase.

If a mixture is below its bubble-point temperature, the total pressure, T, is equal to:

n = p i i p ; i p : + ... i p; (A-2)

Sample problem A-2 A vessel is to be designed to hold a mixture of 200 lb of butane, 500 Ib of pentane, and 300 lb of

hexane at 150 O F . (1) What is the maximum design pressure to be used for the vessel? (2) What is the vapor pressure of the above mixture at 150 F?

Solution : Moles butane = (200/58) = 3.45; mole fractbm = (3.45/13.96) = 0.247. Moles pentane = (500/72) = 6.94; mole fracion = (6.94/13.96) = 0.497. Moles hexane = (300,434) = 3.57; mole fraction = (3.57/13.96) = 0.256. Total moles = 3.45 + 6 .94 i 3.57 = 13.96 moles.

P o may be obtained from a vapor pressure chart for hydrocarbons:

Component X Po at 150 F, psi P O X , psi

0.247 110 0.497 40 0.256 15 1.000

~

27.2 19.9 3.9

X P O X = 51.0

The vessel, therefore, must be designed for a minimum pressure of 51.0 psia. Dalton's law states that the partial pressure of an individual component in a gaseous mixture is equal

to the product of the total pressure and the mole fraction of that individual component, which can be expressed as follows:

p" = ny ('4-3)

where p"== partial pressure of a component in the vapor phase, T = total pressure of the system, and y = mole fraction of the component in the vapor phase. Raoult's law and Dalton's law can be combined, because at equilibrium the partial pressure of a component in the vapor is equal to the partial vapor pressure of the component in the liquid:

(A-4) p" =

479

Consequently,

y = ( P O X ) / ? r (‘4-5 )

This equation expresses the equilibrium between the vapor and the liquid of an ideal solution at any temperature and pressure. By means of this equation, the dew point and the bubble point of any ideal solution can be calculated. From data obtained, a boiling point diagram may then be constructed.

Fractionation

On vaporizing a mixture of two liquids, that component which has the higher vapor pressure tends to concentrate in the vapor, thus producing a difference in composition between the liquid and the vapor phases which are in equilibrium. The vapor may then be condensed. Vapor coming from this condensate is still enriched in the more volatile component. This successive vaporization and condensation is called fractional distillation.

Figure A-1 shows the composition of the vapor gwen off at 98.5 O C, when boiling a mixture of benzene and toluene at atmospheric pressure. From a charge containing 30% benzene and 70% toluene, the vapor will contain 51% benzene and 49% toluene. If this vapor were condensed and then brought up to boiling at 92”C, a new vapor would be evolved having a composition of 72% benzene and 28% toluene. Furthermore the new residue would contain proportionately less benzene than when first condensed. By repeated condensations and re-evaporations, which is called redistillation, a final product of substantially pure benzene could be obtained.

A similar result can be obtained by condensing a very small amount of the vapor by slight cooling, drawing off this condensate, and cooling the vapor a little more. This condenses another small amount of liquid containing a relatively large amount of toluene. If given sufficient time, this liquid must be in equilibrium with the vapor at the existing temperature. This is the method of partial condensation.

If the vapors from an initial mixture of 30% benzene and 70% toluene, boiling at 98.5 C, are allowed to bubble into a liquid of the same composition as the vapor (i.e., 51% benzene and 49% toluene), which has been heated just to its boiling point (92OC), the vapor will condense, giving up latent heat and thereby boiling off a new vapor containing 72% benzene and 28% toluene. At the same time, the liquid residue from this second still, now reduced in benzene content by the removal of vapor containing 72% benzene, could be allowed to flow into the first still. It would, therefore, be reduced again in benzene content. Simultaneously, vapor containing 72% benzene from the second still could be allowed to bubble into a third still containing 72% benzene at its boiling point (86.5 C). This results in evolution of vapor containing 86% benzene and return of liquid containing 72% benzene to the second still. Thus, supplying heat to the first still only, the vapor from each still in the series is progressively richer in benzene and poorer in toluene, until substantially pure benzene passes from the last still into a condenser. Providing there has been no radiation loss from the stills, the amount of heat obtained by condensing this benzene will be exactly equal to that introduced in the coils of the first still. To maintain the exact conditions given, it is necessary to return all of the condensed benzene to the last still, so that the proper amount of liquid could flow back to the preceding still and so on down the line. This operation is called “fractional distillation”, which combines the methods of redistillation and that of partial condensation. Figure A-4 shows this operation diagrammatically.

The following factors are found to be essential for the theoretical case given above: (a) The vapors rising from each still must be in equilibrium with the liquid in the still, following the

temperature and composition conditions given on the boiling-point diagram. (b) The liquid flowing back into each lower still must equal in amount and composition the vapors

coming into the upper still from which that liquid is flowing. (c) There must be no addition or loss of heat in the system except the introduction of heat in the

steam coils of the first still and the removal of exactly the same amount of heat in the final condenser. Practical application of this method of vapor enrichment involves some modification of theory.

Actually, the purpose of such an operation is to take out as much pure benzene as possible. All the condensate, therefore, cannot be returned to the last still. By taking off a portion of the benzene

480

VAPOR - COOLING WATER

V A P O R t I R E F L U X

STEAM T T R A P & +

CONDENSATE

Fig. A-4. Schematic diagram of a fractionating tower.

(product) and returning another portion (reflux), however, it is possible to make use of the process to obtain the desired separation. The proportion of the vapor (leaving the last still in the series), which must be returned to keep the system functioning properly, is called the reflux ratio. It may be reported as the percent of the total vapor returned-"80% reflux" means that 80% of vapor entering the final condenser is returned as reflux and 20% is taken off as product.

Instead of a series of stills, the process may be carried out by having a series of chambers or plates, one above the other, all erected above the original still pot. The vapor from the pot bubbles through the liquid on the first plate, the resulting vapor from that plate bubbles through the liquid on the second plate and so on, until the final vapor from the top of the column passes to a condenser. At the same time, reflux from the condenser is flowing into the top plate. After the partial condensation and reboiling of the reflux on the top plate, reflux flows down to successively lower plates, and finally to the still pot. The bubble-tower shown in Fig. A-5 is essentially the same as the series of stills except that the liquid from each plate is allowed to flow continuously to the still or plate beneath.

Fig. A-5. Schematic diagram of details of trays in a fractionating tower.

481

Inasmuch as complete equilibrium is not established on any actual plate and because part of the product is continually withdrawn, the number of actual plates in a column is always greater than that required for the theoretical conditions. The ratio of the fractionation actually accomplished by a plate to that calculated for a “theoretical” plate is called the plate efficiency. It is generally equal to about 50-60%. It can be shown mathematically that the number of theoretical plates required for a given separation increases as the reflux ratio decreases. There is, however, a minimum reflux ratio for any separation, below which even an infinite number of plates will not give a desired product.

Distillation of gasoline

The distillation curve of gasoline as shown in Fig. A-6, is somewhat indicative of the performance

The general requirements for volatility of a motor gasoline are as follows: (a) The gasoline should contain enough readily volatile constituents to permit starting an engine

under reasonably unfavorable conditions without preheating. It should also be possible to operate the engine with a reasonable degree of flexibility during the period while it is warming up to the optimum operating temperature.

(b) The gasoline should not contain too large a percentage of highly volatile constituents, because it might cause excessive evaporation losses and premature vaporization in carburators or fuel lines, with attending vapor lock. It should be remembered, however, that the vapor lock may also be due to the improper location of the fuel lines.

The gasoline should not contain any considerable percentage of relatively heavy, slightly volatile constituents which would not usually vaporize completely enough (after atomization into the manifold) to permit even distribution to the various cylinders of the engine. These heavy ends are also undesirable because they tend to dissolve in the oil on the cylinder walls and increase dilution of the oil in the crankcase. The design and method of operation of the car also have important effects upon the amount of dilution.

The distillation curve of gasoline is somewhat indicative of its performance characteristics in the car. This method does not give true boiling points of the individual components in any given gasoline, but does give a reliable indication of whether the volatility is within the required limits which have been determined by experience through operation of full-scale engines.

In the case of aviation fuels, it is usually required that when the thermometer in the flask reads 167 OF, not less than 10% nor more than 40% of the volume in the flask should have been boiled off. It is also required that at 221O F not less than 50% and at 275 OF not less than 90% shall have boiled off. The end point (FBP) should not exceed 3 3 8 O F. In addition, the residue left at the bottom of the flask after it has boiled dry must not be more than 1.5%.

The temperature at which 10% of the gasoline is boiled off enables a reasonable prediction of the lowest atmospheric temperature at which the engine will start. The sum of 10% and 50% points is also indicative of vapor locking tendency.

characteristics of gasoline in an automobile.

I E N P PT.

KNDICATIVE OF SPEED I

V o DISTILLED-

Fig. A-6. Significance of various portions of a distillation curve of gasoline

482

The gasoline should not contain any considerable percentage of relatively heavy, only slightly volatile constituents, which will not vaporize completely enough to permit even distribution to the various cylinders of an engine. For an excellent treatment of distillation, the reader is referred to the classical work of Nelson (1949).

Key points

test procedures should be strictly complied with: In order to obtain reproducible results for the distillation experiments (see ASTM D86) the following

(1) Proper position of the thermometer in the flask. (2) The proper size of the hole in the asbestos board, depending on the type of fuel tested. (3) The proper rate of distillation. (4) The temperature of the condenser bath. (5) There must be a tight contact between the flask and the opening of the asbestos board. The corks

must also be tightly fitted.

Questions (1) What corrections are to be applied to the temperature data obtained? To the liquid volume data? (2) State the significance of the 167O, 221°, 275O, and 33S°F distillation control points for

reciprocating fuels. (3) Under what conditions is a high distillation thermometer used? Under what conditions is a low

distillation thermometer used? State the controls governing the sue of asbestos board opening to be used. (4) Indicate the maximum and/or minimum time or temperature controls applicable to the following

distribution features of reciprocating fuels: (a) allowable time for distilling off the last 5 ml, (b) first drop over, (c) condenser box temperature rate, (d) distillation rate, (e) sample temperature, and (f) receiving graduate temperature.

LAYER TYPE AND EUTECTIC TYPE EQUILIBRIUM DIAGRAMS

Three common types of equilibrium diagrams, very often encountered in engineering work, are the (1)

The solution type equilibrium diagram has already been discussed and is typified by Fig. A-1. The layer type diagram is the simplest equilibrium diagram and applies to two mutually insoluble

compounds which form neither chemical compounds nor solutions. A typical example of this type curve is shown in Fig. A-7.a. Figure A-7.b represents a plot of the temperature versus time for the cooling of a solution of constant composition from the liquid state to the solid state. The flat portions of the cooling curve are caused by a large percentage of latent heat of fusion being given up at constant temperature.

The third type of equilibrium diagram, i.e., the simple eutectic type diagram as shown in Fig. A-8.a, is obtained when two materials form a eutectic. The latter is a mechanical mixture of two materials having the lowest freezing point of any combination of these materials. In order to construct a diagram covering

solution type, (2) layer type, and (3) simple eutectic type.

L I P Pb + SOLID AI

a 5 SOLID Pb +SOLID AI

Y

+ T I M E 0 I00

O% Pb COMPOSITION

Fig. A-7. Liquid-solid equilibrium diagram and cooling curves for mixtures of lead and aluminum at a pressure of one atmosphere.

483

LL

W u 3 + a LL w 32 a I

-7.65

50% 23.5% PURE

W LL

a n W a 5 W

T I M E

50% 23.5% PURE

T I M E

Fig. A-8. Liquid-solid diagram and cooling curves for mixtures of sodium chloride pressure of one atmosphere.

and water at a

a wide range of different compositions of the two components, it is necessary to know the behavior of many individual mixtures of various compositions. In this respect, cooling curves may be used as a method of thermal analysis to construct a phase diagram. A mixture of known composition is weighted and then heated until it is completely liquefied. It is then allowed to cool, and the temperature is recorded at frequent intervals, as read on the thermometer or by means of a thermocouple. First a smooth cooling curve is plotted from this data. The heat equivalent to the heat of fusion is evolved whenever a solid phase separates. Then, the rate of cooling, which coresponds to the slope of the line, becomes less. The temperature at which an inflection point or plateau occurs may be used in plotting the phase diagram.

TESTS ON FUELS

Gravity (Hydrometer) (ASTM D 287-82; D 1298-80)

Gravity (hydrometer) method describes a procedure for determining specific gravity and the API gravity by means of a glass hydrometer. The specific gravity of an oil is the ratio of the weights of equal volumes of oil and water, both weights determined at a temperature of 60 OF (15.56 O C). Both weights are also corrected for the buoyant effect of air.

The API gravity is defined \y the following equation:

Degrees API= [141.5/(sp. gr. at 6Oo/6O0)]-131.5

The figure 141.5 is termed the modulus of the API scale. The test for gravity of petroleum and petroleum products by means of the hydrometer involves the

basic principle that when an object floats in a liquid it displaces a volume of liquid equal in weight to the floating mass. Thus, the hydrometer is an instrument whch measures the volume of a liquid which corresponds to its weight, and is essentially a measuring graduate with the liquid on the outside rather than in the inside. Usually, the hydrometers are calibrated with a correction for the buoyant effect of air.

Key points (a) Make sure the cylinder containing the sample is standing on a flat surface. (b) In the case of fluids of low viscosity, a slight spin of the hydrometer will assist in bringing the

(c) Allow sufficient time for the air bubbles in the fluid to be measured to come to the surface. hydrometer to rest, floating freely away from the walls of the cylinder.

484

The weight and volume relationships of two-component system

and b , having specific weights ya and yb, respectively: Assuming additive volumes and weights, the following relationships will hold true for components a

(1) W t , + wt, = W t , b

( 2 ) vol, + u o l , = U 0 l u b

(3) ( w t o / Y a ) + ( W t b / Y b ) = ( W t a b / Y a b ) (4) [( wta / yo) ( 5 ) [( wt8 a 1/70 1 + [( wtS& b ) / Y b 1 = loo/ Y a b

( l O O / w t a b ) l + [( w'b/ y b ) (loo/ w'ob)l = [( W t a b / Y a b ) ( l O O / w f a b ) l

(6) wt%a=100- wt%b (7) [(loo- w t % b ) / y , l -t w t % b / Y b l = l o o / Y u b (8) w r 8 b = [ ( lOO)yb(y , -Yab) l / [Yub(Ya - y b ) l (9) volBa = [ loo(yab - Y b ) l / ( Y a - y b )

Questions

available. How would you proceed? (1) You are interested in the API gravities of various products, for which correction tables are not

(2) What is the API gravity of water? Can a negative API gravity exist?

Vapor pressure (Reid) (ASTM D 323-82)

The Reid vapor pressure test indicates the initial tendency of fuel towards vaporization. Vapor pressure increases with temperature, and the boiling point is reached when the vapor pressure is equal to the atmospheric pressure. There is a definite correlation between the vapor pressure, vapor-locking, and ease of engine starting. The gasoline with a high vapor pressure is very volatile, which increases the tendency to vapor lock.

The vapor pressure of a mixture of substances is not only a function of temperature but is also dependent on the composition of the mixture. Each component of a mixture contributes to the total vapor pressure in proportion to its mole fraction and to its vapor pressure in a pure state at the temperature of measurement:

p ' = P O X

where p'=partial pressure of a component in the liquid phase, P o = vapor pressure of the pure component, and x = mole fraction of the component in the liquid phase.

Inasmuch as the composition of the liquid phase is changing through vaporization, the vapor pressure of the mixture will vary with the volume of vapor space.

In the Reid method, the vapor pressure is determined in the presence of a volume of air four times the volume of gasoline. This standardizes the extent of evaporation, minimizes the effect of dissolved gases, and permits direct observation of the vapor pressure in terms of absolute units (e.g., in pounds per square inch).

Although the Reid method does not measure the true vapor pressure of gasolines, it is sufficiently accurate for commercial and transportation purposes. The true vapor pressure is about 5% higher than the Reid vapor pressure for gasolines.

Key points (I) The Bourdon gages must be carefully checked. (2) The whole assembly should be thoroughly purged. ( 3 ) The bath temperature should be maintained at 100k0.2°F. (4) Shaking of the unit during the test must be vigorous.

Sample problem A-3

to a gasoline with Reid pressure of 2 psi? What is the Reid vapor pressure of 308 by volume addition of gasoline with a vapor pressure of 4 psi

485

Solution (approximate): Reid vapor pressure of a mixture = (30% X 4) + (70% X 2) = 1.2 + 1.4 = 2.6 psi.

Sample problem A-4 The following table concerns a mixture of two hydrocarbons. Both the given value (those values in

table marked with an asterisk) and computed values have been included. It has been assumed that Raoult’s law holds.

Solution ;

Component CaH,a C5H12

Vapor pressure of pure constituent (mm Hg) Density (g/ml) Volume of mixture (gal) Weight in mixture (g) (g = galx 3758 g/cc) Molecular weight Moles Mole fraction Partial pressure of each component (mm Hg)

Total vapor pressure in psi = (831 X 14.7)/760 = 16.1

* 28.8 * 0.682 * 1.5 3870 * 114.2 33.8 0.237 6.82

* 1080 * 0.594 * 3.5 7850 * 72.15 109.0 0.763 824

Conversion factors: 1 gal = 3785 nd; 1 atmosphere = 14.7 psi = 760 mm Hg at 32O F

Questions

tics of an engine. (1) Discuss the Reid vapor pressure of gasoline with regard to its effect on the operating characteris-

(2) Can the Reid bomb be used for measuring the true vapor pressure of a liquid? Why? (3) Explain why the reading obtained with a Reid bomb is not equal to the true vapor pressure of a

(4) List the most common procedural and/or equipment errors contributing to the false vapor gasoline.

pressure determinations.

Knock properties of gasoline (ASTM D 909-83; D 2623-83; D 2699-83; D 2700-83; D 2885-83; D 2886-83)

In high-compression engines or if considerable carbon accumulates in the combustion chamber, abnormal combustion takes place which is manifested by a sharp metallic knock whose pitch is characteristic of the engine. The knock develops in the following manner: after the spark ignites the charge, it burns smoothly until part of it is burned; then, if the fuel or engine operating conditions are unsuitable, the remaining portion burns with a suddenness comparable to the explosion of a rifle cartridge. Preignition, which produces melted pistons, cracked cylinder heads, and backfires (wrecking superchargers and other parts of the induction system), is the most dangerous type of abnormal combustion. Preignition occurs in cases where the charge starts to bum before the spark jumps at the spark plug, and it is usually inaudible. Normal heptane (C7HI6) and 2,2,4-trimethyl pentane (C,H,,) (isooctane) have been adopted as “measuring sticks” of knock intensity with a standard engine known as the C.F.R. (Cooperative Fuel Research) engine. The unit of knock intensity known as the octane number is defined as the percentage by volume of isooctane (with high knock value) that must be mixed with normal heptane (which knocks very easily) in order to match the knock intensity of the test fuel. Inasmuch as these hydrocarbons are expensive, reference gasolines that have been standardized against the octane-heptane mixtures are used in the commercial work.

Aircraft engines operate over a wide variety of conditions, with the amqunt of fuel added t o a given quantity of air being one of the most important variables. Under long range cruising conditions only six

486

TEL IN ISOOCTANE, ml / g a l

OCTANE NUMBER

Fig. A-9. Relationship between performance number and tetraethyl lead content in isooctane in ml/gal.

pounds of fuel may be added to each 100 pounds of air (lean mixture), whereas at take off eleven pounds of fuel per 100 pounds of air can be used (rich mixture).

When the fuel grade includes a number of 100 or less, it indicates octane number. If the number is above 100, it indicates the relative power that the engine can develop safely with equal knocking tendency and is known as the performance number. For example, a performance number of 130 indicates that the engine will develop 1301% (1.3 times) as much knock limited power on this fuel as it would on a fuel having a rich performance number of 100. When the grade includes two numbers such as Grade 100/130 or Grade 91/96, the first number indicates the rating at lean mixture conditions and the second the rating at rich mixture.

Inasmuch as an Octane number of more than 100 cannot be measured in terms of octane, lead in Octane is used to measure the knock value of fuels having a rating higher than 100. (See Fig. A-9.)

Tetraethyl lead in gasoline (lead chromate) (ASTM D 2547-82)

The gasoline containing TEL [Pb(C,H,),] is first refluxed with concentrated hydrochloric acid to yield a PbCl , salt in acid solution. The two water refluxes serve to wash the fuel free of residual PbCl ,. In order to oxidize any interfering organic materials which might have been removed from the fuel in the refluxing process, the PbCl, solution is evaporated and reacted with the concentrated nitric acid (HNO,). The PbCl, is also dissolved with the aid of HNO,. The subsequent additions of ammonium hydroxide (NH,OH) and acetic acid (CH,COOH) serve to neutralize solution and to form a neutral buffering CH,COONH, solution. The buffering action works as follows:

CH,COO- NH; +H++CH,COOH+NH:

CH,COO- NH: + O H - + NH,OH+CH,COO-

When the potassium dichromate is added to the PbCl, solution, the ammonium acetate buffer controls

487

the precipitation of the Pb as PbCrO, (MW = 323.2) rather than as the PbCr20, (MW = 423.2), which would precipitate in acid solution. This reaction is as follows:

2PbC1, + K2Cr20, + H20+2CH3COONH4 + 2PbCr0, + 2KC1+ 2NH,Cl +2CH3COOH

The lead is gravimetrically determined as PbCrO,. Lead is the most powerful antiknock additive, and reduces "knock" in chain paraffins, cyclic

paraffins, aromatics, and olefins (not equally with all, however). For aviation use it is blended with ethylene dibromide and this mixture is identified by a distinctive dye.

Lead bromide in the presence of water and of metals in the cylinder unit, particularly aluminum, at atmospheric temperatures produces corrosive liquids which cause rusting of steel or cast iron if the surfaces are not protected with an oil film. In view of the corrosiveness of lead bromide, the amount of ethylene dibromide which can be added is limited. It should be exactly equal to the theoretical amount necessary to convert all the lead to lead bromide during combustion of the fuel-air mixture.

Key points

0.05-0.10 ml per gallon.

usually sufficient.

(1) With highly volatile gasolines, omission of the distillate may lead to results which are low by

(2) The boiling flask must be cleaned after each use. Refluxing 50 ml of acetone for five minutes is

Fisher TEL-meter

The polarographic method is fundamentally one of electrodeposition on a micro-scale. The dropping mercury electrode is used as the primary electrode (cathode), and the large pool of mercury at the bottom of the cell serves as the secondary electrode. As the mercury droplets fall through the refluxed fuel, the positive metal ions in the solution plate out on the droplets, picking up electrons from the mercury. Thus, mercury at the bottom of the cell becomes more positive than that in the capillary tube, and a current passes through the cell. The greater the concentration of metal ions in the solution, the greater the current through the cell.

In order to standardize the dropping electrode, the current passed by a solution of known metal ion concentration is measured. It is not necessary to use a separate standard solution, because a different metal ion can be used for the standardization. The voltage at which the standardizating metal ion (pilot ion) plates out on the drop must be different from the voltage needed to plate out the metal ion, the concentration of which is to be determined. If a known amount of the pilot ion is added to the unknown solution, and the mixture diluted to a definite volume, the currents due to the plating out of each metal can be measured and their ratio used to determine the concentration of the unknown.

Making a reading involves only three steps: (1) Apply voltage great enough to exceed the cadmium (pilot ion) deposition voltage (use designated

button). This current is then recorded in the TEL-meter by zeroing the galvanometer with this knob. (2) Apply a voltage too small to plate out cadmium ion but great enough to plate out the lead (use

other designated button). This current is then recorded by zeroing the galvanometer with t h s knob. (3) Apply a voltage too small to deposit either metal. This determines the residual current that flows

even when no metal is plating out. The galvanometer is zeroed with knob "TEL", which controls the dial reading.

The TEL-meter in effect (a) subtracts the residual current, (b) calculates the lead-to-cadmium ratio, and finally (c) translates this ratio into ml-of-TEL/gal on the dial face.

Contamination of fuels

The contamination test can be briefly outlined as follows: (1) A four-gallon representative sample shall be used for this test. (2) Some clear, unleaded gasoline or naphtha is filtered through a 200-mesh sieve to insure

488

cleanliness.

nearest milligram.

mixed thoroughly at room temperature and filtered through the weighed sieve.

and the washings filtered through the same weighed sieve.

(212OF) to remove the naphtha or gasoline.

(3) A suitable 200-mesh sieve is dried at 100 O C (212O F), cooled in a dessicator, and weighed to the

(4) The entire oil sample (4 gal), together with an equal amount of filtered naphtha or gasoline is

( 5 ) After filtration of the oil, the oil container is thoroughly rinsed with clean naphtha or gasoline

( 6 ) The sieve is then thoroughly washed with filtered naphtha or gasoline and dried at 100°C

(7) The sieve is again cooled in a dessicator and weighed to the nearest milligram. (8) The increase in weight of the sieve in milligrams per gallon and the presence of fibrous material in

the residue is reported. The content of relatively large foreign solid particles must not exceed 15 mg/gal and should not

contain significant quantities of fibrous material. Inasmuch as the foreign material, such as rust, scale, sand particles, and fiber, settles out on standing,

the importance of taking representative samples cannot be overemphasized. These contaminants clog the filters and screens in the lubrication system. Inasmuch as fibrous material settles very slowly and has a great tendency to clog filters and screens, its presence is of greater concern than that of scale or rust.

Questions (1) What type of samples can be used for the contamination test? (2) A thousand-barrel tank is equipped with three bleeders spaced equally over the height of the tank.

If one-third of the sample is taken from each bleeder, would the sample be representative? Explain!

Doctor test

The doctor test is a very sensitive test for mercaptans and hydrogen sulfide. The doctor test, however, fails to indicate the total quantity of sulfur in an oil, and the presence of free sulfur. The doctor test is also inferior to the copper-strip test for detection of corrosive sulfur compounds. Although it does indicate the presence of mercaptans, it is debatable whether or not these compounds are harmful at low concentration normally existing in the majority of refined petroleum products. High concentration of mercaptans gives a characteristic and unpleasant odor to the fuels.

The test is made by shaking the test fuel with a sodium plumbite solution, which is prepared by dissolving litharge in caustic soda. Upon shaking, a pinch of sulfur is added and the mixture is shaken vigorously again. If the yellow color of the sulfur film is noticeably masked or sample is discolored, the fuel is reported as “sour”.

If the sulfur film is only slightly discolored (grey) or flecked with black specks, the sample is reported as “sweet”. In the presence of much hydrogen sulfide, a black precipitate forms before addition of sulfur and usually masks the mercaptan precipitate. In the absence of hydrogen sulfide, and presence of mercaptans, the first precipitate will be yellow or orange in color. After addition of sulfur it will darken slowly and eventually will become black. The chemical reactions are as follows:

2 RSH+Na2Pb02 + Pb(RS),+2NaOH

Mercaptan + Sodium plumbite + Lead mercaptide +Sodium hydroxide (orange)

(RS),Pb+S+ PbS+(RS)2

Lead mercaptide +Sulfur + Lead sulfide + Disulfide (orange) (black) (oil soluble)

The lead mercaptides may be sufficiently soluble in the case of heavier petroleum products, such as

489

kerosine, and instead of forming a precipitate, will give a yellow or orange tinge to the oil layer. On addition of sulfur, the oil layer will darken slowly with eventual formation of a dark precipitate.

Mercaptan sulfur test (D 1323-62)

The mercaptan sulfur test should be run on samples which show a “sour” doctor test. The specification limit on mercaptan sulfur is required in jet fuels because mercaptans corrode certain metals of the jet aircraft fuel system, cadmium-plated parts being particularly sensitive.

Inasmuch as the specification limit on mercaptan sulfur in jet fuel (0.005%) is half the maximum allowable concentration for the use of a 100-cc sample, this size sample can be used in all but research or special fuels. The step requiring removal of HIS from the sample is unnecessary in all fuels where H,S has been shown to be absent by the negative copper strip corrosion.

A 100-cc sample is shaken with 15 cc of standardized silver nitrate solution and approximately 15 cc of alcohol. The alcohol serves as an emulsion breaker and is not critical as to volume. A portion of the known quantity of silver nitrate present precipitates the mercaptans as insoluble silver mercaptide:

RSH + AgNO, -+ AgSH + RNO, (R may be any organic radical in the mercaptan)

A large amount of shaking is required to insure complete reaction between the mercaptans in the fuel layer and the silver nitrate in the alcohol-water layer. The excess of silver nitrate is then titrated back with standardized ammonium thiocyanate and the amount of mercaptans is determined by the difference between the silver originally added and that remaining in the solution (which reacts with the thiocyanate):

AgNO, +NH,SCN + AgSCN+2(NH4),S04

The indicator used is femc alum which reacts with thiocyanate to form a brick-red femc thiocyanate:

FeNH,(SO,), + 3NH,SCN + Fe(SCN), + 2(NH,),S04

The NH4SCN reacts preferentially with AgNO, until the silver ion is exhausted. After that the red Fe(SCN), begins to form. Thus, any perceptible darkening of the yellow water layer during the titration indicates exhaustion of AgNO, and consequently an end point. Titrating to a brick red end point as the method implies requires the use of more NH,SCN than that actually needed to react with the excess silver ion and will give an erroneous end point.

The titration is best performed by a rough addition of NH,SCN from the burette to a definite red end point. This can then he back-titrated to the original yellow color with standard AgNO, solution. The final fine titration can be accomplished by the dropwise addition of NH,SCN until the first perceptible color change occurs in the water layer.

Key points

AgNO, and consequently an end point. It should not be titrated to the brick red end point. (1) Any perceptible darkening of the yellow water layer during titration indicates exhaustion of the

(2) Care must be exercised in standardizing the solutions.

Water-tolerance of aviation fuels

The water-tolerance test determines the degree of solubility of water in aviation gasoline and jet fuels. It is also indicative of the amount of alcohol or other water-miscible constituents in the gasoline.

The water-tolerance test involves addition of 80 cc of aviation fuel to 20 cc of distilled water and shaking the mixture vigorously for two minutes. The samples are then allowed to stand for five minutes before taking readings.

490

One hundred thousand gallons of average aviation fuel wil dissolve from 3 to 6 gal of water at 75 F. High aromatic content and temperature can increase water solubility. On cooling from 75 to 32OF, around 40-50% of the dissolved water is thrown out of solution.

Although 3 gal of water per 100,000 gal of fuel does not seem significant, it may form considerable volumes of finely divided ice crystals which may plug the fuel filter or fuel screen. The water may also cause freezing and plugging of a fuel line.

The specifications of many users require that fuel shall neither lose nor gain in volume when shaken with water. This prevents the addition of components which would separate out on contact with water, such as wood and grain alcohols. It also ensures that the fuel will not dissolve excessive quantities of water.

In addition, the water-tolerance test of the fuel should not show a lace in the water layer and/or sediment or scum at the interface between layers. These are indicative of the tendency of fuels to plug micronic filters on fuel servicing units and aircraft at time of use. The repeated occurrence of bad water tolerance in cases where filters were plugged with soapy material, indicates a definite relationship between the two.

Mechanism of filter plugging In the case of JP-4 fuel, there were a number of situations in the past in which fuels, although

conforming to specification requirements at the point of manufacture, nevertheless caused micronic filters on fuel servicing units and aircraft to plug at time of use. This problem was more common for California-produced jet fuels. It was also observed that all cases where filter clogging has occurred, the water tolerance test has shown a lace in the water layer and/or sediment or scum at the interface between layers.

Several theories have been proposed to explain the mechanism of filter plugging, including the following:

(a) Collection at the filter of uniformly dispersed colloidal particles which form in the fuel during or after the refinery treatment.

(b) Collection at the filter of a stable fuel-water emulsion formed upstream from the filter. This can possibly occur during agitation in storage tanks or aqua systems where there is high throughput relative to available storage and settling facilities.

(c) Formation at the filter of an emulsion with the water which filtered from the fuel. The complex nitrogen and sulfur polymerization products, which were probably responsible for the

dark color of jet fuel in certain areas, could form a colloidal suspension in the fuel. This suspension in addition to collecting at the filter, could also act as an emulsifying agent. Metallic naphthenates, which form through reaction of the naphthenic acids with caustic or possibly iron rust, could be very good emulsifying agents and, possibly, precipitate out as a colloidal suspension.

The naphthenic acids, which are present in high concentration in untreated jet fuels from some crude oils, could also act as emulsifying agents. They probably will not be as detrimental, however, as the soap of the acids.

No single theory, however, can account for all cases of filter plugging and bad water tolerances, and the filter problem is the result of some combination of these potential offenders.

The water tolerances are influenced by the source of crude oil, amount of heavy components in the blend, and type and efficiency of refinery treatment. Although the water tolerance test is not as positive as the flame photometer, etc., for the presence of soapy material, it is adequate enough for detection of potential trouble. A strict interpretation of the water tolerance test should be made. Passing only fuels with a clean and clear interface solves this problem.

Questions (1) List the chemicals whch accentuate emulsion-forming tendencies of jet fuels. (2) Describe the purpose and procedure for determining the water tolerance test. (3) Upon completion of the water tolerance test, what do the drops of water clinging to the sides of

(4) Under what conditions would dissolved water in aircraft fuel cause malfunctioning of aircraft the stoppered graduate indicate?

engines?

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Thermal value of fuel oil (D 240-76; D 1405-64; D 2382-83)

The thermal (calorific) value of a fuel is the amount of heat generated as a result of its complete combustion. Results are usually expressed in “calories per gram” or “British thermal units (Btu) per pound”. The calorie is the amount of heat necessary to raise the temperature of a gram of water one degree Centigrade, whereas the British thermal unit is the amount of heat required to raise the temperature of one pound of water one degree Fahrenheit. Inasmuch as one pound is equivalent to 453.59 g and a degree Centigrade is equivalent to 1.8OF, 1 Btu is equal to 251.99 cal(1 cal/g=1.8 Btu/lb).

Thermal values are reported as “gross” (higher) or “net” (lower). The heat liberated when 1 Ib of a fuel at 60 F is burned and the products of combustion are cooled to 60 O F is called the net heating value. If in addition the H 2 0 vapor in the flue gas is condensed, the gross (high) heating value is obtained. The gross heating value is measured directly by use of the conventional bomb calorimeter and is generally used in the United States, whereas in Europe the net heating value is used.

The thermal value of gasoline can be determined in an oxygen bomb calorimeter. A weighed quantity of gasoline is burned in a steel bomb placed in a definite quantity of water. The thermal value of the fuel can be calculated from the rise in temperature of the water due to the burning of a definite quantity of fuel.

Key points (1) Sample of fuel must be weighed rapidly to minimize evaporation. (2) Apparatus must be assembled immediately after weighmg and placing the sample in the cup. (3) Temperature of water in jacket must be regulated to agree with the temperature of water in the

(4) It is necessary to determine the correct oxygen pressure to insure complete combustion. bucket.

Sample problem A-5 What is the net heating value of methane expressed in Btu per cu ft? The gross heating value of

methane is given as 1009 Btu per cu ft and the heat evolved when 1 cu ft of H 2 0 vapor is condensed at 60 OF is equal to 50.3 Btu. (The heat evolved on condensing 1 lb of H 2 0 is equal to 1058.2 Btu).

Solution :

CH, + 202 + COZ + 2 HzO

One cu ft of methane on burning produces 2 cu ft of water vapor; therefore, the net heating value = 1009 - (2 x 50.3) = 908.4 Btu/cu ft.

Question

value (total heat of combustion)? (1) How does the net heating value (net heat of combustion) of a fuel differ from the total heating

Gum content (ASTM 381-80)

During cracking, unsaturated hydrocarbons, such as the olefins C,H,,, diolefins C,H,,_,, and acetylene, are produced, which upon exposure to air during storage result in the formation of so-called “gum” in the gasoline. Diolefins cause the formation of tars, a loss in color, and the formation of gum during storage. They tend to polymerize and combine with other unsaturated molecules, forming high-molecular weight, gum-like solids. These compounds are soluble in the gasoline unless a marked degree of aging has taken place. Upon evaporation of the gasoline, however, they form resinous materials insoluble in the gasoline. This gum content is usually expressed in milligrams of gum per 100 ml of sample.

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Excessive gum content in gasoline is attended by stickiness of the valve stems and carburator mechanism, clogging of screens and filters in the fuel lines, and formation of deposits in the intake manifold. All these effects result in uncertain engine performance. If the motor gasoline contains dissolved non-volatile lubricating oil, it will be also obtained as a residue along with the gum. Such gasolines obviously require special treatment depending upon the nature of the non-volatile material.

Freshly manufactured gasoline does not normally have an appreciable gum content. A more significant property of the gasoline, therefore, is its tendency to form gum in storage (gum stability). Gum stability depends upon the nature of gasoline and refining. The gum forms at varying rates and different gasolines have varying gum contents after a given period of aging. The rate of gum formation also depends upon the temperature of storage, access of air, and presence of catalytic materials.

Method of testing: (1) One method of testing involves rapid evaporation of a sample of the gasoline at an elevated

temperature in a current of heated air or dry steam. The results indicate the amount of gum deposition which may occur if the fuel is used immediately, but do not indicate the stability of the product toward gum formation upon storage.

(2) The second method involves accelerated oxidation in closed systems at elevated temperatures. The amount of gum and lead precipitate after a specified period (5 or 16 hours) of oxidation may be used as an indication of the tendency of the fuel to form deposits on storage.

Key points (1) The flowmeter should be calibrated to give required flow rate of dry steam or air. (2) Prior to weighmg, the beakers must be allowed to cool in the vicinity of the balance for at least

two hours.

Questions (1) What is the purpose of the oxidation stability test? (2) What is the purpose of the existent gum test? (3) What is the specified bath temperature for conducting existent gum test on jet fuel? Reciprocating

fuel?

Aniline point (D 611 -82) and aniline-gravity constant

The aniline-gravity constant, which is calculated from the aniline point and API gravity values, can be used in both the aviation gasoline and jet fuel specifications as a substitute for the heat of combustion test. The aniline-gravity constants, however, must have high values before they are considered as a rough measure of the heating values. (The amount of heat liberated when a unit quantity of a fluid is burned is called the heating value or heat of combustion.)

The aniline-gravity constant is the product of the gravity in degrees API and the aniline point in degrees Fahrenheit. The high-API gravity fuels (light fuels), therefore, will have higher aniline-gravity constants. This is of great importance because with the higher-API gravity fuels a greater quantity of fuel can be carried in the aircraft before reaching the limiting fuel weight. In addition, there is a direct correlation between the API gravity and heating value of fuels.

The aniline point is the temperature in O F at which an equivolume mixture of fuel and aniline are no longer soluble in one another. The principle involved in this test is the fact that when two immiscible liquids are heated together, they become increasingly soluble in one another until a point is reached where they are completely miscible.

Figure A-10 shows the solubility temperature of different mixtures of aniline fuel. At any given composition of fuel and aniline there is one temperature at which complete solubility first occurs on heating. For a 50-50 mixture, this temperature, shown as T, in Fig. A-10, is defined as the aniline point. Should the composition, however, be changed even slightly, for example to a 49-51 mixture through careless measurement, then the temperature at which mixing occurs would differ from the true aniline point. Accurate measurements of aniline and fuel volumes, therefore, are essential for obtaining good results in this test.

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nw

W

COMPLETELY MISCIBLE

T c - - - - - - - -

TWO I PHASE

Inasmuch as different hydrocarbons differ in the ease with which they mix with aniline, the aniline point varies with the composition of the fuel. A very general and simplified rule is that the compounds which are most like aniline in structure will tend to mix readily with aniline and, therefore, will have lower aniline points. Inasmuch as aniline is an aromatic amine, the aromatic compounds generally can be expected to have low aniline points. These compounds also have low heating values and attack rubber and plastic parts. In general, the less saturated hydrocarbons which will mix more readily with aniline (low aniline points), usually have lower heating values. Figure A-11 shows the heating values and aniline points of C, aromatic, olefin, and paraffin. This comparison illustrates to some extent why the aniline point can be used as an empirical measure of the heat of combustion for fuels.

The aniline point is determined by heating a fuel-aniline mixture to a point where a clear solution is obtained and then letting it cool to the temperature at which the mixture just becomes cloudy throughout. This is more satisfactory than trying to read the temperature at which the mixture just clears on heating, because the clear homogeneous solution gives a very sharp cloud point when the aniline point is reached.

Key points (1) Accurate measurements of aniline and fuel volumes are essential for obtaining accurate results. (2) It is important that one maintains an absolutely uniform temperature throughout the solution.

Otherwise, stringy clouds of separating material can form in the colder areas where the aniline point is

ANILINE

'C ? H

H - C O C - t ! 4

d /c c\

META-XYLENE (AROMATIC)

H H H Btu/ Ib : 15,000 17, 5 0 0 ANILINE POINT, 'F: - BELOW ROOM TEMPERATURE 1-22]

DIISOBUTYLENE(0LEFIN) ISOOCTANE (PARAFFIN)

H CHS CH H H C% H CH3 H I I 1 ~ 1 I I I I I

H-C - C = C-C - C - H H - C - C - C - C - C - H I I l l I I I I I H H CH3 H HCH3 H H H

EtuIlb: 19.000 19,100 ANILINE P0INT;F: 108.5 175.6

Fig. A-11. Chemical structures, heating values, and aniline points of C, aromatic, olefin, and paraffin.

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reached. The temperature at which the entire solution is uniformly cloudy should be regarded as the true aniline point.

Questions (1) Define the aniline point. (2) What is the purpose of this test? (3) How is the aniline point of fuel related to the Btu value? Why? (4) Give an actual correlation between the 'API gravity and heating value for some fuel.

Fluorescent- Indicator Adsorption (FIA) test (D 1319.83; also see D 936-83)

The fluorescent-indicator adsorption test is used for determining the amounts of aromatics, olefins, and saturates in fuels. It is desirable to limit the amount of aromatics in fuels because of their tendency to leave carbon deposits in the combustion chambers, their relatively low heating values, the ease with which they attack rubber and plastic parts in the fuel-handling systems, and their tendency in some cases to have poor freezing points. The compounds containing sulfur, nitrogen, or oxygen are also determined as aromatics. On the other hand, olefins tend to produce gums and other undesirable polymerization products on storage and are limited for this reason. Inasmuch as the high olefin content is characteristic of cracked stocks in fuels, a tight limit on olefins virtually restricts the refinery to the use of the more stable straight-run blending stocks. The FIA is a rapid substitute for the two laborious chemical analyses for (1) total unsaturates by acid absorption and (2) olefins by bromine number. The FIA method is based upon the principle that liquid organic compounds adsorb on the surface of finely divided silica gel with varying degree of attraction, which depends upon their molecular size, weight and arrangement (structure), heat of wetting, polarity, and solubility. Silica gel has a greater affinity for alcohols than for hydrocarbons. Among the hydrocarbons, silica gel has the greatest affinity for the aromatics and a greater affinity for olefins than for paraffins or cycloparaffins.

Thus, a small sample can be washed down a column of packed silica gel with isopropyl alcohol and the fuel will separate into its paraffinic, olefinic, and aromatic components. The aromatics, which have the greatest affinity for silica gel, will be the last to be displaced by alcohol and, therefore, will concentrate at the top of the fuel layer. The olefins will form the next band and the saturated hydrocarbons will be in the bottom layer. This is due to the chasing of molecules down the column, each molecule displacing another type more loosely held by the gel.

The dye used in the FIA test has olefinic and aromatic components which will concentrate in respective layers. On using ultraviolet light, the various components of the fuel appear as color bands in the packed column. The percentage of different components is determined from the ratios of color band lengths to the overall length of the fuel sample (sum of lengths).

Key points

sealing, and (c) incomplete elution of the hydrocarbons by alcohol. (1) Erratic results can occur f rop (a) improper packing of the silica gel in the tube, (b) improper glass

(2) Isoamyl alcohol is recommended in the case of higher-boiling hydrocarbon samples.

Sulfur content (Lamp) (ASTM D 1266-80) (also see D 129-64)

The sulfur lamp test is intended for the determination of the total amount of sulfur in fuels, without attempting to separate this value into quantities of various classes of sulfur compounds. The sample is burned in a closed system using a wick-type lamp and in sulfur-free air. The oxides of sulfur are absorbed in water, oxidized to sulfuric acid by means of hydrogen peroxide, and determined gravimetrically as barium sulfate. The volumetric method involves titration with NaOH.

Many fuels are not permitted to contain more than 0.05% sulfur by weight, because the sulfuric acid which can form on combustion is highly corrosive.

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Key points (1) In the case of incomplete oxidation of the sample, the absorber liquid will have a characteristic

taste or odor, which can be easily detected by the operator when drawing air through the absorber during titration. In such cases, the test shall be discarded.

(2) Weighmg should be done rapidly in order to prevent evaporation losses. (3) Flame must be maintained at a point just below smoking with a steady, symmetrical appearance.

Questions

conditions? (1) Describe the effect of sulfur upon nickel alloys. What is the significance of oxidizing and reducing

(2) What is the relationship between the sulfur content and coke deposition (turbine type fuels)?

Corrosion (Copper strip, 212 OF) (ASTM D 130-83)

The corrosion test for gasoline is intended primarily to prevent corrosion of metals in the fuel and induction systems of engines. Inasmuch as the most likely corrosive substance present in gasoline and kerosine is sulfur, which readily attacks copper, it is customary to require that products of this type shall pass a test involving contact with polished copper for a specified time, at a specified temperature.

The test involves determination of discoloration produced when a strip of sheet copper is immersed in the gasoline for three hours at a temperature of 212" F. The degree of discoloration is first examined in the center of the copper strip and the relative proportions of areas of different degree of discoloration are determined before assigning a discoloration number from the standard chart. For example, 6 + would indicate that the greater portion of the copper strip has a discoloration number of 6 with some areas around the edges having a discoloration number of 7.

Questions (1) How are the copper strips polished? (2) How long does the copper strip remain in the bath at test temperature? (3) What is the specified bath temperature? (4) Under what conditions is the fuel reported as passing the corrosion test?

FUNCTIONS OF LUBRICATING OILS

The primary purpose of any lubricant is to reduce friction, and thereby eliminate metal-to-metal contact. Lubricating oil provides a film which permits surfaces to glide over each other with less friction. Lubrication is essential, therefore, to prevent wear in any mechanical device where there are surfaces rubbing against each other. The selection of the proper lubricating oil for a given application depends upon the design of the equipment and the conditions under which the equipment is to be operated.

In internal combustion engines, lubricating oils must perform four basic functions: (1) lubrication, (2) cleaning, (3) cooling, and (4) sealing.

( I ) Lubrication

In order to lubricate properly, an oil must have the following characteristics: (a) It must be of low enough viscosity to flow readily between closely-fitted, rapidly moving parts,

but of sufficient viscosiy to prevent metal-to-metal contact between these parts. (b) It must be tough enough so that it will not break down or fail under high temperatures and

pressures. (c) It must have a low enough pour point to enable it to flow readily when starting under extremely

low temperatures.

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(d) It must have high enough flash and fire points so that it will not burn, vaporize, or otherwise be

(e) Its carbon content must be low enough so that it will not deposit excessive amounts of carbon. (f) The oxygen absorption of the oil must be low enough so that varnish and gum do not form. (g) The neutralization number must be as low as possible. (Low neutralization number indicates that

the amount of acid present is small). Inasmuch as acid is detrimental to engine parts, the acid content must be very low.

consumed under high heat.

(2) Cleaning

A major function of a lubricating oil is cleaning or carrying off dirt, road dust, small carbon and steel particles, gum, varnish, etc. This function has become particularly important because of increased compression ratios, higher speed engnes, high operating temperatures, and closer tolerances. Filters have been developed to filter out part of the dirt, and ventilation systems have been designed to carry off vapors and moisture. These devices, however, perform only part of the job. Additives or detergents, therefore, are blended with lubricating oils. The detergent, which is soluble in the oil, cleans dirt, gum, and other impurities from the engine and moving parts. It then holds these impurities in suspension. As the oil, carrying the particles in suspension, is circulated, the dirt is removed by the filter. Gum and varnish, however, are not removed by the filter. Consequently, the oil must be changed at intervals. If not, the amount of gum and varnish held in suspension by the oil increases to the point where these substances are deposited thoughout the engine, causing poor performance.

(3) Cooling

A lubricant must cool moving parts by carrying off waste heat. This is especially true in aircraft engines where the lubricants must carry off approximately one-third of the total waste heat. In order to perform its cooling function, a lubricant must have sufficiently low viscosity to flow readily at all temperatures of operation.

(4) Sealing

Another function of lubricating oil is to seal the space between the piston rings, cylinder walls, and pistons to prevent blowby (leakage of combustion gases from the combustion chamber, past the rings, into the crankcase). When the space between piston rings, cylinder walls, and pistons is properly sealed, the full force of the burning and expanding fuel gases is exerted on the head of the piston, and none of the force of combustion is lost.

TESTS ON LUBRICATING OILS

Viscosity

Viscosity or “body” is the measure of the oil’s fluidity, or rather its resistance to flow. Viscosity (kinematic) can be measured with glass viscometers, immersed in a constant-temperature

bath. (See D 445-83.) The time necessary for the oil to flow between two notched areas (on the outside) of the capillary tube multiplied by the experimentally determined constant for the individual capillary is termed the kinematic viscosity (centistokes), which can be converted to Saybolt viscosity (Saybolt Universal seconds) by means of formula or tables.

The Saybolt type of viscometer was the original apparatus used to measure the viscosity of petroleum oils and the unit for expressing viscosity given by this apparatus is used thoughout the petroleum industry. The Saybolt viscometer contains a carefully machined tube and orifice meeting definite measurement specifications. The tube, which is surrounded by a constant temperature bath, is filled with

491

test oil and is allowed to flow by gravity through the orifice into a calibrated flask. The time in seconds necessary to fill the flask up to a definite volume is termed the Saybolt seconds viscosity.

The viscosity of lubricating oils is the best single index which indicates the uses for which the oils can be recommended.

In a bearing, the viscosity of the lubricating oil at the operating temperature, determines the bearing friction, heat generated, and the rate of oil flow under the particular conditions of load, speed, and bearing design. Lubricating oil prevents direct contact of metal surfaces through adhesion or ability of the oil to stick to the surface of the metal. The oil must be viscous enough, however, in order not to be squeezed out by the bearing pressure. With increasing viscosity, the ability of the oil to stick also increases. Generally, the lower the pressure and greater the speed, the less viscous must be the oil used. Although a reasonable factor of safety is essential, excessive viscosity means unnecessary friction and heat generation. Inasmuch as the rate of change of viscosity with temperature varies with different oils, the viscosity test should be made at that standard temperature which approximates most closely the temperature of the oil in use.

In the case of lubricating oils for automotive equipment, the viscosity of the crankcase oil at low temperature also indicates the ease of starting in cold weather. In transformer oils, or oils for circulation in heat-carrying systems, where the rate of circulation of an oil is important, viscosity becomes a factor of practical significance.

Viscosity index (ASTM D 2270-79)

As far as viscosity is concerned, a perfect oil should have the same viscosity at all temperatures. At the present time, however, there is no such oil. The oils get thinner with increasing temperatures and thicker as the temperature is reduced. This change in viscosity with temperature vanes for different oils, some thinning out more quickly than others. The viscosity index (VI) is an arbitrary numerical index showing the relative change in viscosity of lubricating oils with change in temperature. A low VI indicates a large change of viscosity with temperature.

Inasmuch as many engines operate at great extremes of temperature, in order to retain sufficient protective oil film at high temperatures and also prevent an excessive wear in establishng and maintaining lubrication at low temperatures, the lubricating oils should have a high viscosity index (higher than 100).

Viscosity index below 100 is calculated as follows (see Fig. A-12):

VI = [( L - U)/( L - H ) ] X100

where U = viscosity at 100 OF of the test oil, L = viscosity at 100 F of an oil of 0 viscosity index having the same viscosity at 210 F as the test oil, and H = viscosity at 100 F of an oil of 100 viscosity index having the same viscosity at 210 F as the test oil.

I00 150 200 TEMPERATURE, O F

Fig. A-12. Schematic diagram showing the principle of determining viscosity index.

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Thus, viscosity index can be calculated from the viscosity at 100 F and 210 O F. The flatter the viscosity temperature curve (that is, lower the rate of change of viscosity with temperature), the higher is the viscosity index.

Flush and fire tests

(1) Cleveland Open Cup (ASTM D 92-78), (2) Pensky-Martens Closed Tester (ASTM D 93-80), and (3) Tag Closed Tester (ASTM D 56-82).

The flash point of a petroleum product is the temperature at which sufficient vapors are given off to form an inflammable mixture with air. The fire point may be defined as the temperature to which a product must be heated in order to bum continuously after the flammable air-vapor mixture is already ignited. The flash-point test is more frequently used, because the fire-point test usually does not give any additional information.

Flash-point test in addition to indicating fire hazard, is also related somewhat to the consumption of the oil. A large number of “flash testers” have been devised and used and can be subdivided into two general classes: (1) closed-cup testers, and (2) open-cup testers.

The closed-cup tester is preferable in determining the flash point as an index of fire hazard, because it comes closer to paralleling actual conditions than does the open-cup tester. In handling or storage of petroleum products, an explosive ignition of vapors can occur in the unfilled portions of tanks, drums, or other containers. The closed-cup tester permits measuring the temperature which the oil must reach before it gives off enough vapor to create an explosive mixture in a closed system. In addition, the closed-cup tester is more accurate than the open cup.

The open-cup testers yield sufficiently accurate results to meet almost all of the practical requirements. In addition, the main advantages of the open-cup testers are cheapness and simplicity in operation.

The flash points of petroleum products vary over a wide range. The majority of lubricating oils have flash points between 275 O and 650 OF, whereas the flash points of more volatile gasolines and naphthas are considerably below 0 O F . The normal closed-cup flash point range for kerosine is 100-160 F. Gas oils and fuel oils generally have flash points between 110 and 300 F. The naphthas used as paint thinners and solvents have a closed-cup flash point ranging from 80 to 110 O F .

A closed-cup tester with a water bath and without a stirrer in the cup is best for the naphtha-kerosine group of products. For the testing of fuel oils and gas oils, a closed-cup tester without a waterbath but with a stirrer in the cup is preferred. Lubricating oils are best tested with a simple open-cup tester.

For a large number of petroleum products, including lubricating oils, the flash point is determined for the purposes of identification and classification. Flash point of an oil may serve as a rough indication of its tendency to vaporize. The Occurrence of foaming in the course of a flash-point determination is a sensitive qualitative indication of the presence of moisture in the test sample. In general, the interpretation of results is not simple, because the flash points bear no direct relation to the usefulness of oils.

Flash point is regarded as the most important index of fire hazard. For kerosine and napththa, the fire hazard is a very important consideration. There are wide variations in the flash-point requirements for kerosine enforced by different counties, states, and countries. This is not done because there is a particular temperature limit differentiating between safety and danger. Kerosine with a flash point of 90 O F is just as safe as a kerosine having a flash point of 100 O F , if users are familiar with the precautions necessary in handling it. Safety is measured by the habits of the user rather than by the physical and chemical properties of the product. The user, however, must know the exact properties of the product in order to know how to handle it.

Key points (1) The flash and fire tests should be performed in a room free of drafts. (2) Careless breathing or unnecessary movements near the flash cup, which disturb the vapors over

the cup. should be avoided.

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(3) The true flash point must not be confused with the bluish halo that sometimes surrounds the test

(4) Rate of temperature increase is of prime importance. ( 5 ) The test should not be repeated on the same portion of sample once used. Fresh portions of the

flame.

sample should be used for each test performed.

Questions

closed-cup testers? (1) What relationship exists between the results obtained by open-cup and those obtained by

(2) List all the methods for determining the flash points. (3) Can one set gasoline afire with a match? Kerosine? Motor oil? Explain. (4) What is the definition of kerosine and gasoline? (5) Why does the petroleum industry bother with the flash and fire points? (6 ) Suggest improvements in the open-cup method of testing. (7) What relationship exists between the flash and fire points of petroleum products and their boiling

(8) Enumerate the conditions that must exist at the time a flash occurs above a liquid petroleum points?

product.

Color of lubricating oils and petroleum

The ASTM Union Colonmeter test describes the determination of the color of lubricating oils and petroleum. Measurement of color depends upon matching the color of a given depth or thickness of oil with various color standards. (Also see Saybolt Chromometer Method, D 156-82; ASTM Color Scale, D

By transmission of light, the color of oils varies from a light yellow to a deep red, whereas by reflected light the oil may exhibit a blue or yellow-green appearance at the surface, regardless of the oil’s color. This appearance is due to the fluorescence and is called the “cast” or “bloom” of the oil. It may be noted by looking at the oil at an angle, or by viewing it in thin layers on a black background.

Properly refined paraffin-base oils and even some mixed-base oils have a yellowish-green cast, whereas naphthene oils appear deep blue. The natural yellowish cast of the paraffin-base or mixed-base oils, however, may be spoiled by improper acid treatment.

The chief significance of color as applied to lubricating oils lies in the fact that it is a generally accepted index of the uniformity of a given grade of oil. Color requirements of lubricating oils are frequently overemphasized because color does not necessarily indicate quality. For example, it is erroneously believed by some that pale color is indicative of low viscosity. Color requirements should not be made any more stringent than service demands.

The color is of definite importance, however, in the case of dry-cleaners’ naphtha, because it must be free from materials whch might discolor fabrics.

1500-82.)

Key points (1) Color of oils which are intermediate to the standard colors must be expressed in terms of the

darker standard as “minus”. For example, an oil having a color between 8 and 9 is to be expressed as “9 minus”.

Questions (1) What does the color of lubricating oil indicate? (2) Name other methods for determining the color of petroleum products. (3) How would one determine the color of a “green” lube oil?

Cloud and pour points (ASTM D 97-66; also see D 2500-81)

Because of partial separation of wax and congealing of the hydrocarbons composing the oil, petroleum oils become plastic solids when cooled sufficiently.

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The cloud point of a petroleum oil is the temperature at which paraffin wax or other solid substances begin to crystallize out or separate from solution. The pour point is the lowest temperature at which the oil will pour or flow when chilled without disturbance, under definite prescribed conditions.

The cloud point cannot be determined for oils in which wax does not separate prior to solidification, or in which separation is not visible. The cloud and pour points depend upon the source of the crude oil from which they are made, upon the grade or kind, and upon the method of manufacture.

The cloud point is useful when the haze or cloud in the oil above a given temperature is objectionable for some reason. It has a more limited value and narrower range of application, however, than the pour point. The test may also give erroneous results if the oil is not dry and water separates out.

The pour point gives an indication of the temperature below which it might be dangerous to use oil in gravity-lubricating systems and where the head tending to produce flow is small. The pour point also shows at what temperature the oil may not be possible to pour or remove from its container. The tendency to flow, however, is also affected by the sue and shape of the container, the head or force exerted upon the oil, and the nature of its physical structure when solidified.

The cloud test involves cooling the oil in a specified test jar from at least 25 F above the cloud point. The cooling bath is held between 15 " and 30 " F below the cloud point of the oil. At intervals, the test jar is removed from the brine bath without disturbance to the oil, and the temperature at which a distinct cloudiness or haziness first appears in the bottom of the test jar is recorded as the cloud point. The pour test is conducted in the same manner. The oil, however, is first heated to 115 " F to be sure that all the wax has dissolved, and then cooled to 90" before the test. As in the cloud test, the bath is held at 15-30 O F below the estimated pour point. At intervals of 5 " F, the test jar is removed from the bath and tilted to determine if the oil will flow or move. If there is no movement when the jar is held horizontal for five seconds, the recorded temperature is called the "solid point". The pour point temperature is taken to be 5 " F above the solid point temperature.

Inasmuch as there is no single test which can be taken as a positive and direct measure of the performance of an oil under all conditions of service, cloud and pour points should be interpreted in light of actual performance under the particular conditions of use.

Key points (1) Great care must be exercised in order not to disturb the mass of oil after the formation of paraffin

wax crystals. Any disturbance of the spongy network of wax crystals will result in low and erroneous pour points.

(2) The test may give misleading results if the oil is not dry, due to the separation of water. Thus, the test should always be interpreted with this fact in mind.

Questions

principles. (1) What does the cloud point indicate? Name one other test method that depends on similar

(2) What physical property of an oil does the pour point indicate? How else could it be determined? (3) Explain how the "thermal history" of a sample might affect the pour point. (4) Discuss dewaxing. How does it affect the cloud and pour points?

Dilution of crankcase oil (ASTM D 322-80)

All fluids possess viscosity and, therefore, show certain frictional phenomena when motion occurs. Inasmuch as friction releases heat, the temperature of a cold engine-oil rises with use. This causes the viscosity of the oil to decrease, giving rise to an important problem for the internal combustion engine. When the engine is run at low temperatures, or the piston rings are worn, unburned gasoline may be forced into the crankcase causing dilution of lubricating oil. With a lowered viscosity from both dilution and increase in engine temperature, the oil cannot perform the lubrication necessary to prevent overheating and breakdown on the moving parts. Lubricating oils are made to compensate for the dilution in small amounts and, therefore, no harm is done to the engine until the dilution becomes excessive. Excessive dilution is caused mainly by short running periods of the engine, or worn-out parts

501

of the engine, allowing “blow-by” of the gasoline. If, however, the engine is kept hot for a long period of time, some of the gasoline will be distilled from the oil, tending to restore the normal viscosity.

Precipitation number of lubricating oils (ASTM D 91 -81)

The method entitled “Precipitation Number of Lubricating Oils” is intended for the determination of the precipitation number of steam cylinder stocks, black oils, and other lubricating oils. A definite volume of oil and precipitation naphtha are heated in a prescribed calibrated tube and then centrifuged. The volume of sludge or asphalt present in oil, which is packed at the bottom of the tube due to the centrifugal force, can be read from the calibrations on the tube.

Crude oils contain non-volatile constituents which by distillation are concentrated in the residual products. If the latter are used as lubricants, it is necessary, therefore, to determine the amount of this “asphaltic” material. Inasmuch as the “asphaltic material” is sparingly soluble in naphtha, which is composed of low-boiling paraffin hydrocarbons, this characteristic forms the basis for the precipitation test.

The precipitation tests are successfully used for classifying the several groups of residual lubricating oils. Although some oils which contain appreciable quantities of asphaltic constituents are unsuitable for certain types of service, the importance of moderate variations is exaggerated by many users.

Black oils, which are used for the lubrication of gears and car journals, usually have moderately high precipitation numbers. Another group, which is characterized by a moderate percentage of asphaltic material, is steam-refined cylinder stocks. Filtered products such as “bright stocks”, which are largely used as constituents of motor oils, contain negligible quantities of material that is insoluble in the precipitation naphtha.

One disadvantage of this method is the fact that the compactness of the precipitate is not the same for all types of oil; therefore, there is no relationship between the precipitation number and the percentages of “asphalt” as defined by gravimetric methods.

Questions (1) What is the significance of the precipitation number test? (2) What is the relative amount of “asphaltic” material in black oils, cylinder stocks, and “bright

stocks”?

Carbon residue (D 189-81; D 524-81)

Some oils may be vaporized at room pressure and in the absence of air without leaving an appreciable residue, whereas other oils, upon distillation, leave a non-volatile carbonaceous residue.

The ASTM method involves destructive distillation of a weighed quantity of oil in an apparatus so designed as to exclude air, to permit proper control of rate of heating, and to eliminate possible condensation of distillates in or on the oil contained.

This method throws some light on the relative carbon-forming propensity of the oil. The quantity of carbon deposited in the combustion chamber should be proportional to the carbon residue of the oil. Other factors such as the viscosity of the oil, the mechanical condition of the engine, and the conditions of carburation of the fuel, however, may control the carbon deposition. The results of this test, therefore, must be considered in connection with other tests and the use for which the oil is intended.

Key point

residue.

Ash conteni (ASTM D 482-80; D 874-82)

(1) Petroleum products containing ash-forming constituents will have an erroneously high carbon

The ash content method is used for determining the ash content of fuel oils and other petroleum oils. The test is made by burning a weighed quantity of oil in a platinum or porcelain crucible and weighmg the remaining ash.

502

If a petroleum oil contains any inorganic foreign material, an ash or residue will be obtained after burning and ignition. This foreign material can then be identified by examination of the ash. This method also presents a quick means for determining the presence of clay that might have been left in the oil during clay refining. The ash test used for lubricating oils shows the amount of silt, dust, sand grains, and metallic particles resulting from the wear of the motor. All these inorganic substances are destructive to the operating or moving parts of the engine and should not be present in the oil.

Key points

method is not recommended for oils containing metallo-organic addition agents.

attack platinum at high temperatures.

of alcohol before heating.

Question

(1) Inasmuch as large portions of the metal compounds may be lost by vaporization, the ash content

(2) A platinum dish should not be used when the sample contains lead, zinc or other metals, which

(3) In order to avoid foaming and loss of samples containing moisture, it is advisable to add 1-2 ml

(1) List the materials which can be present in the ash.

Neutrulizntion number (D 664-81)

The procedures described in “neutralization number” method enable determination of organic constituents having acid characteristics in petroleum products and compounded products. They also show the presence of contamination by alkalies and mineral acids.

The majority of petroleum lubricating oils undergo treatment with mineral acid and caustic alkali in the course of refining. Small quantities of these undesirable chemicals may remain in the finished oil in case the refining operations are not properly conducted.

The “neutralization number” of an oil is defined as the weight in milligrams of potassium hydroxide required to neutralize one gram of oil. Inasmuch as the mineral acid or alkali is usually not present in the oil, the neutralization number is directly proportional to the “organic acidity”.

The “alkali neutralization number” is defined as the weight in milligrams of potassium hydroxide equivalent to the acid required to neutralize one gram of oil, whereas the “ mineral-acid neutralization number” is defined as the milligrams of potassium hydroxide necessary to neutralize the mineral acid content in one gram of oil.

Inasmuch as the effect of alkah or mineral acid in a petroleum oil is deleterious, it is usual to specify that the mineral-acid neutralization or alkali neutralization number shall be either zero or extremely low. The practical significance of “organic acidity”, however, is complicated by the following considerations:

(1) In some cases, the presence of organic acids somewhat improves the friction-reducing qualities of oil.

(2) The organic acids are usually not corrosive and do not have direct harmful effects. (3) Oils derived from different crude oils show a wide range in the neutralization number, unless

treated. The organic acids are mainly natural constituents of crude oils and their presence does not necessarily

indicate improper refining or poor quality. Thus, it is obvious that the general quality of lubricating oil cannot be evaluated on the basis of

neutralization number, and the specifications should not include limits on this property unless an oil of low organic acidity is required.

Questions (1) Describe the procedure for determining “alkali neutralization number”. (2) What is the difference between the neutralization and saponification numbers?

Saponification number (ASTM D 94-80)

The saponification number is the best obtainable index of the percentage of fat or fatty oil in a given product. The method is applicable to new or used petroleum oils including electrical insulating oils, and

503

to mixtures of fats and mineral oils. It cannot be used on oils containing compounds of sulfur, phosphorus, the halogens, or other elements that consume both free and combined fatty acids.

The saponification number is the number of milligrams of potassium hydroxide required to saponify one gram of the oil, and is a measure of both free and combined fatty acids.

The saponification numbers of some commercial fats and fatty oils are shown below:

Blown cottonseed oil Blown rapeseed oil Tallow Lard oil Neat’s foot oil Cottonseed oil Peanut oil Degras Soya bean oil Castor oil Rapeseed oil Fish oil Sperm oil

210-225 195-216 193-198 192-198 193-204 191-197 186-197 110-210 189-197 176-187 170-179 140-193 120- 140

In cases where the saponification number of the fat or fatty oil is not known, a value of 195 is used in commercial practice.

Key points (1) The presence of inorganic and certain organic acids, most nonalkali soaps, free sulfur, and other

substances which consume alkali will increase the saponification number above that of fatty saponifiable materials for which the method is primarily intended.

(2) The odor of hydrogen sulfide near the end of back-titration is an indication for presence of certain types of reactive sulfur compounds. A gravimetric determination of the actual amount of fatty acids is a more reliable method for such compounds.

(3) The glassware must be chemically clean. The flasks must be cleaned with chromic acid cleaning solution and rinsed with distilled water.

Questions (1) What are the permissible differences in results for highly colored oils? (2) How is the percentage of fatty oil or fat in a compounded petroleum product determined?

Sulfur (bomb) (ASTM D 1552-83)

The sulfur content of lubricating oil is determined by burning a definite weight of oil in a steel bomb filled with oxygen. All the sulfur in the oil is thus converted to sulfuric acid, whch is then quantitatively determined as barium sulfate.

The lubricating oil fractions (boiling range of 600-850 OF) of different crude oils vary in their sulfur content, some having high values and others low values. It is very expensive to remove the high-boiling sulfur compounds in this fraction.

The heat generated by an engine may break down the sulfur compounds in the oil and the newly-formed sulfur compounds may be corrosive to the metal parts. Consequently, it is important to determine the sulfur content of lubricating oils.

Key points (1) Admit the oxygen slowly to avoid blowing the oil from the cup. (2) Do not add the oxygen or ignite the sample if the bomb has been jarred, dropped, or tilted.

504

Corrosion test of lubricating oils (copper strip at 212OF)

Lubricating oils should not contain any material which tends to corrode the metal parts of the engine. The test is carried out by immersing a strip of polished copper in the oil contained in a test tube. The

reason for using a copper strip is the fact that it is the most sensitive material to corrosive materials such as sulfur and chlorine compounds. After the test tube is kept in a water bath (212OF) for a definite period of time, the copper strip is examined for corrosion by comparing the color change to a standard corrosion chart.

CLASSIFICATION AND REQUIREMENTS OF LUBRICATING GREASES

Lubricating grease is a blend of lubricating agent, soap, and stabilizing agents. The oil is the lubricating agent, the soap is a thickener, and the stabilizing agent keeps the finely divided particles of soap suspended in the oil. The hardness of a grease depends upon the amount of soap used-the more soap, the harder the grease. Properties of the grease, such as appearance, texture, melting point, and oxidation characteristics, are dependent primarily upon the type of soap used in the manufacture of the grease.

Soap is made by the reaction of a fixed oil and an alkali such as hydrated lime, caustic soda, aluminum salts, or lithium. Soaps are classified according to the alkali used in their preparation. Similarly, greases are classified according to the type of soap employed in their manufacture, the common types being calcium-base, soda-base, aluminum-base, lithium-base, and mixed-base greases. The latter contain soaps made from two alkalies.

Most greases are made by batch processes which normally involve the following steps: (1) saponification, (2) soap processing, ( 3 ) mixing, and (4) milling.

(1) Saponification. Fat or fatty acid, the alkali, and the petroleum oil are placed into a kettle which may be either open-type or pressure-type. When the kettle is heated, the fat or fatty acid reacts with the alkali, forming soap.

(2) Soap processing. The soap and the petroleum oil mixture is dehydrated and more petroleum oil is added to cool the mixture. In the case of calcium-base greases, water must be added to plasticize the grease.

( 3 ) Mixing. More petroleum is added until the desired consistency is reached. (4) Milling. The mixture is either milled in the kettle or processed by a homogenizer in order to

produce a smooth product. In general, grease should not be used where oil can perform the necessary lubrication. There are

conditions, however, under which grease is a more suitable lubricant. For example, grease is used in bearings which, because of their nature, are unable to retain oil. Grease is also used in inaccessible bearings where grease is applied by grease cups. Use of oil in such bearings, would necessitate shutting down the machinery. In addition, under dirty atmospheric conditions, the use of grease is advisable as it seals the ends of the bearings and thus prevents dust and dirt from entering the bearings.

The most important requirements of greases are: (1) Stability. A grease must be stable both during storage and when in use. It must be free from

(2) Water resistance. In some cases, a grease which is insoluble in water is required. In others, the

( 3 ) Satisfactory performance in operation. Inadequate lubrication will result if a grease does not

(4) Noncorrosiueness. The grease must not chemically attack the various metals and other materials

Properties of greases vary with the type of soap used: (1) Lime-base grease is water resistant and has good pumpability. Lime-base grease, however, has a

bleeding (separation of oil), oxidation, and changes in consistency.

grease must only be resistant to the weathering or washing action of water.

perform satisfactorily in the equipment for which it was intended.

with which it comes in contact.

low melting point and, therefore, should be applied only where temperatures do not exceed 175 F.

505

(2) Soda-base grease has a high melting point. It is soluble, however, in water. (3) Aluminum-base grease is water resistant. It has a comparatively low melting temperature;

(4) Lithium-base grease is water resistant and has a wide range of operating temperatures. ( 5 ) Barium-base grease is also water resistant and has high heat stability.

however, it changes texture (becoming leathery) on heating and cooling.

Penetration of lubricating greases (D 21 7-82)

The penetration number indicates the consistency of greases, petrolatums, and similar plastic petroleum products. Consistency of finished greases is affected primarily by the kind of soap used in their manufacture. It is also affected by the amount of soap, method of manufacture, water content, and rate of cooling. The penetration number is determined by grease manufacturers to control uniformity in production and by users to compare greases. The penetration number, however, is not a true value of the ability of a grease to perform in service. To predict performance, other characteristics must be known.

In testing grease, an instrument known as a penetrometer is used under prescribed conditions of temperature, load, and time. This instrument measures the depth to which a pointed cone penetrates the grease when the cone is dropped into a sample from a given height. The depth of penetration, in tenths of a millimeter, is read on the scale of the penetrometer and reported as the penetration number. Low penetration numbers indicate a stiff grease, whereas higher numbers are indicative of softer greases.

Key points

erroneous results, because it is equivalent to overworhng the grease beyond the specified 60 strokes. (1) In performing this test, a manipulation should be used. Excessive manipulation will result in

(2) Entrapped air should be removed prior to the test (especially large air bubbles). (3) This test should be performed as rapidly as possible.

Dropping point of grease (D 127-63)

The dropping point is the temperature at which grease passes from the semisolid to the liquid state under certain test conditions.

The dropping point indicates the resistance of greases to heat. The test method is used, for example, to distinguish conventional lime-base cup greases from high-melting-point types, such as soda-base greases.

Key points (1) Rate of heating is of prime importance. (2) Working of the grease should be avoided as far as possible.

ORSAT GAS ANALYSIS

Method of analysis

The Orsat method of gas analysis consists of taking a measured volume of gas sample, removing various components (one at a time by suitable reactions), and measuring the decrease in gas volume after removal of each component. The results are then reported on a percentage basis.

Carbon dioxide Carbon dioxide is removed by absorption in a solution containing about 500 g of potassium

hydroxide per liter of solution; however, solutions having lower concentrations may be used. Sodium hydroxide can be used instead of potassium hydroxide although it deposits carbonate more readily.

Reference: M.P. Matuszak, 1954.

506

Unsaturated hydrocarbons Unsaturated hydrocarbon gases which include ethylene, propylene, acetylene, butylene, and benzene

are removed by absorption in fuming sulfuric acid containing 15-20% sulfur trioxide. Unsaturated hydrocarbons (olefins and diolefins) may also be removed with bromide water.

Carbon monoxide Carbon monoxide may be removed by direct absorption or it may first be oxidized to carbon dioxide.

Conversion of CO to CO, can be achieved by passing the gas over copper oxide at 300 C or by slow combustion in oxygen in the presence of a glowing platinum coil. The carbon dioxide is then absorbed using potassium hydroxide.

A solution of cuprous chloride in hydrochloric acid or a suspension of cuprous sulfate and beta-naphthol in sulfuric acid may be used for direct absorption of carbon monoxide. Absorption is more complete and reaction is somewhat faster in the latter solution. In the case of cuprous chloride, two absorption pipettes should be used for accurate work: one for removing the bulk of carbon monoxide and the other for removing the last traces of monoxide from the gas. It is better, however, to use one pipette with cuprous chloride and the other pipette with cuprous sulfate-beta-naphthol. It is preferable to use acid cuprous chloride rather than ammoniacal cuprous chloride because it does not lead to alkaline conditions in the burette. Inasmuch as cuprous sulfate-beta-naphthol is a suspension in sulfuric acid and settles at the bottom of the stock bottles to a depth of approximately one inch, the solution should be vigorously shaken and the solids suspended prior to transfer to a gas pipette.

Hydrogen Hydrogen may be determined by oxidation to water. This is accomplished by passing the gas over a

copper oxide at 250-300 C or by slow combustion of the gas in oxygen in the presence of a glowing platinum coil. Inasmuch as the volume of water formed is negligible, the amount of hydrogen present in the gas sample is equal to the reduction in gas volume of the sample caused by the oxidation.

Methane and ethane Methane and ethane are determined by slow combustion in oxygen in the presence of a glowing

platinum coil. The reduction of gas sample volume after combustion must be determined in addition to the volume of carbon dioxide formed.

Nitrogen

gas contains all inert components.

Combinations of combustibles The choice of methods to determine combustible gases (hydrogen, carbon monoxide, methane, and

ethane) is dependent upon the combination of combustibles present in the sample. Any one or two of these gases may be determined by a slow combustion method. Methane and ethane are always determined by a slow combustion method. If both methane and ethane are present in the gas sample, slow combustion cannot be used to determine the volume of hydrogen and carbon monoxide. Carbon monoxide may be determined by absorption; however, if hydrogen is also present, oxidation over copper oxide at 300 O C should be used.

Simultaneous determination of more than two combustible gases by slow combustion is not recommended by Fisher Scientific Co.

After removal of all reactive components, the remaining gas is assumed to be nitrogen. The remaining

Introduction of gas sample The manifold and copper oxide tube should be flushed with nitrogen. After the level of the liquid in

the burette is raised to the uppermost graduation mark (marked either 100 ml or 0 ml), the manifold is closed off from the atmosphere. The zero point on the burettes usually corresponds to the upper end of the capillary just below the upper stopcock. A capillary glass tube bent into an L- or U-shape, is used if necessary. The connection may be purged by drawing two to three successive 10- to 15-ml portions of the

SO7

sample gas into the burette and then discarding them into the atmosphere. A three-way stopcock in the connections permits a quick and easy execution of this process.

The sample to be analysed is drawn into the burette after the connection has been filled with the gas. This is done without mixing the gas with nitrogen. In a portable apparatus, however, the nitrogen in the manifold is displaced into the burette by the entering gas. The manifold must not be filled with the gas before drawing in the gas sample.

Size of gas sample It is convenient to analyze exactly 100 ml of gas so that percentages of various components may be

read directly on the burette. More than 100 ml of gas is first drawn in and then the excess gas is discarded so that the volume of gas analyzed is exactly 100 ml. The leveling bottle is raised so that the bottom of its meniscus is level with the lowest burette graduation mark. Then, the excess gas is allowed to escape slowly to the atmosphere. This occurs by way of (1) the stopcocks on the burette and sampling bulb, or (2) the intake stopcock provided at the end of the manifold in some Orsat models. When the meniscus in the burette also reaches the lowest gradation, the stopcock connected to the gas sample source should be closed.

Number of passes The number of passes required for the absorption of any particular gas component is dependent upon

the design of the pipette, the reagent used, the age of reagent, etc. Three to four passes are usually considered sufficient for CO,, whereas six or more passes may be required for other components, e.g., 0, and CO. After all of a particular component has been removed, i.e., when there is no further contraction of the sample gas volume, the gas is passed once again into the pipette. When more than 12 passes for complete absorption are required for 0, and more than S passes are required for CO,, the reagent should be replaced with fresh solution.

Sample problem A-6 (ORSAT analysis) Orsat analysis is used to analyze a gas sample that is 50% saturated with water vapor, and contains

TABLE A-I

Given and computed values of Sample problem A-6

Initially After passing through After passing through p yrogallol conc. H,SO,

Degree of saturation with water (X) 50.0 * 100.0 * 0.0

Total volume of gases (ml) 100.0 * 70.2 * 45.9 *

0.0

45.9 - 0.0 = 45.9

22 - Volume of H,O vapor (ml) % X 100 = 1.5

100 - 1.5 = 98.5

750 X 70.2 = 2.1

70.2 - 2.1 = 68.1 Volume of dry gases (ml)

Type of gas removed - 4 CZH,

Volume of gas removed (ml) - 98.5 - 68.1 = 30.4 68.1 - 45.9 = 22.2

Volume X of gas removed, on dry basis (a) - 22.2 - X 100 = 30.9 98,5 X 100 = 22.5

Volume of N, in sample (ml) 98.5 - 30.4 - 22.2 = 45.9 - -

Volume X of N, in original sample, on dry basis (%) = 46.6 - -

508

N,, CO,, and C,H,. Mercury was used to transfer the gases, and concentrated H,SO, was used to remove the C,H,. At the temperature of the test, the vapor pressure of H,O is 22 mm Hg. Atmospheric pressure was 750 mm Hg. Table A-I lists the given and computed values (values marked with an asterisk have been given, whereas the others have been computed).

Sample problem A-7

of this gas at 75 F and a pressure of 20 psig, if it is saturated with water vapor? A gas contains 22% C,H,, 16% CO,, and 8% 0,. The remainder is N,. What is the weight of 1 cu ft

Solution :

Component Vol. MW V o l % X M W

(a) 2 6 = 6.16 44 = 7.05 32 = 2.56 28 = 14.76 18= 0.2215

30.75 AMW

-4verage molecular weight = 30.75. p = 20 + 14.73 = 34.73 psia. Vapor pressure of H,O at 75 OF = 22 mm. Partial vapor pressure of water vapor = (22 X 14.73)/760 = 0.426 psi. Volume percent of water = 0.426/34.73 = 1.23%. Volume percent of N, = 54- 1.23 = 52.77%. One Ib-mole occupies 379 cu ft at standard conditions (14.7 psia and 60 F). 60° +460° = 5 2 0 ° R 7 5 O +460° =535OR Specific weight of gas, y, in Ib/cu ft, at standard conditions = (30.75 lb/mole)/(379 cu ft/lb mole) Correcting to new pressure and temperature (34.73 psia and 535 R). y, = (30.75/379) X(520/535)X (34.7/14.7) = 0.186 Ib/cu ft.

FREEZING POINT TESTS

Freezing point of fuels (ASTM D 2386-67)

The freezing point test is important because it shows the temperature at which solid particles begin to form in the fuel. In the case of aviation fuels, the freezing point shall not be higher than minus 76 F. The fuel usually becomes cloudy before formation of solid particles, but the clouding due to the freezing of the very small amount of dissolved water is disregarded.

Kqv point

into the test bottle. Formation of finely divided ice crystals will obscure the results.

Lowering of freezing point

(1) Great care must be exercised in avoiding introduction of moisture, even in very small amounts,

Inasmuch as the solvent in a solution has a lower vapor pressure than the pure solvent, a hgher tcrnperature must be reached before the vapor pressure of solution will reach any specified pressure.

509

- ATf

TEMPERATURE

Fig. A-13. Schematic diagram showing freezing point depression and boiling point elevation upon addition of solvent to a solution. AT, = increase of the boiling point temperature, AT, = lowering of the freezing point temperature, A = boiling point of the solvent, B = boiling point of the solution, C = freezing point of the solvent, and D = freezing point of the solution.

Thus, dissolving a non-volatile solute in a solvent will raise the boiling point. In the case of freezing a solution, the solution must be cooled down to some temperature below the freezing point of the pure solvent, until the vapor pressure curve for the solution intersects that for the solid solvent (see Fig. A-13).

For dilute aqueous solutions, the elevation of the boiling point (AT,) and the depression of the freezing point (AT,) are proportional to the molality of the solute molecules (or ions). The AT, and AT, do not depend upon the nature of the solute, unless it controls ionization. In the more concentrated solutions encountered in petroleum testing, the elevation of the boiling point and lowering of the freezing point are proportional to the mole percent of the solute.

The reason that these properties are proportional to the molality for dilute solutions is that the number of moles of solute/1000 g of solvent ratio is practically proportional to the mole percent of solute for dilute solutions.

Sample problem A-8 One ml of kerosine has been added to 10 ml of benzene. If the freezing point of benzene has been

lowered 2.2"C, what is the molecular weight of kerosine? Molecular weight of benzene is 78.1, the specific gravity of benzene is 0.879, specific gravity of kerosine is 0.799, and one mole of impurity lowers the freezing point of 1000 g of benzene 5 " C.

Solution : Mole percent impurity for 5OC lowering of freezing point = 100 X [l /( l + (1000/78.1)] = 7.25%. 78.1 = molecular weight of benzene and (1000/78.1) = moles of benzene in 1000 g. Mole percent impurity for 2.2" C lowering of freezing point = [7.25 X (2.2/5)] = 3.19%. 3.19% = [ N / ( N + moles of solvent)] X 100, where N = moles of impurity and the moles of solvent (benzene) = (10 X 0.879)/78.1 = 0.1125. Thus: 3.19 = [ N / ( N + 0.1125)] X 100; N = 0.00371. Inasmuch as 1 cc kerosine = 0.799 g + 0.00371 moles kerosine, molecular weight of kerosine = (0.799 x 1)/0.00371 = 215 g/mole. If formula of kerosine is CnHZn+,, then n = 15: 12 X n + l(2n + 2) = 215. Thus, the formula of kerosine in this case is C,,H,,.

Sample problem A-9

kg of H,O 1.6 O C. One mole of impurity lowers the freezing point 1.86 O C in 1000 g of H20 . What is the fraction dissociation a of H,C204, if 0.6 moles of H2C,04 lowers the freezing point of 1

510

. *\

Solution ;

H,C,O, +2H20+C202- +2H30f 0.6 - (0.6 X o() 0.6 X a 2(0.6 X a)

1 DRYER

I/ PUMP METER

: / 6 3 / 4 " PIPE

VACUUM

/I

Moles of material present = (0.6-0.6a)+0.60( + 1.2a = 0.6+1.2a (0.6+1.2a)/l= 1.6/1.86 and a = (0.86-0.6)/1.2 = (0.26/1.2) = 0.22.

How could one refine the above solution? Show calculations.

CHARCOAL TEST FOR GASOLINE CONTENT OF NATURAL GAS

The theory of charcoal test for gasoline content of natural gas is based upon selective adsorption of hydrocarbons by charcoal. Although this test was not used after the advent of the gas chromatograph, it is a very good experiment demonstrating basic principles to the students. It should be done in conjunction with the gas chromatograph experiment. This test usually measures iC, content of natural gasoline. The amount of gasoline is recorded as gal/Mcf of gas. Primary charcoal is prepared by heating wood in a closed space. Activated charcoal is then prepared by heating the primary charcoal in the presence of CO, to 900 OF. This creates a tremendous surface area: 20 acres/lb of charcoal in capillaries. One cc of activated charcoal can adsorb 60 cc of methane or 80-100 cc of NH,.

After opening the rate valve (see Fig. A-14), temperature is plotted against the volume of natural gas passed through the meter. Four maximums can be observed on this graph (Fig. A-15). Upon reaching the fourth maximum, the flow of natural gas is shut off, i.e., the test is carried only to the fourth temperature rise.

Upon adsorption on charcoal, the gas changes to a liquid, releasing the latent heat of vaporization. This heat raises the temperature of the charcoal and its surrounding media.

Upon completion of the test, the tube containing charcoal is subjected to (1) steam distillation or (2) distillation with diethylene glycol, having a boiling point of 472OF, or glycerine, with a boiling point of 554OF. These media have low boiling points so that the heavy ends of gasoline are not cracked. In addition, they are immiscible with gasoline.

CHARCOAL

RATE VALVE THERMOMETER-

Fig. A-14. Schematic diagram of charcoal test for gasoline content of natural gas.

' CNGA Bul. TS-351. Standard Procedure for the Charcoal Test for the Determination of the Gasoline Content of Natural Gas.

GAS, CUBIC FEET

Fig. A-15. Plot of temperature versus volume of natural gas passing through the charcoal tube

CHARFOAL

WATER BATH

I 32OF

30 psi0

8.

- Fig. A-16. Schematic diagram of 32-30 charcoal test.

There were two types of tests: (1) 32-30 test-where the water bath is at a temperature of 3 2 O F and the back pressure on the system is held at 30 psia (see Fig. A-16). (2) Rectified test-where the water bath temperature is 100 OF and the back pressure is 22 psia. Inasmuch as more vaporization occurs in the latter test, the gasoline content (gal/Mcf) is lower than in the case of the 32-30 test.

SAMPLE EXPERIMENTS

Experiment A-I: Distillation of gasoline, kerosine and benzene by Engler Flmk (ASTM D 86-82; 0216-77)

Instructions:

expected to run a sample of gasoline and kerosine.

Results:

The distillation test will be operated as described in the ASTM manual (D86-82). Each group is

Record all data and plot temperature versus volume distilled on graph paper.

Questions: (1) What does the ASTM distillation range indicate? (2) Discuss the storage and operational characteristics of a gasoline with varying initial and end

points.

512

(3) Considering this distillation as fractionation, how many theoretical plates are present in this

(4) Given an ASTM distillation curve, can one tell what compounds are present in a gasoline? How?

( 5 ) What corrections are to be applied to (a) the temperature data obtained in the experiment, and

(6) Butane (boiling point = 31 F) is known to be present in gasoline, yet the IBP obtained is 58 F.

(7) Draw three general type curves of temperature-composition diagrams for two-component sys-

experiment?

Why?

(h) the liquid volume data recorded for the experiment?

Why?

tems. Use solid lines for the liquids and broken lines for the vapors.

Experiment A-2: Distillation of crude oil with Hemple Column (ASTM D 285-62)

Instructions: Apparatus and procedures should conform to the ASTM standards. Distillation shall be discontinued

at 460 O F . Each group will run a minimum of two distillations on the same sample of crude oil. Exercise great care to obtain a representative sample.

Results: Volume of water, cc = -

Volume percent of naphtha, '% = -

Questions: (1) What does the ASTM distillation of a crude oil indicate? (2) With the information collected from this experiment, plot a distillation curve: temperature versus

percentage of sample distilled. From this curve, determine the content of naphtha having a boiling point range of - to -.

(3) What other fractions can one determine from this distillation curve? Explain! (See Nelson, 1950; Chapter MI).

Experiment A-3: Graviiy by hydrometer and vapor pressure by the Reid Bomb

Part I-Gravity by the hydrometer (ASTM D 287-82)

Instructions: Procure, assemble and operate the gravity test as described in the ASTM manual. Each group is

expected to run determinations at three temperatures on samples of gasoline, kerosine, and lubricating oil.

Duta:

Questions: (1) Report the obtained values in terms of specific gravity, Ib/cu ft, and Ib/gal. (2) What is the API gravity of water? Can a negative API gravity exist? (3) Name three different instruments that may be used to determine liquid densities. Explain how

each would work, directly or indirectly.

513

(4) Correction tables apply to petroleum products. How would one proceed in the case of benzene, toluene, and various nonpetroleum products?

Part 11-Vapor pressure by the Reid Bomb (ASTM D 323-82)

Instructions: Determine the vapor pressure of a given sample of gasoline according to the standards and

procedures set up in the ASTM manual. Each group is required to run one sample.

Questions: (1) What is the Reid vapor pressure of (a) butane and (b) pentane? (2) What is the Reid vapor pressure of 5% (by weight) addition of butane to a gasoline, the Reid

(3) Can the Reid bomb be used for measuring the true vapor pressure of a liquid? Why? vapor pressure of which is 0.2 psi?

Experiment A-4: Water in petroleum by distillation and water and sediments in petroleum by centrifugation (ASTM D 1796-83; D 4007-81; D 4006-81)

Part I-Water in petroleum by distillation (ASTM D 95-83)

Instructions:

Set up the equipment as instructed in the ASTM manual. Each group is expected to obtain a reliable check on the sample furnished as to percentage of water.

Results: Run No. 1 Run No. 2

Questions: (1) To what type of samples can this method be applied? (2) Why are distillation specifications of the solvent used given in great detail? (3) A 1000-bbl tank is equipped with three bleeders spaced equally over the height of the tank. A

sample of the crude is taken, one-third of the sample from each bleeder. Would this be a representative sample? Explain!

(4) What would happen if calcium carbide were placed in (a) wet petroleum and (b) dry petroleum? Write the chemical equations.

Part 11-Water and sediments in petroleum by centrifugation (ASTM D 96-73)

Instructions: Each group will make two determinations of the water and sediment content of the given crude oil

(emulsion). Results should compare within the limits specified by the ASTM manual. Take a representative sample.

Results: Run No. 1 Run N o . 2

Aug.

Questions:

manual? (1) What is the purpose of the benzene addition and the heating procedure described in the ASTM

514

(2) The volume percentage of sediment is desired for a very dark-colored gas oil. Outline in tabular

( 3 ) What force of gravity (number of “g’s”) was exerted by the centrifuge in this experiment? How

(4) Results are given in volume percentage of water. If the emulsion has an API gravity of 30 O , what

from (1) an approximate method, and (2) an exact method.

much would you weigh under these conditions? (Refer to Perry and Chilton Handbook.)

is the weight percent water?

Experiment A-5: Viscosity by Saybolt uiscosimeter (ASTM D 88)

Instructions:

not compare, make an additional determination. Be sure to obtain a representative sample. Two samples will be tested. Each sample will be run twice at 100 O and twice at 212O F. If results do

Results: Viscosity of sample No. 1 Viscosity of sample No. 2

sus sus

Questions:

Refer to the method of conversion presented in ASTM D 446. (Also see ASTM D 2161-82.) (1) Report the values obtained in both kinematic and absolute units (centistokes and centipoises).

(2) Check the above conversions using the following equations:

M / d = 0.226 f - 195/ t (for oils above 100 sec Saybolt or less)

and

M / d = 0.220 t - 1 3 5 / f (for oils above 100 sec Saybolt)

where: M = absolute viscosity, cP, d = density of oil at temperature of the test (100” -212O), and t = Saybolt seconds (Universal).

(3) Convert the values obtained at 212O F to temperatures of 100 O F , 140 O F, and 180 O F (see ASTM

(4) Determine the viscosity index of each oil tested (see ASTM D 567). For the low-viscosity oil, it

( 5 ) Define the term viscosity. (6) Describe two other methods of determining viscosity.

D 341-77).

may be necessary to use the centistoke table.

E.uperiment A-6: Flash and fire points by fag closed tester, by open cup, and by Pensky-Martens tester

Part I-Flash point by tag closed tester (ASTM D 56)

Instructions:

must be conducted under a firehood. Each group is expected to obtain and check results on a sample of kerosine and motor oil. All work

Results: Kerosine flash point Run no. 1 Run No. 2 Lubricating oil flash point Run No. 1 Run No. 2

515

Questions:

obtained by closed cup testing. Why?

and discuss them.

lubricating oil? Why?

(1) What relationship would one expect to be true of the results obtained by open cup and those

(2) How many methods of determining flash and fire points are discussed in the ASTM manual? List

(3) Which one of the following can be set afire with a match: (1) gasoline, (2) kerosine, and (3)

(4) Define kerosine, gasoline, and fuel oil.

Part 11-Flash and fire points by open cup (ASTM D92)

Instructions: Each group is expected to procure, assemble and operate the open cup tester as described in the

ASTM manual. Each group will obtain two readings of flash and fire points for kerosine, fuel oil, and lube oil. All work must be conducted under a firehood.

Results: Kerosine flash point Run no. 1 Run no. 2

Kerosine fire point Run no. 1 Run no. 2

Fuel oil flash point Run no. 1 Run no. 2

Fuel oil fire point Run no. 1 Run no. 2

SAE No. lube oil Flash point Fire point Run no. 1 Run no. 1 Run no. 2 Run no. 2

Questions: (1) Why is the determination of flash and fire points very important in the petroleum industry? (2) Suggest improvements in the open cup method of testing. (3) What relationship exists between the flash and fire points of petroleum materials and their boiling

(4) Enumerate the conditions that must exist at the time of a flash occurring above a liquid petroleum points?

product. Enumerate these conditions for a fire point.

Part 111-Flash point by means of the Pensky-Martin closed tester (ASTM D 93)

Instructions:

must be performed under a firehood. Each group is expected to obtain check results on a sample of kerosine and a motor oil. All work

Experiment A-7: Color of lube oil and cloud and pour points

Part I-Color of lube oil

Instructions:

ASTM manual for the darker oils, regardless of whether the oil has color above 8 (ASTM) or not. Each group will determine the color of several lube oils, as such, and diluted as described in the

516

Results.

Oil no. 1 Oil no. 2 Oil no. 3 ASTM color no. Diluted color no.

Questions: (1) What does the color of a lube oil indicate? Why? (2) Report your results in at least two other systems. (3) Describe all methods of determining the color of petroleum products. (4) How is the color of green lube oil determined?

Part 11-Cloud and pour points (ASTM D 97)

Instructions: Each group will determine the cloud and pour points of three oils.

Results:

Oil no. 1 Oil no. 2 Cloud point Pour point

Oil no. 3

Questions:

principles. (1) What does the cloud point indicate? Name one other ASTM method that depends upon similar

(2) What physical property of an oil does the pour point indicate? How else could it be determined? (3) Why are pour points important? (4) Explain why the “thermal history” of an oil sample affects its pour point. (5) Discuss dewaxing. How does it affect cloud and pour points?

Experiment A-8: Dilution of crankcase oil (ASTM D 322)

Instructions:

Two determinations will be made of the oil supplied. Each group of three to four students will assemble the apparatus as described in the ASTM manual.

Results: Run no. 1 Run no. 2 Average of two runs

Questions: (1) What does the dilution of crankcase oils indicate about engine performance? (2) Why is a time limit placed on this test? ( 3 ) Why the lube oil does not distill over into the trap? (4) Discuss the steam distillations in general. Give theoretical considerations. (5) Explain how the ASTM distillation test for water in petroleum products is analogous to the

ASTM distillation test for the dilution of crankcase oils. Give in each case the main reason why the liquid is added to the material being tested.

517

Experiment A-9: Orsat analysis of a mixture containing oxygen

Instructions:

provided. Each group will make four complete analyses, two on the atmosphere and two on the sample

Results:

Atmosphere Sample no. 1

no. 1 no. 2 no. 1 no. 2 Volume 0 of CO, Volume B of 0, Volume B of N,

and H ,O vapor

Questions: (1) Report the average of the results for each gas in weight percent. (2) Report the above in mole percent. (3) Report the above in mole percent on a dry basis, assuming that the relative humidity of both

(4) Report the analysis for both of the above samples on a dry, C0,-free basis. (5 ) Calculate the average molecular weight of each sample and determine the weight of the gas in

samples is loo%, and that the humidity remained constant throughout the test.

pounds per cubic foot, cubic yard, and cubic mile.

Experiment A-10: Orsat analysis of a gas mixture containing an olefin

Instructions: Each group is expected to run three complete analysis of the given sample.

Results:

Sample

no. 1 no. 2 no. 3 Volume 5% C,H, Volume B CO, Volume B 0, Volume 8 inerts Totals

Questions: (1) Are the inerts present in the gas sample essentially nitrogen? (2) What reagent can be used to remove acid gases from a gas mixture in an Orsat apparatus? (3) How can oxygen be removed? (4) Discuss in general the removal of unsaturated hydrocarbons from a gas mixture.

Experiment A-11: Orsat analysis of a mixture coniaining hydrogen and carbon monoxide

Instructions: Each group will analyze the sample three times.

51 8

Results:

no. 1 no. 2 no. 3 Volume % CO, Volume % 0, Volume % H, Volume % CO Volume % inerts

Questions:

should be taken? Write equations. (1) Discuss the analysis of gas mixtures containing H, by the Orsat apparatus. What precautions

(2) Repeat the above for CO. (3) Discuss the order of removal of various gases in the Orsat procedure. (4) How is the proportion of water vapor in the air determined on using Orsat analysis. ( 5 ) Rearrange the following gases in the order of their removal in the Orsat apparatus together with

the name of the solution used for removal of each: O,, N,, CO,, H,S, C,H,.

Experiment A-12: Solidifying point of benzene (ASTM D 852) and determination of molecular weight from lonering of freezing point of benzene

Instructions: Apparatus will be assembled according to the instructions in the ASTM manual. Each group is to

check the freezing point (F.P.) of (1) pure benzene, (2) 10 cc of benzene plus 1 cc of kerosine, and (3) 10 cc of benzene plus 1 cc of lube oil.

Calculate the average molecular weight of kerosine and lube oil, knowing that pure benzene freezes at 5.51O C (dry) and that 1 gram-mole of impurity in 1000 g of benzene lowers the freezing point by 5.0" C.

Results: (a) F.P. of benzene: (b) F.P. of (10-1) benzene-kerosine: (c) F.P. of (10-1) benzene-lube oil: (d) Average molecular weight of kerosine: (e) Average molecular weight of lube oil:

Questions:

progressively until it is all solid, and (b) an impure compound.

an impure compound.

compound present in each?

(1) Draw schematic diagrams of the temperature versus time for (a) a pure compound frozen

(2) Explain each significant slope and maximum and minimum points shown on the freezing curve of

(3) If kerosine and lube oil are completely paraffinic in nature (CnH2,,+,), what is the average

(4) What is the estimated error in determining the freezing points?

Experiment A - I 3: Corrosion - electromotive series and galvanic corrosion ' The experiment will consist of the following parts: (1) A strip (1 in. by 6 in.) of zinc will be immersed in 10% HCI. Observe and explain all the reactions

and corrosion.

' See La Que et al. (1961).

519

TABLE A-I1

Electromotive force series

Electrode reaction Standard electrode potential, E O

(Volts, 25 O C)

Li = Li+ + e- + 3.05 K = K + + e- + 2.922 Ca = Ca2+ +2e- + 2.87 Na = N a + + e- + 2.712 Mg=MgZS+2e- + 2.375

A1 = A13+ + 3e- + 1.67 Mn=Mn2++2e- + 1.029 Zn = Zn'+ +2e- + 0.762 Cr = Cr3+ +3e- + 0.74 Ga = Ga3+ + 3e- + 0.53 F e = F e 2 + + 2 e - + 0.440 Cd = Cd2+ i 2 e - + 0.402 In = h3+ + 3e- + 0.340 T1= Tl++ e- + 0.336 co = Co2+ +2e- + 0.277 Ni = NiZ+ +2e- + 0.250 s n = s n 2 + + 2 e - +0.136 ~b = pb2+ +2e- + 0.126

0.000 cu = Cu2+ +2e- - 0.345 Cu = Cu+ + e- - 0.522 2Hg = H g i + +2e- - 0.789 Ag = Ag+ + e- - 0.800 Pd =Pd2++2e- - 0.987 H g = H g z + + 2 e - - 0.854

Au = Au3+ +3e- Au = Au+ + e-

Be=Be2++2e- + 1.85

H, = 2H+ + 2e-

Pt = Pt*+ +2e- ca. -1.2 - 1.50 - 1.68

(2) A strip of iron (or carbon steel) will be immersed in 5% CuSO, solution (use 250 ml of solution in

(3) A strip of copper will be immersed in 10% HCl. Observe all reactions and explain. (4) A strip of copper will be immersed in 5% AgNO, solution. Observe all reactions and explain. (5) Strips of aluminum and zinc will be immersed in 3% NaCl solution and then connected to a

millivoltmeter (0 to lo00 mV DC) without wetting the wires. Record voltage for a period of 15 min and explain the indicated voltages.

(6) Strips of copper and zinc will be immersed in 3% NaCl solution and then connected to a millivoltmeter. Record voltage for a period of 15 min and compare with the results obtained in (5 ) . Explain.

400-ml beaker).

Question (see Table A-ZZ):

evolution? Why? Complete the following reactions in aqueous solutions. In which case will there be more hydrogen gas

520

Ca+Zn2++?

Ca+Pb2++?

Zn + Mg2+ + ?

REFERENCES

ASTM Committee D-2 on Petroleum Products and Lubricants, 1951. The Significance of Tests of

ASTM Standards, 1984. Annual Book, Petroleum Products, Lubricants, and Fossil Fuels, Sec. 5, Vols.

Bertness, T.A. and Chilingarian, G.V., 1984. Corrosion in drilling operations. In: G.V. Chilingarian and

Bureau of Naval Personnel, 1955. Fundamentals of Petroleum. NAVPERS 10883, 190 pp. California Natural Gasoline Association, 1947. Tentative Standard Procedure for the Charcoal Test for the

Chilingar, G.V., 1956. The Technology of Testing Petroleum Products. U.S.A.F. Publ., 70 pp. Ethyl Corporation, 1951. Aviation Fuels and Their Effect on Engine Performance. NAVAER-06-5-501,

LaQue, F.L., May, T.P. and Uhlig, H.H., 1961. Corrosion in Action. International Nickel, New York,

Matuszak, M.P., 1954. Gas Analysis Manual. Fisher Scientific, Pittsburgh, Penn. Nelson, W.L., 1950. Petroleum Refinery Engineering. McGraw-Hill, New York, N.Y., 715 pp. Perry, R.H. and Chilton, C.H., 1973. Chemical Engineers’ Handbook. McGraw-Hill, New York, N.Y., 5th

Tchillingarian (Chilingar), G.V. and Beeson, C.M., 1952, 1958. The Technology of Testing Petroleum

Petroleum Products. ASTM, Philadelphia, Pa., 76 pp.

05.01 through 05.04. ASTM, Philadelphia, Pa.

P. Vorabutr, Drilling and Drilling Fluih. Elsevier, Amsterdam, pp. 559-580.

Determination of the Gasoline Content of Natural Gas. CNGA Bull. TS-351, Long Beach, Calif.

USAF T.O., No. 06-5-4, 145 pp.

N.Y., 47 pp.

ed.,

Products. Univ. Southern California, Pet. Eng. Dep. Publ., 65 pp.; 74 pp.

521

Appendix B

CONVERSION OF UNITS

JOHN 0. ROBERTSON Jr. and GEORGE V. CHILINGARIAN

THEORETICAL ASPECTS

Conversion of units of time and length are simple. For example, 1 year (calendar) = 365 days (mean solar) = 525,600 minutes (mean solar) = 3.1536 X lo7 seconds (mean solar), and 1 yard = 3 feet = 36 inches = 91.44 centimeters.

The units of force and mass, however, are not as easily converted and understood. The earth exerts a gravitational force on all bodies. The magnitude of this force, called weight, is equal to the mass of the body multiplied by the gravitational acceleration, or

F = mg

where: F = weight or force in pounds, m = mass of the body in slugs, g = gravitational acceleration, which at sea level is about 32.2 ft/sec2.

For example, the density (mass per unit volume), p , of water having a specific weight, y , of 62.4 lb/cu ft is

62.4 Ib/cu ft

32.2 ft/sec2 P=Y/g= = 1.94 slug/cu ft

In the opinion of the writers, it is critical to use different terms for the specific weight, y , and for the density, p .

EXAMPLE 1: DYNAMIC VISCOSITY CONVERSION FACTOR

Dynamic or absolute viscosity, p, may be defined as the (shearing stress)/(rate of shearing strain) ratio assuming a linear distribution of velocity between two plates (one plate moving with respect to the other) with fluid in between:

r p = - -

V / h

where: F = the force required to maintain flow (to slide the fluid layers relative to each other, which is accomplished by overcoming the internal fluid friction), A = area of the moving plate in contact with the fluid, Y = velocity of upper plate if lower plate is stationary, h =distance between the two plates, r = shearing stress or F / A .

522

The symbols, M, L, F , and T represent the fundamental dimensions of mass, length, force, and time, respectively; thus:

Inasmuch as force equals mass times acceleration [ F = ( M L / T 2 ) ] , the dimensions of dynamic viscosity are

Thus, dynamic or absolute viscosity can be expressed in Ib-sec/ft2 or slug/ft-sec, whereas in the metric system:

1 (dyne-sec/cm2) = l(g/cm-sec) = 1 poise

Inasmuch as 1 in. = 2.54 cm and 1 dyne = 2.248 X 10K6 Ib,

I poise = 1 ( dyne-sec/cm2 )

dyne(2.248 X lb/dyne) sec

cm2 [(2.54X12)2ft2/cm2]

= 2.089 x 10- (Ib-sec/ft2 )

= 2 . 0 8 9 ~ 10~3(slug/ft-sec)

‘The absolute viscosity of water at 20 C is around 1 centipoise, which is equal to 0.01 of a poise, named in honor of the French scientist Poiseuille.

EXAMPLE 2: DETERMINATION OF MULTICOMPONENT CONVERSION CONSTANTS

When handling equations using field or laboratory data, it is often easier to develop one constant rather than convert each constituent individually. The following example is the determination of the constant for Darcy’s law equation when information is given as follows:

where permeability, k , is in darcys; pressure drop, A p , is in inches of mercury instead of atm; cross-sectional area, A , is in square inches instead of cm2; viscosity, p , is in poises instead of centipoises; length, L, is in yards, instead of cm; and volumetric rate of fluid flow, q, is in quarts per minute instead of cm3/sec.

From the conversion tables:

1 qt = 946.3529 cu cm 1 min = 60 sec 1 poise = 100 CP

1 sq in. = 6.4516 sq cm 1 yd = 91.44 cm 1 in. Hg = 0.0334211 atm

523

Thus:

(qt) (946.3529 cm3/qt)

(min) (60 sec/min) 4 =

(in. Hg) (0.033421 1 atm/in. Hg) (in. ) (6.45 16 cm*/in.’ ) (poises) (100 cP/1 poise) (yd) (91.44 cm/yd)

= (constant)

Solving for the constant gives

(0.0334211)(6.4516) (60)

(100) (91.44) (946.3529) constant = = 1.49x 10-6

If conversion from in. Hg to atmospheres was not given, then the following information should have been given: (a) specific gravity of Hg, and (b) 1 atm = 1033 cm of liquid having density of 1.00 g/cm3.

524

CONVERSION FACTORS

Multiply + by --* To obtain To obtain t by t Divide

abampere abcoulomb abfarad abhenry abmho abohm abvolt acre, U.S. Survey

acre-foot (acre-ft)

ampere-hour (amp-hr) are

angstrom astronomical unit atmosphere, standard

( a t 4

bar

barn barrel, petroleum (bbl)

barrel, U.S., dry

barrel, U.S., liq.

1 1 1 1 1 1 1 4.046856 4.3560 6.272640 1.5625 4.840 1.233482 4.3560 1.613333 3.259 3.6 1 2.471054 3.861022 1 1.49599 1.013250 1.013250 1.6 1.03326 3.38995 3.3941 1.46960 1 9.86923 1 1.45038 1 1.589828 5.614583 4.2 1.589828 1.156271 9.696969 4.083333 1.192405 1.03125 4.210938

x 1 0 * x 1 0 * x 109 ~ 1 0 - 9 x 109 x 10-9 x10 - * x l o 3 x i 0 4 x 106 ~ 1 0 - 3

x l o 3 x l o 3 x104 x l o 3 x l o 5 x l o 3 x 102 x10-2 x 10-5 x 1 0 - ' O x 10" x 105

x 103 x 1 0 *

x 1 0 * x 1 0 * x 1 0 * x 105 x10-' x 106 x 1 0 * x10-28

x10-'

x 1 0 * x l o 2 x10-1 x10- '

x10- '

coulomb f H siemens O h m

sq m sq ft sq in. s q mi (statute)

sq Yd cu m cu ft cu yd gal (U.S., liq) coulomb

s q m acre sq mi m m Pa bars cm of Hg at 0 O C cm of H,O at 4°C f t of H 2 0 at 39.2OF ft of H,O at 62O F psi Pa atm dynes/sq-cm psi

sq cu m cu ft gal ( U S , Sq) 1 c u m bbl (U.S., liq.) cu ft cu m bbl (U.S., dry) cu ft

V

* The appropriate "SI" units are the first conversion, given. The abbreviations used here are those presented in the Hundbook of Chemistty and Physics (1980-1981).

525

CONVERSION FACTORS ' (continued)

Multiply -9 by + To obtain To obtain c by t Divide

barrel per hour, oil

board foot (fbm)

British thermal unit, thermochemical (Btu)

British thermal unit, thermochemical, per minute (Btu/min)

buckets, Brit.

bushels, Brit. (bu, Brit.)

bushels, U.S. (bu, U.S.)

butts, Brit.

caliber, inch calorie, gram-

thermochemical (cal, g)

carat, metric cental

centare

centimeter (cm)

centimeter-dyne (cm-dyne)

centimeter-gram (cm-g)

4.41618 9.36 7 2.359737 8.333333 1.44 1.05435 1.05418 1.05587 1.054350 2.519958 2.50201 3.92752 1.054350 1.75725 2.51996 2.35651 1.818435 4 3.636870 1.032056 3.523907 1.244456 3.523907 3.2 4.769619 1.684375 1.26 2.54 4.184 9.99346 9.98563 3.968321 4.184 4.184 2 4.535923 1 1 1.0763910 1 3.937008 3.280840 1 1.019716 7.375562 1 7.233014

x 1 0 r 5 x10-2 x10- ' x ~ o - ~ x 10-2 x 102 x 10'0 x 103 x103 x 103 x 102 x 104 x x 103 x 10' x10- ' x10-2 x 10-2

x 10-2

x 10-2

x 10' x 10' x10- ' x 10' x 102 x10-2

x 10-1 x10- ' x ~ o - ~ x 107

x ~ o - ~ x 10' x 102

x 10' x10-2 x10- ' x 10-2 x x 10-8 x 10-8 x ~ o - ~ x ~ o - ~

cu m/sec cu ft/min gal/min cu m cu ft cu in. ergs J (Int.) J (mean) J (thermochemical)

ft-poundals hp-hr w-sec

cal, kg/min hP cu m gal (Brit.) cu m bu (U.S.) cu m cu ft 1 qt (U.S., dry ) cu m cu ft gal (U.S.) m J

cal, g(mean) Btu ergs w-sec kg kg

cal, g

W

cal, g(IST)

Ib s q m

m in. ft mu m-kg

m-kg

sq ft

lb-ft

Ib-ft

526

CONVERSION FACTORS (continued)

Multiply + To obtain t

by + To obtain by t Divide

centimeter of mercury at 1.33322 X103 Pa 0 ° C (cm of Hg @ 0°C) 1.315789 X atm

1.33322 X 1 0 4 dynes/sq cm 3.937008 X lo- ' in. of Hg, 0 " C 4.46474 X 10 ' ft H 2 0 (60 " F)

centimeter of water at 4 ° C (cm H,O @ 4°C)

centimeters per second (crn/sec)

centimeters per second per second (cm/sec2)

centipoise (cP)

centistokes chain, Gunter's

circle (cir)

circular mil (cir mil) clo cord (cd)

cubic centimeter (cu crn)

cubic centimeter per second (cu cm/sec)

cubic foot (cu ft)

cubic foot of water (cu ft of H,O @ 39.2O F)

1.93368 9.80638 9.67814 1.42229 1 1.968504 3.280840 1.034646 2.834646 2.236936 3.728227 1 3.6 2.236936 1 2.419088 6.71969 1 2.01168 6.6 6.6 1.25 6.283185 3.6 4 2.16 5.067075 2.003712 3.624573 1.28 1 3.531467 6.102374 1.307951 2.641720 1 .o 1 2.118880 1.585032 2.8316847 2.2956841 1.728 7.4805195 2.831685 9.575065 2.98898 6.24262

x10-I x 10' x ~ o - ~ x 10-2 x 10-2

x10-2 x 10' x 103 x 10-2 x ~ o - ~ x 10-2 x10-2 x 10-2 x ~ o - ~

x x10-6 x 10' x10-1 x 10' x 10-2

x 102 x 102 x l o 4 x 10-10 x 10-1

x 102 x10-6 x 1 0 - 5 x 10-2 x10-6 x ~ o - ~ x ~ o - ~ x 10-6 x ~ o - ~ x10-2 x10-2 x 1 0 - 5 x 103

x 10' x 102 x 1 0 3 x 10'

psi Pa atm psi m/sec ft/min ft/sec

ft/day mi/hr mi/min m/sec2 km/(hr-see) mi/(hr-sec) Pa-see lb/(ft-hr) Ib/(ft-see) sq m/sec m chain (Ramden's) ft mi (statute) rad

grades min (angular) sq m Kelvin m2/watt [(K-m2)/w] cu m cu ft cu m cu ft cu in. cu yd gal (U.S. liq.) 1 cu rn/sec cu ft/min gal (U.S., liq)/min cu m acre-ft cu in. gal (U.S., liq) 1 oz (U.S., liq) Pa Ib of H 2 0

ft/yr

deg



by + To obtain by t Divide

cubic foot of water (cuftof H,O@6O0F)

cubic foot per hour (cu ft/hr)

cubic feet per minute (cu ft/min)

cubic inch (cu in.)

cubic inch of water at

cubic inch of water

cubic meter (cu m)

4O C (cu in. H,O @ 4O C)

at 60° F (cu in. H,O @ 69OF)

cubic yard (cu yd)

cubit

CUP day, mean solar

(d, solar)

day, sidereal (d, sidereal)

decistere degree, angular (deg)

demal denier drachm (Brit., liq)

dram, avdp (dr)

2.986112 6.23663 7.4805195 8.466667 2.295684 7.865791 7.480520 2.831605 4.119474 1.377410 7.480520 4.119342 1.6387064 1.6387064 5.7870370 2.143347 1.638706 2.490792 3,61263 2.4884 3.61263 8.107132 1 3.531467 6.102374 2.64112 1 .o 7.645549 2.1 2.019740 1.64555 4.572 1.5 1.8 2.365882 8.64 2.4 2.7397260 2.7378031 2.7379093 8.616409 8.6400 1 1,745329 2.7777 6 1.11111 3.6 1 1.111111 3.551631 2.167338 1.771845 4.557292 2.734375 5.69661 6.25

x 103 x 10'

x ~ o - ~ X ~ O - ~

x 10' x l o r 4 x ~ o - ~

x lo-' x 1 0 - ~ x 10' x 1 0 - ~ ~ 1 0 ~ xlo-2 X102 x10-2 X l O '

x l o r 2 x x 106 x 10' x 104 x 102 x 103 x10- ' x 10' x l o2 x 102 x10-'

x 10' x ~ o - ~ x l o4 x 10' ~ 1 0 ~ ~ x1or3 x ~ o - ~ x l o4 x 104 x10- ' x10-2 x ~ o - ~ x 10' x10-2 x lo3

x lo-' x l o r 6 x lo-' x 1 0 - ~ x lo-' x10-' x 10-2 x10-2

Pa Ib of H,O gal (U.S., liq) m/sec acre-ft/hr cu cm/sec gal (US., liq)/hr l/hr cu m/sec acre-ft/hr gal (U.S., liq)/min l/sec cu m cu cm cu f t cu yd 1 Pa lb H 2 0 Pa lb H,O acre-ft cu cm cu ft cu in. gal (US., liq) 1 cu m cu f t gal (U.S., liq) 1 m ft in. cu m sec (mean solar) hr (mean solar) yr (calendar) yr (sidereal) yr (tropical) sec (mean solar) sec (sidereal) cu m rad cir min (angular) quadrants sec (angular) g-eqiv/cu dm

kg/m cu m cu in.

kg dr (troy or apoth) grains oz (troy or apoth) oz (avdp)


Multiply + by + To obtain To obtain + by t Divide

dyne 1 x1or5 1.573663 X l O - *

dyne per square centimeter (dyne/sq cm)

electron volt

ells

erg

erg per second (erg/sec)

erg-second (erg-sec) fathom (fath)

Firkin (US.)

foot (ft)

foot, US. Survey

foot of air (1 atm, 60 F)

foot of mercury (ft Hg, 32 O F )

foot of water ( f t H20,4"C)

foot per hour (ft/hr)

1.019716 7.233014 2.248089 1 9.86923 1 7.50062 1.01 9745 4.666451 1.450377 1.60219 1.60219 1.143 4.5 1 9.48451 2.39006 2.373036 9.86895 1 5.69071 1.43403 4.42537 1.34102 1 1.50932 1.8288 6 9.87473 1.136363 4.0914 2.857143 1.203 125 8.326747 3.406775 3.048 9.99998 3.048 1.89393 3.048006 1.000002 3.656109 3.6083 5.3027 4.063665 5.89385 2.98898 2.94990 4.33515 8.466667 3.048 5.08 1.89393 5.260943

x ~ o - ~ x1or5 x 10-6 x10- ' x 1 0 - ~ x 10-6 x x l o r 3 x 1 0 - ~ x ~ o - ~ x ~ o - ' ~ x10-'2

x 10' x ~ o - ~ x10- " x 10-8 x l o r 6 x10-'O x ~ o - ~ x 1 0 - ~ x 10-6 x 10-6 x 10-10 x 1 0 - ~ x 1026

x 1 0 - ~ XIO-~

X102 x10- '

x lo - ' x 10' x10- ' x lo- ' x 10' x 1 0 - ~ x10- '

x 10-8 x10P x10r4 x l o 4

x l o 3 x10-2 x10-1 x ~ o - ~ x 10' x lo- ' XIO-~

x10-*

N grains

g poundal Ib Pa atm bars cm Hg, 0 ° C cm H20, 4OC poundal/sq in. lb/sq in. J ergs m in. J Btu cal, g ft-poundals I-atm

Btu/min cal, g/min ft-lb/min

J/sec Planck's constant m ft mi (naut., Int.) mi (statute) cu m bbl (U.S., Sq) cu ft Firkin (Brit.) 1 m ft (U.S. Survey) em mi (statute) m f t Pa atm psi Pa psi Pa atm psi m/sec cm/hr cm/min mi/hr mi/sec

W

hP

529


Multiply + by + To obtain To obtain t by t Divide

foot per minute (ft/min) 5.080 x 103 3.048 x 10'

foot per second (ft/sec)

foot per second per second (ft/sec2)

foot-poundal (ft-poundal)

foot-pound (ft-lb)

foot-pound per hour (ft-lb/hr)

furlong

free fall, standard (g)

gallon, US., liq (gal)

gallon (U.S., liq)

gallon (US., liq) per day (gal/day)

per min (gal/min)

gamma

geepound

gill (U.S.)

1.136363 3.048 1.8288 6.818182 3.048 6.818182 4.2140110 3.99678 1.00717 1.355818 1.28593 3.2408048 5.0505 3.766161 2.14321 5.050505 2.01168 6.6 1.25 9.806650 3.21725 3.785412 3.068883 3.174603 2.380952 3.785412 1.336805 2.31 8.326747 8.593670 3.785412 1.28 8 4 4.381264 5.570023 6.309020 2.228 6.309 1 1 1.45939 1 1.182941 7.21875 3.125 8.326747 1.182908

x 10-2 x10-1 x103 x10-1 x l o - ' x lo-' x 10-2 X ~ O - ~

x 10-2

x ~ o - ~ x 10-1 x ~ o - ~ x l o r 4 x 1 0 - ~ x1or7 x 102 x 102 x10- '

x 10' x1or3 x 10-6 x 10-2 x 10-2 x 103 x10- ' x 102 x10- ' x 10-1

X l O *

x 10-8 x 10-2 X ~ O - ~

x ~ o - ) x 10-2 x ~ o - ~ x 10-6 x 10'

x 1 0 - ~

x 10-2 x 10-1 x 10-1

m/sec cm/min

m/sec cm/min mi/hr m/sec mi/hr-sec J Btu cal, g J Btu

mi/hr

c 4 g hp-hr W

Btu/min

m f t mi (statute) m/sec2 ft/sec2 cu m ac-ft bbl (U.S., liq) bbl (petrol) cu cm cu ft cu in. gal (Brit.) gal (U.S., dry) 1 oz (U.S., liq) pt (U.S., liq) qt (U.S., liq) cu m/sec cu ft/sec cm m/sec cu ft/sec l/sec

g

hP

kg

kg slug cu m cu in. gal (U.S., liq) gills (Brit.) 1

530


Multiply --* by + To obtain To obtain t by c Divide

grades (grad) 1.5707963 X l O - ’ 9 x 10-1

grain, avdp

grains/gal (U.S., liq)

gram (€9

gram per cubic centimeter (g/cu cm)

grams per liter (g/l)

gravitational constants

hands (g)

hectare (ha)

hectogram (hg)

hectoliter (hl)

hectometer (hm)

hogshead (hhd)

2.5 x ~ o - ~ 2.5 x 1 0 r 3 5.4 x 10’ 6.479891 X

3.239945 X l o - ’ 6.3546 X10’ 2.0833 X10-3 1.711806 X10-2 1.711854 X10’

1.428571 X l o 2

5 9.80665 X102 3.2150737 X

3.5273962 X l o 2 7.09316 X l O - ’

2.6792289 X l o - ’ 2.2046226 X low3 7.7161792 X l o - ’

9.80665 X102 1.16236 6.2427961 X 10’ 3.6127292 X10W2 8.3454044

1 x ~ o - ~

1 x 103

1 .o x 106 1 x 10’

6.242621 X

8.345171 X10W2 9.806650 3.21725 X10’

4

2.471054

1.016 x 1 0 - ’

1 x l o 4

1 x 102 1 x 108 1.076391 X lO’

3.8610216 X l o - ’

2.679229 X l o - ’ 1.00028 X l o - ’ 3.531566 2.641794 X 10’

3.280840 X l o 2 2.384809 X l o - ’ 8.421875

2.384743 X l o 2

1 x10-I

1 x 102

6.3 x 10‘

rad deg (angular) cir circumference min (angular) kg carats (metric) dynes oz (apoth or troy) kg/cu m parts/million (based upon

lb/million-gal kg carrot (metric) dynes oz (apoth or troy) oz (avdp) poundals lb (apoth or troy) Ib (avdp) scruples kg/cu m dynes/cu cm poundals/cu in. Ib/cu f t lb/cu in. lb/gal (U.S., liq) kg/cu m parts/million (based upon a

lb/cu ft lb/gal (U.S., liq) m/sec2 ft/sec2 m in. sq m acre ares sq cm sq ft sq mi

kg

density of 1 g/ml)

density of 1 g/ml)

Ib (apoth or troy) cu m cu ft gal (US., liq) m f t cu m cu ft gal (U.S., liq) 1

531


Multiply -+ To obtain c

horsepower, boiler (hp, boiler)

horsepower, electrical (hp, elect)

horsepower, metric (hp, metric)

horsepower, mechanical (hp, mechanical)

horsepower, water (hp, water)

horsepower, U.K.

hour, mean solar (hr) (hp, U.K.)

hour (sidereal)

hundredweight, long

hundredweight, short

inch (in.)

(cwt)

inch of mercury, 32 " F (in. Hg (@ 32" F)

inch of mercury, 60 F (in. of Hg @ 60 " F)

inch of water at 4 " C (in. H20 (@ 4OC)

inch of water at 60 " F (in. H20 @ 60 " F)

by by

9.80950 1.31548 4.34107 7.460 1.0004 5.50221 7.35499 9.86320 5.42476 7.456999 2.54248 6.41616 7.457 5.50 7.60181 9.99598 1.01381 7.46043 1.00046 5.502533

7.4570 3.6 4.166667 6 3.609856 5.952381 3.590170 4.166667 4.1552899 9.9726957 5.080235 1.12 4.5359231 1 2.54 2.54 8.33333 2.11771 3.38638 3.34211 1.132957 7.07262 3.37685 3.33269 7.05269 2.49082 2.4582 3.612628

2.4884

+ To obtain t Divide

x 103 W

x 10' hp (mech) x 105 ft-lb/min

hp (mech) x 102 W

x 102 ft-lb/sec x 1 0 2 W

x lo-' hp (mech) x 102 ft-lb/sec x 102 W

x l o 3 Btu (mean)/hr x l o5 cal, g/hr x 109 erg/sec x 102 ft-lb/sec x hp (boiler) X lo-' hp (electric)

hp (metric) x 102 W

hp (mech) x 102 ft-lb/sec

x 102 x 103 x 10-2 x 10' x l o3 x ~ o - ~ x lo3 x 1 0 - 2 x10-2 x 10-1 x 10' x 1 0 2 x 10' x 102 x 10-2

x 108 x 1 0 - 2 x 1 0 - 2 x 103 x 10-2

x 10' x 103 x 10-2 x 10' x 102 x ~ o - ~ x 1 0 - 2

W

sec (mean solar) days (mean solar) min (mean solar) sec (sidereal) week (mean calendar) sec (mean solar) days (sidereal) days (mean solar) hours (mean solar)

kg lb (avdp)

kg Ib (avdp) m A f t

Yd Pa atm ft of H20 @ 39.2" F PSf Pa atm

Pa atm psi

PSf

x 1 0 2 Pa

532


+ t

Mu1 tiply + by To obtain t by

inch per hour (in./hr) 7.056 x 10-6 8.33333 X

1.578282 X lo-' inch per minute (in./min)

joule, absolute (J, abs.)

joule, International

joule per second,

kayser Kelvin ( K) kilderkin, Brit.

(J, Int.)

absolute (J/sec)

kilocalorie, Intl. (kcal, Intl.)

kilocalorie, mean (kcal, mean)

kilogram (kg)

kilogram per cubic meter

(kg/cu m)

kilogram per square centimeter (kg/sq cm)

kilopond kilowatthour (kw-hr) kip

kip per sq in. knot. Intl.

last, Brit. league, Intl., nautical

4.233333 X

5 9.46969 X10-4 1 9.48451 X

2.39006 XlO- '

2.37304 X10' 7.37562 X lo-' 3.72506 X lo-' 9.99835 X lo-'

1 x 10’

1.000165 5.69071 X lo-' 1.34102 X low3 1 x 102 T, = TK - 273.15 8.182957 X10-' 4.99355 x103 1.8 x 10’ 4.1868 X103 9.992315 X lo-'

4.19002 X103 1 9.80665 XIOs 3.215074 X 10' 7.093163 X 10' 2.679229 2.2046226 1 6,242796 X lo-' 3.612729 X lo-' 9.80665 9.67841 X lo-' 9.80665 X10-' 1.422334 X 10' 9.80665

4.448222 X103

6.894757 X lo6 5.14444 X10-' 6.076115 X lo3 1 1.150779 2.909414 5.5560082 X lo3 1.150779

3.6 x 106

1 x 103

To obtain Divide

m/sec ft/hr

mim m/sec ft/hr mi/hr J Btu

ergs ft-poundals

cal, g

ft-lb hp-hr J (Int.)

J (abs.) Btu/min hp (mech)

I/m " C cu m cu in. gal (Brit.) J kcal (mean)

J kg dynes oz (apoth or troy) poundals Ib (apoth or troy) lb (avdp) kg/cu m lb/cu ft Ib/cu in. Pa atm bars psi N J N lb Pa m/sec ft/hr mi (nautical Intl.)/hr mi (statute)@ cu m m league (statute)

533


M i tiply + by + To obtain To obtain t by t Divide

league, statute 4.828032 x 10'

light year

link, Gunter's (li, Gunter's)

link, Ramden's (li, Ramden's)

liter (1)

liter per minute (l/min)

liter-atmosphere (1-atm)

Maxwell

meter (m)

meter per hour (m/hr)

meter per minute (m/min)

mho micron (pm)

mil mile, Brit., nautical

mile, Intl., nautical

mile, Intl.

mile, statute (mi)

2.64 1.584 8.689762 3 9.46055 6.32795 5.87851\ 2.01168 6.6 1.25 3.048 1 1.5151515 1 3.5 3 1466 6.102545 2.641720 3.381402 1.666667 3.531470 2.641723 1.01328 9.61045 2.42179 7.47356 1 3.335635 1 9.9967 3.280839 3.937008 6.213712 2.777778 3.280840 6.213712 1.666667 5.468066 3.728227 1 1 1 3.28084 3.93701 2.54 1.853184 1.151515 1.852 1.150779 1.609344 1.0000273 1.6093 5.28 6.336

x103 x l o 4 x10-1

x 1015 x l o 4 x 10'2 x lo-' x 10-1 x 1 0 - ~ x10-1

x ~ o - ~ x 10-2 x 10' x10-1 x 10' x1or5 x 10-2 x 10-1 x 102 x 10-2 x 10' x 10' x 10-8 x10-"

x 10-1

x 10' x ~ o - ~ x 1 0 - ~

~ 1 0 : ~ x 10-2 x10-2 x10-2

x10-6 x l o 4 x10-6 ~ 1 0 - 5 x ~ o - ~ x l o3

x l o3

x lo3

x lo3 x lo3 x 104

1.70111 X

m fath ft leagues (nautical, Intl.) mi (statute) m astronomical units mi (statute) m ft mi (statute) m f t li (Gunter's) cu m cu ft cu in. gal (U.S., 1;s) oz (U.S., liq) cu m/sec cu ft/min gal (U.S., liq)/min J Btu cal, g ft-lb Weber E.S. cgs units line maxwells (Intl.) ft in. mi (statute) m/sec ft/hr

m/sec ft/sec mi (statute)/hr siemens m

ft in. m m mi (statute) m mi (statute) m mi (statute) m ft in. light year

mi/hr

A

5 34



mile per hour (mi/hr)

millibar

milliliter (ml)

millimeter (mm)

millimeter of mercury at 0 C (mm Hg @ 0 C )

minim (Brit.)

minim (US.)

minute, angular (min, angular)

minute, mean solar (min)

minute, sidereal

minute (angular) per

month, mean calendar centimeter (min, angular/cm)

(mo)

myriagram

Newton (N)

Noggin (Brit.)

ounce, apoth or troy (oz, troy)

by by

4.4704 8.8 1.46666 1 9.86923 1.45038 1 6.102545 3.381497 1

1 3.28084 3.937008 1.33322 1.315789 1.33322 1.93368 5.919385 3.612230 1.0416817 6.161152 3.7597656 2.083333 2.908882 1.666666 1.85185 6 6 6.944444 1.666666 5.983617 6.9254831 2.2768712

2.908882 2.628 3.041667 7.3 1.030005 4.3452381 8.3333333 8.3274845 1 2.204623 1 2.248089 1.420652 3.125 1 3.110348 4.8 1.0971429 8.333333

+ To obtain t Divide

x10-' m/sec x 10' ft/min

ft/sec x 102 Pa x 10-4 atm x 10-2 psi x 1 0 - 6 cu m x 10-2 cu in. x 10-2 oz (U.S., liq) x1or3 m

x 10' A x ~ o - ~ ft x 10-2 in. x 102 Pa x ~ o - ~ atm x1or3 bars x 10-2 psi x 10-8 cu m x ~ o - ~ cu in.

x 10-8 cu m x ~ o - ~ cu in.

x rad x10-2 deg (angular) XIO-~ quadrants x 10' sec (angular) x 10' sec (mean solar) x days (mean solar) x 10-2 hr (mean solar) x 10' sec (mean solar) x l o r 4 days (mean solar) x l o r 5 months (mean calendar)

minim (US.)

x ~ o - ~ 02 (U.S., liq)

x 10-6 x 106 x 10' x102

x 10-2 x10-2 x 10' x 10' x 105 x 10-1 x ~ o - ~ x 10-2

x 10-2 x 102

rad/m sec (mean solar) days (mean solar) hr (mean solar) mo (lunar) week (mean calendar) yr (calendar) yr (sidereal)

lb (avdp) dynes lb cu m gal (Brit.) gill (Brit.)

grains oz (avdp)

kg

kg

x 10-2 lb (apoth or troy) 6.8571429 X lb (avdp)

535


Multiply + by To obtain t by

ounce, avdp 2.834952 (oz, avdp) 9.114583

7.5954861 6.25

ounce, Brit., fluid 2.841305 9.607594

ounce, US., fluid 2.957373 (oz, liq) 1.8046875

7.8125 2.9572702 3.125

2.5 3

2.5 3

1.91615

pace 7.62

palm 7.62

parsec 3.085678

part per million (ppm) 1 peck, US. (pk) 8.809768

3.111140 5.37605 2.327294 8.809521 1.555174 4.16666

pennyweight (dwt)

perm, 0 O C

perm, 23O C

perm-in., 0 O C perm-in., 23O C perch, masonry

pica, printer's

(not reservoir)

(not reservoir)

pint (pt), U.S., dry pint (pt), U.S., liq

Planck's constant point, printers poise, absolute

viscosity

pottle, Brit.

5.72135

5.745 25 1.45322 1.45929 7.0084 2.475 4.217518 1.66044 5.506105 4.731765 1.671007 2.8875 1.25 4.731632 1.6 6.6255 3.514598 3.6 1 6.72 1.45 5 2.27298

+ c

x 1 0 - x10- ' x 10-2 x 10-2 x ~ o - ~ x lo-' x1or5

x 1 0 - x 1 0 r 2 x 10-2 x 10-1

x 10' x 10-2 x 1 0 r '

x 10'6 x 1013 ~ 1 0 - 3 x ~ o - ~ x10- ' x 102

~ 1 0 - 3 x 10-3

x l o - "

x 10- 'I

x 10- l2

x10- ' x 10' x io- ) x lo-' ~ 1 0 - x 1 0 - ~ x 10-2 x 10' x l o - ' x10- ' x 10' x1or2' x x 102

x

x 10-2 x1or5 x l o - '

To obtain Divide

kg oz (apoth or troy) Ib (apoth or troy) Ib (avdp) cu m oz (U.S., fluid) cu m cu in. gal (U.S., liq) 1 qt (US., liq) m ft in. m f t in. m mi (statute)

cu m cu ft cu in. gal (U.S., liq) 1

lb (apoth or troy)

kg/(Pa-sec-m2 )

kg/( Pa-sec-m2 ) kg/(Pa-sec-m2 ) kg/(Pa-sec-m2) cu m cu ft m in. cu m cu m cu f t cu in. gal (U.S., liq) 1 oz (U.S., liq) erg-sec m kg/m-hr g/cm-sec Ib/ft-sec reyn (Ibrsec/in2.) gal (Brit.) 1

8/1

kg

536

CONVERSION FACTORS I (continued)


pound, apoth or troy 3.732417 X lo-'

pound, avdp (lb)

pounds of water evap. from and at 212O F

pounds per cubic foot (lb/cu ft)

pounds per cubic inch (lb/cu in.)

pounds per gallon, Brit.

pounds per gallon, U.S. lb/gal (U.S., liq)

pound-force (lb,) pounds per minute

pounds of water (lb/min)

at 39.2" F/min

pounds per square foot (PSf)

pounds per square inch

pucheon, Brit. (Psi)

quadrant

quartern, Brit., dry

quartern, Brit., liq

quarter, US., long

quarter, U.S., short

quart, Brit., (qt, Brit.)

8.228751 1.2 4.114286 4.535924 3.2174 1.215277 3.5 4.4642857 4.5359237 5 1.0237 9.709

1.601846

2.7679905 9.977633 6.228839 1.198264 7.4805195 4.448222

7.559873 4.5359237 1.601891 1.198298 4.788026 4.72541 1.3096 4.8824276

6.894757 3.179751 8.4 1.570796 5.4 2.273044 5 2.272980 1.420652 3.125 1.420613 2.540117 5.6 2.267962 5 1.136522 6.935482 3.002373 1 I36490

x 10-1 x 10' x 1 0 - ~ x10- ' x 10'

x 102 x ~ o - ~ x1or4 x x 106 x 102

x 10'

x 104 x 10'

x 102

x ~ o - ~ x 10-1 x 10-2 x lo - ' x 10' x ~ o - ~ x 10'

x l o 3 x l o - ' x 10'

x l o3 ~ 1 0 - 3 x l o - '

x1or4 x 10-2 x10 - ' x 102 x 102 x 102 x 102 x ~ o - ~ x 10' x10- '

kg lb (avdp) oz (apoth or troy) tons (short)

kg poundals lb (apoth or troy) scruples (apoth) tons (long) tons (metric) tons (short) J Btu

kg/cu m

kg/cu rn kg/cu m lb/cu ft kg/cu m lb/cu ft N

kg/sec l/min cu ft/min gal (U.S., liq)/min Pa atm ft of air (1 atm, 60 F) kg/sq m

Pa cu m gal (U.S., Sq) rad min (angular) cu m gal (Brit.) 1 cu m gal (Brit.) 1 kg lb (avdp)

kg lb cu m cu in. gal (U.S., liq) 1

537



quart, U.S., dry 1.1012209 X l o r 3 (qt, dry) 3.8889251 x

6.7200625 X 10' quart, U.S., liq.

(st, LS,

quintal, metric

radian (rad)

radian per centimeter (rad/cm)

radian per second (rad/sec)

radians per second

register ton (rad/sec2)

revolution, angular

Reyn

rhe

rod

rod, Brit., volume

rood, Brit.

rope, Brit.

9.463529 3.3420136 5.175 8 9.463264 3.2 1 1.9684131 2.204623 1 1.591549 5.729578 3.437141 6.366198 1 1.746375 1.455313 1 5.729578 9.549291 1.591549 5.129578 1.5915494 2.8316847 1 6.283185 3.6 4 4 6.89416 6.89476 1 1 5.0292 2.5 1.65 1.65 1.6499967 2.5 3.125 2.831685 1 1.0117183 2.5 4 1.21 6.096 2 6.66666

x x 10-2 x 10'

x 10-1 x 10' x 102

x 102

x 10-1 x 10' x 103 x 10-1 x 10-2 x 103 x 102

x 10'

x 10-1 x 102 x10-'

x 102

x 102 x 102

x 103 x 106 x 10'

x 10-1 x 10-1 x 10' x 10' x 10-2 x x 10' x 103 x 103 x 10-1 x 10' x 103

x 10’

cu m cu ft cu in. cu m cu ft cu in. gills (U.S.) 1 oz (U.S., liq)

kg hundredweights (long) lb (avdp) rad circumference deg (angular) min (angular) quadrants rad/m deg (angular)/ft deg (angular)/in. rad/sec deg (angular)/sec

'pm r p s revolution/min2 revolution/sec cu m cu ft rad deg (angular) grade quadrant Pa-sec CP Pa-sec poise- m chain (Gunter's) chain (Ramden's) ft ft (U.S., Survey) fur mi (statute) cu m cu ft

sq m acre sq perches

m ft

Yd

sq Yd

538


+ To obtain Multiply + by To obtain t by t Divide

scruule. auoth 1.2959782 x ~ o - ~ . - 4.1666

scruple, Brit., fluid seam, Brit.

section

seconds, angular (sec, angular)

second, mean solar (sec, mean solar)

second, sidereal (sec, sidereal)

shake skein

slug

slug per foot second

slugs per cubic foot

space, entire

(slug/ft-sec)

(slug/cu ft)

span

spherical right angle

square centimeter (sq cm)

square chain, Gunter's

square chain, Ramden's

square degree square foot (sq f t )

square foot, U.S. Survey

square inch (sq in.)

4.5714286 2.0 2.9094969 8 1.027479 2.909414 2.589997 1 4.848137 2.777777 1.1574074 2.777777 1.00273791 9.9726957 1.1542472 1 1.09728 3.6 1.459390 1 3.21740

4.788026

5.153788 1.2566372 2 2.286 1.25 7.5 1 1.570796 2.5 1 1,076391 1.550003 4.0468564 1 4.356 1.5625 9.290304 1 3.046174 9.290304 2.295684 1.44 3.5870064 9.2903412 1.0000040 6.4516 6.9444 1

x 10-2 x10-2 x 10' x10- '

x 10' x l o 2 x 106

x10-6 x l o r 4 x10-5 x 1 0 - ~

x 10-1 x 10-5 x 10-8 x 102 x 102 x 10'

x 10'

x 10'

x 102 x 10'

x10-1 x l o - ' x10- '

x10- ' x ~ o - ~ ~ 1 0 - 3 x10 - ' x 102 x 10-1 x l o 3 x ~ o - ~ x 10-2 x l o 4 x ~ o - ~ x10-2 x 10-5 x 102 x10-8 x 10-2

x1or4 x ~ o - ~ x 106

kg oz (apoth or troy) on (avdp) minims (Brit.) cu m bu (Brit.) cu ft 1 sq m

rad min (angular) days (mean solar) hr (mean solar) sec (sidereal) sec (mean solar) days (mean solar) sec (mean solar) m ft

geepound lb (avdp)

sq mi

kg

Pa-sec

kg/cu m steradian hemisphere m fathom ft quarter (Brit., linear) steradian hemisphere

sq m

sq in.

sq m acre sq ft sq mi

sq ft

sq ft

sq m

steradian

sq m acre sq in.

sq

sq m

sq mi

sq f t

sq ft sq mils

539



square link, Gunter's (sq li, Gunter's)

square link, Ramden's (sq li, Ramden's)

square meter (sq m)

square mile (sq mi)

square rod

square yard (sq yd)

steradian

stere (s)

Stoke

stone, Brit., legal ton, assay ton, long

ton, metric

ton, short

ton, refrigeration ton, register tonne torr, mrn of Hg, 0 O C

township, US.

by by

4.0468564 1 4.356 5.5208695 2.2956841 1 1 2.471054 1.076391 3.861022 2.5899881 6.40 2.787829 2.52928526 6.25 2.7225 9.76562 8.3612736 2.066116 9 3.228306 1.591549 7.957747 6.366198 3.282806 1 9.99972 1 1.550003 1 1.4 2.916661 1.016047 2.12222 2.240 1.12 1 2.6792289 2.2046226 1.1023113 9.0718474 3.2 2.430555 2.000 3.516800 2.831685 1 1.33322 1 9.3239954 2.3040 3.6 3.6

+ t

x 10-2 x1or5 x10- ' x 10-1 x ~ o - ~

x l o 4 x1or4 x 10' x ~ o - ~ x 106 x 102 x l o 7 x 10' x ~ o - ~ x 102 x 10-6 x 10-1 x1or4

x ~ o - ~ x10-' x 10-2 x10-' x 1 0 3

x 102 x x 10-1

x 10-1 x 10-2 x l o 3 x l o 3 x 103

x l o 3 x l o 3 x l o 3

x 102 x104 x 103 x 103 x 103

x 1 0 3 x 102

x lo7 x104 x 10' x 10'

To obtain Divide

sq m acre sq ft sq m acre

hectare acre

sq mi sq m acre

sq m acre

sq ft

sq ft

sq ft

sq ft sq mi sq m acre sq ft sq mi hemisphere solid angle spherical right angle sq deg (angular) cu m 1 m2/sec sq in./sec poise-cu cm/g cental (Brit.) kg kg lb (apoth or troy) lb (avdp) ton (short) kg lb (apoth or troy) lb (avdp) ton (short) kg oz (avdp) lb (apoth or troy) lb (avdp)

cu m kg Pa mm of Hg @ 0 "C sq acre sections

W

sq mi

540


To obtain -. + Mu1 tiply + by To obtain t by t Divide

tun

watt (w)

watt, Int. (w, Int.) watthour (whr)

weeks (mean calendar)

wey, Brit., mass

Yard (Yd)

year, calendar (yr, calendar)

year, leap (yr, leap)

year, sidereal (yr, sidereal)

year, tropical (yr, tropical)

9.5392382 2.52 4 1 3.41443 8.60421 1 4.42537 1.34102 1 1.000165 3.60 3.41443 8.60421 1.34102 6.04800 7.0191654 2.3704235 1.9178082 1.9164622 1.9165365 1.14305285 2.52 9.144 3 3.6 4.54545 1.81818 4 4 3.1536 3.65 8.76 5.256 1.236006 1.2 9.992981 9.993369 3.16224 3.66 3.155815 1.00702 1 .OOO0388 3.155693 1.0006635 9.9996121

x l o - ' x 102

x 102 x l o 7 x 10' x ~ o - ~

x lo3

x 102 XIO-~

x lo5

x 1 0 - ' x10-2 x 1 0 - * x10-2 x 102 x 102 x 1 0 - 1

x 10' ~ 1 0 ~ ~ x l o - '

x l o 7 x 102 x 103 x 105 x 10' x 10' x 10-1 x 10-1 x 107 x 102 x 107

x 107

x 1 0 - '

cu m gal (U.S., liq) hogshead

Btu/hr cal, g/hr ergs/sec ft-lb/min

J/sec

J Btu cal, g

W

hP

W

hp-hr sec (mean solar) day (sidereal) mo (lunar) yr (calendar) yr (sidereal) yr (tropical)

lb (avdp) m ft in. fur pole (Brit.) quarter (Brit.) span sec (mean solar) days (mean solar) hr (mean solar) min (mean solar) mo (lunar) mo (mean calendar) yr (sidereal) yr (tropical) sec (mean solar) days (mean solar) sec (mean solar) yr (calendar) yr (tropical) sec (mean solar) yr (calendar) yr (sidereal)

kg

541

TEMPERATURE CONVERSION FORMULAS

To obtain Formula

OF (Fahrenheit) ( " CX 1.8)+32

O C (Centigrade) a

" C K (Kelvin)

" R (Rankine)

" F + 4 0

1.8 - 40

("F-32)X0.5555 " C + 213.16 " F + 459.688

a Or Celcius, which is preferred for international use.

REFERENCES

A.I.S.C., 1958. Steel Construction Manual. American Institute of Steel Construction, New York, N.Y.,

Binder, R.C., 1962. Fluid Mechanics. Prentice-Hall, Englewood Cliffs, N.J., 4th ed., 453 pp. Burington, R.S., 1957. Handbook of Mathematical Tables and Formulas. Handbook Publishers, Sandusky,

Chilingar, G.V. and Beeson, C.M., 1969. Surface Operations in Petroleum Production. Elsevier, New York,

Frick, T.C. (Editor), 1968. Petroleum Production Handbook, McGraw-Hill, New York, N.Y., Vols. 1 and

420 pp.

Ohio, 296 pp.

N.Y., 391 pp.

Langnes, G.L., Robertson, J.O., Jr. and Chilingar, G.V., 1912. Secondary Recovery and Carbonate

Society of Petroleum Engineers, 1982. The SZ Metric System of Units and SPE Metric Standard. SPE

Weast, R.C. and Astle, M.J., 1980-1981. CRC Handbook of Chemistty and Physics. CRC Press, Boca

Weast, R.C. (Editor), 1968. Handbook of Chemistry and Physics. Chemical Rubber, Cleveland, Ohio, 49th

Zaba, J. and Doherty, W.T., 1956. Practical Petroleum Engineer's Handbook, Gulf, Houston, Tex., 4th

Reservoirs. Elsevier, New York, N.Y., 304 pp.

Publ., 39 pp.

Raton, Fla., 61st ed.

ed., 2074 pp.

ed., 818 pp.


543

REFERENCES INDEX *

Numbers in italics refer to references lists

A.I.S.C., 541 AGA, 33, 34, 54, 58 APHA, 339, 369 API, 63, 70, 94, 99, 356, 359 API, RP-llAR, 295, 316 API, RP-1 lL, 295, 316 API, RP-2A, 410, 411, 412, 413, 418

API, RP-45, 339, 369 ASME, 33, 58 ASTM, 1982b, 339, 369 ASTM, D 1293-78, 339

API, RP-38, 329, 352, 369

ASTM, D 888-81, 339 ASTM, G1-72, 343 ASTM Committee D-2, 520 ASTM Standards, 520 Abbott, W.A., 192, 220 Acme Resin, 143, 157 Adams, B.H., 238, 243 Adams, K.C., 276, 277 Alford, W.O., 276 Allen, D.R., 1, 2, 7, 11, 108, 115 Allen, J.R.L., 191, 193, 194, 219 Allen, K., 460, 461, 463, 464, 465, 472 Allen, T.O., 11, 157, 219 Altieri, V., 302, 317 American Meter Co., 39, 41, 42, 43, 46 American Bur. Shipping, 410, 412, 418 American Gas Assoc., AGA, 32, 33, 34, 54, 58 Amstutz, R.W., 323, 324, 369 Anderson, G.W., 102, 158, 204, 219 Annand, R.R., 310, 316 Aseltine, R.J., 276 Aspdin, J., 61 Astle, M.J., 541 Atchison, T.C., 102, 158 Athy, C.H., 110 Atkinson, C.H., 153, 154, 157 Atmosudiro, H.W., 276 Atteraas, L., 418

Aune, Q.A., 320, 370 Avdonin, N.A., 230, 276 Axelson, Inc., 4

Baghdikian, S.Y., 8 Baker, H.R., 129, 157 Baker, O.E., 325, 369 Baker, P.E., 276 Baker, W., 375, 418 Baker Oil Tools, Inc., 86, 99 Barkman, J.H., 340, 370 Barnard Jr., P., 328, 370 Barton Instruments, 47 Battelle Mem. Inst., 295, 316 Battles, W.R., 323 Baumann, E.R., 328, 362, 370 Bays, A.C., 461, 472 Bean, H.S., 59 Bearden, W.G., 68, 99 Beeson, C.M., 33, 59, 306, 316, 541 Bell, G.R., 362, 370 Bergey, K.H., 376, 377, 378, 419 Bernard, G.G., 131, 157 Bertness, T.A., 294, 305, 316, 520 Bigelow, H.L., 230, 280 Billingsley, R.H., 276 Binder, R.C., 541 Binkley, G.W., 69, 99 Birch, F., 157 Birdwell, B.F., 279 Black, A.P., 357, 370 Black, H.N., 131, 157 Blanks, R.F., 61, 99 Blaunt, F.E., 297, 304, 305, 316, 317 Bleakley, W.B., 276 Blevins, T.R., 276, 280 Boardman, C.R., 154, 157 Boberg, T.C., 239, 276, 281 Bolstead, J.H., 106, 158 Bolster, R.N., 129, 157

* Prepared by John 0. Robertson, Jr. and George V. Chilingarian.

544

Borden, T.F., 203, 204, 206, 21 7 Bosley, T.C., 68, 100 Boulet, D.P., 197, 219 Bowman, C.H., 276 Brady, J.D., 441, 452, 454 Branyan, S.C., 469, 473 Bray, B.G., 154, 157, 158 Brew, J.R., 281 Brewer, S.W., 279 Brice Jr., J.W., 70, 99 Brigham, W.E., 277 Brinkley, T.W., 277 Britton, 222, 277 Brooks Instrument Div., 19, 59 Brooks Jr., F.A., 69, 99 Brown, D.A., 410, 418 Brown, J.L., 128, 157 Brunsmann, J.J., 356, 370 Buckles, R.S., 223, 224, 277 Burington, R.S., 541 Burnett, A.I., 277 Burnham, J.W., 125, 128, 129, 157 Bursell, C.G., 243, 277 Butler, R.M., 277 Byron Jackson, Inc., 99

Calif. Nat. Gasoline Assoc., CNGA, 33, 34, 54,

Calhoun Jr., J.C., 102, 159 Calvert, D.G., 69, I00 Campbell, J.B., 281 Campbell, J.M., 356, 370 Carborundum Co., 201, 219 Carey, B.D., 10, I2 Carlson, U., 458, 459, 469, 473 Carter, M.A., 68, I00 Carter, R.D., 122, 157 Cassi, F.J., 241, 282 Caudle, B.H., 243, 277 CE Invalco, 59 CEMBUREXU, 70, 72 Cerini, W.F., 323, 370 Chappelear, J.E., 277, 282 Charlock, M.A., 376, 377, 378, 419 Chen, W.H., 243, 277 Cheng, S.K., 219 Cheung, C.V., 199, 200, 201 Chilingar, G.V., 7, 33, 59, 64, 100, 158, 306, 316,

457, 520, 541 Chilinganan, G.V., 6, 7, 33, 110, 111, 114, 152,

153, 157, 158, 159, 194, 195, 219, 220, 473, 520

510, 520

Chilton, C.H., 520 Christianovich, S.A., 113, 158 Clark, J.B., 100, 418 Clark, J.E., 106, 158 Clark, J.M., 301, 317 Clark, R.C., 106, 158 Clark Jr., R.C. 69, 99 Cloninger, D.K., 339, 340, 371 Closmann, P.J., 277 Coats, K.H., 277, 280, 458,468,469, 470, 473 Coberly, C.J., 192, 194, 204 Coffer, H.F., 69, 99, 106, 154, 158 Coleman, D.D., 9, 10, I 1 Coleman, D.M., 416, 417, 418 Collins, A.G., 348, 370 Collins, D.B., 264, 277 Collipp, B.G., 401, 402, 418 Conley Jr., W.R., 370, 357 Controlotron, 31, 59 Cook, D.L., 243, 277 Cook, N.H., 59 Cooke, C.E., 138, 140, 158 Cookston, R.B., 277 Comell, D., 6, I 1 Come11 Heavy Oil, Inc., 245 Corporon, W., 380, 418 Coulter, A.W., 128, 131, 158, I59 Cowan, R., 418 Craft, B.C., 1, 11, 86, 99,109, 123, 154, 156, I58 Crapps, D.K., 358, 371 Crawford, P.B., 128, 158, 320 Cron, C.J., 297, 305, 306, 316 Crookston, R.B., 243 Crosby, G., 403, 404, 418 Culham, W.E., 243, 277 Cunningham, W.C., 68, 100

Dallmus, K.F., 110 Daneshy, A.A., 113, 116, I58 Daniel Industries, 23, 24, 25, 37, 38, 48, 59 Darlington, R.H., 204, 209, 219 Das, Kamalendu, 200, 201, 202, 220 Davidson, D.H., 340, 370 Davidson, L.B., 277 Davies, D.W., 353, 371 Davies, L.G., 243, 277 Davis, J.B., 306, 316 Davis, J.S., 233, 234, 277 Davis, L.E., 327, 371 De Haan, H.J., 237, 277 De Swaan, O.A., 277 Dean, H.J., 316

545

Devine, M.D., 376, 377, 378, 419 Dew, J.N., 154, 157, 280 Dickey, P.A., 102, 158 Dickinson, G., 110 Diehl, J.C., 59 Dietrich, W.K., 230, 282 Dietz, D.N., 277 Dill, W.R., 134, 158 Dillabough, J.A., 277 Doherty, W.T., 541 Doig, K., 306, 316 Dorfman, M.H., 277 Dorsey, J.B., 277 Doscher, T.M., 278, 281 Dougherty, E.L., 218 Dow Chern. Co., 118, 119, 120, 121, 122, 123,

124, 158 Drake, L.P., 282 Dreyer, W., 458, 461, 471, 472, 473 Duerksen, J.H., 278 Dumbauld, G.K., 69, 99, 100 Dunlap, R.G., 220 Dunn, F.P., 391, 398, 418 Durnell, W.E., 458, 460, 462, 463, 464, 465, 466,

Duvall, W.I., 102, 158 467, 473

Earl, R.B., 128, 158 Eaton, B.A., 110 Echols, E.E., 209, 219 Eckerfield, R.J., 406, 418 Edwards, L.M., I00 Elenbaas, J.R., 6, 11, 59 Elias Jr., R., 248, 278 Ellers, F.S., 374, 381, 385, 386, 387, 388, 390,

Ellis, R.C., 100 Elson, T.D., 203, 204, 206, 209, 217, 219 English, J.G., 399, 400, 418 Enright, R.J., 382, 418 Erlougher Jr., R.C., 230, 278 Ershagi, I., 277 Eson, R.L., 245, 278 Ethyl Corp., 520 Evans, J.E., 280

392, 393, 394, 395, 418

Fair, J.R., 278 Fairall, R.S., 280 Fairfield, W.H., 243, 278 Fanaritis, J.P., 233, 234, 277, 278 Farouq Ali, S.M., 232, 243, 278, 280 Farris, R.F., 68, 99, 102, 103, 158

Fast, C.R., 102, 103, 104, 106, 108, 117, 128, 133, 134, 143, 144, 145, 146, 147, 148, 149, 150, 152, 154, 158

Ferrier, J.J., 243, 278, 281 Fertl, W.H., 6 , 7, 11, 100, 111, 152, 153, 158 Finch, T.M., 334, 370 Fischer and Porter Co., 27, 30, 59 Fitch, J.L., 379, 418 Fitch, J.P., 278 Flock, D.L., 243, 279 Flow Measurement Co., 44 Fontana, M.G., 316 Foxboro Co., 32, 46, 59 Franco, A,, 279 Freeman, H.G., 106, 158 Frick, T.C., 158, 541 Froning, S.P., 279 Frydenbo, F., 418 Fuex, A.N., 10, I 1

Gacesa, M., 264, 277 Gaddis, M.P., 277 Gates, C.F., 279 Gates, F.I., 320, 370 Gatlin, C., 73, 77, 99 Gatzke, L.K., 308, 309, 316 Geer, R.L., 399, 419 Gibbs, M.A., 99 Gilbert, S., 276 Gilbert, W.E., 5, 6, I1 Goins Jr., W.C., 93, 100 Gomaa, E.E., 243, 278, 279 Gottfried, B.S., 243, 279 Graff, W.J., 410, 419 Graham and Trotrnan, 389 Graham, J.W., 193, 219, 389 Grant, B.F., 102, 158 Graphic Control Corp., 40 Graves Jr., E.D., 1, I I , 86, 99, 109,123,154, 158 Gray, D.J., 403, 404, 407, 419 Greaser, G.R., 279 Grebe, J.J., 102, 158 Greene, N.D., 316 Greer, F.C., 230, 279 Grim, R.E., 370 Grove Valve and Regulator Co., 26, 59 Gruesbeck, C., 209, 219 Gulati, M.S., 198, 219 Guy, A.L., 419

HTI Superior, Inc., 430, 432 Hackerman, N., 311, 316

5 46

Hagoort, J., 279 Hails, J.R., 195, 220 Hall, C.D., 131, 158 Halliburton Co., 16, 17, 19, 20, 59, 67, 70, 71, 74,

79, 80, 81, 82, 83, 86, 87, 88, 89, 90, 91, 92, 93, 95, 99, 100, 104, 105, 106, 109, 112, 113, 114, 115, 117, 130, 131, 135, 144, 145, 147, 150, 154, 158

Handbook of Chemistry and Physics, 427 Hansen, W.C., 66, I00 Hanzlik, E.J., 279 Harding, R.W., 325, 371 Harris, J.O., 370 Harris, L.E., 125, 128, 129, 157 Harris, L.M., 419 Harrison, E., 158 Hartline, B.K., 279 Hastings, J.R., 279 Hatlestad, B., 418 Hausler, R.H., 308, 309, 316 Hawthorne, R.G., 281 Heintz, R.C., 279 Herbeck, E.F., 279 Herschel, C., 33 Herzber, D.E., 277 Hewitt, C.H., 320, 370 Hickstein, E.O., 33 Hill, K.E., 61, 195, 196, 219 Hillard, H.M., 307, 316 Hockaday, D.E., 370 Holden, W.R., 109, 123, 154, 158 Holm, J.A., 202, 220 Holm, L.W., 131, 157 Holmes, B.G., 70, 279 Hong, K.C., 279 Hoppen, T., 418 Horton, E.H., 418 Horton, R.L., 132, 158 Hottel, H.C., 279, 282 Houpeurt, A.H., 279 Howard, G.C., 100, 101, 102, 103, 104, 106, 108,

117, 128, 133, 134, 143, 144, 145, 146, 147, 148, 149, 150, 151, 152, 154, 158

Hower, W.E., 131, 157 Hower, W.F., 65, 66, 100 Hubbert, M.K., 112, 158 Hudgins, C.M., 292, 293, 303, 316 Hudson Jr., H.E., 357, 370 Huge, E.C., 279 Hurst, W., 101, 158

I1T Barton, 18, 21, 59 Ikoku, Chi U., 6, 11, 59

Ingersoll, A.C., 356, 370 Ironite Products Co.. 316

Jacobs, W.L., 131, 157 Jahns, H.O., 379, 381, 419 Johnson, J.L., 370 Johnson, J.W., 411, 419 Johnson, W.M., 280 Johnstone, J.R., 278, 356 Jones, J.R., 243, 279, 320 Jones, M.E., 379, 417, 418, 419 Jones, P.H., 323, 370 Jones Jr., F.O., 370

Kalfayan, L.J., 202, 220 Kaltenbach, A.J., 10, I 1 Kaplan, M., 323, 370 Kash, D.E., 376, 377, 378, 419 Katz, W.J., 6, 11, 59, 356, 370 Katz, D.L., 458, 468, 469, 470, 473 Kaufman, D.W., 461, 473 Kemp, L.J., 33 Kendall, 22 Kennedy, H.B., 61, 99 Kennedy, J.L., 419 Keogh, R.A., I 1 Kern, R., 59 Kerr, T.H., 59 Khan, A.M., 238, 243, 276 Kieschnick Jr., W.F., 158 Kimmel, J.D., 278 Kirk, R.S., 276 Klein, A., 66, 100 Knapp, R.H., 279 Knox, J.A., 134, 158 Knutson, C.F., 154, 157, I58 Kobayashi, R., 6 , 11, 59 Krause, J.D., 278 Krisher, A.S., 279 Krumbein, W.C., 198, 199, 219 Kubit, R.W., 306, 316 Kuo, C.H., 279 Kuuskraa, V.A., 279

LaFrenz, R.L., 328, 362, 370 LaFuma, H., 66, I00 LaQue, F.L., 518, 520 Lamb, M.J., 414, 415, 419 Landers, M.M., 128, 157 Landreth, T.C., 196, 220 Lane, R.D., 68, 99 Langelier, W.F., 327, 370 Langenheim, R.H., 235, 242, 280

547

Langnes, G.L., 158, 541 Lantz, R.B., 237, 276 Larman, J.H., 280 Lasater, R.M., 134, 158 Laumbach, D.D., 281 Laurie, A.M., 209, 220 Lauweier, H.A., 279 Leach, P.B., 129, 157 Leal, M.A., 243, 279 Lee, G.C., 397, 398, 408, 419 Legatski, L.K., 441, 454 Leighton, A.J., 280 LeGnse, A., 279 Lekas, M.A., 153, 157 Leonard, R.L., 376, 377, 378, 419 Leutwyler, K., 230, 237, 280 Lewelling, H., 323, 370 Lindberg, F.A., 10, I 1 Lindemann, W.B.N., 458, 459, 469, 473 Lister, C.R.B., 279 Little, R.C., 129, I57 Liu, C.L., 10, 11 Lobo, W.E., 280, 282 Lochridge, J.C., 415, 419 Lueders, R.K., 151, 159 Lynes, Inc., 96, 98

Maier, L.F., 68, 100 Malofeev, G.E., 280 Maly, G.P., 198, 209, 216, 219, 220 Maly, J.W., 106, 158 Mandl, G., 235, 280 Mantooth, M.A., 204, 209, 219 Marawen, S.A., 282 Mare, De la, R.F., 2, 11 Marsh, G.A., 297, 305, 306, 316, 371 Martin, R.L., 296, 311, 316, 317 Martin, W.L., 280 Marx, J.W., 235, 242, 280 Mason, J.P., 404, 405, 406, 407 Matheney Jr., S.L., 280, 337, 370 Matheny, F., 461, 473 Mathews, C.S., 107, 158 Matuszak, M.P., 505, 520 May, P.D., 317 May, T.P., 518, 520 McArthur, R.D., 153, 157 McCulloh, T.H., 110 McDaniel, B.W., 125, 128, 129, 157 McDermott Inc., 383, 384 McGIasson, R.L., 292, 298, 299, 316 McGuire, W.J., 108, 127, 158 McIntyre, H., 280

McLeod, H.O., 131, I58 McNabb, D., 419 Meents, W.F., 10, I 1 Mehdizadeh, P., 292, 316 Mekler, L.A., 280 Meldau, R.F., 243, 278, 280 Meyer, F.H., 298, 299, 317 Meyer, R.F., 226, 280 Meyers, A.J., 468, 473 Micromotion Inc., 29, 59 Miller, F.G., 277 Miller, J.S., 280 Miller, T.E., 59 Miller, W.K., 151, 159 Millhone, R.S., 203, 204, 206, 217, 219, 220 Milton, C., 329, 370 Minich, A., 127, 158 Minter, R.B., 278 Mitchell, R.W., 334, 370 Monaghan, P.H., 219 Monrad, C.C., 259, 280 Monroe, R.F., 128, 158 Montgomery, P.C., 65, 66, 100 Moore, J.W., 370 Morgan, J.J., 100, 357 Morris, E.F., 68, 100 Morris, V.C., 320, 370 Morrison, J.R., 411, 419 Morton, T.E., 106, 158 Moss, J.T., 243, 280 Mueller, T.D., 277 Muller, J.M., 279 Muskat, M., 158 Myhill, N.A., 238, 243, 244, 280

NACE, 307, 340 NACE, RP-07-75, 343, 371 NACE, TM-01-73, 339, 370 NACE, TPC #5, 317 NGAA, 307, 317 NGPSA, 59 Neal, M.R., 216, 220 Neil, J.D., 320, 370 Nelson, W.L., 520 Nemerow, T.E.W., 428, 454 Newman, K., 66, 67, 100 Niko, H., 280 Nind, T.E.W., 6, I 1 Noran, D., 288

OBrian, M.P., 411, 419 ODell, P.M., 244, 280 OMedia, C.R., 358, 371

548

O’Nesky, S.K., 245, 278 Obert, L., 102, 158 Oglesby, K.D., 280 Olson, J.C., 280 Oskay, M.M., 277 Osoba, J.S., 219 Ousterhout, R.S., 131, 158

Pacheco, E.F., 232, 280 Parker, J.C., 317 Parlar, M., 155 Patton, D.L., 192, 220 Pellegrini Jr., J.P., 128, 159 Perkin, A.A., 61 Perry, R.H., 281, 520 Petroleum Extension Service, Univ. Texas,

Austin, 59 Phansalker, A.K., 128, 158 Phocas, D.M., 279 Pierce, R.R., 280 Pittman, G.M., 243, 277 Poettmann, F.H., 6, 11, 59 Pope, R., 340, 371 Postgate, 342 Powers, J., 59 Powers, L.W., 281 Powers, M.L., 280 Prats, M., 277, 280 Production Profits, Inc., 354

Querio, C.W., 458, 460, 462, 463, 464, 465, 466,

Quon, D., 243, 279 467, 473

Rabb, D.D., 153, 157 Rabinowicz, E., 59 Ramey Jr., H.J., 229, 230, 241, 280, 281, 282 Randall, B.V., 317 Ranney, M.W., 374, 376, 379, 419 Ratliff, N.W., 277 Ray, J.D., 317 Reed, M.G., 200, 220 Reilly, P.B., 434, 435, 454 Reitsema, R.H., 10, 11 Rcpublic Geothermal, 108, 126, 127, 135, 136,

Reynolds, J.J., 69, 99 Rhodes, F.H., 301, 31 7 Richards, E.C., 26, 27, 59 Riddick, T.M., 357, 371 Rieke 111, H.H., 7, 11, 64, 100, 110, 158 Riggs, O.L., 298, 299 Rivero, R.T., 281

137, 138, 139, 141, 142, 158

Roberts, A.P., 1, 2, 11, 108, 115, 157, 191, 193,

Robertson Jr., J.O., 158, 541 Robinson, J.M., 216, 449, 455 Robinson, J.P., 209, 220 Roebuck, A.H., 128, 159 Rogers, E.E., 244 Rogers, W.L., 280 Root, P.J., 282 Root, R.L., 129, 159 Rosborough, W.M., 292, 316 Rough, R.L., 102, 158 Rubinshtein, L.I., 281, 230 Russell, R., 302, 317

219

Sachtschale, J.R., 441, 444, 455 Sackett, W.M., 10, I 1 Sahuquet, B.C., 281 Salathiel, W.M., 209, 219 Salomon, S.N., 376, 377, 378, 419 Sanford, J., 59 Sarem, A.M., 281 Satter, A., 230, 232, 281 Saucier, R.J., 192, 193, 195, 206, 220 Sawabini, C.T., 7, I1 Scanlan, J.C., 278 Schaaf, S.A., 411, 419 Schairer, J.F., 112, 157 Schaschl, E., 371 Schenk, L., 239, 277 Schlottman, B.W., 151, 159 Schoell, M., 10, 11 Schwartz, D.H., 195, 196, 218, 220 Scisson, S.E., 470, 473 Scott, J.B., 128, 159 Seba, R.D., 281 Sellars, C., 401, 414, 419 Serick Baker, Inc., 359, 360, 361 Shain, S.A., 279 Shelton, J.L., 279 Shipley, R.G., 280 Shore, R.A., 279 Shryock, S.G., 64, 70, 75, 76, 100, 209, 214, 216,

Shryock, S.H., 279 Shutler, N.D., 243, 281 Sikora, V.J., 108, 127, 158 Silberberg, I.H., 243, 277 Simonsen, R.N., 356, 371 Simpson, J.P., 317 Sivalls, C.R., 2, 11 Skeeks, K.A., 110 Slagle, K.A., 100

220

549

Sloss, L.L., 198, 199, 219 Small, H., 59 Smatko, J.S., 311 Smith, D.K., 63, 64, 65, 66, 67, 68, 69, 70, 73, 81,

82, 83, 84, 86, 89, 99, 100 Smith, J.E., 155, 159 Snavely, E.S., 297, 311, 316, 317 Snyder, R.E., 100 SOC. Petrol. Engr., 541 Solum, J.R., 203, 204, 206, 209, 211, 214, 216,

220 Solum Oil Tool Corp., 90, 92, 93, 94, 100, 207,

208, 210, 211, 212, 220 Somerton, W.H., 231, 281 Spangle, L.B., 69, 100 Spencer, O.J., 325, 371 Spicer, H.C., 112, 157 Spillete, A.G., 281 Spink, L.K., 59 Squier, D.P., 281 Staehle, R.W., 317 Stahl, W., 10, I2 Starkey, R.L., 307, 317 Stegemeier, G.L., 238, 244, 280, 281 Steiner, M.E., 458 Stephens, R.J., 277 Steves, H.B., 280 Steward, J.B., 128, 159 Stiff, H.A.. 327. 371 Stiner, M.E., 460, 462, 463, 464, 465, 466, 467,

Stokes, D.D., 281 Storer, D., 110 Strange, H.O., 128, 159 Struthers Thermo-Flood, Corp., 248, 249, 253,

Struthers-Anderson, 448 Stumm, W., 357, 371 Sudbury, J.D., 298, 299, 317 Suman Jr., G.O., 100, 198, 206, 220 Superior, Inc., 430, 432 Sutherland, L.B., 252, 253, 281

4 73

257, 268, 269, 270, 275

TEMA Standards, 258 Taschman, B.M., 281 Taylor, F.B., 61, 62, 63, 100 Taylor, H.F.W., 100 Taylor, R.W., 158 Tchillingarian, G.V., 520 Templeton, W.J., 59 Terrell, C.E., 59, 418 Thachuk, A.R., 243, 279

Thurber, J.L., 281 Tokheim Corp., 59 Tong, L.S., 250, 281 Tough, F.B., 61, 100 Towson, D.E., 239, 281 Traynor, B.V., 230, 233, 281 Troost, P.J.P.M., 280 Trotman, Graham and, 389 Troxell, G.E., 66, 100 Truitt, N.E., 277 Tubular Exch. Manu. Assoc., 281 Tunn, P.A., 320, 321 Tyrand, P.A., 281

US. Maritime Admin., 375, 419 UGC Instruments, 45 Udwin, E., 358, 371 Uhlig, H.H., 302, 317, 518, 520 Ulrich Books, Inc., 459 Underdown, D.R., 200, 202, 220 Urn, M., 328, 371

Valleroy, V.V., 281 Van Dijk, C., 282 Van Poelgeest, F., 279 Van der f i a p p , W., 282 Van Lookeren, J.A., 277 Vary, J.A., 6, 11, 59 Veatch, R.W., 101, 125, 127, 132, 134, 139, 159 Venturi, G.B., 33 Vipperman, O.T., 279 Volek, C.W., 235, 277, 280, 281 Von Engelhardt, W., 320, 321, 371 Vorabutr, P., 114, 157 Vrablik, E.R., 427, 428, 429, 455

Wachter, A.P., 306, 316 Wahl, H.A., 154, 157 Walker, R.W., 419 Watanabe, D.J., 202, 220 Watkins, J.W., 200, 202, 220, 298, 317 Weast, R.C., 541 Weeter, R.F., 291, 31 7 Weinaug, C.F., 6, 11, 59 Weinbrandt, R.M., 214, 282 Welbourn, M.E., 279, 281 Wendt, R.P., 31 7 Weymouth, T.R., 33 White, F.L., 100 White, I.L., 376, 377, 378, 419 Whitman, W., 302, 317 Whitten, D.G., 281

550

Wieland, D.R., 69, 100 Willhite, P.G., 230, 282 Williamson, A.S., 282 Willis, D.G., 112, 158 Willis, Sii, 2 Willman, B.T., 281 Wilson, D.W., 282 Wilson, L.R., 282 Wimpress, R.N., 253, 282 Witherspoon, P.A., 371 Wolf, K.H., 7, 11, 194, 195, 219, 220 Wooden, L.G., 281 Wright, C.C., 298, 323, 335, 339, 340, 348, 353,

370, 371

Wright, D.C., 203, 204, 206, 380, 419 Wright, J., 317 Wright, K.A., 220 Wu, C.H., 282 Wynn, J.C., 280

Yen, T.F., 6, 7, 11, 153, 157, 158 Yoelin, S.D., 282 Young, H.W., 278, 376, 377, 419 Yuster, S.T., 102, 159

Zaba, J., 295, 317, 541 Zheltov, Y.P., 113, I58 Zinn, J., 418

551

SUBJECT INDEX *

Acid, 161 - additives, 174 - - , cleanup 182 - - , complexing agents, 181, 182 _ - , corrosion inhibitors, 175 - - , diverting agents, 180 - _ , fluid-loss, 178, 179 - - , friction reducers, 177, 178 - - , iron-sequestering agents, 181, 182 - - , purpose of, 162, 174 - - , solvents, 176 - - , surfactants, 176, 177

- , desired properties of oilwell, 165 - , dissolving power of, 169 - fracturing design, 186 - , gravel solubility in, 200, 201 - , inorganic, 163, 164 - , mud, 162 - , organic, 163, 164 - , properties of, 163, 165 - reaction, with rock, 168, 170 - - rate, effect of temperature on, 183 - soak, 171 - spending time, 165, 183-185 - types, 163 - washing, 171 Acid rain, 436 Acidity of petroleum products, organic, 502 Acidizing, 161 - carbonate reservoirs, 167 - design, 182-186 - -, fracture, 186 - -, matrix, 182 - , high-pressure, 174

- , matrix, 172, 182 - , purpose of, 162, 171 - reactions, kinetic models for, 167 - sandstone reservoirs, 169 - treatments, 171 Aerobic plate count test, 339, 342, 345, 350

- , carbonic, 301, 303, 331

- , history of, 161

Alkalinity, 266 - effect on corrosion, 302, 303 - of feedwater in steam injection, 266 Ammonia injection, 449 Aniline, 492 - - gravity constant, 492

Antiknock additives, 487 API gravity, 483, 512 - _ , definition, 483 - - , measurement, 483, 512 Ash content of oils, testing, 501 Aviation fuels, see fuels Avogadro’s law, 49 Azeotropic solutions, 477

- point, 492

Bacteria, 306, 339 - count, 348 - , facultative, 342 - growth tests, 339, 341, 342, 345, 346 - , role of, in corrosion, 306 - , sulfate-reducing, 306, 307, 339, 341, 342 - , total, in water, 339, 342, 345 Barite, 69 Bean performance chart, 5, 6 Bernoulli‘s equation, 24, 27 Blistering, hydrogen, 293 Boyle’s law, 49

Caprock, 458 - , pump testing of, 459 Carbon dioxide, 301, 329, 363, 505 - - content of a gas, testing, 505 - - corrosion, 301, 329 - --, in drilling and production, 301 - --, in waterflooding, 329 - - removal from water, 363 Carbon monoxide, 422, 436, 506 - -, as pollutant, 422, 436 - - content of a gas, testing, 506 Carbon residue of oil, 501 Carter’s equation, 122, 155

* Prepared by Mehmet Parlar and George V. Chilingarian.

552

Casing vent, gas collection systems, 450 ~ ~ gathering systems, 272 Catalytic converters, 449 Catalytic reduction, 449 Cathodic protection, 285, 303, 305 ~ - for corrosion control, 285, 303

~- , galvanic type, 305 _ - , impressed-current type, 305 Caustic soda, use in sulfur dioxide control, 443,

Caverns, 459, 462, 470 ~ , mined, 470 - . salt, 462, 463, 466, 468 Cells, 328 - , concentration, 328

~ , dissimilar electrode corrosion, 328 Cement, 61 - additives, 68 _ - , accelerators, 68 _ _ , dispersants, 70 ~- , filtration control, 70 _ _ , Friction reducers, 70 _ - , heavy-weight, 69 - - , light-weight, 68 ~- , lost circulation, 69 - -, retarders, 69

~ , calcium aluminate, 67 ~ , chemistry and characteristics of, 61 - , classification of, 63 -

- , curing of, 63 - , diesel oil, 65 ~ displacement operations, types of, 75 - , expanding, 66 - , gypsum, 66 ~ , hardening of, 62 - , latex, 67 - , low-density, 67 - paste, 62, 63 - , permafrost, 68 - , plastic, 65 - , pozzolan-lime, 65

~ , properties of, used in USA, 71 - , resin, 65

~ slurry density, 77 - , setting of, 62 - , specialty oilwell, 64 - , spherelite, 67 - standards outside USA, 70 Cementing, - , delayed setting, 76 - equipment, 78, 83

445

, --, in various countries, 72

- , P O Z Z O ~ ~ ~ ~ C , 64

- -, subsurface, 83, 84 - -, -, casing-cementing heads, 86 - -, -, casing centralizers, 85, 89-91, 93-95 - -, -, --, API specifications, 94 - -, -, casing packer, 85, 96-99 - -, -, casing scratchers, 85, 91-93 - -, -, cement basket, 85, 94, 95, 99 - -, -, cementing plugs, 85, 86 - -, -, float collar, 84, 86, 87 - -, -, float shoe, 86, 87, 95 - -, -, guide shoe, 83, 84, 86, 95 - -, -, stage cementing tools, 84, 88, 89

- -, surface, 78, 84 - -, -, mixing, 79 - -, -, -, batch, 82 - -, -, -,Jet, 80 - -, -, -, recirculating, 81 - -, -, pumping, 78 - -, -, recirculating, 81

- , inner-string, 75 - , liner, 75, 98 - , multiple-stage, 88 - , normal displacement, 75 - operations, 73 - -, regulations for, 73, 76 - practice, 73 - , primary, 73-75 - , reverse circulation, 76 - , secondary, 73 - , squeeze, 73, 76 - , stage, 75, 88, 97, 98

- , WOC time in, 76 Charcoal test, 510 Charles’ law, 49 Chart, - , Gilbert’s bean performance, 5,6 - , orifice meter, 40 - , pressure drop/flow rate, turbine flowmeters,

- , pressure drop of 85%-quality steam flowing

- , pressure losses in fracturing treatment,

- , roundness and sphericity of sand grains, 199 - , steam generator heating requirements, 260 - , sulfide increase, 347 - , waterflood rating, 348 Choke, 2-4 - location, on Christmas tree, 2 - - , on offshore production platform, 4

- -, summary of, 84

- , history of, 61

- , -, tools, 84, 88, 89

20

in pipes, 228

117-124

553

Christmas tree, 2 Clay, swelling of, 320, 321 Cleveland open cup tester, 498, 515 Cloud point, 499, 516 Coagulants, chemical, 435 Coagulation, 434, 435 Color of oil, 499, 515 Compressibility of unconsolidated sands, 7 Contaminants, water, 423 Contamination of fuels, testing for, 487 Conversion of units, 521-541 - factor, dynamic viscosity, 521, 522 - -, multicomponent, 522, 523 - -, theoretical aspects, 521 Copper strip corrosion test, 495, 504 - --_ for gasoline, 495 - - _ _ for lubricating oils, 504 Corrodants, 283, 296, 297, 301, 327 - , bacteria, 306, 307, 331 - , carbon dioxide, 301-303, 329 - , hydrogen sulfide, 297, 329 - in drilling and production operations, 283, 296 - in waterflooding, 327 - , oxygen, 296, 330 Corrosion, 283, 307, 327, 495, 504, 518 - , bacterial, 306, 307, 331 - , carbon dioxide-induced, 301-303, 329 - , cavitation, 291

~ , chemistry of, 287 - , conditions promoting, 284 - control, 285, 300 - -, cathodic protection for, 285, 303 - -, in hydrogen sulfide environment, 300 - coupons, 343-345, 348 - , definition of, 283 - , electrochemical, 284 - , -, components of, 286 - , electrode polarization by, 285 - , erosion, 291 - , fatigue, 294 - , galvanic, 290 - , hydrogen sulfide-induced, 297, 329 - in drilling and production operations, 283,296 - in gas-condensate wells, 307 - in waterflooding, 327, 329 - inhibition, 339 - inhibitors, 310 - -, in acidizing, 175 - , intergranular, 290 - , measurement of actual, 349 - , measurement of factors leading to, 350 - , microbial, 306, 307, 331 - , oxygen-induced, 296, 330

- passivators, 310 - , pitting, 290 - rate, 175, 348 - -, effect of temperature on, 175 - reaction rates, 285, 286 - , ring worm, 290 - , selective leaching, 291 - , steel, 289 - , stress, 291, 292 - test, for gasoline, 495 - _ , for lubricating oils, 504 - , two-metal, 290 - , types of, 290 - , uniform attack, 290 Cracking, 292 - , in drilling and production environments, 292 - , sulfide, 292, 303 Crankcase oil, dilution of, 500, 516

Dalton’s law, 49, 330, 478 Daneshy’s formula, 113 Deaeration, 260, 367 - equipment for injection water, 367 - , feedwater, in steam injection, 260 Deep agar test, 342, 345, 350 Density - meter, 149 - of rocks, 231 Depolarizers, 285, 286 Design, - , acidizing, 182-186 - , gravel pack, 217 - , offshore platform, 407-414 - , steam injection equipment, 246-258 - , wastewater treatment, 424 - , water intake in waterflooding, 335 Dew point, of flue gas, 259, 270 Discoloration number, 495 Dissolved gases, removal from injection water,

Distillation, 475 - of gasoline, 481, 511 - of crude oil, 512 - , theoretical considerations, 475 - , water in petroleum by, 513 Doctor test, 488

363

Electrochemical corrosion, 284 - -, components of, 286 - -, reactions in, 284 - -, requirements for, 284 Electrode potentials, 287-289 - reactions, 288

554

Electromotive force (EMF) series, 287, 288 Embrittlement, hydrogen, 291, 292 Emission, steamflood, 436 - control, 441, 447, 449, 450, 452 - _ , hydrocarbon, 450, 452 ~~ , nitrogen oxides, 449, 452

~~ , particulate, 447, 452 _ - , sulfur dioxide, 441, 452 Eminence Salt Dome caverns, 463 ~ _ _ _ , design specifications for, 463 - _ _ _ , operating cycle of, 465 Enhanced oil recovery (EOR), 221 - -- classification, 222 - -_ , hot plate, 245 ~ ~- , steam, 221 Engler distillation, 511 Equation, - , Bernoulli’s, 24, 27, 36 - , Carter’s, 122, 155 - , Daneshy’s, 113 - , Foxboro’s, 32 Equilibrium diagrams, 476, 482 - - , eutectic type, 482 - _ , layer type, 482 - - , solution type, 476 Ethane-methane content of a gas, 506 Ettringite, 66

FAST (fracture assisted steamflooding technology), 245, 246

Feedwater, 264-267 - , alkalinity of, 266 - , dissolved gases in, 265 ~ , hardness of, 267 - , metal contaminants in, 266 - , oil content in, 265

- , silica content in, 266 - , treatment of, 264 - , turbidity of, 265 Filtercake permeability, 348 Fire point, test, 498, 514 Fixation, oxidation of elemental nitrogen, 440 Flash point, test, 498, 514 Flocculation, 366, 367, 434, 435 - filters, 367 - systems, 366 Flowmeter, 13 - , accuracy of, 13 - cutaway, 148 - , electromagnetic, 30, 31 - , linearity of, 14 - , magnetic, 30

- , pH of, 266

- , mass, 29 - , orifice, 13, 21-23, 32, 33 - , -, description of, 34, 37 - , -, flow rate equations for, 32

- , -, operation of, 35 - , -, plate holders, 24, 25 - , -, plate types, 22, 23, 25 - , -, pressure taps, 23, 24, 26, 21 - , positive displacement, 13, 15, 17, 18, 28 - , --, nutating disc type, 15 - , --, oval gear, 15, 19 - , --, rotary vane type, 15

, , , specifications of, 21 - , --, types of, 15 - , rangeability of, 14 - , readout devices of, 21 - , repeatability of, 14 - , special, 30-32 - , turbine, 13, 15, 16, 27 - , -, cross-section of, 17 - , -, pressure drop curves for, 20 - , -, specifications of waterfood, 19 - , types of, 13 - , ultrasonic, 31, 32 - , vortex shedding, 27, 28 Flue gas, dewpoint, 259, 270 - - scrubbers, 267 Foxboro’s equation, 32 Fractionation, 479 - tower, schematic diagram of, 480 Fracture, - area, 119 - -, Carter’s equation for, 122, 155 - closure pressure, 116 - conductivity, 125,126, 136-138 - - , effect of particle sue on, 136 - -, -- particle concentration on, 137 - -, -- proppant quality on, 136 - _ , -- proppant roundness on, 138 - _ , factors reducing, 125 - _ , variation with effective stress, 126 - geometry, 113 - inclination, 115 - initiation, 116 - orientation, 111 - propagation, 115 - treatments, trend of, 104 Fracturing, 101 - fluid coefficient, 123 - fluids, 105, 125, 127 - - , acid-base, 133, 134 - - additives, 125, 127, 139

- , -, history of, 33

- -_ --_

555

- --, fluid loss control, 128, 132, 133 - --, friction reducing, 128, 131, 133 - --, gelling agents, 128, 129, 132 - --, surfactants, 131 - --, types of, 139 - -, crosslinked, 132 - -, foams as, 134 - -, functions of, 125 - -, gelled two-stage, 132, 133 - -, geothermal wells, 132 - -, oil-base, 128 - -, --, advantages of, 129 - -, selection of, 125, 128 - - systems, commonly used, 127 - -, trends in use of, 105 - -, water-base, 129 - -, --, advantages of, 131

- , mechanical equipment, 143 - , --, bulk-handling, 150 - , -- layout for massive frac operation, 151 - , --, metering and control, 147

- , history of, 101

- , _ _ , _-- , density meter, 148 - , _ _ , --- , flow meter, 148 - , -- , --- , fracture parameter meter, 150

- , --, proportioning, 106, 146 - , --, pumping, 143 - , mechanics of, 108 - , nuclear, 152-154 - , -, post-shot environment, 153 - , -, volume of increased permeability, 154 - pressure, 102, 116 - process variables, 108 - , propping agents (proppants) for, see prop-

- , purpose of, 101, 105 - , rock mechanics considerations in, 109 - techniques, evolution of, 105 - treatment, - -, criteria of well selection for, 106 - -, pressure-injection rate relationship during,

- - , pressure losses in, 117 - - , --- , charts for, 117-124 - -, procedures for successful, 109 - -, reasons for failure of, 108 Freezing point, 508, 518 - -, lowering of, 508, 518 - - of fuels, 508 Fuel, - , aniline point of, 492 - , contamination of, 487 - , filter plugging caused by, 490

pants

116

- , flash and fire points of, 498, 514 - . fluorescent-indicator adsorption test of, 494 - , mercaptan sulfur test for jet, 489 - , sulfur content (lamp) test of, 494 - , thermal value of, 491 - , water tolerance of aviation, 489

Galvanic series, 289 Gas, - , equation for ideal, 48

- flow rate measurement, 22, 32 - --- , volumetric, 22

- --- , see also flowmeters - , flue, 259, 261, 262, 267, 270 - , supercompressibility of, 50, 51 - , superexpansibility of, 50 - , underground storage of, 457 Gases, interactions of, 330 Gas-condensate wells, corrosion in, 307 Gasoline, - content of natural gas, 510 - , corrosion test for, 495 - , distillation of, 481, 511 - , gum content of, 491, 492 - , knock properties of, 485 - , tetraetbyl lead in, 487 - , vapor pressure of, 484, 512 Gilbert’s bean performance chart, 5, 6 Gravel, - dissolution, 199-202 - quality, 197 - screening, 197 - selection, 192 - shape, 198

- solubility, 199 - - in acid, 199-201 - - in water, 200-202 - strength, 203 Gravel pack, - - design considerations, 217 - - effectiveness, factors determining, 217 - - evaluation, 216 - - permeability, 193, 197, 198 Gravel packing, 191 - - arrangement, 192, 194, 195

, cased-hole, 206

- -, cylinder type, 210 - - deviated holes, 209 - - equipment, 209

- , --- , deviations from, 49

, weight, 32 - _ _ _

- Sizing, 192

- _ - - , -_ , circulation washer tool for, 206-208

556

- --, blender, 209 - --, circulation washer tool, 206-208 - --, crossover tool, 211, 214 - --, gravel blending unit, 210-212 - -- , _ _ - , conventional, 210 - -- , --- , positive-displacement, 211, 212 - --, gravel pots, 211 - --, liner vibrator, 216 - .--, port collar, 215 ~~ --, surface equipment, 211, 213 - --, unipack tool, 216 - - fluids, 203, 204 - -, methods of, 205 - -, open-hole, 205 - - , screen or liner selection in, 204 Gravity, API, 483 - of petroleum products, test for, 483, 512 Gum content of gasoline, 491

Gypsum, 66 - cements. 66

, test for, 492 - _-_

Hardness of water, 267 Heat loss, 227, 262 - - in steam injection, 227 - ---- , frictional, 228 - _--- , surface radiation, 229 - _ _ _ _ , to surrounding formations, 232, 234 - _ _ - _ , wellbore, 229, 233 - - from bare pipe in still air, 262 - - rates in steel pipes, 229 Heavy oil, - - viscosity variation with temperature, 223,

224 - - , world reserves of, 226 Hematite, 69 Hemple column, distillation of oil with, 512 Henry’s law, 49, 330 Horsepower, formula for hydraulic, 118, 144 Hot plate steam injection process, 245 Hydrates, 6 Hydraulic fracturing, see fracturing Hydrogen, - blistering, 293 - content of gas, testing for, 506 - embrittlement, 291, 292 Hydrogen sulfide, - - as pollutant, 422 - - control, 450, 452 - -- processes, chemical reactions in, 451 - - corrosion, 297 - -- control, 300 - -- in waterflooding, 330

- - removal from drilling fluids, 299 - - removal from water, 363 - - scavengers, 299 Hydrometer, 483, 512

Ilmenite, 69 Injectivity loss, measurement of, 350 Inhibitors, 310 - , anodic, 310 - , cathodx, 310 - , definition of, 310 - , organic, 311 Iron count, 339, 341, 350 - - increases, 345, 348 Ironite sponge, 299 - - reaction with hydrogen sulfide, 300 Isotopes, 10 Isotopic analysis of natural gases, 10

Joule-Thomson effect, 6 Jet fuels, see fuel.

Knock properties of gasoline, 485

Law, - , Avogadro’s, 49 - , Boyle’s, 49 - , Charles, 49, 50 - , Dalton’s, 49, 330, 478 - , Henry’s, 49, 330 - , ideal gas, 48, 49 - , Raoult’s, 49, 478 - , Stokes’, 426 Leach-fill process, storage in salt, 463 - _- , steps during, 464 Leaching, storage in salt, 462 - , direct, 465 - , indirect, 467 Lead, 486, 487 - as antiknock additive, 487 - content of gasoline, 486, 487 Lime/limestone, use in sulfur dioxide control,

Liquid flow rate, measurement, 15 Lubricating greases, 504, 505 - _ , classification and requirements of, 504 - _ , dropping point of, 505 - _ , penetration number of, 505 Lubricating oils, 495 - _ , functions of, 495 - - testing, 496 - _- , ash content, 501 - _- , carbon residue, 501

441, 443

557

- --, cloud point, 499, 516 - --, color, 499, 515 - --, corrosion test, 504 - --, dilution of crankcase oil, 500, 516 - --, fatty oil content, 502 - --, flash and fire points, 498, 514 - --, neutralization number, 502 - --, organic acidity, 502 - --, pour point, 499, 516 - --, precipitation number, 501 - --, saponification number, 502 - --, sulfur content, 503 - --, viscosity, 496, 514 - --, viscosity index, 497

Marx-Langenheim model, 235-237 Measurement of, - - bacteria, 339, 341, 342, 350, 351 - --, sulfate-reducing, 339, 341, 342, 351 - --, total, 342, 343, 350, 351 - --, -, aerobic plate count, 339, 342, 350 - --, -, deep agar test, 342, 350 - --, -, membrane filter count, 343, 350 - - corrosion and corrosion rate, 343-345, 349,

350 - - dissolved oxygen in water, 339, 346 - - Eh, 346 - - injectivity loss, 350 - - iron count increase of water, 339, 341, 346,

- - pH of water, 339, 340 - - pit depth, 343-345, 349, 350 - - pit frequency, 343-345, 349, 350 - - salinity of water, 339 - - salt caverns, 468 - - sulfides in water, 339, 344, 345, 351 - - suspended solids in water, 339, 340 Membrane filter test, 340, 343, 346, 350 Mercaptan sulfur test, 489 Methane-ethane content of a gas, measurement,

Mined caverns, 470 Molecular weight, - - , determination by lowering of freezing point,

508, 509, 518 Mooring systems, 401

349

506

Natural gas, - - from different sources, distinguishing, 9 - -, gasoline content of, 510 - -, geochemical fingerprinting of, 9 - -, isotopic analysis of, 10

Neutralization number, 502 Nitrogen content of a gas, measurement, 506 Nitrogen oxides, - - as pollutants, 422, 436, 439, 440 - - control, 449, 452 - -- , ammonia injection, 449 - -- , burner modification, 450 - _- , catalytic reduction, 449 Nuclear fracturing, 152-154 - - , post-shot environment, 153 - - , volume of increased permeability, 154

Octane number, 486 Offshore, - exploration, 374 - - , chronological order of events during, 375 - _ , drilling techniques, 375 - - , jackup drilling rigs for, 374, 376 _ - , semi-submersible drilling rigs for, 378 - - , ship-shape drilling units for, 337 - - , submersible rigs for, 374 - mooring systems, 401 - production facilities, 379 - _- , artificial islands, 379 - -- , -- ,gravel, 379 - -- , -- ,ice, 380

- -- , - , cost comparison of various, 398 - -_ , - , construction steps, 401 - -- , -, design considerations, 407 - -_ , - , -- , earthquake,409 - -_ , - , -_ , environmental forces, 409 - _- , - , -- , operational forces, 408 - _- , - , -- , pile capacity, 412 - -- , - , -- , wind and wave forces, 409 - -_ , - , fixed-bottom mounted type, 382 - - - - - -- - , gravity, 385, 388-390 - - - 7 , - - _- - , template-jacket type, 382, 386 - - - - - - _ - , tower (self floater), 384 - --, -, floating-buoyant type, 389

- -- , platforms, 381

9 ,

, >

- -- , - , - - - , guyed lower, 391, 392 - - - , - , - - - , tension-leg, 393-395 - -- , -, installation, 396- - -- , -, selection of, 398 - seafloor templates, 398 - -_ , integrated, 399, 400 - _- , modular, 399,400,407 - storage, 415-417 - subsea production systems (SPS), 403 - -_- , Exxon’s SPS, 406, 407 - --- , one-atmospheric chamber, 405 - --- , satellite well, 403

558

- --- , semisubmersible, 404 - --- , subsea atmospheric system (SAS), 405,

406 -- tanker loading, 417

transportation methods, 414 - --, tankers, 415 - --, underwater pipelines, 414 Oil, underground storage of, 457 Orifice meter, 13, 21, 22, 32, 33 - - chart, 40 - -- changer, automatic, 42 - -- integrators, 44-47 - -- planimeters, 43 -~ -- volume computation from, 53

- -, definition and description of, 34, 37 - - fittings, 23-25, 37-39 - - flow constant, 51-53 - -, flow formula for, 50-53 - -, flow rate equations for, 32 - -, history of, 33 - -, operation of, 35 - - pressure gauges, 39-41 - - pressure taps, 23, 24, 26, 27, 36, 37 - - plates, 23-25 - - readout devices, 21 Orsat gas analysis, 505-507, 517 Oxidation, 287 - -reduction potentials, 289 Oxidizing agent, 287 Oxygen, - , dissolved, measurement in waterflooding,

- , -, removal from water, 297, 363, 367 - induced corrosion, 296, 330 - scavengers, 297, 337

- coefficient record form, 55

340, 346, 350

Packers, - , casing, 85, 96-99 - , high-temperature thermal, 271 Penetrometer, 505 Pensky-Martens closed tester, 498, 515 Perlite, 70 - , expanded, 360 Permeability, - , effect of salinity on sandstone, 321 - , filtercake, 348 Pipelines, for water injection, 363 - , underwater, 414 Poisson’s ratio, 109, 112 Polarization, electrode, 285 Pollutants, 422 Pollution control, 421

Polymers, - as acid additives, 177-179 - as gravel-packing fluid additives, 203 Portland cement, 61-63 (see also cements) Positive displacement meters, 13, 15, 17, 18, 28 - _- , nutating disc type, 15 - _- , piston type, 15 - _- , readout devices of, 21 - -_ , rotary vane type, 15 - _- , specifications of, 21 Pour point of oils, 499, 516 Precipitation number, 501 Pressure, - , formation breakdown, vs depth, 102, 103 - , fracture closure, 116 - , fracturing, 102 - , grain-to-grain, 6, 7 - , overburden, 7, 110 - , -, vs depth, 103, 104 - , partial, 478 - , pore, 7, 110 - , surface treating (in fracturing), 116 - , tubing head, 2, 6 - , vapor, test, 484, 512 Production, - facilities, offshore, 379 - systems, subsea, 403 - techniques, 222 Productivity index, 108 Productivity ratio, 173 Proppant, 134 - , bauxite pellets as, 142 - diameter, relationship between permeability

- effect on fracture conductivity, 136-138 - fluid ratio, 149 - , glass beads as, 138, 142 - , permeability vs applied stress for various,

- properties, comparison of various, 142 - , resin-coated sand as, 140 - , sand as, 138, 141, 142 - , selection of, 135 - , sintered bauxite as, 140, 142 - , walnut shells as, 140, 142

and, 138

141

Radiant tube, - - arrangements, relative effectiveness of, 254 - - design, 252 - -, heat flux distribution (peripheral) for, 255 - -, pressure drop (two-phase) in, 228, 261 - - wall temperature, 256 Raoult’s law, 49, 478

559

Reid vapor pressure test, 484, 512 Relative permeabilities, effect of temperature on,

Resistivity, - profile, share, 7 - ratio, shale, 6

241

Salt, - cavern, 459 - - , design specifications for, 463 - - , measurement of, 468 _ _ , stability, nomenclature for, 462 - _ , sump development in a, 466 - cavity, 461 _ _ , creation of, 461 _ _ , storage requirements for, 461 - dome,459 _ - , advantages of storing natural gas in, 469 - - , profile of a, 464 _ _ , upward movement of projections by, 460 Salting-out effect, 330 Sand, 138 - as propping agent, specifications, 141, 142 - concentration effect on friction pressure, 118 - , frac, 138, 141, 142 - grains, roundness and sphericity chart, 199 - production, 191 - proportioner, schematic diagram of, 106 - sieve analysis, 192, 195, 196 - size, ten percentile point, 195 - uniformity coefficient, 196 Saponification number, 502 Saybolt viscosity, 496, 514 Scale, 325 - , calcium carbonate, 326 - , --, prevention of, 327 - formation, 325

, causes of, 326 - , sulfate, 327 - , -, prevention of, 327 Scavengers, - , hydrogen sulfide, 299 - , oxygen, 297, 337 Scrubbers, 436, 444, 446 - , ejector, 448 - , venturi, 447 Sea water, _ _ , biocidal treatment of, 338 - _ , calcium carbonate content of, 333 - - , characteristics of, 332 - - chlorination, 336 - - composition, seasonal changes in, 334 - - deaeration, 337

- -

- -, dissolved oxygen content of, 332 - - filtration, 336 - - injection, 332 - - intake, 334 - _ _ , design of, 335 - _ _ , elements of, 335 - _ , magnesium ion content of, 333 - - , marine growth in, 334 - _ , oil content of, 334 - - , oxygen scavenging of, 337 - _ , pH of, 333 - - , stabilization of, 338 - - , sulfate ion content of, 333 - - , temperature of, 338 Separators, for solids removal from water, 364 Shale, - bulk density variation with depth, 110 - resistivity, profile, 7 - - ratio, 6 - , undercompacted, 7 Soda ash, use in sulfur dioxide control, 443, 446 Solids, 323, 324, 339, 340, 346 - , adherent, 323, 324 - , filtered, 350, 351 - , non-adherent, 323, 324 - , removal of, 364, 366, 433 - , suspended, 323, 324 - , -, size ranges for, 434 Solution-mining system, 462 Sonar measurements, 468 Specific gravity, - _ , correction for friction losses for changes in,

- - difference between oil and water, tempera-

Specific heat of rocks, 231 Spending time, acid, 165, 183-185 Spherelite, 67 - as cement additive, 67 Steam, - additives, 244 - foam, 245 - generator, 247-261 - - design, 246, 247 - -_ , two-phase pressure drop in tubes, 228,

- -_ , vapor and liquid velocities in, 250, 251 - - downhole, 272, 273 - - heating requirements, chart, 260 - - , once-through, 250 - - , _ _ , radiant section of, 252

- - performance requirements, 246 - _ , thermal efficiency of, 259, 261, 262

119

ture effect on, 355

261

560

- quality measurement, instrumentation, 261 - -- system for 50-to-855& quality steam, 263 - temperature, friction loss effect on, 228 Steam injection, 221 - -, additives in, 244 - -, casing vent gas collection systems in, 450

- -, continuous, 240, 241 - -, -, typical project arrangement, 241 - - equipment components, 247 - --_ , casing vent systems, 272 - _ _ _ , feedwater treatment, 264 - --- , flue gas scrubbers, 267 - -__ , high-temperature thermal packers, 271 - _ _ _ , low-temperature economizers, 270 - _-- , steam generator, 247-261 - _--_ , downhole, 272, 273 - -__ , steam quality measurement instrumenta-

tion, 261 - _ , equipment design, 246 - - , --, convection section, 258 _ - , --, radian section, 252 - - , --, steam generator, 246, 247 - - , --, tube side flow, 249 - -, feedwater deaeration, 260 - -, fracture-assisted steamflooding (FAST),

245, 246 - -, heat losses in, 227

- , --- , frictional, 228 - - , -_- , surface radiation, 229 - - , -__ , to surrounding formations, 232, 234,

- -, cyclic, 238, 240

-

237 - , -_- , wellbore, 229, 233 -

- -, hot plate process, 245 - - mechanisms, 222 - -, oil/steam ratio (cumulative) in, 226 - - performance data, 224 - - performance prediction, Marx-Langenheim

- -, pollution control in, 436, 441, 447, 449, 450 - - projects, typical data, 225 - - rate, average, 226 - -, reservoir heating by, schematic diagram,

- - techniques, 238 - --, recent developments in, 244 - -, ultimate oil recovery by, 244 - -, well depth limitations in, 224 Steamflood emissions, 436 Stimulation ratio, 240 Stokes’ law, 426 Storage, - , offshore, 415-417

method, 235

242

- , underground, see underground storage Stress, compressive, 109, 110 - , tensile, 109, 110 Subsea production systems, 403-407 Subsidence, 6 Sulfide cracking, 292, 297 Sulfur content of, - -- fuels, 494 - -- lubricating oils, 503 Sulfur dioxide, - - as pollutant, 422, 436 - - control, 441, 452 - -- processes, chemical reactions in, 443 - _ emissions from oil-fired steam generators,

Sump development in a cavern, 466 Sonar caliper survey, schematic diagram of, solu-

437,441

tion cavities, 468

Tag closed tester, 498, 514 Tar sands, estimated world reserves of, 226 - -, fracture-assisted steamflood technology,

245, 246 TEL-meter, 487 Templates, 398 - , integrated, 399, 400 - , modular, 399, 400 Testing - , bacteria in water, 339, 342, 345, 350 - fuels, 483-495 - , jar , 433 - lubricating oils, 496-504 - oilfield wastewater samples, 431 - petroleum products, 475 - -- , aniline point of fuels, 492 - _ _ , ash content of oils, 501 - -- , carbon residue of oils, 501 - _- , charcoal test, 510 - -_ , cloud point, 499, 516 - -_ , color of lubricating oils and petroleum,

- _ _ , contamination of fuels, 487 - -- , corrosion test for gasoline, 495 - _- , corrosion test for lubricating oils, 504 - _- , dilution of crakcase oil, 500, 516 - -- , distillation, 475, 481, 511, 512 - -- , doctor test for sulfur content, 488 - -_ , dropping point of lubricating greases, 505 - _- , fatty oil content, 502 - _ _ , flash and fire points, 498, 514 - -- , fluorescent-indicator adsorption test of

- --, freezing point of fuels, 508

499, 515

fuels, 494

561

- -- , gasoline content of natural gas, 510 - -- , gravity, 483, 512 - -- , gum content of gasoline, 491, 492 - -- , knock properties of gasoline, 485 - -- , mercaptan sulfur test for jet fuels, 489 - _ _ , molecular weight by lowering of freezing

- --, neutralization number, 502 - --, organic acidity, 502 - --, Orsat gas analysis, 505, 517 - --, penetration number of lubricating greases,

-

- --, precipitation number of lubricating oils,

- --, saponification number, 502 - --, sulfur content of lubricating oils, 503 - --, sulfur lamp test for fuels, 494 - --, tetraethyl lead in gasoline, 487 - --, thermal value of fuel oil, 491 - -- , vapor pressure, 484, 512 - --, viscosity of lubricating oils, 496, 514 - --, viscosity index of lubricating oils, 497 - -- . water and sediments in petroleum by

- --, water in petroleum by distillation, 513 - --, water tolerance of aviation fuels, 489 Thermal, - conductivity of, - -- metals, 258 - -- rocks, 231 - diffusivity of rocks, 231 - efficiency of steam generator, 259 - ---_ vs flue gas temperature, 261, 262 - properties of rocks, 231 - value of fuel oil, 491 Throttling effect, 6 Turbine meters, 13, 15, 16, 27 - -, cross-section of, 17 - -, pressure drop curves for, 20 - -, readout devices of, 21 - -, specifications of waterflood, 19

point, 508, 518

505 --, pour point, 499, 516

501

centrifugation, 513

Undercompaction, 7 Underground storage of, - -- gas, - --- in aquifers, 458 - --- in depleted gas and oil fields, 458 - --_ in salt caverns, 459 - __- in salt domes, 469 - -- gas and oil, 457

, reasons for, 457 - ---__

Viscosity, - , dynamic, conversion factor, 521, 522 - index, 497 - , kinematic, 496 - of heavy oil vs temperature, 223, 224 - , Saybolt, 496, 514 Vortex flowmeter, 27, 28

Wastewater, - disposal, 424 - , removal of suspended solids from, 433 - treatment, - -, air flotation, 425 _ _ , --, dissolved, 426

, , induced, 425 - -, --, operation of, 429 - -, ancillary equipment for, 431 - -, --, automatic oil skimmer, 431, 432 - -, chemical treatment, 433 - treatment system, 424 - -- design, 424 Water, - , aggressiveness, 365 - and sediments in petroleum by centrifugation,

- chemical treatment systems for oilfield, 433 - contaminants, 423 - filtration, 357, 366 - -, selection of diatomite for, 362 - in petroleum by distillation, 513 - , injection suitability of, 319 - injection, causes of increased injection pres-

sure during, 320 - intake design, 335 - intake location, selection of, 334 - , oilfield, contaminated, 421 - preparation for subsurface injection, 353 - quality, 319, 423 - - for subsurface injection, 319 - - parameters, 423 - , removal of dissolved gases from injection,

- - -_

513

363, 367 , aeration, 363 , deaeration, 367

- --_--- - _-____ - , removal of solids from injection, 357, 364,

- , removal of oil from injection, 353 - --_-- , flotation, 356 - -__-- , gravity separation, 355 - sampling and testing, 431 - , sea, 332 - , -, characteristics of, 332

366

562

- , -, for injection purposes, 332 - , solubility of air in, 427 - tolerance of aviation fuels, 489 - treatment, 422 - , treatment and disposal of produced, 451 Waterflood. - , corrosion in, 327-330 - installation, schematic, 354 - rating chart, 348 - , sea water use in, 332 - test methods, 339 - --, aerobic plate count, 339, 342, 345, 350 - --, corrosion coupons, 343, 344, 348 - --, dissolved oxygen, 340, 346, 350 - --, iron count, 341, 345, 346, 348 - --, membrane filter test, 340, 351

- -- , significance of various, 344, 345, 346, 351, - --, pH, 340

352

- --, sulfate-reducing bacteria, 341, 345 - --, sulfide, 345, 350 - --, total bacteria, 342, 345, 350 - , equipment for injection, 363-368 - --- , chemical mixing and feed, 368 - , -__ , clarification, 366 - , --_ , deaeration, 367 - , --_ , degassing, 367 - , --_ , filter-aid filters, 367

, --_ , filtration, 366 - , --_ , flocculation, 366 - , --_ , pipelines, 363 - , --_ , separators, 364

- turbine meters, 15-17, 19-21 Weld decay, 290 WOC time, 76

-

Young’s modulus, 109, 112

Documents

Surface Operations in Petroleum Production II