Cranfield University

School of Energy, Environment and AgrifoodOffshore and Ocean Technology MSc

Low Cost Subsea Processing Systemfor Brownfield Developments

Academic year : 2014-2015

Industrial Partner: INTECSEA

Academic Supervisor: Dr. Fuat Kara

Delphine GALLAlberto GUIJARRO RODRIGUEZ

Kelvin Chidozie OKOLIEABOHPatrick C. OSERE

Peter OVUOMARAHASUAndre S.N.PIAZZINIOlawale B. SAMUELMoshood A.YAHAYA

27 April 2015

Cranfield University

School of Energy, Environment and AgrifoodOffshore and Ocean Technology MSc

Low Cost Subsea Processing Systemfor Brownfield Developments

Academic year : 2014-2015

Industrial Partner: INTECSEA

Academic Supervisor: Dr. Fuat Kara

Delphine GALLAlberto GUIJARRO RODRIGUEZ

Kelvin Chidozie OKOLIEABOHPatrick C. OSERE

Peter OVUOMARAHASUAndre S.N.PIAZZINIOlawale B. SAMUELMoshood A.YAHAYA

This thesis is submitted in partial fulfilment of the requirements forthe degree of MSC Offshore and Ocean Technology.

©Cranfield University 2015. All rights reserved. No part of this publicationmay be reproduced without the written permission of the copyright owner.

27 April 2015

Executive Summary

Many topside processing facilities are currently capacity constrained due to the volumes of producedwater that requires treatment. This is backing out potential oil production from other satellite dis-coveries. Reducing the amount of produced water requiring topside treatment would debottleneckthe topside facilities, increase oil handling capacities and also create space for additional productionand tieback of surrounding marginal fields. A viable option of addressing these challenges is throughSubsea Processing.

Some of the fields challenged with high water cut are brownfield with limited operational life, henceit could be capital intensive and uneconomical to invest in full subsea processing at such stage of afield’s life. It therefore become necessary to develop a low cost subsea processing system that couldbe economically suitable for brownfield development. This is the focus of this work.

An examination of existing subsea processing technologies and their suppliers were made and theiradvantages and limitation in brownfield application were assessed. Two different subsea processingsystem configuration options were proposed and analysed. An analysis of the various equipmentbuilding blocks such as separators, pumps, compressors, sand handling and water treatment unitwere performed and the chosen options justified.

A numerical simulation with matlab was performed to determine the sizing and capacity of a 3-phase gravity-based separator considered to be the preferred separator choice. The pump net positivesuction pressure and pump power requirement was calculated for different water depths, total pipelinedistance, flowrate and water cut. Furthermore, Hysys simulation was used to analyse the hydrocarbondata from balmoral field, UK which was used as a case study for this project.

Finally, a low cost subsea processing system for brownfield development comprising of a three phasegravity-based separator, oil and gas boosting pump and a water re-injection pump was proposed.

Acknowledgement

The members of Group D would like to appreciate everyone who has assisted us in the successfulcompletion of this group project.

We are grateful to John Purdue and Ronald Doherty of INTECSEA UK Ltd for their dedicationand relentless effort in monitoring our progress, and providing us with every necessary technical as-sistance, useful literatures and field data.

Our heartfelt gratitude also goes to, Engr. Basil Akpan of Westfield Subsea Ltd, who facilitatedthe success of this group work by providing us with directions and vital industry information.

Also, we appreciate Professor Guy Kirk for the feedback sessions he gave to the team members.He undoubtedly helped every group member of this team improve their technical and soft skills whichwas helpful in the successful delivery of this project.

Special thanks goes to our academic supervisors, Dr. Fuat Kara and Dr. Mahmood Shafiee ofCranfield University for their support, guidance and encouragement in completing this work.

Finally, we appreciate every member of the team for their selfless contribution to the group andthe high level of cooperation, understanding and diligence shared amongst the group. We anticipateworking again in the future.

Table of Contents

1 Project Introduction 11.1 Background of Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.2 Why Subsea Processing ? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11.3 History and Evolution of Subsea Processing . . . . . . . . . . . . . . . . . . . . . . . . 31.4 Major Suppliers of Subsea technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . 61.5 Project Aim . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71.6 Project Scope . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71.7 Project Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71.8 Concepts Design Philosophy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

2 System Configuration 82.1 Technical Option One . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82.2 Technical Option Two . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92.3 Selection of the Low Cost Subsea Processing System Configuration . . . . . . . . . . . 10

3 Subsea Processing Technologies 113.1 Subsea Separators and Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

3.1.1 Gravity Separator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123.1.1.1 Design Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . 143.1.1.2 Performance Impediments . . . . . . . . . . . . . . . . . . . . . . . . . 15

3.1.2 Compact and Dynamic Separator . . . . . . . . . . . . . . . . . . . . . . . . . . 163.1.2.1 Cyclonic Separators . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173.1.2.2 Hydrocyclone Separator . . . . . . . . . . . . . . . . . . . . . . . . . . 193.1.2.3 Compact Electrostatic Coalescer (CEC) . . . . . . . . . . . . . . . . . 213.1.2.4 In-line or Pipe Separators . . . . . . . . . . . . . . . . . . . . . . . . . 21

3.1.3 Semi Compact Gravity Separation System . . . . . . . . . . . . . . . . . . . . . 233.1.4 Caisson Separation System and Vertical Annular Separation and Pumping Sys-

tem (VASP) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 243.1.5 Comparison of Separator Technologies . . . . . . . . . . . . . . . . . . . . . . . 243.1.6 Technology Manufacturers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

3.2 Subsea Pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273.2.1 Single Phase Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273.2.2 Multiphase Pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

3.2.2.1 Advantages of Multiphase Pumping Technology . . . . . . . . . . . . 273.2.2.2 Multiphase Pumping Technologies . . . . . . . . . . . . . . . . . . . . 283.2.2.3 Electrical Submersible Pumps . . . . . . . . . . . . . . . . . . . . . . 293.2.2.4 Helico-axial Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . 303.2.2.5 Twin Screw Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

3.2.3 Intallation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 323.2.4 Suppliers/Vendors . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 333.2.5 Field Application/Operators . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

3.3 Sand Handling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 353.3.1 Sand Separation Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

3.3.1.1 Screen / Filter (Gravel Pack) . . . . . . . . . . . . . . . . . . . . . . . 353.3.1.2 Cyclonic (Desander, Inline) . . . . . . . . . . . . . . . . . . . . . . . . 353.3.1.3 Settling (Sand Jetting System) . . . . . . . . . . . . . . . . . . . . . . 38

3.3.2 Sand Removal/Disposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 393.3.3 The consequences of sand deposits . . . . . . . . . . . . . . . . . . . . . . . . . 403.3.4 Suppliers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

3.4 Water Treatment Technologies for reinjection . . . . . . . . . . . . . . . . . . . . . . . 413.4.1 Seawater Treatment Technologies . . . . . . . . . . . . . . . . . . . . . . . . . . 41

3.4.1.1 Topside Seawater Treatment . . . . . . . . . . . . . . . . . . . . . . . 413.4.1.2 Subsea Seawater Treatment . . . . . . . . . . . . . . . . . . . . . . . . 453.4.1.3 Subsea Produced Water Treatment Technology . . . . . . . . . . . . . 46

4 Proposed Subsea Processing System Building Blocks 494.1 Separator Selection Options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

4.1.1 Balmoral Fluid Composition Analysis . . . . . . . . . . . . . . . . . . . . . . . 494.1.2 Separator Options Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

4.1.2.1 Two Cyclones in Series . . . . . . . . . . . . . . . . . . . . . . . . . . 514.1.2.2 Cyclone and 2-Phase Separator in Series . . . . . . . . . . . . . . . . 524.1.2.3 Gravity Separator Options . . . . . . . . . . . . . . . . . . . . . . . . 534.1.2.4 Two-Phase Gravity Separator . . . . . . . . . . . . . . . . . . . . . . 544.1.2.5 Three-Phase Gravity Separator . . . . . . . . . . . . . . . . . . . . . . 55

4.1.3 Selection Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 564.1.4 Designing a Three Phase Gravity Separator . . . . . . . . . . . . . . . . . . . . 59

4.1.4.0.1 Operating Conditions . . . . . . . . . . . . . . . . . . . . . . 594.1.4.0.2 Produced Fluid Composition . . . . . . . . . . . . . . . . . . 594.1.4.0.3 Expected Water cut . . . . . . . . . . . . . . . . . . . . . . . 59

4.1.4.1 Calculation Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . 604.1.4.1.1 Compresibility factor . . . . . . . . . . . . . . . . . . . . . . 604.1.4.1.2 Gas Viscosity . . . . . . . . . . . . . . . . . . . . . . . . . . . 614.1.4.1.3 Souders & Brown Constant (K) . . . . . . . . . . . . . . . . 624.1.4.1.4 The Drag Coefficient . . . . . . . . . . . . . . . . . . . . . . 624.1.4.1.5 Gas Capacity & Liquid Capacity Requirements . . . . . . . . 634.1.4.1.6 Separator Dimensioning . . . . . . . . . . . . . . . . . . . . . 65

4.1.4.2 Separator’s Weight . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 664.1.4.2.1 Body‘s Volume . . . . . . . . . . . . . . . . . . . . . . . . . . 664.1.4.2.2 Semi-spherical Tap Volume . . . . . . . . . . . . . . . . . . . 674.1.4.2.3 Design Thickness . . . . . . . . . . . . . . . . . . . . . . . . 67

4.1.4.3 Separator Cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 684.1.4.4 Efficiency of the separation process in the liquid phase . . . . . . . . . 69

4.1.4.4.1 Retention Time . . . . . . . . . . . . . . . . . . . . . . . . . 694.1.4.4.2 Particle Diameter . . . . . . . . . . . . . . . . . . . . . . . . 694.1.4.4.3 Water cut . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

4.1.4.5 Analysis of the effects of the different variables involved in the designprocess (sensitivity analysis) . . . . . . . . . . . . . . . . . . . . . . . 74

4.1.4.5.1 Separator’s Weight . . . . . . . . . . . . . . . . . . . . . . . . 754.1.4.5.2 Separator’s Efficiency and Expected Water Cut . . . . . . . 76

4.2 Chosen Pump Option for Oil Boosting . . . . . . . . . . . . . . . . . . . . . . . . . . . 794.2.1 Boosting Pump Capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

4.2.1.1 Separator’s Pressure Drop . . . . . . . . . . . . . . . . . . . . . . . . 794.2.2 Oil and Gas Multi Phase Boosting Pump Capacity . . . . . . . . . . . . . . . . 80

4.3 Sand Handling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 834.3.1 When to use it ? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

4.3.1.1 Sand Handling technologies for a low cost subsea processing system . 834.4 Water Reinjection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86

4.4.1 The Seawater Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 864.4.1.1 Topside seawater treatment . . . . . . . . . . . . . . . . . . . . . . . . 864.4.1.2 Subsea seawater treatment . . . . . . . . . . . . . . . . . . . . . . . . 874.4.1.3 Seawater Treatment Options Assessment . . . . . . . . . . . . . . . . 88

4.4.2 The Produced Water Treatment . . . . . . . . . . . . . . . . . . . . . . . . . . 914.4.2.1 Safely tolerable amount of oil in injected produced . . . . . . . . . . 924.4.2.2 Subsea De-oiling Technologies . . . . . . . . . . . . . . . . . . . . . . 92

4.4.3 The Injection Pump . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 944.4.4 Summary & Conclusion for water treatment and injection systems . . . . . . . 96

5 Conclusion and Recommendations 97

A Computational Code for Designing a 3 Phase Gravity Based Separator 99

List of Figures

1 Subsea Processing (Source:FMC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22 Subsea separation and pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 Evolution of Seafloor well technology . . . . . . . . . . . . . . . . . . . . . . . . . . . . 44 Major Subsea Processing Projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 Subsea processing system configuration showing the equipments building block with

one production line and one topside water re-injection line. . . . . . . . . . . . . . . . 86 Subsea processing system configuration showing the equipments building blockwith two

production line and one topside water re-injection line. . . . . . . . . . . . . . . . . . . 97 subsea separator showing the input and output layout. . . . . . . . . . . . . . . . . . . 118 Ensepatec 3-phase separator: http://www.ensepatec.com/en/products/process-internals/three-

phase-separator-2.html, Accessed March 2015. . . . . . . . . . . . . . . . . . . . . . . . 129 Three Phase Vertical Gravity Separator [Mulyandasari, 2011]) . . . . . . . . . . . . . . 1310 Three Phase Horizontal Gravity Separator [Mulyandasari, 2011]) . . . . . . . . . . . . 1311 Typical Cyclonic Separator [BENAVIDES, 2012] . . . . . . . . . . . . . . . . . . . . . 1712 Gas Liquid Cylindrical Cyclone [Slettebø, 2009] . . . . . . . . . . . . . . . . . . . . . . 1813 Compact Cyclonic Degasser [Slettebø, 2009] . . . . . . . . . . . . . . . . . . . . . . . . 1814 Hydrocyclone Separator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1815 Sketches of a reverse-flow, cylinder-on-cone cyclone with a tangential inlet . . . . . . . 2016 Compact Electrostatic Coalescer (CEC) . . . . . . . . . . . . . . . . . . . . . . . . . . 2117 Schematics of Inline Cyclonic Units: Phase Splitter (Left), Deliquidizer (Middle) and

Degasser (Right) [SPE, 2012] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2218 Inline Cyclonic Separation Equipment: Liquid/Liquid Separator (Top Left), Phase

Splitter (Top Right), Deliquidiser (Bottom Left), and Desander (Bottom Right) . . . . 2319 Semi Compact Separator in Statoil’s Tordis Field . . . . . . . . . . . . . . . . . . . . . 2320 The Inlet Block of the Caisson Separator Used in the Shell Perdido Field . . . . . . . 2421 Multiphase Pumping Technologies currently utilized . . . . . . . . . . . . . . . . . . . 2922 Schematic of an ESP system Source: Islam, (2005, p.6) . . . . . . . . . . . . . . . 3023 HAP Compression Stage (Framo Engineering) . . . . . . . . . . . . . . . . . . . . . . . 3124 Distribution of a TSP Internals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3225 Multiphase Pump Module installation by cable . . . . . . . . . . . . . . . . . . . . . . 3326 Graph showing relationship between sand removal efficiency and the diameter of inline

Desander . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3627 A typical inline Desander, image source FMC Technologies inline Desander, accessed

22/04/2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3628 Desander (FMC Technologies) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3729 A wellhead Desander with oversized accumulator integrated into the well bay of a

production spar. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3830 Sand jetting for gravity settling systems . . . . . . . . . . . . . . . . . . . . . . . . . . 3931 Sand handling treatment and disposal (FMC technologie: Sand Handling Brochure) . 4032 Predicted typical oilfield production profile with (secondary Production) or without

(Primary Production) water injection. . . . . . . . . . . . . . . . . . . . . . . . . . . . 4133 Topside Seawater Treatment System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4234 Seawater Coarse Filter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4235 Coarse seawater filter package. (Courtesy of Cameron Process Systems) . . . . . . . . 4336 TIMEX fine filters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4437 Deaeration Tower . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4438 Solution with both the SWIT unit and an injection pump integrated into the same

subsea structure. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4539 Aspen Hysys analysis Phase envelope Balmoral Fluid composition . . . . . . . . . . . 50

40 Aspen Hysys analysis Critical Temperature: 226.2o and Pressure: 66.65 bar for Bal-moral Fluid Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

41 Image above shows A (Gas / Liquid Cylindrical Cyclone) in series with B (Hydrocyclone) 5142 Image above shows A (Gas/Liquid Cylindrical Cyclone) in series with B (2-Phase

Separator) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5343 Comparison between Horizontal and Vertical Separator . . . . . . . . . . . . . . . . . 5444 Subsea Processing System Configuration with a Two Phase Gravity Separator . . . . . 5445 Subsea Processing System Configuration with a Three Phase Gravity Separator . . . . 5646 Typical Design Retention Times in Three Phase Separation [Bautista and Gamboa,

2011] . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6947 Water particle diameter as a function of the oil retention time . . . . . . . . . . . . . . 7048 Cross Section of the Separator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7149 Graphic representation of the above equation and its linear plus parabolic approximation 7250 Expected water cut as a function of the particle diameter . . . . . . . . . . . . . . . . 7451 Sized Separator Weight as a function of the retention time . . . . . . . . . . . . . . . . 7652 Expected water cut, at different production levels with variable retention time . . . . 7753 Variation of the efficiency and the expected water cut at different levels of initial water

cut and retention time values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7754 Volume of Oil generated for every separator cycle, at different retention time levels . . 7855 Required Pump Head Pressure and Power for Different Initial Water Cut levels, with

a constant incoming Flow of 21000bpd among Different Production Distances of thePipe System, for a Constant Depth of 200m . . . . . . . . . . . . . . . . . . . . . . . . 81

56 Required Pump Head Pressure and Power for Different Initial Water Cut levels, witha constant incoming Flow of 21000bpd among Different Production Distances of thePipe System, for a Constant Depth of 200m . . . . . . . . . . . . . . . . . . . . . . . . 82

57 Mature Field Production Optimization [Bedwell et al., 2015] . . . . . . . . . . . . . . . 8358 Typical Topside seawater injection system . . . . . . . . . . . . . . . . . . . . . . . . . 8759 The Well Processing SWIT and The Seabox SWIT . . . . . . . . . . . . . . . . . . . . 8860 The Sorbwater Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9261 Inline Hydrocyclones . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9362 Assessment Matrix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9363 Produced Water Treatment Technologies Assessment Summary . . . . . . . . . . . . . 9364 Processing system with Produced Water Treatment . . . . . . . . . . . . . . . . . . . . 9465 Final Configuration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 97

List of Tables

1 Recent Subsea Processing and boosting installations . . . . . . . . . . . . . . . . . . . 52 Comparison between the identified low cost subsea processing system configuration

options. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 103 Advantages and disadvantages of horizontal and vertical separators . . . . . . . . . . . 144 Internal Devices and Separation Aids for Separators . . . . . . . . . . . . . . . . . . . 165 Dimension of Standard Cyclone, Columns (1) and (5) = Stairmand, 1951; Columns

(2), (4) and (6) = Swift, 1969; Column (3) and sketch = Lapple, 1951 . . . . . . . . . 206 Comparison of In-line or Pipe Separators . . . . . . . . . . . . . . . . . . . . . . . . . 227 Advantages of multiphase pumping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288 Advantages and limitations of Electrical Submersible Pumps . . . . . . . . . . . . . . 309 Advantages and limitations of Helico-axial Pumps . . . . . . . . . . . . . . . . . . . . 3110 Advantages and limitations of Twin Screw Pumps . . . . . . . . . . . . . . . . . . . . 3211 Field application of Multiphase pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . 3412 Equipment specification data (Wellhead Desander Halliburton) . . . . . . . . . . . . . 3813 Technical Specifications of a Coarse Filter . . . . . . . . . . . . . . . . . . . . . . . . . 4314 Balmoral Oil Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4915 Balmoral Reservoir Fluid Composition . . . . . . . . . . . . . . . . . . . . . . . . . . . 4916 Matrix analysis approach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5617 Separator Matrix Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5818 Operating Parameters of Balmora Field . . . . . . . . . . . . . . . . . . . . . . . . . . 7419 Table with the separator sizing for 21000bpd production rate . . . . . . . . . . . . . . 7520 Comparaison between Exclusionary techniques and Inclusionary techniques . . . . . . 8421 Advantages and Disadvantages of Topside and Subsea Treatment . . . . . . . . . . . . 8922 Advantages and Disadvantages of Disposal solutions . . . . . . . . . . . . . . . . . . . 9123 Single-Phase Centrifugal Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95

Abbreviations

API: American Petroleum InstituteBpd: B/D Barrels produced per dayBHP: Bore Hole PressureBOPD: Barrel of oil produced per dayCAPEX: Capital ExpenditureCEC: Compact Electrostatic CoalescerCD: Drag CoefficientCFU: Compact Flotation UnitCTAGC: constant of gas capacity processCTALC: constant of the liquid capacity processDSV: Diving Supply VesselDM: DiameterDi: Internal diameterE: Joint EfficiencyEp: Pump EnergyESP Electrical: Submersible PumpFW: Expected water cutGLCC: Gas-Liquid Cylindrical CycloneGoM: Gulf of MexicoGOR: Gas Oil RatioGVF: Gas Volume FactorHAP: Helico-Axial PumpHO: Oil thicknessIFP: French Institute of PetroleumK: Sounders and Brown ConstantLss: Total lengthLEFF: Effective lengthmD: MillidarcyMm: millimetresMMSM3/D: Million Standard Cubic Meter per dayMW: Mega WattMMBOPD: Million Barrel of Oil produced per dayMpa: MegapascalNFA: Net Free Arean: number of molesOPEX: Operational ExpenditureOTC: Offshore Technical ConferenceOiW: Oil in WaterP: pressurePFL: Pressure loss due to frictionPEH: Pressure loss due to elevation HeadPPR: pseudo-reduced pressurePCP: Progressive Cavity PumpPFR: Pump Inlet Flow Rate PressurePsi: pounds per square inchPPM: Parts per MillionPVT: Pressure Volume TemperaturePpmv: Parts per million by volumeQI: Flow rateQG: Gas Flow rate

QW: Water Flow RateQO: Oil Water RateR: Ideal Gas ConstantRE: Reynolds numberROV: Remotely Operated VehicleRDP: Roto-Dynamic PumpsRev/min: Revolution per minuteSCF: Standard Cubic FeetSTB: Stock Tank BarrelS: Maximum TensionSESV: Subsea Equipment Support VesselsSG: Specific GravityST: Total SECTIONSW: Water SectionSWIT: Seawater Injection and TreatmentT: temperatureTA: Axial ThicknessTD: Design ThicknessTSP: Twin Screw PumpTPH: Total Petroleum HydrocarbonTPR: Pseudo-Reduced TemperatureTR: Retention TimeTRW: Water Retention TimeTRO: Oil retention timeTR: Radial ThicknessTSS: Semi Spherical ThicknessUV: UltravioletV: VolumeVT: Settling VelocityVSEP: Volume of separatorVBODY: Body Volume of SeparatorVTAP: Tap Volume of SeparatorVASP: Vertical Annular Separation and Pumping SystemWC: Water CutWHD: Wellhead DesanderWSEP: Weight of separatorZ: Gas compressibility factor

α: Constantρg: Gas densityρl: Liquid densityη: Pump Efficiencyµg: Gas Viscosityµm: Micron∆p: Pressure differential∆γ: Viscosity differential3-PGS: 3 Phase Gravity Separator2-PGS: 2 Phase Gravity Separator

1 Project Introduction

1.1 Background of Work

Many topside processing facilities are currently capacity constrained due to the volume of producedwater that requires treatment at the topside. This is backing out potential oil production from othersatellite discoveries that could have been tied back to existing offshore platform; and thus reducingthe amount of produced water requiring topside treatment would increase oil handling capacities ofsuch offshore platforms.

There are strong indications that several offshore oil and gas fields are maturing and have alreadyor almost passed their production plateau. Several of these fields have now reached their productionpeak with reservoir pressures declining and their natural drive insufficient to maintain the originalproduction levels. Countering this trend leads to the critical point when a decision arises as to whenfields must either be abandoned or some form of additional pressure boosting provided in order toenhance recovery from these ageing fields.

Decommissioning offshore infrastructures from these fields could be very costly and the roundingexisting marginal field may never be produced. It is of interest to both the operators and governmentto maximise reserve recovery and tieback close by marginal fields. One way to debottleneck top-side facilities and increase hydrocarbon production from both existing and new fields is through theapplication of subsea processing system. Subsea processing, also known as seabed processing refersto the treatment of produced hydrocarbon on the seabed, in order to reduce the amount of topsideprocessing, enhance reservoir oil recovery and also reducing flow assurance challenges before gettingto the topside or onshore facilities. It also encompasses a number of different procedures to assistin reducing the capital expenditure, operating cost and complications of setting up an offshore field.Subsea processing technologies now provides tremendous solutions to offshore oil and gas productionwhich before now has been major challenge. This project therefore tries to address the challenge ofhigh amount of water cut from Brownfields using subsea processing system.

1.2 Why Subsea Processing ?

Subsea processing has huge tendency of optimising recovery by water/gas injection and also reducesdevelopment cost by transferring some of the traditional topside fluid processing to the seabed.

In addition, it saves space on topside facilities, as water separation and sand treatment processescan be carried out on the seabed, debottlenecking the processing capacity of the topside facility. Byremoving undesirable constituent of production at the seafloor, required transportation through flowlines and risers to the facility on the water’s surface for further reinjection is avoided. As shown inthe figure below.

1

Figure 1 – Subsea Processing (Source:FMC)

The key advantages of subsea processing are discussed briefly below.

Improved Reservoir Productivity: A fundamental benefit of seabed processing (separation andliquid pumping) is improvement in pressure drawdown as a result of reduction in back pressure andincrease in reservoir pressure through water reinjection. This results in increase in production ratesand improved oil and gas recovery. The use of a Single Phase pump overwhelms the static back-pressure of the fluid column along the production line from the seafloor to the surface, while alsoavoiding it avoids undue pressure drops and upsurge of multiphase flow.

Deepwater and Long-Distance Tiebacks: Subsea separation and liquid pumping allows easyflow of produced and processed hydrocarbon over a long step out distance, and in deep water applica-tion. This is as a result of the transportation of produced fluid by a mechanical means (use of pump)rather than full dependent on reservoir pressure for pumping. Subsea liquid pumps are currentlyavailable for most applications, while separator gas can flow long distances under natural pressure.

As large capacity production advances are made, subsea power supply and compressor systems, sub-sea gas compression becomes a viable option, allowing reduced pipeline size and even longer transportdistances.

Flow Assurance: Subsea processing can provide a cost resolution to flow assurance related chal-lenges. The subsea processing system in the figure below shows that the different phases of the wellstream is separated and conveyed in different pipelines, to eliminate multiphase flow and relatedproblems. Although the separated gas entering the flow line is saturated with water, which still raisesthe concern of hydrate formation, the volume of water can however be very much predictable, andtoo little to trigger hydrate formation. It also disqualifies the need to over inject inhibitor to mitigatewater slug, which is naturally avoided when liquid and gas flows in different flow lines, so as to allowthe use of the more environmentally friendly inhibitor like glycol that can be readily recovered andregenerated at the host platform.

2

Figure 2 – Subsea separation and pumping

Topside Facilities Limitations: Produced fluid gets to the platform facilities already processedand separated into various phase in the case of subsea processing which reduces the need for largeslug catchers and separators. Degassed oil and water can go through subsequent separations on theseabed with the produced water re-injected back to boost production, thus eliminating the need forsurface water treatment with a reasonable reduction in overall power requirement.

Unmanned, Safe and Minimum Facilities Developments: Aside the primary benefit of im-proved productivity and recovery, subsea processing also ensures oil and gas development with mini-mum production enables huge reduction in personnel requirement for operations. It ensures increasedsafety of personnel and environment as the facility is located far from the personnel. [Choi and Wein-garten, 2007]

1.3 History and Evolution of Subsea Processing

Subsea processing has been the subject of much research and development for many years. In thiscontext, the word “processing” is usually used to cover separation of sand, oil, water and gas, pump-ing, compression or any combination of these. However, despite all of this work and a number ofpilot projects in recent years, subsea processing has not yet become a routine operation. A number ofbuilding blocks have been demonstrated in the past with varying success. There remains much workto be done and indeed, there are technology gaps yet to be filled.

Since 1970, development of subsea separation and pumping systems has resulted in massive capi-tal investments, with lots of unresolved issues as a result of lack of clear understanding of the costbenefits of subsea developments, which led to an obvious lack of confidence and complete reluctancein carrying out a full commercial deployment of the technology.

The maiden step into conventional subsea processing originated from of subsea pumping system,having backpressure reduction as the main focus. The trend however moved from the stand alonepumping system to a more advanced separation and pumping operation. Gas and liquids separationtakes place subsea, with the gas (due to its natural tendency to flow on its own) flowing naturally and

3

liquids pumped to surface in order to reduce the back pressures and optimise production efficiency.

The subsea separation activity which was initially in form of primary separation, soon evolved intosecondary separation, with further water treatment and injection. In order to continue this giantstride, gas compression also became an additional subsea processing operation to carry out seabedgas compression which reduces backpressure on the reservoir and prevents slugging.

Figure 3 – Evolution of Seafloor well technology

The subsea separation and processing system has long been the major desire of upstream engineersand operators, this technology though relatively new and yet to gain wide acceptance has experiencedtremendous improvements. This dream was realised in 2007, with the successful startup of the FMCtechnology operated subsea separation, boosting and injection system on Statoils’ Tordis field in theNorth Sea. This installation popularly regarded as the first full-field subsea processing system, en-sured an increase in recovery by about 35MMBOPD and also extending the field life by 15 to 17 years.

Before the Tordis installations, operators only regard subsea processing as just a form of artificiallift method for subsea developments. However, with a more refined outlook to the technique, result-ing in both Green and more importantly Brownfield applications to reduce topside processing, it hasled to an increased drive in the usage of the technology. Future field developments can also gainfrom the application of subsea separation technology to reduce required topside processing facilityand by extension saving more on production platform costs while also improving profits on subseawells (which holds a predicted 400-500 increase in number of wells coming on stream from the year2011 [Howard, 2007].

Subsea processing can be key to operators’ project economics from startup of Greenfields. Lowertertiary fields mostly found in the Gulf of Mexico, with heavy oil and poor rock reservoirs, havebenefited from initial installation of subsea separation and pumping systems before commissioning.These options are forms a major part of the field development plan. Having the systems in placebefore the first oil can help the operator maintain production at a higher level for a longer period.

Another case of the usage of subsea processing system is in remote or harsh regions, where fielddevelopment options with surface facilities can be limited. In such cases, with more robust and so-phisticated subsea processing technologies, it is more likely to see full field development done subsea.A typical example is in the arctic regions where operator may not have the option to construct asurface facility [Perry and Rega, 2011].

The following shows a summary of some subsea processing technologies employed till recent time:

4

� Zakum Subsea Process System 1969, OTC 1083

� GoM Submerged Processing System 1975

� Highlander Subsea Slug Catcher 1985

� BOET Argyll Subsea Separator 1988, OTC 5922; 1990 OTC 6423

� GA-SP Goodfellows Statoil 1991 carried into Alpha Thames work

� Kvaerner Subsea Booster Station 1992

� GLASS Bardex 1993 OTC 7245

� VASPs Petrobras 1990 – 1998

� DEEPSEP MAI & Petrobras 1995

� ABB COSWAS 1997 – 2001

Table 1 – Recent Subsea Processing and boosting installations

The rapid growth in subsea production systems was mainly driven by major deep-water developmentsand the need for cost effective production of marginal offshore fields. However, there is also increasinginterest in extending the subsea tieback distance boundaries as well. “Subsea to Beach” developments,such as West Delta Deep offshore Egypt and Ormen Lange offshore Norway which have the additionaladvantage of requiring no personnel permanently based offshore, giving both safety, and cost benefits.

5

Figure 4 – Major Subsea Processing Projects

The Petrobras Marlim (2011) located in Brazil uses a 3-phase separation and water injection system.The water depth is about 900 metres, with a step out of about 5 Kilometres. The processing capac-ity of 22,000 bpd achieved a water cut of 67%. The project also made use of compact separators forde-oiling and de-sanding, alongside a water injection pump (1.9 MW/∆p 180 bar, OiW100 PPM). Ma-jor challenges solved for this project were high viscosity, sand production, reduced water production.

Considering the Petrobras’ Marlin project, which was one of the world’s first pilot system for deep-water subsea separation of heavy oil and water, it includes a reinjection of produced water to optimiseproduction in a mature field development. The system is aimed towards improving production, em-ploying the same topside facilities, or to completely replace the topside equipment. The field architec-ture maybe redesigned to incorporate more subsea separators to address existing wells. This improvedfield production life without adding different topside facilities, and thereby improving revenue withthe existing wells and floating units.

The world’s first gas/liquid separation and boosting system, on Shells’ BC-10 project (offshore Brazil),which was developed to operate over 13 subsea wells, with six subsea separators and boosters beganproducing heavy oil from ultra-deep waters in July 2009. The Shell Perdido project in the Gulf ofMexico also incorporates a subsea boosting and separation system, with same aim of achieving pro-duction.

On the 5th of September 2011, the first application of the subsea processing system in the WestAfrica region was recorded on Total’s Pazflor offshore project with a water depth between 800-900metres, a step out distance of 14 kilometers and a processing capacity of 110,000 BOPD and 1.0MMSM3/D utilizing a gas tolerant pump (Hybrid to 15% GVF, X 2.3 MW max Ap 180 bar). Thisinnovation was able to address the high viscosity and stable emulsion challenge. Large pressure dropin flowlines and risers where improved alongside the large amounts of methanol needed to hydrateprevention.

1.4 Major Suppliers of Subsea technologies

There are quite a few suppliers of subsea processing equipment already existing in the oil and gasmarket. The Leading suppliers of this innovative solution includes Cameron, OneSubsea., FMCTechnologies, GE Oil & Gas, Subsea 7, Technip, Expro, Intecsea and Foster Wheeler.

6

1.5 Project Aim

The aim of this project is to develop a low cost subsea processing system and can be employedin brownfields to cut down the amount of produced water transported to topside, and identify theequipment building blocks of the system and performing a detailed design of the equipments.

1.6 Project Scope

The scope of this project includes the identification of possible subsea processing system configura-tions, and also identify technologies available and equipment building blocks for each of the identifiedsubsea processing system. With an analysis of the identified options and a detail design of the pro-posed low cost subsea separation system.

1.7 Project Methodology

In order to objectively achieve the aim of the project, several fields currently employing subsea pro-cessing were thoroughly reviewed. These include Statoil Tordis field, Total Pazflor field, PetrobrasMarlim field, Troll and Balmoral field. Existing technologies from providers such as FMC technolo-gies, One Subsea, Cameron, Aker Solutions, GE and the technology they provide were reviewed andassessed.

Then different technical proposals suitable for relatively low cost subsea processing for brownfieldswere developed and assess based on their advantages and limitations; and an optimal subsea process-ing system established. Finally, the different equipment building blocks in the chosen low cost subseaprocessing system were discussed.

1.8 Concepts Design Philosophy

The configuration concepts are based upon existing, proven and readily obtainable components andtechnologies. The following design philosophies have been adopted in order to meet the project designobjectives:

� All components must be field proven in similar applications.

� All key components must be available “off the shelf”, preferably from more than one supplier.

� Design must minimize the number of “active” component. i.e. minimize the number of compo-nents which may require maintenance.

� All “active” component to be maintainable from a small to medium sized Diving Supply Vessel(DSV).

� Minimize life-cycle costs by reducing the need and frequency of intervention.

7

2 System Configuration

The configuration of the subsea separating system is critical to the overall effectiveness and cost ofa subsea processing system. For this project, two options have been taken into consideration andassessed to establish an optimum configuration for a brownfield development in terms of cost andfield reservoir characteristics.

The two subsea processing system configuration options considered are:

� Two Production Lines, One Injection Line

� One Production Line, One Injection Line

This chapter analyses two different configuration options for a subsea processing system, their equip-ment building block, merit and demerit of the configuration, the suitability of the configuration toa mature brownfield development in terms of cost and function (to reduce the amount produce wa-ter transported to topside); and finally, a selection criteria established to choose the optimal subseaprocessing system for brownfield development.

2.1 Technical Option One

Figure 5 – Subsea processing system configuration showing the equipments building block with oneproduction line and one topside water re-injection line.

The system equipments blocking block for this technical option one are:

� Separator

� Oil pressure boosting pump, and

� Water injection pump.

Produced reservoir fluid coming from the wellhead enters the separator, where the fluid is separated

8

into its gas, oil and water component. The separated components are then taken out of the separatorfrom different outlet. The efficiency of the separation is discussed further under separator design inthe next chapter.

The produced gas is again introduced back into the oil flow and boosted together to topside viathe production line. The existing topside injection is comingled with the separated produced water,and reinjected to maintain reservoir pressure and enhance hydrocarbon recovery.

It is assumed; and this is correct most of the time, that before the implementation of this optionthe brownfield already has installed a single production line that is been used for the transportationof the untreated produced reservoir fluid (gas, oil and water) and a water injection line used formaintaining pressure. Hence, in implementing this option no new additional riser line; which couldotherwise lead to a very substantial cost, needs to be installed as only the existing the productionline and water injection line is needed to implement this option. A short fall of this option is that theintroduction of gas in the oil line could lead to slugging.

2.2 Technical Option Two

Figure 6 – Subsea processing system configuration showing the equipments building blockwith twoproduction line and one topside water re-injection line.

The system equipments blocking block for this technical option one are:

� Separator

� Oil pressure boosting pump

� Water injection pump, and

� Gas compressor

The system configuration shown above in figure 6 is similar to that of option one except that twoproduction lines are employed (an oil production line and a gas production line) and a gas compressoris added. This is to enable the separated gas and oil to be separated to topside independently and

9

thus avoid the problem of slugging. This option is more feasible if the amount of gas produced fromthe reservoir is large.

The major short fall of this option is the cost involved in installation of a new additional riserline and the cost of the additional equipment – subsea gas compressor. Like it has been explainedabove, it is assumed that only two riser lines already exist in the brownfield, hence a new riser lineneed to be installed if the gas is to be transported to the topside independently.

2.3 Selection of the Low Cost Subsea Processing System Configuration

The separation of gas, water and oil and adequate sand management sand is a great benefit of subseaprocessing, resulting in increased production and improved way of handling flow assurance challenges.Although the subsea processing system configurations shown by both options one and two capturesmost of the benefits of subsea processing operations, like reducing back pressure, and eliminatingmultiphase flow assurance challenges. Considering the low cost approach to this project, the choiceof the subsea processing system configuration has been based on the suitability of the configurationto brownfield development in terms of cost and function (to reduce the amount produce water trans-ported to topside).

The table 2 below shows a comparison of the merit and demerit of the two different subsea pro-cessing system configuration considered, and that it forms a basis for the justification of the optionselected.

Table 2 – Comparison between the identified low cost subsea processing system configuration options.

From the analyses of the merit and demerit of the options, option one (one production line and onewater injection line) is the optimal subsea processing system configuration for brownfield development.In the next chapter, a detail description and design has been done of each of the equipment buildingblocks as outline in the chosen configuration option.

10

3 Subsea Processing Technologies

3.1 Subsea Separators and Technologies

Separators are a major building blocks of a Subsea Separation System used primarily to breakdownand separate various product composition from a reservoir. Operators choose many reasons for in-stalling subsea processing equipment. Subsea separation and processing system will enhance thehydrocarbon recovery from the field and water cut, especially in the case of a brownfields, thus in-creasing profits.

A mixture is considered heterogeneous, if it consists of two or more phases with different compo-sitions. Under careful observations, it is possible to see visible boundaries of separation between thevarious constituents of the mixture. Compounds and elements may be the building block of thesesubstances. The components and composition of the mixture can be separated by considering anappropriate and suitable technique [Viska and Karl, 2011].

An approach that exploits the basics of physics for use in the difference in density between thephases of the composition is very useful. The simplified classification of the likely phase separationare:

� Liquid – Solid

� Solid – Solid

� Gas – Solid (Vapour – Solid)

� Liquid – Liquid (Immiscible)

� Gas – Liquid (Vapour – liquid)

Subsea separator refers to equipment used in separating different phase compositions of producedhydrocarbon on the seabed. They convert marginal fields into economically viable developments usedto debottleneck on topside processing facilities. The choice of a subsea separator type depends mainlyon the aim and objective of the separation to be made, fluid composition, depth of operation andexpected flow assurance problems.

Figure 7 – subsea separator showing the input and output layout.

11

The main types of subsea separators are as follows:

� Gravity Separator

� Compact and Dynamic Separators

� Semi Compact Gravity Separation System

� Caisson Separation System

3.1.1 Gravity Separator

Subsea gravity-based separators (which are most widely separators in the oil and gas industry) op-erates on the principle of specific gravity differences of fluid composition to be separated. As shownin the figure below, the lighter fluid phase rises at certain rate which is dependent on the dropletdiameter and fluid viscosity [DAIGLE et al., 2012]. Oil droplets with smaller diameter rises slowlyand if the retention time of the separator is not sufficient, the water will exit the separator before thesmall droplets of oil rises through the water to form an oil layer.

Figure 8 – Ensepatec 3-phase separator: http://www.ensepatec.com/en/products/process-internals/three-phase-separator-2.html, Accessed March 2015.

Gravity-based separators are useful for the first line of a hydrocarbon separation. They are designedto ensure complete separation of gas in free water. Gases are mechanically withdrawn as a floatingphase, with oil occupying the intermediate column and water settling to the lower part of the vessel.The gravity-based separator can be configured both horizontally and vertically.

Vertical separators are used to separate fluids that are predominantly gaseous in composition. Theyare an ideal choice for separating fluids with more gas because gases require a larger coalescing area,which is offered by the longer distance in the vertical direction.

12

Figure 9 – Three Phase Vertical Gravity Separator [Mulyandasari, 2011])

However, horizontal separators are ideal for separating fluids, which consists of mainly liquid. Thequality of liquid / liquid separation depends on the retention time of the separator, which is a func-tion of the separator length and diameter. Hence, the longer a separator, the higher the retention orsettling time and by extension, the higher the efficiency.

The gravity-based separator performs to about 50% to 90% efficiency in the removal of free oilabove 150µ. However, the major downside to the usage of gravity-based separator is that solublecomponents of the total petroleum hydrocarbon (TPH) are not efficiently removed with the process.It is recommended free oil concentration in the range of 15 -100ppm [DAIGLE et al., 2012].

Figure 10 – Three Phase Horizontal Gravity Separator [Mulyandasari, 2011])

Asides the vertical or horizontal orientation classification of gravity-based separators; it can also beclassified as either two or three phase. A two-phase separator is used for liquid / liquid or gas / liquidseparation, while the three-phase separator is used to separate gas, oil and water.

13

Table 3 – Advantages and disadvantages of horizontal and vertical separators

3.1.1.1 Design Considerations

The design of the vessel internals could fundamentally influence the working performance of a sepa-rator through it drop / bubble shearing and blending, foam creation, distribution, mixture and levelcontrol. A major factor to be considered for design of a separator is the settling hypothesis or re-tention time for its liquid holding column. Separators are designed with sufficient margin to handleliquid surges or production changes regularly experienced amidst production. They have the followingfunctional zones deliberately designed to produce and attain its required performance.

� Inlet zone

� Flow distribution zone

� Gravity separation / Coalescing zone

� Outlet zone

Inlet Zone

The inlet zone takes care of the initial bulk separation of the oil (liquid) and gas, removing mostof the gas from the liquid. The gas separation would be effected as the pipe leads it into the separatorbecause of a drop in pressure across a control valve or upstream choke. Cyclones are now beingconsidered in the inlet design to address foaming issues and high capacities handling. Flat impactplates, dished-head plates, half-open pipes, vane-type inlet and cyclone-cluster inlet are examples oftypical inlets.

These aforementioned inlet types, though inexpensive, often affects separation performance, as inletselections may pose a huge challenge for fluids with higher momentum. Foams and small drops mayoccur when a dished-head or flat head plate are used [Wally, 2013].

Flow Distribution Zone

A poor separation efficiency may result from short-circuiting irrespective of the size of the sepa-rator vessel. An important addition and consideration to the inlet is flow straightener, which may be

14

a single perforated baffle plate. The uniform flow of the gas and liquid after it leaves the inlet (cy-clones, impact plates, or vane-type inlet) is solely dependent on the diameter of the plate. The biggerthe plate, which also doubles as a foam breaker and an impingement demister, the more uniform theflow [Heijckers, 2012].

The net-free area (NFA) which is between a range of 10 to 50% when lowered leads to a higherfluid shear, so that it can match a particular application. A major concern is the solid build-up thatoccurs on the upstream side of the plates. The inlet velocity is enough to move the solids throughthe perforations. A flush nozzle installed in the inlet zone will likewise aid its proficiency.

Gravity/ Coalescing Zone

The internal of a gas / liquid gravity separator is sometimes fitted with plate / matrix packs, meshpad, and vane pack to aid separation and foam breaking. These internals help enhance coalescingeffect of the dispersed phase by providing a better impingement or searing surface. In a gas phase,liquid drop coalescence or foam breaking can be attained by utilising the matrix / plate packs andvanes. The principle of installation of the high surface internals like the plate packs for foam breakingis so bubbles stretches and break as they drag across surfaces. Be that as it may, if the bulk of thegas flows through the top portion of the pack, the foamy layer will not be sufficiently sheared, andthe bobbles will meander through to the other end

Outlet Zone

All mist elimination equipment can be classified as cyclones, fibre-beds, mesh and vanes. The cap¬tureof mist can happen by three mechanisms; it is noteworthy, that there are no clear limitation betweensystems. The droplet momentum varies directly with liquid density and the diameter of the cube,heavier or larger particles tend to resist following the streamline of a flowing gas and will strike objectsplaced in their line of travel.

The mechanism in charge of removing most particles of diameter > 10µm is termed inertial im-paction. Direction impact defines a situation when particles with smaller diameter that follows thestreamlines collide with the solid objects, if their distance of approach is less than their radius. Itis frequently the governing mechanism for droplets in the 1 to 10µm range. With submicron mists,Brow¬nian capture becomes the predominant collection mechanism. This relies on Brownian motion:the unbroken random motion of droplets in elastic collision with gas molecules. As the particlesbecome smaller and the velocity gets reduced, the Brownian capture becomes more efficient.

3.1.1.2 Performance Impediments

Foaming (froth) happens, when there is a pressure reduction on some reservoir oil types, leadingto the dispersion of tiny bubbles of gas that are encased in a thin film of oil are dispersed whenthe gas is liberated from the solution. For some other crude oil types, the oil viscosity and surfacetension may mechanically hold gas in the oil and may lead to a similar impact to foam. Oil foamis not particularly steady or durable except in the presence of a foaming agent in the oil. Organicacids are the major foaming agent, while high-gravity oils and condensates do not result in foamingsituations [Callaghan et al., 1985].

The ability of an oil / gas separator is reduced by foaming, needing a higher retention time forproper separation of a given quantity of foaming crude oil. It is difficult to measure with conventionalvolumetric metering vessels or a positive-displacement foaming crude oil. It leads to loss of oil andgas as such special equipment and procedures are required in handling such challenges. The underlisted factors assist in breaking / reducing foaming and to eliminate entrained gas from the oil:

15

The under listed factors assist in breaking / reducing foaming and to eliminate entrained gas fromthe oil:

� Agitation (baffling)

� Centrifugal force

� Chemicals

� Heat

� Settling

Table 4 – Internal Devices and Separation Aids for Separators

3.1.2 Compact and Dynamic Separator

The installation and maintenance of the traditional gravity based separator poses a huge challenge fordeep-water applications. The focus of the offshore industry was channelled into a research programmeto seek alternative technologies that could meet requirement for deep-water application; this led tothe development of compact and dynamic separators.

The main driver behind manufacturing compact separator is to improve project economics or re-duce project cost especially in deep water. Using large gravity based separator for deep water affectsoverall cost of subsea station [SPE, 2012]. This is because the prospect of retrieving separators forrepairs in deep water is completely remote.

The available technology of compact separator varies, a few of which are explained below:

� Cyclonic Separators

� Hydrocyclone

� Compact Electrostatic Coalescer system- Aker Solution

� In-line or Pipe Separators

16

3.1.2.1 Cyclonic Separators

Cyclonic separators are used in the oil and gas industry for separating particulates from gas or liquidstream, without using any filter through vortex separation. This technology utilises the principle ofrotational impact and gravity to separate mixtures of solids and fluids. Additionally, it can also beused in separating fine droplets of liquid from a gaseous stream.

A typical cyclone is made up of an inlet, two outlets for the separated fluids and a cylindrical bodywhere a swirl is created, which then introduces centrifugal forces on the fluid stream as shown inthe figure below. The centrifugal force is several times the gravitational forces [Slettebø, 2009]. Dueto differences in density, the liquid will travel outward forming the outer vortex and moving in adownward direction. The gas on the other hand moves inward and form the inner vortex and travelsin the upward direction towards the gas outlet.

Although the cyclonic separator offers a system of separation at low cost and easy retrieval, theirdesigns are very complicated when compared to the simple gravity settling systems, with potentiallyexpensive operating cost because of their eroded parts which can easily experience failure. Despiteits limitations with respect to cost, their removal efficiency is preferable when compared to that ofthe gravity separators especially when used for smaller particle sizes.

Figure 11 – Typical Cyclonic Separator [BENAVIDES, 2012]

The Gas-Liquid Cylindrical Cyclone (GLCC) below was an outcome of a joint research by Chevronand Tulsa University [Slettebø, 2009]. Its main feature is the downward-tilted inlet, with the mainaim of forcing the liquid level below the inlet zone, to reduce the carryover of liquid into gas stream.The carryover of liquid to the gas stream which would have been experienced with a horizontal inletprevents stratification and hence a pre-separation in the pipe. The gas and liquid outlet on the otherhand are made of horizontal pipes.

17

Figure 12 – Gas Liquid Cylindrical Cyclone [Slettebø, 2009]

Below is another type of cyclonic separator, the Compact Cyclonic Degasser, which was developedby Aker Solution.

Figure 13 – Compact Cyclonic Degasser [Slettebø, 2009]

Figure 14 – Hydrocyclone Separator

18

3.1.2.2 Hydrocyclone Separator

A gas cyclone is the type of cyclone used for separating gas, the term Hydrocyclone however refersto a cyclonic separator used for separating either of solids, or liquids from a liquid [Husveg et al.,2009]. The hydrocyclone separator is used mainly to separate a two-phase composition of either gas/ liquid, liquid / liquid or liquid / solid. It uses an induced cyclonic rotation to force the heavierparticle of the mixed phase in one direction while forcing the lighter phase in the opposite direction.The heavier phase moves outwards and leaves the lighter one to remain in the middle section. It hasan inlet or entrance, a body and two exists. The design in most cases includes the rotational flow orcyclonic motion [Osvaldo Zuniga, 2013].

The Hydrocyclone, cylindrically constructed, is fitted with more than one inlet that causes fluidentering into it follow a circular path on the wall. By the rotation of the fluid, a centripetal ac-celeration field, thousands of times larger that of the earth’s gravity when generated causes heavierwater and solids to move towards the outer wall while causing the lighter material to move to thecentre. By establishing a conical or cylindrical container also referred to as a cyclone, a very highspeed rotating flow established is the basis of operation of the hydrocyclone. The rotation or spinningmotion generates strong centrifugal forces. This in turn causes air to flow in a helical array, beginningat the wide end, which is the upper part of the cyclone and it ends at the narrow end, which is thebottom before the liquid exits the system in a straight stream through the centre of the cyclone andout at the top.

The hydrocyclone when used for pre-treatment is a bulk separator for large concentrations of gas,hydrocarbons, and solids in the wastewater stream. The separator helps to remove oil droplets andsolid particles greater than 100 microns in size, which yields a 90% removal efficiency. For primarytreatment, the vessel is designed to remove all droplets of oil and remove particles containing solidsof sizes greater than 35% microns. A significant amount of emulsified oil and suspended solids areeffluent of the primary treatment. A downstream secondary treatment can help to eradicate thesuspended solids and emulsified oils. The hydrocyclone removes particle within the range of 5-15microns, and does not remove soluble oil or grease.

Standard Dimension of a Cyclone

During the design of cyclones, good consideration of previous working standards were adopted todefine how varying dimensions of cyclones would affect its performance. A typical example still usedtoday is a design standard by Shepherd and Lapple (1939 and 1940), who determined the “opti-mal” dimensions for cyclones. Succeeding investigators testified similar work result as such; cyclones“standard” became adopted.

19

Figure 15 – Sketches of a reverse-flow, cylinder-on-cone cyclone with a tangential inlet

The geometrical notations indicated in the right sketch are:

a – Inlet heightb – Inlet widthh – Height of cylindrical sectionhc – Height of conical sectionD – Body diameter (barrel diameter)Ht – total height of the cyclone (roof to dust exit)Dx – Vortex finder diameterS – Vortex finder length (roof to separation space)Bc – Cone-tip diameter (dust exit diameter)

The table below shows dimensions related to the cyclone’s body diameter. It recapitulates the dimen-sions of standard cyclones of the three different types, with the highlighted option the most adopted.The selection of other options depends on the target objective of the separation process.

Table 5 – Dimension of Standard Cyclone, Columns (1) and (5) = Stairmand, 1951; Columns (2), (4)and (6) = Swift, 1969; Column (3) and sketch = Lapple, 1951

Primarily, a hydrocyclone is an economical and recognised technique with little or no moving partsin this device, which makes its fabrication easier. Depending on the intended usage, hydrocyclones

20

allow manufacture size more compact whereby they take little or no space topside or subsea. Recentinnovations now allow the possibility to place hydrocyclones in multiples next to each other either ina parallel, in a series or both combination set-up.

3.1.2.3 Compact Electrostatic Coalescer (CEC)

This small lightweight flow-through system, which was developed by Aker Solution, greatly im-proves the efficiency of separation by existing downstream gravity separation equipment. This iscan be achieved by coalescing emulsified water droplets caught in the crude oil into much largerdroplets [AkerSolution, 2015]. The coalescing action takes place very rapidly under turbulent flowconditions as the emulsion is subjected to an intense electrostatic field.

In addition to reducing space and weight requirements, the CEC provides a proven efficiency levelwhen debottlenecking. If an existing separator is being modified without any alteration in its existinginstallations, a compact electrostatic coalescer may also be considered.

Figure 16 – Compact Electrostatic Coalescer (CEC)

3.1.2.4 In-line or Pipe Separators

In line or pipe separators involves the use of cyclones in the pipelines, in order to effect separations.Below are different types of inline separators.

� Dewaterer: This is used to remove water from oil stream. It can be used as the second line ofseparation after the gas / liquid cyclone, in a train of separation made of mainly cyclones

� Inline Phase Splitter: It is used to split the flow in a gas volume fraction between 10% and90%. Usually, it takes care of the first stage separation before some finer separation is done tothe separated flow. It enables separation of two uniform phases.

� Inline Degasser: It removes gas from a liquid stream. The gas outlet includes a second stageseparator system for the removal of liquid droplets that were entrained in the gas.

� Inline Deliquidiser: This is used to separate liquid from a gas stream. The liquid outletincludes a second stage separator system for removing of bubbles of gas that followed the liquid.

� Inline Electrostatic Coalescer: Like the CEC, it increase the size of water bubble in oil.

� Inline Demister: A bundle of small diameter demisting cyclones (Spiral flow) in a pipe spool.

� Bulk Deoiler: Separates oil from water stream.

21

� Desander: Used to separate solid from gas and liquid or multiphase stream.

Table 6 – Comparison of In-line or Pipe Separators

The figures below shows the various types of inline separators.

Figure 17 – Schematics of Inline Cyclonic Units: Phase Splitter (Left), Deliquidizer (Middle) andDegasser (Right) [SPE, 2012]

22

Figure 18 – Inline Cyclonic Separation Equipment: Liquid/Liquid Separator (Top Left), Phase Splitter(Top Right), Deliquidiser (Bottom Left), and Desander (Bottom Right)

Although the compact separator reduces the capital cost of a subsea processing project and increasethe ease for the retrieval of a separator, reduction in separator size, it however, comes with an un-wanted trade off effect with performance. Compact separators, with reduced sizes affects separationperformance and the ability to handle change in flow, and thereby raises serious doubt in its confor-mance with separation requirement especially when operation is under slugging condition [Hannisdalet al., 2012].In effect, the risk for loss in revenue because of poor separation performance is increased comparedto that of the non-compact traditional gravity separator, thereby affecting the overall cost of thesubsea station. In shallow water, the installation can be made easier if the size is within the capacityof a diver crane. Although the retrieve-ability of a separator is affected by module weight and theavailability of intervention ships, it becomes less of an issue for a gravity separator because of itsusually high reliability and mean time to failure.

3.1.3 Semi Compact Gravity Separation System

It is a system that Incorporates the use of a typical gravity based separator with a Gas-liquid compactcyclonic at the inlet, hence the name Semi Compact. Gas liquid separation takes place at the inletwhile liquid/liquid Separation takes place in the Gravity vessel. The most common example of theusage of a semi compact gravity separator is in the case of Tordis’ subsea processing system, assemblesby FMC Technology for Statoil.

Figure 19 – Semi Compact Separator in Statoil’s Tordis Field

23

3.1.4 Caisson Separation System and Vertical Annular Separation and Pumping Sys-tem (VASP)

The caisson is generally a tall separator that is usually installed in a dummy well. The system hasa tangential inlet to a tall narrow vessel that handles slugs, provides surge volume for the producedhydrocarbon to be separated, and supports the ESP.The vertical annular separation and pumping system (VASPS) is another type of separator that isvery much similar to the caisson separator. The VASPS is made up of an internal helix that separatesthe pressure housing and the inner gas annulus in the tall separator. The VASP like the Caissonseparator is also installed in a dummy well.

Figure 20 – The Inlet Block of the Caisson Separator Used in the Shell Perdido Field

Caisson Separators are generally more complex than the gravity separators. It comprises the caissondriven into the seabed, and a cylindrical cyclonic gas liquid separator at the top and an electricalsubmersible pump (ESP) located further down inside the caisson. The processes of separation in acaisson separator is as follows:

� The produced fluid comes into the caisson through the inlet block, which is just above the mudline and then moves into the separator via a purposefully angled and tangential inlet.

� As the fluid stream flows in downward direction, the spiral designed flow pattern gives riseto a liquid and gas separation. The separation occurs by a combination of centrifugal andgravitational force, which throws the heavier liquid or fluid to the wall of the separator

� The separated liquid continues with the downward flow to the caisson sump, where the ESPpumps it upward.

� The separated gas flows upward due to its own pressure.

3.1.5 Comparison of Separator Technologies

The following table compare separator technologies.

24

S/N SEPARATOR TYPE

ADVANTAGES DISADVANTAGES

1

Gravity Separator

� Simple Concept � High Reliability and Mean Time To

Failure � Better Sand Separation From Fluid

Stream with a sand flushing system � Good Separation Efficiency � Tested with success in shallow water

processing � Can be Installed with diver crane � Reduced operating cost because of

reduced level of required intervention due to little or no repairs

� Might not require batch separation � Effective handling of change in flow � Meets oil in water requirements � Performs well in treatment of high Oil

concentration. � About 50-99% efficiency in removal of

free oil particulate above 150µ

� More difficult to install than the compact separator because of its size

� High capital cost � Requires sand flushing or

jetting system as sand settles at the bottom without following water

2

Inline or Pipe Separator

� Smaller size, hence more suitable for higher depth and high design pressure.

� Suitable for separating difficult fluid

� Not good in handling change in flow

� Overall system still as bulky as the gravity, with only diameter reduction#

� No recorded test and success level in shallow water

� Not efficient for one batch three phase separation

� Sand handling is a major challenge.

� Will not handle large slug except with slug catcher.

3

Cyclonic Separator � Smaller size, hence more suitable for higher depth and high design pressure.

� Handle sand easy because it goes out together with the separated water

� Not good in handling change in flow

� No recorded test and

success level in shallow water

� Not efficient for one batch three phase separation

� Challenges with meeting requirements for both Oil in water and Water in Oil

� Results in large pressure drop

� Requires extra water treatment technology.

4

Semi Compact Gravity Separation System.

� More optimal separation compared to the Gravity separator.

� Tested on the Tordis field with recorded success.

� Like the gravity, it is good with sand treatment.

� Handles higher gas flowrates than the gravity separator.

� Separates three-phase in one batch, with gas separation taking place at the inlet G/L Cyclone.

� Also more difficult to install, even though it is more compact than the gravity separator.

� Like the Gravity separator, requires sand flushing system.

5

Caisson Separation System and VASP

� Suitable for deep water with recorded success.

� Not effective for high level of produced sand.

� Huge operating cost which may arise through drilling of the required dummy well

� Retrieval of ESP can be very challenging.

3.1.6 Technology Manufacturers

� Subsea 7

� Technip

� Cameron

� Saipem

� One Subsea

� Expro

� General Electric Oil & Gas

� Foster wheeler

� FMC Technologies

26

3.2 Subsea Pumping

3.2.1 Single Phase Pump

Historically, single phase pumps have been used by the oil and gas industry and are based on thefollowing operational principles:

� Positive-displacement pumps: capable of physically moving a volume of fluid from low pressureto high pressure.

� Roto-dynamic pumps (RDP): transfers kinetic energy to fluids utilizing a rotating impeller andsubsequently transforms the kinetic energy to potential by means of a static diffuser.

� Hydraulic pumps: transfer kinetic energy from high velocity fluid to low pressure fluid.

The single phase pumps are used to boost fluids to the topside, when the gas volume fraction (GVF)is low, that is if the fluid stream is mainly liquid. However, with the growing needs for multiphaseproduction, other pump variants were proposed on the basis of single phase pumps concept. FrenchInstitute of Petroleum (IFP) and Total began research into multiphase pumping in the mid-1970s andlimited their work to topside application due to technical requirements in system footprint.

3.2.2 Multiphase Pumping

Subsea multiphase pumping has become the most commonly applied subsea processing technologyand has advanced to become a major oil and gas production tool aimed at increasing the flow ofproduced hydrocarbons from a reservoir, to the host facility [Bai and Bai, 2010].

Subsea pumps are used to either inject produced and/or treated water into the reservoir as wellas directly boost produced oil and gas to a host facility.

According to [Schoener, 2004], in the past 15 years multiphase pumps have gained acceptance by theglobal oil and gas industry and has thus replaced other conventional production equipment becauseof its simplicity, operational flexibility and economic viability. Following its emergence, multiphasepumping has been beneficial and utilized in offshore fields in the Gulf of Mexico, North Sea, AlaskanNorth Slope, Middle East and West Africa. Various pumping systems are available with each tech-nology possessing its own operational window and application niche which is discussed further in thischapter.

3.2.2.1 Advantages of Multiphase Pumping Technology

Multiphase pumps for subsea and downhole applications have been available for decades, and hasbecome a viable solution to a range of field developments. The advantages of multiphase pumpingover other single phase production methods is summarized in the table below.

27

Table 7 – Advantages of multiphase pumping

3.2.2.2 Multiphase Pumping Technologies

Today, the leading multiphase pumps designs are classified into two categories, positive displace-ment and roto-dynamic concept, and certain criteria govern the pump selection based on its intendedapplication. These pump concepts have been utilized onshore, offshore, downhole and subsea. TheProgressive Cavity Pump (PCP) and Electrical Submersible Pumps (ESP) are used for downholeapplications, while the Twin Screw Pump (TSP) and Helico-Axial Pump (HAP) being the mostcommonly used pumps for subsea applications. The figure below illustrates the commercialized andestablished pumping technologies available for multiphase fluids. This section focuses on HAPs andTSPs utilized for subsea applications which falls in line with the project objective, while brieflyexplaining the downhole ESP technology.

28

Figure 21 – Multiphase Pumping Technologies currently utilized

3.2.2.3 Electrical Submersible Pumps

ESPs are widely used in upstream oil production as an artificial lift method for boosting moder-ate to high volumes of fluids from a reservoir, a driver module and a pumping unit makes up the ESPmodular. The volumetric flow rate of this pump can vary between 150 and 64,000B/D with pressuresup to 6,000 psi but depends on factors such as gas oil ratio (GOR), bore hole pressure (BHP) andwater cut (WC) [Islam, 2005]. Downhole HAPs which are designed to be a priming device and caneliminate gas separation, is always connected upstream of a standard ESP, which is used as the mainproduction device. However, ESPs gas handling capabilities is limited to 75% suction GVF [Huaet al., 2012] and requires additional gas separation to further handle higher GVF. Similarly, multi-vane centrifugal pumps can be coupled upstream of a standard ESP to increase its tolerance in gassywells. The downhole and surface components of an ESP system is shown in the diagram below, withthe operational benefits and constraints of ESPs summarized in the table below.

29

Figure 22 – Schematic of an ESP system Source: Islam, (2005, p.6)

Table 8 – Advantages and limitations of Electrical Submersible Pumps

3.2.2.4 Helico-axial Pumps

The HAP has an operating principle similar to a centrifugal pump whereby rotating impellers in-creases the fluid kinetic energy and transfers this energy to potential energy by means of staticdiffusers. HAPs utilize specifically designed impeller geometry as shown below, which when comin-gled with a hydraulic channel profile, reduces the radial flow component and results in an axial flowinstead.

30

Figure 23 – HAP Compression Stage (Framo Engineering)

Multiphase HAPs till date, used for surface and subsea applications have been manufactured withimpeller diameter ranging from 70mm to 400 mm and normally falls between 3,500 and 6,500 rev/min.They also cover a flow rate (includes water, oil and gas) at suction conditions between 22,000 to450,000B/D with a differential pressure up to 2900psi (Hua, 2012). HAPs are widely recognizedto handle suction GVF beyond 90% but in reality this could vary between 0% and 100% makingtheir range of operating parameters wide. The advantages and constraints in this pump technologyis summarized in the table below.

Table 9 – Advantages and limitations of Helico-axial Pumps

3.2.2.5 Twin Screw Pumps

TSPs have gained predominance in topside heavy oil production and can be dated back to 1934where it was developed primarily for this purpose. TSPs are available as low pressure pumps up to45 psi and differential pressures high as 1,450 psi with rotational speed ranging between 600 to 1,800rev/min but have been reliably run at 3,600 rev/min to attain higher capacities. At suction conditionthey can achieve volumetric flow rates (oil, water and gas) from 10,000 to 300,000 B/D depending ontheir size [Hua et al., 2012].

TSPs are hydraulically balanced and features two parallel helical screws meshed with each otherand torque is transmitted by timing gears on the end of shafts. The timing gears and drive shaftsin most designs are external to the pumped fluids, timing gears are oil lubricated while shafts couldbe oil or grease lubricated in order to improve overall system reliability with heat dissipation. In

31

operation, these screws rotate in opposite directions and results in the helical channel of one screwbeing periodically obstructed by the other screw. This configuration enables the pumped fluid toform many small chambers and fill the clearances between one screw’s flange, another screw’s shaftbody and a liner which is displaced during operations shown below.

Figure 24 – Distribution of a TSP Internals

TSPs offer several advantages in certain applications and their operational capabilities can howeverbe constrained, which is summarized in the table below.

Table 10 – Advantages and limitations of Twin Screw Pumps

3.2.3 Intallation

Multiphase pumps are installed in remote locations from onshore, topside to subsea. Installation ofthese packages require unmanned and reliable equipment. SESV (Subsea Equipment Support vessels)and if necessary, heavy compensation systems utilizing guidelines or guideline-less methods are usedfor such operations. The pump module can be installed on mud mats or suction piles/anchor locatedat the sea bed. The image below illustrates installation of a pump module with guidelines.

32

Figure 25 – Multiphase Pump Module installation by cable

3.2.4 Suppliers/Vendors

The main pump suppliers for HAP, TSP and ESP subsea pump technology applications includes thefollowing:

Helico Axial Pumps

� Frank Mohn AS (www.framo.com)

� Sulzer (www.sulzer.com)

Twin Screw Pumps

� Bornemann (www.bornemann.com)

� Flowserve (www.flowserve.com)

� GE oil & gas (www.gepowerconversion.com)

� Leistritz (www.leistritz.com)

� Clydeunion (SPX) (www.spx.com)

� Colfax Fluid Handling (www.colfaxfluidhandling.com)

Electrical Submersible Pumps

� Schlumberger (REDA) (www.slb.com)

� Baker Hughes Centrilift (www.bakerhughes.com)

� Canadian Advanced ESP (www.cai-esp.com)

� Halliburton (www.halliburton.com)

� Weatherford (www.weatherford.com)

33

3.2.5 Field Application/Operators

The oil and gas industry being a dynamic one that has sought advancement in technology driven bynumerous factors such as extended water depth, harsher environments and optimization of lifecycleperformances. Over the years, subsea pumping technology has seen improvement from single phasepumps to state of the art multiphase pumps, the table below shows various pump manufacturers andoffshore fields utilizing multiphase HAP and TSP technologies.

Table 11 – Field application of Multiphase pumps

34

3.3 Sand Handling

The difficulty in accessing potent data from the formation depth and enclosing volumes has madeaccurate prediction of sand production rate and volume an uphill task. Thus, over the last decade newtechnologies for solids handling, especially sand, has been developed in order to increase separationefficiency, reduce the equipment size and consequently improve hydrocarbon production.

3.3.1 Sand Separation Technologies

3.3.1.1 Screen / Filter (Gravel Pack)

For optimum hydrocarbon recovery, gravel pack, screen, and filters are widely accepted sand con-trol techniques to restrict sand from leaving the wellbore into the processing modules either topsideor at the seabed. The completion equipment, especially the gravel pack, has a confirmed and testedinstallation and working base and thus forms the bulk of conventional sand management. Duringsand production controls in wells, these methods might yet allow the passage of 50 to 125 µm through(even basic working conditions) interfering with operations. In event of failure in completion jobssand volume and particle sizes might increase swiftly, resulting in restricted recovery and damagedequipment.

3.3.1.2 Cyclonic (Desander, Inline)

Desander

Desanders are cyclone (centrifugal devices with no moving parts) which remove solids from the wellstream. The produced crude oil is boosted into the wide top part of the cyclone at an angle roughlytangential to its circumference. As the hydrocarbon streams around and steadily down the inner partof the cone shape, solids are removed from the liquid by centrifugal forces. The solids continue roundand downward to exit at the hydrocyclone base and are discharged into an accumulator tank, fromwhich they are purged periodically.

Inline Desander

The Inline Desander removes sand from single and multiphase reservior fluid. The system can becustomized to suit any application. It use the same principle as the Desander and it is a compactcyclonic unit without any reject streams that can handle a wide range of flow rates and achieve ef-ficiencies up to 99%. Particle sizes down to 1 Micron can be removed depending on the size of theunit. The sand removal efficiency can be seen on the Figure below.

35

Figure 26 – Graph showing relationship between sand removal efficiency and the diameter of inlineDesander

The fluid enters the Desander axially (or tangentially) while the pressure energy plus swirls elementinitiates circular motion (Centrifugal force). The developed gravitational force separates sand particlesfrom the process stream and finally clean underflow reverses to outlet through the internal low-pressurecore.

Figure 27 – A typical inline Desander, image source FMC Technologies inline Desander, accessed22/04/2015

The compactness of the inline separators allows it to be built and installed to standard piping speci-fication, with limited weight and space requirement.

36

Figure 28 – Desander (FMC Technologies)

Wellhead Desander

The active influence for evolution of the wellhead Desander (WHD) was to upgrade the scope ofoperation of the cyclonic technology to the multiphase flow regime. Multiphase Desander functionsbased on the combined effect of the hydraulic and pneumatic cyclonic standards [Rawlins, 2002]. Insimilar operating principle of a standard cyclonic devices, pressure energy is transformed to radialand tangential acceleration to impart centrifugal forces on the enclosed fluids. The improved forcesspeeds up the dissolution of phases with distintive densities. For a multiphase Desander, solids areremoved from the fluid stream. The transmitted force is about 400-5006 times higher than gravity,resulting to fast-tracked removal of solids from fluids and also neutralizing the effect of any externalforce on the performance of the cyclone. The equipment specification data of a multiphase desanderHalliburton is showed below on table 12.

37

Table 12 – Equipment specification data (Wellhead Desander Halliburton)

The removed solids are gathered into a vessel or accumulator chamber scheduled retrieval, with nostoppage of the unceasing fluids flow as illustrated in Figure 28. Cyclonic technology has the highestthroughput-to-size ratio of any type of static separation equipment resulting in minimal installedfootprint and weight [Rawlins, 2003].

Figure 29 – A wellhead Desander with oversized accumulator integrated into the well bay of a pro-duction spar.

3.3.1.3 Settling (Sand Jetting System)

The Sand Jetting system is about the most frequently employed upstream separator to get rid ofaccumulated solids from the base of a gravity separators. Solid removal is achieved by introductionof pressurized water with specially invented nozzles. The solids are subsequently disposed using sand

38

drains placed down the length of the vessel. The system can be configured to flush out the entirevessel independently, or for sectional flushing of reduced length, in case of shortage in water supply.

Due to difficulty in cleaning a clogged nozzle, a sand is often set up, just above the sand drain,to avoid the blockage of the nozzle before flushing. The sand pan is made up of a triangular cut outsdown its length through which the fluidized sand will pass to get to the sand drains. It is the basicfunction of the flushing nozzles to keep these triangular openings clear of clogs, to guarantee effectiveflushing rounds.

Figure 30 – Sand jetting for gravity settling systems

3.3.2 Sand Removal/Disposal

Separate solids from the well fluids and manage as separate flow stream. Different ways of handlingsand removal/disposal are available in the market the technologies / ways that could be fitted on oursubsea processing system are highlighted below.

� Containerize: In order to collect the sand produced for a late removal, accumulation bags,tubes and flexible containers can be implored. This can also be collected into a vessel andretrieved by ROV, wireline or float to surface. As we are dealing with mature field and theexpected field life is 3/5 years, the simplest way to retrieve the sand for a late disposal iscontainerizing it.

� Inject into disposal well: All the sand produced is re-injected back into a disposal well androute upwards to the topside facility and can be further handle.

� Add back to oil stream:The separated sand is redirected to the oil and move up to theplatform processing facility. The main disadvantage is that a new process of sand separationmust be made topside in order to separate the sand again. In addition erosion on the valvesand pipes could occur.

� Particle consolidation: Consolidate particles into solid or semi-solid shape, for ease of carry-ing or contained seafloor disposal. The main techniques used are - Compress into puck which isa mechanical densification; Adhesive polymer, an extruder can be added; Add cement to makebrick.

� Clean and seafloor discharge: The sand removed from the well stream is treated, cleanedand posteriorly discharged on the seafloor. The quality of the sand (Oil concentration) mustbe within the established parameter by the local authority. Although OSPARCOM commis-sion, which protects and conserve the north-east Atlantic and its resources, still allow the sanddis¬charge (lwt% oil on dry solids) the ultimate aim is to cease the discharge, emission andlosses of hazardous substance by 2020. Despite the laws being restricted continuously, FCM

39

technologies designed a outright solution for retrieving sand from the production stream andfor proper treatment of the sand for disposal as shown in the figure below 31:

Figure 31 – Sand handling treatment and disposal (FMC technologie: Sand Handling Brochure)

3.3.3 The consequences of sand deposits

Continuous deposition of sand in a separators results in corresponding proportional reduction ofavailable separator capacity. For instance, a separator half filled with sand only possess an effectivecapacity of 50% with a corresponding half capacity lost to sand accumulations, thereby reducing theretention time by 50%The operator would then need to decrease fluid flow to half in order to maintainthe residence time. The sand gathering can cause production drop. Another source of worry is thata flushing system can be overwhelmed by excessive sand accumulation in the separator, and becomeless capable of ejecting sand from the separator base. It would take a complete intervention processto retrieve the separator to dispose the sand.

3.3.4 Suppliers

Several companies offer a wide range of sand handling facilities. Some of the more active are:

� ASCOM

� FMC

� KERBS

� IWS

� DDS

� HALLIBURTON

� SCHULUMBERGER

40

3.4 Water Treatment Technologies for reinjection

The extraction of the hydrocarbon from a reservoir leads to the drop of the pressure in the reservoir,which decreases the recovery. To deal with this issue, water is injected through injection wells intothe reservoir to maintain the pressure and the recovery.

Figure 32 – Predicted typical oilfield production profile with (secondary Production) or without(Primary Production) water injection.

The volumes of water required for injection are reservoir specific but range from 110% to more than400% of peak oil production rate.

This part reviews the technologies currently available in terms of seawater treatment, produced watertreatment and water reinjection.

3.4.1 Seawater Treatment Technologies

To maintain pressure into the reservoir, seawater is injected. However, the raw seawater requires tobe treated before injection to avoid well damages due to bacteria or corrosion.

Two kind of Seawater treatment are currently available:

� Topside Seawater Treatment

� Subsea Seawater Treatment

3.4.1.1 Topside Seawater Treatment

Topside seawater treatment deals with seawater treatment on the rig. This system is composedof:

� A Seawater lift Pump

41

� Filters

� A Deaeration Tower

� A Booster Pump

Note: The heat exchanger is not a seawater treatment device, but the seawater is used to feed it tocool hydrocarbons, and then the water is treated.

Figure 33 – Topside Seawater Treatment System

Filters

� Seawater Coarse Filter with Automatic Backwash

Figure 34 – Seawater Coarse Filter

The objective of this first filtration is to remove the coarse suspended solids that could deposit

42

in equipment or plug pores of the reservoir formation [Humborstad, 2013].

This device is fully automatic, reliable and provides an efficient filtration. This technologyis used for more than 15 years in the North sea and worldwide.

This technology of coarse filtration offers a range of advantages:

– Automatic Cleaning

– No interruption required for cleaning operations

– Long life Time

– The design can be easily changed regarding seawater composition

Figure 35 – Coarse seawater filter package. (Courtesy of Cameron Process Systems)

The technical specifications of the filter are described in the following table:

Table 13 – Technical Specifications of a Coarse Filter

� Fine Filtration

The seawater go through a second filter which allows a fine filtration. Indeed, solids up to0.1 µm can be removed. During this step, scrimpy sand particles, algae, micoorganisms areremoved to obtain a seawater dree of solids.

43

Figure 36 – TIMEX fine filters

Deaeration Tower

Removed dissolved oxygen widely presents into surface seawater is essential to avoid the corrosion ofthe downstream devices or of the well and control the bacteria growth.

The gas removal process consist of [EQUIPMENT, 2012]:

� Heat the seawater until its saturation temperature. The solubility of the oxygen will decreaseand attempted zero.

� The heated seawater is agitated. Water is spraying in a thin film to reduce the distance requiredby the gas bubble to be released by the water.

Figure 37 – Deaeration Tower

44

Biocide Injection

Surface water contains biological constituents which may affect the good operating of the processingsystem and of the water injection. Bacteria growth causes injection-well plugging and helps corrosion.

The most commonly biocide are used to kill anaerobic and aerobic bacteria, they are:

� Chlorine (very effective for seawater)

� Aldehydes

� Amines

� Chlorinated phenols

� Organometallic compounds

� Sulfur organic compounds

Suppliers

Topside Seawater Treatment packages are widely offered by Oil & Gas suppliers. The followinglist quotes some of them:

� Expro

� Siemens

� Veolia

3.4.1.2 Subsea Seawater Treatment

The seawater treatment can also take place subsea, on the seabed. It is called Sea Water Intakeand Treatment (SWIT). The treatment of the seawater is done by one single unit installed subseawhich performs three steps of water treatment (disinfection, solid removal and final cleaning) andincludes an injection pump [?].

Figure 38 – Solution with both the SWIT unit and an injection pump integrated into the same subseastructure.

45

First Technology Step: Disinfection

The first step of SWIT treatment process is the disinfection by Chlorine exposure. Chlorine is usuallyused to remove microorganisms from water. The efficiency of the Chlorine treatment depend of thechlorine concentration, the time of exposure and the pH of the water. When the water enter intothe SWIT, through grids on the top of the device, it goes through several electro chlorination cellsproducing sodium hypochlorite: the disinfection process begins.

The disinfection process is controlled by sensors which allow the adjustment of the chlorine levelin the treated water and thus avoid the water to be polluted by a too high amount of chlorine.

Furthermore, the SWIT allows a exposure time of chlorine between 60 to 120 minutes against 60to 90 for topside facilities. This long exposure time allows a very good kill rate of organic speciesinitially present in the seawater. This part of the process takes place into a chamber called “stillroom”.

Second Technology Step: Solid Removal

The second stage of SWIT seawater treatment is solid removal. Thanks to it particularly design,the unit gives rise for low laminar and low speed flow to guarantee an effective settlement of solids.The SWIT is able the remove 99% of particle greater than 18 micron with a flow capacity of 40,000bpd.

Third Technology Step: Final cleaning

The last step of the seawater treatment happens in a hydroxyl radical generator which cleans thewater by breaking into smaller particles the dead bacteria. Finally the treated water is injected intothe reservoir thanks to an injection pump.

Suppliers

The SWIT technology is new and currently offers by a few suppliers. The two main companiespropose industry version of SWIT:

� Seabox

� Well Processing

3.4.1.3 Subsea Produced Water Treatment Technology

The produced water is the water separated from the hydrocarbons during the processing. This watercontains oil particles, organic and inorganic particles, bacteria, chemical. The concentration of theseparticles depends of the field composition and the efficiency of the separation. To avoid pollutionof the environment (if the produced water is discharged) or of the reservoir (if the produced wateris reinjected), different kind of treatments have been developed. The most current produced watertreatments are:

� Oxygen Removal / Deaeration

� Bacteria Removal / Desinfection

� Demineralization

� Grease Removal/ Deoiling

46

Oxygen Removal / Deaeration

It is important that as low as possible oxygen remain in the water to avoid damage of equipments bycorrosion or bacteria growth.

Several technologies for sea water deaeration are available and include the following;

� Chemical dearetion: utilizes the addition of a sulphite based chemicals to water to form sulphates

� Membrane deaeration: employs the concept of a hollow-fiber hydrophobic membrane to transfergas from the liquid phase across the membrane to the gas phase

� Contacting towers: are tall towers with either trays or packing’s inside and provides surfacearea for water and stripping gas to get in contact

Bacteria Removal / Desinfection

Disinfection treatments for produced water helps in the removal of algae, microorganisms, virusesand mitigates scaling and water contamination. Microorganisms such as sulphide reducing bacteriaoccur naturally in produced water and when pumped in the formation without proper disinfection,reduces under anaerobic conditions and leads to severe corrosion of tubular and surface equipment.

Chlorine/iodine reaction, pH treatment and ultraviolet radiation (UV) treatment are among avail-able remediation for treating produced water or sea water in order to satisfy disposal regulations andminimize corrosion. According to [Team, 2010], the UV disinfection is a primary form of disinfectioncause of its simplicity, no chemicals required and no formation of by-products.

A typical UV disinfection entails water to be treated being pumped through an UV reactor equippedwith an array of UV lamps supplying disinfection dosages of 30-50 mega joules per square centime-tre, thus making pathogens inactive as they pass through the reactor. However, the desired level ofdisinfection depends on the duration of exposure.

Demineralization

This is the removal of cations and anions associated with substances that are dissolved in wa-ter [Sharma, 2007]. The removal process is carried out by passing the water through a cation exchangerto remove cations, and the through anion exchange units which absorbs anions. The cation removalprocess is referred to a decationisation, while that of anion removal is termed deionisation. Thistreatment is useful to avoid the the presence of minerals sush as salt which can reduce lifetime of theequipments.

� The anion exchange process involves the exchange of anion between electrolytes dissolved inwater and a granular solid material immersed in water. The granular solid material is usuallyreferred to as anion exchange material or anion exchanger. The anion OH− can also be used asan exchanger, just like aother anions like the CL−, CO2−3 and HCO3−.

� The deionisation process makes use of special-manufactured ion exchange resins, which removesionised salts from water. It can theoretically remove up to about 100 % of salts in water.

Grease Removal/ Deoiling

47

This is the removal of any dispersed oil or grease present in produced water. Oil and grease in pro-duced water can be inform of free oil, dispersed oil and emulsified oil. Oil and grease removal methodsdepend on the end usage of treated water and composition of oil in the produced water [Arthur et al.,2005].

The technology for deoiling varies with varying complexity of operaions, although the basic prin-ciple involves the collection and recovery of valuable oils and the removal of undesirable pollutantsbefore discharge to a receiving system. The type of wastewater treatment systems used in the oilprocessing wastewaters are usually a lot more bigger in size and more complex than those found inother industries.

Two main technologies for deoiling are available in the market:

� Inline Sorbwater Process : It is a technology owned by FMC Technologies which manage geaseremoval using a chemical treatment, a CFU and a polisher.

� Inline Hydrocyclone: This a technology based oon a unique axial flow design and This deviceworks as a typical hydrocyclone separator described before. FMC Technologies offers a goodInline Hydrocyclone providing a high separation efficiency with a low pressure-drop. It is re-sistant to the corrosion and to clogging. Its well operating has been proved since 2011 on thePetrobras Marlim Subsea Separation Project [FMCTechnologies, 2015].

48

4 Proposed Subsea Processing System Building Blocks

4.1 Separator Selection Options

For an effective separator selection process, an analysis of the fluid composition alongside differenttypes and arrangements of separators would be helpful in determining the most suitable option forthe case study being examined.

4.1.1 Balmoral Fluid Composition Analysis

Generally, two or three different types of fluids phase exists in the reservoir. A typical reservoirusually contains formation water which seats on the aquifer, and also hydrocarbon fluid which caneither be oil or gas, or both.

Effective assessment of reservoir behaviour depends mainly on the PVT (pressure, volume and tem-perature) relationships of the different fluids that exists side by side in the reservoir. It is a traditionalpractice in petroleum engineering to illustrate the phase behaviour of reservoir fluid on the P-T graph(phase diagram), which shows the pressure and temperature limits above which the reservoir fluid existas a single phase. It also shows the oil and gas proportion and different points (different temperatureand pressure) within the two phase range.

Table 14 – Balmoral Oil Characteristics

Table 15 – Balmoral Reservoir Fluid Composition

49

Figure 39 – Aspen Hysys analysis Phase envelope Balmoral Fluid composition

Figure 40 – Aspen Hysys analysis Critical Temperature: 226.2o and Pressure: 66.65 bar for BalmoralFluid Composition

The phase diagram of the Balmoral field sample typifies a Volatile oil reservoir behaviour, with the

50

phase envelope that is relatively wider than that of the condensate gas and a little less than that ofthe black oil reservoir. The volatile oil is also referred to as the near critical oil, because its initialreservoir temperature is close to the critical temperature. It is called volatile oil because a littlereduction of pressure below the bubble point pressure causes a significant amount of oil to vaporise.

The gas oil ratio of the volatile oil is between 2000-3000 scf/STB, with and API gravity of over40o [Manning and Thompson, 1995]. Specific gravity of the volatile oil is less than 0.82.

4.1.2 Separator Options Analysis

4.1.2.1 Two Cyclones in Series

Figure 41 – Image above shows A (Gas / Liquid Cylindrical Cyclone) in series with B (Hydrocyclone)

In the option considered above, two cyclones A and B are adopted in the configuration and connectedin series. The first cyclone A is the Gas Liquid Cylindrical Cyclone (GLCC) is majorly used forpre-separation or partial separation of raw gas from high-pressure wells. A typical GLCC is made upof an inlet, two outlets for the separation and a cylindrical body where a swirl is created, which thenintroduces centrifugal forces on the fluid stream. The centrifugal force is several times the gravita-tional forces [Slettebø, 2009]. Due to differences in density, the liquid will travel outward forming theouter vortex and moving in a downward direction, the gas on the other hand will move inward andform the inner vortex and travels in the upward direction towards the gas outlet. Separation will oc-cur much faster; hence, the separation equipment can be smaller, reducing both footprint and weight.

51

The GLCC is a technology with a compact, low-cost simple separator. It has an efficiency for 5- 200 micron particles and a high volume flowrate. Compared to conventional separators, it receivesa better economical attraction over a range of application. The biggest obstacle to the broader ac-ceptance and usage of GLCCs has been the lack of trustworthy performance prediction tools if theirapplication is successful. A gas-liquid cyclone separator was developed with an auger internal fordownhole and surface separation of raw gas. They showed that the auger cyclone could successfullyseparate up to 80% of the gas without significant liquid carry-over into raw lift gas stream, with thereport indicating total cost as 2% of conventional separators. This assisted in reducing or eliminatinggas compression facilities, thereby separating a substantial portion of the gas, which in turn willreduce fluctuations in the liquid flow and may result in improved performance of other downstreamseparation devices [Weingarten et al., 1995].

As the gas extraction takes place through one outlet, the liquid, a combination of oil and wateris expelled through the lower outlet, which is then channelled into the second hydrocyclone B. Thisacts as a primary separator. The hydrocyclone, cylindrically constructed, is fitted with more than oneinlet that causes fluid entering into it follow a circular path on the wall. By the rotation of the fluid,a centripetal acceleration field, thousands of times larger that of the earth’s gravity when generatedcauses heavier water and solids to move towards the outer wall while causing the lighter materialto move to the centre. The oil leaves through the upper outlet while the by-product – water leavesthrough the lower outlet.

Several combinations of GLCC and jet pumps that could be used to extract energy from high-pressuremultiphase wells to boost production from brownfields and low-pressure wells has also been experi-mented. Krebs Petroleum Technologies is exploring the use of a GLCC in series with other compactseparation devices such as a wellhead desanding hydrocyclone and a free water knockout hydrocyclone.Chevron is investigating the series combination of a GLCC with a free water knockout hydrocycloneand a deoiling hydrocyclone in an effort to improve discharge water quality [Sarshar and Loh, 1995].

4.1.2.2 Cyclone and 2-Phase Separator in SeriesThis option considers two basic arrangements of the two basic separators in a series connection.

52

Figure 42 – Image above shows A (Gas/Liquid Cylindrical Cyclone) in series with B (2-Phase Sepa-rator)

In the arrangement above, the GLCC is used to separate the gas from the reservoir fluid. After theseparation, the fluid is then transported to the next separator, which is a 2-phase gravity separator.The assumption here is that the gas must have been totally removed as such; the two-phase gravityseparator only handles oil and water separation. It uses gravity as a major basis of separation. Waterthat is denser than oil settles below and the oil, which is less dense, floats. This layout arrangementis very efficient if the reservoir contains a very large amount of gas.

4.1.2.3 Gravity Separator Options

The gravity based separator is the most widely used separator technology for subsea application,especially in shallow water processing of produced fluid, mainly because of its effectiveness, reliabilityand ease of maintenance. It presents a relatively expensive capital cost, due to its large compart-ment vessel, bulky size and massive weight, which affects its install-ability especially when installedalongside other components of the processing system. It however offers a very cheap operating cost,because of its high reliability and mean time failure, which reduces its maintenance cost to a con-siderably low level, which makes a better alternative to the cyclonic separators and other types ofcompact separation system.

The vertical gravity based separator is employed in case of a gas driven fluid, while for an oil drivenfluid the horizontal based separator provides a better solution. After a careful examination of the dif-ferent fluid compositions for the given Balmoral field which provides a volatile oil reservoir behaviour,a horizontal based separator will be selected for a better separation of the predominantly oil reservoirproduced fluids.

53

Aside the fact that the horizontal separator separates produced fluid with little gas compositionsbetter, it is also cheaper, easier and cheaper to ship and assemble. It also requires less amount of pipeconnection for field connection [Viska and Karl, 2011]. The table below shows a comparison betweenthe horizontal and vertical gravity separator, which justifies the usage of the horizontal gravity basedseparator.

Figure 43 – Comparison between Horizontal and Vertical Separator

The only major advantage of the vertical separator over the horizontal, is that it requires lesser space,but this is would have been an issue for topside application, due to minumum space on the platform.However for subsea application, there is an abundance of space at the seabed for installation. Thecomparison above shows the horizontal gravity separator as a better fit for a subsea processing systemapplication, taking into account the result of the fluid composition analysis. It also offers a cheaperand easier fabrication and installation subsea.

4.1.2.4 Two-Phase Gravity Separator Following the decision to go for the horizontal gravitybased separator, also the usage of the existing production and injection without the installation of anew injection line, the system in the figure below is considered. It is made up of a two phase gravityseparator and two pumps.

54

Figure 44 – Subsea Processing System Configuration with a Two Phase Gravity Separator

Two phase gravity separators can be used for either a liquid/liquid separation, or a liquid/gas separa-tion. With the reservoir behaviour of the fluid compositions analysis result, showing a predominantlyoil reservoir and little gas, a liquid/liquid two phase separator is worth considering.

Though it offers a cheaper capital cost when compared to the three phase gravity separator, ithowever doesn’t satisfy the purpose of the project, as effective removal of water would not be deriveddue to the presence of gas in the produced fluid mixture.

This would have been the best option of separator selection, if the produced fluid does not con-tain any amount of gas. But with gas production expected, especially for the volatile oil reservoir, athree phase separator serves a better purpose.

It would also have been a good choice to use the two phase separator alongside a gas/liquid cy-clonic separator, either before the two phase gravity separator, or at the inlet. This also would notpresent a good solution to this project as it becomes a complex and expensive system.

4.1.2.5 Three-Phase Gravity Separator

The three phase gravity separator separates oil/water/gas. With a close look at the results of theanalysis of the fluid compositions of the three fluid samples considered, and given that the amount ofseparable gas contained in a typical black oil reservoir and the volatile oil reservoir, especially as thefluid moves towards production line, a three phase separator presents the best suited solution for theproposed subsea processing system.

Though the three phase separator might be a little bit more expensive than the two phase, it isbetter suited for the purpose of separating a three phase produced fluid. A three phase separatorpresents an average to very good efficiency of between 50%-90%, depending on varying factors like,pressure drop, separator length and liquid retention time.

The oil and gas after separation are comingled to avoid the need for installing a new productionflow line and riser, which would have increased the overall cost of the project. After comingling, theoil/gas phase is boosted to the surface for further separation.

Water is collected at the bottom of the separator, and connected to the injection line where it isfurther boosted for injection. When separated water does not meet the required standard by regula-tion, further water treatment is prescribed.

Same optional approach is applied to the sand treatment, with little sand production observed,further sand treatment will not be required. It would however become necessary if a large volume ofsand is produced.

The diagram below shows a sketch of the adopted system, with a three phase separator and twopumps. Further analysis on the choice of pump is made in the next section.

55

Figure 45 – Subsea Processing System Configuration with a Three Phase Gravity Separator

4.1.3 Selection Process

For a semi quantitative assessment and selection of the best separator technology for the proposedsubsea processing system, a matrix analysis approach is employed. Adequate consideration is givento the various factors that affects the choice of separator technology. Based on the strength, weaknessand history of usage of each technology, a scoring format is employed to describe their suitability withranges from bad to excellent as shown below:

Table 16 – Matrix analysis approach

The colour red represents a situation, which completely negates the aim of the project, and the colourgreen represents the most favourable situation with each verdict, allocated scores ranging from onefor the lowest, to five the highest. The suitable technology is selected by taking the highest totalscore of the different parameters, as shown in the table 17.

Typically, the choice of a subsea separator technology depends on the following factors:

� Produced fluid composition

56

� Depth of operation

� Type of flow assurance challenges envisaged

� Project capital cost

� Maintenance cost

� Install-ability

� Inspection

� Power consumption

57

Tab

le17

–S

epar

ator

Mat

rix

An

alysi

s

58

The matrix analysis proves that the three phase gravity based separator selected for the project isbest suited for effective separation of produced fluid made up of oil, water and gas, in the cheapestway possible, over the remaining life of the brownfield being considered.

4.1.4 Designing a Three Phase Gravity Separator

Traditionally, petroleum engineers do not perform in depth design of separators, but only performseparator selection, by determining the suitable weight and size suitable for specific operating condi-tions and aim. Separator designs basically involves an iterative process, with the main objective ofdetermining the diameter, total length and thickness.For a brown field development, it is noteworthy that the low cost target can be achieved with par-ticular attention given to the size (diameter, length and thickness) of a separator for a feasible andeffective design. The following are some of the factors that affects separator sizing and by extensiondefines the efficiency of a separator.

� Operating Conditions

� Flow Composition

� Expected Water Cut

4.1.4.0.1 Operating ConditionsWhen sizing the separator the reservoir characteristic will have a direct impact on the operatingcondition and by extension the dimensions, the following operating parameters are considered for anoptimum separator design.

� Operating Pressure

� Operating Temperature

� Water Depth were the Separator is to be Installed

The operating pressure and temperature will have a direct effect on the amount of gas present in theproduction stream, as explained the analysis of reservoir fluid compositions, whereas the installationdepth will influence the thickness of the separator.

4.1.4.0.2 Produced Fluid CompositionProduced hydrocarbon is basically a mixture of Oil, water and gas and impurities like sand. However,they are usually in different compositions, depending on the reservoir type and behaviour. For designconsiderations, it is crucial to clarify the composition of the produced fluid to be separated. Analysisof fluid composition is required to determine the predominant phase of the produced hydrocarbon.When analyzing the flow composition the particle size distribution of the oil and water inside thegaseous phase should be ascertained as this has a direct effect on the efficiency of the separator.

4.1.4.0.3 Expected Water cutSince the main aim of subsea separation is to remove as much water as possible from the producedreservoir fluid, it forms the main basis of the analysis of the efficiency of any separation process. Theeffectiveness and profitability of any separator design option is a measure of the percentage reductionin fraction of water in the produced hydrocarbon (i.e water cut). The water cut of the liquid phaseis strongly dependant on the retention time of both fluids inside the separator as well as the particlesize distribution of the water droplets in the oil stream. These two parameters will have a direct effecton the expected water cut for every considered design.

59

4.1.4.1 Calculation ProcessThe following are the steps for sizing a three phase gravity separator:

� Calculating the gas compressibility factor (Z)

� Calculating the gas viscosity

� Calculating the Souders & Brown Constant (K)

� Calculating the Gas Capacity

� Calculating the Liquid Capacity

� Dimensioning the Separator.

4.1.4.1.1 Compresibility factorGases are compressible substances which will change their volume and consequently their densitywhen affected by different combinations of pressure and temperature. The compressibility factor isgenerally defined as:

z =P ∗ V

n ∗R ∗ T(1)

This constant is equal to one when analysing an ideal gas but when considering the behaviour of theextracted gas from the reservoir this factor must be assessed.In this analysis an approximated method is used to calculate the compressibility factor using a poly-nomial approximation to the Standing and Katz z-factor chart [Requena et al., 2006].The compressibility factor is calculated using an iterative process and the pseudo-reduced pressureand temperature.

Pseudo-reduced Pressure and TemperatureThe pseudo-reduced pressure and temperature can be obtained using equations 2 and 3 below:

Ppr =P

756.8− 131 ∗ SGg − 3.6 ∗ SG2g

(2)

Tpr =T

169.2 + 349.5 ∗ SGg − 74 ∗ SG2g

(3)

Where:Ppr: is the pseudo-reduced pressure (dimensionless)P: is the operating pressure in pounds per square inch (psi)Tpr: is the pseudo-reduced temperature (dimensionless)T: is the operating temperature in Rankine degrees (oR)SGg: is the specific gravity of the gas (dimensionless)

Iterative ProcessThe iterative process is aimed at minimizing the following error function:

60

error = abs(z − z0z + 10−9

) < 10−4 (4)

The process begins by establishing initial values for z and z0 of 1 and 0 respectively, then solving forM parameter, which is a function of the pseudo-reduced pressure and temperature. The calculatedM is is used to obtain a new z factorising the polynomial approximation to the Standing and Kaztz-chart as shown below.

M = 0.27 ∗ Ppr

z ∗ Tpr(5)

z = 1 + (0.3265− 1.07

Tpr− 0.5339

Tpr+

0.01569

T 2pr

− 0.05165

T 5pr

)M + (0.5475− 0.7361

Tpr+

0.1844

T 2pr

M2

− 0.1056 ∗ (−0.7361

Tpr+

0.1844

T 2pr

) ∗M5 + 0.6134 ∗ (1 + 0.721 ∗M2)M2

T 3pr

∗ Exp(−0.721 ∗M2) (6)

Where:z: is the gas compressibility factor

4.1.4.1.2 Gas ViscosityThe gas viscosity affects the velocity of separation of the liquid particles in the gaseous phase. Inaddition to this, it is necessary to obtain the Souders & Brown constant [Requena et al., 2006].In order to obtain the gas viscosity the gas density can be gotten with equation 7 below.

ρg = 0.19197 ∗ SGg ∗ 28.97 ∗ P10.73 ∗ T ∗ z

(7)

Where:ρg: is the gas density in grams per cubic centimetres (gr/cm3)SGg: is the specific gravity of the gas (dimensionless)P: is the operating pressure in pounds per square inch (psi)T: is the operating temperature in Rankine degrees (oR)z: is the gas compressibility factor (dimensionless)The gas viscosity can be gotten from the expression below:

µg = A ∗ Exp(B ∗ ρCg ) ∗ 10−4 (8)

The three constants, A, B and C from equation 8, which permit to obtain the gas viscosity can becalculated from equations 9 to 11 below:

61

A =9.379 + 0.0167 ∗ SGg ∗ 28.97

209.2 + 19.26 ∗ SGg ∗ 28.97 + T∗ T 1.5 (9)

B = 3.448 +986.4

T+ 0.01009 ∗ (SGg ∗ 28.97) (10)

C = 2.447− 0.2224 ∗B (11)

Where:µg: is the gas viscosity in centipoises (cp)

4.1.4.1.3 Souders & Brown Constant (K)The Sounders and Brown Constant is of great relevance when predicting the behaviour of the fluidinside the vessel.This parameter takes into account the size of a fluid particle in the continuous phaseas well as the drag force actuating on the particle while it descends from the gaseous phase to theliquid phase or when the water particles inside the oil phase is moving towards the oil-water inter-face [Requena et al., 2006]

K '

√ρg

ρl − ρg∗ CD

dm(12)

Where:K: is the Souders & Brown constant (dimensionless)ρg: is the gas density in grams per cubic centimetres (gr/cm3)ρl: is the gas density in grams per cubic centimetres (gr/cm3)CD: is the drag coefficient (dimensionless)dm: is the particle diameter in microns (µm)

4.1.4.1.4 The Drag CoefficientThe particles suspended on the continuous phase will settle by the actuation of the gravitationalforce. These downwards movement will imply the appearance of a dragging force opposite to thedisplacement direction which will have direct effect in the settling velocity. This settling velocity willpermit us to obtain, by means of an iterative process, the drag coefficient.

Iterative ProcessThe iterative process in this case is aimed at minimizing the error between two consecutive values ofthe settling velocity. First of all, an initial value of the drag coefficient (CD) of 0.34 is assumed, tocalculate the settling velocity (vt).

The Settling VelocityThis is the velocity at which the particle descends through the continuous phase. It is affected by thesize of the settling particle and the density and viscosity of the continuous phase.

62

vt = 0.0119 ∗

√ρg

ρl − ρg∗ CD

dm(13)

Where:vt: is the settling velocity in feet per second (ft/s)

Once obtained, the next step is assessing the value for the Reynolds number for that flow.

Re = 0.0049 ∗ ρg ∗ dm ∗ vtµg

(14)

CD =24

Re+

3√Re

+ 0.34 (15)

Where:Re: is the Reynolds number (dimensionless)

With equation 15 the drag coefficient is reassessed and compared with the initial value used to startthe process, if the error between both is smaller than 10−4, the value is accepted and the iterativeprocess stops, otherwise this new calculated value of the drag coefficient will be used as the new initialvalue to restart the process.

4.1.4.1.5 Gas Capacity & Liquid Capacity RequirementsThe separator design must satisfy the gas and liquid capacity requirements, both gas and liquid phaseswill require a minimum size for the diameter and total length in order to guarantee sufficient availablevolume in the separator vessel to deal simultaneously with the two phases (gaseous and liquid) overa the design retention time.

The parameters that defines the dimensions of the separator will be:

� Gas and liquid flows rates (Qi): This is the most determinant parameter affecting the designprocess of the separator. It will decide the main driver of the design (gas or liquid) and theoverall size of the separator will be strongly influenced by its value.

� Retention time (tr): it is a critical parameter when establishing if the separator design is gas orliquid driven, it will be considered equal for oil and water. It strongly affects the efficiency ofthe separator

� Internal diameter (di): This is a vital parameter that determines the size of a separator (in formof weigth) and also has a crucial impact in the efficiency of the separation process. The largerthe separator diameter, the higher the weight of the separator.

63

� Effective length (Leff ): This represents the length of the part of the separator were the sepa-ration process occurs, and it is always smaller than the total length.

� Total length (Lss): This is the length between the taps of the separator and its value will differregarding which of the capacities drives the design

Gas Capacity RequirementsThe gas capacity constant is calculated using the following expression.

ctaGC = Leff ∗ di = 420 ∗ T ∗ z ∗Qg

P∗K (16)

Where:ctaGC : is the constant of the gas capacity process in feet per inches (ft*in)Leff : is the effective length of the separator in feet (ft)di: is the inner diameter of the separator in inches (in)T: is the operating temperature in Rankine degrees (oR)z: is the gas compressibility factor (dimensionless)Qg: is the gas flow in millions of cubic feet per day (MMcfpd)P : is the operating pressure in pounds per square inches (psi)K: is the Souders & Brown constant (dimensionless)

Once obtained, the gas capacity constant is substituted into equation 17 below to calculate the innerdiameter [Requena et al., 2006], this diameter will also be used when calculating the liquid capacity.

di =

√12 ∗ ctaGC

2(17)

The effective length (Leff) of the separator will then be:

Leff =ctaGC

di(18)

And the total length can be obtained by applying the inner diameter and the effective length into theequation below:

Lss = Leff +di12

(19)

Liquid Capacity RequirementsThe liquid capacity constant is calculated from the following expression:

ctaLC = Leff ∗ d2i = 1.42 ∗ (tro ∗Qo + trw ∗Qw) (20)

64

Where:ctaLC : is the constant of the liquid capacity process in feet per square inches (ft ∗ in2)Leff : is the effective length of the separator in feet (ft)di: is the inner diameter of the separator in inches (in)tro: is the oil retention time in minutes (min)Qo: is the oil flow in barrels per day (bpd)trw: is the water retention time in minutes (min)Qw: is the water flow in barrels per day (bpd)

As mentioned in the previous step the diameter obtained in the gas capacity process will be usedat this stage to obtain the effective length of the liquid capacity.

Leff =ctaLCd2i

(21)

ctaLC : is the constant of the liquid capacity process in feet per square inches (ft ∗ in2) And the totallength (Lss)will be:

Lss =4

3∗ Leff (22)

4.1.4.1.6 Separator DimensioningThe total lengths of the liquid and gas capacity will be compared, and the larger of both lengths decidesif the design is liquid or gas driven. Once the nature of the design is established,, an iterative processto obtain the most efficient/low cost solution (which includes recalculating the length- diameter ratiountil a less than three result is obtained) is performed.

R = 12 ∗ Lss

di(23)

Where:R: is the length-diameter ratio (dimensionless)Lss: is the effective length of the separator in feet (ft)di: is the inner diameter of the separator in inches (in)It is generally accepted to use a separator design with a length-diameter ratio between 3 and 4,but values between 1.5 and 8 are generally accepted [Requena et al., 2006] [Benıtez Orellana andOlmedo Arce, 2011].The low cost solution requirement permitted to adopt 6 as the value for thelength-diameter ratio because it is between the ranges generally accepted and produces a less expen-sive solution, as the higher length diameter ratio, the lighter the separator.

65

4.1.4.2 Separator’s WeightThe weight of a separator is especially important because it affects the feasibility of a designed option,besides it is directly linked with the total cost of the separator in terms of installability and vesselconstruction.

The total weight of the separator can be obtained using the following equation:

WSep = 1.06 ∗ (VSep ∗Density) (24)

Where:WSep: is the separator’s weight in tonnes (t)VSep: is the separator’s volume in cubic meters (m3)Density: is steel’s density in tonnes per cubic meter (t/m3)

The hypotheses adopted when defining the process to obtain the weight of the separator are:

� The body of the separator will be assumed as a perfect empty cylinder

� The tap of the separator will be assumed as an empty semi-spherical body

� The weight of the welding will be adopted as a 6 % of the total weight without welding[Benıtez Orellana and Olmedo Arce, 2011]

� The steel’s density value will be adopted as 7.85 tonnes per cubic meter (t/m3).

Thus the expression which permits to calculate the separator’s volume is:

VSep = Vbody + 2 ∗ Vtap (25)

Where:Vbody: is the body’s volume in cubic meters (m3)Vtap: is the tap’s volume in cubic meters (m3)

4.1.4.2.1 Body‘s VolumeIn the hypotheses the body design was adopted as an empty cylinder of which the volume can becalculated with the following expression:

Vbody =0.0283168m3

1ft3∗ Lss ∗ π

4∗ 1

144∗ ((2 ∗ td +Di)

2 −D2i ) (26)

66

4.1.4.2.2 Semi-spherical Tap VolumeThe tap design considered in the hypotheses was empty semi-spherical, thus with the following ex-pression the volume of an empty semi-sphere can be calculated:

Vtap =0.0283168m3

1ft3∗ 1

2∗ 4

3∗ π

8∗ 1

123∗ ((Di + 2 ∗ td)3 −D3

i ) (27)

4.1.4.2.3 Design ThicknessWhen calculating the thickness several types of loads must be considered in order to satisfy all thepossible service and failure scenarios affecting the vessel. The final design thickness will be the max-imum value of all the considered scenarios [Benıtez Orellana and Olmedo Arce, 2011].For the design pressure (P) we will consider a water density of 62.42796pcf, and regarding the maxi-mum depth analyzed in this project is 200m the design pressure will be:

P = γw ∗ depth = 62.42796pcf ∗ 200m ∗ 3.28084ft

1m∗ 0.0069444psi

1psf= 285psi (28)

With the adopted assumptions, in any other scenario in shallower waters, the thickness obtained withthis design pressure will always be above the minimum value required for that new design depth,which means that this design will be safe.The material chosen in this case is the steel SA 516-70 recommended by the ASME. Using a se-curity factor of 4 and semi-spherical taps the recommended design data is [Benıtez Orellana andOlmedo Arce, 2011]:

� Maximum tension resisted (S) = 15700psi

� Joint efficiency (E) = 0.85

Different loads scenarios considered [Benıtez Orellana and Olmedo Arce, 2011]

Radial Loads.These loads are applied around the design vessel’s diameter. The equation 28 permits to obtain theminimum required thickness and it will be acceptable if and only if the following conditions met:

� The Design Pressure is smaller than 0.385*S*E

� The axial thickness is smaller than half the inner radio

tr =P ∗R

S ∗ E − 0.6 ∗ P= 0.02163352 ∗R (29)

Axial Loads.The axial loads is applied throughout the length of the vessel and as happened with the radial loads,equation 30 gives the minimum thickness which must be defined in order to resist the existing loads.This equation will be acceptable if and only if two conditions meet simultaneously:

67

� The Design Pressure is smaller than 1.25*S*E

� The axial thickness is smaller than half the inner radio

ta =P ∗R

2 ∗ S ∗ E − 0.4 ∗ P= 0.01072396 ∗R (30)

Semi-spherical TapsFor the semi-spherical taps, the following equation can obtain the minimum required thickness toresist the loads on the taps.

tss =2 ∗ P ∗R

2 ∗ S ∗ E − 0.2 ∗ P= 0.02140202 ∗R (31)

Where:tr: is the radial thickness in inches (in).ta: is the axial thickness in inches (in).tss: is the semi-spherical thickness in inches (in).P: design pressure in pounds per square inch (psi)R: inner radius in inches (in)S: Maximum tension resisted by the material in pounds per square inch (psi)E: joint efficiency

It is essential to consider corrosion damage allowance when defining the thickness in our design,a value of 5 thousandth inches per year is commonly accepted for vessels and pipes [Benıtez Orellanaand Olmedo Arce, 2011], in this particular analysis we have considered an expected system’s life of 5years, therefore:

td = max(tr, ta, tsc) + 0.005 ∗ 5 (32)

With the adopted assumptions, the design thickness will be:

td = 0.02163352 ∗R+ 0.0254 (33)

Where:td: is the design thickness in inches (in).

4.1.4.3 Separator Cost

The cost of the designed vessel strongly depends on the final design dimensions, as was mentionedbefore, the length-diameter ratio is the parameter which has been used to define the appropriate lowcost/efficient solution. The assessment of the monetary cost of the separator is beyond the scope ofthis project.

68

4.1.4.4 Efficiency of the separation process in the liquid phase

The efficiency in the separation is defined as the difference between the water cut at the begin-ning and at the end of the process. The efficiency of the separator will depend on the internal layoutwhich is determined by the supplier of the technology and it is the key aspect to determine the realseparation efficiency, but leaving aside the internal layout, the two main parameters which controlthe efficiency in the separation process are:

� The retention time of the oil inside the separator (tor)

� The water particle diameter distribution inside the oil phase.

4.1.4.4.1 Retention TimeRetention time is the necessary amount of time to reach the equilibrium and separate the gas phasefrom the liquid phase, and also to allow the suspended water particles inside the oil to flow by coa-lescence from the oil phase to the oil-water interface.Laboratory experiments have established a typical range between 3 to 30 minutes for the design re-tention time, but in case that these analyses are not available a value of 10 minutes is considered asacceptable when designing a separator [Bautista and Gamboa, 2011].

Figure 46 – Typical Design Retention Times in Three Phase Separation [Bautista and Gamboa, 2011]

4.1.4.4.2 Particle Diameter The particle diameter is also a crucial parameter when consid-ering the efficiency of the separation process, and the velocity at which the separation occurs it isgiven by the Stokes law.

vt = 1.787 ∗ 10−6 ∗ ∆γ ∗ d2mµo

(34)

And the distance that the particle must traverse is the oil thickness (Ho) thus the time the particleneeds to cross that distance can be calculated as follows:

tor =

Ho

12V t

=1

60∗

Ho

121.787 ∗ 10−6 ∗∆γ ∗ d2m

∗ µo (35)

Where:Ho: oil thickness in inches (in)

Below, there is a plot of the particle diameter as a function of the retention time.

69

Figure 47 – Water particle diameter as a function of the oil retention time

As can be concluded from the chart, the design oil retention time will considerably increase whenseparating the smaller water droplets inside the oil phase. In other words, the better the efficiency ofthe process, the higher the retention time and consequently the weight and the cost of the vessel.

4.1.4.4.3 Water cutThe water cut of the separator technology, which differs from its efficiency (but directly related to itas was mentioned before), can only be accurately obtained using laboratory and field tests [Bautistaand Gamboa, 2011]. The water cut directly depends on the water particle size distribution as wellas on the fluid composition, the incoming flow and how the separator processes the emulsion phase(using or not emulsion breakers). The emulsion phase needs even longer retention times than the oilphase to achieve an accurate water-oil separation.

Nevertheless a heuristic method has been developed to estimate the water cut at the end of theprocess. In the design of the separator we have considered that half of the volume will be filled withliquid.

ST = 2 ∗ (So + Sw) (36)

Rewriting that expression:

SwST

=Qw ∗ twr

Qo ∗ tor +Qw ∗ twr(37)

70

Where:Sw: water section in square feet (ft2)ST : Total section of the separator in square feet(ft2)tor: oil retention time in minutes (min)twr: water retention time in minutes (min)Qo: oil flow in barrels per day (bpd)Qw: water flow in barrels per day (bpd)

The relationship of water section over total section it is related to the oil height inside the flow[Benıtez Orellana and Olmedo Arce, 2011].

Figure 48 – Cross Section of the Separator

Writing mathematically this relationship:

SWST

=1

Π(acos(2

Ho

D)− (2

Ho

D)−

√(1− (2

Ho

D)2) (38)

Where:D: the inner diameter in inches (in)

PlottingSwSt

againstHo

D, shows initially a clear linear tendency and then at the end a parabolic

one; in order to speed up the process a linear interpolation plus a final parabolic approximationwas developed. For the linear approximation, the parameters were fit minimizing the sum of thesquared differences with the exact function. The parabolic part was developed with the followingconsiderations:

� Maintaining the continuity with the linear approximation atHo

D= 0.35

� WhenHo

D= 0.5, the parabolic function value will be zero.

71

Figure 49 – Graphic representation of the above equation and its linear plus parabolic approximation

The graph shows that both curves are quite close to each other and when calculating the R2 parameterfor the linear approximation,

R2 = 0.99919 (39)

A value close to one is obtained which confirms that the linear curve is a good approximation. Thusthe linear plus parabolic approximation will be:

WhileSwSt≥ 0.09

SwSt

= −1.1539618301533 ∗ Ho

D+ 0.490439096659232 (40)

And whenSwSt

< 0.09

SwSt

= 3.84630304077407 ∗ (Ho

D)2 − 3.84637395869514 ∗ Ho

D+ 0.961611219154055 (41)

With the value of Ho and the calculated Diameter we can obtain the value of the Oil height, and withthis value calculate the minimum particle size which was able to reach the oil-water interface in theconsidered retention time.

72

Ho =Ho

D∗D (42)

dm =

√√√√ Ho

12∗ µo

60 ∗ 1.787 ∗ 10−6 ∗∆γ ∗ tro(43)

When assessing the expected water cut, the method is based in the following hypotheses:

� The function which relates water cut and particle diameter is the exponential distribution

� When the dm of the particle tends to infinite the value of the water-cut is the same as the initialwater-cut (fwo).

� If the separated size of the particle is of 75µm a good level of separation will have been achieve,understanding as good that the water cut for that particle size is the 55% of the water cut atthe entrance of the separator.

The curve which fits these requirements is:

fw = fwo ∗ (1− Exp(−α ∗ dm)) (44)

α = − ln(1− 0.55)

75(45)

Where:fw: is the expected water cut (dimensionless)fwo: is the expected water cut (dimensionless)α: is constant which defines the model in microns−1(µm−1)

When plotted the expected water cut as a function of the particle size diameter,

73

Figure 50 – Expected water cut as a function of the particle diameter

As presented in the figure 50, the chart represents how the expected water cut decreases with thedecreasing value of the diameter of the water droplet eliminated with our separator, besides thesmaller the initial water cut the smaller the expected water cut will be. Both conclusions are logicaland permit to use the model as a tool to compare an ”expected efficiency for different separatordesigns”. The main weakness of this model is the constant α defining the model which should becorroborated with field results in order to adjust the model.

4.1.4.5 Analysis of the effects of the different variables involved in the design process(sensitivity analysis)

The separator design, as was presented along the entire chapter, it is a process which basicallydepends on the operating conditions and the incoming flow which goes inside the vessel. This gen-erates a great variability of scenarios which must be meticulously analysed and explained, so that inthis way a fully understanding on the effect of the different variables involved in the design processof the separator can be guaranteed.In order to carry this analysis out, the production and operating data of Balmora field have been usedas a reference because they have been considered as representative of the analyzed on the NorthernSea.

Table 18 – Operating Parameters of Balmora Field

In Brownfield developments, the amount of gas that has to be handled is not significant and practi-cally despicable in the design of the separator, thus it is considered as a fixed initial data which doesnot give any variability to the performed analysis.

74

Also highlight the value of the oil API gravity which is considerably high, for this kind of values therecommended value for the oil retention time, as was previously explained, is within an interval from3 to 5 minutes.

For a daily production rate of 21000 barrels, the following simulation results were achieved:

Table 19 – Table with the separator sizing for 21000bpd production rate

The highlighted portion in green shows the design value considered as the optimum when consider-ing installability and low cost. It is also true that the bigger our separator will be the better theexpected level of water at the end of the separation process will be achieved, in this situations it isrecommended to develop an economic feasibility analysis of the chosen option in order to see if it ispossible its development from a monetary point of view.

4.1.4.5.1 Separator’s WeightThe amount of flow which comes inside the access cavity to the separator has a major influence in theseparator dimensions. It affects it’s strength, if it’s considered that every separator is also designedfor different values of the oil retention time regarding installability and efficiency criteria. The reasonfor this is that an extremely big separator, even though very efficient, could result outrageously costlyto install which will fully dismiss this option.

75

Figure 51 – Sized Separator Weight as a function of the retention time

The above chart permit to appreciate how for a typical value of 10 minutes for the retention time,the separator’s design for 31000bpd and beyond would be impassable. In this situations it is stronglyrecommended to reduce the retention time (at expenses of the separation efficiency) or to redistributethe flow in various separators so that each separator could handle a smaller amount of barrels perday, which will significantly reduce the separator’s shape and size.

4.1.4.5.2 Separator’s Efficiency and Expected Water Cut At some point in this chap-ter, it was already mentioned that the existing relationship between both parameters and the waythe amount of water inside the leaving oil will be analysed, nevertheless it is still interesting to seehow both variables are affected by the production rate and the considered retention time.When plotting the variability of the expected water cut as a function of the design retention time fordifferent levels of the production rates at which the separator can be subjected, the result will be thefollowing:

76

Figure 52 – Expected water cut, at different production levels with variable retention time

As could have been logically predicted, for bigger production, rates the separation level of the de-signed vessel is lessen due to the bigger production rate the separator has to deal with. Likewise, aswas mentioned at the beginning of this chapter, the expected water cut diminishes when the valuefor the design retention time is increased. It worth noting that the installability level of this analysislies at 30 tonnes and to reach certain levels of separation quality, the design of that separator couldresult as an impassable option.

The following chart seeks to represent the relationship between the separation efficiency processand the expected water cut level when the oil leaves the separator for different levels of initial watercut, considering a constant production rate of 21000bpd.

Figure 53 – Variation of the efficiency and the expected water cut at different levels of initial watercut and retention time values

At first sight the result may seem illogical, due to the fact that for higher initial water cut levels,the values for the expected water cut and separator’s efficiency are better than the ones obtainedfor a lower level of the initial water cut. However, if the volume of oil produced in each situation is

77

analysed, the lesser efficient option gives a bigger amount of barrels of oil per complete cycle insidethe separator. In other words, the option with an initial water cut of 70% will produce much morevolumes of oil than the one with an initial value for the water of 90%, even though the efficiency ofthe option with an initial value for the water cut of 90% is better.

Figure 54 – Volume of Oil generated for every separator cycle, at different retention time levels

78

4.2 Chosen Pump Option for Oil Boosting

After careful consideration and review of multiphase pump technology, the ESP is found to be com-monly employed in downhole applications and is not suitable for this project. However, the HAP(Helical Axial Pump) which maintains a unique subsea profile has been selected as the preferredchoice over the TSP (Twin Screw Pump) for this project with the following justifications;

� HAP is an economically and technically viable option for this project since a light oil (of 0.85SG) is being boosted and this pump was designed particularly for such.

� The ability of HAPs to be installed in vertical configurations allows cost effective interventionsfor subsea applications compared to TSPs which have only been installed for subsea applicationin horizontal configuration [Hua et al., 2012].

� Flow rate can influence the pump size and the flow rate for HAPs is determined by the differentialpressure, stage geometry, rotation speed and suction conditions. On the other hand, flow ratesfor TSPs are determined by the screw geometry and rotation speed. [Hua et al., 2012] furtherelaborates the tendency of HAPs to achieve higher flow rates than TSPs if a lower differentialpressure can be maintained.

� Rotation speed plays a key role on the inlet flow for both HAPs and TSPs. [Falcimaigne andDecarre, 2008] explained that HAPs which usually runs between 3,500rpm and 6,500rpm wouldbe a compelling advantage over TSPs that runs between 1,500rpm and 2,400rpm. HAPs havean edge over TSPs because they can adjust their pump speeds to variable flow rates thus makingthem more flexible and a wider operating range.

� Sand production can be exacerbated by high water cut in oil wells, however, HAPs can toleratehigh amounts of sand compared to TSPs and offers an advantage where sand production couldbe a major concern.

� The integrated variable speed drive of HAPs permits operational flexibility over the life of assets.

� HAP technology has a track record of 15 installations and an accumulated operation hour ofover 750,000 hours [Hua et al., 2012].

� At a depth of 170 m the pump module can be easily installed using guidelines and the individualcomponents easily retrievable by a running tool.

4.2.1 Boosting Pump Capacity

The use of two pumps has been recommended in the proposed subsea processing system. One of whichis needed for boosting of the oil pressure to carry the separated hydrocarbon to the topside facilityand another pump needed for water re-injection into the reservoir to increase reservoir pressure.This section discusses the net positive suction head (NPSH) of the HAP pump and power requirementneeded to handle the boosting of the separated oil and gas to topside facility for a specific range ofwater depths, flow rates and operating pressures.

4.2.1.1 Separator’s Pressure Drop

The Pressure drop inside the three phase gravity based separator can be estimated between 1 to2 bar [Abili et al., 2012], and for clarity sake it will be assumed as despicable when calculating thepressure requirements for the operating pump.

79

4.2.2 Oil and Gas Multi Phase Boosting Pump Capacity

The subsea separation system is most preferred to be installed close to the wellhead. This allowsan increase in the amount of recovery from the reservoir by reducing back pressure. Therefore, thesubsea oil and gas multiphase boosting pump comes after the separator, both close to the wellhead.The capacity of the pump must be high enough to boost the fluid against the frictional pressure dropalong the pipeline and riser, and also the static head along the riser.Hence, the energy the subsea boosting pump must supply is equal to the energy lost along the pipelineand riser; and the elevation energy (static head) along the riser (water depth). Therefore;

Ep =Qo ∗ Pr

η(46)

Where:Ep: is the energy required to the pump in Watts (Watt)Qo: is the incoming fluid flow rate in cubic meters per second (m3/s)Pr: is the Pump pressure required in Pascals (Pa)η: is the efficiency of the pump

And the pump pressure required can be calculated:

Pr =6894.757Pa

1psi∗ (Pfl + Peh − PFR) (47)

Where:Pfl: is the pressure requirement due to friction losses in pounds per square inch (psi)Peh: is the pressure requirement to overcome the elevation head pressure in pounds per square inch(psi)PFR: is the incoming flow pressure in pounds per square inch (psi)

For simplicity in calculating the pump pressure requirement and power need for the pump, the fol-lowing assumptions are made [Abili et al., 2012]:

� Typical multiphase pipeline frictional loss is 50psi/mile

� Typical multiphase hydrostatic head gradient for oil after water separation is 0.4psi/ft

In the analysed case study of Balmora field, the input data to determine the pump requirements areas follows:

Pump Inlet Flow Rate Pressure (PFR) =38 bar= 550psiTotal production pipeline distance = 14km= 8.699 milesMaximum Water depth considered=200m=656.168 ftHydrocarbon flow rate (Qo) = 840bpd = 1.325 ∗ 10−3m3/sPump’s Efficiency= 0.60

Therefore;

Frictional Losses Pfl (psi) = 50*8.699 = 434.960 psiElevation Head Peh (psi) = 0.4*656.168 = 262.467 psi

80

Required Pump Pressure Pr (Pa) = 6894.757*(434.960+262.467-550) = 1008590.069 Pa

Thus, the power supply needed will be:

Power Supply Ep (Watt) = (1.325 ∗ 10−3 ∗ 1008590.069)/0.6 = 2227.125 Watt

These values of net positive suction head and required power supply give a basic idea of the pressureboosting pump required for the given particular flow rate, water depth, suction pressure and pipelinedistance. As this value does not take into consideration the pressure needed to move the fluid intotopside storage task. Hence, the actual net positive suction head of the pump and power supply willbe higher than the above values above for this given consideration.The graphs below, show different pump pressure requirements and power supply needed for variousflow rates, water depth and pipeline distance. It clearly shows that the pump’s capacity and thepower supply required increase as the water depth, pipeline distance and flow rate increase.

The first factor to consider is the required head pressure as a function of the water depth and theproduction length, as shown in the figure 55.

Figure 55 – Required Pump Head Pressure and Power for Different Initial Water Cut levels, with aconstant incoming Flow of 21000bpd among Different Production Distances of the Pipe System, fora Constant Depth of 200m

From the graph, the higher the production length the higher the pressure requirements. Regardingthe different considered depths, the value for the pressure requirement also increases, as presented infigure 56.

81

Figure 56 – Required Pump Head Pressure and Power for Different Initial Water Cut levels, with aconstant incoming Flow of 21000bpd among Different Production Distances of the Pipe System, fora Constant Depth of 200m

As expected, the power requirements increase when a longer distance has to be traversed or when alarger volume of flow has to be handled by the pump, it is also important to highlight the increasingvalue for the Pressure Head from less than 1MPa to 6Mpa, this shows significant increase in the pumppower requirements.

82

4.3 Sand Handling

The production of solids from hydrocarbon reservoir is a critical problem to the separation processin a separator on platforms.

The solids produced is responsible for severe erosion in valves and lines, its accumulation in mainprocess devices may force stopping the process for cleaning and thereby causing huge productionloses. (FMC Technologies)

4.3.1 When to use it ?

Sand production is not usually envisaged, but happens for different reasons ranging from increasedgas oil ratio to, to low pressure production, and also increased water production and well/sand crum-bling. The sand produced can cause erosion on pipe/components or valves, fill vessels, tanks and lowvelocity zones. It can also cause interference on instruments/valves.

Difficulty in obtaining data on formation, make prediction of sand production completely challenging.Although, traditional topside processing equipment design includes normal sand production handling,they still require maintenance intervetion.

Pore pressure reduction and increased water production at maturity stage of a field makes sandmanagement an extremely demanding task. Reservoir fluid aids the downhole pressure in the forma-tion along with its natural ability, resulting in bringing the sand production [?]. The figure 57 showsa mature field production optimization.

Figure 57 – Mature Field Production Optimization [Bedwell et al., 2015]

4.3.1.1 Sand Handling technologies for a low cost subsea processing system

Basically the facilities Sand-Management techniques fall into two types:

� Inclusionary

� Exclusionary

83

Table 20 – Comparaison between Exclusionary techniques and Inclusionary techniques

Subsea sand management lead with inclusionary techniques therefore will be the focus of this chapter.

The main inclusionary Technologies used nowadays are:

� Sand Jetting System

� Cyclonic (Desander, Inline)

Sand jetting system is located inside the gravity based separator in order to remove the sandsettled inside it, A large number of based gravity separators originally had basic desanding systemsinstalled with little provision for upgrades [Bedwell et al., 2015]. In addition as solids with highparticle sizes (>50 pm) settles in the separator, the liquid retention time is decreased, resulting in areduction in through¬put. Schedule shutdown for hand operated discharge of solid might be necessaryto revive the production rate.

The quantity of sand produced determine the sand handling system to be installed into the sys-tem. “even if with a good completion a sand prone well may produce 5 ppmv sand” [Rawlins, 2002].Therefore it will be considered a concentration of 5ppmv and the total amount of sand produced dailywill depend on the flowrate. In this project, the assumption is If the sand produced daily is up to150kg the sand jetting system installed inside the separator should be enough to remove the sand andthe system will work properly. On the other hand, If the sand produced increase, an extra deviceshould be installed to enhance the efficiency of your system. Considering a sand production above150kg daily an inline desander should be installed at the inlet of the gravity based separator in orderto protect it from erosion or any possible sand damaging.

According to Rawlings [Rawlins, 2013], the best area for surface solids elimination is before thechoke, to secure all downstream equipment, like the choke orifice, flowlines and piping, productionseparator, heat exchanges, control valves and produced water treating equipment.

84

In case of limited space (for example brownfield), the multiphase desander can be installed afterthe choke and right before the separator. The only discrepancy in design when the desander comesbefore or after the choke, is the pressure rating of the vessels. Operating potential and specificationsof the multiphase desander is similar, rirrespective of the pressure rating. The Inline Desander canalso be located upstream a compact liquideiliquide separator, if hydrocyclone separator is used, inorder to remove sand and improve the compact liquide/liquide separator performance and robustness.As mentioned before the inline desander use cyclonic technology (centrifugal forces) to separate solidsfrom the wellstream [Rawlins, 2002].

The sand recovered from the separator/desander is disposed to a suitable location. Resolve to ensurea subsea system devoid of any form of complexity, it considered to recombine the separated sand withoil stream for direct boosting to the topside facilities, for further treatment.

Another important point to be mentioned is the OPEX. As multiphase desander does not havemoving parts (screen, filters) the maintenance (e.g for cleaning) is considerably reduced. The inlinedesander can be incorporated into an existing process system with limited accessible space becauseof it conciseness. The added advantage of compactness is the low hardware and installation cost, inrelation to other mainstream solutions which guarantee a low CAPEX. It also provides small neg-ative differential pressure (typically 0.3 — l bar) which is a fundermental quality. Inline desanderseliminates the bulk of sand from the well stream with a regular effectiveness of about 80% to 99%,contingent on the features of the sand, well stream, and the chosensize of the Inline desander (98%when removing 40um and above solids).

85

4.4 Water Reinjection System

The technologies described in the Chapter 3.D. Water Injection Technologies about Seawater Treat-ment, Produced Water Treatment and Injection Pump will be assessed in this part and the moresuitable technologies options for this project of low cost subsea processing system will be chosen.

4.4.1 The Seawater Treatment

Sea water, due to its wide availability and cheapness, is generally used for water injection. However,raw seawater requires effective treatment before injection, because of the presence of bacteria andoxygen which damage the wellbore. Oxygen promotes corrosion of the pipes, pumps and also leadsto bacteria growth in wells. Bacteria growth and fouling can damage and obstruct the well and byextension limit the recovery process. For these reasons, seawater required filtration, de-oxygenationand biocide treatment before injection are regarded as effective measures to palliate these issues. Thetreatment of seawater before injection into the reservoir could either be done topside or at the seabed.

4.4.1.1 Topside seawater treatment

Generally, seawater is treated topside before injection. The topside treatment of seawater for in-jection involves the following seven steps:

1. Seawater lift pumps2. Coarse strainer3. Fine filters4. Deaeration (de-oxygenation)5. Booster and injection pumps6. Cartridge filters7. Chemical dosing

The two most important stages are the filtration and the de-oxygenation, because major purifica-tion takes place in these two stages. The Filters remove solid particles from the seawater, while thede-oxygenation stage, as the name implies, involves the complete removal of oxygen.

Seawater is lifted to the platform by a lift pump and subsequently fed to Coarse Filters and finefilters for filtering. The first filtration which is carried out by the Coarse Filters remove particle sizeup to 20 microns and the fine filters remove particles size up to 2 microns. These filtrations areimproved by the addition of poly electrolyte and coagulants to the seawater to promote coagulationof suspended particles, guaranteeing a better filtration.

Following the filtration stage is the de-oxygenation of the seawater. The filtered water flows to ade-oxygenation tower for oxygen removal. This treatment prevents the formation of aerobic bacteriain the well’s injection flow line and wellbore [PETROFED, 2015].

The figure below shows a typical topside seawater treatment and injection system.

86

Figure 58 – Typical Topside seawater injection system

4.4.1.2 Subsea seawater treatment

The Sea Water Intake and Treatment (SWIT) is a technology that enables seawater treatment subsea.This technology uses a single unit to perform three steps of the seawater treatment at the seabed andincludes a pump for the injection of the water into the reservoir.

Firstly, solids are removed. Solid particles down to 10µm can be removed using a patented still-room concept. No filters are used in this process, thus clog up is avoided, and no maintenance isneeded for two years at least.

The second stage of subsea water treatments is “seawater sterilization”: it involves the removalof bacteria present in the raw seawater using electrically generated hypochlorite, and ensures a longexposure time of the seawater to the generated hypochlorite, which enables the chlorine to workproperly. The sterilization is completed by a new technology utilizing electro-chemically generatedhydroxyl radicals which is 2.5 times more bactericidal and fungicidal than chlorine. Basically thesterilization process is designed to run without maintenance for two years.

The last part of the treatment is a periodic shock dosing with biocide similar to conventional topsidesystems. The biocide requirements however are reduced thanks to the efficient sterilization, thus thereload of chemicals must be done only every two years.

Finally, a subsea injection pump transfers the treated water into the reservoir or towards topsideor onshore facilities regarding the needs and the configuration of the entire system [?].

87

Figure 59 – The Well Processing SWIT and The Seabox SWIT

4.4.1.3 Seawater Treatment Options Assessment

The table below shows a qualitative comparison of subsea and topside treatment of seawater basedwith their various benefits and drawbacks.

88

Table 21 – Advantages and Disadvantages of Topside and Subsea Treatment

The following assessment took into consideration five criteria which were justified to choose whichkind of seawater treatment is the be better option for a project of low cost subsea processing. Thesecriteria are:

� Efficiency: Referred to the quality of the water after the treatment.

� Environmental Friendly: This factor considers the likelihood of the treatment interferingnegatively with the environment.

� CAPEX: This factor puts into consideration the cost of the seawater treatment equipment andof its installation.

� OPEX: This factor puts into consideration the cost of inspection, maintenance and interventionon the equipment when fully operational.

� Existing Technology: This factors put into consideration how the likelihood that the existingplatform is already using topside treatment.

89

The efficiency of a Sea Water Intake and Treatment (SWIT) unit is usually better than the topsideseawater treatment. Due to the limited space on the platform, the weight of installations is limited,this affects the maximum size of the seawater treatment unit that is installable topside. A smallersized seawater treatment unit reduces the efficiency of the topside water treatment. There are no suchlimitations when considering subsea processing. This allows using bigger treatment equipment andlonger exposure time of the flowing seawater to the chemical used for treating it, which guaranteesa better efficiency in the process. For example, the SWIT unit allows for a chlorine exposure timeof 60-120 minutes compared to the typically 60-90 seconds for topside facilities. The net result is aneffective kill rate and collapse of the cell structure of organic species.

The technologies used for treatment not only influence the efficiency, but also impact the envi-ronment. Indeed the technologies that employed the SWIT do not required any chemicals for watertreatment, whereas topside conventional treatment uses several chemicals as coagulants, which stayin the injected water and can pollute the production reservoir or neighboring reservoir.

Regarding the CAPEX criteria, the cost of procurement of a SWIT unit is more expensive thanthat of the conventional topside units. This mostly has to do with the number of suppliers offeringthis technology; because the SWIT technology is new and only a few suppliers after it. The topsidetreatment equipment on the other hand is well developed and proposed by a large number of compa-nies, the competition between the suppliers dramatically reduces the price of the system.

Furthermore, the ease and cost of the system installation also defines the CAPEX. The SWIT treat-ment as a single unit (with several pieces of kit assemble), is easy to install. Although as a subseasystem, it involves quite a number binding installation standards and regulations (specific equipment,favorable weather conditions). On the other hand, a topside treatment is composed of several unitsinvolving a longer and more difficult installation but topside so this installation can be done onshoreor at least with less binding than a subsea one.

The OPEX is significantly low with a SWIT, as no form of maintenance is required for the ini-tial two years due to the fact that its solid removal and water sterilization equipment are guaranteedwithout failure for the two first years. For the subsequent years, the likelihood of failure is also lowby its patterned technologies using no moving parts. It is however worthy to note that, althougha topside treatment might require more maintenance, topside inspection and intervention is usuallymuch easier and cheaper to than a subsea one. In essence, when maintenance becomes necessary, thecost of the SWIT would be subsequently significant.

For the purpose of this project, which is focused on Brownfield developments, the most likely sce-nario is that current platforms have already implement existing seawater treatment systems topside.With existing topside water treatments in place, considering the low cost nature of this project, theinstallation of a new subsea seawater treatment will be expensive and not economically justifiable ina low cost processing system used in Brownfield developments with limited operating years.

In conclusion, with emphasis on cost reduction, topside seawater treatment seems the best option.Although the efficiency of the water treatment can be improved with newer technologies, a long-termreduction of the CAPEX and OPEX can be noticed using topside seawater treatment. This projectis integrated into a brownfield development with limited operating years, and as such a financialinvestment on a SWIT unit will not be profitable for a short-term development.

90

4.4.2 The Produced Water Treatment

During subsea processing, water and hydrocarbons are separated. The produced water obtainedduring the hydrocarbon processing can be rich in oil and grease residue and organic and inorganicchemicals. The large amount of produced water represents one of the biggest waste streams in pro-duction process and must be dealt with by the appropriate disposal solution and treatment if needed.

Common ways of managing the produced water include [C Clarck, 2009] :

� Discharge in the sea water

� Reinjection into the reservoir for increasing recovery

� Reinjection into authorized zones for disposal

Table 22 – Advantages and Disadvantages of Disposal solutions

Based on the above comparison, reinjection of produced water in the reservoir is the best waterdisposal management method. Indeed, this solution is a good way to reduce waste and improve hy-drocarbon recovery at the same time, which reduces costs.

Produced water contains a wide range of dissolved and suspended substances such as cations, an-ions, dissolved or dispersed greases, which may affect the injectivity (measure of the ability of thewell to take up injected fluids) [Abou-Sayed, 2000]. Indeed, the injection of produced water maydamage the formation, provoking a reduction in permeability of the formation and so decrease theinjectivity and the recovery. For these reasons, even if in most cases produced water can be reinjectedwith minimal treatment, some kind of reservoirs require treated produced water.

With the aim of minimizing the cost associated to produced water treatments, the decision on treat-ment of the produced water subsea, when necessary has been done.

The adopted system configuration for this project is one production line and one injection line,

91

knowing that the installation of a third line to bring up the produced water topside for treatmentwill be too expensive and economically unjustified regarding the unsystematic treatment of producedwater before reinjection.

The first criteria defining the necessity or not for produced water treatment is the kind of reser-voir formation the water is injected into. Usually, produced water can be injected into fracturedformations without treatment but a better water quality is required for matrix rate (sub-fracturing)injection.

The two main water impurities which must be dealt with to avoid poor injectivity issues are sandand oil-in-water. If the size of the solid particles contained in the injected water is large enough toplug the rock pores (which may happen in sub-fracturing injection) the injectivity, so the recovery,will decline. Furthermore, the presence of suspended oil in water can affect the permeability of thereservoir formation to water and thus impairs the injectivity [Abou-Sayed, 2000].

The sand handling processes and techniques have been discussed in the previous part 4.3. Thefollowing part will describe the produced water treatment in terms of oil-in-water.

4.4.2.1 Safely tolerable amount of oil in injected produced

The tolerable amount of oil in injected water mainly depends of the oil properties, the size of therock pores and the wettability of the formation. According industrial experiences, a level of less than5ml/l of oil and grease content in injected water is acceptable for most injection wells with a greaterpermeability than 20-30mD [Bennion et al., 2011]. If this level is not met, a de-oiling treatment of theproduced water is required before re-injection in order to guarantee a safe injection and injectibility.

4.4.2.2 Subsea De-oiling Technologies

The produced water treatment can be ensured by inline processing. Two main technologies forproduced water treatment will be considered:

� Inline Sorbwater Process

� Inline Hydrocyclone

The Inline Sorbwater Process is a new patented technology from FMC Technologies and it is a three-step treatment composed of Chemical Treatment, CFU and Polishing. The association of this threestages guarantees an amount of oil in water after treatment between 1-5 ppm [FMCTechnologies,2015]. This technology is fully automated, compact, robust, reliable, low maintenance requirementand has no moving part which will ensure a low OPEX.

Figure 60 – The Sorbwater Process

92

The Inline Hydrocyclone is a solution for produced water treatment based on a unique axial flowdesign. It ensures a high oil removal efficiency, a low pressure drop, a compact size, anerosionresistance and easy to fit to existing field. The moving part of this device may increase it maintenance.After the treatment, the oil amount in water is guaranteed below 5ppm.

Figure 61 – Inline Hydrocyclones

Regarding the low cost objective of this project the choice of produced water treatment technologymust be analysed regarding the CAPEX and the OPEX of the considered technologies. The Sorb-water Process is a new patented technology only offered by FMC Technology so its CAPEX will behigher than the one of the Inline Hydrocyclone, which is a well-known technology offered by severalcompanies and used on several field.

Besides, if the maintenance requirements are very low for both technologies, the probability of failureassociated to a serial arrangement of three devices is bigger than only one device. Thus, the OPEXof the Inline Sorbwater Process will be higher than the Inline Hydrocyclone. Finally, it is easier toinstall one single device in an existing field rather than three, so the instability (how the system iseasy to install into an existing field) of the Hydrocyclone will be easier and cheaper.

Employing the similar form of matrix arrangement and scoring format, to the analysis of separa-tor technology for the chosen system configuration as shown below below.

Figure 62 – Assessment Matrix

93

Figure 63 – Produced Water Treatment Technologies Assessment Summary

In conclusion, the produced water is a waste product of hydrocarbon processing that needs to be dealtwith, as such the best managing option for this water is the reinjection into the reservoir for boostingrecovery. Thus, the waste becomes a useful product and the required water quality standards areeasily met than considering a disposal into the seawater solution.

However, before reinjection the produced water may need to be treated to avoid well damage andinjectivity reduction due to residual oil in water. Considering the configuration of the processingsystem chosen for this project, this treatment should be done subsea to avoid a very expensive instal-lation of a new line to bring up the produced water for a topside treatment. Based on different casestudies and experts opinions, such treatments are not required, especially if the reservoir formationis a fractured formation or if the amount of oil in water is below 5mg/l. If this last requirements arenot met, produced water must be treated to ensure a safe and efficient injection. Inline Hydrocycloneis the cheapest treatment technology to use in this case.

Figure 64 – Processing system with Produced Water Treatment

4.4.3 The Injection Pump

Once seawater and produced water are treated, they are ready for injection into the reservoir. Pro-duced water and seawater are co-mingled into the injection line and are injected together into thereservoir using the subsea injection pump. A risk of reservoir souring is increased when a mixing ofseawater and produced water is injected but can be controlled by chemicals additives. This treatmentis however secondary and will therefore not be developed in this report.

The injection pumps commonly used in the industry are Single-Phase Centrifugal Pumps. This

94

choice is especially justified by the composition of the fluid pumped water. Even if residue of oil maystill be present into the injected water, its quantity is low enough to consider the injected water as asingle phase fluid.

There are different types of single phase centrifugal pumps, a few of which are shown below withspecifications.

Table 23 – Single-Phase Centrifugal Pumps

The field characteristics are the criteria which justify the choice of the injection pump. As this projectconsiders a Brownfield, the amount of produced water and of treated seawater to be injected into thereservoir to maintain the pressure is very high. It is then necessary to select a high capacity pump tomanage the high injection volume needed. In addition, the depth of the reservoir defines the headsof the pump, the higher the depth of application, the higher the heads to be reached. Finally, thedesign pressure and temperature of the pump can be low because the fluid injected, sea and producedwater, don’t reach high pressure and temperature.

95

In sum up, the choice of the type of Centrifugal pump to use for water injection must be doneregarding the maturity of the field, the depth of the reservoir and the fluid pressure and temperature.

4.4.4 Summary & Conclusion for water treatment and injection systems

In conclusion, water is injected into the reservoir to maintain the pressure and boost the recovery.Seawater is usually treated topside before being injected into injection well via the injection line.

The separation process creates a produced water which, when required, is cleaned from sand andoil subsea to meet the acceptable levels which guaranteed a safe and efficient injection. Treatedseawater and produced water are injected together into the formation by a single-phase centrifugalpump.

96

5 Conclusion and Recommendations

The implementation of subsea processing technologies to reduce the amount of produced water re-quiring topside treatment is possible as there is proven technology which has been applied in fieldslike Troll, Tordis and Pazflor. Subsea separation of water, gas and oil has been successfully imple-mented in several fields and can be effectively utilized in removing water from the produced reservoirfluids. Likewise, subsea pumping technology is also a proven technology which can be employed inboth boosting the separated oil in order to increase well productivity and also injecting the producedwater into the reservoir to increase the reservoir pressure.

To ensure the economic viability of subsea processing technologies in Brownfield developments, theequipment building blocks of the system should be designed to ensure minimal CAPEX and OPEX.The MTTF (mean time to failure) of the equipment must satisfy the ALARP (as low as reasonablepracticable) principle to minimize maintenance, inspection and repair costs. Equipment’s efficiencycan easily increase the CAPEX of the considered machinery since they are only to be deployed inBrownfields with limited operating years. This ensures a low cost system that is suitable for Brown-field developments.

Using the Balmoral field as a case study, the following subsea processing system configuration and theequipment building blocks are recommended for a low cost subsea processing system for Brownfielddevelopments in order to reduce the amount of produced water taken to topside.

Figure 65 – Final Configuration

97

The equipment building blocks include a three phase gravity based separator, a multi phase helico-axial boosting pump and a single phase re-injection pump; with optional equipment of inline desanderfor handling sand and inline hydrocyclone for de-oiling the separated produced water; depending onthe field fluid characteristics.

The proposed mathematical design for the chosen separator option provides with a basic idea of thesize, weight and expected cost of each considered option, but until a proper project study is devel-oped, the considered values in this project shall be used as indicators for the possible final outcomes.

It is observed that if the well head pressure of the produced fluid is high and the water depth isquite small, the oil boosting pump can be ignored; which further simplifies the configuration andreduces the cost of the system.

The technology gap that must be improved to further enhance the system is the produced waterquality monitoring system. This will become more useful if the option of disposal of the producedwater into the sea is feasible (regarding the environmental requirements). Subsea gas compressiontechnology still requires further development and qualification in order to be considered as a proventechnology for subsea processing systems.

98

A Computational Code for Designing a 3 Phase Gravity Based Sep-arator

The following code was developed for the Matlab software.The equations used in this code have the same units as the equations used in the design section (5.1.6)of the report.

Gas Compressibility Factor

function[z]=CF(P,T,SGg)Ppr=P/(756.8-131*SGg-3.6*SGgˆ2);Tpr=T/(169.2+349.5*SGg-74*SGgˆ2);z=1;z0=0;i=0;e=abs((z-z0)/(z+1e-9));while e>=0.001;

z0=z;i=i+1;M=0.27*Ppr/(z*Tpr);z=1+(0.3265-(1.07/Tpr)-(0.5339/Tpr)+(0.01569/Tprˆ2)-0.05165/(Tprˆ5))*M;z=z+(0.5475-(0.7361/Tpr)+(0.1844/Tprˆ2))*Mˆ2;z=z-0.1056*(-(0.7361/Tpr)+(0.1844/Tprˆ2))*Mˆ5;z=z+0.6134*(1+0.721*Mˆ2)*(Mˆ2/Tprˆ3)*exp(-0.721*Mˆ2);e=abs((z-z0)/(z+1e-9));

end

Gas Viscosisty

function [GV,GD]=Visc(P,T,SGg,z)PMg=SGg*28.97;GD=PMg*P/(10.73*T*z);GD=GD/62.492;%Parameters CalculationA=(9.379+0.0167*PMg)*Tˆ(1.5)/(209.2+19.26*PMg+T);B=3.448+986.4/T+0.01009*PMg;C=2.447-0.2224*B;GV=A*exp(B*GDˆC)*1e-4;

Drag Coefficient

function [K,SGo]=DragC(API,GD,GV,Dm)GD=GD*62.492;%The Diameter of the particle is in microns%Dm = 100microns if no data is providedSGo=141.5/(131.5+API);OD=SGo*62.4;Cd0=0.34;Vt0=0.0119*sqrt((OD-GD)*Dm/GD/Cd0);Re=0.0049*GD*Dm*Vt0/GV;Cd=24/Re+3/sqrt(Re)+0.34;Vt=0.0119*sqrt((OD-GD)*Dm/GD/Cd);e=abs(Vt-Vt0);while e>1e-4

Vt0=Vt;Re=0.0049*GD*Dm*Vt/GV;Cd=24/Re+3/sqrt(Re)+0.34;

99

Vt=0.0119*sqrt((OD-GD)*Dm/GD/Cd);e=abs(Vt-Vt0);

end%Souders & Brown ConstantK=sqrt(GD*Cd/Dm/(OD-GD));

Design of a 3 Phase Gravity Based Separator

function [M]=HGS3P(P,T,OF,GF,WF,SGg,API,OV,Dm)%Convert Farenheit in RankineT=T+459.67;[z]=CF(P,T,SGg);[GV,GD]=Visc(P,T,SGg,z);[K,SGo]=DragC(API,GD,GV,Dm);format shortG %Shows every column with its own amount of numbers%Oil and Water retention time will be assumed as equalTRO=[2 3 4 5 10 15 20 25 30];TRW=TRO;[~,colsz]=size(TRO);IWC=WF/(OF+WF);i=1;a=1;while a<=colsz

AwAt=0.5*WF*TRW(a)/(OF*TRO(a)+WF*TRW(a));%Linear + Parabolic interpolation for HoDo due to

%the long convergence time for the original equationHoDop=0;HoDo=0.25;HoDol=0.5;AwAt1= AwAt;error=1;while error>1e-4

if AwAt1>0.09AwAt1=-1.1539618301533*HoDo+0.490439096659232;

elseAwAt1=3.84630304077407*HoDoˆ2-3.84637395869514*HoDo+0.961611219154055;

endif AwAt1>AwAt

HoDop=HoDo;HoDo=(HoDo+HoDol)/2;

elseHoDol=HoDo;HoDo=(HoDop+HoDo)/2;

enderror=abs(AwAt-AwAt1);

end%Determine flow behaviour%Gas Capacitycteg=420*T*z*GF*K/P;dg=sqrt(12*cteg)/2;%Aproximating to the nearest integer diameterauxd=round(dg);if dg>auxd;

dg=auxd+1;else

dg=auxd;endLeffg=cteg/dg;Lssg=Leffg+dg/12;%Liquid Capacityctel=1.42*(TRO(a)*OF+TRW(a)*WF);Leffl=ctel/(dgˆ2);

100

Lssl=4/3*Leffl;%Comparison between Gas and Liquid Capacityif Lssg>=Lssl

%Gas Driven Designdisp('Gas goberns the design');%Iterative Process to Obtain the Minimum DiameterRg=12*Lssg/dg;j=1;while Rg>3

M(i,1)=TRO(a);M(i,2)=dg+6*(j-1); %The j-1 seeks to keep the initial

%value of the diameter for i=1. The initial value of%the diameter it is increased in 6 by 6 inches

M(i,3)=cteg/M(i,2);M(i,4)=M(i,3)+M(i,2)/12;M(i,5)=12*M(i,4)/M(i,2);Rg=M(i,5);M(i,6)=0.02163352*(M(i,2)/2)+0.025;M(i,7)=0.0283168*M(i,4)*pi/4/144*((2*M(i,6)+M(i,2))ˆ2-M(i,2)ˆ2);M(i,7)=M(i,7)+2*0.0283168*0.5*4/3*pi*(((M(i,2)+2*M(i,6))/12)ˆ3-(M(i,2)/12)ˆ3)/(2ˆ3);M(i,7)=M(i,7)*7.85*1.06;Hoeff=HoDo*M(i,2);diameff=sqrt(Hoeff/12*OV/(60*1.787e-6*(1.07-SGo)*TRO(a)));alpha=-log(1-0.55)/75;M(i,8)=IWC*(1-exp(-alpha*diameff));M(i,9)=(IWC-M(i,8))/IWC;j=j+1;i=i+1;

endelse

%Liquid Driven Designdisp('Oil and Water gobern the design');%Iterative Process to Obtain the Minimum DiameterRl=12*Lssl/dg;j=1;while Rl>3

M(i,1)=TRO(a);M(i,2)=dg+6*(j-1); %The j-1 seeks to keep the initial

%value of the diameter for i=1. The initial value of%the diameter it is increased in 6 by 6 inches

M(i,3)=ctel/(M(i,2)ˆ2);M(i,4)=4/3*M(i,3);M(i,5)=12*M(i,4)/M(i,2);Rl=M(i,5);M(i,6)=0.02163352*(M(i,2)/2)+0.025;M(i,7)=0.0283168*M(i,4)*pi/4/144*((2*M(i,6)+M(i,2))ˆ2-M(i,2)ˆ2);M(i,7)=M(i,7)+2*0.0283168*0.5*4/3*pi*(((M(i,2)+2*M(i,6))/12)ˆ3-(M(i,2)/12)ˆ3)/(2ˆ3);M(i,7)=M(i,7)*7.85*1.06;Hoeff=HoDo*M(i,2);diameff=sqrt((Hoeff)/12*OV/(60*1.787e-6*(1.07-SGo)*TRO(a)));alpha=-log(1-0.55)/75;M(i,8)=IWC*(1-exp(-alpha*diameff));M(i,9)=(IWC-M(i,8))/IWC;j=j+1;i=i+1;

endenda=a+1;

endend

101

References

[Abili et al., 2012] Abili, N., Udofot, O., and Kara, F. (2012). Subsea Processing: A Holistic Approachto Marginal Field Developements. Houston, Offshore Technology Conference.

[Abou-Sayed, 2000] Abou-Sayed, A. (2000). Guidelines for produced water injection. The Interna-tional Association of Oil and Gas Producers.

[AkerSolution, 2015] AkerSolution (2015). Processing Solution.

[Arthur et al., 2005] Arthur, D., Langhus, B., and Patel, C. (2005). TECHNICAL SUMMARY OFOIL AND GAS PRODUCED WATER TREATMENT TECHNOLOGIES. ALL CONSULTING,LLC.

[Bai and Bai, 2010] Bai, Y. and Bai, Q. (2010). Subsea Engineering Handbook. Elsevier Science.

[Bautista and Gamboa, 2011] Bautista, J. L. E. and Gamboa, L. P. C. (2011). Estudio de la Eficienciade los Separadores de Petroleo de las Estaciones de Produccion de Secoya y Pinchinca del CampoLibertador. Facultad de Ingenierıa en Geologıa y Petroleos, Escuela Politecnica Nacional.

[Bedwell et al., 2015] Bedwell, I., Das, S., and McCall, E. (2015). Life Extension of Mature FacilitiesThrough Robust Engineering and Chemistry Solution. Maxoil Solutions.

[BENAVIDES, 2012] BENAVIDES, S. (2012). Cyclone Separators: Physics behind them and howthey work.

[Bennion et al., 2011] Bennion, D., Thomas, F., Imer, D., Ma, T., and Schulmeister, B. (2011). WaterQuality Considerations Resulting in the Impaired Injectivity of Water Injection and Disposal Wells.Hycal Energy Research Laboratories Ltd.

[Benıtez Orellana and Olmedo Arce, 2011] Benıtez Orellana, V. G. and Olmedo Arce, P. V. (2011).Diseno de un Separador de Produccion Trifasico Horizontal para el Campo Secoya del DistritoAmazonico. Facultad de Ingenierıa Mecanica, Escuela Politecnica Nacional.

[C Clarck, 2009] C Clarck, J. V. (2009). Produced Water Volumes and Management Practices in theUnited States. U.S Department of Energy.

[Callaghan et al., 1985] Callaghan, I., McKechnie, A., and Ray, J. (1985). Identification of Crude OilComponents Responsible for Foaming. SPE.

[Choi and Weingarten, 2007] Choi, M. and Weingarten, J. (2007). Petroleum Engineering Handbook.Number p.143-181. SPE.

[DAIGLE et al., 2012] DAIGLE, T., PHILLIPS, B., HANTZ, S., and JANJUA, R. (2012). AdvancedProduced Water Treatment. American Institute of Chemical Engineers.

[EQUIPMENT, 2012] EQUIPMENT, A. (2012). Water treatment technologies, deaerators. TechnicalReport 18974, ALTAIR EQUIPMENT CO.,INC.

[Falcimaigne and Decarre, 2008] Falcimaigne, J. and Decarre, S. (2008). Multiphase Production:Pipeline Transport, Pumping and Metering. IFP Publications, Editions Technip.

[FMCTechnologies, 2015] FMCTechnologies (2015). Produced Water - Separation Systems.

[Hannisdal et al., 2012] Hannisdal, A., Westra, R., Akdim, R., Bymaster, A., Grave, E., and Teng,D. (2012). Compact Separation Technologies and Their Applicability for Subsea Field Developmentin Deep Water. Offshore Technology Conference.

[Heijckers, 2012] Heijckers, C. (2012). Flow Conditioning Impact on Separations.

102

[Howard, 2007] Howard, W. (2007). Subsea Tieback Forum, Subsea trends, Challenges, and technologyrequirements. Infield Systems Ltd.

[Hua et al., 2012] Hua, G., Falcone, G., Teodoriu, C., and Morrison, G. (2012). Comparison ofMultiphase Pumping Technologies for Subsea and Downhole Applications. Society of PetroleumEngineers.

[Humborstad, 2013] Humborstad, A. (2013). Seawater Coarse Filter with Automatic Backwash.

[Husveg et al., 2009] Husveg, T., Bilstad, T., Guinee, P., Valves, M., and Jemsletten, J. (2009). ACyclone Based Low Shear Valve for Enhanced Oil-Water Separation. Offshore Technology Confer-ence.

[Islam, 2005] Islam, M. (2005). Use of Electrical Submersible Pumps (ESPs) in Oil and Gas Produc-tion Facilities - A Brief Review. NACE International.

[Manning and Thompson, 1995] Manning, F. and Thompson, R. E. (1995). Oilfield Processing ofPetroleum: Crude oil. PennWell Publishing Company.

[Mulyandasari, 2011] Mulyandasari, V. (2011). Separation Vessel Selection and Sizing. EngineeringDesign Guideline.

[Osvaldo Zuniga, 2013] Osvaldo Zuniga, S. (2013). Separation Technologies in Oil and Gas Produc-tion. Norwegian University of Science and Technology.

[Perry and Rega, 2011] Perry, R. and Rega, A. (2011). Reviewing trends in subsea processing. InOFFSHORE. Penn Well Corporation.

[PETROFED, 2015] PETROFED (2015). Offshore oil and gas production system.http://petrofed.winwinhosting.net/upload/OffshoreoilandProd.pdf. Petroleum Federation ofIndia.

[Rawlins, 2002] Rawlins, C. (2002). Application of Multiphase Desander Technology to Oil and GasProduction.

[Rawlins, 2003] Rawlins, C. (2003). The Case for Compact Separation.

[Rawlins, 2013] Rawlins, C. (2013). Sand Management Methodologies for Sustained Facilities Oper-ations. SPE.

[Requena et al., 2006] Requena, G., Jose, L., Rodrıguez, M., and Mauricio, R. (2006). Diseno yEvaluacion de Separadores Bifasicos y Trifasicos. Caracas, Venezuela.

[Sarshar and Loh, 1995] Sarshar, M. and Loh, W. (1995). Applications of Wellcom Systems to En-hance Production. Proceedings of the BHR Group 7th International Conference on MultiphaseFlow.

[Schoener, 2004] Schoener, H. (2004). Multiphase pumping- a successfully growing oilfield productiontechnology.

[Sharma, 2007] Sharma, B. (2007). Environmental Chemistry. Krishna Prakashan Media (T) ltd.

[Slettebø, 2009] Slettebø, E. S. (2009). Separation of Gas from Liquids in Viscous Systems. NorwegianUniversity of Science and Technology.

[SPE, 2012] SPE (2012). Separation technology shrinks to fit subsea development in deep waterbetter.

103

[Team, 2010] Team, W. T. E. (2010). Water treatment primer for communities in need. TechnicalReport 68, U.S. Department of the Interior, Denver, Colorado.

[Viska and Karl, 2011] Viska, M. and Karl, K. (2011). Separator Vessel Selection, and Sizing.

[Wally, 2013] Wally, J. (2013). Foaming in Separators: Handling and Operation.

[Weingarten et al., 1995] Weingarten, J., Kolpak, M., Mattison, S., and Williamson, M. (1995). NewDesign for Compact Liquid-Gas Partial Separation: Downhole and Surface Installations for Artifi-cial Lift Applications. SPE.

104