ADS Well Control Manual

➞

➞

•AB

ERDEEN DRILLING SCHOOLS •

&W

E LL CO NTROL TRAINING CENT

RE

ABERDEEN DRILLING SCHOOLS& Well Control Training Centre

for the Rig-Site Drilling Team

WELL CONTROL

TRAINING MANUAL

COPYRIGHT STATEMENT

WELL CONTROL for the Rig-Site Drilling Team

All rights reserved. No part of this publication may be reproduced or transmitted in anyform or by any means, including photocopying and recording without the written permissionof the copyright holder, application for which should be addressed to:

Aberdeen Drilling Schools Ltd.,50 Union Glen,Aberdeen, AB11 6ER.

Such written permission must also be obtained before any part of this publication is stored ina retrieval system of any nature.

Brand names, company names, trademarks, or other identifying symbols appearing inillustrations and/or text are used for educational purposes only and do not constitute anendorsement by the author or publisher.

Illustrations have been included in this document with the kind permission of Cooper CameronUK Ltd, Shaffer A Varco Co and Hydril UK Ltd.

SECTION

Introduction

1 Fundamental Principlesof Well Control

2 Causes of Kicks

3 Kick Indicators

4 Shut-in Procedures

5 Methods of Well Control

6 Well Control Equipment

7 Inspection, Testingand Sealing Components

9 Surface BOP Control Systems

10 Subsea BOP Control Systemsand Marine Riser Systems

Formulae, Conversion Factors& Glossary of Terms

CONTENTS


1

2

3

4

5

6

7

8

9

10

INTRODUCTION


INTRODUCTION

The objective of this manual is to provide a good understanding of thefundamentals of Well Control that can be applied to most Well Control operations.In all cases, minimising the kick volume and closing the well in is our first priority.We have tried, as far as possible, to avoid using specialist terms and iconography.

This manual describes industry recognised standards and practices and basic WellControl procedures. They differ from our advanced Well Control methods whichtend to be well, formation, or rig specific. The manual covers the guidelines foundin API 59 and API 53 along with the International Well Control Forum syllabus.

All Well Control principles rely upon an understanding that good planning andearly recognition and close in, is the best form of Well Control. Not all kicks areswabbed kicks, many wells are drilled into unknown formation. It is recognisedthat equipment can fail despite all the correct procedures being followed. This iswhy you will find the equipment section comprehensive and useful for generaltrouble shooting ideas.

FUNDAMENTAL PRINCIPLESOF WELL CONTROL

SECTION 1 :

Page

1. 0 Objectives 1

1. 1 General Information 1

1. 2 Hydrostatic Pressure 3

1. 3 Formation Pressure 4

1. 4 Normal Formation Pressure 4

1. 5 Abnormal Pressure 7

1. 6 Formation Fracture Pressure 12

1. 7 Leak-off Tests 14

1. 8 Maximum Allowable Annular Surface 21Pressure - MAASP

1. 9 Casing Setting Depths 21

1. 10 Circulating Pump Pressure 23

1. 11 Choke Line Friction 25

1.12 Workshop 1 30


SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL

1 - 1

FUNDAMENTAL PRINCIPLES OF WELL CONTROL

1.0 OBJECTIVES

The objectives of this section are to introduce the Fundamental Principles of WellControl.

1.1 GENERAL INFORMATION

The function of Well Control can be conveniently subdivided into three maincategories, namely PRIMARY WELL CONTROL, SECONDARY WELLCONTROL and TERTIARY WELL CONTROL. These categories are brieflydescribed in the following paragraphs.

Primary Well Control

It is the name given to the process which maintains a hydrostatic pressure in thewellbore greater than the pressure of the fluids in the formation being drilled, butless than formation fracture pressure. If hydrostatic pressure is less than formationpressure then formation fluids will enter the wellbore. If the hydrostatic pressureof the fluid in the wellbore exceeds the fracture pressure of the formation then thefluid in the well could be lost. In an extreme case of lost circulation the formationpressure may exceed hydrostatic pressure allowing formation fluids to enter intothe well.

An overbalance of hydrostatic pressure over formation pressure is maintained,this excess is generally referred to as a trip margin.

Secondary Well Control

If the pressure of the fluids in the wellbore ( i.e. mud) fail to prevent formationfluids entering the wellbore, the well will flow. This process is stopped using a“blow out preventer” to prevent the escape of wellbore fluids from the well.

This is the initial stage of secondary well control. Containment of unwantedformation fluids.

1 - 2



Tertiary Well Control

Tertiary well control describes the third line of defence. Where the formationcannot be controlled by primary or secondary well control (hydrostatic andequipment). An underground blowout for example. However in well control it isnot always used as a qualitative term. ‘Unusual well control operations’ listedbelow are considered under this term:-

a) A kick is taken with the kick off bottom.

b) The drill pipe plugs off during a kill operation.

c) There is no pipe in the hole.

d) Hole in drill string.

e) Lost circulation.

f) Excessive casing pressure.

g) Plugged and stuck off bottom.

h) Gas percolation without gas expansion.

We could also include operations like stripping or snubbing in the hole, or drillingrelief wells. The point to remember is "what is the well status at shut in?" Thisdetermines the method of well control.



1 - 3

1.2 HYDROSTATIC PRESSURE

Hydrostatic pressure is defined as the pressure due to the unit weight and verticalheight of a column of fluid.

Hydrostatic Pressure = Fluid Density x True Vertical Depth

Note: It is the vertical height/depth of the fluid column that matters, its shape isunimportant.

TV

D

Figure 1.1 Different shaped vessels

Since the pressure is measured in psi and depth is measured in feet, it isconvenient to convert mud weights from pounds per gallon ppg to a pressuregradient psi/ft. The conversion factor is 0.052.

Pressure Gradient psi/ft = Fluid Density in ppg X 0.052

Hydrostatic Pressure psi = Density in ppg X 0.052 X True Vert. Depth

The Conversion factor 0.052 psi/ft per lb/gal is derived as follows:

A cubic foot contains 7.48 US gallons.

A fluid weighing 1 ppg is thereforeequivalent to 7.48 lbs/cu.ft

The pressure exerted by one foot of thatfluid over the area of the base would be:

7.48 lbs–––––––– = 0.052 psi144 sq.ins

Figure 1.2Area definition of a cubic foot

12"

12"

12"

1 - 4



Example:

The Pressure Gradient of a 10 ppg mud

= 10 x 0.052

= 0.52 psi/ft

Conversion constants for other mud weight units are:

Specific Gravity x 0.433 = Pressure Gradient psi/ft

Pounds per Cubic Foot ÷ 144 = Pressure Gradient psi/ft

1.3 FORMATION PRESSURE

Formation pressure or pore pressure is said to be normal when it is caused solelyby the hydrostatic head of the subsurface water contained in the formations andthere is pore to pore pressure communication with the atmosphere.

Dividing this pressure by the true vertical depth gives an average pressuregradient of the formation fluid, normally between 0.433 psi/ft and 0.465 psi/ft.The North Sea area pore pressure averages 0.452 psi/ft. In the absence of accuratedata, 0.465 psi/ft which is the average pore pressure gradient in the Gulf of Mexicois often taken to be the “normal” pressure gradient.

Note: The point at which atmospheric contact is established may notnecessarily be at sea-level or rig site level.

1.4 NORMAL FORMATION PRESSURE

Normal Formation Pressure is equal to the hydrostatic pressure of water extendingfrom the surface to the subsurface formation. Thus, the normal formation pressuregradient in any area will be equal to the hydrostatic pressure gradient of the wateroccupying the pore spaces of the subspace formations in that area.

The magnitude of the hydrostatic pressure gradient is affected by theconcentration of dissolved solids (salts) and gases in the formation water.Increasing the dissolved solids (higher salt concentration) increases the formationpressure gradient whilst an increase in the level of gases in solution will decreasethe pressure gradient.



1 - 5

For example, formation water with a salinity of 80,000 ppm sodium chloride(common salt) at a temperature of 25°C, has a pressure gradient of 0.465 psi/ft.Fresh water (zero salinity) has a pressure gradient of 0.433 psi/ft.

Temperature also has an effect as hydrostatic pressure gradients will decrease athigher temperatures due to fluid expansion.

In formations deposited in an offshore environment, formation water density mayvary from slightly saline (0.44 psi/ft) to saturated saline (0.515 psi/ft). Salinityvaries with depth and formation type. Therefore, the average value of normalformation pressure gradient may not be valid for all depths. For instance, it ispossible that local normal pressure gradients as high as 0.515 psi/ft may exist informations adjacent to salt formations where the formation water is completelysalt-saturated.

The following table gives examples of the magnitude of the normal formationpressure gradient for various areas. However, in the absence of accurate data,0.465 psi/ft is often taken to be the normal pressure gradient.

Figure 1.3 Average Normal Formation Pressure Gradients

Formation Water Pressure Gradient Example areapsi/ft (SG)

Fresh water 0.433 1.00 Rocky Mountains and Mid-continent, USA

Brackish water 0.438 1.01

Salt water 0.442 1.02 Most sedimentary basinsworldwide

Salt water 0.452 1.04 North Sea, South China Sea

Salt water 0.465 1.07 Gulf of Mexico, USA

Salt water 0.478 1.10 Some area of Gulf of Mexico

1 - 6



Figure 1.4

Porosity %

0 10 20 30 40 50 60 70 80

Dep

th (

met

res)

0

1000

2000

3000

4000

5000

Permian Pennsylvaniaand Oklahoma (Athy)

Lias Germany(Won Engelwardt)

Miocene and PliocenePo Valley (Storer)

Tertiary Gulf Coast(Dickinson)

Tertiary Japan(Magara)

Joides

Reduction in clay porosity as a function of depth (modified from Magara, 1978)



1 - 7

1.5 ABNORMAL PRESSURE

Every pressure which does not conform with the definition given for normalpressure is abnormal.

The principal causes of abnormal pressures are:-

1.5.1 Under-compaction in shales

When first deposited, shale has a high porosity. More than 50% of the total volumeof uncompacted clay-mud may consist of water in which it is laid. During normalcompaction, a gradual reduction in porosity accompanied by a loss of formationwater occur as the thickness and weight of the overlaying sediments increase.Compaction reduces the pore space in shale, as compaction continues water issqueezed out. As a result, water must be removed from the shale before furthercompaction can occur. See Fig 1.4.

Not all of the expelled liquid is water, hydrocarbons may also be flushed from theshale.

If the balance between the rate of compaction and fluid expulsion is disruptedsuch that fluid removal is impeded then fluid pressures within the shale willincrease. The inability of shale to expel water at a sufficient rate results in a muchhigher porosity than expected for the depth of shale burial in that area.

Figure 1.5a

Coarse-grained,well sorted

Good permeability

Fine Grained Poorly-sorted

Poor permeability

Quality of reservoir permeability.

1 - 8



Figure 1.5b

Figure 1.5c

Coarse - and very coarse - grained

Coarse - and medium - grained

Fine - grained

Silty

Clayey

1000080006000

4000

2000

40

20

10864

2

1

1008060

400

200

1000800600

0 2 4 6 8 10 12 14 16 18 20 24 28 30 32 34 3622 26

POROSITY %

PE

RM

EA

BIL

ITY

(m

d)

The relationship between permeability and porosity (from Chilingar, 1964)

1st DEHYDRATION

AND LATTICE WATERSTABILITY ZONE

2ndDEHYD'N

STAGE

3rdDEHYDRATION

STAGE

INTER-LAYER

WATER

PORE ANDINTERLAYERWATER EXPULSION

INTERLAYER WATERISOPLETH

DEEP BURIALWATER LOSS

LATTICE WATERSTABILITY ZONE

'NO MIGRATION LEVEL'

BU

RIA

L D

EP

TH

(SC

HE

MA

TIC

)

PORE WATER

SEDIMENT SURFACE

WATER AVAILABLEFOR MIGRATION

% WATER

0 10 20 30 40 50 60 70 80

WATER ESCAPE CURVE

(SCHEMATIC)

WATER CONTENT OF SHALES

Water Distribution Curves for Shale Dehydration



1 - 9

1.5.2 Salt Beds

Continuous salt depositions over large areas can cause abnormal pressures. Salt istotally impermeable to fluids and behave plastically. It deforms and flows byrecrystallisation. Its properties of pressure transmission are more like fluids thansolids, thereby exerting pressures equal to the overburden load in all directions.The fluids in the underlying formations cannot escape as there is nocommunication to the surface and thus the formations become over pressured.

1.5.3 Mineralisation

The alteration of sediments and their constituent minerals can result in variationsof the total volume of the minerals present. An increase in the volume of thesesolids will result in an increased fluid pressure. An example of this occurs whenanhydrite is laid down. If it later takes on water crystallisation, its structurechanges to become gypsum, with a volume increase of around 35%.

1.5.4 Tectonic Causes

Is a compacting force that is applied horizontally in subsurface formations. Innormal pressure environments water is expelled from clays as they are beingcompacted with increasing overburden pressures. If however an additionalhorizontal compacting force squeezes the clays laterally and if fluids are not ableto escape at a rate equal to the reduction in pore volume the result will be anincrease in pore pressure.

Figure 1.6

Abnormal Formation Pressures caused by Tectonic Compressional Folding

COMPRESSION COMPRESSION

COMPRESSION COMPRESSION

EXTENSIONEXTENSION

POSSIBLE OVERPRESSURED ZONES

Amount of Shortening

1 - 10



1.5.5 Faulting

Faults may cause abnormally high pressures.Formation slippage may bring a permeableformation laterally against an impermeableformation preventing the flow of fluids. Non-sealing faults may allow fluids to move from adeeper permeable formation to a shallowerformation. If the shallower formation is sealed thenit will be pressurised from the deeper zone.

Figure 1.7

1.5.6 Diapirism

A salt diapirism is an upward intrusion of salt toform a salt dome. This upthrust disturbs the normallayering of sediments and over pressures can occurdue to the folding and faulting of the intrudedformations.

Figure 1.8

1.5.7 Reservoir Structure

Abnormally high pressures can develop in normally compacted rocks. In areservoir in which a high relief structure contains oil or gas, an abnormally highpressure gradient as measured relative to surface will exist as shown in thefollowing fig:

Figure 1.9a Figure1.9b

This is a trap resulting from faultingin which the block on the right hasmoved up with respect to the oneon the left.

IMPERVIOUS SHALE

GASOIL

WATER

Salt domes often deform overlyingrocks to form traps like the one shown here.

Cap RockGas

Oil

WaterWater

Salt

An anticlinal type of folded structure is shown here. Anticline differs from a dome in being long and narrow.

WATER

OIL

Trap nomenclature (a) in a simple structural trap and (b) in stratigraphic traps. Note that the size of the stratigraphic trap on the left is limited only by its petroleum content, while the size of the trap on the right is self-limiting.

b

a

ClosureOil

Water

SpillPoint

Gas-OilContact(GOC)

Oil-WaterContact(OWC)

Gas

OilWater

Gas

GasGas-Water

Contact(GWC)

Gas-OilContact(GOC)



1 - 11

1.5.8 Typical types of hydrocarbon traps versus percentage of world total.

Figure 1.10

1.5.9 Typical hydrocarbon seals versus percentage of world total

Types of seals and percentage of world’s petroleum occurrence for each.

Carbonate(limestone & dolomite)

Evaporite(salt)

Shale

2%

33%65%

Figure 1.11

Major types of oil traps and percentage of world’s petroleum occurrence for each.

CombinationOther Stratigraphic

ReefUnconformitySalt DiapirsFaultsAnticlines

Structural Traps Stratigraphic Traps CombinationTraps

3%3%2%1%

75%

9%7%

1 - 12



1.6 FORMATION FRACTURE PRESSURE

In order to plan to drill a well safely it is necessary to have some knowledge of thefracture pressures of the formation to be encountered. The maximum volume ofany uncontrolled influx to the wellbore depends on the fracture pressure of theexposed formations.

If wellbore pressures were to equal or exceed this fracture pressure, the formationwould break down as fracture was initiated, followed by loss of mud, loss ofhydrostatic pressure and loss of primary control. Fracture pressures are related tothe weight of the formation matrix (Rock) and the fluids (water/oil) occupying thepore space within the matrix, above the zone of interest. These two factorscombine to produce what is known as the overburden pressure. Assuming theaverage density of a thick sedimentary sequence to be the equivalent of 19.2 ppgthen the overburden gradient is given by:

0.052 x 19.2 = 1.0 psi/ft

Since the degree of compaction of sediments is known to vary with depth thegradient is not constant.

NORMAL COMPACTIONAbnormally High Pressure Due to Hydrocarbon Column

0

4

5

6

7

8

9

1000’

WATER

GAS

DE

PT

H -

100

0 ft

Normal pressure at the Gas-Water contact

.465 x 6000’ = 2790 psi

1. Pressure on the Gas-Water Contact = 2790 psi 2. Less Gas Column Pressure = 0.10 x 1000’ = 100 psi

3. Pressure at top of Sand = 2690 psi

4. Abnormal Gradient at top Sand2690 psi––––––– = 0.538 psi/ft5000 ft

GRADIENT = 0.10 psi/ft

1

Figure 1.12



1 - 13

Onshore, since the sediments tend to be more compacted, the overburdengradient can be taken as being close to 1.0 psi/ft. Offshore, however theoverburden gradients at shallow depths will be much less than 1.0 psi/ft dueto the effect of the depth of seawater and large thicknesses of unconsolidatedsediment. This makes surface casing seats in offshore wells much more vulnerableto break down and is the reason why shallow gas kicks should never be shut in.See Fig 1.13

A B

C D

Hydrostatic due to sea water1500 x 0.445 = 667.5 psi

Pressure due to overburden1500 x 1.0 = 1500 psi

Hydrostatic due to sea water1500 x 0.445 = 667.5 psi




0 ft

1500 ft

3000 ft

0 ft

1500 ft

12000 ftTotal Overburden

11167.5 psi (0.93 psi/ft)Total Overburden

12000 psi (1.0 psi/ft)

Total Overburden 2167.5 psi (0.723 psi/ft)

Total Overburden 3000 psi (1.0 psi/ft)

Fracture Gradient Comparisons(for illustration purposes only)

Figure 1.13

1 - 14



1.7 LEAK-OFF TESTS

The leak-off test establishes a practical value for the input into fracture pressurepredictions and indicates the limit of the amount of pressure that can be applied tothe wellbore over the next section of hole drilled. It provides the basic data neededfor further fracture calculations and it also tests the effectiveness of the cement job.

The test is performed by applying an incremental pressure from the surface to theclosed wellbore/casing system until it can be seen that fluid is being injected intothe formation. Leak-off tests should normally be taken to this leak-off pressureunless it exceeds the pressure to which the casing was tested. In some instances aswhen drilling development wells this might not be necessary and a formationcompetency test, where the pressure is only increased to a predetermined limit,might be all that is required.

1.7.1 Leak-Off Test Procedure:

Before starting, gauges should be checked for accuracy. The upper pressure limitshould be determined.

1) The casing should be tested prior to drilling out the shoe.

2) Drill out the shoe and cement, exposing 5 - 10 ft of new formation.

3) Circulate and condition the mud, check mud density in and out.

4) Pull the bit inside the casing. Line up cement pump and flush all lines to beused for the test.

5) Close BOPs.

6) With the well closed in, the cement pump is used to pump a small volume ata time into the well typically a 1/4 or 1/2 bbl per min. Monitor the pressurebuild up and accurately record the volume of mud pumped. Plot pressureversus volume of mud pumped.

7) Stop the pump when any deviation from linearity is noticed between pumppressure and volume pumped.

8) Bleed off the pressure and establish the amounts of mud, if any, lost to theformation.



1 - 15

EXAMPLES OF LEAK-OFF TEST PLOT INTERPRETATION

In non-consolidated or highly permeable formations fluid can be lost at verylow pressures. In this case the pressure will fall once the pump has beenstopped and a plot such as that shown in Fig 1.14a will be obtained. Figs1.14b and 1.14c show typical plots for consolidated permeable andconsolidated impermeable formations respectively.

IDEALISED LEAK-OFF TEST CURVES

CUMULATIVE VOLUME

a) Unconsolidated Formations

PR

ES

SU

RE

CUMULATIVE VOLUME

b) Consolidated Permeable Formations

PR

ES

SU

RE

CUMULATIVE VOLUME

c) Consolidated Impermeable Formations

PR

ES

SU

RE

Final Pumping Pressure AfterEach Volume Increment

Final Static Pressure After Each Volume Increment

Leak-off Point

Figure 1.14

1 - 16



Working example of leak-off test procedure (floating rigs)

“Operational Drilling Procedures for Floating Rigs” is designed to determine theequivalent mud weight at which the formation will accept fluid. This test is notdesigned to break down or fracture the formation. This test is normally performedat each casing shoe.

Prior to the formation leak-off, have “handy” a piece of graph paper (see graph 1 ),pencil and straight edge (ruler). Utilising the high pressure cement pumping unit,perform leak-off as follows:

1. Upon drilling float equipment, clean out rat hole and drill 15 ft of new hole.Circulate and condition hole clean. Be assured mud weight in and mudweight out balance for most accurate results.

2. Pull bit up to just above casing shoe. Install circulating head on DP.

3. Rig up cement unit and fill lines with mud. Test lines to 2500 psi. Breakcirculation with cementing unit, be assured bit nozzles are clear. Stoppumping when circulation established.

4. Close pipe rams. Position and set motion compensator, overpull drillpipe(+/- 10,000 lbs), close choke/kill valves.

5. At a slow rate (i.e. 1/4 or 1/2 BPM), pump mud down DP.

6. a. Pump 1/4 bbl - record/plot pressure on graph paper.

b. Pump 1/4 bbl - record/plot pressure on graph paper.

c. Pump 1/4 bbl - record/plot pressure on graph paper.

d. Pump 1/4 bbl - record/plot pressure on graph paper.

e. Pump 1/4 bbl - record/plot pressure on graph paper.

f. Continue this slow pumping. Record pressure at 1/4 bbl incrementsuntil two points past leak-off.(See examples, Graph 1, 2 & 3.)

g. Upon two points above leak-off, stop pumping. Allow pressure tostabilize. Record this stabilized standing pressure (normally willstabilize after 15 mins or so).



1 - 17

h. Bleed back pressure into cement unit tanks. Record volume of bleedback.

i. Set and position motion compensator, open rams.

j. Rig down and cement unit lines. Proceed with drilling operations.

k. Leak-off can be repeated after step 6 if data confirmation is required,otherwise leak-off test is complete.

NOTE: For 20" and 13 3/8" csg leak-off tests, plot pressure every 1/2 bbl. Resultswill be the same.

It should be noted that in order to obtain the proper leak-off and pumping rateplot, it will be necessary to establish a continuous pump rate at a slow rate inorder to allow time to read the pressure and plot the point on the graph. (Barrelspumped vs. pressure - psi), normally 1/2 BPM is sufficient time.

A pressure gauge of 0-2000 psi with 20 or 25 increments is recommended.

NOTE: In the event Standing Pressure is lower than leak-off point. Use standingpressure to calculate equivalent mud weight. Always note volume of mudbled back into tanks.

1.7.2 Formation Breakdown Pressure (psi)

= hydrostatic pressure of mud in casing + applied surface pressure= (mud wt. x constant x vert shoe depth) + surface pressureThe formation breakdown pressure can be expressed as a GRADIENT.

Formation Breakdown Pressure (psi)Formation Breakdown Gradient (psi/ft) = ––––––––––––––––––––––––––––––

Vert. Shoe Depth (ft)

The formation breakdown gradient expressed as a maximum allowable mudweight:

Maximum Allowable Mud Weight (ppg) = Formation Breakdown Gradient (psi/ft) ÷ 0.052

orFormation Breakdown Pressure (psi)

Maximum Allowable Mud Weight (ppg) = –––––––––––––––––––––––––––––– ÷ 0.052Vert Shoe Depth (ft)

1 - 18



Graph 1.1 Formation Pressure Test Work Sheet

1100

1000

900

800

700

600

500

400

300

200

100

00 1 2 3 4 5 6 7 8 9 10 11 12 13 14

NOTE: Commence measuring volumeNOTE: after pressuring up to 200 psiNOTE: Pump at a 0.3 BPM rate andNOTE: plot pressures and volumesNOTE: (BBL's MUD)

SU

RFA

CE

TE

ST

PR

ES

SU

RE

- P

SI

BARRELS MUD PUMPED



1 - 19

Graph 1.2

1100

1000

900

800

700

600

500

400

300

200

100

00 1 2 3 4 5 6 7 8 9 10 11 12 13 14

NOTE: Commence plotting pressureNOTE: and pumped volume afterNOTE: pressuring up to 200 psi

SU

RFA

CE

TE

ST

PR

ES

SU

RE

- P

SI

BARRELS MUD PUMPED

Typical Pressure Testcsg set at 5000' TVDw/12 lb mud in hole.

Required Test Pressure(Equivalent to 16,0 Mud)

705 psi5 min stabilized

pressure

1 - 20



Graph 1.3

1100

1000

900

800

700

600

500

400

300

200

100

00 1 2 3 4 5 6 7 8 9 10 11 12 13 14

NOTE: Commence plotting pressureNOTE: and pumped volume afterNOTE: pressuring up to 200 psi

SU

RFA

CE

TE

ST

PR

ES

SU

RE

- P

SI

BARRELS MUD PUMPED

Typical Pressure Plot forFormation Breakdown andFracture Propagation

FormationBreakdown Pressure

Leak-offPressure



1 - 21

1.8 MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE - MAASP.

The leak-off test was used to determine the strength of the formations below thecasing shoe.

The Formation Breakdown Pressure = an applied surface pressure + hydrostatic pressure of mud in the casing

The applied surface pressure at which leak-off occurred is the maximum allowableannular surface pressure with the mud weight in use at that time. MAASP is themaximum surface pressure that can be tolerated before the formation at the shoefractures.

MAASP = Formation Breakdown pressure at shoe – Hydrostatic Pressure of mud in use in the casing shoe

or rewritten as:

MAASP = (Fracture gradient – Mud gradient) x True Vert. Shoe Depth

or as:

MAASP = (Max equiv. mud wt. – Mud wt. in casing) x (0.052 x True Vert. shoe depth)

MAASP is only valid if the casing is full of the original mud, if the mud weight inthe casing is changed MAASP must be recalculated.

The calculated MAASP is no longer valid if influx fluids enter into the casing.

1.9 CASING SETTING DEPTHS

The choice of setting depths for all the casingstrings is a vital part of the well planning process.An incorrect decision with the casing settingdepths too shallow could have seriousconsequences. An unnecessarily deep settingdepth could have adverse economicconsequences when considering the extra timeneeded to drill the hole deeper and the extraamount of casing required to be run andcemented.

Figure 1.15Typical Offshore Casing Program

30" Casing(Conductor)

20" Casing(Surface String.)

13 1/8" Casing(Intermediate String)

9 5/8" Casing(Production String)

7" Liner8 1/2" Hole

12 1/4" Hole

17 1/2" Hole

26" Hole

36" Hole

Seabed

1 - 22



1.9.1 Deep Casing Setting Depths

The selection of deeper casing setting depths will use different criteria to thoseused for shallow casing seats. Initial selection of the setting depth is made withreference to the anticipated lithological column, formation pressure and fracturegradient profiles. Once all the information has been collated from offset well data aplot similar to that shown in Fig 1.16 can be drawn up. By studying the geologyand pressure profiles, tentative setting depths can be chosen based on theprevention of formation breakdown by mud weights in use in the subsequent holesection. See Fig 1.17. From a Well Control point of view, it is necessary todetermine whether this tentative setting depth will give adequate protectionagainst formation breakdown when a kick is taken. A kick tolerance “factor” willnormally be applied.

Figure 1.16 Figure 1.17

PRESSURE PROFILE PREDICTIONS

0

2

4

6

8

10

12

14

8.0 10.0 12.0 14.0 16.0 18.0 20.0

Pressure Gradient - lb/gal Equivalent

Fracture Gradient

Pore Pressure Gradient

Dep

th x

100

0 ft

PRESSURE PROFILES WITH CASING SETTING DEPTHS

Proposed MudWeight program

Preferred Setting Depths

(based on lithological column)

Required Setting Depths

(to prevent formation fracturedue to weight of mud column)

0

2

4

6

8

10

12

14

8.0 10.0 12.0 14.0 16.0 18.0 20.0

Pressure Gradient - lb/gal Equivalent

Fracture Gradient

Pore Pressure Gradient

Dep

th x

100

0 ft



1 - 23

1.10 CIRCULATING PUMP PRESSURE

The pressure provided by the rig pump is the sum of all of the individualpressures in the circulating systems. All the pressure produced by the pumpis expended in this process, overcoming friction losses between the mud andwhatever it is in contact with:

• Pressure loss in surface lines• Pressure loss in drill-string• Pressure loss across but jets• Pressure loss in annulus

Pressure losses are independent of hydrostatic and imposed pressures.

Pressure losses in the annulus acts as a “back pressure” on the exposedformations, consequently the total pressure at the bottom of the annulus is higherwith the pump on than with the pump off.

Static bottom AnnulusCirculating bottom hole pressure =

hole pressure + pressure losses

0psi

3000psi

BHP = 5200 psi

5300 psi

BHP = 5450 psi

5300 psi

10000’

10 ppg MUD

Annulus Pressure Loss = 250 psi

Formation Pressure

STATICFormationwill Kick

CIRCULATINGFormation under

Control

Figure 1.18

1 - 24



The total pressure on bottom can be calculated and converted to an equivalentstatic mud weight which exerts the same pressure.

Equivalent Mud Wt (ppg) = (APL + Pmuda) ÷ 0.052 ÷ TVD

orAPL

Equivalent Mud wt E.C.D = Mud Wt in use + –––––––––– 0.052 X TVD

Where: APL = Annulus Pressure LossPmuda

= Hydrostatic Mud Pressure in Annulus

Circulating pressure will be affected if the pump rate or the properties of the fluidbeing circulated are changed.

Example:-Assuming a circulating pump pressure is 3000 psi when pumping at100 spm. The pump speed is increased to 120 spm. To approximate the newcirculating pump pressure:

New Pump Speed 2P(2) = P(1) x –––––––––––––––––

Original Pump Speed

Where:- P(1) = Original pump pressure at original pump speed.P(2) = New circulating pressure at new pump speed.

120 2P(2) = 3000 x –––– P(2) = 4320 psi at 120 spm

100

Example:-Assuming a circulating pump pressure in 3000 psi with a 10 ppg mudweight pumping at 100 spm. If the mud weight in the system was changedto 12 ppg. To approximate the new circulating pump pressure:

New Mud Weight 12P(2) = P(1) x –––––––––––––––– P(2) = 3000 x –––

Original Mud Weight 10

P(2) = 3600 psi when circulating with 12 ppg mud.

Note: Changing either pump speed or mud weight will affect annulus pressurelosses.

( )

( )



1 - 25

500PSI

SHAKERS

CONVENTIONAL SCF FLOW PATH

0PSI

SHAKERS

CLFL MEASUREMENT PUMPING DOWN CHOKE LINE CLCF = 200 PSI

200PSI

FROM PUMP

CHOKE

DRILL PIPE CHOKE MANIFOLD

1.11 CHOKE LINE FRICTION

LOSSES IN SUBSEA KILL OPERATIONSFigure 1.19

In subsea situations, a pressure loss exists whencirculating through the choke due to the friction losses inthe extended choke line running up from the BOP. Thispressure loss is not accounted for in normal SlowCirculating Rate (SCR) measurements, which are takenwhile circulating up the marine riser (see Fig 1.19).

If the normal method of bringing pumps to kill speed isfollowed (that is, choke manifold pressure maintainedequal to SICP until kill rate is achieved), bottom holepressure will be increased by an amount equal to thischoke line friction loss (CLFL). This excess pressure canresult in serious lost circulation problems during the killoperations.

Since fracture gradients generally decrease with increasedwater depth, correct handling of the CLFL becomes morecritical as water depth increases. Beyond approximately500 feet water depth, it should always be consideredwhile planning well control operations.

Figure 1.20It is possible to measure CLFL while takingSCR’s. One simple way to do this is to pumpdown the choke line at reduced pump rates(taking returns up the open marine riser as isshown in Figure 1.20) and record the pressurereading on the choke manifold gauge.

It is fundamental to all standard methods of wellcontrol to maintain constant bottom hole pressure(BHP) throughout kill operations. To accomplishthis a method must be used to keep total appliedcasing pressures relatively constant whilebringing the mud pump to kill rate.

In the absence of significant CLFL (surface stacksor shallow water), the method used is to merelykeep choke manifold pressure equal to SICP untilthe pump is up to speed.

1 - 26



But when CLFL exists, total applied casing pressure varies from SICP at pumpstart-up to SICP + CLFL with the pump at kill rate, if the above method were used.This would cause bottom hole pressure to increase by an amount equal to CLFL,as shown in Figures 1.21 and 1.22


800PSI

Pf = 6000 psiPh = 5200 psi (in annulus)PUMPS OFF (kick shut in)

1000PSI

CHOKE


SUBSEA BOP

CLFL0 PSI(STATIC)

APL0 PSI

BHP 6000 PSI

1500PSI

Pf = 6000 psiPh = 5200 psi (in annulus)PUMP AT KILL RATE HOLDING CONSTANTCHOKE MANIFOLD PRESSURE CHANGE IN BHP = 200 psi increase

1000PSI

CHOKE


SUBSEA BOP

CLFL200 PSI(DYNAMIC)

APLNEGLIGIBLE

BHP 6200 PSI

RETURNS



1 - 27

Figure 1.23

To eliminate this problem, two methods exist. First, byreducing choke manifold pressure by an amount equalto a known CLFL (adjusting choke manifold pressure toSICP -CLFL), the effect of the CLFL is negated. This isaccomplished by reducing the original SICP by theamount of CLFL while bringing the pumps to speed (seeFigure 1.23). Once kill rate pressure has been established,the choke operator switches over to the drill pipe gaugeand follows the drill pipe pressure graph in the usualway.

Or secondly, given a choke manifold configuration withseparate pressure gauges for choke and kill lines, it ispossible to utilise the kill line (shut off down-stream ofthe gauge outlet to prevent flow, thus eliminatingfriction) as a pressure connection to a point upstream ofany potential CLFL (known or unknown). This is shownin Figure 1.24. If the kill line gauge in this instance iskept constant while bringing the pump to speed, theeffect of CLFL is eliminated.

Figure 1.24Note the advantages of the second method:

1. The gauge reading choke manifoldpressure will show a decrease after pumpis up to speed. The amount of thisdecrease is equal to the CLFL.

2. No precalculated or pre-measured CLFLinformation is required.

3. The kill line gauge can be subsequentlyused like the choke manifold pressuregauge on a surface stack for the purposesof altering pump rates or problemanalysis.

NOTE: If the second method of handling theCLFL situation is preferred, it would beadvisable to rig a remote kill linepressure gauge which could be seen bythe choke operator.

Well shut in

1300PSI

Pf = 6000 psiPh = 5200 psi (in annulus)PUMP AT KILL RATE WITH REDUCEDCHOKE MANIFOLD PRESSURE CHANGE IN BHP = 0 psi increase

800PSI

CHOKE


SUBSEA BOP


APLNEGLIGIBLE

BHP 6000 PSI

RETURNS

1300PSI

Pf = 6000 psiPh = 5200 psi (in annulus)PUMP AT KILL RATE HOLDING CONSTANTKILL LINE PRESSURE READINGCHANGE IN BHP = 0 psi increase

800PSI

CHOKE


SUBSEA BOP


APLNEGLIGIBLE

BHP 6000 PSI

RETURNS

KLFL0 PSI

(STATIC)

1000PSI

1 - 28



575PSI

Pf = 5200 psiPh = 5100 psi (in annulus)PUMP AT 4 BBL/MIN HOLDING 0 PSICHOKE MANIFOLD PRESSURE CHANGE IN BHP = 100 psi increase

0PSI

CHOKE


SUBSEA BOP


APLNEGLIGIBLE

BHP 5300 PSI

RETURNS

It is extremely important to note that regardless of which Figure 1.25method is used, they both accomplish the goal ofmaintaining constant bottom hole pressure equal toformation pressure, just as would be the case were CLFLabsent. This is done without the need to alter anycalculations on the kick sheet. Thus initial and finalcirculating pressures, which are read on the drill pipe gauge,are unaffected by CLFL. CLFL is recorded on the Kick Sheetfor convenience only – it is not used in kick sheetcalculations.

Several additional points should be made about CLFL. Itshould be noted that it will only be possible to use the aboverecommended methods when SICP is greater than CLFL. Ifthis is not true, it will be unavoidable to apply excesspressure to the bottom of the hole using standard wellcontrol procedures. Also, as kill mud comes up the annulus,total applied casing pressure needed to maintain constantbottom hole pressure will eventually drop below CLFL.After this point, drill pipe pressures will exceed plannedFinal Circulating Pressure in spite of having the choke wideopen with no choke manifold back pressure.

Figure 1.26These situations can be mitigated by use of unusually slowpumping rates or by taking returns up choke and kill linessimultaneously. Figures 1.25 - 1.28 illustrate this problemand methods of dealing with it. They show an example inwhich a static SICP of 100 psi is reduced while pumping as aresult of the increase in back pressure created in circulatingup the choke line, by itself or choke and kill lines together.

Fig 24: Pumping 4 bbl/minwith choke wide open.

Note increase in BHPdue to excess CL friction.

75PSI

Pf = 5200 psiPh = 5100 psi (in annulus)PUMPS OFF (kick shut in)FCP @ 4 bbl/min = 400 psiFCP @ 2 bbl/min = 200 psiCLFL @ 4 bbl/min = 200 psiCLFL @ 2 bbl/min = 60 psi

100PSI

CHOKE


SUBSEA BOP

CLFL0 PSI(STATIC)

APL0 PSI

BHP 5200 PSI



1 - 29

Fig 1.27: Pump rate reduced to Fig 1.28: By taking flow up choke andbbl/min. BHP is held constant kill lines simultaneously, the same effectat SICP - CLFL is achieved as in fig 1.27, but at a

pumping rate of 4 bbl/min.


475PSI

Pf = 5200 psiPh = 5100 psi (in annulus)PUMP AT 4 BBL/MIN USING CHOKE AND KILL LINES FOR RETURN FLOWCHANGE IN BHP = 0 psi

40PSI

CHOKE


SUBSEA BOP

CLFL60 PSI(DYNAMIC)

APLNEGLIGIBLE

BHP 5200 PSI

RETURNS

KLFL60 PSI

(DYNAMIC)

40PSI

CHOKE

RETURNS

2 BBL/MIN2 BBL/MIN

4 BBL/MIN

275PSI

Pf = 5200 psiPh = 5100 psi (in annulus)PUMP AT 2 BBL/MIN WITH REDUCEDCHOKE MANIFOLD PRESSURE CHANGE IN BHP = 0 psi increase

40PSI

CHOKE


SUBSEA BOP

CLFL60 PSI(DYNAMIC)

APLNEGLIGIBLE

BHP 5200 PSI

RETURNS

1 - 30



1.12 - WORKSHOP 1

SCORE1. Convert the following mud densities into pressure gradients.

a. 13.5 ppg _____________ psi/ftb. 16 ppg _____________ psi/ftc. 12 ppg _____________ psi/ft 2

2. Convert the following gradients into mud densities.

a. 0.806 psi/ft _____________ ppgb. 0.598 psi/ft _____________ ppgc. 0.494 psi/ft _____________ ppg 2

3. Calculate the hydrostatic pressure for the following.

a. 9.5 ppg mud at 9000ft MD/8000 ft TVD =_____________b. 15.5 ppg mud at 18000ft TVD/21000ft MD =_____________c. 0.889 psi/ft mud at 11000ft MD/9000ft TVD =_____________ 2

4. Convert the following pressures into equivalent mud weights in PPG.

a. 3495 psi at 7000ft =_____________b. at 4000ft with 2787 psi =_____________c. 12000ft MD/10500ft TVD with 9000 psi =_____________ 2

5. High bottom hole temperatures could affect the hydrostatic pressuregradients resulting in:

a. An increase in the hydrostatic gradientb. A decrease in the hydrostatic gradientc. Would have no effect 2



1 - 31

SCORE6. Assuming a 10 ppg mud is being circulated at 700 GPM at a

depth of 10000ft TVD/MD the circulating pump pressure is3000 psi. If the circulating friction losses in the system are asfollows:

Pressure losses through pipe/collars 1200 psiPressure loss across the bit jets 1600 psiPressure loss in the annulus 200 psi

a. When circulating what is the dynamic bottom holepressure?

Answer..................... 2

b. What is the static bottom hole pressure?

Answer..................... 2

c. What is the equivalent circulating density ECD?

Answer..................... 2

d. If the pump speed is increased to give 800 GPM, what willthe pump pressure be?

Answer..................... 2

e. Will this increase in the pump speed have any effect onbottom hole pressure?

Answer YES/NO 2

f. Referring to the data given above, if the mud weight beingcirculated at 700 GPM was 12 ppg rather than 10 ppg, whatwould pump pressure be?

Answer...................... 2

7. When circulating a 12 ppg mud at 10000ft ECD is 12.3 ppg. Whatis the annular pressure loss?

Answer...................... 2

1 - 32



SCORE8. Calculate the pressure that one barrel of 12 ppg mud Wt exerts.

a. Around the drill collars if the annular capacity is 0.03 bbls/ft.

Answer...................... 2

b. Around the drill pipe if the annular capacity is 0.05 bbls/ft.

Answer...................... 2

9. If the fluid level in a well bore fell by 480ft, what is the reductionin bottom hole pressure if the mud weight is 12 ppg?

Answer...................... 2

10. If a 12 ppg mud over-balances the formation pressure by 240 psitheoretically how far could the mud level fall before goingunder-balance?

Answer....................... 2

11. Drilling at 12700ft with an 8 1/2" bit, the drill pipe is 5" with 700ftof 6 1/2" collars. The mud weight = 12 ppg. The yield point of themud is 12lbs/100ft2. Use the equation given below to determineECD.

Answer...................... 4

Annular-pressure loss = YP x L—————200(DH-DP)

where YP = Yield point of mud in lbs/100ft2

L = Length of annulus, collar or pipeDH = Hole diameterDP = Collar or pipe diameter

12. If a formation pore pressure gradient at 8500ft is 0.486 psi/ft,what mud weight is required to give an over-balance of 200 psi?

Answer...................... 2

WORKSHOP 1 - Answers



1 - 33


1. MUD WEIGHT x 0.052

a. 13.5 x 0.052 = 0.702 psi/ftb. 16.0 x 0.052 = 0.832 psi/ftc. 12.0 x 0.052 = 0.624 psi/ft

2. GRADIENT ÷ 0.052

a. 0.806 ÷ 0.052 = 15.5 ppgb. 0.598 ÷ 0.052 = 11.5 ppgc. 0.494 ÷ 0.052 = 9.5 ppg

3. T.V.D. x MUD WEIGHT x 0.052

a. 8000 x 9.5 x .052 = 3952 psib. 18000 x 15.5 x .052 = 14508 psic. 9000 x 0.889 = 8001 psi

4. PRESS ÷ T.V.D ÷ .052

a. 3495 ÷ 7000 ÷ .052 = 9.6 ppgb. 2787 ÷ 4000 ÷ .052 = 13.39 ppg (13.4)c. 9000 ÷ 10500 ÷ .052 = 16.48 ppg (16.5)

5. b.

6. (T.V.D. x MUD WT x .052) + A.P.L.

a. (10000ft x 10ppg x .052) + 200 = 5400 psib. 10000 x 10 x .052 = 5200 psic. 5400 ÷ 10000 ÷ .052 = 10.38 ppgd. 3000 x (800)2 = 3918 psi

—— (700)

Note d. This calculation is the same relationship asPress-Strokes-Relationship.(i.e.) P x (new S.P.M)2

—————(old S.P.M.)

1 - 34



e. YES

f. PRESS x (new MUD WT)———————— (old MUD WT)

3000 x (12)——(10) = 3600 psi

7. A.P.L. = (ECD - MUD WT) x (TVD x .052)= (12.3 - 12) x (10000 x .052)= .3 x 520

A.P.L. = 156 psi

8. MUD g psi/ft———ANN vol psi/ft

a. = 12 x .052 = .624 = 20.8 psi/bbl——.03

b. = .624 psi/bbl—————— = 12.48 Psi/bbl .05

9. 480 x 12 .052 = 299.52 psi (300 psi)

10. PRESS - psi = 240 = 384ft——— ——MUD g psi/ft .624ft



1 - 35

11. A.P.L. around D/C = 12 x 700 = 21 psi ————— 200(8.5-6.5)

A.P.L. around D/P = 12 x 12000 = 206 psi——————200 x (8.5 - 5)

TOTAL A.P.L. = 227psi

227ECD = 12 + —— ÷ .052

12700

ECD = 12.34 PPG

12. 8500 x .486 = 4131 + 200= 4331 psi

4331 ÷ 8500 ÷ .052 = 9.79 ppg = (9.8 ppg)

SECTION 2 : CAUSES OF KICKS

Page

2. 0 Objectives 1

2. 1 Introduction 1

2. 2 Primary Well Control- How it is Affected 1

2. 3 Causes of Kicks and Influxes 6

2. 4 Extracts From API RP59 15

2. 5 Workshop 2 22



2 - 1

CAUSES OF KICKS

2.0 OBJECTIVES

The objectives of this section are to Highlight the Causes of Kicks and Influxes.

2.1 INTRODUCTION

Primary control is defined as using the drilling fluid to control formation fluidpressure. The drilling fluid has to have a density that will provide sufficientpressure to overbalance pore pressure. If this overbalance is lost, even temporarilythen formation fluids can enter the wellbore. Preventing the loss of primarycontrol is of the utmost importance.

Definition of Kick

A kick is an intrusion of unwanted fluids into the wellbore such that the effectivehydrostatic pressure of the wellbore fluid is exceeded by the formation pressure.

Definition of Influx

An influx is an intrusion of formation fluids into the wellbore which does notimmediately cause formation pressure to exceed the hydrostatic pressure of thefluid in the wellbore, but may do, if not immediately recognised as an influx,particularly if the formation fluid is gas.

2.2 PRIMARY WELL CONTROL - HOW IT IS EFFECTED

To ensure primary well control is in place the following procedures andprecautions must be observed.

Mud Weight

Mud into and out of the well must be weighted to ensure the correct weight isbeing maintained to control the well. This task is normally carried out by theshaker man at least every thirty minutes or less, depending upon the nature of thedrilling operation and/or company policy. The mud weight can be increased byincreasing the solid content and decreased either by dilution or the use of solidscontrol equipment.

Tripping Procedures

Tripping in or out of the well must be maintained using an accurate log called atrip sheet. A trip sheet is used to record the volume of mud put into the well ordisplaced from the well when tripping.

A calibrated trip tank is normally used for the accurate measurement of mudvolumes and changes to mud volumes while tripping.

2 - 2



Figure 2.1

Numberof Stands

DISPLACEMENT

Per ___ Std. Total

Theoretical Last Trip This Trip Comments

Per ___ Std. Total Per ___ Std. Total

Well Name

Date

Depth

Time Trip Started

Mud Weight

D.P. Size

D.C. Size

Trip No.

Fluid Loss

D.P. Displacement

D.C. Displacement

If trip tank is used, record level of decrease.

If rig pump is used, calculate from strokes.



2 - 3

When tripping pipe or drill collars out of the hole, a given volume of mud is putinto the well for the volume of steel removed. If the volume required to fill thehole is significantly less than the volume of steel removed, then tripping must bestopped to ensure the well is stable, and consideration given to going back tobottom to condition the mud and investigate the cause of the problem.

THE HOLE MUST BE KEPT FULL AT ALL TIMES

A full opening or safety valve should be available at all times on the drill floortogether with the required crossover subs. A non-return (i.e. grey) valve shouldalso be readily available.


Trip Margin (Safety Factor)

Trip Margin (Safety Factor) is an overbalance to compensate for the loss of ECDand to overcome the effects of swab pressures during a trip out of the hole.

Upper Seat

Ball

Lower Seat

Crank

Body

FULL BORE OPENING SAFETY VALVE

NON RETURN SAFETY VALVE (GREY VALVE)

RELEASE TOOL

VALVE SEAT

VALVE RELEASE ROD

VALVE SPRING

2 - 4



Flow Checks

Flow checks are performed to ensure that the well is stable. Flow checks should becarried out with the pumps off to check the well with ECD effects removed. Flowchecks are usually performed when a trip is going to take place at the followingminimum places:

• on bottom

• at the casing shoe

• before the BHA is pulled into the BOP's

Short Trips/Wiper Trips

In some circumstances prior to pulling out of the hole a short trip, 5 or 10 standsshould be considered. The well is then circulated and mud returns carefullymonitored.

Pumping a Slug of Heavy Mud

This is a practice often carried out to enable the pipe to be pulled dry and the holeto be more accurately monitored during the trip. The following equation is used tocalculate the dry pipe volume for the slug pumped:

Dry Pipe Volume = Slug Volume x (Slug Weight ÷ Mud Weight - 1)

This dry pipe volume can be converted to Dry Pipe Length by dividing thisvolume by the internal capacity of the pipe as illustrated in the following equation:

Dry Pipe Length = Dry Pipe Volume (bbls) ÷ Drill Pipe Capacity (bbls/ft)

Mud Logging

A logging unit if available is extremely important particularly with respect to wellcontrol. The unit carries out some of the following services:

• Gas detection in the mud

• Gas analysis

• Cuttings density analysis

• Recording mud densities in and out

• Recording flow line temperatures

• Recording penetration rates

• Pore Pressure Trends



2 - 5

A typical mud logging system is illustrated in Figure 2.4 below.

KELLY POSITIONROPWOB

DEPTH

STANDPIPEPRESSURE

PUMP RATE

PIT LEVELS

STAND PIPE

KELLY HOSESWIVEL

KELLYPUMP

SUCTION

SUCTION PIT

FLOWLINE

SHAKER

SHALESLIDE

GAS QUANTITYGAS TYPE

MUD TEMPERATURERETURN MUD WEIGHT

• ROTARY SPEED

• TORQUE

VDU IN COMPANY

REP'S OFFICE

MUD LOGGING

UNIT

PROCESSING AND

EVALUATION

CUTTINGS DENSITY

FIG 2.4 TYPICAL MUD LOGGING SYSTEM

2 - 6



Communication

If a transfer of mud to the active system is requested the driller will be informed,the logging unit must likewise be informed. Good communication all round isessential.

Alarms

The high and low settings for the pit level recorder and flow line recorder must bechecked and are set to appropriate values.

2.3 CAUSES OF KICKS AND INFLUXES

The most common causes of kicks are:

• Improper monitoring of pipe movement (drilling assembly and casing).

- Trip out - making sure hole takes the proper amount of mud.- Trip in - making sure it gives up proper amount of mud and

preventing lost circulation due to surges.

• Swabbing during pipe movement.

• Loss of circulation.

• Insufficient mud weight.

- Abnormal pressured formations- Shallow gas sands

• Special situations.

- Drill stem testing- Drilling into an adjacent well- Excessive drilling rate through a gas sand

Surveys in the past have shown that the major portion of well control problemshave occurred during trips. The potential exists for the reduction of bottom holepressure due to:

• Loss of ECD with pumps off.

• Reduction in fluid levels when pulling pipe and not filling the hole.

• Swabbing.



2 - 7

2.3.1 FAILURE TO KEEP THE HOLE FULL DURING A TRIP

If the fluid level in the hole falls as pipe is removed a reduction in bottom holepressure will occur. If the magnitude of the reduction exceeds the trip margin orsafety overbalance factor a kick may occur. The hole must be kept full with a linedup trip tank that can be monitored to ensure that the hole is taking the correctamount of mud. If the hole fails to take the correct mud volume, it can be detected.A trip tank line up is shown in Fig 2.5.

Figure 2.5

It is of the utmost importance that drill crews properly monitor displacement andfill up volumes when tripping. The lack of this basic practice results in a largeamount of well control incidents every year.

2.3.2 SWABBING AND SURGING

Swabbing is when bottom hole pressure is reduced below formation pressure dueto the effects of pulling the drill string, which allows an influx of formation fluidsinto the wellbore.

When pulling the string there will always be some variation to bottom holepressure. A pressure loss is caused by friction, the friction between the mud andthe drill string being pulled. Swabbing can also be caused by the full gauge downhole tools (bits, stabilisers, reamers, core barrels, etc.) being balled up. This cancreate a piston like effect when they are pulled through mud. This type ofswabbing can have drastic effects on bottom hole pressure.

FILL UP LINE

RETURN LINE

TANK

BELL NIPPLE

FLOAT

INDICATOR

PUMP

CONTINUOUS CIRCULATING TRIP TANK

2 - 8



The factors affecting swabbing and surging are:

• Pulling speed of pipe.

• Mud properties.

• Viscosity.

• Hole geometry.

Surging

Surging is when the bottom hole pressure is increased due to the effects of runningthe drill string too fast in the hole. Down hole mud losses may occur if care is nottaken and fracture pressure is exceeded while RIH. Proper monitoring of thedisplacement volume with the trip tank is required at all times.

Figure 2.6

Swabbing is a recognised hazard whether it is “low" volume swabbing or “high”volume swabbing. A small influx volume may be swabbed into the open holesection. The net decrease in hydrostatics due to this low density fluid will also besmall. If the influx fluid is gas it can of course migrate and expand. The expansionmay occur when there is little or no pipe left in the hole. The consequences ofrunning pipe into the hole and into swabbed gas must also be considered.

Pulling Speeds

Tripping speeds must be controlled to reduce the possibility of swabbing. It isnormal practice for the Mud Logger to run a swab and surge programme and tomake this information available to the Driller. This will provide ample informationto reduce the possibility of unforeseen influx occurring.

PRESSURE SURGES SWABBING ACTION



2 - 9

Mud Properties

Controlling the rheology of mud is important. Controlling water-loss to avoidthick wall cake will also help.

Trip Margin

A safety factor to provide an overbalance to compensate for swab pressure can be:

Trip Margin Factor APL psi––––––––––––––––– = –––––––––––––––––

(psi/ft) True Vert. Depth. ft

APL = Annulus Pressure Loss

If swabbing has been detected and the well is not flowing a non return valveshould be installed and the bit returned to bottom. Flow check each stand. Onceback on bottom the well should be circulated and the bottoms up sample checkedfor contamination.

If the well is flowing or the returns from the well are excessive when tripping inthen the following should be carried out:

• Install a non return valve. If there is a strong flow then a kelly cock mayhave to be installed first.

• Shut the well in.

• Prepare for stripping.

• Strip in to bottom.

• Circulate the well, check bottoms up for contamination.

Continuous monitoring of replacement and displacement volumes is essentialwhen performing tripping. A short wiper trip and circulating the well beforepulling completely out of the hole will provide useful information about swabbingand pulling speeds.

Useful formulae for calculating the psi reduction per foot of drill pipe pulled are asfollows:

(mud grad. (psi/ft) x metal disp. (bbls/ft))Pulling Dry Pipe: psi/ft or dry pipe pulled = (–––––––--––––––––––––--––––––––––––––– ) (casing cap. (bbls/ft) - metal disp. (bbls/ft))

(mud grad. (psi/ft) x metal disp. + cap. (bbls/ft)Pulling Wet Pipe: psi/ft or wet pipe pulled = (–––––––--–––––––-–––––-–––––––––-–––––– ) (casing cap. (bbls/ft) - metal disp. + cap. (bbls/ft))

2 - 10



2.3.3 LOSS OF CIRCULATION

Another cause for a kick to occur is the reduction of hydrostatic pressure throughloss of drilling fluid to the formation during lost circulation. When this happens,the height of the mud column is shortened, thus decreasing the pressure on thebottom and at all other depths in the hole.

The amount the mud column can be shortened before taking a kick from apermeable zone can be calculated by dividing the mud gradient into theoverbalance at the top of the permeable kick zone.

Overbalance (psi)H (ft) = ––––––––––––––––––––––

Mud Gradient (psi/ft)

2.3.4 INSUFFICIENT MUD WEIGHT

A kick can occur if a permeable formation is drilled which has a higher pressurethan that exerted by the mud column. If the overpressurised formations have lowpermeability then traces of the formation fluid should be detected in the returnsafter circulating bottoms up. If the overpressured formations have a highpermeability then the risk is greater and the well should be shut-in as soon as flowis detected.

2.3.5 ABNORMAL PRESSURED FORMATIONS

A further cause of kicks from drilling accidentally into abnormally pressuredpermeable zones. This is because we had ignored the warning signals that occur,these help us detect abnormal pressures. Some of these warning signals are: anincreased penetration rate, an increase in background gas or gas cutting of themud, a decrease in shale density, an increase in cutting size, or an increase inflow-line temperature, etc.

In some areas, there were adequate sands that were continuous and open into thesea or to the surface. In these areas the water squeezed from the shale formations,travelled through the permeable sands and was released to the sea or to a surfaceoutcrop. This de-watering allowed the formations to continue to compact andthereby increase their density.



2 - 11

Figure 2.7

In other areas, or at other times, the sands did not develop or were sealed bydeposition of salt or other impervious formations, or by faulting such as we haveindicated here. Although the shale water was squeezed, it could not escape. Sincewater is nearly incompressible, the shales could not compress past the point wherethe water in the shale started to bear the weight of the rock above. This sectioncaused a condition in which the weight of the formation - that is, the overburden -was borne not by the shale alone, but assisted by the fluids in the shale. In thissituation the shale will have more porosity, and a lower density, than they wouldhave had if the now pressured water had been allowed to escape. Theseformations, both sand and shale, are then overpressured. If a hole is drilled intoan overpressured formation, weighted mud will be required to hold back thefluids contained in the pore space.

Figure 2.8

Abnormally high formation pressure is defined as any formation pressure that isgreater than the hydrostatic pressure of the water occupying the formation porespaces. Abnormally high formation pressures are also termed surpressures,overpressures and sometimes geopressures. More often, they are simply calledabnormal pressures.

PERMEABLE ZONE

NORMAL PRESSURE

SEA

FAULT

ABNORMAL PRESSURE

SEA

2 - 12



Abnormally high formation pressures are found worldwide in formations rangingin age from the Pleistocene age (approximately 1 million years) to the Cambrianage (500 to 600 million years). They may occur at depths as shallow as only a fewhundred feet or exceeding 20,000 ft and may be present in shale/sand sequencesand/or massive evaporite-carbonate sequences.

The causes of abnormally high formation pressures are related to a combinationof geological, physical, geochemical and mechanical processes.

As defined, the magnitude of abnormally high formation pressures must begreater than the normal hydrostatic pressure for the location, and may be as highas the overburden pressure. Abnormally high pressure gradients will thus bebetween the normal hydrostatic gradient (0.433 to 0.465 psi/ft) and theoverburden gradient (generally 1.0 psi/ft).

However, locally confined pore pressure gradients exceeding the overburdengradient by up to 40% are known in areas such as Pakistan, Iran, Papua NewGuinea, and the CIS. These super pressures can only exist because the internalstrength of the rock overlying the super pressured zone assists the overburdenload in containing the pressure. The overlying rock can be considered to be intension.

In the Himalayan foothills of Pakistan, formation pressure gradients of 1.3 psi/fthave been encountered. In Iran, gradients of 1.0 psi/ft are common and in PapuaNew Guinea, a gradient of 1.04 psi/ft has been reported. In one area of Russia,local formation pressure in the range of 5870 to 7350 psi at 5250 feet were reported.This equates to a formation pressure gradient of 1.12 to 1.4 psi/ft.

In the North Sea abnormal pressures occur with widely varying magnitudes inmany geological formations.

The Tertiary sediments are mainly clays and may be overpressured for much oftheir thickness. Pressure gradients of 0.52 psi/ft are common with locallyoccurring gradients of 0.8 psi/ft being encountered. An expandible clay (gumbo)also occurs which is of volcanic origin and is still undergoing compaction. Theconsequent decrease in clay density would normally indicate an abnormalpressure zone but this is not the case. However, in some areas, mud weights of theorder of 0.62 psi/ft or higher are required to keep the wellbore open because of theswelling nature of these clays. This is almost equal to the low overburdengradients in these areas.

In the Mesozoic clays of the North Sea Central Graben, overpressures of 0.9 psi/fthave been recorded. One reported case indicated a formation pressure gradient of0.91 psi/ft in the Jurassic section. In the Jurassic of the Viking Graben, abnormalformation pressure gradients of up to 0.69 psi/ft have been recorded.



2 - 13

In Triassic sediments, abnormally high formation pressures have been found ingas bearing zones of the Bunter Sandstone in the southern North Sea. Also in thesouthern North Sea, overpressures are often found in Permian carbonates,evaporates and sandstones sandwiched between massive Zechsteins salts.

2.3.6 SHALLOW GAS SANDS

Kicks from shallow sands (gas and water) whilst drilling in the top hole sectionwith short casing strings can be very hazardous, as documented by many casehistories. Some of the kicks from shallow sands are caused by charged formations:poor cement jobs, casing leaks, injection operations, improper abandonments, andprevious underground blowouts can produce charged formations.

2.3.7 SPECIAL SITUATIONS

a) Drill Stem Testing (DST)

The formation test is one of the most hazardous operations encountered in drillingand completing oil and gas wells. The potential for stuck tools, blowouts, lostcirculations, etc., is greatly increased.

A drill stem test is performed by setting a packer above the formation to be tested,and allowing the formation to flow. Down hole chokes can be incorporated in thetest string to limit surface pressures and flow rates to the capabilities of the surfaceequipment to handle or dispose of the produced fluid.

During the course of the test, the bore hole or casing below the packer, and at leasta portion of the drill pipe or tubing, is filled with formation fluid. At theconclusion of the test, this fluid must be removed by proper well controltechniques to return the well to a safe condition. Failure to follow the correctprocedures to kill the well could lead to a blowout.

b) Drilling Into an Adjacent Well

Drilling into an adjacent well is a potential problem, particularly offshore where alarge number of directional wells are drilled from the same platform. If the drillingwell penetrates the production string of a previously completed well, theformation fluid from the completed well will enter the wellbore of the drillingwell, causing a kick. If this occurs at a shallow depth, it is an extremely dangeroussituation and could easily result in an uncontrolled blowout.

2 - 14



c) Excessive Drilling Rate Through a Gas Sand/Limestone

When drilling a gas bearing formation, the mud weight will be gas cut due to thegas breaking out of the pore space of the cuttings near the surface. The severity ofthe influx will depend on the penetration rate, porosity and permeability, and isindependent of mud weight. The importance attached to gas cutting is that gas isentering the wellbore in small quantities, which calls for caution. Degassing isnecessary to ensure that good mud is being pumped back into the hole to preventthe percentage of gas from increasing with each circulation, which would allowgreater and greater bottom hole hydrostatic pressure reductions.

Figure 2.9 Reduction in Hydrostatic Head Due to Gas Cutting of the Mud

18 ppg mud cut 50% to 9.0 ppg

Depth Normal Head Reduced Head

18 ppg mud Head Reduction

1,000' 936 psi 866 psi 60 psi

5,000' 4,680 psi 4,598 psi 82 psi

10,000' 9,360 psi 9,265 psi 95 psi

20,000' 18,720 psi 18,615 psi 105 psi

Most of mud cutting is close to surface. Divert flow through choke manifold toprevent belching and to safely contain gas through mud gas separator. Time drillthe gas cap to prevent severe gas cutting of mud.

Gas cutting alone does not indicate the well is kicking, unless it is associated withpit gain. Allowing the well to belch over the nipple could cause reduction inhydrostatic pressure to the point that the formation would start flowing, resultingin a kick.



2 - 15

2.4 EXTRACTS FROM API RP59

4.1 Introduction. Loss of primary well control most frequently results from:1) failure to keep the hole full; 2) swabbing; 3) insufficient drilling fluid density;and/or 4) lost circulation. These problems can occur during any operationconducted on a well. The goal of well control is to prevent a well kick (influx offormation fluid into the wellbore) from becoming a blowout (uncontrolled flowof formation fluid).

4.2 Conditions Necessary for a Kick. The two conditions that must be present inthe wellbore for a kick to occur are 1) the pressure in the wellbore at the face of thekicking formation must be less than the formation pressure; and 2) the kickingformation must have sufficient permeability to allow flow into the wellbore. Tomaintain primary well control, drilling personnel should utilise all techniques attheir disposal to ensure that the hydrostatic pressure in the wellbore is alwaysgreater than the formation pressure. A number of conditions which can cause orcontribute to well kicks are discussed in Paras 4.3 through 4.15.

4.3 Hole Not Full of Drilling Fluid. When the fluid level in the wellbore isallowed to drop or is maintained with a lighter density fluid, the resultant reducedhydrostatic head can allow fluid entry from the formation. The rig should havedrilling fluid measuring devices to determine that proper fluid replacement ordisplacement occurs when pulling or running pipe. The type of fluid measuringequipment used should be influenced by the anticipated well control operationsinvolved in drilling the well.

4.4 Tripping Out of the Hole. When pulling pipe, its displacement volume shouldbe replaced with the proper amount of drilling fluid to maintain constanthydrostatic pressure. Any significant reduction in hydrostatic pressure may resultin loss of primary control. If the hole fails to take the proper amount of drillingfluid, hoisting operations should be suspended and an immediate safe course ofaction determined while observing the well. This usually requires returning tobottom and circulating the hole. The frequency of filling the hole during trippingoperations is critical in maintaining primary control. The hole should be completelyfilled at intervals that will prevent an influx of formation fluid. Continuous fillingor filling after each stand of drill pipe may be advisable. The hole should be filledafter each stand of drill collars. When the hole is filled continuously, an isolateddrilling fluid volume measurement facility (such as a trip tank) must be used.

4.5 Tripping In the Hole. In running pipe back in the hole, the drilling fluidvolume increase at the surface should be no greater than predicted displacement.Some holes take significant volumes of drilling fluid during trips because ofseepage loss. It is necessary to keep a trip book (refer to Para. 10.3 and Table 10.1)for ready comparison to determine if an abnormal condition occurs. The gaugingof fluid returns and comparison with prior trip records should provide a warningof possible loss of primary well control. The hole and fluid returns should bechecked at frequent intervals.

2 - 16



4.6 Out of the Hole. Time with pipe out of the hole should be minimised.Particular care should be taken when a servicing tool, such as a core barrel, withits length too great to clear the ram closure zone and/or its outside diameter toolarge to fit the pipe rams, to have the necessary crossover connection(s) readilyavailable so that correct pipe movement can be effected to be able to close morethan the annular blowout preventer. In case of equipment repair on drilling rigs,the pipe should be run at least back to the last easing shoe, if possible, beforerepairs are undertaken. In well servicing operations, when making equipmentrepairs, effecting routine maintenance, or shutting down overnight, the pipeshould be run to a sufficient depth to ensure that the well can be controlled.

4.7 Swabbing. When pipe is pulled from a well, a reduction in bottom-holehydrostatic pressure (swabbing) may occur. Bottom-hole pressure reduction ofseveral hundred pounds per square inch (psi) can occur when swabbing takesplace. This pressure reduction, which can be sufficient to permit the entry offormation fluid into the wellbore, is one of the major reasons for losing primarywell control. This type of swabbing action should not be confused with the moreobvious concept of actually pulling fluid from a well with a balled up bit orpacker, or swabbing in a producing well through tubing. When pipe is pulled froma well, swabbing can be difficult to detect. The well may take some fluid as thepipe is withdrawn but less than the complete pipe displacement. The detection ofswabbing, therefore, can only be done by accurately measuring the drilling fluidadded to the hole as pipe is pulled. Three prime factors in controlling swabbingare: 1) drilling fluid properties; 2) rate of pulling pipe; and 3) drill string and holeconfigurations.

4.8 Trip Margin. The use of a trip margin is encouraged to offset the effects ofswabbing. The additional hydrostatic pressure will permit some degree ofswabbing without losing primary well control.

4.9 Short Trip. After tripping and circulating “bottoms-up,” the amount of gas,salt water, or oil contamination will enable the evaluation of operating practicesaffecting swabbing. Adjustments in pulling speed, drilling fluid flow properties,and/or drilling fluid density may be warranted. A short trip and circulating“bottoms-up” before pulling out of the hole can also be used to determine thesystem’s swabbing characteristics.

4.10 Insufficient Drilling Fluid Density. The condition where formation pressureexceeds existing hydrostatic pressure in the wellbore is referred to as under-balance and can be caused be insufficient drilling fluid density.

4.11 Lost Circulation. Lost circulation occurs in both drilling and well servicingoperations and may quickly destroy the hydrostatic overbalance that constitutesprimary control. The loss can result from natural or induced causes. Naturalcauses include fractured, vugular, cavernous, subnormally-pressured, or pressure-depleted formations. Induced loss can result from mechanical formation fracturingresulting from 1) excessive drilling fluid density, 2) excessive annular circulatingpressure, 3) pressure surges related to running pipe or tools. 4) breakingcirculation, or 5) packing off in the annulus.



2 - 17

4.12 Drill Stem Testing. Drill stem tests are performed by setting a packer abovethe formation to be tested and allowing the formation to flow. During the courseof testing, the borehole or casing below the packer and at least a portion of thedrill pipe or tubing is filled with formation fluid. At the conclusion of the test, thefluid in the test string above the circulating valve must be removed by proper wellcontrol techniques, such as reversing, to return the well to a safe condition.Depending on the length of hole below the packer, type of fluid entry, andformation pressure, the normal drilling hydrostatic overbalance can be reducedor lost. Caution should be exercised to avoid swabbing when pulling the teststring because of the large diameter packers.

4.13 Drilling Into an Adjacent Well. Frequently, a large number of directionalwells are drilled from the same offshore platform or onshore drilling pad. If adrilling well penetrates the production string of a previously completed well,the formation fluid from the completed well may enter the wellbore of the drillingwell, causing a kick. Special care should be exercised to avoid a collision coursewith another well.

4.14 Excessive Drilling Rate Through a Gas Sand. Even if the drilling fluiddensity in the hole is sufficient to control gas zone pressure, gas from the drilledcuttings will mix with the drilling fluid. Excessive drilling rate through a shallowgas zone or coal bed can supply sufficient gas from cuttings to reduce thehydrostatic pressure of the drilling fluid column through a progressivecombination of density reduction and drilling fluid loss from “belching” to thepoint that the formation will begin flowing into the wellbore.

4.15 Others. Primary control can also be lost while performing operations otherthan circulating, drilling, or running and pulling pipe, loss of well control canoccur during coring, perforating, fishing, performing primary or remedialcementing, running casing or liner operations, or when differential fill equipmentmalfunctions. All such operations require the accurate measurement and controlor drilling fluid replaced or displaced in the well to maintain primary control.Complications can occur in primary control during floating drilling operationsdue to distorted readings caused by motion and heave. The measurement ofdrilling fluid volume and flow rate is most critical in floating operations andrequires pit level monitoring devices (floats) located in the centre of the pits ormulti-floats with sequential integration utilised. A trip tank and pit watchershould be considered if vessel movement creates any problem in measuringdrilling fluid requirements on trips.

4.16 Special Situations. The accurate prediction of pressure gradients, particularlyabnormal pressure, and the prevention of an insufficient drilling fluid densitysituation, are highly desirable but not always attainable. In some situations ofinsufficient drilling fluid density, operations can be safely handled and proceedwithout increasing drilling fluid density, yet maintain control (underbalanceddrilling). An abnormally pressured gas zone with low productivity (e.g., shale gas)is a possible example where the well will not flow appreciably but gas exists after

2 - 18



a trip which may require use of blowout prevention equipment and/or rotatingheads. Sometimes fluid influx will occur when circulation is stopped, but will notoccur during drilling operations due to the effect of annular circulating pressure.In this instance, successful operations usually require an increase in drilling fluiddensity or, in some fields, the use of a lighter drilling fluid and another heavierdrilling fluid to control the well on trips.

WELL CONTROL WARNING SIGNALS

4.17 General. Well control warning signals can be classified in three major generalcategories as follows:

A. Previous Field History and Drilling Experiences.

1. Depth of zones capable of flowing.

2. Formation gradients.

3. Fracture gradients.

4. Formation content.

5. Formation permeability.

6. Intervals of lost circulation.

B. Physical Response From the Well.

1. Pit gain or loss.

2. Increase in drilling fluid return rate.

3. Changes in flowline temperature.

4. Drilling breaks.

5. Variations in pump speed and/or standpipe pressure.

6. Swabbing.

7. Drilling fluid density reduction.

8. Effects of connections, short trip, and trip on shows and gains.

9. Hole problems indicating underbalance (i.e., tight hole, packing-off, sloughing).

10. Excessive pressure or pressure changes between casing strings.



2 - 19

C. Chemical and Other Technical Responses From the Well.

1. Chloride changes in the drilling fluid.

2. Oil show.

3. Gas show (chromatograph).

4. Formation water.

5. Shale density.

6. Electric logs.

7. Drilling equation exponents.

4.18 Volume of Drilling Fluid to Keep the Hole Full on a Trip is Less ThanCalculated or Less Than Trip Book Record. This condition is usually caused byformation fluid entering the wellbore due to the swabbing action of the drill string.As soon as swabbing is detected, the drill string should be run back to bottom.Circulate and condition the drilling fluid to minimise further swabbing. It may benecessary to increase the drilling fluid density, but this should not be the first stepconsidered because of the inherent potential problems of causing lost returns ordifferential sticking.

4.19 Gain in Pit Volume. An unaccounted volume gain in the drilling fluid pit(s) isan indication that a kick may be occurring. As the formation fluid feeds into thewellbore, it causes more drilling fluid to flow from the annulus than is pumpeddown the drill string, thus the volume of fluid in the pit(s) increases.

4.20 Increased Flow From Annulus. If the pumping rate is held constant, the flowfrom the annulus should be constant. If the annulus flow increases without acorresponding change in pumping rate, the additional flow is caused by formationfluid(s) feeding into the wellbore or gas expansion.

4.21 Sudden Increase in Bit Penetration Rate. A sudden increase in penetrationrate (drilling break) is usually caused by a change in the type of formation beingdrilled: however, it may also signal an increase in formation pore pressure.Increased penetration rates due to higher pore pressures are usually not as abruptas formation drilling breaks, but they can be. In order to be certain that gradualincreases in pore pressure are recognised, a penetration rate versus depth curveplot is recommended to highlight the trend of increasing pore pressure.

4.22 Change in Pump Speed or Pressure. The initial surface indication that a wellkick has occurred could be a momentary increase in pump pressure. The pumppressure increase is seldom recognised because of its short duration, but it hasbeen noted on some pump pressure recording charts after a kick was detected.

2 - 20



The pressure increase is followed by a gradual decrease in pump pressure, andmay be accompanied by an increase in pump speed. As the lighter formation fluidflows into the wellbore, the hydrostatic pressure exerted by the annular column offluid decreases, and the drilling fluid in the drill pipe tends to U-tube into theannulus. When this occurs, the pump pressure will drop and the pump speed willincrease. The lower pump pressure and increase in pump speed symptoms arealso indicative of a hole in the drill string, commonly referred to as a washout.Until a confirmation can be made whether a washout or a well kick has occurred, akick should be assumed.

4.23 Gas-cut Drilling Fluid. Gas-cut drilling fluid often occurs during drillingoperations and can be considered one of the early warning signs of a potentialwell kick: however, it is not a definite indication that a kick has occurred or isimpending. An essential part of analysing this signal is being able to determinethe downhole conditions causing the drilling fluid to be gas-cut. Gas-cut fluidoccurs as a result of one or more of the following downhole conditions:1) drilling a gas-bearing formation with the correct drilling fluid density in thehole (drilled gas); 2) swabbing while making connections or making a trip(trip or connection gas); and 3) influx of gas from a formation having a porepressure greater than the pressure exerted by the drilling fluid (gas flow).

A. Drilled Gas. When the hydrostatic pressure exerted by the drilling fluid isgreater than the pore pressure of a gas-bearing formation being drilled, therewill be no influx of gas from the formation. Nevertheless, gas from the drilledcuttings will usually mix with the drilling fluid causing the returns to be gascut. As gas is circulated up the annulus, it expands slowly until just beforereaching the surface. The gas then undergoes a rapid expansion, resulting inthe drilling fluid density being reduced considerably upon leaving theannulus. In some cases this reduction in density can be quite extreme but itmay not mean that a kick is about to occur. Usually, only a small loss inhydrostatic pressure results because the majority of gas expansion occurs inthe top of the hole. Drilling fluid of proper density is still maintained in mostof the hole. Quite often when the drilled gas reaches the surface, the annularpreventer must be closed and the drilling fluid circulated through the openchoke manifold. This prevents the expanding gas from “belching” fluidthrough the bell nipple. If “belching” continues, the hydrostatic head will bereduced due to loss of drilling fluid from the hole.

B. Trip or Connection Gas. After circulating “bottoms-up” following a trip orconnection, a higher level of gas entrained in the drilling fluid returns maycause a short duration density reduction or gas unit increase. If the well didnot flow when the pumps were stopped during the trip or connection, it canbe reasonably assumed that the gas was swabbed into the wellbore by thepipe movement. These symptoms can indicate increasing formation pressurewhen compared with previous trips and connections.



2 - 21

C. Gas Flow. Influx from a gas zone while drilling is a serious situation.While drilling, the formation pore pressure must exceed the hydrostaticpressure of the drilling fluid plus the circulating friction losses in the annulusfor gas from the formation to flow into the wellbore. Once influx begins,continued circulation without the proper control of surface pressures willinduce additional flow, since the density of the hydrostatic column (annulus)is continually lessened by the flow of formation fluid and expansion of gas.

4.24 Liquid-cut Drilling Fluid. When a permeable liquid-bearing formationhaving pore pressure greater than the drilling fluid hydrostatic pressure isencountered, fluid will feed into the wellbore. Depending upon the pressuredifferential between the formation and the drilling fluid, influx may be detectedby: 1) a gain in pit volume, 2) lower density returns, 3) a change in drilling fluidchlorides, and/or 4) an increase in rotary torque. The volume of liquid containedin the cuttings is usually so small that unless accompanied by gas, it will notsignificantly affect the drilling fluid density.

NOTE: A rare exception to this rule is the very low permeability formation which can bedrilled while allowing a continuous small influx to occur. This type of underbalanceddrilling is only practicable in certain well-known drilling areas where the geology issufficiently known to allow preplanning for the rig equipment and drilling practicesnecessary.

ADDITIONAL CAUSES OF KICKS UNIQUE TO SUBSEA OPERATIONS

9.2 Loss of Integrity. Wellbore hydrostatic pressure is a function of height anddensity of the drilling fluid column from the flowline to the depth of interest. If ariser fails, leaks, or becomes disconnected, the drilling fluid gradient in the riser islost and replaced by a sea water gradient (approximately 0.445 psi/ft — 8.56 Ib/gal) from the point of failure to sea level. The loss of wellbore hydrostatic pressureassociated with this situation can sometimes be sufficient to allow the well to flow.The first response should be to close the blowout preventers. In some situations,the drilling fluid density may be sufficient to compensate for the loss ofhydrostatic pressure. If not, the loss of hydrostatic pressure should be restoredprior to opening the blowout preventer.

9.3 Trapped Gas Below Blowout Preventers Subsequent to control operationsduring which gas is circulated out the choke line, free gas will remain trappedbelow the closed preventer. If the closed preventer is an annular preventer, it ispossible for this volume of gas to be quite significant. In order to prevent a rapidunloading of the riser due to trapped gas when the annular preventer is opened orthe introduction of a secondary kick due to light density drilling fluid in the riser,close the uppermost rams below the choke line and close the diverter. Open thepreventer above the trapped gas and allow this gas to rise toward the surface.Displace the riser with kill fluid and reopen the rams. It may be necessary inextreme cases to close the bottom rams to isolate the hole and fill the riser bycirculating through the kill line. This problem becomes more severe with increasedwater depth and/or preventer size.

2 - 22



2.5 - WORKSHOP 2

SCORE

1. There are a variety of mechanisms that can cause abnormalformation fluid pressures. List 4 of the principle causes below.

Answer (a) ————————(b) ————————(c) ————————(d) ———————— 2

2. Shown below is a pressure versus volume plot of a leak off test.

The leak off was carried out with a 10.6 ppg mud. The casing shoe is at4000ft TVD.

a. What is the maximum pressure that the exposed formations below the shoe can support?

ANSWER................. 2

b. What is the “Fracture Gradient?”ANSWER................. 2

c. What is the maximum mud weight?ANSWER................. 2

d. If drilling was resumed and the mud weight was increased to12.6 ppg. Calculate M.A.A.S.P

ANSWER................. 2

1200

1000

800

600

400

200

0

PR

ES

SU

RE

(P

SI)

VOLUME



2 - 23

SCORE3. M.A.A.S.P. The maximum allowable annular surface pressure

should be re-calculated..

a. At the start of each shiftb. As soon as possible after a drilling breakc. When approaching a suspected transition zoned. When the mud weight has been increased in the systeme. If a kick has occurred and the well is shut-in

ANSWER................. 2

4. The calculated M.A.A.S.P. value is relevant..

a. When the influx is in the open-hole sectionb. As the influx approaches the surface

ANSWER................. 2

SCORE5. Given the following data:

Depth 10000ft TVDBit size 8 1/2"Shoe depth 8500ft TVDMud weight 12.6 ppg

Collars - 600ft. capacity = 0.0077 bbl/ftMetal displacement = 0.03 bbl/ftDrill-pipe 5" capacity = 0.0178 bbl/ftMetal displacement = 0.0075 bbl/ftCasing/pipe annular capacity = 0.0476 bbl/ftCasing capacity = 0.0729 bbl/ftOne stand of drill-pipe = 94ft.

Assuming the 12.6 ppg mud gives an over-balance of 200 psi.

a. If 10 stands of pipe are removed “dry” without filling the hole,what would be the resultant reduction in bottom-hole pressure?

ANSWER........................... 3

b. If 5 stands of pipe had been pulled “wet” without filling thehole, the resultant reduction in bottom-hole pressure would be.

ANSWER........................... 3

c. If prior to tripping a 20 barrel slug of 14.6 ppg mud wasdisplaced to prevent a wet trip, what would be the expectedvolume return due to the U-tubing of the heavy mud?

ANSWER........................... 2

2 - 24



6. Prior to tripping out of the hole a trip tank and pump are lined up tokeep the hole full as the pipe is removed. The trip tank contains 30barrels of mud. After pulling 10 stands of pipe the level in the triptank is 27 barrels. (Use data given in Question 6). Would the safestoption be..

a. To continue tripping but flow-check when bits at shoe.b. Stop and shut the well in. If no pressures seen open

the well up and continue tripping.c. Flow-check. If no flow, go back to bottom and circulate.d. Flow-check. If no flow, continue tripping

ANSWER............................ 2SCORE

7. A well can be induced to flow by swabbing. Swabbing is thereduction of bottom hole pressure due to the effects of pulling pipe.List below 3 conditions that can cause swabbing.

Answer (a) ———————(b) ———————(c) ——————— 2

8. A drill string consist of 5" 20 lb/ft drill-pipe and 8 1/2" drill-collars.The spare kelly cock has 4 1/2" I. F. thread connections. Whatcrossover sub is required for the collars?

ANSWER.......................... 2

9. A fixed rig is set in 300ft of sea water. The marine conductor hasbeen set X ft below the sea-bed. The flow line is 65ft above themean sea-level. The strength of the sub-sea formations is 0.68 psi/ft.Sea-water gradient is 0.445 psi/ft. It is proposed to drill with 9.2 ppgmud. What is the minimum depth that the conductor has to be setbelow sea-bed to prevent losses?

ANSWER............................. 8

10. An over-balance or trip margin is added to the mud. Whentripping this will prevent a loss of B.H.P. due to the swabbing effectof pulling the pipe.

ANSWER. TRUE/FALSE 2

11. Assume casing is set at 4800ft TVD/MD and that gas sands wereencountered at 5000ft and at 8500ft. If the formation pressure gradient at5000ft is 0.47 psi/ft and at 8500ft it is 0.476 psi/ft. What mud weight isrequired to give an over-balance or trip margin of 200 psi?

ANSWER............................ 4



2 - 25


1. (a) Under compacted shales(b) Thick gas sands(c) Faults(d) Diaprism salt domes(e) Shape of reservoir structure

2. Surface pressure = 1100 psi

a. (CSG TVD x MUD WT x .052) + Surface pressure= (4000 x 10.6 x .052) + 1100 = 3305 psi

b. Frac g = Max press ÷ CSG TVD = 3305 ÷ 4000 = 0.826 psi/ft

c. Max Mud Wt = Frac g ÷ .052 = .826 ÷ .052 = 1 5.88ppg

d. MAASP = (Max mud wt - Drlg mud wt) x .052 x CSG TVD= (15.88 - 12.6) x .052 x 4000= 682 psi

3. d.

4. a.

5. a. Mud g x Met Disp—————————CSG Cap - Met Disp

= .655 x .0075 = .0049 = .0751 psi/ft————— ———.0729 – .0075 .0654

.0751 x 940 = 71 psi

b. Mud g x (Met Disp + pipe cap)———————————————

Ann Cap

= .655 (.0075 + .0178) = .3525 psi/ft—————————

.047

470ft x .3525psi/ft = 166 psi

2 - 26



c. Dry pipe vol = Slug vol x (slug wt)————— - 1 (mud wt)

= 14.620 X ———– – 1

12.6

= 3.17 bbls

6. c.

7. (a) Pulling speed.(b) Mud Properties, viscosity - Gel strength.(c) Profile of hole (Wellbore geometry).

8. 4 1/2" if box - 6 5/8" reg pin.

9. (Hyd mud to sea bed) - (Hyd sea water)——————————————————

(Frac g - Mud g)

= (365 x 9.2 x .052) - (300 x .445)—————————————

(.68 - .478)= 41.1

——.202203 ft.

10. False.

11. Mud Wt to give 200 psi overbalance= 5000 x .47 psi/ft = 2350 + 200

= 2550

∴ 2550 ÷ 5000 ÷ .052 = 9.8 ppg

If the 200 psi is to overbalance formation pressure at 8500ftmud wt would be 9.6 ppg. This would overbalance the sands at5000ft by 148 psi.

( )

SECTION 3 : KICK INDICATORS

Page

3. 0 Objectives 1

3. 1 Early Warning Signs 1

3. 2 Increase in Drilling Rate of Penetration -Drilling Break 1

3. 3 Increase Torque and Drag 2

3. 4 Decrease in Shale Density 2

3. 5 Increase in Cutting Size and Shape 3

3. 6 Mud Property Changes 3

3. 7 Increase in Trip, Connection and aBackground Gas 4

3. 8 Change in the Temperature of the ReturnDrilling Mud 5

3. 9 Decrease in D-Exponent 7

3.10 Positive Kick Signs 8

3.11 Hydrocarbon Kick Behaviour 10

3.12 Workshop 3 12



3 - 1

KICK INDICATORS

3.0 OBJECTIVES

The objectives of this section are to review the indication of a kick. Early warningsigns will be covered as well as positive kick signs.

3.1 EARLY WARNING SIGNS

The alertness in determining early warning signs in well control is of the upmostimportance to wellbore safety. Careful observance and positive reaction to thesesigns will keep the well under control and prevent the occurrence of a well flowsituation. The various signs that have been recorded as early warning indicatorsare not consistent in all situations. The signs however may have to be usedcollectively as one indicator may not accurately provide the warning of gettinginto an unbalanced situation. Even though the series of signs may change betweenwells, early warning indications can be found from the following list.

• Increase in drilling rate of penetration.• Increase torque and drag.• Decrease in shale density.• Mud property changes.• Increase in cutting size and shape.• Increase in trip, connection and/or background gas.• Increase in the temperature of the return drilling mud.• Decrease in D-exponent.

3.2 INCREASE IN DRILLING RATE OF PENETRATION - DRILLING BREAK

When drilling ahead and using consistent drilling parameters, as the bit wears, anormal trend of decrease penetration rate should occur. If the differential pressurebetween the hydrostatic pressure of the drilling fluid and formation pore pressuredecreases, an increase in the drilling rate occurs as the chip hold down effect isreduced.

A general and consistent increase in penetration rate is often a fairly goodindicator that a transition zone may have been penetrated. A rapid increase inpenetration rate may indicate that an abnormal pressure formation has beenentered and an underbalance situation has occurred.

3 - 2



3.3 INCREASED TORQUE AND DRAG

Increased drag and rotary torque are often noted Figure 3.1when drilling into overpressured shale formationsdue to the inability of the underbalanced muddensity to hold back physical encroachment of theformation into the wellbore.

Drag and rotating torque are both indirect andqualitative indicators of overpressure. They are alsoindicators of hole instability and other mechanicalproblems.

Torque and drag trend increases often indicate to thedriller that a transition zone is being drilled. Up dragand down drag as well as average torque figuresshould be recorded on each connection. These trendsare valuable when comparing other trend changes.

3.4 DECREASE IN SHALE DENSITY

The density of shale normally increases with depth, but decreases as abnormalpressure zones are drilled. The density of the cuttings can be determined at surfaceand plotted against depth. A normal trend line will be established and deviationscan indicate changes in pore pressure.

∆W––––drag(up)

∆W––––drag

(down)



3 - 3

3.5 INCREASE IN CUTTING SIZE AND SHAPE

In transition zones or in abnormally pressured shales (sandy shales and beddingsand streaks) the shales break off and fall into hole because of under balancedcondition (pore pressure greater than mud hydrostatic pressure). Water wettingmay further aggravate this problem.

Changes in the Shape of Shale Cuttings can occur as an underbalanced situation isdeveloping. The particles are often larger and may be sharp and angular in thetransition zone. Extra fill on bottom may coincide with the trend change. Severesloughing will often cause changes in pressure and stroke relationship.

Normally pressured shales produce small cuttings with rounded edges and aregenerally flat, while cuttings from an over pressured shale are often long andsplintery with angular edges. As reduction of hydrostatic differential between thepore pressure and bottomhole pressure occurs, the hole cuttings will have agreater tendency to come off bottom. This can also lead to shale expansion causingcracking, and sloughing of the shales into the wellbore. Changes in cuttings shapeand cuttings load over the shakers needs to be monitored at surface.

3.6 MUD PROPERTY CHANGES

Water cut mud or a chloride (and sometimes calcium) increase that has beencirculated from bottom always indicates that formation fluid has entered thewellbore. It could be created by swabbing or it could indicate a well flow isunderway. Small chloride or calcium increases could be indicative of tight (non-permeable) zones that have high pressure.

In certain type muds, the viscosity will increase when salt water enters thewellbore and mixed with the mud. This is called flocculation because the littlemolecules of mud solids, which are normally dispersed, form little “groups” calledflocs. These flocs cause viscosity and gel increases.

In other type muds you might see a viscosity decrease caused by water cutting(weight decrease). This is true when operating with low pH salt saturated waterbase muds.

In oil muds, any water contamination would act as a “solid” and cause viscosityincreases.

Gas cut mud would be fluffy and would have higher viscosities (and lower mudweight).

IT IS ESSENTIAL TO KNOW THAT TREND CHANGES ARE MOREIMPORTANT THAN ACTUAL VALUE OF THE CHANGE.

3 - 4



3.7 INCREASE IN TRIP, CONNECTION AND A BACKGROUND GAS

Return mud must be monitored for contamination with formation fluids. This isdone by constantly recording the flowline mud density and accurately monitoringgas levels in the returned mud.

Gas cut mud does not in itself indicate that the well is flowing (gas may beentrained in the cuttings). However, it must be treated as early warning of apossible kick. Therefore pit levels should be closely monitored if significant levelsof gas are detected in the mud.

An essential part of interpreting the level of gas in the mud is the understandingof the conditions in which the gas entered the mud in the first place.

Gas can enter the mud for one or more of the following reasons:

• Drilling a formation that contains gas even with a suitable overbalance.

• Temporary reduction in hydrostatic pressure caused by swabbing as pipe ismoved in the hole.

• Pore pressure in a formation being greater than the hydrostatic pressure ofthe mud column.

Gas due to one or a combination of the above, can be classified as one of thefollowing groups:

Drilled Gas

When porous formations containing gas are drilled, a certain quantity of the gascontained in the cuttings will enter the mud.

Gas that enters the mud, unless in solution with oil base mud and kept at apressure higher than its bubble point, will expand as it is circulated up the hole,causing gas cutting at the flowline. Gas cutting due to this mechanism will occureven if the formation is overbalanced. Raising the mud weight will not prevent it.

It should be noted that drilled gas will only be evident during the time taken tocirculate out the cuttings from the porous formation.



3 - 5

Connection Gas

Connection gases are measured at surface as a distinct increase above backgroundgas as bottoms up occurs after a connection.

Connection gases are caused by the temporary reduction in effective total pressureof the mud column during a connection. This is due to pump shut down and theswabbing action of the pipe.

In all cases, connection gases indicate a condition of near balance. When anincrease trend of connection gases are identified, consideration should be given toweighting up the mud before drilling, operations continue and particularly priorto any tripping operations.

Trip Gas

Trip gas is any gas that enters the mud while tripping the pipe with the holeappearing static. Trip gas will be detected in the mud when circulating bottoms upoccurs after a round trip.

If the static mud column is sufficient to balance the formation pressure, the trip gaswill be caused by swabbing and gas diffusion.

Significant trip gas may indicate that a close to balance situation exists in the hole.

Gas Due to Inadequate Mud Density

Surface indication of an underbalanced formation depend on the degree ofunderbalance, as well as the formation permeability. Drilling of a permeableformation that is significantly overbalanced will cause an immediate flow increasefollowed by a pit gain.

3.8 CHANGE IN THE TEMPERATURE OF THE RETURN DRILLING MUD

The temperature will normally take a sharp increase in transition zones. Thecirculating rate, elapsed time since tripping and mud volume will influenceflowline temperature trends.

The temperature gradient in abnormally pressured formations is generally higherthan normal. The temperature gradient decreases before penetrating the interfaceand, therefore marked differences can give and early indication of abnormalpressures. This is usually a surface measurement which has a tendency to beinfluenced by operating factors. Figure 3.2 shows plots of temperature increasewhile penetrating an abnormal pressure formation.

3 - 6



Figure 3.2 Flowline Temperature Data

FLOWLINE TEMPERATURE = °F

Temperature data from Gulf Coast well

TOP OF ABNORMALPRESSURE ZONE

∆T = 0.53 °F 100'

∆T = 4.33 °F 100'

DE

PT

H 1

000

ft

5

6

7

8

990 100 110 120 130


Temperature data from South Texas well


∆T = 0.23 °F 100'

∆T = 2.08 °F 100'

DE

PT

H 1

000

ft

8

9

10

11

12110 120 130 140 150 160


Temperature data from Pacific Coast well


∆T = 0.39 °F 100'

∆T = 3.38 °F 100'

DE

PT

H 1

000

ft

7

8

9

10

11120 130 140 150 160


Temperature data from South China Sea well


∆T = 0.70 °F 100'

∆T = 10.0 °F 100'

DE

PT

H 1

000

ft

3

4

5

6

7110 120 130 140 150100


Temperature data from North Sea well


∆T = 0.43 °F 100'

∆T = 5.20 °F 100'

DE

PT

H 1

000

ft

3

4

580 90 100 110 12070

1

2



3 - 7

3.9 DECREASE IN D-EXPONENT

The D-Exponent will be plotted by the well loggers and maintained current at alltimes. This value was introduced in the mid sixties to calculate a normalisedpenetration rate in relation to certain drilling parameters.

log (R/60N)d = ––––––––––––––

log (12W/10°D)

Where:

R = rate of penetration, ft/hrN = rotary speed, rpmW = weight on bit, lbsD = bit size, insd = D-exponent

The D-exponent may be corrected and normalised for mud weight changes and/or ECD (equivalent circulating density) by the following:

d x normal pressure (ppg)dc = –––––––––––––––––––––––

mud weight or ECD (ppg)

Figure 3.3

A plot of Dc-Exponent versus depthin shale sections, has been used withmoderate success in predictingabnormal pressure. Trends ofDc-exponent normally increase withdepth, but in transition zones, its valuedecreases to lower than expected values.Mud logging companies have furthervariations/models which try tonormalise for other parameters (such asbit wear and rock strength) to varyingdegrees of success. An illustration of aDc plot is attached as figure 3.3.

NormalTrendLine

1.0 1.5 2.0

17 16 15 14 13 12 11 10 9

13 -

12 -

11 -

10 -

Dep

th (

1000

ft)

SAMPLE PLOT OF Dc EXPONENT vs. DEPTH

3 - 8



3.10 POSITIVE KICK SIGNS

A kick occurs when the hydrostatic pressure of the mud column in the well is lessthan the formation pressure provided that the formation has the ability toproduce. A kick is a positive indicator that formation fluid is entering the wellboreand Secondary Well Control must be initiated.

Recognising a Kick While Drilling

Flow into the wellbore causes two changes to occur in the mud circulating system:

• Increase of active mud system volume.

• The mud return flow rate exceeds the mud flow rate into the well.

Since a rig’s fluid system is a closed system, and increase in returns detected by aflow monitoring system will also be indicated by a gain in pit level. Detecting achange in pit level may be done by visual observation. This means placing sometype of pit level marker in the tank, then posting someone to keep a constantwatch. From your own experience, you know that to keep a constant watch on thepit level is next to impossible. This is especially true during trips, when most kicksoccur. A more accurate and reliable method is to use any of the several pit levelmeasuring instruments with the recorder mounted at the driller’s console andsupported by the mud logger’s monitoring system. This allows a constant watchon the pit level by the driller, both while tripping and drilling. Goodcommunication between crew members is essential on the rig. Drillers shouldmake sure crew hands notify them if they do anything to change the level in thepits. If crew hands are adding volume to the pits, they should also notify thedriller when they stop adding volume.

When drilling a formation containing gas, a minor pit level rise will be notedbecause of the core volume of gas being drilled. However, this will occur only asthe gas nears the surface, and is due to the drilled gas expanding and is notnecessarily an indication that the well is underbalanced. The timing of the increasein pit volume is important in distinguishing between a true kick and gasexpansion only. The hole will also take the same volume of fluid that it gave up,after the gas bubble has reached the surface. However, if there is any question as tothe cause of the pit gain, stop the pump and check the well for flow.

On trips, the drill crew should be able to recognise a 5-barrel kick or less. Duringdrilling, the crews are generally able to recognise a 10 barrel kick or less.

The size or severity of a kick depends on the volume of foreign fluid allowed toenter the wellbore, which depends on the degree of underbalance, the formationpermeability, and the length of time it takes the drilling crew to detect that the wellis kicking.



3 - 9

Recognising a Kick While Tripping

Flow into the wellbore will cause improper hole fill up, if this is seen a flow checkshould be performed.

• If the flow check is positive then the well should be shut in.

• If the flow check is negative the drill string should be run back to bottom tocirculate bottoms up (stripping may have to be used here).

Trip tanks are recognised to be the safest and most reliable method of monitoringmud volumes on trips. It is recommended that a continuous hole fill up be usedwhen tripping out of the hole. When tripping in the hole the, trip tank should beused to ensure the correct mud displacement is taking place.

Rig movement with a floating drilling rig makes it more difficult to recognise kickindicators while drilling or tripping. For this reason additional fluid volumedetection equipment is installed in the mud pits to compensation for rig motion. Itis recommended for floating drilling units that flow checks be performed on thetrip tank with the hole fill pump circulating across the bell nipple to eliminate rigmotion as much as possible.

Situations that can mask a kick:-

• Mud weight adjustments while drilling.

• Mud transfers while drilling.

• Partial lost circulation.

• Solids control equipment and degassing mud.

• Spills and leaks in surface equipment.

• Drain back.

• Pump start up and shut down.

3 - 10



3.11 KICK BEHAVIOUR

A Comparison Between Oil and Water Base Muds

Due to high temperatures and pressure a small gas kick can turn into a seriouswell control problem with oil base muds. Solution gas can become dissolved andmiscible. The reason for this is that the gas remains in solution until it reaches itsbubble point. In the same way that gas in a disposable lighter remains in its liquidphase until the pressure is relieved.

In fig 3.4a three barrels of mud have entered the wellbore at 10,000 ft, but wewould see no pit gain while drilling until the gas has been circulated up to 2600 ft.The gas then expands rapidly and there is a real danger of blowing out sufficientmud to put the entire well underbalance. This problem is easier to detect in waterbased muds because the original volume of the gas will expand much earlier asthe pressure above the gas is reduced (see fig. 3.4b). The problem in OBM's is thatif a kick has entered the wellbore undetected it is impossible to know where thetop of the gas is. For example if the drilling rate is say 80 SPM and the pumpoutput is .117bbls per stroke then in an 8.5" hole section with 5" drillpipe the influxwould travel 203 ft. for each minute that the kick is undetected. In extreme casesthe gas could be 6000 - 7000ft. away from the surface without the driller realisinganything is wrong.

Under these conditions it may be prudent to count all drilling breaks as primaryindicators. Stop drilling, shut off the pumps and close the well in. The gas can thenbe circulated through the choke in a safe manner utilising the first circulation ofthe drillers method. Some procedures advise that the gas should be circulated to2500 ft. below the BOP before the well is shut in and the gas circulated through thechoke. It may be the case that the bubble point is lower and unless thisinformation is known, even though the first procedure may take a little longer,remember safety is always our main concern.



3 - 11

Figure 3.4a - Oil Base Mud Figure 3.4b - Water Base Mud

ASSUME: Three bbls of gas is swabbed into the hole during a connection (undetectable)

Surface Conditions15 psi 70°F

0Surface Conditions15 psi 70°F

0

Solution gas will not migrate or expand untilbubble point pressure is reached.

Bottom Hole Conditions7000 psi 250°F

0 3 bbls Bbls 1,40010,000'

NOTE:The dissolving of gas into oil base mud does not hinder the detection of large volume kicks (5 bbls +), normal kick detection applies. After the well is shut in. Normal kick killing procedures apply.

Gas in WBM will migrate and expand aspressure is reduced.

Bottom Hole Conditions7000 psi 250°F

0 3 bbls Bbls 1,40010,000'

Detectable Pit Gain

5,000'

2,500'

Dep

th

5,000'

2,500'

Dep

th

Bubble Point1000' - 2000'

100% of Total Expansion

12 bblsGas

Volume

6 bblsGas

Volume

3 - 12



WORKSHOP 3

1) GAS cutting of the mud could be prevented by having a mud weightthat gives a large over pressure.

(a) TRUE

(b) FALSE

2) The affect on bottom hole pressure of gas cutting will be greatest:

(a) Initially when the gas enters into the mud.

(b) When the gas cut mud nears the casing shoe.

(c) When it gets near the surface.

3) Given the following data:

Depth 9850 ft TVDShoe 5500 ft TVDMud 11 ppg (Assume this mud gives an overbalance of 150 psi.)

If the top 500 ft of this mud column is cut to 9 ppg and from 500 ft to1300 ft the mud in the cut to 10.5 ppg, from 1300 ft to 1500 ft the mud is 10.8 ppg. If the rest of the system is uncut, what is the reduction in bottom hole pressure.

Answer–––––––––––––––––––––

4) If the gas cutting of the mud is at a constant level but shows significantlybigger peak levels when connections are made, this indicates:

(a) That formation permeability has changed.

(b) That it must be high pressure gas from the formations.

(c) That bottom hole pressure is increasing when the pumps are off.



3 - 13

5) Generally predictions are based on the fact that abnormally pressuredformations are not as “dense” as normally pressured formations at the same depth.Is this statement:

(a) TRUE

(b) FALSE

6) An increase in both the volume and size of cuttings at the shakeris an indication of overpressured formations:

(a) TRUE

(b) FALSE

7) Drilling in a deep high pressure high temperature well with oilbased muds. A small gas kick that goes into solution:(Select two answers)

(a) Will remain in solution until it gets to the surface.

(b) Will come out of solution when it reaches a bubble point pressure.

(c) Would be easier to detect in water based muds.

8) An increase in penetration rate of a drilling break can be caused:

(a) By an increase in formation porosity.

(b) By an increase in permeability.

(c) By an increase in formation pressure.

(d) By a change in one OR all of the above.

9) Connection gas as opposed to background gas can be caused:

(a) Due to a temporary reduction in the overall mud pressureduring a connection.

3 - 14



(b) Due to a temporary increase in the overall mud pressureduring the connection.

(c) By a reduction in the rate of penetration.

WORKSHOP 3 - ANSWERS



3 - 15


1. B

2. C

3. 75 psi Reduction

4. B

5. A

6. A

7. B & C

8. D

9. A

9850

1500

1300

500

500ft x 9ppg x .052 = 234psi

+

800ft x 10.5ppg x .052 = 437psi

200ft x 10.8ppg x .052 = 112psi

8350 x 11ppg x .052 = 4776psi

5559psi

9850 x 11ppg x .052 = 5634 - 5559 = 75psi

+

+

SECTION 4 : SHUT-IN PROCEDURES

Page

4. 0 Objectives 1

4. 1 Introduction to Shut-in Procedureson a Fixed Rig 1

4. 2 Soft Shut-in Procedure While Drillingon a Fixed Rig 2

4. 3 Soft Shut-In Procedure While Trippingon a Fixed Rig 2

4. 4 Hard Shut-In Procedure While Drillingon a Fixed Rig 3

4. 5 Fast Shut-In Procedure While Drilling ona Fixed Rig 4

4. 6 Diverter Procedure While Drilling ona Fixed Rig 4

4. 7 General Introduction for Shut-In Procedureon a Floating Rig 5

4. 8 Soft Shut-In Procedure While Drilling on aFloating Rig 6

4. 9 The Hard Shut-In Procedure on a Floating Rig 7

4.10 The Fast Shut-In Procedure on a Floating Rig 8

4.11 Shallow Gas and Diverting Procedure ona Floating Rig 8

4.12 Surface & Subsea BOP's While Wireline Logging 10

4.13 Extracts from API RP59 11

Workshop 4(a) - Surface 15

Workshop 4(b) - Subsea 19



4 - 1

SHUT-IN PROCEDURES

4.0 OBJECTIVES

To cover the shut-in procedures and diverter procedures for a surface BOP. Tocover A.P.I. recommendations for these procedures which includes advantagesand disadvantages.

To cover the shut-in procedures and diverter procedures for a subsea BOP. Tocover A.P.I. recommendations for these procedures which includes advantagesand disadvantages.

4.1 GENERAL INTRODUCTION TO SHUT-IN PROCEDURESON A FIXED RIG

Note: A fixed rig is defined as a drilling rig equipped with a surface BOP.

Shut-in procedure should be agreed by contractor and operating company andposted on rig floor before drilling the well begins.

When any positive indication of a kick is observed such as a sudden increase inflow or an increase in pit level, then the well should be shut in immediatelywithout doing a flow check. If the increase in flow or pit gain is hard to detectthen a flow check can be done to confirm the well is flowing.

If surface hole is being drilled and the conductor pipe is not set in a competentformation and a shallow gas kick is taken then the gas should be diverted. Thiswill be discussed at the end of this section.

The procedures which follow are generalised suggestions and not necessarilyapplicable to any specific rig.

4 - 2



4.2 SOFT SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG

1. When any indications are observed, while drilling, that the well may beflowing, stop rotating the drill string, raise the drill string with pumps onuntil tool joint is above the drill floor.

2. Stop pumps and check for flow, if positive:

3. Open choke line HCR valve.

4. Close BOP.

5. Close choke. If the choke is not a positive closing choke then close a valvedownstream of choke.

6. Call supervisors and commence plotting a graph of shut in drill pipepressure. Check pit volume gain.

7. Refer to A.P.I. R.P. 59 section 3.8 for the advantages and disadvantagesof the soft shut-in.

Note: Choke in open position while drilling.

4.3 SOFT SHUT-IN PROCEDURE WHILE TRIPPING ON A FIXED RIG

1. If there is an indication of swabbing and the well flows during a flow checkproceed as follows.

2. Set the slips.

3. Install full opening safety valve (Kelly cock).

4. Close safety valve.

5. Open choke line HCR valves.

6. Close BOP.

7. Close choke.

8. Call supervisor and check pressures.

9. Install inside blowout preventer (Gray valve or Non-Return Valve).

10. Open safety valve.



4 - 3

11. Reduce annular preventer pressure and start stripping drill pipe in the hole.

Note: Choke in open position while tripping.

With a swabbed kick there are four options:

1. Strip back in hole.

2. Perform a volumetric bleed.

3. Bullhead kick back into formation.

4. Perform off bottom kill then return to bottomand circulate well to desired mud weight.

4.4 HARD SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG

1. When any indication is observed while drilling that the well maybe flowing,stop rotating the drill string, raise the drill string with pumps on until tooljoint is above the drill floor.


3. Close annular or pipe rams.


5. Call supervisor and commence plotting a graph of shut in drill pipe pressure.Check pit volume gain.

6. Refer to A.P.I. R.P. 59 sections 3:7 for advantages and disadvantages of thehard shut-in.

After the well has been shut in.

In any shut-in procedure it is prudent to line up the annulus to the trip tank abovethe annular or rams. This will assist in double checking to see if they are leaking.Double check that the well is lined up through the choke manifold prior tocirculating kick out.

4 - 4



4.5 FAST SHUT-IN PROCEDURE WHILE DRILLING ON A FIXED RIG

1. When any indication is observed while drilling that the well maybe flowing,stop rotating the drill string, raise the drill string with pumps on until tooljoint is above the drill floor.



4. Close Annular.


Note: There are no A.P.I recommendations for the fast shut-in

4.6 DIVERTER PROCEDURE WHILE DRILLING ON A FIXED RIG

1. Where shallow casing strings or conductor pipe are set, fracture gradientswill be low. It may be impossible to close the BOP on a shallow gas kickwithout breaking down the formation at the shoe. If a shallow gas kick istaken while drilling top hole then the kick should be diverted.

Drilling shallow sand too fast can result in large volumes of gas cut mud inthe annulus and cause the well to flow, also fast drilling can load up theannulus increasing the mud density leading to lost circulation and if the levelin annulus drops far enough then well may flow.

When drilling top hole a diverter should be installed and it is good practiceto leave the diverter installed until 13 3/8" casing has been run. An automaticdiverter system should first:-

a) Open an alternative flow path to overboard lines.

b) Close shaker valve and trip tank valve.

c) Close diverter annular around drill pipe.

d) If there are two overboard lines then the upwind valve should bemanually closed.



4 - 5

2. If any indication of flow is observed while drilling top hole, close diverterimmediately as the gas will reach surface in a very short time and it isinadvisable to attempt a flow check.

3. Suggested diverting procedure in the event of a shallow gas kick.

a) Maintain maximum pump rate and commence pumping kill mud ifavailable.

b) Space out so that the lower safety valve is above the drill floor.

c) With diverter line open close shaker valve and diverter packer.

d) Shut down all nonessential equipment, if there is an indication of gas onrig floor or cellar area then activate deluge systems.

e) On jack-up and platform rigs monitor sea for evidence of gas breakingout around conductor.

f) If mud reserves run out then continue pumping with sea-water.

g) While drilling top hole a float should be run. This will prevent gasentering drill string if a kick is taken while making a connection. It willalso stop backflow through the drill string on connections.

4.7 GENERAL INTRODUCTION FOR SHUT-IN PROCEDURE ONA FLOATING RIG

Note: A floating rig is defined as a rig equipped with subsea BOP’s.

Shut-in procedure should be agreed by contractor and operating company andposted on rig floor before drilling the well begins.

When any positive indication of a kick is observed such as a sudden increase inflow or increase in pit level, then the well should be shut in immediately withoutdoing a flow check. If the increase in flow or pit gain is hard to detect then flowcheck can be done to confirm the well is flowing.

It maybe difficult to obtain an accurate flow check by observing flow line on rigfloor or flow line at shaker due to rig movement.

4 - 6



To obtain an accurate flow check:

a) Stop rotating, pick up and space out for hang off rams.

b) Shut down rig pumps.

c) Line up trip tank.

d) Close shaker valve.

e) Half fill trip tank with mud and perform a flow check.

If surface hole is being drilled and the conductor or surface casing is not set in acompetent formation and a shallow gas kick is taken, then the kick should bediverted and not shut in. Diverting procedure will be discussed at the end of thissection.

The procedure which follow are generalised suggestions and not necessaryapplicable to any specific rig.

4.8 SOFT SHUT-IN PROCEDURE WHILE DRILLING ON A FLOATING RIG

1. When any indication is observed while drilling that the well maybe flowing,stop rotating the drill string, raise drill string with pumps running and spaceout for hang off rams.


3. Open fail-safe valve, open the choke line.

4. With compensator at mid-stroke, close annular.

5. Close choke if the choke is not a positive closing choke then close a valvedownstream of choke.


7. Close hang off rams with reduced pressure, reduce annular pressure, slackoff and land drill string on rams. Increase manifold pressure to 1500 psi andopen annular.



4 - 7

8. Close wedge locks and adjust compensator to support drill string weight toBOP plus 20,000 lbs.

Note: There will be pressure trapped between annular and rams.

9. It has become accepted practice to the lower annular to minimise volume ofgas trapped in BOP. With a stack set up of three sets of pipe rams and one setof shear rams, hang off rams would always be upper or middle pipe ramsbut never lower pipe rams. This is because if a kill or choke line washes outbeneath the lower pipe rams it would be impossible to secure the wall.

10. Refer to A.P.I. R.P 59 section 3:8 for advantages and disadvantages for thesoft shut-in.

Note: Choke in open position while drilling.

4.9 THE HARD SHUT-IN PROCEDURE ON A FLOATING RIG

1. When any indication is observed while drilling that the well maybe flowing,stop rotating the drill string, raise drill string with pumps running and spaceout for hang off rams.


3. With compensator at mid-stroke close annular or pipe rams.

4. Open fail-safe valves on the choke line.


6. If rams have been closed then reduce manifold pressure, slack off on drillstring and land tool joint on rams. Increase manifold pressure to 1500 psi -close wedge locks, adjust compensator to support drill string weight to BOPplus 20,000 lbs.

7. Refer to A.P.I. R.P. 59 section 3:7 for advantages and disadvantages of thehard shut-in.

4 - 8



4.10 THE FAST SHUT-IN PROCEDURE ON A FLOATING RIG

1. When any indication is observed while drilling that the well maybe flowing,stop rotating, raise drill string with pumps running and space out for hangoff rams.

2. Stop pump and check for flow, if positive:

3. Open fail-safe valves on the choke line.

4. With compensator at mid-stroke, close annular.

5. Call supervisors and commence plotting a graph of shut in drill pipepressure, check pit volume gain.

6. Close hang off rams with reduced pressure, reduce annular pressure, slackoff and land drill string on rams. Increase manifold pressure to 1500 psi openannular.

7. Close wedgelocks and adjust compensator to support drill string weight toBOP plus 20,000 lbs.

Note: There will be pressure trapped between annular and rams.

8. There are no A.P.I. recommendations for the fast shut-in.

4.11 SHALLOW GAS AND DIVERTING PROCEDURE ON AFLOATING RIG

1. Shallow gas sand lenses are normally completely enveloped in mud stoneand tend to be highly porous, permeable and relatively unconsolidated.These lenses maybe normally pressured, but if they are lying at an inclinationthey may be overpressured.

2. Shallow gas kicks happen when drilling into a sand lens and are generallycaused by loss of hydrostatic head due to one or a combination of thefollowing.

a) Overloading the annulus with cuttings which may cause losses.

b) Fast drilling leading to drilled gas unloading the annulus.

c) Improper hole fill while tripping if a riser has been run.



4 - 9

3. The following are the recommended procedures for drilling 36" and 24" holefrom a floating rig if there is a risk of shallow gas.

a) Drill a pilot hole prior to drilling 24" hole.

b) Drill with returns to sea-bed.

c) Restrict penetration rate to avoid overloading annulus or having anexcess of drilled gas in annulus.

4. Precautions to take while drilling top hole.

a) If possible have camera on sea-bed observing for any sign of gas.

b) Have a crew member observing surface of sea.

c) A procedure for moving the rig off location must be in place and thisprocedure should be practised prior to spudding the well.

d) A reserve of weighted mud of twice hole volume should be mixed priorto spudding well.

e) A float should always be run in drill string.

5. Suggested action to take if a shallow gas kick occurs while taking returns tosea-bed.

a) Attempt to control the well by pumping sea water or mud.

b) If gas flow is endangering personnel or rig, attempt to drop drill string.

c) Move rig to a safe position up wind of gas plume.

6. Suggested action to take if a riser and connector has been run and a shallowgas kick has been taken.

a) It is not recommended to divert as any solids in the gas influx willquickly erode overboard lines.

b) Drop the drill string.

c) Unlatch the connector with an overpull on riser tensioner lines.

d) Move rig to a safe position outside and upwind of gas plume whileslacking off on guide lines.

4 - 10



4.12 SURFACE & SUBSEA BOP’S WHILE WIRELINE LOGGING

- Direct the wireline loggers to cease operations and close the well on theupper annular.

- Open kill line valves and begin to record shut in pressure and pit gain.

- Pass word to the OIL COMPANY REPRESENTATIVE and SENIORDRILLING CONTRACTOR REPRESENTATIVE of the well condition.

- Decide on kill programme.

Note: If at all possible the wireline should be pulled or stripped out of the hole. Ifthe line needs to be cut and dropped, a surface hydraulic cable cutter shouldbe used. The shear rams should be considered as a last resort and used only ifthe annular(s) fail to secure the well.



4 - 11

4.13 EXTRACTS FROM API RP59

CLOSING IN KICKS

3.6 Soft Close-in Procedure. For a soft close-in, a choke is left open at all timesother than during a well control operation. The choke line valves are aligned suchthat a flow path is open through the choking system, with the exception of onechoke line valve located near the blowout preventer. When the soft close-inprocedure is selected for closing in a well the: 1) choke line valve is opened, 2)blowout preventer is closed, and 3) choke is closed. This procedure allows thechoke to be closed in such a manner to permit sensitive control and monitoring ofcasing pressure buildup during closure. This is especially important if formationfracturing and broaching to the surface is likely to occur if the well is closed inwithout regard to the possibility of excessive initial closed-in casing pressure.

3.7 Hard Close-in Procedure. For a hard close-in, the chokes remain closed at alltimes other than during a well control operation. The choke line valves are alignedsuch that a flow path is open through the choking system with the exception of thechoke(s) itself and one choke line valve located near the blowout preventer stack.When the hard close-in procedure is selected for closing in a well, the blowoutpreventer is closed. If the casing pressure cannot be measured at the wellhead, thechoke line valve is opened with the choke or adjacent high pressure valveremaining closed so that pressure can be measured at the choke manifold. Thisprocedure allows the well to be closed in the shortest possible time, therebyminimising the amount of additional influx of kicking fluid to enter the wellbore.Use of the hard close-in procedure is limited to well conditions in which themaximum allowable casing pressure is greater than the anticipated initial close inpressure and a well fracture would not be expected to broach to the surface oninitial closure.

3.8 Soft Close-in Versus Hard Close-in Procedure. The soft close-in procedureprovides a means of monitoring casing pressure and a more sensitive control ofcasing pressure buildup during closure than will be experienced using the hardclose-in procedure. If the initial closed-in casing pressure is likely to exceed themaximum allowable casing pressure, the soft close-in procedure permits initiationof a low choke pressure procedure or other alternate procedures before maximumallowable casing pressure is reached. In this situation, the soft close-in procedurehas a distinct advantage over the hard close-in procedure. The major disadvantageof the soft close-in procedure is that the additional time involved in opening thechoke line valve and closing the choke will allow additional influx into thewellbore. This procedure will result in a larger kick volume and potentially highercasing pressure than obtained if the hard close-in procedure is used whilecirculating out the kick. The hard close-in procedure is somewhat lesscomplicated, can be performed by one man working on the rig floor, and is morelikely to be performed without inadvertent delays in closure than the soft close-inprocedure.

4 - 12



3.9 Stabilised Pressures. When a kick is detected, the well should be closed in asquickly as possible to minimise kick influx volume. Figure 3.3 shows a schematicdiagram of a well shut in on a kick. In this well, a 20-barrel gas influx occurs whendrilling at 10,000 feet with a 10.0 Ib/gal drilling fluid. The stabilised closed-inpressures are 500 psi on the drill pipe and 640 psi on the casing or annulus gauge.

Figure 3.4 illustrates various pressures in the wellbore. To understand how thevarious pressures interact, it is necessary to isolate and identify each one. The drillpipe gauge pressure plus the hydrostatic pressure of the drilling fluid equals theformation pressure. The same pressure balance can be made for the annulus, i.e.,casing gauge pressure plus the hydrostatic pressure of the annulus drilling fluidplus the hydrostatic pressure of the influx equals the formation pressure.

Figure 3.5 illustrates an example of a10,000 foot closed-in well with 10.0 Ib/gal drilling fluid and a small volume ofgas at bottom. When the gas rises to5000 feet without expansion ortemperature change, the bottom-holepressure rises to 7800 psi, which isequivalent to a 15.0 Ib/gal drillingfluid column. When the gas reachesthe surface, bottom-hole pressure is10,400 psi, which is equivalentto a 20.0 Ib/gal drilling fluidcolumn. At 5000 feet the boreholepressure is equivalent to a30.0 Ib/gal drilling fluidcolumn to that depth. Suchexcessive pressure should be avoided whether gas risesthrough a static drilling fluid column or is circulated out by allowing the gas to expand asit rises. This also requires thatthe pits be allowed to gainvolume. If a gas bubble ispermitted to rise in a wellborewithout expanding, the gaspressure will remain constant.The reduced hydrostatic headabove the gas column mustbe overcome by increasedsurface pressure on the casing:in turn this increased pressureresults in a higher bottom-holepressure.

500 PSI

640 PSIDRILL

PIPE

CASING

10 LB/GALDRILLING FLUID

10 LB/GALDRILLING FLUID

20 BBL GAS ENTRY

10,000 FT

BOTTOM-HOLE PRESSURE = 5700 PSI

FORMATION PRESSURE = 5700 PSI

WELL CLOSED IN ON A KICK



4 - 13

FIG 3.6CLOSED-IN DRILL PIPE PRESSURE

DESIRED VALUE

INCREASE DUE TO RISE OF GAS

TIME

DRILL PIPEPRESSURE PSI

FIG 3.4WELL CLOSED IN ON A KICK

5700 PSI

500 PSI

DRILL PIPE

5200 PSI

5700 PSI

ANNULUS

80 PSI

5700 PSI

640 PSI

4980 PSI

DRILLING FLUIDCOLUMN PRESSURE

DRILLING FLUIDCOLUMN PRESSURE

GASHYDROSTATICPRESSURE

FORMATIONPRESSURE

FIG 3.5CLOSED-IN WELLBORE PRESSURE

WITH TIME

DRILLINGFLUID

5200 PSS

GAS5200PSS

GAS5200PSS

GAS5200PSS

5200 PSI2600 PSI0 PSI

DRILLINGFLUID

5200 PSS

SURFACEPRESSURE

10000 FT

0 FT

5000 FT

FINALINITIAL

BOTTOM-HOLE PRESSURE = 5200 PSI = 7800 PSI =10400 PSI

EQUIVALENT DRILLING FLUID DENSITY = 10.0 LB/GAL = 15.0 LB/GAL = 20.0 LB/GAL

3.10 Closed-in Drill Pipe Pressure. Formation pressure near the wellbore isreduced during flow. When the well is closed in, the borehole pressure will riseuntil equal to formation pressure. As the drill pipe (and annulus) is incommunication, the drill pipe pressure will also rise and stabilize. The drill pipepressure at this time indicates the amount to increase the drilling fluid density. Ifthe well is not circulated, the gas will slowly rise and increase both wellbore anddrill pipe pressures. Drill pipe pressures read after the initial stabilized readingwill indicate excessive drilling fluid density increase. To avoid excess wellborepressures, the choke should be used to bleed drilling fluid from the casing andmaintain the initial shut-in drill pipe pressure. These conditions are illustrated inFigure 3.6. To determine the closed-in drill pipe pressure when a back-pressurevalve is in the drill string, pressure should be increased slowly using the smallestpump available to determine the pressure at which the back-pressure valve opens.If casing pressure is seen to rise while pumping on the drill pipe, pumping shouldbe stopped and the increase in casing pressure subtracted from drill pipe pressure.

4 - 14



FORMATION INTEGRITY TESTS

3.11 Leak-off Test. A leak-off test is made to determine the pressure at which aformation will begin to fracture. Leak-off tests are usually run after drilling a shortdistance below the surface casing shoe. These tests may also be made on othercasing strings. A leak-off test is performed by pumping drilling fluid into thewellbore at a slow rate (typically one-half barrel per minute), with blowoutpreventers closed and carefully plotting the resulting pressure versus the totalvolume pumped. The pressure at which the plotted curve begins to flatten. i.e.,when the pressure increases a smaller amount for a volume pumped, is the surfaceleak-off pressure. The pump should be stopped immediately. This pressure plusthe hydrostatic pressure of the drilling fluid is the formation fracture pressure.

Formation fracture pressure (psi) =

Leak-off pressure (psi) + [.052 x Drilling fluid density (Ib/gal)] x Casing TVD (ft).

It is useful to calculate the formation fracture gradient as equivalent or fracturedrilling fluid density.

Fracture drilling fluid density (Ib/gal) =

Leak-off pressure Drilling fluid density in––––––––––––––––––– + use during test (Ib/gal). .052 x Casing TVD (ft)

Fracture pressure is the maximum surface pressure that can be applied to a casingthat is full of drilling fluid without fracturing the formation. Fracture pressure iscalculated as follows:

Fracture pressure (psi) =

.052 x Casing TVD (ft) x [Fracture drilling fluid density (Ib/gal) - Present drilling fluid density (lb/gal)].

3.12 Formation Competency Test. A formation competency test is made todetermine if a wellbore will support drilling fluid of a higher density which maybe required at some future time during the well drilling and completionoperations. The formation competency test is performed by pumping drilling fluidinto the wellbore at a slow rate (typically one-half barrel per minute) with blowoutpreventers closed. Pumping into the wellbore should be continued until reachingthe predetermined test pressure as calculated below:

Test pressure (psi) =

.052 x Casing TVD (ft) x [Required test drilling fluid density b/gal) - drilling fluid density currently in use (Ib/gal)].



4 - 15

4.14 - WORKSHOP 4(a) - Surface

DRILLSPOOL

ANNULARPREVENTER

CASINGHEAD

SHEAR RAM

HCRVALVE

HCRVALVE

5" PIPE RAM

5" PIPE RAM

4321

65

P

P

CHOKE LINE

15

8

7

9

1211

10

13

14

Remotely operated choke - left hand

To mud/gas separators,pits and diverter lines

To pit

Bleed line

To mud/gas separators,pits and diverter lines

Remotely operated choke - right hand

Note: The well will be killed using the left hand automatic choke.

ManualAdjustable Choke

P = Positive Closing Choke

Questions 1-4 refer to the diagram above. The valves shown are numbered 1 to 15.

1. If all of the above valves were closed, indicate below those valvesthat should be in the open position if the Manifold is lined up tosuit a Soft Shut-in (excluding choke).

Answer:

2 . Referring to the above question indicate the position of the chokes,when lined up for a Soft Shut-in .

a. Left hand remote choke Opened Closedb. Manual adjustable choke Opened Closedc. Right hand remote choke Opened Closed

4 - 16



3. Indicate the position of the chokes, when lined up for a Fast Shut-in .


4. Indicate the position of the chokes, when lined up for a Hard Shut-in .


If an indication of a Kick while Drilling occurs, or if the Well flows whileTripping, then the well must be closed-In. (A Kelly is being used)The following is a list of possible Actions that could or could not be takenwhen shutting the well in.

1. Pick up and space out2. Stop Rotating3. Set Slips4. Open HCR valve5. Close HCR valve6. Install Safety Valve(FOSV)7. Open Safety Valve8. Close Safety Valve9. Open Ram Preventer10. Close Ram Preventer11. Open Annular Preventer12. Close Annular Preventer13. Stop pumping14. Install Inside B.O.P (Grey Valve)15. Open Choke16. Close Choke17. Record Data

For questions 5 to 8 refer to the list shown above.

5. Select the correct sequence of actions which should be taken if awell kicks while drilling and the Soft Shut-in is to be used.

Answer:

6. Select the correct sequence of actions which should be taken if a



4 - 17

well kicks while drilling and the Fast shut-in is to be used.

Answer:

7. Select the correct sequence of actions which should be taken if awell kicks while drilling and the Hard shut-in is to be used.

Answer:

8. If a well flow while Tripping, select the correct sequence of actionswhich should be taken if the Fast shut-in is to be used.

Answer:

9. Secondary well control could be defined as initially;

a. Controlling formation fluids with the pressure of the mudcolumn, in a static or dynamic condition.

b. Controlling formation fluids with the pressure of the mudcolumn and the well closed in.

10. Prior to Stripping back to bottom, and assuming there is no floatvalve in the string, the equipment made up on top of the stringwould generally be;

a. A Safety valve (Kelly cock) in the closed position.b. An Inside Blow-Out Preventer (Grey valve).c. An I.B.O.P valve on top of a opened Safety Valve.d. A Safety valve closed with an IBOP valve below it.e. A closed Regan "Fast Shut-off valve".f. An I.B.O.P. valve on top of an opened Regan "Fast

Shut-off valve".

11. If a well starts to Flow due to Gas at shallow levels, the safestaction would be: (Select three answers)

a. Shut the Well in as fast as possible, use a ram preventer.b. Shut the diverter and then open the vent line and close the flow line.c. Open the vent line, close the flow line and then close the diverter.d. Have all nonessential personnel removed from the rig.e. Pump into the well at the fastest rate.f. Line up the returns to go through the Poor-Boy Degasser.

4 - 18



WORKSHOP 4(a) - Answers

1. The valves which should be in the open position:numbers: 2, 3, 7, 8 and 15. ref ch 6-43

2. Left hand remote choke- openedManual Adjustable choke- closedRight hand remote choke- closed

3. Left hand remote choke- closedManual Adjustable choke- closedRight hand remote choke- closed

4. As Q 3. All chokes Closed

5. 2, 1, 13, 4, 12, 16 and 17. ref. ch 4-2

6. 2, 1, 13, 4, 12 and 17 ref. ch 4-5

7. 2, 1, 13, 10 or 12, 4 and 17 ref. ch 4-3

8. 1, 3, 6, 8, 4, 12, 14, 7 and 17 ref. ch 5-29

9. b. ref. ch 1-1

10. c. ref. ch 5-29

11. c. d. and e. ref. ch 4-4



4 - 19

WORKSHOP 4(b) - Subsea

REMOTELY ACTUATED VALVES

NOTE: Right hand auto-choke will be used during well killing operations. The upper pipe rams will be used during well kill operations.

Vent to top of derrick

10” Vent

36” diameter separator

To shale shaker

Mud-gas separator

From C&K manifold 4” pipe

To port - Blow-down lineflare line

Blow-down lineTo starboard flare line

to mud-gas separator

L/handremotechoke

R/handremotechoke

Manualchoke

To cementunit mud pumps

To shaleshaker

Kill line

ChokelineDECK LEVEL

SEA LEVEL

SEA FLOORH-4

Connector

5” Rams

VariableRams

5” Rams

ShearRams

Annular Preventer

H-4Connector

Flex joint

Annular Preventer

Kill line

Chokeline

F1 F2

F3 F4

F5 F6

F7 F8

1

2

3

4

5

6

7

8

9

10

11

1215

16

18

17

14

13

19

20

21

22

23

24

25

30

29

3126

27

28

Questions 1-4 refer to the stack and manifold diagram. The valves shown in thediagram are on the choke and kill line at the stack numbered F1 to F8.The valves on the manifold are numbered 1 to 31.

4 - 20



1. If all of the above valves were closed, indicate below those valvesthat should be in the open position if the Manifold is lined up tosuit a Soft Shut-in while drilling.

Answer:

2 . Referring to the above question indicate the position of the chokes,when lined up for a Soft Shut-in .


3. Indicate the position of the chokes, when lined up for a Fast Shut-in .


4. Indicate the position of the chokes, when lined up for a Hard Shut-in .


If an indication of a Kick while Drilling occurs, or if the Well flows whileTripping, then the well must be closed-In. (A Kelly is being used)The following is a list of possible Actions that could or could not be takenwhen shutting the well in.

1. Pick up and space out2. Stop Rotating3. Set Slips4. Open Fail-safe valves5. Close Fail-safe valves6. Close Ram preventer7. Open Ram preventer8. Close Upper Annular9. Close Lower Annular10. Open Annular11. Open Choke12. Close Choke13. Stop pumping14. Set compensator to mid stroke15. Hang Off16. Record Data



4 - 21

For questions 5 to 7 refer to the list shown above.

5. Select the correct sequence of actions which should be taken if awell kicks while drilling and the Soft Shut-in is to be used.

Answer:

6. Select the correct sequence of actions which should be taken if awell kicks while drilling and the Fast shut-in is to be used.

Answer:

7. Select the correct sequence of actions which should be taken if awell kicks while drilling and the Hard shut-in is to be used.

Answer:

8. Having information about tides and rig heave on a floating rigis important for many reasons, particularly if a well has to be shut in.From the following select the most important reason for this.

a. To know the exact measured depth from the bit to the rig floor.b. To know where the tool joints are in relation to the ram that

will be used.c. To be able to make necessary adjustments to the riser tensionersd. To reduce the risk of collapsing the riser.

9. Some sensible precautions that could be taken while drilling top ifthere is any risk of shallow gas would be: (There is more than 1 answer)

a. Monitor sea bed returns and observe surface of sea.b. Drill pilot holec. Restrict penetration rated. Close the well in at the first sign of flowe. All of the above.

10. Drilling for the 20 inch casing is generally done without a riser.this is because:

a. It is much easier to detect any flow or pit changes.b. It is easier to control bottom hole pressurec. It is easier to move the rig off location in an emergencyd. It is easier to close the well in.

4 - 22



WORKSHOP 4(b) - Answers

1. The valves which should be in the open position:numbers: 8, 9, 10, 11, 12, 25, 26, 27 and 30

2. Left hand remote choke- closedManual Adjustable choke- closedRight hand remote choke- opened

3. Left hand remote choke- closedManual Adjustable choke- closedRight hand remote choke- closed

4. As Q 3. All chokes Closed

5. 2, 1, 13, 4, 8, 12, 6, 15, 14, 10 and 16

6. 2, 1, 13, 4, 8, 6, 15, 14, 10 and 16

7. 2, 1, 13, 8, 4, 6, 15, 14, 10 and 16

8. b.

9. a, b and c

10. c.

SECTION 5 : METHODS OF WELL CONTROL

Page

5. 0 Objectives 1

5. 1 Kill Methods General 1

5. 2 Constant Bottom Hole Pressure Kill Methods 4

5. 3 The Driller's Method 5

5. 4 The Wait and Weight Method 13

5. 5 Volumetric Well Control 17

5. 6 Volumetric Stripping 23

5. 7 Edited Extract From API RP53 28

5. 8 Removal of Gas Trapped in BOP's 30

5. 9 Kick Detection and Well Control Problemson Deviated and Horizontal Wells 34

5.10 Kick Tolerance 42

5.11 Workshop 5 49



5 - 1

METHODS OF WELL CONTROL

5.0 OBJECTIVES

To cover the methods of well control for fixed rigs, to cover the specialconsiderations for subsea rigs and to look at step down graphs for deviated andhorizontal wells.

5.1 KILL METHODS GENERAL

The objective of the various kill methods is to circulate out any invading fluid andcirculate a satisfactory weight of kill mud into the well without allowing furtherfluid into the hole. Ideally this should be done with the minimum of damage tothe well.

If this can be done, then once the kill mud has been fully circulated around thewell, it is possible to open up the well and restart normal operations. Generally, akill mud which just provides hydrostatic balance for formation pressure iscirculated.

This allows approximately constant bottom hole pressure which is slightly greaterthan formation pressure to be maintained as the kill circulation proceeds becauseof the additional small circulating friction pressure loss.

After circulation, the well is opened up again and the mud weight may be furtherincreased to provide a safety or trip margin.

5 - 2



BALANCE OF PRESSURES

Once the well is shut-in providing nothing has broken down, the pressures in thewell will be in balance. What is lacking in hydrostatic head of fluid in the well isnow being made up by surface applied pressure on the annulus and on the drillpipe.

Providing the bit is on bottom and the string is full with a known mud density thisallows us to determine what the formation pressure is and hence what kill mudweight is required to achieve balance.

On the drill pipe side of the U-tube. (Figure 5.1):

Formation Pressure = [Hydrostatic Pressure of Mud in Drill pipe] + [Shut-in Drill Pipe Pressure SIDPP]

On the casing side of the U-tube:

Formation = Hydrostatic Pressure + Hydrostatic Pressure + Shut-in CasingPressure of Mud in Annulus of Influx Pressure

The mixture of mud and formation fluid in the annulus makes it impossible todetermine formation pressure using the casing information. The drill pipe,however, is full of clean mud of known weight and can be used as a “barometer’of what is happening downhole.

PF = Head of Mud In Drill pipe + SIDPP

We require the mud to produce a hydrostatic pressure equal to the formationpressure over a length equal to the true vertical depth of the hole. This can beexpressed as a gradient, and converted to any desired mud weight unit; in thiscase ppg.

The kill mud weight required could also be described as the original mud weightincreased by an amount which will provide a hydrostatic pressure equal to theamount of the drill pipe shut-in pressure over the vertical length of the hole.

Kill Mud Original Mud SIDPP (psi)Weight (ppg) = Weight (ppg) + –––––––––––––––––– ÷ 0.052

True Vertical Depth (ft)

Once the formation pressure is known, the mud weight required to balance, or‘kill’, it can be calculated, since:-

Formation Pressure (psi)Kill Mud Weight (ppg) = ––––––––––––––––––– ÷ 0.052

True Vertical Depth (ft)

[ ]



5 - 3

Drill Pipe: SIDPP + Hydrostatic Pressure of Mud = Formation Pressure

Annulus: SICP + Hydrostatic Pressure of Mud + Hydrostatic Pressure of Influx = Formation Pressure

800 psi 1220 psi

8613 psi

67 psi9100 psi

9900 psi9900 psi

9900 psi 9900 psi

9900 psi

FORMATION PRESSURE

DRILL PIPEPRESSURE

CASINGPRESSURE

MUD HYDROSTATICPRESSURE IN THEANNULUS

TOTAL PRESSUREACTING DOWN(8613 + 1220 + 67 =9900 psi)

MUD HYDROSTATICPRESSURE IN THEDRILL PIPE

TOTAL PRESSUREACTING DOWN(9100 + 800 = 9900 psi)

DRILL PIPE ANNULUS

Figure 5.1

5 - 4



5.2 CONSTANT BOTTOM HOLE PRESSURE KILL METHODS

There are three ‘constant bottom-hole pressure’ kill methods in common use todaywhich are:

• Driller’s Method

• Wait & Weight Method (also known as the ‘Engineer’s Method’)

• Concurrent Method

These three techniques are very similar in principle, and differ only in respect ofwhen kill mud is pumped down.

In the Driller’s Method, the kill is split into two circulations. During the first, thekick fluid is circulated without changing the mud weight; once the kick is out, themud is weighted up and pumped around the well on the second circulation.

The Wait & Weight method achieves both of these operations simultaneously. Killmud is prepared before starting the kill, and the kick fluid is circulated out whilethis mud is circulated into the well.

In the Concurrent method, a compromise is adopted between these two methods.The kick fluid is circulated out while the mud being circulated in, is weighted upin stages, towards the kill weight.



5 - 5

5.3 THE DRILLER'S METHOD

In the Driller’s Method, the kick is circulated out of the hole using the existingmud weight. The mud weight is then raised to the required level and circulatedaround the well.

Two complete circulations are thus required, as a minimum, for this method. Sinceit deals separately with the removal of the kick and the addition of kill weightmud, it is generally considered to be the simplest of well control methods, and itrequires least arithmetic. However, this results, in the well being circulated underpressure for a relatively long time, possibly the longest of the three methods, withan increased possibility of choke problems. Also, the annular pressures producedduring the first circulation are higher than produced with any other method.

CAUTION: because very high annular pressure may arise when killing a gas kickwith this method, care should be taken. Annular pressure will be at amaximum immediately before gas arrives at surface, and casing burstpressure limitations may be critical.

This method is most used on small land rigs where the Driller may have little helpand limited equipment. It is also used on highly deviated and horizontal wells,where the influx is likely to be a swabbed kick.

In addition the simplicity of the Driller’s Method makes it useful when onlylimited information is available about the well conditions.

To summarise:

FIRST CIRCULATION: Pump the kick out of the well, using existing mud weight.

SECOND CIRCULATION: Pump kill weight mud around the well.

Advantages of Driller’s Method:

• Minimum Arithmetic• Minimum Waiting Around Time - can start kill at once• Minimum Information Required

Disadvantages of Driller’s Method:

• Highest Annular Pressure Produced• Maximum Well Under Pressure Time• Longest ‘On-choke’ Time

5 - 6



Procedure for Driller’s Method (See Figure 5.2)

1. The well is closed in and the information recorded.

FIRST CIRCULATION

2. If a slow circulating rate pressure, PSCR, has been taken, then calculate thepressure required on the drill pipe for the first circulation of the well.

This is: Initial Circulation = Slow Circulation Rate + Shut-in Drill pipePressure Pressure Pressure

or: ICP = PSCR + SIDPP

3. Open the choke about one quarter, start the pump and break circulation; thenbring the pump up to the KILL RATE.

4. While the Driller is bringing the pump up to the KILL RATE, the chokeoperator should operate the choke so as to keep the casing pressure at or nearthe closed in casing pressure reading.

5. Once the pump is up to the KILL RATE, the choke operator should transferhis attention to the drill pipe pressure gauge and adjust the choke tomaintain the INITIAL CIRCULATING PRESSURE on the drill pipe pressuregauge.

6. The INITIAL CIRCULATING PRESSURE is held constant on the drill pipepressure gauge by adjusting the choke throughout the whole of the firstcirculation, until all of the kick fluid has been circulated out of the well. Thepump rate must also be held constant at the KILL RATE throughout thisperiod.

7. Once the kick is out of the hole, shut the well in and mix up the kill mudweight required.

SIDPPKill Weight Mud (ppg) = Original Mud Weight + ( –––––––––––––––)

T.V.D. x 0.052

NOTE 1: This is a kill weight mud to balance formation pressure. It is the lowestpossible mud weight which will ‘kill’ the well. Once the well is dead, itwill be necessary to increase the mud weight further to provide a tripmargin.

NOTE 2: Some operators prefer to continue circulating the well while kill weightmud is being mixed. There is no theoretical reason why this should not bedone, though it does result in further wear and tear on equipment underpressure - in particular the choke.



5 - 7

Figure 5.2

EB

F.C

.P.

INIT

IAL

CIR

CU

LA

TIN

GP

RE

SS

UR

E

CA

SIN

GP

RE

SS

UR

ER

ISIN

G

CA

SIN

GP

RE

SS

UR

EB

EIN

GR

ED

UC

ED

DR

ILL

ER

’SM

ET

HO

D

CIR

CU

LA

TIN

GK

ICK

OU

T

DR

ILL

ER

’SM

ET

HO

D

KIL

L M

UD

CO

MIN

G U

PA

NN

UL

US

Exp

andi

ng g

as is

pus

hing

mor

em

ud o

ut o

f ann

ulus

, so

Cas

ing

Pre

ssur

e ris

ing

to c

ompe

nsat

e an

dK

EE

P C

ON

STA

NT

BO

TT

OM

HO

LE P

RE

SS

UR

E

Ch

oke

be

ing

ste

ad

ilyo

pe

ne

d t

o k

ee

p F

.C.P

. o

nd

rill p

ipe

, h

enc

e C

asi

ng

Pre

ssu

re r

ed

uci

ng

GA

SE

XP

AN

DIN

G

A D

SID

PP

SIC

P

CA

SIN

GP

RE

SS

UR

ES

TE

AD

Y

DR

ILL

PIP

EP

RE

SS

UR

ED

RO

PP

ING

DR

ILL

ER

’SM

ET

HO

D

KIC

K S

HU

T IN

Gas

Kic

k

Bef

ore

star

tof

firs

tci

rcul

atio

n

DR

ILL

ER

’SM

ET

HO

D

CIR

CU

LA

TIN

GK

ILL

MU

D IN

Dri

ll p

ipe

pre

ssu

red

rop

pin

g (

fro

m I

.C.P

to F

.C.P

. a

s K

ill M

ud

go

es

to b

it )

FCS

IDP

P

0 p

si0

psi

CA

SIN

GP

RE

SS

UR

E=

SID

PP

DR

ILL

ER

’SM

ET

HO

D

FIR

ST

CIR

CU

LA

TIO

NC

OM

PL

ET

E

WE

LL

KIL

LE

D

Sh

ut

in -

kill

mu

d a

ll ro

un

dw

ell

Wel

l clo

sed

in

Orig

inal

wei

ght m

ud a

llar

ound

wel

l

Wel

l cle

an u

p m

ay ta

keso

me

time

- sm

all

resi

dual

pre

ssur

e on

the

casi

ng is

thus

like

ly

GA

S

KIL

LW

EIG

HT

MU

D

KIL

LM

UD

OR

IGIN

AL

WE

IGH

TM

UD

5 - 8



SECOND CIRCULATION

8. Once the kill mud is ready, open the choke about one quarter, start the pumpand break circulation. Then bring the pump up to the kill rate.

9. While the Driller is bringing the pump up to the kill rate, the choke operatorshould operate the choke so as to keep the casing pressure steady at the samepressure as when closed in.

10. While the drill pipe is being filled with heavy mud there are two options forkeeping B.H.P. constant, either keep the casing pressure constant or make outa graph going from I.C.P. to F.C.P.

NOTE: If the influx was gas and all the gas was not removed in first circulation,the first option of keeping casing pressure constant could lead to higherannular pressures.

The drill pipe pressure will go down as the drill pipe is being slugged with theheavier mud. In practice, if all the kick was properly removed in the firstcirculation, the choke should not need to be touched once the pumps are steady atthe Kill Rate, until kill mud reaches the bit.

Once the kill mud reaches the bit, the pressure held on the drill pipe is just thatrequired to circulate the kill mud around the well. This is the slow circulating ratepressure, increased slightly for the extra mud weight.

Final Circulating = Slow Circulating x Kill Mud Weight . Pressure Rate Pressure Original Mud Weight

The drill pipe pressure starts dropping below the initial circulating pressure, as thekill mud starts down the drill pipe, reaching the final circulating pressure whenthe kill mud reaches the bit. Thereafter the drill pipe pressure is held at the finalcirculating pressure by controlled opening of the choke, as the kill mud moves upthe annulus.

A graph showing how drill pipe pressure drops from the initial to the finalcirculating pressure is shown in Figure 3 and this can be used as a guide to thedrill pipe pressures required. The drill pipe pressure should drop according to thegraph, as kill mud goes to the bit, without the choke being moved.



5 - 9

Figure 5.3

Because of the possibility that the annulus may not be circulated completely clean,during the first circulation, it may be preferable to work out how the drill pipepressure should vary as kill mud is pumped around the well. This will allow thedrill pipe pressure to be used throughout, so eliminating the possibility of smallgas bubbles in the annulus producing misleading information.

The following graphs depict the variations in pressure during the well circulation.

DRILL PIPE PRESSURE

Graph of Drill Pipe Pressure as Kill Mud is Pumped

PUMP STROKES

ICP

KILL MUD AT BIT

0

FCP

5 - 10



Figure 5.4

FIRST CIRCULATION

Profile of Circulating and Annular PressureWhile Killing by Driller's Method

Water Influx

START FINISH

Gas Influx

Annular Pressure

Time or Pump Strokes

Annular Pressure

Pressure Constant

START FINISHCirculating Pressure

Drill Pipe Closed in Pressure

Circulating Pressure at

Reduced Rate




5 - 11

Figure 5.5

Surface to Bit

START FINISH

Constant

Pressure Constant

START FINISH

Circulating Pressure with Kill Mud

Well Dead in Drill Pipe

Surface to Bit

SECOND CIRCULATION

Profile of Circulating and Annular PressureWhile Killing by Driller's Method

START

Annular Pressure


Annular Pressure

Circulating Pressure



Reduced Rate


5 - 12



Determination of Initial Circulating Pressure

If no slow circulating rate pressure has been taken, then the initial circulatingpressure can be determined using the start-up procedures described in thecirculations of the Driller’s Method.

Where the casing pressure has been held constant while the pumps are brought upto a kill rate, the drill pipe pressure reading will be the initial circulating pressure.

WARNING: the existence of a predetermined kill rate gives rig personnel a wrongimpression that a kick must be circulated exclusively at this rate.

The procedure consists of:

1. Noting casing pressure reading.

2. Adjusting pumps to new kill rate. Adjusting choke to hold casing pressureconstant at the value noted.

3. As soon as the driller has the pumps settled on the new rate, return to thedrill pipe pressure gauge. Note this new reading is the circulating pressure for thenew pump rate and maintain this.

4. Check choke orifice size, in relation to kill rate

NOTE: This procedure is satisfactory at any time during a kill providing the mudweight in the drill string is not changing during the process. It is howeverpreferable to maintain pump rate constant as much as possible. Anydecision to change pump rate should be taken early.



5 - 13

5.4 THE WAIT AND WEIGHT METHOD

The “Wait and Weight” is sometimes referred to as the ‘Engineers Method’ or the‘One Circulation Method’. It does, at least in theory, kill the well in one circulation.

Once the well is shut in and pressures stabilised, the shut in drill pipe pressure isused to calculate the kill mud weight. Mud of the required weight is made up inthe mud pits. When ready, kill mud is pumped down the drill pipe. Atcommencement, enough drill pipe pressure must be held to circulate the mud,plus a reserve equivalent to the original shut in drill pipe pressure. This totalsteadily decreases as the mud goes down to the bit, until with kill mud at the bit,the required pressure is simply that needed to pump kill mud around the well.

The choke is adjusted to reduce drill pipe pressure while kill mud is pumpeddown the string. With kill mud at the bit, the static head of mud in the drill pipebalances formation pressure. For the remainder of the circulation, as the influx ispumped to the surface, followed by drill pipe contents and the kill mud, the drillpipe pressure is held at the final circulating pressure by choke adjustment.

Advantages of the Wait and Weight Method

• Lowest wellbore pressures, and lowest surface pressures - this means lessequipment stress.

• Minimum ‘on-choke’ circulating time - less chance of washing out the choke.

Disadvantages of the Wait and Weight Method

• Considerable waiting time (while weighting up) - gas migration.

• If large increases in mud weight required, this is difficult to do uniformly inone stage.

Procedure for the Wait and Weight Method

The Wait and Weight method uses the same calculations already described for adrill pipe pressure schedule. The calculations are:

Kill Mud Weight = Original Mud Weight + _______(SIDPP)_______(PPG) (PPG) True Vertical Depth x.052

5 - 14



At the start of the circulation, with kill mud:

Initial Circulating Slow Circulating Rate Shut in Drill pipePressure = Pressure + Pressure (ICP) (SCRP) (SIDPP)

Once the capacity of the drill string is calculated, it is possible to draw a graphshowing how drill pipe pressure varies as kill mud is pumped down to the bit.(See Figure 5.6)

Once kill mud is ready, the start-up procedure is as previously described.

The choke is cracked open, the pump started to break circulation, and then broughtup slowly to the Kill Rate.

While the Driller brings the pump up to the Kill Rate, the choke operator works thechoke so as to keep the casing pressure at or as near as possible to the closed incasing pressure reading.

When the pump is up to the Kill Rate, the choke operator transfers to the drill pipepressure gauge.

As the kill mud proceeds down the drill pipe, the drill pipe pressure is allowed todrop steadily from the Initial Circulating Pressure to the Final Circulating Pressure,by choke adjustment.

Where the kick is a small one, at or near the bottom of the hole, the drill pipepressure tends to drop of its own accord as the kill mud moves down. Little or nochoke adjustment is required.

Only in cases of diffused gas kicks with gas far up the annulus will significantchoke adjustments be needed during this period.

After kill mud has reached the bit, the drill pipe pressure is maintained at the FinalCirculating Pressure, until the kill mud returns to surface.

As with the Driller’s method, this Final Circulating pressure is held constant aslong as pump rate is held constant at the selected value. If, for any reason, thepump rate is felt to be wrong, it can be changed using the same proceduredescribed previously. However, pump rate changes should be avoided, wherepossible.

While the pump rate is adjusted, the casing pressure is held steady by adjustingthe choke. Once the pump is stabilised at its new speed, the revised circulatingpressure is read from the drill pipe gauge. If a gas influx is very near to the surface,adjusting pump rate by holding a steady casing pressure may significantly increasethe bottom hole pressure. This is due to the rapid expansion of gas near thesurface. Alterations in pump rate are to be made early on!

The following two graphs depict pressure variations during the Wait and Weightmethod.



5 - 15

Figure 5.6

START

Surface to Bit

Pressure Constant

START FINISH

Circulating Pressure with Kill Mud

Well Dead in Drill Pipe

Surface to Bit

Profile of Circulating and Annular PressureKilling by Wait and Weight Method

Annular Pressure


Annular Pressure

Circulating Pressure



Reduced Rate


FINISH

PH1 PH2 PH3 PH4

5 - 16



Figure 5.7

A D

SIC

P

CA

SIN

GP

RE

SS

UR

EA

TM

AX

IMU

M

WA

IT &

WE

IGH

T

STA

RT

OF

KIC

K

Gas

Kic

k

Just

sta

rtin

g ki

ll m

uddo

wn

drill

pip

e

WA

IT &

WE

IGH

T

GA

S A

TS

UR

FAC

E

Cas

ing

Pre

ssur

eat

its

max

imum

valu

e

I.C.P

.D

RIL

LP

IPE

PR

ES

SU

RE

DR

OP

PIN

G

EB

F.C

.P.

CA

SIN

GP

RE

SS

UR

EV.

SL

OW

LYR

ISIN

G

SM

AL

LC

AS

ING

PR

ES

SU

RE

WA

IT &

WE

IGH

T

CIR

CU

LA

TIN

GK

ILL

MU

D D

OW

N

WA

IT &

WE

IGH

T

DR

ILL

PIP

EC

ON

TE

NT

SA

T S

UR

FAC

E

Dril

l pip

e pr

essu

re d

ropp

ing

from

Initi

al C

ircul

atin

gP

ress

ure

to F

inal

Circ

ulat

ing

Pre

ssur

e C

asin

g P

ress

ure

risin

g ve

ry s

low

ly (

little

gas

expa

nsio

n)

Sm

all C

asin

g P

ress

ure

still

held

- a

s lig

ht m

ud fr

omdr

illpi

pe c

ircul

ated

out

FCF.

C.P

.

0

WA

IT &

WE

IGH

T

KIL

L M

UD

AT

BIT

WA

IT &

WE

IGH

T

WE

LL

KIL

LE

D

Dril

l pip

e P

ress

ure

now

ste

ady

atF

inal

Circ

ulat

ing

Pre

ssur

e

Wel

l ‘cl

ean

up’ t

akes

som

e tim

e, a

s sm

all

resi

dual

Cas

ing

Pre

ssur

e is

like

ly

CA

SIN

GP

RE

SS

UR

EV.

SL

OW

LYR

ISIN

G

F.C

.P.

F.C

.P.

Kill

Mud

Wei

ght

Kill

Mud

Wei

ght

Kill

Mud

Wei

ght



5 - 17

5.5 VOLUMETRIC WELL CONTROL

The volumetric method is mostly used in workover and production operations. Itis a means of allowing the gas to migrate to surface under control. The gas needsto migrate at over (approx.) 1000' per hour. To allow the bubble to expand thecasing gauge is held constant for a given volume of mud bled off. This operation isrepeated, holding an ever increasing pressure on the gauge until the gas reachesthe surface. This is to ensure the BHP is constant.

WHEN TO USE VOLUMETRIC WELL CONTROL

• A gas kick is taken and is migrating and the drill string is plugged and onlycasing pressure can be read.

• No drill string in the well, packer leaking, wireline logging and swabbed gasmigrating.

Figure 5.9 Example of volumetric well control with a plugged bit

For calculating safety margins and working margins use the universal volumetricwell control equation below:-

P.choke = Pann + Ps + Pw

Pa = Initial SICP

Ps = Built in safety margin prior to volumetric well controlcommencing.Recommended safety margin = 100 - 200 psi

Pw = Working margin for volumetric well controlRecommended working margin = 50 - 100 psi

0

700

130 bbls

WELL DATA

=======

12000'8000'0.0459 bbl/ft0.0291 bbl/ft12.0 ppg0.12 psi/ft700 psi

TVDTVD Shoe

DP/csg/OH capDC/OH cap

Mud wtInflux Grad

Casing Press

Active pit volume before kick = 120 bblsActive pit volume after kick = 130 bbls

5 - 18



P.choke = Pann + Ps + Pw= 700 + 100 + 50= 850 psi

5.5.1 Allow the casing pressure to increase to 850 psi. Note the time taken for thispressure increase then estimate percolating rate in ft/hr.

Example:-

Pressure increased by 150 psi in 15 minutes or 600 psi/hr

Pressure increase/hrPercolating rate= –––––––––––––––––

Mud grad psi/ft

600 psi= –––––––––

0.624 psi/ft

= 962 ft/hr

Note: With this percolating rate it will take approximately 12 hours to get theinflux to the surface and it should also be noted percolating rate mayincrease when gas is close to surface.

5.5.2 When casing pressure is at 850 psi bleed off at choke a volume of mud equalto the working pressure (50 psi).

Note: Casing pressure must be kept constant at 850 psi during this operation.After 50 psi of mud equivalent has been bled off at choke allow the gas tomigrate unexpanded until a further 50 psi of overbalance is attained.Bleed off 50 psi equivalent mud at choke and repeat procedure until gas isat choke. The next step lubrication will be discussed later.

5.5.3 CALCULATIONS FOR MUD VOLUME TO BLEED FOR PW

OH/DC's CapA. Around drill collars mud volume to bleed = Pw x –––––––––––

Mud grad

0.0291= 50 X ––––––

0.624

= 2.3 bbls



5 - 19

B. Around Drill Pipe

DP/OH Casg CapMud volume to bleed = Pw x ––––––––––––––

Mud Grad

0.0459= 50 x ––––––

0.624

= 3.6 bbls

5.5.4 GRAPHICAL EXAMPLE OF A VOLUMETRIC BLEED

Figure 5.10

500

600

700

800

900

1000

1

2

3

4

5Allow gas to migrate until casing pressure read 850 psi

First build up when well was shut in

Bleed off 2.3 bbl keepingchoke pressure ± 20 psi either side of 850 psi influx around DC's

Bleed off 3.6 bbls keeping choke pressure ± 20 psi either side of 900 psi Influx around D.pipe

Bleed off 3.6 bbls

Bleed off 3.6 bbls

Time

5 - 20



5.5.5 Figure 5.11 shows what is happening to the gas in the well.

Figure 5.11

Clearly the description outlined is simplified. Four bleeds are shown.Depending upon the size of the volume bled and the well depth more or lessbleeds may be required than illustrated here.

Important Points

1. Bleed mud at constant choke pressure using the manual choke. Ensurecrew trained not to be tempted to bleed off faster than this as moreinflux could be induced into the well. A major problem with themethod could be boredom, careful records must be kept of pressureand volumes.

2. Gas may not conveniently migrate up the well in one bubble. As soonas gas reached choke, stop bleeding until rest of gas catches up. Thismay build up an unacceptable overbalance and each situation will haveto be judged on the operational merits of the situation.

0

700

original volume(10 bbls)

0

850

(10 bbls)

0

850

(12.3 bbls)

0

900

(15.9 bbls)

0

950

(18.5 bbls)

0

1000

(22.1 bbls)

Gas volume in bbls at the end of each mud bleed.



5 - 21

5.5.6 LUBRICATION

Once gas is at choke stop the bleed operation and commence pumping mudinto the well using the kill line.

The procedure for lubrication is as follows:-

1. Pump slowly into kill line and let kill and choke line pressure equalisebefore opening kill line stack valves.

2. Pump 3.6 bbls mud into annulus and allow the mud time to fallthrough the gas, then bleed off pressure at the choke equal to thehydrostatic pressure of the mud pumped into the annulus.

Example:-

Pumped volumePressure to bleed = ––––––––––––– x Mud grad

Ann Cap

3.6= –––––– x 0.624

0.0459

= 50 psi

3. Repeat the lubrication process until all the gas has been replaced withmud and referring to the drawing in figure 5.11, this will takeapproximately 22.1 bbls.

Note: Pit volume should return to 120 bbls the volume in active pitbefore kick was taken.

5 - 22



Figure 5.12 Graphical example of lubricating mud into annulus

1. Original Pit Volume = 120 bbls

Pit volume after kick and volumetric bleed = 152.1 bbls

2. Formation pressure = SICP + P° hyd mud + P° hyd gas= 700 + (11656 x 0.624) + (344 x 0.12)= 700 + 7273 + 42= 8015 psi

BHP after lubrication = SICP + P° Hyd mud= 550 + (12000 x 0.624)= 550 + 7488= 8038 psi

5.5.7 Once the volumetric bleed and lubrication has been completed then the wellmust be circulated to kill mud. This can be done by running wire line andperforating drill pipe or drill collars. If all the gas has been bled from theannulus then SICP can be used to calculate the kill mud.

1050

1000

950

900

850

800

750

700

650

600

550

500

450

400

350152.1 148.5 145 141 138 134 130.5 127 123 120

3.6 7.2 10.8 14.4 18 21.6 25.2 28.8 32.4

Barrels Pumped

Cas

ing

Pre

ssu

re

Pit Volume

Pump 3.6 bbls

After pumping mud into annulus, waiting period allows mud to fall then bleed gas until casing pressure reduces by 50 psi below original pressure.



5 - 23

5.6 VOLUMTRIC STRIPPING

5.6.1 Example of Volumetric Stripping

The options available if an influx is swabbed or if the well starts flowingduring a trip are as follows:-

a) If well is not flowing, trip back to bottom keeping a careful check onreturns. Then circulate influx out of hole.

b) If well is flowing and is shut in and the gas is percolating with the bit along way off bottom and tight hole conditions have been experienced,then consider doing a volumetric bleed.

c) If well is flowing and is shut in and the gas is percolating with the bit along way off bottom and tight hole conditions have been experienced,then consider bullheading.

d) If well is flowing and is shut in and the gas is percolating and noproblems are anticipated in stripping back to bottom, then considervolumetric stripping to get bit to bottom. Circulate influx out using firstcirculation of Driller's Method.

Note: A swabbed kick well can be most effectively killed with bit onbottom. So every effort must be made to get bit safely back onbottom.

5 - 24



5.6.2 Well details

Figure 5.13

Bit size = 8 1/2"TVD = 12,000'TVD shoe = 9,000'Bit Depth = 11,000'DP Cap = 0.02776 bbl/ftDP Disp = 0.0075 bbl/ftDP/OH cap = 0.0459 bbl/ftMud wt = 12.0 ppgPit Gain = 15.0 bblsInflux Grad = 0.12 psi/ft

Bit depth at original shut in = 11,000'

Figure 5.14

Shut in pressures and influx sizewith bit on bottom.

108

108

15 bbls

0

560

24.5 bbls



5 - 25

5.6.3 Shut in procedure for a swabbed kick while tripping

Fast shut-in

1. Stab safety valve (kelly cock).

2. Close safety valve.

3. Open HCR fail safe valves.

4. Close annular.

5. Read casing pressure and if possible read drill pipe pressure.

6. Stab inside BOP (Gray valve).

7. Open safety valve.

8. Do stripping calculations, prepare stripping sheet.

9. Reduce annular pressure and commence stripping drill pipe.

Note: The above procedure (steps 1 through 5) assumes there is no float ornon-return valve in the drill string.

5.6.4 For calculating safety margins and working margins use the universalvolumetric well control equation below:-

P.choke = Pann + Ps + Pw

Pa = Initial SICP

Ps = 100 psi + *Increase in casing pressure with influx around drill collars* ∆P.csg = Mud grad - Influx grad x (H2 - H1)

Pw = Working margin (Recommended working margin = 50 - 100 psi)

15 15H1 = –––– = 214' H2 = ––––– = 514'

0.07 0.0292

Pa = 108 psi

Ps = 100 + (0.624 - 0.12) x (514 - 214)= 100 + 0.504 x 300= 251 psi

Pw = 50 psi

P.choke = 108 + 251 + 50= 410 psi

5 - 26



Theoretical bleed off in bbl/ft while stripping = DP displacement + DP cap= 0.01776 + 0.0075= 0.02526 bbl/ft

Ann CapExcess bleed off for each 50 psi working margin = Pw x (–––––––––– )

Mud grad

0.0292= 50 x (––––––– )

0.0624

= 2.3 bbls

Note: If the gas is not migrating while stripping, only theoretical bleed off willbe seen in strip tank.If gas is migrating then any excess bleed off is due to migration.When excess bleed off is ± 2.3 bbls, then build in another 50 psi workingpressure. Refer to Volumetric Stripping chart (Fig. 5.15).

Figure 5.15

After 50' pressure at 410 psi

After 15' stripped pressure at 460 psi



Step 1

Step 2

Step 3

Step 4

ACCUMULATIVE VOLUMESTheoretical

vol. bleed offActual vol.bleed off

Excess vol.bleed off

Average length= 94'

No. StandsP° choke

108 –>410

410

410

460

460

460

510

510

510

560

560

1

2

3

4

5

6

7

8

9

10

11

1.00

3.37

5.74

7.74

10.11

12.48

14.48

16.85

19.22

21.59

23.96

1.20

4.53

7.86

10.72

14.05

17.38

20.18

23.51

26.84

30.07

33.41

0.20

1.16

2.12

2.98

3.94

4.90

5.70

6.66

7.62

8.48

9.45



5 - 27

Step 1 Allow casing pressure to increase to calculated Pchoke pressurewhile stripping first stand, then hold casing pressure constant bybleed off at choke.

Note: The casing pressure may not rise straight away because the gas hasto be compressed. It may take 2 - 3 stands before a pressure build upis seen.

Step 2, 3 & 4 With theoretical bleed already calculated, record actual bleed,when the difference between the actual and theoretical bleed is2.3 bbls allow annulas pressure to increase by Pw (50 psi).

Figure 5.16

5.6.5 With bit on bottom casing pressure reads 560 psi, gas influx has expanded by9.45 bbls and if it was possible to read drill pipe pressure it would read zerowith drill pipe full of mud. The influx should now be circulated out usingauto choke.

Note: No kill mud will be required as this is a swabbed kick.

600

500

400

300

200

100

01 2 3 4 5 6 7 8 9 10 11 12

Step 1Step 2

Step 3Step 4

Stands

Pre

ssu

re

5 - 28



5.7 EDITED EXTRACT FROM API RP53

PIPE STRIPPING ARRANGEMENTS - SURFACE INSTALLATIONS

PURPOSE

During operations on a drilling or producing well, a sequence of events mayrequire tubing, casing, or drill pipe to be run or pulled while annular pressure iscontained by blowout preventers; such practice is called “stripping”. Stripping isnormally considered an emergency procedure to maintain well control; however,plans for certain drilling, completion, or well work operations may includestripping to eliminate the necessity of loading the well with fluid.

EQUIPMENT

Stripping techniques vary, and the equipment required depends upon thetechnique employed. Each stripping operation tends to be unique, requiringadaptation to the particular circumstances. Therefore, the equipment and the basicguidelines discussed herein are necessarily general in nature. Stripping requiressurface equipment which simultaneously:

a. permits pipe to be pulled from or run into a well,

b. provides a means of containing and monitoring annular pressure, and

c. permits measured volumes of fluid to be bled from or pumped into the well.

Subsurface equipment is required to prevent pressure entry or flow into the pipebeing stripped. This equipment should either be removable or designed so that itspresence will not interfere with operations subsequent to stripping.

The well site supervisor and crew must have a thorough working knowledge of allwell control principles and equipment employed for stripping. Equipment shouldbe rigorously inspected, and, if practicable, operated prior to use.

For stripping operations, the primary surface equipment consists of blowoutpreventers, closing units, chokes, pumps, gauges, and trip tanks (or other accuratedrilling fluid measuring equipment).

The number, type, and pressure rating of the blowout preventers required forstripping are based on anticipated or known surface pressure, the environment,and degree of protection desired. Often the blowout preventer stack installed fornormal drilling is suitable for low pressure stripping if spaced so that tool joints orcouplings can be progressively lowered or pulled through the stack, with at leastone sealing element closed to contain well pressure.



5 - 29

Annular preventers are most commonly employed for stripping because tooljoints and some couplings can be moved through the preventer without openingor closing of the packing element. Wear of the packing element limits the sole useof this preventer if high annular pressure must be contained while stripping. Tominimise wear the closing pressure should be reduced as much as possible and theelement allowed to expand and contract (breathe) as tool joint pass through.Lubrication of the pipe with a mixture of oil and graphite or by permitting a smallleakage of annular fluid will reduce wear on the packing element. A spare packingelement should be at the well site during any stripping operation.

Ram type preventers or combinations of ram and annular preventers areemployed when pressure and/or Configuration of the coupling could causeexcessive wear if the annular preventer were used alone. Ram preventers must beopened to permit passage of tool joints or couplings. When stripping betweenpreventers, provision should be made for pumping into and releasing fluid fromthe space between preventers. Pressure across the sealing element should beequalised prior to opening the preventer to reduce wear and to facilitate operationof the preventer. After equalising the pressure and opening the lower preventer avolume of drilling fluid equal to that displaced as the pipe is run into or pulledfrom the well should be, respectively, bled from or pumped into the spacebetween the preventers.

Chokes are required to control the release of fluid while maintaining the desiredannular pressure. Adjustable chokes which permit fast, precise control should beemployed. Parallel chokes which permit isolation and repair of one choke whilethe other is active are desirable on lengthy stripping operations. Because of thesevere service, spare parts or spare chokes should be on location. Fig. 10.A.1illustrates an example choke installation on the standpipe suitable for strippingoperations.

A pump truck or skid mounted pump is normally employed when stripping out.The relatively small volume of drilling fluid required to replace the capacity anddisplacement of each stand or joint of pipe may be accurately measured andpumped at a controlled rate with such equipment. Well fluid from below thepreventer should not be used to equalise pressure across the stripping preventer.

A trip tank or other method of accurately measuring the drilling fluid bled off,leaked from, or pumped into the well within an accuracy of one-half barrel isrequired.

The lowermost ram should not be employed in the stripping operation. This ramshould be reserved as a means of shutting in the well if other components of theblowout preventer stack fail. It should not be subjected to the wear and stress ofthe stripping process.

5 - 30



5.8 REMOVAL OF GAS TRAPPED IN BOP’S

In order to displace a gas kick completely from the wellbore several circulations ofthe well might be needed. During this time some of the gas may have becometrapped under closed rams in the BOP stack as shown in Fig 5.28. This has thepotential to cause a serious problem if the gas is not removed in a controlledmanner. If the rams were opened without removing the trapped gas, the gaswould be released into the riser. As the gas migrated, it would expand rapidly andcause the riser to unload mud onto the rig floor.

The most thorough method of gas removal is to leave the well shut on the lowerrams whilst displacing the choke and kill lines to water. By closing the kill linevalves, pressure can be bled off up the choke line and “U-tubed” up the choke lineby opening the pipe rams. This sequence is shown in Fig 5.29 and 5.30.

The surface diverter should be closed during the operations so that any residualgas from the riser can be safely dealt with. Once the riser has been displaced to killweight mud the lower rams can be opened and the well flow-checked. Calculateany new riser margin or trip margin that might have to be added to the mudweight.

Figure 5.28 TRAPPED GAS IN BOP STACK

UPPER ANNULAR

BLIND/SHEARRAMS

LOWER ANNULAR

PIPE RAMS

PIPE RAMS

PIPE RAMS

KILLLINE

CHOKELINE



5 - 31

Figure 5.29 REMOVING TRAPPED GAS FROM BOP STACK

KILLLINE

CHOKELINE

KILLLINE

CHOKELINE

KILLLINE

CHOKELINE

Isolate the well from the BOP stack by closing the lower pipe rams.

Slowly displace kill line to salt water.As the kill line is displaced to water, increase the kill line circulating pressure by an amount equal to the difference in hydrostatic pressure between kill mud and salt water at stack depth. This will maintain the gas at original pressure with clean salt water returns at surface stop pumping close choke.

Displace riser to kill mud using upper kill line.

5 - 32



Figure 5.30 REMOVING TRAPPED GAS FROM BOP STACK

KILLLINE

CHOKELINE

Close the subsea kill line valves.

At this point the pressure is still trapped in the gas bubble.

Bleed off pressure through the choke to allow the gas to displace water from the choke line.

The gas bubble should now be at close to atmospheric pressure.

KILLLINE

CHOKELINE

Close the diverter and line up to fill the riser.

Open the pipe rams and allow the riser to U-tube taking returns up the choke line.

Fill the riser as necessary.

Open the lower pipe rams and diverter element.

Flow check the well.



5 - 33

Bubble Expansion Example:-

Choke Line Length = 1000'Choke Line Volume = 8 bblsKill Mud = 15 ppgSea Water Grad = 0.445

P1 V1 780 X 3V2 = –––– = ––––––– = 5.3 bbls

P2 445

P1 = 15 x 1000 x 0.052 = 780 psi

V1 = 3 bbls

P2 = 0.445 x 1000 = 445 psi

Example:

This example gives some idea of the large volumes of gas that could bereleased to atmosphere if the annular is opened without sweeping the stack.

Lets say that we are drilling in 1800' of water and the well has been killed tosurface, via the choke line with 16.5 ppg mud.

The hydrostatic head compressing the gas under the bag would be

(1800 x 16.5 x .052) + 14.7 = 1559 psi

If the volume of gas trapped below the BOP = 5.46 bbls then:

P1 x V1 1559 x 5.46–––––– = V2 –––––––––– = 579 bbls P2 14.7

573 bbls of gas released at surface.

5 - 34



5.9 KICK DETECTION AND WELL CONTROL PROBLEMS ONDEVIATED AND HORIZONTAL WELLS

Figure 5.31

INTRODUCTION

Kick behaviour can be significantly different in highly deviated and horizontalwells. If influx is mainly gas, problems can be experienced getting the gas to moveout of the horizontal section. It maybe impossible to remove the gas if thehorizontal section is greater than 90 degrees. Swabbed influxes can be hard todetect in horizontal sections and care must be taken while making connections ortripping in these sections of the hole. Drill pipe pressure graphs will also besignificantly different for horizontal and deviated wells.

5.9.1 KICK DETECTION AND PRECAUTIONS TO TAKE WHILE DRILLING

a) First indication of a kick while drilling would be an increase in flow rate.

b) If the increase in flow rate is not picked up then the second indication of akick would be a pit level increase.

c) While drilling the horizontal section mixing chemicals or slow addition ofmud into the active system should be avoided

A - SURFACE

B - KICK OFF POINT (K.O.P.)

C - END OF BUILD (E.O.B.) D - TOTAL MEASUREDDEPTH (M.D.)

30" Shoe TVD = 1000' MD = 1000'

20" Shoe TVD = 2500' MD = 2500'

13 3/8" Shoe TVD = 5000' MD = 5500'

9 5/8" Shoe TVD = 9500' MD = 17500'

Mud Weight = 10.0 ppg

Formation Pressure = 4700 psiMD at C = 12500'

Well Depth TVD = 10000' MD = 15000'



5 - 35

5.9.2 KICK DETECTION AND PRECAUTIONS TO TAKE WHEN MAKINGCONNECTIONS.

a) The equivalent circulating density is relatively higher when drilling highangle wells. While drilling, the trip tank should be kept half full of mudwhen pumps are off. During a connection well should be lined up on triptank as the most likely time to swab or take a kick is when APL is lost withpumps off.

b) If an influx has been swabbed in and not picked up during a connection noincrease pit level will be seen until influx is out of horizontal section. If it is agas influx in an oil base mud then no increase maybe seen until influxreaches bubble point usually ± 3000 feet beneath mud return flow line. Thedriller and mud logger should pay particular attention to flow rates and pitlevels when connection gas moves out of horizontal section or is ± 3000 feetbeneath mud return flow line.

5.9.3 KICK DETECTION AND PRECAUTIONS TO TAKE WHILE TRIPPING.

a) Mud loggers will calculate maximum tripping speed to avoid swabbing.

b) Check mud rheology is within specifications prior to tripping, high mudrheology can lead to swabbing.

c) When tripping out of horizontal section there are two options availableand a slug should not be pumped until bit is inside 9 5/8" casing.

1. Line up to trip tank pull out to 9 5/8" shoe monitoring hole fill in triptank

ADVANTAGES: Accurate record of hole fill.

DISADVANTAGES: Pulling out of hole with pumps off there is no APLto Act as a safety margin.

2. Pull out of hole to 9 5/8" shoe back reaming and circulating.

ADVANTAGES: While circulating annular pressure loss will be actingon formation and should prevent swabbing.

DISADVANTAGES: If an influx is swabbed in, it would be very hard ifnot impossible to detect.

5 - 36



5.9.4 GAS KICK IN HORIZONTAL SECTION.

a) Gas will not migrate if hole angle is 90 degrees or greater.

b) Gas will not migrate if it is dissolved in oil based mud.

c) Gas maybe trapped in undulations or washouts or in hole sections which aregreater than 90 degrees.

d) If gas cannot be removed from inverted sections then consider bullheadinggas into formation.

e) Slow circulating rates which give a flow rate greater than 130 ft/min whilecirculating gas out of horizontal section should be considered. Flow rateslower than this may not remove the gas from the horizontal section

f) A swabbed influx will not give a SICP if shut in while it is in horizontalsection.

g) Referring to drawings on page 1 it would be impossible to take a kick ifformation pressure remains at 4700 psi. If a fault is drilled and formationpressure increases and the well is shut on a kick then SIDPP = SICP and thegradient of the influx cannot be calculated.



5 - 37

Drill pipe kill graph for a vertical well using well details from Fig 5.31

Additional Information

SIDPP = 600 psiPSCR (Up Riser) = 700 psiPump Output = 0.117 bbl/stksDrill Pipe Cap = 0.01776 bbl/ftBHA Cap = 1000' X 0.008 bbl/ftDrill String Cap = 9000 X 0.01776 = 159.8

1000 X 0.008 = 8.0167.8 bbl

Strokes to 167.8Disp D.string = ––––– = 1434 stks

0.117

ICP - FCP 1300-784Press Step Down psi/stks = –––––––––––––– = ––––––––– = 0.36 psi/stks

Surface to bit stks 1434

6001. Kill Mud wt = ––––– ÷ 0.052 + 10.0

10000

= 11.2 ppg

2. ICP = 600 + 700

= 1300 psi

11.23. FCP = 700 x ––––

10

= 784 psi

5 - 38



Figure 5.32

To construct this graph calculate ICP and FCP and strokes to displace the drillstring then draw a line between the two points.

IT SHOULD BE NOTED THAT THIS GRAPH IS MADE UP OF TWODIFFERENT PRESSURES

No 1 Is the SIDPP which will decrease from 600 psi to zero when kill mudis at the bit.

No 2 Is the SCR pressure which increases from 700 psi to 784 psi when thekill mud is at the bit.

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 17000

100

200

300

400

500

600

700

800

900

1000

1100

1200

1300

1400

1500

PR

ES

SU

RE

STROKES

FCP

ICP



5 - 39

Drill pipe kill graph for a horizontal well using well details from Fig 5.31

Additional Information

SIDPP = 600 psiPSCR (Up Riser) = 1050 psiPump Output = 0.117 bbl/stksDrill Pipe Cap = 0.01776 bbl/ftBHA Cap = 1000' X 0.008 bbl/ftDrill String Cap = 14000 X 0.01776 = 248.6

1000 X 0.008 = 8.0256.6 bbl

Strokes to 256.6Disp D.string = ––––– = 2194 stks

0.117

Figure 5.33

6001. Kill Mud wt = ––––– ÷ 0.052 + 10.0 = 11.2 ppg

10000

2. ICP = 600 + 1050 = 1650 psi

11.23. FCP = 1050 x –––– = 1176 psi

10

MD = 2500'TVD = 2500'

MD = 12500'TVD = 10000'

MD = 15000'TVD = 10000'

A - (SURFACE)

B - (K.O.P.)

C - (E.O.B.) D - (M.D.)

5 - 40



Figure 5.34

The calculations for Figure 34 are as follows:-

1. Pressure Drop from A to B

TVD(B)Static drill pipe pressure drop to point (B) = SIDPP - (––––––– x SIDPP)

TVD

2500= 600 - ––––– x 600 = 600 - 150 = 450 psi

10000

MD(B)Frictional pressure increase at point (B) = SCR UP RISER + (––––– FCP-PSCR)

MD

2500= 1050 + ( –––––– x 126)= 1050 + 21 = 1071 psi

15000

Pressure drop from A–> B = 1650 –> (1071 + 450) = 1650 psi –> 1521 psi

44.4Strokes from A–> B 2500 x 0.01776 = –––––– = 380 strokes

0.117

0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 26000

200

400

600

800

1000

1100

1200

1300

1400

1500

PR

ES

SU

RE

STROKES

A - (SURFACE) 16501600

1700

D - (M.D.) 1170

C - (E.O.B.) 1155

B - (K.O.P.) 1521



5 - 41

2. Pressure drop from B to C TVD(C)

Static drill pipe pressure drop to point (C) = SIDPP - (–––––– x SIDPP) TVD

10000= 600 - ( ––––– x 600) = 0 psi

10000 MD(C)

Frictional pressure increase at point C = SCR + ( ––––– x ∆P SCR) MD

12500= 1050 + (–––––– x 126) = 1050+105 = 1155 psi

15000

Pressure drop from B to C = 1521 to 1155 psi

177.6Strokes from B to C = (12500 - 2500) x 0.01776 = (–––––)= 1518 strokes

0.117

Accumulative strokes = 380 + 1518 = 1898 strokes

3. Frictional pressure increase from point C to point D

Frictional pressure at C = 1155 psiFrictional pressure at D = 1176 psi

26.64Strokes from C to D = (12500 - 14000) x 0.01776 = –––––– = 228 strokes

0.117

81000 x 0.008 = –––– = 68 strokes

0.117

296 strokes

Accumulative strokes to point D = 380 + 1518 + 296 = 2194 strokes

5 - 42



5.10 KICK TOLERANCE

When a gas influx has entered a well there are 2 critical locations for the influx:-

a) When the influx is at the bottom of the well. In this case the SICP must notexceed the MAASP, if the formation is not fractured at the casing shoe.

b) When the influx has been circulated up to the casing shoe, by a constantbottom hole pressure method. In this case, the pressure at the choke mustnot exceed the MAASP.

KICK TOLERANCE DEPENDS UPON:-

Formation strength, fracture pressure or fracture gradient.

Mud density or gradient.

Gas influx density or gradient.

Formation pore pressure, gradient or SIDPP.

Drill string and wellbore geometries.

The maximum tolerable length of gas influx in the annulus at any positionbetween bottom hole and the casing shoe is:-

H (Max) = MAASP - SIDPP (Eqn1) Gm - Gi

Where:- GM = mud gradient (psi/ft)

GI = influx gradient (psi/ft)

MAASP = (Gfrac - Gm) x Ds (psi)

Gfrac = formation fracture gradient at the shoe (psi/ft)

DS = TVD to the shoe (ft)

SIDPP = shut-in drillpipe pressure (psi)



5 - 43

BDE = pressure profile in annulus atshut-in.

BD = initial gas influx height = H1

BMFKL = pressure profile in annuluswhen top of gas is circulated tocasing shoe, by 'drillers method'.

SK = fracture pressure at shoe.

FK = maximum tolerable length ofexpanded gas influx at shoe= HMAX.

∆le FKN = ∆le BDM.

Hence HMAX = MAASP - SIDPP GM - GI

MAASP

SICP

0 E L PRESSURE

KICK TOLERANCE : DRILLED KICK

SIDPP

Phyd PporeC

AM

B

D

H1(gas)

H max (gas)

N KSShoe

F

Mud G

radient/Preffure Line

DE

PT

H (

TV

D)

Fracture Line

NB. Well geometry assumed to be constant

5 - 44



DEFINITION 1: for a kick taken while drilling into a high pressure formation.

Kick Tolerance is the maximum allowable influx volume, for a known or assumedSIDPP, which will not cause the formation to fracture when either the influx is atthe bottom of the annulus or when it is circulated and expanded to the casing shoeby a constant bottom-hole pressure method. (Usually the Driller's method).

Thus the kick tolerance is either

a) V1g = H x Vdca bbl (If H is <Ldc) Ldc

or V1g = Vdca + (H - Ldc) bbl (if H is >Ldc) Cdpa

where H is calculated from Eqn 1

OR

b) V1g = Pfrac x (MAASP - SIDPP) bbl Ppore x (GM - GI) x Csa

The Lower value of V1g calculated from a) and b) is the Kick Tolerance.

Where:- Vdca = Volume of DC/OH annulus, (bbl)

Ldc = (Vertical) length of drill collars, (ft)

Cdca = Capacity of DC/OH annulus (ft/bbl)

Cdpa = Capacity of DP/OH annulus (ft/bbl)

Csa = Capacity of annulus (ft/bbl) at the casing shoe - thiswill probably = Cdpa, but on occasion it may = Cdca

Pfrac = fracture pressure at shoe (psi)

Ppore = pore pressure at bottom of hole (psi)



5 - 45

DEFINITION 2: for a kick taken while tripping out of the hole.

Kick tolerance for a swabbed kick is the maximum allowable influx volume whichmay be swabbed into the bottom of a well, without fracturing the formation whenthe well is closed in, and when the mud gradient is at the least equal to theformation pore pressure gradient.

It is assumed that prior to tripping, the mud weight was correct. In this case, whenthe bit is eventually back at bottom SIDPP=0, although initially SIDPP should =SICP (no float) when the well is closed in and the bit is above the influx.

In this case Hmax = MAASP ft GM - GI

and the kick tolerance is either

V1g = H x VdcaLdc

or V1g = Vdca + (H - Ldc)Cdpa

5 - 46



KICK TOLERANCE EXERCISE 1

A well has a TVD of 14500 ft with the casing shoe at 13200 ft TVD. The fracturegradient is 0.87 psi/ft and the current mud is 15.3 ppg. There is 700 ft of 6 1/2"OD drill collar and the open hole diameter is 8 1/2", with 5" drill pipe.

The annular capacities are:-

DC/OH = 34.314 ft/bbl

DP/OH = 21.787 ft/bbl

1) Calculate the kick tolerance if the well is shut-in with thecurrent mud and a SIDPP of 570 psi.

The gas gradient is 0.1 psi/ft.

2) Calculate the kick tolerance for a swabbed kick when the mudweight is equivalent to the formation pore pressure.

The mud gradient is 0.835 psi/ft.



5 - 47

SOLUTION

1) MAASP = (Gfrac - GM) x DShoe GM = 15.3 x 0.052 = 0.7956 psi/ft

= (0.87 - 0.7956) x 13200

= 982 psi

Then H1 max = MAASP - SIDPP GM - GI

= 982 - 570 .0.7956 - 0.1

= 592.3 ft

a) For influx at the bottom of the well, influx is still within the DC/OH annulus,at its maximum.

Volume of DC/OH annulus= 700 = 20.40 bbl 34.314

Therefore: Kick tolerance (a) = 592.3 x 20.40 = 17.3 bbl 700

b) For kick at casing shoe,

Kick tolerance (b) = Pfrac x (MAASP - SIDPP)Ppore x Cdpa x (GM - GI)

= Gfrac x (MAASP - SIDPP) x DshoeGpore x Cdpa x (GM - GI) x TVD

Gpore = 15.3 x 0.052 x 14500 + 570 = 0.835 psi/ft14500

Therefore: kick tolerance (b) = 0.87 x (982 - 570) x 13200 = 25.8 bbl 0.835 x 21.787 x (0.7956 - 0.1) x 14500

conclusion: The smaller of those 2 values is the (a) valuetherefore kick tolerance = 17.3 bbl when the kick isin the DC/OH annulus. This is usually the case inshort open-hole sections.

5 - 48



2) For a swabbed kick, maximum allowable (SIDPP = 0) influx height is:

Hmax = MAASP ft GM - GI

New MAASP = (0.87 - 0.835) x 13200

= 462 psi

Therefore H1 max = 462 = 628.6 ft 0.735

Therefore swabbed kick tolerance with 0.835 psi/ft mud.

= 628.6 x 20.4 700

= 18.3 bbl



5 - 49

WORKSHOP 5

The following questions 1-5 refer to the first stage of the Drillers Method.

1. A well was shut-in on a kick that occurred whilst drilling. Duringthe first circulation of the Drillers Method, the choke operatormaintains a constant drill pipe pressure at a constant pumpspeed.Will bottom hole pressure:

a. Be increasingb. Be decreasingc. Being kept constant

2 . Referring to the question above, the choke operator has nottaken into account the large volume of the surface lines, i.e.from the pump to the rig floor.This will result in:

a. An increase in bottom hole pressureb. A reduction in bottom hole pressurec. No change to bottom hole pressure

3. Referring to question 1 above if the kick was brine, (with no gas)Casing or Choke pressure will be at its highest :

a. When pressures have stabilised at shut-inb. When the kick is going into the shoec. When the kick is nearing the surface

4. What happens to pressure at the shoe as the brine kick is beingmoved into the casing shoe?:

a. Pressure at the shoe will be constantb. Pressure at the shoe will reducec. Pressure at the shoe will increase

5. If the kick is gas rather than brine and as it is being circulatedinto the casing shoe will:

a. Pressure at the shoe increaseb. Pressure at the shoe decreasec. Pressure at the shoe remain constant

5 - 50



6. During the second stage of the Drillers Method, assuming all ofthe kick was removed during the first stage, if when starting theoperation the choke operator maintained a constant initialcirculating pressure in the drill-pipe until kill mud reached the bit.Would bottom hole pressure?

a. Be increasedb. Have reducedc. Be constant

7. If at the start of the second stage of the Drillers Method, the chokeoperator maintained a constant Casing or Choke pressure untilkill mud was at surface. How would this action affect B.H.P. ?

a. B.H.P. would be seeing an increase from the moment thepump reached kill speed until kill mud was at surface.

b. B.H.P. would have increased until kill mud was at the bit,then B.H.P. would have remained constant as kill muddisplaced the annulus.

c. B.H.P. would have remained constant until kill mud at bitthen B.H.P. would be increased as kill mud displaced theannulus.

8. If total losses occur when drilling and with the bit off bottom andthe mud pumps off. Sea-water is then pumped to the annulus.Assume the volume of water it took to fill the well to the top wasequivalent to 500' of annulus. What is the resultant reduction inbottom hole pressure due to this action ?

Mud weight = 10 ppgSea-water = 8.7 ppg

a. 260 psib. 226 psic. 34 psi

9. The well flows with the bit 10 stands off bottom. Shut-in casingpressure reads 200 psi. If the influx is below the bit:

a. Shut-in drill pipe pressure will be higher than 200 psib. Shut-in drill pipe pressure will be lower than 200 psic. Shut-in drill pipe pressure should be 200 psi



5 - 51

10. A well is shut-in on a kick whilst drilling and stabilised shut-inpressures have been established. Due to a delay in starting the killoperation surface pressures have increased by 100 psi as theinflux is migrating. The safest action would be:

a. To bleed mud off using the choke until casing pressurereduces by 100 psi. Then keep it constant.

b. Bleed mud off keeping a constant drill pipe pressure.c. Leave it until the problem causing the delay has been

resolved then increase the kill mud weight by .5 ppg.

11. Referring to Q10. If surface pressure had increased by 200 psidue to migration of the influx. How far has the influx migratedif the mud weight is 10 ppg and the influx density is assumedto be .12 psi/ft ?

Answer:

12. When comparing the Drillers and Wait & Weight Kill Methodswith regards to the pressures that will be exerted on the exposedfoundations immediately below the casing shoe: Select 2 answersfrom the following statements.

a. The Drillers Method will always give a higher shoe pressure.b. The Wait & Weight Method will always give a lower shoe

pressure.c. The Drillers Method will give the lowest shoe pressure when

the open hole volume is smaller than the string volume.d. The Wait & Weight Method will give the lowest shoe pressure

when the open hole volume is greater than the string volume.e. There will be no great difference in shoe pressures whether

the Drillers or Wait/Weight Method is used if the open holevolume is less than the string volume.

13. If a well is shut-in on a gas kick and the gas is not allowed toexpand as it migrates up the well-bore. What happens ?

a. To B.H.P.

(i) It increases(ii) It decreases(iii) Stays more or less the same

5 - 52



b. To surface pressures

(i) They increase(ii) They stay more or less the same(iii) Only casing pressure will increase

c. To pressures at the shoe

(i) Will only increase if the influx is below the shoe(ii) Will continue to increase(iii) Will remain fairly constant

d. Pressures in the gas influx. Assuming no temperature change.

(i) Pressure in the gas will continue to increase(ii) Pressure in the gas will keep reducing as it migrates(iii) There should be no great change to the pressures in the

gas influx

14. A kick is being circulated out using the Wait & Weight Kill Method.Shortly after pumping kill mud to the bit, final circulating pressurehas suddenly increased by 200 psi. The pump speed has been keptconstant at kill speed and there was no change noted on the chokegauge. What is the problem ?

a. The choke has pluggedb. A bit nozzle has pluggedc. A pack-off has occurred around the bit

15. If the choke operator opened the choke and reduced drill pipepressure back to the calculated final circulating pressure in theproblem as described in Question 14. The result would be:

a. B.H.P. would be reducedb. B.H.P. would be increasedc. no change to B.H.P



5 - 53


1. c. Being kept constant

Maintain ICP with present mud weight until bottoms-up(1st circ. driller's method).

2 . c. No change to bottom hole pressure

Kill mud is not being circulated until the 2nd circulation.

3. a. When pressures have stabilised at shut-in

When the height of the kick is at its highest: ie aroundthe drill collars.

4. b. Pressure at the shoe will reduce

Kick fluid is being replaced with a heavier "mud",reducing pressure at the shoe.

5. b. Pressure at the shoe decrease

Kick fluid is being replaced with a heavier "mud",reducing pressure at the shoe.

6. a. Be increased

Casing pressure should be constant while DP pressureshould reduce from an ICP to a FCP.

7. c. B.H.P. would have remained constant until kill mud at bitthen B.H.P. would be increased as kill mud displaced theannulus.

Casing pressure should reduce as kill mud displaces annulus.

8. c. 34 psi

500 x (10 - 8.7) x .052 = 33.8 psi

5 - 54



9. c. Shut-in drill pipe pressure should be 200 psi

10. b. Bleed mud off keeping a constant drill pipe pressure.

11. Answer: 385'

200 psi= 385'

.52 psift

12. d. The Wait & Weight Method will give the lowest shoe pressurewhen the open hole volume is greater than the string volume.

e. There will be no great difference in shoe pressures whetherthe Drillers or Wait/Weight Method is used if the open holevolume is less than the string volume.

13. a. (i) It increases

b. (i) They increase

c. (ii) Will continue to increase

d. (iii) There should be no great change to the pressures inthe gas influx

14. b. A bit nozzle has plugged

15. a. B.H.P. would be reduced

SECTION 6 : WELL CONTROL EQUIPMENT

Page

6. 0 API Guidelines - API RP53 1

6. 1 Ram Blowout Preventers 10

6. 2 Annular Preventers 38

6. 3 Diverters 57

6. 4 Gaskets, Seals and Wellheads 68

6. 5 Manifolds 80

6. 6 Inside BOP’s 98



6 - 1

6.0 API GUIDELINES (API RP53)

BLOWOUT PREVENTER STACK ARRANGEMENTSSURFACE INSTALLATIONS

CLASSIFICATION OF BLOWOUT PREVENTERS

API classification of example arrangements for blowout preventer equipment isbased on working pressure ratings. Example stack arrangements shown in Figs.C.1 to C.9 should prove adequate in normal environments, for API Classes 2M,3M, 5M, 10M and 15M. Arrangements other than those illustrated may be equallyadequate in meeting well requirements and promoting safety and efficiency.

STACK COMPONENT CODES

The recommended component codes for designation of blowout preventer stackarrangements are as follows:

A = annular type blowout preventer.G = rotating head.R = single ram type preventer with one set of rams, either blank or for pipe,

as operator prefers.Rd = double ram type preventer with two sets of rams, positioned in

accordance with operator’s choice.Rt = triple ram type preventer with three sets of rams, positioned in

accordance with operator’s choice.S = drilling spool with side outlet connections for choke and kill lines.M = 1000 psi rated working pressure.

Components are listed reading upward from the uppermost piece of permanentwellhead equipment, or from the bottom of the preventer stack. A blowoutpreventer stack may be fully identified by a very simple designation, such as:

5M -13 5/8 - SRRA

This preventer stack would be rated 5000 psi working pressure, would havethroughbore of 13 5/8 inches, and would be arranged as in Fig. C.5.

RAM LOCKS

Ram type preventers should be equipped with extension hand wheels hydrauliclocks.

6 - 2



SPARE PARTS

The following recommended minimum blowout preventer spare parts approvedfor the service intended should be available at each rig:

a. a complete set of drill pipe rams and ram rubbers for each size drill pipebeing used,

b. a complete set of bonnet or door seals for each size and type of ram preventerbeing used,

c. plastic packing for blow out preventer secondary seals,

d. ring gaskets to fit flange connections, and

e. appropriate spare parts for annular preventers, when used.

PARTS STORAGE

When storing blowout preventer metal parts and related equipment, they shouldbe coated with a protective coating to prevent rust.

DRILLING SPOOLS

While choke and kill lines may be connected to side outlets of the blowoutpreventers, many operators prefer that these lines be connected to a drilling spoolinstalled below at least one preventer capable of closing on pipe. Utilisation of theblowout preventer side outlet reduces the number of stack connections byeliminating the drilling spool and shortens the overall preventer stack height. Thereasons for using a drilling spool are to localise possible erosion in the lessexpensive spool and to allow additional space between rams to facilitate strippingoperations.

Drilling spools for blowout preventer stacks should meet the following minimumspecifications:

a. Have side outlets no smaller than 2" nominal diameter and be flanged,studded, or clamped for API Class 2M, 3M, and 5M. API Class 10M and 15Minstallations should have a minimum of two side outlets, one 3" and one 2"nominal diameter.

b. Have a vertical bore diameter at least equal to the maximum bore of theuppermost casinghead.

c. Have a working pressure rating equal to the rated working pressure of theattached blowout preventer.



6 - 3

For drilling operations, wellhead outlets should not be employed for choke or killlines Such outlets may be employed for auxiliary or back-up connections to beused only if a failure of the primary control system is experienced.

S*

FIG

6.0

.1E

XA

MP

LE

BL

OW

OU

T P

RE

VE

NT

ER

AR

RA

NG

EM

EN

TS

FOR

2M R

AT

ED

WO

RK

ING

PR

ESS

UR

E S

ER

VIC

E –

SU

RFA

CE

IN

STA

LL

AT

ION

FIG

C.2

AR

RA

NG

EM

EN

T S

*RR

Dou

ble

Ram

Pre

ven

ters

,R

d O

pti

onal

.

FIG

C.3

AR

RA

NG

EM

EN

TS*

RR

FIG

C.4

AR

RA

NG

EM

EN

TR

S*R

FIG

C.1

AR

RA

NG

EM

EN

T S

*A

A

S*

R R

S*

A RS

*

R R

6 - 4



FIG 6.0.2EXAMPLE BLOWOUT PREVENTER

ARRANGEMENTS FOR 3M AND 5M RATEDWORKING PRESSURE SERVICE –

SURFACE INSTALLATION

FIG C.5ARRANGEMENT S*RRA

Double Ram Type Preventers,Rd Optional.

FIG C.6ARRANGEMENT

RS*RA

* Drilling spool and its location in the stack arrangement is optional

S*

R

R

A

S*

R

R

A



6 - 5

R

FIG 6.0.3EXAMPLE BLOWOUT PREVENTER ARRANGEMENTSFOR 10M AND 15M WORKING PRESSURE SERVICE –

SURFACE INSTALLATION

FIG C.7ARRANGEMENT RS*RRA**Double Ram Type Preventers,

Rd Optional.

S*

R

A**

R

CASINGSPOOL

R

FIG C.8ARRANGEMENT S*RRRA**Double Ram Type Preventers,

Rd Optional.

S*

R

A**

R

CASINGSPOOL

R

FIG C.9ARRANGEMENT RS*RRA**G**

Double Ram Type Preventers,Rd Optional.

S*

R

A**

R

CASINGSPOOL

G**

* Drilling spool and its location in the stack arrangement is optional.** Annular Preventer A, and rotating head G, can be of a lower pressure rating.

6 - 6



BLOWOUT PREVENTER STACK ARRANGEMENTS -SUBSEA INSTALLATIONS

VARIANCE FROM SURFACE INSTALLATIONS

The arrangements of subsea blowout preventer stacks are similar to the examplepreventer surface installations with certain differences. The differencesare:

a. Choke and kill lines normally are connected to ram preventer body outlets.

b. Spools may be used to space preventers for shearing tubulars, hanging offdrill pipe, or stripping operations.

c. Choke and kill lines are manifolded for dual purpose usage.

d. Blind/shear rams are normally used in place of blind rams.

e. Ram preventers are usually equipped with an integral or remotely operatedlocking system.

STACK COMPONENT CODES

The recommended component codes adopted for designation of subsea blowoutpreventer stack arrangements use the same nomenclature as surfaceinstallations with the addition of remotely operated connectors:

CH =remotely operated connector used to attach wellhead or preventers to eachother (connector should have a minimum working pressure rating equal tothe preventer stack working pressure rating).

CL = low pressure remotely operated connector used to attach the marine riser tothe blowout preventer stack.

Example subsea blowout preventer stack arrangements are illustrated inFigs. D.1 through D.8.



6 - 7

FIG

6.0

.4E

XA

MP

LE

BL

OW

OU

T P

RE

VE

NT

ER

AR

RA

NG

EM

EN

TS

FO

R2M

AN

D 3

M R

AT

ED

WO

RK

ING

PR

ESS

UR

ESE

RV

ICE

– S

UB

SEA

IN

STA

LL

AT

ION

FIG

D.2

AR

RA

NG

EM

EN

T

HR

AC

L

CL

A R CH

FIG

D.3

AR

RA

NG

EM

EN

T

HR

RA

CL

Dou

ble

Ram

Ty

pe

Pre

ven

ters

,R

d, O

pti

onal

.

CL

A R R CH

FIG

D.4

AR

RA

NG

EM

EN

TC

HR

RC

HA

Dou

ble

Ram

Ty

pe

Pre

ven

ters

,R

d, O

pti

onal

.

CH R R CHA*

FIG

D.1

AR

RA

NG

EM

EN

T C

HSA

CL

(2m

rat

ed w

ork

ing

pre

ssu

re o

nly

.)

CL

A S CH

6 - 8



fig

6.0.

5E

XA

MPL

E B

LO

WO

UT

PR

EV

EN

TE

R A

RR

AN

GE

ME

NT

S FO

R5M

, 10M

AN

D 1

5M R

AT

ED

WO

RK

ING

PR

ESS

UR

ESE

RV

ICE

– S

UB

SEA

INST

AL

LA

TIO

N

FIG

D.5

AR

RA

NG

EM

EN

T C

HR

dR

A*C

LTr

iple

Ram

Typ

e Pr

even

ters

,R

d O

ptio

nal

CL

A* R R R CH

FIG

D.6

AR

RA

NG

EM

EN

T

HR

dR

A*C

HA

*

CH

A* R R R CHA*

FIG

D.7

AR

RA

NG

EM

EN

T

HR

dR

dA

*CL

CL

A* R R R CHR

FIG

D.8

AR

RA

NG

EM

EN

TC

HR

dR

dA

*CH

A*

CH

A* R R R CHA* R



6 - 9

FIG

6.1

.1 U

Blo

wou

t Pre

ven

ter

6 - 10



6.1 RAM BLOWOUT PREVENTERS - CAMERON U BOP

The Cameron U BOP is the most widely used ram-type BOP for land, platformand subsea applications worldwide and offers the widest range of sizes of anyCameron ram-type BOP. Like all other Cameron preventers, the rams in the U BOPare pressure-energized. Wellbore pressure acts on the rams to increase the sealingforce and maintain the seal in case of hydraulic pressure loss. Seal integrity isactually improved by increased well bore pressure.

Other features of the U BOP include:

• Hydraulic stud tensioning available on larger sizes to ensure that studloading is consistently accurate and even.

• Bonnet seal carrier is available to eliminate the need for high makeup torqueon bonnet studs and nuts.

• Hydraulically operated locking mechanisms, wedgelocks, lock the ramhydraulically and hold the rams mechanically closed even when actuatingpressure is released. The operating system can be interlocked using sequencecaps to ensure that the wedgelock is retracted before pressure is applied toopen the BOP.

• For subsea applications, a pressure balance chamber is used with the wedgelocks to eliminate the possibility of the wedgelock becoming unlocked due tohydrostatic pressure.

Other features include hydraulically opening bonnets, forged body and awide selection of rams to meet all applications.

Figure 6.1.2 U Blowout Preventer Wedgelock Assembly



6 - 11

Figure 6.1.3 Figure Cameron U - Type BOP

Bonne

t

Lock

ing S

crew

Housin

g,

Lock

ing S

crew

Piston

, Ram

Cha

nge

Cylind

er, R

am C

hang

e

Inte

rmed

iate

Flange

Seal R

ings,

Conne

cting

Rod

Side E

ntry

Por

tBonne

t Sea

l Gro

ove

Bonne

t Sea

ls

Body,

Single

Rams A

ssem

bly

Plastic

Injec

tion

Port

Cylind

er, O

pera

ting

'O' R

ings,

Opera

ting

Cylind

er

Piston

, Ope

ratin

g

Lip S

eal, O

pera

ting

Piston

6 - 12



PIPE RAMS

Cameron pipe rams are available for use in Cameron ram-type BOPs to fit allcommonly used sizes of tubing, drill pipe, drill collar or casing.

• Cameron pipe rams are self-feeding and incorporate a large reservoir ofpacker rubber to ensure a long-lasting seal under all conditions.

• Ram packers lock into place and are not dislodged by well flow

• All Cameron pipe rams are suitable for H2S service per NACE MR-01-75.

• CAMRAM™ top seals are standard for all Cameron pipe rams (exceptU BOPs larger than 13-3/4”).

• CAMRAM 350™ packers and top seals are available for high temperatureservice and for service in which concentrations of H2S are expected.

Top Seal

RamPacker

U BOP Pipe Ram

CAMRAM Packer

CAMRAM Top Seal

Ram

WearPads

T BOP Pipe Ram

Figure 6.1.4 - PIPE RAMS

Top Seal

RamPacker

U II BOP Pipe Ram



6 - 13

VARIABLE BORE RAMS

One set of Cameron variable bore rams (VBRs) seals on several sizes of pipe orhexagonal kelly, eliminating the need for a set of pipe rams for each pipe size.Features include:

• VBR packer contains steel reinforcing inserts which rotate inward when therams are closed so the steel provides support for the rubber which sealsagainst the pipe.

• All VBRs are suitable for H2S service per NACE MR-01-75.

• CAMRAM™ top seals are standard for all Cameron VBRs.

Top SealRam Body

VBR Packer

U and U II BOP Variable Bore Ram

Shearing Blind Rams

Cameron shearing blind rams (SBRs) shear the pipe in the hole, then bend thelower section of sheared pipe to allow the rams to close and seal. SBRs can beused as blind rams during normal drilling operations. Features include:

• Large frontal area on the blade face seal reduces pressure on the rubber andincreases service life.

• Cameron SBRs can cut pipe numerous times without damage to the cuttingedge.

• The single-piece body incorporates an integrated cutting edge.

• CAMRAM™ top seals are standard for all Cameron SBRs.

• H2S SBRs are available for critical service applications and include a bladematerial of hardened high alloy suitable for H2S service.

CAMRAM Packer

Ram Body

CAMRAM Packer

Wear Pads

T BOP Variable Bore Ram

Figure 6.1.5 - VBR'S

6 - 14



DVS rams are shearing blind rams which are similar to SBRs with the followingfeatures:

• DVS (double V shear) rams fold the lower portion of the tubular over aftershearing so that the lower blade can seal against the blade packer

• DVS rams include the largest blade width available to fit within existingram bores.

CAMRAM Top Seal

Blade Insert

Slide Packer

BladeInsert

BladePacker

LowerSBR

UpperSBR

U and U ll H2S BOP Shearing Blind Ram

CAMRAM Top SealRamBodySlide Packer

LowerSBR

UpperSBR

BladePacker

U and U ll BOP Shearing Blind Ram

Blade Packer

Upper Blade Insert

Slide Packer

Screw

CAMRAMTop Seal

Lower BladeInsert

LowerSBR

UpperSBR

WearPads

T BOP Shearing Blind RamUpper Ram Body

Lower Ram Body

Top Seal

BladePacker

SidePacker

DVS Shear Ram

Figure 6.1.6 - SHEAR RAMS



6 - 15

SECONDARY SEAL

The secondary seal is activated by screwing down on the piston which forcesplastic through the check valve and into the space between the two swab cupseals. Further piston displacement causes pressure to build up between the swabcups, forcing them to flare out and provide a seal. When the pressure exerted bythe plastic packing reaches the proper valve, additional displacement of the pistonwill overcome the spring tension in the relief valve and plastic packing will beginto extrude from it.

The secondary seal should be activated only if the primary connecting-rod sealleaks during and emergency operation. The secondary seal is designed for staticconditions and movement of the connecting rod causes rapid seal and rod wear.

Figure 6.1.7 - SECONDARY SEAL

RAM SIDE

PRIMARYSEAL

PACKINGREGULATOR

VALVE

SECONDARYSEALS

CHECK VALVE

PLASTIC PACKING

PACKING PISTON

PROTECTOR

6 - 16



U II Blowout Preventer

The Cameron U II BOP takes all of the features of the U BOP and adapts them forsubsea use in the 18-3/4-10,000 and 15,000 psi WP sizes.Like all other Cameron preventers, the rams in the U II BOP are pressure-energized. Wellbore pressure acts on the rams to increase the sealing force andmaintain the seal in case of hydraulic pressure loss. Seal integrity is actuallyimproved by increased well bore pressure.

Other features of the U II BOP include:

• Internally ported hydraulic stud tensioning system ensures that stud loadingis consistently accurate and even.

• Bonnet seal carrier is available to eliminate the need for high makeup torqueon bonnet studs and nuts.

• Hydraulically operated locking mechanisms, wedgelocks, lock the ramhydraulically and hold the rams mechanically closed even when actuatingpressure is released. The operating system can be interlocked using sequencecaps to ensure that the wedgelock is retracted before pressure is applied toopen the BOP

• A pressure balance chamber is used with the wedgelocks to eliminate thepossibility of the wedgelock becoming unlocked due to hydrostatic pressure.Other features include hydraulically opening bonnets, forged body and awide selection of rams to meet all applications.

Figure 6.1.8 - 18-3/4" DOUBLE U II BLOWOUT PREVENTER



6 - 17

Optional Equipment

Bonnet Seal Carriers for TL, U, UL and U 11 BOPSThe bonnet seal carrier is a bore-type sealing assembly which replaces the face sealused as the previous bonnet seal. Sealing capability is not dependent upon bonnetbolt torque. One seal is captured in a machined bore in the BOP body while theother seal is captured in a machined bore in the intermediate flange.

The seal carrier was designed, developedand performance-verified for use in newlymanufactured BOPs or as a replacement sealassembly for BOPs where either the BOPbody or the intermediate flange requiresweld repair on the sealing surfaces.

Large Bore Shear BonnetsCameron developed large bore shear bonnets to increase the available shearingforce required to shear high strength and high quality pipe. In order to achieve thisthe large bore shear bonnet design increased the available closing area by 35% ormore. Cameron recommends large bore shear bonnets when larger shearing forcesare required. As an alternative to purchasing new large bore shear bonnets, someold shear bonnets can be converted. This process requires reworking and replacingseveral existing components.

Tandem Boosters for U BOPSA BOP equipped with tandem boosters can deliver increased shearing force whilenot increasing the wear and tear on the packers. Tandem boosters approximatelydouble the force available to shear pipe. Since the tail rod of the tandem boosterhas the same stroke as the BOP operating piston, the standard shear lockingmechanism can be installed on the outside end of the booster.

Bonnet Seal Carrier

Figure 6.1.9

Large Bore Shear Bonnet Assembly Exploded View

Tandem Booster Exploded View

6 - 18



Figure 6.1.10 UII BOP Hydraulic Control System



6 - 19

Figure 6.1.11 UII BOP Part Numbers

6 - 20



SHAFFER SL RAM BLOWOUT PREVENTERS

Shaffer Model SL ram blowout preventers are the product of more than 50 years ofexperience in building ram BOP’s to meet the changing demands of the petroleumindustry. SL designated models incorporate the improvements made in the LW Spreventer line over the past 20 years—improvements resulting from a continuingresearch program to ensure that Shaffer preventers meet or surpass the latestindustry requirements.

Special Features

• Flat doors simplify ram changes. To change the rams, apply openinghydraulic pressure to move the rams to the full open position. Remove thedoor cap screws and swing the door open. Remove the ram from the ramshaft and replace it. It is not necessary to apply closing hydraulic pressure tomove the rams inward to clear the door.

• Door seals on most sizes have a hard backing moulded into the rubber. Thisfabric and phenolic backing prevents extrusion and pinching at all pressuresto assure long seal life.

• Internal H2S trim is standard. All major components conform to API andNACE H2S requirements.

• Maximum ram hardness Is Rc22 to insure H2S compatibility of pipe andblind rams. Shear rams have some harder components.

• Manual-lock and Poslock pistons can be interchanged on the same door byreplacing the ram shaft, piston assembly and cylinder head.

• Wear rings eliminate metal-to-metal contact between the piston and cylinderto increase seal life d virtually eliminate cylinder bore wear.

• Lip type piston seals are long-wearing polyurethane with molybdenumdisulfide moulded in for lifetime lubrication..

• Lip-type ram shaft seals hold the well bore pressure and the openinghydraulic pressure. No known failures of this highly reliable high pressureseal have occurred.

• Secondary ram shaft seals permit injection of plastic packing if the primarylip-type seal ever fails. Fluid dripping from the weep hole in the doorindicates that the primary seal is leaking and the secondary seal should beenergised.



6 - 21

• Rams are available which will support a 600,000 pounds when a tooljoint is lowered onto the closed rams. These rams conform to H2Srequirements.

• Shear rams cut drill pipe and seal in one operation. Most common weightsand grades of drill pipe are sheared with less than 1,500 psi hydraulicpressure.

• Poslock operators automatically lock the rams each time they are closed. Thiseliminates the cost of a second hydraulic function to lock. It also simplifiesemergency operation because the rams are both closed and locked just byactivating the close function.

Figure 6.1.12 - SHAFFER SL-RAM BOP

Roundhead ram shaftRam shaft seal

Piston sealsCylinder

Weep hole

Flat door

Cylinder head

Piston assembly

RamWear rings

Ram shaftpacking retainer

Secondaryram shaft seal

6 - 22



Figure 6.1.13 - LOCKING SYSTEMS

Locking shoulder

Locking segment

Locking segment Locking cone

2) Poslock piston in closed position

Cylinder

Piston

Ram shaft Ram

1) Manual-lock piston in open position

3) Manual-lock piston in closed position

Cylinder Head

Locking shaft

2) Manual-lock piston in closed and locked position

Poslock adjustment thread

Piston

Ram shaft Ram

1) Poslock in open position



6 - 23

MODEL SL MANUAL-LOCK SYSTEM

Manual-lock pistons move inward and close the rams when closing hydraulicpressure is applied. If desired, the rams can be manually locked in the closedposition by turning each locking shaft to the right until it shoulders against thecylinder head. Should hydraulic pressure fail, the rams can be manually closedand locked. They cannot be manually reopened.

The manual locking shafts are visible from outside and provide a convenient ramposition indicator. Threads on the manual locking shaft are enclosed in thehydraulic fluid and are not exposed to corrosion from mud and salt water or tofreezing.

Rams are opened by first turning both locking shafts to their “unlocked” position,then applying opening hydraulic pressure to the pistons, which move outwardand pull the rams out of the well bore.

MODEL SL HYDRAULIC SYSTEM

OPERATION AND MAINTENANCE

Hydraulic power to operate a Model SL ram BOP can be furnished by anystandard oil field accumulator system.

Hydraulic passages drilled through the body eliminate the need for externalmanifold pipes between the hinges. Each set of rams requires only one openingand one closing line. There are two opening and two closing hydraulic ports,clearly marked, on the back side of the BOP. The extra hydraulic ports facilitateconnecting the control system to the preventer.

A 1,500-psi-output hydraulic accumulator will close any Model SL ram BOP withrated working pressure in the well bore except for the 11" and 13 5/8—15,000 psiBOP’s, which require 2,100 psi. However, these two will close against 10,000 psiwell pressure with less than 1,500 psi hydraulic pressure.

A 3,000 psi hydraulic pressure may be used, but this will accelerate wear of thepiston seals and the ram rubbers.

A 5,000 psi hydraulic pressure test is applied to all Model SL cylinders at thefactory. However, it is recommended that this pressure not be used in the fieldapplication.

6 - 24



The hydraulic operating fluid should be hydraulic oil with a viscosity between 200and 300 SSU at 100°F. If necessary, a water-soluble oil such as NL Rig EquipmentK-90 and water can be used for environmental protection. Ethylene glycol must beadded to the K-90 and water solution for freeze protection if equipment is exposedto freezing temperatures.

NOTE: Never use fuel oil of any kind as it causes the rubber goods to swell anddeteriorate. Some water-soluble fluids do not give adequate corrosion protectionor lubrication and should not be used.

MODEL SL POSLOCK SYSTEM

SL preventers equipped with Poslock pistons are automatically locked in theclosed position each time they are closed. The preventers will remain locked in theclosed position even if closing pressure is removed. Opening hydraulic pressure isrequired to reopen the pistons.

The hydraulics required to operate the Poslock are provided through opening andclosing operating ports. Operation of the Poslock requires no additional hydraulicfunctions, such as are required in some competitive ram locking systems.When closing hydraulic pressure is applied, the complete piston assembly movesinward and pushes the rams into the well bore. As the piston reaches the’ fullyclosed position, the locking segments slide toward the piston O.D. over the lockingshoulder as the locking cone is forced inward by the closing hydraulic pressure.

The locking cone holds the locking segments in position and is prevented by aspring from vibrating outward if the hydraulic closing pressure is removed.Actually, the locking cone is a second piston inside the main piston. It is forcedinward by closing hydraulic pressure and outward by opening hydraulic pressure.

When opening hydraulic pressure is applied, the locking cone moves outward andthe locking segments slide toward the piston l.D. along the tapered lockingshoulder. The piston is then free to move outward and open the rams.

NOTE: Poslock pistons are adjusted in the factory and normally do not requireadjustment in the field except when changing between pipe rams and shear rams.The adjustment is easy to check and easy to change.



6 - 25

Figu

re 6

.1.1

4 - F

LU

ID C

IRC

UIT

- S

L R

AM

6 - 26



ULTRALOCK™ LOCKING SYSTEM

UltraLock, the most versatile locking system available, provides a maintenance-free and adjustment-free locking system that is compatible with any ram assemblythat the blowout preventers can accommodate. Once the UltraLock is installed, nofurther adjustments will be needed when changing between Pipe Rams, Blind/Shear or MULTI-RAM assemblies. BOPs that are equipped with the UltraLock areautomatically locked in the closed position each time the BOPs are closed; nopreset pressure ranges are needed. The BOPs will remain locked in the closedposition, even if closing pressure is lost or removed. Hydraulic opening pressure isrequired to re-open the preventer, and this opening pressure is supplied by theregular opening and closing ports of the preventer. No additional hydraulic linesor functions are required for operations of the locks. Stack frame modifications arenot required because all operational components are in the hydraulic operatingcylinders. Existing BOPs with PosLock~ Cylinders can be upgraded to theUltraLock. U.S. patent number 5,025,708.

Figure 6.1.15 - ULTRALOCK - UNIQUE POSITION LOCKING SYSTEM

Locking Plate

SecondaryUnlocking Piston

Locking Rod PlateRetaining Screw

Locking Rod Plate

Locking Rod

Locking DogRetainer

LockingDog Ultra Lock

PistonLoad

Spring

RamShaft



6 - 27

TYPE 72 SHEAR RAMS

Type 72 shear rams shear pipe and seal the well bore in one operation. They alsofunction as blind or CSO (complete shut-off) rams for normal operations.

The hydraulic closing pressure required to shear commonly used drill pipe isbelow 1,500 psi for BOP’s with 14'’ pistons. These pistons are standard in all BOP’srated at 10,000 psi working pressure and higher. On lower pressure preventers,optional 14" pistons can be supplied for shearing instead of the standard 10"pistons.

When shearing, the lower blade passes below the sharp lower edge of the upperram block and shears the pipe. The lower section of cut pipe is accommodated inthe space between the lower blade and the upper holder. The upper section of cutpipe is accommodated in the recess in the top of the lower ram block.

Closing motion of the rams continues until the ram block ends meet. Continuedclosing of the holders squeezes the semicircular seals upward into sealing

contact with the seat in the BOP body and energises the horizontal seal. Theclosing motion of the upper holder pushes the horizontal seal forward anddownward on top of the lower blade, resulting in a tight sealing contact. Thehorizontal seal has a moulded-in support plate which holds it in place when therams are open.

Type 72 Shear Rams are covered by U.S. Patent No. 3,736,982. (Ref fig 6.1.16)

6 - 28



Figure 6.1.16 - TYPE 72 SHEAR RAMS

UPPER RUBBER

UPPERBLOCK

LOWER RUBBER LOWER BLOCK

LOWERHOLDER

SHEAR BLADE

SEMICIRCULAR SEALHORIZONRAL SEAL

SUPPORT PLATE

SHEAR RAMS OPEN

SHEAR RAMS CLOSING

SEMICIRCULAR SEALHORIZONRAL SEAL

SUPPORT PLATE

SHEAR RAMS CLOSED

UPPER HOLDER



6 - 29

HYDRIL RAM BLOWOUT PREVENTERS

Features: (Refer to Fig 6.1.17 and 6.1.18)

1. The Ram Body Casting has controlled and predictable structural hardness andstrength throughout the pressure vessel. Hydril pressure vessel material has equalstrength along all axes to provide reliable strength and resistance to sulphide stresscracking in hydrogen sulphide service.

2. The Ram Assembly provides reliable seal off of the wellbore for security andsafety. The Ram accommodates a large volume of feedable rubber in the frontpacker and upper seal for long service life.

3. The Field Replaceable Seal Seat provides a smooth sealing surface for the ramupper seal. The seal seat utilises specially selected and performance effectivematerials for maximum service life.

4 Hinged Bonnet swing completely clear of overhead restrictions (such as anotherBOP) and provide easy access for rapid ram change to reduce downtime.

5. Load Hinges separate from the fluid hinge and are equipped with self-lubricated bearings to support the full weight of the bonnet for quick and easyopening of the bonnet.

6. Fluid Hinges, separate from the load hinges, connect the control fluid passagesbetween the body and bonnets. This arrangement provides a reliable hydraulicseal and permits full pressure testing and ram operation with the bonnets open.The fluid hinges and bonnet hinges contain all the seals necessary for this functionand may be removed rapidly for simple, economical repair.

7. Replaceable Cylinder Liner has a corrosion and wear resistant bore for reliablepiston operation. The cylinder liner is easily field replaceable or reparable forreduced maintenance cost and downtime.

8. Piston and Piston Rod Assembly are one piece for strength and reliability inclosing and opening the ram which results in a secure operating assembly.

9. Choice of Ram Locks—Automatic Multiple Position Locking (MPL) or ManualLocking is available on Ram BOPs.

10. Multiple-Position Locking (MPL) utilises a hydraulically-actuated mechanicalclutch mechanism to automatically lock the rams in a seal off position.

11. Manual Locking utilises a heavy-duty acme thread to manually lock the ram ina sealed-off position or to manually close the ram if the hydraulic system isinoperative.

12. Fluid Connections and Hydraulic Passages are internal to the bonnets andbody and preclude damage during moving and handling operations.

6 - 30



13. Connector Ring Grooves are stainless steel lined for all connectors (top, bottomand side outlets) for corrosion resistance of the sealing surface.

14. Sloped Ram Cavity is self-draining to eliminate build-up of sand and drillingfluid.

15. Bonnet Seal utilises field proven material in an integrated seal design whichcombines the seal and backup ring for reliability and long life.

16. Piston Rod Mud Seal is a rugged, field-proven, integrally designed lip seal andbackup ring retained in the bonnet by a stainless steel spiral lock ring.

17. Secondary (Emergency) Piston Rod Packing provides an emergency piston rodseal for use in the event of primary seal leakage at a time when repair cannot beimmediately effected.

18. A Weephole to atmosphere isolates wellbore pressure, indicates when seal isachieved and possible leakage in the primary seat. (Shown out of position)

19. Piston Seals are of a lip-type design and are pressure-energized to provide areliable seal of the piston to form the operating chambers of the BOP.

20. Side Outlets for choke/kill lines are available on all models. Two outlets, oneon each side, may be placed below each ram. In single and double configurations,outlets may be placed below the upper and lower ram, below the bottom ram only,or below the top ram only, therefore providing great versatility in stack design.

21. Single and Double Configurations are available with a choice of AmericanPetroleum Institute (API) flanged, studded or clamp hub connections. This allowsfor the most-economical use of space for operation and service. (Not shown)

22. Bonnet Bolts are sized for easy torquing and arranged for reliable seal betweenbonnet and body. This prevents excessive distortion during high pressure seal off.

23. Bonnet Bolt Retainers keep the bonnet bolts in the bonnet while servicing theBOP.

24. Guide Rods align ram with bonnet cavity, preventing damage to the ram,piston rod or bonnets while retracting the rams.

25. Ram Seal Off is retained by wellbore pressures. Closing forces are not requiredto retain an established ram seal off.



6 - 31

Figu

re 6

.1.1

7 - 1

3 5/

8" -

10,0

00 P

SI

RA

M B

OP

MA

NU

AL

LO

CK

13. C

ON

NE

CT

OR

RIN

G G

RO

OV

ES

1. T

HE

RA

M B

OD

Y C

AS

TIN

G

3. T

HE

FIE

LD R

EP

LAC

AB

LE

SE

AL

SE

AT

15. B

ON

NE

T S

EA

L

2. T

HE

RA

M

AS

SE

MB

LY

17. S

EC

ON

DA

RY

(EM

ER

GE

NC

Y)

(PIS

TO

N R

OD

PA

CK

ING

)

22. B

ON

NE

T B

OLT

S

11. M

AN

UA

L LO

CK

ING

19. P

IST

ON

SE

ALS

7. R

EP

LAC

AB

LE

CY

LIN

DE

R L

INE

R

18. A

WE

EP

HO

LE16

. PIS

TO

N R

OD

MU

D S

EA

L

14. S

LOP

ED

RA

M C

AV

ITY

24. G

UID

E R

OD

S

20. S

LID

E O

UT

LET

S F

OR

CH

OK

E/K

ILL

12. F

LUID

CO

NN

EC

TIO

NS

AN

D H

YD

RA

ULI

C P

AS

SA

GE

S

5. L

OA

N H

ING

ES

6. F

LUID

HIN

GE

S

6 - 32



Figu

re 6

.1.1

8 - 1

8 3/

4" -

15,0

00 P

SI

RA

M B

OP

MU

LTIP

LE

PO

SIT

ION

LO

CK

(MP

L)

3. T

HE

FIE

LD R

EP

LAC

EA

BLE

S

EA

L S

EA

T13

. CO

NN

EC

TO

R R

ING

GR

OO

VE

S

1. T

HE

RA

M B

OD

Y C

AS

TIN

G

20. S

IDE

OU

TLE

TS

FO

R C

HO

KE

KIL

L

14. S

LOP

ED

RA

M C

AV

ITY

15. B

ON

NE

T S

EA

L

16. P

IST

ON

RO

D M

UD

SE

AL

18. A

WE

EP

HO

LE19

. PIS

TO

N S

EA

LS7.

RE

PLA

CE

AB

LE

CY

LIN

DE

R L

INE

R

8. P

IST

ON

AN

D P

IST

ON

R

OD

AS

SE

MB

LY

10. M

ULT

IPLE

-PO

SIT

ION

LOC

KIN

G (

MP

L)

5. L

OA

D H

ING

ES

6. F

LUID

HIN

GE

S

2. T

HE

RA

M A

SS

EM

BLY

22. B

ON

NE

T B

OLT

S



6 - 33

MPL AUTOMATIC RAM LOCKING(Refer to Fig 6.1.19)Hydril Ram Blowout Preventers are available with automatic Multiple-PositionRam Locking. Multiple-Position Locking (MPL) allows the ram to seal off withoptimum seal squeeze at every closure. MPL automatically locks and maintainsthe ram closed with the optimum rubber pressure required for seal off in the frontpacker and upper seal.

Front packer seal wear (on any ram BOP) requires a different ram locking positionwith each closure to ensure an effective seal off. Multiple-Position Locking isrequired to ensure retention of that seal off position.

A mechanical lock is automatically set each time the ram is closed. Ram closure isaccomplished by applying hydraulic pressure to the closing chamber which movesthe ram to a seal off position. The locking system maintains the ram mechanicallylocked while closure is retained and/or after releasing closing pressure. The ram isopened only by application of opening pressure which releases the locking systemautomatically and opens the ram, simultaneously.

MPL is available on all Hydril Ram Blowout Preventers.

How MPL works

This figure shows the ram maintained closed and sealed off by the MPL.Hydraulic closing pressure has been released. The Hydril Ram Blowout Preventerwith MPL automatically maintains ram closure and seal off. MPL will maintain therequired rubber pressure in the front packer and upper seal to ensure a seal off ofrating working pressure. MPL will maintain the seal off without closing pressureand with the opening forces created by hanging the drill string on the ram.

Locking and unlocking of the MPL are controlled by a unidirectional clutchmechanism and a lock nut. The unidirectional clutch mechanism maintains the nutand ram in a locked position until the clutch is disengaged by application ofcontrol system pressure to open the ram.

Hydraulic opening pressure disengages the front and rear clutch plates to permitthe lock nut to rotate and the ram to open. As the ram and piston move to the openposition, the lock nut and front clutch plate rotate freely.

6 - 34



Figure 6.1.19 - HYDRILL MULTI-POSITION LOCK (MPL)



6 - 35

Cameron U Shaffer 'SL' Hydril Ram

SIZE WP (psi) Open Close Open Close Open Close

7 1/16 in. 3,000 2.3 6.9 1.5 5.4 5,000 2.3 6.9 1.5 5.410,000 2.3 6.9 1.7 8.215,000 2.3 6.9 3.37 7.11 6.6 7.6

9 in. 2,000 3,000 2.6 5.3 5,000 2.6 5.310,000

11 in. 2,000 2.5 7.3 3,000 2.5 7.3 2.0 6.8 5,000 2.5 7.3 2.0 6.810,000 2.5 7.3 7.62 7.11 2.4 7.615,000 2.2 9.9 2.8 7.11 3.24 7.6

13 5/8 in. 3,000 2.3 7.0 3.00 5.54 2.1 5.2 5,000 2.3 7.0 3.00 5.54 2.1 5.210,000 2.3 7.0 4.29 7.11 3.8 10.615,000 5.6 8.4 2.14 7.11 3.56 7.74

16 3/4 in. 2,000 3,000 2.3 6.8 5,000 2.3 6.8 2.03 5.5410,000 2.3 6.8 2.06 7.11 2.41 10.6

18 3/4 in. 10,000 3.6 7.4 1.83 7.11 1.9 10.615,000 4.1 9.7 1.68 10.85 2.15 7.27

21 1/4 in. 2,000 1.3 7.0 0.98 5.2 3,000 1.3 7.0 0.98 5.2 5,000 5.1 6.2 1.9 10.610,000 4.1 7.2 1.63 7.11

26 3/4 in. 2,0003,000 1.0 7.0

Figure 6.1.20 Ram Preventer Opening and Close Ratios

6 - 36



EXAMPLE CLOSING FORCES IN RELATION TO AREA

a) When closing the well in on a floating rig the hard shut in method is usuallyapplied. The string is picked up say 20’ off bottom, the rotary table or top drive isshut off and both pumps are shut down. The annular preventer is then closed andthe fail-safe's opened against a closed choke.

b) The tool joint is then spaced out for the correct pipe rams.

c) The string is stripped down until the tool joint is "hung off’ on the rams. Thecorrect operating pressure to set on the manifold regulator is directly related to thewell bore pressure. For example. Operating ratio 10:56:1. Working pressure of BOPstack 10,000 psi.

F 10,000 psiP = ––– ∴ F = P x A ––––––––– = 947 psi

A 10.56

This pressure does not include an allowance for friction losses so the minimumpressure would be say 1000 psi : 1000 psi x 10.56 = 10560 lbs closing force.

Figure 6.1.21

CLOSING PRESSURE

CLOSING AREARAM SHAFT AREA

➙

➙

➙

➙

➙

➙

➙

➙

➙➙

➙➙

➙ ➙

➙➙



6 - 37

Figure 6.1.22 RAM PREVENTERS -FLUID REQUIRED TO OPERATE

6 - 38



6.2 ANNULAR PREVENTERS

In the unique design of the Cameron DL annular BOP, closing pressure forces theoperating piston and pusher plate upward to displace the solid elastomer donutand force the packer to close inward. As the packer closes, steel reinforcing insertsrotate inward to form a continuous support ring of steel at the top and bottom ofthe packer. The inserts remain in contact with each other whether the packer isopen, closed on pipe or closed on open hole. Other features of the DL BOP include:• The Cameron DL BOP is shorter in height than comparable annular preventers.

A quick-release top with a one-piece split lock ring permits quick packer changeout with no loose parts involved. The design also provides visual indication ofwhether the top is locked or unlocked.

• The DL BOP is designed to simplify field maintenance. Components subject towear are field-replaceable and the entire operating system may be removed inthe field for immediate change-out without removing the BOP from the stack.

• Twin seals separated by a vented chamber positively isolate the BOP operatingsystem from well bore pressure. High strength polymer bearing rings preventmetal-to-metal contact and reduce wear between all moving parts of theoperating systems.

• Packers for DL BOPs have the capacity to strip pipe as well as close and seal onalmost any size or shape object that will fit into the wellbore. These packers willalso close and seal on open hole. Some annular packers can also be split forinstallation while pipe is in the hole. Popular sizes of the DL BOP are availablewith high-performance CAMULAR™ annular packing subassemblies.

Figure 6.2.1 DL ANNULAR BLOWOUT PREVENTER

PACKINGUNIT

PISTON

OPENINGCHAMBER

CLOSINGCHAMBER



6 - 39

Figure 6.2.2 CAMERON 20,000 PSI WP ANNULAR BLOWOUT PREVENTER SEALING ELEMENT

OPEN CLOSED ON PIPE CLOSED ON OPEN HOLE

6 - 40



Figu

re 6

.2.3

HY

DR

IL “

GK

” A

NN

UL

AR



6 - 41

OPERATIONAL FEATURES

The Hydril GK Annular BOPs are particularly qualified to meet the industry’s needs forsimple and reliable blowout protection. Over 40 years of operational experience providethe simplest, field proven mechanism in the industry.

Only Two Moving Parts (piston and packing unit) on the Hydril Annular BOP meanfew areas are subjected to wear. The BOP is thus a safer, and more efficient mechanismrequiring less maintenance and downtime.

A Long piston with a length to diameter ratio approaching one eliminates tendencies tocock and bind during operations with off-centre pipe or unevenly distributedaccumulation of sand, cuttings, or other elements. This design ensures the packing unitwill always reopen to full bore position.

Back to Front Feedable Rubber on the Packing Unit enables the packing unit to closeand seal on virtually any shape in the drillstring or completely shut off the open boreand to strip tool joints under pressure. This feature permits confident closure of the BOPat the initial indication of a “kick” without delaying to locate the tool joint.

The Conical Bowl Design of the Piston provides a simple and efficient method of closingthe packing unit. The piston serves as a sealing surface against the rubber packing unit;there is no metal-to-metal wear and thus longer equipment life results.

Utilisation of Maximum Packing Unit life is made possible with a piston indicator formeasuring piston stroke. This measurement indicates remaining packing unit life andensures valid testing.

A Field Replaceable Wear Plate In the BOP Head serves as an upper non-sealing wearsurface for the movement of the packing unit, making field repair fast and economical.

Flanged Steel Inserts In the Packing Unit reinforce the rubber and control rubber flowand extrusion for safer operation and longer packing unit life.

Greater Stripping Capability is inherent in the design of the packing unit since testing(fatigue) wear occurs on the outside and stripping wear occurs on the inside of thepacking unit. Thus, testing wear has virtually no affect on stripping capability andgreater overall life of the packing unit results. The resulting ability to strip the drillstringto the bottom without first changing the packing unit means a safer operation, loweroperating costs and longer service life for the packing unit.

The Packing Unit Is Tested to Full Rated Working Pressure at the factory and the testsare documented— before it reaches the well site—to ensure a safe, quality performance.

The Packing Unit Is Replaceable with Pipe In the Bore, which eliminates pulling thedrillstring for replacement and reduces operating expenses with more options for wellcontrol techniques.

Large Pressure Energised Seals are used for dynamically sealing piston chambers toprovide safe operation, long seal life, and less maintenance.

Piston Sealing Surfaces Protected by Operating Fluid lowers friction and protectsagainst galling and wear to increase seal life and reduce maintenance time.

6 - 42



BOP CLOSURE SEQUENCE

All Hydril Annular Blowout Preventers employ the same time-tested design forsealing off virtually anything in the BOP bore or the open hole.During normal wellbore operations, the BOP is kept fully open by leaving thepiston down. This position permits passage of tools, casing, and other items up tothe full bore size of the BOP as well as providing maximum annulus flow ofdrilling fluids. The BOP is maintained in the open position by application ofhydraulic pressure to the opening chamber, this ensures positive control of thepiston during drilling and reduces wear caused by vibration.(See Fig 6.2.4/A)

The packing unit is kept in compression throughout the sealing area, thusassuring a tough, v durable seal off against virtually any drill string shape—kelly,tool joint, pipe, or tubing to full rated working pressure. Application of openingchamber pressure returns the piston to the full down position allowing thepacking unit to return to full open bore through the natural resiliency of therubber.(See Fig 6.2.4/C)

The piston is raised by applying hydraulic pressure to the closing chamber. Thisraises the piston, which in turn squeezes the steel reinforced packing unit inward toa sealing engagement with the drill string. The closing pressure should beregulated with a separate pressure regulator valve for the annular BOP.Guidelines for closing pressures are contained in the applicable Operator’s Manual.(See Fig 6.2.4/B)



6 - 43

BOP CLOSURE SEQUENCE

Figure 6.2.4/B - CLOSURE SEQUENCE (PART CLOSED)

Figure 6.2.4/C - CLOSURE SEQUENCE (SEALED OFF)

Figure 6.2.4/A - CLOSURE SEQUENCE (OPEN)

6 - 44



Complete shut off (CSO) of the well bore is possible with all Hydril AnnularBOP’s. During CSO the flanges of the steel inserts form a solid ring to confine therubber and provide a safe seal off of the rated working pressure of the BOP. Thisfeature should be utilised only during well control situations, as it will reduce thelife of the packing unit.

STRIPPING OPERATIONS

Drill pipe can be rotated and tool joints stripped through a closed packing unit,while maintaining a full seal on the pipe. Longest packing unit life is obtained byadjusting the closing chamber pressure just low enough to maintain a seal on thedrill pipe with a slight amount of drilling fluid leakage as the tool joint passesthrough the packing unit. This leakage indicates the lowest usable closing pressurefor minimum packing unit wear and provides lubrication for the drill pipe motionthrough the packing unit.

The pressure regulator valve should be set to maintain the proper closing chamberpressure. If the pressure regulator valve cannot respond fast enough for effectivecontrol, an accumulator (surge absorber) should be installed in the closingchamber control line adjacent to the BOP—precharge the accumulator to 50% ofthe closing pressure required. In subsea operations, it is sometimes advisable toadd an accumulator to the opening chamber line to prevent undesirable pressurevariations with certain control system circuits

Figure 6.2.5



6 - 45

TYPE GL 5000 PSI ANNULAR BLOWOUT PREVENTERS PATENTED

Hydril GL Annular Blowout Preventers are designed and developed both forsubsea and surface operations. The GL family of BOPs represents the cumulationof evolutionary design and operator requirements. The proven packing unitprovides full closure at maximum working pressure on open hole or on virtuallyanything in the bore - casing, drill pipe, tool joints, kelly, or tubing.Features of the GL make it particularly desirable for subsea and deep well drilling.These drilling conditions demand long-life packing elements for drill pipestripping operations and frequent testing.The GL BOP offers the longest life packing unit for annular blowout preventersavailable in the industry today - especially for the combination of BOP testing andstripping pipe into or out of a well under pressure. The latched head permitsquick, positive head removal for packing unit replacement or other maintenancewith only minimum time required.The following outstanding features of the Hydril GL BOPs make these unitsparticularly qualified to meet the industry’s needs for simple and reliable blowoutprotection.The Secondary Chamber, which is unique to the GL BOP, provides this unit withgreat flexibility of control hookup and acts as a backup closing chamber to cutoperating costs and increase safety factors in critical situations. The chamber canbe connected four ways to optimise operations for different effects:

1. Minimise closing/opening fluid volumes.2. Reduce closing pressure.3. Automatically compensate (counter balance) for marine riser hydrostatic pressure effects in deep water.4. Operate as a secondary closing chamber.

Automatic Counter Balance can be achieved in subsea applications by selection ofone of the optional hookups of the secondary chamber.The Latched Head provides fast, positive access to the packing unit and seals forminimum maintenance time. The latching mechanism releases the head with a fewturns of the Jaw Operating Screws, while the entire mechanism remains inside theblowout preventer. There are no loose parts to be lost downhole or overboard.The Opening Chamber Head protects the opening chamber and preventsinadvertent contamination of the hydraulic system while the head is removed forpacking unit replacement.

6 - 46



Figu

re 6

.2.6

PIS

TO

N IN

DIC

AT

OR

HO

LE

WE

AR

PLA

TE

PA

CK

ING

UN

IT

LAT

CH

ED

HE

AD

OP

EN

ING

CH

AM

BE

R H

EA

D

OP

EN

ING

CH

AM

BE

RP

IST

ON

CH

AM

BE

R

CLO

SIN

G C

HA

MB

ER

SE

CO

ND

AR

Y C

HA

MB

ER

Cut

away

Vie

w o

f GL

BO

P s

how

n in

Mid

stro

ke.

5000

or

10,0

00 p

si b

otto

m c

onne

ctio

ns a

reav

aila

ble

in h

ub, A

PI

flang

ed, o

r st

udde

d co

nnec

tion.



6 - 47

Figure 6.2.7 GL 16 3/8" - 5000 PSI BLOWOUT PREVENTER

Item Part Name No Req'd Approx. NetNo. Single Weight lb.

BOP Assembly 1 28,400

1 BOP Head 1 6,641

2 "O" Ring 1 .75

3 "O" Ring 20 .06

4 Jaw Operating Screw 20 4

5 Sleeve Screw 20 .25

6 Spacer Sleeve 20 .25

7 Pipe Plug 20 .25

10 Jaw 20 12

11 Packing Unit - Natural 1 910

Packing Unit - Synthetic 1 920

12 Piston 1 5,380

13 Non-extrusion Ring, Middle 2 3

14 Double "U" Seal, Middle 1 3

15 Non-extrusion Ring, Lower 2 2

16 Double "U" Seal, Lower 1 2.5

17 Body 1 14,105

18 "O" Ring 1 .5

19 Capscrew 14 .75

20 Slotted Body Sleeve 1 300

21 Outer Body Sleeve 1 1180

22 Non-extrusion Ring, Inner 2 1

23 Double "U" Seal, Inner 1 2.3

24 Opening Chamber Head 1 839

27 "U" Seal 2 3

29 Head Gasket 1 2.5

32 Pull Down Bolt Assembly 4 1

33 Relief Fitting 1 .06

34 Pipe Plug 1 .06

Seal Set - Complete

ACCESSORIESChain Sling Assembly 1 202Eye Bolts, Piston (1"-8NC x 17" LG) 2 6Eye Bolts, Head (1 1/2"-6NC x 2" LG) 3 6.75Eye Bolts, Opening Chamber Head - (7/8"-9NC x 2 1/4" LG) 3 1Protector Plate 1 99Protector Plate Screw 4 .13

6 - 48



Figure 6.2.8

SE

CO

ND

AR

Y C

HA

MB

ER

conn

ecte

d to

OP

EN

ING

CH

AM

BE

R (

S -

O)

SE

CO

ND

AR

Y C

HA

MB

ER

conn

ecte

d to

CLO

SIN

G C

HA

MB

ER

(S

- C

)

SE

CO

ND

AR

Y C

HA

MB

ER

conn

ecte

d to

MA

RIN

E R

ISE

R (

CB

)

FIG

. 1F

IG. 2

FIG

. 3

CLO

SIN

G P

RE

SS

UR

EO

PE

NIN

G P

RE

SS

UR

E

Sta

ndar

d su

rfac

e ho

ok-u

p re

quire

s le

ast

fluid

so

give

s a

fast

er c

losi

ng ti

me.

Sub

sea

hook

-up

for

wat

er d

epth

s ov

er80

0 ft.

Sub

sea

hook

-up

for

wat

er d

epth

s up

to 8

00 ft

.

HY

DR

IL 'G

L'



6 - 49

Figure 6.2.9 CONTRACTOR PISTON

As the contractor piston is raised by hydraulic pressure, the rubber packing unit issqueezed inward to a sealing engagement with anything suspended in thewellbore. Compression of the rubber throughout the sealing area assured a seal-offagainst any shape.

differential area exposed to mud column

centre line

packing unit

operating piston

well pressure

well pressurearea

opening pressure

opening area

closing area

closing pressure

6 - 50



Figure 6.2.10

Operating pressure for Subsea Annular Preventers

(0.052 x Wm

x Dw

) - (0.45 x Dw

)Adjustment Pressure (∆P) = –––––––––––––––––––––––––––

pWhere:

Wm = drilling fluid density in lb./gal.Dw = water depth in feet0.052 = conversion factorp = 2.13 = the ratio of closing chamber area to

secondary chamber area for GL 16 3/4 - 5000.0.45 psi/ft. = pressure gradient for sea-water using a specific

gravity of sea water = 1.04 and 0.433 psi/ft.pressure gradient for fresh water.

The optimum closing pressure for the standard hookup is obtainedusing the following formula:

Closing Pressure = Surface Closing Pressure + Adjustment Pressure (∆P)

500

1000

1500

0 1000 2000 3000 4000 5000

CAUTION : Due to limiting properties of casing, closure shouldbe done carefully, using initial closing pressure to preventcollapse of casing.The closing pressures shown are initial closing pressures formost casing at O (zero) well pressure. Slightly higher closingpressure may be required for seal-offat higher well pressures.

WELL PRESSURE - PSI

Average Surface Closing Pressure(GL-16 3/4-5000 Standard Hook-up)

0

CSO

3 1/2" thru 7" Pipe

7 5/8" thru 13 3/8" Pipe

CLO

SIN

G P

RE

SS

UR

E -

PS

IS

EC

ON

DA

RY

CH

AM

BE

R C

ON

NE

CT

ED

TO

OP

EN

ING

CH

AM

BE

R

NOTE : Pressures shown areaverage. Actual pressurerequired to affect seal-off willvary slightly with eachindividual packing unit.



6 - 51

Operating Pressure for Accumulator Bottles

Example 1

3 1/2" - 7" pipe, 3500 psi well pressure, 16 lb./gal. drilling fluid, 500 ft. water depth.

Closing Pressure = Surface Closing Pressure + Adjustment Pressure (∆P)

From the Surface Closing Pressure graph Figure 6.5.13:

Surface Closing Pressure = 900 psi.

(0.052 x 16 Ib/gal x 500 ft) - (0.45 psi/ft x 500 ft)Adjustment Pressure (∆P) = –––––––––––––––––––––––––––––––––––––

2. 13

Adjustment Pressure (∆P) = 90 psi

Closing Pressure = 900 psi + 90 psi = 990 psi.

Pre-Charge Pressures - Surge Bottles

The pre-charge pressure for the closing chamber surge absorber can be calculated using thefollowing example:

Example 2

3 1/2" - 7" pipe, 500 feet water depth.

Precharge = 0.80 [Surface Closing Pressure + (0.41 x Dw

)]

Where:Dw = water depth in feet.

0.41 psi/ft. = pressure gradient for control fluid (water and watersoluble oil) using a specific gravity of the mixture= 0.95 and 0.433 psi/ft pressure gradient for fresh water.

Surface Closing Pressure = 600 psi.

Precharge = 0.80 [600 psi + (0.41 psi/ft. x 500 ft)]

= 644 psi.

6 - 52



Only packing elements which are supplied by the manufacturer of the annularpreventer should be used. New or repaired units obtained from other servicecompanies should not be used since the preventer manufacturers cannot be heldresponsible for malfunction of their equipment unless their elements are installed.

Figure 6.2.11 Packing unit selection (from Hydril)

IDENTIFICATIONPACKING UNIT OPERATING DRILLING FLUID

TYPE Colour Code TEMP RANGE COMPATIBILITY

NATURAL Black NR -30°F – 225°F Waterbase FluidRUBBER

NITRILE Red NBR 20°F – 190°F Oil base/OilRUBBER Band Additive Fluid

NEOPRENE Green CR -30°F – 170°F Oil Base FluidRUBBER Band

Figure 6.2.12 Annular Preventers - Gallons of Fluid Required to Operate on Open Hole

Size and Hydril NL Shaffer

Working Pressure GK GL Spherical

Inches psi Close Open Close Open Balancing Close Open6 3,000 2.9 2.2 4.6 3.26 5,000 3.9 3.3 4.6 3.2

7 1/16 10,000 9.48 3,000 4.4 3.0 7.2 5.08 5,000 6.8 5.8 11.1 8.710 3,000 7.5 5.6 11.0 6.810 5,000 9.8 8.0 18.7 14.611 5,00011 10,000 25.112 3,000 11.4 9.8 23.5 14.7

13 5/8 3,00013 5/8 5,000 18.0 14.2 19.8 19.8 8.2 23.6 17.413 5/8 10,000 34.5 24.3 47.2 37.6

16 2,000 17.5 12.616 3,000 21.0 14.8

16 3/4 3,00016 3/4 5,000 28.7 19.9 33.8 33.8 17.3 33.0 25.616 3/4 10,000

18 2,000 21.1 14.418 3/4 5,000 44.0 44.0 20.0 48.2 37.6

20 2,000 32.6 17.020 3,00020 5,000 58.0 58.0 29.5 61.4 47.830 1,00030 2,000



6 - 53

SPHERICAL BLOWOUT PREVENTERS

Shaffer Spherical blowout preventers are compact, annular type BOP’s whichreliably seal on almost any shape or size—kellys, drill pipe, tool joints, drill collars,casing or wireline. Sphericals also provide positive pressure control for strippingdrill pipe into and out of

the hole. They are available in bolted cover, wedge cover and dual wedge covermodels. There are also special lightweight models for airlifting and Arctic modelsfor low temperature service.

Figure 6.2.13 SHAFFER ANNULAR

6 - 54




INSTALLATION

A blowout preventer operating and control system is required to actuate theSpherical BOP. Several systems are available and those commonly used on drillingrigs work well. The recommended installation requires:

1. A control line to the closing (lower) port.

2. For stripping, an accumulator bottle in the closing line adjacent to the BOP. Thisbottle should be precharged to 500 psi for surface installations and to 500 psiplus 45 psi per 100' of water depth for subsea installations.

3. control line to the opening (upper) port.

4. A hydraulic regulator to allow adjustment of operating pressure to meet anygiven situation.

The hydraulic operating fluid should be hydraulic oil with a viscosity between 200and 300 SSU at 100°F If necessary, a water-soluble oil such as Koomey K-90 andwater can be used for environmental protection. If equipment is exposed tofreezing temperatures, ethylene glycol must be added to the K-90 and watersolution for freeze protection.

NOTE: Some water-soluble systems will corrode the metals used in BOP’s. Ifwater-soluble oil is used, the user should ensure that it provides adequatelubrication and corrosion protection.

Figure 6.2.14

Accumulator bottle

(1-gal. capacity for 1 1/16" - 10,00 psi bolted-cover model;5-gal. capacity for all other bolted-cover models and 13 5/8"-5,000 psi wedge-cover model;10-gal. capacity for all other wedge-cover models)

Opening line

Closing lineHydraulic

unit

Installation hookup for single Spherical BOP

Accumulatorbottles

Opening line

Closing line

Opening line

Closing line Station1 Station 2 Hydraulic unit

Installation hookup for dual Spherical BOP



6 - 55


OPERATING REQUIREMENTS

Sphericals have relatively simple operating requirements compared to otherannulars. When closing on stationary pipe, 1,500 psi operating pressure issufficient in most applications. Recommended closing pressures for specificapplications are given in the table at the bottom of the page.

Closing action begins when hydraulic fluid is pumped into the closing chamber ofthe Spherical BOP below the piston (upper right). As the piston rises, it pushes theelement up, and the element’s spherical shape causes it to close in at the top as itmoves upward.

The element seals around the drill string as the piston continues to rise (middleright). Steel segments in the element move into the well bore to support the rubberas it contains the well pressure below.

When there is no pipe in the preventer, continued upward movement of the pistonforces the element to seal across the open bore (lower right). At complete shutoff,the steel segments provide ample support for the top portion of the rubber. Thisprevents the rubber from flowing or extruding excessively when confining highwell pressure.

STRIPPING OPERATIONS

Stripping operations are undoubtedly the most severe application for anypreventer because of the wear the sealing element is exposed to as the drill stringis moved through the preventer under pressure. To prolong sealing element life, itis important to use proper operating procedures when stripping. Therecommended procedures are:

1. Close the preventer with 1,500 psi closing pressure.

2. Just prior to commencing stripping operations, reduce closing pressure to avalue sufficient to allow a slight leak.

3. If conditions allow, stripping should be done with a slight leak to providelubrication and prevent

excessive temperature buildup in the element. As the sealing element wears, the,closing pressure will need to be incrementally increased to prevent excessiveleakage.

6 - 56



Figure 6.2.15



6 - 57

6.3 DIVERTERS

Figure 6.3.1 Typical Diverter System Installed on a Floating Rig

PRESSURE

RELAX

ADJUST

DIVERTER ELEMENT

PORT VENT

CLOSED

OPEN

RETURNS TO SHAKER

OPEN

CLOSED

UNLOCK

DIVERTER INSERT

LOCK

STARBOARDVENT

CLOSED

OPEN

LOWER PACKINGELEMENT CLOSEDWHEN DIVERTERIS OPERATED

UPPER "WORKING"PACKING ELEMENT

PRESSURE BELOWDIVERTER BAG

SLIP JOINTANNULUSPRESSURE

SLIP JOINTUPPER ELEMENT

BLEEDADJUST

RIG AIR

SLIP JOINTUPPER ELEMENT

ADJUST

RELAX

PRESSURIZE

6 - 58



Typical Operating Pressures

The diverter packer regulator will provide a maximum pressure of 1200 psi on thepacker.

For normal pressure use 750 psi.

The manifold pressure regulator provides a maximum pressure of 1650 psi.

For insert packer lock down dogs. Diverter lock down dogs etc.

For normal operation do not exceed 1250 psi.

Recommended pressure settings generally are:

Hydraulic supply pressure 3000 psiManifold pressure 1250 psiDiverter packer pressure 750 psi



6 - 59

Figure 6.3.2 Hydril FSP 28-2000 Diverter/BOP System Hydraulic Schematic

OPEN

CLOSE

DIVERTER/BOP

5 GALLONACCUMULATOR

REGULATEDHYDRAULIC

SUPPLY

BELL NIPPLELATCH

LATCH

UNLATCH

PUSH AND HOLDTO UNLATCH

REGULATEDHYDRAULIC

SUPPLY

HANDLING/TESTTOOL

LATCH

UNLATCH

HOSE BUNDLE

PORT

STBD

SELECTOR

PORT

AUTOMATIC OPENINGTO DIVERTER LINES

AS BAG CLOSES.

CERAMIC LINED

6 - 60



If an Annular Sequencing Device which requires lockdown of an insert packer is inuse, the lockdown function should be included in the automatic sequencing.

Figure 6.3.3

CLOSE

DIVERTERCLOSE

DIVERTEROPEN

VENTVALVEACTUATOR

FLOWLINEVALVEACTUATOR

ANNULARSEALINGDEVICE

CLOSE

OPEN

DIVERTED ANNULARSEALING DEVICEOPERATING PRESSURE

VALVEOPERATINGPRESSURE

CLOSE

OPEN

OPEN



6 - 61

Figure 6.3.4

DERRICK FLOOR

BELL NIPPLE

FLOW LINE

INSERT TYPE PACKER

HYDRAULIC VALVE OPERATOR

BLEED-OFF LINE

VALVE

HEAVE COMPENSATOR LINE

INNER BARREL OF TELESCOPING JOINT

SEA LEVEL

OUTER BARREL OF TELESCOPING JOINT

RISER COUPLING

FLEXIBLE JOINT

GUIDE FRAME

HYDRAULIC LATCH

PERMANENT GUIDE BASE

TEMPORARY GUIDE BASE

When drilling surface hole from a template the cuttings are returned to surfacefor disposal to avoid spool build up on the template.

6 - 62



Figure 6.3.5

Sub-sea diverting stack (template operations).

21 in HST RISERCOUPLING PIN

MUD BOOST LINECONNECTION

21 1/4 in – 2000 MSPANNU-FLEX

FLEX JOINT

ANNULAR BOP

21in HYDRAULICCONNECTOR

21 1/4 in – 2000SHEAR RAM

OUTLET NOZZLE(S)

21 1/4 in – 2000FSS SPOOL

BLIND FLANGE

C K VALVE

30 in LATCH



6 - 63

Figure 6.3.6 (SURFACE DIVERTER)

6 - 64



Figure 6.3.7 (MSP DIVERTER/BOP)



6 - 65

Figure 6.3.8

PIL

OT

CO

NT

RO

L L

INE

TO D

RIL

LIN

G C

ON

SO

LE

AC

CU

MU

LA

TOR

BA

NK R

EG

UL

AT

ED

HY

DR

UA

LIC

SU

PP

LY

VE

NT

Ris

erG

PLG

Ris

erG

PLG

Ris

erG

PLG

Ris

erD

iver

ter

TO S

HA

LE

SH

AK

ER

MU

D P

UM

P

RIG

FL

OO

R

Bel

lN

ippl

eD

iver

ter

Upp

erFl

exJo

int

VE

NT

MU

D G

AS

SE

PE

RR

TOR

FR

OM

DR

ILL

ING

CH

OK

E M

AN

IFO

LD

RIS

ER

DIV

ER

TE

R M

AN

IFO

LD

(NE

AR

DR

ILL

ING

MA

NIF

OL

D)

12"Ø

BE

LL

NIP

PL

E D

IVE

RT

ER

OV

ER

BO

AR

D L

INE

6"Ø

RIS

ER

DIV

ER

TE

R O

VE

RB

OA

RD

LIN

E

RIS

ER

CH

OK

E L

INE

OP

EN

CO

NT

RO

L L

INE

CL

OS

E C

ON

TR

OL

LIN

E

QU

ICK

CO

NN

EC

TC

OU

PL

ING

6" D

RA

PE

HO

SE

CH

OK

E D

RA

PE

HO

SE

KIL

L D

RA

PE

HO

SE

RIS

ER

DIV

ER

TE

RJO

INT

RIS

ER

BO

OS

T L

INE

OU

TE

RB

AR

RE

L

TE

LE

SC

OP

IC J

OIN

T

INN

ER

BA

RR

EL

MO

ON

PO

OL

16"Ø

6"Ø

6"Ø

3"Ø

3"C

HO

KE

3"Ø

6"Ø

12"Ø

6"Ø

6 - 66



Figure 6.3.9 HYDRIL ANNULAR PREVENTER - TYPE “MSP” - 2000 PSI

Operating Features:

1. Will close on open hole and hold 2000 psi (but not recommended).

2. Primary usage is in diverter systems.

3. Automatically returns to the open position when closing is released.

4. Sealing assistance is gained from the well pressure.

5. Greater stripping capability of the packing unit since (fatigue) wear occurson the outside of the packing unit.



6 - 67

ROTATING HEADS

When used, rotating heads are installed above the BOP stack. They provide a sealon the kelly or drillpipe. A drive unit, attached to the kelly, locates in a bearingassembly above the stripper rubber.

Some applications for rotating heads are:

• Drilling with air or gas, to divert the returns through a "Blooey line".

• To permit drilling with underbalanced mud, by maintaining a back pressureon the wellbore.

• As a diverter for surface hole.

• To keep gas away from the rotary table. This is especially important whereHydrogen Sulphide can be expected.

Realistic working pressures for rotating heads are 500 to 700 psi. It isrecommended that they are not installed for routine gas cap drilling (unless sourgas is expected) since their use precludes observation from the rig floor of annulusfluid level.

Figure 6.3.10

KELLY BUSHING

DRIVE BUSHINGASSEMBLY

SWING-BOLTCLAMP ASSEMBLY

SHOCK PAD

BOWL

STRIPPER RUBBER

DRIVE RING ANDBEARING ASSEMBLY

OUTLET FLANGE

INLET FLANGE

6 - 68



6.4 GASKETS, SEALS AND WELLHEADS

API Type 'R' Ring Joint Gasket

The type ‘R’ ring joint gasket is not energised by internal pressure. Sealing takesplace along small bands of contact between the grooves and the gasket, on boththe OD and ID of the gasket. The gasket may be either octagonal or oval in crosssection. The type ‘R’ design does not allow face-to-face contact between the hubsor flanges, so external loads are transmitted through the sealing surfaces of thering. Vibration and external loads may cause the small bands of contact betweenthe ring and the ring grooves to deform the plastic, so that the joint may develop aleak unless the flange bolting is periodically tightened. Standard procedure withtype ‘R’ joints in the BOP stack is to tighten the flange bolting weekly.

Figure 6.4.1 Figure 6..4.2

CL CL

ENERGISED



6 - 69

Figure 6.4.3

6 - 70



API Type 'RX' Pressure-Energised Ring Joint Gasket

The ‘RX’ pressure-energised ring joint gasket was developed by Cameron IronWorks and adopted by API. Sealing takes place along small bands of contactbetween the grooves and the OD of the gasket. The gasket is made slightly largerin diameter than the grooves, and is compressed slightly to achieve initial sealingas the joint is tightened. The ‘RX’ design does not allow face-to-face contactbetween the hubs or flanges. However, the gasket has large load-bearing surfaceson the inside diameter, to transmit external loads without plastic deformation ofthe sealing surfaces of the gasket. It is recommended that a new gasket be usedeach time the joint is made up.

Figure 6.4.4 Figure 6.4.5CL CL

ENERGISED



6 - 71

API Type 'BX' Pressure-Energised Ring Joint Gasket

Sealing takes place along small bands of contact between the grooves and the ODof the gasket. The gasket is made slightly larger in diameter than the grooves, andis compressed slightly to achieve initial sealing as the joint is tightened.Although the intent of the ‘BX’ design was face-to-face contact between the hubsand flanges, the groove and gasket tolerances which are adopted are such that, ifthe ring dimension is on the high side of the tolerance range and the groovedimension is on the low side of the tolerance range, face-to-face contact may bevery difficult to achieve. Without face-to-face contact, vibration and external loadscan cause plastic deformation of the ring, eventually resulting in leaks. Bothflanged and clamp hub ‘BX’ joints are equally prone to this difficulty. The ‘BX’gasket frequently is manufactured with axial holes to ensure pressure balance,since both the ID and the OD of the gasket may contact the grooves.

In practice, the face-to-face contact between hubs or flanges is seldom achieved.

Figure 6.4.6 Figure 6.4.7 Figure 6.4.8

CL CL CL

ENERGISED

6 - 72



API Face-to-Face Type ‘RX’ Pressure-Energised Ring Joint Gasket

The face-to-face ‘RX’ pressure-energised ring joint gasket was adopted by API asthe standard joint for clamp hubs. Sealing takes place along small bands of contactbetween the grooves and the OD of the gasket. The gasket is made slightly largerin diameter than the grooves, and is compressed slightly to achieve initial sealingas the joint is tightened. Face-to-face contact between the hubs is ensured by anincreased groove width, but this leaves the gasket unsupported on it’s ID. Withoutsupport from the ID of the grooves, the gasket may not remain perfectly round asthe joint is tightened. If the gasket buckles or develops flats, the joint may leak.

This type of gasket has not been accepted by the industry and is seldom used.

Figure 6.4.9 Figure 6.4.10

CL

ENERGISED

CL



6 - 73

‘CIW’ Type ‘RX’ Pressure-Energised Ring Joint Groove

CIW modified the API face-to-face type ‘RX’ pressure-energised ring joint groovesto prevent any possible leaking caused by the buckling of the gasket in the APIgroove. The same API face-to-face type ‘RX’ pressure energised ring joint gasketsare used with these modified grooves. Sealing takes place along small bands ofcontact between the grooves and the OD of the gasket. The gasket is made slightlylarger in diameter than the grooves, and is compressed slightly to achieve initialsealing as the joint is tightened. The gasket ID will also contact the grooves when itis made up. This constraint of the gasket prevents any possible leaking caused bythe buckling of the gasket. Hub face-to-face contact is maintained within certaintolerances. The maximum theoretical stand-off from the stack-up of the tolerancesof the gasket and the groove is 0.022 inches.

Face-to-face contact cannot be assured with this ring/groove combination. Thisring is seldom found in use. The ‘CX’ ring accomplishes the intent of the ‘RX’ face-to-face design.


6 - 74



Type 'AX' and 'VX' Pressure-Energised Ring Joint Gasket

The ‘AX’ pressure-energised ring joint gasket was developed by Cameron IronWorks. The ‘VX’ ring was developed by Vetco.

Sealing takes place along small bands of contact between the grooves and the ODof the gasket. The gasket is made slightly larger in diameter than the grooves, andis compressed slightly to achieve initial sealing as the joint is tightened. The ID ofthe gasket is smooth and is almost flush with the hub bore. Sealing occurs at adiameter which is only slightly greater than the diameter of the hub bore, so theaxial pressure load on the connector is held to an absolute minimum. The belt atthe centre of the gasket keeps it from buckling or cocking as the joint is beingmade up. The OD of the gasket is grooved. This allows the use of retractable pinsor dogs to positively retain the gasket in the base of the wellhead or riserconnector when the hubs are separated. The gasket design allows face-to-facecontact between the hubs to be achieved with minimal clamping force. Externalloads are transmitted entirely through the hub faces and cannot damage thegasket.


ENERGISED



6 - 75

‘CIW’ Type ‘CX’ Pressure-Energised Ring Joint Gasket

The ‘CX’ pressure-energised ring joint gasket was developed by Cameron IronWorks. Sealing takes place along small bands of contact between the grooves andthe OD of the gasket. The gasket is made slightly larger in diameter than thegrooves, and is compressed slightly to achieve initial sealing as the joint istightened. The gasket is patterned after the ‘AX’ and ‘VX’ gasket, but is recessed,rather than being flush with the well bore, for protection against keyseating.The gasket seals on approximately the same diameter as do the ‘RX’ and ‘BX’gaskets. The belt at the centre of the gasket keeps it from buckling or cocking asthe joint is being made up. Since the ‘CX’ gasket is protected from keyseating, it issuitable for use through the BOP and riser system, except at the base of thewellhead and riser connectors. The gasket design allows face-to-face contactbetween the clamp hubs or flanges to be achieved with minimal clamping force.External loads are transmitted entirely through the hub faces and cannot damagethe gasket.


ENERGISED

6 - 76



Application of Type 'AX', 'VX' and 'CX' Pressure-Energised Ring Joint Gaskets

The ‘AX’, ‘VX’ and ‘CX’ face-to-face pressure-energised ring gaskets allow face-to-face contact between the hubs to be achieved with minimal clamping force. The‘AX’ and ‘VX’ gasket is used at the base of the wellhead and riser connector whenthe hubs are separated. The ‘AX’/’VX’ design ensures that axial pressure loadingon the connector is held to an absolute minimum. The ‘AX’ gasket also is suitablefor side outlets on the BOP stack, since these outlets are not subject to keyseating.The ‘CX’ gasket is recessed for protection against keyseating. The ‘CX’ gasket issuitable for use throughout the BOP and riser system, except at the base of thewellhead and riser connector.

Figure 6.4.17 HYDRIL DRILLING SPOOL DATA



6 - 77

Figure 6.4.18

6 - 78



Figure 6.4.19



6 - 79

Figure 6.4.20 SPECIFICATIONS FOR BOP FLANGES, RING GASKETS, FLANGEBOLTS AND NUTS

RA

TIN

G O

F B

OP

AP

PR

OV

ED

*M

AX

IMU

M B

OLT

**

MIN

IMU

M N

UT

S

TAC

KA

PP

RO

VE

D F

LA

NG

ES

RIN

G G

AS

KE

TS

S

TR

EN

GT

H S

TR

EN

GT

H

2000

psi

wp

AP

I Typ

e 6B

with

A

PI T

ype

AS

TM

Gra

deA

ST

M G

rade

and

3000

psi

wp

Type

R F

lat B

otto

m

RX

B-7

2H

Inst

alla

tions

Gro

ove

5000

psi

wp

AP

I Typ

e 6B

with

AP

I Typ

e R

X o

rA

ST

M G

rade

AS

ME

Gra

deIn

stal

latio

nsTy

pe R

Fla

t Bot

tom

AP

I Typ

e B

X w

p

B

-7

2

-HG

roov

e or

AP

I Typ

eTy

pe 6

BX

Fla

nge

6BX

w/T

ype

BX

Gro

ove

10,0

00 p

si w

pA

PI T

ype

6BX

with

AP

I Typ

eA

ST

M G

rade

AS

TM

Gra

dIn

stal

latio

nsTy

pe B

X G

roov

e

BX

B-7

2-H

All

blow

out p

reve

nter

s, d

rillin

g sp

ools

, ada

pter

flan

ges

will

be

furn

ishe

d w

ith th

e sp

ecifi

c A

PI r

ing

join

t fla

nge

equ

ipm

ent l

iste

d be

low

:

*A

ccep

tabl

e m

ater

ial f

or fl

ange

rin

g ga

sket

s as

per

AP

I Spe

c 6A

, "W

ellh

ead

Equ

ipm

ent"

.

Sw

eet O

il-

Low

Car

bon

Ste

el

Sou

r O

il or

Gas

-Ty

pe 3

16 s

tain

less

ste

el p

refe

rred

but

Typ

e 30

4 st

ainl

ess

stee

l acc

epta

ble

exce

ptfo

r hi

gh r

isk

H2S

wel

ls.

**In

som

e H

2S a

pplic

atio

ns, A

ST

M A

-193

Gr

B/M

with

a m

axim

um R

ockw

ell h

ardn

ess

of 2

2 m

ay b

e ac

cept

able

.If

used

, fla

nges

sho

uld

be d

erat

ed p

er T

able

1.4

B o

f AP

I 6A

.

6 - 80



6.5 MANIFOLDS, VALVES, SEPARATORS AND FLOW GAIN SENSORS

1. MUD CONTROL AND MONITORING EQUIPMENT

Correct installation and operation of this equipment is fundamental to effectiveprimary and secondary well control. The following are the most important aspects:

a) Pit Volume Measurement

A pit volume totalising (PVT) should be provided. A calibrated read-out andaudio alarm should be installed at the Driller’s station.

The following measurement devices are required for all tanks:

• A float for the PVT system, to isolate other floats when the trip tank is in use.

• An internal calibrated ladder-type scale.

• A remote ladder-type scale, visible from the Driller’s station for the trip tank.

• A small wireline can be used to connect a float in the tank to the scale on therig floor.

b) Flow line Measurement

A device should be provided for measurement of flow line and mud return rate.This (Flo Show) device should have a read-out and alarm at the Driller’s station.

c) Trip Tank

Trip tanks are used to fill the hole on trips, measure mud or water into the annuluswhen circulation has been lost, monitor the hole when tripping, logging or othersimilar type operations. There are two basic types of trip tanks - gravity feed andpump. The pump type system is better because it provides for safer and moreexpedient trip operation. The trip tank would be isolated from the surface mudsystem to prevent inadvertent loss or gain of mud from the trip tank due to valvesbeing left open.

In the past, many blowouts occurred due to swabbing or not keeping the holefilled while tripping the drill string out of the hole. To provide exact fluidmeasurements for pipe displacement, trip tanks were developed to accuratelymeasure within ± 1.0 barrel the influx or efflux of fluid from the wellbore. As thedrill string is pulled from the hole, the mud level will drop due to the volume ofmetal being removed. If mud is not added to the hole as pipe is pulled, it ispossible to reduce hydrostatic pressure to less than formation pressure. When thishappens, a kick will occur. Swabbing can occur when pipe is pulled too fast andfriction between the pipe and the mud column causes a reduction in hydrostaticpressure to a valve less than formation pressure.



6 - 81

Figure 6.5.1

Figure 6.5.2CL

ENERGISED

10

20

3040 50 60

7080

90

1000 %RETURN

MUDFLOW

HIADJUST

LOADJUST

LOFLOW

HIFLOW

ON2 AMP

SMOOTHINGLO

MED HI

RECORDERRETURN

WARNING

RETURNFLOWHI-LO

WARNING

FLOWSENSOR115 VAC

REMOTEINDICCTOR

HORN

WARNINGLIGHTS(Optional)

FROM MVT4RETURN MUDFLOW SYSTEM (Optional)

115VAC

H1240 WARNING SYSTEM

LINE

MFT2 MUD FLOW SENSOR

MUDFLOO

MFS 3 - Series RETURN MUD FLOW SYSTEM

MFR2 or MFRE2RECORDER(Optional)

MFC3 CONTROL CONSOLE

6 - 82



To prevent loss of hydrostatic pressure it is necessary to fill the hole on a regularschedule, or continuously, using a trip tank to keep the track of the fluid volumerequired. The metal volume of the pipe being pulled can be calculated, but mudadditions necessary to replace hole seepage losses due to filtration effects can onlybe predicted by comparison with the mud volumes required to keep the holeproperly filled on previous trips. For this reason, it is import that a record of mudvolume required, versus number of stands pulled be maintained on the rig in atrip book for every trip made.

Typical Trip Tank Hook-up - On A Floating Rig

As illustrated in Figure 6.5.3, a centrifugal pump takes suction from the trip tankand fills the hole through a line into the bell nipple. The pump runs constantlywhile the drill string is pulled from the hole. The hole stays full as each stand ofpipe is pulled and excess mud returns to the trip tank through an outlet on themain flow line. A valve must be installed in the flow line downstream of thisoutlet to block all flow to the shale shakers while making a trip. A closedcirculation system can be monitored by a float system and a digital read-out in1-barrel increments on the Driller’s console.

Mud Gas Separator

The separator is installed downstream of the choke manifold to separate gas fromthe drilling fluid. This provides a means of safely venting the gas and returningusable liquid mud to the active system.

There are two types of mud gas separators: Atmospheric and Pressurised.

• The atmospheric type separator is standard equipment on nearly all rigs andis referred to in the field as a ‘gas buster’ or ‘poorboy' separator. The mainadvantage of this type of separator is its operational simplicity which doesnot require control valves on either the gas or mud discharge lines.

• A pressurised mud gas separator is designed to operate with moderate backpressure, generally 50 psi or less. Pressurised separators are utilised toovercome line pressure losses when an excessive length of vent line isrequired to safely flare and burn the hazardous gas an extended distancefrom the rig. The pressurised separator is considered special rig equipmentand may not be provided by the contractor. This type of separator is installedon rigs drilling in high risk H2S areas and for drilling underbalanced in areaswhere high pressure, low volume gas continually feeds into the circulatingfluid.



6 - 83

During well control operations, the main purpose of a mud gas separator is to ventthe gas and save the drilling fluid. This is important not only for economicreasons, but also to minimise the risk of circulating out a gas kick without havingto shut down to mix additional mud volume. In some situations the amount ofmud lost can be critical when surface volume is marginal and on-site mudsupplies are limited. When a gas kick is properly shut in and circulated out, themud gas separator should be capable of saving most of the mud.

There are a number of design features which affect the volume of gas and fluidthat the separator can safely handle. For production operations, gas oil separatorscan be sized and internally designed to efficiently separate gas from the fluid.This is possible because the fluid and gas characteristics are known and designflow rates can be readily established. It is apparent that ‘gas busters’ for drillingrigs cannot be designed on the same basis since the properties of circulated fluidsfrom gas kicks are unpredictable and a wide range of mixing conditions occurdownhole. In addition, mud rheological properties vary widely and have a strongeffect on gas environment. For both practical and cost reasons, rig mud gasseparators are not designed for maximum possible gas release rates which mightbe needed; however, they should handle most kicks when recommended shut-inprocedures and well control practices are followed. When gas low rates exceed theseparator capacity, the flow must be bypassed around the separator directly to theflare line. This will prevent the hazardous situation of blowing the liquid from thebottom of the separator and discharging gas into the mud system.

Figure 6.5.4 illustrates the basic design features for atmospheric mud gasseparators. Since most drilling rigs have their own separator designs, the DrillingSupervisor must analyse and compare the contractor’s equipment with therecommended design to ensure the essential requirements are met.

The atmospheric type separator operates on the gravity or hydrostatic pressureprinciple. The essential design features are:

• Height and diameter of separator.

• Internal baffle arrangement to assist in additional gas break-out.

• Diameter and length of gas outlet.

• A target plate to minimise erosion where inlet mud gas mixture contacts theinternal wall of the separator, which provides a method of inspecting platewear.

• A U-tube arrangement properly sized to maintain a fluid head in theseparator.

6 - 84



Figure 6.5.3

Figure 6.5.4 An Example Mud Gas Separator

ROTARY TABLE

DIVERTER

RIG FLOORTRIP TANKLEVELINDICATOR

HOLE FILLUP LINE

FLOWLINE

TELESCOPICJOINN

RISER

CHECK

ALVE

TRIP TANK PUMPDRAIN

FROMMISSION PUMPS

RETURNS TOSHAKERS

OVERBOARD

REMOTECONTROL VALVE

GAS OUTLET8" ID MINIMUM

GAS BACK PRESSUREREGISTERED ATTHIS GAUGE(Typically 0 to 20 psi)

INSPECTIONCOVER

STEELTARGET PLATE

INLET

30" OD

SECTION A-ATANGENTIAL INLET

4" ID INLET-TANGENTIAL TO SHELLFROM CHOKE MANIFOLD

HALF CIRCLE BAFFLES ARRANGEDIN A 'SPIRAL' CORFIGURATION

BRACE

A

TO SHAKER HEADER TANK

MAXIMUM HEAD AVAILABLEDEVELOPED BY THIS HEIGHTOF FLUIDeg 10 foot HEAD AT 1.5 SG GIVES 6.5 psi MAXIMUM CAPACITY

8" NOMINAL 'U' TUBE

2" DRAIN OR FLUSH LINE4" CLEAN-OUT PLUG

10' A

PP

RO

X

INSPECTIONCOVER

A

AP

PR

OX

1/2

OF

HE

IGH

T

10' M

INIM

UM

HE

IGH

T



6 - 85

The height and diameter of an atmospheric separator are critical dimensionswhich affect the volume of gas and fluid the separator can efficiently handle.As the mud and gas mixture enters the separator, the operating pressure isatmospheric plus pressure due to friction in the gas vent line. The vertical distancefrom the inlet to the static fluid level allows time for additional gas break-out andprovides an allowance for the fluid to rise somewhat during operation toovercome friction loss in the mud outlet lines. As shown in Figure 6.5.4, thegas-fluid inlet should be located approximately at the midpoint of the verticalheight. This provides the top half for a gas chamber and the bottom half for gasseparation and fluid retention. The 30 in. diameter and 16 ft minimum vesselheight requirements have proven adequate to handle the majority of gas kicks. Theseparator inlet should have at least the same ID as the largest line from the chokemanifold, which is usually 4 in. Some separators use tangential inlet, which createsa small centrifugal effect on the gas-fluid mixture and causes faster gas break-out.

The baffle system causes the mud to flow in thin sheets which assists theseparation process. There are numerous arrangements and shapes of baffles used.It is important that each plate be securely welded to the body of the separator withangle braces.

A 8 in. minimum ID gas outlet is usually recommended to allow a large volume oflow pressure gas to be released from the separator with minimum restriction.Care should be taken to ensure minimum back pressure in the vent line. On mostoffshore rigs, the vent line is extended straight up and supported to a derrick leg.The ideal line would be restricted to 30 ft in length and the top of the line shouldbe bent outward about 30 degrees to direct gas flow away from the rig floor. If it isintended that the gas be flared, flame arresters should be installed at the dischargeend of the vent line.

As stated previously, when the gas pressure in the separator exceeds thehydrostatic head of the mud in the U-tube, the fluid seal in the bottom is lost andgas starts flowing into the mud system. The mud outlet downstream of the U-tubeshould be designed to maintain a minimum vessel fluid level of approximately3 1/2 ft in a 16 ft high separator. Assuming a 9.8 ppg mud and total U-tube heightof 10 ft, the fluid seal would have a hydrostatic pressure equal to 5.096 psi. Thispoints out the importance for providing a large diameter gas vent line with thefewest possible turns to minimise line frictional losses.

The mud outlet line must be designed to handle viscous, contaminated mudreturns. As shown in Figure 6.5.4 an 8 in. line is recommended to minimisefrictional losses. This line usually discharges into the mud ditch in order that goodmud can be directed over the shakers and untreatable mud routed to the waste pit.

6 - 86



Degassers

If a fluid's viscosity does not allow gas to break out completely, a degasser mayalso be used. A degasser is not designed to handle large volumes of gas, becausethe volume of gas actually entrained in the fluid is small. Degassers separateentrained gas from fluid using a vacuum chamber, a pressurised chamber, acentrifugal spray, or a combination. The most commonly used degassers arevacuum tanks and centrifugal pump sprayers, but many others are available.

Properly maintaining degassers is not difficult. Primarily, it is a matter of correctlylubricating any pumps used in the system. In degassers that employ a float arm,joints must be kept lubricated. When a vacuum pump is used, the water knockoutahead of the compressor must be emptied daily.

In general, vacuum degassers are very effective with heavy, viscous muds fromwhich it is difficult to extract gas with a separator alone. In any degassingoperation, residence time and extraction energy requirements are increased asmud viscosity and gel strength increases.

Figure 6.5.5

FLARE LINE

SUCTIONDISCHARGE



6 - 87

Choke Manifolds

The choke manifold is an arrangement of valves, fittings, lines and chokes whichprovide several flow routes to control the flow of mud, gas and oil from theannulus during a kick.

Figure 6.5.6

Figure 6.5.7

P

P

2"

2"

2"

2"

Adjustable choke

To pit and/or mud/gasseparators

Bleed line

To mud/gas separatorand/or pit

Remotely operatedor adjustable choke

P To pit

2" Nominal

4" Nominal3" NominalSequenceOptional

Blowout PreventerStack Outlet

2" Nominal

Typical Choke Manifold for 5,000 psiWorking Pressure Service-Surface Installation

RemotelyOperated

Valve

P

P

CHOKELINE

2"

2"

2"

2"

2"

Remotely operated choke

To mud/gas separatorsand/or pit

To pit

Bleed line

To mud/gas separatorand/or pit

Remotely operated choke

Adjustable Choke

P To pit

2" Nominal

2" Nominal

4" Nominal3" NominalSequenceOptional

Remotely Operated Valve

Blowout PreventerStack Outlet

2" Nominal

Typical Choke Manifold for 10,000 psi and 15,000 psiWorking Pressure Service-Surface Installation

6 - 88



Figure 6.5.8

BURNING LINE(PRODUCTION GAS SEPARATOR

OFFSHORE RIGS)

1. 10,000 psi gate valves.2. 5,000 psi gate valves.3. Remote controlled chokes.4. Manually adjusted chokes.

FROM DSTCHOKE MANIFOLD

DST LINE

KILL ORSECONDARYCHOKE LINE

MANIFOLD CHOKE LINE

TO GAUGE

CHOKE BYPASS LINE

PRIMARYCHOKE LINE

FROM KILLPUMP

RESERVE PIT(DERRICK FLAREOFFSHORE RIGS)

BUFFER CHAMBER

BYPASS TOPOORBOY DEGASSER

OR TRIP TANKTO POORBOY

DEGASSERTO MUD

PITS

BOP STACK

4

31

1 1

1

13

1

4

2

2

2

2

2

2

11



6 - 89

SPECIFICATION 1 13/16" THRU 2 9/16", 10,000 PSI


10,000 lb Working Pressure (Inches)

Size WP A B C D E Wt No of Turnsto Open

1 13/16" 10,000 1 13/16 18 1/4 5 11/16 18 5/8 8 206 12 1/2

2 1/16" 10,000 2 1/16 20 1/2 5 11/16 18 5/8 9 3/4 218 13 1/2

2 9/16" 10,000 2 9/16 22 1/4 6 7/8 19 1/2 9 3/4 292 16

Flange specifications conform to API standard 6A

National Gate Valves are available with flanged ends in standard API bore sizesand working pressures. Special trims are available for sour gas and oil service onrequest. National Gate Valves are also readily available to accept most pneumaticor hydraulic operators. National Gate Valves meet the applicable standards setforth by the American Petroleum Institute. When ordering, be sure to specifyquantity, size, working pressure, end connection, body and trim materials, andservice conditions (such as temperature, pressure, and composition of flowmaterial).

E

A

C

B

C

6 - 90



.

Figure 6.4.11 - Components 113/16" thru 21/16" 15,000 psi

Body

GreaseFitting

Gate

SeatAssembll

Hub SealClevis Pin

ClevisNut

Stem

PlasticPackingInjection

Fitting

PlasticPacking

Packing Header RingStem Packing

Stud Bolt

Bonnet

BonnetGasket

Hex Nut

Hex Nut

Handwheel

Bonnet Cap

Grease Seal

O-Ring

Flat SplitRing

Stem Bearing

ShoulderSplit Ring

Packing Gland

Set Screw

BearingGrease Fitting

GreaseFitting



6 - 91

Figure 6.5.12 - Type ‘HCR‘ pressure operated gate valve

The type ‘HCR‘ pressure operated gate valves is a flow line valve requiringrelatively low operating pressures. This is a single ram, hydraulic gate valvepacked with elements similar to the old ‘QRC‘ ram assembly. The closing ratio ofwell pressure to hydraulic operating pressure is approximately 8 to 1. Availablesizes are 4-inch 3000 to 5000 psi working pressure, and 6-inch 3000 and 5000 psiworking pressure with standard API flanges.

6 - 92




Cameron type “F“ Gate Valve

The Cameron type “F“ gate valve is a commonly used valve on BOP system lines.The valve is conduit type with no pockets for solids to deposit and hardenedrotating seats which distribute wear. Gates and seats may be replaced withoutdisconnecting the valves. These valves may be equipped with either hydraulic orpneumatic operators. Control pressure is lower, especially at high operatingpressures. Sizes from 1-13/16 to 6-6/8 inch are available in ratings of 2,000 to10,000 working pressure.

Fail-safe type “F“ valves are opened and held open by control pressure in theoperating cylinder. Line pressure tends to close the valve because the gate andstem move outward in closing. Closing force is supplied by valve body pressureacting on the stem area, plus the action of a coiled spring. Since operating pressureis low so that closing ratio is not a problem, “fail-safe“ models close automaticallyupon loss of pressure and are ideally suited for subsea use.



6 - 93

Fail Safe Valves

High pressure choke and kill lines run from the stack to the choke manifold on therig floor. To shut these lines off when not required, each is equipped with two failsafe valves. These can be opened hydraulically from the surface but when theopening pressure is released spring action automatically forces the gate closed.The valves are always rated at the same pressure as the stack and choke and killlines.

Due to space limitations the first valve out from the stack (the inner valve) is a 90degree type with a target to avoid sand cutting. The outer valve is straight throughand must be able to hold pressure from on top as well as below when the chokeand kill lines are tested.

In the Cameron type AF fail safe valve (fig 6.5.15) flow line pressure acting againstthe lower end of the balancing stem assists in closing the valve. A port in theoperator housing allows the hydrostatic pressure due to water depth to balancethe hydrostatic head of the operating fluid. A resilient sleeve transmits the seawater pressure to an oil chamber on the spring side of the operating piston.Without this feature the hydrostatic head of the operating fluid acting on top of thepiston would tend to open the valve itself, especially in deep water.

Liquid lock between the two valves in each line is eliminated by porting the fluidexhausted from the pressure chamber when opening the valve, away from theneighbouring valve.

6 - 94



Figure 6.5.15

Woodruff keyLocking ring

Sea water hydrostatic pressure

Sea water hydrostaticpressure equalizing port

ClampRing

"J" PackingVent "O" ring

"J" PackingJunk ring

Retainer ringPin

Pipe plugBonnet gasket

Pin

Adaptor stem

Balancing stem"O" ring

"J" packing"O" ring

"O" ring

"J" packing

Nut

"O" ring

Gland

Pipe plug

Operator fluid inletRetainer ring

Piston

Set screw

"O" Ring

Spring cartridge assembly

Resilient sleeve

Sleeve

Ring

Pipe plugAnti-extrusion ringBonnet studBonnet nut

Bonnet

Gate and seat assembly

Body

CAMERON TYPE AF FAIL SAFE VALVE



6 - 95

Figure 6.5.16

Positive SealGate Diameter

Positive SealSeat Orifice

H2S ServiceWith Hydraulic Actuator

3 to 15 psiPosition Indicator


WithHandwheel

Actuator

H2S and/or CO2Service



WithHandwheel

Actuator

With Hydraulic Actuator

LengthLengthSizeSpool Part Number

H2S Service H2S and/or CO2ServiceLengthLengthSize

Spool Part NumberH2S Service H2S and/or CO2Service

6 - 96



Figure 6.5.17



6 - 97

K Choke Beans and Wrenches

• Flared Orifice entrance reduces erosion on the entrance surface.

• Accuracy levels are maintained over extended periods of use.

• Choke beans save time and money because replacement intervals areextended.

Cameron K choke beans come in two styles, positive and combination. Thepositive bean has a fixed orifice diameter. The combination bean has a fixeddiameter and a throttling taper at the entry. The combination bean is used with anadjustable choke needle to make incremental changes to orifice sizes smaller thanthe fixed orifice.

The part numbers of the positive and combination beans are determined bydesired orifice size. K1 positive bean orifice sizes range from 4/64" to 64/64"/ Partnumbers for K1 positive beans are available on request. K2 positive bean orificesizes range from 4/64" to 128/64". The part number for K2 positive bean is626397-( )-( ). The dash numbers indicate desired orifice size; for example,626397-01-10 is a 110/64" diameter orifice. K3 positive bean orifice sizes rangefrom 4/64" to 192/64". Part numbers for K3 positive beans are available onrequest.

K1 combination bean sizes range from 6/64" to 64/64". K2 combination bean sizesrange form 6/64" to 128/64". The part number for the K2 combination bean is626396-( )-( ). K3 combination bean sizes range from 6/64" to 192/64". Partnumbers for the K1 and K3 combination beans are available upon request.

The part number of the K2 bean wrench is 626266-01. The part numbers of the K1and K3 bean wrenches are available on request.

6 - 98



6.6 INSIDE BOP'S

Drill Pipe Float Valves

The drill pipe float valve and the flapper type of back pressure valve, serveessentially the same purpose, but differ in design.

These valves provide instantaneous shut-off against high or low back pressure andallow full fluid flow through the drill string. Another advantage is that it preventscuttings from entering the drill string, thus reducing the likelihood of pulling awet string. Abnormal pressures and anticipated subnormal pressure zones shouldbe the deciding factor regarding what type of valve to run or the possibility of notrunning any valve at all. Expectations of abnormal pressures have shown thevented type of flapper valve to be the most popular because of the ease involvedin recording shut-in drill pipe pressures. The disadvantages are that the pipe mustbe filled while tripping in, and reverse circulation is not possible.

Figure 6.6.1



6 - 99

Figure 6.6.2 - Kelly Cock Figure 6.6.3 - Gray Valve

Figure 6.6.4Installing a Checkguard improves well controlsignificantly. It serves as a check valve to preventupward flow through the drill string while permittingdownward mud pumping or flow from injectors.

While stripping drill pipe into the hole, Checkguardcontrol upward pressure in the annulus and in the drillpipe. Latching the check valve into the landing subcontains the pressure in the drill pipe.

Prior to shearing drill pipe, install the check valve toprotect against the release of well pressures. Installationof the check valve simplifies well control, sinceformation pressures cannot communicate up the drillstring.

While tripping, Checkguard contains upward well borepressure in the drill pipe, allowing the top connection tobe open.

Upper Seat

Ball

Lower Seat

Crank

Body

RELEASE TOOL

VALVE SEAT

VALUE RELEASE ROD

VALVE SPRING

6 - 100



Checkguard uses a spring and ball design. Fluid can be pumped through thevalve from the top. But when fluid tries to flow from the bottom to the top, it issealed by the spring-loaded ball against the seat.

A large rubber packer provides sealing when fluid attempts to flow around thevalve. The packer is engaged by the tapered body. The body is driven upward bypressure from below. The more pressure from below, the tighter the seal is.

Installation and Retrieval

Install the landing sub in the drill string while tripping into the hole. Position thelanding sub in the lower end of the drill string.

Install the check valve by dropping it into an open tool joint. Connect the kellyand pump the check valve into the landing sub. Use the drill pipe safety kellyguard and lower the kelly guard if excessive back flow exists.

Retrieve the check valve by installing a sinker bar above the retrieving tool andusing a wire line. Use normal wire line procedure. Another way is to trip the drillstring and remove the check valve from the landing sub with the retrieval tool.

Operating tips include ensuring the packer rubber is clean and pliable. Check forforeign substances such as paint, grease and dirt on the packer surface. Check forcracking and embrittlement of packer. Never oil rubber packer. Replace packer ifcondition requires.

The check valve should be disassembled, cleaned and lubricated (not packer) onceit is retrieved from the landing sub after downhole use.

The valve should be stored in a protected area, away from sun and rain while notin use. This protects the working parts and packer.

SECTION 7 : INSPECTION, TESTINGAND SEALING COMPONENTS

Page

7A Inspection and Testing - Surface Installations 1

7B Inspection and Testing - Subsea Installations 12

7C Sealing Components - Surface Installations 14

7D Sealing Components - Subsea Installations 15


SECTION 7 : INSPECTION & TESTING

7 - 1

SECTION 7-AINSPECTION AND TESTING - SURFACE INSTALLATIONS

FIELD ACCEPTANCE INSPECTION AND TESTING

7.A.1 The field acceptance procedure should be performed each time a new orreworked blowout preventer or blowout preventer of unknown condition isplaced in service.

Ram Type Preventers and Drilling Spools

7.A.2 Following are recommended inspections and tests for this equipment:

a. Visually inspect the body and ring grooves (vertical, horizontal, or ram bore)for damage, wear, and pitting.

b. Check bolting, both studs and nuts, for proper type, size, and condition.Refer to Section 8-A for bolting recommendations.

c. Check ring joint gaskets for proper type and condition. Refer to Section 8-Afor ring joint gasket recommendations.

d. Visually inspect ram type preventers for:

1) Wear, pitting, and or damage to the bonnet or door seal area, bonnet ordoor seal grooves, ram bores, ram connecting rod, and ram operating rods.

2) Packer wear, cracking, and excessive hardness, Refer to Section 8-A forinformation on sealing components.

3) Measure ram and ram bore to check for maximum vertical clearanceaccording to manufacturer’s specifications. This clearance is dependent ontype, size, and trim of the preventers.

4) If preventer has secondary seals, inspect secondary seals and remove theplugs to expose plastic packing injection ports used for secondary sealingpurposes. Remove the plastic injection screw and the check valve in this port.(Some preventers have a release packing regulating valve that will need to beremoved.) Probe the plastic packing to ensure it is soft and not energising theseal. Remove and replace packing if necessary.

7 - 2



e. Hydraulically test with water using the following procedure(refer to Para. 7.A.5 for test precautions):

1) Connect closing line(s) to preventer(s).

2) Set preventer test tool on drill pipe below preventer(s) if testing preventerwith pipe rams.

3) Check for closing chamber seal leaks by applying closing pressure to closethe rams and check for fluid leaks by observing opening line port(s). Closingpressure should be equivalent to the manufacturer’s recommended operatingpressure for the preventer’s hydraulic system.

4) Release closing pressure, remove closing line(s), and connect openingline(s).

5) Check for opening chamber seal leaks by applying opening pressure toopen rams and check for fluid leaks by observing closing line port(s).Opening pressure should be equivalent to the manufacturer’s recommendedoperating pressure for the preventer’s hydraulic system.

6) Release opening pressure and reconnect closing line(s).

7) Check for ram packer leaks at low pressure by closing rams with 1500 psioperating pressure and apply pressure under rams to 200-300 psi withblowout preventer test tool installed (when testing preventer containing piperams). Hold for three minutes. Check for leaks. If ram packer leaks, refer tostep 9. If ram packer does not leak, proceed to step 8.

8) Check for ram packer leaks by increasing pressure slowly to the ratedworking pressure of the preventer. Hold for three minutes. Check for leaks.If ram packer leaks, proceed to step 9.

9) If rams leak, check for worn packers and replace if necessary. If thepreventer is equipped with an automatic locking device, check same forproper adjustment in accordance with manufacturer’s specifications.Continue testing until a successful test is obtained.

10) Test the connecting rod for adequate strength by applying openingpressure as recommended by the manufacturer with rams closed andblowout preventer rated working pressure under the rams.

11) Release opening pressure and release pressure under rams.

12) Repeat procedure (steps 1 through 9) for each set of pipe rams.

13) Test blind rams in same manner as pipe rams (step 1, steps 3 through 9)with test plug installed but test joint removed.



7 - 3

Annular Blowout Preventers and Diverters

7.A.3 Following are recommended inspections and tests for this equipment:

a. Visually inspected:

1) Studded face of preventer head for pitting and damage, particularly inring groove and stud holes.

2) Body for wear and damage.

3) Vertical bore for wear and damage from drill string and drill tools.

4) Inner sleeve for pitting and damage. Look through slots in base of innerliner for cuttings that might be trapped, thereby preventing full movement ofthe piston.

5) Packer for wear, cracking excessive hardness, and correct elastomercomposition. Refer to Section 8-A for information on sealing components.

6) Bolting (both studs and nuts) for proper type, size, and condition. Refer toSection 8-A for bolting recommendations.

7) Ring-joint gaskets for proper type and condition. Refer to Section 8-A forring-joint gasket recommendations.

b. Hydraulic test using the following procedure:

1) Connect closing line to preventer.

2) Set blowout preventer test tool on drill pipe below preventer.

3) Test the seals between the closing chamber and wellbore and between theclosing chamber and opening chamber by closing preventer and applyingmanufacturer’s recommended closing pressure. If other chambers are locatedbetween the wellbore and operating chamber, this seal should also be tested.

4) a) If pressure holds, refer to step 13.

b) If pressure does not hold and no fluid is running out of openingchamber opening, the seal between the closing chamber and thewellbore or other operating chambers is leaking. Refer to step 11.

c) If fluid is coming out of the opening chamber opening, indicating theseal between the closing chamber and opening chamber is leaking,proceed to step 5.

7 - 4



5) Release closing pressure.

6) Install plug in opening chamber opening, or if opening line is equippedwith a valve install opening line and close valve.

7) Test seals between the closing chamber, operating chambers, and wellboreby applying manufacturer’s recommended closing pressure. Observe to seethat pressure holds.


9) Remove plug in opening chamber opening and install opening line oropen valve in opening line.

10) Apply 1500 psi closing pressure.

11) Apply 1500 psi wellbore pressure.

12) Bleed closing pressure to 1000 psi.

13) To test the seal between the wellbore and the closing chamber. Closevalve on closing line and disconnect closing line from valve on closing unitside of valve. Install pressure gauge on closing unit side of valve and openvalve. If this seal is leaking, the closing line will have pressure greater than1000 psi. Caution: If the closing line does not have a valve installed, the closing lineshould not be disconnected with pressure trapped in the closing chamber.

14) Release wellbore pressure.


16) a) To test the seals between the opening chamber and the closingchamber and between the opening chamber and the piston, applymanufacturer’s recommended opening pressure. If pressure holds, referto step 21.

b) If pressure does not hold and no fluid is running out of the closingchamber opening, the seal between the opening chamber and the pistonis leaking. Verify this visually. Refer to step 21.

c) If fluid is coming out of the closing chamber opening, indicating theseal between the opening chamber and the closing chamber is leaking,proceed to step 17.

17) Release opening pressure.



7 - 5

18) Install closing line and block flow (close valve in closing line, if available).

19) Apply 1500 psi opening pressure. If pressure does not hold, seal betweenthe opening chamber and the preventer head is leaking. Verify this visually.

20) Release opening pressure and replace necessary seals. Refer to step 22.

21) Release opening pressure, replace closing line, and replace necessaryseals.

22) If closing line has a valve installed, make certain that valve is open at theend of the test. NOTE: This procedure tests all seals except the seal between thewellbore and the opening chamber. This seal should be tested in the bottom annularpreventer if two annular preventers are being used or if a stack is nippled up on anannular preventer (for snubbing. etc.). It can be tested as follows:

a) To rated working pressure by running a test joint and plug, closingan upper preventer, removing the opening line, and pressuring thepreventer stack.

b) To 1500 psi maximum, or by closing an upper preventer and theannular preventer, removing the opening line, and pressuring upbetween preventers.

PERIODIC FIELD TESTING

Blowout Preventer Operating Test

7.A.4 A preventer operating test should be performed on each round trip but notmore than once per day. The test should be conducted as follows while trippingthe drill pipe with the bit just inside casing:

a. Install drill pipe safety valve.

b. Operate the choke line valves.

c. Operate adjustable chokes. Caution: Certain chokes can be damaged if full closureis effected.

d. Position blowout preventer equipment to check choke manifold. Openadjustable chokes and pump through each choke manifold to ensure that it isnot plugged. If choke manifold contains brine, diesel or other fluid to preventfreeze-up in cold weather, some other method should be devised to ensuremanifold, lines, and assembly are not plugged.

7 - 6



e. Close each preventer until all pipe rams in the stack have been operated.Caution: Do not close pipe rams on open hole. If blind rams are in the stack, operatethese rams while out of the hole.

f. Return all valves and preventers to their original position and continuenormal operations. Record test results.

g. Annular preventers need not be operated on each round trip. They should,however, be operated at an interval not to exceed seven (7) days.

Blowout Preventer Hydraulic Tests

7.A.5 The following items should be checked each time a preventer is to behydraulically tested:

a. Verify wellhead type and rated working pressure.

b. Check for wellhead bowl protector.

c. Verify preventer type and rated working pressure.

d. Verify drilling spool, spacer spool, and valve types and rated workingpressures.

e. Verify ram placement in preventers and pipe ram size.

f. Verify drill pipe connection size and type in use.

g. Open casing valve during test, unless pressure on the casing or hole isintended.

h. Test pressure should not exceed the manufacturer’s rated working pressurefor the body or the seals of the assembly being tested.

i. Test pressure should not exceed the values for tensile yield, collapse andinternal pressure tabulated for the appropriate drill pipe as listed inAPI RP 7G: Recommended Practice for Drill Stem Design and Operating Limits*.

j. Verify the type and pressure rating of the preventer tester to be used.



7 - 7

TABLE 7-A

Test Pressure Recommendations Preventer Equipment Tested

Blowout preventer stack rated working 1. Entire blowout preventer stack.pressure (or as specified in Notes below.) 2. All choke manifold components upstream of chokes.

3. All kelly valves, drill pipe, and tubing safety valves.4. Drilling spools, intermediate casingheads, and side outlet valves.

Rated working pressures of preventers or 1. Closing unit valves and manifold3000 psi. whichever is less 2. All operating lines.

Casing test pressure 1. Any blind rams below drilling spool.2. Primary casinghead and side outlet valves.3. Casing string.

Fifty percent (50%) of rated working pressure 1. Choke manifold components downstream of chokesor components

200 - 300 psi. 1. All ram type preventers2. Annular preventers3. Hydraulically operated valve.

Notes: 1. Initial test pressure for the blowout preventer stack, manifold, valves, etc., should be the lesser ofthe rated working pressure of the preventer stack, wellhead, or upper part of the casing string.

2. Optional test - a rated working pressure test on top flange of the annular preventer. A companiontest flange will be required.

*Available from American Petroleum Institute. Production Department. 2535 One Main Place, Dallas TX 75202-3904.

7.A.6 An initial pressure test should be conducted on all preventer installationsprior to drilling the casing plug. Conduct each component pressure test for at leastthree minutes. Monitor secondary seal ports and operating lines on each preventerwhile testing to detect internal seal leaks.

7.A.7 Subsequent pressure tests of blowout preventer equipment should beperformed after setting a casing string, prior to entering a known pressuretransition zone, and after a preventer ram and/or any preventer stack or chokemanifold component change; but no less than once every 21 days. Equipmentshould be tested to at least 70 percent of the preventer rated working pressure, butlimited to the lesser of the rated working pressure of the wellhead or 70 percent ofthe minimum internal yield pressure of the upper part of the casing string:however, in no case should these or subsequent test pressures be less than theexpected surface pressure. An exception is the annular preventer which may betested to 50 percent of its rated working pressure to minimise pack-off elementwear or damage. After a preventer stack or manifold component change,hydraulically test in accordance with the provisions in Par. 7.A.6 and Table 7-A.Precautions should be taken not to expose the casing to test pressures in excess of its ratedstrength. A means should be provided to prevent pressure build up on the casing in theevent the test tool leaks.

7 - 8



Closing Unit Pump Capability Test

7.A.8 Refer to Par. 5.A.21 for closing unit pump capability test details.

Accumulator Tests

7.A.9 Refer to Paras. 5.A.22 and 5.A.23 for accumulator tests details.

Auxiliary Equipment Testing

7.A.10 The lower kelly valve, kelly, kelly cock, and inside blowout preventershould be tested to the same pressure as the blow out preventer stack at the sametime the preventer assembly tests are made. This equipment should be tested withpressure applied from below.

MAINTENANCE PROCEDURES

7.A.11 Field welding on a blowout preventer or related equipment is notrecommended.

7.A.12 The service life of annular preventer packing units can be extended by:

a. Closing on pipe rather than full closure.

b. Using closing pressures recommended by the manufacturer.

c. Utilising the type of elastomer packing unit that best suits the drilling fluidconditions and environment expected .

d. Proper use of a regulator or accumulator when stripping tool joints. Rapidmovement of a tool joint through the preventer packing unit may causesevere damage and early failure of the packing unit.

7.A.13 If elastomer parts are to be stored for a long time period, sealed containerswill help extend their useful life. Refer to Section 8-A for information on extendingthe life of elastomers for preventers and related equipment.

7.A.14 When a blowout preventer is taken out of service, it should be completedwashed, steamed, and oiled. The rams (sealing element) should be removed andthe ram bore washed inspected, and coated with a rust inhibitor. Flanged facesshould be protected with wooden covers. Any burrs or galled spots should besmoothed.



7 - 9

TEST PLUGS AND TEST JOINTS

7.A.15 Test Plugs. Several makes of test plugs are available for testing preventerstacks. The testing tool arrangement should provide for testing the bottomblowout preventer flange. Test plugs generally fall into two types, hanger type andcup type.

a. The hanger type test plug has a steel body with outer dimensions to fit thehanger recess of corresponding types of casinghead. An O-ring pressure sealis provided between the tester and the hanger recess (refer to Figs 7.A.1 and7.A.2). The tester is available in various sizes depending on wellhead typeand size and is equipped with tool joint connections. These plugs should beconstructed with an upper bevel and/or bevelled groove (refer to Figs, 7.A.1and 7.A.2) to facilitate the use of locking screws. The O-ring groove, if used,should be machined to permit a pressure seal from above or below the plug.Other types of seals should also be capable of holding pressure from above orbelow the plug. Weep holes may be drilled in the pin end of the test joint ormay be installed in the test plug. These testers can be provided with a plug totest blind rams with the drill string removed. The tester can be retrieved withthe drill string.

b. The cup type test plug (refer to Figs. 7.A.3 and 7.A.4) consists of a mandrelthreaded with a box on top and a pin on bottom, for a tool joint connection. Acup type pressure element holds pressure from above. Some models (refer toFig. 7.A.1) contain a back pressure valve to bypass fluid when going in thehole. Also, a set of snap plugs (usually 4) can be provided integral to themandrel so that the snap plugs can be broken off by dropping a bar insidethe pipe, thereby allowing the annulus to be connected with the inside of thedrill pipe to permit pulling the tool without swabbing the hole.

7.A.16 Test Joints. The test joint should be made of pipe of sufficient weight andgrade to safely withstand tensile yield, collapse or internal pressures that will beplaced on it during, testing operations Refer to API RP 7G: Recommended Practice forDrill Stem Design and Operating Limits* for tabulated data listed by pipe size, grade,weight, and class (condition of pipe). The test joint (refer to Fig. 7.A.5), or a boxand pin sub on top of a standard joint of drill pipe, should have a tapped orwelded connection below the box end connection equipped with a valve, gauge,and fittings having a working pressure at least equal to the rated working pressureof the preventer stack. Weep holes may be drilled in the pin end of the test joint ormay be installed in the test plug.

7.A.17 Casing Ram Test Sub. Fig. 7.A.6 illustrates a casing ram test sub. Casingrams can be tested by connecting this test sub between the test joint and the testplug so that the sub can be placed in the casing rams to be tested. A casing ramtest sub can be made by welding tool joint connections on the ends of a shortlength of casing of desired diameter.

*Available from American Petroleum Institute. Production Department. 2535 One Main Place, Dallas TX 75202-3904.

7 - 10



LOCKING FLANGE MUST BE REMOVED BEFORE NEXTSECTION OF WELLHEADIS INSTALLED

Figure 7.A.1 Figure 7.A.2HANGER TYPE TEST PLUG HELD IN HANGER TYPE TEST PLUG HELD IN

PLACE WITH LOCKING FLANGE PLACE WITH CASINGHEADLOCK SCREWS LOCK SCREWS

EXAMPLE OF HANGER TYPETEST PLUGS

Figure 7.A.3 Figure 7.A.4

EXAMPLE CUP TYPE TEST PLUGS

MANDREL

SNAP PLUGS90° SPACING

RETAINING NUT

RETAINING PLATE

PRESSURE SEAL

SIZE PLATE

TAPPED FOR 1"SNAP PLUGS 90° SPACING

LOWER VALVE

RETAINING SLEEVE

SNAPBAR

CUP

SUB

'O' RING

MANDREL



7 - 11

ST

EE

L P

LAT

E(W

ELD

ED

TO

CA

SIN

G S

UB

AN

D T

OO

L JO

INT

BO

X)

ST

EE

L P

LAT

E(W

ELD

ED

TO

CA

SIN

G S

UB

AN

D T

OO

L JO

INT

BO

X)

TO

OL

JOIN

T P

IN T

OM

AT

CH

TE

ST

PLU

G

WE

EP

HO

LE

CA

SIN

G S

UB

OF

SU

FF

ICIE

NT

LE

NG

TH

TO

TE

ST

CA

SIN

G R

AM

S

TO

OL

JOIN

T B

OX

TO

MA

TC

H T

ES

T J

OIN

T

1" O

R L

AR

GE

R V

ALV

E

WE

EP

HO

LE

FIG

. 7.A

.5E

XA

MPL

E T

EST

JOIN

TFI

G. 7

.A.6

EX

AM

PLE

CA

SIN

G R

AM

TE

ST S

UB

7 - 12



SECTION 7-BINSPECTION AND TESTING—SUBSEA INSTALLATIONS

SURFACE INSPECTION AND TESTING

7.B.1 Prior to delivery to an offshore drilling unit, visually inspect the preventers,spools, high pressure connector, and kill and choke valves for condition of bodies,machined surfaces, grooves, actuating rods, rams, seals, and gaskets. Inspect inaccordance with procedures in Para. 7.A.2.e.

7.B.2 Test each individual component of the blowout prevention system to beutilised in test facilities under shop conditions to rated working pressure utilisingprocedures outlined in Para.7.A.2.e. Following unitisation in the shop, test entireunit for proper operation using the hydraulic closing system. Test the closingsystem to 3000 psi. Pressure test each preventer and high pressure connector forlow pressure (200 psi) leaks and to rated working pressure. Record the date andresults of inspection and tests on the shipping tags.

7.B.3 After delivery to an offshore drilling unit, install the unitised blowoutprevention system on a prepared test stump. A low pressure and rated workingpressure test of each component as in the off-site procedure (Para. 7.B.2) should berepeated and properly recorded in the well log. Test record should includeopening and closing times and hydraulic fluid volumes required for each function.Subsequent pressure tests should be limited to 70% of the rated working pressureof the blowout preventer stack or the anticipated surface pressure, whichever isgreater. Full rated working pressure tests should be limited to one test followingany major ram cavity repair work.

7.B.4 The blowout prevention system should be visually inspected and pressuretested in accordance with Para. 7.B.3 before returning on a well.

SUBSEA TESTING

7.B.5 The blowout prevention system should be operated on each trip but notmore than once every 24 hours during normal operations. The annular preventersneed not be operated on each trip. They must, however, be operated in conjunctionwith the required pressure tests and at an interval not to exceed seven days. Theperiodic actuation test is not required for the blind or blind shear rams. Theserams need only be tested when installed and prior to drilling out after each casingstring has been set. A record of these tests should be maintained in the well logand should include closing and opening times and pressures and volumes ofhydraulic fluid for each function.

7.B.6 Pressure tests of the subsea system should be conducted after installation,after setting casing, and before drilling into any known or suspected high pressurezones. Otherwise, these tests should be conducted at regular intervals but not



7 - 13

more than once every week. On installation of the blowout preventer stack, eachcomponent including the high pressure connectors should be individuallypressure tested at a low pressure (200 psi) and to the greater of 70 percent of ratedworking pressure or the maximum pressure expected in the upper part of thecasing. Subsequent pressure tests may be limited to the lesser of 70 percent of therated working pressure of the blowout preventers or 70 percent of the minimuminternal yield strength rating of the upper part of the casing, provided the testpressure equals or exceeds the maximum pressure expected inside the upper partof the casing. An exception is the annular preventer which may be tested to 50percent of its rated working pressure to minimise pack-off element wear ordamage. A test plug or cup type tester should be used (refer to Section 7-A).Precautions should be taken not to expose the casing to test pressures in excess of its ratedinternal yield strength. A means should be provided to prevent pressure build up on thecasing in the event the test tool seals leak. Actuation testing of pipe rams should not beperformed on moving pipe.

7.B.7 The subsea blowout prevention system is dependent on surface actuatedhydraulic, pneumatic, and electric controls. The design of this prevention system isdependent on water depth and environmental conditions and should have anadequate backup system to operate each critical function. It is equally important topressure and operationally test this system concurrently with the blowoutpreventers and connectors.

7 - 14



SECTION 7-CSEALING COMPONENTS—SURFACE INSTALLATIONS

FLANGES AND HUBS

7.C.1 The following tabular data detail sizes in use on blow out preventers

Rated Working Flange or Minimum Ring-JointPressure Hub Size Vertical Bore Gaskets

psi in. in. RX BX

500 (0.5 M) 29 1/2 29 1/2 - -

2,000 (2 M) 16 16 3/4 65 -20 21 1/4 73 -26 3/4 26 3/4 - -

3,000 (3 M) 6 7 1/16 45 - 8 9 49 -10 11 53 -12 13 5/8 57 -20 20 3/4 74 -26 3/4 26 3/4 - -

5,000 (5 M) 6 7 1/16 46 -10 11 54 -13 5 /8 13 5/8 - 16016 3/4 16 3/4 - 162‡18 3/4 18 3/4 - 16321 1/4 21 3/4 - 165

10,000 (10 M) 7 1/16 7 1/16 - 156 9 9 - 15711 11 - 15813 5/8 13 5/8 - 15916 3/4 16 3/4 - 16218 3/4 18 3/4 - 16421 1/4 21 1/4 - 166

15,000 (15 M) 7 1/16 7 1/16 - 156 9 9 - 15711 11 - 15813 5/8 13 5/8 - 159

20,000 (20 M) 7 1/16 7 1/16 - 156

Notes:

* Replaces 20 1/4" subsequent to January 1974.‡ Replaces BX-161 subsequent to adoption of 5000 psi rated working pressure (10,000 psi test pressure) flange in lieu of 5000 psi rated working pressure (7500 psi test pressure) flange in June 1969.



7 - 15

SECTION 7-DSEALING COMPONENTS—SUBSEA-INSTALLATIONS

GENERAL

7.D.1 Operation of the subsea blowout preventer stack and marine riser systemrequires particular attention to the availability and correct usage of sealingcomponents which are peculiar to subsea equipment. These non-API componentsare described in the following paragraphs. Manufacturers should be consulted forspecifications and spare parts recommendations. Other sealing components arecovered in Section 7-C.

WELLHEAD CONNECTOR

7.D.2 The primary seal for the wellhead connector is a pressure energised metal-to-metal type seal. Initial seal requires that the metal seal be coined into contactwith the mating seal surfaces. These seals are not recommended for reuse. Somewellhead connectors are equipped with resilient secondary seal which may beenergised should the primary seal leak. This seal should be utilised underemergency conditions only.

MARINE RISER

7.D.3 The primary seal for the marine riser connector consists of resilient typeO-Ring or lip-type seals. The primary seal for choke and kill line stab subs on theintegral riser connector consists of pressure energised resilient seals or packing.Care should be taken to carefully clean and inspect all seals prior to running themarine riser.

7.D.4 The primary telescopic joint seal assembly consists of a hydraulic orpneumatic pressure energised resilient packing element.

SUBSEA CONTROL SYSTEM

7.D.5 Primary hydraulic system seal between the male and female sections of thecontrol pods is accomplished with resilient seals of the O-ring, pressure energised,or face sealing types.

7.D.6 The hydraulic junction boxes consist of stab subs or multiple check valvetype quick disconnect couplings. The primary seals are O-rings. These seals shouldbe inspected each time the junction box is disconnected.

7.D.7 The primary pod valve seals vary according to the manufacturer with bothresilient and lapped metal-to-metal type seals used.

Page

8.0 BOP and Control Systems 1

8A Closing Units - Surface Installations 7

8B Closing Units - Subsea Installations 21

SECTION 8 : SURFACE BOP CONTROL SYSTEMS



8 - 1

8.0 SURFACE BOP AND CONTROL SYSTEMS

Figure 8.0.1 Land Rig Operation

8 - 2



TYPICAL SURFACE BOP CONTROL SYSTEMT-SERIES

Figure 8.0.2



8 - 3

TYPICAL SURFACE BOPCONTROL SYSTEM

1. Accumulators - Precharge perlabel. Warning! USENITROGEN ONLY-DO NOTUSE OXYGEN! Check every 30days.

2. Accumulator Bank IsolationValve -Manually operated,normally open.

3. Accumulator Bank BleedValve - Normally closed.

4. Accumulator Relief Valve -Set at 3300 PSI.

5. Air Filter - Automatic Drain.Clean every 30 days.

6. Air Lubricator -Fill with SAE10 lubricating oil, set for 6 dropsper minute. Check oil levelweekly.

7. Air Pressure - Gauge - 0 to300PSI.

8. Hydro-pneumatic PressureSwitch -Automatically stops airoperated pumps when pressurereaches 2900 PSI and startspumps when pressure dropsapproximately 400 PSI.

9. Air Supply Valves -Normallyopen. Close when servicing airoperated pumps.

10. Suction Valve, Air OperatedPumps -Normally open. Closewhen servicing pumps.

11. Suction Strainer, AirOperated Pumps - clean every30 days.

12. Air Operated Pump.

13. Discharge Check Valve, AirOperated Pump.

14. Duplex or Triplex Pump -Fill crankcase with SAE 20 oil for40F to 115F ambient temperaturerange. Check oil level monthly.

15. Chain guard - Fill with SAE40 oil for operation above 20Fambient temperature. Check oillevel monthly.

16. Explosion-Proof ElectricMotor.

17. Electric Pressure Switch -Automatically stops pumpswhen accumulator pressurereaches 3000 PSI and startspumps when pressure drops to2700 PSI nominal.

18. Electric Motor Starter - Keepstarter switch in “Auto” positionexcept when servicing. TURNOFF power at main panel whenservicing.

19. Suction Valve, Triplex orDuplex pump. Normally open.Close when servicing pump.

20. Suction Strainer, Triplex orDuplex pump - Clean every 30days.

21. Discharge Check Valve,Duplex or Triplex Pump.

22. High Pressure Strainer -Clean every 30 days.

23. Shut Off Valve - Normallyclose. Connection for separateoperating fluid pump.

24. Manifold Regulator -Regulates operating pressure toram preventers and gate valves.Manually adjustable from 0 to1500 PSI, TR™ Regulatorcontains internal by-pass forpressures up to 3000 PSI or 5000PSI. (See 39 option)

25. Manifold Regulator InternalOverride Valve - Normally inlow-pressure (handle left)position. For operating pressuresabove l 500 PSI (ram preventersand gate valves), move to highpressure position (handle right).

26. 5,000 PSI W.P. Sub-PlateMounted Four-way ControlValve - Direct the flow ofoperating fluid pressure to thepreventers and gate valves.NEVER leave in the centreposition.

27. Manifold Bleeder Valve.

28. Accumulator PressureGauge - 0 to 6000 PSI.

29. Manifold Pressure Gauge - 0to 10,000 PSI.

30. Annular Regulator -Provides independent regulation

of the annular operatingpressure. Adjustable from 0 to1500 PSI. TR Regulator canprovide regulation up to 3000PSI for Cameron Type Dannulars and contains a manualoverride to prevent loss ofoperating pressure shouldremote control pilot pressure belost.

31. Annular Pressure Gauge - 0to 3000 PSI. (0-6000 PSI forCameron D Annulars.)

32. Annular PressureTransmitter - Hydraulic input,3-15 PSI air output.

33. Accumulator PressureTransmitter - 0 to 6000 PSIhydraulic input, 315 PSI airoutput.

34. Manifold PressureTransmitter - 0 to 10,000 PSIhydraulic input,3- 15 PSI airoutput. (Transmitter convertshydraulic pressure to airpressure and sends a calibratedsignal to corresponding airreceiver gauges on the Driller’sair operated remote controlpanel.)

35. Air Junction Box - Used forconnecting the air cable from theair operated remote controlpanels.

36. Reservoir - Stores operatingfluid at atmospheric pressure.Fill to within 8 inches from topwith Welkic™ 10 or SAE 10 oil.

37. Clean out man-way (T-Seriesunits).

38. Sight glass, fluid level(T-Series units).

Option- Available on units with5000 PSI working pressuremanifold valves and piping.

39. By-pass Valve -Hydro-pneumatic pressureswitch.

40. Normal Pressure IsolationValve -Normally open. Close forpressure above 3000 PSI. Thisfeature can be used for shearing.

41. Manifold Protector ReliefValve - Set at 5500 PSI.

8 - 4



SYSTEM DESCRIPTION

GENERAL

A Blowout Preventer (BOP) Control System is a high pressure hydraulic powerunit fitted with directional control valves to safely control kicks and preventblowouts during drilling operations. A typical system offers a wide variety ofequipment to meet the customer’s specific operational and economic criteria. Thefollowing text gives a brief description of the equipment and some of its majorcomponents.

Figure 8.0.3 ACCUMULATOR UNIT MODULE

The primary function of the accumulator unit module is to provide theatmospheric fluid supply for the pumps and storageof the high pressure operating fluid for control of the BOP stack. It includesaccumulators, reservoir, accumulator piping and a master skid for mounting of theair operated pumps, electric motor driven pumps and the hydraulic controlmanifold.

Accumulators

Accumulators are ASME coded pressure vessels for storage of high pressure fluid.These accumulators are available in a variety of sizes, types, capacities andpressure ratings. The two (2) basic types are bladder and float which are availablein cylindrical or ball styles. The accumulators can either be bottom or top loading.Top loading means the bladder or float can be removed from the top while it is stillmounted on the accumulator unit. Bottom loading accumulators must be removedfrom the accumulator unit to be serviced. Bladder and buoyant float typeaccumulators can be repaired in the field without destroying their stamp ofapproval.



8 - 5

Reservoir

A rectangular reservoir is provided for storage of the atmospheric fluid supply forthe high pressure pumps. It contains baffles, fill and drain ports andtroubleshooting inspection ports. For filling and cleaning procedures see theMaintenance section. It should be able to store 2 times the capacity of the usablefluid capacity.

Accumulator Piping

This piping connects the high pressure discharge lines of the pumps to theaccumulators and the hydraulic manifold. It is comprised of 1 or 1-1/2" Schedule80 or 160 pipe, isolator valves and a 3300 psi relief valve to protect theaccumulators from being over pressured. Cylindrical type accumulators aremounted on machined headers to minimise line restrictions and leaks.

AIR PUMP ASSEMBLY

The air pump assembly consists of one (1) or more air operated hydraulic pumpsconnected in parallel to the accumulator piping to provide a source of highpressure operating fluid for the BOP Control System. These pumps are available ina variety of sizes and ratios.

Figure 8.0.4

8 - 6



ELECTRIC PUMP ASSEMBLY

The electric pump assembly consists of a duplex or triplex reciprocating plungertype pump driven by an explosion-proof electric motor. It is connected to theaccumulator piping to provide a source of high pressure operating fluid for theBOP Control System. It is available in a variety of horsepower and voltage ranges.

Figure 8.0.5



8 - 7

SECTION 8.ACLOSING UNITS—SURFACE INSTALLATIONS

ACCUMULATOR REQUIREMENTS

General

8.A.1 Accumulator bottles are containers which store hydraulic fluid underpressure for use in effecting blowout preventer closure. Through use ofcompressed nitrogen gas, these containers store energy which can be used to effectrapid preventer closure. There are two types of accumulator bottles in commonusage, separator and float types. The separator type uses a flexible diaphragm toeffect positive separation of the nitrogen gas from the hydraulic fluid. The floattype utilises a floating piston to effect separation of the nitrogen gas from thehydraulic fluid.

Volumetric Capacity

8.A.2 As a minimum requirement, all blowout preventer closing units should beequipped with accumulator bottles with sufficient volumetric capacity to providethe usable fluid volume (with pumps inoperative) to close one pipe ram and theannular preventer in the stack plus the volume to open the hydraulic choke linevalve.

8.A.3 Usable fluid volume is defined as the volume of fluid recoverable from anaccumulator between the accumulator operating pressure and 200 psi above theprecharge pressure. The accumulator operating pressure is the pressure to whichaccumulators are charged with hydraulic fluid.

8.A.4 The minimum recommended accumulator volume (nitrogen plus fluid)should be determined by multiplying the accumulator size factor (refer toTable 8-A) times the calculated volume to close the annular preventer and onepipe ram plus the volume to open the hydraulic choke line valve.

TABLE 8. A

MinimumAccumulator Recommended Usable Fluid Accumulator

Operating Precharge Volume* SizePressure Pressure (fraction of Factor*

psi psi bottle size)

1500 750 1/8 82000 1000 1/3 33000 1000 1/2 2

Notes: *Based on minimum discharge pressure of 1200 psi.

8 - 8



Response Time

8.A.5 The closing system should be capable of closing each ram preventer within30 seconds. Closing time should not exceed 30 seconds for annular preventerssmaller than 18 3/4 inches and 45 seconds for annular preventers 18 3/4 inchesand larger.

Operating Pressure and Precharge Requirements for Accumulators

8.A.6 No accumulator bottle should be operated at a pressure greater than its ratedworking pressure.

8.A.7. The precharge pressure on each accumulator bottle should be measuredduring the initial closing unit installation on each well and adjusted if necessary(refer to Para. 8.A.4). Only nitrogen gas should be used for accumulator precharge.The precharge pressure should be checked frequently during well drillingoperations.

Requirements for Accumulator Valves, Fittings, and Pressure Gauges

8.A.8 Multi-bottle accumulator banks should have valving for bank isolation.An isolation valve should have a rated working pressure at least equivalent to thedesigned working pressure of the system to which it is attached and must be in theopen position except when accumulators are isolated for servicing, testing, ortransporting (refer to Fig. 8.A.1). Accumulator bottles may be installed in banks ofapproximately 160 gallons capacity if desired, but with a minimum of two banks.

8.A.9 The necessary valves and fittings should be provided on each accumulatorbank to allow a pressure gauge to be readily attached without having to removeall accumulator banks from service. An accurate pressure gauge for measuring theaccumulator precharge pressure should be readily available for installation atany time.

CLOSING UNIT PUMP REQUIREMENTS

Pump Capacity Requirements

8.A.10 Each closing unit should be equipped with sufficient number and sizes ofpumps to satisfactorily perform the operation described in this paragraph. Withthe accumulator system removed from service. The pumps should be capable ofclosing the annular preventer on the size drill pipe being used, plus opening thehydraulically operated choke line valve and obtain a minimum of 200 psi pressureabove accumulator precharge pressure on the closing unit manifold within two (2)minutes or less.



8 - 9

Pump Pressure Rating Requirements

8.A.11 Each closing unit must be equipped with pumps that will provide adischarge pressure equivalent to the rated working pressure of the closing unit.

Pump Power Requirements

8.A.l2 Power for closing unit pumps must be available to the accumulator unit atall times, such that the pump will automatically start when the closing unitmanifold pressure has decreased to less than 90 percent of the accumulatoroperating pressure.

8.A.13 Two or three independent sources of power should be available on eachclosing unit. Each independent source should be capable of operating the pumpsat a rate that will satisfy the requirement described in Para. 8.A.10. The dualsource power system recommended is an air system plus an electrical system.Minimum recommendations for the dual air system and other acceptable but lesspreferred dual power source systems are as follows:

a. A dual air/electrical system may consist of the rig air system (provided atleast one air compressor is driven independent of the rig compound) plus therig generator (refer to Fig. 8.A.2).

b. A dual air system may consist of the rig air system (provided at least one aircompressor is driven independent of the rig compound) plus an air storagetank that is separated from both the rig air compressors and the rig airstorage tank by check valves. The minimum acceptable requirements for theseparate air storage tank are volume and pressure which will permit use ofonly the air tank to operate the pumps at a rate that will satisfy the operationdescribed in the pump capacity requirements (refer to Para. 8.A.10).

c. A dual electrical system may consist of the normal rig generating system anda separate generator (refer to Fig. 8.A.3).

d. A dual air/nitrogen system may consist of the rig air system plus bottlednitrogen gas (refer to Fig.8.A.4).

e. A dual electrical/nitrogen system may consist of the rig generating systemand bottled nitrogen gas (refer to Fig. 8.A.5).

8.A.14 On shallow wells where the casing being drilled through is set at 500 feet orless and where surface pressures less than 200 psi are expected, a backup source ofpower for the closing unit is not essential.

8 - 10



REQUIREMENTS FOR CLOSING UNIT VALVES FITTINGS, LINES, ANDMANIFOLD

Required Pressure Rating

8.A.15 All valves and fittings between the closing unit and the blowout preventerstack should be of steel construction with a rated working pressure at least equalto the working pressure rating of the stack up to 3000 psi. Refer to API Spec 6A:Specification for Wellhead Equipment* for test pressure requirements. All linesbetween the closing unit and blowout preventer should be of steel construction oran equivalent flexible, fire-resistant hose and end connections with a ratedworking pressure equal to the stack pressure rating up to 3000 psi.

Valves Fittings and other Components Required

8.A.16 Each installation should be equipped with the following:

a. Each closing unit manifold should be equipped with a full-opening valveinto which a separate operating fluid pump can be easily connected (refer toFig. 8.A.1).

b. Each closing unit should be equipped with sufficient check valves or shut-offvalves to separate both the closing unit pumps and the accumulators fromthe closing unit manifold and to isolate the annular preventer regulator fromthe closing unit manifold.

c. Each closing unit should be equipped with accurate pressure gauges toindicate the operating pressure of the closing unit manifold, both upstreamand downstream of the annular preventer pressure regulating valve.

d. Each closing unit should be equipped with a pressure regulating valve topermit manual control of the annular preventer operating pressure.

e. Each closing unit equipped with a regulating valve to control the operatingpressure on the ram type preventers should be equipped with a bypass lineand valve to allow full accumulator pressure to be placed on the closing unitmanifold, if desired.

f. Closing unit control valves must be clearly marked to indicate (1) whichpreventer or choke line valve each control valve operates, and (2) the positionof the valves (i.e., open, closed, neutral). Each blowout preventer controlvalve should be turned to the open position (not the neutral position) duringdrilling operations. The choke line hydraulic valve should be turned to theclosed position during normal operations. The control valve that operates theblind rams should be equipped with a cover over the manual handle to avoidunintentional operation.



8 - 11

g. Each annular preventer may be equipped with a full-opening plug valve onboth the closing and opening lines. These valves should be installedimmediately adjacent to the preventer and should be in the open position atall times except when testing the operating lines. This will permit testing ofoperating lines in excess of 1500 psi without damage to the annular preventerif desired by the user.

*Available from American Petroleum Institute. Production Department, 2535 One Main Place Dallas TX 75202-3904.

REQUIREMENTS FOR CLOSING UNIT FLUIDS AND CAPACITY

8.A.17 A suitable hydraulic fluid (hydraulic oil or fresh water containing alubricant) should be used as the closing unit control operating fluid. Sufficientvolume of glycol must be added to any closing unit fluid containing water ifambient temperatures below 32 F are anticipated. The use of diesel oil, kerosene,motor oil, chain oil. or any other similar fluid is not recommended due to thepossibility of resilient seal damage.

8.A.18 Each closing unit should have a fluid reservoir with a capacity equal to atleast twice the usable fluid capacity of the accumulator system.

CLOSING UNIT LOCATION AND REMOTE CONTROL REQUIREMENTS

8.A.19 The main pump accumulator unit should be located in a safe place which iseasily accessible to rig personnel in an emergency. It should also be located toprevent excessive drainage or flow back from the operating lines to the reservoir.Should the main pump accumulator be located a substantial distance below thepreventer stack, additional accumulator volume should be added to compensatefor flow back in the closing lines.

8.A.20 Each installation should be equipped with a sufficient number of controlpanels such that the operation of each blowout preventer and control valve can becontrolled from a position readily accessible to the driller and also from anaccessible point at a safe distance from the rig floor.

8 - 12



CLOSING UNIT PUMP CAPABILITY TEST

8.A.21 Prior to conducting any tests, the closing unit reservoir should be inspectedto be sure it does not contain any drilling fluid, foreign fluid, rocks, or otherdebris. The closing unit pump capability test should be conducted on each wellbefore pressure testing the blowout preventer stack. This test can be convenientlyscheduled either immediately before or after the accumulator closing time test.Test should be conducted according to the following procedure:

a. Position a joint of drill pipe in the blowout preventer stack.

b. Isolate the accumulators from the closing unit manifold by closing therequired valves.

c. If the accumulator pumps are powered by air, isolate the rig air system fromthe pumps. A separate closing unit air storage tank or a bank of nitrogenbottles should be used to power the pumps during this test. When a dualpower source system is used, both power supplies should be testedseparately.

d. Simultaneously turn the control valve for the annular preventer to the closingposition and turn the control valve for the hydraulically operated valve tothe opening position.

e. Record the time (in seconds) required for the closing unit pumps to close theannular preventer plus open the hydraulically operated valve and obtain200 psi above the precharge pressure on the closing unit manifold. It isrecommended that the time required for the closing unit pumps toaccomplish these operations not exceed two minutes.

f. Close the hydraulically operated valve and open the annular preventer.Open the accumulator system to the closing unit and charge the accumulatorsystem to its designed operating pressure using the pumps.

ACCUMULATOR TESTS

Accumulator Precharge Pressure Test

8.A.22 This test should be conducted on each well prior to connecting the closingunit to the blowout preventer stack. Test should be conducted as follows-

a. Open the bottom valve on each accumulator bottle and drain the hydraulicfluid into the closing unit fluid reservoir.

b. Measure the nitrogen precharge pressure on each accumulator bottle, usingan accurate pressure gauge attached to the precharge measuring port, andadjust if necessary.



8 - 13

Accumulator Closing Test

8.A.23 This test should be conducted on each well prior to pressure testing theblowout preventer stack. Test should be conducted as follows:

a. Position a joint of drill pipe in the blow out preventer stack.

b. Close off the power supply to the accumulator pumps.

c. Record the initial accumulator pressure. This pressure should be thedesigned operating pressure of the accumulators. Adjust the regulator toprovide 1500 psi operating pressure to the annular preventer.

d. Simultaneously turn the control valves for the annular preventer and for onepipe ram (having the same size ram as the pipe used for testing) to theclosing position and turn the control valve for the hydraulically operatedvalve to the opening position.

e. Record the time required for the accumulators to close the preventers andopen the hydraulically operated valve. Record the final accumulator pressure(closing unit pressure). This final pressure should be at least 200 psi abovethe precharge pressure.

f. After the preventers have been opened, recharge the accumulator system toits designed operating pressure using the accumulator pumps.

8 - 14



Figu

re 8

.A.1

EX

AM

PL

E B

LO

WO

UT

PR

EV

EN

TE

RC

LO

SIN

G U

NIT

AR

RA

NG

EM

EN

T

PU

MP

PU

MPB

LOW

OU

TP

RE

VE

NT

ER

TE

ST

LIN

E

TE

ST

F

LUID

LIN

E

NE

ED

LE V

ALV

ES

AC

CU

MU

LAT

OR

BA

NK

S

FU

LL-O

PE

NIN

G V

ALV

ES

PR

ES

SU

RE

RE

GU

LAT

OR

(150

0-30

00 P

SI)

VA

LVE

A

ND

G

AU

GE

RE

LIE

F

VA

LVEF

ULL

OP

EN

ING

VA

LVE

CO

NN

EC

TIO

N F

OR

AN

OT

HE

R P

UM

P

PR

ES

SU

RE

RE

GU

LAT

OR

(0-1

500

PS

I)

VA

LVE

AN

D

GA

UG

E

NO

TE

:P

LUG

VA

LVE

IN C

LOS

ING

LIN

E A

DJA

CE

NT

TO

AN

NU

LAR

PR

EV

EN

TE

R T

O F

AC

ILIT

AT

ELO

CK

ING

CLO

SIN

G P

RE

SS

UR

EO

N P

RE

VE

NT

ER

.T

O A

NN

ULA

RB

LOW

OU

TP

RE

VE

NT

ER

TO

CH

OK

E

LIN

E V

ALV

ET

O R

AM

B

LOW

OU

TP

RE

VE

NT

ER

S

CH

EC

K

VA

LVE

CH

EC

K

VA

LVE

FO

UR

-WA

Y V

ALV

ES

(NO

TE

: SH

OU

LD N

OT

CO

NTA

IN

CH

EC

K V

ALV

E A

ND

SH

OU

LDB

E IN

PO

WE

R O

N P

OS

ITIO

N)

RE

GU

LAT

OR

BY-

PA

SS

LIN

EC

ON

NE

CT

ION

FO

R

AN

OT

HE

R P

UM

P

FU

LL-O

PE

NIN

G V

ALV

E

FLU

ID

RE

SE

RV

OIR



8 - 15

CLOSING UNIT PUMPS

TO RIG

TO CLOSING UNITMANIFOLD AND ACCUMULATORS

STORAGE TANKFOR RIG AIR

ELECTRICAL POWER SUPPLY

CHECK VALVE

AIR COMPRESSORS

CLOSING UNIT PUMPS


SEPARATE GENERATOR

RIG GENERATOR

Figure 8.A.2EXAMPLE REDUNDANT AIR/ELECTRIC SYSTEMS

FOR OPERATING CLOSING UNIT PUMPS

Figure 8.A.3EXAMPLE REDUNDANT ELECTRICAL SYSTEMS


8 - 16



CLOSING UNIT PUMPS

NITROGEN

RIG GENERATOR

OPTIONAL


Figure 8.A.4EXAMPLE REDUNDANT AIR/NITROGEN SYSTEMS


Figure 8.A.5EXAMPLE REDUNDANT ELECTRIC/NITROGEN SYSTEMS


CLOSING UNIT PUMPS

NITROGEN

CHECK VALVE

TO RIGCHECK VALVE

STORAGE TANKFOR RIG AIR

OP

TIO

NA

L




8 - 17

Calculation of Accumulator Size

The volume of the accumulator system as calculated by using “Boyle’s law”:

P1V1 = P2V2

where

P1 = Maximum pressure of the accumulator when completely chargedP2 = Minimum pressure left in accumulator after use. (Recommended

minimum is1200 psi)V = Total volume of accumulator (fluid and nitrogen)V1 = Nitrogen gas volume in accumulator at maximum pressure P1.V2 = Nitrogen gas volume in accumulator at minimum pressure P2.V2 = V, plus usable fluid maximum to minimum pressure.V2-V1 = Total usable fluid with safety factor usually 50% included.3000 psi system precharged to 1000 psi; V = 3V1

Figure 8.0.6 ACCUMULATOR SIZINGS

8 - 18



Surface Accumulators (Refer to Fig 8.0.6)

For the purpose of simplicity, the effects of temperature and nitrogen gascompressibility will be ignored and Boyle’s gas law applied to determine thevolume of nitrogen present in the accumulator bottle when fully charged andwhen usable hydraulic fluid has been expelled to operate the BOP functions.

In an 11 gallon accumulator bottle the volume of nitrogen it contains before anyfluid is pumped in will be 10 gallons (the rubber bladder occupies a volume of1 gallon).

According to Boyle’s gas law:

P1 x V1 = P2 x V2 and also P1 x V1 = P3 x V3

where:-P1 = nitrogen precharge pressure of 1000 psiP2 = minimum operating pressure of 1200 psiP3 = maximum operating pressure of 3000 psiV1 = bladder internal volume at precharge pressure (11 gal - 1 gal)V2 = bladder internal volume at minimum operating pressure, P2 (in gals)V3 = bladder internal volume at maximum operating pressure, P3 (in gals)

therefore:-

1000 psi x 10 gals = 1200 psi x V2

and

1000 psi x 10 gals = 3000 psi x V3

giving

V2 = 1000 psi x 10 gals = 8.33 gals1200 psi

and

V3 = 1000 psi x 10 gals = 3.33 gals3000 psi

The usable volume of hydraulic fluid expelled from the bottle as the nitrogenexpands from V3 (3.33 gals) at 3000 psi to V2 (8.33 gals) at 1200 psi will be equalto:-

V2 - V3 = 8.33 gals - 3.33 gals = 5 gals



8 - 19

Subsea Accumulators

The nitrogen precharge pressure must be increased in the subsea accumulatorbottles in order to account for the hydrostatic pressure of the hydraulic fluid inthe power fluid supply hose, when calculating the amount of usable fluid volume.As an added safety factor the sea water gradient is used for this purpose,i.e. .445 psi/ft.

If operating in 1500 ft of water, the hydrostatic pressure would be:-

1500 ft x .445 psi/ft = 667.5 or 668 psi (rounded off).

Thus the nitrogen precharge would need to be increased by 668 psi.

i.e. 1000 psi + 668 psi = 1668 psi.

therefore:-P1 = nitrogen precharge pressure of 1668 psi (1000 psi + 668 psi)P2 = minimum operating pressure of 1868 psi (1200 psi + 668 psi)P3 = maximum operating pressure of 3668 psi (3000 psi + 668 psi)V1 = bladder internal volume at precharge pressure (11 gal - 1 gal)V2 = bladder internal volume at minimum operating pressure, P2 (in gals)V3 = bladder internal volume at maximum operating pressure, P3 (in gals)

therefore:-1668 psi x 10 gals = 1868 psi x V2 and 1668 psi x 10 gals = 3668 psi x V3

giving:-V2 = 1668 psi x 10 gals = 8.93 gals and V3 = 1668 psi x 10 gals = 4.55 gals

1868 psi 3668 psi

The usable volume of hydraulic fluid per subsea bottle in 1500 ft of water wouldbe the difference between these two volumes.

V2 - V3 = 8.93 gals - 4.55 gals = 4.38 gals.

Application of the above calculation now makes it possible to determine the totalnumber of accumulator bottles required both on the surface and subsea, given thefollowing opening and closing volumes of hydraulic fluid for a typical 18.75 inchsubsea BOP stack

Annular preventer 44 gals to close 44 gals to openRam preventer 17.1 gals to close 15.6 gals to openFailsafe valves 0.6 gals to close 0.6 gals to open

8 - 20



Assuming that company policy is to have sufficient subsea accumulator capacityto close:

1 annular1 ram preventer4 failsafe valves

then the usable volume required will be 44 gal + 17.1 gal + (4 x 0.6 gal) = 63.5 galsand since each bottle can deliver 4.38 gals then:

63.5 gals = 14.49 or 15 bottles will be required subsea.4.38 gal/bottle

If the BOP stack consists of:

2 annular preventers4 ram preventers8 failsafe valves

then the total volume of hydraulic fluid required to open and close all of the BOPfunctions together will be:

CLOSE OPEN2 x annular preventers 2 x 44 gal = 88 gal 2 x 44 gal = 88 gal4 x ram preventers 4 x 17.1 gal = 68.4 gal 4 x 15.6 gal = 62.4 gal8 x failsafe valves 8 x 0.6 gal = 4.8 gal 8 x 0.6 gal = 4.8 gal–––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––––TOTAL 161.2 gal 155.2 gal

Including a 1.5 safety factor will give a grand total of

(161.2 gal + 155.2 gal) x 1.5 = 474.6 gals.

Since 63.5 gals are available subsea, the surface accumulators will have to supply(474.6 gal - 63.5 gal) = 411.1 gals. As calculated above, the usable fluid from eachsurface accumulator bottle is 5 gals therefore:

411.1 gals = 82.22 or 83 bottles will be required on surface.5 gal/bottle



8 - 21

SECTION 8-BCLOSING UNITS—SUBSEA INSTALLATIONS

VARIANCE FROM SURFACE INSTALLATIONS

8.B.1 Closing unit systems for subsea installations are basically the same as thoseused in surface installations except more accumulator volume is normally requiredand some of the accumulator bottles may be mounted on the subsea blowoutpreventer stack.

ACCUMULATOR REQUIREMENTS

Volumetric Capacity

8.B.2 As a minimum requirement, closing units for subsea installations should beequipped with accumulator bottles with sufficient volumetric capacity to providethe usable fluid volume (with pumps inoperative) to close and open the rampreventers and one annular preventer. Usable fluid volume is defined as thevolume of fluid recoverable from an accumulator between the accumulatoroperating pressure and 200 psi above the precharge pressure.

8.B.3 In sizing subsea mounted bottles, the additional precharge pressure requiredto offset the hydrostatic head of the sea-water column and the effect of subseatemperature should be considered.

Response Time

8.B.4 The closing system should be capable of closing each ram preventer within45 seconds. Closing time should not exceed 60 seconds for annular preventers.

Requirements for Accumulator Valves

8.B.5 Multi-bottle accumulator banks should have valving for bank isolation. Theisolation valves should have a rated working pressure at least equivalent to thedesigned working pressure of the system to which they are attached. The valvesmust be in the open position except when the accumulators are isolated forservicing, testing, or transporting.

Accumulator Types

8.B.6 Both separator or float type accumulators (refer to Para. 9.A.l) may be used.

8 - 22



HYDRAULIC FLUID CONTROL MIXING SYSTEM

8.B.7 The hydraulic fluid reservoir should be a combination of two storagesections; one section containing mixed fluid to be used in the operation of theblowout preventers, and the other section containing the concentrated water-soluble hydraulic fluid to be mixed with water to form the mixed hydraulic fluid.This mixing system should be automatically controlled so that when the mixedfluid reservoir level drops to a certain point, the mixing system will turn on andwater and hydraulic fluid concentrate will be mixed into the mixed fluid reservoir.The mixing system should be designed to mix at a rate equal to the total pumpoutput.

PUMP REQUIREMENTS

8.B.8 A subsea closing unit control system should include a combination of air andelectric pumps. A minimum of two air pumps should be in every system alongwith one or two electric powered triplex pumps. The combination of air andelectric pumps should be capable of charging the entire accumulator system fromthe precharge pressure to the maximum rated charge pressure in fifteen minutes orless. The pumps should be installed so that when the accumulator pressure dropsto 90 percent of the preset level, a pressure switch is triggered and the pumps areautomatically turned on.

CENTRAL CONTROL POINT

8.B.9 A subsea closing unit control system should have a central control point. Fora hydraulic system, this should be a manifold capable of controlling all thehydraulic functions on the blowout preventer stack. The hydraulic control systemshould consist of a power section to send hydraulic fluid to subsea equipment anda pilot section to transmit signals subsea via pilot lines. When a valve on thecontrol manifold is operated, a signal is sent subsea to a control valve, which whenopened allows hydraulic fluid from the power fluid section to operate the blowoutpreventers. Pressure regulators on the surface control manifold send pilot signalsto subsea regulators to control the pressure of the hydraulic fluid at the preventers.The surface control system should also include a flow meter which, by a measureof the volume of fluid going to a particular function, will indicate if that function isoperating properly. The hydraulic manifold should be located in a safe but readilyaccessible area.

8.B.10 An Electro-hydraulic system should have a central control point whichinterfaces various signals electronically and sends one set of signals electrically tothe subsea solenoid valves, which direct the flow of hydraulic fluid to operate ablowout preventer function. In this system, a flow meter should be used toprovide an indication of the proper flow of hydraulic fluid and proper operationof the blow out preventer.



8 - 23

OTHER CONTROL PANELS

8.B.11 Subsea control systems should have at least one remote control panel. Thepanel should have a schematic outline of the blowout preventer stack and providefor remote panel activation. There should be a remote control panel located on therig floor adjacent to the driller’s station. This panel should comply withAPI RP 500B: Recommended Practice for Classification of Areas for ElectricalInstallations at Drilling Rigs and Production Facilities on Land and on Marine Fixed andMobile Platforms.* Another remote panel is sometimes located in the toolpusher’soffice. One control station should be located at least 50 feet from the centre line ofthe wellbore.

HOSE AND HOSE REELS

8.B.12 A hydraulic hose bundle may consist of pilot hoses which have an insidediameter of 3/16" or 1/8" or both, and a power hose which is one inch insidediameter. The pilot hoses, as previously described, carry the signals to the subseavalves on the blowout preventer stack, while the main hydraulic fluid is suppliedthrough a hose or rigid line to the pod and accumulators on the blowout preventerstack. The working pressure rating of the hose bundle should equal or exceed theworking pressure rating of the control system. For an Electro-hydraulic system,electrical cables are run subsea to the solenoid valves. The hydraulic power supplyline may be integrated into an electrical cable bundle or may be run separately.

8.B.13 The hose reels should be equipped so that some functions are operablewhile running or pulling the blowout preventer stack or lower marine riserpackage. Recommended functions to be operable at these times are the stackconnector, riser connector, one set of pipe rams, pod latches, and, if applicable, ramlocks.

SUBSEA CONTROL PODS

8.B.14 There should be two completely redundant control pods on the blowoutpreventer stack after drilling out from under the surface casing. Each control podshould contain all necessary valves and regulators to operate the blowoutpreventer stack functions. The control pods may be retrievable or non-retrievable.The hoses from each control pod should be connected to a shuttle valve that isconnected to the function to be operated. A shuttle valve is a slide valve with twoinlets and one outlet which prevents movement of the hydraulic fluid between thetwo redundant control pods.

Page

9. 1 Subsea BOP Control Systems 1

9. 2 Marine Riser Systems 35

SUBSEA BOP CONTROL SYSTEMSAND MARINE RISER SYSTEMSSECTION 9 :


SECTION 9 : SUBSEA BOP CONTROL SYSTEMS & MARINE RISER SYSTEMS

9 - 1

9 .1 SUBSEA BOP CONTROL SYSTEMS

INTRODUCTION

Every component in a blowout preventer assembly is operated hydraulically bymoving a piston up and down or back and forth. Thus the function of a BOPcontrol system is to direct hydraulic fluid to the appropriate side of the operatingpiston and to provide the means for fluid on the other side of the piston to beexpelled.

On land, jack-up or platform drilling operations the control of the BOP is easilyachieved in a conventional manner by coupling each BOP function directly to asource of hydraulic power situated at a safe location away from the wellhead.Operation of a particular BOP function is then accomplished by directinghydraulic power from the control unit back and forth along two large bore lines tothe appropriate operating piston.

This system uses the minimum number of controlling valves to direct thehydraulic fluid to the required function. It also enables the returning fluid to bereturned to the control unit for further use.

For subsea drilling operations, it is necessary to control larger, more complex BOPassemblies which are remotely located on the sea-bed. In this instance, directcontrol cannot be applied since the resulting control lines connecting the BOPs tothe surface would be prohibitively large to handle. Reaction times would also beunacceptable due to the longer distances to the BOP functions and the consequentpressure drop.

In order to overcome these problems indirect operating systems have beendeveloped. There are two types - hydraulic and multiplex electro-hydraulic ofwhich the indirect hydraulic system is by far the most common.

INDIRECT HYDRAULIC SYSTEM

This reduces the size of the control umbilical by splitting the hydraulic controlfunctions into two -

• Transmitting hydraulic power to the BOP down a large diameter line.

• Transmitting hydraulic signals down smaller lines to pilot valves which in turndirect the operating power fluid to the appropriate BOP function.

The pilot valves are located in control pods on the BOP stack. In order to provide acomplete back-up of the subsea equipment there are two control pods - usuallyreferred to as the blue and the yellow pods.

No attempt is made to recover the hydraulic power fluid once it has been used tooperate a function since this would increase the number of lines required in theumbilical. Instead the fluid is vented subsea from the control pod.

9 - 2



MULTIPLEX ELECTRO-HYDRAULIC SYSTEM

As greater water depths were encountered the problems of umbilical handling andreaction times became significant. In order to overcome them the hydraulic linescontrolling the pilot valves were replaced by separate electrical cables whichoperate solenoid valves. These valves then send a hydraulic signal to the relevantpilot valve which in turn is actuated and directs power fluid to its associated BOPfunction.

The time division multiplexing system provides simultaneous execution ofcommands and results in a relatively compact electrical umbilical. This typicallyconsists of four power conductors, five conductors for signal transmission andadditional back-up and instrumentation lines. With the armoured sheath theumbilical has a resulting diameter of some 1.5 inches with a weight of about 3 Ib/ft in air.

ACOUSTIC SYSTEM

In addition to either of the� primary control methods mentioned above, thesubsea BOP stack can also be equipped with an acoustic emergency back-upsystem. In principle this is similar to the other two systems but with the hydraulicor electrical commands to the pilot valves being replaced with acoustic signals.Being a purely back-up system the number of commands is limited to those whichmight be required in an absolute emergency.

INDIRECT HYDRAULIC BOP CONTROL SYSTEM

The main manufacturers of control systems are Cameron Iron Works, NL Shaffer,Koomey, and the Valvcon Division of Hydril. The NL Shaffer and Koomey systemswill be discussed in detail to illustrate the general concept since these are probablythe most common types.

9.1.1 OVERVIEW

Fig 9 .1 shows the general arrangement. Fluid used to operate the functions on theBOP stack is delivered from the hydraulic power unit on command from thecentral hydraulic control manifold. This contains the valves which direct pilotpressure to the pilot valves in the subsea control pods and which are operatedeither manually or by solenoid actuated air operators.

In this way the manifold can be controlled remotely via the actuators from themaster electric panel (usually located on the rig floor) or from an electric mini-panel (located in a safe area). The system may include several remote mini-panelsif desired. An electric power pack with battery back-up provides an independentsupply to the panels via the central control manifold.



9 - 3

The pilot fluid is sent to the subsea control pods through individual, smalldiameter hoses bundled around the larger diameter hose which delivers the powerfluid. In order to provide complete redundancy for the subsea portion of thecontrol system there are two independent hydraulic hose bundles and twoindependent control pods.

The hydraulic hose bundles (or umbilicals) are stored on two hose reels, each ofwhich is equipped with a special manual control manifold so that certain stackfunctions can be operated whilst the stack is being run. Hydraulic jumper hosebundles connect the central hydraulic control manifold to the two hose reels. Eachumbilical is run over a special sheave and terminates in its control pod.

For repair purposes each pod along with its umbilical can be retrieved and runindependently of the BOP stack. In order to do this, the pod and umbilical is runon a wireline which is usually motion compensated. In some designs of controlsystem, the umbilical is run attached to the riser in order to give it more supportand reduce fatigue at hose connections. The pod is still attached to a wireline forretrieval purposes. This design has the advantage of not having to handle theumbilicals whenever the pod is pulled but has the disadvantage of requiring moresubsea remote hydraulic connections. Guidance of the pod is provided by theguidewires and guideframe as shown.

Fig 9.2 is a block diagram of the hydraulic flow system for a stack function. Thehydraulic fluid is prepared and stored under pressure in the accumulators. Someaccumulators (usually two) are dedicated to storing fluid for use in the pilot linenetwork and the remaining accumulators contain the fluid that is used to powerthe various BOP functions.

9 - 4



Figure 9.1



9 - 5

Figure 9.2 SUBSEA CONTROL SYSTEM - BLOCK DIAGRAM

MIXED FLUIDRESEVOIR

CONCENTRATE

AIR & ELECTRICPUMPS

(POWER FLUID)

AIR PUMP(PILOT FLUID)

ACCUMULATORS(PILOT FLUID)

WATER

JUNCTION BOX(YELLOW)

HOSE REEL(YELLOW)

JUNCTION BOX(BLUE)

HOSE REEL(BLUE)

ACCUMULATORS(STACK MOUNTED)

BOP STACK

ISOLATIONVALVE

CHECKVALVE

POD SELECTVALVE

VENT

ISOLATIONVALVE

SHUTTLEVALVE

ISOLATIONVALVE

SHUTTLEVALVE

REGULATOR

SPMPILOT SPM

PILOT

PILOT psi

ACCUMULAT OR psi

REGULATOR psi

VENT psi

KEY

ACCUMULATORS(POWER FLUID)

9 - 6



The power fluid is routed to the subsea control pod selected by the pod selectorvalve which is located in the central hydraulic control manifold. The line to thenon-selected pod is vented. When power fluid reaches the pod, it is combinedwith fluid stored at the same pressure in subsea accumulators, located on the BOPstack. The pressure of the combined fluid is then reduced, to that required tooperate the stack function, by a subsea regulator situated in the control pod.Adjustment of this regulator is performed from the surface via dedicated pilot andread-back lines in the hose bundle.

Pilot fluid is always directed to both pods at the same time. When the pilot fluidfor a particular function reaches each pod it lifts the spindle of its associated SPM(sub plate mounted) pilot valve. In the pod to which the power fluid has been sentthis will allow the fluid to pass through the SPM valve and be routed to the stackfunction via a shuttle valve.

A summary of this operating sequence is shown in Fig 9.3.

9.1.2 OPERATING SEQUENCE

A more detailed description of the sequence of events that occur when a functionis operated will now be given with reference to the flow diagram in Figs 9.3a b andc. Each piece of equipment on the BOP stack has a corresponding pilot controlvalve on the central hydraulic control manifold which actuates the appropriateSPM valve. The control valve is a four-way, three position valve and can befunctioned manually or by an air operator.

CLOSE FUNCTION

In Fig 9.3a one of the BOP rams is being closed using the drillers master controlpanel. Pushing the ‘close’ button on this panel actuates the solenoid valves on thehydraulic manifold thus allowing air pressure to move the pilot control valve tothe ‘close’ position. The solenoid valve on the right in the diagram vents the otherside of the air cylinder.

With the pilot control valve in the ‘close’ position, pilot fluid at 3000 psi is sentdown the umbilical to the RAMS CLOSE SPM valve in the subsea control pods.The pressure lifts the spindle in this valve so that it seals against: the upper seat,thus blocking the vent .

At the same time power fluid at its regulated pressure is allowed past the bottomof the spindle and into the valve block in the male and female sections of thecontrol pod. From the bottom of the female section, the power fluid then travelsthrough the shuttle valve to the ‘close’ side of the BOP ram cylinder.

Simultaneous reciprocal action in the RAMS OPEN SPM valve vents the hydraulicfluid from the ‘open’ side of the BOP ram.



9 - 7

Figure 9.3 OPERATING SEQUENCE - GENERAL

9 - 8



Figure 9.3.A OPERATING SEQUENCE - CLOSE FUNCTION

PILOT psi

ACCUMULAT OR psi

REGULATOR psi

VENT psi

KEY

CLOSE BLOCK OPEN

MIX WATER TANK

POWER FLUIDACCUMULATORS

PILOT FLUIDACCUMULATORS

SOLENOIDVALVE

PILOT CONTROL VALVE

POD SELECT VALVE

AIROPERATOR

SOLENOIDVALVE

CONTROLPANEL

RIG AIR

CLOSESPM

OPENSPM

SHUTTLE VALVE

SHUTTLE VALVE

BOP RAMS

YELLOW POD BLUE PODREGULATOR

INACTIVE POD



9 - 9

Figure 9.3.B OPERATING SEQUENCE - BLOCK

CLOSE BLOCK OPEN

MIX WATER TANK



SOLENOIDVALVE

PILOT CONTROL VALVE

POD SELECT VALVE

AIROPERATOR

SOLENOIDVALVE

CONTROLPANEL

RIG AIR

CLOSESPM

OPENSPM

SHUTTLE VALVE

SHUTTLE VALVE

BOP RAMS

YELLOW POD BLUE PODREGULATOR

INACTIVE POD

PILOT psi

ACCUMULAT OR psi

REGULATOR psi

VENT psi

KEY

9 - 10



Figure 9.3.C OPERATING SEQUENCE - OPEN FUNCTION

CLOSE BLOCK

MIX WATER TANK



SOLENOIDVALVE

PILOT CONTROL VALVE

POD SELECT VALVE

AIROPERATOR

SOLENOIDVALVE

CONTROLPANEL

RIG AIR

CLOSESPM

OPENSPM

SHUTTLE VALVE

SHUTTLE VALVE

BOP RAMS

YELLOW POD BLUE POD

OPEN

REGULATOR

INACTIVE POD

PILOT psi

ACCUMULAT OR psi

REGULATOR psi

VENT psi

KEY



9 - 11

BLOCK FUNCTION

The block function is used to vent a pilot control valve. By doing this individuallyon each valve a leak in the control system or the preventers can be located andisolated. By centring and venting all the valves when the accumulator unit is firstbeing pressurised unintentional and inadvertent operation of the various otherpositions and functions can be eliminated.

Referring to Fig 9.3b, when the ‘block’ button is pressed, both the solenoid valvesare actuated in such a way as to apply pressure to both sides of the air operator.This causes the pilot control valve to be centred which then allows both the pilot‘open’ and ‘close’ lines to be vented. The springs in both the SPM valves then pushthe spindles down so that they seal against the bottom seats and block the flow ofany power fluid through the valves. At the same time this also vents both sides ofthe BOP ram operating cylinders.

OPEN FUNCTION

This sequence is the parallel opposite of the CLOSE function. As shown in Fig 9.3c,when the ‘open’ button is pressed, the solenoid valves on the hydraulic controlmanifold are actuated and allow air pressure to move the operator on the pilotcontrol valve to the ‘open’ position. The solenoid valve on the left in the diagramvents the ‘close’ side of the operating piston.

The pilot fluid can then flow down to the subsea control pod where it lifts thespindle in the RAMS OPEN SPM valve thus blocking the vent and allowing powerfluid to flow through the valve. From the pod the power fluid travels through the‘open’ shuttle valve to the ‘open’ sides of the BOP ram operating cylinders.Simultaneous reciprocal action in the RAMS CLOSE SPM valve allows the fluidfrom the ‘close’ side of the operating cylinders to be vented.

CONTROL FLUID CIRCUIT

In addition to the control fluid circuits used to operate stack functions such as ramor annular preventers, the control system must also perform other functions suchas control of subsea regulators, provide readback pressures, latch/unlatch thesubsea control pods and charge the subsea accumulators.

Fig 9.4 shows a typical control fluid circuit. The hydraulic fluid is mixed,pressurised and stored in accumulator bottles by the hydraulic power unit. A pilotoperated accumulator isolator valve is provided to allow the pumps to charge thesubsea accumulators. When control fluid is used, it passes through a totalisingflow meter in the hydraulic control manifold and then through the pod selectorvalve which directs it to the chosen subsea pod. After passing through the jumper hose and the subsea hose bundle to the controlpod, the fluid supplies the hydraulically operated subsea regulators. These reducethe fluids pressure to that required to operate the particular BOP function desired.The fluid is also routed to a SPM valve in the pod which is controlled by theaccumulator isolator valve on the hydraulic control manifold. In the open positionthis SPM valve allows the control fluid to charge the stack mounted accumulatorbottles. Shuttle valves allow the bottles to be charged from either pod.

9 - 12



M

FLUIDMIXING SYSTEM

WATERSUPPLY

WATERSOLUBLECONCENTRATE

MIXEDFLUID

RESERVOIR

ACCUMULATOR UNIT

ACCUMULATORPRECHARGED TO

1000 PSI

ACCUMULATORISOLATOR VALVE PRESSURE SWITCH

SET AT 3000 PSI

TRIPLEX PUMP

ACCUMULATORISOLATOR VALVE

(PILOT) FLOW METER

POD SELECTORVALVE

HYDRAULICMANIFOLD

PILOTSUPPLY

QUICK DISCONNECTJUNCTION BOX

BLUE YELLOW

TO YELLOWHOSE REEL

BLUE HOSEREEE

HYDRAULIC REGULATORS

CONTROLFLUID

TOSPM

VALVES

FROM YELLOW POD

STACK MOUNTEDACCUMULATOR

1/4" SHUTTLE VALVE

FROM YELLOW POD

STACK MOUNTEDACCUMULATOR

ISOLATORVALVE

1 1/4" SHUTTLEVALVE

POD MOUNTEDACCUMULATOR

ISOLATORVALVE

BLUE POD


Figure 9.4 SUBSEA CONTROL SYSTEM - HYDRAULIC SCHEMATIC



9 - 13

PILOT FLUID CIRCUIT

The pilot valves in the subsea pods are controlled from the surface by means ofcontrol valves located in the hydraulic control manifold. These control valves canbe operated either manually from the control manifold itself or remotely from anelectrical panel via pneumatic solenoid valves.

Any BOP stack function such as a failsafe valve, which requires pressure only toopen or close it is called a 2-position function. There is an ‘operate’ position and a‘vent’ position. The latter position is used to release pressure from the operatingside of the pilot valve.

Fig 9.5 shows a typical 2-position function pilot circuit. The control valve, a 1/4',four-way manipulator valve, can be controlled from a remote panel via the twosolenoid valves which can place the valve either in the ‘open’ or ‘vent’ positions. Apressure switch connected to the discharge line of the control valve is activatedwhen a pilot signal is present and lights up the appropriate lamp on the controlpanel.

In the ‘open’ position the pilot signal is transmitted to the subsea control podswhere it operates its associated pilot valve which then allows the power fluid toflow through the selected pod to the BOP function.

A BOP stack function requiring pressure to both open and close is called a 3-position function. The hydraulic pilot fluid circuit for a 3-position function isshown in Fig 9.6. It requires the use of three solenoid valves, the ‘block’ solenoidvalve being used in conjunction with two shuttle valves in order to centre thecontrol valve.

A pressure switch is connected to each discharge line of the control valve and willtransmit a signal to the appropriate control panel lamp whenever a pilot signal ispresent. The operation of the 3-position pilot circuit is as described above.

The main components of the control system and some of the other operatingsequences are now described in more detail.

9 - 14



Blue Yellow

Hydraulic Pilot SupplySolenoid

Open

Vent

1/4" Manipulator Valve OrSelector Valve With 2 PositionAir cylinder

Pressure Switch

Air Supply

Vent

Quick DisconnectJunction Box

To YellowHose Reel

Hydraulic Manifold


Blue Hose ReelQuick DisconnectJunction Box

SPM ValveHydraulicRegulator

Blue Pod

Control FluidSupply

Shuttle Valve

FromYellow Pod

Open

Failsafe Valve OperatorShowing Spring HousingAnd Gate

Figure 9.5 PILOT FLUID CIRCUIT (2-POSITION FUNCTION)



9 - 15

YELLOWBLUE

Hydraulic Pilot Supply Solenoid

1/4" Air Shuttle Valve

1/4"Manipulator Valve

Air Supply

Open

Block

ClosePressure Switch

Vent

Quick DisconnectJunction Boo To Yellow Hose Reel NOTE: - Three Solenoid Valves

Can Be Used For Critical Functions, Such As Shear Rams

Blue Hose Reel


Control Fluid Supply

Blue Pod

SPM Valve

Shuttle Valve

From Yellow Pod

From Yellow Pod

CloseOpen

Ram Type BOP

Figure 9.6 PILOT FLUID CIRCUIT (3-POSITION FUNCTION)

9 - 16



9.13 HYDRAULIC POWER UNIT

This unit contains the mixing system, high pressure pumps and accumulatorbanks as shown in Fig 9.4.

MIXING SYSTEM

The hydraulic power unit supplies hydraulic fluid to the entire control system. Itrequires fresh water, soluble oil, glycol (for freeze protection), compressed air andelectrical power for operation. Two small reservoirs contain the soluble oil andglycol which are automatically blended with fresh water to make up the hydraulicfluid which is then stored in a large reservoir known as the mixed fluid tank.

Since the control system is an ‘open’ one in that the used hydraulic power fluid isvented into the sea, the type of soluble oil used must be completely biodegradable.Additives to prevent bacteria growth and to inhibit corrosion are also frequentlyincluded in the mix water.

The soluble oil reservoir has a capacity of at least 110 gal whilst the mix fluid tankshould be capable of holding sufficient fluid to charge the system accumulatorsfrom their pre-charge condition to their maximum operating pressure. All thetanks are fitted with sight glasses and a low-level alarm system which activates awarning light and horn on the control panels.

The proper mixing fluid ratio is maintained by air operated hydraulic pumps, awater pressure regulator, a double acting motor valve and a water flow rateindicator. A reservoir float switch is used to control operation of the mixing systemin order to maintain the correct level of fluid and to ensure a continued supply forthe control system.

Water/additive concentrations can be adjusted by setting the mixing pump to runat the appropriate rate. A minimum rig water supply pressure of 25 psi is typicallyrequired for the correct operation of the mixing system and to provide a fluidsupply at least equal to the rate at which mix fluid is drawn from the tank by thehigh pressure pumps.

HIGH PRESSURE PUMPS

These are the pumps which take the fluid from the mix tank and transfer it to theaccumulator bottles, under pressure, where it is stored ready for use by thesystem. Typically, three air powered and two electrically powered pumps are used.During normal operation the electric pumps are used to recharge the system.However if these cannot keep up with demand, or fail in some way, then the airpowered pumps can assist or take over completely.

The electric pump assemblies consist of a heavy duty triplex reciprocating plungerpump with a chain and sprocket drive and powered by an explosion-proof motor.Pump capacity should be such that they can charge the system accumulators fromtheir pre-charge condition to their maximum operating pressure in less than 15minutes. See Section 9.1.4 below for calculations involving accumulator andcharging pump capacities.



9 - 17

From'OPEN'SPM

From'CLOSE'

SPM

Both Lines Vented

PILOT PRESSURE

To'CLOSE'

SPM

From'OPEN'SPM

Vent

From'CLOSE'

SPM

PILOT PRESSURE

To'OPEN'SPM

Vent

SELECT 'BLOCK'

SELECT 'CLOSE' SELECT 'OPEN'

SELECT 'BLOCK'

SELECT 'CLOSE' SELECT 'OPEN'

Power Fluid Power Fluid

FromOpen

FromClose

Both Lines BlockedToCloseSide

FromOpenSide

Vent

FromCloseSide

ToOpenSide

Vent to Mix Tank

PowerFluid

Blocked

B) SURFACE SELECTOR VALVEPV

AB

A) SUBSEA MANIPULATOR VALVEPV

AB

Figure 9.9 ROTARY SHEAR SEAL TYPE VALVES

9 - 18



PILOTACCUMULATORS

SUPPLY FROMPOWER UNIT

VENT TO MIXFLUID TANK MANUAL

CONTROLHANDLE

PRESSURE SWITCH

'OPEN' PILOT LINE

'CLOSE' PILOT LINE

JUMPERHOSES

PRESSURE SWITCH

AIR OPERATOR

TYPICAL PILOT CONTROL VALVE

REGULATOR CONTROL

Since the power fluid arrives at the subsea control pod at 3000 psi and the BOPfunctions have a maximum normal operating pressure of 1500 psi, regulators areneeded in the pods - one is provided for the annular preventers and one for the rampreventers. Fig 9.11 shows how the subsea regulator is controlled from the surface.

A 1/2" air operated pilot regulator in the control manifold transmits pilot pressureto the subsea regulator in order to adjust its setting. The air operator can bemanipulated either manually using an air regulator on the control manifold orremotely from another control panel. When operated from a remote panel asolenoid valve is used to increase the air pressure by allowing rig air to flow into a1 gallon receiver connected to the air pilot line. The receiver acts as a surgeprotector for the pilot regulator. Decreasing the air pressure is achieved by using asolenoid valve to vent the line to atmosphere.

PRESSURE READBACK

In order to ensure that the subsea regulator has set the desired operating pressurethe manifold incorporates a readback system. The output of each subsea regulatoris connected through a 1/8" hose in the umbilical back to a pressure gauge in thecontrol manifold. Pressure transducers transmit the readback pressures to remotepanels. A shuttle valve also in the manifold unit connects the lines from bothumbilicals and isolates the active and inactive pods. All the electrical components are housed in separate explosion proof housings onthe control manifold unit. One housing contains the solenoid valves and anothercontains the transducers and pressure switches. The pressure switches are typicallyset to be activated ‘on’ when pressure in the pilot line to the ram or failsafe SPMreaches 1000 psi and to switch ‘off, when the pressure falls to below 700 psi.

FIGURE 9.10 PILOT CIRCUIT



9 - 19

Figure 9.11 SUBSEA REGULATOR CONTROL CIRCUIT

DECREASE INCREASE

YELLOWBLUE

REGULATORPRESSURE

REMOTEPANELREGULATOR PRESSURE

READBACK

VENT

AIRSUPPLY

DECREASESOLENOID

INCREASESOLENOID

AIRSUPPLY

REGULATORPRESSURE

PRESSURETRANSDUCER

1 GALLON AIRRECEIVER

1/2" AIR PILOT REGULATORPILOT

SUPPLY

REGULATORPRESSUREREADBACK

PRESSURETRANSDUCER

QUICK DISCONNECTJUNCTION BOXES

TO YELLOWHOSE REEL

BLUE HOSE REEL


REGULATED FLUIDSUPPLY TO SPM

VALVES

HYDRAULICREGULATOR

POWER FLUID SUPPLY

HYDRAULICCONTROLMANIFOLD

BLUE POD

9 - 20



9.1.6 CONTROL PANELS

These panels permit the operation of the manifold unit from remote locations.Usually two remote panels are used - a master one on the drill floor, and a mini-panel in a relatively safe location such as a rig office. Other mini-panels can beintegrated into the system if desired.

The drillers master panel is normally explosion proofed or air-purged since it islocated in a hazardous area. It contains a set of graphically arranged push-button/indicating lights for operation and status indication of each stack function. Theregulator pressures are controlled by increase/decrease push-buttons and thereare gauges for monitoring pilot and readback values. A digital readout of the flowmeter located on the control manifold is also provided.

Many types of drillers panel also include controls for the operation of the rigdiverter system which is controlled in a similar way to a surface BOP system.

The mini-panel is usually not required to be explosion proof. It operates in thesame way as the master panel but does not include the pressure gauges. Bothpanels include ‘lamp test’ facilities to check for burnt out lamps. They also containalarms for low hydraulic fluid level, low accumulator pressure, low rig airpressure and an alarm to indicate that the emergency battery pack is in use.

The remote panels contain all the necessary electrical switches to operate thesolenoid valves on the hydraulic control manifold which in turn control the airoperators of the pilot control valves. Lights on the panels (red, amber, green)indicate the position of the 3-way valve (open, block, close) and there is a memorysystem so that when a function is in block with the amber light on, the actualposition of the function (the red or green light) will also be displayed.

Fig 9.12 shows in more detail the operation of a BOP function from a remote panel.Although the lights on the panels show the position of the BOP functions, thecontrol buttons are not active until a ‘push and hold’ button is depressed in orderto allow the supply of electrical power to the panel. The sequence of events thatoccur is as follows -



9 - 21

CLOSE

1. The ‘press and hold’ button is held in to activate the panel.

2. The ‘close’ button is pressed.

3. Current flows to the ‘close ‘ solenoid valve which lifts to supply air to the3-position air operator.

4. The air operated piston moves the pilot control valve to the ‘closes positionand pilot pressure is sent to the subsea control pod.

5. Successful pressurisation of the pilot line to the control pod actuates apressure switch on the control manifold.

6. Current flows through an electronic card which illuminates the lamp of the‘close’ button indicating that the function is now closed.

7. The ‘press and hold’ button is released, the ‘close’ lamp remains illuminated.

Figure 9.12A REMOTE OPERATION -CLOSE FUNCTION

MIX WATER TANK


SOLENOIDVALVE

PILOT CONTROL VALVEAIROPERATOR

SOLENOIDVALVE

CONTROLPANEL

RIG AIR

CLOSE BLOCK OPEN

PILOT LINES TOSUBSEA PODS

'OPEN' PRESSURE SWITCH

'CLOSE' PRESSURE SWITCH

ELECTRONICCARD

ELECTRICSUPPLY

'PUSH AND HOLD'BUTTON

PILOT psi

ACCUMULAT OR psi

REGULATOR psi

VENT psi

KEY

9 - 22



OPEN


2. The ‘open’ button is pressed.

3. Current flows to the ‘open ‘ solenoid valve which lifts to supply air to the3-position air operator.

4. The air operated piston moves the pilot control valve to the ‘open’ positionand pilot pressure is sent to the subsea control pod.

5. Successful pressurisation of the pilot line to the control pod actuates apressure switch on the control manifold.

6. Current flows through an electronic card which illuminates the lamp of the'open’ button and extinguishes the ‘close’ lamp indicating that the function isnow open.

7. The ‘press and hold’ button is released, the ‘open’ lamp remains illuminated.

Figure 9.12B REMOTE OPERATION - OPEN FUNCTION

MIX WATER TANK


SOLENOIDVALVE


SOLENOIDVALVE

CONTROLPANEL

RIG AIR

CLOSE BLOCK OPEN




ELECTRONICCARD

ELECTRICSUPPLY


PILOT psi

ACCUMULAT OR psi

REGULATOR psi

VENT psi

KEY



9 - 23

BLOCK


2. The ‘block’ button is pressed.

3. Current flows to both the ‘close ‘ and ‘open’ solenoid valves which lift tosupply air to both sides of the 3-position air operator piston.

4. The air operated piston moves to a central position which places the pilotcontrol valve in the middle ‘block’ position so that no pilot pressure is sentdown either the ‘close’ or ‘open’ pilot line.

5. Since no pilot line is pressurised, neither pressure switch is activated.

6. The electronic card senses that no pressure switch has been operated andilluminates the ‘block’ lamp.

7. The ‘press and hold’ button is released, the ‘block’ lamp remains illuminated.

Figure 9.12C REMOTE OPERATION - BLOCK FUNCTION

MIX WATER TANK


SOLENOIDVALVE


SOLENOIDVALVE

CONTROLPANEL

RIG AIR

CLOSE BLOCK OPEN




ELECTRONICCARD

ELECTRICSUPPLY


PILOT psi

ACCUMULAT OR psi

REGULATOR psi

VENT psi

KEY

9 - 24



The ‘block’ position is of use to try and locate the position of a hydraulic leak in thesystem by systematically isolating the various BOP stack functions. It is also used todepressurise the pilot lines when attaching junction boxes to the umbilical hosereels.

Note that the illumination of a push button lamp only indicates that a pilot pressuresignal has been generated and not that a function has been successfully operatedsubsea. Indications of a successful subsea function movement are -

a. The flow meter shows that the correct amount of power fluid has been used.

b. There are fluctuations in manifold and readback pressure readings.

c. There is a noticeable drop in accumulator pressure.

The BOP functions can be controlled from any panel at any time during normaloperations. If one panel or a cable to a panel is damaged, destroyed or malfunctionsthen it will not interfere with the operation of the system from any other panel.

An emergency battery pack supplies the electric panels with power for a period ofup to 24 hours (depending on use) in case of failure of the rig supply. The powerpack typically consists of ten 12 volt lead-acid batteries. A battery charger is alsoincluded to maintain the batteries in a fully charged condition ready for immediateuse. Electrical cable connects the remote panels and the battery pack to the junctionboxes on the hydraulic control manifold.

9.1.7 HOSE REELS

The hose bundles are mounted on heavy duty reels for storage and handling and areconnected to the hydraulic control manifold by jumper hoses. The reels are drivenby reversible air motors and include a disc brake system to stop the reel in forwardor reverse rotation.

When the subsea control pod is run or retrieved, the junction box for the jumperhose is disconnected from the hose reel. However in order to keep selected functions‘live’ during running or retrieval operations, five or six control stations are mountedon the side of the reel. These live functions include at least the riser and stackconnectors, two pipe rams and the pod latch. Fig 9.13 is a schematic of the hydraulicsystem through which the power fluid flows to the controlled functions during reelrotation.

Once the BOP has been landed and latched on to the wellhead, the control points onthe side of the reel are shut down and isolated to prevent interference with the fullcontrol system. The regulators on the reel which control the manifold and annularpressures must also be isolated in case they dump pressure when the jumper hoseRBQ plate is attached.

With the supply pressure isolated the 3-position, 4-way valves are used to vent anypressure that may remain trapped in a pilot line holding an SPM valve open. This isnecessary since the reel is fitted with a different type of valve to the control manifoldmanipulator valves. These valves look similar but do not vent when placed in the‘block’ position (see Fig 9.12b).



9 - 25

MAIN HYDRAULICSUPPLY THROUGH

SWIVEL JOINT

JUMPER HOSE FROMHYDRAULIC MANIFOLD

BLUE PODHOSE REEL

MANIFOLDREGULATOR

1/4"SELECTORVALVES

VALVE MANIFOLDMOUNTED ON SIDE

OF HOSE REELHOSE

BUNDLE

BLUE PODJUNCTION BOX

OPENSPM

REGULATOR

CLOSESPM

SHUTTLE VALVE

SHUTTLE VALVEBLUEPOD

FROMYELLOW

POD

OPEN

CLOSE

Figure 9.13 HOSE REEL CONTROL MANIFOLD

9 - 26



9.1.8 UMBILICAL HOSE

The umbilical transmits all power fluid and all pilot signals from the surface to thesubsea control pods. Hydraulic pressure from the regulated side of the subsearegulators is also transmitted through the umbilical to pressure readback gauges atsurface. The power fluid is supplied only to the umbilical of the selected active pod,whereas pilot pressure is normally supplied to both the active and inactive pods.The most common umbilicals contain a 1" ID supply hose for the power fluid whichis surrounded by up to sixty four 1/8" and 3/16" hoses for pilot valve activation andreadbacks. An outer polyurethane covering protects the whole bundle.

Roller sheaves are used to support the umbilical and provide smooth and safehandling where it leaves the hose reel and goes over the moon pool area. Specialclamps are used to attach the hose bundle to the pod wireline at intervals thatcorrespond to the lengths of riser in use.

9.1.9 SUBSEA CONTROL PODS

The subsea control pods contain the equipment that provides the actual fluidtransfer from the hose bundle to the subsea stack. A typical pod assembly(Fig 9.14) consists of three sections -

• a retrievable valve block

• an upper female receptacle block permanently attached to the lower marine riser package

• a lower female receptacle permanently attached to the BOP stack

Control fluid enters the pod at the junction box and is routed either direct to anSPM valve or to one of the two regulators (one for the BOP rams and one for theannular preventers) from where it is sent to the appropriate SPM. When a SPMpilot valve is actuated it allows the control fluid to pass through it to one of theexit ports on the lower part of the male stab and into the upper female receptacleattached to the lower marine riser package.

For those functions which are part of the lower marine riser package the fluid isthen routed out of the upper female receptacle and directed via a shuttle valve tothe functions operating piston. For those functions which are part of the main BOPstack, the fluid is routed through the upper female receptacle and into the lowerfemale receptacle from where it goes via a shuttle valve to the appropriateoperating piston.

Not all the functions on the BOP stack are controlled through pod mounted pilotvalves. Low volume functions such as ball joint pressure are actuated directly fromsurface through 1/4" lines. These are generally referred to as straight throughfunctions.



9 - 27

Figure 9.14 KOOMEY

9 - 28



The integrity of each fluid route between the different sections is achieved byusing a compression seal that is installed in the retrievable valve block section ofthe pod. Compression between the three sections is achieved by hydraulicallylocking the pod into the lower receptacle (which is spring mounted on the BOPstack in order to facilitate easier engagement).

Locking is accomplished by hydraulically extending two dogs that locate underthe bottom of the upper female receptacle. A helical groove on the outside of thelower skirt of the pod ensures correct alignment of the fluid ports. To retrieve thepod independently of the lower marine riser package, the locking pressure is bledoff and the dogs are retracted mechanically when an overpull is taken on theretrieving wire.

A more recent design utilises the same concept but consists of a cube shapedretrievable valve block which latches over two tapered blocks mounted on a baseplate permanently attached to the lower marine riser package. A single taperedblock mounted on a spring base is permanently attached to the BOP stack. Thepacker seals on the retrievable valve block are pressure balanced in a breakawaycondition so that there is no tendency for it to be blown out of the pocket if thepod has to be released under pressure.

Besides the latching system, packer seals and piping, the principal components ofthe retrievable valve blocks are the SPM pilot valves and regulators.

SPM VALVES

As described above these valves direct the regulated power fluid to the desired side ofthe preventer, valve or connector operating piston and vent the fluid from the otherside of the piston to the sea. The annular preventers typically use large 1 1/2" SPMvalves in order to provide sufficient fluid flow, the ram preventers use 1" valves andthe other functions such as failsafe valves and connectors use 3/4" valves. Fig 9.15shows a NL Shaffer 1 in SPM valve.

The valve is a poppet type in which a sliding piston seals at the top and bottom of itstravel on nylon seats. In the normally closed position a spring attached to the top ofthe piston shaft keeps the piston on the bottom seat and prevents the power fluidfrom passing through the valve to the exit port. Power fluid pressure, which ispermanently present, also assists in keeping the valve closed by acting on a smallpiston area on the spindle. In this position fluid from the valve’s associated operatingpiston is vented through the sliding piston at ambient conditions.

When pilot pressure is applied to the valve the sliding piston moves up and sealsagainst the upper seat which blocks the vent ports and allows regulated power fluidto flow through the bottom section of the valve to function the BOP. Note that thepilot fluid therefore operates in a closed system whilst the hydraulic power or controlfluid is an ‘open’ circuit with all used fluid being vented to the sea.

As illustrated in Fig 9.3 two SPM pilot valves are required to operate a BOP function.



9 - 29

Figure 9.15 NL SHAFFER 1" SPM VALVE

REGULATORS

Each subsea control pod contains two regulators - one to regulate pressure for theram preventers and one to regulate the pressure for operating the annularpreventers. Some control systems incorporate a third regulator so that theoperating pressure of each annular preventer can be individually manipulated.

Typical regulators are 1 l/2" hydraulically operated, stainless steel, regulating andreducing valves. As shown in Fig 9.11 the output line of each regulator is tappedand the pressure roused back to a surface gauge through the umbilical. Thisreadback pressure is used to confirm that the subsea regulator is supplying thepower fluid at the pressure set by the pilot surface regulator.

9.1.10 REDUNDANCY

The two subsea control pods are functionally identical. When a pilot control valve(rams close for example) is operated on the hydraulic control manifold a pilotsignal is sent down both umbilicals so that the associated SPM valve in each pod‘fires’. If the pod selector valve is set on yellow then power fluid is sent only to thispod and it is only through the SPM valve in this pod that the fluid will reach theram operating piston. The pod selection has no effect on the pilot system.

Once the yellow pod SPM valve ‘fires’, the power fluid passes through it to ashuttle valve, the shuttle piston of which moves across and seals against the bluepod inlet. The fluid then passes through the shuttle valve to move the ram to theclose position. Fluid from the opposite side of the operating piston is forced outthrough the ‘ram open’ shuttle valve and vented through the ‘ram open’ SPM valveand into the sea.

Upper Seat

Lower Seat

Power Fluid Out

Power RegulatedFluid In

Power Fluid Vent

Pilot PressureIn 3000 PSI

Sea Water Hydrostatic

CompressedSpring

S.P.M. "ACTIVATED"

9 - 30



Note that if the blue pod was now selected to open the rams; then the power fluidwould flow to the ram through the ‘open’ SPM on the blue pod but the fluid fromthe ‘close’ side of the piston would be vented through the yellow pod SPM sincethe ‘close’ shuttle piston would still be sealing the blue pod inlet port.

The shuttle valves should be located as near as possible to their relevant ports onthe BOP stack since the system is redundant only down as far as the shuttle valves.Fig 9.16 shows a NL Shaffer shuttle valve.

Figure 9.16 N LN SHAFFER SHUTTLE VALVE

9.1.11 TROUBLE SHOOTING

Trying to locate a fluid leak or a malfunction of the subsea control system requiresa very thorough knowledge of the equipment and a systematic approach to tracingthe source of the problem. Subsea control systems are very complex in their detailand there are always minor variations and modifications even between similarmodels therefore trouble shooting should always be carried out with reference tothe relevant schematics.

LEAKS

A fluid leak is usually detected by watching the flow meter. If a flow is indicatedwhen no function is being operated or if the flow meter continues to run and doesnot stop after a function has been operated then a leak in the system is implied.



9 - 31

Once it has been determined that there is a leak then the following steps could beused to try and locate its source -

CHECK THE SURFACE EQUIPMENT

• examine the hydraulic control manifold for a broken line or fitting

• examine the accumulator bottles for signs of a fluid leak

• check the jumper hoses for signs of damage

• check the hose reels and junction boxes for loose connections

• examine the hose reel manifold to ensure that all the valves are centred

make certain that the shut-off valve to the reel manifold pressure supply is tightlyclosed (if this is left open when the junction box is connected to the reel, it willallow fluid pressure to be forced back through one of the surface regulators andvent into the mix water tank thus indicating a leak)

If this fails to locate the source of the leak then return to the hydraulic controlmanifold for an item-by-item check of the system -

USE THE POD SELECTOR VALVE TO OPERATE THE SYSTEM ON THE OTHER POD

• If the leak does not stop then it must be located either in the hydraulic control manifold or downstream of the subsea control pods

• if the leak does stop then it will be known which side of the system it is in

Further checks would then be as follows -If the Leak Stops -

• assuming conditions permit, switch back to the original pod and block eachfunction in turn (allow plenty of time for the function to operate and check theflowmeter on each operation)

• if the leak stops when a particular function is set to block then the leak has beenisolated and it is somewhere in that specific function

• in this case run the subsea TV to observe the pod whilst unblocking the function

• if the leak is coming from the pod it will be seen as a white mist in the waterand a bad SPM valve or regulator can be assumed and the options are -

•pull the pod to repair the faulty component

• leave the function in block until the stack or lower marine riser package isretrieved

9 - 32



• If the leak is seen to be coming from below the pod then the options are -

• attempt repairs using divers

• leave the function in block until the stack is brought to surface

If the Leak Does Not Stop -

• check the return line to the mix water tank (if there is fluid flowing from this linethen there is a leaking control valve or regulator)

• check that all the control valves are in either the open closed or block position (apartially open valve can allow fluid to leak past it)

• if the valve positions are correct then disconnect the discharge line from eachvalve - one at a time (fluid flow from a discharge line indicates a faulty valve)

• if the discharge lines do not show any signs of a leak then disconnect thedischarge lines from the regulators in the same way

It can sometimes be the case that the system is operating normally until aparticular function is operated and the flowmeter continues to run after the timenormally required for that function to operate. In this case there is a leak in thatfunction with a likely reason being foreign material in the SPM valve not allowingthe seat to seal thus causing the system to leak hydraulic fluid.

A possible remedy is to operate the valve several times to try and wash out theforeign material. Observe the flowmeter to see if the leak stops. If the leak stillpersists then it will be a case of running the subsea TV to try and locate the leakvisually.

MALFUNCTIONS

Typical control system malfunctions are slow reaction times or no flowmeterindication when a button is pressed to operate a function. A slow reaction timecould be due to -

• low accumulator pressure

• a bad connection between the jumper hose and hose reel

• a partially plugged pilot line

In this case the trouble shooting sequence would be -



9 - 33

CHECK THE PRESSURES

• verify that the gauges are indicating the correct operating pressures

• if a low pressure is indicated then verify correct operation of the high pressurepumps and check the level of hydraulic fluid in the mix water tank

• check that the shut-off valve between the accumulators and the hydrauliccontrol manifold is fully open

CHECK THE HOSES

• if the pressures are good then check all the surface hose connections

• check the junction box connections (if they are not tightly seated, the flow ratethrough the connection can be restricted and cause the function to operate slowly)

CHECK THE PILOT LINES

• if the above checks fail to locate the problem then the final option will be toretrieve the pod and check the pilot line for any sludge that may have settled outfrom the hydraulic fluid (disconnect each pilot line from the pod one at a timeand flush clean fluid through it

In the situation where there is no flowmeter indication when a function button ispressed, this could be due to -

no accumulator or pilot pressure

• the control valve on the hydraulic manifold did not shift

• the flowmeter is not working properly

• there is a plugged pilot line or a faulty SPM valve

CHECK THE PRESSURES

• verify that the gauges are indicating the correct operating pressures

• if a low pressure is indicated then verify correct operation of the high pressurepumps and check the level of hydraulic fluid in the mix water tank

• check for correct operation of the pressure switches

• check the fluid filters to make certain they are not plugged

• check the accumulator pre-charge pressures

9 - 34



• bleed the fluid from the bottles back into the tank and check the nitrogenpressure in each bottle

CHECK THE HYDRAULIC CONTROL MANIFOLD

• use the ‘test’ button on the control panel to make certain that the position lampsare not burnt out

check the air and electrical supply to the hydraulic control manifold

• check the electrical circuits to the control panel and also the solenoid valves andpower relays

• if the air supply pressure is sufficient to work the control valve operator checkfor an obstruction to the manual control handle

• if the valve can be easily operated manually then replace the entire valveassembly with a valve known to be in good working order

CHECK THE FLOWMETER

• if the regulator pressure drops by 300 to 500 psi when the function is operatedand then returns to normal, the function is probably working correctly and theflowmeter is faulty

• monitor the flowmeter on the hydraulic manifold to verify that the one on thedrillers panel is not at fault (the impulse unit that sends the flowmeter signal tothe panel could malfunction)



9 - 35

SECTION 9.2 MARINE RISER SYSTEMS

GENERAL

9.2.1 A marine riser system is used to provide a return fluid flow path from thewellbore to either a floating drilling vessel (semi submersible or hull type) or abottom supported unit, and to guide the drill string and tools to the wellhead onthe ocean floor. Components of this system include remotely operated connectors,flexible joints (balljoints), riser sections, telescopic joints, and tensioners. Data onthese components, together with information on care and handling of the riser, areincluded in this Section, API RP 2K: Recommended Practice for Care and Use of MarineDrilling Risers* and API RP 2Q: Recommended Practice for design and Operation ofMarine Drilling Riser Systems.*

9.2.2 For a drilling vessel, the marine riser system should have adequate strengthto withstand:

a. dynamic loads while running and pulling the blowout preventer stack;

b. lateral forces from currents and acceptable vessel displacement;

c. cyclic forces from waves and vessel movement;

d. axial loads from the riser weight, drilling fluid weight, and any free standingpipe within the riser; and

e. axial tension from the riser tensioning system at the surface (which may besomewhat cyclic) or from buoyancy modules attached to the exterior of theriser.

Unless otherwise noted, internal pressure rating of the marine riser system (pipe,connectors, and flexible joint) should be at least equal to the working pressure ofthe diverter system plus the maximum difference in hydrostatic pressures of thedrilling fluid and sea water at the ocean floor. In deeper waters, riser collapseresistance, in addition to internal pressure rating, may be a consideration ifcirculation is lost or the riser is disconnected while full of drilling fluid.

9.2.3 For bottom-supported units, consideration should be given to similar forcesand loads with the exception of vessel displacement, vessel movement, and highaxial loads. Operating water depths for bottom-supported units are often shallowenough to permit free standing risers to be used without exceeding criticalbuckling limits, with only lateral support at the surface and minimal tension beingrequired to provide a satisfactory installation.

9 - 36



9.2.4 Information presented in this Section applies primarily to floating drillingvessels, since more demanding conditions normally exist for these marine risersystems than for those installed for bottom-supported units.

*Available form American Petroleum Institute, Production Department, 2535 One Main Place, Dallas TX 75202-3904

MARINE RISER SYSTEM COMPONENTS

(NOTE: Additional details are contained in API RP 2K: Recommended Practice for Careand Use of Marine Drilling Risers and API RP 2Q: Recommended Practice for Design andOperation of Marine Drilling Riser Systems.)

Remotely Operated Connector

9.2.5 A remotely operated connector (hydraulically actuated) connects the riserpipe to the blowout preventer stack and can also be used as an emergencydisconnect from the preventer stack, should conditions warrant. Connectorinternal diameter should be at least equal to the internal bore of the blowoutpreventer stack. Its pressure rating can be equal to either the other components ofthe riser system (connectors, flexible joint, etc.) or to the rated working pressure ofthe blowout preventer stack (in case special conditions require subsequentinstallation of additional preventers on top of the original preventer stack).Connectors with the lower pressure rating are designated CL while those rated atthe preventer stack working pressure are designated CH. Additional factors to beconsidered in selection of the proper connector should include ease and reliabilityof engagement/disengagement, angular misalignments, and mechanical strength.

9.2.6 Engagement or disengagement of connector with the mating hub should bean operation that can be repeatedly accomplished with ease, even for thoseconditions here some degree of misalignment exists.

9.2.7 Mechanical strength of connector should be sufficient to safely resist loadsthat might reasonably be anticipated during operations. This would includetension and compression loads during installation, and tension and bending forcesduring both normal operations and possible emergency situations.

Marine Riser Flexible Joint (Ball Joint)

9.2.8 A flexible joint is used in the marine riser system to minimise bendingmoments, stress concentrations, and problems of misalignment engagement. Theangular freedom of a flexible joint is normally 10 degrees from vertical. A flexiblejoint is always installed at the bottom of the riser system either immediately abovethe remotely operated connector normally used for connecting/disconnecting theriser from the blowout preventer stack, or above the annular preventer when theannular preventer is placed above the remotely operated connector.



9 - 37

9.2.9 For those vessels having a diverter system, a second flexible joint issometimes installed between the telescopic joint and the diverter to obtainrequired flexibility, or some type of gimbal arrangement may also be used. Fordeep water operations or unusually severe sea conditions, another flexible jointmay be installed immediately below the telescopic joint.

9.2.10 Mechanical strength requirements for flexible joints are similar to those forthe remotely operated connector. They should be capable of safely withstandingloads that might reasonably be encountered during operations, both normal andemergency. In addition, the angular freedom of up to approximately 10 degreesshould be accomplished with minimum resistance while the joint is under fullanticipated load. Hydraulic “pressure balancing” is recommended for ball-typeflexible joints to counteract unbalanced forces of tensile load, drilling fluid density,and sea water density. This pressure balancing also provides lubrication forflexible joints.

9.2.11 Technical investigations and experience have shown the importance of closemonitoring of the flexible joint angle during operations to keep it at a minimum.One method of accomplishing this is by the use of an angle-azimuth indicator. Theflexible joint angle, vessel offset, and applied (riser) tension are indications ofstress levels in the riser section. For continuous drilling operations, the flexiblejoint should be maintained as straight as possible, normally at an angle of less than3 degrees: greater angles cause undue wear or damage to the drill string, riser,blowout preventers, wellhead or casing. For riser survival (i.e. to preventoverstressing) the maximum angle will vary from about 5 degrees to somethingless than 11 degrees, depending upon parameters such as water depth, vesseloffset, applied tension, and environmental conditions. Drill pipe survival mustalso be considered if the pipe is in use during those critical times of riser survivalconditions.

Marine Riser Sections

(Refer to API RP 2Q: Recommended Practice for Design and Operation of Marine Drilling RiserSystems* for additional details.)

9.2.12 Specifications for riser pipe depend upon service conditions. It should benoted, however, that drilling vessels normally encounter a wide variety ofenvironments during their service life; consequently, the riser should have aminimum yield strength and fatigue characteristics well in excess of thoserequired not only for the present but for reasonably anticipated future conditions.

9 - 38



9.2.13 Riser pipe steel should conform to ASTM Designation A-530: GeneralRequirements for Specialised Carbon and Alloy Steel Pipe† and be fabricated andinspected in accordance with API Spec 5L: Specification for Line Pipe*. Specificationsthat provide riser pipe with a reasonable service life for operation in most parts ofthe world include a steel having a minimum yield strength of between 50,000 psiand 80,000 psi. Risers with lower minimum yield strength (35,000 psi) have provensatisfactory if used in those areas where only light to moderate service conditionsare encountered.

†Available from American Petroleum Institute. Production Department, 2535 One Main Place, Dallas TX 75202-3904.*Available from American Society for Testing and Materials, 1916 Race St, Philadelphia Pennsylvania 19103.

9.2.14 Computer programs are available for determining riser stresses undervarious operating conditions, and should be used for installations where previousexperience is limited or lacking. Permissible operating stresses are normallyexpressed as a percent of minimum yield strength and depend upon thepreciseness of the data input. For any combination of service conditions (i.e.environmental, vessel offset, drilling fluid weight riser weight, etc.). there is anoptimum riser tension for which static and dynamic riser stresses are minimum.

9.2.15 The internal diameter of the riser pipe is determined by size of the blowoutpreventer stack and the wellhead, with adequate clearances being necessary forrunning drilling assemblies, casing and accessories, hangers, packoff units, wearbushings, etc.

9.2.16 Marine riser connectors should provide a joint having strength equal to orgreater than that of the riser pipe. For severe service, quench and tempering andshotpeening the connector pin end are sometimes done. The joint, when made upand tested under reasonable maximum anticipated service loads, should haveessentially no lateral, vertical, or rotational movement. After release of load, the,joint should be free of deformation, galling or irregularities. Make-up practice,including bolt- torque requirement, should be specified by the manufacturer.

9.2.17 Auxiliary drilling fluid circulation lines are sometimes required andincluded as an integral part of large diameter riser systems. Drilling fluid can bepumped into the lower section of the riser system to maintain adequate annularvelocities while drilling small diameter holes. The number of lines, size, andpressure rating will be determined by flow rates and pressures required.

Marine Riser Telescopic Joint

9.2.18 The telescopic joint serves as a connection between the marine riser and thedrilling vessel, compensating principally for heave of the vessel. It consists of twomain sections, the outer barrel (lower member) and the inner barrel (uppermember).



9 - 39

9.2.19 The outer barrel (lower member), connected to the riser pipe and remainingfixed with respect to the ocean floor, is attached to the riser tensioning system andalso provides connections for the kill and choke lines. A pneumatically orhydraulically actuated resilient packing element contained in the upper portion ofthe outer barrel provides a seal around the outside diameter of the inner barrel.

9.2.20 The inner barrel (upper member), which reciprocates within the outerbarrel, is connected to and moves with the drilling vessel and has an internaldiameter compatible with other components of the marine riser system. The topportion of the inner barrel has either a drilling fluid return line or diverter systemattached, and is connected to the underneath side of the rig sub structure.

9.2.21 The telescopic joint, either in the extended or contracted position, should becapable of supporting anticipated dynamic loads while running or pulling theblowout preventer stack and should have sufficient strength to safely resiststresses that might reasonably be anticipated during operations. Stroke length ofthe inner barrel should provide a margin of safety over and above the maximumestablished operating limits of heave for the vessel due to wave and tidal action.

9.2.22 Selection of a telescopic joint should include consideration of such factors assize and stroke length, mechanical strength, packing element life, ease of packingreplacement with the telescopic joint in service, and efficiency in attachment ofappurtenances (i.e. tensioner cables, choke and kill lines, diverter systems. etc.).

Marine Riser Tensioning System

9.2.23 The marine riser tensioning system provides for maintaining positivetension on the marine riser to compensate for vessel movement. The systemconsists of the following major components:

a. tensioner cylinders and sheave assembly.

b. hydropneumatic accumulators/air pressure vessels,

c. control panel and manifolding,

d. high pressure air compressor units, and

e. stand-by air pressure vessels.

Tensioning at the top of the riser is one of the more important aspects of the risersystem, as it attempts to maintain the riser profile as nearly straight as practicableand reduce stresses due to bending. As tension is increased, axial stress in the riseralso increases. Therefore, an optimum tension exists for a specific set of operatingconditions (water depth, current, riser weight, drilling fluid density, vesseloffset, etc.).

9 - 40



9.2.24 Wirelines from the multiple hydraulic tensioner cylinders are connected tothe outer barrel of the telescopic joint. These cylinders are energised by highpressure air stored in the pressure vessels. Tension on the wirelines is directlyproportioned to the pressure of stored air. In general, as the vessel heaves upward,fluid is forced out of the hydraulic cylinders thereby compressing air. As the vesselheaves downward pressure of the compressed air will cause the hydrauliccylinders to stroke in the opposite direction .

9.2.25 Selection of tensioners should be based on load rating, stroke length, speedof response, service life, maintenance costs, and ease of servicing. Maximum loadrating of individual tensioners depends on the manufacturer, typically rangingfrom 45.000 to 80.000 pounds and allowing maximum vertical vessel motion of 30to 50 feet. Design of the wireline system that supports the riser must take intoconsideration the angle between the wireline and the axis of the telescopic jointand its influence on stresses.

19.2.26 The number of tensioners required for a specific operation will depend onsuch factors as riser size and length, drilling fluid density, weight of suspendedpipe inside the riser, ocean current, vessel offset, wave height and period andvessel motion. Computer programs are available for riser analysis, includingtensioning requirements. Consideration should also be given to operatingdifficulties that might occur should one of the tensioners experience wirelinefailure. Recommendations for marine riser design and operation of risertensioning systems are contained in APl RP 2K: Recommended Practice for Care andUse of Marine Drilling Risers and API RP 2Q: Recommended Practice for Design andOperation of Marine Drilling Riser Systems.*

9.2.27 Periodic examination of riser tensioning system units should be made whilein service, since the system can cycle approximately 6000 times per day. Particularcare should be taken to establish a wireline slipping and replacement programbased on ton cycle life for the particular rig installation. Users should consult theequipment manufacturer for general maintenance procedures and specificationsrecommendations.

Buoyancy

9.2.28 For deeper waters, it may be impractical from an operating view point toinstall sufficient units capable of providing adequate tensioning. In these cases,some types of riser buoyancy may be the solution (flotation jackets, buoyancytanks, etc.) Buoyancy reduces the top tensioning requirements but loses some of itseffectiveness as a result of the increased riser diameter exposing a greater crosssectional area to wave forces and ocean currents. Selection of the optimum methodand/or material for obtaining buoyancy requires careful consideration of anumber of factors, including water absorption, pressure integrity, maintenancerequirements, abuse resistance, and manufacturer's quality control. Several ofthese factors are time and water-depth dependent. As water depth increases, these



9 - 41

factors become more critical. A part of any analysis for an optimum safe systemshould include consideration of the consequences of buoyancy failure duringoperations.

Riser Running and Handling

9.2.29 Well trained crews and close supervision are needed for maximumefficiency and to preclude any failure from improper handling or make-up ofmarine riser connectors. Some special equipment and tools for handling, running,and make-up/break-out may also be beneficial, both in protecting the riser andimproving efficiency. These tools include a flare-end guide tube for guiding theriser through the rotary table and a joint laydown trough installed in the V-door.Care should also be taken in protecting riser joints stored on the vessel.

Marine Riser Inspection and Maintenance

9.2.30 As marine riser joints are removed from service, each joint and connectorshould be cleaned, surfaces visually inspected for wear and damage, damagedpacking or seals replaced, and surface relubricated as required. Buoyancy materialand/or systems, if installed, should also receive close inspection. Prior to runninga riser, thorough inspection of all components may also be warranted, particularlyif the riser has been idle for some time or previous inspection procedures areunknown. For those operations where environmental forces are severe and/ortensioning requirements are high, consideration should be given to maintainingrecords of individual riser joint placement in the riser string and periodic testing(non-destructive) of the connector and critical weld areas to reduce failures. Referto APIRP2K: Recommended Practice for Care and Use of Marine Drilling Risers* forspecific information.

*Available from American Petroleum Institute, Production Dept. 2535 One Main Place, Dallas TX 75202-3904.

9 - 42



Figure 9.18 H-4 High-Angle-Release Connector

Vetco's H-4 High-Angle-Release Connector maintains releasing capability underhigh angles of up to 15° of riser deflection. Minimum swallow of pin mandrelassures quick separation.

LOCK PORT

PRIMARY LOCK PORT

VENT PORT

SECONDARY RELEASE

PORT

PRIMARY RELEASE

PORT

PIN MANDREL PROFILE

SEAL RING

PISTON

SEAL RING RETAINER

SCREW

CAM RING

CONNECTING ROD

LOCKING DOG



9 - 43

EL Style BOP and Riser Connectors - General Description

EL Connectors are hydraulically actuated units which provide ease of operation,positive sealing and field repairability. The connectors are available in a range ofsizes at working pressures of 2,000; 5,000 and 10,000 psi. They can be used as aBOP connector, as a riser connector above the BOP, or between BOP components.

Features:-

• Metal-to-metal primary seal.

• The large number of locking dogs distribute the load evenly throughout thebody and mandrel of the connector.

• Unit can be serviced without removal from the BOP stack.

• Optional, secondary resilient seal can be incorporated. This seal isindependently energised.

• Mandrel type construction provides stable engagement before energisation.

• The 5,000 psi system is completely internally piped.

• Positive mechanical dogs ensure easy unlatching.

• Various override mechanisms available.

• As a riser connector, interchangeability of parts with the BOP connector ispossible.

• Self alignment, five inches before make-up, facilitates choke and kill linestabs.

9 - 44



Figure 9.20 MCK Valve

The Cameron MCK valve is designed for the rugged service requirements ofsubsea choke and kill lines.

• The valve is compact and bolted sideways to the side of the BOP.

• A detachable actuator allows maintenance to be performed withoutremoving the valve body from the line.

• Retained seats prevent erosion of the valve.

• The MCK valve is available in a full range of pressure and bore sizes.

• Seat and body bushings have been combined into one piece, reducing thenumber of cavity parts and seals.

• Balance stem design improves performance.

• Stem packing can be changed without removing the bonnet from the valve.



9 - 45

Figure 9.21 Marine Riser Fill-up Valve

Riser Fill-up Valve

The Cameron riser fill-up valve isdesigned to prevent the riser fromcollapsing if the level of drilling fluiddrops due to intentional drive-off,loss of circulation, or accidentaldisconnection of the line.

During normal drilling operations,the pressure head created by themud column inside the riser keepsthe valve's internal sleeve closed.When riser pressure drops, oceanpressure pushes the sleeve up,initiating a sequence which fullyopens the valve to allow sea water toenter the riser, equalizing thepressure and preventing risercollapse.

The riser fill-up valve is activated bythe pressure sensory sleeve when thepressure inside the riser is from 250 -350 psi below the ambient oceanpressure. When activate, the valvefully opens to rapidly fill the riser.When pressure is equalized, thepressure sensor returns to its normalposition and the internal sleevecloses.

Although the unit is totally self-contained and independent of anycontrol lines, the valve can also bemanually operated through controllines to the surface.

SD–8140

Page

10. 0 Formulae and Conversion Factors 1

10. 1 Glossary for Well Control Operations 5

FORMULAE, CONVERSIONFACTORS & GLOSSARY OF TERMSSECTION 10 :


SECTION 10 : FORMULAE, CONVERSION FACTORS & GLOSSARY OF TERMS

10- 1

FORMULAE AND CONVERSION FACTORS

10.0 EQUATION SHEET FOR OILFIELD/FIELD UNITS

1. Pressure Gradient psi/ft = Mud Weight ppg x 0.052

2. Mud Weight ppg = Pressure Gradient psi/ft ÷ 0.052

3. Hydrostatic Pressure psi = Mud Weight ppg x 0.052 x True Vertical Depth ft

4. Formation Pressure psi = Hydrostatic Pressure in Drill String psi + SIDPP psi(with bit on bottom)

5. Equivalent MudWeight ppg = Pressure psi ÷ True vertical Depth ft ÷ 0.052

6. Pump Output bbls/min = Pump Output bbls/stk x Pump Speed spm

7. Annulus Velocity ft/min = Pump Output bbls/min ÷ Annulus Volume bbls/ft

8. Initial CirculatingPressure psi = SCR psi + SIDPP psi

9. Final CirculatingPressure psi = SCR psi x (Kill Mud Weight ppg ÷ Original Mud ppg)

10. Kill Weight Mud ppg = (SIDPP psi ÷ TVD ft ÷ 0.052) + Original Mud ppg

11. Shut in Casing [(Mud Grad psi/ft - Influx Grad psi/ft) x InfluxPressure psi = Height ft] + SIDPP psi

12. Equivalent circulating (Annulus Pressure loss psi ÷ TVD ft ÷ 0.052)density ppg = + Original Mud ppg

13. Height of influx ft = Kick size bbls ÷ Annulus Volume bbls/ft

(SICP psi - SIDPP psi)14. Gradient of Influx psi/ft = (Mud weight ppg x 0.052) ––––––––––––––––

Influx Height ft

15. Trip Margin/safety = (Safety factor psi ÷ TVD ÷ 0.052) + Mud factor ppg Weight ppg

16. Pump Pressure/Pump StksRelationship psi = Present Pressure psi x (New SPM ÷ Old SPM)2

10- 2



17. Max. Allowable Mud (Surface Leak Off psi ÷ Shoe TVD ft ÷ 0.052)Weight ppg = + Test Mud ppg

18. New MAASP psi = (Max. Allowable Mud Weight ppg -Current Mud Weight ppg)

(Kill mud weight ppg - Old mud weight ppg) x 150019. Barite to raise mud = ––––––––––––––––––––––––––––––––––––––––––––

weight lbs/bbl (35.8 - kill weight mud ppg)

20. Percolation Rate ft/hr = Drill pipe pressure increase psi/hr ÷ Mudgradient psi/ft

(MAASP - (Mud gradient psi/ft - Influx Grad ft)) x Influx Height ft21. Kick Tolerance ppg = ––––––––––––––––––––––––––––––––––––––––––––

TVD x 0.052

Kick tolerance in feet MAASP - SIDPPor [–––––––––––––] = Max Tol Length of Influx

GM- GI

P1V1 V1P122. Boyle’s Law: P1V1 = P2V2 P2 = –––– V2 = –––––

V2 P2

Mud grad psi/ft x Metal Disp bbls/ft23. Pressure drop per ft. = ––––––––––––––––––––––––––––––

tripping dry pipe Casing cap. bbls/ft - Metal Disp bbls/ft

Mud grad psi/ft x (Metal disp bbls/ft + Pipe disp bbls/ft)24. Pressure drop per ft. = –––––––––––––––––––––––––––––––––––––––––––

tripping wet pipe Annulus Volume bbls/ft

Length of collars ft x metal disp bbls/ft25. Level drop for pulling = –––––––––––––––––––––––––––––––

collars out of hole ft Casing cap. bbls/ft

Overbalance psi x (casing cap. bbls/ft - pipe disp bbls/ft)26. Length of pipe to pull = –––––––––––––––––––––––––––––––––––––––––––

before well starts to flow ft Mud gradient psi/ft x pipe Disp bbls/ft

Mud grad psi/ft x Casing Cap bbls/ft x differential height ft27. Hydrostatic Pressure = ––––––––––––––––––––––––––––––––––––––––––––

loss if casing float fails (casing capacity + Annulus capacity bbls/ft)



10- 3

W228. Volume displace by slug = Slug Vol x ––– - 1

W1 ∆P

29. Riser Margin = ––––– ÷ .052 R TVD

Where ∆P = [Pmud] - [Psw] Riser Sea-water

R TVD = [L of hole RKB/TVD] - [L of Riser RKB/BML]

or the total increase in mud Wt required before disconnected.

[Pmuda + Psw] = P0

D2

30. Conversion of pipe diameter to bbls/ft = ––––––– = bbls/ft 1029.42

D2 - d2

or ––––––– = bbls/ft 1029.42

31. Max Mud Wt [Offshore]

[Psw] + [Pf] ÷ [BML - TVD] ÷ [.052]

32. Estimated Casing setting depth beneath sea floor

[P Mud] - [P sw] ÷ [G.F.B. - G.M] Riser Sea-water

33. 'U' Tube formula

SIDPP + [Pmud]DS = [SICP] + [Pmuda] +[Psasa]

[ ]

10- 4



APPROPRIATE CONVERSIONS

DEPTH Feet x 0.3048 to give Metres (m)Metres x 3.2808 to give Feet (ft)

VOLUME (U.S.) Gallon x 0.003785 to give Cubic Metres (m3)(U.S.) Barrel x 0.1590 to give Cubic Metres (M3)Cubic Metre x 6.2905 to give Barrel (U.S.)

PRESSURE PSI x 6.895 to give Kilo Pascals (KPa)KPA x 0.14503 to give Pounds per Square Inch (psi)Kg/cm2 x 98.1 to give Kilo Pascals (KPa)Bar x 100 to give Kilo Pascals (KPa)

MUD WEIGHT PPG x 119.8 to give Kilogram per Cubic Metre (Kg/m3)Kg/m3 x 0.00835 to give (Pounds per Gallon)

ANNULAR Feet/Minute x 0.3048 to give Metres per Minute (m/min)VELOCITY Metres/Minute x 3.2808 to give Feet per Minute (ft/min)

FLOW RATE Gallons/Minute x 0.003785 to give Cubic Metres per Minute (m3/min)Barrels/Minute x 0.159 to give Cubic Metres per Minute (M3/min)Cubic Metres/Minute x 6.2905 to give Barrels per Minute (bbl/min)Cubic Metres/Minute x 264.2 to give Gallons per Minute (gals/min)

FORCE Pound Force x 0.445 to give Decanewtons(eg WEIGHT ON BIT) Decanewtons x 2.2472 to give Pound Force

MASS Pounds x 0.454 to give Kilograms (Kg)

Tons(Long-2240 lbs) x 1017 to give Kilograms (Kg)

Tonnes(Metre-2205 lbs) x 1001 to give Kilograms (Kg)

Kilograms x 2.2026 to give Pounds (lbs)

PRESSURE PSI/Foot x 22.62 to give Kilo Pascals per Metre (K/Pa/m)GRADIENT KPa/Metre x 0.04421 to give Pounds per Square Inch per Foot (psi/ft)

MUD WEIGHT PPG x 0.052 to give Pounds per Square Inch per Foot (psi/ft)TO PRESSURE [Pressure Gradient]GRADIENT SG x .433 to give Pounds per Square Inch per Foot (psi/ft)

b/ft3 ÷ 144 to give Pounds per Square Inch per Foot (psi/ft)Kg/m3 x 0.000434 to give Pounds per Square Inch

or ÷ 2303 per Foot (psi/ft)Kg/m3 x 0.00982 to give Kilo Pascals per Metre (K/Pa/m)



10- 5

10.1 GLOSSARY FOR WELL CONTROL OPERATIONS

Abnormal Pressure - Pore pressure in excess of that pressure resulting from thehydrostatic pressure exerted by a vertical column of water salinity normal for thegeographic area.

Accumulator - A vessel containing both hydraulic fluid and gas stored underpressure as a source of fluid power to operate opening and closing of blowoutpreventer rams and annular preventer elements. Accumulators supply energy forconnectors and valves remotely controlled.

Accumulator Bank Isolator Valve - The opening and closing device locatedupstream of the accumulators in the accumulator piping which stops flow offluids and pressure in the piping.

Accumulator Relief Valve - The automatic device located in the accumulatorpiping that opens when the pre-set pressure limit has been reached so as to releasethe excess pressure and protect the accumulators.

Accumulator Unit - The assembly of pumps, valves, lines, accumulators, andother items necessary to open and close the blowout preventer equipment.

Air Breather - A device permitting air movement between the atmosphere and thecomponent in which it is installed.

Air Pressure Switch Bypass Valve - The opening and closing device located in theair supply line which blocks air flow in one line to be redirected through another.In open position, air flow is not routed through the air pressure switch forautomatic shutoff thereby allowing the air pumps to continue to run.

Air Pump Suction Valve - The opening and closing device located in the pipingline that draws fluid from the reservoir into the fluid end of the pump when theair motor is operating.

Air Regulator - The adjusting device to vary the amount of air pressure enteringas to the amount to be discharged down the piping lines.

Air Supply Valve - The opening and closing device in the connecting line of thecompressed air routed to flow into the accumulator system lines as a power sourcefor components.

Ambient Temperature - The temperature of all the encompassing atmospherewithin a given area.Ampere - The unit used for measuring the quantity of an electric current flow. Oneampere represents a flow of one coulomb per second.

10- 6



Annular - A large valve, usually installed above the ram preventers, that forms aseal in the space between the pipe and wellbore or on the wellbore itself. The spacearound a pipe in a wellbore, the outer wall of which may be the wall of either theborehole or the casing.

Annular Preventer - A device which can seal around any object in the wellbore orupon itself. Compression of a reinforced elastomer packing element by hydraulicpressure effects the seal.

Annular Regulator - The device located in the annular manifold header to enableadjustment of pressure levels which will flow past to control the amount of closureof the annular preventer.

Annulus Friction Pressure - Circulating pressure loss inherent in annulus betweenthe drill string and casing or open hole.

Back Pressure (Casing Pressure, Choke Pressure) - The pressure existing at thesurface on the casing side of the drill pipe/annulus flow system.

Baffle - A partition plate inside the reservoir to prevent unbalancing by suddenweight shifting of the hydraulic fluid.

Barite Plug - A settled volume of barite particles from a barite slurry placed in thewellbore to seal off a pressured zone.

Barite Slurry - A mixture of barium sulphate, chemicals, and water of a unitdensity between 18 and 22 pounds per gallon (lb/gal).

Belching - A slang term to denote flowing by heads.

Bell Nipple (Mud Riser, Flow Nipple) - A piece of pipe, with inside diameterequal to or greater than the blowout preventer bore, connected to the top of theblowout preventer or marine riser with a side outlet to direct the drilling fluidreturns to the shale shaker or pit. Usually has a second side outlet for the fill-upline connection.

Bleeding - Controlled release of fluids form a closed and pressured system inorder to reduce the pressure.

Blind Rams (Blank, Master) - Rams whose ends are not intended to seal againstany drill pipe or casing. They seal against each other to effectively close the hole.

Blind/Shear Rams - Blind rams with a built-in cutting edge that will sheartubulars that may be in the hole, thus allowing the blind rams to seal the hole.Used primarily in subsea systems.



10- 7

Blowout - An uncontrolled flow of gas, oil, or other well fluids into theatmosphere. A blowout, or gusher, occurs when formation pressure exceeds thepressure applied to it by the column of drilling fluid.

Blowout Preventer - The equipment installed at the wellhead to enable the drillerto prevent damage at the surface while restoring the balance between the pressureexerted by the column of drilling fluid and formation pressure. The BOP allowsthe well to be sealed to confine the well fluids and prevent the escape of pressureeither in the annular space between the casing and drill pipe or in an open hole.The blowout preventer is located beneath the rig at the land’s surface on land rigsor at the water’s surface on jack-up or platform rigs and on the sea floor forfloating offshore rigs.

Blowout Preventer Drill - A training procedure to determine that rig crews arecompletely familiar with correct operating practices to be followed in the use ofblowout prevention. A dry run of blowout preventive action.

Blowout Preventer Operating and Control System (Closing Unit) - The assemblyof pumps, valve, lines, accumulators and other items necessary to open and closethe blowout preventer equipment.

Blowout Preventer Stack - The assembly of well control equipment includingpreventers , spools, valves and nipples connected to the top of the wellhead.

Blowout Preventer Test Tool - A tool to allow pressure testing of the blowoutpreventers stack and accessory equipment by sealing the wellbore immediatelybelow the stack.

Bleeder Valve - An opening and closing device for removal of pressurised fluid.

Borehole Pressure - Total pressure exerted in the wellbore by a column of fluidand/or back pressure imposed at the surface.

Bottom-hole Pressure - Depending upon context, either a pressure exerted by acolumn of fluid contained in the wellbore or the formation pressure at the depth ofinterest.

Broaching - Venting of fluids to the surface or to the sea-bed through channelsexternal to the casing.

Bullheading - A term to denote pumping into a closed-in well without returns.

Casinghead/Spool - The part of the wellhead to which the blowout preventerstack is connected.

Casing Pressure - see Back Pressure.

10- 8



Casing Seat Test - A procedure whereby the formation immediately below thecasing shore is subjected to a pressure equal to the pressure expected to be exertedlater by a higher drilling fluid density or by the sum of a higher drilling fluiddensity and back pressure created by a kick.

Chain Guard - The metal enclosure surrounding the electric pump driving chainto protect and contain an oil lubricate for the chain.

Check Valve - A valve that permits flow in only one direction.

Choke - A variable diameter orifice installed in a line through which high pressurewell fluids can be restricted or released at a controlled rate. Chokes also control therate of flow of the drilling mud out of the hole when the well is closed in with theblowout preventer and a kick is being circulated out of the hole.

Choke Line - The high pressure piping between blowout preventer outlets orwellhead outlets and the choke manifold.

Choke Line Valve - The valve(s) connected to and a part of the blowout preventerstack that control the flow to the choke manifold.

Choke Manifold (Control Manifold) - The system of valves, chokes, and pipingto control flow from the annulus and regulate pressures in the drill pipe/annulusflow system.

Choke Pressure - See Back Pressure.

Circuit Breaker - An electrical switching device able to carry an electrical currentand automatically break the current to interrupt the electrical circuit if adverseconditions such as shorts or overloads occur.

Circulating Head - A device attached to the top of drill pipe or tubing to allowpumping into the well without use of the kelly.

Clamp Connection - A pressure sealing device used to join two items withoutusing conventional bolted flange joints. The two items to be sealed are preparedwith clamp hubs. These hubs are held together by a clamp containing two to fourbolts.

Closing Unit - The assembly of pumps, valves, lines, accumulators and otheritems necessary to open and close the blowout preventer equipment.

Closing Ratio - the ratio of the wellhead pressure to the pressure required to closethe blowout preventer.

Conductivity - The capability of a material to carry an electrical charge. Usuallyexpressed as a percentage of copper conductivity (copper being one hundred 100



10- 9

percent). Conductivity is expressed for a standard configuration of conductor.

Conductor - The substance or body capable of transmitting electricity, heat, light,or sound.

Conductor Pipe - A relatively short string of large diameter pipe which is set tokeep the top of the hole open and provide a means of returning the upflowingdrilling fluid from the wellbore to the surface drilling fluid system until the firstcasing string is set in the well. Conductor pipe is usually cemented.

Continuity - The uninterrupted flow of current in a conductor.

Contract Block - The conductor located in the electric panels which bring togetherthe electrical connections of the operation pushbuttons with those of the operatorvalves.

Control Manifold - The system of valves and piping used to control the flow ofpressured hydraulic fluid to operate the various components of the blowoutpreventer stack.

Control Panel, Remote - A panel containing a series of control that will operatethe valves on the control manifold from a remote point.

Control Pod - An assembly of subsea valves and regulators which when activatedfrom he surface will direct hydraulic fluid through special apertures to operateblowout preventer equipment.

Corrosion Inhibitor - Any substance which slows or prevents the chemicalreactions of corrosion.

Cut Drilling Fluid - Well control fluid which has been reduced in density or unitweight as a result of entrainment of less dense formation fluids or air.

Cylinder - A device which converts fluid or air power into linear mechanical forceand motion. It consists of a movable element such as a piston and piston rod,plunger rod, plunger or ram, operating within a cylindrical chamber.

Degasser - A vessel which utilizes pressure reduction and/or inertia to separateentrained gases from the liquid phases.

Discharge Check Valve - The device located in the expelling line of a pump (air orelectric) which allows fluid to flow out only and thereby prevents a back flow offluid into the pump.

Displacement - The volume of steel in the tubulars and devices inserted and/orwithdrawn from the wellbore.

10- 10



Diverter - A device attached to the wellhead or marine riser to close the verticalaccess and direct any flow into a line away from the rig.

Drain Port - The plugged openings on the lower side portions of the reservoirwhich can be opened to empty or release the hydraulic fluid, and through whichthe reservoir can be cleaned.

Drilling Fluid Weight Recorder - An instrument in the drilling fluid system whichcontinuously measures drilling fluid density.

Drilling Spool - A connection component with ends either flanged or hubbed. Itmust have an internal diameter at least equal to the bore of the blowout preventerand can have smaller side outlets for connecting auxiliary lines.

Drill Pipe Safety Valve - An essentially full-opening valve located on the rig floorwith threads to match the drill pipe in use. This valve is used to close off the drillpipe to prevent flow.

Drill Stem Test (DST) - A test conducted to determine production flow rate and/or formation pressure prior to completing the well.

Drill String Float - A check valve in the drill string that will allow fluid to bepumped into the well but will prevent flow from the well through the drill pipe.

Drive Pipe - A relatively short string of large diameter pipe driven or forced intothe ground to function as conductors pipe.

Dust Cap - The screw on covering for the electric panel connector receptacleswhich protect the electrical contacts from foreign matter and moisture.

Electric Pump Suction Valve - The opening and closing device located in thepiping line that draws fluid from the reservoir into the pump inlet when the motoris operating.

Element (Filter) - The substance of porous nature which retains foreign particlesthat pass through the containing chamber to separate and clean the gas or liquidflow.Equivalent Circulating Density (ECD) - The sum of pressure exerted byhydrostatic head of fluid, drilled solids, and friction pressure losses in the annulusdivided by depth of interest and by 0.052, if ECD is to be expressed in pounds pergallon (lb/gal).

Feed-in (Influx, Inflow) - The flow of fluids from the formation into the wellbore.

Fill Port - The plugged opening in the top of the fluid reservoir through whichhydraulic oil is added.



10- 11

Fill-up Line - A line usually connected into the bell nipple above the blowoutpreventers to allow adding drilling fluid to the hole while pulling out of the holeto compensate for the metal volume displacement of the drill string being pulled.

Filter (Air) - Apparatus used to clean air flow of dirt, moisture and othercontaminants.

Filter (Hydraulic) - A device whose function is the retention of insolublecontaminants from a fluid.

Final Circulating Pressure - Drill pipe pressure required to circulate at theselected kill rate adjusted for increase in kill drilling fluid density over the originaldrilling fluid density; used from the time kill drilling fluid reaches the bottom ofthe drill string until kill operations are completed or a change in either kill drillingfluid density or kill rate is effected.

Flow Meter - A device which indicates either flow rate, total flow, or acombination of both, that travels through a conductor such as pipe or tubing.

Flow Rate - The volume, mass, or weight of a fluid passing through anyconductor, such as pipe or tubing, per unit of time.

Fluid - A substance that flows and yields to any force tending to change its shape.Liquids and gases are fluids. The accumulator system pressurises fluid to be usedas a source of power to open and close valves and rams on the BOP stack.

Fluid Density - The unit weight of fluid; e.g., pounds per gallon (lb/gal).

Formation Breakdown - An event occurring when borehole pressure is ofmagnitude that the exposed formation accepts whole fluid from the borehole.

Formation Competency (Formation Integrity) - The ability of the formation towithstand applied pressure.

Formation Competency Test (Formation Integrity Test) - Application of pressureby superimposing a surface pressure on a fluid column in order to determineability of a subsurface zone to withstand a certain hydrostatic pressure.Formation Integrity - See Formation Competency.

Formation Integrity Test - See Formation Competency Test.

Formation Pressure (Pore Pressure) - Pressure exerted by fluids within the poresof the formation (see Pore Pressure).

Flowline Sensor - A device to monitor rate of fluid flow from the annulus.

Fracture Gradient (Frac. Gradient) - The pressure gradient (psi/ft) at which the

10- 12



formation accepts whole fluid from the wellbore.

Full Load Current - The amount of current used by an electrical circuit when thecircuit is operating at its designed or rated maximum capacity.

Function - The term given to the duty of operating the control valves of theaccumulator system. The action performed by the control valves when operatingthe ram preventers or gate valves.

Gage - A standard method of specifying the physical size of a conductor (wire)diameter based on the circular mil system. 1 mil equals .001. The higher thenumber, the smaller the diameter.

Gas Buster - A slang term to denote a mud gas separator.

Gate Valve - A valve which employs a sliding gate to open or close the flowpassage. The valve may or may not be full-opening.

Gauge - An instrument for measuring fluid pressure that usually registers thedifference between atmospheric pressure and the pressure of the fluid byindicating the effect of such pressure on a measuring element (as a column ofliquid, a bourdon tube, a weighted piston, a diaphragm, or other pressure-sensitive devices).

Gland - The cavity of a stuffing box.

Ground - An electrical term meaning to connect to the earth, or another largeconducting body to serve as earth, thus making a complete electrical circuit. Theconducting connection of a circuit to the earth.

Gunk Plug - A volume of gunk slurry placed in the wellbore.

Gunk Slurry - A slang term to denote a mixture of diesel oil and bentonite.

Gunk Squeeze - Procedure whereby a gunk slurry is pumped into a subsurfacezone.

H2S - An abbreviation for hydrogen sulphide.

Hard Close In - To close in a well by closing a blowout preventer with the chokeand/or choke line valve closed.

Hydrostatic - Relating to liquids at rest and the pressure they exert.

Hydrostatic Head - The true vertical length of fluid column, normally in feet.

Hydrostatic Pressure (Hydrostatic Head) - The pressure which exists at any point



10- 13

in the wellbore due to the weight of the vertical column of fluid above that point.

Indicating Light - The bulbs of the electric control panels that shine to point outwhich electrical contacts have made a circuit. The electric panel bulbs make circuitcontacts through pressure switches, transducers, and solenoid valves todemonstrate activation.

Inflow - See Feed-in.

Influx - See Feed-in.

Initial Circulating Pressure - Drill pipe pressure required to circulate initially atthe selected kill rate while holding casing pressure at the close-in value;numerically equal to kill rate circulating pressure plus closed-in drill pipepressure.

Inside Blowout Preventer - A device that can be installed in the drill string thatacts as a check valve allowing drilling fluid to be circulated down the string butprevents back flow.

Inspection Port - The plugged openings on the sides of the fluid reservoir whichcan be opened to view the interior fluid level and return lines from the relief,bleeder, control valves, and regulators.

Insulation - A non-conductive material usually surrounding or separating thecurrent carrying parts from each other or from the core.

Kelly Cock - A valve immediately above the kelly that can be closed to confinepressures inside the drill string.

Kelly Valve - Lower. An essentially full opening valve installed immediatelybelow the kelly with outside diameter equal to the tool joint outside diameter.

Kick - Intrusion of formation fluids into the wellbore.

Kill Drilling Fluid Density - The unit weight e.g. pounds per gallon (lb/gal),selected for the fluid to be used to contain a kicking formation.

Kill Line - A high-pressure fluid line connecting the mud pump and the wellheadat some point below a blowout preventer. This line allows heavy drilling fluids tobe pumped into the well or annulus with the blowout preventer closed to control athreatened blowout.

Kill Rate - A predetermined fluid circulating rate, expressed in fluid volume perunit time, which is to be used to circulate under kick conditions; kill rate is usuallysome selected fraction of the circulating rate used while drilling.

10- 14



Kill Rate Circulating Pressure - Pump pressure required to circulate kill ratevolume under non-kick conditions.

Leak-off Test - Application of pressure by superimposing a surface pressure on afluid column in order to determine the pressure at which the exposed formationaccepts whole fluid.

Lost Circulation (Lost Returns) - The loss of whole drilling fluid to the wellbore.

Lost Returns - See Lost Circulation.

Lubrication. Alternately pumping a relatively small volume of fluid into a closedwellbore system and waiting for the fluid to fall toward the bottom of the well.

Lubricator (Air) - A device which adds controlled or metered amounts of asubstance into the air line of a fluid power system to prevent or lessen friction.

Manifold Bleeder Valve - The opening and closing device in the piping thatconnects the manifold header and the reservoir, and which can be opened torelease the fluid pressure and vent it back into the reservoir.

Manifold Header - The piping system which serves to divide a flow throughseveral possible outlets. The 4-Way control valve inlets connect to the piping sothat high pressure fluid is available to pass through any or all of the valves.

Manifold Regulator - The device located in the manifold header which can varythe amount of pressure that enters and exits its chamber. The manifold regulatorcontrols the pressure level of the fluid flowing through and out the 4-Way controlvalves.

Manifold Regulator Bypass Valve - The opening and closing device which blocksflow in one line to be redirected through another. This valve is located in themanifold piping so that in the open position the high pressure fluid does not flowthrough the regulator in the manifold header, thereby allowing higher pressurefluid to be available to the 4-Way control valves.

Manifold Relief Valve - The automatic opening device located on the manifoldheader that opens when the present pressure limit has been reached so any excesspressure is released, thereby protecting the manifold header.

Meter - An instrument, operated by an electrical signal, that indicates ameasurement of pressure.

Meter Circuit Board - Printed circuit board used with the electrical meters toprovide the circuits necessary for calibration of the meter.

Micron - (A millionth of a meter or about 0.0004 inch). The measuring unit of the



10- 15

porosity of filter elements.

Mil - A measurement used in determining the area of wire. The area of a circle one1/thousandth inch in diameter.

Minimum Internal Yield Pressure - The lowest pressure at which permanentdeformation will occur.

Motor Starter - Automatic device which starts or stops the electric motor drivingthe duplex or triplex pump which works in conjunction with the automaticelectrical pressure switch for pressure limits of pump start-up and shutoff.

Mud-gas Separator - A vessel for removing free gas from the drilling fluid returns.

Needle Valve - A shutoff (2-Way) valve that incorporates a needle point to allowfine adjustments in flow.

Normal Pressure - Formation pressure equal to the pressure exerted by a verticalcolumn of water with salinity normal for the geographic area.

Ohm - A unit of electrical resistance, the resistance of a circuit in which a potentialdifference of one volt produces a current of one ampere.

Ohmmeter - The measuring instrument which indicates resistance in ohms.

Opening Ratio - The ration of the well pressure to the pressure required to openthe blowout preventer.

Overbalance - The amount by which pressure exerted by the hydrostatic head offluid in the wellbore exceeds formation pressure.

Overburden - The pressure on a formation due to the weight of the earth materialabove that formation. For practical purposes this pressure can be estimated at1 psi/ft of depth.

Packoff or Stripper - A device with an elastomer packing element that depends onpressure below the packing to effect a seal in the annulus. Used primarily to run orpull pipe under low or moderate pressures. This device is not dependable forservice under high differential pressures.

Petcock - The small faucet or valve used to release compression or drain moistureaccumulated in the anterior chamber of the lubricator.

Phase (3-Phase Motor) - A particular stage or point of advancement in anelectrical cycle. The fractional part of the period through which the time hasadvanced, measured from some arbitrary point usually expressed in electricaldegrees where 360° represents one cycle.

10- 16



Pipe Rack - The connecting pipelines between the control valve outlets and theBOP stack preventers which carry the high pressure operating fluid. The lines ofpipe are laid together and are often covered with a grating to create a walkway.

Pipe Rams - Rams whose ends are contoured to seal around pipe to close theannular space. Separate rams are necessary for each size (outside diameter) pipe inuse.

Pit Volume Indicator - A device installed in the drilling fluid tank to register thefluid level in the tank.

Pit Volume Totaliser - A device that combines all of the individual pit volumeindicators and registers the total drilling fluid volume in the various tanks.

Plug Valve - A valve whose mechanism consists of a plug with a hole through iton the same axis as the direction of fluid flow. Turning the plug 90 opens or closesthe valve. The valve may or may not be full-opening.

Pore Pressure (Formation Pressure) - Pressure exerted by the fluids within thepore space of a formation.

Potable - A liquid that is suitable for drinking.

Pressure Gradient, Normal - The normal pressure divided by true vertical depth.

Pressure Switch (Air) - The automatic device to start and stop the air pumpoperation when the present pressure limits are reached.

Pressure Switch (Electric) - An electrical switch, operated by fluid pressure,which automatically starts and stops the electrical pump when the presentpressures are reached.

Pressure Transmitter - Device which sends a pressure signal to be converted andcalibrated to register the equal pressure reading on a gauge. The air outputpressure in proportion to the hydraulic input pressure.

Primary Well Control - Prevention of formation fluid flow by maintaining ahydrostatic pressure equal to or greater than formation pressure.

Pump (Air) - A device that increases the pressure on a fluid or raises it to a higherlevel by being compressed in a chamber by a piston operated with an air pressuremotor.

Pump (Electric) - A device that increases the pressure on a fluid and moves it to ahigher level using compression force from a chamber and piston that is driven byan electric motor.



10- 17

Pushbutton/Indicating Light - The control valve operates with bulbs on theelectrical remote panel which change and indicate the position of the controlvalves.

Ram - The closing and sealing component on a blowout preventer. One of threetypes - blind, pipe, or shear - may be installed in several preventers, mounted in astack on top of the wellbore. Blind rams, when closed, form a seal on a hole thathas no drill pipe in it; pipe rams, when closed, seal around the pipe; shear ramscut through drillpipe and then form a seal.

Recorder - An automatic device that reads and records pressure outputscontinually on a revolving chart to provide continuous evidence of pressures.

Regulator - A device that varies and controls the amount of pressure of a liquid orgas that passes through its chambers.

Relay - An electrical device to automatically control the operation of anotherdevice in another circuit by passing on an electric current.

Relay Socket - A device used to interconnect a relay with its circuitry and whichallows quick and easy removal of the relay without special tools.

Relief Well - An offset well drilled to intersect the subsurface formation to combatblowout.

Replacement - The process whereby a volume of fluid equal to the volume of steelin tubulars and tools withdrawn from the wellbore is returned to the wellbore.

Reservoir - The container for storage of liquid. The reservoir houses hydraulicfluid at atmospheric pressure as the supply for fluid power.

Resistance - The property of an electrical circuit which determines for a givencurrent, the rate at which electrical energy is converted into heat and has a valuesuch that the current squared, multiplied by the resistance, gives the powerconverted.

Rotating Head - A rotating, low pressure sealing device used in drillingoperations to seal around the drill stem above the top of the blowout preventerstack.

Rupture Disk - A device whose breaking strength (the point at which it physicallycomes apart) works to relieve pressure in the system. The rupture disk iscontained as a safety device for the test unit system.

Safety Factor - In the context of this publication, an incremental increase indrilling fluid density beyond the drilling fluid density indicated by calculations tobe needed to contain a kicking formation.

10- 18



Salt Water Flow - An influx of formation salt water into the wellbore.

Shear Rams - Blowout preventer rams with a built in cutting edge that will sheartubulars that may be in the hole.

Soft close In - To close in a well by closing a blowout preventer with the chokeand choke line valve open, then closing the choke while monitoring the casingpressure gauge for maximum allowable casing pressure.

Solenoid Valve - The opening/closing device which is activated by an electricalsignal to control liquid or gas pressured flow to be sent to open or close the 4-Waycontrol valves. The valve position is controlled by an electromagnetic bar, enclosedby a coil.

Solenoid Valve Box - The explosion proof enclosure, located on the accumulatorunit, which contains the electrically powered actuators for the remote controlelectrical panel. The box is wired to the electrical supply, and houses solenoidvalves, pressure switches and transducers.

Sour Gas - Natural gas containing hydrogen sulphide.

Space Out - Procedure conducted to position a predetermined length of drill pipeabove the rotary table so that a tool joint is located above the subsea preventerrams on which drill pipe is to be suspended (hung-off) and so that no tool joint isopposite a set of preventer rams after drill pipe is hung-off.

Space-Out Joint - The joint of drill pipe which is used to hang off operations sothat no tool joint is opposite a set of preventer rams.

Span Adjustment - The control to vary the space between the electrical contactpoints in the electrical pressure switch.

Squeezing - Pumping fluid into one side of the drill pipe/annulus flow systemwith the other side closed so as to allow no outflows.

Stack - The assembly of well control equipment including preventers, spools,valves, and nipples connected to the top of the casing head.

Strainer - A porous material which retains contaminants passing through a linealong with the gas or liquid flow.

Suction Strainer - The porous element, located in a “y” shaped fitting of the pumpsuction lines, which cleans the hydraulic fluid or air of contaminants beforeentering the pumps.

Surge Damper - The one quart capacity bladder accumulator used to absorb theshock and waves caused by an initial flow of high pressure fluid. Located in thedownstream line of the annular regulator.



10- 19

Swabbing - The lowering of the hydrostatic pressure in the wellbore due toupward movement of tubulars and/or tools.

Swivel Joint - A connecting device, joining parts so that each can pivot freely.Swivel joints are used at the ends of the pipe rack to ease connections to thecontrol valve outlets and to the BOP stack.

Target - A bull plug or blind flange at the end of a T to prevent erosion at a pointwhere change in flow direction occurs.

Targeted - Refers to a fluid piping system in which flow impinges upon a lead-filled end (target) or a piping T when fluid transits a change in direction.

Terminal Strip - Grouped electrical conductor endings where screw connectionsare made.

Transducer - The device located in the solenoid valve box which is actuated byhydraulic pressure and converts the force to an electrical force for indication on ameter. The electrical output signal is in proportion to the hydraulic input pressure.

Trip Gas - An accumulation of gas which enters the hole while a trip is made.

Trip Margin - An incremental increase in drilling fluid density to provide anincrement of overbalance in order to compensate for effects of swabbing.

Tubulars - Drill pipe, drill collars, tubing, and casing.Underground Blowout - An uncontrolled flow of formation fluids from asubsurface zone into a second subsurface zone.

Underbalance - The amount by which formation pressure exceeds pressureexerted by the hydrostatic head of fluid in the wellbore.

Unit/Remote Selector - The valve located on the manifold header whose portsallow flow into the annular regulator. The valve position determines the source offlow supply and subsequently controls the location of operation.

Valve, Float - A device that is positioned as either open or closed, depending onthe position of a lever connected to a buoyant material sitting in the fluid to bemonitored.

Valve, Manipulator - A control device having three positions, giving fourdirection selections for flow which alternately pressurises and vents the pressureoutlets. The manipulator style valve vents all pressure outlets when placed in thecentre position.

Valve, Poppet - The opening and closing device in a line of flow which restrictsflow by lowering a piston type plunger into the valve passageway.

10- 20



Valve, Pre-charge - The device located on the accumulator bladder ports whichopen and close for the nitrogen pressure contained.

Valve, Relief - A valve that opens at a present pressure to relieve excessivepressures within a vessel or line whose primary function is to limit systempressure.

Valve, Selector - A control device having three positions, giving four directionselections for flow which alternately pressurises and vents the pressure outlets.The selector style valve blocks all pressure points if placed in the centre position.

Valve, Shutoff - A valve which operates fully open or fully closed to control theflow through the lines.

Valve, Shuttle - A connective valve which selects one of two or more circuitsbecause flow or pressure changes between the circuits.

Viscosity - A measure of the internal friction or the resistance of a fluid to flow.

Volt - A unit of electromotive force.

Watt - A unit of electrical power; the power of one ampere of current pushed byone volt of electromotive force.

Weight Cut - The amount by which drilling fluid density is reduced by entrainedformation fluids or air.

Wireline Preventers - Preventers installed on top of the well or drill string as aprecautionary measure while running wirelines. The preventer packing will closearound the wireline.

Zero Adjustment - The control to move the meter gauge indicator for resettingcalibration accuracy. Control used to make the meter read 0 by applying an offsetvoltage to the meter to offset any positive voltage present at the meter, eventhough there is no pressure at the input of the transducer.

Documents

ADS Well Control Manual