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A B E R D E

E N D RILL I N G S C H

O O L S

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&

W E L L C O N T R O L T R A I N

I N G

C E N T R E

for the Rig-Site Drilling Team

TRAINING MANUAL

REVISED EDITION

ABERDEEN DRILLING SCHOOLS& Well Control Training Centre

WELL CONTROL



ABERDEEN DRILLING SCHOOLS and Well Control Training Centre

WELL CONTROL for the Rig-Site Drilling Team

REV 6: JAN 2008

Training Manual

50 Union Glen, Aberdeen, AB11 6ER SCOTLAND U.K. Tel: (01224) 572709 Fax: (01224) 582896 e-Mail: [email protected]

WELL CONTROLfor the Rig-Site Drilling Team





REV 6: JAN 2008

COPYRIGHT STATEMENT

All rights reserved. No part of this publication may be reproduced or transmitted inanyform or by any means, including photocopying and recording without the writtenpermissionof 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 publicationis stored ina retrieval system of any nature.

Brand names, company names, trademarks, or other identifying symbols appear-ing in illustrations and/or text are used for educational purposes only and do notconstitute an endorsement by the author or publisher.

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





REV 6: JAN 2008

Introduction

1. Fundamental Principles of Well Control

2. Causes of Kicks

3. Kick Indicators

4. Shut-in Procedures

5. Methods of Well Control

6. Well Control Equipment

7. Inspection, Testing and Sealing Components

8. Surface BOP Control Systems

9. Subsea BOP Control Systems and Marine Riser Systems

10. Formulae, Conversion Factors & Glossary of Terms

CONTENTS




INTRODUCTION

REV 6: JAN 2008

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 rst 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 specic. The manual covers the guidelines foundin API 16E, API 53 and API 59 along with the International Well Control Forumsyllabus. It also covers the basic requirements for IADC WellCap Certication at

all levels.

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 nd the equipment section comprehensive and useful for generaltrouble shooting ideas.





REV 6: JAN 2008

SECTION 1Fundamental Principles Of Well Control

1.0 Objectives

1.1 General Information

1.2 Hydrostatic Pressure

1.3 Formation Pressure

1.4 Normal Formation Pressure

1.5 Abnormal Pressure

1.6 Formation Fracture Pressure

1.7 Leak-off Tests

1.8 Maximum Allowable Annular Surface Pressure - MAASP

1.9 Casing Setting Depths

1.10 Circulating Pump Pressure

1.11 Choke Line Friction

1.12 Workshop 1




SECTION 1 : FUNDAMENTAL PRINCIPLES OF WELL CONTROL

REV 7: AUG 2009 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 threemain categories, namely PRIMARY WELL CONTROL, SECONDARY WELL

CONTROL and TERTIARY WELL CONTROL. These categories are brieydescribed 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 uids in the formation being drilled, butless than formation fracture pressure. If hydrostatic pressure is less than formationpressure then formation uids will enter the wellbore. If the hydrostatic pressureof the uid in the wellbore exceeds the fracture pressure of the formation then theuid in the well could be lost. In an extreme case of lost circulation the formation

pressure may exceed hydrostatic pressure allowing formation uids 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 uids in the wellbore ( i.e. mud) fail to prevent formationuids entering the wellbore, the well will ow. This process is stopped using a“blow out preventer” to prevent the escape of wellbore uids from the well.

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





REV 7: AUG 2009 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 itis not always used as a qualitative term. ‘Unusual well control operations’ listed

below 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.





REV 7: AUG 2009 1 - 3

1.2 HYDROSTATIC PRESSURE

Hydrostatic pressure is dened as the pressure due to the unit weight and verticalheight of a column of uid.

Hydrostatic Pressure = Fluid Density x True Vertical Depth

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

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

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

7.48 lbs –––––––– = 0.052 psi 144 sq.ins

Figure 1.2Area denition of a cubic foot

12"

12"

12"

T V D





REV 7: AUG 2009 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:

Specic 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 solely by 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 uid, 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 ofMexico is 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.





REV 7: AUG 2009 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 uid 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 in

formations 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

FormationWater

Pressure

PSI/ft

Gradient

(SG)

Example Area

Fresh water

Brackish water

Salt water

Salt water

Salt water

Salt water

0.433

0.438

0.442

0.452

0465

0.478

1.00

1.01

1.02

1.04

1.07

1.10

Rocky Mountains and Mid-

continent, USA

Most sedimentary basins

world wide

North Sea, South China sea

Gulf of Mexico, USA

Some area of Gulf of Mexico





REV 7: AUG 2009 1 - 6

Figure 1.4

Porosity %

0 10 20 30 40 50 60 70 80

D e p t h ( m e t r e s )

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 ofdepth (modified from Magara, 1978)





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1.5 ABNORMAL PRESSURE

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

The principal causes of abnormal pressures are:-

1.5.1 Under-compaction in shales

When rst 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 normal

compaction, 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 ushed from theshale.

If the balance between the rate of compaction and uid expulsion is disruptedsuch that uid removal is impeded then uid pressures within the shale will

increase. The inability of shale to expel water at a sufcient 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.





REV 7: AUG 2009 1 - 8

Figure 1.5b

Figure 1.5c

Coarse - and very coarse - grained

Coarse - and medium - grained

Fine - grained

Silty

Clayey

100008000

6000

4000

2000

40

20

1086

4

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 %

P E R M E A B

I L I T Y ( m d )

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

1stDEHYDRATION

ANDLATTICE WATERSTABILITY ZONE

2ndDEHYD'N

STAGE

3rdDEHYDRATION

STAGE

INTER-LAYER

WATER

PORE ANDINTERLAYERWATER EXPULSION

INTERLAYER WATERISOPLETH

DEEP BURIAL

WATER LOSS

LATTICE WATERSTABILITY ZONE

'NO MIGRATION LEVEL'

B U R I A L D E P T H

( S C H E M A T I C )

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





REV 7: AUG 2009 1 - 9

1.5.2 Salt Beds

Continuous salt depositions over large areas can cause abnormal pressures. Saltis totally impermeable to uids and behave plastically. It deforms and ows

by recrystallisation. Its properties of pressure transmission are more like uidsthan solids, thereby exerting pressures equal to the overburden load in alldirections. The uids 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 uid 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 being

compacted with increasing overburden pressures. If however an additionalhorizontal compacting force squeezes the clays laterally and if uids 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 ofShortening





REV 7: AUG 2009 1 - 10

1.5.5 Faulting

Faults may cause abnormally high pressures.Formation slippage may bring a permeableformation laterally against an impermeableformation preventing the ow of uids. Non-sealing faults may allow uids to move froma deeper permeable formation to a shallowerformation. If the shallower formation is sealedthen it 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 g:

Figure1.9b Figure1.9b

An anticlinal type of folded structureis shown here. Anticline differs froma dome in being long and narrow.

WATER

OIL

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

IMPERVIOUS

SHALE GAS

OIL

WATER

Trap nomenclature (a) in a simple structural

trap and (b) in stratigraphic traps. Note that

the size of the stratigraphic trap on the leftis 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

Gas

Gas-WaterContact(GWC)

Gas-OilContact(GOC)

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

Cap Rock

Gas

Oil

WaterWater

Salt





REV 7: AUG 2009 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

Figure 1.11

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

CombinationOtherStratigraphic

ReefUnconformitySalt DiapirsFaultsAnticlines

Structural Traps Stratigraphic Traps CombinationTraps

3%3%2%1%

75%

9%7%

Types of seals and percentage of world’s petroleumoccurrence for each.

Carbonate(limestone & dolomite)

Evaporite(salt)

Shale

2%

33%

65%





REV 7: AUG 2009 1 - 12

1.6 FORMATION FRACTURE PRESSURE

In order to plan to drill a well safely it is necessary to have some knowledge ofthe fracture pressures of the formation to be encountered. The maximum volumeof any uncontrolled inux 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 uids (water/oil) occupyingthe pore space within the matrix, above the zone of interest. These two factors

combine 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.

Figure 1.12

NORMAL COMPACTIONAbnormally High Pressure Due to Hydrocarbon Column

0

4

5

6

7

8

9

1000’

WATER

GAS

D E P T H

- 1 0 0 0 f t

Normal pressure atthe 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 Sand

2690 psi ––––––– = 0.538 psi/ft5000 ft

GRADIENT = 0.10 psi/ft

1





REV 7: AUG 2009 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

Figure 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 ft

Total Overburden11167.5 psi (0.93 psi/ft)

Total Overburden12000 psi (1.0 psi/ft)

Total Overburden2167.5 psi (0.723 psi/ft)

Total Overburden3000 psi (1.0 psi/ft)

Fracture Gradient Comparisons(for illustration purposes only)





REV 7: AUG 2009 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 uid 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 instancesas when drilling development wells this might not be necessary and a formation

competency 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 ush 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 volumeat a time into the well typically a 1/

4 or 1/

2 bbl per min. Monitor the pressure

build 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.





REV 7: AUG 2009 1 - 15

EXAMPLES OF LEAK-OFF TEST PLOT INTERPRETATION

In non-consolidated or highly permeable formations uid can be lost at verylow pressures. In this case the pressure will fall once the pump has been stoppedand a plot such as that shown in Fig 1.14a will be obtained. Figs 1.14b and 1.14cshow typical plots for consolidated permeable and consolidated impermeableformations respectively.

Figure 1.14

IDEALISED LEAK-OFF TEST CURVES

CUMULATIVE VOLUME

a) UnconsolidatedFormations

P R E S S U R E

CUMULATIVE VOLUME

b) Consolidated PermeableFormations

P R E S S U R E

CUMULATIVE VOLUME

c) ConsolidatedImpermeable Formations

P R E S S U R E

Final Pumping Pressure After

Each Volume Increment

Final Static Pressure After

Each Volume Increment

Leak-off Point





REV 7: AUG 2009 1 - 16

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

“Operational Drilling Procedures for Floating Rigs” is designed to determine theequivalent mud weight at which the formation will accept uid. 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 oat 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 ll 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 increments untiltwo 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 will stabilizeafter 15 mins or so).





REV 7: AUG 2009 1 - 17

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

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 conrmation is required, otherwiseleak-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 sufcient 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 standing pressure 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 pressure

The 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

or Formation Breakdown Pressure (psi)Maximum Allowable Mud Weight (ppg) = –––––––––––––––––––––––––––––– ÷ 0.052 Vert Shoe Depth (ft)





REV 7: AUG 2009 1 - 18

Graph 1.1 Formation Pressure Test Work Sheet

1100

1000

900

800

700

600

500

400

300

200

100

0

0 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)

S U R F A C E

T E S T P R E S S U R E

- P S I

BARRELS MUD PUMPED





REV 7: AUG 2009 1 - 19

Graph 1.2

1100

1000

900

800

700

600

500

400

300

200

100

0

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14

NOTE: Commence plotting pressureNOTE: and pumped volume after

NOTE: pressuring up to 200 psi

S U R F A C E

T E S T P R E

S S U R E

- P S I

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





REV 7: AUG 2009 1 - 20

Graph 1.3

1100

1000

900

800

700

600

500

400

300

200

100

0

0 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

S U R F A C E

T E S T

P R E

S S U R E

- P S I

BARRELS MUD PUMPED

Typical Pressure Plot forFormation Breakdown andFracture Propagation

FormationBreakdownPressure

Leak-offPressure





REV 7: AUG 2009 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 in

the casing is changed MAASP must be recalculated. If mud weight is increasedMAASP will decrease

The calculated MAASP is no longer valid if inux uids 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 thecasing setting depths too shallow could haveserious consequences. An unnecessarily deepsetting depth could have adverse economicconsequences when considering the extratime needed to drill the hole deeper and theextra amount 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" Liner

8 1/2" Hole

12 1/4" Hole

17 1/2" Hole

26" Hole

36" Hole

Seabed





REV 7: AUG 2009 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 proles. Once all the information has been collated from offset welldata a plot similar to that shown in Fig 1.16 can be drawn up. By studying thegeology and pressure proles, tentative setting depths can be chosen based onthe prevention of formation breakdown by mud weights in use in the subsequenthole section. 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” will

normally 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

D e p t h x 1 0 0 0 f t

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

D e p t h x 1 0 0 0 f t





REV 7: AUG 2009 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 exposed formations,consequently the total pressure at the bottom of the annulus is higher with thepump on than with the pump off.

Static bottom AnnulusCirculating bottom hole pressure =

hole pressure+pressure losses

Figure 1.18

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 underControl





REV 7: AUG 2009 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

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

Where: APL = Annulus Pressure Loss P

muda = Hydrostatic Mud Pressure in Annulus

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

Example:- Assuming a circulating pump pressure is 3000 psi when pumping at

100 spm. The pump speed is increased to 120 spm. To approximate the newcirculating pump pressure:

New Pump Speed 2 P(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 2 P(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 12

P(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 pressure

losses.

( )

( )





REV 7: AUG 2009 1 - 25

1.11 CHOKE LINE FRICTION

LOSSES IN SUBSEA KILL OPERATIONS Figure 1.19In subsea situations, a pressure loss exists when circulatingthrough the choke due to the friction losses in the extendedchoke line running up from the BOP. This pressure lossis not accounted for in normal Slow Circulating Rate (SCR)measurements, which are taken while circulating up themarine riser (see Fig 1.19).

If the normal method of bringing pumpsto kill speed is followed (that is, choke manifold pressuremaintained equal to SICP until kill rateis achieved), bottom hole pressure will be increased byan amount equal to this choke line friction loss (CLFL).This excess pressure can result in serious lost circulationproblems during the kill operations.

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 considered whileplanning well control operations.

It is possible to measure CLFL while taking SCR’s. Onesimple way to do this is to pump down the choke line atreduced pump rates (taking returns up the open marineriser as is shown 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 accomplish thisa method must be used to keep total applied casingpressures relatively constant while bringing the mudpump to kill rate.

In the absence of signicant CLFL (surface stacks orshallow water), the method used is to merely keepchoke manifold pressure equal to SICP until the pump

is up to speed.

But when CLFL exists, total applied casing pressure

500

PSI

SHAKERS

CONVENTIONAL SCF

FLOW PATH

0PSI

SHAKERS

CLFL MEASUREMENT PUMPING

DOWN CHOKE LINE CLCF = 200 PSI

200PSI

FROM PUMP

CHOKE

DRILL PIPE CHOKE MANIFOLD

Figure 1.20





REV 7: AUG 2009 1 - 26

varies from SICP at pump start-up to SICP + CLFL with the pump at kill rate, if theabove method were used. This would cause bottom hole pressure to increase by anamount equal to CLFL, as shown in Figures 1.21 and 1.22


800

PSI

Pf = 6000 psi

Ph = 5200 psi (in annulus)

PUMPS OFF (kick shut in)

1000

PSI

CHOKE


SUBSEA BOP

CLFL

0 PSI

(STATIC)

APL

0 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





REV 7: AUG 2009 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 pressureto SICP -CLFL), the effect of the CLFL is negated. Thisis accomplished by reducing the original SICP by theamount of CLFL while bringing the pumps to speed(see Figure 1.23). Once kill rate pressure has beenestablished, the choke operator switches over to thedrill pipe gauge and follows the drill pipe pressuregraph in the usual way.

Or secondly, given a choke manifold congurationwith separate pressure gauges for choke and killlines, it is possible to utilise the kill line (shut offdown-stream of the gauge outlet to prevent ow, thuseliminating friction) as a pressure connection to a pointupstream of any potential CLFL (known or unknown).This is shown in Figure 1.24. If the kill line gauge inthis instance is kept constant while bringing the pumpto speed, the effect of CLFL is eliminated.

Figure 1.24Note the advantages of the second method:

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

2. No precalculated or pre-measured CLFL

information 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 wouldbe advisable to rig a remote kill line

pressure gauge which could be seen bythe choke operator.

1300PSI

Pf = 6000 psi


PUMP AT KILL RATE WITH REDUCED

CHOKE MANIFOLD PRESSURE


800

PSI

CHOKE


SUBSEA BOP

CLFL

200 PSI

(DYNAMIC)

APL

NEGLIGIBLE

BHP 6000 PSI

RETURNS

1300PSI

Pf = 6000 psi


PUMP AT KILL RATE HOLDING CONSTANT

KILL LINE PRESSURE READINGCHANGE IN BHP = 0 psi increase

800

PSI

CHOKE


SUBSEA BOP

CLFL

200 PSI

(DYNAMIC)

APL

NEGLIGIBLE

BHP 6000 PSI

RETURNS

KLFL

0 PSI

(STATIC)

1000

PSI





REV 7: AUG 2009 1 - 28

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 wereCLFL absent. This is done without the need to alter anycalculations on the kick sheet. Thus initial and nalcirculating pressures, which are read on the drill pipegauge, are unaffected by CLFL. CLFL is recorded on theKick Sheet for convenience only – it is not used in kicksheet calculations.

Several additional points should be made about CLFL.

It should be noted that it will only be possible to use theabove recommended methods when SICP is greater thanCLFL. If this is not true, it will be unavoidable to applyexcess pressure to the bottom of the hole using standardwell control procedures. Also, as kill mud comes up theannulus, total applied casing pressure needed to maintainconstant bottom hole pressure will eventually drop belowCLFL. After this point, drill pipe pressures will exceedplanned Final Circulating Pressure in spite of having thechoke wide open with no choke manifold back pressure.

These 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 pumpingas a result of the increase in back pressure created incirculating up the choke line, by itself or choke and killlines together.

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

Note increase in BHP

due 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

575

PSI

Pf = 5200 psi


PUMP AT 4 BBL/MIN HOLDING 0 PSI

CHOKE MANIFOLD PRESSURE


0

PSI

CHOKE


SUBSEA BOP

CLFL

200 PSI

(DYNAMIC)

APL

NEGLIGIBLE

BHP 5300 PSI

RETURNS

Figure 1.26





REV 7: AUG 2009 1 - 29

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

pumping rate of 4 bbl/min.


275PSI

Pf = 5200 psi

Ph = 5100 psi (in annulus)PUMP AT 2 BBL/MIN WITH REDUCEDCHOKE MANIFOLD PRESSURECHANGE IN BHP = 0 psi increase

40PSI

CHOKE


SUBSEA BOP

CLFL60 PSI(DYNAMIC)

APLNEGLIGIBLE

BHP 5200 PSI

RETURNS

475

PSI

Pf = 5200 psiPh = 5100 psi (in annulus)

PUMP AT 4 BBL/MIN USING CHOKE

AND KILL LINES FOR RETURN FLOW

40

PSI

CHOK


SUBSEA BOP

CLFL

60 PSI

(DYNAMIC)

APL

NEGLIGIBLE

BHP 5200 PSI

RETUR

KLFL

60 PSI

(DYNAMIC)

40

PSI

CHOKE

RETURNS

2 BBL/MIN2 BBL/MIN

4 BBL/MIN





REV 7: AUG 2009 1 - 30

1.12 - WORKSHOP 1

SCORE

1. Convert the following mud densities into pressure gradients.

a. 13.5 ppg _____________ psi/ft b. 16 ppg _____________ psi/ft c. 12 ppg _____________ psi/ft 2

2. Convert the following gradients into mud densities.

a. 0.806 psi/ft _____________ ppg b. 0.598 psi/ft _____________ ppg c. 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 pressure gradients resulting in:

a. An increase in the hydrostatic gradient b. A decrease in the hydrostatic gradient c. Would have no effect 2





REV 7: AUG 2009 1 - 31

SCORE

6. Assuming a 10 ppg mud is being circulated at 700 GPM at adepth 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 psi

Pressure loss across the bit jets 1600 psi Pressure loss in the annulus 200 psi

a. When circulating what is the dynamic bottom hole

pressure?

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 on bottom 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





REV 7: AUG 2009 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 uid level in a well bore fell by 480ft, what is the reduction

in 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 psi theoretically how far could the mud level fall before going

under-balance?

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

11. 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





REV 7: AUG 2009 1 - 33

WORKSHOP 1 - Answers


1. MUD WEIGHT x 0.052

a. 13.5 x 0.052 = 0.702 psi/ft b. 16.0 x 0.052 = 0.832 psi/ft c. 12.0 x 0.052 = 0.624 psi/ft

2. GRADIENT ÷ 0.052

a. 0.806 ÷ 0.052 = 15.5 ppg b. 0.598 ÷ 0.052 = 11.5 ppg c. 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 psi b. 18000 x 15.5 x .052 = 14508 psi c. 9000 x 0.889 = 8001 psi

4. PRESS ÷ T.V.D ÷ .052 a. 3495 ÷ 7000 ÷ .052 = 9.6 ppg

b. 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 psi

b. 10000 x 10 x .052 = 5200 psi c. 5400 ÷ 10000 ÷ .052 = 10.38 ppg d. 3000 x (800)2 = 3918 psi ——

(700)





REV 7: AUG 2009 1 - 34

Note d. This calculation is the same relationship asPress-Strokes-Relationship.

(i.e.) P x (new S.P.M)2

————— (old S.P.M.)

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 0.052 = 299.52 psi (300 psi)

10. PRESS - (psi) = 240 = 384ft

——— —— MUD g (psi/ft) .624ft

11. 8500 x .486 = 4131 + 200

= 4331 psi

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





REV 6: JAN 2008

SECTION 2Causes Of Kicks

2.0 Objectives

2.1 Introduction

2.2 Primary Well Control- How it is Affected

2.3 Causes of Kicks and Inuxes

2.4 Hydrate Formation & Prevention

2.5 Function of Drilling Muds

2.6 Extracts From API RP59

2.7 Workshop 2




SECTION 2 : CAUSES OF KICKS

REV 7: AUG 2009 2 - 1

CAUSES OF KICKS

2.0 OBJECTIVES

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

2.1 INTRODUCTION

Primary control is dened as using the drilling uid to control formation uidpressure. The drilling uid has to have a density that will provide sufcientpressure to overbalance pore pressure. If this overbalance is lost, even temporarilythen formation uids can enter the wellbore. Preventing the loss of primarycontrol is of the utmost importance.

Denition of Kick

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

Denition of Inux

An inux is an intrusion of formation uids into the wellbore which does notimmediately cause formation pressure to exceed the hydrostatic pressure of theuid in the wellbore, but may do, if not immediately recognised as an inux,

particularly if the formation uid 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 is being 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 or

displaced 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.



REV 7: AUG 2009



2 - 2

Figure 2.1

Numberof Stands

DISPLACEMENT

Per ___ Std. Total

Theoretical Last Trip This Trip Comments

Per ___ Std. Total Per ___ Std. Total

Well NameDate

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, recordlevel of decrease.

If rig pump is used, calculate from strokes.





REV 7: AUG 2009 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 ll the

hole is signicantly less than the volume of steel removed, then tripping must be stopped to ensure the well is stable, and consideration given to going back to bottom 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 oortogether 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 ECDwhen pumps are off and to overcome the effects of swab pressures during a tripout 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



REV 7: AUG 2009



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 ow line temperatures

• Recording penetration rates

• Pore Pressure Trends





REV 7: AUG 2009 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 TEMPERATURE

RETURN MUD WEIGHT

• ROTARY SPEED

• TORQUE

VDU INCOMPANY

REP'S OFFICE

MUD L

OGGIN

G

UNIT

P R O C E

S S I N G

A N D

E V A L U A

T I O N

CUTTINGS DENSITY



REV 7: AUG 2009



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 ow 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.

• Insufcient 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 uid levels when pulling pipe and not lling the hole.

• Swabbing.





REV 7: AUG 2009 2 - 7

2.3.1 FAILURE TO KEEP THE HOLE FULL DURING A TRIP

If the uid 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 andll 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 inux of formation uidsinto 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 mudand the drill string being pulled. Swabbing can also be caused by the full gauge

down hole tools (bits, stabilisers, reamers, core barrels, etc.) being balled up. Thiscan create a piston like effect when they are pulled through mud. This type ofswabbing can have drastic effects on bottom hole pressure.

FILL UPLINE

RETURN LINE

TANK

BELL

NIPPLE

FLOAT

INDICATOR

PUMP

CONTINUOUS CIRCULATING TRIP TANK



REV 7: AUG 2009



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 running

the drill string too fast in the hole. Down hole mud losses may occur if care isnot taken 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 inux volume may be swabbed into the open holesection. The net decrease in hydrostatics due to this low density uid will also besmall. If the inux uid 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 is

normal 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 inux occurring.

PRESSURE SURGES SWABBING ACTION





REV 7: AUG 2009 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 owing a non return valveshould be installed and the bit returned to bottom. Flow check each stand. Once

back on bottom the well should be circulated and the bottoms up sample checkedfor contamination.

If the well is owing 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 ow then a kelly cock mayhave to be installed rst.

• 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. + dp cap. (bbls/ft))Pulling Wet Pipe: psi/ft or wet pipe pulled = –––––––--–––––––-–––––-–––––––––-––––––

(casing cap. (bbls/ft) - (metal disp. + dp cap. (bbls/ft))

( )

( )



REV 7: AUG 2009



2 - 10

2.3.3 LOSS OF CIRCULATION

Another cause for a kick to occur is the reduction of hydrostatic pressure throughloss of drilling uid to the formation during lost circulation. When this happens,the height of the mud column is shortened, thus decreasing the pressure on the

bottom and at all other depths in the hole.

The amount the mud column can be shortened before taking a kick froma permeable 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 havelow permeability then traces of the formation uid should be detected in thereturns after 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 ow

is 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 inow-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.





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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 uids in the shale. Inthis situation the shale will have more porosity, and a lower density, than they

would have 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 theuids contained in the pore space.

Figure 2.8

Abnormally high formation pressure is dened as any formation pressure thatis greater than the hydrostatic pressure of the water occupying the formationpore spaces. 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



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2 - 12

Abnormally high formation pressures are found worldwide in formations rangingin age from the Pleistocene age (approximately 1 million years) to the Cambrian

age (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 dened, the magnitude of abnormally high formation pressures must begreater than the normal hydrostatic pressure for the location, and may be ashigh as the overburden pressure. Abnormally high pressure gradients willthus be between the normal hydrostatic gradient (0.433 to 0.465 psi/ft) and the

overburden gradient (generally 1.0 psi/ft).

However, locally conned 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/ft

have 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 muchof their thickness. Pressure gradients of 0.52 psi/ft are common with locally

occurring 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 ofthe order of 0.62 psi/ft or higher are required to keep the wellbore open becauseof the swelling 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/ft have been recorded. One reported case indicated a formation pressure gradientof 0.91 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.





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In Triassic sediments, abnormally high formation pressures have been found ingas bearing zones of the Bunter Sandstone in the southern North Sea. Also in

the southern 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.

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 ow. Down hole chokes can be incorporated in the

test string to limit surface pressures and ow rates to the capabilities of the surfaceequipment to handle or dispose of the produced uid.

During the course of the test, the bore hole or casing below the packer, andat least a portion of the drill pipe or tubing, is lled with formation uid. Atthe conclusion of the test, this uid 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 wherea large number of directional wells are drilled from the same platform. If thedrilling well penetrates the production string of a previously completed well, theformation uid 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.



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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 severityof the inux will depend on the penetration rate, porosity and permeability, andis independent of mud weight. The importance attached to gas cutting is that gasis entering 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.

Most of mud cutting is close to surface. Divert ow through choke manifold toprevent belching and to safely contain gas through mud gas separator. Time drill

the 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 owing, resultingin a kick.





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2.4 APPENDIX - HYDRATE FORMATION & PREVENTION

2.4.1 FORMATION OF HYDRATES

Hydrates will only form if there is free water present in a system.

Hydrates are crystalline water structures lled with small molecules. In oil / gassystems they will occur when light hydrocarbons (or carbon dioxide) are mixedwith water at the correct temperature and pressure conditions.A very open, cage-like structure of water molecules is the backbone of hydrates.This structure which bears some resemblance to a steel lattice in a building cantheoretically be formed in ice, liquid water, and water vapour. In practice however,hydrates are only formed in the presence of liquid water. The crystal framework isvery weak and collapses soon if not supported by molecules lling the cavities inthe structures.Methane, Ethane, CO2 and H2S are the most suitable molecules to ll cavities.Propane and Isobutane can only ll the larger cavities. Normal butane and heavierHydrocarbons are too big and tend to inhibit hydrate formation.Tests indicate that Hydrate formation is comparable with normal crystallisation.‘Undercooling’ is possible, but the slightest movement within and undercooledmixture, or the presence of a few crystallisation nuclei will cause a massivereaction. Once the crystallisation has started, hydrates may block a owlinecompletely within seconds.

The formation of hydrates is governed by the crude composition, watercomposition, temperature and pressure. In most cases the crude compositioncannot be changed. Hydrates can be dissolved / prevented by a temperatureincrease or a pressure decrease. A chemical hydrate inhibition can be performed bychanging the composition of the water.Under the correct conditions of temperature and pressure, hydrates will formspontaneously.At high pressures, hydrates may form at relatively high temperatures; e.g. at 2900psi they can begin to form at about 77˚ F .Hydrates do not require a pressure drop to form. However, the refrigeration

effect from a small pressure drop, such as a stufng box leak, may be sufcient toproduce optimum pressure and temperature conditions for hydrate formation.Hydrates can form under owing or static conditions. The rst indication ofthem forming in the tubing or annular ow string is a drop in owing wellheadpressure followed by an initially slow then progressively rapid drop in wellheadowing temperature.During well operations, the greatest danger posed by hydrates is the plugging ofthe tubing string downhole. The biggest risk area for this occurring is on offshoreinstallations from the seabed upwards where temperatures are generally thelowest.



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A hydrate plug in the tubing string under owing or static conditions results in; being unable to run or pull wireline tools, unable to squeeze or circulate the well

dead, and unable to ow the well to remove the hydrates. Also, hydrates mayprevent vital equipment, such as the Downhole Safety Valve from functioningcorrectly. Thus a downhole hydrate plug gives rise to a potentially dangeroussituation and must be avoided at all costs.





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2.5 THE FUNCTIONS OF DRILLING MUDS

(1) PRIMARY FUNCTIONS:

(a) To help maintain the stability of the wellbore, by outward hydrostatic pressure andmud lter cake.

(b) To carry the drill cuttings up the annulus and back to the surface by its upward mo-tion and viscosity.

(c) To maintain pressure balance in the well during drilling, tripping and other opera-tions. The mud hydrostatic pressure must be at least equal to or greater than the reser-voir pore pressure.

(d) To cool the bit and drillstring and to lubricate the cutting surfaces at the bit.

(e) To hold cuttings in suspension, by its gelling action, when circulation is stopped.

(2) SECONDARY FUNCTIONS:

(f) To provide a working uid for downhole motors and turbines and for the transmis-sion of coded downhole signals to the surface (MWD)+.

(g) To help to support part of the weight of the drillstring by its buoyancy.

(h) To help to prevent mud ltrate invasion of productive formations by an imperme-able lter cake.

(i) To ease the movement of drillstring in the well and to reduce wear by its lubricity



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PROPERTIES of DRILLING MUDS

Drilling muds need to have some essential properties. Those are :

RHEOLOGY: This group of mud properties inuences the hydrodynamics of the mud behaviour. It includes:Mud (plastic) viscosity in centipoise units.Mud yield strength in lbf/l00ft2.Gel strength at 10sec and 10 minutes.

DENSITY: This is controlled by the weight additives in the mud. It is of importance

in pressure control, drilling rate (ROP) and in wall stability of the well.

FILTRATION: This is the ability of the mud to build a thin layer of lter cake on thewall of the hole. The lter cake controls the outward ow of liquidltrate from the mud into the reservoir formation. The deeper thepenetration of this ltrate into the rock, the more difcult later loggingof the well becomes.

LUBRICITY: This is the ability of the mud to provide a degree of lubrication of therubbing surfaces of the drillstring and the rock or the casing, and so

reduce wear. lt is provided by the clays, polymers or oils in mud.

Additionally, the mud needs to have properties of resistivity and corrosion inhibition .

CLASSIFICATION OF DRILLING MUDS

Drilling muds can be divided into the following classes:

(1): Water-based muds ie fresh water or sea water.

(2): Oil-bascd muds: (a) Invert emulsions, with oil:water ratios from 50:50 to 90:10.

(b) Low toxic invert emulsions, as in(a) but with low to base oils.

(3): Synthetic or pseudo oil-based muds.

In addition to muds, gas and stable foams may be used as drilling uids.





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INGREDIENTS of DRILLING MUDS:

All muds have 4 categories of ingredients:

(a) A liquid base to support other components

(b) A viscosier, to produce viscosity and gel.

(c) A weighting agent, to produce density.

(d) Chemicals to control changes to the mud arising from interactions with thedrilled formations.

MUD CLASSlFICATION: WATER-BASED MUDS.

BASE FLUID: Fresh water or sea water or brackish water. (SG = l to 1.03)

VISCOSIFIER: Bentonite clays and/or co-polymers.(SG= 2.6)

WEIGHTING: Barite (sg = 4.2) or,Magnetite (sg = 5.1) or,Galena (sg= 6.5)

CHEMICALS: Caustic soda or lime for pH control.Lignosulfonate derivatives, for thinning.Salts, for inhibition of reactions.Gypsum, for inhibition.Starch and gums.Surfactants.Corrosion inhibitors' etc.



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SOME TYPICAL MUDS:

(1) SPUD MUDS: Very basic: Sea water and pre-hydrated clays, or native clays.Used for top-hole sections. Hi pump rates needed to give good hole-cleaning and wall support. Very low cost/bbl.

(2) LIGNOSULFONATE MUDS: Used where active native clays have to be drilled.Lignite materials are added to control the thickening effect of thoseclays. Give good control of the drilled solids and mud rheology. If seawater is base uid, pre-hydrated bentonite slurry must be used .

(3) LIME ,GYPSUM or CALCIUM TREATED MUDS: Used where shale/clays oranhydrites are present and may cause hole instability.

(4) SALT WATER MUDS: Used where salt formations or unstable shales are to bedrilled. Sodium or potassium salts (NaC1 or KCI) are used forinhibition.

(5) POLYMER MUDS: Use high molecular weight polymers (CMC, hydroxyethylcellulose) to give viscosity and gel. May be used with small amountsof bentonites to give Low Solids Non-Dispersed muds. Good ROP'sand protection against formation damage.





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FUNCTIONS AND PROPERTIES OF OIL WELL DRILLING FLUIDS

F u n c t i

o n

1 . C o n f i n e s f o r m a t i o n

p r e s

s u r e s

2 . C a r

r i e s o u t c u t t i n g s

3 . P r o t e c t s a n d s u p p o r t s

b o r e - h o l e w a l l b y t h e

f o r m

a t i o n o f a n

i m p

e r m e a b l e m u d c a k e

w h i c h a l s o m i n i m i s e

c o n t a m i n a t i o n

4 . L u b

r i c a t e s a n d c o o l s

b i t a n d d r i l l s t r i n g

R e l e v a n t p r o p e r t y

M u d d e n

s i t y

a . V i s c o s i t y

b . B i n g h a m

y i e l d p

o i n t

c . G e l S t r

e n g t h

a . F l u i d l o s s

b . S o l i d c

o n t e n t

a . W a t e r c o n t e n t

E f f e c t o f p r o p e r t y

o n p e n e t r a t i o n r a t e

I n c r e a s e d m u d d e

n s i t y

d e c r e a s e s p e n e t r a t i o n

r a t e

I n c r e a s e m u d v i s c

o s i t y


r a t e

I n c r e a s e y i e l d p o i n t a n d

g e l s t r e n g t h d e c r e a s e s

p e n e t r a t i o n r a t e

D e c r e a s e d f l u i d l o

s s

s l i g h t l y d e c r e a s e s

p e n e t r a t i o n r a t e

I n c r e a s e s s o l i d s c o

n t e n t


r a t e

I n c r e a s e d w a t e r c o n t e n t

I n c r e a s e s p e n e t r a t i o n r a t e

R e c o m m e n d e d v a l u e

H a s t o b e c a l c u l a t e

d f r o m

w e l l d e p t h a n d e x p

e c t e d

p r e s s u r e s

S a f e t y f a c t o r : 2 - 3 0 0

p s i

o v e r p r e s s u r e

( 1 5 0 0 - 2 0 0 0 K P a )

K e e p a s l o w a s i s

p r a c t i c a l l y p o s s i b l e

3 5 - 5 0 s e c s

M . F .

A . V

1 2 - 2 0 c p

P V

1 0 - 1 5 c p

Y P + 9 x m u d d e n s

i t y k g / L

0 ’ g e l ( m u d d e n s i t y - 1 ) x 1 0

1 0 ’ g e l ( m u d d e n s i t y - 1 ) x 1 5

S p u d m u d + 2 0 m l

s

S h a l l o w n o p r o d u c

i n g

z o n e s 1 0 m l s

B e l o w 1 0 , 0 0 0 f t 5 m

l s

H o l e t r o u b l e s o r p r o d u c i n g

z o n e s

< 5 m l s

I n u n w e i g h t e d m u

d s

< 1 0 % v o l

.

I n u n w e i g h t e d m u

d s

> 9 0 % v o l

.

C h e m i c a l s f o r

c o n t r o l

R a i s e b y a d d i n g

B A R Y T E S

L o w e r b y a d d i n g

W A T E R

( c h e c k v i s c o s i t y )


B E N T O N I T E o r

C . M . C .


W A T E R

( c h e c k d e n s i t y ) o r

T H I N N E R


B E N T O N I T E


T H I N N E R


C . M . C . o r

T H I N N E R


W A T E R

K e e p a s l o w a s

p o s s i b l e b y

c o n t i n u o u s r e m o v a l

o f u n w a n t e d c l a y ,

s i l t , s a n d a n d

c u t t i n g s



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2 - 22

MUD CONTAMINATION:

Mud contaminants are extraneous materials which enter the mud during the drillingprocess, and which alter and degrade the essential mud properties.

Mud contaminants arise from:

(1) The formations which are drilled. Those contaminants are either solid or liquidsor gases from:

(a) Shales:(b) Limestones,dolomites and anhydrites:(c) Salt formations:

(d) Formation brines:(e) Hydrogen sulphide, carbon dioxide:(f) Retained small particles (< 2 microns) of cuttings.

(2) Cement: this is a potential problem when cementing casings and on drilling out"green" cement plugs.

Those contaminants will generally cause adverse reactions in the muds(particularly water-based muds), such as:

Flocculation, where dispersed bentonite clay platelets can aggregate, causing (i) rising gel strengths;

(ii) high rates of uid loss from mud;(iii) thick,soft lter cake.

Viscosity changes.





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LOW TOXIC OIL BASED MUDS:

Generally all oil-based muds in Western activities are of the low-toxic base oil types.Many governments have stringent regulations which limit or ban the discharge of oilimpregnated cuttings. Oil to water ratios lie in the range of 50%: 50% to 90%: 10% . Atypical LT OBM would have the following categories of constituents:

LT base oil (of the parafn series).

Water, which has calcium chloride (CaCl) dissolved to 250,000 ppm or which issaturated with salt (NaCI) to 315,000 ppm.

Primary emulsier.

Organophilic clay ( for viscosity).

Secondary emulsier and wetting agent.

Lime.

Weighting agent ( barite)

At atmospheric conditions, the lter cake from an OBM will be very thin and the

ltrate loss negligible.

LT OBM's are generally more expensive than straight water-based muds and, whendiluted, base oil should be used. Rig modications are necessary to handle LT OBM's.

Unlike water based muds, there is a problem relating to the solubility of a gas kick inthe base oil of the mud. This problem is much more acute at bottom hole pressuresaround 4000 psi than at high bottom hole pressures. Due to the gas solubility, the truevolume of an inux may be substantially greater than the measured pit gain. Thisproblem is compounded when the dissolved gas breaks out of solution at the bubble-

point pressure, when large volumes of gas can be released within the annulus or down-stream of the choke.



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2.6 EXTRACTS FROM API RP59

6.1 Introduction. Loss of primary well control most frequently results from:1) failure to keep the hole full; 2) swabbing; 3) insufcient drilling uid 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 (inux offormation uid into the wellbore) from becoming a blowout (uncontrolled owof formation uid).

6.2 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 ofthe kicking formation must be less than the formation pressure; and 2) the kickingformation must have sufcient permeability to allow ow into the wellbore. Tomaintain primary well control, drilling personnel should utilise all techniquesat their 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.

6.3 Hole Not Full of Drilling Fluid. When the uid level in the wellbore isallowed to drop or is maintained with a lighter density uid, the resultant reducedhydrostatic head can allow uid entry from the formation. The rig should havedrilling uid measuring devices to determine that proper uid replacement ordisplacement occurs when pulling or running pipe. The type of uid measuring

equipment used should be inuenced by the anticipated well control operationsinvolved in drilling the well.

6.4 Tripping Out of the Hole. When pulling pipe, its displacement volumeshould be replaced with the proper amount of drilling uid to maintain constanthydrostatic pressure. Any signicant reduction in hydrostatic pressure may resultin loss of primary control. If the hole fails to take the proper amount of drillinguid, hoisting operations should be suspended and an immediate safe course ofaction determined while observing the well. This usually requires returning to

bottom and circulating the hole. The frequency of lling the hole during tripping

operations is critical in maintaining primary control. The hole should be completelylled at intervals that will prevent an inux of formation uid. Continuous llingor lling after each stand of drill pipe may be advisable. The hole should be lledafter each stand of drill collars. When the hole is lled continuously, an isolateddrilling uid volume measurement facility (such as a trip tank) must be used.

6.5 Tripping In the Hole. In running pipe back in the hole, the drilling uidvolume increase at the surface should be no greater than predicted displacement.Some holes take signicant volumes of drilling uid 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 uid returns and comparison with prior trip records should provide a warningof possible loss of primary well control. The hole and uid returns should bechecked at frequent intervals.





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6.6 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, with its

length too great to clear the ram closure zone and/or its outside diameter too largeto t the pipe rams, to have the necessary crossover connection(s) readily availableso that correct pipe movement can be effected to be able to close more than theannular blowout preventer. In case of equipment repair on drilling rigs, the pipeshould be run at least back to the last easing shoe, if possible, before repairsare undertaken. In well servicing operations, when making equipment repairs,effecting routine maintenance, or shutting down overnight, the pipe should be runto a sufcient depth to ensure that the well can be controlled.

6.7 Swabbing. When pipe is pulled from a well, a reduction in bottom-holehydrostatic pressure (swabbing) may occur. Bottom-hole pressure reduction of

several hundred pounds per square inch (psi) can occur when swabbing takesplace. This pressure reduction, which can be sufcient to permit the entry offormation uid 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 uid 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 difcult to detect. The well may take some uid as thepipe is withdrawn but less than the complete pipe displacement. The detection ofswabbing, therefore, can only be done by accurately measuring the drilling uidadded to the hole as pipe is pulled. Three prime factors in controlling swabbingare: 1) drilling uid properties; 2) rate of pulling pipe; and 3) drill string and hole

congurations.

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

6.9 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 uid ow properties,and/or drilling uid 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.

6.10 Insufcient 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 insufcient drilling uid density.

6.11 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 uid density, 2) excessive annular circulatingpressure, 3) pressure surges related to running pipe or tools. 4) breakingcirculation, or 5) packing off in the annulus.



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6.12 Drill Stem Testing. Drill stem tests are performed by setting a packer abovethe formation to be tested and allowing the formation to ow. During the course

of testing, the borehole or casing below the packer and at least a portion of thedrill pipe or tubing is lled with formation uid. At the conclusion of the test,the uid in the test string above the circulating valve must be removed by properwell control techniques, such as reversing, to return the well to a safe condition.Depending on the length of hole below the packer, type of uid 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.

6.13 Drilling Into an Adjacent Well. Frequently, a large number of directionalwells are drilled from the same offshore platform or onshore drilling pad. If a

drilling well penetrates the production string of a previously completed well,the formation uid 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.

6.14 Excessive Drilling Rate Through a Gas Sand. Even if the drilling uiddensity in the hole is sufcient to control gas zone pressure, gas from thedrilled cuttings will mix with the drilling uid. Excessive drilling rate througha shallow gas zone or coal bed can supply sufcient gas from cuttings to reducethe hydrostatic pressure of the drilling uid column through a progressive

combination of density reduction and drilling uid loss from “belching” to thepoint that the formation will begin owing into the wellbore.

6.15 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, shing, performing primary or remedialcementing, running casing or liner operations, or when differential ll equipmentmalfunctions. All such operations require the accurate measurement and controlor drilling uid replaced or displaced in the well to maintain primary control.Complications can occur in primary control during oating drilling operations due

to distorted readings caused by motion and heave. The measurement of drillinguid volume and ow rate is most critical in oating operations and requirespit level monitoring devices (oats) located in the centre of the pits or multi-oats with sequential integration utilised. A trip tank and pit watcher should beconsidered if vessel movement creates any problem in measuring drilling uidrequirements on trips.

6.16 Special Situations. The accurate prediction of pressure gradients, particularlyabnormal pressure, and the prevention of an insufcient drilling uid densitysituation, are highly desirable but not always attainable. In some situations ofinsufcient drilling uid density, operations can be safely handled and proceedwithout increasing drilling uid 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 ow appreciably but gas exists after





REV 7: AUG 2009 2 - 27

a trip which may require use of blowout prevention equipment and/or rotatingheads. Sometimes uid inux will occur when circulation is stopped, but will not

occur during drilling operations due to the effect of annular circulating pressure.In this instance, successful operations usually require an increase in drilling uiddensity or, in some elds, the use of a lighter drilling uid and another heavierdrilling uid to control the well on trips.

WELL CONTROL WARNING SIGNALS

6.17 General. Well control warning signals can be classied in three major generalcategories as follows:

A. Previous Field History and Drilling Experiences.

1. Depth of zones capable of owing.

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 uid return rate.

3. Changes in owline temperature.

4. Drilling breaks.

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

6. Swabbing.

7. Drilling uid 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.



REV 7: AUG 2009



2 - 28

C. Chemical and Other Technical Responses From the Well.

1. Chloride changes in the drilling uid.

2. Oil show.

3. Gas show (chromatograph).

4. Formation water.

5. Shale density.

6. Electric logs.

7. Drilling equation exponents.

6.18 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 uid 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 uid to minimise further swabbing. It may benecessary to increase the drilling uid density, but this should not be the rst stepconsidered because of the inherent potential problems of causing lost returns or

differential sticking.

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

6.20 Increased Flow From Annulus. If the pumping rate is held constant, theow from the annulus should be constant. If the annulus ow increases without acorresponding change in pumping rate, the additional ow is caused by formation

uid(s) feeding into the wellbore or gas expansion.

6.21 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.

6.22 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 has

been noted on some pump pressure recording charts after a kick was detected.





REV 7: AUG 2009 2 - 29

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 uid

ows into the wellbore, the hydrostatic pressure exerted by the annular columnof uid decreases, and the drilling uid in the drill pipe tends to U-tube into theannulus. When this occurs, the pump pressure will drop and the pump speedwill increase. The lower pump pressure and increase in pump speed symptomsare also indicative of a hole in the drill string, commonly referred to as a washout.Until a conrmation can be made whether a washout or a well kick has occurred, akick should be assumed.

6.23 Gas-cut Drilling Fluid. Gas-cut drilling uid often occurs during drillingoperations and can be considered one of the early warning signs of a potentialwell kick: however, it is not a denite indication that a kick has occurred or is

impending. An essential part of analysing this signal is being able to determinethe downhole conditions causing the drilling uid to be gas-cut. Gas-cut uidoccurs as a result of one or more of the following downhole conditions:

1) drilling a gas-bearing formation with the correct drilling uid density in thehole (drilled gas); 2) swabbing while making connections or making a trip(trip or connection gas); and 3) inux of gas from a formation having a porepressure greater than the pressure exerted by the drilling uid (gas ow).

A. Drilled Gas. When the hydrostatic pressure exerted by the drilling uid isgreater than the pore pressure of a gas-bearing formation being drilled, there

will be no inux of gas from the formation. Nevertheless, gas from the drilledcuttings will usually mix with the drilling uid 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, resultingin the drilling uid density being reduced considerably upon leaving theannulus. In some cases this reduction in density can be quite extreme butit may 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 uid of proper density is still maintained in mostof the hole. Quite often when the drilled gas reaches the surface, the annular

preventer must be closed and the drilling uid circulated through the openchoke manifold. This prevents the expanding gas from “belching” uidthrough the bell nipple. If “belching” continues, the hydrostatic head will bereduced due to loss of drilling uid from the hole.

B. Trip or Connection Gas. After circulating “bottoms-up” following a tripor connection, a higher level of gas entrained in the drilling uid returns maycause a short duration density reduction or gas unit increase. If the well didnot ow when the pumps were stopped during the trip or connection, it can

be 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.



REV 7: AUG 2009



2 - 30

C. Gas Flow. Inux from a gas zone while drilling is a serious situation.While drilling, the formation pore pressure must exceed the hydrostatic

pressure of the drilling uid plus the circulating friction losses in the annulusfor gas from the formation to ow into the wellbore. Once inux begins,continued circulation without the proper control of surface pressures willinduce additional ow, since the density of the hydrostatic column (annulus)is continually lessened by the ow of formation uid and expansion of gas.

6.24 Liquid-cut Drilling Fluid. When a permeable liquid-bearing formationhaving pore pressure greater than the drilling uid hydrostatic pressure isencountered, uid will feed into the wellbore. Depending upon the pressuredifferential between the formation and the drilling uid, inux may be detected

by: 1) a gain in pit volume, 2) lower density returns, 3) a change in drilling uid

chlorides, 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 notsignicantly affect the drilling uid density.

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

necessary.

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 uid column from the owline to the depth of interest. If ariser fails, leaks, or becomes disconnected, the drilling uid gradient in the riseris lost and replaced by a sea water gradient (approximately 0.445 psi/ft — 8.56Ib/gal) from the point of failure to sea level. The loss of wellbore hydrostaticpressure associated with this situation can sometimes be sufcient to allow thewell to ow. The rst response should be to close the blowout preventers. In somesituations, the drilling uid density may be sufcient to compensate for the lossof hydrostatic 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 trapped

below the closed preventer. If the closed preventer is an annular preventer, it ispossible for this volume of gas to be quite signicant. In order to prevent a rapidunloading of the riser due to trapped gas when the annular preventer is openedor the introduction of a secondary kick due to light density drilling uid in theriser, close the uppermost rams below the choke line and close the diverter. Openthe preventer above the trapped gas and allow this gas to rise toward the surface.

Displace the riser with kill uid and reopen the rams. It may be necessary inextreme cases to close the bottom rams to isolate the hole and ll the riser bycirculating through the kill line. This problem becomes more severe with increasedwater depth and/or preventer size.





REV 7: AUG 2009 2 - 31

2.7 - WORKSHOP 2

SCORE

1. There are a variety of mechanisms that can cause abnormal formation uid pressures. List 4 of the principle causes below.

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

22. 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

P R E S S U R E

( P S I )

VOLUME



REV 7: AUG 2009



2 - 32

SCORE3. M.A.A.S.P. The maximum allowable annular surface pressure should be re-calculated..

a. At the start of each shift b. As soon as possible after a drilling break c. When approaching a suspected transition zone d. When the mud weight has been increased in the system e. 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 inux is in the open-hole section b. As the inux approaches the surface

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

SCORE5. Given the following data:

Depth 10000ft TVD Bit size 8 1/2" Shoe depth 8500ft TVD

Mud weight 12.6 ppg Collars - 600ft. capacity = 0.0077 bbl/ft Metal displacement = 0.03 bbl/ft Drill-pipe 5" capacity = 0.0178 bbl/ft Metal displacement = 0.0075 bbl/ft Casing/pipe annular capacity = 0.0476 bbl/ft Casing capacity = 0.0729 bbl/ft One 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 lling 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 lling 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 was

displaced to prevent a wet trip, what would be the expectedvolume return due to the U-tubing of the heavy mud?

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





REV 7: AUG 2009 2 - 33

6. Prior to tripping out of the hole a trip tank and pump are lined up to keep the hole full as the pipe is removed. The trip tank contains 30

barrels of mud. After pulling 10 stands of pipe the level in the trip tank is 27 barrels. (Use data given in Question 6). Would the safest option be..

a. To continue tripping but ow-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 ow, go back to bottom and circulate. d. Flow-check. If no ow, continue tripping

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

SCORE

7. A well can be induced to ow by swabbing. Swabbing is the reduction 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. What crossover sub is required for the collars? ANSWER........................ 2

9. A xed rig is set in 300ft of sea water. The marine conductor has been set X ft below the sea-bed. The ow line is 65ft above the mean 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 ppg

mud. What is the minimum depth that the conductor has to be set below 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 were encountered at 5000ft and at 8500ft. If the formation pressure gradient at

5000ft is 0.47 psi/ft and at 8500ft it is 0.476 psi/ft. What mud weight is required to give an over-balance or trip margin of 200 psi?

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



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2 - 34


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





REV 7: AUG 2009 2 - 35

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

(mud wt) = 14.6

20 X ———– – 112.6

= 3.17 bbls

6. c.

7. (a) Pulling speed. (b) Mud Properties, viscosity - Gel strength. (c) Prole 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 —— .202 203 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.

( )





REV 6: JAN 2008

SECTION 3Kick Indicators

3.0 Objectives

3.1 Early Warning Signs

3.2 Increase in Drilling Rate of Penetration - Drilling Break

3.3 Increase Torque and Drag

3.4 Decrease in Shale Density

3.5 Increase in Cutting Size and Shape

3.6 Mud Property Changes

3.7 Increase in Trip, Connection and a Background Gas

3.8 Change in the Temperature of the Return Drilling Mud

3.9 Decrease in D-Exponent

3.10 Positive Kick Signs

3.11 Hydrocarbon Kick Behaviour

3.12 Workshop 3




SECTION 3 : KICK INDICATORS

REV 7: AUG 2009 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 ow

situation. 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 pressure between the hydrostatic pressure of the drilling uid 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.





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3.3 INCREASED TORQUE AND DRAG

Increased drag and rotary torque are often noted Figure 3.1when drilling into overpressured shale formations dueto the inability of the underbalanced mud density tohold back physical encroachment of the formation intothe 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 tothe driller that a transition zone is being drilled. Updrag and down drag as well as average torque guresshould 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)





REV 7: AUG 2009 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 situationis developing. The particles are often larger and may be sharp and angular in thetransition zone. Extra ll 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 at, while cuttings from an over pressured shale are often long andsplintery with angular edges. As reduction of hydrostatic differential betweenthe pore 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 uid has entered thewellbore. It could be created by swabbing or it could indicate a well ow 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 occulation because the littlemolecules of mud solids, which are normally dispersed, form little “groups” calledocs. These ocs 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 water

base muds.

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

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

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





REV 7: AUG 2009 3 - 4

3.7 INCREASE IN TRIP, CONNECTION AND A BACKGROUND GAS

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

Gas cut mud does not in itself indicate that the well is owing (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 signicant levelsof gas are detected in the mud.

An essential part of interpreting the level of gas in the mud is the understanding ofthe conditions in which the gas entered the mud in the rst 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 classied 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 a

pressure higher than its bubble point, will expand as it is circulated up the hole,causing gas cutting at the owline. 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.





REV 7: AUG 2009 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 identied, 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 sufcient to balance the formation pressure, the trip gaswill be caused by swabbing and gas diffusion.

Signicant 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 signicantly overbalanced will cause an immediate ow 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 inuenceowline 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 be

inuenced by operating factors. Figure 3.2 shows plots of temperature increasewhile penetrating an abnormal pressure formation.





REV 7: AUG 2009 3 - 6

Figure 3.2 Flowline Temperature Data

FLOWLINE TEMPERATURE = °F

Temperature data from Gulf Coast well

TOP OF ABNORMAL

PRESSURE ZONE

∆T = 0.53 °F 100'

∆T = 4.33 °F 100'

D E P T H 1

0 0 0 f t

5

6

7

8

9

90 100 110 120 130FLOWLINE TEMPERATURE = °F

Temperature data from South Texas well

TOP OF

ABNORMAL

PRESSURE ZONE

∆T = 0.23 °F 100'

∆T = 2.08 °F 100'

D E P T H 1

0 0 0 f t

8

9

10

11

12

110 120 130 140 150 160


Temperature data from Pacific Coast well

TOP OF ABNORMAL

PRESSURE ZONE

∆T = 0.39 °F 100'

∆T = 3.38 °F 100'

D E P T H 1

0 0 0 f t

7

8

9

10

11120 130 140 150 160


Temperature data from South China Sea well

TOP OF

ABNORMAL

PRESSURE ZONE

∆T = 0.70 °F 100'

∆T = 10.0 °F 100'

D E P T H 1

0 0 0 f t

3

4

5

6

7110 120 130 140 150100


Temperature data from North Sea well

TOP OF

ABNORMAL

PRESSURE ZONE

∆T = 0.43 °F 100'

∆T = 5.20 °F 100'

D E P T H 1

0 0 0

f t

3

4

5

80 90 100 110 12070

1

2





REV 7: AUG 2009 3 - 7

3.9 DECREASE IN D-EXPONENT

The D-Exponent will be plotted by the well loggers and maintained current atall times. 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/hr N = rotary speed, rpm W = weight on bit, lbs D = bit size, ins d = 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 with moderatesuccess in predicting abnormal pressure.Trends of Dc-exponent normally increasewith depth, but in transition zones, its valuedecreases to lower than expected values. Mud

logging companies have further variations/models which try to normalise for otherparameters (such as bit wear and rock strength)to varying degrees of success. An illustration ofa Dc plot is attached as gure 3.3.

NormalTrendLine

1.0 1.5 2.0

1 7

1 6

1 5

1 4

1 3

1 2

1 1

1 0

9

13 -

12 -

11 -

10 -

D e p t h

( 1 0 0 0 f t )

SAMPLE PLOT OF Dc EXPONENT vs. DEPTH





REV 7: AUG 2009 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 to produce.A kick is a positive indicator that formation uid is entering the wellbore andSecondary 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 ow rate exceeds the mud ow rate into the well.

Since a rig’s uid system is a closed system, and increase in returns detected bya ow 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 onthe pit level is next to impossible. This is especially true during trips, when mostkicks occur. A more accurate and reliable method is to use any of the several pitlevel measuring instruments with the recorder mounted at the driller’s console

and supported by the mud logger’s monitoring system. This allows a constantwatch on 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 noted because of the core volume of gas being drilled. However, this will occur onlyas the gas nears the surface, and is due to the drilled gas expanding and is

not necessarily an indication that the well is underbalanced. The timing of theincrease in pit volume is important in distinguishing between a true kick and gasexpansion only. The hole will also take the same volume of uid 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 ow.

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 uid 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.





REV 7: AUG 2009 3 - 9

Recognising a Kick While Tripping

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

• If the ow check is positive then the well should be shut in. (Stripping mayhave to be used.)

• If the ow check is negative the drill string should be run back to bottom tocirculate bottoms up (stripping may have to be used here if in OBM, gas is insaturation).

Trip tanks are recognised to be the safest and most reliable method of monitoringmud volumes on trips. It is recommended that a continuous hole ll 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 oating drilling rig makes it more difcult to recognisekick indicators while drilling or tripping. For this reason additional uid volumedetection equipment is installed in the mud pits to compensation for rig motion.It is recommended for oating drilling units that ow checks be performed on thetrip tank with the hole ll 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.





REV 7: AUG 2009 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 its

bubble point. In the same way that gas in a disposable lighter remains in its liquidphase until the pressure is relieved.

In g 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 sufcientmud to put the entire well underbalance. This problem is easier to detect in water

based muds because the original volume of the gas will expand much earlier asthe pressure above the gas is reduced (see g. 3.4b). The problem in OBM's isthat if a kick has entered the wellbore undetected it is impossible to know wherethe top 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 inuxwould 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 then

be circulated through the choke in a safe manner utilising the rst 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 this informationis known, even though the rst procedure may take a little longer, remembersafety is always our main concern.





REV 7: AUG 2009 3 - 11

GAS EXPANSION

(UNCONTROLLED)

(WELL OPEN)

If a gas bubble is allowed to expand without control of any kind it will eventuallyunload the well. With the well unloaded, kick sizes increasing, causing moreunloading. This cycle of inux and unloading has caused the loss of many wells.

Boyles Law is shortened version of equation for gas expansion e.g. P1V

1 = P

2V

2.

It generally states that if the volume of gas doubles, the pressure is reduced by

half in the bubble.

P1 = Hydrostatic Pressure (W/Gas bubble on bottom)

=T.D V

1 = Original Pit Gain

P2 = Hydrostatic press at secondary depth

V2 = Gas volume @ surface or at secondary depth

V2 = P

1V

1 ––– P

2





REV 7: AUG 2009 3 - 12

GAS MIGRATION WHEN GAS IN SOLUTION

(OIL BASE MUD)

Well Control problems can result in blowouts because of the solubility of certain gasesin specic types of mud e.g. Methane dissolves in oil base mud, and H

2S dissolves in

water base mud. This fact makes it more difcult to detect a kick. A large gas inuxentering the wellbore may change the pit level very little if the gas dissolves in the mud.The inux is then circulated up the wellbore in the mud column, until the hydrostatic

pressure on top of the gas decreases to a certain point then the gas ashes or bubble pointreached and gas comes out of solution. Detecting the kick by observing ow-line ormud pits can be very difcult until the kick is very close to surface and expands rapidly.Moreover, gas dispersed in well bore uids does not migrate up the hole therefore ao-check may not show.





REV 7: AUG 2009 3 - 13

GAS MIGRATION

(WELL SHUT IN)

When a well is shut in on a kick that contains gas the gas will percolate or migrateup the hole even if the well is allowed to remain static. Gas migration can causeconfusion during a well control operation, because it can be overlooked. Gas or Gas

bubbles oat or migrate up the hole because they are lighter than mud. When gas bubbles rise they expand or if they are not allowed to expand they cause an increaseon all wellbore pressures and surface pressures. Therefore if a well is shut in for along time, all pressures, wellbore surface etc. will increase causing lost circ. etc., ifnot relieved by allowing gas to expand. So lowering SIDPP to original value throughchoke and observing, keeping SIDPP at original value, will prevent this problem.

All pressures will increase during migration of gas except pressure in actual bubblewhich is usually at formation pressure.





REV 7: AUG 2009 3 - 14

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 Conditions

7000 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'

D e p t h

5,000'

2,500'

D e p t h

Bubble Point1000' - 2000'

100% of Total Expansion

12 bblsGas

Volume

6 bblsGas

Volume





REV 7: AUG 2009 3 - 15

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 TVD Shoe 5500 ft TVD Mud 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 signicantly bigger 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.





REV 7: AUG 2009 3 - 16

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 oil based 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.





REV 7: AUG 2009 3 - 17

(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





REV 7: AUG 2009 3 - 18


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

+

+





REV 6: JAN 2008

SECTION 4Shut-in Procedures

4.0 Objectives

4.1 Introduction to Shut-in Procedures on a Fixed Rig

4.2 Soft Shut-in Procedure While Drilling on a Fixed Rig

4.3 Soft Shut-In Procedure While Tripping on a Fixed Rig

4.4 Hard Shut-In Procedure While Drilling on a Fixed Rig

4.5 Fast Shut-In Procedure While Drilling on a Fixed Rig

4.6 Diverter Procedure While Drilling on a Fixed Rig

4.7 General Introduction for Shut-In Procedure on a Floating Rig

4.8 Soft Shut-In Procedure While Drilling on a Floating Rig

4.9 The Hard Shut-In Procedure on a Floating Rig

4.10 The Fast Shut-In Procedure on a Floating Rig

4.11 Shallow Gas and Diverting Procedure on a Floating Rig

4.12 Surface & Subsea BOP's While Wireline Logging

4.13 Extracts from API RP59

Workshop 4(a) - Surface

Workshop 4(b) - Subsea




SECTION 4 : SHUT-IN PROCEDURES

REV 7: AUG 2009 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 advantages anddisadvantages.

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

4.1 GENERAL INTRODUCTION TO SHUT-IN PROCEDURESON A FIXED RIG

Note: A xed rig is dened as a drilling rig equipped with a surface BOP.

Shut-in procedure should be agreed by contractor and operating company and postedon rig oor before drilling the well begins.

When any positive indication of a kick is observed such as a sudden increase in owor an increase in pit level, then the well should be shut in immediately without doing aow check. If the increase in ow or pit gain is hard to detect then a ow check can bedone to conrm the well is owing.

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. This will bediscussed at the end of this section.

The procedures which follow are generalised suggestions and not necessarily applicableto any specic rig.





REV 7: AUG 2009 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 beowing, stop rotating the drill string, raise the drill string with pumps onuntil tool joint is above the drill oor.

2. Stop pumps and check for ow, 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 ows during a ow 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.





REV 7: AUG 2009 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 owing,stop rotating the drill string, raise the drill string with pumps on until tool

joint is above the drill oor.


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 above theannular or rams. This will assist in double checking to see if they are leaking. Doublecheck that the well is lined up through the choke manifold prior to circulating kick out.





REV 7: AUG 2009 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 maybeowing, stop rotating the drill string, raise the drill string with pumps onuntil tool joint is above the drill oor.



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 mudin the annulus and cause the well to ow, 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 ow.

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 rst:-

a) Open an alternative ow 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.





REV 7: AUG 2009 4 - 5

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

inadvisable to attempt a ow 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 oor.

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 oor 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 oat should be run. This will prevent gasentering drill string if a kick is taken while making a connection. It will

also stop backow through the drill string on connections.

4.7 GENERAL INTRODUCTION FOR SHUT-IN PROCEDURE ON A FLOATING RIG

Note: A oating rig is dened as a rig equipped with subsea BOP’s.

Shut-in procedure should be agreed by contractor and operating company and postedon rig oor before drilling the well begins.

When any positive indication of a kick is observed such as a sudden increase in ow orincrease in pit level, then the well should be shut in immediately without doing a owcheck. If the increase in ow or pit gain is hard to detect then ow check can be done toconrm the well is owing.

It maybe difcult to obtain an accurate ow check by observing ow line on rig oor orow line at shaker due to rig movement.





REV 7: AUG 2009 4 - 6

To obtain an accurate ow 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 ll trip tank with mud and perform a ow check.

If surface hole is being drilled and the conductor or surface casing is not set in a

competent formation and a shallow gas kick is taken, then the kick should be divertedand not shut in. Diverting procedure will be discussed at the end of this section.

The procedure which follow are generalised suggestions and not necessary applicableto any specic 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 owing,

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 valve

downstream 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.





REV 7: AUG 2009 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 rams

but never lower pipe rams. This is because if a kill or choke line washes out beneath 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 owing,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 drill

string 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.





REV 7: AUG 2009 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 owing,stop rotating, raise drill string with pumps running and space out for hangoff rams.

2. Stop pump and check for ow, 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 ll while tripping if a riser has been run.





REV 7: AUG 2009 4 - 9

3. The following are the recommended procedures for drilling 36" and 24" holefrom a oating 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 oat 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 ow 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 inux 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.





REV 7: AUG 2009 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 should

be used. The shear rams should be considered as a last resort and used only ifthe annular(s) fail to secure the well.





REV 7: AUG 2009 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 times otherthan during a well control operation. The choke line valves are aligned such that a owpath is open through the choking system, with the exception of one choke line valvelocated near the blowout preventer. When the soft close-in procedure is selected forclosing in a well the: 1) choke line valve is opened, 2) blowout preventer is closed, and3) choke is closed. This procedure allows the choke to be closed in such a manner topermit sensitive control and monitoring of casing pressure buildup during closure. Thisis especially important if formation fracturing and broaching to the surface is likely to

occur if the well is closed in without 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 all timesother than during a well control operation. The choke line valves are aligned such thata ow path is open through the choking system with the exception of the choke(s) itselfand one choke line valve located near the blowout preventer stack. When the hardclose-in procedure is selected for closing in a well, the blowout preventer is closed. Ifthe casing pressure cannot be measured at the wellhead, the choke line valve is openedwith the choke or adjacent high pressure valve remaining closed so that pressurecan be measured at the choke manifold. This procedure allows the well to be closed

in the shortest possible time, thereby minimising the amount of additional inux ofkicking uid to enter the wellbore. Use of the hard close-in procedure is limited towell conditions in which the maximum allowable casing pressure is greater than theanticipated initial close in pressure and a well fracture would not be expected to broachto the surface on initial closure.

3.8 Soft Close-in Versus Hard Close-in Procedure. The soft close-in procedure providesa means of monitoring casing pressure and a more sensitive control of casing pressure

buildup during closure than will be experienced using the hard close-in procedure.If the initial closed-in casing pressure is likely to exceed the maximum allowable

casing pressure, the soft close-in procedure permits initiation of a low choke pressureprocedure or other alternate procedures before maximum allowable casing pressureis reached. In this situation, the soft close-in procedure has a distinct advantage overthe hard close-in procedure. The major disadvantage of the soft close-in procedureis that the additional time involved in opening the choke line valve and closing thechoke will allow additional inux into the wellbore. This procedure will result in alarger kick volume and potentially higher casing pressure than obtained if the hardclose-in procedure is used while circulating out the kick. The hard close-in procedure issomewhat less complicated, can be performed by one man working on the rig oor, andis more likely to be performed without inadvertent delays in closure than the soft close-

in procedure.





REV 7: AUG 2009 4 - 12

500 PSI

640 PSIDRILL

PIPE

CASING

10 LB/GAL

DRILLING FLUID

10 LB/GAL

DRILLING FLUID

20 BBL GAS ENTRY

10,000 FT

BOTTOM-HOLE PRESSURE

= 5700 PSI

FORMATION PRESSURE

= 5700 PSI

WELL CLOSED IN ON A KICK

3.9 Stabilised Pressures. When a kick is detected, the well should be closed in asquickly as possible to minimise kick inux volume. Figure 3.3 shows a schematic

diagram of a well shut in on a kick. In this well, a 20-barrel gas inux occurs whendrilling at 10,000 feet with a 10.0 Lb/gal drilling uid. The stabilised closed-in pressuresare 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 the variouspressures interact, it is necessary to isolate and identify each one. The drill pipegauge pressure plus the hydrostatic pressure of the drilling uid equals the formationpressure. The same pressure balance can be made for the annulus, i.e., casing gaugepressure plus the hydrostatic pressure of the annulus drilling uid plus the hydrostaticpressure of the inux equals the formation pressure.

Figure 3.5 illustrates an example of a 10,000foot closed-in well with 10.0 Lb/gal drillinguid and a small volume of gas at bottom.When the gas rises to 5000 feet withoutexpansion or temperature change, the

bottom-hole pressure rises to 7800 psi,which is equivalent to a 15.0 Lb/gal drillinguid column. When the gas reachesthe surface, bottom-hole pressure is10,400 psi, which is equivalent

to a 20.0 Lb/gal drilling uidcolumn. At 5000 feet the boreholepressure is equivalent to a30.0 Lb/gal drilling uidcolumn to that depth. Suchexcessive pressure should

be avoided whether gas risesthrough a static drilling uidcolumn or is circulated out byallowing the gas to expand as

it 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 must

be overcome by increasedsurface pressure on the casing:in turn this increased pressureresults in a higher bottom-hole pressure.





REV 7: AUG 2009 4 - 13

3.10 Closed-in Drill Pipe Pressure. Formation pressure near the wellbore is reducedduring ow. When the well is closed in, the borehole pressure will rise until equal toformation pressure. As the drill pipe (and annulus) is in communication, the drill pipepressure will also rise and stabilize. The drill pipe pressure at this time indicates theamount to increase the drilling uid density. If the well is not circulated, the gas willslowly rise and increase both wellbore and drill pipe pressures. Drill pipe pressures

read after the initial stabilized reading will indicate excessive drilling uid densityincrease. To avoid excess wellbore pressures, the choke should be used to bleeddrilling uid from the casing and maintain the initial shut-in drill pipe pressure. Theseconditions are illustrated in Figure 3.6. To determine the closed-in drill pipe pressurewhen a back-pressure valve is in the drill string, pressure should be increased slowlyusing the smallest pump available to determine the pressure at which the back-pressurevalve opens. If casing pressure is seen to rise while pumping on the drill pipe, pumpingshould be stopped and the increase in casing pressure subtracted from drill pipepressure.

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 FLUID

COLUMN PRESSURE

DRILLING FLUID

COLUMN PRESSURE

GAS

HYDROSTATIC

PRESSURE

FORMATION

PRESSURE

FIG 3.5CLOSED-IN WELLBORE PRESSURE

WITH TIME

DRILLING

FLUID

5200 PSS

GAS

5200

PSS

GAS

5200

PSS

GAS

5200

PSS

5200 PSI2600 PSI0 PSI

DRILLING

FLUID

5200 PSS

SURFACE

PRESSURE

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

FIG 3.6CLOSED-IN DRILL PIPE PRESSURE

DESIRED VALUE

INCREASE DUE TO RISE OF GAS

TIME

DRILL PIPE

PRESSURE PSI





REV 7: AUG 2009 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 other casingstrings. A leak-off test is performed by pumping drilling uid into thewellbore at a slow rate (typically one-half barrel per minute), with blowout preventersclosed and carefully plotting the resulting pressure versus the total volume pumped.The pressure at which the plotted curve begins to atten. i.e., when the pressureincreases a smaller amount for a volume pumped, is the surface leak-off pressure. Thepump should be stopped immediately. This pressure plus the hydrostatic pressure ofthe drilling uid is the formation fracture pressure.

Formation fracture pressure (psi) =

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

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

Fracture drilling uid density (Ib/gal) =

Leak-off pressureDrilling uid 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 casing thatis full of drilling uid without fracturing the formation. Fracture pressure is calculatedas follows:

Fracture pressure (psi) =

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

3.12 Formation Competency Test. A formation competency test is made to determineif a wellbore will support drilling uid of a higher density which may be required atsome future time during the well drilling and completion operations. The formationcompetency test is performed by pumping drilling uid into the wellbore at a slow rate(typically one-half barrel per minute) with blowout preventers closed. Pumping intothe wellbore should be continued until reaching the predetermined test pressure ascalculated below:

Test pressure (psi) =

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





REV 7: AUG 2009 4 - 15

CREW DRILLS

The prociency with which drilling crews react to well control situations and followcorrect control procedures can be enhanced by repetitive drills. When the desiredprociency is attained, periodic drills should be continued to maintain performance.The following drills, frequency, and prociency levels are considered desirable:

A. Pit Drill.

Without prior warning and during a routine operation, the rig supervisor shouldsimulate a gain in pit drilling uid volume by raising a oat sufciently to causean alarm to be activated. If automatic equipment is not available, the drills may besignalled by word of mouth. This, of course, diminishes the surprise element, but the

training is still effective. The drilling crew should immediately initiate one of the fourprocedures discussed in Paragraph B depending on the operation at the time of thedrill. A pit drill is terminated when the crew has completed the steps up to, but notincluding, closing the blowout preventers (Crews must be advised that this is a pit drill,otherwise they should proceed with the complete blowout preventer drill). The supervisorinitiating the drill should record response time. Crew response time should be oneminute or less.

B. Blowout Preventer Drill.

This drill includes all steps of the pit drill (refer to Paragraph A) but is continuedthrough all the steps of closing in the well as outlined below. This drill should berepeated on a daily basis until each crew can close in the well within a span of twominutes. Thereafter the drill should be repeated weekly to maintain prociency.

1. On-bottom Drill.

a. Signal given.

b. Stop rotary.

c. Raise kelly tool joint above the rotary, while sounding the alarm.

d. Stop pump.

e. Check for well ow.

The on-bottom drill should be carried only to the point of driller recognition,signalled by raising the kelly and pump shutdown. This is to avoid thedanger of stuck pipe.





REV 7: AUG 2009 4 - 16

2. Tripping Drill Pipe Drill

a. Signal given.

b. Position the upper tool job above rotary table and set slips.

c. Stab full-open valve on drill pipe.

d. Close drill pipe safety valve.

e. Close blowout preventer.

Drills while tripping drill pipe should be performed after the bit is up in the casing. A

full opening safety valve for each size and type connection in the string must be openand on the oor ready for use. Safety valves must be clearly identied as to size andconnection to avoid confusion and lost time when stabbing.

3. Drill with Drill Collars in the Preventer.

a. Signal given

b. Position the upper drill collar in rotary table and set slips.

c. Stab full-open safety valve made up on one joint of drill pipe with change-oversub onto collars.

NOTE: Preparation for this operation must be made in advance. Prior to reachingthe drill collars when pulling out of the hole, a drill pipe to drill collar change-oversub must be placed on a single joint of drill pipe. The full open safety valve is thenmade on the top of the joint of drill pipe.

d. Lower collars with joint of drill pipe into the hole.

e. Close the drill pipe safety valve.

f. Close the pipe rams above drill pipe tool joint.

Flows that occur with drill collars in the preventers will generally be quite rapidsince they are usually the result of expansion of a gas bubble that is quite close tothe surface. The joint of drill pipe picked up with the elevators will usually be easierto stab and make up than a safety valve alone. Under actual kick conditions (otherthan drill) if only one stand of drill collars remained in the hole it would probably befaster to simply pull that last stand and close the blind rams.





REV 7: AUG 2009 4 - 17

4. Out of the Hole Drill.

a. Signal given.

b. Close blind rams.

C. Stripping Drill.

The performance of a stripping drill by at least one crew on each well should beconsidered. This drill can be conveniently performed after casing is set and beforedrilling out cement. With drill pipe in the hole a blowout preventer should be closedand the desired pressure trapped. Each crew member should be assigned a specic

position. Following an acceptable procedure, the crew should strip sufcient pipeinto the hole to establish the workability of the equipment and to allow each crewmember to learn to perform assignments. In addition to establishing equipmentreliability, this will permit the training of at least one crew on each well. Over aperiod of time, all crews should become procient in stripping operations. Strippingdrills are not recommended for operations involving subsea blowout preventerstacks.

D. Choke Drill.

Choke drills should be performed before drilling out surface casing and eachsubsequent casing string. With pressure trapped below a closed preventer, the chokeshould be used to control casing pressure while pumping down the drill pipe at aprescribed rate. This drill will establish equipment performance and allow the crewto gain prociency in choke operation. It is desirable to discharge into a trip tank toaccurately monitor ow rates for correlation with choke opening, pump rates, andpressure drops in the circulating system and across the choke. This is particularlyimportant for subsea blowout preventer stacks in deep water, which may havesignicant circulating pressure losses in the choke lines.

E. Hang-off Drill (Subsea Blowout Preventers Only)

Following prescribed procedures, the crew should place the drill string in position forhang-off. One hang-off should be made before drilling out of surface pipe to ensurethat all necessary equipment is on hand and in working condition. Actual hang-offwill not normally be performed on subsequent drills. This drill can be convenientlyperformed in conjunction with the pit drill.





REV 7: AUG 2009 4 - 18

TRIP TANKS

A trip tank is a low-volume, calibrated tank which can be isolated from theremainder of the surface drilling uid system and used to accurately monitor theamount of uid going into or coming from the well. A trip tank may be of anyshape provided that it is calibrated accurately and a means is provided for readingthe volume contained in the tank at any liquid level. The readout may be direct orremote, preferably both. The size of the tank and readout arrangement should besuch that volume changes in the order of one-half barrel can be easily detected. Tankscontaining two compartments with monitoring arrangements in each compartmentare preferred as this facilitates removing or adding drilling uid without interruptingrig operations. The primary use of the trip tank is to measure the amount of drillinguid required to ll the hole while pulling pipe to determine if the drilling uid

volume matches pipe displacement. Other uses of the trip tank include measuringdrilling uid or water volume into the annulus when returns are lost, monitoring thehole while logging or following cement job, calibrating drilling uid pumps, etc. Thetrip tank is also used to measure the volume of drilling uid bled from or pumpedinto the well as pipe is stripped into or out of the well.

TRIP BOOK

A tally should be maintained showing the volume of drilling uid required to ll thehole after pulling the specied number of stands along with the cumulative volume.

It is important to keep this record in a "trip book" so that each trip may be comparedwith previous trips for anomalous behaviour, rather than to rely only on comparisonwith theoretical displacement volumes. A similar record is made of drilling uidreturns while running pipe in the hole.





REV 7: AUG 2009 4 - 19

4.14 - WORKSHOP 4(a) - Surface

DRILLSPOOL

ANNULARPREVENTER

CASINGHEAD

SHEAR RAM

HCRVALVE

HCRVALVE

5" PIPE RAM

5" PIPE RAM

4321

65

P

P

CHOKELINE

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 to

suit 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 Closed b. Manual adjustable choke Opened Closed

c. Right hand remote choke Opened Closed





REV 7: AUG 2009 4 - 20

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

a. Left hand remote choke Opened Closed b. Manual adjustable choke Opened Closed c. Right hand remote choke Opened Closed

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 fows while

Tripping , 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 taken

when shutting the well in.

1. Pick up and space out2. Stop Rotating

3. Set Slips 4. Open HCR valve 5. Close HCR valve

6. Install Safety Valve(FOSV) 7. Open Safety Valve 8. Close Safety Valve 9. Open Ram Preventer 10. Close Ram Preventer 11. Open Annular Preventer 12. Close Annular Preventer 13. Stop pumping 14. Install Inside B.O.P (Grey Valve) 15. Open Choke

16. Close Choke 17. 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:





REV 7: AUG 2009 4 - 21

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. If a well ows while Tripping, select the correct sequence of actions

which should be taken if the Fast shut-in is to be used.

Answer:

9. Secondary well control could be dened as initially;

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

b. Controlling formation uids with the pressure of the mud

column and the well closed in.

10. Prior to Stripping back to bottom, 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 ow line. c. Open the vent line, close the ow 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.





REV 7: AUG 2009 4 - 22

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- opened

Manual Adjustable choke- closed Right hand remote choke- closed

3. Left hand remote choke- closed

Manual Adjustable choke- closed Right 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





REV 7: AUG 2009 4 - 23

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 topof derrick

10” Vent

36” diameterseparator

To shaleshaker

Mud-gasseparator

From C&Kmanifold4” pipe

To port - Blow-down lineflare line

Blow-down lineTo starboardflare line

tomud-gasseparator

L/handremotechoke

R/handremotechoke

Manualchoke

To cementunit mudpumps

To shaleshaker

Kill

line

ChokelineDECK LEVEL

SEA LEVEL

SEA FLOORH-4

Connector

5”Rams

VariableRams

5”Rams

ShearRams

AnnularPreventer

H-4Connector

Flex joint

AnnularPreventer

Kill

line

Choke

line

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.





REV 7: AUG 2009 4 - 24

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 fows 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 Rotating

3. Set Slips 4. Open Fail-safe valves 5. Close Fail-safe valves 6. Close Ram preventer 7. Open Ram preventer 8. Close Upper Annular 9. Close Lower Annular 10. Open Annular 11. Open Choke 12. Close Choke 13. Stop pumping 14. Set compensator to mid stroke 15. Hang Off 16. Record Data





REV 7: AUG 2009 4 - 25

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 oating 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 oor. 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 tensioners d. 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 hole c. Restrict penetration rate d. Close the well in at the rst sign of ow e. 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 ow or pit changes. b. It is easier to control bottom hole pressure c. It is easier to move the rig off location in an emergency d. It is easier to close the well in.





REV 7: AUG 2009 4 - 26

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- closed

Manual Adjustable choke- closed Right hand remote choke- opened

3. Left hand remote choke- closed Manual Adjustable choke- closed Right 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.





REV 6: JAN 2008

SECTION 5Methods Of Well Control

5.0 Objectives

5.1 Kill Methods General

5.2 Constant Bottom Hole Pressure Kill Methods

5.3 The Driller's Method

5.4 The Wait and Weight Method

5.5 Volumetric Well Control

5.6 Volumetric Stripping

5.7 Edited Extract From API RP53

5.8 Removal of Gas Trapped in BOP's

5.9 Kick Detection and Well Control Problems on Deviated and

Horizontal Wells

5.10 Kick Tolerance

5.11 Workshop 5




SECTION 5 : METHODS OF WELL CONTROL

REV 7: AUG 2009 5 - 1

METHODS OF WELL CONTROL

5.0 OBJECTIVES

To coer the methods of well control for ed rigs, to coer the specialconsiderations for subsea rigs and to look at step down graphs for deiated andhorizontal wells.

5.1 KILL METHODS GENERAL

The objectie of the arious kill methods is to circulate out any inading uid and

circulate a satisfactory weight of kill mud into the well without allowing furtheruid 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,a kill mud which just proides hydrostatic balance for formation pressure iscirculated.

This allows approimately constant bottom hole pressure which is slightly greater

than 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 proide a safety or trip margin.





REV 7: AUG 2009 5 - 2

BALANCE OF PRESSURES

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

Proiding 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 achiee 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 Casing

Pressure of Mud in Annulus of Inux Pressure

The miture of mud and formation uid in the annulus makes it impossibleto determine formation pressure using the casing information. The drill pipe,howeer, 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 oer a length equal to the true ertical depth of the hole. This can beepressed as a gradient, and conerted 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 proide a hydrostatic pressure equal to theamount of the drill pipe shut-in pressure oer the ertical 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)

[ ]





REV 7: AUG 2009 5 - 3

Figure 5.1

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 PIPE

PRESSURECASING

PRESSURE

MUD HYDROSTATIC

PRESSURE IN THE

ANNULUS

TOTAL PRESSURE

ACTING DOWN

(8613 + 1220 + 67 =9900 psi)

MUD HYDROSTATIC

PRESSURE IN THE

DRILL PIPE

TOTAL PRESSURE

ACTING DOWN

(9100 + 800 = 9900 psi)

DRILL PIPE ANNULUS





REV 7: AUG 2009 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 ery 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 rst, thekick uid 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 achiees both of these operations simultaneously. Killmud is prepared before starting the kill, and the kick uid is circulated out whilethis mud is circulated into the well.

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





REV 7: AUG 2009 5 - 5

5.3 THE DRILLER'S METHOD

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

Two complete circulations are thus required, as a minimum, for this method. Sinceit deals separately with the remoal 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. Howeer, this results, in the well being circulated underpressure for a relatiely long time, possibly the longest of the three methods, withan increased possibility of choke problems. Also, the annular pressures producedduring the rst circulation are higher than produced with any other method.

CAUTION: because very high annular pressure may arise when killing a gaskick with this method, care should be taken. Annular pressure will be ata maximum immediately before gas arrives at surface, and casing burst

pressure limitations may be critical.

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

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

To summarise:

FIRST CIRCULATION: Pump the kick out of the well, using eisting 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• Maimum Well Under Pressure Time• Longest ‘On-choke’ Time





REV 7: AUG 2009 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 rst circulation of the well.

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

or: ICP = PSCR

+ SIDPP

3. Open the choke about one quarter, start the pump and break circulation; then bring 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 to maintainthe INITIAL CIRCULATING PRESSURE on the drill pipe pressure gauge.

6. The INITIAL CIRCULATING PRESSURE is held constant on the drill pipepressure gauge by adjusting the choke throughout the whole of the rstcirculation, until all of the kick uid 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 mi 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 lowest possible 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 under

pressure - in particular the choke.





REV 7: AUG 2009 5 - 7

Figure 5.2

E B

F . C . P .

I N I T I A L

C I R C U L A T I N G

P R E S S U R E

C A S I N G

P R E S S U R E

R I S I N G

C A S I N G

P R E S S U R E

B E I N G

R E D U C E D

D R I L L E R ’ S

M E T H O D


K I C K O U T

D R I L L E R ’ S

M E T H O D

K I L L M U D

C O M I N G U P

A N N U L U S

E x p a n d i n g g a s i s p u s h i n g m o r e

m u d o u t o f a n n u l u s , s o C a s i n g

P r e s s u r e r i s i n g t o c o m p e n s a t e a n d

K E E P C O N S T A N T B O T T O M

H O L E P R E S S U R E

C h o k e b e i n g s t e a d i l y

o p e n e d t o k e e p F . C . P . o n

d r i l l p i p e ,

h e n c e C a s i n g

P r e s s u r e r e d u c i n g

G A S

E X P A N D I N G

A D S

I D P P

S I C P

C A S I N G

P R E S S U R E

S T E A D Y

D R I L L P I P E

P R E S S U R E

D R O P P I N G

D R I L L E R ’ S

M E T H O D

K I C K S H U T I N

G a s K i c k

B e f o r e s t a r t

o f f i r s t

c i r c u l a t i o n

D R I L L E R ’ S

M E T H O D

C I R C U L A T I N

G

K I L L M U D I N

D r i l l p i p e p r e s s u r e

d r o p p i n g ( f r o m

I . C . P

t o F . C . P . a s

K i l l M u d

g o e s t o b i t )

F C

S I D P P

0 p s i

0 p s i

C A S I N G

P R E S S U R E

= S I D P P

D R I L L E R ’ S

M E T H O D

F I R S T

C I R C U L A T I O N

C O M P L E T E

W E L L K I L L E D

S h u t i n - k i l l

m u d a l l r o u n d

w e l l

W e l l c l o s e d i n

O r i g i n a l w e i g h t m u d a l l

a r o u n d w e l l

W e l l c l e a n u p m a y t a k e

s o m e t i m e - s m a l l

r e s i d u a l p r e s s u r e o n t h e

c a s i n g i s t h u s l i k e l y

G A S

K I L L

W E I G H T

M U D

K I L L

M U D

O R I G I N A L

W E I G H T

M U D





REV 7: AUG 2009 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 lled with heay 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 inux was gas and all the gas was not removed in rst circulation,the rst 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 withthe heaier mud. In practice, if all the kick was properly remoed in the rstcirculation, 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 rate

pressure, increased slightly for the etra mud weight.

Final Circulating= Slow Circulating

xKill 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 nal circulating pressure whenthe kill mud reaches the bit. Thereafter the drill pipe pressure is held at the nalcirculating pressure by controlled opening of the choke, as the kill mud moes upthe annulus.

A graph showing how drill pipe pressure drops from the initial to the nalcirculating 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 moed.





REV 7: AUG 2009 5 - 9

Figure 5.3

Because of the possibility that the annulus may not be circulated completely clean,during the rst circulation, it may be preferable to work out how the drill pipepressure should ary 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 ariations in pressure during the well circulation.

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 17000

100

200

300

400500

600

700

800

900

1000

1100

1200

1300

1400

1500

P R E S S U R E

STROKES

FCP

ICP





REV 7: AUG 2009 5 - 10

Figure 5.4

FIRST CIRCULATION

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

Water Influx

START FINISH

G a s I n f l u

x

Annular

Pressure

Time or Pump Strokes

Annular Pressure

Pressure Constant

START FINISHCirculating Pressure

Drill Pipe

Closed in

Pressure

Circulating

Pressure at

Reduced Rate






REV 7: AUG 2009 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 Pressure

While Killing by Driller's Method

START

AnnularPressure


Annular Pressure

Circulating Pressure

Drill Pipe

Closed in

Pressure

Circulating

Pressure at

Reduced Rate






REV 7: AUG 2009 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 alue 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 orice 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 however

preferable to maintain pump rate constant as much as possible. Anydecision to change pump rate should be taken early.





REV 7: AUG 2009 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 pressureis used to calculate the kill mud weight. Mud of the required weight is madeup in the 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 resere equialent 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 pipe balances formation pressure. For the remainder of the circulation, as the inu ispumped to the surface, followed by drill pipe contents and the kill mud, the drillpipe pressure is held at the nal 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 difcult 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





REV 7: AUG 2009 5 - 14

At the start of the circulation, with kill mud:

Initial Circulating Slow Circulating Rate Shut in Drill pipe

Pressure = 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 aries as kill mud is pumped down to the bit.(See Figure 5.6)

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

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

While the Driller brings the pump up to the Kill Rate, the choke operator worksthe choke 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 allowedto drop steadily from the Initial Circulating Pressure to the Final CirculatingPressure, 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 moes down. Little or nochoke adjustment is required.

Only in cases of diffused gas kicks with gas far up the annulus will signicantchoke 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 constantas long as pump rate is held constant at the selected alue. If, for any reason,

the pump rate is felt to be wrong, it can be changed using the same proceduredescribed preiously. Howeer, pump rate changes should be aoided, 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 reised circulatingpressure is read from the drill pipe gauge. If a gas inu is ery near to thesurface, adjusting pump rate by holding a steady casing pressure may signicantlyincrease the bottom hole pressure. This is due to the rapid epansion of gas nearthe surface. Alterations in pump rate are to be made early on!

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





REV 7: AUG 2009 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

AnnularPressure


Annular Pressure

Circulating Pressure

Drill PipeClosed inPressure

CirculatingPressure at

Reduced Rate


FINISH

PH1 PH2 PH3 PH4





REV 7: AUG 2009 5 - 16

Figure 5.7

A D

S I C P

C A S I N G

P R E S S U R E

A T

M A X I M U M

W A I T & W E

I G H T

S T A R T O F K

I C K

G a s K i c k

J u s t s t a r t i n g k

i l l m u d

d o w n d r i l l p i p e

W A I T & W

E I G H T

G A S A T

S U R F A C E

C a s i n g P r e s s

u r e

a t i t s m a x i m u

m

v a l u e

I . C . P .

D R I L L P I P E

P R E S S U R E

D R O P P I N G

E B

F . C . P .

C A S I N G

P R E S S

U R E

V .

S L O

W L Y

R I S I N G

S M A

L L

C A S I N G

P R E S S

U R E

W A I T & W E I G H T


K I L L M U D D O W N

W A I T & W E I G H T

D R I L L P I P E

C O N T E N T S

A T S U R F A C E

D r i l l p i p e p r e s s u r e d r o p p i n g

f r o m I n i t i a l C i r c u l a t i n g

P r e s s u r e t o F i n a l C i r c u l a t i n g

P r e s s u r e C a s i n g P r e s s u r e

r i s i n g v e r y s l o w l y ( l i t t l e g a s

e x p a n s i o n )

S m a l l C a s i n g P r e s s u r e s t i l l

h e l d - a s l i g h t m u d f r o m

d r i l l p i p e c i r c u l a t e d o u t

F C

F . C . P .

0

W A I T &

W E I G H T

K I L L M U D

A T B I T

W A I T &

W E I G H T

W E L L K I L L E D

D r i l l p i p e P r e s s u r e

n o w s t e a d y a t

F i n a l C i r c u l a t i n g

P r e s s u r e

W e l l ‘ c l e a n u p ’ t a k e s

s o m e t i m e , a s s m a l l

r e s i d u a l C a s i n g

P r e s s u r e i s l i k e l y

C A S I N G

P R E S S U R E

V .

S L O W L Y

R I S I N G

F

. C . P .

F . C . P .

K i l l M u d

W e i g h t

K i l l M u d

W e i g h t

K i l l M u d

W e i g h t





REV 7: AUG 2009 5 - 17

5.5 VOLUMETRIC WELL CONTROL

The olumetric method is mostly used in workoer and production operations. Itis a means of allowing the gas to migrate to surface under control. The gas needsto migrate at oer (appro.) 1000' per hour. To allow the bubble to epand thecasing gauge is held constant for a gien olume of mud bled off. This operationis repeated, holding an eer 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 only

casing 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 uniersal olumetricwell control equation below:-

P.choke = Pann + Ps + Pw

Pa = Initial SICP

Ps = Built in safety margin prior to olumetric well controlcommencing.

Recommended safety margin = 100 - 200 psi

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

0

700

130 bbls

WELL DATA

==

=

=

=

=

=

12000'8000'

0.0459 bbl/ft

0.0291 bbl/ft

12.0 ppg

0.12 psi/ft

700 psi

TVDTVD Shoe

DP/csg/OH cap

DC/OH cap

Mud wt

Influx Grad

Casing Press

Active pit volume before kick = 120 bbls

Active pit volume after kick = 130 bbls





REV 7: AUG 2009 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.

Eample:-

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

Pressure increase/hr

Percolating 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 theinux 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 olume 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 gasto migrate 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 Cap A. Around drill collars mud volume to bleed = Pw x ––––––––––– Mud grad

0.0291

= 50 X –––––– 0.624

= 2.3 bbls





REV 7: AUG 2009 5 - 19

B. Around Drill Pipe

DP/OH Casg Cap

Mud 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 untilcasing pressure read 850 psi

First build upwhen well wasshut in

Bleed off 2.3 bbl keepingchoke pressure ± 20 psieither side of 850 psiinflux around DC's

Bleed off 3.6 bbls keeping choke

pressure±

20 psi either side of 900psi Influx around D.pipe

Bleed off 3.6 bbls

Bleed off 3.6 bbls

Time





REV 7: AUG 2009 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 simplied. Four bleeds are shown.Depending upon the size of the olume bled and the well depth more or less

bleeds may be required than illustrated here.

Important Points

1. Bleed mud at constant choke pressure using the manual choke. Ensure

crew trained not to be tempted to bleed off faster than this as moreinu could be induced into the well. A major problem with the methodcould be boredom, careful records must be kept of pressureand olumes.

2. Gas may not coneniently 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 oerbalance and each situation will haeto 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.





REV 7: AUG 2009 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 equalise before opening kill line stack ales.

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

Eample:-

Pumped volume Pressure 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 replacedwith mud and referring to the drawing in gure 5.11, this will takeapproimately 22.1 bbls.

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





REV 7: AUG 2009 5 - 22

Figure 5.12 Graphical example of lubricating mud into annulus

1. Original Pit volume = 120 bbls

Pit olume after kick and olumetric 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 olumetric 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

C a s i n g P

r e s s u r e

Pit Volume

P u m p 3. 6 b

b l s

After pumping mud into annulus, waitingperiod allows mud to fall then bleed gas untilcasing pressure reduces by 50 psi beloworiginal pressure.





REV 7: AUG 2009 5 - 23

5.6 VOLUMTRIC STRIPPING

5.6.1 Example of Volumetric Stripping

The options aailable if an inu is swabbed or if the well starts owingduring a trip are as follows:-

a) If well is not owing, trip back to bottom keeping a careful checkon returns. Then circulate inu out of hole.

b) If well is owing and is shut in and the gas is percolating withthe bit a long way off bottom and tight hole conditions hae beeneperienced, then consider doing a olumetric bleed.

c) If well is owing and is shut in and the gas is percolating withthe bit a long way off bottom and tight hole conditions hae beeneperienced, then consider bullheading.

d) If well is owing and is shut in and the gas is percolating and noproblems are anticipated in stripping back to bottom, then considerolumetric stripping to get bit to bottom. Circulate inu out usingrst circulation 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.





REV 7: AUG 2009 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/ft DP Disp = 0.0075 bbl/ft

DP/OH cap = 0.0459 bbl/ft Mud wt = 12.0 ppg Pit Gain = 15.0 bbls Inu Grad = 0.12 psi/ft

Bit depth at original shut in = 11,000'

Figure 5.14

Shut in pressures and inu size with bit on bottom.

108

108

15 bbls

0

560

24.5 bbls





REV 7: AUG 2009 5 - 25

5.6.3 Shut in procedure for a swabbed kick while tripping

Fast shut-in

1. Stab safety ale (kelly cock).

2. Close safety ale.

3. Open HCR fail safe ales.

4. Close annular.

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

6. Stab inside BOP (Gray ale).

7. Open safety ale.

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 oat 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 + P

w

Pa = Initial SICP

Ps = 100 psi + *Increase in casing pressure with inux around drill collars

* ∆P.csg = Mud grad - Inux grad x (H2 - H

1)

Pw

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

15 15H

1 = –––– = 214' H

2 = ––––– = 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





REV 7: AUG 2009 5 - 26

Theoretical bleed off in bbl/ft while stripping = DP displacement + DPcap

= 0.01776 + 0.0075 = 0.02526 bbl/ft

Ann CapExcess bleed off for each 50 psi working margin = P

w x( ––––––––––)

Mud grad

0.0292 = 50 (––––––– ) 0.0624

= 2.3 bbls

Note: If the gas is not migrating while stripping, only theoretical bleed off will

be 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 working

pressure. Refer to Volumetric Stripping chart (Fig. 5.15).

Figure 5.15

After 50' pressure at 410 psi

After 15' stripped

pressure at 460 psi

After 15' stripped

pressure at 510 psi

After 15' stripped

pressure at 560 psi

Step 1

Step 2

Step 3

Step 4

ACCUMULATIVE VOLUMES

Theoretical

vol. bleed off

Actual vol.

bleed off

Excess vol.

bleed off

Average length= 94'

No. Stands

P° 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





REV 7: AUG 2009 5 - 27

Step 1 Allow casing pressure to increase to calculated Pchoke pressurewhile stripping rst stand, then hold casing pressure constant by

bleed off at choke.

Note: The casing pressure may not rise straight away because the gas has tobe compressed. It may take 2 - 3 stands before a pressure build up isseen.

Step 2, 3 & 4 With theoretical bleed already calculated, record actual bleed, whenthe difference between the actual and theoretical bleed is 2.3

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 inu has epanded by9.45 bbls and if it was possible to read drill pipe pressure it would read zerowith drill pipe full of mud. The inu 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 1

Step 2

Step 3

Step 4

Stands

P r e s s u r e





REV 7: AUG 2009 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 eents mayrequire tubing, casing, or drill pipe to be run or pulled while annular pressure iscontained by blowout preenters; such practice is called “stripping”. Stripping isnormally considered an emergency procedure to maintain well control; howeer,plans for certain drilling, completion, or well work operations may includestripping to eliminate the necessity of loading the well with uid.

EQUIPMENT

Stripping techniques ary, 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. proides a means of containing and monitoring annular pressure, and

c. permits measured olumes of uid to be bled from or pumped into the well.

Subsurface equipment is required to preent pressure entry or ow into the pipe being stripped. This equipment should either be remoable or designed so that itspresence will not interfere with operations subsequent to stripping.

The well site superisor and crew must hae a thorough working knowledge of allwell control principles and equipment employed for stripping. Equipment should

be rigorously inspected, and, if practicable, operated prior to use.

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

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





REV 7: AUG 2009 5 - 29

Annular preenters are most commonly employed for stripping because tool joints and some couplings can be moed through the preenter without opening

or closing of the packing element. Wear of the packing element limits the sole useof this preenter if high annular pressure must be contained while stripping. Tominimise wear the closing pressure should be reduced as much as possible andthe element allowed to epand and contract (breathe) as tool joint pass through.Lubrication of the pipe with a miture of oil and graphite or by permitting a smallleakage of annular uid will reduce wear on the packing element. A spare packingelement should be at the well site during any stripping operation.

Ram type preenters or combinations of ram and annular preenters areemployed when pressure and/or Conguration of the coupling could causeecessie wear if the annular preenter were used alone. Ram preenters must

be opened to permit passage of tool joints or couplings. When stripping betweenpreenters, proision should be made for pumping into and releasing uid fromthe space between preenters. Pressure across the sealing element should beequalised prior to opening the preenter to reduce wear and to facilitate operationof the preenter. After equalising the pressure and opening the lower preentera olume of drilling uid equal to that displaced as the pipe is run into or pulledfrom the well should be, respectiely, bled from or pumped into the space

between the preenters.

Chokes are required to control the release of uid while maintaining the desired

annular pressure. Adjustable chokes which permit fast, precise control should be employed. Parallel chokes which permit isolation and repair of one chokewhile the other is actie are desirable on lengthy stripping operations. Because ofthe seere serice, spare parts or spare chokes should be on location. Fig. 10.A.1illustrates an eample choke installation on the standpipe suitable for strippingoperations.

A pump truck or skid mounted pump is normally employed when strippingout. The relatiely small olume of drilling uid required to replace the capacityand displacement of each stand or joint of pipe may be accurately measured and

pumped at a controlled rate with such equipment. Well uid from below thepreenter should not be used to equalise pressure across the stripping preenter.

A trip tank or other method of accurately measuring the drilling uid 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 resered as a means of shutting in the well if other components of the

blowout preenter stack fail. It should not be subjected to the wear and stress ofthe stripping process.





REV 7: AUG 2009 5 - 30

5.8 REMOVAL OF GAS TRAPPED IN BOP’S

In order to displace a gas kick completely from the wellbore seeral circulationsof the well might be needed. During this time some of the gas may hae 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 remoed in a controlledmanner. If the rams were opened without remoing the trapped gas, the gaswould be released into the riser. As the gas migrated, it would epand rapidly andcause the riser to unload mud onto the rig oor.

The most thorough method of gas remoal is to leae the well shut on the lowerrams whilst displacing the choke and kill lines to water. By closing the kill lineales, pressure can be bled off up the choke line and “U-tubed” up the choke line

by opening the pipe rams. This sequence is shown in Fig 5.29 and 5.30.

The surface dierter 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 ow-checked. Calculateany new riser margin or trip margin that might hae to be added to the mudweight.

Figure 5.28 TRAPPED GAS IN BOP STACK

UPPERANNULA

R

BLIND/SHEARRAMS

LOWERANNULA

R

PIPE RAMS

PIPE RAMS

PIPE RAMS

KILLLINE

CHOKELINE





REV 7: AUG 2009 5 - 31

Figure 5.29 REMOVING TRAPPED GAS FROM BOP STACK

KILLLINE

CHOKELINE

KILLLINE

CHOKELINE

KILLLINE

CHOKELINE

Isolate the well from the BOP stackby closing the lower pipe rams.

Slowly displace kill line to salt water.As the kill line is displaced to water,increase the kill line circulatingpressure by an amount equal to thedifference in hydrostatic pressurebetween kill mud and salt water atstack depth. This will maintain the gasat original pressure with clean saltwater returns at surface stop pumpingclose choke.

Displace riser to kill mud using upperkill line.





REV 7: AUG 2009 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 stilltrapped in the gas bubble.

Bleed off pressure through the choketo allow the gas to displace waterfrom the choke line.

The gas bubble should now be atclose to atmospheric pressure.

KILLLINE

CHOKELINE

Close the diverter and line up to fill the riser.

Open the pipe rams and allow the riser toU-tube taking returns up the choke line.

Fill the riser as necessary.

Open the lower pipe rams and diverterelement.

Flow check the well.





REV 7: AUG 2009 5 - 33

Whilst displacing with seawater what size would the bubble expand to?

Bubble Epansion Eample:- Choke Line Length = 1000' Choke Line volume = 8 bbls Kill Mud = 15 ppg Sea Water Grad = 0.445

P1

V1 780 X 3

V2 = –––– = ––––––– = 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 V

1 1559 x 5.46

–––––– = V2 –––––––––– = 579 bbls

P2

14.7

573 bbls of gas released at surface.





REV 7: AUG 2009 5 - 34

5.9 KICK DETECTION AND WELL CONTROL PROBLEMS ONDEVIATED AND HORIZONTAL WELLS

Figure 5.31

INTRODUCTION

Kick behaiour can be signicantly different in highly deiated and horizontalwells. If inu is mainly gas, problems can be eperienced getting the gas tomoe out of the horizontal section. It maybe impossible to remoe the gas if thehorizontal section is greater than 90 degrees. Swabbed inues can be hard todetect in horizontal sections and care must be taken while making connectionsor tripping in these sections of the hole. Drill pipe pressure graphs will also besignicantly different for horizontal and deiated 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 ow rate.

b) If the increase in ow rate is not picked up then the second indication of akick would be a pit leel increase.

c) While drilling the horizontal section miing chemicals or slow addition ofmud into the actie system should be aoided

A - SURFACE

B - KICK OFF POINT (K.O.P.)

C - END OF BUILD (E.O.B.) D - TOTAL MEASURED

DEPTH (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'





REV 7: AUG 2009 5 - 35

5.9.2 KICK DETECTION AND PRECAUTIONS TO TAKE WHEN MAKINGCONNECTIONS.

a) The equialent circulating density is relatiely 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 inu has been swabbed in and not picked up during a connection noincrease pit leel will be seen until inu is out of horizontal section. If itis a gas inu in an oil base mud then no increase maybe seen until inureaches bubble point usually ± 3000 feet beneath mud return ow line. The

driller and mud logger should pay particular attention to ow rates and pitleels when connection gas moes out of horizontal section or is ± 3000 feet

beneath mud return ow line.

5.9.3 KICK DETECTION AND PRECAUTIONS TO TAKE WHILE TRIPPING.

a) Mud loggers will calculate maimum tripping speed to aoid swabbing.

b) Check mud rheology is within specications prior to tripping, high mud

rheology can lead to swabbing.

c) When tripping out of horizontal section there are two options aailableand 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 ll in triptank

ADvANTAGES: Accurate record of hole ll.

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 preent swabbing.

DISADvANTAGES: If an inu is swabbed in, it would be ery hard ifnot impossible to detect.





REV 7: AUG 2009 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 dissoled 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 remoed from inerted sections then consider bullheadinggas into formation.

e) Slow circulating rates which gie a ow rate greater than 130 ft/min while

circulating gas out of horizontal section should be considered. Flow rateslower than this may not remoe the gas from the horizontal section

f) A swabbed inu will not gie a SICP if shut in while it is in horizontalsection.

g) Referring to gure 5.31 on page 5-34 it would be impossible to take a kickif formation 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 inu cannot be calculated.





REV 7: AUG 2009 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 = 8.0

167.8 bbl

Strokes to 167.8Disp D.string

= ––––– = 1434 stks 0.117

ICP - FCP 1300-784

Press Step Down psi/stks = –––––––––––––– = ––––––––– = 0.36 psi/stks Surface to bit stks 1434

6001. Kill Mud wt = ––––– ÷ 0.052 + 10.0

10000

2. ICP = 11.2 ppg

= 600 + 700

= 1300 psi

11.23. FCP = 700 x ––––– 10

= 784 psi





REV 7: AUG 2009 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 the

kill 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

400500

600

700

800

900

1000

1100

1200

1300

1400

1500

P R E S S U R E

STROKES

FCP

ICP





REV 7: AUG 2009 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 = 248.61000 X 0.008 = 8.0 256.6 bbl

Strokes to 256.6Disp D.string

= ––––– = 2194 stks 0.117

Figure 5.33

600

1. 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.)





REV 7: AUG 2009 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

P

R E S S U R E

STROKES

A - (SURFACE) 1650

1600

1700

D - (M.D.) 1170

C - (E.O.B.) 1155

B - (K.O.P.) 1521





REV 7: AUG 2009 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





REV 7: AUG 2009 5 - 42

5.10 KICK TOLERANCE

When a gas inu has entered a well there are 2 critical locations for the inu:-

a) When the inu is at the bottom of the well. In this case the SICP must noteceed the MAASP, if the formation is not fractured at the casing shoe.

b) When the inu has been circulated up to the casing shoe, by a constant bottom hole pressure method. In this case, the pressure at the choke mustnot eceed the MAASP.

KICK TOLERANCE DEPENDS UPON:-

Formation strength, fracture pressure or fracture gradient.

Mud density or gradient.

Gas inu density or gradient.

Formation pore pressure, gradient or SIDPP.

Drill string and wellbore geometries.

The maimum tolerable length of gas inu in the annulus at any position between bottom hole and the casing shoe is:-

Eqn1 H (Max) =

MAASP - SIDPP G

m - G

i

Where:- GM

= mud gradient (psi/ft)

GI = inu gradient (psi/ft)

MAASP = (Gfrac - Gm) Ds (psi)

Gfrac = formation fracture gradient at the shoe (psi/ft)

DS = TvD to the shoe (ft)

SIDPP = shut-in drillpipe pressure (psi)





REV 7: AUG 2009 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 to

casing shoe, by 'drillers method'.

SK = fracture pressure at shoe.

FK = maximum tolerable length ofexpanded gas influx at shoe= H

MAX.

∆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

M u d G r a

d i e n t / P

r e f f u r e

L i n

e

D E P T H ( T

V D

)

F r a

c t u r e

L

i n e

NB. Well geometry assumed to be constant





REV 7: AUG 2009 5 - 44

DEFINITION 1: for a kick taken while drilling into a high pressure formation.

Kick Tolerance is the maimum allowable inu olume, for a known or assumedSIDPP, which will not cause the formation to fracture when either the inu is atthe bottom of the annulus or when it is circulated and epanded to the casing shoe

by 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 alue 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)





REV 7: AUG 2009 5 - 45

DEFINITION 2: for a kick taken while tripping out of the hole.

Kick tolerance for a swabbed kick is the maimum allowable inu olume whichmay be swabbed into the bottom of a well, without fracturing the formationwhen the 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 eentually back at bottom SIDPP=0, although initially SIDPP should =SICP (no oat) when the well is closed in and the bit is aboe the inu.

In this case Hmax =MAASP

ft GM

- GI

and the kick tolerance is either

V1g =H

x Vdca

Ldc

or V1g = Vdca +(H - Ldc)

Cdpa





REV 7: AUG 2009 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 the current 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 mud weight is equialent to the formation pore pressure.

The mud gradient is 0.835 psi/ft.





REV 7: AUG 2009 5 - 47

SOLUTION

1) MAASP = (Gfrac - GM) x DShoeGM = 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 inu at the bottom of the well, inu is still within the DC/OH annulus,at its maimum.

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 Dshoe Gpore x Cdpa x (G

M - G

I) x TVD

Gpore = 15.3 x 0.052 x 14500 + 570 = 0.835 psi/ft 14500

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) value therefore kick tolerance = 17.3 bbl when the kick is in the DC/OH annulus. This is usually the case in short open-hole sections.





REV 7: AUG 2009 5 - 48

2) For a swabbed kick, maimum allowable (SIDPP = 0) inu 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





REV 7: AUG 2009 5 - 49

WORKSHOP 5

The following questions 1-5 refer to the rst stage of the Drillers Method.

1. A well was shut-in on a kick that occurred whilst drilling. Duringthe rst circulation of the Drillers Method, the choke operatormaintains a constant drill pipe pressure at a constant pumpspeed.

Will bottom hole pressure:

a. Be increasing

b. Be decreasing c. Being kept constant

2 . Referring to the question aboe, the choke operator has nottaken into account the large olume of the surface lines, i.e.from the pump to the rig oor.

This will result in:

a. An increase in bottom hole pressure b. A reduction in bottom hole pressure

c. No change to bottom hole pressure

3. Referring to question 1 aboe if the kick was brine, (with no gas)Casing or Choke pressure will be at its highest :

a. When pressures hae stabilised at shut-in b. When the kick is going into the shoe c. When the kick is nearing the surface

4. What happens to pressure at the shoe as the brine kick is beingmoed into the casing shoe?:

a. Pressure at the shoe will be constant b. Pressure at the shoe will reduce c. 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 increase b. Pressure at the shoe decrease

c. Pressure at the shoe remain constant





REV 7: AUG 2009 5 - 50

6. During the second stage of the Drillers Method, assuming all ofthe kick was remoed during the rst stage, if when starting the

operation the choke operator maintained a constant initialcirculating pressure in the drill-pipe until kill mud reached the bit.Would bottom hole pressure?

a. Be increased b. Hae reduced

c. 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 hae increased until kill mud was at the bit,then B.H.P. would hae remained constant as kill muddisplaced the annulus.

c. B.H.P. would hae 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 olume of water it took to ll the well to the top wasequialent to 500' of annulus. What is the resultant reduction in

bottom hole pressure due to this action ?

Mud weight = 10 ppg Sea-water = 8.7 ppg

a. 260 psi

b. 226 psi c. 34 psi

9. The well ows with the bit 10 stands off bottom. Shut-in casingpressure reads 200 psi. If the inu is below the bit:

a. Shut-in drill pipe pressure will be higher than 200 psi b. Shut-in drill pipe pressure will be lower than 200 psi c. Shut-in drill pipe pressure should be 200 psi





REV 7: AUG 2009 5 - 51

10. A well is shut-in on a kick whilst drilling and stabilised shut-inpressures hae been established. Due to a delay in starting the kill

operation surface pressures hae increased by 100 psi as theinu 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. Leae it until the problem causing the delay has been

resoled 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 inu. How far has the inu migrated

if the mud weight is 10 ppg and the inu 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 eerted on the eposedfoundations immediately below the casing shoe: Select 2 answersfrom the following statements.

a. The Drillers Method will always gie a higher shoe pressure.

b. The Wait & Weight Method will always gie a lower shoepressure.

c. The Drillers Method will gie the lowest shoe pressure whenthe open hole olume is smaller than the string olume.

d. The Wait & Weight Method will gie the lowest shoe pressurewhen the open hole olume is greater than the string olume.

e. There will be no great difference in shoe pressures whether

the Drillers or Wait/Weight Method is used if the open holeolume is less than the string olume.

13. If a well is shut-in on a gas kick and the gas is not allowed toepand 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





REV 7: AUG 2009 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 inu is below the shoe (ii) Will continue to increase (iii) Will remain fairly constant

d. Pressures in the gas inu. 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 inu

14. A kick is being circulated out using the Wait & Weight Kill Method.Shortly after pumping kill mud to the bit, nal circulating pressurehas suddenly increased by 200 psi. The pump speed has been keptconstant at kill speed and there was no change noted on the choke

gauge. What is the problem ?

a. The choke has plugged b. A bit nozzle has plugged c. A pack-off has occurred around the bit

15. If the choke operator opened the choke and reduced drill pipepressure back to the calculated nal circulating pressure in theproblem as described in Question 14. The result would be:

a. B.H.P. would be reduced b. B.H.P. would be increased c. no change to B.H.P





REV 7: AUG 2009 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 hae 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 fuid is being replaced with a heavier "mud",reducing pressure at the shoe.

5. b. Pressure at the shoe decrease

Kick fuid 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 hae remained constant until kill mud at bit

then 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





REV 7: AUG 2009 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 gie the lowest shoe pressurewhen the open hole olume is greater than the string olume.

e. There will be no great difference in shoe pressures whetherthe Drillers or Wait/Weight Method is used if the open hole

olume is less than the string olume.

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 inu

14. b. A bit nozzle has plugged

15. a. B.H.P. would be reduced





REV 6: JAN 2008

SECTION 6WELL CONTROL EQUIPMENT

6.0 API Guidelines - API RP53

6.1 Ram Blowout Preventers

6.2 Annular Preventers

6.3 Diverters

6.4 Gaskets, Seals and Wellheads

6.5 Manifolds

6.6 Inside BOP’s




SECTION 6 : WELL CONTROL EQUIPMENT

REV 7: AUG 2009 6 - 1

6.0 API GUIDELINES (API RP53)

BLOWOUT PREVENTER STACK ARRANGEMENTS

SURFACE INSTALLATIONS

CLASSIFICATION OF BLOWOUT PREVENTERS

API classication of example arrangements for blowout preventer equipment is based 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 equally

adequate in meeting well requirements and promoting safety and efciency.

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 inaccordance with operator’s choice.

Rt = triple ram type preventer with three sets of rams, positioned inaccordance 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 identied 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.





REV 7: AUG 20096 - 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 pipe being used,

b. a complete set of bonnet or door seals for each size and type of ram preventer being used,

c. plastic packing for blow out preventer secondary seals,

d. ring gaskets to t ange connections, and

e. appropriate spare parts for annular preventers, when used.

PARTS STORAGE

When storing blowout preventer metal parts and related equipment, they should be 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 ofthe blowout preventer side outlet reduces the number of stack connections byeliminating the drilling spool and shortens the overall preventer stack height.The reasons 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 minimumspecications:

a. Have side outlets no smaller than 2" nominal diameter and be anged,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.





REV 7: AUG 2009 6 - 3

For drilling operations, wellhead outlets should not be employed for choke orkill lines Such outlets may be employed for auxiliary or back-up connections to be

used only if a failure of the primary control system is experienced.

S *

F I G 6 . 0 . 1

E X A M P L E B

L O W O U T P R E V E N T E R A

R R A N G E M E N T S F O R

2 M R A T E D W O R K

I N G P R E S S U R E S E R V I C E

– S U R F A C E I N S T A L L A T I O N

F I G C . 2

A R R A N G E M E N T S * R R

D o u b

l e R a m P r e v e n t e r s ,

R d O p t i o n a l .

F I G C . 3

A R R A N G E M E N T

S * R R

F I G C . 4


R S * R

F I G C . 1

A R R A N

G E M E N T S * A

A

S *

R R

S *

A R

S *

R R





REV 7: AUG 20096 - 4

FIG 6.0.2

EXAMPLE BLOWOUT PREVENTERARRANGEMENTS FOR 3M AND 5M RATED

WORKING 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





REV 7: AUG 2009 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

CASING

SPOOL

R

FIG C.8ARRANGEMENT S*RRRA**Double Ram Type Preventers,

Rd Optional.

S*

R

A**

R

CASING

SPOOL

R

FIG C.9ARRANGEMENT RS*RRA**G**

Double Ram Type Preventers,Rd Optional.

S*

R

A**

R

CASING

SPOOL

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.





REV 7: AUG 20096 - 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 to

the blowout preventer stack.

Example subsea blowout preventer stack arrangements are illustrated inFigs. D.1 through D.8.





REV 7: AUG 2009 6 - 7

F I G 6

. 0 . 4

E X A M

P L E B L O W O U T P R E V E N

T E R A R R A N G E M E N T S F O R

2 M A N D 3 M R A T E D W

O R K I N G P R E S S U R E

S E R V I C E – S U B S E A

I N S T A L L A T I O N

F I G D . 2


H R A C L

C L

A R C H

F I G D . 3


H R R A C L

D o u b l e R a m T y p e P r e v e n t e r s ,

R d , O p t i o n a l .

C L

A R R C H

F I G D . 4


C H R R C H A

D o u b l e R a m T y p e P r e v e n t e r s ,

R d , O p t i o n a l .

C H R R C

H A *

F I G D . 1

A R

R A N G E M E N T C H S A C L

( 2 m r a t e d w o r k i n g p r e s s u r e o n l y . )

C L

A S C H





REV 7: AUG 20096 - 8

f i g 6 . 0 . 5

E X A M P L E B L O W O U T P R

E V E N T E R A R R A N G E M E N T S F O R

5 M , 1 0 M A N D 1 5 M R

A T E D W O R K I N G P R E S S U R E

S E R V I C E – S U

B S E A I N S T A L L A T I O N

F I G D . 5

A R R A N G E M E N T C H R d R A * C

L

T r i p l e R a m T y p e P r e v e n t e r s ,

R d O p t i o n a l

C L

A *

R R R C H

F I G D . 6


H R d R A * C H A *

C H

A *

R R R C H

A *

F I G D . 7


H R d R d A * C L

C L

A *

R R R C H R

F I G D . 8


C H R d R d A * C H A *

C H

A *

R R R C H

A *

R





REV 7: AUG 2009 6 - 9

F I G 6 . 1 . 1 U B l o w

o u t P r e v e n t e r





REV 7: AUG 20096 - 10

6.1 RAM BLOWOUT PREVENTERS - CAMERON U BOP

The Cameron U BOP is the most widely used ram-type BOP for land, platform andsubsea 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 stud loading is consistently accurate and even.

• Bonnet seal carrier is available to eliminate the need for high makeup

torque on bonnet studs and nuts.

• Hydraulically operated locking mechanisms, wedgelocks, lock the ram hydraulically and hold the rams mechanically closed even when actuating pressure is released. The operating system can be interlocked using

sequence caps to ensure that the wedgelock is retracted before pressure isapplied to open the BOP.

• For subsea applications, a pressure balance chamber is used with the

wedge locks to eliminate the possibility of the wedgelock becomingunlocked due to hydrostatic pressure.

Other features include hydraulically opening bonnets, forged body and a wideselection of rams to meet all applications.

Figure 6.1.2 U Blowout Preventer Wedgelock Assembly





REV 7: AUG 2009 6 - 11

Figure 6.1.3 Figure Cameron U - Type BOP

�

�

�

�

�

�

�

�

�





REV 7: AUG 20096 - 12

PIPE RAMS

Cameron pipe rams are available for use in Cameron ram-type BOPs to t allcommonly used sizes of tubing, drill pipe, drill collar or casing.

• Cameron pipe rams are self-feeding and incorporate a large reservoir of packer rubber to ensure a long-lasting seal under all conditions.

• Ram packers lock into place and are not dislodged by well ow

• All Cameron pipe rams are suitable for H2S service per NACE MR-01-75.

• CAMRAM™ top seals are standard for all Cameron pipe rams (except

U BOPs larger than 13-3/4”).

• CAMRAM 350™ packers and top seals are available for high temperature service and for service in which concentrations of H2S are expected.

Figure 6.1.4 - PIPE RAMS

Top Seal

Ram

Packer

U BOP Pipe Ram

Top Seal

RamPacker

U II BOP Pipe Ram

CAMRAM Packer

CAMRAM Top Seal

Ram

WearPads

T BOP Pipe Ram





REV 7: AUG 2009 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 whenthe rams are closed so the steel provides support for the rubber whichseals against the pipe.

• All VBRs are suitable for H2S service per NACE MR-01-75.• CAMRAM™ top seals are standard for all Cameron VBRs.

Shearing Blind RamsCameron 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 rubberand increases service life.

• Cameron SBRs can cut pipe numerous times without damage to thecutting edge.

• 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 blade material of hardened high alloy suitable for H2S service.

Figure 6.1.5 - VBR'S

Top SealRam Body

VBR Packer

U and U II BOP Variable Bore Ram

CAMRAM Packer

Ram Body

CAMRAM Packer

Wear Pads

T BOP Variable Bore Ram





REV 7: AUG 20096 - 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 after shearing so that the lower blade can seal against the blade packer

• DVS rams include the largest blade width available to t within existing ram bores.

Figure 6.1.6 - SHEAR RAMS

CAMRAM Top Seal

RamBodySlide Packer

LowerSBR

UpperSBR

BladePacker

U and U ll BOP Shearing Blind Ram

CAMRAM Top Seal

Blade Insert

Slide Packer

BladeInsert

BladePacker

LowerSBR

UpperSBR

U and U ll H2S BOP Shearing Blind Ram

Blade Packer

Upper Blade Insert

Slide Packer

Screw

CAMRAMTop Seal

Lower BladeInsert

LowerSBR

UpperSBR

WearPads

T BOP Shearing Blind Ram Upper Ram Body

Lower Ram Body

Top Seal

BladePacker

SidePacker

DVS Shear Ram





REV 7: AUG 2009 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 are 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





REV 7: AUG 20096 - 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 studloadingis consistently accurate and even.

• Bonnet seal carrier is available to eliminate the need for high makeuptorque on 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 usingsequence caps to ensure that the wedgelock is retracted before pressure isapplied to open the BOP

• A pressure balance chamber is used with the wedgelocks to eliminate the possibility of the wedgelock becoming unlocked due to hydrostatic

pressure. Other features include hydraulically opening bonnets, forged body and a wide selection of rams to meet all applications.

Figure 6.1.8 - 18-3/4" DOUBLE U II BLOWOUT PREVENTER





REV 7: AUG 2009 6 - 17

Optional Equipment

Bonnet Seal Carriers for TL, U, UL and U 11 BOPS The 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 bonnet

bolt 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 ange.

The seal carrier was designed, developedand performance-veried for use in newlymanufactured BOPs or as a replacement sealassembly for BOPs where either the BOP

body or the intermediate ange requires

weld 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 replacing

several 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.

Figure 6.1.9

Large Bore Shear Bonnet Assembly Exploded View

Tandem Booster Exploded View





REV 7: AUG 20096 - 18

Figure 6.1.10 UII BOP Hydraulic Control System





REV 7: AUG 2009 6 - 19

Figure 6.1.11 UII BOP Part Numbers





REV 7: AUG 20096 - 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

the door cap screws and swing the door open. Remove the ram fromthe ram shaft and replace it. It is not necessary to apply closing hydraulicpressure to move the rams inward to clear the door.

• Door seals on most sizes have a hard backing moulded into the rubber.This fabric and phenolic backing prevents extrusion and pinching at allpressures to assure long seal life.

• Internal H2S trim is standard. All major components conform to API and NACE H2S requirements.

• Maximum ram hardness Is Rc22 to insure H2S compatibility of pipe and blind rams. Shear rams have some harder components.

• Manual-lock and Poslock pistons can be interchanged on the same door by replacing the ram shaft, piston assembly and cylinder head.

• Wear rings eliminate metal-to-metal contact between the piston andcylinder to increase seal life and virtually eliminate cylinder bore wear.

• Lip type piston seals are long-wearing polyurethane with molybdenumdisulde moulded in for lifetime lubrication..

• Lip-type ram shaft seals hold the well bore pressure and the opening hydraulic pressure. No known failures of this highly reliable high

pressure seal have occurred.

• Secondary ram shaft seals permit injection of plastic packing if theprimary lip-type seal ever fails. Fluid dripping from the weep hole in thedoor indicates that the primary seal is leaking and the secondary sealshould be energised.





REV 7: AUG 2009 6 - 21

• Rams are available which will support a 600,000 pounds when a tool joint is lowered onto the closed rams. These rams conform to H2S

requirements.

• Shear rams cut drill pipe and seal in one operation. Most common weights and grades of drill pipe are sheared with less than 1,500 psi hydraulic

pressure.

• Poslock operators automatically lock the rams each time they are closed.This eliminates the cost of a second hydraulic function to lock. It alsosimplies emergency operation because the rams are both closed andlocked just by activating the close function.

Figure 6.1.12 - SHAFFER SL-RAM BOP

Roundhead ram shaft

Ram shaft seal

Piston seals

Cylinder

Weep hole

Flat door

Cylinder head

Piston assembly

Ram

Wear ringsRam shaft

packing retainerSecondary

ram shaft seal





REV 7: AUG 20096 - 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





REV 7: AUG 2009 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 closed

and locked. They cannot be manually reopened.

The manual locking shafts are visible from outside and provide a convenientram position indicator. Threads on the manual locking shaft are enclosed in the

hydraulic uid and are not exposed to corrosion from mud and salt water or tofreezing.

Rams are opened by rst turning both locking shafts to their “unlocked” position,then applying opening hydraulic pressure to the pistons, which move outward

and 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 eld 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 facilitate

connecting 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 psi

well 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 the

factory. However, it is recommended that this pressure not be used in the eldapplication.





REV 7: AUG 20096 - 24

The hydraulic operating uid should be hydraulic oil with a viscosity between 200

and 300 SSU at 100°F. If necessary, a water-soluble oil such as NL Rig Equipment

K-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 uids 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 the

closed 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 and

closing 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 locking

shoulder as the locking cone is forced inward by the closing hydraulic pressure.

The locking cone holds the locking segments in position and is prevented bya spring 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 outwardand the locking segments slide toward the piston l.D. along the tapered locking

shoulder. 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 eld except when changing between pipe rams and shear rams.

The adjustment is easy to check and easy to change.





REV 7: AUG 2009 6 - 25

F i g u r e 6 . 1 . 1 4 - F L U I D

C I R C U I T - S L R A M





REV 7: AUG 20096 - 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 UltraLockare automatically locked in the closed position each time the BOPs are closed;no preset pressure ranges are needed. The BOPs will remain locked in the closedposition, even if closing pressure is lost or removed. Hydraulic opening pressureis required 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 modications are

not 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





REV 7: AUG 2009 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 is

below 1,500 psi for BOP’s with 14'’ pistons. These pistons are standard in all BOP’s

rated 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 in

the space between the lower blade and the upper holder. The upper section of cut

pipe 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. Continued

closing of the holders squeezes the semicircular seals upward into sealing

contact with the seat in the BOP body and energises the horizontal seal. The

closing motion of the upper holder pushes the horizontal seal forward and

downward on top of the lower blade, resulting in a tight sealing contact. The

horizontal seal has a moulded-in support plate which holds it in place when the

rams are open.

Type 72 Shear Rams are covered by U.S. Patent No. 3,736,982. (Ref g 6.1.16)





REV 7: AUG 20096 - 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





REV 7: AUG 2009 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 uid 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 uid passages between the body and bonnets. This arrangement provides a reliable hydraulicseal and permits full pressure testing and ram operation with the bonnets open.The uid 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 eld replaceable or repairable 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 ramin a 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 and body and preclude damage during moving and handling operations.





REV 7: AUG 20096 - 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 drillinguid.

15. Bonnet Seal utilises eld 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, eld-proven, integrally designed lip seal and backup 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 congurations,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 Congurations are available with a choice of AmericanPetroleum Institute (API) anged, 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 between bonnet 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.





REV 7: AUG 2009 6 - 31

F i g u r e 6 . 1 . 1 7 - 1 3 5 / 8 " - 1 0 , 0 0 0 P S I R A

M B O P M A N U A L L O C K

1 3 . C O N N E C T O R R I N G G R O O V E S

1

. T H E R A M B O D Y C A S T I N G

3 . T H E F I E L D R E P L A C A B L E

S E A L S E A T

1 5 . B O N N E T S E A L

2 . T H E R

A M

A S S E M B L Y

1 7 . S E C O N D A R Y

( E M E R G E N C Y )

( P I S T O N R O D P A C K I N G )

2 2 . B O N N E T B O L T S

1 1 . M A N U A

L L O C K I N G

1 9 . P I S T O N S E A L S

7 . R E P L A C A B L E

C Y L I N D E R L I N E R

1 8 . A W E E P H O L E 1

6 . P I S

T O N R O D M U D S E A L

1 4 . S L O P E D R A M C A V I T Y

2 4 . G U I D E R O D S

2 0 . S L I D E O U T L E T S F O R C H O K E / K I L L

1 2 . F L U I D C O N N E C T I O N S

A N D H Y D R A U L I C P A S S A G E S

5 . L O A N H I N G E S

6 . F L U I D H I N G E S





REV 7: AUG 20096 - 32

F i g u r e 6 . 1 . 1 8 - 1 8 3 / 4 " - 1 5 , 0 0 0 P S I R A M B O P M U

L T I P L E P O S I T I O N L O C K

( M P L )

3 . T H E

F I E L D R E P L A C E A B L E

S E A L S E A T

1 3 . C O N N E C T O R R I N G G R O O V E S

1 . T H E R A M B O D Y C A S T I N

G

2 0 . S I D E O U T L E T S F O R C H O

K E K I L L

1 4 . S L O P E

D R A M C A V I T Y

1 5 . B O N N E T S E A

L

1 6 . P I S T O N R O D M U D S E A

L

1 8 . A

W E E P H O L E

1 9 . P I S T O N S E A L S

7 . R E P L A C E A B

L E

C Y L I N D E R L I N E R

8 . P I S T

O N A N D P I S T O N

R O D

A S S E M B L Y

1 0 . M U

L T I P L E - P O S I T I O N

L O

C K I N G ( M P L )

5 . L O A D H I N G E S

6 .

F L U I D H I N G E S

2 . T H E R A M A S S E M B L Y

2 2 . B O N N E T B O L T S





REV 7: AUG 2009 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 with

optimum seal squeeze at every closure. MPL automatically locks and maintains

the ram closed with the optimum rubber pressure required for seal off in the front

packer and upper seal.

Front packer seal wear (on any ram BOP) requires a different ram locking position

with each closure to ensure an effective seal off. Multiple-Position Locking is

required to ensure retention of that seal off position.

A mechanical lock is automatically set each time the ram is closed. Ram closure is

accomplished by applying hydraulic pressure to the closing chamber which moves

the ram to a seal off position. The locking system maintains the ram mechanically

locked while closure is retained and/or after releasing closing pressure. The ram is

opened only by application of opening pressure which releases the locking system

automatically and opens the ram, simultaneously.

MPL is available on all Hydril Ram Blowout Preventers.

How MPL works

This gure shows the ram maintained closed and sealed off by the MPL.

Hydraulic closing pressure has been released. The Hydril Ram Blowout Preventer

with MPL automatically maintains ram closure and seal off. MPL will maintain the

required rubber pressure in the front packer and upper seal to ensure a seal off of

rating working pressure. MPL will maintain the seal off without closing pressure

and with the opening forces created by hanging the drill string on the ram.

Locking and unlocking of the MPL are controlled by a unidirectional clutch

mechanism and a lock nut. The unidirectional clutch mechanism maintains the

nut and ram in a locked position until the clutch is disengaged by application of

control system pressure to open the ram.

Hydraulic opening pressure disengages the front and rear clutch plates to permit

the 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.





REV 7: AUG 20096 - 34

Figure 6.1.19 - HYDRILL MULTI-POSITION LOCK (MPL)





REV 7: AUG 2009 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 5.4 10,000 2.3 6.9 1.7 8.2 15,000 2.3 6.9 3.37 7.11 6.6 7.6

9 in. 2,0003,000 2.6 5.3

5,000 2.6 5.3 10,000

11 in. 2,000 2.5 7.33,000 2.5 7.3 2.0 6.8

5,000 2.5 7.3 2.0 6.8 10,000 2.5 7.3 7.62 7.11 2.4 7.6

15,000 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 5.2 10,000 2.3 7.0 4.29 7.11 3.8 10.6 15,000 5.6 8.4 2.14 7.11 3.56 7.74

16 3/4 in. 2,0003,000 2.3 6.8

5,000 2.3 6.8 2.03 5.54

10,000 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 10.6 15,000 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 10.6 10,000 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





REV 7: AUG 20096 - 36

EXAMPLE CLOSING FORCES IN RELATION TO AREA

a) When closing the well in on a oating rig the hard shut in method isusually applied. The string is picked up say 20’ off bottom, the rotarytable or top drive is shut off and both pumps are shut down. The annularpreventer is then closed and the 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.The correct operating pressure to set on the manifold regulator is directlyrelated to the well bore pressure. For example. Operating ratio 10:56:1.Working pressure of BOP stack 10,000 psi.

F 10,000 psi P = ––– ∴ 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

PRESSURECLOSINGAREARAM SHAFT AREA

➙

➙

➙

➙

➙

➙

➙

➙

➙

➙

➙

➙

➙ ➙

➙➙





REV 7: AUG 2009 6 - 37

Figure 6.1.22 RAM PREVENTERS -FLUID REQUIRED TO OPERATE





REV 7: AUG 20096 - 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 change

out 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 eld maintenance. Components subject towear are eld-replaceable and the entire operating system may be removed inthe eld 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 t into the wellbore. These packers will

also close and seal on open hole. Some annular packers can also be split for installation while pipe is in the hole. Popular sizes of the DL BOP are available

with high-performance CAMULAR™ annular packing subassemblies.

Figure 6.2.1 DL ANNULAR BLOWOUT PREVENTER

PACKING UNIT

CONSISTING OF:

PISTON

OPENING

CHAMBER

CLOSING

HYDRAULIC

PORTS

DONUT

PACKER,

VENT

OPENING

HYDRAULIC

PORT

PUSHER

PLATE

LOCKING

GROOVES

ACCESS

FLAPS





REV 7: AUG 2009 6 - 39

Figure 6.2.2 CAMERON 20,000 PSI WP ANNULAR BLOWOUT PREVENTERSEALING ELEMENT

OPEN CLOSED ON PIPE CLOSED ON OPEN HOLE





REV 7: AUG 20096 - 40

F i g u r e 6 . 2 . 3 H Y D R I L “ G K ” A N N U L A R





REV 7: AUG 2009 6 - 41

OPERATIONAL FEATURES

The Hydril GK Annular BOPs are particularly qualied to meet the industry’s needs forsimple and reliable blowout protection. Over 40 years of operational experience providethe simplest, eld 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 efcient mechanismrequiring less maintenance and downtime.

A Long piston with a length to diameter ratio approaching one eliminates tendenciesto cock 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 close andseal on virtually any shape in the drillstring or completely shut off the open bore and tostrip tool joints under pressure. This feature permits condent closure of the BOP at theinitial indication of a “kick” without delaying to locate the tool joint.

The Conical Bowl Design of the Piston provides a simple and efcient 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 eld repair fast and economical.

Flanged Steel Inserts In the Packing Unit reinforce the rubber and control rubber ow andextrusion 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 and greater

overall life of the packing unit results. The resulting ability to strip the drillstring to the bottom without rst changing the packing unit means a safer operation, lower operatingcosts and longer service life for the packing unit.

The Packing Unit Is Tested to Full Rated Working Pressure at the factory and the tests aredocumented— 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 to

provide safe operation, long seal life, and less maintenance.

Piston Sealing Surfaces Protected by Operating Fluid lowers friction and protects againstgalling and wear to increase seal life and reduce maintenance time.





REV 7: AUG 20096 - 42

ANNULAR 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 the

piston down. This position permits passage of tools, casing, and other items upto the full bore size of the BOP as well as providing maximum annulus ow ofdrilling uids. 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

opening chamber pressure returns the piston to the full down position allowingthe packing 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 inwardto a sealing engagement with the drill string. The closing pressure should be

regulated 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)





REV 7: AUG 2009 6 - 43

ANNULAR 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)





REV 7: AUG 20096 - 44

Complete shut off (CSO) of the well bore is possible with all Hydril AnnularBOP’s. During CSO the anges of the steel inserts form a solid ring to conne 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

by adjusting the closing chamber pressure just low enough to maintain a seal onthe drill pipe with a slight amount of drilling uid 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 chamber

pressure. 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 pressure

variations with certain control system circuits

Figure 6.2.5





REV 7: AUG 2009 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 testingand stripping pipe into or out of a well under pressure. The latched head permits

quick, 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 qualied 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 exibility of control hookup and acts as a backup closing chamber to cutoperating costs and increase safety factors in critical situations. The chamber can

be connected four ways to optimise operations for different effects:

1. Minimise closing/opening uid 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 few

turns of the Jaw Operating Screws, while the entire mechanism remains inside the blowout 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.





REV 7: AUG 20096 - 46

F i g u r e 6

. 2 . 6

P I S T O N I N D I C

A T O R H O L E

W E A R P L A T E

P A C K I N G U N I T

L A T C H E D H E A

D

O P E N I N G C H A

M B E R H E A D

O P E N I N G C H A

M B E R

P I S T O N C H A M

B E R

C L O S I N G C H A

M B E R

S E C O N D A R Y C H A M B E R

C u t a w a y V i e w o f G L

B O P s h o w n i n M i d s t r o k e .

5 0 0 0 o r 1 0 , 0 0 0 p s i b

o t t o m c o n n e c t i o n s a r e

a v a i l a b l e i n h u b , A P I

f l a n g e d , o r s t u d d e d c o n n e c t i o n .





REV 7: AUG 2009 6 - 47

Figure 6.2.7 GL 16 3/8" - 5000 PSI BLOWOUT PREVENTER

Item Part Name No Req'd Approx Net No. 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

ACCESSORIES Chain Sling Assembly 1 202 Eye Bolts, Piston (1"-8NC x 17" LG) 2 6 Eye Bolts, Head (1 1/2"-6NC x 2" LG) 3 6.75 Eye Bolts, Opening

Chamber Head - (7/8"-9NC x 2 1/4" LG) 3 1 Protector Plate 1 99 Protector Plate Screw 4 .13





REV 7: AUG 20096 - 48

Figure 6.2.8

S E

C O N D A R Y C H A M B E R

c o n n e c t e d t o

O P

E N I N G C

H A M B E R

( S - O )

S E C O N D A R Y C H A M B E R


C L O S I N G C

H A M B E R

( S -

C )

S E C O N D A R

Y C H A M B E R


M A R I N E R I S E R

( C B )

F I G . 1

F I G . 2

F I G . 3

C L O S I N G P

R E S S U R E

O P E N I N G P

R E S S U R E

S t a n d a r d s u r f a c e h o o k - u p r e q u i r e s l e a s t

f l u i d s o g i v e s a f a s t e r c l o s i n g t i m e .

S u b s e a h o o k - u p f o r w a t e r d e p t h s o v e r

8 0 0 f t .

S u b s e a h o o k - u

p f o r w a t e r d e p t h s u p

t o 8 0 0 f t .

H Y D R I L ' G L '





REV 7: AUG 2009 6 - 49

Figure 6.2.9 CONTRACTOR PISTON

As the contractor piston is raised by hydraulic pressure, the rubber packing unitis squeezed 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 areaexposed to mudcolumn

centre line

packingunit

operating

piston

wellpressure

well pressurearea

openingpressure

openingarea

closing

area

closingpressure





REV 7: AUG 20096 - 50

Figure 6.2.10

Operating pressure for Subsea Annular Preventers

(0.052 x Wm

x Dw

) - (0.45 x Dw

)Adjustment Pressure (∆P) = ––––––––––––––––––––––––––– p

Where:

Wm

= drilling uid density in lb./gal.D

w = water depth in feet0.052 = conversion factor p = 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 specic

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 prevent

collapse of casing.The closing pressures shown are initial closing pressures for

most 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 C L O S I N G

P R E S S U R E - P S I

S E C O N D A R Y C H A M B E R C O N N E C T E D

T O O

P E N I N G C

H A M B E R

NOTE : Pressures shown areaverage. Actual pressurerequired to afect seal-of willvary slightly with eachindividual packing unit.





REV 7: AUG 2009 6 - 51

Operating Pressure for Accumulator Bottles

Example 1

31/

2" - 7" pipe, 3500 psi well pressure, 16 lb./gal. drilling uid, 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 Lb/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 the

following example:

Example 2

31/

2" - 7" pipe, 500 feet water depth.

Precharge = 0.80 [Surface Closing Pressure + (0.41 x Dw

)]

Where:D

w = water depth in feet.

0.41 psi/ft. = pressure gradient for control uid (water and watersoluble oil) using a specic gravity of the mixture

s= 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.





REV 7: AUG 20096 - 52

Only packing elements which are supplied by the manufacturer of the annularpreventer should be used. New or repaired units obtained from other service

companies 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)

IDENTIFICATION PACKING UNIT OPERATING DRILLING FLUID

TYPE Colour Code TEMP RANGE

COMPATIBILITY

NATURALBlack NR -30°F – 225°F Waterbase Fluid

RUBBER

NITRILERed

NBR20°F – 190°F

Oil base/Oil RUBBER Band Additive Fluid

NEOPRENE GreenCR -30°F – 170°F Oil Base Fluid

RUBBER 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 Open

6 3,000 2.9 2.2 4.6 3.2

6 5,000 3.9 3.3 4.6 3.2

7 1/16 10,000 9.4

8 3,000 4.4 3.0 7.2 5.0

8 5,000 6.8 5.8 11.1 8.7

10 3,000 7.5 5.6 11.0 6.8

10 5,000 9.8 8.0 18.7 14.6

11 5,000

11 10,000 25.1

12 3,000 11.4 9.8 23.5 14.7

13 5/8 3,000 13 5/8 5,000 18.0 14.2 19.8 19.8 8.2 23.6 17.4

13 5/8 10,000 34.5 24.3 47.2 37.6

16 2,000 17.5 12.6

16 3,000 21.0 14.8

16 3/4 3,000

16 3/4 5,000 28.7 19.9 33.8 33.8 17.3 33.0 25.6

16 3/4 10,000

18 2,000 21.1 14.4

18 3/4 5,000 44.0 44.0 20.0 48.2 37.6

20 2,000 32.6 17.0

20 3,000

20 5,000 58.0 58.0 29.5 61.4 47.8

30 1,000 30 2,000





REV 7: AUG 2009 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 coverand dual wedge cover models. There are also special lightweight models forairlifting and Arctic models for low temperature service.

Figure 6.2.13 SHAFFER ANNULAR





REV 7: AUG 20096 - 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 theBOP. This bottle should be precharged to 500 psi for surface installationsand to 500 psi plus 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 meetany given situation.

The hydraulic operating uid should be hydraulic oil with a viscosity between200 and 300 SSU at 100°F If necessary, a water-soluble oil such as Koomey K-90and water can be used for environmental protection. If equipment is exposedto freezing 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.If water-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





REV 7: AUG 2009 6 - 55


OPERATING REQUIREMENTS

Sphericals have relatively simple operating requirements compared to otherannulars. When closing on stationary pipe, 1,500 psi operating pressure issufcient in most applications. Recommended closing pressures for specicapplications are given in the table at the bottom of the page.

Closing action begins when hydraulic uid is pumped into the closing chamber ofthe Spherical BOP below the piston (top drawing next page). As the piston rises,it pushes the element up, and the element’s spherical shape causes it to close in at

the top as it moves upward.

The element seals around the drill string as the piston continues to rise (middledrawing). Steel segments in the element move into the well bore to support therubber as 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 (bottom drawing). At completeshutoff, the steel segments provide ample support for the top portion of therubber. This prevents the rubber from owing or extruding excessively when

conning high well 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 elementlife, it is 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 toa value sufcient 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 beincrementally increased to prevent excessive leakage.





REV 7: AUG 20096 - 56

Figure 6.2.15

OPENING PORT

OPENING PORT

OPENING PORT

CLOSING PORT

CLOSING PORT

CLOSING PORT





REV 7: AUG 2009 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

STARBOARD

VENT

CLOSED

OPEN

LOWER PACKING

ELEMENT CLOSEDWHEN DIVERTER

IS OPERATED

UPPER "WORKING"

PACKING ELEMENT

PRESSURE BELOWDIVERTER BAG

SLIP JOINT

ANNULUS

PRESSURE

SLIP JOINT

UPPER ELEMENT

BLEEDADJUST

RIG AIR

SLIP JOINT

UPPER ELEMENT

ADJUST

RELAX

PRESSURIZE





REV 7: AUG 20096 - 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





REV 7: AUG 2009 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





REV 7: AUG 20096 - 60

Figure 6.3.3 Example diverter with annular packing element





REV 7: AUG 2009 6 - 61

Figure 6.3.4 Example diverter with insert - type packer





REV 7: AUG 20096 - 62

Figure 6.3.5 Example diverter with rotating stripper





REV 7: AUG 2009 6 - 63

Figure 6.3.6 Example diverter systems - Integral sequencing





REV 7: AUG 20096 - 64

If an Annular Sequencing Device which requires lockdown of an insert packer is in use,the lockdown function should be included in the automatic sequencing.

Figure 6.3.3

CLOSE

DIVERTER

CLOSE

DIVERTER

OPEN

VENTVALVE

ACTUATOR

FLOWLINE

VALVE

ACTUATOR

ANNULAR

SEALING

DEVICE

CLOSE

OPEN

DIVERTED ANNULAR

SEALING DEVICE

OPERATING PRESSURE

VALVE

OPERATING

PRESSURE

CLOSE

OPEN

OPEN





REV 7: AUG 2009 6 - 65

Figure 6.3.4

When drilling surface hole from a template the cuttings are returned to surface fordisposal to avoid spool build up on the template.

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





REV 7: AUG 20096 - 66

Figure 6.3.5

Sub-sea diverting stack (template operations).

21 in HST RISER COUPLING PIN

MUD BOOST LINECONNECTION

21 1/4 in – 2000 MSP ANNU-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





REV 7: AUG 2009 6 - 67

Figure 6.3.6 (SURFACE DIVERTER)





REV 7: AUG 20096 - 68

Figure 6.3.7 (MSP DIVERTER/BOP)





REV 7: AUG 2009 6 - 69

Figure 6.3.8

P I L O T C O N T R O L L I N E

T O D

R I L L I N G C

O N S O L E

A C C U M U L A T O R B A N K R

E G U L A T E D

H Y D R U A L I C

S U P P L Y

V E N T

R i s e r

G P L G

R i s e r

G P L G

R i s e r

G P L G

R i s e r

D i v e r t e r

T O S

H A L E

S H A K E R

M U D P U M P

R I G F

L O O R

B e l l

N i p p l e

D i v e r t e r

U p p e r

F l e x

J o i n t

V E N T

M U D G A S

S E P E R R T O R

F R O M D

R I L L I N G

C H O K E M A N I F O L D

R I S E R D

I V E R T E R M A N I F O L D

( N E A R D

R I L L I N G M

A N I F O L D )

1 2 " Ø B

E L L N I P P L E D I V E R T E R O

V E R B O A R D L I N E

6 " Ø R

I S E R D I V E R T E R O V E R B O A R D L I N E

R I S E R C H O K E L I N E

O

P E N C O N T R O L L I N E

C L

O S E C O N T R O L L I N E

Q U I C K C O N N E C T

C O U P L I N G

6 " D R A P E H O S E

C H O K E D R A P E H O S E

K I L L D R A P E H O S E

R I S E R

D I V E R T E R

J O I N T

R I S E R B O O S T L I N E

O U T E R

B A R R E L

T E L E

S C O P I C J O I N T

I N N E R

B A R R E L

M O O N P

O O L

1 6 " Ø

6 " Ø

6 " Ø

3 " Ø

3 " C H O K E

3 " Ø

6 " Ø

1 2 " Ø

6 " Ø





REV 7: AUG 20096 - 70

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.





REV 7: AUG 2009 6 - 71

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 oor of annulusuid level.

Figure 6.3.10

KELLY BUSHING

DRIVE BUSHING

ASSEMBLY

SWING-BOLT

CLAMP ASSEMBLY

SHOCK PAD

BOWL

STRIPPER RUBBER

DRIVE RING AND

BEARING ASSEMBLY

OUTLET FLANGE

INLET FLANGE





REV 7: AUG 20096 - 72

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 anges, 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 developa leak unless the ange bolting is periodically tightened. Standard procedure withtype ‘R’ joints in the BOP stack is to tighten the ange bolting weekly.

Figure 6.4.1 Figure 6..4.2

CL CL

ENERGISED





REV 7: AUG 2009 6 - 73

Figure 6.4.3





REV 7: AUG 20096 - 74

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 contact between 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 contact

between the hubs or anges. 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 6.4.5

CLCL

ENERGISED





REV 7: AUG 2009 6 - 75

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 anges, the groove and gasket tolerances which are adopted are such that,if the 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

be very difcult to achieve. Without face-to-face contact, vibration and externalloads can cause plastic deformation of the ring, eventually resulting in leaks. Bothanged and clamp hub ‘BX’ joints are equally prone to this difculty. 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 anges is seldom achieved.

Figure 6.4.6 Figure 6.4.7 Figure 6.4.8

C

LCL

CL

ENERGISED





REV 7: AUG 20096 - 76

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 contact between 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 ats, the joint may leak.

This type of gasket has not been accepted by the industry and is seldom used.


CL

ENERGISED

CL





REV 7: AUG 2009 6 - 77

‘CIW’ Type ‘RX’ Pressure-Energised Ring Joint Groove

CIW modied 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 modied 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.


CL L





REV 7: AUG 20096 - 78

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 IDof the gasket is smooth and is almost ush 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 being madeup. The OD of the gasket is grooved. This allows the use of retractable pins or dogsto positively retain the gasket in the base of the wellhead or riser connector whenthe hubs are separated. The gasket design allows face-to-face contact between thehubs to be achieved with minimal clamping force. External loads are transmittedentirely through the hub faces and cannot damage the gasket.


CL CL

ENERGISED





REV 7: AUG 2009 6 - 79

‘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 groovesand the OD of the gasket. The gasket is made slightly larger in diameter thanthe grooves, 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 ush 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 is suitable for use through the BOP and riser system, except at the base of thewellhead and riser connectors. The gasket design allows face-to-face contact

between the clamp hubs or anges to be achieved with minimal clamping force.External loads are transmitted entirely through the hub faces and cannot damagethe gasket.






REV 7: AUG 20096 - 80

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





REV 7: AUG 2009 6 - 81

Figure 6.4.18





REV 7: AUG 20096 - 82

Figure 6.4.19





REV 7: AUG 2009 6 - 83

Figure 6.4.20 SPECIFICATIONS FOR BOP FLANGES, RING GASKETS, FLANGEBOLTS AND NUTS

R A T I N G O F B O P

A P P R O

V E D *

M A X I M U M B O L T * * M I N I M U M N U T

S T

A C K

A P P R O V E D F L A N G E S

R I N G G

A S K E T S

S T R E N G T H

S T R E N G T H

2 0 0 0

p s i w p

A P I T y p

e 6 B w i t h

A P I T

y p e

A S T M G r a d

e

A S T M G r a d e

a n d

3 0 0 0 p s i w p

T y p e R

F l a t B o t t o m

R X

B - 7

2 H

I n s t a l l a t i o n s

G r o o v e

5 0 0 0

p s i w p

A P I T y p

e 6 B w i t h

A P I T y p e R X o r

A S T M G r a d

e

A S M E G r a d e


T y p e R

F l a t B o t t o m

A P I T y p e B X w p

B - 7

2 - H

G r o o v e

o r A P I T y p e

T y p e 6 B X F l a n g e

6 B X w /

T y p e B X G r o o v e

1 0 , 0 0 0 p s i w p

A P I T y p

e 6 B X w i t h

A P I T y p e

A S T M G r a d

e

A S T M G r a d


T y p e B X

G r o o v e

B X

B - 7

2 - H

A l l b

l o w o u t p r e v e n t e r s , d r i l l i n g

s p o o l s , a d a p t e r a n g e s w i l l b e f u r n i s h e d w i t h t h e s p e c i

c A P I r i n g j o i n t a n g e

e q u i

p m e n t l i s t e d b e l o w :

*

A c c e p t a b l e m a t e r i a l f o r a n

g e r i n g g a s k e t s a s p e r A P I S p e c 6 A , " W e l l h e a d E q u i p m e n t " .

S w e e t O i l

-

L o w C a r b o n S t e e l

S o u r O i l o r G a s

-

T y p e 3 1 6 s t a i n l e s s s t e e l p r e f e

r r e d b u t T y p e 3 0 4 s t a i n l e s s s t e e l a c c e p t a b l e e x c e p t

f o r h i g h r i s k H 2 S w e l l s .

* *

I n s o m e H 2 S a p p l i c a t i o n s , A

S T M A - 1 9 3 G r B / M w i t h a m a x i m u m R o c k w e l l h a r d n e s s o f 2 2 m a y b e a c c e p t a b l e .

I f u s e d , a n g e s s h o u l d b e d e r a t e d p e r T a b l e 1 . 4 B o f A P I

6 A .





REV 7: AUG 20096 - 84

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 and audioalarm should be installed at the Driller’s station.

The following measurement devices are required for all tanks:

• A oat for the PVT system, to isolate other oats 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 oat in the tank to the scale on therig oor.

b) Flow line Measurement

A device should be provided for measurement of ow 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 ll 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 mud

system to prevent inadvertent loss or gain of mud from the trip tank due to valves being left open.

In the past, many blowouts occurred due to swabbing or not keeping the holelled while tripping the drill string out of the hole. To provide exact uidmeasurements for pipe displacement, trip tanks were developed to accuratelymeasure within ± 1.0 barrel the inux or efux of uid from the wellbore. As thedrill string is pulled from the hole, the mud level will drop due to the volumeof metal 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 value less than formation pressure.





REV 7: AUG 2009 6 - 85

Figure 6.5.1

10

20

3040 50 60

70

80

90

1000 %RETURN

MUDFLOW

HIADJUST

LOADJUST

LOFLOW

HIFLOW

ON

2 AMPSMOOTHING

LOMED

HI

RECORDERRETURN

WARNING

RETURNFLOWHI-LO

WARNING

FLOWSENSOR

115 VAC

REMOTEINDICCTOR

HORN

WARNINGLIGHTS(Optional)

FROM MVT4RETURN MUDFLOW SYSTEM (Optional)

115VAC

H1240 WARNING SYSTEM

LINE

MFT2 MUD FLOW SENSOR

MUD

FLOO

MFS 3 - Series RETURN MUD FLOW SYSTEM

MFR2 or MFRE2RECORDER(Optional)

MFC3 CONTROL CONSOLE

10

20

30

40 50 60

70

80

90

1000

H1268 WARNINGSYSTEM HORN

MVR2 ELECTRONIC

RECORDER (Optional)MFCX RETURN MUD FLOW AND

PUMP STROKE SENSOR CONSOLE

MFTX2 FLOW SENSORASSEMBLY

H1234A PUMPSTROKE SENSOR

H1267 WARNING SYSTEMCONTROL BOX

MFSX2 MUD FLOW FILL SYSTEM

Figure 6.5.2





REV 7: AUG 20096 - 86

To prevent loss of hydrostatic pressure it is necessary to ll the hole on a regularschedule, or continuously, using a trip tank to keep the track of the uid volume

required. The metal volume of the pipe being pulled can be calculated, but mudadditions necessary to replace hole seepage losses due to ltration effects canonly be predicted by comparison with the mud volumes required to keep the holeproperly lled 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 lls the hole through a line into the bell nipple. The pump runs constantly

while 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 ow line. A valve must be installed in the ow line downstream of this outletto block all ow to the shale shakers while making a trip. A closed circulationsystem can be monitored by a oat 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 from

the drilling uid. 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 eld 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 back pressure, generally 50 psi or less. Pressurised separators are utilisedto overcome line pressure losses when an excessive length of vent line isrequired to safely are 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 H

2S areas and for drilling underbalanced in areas

where high pressure, low volume gas continually feeds into the circulatinguid.





REV 7: AUG 2009 6 - 87

During well control operations, the main purpose of a mud gas separator is tovent the gas and save the drilling uid. This is important not only for economic

reasons, 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 amountof mud 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 uidthat the separator can safely handle. For production operations, gas oil separatorscan be sized and internally designed to efciently separate gas from the uid.This is possible because the uid and gas characteristics are known and designow rates can be readily established. It is apparent that ‘gas busters’ for drillingrigs cannot be designed on the same basis since the properties of circulateduids from gas kicks are unpredictable and a wide range of mixing conditionsoccur downhole. In addition, mud rheological properties vary widely and have astrong effect on gas environment. For both practical and cost reasons, rig mud gasseparators are not designed for maximum possible gas release rates which might

be 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 ow must be bypassed around the separator directly to theare line. This will prevent the hazardous situation of blowing the liquid from the

bottom 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 bafe 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 contactsthe internal wall of the separator, which provides a method of inspectingplate wear.

• A U-tube arrangement properly sized to maintain a uid head in theseparator.





REV 7: AUG 20096 - 88

Figure 6.5.3

ROTARY TABLE

DIVERTER

RIG FLOORTRIP TANK

LEVEL

INDICATOR

HOLE FILL

UP LINE

FLOWLINE

TELESCOPIC

JOINT

RISER

CHECK

VALVE

TRIP TANK PUMPDRAIN

FROM

MISSION PUMPS

RETURNS TO

SHAKERS

OVERBOARD

REMOTE

CONTROL VALVE

GAS OUTLET8" ID MINIMUM

GAS BACK PRESSUREREGISTERED ATTHIS GAUGE(Typically 0 to 20 psi)

INSPECTIONCOVER

STEELTARGET PLATE

INLET

30" OD

SECTION A-A

TANGENTIAL 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

1 0 ' A P P R O X

INSPECTIONCOVER

A

A P

P R O X 1 / 2 O F H E I G H T

1 0 ' M I N I M U M H

E I G H T

Figure 6.5.4 An Example Mud Gas Separator





REV 7: AUG 2009 6 - 89

The height and diameter of an atmospheric separator are critical dimensionswhich affect the volume of gas and uid the separator can efciently 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 uid level allows time for additional gas break-outand provides an allowance for the uid to rise somewhat during operationto overcome friction loss in the mud outlet lines. As shown in Figure 6.5.4, thegas-uid 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 uid retention. The 30 in. diameter and 16 ft minimum vesselheight requirements have proven adequate to handle the majority of gas kicks.The separator inlet should have at least the same ID as the largest line from thechoke manifold, which is usually 4 in. Some separators use tangential inlet, which

creates a small centrifugal effect on the gas-uid mixture and causes faster gas break-out.

The bafe system causes the mud to ow in thin sheets which assists theseparation process. There are numerous arrangements and shapes of bafes 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 volumeof low 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 should

be bent outward about 30 degrees to direct gas ow away from the rig oor. If it isintended that the gas be ared, ame 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 uid seal in the bottom is lost andgas starts owing into the mud system. The mud outlet downstream of the U-tube

should be designed to maintain a minimum vessel uid level of approximately3 1/2 ft in a 16 ft high separator. Assuming a 9.8 ppg mud and total U-tubeheight of 10 ft, the uid seal would have a hydrostatic pressure equal to 5.096 psi.This points out the importance for providing a large diameter gas vent line withthe fewest 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.





REV 7: AUG 20096 - 90

Degassers

If a uid'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 uid is small. Degassers separateentrained gas from uid 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 difcult. Primarily, it is a matter of correctlylubricating any pumps used in the system. In degassers that employ a oat 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 mudsfrom which it is difcult 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





REV 7: AUG 2009 6 - 91

Choke Manifolds

The choke manifold is an arrangement of valves, ttings, lines and chokeswhich provide several ow routes to control the ow of mud, gas and oil fromthe annulus 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





REV 7: AUG 20096 - 92

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





REV 7: AUG 2009 6 - 93

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 Turns to 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 specications conform to API standard 6A

National Gate Valves are available with anged 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 specify

quantity, size, working pressure, end connection, body and trim materials, andservice conditions (such as temperature, pressure, and composition of owmaterial).

E

A

C

B

C





REV 7: AUG 20096 - 94

Figure 6.5.11 - Components 113 / 16

" thru 21 / 16

" 15,000 psi

Body

GreaseFitting

Gate

SeatAssembll

Hub Seal Clevis Pin

ClevisNut

Stem

PlasticPackingInjection

Fitting

PlasticPacking

Packing Header Ring

Stem 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





REV 7: AUG 2009 6 - 95

Figure 6.5.12 - Type ‘HCR‘ pressure operated gate valve

The type ‘HCR‘ pressure operated gate valves is a ow 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 anges.





REV 7: AUG 20096 - 96


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 without

disconnecting the valves. These valves may be equipped with either hydraulicor pneumatic 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.





REV 7: AUG 2009 6 - 97

Fail Safe Valves

High pressure choke and kill lines run from the stack to the choke manifold onthe rig oor. To shut these lines off when not required, each is equipped with twofail safe 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 rst 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 (g 6.5.15) ow 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 uid. 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 uid 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 uid

exhausted from the pressure chamber when opening the valve, away from theneighbouring valve.





REV 7: AUG 20096 - 98

Figure 6.5.15

Woodruff key

Locking ring

Sea water hydrostatic pressure

Sea water hydrostatic

pressure equalizing port

ClampRing

"J" Packing

Vent "O" ring

"J" Packing

Junk ringRetainer ring

Pin

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 inlet

Retainer ring

Piston

Set screw

"O" Ring

Spring cartridge assembly

Resilient sleeve

Sleeve

Ring

Pipe plug

Anti-extrusion ringBonnet stud

Bonnet nut

Bonnet

Gate and seat assembly

Body





REV 7: AUG 2009 6 - 99

Figure 6.5.16





REV 7: AUG 20096 - 100

Figure 6.5.17





REV 7: AUG 2009 6 - 101

K Choke Beans and Wrenches

• Flared Orice 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 xed orice diameter. The combination bean has a xeddiameter and a throttling taper at the entry. The combination bean is used with anadjustable choke needle to make incremental changes to orice sizes smaller than

the xed orice.

The part numbers of the positive and combination beans are determined bydesired orice size. K1 positive bean orice sizes range from 4/64" to 64/64"/ Partnumbers for K1 positive beans are available on request. K2 positive bean oricesizes range from 4/64" to 128/64". The part number for K2 positive bean is626397-( )-( ). The dash numbers indicate desired orice size; for example,626397-01-10 is a 110/64" diameter orice. K3 positive bean orice 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 beansizes range form 6/64" to 128/64". The part number for the K2 combination beanis 626396-( )-( ). 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.





REV 7: AUG 20096 - 102

6.6 INSIDE BOP'S

Drill Pipe Float Valves

The drill pipe oat valve and the apper 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 uid ow 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 should

be the deciding factor regarding what type of valve to run or the possibility ofnot running any valve at all. Expectations of abnormal pressures have shown thevented type of apper valve to be the most popular because of the ease involvedin recording shut-in drill pipe pressures. The disadvantages are that the pipe must

be lled while tripping in, and reverse circulation is not possible.

Figure 6.6.1





REV 7: AUG 2009 6 - 103

Figure 6.6.2 - Kelly Cock Figure 6.6.3 - Gray Valve

Figure 6.6.4

Installing a drop in dart or checkguard improveswell control signifcantly. It serves as a check valveto prevent upward ow through the drill stringwhile permitting downward mud pumping or owfrom injectors.

While stripping drill pipe into the hole,

Checkguard control upward pressure in theannulus and in the drill pipe. Latching the checkvalve into the landing sub contains the pressure inthe drill pipe.

Prior to shearing drill pipe, install the checkvalve to protect against the release of wellpressures. Installation of the check valve simplieswell control, since formation pressures cannotcommunicate up the drill string.

While tripping, Checkguard contains upward well bore pressure in the drill pipe, allowing the topconnection to be open.

RELEASE TOOL

VALVE SEAT

VALUE

RELEASE ROD

VALVE SPRING

Upper Seat

Ball

Lower Seat

Crank

Body





REV 7: AUG 20096 - 104

Checkguard uses a spring and ball design. Fluid can be pumped through thevalve from the top. But when uid tries to ow from the bottom to the top, it is

sealed by the spring-loaded ball against the seat.

A large rubber packer provides sealing when uid attempts to ow 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. Positionthe landing sub in the lower end of the drill string. Ensure dart and sub arecompatable before running landing sub. Ensure no smaller I.D.'s above landing

sub.

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 ow 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.





REV 6: JAN 2008

SECTION 7

INSPECTION, TESTING AND SEALING COMPONENTS

7A Inspection and Testing - Surface Installations

7B Inspection and Testing - Subsea Installations

7C Sealing Components - Surface Installations

7D Sealing Components - Subsea Installations




SECTION 7 : INSPECTION & TESTING

REV 7: AUG 2009 7 - 1

SECTION 7-A

INSPECTION AND TESTING - SURFACE INSTALLATIONS

FIELD ACCEPTANCE INSPECTION AND TESTING

7.A.1 The eld 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 specications. This clearance is dependent on

type, 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.





REV 7: AUG 2009 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 uid 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 pressureto open rams and check for uid 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

psi operating pressure and apply pressure under rams to 200-300 psi with blowout 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 specications.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 and

blowout 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.





REV 7: AUG 2009 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 the

closing chamber and opening chamber by closing preventer and applyingmanufacturer’s recommended closing pressure. If other chambers are located between 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 uid 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 uid is coming out of the opening chamber opening, indicating theseal between the closing chamber and opening chamber is leaking,proceed to step 5.





REV 7: AUG 2009 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 wellbore by 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 open

valve. 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, apply

manufacturer’s recommended opening pressure. If pressure holds,refer to step 21.

b) If pressure does not hold and no uid is running out of theclosing chamber opening, the seal between the opening chamberand the piston is leaking. Verify this visually. Refer to step 21.

c) If uid is coming out of the closing chamber opening, indicatingthe seal between the opening chamber and the closing chamber isleaking, proceed to step 17.

17) Release opening pressure.





REV 7: AUG 2009 7 - 5

18) Install closing line and block ow (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 annular

preventer 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 up

between 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 uid to preventfreeze-up in cold weather, some other method should be devised to ensuremanifold, lines, and assembly are not plugged.





REV 7: AUG 2009 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, operate

these 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 be

hydraulically 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.





REV 7: AUG 2009 7 - 7

TABLE 7-A

Test Pressure Recommendations Preventer Equipment Tested

Blowout preventer stack rated working pressure(or as specied in Notes below.)

1. Entire blowout preventer stack.2. All choke manifold components upstream of chokes.3. All kelly valves, drill pipe, and tubing safety valves.4. Drilling spools, intermediate casingheads, and sideoutlet valves.

Rated working pressures of preventers or 3000psi. whichever is less

1. Closing unit valves and manifold2. 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 orcomponents

1. Choke manifold components downstream of chokes

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 ange of the annular preventer. A companiontest ange 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,

but limited to the lesser of the rated working pressure of the wellhead or 70percent of the minimum internal yield pressure of the upper part of the casingstring: however, in no case should these or subsequent test pressures be lessthan the expected surface pressure. An exception is the annular preventer whichmay be tested to 50 percent of its rated working pressure to minimise pack-offelement wear 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.





REV 7: AUG 2009 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 preventer (greyvalve) should be tested to the same pressure as the blow out preventer stack at thesame time the preventer assembly tests are made. This equipment should be tested

with pressure 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 uidconditions 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.





REV 7: AUG 2009 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 bottom blowout preventer ange. 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 t 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.1

and 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 or

below 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.A cup type pressure element holds pressure from above. Some models (referto Fig. 7.A.1) contain a back pressure valve to bypass uid when going inthe hole. 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 sufcient 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

for Drill 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), ora box and 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 ttings 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 ram testsub can be made by welding tool joint connections on the ends of a short length of

casing of desired diameter.

*Available from American Petroleum Institute. Production Department. 2535 One Main Place, Dallas TX 75202-3904.





REV 7: AUG 2009 7 - 10

Figure 7.A.1 Figure 7.A.2 HANGER TYPE TEST PLUG HELD IN HANGER TYPE TEST PLUG HELD IN PLACE WITH LOCKING FLANGE PLACE WITH CASINGHEAD

LOCK SCREWS LOCK SCREWS

EXAMPLE OF HANGER TYPE TEST PLUGS

Figure 7.A.3 Figure 7.A.4

EXAMPLE CUP TYPE TEST PLUGS

LOCKING FLANGE

MUST BE REMOVED

BEFORE NEXT

SECTION OFWELLHEAD

IS INSTALLED

MANDREL

SNAP PLUGS

90° SPACING

RETAINING NUT

RETAINING PLATE

PRESSURE SEAL

SIZE PLATE

TAPPED FOR 1"

SNAP PLUGS

90° SPACING

LOWER VALVE

RETAINING SLEEVE

SNAP

BAR

CUP

SUB

'O' RING

MANDREL





REV 7: AUG 2009 7 - 11

S T E E L P L A T E

( W E L D E D T O C A S I N

G S U B

A N D T O O L J O I N T B O X )

S T E E L P L A T E

( W E L D E D T O C A S I N G S

U B

A N D T O O L J O I N T B O X )

T O O L J O I N T P I N T O

M A T C H T E S T P L U G

W E E P H O L E

C A S I N G S U B O F

S U F F I C I E N T L E N G

T H T O

T E S T C A S I N G R A M S

T O O L J O I N T B O X T O

M A T C H T E S T J O I N T

1 " O R L A R G E R V A L V E

W E E P H O L E

F I G . 7 . A . 5

E X A M P L E T E S T J O I N T

F I G . 7 . A . 6

E X A M P L E C A S I N G R A M T

E S T

S U B





REV 7: AUG 2009 7 - 12

SECTION 7-B

INSPECTION 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 utilising

procedures 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

be repeated and properly recorded in the well log. Test record should include

opening and closing times and hydraulic uid 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. These ramsneed only be tested when installed and prior to drilling out after each casing stringhas been set. A record of these tests should be maintained in the well log andshould include closing and opening times and pressures and volumes of hydraulicuid 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





REV 7: AUG 2009 7 - 13

more than once every week. On installation of the blowout preventer stack,each component including the high pressure connectors should be individually

pressure 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 upperpart of the casing. An exception is the annular preventer which may be testedto 50 percent of its rated working pressure to minimise pack-off element wearor damage. 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 the

casing in the event the test tool seals leak. Actuation testing of pipe rams should not be performed 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 systemis dependent on water depth and environmental conditions and should have anadequate backup system to operate each critical function. It is equally importantto pressure and operationally test this system concurrently with the blowoutpreventers and connectors.





REV 7: AUG 2009 7 - 14

SECTION 7-C

SEALING 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-Joint Pressure 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 -

263/

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 -

263/

4 26

3/4 - -

5,000 (5 M) 6 7 1/16

46 - 10 11 54 -

13 5 /8 13 5/8 - 160 16

3/4

16 3/

4 - 162‡

18 3/4 18 3/

4 - 163

211/

4 21

3/4 - 165

10,000 (10 M) 7 1/16

71/

16 - 156

9 9 - 157 11 11 - 158 13

5/8 13

5/8 - 159

163/

4 16

3/4 - 162

18 3/4 18 3/

4 - 164

211/

4 21

1/4 - 166

15,000 (15 M) 71

/16 7

1

/16 - 156 9 9 - 157 11 11 - 158 13

5/8 13

5/8 - 159

20,000 (20 M) 7 1/16

71/

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) angein lieu of 5000 psi rated working pressure (7500 psi test pressure) ange in June 1969.





REV 7: AUG 2009 7 - 15

SECTION 7-D

SEALING 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 forspecications 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

be energised 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 the

integral 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 should

be 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.





REV 6: JAN 2008

8.0 BOP and Control Systems

8A Closing Units - Surface Installations

8B Closing Units - Subsea Installations

SECTION 8

SURFACE BOP CONTROL SYSTEMS




SECTION 8 : SURFACE BOP CONTROL SYSTEMS

REV 7: AUG 2009 8 - 1

8.0 SURFACE BOP AND CONTROL SYSTEMS

Figure 8.0.1 Land Rig Operation





REV 7: AUG 2009 8 - 2

TYPICAL SURFACE BOP CONTROL SYSTEMT-SERIES

Figure 8.0.2





REV 7: AUG 2009 8 - 3

TYPICAL SURFACE BOPCONTROL SYSTEM

1. Accumulators - Prechargeper label. 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 every

30 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 pressure

reaches 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 or

Duplex 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 uid pump.

24. Manifold Regulator -Regulates operating pressure toram preventers and gate valves.Manually adjustable from 0to 1500 PSI, TR™ Regulatorcontains internal by-pass forpressures up to 3000 PSI or 5000PSI. (See 39 option)

25. Manifold Regulator InternalOverride Valve - Normallyin low-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 ow ofoperating uid 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 0to 1500 PSI. TR Regulator can

provide 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- 0 to 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 fromthe air operated remote controlpanels.

36. Reservoir - Stores operatinguid 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, fuid 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.





REV 7: AUG 2009 8 - 4

SYSTEM DESCRIPTION

GENERAL

A Blowout Preventer (BOP) Control System is a high pressure hydraulic powerunit tted with directional control valves to safely control kicks and prevent

blowouts during drilling operations. A typical system offers a wide variety ofequipment to meet the customer’s specic 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 uid supply for the pumps and storageof the high pressure operating uid for control of the BOP stack. It includesaccumulators, reservoir, accumulator piping and a master skid for mounting ofthe air operated pumps, electric motor driven pumps and the hydraulic control

manifold. Accumulators

Accumulators are ASME coded pressure vessels for storage of high pressureuid. These accumulators are available in a variety of sizes, types, capacities andpressure ratings. The two (2) basic types are bladder and oat which are availablein cylindrical or ball styles. The accumulators can either be bottom or top loading.Top loading means the bladder or oat can be removed from the top while it isstill mounted on the accumulator unit. Bottom loading accumulators must beremoved from the accumulator unit to be serviced. Bladder and buoyant oattype accumulators can be repaired in the eld without destroying their stamp ofapproval.





REV 7: AUG 2009 8 - 5

Reservoir

A rectangular reservoir is provided for storage of the atmospheric uid supplyfor the high pressure pumps. It contains bafes, ll and drain ports andtroubleshooting inspection ports. For lling and cleaning procedures see theMaintenance section. It should be able to store 2 times the capacity of the usableuid 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"Schedule 80 or 160 pipe, isolator valves and a 3300 psi relief valve to protect

the accumulators 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 uid for the BOP Control System. These pumps are available ina variety of sizes and ratios.

Figure 8.0.4





REV 7: AUG 2009 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 uid for theBOP Control System. It is available in a variety of horsepower and voltage ranges.

Figure 8.0.5





REV 7: AUG 2009 8 - 7

SECTION 8.ACLOSING UNITS - SURFACE INSTALLATIONS

ACCUMULATOR REQUIREMENTS

General

8.A.1 Accumulator bottles are containers which store hydraulic uid 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 oat types. The separator type uses a exible diaphragm toeffect positive separation of the nitrogen gas from the hydraulic uid. The oat

type utilises a oating piston to effect separation of the nitrogen gas from thehydraulic uid.

Volumetric Capacity

8.A.2 As a minimum requirement, all blowout preventer closing units should beequipped with accumulator bottles with sufcient volumetric capacity to providethe usable uid 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 uid volume is dened as the volume of uid 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 uid.

8.A.4 The minimum recommended accumulator volume (nitrogen plus uid)should be determined by multiplying the accumulator size factor (refer toTable 8-A) times the calculated volume to close the annular preventer and one piperam plus the volume to open the hydraulic choke line valve.

TABLE 8. A

Minimum Accumulator Recommended Usable Fluid Accumulator Operating Precharge Volume* Size Pressure Pressure (fraction of Factor* psi psi bottle size)

1500 750 1/8 8

2000 1000 1/3 3

3000 1000 1/2 2

Notes: *Based on minimum discharge pressure of 1200 psi.





REV 7: AUG 2009 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 measured

during 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

the open 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 ttings should be provided on each accumulator bank 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 sufcient 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.





REV 7: AUG 2009 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 unitat all 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 each

closing 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 dual sourcepower system recommended is an air system plus an electrical system. Minimumrecommendations for the dual air system and other acceptable but less preferreddual 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.





REV 7: AUG 2009 8 - 10

REQUIREMENTS FOR CLOSING UNIT VALVES FITTINGS, LINES, ANDMANIFOLD

Required Pressure Rating

8.A.15 All valves and ttings 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:Specication for Wellhead Equipment* for test pressure requirements. All lines

between the closing unit and blowout preventer should be of steel constructionor an equivalent exible, re-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 uid pump can be easily connected (refer toFig. 8.A.1).

b. Each closing unit should be equipped with sufcient check valves or shut-offvalves to separate both the closing unit pumps and the accumulators from

the 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 the

blind rams should be equipped with a cover over the manual handle to avoidunintentional operation.





REV 7: AUG 2009 8 - 11

g. Each annular preventer may be equipped with a full-opening plug valveon both the closing and opening lines. These valves should be installed

immediately 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 uid (hydraulic oil or fresh water containing alubricant) should be used as the closing unit control operating uid. Sufcient

volume of glycol must be added to any closing unit uid containing water ifambient temperatures below 32 F are anticipated. The use of diesel oil, kerosene,motor oil, chain oil. or any other similar uid is not recommended due to thepossibility of resilient seal damage.

8.A.18 Each closing unit should have a uid reservoir with a capacity equal to atleast twice the usable uid 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 whichis easily accessible to rig personnel in an emergency. It should also be located toprevent excessive drainage or ow 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 ow back in the closing lines.

8.A.20 Each installation should be equipped with a sufcient number of controlpanels such that the operation of each blowout preventer and control valve can

be controlled from a position readily accessible to the driller and also from an

accessible point at a safe distance from the rig oor.





REV 7: AUG 2009 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 uid, foreign uid, rocks, or otherdebris. The closing unit pump capability test should be conducted on each well

before pressure testing the blowout preventer stack. This test can be convenientlyscheduled either immediately before or after the accumulator closing time test.Tests 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 systemfrom the pumps. A separate closing unit air storage tank or a bank ofnitrogen bottles should be used to power the pumps during this test. Whena dual power 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 to theopening position.

e. Record the time (in seconds) required for the closing unit pumps to closethe annular preventer plus open the hydraulically operated valve andobtain 200 psi above the precharge pressure on the closing unit manifold.It is recommended 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 hydraulicuid into the closing unit uid reservoir.

b. Measure the nitrogen precharge pressure on each accumulator bottle, usingan accurate pressure gauge attached to the precharge measuring port, andadjust if necessary.





REV 7: AUG 2009 8 - 13

Accumulator Closing Test

8.A.23 This test should be conducted on each well prior to pressure testing the blowout 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 forone pipe 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 nal accumulator pressure(closing unit pressure). This nal 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.





REV 7: AUG 2009 8 - 14

F i g u

r e 8 . A . 1

E X A M P L E B L O W

O U T P R E V E N T E R

C L O S I N G U N I T A R R A N G E M E N T

P U M P

P U M P B

L O W O U T

P R E V E N T E R

T E S T L I N E

T E S T

F L U I D

L I N E

N E E D

L E V A L V E S

A C C U

M U L A T O R

B

A N K S

F U L L - O P E N I N G V A L V E S

P R E S S U R E R E G U L A T O R

( 1 5 0 0 - 3 0 0 0 P S I )

V A L V

E

A N D G A U

G E

R E L I E F

V A L V E F

U L L O P E N I N G V A L V E

C O N N E C T I O N F O R

A N O T H E R P U M P

P R E S S U R E R E G U L A T O

R

( 0 - 1 5 0 0 P S I )

V A L V E A N D

G A U G E

N O T E :

P L U G V A L V E I N C L O S I N G

L I N E A D J A C E N T T

O A N N U L

P R E V E N T E R T O F

A C I L I T A T

L O C K I N G C L O S I N

G P R E S S

O N P R E V E N T E R .

T O A N N U L A R

B L O W O U T

P R E V E N T E R

T O C H O K E

L I N E V A L V E

T O R A M

B L O W O U T

P R E V E N T E R S

C H E C K

V

A L V E

C H E C K

V A L V E

F O U R - W A Y V A L V E S

( N O T E : S H O U L D N O T C O N T A I N

C H E C K V A L V E A N D S H O U L D

B E I N P O W E R O N P O S I T I O N )

R E

G U L A T O R

B Y

- P A S S L I N E

C O N N E C T I O N F O R

A N O T H E R P U M P

F U L L - O P E N I N G V A L V E

F L U I D

R E S E R V O I R





REV 7: AUG 2009 8 - 15

Figure 8.A.2

EXAMPLE REDUNDANT AIR/ELECTRIC SYSTEMSFOR OPERATING CLOSING UNIT PUMPS

CLOSING

UNIT PUMPS

TO RIG

TO CLOSING UNIT

MANIFOLD AND

ACCUMULATORS

STORAGE TANKFOR RIG AIR

ELECTRICAL POWER SUPPLY

CHECK VALVE

AIR

COMPRESSORS

CLOSING

UNIT PUMPS

TO CLOSING UNIT

MANIFOLD AND

ACCUMULATORS

SEPARATE GENERATOR

RIG GENERATOR

Figure 8.A.3EXAMPLE REDUNDANT ELECTRICAL SYSTEMS

FOR OPERATING CLOSING UNIT PUMPS





REV 7: AUG 2009 8 - 16

Figure 8.A.4EXAMPLE REDUNDANT AIR/NITROGEN SYSTEMS


CLOSING

UNIT PUMPS

NITROGEN

CHECK

VALVE

TO RIG

CHECK

VALVE

STORAGE TANK

FOR RIG AIR

O P T I O N A L

TO CLOSING UNIT

MANIFOLD AND

ACCUMULATORS

CLOSING

UNIT PUMPS

NITROGEN

RIG GENERATOR

OPTIONAL

TO CLOSING UNIT

MANIFOLD AND

ACCUMULATORS

Figure 8.A.5EXAMPLE REDUNDANT ELECTRIC/NITROGEN SYSTEMS






REV 7: AUG 2009 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 (uid 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 uid maximum to minimum pressure.V2-V1 = Total usable uid with safety factor usually 50% included.3000 psi system precharged to 1000 psi; V = 3V1

Figure 8.0.6 ACCUMULATOR SIZINGS





REV 7: AUG 2009 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 uid has been expelled to operate the BOP functions.

In an 11 gallon accumulator bottle the volume of nitrogen it contains before anyuid is pumped in will be 10 gallons (the rubber bladder occupies a volume of1 gallon).

According to Boyle’s gas law:

P1 x V

1 = P

2 x V

2 and also P

1 x V

1 = P

3 x V

3

where:-

P1 = nitrogen precharge pressure of 1000 psi

P2 = minimum operating pressure of 1200 psi

P3 = maximum operating pressure of 3000 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, P

3 (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 gals 1200 psi

and

V3 = 1000 psi x 10 gals = 3.33 gals

3000 psi

The usable volume of hydraulic uid 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





REV 7: AUG 2009 8 - 19

Subsea Accumulators

The nitrogen precharge pressure must be increased in the subsea accumulator bottles in order to account for the hydrostatic pressure of the hydraulic uid inthe power uid supply hose, when calculating the amount of usable uid 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, P

3 (in gals)

therefore:- 1668 psi x 10 gals = 1868 psi x V

2 and 1668 psi x 10 gals = 3668 psi x V

3

giving:- V

2 = 1668 psi x 10 gals = 8.93 gals and V

3 = 1668 psi x 10 gals = 4.55 gals

1868 psi 3668 psi

The usable volume of hydraulic uid per subsea bottle in 1500 ft of water would

be the difference between these two volumes.

V2 - V

3 = 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 uid 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 open

Failsafe valves 0.6 gals to close 0.6 gals to open





REV 7: AUG 2009 8 - 20

Assuming that company policy is to have sufcient 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 uid required to open and close all of the BOPfunctions together will be:

CLOSE OPEN

2 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 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 uid from eachsurface accumulator bottle is 5 gals therefore:

411.1 gals = 82.22 or 83 bottles will be required on surface: 5 gal/bottle





REV 7: AUG 2009 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 be equipped with accumulator bottles with sufcient volumetric capacity toprovide the usable uid volume (with pumps inoperative) to close and open theram preventers and one annular preventer. Usable uid volume is dened asthe volume of uid 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 subsea

temperature 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.

The isolation valves should have a rated working pressure at least equivalentto the designed working pressure of the system to which they are attached. Thevalves must be in the open position except when the accumulators are isolated forservicing, testing, or transporting.

Accumulator Types

8.B.6 Both separator or oat type accumulators (refer to Para. 9.A.l) may be used.





REV 7: AUG 2009 8 - 22

HYDRAULIC FLUID CONTROL MIXING SYSTEM

8.B.7 The hydraulic uid reservoir should be a combination of two storagesections; one section containing mixed uid to be used in the operation of the blowout preventers, and the other section containing the concentrated water-soluble hydraulic uid to be mixed with water to form the mixed hydraulic uid.This mixing system should be automatically controlled so that when the mixeduid reservoir level drops to a certain point, the mixing system will turn on andwater and hydraulic uid concentrate will be mixed into the mixed uid 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 airand electric pumps. A minimum of two air pumps should be in every systemalong with 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 fteen 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.For a 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 uid to subsea equipmentand a 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 uid from the power uid section to operate the blowoutpreventers. Pressure regulators on the surface control manifold send pilot signals

to subsea regulators to control the pressure of the hydraulic uid at the preventers.The surface control system should also include a ow meter which, by a measureof the volume of uid 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 electricallyto the subsea solenoid valves, which direct the ow of hydraulic uid to operatea blowout preventer function. In this system, a ow meter should be used toprovide an indication of the proper ow of hydraulic uid and proper operation of

the blow out preventer.





REV 7: AUG 2009 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 oor adjacent to the driller’s station. This panel should comply withAPI RP 500B: Recommended Practice for Classication of Areas for ElectricalInstallations at Drilling Rigs and Production Facilities on Land and on Marine Fixed and

Mobile Platforms.* Another remote panel is sometimes located in the toolpusher’sofce. 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 uid 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 blowout

preventer stack after drilling out from under the surface casing. Each controlpod should 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 uid between thetwo redundant control pods.





REV 5: JAN 2008

9.1 Subsea BOP Control Systems

9.2 Marine Riser Systems

SECTION 9 SUBSEA BOP CONTROL SYSTEMSAND MARINE RISER SYSTEMS




SECTION 9 : SUBSEA BOP CONTROL SYSTEMS & MARINE RISER SYSTEMS

REV 7: AUG 2009 9 - 1

9 .1 SUBSEA BOP CONTROL SYSTEMS

INTRODUCTION

Every component in a blowout preventer assembly is operated hydraulically by moving a piston up and down or back and forth. Thus the function of a BOPcontrol system is to direct hydraulic uid to the appropriate side of the operatingpiston and to provide the means for uid 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 uid to the required function. It also enables the returning uid to bereturned to the control unit for further use.

For subsea drilling operations, it is necessary to control larger, more complexBOP assemblies which are remotely located on the sea-bed. In this instance, directcontrol cannot be applied since the resulting control lines connecting the BOPs to

the 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 uid to the appropriate BOP function.

The pilot valves are located in control pods on the BOP stack. In order to providea complete 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 uid once it has been used tooperate a function since this would increase the number of lines required in theumbilical. Instead the uid is vented subsea from the control pod.





REV 7: AUG 2009 9 - 2

MULTIPLEX ELECTRO-HYDRAULIC SYSTEM

As greater water depths were encountered the problems of umbilical handlingand reaction times became signicant. In order to overcome them the hydrauliclines controlling 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 uid 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, ve conductors for signal transmission andadditional back-up and instrumentation lines. With the armoured sheath the

umbilical 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, the subseaBOP stack can also be equipped with an acoustic emergency back-up system.In principle this is similar to the other two systems but with the hydraulic orelectrical commands to the pilot valves being replaced with acoustic signals. Beinga purely back-up system the number of commands is limited to those which might

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 onthe BOP 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 oor) 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.





REV 7: AUG 2009 9 - 3

The pilot uid is sent to the subsea control pods through individual, smalldiameter hoses bundled around the larger diameter hose which delivers the

power uid. In order to provide complete redundancy for the subsea portion ofthe control 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 hose

bundles 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 ow system for a stack function. The

hydraulic uid is prepared and stored under pressure in the accumulators. Someaccumulators (usually two) are dedicated to storing uid for use in the pilot linenetwork and the remaining accumulators contain the uid that is used to powerthe various BOP functions.





REV 7: AUG 2009 9 - 4

Figure 9.1





REV 7: AUG 2009 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

ISOLATION VALVE

CHECK VALVE

POD SELECT VALVE

VENT

ISOLATION VALVE

SHUTTLE VALVE

ISOLATION VALVE

SHUTTLE VALVE

REGULATOR

SPMPILOT

SPMPILOT

PILOT psi

ACCUMULAT OR psi

REGULATOR psi

VENT psi

KEY

ACCUMULATORS(POWER FLUID)





REV 7: AUG 2009 9 - 6

The power uid is routed to the subsea control pod selected by the pod selectorvalve which is located in the central hydraulic control manifold. The line to the

non-selected pod is vented. When power uid reaches the pod, it is combined withuid stored at the same pressure in subsea accumulators, located on the BOP stack.The pressure of the combined uid is then reduced, to that required to operatethe stack function, by a subsea regulator situated in the control pod. Adjustmentof this regulator is performed from the surface via dedicated pilot and read-backlines in the hose bundle.

Pilot uid is always directed to both pods at the same time. When the pilot uidfor 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 uid has been sentthis will allow the uid to pass through the SPM valve and be routed to the stack

function 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 ow diagram in Figs 9.3a band c. Each piece of equipment on the BOP stack has a corresponding pilot controlvalve on the central hydraulic control manifold which actuates the appropriate

SPM 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 uid 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 uid 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 uid 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 hydraulicuid from the ‘open’ side of the BOP ram.





REV 7: AUG 2009 9 - 7

Figure 9.3 OPERATING SEQUENCE - GENERAL





REV 7: AUG 2009 9 - 8

Figure 9.3.A OPERATING SEQUENCE - CLOSE FUNCTION

PILOT psi

ACCUMULATOR psi

REGULATOR psi

VENT psi

KEY

CLOSE BLOCK OPEN

MIX WATER TANK

POWER FLUID

ACCUMULATORS

PILOT FLUID

ACCUMULATORS

SOLENOID

VALVE

PILOT CONTROL VALVE

POD SELECT VALVE

AIR

OPERATOR

SOLENOID

VALVE

CONTROL

PANEL

RIG AIR

CLOSESPM

OPENSPM

SHUTTLE VALVE

SHUTTLE VALVE

BOP RAMS

YELLOW POD BLUE PODREGULATOR

INACTIVE POD





REV 7: AUG 2009 9 - 9

Figure 9.3.B OPERATING SEQUENCE - BLOCK FUNCTION

CLOSE BLOCK OPEN

MIX WATER TANK

POWER FLUID ACCUMULATORS

PILOT FLUID ACCUMULATORS

SOLENOID VALVE

PILOT CONTROL VALVE

POD SELECT VALVE

AIR OPERATOR

SOLENOID VALVE

CONTROLPANEL

RIG AIR

CLOSESPM OPENSPM

SHUTTLE VALVE

SHUTTLE VALVE

BOP RAMS

YELLOW POD BLUE PODREGULATOR

INACTIVE POD

PILOT psi

ACCUMULAT OR psi

REGULATOR psiVENT psi

KEY





REV 7: AUG 2009 9 - 10

Figure 9.3.C OPERATING SEQUENCE - OPEN FUNCTION

CLOSE BLOCK

MIX WATER TANK

POWER FLUID ACCUMULATORS


SOLENOID VALVE

PILOT CONTROL VALVE

POD SELECT VALVE

AIR OPERATOR

SOLENOID VALVE

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





REV 7: AUG 2009 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 rst

being 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 ow ofany power uid through the valves. At the same time this also vents both sides of

the 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 uid can then ow down to the subsea control pod where it lifts the

spindle in the RAMS OPEN SPM valve thus blocking the vent and allowing poweruid to ow through the valve. From the pod the power uid travels throughthe ‘open’ shuttle valve to the ‘open’ sides of the BOP ram operating cylinders.Simultaneous reciprocal action in the RAMS CLOSE SPM valve allows the uidfrom the ‘close’ side of the operating cylinders to be vented.

CONTROL FLUID CIRCUIT

In addition to the control uid 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 uid circuit. The hydraulic uid 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 uid is used, it passes through a totalisingow 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 uid supplies the hydraulically operated subsea regulators. These reducethe uids pressure to that required to operate the particular BOP function desired.The uid is also routed to a SPM valve in the pod which is controlled by the

accumulator isolator valve on the hydraulic control manifold. In the open positionthis SPM valve allows the control uid to charge the stack mounted accumulator

bottles. Shuttle valves allow the bottles to be charged from either pod.





REV 7: AUG 2009 9 - 12

Figure 9.4 SUBSEA CONTROL SYSTEM - HYDRAULIC SCHEMATIC

M

FLUIDMIXING SYSTEM

WATERSUPPLY

WATERSOLUBLECONCENTRATE

MIXEDFLUID

RESERVOIR

ACCUMULATOR UNIT

ACCUMULATORPRECHARGED TO1000 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






REV 7: AUG 2009 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 can

be 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 operating

side 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 operate (open) or ‘vent’

positions. A pressure switch connected to the discharge line of the control valve isactivated when a pilot signal is present and lights up the appropriate lamp on thecontrol panel.

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 uid to

ow 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 uid 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 will

transmit 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.





REV 7: AUG 2009 9 - 14

Figure 9.5 PILOT FLUID CIRCUIT (2-POSITION FUNCTION)

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





REV 7: AUG 2009 9 - 15

Figure 9.6 PILOT FLUID CIRCUIT (3-POSITION FUNCTION)

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





REV 7: AUG 2009 9 - 16

9.13 HYDRAULIC POWER UNIT

This unit contains the mixing system, high pressure pumps and accumulator banks as shown in Fig 9.4.

MIXING SYSTEM

The hydraulic power unit supplies hydraulic uid 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 hydraulicuid which is then stored in a large reservoir known as the mixed uid tank.

Since the control system is an ‘open’ one in that the used hydraulic power uid is

vented 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 uid tankshould be capable of holding sufcient uid to charge the system accumulatorsfrom their pre-charge condition to their maximum operating pressure. All thetanks are tted with sight glasses and a low-level alarm system which activates awarning light and horn on the control panels.

The proper mixing uid ratio is maintained by air operated hydraulic pumps,

a water pressure regulator, a double acting motor valve and a water ow rateindicator. A reservoir oat switch is used to control operation of the mixing systemin order to maintain the correct level of uid 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 uidsupply at least equal to the rate at which mix uid is drawn from the tank by thehigh pressure pumps.

HIGH PRESSURE PUMPS

These are the pumps which take the uid from the mix tank and transfer it to theaccumulator bottles, under pressure, where it is stored ready for use by the system.Typically, three air powered and two electrically powered pumps are used. Duringnormal operation the electric pumps are used to recharge the system. Howeverif these cannot keep up with demand, or fail in some way, then the air poweredpumps 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 accumulatorsfrom their pre-charge condition to their maximum operating pressure in less than15 minutes. See Section 9.1.4 below for calculations involving accumulator andcharging pump capacities.





REV 7: AUG 2009 9 - 17

Figure 9.9 ROTARY SHEAR SEAL TYPE VALVES

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 VALVE

PV

AB

A) SUBSEA MANIPULATOR VALVE

PV

AB





REV 7: AUG 2009 9 - 18

REGULATOR CONTROL

Since the power uid 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 ram

preventers. 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 manifoldor remotely from another control panel. When operated from a remote panel asolenoid valve is used to increase the air pressure by allowing rig air to ow intoa 1 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

PILOT

ACCUMULATORS

SUPPLY FROM

POWER UNIT

VENT TO MIX

FLUID TANK MANUAL

CONTROL

HANDLE

PRESSURE SWITCH

'OPEN' PILOT LINE

'CLOSE' PILOT LINE

JUMPER

HOSES

PRESSURE SWITCH

AIR OPERATOR

TYPICAL PILOT CONTROL VALVE





REV 7: AUG 2009 9 - 19

Figure 9.11 SUBSEA REGULATOR CONTROL CIRCUIT

DECREASE INCREASE

YELLOWBLUE

REGULATORPRESSURE

REMOTEPANEL

REGULATOR PRESSUREREADBACK

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





REV 7: AUG 2009 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 oor, and a mini-panel in a relatively safe location such as a rig ofce. 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 owmeter 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 alsocontain alarms for low hydraulic uid 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 order

to allow the supply of electrical power to the panel. The sequence of events thatoccur is as follows -





REV 7: AUG 2009 9 - 21

CLOSE

1. The ‘press and hold’ button is held in to activate the panel.

2. The ‘close’ button is pressed.

3. Current ows 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 ‘closesposition and pilot pressure is sent to the subsea control pod.

5. Successful pressurisation of the pilot line to the control pod actuates a

pressure switch on the control manifold.

6. Current ows through an electronic card which illuminates the lamp ofthe‘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


SOLENOID VALVE

PILOT CONTROL VALVE AIR OPERATOR

SOLENOID VALVE

CONTROLPANEL

RIG AIR

CLOSE BLOCK OPEN

PILOT LINES TOSUBSEA PODS

'OPEN' PRESSURE SWITCH

'CLOSE' PRESSURE SWITCH

ELECTRONICCARD

ELECTRICSUPPLY

'PUSH AND HOLD'BUTTON

PILOT psi

ACCUMULATOR psi

REGULATOR psi

VENT psi

KEY





REV 7: AUG 2009 9 - 22

OPEN


2. The ‘open’ button is pressed.

3. Current ows 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’ position and pilot pressure is sent to the subsea control pod.

5. Successful pressurisation of the pilot line to the control pod actuates a

pressure switch on the control manifold.

6. Current ows through an electronic card which illuminates the lamp of the'open’ button and extinguishes the ‘close’ lamp indicating that the function is

now open.

7. The ‘press and hold’ button is released, the ‘open’ lamp remains illuminated.

Figure 9.12B REMOTE OPERATION - OPEN FUNCTION

MIX WATER TANK


SOLENOID VALVE

PILOT CONTROL VALVE AIR OPERATOR

SOLENOID VALVE

CONTROLPANEL

RIG AIR

CLOSE BLOCK OPEN

PILOT LINES TOSUBSEA PODS



ELECTRONICCARD

ELECTRICSUPPLY

'PUSH AND HOLD'BUTTON

PILOT psi

ACCUMULATOR psi

REGULATOR psi

VENT psi

KEY





REV 7: AUG 2009 9 - 23

BLOCK


2. The ‘block’ button is pressed.

3. Current ows 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 sent

down 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 and illuminates 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

PILOT FLUID

ACCUMULATORS

SOLENOID

VALVE

PILOT CONTROL VALVE AIR

OPERATOR

SOLENOID

VALVE

CONTROL

PANEL

RIG AIR

CLOSE BLOCK OPEN

PILOT LINES TO

SUBSEA PODS



ELECTRONIC

CARD

ELECTRIC

SUPPLY

'PUSH AND HOLD'

BUTTON

PILOT psi

ACCUMULAT OR psi

REGULATOR psi

VENT psi

KEY





REV 7: AUG 2009 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 usedto depressurise 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 ow meter shows that the correct amount of power uid has been used.

b. There are uctuations 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 junction boxes 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 driven by 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, ve or six control stations are mountedon the side of the reel. These live functions include at least the riser and stack

connectors, two pipe rams and the pod latch. Fig 9.13 is a schematic of the hydraulicsystem through which the power uid ows 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 any

pressure that may remain trapped in a pilot line holding an SPM valve open. This isnecessary since the reel is tted 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).





REV 7: AUG 2009 9 - 25

Figure 9.13 HOSE REEL CONTROL MANIFOLD

MAIN HYDRAULICSUPPLY THROUGH

SWIVEL JOINT

JUMPER HOSE FROMHYDRAULIC MANIFOLD

BLUE PODHOSE REEL

MANIFOLDREGULATOR

1/4"SELECTOR VALVES

VALVE MANIFOLDMOUNTED ON SIDE

OF HOSE REEL

HOSEBUNDLE

BLUE POD JUNCTION BOX

OPENSPM

REGULATOR

CLOSESPM

SHUTTLE VALVE

SHUTTLE VALVEBLUEPOD

FROM YELLOW

POD

OPEN

CLOSE





REV 7: AUG 2009 9 - 26

9.1.8 UMBILICAL HOSE

The umbilical transmits all power uid and all pilot signals from the surface tothe subsea control pods. Hydraulic pressure from the regulated side of the subsearegulators is also transmitted through the umbilical to pressure readback gauges atsurface. The power uid 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 uid 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. Special

clamps 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 uidtransfer 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 uid 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 uid to pass through it to one of theexit ports on the lower part of the male stab and into the upper female receptacle

attached to the lower marine riser package.

For those functions which are part of the lower marine riser package the uid isthen routed out of the upper female receptacle and directed via a shuttle valveto the functions operating piston. For those functions which are part of the mainBOP stack, the uid is routed through the upper female receptacle and into thelower female 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 directlyfrom surface through 1/4" lines. These are generally referred to as straight throughfunctions.





REV 7: AUG 2009 9 - 27

Figure 9.14 KOOMEY





REV 7: AUG 2009 9 - 28

The integrity of each uid route between the different sections is achieved byusing a compression seal that is installed in the retrievable valve block section

of the 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 uid ports. To retrievethe pod independently of the lower marine riser package, the locking pressure is

bled off 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 tapered

block 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 the podhas 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 uid to the desired sideof the preventer, valve or connector operating piston and vent the uid from the otherside of the piston to the sea. The annular preventers typically use large 1 1/2" SPMvalves in order to provide sufcient uid ow, 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 ofits travel on nylon seats. In the normally closed position a spring attached to thetop of the piston shaft keeps the piston on the bottom seat and prevents the poweruid from passing through the valve to the exit port. Power uid pressure, whichis permanently present, also assists in keeping the valve closed by acting on a smallpiston area on the spindle. In this position uid 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 uidto ow through the bottom section of the valve to function the BOP. Note that the

pilot uid therefore operates in a closed system whilst the hydraulic power or controluid is an ‘open’ circuit with all used uid being vented to the sea.

As illustrated in Fig 9.3 two SPM pilot valves are required to operate a BOP function.





REV 7: AUG 2009 9 - 29

Figure 9.15 NL SHAFFER 1" SPM VALVE

REGULATORS

Each subsea control pod contains two regulators - one to regulate pressure forthe ram preventers and one to regulate the pressure for operating the annularpreventers. Some control systems incorporate a third regulator so that the operatingpressure 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 conrm that the subsea regulator is supplying thepower uid 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‘res’. If the pod selector valve is set on yellow then power uid is sent only to thispod and it is only through the SPM valve in this pod that the uid will reach theram operating piston. The pod selection has no effect on the pilot system.

Once the yellow pod SPM valve ‘res’, the power uid passes through it to ashuttle valve, the shuttle piston of which moves across and seals against the blue

pod inlet. The uid 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"





REV 7: AUG 2009 9 - 30

Note that if the blue pod was now selected to open the rams; then the power uidwould ow to the ram through the ‘open’ SPM on the blue pod but the uid from

the ‘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 uid 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 modications even between similarmodels therefore trouble shooting should always be carried out with reference tothe relevant schematics.

LEAKS

A uid leak is usually detected by watching the ow meter. If a ow is indicated

when no function is being operated or if the ow meter continues to run and doesnot stop after a function has been operated then a leak in the system is implied.Once it has been determined that there is a leak then the following steps could beused to try and locate its source -





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CHECK THE SURFACE EQUIPMENT

• examine the hydraulic control manifold for a broken line or tting• examine the accumulator bottles for signs of a uid 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 tightly

closed (if this is left open when the junction box is connected to the reel, it willallow uid 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 theowmeter 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 specic 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 is

retrieved





REV 7: AUG 2009 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 uid owing 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 uid to leak past it)

• if the valve positions are correct then disconnect the discharge line from eachvalve - one at a time (uid ow 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 owmeter continues to run after the timenormally required for that function to operate. In this case there is a leak in that

function with a likely reason being foreign material in the SPM valve not allowingthe seat to seal thus causing the system to leak hydraulic uid.

A possible remedy is to operate the valve several times to try and wash out theforeign material. Observe the owmeter 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 owmeterindication 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 -





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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 uid 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 ow 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 nal option will be toretrieve the pod and check the pilot line for any sludge that may have settled outfrom the hydraulic uid (disconnect each pilot line from the pod one at a timeand ush clean uid through it

In the situation where there is no owmeter 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 owmeter 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 uid in the mix water tank

• check for correct operation of the pressure switches

• check the uid lters to make certain they are not plugged

• check the accumulator pre-charge pressures





REV 7: AUG 2009 9 - 34

• bleed the uid from the bottles back into the tank and check the nitrogen

pressure 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 sufcient 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 operated

and then returns to normal, the function is probably working correctly and theowmeter is faulty

• monitor the owmeter on the hydraulic manifold to verify that the one on thedrillers panel is not at fault (the impulse unit that sends the owmeter signal tothe panel could malfunction)





REV 7: AUG 2009 9 - 35

SECTION 9.2 MARINE RISER SYSTEMS

GENERAL

9.2.1 A marine riser system is used to provide a return uid ow path from thewellbore to either a oating drilling vessel (semi submersible or hull type) or a

bottom supported unit, and to guide the drill string and tools to the wellhead onthe ocean oor. Components of this system include remotely operated connectors,exible 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 of

Marine 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 uid 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 exible joint) should be at least equal to the working pressureof the diverter system plus the maximum difference in hydrostatic pressures of

the drilling uid and sea water at the ocean oor. 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 uid.

9.2.3 For bottom-supported units, consideration should be given to similar forcesand loads with the exception of vessel displacement, vessel movement, andhigh axial loads. Operating water depths for bottom-supported units are oftenshallow enough to permit free standing risers to be used without exceeding critical

buckling limits, with only lateral support at the surface and minimal tension beingrequired to provide a satisfactory installation.





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9.2.4 Information presented in this Section applies primarily to oating drillingvessels, since more demanding conditions normally exist for these marine riser

systems 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 and

Operation 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, exible joint, etc.) or to the rated working pressureof the 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 C

L while those rated at

the 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 be an 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 sufcient to safely resist loadsthat might reasonably be anticipated during operations. This would include

tension 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 exible joint is used in the marine riser system to minimise bendingmoments, stress concentrations, and problems of misalignment engagement. Theangular freedom of a exible joint is normally 10 degrees from vertical. A exible

joint is always installed at the bottom of the riser system either immediately abovethe remotely operated connector normally used for connecting/disconnecting the

riser from the blowout preventer stack, or above the annular preventer when theannular preventer is placed above the remotely operated connector.





REV 7: AUG 2009 9 - 37

9.2.9 For those vessels having a diverter system, a second exible joint issometimes installed between the telescopic joint and the diverter to obtain

required exibility, or some type of gimbal arrangement may also be used. Fordeep water operations or unusually severe sea conditions, another exible jointmay be installed immediately below the telescopic joint.

9.2.10 Mechanical strength requirements for exible 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-typeexible joints to counteract unbalanced forces of tensile load, drilling uid density,

and sea water density. This pressure balancing also provides lubrication forexible joints.

9.2.11 Technical investigations and experience have shown the importance of closemonitoring of the exible joint angle during operations to keep it at a minimum.One method of accomplishing this is by the use of an angle-azimuth indicator.The exible joint angle, vessel offset, and applied (riser) tension are indicationsof stress levels in the riser section. For continuous drilling operations, the exible

joint should be maintained as straight as possible, normally at an angle of lessthan 3 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 Specications for riser pipe depend upon service conditions. It should be noted, 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 those requirednot only for the present but for reasonably anticipated future conditions.





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9.2.13 Riser pipe steel should conform to ASTM Designation A-530: GeneralRequirements for Specialised Carbon and Alloy Steel Pipe

† and be fabricated and

inspected in accordance with API Spec 5L: Specication for Line Pipe*. Specicationsthat 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 under

various operating conditions, and should be used for installations whereprevious experience is limited or lacking. Permissible operating stresses arenormally expressed as a percent of minimum yield strength and depend uponthe preciseness of the data input. For any combination of service conditions (i.e.environmental, vessel offset, drilling uid 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, wear

bushings, 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 madeup and 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 specied by the manufacturer.

9.2.17 Auxiliary drilling uid circulation lines are sometimes required and

included as an integral part of large diameter riser systems. Drilling uid 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 ow rates and pressures required.

Marine Riser Telescopic Joint

9.2.18 The telescopic joint serves as a connection between the marine riser andthe drilling vessel, compensating principally for heave of the vessel. It consists oftwo main sections, the outer barrel (lower member) and the inner barrel (upper

member).





REV 7: AUG 2009 9 - 39

9.2.19 The outer barrel (lower member), connected to the riser pipe and remainingxed with respect to the ocean oor, is attached to the riser tensioning system

and also 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 outer barrel,is connected to and moves with the drilling vessel and has an internal diametercompatible with other components of the marine riser system. The top portion ofthe inner barrel has either a drilling uid return line or diverter system attached,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

be capable of supporting anticipated dynamic loads while running or pullingthe blowout preventer stack and should have sufcient 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 efciency 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 prole 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 specic set of operatingconditions (water depth, current, riser weight, drilling uid density, vesseloffset, etc.).





REV 7: AUG 2009 9 - 40

9.2.24 Wirelines from the multiple hydraulic tensioner cylinders are connectedto the outer barrel of the telescopic joint. These cylinders are energised by high

pressure 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,uid is forced out of the hydraulic cylinders thereby compressing air. As thevessel heaves 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 of30 to 50 feet. Design of the wireline system that supports the riser must take into

consideration the angle between the wireline and the axis of the telescopic jointand its inuence on stresses.

19.2.26 The number of tensioners required for a specic operation will depend onsuch factors as riser size and length, drilling uid 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 operatingdifculties that might occur should one of the tensioners experience wirelinefailure. Recommendations for marine riser design and operation of riser

tensioning 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 program

based on ton cycle life for the particular rig installation. Users should consult theequipment manufacturer for general maintenance procedures and specicationsrecommendations.

Buoyancy

9.2.28 For deeper waters, it may be impractical from an operating view point toinstall sufcient units capable of providing adequate tensioning. In these cases,some types of riser buoyancy may be the solution (otation jackets, buoyancytanks, etc.) Buoyancy reduces the top tensioning requirements but loses someof its effectiveness as a result of the increased riser diameter exposing a greatercross sectional area to wave forces and ocean currents. Selection of the optimummethod and/or material for obtaining buoyancy requires careful consideration ofa number 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





REV 7: AUG 2009 9 - 41

factors become more critical. A part of any analysis for an optimum safe systemshould include consideration of the consequences of buoyancy failure during

operations.

Riser Running and Handling

9.2.29 Well trained crews and close supervision are needed for maximumefciency 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 benecial, both in protecting the riser andimproving efciency. These tools include a are-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/or

tensioning 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* forspecic information.

*Available from American Petroleum Institute, Production Dept. 2535 One Main Place, Dallas TX 75202-3904.





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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 deection. Minimum swallow of pin mandrel

assures quick separation.

LOCK PORT

PRIMARYLOCK PORT

VENT PORT

SECONDARYRELEASE

PORT

PRIMARYRELEASE

PORT

PINMANDREL

PROFILE

SEAL RING

PISTON

SEAL RINGRETAINER

SCREW

CAM RING

CONNECTINGROD

LOCKING DOG





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EL Style BOP and Riser Connectors - General Description

EL Connectors are hydraulically actuated units which provide ease of operation,positive sealing and eld 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 the body 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, ve inches before make-up, facilitates choke and kill linestabs.





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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.





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Riser Fill-up Valve

The Cameron riser ll-up valve isdesigned to prevent the riser fromcollapsing if the level of drillinguid drops 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 waterto enter the riser, equalizing thepressure and preventing risercollapse.

The riser ll-up valve is activated by the pressure sensory sleeve when

the pressure inside the riser is from250 - 350 psi below the ambientocean pressure. When activate, thevalve fully opens to rapidly ll theriser. When pressure is equalized,the pressure sensor returns to itsnormal position and the internalsleeve closes.

Although the unit is totally self-

contained and independent of anycontrol lines, the valve can also bemanually operated through controllines to the surface.

Figure 9.21 Marine Riser Fill-up Valve

SD–8140





REV 5: JAN 2008

10.0 Formulae and Conversion Factors

10.1 Glossary for Well Control Operations

SECTION 10FORMULAE, CONVERSION FACTORS& GLOSSARY OF TERMS




SECTION 10 : FORMULAE, CONVERSION FACTORS & GLOSSARY OF TERMS

REV 7: AUG 2009 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 - Inux Grad psi/ft) x Inux Pressure psi = Height ft] + SIDPP psi 12. Equivalent circulating (Annulus Pressure loss psi ÷ TVD ft ÷ 0.052)

density ppg = + Original Mud ppg

13. Height of inux ft = Kick size bbls ÷ Annulus Volume bbls/ft

14. Gradient of Inux psi/ft = (Mud weight ppg x 0.052)

(SICP psi - SIDPP psi)

Inux Height ft

15. Trip Margin/safety = (Safety factor psi ÷ TVD ÷ 0.052) + Mudfactor ppg Weight ppg

16. Pump Pressure/ Pump StksRelationship psi = Present Pressure psi x (New SPM ÷ Old SPM)2





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[ ]

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 - x 0.052 x shoe TVD 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 - Inux Grad psi/ft)) x Inux Height ft21. Kick Tolerance ppg = –––––––––––––––––––––––––––––––––––––––––––– TVD x 0.052

Kick tolerance in feet MAASP - SIDPP or [–––––––––––––] = Max Tol Length of Inux GM- GI

P1V

1 V

1P

1

22. Boyle’s Law: P1V1 = P2V2 P2 = –––– V2 = ––––– V

2 P

2

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 - metal disp. bbls/ft)26. Length of pipe to pull dry = ––––––––––––––––––––––––––––––––––––––––––– before well starts to ow ft Mud gradient psi/ft x metal disp. bbls/ft

Mud grad psi/ft x Casing Cap bbls/ft x differential height ft27. Hydrostatic Pressure = –––––––––––––––––––––––––––––––––––––––––––– loss if casing oat fails (casing capacity (bbls/ft) + Annulus capacity bbls/ft)





REV 7: AUG 2009 10 - 3

W2 where

W1 = mud wt

28. Volume displace by slug = Slug Vol x ––– - 1

W1 where W2 = slug wt ∆P29. 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] where BML = base mud line [Psw] + [Pf] ÷ [BML - TVD] ÷ [.052]

32. Estimated Casing setting depth beneath sea oor

[P Mud] - [P sw] ÷ [G.F.B. - G.M] where GFB = formation breakdown gradient Riser Sea-water where GM = gradient of mud

33. 'U' Tube formula

SIDPP + [Pmud]DS

= [SICP] + [Pmuda] +[Psas

a]

[ ]





REV 7: AUG 2009 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/ft

3

÷ 144 to give Pounds per Square Inch per Foot (psi/ft) Kg/m3 x 0.000434 to give Pounds per Square Inchor ÷ 2303 per Foot (psi/ft)

Kg/m3 x 0.00982 to give Kilo Pascals per Metre (K/Pa/m)





REV 7: AUG 2009 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 uid and gas stored underpressure as a source of uid 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 ow of uidsand 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 the

component in which it is installed.

Air Pressure Switch Bypass Valve - The opening and closing device locatedin the air supply line which blocks air ow in one line to be redirected throughanother. In open position, air ow 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 uid from the reservoir into the uid 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 ow 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 ow. Oneampere represents a ow of one coulomb per second.





REV 7: AUG 2009 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 space

around a pipe in a wellbore, the outer wall of which may be the wall of either the borehole 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 ow 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 ow system.

Bafe - A partition plate inside the reservoir to prevent unbalancing by suddenweight shifting of the hydraulic uid.

Barite Plug - A settled volume of barite particles from a barite slurry placed in the

wellbore 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 owing 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 the

blowout preventer or marine riser with a side outlet to direct the drilling uid

returns to the shale shaker or pit. Usually has a second side outlet for the ll-upline connection.

Bleeding - Controlled release of uids 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.





REV 7: AUG 2009 10 - 7

Blowout - An uncontrolled ow of gas, oil, or other well uids into theatmosphere. A blowout, or gusher, occurs when formation pressure exceeds the

pressure applied to it by the column of drilling uid.

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 uid and formation pressure. The BOP allowsthe well to be sealed to conne the well uids 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 landrigs or at the water’s surface on jack-up or platform rigs and on the sea oor foroating 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 of

blowout 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 immediately

below the stack.

Bleeder Valve - An opening and closing device for removal of pressurised uid.

Borehole Pressure - Total pressure exerted in the wellbore by a column of uidand/or back pressure imposed at the surface.

Bottom-hole Pressure - Depending upon context, either a pressure exerted by acolumn of uid contained in the wellbore or the formation pressure at the depth ofinterest.

Broaching - Venting of uids 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.





REV 7: AUG 2009 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 uid density or by the sum of a higher drilling uid

density 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 ow in only one direction.

Choke - A variable diameter orice installed in a line through which high pressurewell uids can be restricted or released at a controlled rate. Chokes also control therate of ow of the drilling mud out of the hole when the well is closed in with the

blowout 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 ow to the choke manifold.

Choke Manifold (Control Manifold) - The system of valves, chokes, and pipingto control ow from the annulus and regulate pressures in the drill pipe/annulus

ow 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 ange joints. The two items to be sealed are preparedwith clamp hubs. These hubs are held together by a clamp containing two to four

bolts.

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 100percent). Conductivity is expressed for a standard conguration of conductor.





REV 7: AUG 2009 10 - 9

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 upowingdrilling uid from the wellbore to the surface drilling uid system until the rstcasing string is set in the well. Conductor pipe is usually cemented.

Continuity - The uninterrupted ow 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 owof pressured hydraulic uid to operate the various components of the blowoutpreventer stack.

Control Panel, Remote - A panel containing a series of control that will operate thevalves 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 uid through special apertures to operate

blowout preventer equipment.

Corrosion Inhibitor - Any substance which slows or prevents the chemicalreactions of corrosion.

Cut Drilling Fluid - Well control uid which has been reduced in density or unitweight as a result of entrainment of less dense formation uids or air.

Cylinder - A device which converts uid 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 uid to ow out only and thereby prevents a back ow ofuid into the pump.

Displacement - The volume of steel in the tubulars and devices inserted and/orwithdrawn from the wellbore.

Diverter - A device attached to the wellhead or marine riser to close the verticalaccess and direct any ow into a line away from the rig.





REV 7: AUG 2009 10 - 10

Drain Port - The plugged openings on the lower side portions of the reservoirwhich can be opened to empty or release the hydraulic uid, and through which

the reservoir can be cleaned.

Drilling Fluid Weight Recorder - An instrument in the drilling uid system whichcontinuously measures drilling uid density.

Drilling Spool - A connection component with ends either anged 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 oorwith threads to match the drill pipe in use. This valve is used to close off the drill

pipe to prevent ow.

Drill Stem Test (DST) - A test conducted to determine production ow rate and/or formation pressure prior to completing the well.

Drill String Float - A check valve in the drill string that will allow uid to bepumped into the well but will prevent ow 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 uid 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 liquid

ow.Equivalent Circulating Density (ECD) - The sum of pressure exerted byhydrostatic head of uid, 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 (Inux, Inow) - The ow of uids from the formation into the wellbore.

Fill Port - The plugged opening in the top of the uid reservoir through whichhydraulic oil is added.

Fill-up Line - A line usually connected into the bell nipple above the blowoutpreventers to allow adding drilling uid to the hole while pulling out of the holeto compensate for the metal volume displacement of the drill string being pulled.





REV 7: AUG 2009 10 - 11

Filter (Air) - Apparatus used to clean air ow of dirt, moisture and othercontaminants.

Filter (Hydraulic) - A device whose function is the retention of insolublecontaminants from a uid.

Final Circulating Pressure - Drill pipe pressure required to circulate at the selectedkill rate adjusted for increase in kill drilling uid density over the original drillinguid density; used from the time kill drilling uid reaches the bottom of the drillstring until kill operations are completed or a change in either kill drilling uiddensity or kill rate is effected.

Flow Meter - A device which indicates either ow rate, total ow, or a

combination of both, that travels through a conductor such as pipe or tubing.

Flow Rate - The volume, mass, or weight of a uid passing through anyconductor, such as pipe or tubing, per unit of time.

Fluid - A substance that ows and yields to any force tending to change its shape.Liquids and gases are uids. The accumulator system pressurises uid to be usedas a source of power to open and close valves and rams on the BOP stack.

Fluid Density - The unit weight of uid; e.g., pounds per gallon (lb/gal).

Formation Breakdown - An event occurring when borehole pressure is ofmagnitude that the exposed formation accepts whole uid from the borehole.

Formation Competency (Formation Integrity) - The ability of the formation towithstand applied pressure.

Formation Competency Test (Formation Integrity Test) - Application of pressure by superimposing a surface pressure on a uid 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 uids within the poresof the formation (see Pore Pressure).

Flowline Sensor - A device to monitor rate of uid ow from the annulus.

Fracture Gradient (Frac. Gradient) - The pressure gradient (psi/ft) at which theformation accepts whole uid 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.





REV 7: AUG 2009 10 - 12

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 owpassage. The valve may or may not be full-opening.

Gauge - An instrument for measuring uid pressure that usually registersthe difference between atmospheric pressure and the pressure of the uid byindicating the effect of such pressure on a measuring element (as a columnof liquid, a bourdon tube, a weighted piston, a diaphragm, or other pressure-sensitive devices).

Gland - The cavity of a stufng 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. The

conducting 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 uid column, normally in feet.

Hydrostatic Pressure (Hydrostatic Head) - The pressure which exists at any pointin the wellbore due to the weight of the vertical column of uid above that point.

Indicating Light - The bulbs of the electric control panels that shine to pointout which electrical contacts have made a circuit. The electric panel bulbs makecircuit contacts through pressure switches, transducers, and solenoid valves todemonstrate activation.





REV 7: AUG 2009 10 - 13

Inow - See Feed-in.

Inux - See Feed-in.

Initial Circulating Pressure - Drill pipe pressure required to circulate initiallyat the 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 uid to be circulated down the string butprevents back ow.

Inspection Port - The plugged openings on the sides of the uid reservoir whichcan be opened to view the interior uid 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 connepressures inside the drill string.

Kelly Valve - Lower. An essentially full opening valve installed immediately below the kelly with outside diameter equal to the tool joint outside diameter.

Kick - Intrusion of formation uids into the wellbore.

Kill Drilling Fluid Density - The unit weight e.g. pounds per gallon (lb/gal),selected for the uid to be used to contain a kicking formation.

Kill Line - A high-pressure uid line connecting the mud pump and the wellheadat some point below a blowout preventer. This line allows heavy drilling uids to

be pumped into the well or annulus with the blowout preventer closed to control athreatened blowout.

Kill Rate - A predetermined uid circulating rate, expressed in uid 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.

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 auid column in order to determine the pressure at which the exposed formationaccepts whole uid.





REV 7: AUG 2009 10 - 14

Lost Circulation (Lost Returns) - The loss of whole drilling uid to the wellbore.

Lost Returns - See Lost Circulation.

Lubrication. Alternately pumping a relatively small volume of uid into a closedwellbore system and waiting for the uid 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 uid 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 uid pressure and vent it back into the reservoir.

Manifold Header - The piping system which serves to divide a ow throughseveral possible outlets. The 4-Way control valve inlets connect to the piping sothat high pressure uid 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 uid owing through and out the 4-Way controlvalves.

Manifold Regulator Bypass Valve - The opening and closing device which blocksow in one line to be redirected through another. This valve is located in themanifold piping so that in the open position the high pressure uid does not owthrough the regulator in the manifold header, thereby allowing higher pressureuid 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 theporosity of lter 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.





REV 7: AUG 2009 10 - 15

Motor Starter - Automatic device which starts or stops the electric motor drivingthe duplex or triplex pump which works in conjunction with the automatic

electrical pressure switch for pressure limits of pump start-up and shutoff.

Mud-gas Separator - A vessel for removing free gas from the drilling uid returns.

Needle Valve - A shutoff (2-Way) valve that incorporates a needle point to allowne adjustments in ow.

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 potential

difference 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 ofuid 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 at

1 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 runor pull 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 moisture

accumulated in the anterior chamber of the lubricator.

Phase (3-Phase Motor) - A particular stage or point of advancement in an electricalcycle. The fractional part of the period through which the time has advanced,measured from some arbitrary point usually expressed in electrical degrees where360° represents one cycle.Pipe Rack - The connecting pipelines between the control valve outlets and theBOP stack preventers which carry the high pressure operating uid. 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.





REV 7: AUG 2009 10 - 16

Pit Volume Indicator - A device installed in the drilling uid tank to register theuid level in the tank.

Pit Volume Totaliser - A device that combines all of the individual pit volumeindicators and registers the total drilling uid 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 uid ow. 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 uids 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 uid pressure,which automatically starts and stops the electrical pump when the presentpressures are reached.

Pressure Transmitter - Device which sends a pressure signal to be convertedand calibrated 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 uid ow by maintaining ahydrostatic pressure equal to or greater than formation pressure.

Pump (Air) - A device that increases the pressure on a uid or raises it to a higher level by being compressed in a chamber by a piston operated with an air pressure motor.

Pump (Electric) - A device that increases the pressure on a uid and moves it to ahigher level using compression force from a chamber and piston that is driven byan electric motor.

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 ina stack 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.





REV 7: AUG 2009 10 - 17

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 combat

blowout.

Replacement - The process whereby a volume of uid 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 hydraulicuid at atmospheric pressure as the supply for uid 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 value

such that the current squared, multiplied by the resistance, gives the powerconverted.

Rotating Head - A rotating, low pressure sealing device used in drilling operationsto seal around the drill stem above the top of the blowout preventer stack.

Rupture Disk - A device whose breaking strength (the point at which it physicallycomes apart) works to relieve pressure in the system. The rupture disk is containedas a safety device for the test unit system.

Safety Factor - In the context of this publication, an incremental increase in drillinguid density beyond the drilling uid density indicated by calculations to beneeded to contain a kicking formation.

Salt Water Flow - An inux 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.





REV 7: AUG 2009 10 - 18

Solenoid Valve - The opening/closing device which is activated by an electricalsignal to control liquid or gas pressured ow to be sent to open or close the 4-Way

control valves. The valve position is controlled by an electromagnetic bar, enclosed by 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 pipe

above 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 uid into one side of the drill pipe/annulus ow systemwith the other side closed so as to allow no outows.

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 ow.

Suction Strainer - The porous element, located in a “y” shaped tting of the

pump suction lines, which cleans the hydraulic uid 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 ow of high pressure uid. Located in thedownstream line of the annular regulator.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 ange at the end of a T to prevent erosion at a pointwhere change in ow direction occurs.





Targeted - Refers to a uid piping system in which ow impinges upon a lead-lled end (target) or a piping T when uid 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 uid density to provide an

increment of overbalance in order to compensate for effects of swabbing.

Tubulars - Drill pipe, drill collars, tubing, and casing.Underground Blowout - An uncontrolled ow of formation uids from asubsurface zone into a second subsurface zone.

Underbalance - The amount by which formation pressure exceeds pressureexerted by the hydrostatic head of uid in the wellbore.

Unit/Remote Selector - The valve located on the manifold header whose ports

allow ow into the annular regulator. The valve position determines the source ofow 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 uid to bemonitored.

Valve, Manipulator - A control device having three positions, giving four directionselections for ow which alternately pressurises and vents the pressure outlets.The manipulator style valve vents all pressure outlets when placed in the centre

position.

Valve, Poppet - The opening and closing device in a line of ow which restrictsow by lowering a piston type plunger into the valve passageway.Valve, Pre-charge - The device located on the accumulator bladder ports whichopen and close for the nitrogen pressure contained.

Ads Wc Manual

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