Well Control Manual

WELL CONTROL MANUAL

Introduction andHow to Use

Volume 1Procedures and Guidelines

BP EXPLORATION© 1995 British Petroleum Company PLC

Text originated by BP Drilling DepartmentManual produced by ODL Publications, Aberdeen, Tel (01224) 637171

Volume 2Fundamentals of Well Control

BP WELL CONTROL MANUAL

March 1995

WELCOME

Ladies and Gentlemen:

Following is the Second Edition of the “BP Well Control Manual” first issued in 1987.When issued it was expected to be a living document, accounting for changes intechnology and experience, it still is. Now, eight years later, horizontal and extendedreach wells, coil tubing drilling and under balance drilling have or will become partof our kit for improved profitability.

Our objective with this Second Edition is to bring three changes to the operatinggroups:

1) Issue the manual in an electronic version as a pilot which may lead to collectingall of the manuals on a server or CD-ROM.

2) Make available Excel based well control worksheets which have beenincorporated into the manual.

3) Modify parts of Volume I Chapters 1 and 6 for high angle and horizontal welloperations.

In a separate file we have issued the “HTHP Well Control Manual”. Future updateswill tie this manual with the “BP Well Control Manual”.

Publication of the manual in electronic format should make the abundance ofinformation in it more accessible to you. A powerful search capability and “hot button”references are part of the software package we have selected. Software used iscompatible with Macintosh, MS-DOS and DEC hardware platforms making it accessibleto BP and our contractors when needed. Electronic publishing makes modificationseasier and we solicit your suggestions for correction, clarification, change or additionto the manual. If we have not managed to make the resource more useful and clearto you we have failed our objective. Your views on how well we have done areimportant.

To open and use the manual please read the section below. While use of the electronicversion of the manual is encouraged there is still the option of printing a hard copyof the manual. Hard copies can still be obtained from ODL in Aberdeen at a cost forprinting and shipping.

Originally this manual was not issued as “policy”. In the October 1994 Drilling ManagersMeeting this and two other documents, the “Drilling Policy Manual” and “CasingDesign Manual”, were designated as the three core policy documents covering ouroperations. Every effort has been made in this edition to tie to the other two documents.

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March 1995

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HOW TO USE

ManualContents


March 1995

Volume 1 – Contents

NomenclatureAbbreviations

1 PREPARATION

Section Page

1.1 INSTRUMENTATION AND CONTROL 1-11.2 MANPOWER ORGANISATION 1-91.3 DRILLS AND SLOW CIRCULATING RATES 1-151.4 USE OF THE MUD SYSTEM 1-271.5 KICK TOLERANCE 1-35

2 THE PREVENTION OF A KICK

Section

2.1 CORRECT TRIPPING PROCEDURES 2-12.2 MAINTAIN SUITABLE HYDROSTATIC PRESSURE 2-92.3 CONTROL LOST CIRCULATION 2-17

3 WARNING SIGNS OF A KICK

Paragraph

1 GENERAL 3-22 DRILLING BREAK 3-23 INCREASED RETURNS FLOWRATE 3-24 PIT GAIN 3-35 HOLE NOT TAKING CORRECT VOLUME DURING

A TRIP 3-46 CHANGE IN PROPERTIES OF RETURNED MUD7 INCREASE IN HOOKLOAD 3-68 CHANGE IN PUMP SPEED OR PRESSURE 3-6


March 1995

4 ACTION ON DETECTING AN INFLUX

Section Page

4.1 SHALLOW GAS PROCEDURE 4-14.2 SHUT-IN PROCEDURE 4-94.3 DURING SHUT-IN PERIOD 4-17

5 WELL KILL DECISION ANALYSIS

Paragraph

1 GENERAL 5-22 PIPE ON BOTTOM 5-23 PIPE OFF BOTTOM – (Drillpipe in the Stack) 5-24 PIPE OFF BOTTOM – (Drillcollar in the Stack) 5-55 NO PIPE IN THE HOLE 5-56 WHILE RUNNING CASING OR LINER 5-77 UNDERGROUND BLOWOUT 5-9

6 WELL KILL TECHNIQUES

Section

6.1 STANDARD TECHNIQUES 6-1– Wait and Weight Method 6-2– Driller’s Method 6-3

6.2 SPECIAL TECHNIQUES 6-311. Volumetric Method 6-332. Stripping 6-473. Bullheading 6-674. Snubbing 6-755. Baryte Plugs 6-846. Emergency Procedure 6-93

6.3 COMPLICATIONS 6-97


March 1995

NOMENCLATURE

SYMBOL DESCRIPTION UNIT

A Cross sectional area in.2

a Constant –A

nTotal nozzle area in.2

b Constant –c Constant –C Annular capacity bbl/mC

pPipe capacity bbl/m

Ca

Cuttings concentration %CL Clinging constant –CR Closing ratio –D Depth mD

shoeShoe depth m

Dwp

Depth of openhole weak point md

bitBit diameter in.

dh

Hole diameter in.d

hcHole/casing ID in.

do

Pipe OD in.d

iPipe ID in.

dcut

Average cuttings diameter in.d

cDrilling exponent (corrected) –

F Force lbF

shShale formation factor –

FPG Formation Pressure Gradient SGg Gravity acceleration –G Pressure gradient psi/ft

psi/mSG

Gi

Influx gradient psi/ftH Height mH

iHeight of influx m

Hp

Height of plug mITT Interval Transit Time µsec/mK Bulk modulus of elasticityL Length mλ Rotary exponent –MR Migration rate m/hrM Matrix stress psim Threshold bit weight lbMW Mud weight SG


March 1995


N Rotary speed rpmOPG Overburden Pressure Gradient SGP Pressure psi/SG

(The units of subsurface pressuremay be either psi or SG)

∆P Adjustment pressure psiPa Annulus pressure psi∆Pbit Bit pressure drop psiPcl Choke line pressure loss psiPdp Drillpipe pressure psiPf Formation pressure psi/SGPfrac Fracture pressure psi/SGPfc Final circulating pressure psiPi Hydrostatic pressure of influx psiPic Initial circulating pressure psiPlo Leak off pressure psi/SGPmax Maximum allowable pressure

at the openhole weak point psi/SGPoc Wide open choke pressure psiPp Pore pressure psi/SGPscr Slow circulating rate pressure psiPV Plastic Viscosity cPQ Flowrate gal/minQ

mudMud flowrate gal/min

Qgas

Gas flowrate gal/minRe Reynolds number –R Resistivity ohm-mRw Resistivity of water ohm-mROP Rate of Penetration m/hr

Shale factor meq/100gS Overburden pressure psiS

gGas saturation Fractional

Sw

Water saturation Fractionalt Time seconds

minTR Transport Ratio –T Temperature degrees

C, F, RTD Total Depth mTVD True Vertical Depth mV Kick tolerance bbl


March 1995


V Volume bblccmll

v Velocity m/minm/s

vmud Mud velocity m/minvp Average pipe running speed m/minvs Slip velocity m/minW Weight gm

kglb

w Weight lb/ftlb/bblSG

w Weight of pipe lb/ftwb Baryte required for weighting up lb/bblwcut Average cuttings weight SGWOB Weight on Bit lbx Offset ( )YP Yield Point lb/100ft2

Z Compressibility factor –µ Viscosity cPν Poissons’s Ratio –σ’1 Maximum effective principle stress psi/SGσ’t Tectonic stress psi/SGØ Porosity FractionalØ600 Fann reading lb/100ft2

β Tectonic stress coefficient –ρ Density SGρ

bBulk density SG


March 1995

ABBREVIATIONS

API RP American Petroleum Institute Recommended PracticeBHA Bottomhole AssemblyBOP Blowout PreventerBRT Below Rotary TableDWT Dead Weight TesterECD Equivalent Circulating DensityEMW Equivalent Mud WeightH2S Hydrogen SulphideIADC International Association of Drilling ContractorsID Internal DiameterKTOL Kick ToleranceLCM Lost Circulation MaterialLMRP Lower Marine Riser PackageLO Leak offMAASP Maximum Allowable Annular Surface PressureOBM Oil Base MudOD Outside DiameterPMS Preventive Maintenance SystemPV Plastic ViscosityROP Rate of PenetrationSCR Slow Circulating RateSG Specific GravitySPM Strokes per MinuteYP Yield Point


March 1995

1 PREPARATION

Section Page

1.1 INSTRUMENTATION AND CONTROL 1-1

1.2 MANPOWER ORGANISATION 1-9

1.3 DRILLS AND SLOW CIRCULATING RATES 1-15

1.4 USE OF THE MUD SYSTEM 1-27

1.5 KICK TOLERANCE 1-35


1-1March 1995

1.1 INSTRUMENTATION AND CONTROL

Paragraph Page

1 General 1-2

2 Pressure Gauges 1-2

3 Pump Control 1-4

4 Fluid Measurement 1-6

Illustrations

1.1 Suggested Instrumentation for a Floating Rig 1-3

1.2 Suggested Instrumentation for a Fixed Installation 1-5

1.3 Suggested Fluid Measurement System 1-7

order

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ricatend the of


1-2March 1995

1 General

It is essential that an appropriate level of control equipment is provided on every rig in that a well that is under pressure can be accurately monitored.

In general, during a well control incident, there is a necessity for more accuinstrumentation than under conditions encountered during routine drilling.

The level of instrumentation on every rig therefore must be evaluated in order to aits␣suitability for well control purposes. This evaluation should ideally be carried ouin␣conjunction with the pre contract rig audit and any deficiencies made good priocontract␣award.

The purpose of this section is to highlight the important aspects of instrumentationcontrol and to recommend a standard level of equipment for all rig types.

The level of instrumentation that is recommended will ensure that a suitable level of cois afforded during unusually critical operations, and that adequate back-up is provTherefore, much of this equipment would not be necessary in routine circumstances. Hoequipment failure is most likely when the equipment is highly stressed. It is in these situthat serious incidents can develop if a suitable level of back-up instrumentation and cequipment is not to hand.

2 Pressure Gauges

When a well is under pressure it is important that accurate pressure measurements can b

Each rig will normally be equipped with gauges to read standpipe pressure and anpressure. The gauges that are fitted to the choke panel and at the driller’s console are oftenthe only gauges available for well control purposes.

Although the standpipe and choke manifold will generally be fitted with ‘Cameron’ gauthese are considered to be so inaccurate as to have little application to well control.

All of these gauges will have a fullscale deflection that is at least equal to the wopressure rating of the equipment. In all cases, this means that it will be necessary togauges of lower rating in order that relatively low pressures can be accurately recoThis will be especially important with high pressure equipment.

It is also important that suitable pressure gauges are installed at the choke manifold the well has to be controlled from this position. This will apply to land rigs which may beequipped only with manual chokes and the majority of rigs that are equipped withmanual and remote operated chokes.

Accurate readout of pump pressure and choke pressure is, in the majority of cases, alrequired. However an extra pressure reading is required on a floating rig in order thwellhead pressure can be monitored through the kill line.

In order to be able to install additional pressure gauges it may be necessary to fabmanifolds and install high pressure instrument hose between the choke panel astandpipe/choke manifold. All this equipment must be rated to the working pressurethe␣equipment.


1-3March 1995

Figure 1.1 Suggested Instrumentation for a Floating Rig

SWACO

DK

C

DK

C

D – DRILL PIPE

K – KILL LINE

C – CHOKE LINE

– 1/4in NEEDLE VALVES

– CHECK VALVE/HYDRAULIC FLUID INLET

WEOX02.001

FROM BOP

FLOWLINE

POORBOY DEGASSER

CHOKE LINEBUFFER

TANK

MANUAL CHOKES

REMOTELY OPERATED

CHOKE

KILL LINE

OVERBOARD LINE

DRAIN

PUMP OUTPUT MONITOR

CAMERON GAUGE

TRANSDUCER

1/4in NEEDLE

VALVECHECK VALVE

HYDRAULIC FLUID INLET

CAMERON GAUGE

STANDPIPE 2

STANDPIPE MANIFOLD

CHOKE PANEL

CHOKE MANIFOLD

STANDPIPE 1

ill line

o the

hoke

wn inting

gularch

d be

sure

isuse

uired.a to

e used

rdernter

re is

that

inate


1-4March 1995

So in general:

• There must be gauges available to read choke pressure, standpipe pressure and kstatic pressure in the case of a floating rig.

• The above gauges must be readable from the manifold if manual chokes are fitted tmanifold.

• It must be possible to easily install and remove low range pressure gauges at the cpanel and at the choke manifold.

Suggested pressure recording systems for a floating rig and a fixed installation are shoFigures 1.1 and 1.2. The proposed systems can also be used for measuring slow circularate pressures (SCRs).

The following points should be noted from the proposed systems:

• A good selection of gauges should be available. Gauges should be calibrated on a rebasis with a Dead Weight Tester. It is suggested that the gauges are checked at eaBOP Test and at this stage the pressure monitors in the mud logging unit shoulchecked against the rig equipment.

• It must be easy to change the gauges.

• A hydraulic fluid hand pump should be available to purge the lines at suitable points asshown.

• Consideration should be given to completely isolating the supplementary presmonitoring system from that originally fitted to the rig. This would ensure that the originalsystem was closed and hence in no way susceptible to leaking needle valves or mof the supplementary system.

• Sensitive low pressure rated gauges should be removed from the system unless reqThe piping and manifolding should be permanently installed. It would be a good idefabricate a cover for the manifolding at the choke manifold and choke panel.

• The gauges that are used to measure the slow circulating rate pressures should bto monitor well pressures in the event a kick is taken.

• A stroke counter, similar to the battery operated ‘Swaco’ unit, is recommended for remoteinstallation at the choke manifold. It should be removed when not required. A suitablyisolated terminal should be located at a convenient point at the choke manifold, in othat the signal from the limit switches on the pumps can be transmitted to the cou.

3 Pump Control

It is desirable that the remote control of the pump used to kill a well that is under pressulocated reasonably close to the choke operator.

In most cases the rig pumps will be used. Generally, the Driller will control these pumpsfrom a position that is close to the choke panel. Most choke panels contain a meterdisplays the cumulative output of the pump. Therefore, in the majority of cases, if the wellis controlled with a remote operated choke, the man on the pump will be able to co-ordwith the choke operator.


1-5March 1995

Figure 1.2 Suggested Instrumentation for a Fixed Installation

D

C

D

C

SWACO

D

C – CHOKE LINE

D – DRILL PIPE

– 1/4in NEEDLE VALVES

– CHECK VALVE/HYDRAULIC FLUID INLET

WEOX02.002

TO STANDPIPE

TO DEGASSER

TO DEGASSER

TO BURN PIT

TO BURN PIT

TRANSDUCER

CAMERON GAUGE

REMOTELY OPERATED CHOKE

FROM BOP

1/4in HYDRAULIC FLUID FILLED

HIGH PRESSURE HOSE

CHOKE PRESSURE GAUGE

TO PUMP/ CHOKE PANEL

CHOKE

TO BURN PIT

STANDPIPE MANIFOLD

CHOKE PANEL

CHOKE MANIFOLD

TO STANDPIPE

somen suchanifold.nualfloor

ntrollativelyillingnitor

le to

rillingrrel

e trip

e

hoked the

ured.here

nters,

lt

d area


1-6March 1995

However, if the choke manifold contains manual chokes, the choke operator may be considerable distance from the man on the pump and a monitor of the pump output. Icases, it is recommended that a remote pump output meter is positioned at the choke mThis will be especially important on land rigs which may be equipped only with machokes and where often the choke manifold is located at some distance from the rig .

A further complication may arise if a kill pump or cement pump is used during a well cooperation. It may become necessary to use these pumps on any rig, but the use of a resmall displacement pump will be standard well control procedure on a floating rig that is drin deep water. Therefore, on a floating rig, it is desirable that it is possible to control and mothe kill/cement pump from the rig floor.

4 Fluid Measurement

During stripping operations, as well as during a volumetric kill, it is important to be␣abaccurately measure small volumes of fluid bled from, or pumped into the␣well.

API RP 53 recommends that ‘a trip tank or other method of accurately measuring the dfluid bled off, leaked from, or pumped into a well within an accuracy of half a bais␣required’.

Most rigs will not have suitable equipment to do this.

It is usually assumed that the choke manifold lined up across a manual choke to thtank␣is a suitable fluid measurement system. However, in most cases this will not be asatisfactory arrangement because of the relatively large volume in the line between thchoke and the tank.

In general, there is a requirement for a line from the well, terminating at a manual cpositioned directly above a measuring cylinder, such as the trip tank (hydraulically activatechokes are not suitable for this application). However a bleed line from the well tomixing tanks on the cement/kill pump may be sufficient.

The most satisfactory arrangement is to use a strip tank as shown in Figure 1.3. This tankwould typically have a 3 to 4 bbl capacity so that very small volumes of fluid can be measAfter bleeding into the strip tank, the tank contents can be emptied into the trip tank wthe total volume of mud bled from the well, together with the mud leaked past the prevecan be measured.

Although it is not ideal, it may be sufficient to use a Lo-Torq valve instead of a␣manuachoke to bleed fluid to the tank. However, during a long operation this is likely to wash ouand so provision should be made to easily and quickly replace the valve.

It is not recommended to bleed mud into a measuring tank that is situated in a confinewhen there is a possibility that gas is entrained in the mud.


1-7March 1995

1-7/8

FROM CHOKE MANIFOLD/BOP

3in PIPE

PRESSURE GAUGE

MANUAL CHOKE

STRIP TANK (3 – 4bbl capacity)

LARGE ID DRAIN

LEVEL INDICATOR

TRIP TANK

FLOWLINE RETURNS

WORKING PLATFORM

WEOX02.003

Figure 1.3 Suggested Fluid Measurement System


1.2 MANPOWER ORGANISATION

Paragraph Page

1 General 1-10

2 Individual Responsibilities 1-10

3 Communication 1-12

Illustrations

1.4 An Example Communication System 1-13

1-9March 1995

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1-10March 1995

1 General

This section is intended to provide a guideline for the allocation of individual responsibduring a well control incident. It is Company policy that a well control contingency should include the allocation of individual responsibilities.

The contingency plan should be drawn up in conjunction with the drilling contractoshould be regularly reassessed. Well control drills provide an opportunity to assess effectiveness of the contingency plan and to identify and make good any inadequac

2 Individual Responsibilities

The well control contingency plan must allocate the responsibilities of all those concin the operation. Circumstances at the rigsite may dictate that these responsibilimodified in the event of an incident; however, the following can be used as guidelines the allocation of responsibilities in the event of a well control incident:

(a) The Company Representative

• Once the well has been shut-in and is being correctly monitored, to organise a pre-killmeeting for all those involved in the supervision of the well control operation

• To provide specific well control procedures, using the contingency plan guideline.

• To monitor and supervise the implementation of these procedures.

• To be present on the rig floor at the start of the kill operation. Either the Toolpusheror the Company Representative should be present at all times on the rig floor the operation.

• To maintain communication with the Operations base.

• The Company Representative has the right to assume complete control of threquired to regain control of the well.

• To assign the responsibility of keeping a diary of events.

(b) The Company Drilling Engineer

• Will provide technical back-up to the Company Representative.

• To keep a diary of events.

(c) The Senior Contractor Representative

• Has the overall responsibility for all actions taken on the rig.

• Has the responsibility for supervising the contractor staff that are not directlyinvolved in the well control operation.

ativeegaining

.

ctly

thethe rig

.

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ion.

ning

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ring


1-11March 1995

• However, in the event that the well gets out of control, the Company Representhas the right to assume complete control and supervise the work required to rfull control of the well. (This entitlement is a standard condition of Company drillcontracts.)

(d) The Contractor Toolpusher

• Has overall responsibility for the implementation of the well control operation

• Has the responsibility for ensuring that the driller and the drill crew are corredeployed during the well control operation.

• Must be present at the rig floor during the start of the kill operation. EitherToolpusher or the Company Representative should be present at all times on floor during the operation.

• Has the responsibility for briefing the off duty drill crew prior to starting a new␣shift

(e) The Driller

• Has the responsibility for the initial detection of the kick and closing in the we

• Has the responsibility for supervising the drill crew during the well control operat

(f) The Mud Engineer

• Has continuous responsibility for monitoring the mud system and the conditioof the mud.

It may be prudent to send an extra Mud Engineer to the rig in the event of a well coincident to ensure constant supervision of the mud system.

(g) The Cementing Engineer

• Will ensure that the cement unit is ready for operation at any time.

• Will operate the cement unit at the discretion of the Company Representative

(h) The Subsea Engineer (where appropriate)

• Should be available for consultation at all times during the well control opera

• Has the responsibility for checking all the BOP equipment during the operatio

(j) The Mud Logging Engineers

• Have the responsibility for continuously monitoring the circulating system duthe well control operation.

• One member of the crew must keep a diary of events.

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1-12March 1995

3 Communication

One of the Company Representative’s responsibilities is to organise a pre-kill meeting oncethe well has been shut-in. The purpose of this meeting is to ensure that all those involvethe supervision and implementation of the well control operation are familiar withprocedures that will be used to kill the well. This meeting is also the first stage in thprocess of communication during the well control operation.

Experience has shown that even the most well conceived well control procedures cbadly wrong if communication before and during the operation is not properly organisedand effective.

It is therefore most important that the well control contingency plan details the methodline of communication for each individual involved in the operation.

The objectives of a suitable system of communication are:

• To ensure that all information relevant to the well control operation is communicatethe Company Representative.

• To ensure that those involved in the supervision of the operation are at all timcommunication with the Company Representative.

• To ensure that all those involved in the operation are aware of the line and methcommunication that they should use.

• To ensure that communication equipment on the rig is adequate, and is used duriwell control operation in the most effective manner possible.

Figure 1.4 shows an example of a possible communication system on a semi-submersfor use during standard well control operations. The following can be noted from this example

• After the kick is taken, the well is shut-in and closely monitored.

• The Company Representative calls a pre-kill meeting of those involved in the supervof the operation.

• Responsibilities are allocated to those involved in the operation by the supervisorsattended the meeting.

• Each line and method of communication is defined. It should be noted that:

– The rig telephone system is not overloaded.

– The most important lines of communication to and from the Company Represent(denoted by those inside the broken line) are best maintained with the use ofheld radios.

– The use of intrinsically safe hand held radios ensures that all those inside the bline can listen in on each others communication.

– Depending on the type of operation it may be necessary to include others withibroken line.


1-13March 1995

Figure 1.4 An Example Communication System

1-13/14

COMPANY REPRESENTATIVE COMPANY DRILLING ENGINEER

SENIOR CONTRACTOR REPRESENTATIVE TOOLPUSHER

MUD ENGINEER MUD LOGGING ENGINEER

(2) PREKILL MEETING

(1) KICK TAKEN – WELL SHUT-IN – WELL BEING MONITORED

(3) ALLOCATE RESPONSIBILITIES

MUD ENGINEER

SENIOR CONTRACTOR

REPRESENTATIVE

SENIOR CONTRACTOR

REPRESENTATIVE

TOOLPUSHER

CONTRACTOR STAFF

MATESOFF DUTY DRILL CREW

SUBSEA ENGINEER

CONTRACTOR SHOREBASEDRILLER

PUMPMAN/ DERRICKMANDRILL CREW

(4) MAJOR LINES/METHOD OF COMMUNICATION DURING THE WELL CONTROL OPERATION

MUD ENGINEERTOOLPUSHER

MARINE STAFF

PUMPMAN/ DERRICKMANDRILLER

CONTRACTOR SHOREBASE

COMPANY REPRESENTATIVE

SERVICE COMPANY ENGINEERS

COMPANY SHOREBASE

DRILL CREW

MUD LOGGING ENGINEER

SUBSEA ENGINEER

RT

S/S

RT

RT

H/H

S/S

H/H

H/H

RT

RT

RT – RIG TELEPHONE SYSTEM H/H – HAND HELD SETS/S – SHIP TO SHORE

WEOX02.004


1.3 DRILLS AND SLOW CIRCULATING RATES

Paragraph Page

1 General 1-16

2 BOP Drills 1-16

3 D1: Kick while Tripping 1-17

4 D2: Kick while Drilling 1-17

5 D3: Diverter Drill 1-19

6 D4: Accumulator Drill 1-19

7 D5: Well Kill Drill 1-21

8 Slow Circulating Rate Pressures, SCRs 1-22

9 Choke Line Losses 1-23

Illustrations

1.5 SCR Pressure Plot 1-23

1.6 Choke Line Pressure Loss Data Sheet 1-25

1.7 An example Determination of Choke Line Losses 1-26

1-15March 1995

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1-16March 1995

1 General

Both BOP Drills and the recording of slow circulating rate pressures will be carried oua routine basis on all rigs.

This section covers the reasons why it is necessary to carry out BOP Drills, to regrecord SCRs, as well as recommended procedures.

2 BOP Drills

The purpose of BOP Drills is to familiarise the drillcrews with techniques that willimplemented in the event of a kick.

One of the major factors that influences the wellbore pressures after a kick is takenvolume of the influx. The smaller the influx, the less severe will be the pressures duringwell kill operation. In this respect, it is important that the drillcrew react quickly to any sthat an influx may have occurred and promptly execute the prescribed control proceDrills should be designed to reduce the time that the crew take to implement these proce

The relevant Drills should be carried out as often as is necessary, and as hole conditionspermit, until the Company Representative and the Contractor Toolpusher are satisfied thaevery member of the drillcrew is familiar with the entire operation.

Every effort must be made to ensure that the Drill is carried out in the most realistic mapossible. Where practical, there should be no difference between the Drill and actual contrprocedures.

Once satisfactory standards have been achieved, the Drills (D1, D2 and D3, as approshould be held at least once per week. If standards fall unacceptably, the CompanyRepresentative should stipulate that the Drills are conducted more frequently.

It is important that returning drillcrews have frequent Drills.

The following Drills should be practised where applicable:

D1 – TrippingD2 – DrillingD3 – DiverterD4 – AccumulatorD5 – Well Kill(Suffix R to be included if the remote panel was used)

These codes should be used to record the results of the Drill on the BOP Drill RProforma. This form should be sent to the Drilling Superintendent fortnightly. The resultsof each Drill must also be recorded on the IADC Drilling Report.

l be

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ing

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1-17March 1995

3 D1: Kick while Tripping

The purpose of this Drill is to familiarise the crew with the shut-in procedure that wilimplemented in the event of a kick during a trip. This Drill should only be conducted whenthe BHA is inside the last casing string.

Before the trip is started, the Standing Orders to the Driller will have been posted. This willdetail the action that the crew should take in the event a kick is detected.

When directed by the Company Representative, the Contractor Toolpusher will instruct theDriller to assume that a positive flowcheck has been conducted, and to implemenprescribed control procedure as detailed in the Standing Orders.

Shut-in procedures to be adopted in the event of a kick while tripping are detailed in Chap

However, as a guideline the following procedure should be initiated:

• Without prior notice, the Company Representative will start the Drill by manually raisthe trip tank float to indicate a rapid pit gain.

• The Driller is expected to take the following steps to shut in the well:

1. Stop other operations.

2. Install the drillpipe saf ety v alve .

3. Open the c hoke line v alve .

4. Close the ann ular pre venter .

5. Recor d the casing and drillpipe pressure .

6. Notify the Compan y Representative that the well is shut-in.

7. Recor d the time f or the Drill on the IADC Drilling Repor t.

The Contractor Toolpusher must ensure that the crew are correctly deployed and thatindividual completely understands his responsibilities.

The time taken for the crew to shut in the well should be recorded.

Having shut-in the well, preparations should be made to strip pipe. These preparations shouldinclude lining up the equipment as required, assigning individual responsibilitiespreparing the Stripping Worksheet.

4 D2: Kick while Drilling

The purpose of this Drill is to familiarise the crew with the control procedure that wilimplemented in the event of a kick while drilling.

This Drill may be conducted either in open or cased hole. However if the drill is conduwhen the drillstring is in openhole, the well will not be shut-in .

drill:

nt pit

ucted

eline

cted

es as


1-18March 1995

When the pipe is on bottom, the following procedure can be used as a guideline for the

• Without prior notice, the Company Representative gradually increases the apparelevel by manually raising the float.

• The Driller is expected to detect the pit gain and take the following steps:

1. Pick up the kell y (or topdrive) until the tool joint c lears the BOPs andthe kell y coc k is just abo ve the r otar y tab le.

2. Shut do wn the pumps.

3. Check the well f or flo w.

4. Repor t to the Compan y Representative .

5. Recor d the time required f or the cre w to react and conduct the Drill onthe IADC drilling repor t.

When the bit has been tripped to the previous casing shoe, a further Drill may be condthat will result in the well being shut-in.

Therefore after tripping the bit to the shoe, the following procedure may be used as a guidfor this Drill:

• Stop tripping operations and install the kelly (or topdrive) and start circulating.

• Having been instructed to do so by the Company Representative, the Driller is expeto take the following steps to shut-in the well:

1. Pull up until the tool joint c lears the BOPs.

2. Shut do wn the pumps.

3. Open the c hoke line v alve .

4. Close the ann ular pre venter .

5. Recor d the casing and drillpipe pressure .

6. Doub le check spaceout, close and loc k hang-off rams and hang-off pipeand c heck that the kell y coc k is just abo ve the r otar y tab le.

7. Notify the Compan y Representative that the well has been shut-in.

8. Recor d the time taken f or the cre w to shut-in the well on the IADC drillingrepor t.

* If on a floating rig

The procedures adopted during these Drills should be in line with the shut-in proceduroutlined in the Standing Orders. These procedures are outlined in Chapter 4.

*

eryle in

s. tly

vered be

ties.

the

very

to

rting.


1-19March 1995

5 D3: Diverter Drill

If shallow gas is encountered and the well kicks, blowout conditions may develop vquickly. It is therefore important that crew initiate control procedures as soon as possibthe event of a shallow gas kick.

Diverter Drills should therefore be carried out to minimise the reaction time of the crewAfurther objective of the Drill is to check that all diverter equipment is functioning correc.The time taken for each diverter function to operate should be recorded. A Drill should becarried out prior to drilling out of the conductor casing.

The procedures that should be implemented in the event of a shallow gas kick are coin Chapter 4. Drills should be designed in line with the specific procedure that willadopted in the event of a shallow gas kick.

The Contractor Toolpusher must ensure that the drill crew, and marine staff (offshore), arecorrectly deployed during the Drill and that each individual understands his responsibili

The time recorded in the log should be the time elapsed from initiation of the Drill until rig crew (and marine staff) are ready to initiate emergency procedures.

6 D4: Accumulator Drill

The purpose of the Accumulator Drill is to check the operation of the BOP closing system.The following specific tests are recommended:

(a) Accumulator precharge pressure test

This test must be conducted on each well prior to spudding and approximately e30␣days thereafter at convenient times.

On closing units with two or more banks of accumulator bottles, the hydraulic fluid lineeach bank must have a full opening valve to isolate individual banks. The valves must be inthe open position except when accumulators are isolated for testing, servicing or transpoThe precharge test should be conducted as follows:

1. Shut-off all accum ulator pumps.

2. Drain the h ydraulic fluid fr om the accum ulator system into the c losing unitfluid reser voir.

3. Remove the guar d fr om the v alve stem assemb ly on top of eac haccum ulator bottle . Attac h the c harging and gauging assemb ly to eac hbottle and c heck the nitr og en prec harge.

4. If the nitr ogen prec harg e pressure on an y bottle is less than the minim umacceptab le prec harge pressure listed belo w, rec harge that bottle (withnitr og en gas onl y) to ac hieve the specified desired prec harge pressure .

5. If the nitr og en prec harge on an y bottle is greater than the maxim umacceptab le prec harg e pressure listed belo w, a sufficient v olume of nitr ogengas m ust be b led fr om the accum ulator bottle to pr ovide the specifieddesired prec harg e pressure .

s

.

e

ing

sure itder


1-20March 1995

Accumulator Desired Min. Acceptable Max. AcceptableWorking Pressure Precharge Precharge Precharge

Rating Pressure Pressure Pressure

1500 psi 750 psi 750 psi 850 psi2000 psi 1000 psi 950 psi 1100 psi3000 psi 1000 psi 950 psi 1100 psi

(b) Accumulator closing test

This test should be conducted before BOP stack tests. The test should be conducted afollows:

1. Position a joint of drillpipe in the b low out pre venter stac k.

2. Close off the po wer suppl y to the accum ulator pumps.

3. Recor d the initial accum ulator pressure .

The pressure should be the designed operating pressure of the accumulators.Adjustthe regulator to provide 1500 psi operating pressure to the annular preventer.

4. Operate the sequence of functions as rele vant to the rig type .

For a land rig:Close the annular preventer and one pipe ram (sized for the pipe in the stack)Open the HCR valve on the choke line.

For the floating rig:Close and open all the well control functions (apart from blind/shear rams).Duplicate the operation of the blind/shear rams.

After each function, record the volume used, the time taken, and the residualaccumulator pressure. The residual accumulator pressure after completing all thtests must be at least 200 psi greater than the precharge pressure.

5. Turn on the accum ulator pumps.

Having completed the tests, recharge the accumulator system to its designed operatpressure. Record the time taken to recharge the system.

(c) Closing unit pump test

Prior to conducting any tests, the closing unit reservoir should be inspected to be does not contain any foreign fluid or debris. The closing unit pump capability test shoulbe conducted before BOP stack tests. This test can be conveniently scheduled eithimmediately before or after the accumulator closing time test. The test should beconducted according to the following procedure.

1. Position a joint of drillpipe in the b low out pre venter stac k.

2. Isolate the accum ulator s fr om the c losing unit manif old b y c losing therequired v alves.

uringwer

nularlator

imeceed

ng

gs.

ud).

ation

ction.


1-21March 1995

3. If the accum ulator pumps are po wered b y air , isolate the rig air systemfr om the pumps.

A separate closing unit air storage tank should be used to power the pumps dthis test. When a dual power (air and electric) source system is used, both posupplies should be tested separately.

4. Close the annular preventer and open one choke line failsafe valve(or␣HCR valve).

Record the time (in seconds) required for the closing unit pumps to close the anpreventer plus open the choke line valve and obtain 200 psi above the accumuprecharge pressure on the closing unit manifold. It is recommended that the trequired for the closing unit pumps to accomplish these operations does not extwo minutes.

5. Close the choke line failsafe (or HCR valve) and open the annularpreventer .

Open the accumulator system to the closing unit and charge the accumulator systemto its designed operating pressure using the pumps.

7 D5: Well Kill Drill

The objective of this Drill is to give drillcrews the most realistic type of well control␣trainiand a feel for the equipment and procedures that they would use to kill a well.

This Drill should be carried out prior to drilling out the intermediate and production strinIt should never be carried out when openhole sections are exposed. The following procedureis recommended:

1. Run in hole and ta g the top of cement.

2. Pull bac k one stand and install the kell y (or install topdrive).

3. Break cir culation and estab lish slo w cir culating rate pressures.

(Consider circulating bottoms up prior to this if the annulus may contain contaminated m

4. Carr y out standar d BOP Drill D2, resulting in the well being shut-in.

5. Consider appl ying lo w pressure to the casing (typicall y 200 psi), bring thepump up to kill speed contr olling the drillpipe pressure accor ding to apredetermined sc hedule .

It is important that this opportunity to circulate across a choke is used to maximum effect. Adrillpipe pressure schedule should be drawn up and carefully adhered to.

It is important that the choke operator develops a feel for the lag time between manipulof the choke and its subsequent effect on the drillpipe pressure. The lag time should berecorded, so that it can be used for reference should a kick be taken in the next hole se

at is

kick.ssureuld

rface

ssaryit is

sum

fallk on

deden

ssure attheup to


1-22March 1995

8 Slow Circulating Rate Pressures, SCRs

There are many reasons why a kick should be displaced from the hole at a rate thconsiderably slower than that used during normal drilling. These include:

• To minimise the pressure exerted on the openhole.

• To allow weighting of the mud as the kick is displaced.

• To permit adequate degassing of the returned mud.

• To limit the speed of required choke adjustments.

• To reduce the pressure exerted on well control equipment.

All these factors must be taken into account when deciding at what rate to displace theHowever the absolute upper limit for the displacement rate may be restricted by the prerating of the surface equipment, in particular the setting of the pump relief valve. It shobe noted that it is potentially hazardous to displace a kick from the hole when the supressure is close to the relief valve setting.

In order to estimate the circulating pressures during the displacement of a kick, it is neceto know the friction pressure in the circulating system at low rates. For this reason, useful to have determined the SCR pressure before a kick is taken.

At a given rate of circulation, the initial circulating pressure can be estimated from the of the shut-in drillpipe pressure and the SCR pressure.

Company policy states that SCRs should be conducted regularly and at least:

• Once per tour (or at 300m intervals during the tour).

• When the bit is changed.

• When the BHA is changed.

• When the mud weight or properties are changed.

The range of circulation rates used will be dependent upon many factors, but shouldwithin the limits of 1/2 and 4 barrels per minute. If oil base mud is in the hole, when bacbottom after a trip, circulate bottoms up before measuring SCRs.

At these relatively low pump speeds the volumetric efficiency of the rig pumps may besignificantly less than at normal speeds used during drilling. It is therefore recommenthat the volumetric efficiency of the rig pumps is checked at low pump speed, such as whpumping a slug prior to a trip.

It is useful to plot the SCRs on a graph as shown in Figure 1.5. The drillstring internalfriction should be calculated at the SCRs and used to determine the annulus frictional preas shown. The annulus frictional pressure is a major factor that will influence the ratewhich the kick will be displaced from the hole (using standard well control procedure annulus frictional pressure will be added to wellbore pressure as the pump is brought speed to kill the well).

tuallya range

kick

can be

nal

ed. Ife choke

by an


1-23March 1995

SCR1 SCR2 SCR3

PSCR1

PSCR2

PSCR3

ST

AN

DP

IPE

PR

ES

SU

RE

(ps

i)

Drillstring internal pressure drop

Annulus pressure drop

Other SCRs can be selected to displace the kick

PUMP OUTPUT (bbls/min) (stks/min)

WEOX02.005

Figure 1.5 SCR Pressure Plot

A graph similar to Figure 1.5 aids the selection of circulation rates other than these acmeasured and also provides a guide to the size of the annulus circulating losses over of circulation rates.

9 Choke Line Losses

The frictional pressure caused by circulating through the choke line, while displacing afrom the well, can cause additional pressures to act in the wellbore.

These pressures are not significant in the case of land, platform and jack-up rigs, but critical in the case of a floating rig.

In most cases however, if the correct procedures are adhered to, the choke line frictiopressure should be accounted for as the kick is displaced out of the hole. The recommendedmethod is to monitor the wellhead pressure through the kill line as the pump is startthe wellhead pressure remains constant as the pump is brought up to speed then thline friction will in most cases be automatically compensated for. (This technique is outlinedin detail in Chapter 6.)

It is also possible to account for the choke line losses by reducing the choke pressureamount equal to the choke line loss as the pump is brought up to speed. This method is notconsidered to be as reliable as using the kill line monitor.

e ofssedted.

line

shoe.

s an

form.hts. to


1-24March 1995

It is important that the choke line frictional pressure is accurately known at a wide rangcirculating rates. From this information the additional load on the wellbore can be asseat a range of displacement rates and subsequently the most suitable rate can be selec

The following procedure should be implemented in order to properly assess the chokefrictional pressures at slow circulating rates. This procedure should be carried out initiallywhen the BOP and riser are installed and before drilling out of each subsequent casing

1. Install suitab le pressure gaug es to recor d standpipe and c hoke pressuresduring cir culation.

2. Recor d SCR pressure at a rang e of rates fr om 1/2 to 4 bb l/min do wn drillpipeand up the riser .

3. Open c hoke line v alves.

4. Line up c hoke manif old to r oute flo w acr oss a full y opened remote operatedchoke . Route returned flo w thr ough the poorbo y gas separator to theshaker s.

5. Space out to ensure no tool joint is opposite ann ular pre venter .

6. Close ann ular pre venter .

7. Circulate do wn the drillpipe and up thr ough the c hoke line until returns areunif orm.

8. Recor d SCR pressure at same rates as bef ore . Recor d the c hoke pressureat each rate .

9. Calculate the c hoke line frictional pressure at eac h rate .

Figure 1.6 shows a form that can be used to record the data. The form also shows how todetermine the choke line friction pressure from the recorded data. Figure 1.7 showexample determination of choke line losses.

The choke line losses should be adjusted for changes in mud weight as shown on the The accuracy of this adjustment is however questionable over a wide range of mud weigIn order to verify choke line losses after drilling out of the casing shoe, it is acceptableisolate the well and pump down the choke line at the range of slow circulating rates.

BP

WE

LL CO

NTR

OL M

AN

UA

L

1-25M

arch 1995

Figure 1.6

Choke Line P

ressure Loss Data S

heet

DATE

RECORDED BY

CHOKE LINE PRESSURE LOSS DATA SHEET

25/7/87

J. P.

CORRECTED CHOKE LINE

LOSS

AT…………… MUD WEIGHT

(psi)


LOSS


(psi)


LOSS


(psi)

WEOX02.006

CIRCULATION RATE

(bbl/min)

WELL No

(1) (2) (3) (2)-(1)-(3)

RIG

WELL STATUS DURING TEST

PROPERTIES OF THE MUD IN THE HOLE DURING THE TEST

……………in LINER

PUMP RATE

(SPM)

……………in LINER

PUMP RATE

(SPM)

SCR PRESSURE UP RISER

(psi)

SCR PRESSURE

UP CHOKE LINE

(psi)

6.5

25 RIG 19

133/8in CASING RUN AND TESTED / 135/8in STACK INSTALLED AND TESTED

1.4SG OBM/PV24CP/YP100 lb/100ft2

4.78 40 985

RIG PUMPS: NATIONAL 12 - P - 160

CEMENT PUMP - HT - 400 (4in PLUNGER)

1435 80 370

3.58 30 680 985 55 250

2.39 20 400 590 40 150

1.00 120 190 25 45

0.5 50 65 0 10

0.25 0 0 0 0

CHOKE PRESSURE

AT SCR

(psi)

MEASURED CHOKE LINE

LOSS


(psi)

1.4 SG


1-26March 1995

Figure 1.7 An example Determination of Choke Line Losses

400

CIRCULATING @ 20SPM UP RISER

PSCR @ 20SPM = 400psi

600

CIRCULATING @ 20SPM UP CHOKE LINE (CHOKE WIDE OPEN)

POC = 50psi

50

PCL = PSCR (up choke line) – PSCR (up riser) – POC= 600 – 400 – 50

PCL = 150psi

where PSCR = Slow Circulating Rate Pressure (psi)

PCL = Choke Line Pressure Loss at SCR (psi)

POC = Choke Pressure recorded at SCR with choke wide open (psi)

WEOX02.007


1.4 USE OF THE MUD SYSTEM

Paragraph Page

1 General 1-28

2 Pit Management 1-28

3 Building Mud Weight 1-29

4 Dealing with Gas at Surface 1-31

5 Chemical Stocks 1-34

Illustrations

1.8 An example Mud Gas Separator 1-32– operating at maximum capacity

1-27March 1995

ill be

ctory

tection.ctive

which

efore

ctionsre in

if oil. Mud

acing

t.


1-28March 1995

1 General

Well control contingency plans should outline the manner in which the mud system wutilised during standard well control operations.

This section is intended to highlight the major factors that will determine the most satisfaarrangement of the mud system in such circumstances.

2 Pit Management

The following guidelines should be considered when specifying pit arrangements:

(a) While drilling a critical hole section

• Keep the active mud system surface area as small as is practical to ease kick deAny reserve mud stocks in the tanks should be positively isolated from the asystem. Ensure that the gates on the trough are sealing properly.

• Adequate reserve stocks of mud should be held; the volume and weight of will be determined by the nature of the next hole section.

• Ensure all pit level systems and tank isolating valves are working correctly bdrilling into possible gas-bearing zones.

• Keep all mud treatments and pit transfers to the absolute minimum at critical seof the well. Ensure that the Driller and the Mud Logging Engineer are awaadvance of any changes to the system.

• Crew safety meetings should discuss the problem of gas kicks, especially based mud is in use, and emphasise the importance of early detectionengineering and mud logging personnel should attend these meetings.

(b) When displacing a kick

The major factors that will determine the most satisfactory pit arrangement for displa kick include the following:

• The technique that will be used to displace the kick.

• The usable surface pit volume in relation to the hole volume.

• The method of weighing up the mud.

• How to deal with the kick when it is displaced to the surface.

• How to deal with the pit gain caused by influx expansion during displacemen

• How to deal with contaminated returns.

• The nature and toxicity of the influx fluid.

• The monitoring of pit levels in the active system.

d

med

ment.

hole

inaland

uiredre theitted)

ud

plied

k is

d as

given


1-29March 1995

The kick can be displaced from the hole using either the Wait and Weight Method or theDriller ’s Method. The most satisfactory arrangement of the pits will be different for eachtechnique and clearly will be rig-specific. There are three different stages at which the mucan be weighted up for these two techniques:

• The Wait and Weight Method

– In a typical situation when it is impractical to weight up a complete hole voluprior to displacement of the kick. This will therefore entail that some mud is weightewhile the kick is displaced from the hole. The volume that is weighted prior todisplacement of the kick will depend, for a given hole capacity, on the rate at whichbaryte can be added into the system in relation to the desired rate of displace

– In the unusual situation when there is adequate surface volume, a completevolume of kill mud can be prepared before displacement of the kick.

• The Driller’s Method

– In this case the mud is weighted either while the kick is displaced with origweight mud or after the first circulation depending on the availability of baryte tank space.

3 Building Mud Weight

(a) Baryte delivery to the mud pits

The rate at which baryte can be added to the original mud influences the time reqto increase the weight of a volume of mud. For this reason it is important to measurate at which both the conventional hopper system and the high rate system (if fcan supply baryte.

If the Driller’s Method is used this will determine the time required to build the mweight after the kick has been displaced from the hole.

If the Wait and Weight Method is used, the maximum rate at which baryte can be supto the mud will:

• Determine the time required to weight the hole volume of mud before the kicdisplaced.

• Or it may limit the rate at which the kick can be displaced, if the mud is weightethe kick is displaced.

The maximum rate at which the mud can be weighted can be determined for a required mud weight increase from the following formula:

Maximum possible rate = Baryte delivery rate (lb/min)at which the mud can Baryte required to weight up (lb/bbl)be weighted (bbl/min)

mud

l times

.

hteds:

tive

builtbase

ase

es can

umy a

id’

d, and


1-30March 1995

Therefore for the following example:

Required mud weight increase = 0.2 SG (from 1.5 SG to 1.7 SG)

Baryte required = 1490 X (1.7 - 1.5) = 117 lb/bbl4.25 - 1.7

If the maximum barytes delivery rate for the rig = 350 lb/min

Then:

Maximum rate at which the = 350 = 3 bbl/minmud can be weighted 117

This figure therefore gives an indication of the maximum displacement rate if the is weighted as the kick is displaced from the hole.

(b) Baryte storage

When possible at least one full barytes storage tank should be pressured up at aland the bulk delivery system tested regularly.

The bulk system should be included in the rig PMS (Preventive Maintenance) system

(c) Building viscosity into the mud

There may be well control situations which require that considerable volumes of weigmud are built from a water or oil base. This may be the case in the following situation

• If considerable losses are experienced.

• If the required volume of kill weight mud is greater than the surface stocks of acand reserve weighted mud.

• If the returns are severely contaminated and have to be dumped.

The limiting factor for an oil base mud may be the rate at which viscosity can be into the base oil. Building viscosity is usually a less important factor when water muds are used.

Shear equipment is required for building viscosity using clay viscosifiers in new boil. Some offshore rigs have jet line mixers to help build viscosity.

In circumstances in which large volumes of new oil mud must be built, it would buseful to know the rate at which new mud can be sheared to a level at which barytebe suspended.

This rate is determined by shearing a known volume of new mud until the minimviscosity is reached. As a guideline, the minimum viscosity would be represented byield point of 10, and a 10 second gel reading of 3.

In emergency situations, viscosity can be built quickly using an oil mud polymer (BarosLFR 2000 as an example) at 4 lb/bbl in conjunction with organophilic clays. However,it is recognised that these polymers can cause high temperature gelation of the muas such, they are not recommended for use in high temperature wells.

wing

nce it

sser for

laced.low

the

andle.on toehe mud

be aslope 1.8.


1-31March 1995

(d) Volume increase due to baryte addition

The volume of a given amount of mud will increase as baryte is added to it. This may besignificant when large mud weight increase is required in a large volume of mud.

The volume increase due to baryte addition can be determined from the follorelationship:

Volume increase = 1.48 bbl per metric ton of baryte added

Therefore in the following situation:

The required addition of baryte = 200 lb/bbl

Volume to weight up = 600 bbl

Volume increase due to baryte addition

= 600 X 200 X 1.48 = 80 bbl2205

4 Dealing with Gas at Surface

It is important that suitable equipment is available on the rig to deal with the influx ois displaced to surface.

Returns should be piped through the mud gas separator and then on to the degafurther treatment.

(a) The mud gas separator (poorboy)

The mud gas separator should be lined up at all times when a kick is being dispThe separator is used to remove large gas bubbles from the mud and to deal with a fof gas once the influx is at surface.

There will be a limit to the volume of gas that each separator can safely deal with.Whenthis limit is exceeded, there exists the possibility that gas will blow through intoshaker header box.

An estimation can be made of the maximum gas flowrate that the separator can hThe limiting factors will be the back pressure at the outlet to the vent line in relatithe hydrostatic head of fluid at the mud outlet of the separator. When the back pressurdue to the gas flow is equal to, or greater than, the hydrostatic head available at toutlet, the gas will blow through to the shaker header tank. See Figure 1.8.

In order to minimise the possibility of a gas blow-through, the vent line should straight as possible and have a large ID. The mud outlet should be configured to devea suitable hydrostatic head (minimum recommended head is 10 feet). See Figur

uge as be in they noted

ed inoard


1-32March 1995

The back pressure due to the flow of gas should be monitored with a pressure gashown in Figure 1.8. Some warning of the possibility of a gas blow-through willgiven when the registered pressure approaches the hydrostatic head of the fluiddischarge line. It should be noted that the maximum hydrostatic head available mabe that of the mud in the event that large volumes of oil or condensate are displacto␣surface.

If the safe operating limit of the separator is approached, the choke can be clos(while ensuring that the well is not overpressured) or the flow switched to the overbline or the burn pit.

Figure 1.8 An example Mud Gas Separator– operating at maximum capacity

INSPECTION COVER

GAS OUTLET

8in ID MINIMUM

GAS BACK PRESSURE REGISTERED AT THIS GAUGE (Typically 0 to 20psi)

INSPECTION COVER

SECTION A-A TANGENTIAL INLET

TO SHAKER HEADER TANK

2in DRAIN OR FLUSH LINE4in CLEAN-OUT

PLUG

A A

10ft MINIMUM HEIGHT

8in NOMINAL ‘U’ TUBE

BRACE

30in OD

STEEL TARGET PLATE

INLET

HALF CIRCLE BAFFLES ARRANGED IN A ‘SPIRAL’ CONFIGURATION

4in ID INLET-TANGENTIAL TO SHELL FROM CHOKE MANIFOLD

MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg: 10ft HEAD AT 1.75 SG GIVES 7.6psi MAXIMUM CAPACITY

10ft APPROX

APPROX HEIGHT 1/2 OF

WEOX02.008

e mud

estedows:

l mudge isrking.

mud

n␣the.

ns be

ay beions:

ible togashoke


1-33March 1995

(b) The degasser

The degasser should be lined up at all times during the well control operation.

The degasser is designed to remove the small bubbles of gas that are left in thafter the mud has been through the mud gas separator.

It is important that the degasser is working properly and as such it should be tevery tour. While drilling with gas cut returns, the degasser can be checked as foll

1. Measure actual (gas cut) mud weight at the shaker header box using anon pressurised mud balance.

2. Measure actual mud weight at the degasser outlet using a nonpressurised mud balance.

If the actual mud weight at the outlet of the degasser is greater than the actuaweight at the inlet, then the degasser is working. If the mud weight at this stanot equal to the active system mud weight, then either the degasser is not woproperly, or the returns are at a lower weight than the mud in the active system

If the actual mud weight measured at this stage is equal to the active systemweight, then the degasser is working properly.

3. Measure m ud weight at the degasser outlet and the shaker header bo xusing a pressurised m ud balance .

If the actual mud weight at the outlet of the degasser is equal to the reading opressurised mud balance, the degasser has removed all the gas from the mud

(c) Overboard lines/Flare lines

It is recommended that a second method of dealing with severely gas cut returavailable at the rigsite, whether on land or offshore. This will generally be either anoverboard line, or a flare line to the burn pit on land.

It should be easy to switch the returns from the mud system to the flare line. It mnecessary to use the flare line during a well control operation in the following situat

• The gas flowrate is too high for the mud gas separator.

• Hydrates are forming in the gas vent line from the mud gas separator.

• The gas is found to contain H2S.

• The mud system is overloaded.

Lines that are required to handle high velocity gas must be as straight as possminimise erosion. Significant erosion is likely to occur in the path of high velocity and solids, therefore the redundancy in flowlines and manifolds downstream of the cmust be analysed on all rigs.

ould

ntirea in to

ish to

ill be

priorof


5 Chemical Stocks

(a) Baryte and mud chemical stocks

Company policy details the minimum stocks of baryte and mud chemicals that shbe held at the rigsite. The policy states that:

‘Sufficient weighting material stocks must be maintained on site such that the emud circulating volume can be raised by a minimum of 0.25 SG (See formulParagraph 3). Reserve stocks of bentonite or viscosifier must also be on siteenable this increase in mud weight to be effected’.

‘Where transport and logistics are not assured (offshore and remote locations) theminimum onsite weighting material stock must be 100 tonnes’.

This is a minimum standard, and as such, the Company Representative may wstock a greater quantity of baryte and chemicals.

(b) Cement stocks

Cement stocks should not drop below the quantity of cement and additives that wrequired to set 2 X 150m of cement plugs in the hole section being drilled.

Additionally, in high pressure wells, an abandonment plug recipe should be onsite to drilling into the reservoir. Batch mix tanks should also be onsite during the drilling such reservoir sections.

1-34March 1995


1.5 KICK TOLERANCE

Paragraph Page

1 General 1-36

2 Kick Tolerance Calculation Methods 1-36

3 Procedure for Kick Tolerance Calculations 1-37

4 Considerations for High Angle and Horizontal Wells 1-40

5 When to Calculate Kick Tolerance 1-41

6 Excel Kick Tolerance Calculator 1-42

Illustrations

1.9 Kick Tolerance Values Through a Zoneof Increasing Pore Pressure 1-43

1.10 Excel Kick Tolerance Calculator – Example Calculations 1-44

1-35March 1995Rev 1 March 1995

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1-36March 1995

1 General

Many definitions of kick tolerance have been used in the drilling industry. Within BP, KickTolerance is defined as the maximum volume of kick influx that can be safelyshut-in and circulated out of the well without breaking down the formation atthe openhole weak point .

It is now an accepted part of the Company Casing Design policy to determine the csetting depth by the Limited Kick Method. It is therefore particularly important thatkick tolerance in critical hole sections be accurately monitored.

This section explains how to calculate kick tolerance and when to calculate kick tolerance

In critical hole sections, it is important to calculate kick tolerance on a regular basis. This isbecause kick tolerance changes as a function of hole depth, BHA geometry, mud weight,formation pressure and influx type, etc.

2 Kick Tolerance Calculation Methods

Depending upon how kick tolerance is defined, a number of methods exist for kick tolecalculations. In general, these methods can be classified into two categories:

1 Simple Methods

In these methods kick tolerance calculations are simplified based on several assum

• The kick influx is a “single bubble”.

• At the initial shut-in condition, the influx is at the bottom of the openhole.

• The effects of the gas migration, gas dispersion, gas solubility, downhole temperatureand the gas compressibility are ignored.

Although these assumptions may seem unrealistic, the simple methods have gaineacceptance in the drilling industry because they are simple and generally conservative (safer) kick tolerance. However these methods have an inhshortcoming: they do not measure how quickly an influx will grow. This is to say that insome cases formation deliverability may be such that the well could not be shbefore the kick tolerance volume was exceeded. Therefore the same kick tolerancbetween two wells may not mean that they share the same level of risk !

2 Computer Kick Simulators

In the recent years many sophisticated computer simulators have been developedcan provide a good approximation of kick conditions from the stage when it flowsthe wellbore to that when it is circulated out. In the simulations, assumptions usthe simple methods are replaced by mathematical models.

Among many other applications, the kick simulators can be used for kick tolercalculations. They can predict the maximum pressures at any point of the annulusthe results are more accurate and less conservative than using the simple methaddition, as simulators can simulate how quickly an influx will flow into the wellbothey can predict how much time the rig crew have to shut in the well before the iexceeds the kick tolerance limit. Therefore simulators can be used to provide dirindications in the level of risk involved under various scenarios.

Rev 1 March 1995

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1-37March 1995

However, due to complexity, kick simulators are recommended only in the situatiowhere kick tolerance is considered critical based on the simple methods.

Some computer kick simulators are available from the Drilling & Completions BraBP Exploration, Sunbury.

3 Procedure for Kick Tolerance Calculations

The method illustrated in the following is one of the simple methods. The method calculatesthe maximum allowable kick influx volume when the well is shut in. The method considerstwo scenarios:

• When the influx is at the bottom of the hole at the initial shut in condition

• When the top of the influx has been displaced to the openhole weak point (witoriginal mud weight)

The following procedure can be used to calculate the kick tolerance:

1 Estimate the saf ety factor to be applied to the Maxim um Allo wab le Ann ularSurface Pressure (MAASP)

When the influx is displaced from the hole, there will be additional pressures actithe wellbore. The following are some of the possible causes of such additional presduring circulation:

• Choke operator error (depending upon the choke’s condition, operator’ sexperience,␣etc.)

• Annular friction pressure (depending on the hole size, mud properties, etc.)

• Choke line losses (in particular on floating rigs)

The safety factor (SF) to be applied to the MAASP will be the sum of these additpressures. The drilling engineer must use his/her judgement to determine the mappropriate safety factor.

2 Calculate the Maxim um Allo wab le Ann ular Surface Pressure (MAASP)Without Breaking Do wn the Weak Point Formation:

MAASP = Pleak

– 1.421 x MW x TVDwp

– SF(psi)

where:

MAASP Maximum allowable annular surface pressure (psi)MW Mud weight in hole (SG)P

leakLeak-off pressure at the openhole weak point (psi)

SF Safety factor (psi)TVD

wpVertical depth at the openhole weak point (m)

It should be seen that MAASP is determined based on the consideration of the formfracturing pressure at the openhole weak point. So it is considered only when thefull mud column from the weak point to the surface (i.e. the influx is still below weak point). If lighter fluids (such as a gas influx) occupy the annulus above the point, the surface pressure in excess of MAASP may not cause downhole faTherefore from the moment the top of an influx has been displaced past the ope

Rev 1 March 1995

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1-38March 1995

weak point, MAASP is no longer a consideration and may be exceeded by a maginwhich should be determined based on the casing burst strength and the pressure of BOP stack and choke manifold.

The method for estimating the position of the influx top is described in Vol.I, Chapter 6,Section 6.1.

3 Calculate the maximum allowable height of the influx in the openholesection:

Hmax = MAASP – ( Pf – 1.421 X MW X TVDh)

1.421 X (MW – Gi)(m)

where:

Hmax

Maximum allowable height of the influx (m)G

iInflux gradient (SG)

Pf

Formation pore pressure (psi)TVD

hVertical depth of openhole (bit) (m)

4 Calculate the maximum allowable influx volume that H max corresponds toat the initial shut-in conditions

Vbh

= Hmax

x C1 / cos(θbh

) (bbl)

where:

Vbh

Maximum allowable influx volume at initial shut-in condition (bbl)C1 Annular capacity around BHA (bbl/m)θ

bhHole angle in the bottom hole section (degree)

If the bottom hole section is horizontal (or above 90 degree), the hole angle used calculation should be the openhole angle immediately above the horizontal sectionThekick tolerance should be the sum of the calculated volume (V

bh) plus the annular volume

of the horizontal section.

In cases where Hmax

/cos(θbh

) is greater than the length of BHA, the maximum allowabvolume (V

bh) should be calculated partly based on the annular capacity around B

and partly around drillpipe.

5 Calculate the maximum allowable influx volume that H max corresponds towhen the top of the influx is at the openhole weak point

Vwp

= Hmax

x C2 / cos(θwp

) (bbl)

where:

Vwp

Maximum allowable influx volume when top of the influx is at the openhoweak point (bbl)

C2 Annular openhole capacity around drillpipe (bbl/m)θ

wpHole angle in the openhole section below the weak point (degree)

In cases where Hmax

/cos(θwp

) is greater than the openhole drillpipe length below thweak point, the maximum allowable influx volume (V

wp) should be calculated partly

based on the annular openhole capacity around drillpipe and partly around BHA.

Rev 1 March 1995

the


1-39March 1995

6 Convert the maximum allowable influx volume at the weak point (V wp) towhat would be at the initial shut in condition

Based on Boyle’s law, the maximum allowable influx volume at initial shut-incorresponding to V

wp will be:

Vbh' = Vwp X Pleak

Pf

(bbl)

7 The actual kick tolerance should be the smaller of V bh (Step 4) and V bh'(Step 6)

Example:Bit depth: 4000 mCurrent hole size: 12-1/4"Hole angle: VerticalMud weight in hole: 1.60 SGBHA length / OD: 182 m / 8"Drillpipe OD: 5"Estimated pore pressure at 4000 m: 1.58 SGLast casing shoe: 2695 mLeak-off test EMW: 1.72 SGAnnular back pressure at SCR: 70 psiSafety margin for choke operator error: 150 psi

1. Estimate the safety margin to be applied to MAASP:

SF = 70 + 150 = 220 psi

2. Calculate MAASP:

Leak-off pressure, Pleak

= 1.421 x 1.72 x 2695 = 6587 psi

MAASP = 6587 - 1.421 x 1.6 x 2695 - 220 = 240 psi

3. Calculate the maximum allowable influx height in the openhole section:

Pore pressure gradient, Pf = 1.421 x 1.58 x 4000 = 8981 psi

Hmax = 240 - (8981 - 1.421 X 1.6 X 4000)

1.421 X (1.60 - 0.2) = 178m

4. Calculate the maximum allowable influx volume at the initial shut-in condition:

Annular capacity around BHA, C1= (12.252 - 82) / 313.8 = 0.2743 (bbl/m)

As the BHA length (182 m) is longer than Hmax (178 m), so the influx is around BHAonly when it is at the bottom of the hole. Therefore:

Vbh

= 178 x 0.2743 = 49 bbl

5. Calculate the maximum allowable influx volume when the top of influx is at casing shoe:

Annular capacity around openhole DP, C2= (12.252 - 52) / 313.8 = 0.3985 (bbl/m)

Openhole DP length = 4000 - 2695 - 182 = 1123 m ( > Hmax

of 178 m)

Rev 1 March 1995

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1-40March 1995

Vwp

= 178 x 0.3985 = 71 bbl

6. Convert Vwp

to the initial shut-in condition:

Vbh

' = 71 x 6587 / 8981 = 52 bbl

7. Therefore the actual kick tolerance is 49 bbl.

4 Considerations for High Angleand Horizontal Wells

In high angle and horizontal wells, reservoirs are often drilled at a high or horizangle with the last casing or liner string set on top of the reservoir. When consideringkick tolerance for the reservoir section, it is often the case that the maximum allogas height (determined by step 3 in the previous section) extends from the opebottom to inside the casing/liner. This implies that the well can tolerate an infinite volumof gas influx without fracturing the openhole weak point.

On the other hand, because of the long openhole section through the reservoir inangle or horizontal well, the influx volume can be potentially high. So when the inis circulated to surface, it may fill up the entire annuli of the vertical and low asections and result in very high choke pressures at surface. Therefore, the kick tolerancevolume in this case should be determined not only by the formation fracture gradithe openhole weak point but also by the maximum allowable surface pressure bathe casing burst strength and the pressure ratings of the surface equipment.

When drilling a high angle or horizontal well, the following procedure should be to determine the kick tolerance:

a. Calculate kick tolerance volume as V 1 using the method as described inthe previous section (Step 1 through 7)

b. Determine the maximum allowable surface pressure P surf based on thecasing burst strength and the pressure ratings of the surface equipment(BOP stack, choke manifold, etc.). Note its difference with MAASP whichis based on the formation fracture gradient at the weak point.

c Calculate the maximum allowable gas height H max when the gas influxtop has reached the surface:

Hmax = (Psurf - SF) - (Pf - 1.421 X MW X TVDh)

1.421 X (MW - Gi)

where:

Gi Influx gradient (SG)Pf Formation pore pressure (psi)SF Safety factor mainly determined by the choke operator error margin (psi)TVDh Vertical depth of openhole (bit) (m)

Rev 1 March 1995

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1-41March 1995

d Calculate the influx volume that H max corresponds to when the gas influxtop has reached the surface:

Vsurf

= Hmax

x Ccsn

(bbl)

where:

Vsurf

Maximum allowable influx volume when the influx top reaches surface (C

csnAnnular capacity in the casing near surface (bbl/m)

e Convert V surf to the corresponding volume at the initial shut-in condition:

V2 = Vsurf X Psurf

Pf

(bbl)

f The actual kick tolerance volume is the smaller of V 2 (step e) and V 1

(step␣a).

5 When to Calculate Kick Tolerance

Company policy states that:

“The kick tolerance of the weakest known point of the hole section being drilled muupdated continuously whilst drilling.

If the kick tolerance is less than 50 bbl the Drilling Superintendent must be informed

If the kick tolerance is less than 25 bbl for offshore wells or 10 bbl for land wells, drillingmay only continue when dispensation has been given by the Manager Drilling in tow

Kick tolerance will change if there is a change in hole depth, mud weight, formation preor BHA. Therefore kick tolerance must be constantly re-evaluated as the well is drilleonly based on the current condition but also on the future conditions which are expeoccur deeper in the well.

The frequency with which the kick tolerance should be re-evaluated is dependent nature of the well. However, in hole sections where kick tolerance is likely to be a critifactor, the following guidelines should be considered:

• After LO test, evaluate the kick tolerance at suitable intervals throughout the nexsection with a number of mud weights that are likely to be used.

• If the hole section contains a zone of rapid pore pressure increase, the kick tolshould be evaluated frequently based on the anticipated pore pressure.

• If any factors that affect the kick tolerance (such as mud weight, BHA) change assection is drilled, the kick tolerance below that point in the section should be re-eval

• At each stage in the hole section, the Company Representative and the Drilling Enmust assess the possibility of the pore pressure developing in a manner different to thatpredicted and hence its effect on the kick tolerance.

Rev 1 March 1995

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Figure 1.9 shows an example of the type of calculations that should be worked. The kicktolerance figures shown are those that would typically be calculated before a tranzone. As shown, the current bit depth is 3500 m and the kick tolerance has been calcuat various intervals across the zone of increasing pore pressure. The kick tolerance has beencalculated for the mud weight currently in use, for the maximum mud weight anticipatethe section, and intermediate weight.

From these figures, it is clear that a serious situation would develop if a kick was tfrom the high pressure zone with the mud weight currently in the hole. This might occur ifeither the pore pressure developed more rapidly than predicted, or if the steady increpore pressure was undetected at the surface.

The kick tolerance figures for the intermediate mud weight show that even at this wethe kick tolerance would be small if the high pressure zone was unexpectedly encoun

The kick tolerance is finally calculated at the maximum mud weight. These figures show afinal minimum kick tolerance of 50 bbl at that mud weight. The table also shows the kicktolerance if the pore pressure developed higher than predicted of 1.6 SG. In generafigures indicate that drilling should proceed cautiously through the zone of increasingpressure. On the basis of these figures, it may be decided to weight up the mud a camount before the predicted increase in pressure occurs.

The decisions that are made on the basis of kick tolerance figures such as these largely dependent upon the particulars of each situation, including the level of confidplaced in the pore pressure prediction.

6 Excel Kick Tolerance Calculator

Figure 1.10 is an Excel Kick Tolerance Calculator, which can be activated to calculate thkick tolerance by entering data into green-shaded cells. The kick tolerance volume, togethewith a range of other parameters, will be displayed automatically. The calculator is based onthe same method as described in the previous sections, except that it uses the presthe mid-point of the gas influx. So the calculator is slightly less conservative.



1-43March 1995

Figure 1.9 Kic k Tolerance Values though a Zoneof increasing Pore Pressure

Rev 1 March 1995

9000

3000 4000 5000 6000 7000 8000 9000

10,000

DEPTH (ft)

PORE PRESSURE (psi)

CASING SHOE Maximum Allowable Pressure 13.8ppg EMW

11,000

9.2ppg

CURRENT BIT DEPTH MW = 9.6ppg

9.2ppg

11.3ppg

13.2ppg

12,000

13,000

FOR CURRENT MW (9.6ppg)

TVD (ft)

11,480 12,470 12,630 12,795 12,960 12,990 13,123

9.6 9.6 9.6 9.6 9.6 9.6 9.6

9.2 9.2

10.2 11.3 12.3 12.4 13.2

600 600 460 215 30 7

(0)

12,960 9.6 13.2 (0)

MW (ppg)

PORE PRESSURE

(ppg)

KTOL (bbl)

FOR MUD AT 12ppg

TVD (ft)

11,480 12,470 12,630 12,795 12,960

13,123

12 12 12 12 12

12

9.2 9.2

10.2 11.3 12.3

13.2

600 600 450 246 112

10

12,960 13,123

12 12

13.2 13.3

10 (0)

MW (ppg)

PORE PRESSURE

(ppg)

KTOL (bbl)

TVD (ft)

11,480 12,470 12,630 12,795 12,960

13,123

13.3 13.3 13.3 13.3 13.3

13.3

9.2 9.2

10.2 11.3 12.3

13.2

600 600 450 280 153

50

13,123 13,123

13.3 13.5

13.3 13.2

35 40

MW (ppg)

PORE PRESSURE

(ppg)

KTOL (bbl)

FOR MUD AT 13.3ppg

WEOX02.009


1-44March 1995

Figure 1.10 Example Calculations using Excel KickTolerance Calculator

KICK TOLERANCE CALCULATORFor Vertical, Deviated or Horizontal Wells

Version 1.2, March 1995

Well: Example Calculation Units: (UK/US): UK

Kick Zone Parameters: Input Messages:1 Openhole Size ? (inch) 12.25 2 Measured Depth ? (m) 40003 Vertical Depth (m) ? (m) 40004 Horizontal Length (Angle>87 deg) ? (m) 0 Non-Horizontal5 Tangent Angle Above Horizontal ? (deg) 06 Min Pore Pressure Gradient ? (sg) 1.5807 Max Pore Pressure Gradient ? (sg) 1.600

Weak Point Parameters:8 Measured Depth ? (m) 26959 Vertical Depth ? (m) 2695

1 0 Section Angle (<87 deg) ? (deg) 01 1 Fracture Gradient / EMW ? (sg) 1.720

Other Parameters:1 2 Bottom Hole Assembly OD ? (inch) 81 3 Bottom Hole Assembly Length ? (m) 1821 4 Drillpipe OD ? (inch) 51 5 Gas Hydrostatic Pres Gradient ? (sg) 0.2 1 6 Pressure Safety Factor ? (psi) 220 1 7 Mud Weight in Hole ? (sg) 1.600

Annular Capacity Around BHA: (bbl/m) 0.27426Annular Capacity Around DP: (bbl/m) 0.39854Fracturing Pres at Weak Point: (psi) 6587Max Allowable Shut-in Csg Pres: (psi) 2 4 0

Comments:Min Pore Pressure at Kick Zone: (psi) 8981Maximum Allowable Gas Height: (m) 178Kick Tolerance at Min Pore Pres: (bbl) 48 .7

Max Pore Pressure at Kick Zone: (psi) 9094Maximum Allowable Gas Height: (m) 120Kick Tolerance at Max Pore Pres: (bbl) 33 .0

3 3 1.604 1 1.594 9 1.58

For more infor or help, please contact YUEJIN LUO, BP Exploration, Sunbury, Tel: 853-2424, Fax: 853-4183

1.57

1.58

1.58

1.59

1.59

1.60

1.60

3 3 4 1 4 9

Kick Tolerance (bbl)

Po

re P

ress

ure

Gra

die

nt

Rev 1 March 1995


1-45March 1995

Figure 1.10 Example Calculations using Excel KickTolerance Calculator (cont'd)

APPENDIX:Maximum Allowable Gas Influx Volume

Based on Surface Equipment Rating & Casing Burst

Max Allowable Surface Pressure ? (psi) 5000Casing ID in Surface Section ? (inch) 12.515

Annular Capacity: (bbl/m) 0.419456

At Minimum Pore Pressure Gradient: Comments:Maximum Allowable Gas Height When Gas Arrives at Surface: (m) 2460Max Allowable Gas Vol. on Shut-in: (bbl) 613

At Maximum Pore Pressure Gradient:Maximum Allowable Gas Height When Gas Arrives at Surface: (m) 2403Max Allowable Gas Vol. on Shut-in: (bbl) 547

547 1.60580 1.59613 1.58

For more infor or help, please contact YUEJIN LUO, BP Exploration, Sunbury, Tel: 853-2424, Fax: 853-4183

1.58

1.59

1.59

1.60

1.60

540 550 560 570 580 590 600 610 620

Max Allowable Gas Volume on Shut-in (bbl)

Por

e P

ress

ure

Gra

dien

t

Rev 1 March 1995


2 THE PREVENTION OF A KICK

Section Page

2.1 CORRECT TRIPPING PROCEDURES 2-1

2.2 MAINTAIN SUITABLE HYDROSTATIC PRESSURE 2-9

2.3 CONTROL LOST CIRCULATION 2-17

Formation pressures are contained by the hydrostatic pressure of a column of drillingfluid – this is primary well control.

If primary control is lost the blowout preventers are closed and secondary well controltechniques are used to kill the well.

Primary control is maintained by ensuring that a full column of drilling fluid of anappropriate weight is allowed to exert its full hydrostatic pressure in the hole.

Industry wide experience has shown that the most common causes of loss ofprimary control and hance the well kicks are:

• Swabbing during trips.

• Not adequately filling the hole during a trip.

• Insuf ficient mud weight.

• Lost circulation.

The evidence also shows that the majority of kicks have occurred during trips.

This chapter outlines the measures that are required to eliminate or minimise the riskof a kick due to the above causes, and to minimise influx volumes if a kick occurs.

March 1995


2.1 CORRECT TRIPPING PROCEDURE

Paragraph Page

1 General 2-2

2 Prior to Tripping 2-2

3 Tripping Procedure 2-5

4 Special Procedure for Oil Base Muds 2-8

Illustrations

2.1 Typical Trip Tank Hook-up – on a floating rig 2-3

2.2 BP Trip Sheet – example of a completed sheet 2-4

2.3 Example of Standing Orders for Driller 2-6

2-1March 1995

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2-2March 1995

1 General

Industry wide experience has shown that the majority of well control problems have occduring trips. It is therefore particularly important that special attention is paid to ensucorrect tripping procedure.

During tripping the potential exists for a significant reduction in bottomhole pressure dthe following effects:

• Reduction in ECD as the pumps are stopped.

• Swab pressures due to pipe motion.

• Reduction in height of the mud column as pipe is removed from the well.

The procedures required to deal with an influx when the pipe is off bottom are not sostraightforward as when the pipe is on bottom. Every effort must therefore be made to ensuboth that the well is stable prior to initiating a trip out of the hole, and that correct tripprocedure is strictly adhered to.

2 Prior to Tripping

Considerable preparation is required before the trip is commenced. The following are amongthe most important actions that should be carried out prior to tripping:

• Circulate the hole

– The mud should be conditioned to ensure that tripping will not cause excessive surge pressures.

– Any entrained gas or cuttings should be circulated out.

– The mud weight should be such as to ensure an adequate overbalance will existimes during the trip.

• Determine the maximum pipe speed

– Swab/surge pressures should be calculated at various tripping speeds usinappropriate formulae. (See Chapter 3, Volume 2.)

– The maximum average pipe speed should be selected bearing in mind the estoverbalance or trip margin.

• Line up the trip tank

– Company policy states that:

“A trip tank must be available on every rig and be complete with a mechanicoperated indicator of the trip tank level, visible from the Driller’s position. The triptank level must also be monitored from the Mud Logger’s cabin.”

hole

le, a full.


2-3March 1995

Figure 2.1 Typical T rip Tank Hook-up– on a floating rig

Figure 2.1 shows a typical trip tank hook-up on a floating rig.

– It is considered unsafe to trip without a trip tank and as such, spare parts for thefill pump/motor should be kept at the rig site.

– In order that maximum use is made of the trip tank on trips in and out of the hotrip sheet should be used to record the mud volumes required to keep the hole

• Fill in the trip sheet

– Company policy states that:

“A trip sheet will be filled out by the Driller on every trip.”

REMOTE CONTROL VALVE

OVERBOARD

RETURNS TO SHAKERS

FROM MISSION PUMPS

DRAINTRIP TANK PUMP

CHECK VALVE

RISER

TELESCOPIC JOINT

FLOWLINE

TRIP TANK LEVEL INDICATOR RIG FLOOR

ROTARY TABLE

DIVERTER

HOLE FILL UP LINE

WEOX02.010


2-4March 1995

Figure 2.2 BP Trip Sheet– example of a completed sheet

NO OF STANDS TO TOP OF BHA AT THE STACK

……… No

……… Increment

Trip Tank Volume

(bbl)

Measured Hole Fill/Disp

Calculated Fill/Disp Discrepancy

Remarksincrement

(bbl)accum (bbl)

increment (bbl)

accum (bbl)

increment (bbl)

accum (bbl)

Trip On: NO OF STANDS TO CASING SHOESingles Doubles Stands

DISPLACEMENT OF

DISPLACEMENT OF

DISPLACEMENT OF

DISPLACEMENT OF

DISPLACEMENT OF

in

in

in

in

in

:

:

:

:

:

:

:

:

:

:

bbl/

bbl/

bbl/

bbl/

bbl/

bbl/stand

bbl/stand

bbl/stand

bbl/stand

bbl/stand

HOLE DEPTH INITIAL BIT DEPTH

REASON FOR TRIP DRILLER

WELL No RIG DATE AND TIME SHEET No

TRIP SHEET

26

CHANGE BIT No 20

3250m

5

5

91/2

DRILLPIPE

HEAVYWEIGHT

DRILL COLLARS

53 STANDS

108 STANDS AND 1 SINGLE

STAND STAND

1

2

3

5

7

10

15

20

25

1

1

1

2

2

3

5

5

5

30.5

30.0

29.4

28.6

27.2

25.9

23.8

20.1

16.6

13.2

0.5

0.6

0.8

1.4

1.3

2.1

3.7

3.5

3.4

0.5

1.1

1.9

3.3

4.6

6.7

10.4

13.9

17.3

0.7

0.7

0.7

1.4

1.4

2.1

3.5

3.5

3.5

0.7

1.4

2.1

3.5

4.9

7.0

10.5

14.0

17.5

-0.2

-0.1

+0.1

0

-0.1

0

+0.2

0

-0.1

-0.2

-0.3

-0.2

-0.2

-0.3

-0.3

-0.1

-0.1

-0.2

0.0246

0.0564

0.2624

0.697

1.60

7.35

m

m

m

3250m

A.C.E.

RIG 20 15.30 27/8/87 1

Single Double Stands

Single Double Stands

(1) (2) (3) (4) (1)-(3) (2)-(4)

WEOX02.011

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2-5March 1995

– Figure 2.2 shows a completed example of the BP trip sheet. This trip sheet should beused if the contractor cannot provide a similar sheet. The basic requirement for atrip sheet is that a clear method of comparing calculated with actual hole fill voluis provided. The cumulative discrepancy between the two values should alsrecorded.

– The trip sheet for the last trip out of the hole should be available for compariso

• Provide the Driller with the necessary information

– The Driller should be told the reason for the trip.

– He should be told of any indicators of increasing pore pressure or near balancwere identified during drilling before, or since, he came on shift.

– He should be fully aware of the procedures to be adopted in the event of a kick tripping.

– An example of the standing orders that should be provided to the Driller is showFigure 2.3.

• Drill floor preparation

– Crossovers should be available on the rig floor to allow a full opening drillpsafety valve to be made up to each tubular connection that is in the hole.

– A drillpipe safety valve (kelly valve) should be available on the rig floor. It shouldbe kept in the open position.

– A back-up safety valve, such as a Gray valve, should be available close to tfloor. This valve should only be used in the event that the drillpipe safety valve not hold pressure, or if stripping in the hole is required and no dart sub is fitte

– The rig crew should be completely familiar with, and practiced in, thresponsibilities in the event of a kick.

3 Tripping Procedure

Having completed the preparations as outlined in the previous section, the trip out hole can be started. The following procedure is proposed as a guideline:

1. Flow check the well with the pumps off to ensure that the well is stablewith the ECD (equivalent circulating density) effect removed.

2. Pump a slug.

This enables the pipe to be pulled dry and the hole to be accurately monitored during


2-6March 1995

Figure 2.3 Example of Standing Orders for Driller

DATE COMPANY REP

IF ANY OF THE FOLLOWING OCCUR:

Or if there is any other possible indication of a kick.

1.

2.

3.

4.

5.

6.

7.

8.

HOLE NOT TAKING CORRECT VOLUME DURING THE TRIP

THE WELL IS FLOWING

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

1.

2.

STOP TRIPPING OPERATIONS

FLOWCHECK THE WELL IF NECESSARY

IS THE WELL

FLOWING?

TOOLPUSHER

ORDERS EFFECTIVE

WELL NO RIG

STANDING ORDERS TO DRILLER WHILE TRIPPING

15

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

SET THE SLIPS

INSTALL OPEN DP SAFETY VALVE

CLOSE DP SAFETY VALVE

OPEN CHOKE LINE VALVE (S)

CLOSE ANNULAR PREVENTER

CHECK THAT WELL IS SHUT IN

NOTIFY COMPANY REPRESENTATIVE

INSTALL KELLY

LINE UP STANDPIPE MANIFOLD

OPEN DP SAFETY VALVE

RECORD DP AND CSG PRESSURE

IF IN OPENHOLE: ENGAGE

BUSHINGS, ROTATE THE PIPE

PROCEED AS DIRECTED

ON ALL TRIPS

15/6/87 K.D. SMB

RIG 12

WEOX02.012

1.

2.

NOTIFY COMPANY REPRESENTATIVE AND TOOLPUSHER

PROCEED AS DIRECTED

YES NO

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

L, of

pipe.

ated,

will

d trip. gas at

heck

ed forn tothe

ated rigsite


2-7March 1995

The following formula can be used to calculate the volume of slug to ensure a length,dry pipe:

Vsl = MW X L X Cp (bbl)(MWsl – MW)

where Vsl = volume of slug (bbl)L = length of dry pipe (m)Cp = internal capacity of the pipe (bbl/m)MWsl = slug weight (SG)MW = mud weight in the hole (SG)

As a general rule, the slug should be mixed to maintain a minimum of 2 stands of dryIt is important to accurately displace the slug to the pipe. In this manner, the Driller willknow the weight, depth and height of the slug at all times during the trip.

3. For the first 5 – 10 stands off bottom, monitor the hole through the rotary .

This is to check that the annulus is falling as pipe is removed from the hole. The pipewiper should therefore be installed only after the first stands have been pulled. The triptank should not be overfilled at this stage to ensure that swabbing is clearly indicshould it occur. The circulating pump should be switched off at this stage and the holefilled from the trip tank, after each stand.

4. Circulate the hole across the trip tank and continue to trip out, monitoringhole volumes with the aid of the trip sheet.

5. Conduct a flowcheck when the BHA is into the casing shoe.

6. Conduct a flowcheck prior to pulling the BHA through the stack.

Be aware that the required hole fill volume per stand of heavy weight and drill collarsbe greater than for drillpipe as the BHA is being removed from the hole.

If unsure of the overbalance, consideration should be given to conducting a short rounOnce back on bottom, the overbalance can be assessed from the level of the tripbottoms up.

If the hole does not take the correct amount of fluid at any stage in the trip, a flowcshould be carried out.

If the flowcheck indicates no flow and the cause of the discrepancy cannot be accountat surface, the string should be returned to bottom while paying particular attentiodisplacement volumes. After circulating bottoms up, it may be necessary to increase mud weight before restarting the trip out of the hole.

If the flowcheck is positive, the well should be shut-in according to the procedure indicin the standing orders. Subsequent action will be dependent upon the conditions at the(See Chapter 5).

ith theas gonely atis

n closeificant

ud ate

of this

of the

e well


2-8March 1995

4 Special Procedure for Oil Base Muds

When oil base mud is in use, gaseous fluids have a tendency to go into solution wmud at high temperature and pressure. Experience has shown that once an influx hinto solution, it will not break out of solution until the bubble point is reached, typical1000 – 1500psi (this will depend on the fluids concerned). The possible consequence of this that a small influx that was undetected at depth may suddenly break out of solutioto the surface. This may cause a dangerous liberation of gas at surface as well as signreduction in hydrostatic pressure in the well.

Consideration should also be given to the possibility of thermal expansion of the mhigh temperatures. This can cause a reduction in effective mud weight and hence in thoverall hydrostatic head.

It is therefore recommended that tripping procedures are modified to take account potential problem when oil base mud is in use in the following situations:

• When drilling or coring in a potential pay zone.

• On prediction of an increase in pore pressure.

• On detecting significant levels of gas in the mud.

In these circumstances the following procedure is recommended prior to pulling outhole:

1. Flow check the well.

2. Circulate bottoms up.

3. Check trip to the shoe monitoring hole volumes.

4. Flow check at the shoe and run back to bottom.

5. Circulate bottoms up. Close in the BOP and circulate through the choke whenthe potential influx is at 500m below the stack, watching for any pit gain.

6. If necessary increase the mud weight and perform a further check trip.

This procedure can be relaxed if, after several trips under the same conditions, thremains stable.

The following procedure is recommended in these circumstances after a round trip.

1. When back on bottom prior to any further drilling or coring, circulatebottoms up to check for trip gas.

2. Circulate until potential influx is at 500m below the stack, watching for anypit gain.

3. Close in the well and circulate the potential influx through the choke.


2.2 MAINTAIN SUITABLE HYDROSTATICPRESSURE

Paragraph Page

1 General 2-10

2 Gas Cutting 2-10

3 Cuttings Contamination 2-14

Illustrations

2.4 Bottomhole Pressure Reduction – due to gas cutting 2-12

2-9March 1995

taticd

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hole.

omeated


2-10March 1995

1 General

Primary well control is achieved by controlling formation pressures with the hydrospressure of the drilling fluid. The drilling fluid may be contaminated with cuttings anformation fluids during drilling. These contaminants can significantly alter the effectivehydrostatic pressure exerted by the drilling fluid, and in certain circumstances, thicause loss of primary control.

Hydrostatic pressure will be reduced once drilling stops as a result of the loss of anfrictional pressure and the removal of cuttings from the annulus. The settling of cuttings tothe bottom of the hole may significantly reduce the hydrostatic pressure further up the

This section outlines the techniques that can be used to predict the effect of drilling fluidcontamination on the hydrostatic pressure.

2 Gas Cutting

When drilling through a formation that contains gas, it is inevitable that the mud will beccontaminated with gas from the drilled formation even if the formation is penetroverbalance.

Drilled gas will enter the mud system at a rate determined by the following factors:

• Rate of penetration, ROP (m/hr)

• Hole diameter, dh (in.)

• Formation porosity, Ø (fractional)

• Gas saturation, Sg (fractional)

The rate of gas entering the mud at bottomhole conditions, Qgas (gal/min), is given by thefollowing formula:

Qgas = dh

24 2 X 1.285 X ROP X Ø X Sg (gal/min)

Therefore as an example in the following conditions:

ROP = 25 m/hrdh = 12 1/4 in.Ø = 0.2Sg = 0.75Bottomhole pressure = 6000psiHole depth and depth at whichgas enters the mud, D = 3020m

Qgas = 12.2524

2 X 1.285 X 25 X 0.2 X 0.75

= 1.26 gal/min at 6000psi

e can

owline

to gas

al gas;


2-11March 1995

Therefore at atmospheric pressure the gas flowrate is given by:

Qgas = 1.26 X 6000 = 514 gal/min at atmospheric pressure14.7

This simplified calculation treats the gas as ideal and does not consider the effects oftemperature.

In this hole section the flowrate of mud is 700 gal/min; the actual mud weight at surfacbe calculated using the following formula:

MWact = MW X Qmud

Qmud + Qgas

where MWact = actual mud weight at surface (SG)MW = uncut mud weight (SG)Qmud = flowrate of mud (gal/min)Qgas = flowrate of gas (gal/min)

Therefore in this case the actual (or gas cut) mud weight at surface is given by:

MWact = 1.4 X 700700 + 514

= 0.81 SG

It should be stressed that this figure is an estimation of the actual mud weight at the fland as such will not reflect the actual density of the mud in the hole.

The percentage gas cutting is given by:

Percentage cut= MW – MWact X 100MW

Which in this case gives a figure of:

Percentage cut = 1.4 – 0.81 X 100 = 42% cut1.4

The following formula can be used to estimate the bottomhole pressure reduction duecut mud:

∆P= 14.7 (MW – MWact) ln (96.46 X MW X D) (psi)MWact 1000

where ∆P = bottomhole pressure reduction due to gas cutting (psi)D = depth at which gas enters the mud (m)

Figure 2.4 shows the effect of various levels of gas cutting for two different mud weightsusing the above formula. It should be noted that these curves represent an idetemperature and solubility effects are not considered.

In this case:

∆P= 14.7 (1.4 – 0.81) ln (96.46 X 1.4 X 3020) (psi)0.81 1000

∆P= 64psi


2-12March 1995

Figure 2.4 Bottomhole Pressure Reduction– due to gas cutting

5% 10% 20% 30% 40% 50%

0 20 40 60 80 100

-7000

-6000

-5000

-4000

-3000

-2000

-1000

0

0 20 40 60 80 100

PERCENT GAS CUT AT THE FLOWLINE

DECREASE IN BOTTOMHOLE PRESSURE (psi)

TR

UE

VE

RT

ICA

L D

EP

TH

(m

)

2.1 SG

1.05 SG

2.1 SG

1.05 SG

2.1 SG

1.05 SG

2.1 SG

1.05 SG

2.1 SG

1.05 SG

2.1 SG

1.05 SG

WEOX02.013

y small

erablyrface.

fr the

ing

ore


2-13March 1995

Therefore the average mud weight in the hole is equal to:

MW = (6000 – 64) = 1.38 SG3020 X 1.421

It can be seen that what appeared to be significant gas cutting, at 42%, caused a verreduction in the bottomhole pressure and actually only reduced the effective mud weight by0.02 SG, or by a factor of 1.4%.

The actual reduction in bottomhole pressure is caused by the gas when it has considexpanded. This expansion does not occur until the gas has been circulated to near the suAs can be seen from the previous example, this near surface expansion has a small efect onthe bottomhole pressure in a deep well for moderate levels of gas cutting. Howeveeffect of near surface expansion may be critical in relatively shallow hole sections.

The effect of gas cutting in a relatively shallow hole is demonstrated with the followexample:

dh = 24 in. Ø = 0.3Instantaneous ROP= 80 m/hr Sg = 0.7

D = 300m Pump output= 750 gal/minMW = 1.13 SG Formation pressure= 1.03 SG

Gas enters the mud system at a rate given by:

= 2424

2 X 1.285 X 80 X 0.3 X 0.7

= 21.6 gal/min at bottomhole conditions

Gas flowrate at surface is given by:

21.6 X 1.03 X 1.421 X 300 = 645 gal/min14.7

The actual mud weight at surface is given by:

750 X 1.13 = 0.61 SG750 + 645

Corresponding to a pressure reduction of:

14.7 X (1.13 – 0.61) ln (96.46 X 1.13 X 300) = 44 psi0.61 1000

The average mud weight in the hole is given by:

(1.13 X 1.421 X 300) – 44 = 1.02 SG300 X 1.421

Quite clearly the potential exists for the well to kick in this situation, given that the ppressure at this depth is assumed to be normal at 1.03 SG.

cases

ed theng the

ould

bit

may

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2-14March 1995

Industry experience has shown that excessive gas cutting in shallow hole has in manybeen the cause of shallow gas blowouts in offshore environments. The previous exampleshows the possible effect of gas cutting in shallow hole. However it should also be notthat in shallow hole the annulus pressure loss during circulation will be negligible, andexpansion of the gas may cause mud to be unloaded at surface, thereby further reducihydrostatic head of the mud column.

It is therefore important that the ROP is restricted in shallow hole. High pump output shalso be maintained to disperse the gas within the mud to minimise variations in SG.

3 Cuttings Contamination

One of the most important functions of the drilling fluid is to transport cuttings from theto the surface. The presence of cuttings in the annulus will increase the effective hydrostaticpressure of the fluid column. If this increase is excessive, it can cause losses whichpossibly lead to the loss of primary control.

It is therefore useful to be able to estimate the additional pressure caused by the cuttinthe annulus. In order to be able to estimate this additional pressure, a measure of the of the drilling fluid to remove the cuttings from the well is required.

The cuttings slip velocity is defined as the velocity of the cuttings relative to the velocitythe mud. There are many factors that influence the cuttings slip velocity, however thefollowing relationship can be used to estimate its value:

Slip Velocity, vs = 108 X dcut X (wcut – MW) 0.667

MW 0.333 X µ0.333

wherevs = slip velocity (m/min)µ = average viscosity (cP)MW = mud weight (SG)wcut = average cuttings weight (SG)dcut = cutting average diameter (in.)

However, if the particle Reynolds number is greater than 2000, the following formula shobe used to calculate the slip velocity:

vs = 34.56 dcut (wcut – MW)

1.5 X MW

12

The particle Reynolds number, Re is given by:

Re = 422.78 X MW X vs X dcut

µ

ocity;

ula:

.


2-15March 1995

The transport ratio is defined as the ratio of the actual cuttings velocity to the mud velit is therefore determined as follows:

Transport ratio, TR = vm – vs

vm

wherevm = Q (m/min)0.134(dhc2 – do2)

and vm = mud velocity (m/min)Q = pump output (gal/min)dhc = hole/casing ID (in.)do = pipe OD (in.)

The concentration of cuttings in the annulus can be calculated from the following form

Ca = ROP X dbit2 X (1 – Ø)

448.4 X Q X TR

whereROP = rate of penetration (m/hr)dbit = diameter of the bit (in.)Ø = porosity

The extra pressure caused by the cuttings in the annulus is given by the formula:

∆P = (wcut – MW) X 1.421 X sum (L X Ca)

where L = the length of each section (m)

The cuttings concentration must therefore be determined for each section of hole.

Consider the following example for a 17 1/2 in. hole section drilled from a floating rig

Casing shoe at 900m Average viscosity = 50 cPCasing ID = 22 in. Pump output = 700 gal/minRiser ID = 22 in. ROP = 50 m/hrBit size = 17.5 in. Openhole length = 180 mDrillpipe OD = 5 in. Cuttings density = 2.5 SGCollar OD/length = 8 in./180m Cuttings diameter = 0.3 in.Mud weight = 1.5 SG

The slip velocity = 108 X 0.3 X (2.5 – 1.5)0.667

1.50.333 X 500.333

= 7.7 m/min

The velocity of the mud in 17 1/2 in. hole is given by:

Velocity = 700 = 21.6 m/min0.134 X (17.52 – 82)

In the 22 in. section:

Velocity = 700 = 11.4 m/min0.134 X (222 – 52)

:


This gives a transport ratio of 64% in 17 1/2 in. hole and of 32% in 22 in. hole.

The cuttings concentration, Ca, in the 17 1/2 in. hole is given by:

Ca = 50 X 17.52 = 0.076 (= 7.6%)448.4 X 700 X 0.64

In the 22 in. hole section:

Ca = 50 X 17.52 = 0.152 (= 15.2%)448.4 X 700 X 0.32

The porosity is not considered.

The additional hydrostatic pressure due to the cuttings is determined as follows:

∆P = (2.5 - 1.5) X 1.421 X [(0.076 X 180) + (0.152 X 900)]

∆P = 214 psi

This additional pressure therefore increases the effective mud weight to a figure given␣by

MW = (1.5 X 1.421 X 1080) + 214 = 1.64 SG1080 X 1.421

2-16March 1995


2.3 CONTROL LOST CIRCULATION

Paragraph Page

1 General 2-18

2 Causes of Lost Circulation 2-18

3 Classification of Lost Circulation 2-19

4 Identification of Loss Zone 2-19

5 General Procedure for Spotting Plugs 2-20

6 Lost Circulation Decision Analysis 2-23

7 Drilling Blind 2-27

Illustrations

2.5 Balanced Plug Technique 2-22

2.6 Lost Circulation Remedies 2-24

2-17March 1995

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2-18March 1995

1 General

Lost circulation can occur as a result of the following:

• Unconsolidated or highly permeable low pressure formations (including deplereservoirs and at the base of long permeable reservoirs).

• Natural fractures.

• Induced fractures.

• Cavernous formations.

Lost circulation is undesirable primarily for three reasons. Firstly, that a loss of hydrostatichead may lead to the well kicking and secondly, that the cost of the replacement mud requiremay be considerable. Thirdly, it precludes accurate monitoring of the hole.

This section is intended to outline how to identify the different types of loss zone and, ineach case, to determine the most appropriate remedy.

2 Causes of Lost Circulation

These are as follows:

• Setting intermediate casing too high

Optimum casing design ensures that weak formations are isolated prior to drillingknown areas of higher pressure.

• Drilling with excessive overbalance

• Drilling too fast

Overloading the annulus can cause excessive ECDs or the formation of mud rings aconcentration of cuttings increases.

• Swab/surge pressures when running pipe

The mud properties and tripping procedures must be controlled to ensure that sgepressures are not excessive when running pipe. Care should be taken when brecirculation, possibly by breaking circulation at several depths on the trip in the hol

• Mud cake build up

In severe cases, mud cake can reach a level where the hole packs-off around the drillstring.To minimise this problem good fluid loss control and maximum use of the solids-conequipment must be coupled with a low fluid-loss mud. The drilled solids content of themud must be carefully controlled, by dilution if necessary.

meable loss

val of

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within

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o cure

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2-19March 1995

3 Classification of Lost Circulation

The severity of the loss zone can be assessed as follows:

• Seepage Losses (0.25 – 10 bbl/hr)

This takes the form of very slow losses or sometimes undetectable loss to a performation. In some instances, this may be due to filtration loss due to poor fluidcontrol. (The identification of seepage losses may be confused with the remocuttings from the mud at the shakers.)

Curing this level of loss is sometimes not economical if a cheap mud is in use arig rate is high. If pressure constraints are tight the losses may have to be curedfactors such as the need for a good cement job, formation damage or the risk of pstuck pipe need to be considered in specific cases.

• Partial Losses (10 – 500 bbl/hr)

Because these losses are more severe the cost of the mud in use becomes more iand so it is more likely to be economical to take some rig time to cure them.

Drilling with losses can be considered if the fluid is cheap and the pressures are operating limits.

• Complete Losses (500 bbl/hr – No returns)

If complete loss of returns is experienced, immediately pump water down the anmonitoring the volumes required to fill the hole. From the volume required,hydrostatic head that the hole can maintain should be determined.

When drilling in top hole sections with high ROP, complete losses may be caused overloading the annulus. In this case consideration should be given to pulling oucirculating in stages to clean the hole.

If efforts to cure the losses are unsuccessful, consideration may be given to dblind.

4 Identification of Loss Zone

The formation type determines the most appropriate remedial treatment required tlosses. It is therefore important that the loss zone is correctly identified.

Each type of lost circulation zone will exhibit certain characteristics which can be outas follows:

• Unconsolidated formations

Occur mainly at shallow depth. For whole mud to be lost to a formation, in the abof fractures, requires permeability of the order of 10 Darcies.

Will cause a gradual loss of mud to the hole, however, may worsen if no remedial actiois taken.

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2-20March 1995

• Natural fractures

Can occur in many rock types.

May cause a gradual loss of mud to the hole, however if drilling proceeds and fractures are exposed, complete losses may be experienced.

• Induced fractures

Horizontal fractures may be induced at relatively shallow depths after the formatiomud rings and by overloading the annulus. The formation of a mud ring will be indicatedby an increase in pump pressure and the drillstring becoming tight.

Vertical fractures may occur at greater depth and may be caused by any pressuregeon the formation. Usually indicated by sudden and complete losses.

• Cavernous formations

Normally only experienced in limestone formations.

Loss of returns may be sudden and complete. May be accompanied by the bit droup to several feet depending on the height of the cavern.

• Underground blowout

Condition where the act of shutting in on a kick induces a fracture in the openabove the point of influx. Kick fluids flow, usually from the lower active zone to thzone which has been fractured. Generally indicated by unstable pressure readisurface.

The depth of the loss zone must be established in order to calculate the hydrosinvolved and to determine the remedial action required.

The loss zone can be located using a Temperature Survey, which operates by identifyinga discontinuity in the temperature gradient within the wellbore. A noise log may also beused. Correlation with the known lithology at the confirmed loss zone is very importo identify the type of formation that has been fractured.

5 General Procedure for Spotting Plugs

Accurate placement of plugs downhole is vital if the loss zone is to be sealed. To do this,accurate measurement of pump efficiencies and internal pipe sizes must be made.

When drilling in areas of potential lost circulation, large nozzles should be fitted to the biHowever, coarse LCM must not be pumped through a bit with nozzles.

When the bit in the hole contains small nozzles and an LCM pill is required, considershould be given to tripping the pipe and running a bit with large nozzles or even open endedrillpipe.

The use of bits with a centre jet will also increase the area available for spotting plug

When the plug is being spotted, keep the pipe moving to avoid getting stuck.

When placing plugs containing cement, wherever possible the slurry formulation shoutested by the cementing contractor to determine thickening time.

r the

p at

a bit,ped

pedith

, theancedmn

this


The best displacement method for placing plugs is to use the balanced plug technique.Thisis however not always possible to achieve or desirable, depending on the rate of loss otype of slurry to be pumped.

In general, placement techniques will be as follows (refer to Paragraph 6 for recipes):

(a) Conventional circulation

Used for techniques 2A and 2B.

Place the plug through open ended pipe (if possible) opposite the loss zone. Pum1.0␣bbl/min until the losses cease.

(b) Balanced plug

Used for techniques 3A, 3B, 3C, 4A, 4B, 4C and 4D.

The balanced plug method should be used for the above techniques. However, if cementin any of the above techniques and it becomes necessary to spot the plug through the balanced plug technique should not be used. In this case, the bit should be tripinto the casing and the non-balanced plug technique used (See/(c)).

The basic requirement for a balanced plug is that the correct volume of spacer is pumbehind the slurry, to ensure that the hydrostatic pressure in the annulus is balanced wthat in the pipe before the pipe is pulled out of the plug. The pipe is then pulled out ofthe plug. If it is decided to squeeze the plug, 2 bbl should be pumped down the pipeBOPs closed and then squeeze pressure applied on the annulus below the rams. Balplugs can be allowed to lose to the formation under the hydrostatic head of the colualone, or by squeezing. It may be desirable to reverse circulate the pipe contents, ifis possible after pulling out of the plug.

Plug balancing calculations are as follows:

• Calculate the volume of cement plug for the required height of plug

Volume (bbl) = height (m) X hole capacity (bbl/m) X factor for excess

No of sacks required = volume (bbl)slurry yield (bbl/sk)

2-21March 1995

ehind


2-22March 1995

Figure 2.5 Balanced Plug T echnique

• With the volume of spacer ahead known calculate the height and volume of spacer b(See Figure 2.5)

If the same fluid is used before and after the plug:

h = Spacer vol ahead (bbl)annulus capacity (bbl/m)

Spacer vol behind (bbl) = h X pipe capacity (bbl/m)

where h = height of spacer (m)

TUBING

MUD

SPACER

PLUG

h

H

L

h = height of spacer (m) H = height of plug (m) L = drillpipe/tubing length (m)

where

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2-23March 1995

• Calculate the height of the cement plug before the pipe is pulled out

H(m) = Volume of slurry(bbl)annulus cap (bbl/m) + pipe cap (bbl/m)

where H = height of the plug (m)

• Calculate the plug displacement volume

Displacement volume (bbl) = (L – H – h) X pipe cap (bbl/m)

where L = Drillpipe/tubing length (m)

(c) Non-balanced plug

Used for techniques 5A, 5B, 6, 7A and 7B or whenever using techniques 3C, 4Aand 4C through a bit.

Where the loss zone depth is known with certainty then the pipe can be plaapproximately␣50m above it. The slurry is displaced to the end of the pipe and the BOP isclosed. For a downhole mixed plug, pump simultaneously down the annulus and pi2␣bbl/min. For a spotted plug pump the slurry out of the pipe plus 5 bbl excess, then pdown the annulus only.

6 Lost Circulation Decision Analysis

Figure 2.6 can be used as a guide to determining the most suitable method of dealing lost circulation problem. The techniques referred to in Figure 2.6 are specified below.

• Technique 1Pull up and wait

The bit should be pulled up to safety inside casing and the hole left static for 8/hours without circulation. (While waiting, a lost circulation pill can be mixed (eg/2or 2B), at comparatively low cost, for use in case the zone does not self heal.)

This technique is only likely to succeed in zones of induced fractures. It is thereforeapplicable to naturally occurring horizontal loss zones eg/gravels, natural fractures,and caverns where the overburden is self-supporting.

• Technique 2A

LCM pillMix a 100 – 500 bbl pill as follows:100 – 500 bbl mud15 lb/bbl fine walnut/sawdust/etc10 lb/bbl fine fibres (wood, mica or cane)5 lb/bbl medium to fine fibres (wood, cane, mica or similar)5 lb/bbl large cellophane flakes (1.0 in. diameter)

Pump the pill as recommended in Paragraph 5. Repeat if the hole still takes fluid. If thehole is still not filling go on to use a ‘High filter loss slurry squeeze’.

od,

and


2-24March 1995

Figure 2.6 Lost Circulation Remedies

• Technique 2BLCM pill

As above but using larger concentrations of coarse materials eg coarse mica, wowalnut or cellophane.

• Technique 3AHigh filter loss slurry squeeze (Diearth, Diaseal M etc)

100 bbl water15 lb/bbl bentonite or 1.0 lb/bbl Drispac (or 1.0 lb/bbl XC Polymer)0.5 lb/bbl lime50 lb/bbl Diearth, Diaseal M15 – 20 lb/bbl fine mica, walnut, cellophane or similar material as can be mixedremain pumpable.

LOST CIRCULATION REMEDIES

SEVERITY OF EFFECTIVE INTYPE OF LOSS LOSS, bbl/hr LOSS ZONE GEOMETRY LOST CIRCULATION REMEDIAL TECHNIQUE WBM OBM*

Seeping 1 – 10 to horizontal loss zones** Technique 2A – Plug of fine bridging agents in mud yes yesto induced vert fractures Technique 3A – High-filter-loss slurry squeeze with yes yes

fine bridging agentsPartial 10 – 500 to horizontal loss zones** Technique 1 – Pull up and wait (primarily for induced yes partial

vertical fracture)to induced vert fractures Technique 2B – Plug of medium bridging agents in yes yes

mudTechnique 3A – High-filter-loss slurry squeeze with yes yescoarse bridging agents

Complete 500 – complete to horizontal loss zones** Technique 3B or 3C – High-filter-loss slurry squeeze yes yeswith coarse bridging agentsTechnique 4B – Thixotropic cement or other cements yes no(4A, 4C, 4D)Technique 5B – Mud + diesel-oil-bentonite plus yes nocementTechnique 5A – Downhole-mixed soft plug yes yes(mud-diesel oil-bentonite)Technique 7B – Downhole-mixed hard plug (sodium yes yessilicate, calcium chloride, cement squeezeFlo-Check)

Long Complete to horizontal loss zones** Technique 3A, 3B or 3C – High-filter-loss slurry yes nohoneycomb or squeeze with 25 – 35 lb/bbl or coarse bridging agentscaverns (only Technique 5B – Downhole-mixed soft/hard plugin limestones) continuously mixed in large amounts

Deep induced Complete Vertical in WBM or OBM Technique 1 – Pull up and wait yes partialfractures in WBM Technique 5B – Downhole-mixed soft/hard plug yes no

in WBM Technique 5A – Downhole-mixed soft plug yes noin WBM Technique 7B – Downhole-mixed hard plug yes yes

(sodium, silicate, calcium chloride, cementsqueeze, Flo-Check)

in OBM Technique 3B or 3C – High-filter-loss slurry squeeze yes yeswith coarse bridging agents

in OBM Technique 4A – Neat portland cement yes yesin OBM Technique 7B – Downhole-mixed plug yes yes

(sodium, silicate, calcium chloride, cementsqueeze, Flo-Check)

* Usually not in use where loss zones are WBM – water-base mudhorizontal. They consist of porous sands OBM – oil-base mudand gravels, natural fractures, andhoneycomb and caverns.

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2-25March 1995

• Technique 3BHigh filter loss slurry squeeze

As Technique 3A but include the following:

15 – 30 lb/bbl medium and coarse LCM

• Technique 3CHigh filter loss slurry squeeze

As Technique 3A but include the following:

Reduce Diearth concentration to 10 – 25 lb/bblUse barytes as inert filler at 300 lb/bblAdd cement at 70 lb/bbl

Place in 30 bbl slugs into loss zone with 200 psi squeeze pressure.

Note: Wherever possible, slurry formulations should be tested prior to spottineliminate possible premature setting. When this is the case, always be awaof the thickening time and avoid leaving cement in or opposite the pipe bethis time.

• Technique 4ANeat cement slurry

Neat cement slurries give high compressive strength plugs.

Mix Class G cement at 1.90 SG in water

• Technique 4BExtended cement slurry (using bentonite)

Prehydrated bentonite slurry gives a degree of fluid loss control and ‘plating effect’ tohelp stop lost circulation. Coupled with this, a lightweight slurry can be formul(1.58 SG) which helps in areas of serious lost circulation. A further benefit is thatreasonable compressive strength characteristics are found with slurries of this ty

Add 10 lb/bbl bentonite to pre-treated fresh water (with 0.25 lb/bbl caustic and 0.2bbl soda ash). Mix cement up to 1.58 SG.

• Technique 4CAggregated cement slurry (with sand or ground coal)

Add aggregrate to the neat cement slurry at 1.90 SG up to a maximum weight of 2lb/sack of cement in the mix.

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2-26March 1995

• Technique 4DThixotropic cements

Cement of this type exhibits good flow characteristics when being pumped and a quideveloping gel strength when stationary. This thixotropic behaviour is beneficial forthe following reasons:

– A plug of cement displaced past the loss zone is self supporting and does noback under its own weight.

– The cement will tend to remain next to the wellbore when squeezed into fractudue to their rapidly developing gel strength.

Due to the temperature and chemical formulation sensitivity of this type of slurry, it isnot recommended to use this cement without rigorous quality control and testing pto each job. Halliburton Thixset 1 or 2 are examples of this type of cement.

• Technique 5ADownhole mixed soft plug

This type of lost circulation pill is designed to mix with a water base mud or formatiwater in the downhole environment and subsequently be squeezed into the format

Mix 10.5 gal of diesel or base oil to 100 lb of bentonite.

Granular or fibrous LCM may be added to this mix if required, ie mica at 10 ppb pwalnut at 10 ppb.

This mixture must be kept away from contact with water until it is placed out of tdrillpipe. To do this, a 10 bbl oil spacer is pumped ahead of a plug, followed by 10 after the plug.

The principle of this plug is to form a rubbery plug whenever the mixture contacts water base mud. Formation water will assist the hydration of the bentonite.

• Technique 5BDownhole mixed soft/hard plug

This type of lost circulation pill is designed to mix with a water base mud or formatiwater in the downhole environment. It can be designed to form an initially fluid mixtuof a soft or semi-hard nature depending on its composition, and can be squeezedthe formation where it will harden and develop compressive strength.

The proportion of mud to the pill in the final mix downhole will determine the strengof the plug. For example, a 1:1 mix with fresh water will result in a soft plug, wherea 1:3 (water/mix ratio) mix will result in a hard plug. In every case however, pilot testsshould be carried out at surface for various mixes, prior to spotting the pill.

Mix on surface 300 lb of G neat cement and 158 lb of bentonite to 1 bbl of diesel or boil. All water should be excluded from the mix on surface.

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2-27March 1995

• Technique 6Downhole mixed soft plugOleophilic clay and water

This type of plug formulation is designed for use in an oil base mud. It works bysame principle as 5A, except that the clay disperses in water and hydrates in oopposite of a bentonite squeeze).

Mix on surface 280 lb of oleophilic clay to 1 bbl of water. Add lignosulphonate at 4/lb/bbl water.

An example of oleophilic clay is Baroid Geltone.

The spacers ahead and behind this plug must be water based.

• Technique 7ASurface mixed soft plug (polymer type)

These formulations are mixed on surface, where polymers are blended with activand extenders, to give a delayed thickening reaction. This allows enough time to placethe plug in the loss zone before the chemical reaction takes place.

Haliburton Temblok is an example of this type of material.

This treatment is only temporary and the yield strength breaks down fairly quick. Itshould be followed by a cement slurry to effect a permanent seal.

• Technique 7BDownhole mixed hard plug

Haliburton Flocheck can be used for this.

This is a Sodium Silicate material which on contact with calcium ions forms insoluCalcium Silicate. By pumping a CaCl2 brine to the formation, followed by the Flochecmaterial, plugging of the formation occurs when the two chemicals mix in the formamatrix.

Placement as follows:

Pump 50 bbl 10% (by weight) CaC12 followed by 10 bbl fresh water. Then pump 35/bbl␣ofFlocheck followed by a further 10 bbl fresh water. Care must be taken to ensure thCaC12 does not come into contact with Flocheck on surface as it will go hard in the

This treatment, whilst permanent, may be reinforced by a cement slurry.

7 Drilling Blind

In certain circumstances it may become necessary to drill ahead without any returns at sie drilling ahead blind. This may be required if all attempts as laid out in Paragraph 6 havefailed. Once the decision to drill blind has been made, the main objective will be tcasing in the first competent formation penetrated.

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2-28March 1995

Although no cuttings will be obtained while drilling blind, casing seat can be locatedlogging and by keeping up a penetration log whilst drilling ahead. The hole has to be loggedfrequently, for example every 100m or whenever the penetration rate suggests a formchange. Once a competent formation has been identified, the new formation haspenetrated by at least 20m to successfully set and cement the next casing string.

Whilst drilling blind the following precautions must be taken:

• Use one pump for drilling as normal with the other continuously filling the annuwith water.

• Assign personnel to monitor the flowline for returns at all times.

• Pick the drillstring up off bottom every 2m drilled to ensure that the hole is not packoff above the bit.

• Keep one pit full of viscous mud at all times ready to pump to the hole.

• If one pump requires repair, use the cement unit to fill the annulus continuously.

• After drilling each single, wipe the hole over a full single and kelly length priordrilling ahead. Wipe the hole over the length of a stand if using a topdrive.

If overpull is experienced wipe the hole 3 or 4 times.

Spot a viscous pill around the bit prior to making each connection. This pill should bebalanced in and outside the pipe.

• If, during drilling, the fluid in the annulus reaches surface, stop drilling immediat.Pick up the drillstring so that the BOPs can be closed if required. Stop the pump odrillpipe and the annulus. Close in and observe for any pressure build up.

– If there is no pressure on the annulus, start up the pump on the drillpipe and circbottoms up through a fully opened choke (if this is possible). The loss zone may beplugged with drill cuttings. Drill ahead if everything is normal to a predetermindepth, if the area is well known. Stop and log if the area is not well known to deterif a suitable casing seat has been found and has been sufficiently penetrated.

– If there is pressure on the annulus be prepared to adopt procedures funderground␣blowout.

At all times be prepared to cement the well.

If tripping is required when complete loss of returns exists then the following precaumust be taken:

• Spot a viscous pill across the openhole section.

• Before tripping, stop the pumps on drillpipe and annulus and observe the we30␣minutes. Keep the string moving and be prepared to close in the well if necess.

• Drop the dart into the drop-in dart sub.

• Fill up the annulus continuously during the trip.

• Monitor the flowline at all times.

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ing

ipe


• Stop the pumps and monitor the well whenever the bit is pulled into the previous cashoe.

• Be prepared to shut in at all times during the trip.

If wireline logging is required when complete loss of returns exists then the followprecautions must be taken.

• When logging, the pump should be kept continuously on the hole. The only exception iswhen static fluid level has to be established.

• Logging is best conducted using through drillpipe logging tools, with open ended drillprun to the casing shoe.

2-29March 1995

2-29/30


3 WARNING SIGNS OF A KICK

Paragraph Page

1 General 3-2

2 Drilling Break 3-2

3 Increased Returns Flowrate 3-2

4 Pit Gain 3-3

5 Hole not Taking Appropriate Volume During a Trip 3-4

6 Gas Cut Mud 3-4

7 Increase in Hookload 3-6

8 Change in Pump Speed or Pressure 3-6

3-1March 1995

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3-2March 1995

1 General

When drilling with returns to surface, a kick cannot occur without any warning sign. ThisChapter outlines and explains the signs that indicate either that a kick has occurred okick may soon develop.

2 Drilling Break

One of the first indications that a kick may occur is an increase in penetration ratedrilling break.

Many factors influence the rate of penetration, but an increase in penetration rate ccaused by an increase in formation porosity, permeability or pore pressure. A change in allor one of these formation parameters may create the conditions in which a kick could .

For this reason any drilling break should be checked for flow.

Even if the flowcheck indicates no flow, the reason for each drilling break should bdetermined.

As an example, a drilling break could be caused by drilling into an impermeable tranzone above a permeable reservoir. Because the formation is impermeable, it is unlikely thany significant flow would be noticed during a flowcheck. However, the formation may beconsiderably underbalanced by the mud column. If drilling continued and the reservoipenetrated, a kick would be taken.

Consideration must therefore be given to circulating bottoms up before drilling aheada negative flowcheck, especially in critical sections of the well.

3 Increased Returns Flowrate

The first confirmation that a kick is occurring is an increase in returns flowrate whilepumps are running at constant output.

However, this increase may not be detected if the influx flowrate is particularly slow. In thiscase a slight pit gain may be the first detectable confirmation of the kick.

If low gravity formation fluids enter the wellbore during drilling, the hydrostatic pressin the annulus will decrease rapidly as more influx enters and when the influx expandis circulated up the hole. As a result, rapid influx flowrates can quickly develop, even thouthe initial influx flowrate might have been very low.

The length of formation exposed also has direct bearing on the rate of flow into theThe greater the length of formation exposed, the larger the flowrate.

It is therefore important that surface equipment be able to reliably detect a small increreturns flowrate.

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3-3March 1995

4 Pit Gain

(a) While Drilling

A gain in pit volume, that was not caused by the movement of mud stocks at surfaconfirmation that a kick is occurring or has occurred.

This is the most reliable indicator of a kick. Consequently, every effort must be made toensure that pit levels are accurately monitored at all times.

Very small influx volumes may not be detected at surface as they occur. This may bedue to the fact that, either the initial influx was particularly small, or the influx flowrwas very slow. This could be the case if the formation has low permeability or if a mpermeable formation was only very slightly underbalanced. In such cases, the imay be detected before it is circulated to the surface if it expands significantly rises up the hole. In general, the greater the amount of gas that is contained influx, the greater the expansion of the influx will be as it rises up the hole.

As a result, the greater the proportion of gas in the influx, the more likely it is thainflux will be detected as it is circulated up the hole.

Consequently, a low volume influx heavy oil or brine that does not contain aappreciable quantity of gas, will be relatively difficult to detect at surface.

However, if the active system is accurately monitored, pit gains of less than 10should be detected reliably, even on floating rigs.

(b) During a Connection

An influx may only occur during a connection due to the reduction in bottomhole presas the pumps are shut down and the pipe pulled off bottom.

If the well flows only during a connection, it is likely that the influx flowrate will bslow initially, resulting in only a small pit gain. Therefore, early detection of flow duringa connection may be difficult.

However, it is important to check for flow during a connection, because if a closbalance situation is developing, it is most likely to show initially during a connectThe first signs are likely to be increasing connection gases. However, if the underbalancedevelops very rapidly and the bottoms up time is considerable, then it is possible thinflux may occur before the connection gases are detected at surface. In this insflow during a connection may be the first indication of an underbalanced situation

The detection of a small pit gain during a connection is complicated by the volummud in the flowline returning to the pit after the pumps have been shut down. This willcause an increase in pit level during each connection.

It is important therefore to establish the volume of mud that is contained in the flowduring circulation. For instance, this volume might be 10 bbl and as such, a 10 bgain during a connection would not be significant. However, a 15/bbl gain may indicatethat a 5 bbl influx has occurred.

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3-4March 1995

5 Hole not Taking Appropriate VolumeDuring a Trip

As pipe is pulled from the hole, it is essential that the appropriate volume of mud is uskeep the hole full. This is essential in order that both a full head of mud is maintained in hole and that if an influx is swabbed into the hole, it is detected immediately.

Before every trip, a trip sheet (See Page 2-4) should be filled out. This must clearly showthe expected hole fill volumes as the pipe is pulled out of the hole. As the trip proceeds,actual hole fill volumes should be entered in the trip sheet alongside the expected voluIf the hole takes less mud than expected, this should be taken as positive indication thinflux has been swabbed into the hole.

A flowcheck should be carried out immediately or, if in a reservoir section, the well shouldimmediately be shut in.

A negative flowcheck at this point is not necessarily confirmation that an influx has occurred. It is quite possible, even if an influx has been swabbed into the well, that thewill not flow if the pipe is stationary.

Therefore, if at any stage in a trip the hole does not take the correct volume of mud, theshould be run back to bottom, using the trip tank, and bottoms up circulated.

The problems associated with dealing with a kick when the pipe is off bottom can beconsiderable, and so every effort must be made to ensure that significant swab pressuresavoided during a trip.

Swabbing is minimised by ensuring that the mud is in good condition prior to pulling of␣hole and that predetermined speeds are not exceeded at any stage in the trip (see Chapter␣3,Volume 2).

6 Gas Cut Mud

A kick is confirmed at surface as an increase in returns flowrate and a pit gain.

However, a minor influx that is not detected as a pit gain may first be identified at surfacthe returned mud. Formation fluids and gas in the returned mud may therefore indicatea low volume influx is occurring or has occurred, even though no gain has been detec

Returned mud must be monitored for contamination with formation fluids. This is done byconstantly recording the flowline mud density and accurately monitoring gas levels inreturned mud.

Gas cut mud does not in itself indicate that the well is kicking (gas may be entrained icuttings). However, it must be treated as early warning of a possible kick. Therefore the pitlevel should be closely monitored if significant levels of gas are detected in the mud.

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

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3-5March 1995

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

• As a result of drilling a formation that contains gas even with a suitable overbalan

• As a result of a temporary reduction in hydrostatic pressure caused by swabbing ais moved in the hole.

• Due to the pore pressure in a formation being greater than the hydrostatic pressthe mud column.

Gas due to one or a combination of the above, is classified as follows:

(a) Drilled Gas

As porous formations containing gas are drilled, it is inevitable that a certain quaof the gas contained in the cuttings will enter the mud.

Any gas that enters the mud, unless in solution with oil base mud and above the bpoint, will expand as it is circulated up the hole, causing gas cutting at the flowline.cutting due to this mechanism will occur even if the formation is overbalanced. Rathe mud weight will not prevent it.

However, drilled gas will only be evident during the time taken to circulate out cuttings from the porous formation.

(b) Connection Gas

Connection gases are detected at surface as a distinct increase above backgroundthe hole is circulated bottoms up after a connection.

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

In all cases, connection gases indicate a condition of near balance. Consequently, whenconnection gases are identified, consideration should be given to weighting up thebefore drilling ahead and particularly prior to a trip.

(c) Trip Gas

Trip gas is any gas that entered the mud while the pipe was tripped and the hole apstatic. Trip gas will be detected in the mud on circulating bottoms up after a round

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

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

(d) Gas due to Inadequate Mud Density

Surface indications of an underbalanced formation depend on the degree of underbaas well as the formation permeability.

The penetration of a permeable formation that is significantly underbalanced will can immediate pit gain.

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A permeable formation that is only slightly underbalanced may only cause a small finto the well. The first evidence of this at surface is likely to be gas cut mud, accompanby a small pit gain. The initial pit gain may be so small that it is only detected asexpands as it is circulated up the hole.

In the case a tight formation is underbalanced, there may be little or no actual flowgas into the wellbore. Therefore, drilling such a formation may show only gas cut mueven if the underbalance is relatively high. This is a relatively difficult situation todetect and is also potentially dangerous.

7 Increase in Hookload

If an influx occurs while drilling, an increase in hookload may be noticed at surface.

Influx fluids will generally be lighter than the drilling fluid, especially so if the influx isgas. Displacement of the drilling fluid by the influx will reduce the buoyancy of thbottomhole assembly. This will increase the effective weight of the drillstring, a change thatis likely to be registered as an increase in hookload.

An increase in hookload may only be noticed after a considerable volume of influx occurred. It is not therefore a reliable method of detecting a kick at an early stage.

8 Change in Pump Speed or Pressure

Pump pressure may decrease with a corresponding increase in pump speed if an influx oduring drilling.

This indication is caused as a result of the U-tube effect, caused by light fluids flowing intothe annulus. However, it is only likely to become noticeable as the influx is circulated uthe hole.

A washout in the drillstring will cause the same decrease in pump pressure and increapump speed. However, if these signs are noticed, the Driller should first assume that a kmay have occurred and flowcheck the well.

3-6March 1995


4 ACTION ON DETECTING AN INFLUX

Section Page

4.1 SHALLOW GAS PROCEDURE 4-1

4.2 SHUT-IN PROCEDURES 4-9

4.3 DURING SHUT-IN PERIOD 4-15

March 1995


4.1 SHALLOW GAS PROCEDURE

Paragraph Page

1 General 4-2

2 Gas encountered whilst drilling without a riser froma Floating Rig 4-3

3 Gas encountered whilst drilling for surface casingfrom a Floating Rig with a riser 4-4

4 Gas encountered whilst drilling for surface casingfrom a Bottom Supported Rig 4-6

5 Onshore Shallow Gas 4-7

4-1March 1995

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4-2March 1995

1 General

Offshore shallow gas accumulations are normally associated with recently laid dsand␣lenses that are totally enveloped by mudstones. When encountered at shallowdepths,␣lenses tend to be highly porous, permeable and relatively unconsolidated.Theyare␣commonly thin, flat and normally pressured. However, overpressured lenses have beeencountered. Overpressure at this depth is generally caused by inclination of the lens has the effect of increasing the height of the lens and hence the pore pressure gradienttop of the lens.

In some areas, shallow gas has been associated with buried reefs or vuggy limestonecan be extremely porous and almost infinitely permeable.

Shallow gas kicks are generally caused by loss of hydrostatic head due to one or a combof the following:

• Overloading the annulus with cuttings and hence causing losses.

• Drilled gas expanding and unloading the annulus.

• Improper hole fill while tripping.

Consequently it is strongly recommended to take the following general precautionminimise the possibility of inducing a shallow gas flow:

• Drill pilot hole

• Drill riserless

• Restrict ROPs

• Accurately monitor the hole

Shallow gas flows are often extremely prolific, producing very high flow rates of gas considerable quantities of rock from the formation; particularly so when a long sectiosand has been exposed.

In the event of a shallow gas flow, the Company Representative must immediately liaiwith the Senior Contractor Representative to make preparations to evacuate ininon-essential personnel from the rig. The eventuality of having to completely evacuate thrig must also be addressed (the contractor’s emergency evacuation procedures will beimplemented).

A well should not be drilled through a shallow seismic anomally (bright spot), which mindicate the presence of shallow gas. If a bright spot is present at the proposed dlocation it is good practice to move the rig to avoid the hazard. The new drilling locationshould, if possible, be located on a shallow seismic shot point.

It should be noted that the absence of bright spots does not rule out the possibility existence of shallow gas. Further to this, the absence of shallow gas in one well of a drilled from a surface location does not guarantee the absence of shallow gas in subsdirectional wells drilled from the same surface location.

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4-3March 1995

2 Gas encountered whilst drilling withouta riser from a Floating Rig

Company policy states that surface hole will be drilled riserless unless the particconditions as outlined in Drilling Policy and Guidelines Manual are applicable.

Drilling riserless ensures that the major cause of blowouts from shallow, normally pressuredgas reservoirs – namely, the loss of hydrostatic head – is eliminated. There remains however,the danger of penetrating an overpressured reservoir.

A contingency plan must be developed, prior to spud, in conjunction with the DrilliContractor to cover the following situations:

• The procedures to be adopted in the event of a shallow gas flow.

• The procedure for winching the rig off location.

The contingency plan must be discussed in detail at the pre-spud meeting.

A gas blowout in open water produces a 10 degree cone of low density water and a discgeof highly flammable gas. The intensity of the blowout depends to a large extent on the waterdepth and current. The plume is likely to become more dispersed with greater water depwhilst the effect of a current would be to displace the plume away from the rig.

Within a plume of expanding gas, a floating vessel will suffer some loss of buoyancy; however,this diminishes rapidly with water depth such that the effect on a semi-submersible at operatingdraft would be negligible. The eruption of the gas would tend to displace a vessel, andconstrained by its moorings, might cause a drillship to keel towards the plume, therreducing its freeboard further. Under calm conditions, the gas cloud would disperse slowand would constitute a fire hazard if the gas became entrapped in a confined area.

The severity of the hazard can only be assessed at the time, and whilst there is unlikelyan immediate danger to crew or vessel, the following precautions or considerations shbe addressed before and whilst the surface hole is open:

• The rig should be moored with length of moorings remaining in the locker to allow trig to be winched 400 ft away from the plume. If practical, the windlasses shouldheld on their brakes and the chain stoppers only applied after surface casing is se

• All hatches should be secured to prevent invasion of voids by inflammable gasdownflooding if the freeboard is reduced by loss of buoyancy or heel. This is criticalfor a drillship.

• Facilities and personnel should be continuously available at short notice to slack off themoorings closest to the plume and heave in those up current (but not down wind). Bespudding, a contingency plan should be prepared detailing individual responsibiliand duties.

• Drill pilot hole, limiting the ROP and circulate at a high rate to distribute the cuttinand drilled gas.

• A float valve should always be run in the drillstring.

• Sufficient mud should be kept on site to fill the hole volume twice. (Typically at 1.15/SG.)

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4-4March 1995

• Weather conditions and current should be continuously monitored and the sea sushould be checked for evidence of gas.

If a shallow gas flow is detected:

If there is no immediate danger to personnel or the rig:

1. Attempt to control the well by pumping mud/seawater at a maximum rate.

If the gas flow is endangering personnel or the rig:

2. Drop the drillstring or shear the pipe (See Section 6.2).

3. Winch the rig to a safe position outside the gas plume.

3 Gas encountered whilst drilling for surfacecasing from a Floating Rig with a riser

In relatively shallow offshore environments, the conductor is usually set in a formation tis too weak to contain the pressure of a gas kick. If a kick is detected in such circumstathe well should be diverted in order to avoid an underground blowout and the possibility ofthe gas broaching around the conductor shoe.

It is Company policy that where the situation demands that a riser is to be used when drfor the surface casing, an annular preventer and subsea dump valves are installedmudline, in addition to the normal diverter system at surface.

Industry experience has shown that current diverter systems cannot be relied upon to control shallow gas blowouts. As a result, shallow gas flows should be controlled at thseabed, using the subsea dump valves at the mudline and annular preventer. Immediatepreparations should then be made to unlatch the pin connector or LMRP and winch offlocation, up current but not down wind.

A contingency plan must be developed, prior to spud, in conjunction with the DrillContractor to cover the following situations:

• The procedures to be adopted in the event of a shallow gas flow.

• The procedure for winching the rig off location.

• The procedure to be adopted in the event of failure of any of the major componenthe BOP/riser/diverter system.

The contingency plan must be discussed in detail at the pre-spud meeting.

The surface diverter system ensures that there is a back-up system available in the eva failure of the subsea system. It can also be used to divert gas which may be in theabove the stack.

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4-5March 1995

The following precautions, in line with those listed in Paragraph 2, should be taken routinelywhilst the surface hole is open:

• The rig should be moored with length of moorings remaining in the locker to allowrig to be winched 400 ft away from the plume. If practical, the windlasses shouheld on their brakes and the chain stoppers only applied after surface casing is s

• All hatches should be secured to prevent invasion of voids by inflammable gdownflooding if the freeboard is reduced by loss of buoyancy or heel. This is criticalfor a drillship.

• Facilities and personnel should be continuously available at short notice to slack f themoorings closest to the plume and heave in those up current (but not down wind). spudding, a contingency plan should be prepared detailing individual responsiband duties.

• Care should be taken to ensure that the annulus does not become overloaded with ccausing losses or cuttings liberated gas, and hence the possibility of unloadinannulus. This is achieved by drilling a pilot hole, limiting the ROP and circulating at ahigh rate to distribute the cuttings and drilled gas.

• Facilities should be continuously available to fill the annulus rapidly from surfacthe event of sudden losses.

• Care should be taken to monitor the hole and ensure that it remains full whilst trip


• Sufficient mud should be kept onsite to fill the hole volume twice. (Typically 1.15/SG.)

Should the well start to flow, the following procedure can be used as a guideline:

1. Open the subsea dump valves.

2. Close the annular preventer and allow the gas to vent at the seabed.

If there is no immediate danger to personnel or the rig:

3. Attempt to control the well by pumping sea water/mud at a maximum rate.

If the gas flow is endangering personnel or the rig:

4. Consider dropping the drillstring or shearing prior to (5) (See Section 6.2).

5. Unlatch the LMRP or pin connector and winch the rig to a safe positionoutside the gas plume.

In the event of failure of the subsea diverter system there remains the option to disurface or to unlatch the LMRP or pin connector, thereby venting the gas at the wellheaDiverting at surface is not recommended, however if it becomes absolutely necessdivert at surface, proceed as follows:

1. Maintain maximum pump rate.

2. Space out so that the lower kelly cock is just above the rotary table.

3. Open the diverter lines, close the shaker valve and diverter element therebydiverting returns overboard.

jack-up

ctof a must

in thesing to

nducing

uttings,hat the

e in

emains

w or.


4-6March 1995

4. Shut down all non-essential equipment and machinery to minimise potentialsources of igni��tion. Deploy fire hoses beneath the rig floor .

5. Prepare to unlatch the pin connector or LMRP and winch to a safe position.

If the situation is deteriorating and loss of control is imminent:

6. Consider dropping the drillstring or shearing the pipe prior to (7) (SeeSection 4.3).

7. Release the pin connector or LMRP and winch the rig to a safe positionoutside the gas plume.

4 Gas encountered whilst drilling for surfacecasing from a Bottom Supported Rig

Shallow gas reservoirs are potentially much more hazardous when penetrated from a or platform. Because the conductor extends almost to the rig floor, the products of a kick aredischarged directly into a hazardous zone.

In the event of a shallow gas flow, the diverter will immediately be closed in order to direthe flow overboard. The reliability of the diverter system while subject to the stress shallow gas flow is uncertain and so the possibility of equipment failure at this stagebe considered.

On a bottom supported rig, a hazardous situation is created if a restriction forms diverter line. The subsequent pressure build up may cause gas to broach around the cathe seabed. In this event there is a real risk that the seabed becomes fluidized, thus ia sudden reduction in spudcan resistance.

The following precautions should be taken routinely whilst the surface hole is open:

• Care should be taken to ensure the annulus does not become overloaded with cthus causing losses or gas to be liberated from the cuttings to such an extent tannulus unloads. This is achieved by drilling pilot hole, limiting the ROP, and circulatingat a high rate to distribute the cuttings and drilled gas.

• Facilities should be continuously available to rapidly fill the annulus from surfacthe event of sudden losses.

• Facilities should be available and care taken to monitor the hole and ensure that it rfull whilst tripping.


• A means of diverting the flow away from hazardous zones, without restricting floimposing backpressure on the well, should be available for immediate activation

• Sufficient mud should be kept onsite to fill the hole volume twice.

ceen

an

a bedation

gashouldvailable

ortednly

rop at

flows

a


4-7March 1995

Should the well start to flow, the following procedure may be used as a guideline:

1. Maintain maximum pump rate.

2. Space out such that the lower kelly cock is just above the rotary table.

3. Ensure that diverter lines are open, close shaker valve and diverter elementthereby diverting returns overboard.

4. Shut down all non-essential equipment and machinery to minimise potentialsources of ignition. Deploy fire hoses beneath the rig floor .

5. Evacuate all non-essential personnel.

6. Monitor the sea for evidence of gas breaking through outside the conductor .(Evacuate all personnel if any evidence is detected.)

5 Onshore Shallow Gas

The shallow geology of onshore locations varies widely, but shallow gas is a rare occurrenonshore. Geological control is usually sufficient to predict formations accurately and, whnecessary, specific contingency plans should be made to counter potential problems.

Shallow onshore reservoirs are generally older, more consolidated and less permeable ththose offshore, which will tend to restrict the flow potential of a shallow kick onshore.

Onshore, most wells are spudded through a thin layer of weathered formation intorock. The conductor and surface casing strings are normally set in competent formwhich can permit secondary well control by normal means.

However, if it is not possible to positively exclude the possibility of either a shallow accumulation or a weak casing shoe, a means of diverting the flow away from the rig sbe provided. Provision should also be made to ensure an adequate supply of water is ato pump to the hole at a high rate without taking returns.

Diverter procedures for an onshore well will be similar to those for a bottom suppoffshore rig. However, if water supply is known to be limited, a baryte plug may be the opractical method of halting a shallow gas flow.

Most flows from shallow onshore reservoirs are associated with aquifers that outchigher elevations (or indeed lower elevations if air or foam drilling fluid is in use). A waterflow of this type is usually predictable and of limited consequence. Severe shallow have been encountered in the past as a result of a shallow zone becoming charged by a lowerhigh pressure zone; the shallow zone having been charged by a faulty cement job in previously drilled well.

4-7/8


4.2 SHUT-IN PROCEDURES

Paragraph Page

1 General 4-10

2 Fast Shut-in 4-10

3 Shut-in Procedure 4-11

Illustrations

4.1 Kick while Drilling, Floating Rig, Fast Shut-in 4-12

4.2 Kick while Drilling, Fixed Rig, Fast Shut-in 4-13

4.3 Kick while Tripping, Fast Shut-in 4-14

4-9March 1995

hole

urfaceompany

ethod. rface

made

f thervals to

ar theeg the

a lar

iately

and the


4-10March 1995

1 General

It is Company policy that a well kick will be shut in and controlled at the BOP stack onsections below the surface casing.

The procedures to be adopted in the event of a kick while drilling ahead from the scasing shoe are drawn up at the discretion of the Company Representative and the CDrilling Superintendent.

There are various methods of shutting in a well that is flowing. In general, the best mis that which ensures that the well is safely shut in and the influx volume is minimisedThesmaller the volume of influx, the lower will be the pressures in the wellbore and at suthroughout the kick control process.

It is the responsibility of the Company Representative to ensure that the Contractor isaware of the procedures that should be initiated in the event of a well kick.

The speed with which the Drillcrew carry out these procedures is a criticalfactor . In this respect, if a primary indicator of a kick, such as either a pit gainor an increase in returns flowrate is detected, no time should be spentflowchecking the well. In such circumstances, the kelly (or topdrive) shouldbe picked up, the pumps stopped and the BOP closed immediately .

Speed and proficiency are achieved by regular drills. It is a further responsibility oCompany Representative that he ensures these drills are carried out at suitable inteensure the drillcrews are proficient at implementing the shut-in procedures.

The forms illustrated in Figures 4.1 to 4.3 should be used to make absolutely cleshut-in procedures that will be used on each rig. These forms are intended primarily for thDriller, however copies should be distributed to other relevant personnel includinToolpusher and, where appropriate, the Subsea Engineer.

When a standard shut-in procedure is finalised, this procedure should be written on genotice board that will be positioned prominently on the rig floor.

2 Fast Shut-in

Drilling management have issued the following guideline:

The fast shut-in is the preferred method of shutting in a well.

In order to implement the fast shut-in, the equipment should be set up as follows:

• The remote operated choke closed and isolated by a high pressure valve immedupstream.(Ensure that the choke pressure can be monitored in this position.)

• One remote operated chokeline valve closed.(Outer failsafe on a floating rig and HCR valve on a fixed rig.)

In the event that a kick is detected, or suspected, the choke line valve(s) are openedBOP closed.

ig,re, if

o

y less

ingnt of

ller:


On a floating rig, the annular BOP will be used to initially shut-in the well. On a fixed rthe pipe rams may be used to initially shut-in the well, in order to speed up the proceduthe position of the tooljoint in relation to the pipe ram is known with confidence.

The advantage of this method is quite clear, namely that the operation is relatively simple incomparison with the soft shut-in. Consequently, mistakes are unlikely and the time taken tclose in the well will be minimised.

At all times, be aware that the pressure rating of the standpipe equipment is generallthan that of the BOP stack and the choke manifold.

3 Shut-in Procedure

It is the responsibility of the Company Representative and the Company DrillSuperintendent to define the shut-in procedure that will be implemented in the evea␣kick.

The following forms are examples of the information that should be provided to the Dri

Figure 4.1: Kick while Drilling, Floating Rig, Fast Shut-in.

Figure 4.2: Kick while Drilling, Fixed Rig, Fast Shut-in.

Figure 4.3: Kick while Tripping, Fast Shut-in.

4-11March 1995


Figure 4.1 Kick while Drilling, Floating Rig, Fast Shut-in

DATE COMPANY REP



1.

*2.

*3.

4.

5.

6.

7.

8.

9.

10.

DRILLING BREAK

INCREASED RETURNS FLOWRATE

PIT GAIN

CHANGE IN PUMP SPEED OR PRESSURE

SUDDEN CHANGE IN PROPERTIES OF RETURNED MUD

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

1.

2.

3.

PICK UP UNTIL ………………………… IS ………………………… ABOVE ROTARY

(Space out to ensure that a tool joint is clear of ………………………… rams)

SHUT DOWN THE PUMPS


(Do not flowcheck if 2* or 3* as above have been detected.)

IS THE WELL

FLOWING?

TOOLPUSHER

ORDERS EFFECTIVE

WELL NO RIG

STANDING ORDERS TO DRILLER

24

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

OPEN UPPER CHOKE LINE

FAILSAFE (S)

CLOSE UPPER ANNULAR

CHECK WELL IS SHUT IN


CHECK SPACEOUT

CLOSE UPPER PIPE RAMS

ADJUST ANNULAR CLOSING

PRESSURE

HANG OFF ON UPPER PIPE RAMS

CLOSE RAMLOCKS

PROCEED AS DIRECTED

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

THROUGH 121/4in HOLE SECTION

10/3/87

LOWER KELLY COCK 2.5m

UPPER PIPE

S.M.B. K.D.

RIG 20

WEOX02.015

1.

2.


PROCEED AS DIRECTED

YES NO

4-12March 1995


Figure 4.2 Kick while Drilling, Fixed Rig, Fast Shut-in

DATE COMPANY REP



1.

*2.

*3.

4.

5.

6.

7.

8.

9.

10.

DRILLING BREAK

INCREASED RETURNS FLOWRATE

PIT GAIN

CHANGE IN PUMP SPEED OR PRESSURE

SUDDEN CHANGE IN PROPERTIES OF RETURNED MUD

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

1.

2.

3.

PICK UP UNTIL ………………………… IS ………………………… ABOVE ROTARY

(Space out to ensure that a tool joint is clear of ………………………… rams)

SHUT DOWN THE PUMPS


(Do not flowcheck if 2* or 3* as above have been detected.)

IS THE WELL

FLOWING?

TOOLPUSHER

ORDERS EFFECTIVE

WELL NO RIG

STANDING ORDERS TO DRILLER

28

1.

2.

3.

4.

5.

6.






PROCEED AS DIRECTED

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

FOR WELL No 28

15/9/87

LOWER KELLY COCK 2m

5in PIPE

J.B.H. J.P.

RIG 15

WEOX02.016

1.

2.


PROCEED AS DIRECTED

YES NO

4-13March 1995


Figure 4.3 Kick while T ripping, Fast Shut-in

DATE COMPANY REP



1.

2.

3.

4.

5.

6.

7.

8.

HOLE NOT TAKING CORRECT VOLUME DURING THE TRIP

THE WELL IS FLOWING

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

……………………………………………………………………………

1.

2.

STOP TRIPPING OPERATIONS


IS THE WELL

FLOWING?

TOOLPUSHER

ORDERS EFFECTIVE

WELL NO RIG

STANDING ORDERS TO DRILLER WHILE TRIPPING

28

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

SET THE SLIPS

INSTALL OPEN DP SAFETY VALVE

CLOSE DP SAFETY VALVE





INSTALL KELLY

LINE UP STANDPIPE MANIFOLD

OPEN DP SAFETY VALVE


IF IN OPENHOLE: ENGAGE

BUSHINGS, ROTATE THE PIPE

PROCEED AS DIRECTED

ON ALL TRIPS

23/7/87 A.J.N. H.H.

RIG 10

WEOX02.017

1.

2.


PROCEED AS DIRECTED

YES NO

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

……………………………………………………………

4-14March 1995


4.3 DURING SHUT-IN PERIOD

Paragraph Page

1 General 4-16

2 Record Pressure Data 4-16

3 Record drillpipe pressure with a Float Valve in the string 4-17

4 Trapped Pressure 4-19

5 Identify the Influx Type 4-20

6 Influx Migration 4-21

7 Control Influx Migration 4-24

Illustrations

4.4 Shut-in Pressure Build-up Curve– showing the effect of influx migration 4-17

4.5 Well Control Operations Log 4-18

4.6 An Example Calculation– showing how to evaluate the type of influx fluid 4-22

4.7 An Example of the possible increase in wellborepressure due to influx migration 4-23

4-15March 1995

t-inill meanessure

take kick istivelyin.

tabilise.

and

shut in

casingsures in the

theres can

s not

illpipe


4-16March 1995

1 General

When a flowing well is shut in by closing the BOPs, the flow will continue until shupressures have built up to balance the static reservoir pressure. In most cases, this wthat the flow will stop almost immediately the BOPs are closed and that the shut-in prwill stabilise within a few minutes.

In general, only if the well has been flowing for some time will the kick zone pressuretime to build up to a maximum after the well has been shut in. In most cases, when ataken, the inflow into the wellbore occurs for only a short time and the drawdown is relasmall. As a result, pressure in the wellbore will stabilise quickly after the well is shut

However, there have been many cases of surface pressures taking several hours to sThe reasons for this can be one, or all, of the following:

• The influx originated from a low permeability zone.

• The influx created instability in the wellbore, leading to the hole sloughing packing␣off.

• The influx is migrating up the hole.

• The surface lines or subsea choke line is partially packed off.

This section covers the procedures that may be required during the time the well is prior to circulation.

2 Record Pressure Data

As soon as the well is shut in, a person must be assigned to record the drillpipe andpressures. The pressures should be recorded initially at 1 minute intervals until the preshave stabilised. It is important to record the data frequently in order that any changerate of build-up be clearly identified.

Usually, the rate of build-up is relatively fast until the well begins to stabilise. Oncepressures have begun to stabilise, any further significant increase in surface pressube indicative of influx migration.

The drillpipe pressure reflects the difference between the kick zone pressure and the effectivehydrostatic pressure of the mud column in the drillpipe, assuming that the influx haentered the drillpipe. It can therefore be used to determine the kick zone pressure.

When the surface pressures take a considerable time to stabilise, it is often difficult todetermine the drillpipe pressure that truly reflects the actual bottomhole pressure. There areno hard and fast rules that apply to determine the correct value for the relevant drpressure reading, however, frequent and accurate pressure readings will aid theinterpretation of build-up data .

Figure 4.4 shows a pressure build-up curve which shows signs of influx migration. The kickzone EMW is determined from the drillpipe pressure during the stabilised period.

asing well

t the

e, the


4-17March 1995

Figure 4.4 Shut-in Pressure Build-up Curve– showing the effect of influx migration

Figure 4.5 shows a form that can be used to record the build-up of drillpipe and cpressure. This form should also be used to keep a complete record of events during thecontrol operation.

3 Record drillpipe pressure with a Float Valvein the string

If a non-ported float valve is in the string and a kick is taken, the valve will close againsdifferential pressure and no pressure will be recorded at the standpipe.

In order to open this valve and allow the pressure to be transmitted to the surfacfollowing procedure can be implemented:

1. Line up the pump to the drillpipe.

INITIAL PRESSURE BUILDUP

ANNULUS PRESSURE

DRILLPIPE PRESSURE

STABILISED PERIOD

INFLUX MIGRATION OCCURRING

SU

RF

AC

E P

RE

SS

UR

E (

psi

)

TIME ELAPSED AFTER SHUT-IN

WEOX02.018


Figure 4.5 Well Control Operations Log

FIRST READING AT INTERVAL BETWEEN READINGS

WELL NO RIG DATE AND TIME SHEET NO

WELL CONTROL OPERATIONS LOG

28

/ 1 MINUTE UNTIL PRESSURES STABILISE

RIG 9

bbl

03.00 300 450 120 WELL SHUT IN – 10bbl GAIN

03.01 360 500 ''

03.02 420 560 ''

03.03 460 600 ''

03.04 520 660 ''

03.05 590 730 ''

03.06 630 770 ''

03.07 700 840 ''

03.08 720 860 ''

03.09 740 880 ''

03.10 760 900 ''

03.11 770 910 ''

03.12 775 920 ''

03.13 775 920 ''

03.14 780 925 ''

03.15 780 925 ''

03.16 780 925 ''

03.17 780 925 ''

03.20 780 925 '' INFORM COMPANY REP – PRESSURES STABILISED

03.25 780 925 ''

03.30 780 925 ''

03.45 780 925 '' START MIXING KILL WEIGHT MUD @ 1.75 SG

04.00 780 925 ''

04.30 782 925 ''

05.00 782 925 ''

05.10 782 925 '' 100bbl 1.75 SG MUD MIXED IN TANK No 1

05.15 782 925 '' VERIFY EQUIPMENT CORRECTLY LINED UP – CO REP

AND TOOLPUSHER TO RIG FLOOR

05.20 782 925 '' START CIRCULATION – BRING PUMP UP TO 25 SPM

05.24 1085 925 120 PUMP UP TO SPEED – RETURNS THROUGH DEGASSER

05.30 1010 910

05.40 880 903

05.50 755 930

06.00 630 945

06.10 450 950 KILL WEIGHT MUD TO BIT

3/7/87 03.00 1

WEOX02.019

TIME

(hr min)

DRILLPIPE PRESSURE

(psi)

CHOKE PRESSURE

(psi)

PIT LEVEL/ VOLUME

( )REMARKS

4-18March 1995

ill bessure

ble at

, bleedan the

n,l may

k zone,

actual welle mayild has

weighthe


4-19March 1995

2. Carefully monitoring both the pump and casing pressure, pump to the holeat a controlled rate (very slow).

3. Record the increase in pump pressure and the volume of mud pumped.

The relationship between the pump pressure and the volume of mud pumped wlinear as the mud in the drillpipe is compressed. If pumping is continued after the preequalises across the float valve, the valve will open. As the valve opens, the pumppressure will increase slower than before; this change should be easily recognisaslow pump rates. Stop the pump when this change is noticed. The casing pressure isalso likely to show an indication of the valve opening.

4. Isolate the pump at the standpipe.

5. Record the shut-in drillpipe pressure as the pump pressure recordedimmediately before the float valve opened.

6. If the casing pressure rises at any stage, immediately stop the pump.

Isolate the pump. Bleed off the excess pressure from the casing. As an example, if thecasing pressure rose 50 psi and this extra pressure was considered undesirable50␣psi from the casing and record the shut-in drillpipe pressure as 50 psi less thfinal pump pressure.

The utmost care must be taken in carrying out this procedure. As outlined, this procedureinvolves pumping into a closed well. The well is pressurised at the start of the operatioand so any excessive additional pressurisation caused by pumping into the weloverpressure the openhole section.

4 Trapped Pressure

In some circumstances it is possible that pressure, in excess of that caused by the kiccan be trapped in the well. There are three possible causes of this phenomenon:

• The pumps were left running after the well was shut-in.

• The influx is migrating up the hole.

• Pipe has been stripped into the well without bleeding the correct volume of mud.

Trapped pressure of this kind will result in surface pressures that do not reflect the kick zone pressure. However if the surface pressure built up at any point after thewas␣shut-in, this is confirmation that there is no trapped pressure in the well. Pressurbe trapped in the well if the surface pressure appears constant and no pressure bubeen seen.

The drillpipe pressure is used to determine the kick zone pressure and hence the mudused to kill the well. An artificially high drillpipe pressure reading, used to determine tkill mud weight, will result in overkilling the well.

re will

ssure, each

well,

e well.

t mustyure is

t to a the

rudentd.

abilityre of a

greateray

ssure

en areeterg.


4-20March 1995

The following procedure can be used to check for trapped pressure:

1. Ensure that accurate pressure gauges are fitted to the drillpipe and annulus.Carefully monitor the drillpipe and casing pressure.

2. Using a manual choke, bleed a small volume of mud from the annulus to asuitable measuring tank. (1/2 barrel is a suitable amount.)

3. Shut in the well. Allow pressure to stabilise.

If pressure has been trapped in the well, the drillpipe pressure and casing pressuhave fallen.

If the drillpipe pressure does not drop after bleeding mud from the annulus, no preis trapped in the well. Be aware that, if there is no trapped pressure in the wellincrement of mud bled from the well will cause a further influx into the well. Therefore,if no reduction in drillpipe pressure is detected after bleeding 2 – 3/bbl from the no more mud should be bled off.

An increase in casing pressure is a sure sign that additional influx has entered thTherefore, if this occurs, no more mud should be bled from the well.

4. If both the drillpipe pressure and casing pressure have decreased, continueto bleed mud from the well in 1/2 bbl increments.

5. When the drillpipe pressure no longer decreases as mud is bled from thewell, record the drillpipe pressure as the shut-in drillpipe pressure. Stopbleeding mud from the well.

It should be stressed that bleeding mud from a well that has kicked is an operation thabe carefully implemented. Whilst it is undesirable to overkill the well, it is potentiallhazardous to increase the size of the influx, which is clearly a possibility if this procednot properly carried out.

A firm recommendation is that the volumes bled from the well at this stage are kepminimum, unless influx migration is obviously occurring. If there is some doubt as totrue shut-in drillpipe pressure, even after bleeding mud from the annulus, it may be pto use the Driller’s Method to circulate out the kick, rather than continue bleeding mu

This procedure is not recommended if the kick zone is suspected to have low perme.Bleeding even very small quantities of mud from the annulus may reduce the pressutight kick zone below its final shut-in pressure. The drillpipe pressure will continue todecrease, giving the false impression at surface that the bottomhole pressure is still than the actual kick zone pressure. A possible consequence is that the operator minadvertantly reduce the bottomhole pressure significantly below the kick zone preand cause a further influx into the wellbore.

5 Identify the Influx Type

The shut-in pressures recorded on the drillpipe and the casing after a kick is takgenerally not equal. This is because the effective hydrostatic pressure of the fluid in thannulus will be reduced below that in the drillpipe. It is unlikely that any kick fluid will␣enthe drillpipe, because this is effectively a closed system if the kick was taken while drillin

stimate as

te mud. the

ity of

idesesndlysom the

ucesantity

rior towill beg this

hole.ud.

ore if

d by gas


4-21March 1995

The pit gain at surface provides a guide to the volume of the kick. With this information,together with the annular geometry and the surface pressures, it is possible to ethe␣influx density. The type of influx fluid can then be evaluated, using the followinga␣guide:

Influx fluid Calculated Influx gradient (psi/ft)

Gas 0.05 – 0.2Oil 0.3 – 0.4

Water > 0.4

Figure 4.6 shows an example of how to determine the influx type. This calculation is onlyan approximation, for the following reasons. Firstly, it is assumed that the influx is a discrebubble, whereas it is more likely to be eccentric to the hole and contaminated withSecondly, the effective mud weight in the annulus is not likely to be the same as indrillpipe, due to cuttings loading the annulus, and possibly, contamination of the mud withformation fluid. Thirdly, the hole may be out of gauge. It is important, however, that thiscalculation is carried out for the additional reason that it provides a check of the validthe kick data.

It is useful to know the type of influx before circulation is initiated. Although most formationfluids, including formation water, contain some gas, the calculated influx gradient prova guide to the proportion of gas in the fluid. The proportion of gas in the influx determintwo important factors, firstly, the well bore pressures during displacement, and seco,the pit gain during displacement. If the gas contains sufficient heavy hydrocarbon moleculeat reservoir conditions, condensate fluids may be formed as the gas is displaced frhole. This will not occur for a dry gas that does not contain a sufficient proportion of heavymolecules. Gas will come out of solution from an oil influx when the influx pressure redbelow the bubble point pressure during displacement. For light oils, a significant quof gas will be produced.

It is recommended that all kicks are assumed to contain a certain proportion of gas. Pcirculation therefore, an estimation should be made of the maximum pressures that encountered during circulation, and provision should be made for a pit gain durinperiod. (See Chapter 5, Volume 2 for hand calculation techniques.)

6 Influx Migration

After a kick is taken, there is usually a tendency for the influx to migrate up the This␣tendency is caused by the difference in density between the influx fluid and the m

Influx migration up a closed-in well can cause excessive pressures within the wellbsuitable control procedures are not implemented.

Figure 4.7 shows an example of the potential increase in bottomhole pressure causemigration.


4-22March 1995

Figure 4.6 An Example Calculation– showing how to evaluate the type of influx fluid

855 500

��

��

��

4000m

20bbl INFLUX

HEIGHT OF BHA = 195m

1. Determine the bottomhole pressure

DRILLPIPE

SURFACE PRESSURE

+

HYDROSTATIC PRESSURE OF MUD IN

THE DRILLPIPE

=

BOTTOMHOLE PRESSURE

SURFACE PRESSURE

INFLUX HYDROSTATIC

PRESSURE

+

+

HYDROSTATIC PRESSURE OF MUD IN ANNULUS

=

BOTTOMHOLE PRESSURE

ANNULUS

2. Determine the hydrostatic pressure of the influx

61/4in COLLARS

81/2in HOLE

1.7SG MUD

MUDMUD

INFLUX

HOLE DRILLSTRING DIMENSIONS

Identify the influx fluid as follows:

1. Determine the bottomhole pressure Bottomhole pressure = Drillpipe pressure + mud hydrostatic pressure

= 500 + (1.7 x 1.421 x 4000) = 500 + 9663 = 10,163psi

4. The following formula can also be used routinely to calculate the influx densityDensity of the influx (SG) = MW – Pa – Pdp

h x 1.421

2. Calculate the height of the influx in the annulus Influx volume Annular capacity at collars Height of influx

= Recorded pit gain = 20bbl = 0.1058bblm = 20/0.1058 = 189m

3. From pressure balance Annulus surface pressure + Hydrostatic pressure of the mud + Hydrostatic pressure of the influx = Bottomhole pressure

855 + 1.7 x 1.421 x (4000 – 189) + Pi

Pi, hydrostatic pressure of the influx

Influx gradient

Therefore the influx is mainly gas

= 10,163psi

= 10,163 - 855 - 9206 = 102psi

= Pi/height of the influx = 102/(189 x 3.2808) = 0.16psi/ft

PRESSURE BALANCE

= 1.7 – 855 – 500 189 x 1.421

= 0.378 SG 0.16psi/ft–––

WEOX02.020

esble willrocess

l

s

lt oftely


4-23March 1995

Figure 4.7 An Example of the possible increase inwellbore pressure due to influx migration

Influx migration does not always occur, but when it does, the rate at which the influx risup the hole is dependent on several variables. Experiment has shown that a gas bubmigrate up one side of the annulus as mud falls down the opposite side. Bearing this pin mind, it is clear that the factors that predominantly affect the rate of rise of the influx wilbe the following:

• The viscosity of the drilling fluid.

The more viscous the mud, the more difficult it is for the mud to fall down the annuluto allow the influx to migrate.

• The difference in density between the mud and the influx.

The buoyancy force causes the influx to migrate.

• Any interaction between the mud and the influx fluid.

Migration will be slowed if the viscosity of the mud is increased as a resucontamination with the influx fluid. In severe cases, migration may be compleprevented.

��

��

SURFACE PRESSURE

1.4SG MUD

250psi

0

1500m

GAS @ 6180psi

GAS @ 6180psi

GAS @ 6180psi

2975m

3000m

6180psi 1.45

WEOX02.021

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9160psi 2.15

(12140psi) (2.85)

3195psi 6180psi

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7 Control Influx Migration

There are many possible reasons that a well that has kicked may be left shut-in for experiods. Procedures for relieving bottomhole pressure, should migration occur durinperiod, will depend both on the position of the drillstring in the hole and whether or ndrillpipe pressure can be used to monitor bottomhole pressure.

In both cases however, it is necessary to control the well using the Volumetric Method. Thistechnique ensures that the bottomhole pressure is maintained slightly above the kicpressure at all times. This is accomplished by bleeding suitable volumes of mud fromannulus to allow for expansion of the influx as it migrates up the hole.

This control procedure is greatly simplified if the drillstring is on bottom andcommunication with the annulus. In this case, the bottomhole pressure can be mowith the drillpipe pressure gauge. It is simply necessary to ensure that the drillpipe prstays at a suitable value above the final shut-in pressure (that value recorded before mstarted) by bleeding mud from the annulus.

If the drillstring is off bottom, the bit is plugged, or there is a washout in the drillstring,not possible to monitor bottomhole pressure with the drillpipe pressure gauge. In thisthe annulus pressure is the only reliable guide to subsurface pressures.

The principle behind the control of the annulus is that an increase in annulus pressureby influx migration, must be relieved by an equivalent reduction in the hydrostatic preof the mud in the annulus. Thus, if the annulus pressure rises 100 psi, then a volume ofcorresponding to a hydrostatic pressure in the annulus (at the top of the influx) of 1must be bled from the well at constant choke pressure.

The procedure for implementing the Volumetric Method is covered in detail in Chapter 6.

4-24March 1995


5 WELL KILL DECISION ANALYSIS

Paragraph Page

1 General 5-2

2 Pipe on Bottom 5-2

3 Pipe off Bottom (Drillpipe in the Stack) 5-2

4 Pipe off Bottom (Drillcollar in the Stack) 5-5

5 No Pipe in the Hole 5-5

6 While Running Casing or Liner 5-7

7 Underground Blowout 5-9

Illustrations

5.1 Preparations for the Well Kill 5-3

5.2 Decision Analysis – Pipe off Bottom(Drillpipe in the Stack) 5-4

5.3 Decision Analysis – Pipe off Bottom(Drillcollar in the Stack) 5-6

5.4 Decision Analysis – No Pipe in the Hole 5-8

5.5 Decision Analysis – Flow to a Fracture above aHigh Pressure Zone 5-10

5.6 Decision Analysis – Flow to a Fracture or LossZone below a High Pressure Zone 5-12

5-1March 1995

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5-2March 1995

1 General

This Chapter is intended to provide guidelines to the decision making process in the that a kick is taken in a variety of different situations.

In reality, the specific conditions prevailing at the rigsite at the time that the kick is tawill determine the best course of action to take in order to kill the well.

This Chapter should therefore not be used as a guide at the moment that a kick is taken. Ho,it is anticipated that general familiarity with the analysis presented in this Chapter will enrigsite personnel to be better prepared to deal with a situation in which the well has kicke

The techniques referred to in this section are covered in detail in Chapter 6, Well KillTechniques.

2 Pipe on Bottom

If a kick is taken with the pipe on bottom, the well will be shut-in immediately unlessdecision has previously been made to divert.

Having established that the well is safely closed in, it will be necessary to decide omost appropriate method of killing the well. This decision is the responsibility of theCompany Representative.

Having decided on the most appropriate course of action, the Company Representaresponsible for ensuring that contractor personnel are made aware of the procedurewill be used to kill the well.

The general procedure that is presented in Figure 5.1 represents the steps that shotaken in preparation to kill the well. These steps are applicable to any situation in whichkick is taken.

3 Pipe off Bottom (Drillpipe in the Stack)

If an influx is taken during a trip it will generally be necessary to return the drillstringbottom before the well can be killed.

The surface pressure will be a major factor in determining the most suitable methoreturning the pipe to bottom. It must be considered in relation to the string weight anpressure rating of the BOPs.

The first option that should be considered is stripping the pipe to bottom with the rig equipmAnnular stripping is the most satisfactory method, however ram combination stripping have to be considered if surface pressures are approaching the pressure rating of the ann. Ona floating rig, ram combination stripping is a particularly difficult operation.

The limitations imposed by the rig BOP system may dictate that stripping the pipe to bois impractical. In this case, snubbing must be considered.

Figure 5.2 represents an analysis of the decision making process in the event the welwith the pipe off bottom.


5-3March 1995

Figure 5.1 Preparations for the W ell Kill

• COMPANY REPRESENTATIVE CONTROLS THE OPERATION THROUGH THE CONTRACTOR TOOLPUSHER

START UP KILL PROCEDURE

••

•

CHECK EQUIPMENT ENSURE PERSONNEL ARE BRIEFED VERIFY COMMUNICATIONS

COMPLETE PREPARATIONS

• ESTABLISH THE LINES OF COMMUNICATION

ALLOCATE INDIVIDUAL RESPONSIBILITIES

•

•

DECISION MADE AS TO MOST APPROPRIATE METHOD OF KILLING THE WELL DRILLING SUPERINTENDENT IN TOWN SHOULD BE MADE AWARE OF THE SITUATION

PREKILL MEETING

MONITOR THE WELL

CONTINUOUSLY

KICK TAKEN WELL SHUT-IN

WEOX02.022


5-4March 1995

Figure 5.2 Decision Analysis – Pipe off Bottom(Drillpipe in the Stack)

MONITOR SURFACE PRESSURE –

ROTATE THE PIPE

SURFACE PRESSURE

EXCEEDS PRESSURE RATING OF ANNULAR?

POSSIBLE TO REDUCE SURFACE

PRESSURE?

POSSIBLE TO LOWER

TOOLJOINT THROUGH ANNULAR?


PRESSURE?

CONSIDER FEASIBILITY

OF RAM TO RAM STRIPPING

WELL IS FLOWING UP

THE DRILLSTRING

THE SEVERITY OF THE

SITUATION DICTATES THAT STRIPPING WITH

RIG EQUIPMENT IS IMPRACTICAL

IS IT POSSIBLE

TO STAB A SAFETY VALVE?

ATTEMPT TO REDUCE SURFACE

PRESSURE – CONSIDER:

POSSIBLE TO LOWER PIPE

THROUGH ANNULAR?





CONSIDER FEASIBILITY

OF ANNULAR TO RAM STRIPPING

NO

YES

YES

YES

NO

NO

NO

YES

NO

YES

NONO

YES

YES


PRESSURE ?VOLUMETRIC LUBRICATION BULLHEADING CIRCULATE OUT INFLUX

••••

VOLUMETRIC LUBRICATION BULLHEADING CIRCULATE OUT INFLUX

••••

VOLUMETRIC LUBRICATION BULLHEADING CIRCULATE OUT INFLUX

••••

INSTALL DP DART OR INSIDE BOP

CLOSE ANNULAR

OPEN CHOKELINE VALVE

STAB AND CLOSE FULL OPENING SAFETY VALVE

WELL KICKS PIPE OFF BOTTOM

(Drillpipe in stack)

DROP THE PIPE AND SECURE

THE WELL

HANG OFF

SHEAR PIPE

REDUCE ANNULAR CLOSING

PRESSURE

ATTEMPT TO LOWER PIPE

THROUGH STACK

IMPLEMENT ANNULAR

STRIPPING

CONSIDER SNUBBING

CONSIDER SNUBBING

WEOX02.023

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5-5March 1995

4 Pipe off Bottom (Drillcollar in the Stack)

Every effort should be made to ensure that well control problems are avoided wheBHA is across the stack. Regaining control from a situation in which the well has kiwhen the BHA is across the stack can present serious complications.

If the kick was swabbed in, it may be possible to bring the well under control by bleegas and lubricating mud into the well. It is however, undesirable to leave the collars in thstack for an extended period during a well control operation.

In any event, it is likely that the pipe will have to be stripped to bottom before the welbe killed.

There are considerable operational problems presented by attempting to strip thethrough the annular; these include:

• Many BOP stacks, especially on land, have only one annular BOP. The BOP elementwill be subject to considerable stress as the spiralled collars are stripped througthe element fails there is no back-up.

• Stabilizers in the BHA may prevent stripping completely.

Further complications that may arise in this situation are numerous, but include the follo

• There is not sufficient weight of collars to strip through the annular BOP.

• Well pressures force the collars out of the hole.

• An internal blowout through the drillstring.

The appropriate course of action required in these situations will depend to a large extent onthe particular conditions and equipment at the rigsite. However Figure 5.3 is intendeguide to dealing with such situations.

5 No Pipe in the Hole

Correct tripping procedures will ensure that an influx is detected before the pipe is compout of the hole.

Should an influx remain undetected during tripping and the well is shut in with no pipthe hole, it may not be possible to re-introduce drillpipe into the hole in order to strbottom.

The limiting factor is the surface pressure in relation to the weight of the drillstring athe stack. A simple calculation will determine whether it will be possible to overcome wellbore pressures with the weight of the string. There is quite clearly a limited weight thacan be applied at a surface stack.

If the influx is immediately below the stack, it may be possible to either kill the wellubricating mud into the well, or to reduce the surface pressures such that it becomes pto re-introduce pipe into the hole.


5-6March 1995

Figure 5.3 Decision Analysis – Pipe off Bottom(Drillcollar in the Stack)

ATTEMPT TO LOWER SURFACE

PRESSURE CONSIDER LUBRICATING BULLHEADING

IS IT POSSIBLE TO

STAB A SAFETY VALVE?

WELL IS FLOWING UP THE

DRILLSTRING

IS IT POSSIBLE TO

LOWER PIPE INTO THE HOLE?

LEAK STOPSMINOR LEAK

LEAK THREATENS RIG

FLOOR AREA

IS THE PIPE FORCED OUT OF THE

HOLE?

IS THE PIPE FORCED OUT OF THE

HOLE?

IS IT POSSIBLE TO

LOWER PIPE INTO THE HOLE?

IS THE ANNULAR LEAKING?

YES

NO

YES

NO

NO

YES

NO

YES

YES

NO

WELL KICKS (Drillcollar in

the stack)

OPEN CHOKE LINE VALVE(S)

STAB AND CLOSE A FULL OPENING SAFETY VALVE

CLOSE ANNULAR

INSTALL INSIDE BOP

MAKE UP DRILLPIPE TO COLLARS

STRIP IN UNTIL DRILLPIPE

IN THE STACK

CHECK INTEGRITY OF ANNULAR PREVENTER

STRIP IN THE HOLE

OPEN CHOKE LINE


THE WELL

CONSIDER SNUBBING


THE WELL

OPEN CHOKE LINE

INCREASE ANNULAR

CLOSING PRESSURE

INCREASE ANNULAR CLOSING PRESSURE


THE WELL

NO

YES

WEOX02.024

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5-7March 1995

However, if the influx is someway down the hole, it may not be possible to reducesurface pressure significantly.

If the influx is migrating up the hole, it may be possible to kill the well by implementingVolumetric Control Method.

On fixed offshore and land rigs, the only practical method of controlling the well maywith the use of a snubbing unit. Snubbing units have been used in exceptional circumson floating rigs.

Figure 5.4 represents a full analysis of the decision making process in the event thatis taken with no pipe in the hole.

6 While Running Casing or Liner

Before pulling out of the hole prior to running casing, every effort will be made to ensurethat the mud is conditioned and the well is under control, thereby minimising the possiof well control problems during the casing operation.

However, possible causes of well control problems while running casing includefollowing:

• A kick that was swabbed in on the last trip of the hole.

• Swabbing in a kick on a connection while running the casing.

• Surge pressures while running casing leading to losses and hence inducing a kic

• When casing is run to cure a well control problem, such as after drilling with a floamud cap or after controlling an underground blowout.

Particular attention should therefore be paid to these aspects.

In critical well sections, consideration should be given to installing casing rams in thestack prior to running casing; this is only practical in surface stacks. Specialist shearare available that can shear up to 13 3/8 in. casing; these may be considered appliccertain situations.

It is impractical to detail the procedure required in the event that a kick is taken wrunning casing or a liner. The immediate priority however will be to close in the well, bthe most suitable control technique can only be determined bearing in mind the partconditions at the rigsite. The subsequent options available can be summarised as follo

• Cross over to drillpipe (unless current string weight is too great) and strip to bottokill the well.

• Cross over to drillpipe, strip in until drillpipe is in the stack and kill the well at currshoe depth.

• Kill the well with the casing across the stack.

• Drop the casing.

• Shear the casing.


5-8March 1995

Figure 5.4 Decision Analysis – No Pipe in the Hole

IS THE INFLUX IMMEDIATELY BELOW

THE RAMS?

WELL SHUT IN – NO PIPE IN THE HOLE

MONITOR SURFACE

PRESSURE

LUBRICATE MUD INTO THE HOLE AND

BLEED GAS

ALL GAS BLED

FROM RAMS?

IS THERE ANY PRESSURE UNDER

THE RAMS?

DO SURFACE

PRESSURES INDICATE THAT INTRODUCING

PIPE INTO THE HOLE IS POSSIBLE?

IS THERE EVIDENCE OF INFLUX

MIGRATION?

IS SNUBBING A PRACTICAL

CONSIDERATION?


PRESSURE?

ATTEMPT TO REDUCETHE SURFACE

PRESSURE BY LUBRICATING OR BULLHEADING

YES

NO

SNUB IN PIPE KILL THE WELL

STRIP IN THE HOLE KILL WELL

FLOWCHECK THE WELL

OPEN THE RAMS

BULLHEAD KILL MUD INTO THE WELL

PREPARE CONTINGENCY TO

DEAL WITH THE FRACTURED ZONE

KILL WELL

NO

YES

NO

YES

YES

NO

YES

YESNO

NO

NO

YES

WEOX02.025

IMPLEMENT VOLUMETRIC

CONTROL METHOD

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5-9March 1995

The major factors that will determine the most appropriate course of action will includfollowing:

• The length and type of casing run.

• The possibility and consequences of the casing becoming stuck.

• The possibility and consequences of collapsing the casing.

• The feasibility of circulating out a kick by conventional means. (The relatively smannular clearance may cause excessive pressures in the annulus, or may pcompletely restrict circulation.)

• The feasibility of killing the well by other means such as bullheading or by volumecontrol.

• The BOP stack configuration and ram types.

• The likelihood of the casing being forced out of the hole by the well pressure.

7 Underground Blowout

(a) Flow to a Fracture above a High Pressure Zone

The majority of underground blowouts in the past have been as a result of a fractua weak zone up the hole as high pressure zone is penetrated.

Figure 5.5 shows a decision analysis for identifying and dealing with an undergroundblowout of this type.

If an underground blowout is suspected, on no account should attempts be macontrol the well using standard techniques. If the annulus is opened, reservoir will be allowed to flow up the wellbore to surface, thereby increasing surface press

The first action, after shutting in the well, will be to perform a positive test. The purposeof this test is to determine whether or not the hole is a closed system. A small displacementpump is lined up to the drillpipe and a small amount of fluid is pumped. If the drillpand casing pressure increase, there is no indication of fracture in the openhole.drillpipe pressure does not increase, or if any increase is not evident on the casina fracture in the openhole is indicated.

In order to halt an underground flow, it is necessary to pump fluid at a high rate dowthe drillpipe and up the annulus; thus effecting a dynamic kill. The fluid will eventuallyhave to be at kill weight in order to balance the kick zone EMW. However, it will alsohave to be as thin as possible to ensure that it can be pumped at high rate wexcessive surface circulating pressures.

Generally the kill mud must flow at least as fast as the underground flow if it is not to bedispersed by the flow as it passes out of the bit. The kick zone EMW can at best beestimated because reliable drillpipe pressure will not be available. The mud weightrequired to kill the well will depend on the position of the fracture in the wellbore the average weight of the fluid occupying the annulus between the fracture and su


5-10March 1995

Figure 5.5a Decision Analysis – Flow to a Fracture abovea High Pressure Zone

IF ANNULUS PRESSURE IS BUILDING, PUMP MUD AT

SLOW RATE DOWN ANNULUS. IF ANNULUS

CANNOT SUPPORT MUD, PUMP WATER

CONTINUALLY MONITOR ANNULUS

IF ANNULUS PRESSURE IS NOT EXCESSIVE

LEAVE ANNULUS SHUT IN

1.

2.

DO NOT BLEED FLUID FROM ANNULUS

LINE UP ONE PUMP TO THE ANNULUS. LINE UP MUD AND IF NECESSARY WATER SUCTION

CONTINUED ON FOLLOWING PAGE

UNDERGROUND BLOWOUT

CONFIRMED ?

RUN TEMPERATURE AND/OR NOISE LOG TO

IDENTIFY FLOW IF NECESSARY

RUN POSITIVE TEST

MONITOR SURFACE PRESSURES

SHUT IN THE WELL

1. 2.

3.

SUSPECT UNDERGROUND

BLOWOUT BECAUSE:

DRILLPIPE ON VACUUM PRESSURE BUILDUP CLEARLY INDICATES FORMATION HAS FRACTURED ANNULUS PRESSURE FLUCTUATING

NO EVIDENCE OF UNDERGROUND

BLOWOUT

IMPLEMENT STANDARD TECHNIQUES TO KILL

THE WELL

REASSESS THE SITUATION

NO

YES

WEOX02.026


5-11March 1995

Figure 5.5b Decision Analysis – Flow to a Fracture abovea High Pressure Zone (continued)

PREPARE 2 x ANNULUS VOLUME OF KILL WEIGHT MUD (AT MIN PV AND YP – USE FRICTION REDUCER IF AVAILABLE). REMOVE

KELLY – INSTALL HP CIRCULATING LINE

IMPLEMENT DYNAMIC KILL USING BARYTES PLUG

•

•

•

PUMP KILL WEIGHT MUD AT MAXIMUM RATE KEEP PUMPING UNTIL ALL THE MUD IS USED STOP ONLY IF SURFACE PRESSURES BECOME EXCESSIVE

DRILLPIPE AND ANNULUS PRESSURES

INDICATE THAT UNDERGROUND FLOW

HAS CEASED?

1.

2.

3.

MIX LCM PILL (100bbl MIN FOR LARGE ANNULUS) MIX 2 x ANNULUS VOLUME OF KILL WEIGHT MUD PUMP LCM PILL DOWN ANNULUS UNTIL JUST ABOVE FRACTURED ZONE

IMPLEMENT DYNAMIC KILL

•

•

•

PUMP KILL MUD AT MAXIMUM RATE DOWN DRILLPIPE PUMP LCM PILL DOWN ANNULUS AND INTO FRACTURE KEEP PUMPING UNLESS SURFACE PRESSURE LIMITS ARE REACHED

DRILLPIPE AND ANNULUS PRESSURES

INDICATE THAT UNDERGROUND FLOW

HAS CEASED?

1.

2. 3.

4.

CHECK MUD IS AT KILL WEIGHT REDUCE MUD VISCOSITY REDUCE DRILLSTRING INTERNAL FRICTION PUMP LARGER PLUG

1.

2. 3.

4.

CHECK MUD IS AT KILL WEIGHT REDUCE MUD VISCOSITY REDUCE DRILLSTRING INTERNAL FRICTION PUMP LARGER PLUG

1. 2.

3.

CEMENT BHA IN PLACE POOH TO PLUG FRACTURE POOH TO RUN CASING

TAKE STEPS TO SECURE WELL

1.

2.

BACK OFF, STRIP UP INTO CASING, SQUEEZE HIGH FILTER LOSS CEMENT SLURRY TO PLUG WELL IF CIRCULATION IS POSSIBLE ON BOTTOM, PUMP FRESHWATER AT MAXIMUM RATE TO SLOUGH HOLE

OPTIONS:1.

2.

STRIP UP INTO CASING. HAVING INSTALLED DART SQUEEZE HIGH FILTER LOSS CEMENT SLURRY TO PLUG WELL PUMP FRESHWATER AT MAXIMUM RATE TO SLOUGH HOLE

OPTIONS:

IS THE PIPE STUCK ?

TRY AGAIN

YES

NO

TRY AGAIN

YES

YES NO

NO

OPTIONS:

CEMENT BHA IN PLACE POOH TO PLUG FRACTURE POOH TO RUN CASING


OPTIONS:1. 2.

3.

WEOX02.027


5-12March 1995

Figure 5.6 Decision Analysis – Flow to a Fracture orLoss Zone below a High Pressure Zone

DRILLING AHEAD LOSSES EXPERIENCED

• •

SHUT DOWN ROTARY OR TOP DRIVE

CURE LOSSES DRILL AHEAD

• • •

CANNOT CONTROL LOSSES WELL STARTS TO FLOW SHUT IN WELL

• •

NO SURFACE PRESSURE ANNULUS AND DRILLPIPE ON VACUUM (ANNULUS PRESSURE MAY BUILD UP)

POSSIBLE UNDERGROUND BLOWOUT INDICATORS:

RUN POSITIVE TEST

RUN NOISE AND/OR TEMPERATURE

LOG IF NECESSARY

UNDERGROUND BLOWOUT

CONFIRMED?

•

•

DO NOT BLEED FLUID FROM ANNULUS LINE UP ONE PUMP TO THE ANNULUS. SUPPLY MUD AND IF NECESSARY WATER SUCTION

CONTINUALLY MONITOR ANNULUS

• • •

PUMP LCM PILL SET CEMENT PLUG ON BOTTOM CIRCULATE THE HOLE TO LIGHT MUD. DRILL UNDER PRESSURE WITH ROTATING HEAD

OPTIONS TO CONTROL THE FLOW:

SURFACE PRESSURE LOGS INDICATE THAT UNDERGROUND

FLOW HAS CEASED ?


REASSESS THE SITUATION

NO

YES

YES

NO

WEOX02.028

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5-13March 1995

The fracture may only support a column of water, in which case it will be necessary tobalance the kick zone pressure with the sum of the hydrostatic pressure of the kill wmud from the kick zone to the fracture and the hydrostatic pressure of the water athe fracture.

If the first attempt to control the flow is unsuccessful, the most likely causes will be␣eithat the volume or the velocity of kill mud was insufficient. Subsequent options thereforeinclude increasing the volume of the kill mud pumped and pumping at a greater ra

If the rig pumps have been operating at maximum output there remains the optiobring more pumps to the rigsite or to reduce the frictional resistance of the drillstrinsuch measures as:

• Removing the nozzles of the bit with a charge run on wireline.

• Perforating the BHA close to the bit.

• Pumping a lighter, less viscous mud ahead of the kill weight mud in order to reduthe velocity of the inflow.

As indicated in Figure 5.5, if these measures do not bring the well under control, tremains the option to mix an LCM pill or soft plug (See Chapter 2, Section 2.3) anddisplace it down the annulus and into the fracture as the kill weight mud is pumdown the drillpipe. The pump rates on the drillpipe and the annulus should be such aensure that the LCM pill is completely displaced into the fracture over the periodtime that will be required to pump the prepared volume of kill weight mud.

Past experience has shown that in many cases, having halted the underground flow, afurther flow has been initiated by attempts to pull off bottom. If the decision is made topull off bottom having halted an underground flow, extreme care should be taken.

The industry has given the term ‘Baryte plug’ to the heavy weight pills required to dwith underground blowouts. The recommended procedure for mixing and spottingbaryte plug, to deal with an underground blowout, is covered in Chapter 6.

(b) Flow to a Fracture or Loss Zone below a High Pressure Zone

The most likely cause of an underground blowout that flows down the wellbore from ahigh pressure zone is that a naturally fractured or cavernous formation is drilled The resultant losses reduce the hydrostatic head of the drilling fluid to such an ethat a permeable zone higher up the wellbore begins to flow.

When the well is shut-in, it is unlikely that any pressure will be recorded on eitherdrillpipe or the casing. However, the casing pressure may increase if gas migratesthe casing/drillpipe annulus; this rise in pressure is prevented by pumping mud dthe annulus.

Figure 5.6 shows the decision analysis for identifying and dealing with an undergroundblowout of this type.

Having established that the flow is downwards to a loss zone, there are two optionshould be considered for halting the flow:

• Set a plug on bottom.

• Reduce the mud weight and drill ahead under pressure.

lostability


Drilling under pressure will however only be used in circumstances in which circulation of this type has been anticipated, the high pressure zone has low permeand the correct equipment, including a rotating head, is available onsite.

See Chapter 2, Section 2.3 for LCM and cement plug recipes.

5-14March 1995


6 WELL KILL TECHNIQUES

Section Page

6.1 STANDARD TECHNIQUES 6-1

6.2 SPECIAL TECHNIQUES 6-31

2.1 Volumetric Method 6-33

2.2 Stripping 6-47

2.3 Bullheading 6-67

2.4 Snubbing 6-75

2.5 Baryte Plugs 6-84

2.6 Emergency Procedure 6-93

6.3 COMPLICATIONS 6-97

March 1995


6-1March 1995

6.1 STANDARD TECHNIQUES

Paragraph Page

1 General 6-2

2 Kick Circulation Methods 6-2

3 Kick Sheet 6-3

4 Implementation of the Wait & Weight Method 6-5

5 Implementation of the Driller’s Method 6-8

6 Procedures For High Angle or Horizontal Wells 6-11

7 Floating Rig Procedure 6-14

8 Accounting for Choke Line Losses in Deep Water 6-23

Illustrations

6.1 An Example Completed Kick Sheet 6-14

6.2 The Kill Line Monitor 6-21

6.3 Subsea BOP Gas prior to Removing Gas from Belowthe Preventers 6-24

6.4 Removing Gas from a Subsea BOP Stack– Lower pipe rams closed hang off rams opened 6-25

6.5 Removing Gas from a Subsea BOP Stack– Kill and choke lines displaced to kill weight mud 6-26

6.6 Removing Gas from a Subsea BOP Stack– Kill and choke lines displaced to water 6-27

6.7 Removing Gas from a Subsea BOP Stack– Gas pressure bled down, gas occupies choke line 6-28

6.8 Removing Gas from a Subsea BOP Stack– Diverter is closed, the annular is opened and the gas

is displaced from the stack 6-29

6.9 The Effect of Choke Line Losses– Casing pressure greater than choke line pressure 6-30

6.10 The Effect of Choke Line Losses– Casing pressure after initial circulation is less than

choke line loss 6-31

Rev 1 March 1995

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6-2March 1995

1 General

This section covers the basic steps that are required to implement the Driller’s Method, theWait & Weight Method on both a fixed installation as well as a floating rig. Furthdiscussions on the theories behind the methods are covered in Vol.2, Chapter 5.

Company policy is that a contingency plan must be developed regarding the implemenof the well control methods for both Company operated rigs and rigs that are under a Comcontract. This section is intended to assist in drawing up these contingency plans.

All the well control techniques are designed to ensure that:

Bottom hole pressure is maintained constant and equal to, or slightly greater thanformation pressure.

This is the key to well control practice. These techniques use the principle that:

The drillpipe pressure is used to monitor bottom hole pressure.

In the event of any well control incident it is important that a diary of events is kept. TheWell Control operations log can be used initially for this (See Figure 4.5). A full reportshould eventually be issued and submitted to Line Management.

2 Kick Circulation Methods

(a) The Wait & Weight Method

When conditions permit, it is recommended that the Wait & Weight Methodbe used in pref erence to other methods, in par ticular f or ver tical and lo wangle wells.

With the Wait & Weight Method, the mud is weighted up to the kill weight after the wis shut in. Then circulation is started and the kick displaced from the hole with weight mud. So the well can be killed with one complete circulation. Circulation canstarted immediately if the rig mud weighting system is able to weight up the mudrate greater than or equal to the mud SCR.

Therefore the advantages of the Wait & Weight Method are as follows:

• The surface pressure will be lower than using other methods if the kill weight menters the annulus before the influx is circulated out. This difference is mostsignificant for influx containing gas, and for high intensity (large under-balance)kicks. This is illustrated in Figure 5.5 in Vol.2, Chapter 5.

• The pressure exerted on the casing shoe (or the weak point in the openhole) wlower than using other methods if the kill mud starts up the annulus before the tthe influx is displaced to the shoe (or openhole weak point). This is illustrated inFigure 5.6 in Vol.2, Chapter 5.

• The well will be under pressure for the least time.

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(b) The Driller’s Method

In certain circumstances, it may not be practical to implement the Wait & Weight Method.These include:

• There are insufficient stocks of weighting material at the rigsite.

• The rig mud weighting system is not capable of increasing the active mud weighkill weight as the kick is displaced.

• There is some considerable doubt as to the mud weight required to kill the wel

• Impending bad weather dictates that the kick must be displaced from the holquickly as possible.

• Increasing surface pressures indicate the influx is rising rapidly in the annulus

Under the above circumstances, the Driller’s method should be considered. The Driller’sMethod requires that two complete hole circulations are carried out before the wellbe killed. After a kick is taken and the well shut-in, the kick is displaced from the hoby the first circulation with the original mud. In the mean time the mud is weightedto kill weight, and the second circulation carried out to kill the well.

The advantages of the Driller’s Method over the Wait & Weight Method are:

• The kick can be displaced from the hole soon after the well is shut-in.

• The earlier circulation may reduce the risks of stuck pipe and other hole proble

• Influx fluids can be displaced from the well, even if suitable mud weighting materis not available.

• It avoids the need to initiate a volumetric control during the waiting period.

3 Kick Sheet

The kick sheet should be used to record all the relevant well and kick data. Figures 6.1b and 6.1c show an example kick sheet. The procedures for completing the kick sheet arshown in Figure 6.1d.

The general well data, drillstring/annulus contents, circulating times and the mud pdata should be recorded routinely and available at all times in the kick sheet.

In case a kick is taken, the relevant kick data should be recorded in the kick sheetTheshut-in procedure and the interpretation of the pressure data are covered in Chapter 4.on the kick data, a decision should be made regarding what method be used to kill theIn addition to the standard methods which have been described in the previous paragsome special techniques should be also considered. These special techniques are discussein Section 6.2.

If the decision is made to displace the kick from the hole by using one of the stanmethods, the relevant parameters should be calculated and recorded in the kick shee

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6-4March 1995

(a) Determine the kill weight mud

Circulation may be initiated with the original weight mud, or with the kill weight mudepending on the kill method to be used.

The weight of the mud that would exactly balance the kick zone pressure is calculfrom the shut-in drillpipe pressure as follows

PdpKill Mud Weight, MW2 = MW1 + (SG)TVD x 1.421

where Pdp = Stabilised shut-in drillpipe pressure (psi)MW1 = Original mud weight (SG)TVD = True vertical depth of kick zone (m)

It is not recommended practice to weight the mud any higher than the kill weight duthe well killing operation. After the well has been killed however, the mud weight shouldbe raised to provide suitable overbalance.

(b) Calculate the baryte quantity required to weight up the mud

This calculation is necessary in order to determine if adequate stocks of baryteavailable on site. The amount of baryte required to weight up the mud can be calculafrom the following formula:

(MW2 - MW1)Baryte required, Wb = 1490 x (lb/bbl)

(4.25 - MW2)

Total quantity of baryte required (lb) = Wb x Total Active Mud Volume (lb)

Total active mud volume = Drillstring Vol + Annulus Vol + Surface Active Vol (bbl)

The stocks of baryte at the rigsite must be at least 10% greater than the calcuquantity of baryte required.

(c) Develop annulus pressure profile

It is useful to estimate the maximum pressures that will occur during circulation. Theareas of particular importance will be the maximum pressure that will be exerted ashoe (or openhole weak point) and the maximum surface pressure. It is not howessential to carry out these calculations prior to circulation.

An approximate technique can be used to estimate the maximum pressure at a point in the openhole, as well as the maximum surface pressure during displacemThis has been presented in Vol.2, Chapter 5. The actual pressures will generally belower than those predicted by the technique.

Computer software that utilises the exact technique is also available at the DrillingCompletions Branch, BP Exploration, Sunbury. The software includes the effects thatthe conventional approximate technique has neglected. These include the gas solubilityin oil-based muds, downhole temperature, gas dispersion and slip, etc. So the sofcan provide more realistic predictions of pressures and flows in the wellbore thanapproximate techniques. The software can be also used to investigate the impactsoperational parameters, formation characteristics and human factors on the overallcontrol operation. These include the kick detecting volume, the formation permeabiland over-pressure, the time required for the rig crew to shut-in and the mud SCR, e

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4 Implementation of the Wait & Weight Method

Prior to implementing the Wait & Weight Method, the relevant sections of the Kick Sheet covered in Paragraph 3 should be completed.

The Wait & Weight Method accomplishes the kill operation in one complete circulationrequires weight up of the mud after the well is shut in, followed by circulation with the weight mud. So several calculations are necessary prior to initiating circulation. These areas follows:

(a) Determine the circulation rate

The upper limit for the circulation rate is generally set by the maximum rate that bacan be mixed into the mud. The following formula can be used to estimate the maximupossible circulation rate:

Baryte delivery rate (lb/min)Maximum circulation rate = (bbl/min)

Baryte required to weight up mud (lb/bbl)

A limiting factor, particularly in the case of oil mud, may be the rate at which viscoscan be built in the mud. This, and associated problems of building mud weight adiscussed in Chapter 1 in ‘Use of the Mud System’.

Having established the maximum possible circulation rate, the actual circulation will be determined on the basis of several factors. These factors are detailed in Chapter␣in ‘Drills and SCRs’. The chosen SCR and the relevant pumping data should be recoin the kick sheet.

(b) Calculate the initial circulating pressure

The initial drillpipe circulating pressure, Pic, should be calculated in order to estimthe circulating pressure that will be required to maintain constant bottom hole presat the start of the circulation.

The initial circulating pressure recorded after the pump has been brought uspeed␣should be the sum of the shut-in drillpipe pressure and the SCR pressure chosen rate:

Pic = Pdp + Pscr

where Pic = Initial circulating pressure (psi)Pdp = Stabilised shut-in drillpipe pressure (psi)Pscr = Circulating pressure at SCR with MW1 (psi)

(c) Calculate the final circulating pressure

As the drillpipe is displaced with kill weight mud, the standpipe pressure must be redto take into account the increased hydrostatic pressure of the mud in the pipeThestandpipe pressure must also compensate for the additional friction pressure idrillpipe and across the bit as the kill weight mud displaces the original mud.

Once the drillpipe has been completely displaced to kill weight mud, the static drillppressure required to balance the kick zone will be zero. At this stage thereforethe␣␣circulating pressure can be estimated by determining the SCR pressure for thweight mud.

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The final circulating pressure can be estimated as follows:

MW2Pfc = Pscr (at MW1) x

MW1

where Pfc = Final circulating pressure (psi).

(d) Determine the displacement times and the cumulative pump strokes

At all times during circulation, it is important to know the position of the influx in twellbore, as well as the volume of hole that has been circulated to kill weight mu

The key points during the circulation are as follows:

• When the kill weight mud reaches the bit.

• When the top of the influx is circulated to the casing shoe or openhole weak p

• When the influx is circulated to the choke.

Before circulation is started, the estimated circulating time and the correspondingpump strokes to each point should be calculated.

Volume to be displaced (bbl)Pumping time to reach point = (min)of interest Pump rate (bbl/min)

Volume to be displaced (bbl)Total strokes to reach point = (stk)of interest

Pump output per stroke (bbl/stk)

(e) Plot standpipe pressure schedule

To ensure that the standpipe pressure is adjusted correctly as the kill weight mcirculated down the drillpipe, a plot should be made of the required standpipe pre(See Figure 6.1b).

The initial circulating pressure should be plotted corresponding to zero strokesThefinal circulating pressure should be plotted corresponding to total strokes equivalecomplete displacement of the drillpipe. The two points on the graph can be joined uwith a straight line to produce the standpipe pressure schedule. (Note: for high anhorizontal wells, the graph is not a straight line. See Paragraph 6.)

In practice standpipe pressure is most easily controlled by reducing the pressure insteps, rather than continuously.

(f) Procedure for the displacement of the kick

1 Bring the pump up to kill speed

• Line up the pump to the drillpipe and route returns through the choke manifothe mud gas separator.

• Zero the stroke counter on the choke panel.

• Open the remote operated choke at the same time as the pump is started on thConsider stroking the drillstring up at this point.

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6-7March 1995

• Maintain the choke pressure equal to the original shut-in casing pressure as the is slowly brought up to speed. This may take 1/2 to 1 minute.

• Once the pump is up to speed record the initial circulating pressure.

If the actual initial circulating pressure is considerably different from the calculatedvalue, stop the pump, shut in the well and investigate the cause.

If the actual initial circulating pressure is equal to, or reasonably close to the calcuvalue, continue the displacement and adjust the standpipe pressure schedule accor.

Any marginal difference between the actual and calculated initial circulating pressis most likely to be due to the fact that the SCR pressure used to calculate the icirculating pressure was inaccurate. The actual SCR pressure, and hence the correcfinal circulating pressure, Pfc, can be determined from the initial circulating pressurfollows:

Pscr = Pic – Pdp

The standpipe pressure schedule can therefore be corrected to take into accouadjusted circulating pressures.

2 Circulate the influx fr om the well maintaining constant bottom holepressure

As the drillpipe is displaced with kill weight mud, the standpipe pressure shouldstepped down according to the standpipe pressure schedule. (The standpipe prwill have a natural tendency to drop as the kill weight mud is displaced down drillpipe.)

Once the drillpipe has been displaced to kill weight mud, the drillpipe pressure shbe maintained at the final circulating pressure for the rest of the circulation.

The pit gain, drillpipe pressure, choke pressure and all other relevant informashould␣be recorded during displacement using the Well Control Operations Log(See␣Figure 4.5). These will help to determine the down hole condition during all stagof the kill operation.

As the influx is displaced up the hole, the drillpipe pressure will tend to drop asinflux expands. (This expansion will not occur if the influx is water or oil.) This effectwill be especially marked if the influx contains a significant quantity of gas. The chokeshould therefore be adjusted to compensate for this. For example, if the drillpipe predrops by 70 psi below that required, the choke pressure should be increaseapproximately 70 psi. The pressure on the drillpipe will increase after a lag time whican typically be 2 seconds per 300m of drillstring depth. This technique will be mosteffective at the early stages of displacement; and less so at later stages odisplacement, if the well contains a significant proportion of gas.

When the influx reaches the choke, the choke pressure will start to decrease due differences in density and viscosity between the influx and the mud. If the influx contsignificant quantities of gas, the drop in choke pressure may be quite substantialthe choke will have to be closed down quickly.

As the influx is circulated from the well and mud is circulated to the choke, the chpressure will begin to rise rapidly. The choke should therefore be opened to allow thchoke pressure to drop sufficiently to re-establish the final circulating pressure on thdrillpipe, and hence maintain constant bottom hole pressure.

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6-8March 1995

Once the hole has been circulated to kill weight mud, the pump should be stoppewell shut-in, and the casing and drillpipe checked for pressure. There should be nopressure on either the casing or the drillpipe. However, if there is still some pressure othe casing, circulation should be restarted to clear the contaminated mud from the an

Once the well has been completely killed, a flowcheck on the choke line return shbe carried out before the rams are opened. If this flowcheck indicates no flow, the ramsshould be opened and a further flowcheck on the annulus carried out.

In line with Company policy, a further complete hole circulation should be carried oprior to continuing operations. A suitable overbalance can be added to the mudthis␣stage.

5 Implementation of the Driller’s Method

Prior to implementing the Wait & Weight Method, the relevant sections of the Kick Sheetcovered in Paragraph 3 should be completed.

The Driller’s method is a two complete circulation method. The kick is circulated out of thehole by the first circulation with the original mud. The second circulation is carried out witthe weighted mud to kill the well.

Prior to the first circulation, the following calculations are necessary:

(a) Determine the circulation rate

The circulation rate for the first circulation of the Driller’s Method is not limited by thebaryte mixing capacity of the rig. Limiting factors will include the additional wellbopressures due to circulation, and further practicalities as outlined in Chapter 1. Rthe chosen circulating rate SCR and the corresponding pumping data in the kick


The initial circulating pressure at the start of the first circulation is calculated insame manner as the Wait and Weight Method, although the drillstring displacemevolume/time is not significant in this case.

The initial circulating pressure will be maintained constant throughout the first circulasince the mud weight is not changed.

(c) Determine the displacement times and corresponding pump strokes

These figures are calculated in exactly the same manner as the Wait and Weight Method.

(d) Plot the standpipe pressure schedule

The standpipe pressure is held constant throughout the first complete circulation initial circulating pressure.

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6-9March 1995

The following steps can be used as a guide for the procedure for the displacemthe␣kick:

1 Bring the pump up to speed f or the fir st complete cir culation

• Line up the pump to the drillpipe and route returns through the choke manifothe mud gas separator.

• Set the stroke counter on the remote choke panel to zero.

• Open the remote operated choke at the same time as the pump is slowly brouto speed. Consider stroking the drillstring up at this point.

• Maintain the choke pressure equal to the original shut-in casing pressure as theis slowly brought up to speed. This may take 1/2 to 1 minute.

• Once the pump is up to speed record the initial circulating pressure. If the ainitial circulating pressure is considerably different from the calculated value, stothe pump, shut-in the well and investigate the cause.

If the actual initial circulating pressure is equal to, or reasonably close to the calcuvalue, continue the displacement, holding the standpipe pressure at the value rewhen the pump was first brought up to speed.

Any marginal difference between the actual and calculated initial circulating presis most likely to be due to the fact that the SCR pressure used to calculate the circulating pressure was inaccurate. The actual SCR pressure can be determined frthe initial circulating pressure as follows:

P P Pscr ic dp= −

This adjusted value for the SCR pressure should be used for estimating the circupressures for the second complete circulation.

2 Circulate the influx fr om the well maintaining constant bottom holepressure

Influx behaviour during circulation will be similar to the Wait and Weight Methodrequiring similar choke manipulation.

Choke pressures will inevitably be higher than if the Wait and Weight Method hadbeen␣used. These higher pressures will be reflected downhole, causing greater strethe openhole.

Once the influx has been displaced from the hole, the shut-in drillpipe and shut-in cpressure should be equal. If the casing pressure is higher than the drillpipe prethis is evidence that there is still some kick fluid in the annulus, or the mud weightout of balance.

Prior to circulating kill weight mud into the hole, the calculations as outlinedParagraph␣3 “Kick Sheet” should be carried out. The following further calculations arethen worked:

(a) Determine the circulation rate for the second circulation

The circulation rate is determined on the same basis as if the Wait and Weight Methodhad been used.

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The initial circulating pressure will be the same as for the first circulation.

The initial circulating pressure is therefore calculated as follows:

Pic = Pdp + Pscr

where Pic = Second circulation initial circulating pressure (psi)Pdp = Drillpipe pressure recorded prior to second circulation (psi)Pscr = Slow circulating rate pressure (psi)

(c) Calculate the final circulating pressure

As with the Wait and Weight Method, the circulating pressure must be adjustecompensate for the kill weight mud.

MW2Pfc = Pscr (at MW1) x

MW1

where Pfc = Second circulation final circulating pressure (psi)MW1 = Original mud weight (SG)MW2 = Kill mud weight used for second circulation (SG)

(d) Determine the displacement times and corresponding cumulative pumpstrokes

These figures will be the same as for the first circulation.

(e) Plot the standpipe pressure schedule

The standpipe pressure schedule for the second circulation is drawn up in themanner as for the Wait and Weight Method (Figure 6.1b).

The following can be used as a guide for the procedure of circulating the hole weight mud:

1 Bring the pump up to speed f or the second complete cir culation

• Change pump suctions without stopping the mud pump, and begin pumping thweight mud. (An alternative is to stop pumping and then restart using the procfor the Wait and Weight Method.)

• Zero the stroke counter on the choke panel.

• Once the pump has been switched to the kill mud, record the initial circulpressure.

The initial circulating pressure should be the same with the standpipe pressure the first complete circulation. If this is the case, continue the displacement and the standpipe pressure schedule accordingly.

If the initial circulating pressure has changed considerably, stop the pump, shut in thwell, and investigate the cause.

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6-11March 1995

2 Circulate the hole to kill weight m ud maintaining constant bottom holepressure

As the drillpipe is displaced with kill weight mud, the standpipe circulating pressshould be stepped down according to the standpipe pressure schedule.

Once the drillpipe has been displaced to kill weight mud, the final drillpipe circulatipressure is held constant by manipulating the choke.

As kill weight mud is circulated up the annulus, the drillpipe pressure will tendincrease. The choke should be adjusted to ensure that the drillpipe pressure is maintaat the final circulating pressure; thereby ensuring constant bottom hole pressure.

When the returned mud is at kill weight, the pump should be stopped and the shut-in. The well should be checked for pressure.

Once the well has been killed, a flowcheck on the choke line return should be caout before the rams are opened. If this flowcheck indicates no flow, the rams should beopened and a further flowcheck on the annulus carried out.

In line with Company policy, a further complete hole circulation should be carrieout␣prior to continuing operations. A suitable overbalance can be added to the mudthis stage.

6 Procedures For High Angle or Horizontal Wells

(a) Implementation of Kick Circulation Methods

The procedures for implementing one of the standard kick circulation methodsessentially the same for both the vertical and high angle or horizontal wells (as covin the previous paragraphs). However, there are several points which should be considerbefore and during a well killing operation in a high angle or horizontal well.

• The advantages of the Wait & Weight Method over the Driller’s Method are lessimportant in a high angle or horizontal well. This is because the weighted mud willnot reduce the surface and casing shoe pressures until it has passed the horizohigh angle section. By then the kick may have entered into the casing or been othe well.

• The circulation should be started using the Driller’s Method once the well hasbeen␣shut in and the stabilised shut-in pressures are established. In the meanthe kill weight mud is prepared in the reserve mud pits. The earlier start of thecirculation will reduce the risks of stuck pipe and other hole problems associawith the stagnant mud.

• Once the mud weight has been increased to the kill weight, the circulation shoulswitched to the kill weight mud, even if the influx is still in the annulus. Thecirculation continues until the kick is circulated out and the kill mud returns to surfaThis will minimise the well pressures as well as the time of dealing with the kic

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6-12March 1995

(b) Standpipe Pressure Schedule

When pumping down the kill mud through the drillpipe in a vertical well, the surpump pressure should be reduced linearly from the initial circulating pressure (ICthe final circulating pressure (FCP), in order to maintain the bottom hole preconstant. Thereafter, the pump pressure is kept constant at FCP until the kill mud returnsto surface. Therefore, the pressure schedule during pumping the kill mud througdrillpipe can be obtained by simply joining a straight line between ICP and FCP. Thishas been covered in the previous paragraphs.

However, this is not the case in a high angle or horizontal well because the chathe hydrostatic pressure due to the kill mud is not linear. For example, when the front othe kill mud is going through a horizontal section of the drillpipe, the hydrostatic preat the hole bottom does not change at all. So in this case the pump pressure shkept constant (or increased slightly due to friction pressure increase with kill mu

Therefore, the standpipe pressure schedule should be modified to take into accoeffect of hole angle. To achieve this, the standpipe pressures when the kill mud reaseveral critical depths in the drillpipe should be calculated. These include the depths the kick-off, end-build, end-tangent, etc. The calculations can be performed as follow

i. Calculate the drillpipe size factor and the friction constant. This is necessary inorder to calculate the friction pressure increase due to the kill weight mud.

α1 = L1 / ID15

where: α1 = Size factor for drillpipe section 1, (m/in5)L1 = Length of drillpipe section 1, (m)ID1 = ID of drillpipe section 1, (inch)

If there is more than one drillpipe section (tapered string), then the size factor shocalculated for each of the sections. BHA can be treated as part of the drillpipe se

Pfc - Pscrβ = α1 + α2

where: β = Drillpipe friction constant, (psi.in5/m)α1 α2 = Drillpipe size factors for section 1 and 2, (m/in5)Pfc = Final circulating pressure (psi)Pscr = Slow circulating pressure with original mud MW1, (psi)

ii. Calculate the friction pressure increase when the kill mud reaches each of the depths in the drillpipe (kick-off, end-build, end-tangent, etc.).

• If the critical depth is above/at the drillpipe section cross-over point, then:

MD∆Pfriction = β xID1

5

• If the critical depth is below the drillpipe section cross-over point, then:

(MD - L1)∆Pfriction = β x [α1 + ]ID2

5

where: ∆Pfriction = Friction pressure increase due to kill weight mud, (psi)

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MD = Measured depth at the critical depth, (m)

iii. Calculate the static drillpipe pressure when the kill weight mud reaches each ocritical depths:

TVDPstatic = Pdp x (1.0 - )

TVDh

where: Pstatic = Static drillpipe pressure, (psi)Pdp = Drillpipe pressure before the kill weight mud is circulated, (psi)TVD = Vertical depth at the critical depth, (m)TVDh = Vertical depth at the open hole kick zone, (m)

iv. Calculate the standpipe pressure when the kill weight mud reaches each ocritical␣depths.

Pstand = Pscr + ∆Pfriction + Pstatic

where: Pstand = Standpipe pressure, (psi)

The results of the above calculations should be recorded in the Kick Sheet. Thesecalculations should be carried out if the hole has a maximum angle greater 30␣degrees.

Figures 6.1a shows an example of a completed kick sheet for a high angle well.Figure␣6.1b shows the standpipe pressure schedule for pumping down the kill weightmud. It shows that the standpipe pressures required to maintain a constant bottompressure are lower for a high angle well (with build-hold profile) than if the well wvertical. So if the standpipe pressure schedule for a vertical well was used (dotted stline in Figure 6.1b), excessive high well pressures would result, which would increasethe risk of fracturing the formation at the casing shoe or openhole weak point.

(c) Trapped Gas in Inverted or Horizontal Hole Section

If a kick containing free gas occurs in an inverted hole section (i.e. the hole anggreater than 90 degrees), then the free gas will be trapped there unless the mcirculated fast enough to flush the gas out of the inverted section. Similar scenariooccur in washouts or undulations of a horizontal hole section.

A combination of the following is a possible indication that a kick has occurred ininverted or horizontal hole section:

• There is an increased mud return flowrate

• There is a positive pit gain

• When the well is shut in, the drillpipe pressure and the casing pressure are the(under-balanced kick) or both are zeros (swabbed kick)

• The casing pressure is stable (no gas migration)

However the kick influx density/type (gas, water or oil) can not be determined based onthe above data (as using the method described in Section 4.3). A gas kick is recognisedwhen it is being circulated through the low angle or vertical hole section, whereexpansion causes a continuous increase in the casing pressure. So the first attempt tokill the well should be using one of the standard techniques.

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6-14March 1995

If the kick can not be circulated to surface using the standard techniques, it indicthat the kick influx is free gas which has been trapped in the inverted or horizontal section. To remove the trapped gas, the mud must be circulated with an annular veloabove a critical value. This critical annular velocity is about 100 ft/min when the holangle is between 90~95 degrees. In an 8-1/2" hole, this corresponds to a criticalrate of 4.6 bbl/min, which is higher than the normal range of SCR during a well conoperation. So prior to drilling an inverted or horizontal hole section, the pump presat a SCR corresponding to 100~150 ft/min should be recorded in the kick sheet.

The following procedures may be attempted to remove the trapped gas from the invor horizontal hole section:

• Start circulation with the original mud at a flow rate corresponding to an annumud velocity of 100~150 ft/min until the entire horizontal hole section has bedisplaced;

• Reduce the flow rate to a normal SCR and proceed using one of the standardkilling techniques.

• After one complete circulation, stop the pump and shut in the well to check pit␣gain.

• If there is still a positive pit gain, that indicates that some gas is still trapped downhRepeat the previous procedures.

In cases where the high flow rate can not be achieved to remove the trapped gas, cobullheading the gas back into the formation. As the trapped gas should stay near thkick formation, bullheading is more likely to succeed in an inverted hole section. Thebullheading technique is described in Section 6.2.

7 Floating Rig Procedure

Well control on a floating rig presents special problems that are not encountered onand fixed offshore rigs. The main difficulties stem from the fact that the well must be killedwhile circulating through a small diameter choke line. The problems presented can besummarised as follows:

• The frictional pressure generated by circulating through the choke line may caexcessive pressures in the wellbore or in the circulating system.

• The entry of the influx into the choke line may cause an uncontrollable drop in bottompressure.

• As the mud displaces the influx from the choke line the rapid increase in hydrospressure in the annulus may cause excessive pressures in the openhole.

These problems are particularly acute in deep water. However, well control procedures shouldbe modified in line with those described here, even in relatively shallow water, to takeaccount of these problems. The drillpipe pressure is still used to monitor bottomholepressure.

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6-15March 1995

Figure 6.1a An Example of Completed Kick Sheet

An Example of Completed Kick Sheet

Well No. Well No. Rig Name: Rigname Date: 27-Oct-94 Time: 13:10Hole Size: 8-1/2" Casing Size: 9-5/8" Shoe Depth (m): TVD= 1535 TD= 4291

MAASP (psi): 1003 Max Eqiv. Mud Weight (sg): 1.44 Casing Burst (psi): 10900Barytes on Site (MT): 50 On Order (MT): 40 Total Reserved Mud Vol (bbl): 300

DRILLSTRING CONTENTS

DP/DC Section ID Capacity (bbl/m) Length (m) Vol (bbl) Cumulative Volume (bbl)

5" DP 4.276 0.0583 5180 301.825" HWDP 3 0.0287 60 1.72 303.56-1/4" DC 2.25 0.0161 60 0.97 304.5

ANNULUS CONTENTS

Hole/Casing Section ID Capacity (bbl/m) Length (m) Vol (bbl) Cumulative Volume (bbl)

5"DP - 9-5/8"csg 8.681 0.1605 4291 688.65"DP - Hole 8.5 0.1506 949 142.9 831.5

6-1/4" DC - Hole 8.5 0.1058 60 6.3 837.9

Surface Equipment Vol (bbl): 6 Choke Line ID: 3.0 Length (m): 100 Vol (bbl): 2.9Total Circulating System Vol (bbl): 1151 Surface Active Mud Vol (bbl): 350Total Active Mud Vol (bbl): 1501Pump 1 Liner: 5-1/2" Max Pres (psi): 4723 Eff (%): 97 Stroke Vol (bbl/stk): 0.0855Pump 2 Liner: 5-1/2" Max Pres (psi): 4723 Eff (%): 97 Stroke Vol (bbl/stk): 0.0855

PUMP 1 PUMP 2 TRAVEL TIMES (MIN / STROKES)

SPM bbl/min Pscr SPM bbi/min Pscr Surface to Bit Bit to Shoe Shoe to Choke Total

30 2.565 350 30 2.565 355 119 / 3567 58 / 1746 268 / 8055 445 / 1336840 3.42 590 40 3.42 600 89 / 3567 44 / 1746 201 / 8055 334 / 1336850 4.275 890 50 4.275 900 71 / 3567 35 / 1746 161 / 8055 267 / 13368

KICK DATA

Time of Kick: 15:25 Depth (m): TVD= 1667 TD= 5300 Mud Weight (sg), MW1= 0.98Shut-in DP Pres (psi), Pdp= 400 Annulus Pres (psi), Pa= 460 Pit Gain (bbl): 20Kill Mud Weight (sg), MW2= 1.15 Barytes Required (lb/bbl): 81.1 Total (MT): 55Chosen Pump SPM: 30 Stroke Vol (bbl/stk): 0.086 SCR (bbl/min): 2.565 Pscr (at MW1)= 350 psi

Time Started: 15:30 Initial Circ Pres (psi), Pic= 750 Final Circ Pres (psi), Pfc= 410

For High Angle or Horizontal Wells ( > 30 deg) Drillpipe Size ID Length (m) Size Factor Drillpipe Friction Constant

5" DP + BHA 4.276 5300 3.708 16.27

STANDPIPE PRESSURE WHEN PUMPING DOWN KILL MUD

Section Point MD (m) TVD (m) Vol (bbl) Strokes Pstatic (psi) Pfriction (psi) Standpipe Pressure (psi)

Surface: 0 0 0 0 =Pdp 0 Pic= 750 Kick Off: 350 350 20 239 316 4 670 End Build 1: 1328 1000 77 905 160 15 525 DP Cross-Over:

End Tangent 1:

End Build/Drop 2:

Bit: 5300 1667 309 3612 0 60 Pfc= 410

BP

WE

LL CO

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OL M

AN

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6-16M

arch 1995

Figure 6.1b

An E

xample of K

ick Sheet

STANDPIPE PRESSURE SCHEDULE

500 3000 3500 4000

Bit

ll Was Vertical

0 750 750239 670905 525

3612 410 410

350

400

450

500

550

600

650

700

750

800

0 500 1000 1500 2000 2

Pump Strokes

Sta

nd

pip

e P

ress

ure

(p

si)

Kickoff

End Build

If The We


6-17March 1995

Figure 6.1c An Example of Kick Sheet

Figure 6.1c: An Example of Kick Sheet

SUMMARY OF FORMULAE

1. MAASP = Pwp - 1.421 x MW 1 x Dwp

2. Pipe Internal Capacity (bbl/m) = ID2 / 313.8

3. Annular Capacity (bbl/m) = (DH2 - DP 2) / 313.8

Pdp4. Kill Mud Weight (sg), MW2 = MW 1 + 1.421 x TVDh

(MW2 - MW1 )5. Baryte Required (lb/bbl) = 1490 x (4.25 - MW2)

6. Initial Circulating Pressure (psi), Pic = Pdp + Pscr

MW27. Final circulating Pressure (psi), P fc = Pscr x MW1

8. Pumping Time to Reach Depth of Interest (min):

Volume to be displaced (bbl)=

Pump output (bbl/min)

9. Pump Strokes to Reach Depth of Interest (stk):

Volume to be displaced (bbl) =

Pump stroke volume (bbl/stk)

For High Angle or Horizontal Wells

10. Drillpipe 1 Size Factor, 1 = L1 / ID15

Drillpipe 2 Size Factor, 2 = L2 / ID25

Pfc - Pscr11. Drillpipe Friction Constant, = 1 + 2

12. Static Pressure When Kill Mud at TVD (psi):

Pstatic = Pdp x (1.0 - TVD / TVDh )

13. Friction Pressure Increase When Kill Mud atMD (psi):

a. When MD above/at DP cross-over point:MD

Pfriction = x ID1

5

b. When MD below DP cross-over point: (MD - L1)

Pfriction = x [ 1 + ] ID2

5

14. Standpipe Pressure at Depth of Interest (psi):

Pstand = P scr + Pfriction + Pstatic

SYMBOLS AND UNITS

Dwp Vertical depth at openhole weak point (m)DH Hole diameter or casing ID (inch)DP Drillpipe OD (inch)ID Drillpipe ID (inch)L Length of drillpipe with same size (m)MAASP

Maximum allowable annulus surface pressure(psi)

MD Measured depth at depth of interest (m)MW1 Original (unweighted) mud weight (sg)MW2 Kill mud weight (sg)Pdp Shut-in drillpipe pressure (psi)Pfc Final circulating pressure (psi)Pic initial circulating pressure (psi)Pscr Standpipe pressure at solw circulating rate

with original mud (psi)

Pstand Standpipe pressure (psi)Pstatic Static (drillpipe) pressure (if well was shut

in) when pumping kill mud (psi)Pwp Leak off pressure at openhole weak point

(psi)TVD True vertical depth at depth of interest (m)TVDh True vertical depth of open hole (m)

Drillpipe size factorDrillpipe friction constant

Pfriction Friction pressure increase with kill mud(psi)

Subscripts for ID, L and :1 Drillpipe size 12. Drillpipe size 2


6-18March 1995

Figure 6.1d An Example of Kick Sheet

COMPLETION OF KICK SHEET

GENERAL WELL DATA (Routinely Recorded)

These include well No, rig, date, time, hole size, casing size, shoe depths, MAASP, max mud weight, casingburst pressure, barite quantities and reserved mud volume.

• MAASP [psi] = (Leak-off pressure, psi) − 1.421 x (Mud weight in hole, sg) x (Leak-off TVD, m)

• Max mud weight (Shoe frac grad) [sg] = (Leak-off pressure, psi) / [ 1.421 x (Leak-off TVD, m) ]

DRILLSTRING / ANNULUS CONTENTS (Routinely Recorded)

These include the drillstring, annulus contents, surface volumes and the total active mud volume. Thedrillstring contents include OD, ID, capacity, length and volume. The annulus contents include hole/casingsizes (with drillstring OD), hole/casing ID, capacity, length and volume).

• Drillstring capacity [bbl/m] = (Pipe ID, inch)2 / 313.8

• Annulus capacity [bbl/m] = [ (Hole size, inch)2 − (Pipe OD, inch)2 ] / 313.8

• Volume [bbl] = (Capacity, bbl/m) x (Length, m)

• Total active mud volume [bbl] = (Total circulating system vol, bbl) + (Surface active mud vol, bbl)

CIRCULATION TIME AND PUMP STROKES (Routinely Recorded)

These include the liner size, rated pressure, volume efficiency and stroke volume. Record at least three slowcirculating rates and the corresponding standpipe pressures.

Calculate circulation times and number of pump strokes:

• Surf → Bit [min] = (Total drillstring volume, bbl) / (Pump output, bbl/min)

[stk] = (Total drillstring volume, bbl) / (Pump stroke volume, bbl/stk)

• Bit → Shoe [min] = (Total open hole annular volume, bbl) / (Pump output, bbl/min)

[stk] = (Total open hole annular volume, bbl) / (Pump stroke volume, bbl/stk)

• Shoe → Choke [min] = (Total casing annular volume, bbl) / (Pump output, bbl/min)

[stk] = (Total casing annular volume, bbl) / (Pump stroke volume, bbl/stk)

KICK DATA

Record all the relevant kick data (time, hole depths, mud weight, shut-in DP & casing pressures, pit gain). Allthe kill parameters should be calculated.

• Kill mud weight [sg] = (Mud weight in hole, sg) + [(SIDPP Pdp, psi) / [ 1.421 x (Hole TVD, m)]

(Kill mud weight, sg) − (Mud weight in hole, sg)• Barite required [lb/bbl] = 1490 x

4.25 − (Kill mud weight, sg)

• Total quantity of barite required [MT] = (Total active mud volume, bbl) x (Barite required, lb/bbl) / 2205

• Initial circulating pres P ic [psi] = (SIDPP Pdp, psi) + (SCR pres Pscr , psi)

• Final circulating pres Pfc [psi] = (SCR pres Pscr , psi) x (Kill mud weight, sg) / (Mud weight in hole, sg)


6-19March 1995

Figure 6.1d An Example of Kick Sheet (cont'd)

HIGH ANGLE OR HORIZONTAL WELLS (Angle > 30 deg)

No need to complete this section if the well is vertical (or angle<30 deg). In this case, the standpipe pressureschedule can be obtained by joining a straight line between the initial and the final circulating pressures.

Otherwise, the standpipe pressures should be calculated for pumping down the weighted kill mud to each ofthe depths at kick-off, end-build, drillpipe cross-over, end-tangent, etc. After the kill mud has reached the bitdepth, the standpipe pressure should be maintained constant at the final circulating pressure.

• DP size factor, α = (Drillpipe section length, m) / (Drillpipe ID, inch)5

(Calculate for each of the drillpipe IDs)

(Final circ pres P fc , psi) − (SCR pres Pscr , psi)• DP Friction Const, =

(DP Size 1 factor α1) + (DP Size 2 factor α2)

Calculate the pump stroke and the corresponding standpipe pressure when the kill mud has reached thedepth at MD/TVD (the point for calculation such as kick off, end-build, etc.):

• Volume [bbl] = (Drillstring capacity, bbl/m) x (Measured depth MD, m)

• Pump stroke [stk] = (Volume, bbl) / (Pump stroke volume, bbl/stk)

(TVD, m)• Static (shut-in) pressure Pstatic [psi] = (SIDPP Pdp, psi) x [ 1.0 − ]

(Hole TVD, m)

• Friction pressure increase (due to kill mud) ∆Pfriction :

- If MD (point for calculation) is above or at DP1/DP2 cross-over point:

∆Pfriction [psi] = (DP Friction Const, β) x (MD, m) / (Top drillpipe ID, inch)5

- If MD is below DP1/DP2 cross-over point:

[ (MD, m) − (Top DP1 length L1 , m) ]∆Pfriction [psi] = β x [ (DP1 size factor, α1 ) +

(DP2 ID, inch) 5

• Standpipe Pressure Pstand [psi] = (SCR pres Pscr , psi) + (∆Pfriction , psi) + (Pstatic , psi)

STANDPIPE PRESSURE SCHEDULE

Draw up the standpipe pressure schedule on the graph paper by:1. Choose appropriate scales for the horizontal pump stroke and the vertical standpipe pressure.2. Mark each of the calculated standpipe pressures against the corresponding pump strokes. The initial

circulating pressure should be plotted corresponding to zero stroke and the final circulating pressurecorresponding to the strokes for the kill mud to reach the bit.

3. Join the marked points with straight lines. From the final point onward (after the kill mud has reached the bit), draw a horizontal line.

For vertical or low angle wells, there are only two marked points (i.e. the initial & final circulating pressures)and therefore the pressure schedule is a straight line before the kill mud reaches the bit. For high angle orhorizontal wells, there should be more than two points and the pressure schedule is not be a straight line .

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6-20March 1995

Choke line losses are generally not significant at slow circulating rates in shallow wateso the calculations required during the implementation of both the Driller’ s Method and theWait and Weight Method on a floating rig, drilling in shallow water, do not account forchoke line losses. The calculations as covered in Paragraphs 4 to 6 (which cover the normalimplementation of the Wait and Weight Method and the Driller’ s Method) are therefore stillapplicable.

In deep water, when choke line losses can be significant, it is necessary to assess the effectof choke line losses on wellbore pressures during circulation. In which case fucalculations, as covered in Paragraph 8, ‘Accounting for Choke Line Losses in Deep Water’,are required to account for choke line losses.

Standard procedure (as detailed in Paragraphs 4 to 6) should be modified along the follines when using either the Wait and Weight Method or the Driller’ s Method on a floating␣rig:

1 Bring the pump up to speed

• Line up to monitor wellhead pressure through the kill line. See Figure 6.2 fschematic␣of the kill line monitor. (Bear in mind that the kill line may not containmud at this stage.)

• Line up the pump to circulate down the drillpipe and route returns through the cmanifold to the mud gas separator.

• Set the stroke counter on the choke panel to zero.

• Record the pressure registered on the kill line monitor.

• Open the remote operated choke at the same time as the pump is started on th

• Hold the kill line monitor pressure constant as the pump is brought up to spee

• Once the pump is up to speed the initial circulating pressure should be checke

2 Circulate the kic k to the wellhead maintaining constant bottomhole pressure

In the case of the Wait and Weight Method the standpipe pressure will be reduced inline with the standpipe pressure schedule.

In the case of the Driller’ s Method the standpipe pressure is maintained at initialcirculating pressure as the kick is displaced from the hole.

When the total strokes pumped indicates that the influx is approaching the wellheakill line monitor should be carefully checked for any sudden drops in pressure. A dropin pressure registered on this gauge indicates that the influx has entered the chokhowever this drop may not always be detected.

3 Cir culate the influx out of the well maintaining constant bottomholepressure

It is recommended that the influx is displaced up the choke line at a considerably rerate in order that the choke does not have to be adjusted at an unrealistic rate. This mayinvolve shutting in the well at this point and restarting the displacement at the minimpump speed.

A considerable increase in choke pressure will generally be required as gas or lightwinflux displaces mud from the choke line.



Figure 6.2 Use of Kill Line Monitor f or Wellhead Pressureon Floating Rig

SEABED

��

RETURNS

CHOKE PRESSURE

GAUGE

VALVE CLOSED

KILL LINE (KILL LINE VALVES

OPEN)

CHOKE LINE

PUMP

DRILLPIPE PRESSURE

GAUGE

KILL LINE MONITOR

VALVE OPEN

MUD

��GAS

VALVE OPEN

VALVE CLOSED

KEY

SEA

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6-22March 1995

An increase in the pressure recorded at the kill line monitor may indicate that the orimud behind the influx has started up the choke line.

In the case of the Wait and Weight Method, once the returns are at kill weight, the pumpshould be stopped and the well checked for pressure.

In the case of the Driller’ s Method, the well will be circulated to kill weight mud priorto step (4).

4 Remove BOP gas

It is quite possible that some gas will have accumulated under the closed during␣displacement of the kick. This gas must be removed from the stack before theBOP is opened.

The recommended technique is to isolate the well, displace the kill and choke linwater (maintaining the BOP gas at original pressure), bleed gas up choke line, opeannular and allow riser to U-tube, displacing the gas up the choke line. Diesel maused instead of water if low mud weights have been used to kill the well. (Adeqfacilities should be available to deal with the returned diesel.)

For the example stack shown in Figure 6.4, for which trapped gas has the potentiaa serious problem, this technique is implemented as follows:

• Isolate the well from the BOP stack by closing the lower pipe rams. (See Figure␣6.4.)

• Circulate kill mud down the kill line, across the stack and up the choke line.Route␣returns through the degasser. Record the kill line circulating pressure.(See␣Figure 6.5.)

• Shut the well in. Line up to circulate water down the kill line and up the choke line.

• Slowly displace the kill line to water. As the kill line is displaced to water increasethe kill line circulating pressure by an amount equal to the difference in hydrostaticpressure between the kill mud and water at the depth of the stack. (This will enthat the gas pressure is unchanged.)

• Keep pumping water across the stack and maintain the final circulatpressure.␣When the returns are clear water, stop the pump and shut in at the choke.(See Figure␣6.6.)

• Close the subsea kill line valve(s).

• Bleed pressure from the choke line. (See Figure 6.7.)

(The pressure that has been trapped in the gas bubble is used to ensure that bubble expands as the choke is opened to displace all the water from the chokHaving bled all the pressure from the choke line the gas bubble should be almatmospheric pressure.)

• Close the diverter. Line up the trip tank/pump to circulate the riser under the diverter.

• Slowly bleed back the upper annular closing pressure. Open the annular.

• Allow the riser to U-tube. Take returns up the choke line. Fill the hole as required.(See Figure 6.8.) Be prepared to deal with gas in the riser.

• Displace the riser and kill and choke lines to kill weight mud.

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6-23March 1995

• Open the lower pipe rams.

• Open the diverter and flowcheck the well.

8 Accounting for Choke Line Losses in Deep Water

In line with the standard procedure for floating rigs, an attempt will always be madecompensate for choke line losses with the use of the kill line monitor.

However, the effect of choke line losses should be assessed in any situation in which chokeline losses are considered significant. This is most likely to occur only in deep water. (SeeChapter 1, Section 1.3 for the techniques for measuring choke line pressure losses.)

The following procedure can be used to account for choke line losses for the Wait andWeight Method (however the same principles are applicable to the Driller’ s Method):

1 Assess the eff ect of c hoke line losses at pump star t up

In order to determine the most suitable circulation rate, the additional pressure actinthe wellbore due to choke line friction should be estimated at a range of circularates.

The following two cases may be applicable at this point:

Case A: When shut-in casing pressure is greater than the choke line friction pressuthe desired slow circulating rate. (See Figure 6.9.)

Case B: When the shut-in casing pressure is less than the choke line friction pressureat the desired slow circulation rate. (See Figure 6.10.)

In Case A the choke line friction pressure will be fully compensated for until such timeduring the displacement that the required choke pressure is less than the sum of cline friction pressure and the wide open choke pressure. In most cases this will oonly when the original mud behind the influx is passing the choke, at which tisubsurface pressures are unlikely to be critically high. Therefore, if Case A is applicable,the choke line losses should not impose a limitation on the circulation rate.

However Case B represents a situation in which part of the choke line frictional preswill be applied on the openhole. The choke line frictional pressure can be compensatedfor up to the amount equal to the difference between the shut-in annulus pressure andthe wide open choke pressure.

The additional pressures exerted in the wellbore due to choke line losses at pump up can be determined as follows:

For Case A: there should be no additional pressures in the wellbore due to choke friction at pump start-up

For Case B: additional wellbore pressure due to choke line friction= Pcl – Pa + Poc

where: Pa = annulus shut-in pressure (psi)Poc = choke pressure at SCR recorded with the choke wide open (psi)Pcl = choke line frictional pressure at SCR (psi)


6-24March 1995

Figure 6.3 Subsea BOP Stack prior to Removing Gasfrom Belo w the Pre venter s

CHOKE LINEKILL LINE

��

��

��

��MUD

GAS

VALVE OPEN

VALVE CLOSED

UPPER ANNULAR

LOWER ANNULAR

BLIND/SHEAR

PIPE RAM

PIPE RAM

PIPE RAM

PIPE RAM

WEOX02.031


6-25March 1995

Figure 6.4 Removing Gas from a Subsea BOP Stack– Lower pipe rams closed hang off rams opened

��

CHOKE LINEKILL LINE

��MUD

GAS

VALVE OPEN

VALVE CLOSED

UPPER ANNULAR

BLIND/SHEAR

PIPE RAM

PIPE RAM

PIPE RAM

PIPE RAM

LOWER ANNULAR

��

WEOX02.032


6-26March 1995

Figure 6.5 Removing Gas from a Subsea BOP Stack– Kill and choke lines displaced to kill weight mud

CHOKE LINEKILL LINE

��MUD

GAS

VALVE OPEN

VALVE CLOSED

UPPER ANNULAR

BLIND/SHEAR

PIPE RAM

PIPE RAM

PIPE RAM

PIPE RAM

LOWER ANNULAR

��

WEOX02.033


6-27March 1995

Figure 6.6 Removing Gas from a Subsea BOP Stack– Kill and choke lines displaced to water

CHOKE LINEKILL LINE

��

MUD

GAS

VALVE OPEN

VALVE CLOSED

UPPER ANNULAR

BLIND/SHEAR

PIPE RAM

PIPE RAM

PIPE RAM

PIPE RAM

LOWER ANNULAR

��WATER (OR DIESEL)

WEOX02.034

��


6-28March 1995

Figure 6.7 Removing Gas from a Subsea BOP Stack– Gas pressure bled down, gas occupies choke line

��

��

��

CHOKE LINEKILL LINE

��

MUD

GAS

VALVE OPEN

VALVE CLOSED

UPPER ANNULAR

BLIND/SHEAR

PIPE RAM

PIPE RAM

PIPE RAM

PIPE RAM

LOWER ANNULAR

��

WATER (OR DIESEL)

GAS PRESSURE BLEEDS DOWN TO DISPLACE WATER FROM

CHOKE LINE RESULTANT GAS PRESSURE IS CLOSE TO

ATMOSPHERIC

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6-29March 1995

Figure 6.8 Removing Gas from a Subsea BOP Stack– Diverter is closed, the annular is opened and

the gas is displaced from the stack

��CHOKE LINEKILL LINE

��

MUD

GAS

VALVE OPEN

VALVE CLOSED

UPPER ANNULAR

BLIND/SHEAR

PIPE RAM

PIPE RAM

PIPE RAM

PIPE RAM

LOWER ANNULAR

��

WATER (OR DIESEL)

WEOX02.036


6-30March 1995

Figure 6.9 The Effect of Choke Line Losses– Casing pressure greater than choke line pressure

��

INITIAL SHUT-IN CONDITIONS

CIRCULATION STARTED AT 40SPM

400800 800

��

1385800 430

KILL LINE PRESSURE HELD

CONSTANT

DRILLPIPE PRESSURE INCREASES BY

SCR PRESSURE

CHOKE PRESSURE DROPS BY CHOKE LINE PRESSURE DROP

BOTTOMHOLE PRESSURE STAYS APPROXIMATELY

CONSTANT

SCRS AND CHOKE LINE LOSSES

MINIMUM RATE FOR PUMP

SPM 20 30 40

PSCR 400 680 985

PCL 150 250 370

��MUD

GAS

KEY

WEOX02.037


6-31March 1995

Figure 6.10 The Effect of Choke Line Losses– Casing pressure after initial circulation is

less than choke line loss

�

INITIAL SHUT-IN CONDITIONS

CIRCULATION STARTED AT 30SPM

100400 400

��

780400 150

KILL LINE PRESSURE HELD

CONSTANT

DRILLPILE PRESSURE INCREASED BY

SCR PRESSURE

CHOKE PRESSURE DROPS BY CHOKE LINE PRESSURE DROP

BOTTOMHOLE PRESSURE STAYS APPROXIMATELY

CONSTANT

SCRS AND CHOKE LINE LOSSES

MINIMUM RATE FOR PUMP

SPM 20 30 40

PSCR 400 680 985

PCL 150 250 370

��MUD

GAS

KEY

CIRCULATION STARTED AT MINIMUM RATE, 20SPM

100100 100 600200 50

UNABLE TO KEEP THE KILL LINE PRESSURE

CONSTANT. EVEN WITH THE CHOKE WIDE OPEN

THE KILL LINE PRESSURE INCREASES BY THE SUM

OF CHOKE LINE LOSS AND WIDE OPEN CHOKE

PRESSURE MINUS THE ORIGINAL SHUT-IN

PRESSURE

DRILLPIPE PRESSURE EQUALS THE SUM OF THE ORIGINAL

SHUT-IN DRILLPIPE PRESSURE PLUS THE SCR PRESSURE PLUS

THE CHOKE LINE LOSS PLUS THE WIDE OPEN CHOKE PRESSURE MINUS THE

SHUT-IN CASING PRESSURE

CHOKE PRESSURE WITH CHOKE WIDE OPEN

BOTTOMHOLE PRESSURE INCREASES

INFLUX CIRCULATED OUT WITH ORIGINAL MUD

WEIGHT

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6-32March 1995

These pressures as well as the annulus frictional pressure will act at all pointswellbore and circulating system. The effect of these additional pressures must therefbe analysed at all points in the system and in particular at the openhole weak po

2 Calculate the initial cir culating pressure

The initial circulating pressure is calculated to estimate the standpipe pressure opump is up to speed.

For Case A: the initial circulating pressure = Pdp + Pscr

For Case B: the initial circulating pressure = Pdp + Pscr + Pcl + Poc – Pa

where: Pscr = show circulating rate pressure (psi)Pdp = shut-in drillpipe pressure that reflects the kick zone pressure (pPcl = choke line frictional pressure at SCR (psi)Pa = annulus shut-in pressure (psi)Poc = choke pressure recorded while circulating at SCR with the choke

open (psi)

3 Calculate the final cir culating pressure

The final circulating pressure, when kill weight mud reaches the bit, for each cacalculated as follows:

For Case A: Final circulating pressure = Pscr X MW2MW1

For Case B: Final circulating pressure = (Pscr X MW2) + Pcl + Poc – Pa

MW1

where MW2 = weight of the kill mud (SG)MW1 = weight of the original mud (SG)

4 Monitor pressure at the kill line monitor as the pump is br ought up to speed

For Case A, the pressure at the kill line monitor is held constant as the pump is broup to speed. The choke pressure will decrease by an amount equivalent to the chokfriction pressure once the pump is up to speed.

For Case B, the pressure at the kill line monitor will be constant as the pump is bup to speed. However at some point before the pump is up to the SCR the kmonitor pressure will start to increase. Once the pump is up to speed the choke wide open and the pressure at the kill line monitor will have risen by the proportithe choke line friction pressure that is not compensated for. (The increase will beequivalent to Pcl + Poc – Pa.)

5 Check the initial cir culating pressure once the pump is up to speed

If the initial circulating pressure is significantly different from the calculated value, thpump should be stopped, the well shut in and the cause for the discrepancy dete

If the initial circulating pressure is equal to or reasonably close to the calculated the displacement should be continued.

Any marginal difference is likely to be due to the fact that the actual SCR pressudifferent from the value used to calculate the initial circulating pressure. The actualSCR pressure can be established from the initial circulating pressure recorded whpump is up to speed.

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6-33March 1995

For Case A, the actual SCR pressure can be determined from the initial circulapressure as follows:

Pscr = Pic – Pdp

For Case B, the actual SCR pressure can be determined as follows:

Pscr = Pic – Pdp – Pcl – Poc + Pa

For the Wait and Weight Method the final circulating pressure must be recalculatedfollows:

For Case A, the final circulating pressure can be determined as follows:

Pfc = Pscr X MW2MW1

For Case B, the final circulating pressure is determined as follows:

Pfc = (Pscr X MW2)+ Pcl – Pa + Poc

MW1

The standpipe pressure should therefore be redrawn to take into account these afigures.

6 Assess the eff ect of c hoke line losses at the latter sta g es of kic kdisplacement

For Case A: In the latter stages of the displacement the choke pressure requirmaintain constant bottomhole pressure will drop. This drop will be mostsignificant once the original mud behind the influx is at the choke.

If the required choke pressure drops below the sum of the chokeloss and the wide open choke pressure, it will no longer be possibcompletely compensate for the choke line losses.

The resultant increase in wellbore pressure at this stage will be given

Increase in pressure = Pcl + Poc – Pa

In practice, the choke will be wide open at this stage and the standpressure will rise above final circulating pressure.

When the hole has been circulated to kill weight mud, the circulatpressure will have increased by the sum of the choke line losses anwide open choke pressure.

For Case B: As the influx expands the choke pressure required at surface increase. As the required choke pressure increases it will be possiblcompensate for a greater proportion of the choke line losses.

If the required choke pressure increases to a value equal to the suthe choke line loss and the wide open choke pressure it will be posto compensate for the complete amount of the choke line losses.

It should be noted that the most critical period in terms of downhole pressures is likeoccur at early stages in the displacement. In this respect the change in choke lincompensation at latter stages in the displacement is unlikely to be a critical factor.

6-33/34


6.2 SPECIAL TECHNIQUES

Subsection Page

2.1 VOLUMETRIC METHOD 6-37

2.2 STRIPPING 6-51

2.3 BULLHEADING 6-71

2.4 SNUBBING 6-79

2.5 BARYTE PLUGS 6-89

2.6 EMERGENCY PROCEDURE 6-97

6-35March 1995

6-35/36



Subsection 2.1 VOLUMETRIC METHOD

Paragraph Page

1 General 6-38

2 Static Volumetric Method(Drillpipe pressure used to monitorbottomhole pressure) 6-38

3 Static Volumetric Method(Choke pressure used to monitorbottomhole pressure) 6-40

4 Lubrication 6-46

5 Dynamic Volumetric Control 6-47

Illustrations

6.12 Static Volumetric Method – an example of controlof bottomhole pressure at the choke 6-42

6.13 Static Volumetric Control – illustrating theconsequences of improper procedure 6-43

6.14 Volumetric Control Worksheet – an example for a land rig 6-44

6.15 Static Volumetric Method – choke pressure usedto monitor bottomhole pressure 6-45

6.16 Dynamic Volumetric Method – used to removegas from below a stack 6-49

6-37March 1995

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6-38March 1995

1 General

The Volumetric Method can be used to control the expansion of an influx that is migraduring shut-in periods. It can therefore only be used if significant migration isoccurring. This may occur only in the case of gas kicks.

This method can be used during shut-in periods prior to displacement, or as a mesafely venting an influx from a well in which circumstances prevent the implementationormal well control techniques.

Situations in which the Volumetric Method may be applicable therefore include:

• During any shut-in period after the well has kicked.

• If the pumps are inoperable.

• If there is a washout in the drillstring that prevents displacement of the kick.

• If the pipe is a considerable distance off bottom, out of the hole or stuck off bottom.

• If the bit is plugged.

• If the pipe has been dropped.

There are four techniques that may be required to deal with an influx that is migratinthe hole. These are as follows:

• Static Volumetric Control: When the drillpipe is on or near bottom and can be usedmeasure bottomhole pressure.

• Static Volumetric Control: When the drillpipe cannot be used to measure bottomhpressure.

• Lubrication: When the influx has migrated to the stack this technique is used to repthe influx with mud as the influx is bled at the choke.

• Dynamic Volumetric Control: This technique may be used as an alternative to the abbut is most applicable as an alternative to lubrication on a floating rig.

The following Paragraphs can be used as guidelines for the implementation of the abmentioned procedures.

2 Static Volumetric Method(Drillpipe Pressure used to monitorbottomhole pressure)

This procedure is the most simple to implement in that the drillpipe pressure is availamonitor bottomhole pressure.

It may be necessary to implement this procedure during any time that the well is safter a kick has been taken. This situation may arise while preparations are being madkill a well or when operations have to be suspended due to bad weather or equipment f

influx

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6-39March 1995

The following guidelines can be used:

1 Recor d the shut-in drillpipe and c hoke pressures

After the well has been shut-in the surface pressures can be used to identify the type. These calculations are covered in Chapter 4.

If the influx contains a significant proportion of gas, it will be necessary to allow influx to expand considerably as it migrates up the hole.

2 Develop ann ulus pressure pr ofile

The annular pressures during migration of the influx will be similar to those resulfrom circulation with the Driller’s Method. In this respect, a PC or programmabcalculator can be used to develop the annulus pressure profile as for the Driller’s Method.

The maximum wellbore pressures can therefore be estimated along with the anticipit gain.

3 Determine migration rate

After the surface pressures have built up to values which reflect the kick zone presfurther increases will be due to migration. The rate of migration can be estimated fromtwo pressure readings, recorded either both on the drillpipe or both on the casing,at a known time interval apart.

The distance D (m), migrated up the annulus of constant cross section in theinterval T (min) is given by:

D = P2 – P1 (m)MW X 1.421

where P1 = surface pressure at start of interval (psi)P2 = surface pressure after interval T (psi)MW = mud weight in the hole (SG)T = time interval (min)MR = migration rate (m/hr)

The migration rate can therefore be estimated as follows:

MR = D X 60 (m/hr)T

4 Allo w drillpipe pressure to b uild b y overbalance mar gin

The drillpipe pressure should be allowed to build by a suitable overbalance magin.This margin will be registered on the drillpipe as an increase in pressure over and athe final shut-in pressure.

The overbalance margin may typically be in the range 50 to 200 psi.

5 Allo w drillpipe pressure to b uild up b y operating mar gin

The drillpipe pressure should be allowed to build by a further margin to ensure that theoverbalance is maintained as mud is bled from the well.

The operating margin may also typically be in the range 50 – 200 psi depending onresultant wellbore pressures at each stage in the operation.

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6-40March 1995

6 Bleed increment of m ud fr om the ann ulus to reduce drillpipe pressure

After the drillpipe pressure has built by the sum of the overbalance margin and theoperating margin, the kick zone will be overbalanced by the sum of these two valu

Mud should then be bled from the annulus to reduce the drillpipe pressure to a representing the final shut-in pressure plus the overbalance margin.

A manual choke should be used for this operation to ensure adequate control. It is strecommended that small volumes of mud are bled off at a time to allow time for thedrillpipe pressure to respond. There will be a considerable delay time between choand drillpipe pressure in a deep well and especially if the influx contains gas.

7 Contin ue pr ocess until influx migrates to the stac k

This process should be repeated until the influx migrates to the stack. Arrival of theinflux at the stack may be preceded by bleeding gas cut mud from the well. Howev, ifgas is observed at the choke, the well should be shut-in and mud lubricated inwell. If gas is bled from the well the bottomhole pressure will drop and eventucause a further influx.

When the influx has migrated to the stack, surface pressures should no longer rmigration will cease to occur. This may not be the case on a floating rig when somigration may occur up the choke line.

Use the Volumetric Control Worksheet to record all the relevant data (See Figure 6.1

8 Lubricate m ud into the hole or implement the Dynamic Volumetric Method

See Paragraphs 4 and 5 as follows.

3 Static Volumetric Method(Choke pressure used to monitorbottomhole pressure)

This technique may be required if the drillstring is stuck off bottom, out of the hole or toofar off bottom to be stripped back or if the bit is plugged.

In these cases, it will not be possible to monitor the bottomhole pressure with the driduring the control process. The choke pressure is therefore used in conjunction with volume of mud bled from the well to infer the bottomhole pressure.

The principle of this procedure is that the bottomhole pressure is maintained slightlykick zone pressure by bleeding mud from the annulus to allow the influx to expandmigrates up the hole. Mud is bled in increments from the well as the choke pressuredue to migration. The amount of mud bled off for each increment is determined from thincrease in choke pressure.

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6-41March 1995

For example, if the choke pressure increases by 100 psi, a volume of mud equivalenhydrostatic pressure in the annulus of 100 psi is bled at the choke at constant chokepressure . In this manner, control over the bottomhole pressure is achieved. It should benoted that this method is only applicable if the influx is migrating as the mudis b led fr om the well . The rate of influx migration determines the time required to bleeeach increment of mud from the well.

Figure 6.12 illustrates this technique. In this example, the following conditions apply:

Operating margin = 150 psiAnnulus = 8 1/2 in. X 5 in.Mud weight = 1.85 SG

Hydrostatic equivalent of mud =445.7 – 1.85 = 17.5 psi/bbl(72.25 – 25)

Therefore bleed150 = 8.5 bbl of mud17.5

As can be seen from Figure 6.12, the influx must migrate (1824 – 133 =) 1691m while8.5 bbl of mud is bled from the well. It is clear that this operation will take several hour

If the operating margin was quickly bled from the well, the original influx would expand bapproximately 0.4 bbl before the bottomhole pressure drops to the original kick zone presIf the remaining 8.1 bbl were bled from the well, this would cause a further influx of 8.1 bas shown in Figure 6.13.

As the influx migrates further up the hole, the time required to bleed the 8.5 bbl incremfrom the well will decrease significantly. In this example, the influx must migrate 570m(approximately 2 hours) as the next increment is bled from the well. If the rate of infmigration is maintained, this time will continually reduce until the influx is at surface.

Volumetric control is similar to the Driller’s Method although the influx moves up the holeunder the influence of migration. The resultant wellbore pressures as well as the required gain will be similar for the two techniques.

The following guidelines can be used:

1 Recor d shut-in c hoke pressure

2 Develop ann ulus pressure pr ofile

3 Determine migration rate

The first three steps are carried out in the same manner as for the previous techn

4 Calculate h ydr ostatic pressure of m ud per barrel

The hydrostatic pressure of the mud per barrel should be calculated at the point inthe ann ulus directl y abo ve the influx . It can be calculated as follows:

Hydrostatic pressure per barrel =445.7 X MW (psi/barrel)(dhc2 – do2)

where MW = mud weight in the hole (SG)dhc = hole/casing ID (in.)do = drillstring OD (in.)


6-42March 1995

Figure 6.12 Static Volumetric Method– an example of control of bottomhole

pressure at the choke

��

1. AT INITIAL SHUT-IN

650psi Pa

��

MUD

GAS

KEY

VOLUME OF INFLUX 10bbl DEPTH 3615m

HEIGHT OF INFLUX

66m

2. INCREASE IN SURFACE PRESSURE

FOR OVERBALANCE MARGIN

��

850psi Pa

VOLUME OF INFLUX 10bbl

PRESSURE IN BUBBLE 10,000psi

76m

BHP = Pf = 10,000psi

T = 0

BHP = 10,200psi

T = 15 min (assuming migration rate of 300m/hr)

��

3. INCREASE IN SURFACE PRESSURE

FOR OPERATING MARGIN

1000psi Pa

VOLUME OF INFLUX 10bbl

133m

4. 8.5bbl BLED OFF WHILST HOLDING

CHOKE PRESSURE CONSTANT

��

1000psi Pa

VOLUME OF INFLUX 18.5bbl

PRESSURE IN BUBBLE NOW

5405psi

1824m

BHP = 10,350psi

T = 25 min

BHP = 10,200psi

T = 6 hours

PRESSURE IN BUBBLE

10,000psi

MUD BLED AT CONSTANT CHOKE

PRESSURE

WEOX02.039

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6-43March 1995

Figure 6.13 Static Volumetric Contr ol– illustrating the consequences of improper procedure

5 Allo w choke pressure to b uild b y overbalance mar gin

The choke pressure should be allowed to build by an overbalance margin that maytypically be in the range 50 – 200 psi.

6 Allo w choke pressure to b uild b y operating mar gin

The choke pressure should be allowed to continue building a further similar amoprovide an operating margin.

The total margin will depend on the resultant wellbore pressures at each stage operation.

7 Bleed increment of m ud fr om the well at constant c hoke pressure

A suitable volume of mud should be bled from the well to reduce the bottomhole preby an amount equivalent to the operating margin.

��

3a. BLEED MUD FROM

WELL INSTANTANEOUSLY

��MUD

GAS

KEY

4a. 8.5bbl BLED OFF INSTANTANEOUSLY,

WELL SHUT-IN

��

Pa DROPS BELOW 1000psi

VOLUME OF INFLUX = 10.4bbl

��

Pa > 1000psi

BHP DROPS BELOW

10,000psi

VOLUME OF INFLUX = 10.4bbl

VOLUME OF SECONDARY INFLUX = 8.1bbl

BHP = 10,000psi

T 25 min

BHP = 10,000psi

T 25 min

WEOX02.040


Figure 6.14 Volumetric Contr ol Worksheet– an example for a land rig

VOLUMETRIC CONTROL WORKSHEET

For worksheet calculation enter information into shaded cells. Units (US/UK): UK Version 1/1 1Q'95 by ODL/C. Weddle

WELL NO 26 RIG Rig 10 DATE AND TIME 15:30 20/08/95 SHEET NO 1

MUD WEIGHT IN THE HOLE, sg 1.85 LUBRICATING MUD WEIGHT, sg 1.85

HYDROSTATIC PRESSURE PER BARREL OF 1.85 sg MUD in 5 X 8.5 ANNULUS: 17.46 psi/bbl

HYDROSTATIC PRESSURE PER BARREL OF sg MUD in X ANNULUS: psi/bbl

HYDROSTATIC PRESSURE PER BARREL OF sg MUD in HOLE: psi/bbl Migration Rate Time (min) 20

HYDROSTATIC PRESSURE PER BARREL OF sg MUD in HOLE: psi/bbl P1 2 P2 5

OVERBALANCE MARGIN: 200 psi OPERATING MARGIN: 150 psi Distance, (m) 3.743701 Rate, (mpm) 11.2311

Choke or DPTIME OPERATION Choke Change in Hydrostatic Overbalance Volume Total

If DP pressure can't be read see page 6-36 Monitor Monitor of Mud Bled/ of Mud Bled/ Volume ofof Vol. 1 of BP Well Control Manual Pressure Pressure Lubricated Lubricated Mud

( hr min) (psi) (psi) (psi) (psi) (bbl) (bbl)

19:00 650 0 0 0 0 100

19:15 Influx Migrating 850 200 0 200 0 100


19:25 / 01.25 Bleed Mud at Choke 1000 0 -150 200 8.5 108.5

1:35 Influx Migrating 1150 150 0 350 0 108.5

1:35 / 3:15 Bleed Mud at Choke 1150 0 -150 200 8.5 117


3:30 / 4:45 Bleed Mud at Choke 1300 0 -150 200 8.5 125.5

4.:55 Influx Migrating 1450 150 0 350 0 125.5

4:55 / 5:30 Bleed Mud at Choke 1450 0 -150 200 8.5 134

+ ve+ ve increase - ve bled overbalance + ve bled

- ve- ve decrease + ve lubricated underbalance - ve lubricated

WEOX02.199

6-44March 1995

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6-45March 1995

The choke pressure must be held constant as the mud is bled from the well.

As an example (refer to Figures 6.12 and 6.13):

Operating margin = 150 psiAnnulus = 8 1/2 in. X 5 in.Mud weight = 1.85 SG

Hydrostatic equivalent of mud =445.7 – 1.85 = 17.5 psi/bbl(72.25 – 25)

Therefore bleed 150 = 8.5 bbl of mud17.5

As can be seen from the example in Figure 6.12 the bottom of the influx has hadmigrate from 133m off bottom, to 1824m off bottom, whilst bleeding off 8.5 bbl ofmud. This could take considerable time. If the operating margin, in this case 150 psi(8.5 bbl), had been quickly bled off and assuming no migration during this period, thebubble would have expanded by only about 0.36/bbl before bottomhole pressure (Bdropped to kick zone pressure. This would result in a further influx of 8.14 bbl.

Subsequent volumes bled from the well will require less migration distance, ie for an␣increof bubble size to 27 bbl (after next bleed off), the distance from bottom will be 2395m.

Figure 6.15 Static Volumetric Method– choke pressure used to monitor

bottomhole pressure

FINAL SHUT-IN ANNULUS PRESSURE

OVERBALANCE MARGIN

OPERATING MARGIN

OPERATING MARGIN

OPERATING MARGIN

GAS MIGRATING TO SURFACE

MUD BLED AT CHOKE (at constant choke

pressure until volume bled off corresponds to Operating Margin)

INFLUX MIGRATING

PRESSURE BUILDUP

0 8.5 17 25.5 34 42.5 51 59.5 68 76.5

650

850

1000

1150

1300

1450

1600

1750

1900

2050

2200

VOLUME OF MUD BLED FROM ANNULUS (bbl)

CH

OK

E P

RE

SS

UR

E (

psi

)

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6-46March 1995

8 Contin ue the pr ocess until the influx migrates to the stac k

This process should be repeated until the influx migrates to the stack.

When the influx has migrated to the stack surface pressures should no longer rmigration will cease to occur. This may not be the case on a floating rig when sommigration may occur up the choke line.

Use the Volumetric Control Worksheet to record all the relevant data.

Figure 6.14 shows a completed example.

9 Lubricate m ud into the hole or implement the Dynamic Volumetric Method

See Paragraphs 4 and 5.

If this process has been implemented because the pipe was off bottom, it may be feasibleto circulate the influx out of the hole when the influx has migrated to the bit.

See Figure 6.15 for a typical choke pressure schedule for the Static Volumetric Method.

4 Lubrication

This technique may be used to vent the influx from below the stack while maintaining conbottomhole pressure.

Lubrication is most suited to fixed offshore and land rigs. It can be used to vent gas from stack after implementing the Static Volumetric Method, as well as to reduce surface pressuprior to an operation such as stripping or bullheading.

Lubrication is likely to involve a considerable margin of error when implemented on afloating rig because of the complication of monitoring the bottomhole pressure througchoke line. When the influx has migrated to the stack it is quite possible that the chokewill become full of gas cut mud. In this situation it is impractical to attempt to maintcontrol of the bottomhole pressure with the choke.

However lubrication is simpler to implement than the Dynamic Volumetric Method. Forthis reason alone, it may be considered for use on a floating rig.

The following guidelines can be used to lubricate mud into a well:

1 Calculate the h ydr ostatic pressure per barrel of the lubricating m ud

This is done in the same manner as for the Volumetric Method.

2 Slowl y lubricate a measured quantity of m ud into the hole

Line up the pump to the kill line.

Having determined the safe upper limit for the surface pressure, the pump shoustarted slowly on the hole.

Mud should be lubricated into the well until pump pressure reaches a predetermined limAtthis point the pump should be stopped and the well shut in.

The well should be left static for a period while the gas migrates through the mud thabeen lubricated into the well.

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6-47March 1995

The exact amount of mud lubricated into the well should be closely monitored.

3 Bleed gas fr om the well

Gas should be bled from the well to reduce the surface pressure by an amount equivto the hydrostatic pressure of the mud lubricated into the well.

If the surface pressure increased as the mud was lubricated into the well, the amthat the pressure increased should be bled back in addition.

Ensure that no significant quantity of mud is bled from the well during this operationmud appears at the choke before the surface pressure has been reduced to its dlevel, shut the well in and let the gas percolate through the mud.

Returns should be lined up through the mud gas separator to the trip tank to ensurany volume of mud bled back with the gas is recorded and accounted for.

4 Repeat this pr ocedure until all the influx has been vented fr om the well

This procedure should be repeated until all the gas has been vented from the well

It is likely that it will be necessary to reduce the volume of mud lubricated into the weleach stage during this procedure. This is due to the reduction in volume of gas in the wel

If the influx was swabbed into the well and the mud weight is sufficient to balance formationpressures, the choke pressure should eventually reduce to zero.

However, if the mud weight in the hole is insufficient, the final choke pressure will reflectthe degree of underbalance. It will then be necessary to kill the well.

5 Dynamic Volumetric Control

This technique can be used as an alternative to the Static Volumetric Method. However, itshould only be used only as a method of safely venting an influx from below a subsea sdue to both the complexity of the operation and the level of stress imposed on well coequipment during circulation.

Experience has shown that the Dynamic Volumetric Method is the most reliable method ofventing gas from a subsea stack, if the drillpipe cannot be used to monitor bottomhole pres

The principle of the procedure is identical to the Static Volumetric Control, however theimplementation is considerably different. In this case, circulation is maintained across thwellhead, whilst the surface pressure and pit gain are controlled with the choke. The kill linepressure is used to monitor the well.

It is very important that the active tank be a suitable size to resolve very small changlevel. It should be possible to reliably detect changes of the order of one barrel.

Having identified that the influx is at the stack, the following guidelines can be usedimplement the Dynamic Volumetric Method:

1 Ensure that the kill line is full of m ud

If there is any possibility that the kill line contains gas, the well should be isolated the kill line circulated to mud. This will ensure that the pressure at the stack is accuratemonitored during the operation.

by ansateore

gas

the

(as

static

the

tingsureoint,


2 Circulate do wn the kill line and up the c hoke line

Ensure that it is possible to monitor the active pit level accurately. Route returns throughthe mud gas separator.

3 Bring the pump up to speed

As the pump is brought up to speed, the kill line (or pump pressure) must increase amount equal to the kill line pressure loss. However if it is not possible to compenfor the choke line pressure loss, the kill line pressure will inevitably increase by mthan the kill line pressure loss.

The kill line circulating pressure will be monitored during the operation to remove from the well.

4 Reduce kill line pressure in line with dr op in pit le vel

As gas is bled from the well, the pit level will drop while the choke operator adjustschoke to maintain a constant kill line circulating pressure. This will result in mud beinglubricated into the well.

If the kill line circulating pressure is held constant as mud is lubricated into the wellgas is removed), the bottomhole pressure will increase. Therefore, as the pit leveldecreases, the kill line pressure should be reduced to account for the greater hydropressure in the annulus.

As an example:

Drop in pit level = 10 bblAnnulus = 8 1/2 in. X 5 in.Mud weight = 1.85 SG

Hydrostatic equivalent of mud =445.7 X 1.85 = 17.5 psi/bbl(72.25 – 25)

Therefore reduce kill line circulating pressure by 17.5 X 10 = 175 psi

This procedure should be continued until all the influx has been vented from belowstack. This will be indicated by a constant pit level.

If the well has been completely killed by removing gas from the stack, the final circulakill line pressure will be equal to the sum of the kill line pressure loss, the choke line presloss and the wide open choke pressure. If the well is not yet completely killed at this pthe final circulating kill line pressure will be greater than this value.

See Figure 6.16 for an example kill line pressure schedule for this technique.

6-48March 1995

.042


Figure 6.16 Dynamic Volumetric Method– used to remove gas from below a stack

ORIGINAL KILL LINE PRESSURE ONCE PUMP IS UP TO SPEED

SLOPE OF LINE =

GAS IS REMOVED FROM THE WELL, MUD IS LUBRICATED IN

(PIT GAIN TO ALLOW FOR GAS EXPANSION)

KIL

L L

INE

PR

ES

SU

RE

(p

si)

ORIGINAL PIT LEVEL ONCE PUMP IS UP TO SPEEDGAIN IN PIT LEVEL DROP IN PIT LEVEL

CHANGE IN PIT LEVEL (bbl)

HYDROSTATIC PRESSURE PER BARREL OF MUD

WEOX02

6-49March 1995

6-49/50



Subsection 2.2 STRIPPING

Paragraph Page

1 General 6-52

2 Monitoring Well Pressures and Fluid Volumes 6-52

3 Annular Stripping 6-56

4 Annular Stripping Procedure 6-57

5 Ram Combination Stripping 6-59

6 Ram Combination Stripping Procedure 6-61

7 Dynamic Stripping Procedure 6-67

Illustrations

6.17 A Guide to Interpretation of Surface Pressure Changesduring Stripping 6-54

6.18 The Effect of the Pipe/BHA Entering the Influx 6-55

6.19 Surge Dampener Fitted to the Closing Line of anAnnular BOP 6-57

6.20 Example Stripping Worksheet – showing effect ofmigration and BHA entering the influx 6-60

6.21 Surface BOP Stack Suitable for RamCombination Stripping 6-62

6.22 6-63to to6.25 Annular to Ram Stripping 6-66

6.26 Equipment Rig-up for Dynamic Stripping 6-68

6-51March 1995

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6-52March 1995

1 General

Stripping is a technique that can be used to move the drillstring through the BOP stawhen the well is under pressure. Stripping places high levels of stress on the BOPs andclosing unit, and requires a particularly high level of co-ordination within the drillcrew.

Company policy is that a contingency plan must be developed regarding stripping procedfor both Company operated rigs and rigs that are under a Company contract. This Section isintended to aid in the drawing up of this contingency plan and as such the following aproposed as the most important considerations:

• How to move the tool joint through the BOP.

• Wear on BOP elements and the control unit.

• The level of redundancy in the BOP and the control system.

• Wellbore pressures in relation to the maximum allowable pressure for equipment athe formation.

• The monitoring of pressure and fluid volumes.

• The organisation and supervision of the drillcrew.

• Controlling increases in wellbore pressure due to surge pressure.

• The condition of the drillpipe.(Drillpipe rubbers should be removed and any burrs smoothed out.)

• The possibility of sticking the pipe.

• The control of influx migration.

• Manufacturers’ information regarding minimum closing pressures for annular preventer(This information should be available at the rig site.)

• The procedure to be adopted in the event that the surface pressure approachesmaximum allowable as the pipe is stripped into the influx.

See Figure 5.2 in Chapter 5 for a decision analysis related to stripping operations.

2 Monitoring Well Pressures and Fluid Volumes

During stripping operations, a constant bottomhole pressure is maintained by carefucontrolling the surface pressure and the volume of mud bled from or pumped into the weThe equipment required for this operation is described in Chapter 1, ’Instrumentationand Control’.

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6-53March 1995

Accurate monitoring of the well is required for the following reasons:

(a) To compensate for the volume of pipe introduced into the hole

To avoid over pressuring the well, a volume of mud equal to the volume of pipe and tjoints (the volume of metal plus the capacity) introduced into the well, must be bled of.

Where possible, mud should not be bled from the well while the pipe is stripped in. Itrecommended that mud is bled from the well during each connection. This ensures thatthere is a clear indication at surface of the BHA entering the influx.

However it is recognised that there may be situations when it is impractical to blemud from the well at connections. Such situations include:

• If the surface pressures are close to maximum allowable prior to the strippioperation.

• If a high pressure water kick is taken. In these circumstances the effectivecompressibility of the fluid in the hole will be low and as such there may be a velarge pressure rise as pipe is stripped into the well.

• If the pipe has to be stripped out of the hole. In this case, there will be a tendencythe volume of metal removed from the well to be replaced by influx fluid.

In these circumstances it may be necessary to implement the dynamic stripping techni

(b) To compensate for influx migration.

To compensate for influx migration, it is necessary to bleed mud from the well. This isin addition to the volume of mud bled from the well when introducing the pipe into thhole. Normally, the required volume of mud will be very small in comparison to thevolume bled off to compensate for the introduction of pipe into the hole.

Influx migration is indicated by a gradual increase in surface pressure even though correct volume of mud is being bled from the well (however this may be due to tBHA entering the influx). It is confirmed by increasing surface pressure when the piis stationary (See Figure 6.17). Influx migration is controlled by implementing thVolumetric Method.

(c) To allow an increase in surface pressure as the BHA enters the influx.

When the BHA is run into the influx, the height of the influx will be considerablyincreased. This can cause a significant decrease in hydrostatic pressure in the annurequiring a greater surface pressure to maintain a constant bottomhole pressure Figure 6.18). A potential problem arises if this condition is undetected. The chokeoperator may continue to bleed mud from the well to maintain a constant surface pressand inadvertantly cause further influx into the wellbore. It is therefore important taccurately monitor the total volume of mud bled from the well.

It is recommended that the potential increase in surface pressure resulting from entethe influx should be estimated before stripping into the hole.


6-54March 1995

Figure 6.17 A Guide to Interpretation of Surface PressureChanges during Stripping

START STRIPPING IN

PRESSURE INCREASES AS PIPE

IS STRIPPED IN

CONTINUE STRIPPING

BLEED VOLUME OF MUD EQUAL TO

VOLUME OF PIPE STRIPPED

SURFACE PRESSURE DROPS TO

ORIGINAL VALUE?

CONTINUE STRIPPING

IS THE PIPE ON BOTTOM?

KILL THE WELL

CONTINUE STRIPPING

SURFACE PRESSURE DROPS TO

VALUE GREATER THAN ORIGINAL

SURFACE PRESSURE INCREASES

WHILE PIPE IS STATIONARY?

INFLUX IS MIGRATING

BLEED MUD TO COMPENSATE FOR

MIGRATION

PIPE HAS ENTERED INFLUX

HAS THE CORRECT VOLUME OF

MUD BEEN BLED FROM THE WELL?

SURFACE PRESSURE LIMIT APPROACHED?

CIRCULATE OUT TOP OF GAS BUBBLE

USING THE DRILLER'S METHOD

YES

NO NO

YES

YESYES

NO

NOYES

NO

WEOX02.043


6-55March 1995

Figure 6.18 The Eff ect of the Pipe/BHA Entering the Influx

MUD

��

GAS

KEY

��

GAS INFLUX

1. Start stripping

WEOX02.044

2. BHA has entered influx Height of influx in annulus has increased Overall hydrostatic in annulus decreases Surface pressure required to balance formation pressure increases

•

•

•

MUD ��

GAS INFLUX

MUD

risk

igh

g ram

ole by

ct

ore

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6-56March 1995

3 Annular Stripping

There are two stripping techniques, Annular and Ram combination stripping. The decisionanalysis presented in Chapter 5, ‘Pipe off Bottom – Drillpipe in the Stack’ outlines thebasis upon which the most suitable stripping technique is selected.

Annular stripping is considered to be the most satisfactory technique. It involves lessthan ram combination stripping for the following reasons:

• Annular stripping is a relatively simple technique.

• During annular stripping the only item of well control equipment that is subject to hlevels of stress is the annular element.

• The control system is not highly stressed during the operation (as is the case durincombination stripping).

• The annular element can be changed out on a surface stack when pipe is in the hinserting a split element.

• The upper annular preventer, on a floating rig, is the only stack component that is subjeto wear and this can be changed without pulling the complete BOP stack.

Ram combination stripping is possible on all types of rig but involves significantly mrisk when implemented on a floating rig.

The surface pressure is the overriding factor which determines whether or not it wipossible to implement annular stripping. However, it is also necessary to consider that thoperating life of an annular element is severely reduced by increased wellbore presField tests* carried out on Hydril and Shaffer 5K Annulars, show good performance at 800psi wellbore pressure, but at 1500 psi and above the performance was severely reducunpredictable.

If surface pressures indicate that annular stripping is not possible, attempts should beto reduce the pressures in order to enable annular stripping to be used. The most appropriatetechnique will depend on the position of the influx in the hole. The options are; to circulateout the influx, to lubricate the influx from the well or to bullhead.

To ensure that the annular is not subjected to excessive pressures as the tool joint is sthrough the element, a surge dampener must be placed in the closing line (See Figure 6.1This may not be necessary on a surface stack if the pressure regulator can responenough to maintain a constant closing pressure as a tool joint is stripped through the an.

As a word of caution, some drilling contractors have installed check valves in the conlines to the BOPs; the purpose being to ensure that the BOP stays closed if the hydsupply is lost. However, if a check valve is installed in the closing line to an annular BOP, itwill not be possible to reduce the closing pressure once the annular has been closorder to reduce the annular closing pressure, in this case, it will be necessary to opeannular having closed another ram to secure the well.

* Tests carried out by Exxon Prod. Research 1977.

the

der


6-57March 1995

Figure 6.19 Surge Dampener Fitted to the Closing Line ofan Ann ular BOP

4 Annular Stripping Procedure

Having shut in the well, the following procedure can be used as a guideline for implementation of annular stripping.

1 Install drillpipe dar t

Allow the dart to fall until it seats in the dart sub. To check that the dart is functioningproperly, bleed off pressure at the drillpipe (restrict volumes bled off to an absoluteminimum, typically 1/2 – 1 bbl).

If the dart does not hold pressure allow more time for the dart to drop or consicirculating the dart into place (restrict volumes pumped to a minimum).

If the dart still does not hold pressure, install a Gray valve in the string.

��

��

��

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��

��

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of required closing pressure)

CLOSING LINE

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6-58March 1995

2 Monitor surface pressures

Surface pressures should be monitored after the well has been shut-in to check for inmigration. If the influx is migrating it will be necessary to implement volumetric controduring the stripping operation.

If the pipe is off bottom, it will not be possible to identify the type of influx in the usuamanner. However, a high surface pressure caused by a relatively small underbalanusually indicates that the influx contains a significant quantity of gas.

3 Determine the capacity and displacement of the drillpipe

It will be necessary to bleed mud from the well to compensate for the volume of pintroduced into the hole.

This volume is equal to the sum of the capacity and the displacement of the pipe. Thereare various tables which outline these quantities, but a reasonable estimation camade as follows:

Displacement and capacity = do2 X 0.003187 (bbl/m)

where do = outer diameter of the pipe (in.)

Allowance should also be made for the extra volume of metal in the tool joints.

4 Calculate h ydr ostatic pressure per barrel of m ud

Should migration occur, it will be necessary to bleed from the well at constant chokpressure to allow the influx to expand. The hydrostatic pressure equivalent of the mudin the hole is calculated as follows:

Hydrostatic pressure equivalent =445.7 X MW (psi/bbl)(dhc2 – do2)

where MW = mud weight in the hole (SG)dhc = hole/casing ID (in.)do = drillstring OD (in.)

or if the pipe is above the influx:

Hydrostatic pressure equivalent =445.7 X MW (psi/bbl)dhc2

For more details on this technique, See Sub-section 2.1 ‘Volumetric Method’ in thischapter.

5 Estimate increase in surface pressure due to BHA entering the influx

It is possible to estimate the maximum possible pressure increase due to the BHA entthe influx as follows:

Max possible surface = 445.7 X (MW – Gi) X V X 1 – 1 (psi)pressure increase (dhc

2 – do2) dhc

2

where MW = mud weight in the hole (SG)Gi = influx gradient, converted to SG (water = 1 SG)V = volume of influx (bbl)dhc = hole/casing ID (in.)do = BHA OD (in.)

tion.

start

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6-59March 1995

6 Allo w surface pressure to increase b y overbalance mar gin

An overbalance of 50 to 200 psi should be maintained throughout the stripping opera

If the influx is not migrating, the overbalance margin can be applied by bleeding avolume of mud that is less than the volume of pipe introduced into the hole, at the of the operation.

7 Reduce ann ular c losing pressure

The BOP manufacturers recommend that the closing pressure is reduced, pristripping, until a slight leakage occurs through the BOP. This reduces the wear on theannular by lubricating the element during stripping.

8 Strip in the hole

The pipe should be slowly lowered through the annular while the surface pressuaccurately monitored. The running speed should be reduced when a tool joint pasthrough the annular.

Mud should be bled from the well at each connection, unless surface pressure limitadictate that this should be carried out more frequently.

The pipe should be filled with mud at suitable intervals, typically every 5 stands. Uoriginal mud weight.

A person should be posted at the Driller’s BOP Control Panel at all times to be ready toshut-in the well in the event of failure of the annular preventer.

9 Monitor surface pressure

Surface pressures and all relevant data should be recorded on the Stripping Worksheet.(See Figure 6.20.) Use Figure 6.17 as an aid to the interpretation of changes in supressure.

10 Strip to bottom. Kill the well

The only sure method of killing the well will be to return the string to bottom aimplement standard well kill techniques.

5 Ram Combination Stripping

There are two types of ram combination stripping; annular to ram, and ram to ram. techniques must be considered if either the tool joint cannot be lowered through the anor the surface pressure is greater than the rated pressure of the annular and this prcannot be reduced to within safe limits.

Annular to ram stripping is preferable to ram to ram, unless surface pressures indicatthe annular cannot operate reliably.

For both ram combination techniques there is a requirement that:

• There is sufficient space for the tool joint between the two stripping BOPs.


6-60March 1995

Figure 6.20 Example Stripping Worksheet– showing effect of migration and BHA

entering the influx

STRIPPING WORKSHEETFor worksheet calculation enter information in shaded cells.

Units (US/UK) ukVersion 1/1 1Q'95 by ODL/C. Weddle

WELL NO 3 RIG Rig 10 DATE AND TIME 10/7/87 10:30 SHEET NO 1

MUD WEIGHT IN HOLE 1.75 LUBRICATING MUD WEIGHT 1.75

INITIAL BIT DEPTH 2000 HOLE DEPTH 2250

STRIPPING DATA

VOLUME OF MUD DISPLACED BY 5 Inch Pipe Drillpipe 0.0797 bbl/m : 2.15 bbl/stand

OVERBALANCE MARGIN 120 psi OPERATING MARGIN 150 psi (Max)

VOLUMETRIC CONTROL DATA

HYDROSTATIC PRESSURE PER BARREL OF 1.75 SG MUD IN 5 x 8.5 ANNULUS 16.52 psi/bbl

HYDROSTATIC PRESSURE PER BARREL OF 1.75 SG MUD IN 6.5 x 8.5 ANNULUS 26.01 psi/bbl

HYDROSTATIC PRESSURE PER BARREL OF 1.75 SG MUD IN 8.5 HOLE 10.80 psi/bbl

HYDROSTATIC PRESSURE PER BARREL OF 1.75 SG MUD IN 8.75 HOLE 10.80 psi/bbl

TIME OPERATION Choke or Dp Change in Bit Pipe Stripped Hydrostatic Over- Volume of Total

Choke Monitor Depth of Mud Bled/ balance Mud Bled/ Volume

Monitor Pressure Lubricated Lubricated of Mud

Pressure

( hr min) (psi) (psi) ( ) ( ) bbl (psi) (psi) (bbl) (bbl)

10:05 Well Shut In-Pressures 550 2000 N/A

Stabilized

10:20 Drillpipe Dart Installed 2000

10:30 Strip in Stand No 1 770 120 2027 27 2.2 N/A 120 0 0.0


10:40 Bleed Mud at Connection 770 -120 2054 54 4.4 N/A 120 2.2 2.2






(Assume BHA has entered flux)


11:10 Strip in Stand No6 1080 250 2162 162 13.2 N/A 240 0 8.8








- ve bled +ve + ve bled

+ve increase +ve lubricated overbalance

M M -ve lubricated

-ve decrease NA if bled to - ve

compensate underbalance

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6-61March 1995

• There is an inlet at the stack between the two BOPs used for stripping.

• There is a suitable level of redundancy in the stack to ensure the lowest BOP is noduring the stripping operation.

API RP 53 (issued 1984) states:

“The lowermost ram should not be employed in the stripping operation. This ram shouldbe reserved as a means of shutting in the well if other stack components of the blopreventer fail. It should not be subjected to the wear and stress of the stripping opera

In a critical situation, it may be possible to modify a surface stack to suit these condiafter a kick has been taken. An example surface stack that is suitable for ram combinatstripping is shown in Figure 6.21.

The risks involved in ram combination stripping can be assessed by considering the follopoints:

• The high level of drillcrew co-ordination required.

• The level of stress placed on the BOP elements.

• The level of stress placed on the BOP control system.

(During ram combination stripping, the accumulators are charged to maximum operatingpressure and isolated from the BOP. The pumps are used for operational functions.)

• The possibility of replacing the worn BOP elements during operation.

• On a floating rig, the reduction in level of redundancy within the subsea BOP stacthe ram preventer is used.

6 Ram Combination Stripping Procedure

The following procedure can be used as a guideline for the implementation of annuram stripping. The procedure for ram to ram stripping will be similar.

(For details of Steps 1 to 6 See ‘Annular Stripping Procedure’)




4 Calculate h ydr ostatic pressure per barrel of the m ud

5 Estimate the increase in surface pressure due to the BHA entering the influx

6 Check ram spaceout

To confirm the distance BRT of the two preventers that will be used for stripping.


6-62March 1995

Figure 6.21 Surface BOP Stac k Suitab le forRam Combination Stripping

PIPE RAM

BLIND RAM

ANNULAR

FLANGED ACCESS POINT TO STACK FOR USE DURING RAM COMBINATION STRIPPING

WELLHEAD ACCESS POINT

WEOX02.046

PIPE RAM


6-63March 1995

Figure 6.22 Annular to Ram Stripping– stop stripping in when tool joint is above

the annular

PIPE RAM

ANNULAR

BLIND RAM

PIPE RAM

TO PUMP CHOKE

MUD

VALVE OPEN

VALVE CLOSED

WEOX02.047


6-64March 1995

Figure 6.23 Ann ular to Ram Stripping– close pipe ram– bleed ram cavity pressure

PIPE RAM

ANNULAR

BLIND RAM

PIPE RAM

PRESSURE BLED OFF AT CHOKE

MUD

VALVE OPEN

VALVE CLOSED

WEOX02.048


6-65March 1995

Figure 6.24 Annular to Ram Stripping– strip in until tool joint is just below annular

PIPE RAM

ANNULAR

BLIND RAM

PIPE RAM

MUD

VALVE OPEN

VALVE CLOSED

WEOX02.049


6-66March 1995

Figure 6.25 Annular to Ram Stripping– use rig pump or cement pump to

equalize across pipe ram

PIPE RAM

ANNULAR

BLIND RAM

PIPE RAM

MUD

VALVE OPEN

VALVE CLOSED

FROM PUMP

WEOX02.050

low it.

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trippedchokee 6.26.

the lowessuressure


6-67March 1995

7 Isolate the accum ulator bottles at full operating pressure

The accumulators should be kept as back-up in the event of pump failure.

8 Allo w the surface pressure to increase b y the o verbalance mar gin

9 Reduce ann ular c losing pressure and strip in

10 Stop when tool joint is abo ve ann ular (See Figure 6.22.)

11 Close pipe ram at normal regulated manif old pressure

12 Bleed ram ca vity pressure

Before the annular is opened it will be necessary to bleed down the pressure be(See Figure 6.23).

13 Reduce ram operating pressure

14 Open ann ular . Lo wer pipe

15 Stop when tool joint is just belo w ann ular (See Figure 6.24.)

16 Close ann ular at maxim um operating pressure

17 Pressurise ram ca vity to equalise acr oss ram (See Figure 6.25.)

Do not use wellbore pressure to equalise across the ram.


19 Open pipe ram

20 Contin ue to strip in accor ding to the abo ve pr ocedure . Kill the well

Fill the pipe as required.

7 Dynamic Stripping Procedure

The situations in which it may be necessary to implement Dynamic Stripping are ouin Paragraph 2.

The purpose of this technique is to maintain constant choke pressure as the pipe is sinto the hole. This is achieved by circulating at a constant rate across the end of the line. A manual choke should be used and the equipment rigged up as shown in Figur

For this technique to be effective the pump output must be considerably greater thanrate at which the volume of pipe is introduced into the well. If the pump rate is too,pressure surges will be caused at the choke as the pipe is stripped in, and the choke prwill fluctuate. The same is true for stripping out of the hole, in which case the choke premay drop as pipe is stripped from the well, if the pump rate is too low. This may causefurther influx to occur.


6-68March 1995

Figure 6.26 Equipment Rig-up for Dynamic Stripping

PIPE RAM

ANNULAR

BLIND RAM

PIPE RAM

MUD

VALVE OPEN

VALVE CLOSED

MANUAL CHOKE

MUD TANK

PUMP

MONITOR PRESSURE

GAUGE

WEOX02.051

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6-69March 1995

The main problem associated with this technique is that migration and entrance into thbubble may not easily be detected at surface. If no allowance is made for these complicafurther influx may be allowed to occur. To avoid this, the mud tank levels should be closelmonitored to ensure that the levels rise, or drop, in direct relation to the volume of pipehas been stripped into, or out of, the well. If any discrepancy is noticed, the well shoulshut-in and the surface pressures verified. Influx migration should be dealt with usingVolumetric Method.

The Dynamic Stripping technique can be used during either annular or ram combinastripping. For annular stripping it is implemented along the following lines:

(For details of Steps 1 to 6, See Paragraph 4 ‘Annular Stripping Procedure’)




4 Calculate h ydr ostatic pressure per barrel of the m ud

5 Estimate the increase in surface pressure due to the BHA entering the influx

6 Allo w the surface pressure to increase b y the o verbalance mar gin

7 Line up the pump to the c hoke line (See Figure 6.26.)

8 Ensure that the man ual c hoke is full y c losed. Open c hoke line v alve(s)

9 Open the man ual c hoke at the same time as the pump is br ought up tospeed

10 Maintain final shut-in pressure on the c hoke


12 Strip in the hole

13 Monitor surface pressures and pit le vel

If the choke pressure increases significantly as the pipe is stripped into the hole, ereduce the pipe running speed or increase the circulation rate.

Use the Stripping Worksheet to record all the relevant data. It is very important accurately record pressures and mud volumes while stripping.

14 Strip to bottom. Kill the well

Fill the pipe as required.

1-69/70



Subsection 2.3 BULLHEADING

Paragraph Page

1 General 6-72

2 When to Bullhead 6-72

3 The Important Factors 6-72

4 Procedure 6-73

Illustrations

6.27 Well Shut-in after Production– tubing full of gas prior to bullheading 6-74

6.28 Example Guide to Surface Pressures duringa Bullheading Operation 6-75

6.29 Well during Bullheading Operations 6-76

6.30 Well after Bullheading Operations tubing displacedto kill weight brine 6-77

6-71March 1995

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6-72March 1995

1 General

Bullheading is a technique that may be used in certain circumstances during droperations to pump an influx back into the formation.

This technique may or may not result in fracturing the formation.

Bullheading is however a relatively common method of killing a well during workovoperations. This technique is generally used only during workover operations when theadequate reservoir permeability.

2 When to Bullhead

During operations, bullheading may be considered in the following situations:

• When a very large influx has been taken.

• When displacement of the influx by conventional methods may cause excessive supressures.

• When displacement of the influx by conventional methods would result in an excesvolume of gas at surface conditions.

• If the influx in suspected to contain an unacceptable level of H2S.

• When a kick is taken with the pipe off bottom and it is not considered feasible to strback to bottom.

• When an influx is taken with no pipe in the hole.

• To reduce surface pressures prior to implementing further well control operations

3 The Important Factors

Bullheading during drilling operations will be implemented when standard well contechniques are considered inappropriate. During such situations, it is unlikely that accinformation is available regarding the feasibility of bullheading. In most cases therethe likelihood of successfully bullheading an influx will not be known until it is attempt

However, the major factors that will determine the feasibility of bullheading include the followi

• The characteristics of the openhole.

• The rated pressure of the well control equipment and the casing (making allowancwear and deterioration).

• The type of influx and the relative permeability of the formation.

• The quality of the filter cake at the permeable formation.

• The consequences of fracturing a section of the openhole.

• The position of the influx in the hole.

larred

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ility

SG


6-73March 1995

4 Procedure

In general bullheading procedures can only be drawn up bearing in mind the particucircumstances at the rigsite. For example there may be situations in which it is considenecessary to cause a fracture downhole to bullhead away an influx containing H2S. In anothersituation with shallow casing set, it may be considered totally unacceptable to cause a fracin the openhole.

During a workover operation a procedure for bullheading will be drawn up along tfollowing lines:

1 Calculate surface pressures that will cause f ormation fracture duringbullheading

Calculate also the tubing burst pressures as well as casing burst (to cover the possibof tubing failure during the operation).

2 Calculate static tubing head pressure during b ullheading

3 Slowly pump kill fluid do wn the tubing. Monitor pump and casing pressureduring the operation

As an example consider the following well (See Figure 6.27).

Well information: Depth of formation/perforations at 3100 mFormation pressure = 1.06 SGFormation fracture pressure = 1.66 SGTubing 4 1/2 in. N80 Vam Internal capacity = 0.0499 bbl/m

Internal yield = 8430 psiShut-in tubing pressure = 3650 psiGas density = 0.1 psi/ft

• Total internal volume of tubing

= 3100 X 0.0499 (bbl)

= 155 bbl

• Maximum allowable pressure at pump start up

= (1.66 X 3100 X 1.421) – (0.1 X 3.2808 X 3100) (psi)

= 6300 psi

• Maximum allowable pressure when the tubing has been displaced to brine at 1.06

= (1.66 – 1.06) X 3100 X 1.421 (psi)

= 2640 psi


6-74March 1995

Figure 6.27 Well Shut-in after Pr oduction– tubing full of gas prior to bullheading

��

BRINE

��GAS

VALVE OPEN

VALVE CLOSED

KEY

3650 psi

��

WEOX02.052

4 1/2in N80 TUBING

PERFORATIONS @ 3100m FORMATION PRESSURE FORMATION FRACTURE GRADIENT

1.06SG 1.66SG

––––––

PACKER

matic


6-75March 1995

• Static tubing head pressure at initial shut-in.

= 3650 psi

• Static tubing head pressure when tubing has been displaced to brine

= 0 psi (ie the tubing should be killed)

The above values can be represented graphically (as shown in Figure 6.28). This plot can beused as a guide during the bullheading operation. Figures 6.29 and 6.30 show a scheof the well at two stages of the operation.

Figure 6.28 Example Guide to Surface Pressures duringa Bullheading Operation

10000

9000

8430

6300

5800

8000

7000

5000

40003650

3000

2000

1000

0

10000

9000

6000

8000

7000

5000

4000

2640

2140

1000

00 10 20 30 40 50 60 70 80 90 100 110 120 130 140 155

TUBING BURST

WEOX02.053

VOLUME OF TUBING DISPLACED (bbl)

SU

RFA

CE

PR

ES

SU

RE

(p

si)

STATIC TUBING PRESSURE THAT WOULD FRACTURE FORMATION

INCLUDING 500psi SAFETY FACTOR (if fracturing is a consideration)

STATIC TUBING PRESSURE TO BALANCE FORMATION PRESSURE

WORKING PRESSURE RANGE DURING BULLHEADING OPERATION


6-76March 1995

Figure 6.29 Well during Bullheading Operations

��

BRINE

��GAS

VALVE OPEN

VALVE CLOSED

KEY

60bbl OF THE TUBING DISPLACED (FROM FIG 6.28, TUBING PRESSURE WITHIN ACCEPTABLE LIMITS)

4000psi

BULLHEAD BRINE

��

WEOX02.054

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PERFORATIONS

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6-77March 1995

Figure 6.30 Well after Bullheading Operations– tubing displaced to kill weight brine

1-77/78

��

BRINE

��GAS

VALVE OPEN

VALVE CLOSED

KEY

0psi

WEOX02.055

4 1/2in N80 TUBING

PERFORATIONS

PACKER

GAS TRAPPED UNDER PACKER



Subsection 2.4 SNUBBING

Paragraph Page

1 General 6-80

2 Snubbing Units 6-80

3 Selection of a Snubbing Unit 6-82

Illustrations

6.31 Rig Assisted Snubbing Unit 6-81

6.32 Concentric Cylinder Snubbing Unit 6-83

6.33 Multicylinder Snubbing Unit 6-84

6.34 Force Diagram for Snubbing Pipe 6-85

6-79March 1995

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6-80March 1995

1 General

Snubbing is a technique used to force pipe into a shut-in well when the upthrust due topressure makes it impossible to strip the pipe through the BOP under its own weight.

Snubbing is relatively common in some areas in workover operations, when the wellbe allowed to continue flowing as remedial work is carried out.

Snubbing may be considered during drilling operations for well control purposes, ewhen it is impossible to introduce pipe into a well that is under pressure, or if the rig system is not considered adequate to provide reliable pressure containment during a prostripping operation.

A snubbing unit can be used to introduce a range of sizes of pipe into the well. It caused to snub tubing, drillpipe and even casing in exceptional circumstances.

The lowermost components of the snubbing unit are the snubbing BOPs, which are mato the top flange of the annular preventer on the rig’s stack. This flange is often poorlymaintained because it is normally made up to the bell nipple and does not generally nform a pressure seal. It must therefore be inspected and, if necessary, repaired before thesnubbing BOPs are nippled up.

The snubbing BOPs are likely to be too tall to fit underneath the rotary table and too wigo through it. To overcome this problem, the snubbing company can provide suitable spriser sections to bring the assembly above the rig floor.

The weight of the snubbing unit is supported by the wellhead. Guy lines from the wplatform prevent lateral movement.

Snubbing units can therefore be rigged up on land rigs and fixed offshore installations in arelatively straightforward manner. Snubbing units are not commonly used on floating righowever they have been used successfully in the past for well control operations.

In order to use a snubbing unit on a floating rig, pressure containment must be estabbetween the rig BOP and the unit on the rig floor. Drillpipe or tubing may provide thispressure containment, in which case small diameter tubing may be run into the well thrthe drillpipe or tubing. An operation of this type can only be carried out in relatively caseas so that the rig heave does not cause excessive movement of the snubbing unit.

2 Snubbing Units

(a) The Rig Assisted Type

The rig assisted unit uses the travelling blocks to generate the snubbing force throseries of pulleys and cables. (See Figure 6.31.) The rig assisted unit can handle largerdiameter pipes such as casing up to 13 3/8 in. and have snubbing capacities of 80,to 400,000 lb.

These were the first snubbing units used and the few that are currently availabloperated by Otis and Cudd Pressure Control.


6-81March 1995

Figure 6.31 Rig Assisted Sn ubbing Unit

TRAVELLING BLOCK

BALANCE WEIGHT

TRAVELLING SNUBBERS

SNUB LINE

STATIONARY SNUBBERS

PLATFORM

PUMP INLET

STRIPPING OR SNUBBING PREVENTERS

SAFETY PREVENTERS

WELL PRESSURE

WEOX02.056

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6-82March 1995

The unit consists of a set of travelling snubbers which are connected to the travelling bThe travelling snubbers grip the pipe and force it into the well as the blocks are raise

A set of stationary snubbers grip the pipe while the travelling snubbers are being raisethe counter balance weights) for a new bite on the pipe.

Once sufficient pipe has been run to reach the balance point, the travelling snubbers wremoved and the pipe will be run in by conventional stripping.

(b) The Hydraulic Self Contained Type

Hydraulic snubbing units are the most common type available. They are completely selfcontained and can be used either inside the derrick or when there is no rig on loc

There are two different types of hydraulic unit available, these being:

• The concentric cylinder unit (See Figure 6.32) for snubbing capacities up to 30lb and for pipe up to 5 1/2 in. OD.

• The multicylinder type (See Figure 6.33) for snubbing capacity up to 150,000 lbfor pipe up to 7 5/8 in. OD.

The units are operated from the work platform which is on top of the hydraulic assembly. From this position the speed of the pipe and the slips are controlled as cthe rotary table, if required.

Stationary and travelling slips are operated in sequence to grip the pipe as it is sninto the well.

One operator will control the BOPs and equalising valves. Another operator willco-ordinate the pipe handling, using the counter balance system.

3 Selection of a Snubbing Unit

The following are the criteria that should be used to determine the most suitable unitgiven application:

• Snubbing Force

This is the force that the unit must exert to push the pipe into the hole. The snubbingforce will be a maximum for the first joint of pipe and decrease gradually as the weof the pipe in the hole increases in normal conditions.


6-83March 1995

Figure 6.32 Concentric Cylinder Sn ubbing Unit

TRAVELLING SLIPS (CLOSED)

WORKBASKET WITH CONTROLS

PISTON

ACCESS WINDOW

SNUBBING UNIT BLOWOUT PREVENTER STACK

STATIONARY SLIPS (OPEN)

STATIONARY SLIPS (CLOSED)

TRAVELLING SLIPS (OPEN)

STATIONARY SLIPS (OPEN)

PISTON EXTENDED AND TRAVELLING SLIPS CLOSED PRIOR TO FORCING

PIPE INTO WELL

PISTON RETRACTED AND TRAVELLING SLIPS OPEN BEFORE PISTON IS

AGAIN EXTENDED WEOX02.057

HYDRAULIC CONTROL FLUID

WELL PRESSURE

KEY


6-84March 1995

Figure 6.33 Multic ylinder Sn ubbing Unit

POWER TONGS

BOP CONTROL PANEL

CONTROL PANEL

WORK PLATFORM

TRAVELLING SLIPS

COUNTERBALANCE WINCH

TELESCOPING MAST

FOUR OPERATING CYLINDERS

STATIONARY SLIPS

WINDOW – for stripper bowl or annular BOP

SPOOL

HANGER FLANGE

SNUBBING UNIT BLOWOUT PREVENTER

STACK

PUMP INLET

WEOX02.058


6-85March 1995

The snubbing force is calculated as follows:

– Snubbing force, Fs = Fp + Ff – (wa – Ly X 3.281) – (wb X Lz X 3.281)

where Fp = Pw – Ao

(See Figure 6.34)

where Fs = required snubbing force (lb)Fp = force due to well pressure (lb)Ff = frictional force (lb)wa = weight of pipe (lb/ft)wb = buoyant weight of pipe (lb/ft)Ly = length of pipe above BOP to the travelling snubber (m)Lz = length of pipe in the hole (m)Ao = outside cross sectional area of pipe (in.2)

Figure 6.34 Force Diagram for Snubbing Pipe

Fs

COMPRESSION FORCE

Fs

Ff

Ff(wa)(Ly)

Ly

LzPw

FpFp

(wb)(Lz)

wa

wb

POINT OF APPLICATION

OF TRAVELLING SNUBBERS

SNUBBING BOP

WELLBORE

WEOX02.059

Equilibrium Equation (from ∑ Forces = 0)

Therefore: Fs = Fp + Ff – (wa) (Ly) – (wb) (Lz)

Where Fs Fp Ff wa wb Ly Lz

= required snubbing force (lb) = force due to well pressure (lb) = frictional force (lb) = weight of pipe (lb ft) = bouyant weight of pipe (lb ft) = length of pipe above BOP to the travelling snubber (m) = length of pipe in the hole (m)

PIPE(SNUBBING UNIT STROKE)

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6-86March 1995

– Snubbing force for the first joint of pipe.

In this case, the length of pipe in the hole (Lz) is zero, and the length of pipe athe BOP is considered insignificant. Consider the following example:

The well is shut in with a wellhead pressure of 5000 psi. 2 7/8 in. tubing producfrictional force of 3000 lb at the stripping rams. The area of pipe exposed to thewellbore pressure therefore equals 6.492 in.

Snubbing force, Fs = Fp + Ff

= (6.492 X 5000) + 3000 (lb)

= 35,460 lb

– The snubbing force, Fs, if there is already some pipe in the hole.

In this case the length of the pipe above the BOP is again considered insignifiAs an example:

2 7/8 in. tubing of 6.5 lb/ft is run empty to 1000 metres in 1.2 SG mud. The wellheadpressure is 5000 psi. Drag in the hole is 2000 lb, friction at the BOPs is 5000 l

Ai = internal cross sectional area area of pipe (in.2)Ao = outside cross sectional area area of pipe (in.2)wi = weight of fluid inside the pipe (SG)wo = weight of fluid in annulus (SG)wa = weight of pipe in air (lb/ft)wb = buoyant weight of pipe (lb/ft)D = depth of tubing (m)

wb = wa + (wi X Ai) – (wo X Ao)

wb = 6.5 + (O X Ai) – (1.2 X 62.4 X 6.492) (lb/ft)144

wb = 3.12 lb/ft

Therefore the snubbing force is given by:

Fs = Fp + Ff – (wa X Ly) – (wb X Lz)

Fs = (6.492 X 5000) + 2000 + 5000 – (3.12 X 1000 X 3.281) (lb)

= 29,200 lb

• Size of the Unit

The dimensions of the unit must be checked against the internal dimensions of the deif the unit is to be used with a rig on location.

• Lifting Force

The unit must be able to provide a reasonable overpull, over and above the weigthe maximum string weight.

to

in.

ding

for

to


• Tubular Selection

If there is already pipe in the hole, this will determine the most suitable type of pipebe used.

Drillpipe can be used, however the following points should be considered:

– Drillpipe will require a relatively high snubbing force because of its large cross-sectional area at the tool joints.

– Drillpipe does not have gas-tight connections.

– The drillpipe must be in good condition and inspected thoroughly before running

Tubing is more commonly used for snubbing for the following reasons:

– The force required to snub it in is very much less, and the unit required corresponsmaller.

– External flush tubing can be run through the stripper rubbers without the needsequencing the rams.

The following points must also be considered:

– The limitations imposed by the ID of the tubing on the maximum pump rate.

– External upset tubing will be slower to run, but will be easier to control, if it startsbe forced out of the well.

– Premium connections are desirable because they are gas tight.

– The collapse strength of the tubing.

– The susceptibility of the tubing to failure due to buckling.

6-87March 1995

1-87/88



Subsection 2.5 BARYTE PLUGS

Paragraph Page

1 Characteristics of Baryte Plugs 6-90

2 Deflocculation 6-92

3 Pilot Tests 6-92

4 Slurry Volume 6-92

5 Pumping and Displacement Rate 6-93

6 Preparation of a Baryte Plug 6-93

7 After Pumping a Baryte Plug 6-93

8 Baryte Plug Procedure 6-94

Illustrations

6.35 Field Mixing of Baryte Plugs 6-91

6-89March 1995

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houldarytenatebs or

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6-90March 1995

1 Characteristics of Baryte Plugs

(a) Hydrostatic Kill

Since baryte settling is inherently slow and since the results of settling are qunpredictable, the use of a settling recipe should not be a dominant factor in desia well control operation. In general, the goal in using a baryte kill slurry should besame as with any other kill weight mud – achieving a hydrostatic kill.

Three factors contribute to achieving a hydrostatic kill: the density of the fluid, thevolume of the fluid, and the rate at which the fluid is pumped. The density and volumeof the kill weight mud must be high enough to control the formation, and the pumpduring the kill must exceed the influx rate by sufficient margin so that the kill weightmud is not blown out of the wellbore. The properties of the fluid pumped should bchosen with these three factors in mind. The ideal kill weight mud would be inexpensivand simple to mix and handle over a wide range of densities. Deflocculated baryte slfit this description except that the settling of the baryte can be a problem in suhandling and pumping.

(b) Bridging effect

It has been suggested that a baryte plug can stop unwanted flow by a bridging effect andthat achieving a hydrostatic kill is not necessary. Some field experiences support thiview; there are cases where a well has stopped flowing after being treated with abaryte plug. Nonetheless, it is imprudent to rely on baryte bridging when attemptinkill a well.

Laboratory tests show clearly that even very low gas volumes (0.01 Mcf/d at bottomconditions) can flow through a settling baryte plug. This fact, as well as field experienceshows that the bridging action of a baryte plug is not dependable. For this reasodesign of a baryte plug should be based on achieving a hydrostatic kill.

The strength of the settled baryte is another significant factor in well control. Laboratests show that the strength of a settled baryte plug is quite variable. Settled baryappear rock-solid when pushed hard and yet move slowly out of the way of a persgently force. This behaviour is actually a well understood property of deflocculacakes. A baryte plug can fail unexpectedly if a hydrostatic kill condition is not maintain

(c) Settling/Non-settling

Since baryte settling is of little value downhole and troublesome on the surface, it sbe an optional feature of the slurry recipe. Figure 6.35 shows two recipes for bslurries. The recipes are identical except that one contains XC polymer to elimibaryte settling. It would seem reasonable to use the settling recipe for small jowhere the settling baryte might really be helpful downhole. For large kill operations,the non-settling recipe would be preferred.

Bentonite or some polymer other than XC could be used to suspend the baryteslurry. The particular recipe in Figure 6.35 was selected because it is prepared eaboth fresh and seawater and because XC solutions are shear-thinning enough to allowgood pumpability while adequately suspending the baryte in the pits.


6-91March 1995

Figure 6.35 Field Mixing of Bar yte Plugs

(a) For use with water based muds

1. Prepare mix water equal to 54 per cent of final v olume of slurr y required.Recipes belo w are f or one barrel of mix water:

• Setting recipe

1 bbl water (fresh or sea)15 lb lignosulphonate2 lb/bbl of caustic (pH = 10.5 to 11.5)

• Non-setting recipe

1 bbl water (fresh or sea)15 lb lignosulphonate1 lb XC polymerDefoamer (octanol or other)2 lb/bbl of caustic (pH = 10.5 to 11.5)

2. Ad d bar yte to mix water to prepare final slurr y.

For 1 bbl of 2.5 SG slurry, mix

0.54 bbl mix water700 lb baryte

(b) For use with oil based muds

1. Prepare mix oil equal to 47 per cent of final v olume of slurr y required.Recipes belo w are f or one barrel of mix oil:

• Setting recipe

1 bbl base oil1.5 US gal oil wetting agent

• Non-setting recipe

1 bbl base oil4 lb organophilic clay1.5 US gal oil wetting agent

2. Ad d bar yte to mix oil to prepare final slurr y.

For 1 bbl of 2.5 SG slurry, mix

0.54 bbl mix water700 lb baryte

e nowthat, inossible

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6-92March 1995

Baryte-plug-type slurries can be prepared with all of the baryte substitutes which aron the market. In general the recipes in Figure 6.35 do not require change except some cases, the higher density of the substitue allows higher slurry weights than were pwith baryte. For example, hematite slurries can be prepared to 3.00 SG using the non-recipe in Figure 6.35. Replace the baryte with 870 lb hematite per final bbl of slurry. Thenon-settling recipe is strongly recommended for hematite slurries because of the relcoarse grind of oil-field hematite.

2 Deflocculation

For years it has been standard practice to add a thinner to baryte slurries used fcontrol. Both lignosulphonates and phosphates have been used, with the phosphathaving the widest acceptance. Chemicals of either type can deflocculate a baryte slimprove pumpability and allow settling into a firm cake.

The choice of deflocculant will influence the baryte slurry properties as follows:

• Use of SAPP gives a slurry with fairly high fluid loss (50cc). SAPP will not defloccuin sea water or in the presence of some contaminants which occur in natural bar

• Use of lignosulphonate gives a slurry with low fluid loss (5cc). Lignosulphonateffective in sea water and tolerates both contamination and elevated temperatur

Use of a high fluid loss baryte slurry is advantageous, possibly because it might dehand plug the wellbore, or promote, perhaps, hole instability. On the other hand, a low fluidloss slurry would reduce the chances of differential sticking. Faced with this choice, prudensuggests using the more reliable lignosulphonate rather than the somewhat unpredSAPP. The recipes in Figure 6.35 contain lignosulphonate.

3 Pilot Tests

Because of variation and possible contamination of ingredients throughout the worldalways advisable to pilot test a baryte slurry. Prepare a sample of the slurry using the recchosen and the ingredients at the wellsite. After being stirred well, the sample should hathe expected density and be easily pumpable. If the baryte needs to settle in the wethis should also be checked ahead of time. Reasonable settling is 2 in. in a mud cup15 minute wait. The settled cake should be hard and somewhat sticky rather than soslippery. The settling test is not a guarantee that the baryte pill will form an effective plugunder downhole conditions, but will certainly give an indication of the settling characteri

4 Slurry Volume

Slurry volumes depend upon the amount of openhole and the severity of the kick. Thesevolumes normally range from 40 bbl to 400 bbl.

The slurry volume should be 125 to 150 percent of the annular capacity necessary the height of plug desired, but should not be less than 40 bbl. If a second baryte prequired, the slurry volume should be greater than the first.

le. If will

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6-93March 1995

5 Pumping and Displacement Rate

Baryte plugs should always be pumped with the drillpipe close to the bottom of the hothere is any significant volume of mud under the baryte slurry then the baryte slurrymix with the mud because of the large differences in density. If the influx zone is somewhatabove the bottom of the hole, then the baryte slurry should be pumped to bottom anabove the influx zone far enough to provide the desired hydrostatic kill height.

A baryte plug should be pumped and displaced at a rate somewhat higher than the kicIf the kick rate is unknown, a reasonable rate (5 to 10 bbl/min) should be used for theattempt although very large blowouts can ultimately require kill weight mud placementgreater than 50 bbl/min.

6 Preparation of a Baryte Plug

For field preparation of either a settling or non-settling baryte slurry, it is best to prepare themix water first and then add baryte to the desired density. The equipment needed on locatioto prepare and pump a baryte plug is a cementing unit equipped with a high pressurethe mixing hopper, a means of delivering the dry baryte to the cementing unit, and sufficentclean tankage for the mix water so that the lignosulphonate and caustic soda can bein advance. The non-settling slurry may be recirculated through the mixing hopper sevtimes if necessary to obtain a particular weight; service companies are reluctant to recirsettling baryte slurries through their equipment.

It is possible to weight-up to 2.5 SG in one pass provided the mix water is fed to the hop600 to 1000 psi. Hopper nozzles and feed rate should be selected to give this pressur

Settling-type baryte slurries may only be stored in ribbon blenders or similar equipwhich provide continuous, thorough agitation. Non-settling slurries may be storestandard␣mud tanks although even these slurries may drop out a few in. of baryte pernot stirred.

The baryte slurry may be pumped into the drillpipe either through a cementing or␣through the standpipe and kelly. In either case, the pump tie-in to the drillpipe shoucontain provisions for hooking up both the cementing unit pump and the rig pump soeither can be used to displace the slurry. If this is not done, and the cementing unit breadown, the baryte may settle in the drillpipe before the mud pump tie-in can be made cementing unit repaired. Blockage of the drillstring by baryte settling will complicatewell control problem.

7 After Pumping a Baryte Plug

Baryte plugs may be used in a variety of situations, it is not possible to givefixed␣procedure which will always work. There will always be a need for local decisionand good judgement. This is especially true in deciding what to do after a baryte plug been pumped.

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6-94March 1995

The decision after placing a baryte plug is whether to pull pipe or not. The goal of pumpinga high-density slurry is to achieve a hydrostatic kill; the decision whether to pull pipe depeon an assessment of the success of this kill. If a hydrostatic kill was probably achievedit is usually best to pull up above the slurry and try circulating mud. If there is doubt abthe hydrostatic kill it may be better to stay on bottom to be ready to pump a larger baryteplug if needed. The risk in pulling out is that the pipe may become stuck off bottom or mayhave to be stripped back to bottom if the baryte plug fails. The risk of staying on bottom isthat the pipe may become stuck or plugged. It is possible to keep the pipe free by mov(especially in a non-settling plug) but there is no way to circulate (to avoid plugging) unthe pipe is pulled above the top of the baryte slurry.

8 Baryte Plug Procedure

(a) Leave Pipe in Place

1 Mix and pump the slurr y at the appr opriate rate

Monitor the slurry density with a densometer in the discharge line or a pressurisedmud balance. Displace the slurry immediately at the same rate.

2 Overdisplace the slurr y by 5 bb l to c lear the drillstring

Continue to pump 1/4 bbl at 15 min intervals to keep the drillstring clear.

3 Verify that under gr ound flo w has stopped

A noise log may be used. It is more definitive than temperature logs. Temperaturesurveys can be used in addition or if the noise log is not available. If temperasurveys are used, wait 6 to 10 hr for the temperatures to stabilise. The survey willshow a hotter than normal temperature in the zone of lost returns. Wait another 4 hr,run a second survey. If the underground flow has stopped, the temperature in the loreturns zone will have decreased.

4 After it has been determined that the flo w is stopped, bullhead a cementslurr y thr ough the bit to pr ovide a permanent seal

Observe the annulus during the pumping. If the casing pressure begins varappreciably, or if a sudden change in the pumping pressure occurs, the baryte pmay have been disturbed. Overdisplace the cement to clear the drillstring. Additionalcementing to obtain a squeeze pressure might be desirable.

5 Plug the inside of the drillstring

The cement in step 4 can be underdisplaced, but a wireline bridge plug set neatop of the collars is preferred. Cement should be dump bailed on the wireline briplug for additional safety.

6 Pressure test the inside plug

clue;ure ortion

own

id.

final

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. If a


6-95March 1995

7 Perforate the drillstring near the top of the bar yte plug. Attempt tocir culate

It may be difficult to tell whether the well is circulating or flowing from chargedformations. Pressure communication between the drillpipe and annulus is onea pressure increase should have appeared on the drillpipe from annulus presson the casing from hydrostatic pressure in the drillpipe when the perforawas␣made.

Consideration should be given to circulating with lighter mud because of the knlost returns zone.

• Well will circulate:

– Use drillpipe pressure method to circulate annulus clear of formation flu

– Run a free-point log.

– Begin fishing operations.

• Well will not circulate:

– Squeeze cement slurry through perforation. Cut displacement short on stage to provide an interior plug or set wireline bridge plug. WOC and pressuretest plug.

– Run free-point log.

– Perforate the pipe near the indicated free point.

– Circulate using drillpipe pressure method until annulus is clear.

If well will not circulate, squeeze perforations with cement or set a wirelbridge plug above perforations and perforate up the hole.

(b) Pull Out of Plug (High Pressure, Low Permeability Formation)

1 Mix and pump the slurr y

Monitor the slurry weight with a densometer in the discharge line or a pressurisedmud balance. If mixing is interrupted for any reason, immediately begin displaceof the slurry using either the cement unit pumps or the rig pumps. Work the pipewhile pumping and displacing.

2 Displace the slurr y with m ud at the same rate

Cut the displacement short by 2 or 3 bbl to prevent backflow from the annulusnon-ported, drillpipe float is in the drillstring, overdisplace the slurry.

3 Immediatel y begin pulling the pipe

It may be necessary to strip the pipe through the annular preventer. Pull at least onestand above the calculated top of the baryte slurry.

nulus

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illt, if

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ell is

hree

ld be


4 Monitor the ann ulus

• If no pressure is on the annulus, continue working the pipe, and observe anmud level.

– If the annulus is full, begin circulating at a low rate keeping constant waon pit levels.

– If the annulus is not full, fill annulus with water and observe. If annulus wstand full, begin circulating at a slow rate. Consider cutting mud weighfeasible.

• If pressure is on the annulus, circulate the annulus using normal well cotechniques. Continue working the pipe.

– If returns become gas-free, the baryte plug was successful and the wdead.

– If returns do not become essentially gas-free after circulating two or tannular volumes, the baryte plug was not effective. A second plug will benecessary.

5 Trip out of the hole after verifying that the well is dead

If the bottom part of the hole is being abandoned, then a cement plug shouplaced on top of the baryte.

6-96March 1995



Subsection 2.6 EMERGENCYPROCEDURE

Paragraph Page

1 Use of Shear Rams 6-98

2 Dropping the Pipe 6-99

6-97March 1995

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m

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ar

on.

an


6-98March 1995

1 Use of Shear Rams

Shear rams can be used to cut drillpipe and then act as a blind ram in order to isolate tdrilling rig from the well. Shearing the pipe is a technique that will be required only inexceptional circumstances.

The use of the shear rams can be considered in the following situations:

• In preference to dropping the pipe in the event of an uncontrollable blowout up thedrillstring (an internal blowout).

• When it becomes necessary to move a floating rig off location at short notice.

• When there is no pipe in the hole, the shear rams can be used as blind rams.

Most shear rams are designed to shear effectively only on the body of the drillpipe. Proceduresfor the use of shear rams must therefore ensure that there is no tool joint opposite the raprior to shearing. Be aware that many subsea stacks have insufficient clearance between thetop pipe rams and the shear rams to hang off on the top rams and shear the pipe.

Specialist shear rams, such as the Cameron Super Shear Rams, are available that are desito shear 7 in. drillcollars and casing up to 13 3/8 in. OD. It is clearly important however,that rigsite personnel are aware of the capabilities and operating parameters of the sherams installed in the rig’s BOP stack.

Optimum shearing characteristics are obtained when the pipe is stationary and under tensiIt is therefore recommended practice that the pipe weight is partially hung off prior toshearing. Hanging the pipe off also ensures that there is no tool joint opposite the shearrams. Maximum operating pressure should be used to shear the pipe.

The following procedure can be used as a guideline for shearing the pipe in the case of internal blowout:

1 Space out to ensure that there is no tool joint opposite the shear rams

2 Close the hang-off ram

3 Hang off on the rams

Ensure that the pipe above the hang-off rams remains in tension.

4 Prepare to operate the shear rams

5 Close the shear rams at maxim um accum ulator pressure

6 Monitor the well. Implement appr opriate contr ol pr ocedures

be

hen

ever

ppeds


6-99March 1995

2 Dropping the Pipe

Situations in which it will be necessary to drop the pipe will be extremely rare.

Dropping the pipe is an emergency procedure and as such it is a procedure that will onlyrequired as a last resort when the safety of the rig and personnel is threatened.

Situations that may require the pipe to be dropped include:

• If an internal blowout occurs on a rig that has no shear rams.

• If an internal blowout occurs when the drillcollars are in the stack.

• As an alternative to the use of shear rams in the event of an internal blowout wdrillpipe is in the stack.

• If the pipe is pushed out of the hole under the influence of wellbore pressure.

• If a BOP develops a leak and there is no back-up available.

Once the pipe has been dropped the well is shut-in with the blind/shear rams. How,re-establishing control of the well in this situation will be time consuming and costly.

It is clearly important to be sure that the pipe will clear the stack once it has been dro(especially on a floating rig in deep water). The possibility of damaging the ram packingmust also be considered.

There are two techniques that can be used to drop the string:

(a) Unlatch the elevators

1 Lo wer the string until the ele vator s are at a mana geable distance fr omthe␣floor

2 Ensure that the BOP is c losed at maxim um operating pressure

3 Attac h a tug ger line to the ele vator s

4 Clear the floor

5 Open the c hoke line to b leed do wn surface pressure

6 Open the ele vator s

7 Open the BOP . Allo w the string to dr op

8 Close the b lind/shear ram

9 Close the c hoke


(b) Back off a tool joint

1 Set the slips

2 Break a tool joint. Ensure that the joint can suppor t the weight of thestring

3 Pull the slips

4 Run the joint belo w the r otar y

5 Set the slips

6 Ensure the BOP is c losed at maxim um c losing pressure

7 Open the c hoke line to reduce the surface pressure

8 Turn the r otar y to the left to bac k off the joint

9 Open the BOP and allo w the pipe to dr op

10 Close the b lind/shear ram

11 Close the c hoke

Both of these techniques involve a certain amount of risk. The most suitable method in eachcase will depend on the particular conditions at the rigsite.

6-100March 1995


6-101March 1995

6.3 COMPLICATIONS

Paragraph Page

1 Plugged Bit Nozzle 6-102

2 Plugged Choke 6-102

3 Cut Out Choke 6-102

4 Pump Failure 6-103

5 Pressure Gauge Failure 6-103

6 String Washout 6-103

7 Stuck Pipe 6-104

8 Well Control Considerations in Horizontal Wellbores 6-104

9 Hydrates 6-105

10 Surface Pressures Approach the MAASP 6-109

11 Impending Bad Weather 6-110

12 Loss of Control 6-111

13 Well Control Considerations in Slim Hole Well 6-111

Illustrations

6.36 Temperature at which Gas Hydrates will Freeze (Katz) 6-106

6.37 Natural gas expansion – Temperature reductioncurve (NATCO) 6-107

6.38 Height of 10 bbl Gas Influx in Annulus 6-113

6.39 Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx 6-114

6.40 Annular Friction Pressure Drop 6-115

6.41 Swab Pressure in a 1000 m Hole 6-116

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6-102March 1995

1 Plugged Bit Nozzle

A plugged nozzle in the bit is indicated by an unexpected increase in drillpipe pressurelittle or no change in the choke pressure.

The choke operator may be tempted to open the choke in an attempt to reduce the dripressure to the original circulating pressure. This will result in a drop in choke pressure anda corresponding drop in bottomhole pressure.

Therefore should a plugged bit nozzle be suspected, the pump should be stopped, thshut-in and the pump restarted to establish the increased standpipe pressure that will maa suitable bottomhole pressure.

An increase in drillpipe pressure could also be caused by the hole packing off around theBHA. This would be likely to cause increased, though fluctuating, circulating pressuThe drillstring should be reciprocated in order to clear this problem.

If the bit becomes totally plugged, this will cause an abrupt and continually increasdrillpipe pressure, with little or no change in choke pressure. In this event, if increadrillpipe pressure does not clear the problem, the string must be perforated as close as poto the bit in order to re-establish circulation.

It is good practice, especially in critical hole sections, to run a circulating sub above thor above a core barrel.

2 Plugged Choke

A plugged choke is indicated by an unexpected increase in choke pressure accompanan equal increase in drillpipe pressure. Some plugging of the choke is to be expected annulus is loaded with cuttings.

Clearly the first course of action is to open the choke in an attempt to both clear the restriin the choke and to avoid overpressuring the well. If this action is not successful the pshould be stopped immediately. After switching to an alternate choke the excess pressurethe well should be bled at the choke and the displacement restarted in the usual man.

One of the reasons for displacing a kick at slow circulation rates is to avoid overpressuthe well if cuttings plug the choke. In this respect, circulation rates should be minimisecritical conditions if the annulus is likely to contain a substantial volume of cuttings.

3 Cut Out Choke

A choke is unlikely to suddenly cut out. In this respect, there will not be any dramindication that this problem is occurring.

As a choke wears it will become necessary to gradually close it in to maintain circulapressure. If the operator finds that he has to gradually close in the choke to maincirculating pressure, the first reaction should be to check the pit volume to ensure thacirculation is not occurring.

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6-103March 1995

Having established that there is no loss of circulation a worn out choke should be susp

There may come a stage when it is no longer possible to maintain a suitable circupressure even with the choke apparently fully closed. At, or preferably before this stage, thflow should be switched to another choke and repairs effected to the worn choke.

4 Pump Failure

The most obvious indicator of failure at the fluid end is likely to be erratic standpipe prestogether with irregular rotary hose movement. This may be preceded by an unexplainedrop in circulating pressure.

If pump failure is suspected, the pump should be stopped and the well shut-in.Thedisplacement should be continued with the second rig pump, or if necessary, the cementpump. The faulty pump should be repaired immediately.

5 Pressure Gauge Failure

Every effort should be made to ensure that all pressure gauges are working correctly, andthat back-up gauges are available in the event of failure of a pressure gauge during control operation.

Should gauge failure occur during a well control operation it is important that the defegauge be replaced as quickly as possible. If no back-up gauge is immediately avastop the operation and shut in the well.

6 String Washout

A washout in the drillstring may be indicated by an unexpected drop in standpipe preswhile the choke pressure remains unchanged.

The recommended procedure in the event of a drillstring washout is to stop the pumshut the well in.

Every effort must be made to ensure that the washout is not enlarged by extended circulationand drillstring manipulation.

The most critical situation would be in the event of a washout close to the surface. Sthis occur, it is unlikely that it will be possible to displace the influx from the hole effectively,unless the influx is above the washout.

If the washout is identified as being near the bottom of the well, it may be possibdisplace the kick from the well effectively. In this case, there will of course be the risk oparting the drillstring with continued circulation.

Regardless of the depth of the washout, it will be necessary to re-establish the ccirculating pressure if the pump is restarted. Excessive downhole pressures may be if the original circulating pressure is maintained at the standpipe. It is advisable to periodre-establish the circulating pressure, if the circulation is contained for prolonged pethrough a washout.

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6-104March 1995

7 Stuck Pipe

The complication of stuck pipe during a well control operation can cause serious probmost especially if the pipe is stuck off bottom.

Unfortunately, the likelihood of the pipe becoming stuck during a well control operatioincreased if the pipe is off bottom. The pipe should be rotated, to minimise the risk sticking the pipe, if the well is shut-in with the pipe off bottom and the BHA in openhole.

Due to the relatively high wellbore pressures during a well control operation, the most cause of stuck pipe is differential sticking. However, mechanical sticking may result if thehole sloughs and packs-off as a result of the contact with the influx fluids.

If the pipe is differentially stuck with the bit on bottom, continue the operation becausemost likely that circulation can still be carried out in order to kill the well. Efforts to free thepipe can be made once the well has been killed.

Should the pipe be differentially stuck with the bit off bottom, the situation is complicatedin that it will generally not be possible to reduce the wellbore pressure at that depcirculation. It may be possible to free the pipe by spotting a freeing agent. However, if theinflux was swabbed in, it may be possible to regain control of the well by volumetric con

If the pipe is mechanically stuck, a combination of working the pipe and spotting a freagent can be used in attempting to free the pipe.

8 Well Control Considerations inHorizontal Wellbore

Well control procedures in horizontal wellbores use the same basic principles as thovertical or deviated holes. Downhole equivalent mud weights are calculated using thvertical depth, as always.

There are however several additional points to consider, these are as follows:

• The purposes of drilling a horizontal well are to improve hydrocarbon recovery anmaximise the area of reservoir exposed at the wellbore, in order to maximise produrates. It must therefore be considered that influx flowrates, in the event of a kickbe considerably greater than for a well drilled vertically through the reservoir.

Particular attention must be paid to tripping procedures when the reservoir is exp

• It is possible that shut-in pressures in the event of a kick will be identical on both driland annulus, although a large influx has been taken; this would depend on the lengththe horizontal openhole section.

This is not a problem, however it does mean that it is not possible to check the vaof kick data.

The possibility that the wellbore contains a large influx should therefore be addressein such circumstances.

d.

oir paid

thele to

poundsal

6.36).sationsmixing

s:

OPs,

eeper

ssure

ntrol

ition,deated

e drop


• There is a greater potential for swabbing when a large surface area of reservoir is exposeCorrect tripping procedure must be rigorously adhered to.

It is quite feasible, in a horizontal well, that the horizontal section is full of reservfluid and yet the well be dead. It is therefore recommended that extreme caution bewhen tripping back into such a reservoir after a round trip. When back on bottom it isrecommended to circulate bottoms up through the choke manifold.

In the event of a kick whilst tripping it may not be possible to drop or pump downdart. This will depend on the hole angle at the dart sub position. If it is not possibinstall the dart into the dart sub, the ‘Gray’ valve can be used.

9 Hydrates

Natural gas hydrates have the appearance of hard snow and consist of chemical comof light hydrocarbons and liquid water. They are formed at temperatures above the normfreezing point of water at certain conditions of temperature and pressure (See Figure This formation process is accelerated when there are high gas velocities, pressure pulor other agitations, such as downstream of a choke and at elbows, which cause the of hydrocarbon components.

During well control operations, gas hydrates may cause the following serious problem

• Plugging of subsea choke/kill lines, preventing opening and closing of subsea Bsealing off wellbore annuli and immobilising the drillstring. There have been recordedincidences of such occurrences with subsea stacks in water depths of 350m and d.

• Plugging of surface lines at and downstream of the choke or restriction. This isparticularly hazardous when high gas flowrates are experienced through low preequipment (such as the poorboy separator and gas vent line). The formation of hydrateplugs under these conditions can rapidly overpressure low pressure well coequipment.

The major factors which determine the potential for hydrate formation are gas composliquid content and pressure and temperature. The formation of hydrates can be predicteusing Figure 6.36. It should be noted that the conditions for hydrate formation can be crat a subsea stack operating in a cold water environment.

Figure 6.37 can be used to predict the temperature drop associated with a pressur(across a choke, for example). As an example, if gas at 3000 psi and 90°F was choked to1800 psi, the temperature would be expected to drop to 55°F, in which case, hydrate formationcould be expected.

6-105March 1995

61


6-106March 1995

Figure 6.36 Temperature at whic h Gas Hydrateswill Freeze (Katz)

35

60

70

80

90

100

200

300

400

PR

ES

SU

RE

FO

R H

YD

RA

TE

FO

RM

AT

ION

(p

sia)

TEMPERATURE (°F)

Example: With 0.7 specific gravity gas at 1000psia, hydrates may be expected at 64°F. At 200psia this would be 44°F.

The purpose of this chart is to determine the temperature below which hydrates will form, when sufficient liquid water is present.

500

600

700

800900

1000

2000

3000

4000

40 45 50 55 60 65 70 75 80 85

METHANE

0.6

GRAV

0.7

0.8

0.9

1.0

WEOX02.0


6-107March 1995

Figure 6.37 Natural Gas Expansion – Temperaturereduction cur ve (NATCO)

GAS TEMPERATURE (°F)

PR

ES

SU

RE

(lb

/in2 )

NA

TU

RA

L G

AS

EX

PA

NS

ION

– T

EM

P R

ED

UC

TIO

N C

UR

VE

B

AS

ED

ON

7 S

P G

R G

AS

(F

rom

NA

TC

O)

160

150

140

130

120

110

100 90 80 70 60 50 40 30 20 10 0

160

150

140

130

120

110

100

90 80 70 60 50 40 30 20 10 00

1000

2000

3000

4000

5000

TEM

PD

RO

PD

UE

TOP

RE

SS

UR

ED

RO

P

7000

6500

6000

5500

5000

4500

4000

3500

3000

2500

2000

1500

1000

500

0

CONST

ANT

ENTH

ALPY

CURVE

S

BTU/1

000

CU FT

GAS

INITIAL TEMP RISE

105° - 80° = 25°

HY

DR

AT

E E

XP

EC

TA

NC

Y D

EG

RE

ES

FA

HR

EN

HE

IT

BA

SE

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E

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AM

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ED

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AS

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ES

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M 2

400

# P

SI A

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TO

150

0 #

PS

I DE

TE

RM

INE

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IAL

TE

MP

ER

AT

UR

E

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E N

EC

ES

SA

RY

SO

TH

AT

AF

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R

EX

PA

NS

ION

TO

150

0 #

PS

I TH

E F

INA

L T

EM

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RA

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E 7

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WEOX02.062

rates

from a

d. ction

r thisfon

e length

l with waterrmation

ing inulatedll

cess ofarbon

x iseration

w theare two

lightly


6-108March 1995

Hydrates can be combated by one or a combination of the following:

• Injecting antifreeze agents such as methanol into the gas flow; this has the effect ofdissolving liquid water deposits, and thus lowering the temperature at which hydwould be expected to form.

Methanol is often injected at the subsea test tree during well testing operations floating rig.

The most appropriate place to inject methanol at surface is at the choke manifolThepoint of injection should be upstream of the choke. High pressure chemical injepumps (as manufactured by Texsteam) are suitable for this application.

• Heating the gas above the temperature at which hydrate will form.

During gas well testing operations, a steam exchanger will usually be provided fopurpose. Experience has shown that this is the most effective and reliable method opreventing the formation of hydrates. The combination of heating and antifreeze injectiis ideal.

• Reducing line pressure in order to allow the hydrates to melt. This is a temporary measurand not always practical. Once hydrates have formed, it often takes a considerableof time to clear the line.

It is important that adequate contingency is provided, along the above lines, to deahydrates, if it is suspected that the potential exists for hydrate formation. Subseatemperatures and pressures should be checked as well as the potential for hydrate foat surface in the event of a gas kick.

10 Surface Pressures Approach the MAASP

The MAASP is defined as the maximum allowable annular surface pressure. Bearmind the method that is used to calculate its value (i.e. assuming that MAASP is calcfrom LO Test result), it is clear that the MAASP is a consideration only when there is a fucolumn of mud from the openhole weak point to the surface. Surface pressures in exthe MAASP therefore may not cause downhole failure if lighter fluids (such as a hydrocinflux) occupy the annulus above the openhole weak point.

Consequently, during a well control operation, from the moment that the top of an infludisplaced past and above the openhole weak point, the MAASP is no longer a considand may be exceeded.

In the event that surface pressures exceed the MAASP when the kick is still beloopenhole weak point, consequently causing excessive downhole pressures, there distinct options:

• Hold the choke pressure so as to maintain bottomhole pressure equal to, or sgreater than, the kick zone pore pressure.

• Reduce the choke pressure and limit it to the MAASP.

an be

sessed,

actors.

icked.

el

h thethe

can


6-109March 1995

The consequences of overpressuring the openhole weak point as in the first option cassessed, bearing in mind the following factors:

• The depth of the casing shoe.

• The quality of the cement job.

• By how much the openhole weak point will be overpressured.

• The length of time that the openhole weak point will be overpressured.

• The characteristics of the openhole weak point.

• Any safety factor included in the calculation of the MAASP.

• The possibility of broaching around the casing.

The consequences of underbalancing the formation as in the second option can be asbearing in mind the following factors:

• The type of kick zone fluid.

• The permeability of the kick zone.

• The degree of underbalance.

• The length of time that the kick zone will be underbalanced.

The appropriate course of action should therefore be selected on the basis of these fHowever, in g eneral, a kic k zone should onl y be underbalanced in e xceptionalcir cumstances suc h as when the zone is kno wn to ha ve lo w permeability . Thiscan often be assessed from the rate of pressure build after shutting in a well that has k

11 Impending Bad Weather

Bad weather is most likely to cause serious problems as regards well control on offshore␣rigs.

For example, it may not be possible to offload baryte supplies or remove excess personnin bad weather.

On a floating rig, a critical situation is reached should it become necessary to unlatcriser during a well control operation. In this situation it will not be possible to monitor well and hence control the migration of the influx, should this occur.

Should weather conditions deteriorate with very little warning, the following procedure be implemented:

1 Attempt to b ullhead the influx bac k to the f ormation

2 Displace the drillstring to kill weight m ud

3 Close lo wermost pipe rams (in ad dition to the hang-off rams). Shear thepipe rams

4 Prepare to unlatc h, monitoring wellbore pressures until it becomesnecessar y to unlatc h

plug

ll types

rticular

ssure

belowoperptible

wellnd

ll is a

eirons ofts on

ficant

ared

nfluxonaln a


6-110March 1995

If additional time is available, consideration should be given to spotting a heavy pill oron bottom to either kill the well hydrostatically or provide a barrier to migration.

Bad weather may cause problems regarding the supply of chemicals and barytes to aof rigs. In this respect, it may be necessary to implement the Driller’s Method, should therenot be adequate chemical stocks at the rigsite.

In certain areas of the world, severe cold may cause operational problems. Points of paconcern are, BOP operating fluid, manifolds and flowlines.

12 Loss of Control

Loss of control during a well control operation may result from excessive loading of precontrol equipment or exposed formations.

However there are recorded incidents of equipment failure at pressures significantly rated values. These failures have been attributed to faulty manufacture, lack of prmaintenance, or corrosion. High pressure equipment is considered particularly susceto failure when exposed to corrosive fluids such as H2S.

It is not possible to detail specific procedures in the event of loss of control during acontrol operation. However, in critical situations, action should be taken bearing in mithat the absolute priority is the safety of rigsite personnel.

13 Well Control Considerations in Slim Hole Well

A slim hole is commonly defined as one in which 90% or more of the length of the wedrilled with drill bits less than 7" in diameter. A well with hole sizes smaller than those inconventional well is also broadly considered as a slim hole well.

Whilst the immediate difference between a conventional well and a slim hole well is thhole sizes, other major characteristics of a slim hole include the practice of long secticontinuous coring and the requirements of higher drillpipe rotary speeds, lower weighbit, lower mud flow rates and special mud systems. So a slim hole well requires signichanges in the well design, well operation and the well control procedures.

(a) Slim Hole Characteristics

In terms of well control, a slim hole well has the following characteristics when compwith a conventional well:

• Greater Influx Length

Due to the reduced annular size in a slim hole, the same volume of formation iwill occupy a longer section of the annulus in a slim hole well than in a conventiwell. As shown in Fig.6.38, a 10 bbl influx occupies 66 m long annulus iconventional 8.5"x5" well and 523 m long in a 3.5"x2.5" slim hole well.

Rev 1 March 1995

will

43 psi

many6.40.ntroltional

wells.han inslim

gherionalt in a

ationuced

nulus

into

r slims

bbl).).

ofre

likelyction.


6-111March 1995

• Greater Bottom Hole Pressure Reduction

As the result of the greater influx length, the same volume of formation influxresult in a greater reduction in the bottom hole pressure in a slim hole well. As␣shownin Fig.6.39, a 10 bbl gas influx will reduce the bottom hole pressure by about 7in a 3.5"x2.5" slim hole well and only 94 psi in a conventional 8.5"x5" well.

• Higher Annular Friction Pressure

Also due to the reduced annular size, the annular friction pressure drop can betimes higher in a slim hole well than in a conventional well, as shown in Fig.Therefore the friction pressure drop can become significant during well cooperations in a slim hole well whereas it is all but ignored in the case of a convenwell.

• Higher Swab and Surge Pressures

Fig.6.41 compares the swabbing pressure in both slim hole and conventionalIt can be seen that the swabbing pressure is much higher in a slim hole well ta conventional well. Also the swabbing pressure increases more rapidly in a hole well with increasing the trip speed.

• Effect of High Drillpipe Rotational Speed

During a slim hole drilling operation, the drillpipe is often rotated at a much hirate than that during a conventional drilling operation. Due to the high rotatspeed together with the small annular size, the drillpipe rotation can resulsignificant increase in the annular friction pressure and the ECD. This effect must betaken into account in the well control procedures. Otherwise, the weak formmay be broken down when the drillpipe starts to rotate, or a kick influx be indwhen rotation stops (whilst still maintaining circulation).

(b) Kick Detection System

As described above, a small volume of influx can occupy a long section of the anin a slim hole well and thus greatly reduce the bottom hole pressure. This will cause theinflux flow to intensify continuously. As the result, a kick can develop more rapidlya slim hole well than in a conventional well. Therefore it is important to be able detect a kick at a very early stage during a slim hole well operation.

Although the basic principles in the kick detection technique remain the same foholes, the sensitivity of the detection system must be enhanced. The basic requirementfor a slim hole kick detection system are:

• The system must be able to detect a small volume of pit gain (typically 1 or 2This technique is most reliable when the influx flow is slow (low kick intensity

• The system must be able to detect the difference between the mud flow in and outthe well (typically 25 gpm). When the influx flow is fast, this technique is mosensitive and reliable than the pit volume detection technique.

• The system must be able to detect a kick whilst making a connection. The highannular friction pressure creates a high ECD during drilling ahead. So the mosttime for a kick to occur will be when the pumps are shut down to make a conne

Rev 1 March 1995

fetyhtly

n the

her

therface

oint.

d.

resmBP


(c) Well Kill Technique

As the annular friction pressure is small in a conventional well, it is used as a safactor during the well kill operation to ensure that the bottom hole pressure stays sligabove the formation pressure. So the annular friction pressure is usually ignored iconventional well control calculations. In a slim hole well however, the annular frictionpressure may be so high that when used as a safety factor, it will break down the formationat the weak point and cause lost circulation.

Therefore a decision that must be made when drilling a slim hole is whetthe␣conventional well kill technique can be applied. This can be made in thefollowing␣steps:

• Estimate the annular friction pressure at the slow circulating rates and add this tomaximum static pressure (i.e. the sum of the mud hydrostatic pressure and the sucasing pressure) at the weak point in the wellbore.

• Compare the total wellbore pressure with the breakdown pressure at the weak pWill lost circulation be likely?

• If lost circulation is unlikely, the conventional well control technique can be applieOtherwise the slim hole well control technique must to be used.

(d) Slim Hole Well Control Manual

This section briefly summarises the key differences in well control for slim holes. A BPSlim Hole Well Control Manual is available that details the principles and procedufor kick prevention, kick detection, well shut-in and the well kill technique for sliholes. The manual can be obtained from the Drilling and Completions Branch, Exploration, Sunbury.


BP

WE

LL CO

NTR

OL M

AN

UA

L

6-113M

arch 1995

Figure 6.38

Height of 10 bb

l Gas Influx in A

nnulus

Brine: 4.0 cPMud: PV=15/YP=108.5 x 5 13.8 31.2

6 x 4.5 4 1 128.6

3.5 x 2.5 68.9 254.3

n Annulus

3.5 x 2.5

523 m

Rev 1 M

arch 1995

Gas Influx Annular Gas Influx Reduction In FrictionVolume Size Height BHP (osi) Pressure

(bbl) (inch) (m) 1.0 sg Mud (psi)

1 0 8.5 x 5 6 6 9 4

1 0 6 x 4.5 199 283

1 0 3.5 x 2.5 523 743

Figure 6.38a: Height of 10 bbl Gas Influx i

0

200

400

600

8.5 x 5 6 x 4.5

Size of Annulus (inch)

Hei

gh

t o

f G

as In

flu

x(m

)

66 m

199 m

BP

WE

LL CO

NTR

OL M

AN

UA

L

6-114M

arch 1995

Figure 6.39

Reduction in B

ottom H

ole Pressure D

ueto 10 bb

l Gas Influx

ottom Hole Pressures Influx

x 4.5 3.5 x 2.5

nulus (inch)

psi

743 psi

Between Mud and Gas)

Rev 1 M

arch 1995

Mud: PV=15/YP=1031.2

128.6

254.3

Figure 6.38b: Reduction in BDue to 10 bbl Ga

0

200

400

600

800

8.5 x 5 6

Size of An

Red

uct

ion

in B

HP

(ps

i)

94 psi

283

(1.0 SG Density Difference

BP

WE

LL CO

NTR

OL M

AN

UA

L

6-115M

arch 1995

Figure 6.40

Ann

ular Friction P

ressure Dr

op

swab pressures

sec/std 8 .5 /5 6 /4 .5 3.5/2.5300 40.9 45.8 9 0250 4 1 4 6 90.8200 41.3 46.3 92.1150 41.7 48.8 94.2100 42.5 47.8 98.5

5 0 44.8 50.9 1104 0 46.2 52.5 117.73 0 48.3 55.1 128.42 5 5 5 66.4 1682 0 58.8 92.2 2381 5 64.8 147 368

Hei

gh

t o

f G

as In

flu

x(m

)

ure Drop

3.5 x 2.5

)

68 .9

2 5 4

/min)

Sw

ab P

ress

ure

(ps

i/1

00

0m

)

Rev 1 M

arch 1995

Figure 6.38c: Annular Friction Press

0

5 0

100

150

200

250

300

8.5 x 5 6 x 4.5

Size of Annulus (inch

Fri

ctio

n P

ress

ure

Dro

p(p

si/

10

00

m)

Brine: 4.0 cP

Mud: PV=15/YP=10

13.831.2 4 1

1 2 9

(Mud Annular Velocity = 150 ft

BP

WE

LL CO

NTR

OL M

AN

UA

L

6-116M

arch 1995

Figure 6.41

Sw

ab Pressure in a 1000 m

Hole

Red

uct

ion

in B

HP

(psi

)

Fri

ctio

n P

ress

ure

Dro

p(p

si/

10

00

m)

in a 1000 m Hole

03 0

c/30m std.)

8.5"x5.0"Annulus

6.0"x4.5"

3.5"x2.5"

YP=10 lbf/100sqft)

Rev 1 M

arch 1995

3.5/2.5 8 .5 /59 0

90.892.194.298.5110

117.7128.4

168238368

Figure 6.38d: Swab Pressure

0

6 0

120

180

240

300

6 09 0

Trip Speed (se

Sw

ab P

ress

ure

(ps

i/1

00

0m

)(Mud: 1.0 SG, PV=15 cP,


March 1995

Volume 2 – Contents

NomenclatureAbbreviations

1 THE ORIGINS OF FORMATION PRESSURE

Section Page

1.1 INTRODUCTION 1-1

1.2 NORMAL FORMATION PRESSURE 1-9

1.3 SUBNORMAL FORMATION PRESSURE 1-11

1.4 ABNORMALLY HIGH FORMATION PRESSURE 1-17

1.5 SHALLOW GAS 1-33

2 FORMATION PRESSURE EVALUATION

Section


2.2 FORMATION PRESSURE EVALUATIONDURING WELL PLANNING 2-5

2.3 FORMATION PRESSURE EVALUATIONWHILST DRILLING 2-25

2.4 FORMATION PRESSURE EVALUATIONAFTER DRILLING 2-69


March 1995

3 PRIMARY WELL CONTROL

Paragraph

1 GENERAL 3-2

2 HYDROSTATIC PRESSURE 3-2

3 EQUIVALENT MUD WEIGHT, EMW 3-2

4 CIRCULATING PRESSURES AND ECD 3-4

5 CALCULATING THE CIRCULATINGPRESSURE LOSSES 3-7

6 SWAB AND SURGE PRESSURES 3-10

7 SWAB AND SURGE CALCULATIONS 3-12

4 FRACTURE GRADIENT

Paragraph

1 GENERAL 4-2

2 STRESSES IN THE EARTH 4-2

3 FRACTURE ORIENTATION 4-3

4 FRACTURE GRADIENT PREDICTION 4-4

5 DAINES’ METHOD OF FRACTUREGRADIENT PREDICTION 4-4

6 AN EXAMPLE PRESSURE EVALUATION LOG 4-7

7 LEAK OFF TESTS 4-9

8 LEAK OFF TEST PROCEDURE 4-10

9 INTERPRETATION OF RESULTS 4-11


5 BASICS OF WELL CONTROL

Paragraph

1 GENERAL 5-4

2 DISPLACING A KICK FROM THE HOLE 5-4

3 FACTORS THAT AFFECT WELLBORE PRESSURES 5-9

4 SUBSEA CONSIDERATIONS 5-20

5 SAFETY FACTORS 5-25

6 CALCULATING ANNULUS PRESSURE PROFILES 5-29

6 WELL CONTROL EQUIPMENT

Section

6.1 WELLHEADS 6-1

6.2 BLOWOUT PREVENTER EQUIPMENT 6-5

6.3 CONTROL SYSTEMS 6-43

6.4 ASSOCIATED EQUIPMENT 6-57

6.5 EQUIPMENT TESTING 6-67

March 1995


March 1995

NOMENCLATURE


A Cross sectional area in.2

a Constant –A

nTotal nozzle area in.2

b Constant –c Constant –C Annular capacity bbl/mC

pPipe capacity bbl/m

Ca

Cuttings concentration %CL Clinging constant –CR Closing ratio –D Depth mD

shoeShoe depth m

Dwp

Depth of openhole weak point md

bitBit diameter in.

dh

Hole diameter in.d

hcHole/casing ID in.

do

Pipe OD in.d

iPipe ID in.

dcut

Average cuttings diameter in.d

cDrilling exponent (corrected) –

F Force lbF

shShale formation factor –

FPG Formation Pressure Gradient SGg Gravity acceleration –G Pressure gradient psi/ft

psi/mSG

Gi

Influx gradient psi/ftH Height mH

iHeight of influx m

Hp

Height of plug mITT Interval Transit Time µsec/mK Bulk modulus of elasticityL Length mλ Rotary exponent –MR Migration rate m/hrM Matrix stress psim Threshold bit weight lbMW Mud weight SG


March 1995


N Rotary speed rpmOPG Overburden Pressure Gradient SGP Pressure psi/SG

(The units of subsurface pressuremay be either psi or SG)

∆P Adjustment pressure psiPa Annulus pressure psi∆Pbit Bit pressure drop psiPcl Choke line pressure loss psiPdp Drillpipe pressure psiPf Formation pressure psi/SGPfrac Fracture pressure psi/SGPfc Final circulating pressure psiPi Hydrostatic pressure of influx psiPic Initial circulating pressure psiPlo Leak off pressure psi/SGPmax Maximum allowable pressure

at the openhole weak point psi/SGPoc Wide open choke pressure psiPp Pore pressure psi/SGPscr Slow circulating rate pressure psiPV Plastic Viscosity cPQ Flowrate gal/minQ

mudMud flowrate gal/min

Qgas

Gas flowrate gal/minRe Reynolds number –R Resistivity ohm-mRw Resistivity of water ohm-mROP Rate of Penetration m/hr

Shale factor meq/100gS Overburden pressure psiS

gGas saturation Fractional

Sw

Water saturation Fractionalt Time seconds

minTR Transport Ratio –T Temperature degrees

C, F, RTD Total Depth mTVD True Vertical Depth mV Kick tolerance bbl



V Volume bblccmll

v Velocity m/minm/s

vmud Mud velocity m/minvp Average pipe running speed m/minvs Slip velocity m/minW Weight gm

kglb

w Weight lb/ftlb/bblSG

w Weight of pipe lb/ftwb Baryte required for weighting up lb/bblwcut Average cuttings weight SGWOB Weight on Bit lbx Offset ( )YP Yield Point lb/100ft2

Z Compressibility factor –µ Viscosity cPν Poissons’s Ratio –σ’1 Maximum effective principle stress psi/SGσ’t Tectonic stress psi/SGØ Porosity FractionalØ600 Fann reading lb/100ft2

β Tectonic stress coefficient –ρ Density SGρ

bBulk density SG

March 1995


ABBREVIATIONS

ASN Amplified Short NormalBHA Bottomhole AssemblyBHC Borehole Compensated ToolBHT Bottomhole TemperatureBGG Background GasBRT Below Rotary TableCDP Common Depth PlotCEG Cation Exchange CapacityCG Connection GasDE Drilling EngineerDIL Dual Induction LaterologDRG Designated Resident GeologistDST Drillstem TestECD Equivalent Circulating DensityEMW Equivalent Mud WeightES Electrical SurveyFDC Formation Density Compensated ToolFIT Formation Interval TesterHCR High Closing RatioID Internal DiameterITT Interval Transit TimeLMRP Lower Marine Riser PackageMWD Measurement while DrillingOD Outside DiameterPV Plastic ViscosityRFT Repeat Formation TesterRMS Root Mean SquaredROP Rate of PenetrationSLS Long Spacing Sonic ToolTD Total DepthTG Trip GasUV Ultra VioletWOB Weight of BitYP Yield Point

March 1995


1 THE ORIGINS OF FORMATION PRESSURE

Section Page


1.2 NORMAL FORMATION PRESSURE 1-9

1.3 SUBNORMAL FORMATION PRESSURE 1-11

1.4 ABNORMALLY HIGH FORMATION PRESSURE 1-17

1.5 SHALLOW GAS 1-33

March 1995


1.1 INTRODUCTION

Paragraph Page

1 General 1-2

2 Subsurface Pressures 1-2

3 Pressure Seals 1-6

4 Pressure Gradients 1-7

Illustrations

1.1 Composite Overburden Load for NormallyCompacted Formations 1-4

1.2 Schematic Diagram of Subsurface Pressure Concepts 1-5

Tables

1.1 Types of Formation Pressure Seals 1-6

1-1March 1995

. explain

height

gal).

ging

gives:


1-2March 1995

1 General

All formations penetrated whilst drilling a well exert pressures of varying magnitudesTogain an understanding of the origins of these pressures, it is neccesary to define and certain subsurface pressure concepts. These are explained in this Section.

2 Subsurface Pressures

(a) Hydrostatic Pressure

Hydrostatic pressure is defined as the pressure due to the unit weight and vertical of a fluid column. The size and shape of the fluid column do not affect the magnitude ofthis pressure. Mathematically:

P = r X g X D (1-1)

where P = hydrostatic pressureρ = average fluid densityg = gravitational accelerationD = vertical height of fluid column

Relating this to drilling operations and commonly used oilfield units gives:

P = C X MW X D (1-2)

where P = hydrostatic pressure (psi)MW = fluid density or mud weight (lb/gal or ppg)D = vertical depth (ft)C = conversion constant (psi/ft per lb/gal)

The constant, C, is necessary to allow the use of oilfield imperial units (psi, ft, lb/It has a value of 0.052 psi/ft per lb/gal and is derived as follows:

Using consistent units (pressure in lb/sq.ft, length in ft, density in lb/cu.ft) and rearranequation 1-2, C would be numerically equal to 1:

C = P = 1 lb/sq.ft/ft per lb/cu.ftD X MW

Substituting the standard conversion constants of 144 sq.in/sq.ft and 7.48/gal/cu.ft

C = 1 X 7.48 lb/sq.ft X sq.ft/sq.in144 ft X lb/cu.ft cu.ft/gal

C = 0.052 lb/sq.inft X lb/gal

C = 0.052 psi/ft per lb/gal

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1-3March 1995

So in imperial oilfield units (psi, ft, lb/gal), equation 1-2 becomes:

P = 0.052 X MW – D (1-3)

For the Company’s system of units (psi, SG, m):

P = C' X SG X D (1-4)

where SG = specific gravity of the fluid (no units)D = vertical depth (metres)C' = conversion constant (psi/m)

NOTE: Specific gravity (SG) is not a unit of density. It is the ratio of the density oa␣fluid to the density of fresh water at a specified temperature, and hencno units.

The constant, C', has a value of 1.421 psi/m and is derived as follows:

To express equation 1-2 in terms of SG (as in equation 1-4), the constant C' mrelated to the density of fresh water, which is 8.33 lb/gal. Hence for fresh water:

C' = C X 8.33 psi/ft/lb/gal X lb/gal

C' = 0.052 X 8.33 psi/ft

C' = 0.433 psi/ft (1-5)

Expressing this in terms of metres using 3.2808 ft/m gives:

C' = 0.433 X 3.2808 psi/ft X ft/m

C' = 1.421 psi/m

Equation 1-4 thus becomes:

P = 1.421 X SG X D (1-6)

(b) Overburden Pressure

Overburden pressure is the result of the combined weight of the formation matrix (and the fluids (water, oil and gas) in the pore space overlying the formation of inter

It was originally assumed that overburden pressure increases uniformly with depthTheaverage density of a thick sedimentary sequence is equivalent to an SG of 2.3. Hthe overburden pressure (S) is given by:

S = 0.433 X SG X D (1-7)

where D = vertical depth (ft).

The overburden pressure gradient (OPG) is given by:

OPG = S = 0.433 X SGD

OPG = 0.433 X 2.3 = 1.0 psi/ft


1-4March 1995

Figure 1.1 Composite Overburden Load for NormallyCompacted Formations

0

1. 2. 3. 4.

Constant gradient 1.0psi/ft Gulf of Mexico, Texas and Louisiana, USA Santa Barbara Channel, California, USA North Sea area

4 2 3 1

1

2

3

DE

PT

H 1

000m

OVERBURDEN GRADIENT psi/ft

4

5

6

0.7 0.8 0.9

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1-5March 1995

However, because the degree of compaction of sediments varies with depth, the overbpressure gradient is not constant. Worldwide experience indicates that the probable maximuoverburden gradient in clastic rocks (fragmental sedimentary rocks ie sandstone, shalebe as high as 1.35 psi/ft.

Onshore, with more compact sediments, the overburden pressure gradient may be asto be close to 1 psi/ft. Offshore however, overburden gradients at shallow depths will bmuch less than 1 psi/ft due to the effect of the depth of sea water and large thickness ofunconsolidated sediment. Figure 1.1 shows average overburden gradient for various

Figure 1.2 Schematic Diagram of SubsurfacePressure Concepts

PRESSURE

DE

PT

H

NO

RM

AL H

YD

RO

STA

TIC G

RA

DIE

NT

OVERBURDEN GRADIENT

SUBNORMAL PRESSURES

(Subpressures)ABNORMALLY HIGH PRESSURES (Surpressures)

Formation Pressure, Pf Matrix Stress, M

Overburden Pressure, S = Pf + M

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1-6March 1995

(c) Pore Pressure

Pore pressure is the pressure acting on the fluids contained in the pore space of theThis is the strict meaning of what is generally referred to as formation pressure. Formapressure is related to overburden pressure as follows:

S = Pf + M (1-8)

where S = overburden pressure (total vertical stress)Pf = formation pressure (pore pressure)M = grain-to-grain pressure (matrix stress)

All sedimentary rocks have porosity to some extent. If the pore spaces of the rocksfreely connected from surface, then the formation pressure at any depth will be equthe hydrostatic pressure exerted by the fluid occupying the pore spaces. In this ‘normpressure situation, the matrix stress (grain-to-grain contact pressure) supportsoverburden load. Any departure from this situation will give rise to ‘abnormal’ formationpressures. Formation pressures less than hydrostatic are called subnormal (subpresand formation pressures greater than hydrostatic are termed abnormally high formapressures (surpressures) (See Figure 1.2).

3 Pressure Seals

For abnormal pressures to exist, there must be a permeability barrier which acts as a preseal. This seal restricts or prevents the movement of pore fluids and thus separates normpressured formations from abnormally pressured formations.

The origins of a pressure seal may be physical, chemical or a combination of the two.Thetypes of formation pressure seals are listed below in Table 1.1.

Type of Seal Nature of Seal Examples

Vertical Massive siltstones Gulf Coast, USA,Shales Zechstein in North Germany,Massive salts North Sea, Middle East,Anhydrite USA, USSR.GypsumLimestone, marl, chalkDolomite

Transverse Faults WorldwideSalt and shale diapirs

Combination Worldwide

Table 1.1 Types of Formation Pressure Seals

r unitgal

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1-7March 1995

4 Pressure Gradients

As indicated previously in Paragraph 2(b) under ‘Overburden Pressure’, it is commonpractice to express subsurface pressures in terms of pressure gradients, or pressure pedepth, psi/ft or psi/m. It should be realised that densities such as mud weights in lb/or␣SG, also express pressure gradients. These units can easily be converted to psi/ft or psi/musing the conversion constants derived earlier in Paragraph 2(a). Rearranging equation1-3 gives:

PG = P = 0.052 X MW (1-9)D

where PG = pressure gradient (psi/ft) at depth D (ft), and rearranging equation 1-6 give

PG = P = 1.421 X SG (1-10)D

where PG = pressure gradient (psi/m) at depth D (m).

Or,

PG = P = 0.433 X SG (1-11)D

where PG = pressure gradient (psi/ft) at depth D (ft).

By converting subsurface pressures to gradients relative to a fixed datum, it is possibldirectly compare formation pressures, fracture pressures, overburden pressures, mud weand equivalent circulating densities (ECDs) on the same basis (See Chapter 3). The datumchosen is usually sea/ground level for initial planning purposes. Once a rig has been allocfor the well, then the datum chosen for final well planning and whilst drilling is the rotartable level (since mud hydrostatic pressure starts from just below this level).

During drilling operations, it is standard practice to express all pressure gradients in teof equivalent mud weight (EMW) either in lb/gal or SG. This allows direct comparison ofdownhole pressures to the weight (density) of the mud in use. EMWs can be calculafrom rearrangements of equations 1-9 to 1-11:

EMW (lb/gal) = P (psi) (1-12)0.052 X D (ft)

EMW (SG) = P (psi) (1-13)1.421 X D (m)

EMW (SG) = P (psi) (1-14)0.433 X D (ft)

NOTE: From this point on ppg will be used instead of lb/gal as the abbreviated versiof pounds per gallon.

Example: For a formation pressure of 5970 psi at 3500m BRT, what is theformation␣pressure gradient in psi/ft? What is the equivalent mud weightin ppg and SG?


Formation pressure gradient, FPG =pressuredepth

FPG = 5970 = 0.52 psi/ft3500 X 3.2808

Equivalent mud weight from equation 1-12

EMW = 5970 (ppg)0.052 X 3500 X 3.2808

EMW = 10.0 ppg

From equation 1-13

EMW = 5970 = 1.20 SG1.421 X 3500

1-8March 1995


1.2 NORMAL FORMATION PRESSURE

Paragraph Page

1 General 1-10

2 Magnitude and Examples 1-10

Tables

1.2 Average Normal Formation Pressure Gradients 1-10

1-9March 1995

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1-10March 1995

1 General

Normal formation pressure is equal to the hydrostatic pressure of water extending fromsurface to the subsurface formation. Thus, the normal formation pressure gradient in anarea will be equal to the hydrostatic pressure gradient of the water occupying the pore spof the subsurface formations in that area.

2 Magnitude and Examples

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

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

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

In formations deposited in an offshore environment, formation water density may vary fromslightly saline (1.02 SG, 0.44 psi/ft) to saturated saline (1.19 SG, 0.515 psi/ft). Salinvaries with depth and formation type. Therefore, the average value of normal formationpressure gradient may not be valid for all depths. For instance, it is possible that lnormal pressure gradients as high as 0.515 psi/ft may exist in formations adjacent toformations where the formation water is completely salt saturated.

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

Formation W ater Pressure Gradient Example Area(psi/ft) (SG)

Fresh water 0.433 1.00 Rocky Mountains andMid-continent, USA

Brackish water 0.438 1.01

Salt water 0.442 1.02 Most sedimentary basinsworldwide

Salt water 0.452 1.04 North Sea, SouthChina Sea

Salt water 0.465 1.07 Gulf of Mexico, USA

Salt water 0.478 1.10 Some areas of Gulfof Mexico

Table 1.2 Average Normal Formation Pressure Gradients


1.3 SUBNORMAL FORMATION PRESSURE

Paragraph Page

1 General 1-12

2 Causes of Subnormal Formation Pressure 1-12

3 Magnitude of Subnormal Formation Pressures 1-15

4 Summary 1-16

Illustrations

1.3 Relationship between Piezometric Surface andGround Level for an Aquifer System 1-13

1.4 Temperature-pressure-density diagram for Waterillustrating Subnormal Pressures caused by Coolingan Isolated Fluid 1-14

1.5 Formation Foreshortening 1-15

1-11March 1995

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1-12March 1995

1 General

Subnormal formation pressure is defined as any formation pressure that is less thacorresponding pore fluid hydrostatic pressure. A subnormal formation pressure gradient ithus any gradient less than the pore fluid hydrostatic gradient.

Subnormal formation pressures are often termed subpressures.

2 Causes of Subnormal Formation Pressure

Subnormal formation pressures occur less frequently than abnormally high formapressures. They may have natural causes related to the stratigraphic, tectonic and geochehistory of an area, or may be caused artificially by producing reservoir fluids.

(a) Depleted Reservoirs

Producing large volumes of reservoir fluids causes a decline in pore fluid pressure uncompensated for by a strong water drive. Depleted reservoirs may thus havepressures less than hydrostatic.

For example, the original reservoir formation pressure in BP’s Forties Field was 3215␣psiat a depth of 2175m subsea. This equates to a formation pressure gradient of 0.451␣pswhich is the normal hydrostatic gradient. After twelve years production from the fieldand even with pressure boosting by water injection, the reservoir formation presdropped to approximately 2750 psi. This gives a subnormal pressure gradient 0.385␣psi/ft.

(b) Piezometric Surface

A piezometric or potentiometric surface is an imaginary surface that represents thehead of ground water and is defined by the level to which the ground water will risa well. For example, the water table is a particular potentiometric surface.

In very arid areas such as the Middle East, the water table may be deep. The hydrostaticpressure gradient commences at the water table giving a subnormal pressure grfrom the surface.

A piezometric surface is dependent on the structural relief of a formation and can rin subnormal or abnormally high formation pressures. The piezometric surface for anaquifer system is shown in Figure 1.3.

Drilling in mountainous areas may thus encounter subnormal pressure gradients dthe surface elevation being higher than the water table elevation or formation wpotentiometric surface.

(c) Temperature Reduction

A reduction in subsurface temperature will reduce the pore pressure in an isolatedsystem where the pore volumes (and thus fluid density) remains constant. This maycause subnormal pressures.

s this

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1-13March 1995

Figure 1.3 Relationship between Piezometric Surfaceand Ground Level for an Aquifer System

The temperature-pressure-density diagram for water shown in Figure 1.4 illustrateconcept.

Both temperature and pressure are dependent on depth. For a normal fluid (non-isowhich is allowed to expand and contract freely, a temperature reduction associated wita depth change would follow the path indicated (which in this example correspondstemperature gradient of 2.5°C/100m). A lower pressure would result but it would stilbe equal to the normal hydrostatic pressure. In an isolated fluid system (ie/complsealed shales), cooling must take place along a constant density path as showThepressure corresponding to the lower temperature is thus subnormal.

If gas is present in the pores, the effects of temperature reduction will be greater as gpressure is much more sensitive to temperature changes than water.

Mechanisms which may create a reduction in subsurface temperature include uerosion or a combination of uplift and erosion.

(d) Decompressional Expansion

Decompressional expansion is the term used to describe the combined effects of upliftand erosion. In shales, uplift and overburden removal by erosion may cause a reduin pore fluid pressure. This reduction may be due to an increase in pore volume aremoval of free water from the pore space by adsorption in clay minerals asoverburden pressure decreases. Water adsorption due to mineral transformations (eg/illito montmorillonite) may also occur due to the decrease in temperature. (This isreverse of ‘Clay diagenesis’ as described in Section 1.4 of this Chapter.)

INTAKE AREA

PIEZOMETRIC SURFACE

GROUND LEVEL

ABNORMALLY HIGH PRESSURES

SUBNORMAL PRESSURES

HYDROSTATIC HEAD

DISCHARGE AREA

AQUIFER

RESERVOIRS

WEOX02.065


1-14March 1995

Figure 1.4 Temperature-pressure-density diagram forWater illustrating Subnormal Pressurescaused by Cooling an Isolated Fluid

11

10

9

8

7

6

5

4

3

2

1 2

2

1

1

2

=

=

Initial conditions at depth 1

Conditions at depth 2

0

T2 T1

50 100 150 200 250

PR

ES

SU

RE

100

0psi

TEMPERATURE °C

PRESSURE AT DEPTH 2 FOR ISOLATED FLUIDS

PRESSURE AT DEPTH 2 FOR NORMAL FLUIDS

PRESSURE AT DEPTH 1

2.5°

C/1

00m

DE

NS

ITY

1.0

gm/c

c

0.98

0.96

2

0.93

3

0.90

9

0.87

7

NORMAL FLUIDS

ISOLATED FLUIDS

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1-15March 1995

Figure 1.5 Formation Foreshortening

This pressure reduction may be sufficient to cause subnormal pressures which would transmitted to any reservoir rocks associated with the shales.

(e) Formation Foreshortening

This is a tectonic compression mechanism. It is suggested that during a lacompression process acting on sedimentary beds, upwarping of the upper beddownwarping of the lower beds may occur. The intermediate beds must expand to fithe voids left by this process, as shown in Figure 1.5. It is then possible for mcompetent intermediate beds, such as shales, to have subnormal pressures dueincrease in pore volume.

This mechanism is thought to occur in areas of recent tectonic activity, such as alongthe flanks of the Rocky Mountains.

(f) Osmosis

Osmosis is the spontaneous flow of water from a more dilute to a more concentsolution when the two are separated by a semi-permeable membrane.

In the subsurface environment, clays and clayey siltstones can act as semi-permmembranes. If salinity differences exist between the fluids in the sediments on eitside of clay beds, then osmotic flow can occur. If the flow is from a closed volume, thepressure will decrease and may become subnormal. Likewise, if the flow is into a cvolume, abnormally high pressures may result.

Osmosis is discussed in more detail in Section 1.4 of this Chapter.

P PP P

OVERPRESSURED

WEOX02.067

SUBNORMAL PRESSURE

OVERPRESSURED

BED A

A

B

C

BED B

BED C

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3 Magnitude of Subnormal Formation Pressures

By definition, subnormal formation pressures must be lower than the normal hydrospressure for the location. In terms of pressure gradients, subnormal pressures willgradients less than normal (0.433 to 0.465 psi/ft depending on the particular area).

As previously discussed, the Forties Field reservoir is now subnormally pressure0.385␣psi/ft. Subnormal gradients of 0.36 to 0.39 psi/ft have been quoted for areas oTexas Panhandle (NW Texas) with one case as low as about 0.23 psi/ft thought to beresult of a low piezometric surface.

One of the lowest formation pressure gradients encountered is 0.188 psi/ft which was recin the Keyes gas field in Oklahoma.

4 Summary

The various suggested causes of subnormal formation pressures can be classed as ‘arcaused’ or ‘naturally caused’.

‘Depleted reservoirs’ and ‘piezometric surface’ (where pressure regime depends osurface location of the well) may be classed as artificial causes, since these subnpressures do not originate in the subsurface formation, but are externally influenced.

Conversely, the other causes of subnormal pressure discussed have origins in the formthemselves and can be thought of as being naturally caused. It is unlikely that any othese processes may be the sole cause of subnormal pressures in any particular arprobable that a number of processes have contributed to produce the subnormal preparticularly in the light of the dependency of the processes on depth and temperature

1-16March 1995


1.4 ABNORMALLY HIGHFORMATION PRESSURE

Paragraph Page

1 General 1-18

2 Causes of Abnormally High Formation Pressure 1-18

3 Magnitude of Abnormally High Formation Pressures 1-30

4 Summary 1-31

Illustrations

1.6 Typical Formation Pressures caused byCompaction Disequilibrium 1-19

1.7 Interlayer Water and Cations between Clay Platelets 1-20

1.8 Schematic of Reaction of Montmorillonite to Illite 1-21

1.9 Water Distribution Curves for Shale Dehydration 1-23

1.10 Diagenetic Stages in the alteration of Montmorillonite to Illite 1-23

1.11 Abnormal Formation Pressures caused byTectonic Compressional Folding 1-24

1.12 Abnormal Pressure Distribution around a PiercementSalt Dome 1-26

1.13 Schematic Diagram of a Mud Volcano 1-26

1.14 Abnormally High Pressure due to Reservoir Structure 1-28

1.15 Schematic Diagram illustrating Osmotic Flow 1-30

1-17March 1995

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1-18March 1995

1 General

Abnormally high formation pressure is defined as any formation pressure that is greathan the hydrostatic pressure of the water occupying the formation pore spaces. Abnormallyhigh formation pressure gradients are thus any formation pressure gradient higher thanpore fluid hydrostatic pressure gradient.

Abnormally high formation pressures are also termed surpressures, overpressuressometimes geopressures. More often, they are simply called abnormal pressures.

2 Causes of Abnormally HighFormation Pressure

Abnormally high formation pressures are found worldwide in formations ranging in age␣frothe Pleistocene age (approximately 1 million years) to the Cambrian age (500 to 600␣millyears). They may occur at depths as shallow as only a few hundred feet or exceeding 20,00(6100m) and may be present in shale/sand sequences and/or massive evaporite-carbsequences.

The causes of abnormally high formation pressures are related to a combination of geologphysical, geochemical and mechanical processes, as discussed in the following paragra

(a) Depositional Causes

• Compaction Disequilibrium

Compaction disequilibrium is also known as ‘undercompaction’ or ‘sedimentarloading’. It is the process whereby abnormal formation pressures are caused bdisruption in the balance between the rate of sedimentation of clays and the rateexpulsion of the pore fluids, as the clays compact with burial.

Freshly deposited clays have adsorbed water layers and the solid clay particlesnot have direct physical contact. The pore pressure is hydrostatic as the pore fluid iscontinuous with the overlying sea water. As sedimentation proceeds, a gradualcompaction occurs and as the clay particles are pressed closer together, pore water isexpelled. The clay sediment has high porosity and is permeable in this initial statSo as long as the expelled water can escape to surface or through a porous layer, pore pressures will remain hydrostatic.

For this equilibrium to be maintained, a balance is required between the ratesedimentation and burial, and the rate of expulsion and removal of pore fluids. If trate of sedimentation is very slow, then hydrostatic pressures will be maintained.

The initial porosity of clays is 60 to 90%, depending on the type of clay, whereascompacted clay/shale has a porosity of less than 15%. Thus a vast amount of watermust be removed from clay sediments during burial. If the equilibrium between raof sedimentation and rate of fluid expulsion is disrupted, such that fluid removal impeded, then an increase in pore pressure will result. This could occur either by anincrease in the rate of sedimentation or by a reduction in the rate of fluid remov(caused by a reduction in permeability or by the deposition of a permeability barrisuch as limestone).

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1-19March 1995

The ‘excess’ pore fluids help support the increasing overburden load, theretarding compaction further, and resulting in abnormally high pressured formationAbnormal pressures resulting from this process will have a gradient no greaterthe overburden gradient. This is because these pressures are produced by the exoverburden load being supported by the pore fluids.

If beds of permeable sandstone that are hydraulically connected to zones of fluid pressure are present within an overpressured zone, adjacent clays will deto the sand bed. The adjacent clays will compact and decrease in permeability porosity thus restricting further dewatering of the clay beds. The local pressuregradient across these clay/sand boundaries will be significantly higher than the opressure gradient, but are caused purely by ‘leakage’ from the clays to the Figure 1.6 illustrates typical overpressures caused by compaction disequilibriu

Areas in which abnormal formation pressures associated with high sedimentrates have been encountered include the North Sea, the Gulf of Mexico, and theof Papua.

Figure 1.6 Typical Formation Pressures caused byCompaction Disequilibrium

DE

PT

H

PRESSURE

CLAY

Hydrostatic pore pressure

Overburden pressure

Actual formation pressure

Very high local pressure gradient adjacent to permeable zones due to low permeability of the clays

Overall formation pressure parallels the overburden pressure gradient, but may not reach extrapolated pressure gradient due to leakage from the clays

Extrapolated initial formation pressure (parallel to overburden pressure gradient)

Overpressured sandstone (hydrostatic gradient within sandstone)

SAND

CLAY

SAND

CLAY

SAND

CLAY

SAND

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1-20March 1995

• Rock Salt Deposition

Continuous rock salt deposition over large areas can cause abnormal pressures tmay approach overburden pressure. Salt is totally impermeable to fluids and behplastically at relatively low temperatures and pressures, thereby exerting presequal to the overburden load in all directions. The fluids in the underlying formationscan not escape as there is no communication to the surface and thus the formbecome overpressured.

Massive rock salt deposits are commonly found in the southern North Sea abnormally high formation pressures sometimes being encountered in formabelow or within these massive salts. For instance, one BP southern North Searequired mud weights up to 1.94 SG (0.84 psi/ft) to control a saturated salt wflow from an anhydrite formation at the boundary between the Z2 and Z3 Unitthe Zechstein halite formation.

(b) Diagenesis

Diagenesis is the alteration of sediments and their constituent minerals during bafter deposition. Diagenetic processes include the formation of new minerals,redistribution and recrystallisation of the substances within the sediments, lithification (sediments turning into rocks).

Figure 1.7 Interlayer W ater and Cations betweenClay Platelets

H

O

O

OO

O

O

OOO

O

O

O O

O

O

O

O

O

H

H

H

H H

H

HHH

HH

H

H

HH

H

H

H H H H

HH

H

H

H

H

HH

CLAY SHEET

CLAY SHEETNegative Charge

Imbalance

1 or 2 Layers of Adsorbed Water

H

H

HHHH

Ca + +

Ca + +

Ca + +

Na +

Na +

Na +

About 4 Layers of Structured Water

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1-21March 1995

• Clay Diagenesis

The major constituents of marine shales are bentonitic clays of which montmorillois by far the most common. Montmorillonite has a swelling (expanded) lattstructure and contains approximately 70 to 85% water at initial burial in sea fsediments. This water is present in the form of at least four layers of molecuadsorbed between clay platelets and up to ten layers held on the outside of the plaThe clay platelets have a negative charge imbalance due to their structure. This causesthe adsorption of interlayer water together with various cations (positively chargedions), principally sodium (Na+) and calcium (Ca++). The interlayer water is shownschematically in Figure 1.7.

The environment at this initial burial stage would be alkaline, rich in calcium amagnesium (and of course sodium from salt water), but poor in potassium.

After further burial, compaction expels most of the free pore water (non-adsorband the water content of the sediment is reduced to about 30%. As burial progressesand the temperature increases, eventually all but the last layer of structured (adsowater will be desorbed to the pore spaces. This causes the clay lattice to collapse anwith the availability of potassium, montmorillonite diagenesis to illite occurs. Thisreaction is shown schematically in Figure 1.8. It involves adsorption of potassiuthe interlayer and surface sites as well as the release of a small amount of sili

Figure 1.8 Schematic of Reaction of Montmorillonite to Illite

O

A +

K

W

M= Oxygen

= Silicon

= Hydroxyl (OH)

= Aluminium

ILLITE

MONTMORILLONITE

Ky AL4 (Si8-y, Aly) O20 (OH)4

(Al4-x Mgx)(Si8-y, Aly) O20 (OH)4Negatively charged plates satisfied by interlayer water and cation adsorption

3 LAYER SHEET

INTERLAYER SITES

3 LAYER SHEET

= Magnesium

= Water

= Potassium

= Cation eg Ca ++, Na+

A

A

O

O

K

A

A

A

O

O

M

A

O

O

A

A

W W W

W W

+ W

WW

W W

W +

W

W

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O

O

Add K Substitute Al for Si and Mg

Charge Satisfied

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The reaction is temperature (and hence depth) dependent. Initial dehydration occur at temperatures as low as 6°C. Most of the interlayer water is liberated between100°C and 250°C, but some of the more structured water remains to about 300°C.Water distribution curves showing the various shale dehydration stages are showFigure 1.9.

At the second dehydration stage (See Figure 1.9), the water that is released expdue to a density reduction from the highly structured phase to the pore phase. Thusabnormally high pressures may result, particularly if the rate of expulsion of frpore water from the clay body is less than the rate of water release from the interlayers. Figure 1.10 is a schematic diagram showing the stages of alteratiomontmorillonite to illite.

If water escape from the clay body is restricted, the silica released in the diagenprocess will precipitate in the pore spaces. This may further reduce permeability andso assist in developing abnormal pressures.

• Sulphate Diagenesis

Diagenesis in sulphate formations (gypsum, anhydrite) may cause abnormal pressby creating permeability barriers, a fluid source and/or a rock volume chanCarbonate reservoirs are commonly overlain by evaporite sections (salt, anhydr

Anhydrite (calcium sulphate, CaSO4) is formed by the dehydration of gypsu(CaSO4.2 H2O) which liberates large amounts of water. There is a 30% to 40%shrinkage in formation thickness associated with this process. If this occurs at deand in the presence of a permeability barrier, abnormal formation pressures mayresult. (The anhydrite itself is totally impermeable and may act as a verticpermeability barrier.)

This process may have been the cause of the high pressure salt water flow discuunder ‘Rock Salt Deposition’ in (a) ‘Depositional Causes’. Here, a mud weight of1.94 SG (0.84 psi/ft) was required to control a saturated salt water flow from anhydrite section sandwiched between massive salt sections.

The process is, however, reversible. Anhydrite can take on water to form gypsum.There is an intermediate semi-hydrate stage (CaSO4.1/2 H2O) in which the rock volumewould increase by 15 to 25%. If such rehydration was to occur at depth in a closystem, very high abnormal pressures could be developed.

• Diagenesis of Volcanic Ash

Diagenesis of volcanic ash results in three main products: clay minerals, methand carbon dioxide. Thus formations that originally contained large amounts ofvolcanic ash may become overpressured due to the production of gases fromvolcanic ash.

Areas in which this process has occurred include the NW coast of the USA and aof the South China Sea region (Java, etc).

1-22March 1995


1-23March 1995

Figure 1.9 Water Distribution Curves for Shale Dehydration

Figure 1.10 Diagenetic Stages in the alterationof Montmorillonite to Illite

PORE WATER

INTERLAYER WATERB

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SEDIMENT SURFACE

PORE AND INTERLAYER WATER EXPULSION

1st DEHYDRATION AND LATTICE WATER

STABILITY ZONE

2nd DEHYD'N

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STAGE 1

Before diagenesis (about 3000 – 6000ft, below 60°C) porosity = 20 to 35% clay is 70% montmorillonite 10 mixed layer 20% other

STAGE 2

During alteration to illite (100 – 200°C) high porosity = 30 to 40% clay is 20% montmorillonite 60% illite 20% other

STAGE 3

After diagenesis and compaction (over 200°C) porosity = 10 to 20% clay is 70% illite 10% montmorillonite 20% other

FREE PORE WATER FROM DESORBED INTERLAYER WATER

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1-24March 1995

(c) Tectonic Causes

• Compressional Folding

Tectonic compression is a compacting force that is applied horizontally in subsurformations. In normal pressure environments, clays compact and dewateequilibrium with increasing overburden pressures. However, in a tectonicenvironment, the additional horizontal compacting force (tectonic stress) squethe clays laterally. If conditions are such that the pore fluids can still escape, thpore fluid pressures will remain normal. However, it is more likely that the increasein stress will cause disequilibrium. The pore fluids will not be able to escape at rate equal to the reduction in pore volume, resulting in an increase in pore pres

Abnormal pressure distribution within a series of compressional folds is showFigure 1.11. Abnormally high pressures occur initially within the hinge portion oeach compressional fold in a thick clay sequence.

Figure 1.1 1 Abnormal Formation Pressures caused byTectonic Compressional Folding

An example of overpressures associated with steep tectonic folding is the oilfiof Southern Iran where local pressure gradients as high as 1.00 psi/ft caencountered. Also, one of the highest formation pressures reported of 1.3 psi/ft wrecorded in the tectonically folded Himalayan foothills in Pakistan.

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1-25March 1995

• Faulting

Faults may cause abnormally high formation pressures in the following ways:

– Slippage of formations along a fault may bring a permeable formation, eg abed, laterally against an impermeable formation such as a clay. Thus, the flow ofpore fluids through the permeable zone will be inhibited and abnormally formation pressures may result.

– Non-sealing faults may transmit fluids from a deeper permeable formatioa␣shallower formation. If this shallower formation is sealed, then it wbe␣pressured up by the deeper formation. (See ‘Charged Formations’ in (d)‘Structural Courses’).

• Uplift

If a normally pressured formation is suddently uplifted, abnormally high pressmay be generated. Uplift is not a unique cause of abnormal pressure as the pthat uplifts a buried formation will also uplift the overburden. For abnormal pressto occur, there must be a concurrent geological process that reduces the relief bethe buried formation and the surface. Such processes may be piercement salt shale diapirs, faulting or erosion.

Note that uplift and erosion may also cause subnormal formation pressures, depon the type of formation and the amount of cooling that the formation undergoes.(See ‘Temperature Reduction’ and ‘Decompressional Expansion’ in Section1.3 of this Chapter.)

• Salt Diapirism

Diapirism is the piercement of a formation by a less dense underlying formaSalt will behave plastically at elevated temperatures and pressures and duelower density, will move upwards to form piercement salt domes in overlyformations. This upward movement disturbs the normal layering of sedimentsoverpressures can often occur due to the associated faulting and folding aAdditionally, the salt may act as an impermeable seal and inhibit lateral dewatof clays thereby further contributing to the generation of abnormal pressures.

The typical distribution of abnormal pressure zones around a piercement saltis shown in Figure 1.12.

Abnormally high formation pressures associated with salt domes have encountered worldwide, both onshore and offshore.

• Shale Diapirism

As with salt diapirism, this mechanism refers to the upward movement of adense plastic formation. In this case, high porosity (high water content) sbehave␣plastically causing the formation of shale diapirs called ‘mud volcan(See Figure 1.13).

In practice, wherever mud volcanoes occur, there has been rapid Tertiary and/or lateCretaceous sedimentation. This rapidly loads underlying shales of low shear strencausing the formation of mud volcanoes. Formation pressures are abnormallyFor example, pressure gradients of 0.9 psi/ft have been measured arounvolcanoes on Aspsheron Peninsula in Azerbaidzhan, USSR.


1-26March 1995

Figure 1.12 Abnormal Pressure Distribution around aPiercement Salt Dome

Figure 1.13 Schematic Diagram of a Mud V olcano

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1-27March 1995

• Earthquakes

Earthquakes may cause compression in subsurface formations which causes a sincrease in pore fluid pressures. For example, the 1953 earthquake in Califocaused production in the nearby Mountain View oil field to double over a period ofseveral weeks after the earthquake.

(d) Structural Causes

• Piezometric Surface

This is defined in Section 1.3. A regionally high piezometric surface, such as thacaused by artesian water systems, will result in abnormally high pressures as shin Figure 1.3. Artesian systems require a porous and permeable aquifer sandwicbetween impermeable beds. The aquifer intake area must be high enough for thabnormal pressure to be caused by the hydrostatic head.

Examples of areas where abnormally high pressures are caused by artesian syare the Artesian Basin in Florida and the Great Artesian Basin in Queensland,Australia.

• Reservoir Structure

In sealed reservoir formations containing fluids of differing densities (ie water, oil,gas), formation pressures which are normal for the deepest part of the zone witransmitted to the shallower end where they will cause abnormally high pressuExamples of such formation are lenticular reservoirs, dipping formations aanticlines.

Abnormal formation pressures will only be generated if fluids less dense thanpore water are present, such as in oil/gas reservoirs. The pressure at the top of a fluidzone is given by:

PfT = PfB – [Gf X (DB X DT)] (1-15)

where PfT = formation pressure at top of zone (psi)PfB = formation pressure at bottom of zone (psi)Gf = pressure gradient of fluid in zone (psi/ft or psi/m)DT = vertical depth to top of zone (ft or m)DB = vertical depth to bottom of zone (ft or m)

In the example shown in Figure 1.14, the formation pressure at the oil/water conis normal hydrostatic pressure with a gradient of 0.452 psi/ft. Using equation 1-the pressure at the gas/oil contact is 4850 psi which gives an abnormally hformation pressure gradient of 0.462 psi/ft. Similarly, the pressure at the top of thereservoir is 4784 psi giving an abnormal gradient of 0.486 psi/ft.

Obviously, in very large structures, especially in gas/water systems with long gcolumns, the overpressures developed at the top of the gas column may be high. Indeed one documented example in Iran quotes a pressure gradient of 0.9 (approaching overburden gradient) at a depth of only 640 ft (195m).

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1-28March 1995

Figure 1.14 Abnormally High Pressure due toReservoir Structure

• Charged Formations

Normally pressured, or low pressured porous and permeable formations at shdepths, may be pressured up by communication with deeper higher presformations. This ‘charging’ of the shallower formations may take place by flucommunication along non-sealing faults behind casing in old wells, or wells faulty cement jobs, and whilst drilling a sequence of permeable formations very large differences in pore fluid pressures (causing recharge salt water flows).

Abnormal pressures caused by recharge can be very high, especially if gas is thmedium that transmits the pressure (same mechanics as gas reservoir in ‘ResStructure’, but over greater depth differences). Mud weights as high as 19 pp(2.28␣SG, 0.988 psi/ft) have been quoted as sometimes required for drilling thrshallow charged zones.

(e) Thermodynamic Effects

Thermodynamic processes may be considered as contributing factors in most causes of abnormally high formation pressure already discussed. Formation tempeincreases with depth in any geological system and if the system is essentially cthermodynamic effects will add to the build up of abnormal pressures.

• Aquathermal Pressuring

Referring to the temperature-pressure-density diagram for water (Figure 1.temperature increase in an isolated fluid system must take place along a codensity path. The increase in pressure is thus very rapid and only small increastemperature are required to produce large overpressures.

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CAP ROCK

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9842

.

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TOP OF GAS CAP

D = 3000m (D = 9842ft)

GAS/OIL CONTACT D = 3200m

(D = 10500ft)

OIL/WATER CONTACT D = 3450m

(D = 11319ft)

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10500

.

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However, shales are not totally impermeable and the time taken to heat the sduring burial should be sufficient to allow most of the excess pressures developeleak away. The main effect of heating during burial is to retard compaction, aaquathermal pressuring is not thought to be a major cause of abnormallyformation pressures.

• Thermal Cracking

At high temperatures and pressures caused by deep burial, complex hydrocmolecules will break down into simpler compounds. Thermal cracking ofhydrocarbons will increase the volume of the hydrocarbons in the order of twthree times the original volume. If contained in an isolated system, this would rin high overpressures being developed. However, there is no conclusive evidencthat thermal cracking is a significant cause of abnormal formation pressures.

• Permafrost

In arctic regions, drilling and production operations may cause extensive thawithe permafrost. If this thawed permafrost refreezes later in the life of the ‘freezeback’ pressures, high enough to damage the casing, may result. Obvio,this situation may be avoided by proper well planning and casing design.

Freezeback pressure gradients ranging from 0.66 psi/ft to as high as 1.44 psi/fbeen recorded in Alaska.

• Osmosis

As defined in Section 1.3, osmosis is the spontaneous flow of water from a mdilute to a more concentrated solution when the two are separated by a susemi-permeable membrane. This action is represented schematically in Figure 1.

For a given solution, the osmotic pressure (differential pressure across the membranis almost directly proportional to the concentration differential; and fora␣given␣concentration differential the osmotic pressure increases with temperatTheoretically, osmotic pressures of up to 4500 psi can be produced acrosemi-permeable membrane with solutions of 1.02 gm/cc NaCl in water and satuNaCl␣brine.

Clay and clayey siltstone beds can act as semi-permeable membranes. If sdifferences exist in the sediments above and below such beds, then osmotic flooccur. If the flow is into an isolated system, then a pressure increase will occthis system. Alternatively, the osmotic pressure developed across these bedsinhibit the vertical flow of water from compacting shales, thereby contributingthe development of abnormal pressures.

However, the efficiency of clay beds as semi-permeable membranes in the sub-suenvironment is unknown. It is thus currently believed that osmosis is a minor cof abnormal formation pressures.

1-29March 1995

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1-30March 1995

Figure 1.15 Schematic Diagram illustrating Osmotic Flow

3 Magnitude of Abnormally HighFormation Pressures

As defined, the magnitude of abnormally high formation pressures must be greater thnormal hydrostatic pressure for the location, and may be as high as the overburden prAbnormally high pressure gradients will thus be between the normal hydrostatic gra(0.433 to 0.465 psi/ft) and the overburden gradient (generally 1.0 psi/ft).

However, locally confined pore pressure gradients exceeding the overburden gradientto 40% are known in areas such as Pakistan, Iran, Papua New Guinea, and the USSRThesesuperpressures can only exist because the internal strength of the rock overlyinsuperpressured zone assists the overburden load in containing the pressure. The overlyingrock can be considered to be in tension.

In the Himalayan foothills in Pakistan, formation pressure gradients of 1.3 psi/ft haveencountered. In Iran, gradients of 1.0 psi/ft are common and in Papua New Guinea, a gof 1.04 psi/ft has been reported. In one area of Russia, local formation pressures range of 5870 to 7350 psi at 5250 ft (1600m) were reported. This equates to a formationpressure gradient of 1.12 to 1.4 psi/ft.

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In the North Sea abnormal pressures occur with widely varying magnitudes in mgeological formations.

The Tertiary sediments are mainly clays and may be overpressured for much of their thicPressure gradients of 0.52 psi/ft are common with locally occurring gradients of 0.8 being encountered. An expandable clay (gumbo) also occurs which is of volcanic origin is still undergoing compaction. The consequent decrease in clay density would normindicate an abnormal pressure zone but this is not the case. However, in some areas, mudweights of the order of 0.62 psi/ft (1.43 SG) or higher are required to keep the welopen because of the swelling nature of these clays. This is almost equal to the low overburdegradients in these areas.

In the Mesozoic clays of the Central Graben, overpressures of 0.9 psi/ft have been recOne BP well encountered a formation pressure gradient of 0.91 psi/ft in the Jurassic sIn the Jurassic of the Viking Graben, abnormal formation pressure gradients up to 0.69␣phave been recorded.

In Triassic sediments, abnormally high formation pressures have been found in gas bzones of the Bunter Sandstone in the southern North Sea. Also in the southern North Seaoverpressures are often found in Permian carbonates, evaporates and sandstones sanbetween massive Zechstein salts.

4 Summary

Of all the processes that may be responsible for causing abnormally high formation preit is unlikely that any one will be the sole cause in any particular area. The effects of severalprocesses will probably combine to cause the observed abnormal pressure.

Certain processes are thought to be either ineffective or uncommon as causes of abnormpressures. These include uplift (as a sole mechanism), osmosis, thermal cracking, permand earthquakes. A recent report(6) has found that the most significant cause of abnormahigh formation pressures in depositional basins is compaction disequilibrium, aquathermal pressuring contributing to a small extent. Clay dewatering (diagenesisfound to have little effect. However conditions within clays during dewatering are vesimilar to these developed during undercompaction; and the two processes probablyconcurrently, while undercompaction is recognised as the primary mechanism.

The significance of aquathermal pressuring as a cause of abnormal pressure is tempand hence depth dependent. This is also true of the diagenetic process.

With increasing depth aquathermal pressuring is thought to be a contributory factorcases of abnormal pressure generation.

1-31/32


1.5 SHALLOW GAS

Paragraph Page

1 General 1-34

2 Definition 1-34

3 Origins of Shallow Gas 1-34

4 Characteristics of Shallow Gas 1-35

1-33March 1995

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1-34March 1995

1 General

Shallow gas accumulations present a major hazard to drilling operations. Gas influxesat shallow depths cannot generally be shut-in for fear that the pressures involved will frathe formation at the previous casing shoe, thereby causing an underground blowout, or flowaround the casing to the seabed.

2 Definition

For the purposes of drilling operations, shallow gas can be defined as any gas accumencountered at any depth before the first pressure containment casing string is set.

For well planning purposes, possible gas bearing zones at shallow depths may be idefrom shallow seismic sections (‘bright spot’ technique – See Section 2.2 of Chapter 2).These are normally used down to a depth of about 1000m below surface or mudline.

3 Origins of Shallow Gas

There are two potential origins of shallow gas:

(a) Biogenic Generation

This is the production of gas at shallow depths of burial from the degradation of organicmatter within the sediment. An example of this would be the Pleistocene section of North Sea which contains some organic rich clays and occasional peat/lignite formationThus a biogenic origin is considered likely for shallow gas accumulations inNorth␣Sea.

(b) Petrogenic Generation

This is the thermocatalytic degradation of kerogen which occurs under conditioelevated temperature and pressure at greater depths. (Kerogen is a complex hydroformed from the biogenic degradation of organic matter which also gives gas as statabove.) Sufficient depth of burial to produce the heat necessary for this process to opis probably not reached in the shallow depths considered here ie down to 1000m

However, migration of gas from deeper petrogenic sources may be possible. This couldoccur naturally, along non-sealing faults for example, or even through the natpermeability of clays at shallow depths. Alternatively, artificial migration paths may beproduced in poorly cemented casing annuli allowing gas from petrogenic sourcaccumulate in shallower formations. This could result in shallow gas accumulationforming later in the life of a producing field when early wells showed no indicationshallow gas.

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1-35March 1995

4 Characteristics of Shallow Gas

(a) Composition

Shallow (biogenic) gas has the following typical composition (provided by BP/Sunbu

99% + methane (CH4)0.5% carbon dioxide (CO2)

less than 0.5% nitrogen (N2)less than 0.1% ethane (C2H6) and higher hydrocarbons.

Hydrogen sulphide (H2S) may also be present.

Petrogenic gas associated with the generation of oil should contain a larger proportionof ethane and higher hydrocarbons.

(b) Configuration of Shallow Gas Accumulations

Shallow gas accumulations are commonly found in sand lenses which are inferrhave been deposited in a shallow marine shelf environment with tidal influence. Inenvironment, the sands would tend to be in the form of sand waves, sand patcheridges resulting in a discontinuous and patchy distribution. These sand lenses couldthus be sealed by the surrounding clay sediments.

This patchy distribution of shallow gas is very important. It must not be assumedbecause several wells have penetrated a potential shallow gas zone successfull, thenall future wells will also be free of shallow gas hazards.

(c) Pressures and Volumes

Most shallow gas accumulations tend to be normally pressured. However, the classicarea where overpressured shallow gas sands are encountered is the Gulf of MUSA. In this area, overpressuring is thought to be the result of undercompactioshales due to rapid deposition (See ‘Compaction Disequilibrium’, Section 1.4 of thisChapter.)

One instance of overpressured shallow gas in the North Sea was reported for a wthe SE Forties area where a gas kick from a sand at about 800m subsea gave a calformation pressure gradient of at least 1.20 SG (0.52 psi/ft). Shallow gas accumularesulting from migration of petrogenic gas may well be overpressured (See ‘ChagedFormations’, Section 1.4). Also, overpressured shallow gas may result from long ‘tiltesand lenses, in an identical manner to that described under ’Reservoir Structure’in Section 1.4.

It is difficult to estimate the volumes of gas present in shallow gas accumulatiHowever, estimates have been made from shallow gas discharges. In one North Seaincident, it has been estimated that 8 mmscf of gas was vented. At a depth of about410m subsea and 600 psi pressure, this corresponds to a bulk rock volume of 2cubic metres, assuming a porosity of 30%. For a 5m thick sand, this correspondsarea of only 70m in diameter.

The flowrate of gas in the above incident was estimated at 40 to 50 mmscfd. Flowof over 100 mmscfd have been reported for shallow gas blowouts in the Gulf of MexThese high flowrates are as a result of the high porosity and permeability in shalarge grain sand deposits.

g

g


Suggestions for further reading:

1. ‘EXLOG’, 1981. Theory and Evaluation of Formation Pressures. Exploration LogginInc., USA.

2. ‘EXXON’, 1975 Abnormal Pressure Technology. Exxon Company, USA.

3. FERTL, W.H., 1976. Abnormal Formation Pressures. Elsevier Scientific PublishinCompany, Amsterdam.

4. FERTL, W.H. and CHILINGARIAN, G.V., 1976. Importance of Abnormal Pressures tothe Oil Industry. Soc. Petrol. Eng., Paper 5946.

5. ‘GEARHART’, 1986. Overpressure. Gearhart Geodata Services Ltd., Aberdeen.

6. MANN, D.M., 1985. The Generation of Overpressures During Sedimentation and TheirEffects on the Primary Migration of Petroleum. Report GCB/156/85. BP Research Centre,Sunbury.

7. SELLEY, R.C., 1985. Elements of Petroleum Geology. W.H. Freeman and Company,New York.

8. SHEPHERD, M., 1984. Forties Field: Shallow Gas Hazards in the Main Field Area.Report GL/AB/1880. BPPD Aberdeen.

1-36March 1995


2 FORMATION PRESSURE EVALUATION

Section


2.2 FORMATION PRESSURE EVALUATIONDURING WELL PLANNING 2-5

2.3 FORMATION PRESSURE EVALUATIONWHILST DRILLING 2-23

2.4 FORMATION PRESSURE EVALUATIONAFTER DRILLING 2-65

March 1995


2.1 INTRODUCTION

Paragraph Page

1 General 2-2

2 The Transition Zone 2-2

Table

2.1 Techniques used to Predict, Detect and EvaluateFormation Pore Pressures 2-3

2-1March 1995

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2-2March 1995

1 General

Knowledge of formation pore pressure is of prime importance in the planning, drillingevaluation of a well. Good estimates of formation pore pressures and fracture pressurequired to optimise casing and mud weight programmes, and to minimise the risk okicks, stuck pipe, lost circulation and other costly drilling problems.

The following sections describe the techniques used to predict, detect and evaluate fopore pressures at the various stages of drilling a well. Table 2.1 summarises these techniquMethods for predicting and evaluating fracture pressure are covered separately in section of this Manual.

Abnormally high pressured zones are by far the most common encountered, and thimportant, in drilling operations. This Chapter is therefore mainly concerned with methof predicting, detecting and evaluating abnormally high formation pressures.

2 The Transition Zone

Formation pressure gradients are considered to be the normal hydrostatic gradientarea until a depth is reached where various pressure indicators suggest the onset ofsubnormally or an abnormally high pressured zone. The zone in which the formation pressugradient changes from normal to subnormal or abnormally high gradient is known transition zone.

In shales, the transition zone is the equivalent of the pressure seal discussed in Section 1.1of Chapter 1. Since perfect seals of zero permeability rarely occur (except, for examsalt and anhydrite), transition zones are normally present. The differential pressure acrosstransition zone causes pore fluid flow through the transition zone. However, the flow ratethrough the zone will be extremely low, due to the very low permeability within the zonThe thickness of the transition zone depends on the permeabilities within and adjathe overpressured formation and the age of the overpressure ie, the time available fflow and pressure depletion since the overpressure developed.

The presence of the transition zone is very important in formation pressure evaluFormation properties in this zone often show a change away from normally pressuredrelated trends. The magnitude of the change in the trend can sometimes be used to esthe change in the formation pressure gradient. The parameters used to monitor the trendsformation properties are listed in Table 2.1. It must be realised that the start of the transizone marks the onset of abnormal pressures. Every effort must be made to recognise thstart of this zone both in well planning and during drilling.


2-3March 1995

Table 2.1 Techniques used to Predict, Detect andEvaluate Formation Pore Pressures

Data Source Pressure Data/Indicators Stage of W ell

Offset wells Mudloggers reports Planning (also used forMud weights used comparisons whilst drilling)Kick dataWireline log dataWireline formation test dataDrillstem test data

Geophysics Seismic (interval velocity) Planning

Drilling Drilling rate While drillingparameters Drilling exponents

Other drilling rate methodsTorqueDragMWD logs

Drilling mud Gas levels While drilling (delayed byparameters Flowline mud weight the time required for mud

Flowline temperature return)Resistivity, salinity andother mud propertiesWell kicksPit levelsHole fill-upMud flow rate

Cuttings Bulk density While drilling (delayed byparameters Shale factor the time required for mud

Volume, shape and size return)Miscellaneous methods

Wireline logs Sonic (int. transit time) After drillingResistivity logDensity logOther logs

Direct pressure Wireline tests (RFT/FIT) Well testing or completionmeasurements Drillstem tests

2-3/4


2-5March 1995

2.2 FORMATION PRESSUREEVALUATION DURING WELL PLANNING

Paragraph Page

1 General 2-6

2 Offset Well Data 2-6

3 Seismic Data 2-8

3.1 Abnormal Pressure Evaluation from Seismic Data 2-9

3.2 Identifying Shallow Gas Hazards 2-20

4 Summary 2-21

Illustrations

2.1 Pressure/Depth Plot 2-7

2.2 Schematic Diagram illustrating Seismic Reflection Systemand Seismic Traces 2-9

2.3 Schematic Diagram showing Common Depth Point(CDP) Seismic Ray Paths 2-10

2.4 Schematic Plot of Offset versus Two Way Travel Timefor Common Depth Point System 2-11

2.5 Example Seismic Velocity Analysis Plot 2-13

2.6 Example of Stacking Velocity Data on a Seismic Section 2-14

2.7 Seismic and Sonic ITT versus Depth Plots forAbnormally Pressured Well 2-17

2.8 Log-log Plot of Seismic Interval Transit Time 2-18

2.9 ITT Departure versus Formation Pressure Gradient 2-19

2.10 ITT Ratio versus Formation Pressure Gradient 2-20

2.11 Example of Drilling Hazard Log over Shallow Section 2-22

Table

2.2 Calculation of Depths and Interval Transit Times 2-16

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2-6March 1995

1 General

At the planning stage of a well, several early decisions are made that are directly influby the predicted formation pore pressure profile for the well. The magnitude of the expecteformation pressure influences the pressure rating of the casing and wellhead/BOP equto be used, and can ultimately influence drilling rig selection. Casing programme dand mud weight programmes should be tailored to the predicted formation pressurthe␣well.

Other related aspects of well planning that are influenced include, cement programcompletion equipment, contingency stocks of casing, and mud chemicals/baryte stobe held.

Thus, accurate formation pressure predictions are required in order to optimise well plaGood well planning will, in turn, help to minimise the risk of costly problems whilst drillin

There are normally (but not always) two sources of formation pressure information fowell location being considered. The first and most widely used is offset well data. However,in areas where there are no offset wells or they are considered to be too far away to greasonable data, then seismic data may be used to predict formation pore pressures. analysis may also be useful in validating offset well data for the location being considere

2 Offset Well Data

Pressure data from nearby wells are commonly used to predict the pore pressure pThe data are often direct measurements which will give accurate pressures for the paroffset well location. Pressures can also be calculated or inferred from other well data avain well reports. The most commonly used sources of pressure data from offset wells arelisted at the top of Table 2.1. The methods used to calculate formation pressures from owell data, such as wireline logs, are described in Sections 2.3 and 2.4.

The measured and calculated/inferred formation pressures are then applied to theformations in the well being planned. Additional information, such as the pressure gradieof the expected reservoir fluid, is also used to finally arrive at a predicted formation preprofile for the well. This information is presented as a pressure depth plot, an exampwhich is shown in Figure 2.1. (Fracture pressure information is also presented in theof formation leak off tests from offset wells.)

The accuracy of the pore pressure prediction from offset well data will depend on the typeof well that is to be drilled. The following two cases can be considered:

• Appraisal/development wells

The offset well data should usually be reliable as the offset wells will normally be fairlyclose to the proposed well location and usually drilled on the same structuredevelopment wells, the pore pressure profile should be accurately defined fromfrom the appraisal wells.


2-7March 1995

Figure 2.1 Pressure/Depth Plot

15000130001100090007000500030001000 1400012000100008000

PRESSURE (psi)

6000400020000

5500

5000

4500

4000

3500

TE

RT

IAR

Y T

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TC

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oceneU

pperU

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DE

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m)

Leak Off Test 30/4–1

Leak Off Test 30/4–2

Predicted Formation Pressure 3/10b-a

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3000

2500

2000

1500

1000

500

0

WELL No: AREA:

3/10b-a UKCS North

1.4 1.5 1.6 1.7 1.8 1.9

2.611.128

1.085

1.042

0.998

0.955

0.911

2.51

2.41

2.31

2.21

2.1

1.0SG EQUIVALENT

psi ft

SG

EQ

UIV

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T

psi

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0.477 0.564 0.651 0.738

0.434 0.521 0.607 0.694 0.781

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2-8March 1995

• Exploration wells

In well explored regions, such as certain areas of the North Sea, the offset well datashould be reliable enough for a good estimate to be made of the pore pressure for the proposed exploration well. However, if the nearest offset wells are far away,then the pressure data should be treated with caution when applying it to the prowell. If there are insufficient pressure data available for any one profile to be predicthen the alternatives should be considered and the ‘worst case’ evaluated foparticular aspect of well planning.

Analysis of seismic data may be required to back-up the pressure profile predictedoffset wells. In areas where there is no offset well information or they are too far awato be of any use, then seismic data analysis may be the only method available to the pore pressure profile (See Paragraph 3, ‘Seismic Data’).

In exploration areas where there is a well established Company office, the predicted pressurprofile is usually compiled by the Designated Resident Geologist (DRG) for the well.Thepressure depth plot should be obtained as soon as possible and the data must be immediately by the Drilling Engineer responsible for planning the well. The DE must ensurethat the pressure data is the best available, whilst also accepting that the accuracydata will vary depending on the number and proximity of nearby wells.

In areas where there is no established exploration office, or where the pressure profile irequired prior to compilation by the DRG, then the well planning DE will have to prethe formation pressure profile. The DRG or Area Geology Group must be consulted. TheDRG or Area Geology Group will determine which offset wells are most ‘geologicallysimilar’ to the proposed well and hence the best source of formation pressure dataAlso,geological features such as faults and unconformities in the area will be identified. Thesemay affect the way in which the pressure data are applied to the proposed well.

Notes on formation pressures from offset wells are often given in the ‘Drilling Proposadocument, together with the lithological prognosis and other pertinent data (well locatarget depths, total depth etc). Petroleum Engineers should also be consulted, as thhave additional pressure information, especially regarding expected reservoir pressu

3 Seismic Data

In hydrocarbon exploration, seismic data are mainly used to identify and map prospreservoir traps and to estimate the depths of formation tops in the lithological column. Sedata can also be used to predict formation pressures quantitatively, or at least to give anindication of the entrance into abnormally high pressures. In new or relatively unexpareas, seismic data are often the only information available from which pore pressurcan be derived.

Seismic data can also be used to indicate the possible presence of shallow gas bearinThis is done using data from high resolution shallow seismic surveys which are norused down to a maximum depth of about 1000m below surface or the mudline.

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2-9March 1995

3.1 Abnormal Pressure Evaluation from Seismic Data

(a) Basic Theory

A seismic wave is an acoustic wave propagated in a solid material - normally a roThe velocity at which the wave travels depends upon the density and elasticity ofrock, and the type of fluid occupying the pore spaces of the rock. Thus the formationtype, formation fluid type, and degree of compaction (ie depth) will determine the seisvelocity in an particular formation.

Knowledge of seismic velocities in particular formations over a range of depths enageophysicists to make fairly reliable formation lithology predictions from seismic daIt is also the seismic velocity of shale sequences that permits the use of seismic dapredicting the presence of overpressured formations, and to estimate the magnituthe overpressure.

Figure 2.2 Schematic Diagram illustrating SeismicReflection System and Seismic T races

Geophones

Shot Moment

First breaks

Tim

e

Reflecting Beds

Interval Velocities

A

B

C

V1

1 2 3 4

Up

hole

tim

e

5 6

Refl A

Refl B

Refl C

7 8 9 10 11 12

V2

V3

Geophones

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2-10March 1995

With increasing depth and compaction, the density and elasticity of shales increwhich results in increasing seismic velocity with depth. Overpressured shalesundercompacted. This results in lower density and elasticity for that depth. The seismicvelocity in overpressured shales is thus lower than in normally pressured shales at sdepths. Thus we need formation interval seismic velocity data to detect and evaloverpressured shales. These data are readily available from seismic surveys.

Seismic data are acquired by creating acoustic waves, by some form of explo(or␣implosion), and measuring the time taken for the wave to travel down to subsureflecting beds and back to the surface. The surface point of origin of the wave iscalled␣the shot point and the reflected waves are detected at surface by a sergeophone (or hydrophones if offshore) placed at known distances from the shot poiThe system is shown schematically in Figure 2.2, together with the seismic trrecorded by the geophones. The whole system is moved across the surface and measurements are repeated from a new shot point. The process is continued along pre-determined ‘seismic line’.

By using the geometric relationships between the shot points and geophone positiois possible to identify a series of seismic traces that have approximately the reflection point on a reflecting bed. This point is known as a common depth point (CDPand the seismic paths associated with this point are shown in Figure 2.3. For cl,only the first reflecting bed is shown, but obviously the deeper reflecting beds will have corresponding CDPs vertically below, the reflections from which will appear onthe series of seismic traces. The distance between the shot point and any particugeophone is termed the ‘offset’.

Figure 2.3 Schematic Diagram showing Common DepthPoint (CDP) Seismic Ray Paths

COMMON DEPTH POINT (CDP)

Reflecting bed A

SurfaceGeophones

Offset

Shot Points


2-11March 1995

Figure 2.4 Schematic Plot of Offset versus T wo Way TravelTime for Common Depth Point System

E

Ref

lect

ing

Bed

s

Tim

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Offset, x

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The equations of the dashed lines through the seismic reflections are of the form:

x = V Ã t2 - to2

where to V

Thus the stacking velocity, V, is the variable defining the hyperbolae which best fit the seismic reflections.

= vertical two way reflection time to reflecting beds (ie offset, x = o) = stacking velocity (average velocity)

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2-12March 1995

In practice, the seismic traces from the same CDP are collected together to form a ‘gather’in which seismic traces at the various offsets are plotted against the reflection time. Asimplified schematic plot of offset versus reflection time is shown in Figure 2.4. Withgreater offset, the path length of the wave is longer (See Figure 2.3) and the reflectime for the same reflecting bed increases. Curves can be drawn through the peathe seismic traces, corresponding to the same reflecting beds, as shown by the dlines in Figure 2.4.

The geometry of the CDP seismic system is such that the equation of the curve ththe seismic peaks (known as a ‘seismic event’) from a horizontal reflector shouldhyperbola. The variable defining the shape of the hyperbola is called the ‘stackvelocity’ or the ‘normal moveout velocity’. In practice, the peaks on the seismic trado not lie exactly on a hyperbola. Velocity analyses are performed to determine thvelocity value that gives a ‘best fit’ hyperbola to the data. This is done by investigatingthe hyperbolic function with a range of stacking velocities at increasing time incremeand comparing the result to the actual data from the seismic traces on the gather.

The results from the velocity analysis are output in the form of a plot of stacking veloversus reflection times. A typical example plot from an actual analysis is shown Figure 2.5. The plot appears as a series of ‘contours’ defining a number of ‘peaks’. Dueto the mathematical computations involved in the analysis, the peaks represent thefit’ stacking velocity values and the corresponding vertical two-way reflection timfor each reflecting bed.

The stacking velocities obtained are not the true average velocities from the surfathe reflecting bed. However, the stacking velocity is usually considered to approximato the root mean square (RMS) velocity (as indicated on the horizontal axis in FigureThe RMS velocity is the average velocity along the actual path of the seismic wavmany cases, this is also considered to be equal to the vertical average velocity frosurface to the subsurface reflecting bed. Thus, the velocity-time pairs (as they are calledfrom the velocity analysis can be used to calculate the depths of the reflecting be

The stacking velocities are used to compute the vertical two-way reflection timeseach of the seismic traces on the seismic gather. The seismic gather can then be ‘stacketo form one ‘complete’ seismic trace for that particular CDP. A seismic section is thenproduced by displaying the stacked traces for each CDP along a seismic line.

The stacking or RMS velocities are also used to calculate the interval velocities betreflecting beds, which is the property that we require to detect and evaluate abnopressure.

(b) The Method

Before attempting to predict a formation pore pressure profile from seismic dataDrilling Engineer must discuss the seismic data and velocity analyses with the AreaGeophysicist and Geologist. This will help to identify potential problems such as pooseismic data, lithology complications, errors introduced by formation dip, etc. The DEshould then have a better understanding of the problems involved in predicting apressure profile for the well being planned.

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Exam

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4000

6000

5000

8000

7000

9000

10000

11000

12000

13000

0.0

0.2

0.4

RM

S V

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OC

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(ft/sec)

0.6

0.8

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1.6

1.8

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TWO-WAY TRAVEL TIME (millisecs)

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02.082


Figure 2.6 Example of Stacking V elocity Data on aSeismic Section

0 200 300 650

1150 1450 1700 1850 2050 2200 2350 3100 5000

1470 1470 1527 1685 1986 2218 2368 2668 2750 2850 2851 2930 3150

1470 1635 1809 2320 2942 3098 4923 3416 3972 2866 3165 3479

SP 561

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2-15March 1995

The first step in the method is to obtain the stacking velocity data for a range of near to the proposed well location. The stacking velocities used for these CDPs shobe given in panels displayed above the surface line on the seismic section. An exampleis shown in Figure 2.6.

At this point, it is worth checking the stacking velocities given in the panels againvelocities obtained from the CDP velocity analyses. This is because stacking velocitieare chosen to produce a good CDP stack (‘clean’ appearance) and may not be ethe values that would be obtained from a velocity analysis such as that in Figure Ageophysicist should be consulted to decide which stacking velocities should bealthough more often than not, the velocities given in the panel on the seismic swill suffice.

The interval velocities are then calculated from the two-way time and stacking ve(average velocity) using Dix’s formula:

(V i12)2 = t2(V2)2 – t1(V1)2

t2 – t1 (2-1)

where Vi12 = interval velocity between reflecting beds 1 and 2 (m/s)t1 = two-way travel time for reflecting bed 1 (s)t2 = two-way travel time for reflecting bed 2 (s)V1 = average velocity to reflecting bed 1 (m/s)V2 = average velocity to reflecting bed 2 (m/s)

In the example shown in Figure 2.6, the interval velocities have already been comusing Dix’s formula. The depths to the reflecting beds are calculated from:

D = t.V (2-2)2

where D = depth of the reflecting bed (m)t = two-way travel time for the reflecting bed (s)V = average velocity to reflecting bed (m/s)

Note that the two-way time in the panel in Figure 2.6 is given in milliseconds (ms).Thisneeds to be converted to seconds for use in equation (2-2) (1ms = 103 sec).

A table should be drawn up as shown in Table 2.2. The final step in the calculations is tconvert interval velocities, a term used by geophysicists, into interval transit times wis a term more familiar to drilling engineers. This is done by simply taking the reciprocof the interval velocity. Note that interval transit times are expressed in micro-secoper metre (µsec/m) (1µsec = 10-6 sec).

A plot of interval transit time (ITT) versus depth can then be constructed. The intervaltransit time is plotted as a vertical line over the depth interval, for which it was calcuThis results in a plot similar to a sonic log plot but in which the data are averagedlong sections and not, as with the wireline sonic log, over a few feet only. A plot of thedata from Table 2.2 is shown in Figure 2.7. The corresponding wireline sonic log plot also shown for comparison. Note that ITT is plotted on a logarithmic scale and depa linear scale. The types of scales that are used are discussed further i‘ Interpretation’.

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2-16March 1995

Two-way Average Depth Int. velocity Int. transittime (stacking) (Dix’ s formula) time

velocityt V D Vi ∆t i

(millisecs) (m/s) (m) (m/s) (µsec/m)

0 1470 0 1470 680

200 1470 147 1635 612

300 1527 229 1809 553

650 1685 548 2320 431

1150 1986 1142 2942 340

1450 2218 1608 3098 324

1700 2368 2013 4923 203

1850 2668 2468 3416 293

2050 2750 2819 3972 252

2200 2850 3135 2866 349

2350 2851 3350 3165 316

3100 2930 4542 3479 287

5000 3150 7875

Table 2.2 Calculation of Depths and Interval T ransit T imes

(c) Interpretation

As stated, overpressured shales have lower interval velocities, and therefore hinterval transit times than normally pressured shales at the same depth. The normalshale compaction trend line on the ITT depth plot decreases with depth. Thus an increasein interval transit time away from the normal trend line indicates the presence of abnopressures. This is shown by the shaded section in Figure 2.7. From the seismic ITT plot(‘stepped’ profile), the top of the abnormal pressures would probably be estimated at 2300m to 2500m. When the well was drilled the top of the abnormal pressures wfound to be at about 2000m.

There is a certain amount of conflict surrounding the types of scale that should befor plotting ITT data. The format used in Figure 2.7 assumes that the normal compactrend is a straight line on semi-logarithmic scales. This method is recommended byFertl(17), as it enables ITT data to be directly compared with other pressure indicathat are plotted using the same linear depth scale (composite plots). Alternatively,Pennebaker(25) suggested that the normal compaction trend should be a straight linlog-log scales. An example plot of this format is shown in Figure 2.8.


2-17March 1995

Figure 2.7 Seismic and Sonic ITT versus Depth Plots forAbnormally Pressured W ell

��

mudstone and siltstone

800600500400300200100

4500

4000

3500

3000

Nor

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com

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ion

tren

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e

2500

2000

DE

PT

H (

met

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Overpressure Top:

SEISMIC DATA

SONIC LOG

Actual

Predicted

INTERVAL TRANSIT TIME (µsec/m)

1500

1000

500

mudstone and siltstone

sandstone

limestone

sandstone

calcareous mudstone

and siltstone

siltstone with mudstone

LITHOLOGY

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2-18March 1995

Figure 2.8 Log-log Plot of Seismic Interval T ransit T ime

Both the semi-log and log-log plots of ITT versus depth will show approximately same top of abnormal pressures. However, a major difference between the two methodsarises when the plots are used to estimate the magnitude of the abnormal presCharts relating the magnitude of formation pressures to some function of the ‘deparof the observed ITT values from the extrapolated normal ITT values are availableboth methods. For the semi-log plot, the difference between the observed and normITT values is used to estimate formation pressures from a chart such as the one sin Figure 2.9. For the log-log plot, Pennebaker(25) presented a chart that required thratio of observed ITT to normal ITT in order to estimate the magnitude of the abnorpressures, as shown in Figure 2.10.

Thus, the two methods of plotting ITT data require entirely separate empirically dericharts to estimate the magnitude of abnormal pressures. It is most important thacorrect chart is used when estimating formation pressures. The chart from onemethod should never be used with an ITT plot from the other method.

It should also be noted that different geological areas have vastly different correlationsbetween ITT departure and formation pressure (See Figure 2.9). Hence, it is important to obtain the correct correlation for the area that is being investigated. It be necessary to determine a new correlation for the area of interest. This can only bedone using actual well data on a regional basis and with the assistance of the geoland geophysicists. In completely unexplored areas, this may not be possible at al

TOP OF OVERPRESSURE

NORMAL TREND

DEPTH

T, Interval Transit Time

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2-19March 1995

Another major problem in interpreting seismic ITT plots is the placing of the norcompaction trend line. Referring to Figure 2.7, it would be most difficult to determinethe exact position and gradient of the normal compaction trend line from the sedata alone. The various non-shale lithologies affect the data quite considerably aneven with the actual sonic log from the well overplotted, the correct position ofnormal compaction trend line is still open to debate. One possible solution to this prois to make numerous seismic ITT (and sonic log ITT, if available) plots for the regionbeing investigated. It may then be possible to determine the position and gradienaverage normal compaction trend line for the region.

A full discussion of other problems associated with the interpretation of seismic ITT␣is given by Barr(2) and are further discussed in relation to sonic log plots in Section 2.4of this Chapter.

Figure 2.9 ITT Departure versus FormationPressure Gradient

To summarise, seismic ITT data may be of use in determining the possible existencoverpressures at the planned well location. Depending on the degree of knowledcompaction trends/formation pressure relationships for the area, it may be possuse the seismic ITT data to estimate the magnitude of formation pressures. Howev, itmust not be assumed that abnormal pressures do not exist because of a lack of indfrom the seismic ITT data. The construction and interpretation of seismic ITT plotsshould always be done in conjunction with the local geophysicists and geologists

WEOX02.086

SONIC LOG DEPARTURE

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GR

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T p

si/f

t

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T M

UD

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T S

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tabnormal pressured

shale

(FRIO, VICKSBURG, AND WILCOX – SOUTH TEXAS GULF COAST AREAS)

GULF COAST

GU

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T 2 VICKSBURG

WILCOX

FRIO

WEST TEXAS DELAWARE BASIN

SOUTH CHIN

A SEA

NORTH SEA

t , u sec/ft–normal

pressured shale

1.0

0.9

0.8

0.7

0.6

0.5

0.4

0 10 20 30 40 50 60 70 80

1.00

1.25

1.50

1.75

2.00

2.25

sed tobrighthapsetresions

2.087


2-20March 1995

Figure 2.10 ITT Ratio versus Formation Pressure Gradient

3.2 Identifying Shallow Gas Hazards

Detailed high resolution seismic surveys as well as conventional seismic data are uidentify potential gas bearing zones at shallow depths by using a technique known as ‘spot’ analysis. The high resolution seismic data are acquired over a survey grid with peronly 150m between seismic lines, the grid covering an area of only a few square kilomaround a proposed well location. The data are processed to produce detailed seismic sectusually down to a maximum depth of about 1000m.

0.4

0.5

0.6

0.7

0.8

0.9

1.0

Note: See warning in (c) Interpretation.

1.2 1.4 1.6

2.25

2.00

1.75

1.50

1.25

PORE PRESSURE GRADIENT

psi/ft

EQUIVALENT MUD DENSITY

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2-21March 1995

Gas bearing formations may produce high amplitude ‘anomalies’ on the seismic refltraces of the seismic section. These high amplitudes (relative to the other seismic reflectioare caused by strong seismic reflections due to the velocity impedance contrast betwgas bearing formation and the overlying formations. These amplitude anomalies appevisually on the seismic section as bright areas. The lateral extent of the bright spots can mapped on a horizontal section, or sections, and the area of the proposed well loexamined in detail. It may be necessary to move the well location to avoid drilling ipossible shallow gas zone as indicated by a bright spot.

It must be noted that the high resolution seismic technique cannot usually detect a gthat is less than 2 to 3 metres thick, although such a thickness of gas accumulation enough to cause a shallow gas blowout. Also, the absence of bright spots does not mean there will be no shallow gas and conversely, bright spots do not always contain gas. Howev,it is wise to avoid drilling through any bright spots if possible.

Ideally, the Geophysicists must be responsible for analysing the shallow seismic dataproposed well location. Once the well location has been finalised, the Drilling Engshould liaise closely with the Geophysicists and Geologists to produce a drilling enginhazard log over the depths covered by the shallow seismic survey. An example hazard log isshown in Figure 2.11. It will not be possible to predict formation pressures for shallowformations from the seismic data. However, drilling personnel should always be aware thshallow gas bearing formations may be overpressured, though this is not normally th

4 Summary

The importance of reliable formation pressure data must be stressed. It is the responof the well planning DE to ensure that the pressure data used are the most accurate a

Whenever possible, pressure data from offset wells should be used to predict the pore presprofile for well planning. Direct pressure measurements such as those from RFTs, drillstemtests and well kicks should give more accurate data than pressures derived from we

Seismic methods of pressure prediction should only be used in the absence of offset welldata. Occasionally, seismic analysis may be necessary to endorse the data from offset wells,although there is no guarantee that this will be successful.

A recent development by Geochemistry Branch at Company Research Centre, Sunworthy of note. A compaction model has been developed that may have an applicatiopredicting formation pressures. This model may be useful for pressure prediction in arwith very few or no offset wells, especially if used in conjunction with seismic data.Atpresent, the model is being validated against actual well data.


2-22March 1995

Figure 2.1 1 Example of Drilling Hazard Logover Shallow Section

BASE OF NEAR SURFACE SEDIMENT

DRILLING HAZARD

DEPTH (m)

CASING

POSSIBLE SHALLOW GAS

FAULT

SAND, LENSES, POSSIBLE GAS

SAND AND SHALE

FAULT

BASE OF SHALLOW SURVEY

350

400

30in (320m)

18 5/8in (580m)

470

600

200

WEOX02.088

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620

800

850

1000

100SEABED

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2-23March 1995

2.3 FORMATION PRESSURE EVALUATIONWHILST DRILLING

Paragraph Page

1 General 2-25

2 Drilling Parameters 2-25

2.1 Rate of Penetration 2-25

2.2 Drilling Exponents 2-27

2.3 Other Drilling Rate Methods 2-38

2.4 Hole Characteristics 2-42

3 Drilling Mud Parameters 2-43

3.1 Gas Levels 2-43

3.2 Temperature 2-52

3.3 Resistivity/Conductivity/Chlorides 2-533.4 Flowline Mud Weight 2-53

4 Cutting Parameters 2-53

5 Measurement While Drilling (MWD) Techniques 2-60

6 Mud Logging Service 2-61

7 Summary 2-64

Illustrations

2.12 Example showing Increase in Penetration Rateon Entering an Abnormally High Pressure Zone 2-26

2.13 Effect of Lithology Variation on Penetration Rate 2-27

2.14 Effect of Bit Condition on Penetration Rate when Drilling into an Overpressured Zone 2-28

2.15 Schematic Diagram showing Typical response ofCorrected d-exponent in Transition andOverpressured Zones 2-30

2.16 Schematic Diagrams showing Various Typicaldc-exponent Responses 2-31

2.17 Schematic Diagram showing dc-exponent Responseto Overcompaction caused by Ice Sheet Loading 2-33

2.18 Example of Formation Pressure Determination from thedc-exponent plot using the ‘Ratio Method’ 2-34


2-24March 1995

Illustrations

2.19 Example showing the ‘Equivalent Depth Method’ forFormation Pressure Determination from dc-exponent Plots 2-36

2.20 Example showing Formation Pressure Determinationfrom the dc-exponent Plot using Lines Constructedfrom the ‘Eaton Equation’ 2-49

2.21 Example showing the ‘Normalized Penetration Rate’Method for Determination of Formation Pressures 2-40

2.22 Schematic Diagram showing Mud Gas Levels as anIndicator of Formation Pressures 2-45

2.23 Example of Mud Gas Levels showing Trip Gas,Kelly Gas (Kelly Cut), and Recycled Trip Gas 2-46

2.24 Schematic Diagram showing Theoretical GeothermalGradients and Temperature Profile through anOverpressured Zone 2-49

2.25 Schematic Diagram showing Expected FlowlineTemperature Response on Drilling throughan Overpressured Zone 2-49

2.26 Example Flowline Temperature Plots showing RawData Plot, End-to-end Plot and Trend-to-trend Plot 2-50

2.27 Example ‘Horner’ Temperature Plot for Estimationof True Bottomhole Temperature (BHT) 2-51

2.28 Example of Typical Response of Differential MudConductivity/Delta Chlorides 2-53

2.29 Schematic Shale Bulk Density/Depth Plot 2-54

2.30 Variable Density Column for Measuring Shale Bulk Density 2-55

2.31 Response of Shale Bulk Density/Depth Plots inOverpressures caused by Various Mechanisms 2-56

2.32 Shale Factor/Depth Response to Overpressure causedby Compaction Disequilibrium and Clay Diagenesis 2-58

2.33 Characterisation of Shale Cavings Caused byUnderbalanced Conditions and Stress Relief 2-59

2.34 Mud Logging Unit Functions and Information Flow Diagram 2-62

Table

2.3 General Mud Logging Sensor Specifications 2-63

mudtes of

ct anyrmally

pared

sed as aateerdters.

king

re.

size,tarytrationnnded thaterlying


2-25March 1995

1 General

The aim of formation pressure evaluation whilst drilling is to determine the optimumweight to contain any formation pore pressures encountered, whilst maximising rapenetration and minimising the hazards of lost circulation and drillstring differential sticking.To achieve this, formation properties have to be closely monitored in order to detechanges that may indicate the transition from a normally pressured zone to an abnopressured zone or vice versa.

Abnormally pressured zones may exhibit several of the following properties when comto normally pressured zones at the same depths.

• Higher porosities

• Higher temperatures

• Lower formation water salinity

• Lower bulk densities

• Lower shale resistivities

• Higher interval velocities

• Hydrocarbon saturations may be different (ie higher saturation)

Any measureable parameter which reflects the changes in these properties may be umeans of evaluating formation pressures. The parameters commonly used to evaluformation pressures while drilling are listed in Table 2.1. It should be remembered howev,that the above properties also vary with differing lithologies. Lithological variations shoulalways be taken into account when interpreting changes in drilling and mud parame

As the aim of formation pressure evaluation whilst drilling is to reduce the risk of tawell kicks, this section concentrates on the techniques used to achieve this. The pressureevaluation techniques in Table 2.1 that are associated with kicks are not discussed he

2 Drilling Parameters

2.1 Rate of Penetration

Rate of penetration varies with the weight on the bit, rotary speed, bit type andhydraulics, drilling fluid properties and formation characteristics. If the weight on bit, rospeed, bit type, mud density and hydraulics are held constant, then the rate of pene(ROP) in shales will decrease uniformly with depth. This is due to the normal compactioincrease in shales with depth. However, the undercompaction present in transition aabnormally pressured zones, together with the reduction in differential pressures across thbottom of the hole, result in an increase in penetration rate. It should also be noteslower penetration rates have often been observed in the ‘cap rock’ (pressure seal) ovtransition zones.

ROPer

way

logy

uch

ated

it may

02.089


2-26March 1995

The increase in ROP on drilling into a transition zone can be best seen on a plot of versus depth. The average ROP over 0.5 to 2m depth increments (depending on wheththe␣drilling is slow or fast) is plotted as shown in Figure 2.12. A normal compaction trendcan be established in shales as shown. A new trendline must be established for each nebit␣run. An increase in penetration rate away from the normal compaction trend mindicate␣abnormal pressures provided that the drilling and mud parameters, and litho,remain constant.

Figure 2.12 Example showing Increase in PenetrationRate on Entering an Abnormally HighPressure Zone

Complications arise due to lithology changes and bit dulling. Sandstone usually drills mfaster than shales. This is normally shown by a sharp increase in ROP as the sandstone ispenetrated. This effect, known as a ‘drilling break’ is shown schematically in Figure 2.13.The normal compaction trend must be established over the shale sections only.

Drilling breaks must always be flow checked regardless of whether the current estimpore pressure gradient is less that the mud weight. Occasionally, the transition zone may beonly a few metres thick if there is a very good pressure seal. This may make it very difficultto identify an increase in ROP as being one due to increased pore pressure, becausebe masked by a drilling break.

��

DE

PT

H

ROP

NORMAL SHALE TREND LINE

NEW BIT

TOP OF OVERPRESSURES

WEOX

s. t aree

close

d in

g for

WEOX02.090


2-27March 1995

Figure 2.13 Effect of Lithology V ariationon Penetration Rate

Bit dulling can also mask penetration rate changes due to pore pressure increaseAcomparison of ROP curves in an overpressured section for a dull bit and a sharp bishown in Figure 2.14. The dull bit continues to show the normal compaction trend in thtransition zone whilst the sharp bit clearly shows a gradual increase in ROP. The dull bitROP may even show a decrease in the overpressured zone if the bit is very worn and to being pulled.

In practice, drilling parameters are rarely held constant, as they are purposefully varieorder to maximise the penetration rate. Thus, ROP curves alone tend to be of limited use inidentifying overpressured zones. They may, however, provide additional information whenused in conjunction with other abnormal pressure indicators.

2.2 Drilling Exponents

From the preceding discussion on ROP curves, it is clear that a method of accountinthe effect of drilling parameters is desirable in order to make ROP a better indicator ofabnormal pressures. The ‘d-exponent’ attempts to achieve this.

DE

PT

H

ROP

DE

PT

H

ROP

NORMAL SHALE COMPACTION TREND LINE

sand

shale

ant


2-28March 1995

Figure 2.14 Effect of Bit Condition on Penetration Ratewhen Drilling into an Overpressured Zone

(a) d-Exponent

In 1965, Bingham(4) proposed a generalised drilling rate equation to relate all the relevdrilling parameters:

ROP N

= a WOBB

d(2-3)

whereROP = penetration rate (ft/min)N = rotary speed (rpm)B = bit diameter (ft)WOB = weight on bit (lb)a = rock matrix strength constant (dimensionless)d = formation drillability exponent (dimensionless)

DE

PT

HD

EP

TH

SHARP BIT ROP

DULL BIT ROP

sand

shale

WEOX02.091

TOP TRANSITION ZONE

gthth

to0.

le.

neral,ent

nent.o

ECDund toly in

ther

at

sible.


2-29March 1995

Jorden and Shirley(21) rewrote equation 2-3 for ‘d’, the drillability exponent. They insertedconstants to allow the use of more common oilfield units and let the matrix strenconstant, ‘a’, equal 1. This removed the need to derive values for the matrix strengconstant, but made d-exponent lithology dependent:

d = log ROP

60N

log 12WOB106 B

where d = drillability exponent (d-exponent) (dimensionless)ROP = penetration rate (ft/hr)N = rotary speed (rpm)B = bit diameter (in.)WOB = weight on bit (lb)

NOTE: The constant 106 is simply a scaling factor inserted in the equation in ordergive values of d in a convenient workable range, normally about 1.0 to 3.

In constant lithology, d-exponent will increase with depth as the ROP decreases due tothe increased compaction and differential pressures across the bottom of the hoHowever, when an overpressured zone is penetrated, compaction and differential pressurewill decrease and will result in a decrease in d-exponent. Hence d-exponent is, in gerelated to the differential pressure at the bottom of the hole which in turn is dependon pore pressure.

(b) Corrected d-Exponent

Since the differential pressure across the bottom of the hole is affected by the mud␣weightalso, then changes in the mud weight will produce unwanted changes in d-expoHence Rehm and McClendon(27) proposed the following correction to the d-exponent taccount for mud weight variations:

dc = d X FPGN (2-5)ECD

where dc = corrected or modified d-exponent (dimensionless)FPGN = normal formation pressure gradient (ppg, SG)ECD = equivalent circulating density (ppg, SG)

This correction has no theoretical basis but has been successfully used worldwide.should be used whenever possible but use of the actual mud density has been fobe acceptable. The response of d-exponent in overpressure is shown schematicalFigure 2.15.

The dc-exponent may be plotted with either semi-log or linear co-ordinate axes. Eisystem will produce an approximately linear, normal compaction trendline, as indicatedin Figure 2.15. In practice, the semi-log co-ordinate system gives a more efficient datadisplay (values of dc are normally in the range 0.5 to 2.0) and is a more suitable formfor making formation pressure estimates from dc-exponent.

A dc-exponent plot should be commenced as soon as drilling begins. Values should becalculated at 0.5 to 2m intervals, depending on penetration rate. This is normally doneautomatically by the Mud Logger’s computer and displayed as required. The valuesmay also be plotted up automatically to enable trends to be spotted as early as pos

itionr

stantges

d


2-30March 1995

Figure 2.15 Schematic Diagram showing T ypical responseof Corrected d-exponent in T ransition andOverpressured Zones

The ‘normal’ dc trendline should be established as soon as possible in order that transzones to abnormal pressures can be recognised as they are being drilled. Howeve, it isoften difficult to precisely establish the normal dc trendline due to scatter in the dc

values calculated. This variation in dc values is mainly caused by:

• Lithology

As previously stated, d-exponent increases with depth and compaction in conlithology. This implies that d-exponent is mainly applicable to shales. Chanin␣lithology will thus cause changes in the value of dc. If the lithology change isrelatively minor, such as silty shales, then a slight decrease in dc values may beobserved which may not affect the overall trend significantly. Cuttings analysis shouldhelp to identify ‘true’ shale points for use in establishing the normal trend if thec

values show a large␣scatter.

NORMAL CONCEPTION TREND UNE

NORMAL PRESSURE

WEOX02.092

TRANSITION ZONE

dc

OVERPRESSURED ZONE

DE

PT

H


2-31March 1995

Figure 2.16 Schematic Diagrams showing V arious T ypicaldc-exponent Responses

SMOOTHED CURVERAW DATA

INSERT BIT

ROCK BIT

ROCK BIT

(c)

WEOX02.093

dc

DE

PT

H

NEW BIT

NEW BIT

NEW BIT

(e)

dc

DE

PT

H

SILTY MUDSTONE

SOFT CLAY

CALCITIC MUDSTONE

MUDSTONE

CALCITIC MUDSTONE

MUDSTONE

CALCITIC MUDSTONE

(a)

dc

DE

PT

H

NO

RM

AL

PR

ES

SU

RE

OV

ER

PR

ES

SU

RE

SMOOTHED CURVE

RAW DATA

12 1/4in / 25 000 lb W/B = 2040 lb/in

12 1/2in / 10 000 lb W/B = 1178 lb/in

(d)

dc

DE

PT

H

FRESH BIT DULL BIT

(f)

dc

DE

PT

H

MUDSTONE

MUDSTONE

MUDSTONE

MUDSTONE

MUDSTONE

SAND

SAND

SAND

(b)

dc

DE

PT

H

NO

RM

AL

PR

ES

SU

RE

OV

ER

PR

ES

SU

RE

NO

RM

AL

PR

ES

SU

RE

OV

ER

PR

ES

SU

RE

rmal

rmalsure

6

nly

ts asalso

f the

none

allyteduced.

greatrves.

ons

elow

h


2-32March 1995

For major lithological variations, such as interbedded sandstone/shale, the notrend must be developed through the shale sections only. The increased ROP in sandsections will give sharply decreased dc values. (It may be possible to develop notrendlines for the various other lithologies but these are of little use in overpresevaluation and may only serve to confuse matters.) The important message here isthat lithology variations must be taken into account when interpreting dc-exponentplots. The response of dc in various lithologies is shown schematically in Figure␣2.1(a) and (b).

• Hydraulics

Changes in drilling hydraulics may produce changes in dc-exponent. This also appliesto formations that are susceptible to jetting. Therefore, it is often impossible toestablish a normal dc trend in soft, unconsolidated sediments, such as those commodrilled in offshore top hole sections.

• Bits

The different drilling actions of different types of bits, ie mill tooth or insert, cancause variations and trend shifts in dc.

It is sometimes necessary to plot a ‘smoothed’ curve to account for trend shifshown schematically in Figures 2.16 (c) and (d). Changes in hole size will produce a trend shift in dc.

The effect of bit wear is to produce an increase in dc values towards the end obit run, as indicated in Figure 2.16(e). The new bit should give a new dc trend thatcontinues along the previous trend provided that it is the same type of bit and of the other parameters have varied significantly.

The effect of drilling into an overpressured zone as the bit dulls is shown schematicin Figure 2.16 (f). A dull bit may mask the decrease in dc which would be expecif the bit was fresh. In extreme cases, bit dulling may totally mask or even prodan increase in dc values even though an overpressured zone has been penetrate

Thus it can be seen that the position of normal trends should be established withcare, as should the practice of shifting trends from raw data to produce smoothed cu

Two further noteworthy phenomena that may cause difficulty in interpreting the plots␣are:

• Unconformities/Disconformities

The presence of an unconformity/disconformity in the geological age of formatibeing drilled will often change the character of the normal trendline. The differentcompaction histories and sedimentary conditions of the formations above and ban unconformity/disconformity may result in not only a shifted normal dc trendline,but also a change in slope. A new trendline should be established after drilling througan unconformity/disconformity.

o be

esent

ted a

tions in

EOX02.094


2-33March 1995

Figure 2.17 Schematic Diagram showing d c-exponentResponse to Overcompaction caused by IceSheet Loading

• Ice Sheet Compaction

Ice sheet compaction can often cause a good normal compaction trend testablished at shallow depths in top hole sections. This is due to the increasedcompaction of the near surface sediments caused by the weight of a once proverlying ice sheet. This may lead to a normal dc trend being developed through dc

values that are too high. The compacting influence of the ice sheet is often dissipaafter the first few hundred metres and the dc-exponent then appears to decrease tonew normal trend, falsely indicating an increase in pore pressure. This effect is shownschematically in Figure 2.17.

(c) The Calculation of Formation Pressures using dc

Once the normal compaction trend has been firmly established on the dc-exponent plot,then dc values that decrease away from this line may indicate abnormal formapressures. This is, of course, provided that there have been no significant changelithology or in any of the other relevant parameters.

dc – EXPONENT

0.5

1.2SG

1.1SG

1.3SG

1.0 2.01.5

OVERCOMPACTED

OVERPRESSURED

NORMALLY COMPACTED

DE

PT

H

NORMAL COMPACTION TREND

W

5


2-34March 1995

• The ratio method

The magnitude of the formation pressure can be related to the dc deviation on thesemi-log plot using the ‘ratio method’:

FPGO = FPGN X dcN

dcO (2-6)

where FPGO = actual formation pressure gradient at depth of interest(psi/ft, SG or ppg)

FPGN = normal formation pressure gradient (psi/ft, SG or ppg)dcO = observed corrected d-exponent at depth of interestdcN = expected corrected d-exponent on normal trendline at

depth of interest

Figure 2.18 Example of Formation Pressure Determinationfrom the d c-exponent plot using the‘Ratio Method’

Equation 2-6 is only valid for the semi-log dc plots as it is assumed that dc is anexponential function of depth. By rearranging the above equation into:

dcO = dcN X FPGN (2-7)FPGO

SANDS

Normal shale trend line Normal formation pressure Gradient is 1.08 SG

Maximum formation press gradient is 1.43 SG

SG

2.041.80

1.561.44

1.321.20

1.08 SG

Maximum formation press gradient is 1.66 SG

TYPICAL TRANSITION ZONE

DE

PT

H

dc – EXPONENT (SEMI-LOG SCALE) WEOX02.09

e

y

urectly

king

atestnts

alsotionst thatth at

equale

d bygs.s forh


2-35March 1995

and substituting known values of FPGN and dc at various depths, it is possible tocalculate a series of values of dcO, equivalent to various values of formation pressurgradient, FPGO. These series of values of dcO can be plotted on the semi-log dc plotas lines parallel to the normal dc trendline. The formation pressure gradient at andesired depth can then be estimated directly from the dc plot. Figure 2.18 shows anexample dc plot with equivalent formation pressure gradient lines drawn in.

NOTE:Transparent overlays ready marked with equivalent formation pressgradient lines are sometimes available for reading formation pressures direoff the dc plot. As it is never certain exactly what depth and dc scales wereused to construct these overlays, their use should be avoided in maformation pressure gradient estimates.

The ratio method is a very simple method of making formation pressure estimfrom dc-exponent. However, it ignores the effect of the variable overburden gradien(See ‘Overburden Pressure’ in Chapter 1, Section 1.1), which controls compactiotrends. This effect is reflected in the dc-exponent trend, but is considered noaccurately defined by it. An alternative method of calculating formation pressurefrom the dc plot is the equivalent depth method.

• Equivalent Depth Method

Due to the increase in compaction with depth, the formation matrix stress increases, and the formation becomes harder to drill. In overpressured formathe compaction and matrix stresses are less than would be normally expected adepth. The equivalent depth method attempts to relate these values to the depwhich they would be normal.

The method assumes that the matrix stress (grain to grain contact pressure) isat all depths having the same value of dc. Matrix stress (M) is related to pore pressur(Pf) and the overburden pressure (S) as shown by equation 1-8 (See Chapter 1,Section 1.1). This equation can be rearranged to give:

Pf = S – M (2-8)

This equation holds at any depth. Therefore, referring to the example dc plot inFigure 2.19, the actual formation pressure gradient (FPGO) at the depth of interest(DO) is given by:

FPGO = PfO = SO – MO

DO DO DO

FPGO = OPGO – MO (2-9)DO

where OPGO = overburden pressure gradient at depth of interest (psi/ft)MO = matrix stress at depth of interest (psi)

The overburden pressure gradient is known because it is continually estimatethe Mud Loggers and updated from wireline formation density or sonic lo(The␣overburden gradient is required for estimating fracture pressures as well amaking pore pressure estimates.) However, the value of the matrix stress at the deptof interest is unknown.

e

ont


2-36March 1995

A line is then constructed vertically upwards from the value of dc at the depth ofinterest until it crosses the normal dc trendline at ‘the equivalent depth’ (DE), asshown in Figure 2.19. At this equivalent depth, both the pore pressure and thoverburden pressure are known. Thus, equation 2-8 can be solved for the matrixstress (ME) at the equivalent depth (DE):

ME = SE – PfE (2-10)

In terms of gradients:

ME = SE = PfE = OPGE – FPGE

DE DE DE

ME = DE (OPGE – FPGE) (2-11)

where OPGE = overburden gradient at equivalent depth (psi/ft)FPGE = formation pressure gradient at equivalent depth (psi/ft) which als

equals the normal formation pressure gradient at the equivaledepth FPGNE (psi/ft)

Figure 2.19 Example showing the ‘Equivalent DepthMethod’ for Formation Pressure Determinationfrom d c-exponent Plots

dc – EXPONENT

0.5 1.0 1.5 2.0

WEOX02.096

DE

DO

NORMAL COMPACTION TREND

DE

PT

H

dered

t)

i/ft

ation

on ise

eoresually

datrix


2-37March 1995

Since the matrix stress at the depth of interest and equivalent depth are consiequal (equal dc values), then substituting equation 2-11 into equation 2-9 gives:

FPGO = OPGO – DE (OPGE – FPGNE) (2-12)DO

where FPGO = formation pressure gradient at depth of interest (psi/ft)OPGO = overburden pressure gradient at depth of interest (psi/ft)OPGE = overburden pressure gradient at equivalent depth (psi/ft)FPGNE = normal formation pressure gradient at equivalent depth (psi/fDO = depth of interest (ft)DE = equivalent depth (depth at which dc is equal to value at DO) (ft)

NOTE: Equation 2-12 can be used directly with gradients in SG, lb/gal or psand depths in metres or ft.

The equivalent depth method has been successfully used to estimate formpressures from both semi-log and linear scale dc plots. However a major flaw in thetheory occurs when the equivalent depth of a particular overpressured formatifound to be above the rig floor. This will be the case if high overpressures ardeveloped at relatively shallow depths. Also, the method relies on determining thintersection point of a vertical line with the normal compaction trendline. It therefbecomes inaccurate when the normal compaction trendline is very steep, as is uthe case on the semi-log dc plot.

• The Eaton Method

The most accurate estimates of formation pressure from dc-exponent are consideredto be obtained from the Eaton equation. This empirical equation was again developefrom the basic relationship between pore pressure, overburden pressure, and mstress (equation 2-8). For normal pressure conditions:

MN = SO – PfN (2-13)

Eaton then introduced a term to relate the dc-exponent (drilling rate) response inoverpressures to the reduction in matrix stress:

MO = MN DcO

dcN

1.20(2-14)

Combining equations (2-13) and (2-14) gives:

MO = (SO – PfN) dcO

dcN

1.20(2-15)

Rewriting equation 2-13 for an abnormally pressured situation gives:

MO = SO – PfO (2-16)

Substituting equation 2-16 into equation 2-15 then gives the Eaton equation:

PfO = SO – (SO – PfN) DcO

dcN

1.20(2-17)

ns

ients

ures

al

uredure

tion

as is

hichoreg

ed

re as

ttinglling

thatods,

tors.


2-38March 1995

Dividing through by the depth (D), gives the equation in terms of gradients:

PfO

DO

= SO

DO

– SO – PfN

DO DO

dcO

dcN

1.20

FPGO = OPGO (OPGO – FPGN) dcO

dcN

1.20

where FPGO, FPGN, OPGO, dcO and dcN are the same terms as explained for equatio2-6 and 2-12.

By rearranging equation 2-18 and substituting known values of FPGN, dcN and OPG,it is possible to plot a series of dcO lines equivalent to various values of FPGO (in asimilar manner to that previously explained for the Ratio method). An example ofthis construction is shown schematically in Figure 2.20. Formation pressure gradcan then be read directly from the dc plot.

Eaton originally developed the equation for use in estimating formation pressfrom shale resistivity plots (See Section 2.4), but found that it applied equallyto␣corrected d-exponent. The value of the exponent, 1.20, was derived from actuwell data.

All the methods for estimating formation pressures from dc-exponent plots rely on correctplacement of the normal compaction trend. The difficulties in achieving this havepreviously been discussed and highlight the fact that identification of overpresszones should not be based on dc-exponent calculations alone. Other abnormal pressindicators, which are often more basic in nature than dc-exponent calculations, shouldalways be checked. These indicators must support, as far as possible, any formapressure conclusions drawn from the dc plot.

Drilling factors that are not accounted for by dc-exponent are drilling hydraulics, bittooth efficiency (bit wear) and matrix strength (lithology dependent). Also, therelationship between ROP and the various drilling parameters is not so simple implied by the dc-exponent equation.

These factors have led to the development of more refined drilling exponents in wattempts have been made to model the various drilling/formation interactions mclosely. In particular, mud logging companies have developed their own drillinexponents from which they make formation pressure estimates. Exlog’s ‘Nx’ (normalisedexponent) and ‘Nxb’, and Anadrill’s ‘A’ exponent are examples of these more refindrilling exponents.

The theory of these drilling exponent methods will not be discussed in detail hetheir formulae are of a proprietary nature and are not generally available. Suffice it tosay that the methods still rely on estimating a normal compaction trend and spodeviations from it caused by pore pressure changes and not by lithology or drichanges.

2.3 Other Drilling Rate Methods

There are a number of other drilling rate methods for estimating formation pressuresare worthy of note. As these methods are generally more complex than d-exponent meththey have not gained wide acceptance and thus tend only to be used by their origina


2-39March 1995

Figure 2.20 Example showing Formation PressureDetermination from the d c-exponent Plotusing Lines Constructed from the‘Eaton Equation’

1.80 1.68 1.56 1.44 1.33 1.20

dc – EXPONENT

1.08 SG

0.5

NORMAL TREND

WEOX02.097

TOP OF OVERPRESSURE

1.0 1.5

DE

PT

H

overge in


2-40March 1995

(a) Normalised Penetration Rate

This method was developed in 1980 by Prentice(26) from work done originally by Vidrineand Benit(32). The method uses a drilling rate equation to ‘normalise’ the effects of thevariables controlling ROP. The only variable not normalised is differential pressureacross the bottom of the hole. If the ECD is then considered to be fairly constant short intervals of the hole, a change in ‘normalised’ penetration rate reflects a chanformation pressure.

Figure 2.21 Example showing ‘Normalized PenetrationRate’ Method for Determination ofFormation Pressures

0

4100

3080

3050

3020

2990

ECD = 1.25 SG

ECD = 1.25 SG

ECD = 1.38 SG

2960

4

NORMALIZED PENETRATION RATE (m/hr)

NEW BIT

1.08 SG

NEW BIT

NEW BIT

DE

PT

H (

met

res)

812

CIRCULATED 1.38 ECD ALL AROUND

CIRCULATED 1.5 ECD ALL AROUND

1.08 SG

4.11m/hr8.53m/hr

1.28 SG

1.28 SG

1.37 SG

6.1m/hr8.23m/hr

WEOX02.098

cted.ration

b)

try and astely

n inhe bit

hangeified.d, as

by this

sure

ation

g


2-41March 1995

As drilling proceeds, a plot of normalised penetration rate against depth is construThe observed penetration rate is mathematically corrected to the normalised penetrate by applying arbitrarily chosen normal parameters according to the equation:

ROPN = ROPO X WN – mWO – m

X NNNO

λ

X ∆PbitN QN

∆PbitO QO

(2-19)

where ROP = penetration rate (ft/hr or m/hr)W = weight on bit (lb)N = rotary speed (rpm)∆Pbit = bit pressure drop (psi)Q = mud flow rate (gpm)m = ‘threshold’ bit weight (weight necessary to initiate formation failure) (lλ = rotary exponent

and the subscripts

N = ‘normal’ valuesO = observed values

Values of λ and m are given by Prentice(26). If the ‘normal’ conditions are chosen so thamost of a bit run can be drilled at these conditions, then no corrections will be necessaROPN will equal ROPO. Each bit run is treated as an individual unit and is plotted upshown in the example in Figure 2.21. Changes in mud weight are also plotted separa.

Drilling trends are fitted to each bit run, or part bit run, at constant ECD, as showthe example. Provided that the ECD and formation pressure remain constant, twill dull and the ROPN will follow the dulling trend. If a deviation from the dullingtrend is noted at constant ECD, this then indicates either a lithology change or a cin formation pressure. Lithology changes are generally abrupt, and easily identFormation pressure changes show a more gradual deviation from the dulling trenshown in the example plot at about 9950 ft and 10,100 ft.

Vidrine and Benit(32) developed a graphical relationship between differential pressureacross the bottom of the hole and the percentage decrease in ROP caused overbalance. Using this relationship, the extrapolated dulling trend ROPN and theobserved ROPN at a particular depth are used to estimate the actual formation presat that depth. The method is detailed in full by Prentice(26) together with worked examplesand a comprehensive discussion of the theory behind the method. The method is quotedas being the most responsive of all methods used to indicate the changes in formpressure, but no data are presented to support this claim.

(b) Sigmalog

This method was developed by AGIP and Geoservices(3). Basically, it is a plot of acalculated rock strength parameter versus depth. The method is based on the followingdrilling rate equation (developed by AGIP):

√σt = WOB0.5 . N0.25

B . ROP0.25(2-20)

where √σt = ‘raw’ rock strength parameter and WOB, N, B and ROP are as previouslydefined. The ‘raw’ rock strength is then corrected to the rock strength parameter, √σo, usingexperimentally derived relationships to account for depth and bottomhole differential pressure(assuming a normal formation pressure gradient). The Sigmalog is then constructed by plottin√σo versus depth.

d

leted

samef tingt theoth in to

tions

est to

string

tendtion.

into tollars

000 muches. In

ntactrease

pecially

seenlentitions,

ted.


2-42March 1995

In normally pressured formations, √σo will increase with increasing depth ancompaction. A normal compaction trend can be established and a decrease in √σo awayfrom the normal trend will indicate an increase in formation pressure. When this occurs,the relationship used to correct √σt to √σo is reworked to determine the true bottomhodifferential pressure (not the assumed one). The formation pressure can then be calculafrom the differential pressure and the ECD for the mud weight in use.

Various factors such as faults, unconformities/disconformities, poor bit efficiency, coringetc, cause ‘shifts’ in the normal trend. However all the normal trends have the slope, and the shifts of the trendlines are proportional to the shifts in the values o√σo.Correct shifting of the normal trendlines is thus of prime importance in calculaformation pressures from the Sigmalog. Despite this problem, it is claimed thaSigmalog is an excellent formation pressure evaluation tool and can be applied bshale and non-shale lithologies. The Sigmalog is commonly used by Geoservicesestimate formation pressures.

(c) Other Methods

Several other methods of formation pressure evaluation from drilling rate equahave been put forward. These include methods by Combs(10), Zoeller(33), andBourgoyne(5). These are not discussed here but are referenced in case of interthe␣reader.

2.4 Hole Characteristics

(a) Drag and Torque

Drag is the excess hook load over the free hanging load required to move the drillup the hole. Drag may be caused by bit and stabiliser balling, dog legs, insufficient holecleaning, etc, and also by overpressure effects in shales. Overpressured shales ofbehave plastically and creep into the borehole. This reduces the wellbore diameter anwill cause an increase in drag as the bit/stabilisers are moved up through the sec

In an underbalanced drilling situation, an increased volume of cuttings may comethe wellbore. This may result in an increase in drag when picking up the drillstringmake a connection, especially if the cuttings are not circulated above the drillcoprior to picking up. Normal drag after drilling new hole is usually of the order of 10,to 20,000 lb, depending on the hole and BHA geometries. Consistent drag valueshigher than this may indicate borehole instability caused by abnormal pressurdeviated holes however, consistently higher drag will invariably be seen.

Torque usually increases gradually with depth due to the increase in wall-to-wall cobetween the drillstring and borehole. If underbalanced conditions exist then an incin torque may be observed due to excess cuttings entering the hole. A reduced wellborediameter caused by overpressured shales may also result in an increased torque, esif full gauge stabilisers are being used.

However, increased torque resulting from underbalanced conditions is virtually unwhen the pressure differential into the wellbore is less than 1 ppg (0.12 SG) equivapressure gradient. If an increase in torque is taken to indicate underbalanced condthen concurrent increases in drag and hole fill (see below) should also be expec

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2-43March 1995

Torque can be useful in detecting large increases in pore pressures, for example whcrossing a fault line into overpressured formations. However, sudden large increases intorque can also be caused by a locked cone on the bit, a sudden change in formtype, and by stabilisers ‘hanging up’ on hard stringers.

Both torque and drag are not considered to be valid overpressure indicators when drhigh angle deviated holes. Also, increases in torque due to abnormal pressures are difficultto distinguish from the normal torque increase with depth. When drilling from a floatingrig the vessel motion and varying offset from the wellhead tend to produce significantorque fluctuations that make interpretation very difficult.

(b) Hole Fill

Hole fill after making a connection or after a trip out of the hole may indicate abnorpressures. As discussed above, overpressured shales may squeeze into the wellborreduce its diameter. Then, as the bit is run in the hole to bottom after a connectiontrip, it removes the shale which is pushed to the bottom of the hole. Cavings causeunderbalance conditions may also enter the wellbore during a connection or a tripcause hole fill.

Hole fill may also be the result of insufficient hole cleaning caused by poor mudproperties, or by not circulating all the cuttings out of the hole prior to tripping. Howev,any excessive hole fill after making a connection or a trip should be noted and oabnormal pressure indicators evaluated to determine if overpressures are actually encountered.

3 Drilling Mud Parameters

3.1 Gas Levels

Hydrocarbon gases enter the mud system from various sources during the drilling of aThe gases in the return mud stream are extracted from the mud for analysis in thelogging unit. There is no quantitative correlation between measured gas levels and formpressure. However, changes in gas levels can be accounted for by relating them to the adrilling operation in progress (drilling, tripping etc) and the mud weight in use. Tentativepore pressure estimates may then be made.

The main sources of gas in the mud system are:

• Gas liberated from drilled cuttings.

• Gas flowing into the wellbore due to underbalanced conditions.

The gas levels from these sources are dependent upon the formation gas saturatiomud weight and the particular drilling operation.

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2-44March 1995

Gas levels are categorised as follows:

(a) Background Gas (BGG)

This is the total level of gas extracted from the return mud stream whilst drilling aheIt originates primarily from the unit volume of formation cut by the bit. Hydrocarbonare often generated within shales and migrate to more porous formations sucsandstones where they may be trapped. Gas in shale cuttings is released into thestream due to the reduction in pressure as the cuttings are circulated up the hole.

If hydrocarbons are present in any porous formations drilled, there will be relativhigh levels of background gas in the mud stream. However, if the mud weight in usecauses a high overbalance, there may be little, if any, entry of gas into the mud. Thehigh overbalance will cause the mud filtrate to ‘flush’ the gas away from the wellbo

In underbalanced drilling conditions, gas may enter the mud at a rate that dependthe permeability of the formations being drilled. Shales may shown an increasebackground gas levels, due to an increase in cavings caused by the underbalaconditions. Background gas levels normally show a gradual increase as a transzone to abnormal pressures is drilled.

Background gas can not be used quantitatively to estimate formation pressures the levels depend on mud circulation rate, efficiency of gas extraction from the returnmud stream (gas trap efficiency) and also on the gas composition. However, if mudproperties, drilling conditions, and lithology remain fairly constant, then increasibackground gas levels may well indicate that the formation pressure gradienapproaching, or possibly exceeding the mud weight gradient.

(b) Connection Gas (CG)

When circulation is stopped to make a connection, the bottomhole pressure of the column is reduced by an amount equal to the annulus pressure loss i.e. the effectivemud weight is reduced from the ECD to the static mud weight. This reduction in pressuremay be enough to allow a small amount of gas to be produced into the mud coluThis is known as connection gas. Also, connection gas may also be caused by ‘swabbinwhen picking up the drillstring to make a connection.

When this gas reaches the surface, it appears as a peak above the background gaon the total gas trace recorded in the mud logging unit. Connection gas peaks are genshort and sharp depending on the ‘bottoms up’ time, i.e. the longer the bottoms up tthe wider the peak will be.

It is possible to correlate connection and background gas levels with the mud weiggive a fairly accurate estimate of the formation pressure. This is shown schematically inFigure 2.22. As the pore pressure approaches the bottomhole dynamic pressconnection gas peaks begin to appear, probably due to swabbing. As the pore pressureincreases further, the background gas level also begins to increase and the connecgas peaks become higher. It is reasonable to assume at this point that the pore pressslightly exceeds the dynamic bottomhole pressure (ECD). A slight increase in the mudweight at this point then causes a sudden decrease in the background gas anconnection gas peaks disappear, indicating that a slight static overbalance has beeestablished.

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2-45March 1995

Figure 2.22 Schematic Diagram showing Mud Gas Levelsas an Indicator of Formation Pressures

One major problem with this type of interpretation is to distinguish connection peaks caused by effective mud weight reduction due to stopping circulating, from gswabbed into the wellbore when the drillstring is picked up. Swabbing effects are muchmore difficult to quantify than simple reductions from the ECD to static mud weigThis may result in higher than actual pore pressure estimates being made, especthe connection gases observed are entirely due to swabbing. Clearly, it is good practiceto use connection procedures that minimise swabbing. If used consistently, this will aidin the interpretation of connection gas levels.

(c) Trip Gas (TG)

This gas is produced by the same mechanism as connection gas, but the effect of swabbingdue to pulling the drillstring from the hole will generally be greater. This is because thecuttings will have been circulated from the annulus and pipe speeds will be great.

A trip gas peak will be observed on circulating bottoms up after a round tripnon-drilling operation.

Swabbing, due to pulling the drillstring out of the hole, may cause the whole ofopenhole section to be underbalanced. Thus the observed trip gas may not come frothe bottom of the hole but from somewhere higher in the openhole section, and twmore gas peaks may be observed. This effect may also appear for connections if there a high degree of swabbing or the hole is underbalanced. Lag time calculations slocate the depths/formations causing the gas peaks.

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2-46March 1995

Due to the complex causes of trip gas, it may only be used qualitatively in estimformation pressures. The early onset of trip gas after circulation is resumed may indicthat much of the openhole is slightly underbalanced. Other abnormal pressure indimust be consulted to confirm this.

(d) Miscellaneous Gases

These are mainly ‘kelly gas’, recirculated trip gas and carbide gas.

Figure 2.23 Example of Mud Gas Levels showing T rip Gas,Kelly Gas (Kelly Cut), and Recycled T rip Gas

TOTAL GAS

TIM

E

MUD WEIGHT

GAS LEVEL

10 20 30 40 50 60 70

10 20 30 40 50 60 70

10 20 30 40 50 60 70

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KELLY CUT

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2-47March 1995

Kelly gas (also known as ‘kelly cut’) is caused by air being circulated around the sysfrom a partly empty drillstring or kelly after a trip or connection. The air is pumped intothe borehole as a slug of mud aerated with compressed air. This enhances any gasdiffusion effects from formations to the borehole and may result in enrichment of aerated mud with the hydrocarbon gases. A gas peak will thus be recorded when thimud is circulated back to the surface.

Kelly gas due to connections is rarely seen as the kelly is usually kept full of mduring connections by closing the lower kelly cock. Kelly gas after a trip is sometimobserved (as shown in Figure 2.23) but should be easily distinguishable from othepeaks by experienced Mud Loggers. Although indicating the presence of hydrocarbogases, kelly gas is of no value for formation pressure evaluation.

Recirculated trip gas (or any other recirculated gas) behaves in a similar way to gas, and should be anticipated by the Mud Loggers from knowledge of the mud sytotal circulation time. An example is shown in Figure 2.23.

Carbide gas is used to check the calculated total circulation time and is caused by thLoggers putting calcium carbide down the drillpipe at a connection. The carbide reacts withthe water in the mud to produce acetylene, a hydrocarbon gas that is detected as gesharp gas peak when circulated round to surface. The circulation time can then be used tback calculate the openhole volume and thus to check for hole enlargement.

It must be noted that evaluation of formation pressures from gas levels relies entirehydrocarbon gases being present to some extent in the well being drilled. Occasio,very ‘dry’ holes are drilled which may be overpressured, but show very low backgrogas levels. In these wells, it is very difficult to use gas levels as a reliable formatiopressure indicator.

3.2 Temperature

Due to the radial flow of heat from the earth’s core to the surface, the subsurface temperatincreases with increasing depth. The geothermal gradient is the rate at which the temperatincreases with depth and is usually assumed to be constant for any given area. Howe, ithas been found that the temperature gradient across abnormally pressured formatgenerally higher than that found across normally pressured formations in the same a

This phenomenon can be explained by considering the thermal conductivity of the formaSince water has a thermal conductivity of about one-third to one-sixth that of most formmatrix materials, then formations with a higher water content (higher porosity) will halower thermal conductivity. These formations will thus have a higher geothermal gradieacross them. Overpressured shales usually have a higher water content than normal athus have higher than normal geothermal gradients across them.

The top of an overpressured shale should therefore be marked by a sharp incregeothermal gradient. This may often be reflected by an increase in the temperature ofreturn mud in the flowline. Also, the caprock immediately above a pressure transition zooften shows a reduced geothermal gradient due to increased compaction (higher thconductivity) and a lower than normal temperature at the top of the transition zone.Thiseffect is shown schematically in Figure 2.24. Again, this may be reflected in the flowlinemud temperature by a reduced flowline temperature gradient. In some cases, the flotemperature may even fall (negative gradient) and be then followed by a large increase asthe overpressured zone is penetrated, as shown schematically in the plot of flotemperature versus depth in Figure 2.25.

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2-48March 1995

The example in Figure 2.25 is, of course, an idealised case. The flowline temperature veryclearly reflects the changes in formation temperature and there are no other influenthe mud temperature. In practice, there are many other factors that affect the flowlinetemperature and make the interpretation of flowline temperature plots very difficult,especially offshore. Such factors include:

• Circulation rate.

• Rate of penetration.

• Time elapsed since the last trip (the mud in the hole heats up during a trip).

• Volume of the mud system.

• Surface treatments such as adding water, mud chemicals or weighting material.

• Ambient temperature (diurnal temperature changes, such as those encountered inregions, may cause large fluctuations in flowline temperatures).

• Lithology effects (sandstones and limestones generally have higher theconductivities than shales).

• Cooling effect of the sea around long marine risers.

Various methods are used to improve the interpretation of temperature-depth plots. Seffects can be minimised by measuring the temperature of the mud in both the flowlinthe suction pit (mud temperature into the hole), and then plotting lagged differentialtemperature. A sharp increase in differential pressures may then indicate entry into a presstransition zone. However, the temperature trends (flowline and differential) are still foundto be obscured by discontinuities at bit trips, wiper trips and other periods with no circulaThese discontinuities split the temperature depth plot into a series of unconnectedsegments, as shown in the left hand curve in Figure 2.26.

Since overpressure indications are based on temperature gradient changes rather thamagnitude of the flowline temperature, each depth segment on the temperature-depcan be investigated separately for gradient changes. It may, however, be helpful to plot thesegments end to end, disregarding the absolute temperatures, to produce a ‘smoothedAlso, end to end plotting of the individual segment trendlines may be of value, but carequired to ensure that this technique does not smooth out obvious gradient changesan individual segment. The three techniques for plotting flowline temperature are showFigure 2.26.


2-49March 1995

Figure 2.24 Schematic Diagram showing TheoreticalGeothermal Gradients and T emperatureProfile through an Overpressured Zone

Figure 2.25 Schematic Diagram showing ExpectedFlowline T emperature Response on Drillingthrough an Overpressured Zone

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2-50March 1995

Figure 2.26 Example Flowline T emperature Plots showingRaw Data Plot, End-to-end Plot andTrend-to-trend Plot

Due to the many factors affecting the flowline mud temperature, it is very difficult to interprettemperature-depth plots to evaluate formation pressures. At least, changes in the gradient othe plots may suggest that an overpressured zone has been penetrated. It is unlikeflowline temperature will be the primary indication of abnormal pressures, though it mwell be useful to support other pressure indicators.

(a) Bottomhole Formation Temperature (BHT)

The actual formation geothermal gradient can not be estimated from surface temperature measurements. Downhole formation temperatures are required. How,it is only possible to measure the downhole mud temperature. This is normally doneduring wireline logging runs as most logging tools contain a maximum recordthermometer. Mud temperatures recorded from consecutive logging runs are usepredict the actual bottomhole formation temperature, assuming that the maximtemperature is at the bottom of the hole.

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2-51March 1995

Figure 2.27 Example ‘Horner ’ Temperature Plot forEstimation of T rue BottomholeTemperature (BHT)

When drilling, the formations in the lower section of the hole are cooled by the mudcirculation. When circulation stops, the mud temperature begins to rise and graduaapproaches the formation temperature. It is estimated that about four days are requfor the mud temperature to reach equilibrium with the formation temperature. A modifiedHorner expression is used to model the temperature increase with time. By extrapola

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2-52March 1995

the temperature increases to infinite time, it is possible to estimate the formtemperature. The Horner temperature expression is:

T = Tf – c.log tC + tL

tL

(2-21)

where T = measured temperature (°F or °C) (from each wireline logging run)Tf = actual formation temperature (°F or °C)c = constanttC = circulation time at TDtL = time since circulation stopped

A plot of T versus log ((tC + tL)/tL) should thus give a straight line, as shown Figure␣2.27.

At ‘infinite time’ after circulation was stopped (i.e. tL = infinity), the value of log(tC␣+␣tL)/tL) equals zero. Hence, extrapolating the plot to intercept the temperaturegives the estimated actual formation temperature, as shown in Figure 2.27Thegeothermal gradients between the logging run end points can then be calculated. Incin the geothermal gradient may indicate the presence of abnormal pressures.

Unfortunately the actual formation temperature can only be estimated at logging pThus, only three or four formation temperatures can be estimated from which geothgradients can be established. These gradients are thus average gradients over signifidepth intervals and they can only be established after each hole section has been Hence, they are generally of little use in pressure evaluation while drilling, but confirm any flowline temperature trends that were noticed earlier.

3.3 Resistivity/Conductivity/Chlorides

The resistivity of a formation depends on the porosity and the dissolved salts concentin the formation pore water. Due to their higher pore water content, overpressured shgenerally have lower resistivities than normally pressured shales at the same depthsWhenusing water base muds, an attempt can be made to monitor this formation propemeasuring the mud conductivity (conductivity is simply the inverse of resistivity).

The mud conductivity at the flowline and suction pit can be measured and a convemade to chlorides. An increase in the differential chlorides, known as ‘delta-chloridesmay then indicate abnormal pressures. It is doubtful whether an increase in mud condudue to the release of pore water from drilled cuttings would be measurable. This is due tothe volume of pore water released being minute compared to the volume of mud.

However, pore water influxes from more permeable formations may be seen as chanmud conductivity or delta-cholrides. Hence, a warning of underbalanced conditions mgiven. The system is best suited to situations where there is a large difference between porewater and mud salinity. In these situations, the response of differential mud conductivity issimilar to that of mud gas levels showing influx peaks at connections or a gradual incdue to underbalanced conditions. This is shown schematically in Figure 2.28.

Obviously, mud conductivity as an abnormal pressure indicator has many limitationAlarge salinity contrast between mud filtrate and formation fluids is required. Thus, the methodis of little use in saline mud systems, unless of course, the mud filtrate salinity is mgreater than the formation water salinity. This could be the case with saturated salt apotassium chloride (KCl) mud systems, and may well result in a mirror image plot toshown in Figure 2.28.

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2-53March 1995

Figure 2.28 Example of T ypical Response of Differential MudConductivity/Delta Chlorides

3.4 Flowline Mud W eight

Continuous recording of the flowline mud weight will show mud density changes due tocutting or formation influxes. Some influxes are not always picked up by an increasreturn mud flow or by an increase in mud pit level, especially if the influx occurs gradudue to a very low permeability formation. Thus, an underbalanced situation due to abnormpressures may be indicated by a slight reduction in the flowline mud weight.

4 Cuttings Parameters

(a) Shale Bulk Density

The bulk density of normally compacted shales increases with depth. Overpresshales are generally undercompacted and thus have higher porosities and lowedensities than would be expected. If shale bulk density is plotted against depth as dprogresses, then a normal compaction trendline can be established. A decrease in shalebulk density away from the normal compaction trendline may then indicate the presof an overpressured zone. A schematic shale bulk density plot is shown in Figure 2.2

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2-54March 1995

The magnitude of abnormal pressures can be calculated from shale bulk density pusing the equivalent depth method (as described previously for d-exponent plots).

Figure 2.29 Schematic Shale Bulk Density/Depth Plot

Alternatively empirical curves, relating observed bulk density deviation from the normtrend to formation pressure gradient, can be used. However, such curves are areadependent, so can only be used if the appropriate area curve is available. Hence itusually be necessary to use the equivalent depth method if formation pressure magnitare required from shale bulk density plots.

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2-55March 1995

The most common methods of measuring shale bulk density at the rigsite are:

• Mud Balance

Shale cuttings are added to the mud balance cup until the balance reads 1.0(8.33␣ppg) with the cap on. The cup is then topped up with fresh water and re-weighe(W). The shale bulk density is then given by:

Bulk density (SG) = 1 (2-22)2 – W

• Density Column

A graduated column of fluid is prepared from a mixture of two fluids of differentdensities such that the density of the mixture varies with column height. The columnis calibrated using beads of known density which settle at different heights in thecolumn. Selected shale cuttings are then dropped into the column and the heigwhich they settle is converted to shale density using the calibration curve. The methodis illustrated in Figure 2.30.

Figure 2.30 Variable Density Column for Measuring ShaleBulk Density

The mud balance method has the advantage of being fast and simple and uses aquantity of cuttings to obtain a good average bulk density. The density column, however,requires selection of individual cuttings and multiple determinations to obtain an averdensity value. The mud balance method is probably the more representative method

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2-56March 1995

Use of shale bulk densities for the detection and evaluation of formation pressfrequently has the following limitations:

• Presence of shale gas in the cuttings decreases the bulk density values determ

• Cavings from higher up the hole may be part of the sample.

• The reliability of the data depends on the consistency and care taken by persowhen carrying out the density determinations.

• Formation age boundaries and unconformities may cause shifts in the nocompaction trendline. It may be necessary to determine individual normal compactrends for each geological age unit.

• Variations in the lithology, such as high carbonate content, silty/sandy shales emay cause significant variations in the bulk density determinations. Only good cshales should be plotted. The presence of high density minerals, such as pyrite, wincrease bulk density values and may mask the onset of abnormal pressures.

• Density measurements on cuttings from water base muds are usually low due tabsorption of water by the cuttings. Less reactive muds, such as oil base mudhighly inhibited water base muds, will give more accurate cuttings densities.

Figure 2.31 Response of Shale Bulk Density/Depth Plotsin Overpressures caused by V ariousMechanisms

NORMAL PRESSURE

SHALE DENSITY

COMPACTION DISEQUILIBRIUM

CLAY DIAGENESIS

AQUATHERMAL PRESSURING

TECTONIC PRESSURING

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2-57March 1995

• The response of shale bulk density values in abnormal pressured zones will with the type of mechanism that caused the overpressure. This is illustrated by theidealised plots shown in Figure 2.31. However, as most overpressures in shales arcaused by compaction disequilibrium and aquathermal pressuring, the most comresponse will be a decrease in shale bulk density at the top of an overpressured (See Chapter 1 Section 1.4 for explanations of the various causes of abnormaformation pressures.)

Despite the above limitations, shale bulk density plots can be a very valuable indicof abnormal pressures. They should be constructed during the drilling of all exploratioand appraisal wells, and are most useful when long shale sections are encountere

(b) Shale Factor

Shale factor is a measure of the cation exchange capacity (CEC) of shales. The CEC ofa shale is dependent on the montmorillonite content. This in turn depends on the degreeto which montmorillonite conversion to illite has progressed in the shale sinmontmorillonite has a much higher CEC than illite (See ‘Clay Diagenesis’, in Chapter␣1Section 1.4). The CEC is expressed in milli equivalents per 100 grams of samp(meq/100gm), and is termed the shale factor.

The shale factor of a sample of shale cuttings is determined using the methylene test. Basically, a suspension of powdered sample (in water) is titrated against a soluof methylene blue dye of known concentration. The end point of the titration is whenthe sample suspension water first turns blue. The shale factor is then calculated from:

shale = 100 X titrant X titrant (2-23)factor sample wt vol normality

(meq/100gm) (gm) (ml)

Pure montmorillonite clays have a high shale factor of about 100 meq/100gm. This isdue to the presence of many loosely bound cations (Na+, Ca++) between the clay platelets.However, pure illite clays, due to their tightly bound cation (K+) between clay patelets,have low shale factors of 10 to 40 meq/100gm. Thus, shale factor can be used to identifythe montmorillonite/illite content of shale samples.

For abnormal pressure evaluation, however, the use of shale factor is limited as it isdependent on the various mechanisms that may cause overpressures.

Generally, shale factor decreases with depth as montmorillonite is converted to illIn␣overpressured intervals caused by compaction disequilibrium (see Chapter 1Section␣1.4) clay dewatering has been restricted, which in turn restricts montmorillondiagenesis to illite. Thus a larger proportion of montmorillonite will be present in theoverpressured zone, resulting in an increase in shale factor. This is shown schematicallyin Figure 2.32␣(a).

However, overpressures caused by clay diagenesis (montmorillonite dehydration) show a decrease in shale factor on entering the overpressured zone. The proportion ofmontmorillonite has been reduced by conversion to illite, with the release of lageamounts of water. This causes increased pore pressure if water escape is restricted. Thisshale factor response is shown schematically in Figure 2.32 (b).

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2-58March 1995

Since compaction disequilibrium is thought to be the major contributing mechanismoverpressure development in shales, the shale factor response of Figure 2.32 (a)probably be the most dominant. However, the contribution of other overpressuremechanisms will complicate the interpretation of shale factor plots. This often resultsin shale factor being of little use in the detection of abnormal pressures.

Figure 2.32 Shale Factor/Depth Response to Overpressurecaused by Compaction Disequilibrium andClay Diagenesis

(c) Cuttings Character

The presence of cavings in drilled cuttings samples is an indication that the borehwall is unstable. Cavings are much larger than normal drilled cuttings and are readilyseen at the shale shakers. They are thought to be produced by two different mechanismswhich result in cavings of different shapes and sizes, these two mechanisms are:

• Underbalanced drilling

• Borehole stress relief

In underbalanced drilling conditions, the pore pressure in the formation adjacent to borehole is greater than the pressure in the borehole. In impermeable formations, sas shales, the pressure differential due to an underbalance may be high enough to excethe tensile strength of the shales. The shale will thus fail in tension and form cavingswhich fall into the borehole. These cavings are usually long, splintery, concave anddelicate, as illustrated in Figure 2.33 (a).

SHALE FACTORSHALE FACTOR

OVER PRESSURES

MONTMORILLONITE CONTENT INCREASE

(a) COMPACTION DISEQUILIBRIUM (b) CLAY DIAGENESIS

MONTMORILLONITE CONTENT DECREASE

OVERPRESSURES

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2-59March 1995

The natural stresses that are present in the earth’s crust vary regionally and with depthlithology etc. Drilling a hole through formations will relieve some of these stresdepending on the hole angle and direction in relation to the principal formation streThe result may be that the formation stress at the borehole wall is greater than the(pressure) due to the mud column. The borehole wall may then fail either in compressifrom vertical stresses or in tension due to horizontal stresses, or a combination oCavings produced in this manner tend to be blocky and rectangular in shape, as in Figure 2.33 (b).

Thus, the presence of cavings in cuttings samples will not necessarily mean thhole is underbalanced. However, other overpressure indicators should always examined in detail to confirm whether abnormal pressures are being encounteredif it can not be confirmed that the hole is underbalanced, it may still be necessaincrease the mud weight to regain hole stability, and avoid the problems caused bexcessive amounts of cuttings/cavings being present in the hole.

Figure 2.33 Characterisation of Shale Cavings Caused byUnderbalanced Conditions and Stress Relief

(d) Other Methods

Several other methods of formation pressure evaluation based on measurements ocuttings have been developed. These include shale cuttings resistivity, filtration rate ofshale cuttings slurry, filtrate (shale water) colour index, shale cuttings moisture indredox and pH potential of cuttings slurry and slurry filtrate. These methods are fairlycomplex and time consuming and thus have not gained wide acceptance as techniques. A more detailed discussion of these techniques is given by Fertl(17).

WEOX02.110

Typical shale caving produced by underbalanced conditions

(a) Typical shale caving produced by stress relief

(b)

PLAN

FRONT SIDE

SCALE

0.5in to 1.5in

CONCAVE SURFACE

TYPICALLY CRACKED

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2-60March 1995

5 Measurement While Drilling(MWD) Techniques

Measurement While Drilling (MWD) tools are now able to provide continuous downhodrilling parameter data and electric log data whilst drilling is in progress. The use of MWDdata in formation pressure evaluation follows the same principles as previously discufor surface measured drilling parameters, as outlined for wireline log data in Section 2.4 ofthis Chapter. The advantage of MWD data is that actual downhole drilling paramet(weight-on-bit, torque) are measured and the formation log data are obtained very shafter the formation has been drilled. Thus, formation log data and conventional ‘whilsdrilling’ techniques can be combined to evaluate formation pressures as drilling progre

The downhole drilling parameters of most relevance are:

• Weight-on-bit

The actual downhole weight-on-bit (WOB) is usually less than recorded at surfaceto the drag in the hole. Using the actual downhole WOB will give more accurate valuesfor d-exponent or the drilling rate method that is being used as a formation presindicator.

• Downhole Torque

Variations in torque at the bit may be used to indicate bit wear. This in turn may be used toaccount for bit wear in more complex drilling rate methods for estimating formation press

• Downhole Temperature

The difference between downhole annulus temperature and flowline temperaturesgive an indication of the amount of heat transferred from the formation to the muAsimilar effect to that described in ‘Differential Temperature’ on Page 2-50, should beobserved on drilling into an overpressured zone.

The MWD formation logs presently available for formation pressure evaluation are gamray, resistivity and most recently, porosity.

The gamma ray log is used to identify lithology. Shales show a high level of radioactivity,whereas sands and evaporites (except for complex salts) show a low level. Hence the gray log can be used to pick clean shale sections for overpressure determination by anyshale related parameters previously discussed. In particular, the gamma ray log can be usein conjunction with the MWD resistivity log to plot shale resistivities whilst drilling. Thetheory and method of formation pressure evaluation from shale resistivities is discufurther under ‘Wireline Logs’ in Section 2.4 of this Chapter.

The gamma ray log itself has been used as a formation pressure indicator. A normal depthrelated compaction trend was established with departures from this trend indicatingmagnitude of overpressures. However, it would appear that this method may only be valifor US Gulf Coast shales.

More recently, an MWD porosity log has become available. Thus shale porosities may bemeasured whilst drilling and a normal compaction trend established. Again, overpressuredshales will show an increase in porosity away from the decreasing normal trend. The MWDgamma ray log will also be required to pick clean shales, from which the porosity vacan be plotted.

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2-61March 1995

The combination of MWD logging techniques and downhole/surface measured driparameter techniques should enhance the ability to detect and evaluate formation prewhilst drilling is in progress. Developing MWD technology is continually assessed by DrilDivision, and reports periodically issued.

6 Mud Logging Service

The function of the wellsite mud logging service is twofold:

• Sampling and description of drilled cuttings, and hydrocarbons detection and evalua

• Monitoring and interpretation of drilling data for drilling optimisation and formatiopressure evaluation.

These functions, and their relation to information flow through a typical mud logging unitillustrated in Figure 2.34. The level to which the latter function is required depends the␣type of well being drilled. Usually exploration and appraisal wells require mlogging␣services capable of a higher level of formation pressure evaluation thandevelopment wells.

(a) Pressure Evaluation Service

In most mud logging services, there is a Pressure Evaluation Geologist or Engpermanently on duty in the mud logging unit. It is this individual’s responsibility toclosely monitor all the available formation pressure indicators and to communicateinformation to the Company supervisory personnel at the rigsite. He should also mformation pressure estimates based on all the available pressure indicatorsdiscussions with Company personnel), and be able to support these estimates withreasoning.

The Pressure Evaluation Geologist/Engineer holds a very responsible position amthe various rigsite personnel and should have many years experience in rigsitelogging work. It is important that a good level of communication is established maintained with the person(s) concerned in order that reliable formation presestimates are obtained and their implications speedily acted upon.

(b) Composite Logs

As part of the pressure evaluation service, the Pressure Evaluation Geologist/Engwil l prepare ‘composite logs’ showing well depth versus various selecoverpressure␣indicators. These logs are potentially most useful as they show graphicthe response of the various overpressure indicators to differing lithologies andformation␣pressure regimes. It is most important that these logs are kept up to denable up-to-the-minute pressure estimates to be made based on the informationby the logs.


2-62March 1995

Figure 2.34 Mud Logging Unit Functions and InformationFlow Diagram

KELLY POSITION

DEPTH PENETRATION RATE

GAS FROM MUDSTREAM

CARBON DIOXIDE

DISPLAY

PUMP RATE

MUD FLOW

MICRO GAS

H2S HYDROCARBONS

UV BOX

TOTAL GAS

CHROMATOGRAPH

EVALUATION

DATA STORAGE

REMOTE DATA DISPLAY

MUD pH/PHS

MUD RESISTIVITY

MUD WEIGHT

MUD TEMPERATURE

PIT LEVEL/PVT

MUD PRESS

BASICADDITIONAL

WIRELINE LOG DATA

FORMATION LOG

PRESSURE LOG

DENSITY

GEOCHEMICAL ANALYSIS

FORMATION CUTTINGS

COMPUTATION

CEC

GEOCHEMICAL LOG

REMOTE DATA TRANSMISSION

DRILLING PARAMETERS

KELLY HEIGHT

DRILL RATE

TOTAL DEPTH

HOOK LOAD

WEIGHT ON BIT

STANDPIPE PRESSURE

BIT REVOLUTIONS

ROTARY SPEEDTORQUE

CASING PRESSURE

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2-63March 1995

(c) Mud Logging Equipment

The equipment contained within a modern mud logging unit is very complex, and tare numerous differrent types of sensors available for measuring the various drillparameters. Different methods are also employed to relay the measured data to thelogging unit. It is not the intention of this manual to discuss the equipment used bindividual mud logging service companies. General sensor specifications are howgiven in Table 2.3.

Parameter to Required Preferred Sensor T ypebe Measured Accuracy

Mud Logging Service

Total gas +/- 0.1% Flame ionisationHydrogen sulphide +/- 1ppm Solid state semi-conductor instrumentConstituent gases +/- 0.5% Flame ionisation

Drilling Data Service

Depth +/- 10 cm Heave and tide compensationKelly position +/- 10 cm independent of kelly, for trip monitoringHookload +/- 200 lb Pressure transducer (strain gauge)Rotary speed +/- 1 rpm Proximity switchRotary torque +/- 5 amp Hall effect current sensorMud weight +/- 0.01 SG Gamma rayStandpipe pressure +/- 10 psi Strain gaugeChoke pressure +/- 10 psi Strain gaugeFlow rate in +/- 20 gpm Non-intrusive flow meterFlow rate out +/- 50 gpm Paddle type flow meterFlow rate out +/- 20 gpm Non-intrusive flow meterPump rate +/- 1 SPM Proximity switchesMud temperatures +/- 1°C Platinum resistancePit volumes +/- 5 bbl UltrasonicsTrip tank volume +/- 0.5 bbl Ultrasonics

Table 2.3 General Mud Logging Sensor Specifications

(d) Mud Logging Unit Suitability

The suitability of a mud logging unit for a Company drilling operation depends essenton the level of pressure evaluation service required, which in turn depends on theof well that is to be drilled. The basic geological sampling and mud logging servishould not vary significantly with the well type.

Once the required levels of mud logging and pressure evaluation services havedefined, then the suitability of individual mud logging units can be evaluated. The currentspecifications against which the mud logging units/services should be evaluatedcontained in BP report DTG/D/4/86(24).These specifications cover the basic mud logginservice (sampling, cuttings description etc), drilling data service (including presevaluation and drilling optimisation), reporting, software, data storage and persorequirements.

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7 Summary

The majority of the ‘whilst drilling’ formation pressure indicators discussed are oapplicable to massive shale sections interbedded with sandstone/siltstones. Howev, asmost of our drilling occurs in sedimentary basins containing such sections, then the techndiscussed are of direct relevance to our drilling operations.

The most reliable abnormal pressure indicators in shales are probably d-exponent (ordrilling rate method) in combination with gas levels and cuttings character (cavinOccasionally, one indicator may be particularly effective in showing the onset of abnormapressures, but this will probably not be apparent until drilling has progressed well intooverpressured zone.

It is stressed that all formation pressure indicators must be carefully examined to cothe possible abnormal pressures that may be implied by a particular overpressure ind.Also, the possibility of lithological changes should always be borne in mind when shchanges in abnormal pressure indicators are observed.

2-64March 1995


2-65March 1995

2.4 FORMATION PRESSURE EVALUATIONAFTER DRILLING

Paragraph Page

1 General 2-66

2 Formation Pressures from Wireline Logs 2-66

2.1 Sonic Log 2-66

2.2 Resistivity Log 2-70

2.3 Density Log 2-752.4 Other Logs 2-77

3 Direct Pressure Measurements 2-77

3.1 RFT/FIT Data 2-77

3.2 Drillstem Test Data 2-82

4 Summary 2-84

Illustrations

2.35 Schematic diagram showing the Operating Principleof the Sonic (BHC) Logging Tool 2-67

2.36 Schematic diagram showing Shale Sonic IntervalTravel Time Response in Overpressures 2-68

2.37 Schematic Shale Resistivity/Depth Plot showing Responsein Overpressures 2-71

2.38 Shale Resistivity/Depth Plot illustrating the ProblemsAssociated with Formation Pressure Interpretation 2-73

2.39 Empirical Correlations for Estimation of FormationPressures from Shale Resistivity Ratio 2-74

2.40 Log-derived Shale Bulk Density Plot on Semi-logarithmic Scales 2-76

2.41 Schematic diagram showing the RFT Pre-testand Sampling Principle 2-78

2.42 Diagram showing the Operation of the RFT Sample Probe 2-79

2.43 Example of an RFT Analogue Pressure Recording 2-79

2.44 Example of a Typical Drillstem Test String(for high pressure gas well) showing Position of Gauges 2-81

2.45 Example of a Typical Pressure Chart from a MechanicalGauge placed below the Tester Valve in the DST String 2-83

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2-66March 1995

1 General

After each intermediate and reservoir hole section has been drilled, the formatioelectrically logged to evaluate their physical characteristics and hydrocarbon potential.of these logs can be used to estimate formation pressures to confirm (or otherwisestimates made whilst the hole sections were being drilled. Formation pressures calfrom wireline logs are estimates only.

Direct formation pressure measurements are normally taken in the reservoir hole secusing a wireline repeat formation test (RFT) tool. Also, formation pressures are directmeasured in the ‘shut-in’ (pressure build-up) periods during drillstem testing (DSTpotential reservoir formations.

2 Formation Pressures from Wireline Logs

2.1 Sonic Log

The sonic logging tool measures the time, ∆t, required for a compressional sonic wavetravel through one foot (or metre) of formation. This is known as the interval transit tim(ITT) and is the reciprocal of formation interval velocity. The principle of operation of thesonic tool (borehole compensated (BHC) tool) is shown in Figure 2.35. Sonic pulsestwo transmitters travel through the formation, and are picked up by two pairs of receThe time difference between sonic arrivals at each pair of receivers is measured. The averagetime difference is then recorded to compensate for borehole geometry and tool tilt.

As discussed in Section 2.2 of this Chapter, overpressured shales show a higher sonic than normally pressured shales at the same depth. Thus, a plot of sonic ITT in shales versusdepth on semi-logarithmic axes should show a straight line compaction trend in norpressured shales. Departures from this line towards higher shale ITT values indabnormal pressures. The normal compaction trend and sonic log departure in overpresare shown in the schematic sonic log plot in Figure 2.36.

A discussion of the problems associated with the interpretation of ITT depth plots, is in relation to seismic ITT data in Section 2.2 of this Chapter. The main problem areas are

• Scales

Two types of formats have been proposed for plotting ITT-depth data. These are log-logplots (as suggested by Pennebaker(25)), and semi-log plots, as suggested above. Thesemi-log format is recommended as the linear depth scale enables direct comparsonic ITT data with other overpressure indicator plots.

• Normal Trend Line

It is sometimes very difficult to confidently establish the position of the normshale␣compaction trend line. The depth interval over which the sonic log data are obtaiin normally pressured upper hole sections is often too small to reliably establisnormal compaction trend. This is because logs are normally only obtained from besurface casing.

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2-67March 1995

Figure 2.35 Schematic diagram showing the OperatingPrinciple of the Sonic (BHC) Logging T ool

Dif ferent lithologies frequently have vastly different sonic ITTs. Care should be takento ensure that the normal compaction trend line is established through ITT valugood clean shale sections only. It may be necessary to make sonic log plots from sevewells (if data are available) in the area of interest. These may then be used to determinthe position and gradient of an average regional normal compaction trend line.

• The BHC sonic tool has a ‘depth of investigation’ of only a few inches into the borehwall. Hence, reactive shales that absorb water from the drilling mud, may exhibit hiITT values (higher porosity) than would be recorded if the shales were non-reacThese higher ITT values may falsely indicate the presence of abnormal formapressures. A deeper reading ‘long spacing sonic’ (SLS) tool is sometimes run. Whenavailable, the sonic log data from this deeper reading tool should be used in prefeto those from the BHC sonic tool.

T

T LOWER TRANSMITTERMUD CAKE

R1

R2

R3

R4

PAIRED RECEIVERS R1 + R3/R2 + R4

UPPER TRANSMITTER

t1

t2

t = t2 – t1

WEOX02.112


2-68March 1995

Figure 2.36 Schematic diagram showing Shale SonicInterval T ravel T ime Response inOverpressures

DE

PT

H


tSHALE INTERVAL TRAVEL TIME,

NORMAL COMPACTION TREND LINE

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2-69March 1995

• Unconformities/disconformities may produce a marked sudden shift in sonic ITT vaand may require a second separate normal compaction trend line to be establishe

Once the position of the normal compaction trend lines has been firmly established osemi-log sonic ITT-depth plot, then the depths and magnitudes of suspected abnopressures may be calculated. Several methods are available for estimating the magnitabnormal pressures from sonic log plots:

(a) Empirical Correlations

Charts relating the magnitude of formation pressures to the difference between theobserved shale ITT value and the extrapolated normal ITT value are available. Theseempirical correlations are area dependent, as shown by the examples in FigureNote that the correlation developed by Pennebaker(25) (Figure 2.10) should not be usedwith semi-log ITT plots. This was developed for use in conjunction with log-log seismITT plots and is probably only valid for the US Gulf Coast.

The empirical correlations are quick and easy to use as formation pressure gradienread directly from the charts. However, the correlations are area dependent, so their uis limited to areas for which correlations are available.

(b) Equivalent Depth Method

When no empirical correlation is available, the equivalent depth method may be uA full discussion of the method is given in connection with dc-exponent plots, inSection␣2.3 of this Chapter. Equation 2-12 is also used for formation pressucalculations from sonic ITT plots:

FPGO = OPGO – DE

DO

(OPGE – FPGNE) (2-12)

where FPGO = formation pressure gradient at depth of interest (psi/ft)OPGO = overburden pressure gradient at depth of interest (psi/ft)OPGE = overburden pressure gradient at equivalent depth (psi/ft)FPGNE = normal formation pressure gradient at equivalent depth (psi/ft)DO = depth of interest (ft)DE = equivalent depth (depth at which sonic ITT is equal to value at DO) (ft)

NOTE: Equation 2-12 can be used directly with gradients in SG, ppg or psi/ft adepths in metres or feet.

It is necessary to obtain overburden pressure gradient data for the well being investiin order to use the equivalent depth method. These data should be available in the formof an overburden gradient-depth plot in the Mud Logger’s report for the well.

The advantages and disadvantages of this method are discussed in Section 2.3 ofthis␣Chapter.

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2-70March 1995

(c) Eaton Equation

The following equation was presented by Eaton(12) for calculation of formation pressuresfrom sonic ITT plots, the derivation of which is exactly analogous to equation 2-which was developed for dc-exponent plots:

FPGO = OPGO – (OPGO – FPGN) ∆tN

∆tO

3.0

(2-24)

where FPGO and OPGO are as defined above and,

FPGN = normal formation pressure gradient (psi/ft)∆tN = extrapolated normal trend sonic ITT at depth of interest (µsec/ft)∆tO = observed sonic ITT at depth of interest (µsec/ft)

The value of the ITT ratio exponent, 3.0, was derived from actual well data.

Despite the problems outlined earlier, it is considered that the use of sonic ITT dataprovides the most reliable method of formation pressure evaluation from well logs.Theuse of an empirical correlation provides the quickest method of estimating the magnof abnormal pressures from sonic ITT plots. However, if a correlation is not availablefor the area of interest, it will be necessary to use either the equivalent depth meththe Eaton equation (or both). These latter methods require overburden pressure graddata which should be readily available in Mud Loggers’ reports for the well(s) uninvestigation.

2.2 Resistivity Log

The resistivity of shales depends on the following factors:

• Porosity

• Salinity of pore water

• Temperature

Temperature varies approximately linearly with depth and hence formation resistivitiesbe corrected for temperature. Also, the salinity of the pore water should not vary significantwith depth. Porosity is thus the major factor controlling shale resistivity.

Under normal compaction (i.e. in normal pressure environments), shale resistivity increwith depth since porosity decreases. A plot of shale resistivity versus depth will thus showan increasing trend with depth. In clean shale sections, any departure from this normaltowards lower shale resistivities may indicate an increase in porosity and hence overpres

Shale resistivity (Rsh) is plotted on a log scale versus depth on a linear scale. The shape andslope of the normal trend line will vary with the age and type of shales present. This willlead to individual normal compaction trends being developed for each area investigatis unlikely that any two areas will have identical normal compaction trends. A schematicshale resistivity-depth plot is shown in Figure 2.37. The normal compaction trend line maybe a curve or may approximate to a straight line over certain depth intervals, dependithe area under investigation.


2-71March 1995

Figure 2.37 Schematic Shale Resistivity/Depth Plotshowing Response in Overpressures

DE

PT

H

SHALE RESISTIVITY, Rsh (ohm-m)

0.4 0.6 0.8 1.0 1.5 2.0 3.0


CAP ROCK

TOP OF OVERPRESSURE

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2-72March 1995

Originally, shale resistivities were plotted from the amplified short normal (ASN) curvthe now absolute ES (electrical survey) logging suite. Today, a variety of resistivity loggingtools are run, from which shale resistivity plots may be made. The tools are designed fovarious depths of investigation from shallow to very deep. The deep reading tools recorthe true resistivity of virgin formation and thus near borehole effects (shale hydration, mufiltrate invasion in permeable zones) do not affect the resistivity values recorded.

The deep reading logs that should be used for resistivity plots are the ILd curve frodual induction laterolog (DIL) tool and the LLd curve from the dual laterolog (DLL) tThe dual laterolog tool requires a conductive mud, so it will not work in oil base mudsThedual induction laterolog will work in oil base or water base muds and tends to be the reslog that is normally run.

Possible problems that may be encountered with shale resistivity plots are:

• Only shale resistivities in thick clean shales must be plotted. It may be necessconsult a geologist in order to pick good clean shales from the well logs. Use the dreading resistivity curve available to plot true shale resistivities.

• It may be very difficult to firmly establish the shape and position of the normcompaction trend line from the resistivity plot for just one well. An average regionatrend may have to be established from the resistivity plots of many wells in the ainterest. Unconformities/disconformities and variations in geological age may sudden changes in shale resistivities which will affect the position of the normal trenline.

• Changes in formation water salinity may give false pressure indications. For exashales in the proximity of large salt masses (e.g. salt domes) have very low resistivdue to increased pore water salinity. This may indicate higher-than-actual formationpressures. Also, shales at depths less than 1000m below surface or the mudline, ucontain formation water fresher than sea water. This results in high resistivity valuethat may indicate lower-than-actual formation pressures.

The problems associated with interpreting shale resistivity plots are illustrated in Figure

Once the normal compaction trend has been firmly established, it is possible to estimmagnitude of any abnormal formation pressures indicated by the shale resistivity plot. Again,there are several methods available:

(a) Empirical Correlations

At depths where the observed shale resistivity values (Rsh(O)) diverge from the normaltrend value (Rsh(N)), the ratio of normal to observed shale resistivity (Rsh(O)/Rsh(N)) iscalculated. The corresponding formation pressure gradient is then read from a such as the one shown in Figure 2.39. As can be seen from this chart, the correlatioare area-dependent and the appropriate chart is required for the particular areainvestigation.

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2-73March 1995

Figure 2.38 Shale Resistivity/Depth Plot illustrating theProblems Associated with FormationPressure Interpretation

(b) Equivalent Depth Method

This method is identical to that previously discussed for dc-exponent plots (Section␣2.3)and sonic log plots (earlier this Section). Again, equation 2-12 is valid for use withshale resistivity plots:

FPGO = OPGO – DE

DO

(OPGE – FPGNE) (2-12)

where DE = equivalent depth (depth at which shale resistivity is equal to the valuthe depth of interest, DO) (ft)

and FPGO, OPGO, DO, OPGE, and FPGNE are as previously defined in connection witdc-exponent plots and sonic ITT plots. As explained previously, overburden gradientdata must be obtained (from Mud Loggers’ report) in order to use this method.

DE

PT

H

Rsh (ohm-m)

0.1 0.5 1.0 5.0

Normal pressure environment

Pressure

Erroneous trendN

ormal trend

top

Abnormally high pressure environment

Fresh water shales

Region 'A' limey shales

Region 'B' Lithology, not pressure, change

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2-74March 1995

Figure 2.39 Empirical Correlations for Estimation ofFormation Pressures from ShaleResistivity Ratio

(c) Eaton equation

Equation 2-25 was proposed by Eaton�(12)� for calculating formation pressfrom␣shale resistivity plots (derivation analogous to equation 2-18, developeddc-exponent plots):

FPGO = OPGO – (OPGO – FPGN) Rsh(N)

Rsh(O)

1.20

where FPGO, OPGO and FPGN are as defined for equation 2-24 (sonic log plots), an

Rsh(N) = extrapolated normal trend shale resistivity at depth of interest (ohm-m

Rsh(O) = observed shale resistivity at depth of interest (ohm-m)

Again, the value of the shale resistivity ratio exponent, 1.20, was derived from awell data. Overburden pressure gradients for the well are also required (fromLoggers’ well report) in order to use equation 2-25.

101.0

0.9

0.8

0.7

0.6

1.25

1.50

1.75

2.00

2.25

0.5

0.4

15

Normal R(sh)/observed R(sh)

E Riverton area, Wyo (Timko, 1972)

North Sea (limited data) (Timko, 1972)

South China Sea (Limited data) Timko, 1972

Hottman- Johnson, 1965

East Cameron Timko-Fertl, 1970

Eaton, 1972 (Range)

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2-75March 1995

(d) Formation Factor Method

This method was proposed by Foster and Whalen,(18) and is based on the equation:

Fsh = Rsh (2-26)Rw

where Fsh = shale formation factor (dimensionless)Rsh = shale resistivity (ohm-m)Rw = formation water resistivity (ohm-m)

Basically, the method involves computing a formation water resistivity (Rw) depth profilefrom the SP (spontaneous potential) curve in clean, shale free water sands. Values ofRsh are then obtained from thick, clean shales from whichever resistivity log is availa(ILd or LLd curve). Values of Fsh at depths corresponding to the Rsh values are thencalculated from equation 2-26.

A plot of Fsh versus depth on semi-log scales (linear depth scale) then shows a strline trend in normally pressured formations, Fsh increasing with depth. Departure fromthe normal trend towards decreasing Fsh values then indicates abnormal pressures. Themagnitude of any abnormal pressures can then be calculated using the equivalentmethod (as discussed in (b) above).

The major drawback with this method is the calculation of Rw values from the SP curve.The method is subject to inaccuracies, is difficult and is very time consuming. Theadvantage of this method is that it takes into account changes in formation wresistivity, Rw. Other methods rely on the assumption that formation water resistivremains relatively constant with depth.

The method is detailed in full by Foster and Whalen(18) and Fertl(17).

All the pressure evaluation methods using resistivity logs were developed for the US Coast and would appear to work quite well for this region. However, they have been foundto be of limited use in the North Sea. Formation water salinity variations cause erraticresponses which make it virtually impossible to construct a normal compaction trend.

2.3 Density Log

The formation density logging tool consists of a radioactive source which bombardsformations with medium-energy gamma rays. The gamma rays collide with electrons in theformation which cause the gamma rays to scatter. The degree of scattering is directly relateto the electron density and therefore the bulk density of the formation. The scattered gammarays that return to the borehole are picked up by detectors in the logging tool.

In the FDC (formation density compensated) logging tool, the gamma ray source anddetectors are mounted on a skid that is pushed against the borehole wall by an eccenarm. The skid has a plough shaped leading edge to cut through any mud cake present borehall wall. Any mud cake that is not removed will effect the tool reading. The dualdetectors of the FDC tool automatically compensate for mud cake effects. The correctedbulk density (Pb) and the correction made (∆ρ) are recorded on the FDC log.


2-76March 1995

Figure 2.40 Log-derived Shale Bulk Density Plot onSemi-logarithmic Scales

DE

PT

H

SHALE BULK DENSITY (gm/cc)



CAP ROCK

2.0 2.1 2.2 2.3 2.4 2.5 2.7

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2-77March 1995

A plot of shale bulk density versus depth on either linear or semi-log scales will shostraight line normal compaction trend. Since the bulk density of shales is inverproportional to porosity, and an increase in shale porosity indicates abnormal pressuthen a decrease in shale bulk density from the normal compaction trend line will indiabnormal pressures. The semi-log type plot is shown schematically in Figure 2.40.

The densities from non-washed-out pure shale sections should be plotted. After the normalcompaction trend line has been established, the equivalent depth method (See ‘Sonic’ and‘Resistivity Logs’) may be used to estimate the magnitude of formation pressures.

The use of shale bulk density trends from the formation density log should be a fairly reloverpressure indicator. However, it has been found that unless borehole conditions are id(uniform gauge hole), the formation density log will not be as accurate or reliable for presevaluation as other techniques based on sonic or resistivity logs.

2.4 Other Logs

Other wireline logs that have been used to evaluate formation pressures includspontaneous potential (SP) log, the neutron porosity log (CNL), the thermal neutron dtime log (TDT), and also downhole gravity and nuclear magnetic resonance (NMR) lThese techniques are discussed further by Fertl(17).

Also, the use of an MWD gamma ray log for formation pressure evaluation of US GCoast shales, has been discussed by Zoeller(34).

3 Direct Pressure Measurements

3.1 RFT/FIT Data

The repeat formation tester (RFT) is an electric wireline tool designed to measure formpressures and to obtain fluid samples from permeable formations. After it has been run inthe hole, the tool can be ‘set’ any number of times. This enables a series of pressure readinto be taken and permits the Logging Engineer to ‘pre-test’, or ‘probe’ the formationpermeable zones before attempting to take a fluid sample or a pressure recording.

The RFT was developed from the formation interval tester (FIT) which is only able to tone, less accurate, pressure measurement whilst taking a sample. However, the FIT is ableto take a pressure measurement/sample in cased hole by using a shaped charge to perforatethe casing.

A schematic diagram of the RFT pre-test and sampling principle is shown in Figure 2

on thef the

e).filterringigital


2-78March 1995

Figure 2.41 Schematic diagram showing the RFT Pre-testand Sampling Principle

When the tool is set, a packer moves out on one side and back-up pistons move out opposite side. This forces the packer against the borehole wall and holds the body otool away from the wall to reduce the chances of differential sticking. The probe is thenforced into the formation and opened by retracting the filter probe piston. This operation isshown in Figure 2.42.

The two pre-test chambers are then operated sequentially, each sampling a small volume(10cc) of the formation fluid at different rates (assuming that the formation is permeablA filter in the flowline probe prevents sand entry into the tool and the piston cleans the when the tool is retracted. A strain gauge pressure transducer monitors the pressure duthe pre-test. The pressure is continuously recorded at surface in both analogue and dform. An analogue pressure recording from a typical pre-test is shown in Figure 2.43.

FILTER PROBE

PRETEST CHAMBER

EQUALIZING VALVE (TO MUD COLUMN)

SEAL VALVE (TO LOWER SAMPLE

CHAMBER)

SEAL VALVE (TO UPPER SAMPLE CHAMBER)

FLOWLINE

PACKER

PRESSURE GAUGE

CHAMBER No 1

CHAMBER No 2

WEOX02.118

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2-79March 1995

Figure 2.42 Diagram showing the Operation of theRFT Sample Probe

Figure 2.43 Example of an RFT AnaloguePressure Recording

MUD CAKE

UN

CO

NS

OLI

DA

TE

D

SA

ND

PROBE CLOSED DURING

INITIAL SET

PROBE OPEN AND SAMPLING

PACKER

PROBE

PISTON

FLOWLINE

FILTER

W

FLOWRATE, Q

SHUT-IN

q2

q1

P1

t1t = 0 t2

TIME, t

FORMATION PRESSURE

HYDROSTATIC PRESSURE

PR

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, P

TIME, t

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2-80March 1995

The initial pressure (See Figure 2.43) before the tool is set is the hydrostatic pressuremud column. When the tool is set, the pressure rises slightly due to the compression mud cake by the packer. The probe piston then retracts giving a drop in pressure due tflowline volume expansion and communication with the formation. When the piston stopsretracting, there is a slight pressure rise because the packer continues to compress cake until the tool is fully set.

The pressure then drops again as the first 10cc pre-test piston starts to retract (at tO).After about 15 seconds, the first pre-test chamber is full (at time t1) and the second pistonbegins moving at a rate 2.5 times faster than the first piston. The pressure thus drops furtheuntil the second pre-test chamber is full (at time t2). The pressure then builds up towardsfinal pressure, which is usually that of the original formation pressure(30). Finally, the probeand packer are retracted and the mud hydrostatic pressure is again measured.

Thus, the RFT provides three distinct pieces of pressure data:

• The mud column hydrostatic pressure (two readings).

• The formation pressure.

• The pressure transient induced by the withdrawal of a small sample of formation(2 x 10cc).

The two mud hydrostatic pressure readings are compared to verify the stability of thesrecording system. The two values should be within a few psi of each other.

The formation pressure is used to verify estimates made whilst drilling the well aconstruct a reservoir pressure profile. This will yield data on the pressure gradients anature of the reservoir fluids.

The pressure/flowrate/time data from the pre-test sample withdrawal can be used to careservoir characteristics, such as permeability.

Hence, the RFT provides accurate data on formation pressures. However, formation pressuredata can only be obtained from permeable formations such as reservoir sandstonesTheseformations may or may not be at the same pressure as adjacent shales.

RFTs are normally run at the request of the Geologists/Petroleum Engineers toinformation on potential reservoir formations. However, in deep high pressure wells, thRFT is being increasingly run to obtain accurate formation pressures before potetroublesome drilling operations (such as coring) are commenced. Accurate knowledge offormation pressures in such wells allows fine mud weight adjustments to be made to mithe risk of swab/surge pressure problems.


2-81March 1995

Figure 2.44 Example of a T ypical Drillstem T est String(for a high pressure gas well) showingPosition of Gauges

5in PIPE RAMS

DESCRIPTION

Flowhead

Tubing

Lubricator Valve

Tubing

5in Slick Joint

Tubing

Tubing

Tubing

Tubing

Tubing (2 joints)

Crossover

Pressure Gauge Carrier + 2 Gauges



No-Go Shoulder of Seal Assembly

Permanent Packer

Millout Extension

Seal Assembly

Seal Bore Extension

Liner

Drill Collar (1 joint)

Drill Collar (1 joint)

Nipple

Annulus pressure operated Downhole Shut-in Tool (including tubing reverse-out facilities)

Downhole Safety Valve (surface controlled)

5in Slick Joint

MUD LINE

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2-82March 1995

3.2 Drillstem T est Data

Whenever drillstem tests are carried out on potential reservoir formations, various pregauges are run in the hole with the test string. The purpose of these pressure gauges isrecord the downhole pressure during the sequence of flow and shut-in periods that comthe drillstem test (DST). The pressures recorded during the test are used to calculate resecharacteristics such as formation pressure, permeability, skin damage and productivity index

Various types of pressure gauges are available. These are run in conjunction with clocksand recorders, and include:

• Mechanical gauges – normally bourdon tube (BT) type pressure gauges with mechaclocks and recorders.

• Electronic gauges – strain gauge, quartz crystal or bourdon tube type pressure gwith electronic clocks. Data are recorded on various types of electronic memoriesread from the gauge on surface after the test by a special reader.

• Electronic surface read out (SRO) gauges – strain gauge or quartz crystal type pregauges linked by cable to the surface where downhole pressures are continumonitored and recorded.

The mechanical and electronic gauges can be run in various ways/positions in the test

• Set in a wireline nipple (hence retrievable during or after a test).

• Hung off in the tailpipe (below the packer) using a DST hanging kit.

• Placed in a ‘bundle carrier’ or ‘gauge carrier’ in various positions in the string.

The SRO gauges are always placed above the tester valve (above the packer) as tconnected to surface equipment by a cable. A typical DST string is shown in Figure 2.44(for a gas well test). This illustrates the various positions of the pressure gauges inDST␣string.

After a DST has been successfully completed, the test string is pulled and the pregauges are retrieved for the pressure charts to be read. A typical valid pressure chart from amechanical gauge placed below the tester valve is shown in Figure 2.45. Note that aplot of the pressures recorded by an electronic gauge should have the same generawithout the baseline.

The significant events during the test (marked by capital letters) on Figure 2.45 are as fo

A: Atmospheric pressure at surface.

A-B: The gauge is run in the hole with the test string and records increasing hydrospressure. The early ‘steps’ effect is the result of pauses to pump the water cushiinto the test string.

B: At test interval depth, the gauge records the hydrostatic pressure of the mud co

C: The packer is set, squeezing the sump below the packer and causing an increpressure.

D-E: The tester valve is opened and the gauge is suddenly subjected to the rehydrostatic pressure of the water cushion alone.

rtial

.

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.122


2-83March 1995

Figure 2.45 Example of a T ypical Pressure Chart from aMechanical Gauge placed below the T esterValve in the DST String

E-F: The influx of reservoir fluid into the test string adds to the pressure of the pawater cushion.

F: The tester valve is shut after an initial 5 to 10 minute short flow period.

F-G: The reservoir pressure slowly builds up. After 30 minutes, no more build up is seenThe gauge now gives an estimate of the virgin reservoir pressure (G).

G-H: The tester valve is now opened again and the reservoir is exposed to hydropressure of the fluids in the test string.

H-I: The reservoir flows again and the gauge pressure increases until the water cureaches the surface.

I-J: As the reservoir fluid replaces the water cushion in the test string, the gauge predecreases until all the water cushion has been unloaded (J).

J-K: The pressure continues to fall due to wellbore effects before steadying out as thflow into the wellbore becomes radial.

K: The tester valve is closed at the end of the second flow period.

K-L: The reservoir pressure starts to build up again as it returns to equilibrium.

L-M: The packer is unset at the end of the second build up period and the pressureagain reads the pressure of the annulus mud column.

N-O: The test string is pulled out of the hole and the gauge pressures reduces.

O: Finally, the gauge is back on surface and reads atmospheric pressure.

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2-84March 1995

Analysis of the pressure build up data from the shut-in periods can then give acestimates of the reservoir formation pressure. An example of this analysis is given in the BGuide to Testing Operations.

Thus, data from drillstem tests can give accurate estimates of formation pressures. Ho,the pressure data can only be obtained from permeable reservoir formations thconsidered to have sufficient hydrocarbon potential to warrant the expense of a drillstest. As with RFT pressure data, the reservoir pressure calculated from DST data may ormay not be the same as the pressures in adjacent shales.

4 Summary

The most accurate estimates of formation pressures are obtained from wirelinemeasurements and drillstem test pressure data. However, these direct measurements aonly possible in permeable formations such as sandstones and limestones. These methodsare clearly not applicable to impermeable shale sections (where the majority of overpreare developed).

Conversely, estimates of formation pressures from wireline logs are restricteshale␣sections, with assumptions made as to the pressures in any adjacent permeable The recognition of a normal shale compaction trend line is of vital importawhen␣estimating formation pressures from log-derived shale properties. Of the variouavailable, the sonic log is usually the best log for quantitative pressure evaluationis␣relatively unaffected by changes in hole size, formation temperature, and formawater␣salinity.

Section 2 References

1. ANSTEY, N.A., 1976. the New Seismic Interpreter – Videotape Manual, InternationaHuman Resources Development Corporation, Boston, Massachusetts, USA.

2. BARR, M.V., 1983. An Appraisal of Seismic Reflection Techniques for the Recognitioand Prediction of Abnormal Formation Pressures. Report PEB/55/83. BP ResearchCentre, Sunbury.

3. BELLOTTI, P. and GERARD, R.E., 1976. Instantaneous Log Indicates PorosityPore Pressure. World Oil, Oct. 1976.

4. BINGHAM, M.G., 1965. A New Approach to Interpreting Rock Drillability. Oil andGas Journal, Nov. 2 1964?Apr. 5 1965.

5. BOURGOYNE, A.T., 1971. A Graphic Approach to Overpressure Detection WhileDrilling. Pet. Eng. 43(9): 76?78.

6. “BP”, 1985. A Guide to Testing Operations. BP Exploration Co. Ltd., Operations SuppoDivision, London. June 1985.

7. “BP”, 1986. A Wellsite Guide to Logging Operations. BP Exploration Co.Ltd., LoggingOperations Branch, London. January 1986.

8. “BP”, 1985. Resident Geologists Manual. BPPD Aberdeen. 2nd Edition, Sept. 1985.

9. COCHRANE, D.F. and HARDMAN, P., 1986. Shallow Gas Hazards in DrillinOperations. Report DTG/L/1/1986. BPPD London.

r␣2162.

?86.

ing

ing

ing

om

from

D

and

.

E

Plots.

from


2-85March 1995

10. COMBS, G.D., 1968. Prediction of Pore Pressure from Penetration Rate. SPE Pape

11. DIX, C.H., 1955. Seismic Velocities from Surface Measurements. Geophysics, 20: 68

12. EATON, B.A., 1975. The Equation of Geopressure Prediction from Well Logs.SPE␣Paper␣5544.

13. “EXLOG”, 1980. Field Geologist’s Training Guide. Exploration Logging Inc., USA.

14. “EXLOG”, 1979. Mud Logging: Principles and Interpretations. Exploration LoggInc., USA.

15. “EXLOG”, 1981. Theory and Evaluation of Formation Pressures. Exploration LoggInc., USA.

16. “EXXON”, 1975. Abnormal Pressure Technology, Exxon Company, USA.

17. FERTL, W.H., 1976. Abnormal Formation Pressures. Elsevier Scientific PublishCompany, Amsterdam.

18. FOSTER, J.B., amd WHALEN, H.E., 1966. Estimation of Formation Pressures frElectrical Surveys – Offshore Louisiana. SPE Paper 1200.

19. “GEARHART”, 1986. Overpressure. Gearhart Geodata Services Ltd., Aberdeen.

20. HOTTMAN, C.E., and JOHNSON, R.K., 1965. Estimation of Formation Pressures Log-derived Shale Properties. Journal of Petroleum Technology, 17: 717-723.

21. JORDEN, J.R., and SHIRLEY, O.J., 1966. Application of Drilling Performance Data toOverpressure Detection. Journal of Petroleum Technology, 18: 1387-1394.

22. LESSO, W.G. and BURGESS, T.M., 1986. Pore Pressure and Porosity from MWMeasurements. IADC/SPE Paper 14801.

23. MANN, D.M., 1985. The Generation of Overpressures During Sedimentation their␣Effects on the Primary Migration of Petroleum. Report GCB/156/85. BP ResearchCentre, Sunbury.

24. MINT ON, R.C., 1986. Technical Specification for Drilling Mud Logging ServiceReport␣DTG/D/4/86. BPPD Aberdeen.

25. PENNEBAKER, E.S., 1968. An Engineering Interpretation of Seismic Data. SPPaper␣2165.

26. PRENTICE, C.M., 1980. Formation Pressures from Normalized Penetration Rate Prentice and Records Enterprises, Inc., Lafayette, Louisiana, USA.

27. REHM, W.A., and McCLENDON, R., 1971. Measurement of Formation Pressure Drilling Data. SPE Paper 3601.

28. ROESLER, R.F., BARNETT, W.C., and PASKE, W.C., 1986. Theory and Applicationsof an MWD Neutron Porosity Sensor. SPE/IADC Paper 16057.

29. “SCHLUMBERGER”, 1972. Log Interpretation Volume 1 – Principles. SchlumbergerLtd., New York, USA.

30. “SCHLUMBERGER”, 1981. RFT – Essentials of Pressure Test Interpretation.Schlumberger Ltd.,

.

y


31. SINGH, J., 1987. A Review of Measurement-While-Drilling Systems. Report DTG/L3BPPD London.

32. VIDRINE, D.J., and BENIT, E.J., 1967. Field Verification of the Effect of DifferentialPressure on Drilling Rate. SPE Paper 1859.

33. ZOELLER, W.A., 1970. The Drilling Porosity Log “DPL”. SPE Paper 3066.

34. ZOELLER, W.A., 1983. Pore Pressure Detection from the MWD Gamma Ra.SPE␣Paper␣12166.

2-86March 1995


3 PRIMARY WELL CONTROL

Paragraph Page

1 General 3-2

2 Hydrostatic Pressure 3-2

3 Equivalent Mud Weight, EMW 3-2

4 Circulating Pressures and ECD 3-4

5 Calculating the Circulating Pressure Losses 3-7

6 Swab and Surge Pressures 3-10

7 Swab and Surge Calculations 3-12

Illustrations

3.1 Hydrostatic Pressure 3-3

3.2 The Effect of Flowline Elevation – shown in relationto calculation of formation pressure 3-5

3.3 Example Calculation of the Equivalent CirculatingDensity (ECD) 3-6

3.4 Theoretical Variation in Swab/Surge Pressure– when tripping pipe at constant speed 3-11

3.5 Pressure Surges associated with Lowering Pipe intoa Borehole 3-12

3-1March 1995

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3-2March 1995

1 General

Primary well control is maintained by controlling formation pore pressures with thydrostatic pressure of the drilling fluid.

Primary well control is exercised between two distinct limits; these being the maximformation pore pressure gradient and the minimum fracture pressure gradient in a sectiopenhole.

This Chapter is intended to outline the various factors that can influence the actual preexerted by the drilling fluid in the wellbore during routine drilling operations.

The effect of the following is considered:

• Flowline elevation.

• Circulation.

• Tripping pipe.

Easy to use formulae are presented to predict the effects of these factors.

2 Hydrostatic Pressure

The hydrostatic pressure of a column of drilling fluid is determined, in theory, by the density,and vertical height of the fluid above a point of interest.

The density of the drilling fluid and the height of the fluid column are related to the hydrostpressure as follows:

Hydrostatic pressure (psi) = MW (SG) X D (m) X 1.421

Figure 3.1 shows a sample calculation.

3 Equivalent Mud Weight, EMW

The most convenient method of describing downhole pressure is in terms of an equivmud weight (EMW).

EMW is used in order that downhole pressure can easily, and without confusion, be relatedto the density of a mud column. EMW can therefore be used to describe a formation preas well as a pressure applied by a column of mud.

The hydrostatic pressure of the mud column acts as a result of the height of fluid betwthe flowline and the point of interest in the wellbore. The EMW must therefore be referencedto the flowline.


3-3March 1995

Figure 3.1 Hydrostatic Pressure

VERTICAL DEPTH = 1000m

MEASURED DEPTH = 1200m

MUD @ 1.5 SG

The hydrostatic pressure at total depth in well A and well B= Density of the (SG) x vertical depth (m) x 1.421= 1.5 x 1000 x 1.421 = 2130 psi

A B

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3-4March 1995

It is important therefore that the effect of flowline elevation be considered when describiformation pressures in terms of an equivalent mud weight. This is because formation pressurare originally referred to sea-level, or the surface elevation, depending on whether this offshore or on land.

Figure 3.2 shows an example of the calculation of the EMW of a normally pressured formreferenced to the flowline of a semi-submersible drilling rig.

4 Circulating Pressures and ECD

When the well is static, the applied pressure at a given point in the well is equal hydrostatic pressure exerted by the head of fluid above that point.

Therefore if the hole is full to the flowline of 1.5 SG fluid, the EMW at any point in hole, referenced to the flowline, is 1.5 SG. However, if the pumps are started, the EMW atevery point in the well will no longer be equal to the weight of the mud. The EMW will begreater than 1.5 SG at every point in the wellbore.

The increase in EMW is due to the frictional pressure resulting from the flow of the muthe annulus. At each point in the well the EMW is increased by a factor reflecting the totfrictional pressure above that point.

Consider the example of a land well in Figure 3.3. As shown, when the well is beincirculated, the downhole pressures are described as equivalent circulating density o

There are many factors that can affect the ECD in a particular well, however the mofundamental factors are:

• The hole depth.

• The circulation rate.

• The mud weight.

• The rheology of the mud.

• The size of the hole.

• The OD of the drillstring.

• The quantity of cuttings in the annulus.(The presence of cuttings and drilled solids in the mud will have the effect of increasingthe effective mud weight and changing the mud rheology.)

It is clearly important to be able to estimate circulating pressure losses in order to be predict both the pump pressure and downhole ECD at specified circulating rates.

The next paragraph details the formulae that can be used to estimate circupressure␣losses.


3-5March 1995

Figure 3.2 The Effect of Flowline Elevation– shown in relation to calculation of

formation pressure

1 NORMALLY PRESSURED SHOWING SAND @ 300m BELOW SEA LEVEL

2

FLOWLINE ELEVATION

SEA LEVEL

SEA BED

SAND EQUIVALENT MUD WEIGHT REFERENCED TO THE FLOWLINE OF A SEMISUBMERSIBLE DRILLING RIG

Formation pressure at 325m BRT = 1.03 x 1.421 x 300 = 439psi

Normal pore pressure gradient = 1.03 SG

Formation pressure at this point referenced to the flowline, in EMW= = =

439 1.421 x 325

25m

100m

200m

0.95 SG

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3-6March 1995

Figure 3.3 Example Calculation of the EquivalentCirculating Density (ECD)

A HOLE STATIC

1.5 SG MUD IN THE HOLE

2000m

500m

Pressure drop = 100psi

Pressure drop = 150psi

Hydrostatic pressure EMW = 1.5 SG

Hydrostatic pressure EMW = 1.5 SG

Total pressure at shoe = (1.5 x 2000 x 1.421) + 100 = 4363psi ECD at shoe = 4363

2000 x 1.421

= 1.54 SG

B HOLE BEING CIRCULATED

PUMP

Total pressure at TD = (1.5 x 2500 x 1.421) + 250 = 5579psi ECD at TD = 5577

2500 x 1.421

= 1.57 SG

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3-7March 1995

5 Calculating the Circulating Pressure Losses

There are various models that attempt to describe the rheology of drilling fluids. The mostwidely used are the Bingham, Power Law and Modified Power Law Models.

The best results have been obtained using the Modified Power Law to model the behaof water base drilling fluids.

Very large discrepancies have been recorded between predicted and actual circulpressures when using the Modified Power Law to model the behaviour of oil base drilfluids. The cause of this discrepancy is considered to be primarily the variation in rheologcharacteristics of the oil mud under the influence of downhole conditions.

The Bingham Model is considerably easier to use than the Modified Power Law and, result, it is recommended for field use when the BP Hydraulics Programme is not availaIt is recognised that, at low velocity, the Bingham model may overestimate the frictionpressure of a mud that exhibits low gel strength.

The following procedure can be used to approximate circulating pressure losses usinBingham Model.

(a) For use inside the pipe:

1. Calculate PV and YP.

PV = Ø600 – Ø300 and YP = Ø300 – PV

2. Calculate the mud velocity .

v = 7.47 X Q (m/min)di

2

3. Calculate the pressure loss for the pipe section, assuming laminar flow .

P = L X PV X v + L X YP (psi)8361.5 X di

2 68.6 X di

4. Calculate the effective viscosity .

µ = 8361.5 X P X di2 (centipoise)

L X v

5. Calculate the Reynolds number .

Re = 422.8 X MW X v X di2

µ

The critical Reynolds number is assumed to be 2000 for Bingham fluids. If Re is␣lthan 2000, the flow is assumed to be laminar and the pressure loss is calculated␣the formula in step 3. If Re is greater than 2000, the flow is assumed to be non␣lamand the pressure loss must be re-calculated using the formulae in steps 6 and

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3-8March 1995

6. Calculate the Fanning friction factor .

f = 0.079Re0.25

7. Calculate the pressure loss for the pipe section in non laminar flow .

P = f X L X MW X v2 (psi)315.8 X di

8. Calculate the critical velocity .(ie the velocity above which the flow will be non laminar)

vc = 7.76 X PV + [7.76 X (PV2 + (102.79 X YP X MW X di

2) )12]

MW X di

(m/min)

(b) For use in the annulus:

1. Calculate the mud velocity .

v = 7.47 X Q (m/min)dhc

2 – do2

2. Calculate the pressure loss for the section of annulus assuming laminar␣flow .

P = L X PV X v + L X YP (psi)5574.32 (dhc – do)2 60.96 (dhc – do)

3. Calculate the effective viscosity .

µ = 5574.32 X P X (dhc – do)2 (centipoise)L X v

4. Calculate the Reynolds number .

Re = 422.8 X MW X v X (dhc – do)µ

The critical Reynolds number is assumed to be 3000 for Bingham fluids. If Rless than 3000, the flow in this section of the annulus is assumed to be laminathe pressure loss is calculated using the formula in step 2. If Re is greater than the flow is assumed to be non laminar and the pressure loss must be re-calcusing the formulae in steps 5 and 6:

5. Calculate the Fanning friction factor .

f = 0.079Re0.25

6. Calculate the pressure loss for the section of the annulus in non laminarflow .

P = f X L X MW X v2 (psi)315.8 X (dhc – do)

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3-9March 1995

7. Calculate the critical velocity .(The velocity above which the flow will be non laminar)

vc = 11.63 X PV + [11.63 X (PV2 + (51.46 X MW X YP X (dhc – do)

2))12]

MW X (dhc – do)

(m/min)

(c) To calculate the pressure drop across the bit:

1. Calculate the nozzle velocity .

vn = Q (m/sec)An X 10.23

2. Calculate the bit pressure loss.

∆Pbit = vn2 X MW (psi)12.49

where v = mud velocity (m/min)vn = nozzle velocity (m/min)Q = pump output (gal/min)di = ID of pipe (in.)dhc = ID of hole/casing (in.)do = OD of pipe (in.)L = length of section of pipe/annulus (m)PV = plastic viscosity (centipiose)YP = yield point (lb/100ft2)MW = mud weight (SG)µ = effective viscosity (centipiose)Ø600 = Fann viscometer reading at 600 rpm (lb/100ft2)Ø300 = Fann viscometer reading at 300 rpm (lb/100ft2)An = total nozzle area (in.2)P = section pressure loss (psi)∆Pbit = bit pressure loss (psi)

These formulae can be used to estimate the pressure drop in each section of pipe and The standpipe circulating pressure can be estimated from the sum of the pressureacross the bit and in all sections of the pipe and the annulus. The ECD at the bottom of thehole can be estimated from the total annulus pressure loss.

The annulus pressure losses may also be estimated when circulating by subtractcalculated pressure drop in the drillstring and the bit from the actual standpipe pre(accounting also for surface pressure losses).

This technique is likely to yield a more accurate estimate of the annulus pressure losthe following reasons:

• The inside measurements of the drillstring are more accurate than the openhole indiameter.

• The pressure drop through the bit is accurately modelled by the formula presente

• The effect of loading the annulus with cuttings is measured directly.

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3-10March 1995

The main disadvantage of this technique stems from the fact that the majority of the prloss in the system is in the drillstring and across the bit. Therefore, a small error in thcalculated pressure drop will cause a relatively large error in the estimate of the annulpressure loss.

6 Swab and Surge Pressures

Swab and surge pressures are caused by the movement of pipe in and out of the wel

Traditionally swab and surge pressures have been calculated using a steady state modis based on the assumption that swab and surge pressures are caused by three effects:

• Viscous drag of the mud as the pipe is moved.

• Inertial forces of the mud when the speed of the pipe is changed.

• Breaking the mud gel.

Therefore the factors that determine the magnitude of swab and surge pressures are assumto be:

• The annular clearance.

• The viscosity of the mud.

• The gel strength of the mud.

• The speed of the pipe.

• The length of low clearance pipe in the hole.

• The position of the low clearance pipe in the hole in relation to the point of intere

• The acceleration or deceleration of the pipe.

On the basis of these assumptions, typical variations in wellbore pressure due to swsurge pressures whilst tripping pipe are shown in Figures 3.4 and 3.5.

Recent studies however, have shown that steady state models are not adequate to modbehaviour of the mud while the pipe is tripped. It has been shown that swab andgepressures are best modelled as a transient, rather than a steady state phenomenon

The transient model assumes that a pressure wave is propogated at the instant thatbegins to move; the wave then travels down the well at the speed of sound and is reback up the hole. As a result of this effect, the pressure at a point in the well oscillates. Theoscillations will continue until either the pipe reaches a steady speed, or the pipe has sand the reflected pressure waves have diminished.


3-11March 1995

Figure 3.4 Theoretical V ariation in Swab/Surge Pressure– when tripping pipe at constant speed�

A

1

A

A

BIT

DE

PT

H

SURGE PRESSURE AT

MAX SURGE PRESSURE

WHEN BIT IS AT POINT

OF INTEREST

Increase due to BHA

RUNNING IN THE HOLE

1

Increase due to drillpipe

2

Decrease as BHA passes point

3

Constant stage pressure due to drillpipe in the casing

4

A

2

A

BIT

DE

PT

H

SWAB PRESSURE AT

MAX SWAB PRESSURE

WHEN BIT IS AT POINT

OF INTEREST

Reduction due to removal of BHA from the hole

PULLING OUT OF THE HOLE

4

Reduction due to removal of drillpipe from the hole

3

Influence of BHA2

Constant swab pressure due to drillpipe in the casing

1

WEOX02.126

enon

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3-12March 1995

Figure 3.5 Pressure Surges associated with LoweringPipe into a Borehole

The latest swab/surge software models the behaviour of the mud as a transient phenomand also accounts for the following factors:

• The compressibility of the mud.

• The elasticity of the wellbore.

• The change in rheological properties of the mud with pressure and temperature.

• The temperature profile in the wellbore.

• The elasticity of the pipe.

7 Swab and Surge Calculations

The swab/surge software that is able to model the transient response of the mud tomovement has been developed by Sunbury.

The software used by mud logging companies currently uses a steady state modeTheswab/surge pressures predicted by this model are subject to inaccuracy; especially inwells when the transient response of the mud is most significant.

PR

ES

SU

RE

TIME

0

A

B

C

D

E

WEOX02.127

Negative Surge – Pipe Lifted from Slips Positive Pressure to Break Mud Gel Minimum Pipe Velocity Maximum Pipe Velocity Negative Surge – Sudden Pipe Stoppage

A

B C D E

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3-13March 1995

The formulae used for the steady state model are relatively easy to use and, as suchused in the field to approximate swab/surge pressures.

The following procedure should be used to calculate swab/surge pressure for either open closed pipe:

1. Estimate the velocity of the mud for a given pipe running speed.

For closed pipe: v = CL + do 2

dhc 2 – do

2 X vp

For open pipe: v = CL + do

2 – di 2

dhc 2 – do

2 – di 2

X vp

where v = velocity of the mud (m/min)CL = clinging constantvp = average running speed of the pipe (m/min)

The clinging constant, K, is assumed to equal 0.45 in the absence of detailed fthat are used to predict this quantity.

2. Determine the maximum mud velocity .

The maximum mud velocity is generally taken to be 1.5 X the average velocity (acalculated in (1)).

3. Determine the swab/surge pressures due to the pipe movement.

The swab/surge pressure resulting from the pipe movement can be estimatesubstituting the maximum annular mud velocity as calculated in (2) into the formfor annular pressure loss (Bingham or Power Law).

The swab/surge pressure is added to the hydrostatic pressure of the mud if the pbeing run into the hole and subtracted if the pipe is being pulled. Therefore:

EMW at point of interest = MW ± sumPD X 1.421

(SG)

where sumP = total swab/surge pressure (psi)D = vertical depth to point of interest (m)

Preston Moore’s method can be used to approximate swab/surge pressures due to thmovement of a drillstring that contains a bit with nozzles. The range of values for the resultaswab/surge pressure that are predicted by this technique should be treated with some cas it is generally assumed that it will predict low values of swab/surge pressures.

The upper limit for swab/surge pressures for a drillstring with a bit and nozzles willrepresented by the value calculated for closed pipe.

nd

ity in

or

evel.

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ars.


3-14March 1995

The procedure for calculating swab/surge pressures for a drillstring that contains a bit anozzles is as follows:

1. Calculate the velocity of the mud around the drillpipe for open pipe.

Use the formulae as shown for the previous technique.

2. Calculate the swab/surge pressure generated by the drillpipe due to thepipe movement.

The swab/surge pressure can be calculated by substituting the annular mud velocthe formulae for annular pressure loss (Bingham or Power Law).

3. Calculate the velocity of the mud around the collars.

Use the following formulae:

v(drillcollar) = v(drillpipe) X Adp

Adc

where Adp = cross-sectional area of drillpipe annulus (in.2)Adc = cross-sectional area of drillcollar annulus (in.2)

4. Calculate the swab/surge pressure generated at the collars due topipe␣movement.

Use the formulae for annular pressure loss (Bingham or Power Law) and v(drillcollar) ascalculated in (3).

5. Calculate the total annular swab/surge pressure.

This is equal to the sum of the swab/surge pressures at the drillpipe and the collars,the sum of (2) and (3).

6. Calculate the swab/surge pressure inside the drillstring.

Using Preston Moore’s assumption that the fluid level outside the pipe equals the linside the pipe, the velocity of the mud inside the pipe equals the velocity outside

7. Calculate the swab/surge pressure generated inside the drillpipe.

Assuming that the mud velocity outside the pipe equals that inside the pipe, usformulae for internal pressure loss (Bingham or Power Law).

8. Calculate the swab/surge pressure generated inside the drillcollar .Assuming that the mud velocity outside the drillcollar equals that inside the collar, usethe formulae for internal pressure loss (Bingham or Power Law).

9. Calculate the swab/surge pressure generated at the bit.

Using the formulae:

vn = Q (m/sec)An X 10.23

∆Pbit = vn2 X MW (psi)12.49

where in this case the mud flowrate, Q, is equal to the mud flowrate through the coll

,

d

the


10. Calculate the total internal swab/surge pressure due to the pipe movement.

This is equal to the sum of the swab/surge pressures inside the drillstring, (6) plus (8)plus the bit swab/surge pressure as calculated in (9).

11. Estimate the actual swab/surge pressure due to the pipe movement.It is assumed that the actual swab/surge pressure will be between the values calculatein (5) and (10).

The resultant swab/surge pressure is added to the hydrostatic pressure of the mud if pipe is being run into the hole and subtracted if the pipe is being pulled. Therefore:

EMW at the point of interest = MW ± sumP (SG)D X 1.421

where sumP = total swab/surge pressure (psi)D = vertical depth to point of interest (m)

3-15March 1995

3-15/16


4 FRACTURE GRADIENT

Paragraph Page

1 General 4-2

2 Stresses in the Earth 4-2

3 Fracture Orientation 4-3

4 Fracture Gradient Prediction 4-4

5 Daines’ Method of Fracture Gradient Prediction 4-4

6 An Example Pressure Evaluation Log 4-7

7 Leak Off Tests 4-9

8 Leak Off Test Procedure 4-10

9 Interpretation of Results 4-11

Illustrations

4.1 Principal Stress Orientation 4-3

4.2 Poisson’s Ratio for Different Lithologies 4-5

4.3 An Example Pressure Evaluation Log

4.4 A Typical Fracture Test 4-12

4-1March 1995

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ate to

into

rock

d the

l.


4-2March 1995

1 General

The absolute upper limit of primary well control is the point at which the wellbore presequals the fracture pressure of the exposed formation. At this point a fracture is initiatedand the wellbore can no longer be considered to be a closed system. This will lead to loss ofmud from the hole and the possibility of the loss of primary control.

In order to drill a well safely therefore, it is useful for the Drilling Engineer to be ablepredict and measure fracture pressures.

At the well planning stage, the fracture gradient can be estimated from offset well data.If␣this information is not available then Daines’ Method can be used to predict the fracgradient.

As the well is drilled, Leak Off Tests are carried out to assess the mud holding capabilitthe openhole. It is Company policy that these tests be carried out to leak off point, which inmost cases will represent a pressure that is less than the actual fracture initiation preThe leak off pressure is converted to an equivalent mud weight which determines the ulimit of primary control for the next hole section.

LO tests are generally carried out once in each openhole section after drilling out oshoe. However the test should be repeated when weaker zones are drilled into. It practical to conduct a leak off test at every change in formation and consequently it is useto be able to predict the fracture gradient of new formations without conducting furtheroff tests.

Before covering the techniques that are used to predict fracture gradient, it is appropriexplain the origins of the stresses that occur naturally below the surface of the earth.

2 Stresses in the Earth

At any point below the earth’s surface, the resultant stress in the rock can be resolved three principal stresses that act at right angles to each other; these being:

• The maximum stress.

• The intermediate stress.

• The minimum stress.

In most cases, the maximum stress will be vertical, due to the pressure of the overlyingand pore fluid. This is defined as the overburden pressure.

In a tectonically relaxed area the maximum stress will, in most cases, be vertical anstresses in the horizontal plane will be equal. At shallow depths however, the horizontalstress may be greater than the vertical stress, even in a tectonically relaxed area.

Figure 4.1 shows the effect of tectonic forces on the principal stresses. A small tectonicforce ensures that the two principal stresses in the horizontal plane are no longer equaThishas the effect of creating an actual intermediate stress.

ximumgiont

at any

right

, and

ligible,ed inre

res due


4-3March 1995

Figure 4.1 Principal Stress Orientation

In an area where tectonic stresses are particularly high, it is possible that the maprincipal stress acts horizontally. This may be the case, for example, in a mountainous rewhere the formations may be severely folded. However, this is unlikely to occur at greadepths where the overburden pressure is generally the predominant factor.

3 Fracture Orientation

A fracture will be created if wellbore pressures exceed the minimum principal stress point in the openhole.

The fracture will propogate along the path of minimum resistance, which will be at angles to the direction of the minimum principal stress.

Fractures will therefore be vertical when the minimum principal stress is horizontalhorizontal if the minimum principal stress is vertical. (See Figure 4.1).

Consequently induced fractures will be vertical in areas where tectonic forces are negexcept possibly at very shallow depths. However horizontal fractures may be formareas where tectonic forces are significant. In effect, it is necessary for the applied pressuto lift the weight of the overburden for horizontal fractures to be formed. This is unlikely tooccur at depth when overburden pressure will, in most cases, be greater than pressuto tectonic forces.

– Tectonically relaxed area – σ'1 is vertical – σ'2 = σ'3 – induced fractures will be vertical

1 under the influence of a small tectonic stress σ'1 is vertical σ'2 = σ3 an actual intermediate stress is created

maximum principal stress intermediate principal stress minimum principal stress

–

– –

= = =

2

σ'1 σ'2 σ'3

in an area that is significantly affected by tectonic stress σ'1 is horizontal induced fractures will be horizontal

–

– –

3

σ'1

σ'2

σ'3

σ'1

σ'3

σ'2

σ'3

σ'2

σ'1

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4-4March 1995

4 Fracture Gradient Prediction

Many different techniques can be used to estimate fracture gradients. Hubbert and Williswere the first to derive a method, but they were followed, amongst others, by Ben Ewhose technique is currently used by Anadrill, Geoservices and Gearhart.

Eaton’s Method was refined by Daines, in 1982, whose technique has since been usExlog.

Eaton’s Method is most applicable to predicting fracture pressures in areas where adeal of data relating to subsurface stress regimes is already available. Eaton’s Method relieson the availability of accurate locally calculated stress coefficients to predict fracturepressures. When such information is available, such as in the Gulf Coast, this methodbeen shown to be very accurate.

However, in areas where the subsurface stress regime is relatively unknown, it is not poto use Eaton’s Method with any degree of accuracy.

Daines’ Method is particularly useful in wildcat areas, because the result of the first LOcarried out in a competent formation is used to measure the subsurface stress regime d.The coefficients that are used to calculate the fracture pressures are specific to each lith,but are applicable worldwide. As a result, once the first LO test has been carried out, possible to predict the fracture pressure in subsequent formations with reasonable ac.This technique has proved particularly accurate in wildcat wells in the North Sea.

5 Daines’ Method of Fracture Gradient Prediction

Having conducted the first LO test in a competent formation, Daines’ Method can beto predict fracture pressures in all types of formation types, with the use of the valuePoisson’s ratio as shown in Figure 4.2.

The following procedure can be used after the first LO Test (assuming the maximum effectivestress to be vertical and due to the overburden):

1. Calculate the magnitude of the tectonic stress.

The magnitude of the tectonic stress is calculated at the depth of the first LO testThisis done using the following formula:

σt = Pfrac – σ'l µ

l – µ – Pf

where σt = tectonic stress (psi)Pfrac= fracture pressure (psi)σ'1 = maximum effective principle stress (psi)µ = Poisson’s ratio for the rockPf = formation pore pressure (psi)

and σ'1 = S – Pf

where S = overburden pressure (psi)


4-5March 1995

Figure 4.2 Poisson’ s Ratio f or Diff erent Lithologies

Clay, very wet 0.50

Clay 0.17

Conglomerate 0.20

Dolomite 0.21

Greywacke:coarse 0.07fine 0.23medium 0.24

Limestone:fine, medium 0.28medium, calcarenitic 0.31porous 0.20stylolitic 0.27fossiliferous 0.09bedded fossils 0.17shaley 0.17

Sandstone:coarse 0.05coarse, cemented 0.10fine 0.03very fine 0.04medium 0.06poorly sorted, clayey 0.24fossiliferous 0.01

Shale:Calcereous (<50% CaC03) 0.14dolomitic 0.28siliceous 0.12silty (<70% silt) 0.17sandy (<70% sand) 0.12kerogenaceous 0.25

Siltstone 0.08

Slate 0.13

Tuff: Glass 0.13

From Weurker H.G: “Annotated Tables of Strength and Elastic Properties of Rocks,”Drilling, reprint Series SPE Dallas (1963).

mined

t␣holeerally

pth.

culated

ssure

ensity

tress

acture


4-6March 1995

The overburden pressure is determined from density logs, or from bulk densities deterfrom the cuttings.

2. Calculate the tectonic stress coefficient.

The tectonic stress coefficient can be calculated as follows:

β = σt / σ'1

where β = tectonic stress coefficient

This value is used to predict the magnitude of the tectonic stress throughout the nexsection until the next LO test can be used to recalculate the figure. It is however genthe case that σ'1 remains directly proportional to σt throughout the well, if the rockstrata are horizontal and the basin structure does not change significantly with de

Having calculated the above figures at the first LO test, the fracture pressure can be calas drilling proceeds in the following manner:

3. Calculate the maximum principal stress at the point of interest.

The magnitude of the maximum principal stress is calculated from the pore preand the overburden pressure as follows:

σ'1 = S – Pf

where S = overburden pressure (psi)Pf = pore pressure (psi)

The overburden pressure can be calculated from density logs, or from the bulk dvalues determined from the cuttings.

4. Calculate the tectonic stress at the point of interest.

The magnitude of the tectonic stress is calculated from the maximum principal sand the tectonic stress coefficient as follows:

σ t = σ'1 X β

5. Calculate the fracture pressure at the point of interest.

Using Figure 4.2 to determine a value for the Poisson’s ratio for the rock, the fracturepressure can be calculated from the following formula:

Pfrac = σt + σ'l µ

l – µ + Pf (psi)

where Pfrac = fracture pressure at the point of interest (psi)

This procedure can be repeated as the well is drilled in order to map the trend in frgradient with depth.

ed by

tone.rom theys

only bewulation

ditions

ant.

talurden

n the

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4-7March 1995

6 An Example Pressure Evaluation Log

Figure 4.3 (contained in wallet) shows an example Pressure Evaluation Log producExlog for a well drilled in the North Sea.

From the 30 in. casing point to the 18 5/8 in. casing point, the formation is mudsFrom␣the log, the fracture pressure appears to be greater than overburden pressure fseabed to approximately 1450m. This is a typical feature of young unconsolidated clawhich can behave as a liquid and as such have relatively high Poisson’s ratio of the order of0.5. Such clays possess negligible shear strength and, as a result, the formation mayfractured by actually lifting the overburden. The calculated fracture gradient at shallodepths should therefore be greater than the overburden; as shown in the following calcusing Daines’ formula:


l – µ + Pf (SG)

at 600m BRT the fracture pressure is calculated:

Pfrac = 0.4 (1.79 – 1.00) + (1.79 – 1.00) 0.44l – 0.44

+ 1.0

Pfrac = 1.93 SG

An interesting case would be to estimate the fracture gradient of a sand at these conand at this depth. Using the same formula, but substituting a Poisson’s ratio of 0.01 for atypical shallow marine sand, the fracture gradient is calculated as follows:

Pfrac = 0.4 (1.79 – 1.00) + (1.79 – 1.00) 0.01l – 0.01

+ 1.0

Pfrac = 1.32 SG

The possible variation in fracture gradients at these depths is therefore quite signific

After 1450m, the clays have sufficiently dewatered due to compaction to support a horizonstress. As a result, the fracture gradient is reduced to a value that is less than the overbgradient. This means that vertical fractures may be formed at pressures lower thaoverburden pressure.

The tectonic stress coefficient is calculated from the result of the LO test carried out at 18 5/8 in. casing shoe. This is the first point at which the clays are assumed to be adequcompacted so as to predict a reasonable figure for the tectonic stress coefficient as follows:

σt = Pfrac – σ'l µ

l – µ – Pf (SG)

burdention in

in the

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lightly

2 1/4 in.

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4-8March 1995

from the result of the LO test:

σt = 1.8 – (1.95 – 1.53) 0.2l – 0.2

– 1.53

= 0.165 SG

therefore the tectonic stress coefficient is given by:

β = σ t = 0.165 = 0.39σ'1 (1.95 – 1.53)

and this value of – is used to calculate the tectonic stress in subsequent rock strata.

From the 18 5/8 in. shoe to 2880m, the fracture gradient increases in line with the overgradient. At 2880m, the pore pressure gradient begins to decrease, causing a reducthe calculated fracture gradient to 1.88 SG at 3100m.

At 3120m, the formation changes to a sandstone interbedded with siltstone. A Poisson’sratio of 0.06 is chosen for these loose fine grained sands which results in a reductioncalculated value of the fracture gradient to approximately 1.72 SG.

At 3220m, the formation changes to limestone, for which a Poisson’s ratio of 0.28 is usedTherefore at 3400m, the fracture gradient is calculated as follows using Daines’ form


l – µ + Pf (SG)

whereσ'1 = S – Pp = 2.24 – 1.25 = 0.99 SGσ t = 0.39 – 0.99 = 0.39 SG

Therefore:

Pfrac = 0.39 + 0.99 0.28l – 0.28

+ 1.25

Pfrac = 2.03 SG

The LO test at the 13 3/8 in. shoe shows a fracture gradient of 2.13 SG, which is shigher than the predicted figure.

The fracture pressure then increases with depth and pore pressure throughout the 1section to a calculated maximum of 2.23 SG at the 9 5/8 in. casing point. The LO test at thispoint confirms a 2.21 SG fracture gradient.

Mud was lost to the sandstone stringers at the base of the limestone (4200m) at an 2.06 SG. This figure is therefore taken to be the minimum fracture gradient in the 8 1hole. However, the actual fracture gradient of the mudstone increases with depth and iwith the pore pressure, to 2.205 SG at 4429m.

A Poisson’s ratio of 0.06 is used to calculate the fracture gradient in the sandstone safter 4429m. The fracture pressure in the sand remains constant at 2.16 SG until the formbecomes interbedded with mudstone, at which point, the calculated fracture pressure into 2.22 SG.

The underlying mudstone has a calculated fracture gradient of 2.22 SG.

hole

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4-9March 1995

7 Leak Off Tests

The purposes of carrying out a leak off test are:

• To establish the upper limit of primary control for a section of openhole.

• To test the effectiveness of a cement job.

Company policy is that:

“Leak off tests or competency tests will be performed prior to drilling each newsection (except for conductors).”

The following guidelines are offered:

“Leak off tests should be performed after drilling 3 to 5m of new hole belowcasing␣shoe.

Leak off tests should be taken to leak off unless:

• The pressure exceeds that to which the casing was tested.

• (On a development well) where the pressure may be limited to that required tsafely the next section of hole (competency test).

When drilling through sands, or permeable rock, at any point below the casingconsideration should be given to carrying out a further LO test to ascertain the nestrength, and thus, the ability of the hole to contain a kick. Leak off tests should not bconducted in brittle formations (eg fractured limestone).’’

Company policy is therefore to restrict applied pressures to a maximum representedLO point. The reason for this is that, in many cases, it is not certain that an induced frwill heal completely to withstand the pressure that originally caused it to fracture. Fieldevidence , however, sug gests that in most cases induced fractures will healcompletel y. However it is difficult to predict the circumstances in which fractures will heal completely and hence permanently weaken the formation.

It has been suggested that the drilling process locks additional stresses into the rockthe wellbore, thereby increasing the pressure required to cause a fracture. If a fracreated, these additional stresses are released and consequently the pressure requopen the fracture may be less than that originally required.

It is accepted, however, that particularly brittle rocks, such as limestone, will show vlittle inelastic behaviour prior to fracture. As a result, there may be no clear leak off beforea fracture occurs. A brittle formation may be permanently weakened by an induced fraand consequently it is not recommended to conduct LO tests in such formations.

a Dead

nd

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istics

ount

O test.


4-10March 1995

8 Leak Off Test Procedure

The following general procedure is recommended for conducting LO tests:

1. Ensure that suitable pressure gauges are available.�

The gauges should be of a suitable range and have been recently calibrated withWeight Tester.

2. Assess the upper limit for the test.

It may not be necessary to conduct a leak off test in a development well when pore afracture pressures are well defined; in which case, a limit test will suffice. The absoluteupper limit for all types of test will be the overburden gradient at current depth.

NOTE: This may be lower than 2.31 SG or 1 psi/ft, as is common in deep water offshore.

3. Determine the estimated fracture pressure.

The mud logging company will provide an estimate of the fracture pressure at cdepth. This figure may be used as an upper limit for the test, or to interpret any anoobserved during the test.

4. Test the casing prior to drilling out of the shoe .

An estimate of the volume of fluid required to pressurise the hole can be detefrom the bulk modulus of elasticity of the fluid that is in the hole.

∆V = ∆P X VK

when ∆V = volume required to pressurise hole (bbl)V = volume to be pressurised (bbl)∆P = required increase in pressure (psi)K = bulk modulus of elasticity (psi)

The bulk modulus of elasticity of a drilling fluid is determined by the characterof␣the base fluid as well as the solids content of the fluid. The following figures canbe␣used:

K, water = 290,000 – 335,000 psiK, BP H3HF Base Oil= 160,000 – 260,000 psi

The bulk modulus of actual drilling fluids will be greater than these figures by an amrelated to solids content.

Plot a graph of pressure versus mud pumped to establish linearity prior to the L

5. Drill out of the shoe and 3 to 5 m of new hole.

6. Circulate and condition the mud.

7. Pull up into the casing.

8. Line up the pump to the annulus and displace all lines to the well to mud.

9. Close the BOP .

d. Plot

d low

tween

of thehatplied

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ure as

d. pressure

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ation


4-11March 1995

10. Run the pump at a constant 0.3 to 0.5 bbl/min.

Monitor the pressure build up, and accurately record the volume of mud pumpepressure versus volume of mud pumped.

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

Record the final pump pressure and calculate LO EMW.

12. Bleed back mud from the well and compare with the volume pumped.

9 Interpretation of Results

Figure 4.4 shows the result of a typical fracture test carried out in a consolidatepermeability formation in a tectonically relaxed area.

NOTE: It is Compan y polic y that the test is stopped at leak off point .

From points 1 to 2, the exposed rock is deforming elastically as the relationship bepressure and volume pumped is linear.

At point 2, the pressure in the wellbore at the exposed formation is equal to the sumpore pressure and the minimum horizontal effective stress. In other words, any cracks texist at the wellbore and in the vertical plane will be in a state of equilibrium, the appressure exactly counteracting the naturally occurring compressive forces. At point 3, whichrepresents the leak off point (because it is the first noted deviation from the linrelationship), the pump would normally be stopped and the pressure bled down in linCompany policy.

If the pump was left running, the pressure would eventually build to fracture pressshown. From points 2 to 4, the formation is deforming plastically, in that for the sameincrement of applied stress (pressure), a greater level of strain (volume) is produceThedifference between the pressure at point 2 and the pressure at point 4 represents therequired to initiate the fracture.

If the pump was stopped at point 4, as is shown on the diagram, the fracture wopropogate further into the formation and the pressure will drop to point 5. The pressure apoint 5 should be equal to the pressure at point 2. If the pressure is then bled doreturned volume should be equal to the volume pumped into the hole; if it is significless, then the fracture may be still be open.

If the pump was kept running after point 4, the fracture would propogate into the format a pressure slightly lower than point 4, or the fracture propogation pressure.

WEOX02.130


LEAK OFF PRESSURE

bbl PUMPED

GA

UG

E P

RE

SS

UR

E, p

si

1 2

2

3

1

1

2 3

3

4

4

5

TIME, MINUTES

PRESSURE BLED DOWN

FRACTURE PRESSURE (pump stopped)

(the pump would normally be stopped at this point)

Figure 4.4 A Typical Fracture Test

4-12March 1995


5-1March 1995

5 BASICS OF WELL CONTROL

Paragraph Page

1 General 5-3

2 Displacing a Kick from the Hole 5-3

3 Factors that Affect Wellbore Pressures 5-8

4 Subsea Considerations 5-19

5 Safety Factors 5-24

6 Calculating Annulus Pressure Profiles 5-27

Illustrations

5.1 Choke and Standpipe Pressure – during the first circulationof the Driller’s Method 5-5

5.2 Pit Gain – during the first circulation of the Driller’s Method 5-5

5.3 Shoe Pressure – during the first circulation of the Driller’s Method 5-6

5.4 Choke and Standpipe Pressure – during the secondcirculation of the Driller’s Method 5-6

5.5 Choke and Standpipe Pressure – during the Wait andWeight Method 5-7

5.6 Shoe Pressure – during the Wait and Weight Method 5-8

5.7 Choke Pressure – during the Driller’s Method for variousinflux volumes 5-9

5.8 Choke Pressure – during the Wait and Weight Methodfor various influx volumes 5-9

5.9 Shoe Pressure – during the Driller’s Method for variousinflux volumes 5-11

5.10 Shoe Pressure – during the Wait and Weight Methodfor various influx volumes 5-11

5.11 Choke Pressure – during the Wait and Weight Methodand the Driller’s Method for two different influx volumes 5-12

5.12 Choke Pressure – during displacement of a gas kickusing the Driller’s Method for various kick intensities 5-12

5.13 Choke Pressure – during displacement of a gas kickusing the Wait and Weight Method for various kick intensities 5-13


5-2March 1995

5.14 Choke Pressure – during displacement of a gas kickusing the Wait and Weight Method for various kick intensities 5-13

5.15 A Comparison of the Shoe Pressure – during displacementusing the Driller’s and Wait and Weight Method for twogas kicks of different intensities 5-14

5.16 A Comparison of Shoe Pressures – during displacementof a 20 barrel gas kick for various shoe depths 5-15

5.17 A Comparison of Shoe Pressures – during displacementof a gas kick shoe at 3000m 5-15





5.22 Choke Pressure – during displacement of a water kickusing the Wait and Weight Method 5-19

5.23 Comparison of Choke Pressures – during displacementof a gas kick on a fixed rig and a floating rig 5-20

5.24 Choke Pressure for various Water Depths – duringdisplacement of a gas kick 5-21

5.25 Determination of the Required Rate of ChokeManipulation for a Deep Water Subsea Well 5-22

5.26 Estimated Choke Line Losses (psi) for Various ChokeLine Lengths (3in. ID) 5-24

5.27 Annulus Pressure Loss for various Well Configurations 5-25

5.28 Choke Pressure – during displacement of a gas kickwith overbalanced mud 5-26

5.29 Shoe Pressure – during displacement of a gas kickwith overbalanced mud 5-26

5.30 Annulus Pressure Worksheet 5-31

5.31 Graph of Pseudo-critical Temperature and Pressurefor Hydrocarbons 5-33

5.32 Compressibility Factors for Natural Gas 5-34

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omhole

forend

alue at the

ountr the

been

acede theof the


5-3March 1995

1 General

When a kick is taken with the pipe on bottom, the well can be killed using either the Waitand Weight Method or the Driller’s Method. The Wait and Weight is the pref erredmethod. The procedures used to implement these techniques on either a floating or arig are detailed in Volume 1.

Both these methods ensure that the bottomhole pressure is maintained constant anto, or slightly greater than, the kick zone pressure.

In order to fully understand the implementation of these methods, it is important to underthe surface and downhole pressures that are caused by displacing a kick from the holeeither the Driller’s Method or the Wait and Weight Method.

This chapter is intended to cover the variations in surface and subsurface pressures durinmethods, and to explain the most important factors that affect the magnitude of these pressure

All the pressure plots shown in this chapter are developed by computer programmeThepressures are determined by simulating the displacement of a gas kick from a well wimodel of a discrete bubble of gas. The actual pressures seen when a kick is taken maydifferent from those predicted by the programme; however the plots can demonstrainfluence of the major factors that affect the wellbore pressures during circulation.

The pressure plots contained in this chapter are generated on the basis that the bottpressure is constant and exactly equal to the kick zone pressure.

2 Displacing a Kick from the Hole

(a) Driller’s Method

The Driller’s Method requires that two complete hole circulations are carried out bethe well is killed. The original mud weight is used to displace the kick from the hole athen the mud is weighted to kill weight for the second circulation.

During the first circulation, the drillpipe circulating pressure is held constant at a vequal to the shut-in drillpipe pressure plus the circulating pressure loss in the systemslow circulating rate.

During the second circulation, the drillpipe circulating pressure is adjusted to accfirstly for the increased circulating pressure due to the heavy mud, and secondly foreduction in underbalance as the drillpipe is displaced. Once the drillpipe has displaced to kill weight mud, the circulating pressure is held constant.

The pressure at each point in the annulus will vary significantly as the kick is displfrom the hole. Once the well has been shut-in, the major factors that determinpressure at any point in the annulus during displacement of the kick are the height influx in the annulus and the relative position of the influx in the annulus.

iller

nulusiate

ence

ssure.when

n theensityke; the

ain thesurentinually

bilise

hoke.

e hole.BHA.ulatedandx hase influx seenll was

ulus

duringing to killagemped will

red to willssure


5-4March 1995

Figure 5.1 shows the choke pressure during the displacement of a kick with the Dr’sMethod for a surface BOP. Point A represents the shut-in casing pressure. From point A topoint B, the casing pressure drops as the influx is displaced past the BHA. This drop iscaused by a reduction in height of the influx as the influx is displaced from the BHA anto the drillpipe annulus. The choke operator will open the choke to maintain the approprstandpipe pressure.

From point B to point D, the influx is expanding as it is circulated up the hole and hthe choke pressure required to balance the kick zone pressure is increasing. The chokeoperator will therefore close in on the choke to maintain the correct standpipe preAt point C, the gas has expanded to occupy its original height in the annulus opposite the BHA.

At point D, the gas arrives at the choke; the choke operator will have to close in ochoke to ensure that the choke pressure does not drop significantly as the low dgas passes across the choke. From point D to point E, the gas is passing the chochoke operator will have to open the choke to reduce the choke pressure to maintcorrect standpipe pressure. The choke pressure required to balance the kick zone presreduces as the gas passes the choke because the column of gas in the annulus is codecreasing in height.

At point E, the gas has been displaced from the well and the choke pressure will staat a value determined by the degree of underbalance.

Figure 5.2 shows the pit gain, or the volume of the kick, as it is displaced to the c

Figure 5.3 shows the pressure at the casing shoe as the kick is displaced from thFrom point P to point Q, the pressure drops as the influx is displaced past the From point Q to point R, the pressure increases as the influx expands as it is circup to the casing shoe. At point R, the top of the influx has arrived at the casing shoe from point R to point S the influx is circulated past the casing shoe. Once the influbeen circulated past the shoe, the pressure at the shoe will remain constant as this circulated to the choke, as long as the choke is correctly manipulated. It can befrom Figure 5.3 that, in this case, the shoe pressure was at maximum when the weshut-in. In other words, the influx did not expand to its original height in the annbefore it arrived at the choke. However, if the shoe was shallower, the maximum shoepressure might have been when the influx was circulated to the shoe.

Figure 5.4 shows the standpipe and choke pressure during the second circulation which the well is circulated to kill weight mud. Having established the initial circulatpressure, the standpipe pressure must be reduced as the drillpipe is displacedweight mud. In practice, very little choke manipulation will be required at this stbecause the standpipe pressure will drop automatically as the kill weight mud is pudown the drillpipe. Once the kill weight mud starts up the annulus, the choke sizehave to be increased so that the correct final circulating pressure is maintained.

Once the hole has been displaced to kill weight mud, the choke pressure requimaintain the final circulating pressure will be zero. In practice therefore, the chokebe wide open at this point and it may not be possible to keep the standpipe predown to the final circulating pressure.


5-5March 1995

Figure 5.1 Choke and Standpipe Pressure– during the fir st cir culation of the Driller’ s Method

Figure 5.2 Pit Gain– during the fir st cir culation of the Driller’ s Method

WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW:

3500m 2000m 1.7SG 1.83SG

BHA: PIPE: TECH: INFLUX:

6 1/4in/180m 5in DP DRILLER'S 20bbl GAS

0 200

VOL MUD PUMPED (bbl)

SU

RF

AC

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800SCR1

P DRILLPIPE

1000

1200

1400

1600

1800

2000

400

C

AB

D

E

STANDPIPE PRESSURE

CHOKE PRESSURE

600 800

WEOX02.131


3500m 2000m 1.7SG 1.83SG



0 200


PIT

GA

IN (

bb

l)

0

10

20

30

40

50

60

70

80

90

100

400 600 800

WEOX02.132


5-6March 1995

Figure 5.3 Shoe Pressure– during the first circulation of the

Driller’ s Method

Figure 5.4 Choke and Standpipe Pressure– during the second circulation of the

Driller’ s Method


3500m 2000m 1.7SG 1.83SG



0 200

P

Q

R

S


SH

OE

PR

ES

SU

RE

(p

si)

4800

5000

5200

5400

5600

5800

6000

6200

6400

6600

400 600 800

WEOX02.133


3500m 2000m 1.7SG 1.83SG

BHA: PIPE: TECH:

6 1/4in/180m 5in DP DRILLER'S

0 200DRILLPIPE VOLUME

ANNULUS VOLUME


SU

RF

AC

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800SCR1

SCR2P DRILLPIPE

1000

1200

1400

1600

1800

2000

400

STANDPIPE PRESSURE

CHOKE PRESSURE

600 800

WEOX02.134

ht

k areure

influx

e untilhole

s, the

from

ses. essure

t the thusilled.


5-7March 1995

(b) Wait and Weight Method

During the Wait and Weight Method, the kick is displaced from the hole with kill weigmud. The most significant advantages of the Wait and Weight Method in relation to theDriller ’s Method are: firstly that wellbore pressures during displacement of the kicgenerally lower than for the Driller’s Method, and secondly that the well is under pressfor a significantly shorter period.

Figure 5.5 shows the choke and standpipe pressure during displacement of thewith kill weight mud. The choke pressure during the Driller’s Method is included forcomparison. As can be seen, the choke pressure during both techniques is the samthe kill weight mud starts up the annulus at point B. (This is because the bottompressure is kept equal and constant for both methods.) From this point onwardpressure at every point in the annulus will be lower than if the Driller’s Method hadbeen used.

Between points D and E, the volume of original mud behind the influx is displaced the well until, at point E, the kill weight mud arrives at the choke.

Figure 5.5 Choke and Standpipe Pressure– during the Wait and Weight Method

Figure 5.6 illustrates the pressure at the casing shoe for both the Wait and Weight Methodand in comparison with the Driller’s Method. Between point P and point Q, the shoepressure decreases as the influx is displaced past the BHA. The influx expands as it iscirculated to the shoe at point R, after which, the pressure at the shoe decreaAtpoint S, the kill weight mud starts up the annulus and hence reduces the choke prbelow that for the Driller’s Method. Between point T and point U, the original weightmud is displaced past the shoe until point U, when the kill weight mud arrives ashoe. The pressure at point U is equal to the kick zone equivalent mud weight, andrepresents the minimum pressure that the shoe will see once the well has been k


3500m 2000m 1.7SG 1.83SG


6 1/4in/180m 5in DP W + W 20bbl GAS

0 200DRILLPIPE VOLUME


AB

C

D

E

SU

RF

AC

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800

SCR1

SCR2P DRILLPIPE

1000

1200

1400

1600

1800

2000

400

CHOKE PRESSURE (DRILLER'S METHOD)

STANDPIPE PRESSURE (W + W METHOD)

CHOKE PRESSURE (W + W METHOD)

600 800

WEOX02.135

dhe

isore

m the

om the

ill the


5-8March 1995

In this case therefore, the maximum shoe pressure is unaffected by the technique useto kill the well, however, the shoe will be under pressure significantly longer if tDriller ’s Method is used.

Figure 5.6 Shoe Pressure– during the Wait and Weight Method

3 Factors that Affect Wellbore Pressures

(a) Influx Size

The most fundamental factor that affects the wellbore pressures during circulation,the volume of the influx. The greater the volume of influx, the greater will be the wellbpressures during circulation.

Figure 5.7 shows the choke pressure as various influx volumes are displaced frowell using the Driller’s Method.

Figure 5.8 shows the choke pressure as the same influx volumes are displaced frwell using the Wait and Weight Method.

Figures 5.7 and 5.8 quite clearly show that, regardless of the technique used to kwell, the wellbore pressures will be lower the smaller the influx volume.


3500m 2000m 1.7SG 1.83SG


6 1/4in/180m 5in DP BOTH 20bbl GAS

0 200

P

Q

R

SDRILLER'S METHOD

WAIT AND WEIGHT METHOD

U

T


SH

OE

PR

ES

SU

RE

(p

si)

4800

5000

5200

5400

5600

5800

6000

6200

6400

6600

400 600 800

WEOX02.136

DRILLPIPE VOLUME


5-9March 1995

Figure 5.7 Choke Pressure– during the Driller’ s Method f or v arious

influx volumes

Figure 5.8 Choke Pressure– during the Wait and Weight Method f or v arious

influx volumes


50bbl

40bbl

30bbl

20bbl

3500m 2000m 1.7SG 1.83SG


6 1/4in/180m 5in DP DRILLER'S 20, 30, 40, 50bbl GAS

0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

400 600 800

WEOX02.137


50bbl

40bbl

30bbl

20bbl

3500m 2000m 1.7SG 1.83SG


6 1/4in/180m 5in DP W + W 20, 30, 40, 50bbl GAS

0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

400 600 800

WEOX02.138

m theinflux

sureethat doubt

ter the

urespore

h and

well use

e sameme high

starts

er iflus

ce such

nholeplaced

starts


5-10March 1995

Figure 5.9 shows the shoe pressures as various influx volumes are displaced frowell using the Driller’s Method. Figure 5.10 shows the shoe pressures as the same volumes are displaced using the Wait and Weight Method.

Figure 5.11 shows a comparison of choke pressure during the Wait and Weight Methodagainst the Driller’s Method for influx volumes of 20 bbl and 50 bbl.

Influx volume is therefore a variable that has significant influence on wellbore presduring the displacement of a kick. However, it is the only variable that the rig crew havsome control over for a given kick situation; it is therefore particularly important shut-in procedures are implemented as quickly as possible, even if there is someas to whether the well is flowing.

(b) Kick Intensity

The intensity of a kick is a measure of the degree of underbalance recorded afkick has been shut-in. This can be determined from the drillpipe pressure.

The intensity of the kick will be a major factor in determining the wellbore pressduring displacement of the kick. Close attention to the indicators of increasing pressure will ensure that kicks of high intensity are avoided.

Figure 5.12 shows the choke pressure during the displacement of a range of higlow intensity kicks by the Driller’s Method.

Figure 5.13 shows the displacement of the same kicks, using the Wait and Weight Method.It can therefore be seen that the Wait and Weight Method is more effective in reducingchoke pressures for kicks of relatively high intensity.

Figure 5.14 shows a comparison of the two techniques for a low intensity kick, asas a high intensity kick. Figure 5.14 shows clearly that it is especially important tothe Wait and Weight Method for kicks of relatively high intensity.

Figure 5.15 shows a comparison of the shoe pressures during displacement of thtwo kicks. In this case, the Wait and Weight Method does not reduce the maximupressure that the shoe experiences during displacement, but in the case of thintensity kick, the shoe pressure is significantly reduced once the kill weight mud up the annulus.

(c) Hole Configuration

The maximum surface pressure during displacement of a kick will always be lowthe Wait and Weight Method is used, given that kill weight mud will start up the annubefore the kick arrives at the choke.

The maximum shoe pressure is not necessarily affected by the technique used to displathe kick (in most cases the maximum shoe pressure will be at initial shut-in and asis not dependent on the technique used to kill the well). However in a long opesection it is possible that the maximum shoe pressure may occur as the influx is disto the shoe. In this instance, if kill weight mud is to have an effect on the maximumpressure at the shoe, the hole configuration must be such that the kill weight mudup the annulus before the kick is displaced past the shoe.


5-11March 1995

Figure 5.9 Shoe Pressure– during the Driller’ s Method f or v arious

influx volumes

Figure 5.10 Shoe Pressure– during the Wait and Weight Method

for various influx volumes


50bbl

40bbl

30bbl

20bbl

3500m 2000m 1.7SG 1.83SG


6 1/4in/180m 5in DP DRILLER'S 20, 30, 40, 50bbl GAS

0 200


SH

OE

PR

ES

SU

RE

(p

si)

4800

5000

5200

5400

5600

5800

6000

6200

6400

6600

400 600 800

WEOX02.139


50bbl

40bbl

30bbl

20bbl

3500m 2000m 1.7SG 1.83SG


6 1/4in/180m 5in DP W + W 20, 30, 40, 50bbl GAS

0 200


SH

OE

PR

ES

SU

RE

(p

si)

4800

5000

5200

5400

5600

5800

6000

6200

6400

6600

400 600 800

WEOX02.140


5-12March 1995

Figure 5.11 Choke Pressure– during the Wait and Weight Method and

the Driller’ s Method f or tw o diff erentinflux volumes

Figure 5.12 Choke Pressure– during displacement of a gas kick using

the Driller’ s Method f or v ariouskick intensities


1.91SG

1.87SG

1.83SG

1.79SG

1.75SG

3500m 2000m 1.7SG 1.75, 1.79, 1.83, 1.87, 1.91SG



0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

400 600 800

WEOX02.142


DRILLER'S METHOD

50bbl

20bbl


3500m 2000m 1.7SG 1.83SG


6 1/4in/180m 5in DP BOTH 20, 50bbl GAS

0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

400 600 800

WEOX02.141


5-13March 1995


the Wait and Weight Method f or v ariouskick intensities


the Wait and Weight Method f or v ariouskick intensities


1.9SG

1.87SG

1.83SG

1.79SG

1.75SG

3500m 2000m 1.7SG 1.75, 1.79, 1.83, 1.87, 1.91SG


6 1/4in/180m 5in DP W + W 20bbl GAS

0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

400 600 800

WEOX02.143


1.91SG

1.75SGDRILLER'S METHOD


3500m 2000m 1.7SG 1.75, 1.91SG



0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800

1000

1200

1400

1600

1800

2000

400 600 800

WEOX02.144

if the

ee. e

during

arious the

at thee is

n the

ck for a


5-14March 1995

Figure 5.15 A Comparison of the Shoe Pressure– during displacement using the Driller’ s

and Wait and Weight Method f or tw ogas kicks of different intensities

Once the kill weight mud starts up the annulus, shoe pressures will be lower thanDriller ’s Method is used. As discussed in (b), the higher the kick intensity, the moremarked the difference between wellbore pressures during the Wait and Weight Methodand the Driller’s Method. However, for a given kick intensity the significance of thdifference between the two techniques is also influenced by the depth of the shoTheshallower the shoe, the more significant is the effect of the kill weight mud on pressurreduction at the shoe.

The hole configuration therefore can influence the pressures seen at the shoe displacement.

Figure 5.16 shows a comparison of the shoe pressures for the same kick, for vlengths of openhole. A 20 barrel kick is taken at 3500m and is then displaced fromhole; Figure 5.16 shows the pressure variations at 1000m, 2000m and 3000m. As can beseen from Figure 5.16, if the shoe had been at 3000m, the maximum pressureshoe is clearly at initial shut-in. However, if the shoe was at 1000m, the shoe pressuractually greater than at initial shut-in when the influx is displaced to the shoe. Thissituation is brought about when the influx expands to occupy a greater height iannulus than it did at initial shut-in before it is displaced to the shoe. This generallyrequires a considerable length of openhole.

Figures 5.17 to 5.21 compare the shoe pressures during displacement of a gas kirange of shoe depths, using both the Driller’s and the Wait and Weight Methods.


1.91SG

1.75SG



DRILLER'S METHOD

DRILLER'S METHOD

3500m 2000m 1.7SG 1.75, 1.91SG



0 200


SH

OE

PR

ES

SU

RE

(p

si)

4800

5000

5200

5400

5600

5800

6000

6200

6400

6600

400 600 800

WEOX02.145


5-15March 1995

Figure 5.16 A Comparison of Shoe Pressures– during displacement of a 20 barrel gas

kick for various shoe depths

Figure 5.17 A Comparison of Shoe Pressures– during displacement of a gas kick shoe

at 3000m

WELL DEPTH: SHOE DEPTH:

MW1: KICK ZONE EMW:

SHOE AT 3000m

SHOE AT 2000m

SHOE AT 1000m

3500m 1000m, 2000m, 3000m 1.7SG 1.83SG



0 200


CH

AN

GE

IN S

HO

E P

RE

SS

UR

E (

psi

)

-400

-300

-200

-100

0

INITIAL (SHUT IN

PRESSURE)

+100

400 600 800

WEOX02.146


P

Q

R S DRILLER'S METHOD


3500m 3000m 1.7SG 1.83SG



0 200


SH

OE

PR

ES

SU

RE

(p

si)

7800

7900

8000

8100

8200

8300

400 600 800

WEOX02.147


5-16March 1995


at 2500m


at 2000m


3500m 2500m 1.7SG 1.83SG

DRILLER'S METHOD




0 200


SH

OE

PR

ES

SU

RE

(p

si)

6400

6500

6600

6700

6800

6900

7000

7100

400 600 800

WEOX02.148


DRILLER'S METHOD

R


3500m 2000m 1.7SG 1.83SG



0 200


SH

OE

PR

ES

SU

RE

(p

si)

5100

5200

5300

5400

5500

5600

5700

5800

5900

400 600 800

WEOX02.149


5-17March 1995


at 1500m


at 1000m


P

DRILLER'S METHOD


3500m 1500m 1.7SG 1.83SG



0 200


SH

OE

PR

ES

SU

RE

(p

si)

3800

3900

4000

4100

4200

4300

4400

4500

4600

4700

400 600 800

WEOX02.150


P

DRILLER'S METHOD


3500m 1000m 1.7SG 1.83SG



0 200


SH

OE

PR

ES

SU

RE

(p

si)

2500

2600

2700

2800

2900

3000

3100

3200

3300

3400

3500

400 600 800

WEOX02.151

hoe atceds as itndast it.l mud

ore it

he killg the

of the case

atill

of theflux is

etively

ssure

ction

kicks.d from

e

tater from


5-18March 1995

Figure 5.17 shows the shoe pressure for a 20 barrel kick taken at 3500m for the s3000m. From initial shut-in to point P, the pressure decreases as the influx is displapast the BHA; from point P to point Q the pressure increases as the influx expandis displaced up towards the shoe. At point Q, the top of the influx arrives at the shoe afrom point Q to point R the pressure at the shoe drops as the influx is displaced pFrom point R to point S, the pressure at the shoe remains constant as the originaoccupies the annulus from the bottom of the hole to the shoe. However, the pressure atthe shoe is further reduced at point S when, in the case of the Wait and Weight Method,the kill weight mud starts up the annulus.

Figure 5.18 shows the shoe pressure for the shoe at 2500m. A similar pressure profile isshown to that in Figure 5.17; however in this case the influx expands more befarrives at the shoe due to the greater length of openhole.

Figure 5.19 shows the shoe pressure profile for the shoe at 2000m. In this case, tweight mud starts up the annulus at point R, when the tail of the influx is passinshoe.

Figure 5.20 shows the shoe pressure profile for the shoe at 1500m. In the caseDriller ’s Method, the shoe pressure almost reaches its original shut-in value. In theof the Wait and Weight Method however, the kill weight mud starts up the annulus point P, before the influx arrives at the shoe. The shoe pressure is reduced by the kweight mud from this point on.

Figure 5.21 shows the shoe pressure profile for the shoe at 1000m. In the caseDriller ’s Method, the shoe pressure now increases past the shut-in value as the incirculated to the shoe. However, in the case of the Wait and Weight Method, the killweight mud starts up the annulus at point P, and this has the effect of reducing themaximum pressure that the shoe experiences.

Figures 5.17 to 5.21 show that the Wait and Weight Method has only a small influencon the maximum shoe pressure for wells of this type, even when the shoe is relashallow.

The most important point however is that the time that the shoe is subject to high preis substantially reduced when the Wait and Weight Method is used. The reduction inshoe pressure due to the kill weight mud is most significant when there is a long seof openhole (as is seen in Figures 5.17 to 5.21).

(d) Influx Type

All the pressure profiles in Figures 5.1 to 5.21 represent the displacement of gas As can be seen from the pressure profile, the expansion of the gas as it is displacethe well significantly affects the resultant wellbore pressures.

A water kick will behave in a different manner. Water is essentially incompressibland␣consequently will not expand appreciably as it is displaced up the well. This willmean that the wellbore pressures will not be significantly affected by the displacemenof the influx, unless the water contains a significant quantity of gas. However a wkick may cause special problems as a result of hole deterioration as it is displacedthe hole.

frome

points. tends

ke withe

fromil

st oil as ite

gh a

sity of


5-19March 1995

Figure 5.22 shows a typical choke pressure profile for a salt water kick displacedthe hole by the Wait and Weight Method. From point P to point Q, the choke pressurremains relatively constant as the drillpipe is displaced to kill weight mud. From Q to point R, the choke pressure drops as the kill weight mud starts up the annuluThisis in marked contrast to the gas kick where the expansion of the kick at this stageto increase the choke pressure. From point R to point S, the influx passes the choa corresponding drop in choke pressures. From point S to point T, the choke pressurdrops as the original mud behind the influx passes the choke. At point T, the kill weightmud arrives at surface.

Figure 5.22 Choke Pressure– during displacement of a water kick using

the Wait and Weight Method

An oil kick is likely to behave in a similar manner to the gas kick when displaced the well. The term ‘oil’ covers a large variety of fluids, ranging from viscous black othat contains very little gas, to very light oils that have very high gas oil ratios. Mowill contain gas at reservoir conditions which will come out of solution and expandis displaced up the hole. Essentially, therefore, the majority of oil kicks will behavsimilarly to a gas kick.

4 Subsea Considerations

If a kick is taken from a floating rig, the influx will be displaced to the surface throusmall diamater choke line that is attached to the drilling riser. The fundamental differencebetween well control procedures on a fixed and a floating rig originate from the neceshaving to circulate through this choke line.

P Q

R

S

T

0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

100

200

300

400

500

400 600 800

WEOX02.152

arised

it is

nt of aedure is


5-20March 1995

The potential problems caused by circulating through the choke line can be summas␣follows:

(a) Choke pressures will be significantly higher than for an equivalent welldrilled from a fixed rig.

This is due to the fact that the height of the influx is considerably increased asdisplaced from the annulus to the choke line.

Figure 5.23 shows a comparison between the choke pressure during displacemegas kick from a well drilled in 1000m of water and a similar well drilled from a fixrig. The influence of the choke line is apparent in that the maximum choke pressincreased from 1200 psi to approximately 2600 psi.

Figure 5.23 Comparison of Choke Pressures– during displacement of a gas kick on

a fixed rig and a floating rig

FIXED RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW, MW2:

FLOATING RIG

FIXED RIG

3500m 2000m 1.7SG 1.83SG


6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS

FLOATING RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW, MW2:

3500m 2000m 1.7SG 1.83SG

CHOKELINE: BHA: PIPE: TECH: INFLUX:

1000m/3in ID 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS

0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

400

800

1200

1600

2000

2400

2800

400 600 800

WEOX02.153

influx case,

flux isf


5-21March 1995

Figure 5.24 shows the choke pressures during displacement of the same 20 bblfor a variety of water depths. It can be seen that the choke pressure is not, in thissignificantly affected by a water depth of 100m.

Figure 5.24 Choke Pressure f or v arious Water Depths– during displacement of a gas kick

(b) The rate of increase of choke pressure required as the gas enters thechoke line may be unrealistically high at normal displacement rates.

As can be seen from Figure 5.25 the increase in choke pressure required as the indisplaced up the choke line is equivalent to 64 psi/bbl. This can be converted to a rate ochoke manipulation for various displacement rates as follows:

At 4 bbl/min = 64 x 4 = 256 psi/minAt 3 bbl/min = 64 x 3 = 192 psi/minAt 1 bbl/min = 64 x 1 = 64 psi/minAt 0.1 bbl/min = 64 x 0.1 = 6.4 psi/min

FIXED RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW, MW2:

1000m WATER

500m WATER

100m WATER

FIXED RIG

3500m 2000m 1.7SG 1.83SG


6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS

FLOATING RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW, MW2:

3500m 2000m 1.7SG 1.83SG


1000m, 500m, 100m/3in ID 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS

0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

400

800

1200

1600

2000

2400

2800

400 600 800

WEOX02.154

ire ante of

at theheadainlysuch

sure be


5-22March 1995

It can therefore be seen that normal displacement rates have the potential to requunrealistic rate of manipulation of the choke. In this case, the most satisfactory radisplacement would be of the order of 1 bbl/min.

Figure 5.25 Determination of the Required Rate of ChokeManipulation f or a Deep Water Subsea Well

It should be noted however that these calculations are based on the assumption thgas influx enters the choke line as a discrete bubble without mixing with the mud aof it. This may not always be the case, however the figures quoted above certindicate that the normal kick displacement rates have the potential to cause complications.

A further problem exists in that when the gas enters the choke line, the drillpipe preswill only register the drop in bottomhole pressure after the lag time, which cansubstantial in deep wells.


As gas invades the choke line:

p = 1800 = 64psi/bblbbl/pumped 28

3500m 2000m 1.7SG 1.83SG


1000m/3in ID 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS

0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

400

800

1200

1600

2000

2400

2800

2000psi

1800psi

400 600 800

WEOX02.155

As the mud behind the gas enters the choke line

p = 2000 = 71psi/bblbbl/pumped 28

of

kehole

red

ntheepe thew

es.

the

at

g a

res a

or

e

are


5-23March 1995

On a fixed rig, the lag time will not be so problematical because the required rate choke manipulation is generally lower. In other words, the bottomhole pressure willdrop only very slightly before the drillpipe pressures registers that drop and the chooperator closes in the choke (to increase the choke pressure and hence the bottompressure).

The lag time between the choke and the drillpipe pressure gauges is generally consideto be of the order of 2 seconds per 300m of drillstring length. This lag time, however,will be significantly affected by the type and size of the influx in the hole. It can be seetherefore that there may be a lag time of approximately 20 seconds in deep wells. If required rate of choke manipulation is 420 psi/min as the influx is displaced up thchoke line, the bottomhole pressure may have dropped 130 psi before the drillpipressure gauge registers this drop. Clearly this is an additional reason for displacinginflux through the choke line at a rate that is substantially slower than normal slocirculation rates.

(c) The rate of decrease of choke pressure required as the mud behind thegas reaches the base of the choke line may be unrealistically high.

In a similar manner, the required rate of choke manipulation as the mud behind thinflux enters the choke line may be unrealistically high at normal slow circulating rate

In this case, the potential problem is that the well may be overpressured, leading to possibility of fracturing the exposed formation.

Figure 5.25 shows that the choke pressure would theoretically have to be reduced71␣psi/bbl which corresponds to the following rates for various displacement rates:

At 4 bbl/min = 71 x 4 = 284 psi/minAt 3 bbl/min = 71 x 3 = 213 psi/minAt 1 bbl/min = 71 x 1 = 71 psi/minAt 0.1 bbl/min = 71 x 0.1 = 7.1 psi/min

This is clear indication that normal displacement rates are unsuitable when displacingas influx through a long choke line.

(d) The frictional pressure as a result of circulating through the choke linemay be significant at slow circulating rates.

Choke line frictional pressure may be significant, when added to the wellbore pressuresulting from the displacement of a kick. In certain circumstances, it may be ofmagnitude such as to cause formation breakdown.

There are special techniques that can be used to eliminate the effect of choke line lossesduring displacement of a kick. One such technique, namely the use of the kill line monit,is described in Chapter 6 of Volume 1.

Choke line losses are generally insignificant in relatively shallow waters, but can bsignificant in waters of 500m or greater. Figure 5.26 shows a table of estimated chokeline losses for various choke line lengths.

When very slow displacement rates are used, (such as 1 bbl/min) choke line lossesgenerally insignificant, even in deep water.

sure

ion to

ed tos will

kick:

fetyo notniquesus thetional


5-24March 1995

3 bbl/min MUD WEIGHT (SG) 1.5 1.7 1.9 2.1

CHOKE LINE LENGTH (m)

1000 m 120 200 220 245

500 m 90 100 110 125

100 m 17 19 22 25

4 bbl/min MUD WEIGHT (SG) 1.5 1.7 1.9 2.1

CHOKE LINE LENGTH (m)

1000 m 260 295 325 360

500 m 130 145 165 180

100 m 26 30 33 36

Figure 5.26 Estimated Choke Line Losses (psi)for Various Choke Line Lengths (3 in. ID)

5 Safety Factors

During well control operations, it is clearly necessary to maintain the bottomhole presslightly greater than the kick zone pressure. This will provide a margin of error for thechoke operation that will prevent a second influx occurring. However, excessive additionalpressure may needlessly overpressure the wellbore and possibly cause the formatfracture.

In general, every effort should be made to ensure that no additional pressures are applithe openhole at early stages in the displacement of the kick when downhole pressuregenerally be at a maximum.

The following are possible causes of additional pressures during the displacement of a

(a) Annulus Frictional Pressure

During displacement of a kick, the annulus back pressure will always provide a samargin over and above the kick zone pressure. Standard well control techniques dtake annulus frictional pressure into account, and consequently the use of these techensures that the bottomhole pressure is maintained at the kick zone pressure plannulus frictional pressure. Figure 5.27 shows a series of estimations of annulus fricpressures for various well configurations.

vary

n if

illpipeight

ight.

mudt


5-25March 1995

Figure 5.27 Annulus Pressure Loss for variousWell Configurations

It can be seen from these figures that the annulus frictional pressure may considerably from well to well in a kick situation. The significance of the annulus frictionpressure must be assessed before a kick is displaced.

(b) Heavier than Kill Weight Mud

The use of heavier than kill weight mud will result in higher wellbore pressures thakill weight mud is used, when standard techniques are used to displace a kick. This isbecause additional choke pressure must be applied to account for the fact that the drand annulus will be out of balance as the hole is circulated to heavier than kill wemud. The maximum additional pressure will be applied when the heavier than kill wemud arrives at the bit. The use of heavier than kill weight mud is not recommended

Figure 5.28 shows the choke pressure during displacement of a kick for variousweights, in comparison to the Wait and Weight Method. Figure 5.29 shows the equivalenshoe pressures.

7in @ 3200m

9 5/8in @ 3200m

3 1/2in drillpipe

Annulus pressure loss at 3 to 4bbl/min for 1.5 SG mud = 150 to 180psi 2.1 SG mud = 190 to 240psi

7in @ 4200m

200m 4 3/4in collars 6in hole

TD 4500m

9 5/8in shoe @ 3500m

13 3/8in @ 1500m

12 1/4in hole 180m of 8in collarsTD 1800m

Annulus pressure loss at 3 to 4bbl/min for mud weight range 1.7 SG to 2.1 SG = 100 to 125psi

8 1/2in hole 270m of 6 1/2in collars

TD 4000m

Annulus pressure loss at 3 to 4bbl/min for mud weight range 1.3 SG to 1.7 SG = 20 to 25psi

WEOX02.157


5-26March 1995

Figure 5.28 Choke Pressure– during displacement of a gas kick

with overbalanced mud

Figure 5.29 Shoe Pressure– during displacement of a gas kick

with overbalanced mud

WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: MW1:

3500m 2000m 1.7SG 1.83SG 1.83, 1.85, 1.87, 1.9SG

BHA: PIPE: TECH:

INFLUX:

6 1/4in/180m 5in DP OVERBALANCED MUD 20bbl GAS

0 200


CH

OK

E P

RE

SS

UR

E (

psi

)

0

200

400

600

800

1000

1200

1400

1600

400

1.9SG

1.87SG

1.85SG

1.83SG MUD (WAIT AND

WEIGHT)

600 800

WEOX02.158

WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: MW2:

3500m 2000m 1.7SG 1.83SG 1.83, 1.85, 1.87, 1.9SG

BHA: PIPE: TECH:

INFLUX:

6 1/4in/180m 5in DP OVERBALANCED MUD 20bbl GAS

0 200


SH

OE

PR

ES

SU

RE

(p

si)

3800

4000

4200

4400

4600

4800

5000

400 600 800

WEOX02.159

1.9SG MUD

1.87SG MUD

1.85SG MUD

1.83SG MUD (WAIT AND WEIGHT)

lance

alanceld be

latingat thei.

cingulusr

ssures

age inp the

erensure is

tivelyr toand- weak

miningide of

ith the inick. It


5-27March 1995

Heavier than kill weight mud is often considered in order to either add a small overbaafter the kick has been displaced from well or to kill an underground blowout. From theexamples in Figures 5.28 and 5.29 it can be seen that even a relatively small overbwill increase the wellbore pressures during kick displacement. Overbalance shouadded to the mud after the well has been killed.

(c) Additional Choke Pressure

An increase in choke pressure will exert an additional pressure throughout the circusystem. Therefore if the choke pressure is increased by 100 psi, the pressure casing shoe, at the bottom of the well and at the standpipe will increase by 100 psThechoke pressure can therefore be used to apply a safety margin to the kick zone duringdisplacement of the influx.

However, care should be taken to avoid applying several safety factors while displathe kick. Additional choke pressure should therefore only be considered if the annfrictional pressure is known to be insignificant. Additional choke pressure should nevebe applied to the well at an early stage in the displacement when downhole prewill generally be maximum.

The advantage of using additional choke pressure to create a safety margin is that it canbe controlled during displacement. For example, it may be applied only at a late stthe displacement, when the influx is in the casing, kill weight mud has started uannulus and consequently pressures on the openhole are at a minimum.

6 Calculating Annulus Pressure Profiles

The annulus pressure profiles shown in this Chapter have been developed by comput. Thesoftware used applies Boyle’s Law to the original influx at the bottom of the hole and thcalculates the pressures in the wellbore and at surface in order that bottomhole presmaintained constant and exactly equal to the kick zone pressure.

The benefit of the computer is that it can process a great deal of calculations in a relashort time. At the rigsite, it is not essential to have made all these calculations priodisplacing a kick from the hole. It is however useful to have a simple method of hcalculating both the maximum pressures that may be experienced at the openholepoint, and at surface, before the kick is displaced from the hole.

The annulus pressure worksheet shown in Figure 5.30a provides a means of deterthese pressures. The techniques for using these sheets are described on the reverse sthis sheet, in Figure 5.30b. Figures 5.31 and 5.32 should be used in conjunction wannulus pressure worksheet. The benefit of using this worksheet is that it can helpdeveloping an understanding of the pressures involved during the displacement of a kis not the simplest and quickest method.

quicks not

hole

ment. the


5-28March 1995

The formulae that are presented as follows are recommended for use at the rigsite forestimations of annulus pressures during the displacement of a kick, if a computer iavailable for this purpose:

(a) Wait and Weight Method

Use:

PD = S2

4 + K X 1.421 X MW2

C

12 – S

2(psi)

where:

S = (TD – D) MW2 X 1.421 – H1 X 1.421 (MW2 – MW1) + Pi – Pf (psi)

and:

K = PO X VO X ZD X TD

ZO X TO

or:

K = PO X VO (if temperature and compressibility effects are ignored)

and D = depth to the top of the influx (m)PD = pressure at the top of the influx (psi)TD = influx temperature for influx at depth, D (°R)ZD = influx compressiblity factor for influx at depth, DPO = original influx pressure (psi)TO = original influx temperature (°R)ZO = original influx compressibility factorVO = original inlfux volume (bbl)MW2 = kill mud weight (SG)MW1 = original mud weight (SG)C = annular capacity immediately below the influx (bbl/m)TD = well total depth (m)H1 = height of original mud below influx (m)Pi = hydrostatic pressure influx (psi)Pf = kick zone pressure (psi)

Therefore to determine the choke pressure at gas to surface, use D = O. To determinethe pressure at the openhole weak point when the top of the influx is at the openweak point, use D = depth of openhole weak point.

The hydrostatic pressure of the influx is assumed to remain constant during displaceHowever it may be adjusted for substantial changes in annular capacity usingfollowing formula:

Pi1 = Pi2 X C2

C1

where Pi1 = hydrostatic pressure of influx at original conditions (psi)Pi2 = hydrostatic pressure of influx at point of interest (psi)C1 = original annular capacity (bbl/m)C2 = annular capacity at point of interest (bbl/m)

it is

sure

as to


5-29March 1995

(b) Driller’s Method

This formula can be used both for the Driller’s Method and for the Wait and WeightMethod when kill weight mud has not yet been circulated to the bit.

Use:

P = S2

4 + K X MW1 X 1.421

C

12 – S

2(psi)

where:

S = (TD – D) MW1 X 1.421 + Pi – Pf (psi)

(c) For a Subsea Well

In order to calculate the choke pressure with gas to surface for a subsea well, necessary to include into the formula the effect of the choke line.

The formulae presented in (a) and (c) are equally applicable for calculating the presat the top of the influx before it is circulated to the subsea wellhead.

The formulae presented as follows are used only to calculate choke pressure at gsurface:

Use for the Weight and Wait Method:

Pchoke = S2

4 + K X MW2 X 1.421

C

12 – S

2(psi)

where:

S = H1 X 1.421 X MW1 + (TD – H1 – Dwhd + Vcl ) MW2 X 1.421 + Pi – Pf

C (psi)

Use for the Driller’s Method:

Pchoke = S2

4 + K X MW1 X 1.421

C

12 – S

2(psi)

where:

S = (TD – Dwhd +Vcl) MW1 X 1.421 + Pi – Pf (psi)C

and Pchoke = choke pressure at gas to surface (psi)Dwhd = wellhead depth below rotary table (m)Vcl = internal volume of choke line (bbl)C = annular capacity immediately below the influx (bbl/m)

on a

uldre atr than


5-30March 1995

(d) A completed example

Estimate the maximum choke pressure during displacement of a gas kick taken floating rig for the following conditions:

Volume of influx, VO = 20 bbl gasKill mud weight, MW2 = 1.83 SGOriginal mud weight, MW1 = 1.7 SGAnnular capacity below the influx, C = 0.1604 bbl/mWell total depth, TD = 3500mHole/Casing ID = 8.68 in.

Drillstring: 5 in. drillpipe, BHA 180m/ 6 1/4 in. OD/ 2 3/4 in. IDChoke line:1000m/3 in. ID

Capacity of the drillstring = (3370 X 0.05827) + (180 X 0.0239)= 201 bbl

Height of this volume in the annulus, H1 =201 = 1253m0.1604

If the Weight and Wait Method is used:

S = H1 X 1.421 X MW1+ (TD – H1 – Dwhd +Vcl ) MW2 X 1.421 + Pi – Pf

C (psi)

= (1253 X 1.421 X 1.7)+ (3500 – 1253 – 1000 +28.5 ) 1.83 X 1.421 + 59 + 9101

0.1604

= -2310 psi

Substituting into:

Pchoke = S2

4 + K X MW2 X 1.421

C

12 – S

2(psi)

Pchoke = -23102

4 + 20 X 9101 X 1.83 X 1.421

0.1604

12 – -2310

2(psi)

= 3225 psi

Therefore the maximum anticipated pressure during displacement is 3225 psi. It wohowever be anticipated that this figure represents the maximum possible pressusurface and, as such, the actual maximum pressure would be expected to be lowethis value.

(For derivation of these formulae ref: Blowout Prevention, Theory and Application byPeter Mills, 1984, D. Reidel Publishing Company.)

BP

WE

LL CO

NTR

OL M

AN

UA

L

5-31M

arch 1995

Figure 5.30a

Ann

ulus Pressure

Worksheet

Version 1/1 1Q'95 by ODL/C. Weddle

Date:

Original Mud Weight: ppg

Shut in Drill Pipe Pressure: ppg

Mud Weight to Displace Kick: ppg

Surface Temp: °F Temp Grad: °F/ft

Original Mud Hydro-

Influx Size above influx static of Req'd Pressure

Annulus Back at the

Height Height Pressure Fluids Pressure Shoe( ) ( ) (psi) (psi) (psi) (psi)

(16) (17) (18) (19) (20) (21)

ft ft

WEOX02.196

ANNULUS PRESSURE WORKSHEETUnits (US/UK):

For worksheet calculation enter information into shaded cells.Rig Name: Well No:

Drillstring Internal Volume bbl Kick Zone Depth: TVD,ft

Annulus, in. ID X OD length, ft bbl/ft Volume bbl Casing Shoe Depth: TVD,ft

Annulus, in. ID X OD length, ft bbl/ft Volume bbl Kick Zone Pressure: = psi

Annulus, in. ID X OD length, ft bbl/ft Volume bbl Casing Pressure: = psi

Annulus, in. ID X OD length, ft bbl/ft Volume bbl Pit Gain = bbl

Annulus, in. ID X OD length, ft bbl/ft Volume bbl Influx Height = ft

Total Annulus Volume bbl Influx Hydrostatic = psi

Hydro

Original Mud Kill Mud Height of Pressure

Volume Below Influx Below Original Mud Mud of Mud Influx Influx Influx Temp

of Mud Below Below Hydro- Mid-point

Pumped Vol Height Pressure Vol Height Pressure Influx Influx static Pressure Z Vol(bbl) (bbl) ( ) (psi) (bbl) ( ) (psi) ( ) ( psig ) (psi) (psia) °F °R Factor (bbl)

(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15)

ft ft ft


5-32March 1995

Figure 5.30b Ann ulus Pressure Worksheet

The worksheet provided can be used to estimate annulus pressures during the displacement of a kick.

The worksheet can be used as follows for the Wait and Weight method:(if the Drillers method is used (5), (6) and (7) are left out of the calculation)

(1) Barrels (bbl) of kill weight mud

Estimate the volume of kill mud pumped for the gas to arrive at the point of interest.

(2-4) Original mud below gas

This volume is equal to the volume of kill weight mud pumped until the drillpipe is displaced. At this point and subsequently this volume will remainconstant at the drillpipe internal volume.

Convert this volume to height and hydrostatic pressure equivalent, in the annulus.

(5-7) Kill mud below original mud

This volume is zero until the internal volume of the drillstring has been displaced. Once the kill mud starts into the annulus, its height and hydrostaticpressure should be calculated.

(8) Metres of mud below gas

The total height of mud below the influx.

(9) Pressure of mud below the gas

Equal to (4) + (7).

(10) Gas hydrostatic pressure

In a constant annulus size it is assumed that the gas hydrostatic pressure remains constant as the influx expands. The gas hydrostatic musthowever be corrected for substantial changes in annular dimensions using the following relationship:

Gas hydrostatic (2) = Gas hydrostatic (1) X Annular capacity (2)Annular capacity (1)

(11) Gas mid point pressure

This is equal to the kick zone pressure minus the total hydrostatic pressure of the mud below the influx and half of the gas hydrostatic pressure.

(12-13) The gas temperature

This is estimated from the surface pressure and the temperature gradient in the well unless more detailed information is available. The temperaturein °F can be converted to °R by adding 460.

Use Figure 5.31 (BP Well Control Manual, Volume 2) to determine the pseudo critical temperature and pressure of the gas (assume gravity is 0.7unless logging unit has detected presence of CO2 or H2S or unusually heavy hydrocarbon components). The pseudo reduced values are thencalculated as follows:

P pseudo reduced = P absolute (psia)P pseudo critical

and T pseudo reduced = T(°R)T pseudo critical

(14) Z factor

The compressibility factor, Z, can be determined from Figure 5.32 (BP Well Control Manual, Volume 2) using the calculated values of pseudoreduced pressure and temperature.

(15-16) Influx volume and height

The expanded volume of the influx can be calculated using Gas law relationships as follows:

V2 = T2 X Z2 X P1 X V1P2 X T1

V = Influx volume (bbl)T = Influx temperature (°R)P = Influx pressure (psia)Z = Compressibility factor

The influx height is determined as follows:

Influx height = Influx volumeAnnular capacity

(19) Total hydr ostatic pressure of ann ulus fluids

This equal to (9) + (10) + (18).

(20) Required back pressure

This is the difference between the kick zone pressure and the total hydrostatic pressure of the fluid in the annulus (19).

(21) Pressure at the shoe

The pressure at the shoe is determined by either:

• Subtracting the hydrostatic pressure of the annulus fluids from the bottomhole to the shoe from the bottomhole␣pressure

• Adding the hydrostatic pressure of the fluids from the shoe to the surface to the required back pressure (20)

This procedure will be repeated until the influx is positioned at the appropriate point in the well. For example if the first calculation shows that the topof the influx is above the shoe (assuming that the point of interest is when the top of the influx arrives at the shoe), the calculation should bereworked for a smaller volume of mud pumped.

For the first approximations it is a good idea to neglect the effect of temperature and compressibility in order to speed the calculation.


5-33March 1995

Figure 5.31 Graph of Pseudo-critical Temperature andPressure for Hydrocarbons

Pse

ud

o C

riti

cal P

ress

ure

psi

aP

seu

do

Cri

tica

l Tem

per

atu

re °

R

Gas Gravity (air = 1)

Miscellaneous gases

Condensate well fluids

Condensate well fluids

Miscellaneous gases

300

0.5 0.6 0.7 0.8 0.9 1 1.1 1.2

350

400

450

500

550

600

650

700

WEOX02.162


5-34March 1995

Figure 5.32 Compressibility Factors for Natural Gas

70.9

1.0

1.1

0.25

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1.0

1.10 1 2 3 4 5 6 7 8

1.1

1.0

0.95

1.7

1.6

1.5

1.4

1.3

1.2

1.1

1.0

0.98 9 10 11

PSEUDO REDUCED PRESSURE

CO

MP

RE

SS

IBIL

ITY

FA

CT

OR

Z

CO

MP

RE

SS

IBIL

ITY

FA

CT

OR

Z

12 13 14 15

PSEUDO REDUCED TEMPERATURE

PSEUDO REDUCED PRESSURE

1.05

3.0

January 1, 1941

1.21.1

1.05

1.31.4

2.8

2.6 2.4

2.2 2.0

1.9

1.7

1.6

1.8

1.1

1.15

1.2

1.25

1.3

1.35

1.4

1.45

1.4

1.05

1.1

1.2

1.3

1.4

1.5

1.6

1.7 1.8

1.9 2.0

2.2

1.5

1.6

1.5

1.7

1.81.9

2.0

2.22.42.6

2.83.0 1.05

1.1

3.02.6

2.4

1.2

1.3

WEOX02.163


March 1995

6 WELL CONTROL EQUIPMENT

Section Page

6.1 WELLHEADS 6-1

6.2 BLOWOUT PREVENTER EQUIPMENT 6-5

6.3 CONTROL SYSTEMS 6-43

6.4 ASSOCIATED EQUIPMENT 6-55

6.5 EQUIPMENT TESTING 6-64

Blowout preventers and associated equipment provide the means of controlling awell after primary control has been lost.

The basic requirements for effective BOP equipment include:

• A properly designed and cemented casing string that can contain pressuresencountered whilst drilling.

• A properly designed and installed wellhead assembly that can support, and sealbetween, the casing string and the BOP stack.

• BOPs securely anchored to the wellhead and capable of closing off the annulusagainst openhole or any tool that is run into the hole.

• A control system to operate the BOPs which features adequate redundancy andacceptable closing times.

• A choke system that can maintain a variable back pressure on a well whilst it iscirculated.

• A kill system which gives flexibility to pump to the hole via the annulus ordrillstring.

• Instrumentation that allows control of the well killing operation.


6.1 WELLHEADS

Paragraph Page

1 Surface Wellheads 6-2

2 Subsea Wellheads 6-2

6-1March 1995

ies of of

to

asingal.

and

void

slips.

usingies and

casing

in thea single

anger


6-2March 1995

1 Surface Wellheads

A conventional wellhead for use on land, platform and jack-up rigs, comprises a serspools and is based on a starting head. The starting head is anchored to the surface stringcasing, with the weight of the casing transferred to the cement, or mud line hanger. Additionalsupport may be provided by the conductor.

The major components of the surface wellhead are as follows:

(a) Spools

Conventional wellhead spools generally incorporate the following features:

• API standard flanges, or hub to suit a clamp, top and bottom. The flange face has amachined groove, often inlaid with stainless steel, to suit an API gasket.

• A set of seals, sometimes energised with plastic packing, in the base of the spool,pack off around the preceding casing stub.

• A bowl to accommodate the next casing string slips.

• Studded or flanged side-arms below the bowl,which provide communication to the cannulus. Often the side-arm is threaded to accept a plug to facilitate valve remov

• Lock down screws are provided in the top flange of most spools, to retain,sometimes to energise the pack-off, and also to retain the bore protector.

• Ports are provided to allow the pressure testing of the flange seals (i.e. thebetween the slip and seal assembly, the upper spool seals, and the ring gasket).

(b) Slip and Seal Assembly

The weight of the casing string is transferred onto the preceding spool via casingThe assembly incorporates a packer, which is weight or jack screw energised, and sealsthe annulus between casing and spool.

As an alternative to the conventional stack of spools, several manufacturers offer a morecompact system, in which the conventional stack of spools is replaced by wellhead hoin which successive casing slips/hangers are stacked. Such a system greatly simplifspeeds wellhead installation; it can be similar in concept to a subsea wellhead.

2 Subsea Wellheads

A subsea wellhead as used on floating rigs, consists of one or two wellhead housings,hangers/pack-offs and a guide base. It is positioned just above the seabed.

The wellhead housings are normally made up onto the conductor and 13 3/8 in. casingcase of a 2 stack system, or onto the conductor and surface casing in the case of stack system. They perform four functions:

• Support of casing strings by means of an internal upset on which the first casing hlands. Subsequent casing hangers land off on the previous seal assembly.

bore

side of

000 or

:

in the

etween

lically

ated

t is

It actsciselyre four


• Pressure isolation of the casing annulus from the wellbore by providing a polishedon which the seal assembly packs off.

• Pressure containment between the wellhead housing and the BOP, by provision of apolished stainless steel inlaid profile for a gasket in the hub bore.

• Support of the stack which lands on the hub and latches onto a profile on the outthe hub.

Commonly 21 1/4 in. housings are rated to 2000 or 5000 psi, 16 3/4 in. housings to 510,000 psi, 18 3/4 in. and 13 5/8 in. housings to 10,000 psi or 15,000 psi.

The following are the major items of equipment associated with the subsea wellhead

(a) Casing Hangers

Casing hangers are screwed on to the top of the casing string, and are landedwellhead on a retrievable handling string.

(b) Seal Assembly

The seal assembly provides a means of isolating the casing annulus by sealing bthe hanger and the wellhead housing. In most systems, the packer is energised withweight or by right hand torque, although some deep water designs are set hydrau.Generally, the energised packer is locked into a recess in the housing.

(c) Stack Connector

The BOP stack is connected to the wellhead by means of a hydraulically actuconnector which clamps on to a profile on the outside of the hub. The connector shouldhave the same pressure rating as the stack. The connector retains a metal gasket thaweight and pressure energised, to seal between the wellhead and connector.

(d) Permanent Guide Base

A permanent guide base is locked onto and run with the 30 in. wellhead housing.as an anchor for the guidelines, and a guide for locating the stack connector preover the wellhead. For deep water guidelineless operations, the standard squaposted guide base is replaced by a funnel, or petal shaped guide box.

6-3March 1995

6-3/4


6-5March 1995

6.2 BLOWOUT PREVENTER EQUIPMENT

Paragraph Page

1 Annular Preventers 6-7

2 Ram Type Preventers 6-15

3 BOP Stack Size and Pressure Rating 6-20

4 Stack Configurations 6-23

5 Choke and Kill Lines 6-29

6 Choke and Standpipe Manifolds 6-36

7 Diverters 6-39

Illustrations

6.1 Annular Preventer Sealing Elements 6-8

6.2 Hydril Annular Preventer Type MSP 6-9

6.3 Hydril Annular Preventer Type GK 6-10

6.4 Hydril Annular Preventer Type GL 6-11

6.5 Shaffer Annular Preventer 6-12

6.6 Cameron Annular Preventer Type D 6-13

6.7 Packing Unit Selection (from Hydril) 6-14

6.8 Secondary Rod Seal – Cameron Type U 6-17

6.9 Ram Preventer Opening and Closing Ratios 6-18

6.10 Approved BOPs for Company Operations 6-21

6.11 Availability and Bore of Blowout Preventers byMajor Manufacturers 6-22

6.12 5M Surface BOP Stack 6-25

6.13 10M/15M Surface BOP Stack 6-26

6.14 Four Inlet/Outlet 10M/15M Subsea BOP Stack 6-27

6.15 Three Inlet/Outlet 10M/15M Subsea BOP Stack 6-28

6.16 Specifications for BOP Flanges, Ring Gaskets,Flange Bolts and Nuts 6-34


6.17 Hydril Drilling Spool Data 6-35

6.18 Choke Manifold, 10M/15M 6-38

6.19 Standpipe Manifold 6-39

6.20 Subsea Diverter Stack 6-40

6-6March 1995

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6-7March 1995

1 Annular Preventers

Annular preventers have a doughnut shaped elastic element with bonded steel ireinforcing. Extrusion of the element into the wellbore is effected by upwards movement oa hydraulically actuated piston. The element is designed to seal around any shape or sipipe and to close on openhole. (See Figure 6.1.)

An important function of annular preventers is to facilitate the stripping of the drillpipor out of the well, with pressure on the wellhead. Undue wear of the element is avoidthe use of pilot-operated hydraulic regulator, which controls closing pressure.

The majority of annular preventers currently in use are manufactured by Hydril (Types MSP,GK, GL, GX), Shaffer (Spherical) and Cameron (Type D), these are illustrated below (SeFigures 6.2 to 6.6) together with a summary of major operating features.

The following are the most important aspects of the operation of annular preventers:

• To obtain maximum sealing element life, hydraulic closing pressures should confothe manufacturer’s recommendations for pressure testing and operational use opreventers. Excessive closing pressures, when coupled with wellbore pressure seffects, cause high internal stresses in the element and reduce element life.

• Cavities should be flushed out and the element inspected following each well. Prevshould be stripped and inspected annually. Seals should be replaced and all sealsurfaces inspected.

• Cap seals should be replaced when changing elements.

• Drilling tools, especially rock bits, should be run cautiously through BOPs to minimelement damage. Elements of annular preventers do not, on occasions, retract fu.

• The type of elastomer (natural rubber, synthetic rubber, neoprene) used in thepacking␣element should be the most suitable for a particular wellhead environmenFigure 6.7.

• Although most models and sizes of annular preventer will seal an openhole emergency operation, it is not recommended as such gross deformation of the elascauses cracking and accelerated wear.

• Closing pressures should be regulated to the pressures specified by the manufaThis information should be available at the rigsite.

• When stripping, the closing pressure should be regulated to the minimum requiredslight weeping of mud past the element. Closing pressures higher than this will incelement wear. The pipe should be moved slowly, particularly as tool joints pass througthe element. The manufacturers also provide information regarding recommended clopressures during stripping operations. Surge vessels on the closing ports will help smooth-out surge pressures as tool joints pass through the element.


6-8March 1995

Figure 6.1 Ann ular Pre venter Sealing Elements

OPEN CLOSED ON PIPE

(CAMERON)

CUTAWAY DRAWING SHOWING HOW RUBBER IS MOULDED AROUND STEEL SEGMENTS

(HYDRIL)

SPHERICAL SEALING ELEMENT (SHAFFER)

CLOSED ON PIPE

WEOX02.164

ainingessure

ied.may

h the


6-9March 1995

Figure 6.2 Hydril Ann ular Pre venter Type MSP

• Most annular preventers are designed to use wellbore pressure to assist in maintclosure. In some circumstances and depending on the preventer size, the well prcan maintain closure without any closing hydraulic pressure being applied. An annularpreventer should never be operated without some closing hydraulic pressure applThe reason is that with only well pressure maintaining closure, the packing unit suddenly open with only a small surge or reduction in well pressure. Also, the pressureseal may be lost around the body of the drillpipe after a tool joint passes througelement during stripping operations.

PACKING UNIT

PISTON

OPENING CHAMBER

CLOSING CHAMBER

Operating Features:

1. 2. 3. 4. 5.

Will close on open hole and hold 2000psi (but not recommended). Primary usage is in diverter systems. Automatically returns to the open position when closing pressure is released. Sealing assistance is gained from the well pressure. Good stripping capability of the packing unit since (fatigue) wear occurs on theoutside of the packing unit.

WEOX02.165


6-10March 1995

Figure 6.3 Hydril Ann ular Pre venter Type GK

PACKING UNIT

PISTON TRAVEL INDICATOR HOLE

PISTON

OPENING PORT CHAMBER

CLOSING CHAMBER

Operating Features:

1. 2. 3. 4. 5.

Will close on open hole (but not recommended). Sealing assistance is gained from the well pressure. Requires high closing pressures when used in subsea installations. Has provision to measure piston travel to gauge element wear. Available with a bolted top.

WEOX02.166


6-11March 1995

Figure 6.4 Hydril Ann ular Pre venter Type GL

PACKING UNIT

OPENING CHAMBER

PISTON

PRIMARY CLOSING CHAMBER

SECONDARY CHAMBER

Operating Features:

1. 2. 3. 4. 5. 6.

Will close on open hole (but not recommended). Some sealing assistance is gained from well pressure. Bolted cover for easier element charge. Primarily designed for subsea operations. Has provision to measure piston travel to gauge element wear. Has a secondary chamber which can be connected four ways to achieve different effects: a. Minimise closing/opening fluid volumes; b. Reduce closing pressure; c. Automatically compensate (counterbalance) for marine riser hydrostatic pressure effects in deep water; and d. Operate as a secondary closing chamber.

WEOX02.167

ford

ure

the

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6-12March 1995

Figure 6.5 Shaff er Ann ular Pre venter

• Cameron’s Type D annular preventer requires 3000 psi hydraulic closing pressurepositive closure with no pipe in the preventer. This reqires a bypass arrangement arounthe 1500 psi annular regulator on 3000 psi closing units. Hydril’s and Shaffer’s annularpreventers are claimed to provide positive closure with 1500 psi closing unit presswhen the rubber elements are new.

• If the annular packing element wears out during stripping or well killing operations, element can be changed without pulling the pipe. After the pipe rams are closed andlocked below the annular preventer and the hydraulic and well pressure bled off, thecover of the preventer can be unbolted and the packing element lifted out with a hline. With the element above the preventer, the damaged unit can be split and removefrom the pipe. New packing elements for Hydril and Shaffer annular preventers can besplit in the field and installed in reverse order. Cameron has recently developed a packinelement for their Type D annular preventer which can be split in the field.

PACKING UNIT

UPPER ADAPTER HEAD

OPENING CHAMBER

CLOSING CHAMBER

PISTON

Operating Features:

1. 2. 3. 4. 5. 6.

Will close on open hole (but not recommended). Requires higher closing pressure in subsea applications. Some sealing assistance is gained from the well pressure. No provision for measuring piston travel. Currently the most common annular preventer for subsea use. Important to check seals in upper adapter head when changing an element and replace if necessary.

WEOX02.168

nularstingal


6-13March 1995

• A 1 in. valve can be installed on both the opening and closing lines next to the anpreventer. These valves must be in the open position at all times except when tehydraulic lines and hydraulic chamber seals. These valves can be used to verify seleaks between the opening and closing chambers of an annular preventer.

Figure 6.6 Cameron Ann ular Pre venter Type D

PACKING UNIT

PISTON

OPENING CHAMBER

CLOSING CHAMBER

Operating Features:

1. 2. 3. 4. 5. 6.

Quick-release top latch for easy element change. Most sizes use less closing fluid than Shaffer and Hydril annular preventers. Overall height is less than Hydril and Shaffer annular preventers. Two piece packing unit. Operational problems have been experienced with this preventer. Requires 3000psi closing pressure to close an openhole.

WEOX02.169

enterhouldnction

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ater

the


6-14March 1995

PACKING UNIT IDENTIFICATION OPERATING DRILLING FLUIDTYPE Colour Code TEMP RANGE COMPATIBILITY

NATURALBlack NR -30°F – 225°F Waterbase fluidRUBBER

NITRILE RedNBR -20°F – 190°F

Oil base/oilRUBBER Band additive fluid

NEOPRENE GreenCR -30°F – 170°F Oil base fluidRUBBER Band

Figure 6.7 Packing Unit Selection (fr om Hydril)

• Only packing elements which are supplied by the manufacturer of the annular prevshould be used. New or repaired units obtained from other service companies snot be used since the preventer manufacturers cannot be held responsible for malfuof their equipment unless their elements are installed.

Closing pressures must be adjusted when annular preventers are operated subseThemanufacturers’ recommendations for the required adjustment pressure are summarised b

• For Hydril GK and MSP, the adjustment pressure is related to the mud weight, the wdepth, and the water density as follows:

∆P = (MW X 1.421 X D) – (ρw X D X 1.421)

CR(psi)

where ∆P = adjustment pressure (psi)MW = mud weight in the riser (SG)ρw = sea water density (SG)D = water depth (m)CR = annular closing ratio

and

CR = Closing chamber area

Closing chamber area – Opening chamber area

For example CR for Hydril 13 5/8 in. 5M GK = 2.56CR for Hydril 21 1/4 in. 2M MSP = 4.74

and so:

Subsea closing pressure = Surface closing pressure + Adjustment pressure

• For Hydril GL operated subsea (with the secondary chamber connected toopening␣line):

Adjustment pressure as for Hydril GK in subsea operation.

o the

ation

ated

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6-15March 1995

• For Hydril GL operated subsea (with the secondary chamber connected tclosing␣line):

Adjustment pressure = K X Adjustment pressure (as determined for Hydril GK)

where

K = Closing chamber area

Closing chamber area – Secondary chamber area

• For Hydril GL operated subsea (with secondary chamber in hydraulic communicwith the riser):

No adjustment required.

• For the NL Shaffer annular operated subsea, tests carried out by Exxon indicthat the required adjustment to the closing pressure is given by the following:

For the 16 3/4 in. 5M: ∆P = (0.335MW – 0.335)D

For the 18 3/4 in. 5M: ∆P = (0.339MW – 0.318)D

2 Ram Type Preventers

Ram type BOPs have two hydraulically actuated horizontally opposed rams which aredesigned to seal off an openhole or an annulus against a pipe of specific diameter. Variablebore pipe rams are also available for most ram preventers.

At least one preventer should be fitted with rams to suit each size of drillpipe in the However, it is not considered necessary to install casing rams under normal circumstaannular preventers suffice for closing on casing, unless conditions are exceptional.

On subsea stacks, pipe rams should be designed to support the string weight, (i.e. to hfon) and at least one set of blind/shear rams installed.

The working pressure of ram preventers should be at least equal to the maximum anticsurface pressures, plus a margin for pumping to the well.

There are several different types of ram preventer, as outlined below:

(a) Pipe Rams

Standard pipe rams are designed to centralise and pack-off around one specific size odrillpipe or casing.

(b) Variable Pipe Rams

Variable pipe rams are available for some models. One set of variable rams will prback-up for two different pipe rams, e.g. 3 1/2 in. and 5 in. or 5 in. and 7 in. Sovariable rams have a limited hang-off capacity, which is dependent on relative tool joinsize and ram range.

an bef the

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6-16March 1995

Cameron offer the following sizes of variable bore rams:

BOP Bore Pipe Size Range

11 in. 5 in. – 2 7/8 in.11 in. 5 1/2 in. – 3 1/2 in.13 5/8 in. 7 in. – 4 1/2 in.13 5/8 in. 5 in. – 2 7/8 in.16 3/4 in. 7 in. – 3 1/2 in.16 3/4 in. 5 in. – 2 7/8 in.18 3/4 in. 7 5/8 in. – 3 1/2 in.18 3/4 in. 5 in – 2 7/8 in.

(c) Hanging Rams

Pipe rams with enhanced load-bearing capabilities (usually rated to 600,000 lb) cfurnished for floating operations. Sometimes this involves special hardening obearing area, which might render the ram unsuitable for sour service.

(d) Blind/Shear Rams

These are designed to cut drillpipe and then seal as blind rams. The pipe stub isaccommodated in a recess. Shearing of drillpipe should be carried out with thestationary, which involves hanging off on floating rigs, and in tension, if practical. Carshould be taken to ensure that the pipe body, not a tool joint, is opposite the rams. Osome preventers, it may be necessary to increase operating pressure above 150shear. Blind/shear rams should be specified when ordering a preventer, as some preventersrequire oversized cylinders or other special features. Some models of blind/sheaare unsuitable for sour service.

(e) Offset Rams

Offset rams and dual offset rams are available for dual completions, and should be uwhere appropriate.

The majority of ram-type preventers in present day use are manufactured by Cameron ypesU and T), NL Shaffer (Types LWS and SL) and Hydril (Types V and X). Although thedetailed design of products from the three manufacturers varies, most models shafollowing basic features:

• Self Feeding Action of Elastomer

The front elements of ram seals have steel plates bonded to the rubber. As the ramsare␣brought together, these steel plates meet before the preventer is fully closFurther␣movement of the ram bodies causes extrusion of the rubber element, theffecting a seal.

If the rams are used for stripping pipe, the front face of the ram sealing elemenwear. The self-feeding action, brought about by the steel plates, will ensure that rufrom the packing element moves forwards to replace that which is worn away.

• Ram Locking Devices

Hydraulically operated ram preventers are provided with locking-screw stem extenand large diameter hand wheels similar to the operating screws of manually clpreventers. The main purpose of the locking screws is to manually lock the rams in

ed toloseding

osedplied

ually

il. Due wellit is

e roded

ain rod


6-17March 1995

closed position after they are shut hydraulically. In an emergency, the screws can beused to close the rams if the hydraulic system fails. If the locking screws are usclose the rams, the hydraulic closing unit valve handle should be turned to the cposition. This will eliminate the possibility of hydraulic oil being trapped on the openside of the actuating pistons.

An optional hydraulic lock mechanism (Cameron’s Wedge Lock, Shaffer’s Poslock andHydril’ s MPL) can be used in place of locking screws to lock the rams in the clposition. The hydraulic lock holds the rams closed until unlocking pressure is apeven though the primary control pressure is released. The hydraulic ram lock wasdeveloped for subsea BOP stacks and can be used on land rigs in place of the manoperated locking screws.

Figure 6.8 Secondar y Rod Seal – Camer on Type U

• Secondary Shaft Seals

All ram preventers with rated working pressure 5000 psi or higher, should be equippedwith secondary piston rod seals, see Figure 6.8, in case the primary rod seals fato routine wear, the primary rod seal may leak under excessive pressure duringcontrol operations. The secondary seal is plastic which is stored in a cavity until activated by forcing it around the ram rod. This plastic seal is used only during emergencysituations. The secondary seal is designed for static conditions and movement of thcauses rapid wear of both the seal and rod. The primary rod seal must always be repairwhen the emergency is over. During the initial pressure testing of a BOP stack, thesecondary seals on each ram preventer should be removed to assure that the mseals are tested. The secondary seal can be removed by unscrewing the energising plug,removing the check valve and digging out the plastic packing.

PLASTIC INJECTION SCREW

CHECK VALVE

ENERGISING RING

PLASTIC PACKING RING

'O' RING

OPERATING CYLINDER

PREVENTER BONNET

BACK-UP RINGS (IN 10000 AND 15000psi

WP PREVENTERS ONLY)

WEOX02.171

HYCAR LIP SEAL RETAINER RING AND

LOCKING RING

VENT TO ATMOSPHERE

PREVENTER BODY

wn insureso-oneuldure isnd the


6-18March 1995

Figure 6.9 Ram Preventer Opening and Closing Ratios

• Closing Ratios

Ram-type preventers have specially designed opening and closing ratios, as shoFigure 6.9. These are the ratios between the well pressures and the operating presneeded to open or close the rams. Closing ratios are generally in the range of six-tto nine-to-one. This means that a preventer having a closing ratio of six-to-one worequire 500 psi closing pressure to close the preventer when the wellbore press3000 psi. Opening ratios are much lower because the wellbore pressure acts behiram to oppose opening. Opening ratios of two-to-one are common.

SIZE WP (psi)Cameron U Shaff er ‘SL’ Hydril Ram

Open Close Open Close Open Close

7 1/16 in. 3,000 2.3 6.9 1.5 5.45,000 2.3 6.9 1.5 5.4

10,000 2.3 6.9 1.7 8.215,000 2.3 6.9 3.37 7.11 6.6 7.6

9 in. 2,0003,000 2.6 5.35,000 2.6 5.3

10,000

11 in. 2,000 2.5 7.33,000 2.5 7.3 2.0 6.85,000 2.5 7.3 2.0 6.8

10,000 2.5 7.3 7.62 7.11 2.4 7.615,000 2.2 9.9 2.8 7.11 3.24 7.6

13 5/8 in. 3,000 2.3 7.0 3.00 5.54 2.1 5.25,000 2.3 7.0 3.00 5.54 2.1 5.2

10,000 2.3 7.0 4.29 7.11 3.8 10.615,000 5.6 8.4 2.14 7.11 3.56 7.74

16 3/4 in. 2,0003,000 2.3 6.85,000 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 10.615,000 4.1 9.7 1.68 10.85 2.15 7.27

21 1/4 in. 2,000 1.3 7.0 0.98 5.233,000 1.3 7.0 0.98 5.25,000 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

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6-19March 1995

It should also be noted that, for high wellbore pressures, pressures greater than 300may be required to open some ram preventers.

• Bonnet Seals

Bonnet (or door) seals are exposed to wellbore pressures and fluids. Since they casubjected to high pressures and temperatures without being backed-up by anotherbonnet seals are critical to the integrity of the BOP system. The seals are generally offibrous/rubber construction and require careful handling and installation. Manufacturerecommendations should be observed meticulously.

– Bonnet seals should be replaced each time bonnets are opened.

– Bonnet seals should be handled carefully, particularly on installation, and be storedat controlled temperatures in darkness. They should be discarded after storage foone year.

– Bonnet bolts should be made up to manufacturers’ recommended torques, which canbe extremely high with some compression-type seals. Due regard should be pathe type of lubricant used, eg make-up torque is reduced by approximately 50%molybdenum disulphide lubricant, rather than an API5A lubricant, is used.

– Bonnet faces, preventer faces and seal grooves should be clean and dry beforinstallation and make-up.

– Bonnet seals should be tested after installation.

The following are the most important aspects of the care and maintenance of ram preve

• Pipe rams should not be closed on openhole or on mis-matched pipe. This would induceexcessive extrusion of the elastomer and can cause cracking or bonding failures.

• Ram recesses should be washed out and the ram element inspected following eachPreventers should be stripped, inspected (particularly all sealing surfaces) and sreplaced annually.

• When in good operating condition, ram preventers should close with 300 psi or hydraulic pressure without wellbore pressure. If high closing pressure is required dutest operations, the preventer should be checked first for debris in the ram cavitythen inspected for piston rod misalignment or other mechanical problems.

• Wellbore pressure helps close ram preventers. They are designed to hold pressure fromthe lower side and will not seal properly if installed upside down. Also, ram preventersare not designed to be pressure tested from the top side and this can damage the pre.Field experience has proven that ram preventers are more likely to leak witlow␣wellbore pressure than a high pressure. For this reason, they should be test200/300␣psi prior to the rated working pressure test.

• Ram preventers will close faster than annular preventers, especially in the larger sizes.Usually, ram preventers require only one-third or less of the hydraulic fluid volumeclose compared to an annular. In instances where mechanical problems prevent rapclosure of the annular preventer, a ram preventer should be closed immediately tminimise additional well flow.

• The main closing unit control handle for operating blind or blind/shear rams shoalways be protected against accidental closure with pipe in the hole. Numerous coincidents have resulted from accidentally closing the blind rams and flattening or cut

osing

size.150

niumof 41dardon

but itte

rpose. pipe

d the


6-20March 1995

the drillpipe during well control or drilling operations. A flip-up cover without lockingdevice should be used. If the handle is locked in the open position, it prevents clthe preventer from a remote station. Shear rams are not recommended for land rigoperations.

• When aluminium drillpipe is used, special consideration must be given to ramselection. For example, 5 in. aluminium drillpipe has an outside body diameter of 5in., versus a 5.000 in. body diameter for 5 in. steel pipe. Thus, regular 5 in. ram blocksmust be slightly modified to seal and not damage the main tube section of alumipipe. In addition, 5 in. aluminium pipe has a tapered transition zone for a length in. to 46 in. on both the box and pin ends from 5.150 in. OD up to 5.688 in. OD. Stanrams will not seal on the tapered end sections. Variable bore rams can be used to seal the body and end sections of aluminium drillpipe.

• Ram preventers can be used to strip drillpipe in or out of the hole under pressure,is necessary to use two preventers which have sufficient distance between rams to isolaa tool joint box. The drilling spool provides this space in a five preventer stack. Theupper and lower rams of a double ram preventer are too close together for this puExcessive hydraulic pressure should not be applied on the rams when strippingunder pressure because it tends to wear the resilient material of the ram. The lowest ramin the BOP stack should never be used for stripping since it is always consideremaster valve.

3 BOP Stack Size and Pressure Rating

The following stacks are available:

• Single stack systems

Bore Working Pressure

21 1/4 in. 10M (virtually obsolete)18 3/4 in. 10M or 15M16 3/4 in. 5M or 10M

• Multiple stack systems

Bore Working Pressure

21 1/4 in. 2M or 5M13 5/8 in. 5M, 10M or 15M11 in. 5M, 10M or 15M

Figure 6.10 shows a summary of approved BOPs. Figure 6.11 shows the availabilityand bore of BOPs from the major manufacturers.


6-21March 1995

Figure 6.10 Appr oved BOPs f or Compan y Operations

OFFSHORE DIVERTER SYSTEMS

Hughes Offshore Type KFDS (Floating)Hughes Offshore Type KFDJ (Platform)

Hydril C Type FSP (Floating and Platform)(with Flow Selector)

ANNULAR PREVENTERS ACCEPTABLE R UBBERS*

Cameron – Type D Nitrile – Water and Oil Muds

Hydril – MSP, GK, The following types of HydrilGKS, GS, GL, GX rubbers are available:

1. Natural rubber (black) –Water base muds

2. Synthetic rubber (red) – All muds3. Neoprene rubber (green) – Low

temperature service and oil muds

Shaffer – Spherical The following types of Shaffer rubbers are available:1. Natural rubber (black) – Water base muds2. Nitrile (blue) – Oil and water base muds

RAM PREVENTERS ACCEPTABLE R UBBERS*

Cameron – Type QRC Super Wear – Water and oil mudsCameron – Type U Super Wear – Water and oil muds

Hydril – Type Ram Nitrile – Water and oil muds

Shaffer – Type LWP The following types of Shaffer rubbers are available:Shaffer – Type LWS 1. Natural rubber (black) – Water base mudsShaffer – Type SL 2. Nitrile (blue) – Oil and water base muds

Koomey – Type PL PB

* All BOP manufacturers specify their rubber elements and rams as H2S resistant;however, H2S exposure reduces the service life of rubber products. The performanceof these products can vary significantly, depending on the extent of exposure and H2Scontent.

** Shaffer Type 70 ram blocks are not acceptable because of metallurgical and rubberpacker failures.

BP

WE

LL CO

NTR

OL M

AN

UA

L

6-22M

arch 1995

Hydril Shaffer Shaffer Shaffer KoomeyRam LWS SL Spherical

7 1/16 in. – – 7 1/16 in. 7 1/16 in.7 1/16 in. 7 1/16 in. – 7 1/16 in. 7 1/16 in.7 1/16 in. 7 1/16 in. – 7 1/16 in. 7 1/16 in.7 1/16 in. – 7 1/16 in. – 7 1/16 in.

– – – – –9 in. – – 9 in. –9 in. 9 in. – 9 in. –

– – – – –

– – – – –11 in. 11 in. – 11 in. 11 in.11 in. 11 in. – 11 in. 11 in.11 in. – 11 in. 11 in. 11 in.11 in. – 11 in. – 11 in.

13 5/8 in. – 13 5/8 in. 13 5/8 in. 13 5/8 in.13 5/8 in. – 13 5/8 in. 13 5/8 in. 13 5/8 in.13 5/8 in. – 13 5/8 in. 13 5/8 in. 13 5/8 in.13 5/8 in. – 13 5/8 in. – 13 5/8 in.

– – – – –– – – – –– – 16 3/4 in. 16 3/4 in. –

16 3/4 in. – 16 3/4 in. – –

– – – 18 3/4 in. –18 3/4 in. – 18 3/4 in. – 18 3/4 in.18 3/4 in. – 18 3/4 in. – 18 3/4 in.

. 21 1/4 in. 21 1/4 in. – 21 1/4 in. 21 1/4 in.20 3/4 in. 20 3/4 in. – – 20 3/4 in.21 1/4 in. – – 21 1/4 in. 21 1/4 in.

– – 21 1/4 in. – 21 1/4 in.

– – – – –– – – – –

. – – – – –

– – – – –

Figure 6.11

Av

ailability and Bore of B

low

out Pre

ventersb

y Major M

anufacturer

s

Blowout PreventerCameron Cameron Cameron Hydril Hydril Hydril Hydril

Nominal Working U QRC D GK GL GX HSPSize Pressure

7 1/16 in. 3,000 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. – – –7 1/16 in. 5,000 7 1/16 in. 7 1/16 in. 7 1/16 in. 7 1/16 in. – – –7 1/16 in. 10,000 7 1/16 in. – 7 1/16 in. 7 1/16 in. – – –7 1/16 in. 15,000 7 1/16 in. – 7 1/16 in. 7 1/16 in. – – –

9 in. 2,000 – – – – – – 9 in.9 in. 3,000 – 9 in. – 9 in. – – –9 in. 5,000 – 9 in. – 9 in. – – –9 in. 10,000 – – – 9 in. – – –

11 in. 2,000 – – – – – – 11 in.11 in. 3,000 11 in. 11 in. 11 in. 11 in. – – –11 in. 5,000 11 in. 11 in. 11 in. 11 in. – – –11 in. 10,000 11 in. – 11 in. 11 in. – 11 in. –11 in. 15,000 11 in. – 11 in. – – 11 in. –

13 5/8 in. 3,000 13 5/8 in. 13 5/8 in. 13 5/8 in. 13 5/8 in. – – –13 5/8 in. 5,000 13 5/8 in. – 13 5/8 in. 13 5/8 in. 13 5/8 in. – –13 5/8 in. 10,000 13 5/8 in. – 13 5/8 in. 13 5/8 in. – 13 5/8 in. –13 5/8 in. 15,000 13 5/8 in. – – – – 13 5/8 in. –

16 3/4 in. 2,000 – 16 3/4 in. – 16 3/4 in. – – –16 3/4 in. 3,000 16 3/4 in. – 16 3/4 in. 16 3/4 in. – – –16 3/4 in. 5,000 16 3/4 in. – 16 3/4 in. 16 3/4 in. 16 3/4 in. – –16 3/4 in. 10,000 16 3/4 in. – – – – – –

18 3/4 in. 5,000 – – 18 3/4 in. – 18 3/4 in. – –18 3/4 in. 10,000 18 3/4 in. – 18 3/4 in. – – 18 3/4 in. –18 3/4 in. 15,000 18 3/4 in. – – – – – –

21 1/4 in. 2,000 21 1/4 in. – – – – – 21 1/4 in21 1/4 in. 3,000 20 3/4 in. – 21 1/4 in. – – – –21 1/4 in. 5,000 21 1/4 in. – – – 21 1/4 in. – –21 1/4 in. 10,000 21 1/4 in. – – – – – –

26 3/4 in. 2,000 – – – – – – –26 3/4 in. 3,000 26 3/4 in. – – – – – –

29 1/2 in. 500 – – – – – – 29 1/2 in

30 1,000 – – – – – – 30 in.

essure.

certain

and 6.12

d,

r ramailure

avitysing,

the

upper

with.

ilitate


6-23March 1995

The test pressure rating of BOP equipment is a one off test, conducted on the BOP (orvalve) body at the time of manufacture to a pressure 50% greater than the working prIn service, working pressure ratings should not be exceeded.

It is acceptable to use annular preventers rated at 5000 psi less than the rams for10M and 15M applications.

4 Stack Configurations

Company policy regarding minimum stack configurations for all categories of landoffshore operations is detailed in the Drilling Policy and Guidelines Manual. Figuresto 6.15 show examples of acceptable stacks for various applications. The particular detailsof each well will however dictate the most suitable stack for each application.

(a) 5M Surface BOP Stack (Figure 6.12)

The following points should be considered regarding this stack:

• Two ram preventers and one annular preventer in line with Company policy.

• Facility for stripping pipe through annular preventer.

• No facility for ram combination stripping is available on this stack.

• If surface pressures exceed the pressure rating of the annular preventer, the piperams are closed and the blind rams changed to pipe. The upper pipe rams are closethe lower pipe opened and the kick circulated out through the choke line.

• Annular access below the lowermost ram possible through wellhead outlet.

• Lowermost ram not used for stripping operations and only used when no otheavailable for this purpose (i.e. when changing ram elements and in the event of fof rams above).

• If casing rams are required they should be positioned in the top ram preventer c.The rams should be changed out on the trip out of the hole prior to running cabefore pulling the BHA through the stack. The bonnet seals are tested against test plug and the annular prior to running casing.

(b) 10M/15M Surface BOP Stack (Figure 6.13)


• Three ram preventers and one annular preventer in line with Company policy.

• Pipe can be stripped through annular preventer and between annular andpipe␣ram.

• Ram preventer combination stripping is possible if blind rams are replacedpipe rams, if suitable space is available between top two ram type preventers

• A line must be rigged up to the flange between the top two ram preventers to facram combination stripping.

• Annular access below the lowermost ram is possible through wellhead outlet.

rams.

r ram

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6-24March 1995

• Well can be circulated either under the annular preventer or under the upper pipe

• Lowermost rams not used for stripping operations and only used when no otheavailable for this purpose.

• If casing rams are required they should be positioned in the upper pipe ram precavity. The rams should be changed out on the trip out of the hole prior to runcasing, before pulling the BHA through the stack. The bonnet seals are tested agaithe test plug and the annular prior to running casing.

(c) Four Inlet/Outlet 10M/15M Subsea BOP Stack (Figure 6.14)


• Four ram preventers, two annular preventers in line with Company policy for minirequirements for high pressure subsea BOP stacks.

• Four inlet/outlets provided in order to maximise flexibility of the stack.

• For normal kill procedure drillstring is hung off on pipe ram no. 2 and well circulatethrough upper choke line.

• There should be adequate space between the blind shear and pipe ram no. 2 on pipe body when the pipe is hung off on pipe ram no. 2. (This may not be possibif the top two ram type preventers are a double.) It is important to have the facishear the pipe quickly and reliably during a well control operation, especially sa dynamically positioned vessel.

• The lower kill line is used as the kill line monitor (See Standard Techniques,Chapter␣6, Volume 1).

• In the event of failure of pipe ram no. 2, or the upper choke line upstream ofailsafes, the well can be shut-in on and hung off on pipe ram no. 3 and returns takup the lower kill line.

• In the event of failure of the choke line downstream of the failsafes, the well ccirculated through the kill line.

• The fact that there is an inlet/outlet, that can be used as a choke line, immedbelow pipe ram no. 2 and 3, means that the possibility of trapped gas, after control operation, is minimised.

• Variable bore rams can be fitted in the ram preventers below the blind/shearThe hang off capability of these rams should be checked against maximum anticistring weights.

• BOP gas can be removed from this stack using the technique described in Chapter␣6of Volume 1, taking returns up the lower kill line as the riser is U-tubed.

• The upper (primary) annular preventer can be recovered with lower riser pafor element replacement.

• Lowermost ram only used when no other ram available is for this purpose. The conceptfor use of this ram is similar to that of the master valve on a production tree.

• The lower choke line is used primarily for pressure testing and monitoring theIn line with Company policy it should not be used for extended periods of circula(If this line fails during the displacement of a kick there is no back-up availabl


6-25March 1995

Figure 6.12 5M Surface BOP Stac k

CASING SPOOL

PIPE RAMS

SECTION A

21

4 3 7

5

6

1

BLIND RAMS

ANNULAR BOP

FILL UP LINE

FLOWLINE

KILL LINE CHOKE LINE

CHOKE MANIFOLD

8

WEOX02.175

1.

2. 3. 4.

5. 6. 7.

8.

Flanged gate valves – 2in minimum ID – same working pressure as 'A' section. The outside valve is the working valve during drilling operation. This valve is removed and reused after completion. Tee with tapped bullplug, needle valve, and pressure gauge. Flanged gate valve – 2in minimum ID – same working pressure as BOP stack. As 3. or flanged spring-loaded type check valve – 2in minimum ID – same working pressure as BOP stack. Drilling spool – two flanged side outlets – 3in choke and 2in kill line minimum IDs. Flanged hydraulically controlled gate valve – 3in minimum ID – same working pressure as BOP stack. Flanged gate valve – 3in minimum ID – same working pressure as BOP stack. Top of annular preventer must be equipped with API flange ring gasket. All flange studs must be in place or holes filled in with screw type plugs.

•

•

NOTES:Unless specified otherwise in the Bid Letter and/or Contract, the contractor will furnish and maintain all components shown except the 'A' section and items 1 and 2, which will be furnished by the Company. The choke line between the drilling spool and choke manifold should not contain any bend or turn in the pipe body. Any bend or turn required should be made with a running tee with a blind flange or welded bullplug. All connections should be flanged or welded. All fabrications requiring welding must be done by a certified welder. Welds should be stress relieved.


6-26March 1995

Figure 6.13 10M/15M Surface BOP Stac k

FILL UP LINE

FLOWLINE

KILL LINE CHOKE LINE

CHOKE MANIFOLD

LOWER PIPE RAM

DRILLING SPOOL

OUTLET FLANGE (USED ONLY FOR

RAM COMBINATION STRIPPING)

UPPER PIPE RAM

BLIND RAM

ANNULAR BOP

SECTION B

23 3

4 4 7 6

21 1

SECTION A

WEOX02.176

1.

2. 3. 4. 5. 6. 7. 8.

9.

Flanged gate valves – 2in minimum ID – same working pressure as 'A' section. The outside valve is the working valve during drilling operation. This valve is removed and reused after completion. Tee with tapped bullplug, needle valve, and pressure gauge. Flanged gate valve – 2in minimum ID – same working pressure as 'B' section. Flanged gate valve – 2in minimum ID – same working pressure as BOP stack. Drilling spool – two flanged side outlets – 3in choke and 2in kill line minimum IDs. Flanged hydraulically controlled gate valve – 3in minimum ID – same working pressure as BOP stack. Flanged gate valve – 3in minimum ID – same working pressure as BOP stack. Top of annular preventer must be equipped with API flange ring gasket. All flange studs must be in place or holes filled in with screw type plugs. The ID of the bell nipple must be less than the minimum ID of the BOP stack.

•

•

NOTES:Unless specified otherwise in the Bid Letter and/or Contract, the contractor will furnish and maintain all components shown except the 'A' and 'B' sections and items 1 and 2, which will be furnished by the Company. The choke line between the drilling spool and choke manifold should not contain any bend or turn in the pipe body. Any bend or turn required should be made with a running tee with a blind flange or welded bullplug. All connections should be flanged or welded. All fabrications requiring welding must be done by a certified welder. Welds should be stress relieved.

5

9

8


6-27March 1995

Figure 6.14 Four Inlet/Outlet 10/15M Subsea BOP Stac k

PIPE RAM No 3

PIPE RAM No 4

BLIND/SHEAR RAMS

PIPE RAM No 2

LOWER ANNULAR

BOP

UPPER ANNULAR

BOP

RISER CONNECTOR

CHOKE LINEKILL LINE

WELLHEAD CONNECTOR

WEOX02.177


6-28March 1995

Figure 6.15 Three Inlet/Outlet 10/15M Subsea BOP Stac k

PIPE RAM No 3

PIPE RAM No 4

WELLHEAD CONNECTOR

BLIND/SHEAR RAMS

PIPE RAM No 2

LOWER ANNULAR

BOP

UPPER ANNULAR

BOP

RISER CONNECTOR

CHOKE LINEKILL LINE

WEOX02.178

tion

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6-29March 1995

• Annular and ram combination stripping is possible with this stack. Ram combinastripping is however considered impractical from a floating rig. The lowermost ramis not used for stripping operations.

Disadvantages:

• Reliance is placed on the annular preventers when running casing.

• Unless variable or suitable sized pipe rams are installed initially, the stack must bepulled and redressed before using tapered strings. Annular preventers are not to bconsidered an adequate substitute for pipe rams when using tapered strings.

• The requirement to have the facility to hang off on pipe ram no. 2 and shear on thpipe body generally means that it is not possible to use a double preventer fortwo rams.

• If it is not possible to shear on the pipe body when the drillstring is hung off on piperam no. 2, the drillstring should be hung off on pipe ram during well controloperations. This is undesirable and reduces the flexibility of the stack.

(d) Three Inlet/Outlet 10M/15M Subsea Stack

It is recommended that 4 inlets/outlets are provided for high pressure subsea staorder to provide a high level of flexibility/redundancy within the stack.

However it is recognised that many subsea stacks incorporate only 3 inlets/outletthat the cost of conversion to a 4 inlet/outlet configuration may be prohibitive, especfor short term contracts.

Figure 6.15 shows an acceptable configuration of a 3 inlet/outlet high pressure subsea

The majority of the comments relating to the 4 inlet/outlet stack are applicable incase with the obvious exception that there is no line entering the stack belowlowermost ram.

No inlet/outlet is provided below the lowermost ram because it is considered thabenefit of such a line is insignificant compared to the reduction in the flexibility ofstack that this would entail.

5 Choke and Kill Lines

The variations in contractor furnished equipment and the requirements of individual are such that specification of a standard layout is not feasible. However, it is essential thatequipment specifications should suit a particular well, satisfy Company policy and legislation. In particular, the choke and kill lines should never be rated to a lower workpressure than the stack.

It is recommended that ultrasonic testing equipment is held on each rig in order that ththickness of pipework, including choke and kill lines, can be regularly checked.

(a) Surface BOP Stacks

The location of kill and choke outlets on a BOP stack will be influenced primarily bythe number of rams used and their sizes.

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the toitted.

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eldeldssure

ume

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6-30March 1995

• Choke and Kill Outlets

To comply with Company policy, the choke line must have a minimum ID of 3 inthe kill line may be as small as 2 in. (but this might restrict operational flexibishould it be required to substitute for a washed out choke line). During noroperations, the inner (manual) choke and kill line valves should be open andouter (HCR) valves closed.

• Remote Kill Line

On a land rig, a remote kill line can be tied in to the kill line so that it may be uwhichever preventer is closed. The remote kill line should be rated at the pressurating of the BOP stack and should terminate at a similarly rated flanged valveleast 100 ft from the well. The purpose of this line is to enable a pump truck to tied into the well in an emergency situation.

• Wellhead Outlets

It is recommended that wellhead spool outlets are not used for a choke and kiltie-ins. Each wellhead spool should have dual valve isolation on one side and removal plugs (VRP) should be installed on the non-active side.

• Check Valves

Traditionally, a check valve has been installed outboard of the stack valves onkill line. Now many rigs, particularly jack-ups, have the facility to use the kill lineaugment, or replace, the choke line. In such a hook-up, check valves are omCompany policy is that check valves are not mandatory on the kill line.

Choke and kill lines are generally fabricated in line with the following specifications:

• All connections should be flanged, clamped or welded. Screwed fittings, unionschicksans should not be used on the choke lines, although minimal use is acceon kill lines.

• All welding should be carried out under shop conditions with machine cut wpreparations. All welding should be conducted by certified welders to approved wprocedures and all welds should be suitably non destructively tested and pretested prior to use.

• Lines, particularly the primary choke line should be installed with the minimnumber of bends. Where bends are required, targeted tees, or block tees should bused. Swept bends are undesirable.

• Choke lines should be well braced, to withstand severe vibration. Supports shbe fitted as required, but these should not be welded to the choke line.

(b) Subsea BOP Stacks

Subsea choke and kill lines differ from surface systems in that:

• Subsea choke and kill lines require flexible connections at the ball/flex joint, anthe telescopic joint.

• All subsea choke and kill line valves are fail safe and hydraulically actuated.

• Subsea choke and kill lines are much longer. Depending on water depth, line sizeand mud properties, pressure losses in the lines might be significant.

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6-31March 1995

Choke and kill lines are tied into BOP outlets, not to drilling spools or the wellhead. GeneraBOP stacks for exploration wells should have 4 ram, and 2 annular preventers. This providessome flexibility in case a ram or element fails during a well killing operation.

On some rigs, a hydraulically actuated cement dump valve is provided on the kill lineThisvalve may be used to dump cement returns, thereby avoiding long circulation times uriser in deep water. It can also be used to flood the riser if it becomes evacuated andanger of collapsing. However, the dump valve should be treated with caution. Misuseinadvertent opening, could cause considerable loss of hydrostatic head in the well.

Often dump valves are considered to be unnecessary and are omitted on most rigs.

The following points should be noted regarding the major choke and kill line compon

• All valves should be failsafe. Two valves are required per outlet. Valves should beinstalled␣�as close to the BOP outlets as possible, and preferably in line with the ouSide-arms and valves should be well protected by the framework around the stac

• Targeted tees should be used for all 90 degree bends.

• Choke and kill connections at the lower riser disconnect should be rigidly supportethe framework, so that they will not part when full working pressure is appsimultaneously to both lines.

• The choke and kill line across the ball/flex joint should be flexible and not resmovement of the joint up to its maximum designed deflection.

• Riser couplings and the LMRP stab plates should be designed to withstand inloadings when full working pressure is applied simultaneously to both lines.

• The choke and kill lines across the telescopic joint should be able to accommodamaximum designed travel of the joint.

• All surface connections should be flanged, clamped or welded. Screwed fittchicksans and unions should not be used.

• Lines should be installed with the minimum number of bends. Where bends are requiredtargeted tees or block tees should be used. Swept bends are not desirable.

• Choke lines should be anchored to withstand vibration. Supports should be fittrequired, but these should not be welded to the choke line.

• Both the choke and kill line should be tied into the choke manifold to allow onreplace or augment the other.

(c) Hydraulically Operated Valves

A remotely operated valve is installed on the choke line adjacent to the BOP stack torapidly shut off hazardous flow in the event of downstream equipment failure. Anotheradvantage for remote operation is that this valve is usually located at an elevated wlevel in the substructure which makes hand operation difficult and unsafe.

Specifically designed hydraulically controlled gate valves (HCV) are extensively utilfor this service. The valve must be rated WOGM which means that it is serviceable fowater, oil, gas or mud flow. The hydraulic actuator must be designed for 3000 maximum working pressure; however, the actuator should fully open the valve wit1500 psi control pressure for maximum design conditions. The 3000 and 1500 psi desig

le for

eredd for

alvees ast thee as0,000lyused

rkingke.

ted,

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6-32March 1995

pressures are required for compatible operations with standard BOP closing units. Thechoke line valve must be operable from both the main and remote closing units. As anoptional feature, hydraulically operated valves are available with stem and handmanual operation (to close but not open) in case of hydraulic system failure.

Although numerous companies manufacture HCVs, Cameron Iron Works and NL Shaffersupply the majority of remotely operated choke line valves since they are initally ordas a component of the BOP stack. On most rigs, the hand operated gate valves usethe choke manifold and kill line are usually the same type as the HCV.

Cameron introduced the HCR (High Closing Ratio) as the first remotely controlled vfor choke line service. This valve has the same basic design and operational featura Cameron QRC preventer. The HCR valve has been used so extensively throughouindustry that most oil field personnel refer to any make of remotely controlled valvthe HCR. Because the HCR is limited to 5000 psi working pressure, the advent of 1psi and higher working pressure BOP required additional valve development. Current,Cameron’s type F hydraulically operated gate valve is probable the most widely and is available with rated working pressures from 3000 psi to 15,000 psi. NL Shaffer’schoke line valve is the type DB which is rated for 5000, 10,000 and 15,000 psi wopressures. Other reputable valve manufacturers’ equipment may be acceptable for choline service; however, prior well control reliability and experience should be verified

(d) Subsea Failsafe Valves

These valves are made by a number of companies including Cameron, NL Shaffer, WKM,Rockwell and Vetco. Generally, these are gate valves closed with a spring operasometimes pressure assisted, closing mechanism.

Two of the more important parameters used in evaluating these valves for floating doperations are their susceptibility to forming hydraulic blocks when used in tandemthe water depth sensitivity of their operators. The latter is important because when ussubsea, hydrostatic head alone may be sufficient to hold the valves open (in the absenof closing pressure) if a means is not available to balance the hydrostatic forces on the operator and stem.

• NL Shaffer Valve

The operating characteristics of the NL Shaffer Model CB, bi-directional sealingvalve is governed by the selection of either a short or long sea chest. The Model CBvalve with the short sea chest and a pressure-balancing tail rod will failsafe clorated working pressure regardless of water depth; however, a pressure-assist hydrauliline is required for normal closure. When equipped with a long sea chest, the varequires a single hydraulic line for opening, and closure is obtained by spring aplus limited line pressure-assist. Line pressure assists the spring closing abecause the pressure balancing tail rod is 1/4 in. smaller in diameter than theThe pressure-assist feature limits the long sea chest valve to a maximum 2water depth for failsafe spring closure.

• Rockwell Valve

The Rockwell (McEvoy) valve has unique features of a split gate, long slip fit sto minimise wear in the valve body, and a sealant that is injected to complete seal. The seal is always on the downtream side of the gate.

is

m;

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vesll

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6-33March 1995

Prior to a modification made in June, 1972, the valve was marginally failsafe in440m of water; but now a modified version, Model EDU, is available thatindependent of water depth.

• WKM Valve (Model M with D-2-C Operator)

This valve will fail safe closed in 570m water depth. It has no balancing stetherefore, the body volume decreases when the valve opens. WKM claims that thebody cavity is so large compared with this change that pressure locking is no proble

The problem of body lock is solved in the same way as fluid lock when the valare in tandem. Basically, flow paths within the body allow redistribution of the smavolume change resulting from valve stem movement.

• Cameron Valves

Cameron has three subsea valve designs: 1) the Type A valve has a solid gate foruni-directional sealing, 2) The Type AF valve has bi-directional sealing capabilitywith a ported outlet in the lower body cavity to prevent liquid locking, and 3) ttype DF valve is bi-directional with a balancing stem ported to the sea and a verfluid passageway on the outer surface of the gate to prevent pressure locking. Camrates the Type A and the AF valves for service in water depths to 300m. The Type DFvalve is rated by Cameron for service to a water depth of 1800m.

All valves were originally designed with a dog attached to the gate to rotate the sa fraction of a turn when the valve was opened, which reportedly would provuniform seat wear. Cameron now recommends removal of the dog since its actcan induce stresses which may cause the seat to fracture if settled baryte adrilled solids prevent seat rotation.

• Vetco Type VS Valve

The Vetco Type VS subsea gate valve is a full-bore, through-conduit gate valveAmetal-to-metal seat is provided between the moving sealing member (gate) anstationary seats. Since the valve lacks a balancing stem, the manufacturer limivalve to water depths of 900m to ensure failsafe closure.

(e) BOP Stack Connections

There are three types of connections available for blowout preventer units: flanstudded or clamped. Bolted flanges or studs are the most common type of conneused. The tensile rating of the bolts used in these connections must be sufficient towithstand the maximum load which may be imposed. The torque applied to the nuts andbolts must meet API recommended values to maintain the pressure seal.

BP

WE

LL CO

NTR

OL M

AN

UA

L

6-34M

arch 1995

Figure 6.16

Specifications f

or BO

P F

langes, R

ing Gaskets,

Flang

e Bolts and N

uts

ring joint flange equipment listed below:

UM BOLT ** MINIMUM NUTRENGTH STRENGTH

TM Grade ASTM GradeB-7 2-H

TM Grade ASME GradeB-7 2-H

TM Grade ASTM GradeB-7 2-H

teel

y be

All blowout preventers, drilling spools, adapter flanges will be furnished with the specific API

RATING OF BOP APPROVED FLANGES APPROVED * MAXIMSTACK RING GASKETS ST

2000 psi wp API Type 6B with API Type ASand 3000 psi wp Type R Flat Bottom RXInstallations Groove

5000 psi wp API Type 6B with API Type RX or ASInstallations Type R Flat Bottom API Type BX w

Groove or API Type Type 6BX Flange6BX w/Type BX Groove

10,000 psi wp API Type 6BX with API Type ASInstallations Type BX Groove BX

* Acceptable material for flange ring gaskets as per API Spec 6A, ‘Wellhead Equipment’.

Sweet Oil – Low Carbon Steel

Sour Oil or Gas – Type 316 stainless steel preferred but Type 304 stainless sacceptable except for high risk H2S wells.

** In some H2S applications, ASTM A-193 Gr B M a maximum Rockwell hardness of 22 maacceptable. If used, flanges should be derated per Table 1.4B of API 6A.


6-35March 1995

(B)

WEIGHT (lb) (A) SPOOL CENTREBORE CONNECTIONS SIDE OUTLETS (approx) HEIGHT (in.) LINE TO

FLANGE ORHUB FACE (in.)

7 1/16 in. 7 1/16 in. 3,000 Flange 3 1/16 in. 3,000 Flange 510 16.50 13.257 1/16 in. 7 1/16 in. 3,000 Flange 3 1/16 in. 5,000 Flange 525 16.50 13.257 1/16 in. 7 1/16 in. 5,000 Flange 3 1/16 in. 5,000 Flange 510 16.50 13.507 1/16 in. 7 1/16 in. 5,000 Flange 3 1/16 in. 5,000 Flange 500 19.75 13.507 1/16 in. 7 1/16 in. 5,000 Flange 4 1/16 in. 5,000 Flange 525 19.75 13.507 1/16 in. 7 1/16 in. 10,000 Flange 3 1/16 in. 10,000 Flange 1025 21.12 15.187 1/16 in. 7 1/16 in. 10,000 Flange 4 1/16 in. 10,000 Flange 1075 21.12 15.187 1/16 in. 7 1/16 in. 15,000 Flange 4 1/16 in. 15,000 Flange 1400 22.38 16.44

9 in. 9 in. 3,000 Flange 3 1/16 in. 3,000 Flange 700 18.12 15.009 in. 9 in. 3,000 Flange 3 1/16 in. 5,000 Flange 725 18.12 15.009 in. 9 in. 5,000 Flange 2 1/16 in. 5,000 Flange 710 18.12 15.259 in. 9 in. 5,000 Flange 3 1/16 in. 5,000 Flange 725 18.12 15.2511 in. 11 in. 3,000 Flange 3 1/16 in. 3,000 Flange 950 18.62 16.5011 in. 11 in. 3,000 Flange 3 1/16 in. 5,000 Flange 975 18.62 16.5011 in. 11 in. 5,000 Flange 3 1/16 in. 5,000 Flange 1065 23.38 17.2511 in. 11 in. 5,000 Flange 4 1/16 in. 5,000 Flange 1290 22.38 17.2511 in. 11 in. 10,000 Flange 3 1/16 in. 10,000 Flange 2190 25.12 18.6211 in. 11 in. 10,000 Flange 4 1/16 in. 10,000 Flange 2215 25.12 18.6211 in. 11 in. 10,000 Hub 3 1/16 in. 10,000 Hub 1285 25.12 18.6211 in. 11 in. 10,000 Hub 4 1/16 in. 10,000 Hub 1310 25.12 18.6211 in. 11 in. 15,000 Flange 4 1/16 in. 15,000 Flange 1710 29.75 22.50

13 5/8 in. 13 5/8 in. 3,000 Flange 3 1/16 in. 3,000 Flange 1055 19.38 17.2513 5/8 in. 13 5/8 in. 3,000 Flange 3 1/16 in. 5,000 Flange 1080 19.38 17.2513 5/8 in. 13 5/8 in. 5,000 Flange 3 1/16 in. 5,000 Flange 1755 22.38 19.0013 5/8 in. 13 5/8 in. 5,000 Flange 4 1/16 in. 5,000 Flange 1780 22.38 19.0013 5/8 in. 13 5/8 in. 5,000 Hub 3 1/16 in. 5,000 Hub 1050 22.38 19.0013 5/8 in. 13 5/8 in. 5,000 Hub 4 1/16 in. 5,000 Hub 1075 22.38 19.0013 5/8 in. 13 5/8 in. 10,000 Flange 3 1/16 in. 10,000 Flange 3325 27.75 20.8813 5/8 in. 13 5/8 in. 10,000 Flange 4 1/16 in. 10,000 Flange 3355 27.75 20.8813 5/8 in. 13 5/8 in. 10,000 Hub 3 1/16 in. 10,000 Hub 1925 27.75 20.8813 5/8 in. 13 5/8 in. 10,000 Hub 4 1/16 in. 10,000 Hub 1950 27.75 20.8820 3/4 in. 20 3/4 in. 3,000 Flange 3 1/16 in. 3,000 Flange 2590 27.12 22.5220 3/4 in. 20 3/4 in. 3,000 Flange 3 1/16 in. 5,000 Flange 2615 27.12 22.5220 3/4 in. 20 3/4 in. 3,000 Flange 4 1/16 in. 5,000 Flange 2540 27.12 22.5220 3/4 in. 20 3/4 in. 3,000 Hub 3 1/16 in. 3,000 Hub 2565 27.12 22.5221 1/4 in. 21 1/4 in. 2,000 Flange 7 1/16 in. 2,000 Flange 1850 23.38 21.7521 1/4 in. 21 1/4 in. 2,000 Flange 3 1/16 in. 5,000 Flange 1800 23.38 21.7521 1/4 in. 21 1/4 in. 2,000 Flange 4 1/16 in. 5,000 Flange 1850 23.38 21.7521 1/4 in. 21 1/4 in. 2,000 Hub 3 1/16 in. 5,000 Hub 1850 23.38 21.7521 1/4 in. 21 1/4 in. 2,000 Hub 4 1/16 in. 5,000 Hub 1825 23.38 21.75*29 1/2 in. 29 1/2 in. 500 Flange 7 1/16 in. 500 Flange 2380 31.75 25.25*29 1/2 in. 29 1/2 in. 500 Flange 12 in. 500 Flange 2320 31.75 25.00

*30 in. 30 in. 1,000 Flange 7 1/16 in. 5,000 Flange 2500 40.00 27.52*30 in. 30 in. 1,000 Flange 12 in. 1,000 Flange 2450 40.00 27.52

Figure 6.17 Hydril Drilling Spool Data

B

A

WEOX02.180

s made

been

theyrior to

eadsi to

psi Boltsific

ce theped

clampions.ended rigs.

rers’duld be

OPcluded).ns and spooltedd lead

dril’

arytely buf

fves areressure


6-36March 1995

API high-pressure connections are pressure sealed by means of ring-joint gasketof soft iron, low-carbon steel or stainless steel. API Type RX and Type BX ring-jointgaskets are pressure-energised seals but are not interchangeable. Rings that havecoated with Teflon, rubber or other resilient materials are not acceptable. All flanges inthe stack and side-outlets should be fitted with new ring-joint gaskets each timeare assembled. It is important that the ring groove in the flange be clean and dry pflanging up.

API Standard 6A, ‘Wellhead Equipment’, provides specifications for flanged wellhfittings. API Type 6B flanges are available in the following pressure ratings: 2000 p5000 psi range. API Type 6BX flanges are available for the 5000 psi to 30,000range. Figure 6.16 lists specifications for BOP flanges, ring gaskets and bolts.must always be the right size – not larger and not smaller than required for the specbolt holes.

Hub and clamp connectors are principally used on subsea BOP stacks to reduweight and height. The bolts are designed for easier make-up, especially in cramquarters, because the wrench movement is downward instead of horizontal.

When clamp connectors were first used there were numerous problems with theloosening during drilling operations and creating a hazard in well control situatThis problem has been greatly reduced by the manufacturer furnishing recommbolt torque make-up values and the avialability of power torque wrenches on the

Cameron Iron Works clamp connections are installed on most major manufactuhub and clamp preventers. When a clamp connected BOP stack is used, recommendetorque requirements should be obtained from the manufacturer and all bolts shomade up to the required torque with power wrenches.

(f) Drilling Spools

Drilling spools are recommended for choke and kill line outlets on all Bstack␣arrangements (subsea BOP stacks and low pressure surface stacks are exThe spool provides space between ram preventers to facilitate stripping operatiolocalises possible erosion during well control operations in the less expensiverather than the preventer body. Drilling spools should be designed and fabricain␣accordance with API 6A, ‘Specifications for Wellhead Equipment’. Most wellheamanufacturers can fabricate drilling spools to any dimensions required althoughtime is usually several weeks. Figure 6.17 shows dimensional data for Hysdrilling␣spools.

6 Choke and Standpipe Manifolds

(a) Choke Manifold

A typical choke manifold layout is shown in Figure 6.18. It features inlets for the primchoke line, the kill or secondary choke line and from the kill pump; two remoadjustable chokes, two manually adjustable chokes, a straight choke bypass, aferchamber and outlets to the pits, direct or via the poorboy degasser. Valves upstream othe chokes should be rated to the working pressure of the BOPs, lower rated valacceptable downstream. Each choke can be isolated by two valves on the high pside. The system offers complete redundancy, (except of the buffer tank) since flow canbe directed via an alternative route whilst a section is repaired.

eturnske

designuffore

,

riable

bufrator totion

ment

estroke choke

lso be

e leftill be

boy

illing.choke

nifold bed theFornifolds, should


6-37March 1995

A bypass line to the poorboy degasser is provided in order to be able to deal with rin the event of failure of the buffer tank. It is recognised that the majority of chomanifolds installed on drilling rigs comprise a buffer tank into which all the linesdownstream of the chokes are tied. Field personnel should be aware that this compromise seriously reduces the flexibility/redundancy of the manifold. If the bfertank cuts out, the manifold is in effect rendered useless. Consideration should therebe given to installing split buffer tanks and separate flare lines or, as previouslymentioned, a bypass line upstream of the buffer tank. All connections should be flangedwelded, or clamped. Field welding is not acceptable.

Company policy specifies that choke manifolds should incorporate at least two vachokes on offshore rigs, one of which must be remotely adjustable.

On some manifolds, mandatory in some areas, an additional outlet from the ferchamber is provided, so that hydrocarbons can be directed via a production sepaa flare. An inlet to facilitate the tying-in of a specialised choke manifold during formatesting is also provided.

On wells where there is a possibility of encountering hydrogen sulphide, all equipand material should be suitable for sour service.

The control panel for the chokes should be near the Driller’s station, and should havread-outs for standpipe manifold pressure, choke manifold pressure and pump counters. A pressure gauge reading standpipe pressure should be located at themanifold if manual chokes are used during a well kill operation. The MAASP function,where fitted, should not be used.

A recording chart for standby pressure and choke manifold pressure, may aconsidered. This chart can be used when testing BOPs, or when handling kicks.

Under normal drilling conditions, valves on the choke line and manifold should bopen up to the valve immediately upstream of the remotely operated choke that wused in the event of a kick. The valves downstream should be open to the poordegasser and mud tanks. The remote adjustable choke(s) should be left closed. Theouter choke (HCR or failsafe) valve on the BOP stack should be closed during drIt must be possible to record choke pressure when the well is shut-in with the manifold lined up in this manner.

(b) Standpipe Manifold

A typical arrangement of standpipe manifold showing connections to the choke mais illustrated in Figure 6.19. This manifold, for example, permits one mud pump tolined up on the annulus, (through kill line perhaps via the choke manifold) ansecond to kelly, or circulating head, to facilitate control of severe lost circulation. 10,000 and 15,000 psi BOP systems, it is acceptable to use 5000 psi standpipe mabut the isolation valve should be the same pressure rating as the BOP stack, asconnecting pipework.


6-38March 1995

Figure 6.18 Choke Manifold, 10M/15M

BYPASS TO POORBOY

DEGASSER OR TRIP TANK

CHOKE BYPASS LINEKILL OR

SECONDARY CHOKE LINE

PRIMARY CHOKE

LINE

MANUAL CHOKE LINE

TO GAUGE

BUFFER CHAMBER

RESERVE PIT (DERRICK FLARE OFFSHORE RIGS)

BURNING LINE (PRODUCTION

GAS SEPARATOR OFFSHORE RIGS)

WEOX02.181

10000psi gate valves. 5000psi gate valves. Remote controlled chokes. Manually adjusted chokes.

1. 2. 3. 4.

FROM DST CHOKE MANIFOLD

DST LINE

FROM KILL PUMP

BOP STACK

2

2

2

3

4

3

4

1

1

111

1 2

2

2

TO POORBOY DEGASSER

TO MUD PITS

t be

e flow

al,

inh

ignedhe

is not


6-39March 1995

Figure 6.19 Standpipe Manifold

7 Diverters

If a kick is taken when conductor is set in incompetent formation, the well will noshut-in, but instead, will be diverted.

A surface diverter system, consisting of an annular preventer and vent lines, allows thto be directed to a safe area, away from the rig and personnel.

Vent lines should be as large (12 in. minimum on offshore rigs) and as straight as practicso as to minimise back pressure, erosion and the risk of plugging by well debris. The linesshould be sufficiently braced to absorb severe shock loadings; sections likely to suffer erosione.g. bends, should be reinforced. There should be no restriction to the bore, any valvesthe lines should be full opening ball valves. Periodically, the lines should be flushed througto ensure that they remain unobstructed.

To prevent the well being inadvertently shut in, any valves in the vent line should be desto automatically open when the diverter is closed. An acceptable alternative is to elevate tvent line above the flowline, so that no valves are necessary.

If the BOP stack is installed, the control panels should be clearly marked that the wellto be closed in, but that the diverter is to be actuated.

ISOLATION VALVE SAME RATING AS CHOKE MANIFOLD

TO REMOTE PRESSURE GAUGE1

1

2 2

TO CHOKE MANIFOLD OR PRESSURE GAUGE

AUXILIARY TIE-IN POINT

TO HOLE/FILL LINE OR TRIP TANK

SECONDARY STANDPIPE

MUD PUMP

PRIMARY STANDPIPE

MUD PUMP

5000psi gate valves. Gate valve to suit pressure rating of standpipe manifold.

1. 2.

WEOX02.182

1

1

1


6-40March 1995

Figure 6.20 Subsea Diverter Stack

21in HST RISER COUPLING PIN

MUD BOOST LINE CONNECTION

211/4in – 2000 MSP ANNU-FLEX

FLEX JOINT

ANNULAR BOP

21in HYDRAULIC CONNECTOR

211/4in – 2000 SHEAR RAM

OUTLET NOZZLE(S)

BLIND FLANGE

C/K VALVE

30in LATCH

211/4in – 2000 FSS SPOOL

WEOX02.183

larlyical

ssureit

:

fromened

nce of

ed.ctor


6-41March 1995

The working pressures of the diverter and vent lines is not of prime importance (particuon floating rigs where the slip joint packing may be the limiting factor); 500 psi is a typrating.

Company policy states that subsea wells should be drilled riserless until a precontainment string is set. This is to avoid allowing shallow gas flow to the rig. If however becomes necessary to drill for surface casing with a riser, Company policy states that thewell will be diverted subsea in the event of a shallow gas flow.

The most likely stack up that will be used to divert subsea will comprise the following

• Pin connector with subsea dump valves (minimum ID 10 in.).

• LMRP with annular preventer.

This will be a relatively inexpensive stack that will in most cases be made up mainly existing rig equipment. In the event of a shallow gas flow the dump valves will be opand the annular closed to divert subsea. In order to move the rig the LMRP can bedisconnected and the well allowed to flow at the seabed.

Various stacks have been custom made for diverting subsea in areas of high incideshallow gas. An example is shown in Figure 6.20; the diverter stack comprising:

• Flex joint

• Annular preventer

• Hydraulic connector

• Blind/shear ram

• Spool piece with two outlets with dump valves

• Choke/kill line

• Hydraulic connector

In the event of a shallow gas flow, the dump valves will be opened and the annular closIn order to move the rig off location the blind/shear rams can be closed and the connereleased.

6-41/42


6.3 CONTROL SYSTEMS

Paragraph Page

1 General 6-44

2 Power Source 6-44

3 Control Manifolds 6-46

4 Accumulators 6-47

Illustrations

6.21 Subsea Stack Function Schematic 6-45

6.22 Annular Preventers – fluid required to operate 6-48

6.23 Ram Preventers – fluid required to operate 6-50

6.24 Compressibility Factor – Nitrogen 6-51

6-43March 1995

valve,

of

ted atould

ctively

venter

e mainrate a

away

ack is


6-44March 1995

1 General

The Control System provides the means to individually close and open each BOP andconveniently, rapidly, repeatedly and at the correct operating pressure. The equipment shouldbe designed to operate when, in emergencies, primary rig power may not be available.

The essential elements of a control system are:

• Power Source(s)

• Control Manifolds

• Accumulators

• Connecting Pipework/Hose Bundle and Wiring

Detailed specifications for a particular application will be governed by the number, sizeand pressure rating of BOPs. Water depth considerations will also influence the designsubsea BOP control systems.

An example arrangement for subsea BOP systems is shown in Figure 6.21.

2 Power Source

(a) Primary Power Source

The primary power source should be an electrically driven pump (or pumps) locathe main control manifold. For 3000 psi accumulator systems, the pump(s) shincorporate a pressure switch set to cut in and out at 2800 psi and 3000 psi respe.Diesel driven pumps may be substituted for land rig applications.

The electric pump output should be twice that of the secondary air pumps. The combinedelectric and air pumps should be sufficient to charge the accumulator system frompre-charge to operating pressure in less than 15 minutes, also to close an annular pre(without accumulator assistance) in less than 2 minutes.

(b) Secondary Power Source

The secondary power source should be an air power pump system, located at thcontrol manifold. For 3000 psi accumulator systems, the pump(s) should incorpopressure switch set to cut in and out at 2750 psi and 3000 psi respectively. A standbydiesel driven air compressor piped to the pumps should be provided at a locationfrom the primary rig power source, and where possible, 150 ft from the well axis.

(c) Battery Packs

Where electric panels are used, and for electro-hydraulic systems, a battery prequired. This should be located, where possible, 150 ft from the well axis.


6-45March 1995

Figure 6.21 Subsea Stack Function Schematic

KR

KR

3000psi PUMP

YOUR RIG

RIG AIR COMPRESSOR

MINI PANEL

RIG POWER 120V ac

ACCUMULATORS

DRILLER’S PANEL

RESERVOIR

REDUNDANT POD

OPEN BLOCK CLOSE

KR

KR

3000psi PUMP

YOUR RIG

RIG AIR COMPRESSOR

MINI PANEL

RIG POWER 120V ac

ACCUMULATORS

RAMS CLOSED BLOCK POSITION (RAMS CLOSED, NO PRESSURE)

RAMS OPENED

DRILLER’S PANEL

RESERVOIR

REDUNDANT POD

OPEN BLOCK CLOSE

KR

KR

3000psi PUMP

YOUR RIG

RIG AIR COMPRESSOR

MINI PANEL

RIG POWER 120V ac

ACCUMULATORS

DRILLER’S PANEL

RESERVOIR

REDUNDANT POD

WELLHEAD

WEOX02.184

BOP

OPEN BLOCK CLOSE

RAM PREVENTER OPENING LINE

RAM PREVENTER CLOSING LINE

SHUTTLE VALVE

POD LATCH

FEMALE POD CONNECTORS

MALE POD CONNECTOR

SOLENOIDS

POD SELECTOR AIR VALVE

POD SELECTOR

SPM VALVE

POD MOUNTED REGULATOR

PILOT REGULATOR

3000psi Accumulator Fluid Pressure 125psi Rig Air Pressure Regulated KR Fluid PressureVent/or No Pressure

r ram

ls.

tion.

r the

e for

t).

tial

els.

sures

ving


6-46March 1995

(d) Manual Closing of BOPs

For surface BOP installations, extension arms and wheels should be provided fotype BOPs.

3 Control Manifolds

The BOP control systems should ideally be equipped with 3 control manifolds or pane

(a) Central (Main Control) Manifold

This manifold should be located away from the rig floor area and in an accessible locaIt may be all hydraulic, air-hydraulic or electro-hydraulic. The accumulators and chargepumps are usually located with this manifold.

Required features include:

• A regulator to reduce accumulator pressure to manifold (operating) pressure foram preventers and valves.

• A regulator to reduce accumulator pressure to the variable operating pressurannular preventers.

• Control handles, or switches, for all functions. An additional function is required onsubsea stacks to transfer command between hose bundles or pods. A hinged covershould be placed over critical functions (shear/blind rams, wellhead disconnecAlocking device should not be used.

• Pressure gauges for accumulator, manifold and annular pressures.

• A valve to bypass the manifold regulator.

• Tie-in points for accumulators, charge pumps, remote panels, and air lines.

• A vent line for bleeding off accumulator fluid to the storage tank.

• A relief valve for the hydraulic and electric pumps.

• A flowmeter to indicate the volume of fluid used in operating a function (essenon subsea stacks, desirable on surface stacks).

(b) Driller’s Control Panel

The panel should be located on the rig floor within easy access of the Driller’s station.It should be air or electric operated. Explosion-proofing is required for electric pan


• Controls for each BOP stack function and to adjust the manifold regulators.

• Read-outs for the accumulator pressure, regulated manifold and annular presand flowmeter.

• Air supply pressure read-out.

• A schematic of the BOP arrangement showing kill and choke line outlets, and haram sizes marked.

.

e, or

ing

e or

ors,e

nk totors

g

g in

ould open psi


6-47March 1995

• Covers, or interlocks, for critical functions, eg shear rams, wellhead disconnect

• Visual and/or audible warning devices for low accumulator pressure, air pressurfluid levels.

• Where applicable, controls for diverter functions.

(c) Remote Manifold (or Panel)

This panel should be located a safe distance from the well axis. For offshore rigs, it isnormally located in the Toolpusher’s office. It should be air or electric operated.


• Controls for each BOP stack function.

• A schematic of the BOP arrangement showing kill and choke line outlets and havram sizes marked.

• Covers, or interlocks, for critical functions.

• Visual and/or audible warning devices for low accumulator pressure, air pressurfluid levels.

4 Accumulators

The hydraulic fluid required to operate the BOP functions is stored in accumulatpressurised against a nitrogen inflated bladder. The accumulators should be located near thmain control manifold location.

The purpose of the accumulators is to provide a store of hydraulic energy and a high ratesupply of hydraulic fluid to the BOP functions. The response time of the BOP functions istherefore independent of the output of the pumps.

For subsea installations, at least two accumulators should be isolated from the main baprovide pilot line pressure. Also, to ensure acceptable response times, additional accumulashould be mounted on the BOP stack.

Accumulator bottles should be used as surge dampeners on annular preventers for strippinoperations on both surface and subsea BOP stacks.

(a) Accumulator/Precharge

Operating pressure of accumulators is generally 3000 psi. The optimum bladder inflation,or precharge pressure, is governed by the minimum acceptable pressure remaininthe accumulators after operation of the preventers. About 1200 psi is required to holdsome annular preventers closed. A precharge of 1000 psi will retain a small liquid reservein the accumulator when pressure in the system falls to 1200 psi.

(b) Sizing of Accumulators

Company policy for surface stacks specifies that the total accumulator volume shbe 1 1/2 times that required to close one pipe ram and one annular preventer andone hydraulically activated choke and still retain accumulator pressure equal to 200above pre-charge pressure, without pump assistance.

rs for in.

ssure


6-48March 1995

The following is an example of the technique that can be used to size accumulatoa surface stack (comprising one Hydril GL 18 3/4 in. 5M annular and 3 Hydril 18 3/410M ram preventers):

Volume to close:

1 Annular = 44 gal1 Ram = 17.1 gal1 HCR valve = 0.6 gal (See Figures 6.22 and 6.23)

Total fluid required = 61.7 gal X 1.5 = 92.55 gal

Precharge to 1000 psi, maximum operating pressure = 3000 psi, minimum operating pre= 1200 psi

ANNULAR PREVENTERSGALLONS OF FLUID REQ UIRED TO OPERATE AN OPEN HOLE

Inches psi Close Open Close Open Balancing Close Open

6 3,000 2.9 2.2 4.6 3.26 5,000 3.9 3.3 4.6 3.2

7 1/16 10,000 9.48 3,000 4.4 3.0 7.2 5.08 5,000 6.8 5.8 11.1 8.7

10 3,000 7.5 5.6 11.0 6.810 5,000 9.8 8.0 18.7 14.611 5,00011 10,000 25.112 3,000 11.4 9.8 23.5 14.7

13 5/8 3,00013 5/8 5,000 18.0 14.2 19.8 19.8 8.2 23.6 17.413 5/8 10,000 34.5 24.3 47.2 37.6

16 2,000 17.5 12.616 3,000 21.0 14.8

16 3/4 3,00016 3/4 5,000 28.7 19.9 33.8 33.8 17.3 33.0 25.616 3/4 10,000

18 2,000 21.1 14.418 3/4 5,000 44.0 44.0 20.0 48.2 37.6

20 2,000 32.6 17.020 3,00020 5,000

21 1/4 5,000 58.0 58.0 29.5 61.4 47.830 1,00030 2,000

Figure 6.22 Annular Preventer– fluid required to operate

Size andWorking Pressure

Hydril

GK GL Spherical

NL Shaffer

BP

WE

LL CO

NTR

OL M

AN

UA

L

6-49M

arch 1995

Figure 6.23

Ram

Preventers

– fluid required to operate

Close Open Close Open Close Open

2.75 2.32.75 2.3

1.9 1.83.7 3.4

2.75 2.32.75 2.33.25 2.73.25 2.7

5.2 5.2

3.55 2.9 5.95.4 4.9 4.911.5 11.2(S) 12.0 11.2(S)

3.55 2.9 5.4 4.9 5.9 4.911.5 11.2(S) 12.0 11.2(S)11.8 11.8 12.9 11.811.8 11.8(S) 12.9 11.8(S)

3.65 3.0

15.6 14.1

17.1 15.6

Hydril

E Manual (a) Auto (a)

RAM PREVENTERSGALLONS OF FLUID REQUIRED TO OPERATE ONE SET

Inches psi Close Open Close Open Close Open Inches Close Open

4 1/16 10,000 0.59 0.52 66 3,000 1.22 1.17 0.81 0.95 6.56 5,000 1.22 1.17 0.81 0.95 1.19 0.99 6.5

7 1/16 10,000 1.22 1.17 6.35 5.89 147 1/16 15,000 1.22 1.17 6.35 5.89 14

8 3,000 2.36 2.70 2.58 2.27 8.58 5,000 2.36 2.70 2.58 2.27 8.510 3,000 3.31 3.16 2.77 3.18 1.74 1.45 8.510 5,000 3.31 3.16 2.77 3.18 2.98 2.62 8.510 5,000 4.23 4.03(S)11 10,000 3.31 3.16 1011 10,000 4.23 4.03(S) 8.23 7.00 14 9.45 7.0011 15,000 5.54 5.42 14 9.40 8.1012 3,000 5.54 5.20 4.42 5.10 5.50 4.50 8.5

13 5/8 3,000 10 5.44 4.4613 5/8 3,00013 5/8 5,000 5.54 5.42 10 5.44 4.4613 5/8 5,000 6.78 6.36(S) 14 11.00 10.5213 5/8 10,000 5.54 5.42 14 9.45 7.0013 5/8 10,000 6.78 6.36(S)13 5/8 15,000 11.70 11.29 14 11.56 10.52

16 2,000 6.00 7.05 8.516 3/4 3,000 10.16 9.4516 3/4 5,000 10.16 9.45 10 6.07 4.9716 3/4 5,000 12.03 11.19(S) 14 11.76 10.6716 3/4 10,000 12.03 11.19 14 14.47 12.50

18 2,000 6.00 7.0518 3/4 10,000 24.88 23.00 14 14.55 13.21

20 2,000 8.11 7.61 5.07 4.46 8.520 2,000 7.80 6.68 1020 3,000 8.11 7.61 5.07 4.46 8.520 3,000 9.35 8.77(S) 16.88 15.35 14

21 1/4 2,000 8.11 7.6121 1/4 2,000 9.35 8.77(S)21 1/4 7,000 20.41 17.7821 1/4 7,500 23.19 20.20(S)21 1/4 10,000 26.54 21.14 14.42 12.65 1421 1/4 10,000 30.15 27.42(S) 16.05 13.86(P) 1426 3/4 2,000 10.50 9.8426 3/4 3,000 10.50 9.84

Size andWorking Pressure

NL ShafferCameron

CylinderSizeU QRC LWS SL

tions:

notctly

be


6-50March 1995

Therefore:

P1 = 1000 + 15 = 1015 psi Z1 = 1.00 T = 80°FP2 = 1200 + 15 = 1215 psi Z3 = 1.06 V1 = 10 gal (11 gal bottle minusP3 = 3000 + 15 = 3015 psi Z3 = 1.06 1 gal bladder

replacement)

(See Figure 6.24)

where: P1 = precharge pressure (psi)P2 = minimum operating pressure (psi)P3 = maximum operating pressure (psi)V1 = bladder internal volume at precharge pressure (gal)V2 = bladder internal volume at P2 (gal)V3 = bladder internal volume at P3 (gal)Z = compressibility factor for nitrogen

Using the gas law:

P X V = constantT X Z

So in this case:

1015 X 10 = 1215 X V2 = 3015 X V31.00 1.02 1.06

V2 = 8.52 galV3 = 3.57 gal

The useable volume per bottle is given by:

V2 – V3 = 8.52 – 3.57 = 4.95 gal/bottle

Therefore there is a requirement for:

92.55 = 19 bottles4.95

(c) Subsea Accumulators

Accumulators can be mounted on subsea BOP stacks to perform three separate func

• Response Improvement

With increasing water depths, the speed with which subsea preventers may be operateddecreases. This is caused by expansion of the fluid supply hoses and pressure lossesin the lines. (Note that response time will be a function of the hose length andwater depth). Response times can be improved by mounting accumulators direon the BOP stack.

Space and weight constraints will limit the number of accumulators which canstack-mounted.

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6-51March 1995

Figure 6.24 Compressibility Factor – Nitrogen

• Emergency Use

All floating rigs are generally equipped with an acoustic back-up control systemFor dynamically positioned rigs and rigs to be used in hazardous (e.g. ice flowareas this is essential equipment. In such installations, stack-mounted accumulashould be at least capable of closing one set of rams, one annular preventer releasing the riser disconnect upon receipt of a command from the acoustic systeThe accumulators should be manifolded at the stack, so that fluid is not lost shouthe supply lines from the rig be severed. The acoustic system and accumulator systemshould be tailored to the stack configuration.

For subsea stacks, a tie in should be provided for diver or ROV assistance. This willideally be for shear ram activation and will also include LMRP disconnect anwellhead connector disconnect.

2.1

2.0

2.2

1.9

1.8

1.7

1.6

1.5

1.4

1.3

1.2

1.1

1.0

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2000 4000 6000 8000 10000

PRESSURE POUNDS PER SQUARE INCH ABSOLUTE

AFTER SAGE 6 LACY API PROJECT No 37

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6-52March 1995

• Surge Dampening

Surge vessels should be provided for subsea annular preventers to facilitate strippaccording to manufacturers’ recommendations. Some preventers require surge vesselson the opening as well as closing sides. Nominal 10 gal capacity accumulators shbe used.

(d) Sizing of Subsea Accumulators

Company policy for the sizing of the accumulators for a subsea stack is more rigorthan for a surface stack. The accumulator capacity should be 1.5 times the volumrequired to open and close all the well control functions and still retain accumulapressure at 200 psi above initial pre-charge pressure.

The majority of the accumulators will be located at surface, however a small quanmaybe located on the stack in order to speed the response of the system. The total volumeof accumulators required will be determined by Company policy (or local legislation,more rigorous). The total volume will be provided by the sum of the fluid available asurface and subsea, at the stack. The surface located accumulators are sized as previousdescribed however a different technique is used for subsea accumulators.

The basic difference between designing for surface operation and for subsea operais that the precharge pressure must be altered to take account of the hydrostatic pressof the fluid in the supply lines. The useable volume from each subsea accumulator bottwill be lower than the equivalent surface bottle. The deeper the water, the greater willbe the reduction in useable volume from the accumulators.

The following is a technique that can be used to size accumulator bottles for suboperation for 500 m water depth (for 18 3/4 in. 10M stack):

Volume to close:

1 Annular = 44 gal1 Ram = 17.1 gal4 Failsafes = 2.4 gal (See Figures 6.22 and 6.23)

Total fluid required = 63.5 gal

Precharge to 1000 psi plus the hydrostatic of the control fluid.

Therefore:

P1 = 1000 + 15 + (500 X 1.03 X 1.421)= 1747 psi Z1 = 1.01 T1 = 80°F

P2 = 1200 + 15 + 732 = 1947 psi Z2 = 1.00 T2 = 40°FP3 = 3000 + 15 + 732 = 3747 psi Z3 = 1.09 T3 = 40°F

where: P1 = precharge pressure (psi)P2 = minimum operating pressure (psi)P3 = maximum operating pressure (psi)V1 = bladder internal volume at P1 (gal)V2 = bladder internal volume at P2 (gal)V3 = bladder internal volume at P3 (gal)Z = compressibility factor for nitrogen

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6-53March 1995

Using the gas law:

P X V = constant (T in °R)T X Z

So in this case:

1747 X 10 = 1947 X V2 = 3747 X V31.01 X 540 1.02 X 500 1.06 X 500

V2 = 8.23 galV3 = 4.66 gal

The useable volume per bottle is given by:

V2 – V3 = 8.23 – 4.66 = 3.57 gal/bottle

Therefore there is a requirement for:

63.5 = 18 bottles3.57

(e) Pipework/Hose Bundles and Wiring

For surface stacks, the simplest hook-up is to assign a dedicated high capacity cto each individual function. When a particular function is selected, fluid flows from tacccumulators, through a regulator, directly to the function. Concurrently, the oppositefunction is vented and the displaced fluid is returned to the reservoir. When consideringa surface hook-up, the following should be noted:

• Company policy (after API RP53) recommends that the system ensures ramsmall annular preventers (less than 20 in.) close within 30 seconds and larger annularpreventers within 45 seconds.

• Control lines should be seamless steel tubing of 1 in. minimum nominal sizeof␣a pressure rating at least equal to the working pressure of the control s(usually 3000 psi).

• Unions and swivels should be used in the BOP stack area to preclude stressthe␣lines.

• BOP closing and opening lines should be routed so as to minimise the risk of dain the event of a fire or falling debris. Flammable hoses should not be used on sinstallations.

A simple hook-up is impractical for subsea applications – too many individual lines handled easily and the pressure drop through the length of line would be too greacceptable reaction times. Instead, hose bundles are employed, which contain oncapacity (1 in.) conduit (to transfer the hydraulic fluid required to operate all functionsrecharge the subsea accumulators) and up to 64 pilot (3/16 in.) lines (to direct and cthe flow of fluid to a particular function). The bulk line is “teed” with the subsea accumulatoand terminates at a regulator which reduces the accumulator pressure to operating p

The output of the regulator is manifolded to the pilot valves. The pilot lines terminate infunction dedicated pilot (SPM) valves which respond to accumulator pressure when a fuis selected. Each then allows regulated fluid to flow, via a shuttle valve, to a particulafunction. The displaced fluid from the opposite function is vented at its pilot valve.

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6-54March 1995

The pilot valves and regulators are housed in a wireline retrievable pod, whicduplicated to provide complete redundancy. A shuttle valve located at each functionallows control by either pod.

When considering a subsea system, the following should be noted:

• Company policy (after API RP53) recommends that the systems ensure ram prevenclose within 45 seconds and annular preventers within 60 seconds of surface actuElectro-hydraulic systems will be required where water depths preclude satisfacclosing times with all hydraulic systems.

• Systems should be duplicated in all hydraulic and electric lines from the main conpanel to the BOP stack functions, i.e. there should be 100% redundancy. The Driller’spanel and the remote panel should be designed to select and operate either sy

• Dynamically positioned vessels and rigs operating in hazardous areas should an acoustic back-up system to secure the well and release the riser.

• Any unused functions (such as when the low pressure stack in a two stack systrun) should be blanked off to ensure that fluid is not vented by inadvertent operatioof that function.

(f) Operating Fluids

For subsea systems where the fluid from the main supply line is dumped whenvented, the fluid should be potable water, with the recommended percentage of soluboil added to prevent corrosion. Control line fluid is in a closed system and hence isreplaced. It is therefore important to flush out the control lines with the recommenfluid mix when the pods are pulled, prior to rerun.

In all cases, the fluid mix should be maintained year round such that the fluid will freeze at the minimum anticipated temperature for the year. Pure ethylene glycol shouldbe added to prevent freezing when necessary – under no circumstances should seabe used. The reservoir should be self filling, with an automatic mixing system fadditives. Operating fluids must be non-pollutant and bacteria resistant.

Most surface installations employ a simple closed system, with the operating freturned to the reservoir when it is vented. Either a light hydraulic oil or a subsea fluid is suitable.

The accumulator fluid reservoir should have a capacity of twice the working liqvolume of the accumulators.


6.4 ASSOCIATED EQUIPMENT

Paragraph Page

1 Mud Control and Monitoring Equipment 6-56

2 Mud Gas Separator 6-57

3 Drillstring Valves 6-60

4 Rotating Heads 6-62

Illustrations

6.25 Typical Trip Tank Hook-up – on a floating rig 6-57

6.26 An example Mud Gas Separator 6-59

6.27 Grant Rotating Head 6-63

6-55March 1995

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1 Mud Control and Monitoring Equipment

Proper installation and operation of this equipment is fundamental to effective primary andsecondary well control. The following are the most important aspects:

(a) Pit Volume Measurement

A pit volume measurement device (PVT) should be provided. A calibrated read-out andaudio alarm should be installed at the Driller’s station.

The following measurement devices are required for all tanks:

• A float for the PVT system. It should be possible to isolate other floats when thtank is in use.

• An internal calibrated ladder-type scale.

• A remote ladder-type scale, visible from the Driller’s station for the trip tank. Asmall wireline can be used to connect a float in the tank to the scale on the rig.

(b) Flowline Measurement

A device should be provided for measurement of flowline mud return rate. This (FloShow) device should have a read-out and alarm at the Driller’s station.

(c) Trip Tank

Trip tanks are used to fill the hole on trips, measure mud or water into the annuluscirculation has been lost, monitor the hole when tripping, logging or other similaroperations. The industry uses two basic types of trip tanks – gravity feed and pumpThepump type system is recommended because it provides for safer and more exptrip operation. The trip tank would be isolated from the surface mud system to preinadvertant loss or gain of mud from the trip tank due to valves being left open.

In the past, most blowouts occurred due to swabbing or not keeping the holewhile tripping the drillstring out of the hole. To provide more exact fluid measuremenfor pipe displacement, trip tanks were developed to accurately measure within ± 1.0barrel the influx or efflux of fluid from the wellbore. As the drillstring is pulled fromthe hole, the mud level will drop due to the volume of metal being removed. If mnot added to the hole as pipe is pulled, it is possible to reduce hydrostatic pressless than formation pressure. When this happens, a kick will occur. Swabbing can occurwhen pipe is pulled too fast, and friction between the pipe and the mud column ca reduction in hydrostatic pressure to a value less than formation pressure.

To prevent loss of hydrostatic pressure it is necessary to fill the hole on a regular schor continuously, using a trip tank and to keep track of the fluid volume required. Themetal volume of the pipe being pulled can be calculated, but mud additions necesreplace hole seepage losses due to filtration effects can only be predicted by comparisto the mud volumes required to keep the hole properly filled on previous trips. Foreason, it is imperative that a record of mud volume required versus number of spulled be maintained on the rig in a trip book for every trip made.

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6-57March 1995

Figure 6.25 Typical Trip Tank Hook-up– on a floating rig

As illustrated in Figure 6.25, a centrifugal pump takes suction from the trip tank fills the hole through a line into the bell nipple. The pump runs constantly while thedrillstring is pulled from the hole. The hole stays full as each stand of pipe is pulled aexcess mud returns to the trip tank through an outlet on the main flow line. A valvemust be installed in the flow line downstream of this outlet to block all flow to the shshakers while making a trip. This closed circulation system can be monitored by a flosystem and a digital readout in 1-barrel increments on the Driller’s console.

2 Mud Gas Separator

The separator is installed downstream of the choke manifold to separate gas from the dfluid. This provides a means for safely venting the gas and returning usable liquid muthe active system.

REMOTE CONTROL VALVE

OVERBOARD

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Basically, there are two types of mud gas separators: Atmospheric and Pressurised. Theatmospheric type separator is standard equipment on virtually all rigs and is referredthe field as a ‘gas buster’ or ‘poorboy’ separator. The main advantage of this type of separatis its operational simplicity which does not require control valves on either the gas ordischarge lines. A pressurised mud gas separator is designed to operate with moderatepressure, generally 50 psi or less. Pressurised separators are utilised to overcome line plosses when an excessive length of vent line is required to safely flare and burn the hazgas an extended distance from the rig. The pressurised separator is considered specialequipment and is not usually provided by the contractor. This type of separator is installedon rigs drilling in high risk H2S areas and for drilling underbalanced in areas where hpressure, low volume gas continually feeds into the circulating fluid.

During well control operations, the main purpose of a mud gas separator is to vent thand save the drilling fluid. This is important not only for economic reasons, but alsominimise the risk of circulating out a gas kick without having to shut down to mix additiomud volume. In some situations the amount of mud lost can be critical when surface vois marginal and on-site mud supplies are limited. When a gas kick is properly shut in ancirculated out, the mud gas separator should be capable of salvaging most of the mu

There are a number of design features which affect the volume of gas and fluid that thseparator can safely handle. For production operations, gas oil separators can be sizinternally designed to efficiently separate gas from the fluid. This is possible because thfluid and gas characteristics are known and design flow rates can be readily establisis apparent that ‘gas busters’ for drilling rigs cannot be designed on the same basis siproperties of circulated fluids from gas kicks are unpredictable and a wide range of mconditions occur downhole. In addition, mud rheological properties vary widely and hastrong effect on gas environment. For both practical and cost reasons, rig mud gas sepaare not designed for maximum possible gas release rates which might be needed; ho,they should handle most kicks when recommended shut-in procedures and well cpractices are followed. When gas flow rates exceed the separator capacity, the flow must bebypassed around the separator directly to the flare line. This will prevent the hazardoussituation of blowing the liquid from the bottom of the separator and discharging gas into themud system.

Figure 6.26 illustrates the basic design features for atmospheric mud gas separatorsmost drilling contractors have their own separator design, the Drilling Foreman must anand compare the contractor’s equipment with the recommended design to ensure the esserequirements are met.

The atmospheric type separator operates on the gravity or hydrostatic pressure priThe essential design features are:

• Height and diameter of separator.

• Internal baffle arrangement to assist in additional gas breakout.

• Diameter and length of gas outlet.

• A target plate to minimise erosion where inlet mud gas mixture contacts the intewall of the separator, which provides a method of inspecting plate wear.

• A U-tube arrangement properly sized to maintain a fluid seal in the separator.

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6-59March 1995

Figure 6.26 An example Mud Gas Separator

The height and diameter of an atmospheric separator are critical dimensions which fectthe volume of gas and fluid the separator can efficiently handle. As the mud and gas mixtureenters the separator, the operating pressure is atmospheric plus pressure due to frictiothe gas vent line. The vertical distance from the inlet to the static fluid level allows time fadditional gas breakout and provides an allowance for the fluid to rise somewhat doperation to overcome friction loss in the mud outlet lines. As shown on Figure 6.26, thegas-fluid inlet should be located approximately at the midpoint of the vertical height. Thisprovides the top half for a gas chamber and the bottom half for gas separation andretention. The 30 in. diameter and 16 ft minimum vessel height requirements have proadequate to handle the majority of gas kicks. The separator inlet should have at least thsame ID as the largest line from the choke manifold, which is usually 4 in. Some separause tangential inlet, which creates a small centrifugal effect on the gas-fluid mixture andcauses faster gas breakout.

INSPECTION COVER

GAS OUTLET

8in ID MINIMUM

GAS BACK PRESSURE REGISTERED AT THIS GAUGE (Typically 0 to 20psi)

INSPECTION COVER

SECTION A-A TANGENTIAL INLET

TO SHAKER HEADER TANK

2in DRAIN OR FLUSH LINE4in CLEAN-OUT

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4in ID INLET-TANGENTIAL TO SHELL FROM CHOKE MANIFOLD

MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg: 10ft HEAD AT 1.5 SG GIVES 6.5psi MAXIMUM CAPACITY

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The baffle system causes the mud to flow in thin sheets which assists the separation pThere are numerous arrangements and shapes of baffles used. It is important that each plabe securely welded to the body of the separator with angle braces.

A 6 in. minimum ID gas outlet is recommended to allow a large volume of low pressure gato be released from the separator with minimum restriction. Care should be taken to minimum back pressure in the vent line. On most offshore rigs, the vent line is extendestraight up and supported to a derrick leg. The ideal line would be restricted to 30 ft length and the top of the line should be bent outward about 30 degrees to direct gaaway from the rig floor. If it is intended that the gas be flared, flame arresters shoulinstalled at the discharge end of the vent line.

As previously mentioned, when the gas pressures in the separator exceeds the hydhead of the mud in the U-tube, the fluid seal in the bottom is lost and gas starts flowinthe mud system. The mud outlet downstream of the U-tube should be designed to mainminimum vessel fluid level of approximately 3 1/2 ft in a 16ft high separator. Assuming a1.44 SG mud and total U-tube height of 6 ft, the fluid seal would have a hydrostatic prequal to 3.7 psi. This points out the importance for providing a large diameter gas vent linwith the fewest possible turns to minimise line frictional losses.

The mud outlet line must be designed to handle viscous, contaminated mud returAsshown in Figure 6.26, an 8 in. line is recommended to minimise frictional losses. This lineusually discharges into the mud ditch in order that good mud can be directed over the shand untreatable mud routed to the waste pit.

In recent years, there have been a number of serious accidents caused by the failuregas separators during well control situations. Primarily these have resulted from dcontractors not updating their separator design and personnel training standards tohigh pressure gas kicks for deeper drilling operations. It is important that drilling persunderstand the limitations of all well control equipment and are trained to take remaction before pressure or capacity limitations occur. The key initial decision that must bmade is the pump rate at which the kick will be circulated out. Large influx, high pressuregas kicks should always be pumped out at low rates (generally 1 bbl/minute or leminimise the gas release rate at the surface where rapid gas expansion occurs. Cirout at a slow rate reduces the risk of exceeding pressure limitations for the well cequipment and provides additional decision reaction time.

3 Drillstring Valves

Drillpipe valves are used to close in the well on the drillpipe bore and to protect suequipment. The valves may be permanently in place, or installed at surface when reqand may be of a manual shut-off or automatic check valve type.

Drillstring valves should be rated to the same pressure as the BOP and tested at thfrequency.

Some of the drillstring valves impose restrictions on future operations when installeexample, both the inside BOP and drop-in valve, when in place, prevent access below tto the drillstring bore.

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6-61March 1995

The following are the most commonly used drillstring valves:

(a) Kelly Valves

Kelly valves should be full opening valves to allow running of wireline. Wrenches foroperating the valves should be held on the rig floor. Both upper and lower kelly valveshould be function tested daily.

The upper kelly valve is placed between the swivel and the kelly, the upper kelly valveprovides a means of closing in the drillstring when the kelly is down through the rotable and cannot be lifted.

The lower kelly valve, which is placed between the kelly and the drillstring, allowsclosing-in of the drillstring and removal of the kelly if required. The kelly valve providesa means of isolating the kelly if the drillpipe pressure approaches the pressure rathe kelly.

(b) Float Valves

Float valves are frequently used in top hole to prevent backflow during connectionflow up the drillstring in the event of a kick. Ported floats should be run whilst drillbelow surface casing. When installed, a float valve is a permanent part of the drillstriIf a float is run while drilling below surface casing, the valve should be ported.

The following points should be considered:

• The valve can be flapper or plunger type with facility to lock open whilst runnin␣hole.

• The valve requires regular inspection to check for damage, due to fluid erowhilst downhole.

• The valve will prevent U-tubing, that may be required to free differentially stuckpipe. It should not be used whilst drilling highly overbalanced permeable secwithout due consideration.

• Use of the valve may make reading of drillpipe pressures difficult when a kick hasbeen taken, especially when handling gas migration.

• If a ported float is used when drilling from a floating rig, it will be necessaryinstall a further valve in the string when hanging off in the BOP stack.

(c) Drop-in Valves

An automatic check valve that is held on surface until required and can then be dror pumped downhole to a special landing sub. It is Company policy that a landinwill be run in all strings. In the event of a kick while the pipe is off bottom, the drop-invalve can be used to allow the pipe to be stripped to bottom. The following pointsshould be considered:

• The valve will have limited ID which may plug, preventing further circulation acontinuation of control procedures.

• When in place, prevents access to the drillstring bore below it, but may be retrby wireline with some designs.

• The valve is not subject to erosion prior to use, as would be the case wpermanently installed flapper valve, as it can be held on surface until required

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6-62March 1995

• All the items in the drillstring above the landing sub must have sufficient ID toallow the check valve to pass. This includes kelly cocks, mud savers etc.

(d) Drillpipe Safety Valve

A safety valve to be installed at surface on detection of a kick, allowing the drillstrto be closed in. The valve should be a fullbore valve, typically a lower kelly valve allow easy stab-in wireline access if required. Crossovers between the safety valvall other tubulars in hole must be held on the drillfloor. It is Company policy that sucha valve should at all times be available on the rig floor.

(e) Inside BOP

A surface installed check valve to close off the drillstring bore. Commonly called aGray valve and in accordance with Company policy, should always be available on therig floor as a back-up for the drillpipe safety valve, or the drop-in check valve.

Prevents access to the drillstring bore below it and cannot be removed if belowrotary, or under pressure (unless a drillpipe safety valve is installed below it).

4 Rotating Heads

When used, rotating heads are installed above the BOP stack. They provide a seal on thekelly or drillpipe. A drive unit, attached to the kelly, locates in a bearing assembly above thstripper 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 pressure onwellbore.

• As a diverter for surface hole.

• To keep gas away from the rotary table. This is especially important where HydrogenSulphide can be expected.

Realistic working pressures for rotating heads are 500 to 700 psi. It is recommendedthey are not installed for routine gas cap drilling (unless sour gas is expected) since theprecludes observation from the rig floor of annulus fluid level.

Figure 6.27 shows a schedule of the Grant Rotating Head.


Figure 6.27 Grant Rotating Head

KELLY BUSHING

DRIVE BUSHING ASSEMBLY

SWING-BOLT CLAMP ASSEMBLY

SHOCK PAD

BOWL

STRIPPER RUBBER

DRIVE RING AND BEARING ASSEMBLY

OUTLET FLANGE

INLET FLANGE

WEOX02.190

6-63March 1995

6-63/64


6.5 EQUIPMENT TESTING

Paragraph Page

1 General 6-66

2 BOP Equipment and Wellheads 6-66

3 An Example Test Procedure 6-67

4 Test Frequency 6-71

5 Pressure Tests of Casing 6-71

Illustrations

6.28 Choke Manifold Schematic 6-68

6.29 An example BOP/Choke Manifold Test Procedure 6-69

6.30 Schematic of BOP Pressure Tests 6-70

6.31 An example BOP Equipment Test Report 6-72

6-65March 1995

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6-66March 1995

1 General

The consequences of a failure of BOP equipment under operating conditions can reaching. Rigorous BOP testing procedures are required in order that problems midentified under test conditions, and rectified before an emergency arises.

Equipment should be tested at the time of installation on the wellhead and at regular intthereafter, in accordance with Company standard policies and guidelines (unless contraby local policies). Common causes of failure include:

• Casing wear.

• Plugging of lines with baryte.

• Wellhead or BOP connections working loose through vibration.

• Deterioration of seals in valves and BOPs.

• Leaks and faults occurring in control systems.

The recommended procedures in this section cover BOP stack installations at sand␣subsea.

2 BOP Equipment and Wellheads

Preferably, pressure testing should be conducted with water against a solid type plug wis supported by the wellhead and seals either above or below the pack-off. All high pressuretests should be preceded by a low pressure test (e.g. 300 psi) and the final test preached in increments. Normally, a wellhead/BOP test pressure that holds stable for 10 minuis considered satisfactory.

The bore of the test string or the casing valve should be open during testing to prpressure being applied to the casing or formation, in the event of the test plug leakin

The rate of pressure increase due to volume pumped, should be closely monitored to dewhether the pack-off is leaking, and warn of the possible risk of collapsing the casing.

(a) Initial Pressure Test

If possible, the initial pressure test of all BOP functions should be conducted on stump prior to installation. However, if a stump is not available, the test should bconducted on the wellhead immediately after installation. It should be conducted tworking pressure of the wellhead or ram preventers, or the burst pressure of the strcasing to be run, whichever is the lowest. Annular preventers should be tested tomaximum of 70% of their working pressure.

Where possible, the initial sequence of tests should be arranged so as to minimvolume of fluid pressurised (e.g. the initial test of the wellhead connector shouagainst the lowest pipe rams); thereby minimising the damage caused by fluid cuin the event of a leak.

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After latching a subsea stack, a tensile test should be applied to ensure connectoproperly latched before any pressure testing. A pressure test should be carried out to thpressure rating of the wellhead or connector, on initial installation of the stack; thereafter,the connector will be tested during BOP tests to the pressure that the BOPs witested to. Also, the control system should be function tested on both pods.

(b) Routine Pressure Tests

Routine testing of the BOP (pipe rams and valves) and wellhead pack-offs should beconducted to either the maximum anticipated wellhead pressure, 80% of the casing pressure, the wellhead rated pressure or the BOP rated pressure, whichever is low

Annular preventers should not be tested to more than 70% of their working pressu

The blind/shear rams are tested on installation and after the 13 3/8 in. and 9 5/casing have been run. At subsequent BOP tests, the blind/shear rams should be functiotested according to Company policy. If the hole is open, the BOPs should be tested witthe drillstring at the shoe, suspended from the test plug. Tests should be carried outusing, in rotation, the main control panel, Driller’s panel and remote panel.

(c) Pressure Testing of Associated Equipment

The upper and lower kelly cocks, choke and standpipe manifolds, drillpipe safety vainside BOP and circulating head should all be tested to the lower of the maximanticipated wellhead pressure or their rated working pressure.

A test sub is required for testing the string tools from below.

Accumulator pre-charge pressures should be checked according to the manufactur’srecommendations. To test whether the accumulator and charge pumps are working correctly,the procedures as outlined in Chapter 1, ‘Drills and SCRs’ in Volume 1 should be adopted.

3 An Example Test Procedure

The following is an example test procedure for a four ram preventer subsea stackassociated choke manifold.

All the components of the choke manifold, in this example, are rated to the same pressuthe stack, and so all the components of the manifold (buffer tank etc) can be tested at thesame time, and to the same pressure, as the stack.

The kill pump is used as the test pump and is tied into the manifold at point A and point B asshown in Figure 6.28. Test pressure is applied both at point A and point B at all tests otherthan 4 and 5, when it is applied at point A only.

The inner and outer choke and kill line failsafes can be tested from the outside beforstack test is started as these tests do not require a test plug in the stack.

The blind/shear rams are not tested on a routine basis in line with Company policy. Thismeans that the failsafes on the upper kill line can only be tested from the inside to thepressure of the annular, until the blind/shear rams are tested.

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6-68March 1995

Figure 6.28 Choke Manifold Schematic

Figure 6.29 shows the procedure for the test as well as details of each component testeeach stage.

Figure 6.30 shows how the stack is lined up for each test. Figure 6.28 shows a schematthe choke manifold. As previously stated all the components of this manifold, that are showon the diagram, are rated to the full working pressure of the stack. Many other manifoincorporate piping and valves downstream of the chokes that are rated at a lower presthan the stack; in such cases, it is necessary to conduct a separate test of these compo

The following operational guidelines should also be considered for these tests:

• The test pressures used for each test are determined to be in line with Company pofor pressure testing of well control equipment.

• On landing the BOP, only one full working pressure test need be made against one pipram. This is to confirm the integrity of the wellhead connector.

• All subsea pressure tests will be conducted using openbore test tools.

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From Kill Pump B

Choke Line

Gauge Transmitter

Gauge Transmitter

2in 2202 Weco Female

Auto Choke

Auto Choke

From Kill Pump A

Kill Line

From Cement Pump

To Mud Gas Separator

2in 1502 Weco Female

From Mud Manifold

To Production Test Facility

To Drain

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6-69March 1995

• All tests will be carried out using a suitable test plug with only the specifdrillcollar␣weight below; i.e. test plugs will not be run on top of a bottomhole assemexcept when testing the blind/shear rams agains a backed-off test plug, if tested on aseparate run.

• When pressure testing blind/shear rams against casing consideration should be gpressure differential that already exists due to any difference in the weight of the mudinside and outside of the casing.

• All tests should be recorded on a chart.

• When testing blind/shear rams against a backed-off test plug, monitor volumespumped␣closely.

Figure 6.29 An example BOP/Choke Manif old Test Pr ocedure

TEST CHOKE MANIFOLD VALVES BOP LINE UP FAILSAFESCLOSED

1 3, 7, 9, 15, 18, 20, 24, 26,30, 32, 33

2 2, 30 UPPER ANNULAR, UPPER INNER KILL,LOWER INNER KILL

3 2, 30 LOWER ANNULAR, UPPER OUTER KILL,LOWER OUTER KILL

4 3, 5, 12, 17, 19, 22, 30, 34 UPPER PIPE RAMS, UPPER OUTER KILL,UPPER INNER CHOKE, LOWER INNER CHOKE

5 3, 6, 11, 13 UPPER PIPE RAMS, UPPER INNER KILL,UPPER OUTER CHOKE, LOWER OUTER CHOKE

6 2, 13, 14, 19, 20, 23, 27, 31 MIDDLE PIPE RAMS, LOWER OUTER KILL,UPPER OUTER CHOKE

7 3, 7, 12, 17, 19, 22, 33, 35, 36

8 4, 7, 8, 10, 16, 19, 21, 25, 29 LOWER PIPE RAMS, LOWER INNER KILL,UPPER INNER CHOKE

9 1, 7, 8, 26, 28


6-70March 1995

Figure 6.30 Schematic of BOP Pressure Tests

CONNECTOR

LOWER PIPE

UPPER PIPE

BLIND SHEAR RAM

TEST VALVE

TEST VALVE

CHOKEKILL

MIDDLE PIPE

LMRP CONNECTOR

2

LOWER ANNULAR

CONNECTOR

LOWER PIPE

UPPER PIPE

BLIND SHEAR RAM

TEST VALVE

TEST VALVE

CHOKEKILL

MIDDLE PIPE

LMRP CONNECTOR

3

UPPER ANNULAR

CONNECTOR

LOWER PIPE

BLIND SHEAR RAM

TEST VALVE

TEST VALVE

CHOKEKILL

MIDDLE PIPE

LMRP CONNECTOR

4

LOWER ANNULAR

CONNECTOR

LOWER PIPE

UPPER ANNULAR

BLIND SHEAR RAM

TEST VALVE

TEST VALVE

CHOKEKILL

MIDDLE PIPE

LMRP CONNECTOR

5

LOWER ANNULAR

CONNECTOR

LOWER PIPE

UPPER PIPE

BLIND SHEAR RAM

TEST VALVE

TEST VALVE

CHOKEKILL

UPPER ANNULAR

UPPER ANNULAR

LMRP CONNECTOR

6

LOWER ANNULAR

CONNECTOR

UPPER PIPE

BLIND SHEAR RAM

TEST VALVE

TEST VALVE

CHOKEKILL

MIDDLE PIPE

LMRP CONNECTOR

7

LOWER ANNULAR

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6-71March 1995

4 Test Frequency

Pressure testing of BOP equipment should be carried out according to Company poli,however in general:

• After installation of the wellhead component and BOP stack and prior to drilling each casing string.

• At intervals not exceeding 14 days.

• At any time requested by the Company Drilling Representative.

Results of pressure tests should be recorded on IADC reports, and on the BOP test form. Anexample of a typical BOP test form is presented as Figure 6.31.

The following additional points should be considered:

• Annular and ram (pipe) preventers should be operated on each trip into the holethe bit at the shoe (perhaps as part of a kick drill).

• Blind (but not blind/shear) rams should be operated each time the bit is out of the Choke line pressure should be monitored before re-opening the rams.

• Kelly cocks should be operated daily.

• Choke and kill valves should be operated daily, and lines pumped through.

• Choke manifold line-up should be checked each tour.

5 Pressure Tests of Casing

The integrity of casing strings is fundamental to effective well control. Casing design isbased on maximum anticipated pressures caused by a limited kick volume. Wear or corrosionof the casing bore will reduce burst and collapse strengths of casing and undermine thefor the design. The rate of wear depends on the type and duration of operations, anaccelerated by rough hardbanded drillpipe, high rotary speeds, and crooked hole. Prtesting of casing is required to prove the string’s original integrity and that wear does nosubsequently reduce casing strength below an acceptable level.

• Initial Test

Normally, the casing should be tested to prove the string’s integrity when bumping thetop plug, following cementing. Applied test pressure should be the maximum wellhepressure anticipated before the next casing string is set (i.e. casing design presHowever, if the additional tensile loading caused by the pressure test risks partingstring, the plug should be bumped with a nominal pressure and the full test preapplied after the string has gained support from the cement prior to drilling out the track.

• Subsequent Tests

Where significant casing wear is possible, a ditch magnet should be installed to mometal returns. If severe casing wear is suspected, actual wear should be measured by wcalliper tools and then the casing tested to the minimum acceptable pressure.


6-72March 1995

Figure 6.31 An example BOP Equipment Test Repor t

1 BOP STACK Unit Type Size WP Pressure applied Remaining Pressure Test DurationPRESSURE TEST Annular

Annular

Blind Shear Ram

Pipe Ram

Pipe Ram

Pipe Ram

UL Choke Line

CL Inner Valve

CL Outer Valve

UL Kill Line

KL Inner Valve

KL Outer Valve

Remote Kill Line

Diverter

2 CASING Casing in hole: Pressure AppliedPRESSURE TEST Pressure Remaining

Test Duration

Mud Weight: Packer Depth: Date Previous Test:

3 CHOKE MANIFOLD Pressure Applied: YES NO YES NOPRESSURE TEST Test Duration: All valves tested Manifold good for H2S

Valves last serviced: All chokes operated Water left in manifold

Setting max. allowable Handles on all valves Water left in K&C linespressure on remote choke:

Standpipe manifold tested K&C lines pumped through

Pressure applied Manifold line-up OK after test

4 CHARGE PUMPS Eletric pump cut in: Accumulator pressure: YES NO

Electric pump cut-out: Manifold pressure: Filters checked

Air pump cut-in: U Annular pressure: Storage tank level checked

Air pump cut-out: L Annular pressure: Mixing unit checked

Total accumulator volume: Panel used for BOP test: Low level alarms checked

Usable accum. vol. (3000-1200psi): Precharges last checked: Functions left in correct mode

Recharge time (1200-3000psi): Remote compressor available

5 ACCUMULATOR Accumulators and Pumps Accumulators onlyPERFORMANCE UNIT Time to Volume Pressure Time to Volume PressureCHECK Close Initial Final Close Initial Final

Annular

Annular

Blind Shear Ram

Pipe Ram

Pipe Ram

Pipe Ram

CL Inner Valve

CL Outer Valve

KL Inner Valve

KL Outer Valve

6 EQUIPMENT Are the following items on the rig, in good operating condition and pressure tested?CHECK TEST YES NO YES NO YES NO

Circulating head Kelly saver sub & rubber Trip tank

DP Safety Valve Hang-off tool PVT and alarms

XOs to DCs for DPSV Gas buster Flo-show and alarms

Inside BOP De-gasser Nitrogen for precharge

Drop in BOP sub + dart Gas detector Engine H2O spray and s/d

7 FAULTY Mention here leaks experienced in testing parts used, faulty or missing equipment and remedial actionEQUIPMENT

8 SIGNATURES Driller: Toolpusher: Company Drilling Rep:

Documents

Well Control Manual