Sedco Forex Well Control Manual

WELL CONTROL MANUAL

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The Sedco Forex Well Control Manual was compiled withcontributions from many of our own personnel, including Technical,Engineering, Training, Management and Rig staff. The efforts, ideas,and concerns put forth in the development of this manual are to becommended. This document (HQS-PO-OPT-01 rev 0) is exactly thesame as HQ-PO-TRN-01 rev3.0. The only change is a new documentreference number was given to comply with Sedco standards. Bothdocuments supersede Document HQ-PO-TRN-01 rev 2.0.

This Manual is to be kept on the rig and at the District Manager'soffice at all times and is to be used as a reference book for carryingout the Company's Well Control policies in preparation for andduring well control operations. All personnel that will be involved inwell control operations should read this manual carefully tofamiliarize themselves with current company policies. A policy is arule that shall be strictly applied by all personnel within the area ofapplication. The policies are in bold type and bordered with a box

The company requires that management staff and rig supervisorypersonnel discuss the Well Control Manual with our customers andoperator representatives on a timely basis. Any discrepancies ormisunderstandings about the policies are to be clarified beforedrilling/well control operations begin. Any deviation from thepolicies stated in this Manual must be reported to and approved bythe appropriate authority. An “Authorization for Exemption”application form (as shown in section 1.4.7.2 of the HSE Manual) is tobe filled out by the Rig manager, reviewed for approval by anauthority one level higher, and approved by an authority two levelshigher.

For the safety of all concerned use this Manual as a guide to goodwell control practices.

J. CahuzacPresident - Sedco Forex

http://sfmdoc.montrouge.sedco-forex.slb.com/sd/sd.nsf/DS/hse-man-01-4

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The field/district can forward recommendations to the RegionOperations Manager and the Region Technical Manager. Ifagreed within the Region, a proposed wording will be circulatedby the initiating Region Technical Manager to the Sedco ForexTraining Coordinator. The Training Coordinator will circulate theproposal to other Technical Managers and Engineering groups.After receiving comments the Sedco Forex Training Coordinatorwill be responsible for preparing the final revision sheet. Once it isapproved by the Region Technical Managers, he will have therevision distributed to the field manuals. Recommendations fromsources other than the Regions will be handled the same. Thegroup initiating a proposed revision will circulate these to theSedco Forex Training Coordinator.

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Throughout this manual, measurements are printed in SI units withequivalent quantities given in English units (generally inparentheses). An exception to this is when quantities relate tocalculations or measurements intended for practical applicationby rig personnel. Such quantities may be expressed in metric orEnglish units corresponding to those in conventional use on therigs or predominant field gauge markings.

IMPORTANT NOTICE

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Revision: 0TABLE OF CONTENTS

WELL CONTROL MANUAL

SummaryThis document provides the principals utilized for well control in Sedco Forex. These specifications shallbe used, unless otherwise agreed by the Regional Technical/Operations Managers

0 First issue under document number HQS-PO-OPT-01 07/10/993.0 General Revision of Entire Manual under doc number HQ-PO-TRN-01 07/10/992.0 Revised Responsibilities and Policies 1/9/941.0 Revised 1/3/9100 First Issue 1/12/87

RevisionNumber

Description of amendments / page changes/comments Datedd/mm/yy

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Chapter I - RESPONSIBILITIES & SUMMARY OF POLICIES ........................................................................7Chapter II - WELL CONTROL THEORY & PROCEDURES ...........................................................................13

II.1 PRIMARY CONTROL...............................................................................15II.2 SECONDARY CONTROL ........................................................................33

Chapter III - WELL CONTROL EQUIPMENT ..................................................................................................61III.1 MINIMUM BOP REQUIREMENTS...........................................................64III.2 MINIMUM DIVERTER REQUIREMENTS ................................................73III.3 CLOSING UNITS AND ACCUMULATOR REQUIREMENTS..................75III.4 CHOKE AND STANDPIPE MANIFOLD REQUIREMENTS.....................80III.5 OTHER WELL CONTROL EQUIPMENT.................................................86III.6 WELL CONTROL EQUIPMENT TESTING REQUIREMENTS................89

Chapter IV - WELL CONTROL DRILLS ..........................................................................................................94IV.1 ON BOTTOM DRILLING WHEN INSTRUCTION IS TO SHUT IN ..........95IV.2 WHEN INSTRUCTION IS TO DIVERT....................................................96IV.3 DRILL EXAMPLES...................................................................................97IV.4 SPECIAL DRILLS – DRILL SHEET EXAMPLES .....................................97

Chapter V - SPECIAL WELL CONTROL SITUATIONS................................................................................101V. 1 LOST CIRCULATION.............................................................................104V.2 SNUBBING ...........................................................................................105V.3 WORKOVER / BULLHEADING..............................................................107V.4 DST OPERATIONS................................................................................111V.5 H2S - HYDROGEN SULFIDE ................................................................115V.6 WELL CONTROL CONSIDERATIONS - WITH OIL BASED MUD .......117V.7 KICKS WITH DRILLCOLLARS OR CASING IN THE BOP STACK.......118V.8 HYDRATES............................................................................................122V.9 NO CIRCULATION.................................................................................125V.10 DETERMINING SHUT-IN DRILLPIPE PRESSURE WITH A FLOAT

VALVE IN DRILLSTRING.......................................................................126V.11 WIRELINE IN BOPS/LUBRICATORS....................................................127V.12 EMERGENCY DISCONNECT OPERATIONS DURING WELL KILL

OPERATIONS (MOORED FLOATING UNITS) .....................................131V.13 WELL CONTROL OPERATIONS AFTER SHEARING PIPE (MOORED

FLOATING UNITS) ................................................................................132V.14 TERTIARY CONTROL...........................................................................133V.15 TRAPPED GAS IN SUBSEA BOP STACKS ....................................137V.16 EQUIPMENT PROBLEMS .....................................................................138V.17 CHOKE LINE FRICTION........................................................................142V.18 DETERMINING THE CORRECT BOTTOM HOLE PRESSURE:

TRAPPED PRESSURE..........................................................................148V.19 UNDERBALANCED DRILLING..............................................................152V.20 COLLISION AVOIDANCE ......................................................................156

Chapter VI - DEEP WATER CONSIDERATIONS..........................................................................................157VI.1 HYDRATES IN DEEP WATER ..............................................................159VI.2 HANDLING GAS IN THE RISER ...........................................................165VI.3 MAASP IN DEEP WATER .....................................................................170VI.4 SHALLOW WATER FLOWS (SWF)......................................................171VI.5 TEMPERATURE EFFECTS ON MUD DENSITY AND RHEOLOGY.....173VI.6 RISER MARGIN .....................................................................................176

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VI.7 DEEPWATER WELL CONTROL THEORY & PROCEDURES.............177VI.8 EMERGENCY DISCONNECT PROCEDURES & CONTINGENCIE

(DP RIGS) .............................................................................................188VI.9 DEEPWATER WELL CONTROL EQUIPMENT ....................................191

Chapter VII - SLIM HOLE CONSIDERATIONS .............................................................................................195VII.1 SLIM HOLE CONSIDERATIONS – PRIMARY CONTROL....................197VII.2 SECONDARY CONTROL ......................................................................199VII.3 PRE-RECORDED INFORMATION........................................................199VII.4 SLIM HOLE KICK TOLERANCE............................................................203VII.5 SLIM HOLE WELL CONTROL METHODS............................................203VII.6 ANNULAR PRESSURE LOSS CALCULATION SHEET........................209VII.7 SLIM HOLE WELL DECISION TREE ....................................................210

Chapter VIII - HP/HT WELL DRILLING .........................................................................................................211VIII.1 PLANNING .............................................................................................213VIII.2 OPERATING PROCEDURES................................................................214VIII.3 EQUIPMENT ..........................................................................................216VIII.4 MATERIALS ...........................................................................................218

Chapter IX - HORIZONTAL AND HIGHLY DEVIATED WELLS....................................................................219IX.1 HORIZONTAL WELL CONTROL PROCEDURES ................................221IX.2 HORIZONTAL WELL KILL SHEET........................................................222IX.3 MULTILATERAL WELLS .......................................................................227

APPENDIX 1: Abbreviations / Definitions of Terms / References.............................................................2311.1 List of Abbreviations: ..............................................................................2321.2 Definition of Terms .................................................................................2341.3 Reference Documents............................................................................239

APPENDIX 2: CONVERSION TABLES............................................................................................................241APPENDIX 3: FORMS ......................................................................................................................................244APPENDIX 4: WELL CONTROL FORMULAE.................................................................................................267APPENDIX 5: FORMATION TESTS.................................................................................................................271

5.1 Leak-off Test Procedures.......................................................................272APPENDIX 6: EVALUATION OF SHALLOW GAS ..........................................................................................276APPENDIX 7: MUD GAS SEPARATOR...........................................................................................................279

7.1 Operations ..............................................................................................2807.2 System Design .......................................................................................282

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Revision: 0Chapter I Responsibilities & Summary of Policies

Chapter I - RESPONSIBILITIES & SUMMARY OF POLICIES

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I. RESPONSIBILITIES & SUMMARY OF POLICIES

1.1 On all SEDCO FOREX drilling units it is the responsibility of thedesignated man in charge to assure implementation of the properwell control practices and procedures. All SEDCO FOREX personnelmust know and comply with the SEDCO FOREX approved well controlpolicies. The designated man in charge will discuss well controlpolicies with the operator representative on the rig to ensure thatSEDCO FOREX's and Operator's policies are consistent. He will reportany differences to the District Manager. A summary of these policiesis shown in sections I.2 through I.27 of this chapter. In the otherchapters of the manual the policies are in bold type and borderedwith a box.

The practices and procedures included in this manual are minimumand are not to be reduced to comply with any governmentalagency requirements. The well control practices and proceduresshould be adjusted accordingly to comply with more stringent localgovernment regulations or operator policies. The responsibilities ofSEDCO FOREX personnel as described in this manual in no wayreduce those of the operator with regards to well control.

I.2 It is the Driller's responsibility to close the well in if a kick is indicatedor suspected.

I.3 The hole must be kept full at all times by using a trip tank andaccurate trip fill-up records will be maintained.

I.4 All drilling breaks will be flow checked

I.5 When tripping pipe, flow checks will be made:- Just off bottom.- At the lowest casing shoe.- Prior to pulling heavy-weight drillpipe or drill collars through the

BOP.

I.6 Slow circulation rates will be taken:- As practical at the beginning of every tour.- Any time the mud properties are changed.

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- Any time the bit nozzle configuration is changed.- As soon as possible after bottoms up from any trip.

I.7 When lost circulation occurs and cannot be regained through thedrillpipe, the annulus will be filled with the lightest fluid available(usually water) and volume recorded.

I.8 The kelly (or top drive) will always be used for well control operationswith a kick assembly kept available as an alternative. If theanticipated surface pressure exceed the safe working limits of thekelly or top drive assembly or if the motion compensator is notoperational, the kick assembly will be used.

I.9 Tripping out of the hole without full returns is potentially dangerousand will only be permitted under known conditions with permissionobtained at the District Manager level. The Region EVP may decidethat the decision will be made at the Region level. Such permissionmay be granted in advance on a well per well basis.

I.10 Drillers will be instructed in writing on what action to take if a wellkicks while drilling surface hole. This can be either to shut in or divert.

I.11 Unless the following materials are at the rig available to use, drillingoperations will be suspended:

- Enough weighting agent to raise the active mud system at least120 kg/m3 (1 ppg).

- Enough cement to place at least 120 m (400 ft) plug in openhole.

I.12 Pit drills and blowout drills will be held on a weekly basis or moreoften if the Rig Superintendent considers it necessary. These drills willbe logged in the I.A.D.C. drilling report.

I.13 BOP and related equipment shall be pressure tested every 14 days orduring the first trip after the 14 day interval. The intent is that the testbe done when practical near the 14th day and will depend on thetype of operations being carried out or still to be carried out. Theperiod between tests shall not exceed a maximum of 21 days.

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Pressure testing will be conducted in accordance with the SedcoForex Well Control manual.

BOP and related equipment shall be function tested every 7 days orduring the first trip after the 7 day interval. The intent is that the testbe done when practical near the 7th day and will depend on thetype of operations being carried out or still to be carried out. Theperiod between tests shall not exceed a maximum of 14 days

I.14 A float (solid or ported) will be run while drilling and opening holeprior to setting surface casing or any time the posted well controlplan is to divert.

I.15 While running, casing will be completely filled from the top at leastevery 5 joints, irrespective of the type of float equipment in use.

I.16 Wells will be closed in using the procedure described in the SedcoForex Well Control Manual Section II.2. Relevant step by stepprocedure to shut the well in or divert, as applicable, must be postedin the vicinity of Driller's panel.

I.17 When the well is closed in due to a kick, reciprocation of the drillpipeis not permissible unless previously approved by the OperationsManager. Reciprocation of the drillpipe is strongly discouraged andshould not be done unless the following conditions have beenconsidered and limits agreed upon prior to commencing the wellkilling operation.

- Choke or casing pressure limits set (recommend < 1000 psi).- Pipe movement is controlled to avoid stripping tool joint

through annular.- For subsea stacks, sea conditions remain relatively stable

throughout the operation. Recommend limits be set onallowable vessel movement such as 5ft heave and perhaps 3degrees on pitch or roll.

- Stripping speed must be regulated in accordance with sectionII.2.5 (i.e. ≤ 2 ft/sec).

Stripping speed < 2 ft/sec = block speed + vessel motion- Adequate procedures are put in place to provide early

detection of equipment malfunction or failure and fastcorrective action are pre-planned.

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- Also consider the number and the condition of the annularBOP

I.18 The distance from the rotary kelly bushing (R.K.B.) to the pipe ramswill be known at all times and must be posted in the vicinity of theDriller's B0P panel. Drillers on floating units shall have tide charts.

I.l9 The Driller will check all choke manifold, diverter and overboardvalves for proper setting at the beginning of each tour.

I.20 The Driller must know true vertical depth (T.V.D.) measurements.

I.21 Prior to spudding, it is the responsibility of SEDCO FOREX's man-in-charge to review the well plan and ensure that Primary Well Controlhas been addressed.

I.22 Any time a trip is interrupted the hand tight installation of a safetyvalve is required.

I.23 A minimum of one safety valve and one inside BOP with appropriatecross-overs will be available on the rig floor at all times, including acirculating head when running casing. A proper means of handlingwill be provided to assist with its installation.

I.24 If the well cannot be closed in with the BOP, the well will be properlysecured and tested by setting a plug.

I.25 Well Control attendance policy.

A. As a minimum requirement the following Sedco Forex personnel shallsuccessfully complete a Sedco Forex approved Well Control Trainingcourse at least every two years:

Rig Superintendents Assistant Rig SuperintendentsDrillers Assistant DrillersSubsea Equipment Supervisor Rig EngineersDistrict Managers Rig ManagersDrilling Engineers Staff EngineersDrilling Superintendents District Operations ManagersDrilling Equipment Supervisor MDS EngineersRegion and Headquarters Training Managers

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Region Operations Engineers

B. In addition to the above minimum requirements, Regions may have additional requirements of well control training, which could bebased on:- Well control test results of personnel.- Legislative requirements in certain countries.- Type of wells drilled.- Personnel Development.

I.26 The Rig Superintendent will complete a Well Control Report to besent to the Field Support Manager, for review of any equipment-related problems, after a well control operation. Rigs equipped withcomputerized kick detection or MDS™ should have a printout of thewell kick program attached to the report.

I.27 After setting the initial casing string(s), (or during workover operations)a minimum of two independent and tested barriers should be inplace at all times. Upon failure of a barrier, normal operations willcease and not resume until a two barrier position has been restored.

A barrier as defined means: - Any remote operated valve or set of valves that can be regularly

pressure tested.- Any fluid column that exerts sufficient hydrostatic pressure to

overbalance the reservoir pressure.- Any cement plug in the wellbore that has been suitably tested.- Any mechanical equipment installed in the wellhead or christmas

tree or in the production tubing, annulus or wellbore that hasbeen suitably tested.

- Any other pressure sealing mechanism installed for the purpose ofpreventing flow of fluids from a well.

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Revision: 0Chapter II Well Control Theory & Procedures.

Chapter II - WELL CONTROL THEORY & PROCEDURES

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II.1 PRIMARY CONTROL...............................................................................................................................15II.1.1 Well Control Theory..................................................................................15

II.1.1.1 Causes of Kicks ................................................................................15II.1.1.2 Warning Signs of Abnormally Increasing Formation Pressure.........17II.1.1.3 Shallow Gas......................................................................................20

II.1.2 Well Control Procedures ..........................................................................22II.1.2.1 Tripping.............................................................................................22II.1.2.2 Drilling ...............................................................................................26II.1.2.3 Top Hole Operations.........................................................................27

II.2 SECONDARY CONTROL ........................................................................................................................33II.2.1 Shut In Procedures...................................................................................33

II.2.1.1 Surface BOPs - While Tripping.........................................................33II.2.1.2 Surface BOPs - While Drilling...........................................................34II.2.1.3 Subsea BOPs - While Tripping.........................................................34II.2.1.4 Subsea BOPs - While Drilling...........................................................35II.2.1.5 Surface and Subsea BOPs - While Out Of Hole ..............................35

II.2.2 Diverters ...................................................................................................35II.2.2.1 Diverter Procedures While Drilling For Land Rigs, Swamp Barges, Tenders, Jack-Ups..................................................36II.2.2.2 Diverter Procedures While Drilling For Floating Units ......................36II.2.2.3 Diverter Procedures While Tripping With Surface BOPs .................38II.2.2.4 Diverter Procedures While Tripping For Floating Units ....................39

II.2.3 Well Control Methods ...............................................................................39II.2.3.1 Wait & Weight:..................................................................................40II.2.3.2 Driller's ..............................................................................................44II.2.3.3 Static Volumetric...............................................................................46

II.2.4 Pre-Recorded Information ........................................................................48II.2.4.1 Slow Circulating Rates......................................................................49II.2.4.2 Maximum Allowable Annular Surface Pressure (MAASP) ...............49II.2.4.3 Leak-off Tests...................................................................................50II.2.4.4 Kick Tolerance..................................................................................51

II.2.5 Kicks Off Bottom.......................................................................................51II.2.5.1 Stripping To Bottom ..........................................................................53II.2.5.2 Off Bottom Kill...................................................................................56II.2.5.3 String Out of Hole .............................................................................57

II.2.6 Crew Positions During Well Kick Control Operations...............................58II.2.6.1 Driller.................................................................................................58II.2.6.2 Rig Superintendent ...........................................................................59II.2.6.3 Derrickman/Assistant Driller .............................................................59II.2.6.4 Roughnecks......................................................................................59II.2.6.5 Electrician/Mechanic.........................................................................59II.2.6.6 Company Representative .................................................................59II.2.6.7 Mud Engineer....................................................................................59II.2.6.8 Additional Personnel on Offshore Units............................................60

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II.1 PRIMARY CONTROL

Primary well control is the use of drilling fluid density to provide sufficientpressure to prevent the influx of formation fluid into the wellbore.

It is of the utmost importance to ensure that primary well control ismaintained at all times. This involves the following:

- Drilling fluids of adequate density are used.

- Well is kept full of adequate density fluid at all times.

- Active volumes are continuously monitored, especially during tripping.

- Changes in density, volumes and flow rate of drilling fluids from thewellbore are immediately detected and appropriate action taken.

II.1.1 Well Control Theory

II.1.1.1 Causes of Kicks

There are 5 major causes for the loss of primary well control.

Failure To Fill The Hole Properly While Tripping

As the drillstring is pulled from the hole, the mud level drops due to thevolume of pipe being removed. As the mud level drops the hydrostaticpressure may be reduced enough to lose primary well control allowingformation fluids to enter the wellbore.

Swabbing

The hydrostatic pressure in the wellbore will always be reduced to someextent when the drillstring or full gauge tools are being pulled from thehole. The reduction in hydrostatic pressure should not be such that primarycontrol is lost.

Swabbing is caused by one or more of the following:

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- High pulling speeds.- Mud properties with high viscosity and high gels.- Tight annulus BHA-hole clearance, or restricted annulus clearance

Lost Circulation

When lost circulation occurs, the drilling fluid level will drop and areduction in hydrostatic pressure in the wellbore may cause the loss ofprimary well control. Loss of circulation may result from one or more of thefollowing:

- Cavernous or vugular formations.- Naturally fractured, pressure depleted or sub-normally pressured

zones.- Fractures induced by excessive pipe running speeds.- A restricted annulus due to balling of BHA or sloughing shales- Excessively high annular friction losses.- Excessive pressures caused by breaking circulation when

mud gel strength is high.- Mechanical failure (casing, riser, etc.)

Insufficient Mud Weight

When the hydrostatic pressure due to drilling fluid density is less thanformation pressure of a permeable zone, formation fluids will enter thewellbore. This may occur due to the following:

- Drilling into an abnormal pressure zone.- Dilution of the drilling fluid.- Reduction in drilling fluid density due to influx of formation fluids,

in particular gas.- Settling of weighted material.- Failure to displace riser to kill mud after circulating out a kick.- Pumping long column of low weight spacer while cementing.- After cementing while WOC. Cement losses hydrostatic pressure

as is starts to set.

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Loss Of Riser Drilling Fluid Column

On floating unit operations, the loss of the drilling fluid column in the risermay result in a reduction of hydrostatic pressure in the wellbore and maycause the loss of primary well control. This loss of riser hydrostatic columncould be due to:

- Accidental disconnect.- Riser damage.- Displacement of riser with seawater.

II.1.1.2 Warning Signs of Abnormally Increasing Formation Pressure

The detection of abnormal pore pressure increase is an essential step inmaintaining control of a well and preventing a kick. There is no one rulethat will pinpoint abnormally pressured zones but many of the followingindicators appear before the formation pressure becomes high enough tocause a kick.

Increase In Drilling Rate

While drilling normally pressured shales, and assuming a fairly constant bitweight, RPM, mud weight and hydraulics program, a normal decrease inpenetration rate can be expected. When abnormal pressure isencountered, differential pressure and shale density are decreasedcausing a gradual increase in penetration rate.

Trip, Connection and Background Gas

An increase in trip and/or connection gas should be considered as anindicator that pore pressure is increasing. Increased trip and connectiongas can be caused by increased swab pressure or increases in porepressure. When consistent procedures are followed for making connectionsand tripping, increases in trip and connection gas are fairly reliable inindicating pore pressure increases.

Gas readings are reported in "gas units" or percentages. These readingsare qualitative and only indicate the relative gas concentration in themud. These vary greatly from one mud logging instrument to another.

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Therefore, absolute values of gas readings have very little value indetecting abnormal pressures.

Increases in background gas are not very reliable in detecting porepressure increases. This is because gas concentrations can changedrastically in the formation being drilled without any increase in porepressure.

Increase In Torque and Drag

Increases in torque and drag often occur when drilling underbalancedthrough some shale intervals. This condition can be caused by "heaving" or"sloughing" shales. This results in a buildup of cuttings in the annulus andexcessive fill on connections and trips. This may be a sign that porepressure is increasing. Taken alone, increase in torque and drag is notalways a reliable indicator since it may be caused by hydratable shales,change of formation, worn out bit, deviated hole, etc.

Change In D-Exponent

In 1966, Jordan and Shirley developed a normalized penetration ratecalculation from data gathered in the Gulf of Mexico. In their relationship,the normalized drilling rate was defined as a function of measured drillingrate, bit weight and size, and rotary speed in the equation shown below:

d = log (R/60N)log (12W/106D)

R = rate of penetration, ft/hr. N = rotary speed, rpm.W = weight on bit, Lbs. D = bit size, ins. d = d - exponent

Because "d" is an indication of drillability, a plot of "d" versus depth in shalesections, has been used with moderate success in predicting abnormalpressure. Trends of d-exponent normally increase with depth, but intransition zones, values of "d" decrease to lower than expected values.Since the d-exponent tends to indicate the difference between formationpressure and wellbore pressure, changing the mud weight will affect the d-exponent. The original calculation should be corrected as follows:

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dc = d(MW 1 /MW 2)dc = d-exponent modified for mud weightMW 1 = previous mud weightMW 2 = current mud weight

Since the advent of the d-exponent and corrected d-exponent, variousindividuals have proposed other calculations in an attempt to improveabnormal pressure detection techniques. It should be remembered thatthe d-exponent was developed primarily for use in shale type formations.

Change in Cutting Size and Shape

Cuttings from normally pressured shales are small with rounded edges andare generally flat, while cuttings from abnormally pressured shales oftenbecome long and splintery with angular edges. As differential between thepore pressure and bottom hole pressure is reduced, the cuttings have atendency to "explode" off bottom. In addition, because of a reduction indifferential pressure, fluid in the shale can expand causing cracking andsloughing of the shales into the wellbore. A change in cutting shape willoccur along with an increase in the amount of cuttings recovered at thesurface and this should indicate that abnormal pressure has beenencountered.

Chloride Trends

The chloride content of the mud filtrate can be monitored both going intoand coming out of the hole. A comparison of chloride trends can providea warning or confirmation signal of increasing pore pressures.

An alternative to measuring chloride content of the filtrate is continuousmeasurement of the mud resistivity both in and out of the hole. Mudadditives and makeup water can affect resistivity and chloridemeasurements.

Decrease In Shale Density

Shale density normally increases with depth but it decreases as abnormalpressure zones are drilled. The density of the cuttings can be determined

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at surface and plotted versus depth. A normal trend line is established andany deviation should, in theory, indicate changes in pore pressure.

Temperature Measurements

The continuous measurement of the mud temperature at the flow line maygive an indication of change in temperature gradient, which is associatedwith penetrating an abnormally pressured formation. The temperaturegradient in abnormally pressured formations is generally higher thannormal. This temperature gradient increase occurs before penetrating theinterface and, therefore, can give an early indication of abnormalpressures.

The limitation of this method is that the mud temperature can only bemeasured on the surface and, therefore, is subject to external influences.

It is important to note that when these indicators are examined on anindividual basis they may not suggest that abnormally high formationpressures have been encountered. But when these indicators are groupedtogether, they can be a valuable tool. It is imprudent to rely on oneindicator only.

II.1.1.3 Shallow Gas

a) Shallow Gas Definition

Shallow gas is considered to be any gas accumulation encounteredduring drilling at a depth above the setting point of the first casing stringintended for or capable of pressure containment. In such instances, it maybe decided either to shut the well in or divert because well shut inpressures combined with hydrostatic head of the well fluid could result information breakdown and possibly subsequent cratering of the well.

Drillers will be instructed in writing on what action to take in such cases(refer to section I.10).

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b) Shallow Gas Phenomenon and Precautions

Shallow gas normally occurs as accumulations in shallow sedimentaryformations with a high porosity and high permeability, which could belightly overpressured relative to the normal formation gradient butgenerally are considered to be at very low pressure. Drilling through such agas bearing formation requires extreme caution. Because of difficulty inearly detection of gas influx while drilling top hole sections and the shallownature of the hole, the gas, upon entering the well bore, expands andreaches the surface rapidly with little warning.

Preventive measures are necessary in planning drilling operations wherepotential risk of shallow gas is anticipated. Where possible, the drillinglocation must be selected to avoid/limit such hazards. This could beaccomplished through using good quality shallow gas evaluation andinterpretation techniques. Even with careful site selection, a shallow gaskick may still occur and should never be ruled out entirely. Guidelines forspecific top hole drilling operations and sound practices in maintainingprimary well control must be strictly followed at all times in order to preventshallow gas incidents.

Special care should be exercised while planning and conducting top holedrilling operations. Precaution and procedures aimed at limiting the risk ofshallow gas, at improving our ability to detect and control it and atensuring appropriate response to a shallow gas event must be clearlyestablished before drilling and strictly adhered to during the operations.These precautions and procedures will vary according to the assumed riskof shallow gas. It is therefore important to ensure that a thoroughevaluation of the risk, using the best available means, has been carriedout. All well programs should include a statement relative to the evaluationof shallow gas risk. If there is no such statement in your program, youshould request it from your client. If such statement is not obtained in time,you should assume that the risk of such occurrence is high and the DistrictManager must consult the Field Support Manager for advice.

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II.1.2 Well Control Procedures

II.1.2.1 Tripping

Worldwide, a majority of kicks are taken while pulling the drillstring from thewellbore. This is a problem that can be avoided if the crew is well trainedand if proper procedures are followed. It is important that the driller knowsthe reason for tripping out of the hole and that he keeps the properdocumentation. A crew will maintain good tripping habits if they are wellprepared.

The following preparations for a trip will be taken:

Check Hole Conditions

Before starting out of the hole with drillpipe, the mud shall be in goodcondition. Proper conditioning requires either a bottoms-up circulationand/or the following criteria must be met:

- No losses of circulation (unless authorized by the District Manager; see I.9).

- No indication of influx of formation fluids present prior to pulling pipe.

- The mud density in and out of the well will not differ more than, 24 kg/m3 (0.2 ppg).

Trip Tank

The Trip Tank will be filled up with adequate weight fluid and functiontested prior to removing the kelly or top drive.

Trip Sheet

A trip sheet will be prepared for use while tripping.

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Safety Valve

Suitable safety valves with appropriate connections of crossover subs to fitall drillpipe and B.H.A. connections must be on the rig floor, in the 'open'position ready for use with proper fittings and handling devices. Theclosing/opening wrench must be readily available for immediate use.

Slugs

When possible, and after a flow check confirming the well is static, a slugwill be prepared and displaced in the drillstring prior to pulling out of hole.

Mud Bucket

A mud bucket should be readied if a slug cannot be pumped or if pipemust be pulled wet. Design should be arranged so that returns from themud bucket drain to the trip tank.

It is important to ensure that the hole takes the proper amount of fluidduring a trip. The trip tank should be used to keep track of fluid volumes.

The following procedures for pulling pipe out of hole will be taken:

Trip Tank

By using the trip tank, circulation can be maintained across the bell nipplewhile monitoring volumes.

A trip sheet will be filled out on each trip.

In the case of trip tank failure, an alternative will be to use a mud pumpwhile pulling pipe. In this case, the annulus will be filled with mud beforethe change in mud level decreases the hydrostatic pressure by 500 kPa (75psi) or every 5 stands of pipe, whichever gives a lower decrease inhydrostatic pressure. Volumes will be monitored by isolating the suctiontank and closely monitoring fluid volumes. A man will be assigned towatch the flow line to signal when the hole is full. Such an alternativeshould be limited to sections of hole not showing any drag or overpull. A

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periodic visual check into the annulus should ensure the drilling fluid levelis dropping normally while pulling pipe.

Proper Hole Fill

If the hole is not taking the proper amount of fluid, it is important to stoptripping and:

- Flow check.- Inform man-in-charge.

In most cases, the pipe should be returned to bottom.

Flow checks

A flow check is the observation of the well without circulation. Flowchecks are made to determine if the well is, or is not flowing. The durationof a flow check may be specified by the Rig Superintendent but, in anycase, must be whatever time necessary to determine without questionwhether the well is static or flowing.

When tripping, flow checks will be taken as follows:- Just off bottom.- At the lowest casing shoe.- Prior to pulling drill collars through the BOP stack.

Pulling Speed

Every effort should be made to pull pipe at a rate that is slow enough toprevent swabbing.

Trip Interruptions

Any time a trip is interrupted, the hand tight installation of a safety valve isrequired.

Refilling Trip Tank

Whenever the trip tank is refilled, it is important to stop pipe movement.

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Pipe Wiper

If the hole is taking the proper amount of fluid and if there is no drag oroverpull which could generate swabbing, then the pipe wiper will beinstalled after pulling the first 5 stands or after the bit is pulled into casedhole.

The following procedures when PIPE IS OUT OF HOLE will be taken:

The trip tank will be used to ensure that the hole is remaining static. It willbe used to circulate across the bell nipple.

The following procedures when RUNNING PIPE INTO THE HOLE will be taken:

Trip Tank

Just as it is important to monitor hole condition when pulling pipe, it is alsoimportant to check conditions while returning to bottom. The trip tankshould be monitored while tripping into the hole. The Driller should beaware that trip tank level indication will be affected by the size of thenozzles in the bit.

Breaking Circulation

In order to reduce possibilities of high surge pressures, consideration shouldbe given when the shoe is 2,100 meters (7,000 ft) or deeper to breakcirculation prior to entering open hole.

Filling Drillpipe

With a solid float in the string, drillpipe will be filled every 10 to 15 stands.With the BHA in open hole, reciprocating is recommended to avoidsticking problems. The string should be filled from the trip tank to ensureaccurate trip records can be kept.

Bottoms-Up Circulation

Between returning to bottom and circulating bottoms up, drilling fluids willnot be transferred from reserve to the active system without isolation of

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pits. Volumes of the active system and transfer pit will be known and priorto commencement of the operation, mud logging and rig floor monitorswill be set and manned.

II.1.2.2 Drilling

The following indicators of potential formation fluid influx into the wellboreshould be flow checked:

Drilling Break

Drilling breaks will be flow checked.

Increase in Return Flow

The differential flow indicator should offer visual and audible alarms andshould be set to warn the Driller of changes in flow rate.

Pit Level Increase

An increase in pit level can be an indicator that an influx of formation fluidhas occurred. It is important that the Driller maintain good communicationwith his crew so that transfer and/or addition of mud materials can betaken into account.

Pump Pressure Decrease/Pump Stroke Increase

When an influx enters the wellbore, the fluid column in the annulusbecomes lighter. The mud in the drillpipe begins to "U-Tube" and the Drillermay observe a pressure drop which may or may not be accompanied byan increase in pump strokes.

This particular warning sign may not mean there is a kick in the wellbore. Itmay be an indication of pump problems, washout in the string, washednozzles, etc. It is a good idea to flow check when a pump pressuredecrease is detected by the Driller.Where MWD tools offer information regarding BHP, these should be utilized

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II.1.2.3 Top Hole Operations

Before Drilling Operations

Prior to starting of drilling operations, the Rig Manager must discuss with theoperator the assessment of the shallow gas risk. It is imperative that thewell design and specific operating procedures be reviewed in the light ofthis assessment.

Wells with an increased risk of encountering shallow gas are summarizedas follows:

- Exploration wells in general.- Wells drilled in shallow gas prone areas.- Wells with probable /possible shallow gas identified by a preliminary

shallow gas investigation.- Wells drilled in developed fields where charged shallow sands could

occur due to poorly cemented casing strings.

II.1.2.3.1 Evaluation of Shallow Gas Risk

Shallow seismic survey:

- A shallow seismic survey is one of the best methods available todayand is often carried out offshore to identify possible shallow gasaccumulations. While the same principle would make this survey useful inplanning onshore operations it is not often used due to the cost anddifficulty of carrying out such surveys on land.

- The reliability of such a survey varies depending on the methods ofdata acquisition, processing and interpretation.

- The flow chart shown in Appendix 6 can be used as a guideline toevaluate if proper seismic equipment and techniques are employed by theoperator.

- It must be understood that the results of such a survey can beconsidered as a guide, but should in no case be considered as aguarantee.

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- Other techniques which could be used to evaluate shallow gasaccumulations are soil sampling, pre-spud pilot hole drilling as well asevaluation of any available offset well data.

A shallow gas survey is not commonly done onshore. However, it should begiven careful consideration in areas of probable shallow gas risk. In theabsence of such a survey, the assessment should be based on theexploration seismic data, historical well data and the geologicalprobability of a shallow gas trap.

II.1.2.3.2 Well Design Considerations

Drilling Site and Well Course Selection

When the survey indicates a possible shallow gas accumulation,consideration should be given to repositioning the location, if at allpossible, so as to avoid such hazards.

Casing seat Selection

A string of casing should be set and properly cemented in the firstformation that provides an impermeable seal, even if this requires anadditional or contingent string of casing.

On offshore rigs, such a string would provide the ability to shut-in a well atshallow depths without risk of broaching around the wellhead or mudline.

Pilot Hole

A pilot hole (normally 250.8 mm {9 7/8"} or less) can be drilled as it willimprove the capability of controlling a shallow gas kick with a dynamic killoperation (Ref. II.2.2). Caution should be taken while POOH due to thepossibility of swabbing

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Electric Wireline Logs/LWD/MWD

Information about the presence and depth of gas bearing zones can beobtained by logging or using MWD. Early detection of shallow gas wouldenable appropriate safe action to be taken.

Riserless Drilling (Floating Unit)

Riserless top hole drilling from floating rigs (with the exception of drillshipsmoored in shallow waters) is the Sedco Forex recommended method.

II.1.2.3.3 Operational Procedures

Written instruction (Ref. I.10)

Clear written instruction must be issued to the drillers by the man-in-charge, regarding the specific action to take in case of a kick whiledrilling the tophole section. This could involve either shutting in or divertingthe well. A copy of the procedure must be prominently posted near theBOP/diverter control panels.

Shallow gas plan

A shallow gas plan specific to the rig/well must be prepared in conjunctionwith the operator and shall conform to Sedco Forex Policy. Specialconsideration must be given to the following, non exclusive, list of items:

- Crew positions and their specific duties as listed in II.2.6 shall bereviewed.

- Training sessions and diverter drills must be designed around theprocedure outlined in II.2.2 and IV.3. Drills must be held by each crewat the beginning of each tour during this drilling phase to familiarize allpersonnel with the appropriate and immediate actions in case ofshallow gas kick. One of these drills, conducted prior to drilling, willinclude mustering crew and simulation of procedures necessary todisconnect/move off location (floating units only).

- Evacuation plan for all non-essential personnel must be prepared.- Emergency power shut down procedure must be prepared.

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- Disconnecting and/or moving off location procedures for floating unitsmust be prepared.

Heavy mud

A minimum of 50m3 (300 bbls) of heavy mud must be ready in the reservepit [mud weighting 240 kg/m3 (2 ppg) more than the active mud isnormally recommended]. However, caution must be exercised to ensurethat this mud weight is not excessive considering the strength of theexposed formation.

Restricted drilling rate

The penetration rate should be controlled to prevent excessive build up ofsolids which could cause fracturing or lost circulation. It is also necessary toprevent accumulation of gas in the annulus which could induce the wellto flow. Caution should be used while flushing cuttings from the annulusdue to the resulting reduction in annular hydrostatic fluid density.

Active mud system

The mud pit volume and mud density must be continuously monitored. Allmeasuring instruments must be calibrated and in good condition to detectany change in active volume. The most reliable indicator generallyremains the flow out sensor (Ref. II.2.2). If there is any inadequacy in themeasuring instrument, extra personnel should be assigned to ensureadequate monitoring of mud volumes.

Flow check

Flow check will be made every time a problem is suspected. Eachconnection will be systematically flow checked while drilling in potentialshallow gas zones.

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Mud losses

Losses should be avoided. If losses are encountered they should be curedbefore drilling ahead unless under known condition and with the approvalof the district manager. Large bit nozzles should be used to allow pumpingof LCM and to permit high flow rates should diverting be required.

Tripping

Proper tripping procedures must be strictly adhered to (Ref. II.1.2.1).Swabbing must be prevented while tripping out of hole. If necessary thedrillstring should be pumped out to help limit swabbing. It is recommendedto make this a standard procedure on rigs equipped with TDS.Consideration should be given to the use of an under reamer instead of ahole opener, as the former can be collapsed before tripping to reduceswabbing while pulling out of hole.

Float valve

A float valve must be run to prevent sudden flow up the drillstring (Ref.III.5.3).

Watertight Integrity (Floating Units)

All watertight doors and hatches must be kept closed at all times.

Windsock

At least one windsock must be installed in a predominant position visiblefrom the muster point.

Riserless Floating Unit Considerations

A gas blowout in open water produces a 10 degree cone of low densitywater and a discharge of highly flammable gas. The intensity of theblowout depends to a large extent on the water depth and current.Current further disperses and displaces the plume away from the rig. Withinthe plume of expanding gas, a floating vessel will suffer some loss ofstability; however, the effect on a semi submersible at operating draft

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would be negligible. The eruption of gas would tend to displace a vessel,and if constrained by its mooring, may cause a floating unit to heeltowards the plume, thereby reducing its freeboard further.

- The rig should be moored with the length of moorings remaining in thelocker to allow the rig to be moved 122 m (400 ft) away from the plumewithout power. If practical, the windlasses should be held on their brakesand the chain stoppers only applied after surface casing has been set.

Bottom Supported Unit Considerations

Shallow gas reservoirs are potentially much more hazardous whenpenetrated from a jack-up or platform. Because the conductor extendsalmost to the rig floor, the products of a kick are discharged almost directlyinto a hazardous zone. On a bottom-supported rig, a hazardous situation iscreated if a restriction forms in the diverter line. The subsequent build upmay cause gas to broach around the casing to the seabed. In this eventthere is a real risk that the seabed becomes fluidized, thus inducing asudden reduction in spudcan resistance.

- A means of diverting the flow away from hazardous zones, withoutrestricting flow or imposing back pressure on the well should beavailable for immediate activation.

- Monitor the sea for evidence of gas breaking through outside theconductor.

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II.2 SECONDARY CONTROL

Secondary Control is the proper use of blowout prevention equipment tocontrol the well in the event that primary control cannot be properlymaintained. Early recognition of warning signals and rapid shut-in are thekey to effective well control. By taking action quickly, the amount offormation fluid that enters the welIbore and the amount of drilling fluidexpelled from the annulus is minimized. The size and severity of a kickdepends upon:

- The degree of underbalance.- The formation permeability.- The length of time the well remains underbalanced.

Smaller kicks provide lower choke or annulus pressure both upon initialclosure and later when the kick is circulated to the choke.

II.2.1 Shut In Procedures

Choke and valve immediately upstream of chokes on the choke manifoldto be kept in the closed position.

Remote operated choke line valve (HCR) on surface BOPs or failsafevalves on subsea BOPs are to be kept in closed position.

Closing the valve downstream of the choke on the choke manifold,instead of the valve upstream, is allowable provided that this downstreamvalve is rated to the BOP full working pressure and equipped to allowopening under full working pressure. (See III.4.1.3 & III.4.2.3).

II.2.1.1 Surface BOPs - While Tripping

- Set slips below top tool joint. (No tool joint next to shear rams).- Install full opening safety valve and close same.- Close annular/Open remote control choke line valve (HCR).- Notify man in charge.- Make up kelly or top drive (insert a pup joint or single between safety

valve and top drive) and open safety valve.

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- Record annulus and drillpipe pressure and pit gain.

Examples of full opening safety valves are T.I.W., Hydril, S.M.F. but not Gray.

IF UNABLE TO SHUT-IN THE DRILLSTRING, CLOSE SHEAR RAMS OR DROPSTRING.

The preferred course of action after closing in on a kick while tripping willbe to return the pipe as close as possible to bottom. If it is decided to stripback in the hole, follow the procedure described in section II.2.5. Possibleexpansion of the influx volume due to migration and the effect of runningthe string into the influx are to be taken into account during strippingoperations.

II.2.1.2 Surface BOPs - While Drilling

- Stop rotation.- Raise string to shut in position (time permitting).- Stop the pumps and flow check; if well flows, proceed without delay

to next step.- Close annular/open remote controlled choke line valve (HCR).- Notify man in charge.- Check space out and close pipe rams and ram locks.- Bleed off pressure between pipe rams and annular (if possible).- Record annulus and drillpipe pressure and pit gain.

II.2.1.3 Subsea BOPs - While Tripping

- Set slips below top tool joint.- Install full opening safety valve and close same.- Close annular/open choke line failsafe valves.- Notify man in charge.- Make up kelly and open safety valve, or- Make up top drive (insert a pup joint or single between safety valve

and top drive) and open safety valve.- Record annulus and drillpipe pressure and pit gain.- Monitor riser for flow (for Deepwater wells, see section VI.2.3).

Examples of full opening safety valves are T.I.W., Hydril, S.M.F. but not Gray.

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IF UNABLE TO SHUT-IN THE DRILLSTRING, CLOSE SHEAR RAMS OR DROPSTRING.

The preferred course of action after closing in on a kick while tripping willbe to return the pipe as close as possible to bottom. If it is decided to stripback in the hole, follow the procedure described in section II.2.5. Possibleexpansion of the influx volume due to migration and the effect of runningthe string into the influx are to be taken into account during strippingoperations.

II.2.1.4 Subsea BOPs - While Drilling

- Stop rotation.- Raise string to hang off position (time permitting).- Stop the pumps and flow check; if well flows, proceed without delay

to next step.- Close annular/open choke line failsafe valves.- Notify man in charge.- Check space out and close hang off pipe rams.- Hang off, using drillstring compensator and close ram locks.- Bleed off pressure between pipe rams and annular.- Open annular.- Record annulus and drillpipe pressure and pit gain.- Monitor riser for flow (for Deepwater wells, see section VI.2.3).

II.2.1.5 Surface and Subsea BOPs - While Out Of Hole

- Close blind rams or blind/shear rams / Open remote operated valve.- Allow pressure to stabilize and record casing pressure and pit gain.- Monitor riser for flow (for Deepwater wells, see section VI.2.3).

II.2.2 Diverters

The presence of shallow gas can be extremely hazardous, especially if nospecific plan of action is prepared prior to spudding of the well. The Drillerwill be instructed in writing on what action to take if a well kicks whiledrilling surface hole; this may either be to divert or shut the well in. Theproblem of drilling shallow hole is that normal indications of a kick are notreliable; for example:- Penetration rates vary tremendously.

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- Mud volume is continuously being added to the active system.

The most reliable indicator is the differential flow sensor. Due to thedifficulties of early detection and the depth of shallow gas reservoirs,reaction time is minimal. Extreme caution and alertness are required.

II.2.2.1 Diverter Procedures While Drilling For Land Rigs, Swamp Barges, Tenders,Jack-Ups

At first sign of flow:

- DO NOT STOP PUMPING.- Open diverter line to divert/close diverter (both functions should be

interlocked; Ref. I.l9).- Increase pump strokes to maximum (do not exceed maximum pump

speed recommended by the manufacturer or maximum pressureallowed by relief valve).

- Switch suction on mud pumps to heavy mud (Ref. II.1.2.3) in thereserve pit. Zero stroke counter.

- Raise the alarm and announce the emergency using the PA systemand/or inform the rig superintendent. Post personnel to look for gas(Jack-up, swamp barges).

- If the well appears to have stopped flowing after the heavy mud has been displaced, stop pumps and observe well.

- If the well appears to continue to flow after the heavy mud has beenpumped, carry on pumping from the active system and preparewater in a pit for pumping and/or consider preparing a pit withheavier mud. When all mud has been consumed, switch pumps towater. Do not stop pumping for as long as the well continues to flow.

- II.2.2.2 Diverter Procedures While Drilling For Floating Units

Most diverting operations on floating units have been failures, some ofwhich have resulted in the loss of life and equipment. The biggest singleproblem preventing a successful procedure is the weakness of the slip jointpacker. In too many cases, the slip joint packer has leaked severely,exposing the rig to fire hazards.

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Therefore, all rigs with subsea stacks that have the capability of shuttingthe well in will do so when necessary according to the procedures alreadyoutlined.

Moving off location immediately if a kick occurs, may be an option to beconsidered.

Riserless top hole drilling from floating rigs (with the exception of drillshipsmoored in shallow waters) is the Sedco Forex recommended method. Pinconnectors will not be run as normal practice. However, if required bygovernmental regulations or if the operator insists on its use, the followingprocedure shall be used

- DO NOT STOP PUMPING.- Open diverter line (close shaker valve if applicable) and close

diverter (both functions must be interlocked).- Increase pump strokes to maximum (do not exceed maximum pump

speed recommended by manufacturer or maximum pressure allowedby pump relief valve).

- Disconnect pin connector.- Switch suction on mud pumps to heavy mud in the reserve pit. Zero

stroke counter.- Raise the alarm and announce the emergency using PA system

and/or inform the rig superintendent.- Post personnel to look for gas appearing at the water line.- If well appears to continue to flow after pumping heavy mud, carry on

pumping from the active system and prepare water for pumpingand/or consider preparing a pit with heavier mud. When all mud hasbeen consumed, switch pumps to water.

- Make preparation for moving off location.

If the pin connector is equipped with dump valves (this set-up is NOTrecommended), the procedure for diverter operations is as follows:

- DO NOT STOP PUMPING- Open diverter line, (close shaker valve if applicable) and close

diverter (all functions will be interlocked).

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- Increase pump strokes to maximum (do not exceed maximum pumpspeed recommended by the manufacturer or max. pressure allowedby pump relief valve.)

- Open dump valves.- Increase slip joint packer pressure.- Switch suction on mud pumps to heavy mud in the reserve pit. Zero

stroke counter.- Raise the alarm and announce the emergency using the PA system

and/or inform the rig superintendent.- Post personnel to look for gas appearing at the water line.- If well appears to continue to flow after pumping heavy mud, carry on

pumping from the active system and prepare water for pumpingand/or consider preparing pit with heavier mud. When all mud hasbeen consumed, switch pumps to water.

- Make preparation for disconnecting and moving off location.

NOTE: Rigs equipped with subsea diverter should prepare a specificprocedure and have same approved by the Field Support Manager.

II.2.2.3 Diverter Procedures While Tripping With Surface BOPs

- Set slips (below top tool joint for kelly drilling).- Open diverter line, close diverter (both functions will be interlocked)- Make up kelly or top drive.- Start pumping at maximum pump speed (do not exceed maximum

pump speed recommended by manufacturer or max. pressureallowed by pump relief valve).

- Switch suction on mud pumps to heavy mud in the reserve pit. Zerostroke counter.

- Raise the alarm and announce the emergency using the PA systemand/or inform the Rig Superintendent.

- If the well appears to have stopped flowing after the heavy mud has been displaced, stop pumping and observe the well.

- Prepare to run back to bottom.- if the well appears to continue to flow after the heavy mud has been

pumped, carry on pumping from the active system and prepare waterfor pumping and/or consider preparing pit with heavier mud. When allmud has been consumed, switch pumps to water. Do not stoppumping for as long as the well continues to flow.

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II.2.2.4 Diverter Procedures While Tripping For Floating Units

- Set slips (below top tool joint for kelly drilling).- Open diverter line, (close shaker line if applicable), close diverter

(both functions will be interlocked).- Disconnect pin connector or open dump valves and increase slip joint

packer pressure as applicable.- Make up kelly or top drive.- start pumping at maximum pump speed (do not exceed maximum

pump speed recommended by manufacturer or max. pressureallowed by pump relief valve).

- Switch suction on mud pumps to heavy mud in the reserve pit. Zerostroke counter.

- Raise the alarm and announce the emergency using the PA system,and/or inform the Rig Superintendent.

- Post personnel to look for gas appearing at the waterline.- If gas continues to bubble at surface after pumping heavy mud, carry

on pumping from the active system. When all mud has beenconsumed, switch pumps to water. Do not stop pumping for as long asthe well continues to flow.

- Make preparations for moving off location.

II.2.3 Well Control Methods

There are three basic methods of well control:- The Wait and Weight.- The Driller's.- The Volumetric (required in special situations).

NOTE: All methods aim at keeping bottom hole pressure constant andequal to formation pressure.

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II.2.3.1 Wait & Weight:

This method involves one circulation. Kill mud is prepared and is pumpedfrom surface to bit while following a prepared drillpipe pressure dropschedule. Once the kill mud enters the annulus, a constant drillpipepressure is maintained until the heavy mud returns to surface.

The procedure for the Wait and Weight method is as follows:

- After the well has been secured and pressures have stabilized,calculate the kill mud weight.

KMW (kg/l) = SIDPP (kg/cm2) x 10 ÷ TVD (m) + OMW (kg/l)

KMW (kg/ m3) = SIDPP (kPa) x 102 ÷ TVD (m) + OMW (kg/ m3)

KMW (ppg) = SIDPP (psi) ÷ 0.052 ÷ TVD (ft.) + OMW (ppg)

Trip margin will not be included in the calculation for kill mud weight. Themajor reason for this is to avoid any additional wellbore pressure that couldresult in formation breakdown.

- Calculate initial circulating pressure.

ICP = SCRP + SIDPP

- Calculate Final Circulating Pressure.

FCP = SCRP x KMWOMW

- Calculate surface to bit strokes.

Drillstring volume = StrokesPump Output

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- Calculate time to pump surface to bit.

Total strokes from surface to bit = TimeStrokes per minute

Once the preceding calculations are completed, plot pump pressureversus pump strokes and time on the drillpipe graph schedule.

- Plot initial circulating pressure at left of graph.- Plot final circulating pressure at right of graph.- Connect points with a straight line.

Use the formula:

ICP - FCP = pressure drop per increment 10

to calculate the pressure drop per increment and fill in the graph atbottom accordingly.

- For time, put "0" at the left of the graph and total time to bit on right.Divide total time by "10" to calculate minutes per increment.

- For strokes, put "0" at left of graph and total strokes to bit at right ofgraph. Divide total strokes to bit by "10" to calculate strokes perincrement.

Note: This method is exactly correct only if the ID is constant for the entiredrillstring. If a tapered string is used, or if the ID through the BHA is less, thismethod will not be exactly correct but will be adequate for almost allcases.

For example, if it takes 1,000 strokes to fill the drillstring with a kill rate of 40strokes per minute and an initial circulating pressure of 70 kg/cm2 (1000psi) with a final circulating pressure of 35 kg/cm2 (500 psi), then thepumping schedule would appear as follows:

A. Plot initial circ. pressure at left of graph.B. Plot final circ. pressure at right of graph.C. Connect points with a straight line.D. Across the spaces on bottom, write (A) Time: Surface to bit (B) Surface to bit

strokes and (C) Pressures.

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0

50

100

150

200

250

Initi

al C

irc. P

ress

ure

0

50

100

150

200

250

Fina

l Circ

. Pre

ssur

e

SIDPP

ICP

FCP

A. TIME 0 2.5 5 7.5 10 12.5 15 17.5 20 22.5 25

B. STKS 0 100 200 300 400 500 600 700 800 900 1000

C. PRESS 70 67 63 60 56 53 49 46 42 39 35

Once the kill sheet graph has been completed and the mud weight hasbeen raised to the desired value, prepare to circulate through choke.Open choke manifold valve upstream of choke (or downstream ifapplicable), zero stroke counters, ensure good communication betweenchoke operator, mud pump operator and personnel in pump room.

Bring the pump to kill rate speed while holding casing pressure constant.For subsea well control operations; reduce the casing pressure by anamount equal to the choke line friction (Ref. V.17.)

Once the pump is up to speed and the pressures have stabilized, recordthe actual circulating drillpipe pressure.

If the actual circulating pressure is equal to, or reasonably close to thecalculated ICP, continue pumping and adjust the stand pipe pressureaccording to the schedule.

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If the actual circulating pressure is significantly different from thecalculated ICP, stop the pump, shut the well in, and investigate thereason. Ensure there is no trapped pressure (Ref. V.18)

Any marginal difference between the actual and calculated initialcirculating pressure is most likely to be due to the fact that the SCRP usedto calculate the ICP was inaccurate. The actual SCRP, and hence thecorrected final circulating pressure, FCP, can be determined from theinitial circulating pressure as follows :

Actual SCRP = (actual initial circulating pressure) - SIDPPFCP = (actual SCRP) x KMW / OMW

The stand pipe pressure schedule can therefore be corrected to take intoaccount the adjusted circulating pressures.

When the kill mud enters the annulus, the choke operator then holdsdrillpipe pressure constant until the heavy mud returns to surface.

Any time the circulation is interrupted and the well shut in during the killoperation, it will be necessary to ensure that no pressure has beendynamically trapped and that the bottom hole pressure (BHP) is equal tothe formation pressure (Ref. V 18) before resuming the kill.

Once uncontaminated kill mud returns and the kill circulation is deemedcomplete, the well will be shut in and the DP and casing pressuresobserved.

If, as expected, no pressure is measured, the well will be flow checkedthrough chokes before opening the BOPs. On floating units, the riser will bedisplaced to the kill mud and, if necessary, gas trapped in the BOP will bebled off (Ref. V.15) before opening the BOPs.

If any pressure is found, the reason for it will have to be investigated andadditional steps decided as explained in section V.18.

To help in identifying the cause of potential problems, it is important tomaintain a good systematic record of time, pressures, volumes, etc. using

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page 2 of the kick report. Normally the driller or his assistant will beassigned this task.

- Advantages

In some circumstances, it generates the lowest pressure on the formationnear the casing seat. With a long open hole section, it is the least likelymethod to induce lost circulation.

Requires one less circulation than Drillers Method.

- Disadvantages

Requires longest waiting time prior to circulation. In a case where asignificant amount of hole is drilled prior to encountering the kick, thecuttings could settle out and plug the annulus.

Gas migration might become a problem while the density of the system isbeing increased. In which case the volumetric method described insection II.2.3.3 may be used to prevent excessive bottom hole pressureswhile the density of the system is being increased.

Sufficient barite necessary to increase mud weight may not be present on site.

II.2.3.2 Driller's

This is a two circulation method. During the first circulation, the drillpipepressure is maintained at a constant value until the influx is circulated fromthe wellbore. During the second circulation, kill mud weight is pumped tothe bit while following a drillpipe schedule. If all the kick fluid wassuccessfully circulated from the well in the first circulation, the casingpressure should remain constant. When the kill mud enters the annulus,final drillpipe circulating pressure is maintained constant until the kill mudreaches surface.

The exact procedure is as follows:

- Once the pressures have stabilized, bring the pumps to kill rate speedwhile holding the casing pressure constant (less choke line friction forsubsea BOPs).

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- When the kill rate speed is established, the choke operator shouldswitch to the drillpipe gauge and hold this pressure constant until theinflux is removed from the wellbore.

- The active mud system should be adjusted to the proper kill mudweight.

- Prepare a pumping schedule as was done with the Wait and Weightmethod using the indicated drillpipe pressure as ICP.

- Bring the pumps to kill rate speed with kill mud while holding thecasing pressure constant (less choke line friction for floating units).When the kill rate speed is established, switch to the drillpipe gaugeand follow the drillpipe schedule until heavy mud reaches the bit. Atthis point hold drillpipe pressure constant until heavy mud returns tosurface. Refer to Section II.2.3.1 if the drillpipe or casing pressures varysignificantly from the expected values.

- Advantages

Can start circulation right away if hole conditions warrant.Viable option if limited barite available.Less chance of gas migration.Pump pressure schedule is not absolutely required if all kick fluid wasremoved from the well in the first circulation and no additional kick wastaken. However, the driller must still know strokes to bit and stokes to shoeto know where the kill fluid is at all times.

- Disadvantages

Highest casing pressures for longest period.In certain situations, highest shoe pressure.One more circulation required than Wait & Weight

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II.2.3.3 Static Volumetric

(Note: For deepwater, the “Dynamic” method described insection VI.7.4.4 should be used)

If, for some reason, a gas kick cannot be circulated from the wellbore, gasmigration may occur resulting in high surface, casing shoe and bottomhole pressures. To minimize this, it will be necessary to allow the influx toexpand in a controlled fashion. With the volumetric method the bottomhole pressure is maintained slightly in excess of formation pressure whilethe gas is allowed to expand as it migrates to surface.

Drillpipe Communication

If pumping is not an option and gas migration is suspected due to a steadyincrease in drillpipe and annulus pressure, the drillpipe gauge should beutilized. The procedure would be as follows:

- Monitor the drillpipe gauge until it increases 700-1400 kPa (7-14kg/cm2, 100-200 psi) above initial shut-in pressure for an overbalancesafety factor.

- Maintain the new drillpipe pressure value constant by bleeding mudfrom the annulus until the influx reaches surface. If gas is bled from theannulus at this point without pumping mud in the well, the BHP willdrop below formation pressure and another influx will result.

No Drillpipe Communication

If the drillstring becomes plugged when on bottom, off bottom, or out ofthe hole and gas migration is apparent, the situation becomes morecomplicated. The procedure would be as follows:

- Monitor casing pressure allowing it to increase approximately 700 -1400 kPa (7-14 kg/cm2, 100-200 psi) above the original shut-in pressurefor an overbalance.

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- Calculate the hydrostatic pressure exerted by each liter (barrel) ofmud in the annulus. Calculate annulus capacity based on drillpipe ina gauge hole, or if no drillpipe use gauge hole.

Gmud in kg/cm2 or psiAnnular Volume m3 bbl

If pipe is out of the hole use the following calculation:

Gmud in kg/cm2 or psiHole Volume m3 bbl

Now, monitor the casing pressure while allowing it to increase anadditional 350-1050 kPa (3-10 kg/cm2, 50-150 psi). If gas is migrating, thecasing pressure will climb. Calculate the volume of mud in the annulus thatwould contribute a hydrostatic pressure equal to the selected casingpressure increase. This can be accomplished by using the followingformula:

Casing Pressure Increase = Vol. to bleed in Liters (or bbls) Hydrostatic pressure exerted by each Liter (or bbl) of mud

- Now hold the casing pressure constant until the amount of mud calculated is bled off into the trip tank or a calibrated tank. Keep a record of time, pressures and volumes bled.

- Repeat this sequence of allowing casing pressure increases and thenbleeding a calculated volume of mud as long as necessary, or untilgas reaches the surface.

Once the gas is at surface, stop the bleeding process. If gas is bled fromthe annulus at this point, the BHP will drop below formation pressure andanother influx will result. With gas at the surface, casing pressure may bereduced by lubrication as follows:

- Slowly pump a selected volume of mud into the annulus.

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- Allow the mud to fall through the gas. A small pressure increase mayoccur due to the gas being compressed by the mud being pumpedin.

- Bleed gas only from the wellbore allowing casing pressure to fall anamount equal to the hydrostatic pressure of the mud pumped into thewelIbore. If the annulus pressure increases during the pumping-inprocedure, the amount of this increase should be bled off in additionto the pressure bled for the hydrostatic pressure increase. If mud startscoming back, shut the choke and wait for the gas to work up to thesurface before continuing to bleed.

- Repeat until all the gas has been bled off or the desired surface pressure is reached.

- Advantages

Can be used to attempt to keep a constant bottom hole pressure if crew isunable to pump down drillstring, if drillpipe is plugged or if the drillstring isout of hole and gas is migrating.

- Disadvantages

The hole volume necessary in the calculation is not known with greataccuracy.

II.2.4 Pre-Recorded Information

The following information will be pre-recorded on the SEDCO FOREX killsheet and will be updated.

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II.2.4.1 Slow Circulating Rates

Wells will be killed using slow circulating rates for the following reasons:- To allow for a smooth weight-up and degassing of mud.- To maintain pressures at a minimum.

Slow circulation rates will be taken:

- As practical at the beginning of every tour.- Any time the mud properties are changed.- Any time the bit nozzle configuration is changed.- As soon as possible after bottoms up from any trip.

II.2.4.2 Maximum Allowable Annular Surface Pressure (MAASP)

Maximum Allowable Annular Surface Pressure is defined as the surfacepressure which, when added to the hydrostatic pressure of the existingmud column, would result in formation breakdown at the weakest point inthe well. This value is normally based on leak-off test data, with theassumption the area below the last casing shoe is the weakest point in thewell. This assumption should be reconsidered if loss or weaker zones areencountered in subsequent drilling.

During well control operations, it is most important that the position of theinflux, in relation to the last casing shoe, be monitored.

If the influx is below the last casing shoe and the surface casing pressureapproaches the MAASP then one of the following options should beselected:

l) Reduce the circulation rate to lowest possible. Adjust correspondingdrillpipe pressure.

2) Continue with kill procedures and exceed MAASP thereby riskingformation breakdown.

3) Allow the surface casing pressure to increase above the MAASP insuccessive steps while monitoring mud returns for signs of gas or losses.

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4) Continue with kill procedures, but open the choke as needed tomaintain casing pressure equal to MAASP thereby risking additionalinflux.

5) Bullhead the influx back into the formation.

6) Use tertiary control method (barite/cement plug).

The choice between the above methods depends on data availablepertaining to the kicking formation permeability and shoe or open holeweak point ultimate strength. Unless there is a strong indication of lowpermeability for the kick zone, preference will be given to exceeding theMAASP.

Once the influx has passed above the casing shoe, the MAASP basedupon the leak-off test data is no longer relevant. In this case, the MAASPwill be based upon the pressure ratings of the following:

l) Innermost casing string.2) Well head equipment.3) BOP and related surface equipment.4) Other equipment exposed to burst or collapse pressure.

It is most important during well control operations to monitor the position ofthe influx so that the MAASP figure can be correctly determined andutilized.

The driller will be instructed in writing on what action needs to be taken ifthe casing pressure reaches or exceeds the MAASP immediately afterinitial shut in.

Automatic MAASP control devices should not be used; it is recommendedto disable them where they exist.

II.2.4.3 Leak-off Tests

A leak-off test determines the pressure at which the formation begins totake fluid. This test must be conducted upon drilling out about 3 meters (10ft) of new hole below the shoe of any casing intended for pressurecontainment.

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Such a test will establish the strength of the formation at the shoe or theintegrity of the cement job at the shoe.

For long open hole sections, the original leak-off test will not necessarilydetermine the weakest point in the wellbore. In the event that a weakerformation has apparently been drilled, another leak-off test should betaken.

II.2.4.4 Kick Tolerance

Kick tolerance is the maximum kick that can be controlled withoutbreaking down the formation. This is normally expressed in equivalent mudweight. The calculation for kick tolerance includes an assumption on thevolume of influx. This volume depends on many factors, but principally,accuracy and response of pit level sensors, drill crew alertness, andreservoir conditions. In practice the volume can vary considerably.

When the kick tolerance calculation is equivalent to 60 kg/m3 (0.5 ppg) orless, the value of the kick tolerance will be brought to the attention of theoperator. For the purpose of this calculation, the assumption of an influxvolume of 4 m3 (25 bbls) is recommended unless specific informationabout the formation permeability suggests otherwise.

II.2.5 Kicks Off Bottom

When the drillstring is partially or completely out of the hole and a kick isexperienced, every effort should be made to safely return the bit tobottom whilst at the same time maintaining well control. The well can bemost effectively killed with the bit on bottom.

For both surface and subsea stacks, the recommended procedure is toinstall or pump an inside BOP and strip through the annular preventer usingthe combined stripping and volumetric method until the bit is returned tobottom or further stripping becomes impossible. This must be donesmoothly and efficiently. It requires knowledge of equipment andprocedures used by all crews; occasional practice drills are thereforerecommended (refer to section IV).

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Important points to note when stripping are as follows:

1) Install an inside BOP above the full opening safety valve or pump adrop in check valve. Open the full opening safety valve prior tostripping and make sure the inside BOP is not leaking.

2) Have an additional full opening safety valve available on the rig floorduring stripping operations.

3) Remove all drillpipe/casing protectors.

4) Lubricate the string with grease and/or pour oil on top of the annular.Ensure the tool joints are smooth.

5) Apply the lowest practical closing pressure to the annular preventerwhilst avoiding leakage. Watch the flow line for any leakage. Anyreturns are to go back into the trip tank.

6) Accurately measure and record mud volumes bled-off using the triptank. If available, a separate stripping tank should be used.

7) Keep the string full. The string should be filled from the trip tank.Measure and record mud volumes used to fill the string.

8) Monitor the marine riser of a subsea BOP stack for gains and take theeffect of heave and tidal changes into account when stripping.

9) Plot the casing pressures vs. stands run on graph paper and check forsignificant change of slope in order to try to identify when the stringhas entered the influx or when the influx has entered the choke line ofa subsea BOP stack.

10) The packing element of an annular preventer must be allowed tobreath slightly when a tool joint passes through. The pressure regulatorvalve of the BOP control unit should be set to provide and maintainthe proper control pressure. Recommended BOP closing pressures canbe obtained from the manufacturer's BOP operating manuals. Ifinstalled, a surge bottle connected to the closing line of the annularpreventer will improve effective BOP control during stripping tool jointsthrough the annular preventer; adjust its precharge to the required

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value before starting the stripping operation. Stripping tool joints atslow speeds reduces surge pressures and prolongs the packing unitlife. Stripping speeds should not exceed 0.6 m/sec (2 ft/sec). It is alsorecommended to vent the opening chamber control line of theannular preventer (Cameron D-type) to improve stripping tool jointsthrough the preventer.

It is important that the correct procedures to be used are implemented assoon as possible in case of a kick whilst tripping. A "stripping checklist"should be available on each rig to assist supervisors before and during thiswell control operation.Procedures concerning the combined stripping and volumetric methodare discussed for the following conditions:

-Stripping through annular preventer-Stripping through ram preventer

II.2.5.1 Stripping To Bottom

Stripping Through Annular Preventers

1) After closing in the well, record SICP and determine the volume of theinflux.

2) Whilst preparing for stripping, allow the closed-in annulus pressure to build-up to Pchoke, where:

Pchoke = SICP + Psaf + Pstep

SICP = initial shut-in casing pressure.

Psaf = allowance for loss of hydrostatic pressure as the influx risesfrom below the bit to around the DC's calculated as below:

Psaf = {Vinf/CapOH/DC - Vinf/CapOH} x {Gmud - Ginf} kPa (psi)

Vinf = initial Volume of the influx (Pit Gain) m3 (bbl)

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CapOH/DC= open hole/DCs annular capacity m3/m (bbl/ft)

CapOH = open hole capacity m3/m (bbl/ft)

Gmud = mud gradient kPa/m (psi/ft)

Ginf = estimated influx gradient kPa/m (psi/ft)

Pstep = working pressure increment kPa (psi)

Convenient values of Pstep are between 350-700 kPa (50-100 psi),bearing in mind the scale divisions of available pressure gauges.

3) Commence stripping. Allow the choke pressure to build up to:

Pchoke = SICP + Psaf + Pstep without bleeding off any mud.

4) Once the required choke pressure is reached, Pchoke is kept constantwhilst drillpipe is stripped in the hole. Excess pressure is bled off via thechoke manifold into the trip tank, if available. If the influx is entirelyliquid (water for example), the volume of mud bled should be equalto the closed-end displacement of the stripped-in drillpipe. If the influxis all or in part gas, the volume of mud bled should be greater thanthe closed-end displacement of the stripped-in drillpipe because ofthe gas expansion due to the gas migration. This will result in somehydrostatic pressure loss that must be compensated for by using thefollowing procedure:

5) Continue stripping in maintaining Pchoke until the total volume drainedto the trip tank exceeds the closed-end displacement of the stripped-in drillpipe by an amount Vstep calculated as below:

Vstep = Pstep x CapOH/DC / Gmud m3 (bbl)

Note: Depending on rig design and equipment set-up, instead ofbleeding off mud and gas via the mud-gas separator into the triptank, it can also be bled off into an auxiliary calibrated tank (in that

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case, the closed-end pipe displacement volume of each stand isdrained into the trip tank and the excess volume is measured in theauxiliary tank) or the return is taken in the trip tank and the closed enddisplacement of a stand of drillpipe is bled into the auxiliary tank aftereach stand has been stripped in and the excess volume is measuredin the trip tank.

6) Once the measured excess volume equals Vstep, the choke is closedand the choke manifold pressure is allowed to rise by Pstep by meansof stripping drillpipe in the hole. The closed-end pipe displacementvolume should not be bled off during this phase of the operation.

It is recommended to strip the complete stand in the hole for eachphase of the operation (e.g. whilst maintaining Pchoke constant, orwhen increasing Pchoke by Pstep) to simplify the bleeding off processand to improve the accuracy of differential volume measurementswhich directly results in improved bottom hole pressure control. As aresult of stripping the complete stand, higher than required chokepressures will occasionally be obtained which should be taken intoaccount when the next pressure increment is added. Safety factors toobtain sufficient overbalance, in particular when the drillstring entersthe influx are incorporated in this killing method.

7) Steps 5 and 6 are repeated as often as necessary, until one of thefollowing situations arises:

- The bit is back on bottom.- Gas has reached surface.- Stripping is no longer possible (excessive pressures, BOP stack

problems, open hole resistance, etc.).

Stripping is then stopped and the well killed conventionally, if the influx isabove the bit.

The chance of having to kill the well with the bit off bottom is relativelysmall, since the migration rate of gas in mud is such that the bit can bestripped back to bottom before gas has reached surface. Migration rates

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of gas in workover fluids are much higher and should be taken intoconsideration before deciding to start stripping pipe in the hole.

When the bit is back on bottom or below the influx, the well can be killedconventionally using the Driller's Method:

Stripping Through Ram Preventers

- Stripping through ram preventers will only be permitted with surface stacks.

- Stripping ram to ram will not be allowed if only two ram preventers areavailable for use.

- As in all stripping operations, the location of the tool joint in thepreventer stack must be known at all times.

To prevent premature damage to the ram preventers, the closingoperating pressure should be reduced to a minimum. When a tool jointreaches the lower set of closed rams, the upper set must be closed. Thepressure between the rams is then brought up to the current well pressureand the lower rams are opened allowing a tool joint to pass. When thenext tool joint approaches the upper rams, the lower set of pipe rams areclosed and the pressure between the two sets of rams is bled off and theupper rams are opened allowing a tool joint to pass. This process isrepeated alternating stripping through one ram then the other until thepipe reaches bottom or until the bit enters the influx.

II.2.5.2 Off Bottom Kill

This method involves circulation at the point of shut-in. The bit will not be atbottom and the kill operation will be more complicated. An off bottom killmight be considered if:

- Casing pressure is too high to allow stripping.- Heave becomes a problem.- Pipe is stuck.- Equipment problems arise.

The further off bottom and the weaker the casing seat, the more difficultthis method becomes.

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If the casing seat is strong enough, it might be possible to kill the well byweighting up the system and pumping heavy mud. The density of the mudused should not exceed the Equivalent Mud Weight (EMW) based on leakoff data if the bit is in open hole. Because the bit is at a shallower depthrelative to T.D., we will be "over killing" the well. The chances of becomingstuck are considerable. Also, weighting up the system will not prevent gasmigration.

If the well can be stabilized and the influx evacuated with this method, itwill be necessary, once the well is opened up, to run into the hole instages.

II.2.5.3 String Out of Hole

If the string is out of the hole when an influx is detected and the closed-insurface pressure allows safe lowering the first stands of DCs or drillpipe intothe well, the MIC may decide to start stripping since it will improve the wellcontrol situation. The kelly or top drive may have to be used in conjunctionwith singles for extra weight. DC's used should be slick.

The maximum surface pressure that can be overcome by the weight of thefirst stand, ignoring the friction between the annular preventer and thestring, is calculated as follows:

max. surface pressure = weight of first stand in mud cross-sectional area of the stand

The procedure to enter the string back into the well is as follows:

1) Install an inside BOP (Gray valve or preferably, float valve) on the firststand of slick DC's or drillpipe. Use a bit without nozzles to reduce thechance of plugged nozzles.

2) Lower the stand to just above the blind/shear rams and close theannular preventer.

3) Open the blind/shear rams and strip through the annular preventer.Allow the choke pressure to increase by Pstep and maintain constantthereafter.

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4) Fill the string with mud.

5) If DCs are used instead of drillpipe, continue stripping the slick BHAand maintain a constant choke pressure. Do not use more than threestands of DCs.

6) Allow the choke pressure to increase to SICP + Psaf + Pstep withoutbleeding off any mud when stripping the first stands of drillpipe.

7) Continue the combined stripping and volumetric method asdescribed in the previous section.

If it is not possible to strip the string into the well, the volumetric method orbullheading may have to be employed.

Note: Re-entering a closed-in subsea well with a drillstring on a floatingunit may be difficult because of the heave and the distance to thesubsea BOP stack. The heave should not exceed the distancebetween blind/shear rams and annular preventer. In order toavoid buckling of drillpipe in the marine riser, DC weight should beused to get the string back into the hole.

II.2.6 Crew Positions During Well Kick Control Operations

II.2.6.1 Driller

The Driller is the main line of defense when a kick occurs. It is hisresponsibility to:

- Close the well in.- Call man in charge.- On floating rigs, call the Subsea Engineer to the drill floor.- Regularly monitor and record time, pressures, volumes etc. during the

kill operations using page 2 of the kick report form 384 (Ref. Appx. 3).- Remain at the drilling console in order to run the rig pumps during the

kill procedure.

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Revision:0Chapter II Well Control Theory & Procedures.

II.2.6.2 Rig Superintendent

The Rig Superintendent is the SEDCO FOREX man in charge of the killoperation. It is his responsibility to ensure that the crew is organized andprepared to kill the well. He will consult with the Company Representativewhenever possible. The Rig Superintendent or his designee will operate thechoke during well kill operations.

II.2.6.3 Derrickman/Assistant Driller

- The Derrickman/Asst. Driller is to go to the mud pit area, line up mudgas separator, degasser and mixing pumps to raise mud weight.

- Line up to add barite and standby for specific instructions from RigSuperintendent and Mud Engineer.

- When pumping starts, keep constant check on mud weight and keepDriller informed.

II.2.6.4 Roughnecks

On drill floor to follow instructions of Driller.

II.2.6.5 Electrician/Mechanic

Standby for possible instructions.

II.2.6.6 Company Representative

It is suggested that, during the actual kill operation, he remain at theremote choke control panel so he can discuss the operation with the RigSuperintendent.

II.2.6.7 Mud Engineer

Go to pits, check Derrickman/Asst. Driller's preparations, assist in buildingproper mud weight and maintaining same.

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II.2.6.8 Additional Personnel on Offshore Units

Responsibilities are as per the posted station bill; the following are shownbelow as examples:

Barge Supervisor:- Ensure standby boat is notified.- Standby in control room for instructions.

Cementer:- Go to cement unit, line up for cementing, and standby for orders.

Roustabouts:- In mud pump room to follow the instructions of the Derrickman.

Subsea Engineer:- Report to rig floor to inspect subsea panel and observe possible

problems.- Wait for instructions from Rig Superintendent.

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Revision: 0Chapter III Well Control Equipment.

Chapter III - WELL CONTROL EQUIPMENT

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III.1 MINIMUM BOP REQUIREMENTS...........................................................................................................64III.1.1 Surface BOPs...........................................................................................64

III.1.1.1 2M psi Stacks ...................................................................................64III.1.1.2 3M and 5M psi Stacks ......................................................................65III.1.1.3 1OM and 15M psi Stacks..................................................................65III.1.1.4 Blind/Shear Rams - Choke and Kill Outlets ......................................65III.1.1.5 Ram Locks........................................................................................65

III.1.2 Subsea BOPs...........................................................................................69III.1.2.1 2M psi Stacks ...................................................................................69III.1.2.2 5M psi Stacks ...................................................................................69III.1.2.3 1OM and 15M psi Stacks..................................................................69III.1.2.4 Blind/Shear Rams - Choke and Kill Outlets ......................................69III.1.2.5 Ram Locks........................................................................................69

III.1.3 Wellhead and LMRP Connectors .............................................................69III.2 MINIMUM DIVERTER REQUIREMENTS ................................................................................................73

III.2.1 Diverters - On Land Rigs, Swamp Barges, and Jack-Up Units................73III.2.1.1 Relief Lines .......................................................................................73III.2.1.2 Relief System....................................................................................73

III.2.2 Diverters - Floating Units ..........................................................................74III.2.2.1 Relief Lines .......................................................................................74III.2.2.2 Relief System....................................................................................74

III.3 CLOSING UNITS AND ACCUMULATOR REQUIREMENTS..................................................................75III.3.1 Surface BOP Systems..............................................................................75

III.3.1.1 Accumulator Capacity / Response Time ..........................................76III.3.1.2 Surface Stack Accumulator Pre-charge ...........................................76III.3.1.3 Four-Way Valves ..............................................................................76III.3.1.4 Remote Panels .................................................................................76III.3.1.5 Hydraulic Pumps...............................................................................77

III.3.2 Subsea BOP Systems..............................................................................77III.3.2.1 Total Accumulator Capacity / Response Time .................................78III.3.2.2 Subsea Accumulator Capacity..........................................................78III.3.2.3 Subsea Accumulator Pre-charge......................................................79III.3.2.4 Four-Way Valves ..............................................................................79III.3.2.5 Redundancy......................................................................................80III.3.2.6 Remote Control Panels.....................................................................80III.3.2.7 Hydraulic Pumps...............................................................................80

III.4 CHOKE AND STANDPIPE MANIFOLD REQUIREMENTS.....................................................................80III.4.1 Choke Manifolds on Land Rigs, Swamp Barges and Jack-Up Units .......80

III.4.1.1 Flow Paths ........................................................................................81III.4.1.2 Component Specifics........................................................................81III.4.1.3 Valve Positions in Drilling Mode for a Surface Stack........................82III.4.2 Choke Manifolds on Floating Units ...................................................83III.4.2.1 Flow Paths ........................................................................................83III.4.2.2 Component Specifics........................................................................83III.4.2.3 Valve Positions in Drilling Mode for a Subsea Stack ........................84

III.4.3 Standpipe Manifold - Surface and Subsea: ..............................................85III.5 OTHER WELL CONTROL EQUIPMENT.................................................................................................86

III.5.1 Safety Valves............................................................................................86

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III.5.2 Inside BOP ...............................................................................................86III.5.3 Float Valves..............................................................................................87III.5.4 Kelly Cocks...............................................................................................87

III.5.4.2 Lower Kelly Cock ..............................................................................87III.5.4.3 Safety Valves with Top Drive Installation..........................................87

III.5.5 Mud Gas Separators ................................................................................88III.6 WELL CONTROL EQUIPMENT TESTING REQUIREMENTS................................................................89

III.6.1 Pressure Test Frequency .........................................................................89III.6.2 Function Test Frequency..........................................................................90

III.6.2.1 Surface BOPs ...................................................................................90III.6.2.2 Subsea BOPs ...................................................................................90

III.6.3 Equipment to be Tested ...........................................................................91III.6.4 Pressure Test Values ...............................................................................91

III.6.4.1 Low Pressure Test............................................................................91III.6.4.2 High Pressure Test ...........................................................................91III.6.4.3 Standpipe Manifold ...........................................................................91III.6.4.4 Kelly Cocks .......................................................................................92

III.6.5 Testing to Full Working Pressure .............................................................92III.6.6 Accumulator Tests....................................................................................92

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An extremely important aspect of well control is the proper selection andutilization of the blowout preventers, chokes, choke manifolds, mud-gasseparators, degassers, mud-monitoring equipment and all other well controlrelated equipment. Only with properly selected equipment, which hasbeen correctly maintained, and serviced, can successful well controlprocedures be initiated.

III.1 MINIMUM BOP REQUIREMENTS

The well control equipment and procedures as described in the SedcoForex Well Control Manual will be adhered to.

It has to be realized that the BOP is only one part of the well integrity.Wellhead equipment, casing and open hole must all be considered.Wellheads and pressure control equipment should meet the minimumworking pressure requirement.

Well control equipment can be considered available in five (5) workingpressure categories; 13,800 kPa, (2,000 psi-2M); 20,700 kPa, (3,000 psi-3M);34,500 kPa, (5,000 psi-5M); 69,000 kPa, (10,000 psi-1OM); 103,500 kPa, (15,000psi-15M).

The following well control equipment and procedures will be regarded as aminimum requirement:

III.1.1 Surface BOPs

The minimum requirement for the following systems will be as follows:

III.1.1.1 2M psi Stacks

One (1) annular type preventer, but it is highly recommended that one (1)annular type preventer and one (1) ram type preventer be used, (seeFigure III.1).

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III.1.1.2 3M and 5M psi Stacks

One (1) annular type preventer and two (2) ram type preventers, (seeFigure III.2).

III.1.1.3 1OM and 15M psi Stacks

One (1) 5M psi annular type preventer and three (3) 1OM or 15M psi ramtype preventers, (see Figure III.3).

III.1.1.4 Blind/Shear Rams - Choke and Kill Outlets

There will be at least one (1) kill and one (1) choke outlet with at least two(2) full opening valves on each choke outlet. If the BOP stack is equippedwith shears rams, they shall be capable of shearing the highest grade andheaviest drillpipe used on the rig (HWDP excluded).

On 5M, 10M, and 15M psi stacks at least one valve will be a remotehydraulically operated valve.

For 5M psi and higher stack there will be at least two (2) full opening valvesplus a check valve, or two (2) full opening valves (one of which is remotelyoperated) on each Kill inlet.

For 2M and 3M psi stacks there will be at least one (1) full opening valveplus a check valve, or two (2) full opening valves (one of which is remotelyoperated) on each Kill inlet.

III.1.1.5 Ram Locks

All ram type preventers will be equipped with ram locks.

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EXAMPLES OF SURFACE STACK ASSEMBLY

One Annular - 2M psi. One Annular & One Ram - 2M psi.

FIGURE III.1

Bag Type

Ram Type

KillLine Spool

OR

ChokeLine

Ba g TypeKillline

Spoo l

OR

ChokeLine

Hydraulic Actuated Valve

Manual Valves

Non-return Valve

Key

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One Annular & Two Rams - 3M to 5M psi

FIGURE III.2

Bag Type

Ram Type

Ram Type

Spool

KillLine

ChokeLine

OR

RemotelyOpera ted

NRV RemotelyOpera ted

Bag Type

Ram Type

Ram TypeKill

LineChoke

LineSpool

OR

Hydraulic Actuated Valve

Manual Valves

Non-return Valve

Key

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One Annular & Three Rams One Annular & Four Rams 10M to 15M psi 10M to 15M psi

Kill Line Choke Line

Bag Type

Doub le Ram Typ e

OR

Sp ool

Ra m Type

Ba g Type

Ram Type

Ram Type

NRV

REMOTELYOPERATED

REMOTELYOPERATED

FIGURE III.3

Hydraulic Actuated Valve Manual Valves Non-return Valve

Key

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III.1.2 Subsea BOPs


One (1) annular type preventer and two (2) ram type preventers, (seeFigure III.4).


One (1) annular type preventer and three (3) ram type preventers, (seeFigure III.5).

III.1.2.3 1OM and 15M psi Stacks

One (1) 5M psi annular type preventer and four (4) 1OM or 15M psi ramtype preventers, respectively, (see Figure III.6).

III.1.2.4 Blind/Shear Rams - Choke and Kill Outlets

There will be at least one (1) set of blind/shear type rams, one (1) kill andone (1) choke outlet with two (2) failsafe valves per outlet on 2M psi and5M psi stacks. There will be at least one (1) set of blind/shear type rams,one (1) kill and two (2) choke outlets on 1OM and 15M psi stacks. Theseconfigurations will allow circulation beneath the blind/shear rams. Theshear rams will be capable of shearing the highest grade and heaviestdrillpipe used on the rig (HWDP excluded)

III.1.2.5 Ram Locks

All ram type preventers will be equipped with ram locks.

III.1.3 Wellhead and LMRP Connectors

An integral part of the subsea BOP is the wellhead and lower marine riserpackage (LMRP) connector. The minimum pressure rating for the wellheadconnector will be equal to that of the ram type preventers. The LMRPconnector will have a pressure rating equal to or greater than that of theannular. Both the wellhead and LMRP connectors will be run with ring typegaskets designed to provide a metal-to-metal seal. The hy-car type ring

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gaskets will be used only when a metal-to-metal seal cannot be achieved,but is not considered a permanent alternative to the metal-to-metal seal.

BOP equipment shall not be run on wellheads at an angle greater than 1.5degrees in order to avoid internal drillstring keyseating damage of the BOPcomponents. Such damage could compromise the BOP pressure retainingcapability.

Care should be taken to monitor casing wear whenever the well profile hasa shallow kickoff or doglegs just below the mudline.

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EXAMPLES OF SUBSEA STACK ASSEMBLY

One Annular & Two Rams - 2M psi One Annular & Three Rams - 5M psi

Connec tor

Bag Type

Ram Type

Ram Type

Connec tor

ChokeLine

KillLine

Bag Type

Connec tor

Ram Type

Ram Type

Ram Type

Connec tor

KillLine

ChokeLine

FIGURE III.4 FIGURE III.5

Failsafe Valves

Key

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EXAMPLES OF SUBSEA STACK ASSEMBLY

One Annular & Four Rams – 10M to 15M psi.

FIGURE III.6

Bag Type

Ram Type

Ram Type

Ram Type

Ram Type

Connec tor

Connec tor

KillLine

ChokeLine

Failsafe Valves

Key

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III.2 MINIMUM DIVERTER REQUIREMENTS

Closing time should not exceed 30 seconds for diverters smaller than 47.63cm (18 3/4") nominal bore and 45 seconds for diverters of 47.63 cm (18 3/4")nominal bore and larger

III.2.1 Diverters - On Land Rigs, Swamp Barges, and Jack-Up Units

A diverter head that is capable of packing off around the kelly, drillpipe orcasing will be used.

III.2.1.1 Relief Lines

At least two relief lines shall be installed to permit venting of the wellborereturns at opposite ends or sides of the rig. On land rigs a single line isacceptable. The diverter relief line(s) may extend from a common line thatconnects to the well beneath the diverter head. The common line shall beat least 203 mm (8 inch) nominal diameter.

III.2.1.2 Relief System

- The diverter relief system shall be installed with a minimum number ofbends and all lines well secured. Each diverter relief line will beequipped with a pressure-operated, full opening, unrestricted valve. Theoperating sequence of the diverter will be as follows:

- Open selected valve (Ref: I.l9).- Close diverter

These functions will be interlocked. A means of switching flow from onevent to the other without closing in the system must be provided.

- Special care should be taken to protect pipe bends from erosion.This may include:

- Use of long radius pipe bends.

- Providing extra metal thickness at bends.

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- If the regular flow line (mud return line) and the diverter reliefoutlet from the well is a common line or if the regular flow lineconnects below the diverter head. A power-operated valve mustbe installed to automatically shut off mud returns to the pits whenthe diverter is closed.

- Sleeve-type connections shall not be used in the diverter system.

III.2.2 Diverters - Floating Units

Diverters are required as follows:

A diverter that is capable of packing off around either the kelly or drillpipeshall be installed and securely anchored to the rig in such a manner as toprevent the slip joint from extending upward through the rotary tableshould pressure be encountered.

III.2.2.1 Relief Lines

At least two relief lines of 304.56 mm (12-inch) nominal diameter shall beinstalled. (On rigs operating in a dynamically positioned mode a single lineis acceptable.) These lines are to be arranged to permit venting of thewellbore returns at opposite ends or sides of the rig. The diverter relief linesmay extend from a common line that connects to the well beneath thediverter head. The common line shall be at least 304.56 mm (12-inch)nominal diameter.

III.2.2.2 Relief System

- The diverter relief system shall be installed with the minimumnumber of bends and shall be securely anchored.

- Special care should be taken to protect pipe bends from erosion.This may include:

- Use of long radius pipe bends.

- Providing extra metal thickness at the bends.

- Only full opening, unrestricted valves shall be used in the diverterrelief system.

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- All valves in the diverter relief system shall be pressure- operated.

- The diverter system shall be equipped so that at least one diverterrelief line automatically opens to vent when the diverter head isclosed. A means of switching flow from one vent to the otherwithout closing in the system must be provided.

- If the regular flow line (mud return line) and the diverter reliefoutlet from the well is a common line or, if the regular flow lineconnects below the diverter head. A power-operated valve mustbe installed to automatically shut off mud returns to the pits whenthe diverter is closed.

- Sleeve-type connections shall not be used in the divertersystem.

III.3 CLOSING UNITS AND ACCUMULATOR REQUIREMENTS

III.3.1 Surface BOP Systems

The closing unit will consist of an independent automatic accumulator unitrated for at least 20,700 kPa (3,000 psi) working pressure with a controlmanifold, clearly showing 'open' and 'close' positions for preventers and thepressure operated choke line valve. It is essential that BOP operating unitsbe equipped with 0-20,700 kPa (0-3,000 psi) or 0-34,500 kPa (0-5,000 psi asappropriate for the accumulator working pressure) regulator valves,(equipped with manual override) which will not fail open causing acomplete loss of operating pressure. This unit will be located in a safe area.(A safe area is defined as a position where the unit can be operated withthe well on fire or out of control.)

Due to the large volume required to close the annular preventer(s) andlarge bore diverters (such as Hydril MSP) which can result in slow closingtime, the hydraulic pressure for the initial closure of the annular preventerwill be set at the maximum operating pressure during normal drillingoperations. However, it must be readjusted to the manufacturer'srecommended pressure after closure and/or prior to running casing, routinepressure testing and stripping operations.

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III.3.1.1 Accumulator Capacity / Response Time

The accumulator volume of the BOP systems should be sized to keep aremaining stored accumulator pressure of 1380 kPa (200 psi.) or moreabove the minimum recommended precharge pressure after conductingthe following operations (with pumps inoperative):

- Closing all (rams and annular) functions and Open all HCRsvalves.

- Opening all (rams and annular) functions and Close all HCRsvalves

- Closing the annular.- Opening chokeline remote operated valve.

For surface installations, the BOP control system should be capable ofclosing each ram BOP within 30 seconds. Closing time should not exceed30 seconds for annular BOPs smaller than 47.63 cm (18 3/4") nominal boreand 45 seconds for annular preventers of 47.63 cm (18 3/4") nominal boreand larger. Response time for choke and kill valves (either open or close)should not exceed the minimum observed ram closing time.

III.3.1.2 Surface Stack Accumulator Pre-charge

Accumulators fitted with bladders shall have a pre-charge equal to 1/3rdof the rated pressure, i.e.: 6900 kPa for 20700 kPa systems (1000 psi for 3000psi systems) and 10345 kPa for 31000/34500 kPa systems (1500 psi for4500/5000 psi systems). The pre-charge pressure shall not exceed 100% ofthe accumulator rated working pressure. Only Nitrogen (N2) gas should beused for accumulator precharge.

III.3.1.3 Four-Way Valves

All four-way valves will be in either the 'open' or 'close' position duringnormal operations. They should not normally be left in the neutral position.

III.3.1.4 Remote Panels

There will be two (2) remote control panels; each one clearly showing'open' and 'close' positions for each preventer and the pressure operatedchoke line valve. Each of these panels shall include a master control valveand controls for the regulator valves and for a bypass valve. One panel

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must be located near the driller's position; the other panel is to be locatedin a safe area. If the accumulator closing unit is in a safe area, it may beconsidered as the other panel. If the accumulator closing unit is closeenough to the well where access may become difficult in the event of ablowout, then the driller's panel plus another remote panel is required.

III.3.1.5 Hydraulic Pumps

The unit will include one (1) electric pump and two (2) backup air pumpsfor accumulator charging. With the accumulator system removed fromservice, the pumps should be capable of closing the annular preventer(excluding the diverter) on the minimum size drillpipe being used plus,opening the hydraulically operated choke line valve and obtain aminimum of 1380 kPa (200 psi) pressure above accumulator prechargepressure on the closing unit manifold within two (2) minutes or less.

The combined output of all pumps should be capable of charging theentire accumulator system from precharge pressure to the maximum ratedcontrol system working pressure within 15 minutes.

III.3.2 Subsea BOP Systems

The closing unit will consist of an independent automatic accumulator unitrated for at least 20,700 kPa (3,000 psi) working pressure with a controlmanifold, clearly showing 'open' and 'closed' position for preventers andthe failsafe valves. It is essential that all BOP operating units be equippedwith 0-20,700 kPa (0-3,000 psi) or 0-34,500 kPa (0-5,000 psi as appropriate forthe accumulator working pressure) regulator valves, (equipped withmanual override) which will not fail open causing a complete loss ofoperating pressure.

Due to the large volume required to close the annular preventer which canresult in slow closing time, the hydraulic pressure for the initial closure of theannular preventer will be set at the maximum operating pressure duringnormal drilling operations. However, it must be readjusted to themanufacturer's recommended pressure after closure and/or prior torunning casing, routine pressure testing and stripping operations.

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The Region Managers have the option to modify this recommended closingpressure, especially when floating units are operated in significant heavingconditions.

III.3.2.1 Total Accumulator Capacity / Response Time

The accumulator volume of the BOP systems should be sized to keepremaining stored accumulator pressure of 1380 kPa (200 psi) or more abovethe minimum recommended precharge pressure after conducting thefollowing operations (with pumps inoperative):

- Closing all (rams and annulars) functions and open fail safes.- Opening all (rams and annulars) functions and close fail safes.- Closing one (1) annular.- Closing two (2) rams.

For subsea installations, the BOP control system should be capable ofclosing each ram BOP within 45 seconds or less. Closing time should notexceed 60 seconds for annular BOPs. Response time for choke and killvalves (either open or close) should not exceed the minimum observed ramclosing time. Time to unlatch the lower marine riser package on mooredunits (i.e. excludes dynamic positioning) should not exceed 45 seconds.

III.3.2.2 Subsea Accumulator Capacity

Dynamically Positioned Floating Units

Emergency Backup Accumulators:On dynamic positioned units the stack mounted accumulators shouldprovide the hydraulic fluid for all functions selected for emergencydisconnect plus fifty percent reserve. The functions typically selected foremergency disconnect include:- Close annular.- Close lower ram.- Shear drillpipe with shear ram.- Lock ram lock.- Close choke and kill valves.- Retract pod stabs.- Unlatch riser connector.- Unlatch riser connector secondary.

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In the event that BOP functions are in operative due to a failure of the maincontrol system, the stack mounted accumulators of the acoustic systemshould provide the hydraulic fluid for all functions selected for anemergency operation plus fifty percent reserve. The functions typicallyselected for an emergency operation include

- Unlatch riser connector.- Shear drillpipe with shear ram.- Close middle pipe ram.- Close lower pipe ram.- Lock ram lock.- Retract all stabs.

Moored Floating Units

On moored units the stack mounted accumulators should provide thehydraulic fluid for closing the largest annular BOP plus fifty percent reserve.The stack mounted accumulators also help minimize the response time toclose the annular.

III.3.2.3 Subsea Accumulator Pre-charge

Accumulators fitted with bladders shall have a pre-charge equal to 1/3rdof the rated pressure, i.e.: 6900 kPa for 20700 kPa systems (1000 psi for 3000psi systems) and 10345 kPa for 31000/34500 kPa (1500 psi for 4500/5000 psisystems) plus hydrostatic and temperature compensation. A gradient of 10kPa/m (0.445 psi/ft) is used to calculate the hydrostatic compensation. Thepre-charge pressure shall not exceed 100% of the accumulator ratedworking pressure. Only Nitrogen (N2) gas should be used for accumulatorprecharge.

III.3.2.4 Four-Way Valves

All four-way valves on the accumulator manifold will be in either the 'open'or 'close' position during normal operations. They should not normally beleft in the 'block' position.

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III.3.2.5 Redundancy

There will be 100% redundancy of control for all BOP stack functions.

III.3.2.6 Remote Control Panels

- There will be two (2) remote control panels, each one clearly showing'open' and 'close' positions for each preventer and the failsafe valves.One panel must be located near the Driller's position; the other panel is tobe located in a safe area.

- For two stacks systems there will be an overlay on both panels.

III.3.2.7 Hydraulic Pumps

The unit will include at least two pump systems, each having independentdedicated power sources. With the accumulator system removed fromservice, the pump system should be capable of closing the annularpreventer on the minimum size drillpipe being used, plus opening thehydraulically operated choke line valve and obtain a minimum of 1380 kPa(200 psi) pressure above accumulator pre-charge pressure on the closingunit manifold within two (2) minutes.

The combined output of all pumps shall be capable of charging the entireaccumulator system from pre-charge pressure to the maximum ratedcontrol system working pressure within 15 minutes

III.4 CHOKE AND STANDPIPE MANIFOLD REQUIREMENTS

III.4.1 Choke Manifolds on Land Rigs, Swamp Barges and Jack-Up Units

For all installations, the working pressure of the choke manifold shall equalor exceed the working pressure of the ram preventers. In the case of 2M psistacks, the working pressure of the choke manifold shall be at least equalto the working pressure of the annular.

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III.4.1.1 Flow Paths

At least three flow paths must be provided that are capable of flowing wellreturns through conduits that are 76.14 mm (3-inch) nominal diameter orlarger.

- At least one flow path shall be equipped with a remotelycontrolled, pressure operated adjustable choke. Simplified chokemanifolds without remote control choke may be acceptable onlight rigs with 2-3M psi stacks.

- At least one flow path shall be equipped with a manuallyoperated adjustable choke.

- At least one flow path must permit returns to flow directly to thepit, discharge manifold or other downstream piping withoutpassing through a choke. Two gate valves with full rated workingpressure must be provided in this unchoked flow path.

III.4.1.2 Component Specifics

- The working pressure of the choke manifold shall equal or exceedthe working pressure of the ram preventers.

- The chokes, the two valves controlling the unchoked dischargeflow path, and all equipment upstream of these items must havefull rated working pressure and must be equipped with flanged,studded or clamp hub connections.

- Two gate valves must be provided upstream of the choke in eachchoke flow path.

- At least one gate valve must be installed downstream of eachchoke ahead of any discharge manifold. This valve may or maynot carry the full rated working pressure of the choke manifold.

- A pressure gauge or other means of measuring the inlet pressureto manifold must be provided. The manifold outlet for this devicemust be equipped with a flanged, studded or clamp hub typegate valve with 46 mm (1-13/16 inch) minimum bore.

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- Only right angle block turns shall be used in the choke manifoldand discharge piping.

- All chokes shall discharge directly into an erosion nipple. Thisnipple shall be at least 0.9 m (3 ft) long. It shall have a wallthickness at least as great as 76.14 mm (3-inch) XX heavy pipe.

- A Hydrate Inhibition (i.e.: glycol) Injection System should be set upif necessary for use on 10M and 15M psi stacks.

III.4.1.3 Valve Positions in Drilling Mode for a Surface Stack

The Figure III.7 below depicts an example of a manifold set up for a surfaceBOP stack. The valves are shown in their normal, open or closed position:

Closing the valve downstream of the choke on the choke manifold, insteadof the valve upstream, is allowable provided that this downstream valve israted to the BOP full working pressure and equipped to allow openingunder full working pressure.

Figure III.7

C ho k e m a n ifo ld v a lv e p o sitio n s fo r surfa c e sy ste m s.

Ke y

O p e n V a lv e

C lo se d V a lv e

Re m o te O p e ra t o r

C h o ke

C h o k e Lin e

A t St a c k

A t M a n ifo ld

Fu ll W o rk in g Pre ssu re

Re d u c e d W o rk in gPre ssu re A llo w a b le

To M u d / G a s Se p a ra t o rPit s, Fla re o r O v e rb o a rd

Ble e d o f f Lin e t o Fla re o rO v e rb o a rd

To M u d / G a s Se p a ra t o rPit s, Fla re o r O v e rb o a rd

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III.4.2 Choke Manifolds on Floating Units

The choke manifold assembly for floating drilling units serves the samepurpose and in general has the same components as those used on rigswith surface stacks.

III.4.2.1 Flow Paths

At least three flow paths must be provided that are capable of flowing wellreturns through conduits that are 76.14 mm (3-in) nominal diameter orlarger.

- At least one flow path shall be equipped with a remotelycontrolled, power-operated adjustable choke.

- At least one flow path shall be equipped with a manuallyoperated adjustable choke.

- One flow path must permit returns to flow directly to the dischargemanifold or other downstream piping without passing through achoke. Two gate valves with full rated working pressure must beprovided in this unchoked flow path.

III.4.2.2 Component Specifics

- The working pressure of the choke manifold shall equal or exceedthe working pressure of the ram preventers.

- The chokes, the two (2) valves controlling the unchoked dischargepath, and all equipment upstream of these items must have fullrated working pressure and must be equipped with flanged,studded or clamp hub connections.

- Two gate valves must be provided upstream of the choke in eachchoke flow path.

- At least one gate valve must be installed downstream of eachchoke but ahead of any discharge manifold. This valve may ormay not carry the full rated working pressure of the chokemanifold.

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- A pressure transducer or other means for measuring the inletpressure to the manifold must be provided. The manifold outlet forthis device must be equipped with a flanged, studded or clamphub type gate valve with 46 mm (1-13/16 inch) minimum bore. Thereadout for the transducers shall be at the remote choke controlstation.

- Only right angle block turns shall be used in the choke manifoldand discharge piping.

- On systems with flare booms permanently installed, a permanentconnection between the discharge manifold and flare boomshould be installed.

- A Hydrate Inhibitor (i.e.: glycol) Injection System should be set upfor use if necessary on 10M and 15M psi choke/kill manifolds.

III.4.2.3 Valve Positions in Drilling Mode for a Subsea Stack

The Figure III.8 depicts an example of a manifold set up for a subsea BOPstack. The valves are shown in their normal, open or closed position:

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Figure.III.8

Closing the valve downstream of the choke on the choke manifold, insteadof the valve upstream, is allowable provided that this downstream valve israted to the BOP full working pressure and equipped to allow openingunder full working pressure.

III.4.3 Standpipe Manifold - Surface and Subsea:

The choke and standpipe manifold should be isolated by two isolationvalves and have the capability of being connected to the cementing unit.

C ho k e m a nifo ld v a lv e p o sitio n s fo r sub se a c h o k e

Ke yO p e n

C lo se d V a lv e

Re m o t e O p e ra t o r

C h o keC h o ke

A t St a c k

A t M a n ifo ld

Fu ll W o rk in g Pre ssu re

Re d u c e d W o rk in gPre ssu re A llo w a b le

Bu f fe r t o M u d / G a s Se p a ra t o r, Pit s, Fla re s o r O v e rb o a rd

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III.5 OTHER WELL CONTROL EQUIPMENT

III.5.1 Safety Valves

A full opening safety valve (including a closing handle) with bottomconnections, cross-overs or provisions to fit any section of tubing ordrillstring being handled shall be on the rig floor. The valve shall have arated working pressure greater than or equal to the BOP stack. Theconnection is to fit the bottom connection of the kelly or Top Drive. Theoutside diameter of the valve shall be such that it may be run in the hole(an inside BOP must be pumped in the string or installed on top of the safetyvalve in order to run in the hole) with adequate clearance.

This safety valve should be equipped with a means for easy handling toenable immediate connection to the drillstring in the event of a kick.

Examples of full opening safety valves are:

- Hydril Kelly Guard.- T.I.W.- S.M.F.

III.5.2 Inside BOP

An inside BOP is a surface installed back pressure check valve. If this is adrop-in type, the landing sub must be positioned in the drillstring at or nearthe drill collars. There will be one such valve on the rig floor at all times.Examples of inside BOPs are:

- Gray valves.- Hydril drop-in valve.

If a Gray valve is to be used, it will be ready for installation locked in the'open' position. If a drop-in type is used, the landing sub will be in thedrillstring at or near the collars and the correct size dart will be on the drillfloor in a protective box. The dart must be able to pass through all therestrictions above the landing sub.

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III.5.3 Float Valves

Float valves must be used while drilling and opening hole prior to settingsurface casing or any time the posted well control plan is to divert and canalso be used in deeper sections of hole. They:

- Prevent sudden influx entry into drillstring.- Prevent back flow of annular cuttings from plugging bit nozzles.

Either plain or ported floats are acceptable.

III.5.4 Kelly Cocks

III.5.4.1 Upper Kelly Cock

The upper kelly cock is a safety valve placed between the kelly joint andthe swivel. The kelly cock should be closed if drillpipe pressure threatens toexceed the pressure rating of the washpipe packing or rotary hose. Aspecial wrench to operate the kelly cock is required and must be kept onthe rig floor.

III.5.4.2 Lower Kelly Cock

The lower kelly cock, a full opening safety valve, will be installedimmediately below the kelly. An appropriate wrench will be available onthe rig floor for opening and closing purposes. When a mud saver sub isused, it will be inserted above the kelly cock.

Both the lower and upper kelly cock should have a working pressure equalto or greater than the BOPs.

III.5.4.3 Safety Valves with Top Drive Installation

When a top drive installation is in use there will be two safety valvesincluded in the drilling hook up:

- The upper safety valve will be remote operated- The lower safety valve will be manually operated.

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The lower safety valve on the VARCO TDS has a 65/8 Reg. pin upconnection.

Should it become necessary to disconnect the TDS during well controloperations (for example, if stripping is planned after the TDS has beenreconnected in to shut the drillstring during a trip). The lower safety valvewill be backed out from the upper using the pipe handler. A sub toconnect the upper safety valve to the drillpipe in use and a sub to connectthe lower safety valve to the drillpipe in use will be installed temporarily.These subs must be available on the rig floor.

Any item in the string, which may need to be removed through the top ofthe string, such as a MWD drillpipe screen, must have an OD smaller thanthe lower safety valve ID.

III.5.5 Mud Gas Separators

An atmospheric or low pressure separating vessel for handling gas-cutreturns must be provided where blowout preventers are used. It must beequipped with gas vent lines to discharge gas at least 60m (200 ft) from thewell opposite the direction of the prevailing winds. On offshore locations,venting above the crown is acceptable. The vent line should be sized tominimize the back pressure on the separator. The mud gas separatorconfiguration must be such that a sufficient liquid seal is maintained on theunit during a killing operation to avoid blowdown (see Appendix 7).

The mud degasser is used to extract entrained gas from the mud and shallnever be directly connected with returns from the well. When the degassergas exhaust is connected to the mud gas separator gas exhaust, a checkvalve must be inserted between the degasser exhaust and this line.

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III.6 WELL CONTROL EQUIPMENT TESTING REQUIREMENTS

III.6.1 Pressure Test Frequency

The pressure tests of all blowout preventers, wellhead components and theirconnections, BOP operating unit, choke manifold, kill and choke lines,standpipe manifold, kelly and kelly cocks, safety valves and inside BOPsshall be made:

- Prior to installation where possible.- After installation of wellhead and BOP assembly and prior to

drilling.- When any component change is made.- Prior to drilling into a suspected high pressure zone.- At any time requested by the Company Drilling Representative.- After repairs.- Prior to the initial opening of drill stem test tools. (Refer to V.4.1)- When bonnets have been opened solely for the purpose of

changing rams prior to running casing, a body test to ensure theintegrity of the bonnet seals will suffice.

- In any case BOP and related equipment will be pressure testedevery two weeks or during the first trip after the 14-day intervalwith a maximum interval of 21 days (see I.13).

The biweekly test is not required for shear rams. As a minimum, these ramsare to be tested prior to resume drilling operations after each casing stringhas been set and after the WOC is officially over.

Every rig shall have written BOP pressure testing procedures. All pressuretests will be fully documented on the rig's blowout prevention equipmenttest sheets. Tests performed will be recorded in the daily drilling report(IADC report).

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III.6.2 Function Test Frequency

III.6.2.1 Surface BOPs

All rams, annulars, diverters, valves, etc., shall be function tested at thefollowing frequencies:

- On initial installation from Driller's and remote control panel.- Every week or during the first trip after the 7 day interval. Under no

circumstance will this interval exceed a maximum of 14 days (seeI.13).

The weekly test is not required for shear rams. As a minimum, these ramsare to be tested prior to resuming drilling operations after each casingstring has been set and after the WOC is officially over.

III.6.2.2 Subsea BOPs

All rams, ram locks, annulars, failsafe valves, diverters, or other subseaitems shall be function tested at the following frequencies:

- Prior to running the assembled blowout preventer stack, functiontest all components with both control pods from the Driller'sremote control, and hose reel control panels. Operations of theacoustic pod should be confirmed during stack preparation.

- After initial installation of the blowout preventer stack and afterany control components have been repaired or replaced.Function test all components (certain exceptions must be madefor any equipment whose operation may affect the pressureintegrity of the system, e.g., wellhead connector, choke and killline stabs on E.H. units, etc.) using both control pods from theDriller's and remote control panels.

- Every week or during the first trip after the 7 day interval. Thisinterval will not exceed 14 days (see I.13).

The weekly test is not required for shear rams. As a minimum, these ramsare to be tested prior to resuming drilling operations after each casingstring has been set and after the WOC is officially over.

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III.6.3 Equipment to be Tested

- All components of the blowout preventers, wellhead componentsand their connections.

- The choke manifold valves, kill and choke lines and valves on theside outlets.

- The kelly and kelly cocks.- The standpipe manifold.- The safety valves and spare kelly cocks.- Chiksans before use.

III.6.4 Pressure Test Values

All pressure tests will be conducted with water or anti-freeze solution.Pressure test in oil base mud may be conducted with clean oil.

III.6.4.1 Low Pressure Test

1380-2070 kPa (200-300 psi) for 5 minutes prior to each high pressure test.

III.6.4.2 High Pressure Test

- Ram-type BOPs and related control equipment including thechoke manifold shall be tested at the anticipated surface pressureor at 70 percent of the minimum internal yield pressure of thecasing, whichever is the lesser.

- If the cup-type tool is used, the additional load on the drillpipedue to the piston effect needs to be determined and checkedagainst pipe strength.

- Annulars will be tested to 50% of the rated working pressure of thecomponents.

- All high pressure tests will be conducted for 10 minutes.

III.6.4.3 Standpipe Manifold

The standpipe manifold will be tested to its rated working pressure.

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III.6.4.4 Kelly Cocks

The kelly cocks will be tested to the lesser of the following:

- Kelly cock rated working pressure- Drillpipe internal yield pressure- BOP stack rated working pressure

III.6.5 Testing to Full Working Pressure

If a test stump is available, the BOP stack will be tested to its rated workingpressure at least every six months, with exception of the annular which is tobe tested to 50% of its rated working pressure.

III.6.6 Accumulator Tests

Low fluid level alarms will be tested weekly.

Accumulator performance tests will be done on surface stacks after initialinstallation of the BOP

This test will include:

- Fluid charge system to working pressure.- Switch off accumulator pumps.- Closing the annular.- Closing all rams (excepting blind or blind/shear ram BOPs) from

full-open position against zero wellbore pressure.- Opening all HCRs valves against zero wellbore pressure- Opening the annular.- Opening all rams (excepting blind or blind/shear ram BOPs) from

full-open position against zero wellbore pressure.- Closing all HCRs valves against zero wellbore pressure.- Closing the annular.- Opening chokeline remote operated valve.- Observe that there is at least 1380 kPa (200 psi) above the

precharge pressure on the accumulator gauge.- Switch on accumulator pumps. Record accumulator recharging

time, which should be less than 15 minutes.- Check accumulator recharge time for the system in use.

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- Report all recorded information on BOP test forms and the safety register.

See Surface Accumulator Closing Test Worksheet in Appendix 3.

On subsea stacks, prior to BOP installation when all bottles have surfacepre-charge or after initial installation when stack mounted bottles havebeen pre-charged for hydrostatic pressure.

This test will include:

- Fluid charge system greater than 20,700 kPa (3000 psi) or workingpressure of system.

- Switch off accumulator charging pumps.- Closing all annulars, all rams and open all fail safe valves (against

zero wellbore pressure.)- Opening all annulars, all rams and close fail safe valves (while

closing and opening functions, monitor accumulator pressureclosely).

- Closing one (1) annular.- Closing two (2) rams.- Observe that there is at least 1380 kPa (200 psi) above the

precharge on accumulator gauge.- Switch on accumulator pumps. Record accumulator recharging

time, which should be less than 15 minutes.- Check accumulator recharge time for the system in use.- Report all recorded information on BOP Test Forms and the Safety

Register.

See Subsea Accumulator Closing Test Worksheet in Appendix 3

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Revision: 0Chapter IV Well Control Drills.

Chapter IV - WELL CONTROL DRILLS

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Pit drills and blowout drills will be held on a weekly basis or more often ifthe Rig Superintendent considers it necessary. These drills will be loggedin the I.A.D.C. drilling report.

Drills shall be designed to acquaint each crewmember with his functionon the particular test station so he can perform it promptly andefficiently.

The steps described below are general and are based upon theessentials of the operation and should be varied to fit the equipmentand specific needs of each site. A well control drill plan, applicable tothe particular site, shall be prepared for each crew member outliningthe assignments he is to fulfill during the drill and establishing aprescribed time for the completion of this portion of the drill. A copy ofthe complete well control drill plan shall be posted in the driller's shelteror the doghouse.

The actual drill shall be carried out during periods of activity that wouldminimize the risk of sticking the drillpipe or otherwise endanger theoperation. In each of these drills, the reaction time shall be measuredup to the point when the designated person is in the position to beginthe closing sequence of the blowout preventer. The total time for thecrew to complete its entire drill shall also be measured. This operationshall be recorded on the Driller's log as "Well Control Drill". The man incharge shall initiate all drills. The drills shall be timed so they will cover arange of different operations, which include on bottom drilling andtripping. A diverter drill shall be developed and conducted in a similarmanner for shallow operations.

IV.1 ON BOTTOM DRILLING WHEN INSTRUCTION IS TO SHUT IN

When the posted instruction is to shut the well in, a drill conductedwhile drilling or tripping should include the following:- Simulate close in of the well as per shut in procedure.- Record time.

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- Check all valves on choke manifold and blowout preventerstack for correct position (open or closed).

- Check accumulator pressure.- Simulate stopping all hot work.

This operation shall be performed at least once each week (wellconditions permitting) with each crew.

IV.2 WHEN INSTRUCTION IS TO DIVERT

When posted instruction is to divert for surface hole operations,drills are of paramount importance since there is little time toreact. The actions taken by the driller and his crew must beplanned, practiced and immediate to deal with a shallow gaskick.

A specific detailed diverter drill will be prepared for each rig/wellthat should include the following:

- Simulate diverting the well as per diverter procedures(including line up of pumps to heavy mud).

- All essential personnel to their pre-assigned positions.- All non essential personnel to the muster point or to the

assigned position as per emergency plan.- Simulate "get ready for disconnect and move off location".

These drills must be held by each crew at the beginning of eachtour during this drilling phase to familiarize all personnel with theappropriate and immediate actions in case of shallow gas kick.

NOTE These last three steps should be part of one drill at thebeginning of the top hole phase and should be repeatedif a change of crew has taken place or if the top holeoperations last more than 7 days.

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IV.3 DRILL EXAMPLES

Examples of typical drills are shown hereafter. They should beadapted to each rig.

IV.4 SPECIAL DRILLS – DRILL SHEET EXAMPLES

After casing has been set and prior to drilling into a hydrocarbonreservoir or high pressure zone, it is recommended that a full sizeBOP drill including actual closure of BOP, circulation throughchokes (use SCRP + 3000 KPa, 500 PSI), mustering of crews,pressurizing of silos, informing stand-by boat, ensuring adequatepower and water supply etc. be performed.

It is also recommended that, in addition to the above, a "strippingdrill" be performed at that time or occasionally when the wellcondition allows the exercise to be performed safely.

Note that a "Stripping Worksheet" is included in Appendix 3

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WHILE DRILLINGWHEN POSTED WELL CONTROL OPTION REQUIRES SHUTTING WELL IN

1) At a safe time during drilling operations, Rig Superintendentinitiates the drill and records time at start of drill :

.........................HRS.2) Drill crew responses are recorded (check all steps correctly

performed)

❑ Driller stops rotation & picks up to a predetermined tool joint position

❑ Driller shuts down pumps and conducts flow check (Rig Supt. announces drill in progress). Driller sounds alarm tocrew.

❑ Driller simulates* closure of (upper) annular BOP & opening of remote operated valve. Rig Supt. records timesimulated closure begins. ..............................HRS.

Elapsed time since start of drill ................MIN ..........SEC.

❑ Driller talks through closure sequence to the satisfaction of the Supt. (including informing MIC, Hanging off....)

❑ Confirms crew members present know assignments

Record in IADC report as: BOP drill: Drilling................ MIN ..........SEC.

Occasionally, additional steps, some involving non-drilling personnel,will be performed:

- Mechanic to start additional engines if necessary to supportadditional pumps and compressors, then to start same, then tostand by position.

- Electrician to stand by position.- Barge engineer to pressure up and line up barite silos.- A/D to start de-gasser, check return from mud/gas separator line-

up and prepare for weighting mud up.- Radio operator to inform stand by boat of drill.- Non essential crew to muster station.

*After running casing and before entering hydrocarbon reservoir or high-pressurezone, actual closure of BOP and circulation through chokes (use SCRP+3000 KPa,500 PSI) may be performed instead of simulation.

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WHILE DRILLINGWHEN POSTED WELL CONTROL OPTION REQUIRES DIVERTING

At a safe time during drilling operations, Rig Superintendent initiatesthe drill and records time at start of drill: .........................HRS.

❑ Driller sounds alarm and simulates closure of diverter element.

❑ Driller increases pump speed to max. SPM/pressure.

❑ Driller simulates disconnecting pin connector (or opening dumpvalves/increasing slip joint packer pressure as applicable).

❑ Driller verifies arrangements to divert downwind

❑ Rig Supt. records time heavy mud is selected :

.........................HRS.

Elapsed time since start of drill : ................MIN ..........SEC.

❑ Driller talks through other steps to the satisfaction of Supt.

❑ Rig Supt. confirms crew members present know assignments

Record in IADC report as:

Diverter Drill : Drilling................MIN ..........SEC.

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WHILE TRIPPINGWHEN POSTED WELL CONTROL OPTION REQUIRES SHUTTING WELL IN

When safe during tripping operations, the driller or the MIC initiates thedrill by signaling to the drill crew that a kick drill has begun. He notesthe exact time of his signal. He then sets the drillstring in the slips in aposition to permit installation of a full opening safety valve.

The floor crew installs the full opening safety valve, correctly torques itup and closes it. (Driller checks they know to turn the wrench thecorrect direction).

After the valve is closed, driller simulates annular BOP closure.

Time elapsed to start of annular closing sequence :

...............MIN ..........SEC.

Driller confirms crewmembers present know their assignments, and areprepared for safety valve installation on all sizes of BHA.

Record in IADC report as:

Well Control Drill : Tripping................MIN ..........SEC.

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Revision: 0Chapter V Special Well Control Situations.

Chapter V - SPECIAL WELL CONTROL SITUATIONS

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V.1 LOST CIRCULATION.............................................................................................................................104V.1.1 Recognition of Partial Losses.................................................................104V.1.2 Well Control Options When Partial Losses Occur .................................104

V.2 SNUBBING............................................................................................................................................105V.2.1 Unit Types ..............................................................................................106

V.2.1.1 Mechanical Unit ..............................................................................106V.2.1.2 Hydraulic Unit..................................................................................106

V.2.2 Safety Precautions ..............................................................................107V.3 WORKOVER / BULLHEADING..............................................................................................................107

V.3.1 When to Consider Bullheading:..............................................................108V.3.2 Prior to Bullheading ................................................................................109V.3.3 Procedure for Bullheading......................................................................110

V.4 DST OPERATIONS ................................................................................................................................111V.4.1 Basic Precautions for DST .....................................................................112V.4.2 Special Precautions for Floating Units .............................................113V.4.3 Precautions While Testing......................................................................113

V.5 H2S - HYDROGEN SULFIDE.................................................................................................................115V.5.l Properties ...............................................................................................115V.5.2 Drilling Operations ..................................................................................115V.5.3 Well Control............................................................................................115V.5.4 Emergency Procedures..........................................................................116V.5.5 Special H2S Precautions........................................................................116

V.6 WELL CONTROL CONSIDERATIONS - WITH OIL BASED MUD .......................................................117V.6.1 Kick Detection.........................................................................................117V.6.2 Shut-in Procedures While Drilling...........................................................117V.6.3 Special Precautions - While Drilling .......................................................118V.6.4 Special Precautions - While Tripping .....................................................118

V.7 KICKS WITH DRILLCOLLARS OR CASING IN THE BOP STACK .....................................................118V.7.1 Drillcollars ...............................................................................................118

V.7.1.1 Shut-in Procedure with Surface BOPs............................................119V.7.1.2 Shut-In Procedure for Floating Units ..............................................120V.7.1.3 Dropping the Drillcollars..................................................................120V.7.1.4 Special Consideration.....................................................................121

V.7.2 Casing ....................................................................................................121V.8 HYDRATES.............................................................................................................................................122

V.8.1 Formation of Hydrates............................................................................122V.8.2 Well Control Considerations...................................................................123V.8.3 Drilling Considerations............................................................................124V.8.4 Prevention of Hydrates ...........................................................................124

V.9 NO CIRCULATION .................................................................................................................................125V.9.1 Plugged Bit .............................................................................................125V.9.2 Bit Out of Hole ........................................................................................125

V.10 DETERMINING SHUT-IN DRILLPIPE PRESSURE WITH A FLOAT VALVE IN DRILLSTRING .........126V.10.1 Method 1.................................................................................................126V.10.2 Method 2.................................................................................................126

V.11 WIRELINE IN BOPS/LUBRICATORS....................................................................................................127V.11.1 Wireline Operations Without Specialized Wellhead Equipment.............127V.11.2 Wireline Operations With Specialized Wellhead Equipment..................128

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V.11.2.1 Equipment Requirements ...............................................................128V.11.2.2 Equipment Considerations and Safety ...........................................129

V.12 EMERGENCY DISCONNECT OPERATIONS DURING WELL KILL OPERATIONS (MOOREDFLOATING UNITS).................................................................................................................................131

V.12.1 Conditions That May Require a Disconnect ...........................................131V.12.2 Procedures for Emergency Disconnect - Time Permitting .....................131V.12.3 Procedures for Emergency Disconnect - No Warning ...........................132

V.13 WELL CONTROL OPERATIONS AFTER SHEARING PIPE (MOORED FLOATING UNITS) .............132V.13.1 Procedures for Re-connecting................................................................132

V.14 TERTIARY CONTROL ...........................................................................................................................133V.14.1 Barite Plugs ............................................................................................133V.14.2 Cement Plugs .......................................................................................136

V.15 TRAPPED GAS IN SUBSEA BOP STACKS ....................................................................................137V.16 EQUIPMENT PROBLEMS .....................................................................................................................138

V.16.1 Choke .....................................................................................................138V.16.2 Annular Preventer...................................................................................139V.16.3 Ram Packer Damage.............................................................................139V.16.4 Mud Pump Problems..............................................................................140V.16.5 Kelly Mud Saver Valves ......................................................................141

V.17 CHOKE LINE FRICTION........................................................................................................................142V.17.1 Pressure Losses in Subsea Kill Operations ...........................................142V.17.2 Bringing Pump Up To Kill Rate Speed (Non Instrumented BOP)...........143

V.18 DETERMINING THE CORRECT BOTTOM HOLE PRESSURE: TRAPPED PRESSURE. ..................148V.19 UNDERBALANCED DRILLING .............................................................................................................152

V.19.1 Equipment ..............................................................................................152V.19.2 Practices.................................................................................................154V.19.3 Procedures .............................................................................................154

V.20 COLLISION AVOIDANCE ......................................................................................................................156

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V. 1 LOST CIRCULATION

Lost circulation is defined as the loss of mud into a porous,cavernous or fractured formation. During well control operationslost circulation is normally caused by induced fractures. Inducedfractures can occur when the fracture pressure of the weakestformation is exceeded. This can happen at any time during initialshut-in or during the actual kill operation.

When addressing the topic of lost circulation, it is important todifferentiate between partial, severe and complete losses. Theremedies for these problems are considerably different. Partiallosses are addressed in this section. Severe and complete loss ofreturns are covered in detail under Tertiary Control.

V.1.1 Recognition of Partial Losses

- Decrease in pit level. This will sometimes be difficult to seebecause of barite additions, possible transfer of mud and, inthe case of a gas kick, a normal gain caused by gasexpansion.

- Drop in gauge pressures. Drillpipe and casing pressures willdrop and neither responds as they should to choke operation.

V.1.2 Well Control Options When Partial Losses Occur

a) If the mud volume can be kept up by mixing, continue killingthe well in a conventional manner; i.e. maintain kill rate pumpspeed and drillpipe pressure as originally planned to keep aconstant bottom hole pressure. Once the influx passes thezone of lost returns, the problem may solve itself.

b) Add lost circulation material to the kill mud (if possible).

c) Stop pumping and shut in. Give the hole time to cure itself.Observe pressures.

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d) If the permeability of the kicking formation is low, thenconsideration could be given to reducing casing pressure toreduce the pressure on the loss zone. However, this couldallow an additional influx into the well. This option should onlybe considered when it is estimated that the volume of thisadditional influx is less than the volume of the original pit gain.Reduce the casing pressure by the estimated annular losses.Be aware that if this annular pressure loss figure is exceeded,the well will go underbalanced and additional influx willoccur. It is important to give proper consideration to thepermeability of the kicking zone to determine the allowablepressure reduction.

When there is a strong possibility of a kick with lost circulation,consideration may be given to installing a circulating sub in theBHA to allow trouble free pumping of LCM.

Judgment on the part of the crew is extremely important whendealing with partial losses during well control. There is no fixed setof rules. The situation will dictate the method of cure. If theproblem persists and losses become severe or complete, thentertiary methods should be considered.

V.2 SNUBBING

When the wellbore pressure acting on the cross-sectional area ofthe pipe in the hole is greater than its buoyed weight, it may benecessary to force the pipe through the preventers. This operationis called snubbing. Pipe is snubbed into the hole until the buoyedweight of the string is sufficient for normal stripping operations.

See the Sedco Forex Snubbing Guidelines for detailed descriptionsof snubbing operations, procedures, and policies.

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V.2.1 Unit Types

Two types of snubbing units are available. The capacity of the unitdepends on the type (snub loads from 50,000 lbs to 350,000 lbs).The stroke length also depends on the type (from 2m to 11 m {6 to36 ft}). A typical equipment arrangement from bottom to topconsists of the following:

- Safety BOP- Lower stripping BOP- Spacer (to equalize pressure)- Upper stripping BOP- Control manifold between lower and upper BOP- Hanger flange- Stripper bowl- Spool access window (to allow introduction of tools)- Stationary slips- Stationary snubbers- Hydraulic power pack with traveling piston (Hydraulic unit

only)- Traveling snubbers

V.2.1.1 Mechanical Unit

Power to force the pipe in the hole is generated by a system ofpulleys and cables or chains attached to the rig traveling block.As the traveling block is pulled upward, the traveling snubbersgrip the pipe and force the pipe into the hole.

V.2.1.2 Hydraulic Unit

The standard hydraulic snubbing unit is self-contained. A travelingsnubber with slips is connected to a piston that supplies the forceto move pipe in the hole. In addition to a set of travelingsnubbers, the unit is equipped with a set of stationary snubbersthat are closed after the piston has moved the pipe the length ofits full stroke. The stationary snubbers grip the pipe and the pistonis retracted. The traveling snubber is then engaged, the stationarysnubbers are opened and the process is repeated.

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V.2.2 Safety Precautions

- The Rig Superintendent must follow-up the completeoperation with the service company.

- Precautions must be taken to protect the personnel from anydanger (broken chain, high pressure lines, etc.)

- When personnel work at heights, safety devices must be used.

- The Rig Superintendent must witness the pressure test jobs.

- Only responsible personnel should be on the snubbing unit.

- The BOP vent line must be carefully orientated according tothe wind direction.

Minimum vent line length: 30 meters (100 ft.)The vent line should never be used as a burn line.

- When running in:The lower BOP must never be opened before thepressures on either side of it are equalized.The upper BOP must never be opened before pressure isbled-off.

V.3 WORKOVER / BULLHEADING

If normal well killing techniques with conventional circulation arenot possible or will result in critical well control conditions,bullheading may be considered as a useful method to improvethe situation. Mud/influx are displaced/squeezed back down holeinto the weakest exposed open hole formation.

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V.3.1 When to Consider Bullheading:

Bullheading may be considered when the following well controlsituations occur:

1) H2S or high pressure gas influx cannot be handled safely byrig personnel and equipment.

2) Normal circulation is not possible because:

- Pipe has been sheared or no pipe in the hole.- String is off bottom.- String is blocked.- String is washed out or parted.

3) A combined kick and losses situation is experienced(downhole annulus bullhead rates must exceed the gasmigration rate to ensure the situation does not deterioratefurther).

4) Kick calculations show that casing pressure duringconventional kill operations will probably result in adetrimental well control situation. (In this case, only the influxneeds to be squeezed back).

Bullheading is not a routine well control method when drilling. Inmany cases, it will be doubtful whether the well can be killed bysqueezing back the influx into the formation and permanent lostcirculation may be created by pumping fluid immediately belowthe shoe into the formation. The method should in most cases beconsidered only as a last resort.

In some instances, such as work-over in cased hole, bullheadingwill be considered as the prime method; in such cases, the choiceof bullheading, shall be made clear in the well plan. Examples ofsuch cases are high pressure/high temperature or H2S wells, killingof well after a well test or before workover operations.

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V.3.2 Prior to Bullheading

- Consider using the volumetric method to eliminate thecomplication of migrating gas. If the gas can be largelyremoved this way, the bullheading operation is likely to bemuch easier and more effective in killing the well.

- Pressure limitations of pumping equipment, wellheadequipment and casing must be kept in mind throughout thebullheading operation.

- If a gas influx is suspected (shut in pressures continue to riseindicating migrating gas), the pumping rate for bullheadingmust be fast enough to exceed the rate of gas migration. Ifpump pressures increase instead of decreasing, it is anindication that the pumping rate is too low to be successful.This can be a problem in large diameter holes. Note thatincreasing the viscosity of the kill mud may or may not behelpful in controlling this problem, and could possibly evenmake it worse.

- There is often a chance, particularly with relatively long openhole sections beyond the last casing shoe, that bullheadingcould break down the formation at the shoe rather than atthe producing formation. In this event, rather than killing thewell, this procedure may aggravate the development of anunderground blowout that could pose risks to nearby wells incommunication with the formations involved. It could alsoincrease risk of a blowout around casing in place withsubsequent obvious risks. Thus, this method should beconsidered when these risks are considered the lesser of thepotential evils.

- A check valve is required between the pumping unit and thewell to act as a failsafe valve in the event surface equipmentshould fail during the procedure. If possible, the cementingunit should be used for better control and adequate pressurerating.

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- Large mud volume and LCM pills should be available in casemajor losses are experienced during the operation.

V.3.3 Procedure for Bullheading

In general bullheading procedures can only be drawn up bearingin mind the particular circumstances at the rig site. During aworkover operation a procedure for bullheading will be drawn upalong the following lines.

1. Calculate the surface pressure that will cause formationfracturing during the bullheading operation.

2. Calculate the tubing (or drillpipe) burst pressure as well ascasing burst (to cover the possibility of tubing failure duringthe operation).

3. Calculate static tubing head (or drillpipe) pressure duringbullheading.

4. Slowly pump fluid down the tubing. Monitor pump andcasing pressure during the operation.

As an example consider the following well which is to be killed bybullheading brine down the tubing:

Depth of formation/perforations at 10,171 feet TVDFormation pressure = 8.8 ppgFormation fracture pressure = 13.8 ppgTubing 4 1/2" N80 Internal capacity = 0.0152 bbl/ft

Internal yield = 8,430 psiShut-in tubing head pressure = 3,650 psiGas density = 0.1 psi/ft

- Total internal volume of tubing= 10,171 ft x 0.0152 bbl/ft = 155 bbl

- Maximum allowable pressure at pump start up.= (13.8 ppg x 10,171 ft x 0.052) - (0.1 psi/ft x 10,171 ft)= 6,281 psi

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- Maximum allowable pressure when the tubing has beendisplaced to brine at 1.06 sg (8.8 ppg).= (13.8 ppg - 8.8 ppg) x 10,171 ft x .052 = 2,644 psi

- Static tubing head pressure at initial shut-in.= 3,650 psi

- Static tubing head pressure when tubing has been displacedto brine.= 0 psi (i.e. the tubing should be dead)

The above values can be represented graphically (as shown inthe Figure V.1 below). This plot can be used as a guide during thebullheading operation.

0100020003000400050006000700080009000

0 50 100 150

Volume of tubing displaced (bbl)

Surf

ace

Pres

ure

(psi

)

Static tubing pressurethat would fractureformationInclude 500 psi safetyfactor (to avoidfracturing formation)Static tubing pressure tobalance formationpressureTubing Burst Pressure

Figure V.1

V.4 DST OPERATIONS

A drill stem test (DST) is a temporary well completion to gatherinformation on potential productivity of a formation. A tool systemconsisting of a packer, flow control valve and pressure recordingdevice is run in the well on the bottom of the drill stem which wasused to drill the well. Sometimes the drillpipe is replaced bytubing.

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Since drill stem testing involves bringing formation fluids to surfacespecial precautions are required to avoid loss of well control.

V.4.1 Basic Precautions for DST

Prior to conducting any DST the BOPs and the gas detectionsystem should be tested.

Drillpipe or tubing can be used for the DST Rotary connections,while metal to metal sealing is not gas tight beyond certainpressures. The expected pressures and type of hydrocarbons arenot always disclosed to the drilling contractor prior to the DST.Prior to testing a zone when high pressure is expected, the RigSuperintendent and the Operator will meet to discuss whethertubing or drillpipe should be used. Any disagreement will bereferred to the Rig Manager. During the test the annulus pressureshould be monitored to ensure a leak does not develop in the drillstem.

All DST work will use a surface tree that enables the drill stem tobe closed in. When wireline is to be used during the test, alubricator will be installed on surface stacks.

When the DST is finished, ensure that the contents of the drill stemare reverse circulated out to mud prior to releasing the packer,when using retrievable packers, or un-stinging from permanentlyrun packers by opening the reverse circulation valve. This valvemay be pressure actuated or operated by dropping a bar or ball,etc.

Special attention should be emphasized for H2S detection. Referto H2S section V.5.

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V.4.2 Special Precautions for Floating Units

Due to bad weather, loss of anchoring, collisions or otherunexpected problems, it is sometimes impossible for the drillingvessel to stay on location. When this happens, it is imperative thatthe well be left under control for prevention of a blowout.

DSTs on floating units must always be conducted with the drillstem hung-off in the BOPs with a subsea master valve installed. (E-Z tree or subsea test tree.) The subsea master valve consists of acombination valve and hydraulic operator powered by a surfacehydraulic power unit via a three-hose bundle. The three hosesprovide hydraulic pressure to hold the master valve open, assistthe valve in closing and unlatch the hydraulic operator from thevalve and test string.

When it becomes necessary to pull off location due to rough seasor other emergencies, the hydraulic latch assembly isdisconnected by hydraulic power from the surface, leaving thewell shut-in and safely under control.

The BOP pipe rams are closed around the slick joint situatedimmediately below the master valve thus sealing off the wellannulus. Following emergency closure of the master valve anddisconnection of the hydraulic operator, the blind/shear rams willbe closed above the master valve during temporaryabandonment.

Ensure enough chiksans or high pressure flexible lines are used toallow compensation for the maximum heave.

V.4.3 Precautions While Testing

- When testing wells containing H2S, NO GAS, no matter howsmall the amount, should be released into the atmosphereunless it is burned on the spot.

- When sampling, the separator must be properly grounded.

- Always open up a well slowly, using the upper master valve.

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- It is strongly advised to use a surface shut-down system in anywell test hook-up.

- Steel hammers or sledge hammers should be banned; brass isa must.

- Never allow a flame or naked light inside the safetyperimeters. All hot work will be suspended.

- Always pressure test the installation prior to well opening.

- When designing a well testing set-up, make sure theequipment planned can safely withstand and handle themaximum wellhead pressure for the portion which may beexposed to such pressure.

- The spacing between the various units comprising a well testhook-up should be effected as per the recommended safetystandards. This applies particularly on land locations.

- Wind direction should be considered when blowing gas intothe atmosphere. Total lack of wind currents may also createhazardous conditions.

- Chain and stake all flow lines very strongly.

- DST tools must not be opened at night without permission atthe District Managers level. The Region EVP may decide thatthis decision will be made at the Region level.

- All units must be properly grounded to prevent risks of ignitionby static electricity.

- See reference document TOP-001 "Drill Stem Tests"

http://sfmdoc.montrouge.sedco-forex.slb.com/sd/sd.nsf/DS/top-001

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V.5 H2S - HYDROGEN SULFIDE

Also see Sedco Forex HSE manual sections 4.2.4 H2S.

V.5.l Properties

Hydrogen sulfide (H2S) is one of the most poisonous of all naturallyoccurring gases. It occurs worldwide in various concentrations inthe scope of the drilling industry. It is extremely toxic and explosiveand heavier than air. In small concentrations it has an offensiverotten egg odor while greater concentrations can paralyze theolfactory nerves so no odor is detected. When ignited it burns witha blue flame producing sulfur dioxide (SO2) which also can causeserious injury.

V.5.2 Drilling Operations

When drilling a well where H2S is suspected, good practicedemands that all personnel be trained in special proceduresrelative to well control, testing and coring. Also, it isrecommended that all H2S equipment be installed and functional300 m (1000 ft) above, or one week prior to, penetration of thesuspected zone, or as necessary to comply with local regulations,whichever is most stringent.

V.5.3 Well Control

- H2S monitoring equipment should be continually surveyedand tested periodically.

- Personnel should be trained in H2S procedures and personalbreathing apparatus usage. See Sedco Forex HSE manualsection 4.2.4.6.

- When H2S is expected to surface, personal breathingapparatus should be worn.

http://sfmdoc.montrouge.sedco-forex.slb.com/sd/sd.nsf/DS/hse-man-04-pr

http://sfmdoc.montrouge.sedco-forex.slb.com/sd/sd.nsf/DS/hse-man-04-pr

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V.5.4 Emergency Procedures

In the event of an emergency situation involving the release ofH2S into the atmosphere, at either the visual or audible alarm, alloff duty and non-essential personnel should immediately securetheir personal breathing apparatus and proceed to thedesignated briefing area upwind of the wellbore.

V.5.5 Special H2S Precautions

If drilling known H2S zones the following should be considered:

- All casing and tubing strings should be J-55, K-55, C-75 and L-80 or softer material or special H2S resistant grades.

- BOPs and wellhead to be H2S trimmed.

- Use Grade 'E' or X-95 drillpipe whenever possible and limit useof Grade 'G' or 'S' drillpipe.

- Treat mud system to a pH of 12 - 13 with caustic soda andmaintain 6 lb/bbl of lime for corrosion protection.

- Treat mud with 5-8 lbs/bbl of IDZAC H2S scavenger (Dowell),1.5-3 lbs/bbl Zinc Carbonate or equivalent chemicals to avoiddrillstring failures.

- Avoid drill stem testing unless with special tools.

- Know maximum allowable over pull on string and avoid it.

- Bullheading shall be the preferred of handling a kickwhenever H2S is suspected

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V.6 WELL CONTROL CONSIDERATIONS - WITH OIL BASED MUD

V.6.1 Kick Detection

Kicks taken while drilling with oil base mud may be difficult todetect due to the serious problems created by gas solubility inmuds. Gas may go into solution during a kick instead of migratingupwards as occurs with water base drilling fluids.

Unless the producing formation becomes considerablyunderbalanced when using OBM, the Driller may not start seeingany changes in pit volumes until the gas influx (in solution in theOBM, therefore, occupying little or no extra volume) has beenpumped a considerable distance up the wellbore. In this case,when the gas saturated mud reaches a location wherehydrostatic pressure falls below the bubble point, the gas will startcoming out of solution causing a very rapid increase in flow. Insome cases this can unload the annulus resulting in large pit gainsand high annulus pressures.

Since kicks can be best controlled if detected when they occurand not when the bubble reaches the surface, the followingprocedures and recommendations should be considered when oilbased muds are in use:

V.6.2 Shut-in Procedures While Drilling

If, while drilling with oil base mud, the Driller encounters anyindication of a kick, i.e., drilling break, increase in flow, pit gain,decrease in pump pressure and/or increase in strokes,consideration should be given to shutting in the well even if a flowcheck proves inconclusive. If there is no indication of flow, it doesnot necessarily mean that a kick has not taken place. It isrecommended that after the well has been shut in that abottom's-up circulation through a fully open choke at a selectedslow circulation rate is carried out. The above course of actionshould be reviewed with the operator prior to drilling with oil basemud. In any event, the drill crew will be informed of theprocedure to take if a kick warning sign occurs.

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V.6.3 Special Precautions - While Drilling

- Gas sensors must be installed.

- Rig Superintendents must be notified of any changes inbackground gas or connection gas.

- At no time will anything such as base oil, oil base mud ordiesel oil be transferred directly from supply boat to theactive mud pits while drilling operations are in progress.

- Flow checks taken after any kick indicators have beenobserved should be extended to between 15 and 30 minutes.

V.6.4 Special Precautions - While Tripping

- While circulating when back on bottom, if flow rate or pit gainindicate a kick, consider completing the bottoms upcirculating through the choke as you would in the Driller'smethod, as it could indicate trip gas rather than an on-bottom influx, and calculations of required kill mud using theordinary well control formulas at this time could result inexcessive formation overbalance.

V.7 KICKS WITH DRILLCOLLARS OR CASING IN THE BOP STACK

V.7.1 Drillcollars

The detection of a kick when the drillcollars are in the BOP stack isa time of concern for the safety of the crew and the drilling unitbecause the normal methods of secondary control using the BOPsmay fail. A kick of this nature can occur when the drillstring isbeing pulled out of the hole and is extremely hazardous for thefollowing reasons:

- As the hydrostatic pressure should always be high enough tobalance the formation pressure prior to pulling out of the

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hole, the kick is probably due to swabbing or a failure to keepthe hole full.

- The force exerted by the wellbore pressure may exceed theweight of the drillcollars.

- The late detection of the kick could indicate that the influx isclose to the surface. The existence of the influx usuallybecomes apparent when the hoisting speed is reduced whilehandling the heavy, cumbersome drillcollars. This is probablydue to the fact that the bubble migration rate and trippingspeed are approximately equal.

- In many cases there is no float valve in the string and it isdifficult to install a full opening safety valve. The annulus canonly be closed by the annular preventer which may not beable to prevent the drillcollars from being lifted if the wellborepressure is high.

When the kick has been detected, the Driller must quickly decidewhether to close in the well and strip/snub to bottom or as a lastresort, to drop the drillcollars. Unless everything is readily availableand the crew is well trained then it may be necessary to drop thedrillcollars and shut the well in with the blind or blind/shear rams.

V.7.1.1 Shut-in Procedure with Surface BOPs

If the well kicks while the drillcollars are in the BOP, the followingprocedure should be followed:

- Position the drillcollars at the rig floor and set the slips.

- Install the appropriate cross-over.

- Pick up a joint or a stand of drillpipe, make-up and run joint orstand into the hole.

- Make up full opening safety valve and close.- Close the annular preventer.

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- Open the hydraulic remote controlled valve and read andrecord pressures and pit gain.

- Install an inside BOP above the safety valve.

The string can now be stripped/snubbed to bottom if necessary. Ifit is necessary to control the well at the present depth thenprovision should be made to secure the drillpipe to the rotarytable with chains.

V.7.1.2 Shut-In Procedure for Floating Units

If there is a certain amount of heave present there are twoproblems with shutting in around the drillcollars. Firstly, with asubsea stack you cannot hang-off to prevent relative motionbetween the annular preventer and drillcollars.

Secondly, to enable pumping and reduce the relative motionbetween the collar and annular preventer and support the string,the motion compensator system must be used. This takes a certainamount of time and still presents a questionable situation.

V.7.1.3 Dropping the Drillcollars

A quick decision may have to be made by the Driller to drop thedrillcollars. The success of this "last resort" method depends on theseverity of the kick and quick implementation of the correctprocedure.

One procedure for dropping the drillcollars is as follows:

- Position the elevators near the floor.

- Close the annular preventer such that the elevators can beopened.

- Open the annular preventer to drop the drillcollars.

- Close the blind or blind/shear rams.

- Read and record shut-in pressure and pit gain.

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V.7.1.4 Special Consideration

- When the string is out of hole the drillcollars should be rackedin such a way that the drillpipe can be run in the hole first.Access to the stand with the drillpipe to drillcollar x-overshould be maintained at all times.

V.7.2 Casing

Precautions To Take When Running Casing:

- On Surface stack: Change the rams to the casing size and testthe BOP bonnets.

- Prepare a circulating head.

- Floating rigs: Ensure a cross-over from casing to DP is madeup to a stand of DP and stood back in the derrick to allow thestring to be hung off if needed.

- Take care while filling up the casing. Use clean mud andensure that junk does not fall into the casing.

- Record the annular volume between the casing and openhole and outer casing.

- Calculate the running speed to allow an acceptable fluidvelocity and a limited surge into the open hole.

- A record of the tank level is necessary and should becompared with the calculated volume increment due to themetal displacement of the casing.

- In case of a kick while RIH casing, if the shoe cannot bepulled above the shear/blind rams, the casing rams should beclosed (surface BOP) or the annular preventer shut-in (subseaBOP).

- Prior to doing so, a circulating head should be installed incase of float equipment failure.

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- Due to the large size of the string, the weight of the casingmay not be sufficient to overcome the force pushing thecasing out. The circulating head must be chained to thesubstructure if necessary.

V.8 HYDRATES

(Also see section VI.1 concerning Deepwater)

Hydrates are a complex crystalline structure of hydrocarbons andwater. In simple terms, a hydrate is a frozen gas, commonlymethane.

V.8.1 Formation of Hydrates

The formation of hydrates is dependent upon a combination ofthe following conditions:

- Presence of free water.- Presence of hydrocarbon gas.- Low temperature.- High pressure.

It is aggravated by pressure drop/gas expansion (e.g., through achoke) and pressure pulsation. Hydrates usually occur inproduction and drilling operations in cold where they can be aroutine occurrence. However, hydrates can also be found invarious other operations, especially with subsea systems used indeepwater. The figure below (Fig. V.2) shows the conditions whichhydrates can form.

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Hydrate Formation

100

1000

10000

100000

-5 0 5 10 15 20 25 30Temperature, deg. C

Pres

sure

for h

ydra

te fo

rmat

ion,

kPa

Methane0.6 Gravity Gas0.70.80.91

Hydrate Formation

Area

SafeArea

Figure V.2

V.8.2 Well Control Considerations

Hydrates can cause severe problems by forming a plug in valvesor chokes completely blocking flow. Upstream pressure thenincreases which compounds the problem. The two critical areasare the passage in to the choke line through the failsafe valvesand at the choke itself. The resulting pressure drop as the gaspasses through these restrictions and the sudden increase invelocity causes expansion cooling of the gas immediatelydownstream of the choke. Prevention of hydrate formation is agreat deal less difficult than removal of hydrates once they have

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formed. In areas where hydrate formation is possible it is essentialthat at least one of the four conditions necessary for hydrateformation is controlled in such a way that hydrate formationcannot occur.

It may be necessary to inject methanol to suppress hydrateformation. This is normal practice on surface choke manifolds andcould also apply at the SS BOP stack. If hydrates do form and plugoff a choke or line they can be very difficult to remove.Considerable heat is required for decomposition. Suchdecomposition can be explosive since once the process begins itwill continue extremely quickly. The best method of decomposinghydrates is to circulate hot brine solution.

V.8.3 Drilling Considerations

Obviously, if an oil based mud is being used there is no furtherproblem. With water based muds, maintaining a high chlorideconcentration in the mud will serve to lower the freezing point. Afurther precautionary method is to displace the choke and killlines to methanol, which will prevent hydrate formation in the BOPstack. For methane, hydrates will form at pressures of 2620 kPa(380 psi) and temperatures up to 0°C (32°F). At 34,500 kPa (5000psi) the temperatures must be less than 24°C (75°F).

V.8.4 Prevention of Hydrates

Hydrates are much easier to prevent from forming than to removeonce they have formed. Prevention can be achieved as follows:

• Inside the Wellbore:

- Primary good well control practices to minimize gascoming from the formation.

- Reducing free water by using oil based mud ormaximizing the chloride content of a water based mud.

- Maintaining temperature as high as possible.

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- Injecting methanol or glycol at a rate of 2-4 liter (0.5-1gal.) per minute on the upstream side of a choke or line.

• Outside the Wellbore:

- Hydrates could form on the outside of the BOP stack indeep water wells. See Section VI.1.2 External Hydrates inWellhead Connector.

V.9 NO CIRCULATION

V.9.1 Plugged Bit

If we cannot re-establish circulation by increasing the pumppressure, a wireline operation should be planned to try to openthe bit with a string shot or perforate as far down the string aspossible.

While rigging up to perforate, the following should be carried out:

- Observe SICP for gas migration. If gas migration is suspectedconsider using the volumetric technique.

V.9.2 Bit Out of Hole

If the well kicks when the bit is out of hole and it is impossible toget back into the hole with the BOP open, the well must be shut-inwith the blind or blind/shear rams and the well pressure observed.Stripping procedures can be planned according to the wellpressure.

A calculation must be made to check if the upward force isgreater than the weight of the drillstring (float valve is installed atlower end of the string).

FORCE = PRESSURE x AREA

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We must add the friction generated through the annularpreventer (5-10 tons). If the upward force due to the well pressureacting on the lower end of the string is greater than the weight ofthe string, it will be necessary to force the pipe through thestripping preventer by means of snubbing operation. Dependingon preparation time to apply the technique chosen, the surfacepressure can be reduced according to the volumetric technique.As an alternative, bullheading may also be considered.

V.10 DETERMINING SHUT-IN DRILLPIPE PRESSURE WITH AFLOAT VALVE IN DRILLSTRING

There are a number of methods that can be utilized to open afloat so shut-in drillpipe pressure can be determined. The two mostwidely applied methods are as follows:

V.10.1 Method 1

- Pump into the closed in wellbore through the drillpipe at aslow rate and closely monitor drillpipe and shut-in casingpressure.

- When the rate of increase of the DP pressure changessignificantly, or the casing pressure just begins to rise, shut offthe pumps and record the drillpipe pressure. This value will bethe shut-in drillpipe pressure.

V.10.2 Method 2

- Bring pump to speed holding a constant casing pressure (forsubsea stacks, reduce casing pressure by choke line friction lossif known).

- When the pump is up to kill rate speed, switch to the drillpipegauge and read initial circulating pressure.

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- Subtract the slow circulation rate pressure from initialcirculating pressure. This value will be the shut-in drillpipepressure. See figure V.3.

Figure V.3

V.11 WIRELINE IN BOPS/LUBRICATORS

V.11.1 Wireline Operations Without Specialized Wellhead Equipment

Many wireline operations are conducted using drilling fluidhydrostatic pressure as the primary means of pressure control withthe rig BOP equipment as the second line of defense againstformation pressures. In this situation, it should be possible tocontrol the well in the same way you would when all the pipe isout of the hole. In the event that a flow occurs, the rig BOPs would

700

0

Well Sta tic Pump to Sp eed

700

900

S I D P P S I D P P

S I C P S I C P

S C R P = 300 p si @ 30 SPMS I D P P = ICP - S C R PS I D P P = 900 p si - 300 p siS I D P P = 600 p si

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be used to maintain control until a procedure was followed thatwould kill the well. Several points should be kept in mindwhenever this type of logging operation is in progress:

- It is the responsibility of the driller to continuously monitor thewell during logging operations. This should be done bycontinuous circulation over the hole using the trip tank system.Fluctuation in trip tank level due to wireline displacement ofmud, tides or draft changes on floating rigs or system orwellbore fluid losses should be investigated and confirmed.

- If a flow occurs, the annular BOP should be closed andlogging unit notified, preferably before closure is complete.Shear/blind rams are to be used as a last resort only. If thisbecomes necessary on a rig equipped with blind rams only, itis advisable to cut the wireline and drop the tool string toclear the rams prior to closing them. A suitable line cuttershould be kept available on the floor for this purpose in anemergency.

- If well flow or excess fluid loss is considered likely, specialtools may be available to tie rig BOPs back to wirelinewellhead equipment which would afford more well controloptions or would allow well closure without damage towireline. Utilization of this equipment would require advanceplanning in consultation with the wireline contractor.

- Before any wireline operation begins, all drilling personnelshould be involved in a safety briefing during which wellcontrol options and responsibilities should be clearly defined.

V.11.2 Wireline Operations With Specialized Wellhead Equipment

V.11.2.1 Equipment Requirements

When conducting wireline operations during which BOPs areexpected to provide the primary means of well control (duringwell tests, perforating or workover operations, etc.), dedicatedpressure control equipment including BOPs, risers, safety valves

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and flow tubes (grease injection heads) must be used. Thisequipment must be capable of the following:

- Sealing around the specific wireline in use while the tool stringis down-hole.

- Providing a method of closing the well in completely whenthe tool string is in the riser or is being changed out.

- Closing the well in without reliance on external pressure orpower sources (i.e., equipped with a failsafe shut-in system)with or without wireline in the hole.

To satisfy the requirement of sealing around multi-strand wirelinecables as well as to allow them to move through the pressurecontrol equipment while well pressures are being contained,various grease injection equipment is utilized. Flow tubes matchedto the wireline in use require injection of viscous grease (atinjection pressures exceeding the well pressure to be contained)to maintain a pressure-tight seal around wireline. The properchoice of grease and good operational procedures (like limitingrunning speeds in and out to reasonable levels to minimize wearof close tolerance parts) are critical to maintaining sealingcapability.

V.11.2.2 Equipment Considerations and Safety

When using wireline wellhead pressure control equipment severalpoints should be kept in mind:

- Before the operation begins all drilling personnel should beinvolved in a safety briefing during which well control optionsand responsibilities should be clearly defined. Sufficientlydetailed instructions must be given to drilling personnel toenable them to close the well in under any foreseeablecircumstance.

- The relationship of rig BOPs to the operation in progress must bekept clear to all involved.

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- Wireline wellhead equipment should be used only for thespecific purpose for which it was designed. For example,don't use a pack off or stuffing box as a line wiper.

- Be sure that wireline BOP equipment is installed the right wayup. Note that an individual ram type BOP may be intentionallyused upside down if it is to be used in conjunction with greaseinjection equipment and a second, right side up BOP ismounted above it. This arrangement may be necessary tocontrol a flow of gas or if high pressures are expected.

- When two right side up BOPs are installed, close the top onefirst and only the top one. The second BOP should be usedonly if the closing operation needs to be repeated and thetop BOP fails. This allows you, in an emergency, to replace thetop BOP rams. NEVER CLOSE BOTH BOPS AT ONCE.

- A gate valve capable of cutting the wireline is recommendedin addition to (and located above) wireline BOPs wheneverthe drilling rig BOPs are not in use.

- When an inverted BOP is used below an upright BOP, a gastight seal on multi-strand cables may be effected by pumpingviscous grease into the space between the BOPs with a highpressure pump. The sealing effectiveness is a function of thegrease viscosity. If sufficiently viscous grease is not available,an emergency solution is to inject rubber bands by inserting10-20 of them in the grease injection hose. In any case,routine operations should not be commenced until a suitablereserve of injection grease is available on the rig floor.

- Wireline BOPs may be capable of sealing on an open holebut this ability should not be relied on and is very likely todamage the rubber sealing elements. The primary purpose ofthese BOPs is to allow closures around cable to enable repairsto be carried out on the cable while pressure is contained.

- Be aware of pressure ratings and limitations of equipment inuse.

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- For reference see Wireline and Testing's "Pressure OperationsGuidelines" on the internet at:http://wth.montrouge.wireline.slb.com/qhse/risks//pressure/start.html

V.12 EMERGENCY DISCONNECT OPERATIONS DURING WELLKILL OPERATIONS (MOORED FLOATING UNITS)

There are several situations that could arise during well controloperations that may require disconnecting the lower marine riserpackage and moving off the well site.

V.12.1 Conditions That May Require a Disconnect

- If the BOPs become unsafe due to high annular pressures orbecause of equipment failure.

- Vessel movement due to adverse weather conditions (Failureof anchor chains.)

V.12.2 Procedures for Emergency Disconnect - Time Permitting

- Pump down drop in back pressure valve until dart bumps indart sub, while controlling annulus pressures.

- After dart bumps, bleed off drillpipe pressure and observe tosee if dart is holding pressure.

- If dart is holding pressure, close lower pipe rams - assumingstring is already hung off on upper pipe rams.

- Displace riser with sea water.- Close failsafes.- Shear pipe.- Disconnect lower marine riser package and confirm

disconnect.- Slack off guide line tensioners.- Move rig off location.

http://wth.montrouge.wireline.slb.com/qhse/risks/pressure/start.html

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V.12.3 Procedures for Emergency Disconnect - No Warning

- Stop pumping.- Close failsafes.- Close lower pipe rams (assuming string is already hung off on

upper pipe rams).- Shear Pipe.- Disconnect lower marine riser package and confirm

disconnect.- Slack off guide line and move rig off location.

V.13 WELL CONTROL OPERATIONS AFTER SHEARING PIPE(MOORED FLOATING UNITS)

V.13.1 Procedures for Re-connecting

Move rig back to well site. Run and latch lower marine riserpackage. Displace riser with kill mud.

Open choke line failsafe and observe drillpipe pressure (there willbe no pressure if dart is holding). If pressure is observed, either thedart is not holding (though kill procedures can continue) or youshould consider the possibility that the string has been dropped. Inthis case, the choke and kill line pressures would be the same andthe only well control options would involve the use of thevolumetric method or bullheading to kill the well.

Open kill line failsafes below lower pipe rams and observe casingpressure.

Pump down choke line to ensure that circulation through dart ispossible. Observe pressure increase on kill line gauge.

If circulation is possible then continue to kill well using choke linegauge as drillpipe pressure and kill line gauge as casing pressure.Be sure to re-establish circulating pressures as previous slowcirculating rate figures will no longer apply.

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If circulation is impossible then consider bullheading or volumetriccontrol.

V.14 TERTIARY CONTROL

In the event that secondary control cannot be properlymaintained due to hole conditions or equipment failure, certainemergency procedures can be implemented to prevent the lossof control. These procedures are referred to as "Tertiary Control"and usually lead to partial or complete abandonment of the well.

Unlike primary and secondary control, there are no establishedtertiary well control procedures that will work in most situations.The procedures to be applied depends on the particularoperating conditions which are encountered, and specificrecommendations regarding appropriate tertiary controlprocedures cannot be given until the circumstances leading tothe loss of secondary control are established.

However, there are two procedures that are widely used. Theseinvolve the use of:

- Barite plugs- Cement plugs

V.14.1 Barite Plugs

A barite plug is a slurry of barite in fresh water or diesel oil which isspotted in the hole to form a barite bridge that will seal theblowout and allow control of the well to be re-established.

The plug is displaced through the drillstring and, if conditionsallow, the string is pulled up to a safe point above the plug. Thebarite settles out rapidly to form an impermeable mass capable ofshutting off high rates of flow.

The effectiveness of a barite plug derives from the high densityand fine particle size of the barite and its ability to form a tough

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impermeable barrier. To be effective, the slurry must have thefollowing properties:

- The viscosity and yield point should be as low as possible toensure a rapid settling rate and prevent channeling. Highquality barite with low clay content should be used wherepossible.

- The slurry should have a high density: at least 360 kg/m3 (3ppg) greater than the mud density.

- The fluid loss should be high to allow rapid dehydration of theslurry. The high fluid loss can sometimes cause the hole toslough and bridge itself.

A barite plug has the following advantages:

- It can be pumped through the bit and offers a reasonablechance of recovering the drillstring.

- The material required is normally available at the rig site.

- The plug can be drilled easily if required.

The main disadvantage is the risk of settling and consequentplugging of the drillstring if pumping is stopped before the slurryhas been completely displaced.Two types of barite slurries can be used:

- Barite - fresh water slurry

- Barite - diesel oil slurry

Other materials can be used if a very high slurry density is requiredto stop the flow so that the slurry will settle. Ilmenite and galenahave been used in the past and micaceous hematite is potentiallyuseful. All of these materials have a higher density than barite.

Regardless of the materials used, all slurry formulations should bepilot tested to ensure settling and dehydration.

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Barite - Fresh water slurry:

The amount of barite and fresh water required to formulate 0.16m3 (1.0 bbl) of slurry at various densities is shown in the tablebelow:

REQUIRED VOLUME OF WEIGHT OFDENSITY FRESH WATER BARITE

kg/l (ppg) m3 (bbl) kg (lb)

2.15 (18) 0.102 (0.642) 240 (530)2.40 (20) 0.089 (O.560) 292 (643)2.51 (21) 0.084 (0.528) 315 (695)2.63 (22) 0.078 (0.490) 340 (750)

A complex phosphate, such as sodium acid pyrophosphate orsodium hexametaphosphate, should be added to act as a thinnerin case of contamination by mud in the annulus or by low qualitybarite. The concentration required is 2 kg/m3 (0.7 lb/bbl). It shouldbe noted that the complex phosphates will thermally degrade ifthe down hole temperature exceeds 60°C (140°F). If this is thecase, a mixture of lignosulphonate 1.14 kg/m3 (0.4 lb/bbl) andcaustic soda 0.71 kg/m3 (0.25 lb/bbl) can be used instead.Optimum barite settling is achieved by adjusting the pH to 8-10with 0.71 kg/m3 (0.25 lb/bbl) of caustic soda.

Barite plugs should be prepared using fresh water. Consequently,care should be taken to avoid contamination by saline formationwater or drilling mud during the displacement.

Barite - Diesel Oil Slurry:

A barite plug derived from a barite - diesel oil slurry is preferred inoil based or invert emulsion muds. However, a barite - fresh waterslurry can be used provided there is a diesel oil spacer ahead ofand behind the slurry.

The amount of diesel oil and barite required to formulate 0.16 m3

(1.0 bbl) of slurry at various densities is given in the table below:

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REQUIRED VOLUME OF WEIGHT OFDENSITY DIESEL OIL BARITE

kg/l (ppg) m3 (bbl) kg (lb)

2.15 (18) 0.097 (0.610) 259 (572)2.40 (20) 0.086 (0.541) 308 (679)2.51 (21) 0.080 (0.503) 331 (730)2.63 (22) 0.075 (0.471) 354 (781)

An oil wetting agent is added to increase the settling rate at aconcentration of 14.0 kg/m3 (5.0 lb/bbl).

Displacement

Since the barite plug slurry contains no suspending agent for thebarite, the surface mixing facilities and plug placement must becontinuous and rapid. If the mixing or pumping is halted for evena short time, settling in the pits or plugging of the drillstring willoccur. It is possible to batch mix and displace the slurry using therig pumps. However, it is preferable to mix and displace the slurrywith a cementing unit since normal surface rig facilities are notsuitable due to their low mixing rates. Using the cementing unitgives more accurate volume control.

A minimum final plug length of 60 meters (200 ft) and not less than1.6 m3 (10 bbl) volume should be used to ensure a good seal andallow accurate displacement into the wellbore.

V.14.2 Cement Plugs

A cement plug can be used to shut off a downhole flow.However, this generally involves abandonment of the well andloss of most of the drilling tools.

Cement plugs are set by pumping a quantity of quick setting(accelerated) cement into the annulus via the drillstring. Thecement is usually displaced until the pump and choke pressures

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indicate that a bridge has formed. Quick setting cement reducesthe possibility of gas cutting.

If a cement plug has to be set off bottom with mud below it, thenconsideration should be given to spotting a slug of viscous mudbelow the zone to be plugged. This precaution should beconsidered in long or deviated holes or when the cement slurry issubstantially heavier than the mud.

Setting a cement plug offers little chance of recovering thedrillstring. It is also likely that the string will become plugged afterpumping the cement, precluding any second attempt if the firstshould not succeed. Therefore, cement plugging should beregarded as the final option.

V.15 TRAPPED GAS IN SUBSEA BOP STACKS

Trapped gas in a subsea BOP stack can lead to serious problems ifnot handled correctly. Significant gas accumulation can occur,increasingly so as the water depth increases. The amount of gastrapped in the stack depends on the volume between thepreventer in use and the choke line outlet. The object of theprocedure presented below is to allow the major portion of gastrapped in the BOP to vent up the choke line by allowing it toexpand against water (or base oil if using OBM) hydrostatic. If thefollowing is carried out correctly, trapped gas can be evacuatedfrom the BOP 's in a controlled fashion.

- Isolate the wellbore by closing a set of pipe rams: either loweror middle pipe rams (a flow path from the kill line across thetop of the closed rams and up the choke line must beavailable).

- Displace kill weight mud by pumping water (or base oil ifusing OBM) down the kill line and up the choke line, holdingback pressure on the choke equal to the hydrostatic pressuredifference between the kill mud and the water (or base oil).However, in deepwater situations fresh water or seawater

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may not be acceptable as it may allow the formation ofhydrates. A water/glycol or another type of low-densityinhibited mixture should be used. See sections V.8 and VI.1 formore information

- When returns are clear water, stop pumping and close thechoke holding the same back pressure.

- Close kill line.

- Bleed the pressure from the choke line allowing water andgas to escape from the choke line.

- Once the flow stops, close diverter, open fill-up line and fillhole from top, and open annular. Take returns through chokeline.

- When well is static, circulate kill mud up the riser.

V.16 EQUIPMENT PROBLEMS

V.16.1 Choke

When the well is controlled using the Driller's method or the Waitand Weight method, constant pump strokes must be maintainedto detect any change in the circulating system i.e., choke wash-out.

If an abnormal decrease of DP pressure and CSG pressure isnoticed it is possible that a washed out choke is the cause.

If a washed choke is suspected the well should be shut-in. Thesecondary circuit using spare adjustable choke will be prepared.Well control procedures will be re-established using the spareadjustable choke.

Immediate repair action on the washed-out choke will becommenced.

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V.16.2 Annular Preventer

The most vulnerable part of the annular preventer is the rubberpacker unit which is subject to wear. The annular should never beclosed on open hole during function testing as this will shorten thelife of the packing unit.

When packing unit leakage occurs during kick control, pipe rampreventers will be closed and, if necessary, a second set of rampreventers should be equipped with pipe rams before the killingoperation is resumed.

Packing Unit Replacement with Drillpipe in Hole (Surface Stack)

- Disconnect bell nipple.- Remove BOP Head.- Attach and secure BOP head and bell nipple under rotary

table.- Cut with knife and remove worn, packing unit.- Cut new packing unit, for easier cutting exert tension

between segments, use knife and water. (Do not use a saw orother rough cutting tool.)

- Install the new packing unit.- Replace BOP head and bell nipple.

V.16.3 Ram Packer Damage

To prevent rapid deterioration of ram packers the followingprecautions should be observed:

- Recommended hydraulic pressure will be used to operate rampreventer 10,500 kPa (1500 psi). (Higher pressures may berequired to shear pipe with shear rams.)

- Never close on open hole during function tests.

Under severe well control conditions failure of ram packers canoccur. On floating units, the next lower set of rams of correct sizewill be closed.

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On surface stacks, where only one other set of rams is available,the bottom ram (emergency) will be closed and the ram packerswill be changed before the killing operation is resumed. If duringthe time necessary to change ram packers the surface pressuresincrease, the DP pressure may be kept constant, if necessary andsafely feasible, by bleeding through the stand pipe manifold. Iftwo or more rams are still available, the MIC will decide whetherto change the damaged rams or continue with the kill.

V.16.4 Mud Pump Problems

Efficiency of the pump(s) is very important in all well controlcalculations. The Rig Superintendent has to know the efficiency ofthe pump(s) at low rate (which can be different than high rateefficiency).

If pump failure occurs during kick control, this can be observedby:

- Rotary hose vibration.- Variation in DP pressure.- Peaks of pressure on DP pressure gauge.- Pump hydraulic knocking.

If any of the above indicators are noticed, the well should beshut-in and the following action taken:

- Isolate the pump.- Line up the reserve mud pump.- Resume the kick control operation.- Repair the failed pump immediately.

If the second pump fails when the first one is still under repair thekick control will be stopped and well shut-in. Bottom hole pressurecan be kept constant by maintaining a constant DP pressure,bleeding off as necessary through the choke.

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V.16.5 Kelly Mud Saver Valves

Since approximately 1,400 kPa (200 psi) may be required to openthese valves (such as Drilco Mud-Check) a shut in drillpipepressure of less than 1,400 kPa (200 psi) will not be accuratelyregistered.

A possible way to overcome this drawback after shutting in thewell would be:

l) Close the bottom kelly safety valve.2) Bleed off pressure on standpipe manifold.3) Open bottom kelly safety valve.4) Record drillpipe shut in pressure.

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V.17 CHOKE LINE FRICTION

V.17.1 Pressure Losses in Subsea Kill Operations

In subsea situations, a pressure loss existswhen circulating through the choke due tothe friction losses in the extended choke linerunning up from the BOP. This pressure loss isnot accounted for in normal slow CirculatingRate measurements, which are taken whilecirculating up the marine riser (see FigureV.4).

If the normal method of bringing a pump tokill speed is followed (that is, choke manifoldpressure maintained equal to SICP until killrate is achieved), bottom hole pressure willbe increased by an amount equal to thischoke line friction loss (CLFL). This excesspressure can result in serious lost circulationproblems during the kill operations.

Since fracture gradients generally decreasewith increased water depth, correcthandling of the CLFL becomes more criticalas water depth increases. Beyondapproximately 150 meters (500 ft) waterdepth, it should always be considered whileplanning well control operations.

It is possible to measure CLFL (without a BOPpressure sensor) while taking SCRs. Onesimple way to do this is to pump down thechoke line at reduced pump rates (takingreturns up the open marine riser as is shownin Figure V.5) and record the pressurereading on the choke manifold gauge.

500p si

Figure V.4Conventiona lSCRP Flow Pa th

Sha ker

0p si

Figure V.5CLFL Mea surement Pump ingDow n Choke Line CLFL - 200 p si

Drill p ip e

Sha kers

200p si

From Pump

Choke

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V.17.2 Bringing Pump Up To Kill Rate Speed (Non Instrumented BOP)

(See VI.7.4 for instrumented BOP)

It is fundamental to all standard methods of well control to maintainconstant bottom hole pressure (BHP) throughout kill operations. Toaccomplish this a method must be used to keep total appliedcasing pressures relatively constant while bringing the mud pump tokill rate.

In the absence of significant CLFL (surface stacks or shallow water),the method used is to merely keep choke manifold pressure equalto SICP until the pump is up to speed.

But when CLFL exists, total applied casing pressure varies from SICPat pump start-up to SICP + CLFL with the pump at kill rate, if theabove method were used. This would cause bottom hole pressure toincrease by an amount equal to CLFL, as shown in Figures V.6 andV.7.

500p si

Fig ure V.6Pf = 5,000 p siPh = 4,300 p si ( in a nnulus )Pump o ff ( kic k shut in )

Drill p ip e

700p si

Choke

1200p si

Figure V.7Pf = 5,000 p siPh = 4,300 p si ( in a nnulus )Pump a t kill ra te hold ing c onsta ntc hoke ma nifo ld p ressureCha nge in BHP = 200 p si inc rea se

Drill p ip e

700p si

Returns

Choke

Choke Ma nifo ld Choke Ma nifo ld

CLFL 0 p si ( sta tic )

APL 0 psi

Sub seaBOP

Sub seaBOP

CLFL200 p si( d yna m ic )

APLNegligible

BHP 5,000 psi BHP 5,200 psi

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To eliminate this problem, two methods exist. First, by reducingchoke manifold pressure by an amountequal to a known CLFL (adjustingchoke manifold pressure to SICP -CLFL), the effect of the CLFL isnegated. This is accomplished byreducing the original SICP by theamount of CLFL while bringing thepump to speed (see Figure V.8).

Reduced

casing = Shut - in casing pressure - Choke line

pressure losspressure

In the example: SICP = 700 psiCLFL = 200 psi

Reduced Casing Pressure, psi= 700 psi - 200 psi = 500 psi

A pressure chart must be created forbringing the well on choke. Thepressure vs. stroke relationship is not astraight line effect. While bringing the well on choke, to maintaina constant bottom hole pressure, the following chart should beused:

Example kill rate speed = 50 spm Pressure Chart

SPM Pressure

Line 1: Reset stroke counter to "0" = 0Line 2: 1/2 stroke rate = 50 x .5 = 25Line 4: 3/4 stroke rate = 50 x .75 = 38Line 4: 7/8 stroke rate = 50 x .875 = 44Line 5: Kill rate speed = 50

To complete the chart divide the choke line loss (CLFL) by 4,because there are 4 steps on the chart:

1000p si

Figure V.8Pf = 5,000 p siPh = 4,300 p si ( in a nnulus )Pump a t kill ra te w ith red uc edma nifo ld p ressureChange in BHP = 0 psi

Drill p ip e

500p si

Returns

Choke

Choke Ma nifo ld

Sub seaBOP

CLFL200 p si( d ynam ic )

APLNegligible

BHP 5,000 psi

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psi / line = (CLFL) 200 psi

4 = 50 psi

SPM Pressure

Line 1: Shut-in casing pressure, psi = 0 700Line 2: Subtract 50 psi from line 1 = 25 650Line 4: Subtract 50 psi from line 2 = 38 600Line 4: Subtract 50 psi from line 3 = 44 550Line 5: Subtract 50 psi from line 4 = 50 500

Once kill rate has been reached, the choke operator switchesover to the drillpipe gauge and follows the drillpipe pressuregraph in the usual way.

Or secondly, given a choke manifold configuration with separatepressure gauges for choke and kill lines, it is possible to utilize thekill line (shut off down-stream of the gauge outlet to prevent flow,thus eliminating friction) as a pressure connection to a pointupstream of any potential CLFL (known or unknown). This is shownin Figure V.9. If the kill line gauge in this instance is kept constantwhile bringing the pump to speed, the effect of CLFL is eliminated.

Note the advantages of the second method:

1) The gauge reading choke manifold pressure will show adecrease after pump is up to speed. The amount of thisdecrease is equal to the CLFL.

2 No pre-calculated or pre-measured CLFL information isrequired.

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3) The kill line gauge can besubsequently used like the chokemanifold pressure gauge on a surfacestack for the purposes of altering pumprates or problem analysis.

NOTE : If the second method ofhandling the CLFL situation if preferred,it would be advisable to rig a remotekill line pressure gauge which could beseen by the choke operator.

It is extremely important to note thatregardless of which method is used,they both accomplish the goal ofmaintaining constant bottom holepressure equal to formation pressure,just as would be the case were CLFLabsent. This is done without the needto alter any calculations on the kicksheet. Thus initial and final circulatingpressures, which are read on the drill

pipe gauge, are unaffected by CLFL. CLFL is recorded on the KickSheet for convenience only—it is not used in kick sheetcalculations.

Several additional points should be made about CLFL. It should benoted that it will only be possible to use the above recommendedmethods when SICP is greater than CLFL. If this is not true, it will beunavoidable to apply excess pressure to the bottom of the holeusing standard well control procedures. Also, as kill mud comes upthe annulus, total applied casing pressure needed to maintainconstant bottom hole pressure will eventually drop below CLFL.After this point, drillpipe pressure will exceed planned FinalCirculating Pressure in spite of having the choke wide open withno choke manifold back pressure.

1000p si

Fig ure V.9Pf = 5,000 p siPh = 4,300 p si ( in a nnulus )Pump a t kill ra te ho ld ing c onstantkill line p ressureChange in BHP = 0 psi

Drill p ip e

Returns

Choke

Choke Ma nifo ld

Sub seaBOP

500p si


APLNegligible

BHP 5,000 psi

700p si

KLFL0 p si( sta tic )

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These situations can be mitigated by use of unusually slowpumping rates or by taking returns up choke and kill linessimultaneously. Figures V.10 to V.13 illustrate this problem andmethods of dealing with it. They show an example in which SICP is100 psi, which is less than the 240 psi pressure loss in the choke linewhile pumping at 4 bbl/min.

75p si

Figure V.10Pf = 5,000 p siPh = 4,900 p si ( in a nnulus )Pump s o ff ( kic k shut in )SCRP @ 4 bb l/ m in = 800 p siSCRP @ 2 bb l/ m in = 200 p siCLFL @ 4 b b l/ m in = 240 p siCLFL @ 2 b b l/ m in = 60 psi

Drill p ip e

100p si

Choke

1015p si

Figure V.11Pf = 5,000 p siPh = 4,900 psi ( in a nnulus )Pump a t 4 b b l/ m in ho ld ing 0 p sic hoke ma niflod p ressureCha nge in BHP = 140 p si inc rea se

Drill p ip e

0p si

Returns

Choke

Choke Ma nifo ld Choke Ma nifo ld

CLFL 0 p si ( sta tic )

APL 0 psi

Sub seaBOP

Sub seaBOP


APLNegligible


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Returns

40p si


875p si

Fig ure 13Pf = 5,000 p siPh = 4,900 psi ( in a nnulus )Pump a t 4 b b l/ m in using c hoke andkill line fo r re turn flowCha nge in BHP = 0 p si

Drill p ip e

Choke

Choke Ma nifo ld

Sub seaBOP

APLNegligible

BHP 5,000 psi

275p si

Figure 12Pf = 5,000 p siPh = 4,900 p si ( in a nnulus )Pump a t 2 b b l/ m in w ith red uc edc hoke ma nifo ld p ressureCha ng e in BHP = 100 p si inc rea se

Drill p ip e

40p si Choke

Choke Ma nifo ld

Sub seaBOP

CLFL60 psi( d yna m ic )

APLNegligible

BHP 5,000 psi

40p si


Returns

Choke

4 bbl/min

V.18 DETERMINING THE CORRECT BOTTOM HOLE PRESSURE:TRAPPED PRESSURE.

Any time the circulation is stopped and the choke is closed duringa kill operation, there is a risk to dynamically trap pressure in thewell. Before the operations are resumed, it is important to removethe trapped pressure in order to ensure that the Bottom HolePressure (BHP) is equal to the Formation Pressure (Pf) so that noadditional pressure is maintained on bottom over Pf.

Other circumstances that can result in trapped pressure includeinflux migration and stripping drillstring without bleeding mud.

It is generally recommended not to stop circulation once the killoperations have started. If, at any time there is a doubt

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concerning the drillpipe pressure to be maintained, for examplewhen problems such as drillstring wash-out or plugged bit areexperienced, it is advisable to stop circulating and to determinethe correct back pressure required, using the method describedbelow. The pressure read on the drillpipe pressure gauge when, atany time, the circulation is stopped is called the NEW StaticDrillpipe Pressure (NSDPP) to distinguish it from the INITIAL SIDPP.

1) Determine the expected NSDPP : this pressure depends on theposition of the kill mud inside the string; until kill mud ispumped in the pipe, NSDPP should remain equal to theoriginal SIDPP; after the kill mud has reached the bit, NSDPPshould be zero; when the kill mud only partially fills the string,the expected NSDPP is found using the kill sheet as shownbelow.

Kill Gra p h

ICP

SIDPPDP C irc . Press.

FCPSta tic DP Press.

0

C irc . Stop p ed Here

1 Exp ec ted NSDPP

Figure V.14

2) If the pressure measured on the DP gauge significantlyexceeds this expected value, continue with step 3 belowotherwise continue with step 5.

When significant difference is found between the measuredand the expected new static drillpipe pressure (NSDPP), thereason for the difference may be due to dynamically trappedpressure or to a greater than expected difference between Pfand the drillstring hydrostatic pressure (PhDS). This could result

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from insufficient PhDS (i.e. kill mud not weighed up properly orkill mud level not as low as expected) or from increased Pf orfrom incorrect reading of the initial SIDPP. In all these cases, itis necessary to establish that the BHP is equal to Pf, using thefollowing procedure, before resuming the kill operations.

3) Slowly bleed off a small amount of fluid through the chokeallowing only a small DP pressure decrease (e.g. 700 kPa, 7kg/cm2, 100 psi and/or 80 liters, 1/2 bbl max.) - use acalibrated tank or trip tank to monitor return volumes. Closethe choke.

4) Allow pressures to stabilize and check that both DP andCasing pressure have decreased by the same amount.Repeat the above steps until the DP pressure becomes equalto the expected NSDPP or rebuilds to a fixed value afterclosing the choke even if further bleeding off is done (thusindicating that the pressure comes from the formation).

The bottom hole pressure now equals the formation pressure.

Casing p ress.

3 Bleed in Stages

Trappedpress.

Resume c irc .hold ing thisc asing p ress.

1 Expec ted NSDPP

2 Ac tua l DP p ress.

4

Figure V.15

Note: It is recommended that the volume bled from the well bekept to a minimum unless migration is obviously occurring.Stop bleeding mud if the pressure does not stabilize after300 to 500 liters (2 to 3 bbls) of mud have been bled off.

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5) If the final NSDPP, after bleeding off, is approximately equalto the expected NSDPP, then the difference found earlier wasdue to trapped pressure; Resume the pumping operations,maintaining the casing pressure constant (minus CLFL onfloating units) while the pump is brought to slow circulatingrate before switching to the DP pressure as described insection II.2.3. The circulating pressure measured on the DPgauge at that time is the correct pressure that must be usedto re-establish the new pressure schedule to follow in order tomaintain constant BHP while completing the kill.

If the final NSDPP is still significantly different from theexpected pressure (see example below), the reason for thedifference will have to be established and the kill plan willhave to be modified accordingly. This could be for one of thereasons explained above.

Add itiona l bac kpress. required

Resume c irc .hold ing thisc asing p ress.

Initia lNSDPP

Fina l NSDPP

Expec ted NSDPPCirc . Stopped here

New c irc .DP p ress.

Figure V.16

Note: This procedure is not recommended if the kick zone issuspected to have low permeability as bleeding even smallquantities of mud may reduce the drillpipe pressure, givingthe false impression at surface that the bottom holepressure is still greater than the actual formation pressure.

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V.19 UNDERBALANCED DRILLING

V.19.1 Equipment

Underbalanced Drilling (UBD) can take many forms. The types ofequipment and cost depend on the magnitude of the surfacepressures expected, the method of pipe rotation (i.e. top drive orrotary table), the nature of the reservoir fluids to be encounteredand the type of drilling system to be used.

Below are listed various types of underbalanced drillingapplicable for use with jointed pipe:

1. Air, gas (exhaust or natural gas), nitrogen (cryogenic ormembrane separation).

2. Foam drilling.3. Aerated fluid drilling.4. Flow or "live" drilling underbalanced with mud or brine.

Depending on the system used, the equipment required couldconsist of:

1. Compressors and boosters.2. Rotating heads or rotating BOPs.3. Two, three or four phase separators or gas busters.4. Skimmer.5. Blooie line and flares.6. Solids control equipment.7. Surface instrumentation.8. Bypass lines and bleed off lines.9. Fire stop and fire floats.10. Chemical (mist, foam) injection system.11. Special bits and motors (depends on system used).12. Underbalance drilling manifold (different from choke

manifold).

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The BOP stack as a minimum shall comply with the requirementsset forth in Section III of this manual and in addition, may consistof.

- A diverter line and diverter preventer.- The capability to bleed-off to a flare or through a manifold in

the event of a diverter line obstruction or other operationrequiring bleed-off separate from the production vessel.

- The capability to equalize pressure between the diverter line tobelow the lowest ram type preventer.

- The accumulator system used to control the diverter preventershall be independent of the rigs standard accumulator system.

KELLY COCK4” STANDPIPE

PRESSURE GAUGEBLEED OFF VALVE

2” BLEED OFFLINE TO FLARE

MUD LINE

PRESSURE SHUT OFF VALVE

ADJUSTABLE CHOKE

ORIFICE METERMAIN BLOCK VALVE300 FT FROM RIGAIR OR GAS SUPPLYLINE - 3” DIA

1” PILOT FLARE LINE

CHEMICAL INJECTIONMANIFOLD

ROTATING KELLYPACKER

RIG FLOOR LEVEL

RETURN LINESHUT OFF VALVE

EXHAUST LINE FLARED AT200 FT FROM RIG

TO SHALE SHAKER

CHOKE

CHOKE

2” LINEMUD FILL LINE

ANNULAR BOP

PIPE RAMS

BLIND RAMS

CASING HEAD

Figure V.17

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V.19.2 Practices

- No primary well control equipment (preventers other than thediverter preventer) shall be used for stripping, snubbing ordrilling.

- At least two (2) non-ported devices (floats) to prevent backflowfrom the well should be installed near the bottom of thedrillstring while drilling underbalanced.

- When the top float sub is pulled to the floor, equipment andprocedures should be followed to safely remove trapped gasbelow the float before removing from the drillstring.

- A pressure indicator with a readout visible at the driller’s stationshould be installed below the blind rams to monitor wellborepressure while the drillpipe is out of the hole.

V.19.3 Procedures

Below is a general tripping and connection procedure for atypical underbalanced drilling operation using injected gas withno back pressure held on the annulus.

- Circulate hole clean.

- Shut down gas and foam (if applicable) injection.

- Close HCR Valve. Change over valves on stand-pipe andensure valves are correct before killing the well.

- Pump kill fluid volumes down both the drillpipe and the annulusto give enough hydrostatic pressure for an overbalance fluidlevel. Of the total volume pumped to achieve overbalance,the entire drillpipe volume should be pumped through thedrillpipe to ensure the drillstring is clear of foam.

- Observe the well is dead on the annulus pressure gauge. OpenHCR Valve and ensure the well is dead through the blooie line.Check standpipe pressure to ensure well is dead.

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- Take a fluid level shot. Wait 10 minutes and shoot a secondfluid level to see fluid level change. (Foam may mask some ofthe fluid level movement).

- Vent blow line with nitrogen to ensure any gas coming tosurface is pulled through the blooie line and vented out to theflare. Continue venting with nitrogen throughout the trippingprocedure.

- Open HCR. Watch for potential flaring. If no gas is presentproceed. If flaring occurs then additional kill procedures maybe required.

- Open RBOP. Pull out of hole. Ensure that the drillstringdisplacement volume is being pumped every 10 stands. Takefluid level shots as needed. Pump more kill fluid as needed.

Note: The RBOP may be used to strip through if gas is breaking outof the foam to surface. This would be a secondary measure afterpumping additional kill fluid.

- Once the drillstring is out of the fluid level, it will not benecessary to continue pumping the drillstring displacementvolumes. However, continue to monitor the fluid levels.

- Once the drillstring and BHA is out of the hole, close the blindrams and monitor the well through the choke manifold.

Never think the well is dead when tripping after drilling with foam,nitrogen or air. At any time, the well may kick gas. Be prepared

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V.20 COLLISION AVOIDANCE

Collision avoidance is particularly important in the shallowsections of platform wells, generally down to the surface casingdepth. Accurate surveys over this section of hole being drilled,and all wells in close proximity, may reduce the requirement forshutting in producing wells during close proximity drilling. Surveyuncertainty in this hole section should be kept to less than 0.6 mper 300 m (2 ft/1000 ft). Figure V.18 below gives typical surveyingtool accuracy.

While drilling in close proximity to other wells, returns should bemonitored for metal cuttings. If metal cuttings are detected,drilling should stop immediately. A survey shall then be run todetermine the position of the wellbore.

Typical Lateral Position Uncertaintiesfor Magnetic and Gyroscopic Surveys

(After Wolff and de Wardt 1981)

0.1

1

10

100

1000

0.1 10 20 30 40 50 60 70 80 85

Hole Inclination (degrees)

Rela

tive

Late

ral P

osito

n Un

cert

aint

y(f

t per

100

0 ft

)

Good Magnetic

Poor Magnetic

Poor Gyro

Good Gyro

Figure V.18

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Revision: 0Chapter VI Deep Water Considerations.

Chapter VI - DEEP WATER CONSIDERATIONS

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VI.1 HYDRATES IN DEEP WATER ...............................................................................................................159VI.1.1 Hydrate Prevention.................................................................................160VI.1.2 External Hydrates in Wellhead Connector .............................................162VI.1.3 Hydrate Removal....................................................................................163

VI.2 HANDLING GAS IN THE RISER............................................................................................................165VI.2.1 Volumes and Flow Rates........................................................................165VI.2.2 Equipment for Handling Gas in the Riser ...............................................166VI.2.3 Procedures for Handling Gas in the Riser..............................................167VI.2.4 Riser Collapse ........................................................................................168

VI.3 MAASP IN DEEP WATER......................................................................................................................170VI.4 SHALLOW WATER FLOWS (SWF) ......................................................................................................171

VI.4.1 Causes of Shallow Water Flows.............................................................171VI.4.2 Combating Shallow Water Flows ...........................................................172

VI.5 TEMPERATURE EFFECTS ON MUD DENSITY AND RHEOLOGY.....................................................173VI.5.1 Density Effects........................................................................................174VI.5.2 Rheology Effects ....................................................................................175

VI.6 RISER MARGIN......................................................................................................................................176VI.7 DEEPWATER WELL CONTROL THEORY & PROCEDURES .............................................................177

VI.7.1 Kick Prevention and Detection ...............................................................177VI.7.2 Circulating Schedule for Kill and Choke Lines........................................179VI.7.3 Shut-in Procedures.................................................................................179VI.7.4 Kill Procedures (Includes Instrumented BOP).......................................180

VI.8 EMERGENCY DISCONNECT PROCEDURES & CONTINGENCIES (DP RIGS).................................188VI.8.1 During Drilling or Tripping Operations ....................................................188VI.8.2 During a Well Control Situation ..............................................................189VI.8.3 With BHA Across BOP ...........................................................................189VI.8.4 With Casing Across BOP .......................................................................190VI.8.5 Testing Operations .................................................................................190

VI.9 DEEPWATER WELL CONTROL EQUIPMENT.....................................................................................191VI.9.1 Control Systems and Accumulators .......................................................191VI.9.2 BOP Pressure Testing............................................................................191VI.9.3 BOP Stack and Riser .............................................................................191VI.9.4 BOP Rams .............................................................................................193

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Wells drilled in deep water use the same basic well controlprinciples that are used on more standard wells. However somesituations which are considered "special" on standard wells maybe encountered routinely on deepwater wells. The additionalpoints to consider are as follows:

VI.1 HYDRATES IN DEEP WATER

The graph below shows the average water temperatures versuswater depth for various parts of the world (Fig. VI.1). This graphshows that the conditions for hydrate formation almost alwaysexist in wells drilled in more than 250 m (820 ft) of water.

0

200

400

600

800

1000

0 5 10 15 20 25 30

Water Temperature, deg. C

Wat

er D

epth

, m West Africa

Malaysia

Brazil

Gulf of Mexico

Potential hydrate formation

No hydrate formation

Figure VI.1See the discussion in Section V.8 for more details about hydrates.

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VI.1.1 Hydrate Prevention

Hydrate formation while circulating is less likely due to the heatbrought up from the wellbore. Any delay in circulating out gaswill allow the system to cool, thereby increasing the potential forhydrate formation. Therefore, whenever the potential for hydrateformation exists, the Drillers’ method will be the preferred methodof well control.

However, prior to drilling each section a decision should be madeas to which of the following kill methods will be used.

1. Kill well using the Driller’s method.2. Have available a sufficient volume (hole volume but not riser

volume) of reserve kill mud, premixed to an estimated density.With kill weight mud premixed, there would be no delay instarting the kill process, so a No-Wait and Weight methodcould be used. Unless other factors are known, the pre-mixedkill mud density should be pre-mixed to 120 kg/m3 (1 ppg)over current mud weight (as per section I.11). The mud weightcan be reduced by dilution quickly if needed.

3. Use conventional Wait and Weight method.4. Fill the kill line with hydrate inhibitor and inject into well during

kill operation. This is the basis for the single line kill being the“preferred” method rather than taking returns up both thechoke and kill lines.

To calculate the proper amount of hydrate inhibitor to be usedwhile circulating, the following procedures should be followed.

1. From Figure VI.1, calculate the degrees of hydratesuppression required (DHSR). The DHSR is the differencebetween the actual seabed temperature (TSB) and thehydrate formation temperature (TH) at the seabed.

DHSR = TH - TSB

For example, for a well being drilled in 600 m of water inthe Gulf of Mexico (see fig VI.1 for data);

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TH = 16o C, (from the curve at the right side of the“Potential for Hydrate formation” zone at600m)

TSB = 6o CTaken from the water temperature curve for at600 m depth

So DHSR = 16o – 6o = 10o C

2. Look up the concentration of inhibitor necessary to providethe proper level of hydrate suppression. See Figure VI.2 forthe amount of hydrated suppression that is provided bydifferent concentrations of common chemicals. Mixtures ofinhibitors can be more effective than using singlecomponents, but have not been tabulated here. Simulatorsare available to make these calculations.

So, for the example, the following would be acceptable:

17 Wt% NaCl, or23 Wt% CaCl, or26 Vol% Methanol, or26 Vol % Ethylene Glycol

Note: These are the inhibitor concentrations for the fluid that isreturning up the choke line, which will be a blend of theinhibitor and the drilling fluid. Circulation rates of the drillingfluid and the inhibitor must be balanced so that the properconcentration is maintained in the chokeline.

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Hydrate Supression Provided By Common Chemicals (in Degrees C)

0

5

10

15

20

25

0 5 10 15 20 25 30 35 40 45Weight % for Salts

Volume % for Methanol and Ethylene Glycol

Hydr

ate

Supr

essi

on (D

egre

es C

)

NaClCaClKClMethanolE Glycol

Figure VI.2 Hydrate Suppression of Common Chemicals

VI.1.2 External Hydrates in Wellhead Connector

In areas where gas may percolate up from outside the conductor,hydrates can built up around the outside of the lower marine riserpackage (LMRP) and in the wellhead connector cavity.

Once hydrates have formed inside the wellhead connectorcavities, cycling the unlock and lock function repetitively to getdisconnected will worsen the problem, by compacting the solidslug, and allowing new hydrate to form.

To prevent hydrates from collecting in the wellhead connector,one or more additional hydrate seals should be added to theconnectors as shown in Figures VI.3 and VI.4 below.

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New connectors can be built with flush ports built into theconnector to circulate seawater, glycol or methanol through theconnector internal cavity. See Figure VI.3 below.

Also available is a “gas mat”, that seals around the 30” conductorto divert any leaking gas away from the connector.

Figure VI.3 Figure VI.4Vetco Type Connector Cameron Type Connector

VI.1.3 Hydrate Removal

Several methods are available to eliminate the hydrates oncethey have formed. One method is to pump a chemical mixture ofHCL down one string and caustic down another string. Allowingthem to mix at the bottom generates heat. This solution involvespumping two chemicals that are dangerous to handle. Thesechemicals are also very corrosive and can damage equipment ifnot properly inhibited.

A similar approach is a chemical system developed by Petrobrasin which sodium nitrite is reacted with an ammonium salt.

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The reaction yields a lot of heat and the only final products arenitrogen gas and sodium chloride that are environmentallyfriendly. This process is patented by Dowell and is called "SGN".

The most commonly used hydrate inhibitors for deepwater wellsare methanol and glycol. On a weight basis, methanol providesthe greatest inhibition.

0

1

2

3

4

5

6

15 17 19 21 23 25 27 29Weight % NaCl in Water

Vol

. of M

etha

nol /

Vol

. o f

Brin

e

Salt w ill Precipitate

Salt w ill stay in Solution

Figure VI.5

However, methanol is generally more toxic than glycol, has alower vapor pressure and flash point temperature. Because ofthese properties special provisions must be made for storage tankson offshore rigs. Care must also be taken when using brines asalcohol’s, such as methanol and ethylene glycol lower thesolubility of most inorganic salts in water. Figure VI.5 above showsthe solubility limit of NaCl in the presence of methanol.

NH Cl NaNO N NaCl Heat H O4 2 2 22+ → + + +

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VI.2 HANDLING GAS IN THE RISER

When a kick is taken while drilling with a marine riser, there is apossibility that the gas will migrate or be circulated above theBOP stack. If this occurs, the choke and mud gas separator (MGS)are no longer available to control the flow rates when the risergas reaches surface. Special precautions and procedures arenecessary to avoid the effects of the rapid expansion of this gas.

Even if the influx is detected early and the BOPs are closed, wecannot be certain that all of the gas influx is below the BOPs.There may be some gas above the BOPs because detection ofthe kick did not occur until the gas had been circulated abovethe BOP stack.

An early flow check in the riser, immediately after shutting in thewell, may indicate that bubbles are still rising and dissipating. Thisflow should not be falsely interpreted as the BOP not being closedfully.

However, once all the small gas bubbles have becomesuspended in water based mud (WBM), or dissolved in oil basedmud (OBM, and includes synthetic and pseudo oil muds) a flowcheck in the riser will be negative (i.e. no flow). This should not beassumed to indicate that there is no gas in the riser.

VI.2.1 Volumes and Flow Rates

Large amounts of gas above the BOP stack can rise rapidly andcarry a large volume of mud out of the riser at high rates. The keyto managing gas in a riser is to avoid situations where largevolumes of gas have gotten above the BOP stack.

If the volume of gas above the BOP stack is kept small bydetection equipment and shut in, then the gas can be safelyhandled at surface by allowing the gas bubbles to disperse andthen controlling the rate that the mud is brought to surface. Thatis, by controlling the circulation of the riser we can control theflow rates of gas and liquid. The higher the circulating rate, the

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higher the gas and liquid rate. Also, by circulating in stages, wecan control the expansion or dissolution of the gas. There may besome mud loss through the overboard line with this approach, butwith patience and control, all surface equipment will remaineffective.

However, if large volumes of gas have entered the riser, it will flowrapidly on its own and there will be no way to control it byadjusting the circulation rate. Then, the surface gas and liquidrates become very high, especially as the gas bubble reachessurface and the flow must be diverted overboard.

VI.2.2 Equipment for Handling Gas in the Riser

Early kick detection is key to shutting in the well before the gasenters the riser. The use of advanced kick detection equipment issuggested. If possible, an additional sensor that can detect freegas in the annulus at or near the BOP stack should be installed.

A diverter system above the telescopic joint with two (2)overboard lines and a system to remove gas from large volumesof mud and return it to the mud system (such as a mud box on theoverboard line) is preferred. The diverter and overboard linesshould be designed to handle high flow rates and be as straightas possible.

This system is not designed to choke or control high gas or liquidflow. Rather, it is a system to keep combustible gases safely awayfrom sources of ignition and to remove gas from the mud. At anytime, if there is a rapid expansion of gas in the riser, the diverterwill be closed (if not already) and the flow will be divertedoverboard. This is true for water based mud as well as for oilbased mud.

An alternate system using the MGS to remove gas from the mud isshown below (Figure VI.6). Either the mud from the riser or fromthe well can be circulated through the MGS to remove theresidual gas (but only one at a time).

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Automatic valve switching is suggested such that the closing ofthe 305 mm (12”) valve and the opening and the 152.4 mm (6”)valve are coordinated. An override switch should be availablethat will allow the manual opening of the 305 mm (12”) valve ifthe need arises. Also, automatic opening of the 305 mm (12”)valve should be tied to the separator pressure so that theseparator rating is not exceeded or an automatic pressure reliefbypass should be included.

A small volume circulating system should be isolated so that avolume totalizer can be used while circulating and monitoring theriser. This could use the trip tank if available.

Flowline

Port

6” Line (Minimum)

Figure VI.6 – Using Existing MGS to Clean Gas from the Mud

12” Ball Valve

6” Ball Valve

Operation of two valves is tied together.Only one valve open at any time.

Starboard

ExistingMGS

Vent line

Overboard Line

Trip Tank

Diverter

VI.2.3 Procedures for Handling Gas in the Riser

These procedures are to be conducted along with the shut inprocedures for Subsea BOPs as shown in sections II.2.1.3, II.2.1.4,and II.2.1.5

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Limit the volume of gas that may be taken above the BOP stack.- Use good well control techniques to detect any influx early

(See sections II.1.1 and II.1.2.)- When an influx is suspected, quickly shut off the mud pumps.

This will help avoid circulating the gas above the BOP stack.- Close in well as quickly as possible. (See section II.2.1)

When the well is shut in after taking a kick: (See section VI.7.3)- Conduct a riser flow check.- If riser is flowing, divert the flow overboard. If so equipped,

the flow can be diverted through a gas handling system orMGS if the flow rate is within the capacity of the equipment.

- If the riser is not flowing or has stopped flowing, continue tomonitor it for flow. Do not leave it unattended.

- If so equipped and if the MGS is not being used for theprimary well control operations, the riser fluid may becirculated through the MGS at slow rates to remove the gasfrom the fluid.

- Circulate the riser at slow rates. Stop circulation and conducta riser flow check after every 16 m3 (100 bbl) pumped orequivalent volume to 75 linear meters {+ 250 ft} of riser. If gasis seen at surface, stop pumping and watch for flow. Allowthe flow to deplete before continuing. If the flow rateincreases, be prepared to open up the diverter line to sendthe mud overboard.

- Continue to circulate in stages at slow rate until the completeriser volume has been circulated.

After killing the well and removing any gas trapped in the BOPstack (as described in procedures V.15) there is still the possibilitythat some gas trapped under the BOP stack may be released intothe riser after opening the BOP. If this occurs, then the sameprocedures will apply.

VI.2.4 Riser Collapse

In deep water the potential for riser collapse exists if the level ofdrilling fluid in the riser drops due to, gas unloading the riser,intentional drive-off, loss of circulation, or accidental line

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disconnection. Assuming the worst case to be during anemergency or accidental line disconnection, the pressure at thebottom of the riser would equal the seawater hydrostatic. The fluidlevel in the riser would fall until this equilibrium is reached. This isshown graphically in figure VI.7 below.

Pressure

Sea Water Gradient on Outside of Riser

Mud Gradient onInside of Riser

Sea Level

Mud Line

Dep

th

Maximum CollapsePressureFinal

MudHeight

Riser Collapse Pressure Resulting from an Emergency Disconnect

Figure VI.7 Riser Collapse Pressure

The maximum collapse pressure that the riser would be subjectedto resulting from an emergency disconnect can be found by thefollowing equation:

)MW

6.81(xDx)6.8(x)052.0(CP w −=

Where:CP = Collapse Pressure (PSI)Dw = Depth of water (ft)MW = Mud weight (ppg)

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A riser fill-up valve should be used if the collapse pressure couldexceed the collapse pressure rating of the riser.

VI.3 MAASP IN DEEP WATER

Eliminating the effects of choke line friction loss (CLFL) on the bottomhole pressure was discussed in section V.17. Methods of bringing thepump to kill speed were explained. However, notice by thefollowing example that even with these techniques, choke linefriction and deep water still complicates the kill operation.

In the following example, assume gas is swabbed into a well.Assume the SCR pressure is 3,448 kPa (500 psi) and that the choke isopened enough to compensate for the CLFL so that the bottom holepressure is held constant at the original pressure of 34,475 kPa (5,000psi). The well is then circulated until the influx just reaches the chokeline. See figures VI.8 and VI.9 below.

0psi

Figure VI.8Pf = 5,000 psiPh = 4,750 psi ( in annulus )Pump off ( kick shut in )

Drill pipe

250psi

Choke

500psi

Figure VI.9Pf = 5,000 psiPh = 4,750 psi ( in annulus )Pump at kill rate holding constantchoke manifold pressureChange in BHP = 0 psi increase

Drill pipe

50psi

Returns

Choke

Choke Manifold Choke Manifold

CLFL 0 psi ( static)

APL 0 psi

SubseaBOP

SubseaBOP

CLFL200 psi( dynamic )

APLNegligible


Hydrostatic pressure = 1705 psi10 ppg mud @ 1000 m

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Now assume the gas bubble enters the choke line. With a waterdepth of 1000 m (3280 ft), and a mud weight of 1200 kg/m3 (10ppg)the casing pressure would need to increase by 11,776 kPa (1705 psi)just to offset the loss of hydrostatic pressure to maintain a constantBHP of 34,475 kPa (5000 psi).

Pressure = SICP +0.052 x 3280ft x 10ppg= 50 + 1705 = 1755 psi.

If we assume that the CLFL can also drop significantly, since gas canflow with much less friction, then the pressure could increaseanother 1,379 kPa (200 psi) to 13,5480 kPa (1955 psi). As the gasclears the choke line and is replaced with mud, the casing pressureshould be adjusted back down to zero. If the well is being killedwith a high SCR, these pressure fluctuations could occur very quicklyand the choke operator would need to be very skilled to maintainthe proper pressures. This example demonstrates the increasedmagnitude of pressure fluctuations that may occur during wellcontrol operations in deep water. Therefore, influxes need to becirculated out at very slow rates to simplify well control operations indeep water.

VI.4 SHALLOW WATER FLOWS (SWF)

VI.4.1 Causes of Shallow Water Flows

Shallow water flows (SWF), or the flow of water and entrained sandfrom sub-seafloor strata up past the drill bit or surface casing, is arecently encountered phenomenon typically found in deepwater.Shallow water flows are due to rapid sedimentation in delta areas,such as the Mississippi delta. SWF are most likely to occur in areasformed with river deltas

Shallow water flows are thought to form in one of three ways.

Channel sands: Deposits of clean channel sands laid down in adeltaic environment which shift over time so that new sand depositscreate a super-imposed structure.

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Turbidite sands: Sands deposited in the Gulf of Mexico on thecontinental slope, which runs at a steep angle between thecontinental shelf and the deepwater basin. In strong turbiditycurrents, these sands slide down the slope at high speeds, to formturbidite sands on the sea floor. The result is a rapidly formed,coarsely graded turbidity deposit.

Rotated slump block: In this condition, the face of the continentalshelf slides down like an undersea avalanche of sand, to depositrapidly onto the deep basin.

These three forms of rapid deposition lay the foundation, literally, forSWFs. The next ingredient is a sealing layer of shale depositedabove the sands. This shale encloses the sands, as well as the waterand gas pressure they contain. On top of the shale are further rapidsand deposits, which build to increase the pressure within the sands.These sand deposits grow in thickness at the rate of 1640-2300 m(500-7,000 ft) per million years, creating shallow pressure zones nearthe surface.

VI.4.2 Combating Shallow Water Flows

Mechanical Solutions

A subsea annular BOP and rotating drilling head mounted to the topcasing joints by an inflatable packer may be a solution to combatshallow water flows. The rotating drilling head would provide thebackpressure needed to contain the SWF and allow the initial casingjoints to be set.

Using this technology, the operator would set one joint of casing atthe mudline, install the "virtual riser," which includes a subsearotating control head and high-pressure BOP mounted to the casingby an inflatable packer. This virtual riser allows the operator tomaintain backpressure on the SWF.

The backpressure comes from the mud pumps, which pumpseawater through the bit and up the annulus against the control

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head. The mud pump pressure can be regulated by controlling theamount of backpressure needed to contain the formation pressure.

Until such tools are developed, the only method currently successfulis to drill the interval with weighted fluid. This can be very expensivesince the sections are drilled riserless and the fluid cannot be re-used.

Remote operated vehicles (ROVs) should be used to observe whendrilling in areas where SWFs may occur to allow the detection ofproblems as soon as possible.

Chemical Alternatives

Stabilization polymers or resins when put in place, seal off the SWFzone and add strength to sediments may be another solution. Thiswould be a particularly attractive solution in sand flow situations inwhich stopping the flow early is critical to saving the well.

One product that has shown promise is currently being applied tothe rubble zones above and below a salt intrusion. These areas aretechnically stressed meaning there is a risk of the rubble entering thewellbore.

Once the SWF zone has been drilled and casing run and set, thewell needs to be cemented. Good success has been achieved withfoamed cement. Foamed cement continues to transmit originalhydrostatic pressure throughout the thickening process. Whereasconventional cement loses its hydrostatic pressure during thethickening process which may allow the well to start flowing.

VI.5 TEMPERATURE EFFECTS ON MUD DENSITY AND RHEOLOGY

In deepwater, the pre-drilling temperature profile along the wellpath decreases from surface to sea floor (see section VI.1). In deepcold water this can reach (or pass) the normal freezing point ofwater. The reduced temperature has a marked effect on the

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circulating temperature for the whole well and will affect both thedensity and viscosity of the mud.

VI.5.1 Density Effects

The cooler mud in a deepwater well will be denser than in anonshore well. Figure VI.10 illustrates the effect of temperature on thedensity of mud. Mud density increases with increasing pressure.However, mud density decreases with increased temperature. Aspressure and temperature both increase with depth (below the mudline), mud density may increase or decrease with depth, dependingon the relative contribution of the pressure and temperature effect.In water based muds the pressure effect is very small.

In the example shown in Fig. VI.10 it can be seen that the nominal14.5 ppg varies from 14.35 ppg to 14.65 ppg as the temperaturechanges along the flow path indicating that the temperature effectis predominating.

In low temperature wells with OBM the pressure effect maypredominate.

Figure VI.10Example of the effects on mud density

0 2 0 0 0 4 0 0 0 6 0 0 0 8 0 0 0 1 0 0 0 0 1 2 0 0 0 1 4 0 0 01 4 .3

1 4 .4

1 4 .5

1 4 .6

1 4 .7

Seaf

loor

Mud

den

sity

(ppg

)

D e p th ( f t )

0

5 0

1 0 0

1 5 0

2 0 0

2 5 0

Cas

ing

shoe

Tem

pera

ture

(deg

F)

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VI.5.2 Rheology Effects

The cooler mud in a deepwater well will be more viscous than in anonshore well. Figure VI.11 illustrates the effect of temperature on theviscosity of mud.

Figure VI.11

The cumulative effects of temperature on density and rheology canlead to errors in determining several key parameters:

- Leak Off Test (LOT) recording.- Slow Circulating Rate (SCR) pressures.- Choke Line Friction Loss (CLFL) pressures.- Shut-in Pressures.

The above information demonstrates the importance of circulatingthe choke line prior to beginning a well kill operation (see sectionVI.7.4).

0 2000 4000 6000 8000 10000 12000 140000

10

20

30

40

50

60

70

PV

(cP)

Depth (ft)

0

10

20

30

40

50

Seaf

loor

Cas

ing

shoe

YP

(lbf/1

00ft2

)

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VI.6 RISER MARGIN

Figure VI.12

A mud weight, which includes a riser margin, is the minimum mudweight that can be used to ensure sufficient hydrostatic pressurefrom the mud column, between the wellhead and formation, tocontrol formation pressure in case of riser failure or the need todisconnect. When the riser is disconnected the hydrostaticpressure of seawater replaces the hydrostatic pressure of the mudcolumn from the rig to the wellhead.

As water depth increases so does the riser margin mud weight.For example, in Figure VI.12 we’ve assumed a well drilling at 7000ft. with a mud weight balancing formation pressure - including asafety margin - of 12 ppg. Assuming the density of seawater to be8.6 ppg, if we were drilling in 1000 ft. of water, a riser margin of 0.6ppg would be required for a total riser margin mud weight of 12.6ppg. In 2000 ft. of water the riser margin mud weight would be13.4 ppg and in 3000 ft., 14.6 ppg.

Water Line

1000 ft.

2000 ft.

3000 ft.

MW withRiserMargin=14.6 ppg

MW withRiserMargin=13.4 ppg

MW with RiserMargin = 12.6 ppg

TD = 7000 ft.TD =7000 ft.

Formation PorePressure = 12 ppg

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As we drill in increasingly deeper water, sometimes it may not bepractical to carry a riser margin as it becomes too large toeffectively drill a well. In such a case it is important that the BOPsbe closed to maintain bottom hole pressure if the riser is removed.

VI.7 DEEPWATER WELL CONTROL THEORY & PROCEDURES

VI.7.1 Kick Prevention and Detection

The standard well kick warning signs are the same in deepwateras in shallow water and are described in Chapter II. However, aswater depth increases there is a reduction in the differencebetween the mud weight required to balance the formation porepressure and the weight causing formation fracture. As a result,wells drilled in deep water tend to have much lower kicktolerances than wells in shallower water. This fact in addition tothe problems that can occur if gas enters the riser make it veryimportant to; first, prevent kicks if possible, and second, detectand control kicks at an early stage.

Another problem that occurs with increasing depth is the impactof increased annular fluid density (riser cuttings) in creating higherthan assumed hydrostatic pressures. Higher pressures can lead tofracturing of low strength casing shoes, which can lead to theonset of a kick. Therefore, boosting the riser becomes moreimportant with increased water depths.

VI.7.1.1 Kick Prevention

The standard kick prevention methods described in Chapter IIapply equally in deepwater as in shallow water. However, due tothe narrow margin between pore pressure and formation fracturepressure, the overbalance safety margin will be minimal.Therefore special care must be exercised during trips to preventswabbing.

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VI.7.1.2 Kick Detection

Surface Detection relies on the existing warning signs, pit gain andincreased return flow. Prior to drilling each section the requiredkick detection sensitivity and primary detection method to beused for that section should be determined. The kick detectionsensitivity will usually be based on the calculated kick tolerance.That is, the detection sensitivity must be less than the kicktolerance.

The detection method will depend on the drilling fluid type, holegeometry, rig equipment, etc. For example, in a horizontal well pitgain would be the primary method of kick detection, while flowchecks would be used for vertical wells.

Modern kick detection systems using computers and a variety ofsensors are becoming commercially available. One suchexample is acoustic kick detection. Acoustic kick detection is amethod of identifying gas influxes based on the phenomenon thatgas effects the propagation of pressure waves within the mudcirculation system. One particular acoustic kick detection systemuses the mud pumps as an acoustic source and calculates therate of velocity attenuation in the circulation system. Changes intravel time are primarily calculated from the phase shift betweenthe standpipe and annular pressure transducer readings.

Downhole Influx Detection. To justify downhole sensors for influxdetection, they should provide new data that cannot becollected with surface equipment, and should significantly shortenwarning times. In general downhole sensors should be near thebit, but there is no guarantee that the influx will not occur up thehole above the sensors. An MWD annulus pressure sensor isprobably the best downhole influx sensor overall as it detectschanges in mud weight above the sensor. Most other sensors(resitivity, gamma density, etc.) require the influx to pass by thesensor.

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Because many kicks occur on trips, MWD sensors may be of no useunless tripping practices are modified. That is, with a top drivesystem, it is possible, -and often desirable– to circulate on trips.

VI.7.2 Circulating Schedule for Kill and Choke Lines

If glycol or base oil (when using OBM) is inside the choke and killlines while drilling with weighted mud, the difference in densitybetween the drilling mud and glycol may induce uncontrolledtransient over or under-pressures at the beginning of the wellcontrol operation. Therefore, the choke line(s) should becirculated to the same mud as the drilling mud in the hole prior tostarting the kill operation.

If the choke and kill lines are filled the drilling mud, they are to becirculated every tour.

VI.7.3 Shut-in Procedures

The shut in procedures as described in Section II for shallow wateralso apply to deepwater with the additional requirements.- Pumps may be stopped first to prevent pumping influx higher

up the wellbore.- The riser shall be monitored for flow.- If gas is detected in the riser, the decision may be taken not

to hang off the drillpipe (See section I.17) but to remainhanging with the motion compensator unpinned and overpressured. This will prevent pulling the pipe in two if it shouldbecome stuck in the instant before significant rig heave. Thistechnique will eliminate any relative motion between the rigand the drillpipe that could create a leak between thediverter element and the drillpipe. After the riser is cleared,the pipe should then be hung off.

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VI.7.4 Kill Procedures (Includes Instrumented BOP)

- Before beginning each phase of the drilling operations,careful review of the well geometry and kick tolerance needto be done to determine which kill procedure should be used(Drillers, No-wait and Weight, or Wait and Weight) and takeinto account the potential for hydrates as discussed in sectionVI.1.1.

- The Driller’s Method should be used for wells where thedrillpipe volume is greater than the open hole volume. This isbecause the maximum pressure at shoe will be the same asfor the Wait & Weight method so removing the influx ASAP ispreferable.

- Prior to starting the kill procedure, if possible based on theBOP stack arrangement, the kill and choke lines should becirculated in order to break the mud gels.

- A single line kill should be used in most instances (especiallyfor instrumented stacks) with the circulation rate slowed atthe end of the kill.

- Two line kills, using the uppermost outlets on both the chokeand kill sides, may be used in cases where the kill speed usinga single line would be too slow.

- The beginning kill rate selected should be chosen so that theCLFL is less than the shut-in casing pressure (SICP). Prior to thestart of the kill procedure the relative magnitudes of thepressures involved need to be determined and if the CLFL isnot less than the SICP the actions described below should betaken.

SIDPP & SICP > MAASP

Attempting to circulate out will probably fracture the well. Otheroptions should be considered. The possibility of an undergroundblowout seems likely unless the procedure described in section

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V.1.2.d is used. This procedure is also commonly referred to as the“Low Choke” method.

The following are indications of an underground blowout.

- A sudden break in surface pressures during the initial build upto equilibrium.

- Rapid fluctuations in casing pressure.

- Drillstring on a vacuum.

SICP < CLFL

If it is not possible to reduce the SCR to a value where associatedCLFL is less than the SICP, then the casing shoe must be able towithstand the over pressure amount of CLFL - SICP.

SIDPP < CLFL

The CLFL will be sufficient to keep the well in overbalance. Whenmost of the influx is circulated out the choke will be openedcompletely and the pump pressure will start to increase from itsmeasured SCR pressure.

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VI.7.4.1 Deepwater Kill Procedure Decision Tree

Pre-recorded information

1. SCR’s (several rates)

2. Open hole volume greaterthan drillpipe volume

3. Potential for hydrates

Pre-recorded information

1. SCR’s (several rates)

2. Open hole volume greaterthan drillpipe volume

3. Potential for hydrates

Riser flowing YESNO

Use OMWCalculate

KMWPositive SIDPP

YES NO

Drillers method

recommendedYES

NO

DP volume > Open hole

or potential hydrates

Shut in well with annularRecord pit gainSIDPPSICPMonitor riser for flow

Divert riserContinue monitoring Hang off string

Select SCRmaxbased on

CLFL < SICP

Single line killpreferred but mayrequire 2 line kill

Wait and Weight methodshould be used

If riser flow starts,riser may be circulated

through MGS whileweighting up mud

Calc. new static MAASPbased on kill mud weight

Does CLFL at SCRmaxexceed new MAASP at

end of kill

IsSCRmin speed

acceptable

Determine SCRmin for

CLFL = MAASPnew

YES NO

Kill at SCRmax withpump speed manipulation at

end of KILL

Kill at SCRmax with

pump speed reduction to

SCRmin at end of KILLNO

YES

Kill at SCRmaxKill at SCRmax

Kill at SCRminKill at SCRmin

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VI.7.4.2 Beginning Kill - Bringing Pump Up to Kill Speed

On BOP stacks equipped with pressure sensors, the pressure sensorshould be used to maintain a constant pressure at the BOP stackwhile bringing the pump to kill speed. This will remove the inherentuncertainty that exists if the CLFL pressure schedule as describedin Section V.17.2 is used.

If there is no sensor, the methods described in Section V.17.2should be used.

VI.7.4.3 Finishing Kill (Accounting for Choke Line Friction)

Since the kill mud’s density is selected to just balance theformation pressure while static, at the end of the kill process theCLFL caused by circulation acts to overbalance the well. Therewill come a time when the kill mud reaches sufficient height in theannulus such that the hydrostatic pressure added to the CLFLpressure will balance the formation pressure and the choke will bein the fully open position. As the mud rises the hydrostatic pressurewill continue to increase. If the rate is kept constant and heavierkill mud is being pumped, the friction pressure will also increase.

The figure below (Figure VI.13) demonstrates the effect. The firstdiagram shows the effect on a well in shallow water. The seconddiagram shows that the effects can be greater in deeper water,

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SIDPP

ICP

FCP held constant by choke adjustments

Kill mud to bit –Not a straight line if deviated well

Overbalance = CLFL KMWOMW

Drill Pipe Schedule for Shallow/Moderate Water Depth WellOverbalance due to CLFL minor

SIDPP

ICPOverbalance = CLFL KMW

OMW

Drill Pipe Schedule for Deep Water Depth WellOverbalance due to CLFL significant

CirculationPressure

CirculationPressure

Pump Strokes

Choke wideopen

Choke wideopen

Kill mud to bit –Not a straight line if deviated well

FCP held constant by choke adjustments

Figure VI.13Stand Pipe Pressure Increase at End of Kill

Two options exist to eliminate exposing the formation to theoverpressure at the end of the circulation.

Option 1.

If kill mud has been circulated up to the BOP stack, then thefollowing may be considered. At the point the choke is fullyopened, close the lowermost ram below the choke outlet toisolate the open hole. Circulate kill mud down the kill line and upthe choke line at any rate. Then proceed with clearing any gastrapped below the stack.

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Option 2.

At the point the choke is fully opened, the pump pressure willcontinue to rise. If the well is being killed at a rate where the CLFL> New MAASP, the casing shoe fracture pressure will eventually beexceeded.

FCPadm = SCRP * (KMW/OMW) + New MAASPWhere FCPadm= Maximum admissible FCP

To eliminate this problem the pump rate can be slowed. After thepump pressure has risen to near the FCPadm, (i.e. to within about175 kPa, 25 psi) the pump rate should be reduced until whicheveroccurs first; the pump output pressure drops to the original FCPvalue, or the rate is reduced to SCRmin. This is shown graphically inFigure VI.14 below.

Pressure

Time

Slow pump to SCRmin oruntil pressure drops to FCP @ SCR 1

Annulus pressure = 0Choke wide open

FCP adm @ SCR 1

FCP @ SCR 1

FCP adm @ SCR 2

FCP adm exceeded unless circ. slowed

Figure VI.14

When the rate is reduced to SCRmin no other adjustments shouldbe required to finish killing the well. If the pressure drops to FCP@SCR 1 with a rate still exceeding SCRmin, the process will need to

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be repeated until the rate is reduced to SCRmin. The circulatingpressure should be kept as close as practical, slightly above FCPuntil the rate is reduced to SCRmin. This situation will occur beforekill mud reaches surface and care must be taken to ensure the killmud circulation is completed.

VI.7.4.4 Dynamic Volumetric Method

For situations involving deep water wells where meaningfuldrillpipe pressure is not available, the dynamic volumetric methodshould be used. This may be required when one of the followingoccurs.

- Drill bit is plugged.- Drillstring has failed allowing communication between

drillstring and annulus.- Drillstring is off-bottom, causing drillpipe and casing pressures

to read the same until the kick has migrated above the bit.- Drillstring is out of the hole entirely.

The static volumetric method described in Section II.2.3.3 is notadequate for deepwater wells. As the kick migrates above thestack, gas is forced into the subsea chokeline, which has a muchsmaller cross sectional area than the annulus. With thisconfiguration, the static volumetric method is much more difficultto implement, since gas entry into the subsea chokeline must bedetected. Additionally, gas distribution and migration rate mustbe known in order to make appropriate changes in the casingpressure-pit gain schedule.

A dynamic volumetric method should be used where mud ispumped into the kill line, across the top of the annulus, and outthrough the choke line and choke manifold. By carefullymonitoring pit gain, an appropriate casing pressure can beselected that will maintain constant bottomhole pressure.Chokeline friction losses at that pump speed are added to thesurface pressure. See Figure VI.15 below.

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CasingPressure

Pit Gain

Choke line frictionat kill speed

Theoretical SIDP at zero pit gain

Safety margin

Upward gasmigration

Gasremoval

SICP

Gi

Figure VI.15Dynamic Volumetric Kill

The base line is constructed by plotting initial shut-in casingpressure (SICP) against initial pit gain (Gi). The slope of the line iscomputed by dividing the change in hydrostatic pressure of theannular mud by the annular capacity.

Slope = 0.052 MW = psi/bbl Ca

WhereMW = Mud density, ppgCa = Annular capacity, bbl/ft

The line is drawn with the computed slope through this point. Thezero intercept represents the theoretical shut-in drillpipe pressurethat would be observed if meaningful drillpipe pressure wasavailable. A safety margin can be plotted above the base line toallow the choke operator some margin for error. The dashed linerepresents the subsea case in which the choke line friction mustbe added.

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VI.8 EMERGENCY DISCONNECT PROCEDURES & CONTINGENCIES(DP RIGS)

Each rig shall have an emergency disconnect procedure specificto the rig.

Emergency disconnect procedures shall be posted in the Driller’shouse for each of the following situations. The procedures shownbelow are intended only as a general example. Actual rigemergency disconnect procedures may vary.

VI.8.1 During Drilling or Tripping Operations

If DP alert sounds while drilling.

YELLOW 2.5% of water depth1. Pick up off bottom to 5 feet (1.5 meter) above hang off position

(dependent on heave).2. Shut down mud pumps.3. Hang off on middle pipe rams.4. Place DSC at mid-stroke and bleed pressure down to string

weight above the pipe rams plus 10,000 lbs. so that drillpipe willclear the lower stack upon disconnecting.

5. Inform DPO and prepare for emergency disconnect.

RED 4.0% of water depth6. Confirm with DPO that you have a red light.7. If DPO confirms, or fails to reply immediately then shear pipe

and function emergency disconnect.8. Only if Captain or OIM instructs not to disconnect, then stand

by the Driller’s panel and wait for further instructions from DPO.

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VI.8.2 During a Well Control Situation

If DP alert sounds during well control situation.

YELLOW 2.5% of water depth1. Shut down mud pumps.2. Close all failsafe valves on BOP.3. Inform DPO and prepare for emergency disconnect.

RED 4.0% of water depth4. Confirm with DPO that you have a red light.5. If DPO confirms yes, or fails to reply immediately then function

emergency disconnect.6. Only if Captain or OIM instructs not to disconnect, then stand


VI.8.3 With BHA Across BOP

If DP alert sounds with BHA across BOP.

YELLOW 2.5% of water depth1. Close an annular preventer.2. Slack off on the blocks to lose as much string weight as annular

will support.3. Unlatch elevators. If string weight still exists, unlatch elevators

with a tugger using slow and even pull on the latch.4. Open the annular preventer to drop the string.5. Inform DPO and prepare for emergency disconnect.

RED 4.0% of water depth6. Confirm DPO that you have a red light.7. If DPO confirms yes, or fails to reply immediately then function

emergency disconnect.8. Only if Captain or OIM instructs not to disconnect, then stand


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VI.8.4 With Casing Across BOP

If DP alert sounds with casing across BOP stack equipped withrams capable of shearing the casing, follow proceduresdescribed in section VI.8.1. If casing cannot be sheared followprocedures described in section VI.8.3.

VI.8.5 Testing Operations

If DP alert sounds while well is flowing.

YELLOW 2.5% of water depth.1. Close SSTT ball valve at control panel.2. Disconnect SSTT (30 seconds).3. Pick up inside LMRP (close DSC).4. “U” tube drillstring contents using riser hydrostatic.5. Inform DPO and prepare for emergency disconnect.

RED 4.0% of water depth1. Close SSTT ball valve at control panel.2. Disconnect SSTT (30 seconds).3. Pick up inside LMRP (close DSC).4. Activate the emergency disconnect.

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VI.9 DEEPWATER WELL CONTROL EQUIPMENT

VI.9.1 Control Systems and Accumulators

The working pressure for control systems in deepwater is generally>35,000 kPa (>5,000 psi) for water depths greater than 1500 m(5,000 ft). Due to the necessity to pre-charge subsea bottles atthe surface, working pressure of the bottles can be quite high.Accumulators charged to >35000 kPa (>5,000 psi) differential onthe sea floor must be vented before retrieving the BOP stack tothe surface.

VI.9.2 BOP Pressure Testing

In deep water, consideration must be given to mud weights andBOP pressure ratings when testing. The differential pressure of themud column versus seawater gradient must be considered whenpressure testing the BOPs.

For example, a well in 2400m (8,000 ft) of water with 1800 kg/m3

(15 ppg) mud has a differential pressure across the BOPs of18600kPa (2,700 psi). For a BOP rated to 103000 kPa (15,000 psi),the maximum surface test pressure for these conditions would be84800 kPa (12,300 psi).

VI.9.3 BOP Stack and Riser

Risers should be equipped with a booster line. Pressure monitorsshould be placed on the BOP stack. A low-pressure (rated to themaximum anticipated hydrostatic mud weight) monitor should beplaced above the uppermost annular preventer. This monitor willgive an indication of cuttings build up in the riser, and uponshutting-in the well will indicate if gas is rising in the annulus. Ahigh-pressure monitor (rated to the stack working pressure) shouldbe placed in the choke line to monitor pressure below thelowermost ram.

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It is preferred to have an instrumented BOP stack with directreadings of pressure and temperature. These gauges provide amore accurate indication of the conditions at the BOP stack andremove uncertainties that arise from otherwise estimating pressuredrops from a fluid at low temperature and high pressure.

Figure VI.16 below shows the preferred BOP stack arrangement fora dynamically positioned rig.

Up p erAnnula r

BOP

Low erAnnula r

BOP

Connec to r

Blind / Shea rRa m s

Ra m s

Pip eRa m s

Choke line

Kill line

We ll hea d c onnec to r

Pip eRa m s

Ca sing Shea r

M ini c o lle tc onnec to r

M ini c o lle tc onnec to r

Senso rs:Pressure 0-1034 b a r

(0-15k p si).Tem p era ture –40 to 150 C

(-40 to 300 F)

Tra nsm itte rs:Pressure 0-700 b a r

(0-10k p si).Tem p era ture -40 to 150 C (-40 to 300 F).

Figure VI.16Preferred Stack Arrangement for DP Rig

FailsafeValves

Key

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The stack should consist of 5 BOP rams and two annular BOPs. Thefifth ram BOP shall be capable of shearing casing. The casingshear ram is located below the blind shear rams to enableshutting in the well after shearing the casing. This is used in caseswhere the casing may become stuck and the rig needs todisconnect.

Dual annular preventers allow for maximum redundancy. The topannular should be used as the primary well control tool.

VI.9.4 BOP Rams

In deepwater wells, hydraulics, ECD and hole (or riser) cleaningbecome an issue. Therefore, tapered drillstrings may becommonly used. The number and size of pipe rams required willbe determined by the drillstrings. When a tapered drillstring is inuse, the BOP stack should be equipped with one of the followingpipe ram configurations.

a. Two (2) sets of pipe rams for the larger size string and one (1)set for the smaller size string of drillpipe.

b. Two (2) sets of pipe rams for the larger size string and one (1)set of variable bore pipe rams to fit both sizes of drillpipe.

c. Two (2) sets of variable bore pipe rams to fit both sizes ofdrillpipe.

d. One (1) set of pipe rams for the larger size string and one (1)set of variable bore pipe rams to fit both sizes of drillpipe.

e. One (1) set of pipe rams for the larger size string and one (1)set of pipe rams for the smaller size string and one (1) set ofvariable bore pipe rams to fit both sizes of drillpipe.

Note: Caution needs to be taken when using variable bore rams(VBR) because some of these rams are very limited in the smallerranges of pipe on the amount of weight that can be hung off. ForDP operations it’s important that the rams are capable of hangingthe weight of the drillstring as the rig may need to disconnect. For

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example purposes only, the table below shows the hang offcapacity of one manufactures rams.

VBR HANGOFF CAPACITY (POUNDS)BOPSize

Description Pipe5”

Pipe3 ½”

Pipe2 7/8”

11” 15M 5” to 2 7/8” 450,000 150,000 40,00016 ¾” 10M 5” to 2 7/8” 450,000 294,000 70,00018 ¾” 15M 5” to 3 1/2” 450,000 140,000

The hang off capacity of the actual rams being used should beknown.

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Revision: 0Chapter VII Slim Hole Considerations.

Chapter VII - SLIM HOLE CONSIDERATIONS

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VII.1 SLIM HOLE CONSIDERATIONS – PRIMARY CONTROL.................................................................... 197VII.1.1 Causes of Kicks ..................................................................................... 197VII.1.2 Kick Prevention...................................................................................... 198

VII.2 SECONDARY CONTROL....................................................................................................................... 199VII.2.1 Rapid Shut-in ......................................................................................... 199

VII.3 PRE-RECORDED INFORMATION......................................................................................................... 199VII.3.1 Slow Circulating Rates (SCR)................................................................ 199VII.3.2 Determination of Annular Pressure Losses ........................................... 200

VII.4 SLIM HOLE KICK TOLERANCE............................................................................................................ 203VII.5 SLIM HOLE WELL CONTROL METHODS............................................................................................ 203

VII.5.1 Slim hole Wait & Weight Method - Calculations .................................... 203VII.5.2 Slim Hole Wait & Weight Method - Operations ..................................... 206VII.5.3 Slim Hole Driller’s Method...................................................................... 207

VII.6 ANNULAR PRESSURE LOSS CALCULATION SHEET ....................................................................... 209VII.7 SLIM HOLE WELL DECISION TREE...................................................................................................... 210

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VII.1 SLIM HOLE CONSIDERATIONS – PRIMARY CONTROL

VII.1.1 Causes of Kicks

Swabbing

The hydrostatic pressure in the wellbore will always be reduced to someextent when the drillstring or full gauge tools are being pulled from thehole. This is particularly so in slim hole wells where the annular clearancebetween the drill collars and wellbore is smaller, resulting in less flow-byarea for the fluid to bypass as the bit/drillstring is pulled. The reduction inhydrostatic pressure should not be such that primary control is lost.

Lost Circulation

In slim hole drilling, the annular pressure friction losses are much higher thanconventional drilling. This is caused by the very small annular clearancesbetween the pipe and hole and the extremely fast rotation of the drillstring.These high frictional losses increase the equivalent circulation density andcan cause lost circulation in areas where conventional drilling practicesand densities would not.

Insufficient Mud Weight

Slim hole applications with small annuli cause significant frictional pressureloss to occur between the pipe and wellbore wall as the drilling fluid flowsup the annulus. This pressure loss acts to increase the bottom hole pressurewhile circulating and thereby increases the equivalent circulating density.This increased ECD can mask the penetration of an over-pressured sectionand prevent a hydrocarbon influx to occur as long as the pumps are on.However, when the pumps are shut off, the loss of frictional pressurereduces the hydrostatic pressure and an influx can occur at that time.Similarly, the high rotational RPM common to slim hole drilling can cause asignificant increase in annular pressure losses and ECD. Slowing down orstopping pipe rotation will remove this frictional pressure and allow an influxto occur if the drilling fluid density is lower than required to balanceformation pressure.

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VII.1.2 Kick Prevention

Drilling Connections

When the rotating and circulating frictional losses are removed from theannulus during a connection, the probability of an influx or kick will beincreased. Unfortunately, this is also the time that tank levels fluctuate mostmaking detection difficult. To increase the detection capability andreduce potential kick sizes, all connections in the producing hole sectionsshould be flow checked in the following manner:

1. Prior to making the connection and with the pumps still running atdrilling speed, stop the top drive and observe for a gain.

2. If no gain occurs after a reasonable length of time, shut downthe pumps. Observe the well a second time.

3. Proceed with making the connection

This method will account for the fact that both the high RPM and smallannulus cause very high frictional pressure losses. These losses are removedduring connections when the top drive is stopped or the pumps shut down.These high losses and resulting increases in ECDs can mask a situation inwhich the mud density is insufficient to hold back a gas influx.

Pump Pressure Decrease / Pump Stroke Increase

When an influx enters the wellbore, the fluid column in the annulusbecomes lighter. The mud in the drillpipe begins to "U-tube" and the drillermay observe a pressure decrease which may of may not be accompaniedby an increase in pump strokes.

This particular warning sign may not mean there is a kick in the wellbore. Itmay be an indication of pump problems, washout in the string, washednozzles, etc. It is still a good idea to flow check whenever a pump pressuredecrease is detected.

In slim hole wells, the exact opposite may happen. An influx of gas maycause an increase in pump pressure if the influx increases the velocity in theannulus. Such an indicator should be carefully assessed as it could also begenerated by hole pack off problems such as mild wellbore collapse orrapid accumulation of drill cuttings. However, the latter causes will beaccompanied by a noticeable increase in torque.

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VII.2 SECONDARY CONTROL

VII.2.1 Rapid Shut-in

Early and rapid shut in on slim hole wells is a critical step in reducing thekick influx volume, the related choke pressures and the chances of losingreturns during subsequent kill procedures. The smaller annular clearancesresult in significantly longer influx height when compared to conventionalwells.

VII.3 PRE-RECORDED INFORMATION

VII.3.1 Slow Circulating Rates (SCR)

A unique set of SCR readings will be taken for all slim hole wells prior todrilling out the surface casing shoe and before tripping in the hole eachtime the bit, BHA, or nozzles are changed.

1. Make up and run in the bit and first stand of drill collars, using the appropriate cross over, install the top drive.

2. Circulate at 3 SCR rates (i.e. 15, 30, 45 spm) and record the standpipe pressures. These values will be called the surface equipment and bit friction pressure losses (SPL + BPL). Although there will be some annular pressure along the stand of collars, it is considered to be negligible.

Record these SCR readings on the Annular Pressure Loss (APL) CalculationSheet that can be found in Section VII.6.

The SCR will be chosen to kill the well that results in an APL less than thatrequired to cause some sort of formation breakdown and lost returns.

Although the annulus will be exposed to APLs which are many times higherthan the SCR APLs, knowing accurately the bottom hole pressure during awell control situation is always desirable.

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Another significant reason for using a low SCR in slim holes is that theextremely small annulus results in much more rapid changes in influx heightand annular pressure requiring rapid adjustments of the choke to maintainconstant bottom hole pressure.

Calculate the APL using the following method. Assuming the APL isdistributed evenly from the surface to TD, start with the highest SCR andcalculate the ECD at the shoe and at TD or any known weak zone. If thereappears to be a chance of formation breakdown, go to a lower SCR rate.Select the fastest SCR that will not cause well problems. If the one selectedis not the slowest possible, and choke operational control is difficult tomaintain, consider changing to a lower rate.

If the SCR-APL does not pose significant risk of formation breakdown and isless than 100 psi then a conventional well control method can be used.

VII.3.2 Determination of Annular Pressure Losses

Annular pressure loss (APL) is the most important entity for slim hole wellcontrol and in fact is what differentiates slim hole well control methods fromconventional well control methods. The primary complication in circulatingout an influx in a slim hole well is the fact that the APL is high even at slowcirculating rates (SCR). Figure VII.1 below illustrates the difference inannular pressure losses between a 4 3/4" slim hole well and a 6 3/4"conventional well design.

APL Conventional vs Slim Hole Well(8,500 ft with 9.5 ppg mud)

0200400600800

1000

0 10 20 30 40 50 60 70SCR (gpm)

APL

(psi

)

6 3/4" Hole4 3/4" Hole

Figure VII.1The determination of annular pressure losses at the reduced circulationrates is critical for two reasons. First, if the APL is above the threshold valuethat will cause lost circulation while circulating out a kick, then it will haveto be accounted for in the well control process. This is achieved by slightlymodifying either the Driller's method or the Wait and Weight method in such

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a way that the APL is accounted for by the choke adjustment, much thesame way choke line friction losses are accounted for in offshoredeepwater drilling.

The annular pressure loss is calculated with the following equation:

APL = SCRP - DSPL - SPL - BPL

Where: APL = Annular pressure loss.SCRP = Slow circulating rate pressure (measured).SPL = Surface pressure loss (measured).BPL = Bit & nozzle pressure loss (measured).DSPL = Drillstring pressure loss (calculated for collars & drillpipe).

Note that in section VII.3.1, we have a procedure for measuring the SCRand another for measuring the surface equipment losses (SPL) andbit/nozzle losses (BPL) simultaneously.

Calculating the internal drillpipe and collar friction pressure losses is astraightforward exercise when using common oil field units. The process isfurther simplified by the fact that fluid flow regime in the drillpipe at a slowcirculating rate is laminar for a typical range of fluid properties.

Internal Drillstring Frictional Pressure Losses

STEP 1: Obtain the dimensional parameters required.

a. Drillpipe ID ddp - inchesb. Drillpipe length Ldp - feetc. Drill collar ID ddc - inchesd. Drill collar length Ldc - feete. Kill mud plastic viscosity PV - centipoise f. Kill mud yield point YP - lb/100ft2

STEP 2: Calculate the average fluid velocity (ft/sec):

a. Drill collars: Vdc = GPM ÷ (2.448 x ddc2)

b. Drillpipe: Vdp = GPM ÷ (2.448 x ddp2)

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STEP 3: Calculate the frictional pressure losses (psi):

a. Drillcollars: PLdc = (PV x Vdc x Ldc ) + ( YP x Ldc ) ( 1500 x ddc2 ) (225 x ddc )

b. Drillpipe: PLdc = (PV x Vdp x Ldp ) + ( YP x Ldp ) ( 1500 x ddp2 ) (225 x ddp )

DSPL = PLdc + PLdpNote: The effects drillpipe internal upsets are considered negligible

Example Calculation of APLStep 1: Obtain the dimensional and measured parameters:TD = 8500 ftDrillpipe: 3” ID x 7700 ftDrill collars: 2.75” ID x 800 ftMud properties: KMW = 9.0 ppg, YP = 10 lb/100ft2, PV = 8 cp.Measured surface equipment and bit losses @ 30 gpm = 65 psiMeasured SCRP @ TD & 30 gpm = 485 psi

Step 2: Calculate the average fluid velocity:

Vdc = GPM ÷ (2.448 x 2.752) = 1.6204 ft/sec

Vdp = GPM ÷ (2.448 x 32) = 1.3616 ft/sec

Step 3: Calculate the drillstring frictional pressure losses:

PLdc = (8 x 1.6204 x 800 ) + ( 10 x 800 ) = 14 psi ( 1500 x 2.752 ) (225 x 2.75 )

PLdc = (8 x 1.3616 x 7700 ) + ( 10 x 7700) = 120 psi ( 1500 x 32 ) (225 x 3)

DSPL = 14 psi + 120 psi = 134 psi

Step 4. Determine the annular pressure losses:

APL = 485 psi - 65 psi - 134 psi = 286 psi

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VII.4 SLIM HOLE KICK TOLERANCE

The small annular clearance in a slim hole well causes the same kickvolume compared to a conventional well, to spread out much further. Thisreduces the bottom hole pressure proportionally, resulting in higher chokepressures at surface to maintain constant bottom hole pressure. Higherchoke pressures are applied directly to the casing shoe as the influx iscirculated out. The result is that slim hole wells have a much smaller kicktolerance compared to conventional wells.

VII.5 SLIM HOLE WELL CONTROL METHODS

To accommodate the unique features of slim hole well designs we arerequired to slightly modify the two circulating methods to arrive at:

- The slim hole Wait & Weight Method- The slim hole Drillers Method

VII.5.1 Slim hole Wait & Weight Method - Calculations

The slim hole Wait & Weight method includes additional steps to accountfor high annular pressure losses. As with conventional Wait & Weightmethods, the starting point on the pump schedule is the initial drillpipecirculating pressure (ICP). The drillpipe circulating pressure will decline on astraight line basis as the kill mud progress down the pipe. After the kill mudreaches the bit, the drillpipe pressure is held constant until the choke iswide open. Thereafter the circulating pressure will rise automatically to afinal circulating pressure.

The fundamental difference between conventional and slim hole Wait &Weight methods is the magnitude of the final pressure rise due to annularpressure losses is much higher in the slim hole case and must be accountedfor.

The significant increase in drillpipe pressure is accounted for by using aslightly modified naming convention for the process concerned. We willuse the term intermediate circulation pressure (IntCP) to identify the

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pressure that will be maintained as the kill weight mud rises up the annulus.The final circulating pressure (FCP) will be the pressure that will occur whenkill mud reaches the choke.

1. After the well has been secured and pressures have stabilized, calculatethe kill mud weight.

KMW (ppg) = SIDPP (psi) ÷ .052 ÷ TVD (ft) + OMW (ppg)

Trip Margin will not be included in the calculation for kill mudweight. The major reason for this is to avoid unnecessaryadditional wellbore pressure that could result in formationbreakdown.

2. Calculate Initial Circulating Pressure

ICP = SCRP + SIDPP - APL

3. Calculate Intermediate Circulating Pressure

IntCP = ( SCRP - APL ) x KMW OMW

4. Calculate Final Circulating Pressure

FCP = SCRP x KMWOMW

5. Calculate surface to bit strokes

Drillstring volume = StrokesPump Output

6. Calculate time to pump surface to bit.

Total strokes from surface to bit = Time Strokes per minute

7. Once the preceding calculations are completed, fill out the kill sheetgraph by plotting drillpipe pressure versus pump strokes and time ongraph as follows.

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a. Plot Initial Circulating Pressure (ICP) at left of graph.b. Plot Intermediate Circulating Pressure (IntCP) at right of graph.c. Connect points with a straight line.d. Use the following formula to calculate the pressure drop per

increment and fill in the table at the bottom accordingly. (ICP - IntCP )/10 = Pressure drop per increment

e. For time, put “0” at the left of the graph and total time to pumpkill mud to the bit on the right. Divide total time by 10 tocalculate minutes per increment.

f. For strokes, put “0” at the left of graph and total strokes to biton the right. Divide total strokes by 10 to calculate strokes perincrement.

For example if it takes 1,000 strokes to fill the drillstring with a kill rate of 20strokes per minute and an initial circulating pressure of 1,000 psi with anintermediate circulating pressure of 500 psi, then the pumping schedulewould appears as follows:

250

350

450

550

650

750

850

950

Initi

al C

irc. P

ress

ure

250

350

450

550

650

750

850

950

Inte

rmed

iate

Circ

. Pre

ssur

e

TIME 0 5 10 15 20 25 30 35 40 45 50STKS 0 100 200 300 400 500 600 700 800 900 1000PRES

S1000 950 900 850 800 750 700 650 600 550 500

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VII.5.2 Slim Hole Wait & Weight Method - Operations

Circulate Kill Mud to the Bit

1. Once the kill sheet graph has been completed and the mud weight hasbeen raised to the desired value, prepare to circulate through thechoke; open choke manifold valve upstream of choke (or downstream ifapplicable), zero stroke counters, ensure good communicationsbetween choke operator.

2. Once pressures have stabilized, bring the pump to kill rate speed whileadjusting the choke pressure an amount equal to the previouslydetermined annular friction pressure losses (APL).

3. Once the pump is up to speed and the pressures have stabilized, record

the actual circulating drillpipe pressure.

If the actual circulating pressure is equal to, or reasonably close to thecalculated ICP, continue pumping and adjust the stand pipe pressureaccording to the schedule.

If the actual circulating pressure is significantly different from thecalculated ICP, stop the pump, shut the well in, and investigate thereason. Ensure there is no trapped pressure.

Any marginal difference between the actual and calculated initialcirculating pressure is most likely due to the fact that the APL used tocalculate the ICP was inaccurate. A closer approximation of the APL,hence a corrected intermediate circulating pressure, IntCP, can bedetermined from the initial circulating pressure as follows:

APLactual = (Actual initial circulating pressure) - SIDPP + SCRPIntCP = (SCRP - APLactual) x KMW / OMW

The stand pipe pressure schedule can therefore be corrected to takeinto account the adjusted circulating pressures.

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Circulate Kill Mud to Surface

1. When kill mud enters the annulus, the choke operator holds the drillpipepressure constant (at IntCP) until the choke is fully open. Thereafter, thecirculating pressure will consequently increase to final circulatingpressure (FCP).

2. Once the uncontaminated kill mud returns and the kill circulation isdeemed complete the well will be checked for flow through the chokebefore opening the BOPs.

Note that during the circulation, there will come a time when the killmud reaches sufficient height in the annulus that the hydrostatic pressureadded to the APL will balance the formation pressure and the choke willbe in the fully open position. This will occur before kill mud reachessurface and care must be taken to ensure the kill mud circulation iscompleted.

VII.5.3 Slim Hole Driller’s Method

First Circulation - Circulating the kick out

1. Once the pressures have stabilized, prepare to circulate through thechoke; open choke manifold valve upstream of choke (or downstream ifapplicable), zero stroke counters, ensure good communicationsbetween choke operator.

2. Bring the pump to kill rate speed while adjusting the choke in a way thatreduces the casing pressure an amount equal to the previouslydetermined annular friction pressure (APL) losses. This choke adjustmentshould take place over the same duration of time it takes for the pumpto get up to the SCR and for the outflow to stabilize. This may take 20-30seconds. A faster drop in choke pressure will reduce the bottom holepressure and may introduce another kick whereas a slower drop willincrease the bottom hole pressure and risk leak off. Construct a chart tobring up the pump as shown in section V.17.2.

3. When kill rate speed is established, the choke operator should switch tothe drillpipe gauge and hold this pressure (calculated ICP) constant untilthe influx is removed from the wellbore. Note the casing pressure just

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prior to shutting down pumping. This casing pressure should stayconstant while kill mud is circulated to the bit using a drillpipe pressureschedule.

4. The active mud system should be adjusted to the proper kill mud weight.

Second Circulation - Kill mud to the bit

1. Bring the pump to kill rate speed while adjusting the choke in a way thatreduces the casing pressure an amount equal to the previouslydetermined annular friction pressure (APL) losses. This choke adjustmentis identical to that used when initiating the first circulation.

2. When kill rate speed is established, switch to the drillpipe gauge andfollow the drillpipe schedule until heavy mud reaches the bit. This willoccur while dropping from the initial circulating pressure (ICP) to theintermediate circulating pressure (IntCP).

Second Circulation - Kill mud to the surface

1. When the kill mud enter the annulus, hold the drillpipe pressure constantuntil the choke is full open. Continue circulating until heavy mudreaches the surface. The drillpipe circulating pressure will increase tothe same FCP as was determine for the Wait and Weight method. Referto section VII.5.2 if the pressure varies significantly from the expectedvalues.

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VII.6 ANNULAR PRESSURE LOSS CALCULATION SHEET

Sedco Forex Annular Pressure Loss Calculation Sheet

This calculation is for a reduced flow rate (SCR) of : 30 GPM

Measured surface equip. and bit pressure losses (SPL + BPL) : 10 SPM : 30 GPM : 65 psi

Measured SCR pressure at total depth (SCR) : 10 SPM : 30 GPM : 485 psi

Required Information

Measured depth (MD) : 8500 ft Drill pipe ID (d dp) 3 inMud density : 9.00 ppg Drill pipe length (L dp) 7700 ftMud YP : 10 lb/100 ft 2 Drill collar ID (d dc) 2.75 inMud PV : 8 cP Drill collar length (L dc) 800 ft

Average Fluid Velocity in Drill Pipe and Collars

Drill collars : Vdc = GPM ÷ (2.448 x d dc2)

= ( 30 ) ÷ ( 2.448 x ( 2.75 ) 2 ) = 1.62 ft/sec

Drill pipe : Vdp = GPM ÷ (2.448 x d dp2)

= ( 30 ) ÷ ( 2.448 x ( 3 ) 2 ) = 1.36 ft/sec

Drill String Frictional Pressure Losses (DSPL)Note: Assumes flow is Laminar using Bingham Plastic equation

Drill collars : PL dc = ( PV x V dc x L dc ) + ( YP x L dc ) ( 1500 x d dc

2 ) ( 225 x d dc )

PL dc = ( 8 ) x ( 1.62 ) x ( 800 ) + ( 10 ) x ( 800 )( 1500 x ( 2.75 )2 ) ( 225 ) x ( 2.75 )

PL dc = ( 10371.09 ) + ( 8000 ) = 14 psi( 11343.75 ) ( 618.75 )

Note: Assumes flow is Laminar using Bingham Plastic equationDrill pipe : PL dp = ( PV x V dp x L dp ) + ( YP x L dp )

( 1500 x d dp2 ) ( 225 x d dp )

PL dp = ( 8 ) x ( 1.36 ) x ( 7700 ) + ( 10 ) x ( 7700 )( 1500 x ( 3 )2 ) ( 225 ) x ( 3 )

PL dp = ( 83878 ) + ( 77000 ) = 120 psi( 13500 ) ( 675 )

DSPL = Pl dc + Pl dp = 14 + 120 = 134 psi

Annular Pressure Losses (APL)

APL = SCR - DSPL - (SPL + BPL) = ( 485 ) - ( 134 ) - ( 65 ) =

APL = 286 PSI

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VII.7 SLIM HOLE WELL DECISION TREE

USE CONVENTIONALWELL CONTROL

Estimate annulus frictionlosses at kill rate from SCR’s

Estimate maximum weak pointpressures during conventional

well control

Will conventional well controlcause wellbore losses ?

Is estimated annulus pressure dropgreater than

100 psi?

Can the annulus pressuredrop be reduced to 100 psi by

reducing kill rate?

USE SLIM HOLE WELLCONTROL

NO

YES

NO

YES

YES

NO

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Revision: 0Chapter VIII HP/HT Well Drilling.

Chapter VIII - HP/HT WELL DRILLING

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VIII.1 PLANNING..............................................................................................................................................213VIII.2 OPERATING PROCEDURES ................................................................................................................214

VIII.2.1 Kick Prevention.......................................................................................214VIII.2.2 Kick Detection.........................................................................................215VIII.2.3 Kill Procedures .......................................................................................215

VIII.3 EQUIPMENT...........................................................................................................................................216VIII.3.1 Auxiliary Equipment................................................................................216VIII.3.2 BOP Stacks ............................................................................................217

VIII.4 MATERIALS ...........................................................................................................................................218

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A high pressure/high temperature (HP/HT) well is defined as a wellin which wellhead pressure could reach or exceed 70,000 kPa(10,000 psi) in the conditions created by shutting-in on a full gascolumn originating from the highest pressure zone, or in whichwellhead temperature could reach or exceed 150 ºC/ 300 ºF inthe conditions created by an uncontrolled flow from the highestpressure zone through the open choke manifold.

Drilling HP/HT wells requires special planning, operatingprocedures and equipment, in particular when oil based mud(OBM) is used; the following lists some of the most importantprecautions, procedures and equipment required that must bejointly addressed by the District/Rig Manager and the operatorbefore the HP/HT drilling phase commences.

VIII.1 PLANNING

- A simulation shall be made to estimate the maximum gas andfluid flow rates and wellhead temperature that could resultfrom an uncontrolled flow from the highest pressure zonethrough the open choke manifold.

- Specific plans must be made and written instructions given,prior to spud, to all personnel concerning non standardactions/procedures to be done to prevent or react to anywell control problems (see below).

- The casing program will incorporate plans for a contingencycasing string.

- BOPs to be fitted with casing rams to run production casing.Consider not using variable bore rams.

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VIII.2 OPERATING PROCEDURES

Consideration shall be given to the following procedures(applicable only when drilling the HP zone) and specificinstructions shall be given to the crew by the MIC.

VIII.2.1 Kick Prevention

- Limit ROP in such a way that the Rate of Penetration (R.O.P.)will not result in a value larger than:

LAG TIME (hrs.) x R.O.P. = 9.14 m (30 ft)

i.e. R.O.P.( in m/hr) < 9.14/ Bottoms up time (in hours)

The reasoning behind the 9.14 m (30ft) value is as follows:

When first drilling into a high-pressure reservoir, it is possible thatthe formation pressure could be only dynamically balanced.An influx could occur when the pumps are shut off during aconnection. In order to prevent taking more than one influx,bottoms-up has to be reached before stopping the pumps toadd another joint of drillpipe. If drilling with a top drive andthereby making connections every stand, then 27.43 m (90 ft)can be used.

Once drilling in a continuous reservoir and having establishedthat a static overbalance exists at the top of the reservoir, thereason for the restriction no longer exists and can therefore belifted.

- Flow check all connections.

- Have a drop in sub in the string. Consider dropping the dartbefore tripping out (except short trip).

- The MIC or his delegate to be on the rig floor when POOH inopen hole.

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- Complete a bottom’s up circulation through the choke if aswabbed influx is suspected.

- Use a DP stand fitted with a full opening safety valve on bottomif drilling with TDS to allow easy disconnection and installationof a kick assembly at rig floor level.

- Supervisory personnel to undergo special HP/HT well controltraining course prior to spud.

- Limit coring to short intervals (10m, 30 ft) and circulate severaltimes while POOH to limit risk of kick due to gas from the corecoming out of solution.

VIII.2.2 Kick Detection

Detection methods and procedures described in II.1.2 also applyto HPHT wells. However, it is recommended that additionalequipment such as MWD tools to detect the top of the HP/HTformation be used. All efforts shall be done to ensure that pit levelindicators and flow sensors are properly installed and calibrated.Use the minimum surface area in active pit volume to improve pitgain kick detection sensitivity.

VIII.2.3 Kill Procedures

- Control slow circulation rate in order not to exceed surfaceequipment capacity; in particular, procedures shall beprepared to cover the situation where the mud gas separatorcapacity or the down stream choke temperature limits arereached or likely to be reached. Gas expansion downstreamof the choke could lead to low temperatures causingblockages in the choke manifold or mud gas separator.

- Consider using bullheading method for influx volume greaterthan a specific value.

- When BOPs are equipped with lower kill valves, these valvesshall not normally be used for any reason other than

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emergency kill. Using them, in static mode to monitor annularpressure is permissible but not recommended.

VIII.3 EQUIPMENT

VIII.3.1 Auxiliary Equipment

- A 105,000 kPa (15,000 psi) working pressure kill pump shall beavailable, capable of slow circulation rates (± 79.5 liter/min or0.5 bbl/min)

- A 105,000 kPa (15,000 psi) working pressure kill line shall beinstalled between the kill pump and the rig floor.

- All primary pressure containment equipment shall be selectedfor H2S service.

- C/K manifold must have antifreeze injection facility.

- C/K manifold should have mud temperature measurementprobes upstream of chokes to help evaluate wellheadtemperature (unless BOPs are equipped with same) and downstream of choke to help assess risk of hydrate formation withremote reading at choke panel.

- C/K manifold should be fitted with high pressure flare(overboard) line - 35,000 kPa (5000 psi) rating minimum - andremote operated valves to open same and close the mud/gasseparator line.

- Mud/gas separator must be equipped with means ofcontrolling load (normally low pressure differential sensor,typically 150 kPa (20 psig) with remote reading at choke panel.

- Optionally, facilities to heat and to inject low pressure mud inthe separator may be added.

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- Mud/gas separator design and size must be reviewed to ensureadequate capacity (Appendix 7). An additional separator mustbe provided if necessary. Note: 8" to 10" diameter vent lineswith 4 to 6 m (15 to 20 ft) mud seal have been found necessaryin some instances.

- To monitor casing, wellhead and BOP wear, ditch magnetsshould be used. The ditch magnets should be cleaned andinspected at regular intervals not exceeding 12 hours ofrotation. A casing caliper survey should be run prior to drillingout of the casing set above the HP/HT formations. If excessivemetal particles are collected by the ditch magnets and/orabnormal wear on the drillpipe wear bands are noted, thecasing should be re-pressure tested and/or further casingcaliper surveys run. The casing should be pressure tested whenthe BOPS are pressure tested as per section III.6.1.

VIII.3.2 BOP Stacks

The minimum BOP standards required by Sedco Forex for surfaceand subsea stacks are described in sections III.1.1.3 and III.1.2.3respectively. However, in the North Sea the Institute of Petroleum,London Part 17 specifications on “Well Control During the Drillingand Testing of High Pressure Offshore Wells" will be followed. Theserequirements are as follows:

For surface BOPs on Jack-up or platform rigs, a minimum of one(1) 10 K psi annular preventer and four (4) ram type preventersshould be utilized.

For subsea BOPs a minimum of two (2) 10K psi annular typepreventers and four (4) 15 K or greater ram type preventers arerequired.

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VIII.4 MATERIALS

- The temperature rating of all BOP elastomers exposed to wellfluids shall be higher than the maximum anticipatedtemperature at the wellhead/BOP stack for continuousexposure of at least the expected duration of the well. Theelastomers shall also be certified to withstand the anticipatedpeak temperature/pressure for at least one hour. (The peaktemperature is the temperature which could be reached whenuncontrolled flow through the choke line has to be allowed forone hour).

- A sufficient quantity of kill weight mud to kill the well andmaintain a full wellbore until additional mud material can bedelivered should be keep on board until the completion isfinished.

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Revision: 00Chapter IX Horizontal and Highly Deviated Wells.

Chapter IX - HORIZONTAL AND HIGHLY DEVIATED WELLS

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IX.1 HORIZONTAL WELL CONTROL PROCEDURES ................................................................................221IX.2 HORIZONTAL WELL KILL SHEET .......................................................................................................222

IX.2.1 Construction of Kill Sheet .......................................................................222IX.2.2 When to Use Horizontal Kill Sheet .........................................................225

IX.3 MULTILATERAL WELLS.......................................................................................................................227IX.3.1 Multilateral Well Kill Procedures.............................................................229IX.3.2 Multilateral Well Kill Decision Tree ................................................230

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IX.1 HORIZONTAL WELL CONTROL PROCEDURES

Horizontal and highly deviated wellbores use the same basicprinciples as those for vertical of deviated holes. Down holeequivalent mud weights are calculated using the true verticaldepth, as always.

There are, however several additional points to consider. Theseare as follows.

- The purposes of drilling a horizontal well are to improvehydrocarbon recovery and to maximize the area of reservoirexposed at the wellbore in order to maximize production rates.It must therefore be considered that influx flow-rates, in theevent of a kick, will be considerably greater than for a welldrilled vertically through the reservoir.

Particular attention must be paid to tripping procedures when

the reservoir is exposed. - It is possible that shut-in pressures in the event of a kick may be

identical on both drillpipe and annulus although a large influxhas been taken. This would depend on the length of thehorizontal open hole section.

This is not a problem. However, it does mean that it is notpossible to check the validity of kick data.

The possibility that the wellbore contains a large influx shouldtherefore be addressed in such circumstances.

- There is greater potential for swabbing when a large surfacearea of reservoir is exposed. Correct tripping procedure mustbe rigorously adhered to. When tripping out of the hole, a flowcheck should be made once the bit gets out of the horizontalsection.

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It is quite feasible, in a horizontal well, that the horizontalsection is full of reservoir fluid and yet the well is dead. It istherefore recommended that extreme caution be paid whentripping back into such a reservoir after a round trip. Whenback on bottom it is recommended to do a flow check afterpartial circulation as an influx may then be high enough in thewell to be detected.

In the event of a kick while tripping it may not be possible todrop or pump down the dart. This will depend on the holeangle at the dart sub position. If it is not possible to install thedart into the dart sub, the "gray" valve can be used.

IX.2 HORIZONTAL WELL KILL SHEET

IX.2.1 Construction of Kill Sheet

Just as in section II.2.3, a kill sheet must be constructed. As the killmud is pumped, the heavy weight mud will counteract the SIDPPand it will decrease. However, if the kill sheet described in sectionII.2.3.1 is used, which is based on a vertical well, the bottom of thehole could be subjected to excessive pressure as kill mud iscirculated to the bit.

If we were to stop the pump when the kill mud is at the totalvertical depth of the well then the SIDPP would be zero. At anytime whilst the kill mud is being pumped the SIDPP, if we stoppedthe pump, would depend only on how close the kill mud was tothe total vertical depth.

The static pressure can be found at any time during the kill from thefollowing equation.

Static Pressure = SIDPP - SIDPP x TVDTVD

P

T

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Where:TVDP is the vertical depth of the kill mud at the timeTVDT is the total vertical depth of the well.

In the equation we can see that when TVDP equals TVDT, kill mud isat TVD, then the division is one and the static pressure is zero.Conversely the dynamic pressure at any time in the kill is relatedto the MD of the kill mud. The dynamic pressure will increase asthe mud is pumped. It can be found at any time in the kill fromthe following equation.

WhereMDP is the measured depth of the kill mud at that timeMDT is the total measured depth of the well.

As the kill mud is pumped along the pipe, the heavier mud willincrease the dynamic pressure. This should increase from theinitially recorded slow circulating pressure to the calculated finalcirculating pressure. This depends only upon how far along thedrillpipe the kill mud is. The FCP - SCRP is effectively thecalculated increase in pump pressure. When MDP equals MDT, killmud is at bit, then the dynamic pressure is the same as the FCP.When MDP is small then the dynamic pressure is similar to theSCRP.

The circulating pressure whilst the kill mud is being pumped to thebit is simply the sum of the static and dynamic pressures.

Circulating Pressure = Dynamic Pressure + Static Pressure

The main thing to ensure when summing up the Dynamic and theStatic pressure in the well is that both calculations were done forthe same physical point in the string.

If we look at how we can apply this concept to a kick sheet, wecould produce a new kick sheet. Instead, we have chosen toproduce an extension to our existing kick sheet. The idea of the

( )Dynamic Pressure = SCRP + FCP - SCRP MDMD

P

T

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extension sheet is that all the information that is required is firsttransferred from the standard kick sheet. The extension sheet isthen used to find the correct relationship for circulating pressuresversus pump strokes. This can then be plotted back on thestandard kick sheet.

We can look at how this would work in practice with thecompleted sheet below.

Figure IX.1Example Horizontal Well Control Sheet

The only additional information required to fill out the extension tothe kick sheet, is the TVD at the end of each of the sections ofmeasured depth. This data is readily available from the deviationcalculation programs of the surveyor or directional drillers. Theexample well has been broken into ten uniform sections of

WELL CONTROL KICK SHEET( Horizontal Extension )

Complete the standard Sedco Forex kick sheet up to Section G 1. You should then fill out this sheet to allow you to calculate your pumping pressure graph. You need totransfer the following information to this sheet.

Measured Depth = 11672 ftTrue Vertical Depth = 6279 ftSlow Circ Rate Press = 1700 psiSIDPP = 326 psiFinal Circ Pressure = 1877 psiStrokes To Bit = 1678 stks

You can then find the Pressure Increase :Pressure Increase = F.C.P. - S.C.R.P. = 177 psi

You should then break the well up into ten sections of measured depth, ensure the well profile is adequately described, and place the values in Row A of the tablebelow. You should then proceed through the calculations line by line until the table is full. Once the table is full the values can be used to draw your pressure againststrokes graph as normal. The rest of the kick sheet is then filled out as usual.

1 2 3 4 5 6 7 8 9 10

A M.D. 0 1167 2334 3502 4669 5836 7003 8170 9338 10505 11672B M.D. Ratio Row A ÷ Measured Depth 0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0C Strokes Strokes To Bit x Row B 0 168 336 503 671 839 1007 1175 1342 1510 1678D Dynamic Pressure SCRP + ( Pressure Inc x Row B ) 1700 1718 1735 1753 1771 1789 1806 1824 1842 1859 1877

E T.V.D. at M.D. in Row A 0 1167 2334 3502 4263 5554 6140 6279 6279 6279 6279F T.V.D. Ratio Row E ÷ True Vertical Depth 0 0.186 0.372 0.558 0.736 0.885 0.978 1 1 1 1G Static Pressure SIDPP - ( SIDPP x Row F ) 326 265 205 144 86 38 7 0 0 0 0

H Circulating Press. Row D + Row G 2026 1983 1940 1897 1857 1827 1813 1824 1842 1859 1877

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measured depth. The vertical depths corresponding to each ofthe measured depths are put in row E. Remember this informationshould be pre-recorded. Although in this example the ten stepsare exactly equal, this is not a requirement of the sheet. It wouldwork with any ten measured depth points. The main priority is toensure that the ten points are chosen to adequately describe thewell’s geometry and give a fairly even distribution of points for thefinal graph. It is probably easiest to use the ten calculated surveypoints that are closest to the ten uniform steps of measured depth.The even distribution of the points assists the choke operator infollowing the graph.

IX.2.2 When to Use Horizontal Kill Sheet

The extension sheet is applicable to all deviated wells. But inmany wells there will not be a large difference in the requiredcirculating pressure between the standard kick sheet and theextension.

The difference between the circulating pressure ( ∆ P ) calculatedby the standard kick sheet and the extension to the kick sheet canbe calculated at any point in the well by the following equation.

Using this equation with the information shown in Figure IX.1 it canbe shown that the largest difference in pressure between thehorizontal extension and a standard kick sheet in this case wouldbe 890 kPa (127 psi). This is shown graphically in Figure IX.2.

∆P = SIDPP × −

TVDTVD

MDMD

P

T

P

T

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To t a l St ro ke s

1 80 0

1 85 0

1 90 0

1 95 0

2 00 0

2 05 0

2 10 0

0 2 00 40 0 6 0 0 8 0 0 10 00 1 20 0 14 0 0 16 0 0 1 8 00

Sta nd a rd Kic kShe e t

Ex te nsio n

C irc u la t in gPre ssu re

(p si)

Pum p Pre ssure Sc he d u le

Figure IX.2

The case shown in Figure IX.1 assumes a 1 ppg increase. In mostcases involving horizontal wells it is unlikely that formations will beencountered requiring an increase in mud weight of 1 ppg. Kicksare most likely to be caused by swabbing and will not require anyincrease in mud weight. In these cases using the standard killsheet or the horizontal extension will not result in any significantpressure differences.

The following guidelines can be used to determine when thehorizontal extension should be used.

1. A vertical killsheet should be used if the initial, stable SIDPP is100 psi or less, regardless of well profile

2. If the maximum difference between the circulating pressurecalculated by the standard kick sheet and the extension to thekick sheet is found to be less than 175 kPa (25 psi), a verticalkillsheet should be used.

3. A deviated killsheet should be used if MAASP - SICP < 2 ∆ P

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This will depend on the field situation, such as shoe strength andcasing pressure. If there is a risk of lost circulation the kick sheetextension may need to be used at lower maximum difference

A "Horizontal Kick Sheet" extension template can be found inAppendix 3.

Driller’s Method

The first circulation of the Driller’s method (Ref. II.2.3.2) requires nochanges to be used in a highly deviated or horizontal well.However, the pump schedule (circulating pressures versus strokesgraph) referred to in the procedures will be completed asdescribed in this section using the extension sheet.

IX.3 MULTILATERAL WELLS

Provided reliable hydraulic isolation is maintained, existing wellcontrol methodology could apply and each wellbore treatedseparately. Otherwise, calculations need to account for theweakest formation in either bore, possible influx from both boresand the different mud weights in both bores. Kick detection relieson the existing warning signs, pit gain and increased return flow.Pit gain is more sensitive to low intensity kicks and the increasedreturn flow is more sensitive to high intensity kicks.

Indications that the kick occurred in the active bore would be adrilling break or shut in casing pressure being greater than the shutin drillpipe pressure and shut in drillpipe pressure remaining steadywhile shut in casing pressure increases during volumetric control.

Indications that the influx was from the static wellbore would bethat the shut in drillpipe pressure is equal to the shut in casingpressure, or that both the shut in casing pressure and shut indrillpipe pressure are increasing during volumetric control.

Either the "Wait and Weight" or "Driller’s Method" can be useddepending on influx migration rate, company policy, etc. It should

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be noted that if the kick is from the static bore then the depth ofkick should be taken from the junction. Care needs to be taken toassess the weakest point in either wellbore as killing to the junctioncould lead to losses in one of the bores.

- The maximum allowable annular surface pressure (MAASP)should be calculated based on the weakest formation in allwellbores.

- Possible influxes from all wellbores should be considered.

For the active1 wellbore (i.e. the bore containing the drillstring)MAASP1 can be calculated by the following equation.

MAASP1 = LOT - [(MW1 - MWLOT) ÷ 0.052 x TVD1 weak point] (psi) (psi) (ppg ) (ppg) (ft)

For the static2 wellbore(s) (i.e. without drillstring) the possibility ofdifferent mud weights between the static and active wellboresmust be considered. MAASP2 can be calculated using thefollowing equation.

MAASP2 = LOT - [(MW1 - MWLOT) ÷ 0.052 x TVDcasing window] - [MW2 ÷ 0.052 x (TVDcasing window - TVD2 weak point)]

The final MAASP that should be used is the smaller of MAASP1 orMAASP2.

Caution should be taken when re-entering the main wellbore aftercompleting the lateral, as by then the fluid may have been in themain bore for a long time and its condition unknown. Any leak atthe shoe track creates the potential for hydrocarbons to bedirectly below the junction. In this case an under balancedsituation could occur when running in the hole.

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IX.3.1 Multilateral Well Kill Procedures

Once the well has been shut in upon detecting a kick, a decisionmust be made regarding the most appropriate action to kill thewell.

As in a conventional single wellbore well, an attempt shouldalways be made to use one of the standard kill techniques. This isparticularly true when the influx is taken from the active wellbore.A flow chart (Figure IX.3 on the next page) has been prepared tohelp in determining the proper course of action.

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IX.3.2 Multilateral Well Kill Decision Tree

YES

YES

YES

YES

NO

NO

Well Kicks

Known whichwellbore influxwas taken in

Circulate bottoms upwith original mud

Is influx inactive

wellbore

Determine kill mud weightbased on SIDPP and TVD atjunction of main and lateral

wellbores

Will kill mudweight exceed

weak pointfracture pressure

Are new SIDPPand SICP same?

Recalculate highest killmud weight which won’t

fracture well bore

Circulate active wellboreto kill mud weight

(Multilateral kill sheetNew SIDPP and SICP

Circulate active wellbore to kill mud(Multilateral kill

sheet)

Trip string into staticwellbore

Consider killing wellby bullheading

Determine new kill mudweight based on pore

pressure and TVD of influxinformation

Circulate both wellbores to second kill

mud weight

Kill complete

Use standard killtechniques

NO

NO

Figure IX.3Kill Decision Flow Chart for Multilateral Wells

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Revision: 0Appendix 1 Abbreviations / Definitions / References.

APPENDIX 1: Abbreviations / Definitions of Terms / References

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1.1 List of Abbreviations:

APL = Annular Pressure Losses.BHA = Bottom Hole Assembly.BHP = Bottom Hole Pressure.BOP = Blowout Preventer.BPL = Bit & Nozzle Pressure Losses.Ca = Annular Capacity.CLFL = Choke Line Friction Losses.CSG = Casing.DC = Drillcollar.DP = Dynamically Positioned, or Drillpipe.DPO = Dynamic Positioning Officer.DSPL = Drillstring Pressure Losses.DST = Drill Stem Test.ECD = Equivalent Circulating Density.EMW = Equivalent Mud Weight.FCP = Final Circulating Pressure.FCPadm = Maximum Admissible Final Circulating Pressure.Gfb = Formation Breakdown Pressure Gradient.Gi = Initial Pit Gain.Gmud = Pressure Gradient of Mud.GPM = Gallons Per Minute.HCR = Hydraulic Controlled Remote.HP/HT = High Pressure/High Temperature.IADC = International Association of Drilling Contractors.ICP = Initial Circulating Pressure.ID = Inside Diameter.IntCP = Intermediate Circulating Pressure (used for Slim Hole

Well Control).kg/l = Kilograms per liter.kg/m3 = Kilograms per cubic meter.KMW = Kill Mud Weight.LOT = Leak Off Test.LCM = Lost Circulation Material.LMRP = Lower Marine Riser Package.LWD = Logging While Drilling.MAASP = Maximum Allowable Annular Surface Pressure.M = ThousandsMAMW = Maximum Allowable Mud Weight.MD = Measured Depth.

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MGS = Mud Gas Separator.M.I.C. = Man In Charge.MSL = Mean Sea Level.MW = Mud Weight.MWD = Measurements While Drilling.New MAASP = MAASP with KMWNRV = Non Return Valve.NSDPP = New Static Drill Pipe Pressure.OBM = Oil Base Mud.OD = Outside Diameter.OIM = Offshore Installation Manager.OMW = Original Mud Weight.Pf = Formation (Fluid) Pressure.Ph = Hydrostatic Pressure of Mud.POOH = Pulling Out Of Hole.ppg = Pounds per U.S. Gallon - sometimes written lb/gal.PV = Plastic Viscosity.RBOP = Rotating Blowout Preventer.ROP = Rate Of Penetration.ROV = Remotely Operated VehicleSCR = Slow Circulating Rate.SCRmax = Circulating Rate when CLFL < SICP.SCRmin = Circulating Rate when CLFL < New MAASP.SCRP = Slow Circulating Rate Pressure or Kill Rate Pressure,

sometimes written as PSCR or KRP.SICP = Shut In Casing Pressure.SIDPP = Shut in Drill Pipe Pressure.SPL = Surface Pressure Loss.SPM = Strokes Per Minute.SWF = Shallow Water Flow.TD = Total Depth.TDS = Top Drive System.T.I.W. = Texas Iron Works.TVD = True Vertical Depth.UBD = Underbalanced Drilling.WBM = Water Base Mud.WOC = Wait On Cement.YP = Yield Point.

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1.2 Definition of Terms

Abnormal Pore Pressure - Pressure of a formation which exceeds or fallsbelow normal pressure which is expected at agiven depth.

Annular Pressure Loss - (APL) Pressure loss caused by the flow of fluidup the annulus.

Barite or Baryte - Barium sulfate BaSO4. A heavy mineral addedto drilling mud in order to increase its density.

Blowout - An uncontrolled flow of gas, oil or water from awellbore.

Bottom Hole Assembly - (BHA) That portion of the drill string whichincludes the bit, stabilizers, drill collars, heavyweight drill pipe, and ancillary equipment.

Bottom Hole Pressure - Total pressure created at the bottom of thewellbore.

Bullheading - Term for pumping a kick back into a formationwith the B.O.P. closed.

Cap Rock - An impervious layer of rock which overliesreservoir rock, preventing migration of fluids outof the reservoir.

Casing Burst Pressure - The amount of internal pressure that causes thewall of the casing to fail.

Casing Seat - The lowest point in a well at which casing is set.

Density - The weight per unit volume of a substance.

Differential Pressure - Difference between wellbore fluid pressure andpore pressure. Can also relate to opposinginternal and external forces acting on equipment.

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Drilling Break - A significant increase in the rate of penetrationby the drill bit. It may indicate that the bit haspenetrated a high pressure zone and therebywarning of the possibility of a kick.

Equivalent Circulating - (ECD) The effective density at any depthDensity created by the sum of the total hydrostatic

pressure plus annular pressure loss.

Equivalent Mud Weight - (EMW) A pressure exerted at a depth of interestwhich is converted into a density.

Flow check - A flow check is the observation of the wellwithout circulation. Flow checks are made todetermine if the well is, or is not flowing. Theduration of a flow check must be whatever timenecessary to determine without question whetherthe well is static or flowing

Geothermal Gradient - The rate at which subsurface temperatureincreases with depth. The earth averages 1degree C per 33m (1 degree F per 60 ft.) but maybe considerably higher.

Glycol (Ethylene) - A colorless liquid when mixed with water lowersits freezing temperature. Used as a desiccant inremoving water from gas.

Hydrostatic Pressure - Pressure exerted by a column (Ph) of fluid atrest.

Intermediate String - Usually set in a transition zone of an abnormallypressured formation or used to protect weakformations, to case off loss circulation zones,hole sloughing, caving and reservoir formationsand to provide blowout protection. Cementingprogram may be designed to shut offhydrocarbon zones or cover flowing salt sections.

Kick - An entry of oil, gas or water into the wellbore.When the bottom hole pressure becomes less

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than formation pressure and the permeability isgreat enough, formation fluid will enter thewellbore causing a "kick ".

Kick Assembly - Assembly of full opening safety valve(s),circulating head and hose used to circulate, whennecessary, at pressures above Kelly or TDS ratedpressure.

Lag Time - Bottom's-up circulation time. Time it takes forthe mud to reach surface from bit at a givenpumping rate while circulating on bottom.

Leak-off Test Pressure - Pressure imposed at surface (normally by a lowvolume high pressure pump) on the mud columnwhich determines the pressure at which aformation of interest will start to take fluid

Liner - Installed as an intermediate casing string topermit deeper drilling, to separate the productivezones from other reservoir formations or fortesting purposes. Usually cemented to top ofliner.

Maximum Allowable AnnularSurface Pressure (MAASP) - Lessor of the surface pressure which if

exceeded may 1) cause loss of mud into aformation below the casing shoe, or 2) causecasing or other equipment failure.

Marine Conductor - A pipe driven, jetted or cemented in pre-drilledhole, to provide structural strength, to cover verysoft formations below the sea bottom, to serve asa circulation system for the drilling fluid and toguide the drilling and casing strings into the hole.

Normal Formation Pressure - Formation pressure equal to the pressureexerted by a vertical column of water with asalinity normal for the geographic area.

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Mud Gas Separator - An atmospheric or low-pressure vessel forseparating the gas from liquid in well returns.

Non Return Valve - Also Check Valve, device used to restrict theflow of fluid to only one direction.

Overbalance - The amount by which pressure exerted by thehydrostatic head of fluid in the wellbore exceedsformation pressure.

Overburden Pressure - Pressure generated by the fluid and solidmaterial (matrix) of the earth.

Permeability - The ability of fluid to flow from one pore spaceto another.

Production String - Installed to separate the productive zones fromother reservoir formations or for testing purposes.

Porosity - The spaces within a rock. The ratio of thevolume of interstices of a material to its totalvolume.

SCRmax - The circulating rate at which the chokelinefriction loss is equal to the shut-in casingpressure (SICP).

SCRmin - The circulating rate at which the chokelinefriction loss is equal to the maximum allowableannular surface casing pressure (MAASP)

Specific Gravity - The ratio of the weight of a given volume of asubstance at a given temperature to the weight ofan equal volume of fresh water at the sametemperature.

SI Units - (Système International d'Unités) This system ofunits, SI, was the outcome of a resolution of the9th General Conference of Weights andMeasures in 1948. Basic SI units used in wellcontrol are kiloPascal (kPa) for pressure; the

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meter (m) for length and the kilogram per cubicmeter (kg/m3) for density.

Subnormal Pore Pressure - Pressure of a formation which is below normalpressure expected at a given depth

Surface Casing - Installed to provide blowout protection; to sealoff water sands and prevent loss of circulation.This string is normally cemented to surface or atleast up to the shoe of the conductor string.

Underground Blowout - Uncontrolled flow of formation fluids enteringthe wellbore at one point and leaving the wellboreat any point other than the surface. The flow ismost likely to travel up the wellbore beforeexiting, but can on occasion travel down thewellbore to the receiving formation.

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1.3 Reference Documents

Sedco Forex DocumentsRE-EST-415-01 Accumulators For Subsea BOP StackRE-PR-RC-38 Degassing System InstallationNSD-TOP-057 Color coding for Ram BlocksNSD-TOP-016 Kick DrillsNSR-BUL-TCD-05NSR-BUL-TCD-02NSR-TOP-004 BOP Testing FrequencyNSR-016 BOP Pressure TestingNSR-039 BOP Quality ManagementEUA-TOP-005 BOP Quality ManagementEMS-401-01 Ram Type BOP'sEMS-400-01 Maintenance Standard - BOP AnnularsENG-EMB-415-01 BOP Accumulator unit isolation and bleed

down proceduresENG-EMB- 415-02 Min. Design Requirements for BOP

accumulator banks and 4-way valve manifold bleeder valve

TOP-001 Drill Stem Test Procedures710-TOP-DRL-07 Well Control Procedures - Gas flow while

drilling surface hole710-TOP-DRL-025 Well Control Procedures710-TOP-DRL-044 Procedures while killing in DP mode710-TOP-MAR-17 Blowout

Sedco Forex HSE Manual

Other DocumentsAPI Spec-16C Choke and Kill systems, First EditionAPI Spec-16D Control systems for Drilling Well Control

Equipment, First EditionAPI Spec-16E Design of Control systems for Drilling

Well Control Equipment, Latest EditionAPI RP-53 Blowout Prevention Equipment & systems for

Drilling Operations, Third editionAPI RP-54 Oil and Gas Well Drilling and Servicing

Operations, Second edition

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API RP-59 Recommended Practices for Well Control Operation (obsolete)

REFERENCE DOCUMENTS (continued)

Bailey T. J. NPD; “Deep Water Drilling Study”, Sedco Forex 15/1/94.

Bertin D., Lassus-Dessus J.; “Well Control Guidelines for Girassol”,SPE/IADC paper 52763 conference on 3/9/99.

Hansen S. A., Haggen S., Alvestad J. T.; “Drilling on the VoringPlateau, the well control challenges”, IADC conference 26/8/98.

Integrated Project Management; “Well Operation Policy Manual”,Policy Nr.: WCGEN007, Schlumberger, 21/02/96.

Institute of Petroleum, London part 17; “Well Control During theDrilling and Testing of High Pressure Wells.

John P. James, Ian M. Rezmer-Cooper, Sverre K. Sorskar:“MABOPP – A New Diagnostic for Deepwater Well Control”,SPE/IADC 52765.

Mathews J. L., Bourgoyne A. T.; “Techniques for Handling UpwardsMigration of Gas Kicks in a Shut-in Well”, IADC/SPE 11376.

Maus L. D., Tannich J. D., Ilfrey W. T.; “InstrumentationRequirements for Kick Detection in Deep Water”, OTC 8/5/78.

National Association of Corrosion Engineers (NACE) MR 01-75, 97“Sulphide Stress Cracking Resisting Metallic Material for OilfieldEquipment.”

Luo Y., Gibson A., Moutford C., Hibbert T., Weddle C.; “ WellControl Procedures Developed for Multilateral Wells”, Oil & GasJournal 94:45 11/4/96.

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Revision: 0Appendix 2 Conversion Tables.

APPENDIX 2: CONVERSION TABLES


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2 CONVERSION TABLE

Depth

Feet x 0.3048 to give Meters (m)Meters x 3.2808 to give Feet (ft)

Volume(U.S.) Gallon x 0.003785 to give Cubic Meters (m3)(U.S.) Barrel x 0.1590 to give Cubic Meters (m3)Cubic meter x 6.2905 to give (U.S.) Barrel (bbl)Liter x 0.0264 to give (U.S.) Gallon

Pressure

psi x 6.895 to give Kilo Pascals (kPa)kPa x 0.14503 to give Pounds per Square Inch (psi )kg/cm2 x 98.1 to give Kilo Pascals (kPa)psi x .0703 to give Kilogram per Square Centimeter (kg/cm2)kg/cm2 x 14.223 to give Pounds per Square Inch (psi)Bar x 100 to give Kilo Pascals (kPa)

Mud Weight

ppg x 119.8 to give Kilograms per Cubic Meter (kg/m3)ppg x .12 to give Kilograms per Liter (kg/l)kg/l x 8.345 to give Pounds per Gallon (PPG)kg/m3 x 0.008345 to give Pounds per Gallon (PPG)

Pressure Gradient

psi/ft x 22.62 to give Kilo Pascals per Meter (kPa/m)kPa/m x 0.04421 to give Pounds per Square Inch per Foot (psi/ft)


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Mud Weight to Pressure Gradient

ppg x 0.052 to give Pounds per Square Inch per Foot (psi/ft)SG x .433 to give Pounds per Square Inch per Foot (psi/ft)lb/ft3 x 0.00694 to give Pounds per Square Inch per Foot (psi/ft)kg/m3 x 0.000434 to give Pounds per Square Inch per Foot (psi/ft)kg/m3 x 0.00982 to give Kilo Pascals per Meter (kPa/m)

Flow Rate

Gallons/Minute x 0. 003785 to give Cubic Meters per Minute (m3/min)Barrels/Minute x 0.159 to give Cubic Meters per Minute (m3/min)Cubic Meters/Minute x 264.2 to give Gallons per Minute (gals/min)

Annular Velocity

Feet/Minute x 0.3048 to give Meters per Minute (m/min)Meters/Minute x 3.2808 to give Feet per Minute (ft/min)

Mass

Pounds x 0.454 to give kilograms (kg)Tons, Short(2000 lbs) x 908 to give kilograms (kg)Kilograms x 2. 2026 to give Pounds (lbs)

Pipe Weights

Pound/Foot x 1.49 to give Kilograms/Meter (kg/m)Kilogram/Meter x 0.671 to give Pound/Foot (lb/ft)

WELL CONTROL MANUAL

Ref.: HQS-PO-OPT-01

Page: 244

Issued: 07/10/1999

Revision: 0Appendix 3 Forms.

APPENDIX 3: FORMS Trip Sheet

Stripping SheetDecision TreeKill SheetsHorizontal Kick SheetWell Control RecordsAccumulator Test Function WorksheetsBOP Test Form

WELL CONTROL MANUAL

Ref.: HQS-PO-OPT-01

Page: 245

Issued: 07/10/1999


SEDCO FOREX TRIP SHEET

Column 1: This is the stand list as numbered when racked in the derrick.Record single stands for the first 5 stands under normalcircumstances. Then record every 3 to 5 stands.

Column 2: Note the trip tank gauge reading. The difference in reading after anincrement will be the measured amount of mud used to fill the holefor that increment.

Column 3: The displacement of the number of stands for one increment.

Column 4: Actual measured amount of mud used to fill the hole for thatincrement.

Column 5: Cumulative sum of numbers in column 4.

Column 6: Results of subtraction of column 3 from column 4. A negativenumber here may indicate the hole did not take enough mud(possible swabbing). A positive number may indicate the hole tooktoo much mud (losses).

Column 7: Cumulative sum of the numbers in column 6. This column givesthe total amount of fluid swabbed into the hole or the total lossessince the beginning of the trip.

RIG: _______________________ DATE: ___________________WELL: ______________________ TIME: ____________________DRILLER: ____________________ DEPTH: __________________

SEDCO FOREX TRIP SHEETREASON FOR THE TRIP:_____________________________________________________________Number of stands to have top of DC’s one stand below BOP’s: _______________________

Tick Displacement: DC1 DC2 OTHER HWDP DP1 DP2PULL ON: SizeEVEN l/m orSingle l/standDouble x m or stands

÷÷÷÷ 1000 = Vol. ( m3 )

STANDNb

TripTank

CalculatedHole fill (liters)

MeasuredHole fill (liters)

DiscrepancyRemarks

Gauge per increment perIncrement

Accumul. perIncrement

Accumul.

1 2 3 4 5 6 7 80

Note: Units and Calculations are in Metric System.

STANDNb.

TripTank

CalculatedHole fill (liters)

MeasuredHole fill (litres)

DiscrepancyRemarks



Accumul.

1 2 3 4 5 6 7 8

Note: Units and Calculations are in Metric System.

RIG: _______________________ DATE: ___________________WELL: ______________________ TIME: ____________________DRILLER: ____________________ DEPTH: ____________________

SEDCO FOREX TRIP SHEETREASON FOR THE TRIP:_____________________________________________________________Number of stands to have top of DC’s one stand below BOP’s: _______________________

Tick Displacement: DC1 DC2 OTHER HWDP DP1 DP2PULL ON: SizeEVEN bbl/ft orSingle bbl/standDouble x ft or stands

= Vol. (bbls)

STANDNb

TripTank

CalculatedHole fill (bbls)

MeasuredHole fill (bbls)

DiscrepancyRemarks



Accumul.

1 2 3 4 5 6 7 80

Note: Units and Calculations are in Imperial System.

STANDNb

TripTank

CalculatedHole fill (bbls)

MeasuredHole fill (bbls)

DiscrepancyRemarks



Accumul.

1 2 3 4 5 6 7 8

Note: Units and Calculations are in Imperial System.

WELL CONTROL MANUAL

Ref.: HQS-PO-OPT-01

Page: 250

Issued: 07/10/1999


SEDCO FOREX STRIP SHEETColumn 1 Time: Note the time at every operation is done.

Column 2 Operation: Suggested operation would be stripping, bleed mud at choke,influx migrating, lubricating.

Column 3 Bit Depth: Bit depth as pipe is being stripped.

Column 4 Pchoke: Choke Pressure used to monitor the well pressure.

Column 5 Change in Pchoke: Changes monitored in Pchoke. A positive or negativesymbol will precede Pchoke values as it increases or decreasesrespectively. But if the operation is either lubrication or bleeding write zero(0) and record the change in column 6 the hydrostatic of mudbled/lubricated.

Column 6 Hydrostatic of Mud Bled/Lubricated: Use negative (-) preceding bledvalue, when bleeding pressure to keep Pchoke from exceeding theMaximum Allowable Casing Pressure. Use positive (+) proceeding bledvalue, when bleeding to lubricate. Write N/A, when bleeding to compensatefor stripped pipe.

Column 7 Over Balance: Cumulative value added from last over balance value to thechange in Pchoke (Column 5) or hydrostatic of Mud bled (Column 6),whatever the case.

Column 8 Pipe Stripped: Quantity of pipe stripped in to the well, calculated inbarrels. Discrepancies between Column 8 and Column 9 values, should beanalyzed. Notice that recommended procedures are to strip full standlength.

Column 9 Volume of Mud Bled/Lubricated: Volume bled at a single operation, if influxis left to migrate, write zero (0). When the influx is at surface, stop bleedingprocess, because BHP decrease at this point will lead to another influx. Thenproceed with the static volumetric process described in Section II.2.3.3.

Column 10 Total Mud Volume: Cumulative value of the volume of mud bled in everyoperation. Carried from the operation above it and column 9.

Note: When stripping procedures are completed, killing procedures should be followed.

SEDCO FOREX STRIPPING WORKSHEETWell No. Rig Date Time : Sheet ______ of _______.Hole TVD: ft Mud Weight in Hole ppg Lubricating Mud Weight ppgInitial Bit Depth ft Maximum Allowable Casing Pressure: psi.Stripping Data

(Pipe Capacity + Pipe displacement) x Stand Length = Bbls

1)Volume of mud Displaced = ( bbl/ft + bbl/ft ) x ft = . bbls2)Volume of mud Displaced = ( bbl/ft + bbl/ft ) x ft = . bblsPchoke(SICP + Psaf + Pstep)= psi + psi + psi = . psi.Volumetric Control DataHydrostatic Pressure(PSI)/BBL = MW x0.052/ Ca ( ppg) x (0.052) / ( bbl/ft) ( psi/bbl)Max. Surf. Casing Pressure Increase = psi

1 2 3 4 5 6 7 8 9 10

Time Operation Bit

DepthPchoke

Change inPchoke

+/-

Hydrostaticof mudBled/

Lubricated.+/-

Overbalance

+/-

PipeStripped

Volumeof Mud Bled/Lubricated

+/-

TotalMud

Volume(Actual)

(h:min) (ft) (psi) (psi) (psi) (psi) (bbl) (bbl) (bbl)

(+) Increase

(-) Decrease

(0) Ifbleeding/Lubricating

(-) Bled

(+)Lubricated

N/Aif bled tocompensatefor pipe

(+)Over-balance

(-)Under-balance

(+)Bled

(-)Lubricated

Remember: It is better to shut in the well than to hesitate whenconditions require closure.

SEDCO FOREX WELL CONTROL PROCEDURESWhile posted Instructions are to shut well in

While Drilling

IF

- Drilling Break- Increase or Decrease in mud returns- Rise in level of mud tanks- Change in pump speed or pressure

- Stop drilling- If drilling with a kelly, raise Kelly above rotary table (time permitting)- Stop Pumps- Check Well For Flow

Well Stable Fluid Losses Well Flowing

- Notify man-in-charge- Resume cautious drilling

- Notify man-in-charge- Pump in fluid at reduced flow rate in order to maintain hydrostatic level- Pump lightest fluid available and record volumes pumped

- Close annular BOP- Open fail safes or remote control valve- Notify man-in-charge- Check space out and close rams- Hang off on floating unit- Bleed off between rams and annular- Record shut-in pressures and pit gain

Remember: It is better to shut in the well than to hesitate whenconditions require closure.

SEDCO FOREX WELL CONTROL PROCEDURESWhile posted Instructions are to shut well in

While Tripping

IF

- Mud volume displaced is not equal to pipe displacement

- Stop Tripping- Install Full Opening safety Valve- Check Well For Flow

Well Flowing

Fluid Losses

Well Stable

- Tighten safety valve- Close safety valve- Close annular- Open fail-safes or remote control valve- Notify man-in-charge- Make up kelly or TDS- Open safety valve- Record pressures and pit gain- Evaluate situation- Determine whether to strip or perform off- bottom kill

- Notify man-in-charge- Keep well full by pumping into annulus with lightest fluid available and record volumes pumped- Install inside BOP- RIH to bottom- Circulate at reduce flow rate in order to maintain circulation- Rotate slowly- Wait for orders- Be ready to close in the well

- Notify man-in-charge- Run in hole- Keep well full- Circulate according to orders

- Stop pumping- Install inside BOP- Notify man-in-charge- RIH as deep as possible, pumping as needed through kelly / topdrive- Pump into annulus with lightest fluid available and record volumes pumped- Rotate slowly and circ.- Wait for orders- Be ready to close in the well

Pump Reduced FlowVia Annulus

If No Returns (Total Losses)

If Returns(Partial Losses)

IF

While Drilling

Well startsto flow

- Do not stop pumping- Open diverter line / close diverter- Increase pump speed- Switch to heavy mud- Raise alarm- Keep pumping as long as well continues to flow

Surface BOP

While Tripping

- Stop tripping and set slipsOpen diverter line / close diverter- Make up kelly or reconnect the TDS- Start pumping at maximum speed- Switch to heavy mud- Raise alarm- Keep pumping as long as well continues to flow

IF

Well startsto flow

SEDCO FOREX WELL CONTROLPROCEDURES

IF

While Drilling

Well startsto flow

- Do not stop pumping- Open diverter line / close diverter- Increase pump speed- Disconnect pin connector or open dump valve / increase slip joint packer pressure as applicable- Switch to heavy mud- Raise alarm- Keep pumping as long as well continues to flow

Subsea BOP

While Tripping

- Stop tripping and set slips- Open diverter line / close diverter- Make up kelly or stab in TDS- Start pumping at maximum speed- Switch to heavy mud- Raise alarm- Keep pumping as long as well continues to flow

IF

Well startsto flow

WELL CONTROL PROCEDURESWhile posted Instructions are to divert

SF FORM NO. 541 SURFACE/S.I. UNITS (REVISED MAR,1990)

RIG

SEDCO FOREX WELL CONTROL KICK SHEET

PREPARED BY

WELL NO.

(FOR SURFACE STACKS)DATE

A PRE-RECORDED DATA: TIME OF KICK D CALCULATE: KILL MUD WEIGHT:

1 SIDPP ÷ Depth (TVD) x 0.102 = ( ) ÷ ( ) x 0.102 =MEASURED DEPTH mTRUE VERTICAL DEPTH m 2 ORIGINAL MUD WEIGHT =

LAST CASING SHOE DEPTH mLAST CASING SHOE TRUE VERTICAL DEPTH m 3 KILL MUD WEIGHT (1 + 2) =

MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE kPa

PUMP OUTPUT / SLOW PUMP RATES: E CALCULATE: FINAL CIRCULATING PRESSURE:

PUMP 1 SPM kPa l/STKSLOW PUMP PRESSURE X

KILL MUD WEIGHT= FINAL CIRC. PRESS.SPM kPa ORIGINAL MUD WEIGHT

SPM kPaPUMP 2 SPM kPa l/STK

SPM kPa ( ) X ( )=(SPM kPa (

B KICK DATA: F CALCULATE: CAPACITIES AND VOLUMES

SHUT IN DRILLPIPE PRESSURE kPa 1 DRILL STRING CAPACITY

SHUT IN CASING PRESSURE kPaPIT VOLUME INCREASE m3 2 ANNULAR VOLUME OF OPEN HOLE

C CALCULATE: INITIAL CIRCULATING PRESSURE: 3 ANNULAR VOLUME OF CASING

1. SLOW PUMP RATE AT SPM = kPa 4 ACTIVE SURFACE VOLUME

2. SHUT IN DRILL PIPE PRESSURE = kPa3. INITIAL CIRCULATING PRESSURE (1 + 2) = kPa 5 TOTAL ACTIVE SYSTEM VOLUME

(1 + 2 + 3 + 4) NOTE: m3 X 1000 = 1G CALCULATE: PUMPING TIME AND STROKES

1 SURFACE TO BIT TRAVEL TIME = DRILL STRING CAPACITY = l = STKS ÷ SPM =PUMP OUTPUT l/STK

DRILLPIPE GRAPH - SURFACE TO BIT TRAVEL TIME: A. PLOT INITIAL CIRCULATING PRESSURE AT LEFT OF GRAPH.B. PLOT FINAL CIRCULATING PRESSURE AT RIGHT OF GRAPH.C. CONNECT POINTS WITH A STRAIGHT LINE.D. ACROSS THE SPACES ON BOTTOM WRITE. (A) TIME, SURFACE TO BIT. (B) SURFACE TO BIT STROKES AND (C) PRESSURES.

))

Kg/l

Kg/l

Kg/l

0 0 010 10 10

ACTUAL STARTING TIME HRS.

A. TIME 0

B. STKS 0

C. PRESS

2 BIT TO SHOE TRAVEL TIME = ANNULAR VOLUME OPEN HOL= l = STKS ÷ SPM = MINUTESPUMP OUTPUT l/STK

3 SHOE TO BOP TRAVEL TIME = ANNULAR VOLUME OF CASING= l = STKS ÷ SPM = MINUTESPUMP OUTPUT l/STK

4 TO CIRCULATE "BOTTOMS UP" (LINE 2 + LINE 3) STKS MINUTES

5 TO KILL WELL (LINE 1 + LINE 4) TOTAL STKS TOT. MINU

INIT

IAL

CIR

. PR

ESSU

RE

FIN

AL

CIR

C. P

RES

SUR

E

SEDCO FOREX PRERECORDED WELL DATA SHEET – SURFACE STACKS

1. PUMP:Liner Stk : . inches.Liner Size: . inches.Vol/Stks: . bbl/stks

2. BIT:O.D: .inches.

3. CASING:Grade: .O.D.: .inchesWeight: .lb/ft.Length: .feet.

4. CASING SHOE TEST:Pres.at surface: .psiShoe TVD.: .feet.Test Mud: .ppg.

5. TRUE VERTICAL DEPTH: .feet.

6. MEASURED DEPTH: .feet.

7. DRILL PIPE:1) Grade: .O.D.: .inches.Capacity.: . bbl/ft.Annular .Vol. in Open hole: .bbl/ft.Annular Vol. in Casing: .bbl/ft.Total Length: .feet

2) Grade: .O.D.: . inches.Capacity.: . bbl/ftAnnular Vol. in Open hole: .bbl/ft.Annular .Vol. in Casing: .bbl/ft.Total Length: .feet

8. DRILL COLLARS:O.D.: .inches.I.D. : .inches.Capacity.: . bbl/ft Annular Vol. in Open hole:

.bbl/ft.Length : .feet.

9. Mud Properties: Weight: .ppg.

10. PIT GAIN: .bbls

11. DRILL PIPE CAPACITY:1) __ __ ft x _ __ bbl/ft = _ _ __bbls.2) __ __ ft x __ __ bbl/ft = _ _ __bbls.

12. DRILL COLLAR CAPACITY:3) __ __ ft x __ __ bbl/ft = _ _ __bbls

13. DRILL STRING CAPACITY (11+12) = __bbls

14. DRILL COLLAR ANNULUS:4) __ __ ft x __ __ bbl/ft = _ _ __bbls

15. DRILL PIPE ANNULUS IN OPEN HOLE:1) __ __ ft x _ __ bbl/ft = _ _ __bbls.2) __ __ ft x __ __ bbl/ft = _ _ __bbls.

16. ANN. VOL. IN OPEN HOLE (14+15) = _ __bbls

17. DRILL PIPE ANNULUS IN CASING:1) __ __ ft x _ __ bbl/ft = _ _ __bbls.2) __ __ ft x __ __ bbl/ft = _ _ __bbls.

18. TOT. VOL. IN ANNULUS (16+17) = _ _bbls:

19. TOTAL DRILL STRING CAPACITY ANDANNULUS VOLUME:

(13+19) = _ _ bbls:

20. ACTIVE SURFACE VOLUME = _ _bbls:

Mud

S I D P P

S I C

PIT

SF FORM NO. 541 SURFACE/US UNITS (REVISED MAR,1990)

RIG

PREPARED BY

WELL NO. (FOR SURFACE STACKS) DATE

A PRE-RECORDED DATA: TIME OF KICK D CALCULATE: KILL MUD WEIGHT:1 SIDPP ÷ Depth (TVD) ÷ 0.052 =( ) ÷ ( ) ÷ .052 =

MEASURED DEPTH FTTRUE VERTICAL DEPTH FT 2 ORIGINAL MUD WEIGHT =

LAST CASING SHOE DEPTH FTLAST CASING SHOE TRUE VERTICAL DEPTH FT 3 KILL MUD WEIGHT (1 + 2) =

MAXIMUM ALLOWABLE ANNULAR SURFACE PRESSURE PSI

PUMP OUTPUT / SLOW PUMP RATES: E CALCULATE: FINAL CIRCULATING PRESSURE:PUMP 1 SPM PSI BBL/STK

SLOW PUMP PRESSURE X KILL MUD WEIGHT = FINAL CIRC. PRESS.SPM PSI ORIGINAL MUD WEIGHT

SPM PSIPUMP 2 SPM PSI BBL/STK

SPM PSI( ) X (

SPM PSI( )

B KICK DATA: F CALCULATE: CAPACITIES AND VOLUMES

SHUT IN DRILLPIPE PRESSURE PSI 1 DRILL STRING CAPACITYSHUT IN CASING PRESSURE PSIPIT VOLUME INCREASE BBLS 2 ANNULAR VOLUME OF OPEN HOLE

C CALCULATE: INITIAL CIRCULATING PRESSURE: 3 ANNULAR VOLUME OF CASING

1. SLOW PUMP RATE AT SPM = PSI 4 ACTIVE SURFACE VOLUME2. SHUT IN DRILL PIPE PRESSURE = PSI3. INITIAL CIRCULATING PRESSURE (1 + 2) = PSI 5 TOTAL ACTIVE SYSTEM VOLUME

(1 + 2 + 3 + 4)G CALCULATE: PUMPING TIME AND STROKES

1 SURFACE TO BIT TRAVEL TIME = DRILL STRING CAPACITY = bbl = STKS ÷ SPM =PUMP OUTPUT bbl/stk

DRILLPIPE GRAPH - SURFACE TO BIT TRAVEL TIME: A. PLOT INITIAL CIRCULATING PRESSURE AT LEFT OF GRAPH.B. PLOT FINAL CIRCULATING PRESSURE AT RIGHT OF GRAPH.C. CONNECT POINTS WITH A STRAIGHT LINE.D. ACROSS THE SPACES ON BOTTOM WRITE. (A) TIME, SURFACE TO BIT. (B) SURFACE TO BIT STROKES AND (C) PRESSURES.

SEDCO FOREX WELL CONTROL KICK SHEET

)= )

ppg

ppg

ppg

minutes

bbl

bbl

bbl

bbl

bbl

INIT

IAL

CIR

C. P

RES

SUR

E

Fina

l Cir

c. P

res

sure

ACTUAL STARTING TIME HRS.

A. TIME 0 1

B. STKS 0 1

C. PRESS 1

2 BIT TO SHOE TRAVEL TIME = ANNULAR VOLUME OPEN HOLE = bbl = STKS ÷ SPM =PUMP OUTPUT bbl/STK

3 SHOE TO BOP TRAVEL TIME = ANNULAR VOLUME OF CASING = bbl = STKS ÷ SPM =PUMP OUTPUT bbl/STK

4 TO CIRCULATE "BOTTOMS UP" (LINE 2 + LINE 3) STKS

5 TO KILL WELL (LINE 1 + LINE 4) TOTAL STKS

minutes

minutes

minutes

minutes

Sedco Forex Horizontal Kick Sheet(Horizontal Extension)

Complete the standard Sedco Forex kick sheet up to Section G.1 You should then fill out this sheet to allow you to calculate your pressure graph. Youneed to transfer the following information to this sheet

Measured Depth = _________________ ftTrue Vertical Depth = _________________ ftSlow Circ. Rate Pressure= _________________ psiSIDPP = _________________ psiFinal Circ. Pressure = _________________ psiStrokes to Bit = _________________ stks

You can then find the Pressure increase:Pressure Increase = F.C.P. - S.C.R.P. = _______________ psi

You should then break the well up into ten sections of measured depth, ensure the well profile is adequately described, and place the values in Row Aof the table below. You should then proceed through the calculation line by line until the table is full. Once the table is full the values can be used todraw your pressure against strokes graph as normal. The rest of the kick sheet is then filled out as usual.

1 2 3 4 5 6 7 8 9 10A MD 0B MD Ratio Row A ÷ Measured Depth 0C Strokes Strokes to Bit X Row BD Dynamic Pressure SCRP + (Pressure Inc x Row B)

E TVD at MD in Row A 0F TVD Ratio Row E ÷ True Vertical Depth 0G Static Pressure SIDPP - (SIDPP x Row F)

H Circulating Pressure Row D + Row G

SEDCO FOREX WELL CONTROL RECORD

RIG DATE

COUNTRY /AREA T.V.D. WELL KICKED WHILE:OPERATOR MD � DRILLINGWELL LAST CSG SIZE � FISHINGWATER DEPTH LAST CSG DEPTH � TRIPPINGRISER SIZE FT. CSG GRADE WT/FT � LOGGINGB.O.P. SIZE/RATING LEAK OFF TEST (PPG) � CASINGMUD WT. GAIN BBLS � CORINGMUD TYPE HEAVE � OTHERYIELD PT. PLASTIC VIS

A. DESCRIBE OPERATIONS AND ACTION TAKEN UNTIL WELL SHUT IN

B. WELL SHUT IN WITH P.S.I. ON D.P AND P.S.I. ON CSG@ HRS

TIME ALLOWED FOR PRESSURES TO STABILIZE

SEDCO FOREX FORM NO. 384


C. DESCRIBE KILL OPERATION

PRESSURE, BBLS, TIMES, ETC.

TIME STROKES DPP CP PIT.VOLCHANGE

BBLS

REMARKS


D. GENERAL

1. ANY EQUIPMENT FAILURES (MALFUNCTIONS)

2. ATTACH ADDITIONAL PAGES IF REQUIRED3. ATTACH SEDCO KICK SHEET AS USED TO KILL WELL.4. NOTE ANY DEVIATION FROM SEDCO FOREX WELL CONTROL POLICY.

5. GENERAL COMMENTS & RECOMMENDATIONS.

E. FOLLOWING PERSONNEL WERE INVOLVED IN THIS OPERATION & THEIRRESPONSIBLITY WAS:

NAME RESPONSIBILITY

OIL CO. REP RIG SUPT. ASSIST. RIG SUPT. DRILLER DRILLER SUBSEA ENGINEER BARGE ENGINEER A/DRILLER A/DRILLER

WHITE COPY : DISTRICT MANAGERBLUE COPY : REGION MANAGERPINK COPY : REGION TRAINING CENTREYELLOW COPY : RIG FILE

Sedco Forex Accumulator Function Test Worksheet

Rig Name: ________________ Date: _________________ By: ___________________

Pod: Blue Station: ______________ Pod: Yellow Station: ____________

Close Open Close Open

Function _Time, sec. Vol., gal _Time, sec. Vol., gal _Time, sec. Vol., gal _Time, sec. Vol., gal

U. Annular _______L. Annular _______(BSR) _______Lower Pipe Ram _______Middle Pipe Ram _______Lower Pipe Ram _______U.O Kill _______U.I. Kill _______L.O. Kill _______L.I. Kill _______U.O. Choke _______U.I. Choke _______L.O. Choke _______L.I. Choke _______W.H. Conn. _______LMRP Conn. _________________ _______

Does the accumulator system function the ram and annular BOP’s within the proper limits?Each ram BOP in less than 45 sec ________ Yes ________ NoEach annular BOP in less than 60 sec _____ Yes ________ No

If yes, the system is functioning properly. If no, the system is in need of maintenance and/or repair.Note: Closing and operating time should be measured from the moment the function is activated to the moment the read back pressure gauge returns to its full operating pressure

Sedco Forex Subsea Accumulator Closing Test WorksheetRig Name: ________________ Date: _________________ By: ___________________

PUMP SETTINGSFunctions

ClosingTime, sec

VolumeRequired, gal

RemainingPressure, psi

OpeningTime, sec

VolumeRequired, gal


ClosingTime, sec

VolumeRequired, gal


Lower Pipe RamMiddle Pipe RamUpper Pipe Ram DO NOT USE

Blind/Shear Rams* DO NOT USELower Annular

** DO NOT USEPUMP SETTINGS

FunctionsOpeningTime, sec

VolumeRequired, gal


ClosingTime, sec

VolumeRequired, gal


U.I. Choke Valve

U.O. Choke Valve

L.I. Choke ValveL.O. Choke Valve

U.I. Kill ValveU.O. Kill ValveL.I. Kill ValveL.O. Kill Valve

* If pipe is in the hole substitute functioning the upper pipe rams a second time instead of the blind rams. ** Spare Line for different stack configuration.

PUMP SETTINGSElectric pumps turn on at ______ psi; turn off at ______ psi. Air pumps turn on at _____ psi; turn off at _____ psi.Charging pumps: ___________ minutes to charge system from minimum operating pressure to full accumulator working pressure (within 15minutes as per API spec. RP53, 13.4.1 and 14.3.1 respectively).Initial accumulator pressure: __________ psi. Surface accumulator pre-charge pressure: __________ psi.Subsea accumulator pre-charge pressure: ________ psi.

ACCUMULATOR PRESSURE: Is the final pressure equal to or greater than 1380 kPa (200 psi) above pre-charge pressure? ____ Yes _____ No

Sedco Forex Surface Accumulator Closing Test Worksheet

Rig Name: ________________ Date: _________________ By: ___________________

PUMP SETTINGSElectric pumps turn on at ______ psi; turn off at ______ psi. Air pumps turn on at _____ psi; turn off at _____ psi.Charging pumps: ___________ minutes to close annular on smallest size pipe used (within 2 minutes as per API spec. RP53, 12.4.1).Initial accumulator pressure: __________ psi. Surface accumulator pre-charge pressure: __________ psi.

ACCUMULATOR CLOSING TESTPUMP SETTINGS

Functions

ClosingTime,sec

VolumeRequired,

gal

RemainingPressure,

psi

OpeningTimesec

VolumeRequired

gal

RemainingPressure,

psi

ClosingTime,sec

VolumeRequired

gal

RemainingPressure,

psi

OpeningTimesec

VolumeRequired,

gal

RemainingPressure,

psiLower Pipe Ram

Middle Pipe Ram **Upper Pipe Ram

Blind/Shear Rams*Annular

HCR Valve ***

*If pipe is in the hole substitute functioning the upper pipe rams a second time instead of the blind rams. **if applicable***HCR functions are to be the opposite as rams and annular.

ACCUMULATOR PRESSUREIs the final pressure equal to or greater than 200 psi (1.38 MPa) above pre-charge pressure? ____ Yes _____ No

CLOSING TIMEClosing times should be recorded during each test to be used as an indicator of possible problems that could occur in subsequent tests. The timesfor the drill cannot be used to determine the actual closing times during normal operations due to the reduced operating pressure that the systemhas after the first and all succeeding functions have occurred.

Does the accumulator system function the rams and annular within the proper time limits? Each ram BOP in less than 30 sec _____ Yes _____ No

Each annular BOP in less than 30 sec for <18 ¾ “ and 45 sec for 18 ¾” and greater _____ Yes _____ NoIf yes, the system is functioning properly. If no, the system is in need of maintenance and/or repair. Note: Closing and operating time should be measuredfrom the moment the function is activated to the moment the accumulator gauge returns to its full operating pressure.

SEDCO FOREX BOP TEST FORMRIG: ______________________ DATE: _________________________

WELL: ____________________ TIME: __________________________

DRILLER: _________________ DEPTH: __________________

Last casing size / burst: ___________ Wellhead type: _________________RKB –MSL / water depth: _________ RKB-Wellhead: _______________________Test Fluid: ______________________ Last BOP test Date: ___________________Type Test ____ Initial: ________ Biweekly: _______ Ram Change: _______

Element BeingTested Test Period minutes Test Pressure

Low/ High Remarks

Upper Annular

Lower Annular

Blind / Shear Ram

Upper Pipe Ram

Variable Pipe Ram

Lower Pipe Ram

Upper Outer Kill

Upper Inner Kill

Lower Outer Kill

Lower Inner Kill

Outer Choke

Inner Choke

Choke Manifold

Upper Kelly Cock

Lower Kelly Cock

Safety Valve(s)

Inside BOP (s)

Kelly Hose

Standpipe Valve(s)

CONTROL SYSTEM

Master Remote 1 Remote 2 Blue Yellow

Panel used this testPanel used last testPod used this testPod functioned testedHydraulic ClosingPressure

WELL CONTROL MANUAL

Ref.: HQS-PO-OPT-01

Page: 267

Issued: 07/10/1999

Revision: 0Appendix 4 Well Control Formulae.

APPENDIX 4: WELL CONTROL FORMULAE

Formulae found in this appendix provide a theoretical estimate.Actual values may differ depending on individual situations.

WELL CONTROL MANUAL

Ref.: HQS-PO-OPT-01

Page: 268

Issued: 07/10/1999


SI Units:Hydrostatic Pressure Ph Ph = MW ÷ 102 x TVD

(kPa) (kg/m3) (m)Pressure Gradient Gm Gm = MW ÷ 102

(kPa/m) (kg/m3)Bottom Hole Pressure BHP

General case (any units): BHP = Ph(DS) + PDP - PLosses (DS) BHP = Ph(Ann) + PAnn + PLosses (Ann) Application : Shut In Well:

BHP = Ph(DS) + SIDPP BHP = Ph(Ann) + SICP Application : Circulating:

BHP = Ph(DS) + PDP - PLosses (DS)BHP = Ph(Ann) + APL

PDP = Plosses (DS) + APIEquivalent Circulating Density ECD ECD = MW + [APL x 102 ÷ TVD]

(kg/m3) (kg/m3) (kPa) (m) Application : Killing Well (at SCR): BHP = Ph(DS) + PDP - SCRP BHP = Ph(Ann) + PAnn (Surface) BHP = Ph(Ann) + PAnn + CLFL (Subsea)

(assuming APL negligible)

Equivalent Mud Weight (at leak off) EMW = MWLOT + [LOT x 102 TVDShoe](kg/m3) (kg/m3) (kPa) (m)

Maximum Allowable Annular Surface Pressure MAASP = (EMW - MW) ÷ 102 x TVDShoe(kPa) (kg/m3) (kg/m3) (m)

MAASP = LOT - [(MW – MWLOT) ÷ 102 x TVDShoe](kPa) (kPa) (kg/m3) (kg/m3) (m)

Kill Mud Weight KMW = [SIDPP x 102 ÷ TVD] + OMW(kg/m3) (kPa) (m) (kg/m3)

Initial Circulating Pressure (any units) ICP = SIDPP + SCRPFinal Circulating Pressure (any units) FCP = SCRP x KMW ÷ OMWEstimated Influx Density dinf dinf = MW - [(SICP - SIDPP) x 102 ÷ hi ]with hi = Pit Gain (m3) ÷ Annular Vol. (m3/m) (kg/m3) (kg/m3) ((kPa) (kPa) (m)Kick Tolerance (hi : assumed influx height KT = [MAASP - (MW ÷ 102 x hi)] x 102 ÷ TVD calculated from assumed kick volume) (kg/m3) ((kPa) (kg/m3) (m) (m)Weight of Barite Required to Increase Mud weight WBar = VOL Act x 42 x (KMW - OMW) (mud weights in kg/m3) (kN) (m3) (4200 - KMW)Boyle's Law : P x V = Constant P2 = P1 x V1 ÷ V2 Pressure1 x Volume1= Pressure2 x Volume2 V2 = V1 x P1 ÷ P2Pressure Losses (any units) PLosses2 = PLosses1 x (New SPM)2 ÷ (Old SPM)2

PLosses2 = PLosses1 x (New MW) ÷ (Old MW)

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Metric Units:

Hydrostatic Pressure Ph Ph = MW ÷ 10 x TVD(kg/cm2) (kg/l) (m)

Pressure Gradient Gm Gm = MW ÷ 10(kg/cm2/m) (kg/l)

Bottom Hole Pressure BHPGeneral case (any units):

BHP = Ph(DS) + PDP - PLosses (DS) BHP = Ph(Ann) + PAnn + PLosses (Ann)Application : Shut In Well:

BHP = Ph(DS) + SIDPP BHP = Ph(Ann) + SICPApplication : Circulating:


PDP = PLosses (DS) + APIEquivalent Circulating Density ECD ECD = MW + [APL x 10 ÷ TVD]

(kg/l) (kg/l) (kg/ cm2) (m) Application : Killing Well (at SCR): BHP = Ph(DS) + PDP - SCRP BHP = Ph(Ann) + PAnn (Surface) BHP = Ph(Ann) + PAnn + CLFL (Subsea)


Equivalent Mud Weight EMW = MWLOT + [LOT x 10 TVDShoe](kg/l) (kg/l) (kg/ cm2) (m)

Maximum Allowable Annular Surface Pressure MAASP = (EMW - MW) ÷ 10 x TVDShoe(kg/ cm2) (kg/l) (kg/l) (m)

MAASP = LOT - [(MW - MWLOT) ÷ 10 x TVDShoe](kg/ cm2) (kg/ cm2) (kg/l) (kg/l) (m)

Kill Mud Weight KMW = [SIDPP x 10 ÷ TVD] + OMW(kg/l) (kg/cm2) (m) (kg/l)

Initial Circulating Pressure (any units) ICP = SIDPP + SCRPFinal Circulating Pressure (any units) FCP = SCRP x KMW ÷ OMWEstimated Influx Density dinf dinf = MW - [(SICP - SIDPP) x 10 ÷ hi ]with hi = Pit Gain (litres) ÷ Annular Vol. (L/m) (kg/l) (kg/l) (kg/cm2) (kg/cm2) (m)Kick Tolerance (hi : assumed influx height KT = [MAASP - (MW ÷ 10 x hi)] x 10 ÷ TVD calculated from assumed kick volume) (kg/l) (kg/cm2) (kg/l) (m) (m)Weight of Barite Required to Increase Mud weight WBar = VOL Act x 4.2 x (KMW - OMW) (mud weights in kg/l) (m tonnes) (m3) (4.2 - KMW)Boyle's Law : P x V = Constant P2 = P1 x V1 ÷ V2 Pressure1 x Volume1= Pressure2 x Volume2 V2 = V1 x P1 ÷ P2Pressure Losses (any units) PLosses2 = PLosses1 x (New SPM)2 ÷ (Old SPM)2


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Imperial Units:

Hydrostatic Pressure Ph Ph = MW x 0.052 x TVD(psi) (ppg) (ft)

Pressure Gradient Gm Gm = MW x 0.052(psi/ft) (ppg)

Bottom Hole Pressure BHPGeneral case (any units):

BHP = Ph(DS) + PDP - PLosses (DS) BHP = Ph(Ann) + PAnn + PLosses (Ann)Application : Shut In Well:

BHP = Ph(DS) + SIDPP BHP = Ph(Ann) + SICPApplication : Circulating:


PDP = PLosses (DS) + APIEquivalent Circulating Density ECD ECD = MW + [APL ÷ 0.052 ÷ TVD]

(ppg) (ppg) (psi) (ft) Application : Killing Well (at SCR): BHP = Ph(DS) + PDP - SCRP BHP = Ph(Ann) + PAnn (Surface) BHP = Ph(Ann) + PAnn + CLFL (Subsea)


Equivalent Mud Weight EMW = MWLOT + [LOT ÷ 0.052 ÷ TVDShoe](ppg) (ppg) (psi) (ft)

Maximum Allowable Annular Surface Pressure MAASP = (EMW - MW) x 0.052 x TVDShoe(psi) (ppg) (ppg) (ft)

MAASP =LOT-[(MW- MWLOT) x 0.052 x TVDShoe](psi) (psi) (ppg ) (ppg) (ft)

Kill Mud Weight KMW = [SIDPP ÷ 0.052 ÷ TVD] + OMW(ppg) (psi) (ft) (ppg)

Initial Circulating Pressure (any units) ICP = SIDPP + SCRPFinal Circulating Pressure (any units) FCP = SCRP x KMW ÷ OMWEstimated Influx Density dinf dinf = MW - [(SICP - SIDPP) ÷ 0.052 ÷ hi ]with hi = Pit Gain (bbl) ÷ Annular Vol. (bbl/ft) (ppg) (ppg) (psi) (psi) (ft)Kick Tolerance (hi : assumed influx height KT = [MAASP- (MW x 0.052 x hi)] ÷ 0.052 ÷ TVD calculated from assumed kick volume) (ppg) (psi) (ppg) (ft) (ft)Weight of Barite Required to Increase Mud weight WBar = VOL Act x 42 x 35.5 x (KMW - OMW) (mud weights in PPG) (lbs) (bbl) (35.5 - KMW)Boyle's Law : P x V = Constant P2 = P1 x V1 ÷ V2 Pressure1 x Volume1= Pressure2 x Volume2 V2 = V1 x P1 ÷ P2Pressure Losses (any units) PLosses2 = PLosses1 x (New SPM)2 ÷ (Old SPM)2


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Revision: 0Appendix 5 Formation Tests.

APPENDIX 5: FORMATION TESTS

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5.1 Leak-off Test Procedures

The following procedure should be used when performing a leak-off test.

1) Drill out float shoe, rathole and an additional 3 meters (10feet) of new hole.

2) Circulate and condition hole until the mud weight is uniformthroughout.

3) Position bit just above casing shoe.

4) Rig up high pressure, low volume pump such as a cementpump. Rig pumps are not suitable for performing leak-off testsand are not recommended.

5) Close BOP (hang-off string on floating units.) Wherepracticable, open annulus between last casing and previouscasing strings to avoid pressure build-up.

6) Pump down the drill pipe or annulus (each rig to establish apolicy on which way to pump) in increments of.016 to .040 m3

(0.1 to 0.25 bbls).

7) After each increment pumped, stop and record the finalpumping pressure. Wait for approximately 2 minutes or longer,if required, for pressures to stabilize and record final staticpressure. Plot final pump pressure and final static pressureversus cumulative pumped volume on the same graph.

8) Repeat 6 and 7 until the trend of the final pumping pressurecurve deviates from that of the final static pressure curve.

Alternatively, steps 6, 7 and 8 above can be replaced bycontinuous pumping at a selected slow rate with monitoringof the pressure and strokes.

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9) Monitor final static pressure an additional 5-10 minutes.

10) Bleed off pressure by opening the return line back to tank andrecord flow back.

The object of the above test is not to fracture the formation, butrather to identify the "formation intake pressure". This "intakepressure" is identified as that point where a deviation occursbetween the trends of the final pump pressure curve and thestatic pressure curve. Once the formation intake pressure hasbeen reached, further pumping should be avoided.

If pumping is continued a fracture could occur, characterized bya sharp drop in pressure. Once formation breakdown has beeninitiated any further pumping will cause loss of fluid at a lowerpressure referred to as the fracture propagation pressure.

5.1.1 Consolidated Formations

In consolidated formations, the point where the recorded pressureincrements deviate from an established straight line indicates theformation "intake pressure."

Formation IntakePressure

Cumulative Volume

Pressure

Formation IntakePressure

Cumulative Volume

Pressure

Fig. 1 Consolidated permeable formations Fig. 2 Consolidated formations with low permeability or impermeable

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Limit test

In consolidated hard rock areas a formation limit test (also knownas formation or shoe integrity test) should be run instead of a leak-off test. If the leak-off test is carried out a fracture may bepropagated causing a reduction in welIbore integrity. For suchareas, the formation of interest should be tested to the desired testpressure for the well program. Pumping should be stopped whenthe predicted fracture pressure is reached.

Desired TestPressureT t

Cumula tive Volume

Pressure

Fig. 3 Consolidated formation “Limit Test”

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5.1.2 Unconsolidated Formations

In unconsolidated formation, the final pumping pressure willalways be higher than the final static pressure. Intake pressure canonly be approximated. Generally the information is adequatesince the main purpose of the test is to verify the cement jobaround the shoe.

Estima tedformationintakepressure

Cumula tive Volume

Pressure

Fig. 4 Unconsolidated plastic formation

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Revision: 0Appendix 6 Shallow Gas.

APPENDIX 6: EVALUATION OF SHALLOW GASSEISMIC SURVEY

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Revision: 0Appendix 6 Shallow Gas.

The following is a quick summary reminder of things to check

OPTIMIZE PRELIMINARY SHALLOW GAS INVESTIGATION

- Seismic surveys.- Soil sampling.- Pilot holes (pre-spud).

AVOID SHALLOW GAS WHERE POSSIBLE

- Reposition drilling location.- Re-arrange casing schemes and use BOPs.- Apply strict shallow gas procedures.

REDUCE RISK TO RIG IN CASE OF SHALLOW GAS

- Divert subsea.- Employ riserless drilling.- Drill small diameter pilot hole.

Some of the seismic survey high resolution techniques availableare not reliable or suitable for shallow gas evaluation. Thefollowing flow chart will help you evaluate whether the surveyhas been conducted satisfactorily.

SEDCO FOREX DECISION TREE FOR SHALLOW GAS SEISMIC SURVEY

DO YOU MIND IF I HAVE A CONFIDENTIALCOPY OF THE SURVEY FOR INDEPENDENTCOMMENTS WITH RESPECT TO SHALLOW GAS?

600 METRES, OK 300 M, NOTGOO

WHAT LENGTH OFSTREAMER WAS USED?

IN THE ABSENSE OF THIS SURVEYDATA THE OPERATOR MUST BEREQUESTED TO CONDUCT THE SURVEY PRIOR TO SPUDDING. THE DISTRICT MANGER SHOULDREFER TO THE REGION VP IF THESURVEY WILL NOT BE DONE

NO

WHAT SOURCE WAS USED?

YES

HAVE YOU DONE A MULTI-CHANNEL, HIGHRESOLUTION DIGITAL SEISMIC SURVEY?

QUALITY DOUBTFUL

AIR GUNS ORWATER GUNS

SPARKER SURVEYOLD TECHNOLOGYPOOR RESULTS

OKAY

HOW MANY CHANNELSWERE RECORDED AND ATWHAT SAMPLING RATE

24 CHANNELSOR LESS

48 CHANNELS; .5TO 1 MILLISECONDRATE

NOT GOODOKAY

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Revision: 0Appendix 7 Mud Gas Separator (Sedco Forex Standards)

APPENDIX 7: MUD GAS SEPARATOR

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7.1 Operations

The mud gas separator can only operate effectively and safely if a sufficient mudseal is maintained on the discharge line. The sketches below illustrate this point:

Typic a l Offshore Set-up Typ ic a l Land Rig Set-up

Circ ula ting through sepa rator; no gas; no p ressureFigure 1 Figure 2

Figure 3 Figure 4

MudSea l

GasPress.

GasPress.

MudSeal

Circula ting gas through separa tor within design c apac ity

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Figure 5 Figure 6

Figure 7 Figure 8

Typ ic a l Offshore Set-up Typ ic a l Land Rig Set-up

Circ ula ting through separa tor above c apac ity; unload ing gas

MudSea l

GasPress.

GasPress.

MudSea l

Possib le improvement of mud sea l height

MudSea l

GasPress.

GasPress.

MudSea l

To operate safely, the rig crew should have some means of controlling the loadput on the separator and some instructions concerning the conduct to follow ifthe maximum operating criteria are reached or exceeded.

The most common method of measuring the load on the separator consists ininstalling a very low pressure gauge (0-150 kPa or 0-20 psig) or pressure

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transmitter on the separator vessel; the maximum operating criterion in this casecorresponds to the hydrostatic head provided by the mud seal (generallyassuming the mud has been replaced by lighter formation water or oil).

Possible courses of action in case of overloading of the mud/gas separatorinclude switching to a slower kill rate, switching C/K manifold outlet to HPoverboard line or production facilities or using volumetric method to evacuate thegas from the annulus.

7.2 System Design

It is essential to verify that the system is capable of handling themaximum amount of fluid and gas that could be produced by the well in case ofsevere kick. That value should be obtained from the operator and should becompared to the system capacity that can be obtained from Sedco Forex.

Note: NO MODIFICATION SHALL BE DONE TO EXISTING SYSTEMSWITHOUT PRIOR REVIEW AND APPROVAL BY THE REGION OFFICE.

There are two essential aspects to the capacity of a mud/gas separator:

- Separation capacity : this is essentially determined by the physical dimensionsof the separator vessel and vent line which determine the gas vertical velocity.

- Gas flow capacity: this is essentially determined by the length and size of thevent line and by the depth of the mud seal as they respectively affect the pressurecreated in the separator by the gas flow and the amount of back pressureavailable to compensate and avoid gas blowdown. (see Figures 1 to 8 above).

The vent line shall lead a safe distance (at least 60 m, 200 ft) downwind ofprevailing winds. On offshore units, venting to the top of the crown block isacceptable. The size of the vent line must be sufficient to safely handle themaximum expected gas flow rate; 8" is generally considered today as a minimumfor venting to crown block on offshore units. An 8” line should be taken asminimum size whenever replacing or upgrading the vent line.

The discharge line shall not be connected directly to the degasser or to anenclosed mud pit room: it should always have an open pipe or additional vent line(see figures 9 and 10 below).

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DON’T DO

Have a sea led Leave return tanksepara tor return tank (or line) open orand c losed p ipe add separa teto p it room vent line

From degasser

Figure 9 Figure 10

According to the UKCS, HSE-Offshore Safety Division Safety Notice 11/90The size of the liquid outlet line should be based on a minimum gravitational ratefrom the separator of 6 barrels per minute of 12 ppg mud of average viscosity.

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The sketches below illustrate the main dimensions of a mud gas separator system.

Figure 11 Figure 12

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Figure 13 Figure 14

In case of doubt concerning the capacity of the mud/gas separation system on arig, the district manager should contact the regional office with the followinginformation:

- Maximum expected or required gas flow rate.

- Separator vessel drawing showing diameter, length and internal arrangement

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- Drawing or sketch of vent line showing line dimension, length, position andnumber of elbows and other restrictions.

- Drawing or sketch showing the arrangements, length and size of the separatordischarge line and mud seal.

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Revision: 0Subject Index

SUBJECT INDEX

A

Accumulators ........................... 76, 78, 79, 191, 239Subsea ........................................................ 62, 77

Capacity and Response Time .................. 62, 78Surface ....................................................... 62, 75

Capacity and Response Time .................. 62, 76Tests ........................................................... 63, 92

B

Barge Supervisor.................................................. 60Barite...........103, 133, 134, 135, 234, 268, 269, 270

Plug ........................................................ 103, 133BOPs ........................................................ 62, 64, 69

Deepwater ...................................................... 191Drills................................................................. 94Inside.................................................. 63, 86, 266Rams..................................................... 62, 65, 69Requirements.............................................. 62, 64Subsea ...................14, 34, 35, 62, 63, 69, 90, 167Surface ....14, 33, 34, 38, 62, 63, 64, 90, 102, 119

Bullheading .................102, 108, 109, 110, 116, 234

C

Cementer .............................................................. 60Chloride................................................................ 19Chokeline ........................................................... 186

Circulation Schedule ...................................... 179Friction ........................................... 175, 183, 232

Collision Avoidance................................... 103, 156Company Representative................................ 14, 59Converson Tables............................................... 241

D

Diverter ........................................ 14, 36, 38, 39, 99Drillers Method ............................................ 44, 203

Deep Water .................................................... 180Slim Hole ............................................... 196, 207

E

Emergency Disconnect....................... 103, 131, 132Dynamically Positioned ................................. 188Moored FloatingUnits .................................... 131

Equipment Problems .................................. 103, 138

F

Float Valve .....................................................63, 87Forms..................................................................244Function Testing.............................................63, 90

G

Gas in the Riser ..................................................165Equipment for Handling .................................166Procedures for Handling .........................167, 168

H

Horizontal ........... 220, 221, 224, 225, 227, 244, 259Kill Procedures .......................................220, 221Kill Sheet ................................................220, 222

HP/HT ................................................................211Hydrates.............................. 102, 122, 123, 124, 125

Deep Water.....................................................159External...................................................125, 162Formation ...............................................102, 122Removal..........................................................163

I

Inside BOP .............................................63, 86, 266Intermediate Circ. Pressure................. 204, 205, 232

K

Kelly ................... 63, 86, 87, 92, 103, 141, 236, 266Lower Kelly Cock ..............................63, 87, 266Upper Kelly Cock.....................................87, 266

Kick .................. 14, 15, 51, 117, 196, 197, 226, 240Assembly ........................................................236Detection................. 102, 117, 178, 212, 215, 240Prevention....................... 177, 196, 198, 212, 214Tolerance ............................ 14, 51, 268, 269, 270

Kill Mud ..................... 206, 207, 232, 268, 269, 270Kill Mud Weight

density..................................... 232, 268, 269, 270Kill Procedures ................... 180, 212, 215, 220, 229Kill Sheet .................................... 220, 222, 225, 244

L

Lost Circulation ....................................16, 197, 232Lower Marine Riser Package..........................62, 69

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Lubricator................................................... 102, 127

M

MAASP.......................................................... 14, 49Mud Engineer................................................. 14, 59Mud Gas Separator......................... 63, 88, 233, 237Multilateral Wells....................................... 230, 240

O

Oil Base Mud ............................................. 102, 117Overbalance........................................................ 237

P

Permeability ....................................................... 237Pressure Testing ............................................. 63, 89Pumps............................................... 62, 77, 80, 179

Bringing up to speed .............................. 103, 143

R

Roughnecks .................................................... 14, 59Roustabouts .......................................................... 60

S

Safety Valve ......................... 23, 62, 63, 86, 87, 266Shale Density ....................................................... 19Shallow Gas ....................................... 14, 20, 21, 27Shallow Water Flow........................... 171, 172, 233Slim Hole ........................................... 195, 196, 197

Kick Tolerance ....................................... 196, 203Well Control Methods............................ 196, 203

Slow circulating rate .......14, 49, 175, 196, 199, 233Snubbing ............................................................ 105Standpipe.................................... 62, 63, 85, 91, 266

Manifold..................................................... 62, 80Stripping..........10, 14, 53, 55, 56, 97, 125, 244, 251Subsea Engineer ............................................. 58, 60

T

Top Hole ........................................................ 14, 27Trapped Gas ............................................... 103, 137Trapped Pressure........................................ 103, 148Trip

Sheet............................................... 245, 246, 248Tank ............................................... 22, 23, 24, 25

U

Underbalance Drilling ................................ 103, 152Underground Blowout........................ 109, 180, 181

V

Volumetric Kill...................................................187Dynamic .........................................................186Static ...........................................................14, 46

W

Wait and Weight.............................................14, 40Slim Hole................................................196, 203

Well Control Drills ...............................................94Wellhead.........................................................62, 69Wireline ........................ 29, 102, 127, 128, 130, 131Workover....................................................102, 107