BP Well Testing Procedure Manual

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

0020 USER GUIDE 0 01/10/92

USER GUIDE This manual provides policy and procedures for well testing, stimulation and ancillary operations on XEU mobile rigs. It is intended as a means of assisting the BP Petroleum Engineer and BP Drill Rep in conducting operations more safely and effectively. It contains the recommended procedures to be followed for different operations. Deviation from these procedures should only occur after prior discussion and agreement with the Senior Petroleum Engineer and/or the Drilling Superintendent for the rig in advance of an operation being carried out. The manual incorporates BP XEU WEO Well Testing Policy and Guidelines. The manual is a live document and will be updated continuously to reflect changes in technology and new or updated experience. Feedback from you, the manual users, is an essential requirement if the manual is to be accurate and up to date. A few sections of the manual are still to be included and will be added as they become available. The manual has been structured with each activity split into four sections : Safety, Preparations, Operating Procedure and Guidance Notes. The Operating Procedures should form the basis of any rig site procedures/programmes. To assist with the preparation of rig site procedures, copies of all the Operating Procedures will be available electronically in Microsoft Word. Suggested changes to the manual may be made by anyone. However, since the manual aims to assist the BP Petroleum Engineer and BP Drill Rep, it is expected that they will be the primary sources of the changes. The procedure to be followed in the event of a proposed amendment is to fill out the 'updates' proforma, listing the section to be changed, why the change is needed and draft of the replacement section. This is to be sent to the Senior Petroleum Engineer Well Engineering Operations Group in Dyce, copied to your line manager. The SPE WEOG will be responsible for ensuring that the amendment is considered by the appropriate people and the manual updated accordingly. Ideally the proposed change should be discussed with the relevant specialist or Drilling Superintendent prior to submission. Once approved, the relevant section and index of the manual will be re-issued, prepunched so that all that is required is to remove the old section/index and insert the replacements. A document history will record the major changes that have taken place and why they have been made.

Section 0020 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT

1010 GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS PLANNING 0 01/10/92

REVISION DATE

PLANNING 1.

The priorities during the planning of a well test are, in order of preference: i)

The integrity of the well.

ii) Safety of personnel and the drilling unit. iii) Conformance to the regulations and legislation of the government and/or any other relevant legislative body. iv) Minimising the impact of testing operations on the environment. 2.

A detailed programme must be prepared for any testing or completion operations. This programme must be approved by the Drilling Superintendent and be endorsed by the relevant Head/Senior Petroleum Engineer prior to the commencement of operations.

3.

The test programme should include the following information: Organisation and Responsibilities Onsite Equipment Requirements Equipment layout and P&ID Test Pressures of Equipment Equipment Failure Contingency Plans Emergency Test Abandonment Plans H2S Contingency plans Safety Programme and Safety Drills

4.

The test equipment surface hook-up needs to be submitted and approved by the MODU certifying authority. In practice the approvals have been sought by the well testing contractor after due discussion with the rig owner. The certified hook-up then forms part of the well testing package, along with individual equipment certification.

5.

Any significant changes to a programme must be documented and approved by the relevant Head/Senior Petroleum Engineer and Drilling Superintendent.

6.

In areas where the presence of H2S is know or expected, appropriate operating and emergency procedures must be available prior to commencing testing operations.

7.

Regulatory consents that must be obtained before testing are CSON 6 Flaring of gas CSON 59 High pressure-high temperature well testing CSON 7 Flareboom fallout exemption

Section 1010 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

1020 GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS MATERIALS AND SERVICES 0 01/10/92

MATERIALS AND SERVICES 1.

The procurement of services, equipment and materials for testing operations must follow the principles and procedures as set out by the appropriate BPX contracts committee

2.

All materials and services must be fit for purpose and in compliance with BPX standards and specifications where appropriate.

3.

Mercury will not be used in the taking and storage of hydrocarbon samples.

4.

The surface equipment hookup must comply with that approved by the Certifying Authority.

Section 1020 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

1030 GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS WELL INTEGRITY 0 01/10/92

WELL INTEGRITY 1.

The fluid weight in the annulus with the riser removed shall exceed the hydrocarbon pore pressure at the depth of the packer.

2.

All testing or completion operations must conform with the principle of double valve isolation inside the test/completion string and in the annulus (ie packer, valves, seals or rams). In practice this means: i)

To allow disconnection on a semi sub, double valve isolation is required below the disconnect point. This can be achieved by having two valves in the same item of equipment, provided that both isolation valves will independently fail closed (as in the Subsea Test Tree).

ii) On Jack ups, to cover the case of catastrophic loss of the surface wellhead, one of the isolation valves must be below the mud line. 3

.The downhole tester valve (where run) may be counted as an isolation valve provided its position can be guarantied. Note however, that the prime function of the downhole tester valve is to improve data acquisition, not to provide extra well isolation.

4.

Wells tested using a dynamically positioned vessel must have a Subsea test tree that will: i)

Allow closure of the shear rams without disconnecting the SSTT.

ii) Shut in the well within the response time of the BOP unlatch system. 5.

A full BOP test must have been carried out within the seven days preceding running the test string/completion.

6.

Pipe rams must be available to close around every size of tubular of significant length run in the well. Procedures must be in place to ensure that a tubular of the correct size can be placed accurately and quickly across the rams should the need arise to close in the well during the running of the test string. Reference the BP Well Control Manual for all operations where primary well control has to be maintained.

Section 1030 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

1040 GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS PRESSURE TESTING 0 01/10/92

PRESSURE TESTING 1

.All tests must include a low pressure test of 300 psi before proceeding to the full pressure test.

2.

A satisfactory pressure test is represented by the test pressure being held for 10 minutes after the pressure has stabilised.

3.

Completion and test strings are to be pressure tested to at least the maximum anticipated wellhead closed in pressure (or maximum TCP perforating wellhead pressure, whichever is the greater).

4.

All tests must be recorded on a chart.

5.

Water is the preferred fluid for pressure testing or flushing. However, once reservoir hydrocarbons have been produced to surface a water/glycol mixture should be used as the test/flushing fluid to avoid hydrate problems.

6.

The possibility of a test pressure leaking past a pack-off/test plug/valve and being applied to a weaker element must always be considered. All reasonable steps must be taken to monitor for and eliminate such an event.

7.

The wireline lubricator, when used, should be pressure tested to the maximum anticipated well head pressure prior to running a tool into the wellbore.

Section 1040 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

1050 GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS EXPLOSIVES AND RADIOACTIVE SOURCES 0 01/10/92

EXPLOSIVES AND RADIOACTIVE SOURCES 1.

All perforating operations must only be conducted under conditions where the well can be contained, monitored and controlled.

2.

The BP Rep and OIM will ensure that only the Responsible Contractor handles all onsite explosives and radioactive sources i) according to government and Company safety regulations. ii) using suitably qualified and authorised personnel. iii) maintaining an accurate log of such materials and their usage.

3.

The BP Rep and OIM are responsible for the safe and adequate onsite storage of explosives and radioactive sources.

4.

Radioactive sources, detonators and explosives are not to be stored in close proximity to each other.

5.

Radio silence procedures will be applied when running the following well testing tools: i) Wireline perforating guns (except approved Radio Safe guns) ii) Tubing conveyed guns electronically detonated. iii) Tubing punchers.

6.

All personnel handling radioactive sources must wear approved film badges or dosimeters.

Section 1050 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

1060 GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS WELL TESTING OPERATIONS 1 01/11/94

WELL TESTING OPERATIONS 1.

The OIM has ultimate responsibility for the safety, health and general welfare of all persons on board and for the good practice and security of the operation. The OIM appoints a number of competent persons who are responsible for the control and safety of operations in their field of expertise. In all drilling matters, including testing operations, the BP Drilling Representative and the Rig Superintendent are the appointed competent persons.

2.

As one of the competent persons for drilling operations, the BP Drilling Representative is responsible for carrying out the Testing Programmes issued to him from, and in consultation with, the drilling superintendent onshore. To assist the BP Drilling Representative in his duties, the responsibility for specific aspects of the test programme will be delegated to the BP Petroleum Engineer or BP Drilling Engineer. However, overall responsibility is retained by the BP Drilling Representative.

3.

The BP Petroleum Engineer will supervise the service companies involved in the testing operation and will provide technical support to the BP Drilling Representative. The PE also has individual responsibility to monitor the quality of data being recovered and to advise on behaviour of the well being tested. He will independently report to the Senior Petroleum Engineer onshore to inform on the progress of the test. The BP Drilling Engineer will assist in all aspects of well preparation prior to the test and in the running of the downhole equipment ready for testing. During the test, the on duty Driller is in charge of the well and has the authority to shut down the test for safety reasons. He will report directly to the OIM/Toolpusher. The on duty Well Test Crew Chief will be the person responsible for the well test production equipment downstream of the choke and will have the authority to shut down the test for safety reasons. He will report via the BP Drilling Representative to the OIM.

4.

Operations must be conducted in accordance with appropriate Safety Regulations or Systems of Work, which have been approved by management.

5.

For all exploration wells and appraisal wells on untested prospects, the start of the flow test, ie initial flow, initial shut-in, and approximately 1 hour of the main flow period should be timed to coincide with daylight hours. The initial flow and shut in may be allowed to occupy the hours of darkness provided adverse weather is not expected and no reservoir hydrocarbons are produced to surface. Flow into or throughout the night shall only be permitted if the well has stabilised and the surface equipment has been commissioned in daylight.

Section 1060 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

1060 GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS WELL TESTING OPERATIONS 1A 06/12/94

For appraisal and development wells, the initial flow of hydrocarbons to surface may be permitted during the hours of darkness as long as the following conditions have been satisfied: x

Reservoir pressure and expected maximum surface pressure are accurately known through RFT pressure data and/or previous reservoir production.

x

The well is not classified as High Pressure / High Temperature.

x

Hydrocarbon composition is accurately known through previous reservoir production.

x

The well fluid does not contain more than 20 ppm H2S (Ref BP Drilling Manual, Section 0120/GEN/B.2.2)

x

All subsea and surface equipment test equipment has been successfully pressure tested.

x

Sufficient artificial lighting is available on the rig to allow all of the surface test spread to be easily monitored.

x

Weather conditions are good, allowing rig access by both helicopters and boats.

x

The environmental impact risk (spillage, etc) has been minimised.

x

Agreement has been reached between the Rig OIM, the Rig Manager, the BP Representative and the BP Drilling Superintendent in town to perform the initial flow during darkness. All parties must be satisfied that adequate safety and environmental precautions have been taken and that well kill and emergency procedures are in place.

6.

A pretest meeting must be held on-site with all the relevant Company and service company personnel present.

7.

Prior to pulling out of the hole with a test string there must be a facility to circulate the contents of the test string.

8.

Open hole testing operations where the packer is set in open hole will not be conducted from floating drilling units.

9.

Drill pipe will not be used as the test string, (or the completion string) in a gas well or in a well where H2S is present.

Section 1060 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

1060 GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS WELL TESTING OPERATIONS 1 01/11/94

6.10

Drill collars may be used in the minor string.

6.11

All downhole testing and completion equipment (except tubulars) must be pressure tested to the maximum anticipated operating pressure prior to running into the wellbore.

6.12

Unlatch equipment must be function tested before it is run.

Section 1060 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

1060 GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS WELL TESTING OPERATIONS 1 01/11/94

GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS 6.13

Prior to flowing the well: i)

All surface well testing or completion equipment must be pressure tested to the maximum anticipated operating pressure.

ii) A full function test of all valves and automatic systems must be conducted. 6.14

The cushion must not be flowed back to the gauge/surge tank where gas is the prognosed reservoir fluid. (Except to check if the well is dead)

6.15

A surface wireline tension monitoring device must always be installed when running wireline tools/logging equipment in the hole.

6.16

Air lines to the burners must have non return valves fitted. The air supply must be independent of the rig air supply.

6.17

The quantity and operation of all gas detection equipment held on site must be checked prior to the commencement of testing operations, and must be to an acceptable standard.

6.18

Cement retainers or permanent packers fitted with flapper valves should not be used for testing operations.

6.19

A minimum of one complete hole circulation is to be performed prior to pulling out of the hole after completing the well kill.

6.20

The Drilling Representative is to be on the rig floor when recovering the test string to observe a minimum of 10 stands pulled off bottom and until such time as he is satisfied the hole fill is correct.

6.21

The following sections have particular relevance to the testing phase of operations; 1.1, 1.2, 1.4, 1.5, 3.1, 3.2, 3.3, 3.5, 3.6, 4.1, 4.5, 4.6, 4.7, 5.5.

Section 1060 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2010 RUNNING A PERMANENT PACKER 0 01/10/92

RUNNING A PERMANENT PACKER

1.

SAFETY

1.1

Prior to rigging up the permanent packer hold a safety meeting on the rig floor to discuss the operation. The safety meeting should include, the BP REP, OIM, Toolpusher, Driller, Logging Engineer, PE, and rig crew. The following points are to be made at the safety meeting: a

All assembly/disassembly of the packer setting tool is to be carried out under the supervision of the Logging Engineer.

b

All non-essential personnel must keep clear of the setting tool assembly area and the rig floor until permanent packer is below the sea bed.

c

All welding operations must cease and all Hot Work permits be withdrawn for the duration of the packer setting operation.

d

Radio silence must be observed from when the explosive detonator is removed from the explosives store and must be maintained until the packer is 70m below the sea bed. Note. For the purpose of these procedures Radio Silence is deemed to include the following actions and checks :

i

All radio equipment on the rig (with the exception of the emergency stand-by-receiver) shall be switched off prior to removing the detonator from the explosives store and remain so until the packer is 70m below the sea bed, or the detonator is returned to the explosives store, or the detonator is consumed in the packer setting operation. All hand portable radio equipment must be recalled to the radio-room and only re-issued when the packer setting operation is complete.

ii

Check that the stand-by boat and any other vessels in the vicinity of the rig have moved outside the 500m zone and remain there for the duration of the operation. All vessels within one kilometre must silence all MF/HF transmissions. Should it be necessary for any shipping to remain within 500m of the rig they must observe radio/radar silence.

Section 2010 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2010 RUNNING A PERMANENT PACKER 0 01/10/92

iii Check on Helicopter movements. Prior arrangement should be made to ensure as far as possible that no aircraft encroach within 500m of the rig unless the aircraft in question is not using its transmitting system. Helicopters shall not be allowed to land on the rig while armed explosives are above the sea bed or at surface. iv

Switch off all cathodic protection equipment for the duration of packer setting operations.

v

Check that the logging engineer has switched off the unit's generator and that the safety key has been removed from the unit whilst the armed setting charge is at surface or above the sea bed.

vi

Check that a rig to casing monitor is being employed throughout the operation and that its reading does not exceed 0.25 volts.

vii Check that the logging unit is grounded to the rig. 1.2

The following points must be considered by the supervisor of the operation: a

Do not arm the packer setting charge during electrical storms.

b

Strap the packer assembly before it is armed.

Section 2010 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2010 RUNNING A PERMANENT PACKER 0 01/10/92

2.

PREPARATION

2.1

Make a junk basket and gauge ring run to below the setting depth of the permanent packer. Unless setting a sump packer (eg for cased hole gravel packs), do not run the gauge ring below the depth of the top perforation (if perforations are already present). The gauge ring od must be at least as great as the maximum packer od.

2.2

Establish radio silence before removing the detonator from the gun store. The setting charge may be removed from the explosives store without radio silence.

2.3

Strap the packer assembly and running tool. Note the distance from the centre line of the packer rubbers and the land out shoulder to the zero on the running tool.

2.4

Ensure CCL is either fitted with a cartridge to boost the CCL signal or else the tool is decentralised. Taking these steps ensures that depth tie in can be achieved.

Section 2010 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2010 RUNNING A PERMANENT PACKER 0 01/10/92

3.

OPERATING PROCEDURE

3.1

Make up the permanent packer assembly and packer setting tool.

3.2

Establish radio silence. This must be maintained until the packer is 70m below the sea bed. Ensure all non essential personnel stay clear of the drill floor until the packer running tool is below sea level.

3.3

Make up and arm packer running tool and packer.

3.4

Run in hole, depth correlate to the CBL/VDL/GR/CCL, log up to place the centre line of mbrt. the packer rubbers at

3.5

Inform the BP Rep and Driller prior to setting the packer.

3.6

Set packer and POOH. When recovering the packer running tool radio silence must be re-imposed from when the packer is 70m below sea bed until the setting tool is known to be completely safe.

Section 2010 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2010 RUNNING A PERMANENT PACKER 0 01/10/92

4.

GUIDANCE NOTES

4.1

Never run the packer deeper than the depth of the gauge ring run.

4.2

Unless it is strictly necessary, eg when running a gravel pack sump packer, do not run the permanent packer into a perforated interval, this could damage the rubber elements or lead to the tool getting stuck.

4.3

If a sump packer is being run to below the perforated interval it is necessary to dress the perforation entry holes in the casing. This can be done either by running the gauge ring and using it to hammer off any perforation burrs, or by running a scraper assembly. If running the gauge ring, check the rating of the weak point and that the material of the gauge ring is much harder than the casing.

4.4

If there is insufficient sump to depth correlate when logging up to the setting depth, depth correlate above the setting depth, then run in hole and pull up to setting depth.

4.5

Never set the permanent packer opposite or within 1m of a casing joint.

Section 2010 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2020 LANDING STRING DUMMY RUN SEMISUB 0 01/10/92

LANDING STRING DUMMY RUN SEMISUB

1.

SAFETY

1.1

Standard drilling good practice covers all safety aspects of the landing string dummy run.

Section 2020 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2020 LANDING STRING DUMMY RUN SEMISUB 0 01/10/92

2.

PREPARATION

2.1

Supply the Sub Sea Test Equipment Engineer with a diagram of the BOP stack.

2.2

Check that a crossover from the fluted hanger to drill pipe is available.

2.3

Check and agree the Subsea Test Equipment Engineers sketch of the Stack/Wear Bushing/SSTT spaceout. The proposed spaceout must be such that two sets of rams can be closed around the slick joint and the shear rams can be closed once the SSTT is unlatched.

2.4

Check the depth and stroke of the riser slip joint and ensure that when the landing string is run and landed the lubricator valve will be well clear of the riser slip joint stroke.

Section 2020 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2020 LANDING STRING DUMMY RUN SEMISUB 0 01/10/92

3.

OPERATING PROCEDURE

3.1

RIH hole.

3.2

pipe rams to mark the drill pipe. Pull the Locate and engage the wear bushing. Cycle the wear bushing. Measure the spaceout from the wear bushing to the ram imprints.

3.3

Inspect the condition of the wear bushing and check its compatibility with the landing profile of the fluted hangar.

3.4

Re-run the wear bushing.

3.5

Make up and run the following assembly -

wear bushing pulling tool on drill pipe. Paint the first joint of drill pipe going into the

Stand of 5" drill pipe Fluted hangar and 5" slick joint painted white. of 5" drill pipe. Joints to

3.6

pipe rams to mark the RIH, engage compensator and land out in the wear bushing. Close the slick joint. Mark the pipe at the rotary table (at mid heave) and note the tide level.

3.7

Open the rams, strap out of the hole. Check the stack up measurements obtained in the dummy run against the Sub Sea Test Equipment Engineer's drawing. If the spaceout did not allow for both the lower and middle pipe rams to be closed around the slick joint and the shear rams to close over the unlatched SSTT, then adjust the position of the fluted hanger as required. Also check the drill pipe tally to confirm the depth of the hangoff point below the rotary table at mean sea level.

3.8

Pick up the flowhead and 1st joint of landing string. Make up and layout on pipe deck, attach coflexips. Paint a white line across the swivel connection such that it will be visible to the Driller when making up the flowhead to the landing string.

Section 2020 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2020 LANDING STRING DUMMY RUN SEMISUB 0 01/10/92

4.

GUIDANCE NOTES

4.1

The final spaceout must be such that two sets of rams can be closed around the slick joint and the shear rams can be closed once the SSTT is unlatched.

4.2

The dummy run can be made with the landing string tubing instead of drill pipe. However using tubing has the following disadvantages:

4.3

a

It takes longer to do the dummy run with tubing and the lost time is not fully re-couped when it comes to running the landing string using stands of tubing instead of single joints.

b

There is a risk of damaging the tubing connections.

If the landing string tubing is used for the dummy run it is recommended not to run the Lubricator or SSTT valves. The reasons why the SSTT and lubricator valves should not be run at this point are: a

Should the spaceout prove to be incorrect the SSTT could be damaged by attempting to close the rams on it.

b

It adds unnecessarily to the time taken to carry out the dummy run.

NOTE. The dimensions of both the SSTT, Lubricator valve and associated cross-overs must be known and accounted for in the final landing string running tally.

4.4

When considering the position of the Lubricator valve and flowhead the following should be noted : a

The lubricator valve should be a minimum of 15m, but ideally 25-30m below the flowhead to allow for wireline tools.

b

The Lubricator valve should be spaced out so that it is well clear of the riser slick joint stroke. (Note maximum control hose length is approximately 50 m)

c

The normal flowhead stick up required to accommodate tides and rig heave is 4.5m. However on the Ocean Alliance the minimum stick up requirement is 6.5m because in rough weather it is necessary to raise the rig to protect the lowest deck from wave damage.

Section 2020 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.5

2020 LANDING STRING DUMMY RUN SEMISUB 0 01/10/92

Coiled tubing If coiled tubing is to be run then do not attach the coflexips to the flowhead when making up the first joint of landing string tubing (step 3.8). The coiled tubing lifting frame and coflexips are added when the landing string is run.

Section 2020 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2030 LANDING STRING DUMMY RUN JACKUP 0 01/10/92

LANDING STRING DUMMY RUN JACKUP

1.

SAFETY Standard drilling practice covers all safety aspects of the landing string dummy run.

Section 2030 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2030 LANDING STRING DUMMY RUN JACKUP 0 01/10/92

2.

PREPARATION

2.1

Supply the Subsea Test Equipment Engineer with a diagram of the BOP stack.

2.2

Check that cross-overs from the SAFE valve to drill pipe and drill pipe to the ported slick joint are available.

2.3

Check the dimensions of the ported slick joints, lubricator valve and the sketch of where the slick joints will sit in the BOP's. The proposed spaceout must be such that the top ported slick joint is positioned opposite the upper pipe rams when the test string is landed. The bottom ported slick joint must be sufficient distance below to allow the slip joints to be fully extended and the packer unset when the lower slick joint is positioned opposite the upper pipe rams.

Section 2030 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2030 LANDING STRING DUMMY RUN JACKUP 0 01/10/92

3.

OPERATING PROCEDURE

3.1

Make up and run the following assembly -

Stand of 5" drill pipe 5" ported slick joint painted white. Tubing pup joint 5" ported slick joint painted white. Tubing pup joint Lubricator valve Tubing pup joint.

3.2

RIH, to the depth estimated to place the lower ported slick joint opposite the upper pipe rams. Mark the pipe at surface and close the upper pipe rams to mark the slick joint.

3.3

Open the rams, POOH, strap the distance from the rotary to the mid point of the ram imprint. Check the measured versus estimated depth of the upper pipe rams.

3.4

Stand back the assemblies and mark the pipe above the upper and lower slick joints such that the mark will be level with the rotary table when the slick joint is opposite the upper pipe rams.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2030 LANDING STRING DUMMY RUN JACKUP 0 01/10/92

4.

GUIDANCE NOTES

4.1

With most Jack-Up BOP stacks, the final spaceout will be such that the top ported slick joint is positioned opposite the upper pipe rams when the test string is landed. The bottom ported slick joint must be sufficient distance below to allow the slip joints to be fully extended and the packer unset when the lower slick joint is positioned opposite the upper pipe rams. In some cases the BOP stack will be configured or named differently and the preferred rams for use with the slick joint may be different. When planning a test Always check with the rig which set of rams will be used with the slick joints.

4.2

The dummy run can be made with drill pipe instead of the landing string tubing. The pro's and cons of tubing versus drill pipe are : a

Making the dummy run with the final assembly assures depth control. Using drill pipe just gives the depth of the rams and were a measurement error made in the ported slick joint/lubricator valve assembly the error could go undetected and lead to off depth perforation.

b

The landing string is the most common point in the string for problems with incorrect crossovers or insufficient pup joints. Making a run with the final assembly enables early detection of problems and gives time for replacement equipment to be sent.

c

It takes longer to do the dummy run with tubing and the lost time is not quite fully re-couped when it comes to running the landing string.

d

There is a slightly increased risk of damaging the tubing connections.

Section 2030 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2040 RUNNING TCP GUNS 0 01/10/92

RUNNING TCP GUNS

1.

SAFETY

1.1

A BOP test should have been carried out less than 7 days before commencement of the operation.

1.2

Prior to picking up the TCP guns hold a safety meeting on the rig floor to discuss the operation. The safety meeting should include; the BP REP, OIM, Toolpusher, Driller, TCP Engineer, PE, rig crew, crane driver and the roustabouts. The following points are to be made at the safety meeting. a.

All assembly/disassembly of the guns is to be carried out under the supervision of the TCP Engineer. While making up the guns all movement of the blocks should only be as directed by the TCP Engineer. b. All non-essential personnel must stay clear of the gun assembly area, the rig floor and BOP deck until the guns are below sea level. Final assembly and arming of the guns must only be carried out on the rig floor. Under no circumstances should guns be armed on the pipe deck or other area, before being lifted to the rig floor.

The following subjects should also be discussed at the safety meeting. a. b. c. d.

e. 1.3

Transport of guns to the rig floor. Gun make up. Purpose of the Safety spacer. Firing system and possible methods of accidental gun detonation. (Lightening strike, Severe mechanical impact eg the blocks falling on to an exposed booster) That radio silence is not required

The following points should be considered by the BP REP/OIM/PE/TCP Engineer or other supervisors of the operation: a.

All guns and spare explosives should be stored in a designated area taking full account of the position of access routes and emergency equipment. b. No hot work can be conducted within 6m of the stored explosives. c. Should it be necessary to load or unload guns on the rig then the area designated for this work should be cordoned off, no crane movements be permitted over the designated area, and no hot work be conducted within 6m of the gun loading area. d. When retrieving guns DO NOT pull the guns above the rotary table until the firing head has been removed. e. Radio silence is not required for TCP operations.

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1.4

2040 RUNNING TCP GUNS 0 01/10/92

Prior to making up the firing head a tannoy announcement must be made to the effect that the spider deck/BOP deck (semi/jack up) is out of bounds until further notice. Once the guns are below the water line the restriction can be lifted.

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2040 RUNNING TCP GUNS 0 01/10/92

2.

PREPARATION

2.1

If the TCP's are to be run on the test string, then before assembling the guns, pick up the flowhead and first joint of landing string and make up same. Layout the flowhead and first joint of landing string on the pipe deck. Attach the coflexips (if using a coiled tubing lifting frame it is best not to attach coflexips at this point) and paint a white line across the swivel connections.

2.2

For TCP's run with the test string, check that the mud weight in the annulus will give an overbalance of at least 100 psi at the packer with the riser unlatched. For TCP's run on Drill pipe, check that the mud weight will give an overbalance of 100 psi at the top perforation with the riser unlatched.

2.3

Check that the required number of guns, back up guns and associated tools have been supplied.

2.4

Check the position of the firing head in the gun string. Guns systems with the firing head at the base of the guns will not be run.

2.5

Measure the lengths of all components in the TCP string, and running string as far as the RA sub. i.e. The guns, firing heads, drop subs, safety spacers, ported subs, tubing pups, test tools and drill collars.

2.6

Drift all components above the mechanical firing head and check the diameter of the No Go fitted above the mechanical firing head. Check that the logging tools used for the depth correlation run can not pass the No Go.

2.7

Check the operation of the Gun release system.

2.8

Check the TCP Engineer's calculation of firing pressure and agree the type and number of shear pins required to achieve this.

2.9

Check and agree the TCP Engineers gun make up sketch.

2.10

The pinning of the firing head must be witnessed by the BP REP/PE.

2.11

Ensure that all the required handling equipment for the guns has been physically checked for compatibility before starting to make up the guns.

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2040 RUNNING TCP GUNS 0 01/10/92

3.

OPERATING PROCEDURE

3.1

Hold a safety meeting on the rig floor prior to assembling the guns.

3.2

Make tannoy announcement that 'All none essential personnel must stay clear of the rig floor and BOP deck until further notice'.

3.3

As directed by the TCP Engineer, pick up and make up guns in accordance with the TCP Engineer's Make up diagram. Note Accurately strap the distance from the top shot to the position of the RA marker sub in the TCP running string. Check measured versus estimated strap and investigate any discrepancy greater than 0.3m

3.4

Make up safety spacer. (This ensures the guns are below the rotary table when they are armed)

3.5

Remove all non essential personnel from the rig floor and cellar deck prior to making up the firing head to the guns. Do not pull the guns above the rig floor after the firing head has been installed.

3.6

Install cross-over from the TCP string to the TCP running string.

Section 2040 Page 4

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2040 RUNNING TCP GUNS 0 01/10/92

4.

GUIDANCE NOTES

4.1

For Semi sub TCP operations the requirement for 100 psi overbalance in the annulus at the packer (top shot for TCP run on drill pipe with no packer) with riser unlatched, is taken from the BP drilling manual section 0400/GEN. However in special circumstances, eg. Gravel packing where high losses are expected and no gas is present, the overbalance requirement has been relaxed to 50 psi at the discretion of Manager Drilling. For jack-up TCP operations the overbalance requirement in the annulus at the packer (Top shot for TCP run on drill pipe with no packer) is 200 psi.

4.2

Gun systems with the firing head at the base of the guns will not be run. During the planning stage the position of the firing head in the perforating string must be determined to ensure that systems with the firing head at the base of the guns never arrive offshore.

4.3

The minimum pressure to which the firing head should be pinned is calculated as follows : Min firing pressure = SGmud x Dfh x 1.421 + MOP + SF (psig) Where SGmud Dfh MOP

SF 1.421

= The specific gravity of the mud = True vertical depth of the firing head in metres = Maximum annulus operating pressure applied to operate any may be required prior to firing the guns. (Typically 2000 psi for the tester valve) = Safety factor (minimum of 1000 psi) = The hydrostatic head of 1m of fresh water ie SG = 1.0

tool which

The minimum shearing value of the shear pins or shear bar must not be less than the minimum firing pressure calculated above. The tubing pressure required to fire the guns should assume the maximum shearing value of the shear pins or shear bar. Each company has its own calculation sheet for calculating the minimum gun firing pressure and the number of shear pins required. Each sheet is slightly different but follows the principles shown above. 4.4

All possible leak paths to communicate pressure to the guns should be considered when calculating the minimum gun firing pressure.

4.5

Should a misrun occur then the operation to retrieve the TCP guns after the misrun must be discussed with the TCP representative in town. Written procedures specific to the situation encountered must be agreed prior to starting to retrieve the guns.

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4.6

Shock loading when handling guns can lead to a misfire. This is because the perforating charges and primer cord are loaded into an internal carrier which is in turn located inside the gun body by means of small grub screws. Movement of the internal carrier can damage the primer cord or increase the space between the booster and the primer cord to the point where the booster will not ignite the primer cord.

4.7

The maximum gun OD must be at least 1/2" smaller than the casing ID to prevent the guns becoming stuck after firing. A clearance of 1" is often preferred since this further reduces any risk of the guns getting stuck and allows the guns to be recovered with wash pipe if necessary. However increasing the gun standoff can adversely effect the performance of some charges.

4.8

If guns are to be dropped, check that sufficient sump will be available for other operations, eg. BHS, PLT.

4.9

The down hole tools engineer must be present at the cement unit during any operation which involves pressurising the string, eg pressure testing.

4.10

When retrieving guns, if a section of gun or the whole gun assembly has not fired, it must be assumed that pressure is trapped inside the gun section. The source of trapped pressure could be either combustion gases from spent primer cord or mud that leaked into the gun under pressure.

Section 2040 Page 6

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2050 RUNNING TEST STRING SEMISUBS 0 01/10/92

RUNNING TEST STRING SEMISUBS

1.

SAFETY

1.1

A BOP test should have been carried out less than 7 days before commencement of the operation.

1.2

Ensure all equipment to be run is rated for the pressures to which it will be subjected.

1.3

Ensure that any nitrogen to be used in the test tools contains less than 1% Oxygen. Use of off spec Nitrogen could result in the compression ignition of residual hydrocarbons/hydraulic oils present in the test tools.

1.4

Ensure a stab in valve (Kelly Cock) is on the floor and made up to the correct cross over at all times.

1.5

Check that the tubing diameter is within the operating range of the variable rams.

Section 2050 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2050 RUNNING TEST STRING SEMISUBS 0 01/10/92

2.

PREPARATION

2.1

Before making up the minor string pick up the flowhead and first joint of landing string and make up same. Layout the flowhead and first joint of landing string on the pipe deck. Attach the coflexips (if using a coiled tubing lifting frame it is best not to attach coflexips at this point)and paint a white line across the swivel connections. (The making up of the flowhead may already have been done if TCP guns are being run)

2.2

Ensure all downhole tools are certified, that they are pressure tested to their operation is confirmed on the deck before running in the hole.

2.3

Tools that require a nitrogen precharge should be charged up at least 24 hours before they are due to be run. The charge pressure should be checked several hours before the tools are run.

2.4

Check power output of mud pumps/cement pumps to determine the number of circulation ports to use on the circulating valve. (Only applies to Schlumberger and Baker tools).

2.5

The lengths, drift and connections of all downhole tools are to be checked by the PE/DE. The drift diameter must be 2.125".

2.6

Have the tubing cleaned, inspected and protected as follows:

psi and that

a

All joints should be measured and clearly painted with a number.

b

" with a 42" long Each " tubing joint should be drifted from the Box-end to drift. Check the drift across two diameters at each end and in the middle using callipers.

c

Blow through the pipe with compressed air to ensure it is internally clean and dry.

d

The connection threads/seal faces should be cleaned with either, a high pressure steam jet followed by an air blast to dry them, or by a high pressure water jet followed by a de-watering solvent eg 'Houghtoclean 500' applied with a soft clean brush. Diesel or Paraffin should not be used for joint cleaning since, if not fully removed, a lack of lubricant adhesion to thread/seal surfaces can result.

e

Inspect the threads and seal area for damage or manufacturing flaws. Clearly mark rejected joints.

f

After the threads and protectors are completely dry and clean, light gear oil should be applied to the threads and the protectors re-fitted.

Section 2050 Page2

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2.7

The drill collars to be run must be drifted to 2.125" and have their threads inspected for signs of wear/damage.

2.8

Have the running equipment checked as follows: a

Power Tongs Check the torque output of the tongs up to the maximum anticipated for the job. Check the accuracy of the hydraulic load cell versus the computer torque output. Check the operation of the dump valve which automatically cuts make up when the required connection torque has been reached.

b

Elevators and Slips Check that the single joint elevators are in good working order and are rated for the maximum anticipated load. Check the condition of the slip dies and perform a trial latch of the elevators on to the tubing before the job starts.

c

Stabbing Guide Check that the stabbing guide fits snugly over the box, extending at least to the inside of the shoulder, in order to prevent the pin seal catching on the box whilst stabbing.

2.9

Prepare a string running order and include details of all equipment lengths, ID's, OD's, thread connections and make up torques. Indicate on the running list when to pressure test and the joints where the tailpipe/packer assembly enters the BOP's and any liner tops. Note The packer should be set at least 3m from the nearest casing collar (from CBL/CCL log)

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3.

OPERATING PROCEDURE

3.0

Pick up and run TCP assembly to packer as per separate operating procedure.

3.1

Run Packer and DST tools, drill collars and slip joints as per attached running list/diagram. Only dope the pin ends of the test string joints sparingly with either a 2" paint brush or a spray dope applicator. The importance of keeping the string I.D. clear cannot be over stressed. Only set slips after the string has stopped moving to avoid any shock loads. Maximum running speed slips to slips is

seconds

Fill string above the closed tester valve with seawater as RIH. Note string weight when running the first slip joint. 3.2

Run 1st joint of -1/2" tubing. Tubing inspector to be on rig floor to inspect the threads and check the make up of each joint. Fill string and pressure test to 300 psig for 5 minutes and the tester valve.

3.3

Continue to run the

-1/2"

psi for 10 minutes against

tubing using the computerised joint make-up analyser.

Exercise extreme care when the tailpipe/packer assembly enters the BOP's and any liner tops. Continue to fill string with seawater. Inform the BP PE/DE/REP of any joints that fail to make up or are rejected for any other reason. Lay out rejected joints and mark with red paint. 3.4

Pressure test the string to 300 psig for 5 minutes and joint .

3.5

Run the remainder of the

-1/2"

psi for 10 minutes after running

tubing using the computerised joint make-up analyser.

Continue to fill string with seawater. 3.6

Pressure test the string to 300 psig for 5 minutes and tubing has been run.

psi for 10 minutes once all the

Section 2050 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3.7

2050 RUNNING TEST STRING SEMISUBS 0 01/10/92

Pick up and run the fluted hanger and slick joint. Denzo tape or paint the slick joint with to of drill pipe and land out the fluted hangar in the wear white paint. RIH joints bushing. Do not fill the drill pipe with seawater.

3.8

Rig up wireline and compensate as per open hole logging. Run GR/CCL correlation log to locate RA markers in test string and casing.

3.9

Rig down wireline, close then open the middle pipe rams and pull back the landing string. Adjust the tubing spaceout as required taking into consideration the stroke of the slip joints, jars, hydrostatic reference tool and packer.

Section 2050 Page5

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2050 RUNNING TEST STRING SEMISUBS 0 01/10/92

4.

GUIDANCE NOTES

4.1

If TCP guns are not being run then delete item 3.0 from the operating procedure.

4.2

Read section 2900 of the Drilling Manual. This has more detailed procedures for preparing the tubing and the tubing running equipment.

4.3

Discuss the maximum running speed per joint with the TCP and Downhole Tools Engineers.

4.4

If running a Halliburton TST valve the string will be self filling and will fill with wellbore fluid. The operating procedure should be changed to reflect this. Note that prior to pressure testing against a TST valve it is a good idea to Yo-Yo the string to clean the TST valve's seal faces.

4.5

Under no circumstances should tubulars be handled without having thread protectors installed on the pins. This includes standing back in the derrick.

4.6

Note that the packer should be set at least 3m from the nearest casing collar (from CBL/CCL log).

4.7

If a PLT is to be run the distance from the tail pipe to the top shot should ideally be a minimum of 35 metres.

4.8

Following the gun correlation run, the space out should be proposed by the PE and be verified by two others, eg TCP rep & DE. Spaceouts are not recommended to be calculated by committee.

4.9

In sour or CO2 wells consideration should be given to the use of CB rings (Corrosion barrier) in the tubing box ends to protect the seal areas from corrosion.

4.10

The cementing kelly should not be used for pressure testing the tubing.

4.11

It is more time efficient to run the fluted hanger (step 3.7) on drill pipe than use the landing string tubing. This is because it takes extra time to make up and breakout tubing joints than to make and break drill pipe.

Section 2050 Page6

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.12

2050 RUNNING TEST STRING SEMISUBS 0 01/10/92

Running the test string with a permanent packer If a seal mandrel and permanent packer are being run, the following points must be considered. a

Every run into and out of the permanent packer runs the risk of damaging seals.

b

It is possible to pressure lock the string when stabbing in or out of the packer unless consideration has been given to bypass routes.

c

The most common method of spacing out the seal assembly is to stab into the packer and land off in the locator, then pull back and adjust the spaceout as required.

Methods of depth correlation that avoid stabbing the seal assembly into the permanent packer, eg tubing RA sub and GR correlation run, can be used if the risk of damaging the seals by stabbing in twice is considered high.

Section 2050 Page7

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2060 RUNNING TEST STRING JACKUPS 0 01/10/92

RUNNING TEST STRING JACKUPS

1.

SAFETY

1.1

A BOP test must have been carried out less than 7 days before commencement of the operation.

1.2

Ensure all equipment to be run is rated for the pressures to which it will be subjected.

1.3

Ensure that any nitrogen used in the test tools contains less than 1% Oxygen. Use of off spec Nitrogen could result in the compression ignition of residual hydrocarbons/hydraulic oil present in the test tools.

1.4

Ensure a stab in valve (Kelly Cock) is on the floor and made up to the correct cross over at all times.

1.5

Check that the tubing diameter is within the operating range of the variable rams.

Section 2060 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2060 RUNNING TEST STRING JACKUPS 0 01/10/92

2.

PREPARATION

2.1

Ensure all downhole tools are certified, that they are pressure tested to their operation is confirmed on the deck before running in the hole.

2.2

Tools that require a nitrogen precharge should be charged up at least 24 hours before they are due to be run. The charge pressure should be checked several hours before the tools are run.

2.3

Check power output of mud pumps/cement pumps to determine the number of circulation ports to use on the circulating valve. (Only applies to Schlumberger and Baker tools).

2.4

The lengths, drift and connections of all downhole tools are to be checked by the PE/DE. The drift diameter must be 2.125".

2.5

Have the tubing cleaned, inspected and protected as follows:

psi and that

a

All joints should be measured and clearly painted with a number.

b

" tubing joint should be drifted from the Box-end to " with a 42" long Each drift. Check the drift across two diameters at each end and in the middle using callipers.

c

Blow through the pipe with compressed air to ensure it is internally clean and dry.

d

The connection threads/seal faces should be cleaned with either, a high pressure steam jet followed by an air blast to dry them, or by a high pressure water jet followed by a de-watering solvent eg 'Houghtoclean 500' applied with a soft clean brush. Diesel or Paraffin should not be used for joint cleaning since, if not fully removed, a lack of lubricant adhesion to thread/seal surfaces can result.

2.6

e

Inspect the threads and seal area for damage or manufacturing flaws. Clearly mark rejected joints.

f

After the threads and protectors are completely dry and clean, light gear oil should be applied to the threads and the protectors re-fitted.

The drill collars to be run must be drifted to 2.125" and have their threads inspected for signs of wear/damage.

Section 2060 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2.7

2060 RUNNING TEST STRING JACKUPS 0 01/10/92

Have the running equipment checked as follows: a

Power Tongs Check the torque output of the tongs up to the maximum anticipated for the job. Check the accuracy of the hydraulic load cell versus the computer torque output. Check the operation of the dump valve which automatically cuts make up when the required connection torque has been reached.

b

Elevators and Slips Check that the single joint elevators are in good working order and are rated for the maximum anticipated load. Check the condition of the slip dies and perform a trial latch of the elevators on to the tubing before the job starts.

c

Stabbing Guide Check that the stabbing guide fits snugly over the box, extending at least to the inside of the shoulder, in order to prevent the pin seal catching on the box whilst stabbing.

2.8

Prepare a string running order and include details of all equipment lengths, ID's, OD's, thread connections and make up torques. Indicate on the running list when to pressure test and the joints where the tailpipe/packer assembly enters the BOP's and any liner tops. Note The packer should be set at least 3m from the nearest casing collar (from CBL/CCL log). The Safe valve should be run below the mud line hanger. Check that the RA marker in the liner can be accessed by the GR/CCL tool by running into above the tester valve.

Section 2060 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

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3.

OPERATING PROCEDURE

3.0

Pick up and run TCP assembly as per separate operating procedure.

3.1

Run Packer and DST tools, drill collars and slip joints as per attached running list/diagram. Only dope the pin ends of the test string joints sparingly with either a 2" paint brush or a spray dope applicator. The importance of keeping the string I.D. clear cannot be over stressed. Only set slips after the string has stopped moving to avoid any shock loads Maximum speed slips to slips is

seconds

Fill string above the closed tester valve with seawater as RIH. Note string weight when running the first slip joint. 3.2

tubing. Tubing inspector to be on rig floor to inspect the Run 1st joint of -1/2" threads and check the make up of each joint. Fill string and pressure test to 300 psig for 5 minutes and the tester valve.

3.3

Continue to run the

-1/2"

psi for 10 minutes against

tubing using the computerised joint make-up analyser.

Exercise extreme care when the tailpipe/packer assembly enters the BOP's and any liner tops. Continue to fill string with seawater. Inform the BP PE/DE/REP of any joints that failed to make up or were rejected for any other reason. Lay out rejected joints and mark with red paint. 3.4

Pressure test the string to 300 psig for 5 minutes and joint .

3.5

Run the remainder of the analyser.

-1/2"

psi for 10 minutes after running

tubing using the computerised joint make-up

Continue to fill string with seawater. 3.6

Pressure test the string to 300 psig for 5 minutes and tubing has been run.

psi for 10 minutes once all the

Section 2060 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

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3.7

Note the hanging weight of the string, set the slips.

3.8

Rig up wireline for GR/CCL correlation run. RIH and locate RA markers in test string and liner.

3.9

POOH and rig down wireline. Adjust the tubing spaceout as required taking into consideration the stroke of the slip joints, jars, hydrostatic reference tool, and packer.

Section 2060 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2060 RUNNING TEST STRING JACKUPS 0 01/10/92

4.

GUIDANCE NOTES

4.1

If TCP guns are not being run then delete item 3.0 from the operating procedure.

4.2

Read section 2900 of the Drilling Manual. This has more detailed procedures for preparing the tubing and the tubing running equipment.

4.3

Discuss the maximum running speed per joint with the TCP and Downhole Tools Engineers.

4.3

If running a Halliburton TST valve the string will be self filling and will fill with wellbore fluid. The operating procedure should be changed to reflect this. Note that prior to pressure testing against a TST valve it is a good idea to Yo-Yo the string to clean the TST valve's seal faces.

4.4

Under no circumstances should tubulars be handled without having thread protectors installed on the pins. This includes standing back in the derrick.

4.5

Note that the packer should be set at least 3m from the nearest casing collar (from CBL/CCL log).

4.6

The Safe valve should be run below the mud line hangar.

4.7

After running the tubing as far as the SAFE valve, it should be possible to access the RA marker in the liner with the GR/CCL tool by running into above the tester valve. If the RA marker can not be accessed, cross-over to drill pipe and run the required amount of extra drill pipe, strapping as it is run.

4.8

If a PLT is to be run the distance from the tail pipe to the top shot should ideally be a minimum of 35 metres.

4.9

Following the gun correlation run, the space out should be proposed by the PE and be verified by two others, eg TCP rep & DE. Spaceouts are not recommended to be calculated by committee.

4.10

In sour or CO2 wells consideration should be given to the use of CB rings (Corrosion barrier) in the tubing box ends to protect the seal areas from corrosion.

4.11

The cementing kelly should not be used for pressure testing the tubing.

Section 2060 Page6

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.12

2060 RUNNING TEST STRING JACKUPS 0 01/10/92

Running the test string with a permanent packer If a seal mandrel and permanent packer are being run, the following points must be considered. a

Every run into and out of the permanent packer runs the risk of damaging the seals.

b

It is possible to pressure lock the string when stabbing in or out of the packer unless consideration has been given to bypass routes.

c

The most common method of spacing out the seal assembly is to stab into the packer and land off in the locator, then pull back and adjust the spaceout as required.

Methods of depth correlation that avoid stabbing the seal assembly in to the permanent packer eg tubing RA sub and GR correlation run, can be used if the risk of damaging the seals is by stabbing in twice is considered high.

Section 2060 Page7

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2070 RUNNING LANDING STRING SEMISUBS 0 01/10/92

RUNNING LANDING STRING SEMISUBS

1.

SAFETY

1.1

Ensure all equipment to be run is rated for the pressures to which it will be subjected.

1.2

Ensure a stab in valve (Kelly Cock) is on the floor and made up to the correct cross-over at all times.

1.3

Check that the maximum torque rating of the landing string is sufficient to shear the shear pins in the sub sea test tree should it be necessary to mechanically unlatch.

Section 2070 Page1

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2.

PREPARATION

2.1

Before making up TCP guns or the minor string, pick up the flowhead and first joint of landing string and make up same. Layout the flowhead and first joint of landing string on the pipe deck. Attach the coflexips (if using a coiled tubing lifting frame it is best not to attach coflexips at this point) and paint a white line across the swivel connections.

2.2

Pressure and function test the sub sea test tree and lubricator valve on the deck prior to running in hole. Check that the valves open fully and close smoothly. Check that the unlatch operates smoothly without sticking.

2.3

Check that the SSTT ball is dressed with the appropriate cutting capability.

2.4

Check that a cross-over from the fluted hanger to drill pipe is available for use in the spaceout run.

2.5

Flush the chemical injection and control hoses and pressure test to working pressure for 30 minutes

2.6

Check the lengths of the sub sea test tree, lubricator valve and any pup joints made up to them to aid handling.

2.7

Check the dimensions on the service company sketches of the sub sea test tree the lubricator valve and where the SSTT will sit in the BOP's.

2.8

Check the depth and stroke of the riser slip joint and ensure that when the string is landed the lubricator valve will be well clear of the riser slip joint stroke.

2.9

Prepare a landing string running order and include details of all equipment lengths, ID's, OD's, thread connections and make up torques. Indicate on the running list when to pressure test and the joints where the SSTT and lubricator valve enter the riser slip joint.

Section 2070 Page2

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2070 RUNNING LANDING STRING SEMISUBS 0 01/10/92

3.

OPERATING PROCEDURE

3.1

Make up the fluted hanger, slick joint and SSTT to the major string. DO NOT fill up the slick joint with water. Pressure test the open and close control lines to their operating pressure for 5 minutes and observe for leaks. Fill up above the closed ball valve with water. Open the ball valve and observe that the fluid level falls. Function test the SSTT latch assembly. Pick up string weight to confirm the tree is relatched.

3.2

Run the landing string as per the running tally. Strap the hose bundle to the tubing with adhesive tape and steel banding. Hold pressure on the SSTT ball open line. Fill the landing string with sea water as it is run.

3.3

When running the joint below the Lubricator valve DO NOT fill it with sea water.

3.4

Install the Lubricator valve. Pressure test the lubricator valve open and close control hoses to their operating pressures for 5 minutes and observe for leaks. Close the Lubricator valve fill up above the valve with water. Open the valve and observe that the fluid level falls.

3.5

With the SSTT and Lubricator valve open. Fill the string and pressure test the whole psi for 10 minutes from the string against the tester valve to 300 psi for 5 minutes and cement unit. psi to the chemical injection line to Whilst performing the above pressure test, apply confirm its integrity. Bleed off chemical injection line pressure. While still maintaining tubing pressure, close the SSTT and bleed off the pressure above to 300 psi. Monitor for PBU for 10 minutes. Pressure up to equalise across and open the SSTT. While maintaining pressure close the Lubricator valve and bleed off the pressure above to 300 psi. Monitor for PBU for 10 minutes. Pressure up to equalise across and open the Lubricator valve. Bleed off the pressure and psi then close the Lubricator valve. Pressure test the Lubricator valve from above to for 10 minutes. Bleed off the pressure at the cement unit.

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2070 RUNNING LANDING STRING SEMISUBS 0 01/10/92

3.6

Continue running the landing string as per the running tally.

3.7

Put four right hand wraps of the lubricator and SSTT control line hoses around the pipe before making up the flowhead.

3.8

Pick up the long bails. Pick up the flowhead with single joint and coflexips attached and make up to the landing string. When making up this connection ensure that minimum weight is set down and that the first few turns are made with a chain tong. Watch the painted line on the flowhead to ensure no connections are backed off.

3.9

Note the static and running weights.

3.10

Engage compensator. Run in and land off the fluted hangar in the wear bushing. Check the stick up is at least 4.5m at mid heave and mid tide level.

3.11

Pick up the choke manifold. Make up the surface lines.

Section 2070 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2070 RUNNING LANDING STRING SEMISUBS 0 01/10/92

4.

GUIDANCE NOTES

4.1

The control hoses tend to relax under pressure and require a long pressure test to be confident of their integrity. The chemical injection line test pressure should be the lower of: Expected Shut in Well Head pressure + 1000 psi or Test string test pressure - 1000 psi There is no requirement to test the chemical injection line to the WHP required for gun detonation since the chemical injection line is isolated from the tubing and increasing the test pressure increases the possibility of the line failing.

4.2

The sub sea test tree and lubricator valves are normally made up to short pup joints for ease of handling, the lengths of these pup joints must be taken into account in the landing string tally.

4.2

In wells with the possibility of sand production, water production or a low GOR the sub sea test tree should have the capability to cut coiled tubing. In such wells there is always a possibility that coiled tubing will be needed.

4.3

If running a Halliburton TST valve the string will be self filling and will fill with mud.

4.4

The SSTT is pump through and the hydrostatic head of water above the valve may be sufficient to unseat the valve and fill the slick joint with water before the valve is opened.

4.5

Maintain pressure on the SSTT ball open line when running the landing string to ensure the control bundle remains intact.

4.6

Once the SSTT is landed out in the wear bushing DO NOT make a trial disconnect downhole.

4.7

The lubricator valve should be placed at least 15m below the flowhead to allow for wireline tools.

4.8

The normal flowhead stick up required to accommodate tides and rig heave is 4.5m. However on the Ocean Alliance the minimum stick up requirement is 6.5m because in rough weather it is necessary to raise the rig to protect the lowest deck from wave damage.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.9

2070 RUNNING LANDING STRING SEMISUBS 0 01/10/92

Running the landing string with coiled tubing. If coiled tubing is to be used the only difference in running the landing string comes when making up the flowhead. Step 3.8 should be replaced with the following: 3.8.1

Pick up the flowhead without the coflexips attached and stand in the mouse hole.

3.8.2

Pick up the coiled tubing lifting frame,and attach it to the flowhead using the quick disconnect coupling. Pick up the lifting frame 3m and make up the coflexips to the flowhead.

3.8.3

Make up flowhead and single to landing string in the slips. When making up to the landing string ensure that minimum weight is set down and the first few turns are put in with a chain tong. Watch the painted line on the flowhead to ensure no connections are backed out.

(The best time to make up the coiled tubing BOPs and injector head will depend on when the coiled tubing will be required) 4.10

Running the landing string with a permanent packer If a permanent packer is being used step 3.7 should be omitted and the following points considered: a

Rig heave will be moving the base of the seal assembly relative to the packer when making up the single on the flowhead to the landing string. Consideration must be given to the relative positions of the base of the seal assembly and the top of the permanent packer to avoid damaging either item. If necessary a pup joint may be added below the single joint attached to the flowhead.

b

The operation (3.10) of running in to land out the fluted hangar in the wear bushing will stab the seal mandrel into the permanent packer.

c

Standard practice when running TCP's, a retrievable packer and a tubing pressure operated circulating valve, is to circulate the cushion in place prior to setting the packer. This maintains an 'open system' and therefore avoids the risk of communicating pressure to the firing head and accidental gun detonation when cycling the circulating valve open.

Section 2070 Page6

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2070 RUNNING LANDING STRING SEMISUBS 0 01/10/92

However when running TCP's, a permanent packer, and a tubing pressure operated circulating valve, an 'open system can not be maintained. The risk of premature gun detonation when cycling the tubing pressure operated circulating valve open must be overcome by some other method. Alternative methods include: i

Increasing the firing pressure to the pressure applied to operate the cycling valve plus 1000 psi

ii

Running a pressure operated reference tool and circulating the cushion in place before setting the reference tool.

iii

Using a wireline conveyed firing head which would be run after the cushion was in place.

Section 2070 Page7

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2080 RUNNING LANDING STRING JACKUPS 0 01/10/92

RUNNING LANDING STRING JACKUPS

1.

SAFETY

1.1

Ensure all equipment to be run is rated for the pressures to which it will be subjected.

1.2

Ensure a stab in valve (Kelly Cock) is on the floor and made up to the correct cross-over at all times.

Section 2080 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2080 RUNNING LANDING STRING JACKUPS 0 01/10/92

2.

PREPARATION

2.1

Pressure and function test the SAFE and lubricator valve on the deck prior to running in hole. Check that the valves open fully and close smoothly.

2.2

Check that the SAFE valve ball is dressed with the appropriate cutting capability.

2.3

Check that cross-overs from the SAFE valve to drill pipe and from drill pipe to the ported slick joint are available.

2.4

Flush the chemical injection and control hoses and pressure test to working pressure for 30 minutes

2.5

Check the lengths of the SAFE valve, lubricator valve, ported slick joints and any pup joints made up to them.

2.6

Check the dimensions on the service company sketches of the SAFE valve, lubricator valve ported slick joints and where the slick joints will sit in the BOP's.

2.7

Prepare a landing string running order and include details of all equipment lengths, ID's, OD's, thread connections and make up torques. Indicate on the running list when to pressure test and the joint where the SAFE valve enters the mud line hanger.

Section 2080 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2080 RUNNING LANDING STRING JACKUPS 0 01/10/92

3.

OPERATING PROCEDURE

3.1

Make up the SAFE valve to the major string. DO NOT fill up the joint below with water. Pressure test the open and close control lines to their operating pressure for 5 minutes and observe for leaks. Fill up above the closed ball valve with water. Open the ball valve and observe that the fluid level falls.

3.2

Run the landing string as per the running tally. Strap the hose bundle to the tubing with adhesive tape and steel banding. Hold pressure on the SAFE valve ball open line. Fill the landing string with sea water as it is run.

3.3

When running the joint below the Lubricator valve DO NOT fill it with sea water.

3.4

Install the Lubricator valve. Pressure test the lubricator valve open and close control hoses to their operating pressures for 5 minutes and observe for leaks. Close the Lubricator valve fill up above the valve with water. Open the valve and observe that the fluid level falls.

3.5

With the SAFE and Lubricator valves open. Fill the string and pressure test the whole psi for 10 minutes from the string against the tester valve to 300 psi for 5 minutes and cement unit. psi to the chemical injection line to confirm its Whilst performing the above test, apply integrity. Bleed off chemical injection line pressure. While still maintaining pressure, close the SAFE and bleed off the pressure above to 300 psi. Monitor for PBU for 10 minutes. Pressure up to equalise across and open the SAFE. While maintaining pressure close the Lubricator valve and bleed off the pressure above to 300 psi. Monitor for PBU for 10 minutes. Pressure up to equalise across and open the Lubricator valve. Bleed off the pressure and psi then close the Lubricator valve. Pressure test the Lubricator valve from above to for 10 minutes. Bleed off the pressure at the cement unit.

3.6

Put four right hand wraps of the lubricator and SSTT control line hoses around the pipe before making up the flowhead.

Section 2080 Page3

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2080 RUNNING LANDING STRING JACKUPS 1 28/04/95

3.7

Pick up the long bails. Pick up the flowhead and make up to the landing string. When making up this connection ensure that minimum weight is set down and that the first few turns are made with a chain tong. Watch the painted line on the flowhead to ensure no connections are backed off.

3.8

Note the static and running weights.

3.9

Run in and set slips. Flowhead stick up should be kept to a minimum.

3.10

Make up the surface lines, as appropriate (see guidance note 4.10).

Section 2080 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2080 RUNNING LANDING STRING JACKUPS 0 01/10/92

4.

GUIDANCE NOTES

4.1

The control hoses tend to relax under pressure and require a long pressure test to be confident of their integrity. The chemical injection line pressure test should be the lower of: Expected shut in Well Head Pressure + 1000 psi or Test string pressure - 1000 psi There is no requirement to test the chemical injection line to the WHP required for gun detonation since the injection line is isolated from the tubing and increasing the test pressure increases the possibility of the line failing.

4.2

The Safe valve and lubricator valves are normally made up to short pup joints for ease of handling, the lengths of these pup joints must be taken into account in the landing string tally.

4.3

In wells with the possibility of sand production, water production or a low GOR the SAFE valve should have the capability to cut coiled tubing. In such wells there is always a possibility that coiled tubing will be needed.

4.4

If running a Halliburton TST valve the string will be self filling and will fill with wellbore fluid. The operating procedure should be changed to reflect this. Note that prior to pressure testing against a TST valve it is a good idea to Yo-Yo the string to clean the TST valve's seal faces.

4.5

The SAFE is pump through and the hydrostatic head of water above the valve may be sufficient to unseat the valve and fill the joint below with water before the valve is opened.

4.6

Maintain pressure on the SAFE valve ball open line when running the landing string to ensure the control bundle remains intact.

4.7

The flowhead stick up should be kept to a minimum.

4.8

The SAFE valve should be placed below the mudline hanger.

4.9

Running the landing string with coiled tubing. If coiled tubing is to be used the landing string running procedure does not require modification. The best time to attach the lifting frame and coiled tubing BOP's will depend on the sequence of operations proposed for the well.

Section 2080 Page5

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4.9

2080 RUNNING LANDING STRING JACKUPS 1 28/04/95

Running the landing string with a permanent packer If a permanent packer is being used Step 3.6 should be omitted and the following must be considered: Standard practice when running TCP's a retrievable packer and a tubing pressure operated circulating valve, is to circulate the cushion in place prior to setting the packer. This maintains an 'open system' and therefore avoids the risk of accidental gun detonation when cycling the circulating valve open. However when running TCP's, a permanent packer, and a tubing pressure operated circulating valve, an 'open system' can not be maintained. The risk of premature gun detonation when cycling the tubing pressure operated circulating valve open must be overcome by some other method. Alternative methods include:

4.10

a

Increasing the firing pressure to the pressure applied to operate the cycling valve plus 1000 psi

b

Running a pressure operated reference tool and circulating the cushion in place before setting the reference tool.

c

Using a wireline conveyed firing head which would be run after the cushion was in place.

Careful consideration should be given to making up surface lines prior to setting the packer. The following points should be taken into account. a

It may not be appropriate to rig up a chicksan line prior to setting the packer. Chicksan is relatively unwieldy and downward movement on setting packer could result in damage to chicksan or other equipment.

b

Rigging up a line to the flowhead after setting the packer may be an awkward and hazardous operation.

Section 2080 Page6

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2090 SETTING A RETRIEVABLE PACKER 0 01/10/92

SETTING A RETRIEVABLE PACKER

1.

SAFETY

1.1

Standard drilling practice covers all safety aspects of the packer setting operation.

Section 2090 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2090 SETTING A RETRIEVABLE PACKER 0 01/10/92

2.

PREPARATION

2.1

Paint a white line across the swivel connections such that it will be visible to the driller when setting the packer.

2.2

Put four right hand wraps of the lubricator and SSTT control lines hoses around the pipe before making up the flowhead.

2.3

Calculate the pick up required to set the packer and TCP guns on depth. The following elements need to be accounted for when calculating the pick up: -

Slip joints Jars Packer bypass Tester valve reference tool (Only needs to be accounted for with certain types of reference tool eg Schlumberger HRT)

Section 2090 Page2

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2090 SETTING A RETRIEVABLE PACKER 0 01/10/92

3.

OPERATING PROCEDURE

3.1

With compensator engaged and the fluted hanger landed off in the wear bushing, mark the pipe at the rotary table at mid heave.

3.2

Pick up the string weight plus Note

3.3

m.

klbs Pick up weight should be klbs Running weight should be Running weight with packer set should be

klbs

Set slips in the rotary and stand on slips/hammer down into position until slips have engaged. Note Downward movement of the string when setting slips will reset the packer in the safety position and prevent the packer setting.

3.4

Slack off string weight minus 20,000 lbs. (Failure to slack off sufficient string weight will cause the swivel to back off when rotating to set the packer.

3.5

Rotate string

turns to the right using either the rotary table or the rig tongs.

Observe paint line on swivel to check that it is not being backed out. 3.6

Allow torque to unwind from tubing.

3.7

Pick up string weight plus the absolute minimum required to enable the slips to be removed, remove slips.

3.8

Slack off weight. After about 1 foot the weight should start to decrease as the packer sets and takes the weight of the minor string.

3.9

Continue slacking off until the fluted hanger lands out in the wear bushing. The white mark should now be at the rotary table.

3.10

Slack off string weight minus 20,000 lbs.

Section 2090 Page3

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2090 SETTING A RETRIEVABLE PACKER 0 01/10/92

4.

GUIDANCE NOTES

4.1

Should the packer not set at the first attempt the operation should be re-attempted. If more than 10 left hand wraps are put into the control hoses by continued attempts to set the packer then the wraps should be unwound before they become a tangled mess and get caught up and damaged when rotating the string. The only way of removing the left hand wraps is to break out the string at the joint below the flowhead and unravel the wraps. The other commonly promoted idea for unravelling the wraps, namely working in slack, picking up the reel unit and spinning the unit anti-clockwise does not work and only wastes time. On occasion, packers have required as many as 40 turns before being successfully set. However when a packer requires a large number of turns before setting there is usually some problem with the mechanism, this can make it difficult to unseat.

4.2

The retrievable packers used for well testing purposes should have an automatic safety mode ie picking up returns the packer to the safety position. Note The current Baker Hurricane Packer for use in 9-5/8" casing does not have an automatic safety mode. This has not caused serious problems, but has required the use of left hand torque to reset the packer in safety mode .

4.3

If any doubt exits that the packer and TCP guns may be set off depth it is always possible to make a further depth correlation run.

Section 2090 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2100 PRESSURE TESTING FLOWHEAD & SURFACE LINES 0 01/10/92

PRESSURE TESTING FLOWHEAD & SURFACE LINES

1.

SAFETY

1.1

Ensure that the equipment to be tested is rated to the proposed test pressure.

1.2

All in situ pressure testing of the flowhead and surface lines should be undertaken with the fluted hanger landed and prior to setting the packer. All rams and BOP's should be left open during pressure testing.

1.3

Use water as the pressure testing medium and as far as possible ensure there is no air trapped in the equipment under test.

1.4

Always increase pressure slowly in steps to the final pressure.

1.5

The rig floor and all areas exposed to high pressure must be roped off. A P/A announcement detailing the areas where High Pressure Testing will be taking place must be made before the start of the operation. Note BPPD HSEQ Policy allows for a competent person to approach and visually inspect an item under test so long as the equipment has been subject to the particular pressure for 5 minutes, a state of equilibrium has been achieved and the test medium is water. In the case of gas pressure testing, the pressure must be reduced by 10% before the equipment is approached and inspected.

1.6

Ensure that there are no boats below the burner to be used.

1.7

If during flushing and pressure testing there are any unexpected pressure build ups, bleed pressure off and check line up of the valves Use the cement unit relief valve to prevent any accidental over pressuring of equipment.

1.8

Section 2100 Page1

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2100 PRESSURE TESTING FLOWHEAD & SURFACE LINES 0 01/10/92

2.

PREPARATION

2.1

Pressure test the flowhead on the deck to include the following tests: -

Body test. Master valve from below. Flow, kill and swab valves from well stream side. Swab Cap from below. Master valve from above.

All pressure tests are to _____ psi for 10 minutes. Each test must be recorded on a chart recorder and the chart marked with details of each test at the end of that test. All pressure tests must be witnessed by a BP representative. 2.2

Pressure test the Choke manifold on the deck to include the following tests : -

Body test. Front valves closed against upstream pressure. Back valves closed against upstream pressure. Back valves closed against downstream pressure.

All pressure tests are to _____ psi for 10 minutes. Each test must be recorded on a chart recorder and the chart marked with details of each test at the end of that test. All pressure tests must be witnessed by a BP representative. 2.3

Pressure test the Non Return Valve (NRV) on the deck to include the following tests : - Body test. - NRV closed against upstream pressure. All pressure tests are to _____ psi for 10 minutes. Each test must be recorded on a chart recorder and the chart marked with details of each test at the end of that test. All pressure tests must be witnessed by a BP representative. After the above pressure testing the NRV should be made up to the flowhead if this has not already been done.

2.4

Pressure tests that have not been performed on the deck must be carried out in situ.

2.5

Check the example pressure testing procedure against the P&ID drawings. Recheck the procedure on site against the physical equipment.

Section 2100 Page2

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2100 PRESSURE TESTING FLOWHEAD & SURFACE LINES 0 01/10/92

2.6

Rig up a chart recorder to the data header.

2.7

Check that the pressure sensor upstream of the heat exchanger has been rigged up.

Section 2100 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3.

2100 PRESSURE TESTING FLOWHEAD & SURFACE LINES 0 01/10/92

OPERATING PROCEDURE Pressure testing the Flowhead and Choke Manifold.

3.1

Check that the valves are aligned as follows: -

Lubricator valve shut. Master valve open. Kill valve open. Flow valve open. Swab valve shut. Choke manifold front valves open Choke manifold back valves open

3.2

Open lines to both flare booms, by-passing heaters, separator and surge/gauge tank.

3.3

Flush lines to burners. (If pressure builds up, stop pumping bleed off and investigate)

3.4

With the fluted hanger landed and the rams open, close the heater by-pass valve, and heater inlet valve. Pressure test against the heater inlet and by-pass valves to 300 psi for 5 minutes. Increase pressure to _____ psi. Close the Choke back valves bleed off pressure via the bubble hose to 500 psi. Observe the pressures upstream and downstream of the choke using the DAS for 10 minutes.

3.5

On successful completion of the previous test equalise across and open the back chokes. Bleed off all pressure via the bubble hose. Open the heater by-pass. Close the front chokes. Pressure test to _____ psi for 10 minutes. Monitor pressure at the cement unit.

3.6

On successful completion of the previous test and while still holding pressure: Close the Flow and Kill valves. Bleed off pressure at the choke manifold and cement unit to 500 psi. Monitor pressure at the choke manifold and cement unit for 10 minutes.

3.7

On successful completion of the previous test and while still holding pressure: Close the Master valve. Open the Flow and Kill valves and bleed off pressure at the choke manifold to 500 psi. Monitor pressure for 10 minutes at the choke manifold.

Section 2100 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3.8.

2100 PRESSURE TESTING FLOWHEAD & SURFACE LINES 0 01/10/92

On successful completion of the previous test, pressure up to equalise across the Master valve and open same. Bleed off all pressure. END OF PRESSURE TESTING

3.9

Confirm that the Emergency Shut Down ( ESD ) controls at each ESD station are functioning correctly by : a) b) c) d) e)

3.10

check all lines are open to the flare pump through at a slow rate - say 1 bbl/min when flow comes out at the flare boom - initiate ESD stop pumping at cement unit when pressure reaches 500 psi repeat b) - d) above for each ESD control point

Make tannoy announcement that "HIGH PRESSURE TESTING IS NOW COMPLETE".

Section 2100 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2100 PRESSURE TESTING FLOWHEAD & SURFACE LINES 0 01/10/92

4.

GUIDANCE NOTES

4.1

Always check the operating procedure against the P&ID drawings and the physical equipment at the well site. The aim of the in situ pressure testing of the flowhead and choke manifold is to test all the newly made connections and to retest immediately before use, those valves whose function is critical to the well test. It is not necessary to in situ test every valve from every side if the valve has recently been pressure tested on the deck. For example, this procedure does not pressure test the master valve from above. This is because the lubricator valve would be used for any pressure testing related to wireline work. Should the lubricator valve develop a leak from above then the master valve would be pressure tested from above at this time.

4.2

Where sand filters are installed upstream of the choke it may be necessary to install an additional valve to isolate the sand filters during pressuring up for perforating. When this safety valve is fitted the most efficient time to in situ pressure test it, is between step 3.5 and step 3.6. 3.5.1

On successful completion of the previous test and while maintaining pressure: Close the safety valve. Bleed off pressure at the choke manifold to 500 psi. Pressure test to _____ psi for 10 minutes.

4.3

On some rigs it may be possible to rig up and pressure test the choke manifold before installing the flowhead. In such cases the pressure test between the choke manifold and the heater inlet may be deleted (Step 3.4)

4.4

Valve spindles tend to be the most likely place for small leaks and it is worthwhile checking the spindles for leaks even though the chart may indicate a good pressure test.

4.5

Depending on the sequence of operations it may be more efficient to install and pressure test additional equipment, eg Coiled Tubing/Wireline BOP's, at the time of pressure testing the flowhead.

Section 2100 Page6

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.6

2100 PRESSURE TESTING FLOWHEAD & SURFACE LINES 0 01/10/92

Step 3.4 has two purposes : - to pressure test the connections between the choke manifold and the heater that were not already tested as part of the surface equipment pressure testing sequence. - to pressure test the choke back valves from the direction they will see pressure during a choke change. By monitoring the pressure upstream of the choke manifold and between the choke manifold and heater, it is possible to tell the location of any leak. No leakage to the atmosphere is acceptable. No leakage past the back chokes is acceptable. A leak of up to 100 psi in ten minutes past either of the heater valves is considered acceptable since these valves are primarily for flow diversion. Note Step 3.4 may have already been carried out as part of the Surface Equipment Pressure testing procedure. In this case step 3.4 may be deleted provided that none of the connections down stream of the choke were broken and remade during rig up of the flowhead.

4.7

Step 3.5 is to confirm the integrity of the lines two and from the flow head and to confirm that the front choke valves are sealing. No leakage to the atmosphere is acceptable. No leakage past the front chokes is acceptable.

4.8

Step 3.6 is to confirm the integrity of the Flow valve and Kill valve/NRV combination from the well stream side. No leakage is acceptable.

4.9

Step 3.7 is to confirm the integrity of the Master valve against the well stream.

Section 2100 Page7

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2110 PRESSURE TESTING SURFACE EQUIPMENT 0 01/10/92

PRESSURE TESTING SURFACE EQUIPMENT

1.

SAFETY

1.1

Check that the work permit held by the Well Test Supervisor fully covers the scope of the operation.

1.2

Ensure that the equipment to be tested is rated to the proposed test pressure.

1.3

Use water as the pressure testing medium and as far as possible ensure there is no air trapped in the equipment under test.

1.4

Always increase pressure slowly in steps to the final pressure.

1.5

Ensure that all areas exposed to high pressure are roped off. A P/A announcement detailing the areas where High Pressure Testing will be taking place must be made before the start of the operation. Note BPPD HSEQ Policy allows for a competent person to approach and visually inspect an item under test so long as the equipment has been subject to the particular pressure for 5 minutes, a state of equilibrium has been achieved and the test medium is water.

1.6

Ensure that the standby boat or rescue craft is in position/on alert whenever personnel are working over the side of the rig. This includes any work on the flare booms.

1.7

Prior to pressure testing the PE must walk the lines to check that all the equipment and lines are made up according to the P&ID diagram and that all lines to be pressure tested are chained down.

1.8

Before flushing through the burners, check that the standby boat/ rescue craft have moved clear.

1.9

During flushing and pressure testing, if there are any unexpected pressure build ups, bleed pressure off via the cement unit & check the line up of all valves.

1.10

All the surface equipment pressure tests must be for a minimum of 10 minutes and must be recorded on a chart recorder. Details of each test must be marked up on the chart at the time of the test. All pressure tests must be witnessed by a BP representative.

1.11

Use the cement unit adjustable relief valve to prevent accidental over pressuring of the equipment.

Section 2110 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2110 PRESSURE TESTING SURFACE EQUIPMENT 0 01/10/92

2.

PREPARATION

2.1

Rig up a chicksan line from the choke manifold to tie into the cement pump. (This normally means tying into the rig manifold)

2.2

Check the example pressure testing procedure against the P&ID drawings. Recheck the procedure on site against the physical equipment.

2.3

Walk the lines to check that they are made up according to the P&ID diagram and that all lines are chained down.

Section 2110 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3.

2110 PRESSURE TESTING SURFACE EQUIPMENT 0 01/10/92

OPERATING PROCEDURE Pressure testing the Surface Equipment.

Refer to the attached schematic of the surface equipment layout, figure 1. 3.1

Open lines to both flare booms ensuring that: -

3.2

Surge tank is isolated from the pipe work network. All lines are chained down. Both oil and gas diverter valves are open. Heater inlet valve is open Heater choke is open Heater outlet valve is open Heater by-pass valve is closed Separator inlet valve is open Separator gas outlet valve is open Separator oil outlet valve is open Separator water outlet valve is open Separator relief valve is closed Separator by-pass valves are closed Oil manifold surge tank diverter line valve open Surge tank inlet valves closed Oil manifold transfer pump line valve closed Burner head caps removed.

Before flushing lines & vessels ensure there are no boats underneath the burners. Flush all surface lines and equipment with sea water to both burner booms. Check water comes out of both oil burners and both gas lines, check that the separator is full of water. If necessary close the separator oil and water outlets for a short time to completely fill the separator. Check lines and equipment for leaks. Stop pumping immediately if there is any pressure build up. Bleed pressure off via the cement unit, then check position of valves.

3.3

By-pass the heater and separator as follows: HEATER

- close inlet valve - close outlet valve - open by-pass valve

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2110 PRESSURE TESTING SURFACE EQUIPMENT 0 01/10/92

SEPARATOR

- close inlet valve - close gas outlet valve - close oil outlet valve - close water outlet valve - open oil line by-pass valve - open gas line by-pass valve

3.4

With the standby boat on station fit burner plugs/caps to the starboard burner and set cement unit relief valve to 1300 psi.

3.5

Close the gas line diverter valves and the port oil line diverter valve. Pressure the test starboard flare line to 1,000 psi for 10 minutes.

3.6

On successful completion of the previous test, bleed off pressure via the cement unit. With the standby boat on station remove burner plugs/caps from the starboard burner and install burner plugs/caps in the port burner. Open the port oil line diverter valve Close the starboard oil line diverter valve Close the oil manifold surge tank diverter line valve. Open the surge tank inlet valve. Pressure test the port flare lines to 1,000 psi for 10 minutes.

3.7

On successful completion of the previous test, bleed off pressure via the cement unit and remove burner plugs/caps. Open oil line diverter valves and flush through to confirm that the oil lines are open. The standby boat can now be released.

3.8

Line up the separator as follows: -

close oil and gas line by-pass valves open inlet valve all outlet valves closed

Pressure test separator body, separator by-pass line valves and upstream lines to 1,100 psi for 10 minutes. 3.9

On successful completion of the previous test, bleed off pressure via the cement unit. Close Separator inlet valve Open heater inlet valve Open heater outlet valve Close heater by-pass valve Pressure test separator inlet valve, heater body and downstream coil to 1,100 psi for 10 minutes.

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2110 PRESSURE TESTING SURFACE EQUIPMENT 0 01/10/92

3.10

On successful completion of the previous test, bleed off pressure via the cement unit. Install blank plug in the heater choke Open heater outlet valve psi. Set cement unit relief valve to psi for 10 minutes. Pressure test upstream heater coil and upstream lines to

3.11

On successful completion of the previous test and while still holding pressure. Close choke manifold back valves Bleed off pressure at the cement unit to 500 psi. Monitor pressure at the cement unit for 10 minutes.

3.12

On successful completion of the previous test, bleed off all pressure. Remove blank plug from heater choke Open heater by-pass valve Close heater inlet valve Close choke manifold back valves psi. Set cement unit relief valve to psi for 10 minutes. Pressure test choke manifold body and back valves to

3.13

Bleed off pressure at the cement unit. END OF PRESSURE TESTING

3.14

Make tannoy announcement that "HIGH PRESSURE TESTING IS NOW COMPLETE".

Section 2110 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2110 PRESSURE TESTING SURFACE EQUIPMENT 0 01/10/92

4.

GUIDANCE NOTES

4.1

Always check the operating procedure and the test pressures against the P&ID drawings and the physical equipment at the well site. The aims of the surface equipment pressure testing are to: -

Confirm that the equipment is not leaking. Confirm that the equipment is fit for the pressure duty it may be subjected to during the well test Confirm that flow can be diverted through the system as required.

Note No external leaks in the surface equipment however small are tolerable. 4.2

High pressure pilots should be set to 90% of the pressure test value.

4.3

The separator and lines downstream of the separator should be pressure tested to create an operating envelope of at least 0 - 1000 psi. To do this it is necessary to pressure test the separator to 1100 psi to allow the high pressure trip to be set at 1000 psi. On high flow rate wells it may be necessary to pressure test the separator to a value closer to its rated working pressure (1440 psi).

4.4

Where possible the lines to the heater choke should be rated and pressure tested to allow full WHCIP at the heater choke.

4.5

Where sand filters are installed upstream of the choke it is often necessary to install an additional valve to isolate the sand filters during pressuring up for perforating. When this safety valve is fitted it should be pressure tested in situ as part of the flowhead pressure testing procedure.

4.6

Depending on the rig up, it may not be possible to carry out steps 3.11 and 3.12 when pressure testing the surface equipment. These tests should then be carried out as part of the flow head pressure testing program.

Section 2110 Page6

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2110 PRESSURE TESTING SURFACE EQUIPMENT 0 01/10/92

4.7

It is possible to pressure test both burner heads simultaneously, remove the burner plugs and pressure test both diverter valves simultaneously. However if both diverter valves are tested simultaneously it is not possible to identify the which diverter valve is leaking. If a diverter valve and burner head are pressure tested simultaneously, it is possible to visually check all lines and the burner head for leaks. If the source of the leak can not be found, then the leak must be at the oil diverter valve. (Note the gas by-pass valve can be closed to eliminate the gas diverter valves as the source of the leak)

4.8

Choke changes require isolation from both the upstream and down stream flow. Therefore pressure testing of the choke manifold must include a pressure test on the Choke manifold back valves from the down stream side.

4.9

If there is a non-return valve in the kill line, ensure that trapped pressure is bled off on both sides after completing individual pressure tests.

Section 2110 Page7

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2120 SUBSEA TEST TREE DISCONNECT 0 01/10/92

SUBSEA TREE DISCONNECT

1.

SAFETY

1.1

Hydraulic unlatching can take place in any conditions though the risk of the control lines being damaged increases with rig heave. Mechanical unlatching is the backup unlatch mechanism if the hydraulic unlatch fails. Mechanical unlatching with a rig heave in excess of 5-6 ft is likely to result in injury to the floor crew.

1.2

The decision to unlatch the tree in heavy weather should be taken earlier rather than later to ensure that the back up unlatch option is still available. Maximum roll and heave during well testing operations are normally given in the Rig Operating Manual. During a well test the PE/BP Rep/OIM should regularly review the present and forecast weather conditions and their impact on present/forecast operations.

1.3

The choice of unlatch procedure will depend on the time available. Do not start the 'Standard Unlatch' unless there is time available to complete the operation.

1.3

When unlatching ensure that no personnel are on riding belts in the derrick.

1.4

A subsea test tree operator must be available on the rig floor at all times.

2.

PREPARATION

2.1

The subsea test tree (SSTT) and operating console must be available for immediate use at all times.

2.2

Discuss the unlatch options with the BP Rep/Toolpusher/OIM/SSTT operator before the test starts. This will ensure that they are familiar with the unlatch operation and options should it become necessary to unlatch.

Section 2120 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3.

2120 SUBSEA TEST TREE DISCONNECT 0 01/10/92

OPERATING PROCEDURE STANDARD DISCONNECT If it is necessary to close in the well and disconnect at the sea bed and time will permit

3.1

Bleed off annular pressure to close the tester valve.

3.2

Bleed off pressure above the tester valve. Close the choke manifold and monitor tubing pressure to ensure tester valve is closed and sealing.

3.3

Cycle the circulating valve to one cycle short of opening.

3.4

Check that there is still time available to complete reverse circulating the string contents.

3.5

Cycle the circulating valve to the circulating position.

3.6

Apply 200 psi to the annulus and confirm that the WHP has increased.

3.7

Reverse circulate the string contents with kill weight mud to the surge tank using the 'Drillers Method' (ie maintain a small back pressure on the annulus). Ensure annulus pressure does not exceed 400 psi.

3.8

When mud returns are seen at the choke manifold. Stop pumping. Close the choke manifold. If the rig line up permits, circulate a further string volume of mud/brine via the degasser.

3.9

Close the circulating valve.

3.10

Apply 300 psi to the tubing to enable the subsea test tree to be pressure tested from below.

3.11

Close the subsea test tree. Bleed down pressure in the landing string to zero. Observe for pressure build up.

3.12

Slack off any overpull on the tubing, and unlatch the subsea test tree. Pick up the landing string until the latch mechanism is clear of the riser connector. String weight will immediately indicate a successful disconnect.

3.13

Rig down the flowhead and POOH the landing string.

3.14

Unlatch LMRP as required after closing the blind rams above the subsea test tree valve assembly.

3.

NB: Valve Assembly remaining in the BOP is " long. OPERATING PROCEDURE QUICK DISCONNECT

Section 2120 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2120 SUBSEA TEST TREE DISCONNECT 0 01/10/92

If it is unclear that there is sufficient time to carry out the 'Standard Disconnect' 3.1

Bleed off annulus pressure to close the down hole tester valve.

3.2

Bleed off sufficient tubing pressure to confirm that the tester valve is sealing.

3.3

Ensure that the tubing pressure at the depth of the subsea test tree is greater than riser hydrostatic.

3.4

Close the subsea test tree.

3.5

Bleed down pressure in the landing string to zero and observe for pressure build up.

3.6

Open the kill valve and lubricate riser fluid into the landing string taking care not to pump through the subsea test tree.

3.7

Slack off any overpull on the tubing.

3.8

Unlatch the subsea test tree and pick up the landing string until the latch mechanism is clear of the riser connector.

Section 2120 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3.

2120 SUBSEA TEST TREE DISCONNECT 0 01/10/92

OPERATING PROCEDURE EMERGENCY DISCONNECT If it becomes necessary to immediately disconnect when the well is flowing or at any stage during the disconnect procedure:

3.1

Close the subsea test tree.

3.2

Bleed down pressure in the landing string to zero.

3.3

Bleed off annulus pressure to close the down hole tester valve.

3.4

Slack off any overpull on the tubing.

3.5

Unlatch the subsea test tree and pick up the landing string until the latch mechanism is clear of the riser connector.

Section 2120 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2120 SUBSEA TEST TREE DISCONNECT 0 01/10/92

4.

GUIDANCE NOTES

4.1

The Standard disconnect procedure takes about two hours. The 'Standard Disconnect' proves that both the tester valve and SSTT are closed and sealing and gives the added safety of kill weight fluid above the tester valve. The 'Standard Disconnect' should not be attempted unless it is reasonably certain that the operation can be completed. There is a short period (until about 10 bbls of mud/brine has been reversed into the tubing) at the start of reverse circulating when an emergency disconnect could lead to complications. This is because an emergency disconnect immediately after opening the circulating valve could allow hydrocarbons to leak back into the annulus. These hydrocarbons would then migrate to surface, resulting in the tester valve opening and the well being live under the BOP's. For this reason the circulating valve must not be opened unless there is reasonable certainty that reverse circulation can be completed.

4.2

The 'Quick Disconnect' should take about 15 minutes and should be used when it is not clear if sufficient time will be available to complete the 'Standard Disconnect'. This method proves that both the tester valve and the SSTT are closed and sealing. When considering the 'Quick Disconnect' it is important to ensure that the tubing pressure at the SSTT is greater than the riser hydrostatic. If the tubing pressure at the SSTT is less than the riser hydrostatic the SSTT valves will unseat and allow riser fluid and any debris to flow through the SSTT and into the tubing. This may prevent the SSTT from sealing. In addition the failed status of the SSTT would not be known. In wells where WHP is expected to be low or the water depth is high, the SSTT should be specified with a pump through pressure higher than riser hydrostatic. If this has not been done, the disconnect must be started early enough to allow the 'Standard Disconnect' procedure to be followed.

4.3

The emergency disconnect should take between two and five minutes. With this method only the status of the SSTT is known provided the tubing pressure is greater than riser hydrostatic.

Section 2120 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2120 SUBSEA TEST TREE DISCONNECT 0 01/10/92

4.4

It is not a recommended procedure to bleed off all tubing pressure above the tester valve and lubricate in kill weight mud/brine. This is because through out the operation the tubing pressure at the SSTT would be less than riser hydrostatic. Therefore if an emergency disconnect occurred the hydrostatic head of the riser fluid would unseat the SSTT valves and it would be possible for the SSTT valves to become jammed open with debris.

4.5

If it is necessary to mechanically unlatch: -

Slack off weight. Apply right hand torque with the rig tongs to shear the shear pins. Rotate clockwise 8 turns (Expro tree) or 12 turns (Schlumberger tree) using the rig tongs. Pick up straight with the elevators until latch is clear of the riser connector. Close blind rams.

4.6

The time spent unlatched can be used as part of a pressure build up on the reservoir provided the tester valve is the first valve closed and it is not re-opened.

4.7

With an Expro SSTT, if the hydraulic unlatch fails and the heave has increased to the point where mechanical unlatching is no longer possible the only remaining method of unlatching is to close the shear rams. With the Schlumberger SSTT closing the shear rams is not always an option because the latch mechanism sits opposite the shear rams and is too solid for the cutting capability of the rams. Closing the shear rams is a last resort.

4.8

The tubing pressure applied to enable positive testing of the SSTT (steps 3.10 & 3.11) should be adjusted to suit the type of circulating valve fitted. It is not necessary to test the SSTT to its full working pressure (this was done when the string was run) only to confirm that the SSTT has closed and that there is no debris in the valve.

Section 2120 Page6

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2130 SUBSEA TEST TREE RELATCH 0 01/10/92

SUBSEA TEST TREE RELATCH

1.

SAFETY Standard drilling practice covers all safety aspects of the relatch operation.

Section 2130 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2130 SUBSEA TEST TREE RELATCH 0 01/10/92

2.

PREPARATION

2.1

Inspect latch and ensure 'O' ring seals in latch are OK. Function test the latch mechanism on the back up SSTT.

2.2

Flush the chemical injection and control hoses and pressure test to working pressure for 30 minutes.

2.3

Check the length of any components in the landing string that have been changed out.

2.4

Update the landing string running order.

Section 2130 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2130 SUBSEA TEST TREE RELATCH 0 01/10/92

3.

OPERATING PROCEDURE

3.1

Re-land the LMRP and test accordingly.

3.1

Run the landing string as per the running tally. Strap the hose bundle to the tubing with adhesive tape and steel banding. The landing string will fill with the riser fluid as it is run.

3.2

Install the Lubricator valve. Pressure test the lubricator valve open and close control hoses to their operating pressures for 5 minutes and observe for leaks. psi for 10 minutes. Bleed off the

3.3

Pressure test the Lubricator valve from above to pressure at the cement unit.

3.4

Continue running the landing string as per the running tally.

3.5

Pick up the long bails. Pick up the flowhead with single joint and coflexips attached and make up to the landing string. When making up this connection ensure that minimum weight is set down and that the first few turns are made with a chain tong. Watch the painted line on the flowhead to ensure no connections are backed off.

3.6

Engage compensator. Run in hole and latch on to the subsea test tree stub. Check the stick up is at least 4.5m at mid heave and mid tide level.

3.7

Apply pressure on the Unlatch line to free the latch fingers. Sit down, and allow 30 seconds for the subsea test tree to relatch. Rotate clockwise 1/4 turn until torque indicates that the latch is fully engaged in the latch receptacle. Bleed off unlatch pressure, and put 500 psi on the Ball Open line to locate the piston, and complete relatching.

3.8

Confirm latching by applying 5,000 lbs overpull.

3.9

Make up the surface lines and pressure test flow head.

3.10

Pump down and pressure up the landing string to equalise across the subsea test tree, (perform as a LOT until the pressure is seen to by-pass the valve).

3.11

psi. Close the subsea tree Open the subsea test tree. Pressure up the test string to valve and bleed pressure off above to 500 psi and monitor for pressure build up for ten minutes.

Section 2130 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2130 SUBSEA TEST TREE RELATCH 0 01/10/92

3.12

Equalise across and open the subsea test tree.

3.13

Close the lubricator valve. Bleed off pressure above the lubricator valve to 500 psi and monitor for 10 minutes.

3.14

Equalise across and open the lubricator valve.

Section 2130 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

2130 SUBSEA TEST TREE RELATCH 0 01/10/92

4.

GUIDANCE NOTES

4.1

The operating procedure assumes that the landing string was retrieved to surface following disconnect. Some times it is not necessary to recover the landing string following disconnect, (eg. if it was not necessary to disconnect the riser) In this case the relatch procedure starts with step 3.6, and steps 3.9,3.14 and 3.15 are unnecessary.

Section 2130 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3010 PERFORATING WITH CASING GUNS 0 01/10/92

PERFORATING WITH CASING GUNS

1.

SAFETY

1.1

Prior to rigging up the casing guns hold a safety meeting on the rig floor to discuss the operation. The safety meeting should include, the BP REP, OIM, Toolpusher, Driller, Logging Engineer, PE, rig crew and test crew. The following points should be noted at the safety meeting: a

All assembly/disassembly of the guns is to be carried out under the supervision of the Logging Engineer.

b

All non-essential personnel must keep clear of the gun assembly area, the rig floor and BOP/spider deck until the guns are below sea level. Final assembly and arming of guns must only be carried out on the rig floor. Under no circumstances should the guns be armed on the pipe deck or other area, before being lifted to the rig floor.

c

All welding operations must cease and all Hot Work permits be withdrawn for the duration of the perforating operations.

d

Radio silence must be observed from when the guns are removed from their store and must be maintained until the guns are 70m below the sea bed. Only when an approved 'radio safe' perforating system is being used can radio silence procedures be relaxed. Examples of approved 'radio safe' perforating systems are the Schlumberger 'Slapper Activated Firing Equipment' (SAFE) and Atlas 'Exploding Bridge Wire' (EBW).

Note. For the purpose of these procedures Radio Silence is deemed to include the following actions and checks: i

All radio equipment on the rig (with the exception of the emergency stand-by-receiver) shall be switched off prior to removing the detonator from the explosives store and remain so until the guns are 70m below the sea bed, or the detonator is returned to the explosives store, or the detonator is consumed in the perforating operation. All hand portable radio equipment must be recalled to the radio-room and only re-issued when perforating operations are complete.

Section 3010 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

ii

3010 PERFORATING WITH CASING GUNS 0 01/10/92

Check that the stand-by boat and any other vessels in the vicinity of the rig have moved outside the 500m zone and remain there for the duration of the operation. All vessels within one kilometre must silence all MF/HF transmissions. Should it be necessary for any shipping to remain within 500m of the rig they must observe radio/radar silence.

iii Check on Helicopter movements. Prior arrangement should be made to ensure as far as possible that no aircraft encroach within 500m of the rig unless the aircraft in question is not using its transmitting system. Helicopters shall not be allowed to land on the rig while armed explosives are above the sea bed or at surface. iv

Switch off all cathodic protection equipment for the duration of perforating operations.

v

Check that the logging engineer has switched off the unit's generator and that the safety key has been removed from the unit whilst armed guns are at surface or above the sea bed.

vi

Check that a rig to casing monitor is being employed throughout the operation and that its reading does not exceed 0.25 volts.

vii Check that the logging unit is earthed to the rig. 1.2

The following points must be considered by the supervisor of the operation: a

Do not arm guns during electrical storms.

b

Strap the guns before they are armed.

Section 3010 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3010 PERFORATING WITH CASING GUNS 0 01/10/92

2.

PREPARATION

2.1

Establish radio silence before removing the detonator from the gun store. Shaped charges and primer cord may be removed from the explosives store without radio silence.

2.2

Strap the guns and CCL to top shot.

2.3

Check each gun for insulation and continuity.

2.4

All switches must be checked electrically before being installed in the guns.

2.5

Top, bottom shots and blank zones should be marked with paint/tape on the outside of the carrier.

2.6

An electrical continuity check should be made on each gun as they are connected together.

Section 3010 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3.

3010 PERFORATING WITH CASING GUNS 0 01/10/92

OPERATING PROCEDURE This procedure assumes that casing guns are being used to perforate a well which has kill weight fluid in the well bore.

3.1

Hold safety meeting on the rig floor.

3.2

Rig up electric line and casing guns excluding detonator.

3.3

Establish radio silence; arm guns. Ensure that all non essential personnel stay clear of the rig floor and BOP/Spider deck from when the guns are being armed until they are below the sea bed.

3.4

RIH and depth correlate using the CBL/VDL/GR/CCL log as a reference. Radio silence may be relaxed once the guns are 70 m below the sea bed.

3.5

RIH to the perforating depth of

mbrt.

Inform the Driller, BP Rep and OIM prior to perforating. Ensure trip tank is lined up to the well. to mbrt. Perforate the interval 3.6

POOH slowly taking care not to swab hydrocarbons into the well. Observe the well for gains or losses.

3.7

On recovery of the guns radio silence must be re-imposed from when the guns are 70m below the sea bed until the guns are know to be completely safe.

3.8

If a second run is required rig up a second gun string and repeat steps 3.3 to 3.7 and to mbrt. perforate the interval

Section 3010 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3010 PERFORATING WITH CASING GUNS 0 01/10/92

4.

GUIDANCE NOTES

4.1

All logging companies have their own highly detailed procedures covering the rig up and arming of perforating equipment. The preceding operating procedure is intended to provide guidance to the overall sequence of the operation. It does not in any way replace/over ride the logging company perforating procedures.

4.2

If more than one run is required always perforate the deepest interval first.

4.3

After perforating POOH slowly for the first 100m. There after the gun may be retrieved at a faster speed provided this will not swab the well in. Provided the Cable tension - Slow pulling weight < Mud Hydrostatic - Reservoir Pressure Gun cross-sectional area 2

Then no hydrocarbons will be swabbed into the well

Section 3010 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3020 HYDRAULIC FIRING OF TCPS 0 01/10/92

HYDRAULIC FIRING OF TCPS

1.

SAFETY

1.1

This operation effectively marks the transition from the preparatory phase to the operational phase of well testing. Work permits must be resigned or new permits issued prior to starting the operational phase.

1.2

Confirm that the flaring telex has been sent.

1.3

Ensure that there are no boats below the burners, and that the standby boat has been alerted.

1.4

Make a tannoy announcement and clear the rig floor of all non essential personnel prior to pressuring up to initiate firing. Rope off the high pressure areas.

1.5

Detonation of the charges (especially on shallow wells) can cause the string to jump. While waiting for the charges to fire, keep non essential personnel clear of the rig floor.

1.6

If the guns fail to fire after the programmed delay time, wait a further 30 minutes before allowing any personnel to mechanically operate the flowhead valves.

1.7

Perforating can be carried out during hours of darkness.

Section 3020 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3020 HYDRAULIC FIRING OF TCPS 0 01/10/92

2.

PREPARATION

2.1

Calculate the WHP required to initiate firing of the TCP guns.

2.2

Set packer, and set any reference tools or any tools that have been shear pinned, eg PORT/ARTS/LPR-N

2.3

Ensure that the Data acquisition system is working and recording on all channels. Set up the WHP to record at 30 second intervals with a 10psi delta P trigger.

2.4

Walk the surface lines checking that from the choke manifold, the well is lined up direct to the burners, by-passing all vessels.

Section 3020 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3020 HYDRAULIC FIRING OF TCPS 0 01/10/92

3.

OPERATING PROCEDURE

3.1

Ensure the valves are lined up as follows : -

Tester valve Closed. Sub sea test tree open. Lubricator valve open Master valve open. Swab valve shut. Flow valve open. Choke manifold Front valves shut. Choke manifold back valves open. Test equipment lined up to the burners. Kill valve open.

3.2

Close the pipe rams around the SSTT slick joint and apply 2000 psi annulus pressure to open the Tester valve. Check the Data acquisition system for a small kick in well head pressure indicating that the tester valve opened.

3.3

Using the cement pump increase tubing wellhead pressure to psi. Bleed off pressure to

3.4

Observe surface pressure for indication of guns firing. (Sudden drop in WHP followed by a steady increase). Expected time delay is _____ minutes

3.5

Allow WHP to increase with the well shut in at surface for 5 minutes.

3.6

Bleed off annulus pressure to close the tester valve.

3.7

Leave the well shut in downhole for a 55 minute PBU.

3.8

If the guns failed to fire, refer to Guidance notes.

Section 3020 Page3

psi. Hold for 1 minute.

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3020 HYDRAULIC FIRING OF TCPS 0 01/10/92

4.

GUIDANCE NOTES

4.1

TCP's Fail to Fire If, after the programmed delay period, there is no evidence of the guns firing, wait for a further 30 minutes, then repeat the firing process but pressure up to 1000 psi above the previous firing pressure. When repressurising, plot the bbls pumped versus WHP as in a leak off test. This should identify if the guns fired but the reservoir was tight or if the guns failed to fire. If again after the programmed delay period there is no evidence of the guns firing, wait for a further 30 minutes, then prepare to use the back up firing system, if available/installed.

4.2

Mechanical Firing of TCP's Bleed off annulus pressure to close the tester valve. Bleed off sufficient wellhead pressure to confirm that the tester valve has closed. Shut the lubricator valve and bleed off all pressure. Flush the flowhead and surface lines if necessary. With the swab valve closed, open the 1/2" needle valve on the swab cap and bleed off any pressure. remove the swab cap. Rig up the slick line BOPS, close the rams. Open the swab valve and pressure test the BOP's. Rig up the lubricator, slickline tool string and detonating bar, pressure test the slick line psi for ten minutes. lubricator to 300 psi for five minutes and With the tool in the tool catcher (if present), bleed off pressure to equalise above the lubricator valve. Open the lubricator valve. (The pressure below the lubricator valve can change during the rig up due thermal expansion of the cushion. If the correct lubricator equalisation pressure is not known, either: -

Bleed off control line pressure to the lubricator valve this makes the valve pump through from above. Increase tubing pressure slowly using the cement pump until the valve equalised, (conduct as a leak off test).

Section 3020 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

-

3020 HYDRAULIC FIRING OF TCPS 0 01/10/92

Inject slowly through the chemical injection line to determine the pressure below the lubricator valve.)

Close the kill valve. RIH at maximum speed until 100m above the tester valve. Slowly RIH and tag the tester valve. Reference the slick line depth counter. Pull the tool string back up into the tubing. Apply annulus pressure to open the tester valve. Apply/bleed off pressure to achieve

psi underbalance.

Ensure that the WHP is at least 100 psi. This will ensure that the data gathering system can detect if the guns fire. Ensure the data gathering system is sampling every 30 seconds with a 10 psi delta P trigger on the WHP. Inform Driller and BP Rep prior to perforating. RIH and tag ported glass disc sub. Pick up 20m. RIH allowing the toolstring to accelerate to its maximum velocity. Break through the glass disc sub and continue to RIH until the toolstring lands out and jars down on the firing head. (Breaking through the glass disc and RIH to the firing head must be done in one continuous movement so that the drop bar reaches the firing head before any debris from the disc sub) Jar down until guns fire. Allow WHP to stabilise and POOH slickline. If guns do not fire, POOH slickline, and prepare to POOH gun string. Consult TCP Base manager, Duty SPE and DS prior to POOH. The precise gun recovery procedure depends on the preceding operations and must be checked and agreed prior to POOH.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.3

3020 HYDRAULIC FIRING OF TCPS 0 01/10/92

Perforating on Drill pipe When perforating with TCP's on drill pipe the primary mode of initiating firing will be by applying pressure down the annulus or tubing. The back up initiating system is a drop bar run on wireline. The main differences between perforating on a test string and perforation on drill pipe are : -

Perforating on drill pipe is normally done overbalance. A packer is not required The flowhead is replaced by a kelly cock and circulating head.

Ensure the electronic data gathering system is sampling tubing/annulus pressure at 30 sec intervals with a 50 psi delta P trigger. Clear the rig floor of all non essential personnel prior to perforating. Close the middle pipe rams and apply 500 psi annulus/tubing pressure. Check electronic data gathering system is working. Increase annulus/tubing pressure to firing pressure of off pressure to 100-200 psi.

psi. Hold for 1 minute. Bleed

Observe surface pressure for indication of guns firing. If there is no evidence of the guns firing after the delay period, wait a further 30 minutes then repeat the process but pressure up to 3000 psi to activate the guns. If again there is no indication of the guns firing after the delay period, wait a further 30 minutes then prepare to use the back up firing system. After the guns have fired, note trip tank level and monitor well for losses. Circulate in an LCM pill as necessary. POOH and rig down guns. All non-essential personnel must stay clear of the gun disassembly area, the rig floor and BOP deck while the guns are being rigged down.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.4

3020 HYDRAULIC FIRING OF TCPS 0 01/10/92

Delay Systems All Hydraulically fired TCP systems can be fitted with a delay system to enable the firing pressure to be bled off and the well under balanced. Delay systems come in two main types: - Slow burning fuses. - Hydraulic metering/restrictor system. Slow burning fuses are available in units with delay times of 5 or 7 minutes, depending on the supplier. To achieve a longer delay the units are stacked. The duration of the delay is independent of bottom hole temperature and pressure. Hydraulic metering/restrictor systems are available with a wide range of delay times. The actual delay period will depend on the bottom hole pressure and temperature. If the bottom hole temperature was higher than prognosed or if a problem delayed bleeding off of the TCP firing pressure, then the delay period could be shortened by up to 25%. In practice 10 - 15 minutes is the ideal delay period. This allows time to bleed off firing pressure without rushing and four or five minutes of spare time should any minor problems occur, eg Choke valve is pressure locked closed. On shallow wells where the bleed off volume is small it can be practical to use a 7 minute time delay. However if any problems occur there is very little time to rectify the problem and overbalance perforating can result.

4.5

Steps 3.6 and 3.7 can be omitted if the well is being flowed straight to clean up without an initial shut in period.

4.6

If the failed firing head is wireline retrievable, then the failed head should be recovered, inspected and the cause of the misfire identified prior to any further attempts to perforate the well.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3030 THROUGH TUBING PERFORATING 0 01/10/92

THROUGH TUBING PERFORATING

1.

SAFETY

1.1

Prior to rigging up the pressure equipment hold a safety meeting on the rig floor to discuss the operation. The safety meeting should include, but not be limited to; the BP REP, OIM, Toolpusher, Driller, Logging Engineer, PE, rig crew and test crew. The following points should be noted at the safety meeting: a

All assembly/disassembly of the guns is to be carried out under the supervision of the Logging Engineer.

b

All non-essential personnel must keep clear of the gun assembly area, the rig floor and BOP/spider deck until the guns are below sea level.

c

All welding operations must cease and all Hot Work permits be withdrawn for the duration of the perforating operations.

d

Radio silence must be observed from when the guns are removed from their store and must be maintained until the guns are 70m below the sea bed. Only when an approved 'Radio Safe' perforating system is being used can radio silence procedures be relaxed. Examples of approved 'Radio Safe' perforating systems are the Schlumberger 'Slapper Activated Firing Equipment' (SAFE) and the Atlas Wireline 'Exploding Bridge Wire' (EBW).

Note. For the purpose of these procedures Radio Silence is deemed to include the following actions and checks: i

All radio equipment on the rig (with the exception of the emergency stand-by-receiver) shall be switched off prior to removing the detonator from the explosives store and remain so until the guns are 70m below the sea bed, or the detonator is returned to the explosives store, or the detonator is consumed in the perforating operation. All hand portable radio equipment must be recalled to the radio-room and only re-issued when perforating operations are complete.

ii

Check that the stand-by boat and any other vessels in the vicinity of the rig have moved outside the 500m zone and remain there for the duration of the operation. All vessels within one kilometre must silence all MF/HF transmissions. Should it be necessary for any shipping to remain within 500m of the rig they must observe radio/radar silence.

Section 3030 Page 1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3030 THROUGH TUBING PERFORATING 0 01/10/92

iii Check on Helicopter movements. Prior arrangements should be made to ensure as far as possible that no aircraft encroach within 500m of the rig unless the aircraft in question is not using its transmitting system. Helicopters shall not be allowed to land on the rig while armed explosives are above the sea bed or at surface. iv

Switch off all cathodic protection equipment for the duration of perforating operations.

v

Check that the logging engineer has switched off the unit's generator and that the safety key has been removed from the unit whilst armed guns are at surface or above the sea bed.

vi

Check that a rig to casing monitor is being employed throughout the operation and that its reading does not exceed 0.25 volts.

vii Check that the logging unit is earthed to the rig. 1.2

The following points must be considered by the supervisor of the operation: a

When applying pressure with guns in the lubricator the average rate of pressure increase must be less than 2000 psi/minute.

b

The test rod has some form of attachment to prevent it being blown out of the BOP's during pressure testing.

c

Do not arm guns during electrical storms..

d

Strap the guns before they are armed.

e

The tool weight is sufficient to against both present and expected pressures and that if the well is to be perforated under flowing conditions check that the tool weight is sufficient to prevent lifting of the tool string.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3030 THROUGH TUBING PERFORATING 0 01/10/92

2.

PREPARATION

2.1

Where ever possible pressure test the BOP's on the deck prior to starting perforating operations.

2.2

Establish radio silence before removing the detonator from the gun store. Shaped charges and primer cord may be removed from the explosives store without radio silence.

2.3

Strap the guns, weight bar and CCL to top shot.

2.4

Prepare a sufficient volume of 50/50 water glycol for pressure testing the lubricator and equalisation.

2.5

Check for NRV's between the cement pump and flowhead. Presence of NRV's between the cement pump and flowhead will require modification of the pressure bleed off procedures and a larger volume of water/glycol.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3.

3030 THROUGH TUBING PERFORATING 0 01/10/92

OPERATING PROCEDURE This procedure assumes that through tubing guns are being used to add perforations to a well that has been already perforated with TCP's/Casing Guns.

3.1

Hold safety meeting

3.2

With the Tester valve, Lubricator valve and Kill valve closed, bleed off the pressure above the Lubricator valve at the choke manifold to the flare. Open the kill valve and flush the lines with 50/50 water glycol. Close the kill valve and choke manifold and monitor for pressure build up for 5 minutes. Re-open the choke.

3.3

With the swab valve closed, open the 1/2" needle valve on the swab cap and bleed off any pressure from below. Remove the swab cap.

3.4

Rig up the electric line BOP's. Cycle the rams closed then open to confirm the correct connection of the hoses. (Normally the BOP's will have already been pressure tested on the deck prior to being picked up)

3.5

Open the swab valve. Rig up the electric line lubricator and insert the toolstring (Weight bar only. No charges) into the flowhead/lubricator. Open the kill valve. Flush through the flowhead/lubricator with 50/50 Glycol/Water mixture and then pressure test to 300 psi for psi for 10 minutes. Bleed off the pressure at the choke 5 minutes and a test pressure of manifold.

3.6

Break out the electric line lubricator above the BOP's and rig up the guns (re-confirm radio silence before arming the guns), run the guns into the flowhead and stab the lubricator back on.

3.7

With the tool in the toolcatcher, zero control pressure on the grease tube and the choke open, slowly flush through the flowhead with 50/50 water/glycol until fluid is seen at the grease tube. Stop pumping and close the choke. Smoothly pressure up to equalisation pressure of ____ psi. When applying pressure ensure that the rate of pressure increase is less than 2000 psi/minute. Observe the remade quick union for signs of leaks.

3.8

Open the Lubricator valve and monitor the tubing pressure, close the kill valve. With the toolstring still in the toolcatcher. Pressure up on the annulus to open the tester valve, monitor tubing pressure, when stable with the toolstring.

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3030 THROUGH TUBING PERFORATING 0 01/10/92

If the toolstring hangs up in the toolcatcher. Close the lubricator valve and bleed off pressure above. Free the toolstring and equalise as detailed in step 3.7 but with the toolstring 1ft below the toolcatcher. 3.9

and depth correlate using the CBL/VDL/GR/CCL log as a reference. Inform the Driller, BP Rep and OIM prior to perforating. Ensure the electronic data gathering system is sampling tubing pressure at 10 sec intervals with a 10 psi delta P trigger. Perforate the interval

-

mbrt.

3.10

POOH, do not close the tester valve until the toolstring is at least 500m above it.

3.11

When recovering the guns radio silence must be re-imposed from when the guns are 70m below the sea bed until the guns are know to be completely safe.

3.12

With the tool in the toolcatcher and the tester valve closed, close the Lubricator valve. Bleed off the pressure at the choke manifold. Open the kill valve and flush the flowhead/lubricator with 50/50 water glycol. Close the choke manifold, monitor for pressure build up for 5 minutes. Re-open the choke.

3.13

Break out the lubricator, rig down the toolstring, if a second run is required rig up a mbrt. second gun string and repeat steps 3.7 to 3.12 and perforate the interval

3.14

Rig down the electric line lubricator and BOP's. Install the swab cap with the 1/2" needle valve open. Open the kill valve and flush through the flowhead from the cement unit with a 50/50 water/glycol mix.

3.15

Close the 1/2" needle valve and pressure test the swab cap to 300 psi for 5 minutes and a psi for 10 minutes. Bleed off the pressure at the choke manifold to test pressure of equalisation pressure across the Lubricator valve. Close the swab valve and bleed off the pressure above using the 1/2" needle valve, close the needle valve.

3.16

Open the Lubricator valve. Close the kill valve and bleed off pressure at the cement pump. The well status should now be: Well shut in at tester valve and choke manifold.

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3030 THROUGH TUBING PERFORATING 0 01/10/92

4.

GUIDANCE NOTES

4.1

The Master valve may be used in place of either the Lubricator or tester valves.

4.2

Test pressures should be calculated as follows For 10,000 psi equipment Test Pressure = Max Anticipated WHP + 1000 psi For 15,000 psi equipment Test Pressure = Max Anticipated WHP + 10%

4.3

If BOP's have not been pressure tested on the deck before being rigged up then the operating procedure should be modified to: Flush through the flowhead from the cement unit. Install and close rams around the test rod. pressure test the rams with 50/50 glycol/water mixture to 300 psi for 5 minutes and required test pressure for ten minutes.

4.4

It is possible to pressure up to equalise across the lubricator valve either by: i

Knowing the pressure below the lubricator valve either from a previous stabilised WHP or from pumping down the chemical injection line.

ii

Bleeding off control line pressure from the lubricator close line and slowly increasing WHP from the cement pump. When operated in this manner the lubricator valve is pump through when pressure is equalised across it. Monitor volume pumped versus pressure increase to identify when the lubricator valve is equalised.

4.5

If the required equalisation pressure is 0 psi then pressure up to 1000 psi and bleed off before opening the lubricator valve.

4.6

On some occasions it may be necessary to break out the lubricator below the BOP's. In this case greater care must be taken to ensure that the remade connection is not leaking.

Section 3030 Page 6

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

CUSHION PLACEMENT DIESEL/BASE OIL/WATER

1.

SAFETY

1.1

A significant hazard that must be avoided when circulating in a diesel/base oil cushion is the auto ignition of the diesel/base oil. To prevent auto ignition, air and diesel/base oil under pressure must not come into contact. To ensure the operation is conducted safely the following steps must be taken: a

Ensure that the lines between the pit with diesel/base oil and the flowhead are free of air before starting to pump the diesel. A simple method of ensuring no air is present in the system is to pump 5 - 10 bbls of mud/brine from another pit then switch to the diesel pit.

b

If it is not possible to remove all air from the system then the diesel must be preceded by an inert spacer fluid such as sea water to ensure that diesel and air do not come into contact during pumping operations.

c

When the cushion is in place and pumping operations are complete Diesel/Base oil must not be the fluid left in place in the surface lines, kill line or flowhead. An effective method of achieving this is to pump the volume of the surface lines plus 3 bbls of sea water as the tail of the cushion.

The Cushion placement procedures assume that mud pumps are used for the operation. Use of cement pumps is covered in Guidance note 4.1. 1.2

The tubing pressure required to cycle the Schlumberger or Baker circulating valves around to the circulating position can be higher than the TCP firing pressure. To ensure that pressure is not communicated to the guns when cycling the circulating valves the following steps must be taken: a

Where a retrievable packer is used the circulating valve is to be cycled to the circulating position before the packer is set and with the rams open. This will ensure that firing pressure can not be communicated to the guns.

b

Where a permanent packer is used the circulating valve is to be cycled to the circulating position before the PORT/ARTS has been set and the sump by-pass closed.

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4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

1.3

The Halliburton Omni Valve is operated by annulus pressure and the packer must be set before attempting to cycle the valve to the circulating position. The annulus pressure required to cycle the Omni valve to the circulating position should be at least 1000 psi below the TCP firing pressure. However, if the packer were not set, the repeated cycling to within 1000 psi of the firing pressure could cause premature gun detonation.

1.4

Contamination of the mud system with the cushion fluid should be avoided.

1.5

Should pressure increase suddenly and unexpectedly during any pumping operation, the pumps must be shut down and the cause investigated.

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4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

2.

PREPARATION

2.1

Calculate the string volume from surface to the depth of the circulating valve. Check the volume of the surface lines from the mud pit to the flowhead.

2.2

Clean out and prepare a mud pit with the required volume of diesel/Base oil.

2.3

Check the rated output of the mud pumps and the response time to increase from the circulating rate to the circulating valve closure rate.

2.4

Discuss the operation with the BP Rep, Driller, and Downhole Tool hand and agreed how to line up the pipe work on the rig floor.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

3.

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

OPERATING PROCEDURE CUSHION PLACEMENT - DIESEL/BASE OIL - SCHLUMBERGER/BAKER

3.1

Ensure that the valves are lined up as follows: -

Tester valve shut. Sub sea test tree (SSTT) open. Lubricator valve open. Master valve open. Swab valve shut. Flow valve open. Choke manifold front valves shut. Choke manifold back valves open. Test equipment lined up to burners.

3.2

Check chart recorder on rig floor is monitoring well head pressure and that the surface data acquisition system is sampling at an appropriate frequency

3.3

With the rams open and the trip tank lined up to the annulus, open the flowhead kill valve psi. Bleed and pressure up the tubing against the tester valve from the cement unit to off the pressure at the choke manifold. Close the choke manifold.

3.4

Repeat step 3.3 until the circulating valve has been cycled to the open position. The circulating valve will open during the bleed off of tubing pressure. This is detected by: -

A small increase in WHP at the choke manifold when the circulating valve opens due to the imbalance between tubing and annulus fluid SG's. The WHP will appear to stop falling as fluid is bled off. The trip tank level will fall.

3.5

Close the choke manifold, close the kill valve, bleed off pressure at the cement unit and note the change in trip tank level.

3.6

Close the pipe rams on the sub sea tree slick joint and line up the mud pumps to reverse circulate. Apply 200 psi to the annulus with the mud pumps and check that WHP has increased. Zero the pump stroke counter and open the choke manifold. Reverse circulate the tubing contents to the gauge/surge tank using the mud pumps. Ensure annulus pressure does not exceed 400 psi.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

3.7

Stop pumping when mud returns are seen at the choke manifold. Close the choke manifold. Note volume pumped. Open the kill valve, line up to circulate the cushion with the mud pumps. Open the rams.

3.8

Using the mud pumps, pump: BBLS of mud BBLS of diesel/base oil BBLS of seawater Note -

Pump rate must not exceed BBL/MIN while circulating the cushion. (Too high a pump rate will close the circulating valve) String volume to circulating valve is BBLS. Take returns to the trip tank to double check the calculated number of pump strokes required.

3.9 When pumping the last barrel of seawater increase the pumping rate to BBL/MIN to close psi to ensure full closure of the the circulating valve. Increase tubing pressure to circulating valve. 3.10

Bleed off pressure at the choke manifold and close the kill valve.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

4.

GUIDANCE NOTES SCHLUMBERGER/BAKER

4.1

These procedures for diesel/water/base oil cushion placement assume the use of the mud pumps. Using the cement pumps would offer the following advantages: -

They are better maintained. They give greater control over the operation. Pump volumes can be measured with greater accuracy. They are manned throughout the operation.

Against this it can be more difficult to purge the air from all the high points in cement system and prevent any air ingress into the cement pump. The suitability of using the cement pumps for circulating diesel/base oil will depend on the design of the cement pump and how the pump has been installed on the rig. Any decision to use the cement pumps must be made by the BP Rep/Tool pusher/OIM/Cementer taking full regard of any Unit or Cementing Company policy and procedures relating to the pumping of auto/compression ignitable fluids. 4.2

The above operating procedure assumes seawater in the tubing and mud in the annulus. Were the tubing and annulus fluids the same then it would not be necessary to reverse circulate the tubing contents, steps 3.6 & 3.7 would be replaced with the following: 3.6

Close the pipe rams on the sub sea test tree slick joint.

3.7

Open the kill valve, line up to circulate in the cushion with the mud pumps. Open the rams.

The use of brine in the annulus instead of mud would not affect the operating procedure. 4.3

The Schlumberger and Baker circulating valves (MIRV/MRCV) are opened by cycling the tubing pressure to 2000 psi above the absolute annulus pressure at the depth of the circulating valve. Both the Schlumberger and Baker tools are closed by increasing the circulating rate to 2 bbls/min/port. If TCP's are being run on the test string, then cycle the circulating valve to the open position with the rams open and spot the cushion prior to setting the retrievable packer. These two measures will ensure that the tester valve can not be accidentally opened and the guns prematurely fired when cycling tubing pressure to open the circulating valve.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

If a permanent packer and TCP's are being used then:

4.4

a

The PORT/ARTS must not be operated until circulation operations are complete.

b

The rams must not be closed when cycling the circulating valve to the open position. (With the rams and drilling choke closed the annulus becomes a closed system and tubing ballooning could increase annulus pressure sufficiently to set the PORT/ARTS)

c

Alternatively a wireline set firing head may be used in the TCP guns to remove the risk of accidental firing while circulating.

When reverse circulating out the test string 400 - 500 psi is generally a good maximum value to use. Unless something has malfunctioned, the choke has plugged, or the driller is pumping too fast, then 200 - 300 psi is all that is needed for reverse circulating. The real constraint on the maximum annulus pressure when reverse circulating out the test string is the lowest operating pressure of any of the tools or guns in the string minus their safety factor. Typical safety factors are: 1000 psi for TCP guns The lower of 50% of applied annulus operating pressure or 500 psi for an ARTS/PORT. Should the mud be massively out of balance and it not be possible to complete reverse circulation without operating some of the tools then the operation should be suspended at this point and a forward programme discussed with the Down Hole Tool supervisor, TCP engineer, BP Rep, PE and Duty SPE.

4.5

The pumping schedule and fluid volumes required are best illustrated by an example. For a string volume from surface to the circulating valve of 100 bbls with the surface lines from the mud pits to the rig floor having a volume of 5 bbls. The pumping schedule would be: 8bbls mud - Surface line volume(5 bbls) + 3bbls to ensure lines are cleared of any air prior to pumping any diesel/base oil

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4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

94 bbls Diesel/ Base oil

-

Volume surface to circulating valve - 3bbls under-displacement and 3 bbls sea water tail.

8 bbls Sea water

-

3 bbls tail + Surface line volume (5 bbls) to ensure flowhead and surface lines are cleared of diesel completion of circulating operations.

before

If the string has not been reverse circulated prior to pumping the cushion, the string volume from surface to the circulating valve will not be know with the same accuracy. In this case the volume of under-displacement should be increased from 3bbls to 5bbls. 4.6

To avoid contamination of the mud it is generally advisable to under-displace the cushion fluid by a minimum of 3 bbls. Cushion fluids entering the annulus will slightly lighten the fluid column, might affect the mud properties, and diesel if used, would contaminate the mud with environmentally unacceptable toxins. In special circumstances, eg. where lift performance of the well is marginal, the volume of under-displacement may be reduced to 1 bbl if:

4.7

i

The calculated string volume and the string volume measured by reverse circulation agree to within 1 bbl.

ii

The cushion is environmentally compatible with the mud system, eg base oil cushion in oil base mud, seawater cushion in water base mud.

Cushion Placement: Water If a water cushion is required then the easiest method of placement is to fill the test string with water as the string is being run. Should it be necessary to circulate in a water cushion, then the procedure is identical to circulating in a Diesel/Base oil cushion with the exception that the pumping schedule (step 3.8) would consist of only sea water and the required volume would be the string volume to the circulating valve - 3 bbls. ie the mud spacer and the sea water tail would not be needed. The cement pump may be used instead of the mud pumps for placing a water cushion.

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3.

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

OPERATING PROCEDURE CUSHION PLACEMENT - DIESEL/BASE OIL - HALLIBURTON

3.1

Ensure that the valves are lined up as follows: -

3.2

Tester valve shut. Sub sea test tree (SSTT) open. Lubricator valve open. Master valve open. Swab valve shut. Flow valve open. Choke manifold front valves shut. Choke manifold back valves open. Test equipment lined up to burners.

Check chart recorder on rig floor is monitoring annulus pressure and that the surface data acquisition system is sampling at an appropriate frequency

3.3 Close the pipe rams on the sub sea test tree slick joint and apply off pressure via the driller's choke.

psi to the annulus. Bleed

3.4 Repeat step 3.3 until the Omni valve has been cycled to the circulating position. The Omni valve will open during the bleed off of annulus pressure. This is detected by: - A small increase in WHP at the choke manifold when the Omni valve opens due to the residual pressure applied to the annulus. - When starting to pressuring up for the next cycle, tubing and annulus pressures will increase in unison. 3.5

Bleed off annulus pressure and open the rams. Open the kill valve.

3.6 Using the mud pumps, pump: BBLS of mud BBLS of diesel/base oil BBLS of seawater Note - Pump rate should not exceed 6 bbl/min while circulating the cushion. (Too high a pump rate can make it difficult to maintain a steady annulus pressure and lead to premature cycling of the Omni).

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

-

3.7

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

String volume to circulating valve is BBLS. Take returns to the trip tank to double check the calculated number of pump strokes required.

Close the kill valve. Close the pipe rams, apply and then bleed off to cycle the Omni valve to the well test position.

Section 4010 Page10

psi to the annulus

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

4.

GUIDANCE NOTES HALLIBURTON

4.1

These procedures for diesel/water/base oil cushion placement assume the use of the mud pumps. Using the cement pumps would offer the following advantages: -

They are better maintained. They give greater control over the operation. Pump volumes can be measured with greater accuracy. They are manned throughout the operation.

Against this it can be more difficult to purge the air from all the high points in cement system and prevent any air ingress into the cement pump. The suitability of using the cement pumps for circulating diesel/base oil will depend on the design of the cement pump and how the pump has been installed on the rig. Any decision to use the cement pumps must be made by the BP Rep/Tool pusher/OIM/Cementer taking full regard of any Unit or Cementing Company policy and procedures relating to the pumping of auto/compression ignitable fluids. 4.2

The above operating procedure assumes completion fluid in both the tubing and annulus. Were the tubing fluid different to the annulus fluid, then it would be necessary to reverse circulate out the tubing contents before pumping the cushion. Step 3.5 would be replaced with the following: 3.5.1

Close the pipe rams on the sub sea test tree slick joint and line up the mud pumps to reverse circulate. Apply 200 psi to the annulus with the mud pumps and check that WHP has increased. Zero the pump stroke counter and open the choke manifold. Reverse circulate the tubing contents to the burners using the mud pumps. Ensure annulus pressure does not exceed 400 psi.

3.5.2

Stop pumping when mud returns are seen at the choke manifold. Close the choke manifold. Note volume pumped. Open the kill valve, line up to circulate the cushion with the mud pumps. Open the pipe rams.

The use of brine in the annulus instead of mud would not affect the operating procedure.

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.3

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

The Halliburton Omni valve is operated by cycling a ratchet. This is achieved by applying annulus pressure (1200 - 2000 psi) which compresses the nitrogen allowing the operating sleeve to move up the ratchet. When the applied annulus pressure is bled off, the nitrogen expands pushing the operating sleeve back down the ratchet. The Omni is designed such that when the circulating ports are opened, the string below the Omni is isolated by means of a ball valve. The packer must be set before operating the Omni valve. The design of the Omni removes the possibility of accidentally detonating the TCP guns provided the packer has been set.

4.4

When reverse circulating out the test string, 400 psi is generally a good maximum value to use. Unless something has malfunctioned, the choke has plugged, or the driller is pumping too fast, then 200 -300 psi is all that is needed for reverse circulating. The real constraint on the maximum annulus pressure when reverse circulating out the test string is maintaining a steady annulus pressure below the Omni valve operating pressure.

4.5

The pumping schedule and fluid volumes required are best illustrated by an example. For a string volume from surface to the circulating valve of 100 bbls with the surface lines from the mud pits to the rig floor having a volume of 5 bbls. The pumping schedule would be: 8bbls mud - Surface line volume(5 bbls) + 3bbls to ensure lines are cleared of any air prior to pumping any diesel/base oil 92 bbls Diesel/ Base oil

-

Volume surface to circulating valve - 5bbls under-displacement and 3 bbls sea water tail.

8 bbls Sea water - 3 bbls tail + Surface line volume (5 bbls) to ensure flowhead and surface lines are cleared of diesel before completion of circulating operations. If the string has been reverse circulated prior to pumping the cushion, the string volume from surface to the circulating valve will be know with greater accuracy. In this case the volume of under-displacement may be reduced from 5bbls to 3bbls.

Section 4010 Page12

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.6

4010 CUSHION PLACEMENT DIESEL/BASE OIL/WATER 0 01/10/92

The purpose of under displacement is to avoid contamination of the mud. It is generally advisable to under-displace the cushion fluid by between 3 and 5bbls depending on if the string has been reverse circulated first. The effect of cushion fluids entering the annulus will be to slightly lighten the fluid column, possibly effect the mud properties, and diesel if used, would contaminate the mud with environmentally unacceptable toxins. In special circumstances, eg. where lift performance of the well is marginal, the volume of under-displacement may be reduced to 1 bbl if:

4.7

i

The calculated string volume and the string volume measured by reverse circulation agree to within 1 bbl.

ii

The cushion is environmentally compatible with the mud system, eg base oil cushion in oil base mud, seawater cushion in water base mud.

Cushion Placement: Water If a water cushion is required then the easiest method of placement is to fill the test string with water as the string is being run. Should it be necessary to circulate in a water cushion, then the procedure is identical to circulating in a Diesel/Base oil cushion with the exception that the pumping schedule (step 3.6) would consist of only sea water and the required volume would be the string volume to the circulating valve - 5bbls. ie the mud spacer and the sea water tail would not be needed. The cement pump may be used instead of the mud pumps for placing a water cushion.

Section 4010 Page13

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4020 CUSHION PLACEMENT NITROGEN 0 01/10/92

CUSHION PLACEMENT - NITROGEN

1.

SAFETY

1.1

Nitrogen at high pressure is a far more dangerous fluid than water or oil because of the large amount of stored energy in the compressed nitrogen. To reduce the hazards associated with nitrogen: -

The length of the lines between the nitrogen unit and the flow head must be kept to a minimum.

-

The lines between the nitrogen unit and the flowhead must be pressure tested with water before any nitrogen is introduced into the system.

1.2

Ensure that the nitrogen to be used contains less than 1% oxygen. Use of off spec nitrogen could result in the compression ignition of hydrocarbons.

1.3

All pipe work must be securely chained to the deck.

1.4

When pumping nitrogen the high pressure pipe work must be roped off and all unnecessary personnel must stay clear of the rig floor, V-doors and the pipe deck.

1.5

Severe cold burns will result if contact is made with the liquid side of the nitrogen unit.

1.6

In the event of a catastrophic leak in the liquid nitrogen lines, breathing apparatus must be worn in order to close the lines from the nitrogen tank as N2 is an asphyxiant.

1.7

Wooden boards should be placed under the nitrogen unit to prevent liquid nitrogen dripping on to the deck. A water hose must be left running under the area where hoses transfer liquid nitrogen from the tanks to the vaporiser unit. (Serious cracking of deck plates and structural beams has resulted from liquid nitrogen leaks on mobile rigs)

1.8

The tubing pressure required to cycle the Schlumberger or Baker circulating valves around to the circulating position can be higher than the TCP firing pressure. To ensure that pressure is not communicated to the guns when cycling the Baker/Schlumberger circulating valves the following steps must be taken:

Section 4020 Page1

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4020 CUSHION PLACEMENT NITROGEN 0 01/10/92

a

Where a retrievable packer is used all cycling of the circulating valve and circulating operations should be completed before the packer is set and with the rams open.

b

Where a permanent packer is used all cycling of the circulating valve and circulating operations should be completed before the PORT/ARTS is referenced and the sump by-pass closed.

1.9

The Halliburton Omni Valve is operated by annulus pressure and the packer must be set before attempting to cycle the valve to the circulating position. The annulus pressure required to cycle the Omni valve to the circulating position should be 1000 psi below the TCP firing pressure. However, if the packer were not set the repeated cycling to within 1000 psi of the firing pressure could cause premature gun detonation.

1.10

Nitrogen must never be allowed to enter the annulus.

1.11

Never hammer up connections with the lines under pressure.

1.12

Never approach a gas filled line when under full test pressure, always bleed the line down by at least 10% first.

Section 4020 Page2

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4020 CUSHION PLACEMENT NITROGEN 0 01/10/92

2.

PREPARATION

2.1

Check that the circulating valve is suitable for circulating in a nitrogen cushion.

2.2

Calculate the string volume from surface to the depth of the circulating valve.

2.3

Discuss the operation with the BP Rep, Driller, and Downhole Tool hand and agreed how to line up the pipe work on the rig floor.

2.4

Discuss with the nitrogen unit operator: -

The volume of nitrogen required The cushion displacement rate The maximum operating pressure

2.5

Pressure test the lines from the nitrogen vaporiser unit to the flowhead with sea water to the maximum expected pumping pressure + 1000 psi for 10 minutes. Ensure that a check valve is fitted to the nitrogen vaporiser unit before filling the lines with sea water. (Water in the vaporiser will cause the cryogenic pump to seize and the pump can not be repaired offshore)

2.6

Check that a non return valve is fitted on the line to the flowhead as close to the flowhead as possible (see figure 1)

2.7

Notify the nitrogen technician 30 minutes before the nitrogen is required to initiate cool down of the unit.

2.8

Ensure the cement unit is isolated from the nitrogen line before any nitrogen is pumped.

Section 4020 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4020 CUSHION PLACEMENT NITROGEN 0 01/10/92

3.

OPERATING PROCEDURE

3.1

With the tubing contents reverse circulated and the circulating valve cycled to the circulating position. Ensure that the valves are lined up as follows: -

Kill valve open Tester valve shut. Sub sea test tree (SSTT) open. Lubricator valve open. Master valve open. Swab valve shut. Flow valve open. Choke manifold front valves shut. Choke manifold back valves open. Test equipment lined up to burners.

3.2

Check chart recorder on rig floor is monitoring well head pressure and that the surface data acquisition system is sampling at an appropriate frequency.

3.3

With the rams open and lined up to take returns via the trip tank, circulate 5bbls of mud to confirm everything is correctly aligned.

3.4

Pump N2 to displace the sea water out of the nitrogen lines to the flowhead. Close the valve at the end of the N2 line and with all personnel removed from the area, pressure test the N2 line with nitrogen to the maximum expected pumping pressure + 1000 psi for 10 minutes. Bleed off pressure via the N2 blow down choke and open N2 line test valve.

3.5

Start pumping nitrogen. Monitor the volume displaced by means of the trip tank returns. Monitor the nitrogen discharge temperature, (should be at least 60 F). If the nitrogen discharge temperature falls below 32 F, halt the operation and investigate the cause of the low discharge temperature. Note String volume to circulating valve is

bbls

bbls of returns. Shut down the nitrogen unit.

3.6

After

3.7

Close the pipe rams on the slick joint and apply circulating valve.

psi annulus pressure to close the

Section 4020 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4020 CUSHION PLACEMENT NITROGEN 0 01/10/92

3.8

Close the vaporiser isolation valve and depressurise N2 lines through the blow down choke.

3.9

Bleed off pressure at the choke manifold to

3.10

Rig down nitrogen lines and equipment.

psi and close the kill valve.

Section 4020 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4020 CUSHION PLACEMENT NITROGEN 0 01/10/92

4.

GUIDANCE NOTES

4.1

The above operating procedure assumes the tubing has already been reverse circulated to completion fluid following the reverse circulating procedure from the Diesel/Base Oil/Water cushion placement procedures.

4.2

The Schlumberger and Baker circulating valves are operated by cycling the tubing pressure to 2000 - 3000 psi above the absolute annulus pressure at the depth of the circulating valve. For Nitrogen operations, both the Schlumberger and Baker valves have a reverse circulating position and a circulating position. The reverse circulating ports are uni-directional (the ports are fitted with non return valves) and attempting to circulate causes the tool to cycle from the reversing position to the circulating position. The circulating ports are also uni-directional and attempting to reverse circulate will cycle the tool from the circulating position to the closed position. If TCP's are being run on the test string, then the cycling of the circulating valve to the open position must be done with the rams open. The spotting of the cushion must be done prior to setting the retrievable packer. These two measures will ensure that the tester valve can not be accidentally opened and the guns prematurely fired when cycling tubing pressure to open the circulating valve. If a permanent packer and TCP's are being used then:

4.3

a

The PORT/ARTS must not be operated until circulation operations are complete.

b

The rams must not be closed when cycling the circulating valve to the open position. (With the rams and drilling choke closed the annulus becomes a closed system and tubing ballooning could increase annulus pressure sufficient to set the PORT/ARTS)

c

Alternatively a wireline set firing head could be used in the TCP guns to remove the risk of accidental firing while circulating.

The Halliburton Omni valve is operated by applying and bleeding off annulus pressure (1200 - 2000 psi) to cycle a ratchet. The Omni has one set of ports which are used for both circulating and reverse circulating. To prevent excessive back flow of annular fluid into the string when pressuring up to close the ports, the ports must be fitted with flow restrictors.

Section 4020 Page6

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4020 CUSHION PLACEMENT NITROGEN 0 01/10/92

When running TCP guns and an Omni valve, the packer must be set before attempting to cycle the Omni to the circulating position. 4.4

When pumping a nitrogen cushion it is essential that nitrogen is not circulated into the annulus. The nitrogen cushion should be under displaced by 5bbls.

Section 4020 Page7

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4030 DROPPING TCP GUNS 0 01/10/92

DROPPING TCP GUNS

1.

SAFETY

1.1

Check that the work permits held by the Wire line Operator and Well test Supervisor fully cover the scope of the operation.

1.2

Rig up of the wireline/slickline lubricator and BOP's should not be attempted in rough weather or high winds.

1.3

Ensure that the lubricator and BOP's are rated to the proposed test pressure.

1.4

Use sea water as the pressure testing medium and as far as possible ensure there is no air trapped in the equipment under test.

1.5

Always increase pressure slowly in steps to the final pressure.

1.6

The rig floor and all areas exposed to high pressure must be roped off. A P/A announcement detailing the areas where High Pressure Testing will be taking place must be made before the start of the operation. Note BPPD HSEQ Policy allows for a competent person to approach and visually inspect an item under test so long as the equipment has been subject to the particular pressure for 5 minutes, a state of equilibrium has been achieved and the test medium is water.

1.7 1.8

If during flushing and pressure testing there are any unexpected pressure build ups, bleed pressure off and check line up of the valves Use the cement unit relief valve to prevent any accidental over pressuring of the lubricator and BOP's.

Section 4030 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4030 DROPPING TCP GUNS 0 01/10/92

2.

PREPARATION

2.1

Before running the test string drift the gauge carriers and down hole tools with the gun release tool. This should be done in addition to drifting all test tools, drill collars and tubulars with standard API drifts of the appropriate size. Note Any internally offset gauge carriers should be drifted with the complete gun release tool string.

2.2

Function test the gun release tool and disconnect sub before running the disconnect sub with the test string.

2.3

Where possible pressure test the BOP's on the deck prior to rigging up the slickline lubricator.

2.4

Check the dimensions of the tool string and the size and type of the fishing neck.

2.5

If possible carry out the gun drop rig up during a shut in period, but do not attempt to pressure test the slickline lubricator until the pressure build up is complete.

2.5

Check for NRV's between the cement pump and flowhead.

Section 4030 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4030 DROPPING TCP GUNS 0 01/10/92

3.

OPERATING PROCEDURE

3.1

With the tester valve, lubricator valve and kill valve closed, bleed off the pressure above the Lubricator valve at the choke manifold to the flare. Open the kill valve and flush the lines with sea water. Close the kill valve and choke manifold and monitor for pressure build up for 5 minutes. Re-open the choke.

3.2

With the swab valve closed, open the 1/2" needle valve on the swab cap and bleed off any pressure. Remove the swab cap.

3.3

Rig up the BOP's. Cycle the rams closed. (Normally the BOP's will have already been pressure tested on the deck prior to being picked up).

3.4

Open the swab valve. Rig up the slick line lubricator and insert the gun release tool string.

3.5

When the preceding pressure build up is complete. ie at

hrs

Pull the tool into the tool catcher. Flush through the flowhead with water until fluid is seen at the stuffing box. Stop pumping and establish a seal at the stuffing box. Pressure psi for 10 minutes. test to 300 psi for 5 minutes and 3.6

Bleed off to equalisation pressure and open the lubricator valve. Close the kill valve. Pressure up on the annulus to open the tester valve. Check that the tester valve is not in the lock open position. Monitor WHP, when stable RIH.

3.7

Take the running and pulling weight every 500m and again when 50m above the disconnect sub.

3.8

RIH until the gun release tool has passed through the disconnect sub at

3.9

Pick up slowly and take an overpull to confirm that the release tool is in the disconnect sub.

3.10

Jar up to drop off the guns. RIH past the mechanical disconnect to confirm the guns have m to confirm the perforated interval is clear. dropped. Continue to RIH to

3.12

POOH, when the tool string at least 200m above the tester valve, bleed off the annulus pressure to close the tester valve.

Section 4030 Page3

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4030 DROPPING TCP GUNS 0 01/10/92

3.13

With the tool in the lubricator close the Lubricator valve. Bleed off the pressure at the choke manifold. Open the kill valve and flush the lines with sea water. Close the choke manifold and monitor for pressure build up for 5 minutes.

3.14

Break out the lubricator, rig down the tool string.

3.15

If slickline operations are complete, rig down the wireline lubricator and BOP's. Install the swab cap with the 1/2" needle valve open. Open the kill valve and flush through the flowhead from the cement unit with sea water.

3.16

Close the 1/2" needle valve and pressure test the swab cap to 500 psi for 5 minutes and psi for 10 minutes. Bleed off the pressure at the cement unit, bleed off the pressure at the choke manifold to equalise across the Lubricator valve. Close the swab and kill valves and bleed off the pressure above the swab using the 1/2" needle valve, close the needle valve.

3.17

Open the Lubricator valve. Well status is: Well shut in at tester valve and choke manifold.

Section 4030 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4030 DROPPING TCP GUNS 0 01/10/92

4.

GUIDANCE NOTES

4.1

The pressure below the lubricator valve can change during a shut in period due to phase segregation and redistribution. If the correct lubricator equalisation pressure is not known, either :

4.2

-

Bleed off control line pressure to the lubricator valve this makes the valve pump through from above. Increase tubing pressure slowly using the cement pump until the valve equalised, (conduct as a leak off test).

-

Inject slowly through the chemical injection line to determine the pressure below the lubricator valve.

If the tester valve has a lock open facility it should be used for wire line work provided the lock open position can be reached with only 1 - 2 cycles of the tester valve. Excessive cycling of the tester valve (>2 cycles to reach lock open) should be avoided. The reasons for this are: -

The primary reason for running a lock open on the tester valve is to simplify the well kill. Wire line operations should take advantage of the benefit of a lock open facility, but not to the extent of affecting the primary function of the lock open. Excessive cycling of the tester valve may lead to premature failure.

-

It is possible for the surface record of the lock position to be out of sequence with the lock open ratchet mechanism. Thus the lock open should not be relied upon for wire line work.

-

The risk of losing annulus pressure during well testing is very low and the added security achieved by locking the valve open is small.

The absence of a lock open facility does not restrict the range of wireline operations that may be carried out. 4.3

Gun drop is best performed before the clean up flow period. This removes the possibility of any debris being produced into the string and clogging the disconnect sub.

Section 4030 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.4

4030 DROPPING TCP GUNS 0 01/10/92

Gun drop is normally performed after the initial flow and pressure build up. At this stage hydrocarbons have not been produced to surface and sea water can be used to flush the flowhead and for any pressure testing. If gun drop is being performed after hydrocarbons have been produced to surface use a 50/50 water glycol mixture for all flushing and pressure testing.

Section 4030 Page6

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4040 INITIAL FLOW AND CLEANUP 1 01/11/94

INITIAL FLOW AND CLEAN UP

1.

SAFETY

1.1

The production of first hydrocarbons to surface and the first hour of surface production must coincide with daylight hours for all exploration wells and appraisal wells on previously untested prospects. For appraisal and development wells, the initial flow of hydrocarbons may be permitted during the hours of darkness if the conditions laid out in section 1060, paragraph 5, have been satisfied. In multiple DSTs on the same well the second zone perforated may be brought on during hours of darkness following consultation with the DS and SPE.

1.2

Hold a safety meeting on the rig floor prior to opening the well. The following points are to be covered: a

Actions in the event of an emergency and location of Emergency Shut Down buttons

b

Actions to be taken in the event of H2S being detected.

c

All welding operations must cease and all hot work permits be withdrawn for the duration of the flow period.

d

All nonessential personnel must keep clear of the rig floor and well test area for the duration of the flow period.

e

No crane movements over any of the well test equipment or flow lines.

1.3

Select the burner to ensure that the flare is blown away from the rig.

1.4

Sometimes during clean-up slugging or wind conditions make it difficult to keep the flare lit and to burn all the produced gas. Uncombusted gas is a serious hazard to helicopters. In such a circumstance the rule is: If you can't burn the gas, you can't land the helicopter, unless the well is closed in.

1.5

Spillage of diesel or oil due to incomplete combustion is an unacceptable pollution hazard which could endanger the rig if a surface accumulation drifted under the rig and became ignited.

Section 4040 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

1.6

4040 INITIAL FLOW AND CLEANUP 1 01/11/94

Pressure surges can occur with a change in fluid passing through the choke. To safely control gas surge the following must be adopted: -

If WHFP exceeds 2000 psi bean back to a fixed choke size that will restrict the gas flowrate to less than 6 mmscf/d.

-

After first gas the choke size may be increased as required.

2.

PREPARATION

2.1

Prior to opening up the well the following must be checked:-

2.2

-

The separator is by-passed and the well is lined up to the burners. (oil wells may be flowed to the gauge/surge until the first half of the cushion has been produced)

-

The pilot to the relevant burner is lit, the water screen is in operation, and a well test operator is stationed near the burner.

-

The steam generator is fully fired up.

-

That the adjustable choke has been correctly zeroed.

-

That a suitably sized fixed choke (usually 20/64th) is installed on the fixed side of the choke.

-

The work permit has been re-endorsed for the testing phase of operations.

-

That the Radio Operator has notified the Coastguard that the rig is about to commence flaring and notified the standby boat and any helicopters of the intention to open up the well

-

All personnel involved in the test operation are at their respective stations.

Make a tannoy announcement to inform rig personnel that the well is about to be opened up.

Section 4040 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4040 INITIAL FLOW AND CLEANUP 1 01/11/94

3.

OPERATING PROCEDURE

3.1

Make a final check on the wind direction, that the helideck is clear and that there are no boats adjacent to the rig.

3.2

Pressure up the annulus to open the tester valve and allow the wellhead pressure to stabilise.

3.3

Check the position of the tester valve and cycle to a fail safe position, ie not locked open.

3.4

With the adjustable choke set on 16/64" choke, open the front valve on the choke manifold. Monitor the downstream choke pressure. This should be kept below 1000 psi. If the pressure rises quickly towards this figure then the well should be shut in and the problem investigated.

3.5

Bean up well in 4/64" stages as instructed by the Petroleum Engineer.

3.6

Take two samples of the cushion at the choke manifold.

3.7

Monitor annulus pressure and bleed off as required (annulus pressure will rise as the well heats up)

3.8

Monitor wellhead pressure. If WHP increases above 2000 psi switch to a fixed choke size that would restrict the gas flowrate through the choke to less than 6 mmscf/d.

3.9

When hydrocarbons reach the surface, monitor for H2S and CO2 at the choke manifold at 10 minute intervals until levels have stabilised, and at half hour intervals thereafter.

3.10

The well will be considered clean when:BS&W has been constant over 2 hours. The solids content is < 1%. The wellhead pressure is constant or declining as a log function of time.

3.11

When the well is cleaned up. Divert the well through a fixed choke.

3.12

Divert flow through the separator.

Section 4040 Page3

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4040 INITIAL FLOW AND CLEANUP 1 01/11/94

4.

GUIDANCE NOTES

4.1

Do not conduct the initial flow period with the tester valve in a locked open position. Always cycle the valve to a fail safe position.

4.2

Never use adjustable chokes that have the choke tip braised to the shaft. All choke tips must be integral or screwed and pinned to the shaft. A choke tip that comes off will slam into the choke seat resulting in a sudden increase in well head pressure.

4.3

On low rate wells it can be advantageous to switch to a fixed choke if the adjustable choke is plugging with debris. If a fixed choke is used for the clean up flow it could become damaged or partly plugged and must therefore be inspected or changed out for the main flow period.

4.4

For gas wells the flow must initially be directed to the burners. Only if the well does not appear to be flowing may the well be diverted to the surge tank for a short period of time to confirm if the well is dead.

4.5

For oil wells no more than half the cushion is to be flowed to the surge tank, the flow is then be diverted to the burners.

4.6

If the well is producing solids at least one string volume should be produced between choke changes.

4.7

During clean-up the cushion should not be back produced at more than 10,000 bbl/d.

4.8

During clean-up it is not necessary to maintain critical flow across a choke if so doing would compromise the complete removal of mud/brine from the casing. When the well is clean critical flow can be re-established by beaning down the choke as required.

4.9

The Data Acquisition Manual details the parameters that should be recorded and the recording frequency.

4.10

Clean up is most easily detected from looking back at the process trends (WHP, WHT, BS&W) and is easier to spot in hind sight than as it happens. Clean up is a function of both time and volume produced. On an average well a constant BS&W for two hours will represent 1 - 2 string volumes. On a low rate well two hours may represent less than half a string volume and it may be necessary to extend the clean up period until a complete string volume has been produced with constant BS&W. Typical process trends before and after clean up are shown in the Data Acquisition Manual Part 1, Section 1 Figure 2.

Section 4040 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4.11

4040 INITIAL FLOW AND CLEANUP 1 01/11/94

How to Bean up a Well. Bringing a well on and choosing how to bean up the choke relies very much on experience. The following discussion and flow chart (figure 1) can be useful in many circumstances. The objective when bringing a well on will usually be to back-produce the cushion as safely and rapidly as well conditions allow, with the following constraints on choke size: -

the need to maintain BHP above the threshold pressure for sand production. (estimated from core data or sonic response)

-

the need to maintain sufficient WHP to observe the well. (30 - 50 psi)

-

Sufficient flowrate to lift the cushion fluid in the tubing. (This is a function of the slip velocity of oil in water or gas in diesel or water. For an oil well with 4-1/2" tubing the surface flowrate should be > 600 bbl/d. For a gas well with 4-1/2" tubing the surface flowrate should be > 1800 bbl/d flowrates for other tubing sizes can be calculated using Equation 2)

-

Be able to safely handle the gas surge pressure.

-

Maintain BHP above bubble point (If this is a well objective)

Predicting Bottom Hole and Surface Pressures On first opening up a well the pressure will fall firstly because of the drawdown applied to the formation to make it flow, and secondly because mud/brine is being displaced from the casing into the minor string and increasing the hydrostatic head. As oil/gas enters the minor sting the hydrostatic head will decrease and WHP will rise. Later as gas nears surface the rate of gas expansion becomes significant and the rate of increase in WHP will increase. To aid understanding of what is happening during the early stages of bringing a well on, it is helpful to construct a plot of Hydrostatic pressure versus cumulative production. Note Flow of Single Phase Incompressible fluid through a choke can be approximated by: Q = C**2 * (DP)**0.5 K

(1)

Section 4040 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4040 INITIAL FLOW AND CLEANUP 1 01/11/94

Where Q C DP K

= = = =

Surface flowrate, bbl/d Choke size in 64ths Pressure drop across the choke, psi Constant (4.82 for diesel, 5.87 for water)

A plot of hydrostatic head versus cumulative production enables estimation of BHFP if sand control or remaining above the Bubble point are important. The plot is also useful for predicting the future trend of the WHFP on the current choke setting, eg. the minimum the WHFP might fall to, or how much further the pressure may rise as the cushion is produced. Clean-up of Cushion and Drilling fluids At low flow rates the flow regime will be that of bubbles of the lighter phase rising through the continuous heavier phase. As the flowrate increases the light phase becomes continuous and the droplets of the heavy phase (water/brine/mud) fall back through the oil/gas. With bubble flow the bulk of the cushion will remain in place and the hydrostatic head will still be high. To remove the bulk of the cushion from the tubing/casing the well must be flowed at a rate sufficient to make oil/gas the continuous phase. To achieve the transition from bubble flow requires a surface flowrate such that the average tubing/casing velocity is greater than 0.7 times the light phase slip velocity. ie

Qsurf > Al * Vs * 1.4 * (D)**2

(2)

Where Qsurf = Surface flow rate, bbl/d Al = fraction of the flow area occupied by the lighter phase Use Al=0.7 Vs = The light phase slip velocity at 30% heavy phase hold up, ft/min D = The tubing/casing internal diameter, inches

Typical values of slip velocity, Vs, are: Oil in water 15(1 + 4cos(d)sin(d)) ft/min Gas in diesel or water 45(1 + 4cos(d)sin(d)) ft/min

(3) (4)

Section 4040 Page6

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4040 INITIAL FLOW AND CLEANUP 1 01/11/94

Where d

= The angle of deviation

To complete cushion/sump clean-up and remove the last droplets of water/mud/brine from the oil/gas requires much higher flowrates. In an oil well the downhole flowrate required to lift the last droplet of mud/brine/water can be approximated by: Q

= 1.4 * Al * Vhs * (D)**2

(5)

Where Q Al

= Downhole flowrate for total mud/brine/water removal, Res bbl/d = fraction of the flow area occupied by the lighter phase For deviation less than 7 degrees use Al=1.0 For deviation greater than 7 degrees use Al=0.9 Vhs = The heavy phase slip velocity For deviation less than 7 degrees use Vhs=40 ft/min For deviation greater than 7 degrees use Vhs=30(1+4sin(d)cos(d)) where d is the angle of deviation. D = The tubing/casing internal diameter, inches

In a gas well the downhole flowrate required to lift the last droplet of mud/brine/water can be approximated by: Qg

(6)

= P * Vtd * D**2 59.92 * T * Z

Where Qg P Vtd D T Z

= The flowrate required for droplet removal, mmscf/d = Well bore pressure at the point under consideration, psia = The droplet's terminal velocity, ft/sec = The tubing/casing ID, inches = The gas temperature, deg R = The gas super compressibility factor

and Vtd can be approximated by: Vtg = 16.08 * (SG - 0.0000463P)**0.25 (0.0031P)**0.5

(7)

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4040 INITIAL FLOW AND CLEANUP 1 01/11/94

Where SG P

= The specific gravity of the fluid in the droplet (water = 1) = The well bore pressure at the point under consideration, psia

The flow rate required for removal of mud/cushion from the tubing/casing in a gas well is highly sensitive to gas pressure. Ideally all the mud between the gauges and top perforation should be removed during clean-up. A plot of the flowrate required for mud removal versus estimated BHFP will help determine if this has been achieved. In general, unless the bottom set of perforations are the main point of influx then it is unlikely that all the mud will be removed from opposite all the perforations.

Gas Surge Pressure The effect of first gas at surface largely depends on if the WHP is high or low. At low WHP first gas will cause a rapid increase in WHP as the gas restricts the flow area available to the liquid phase. At high WHP first gas will cause a sudden increase in choke downstream pressure as the volume of gas that can pass through a choke at high pressure far exceeds the volume of diesel or water that previously passed through the choke. Flow through a choke is approximated by one of the following equations, depending on if the flow is single phase and incompressible, two phase and compressible, or single phase and compressible. Single Phase Incompressible flow through a choke Qc

= C**2(DP)*0.5/K

(8)

Two Phase Compressible flow through a choke Qo

= P * C**1.89 435 * (GOR/1000)**0.546

(9)

Section 4040 Page8

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4040 INITIAL FLOW AND CLEANUP 1 01/11/94

Single Phase Compressible flow through a choke Qg

(10)

= C**2.083 * P 12260(SG * T)

Where Qc = Cushion Surface flowrate, bbl/d Qo = Oil flowrate, bbl/d Qg = Gas Flowrate, mmscf/D C = Choke size in 64ths DP = Pressure drop across the choke, psi P = Pressure upstream of the choke, psia K = Constant (4.82 for diesel, 5.87 for water) GOR = Gas oil ratio at downstream conditions. SG = Gas Specific gravity (Air = 1.0) T = Upstream gas temperature, Deg R The following example gives an indication of the effect on WHP of the transition from flowing diesel to flowing oil and gas through the choke when the well has a low WHFP. Assume the well is back producing a diesel cushion on a 28/64th choke with a WHFP of 100 psi. This would give a surface flowrate of 1600 bbl/d (Eqn 8). If the flow of diesel through the choke were replaced by oil with a GOR of 1000 scf/stb and Bo of 1.6, then the flowrate through the choke would be reduced to 125 bbl/d (Eqn 9). The marked reduction in flowrate that results from the transition from diesel to oil and gas causes a rapid increase in WHFP. In this example, were the well to continue flowing at 1600 Rb/d the WHFP would to increase from 100 to 800 psi (Eqn 9). The following example gives an indication of the effect on downstream choke pressure of the transition from flowing diesel to flowing gas through the choke when the well has a high WHFP. Assume a well is back producing a diesel cushion on a 24/64th choke with a WHP of 3000 psi and a downstream choke pressure of 400 psi. The surface flowrate would be approx 6000 bbl/d. If the diesel cleaned up to dry gas, then the flow of gas through the choke would be approx 9.3 mmscf/d.

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4040 INITIAL FLOW AND CLEANUP 1 01/11/94

At down stream conditions (400 psi) 9.3 mmscf/d of gas occupies a volume equivalent to 45,000 bbl/d. The pressure down stream of the choke would rise within 1-2 seconds to over 2000 psi as the diesel accelerated and the gas downstream of the choke was re-compressed. Rupture of the low pressure lines (1440 psi Working pressure) and serious injury are likely results of an uncontrolled gas surge. Gas surge is reduced if the choke setting is kept small as this reduces the flowrate to which the diesel is accelerated.

To safely control gas surge the following must be adopted: -

If WHFP exceeds 2000 psi bean back to a fixed choke size that will restrict the gas flowrate to less than 6 mmscf/d.

-

After first gas the choke size may be increased as required.

Section 4040 Page10

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4050 MAIN FLOW PERIOD 0 01/10/92

MAIN FLOW PERIOD

1.

SAFETY

1.1

The main flow period requires no additional safety measures to those already in place for the clean-up flow.

Section 4050 Page1

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4050 MAIN FLOW PERIOD 0 01/10/92

2.

PREPARATION

2.1

Give at least 15 minutes warning of any change of fixed choke.

2.2

Supply surface testing crew chief and DAS operator with details of the Data acquisition requirements and sampling frequencies. The instructions to the surface testing crew chief should include details of how the Manual Data Acquisition requirements would change in the event of failure of the automatic DAS system.

2.3

Before diverting flow to the separator check that : -

2.4

The orifice plate is raised The oil meters are by-passed All the valves to sampling points etc are closed The instrument air supply is on Manual valves down stream of the control valves are open. The gas line is correctly lined up to the flare.

Before making a small choke change, check that : -

The orifice plate is raised The oil meters are by-passed

2.5

Before making a large choke change, eg during a multirate test, ensure that the separator is by-passed before making the choke change.

2.6

Allow approx 1 hour of preparation time before starting to take PVT Separator Samples.

Section 4050 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4050 MAIN FLOW PERIOD 0 01/10/92

3.

OPERATING PROCEDURE

3.1

Divert flow to separator and produce at stable conditions on a fixed choke for

3.2

Monitor the upstream and down stream pressures across the choke for signs of plugging or cutting out.

3.3

Monitor annulus pressure, this will increase as the well heats up. Bleed off annulus and psi. pressure as required to maintain annulus pressure between

Section 4050 Page3

hours.

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4050 MAIN FLOW PERIOD 0 01/10/92

4

GUIDANCE NOTES

4.1

Never use an adjustable choke for the stable flow period to the separator.

4.2

At some point during the flow period swop oil flow meters to confirm they are reading correctly. Any difference in readings of more than 1.5% should be investigated.

4.3

Estimate shrinkage using the shrinkage tester and correlations. Compare measured flow rate times shrinkage factor against gauge/surge tank reading. (Allow time for the shrinkage of the gauge tank to occur). Any significant differences greater than 3% should be investigated, possible causes are gas entrainment in the oil line or mechanical damage to the oil meter.

4.4

The orifice plate must be lifted regularly and the transducer lines bled down to prevent any liquid build up at the orifice plate or in the transducer lines. If lifting the plate and bleeding the lines makes a difference to the calculated flowrate then the plate and lines must be lifted/bled down more frequently. In addition at some time during the main flow period (not while taking PVT separator samples) flow the well for several hours on a different sized orifice plate to confirm that the gas rate is being correctly measured. Common causes of gas rate measurement error are : -

Liquid build-up ahead of the plate Plate damage or mud/valve grease build up on the face of the plate. Plate being installed back to front Leaking impulse lines Leaking orifice plate seals Incorrect recording of the orifice plate size.

4.5

Critical flow should be maintained across the choke during the main flow period unless the well objectives specifically state otherwise.

4.6

Where practical, chemical injection should be stopped at least 1 hour or a minimum of two separator volumes before the taking of separator PVT samples.

4.7

The following operations can affect the quality of PVT separator samples and should be avoided if possible. -

Switching burners while sampling. Switching flow from the burners to the surge/gauge tank. Changing the orifice plate Changing the heater operating conditions Changing the separator level controller Changing the separator pressure controller

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BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4050 MAIN FLOW PERIOD 0 01/10/92

4.8

Gas carry-over in the oil line can be detected by plotting oil rate versus the spare root of WHP. This should give a straight line with gas carry-over showing up by moving points to the left of the straight line. Alternatively and more accurately, a nuclear densitometer can be fitted to measure the oil density.

4.9

Oil carry-over in the gas line will generally show up as a reduction in oil rate before it shows up as an increase in gas rate. Increasing GOR can be an indication of oil carry-over. Small amounts of oil carry-over (< 250 bbl/d) can be difficult to detect. Service companies will sometimes check for carry-over by venting some of the gas through one of the 1/2" NPT valves and observing for droplets. However this technique is not very reliable if the separator pressure is high or the oil has a high GOR.

Section 4050 Page5

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4060 BOTTOMHOLE SAMPLING 0 01/10/92

BOTTOMHOLE SAMPLING

1.

SAFETY

1.1

Check that the work permits held by the Wireline Operator and Well Test Supervisor fully cover the scope of the operation.

1.2

Rig up of the wireline/slickline lubricator and BOP's should not be attempted in rough weather or high winds.

1.3

Ensure that the lubricator and BOP's are rated to the proposed test pressure.

1.4

Use 50/50 water glycol as the pressure testing medium and as far as possible ensure there is no air trapped in the equipment under test.

1.5

Always increase pressure slowly in steps to the final pressure.

1.6

The rig floor and all areas exposed to high pressure must be roped off. A P/A announcement detailing the areas where High Pressure Testing will be taking place must be made before the start of the operation. Note BPPD HSEQ Policy allows for a competent person to approach and visually inspect an item under test so long as the equipment has been subject to the particular pressure for 5 minutes, a state of equilibrium has been achieved and the test medium is water.

1.7 1.8

1.9

If during flushing and pressure testing there are any unexpected pressure build ups, bleed pressure off and check line up of the valves Use the cement unit relief valve to prevent any accidental over pressuring of the lubricator and BOP's. Bottom Hole Sampler are assembled on the deck then each sampler is lowered into the flowhead and attached to the preceding sampler. Any hand tools require to assemble the stack of bottom hole samplers should be attached to the riding belt to prevent it being dropped. All non essential personnel should keep clear of the deck area around and below the flowhead.

1.10

On recovery bottom hole samplers will contain pressurised fluids and gases. Observe each sampler for leaks and handle with care during disassembly.

Section 4060 Page1

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4060 BOTTOMHOLE SAMPLING 0 01/10/92

2.

PREPARATION

2.1

Ensure that the well has been flowed at a sufficient rate in the clean up period to remove any mud, brine, water or diesel from the tubing. If the well has sufficient PI flow the well at a rate sufficient to remove any mud, brine, water or diesel from the liner above top perforation as well.

2.2

Where possible pressure test the BOP's on the deck prior to rigging up the wireline/slickline lubricator.

2.3

Strap the samplers the pressure gauge and the maximum reading thermometers to tool zero.

2.4

If possible carry out the BHS rig up during a shut in period, but do not attempt to pressure test the wireline/slick line lubricator until the pressure build up is complete.

2.5

Check for NRV's between the cement pump and flowhead.

Section 4060 Page2

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4060 BOTTOMHOLE SAMPLING 0 01/10/92

3.

OPERATING PROCEDURE

3.1

With the tester valve, lubricator valve and kill valve closed, bleed off the pressure above the Lubricator valve at the choke manifold to the flare. Open the kill valve and flush the lines with 50/50 water glycol. Close the kill valve and choke manifold and monitor for pressure build up for 5 minutes. Re-open the choke.

3.2

With the swab valve closed, open the 1/2" needle valve on the swab cap and bleed off any pressure. Remove the swab cap.

3.3

Rig up the BOP's. Cycle the rams closed. (Normally the BOP's will have already been pressure tested on the deck prior to being picked up.

3.4

Open the swab valve. Rig up the electric line lubricator and insert the bottom hole sampling tool string. This will be a pressure gauge 4 bottom hole samplers and 3 maximum reading thermometers. Set the sampling clocks hrs delay. for

3.5

When the preceding pressure build up is complete. ie at

hrs

Pull the tool into the tool catcher. Flush through the flowhead with 50/50 water/glycol until fluid is seen at the stuffing box/grease tube. Stop pumping and establish a seal at the psi for 10 minutes. stuffing box/grease tube. pressure test to 300 psi for 5 minutes and 3.6

Bleed off to equalisation pressure and open the lubricator valve. Close the kill valve. Pressure up on the annulus to open the tester valve. Monitor WHP, when stable RIH.

3.7

Monitor tool weight and flow well to the burners on a

3.8

RIH to

3.9

Bean up the well in 4/64 ths and establish stabilised flow on 64 ths fixed choke. Divert the flow to the separator and establish stable conditions as a quickly as possible.

3.10

Remain on depth for 30 minutes after the time when sampling should be complete.

64 ths choke.

mbrt

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4060 BOTTOMHOLE SAMPLING 0 01/10/92

3.11

POOH stopping at mbrt mbrt mbrt mbrt

mbrt for five minutes each.

3.12

With the tool string at least 200m above the tester valve, bleed off the annulus pressure to close the tester valve. Shut the well in at the choke manifold.

3.13

With the tool in the lubricator close the Lubricator valve. Bleed off the pressure at the choke manifold, close the choke manifold and monitor for pressure build up for 5 minutes.

3.14 3.15

Line up to the surge tank and flush the flowhead with water/glycol. Break out the lubricator, rig down the tool string. Use the flow diagram to determine if a second run is necessary.

3.16

If sampling is complete rig down the wireline lubricator and BOP's. Install the swab cap with the 1/2" needle valve open. Open the kill valve and flush through the flowhead from the cement unit with a 50/50 water/glycol mix.

3.17

Close the 1/2" needle valve and pressure test the swab cap to 500 psi for 5 minutes and psi for 10 minutes. Bleed off the pressure at the cement unit, bleed off the pressure at the choke manifold to equalise across the Lubricator valve. Close the swab and kill valves and bleed off the pressure above the swab using the 1/2" needle valve, close the needle valve.

3.18

Open the Lubricator valve. Well status is now : Well shut in at tester valve and choke manifold.

Section 4060 Page4

BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL SECTION SUBJECT REVISION DATE

4060 BOTTOMHOLE SAMPLING 0 01/10/92

4.

GUIDANCE NOTES

4.1

If the tester valve has a lock open facility it should be used for wire line work provided the lock open position can be reached with only 1 - 2 cycles of the tester valve. Excessive cycling of the tester valve (>2 cycles to reach lock open) should be avoided. The reasons for this are: -

The primary reason for running a lock open on the tester valve is to simplify the well kill. Wire line operations should take advantage of the benefit of a lock open facility, but not to the extent of affecting the primary function of the lock open. Excessive cycling of the tester valve may lead to premature failure.

-

It is possible for the surface record of the lock position to be out of sequence with the lock open ratchet mechanism. Thus the lock open should not be relied upon for wire line work.

-

The risk of losing annulus pressure during well testing is very low and the added security achieved by locking the valve open is small.

The absence of a lock open facility does not restrict the range of wireline operations that may be carried out. 4.2

To obtain good quality bottom hole samples the well must be properly conditioned prior to taking the samples. The first stage in well conditioning is to remove any mud, brine, water, diesel from the well bore at the depth of the sampling point. This is done by flowing the well for at least two string volumes at a rate sufficient to lift the heaviest phase or until BS&W has been stable for two string volumes.

4.3

Pre Sampling Clean up flow Ideally it will be possible to remove all mud/brine/water from the well bore during the pre sampling clean up flow whilst maintaining the bottom hole flowing pressure (BHFP) above bubble point.

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4060 BOTTOMHOLE SAMPLING 0 01/10/92

In practice complete mud/brine/water removal is rarely achieved because the flow rate at the bottom perforation is insufficient to lift any mud or brine and it is only possible to remove the heavier phase from above top perforation. In some wells even this is not possible and the best that can be achieved is mud/brine removal from the tubing. Some times it will be necessary to flow the well with the BHFP below bubble point to achieve mud removal from either the tubing or the liner. In such cases the duration of the flow period with BHFP below bubble point should be kept to a minimum. This will minimise the volume of oil in the formation that is drawn below bubble point. The equations used to determine the flow rates necessary to remove mud/brine/water from the well bore are detailed in the GUIDANCE NOTES for the CLEAN UP FLOW PERIOD. 4.4

Sampling Flow Period The sampling flow period can be started at a low rate (