BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 0020
SUBJECT USER GUIDE
REVISION 0
DATE 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, pre-punched 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 1010
SUBJECT GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS
PLANNING
REVISION 0
DATE 01/10/92
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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 1020
SUBJECT GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS
MATERIALS AND SERVICES
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 1030
SUBJECT GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS
WELL INTEGRITY
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 1040
SUBJECT GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS
PRESSURE TESTING
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 1050
SUBJECT GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS
EXPLOSIVES AND RADIOACTIVE SOURCES
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 1060
SUBJECT GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS
WELL TESTING OPERATIONS
REVISION 1
DATE 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
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 1060
SUBJECT GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS
WELL TESTING OPERATIONS
REVISION 1A
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 1060
SUBJECT GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS
WELL TESTING OPERATIONS
REVISION 1
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 1060
SUBJECT GENERAL WELL TESTING POLICY FOR XEU MOBILE RIGS
WELL TESTING OPERATIONS
REVISION 1
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2010
SUBJECT RUNNING A PERMANENT PACKER
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2010
SUBJECT RUNNING A PERMANENT PACKER
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2010
SUBJECT RUNNING A PERMANENT PACKER
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2010
SUBJECT RUNNING A PERMANENT PACKER
REVISION 0
DATE 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 the packer rubbers at mbrt.
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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2010
SUBJECT RUNNING A PERMANENT PACKER
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2020
SUBJECT LANDING STRING DUMMY RUN SEMISUB
REVISION 0
DATE 01/10/92
LANDING STRING DUMMY RUN SEMISUB
1. SAFETY
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2020
SUBJECT LANDING STRING DUMMY RUN SEMISUB
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2020
SUBJECT LANDING STRING DUMMY RUN SEMISUB
REVISION 0
DATE 01/10/92
3. OPERATING PROCEDURE
3.1 RIH wear bushing pulling tool on drill pipe. Paint the first joint of drill pipe going into the hole.
3.2 Locate and engage the wear bushing. Cycle the pipe rams to mark the drill pipe. Pull 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 - Stand of 5" drill pipe
- Fluted hangar and 5" slick joint painted white. - Joints to of 5" drill pipe.
3.6 RIH, engage compensator and land out in the wear bushing. Close the pipe rams to mark 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2020
SUBJECT LANDING STRING DUMMY RUN SEMISUB
REVISION 0
DATE 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:
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.
4.3 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
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2020
SUBJECT LANDING STRING DUMMY RUN SEMISUB
REVISION 0
DATE 01/10/92
4.5 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2030
SUBJECT LANDING STRING DUMMY RUN JACKUP
REVISION 0
DATE 01/10/92
LANDING STRING DUMMY RUN JACKUP
1. SAFETY
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2030
SUBJECT LANDING STRING DUMMY RUN JACKUP
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2030
SUBJECT LANDING STRING DUMMY RUN JACKUP
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2030
SUBJECT LANDING STRING DUMMY RUN JACKUP
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2040
SUBJECT RUNNING TCP GUNS
REVISION 0
DATE 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. Transport of guns to the rig floor. b. Gun make up.
c. Purpose of the Safety spacer.
d. Firing system and possible methods of accidental gun detonation.
(Lightening strike, Severe mechanical impact eg the blocks falling on to an exposed booster)
e. That radio silence is not required
1.3 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2040
SUBJECT RUNNING TCP GUNS
REVISION 0
DATE 01/10/92
1.4 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2040
SUBJECT RUNNING TCP GUNS
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2040
SUBJECT RUNNING TCP GUNS
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2040
SUBJECT RUNNING TCP GUNS
REVISION 0
DATE 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 = The specific gravity of the mud
Dfh = True vertical depth of the firing head in metres
MOP = Maximum annulus operating pressure applied to operate any tool which may be required prior to firing the guns.
(Typically 2000 psi for the tester valve) SF = Safety factor (minimum of 1000 psi)
1.421 = The hydrostatic head of 1m of fresh water ie SG = 1.0
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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2040
SUBJECT RUNNING TCP GUNS
REVISION 0
DATE 01/10/92
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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2050
SUBJECT RUNNING TEST STRING SEMISUBS
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2050
SUBJECT RUNNING TEST STRING SEMISUBS
REVISION 0
DATE 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 psi and that 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:
a All joints should be measured and clearly painted with a number.
b Each " tubing joint should be drifted from the Box-end to " with a 42" long 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2050
SUBJECT RUNNING TEST STRING SEMISUBS
REVISION 0
DATE 01/10/92
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
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2050
SUBJECT RUNNING TEST STRING SEMISUBS
REVISION 0
DATE 01/10/92
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 psi for 10 minutes against the tester valve.
3.3 Continue to run the -1/2" 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 psi for 10 minutes after running joint .
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2050
SUBJECT RUNNING TEST STRING SEMISUBS
REVISION 0
DATE 01/10/92
3.7 Pick up and run the fluted hanger and slick joint. Denzo tape or paint the slick joint with white paint. RIH joints to of drill pipe and land out the fluted hangar in the wear 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2050
SUBJECT RUNNING TEST STRING SEMISUBS
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2050
SUBJECT RUNNING TEST STRING SEMISUBS
REVISION 0
DATE 01/10/92
4.12 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2060
SUBJECT RUNNING TEST STRING JACKUPS
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2060
SUBJECT RUNNING TEST STRING JACKUPS
REVISION 0
DATE 01/10/92
2. PREPARATION
2.1 Ensure all downhole tools are certified, that they are pressure tested to psi and that 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:
a All joints should be measured and clearly painted with a number.
b Each " tubing joint should be drifted from the Box-end to " with a 42" long 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.
2.6 The drill collars to be run must be drifted to 2.125" and have their threads inspected for signs of wear/damage.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2060
SUBJECT RUNNING TEST STRING JACKUPS
REVISION 0
DATE 01/10/92
2.7 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2060
SUBJECT RUNNING TEST STRING JACKUPS
REVISION 0
DATE 01/10/92
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 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 psi for 10 minutes against the tester valve.
3.3 Continue to run the -1/2" 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 psi for 10 minutes after running joint .
3.5 Run the remainder of the -1/2" tubing using the computerised joint make-up analyser.
Continue to fill string with seawater.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2060
SUBJECT RUNNING TEST STRING JACKUPS
REVISION 0
DATE 01/10/92
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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2060
SUBJECT RUNNING TEST STRING JACKUPS
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2060
SUBJECT RUNNING TEST STRING JACKUPS
REVISION 0
DATE 01/10/92
4.12 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2070
SUBJECT RUNNING LANDING STRING SEMISUBS
REVISION 0
DATE 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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2070
SUBJECT RUNNING LANDING STRING SEMISUBS
REVISION 0
DATE 01/10/92
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.
BP EXPLORATION (XEU) WELL TESTING PROCEDURES MANUAL
SECTION 2070
SUBJECT RUNNING LANDING STRING SEMISUBS
REVISION 0
DATE 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 string against the tester valve to 300 psi for 5 minutes and psi for 10 minutes from the cement unit.
Whilst performing the above pressure test, apply psi to the chemical injection line to 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.