Wellsite Leader Handbook

BP North Sea SPU Drilling & Completions

Wellsite Leader’s Handbook

BP North Sea SPU Drilling & Completions

Wellsite Leader’s Handbook

NSDC-00X-001.00U

Document No.

NSDC-00X-001.00U T01

Revision:

1.00U

Authors:

A. Barron, I. Tinegate

Approver:

R. I. Smith

Date:

April 2010

Copyright © BP Exploration Operating Company Limited 2010 All rights reserved.

None of the contents shall be disclosed, except to those directly concerned with the subject and no part of this document may be reproduced or transmitted in any way or stored in any retrieval system without prior written permission of general management, BP Exploration Operating Company Limited.

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Contents 1.

2.

3.

4.

Introduction

1

1.1 1.2 1.3 1.4

1 1 1 2

Purpose Planned Future Content Amendments Amendment Record

Functional Expectations of Well Site Leaders

3

2.1 2.2 2.3 2.4 2.5 2.6 2.7 2.8

3 3 5 6 7 9 10 11

General HSE Cost Management Well Control Drilling and Completion Operations Casing/Tubing Running Operations Cementing Fluids

General Practices

12

3.1 3.2 3.3 3.4

12 13 17 21

Flow-checks Washouts in the String Pressure Testing (General) Leak-Off Testing

North Sea Practices and Regulations

28

4.1 4.2

28

4.3 4.4 4.5 4.6 4.7 4.8

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Golden Rules Lifting Operations and Lifting Equipment Regulations (LOLER), (UK) Provision and Use of Work Equipment Regulations (UK) COSHH Requirements Chemicals and Bulks requirements (OCR and OPPC etc.) Working with Radiation Reporting of Injuries, Diseases & Dangerous Occurrence Regulations, (UK) Master Equipment List (MEL) Procedures, Roles and Responsibilities

32 42 50 52 59 60 61

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6. 7.

8.

9.

NSDC-00X-001.00U

Well Control

63

5.1 5.2 5.3

63 67 72

Kick Tolerance Shallow Gas Well Control Practice and Procedures

Mud Property Trends

98

6.1

98

Mud Property Changes and Trend Analysis

Drilling Practices

101

7.1 7.2 7.3 7.4 7.5 7.6

General Drilling Practices Tripping Practices Bits Rules for Optimising Hydraulics Hole Cleaning BHA Design

101 101 114 118 119 126

Directional Drilling and Surveying

128

8.1 8.2 8.3 8.4 8.5

129 130 134 135 136

Roles and Responsibilities General QA Checks and Survey Procedures Clustershot Surveys Anti-Collision

Sidetracking

138

9.1 9.2

138 140

Open Hole Sidetracking Casing Exits

10. Stuck Pipe and Fishing Operations 10.1 10.2 10.3 10.4 10.5 10.6

Considerations when Dealing with Stuck Pipe Stuck Pipe Mechanisms and Responses Best Practice when Dealing with Stuck Pipe Best Practice when Dealing with Stuck Wireline Best Practice when Required to Back-Off Best Practice when Fishing

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144 145 151 154 159 161 164

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11. Casing Running 11.1 11.2 11.3 11.4 11.5 11.6

174

Preparation of Casing on Deck Preparing the Casing Tally Casing Tallies Versus Liner Tallies Example Casing Checklist WSL's Casing Checks Best Practice when Running Casing

175 176 177 179 184 185

12. Cementing Practices 12.1 12.2 12.3 12.4 12.5 12.6 12.7

2009 Wellsite Cementing Checklist for WSLs Example Cementing Checklist Best Practice when Loading the Cement Head Best Practice when Cementing Casing Typical Cement Calculations for a 13 3/8" Cement Job Best Practice when Pumping Cement as a Plug Example Cement Calculations for a Balanced Cement Plug

13. Appendices 13.1 Appendix A - Clair Drilling Practices 13.2 Appendix B - Examples of Casing Tallies

14. Reference Documents and Links

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190 192 192 199 200 203 204 208 209 209 217 226

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1. Introduction 1.1 Purpose This document is intended to provide a handbook that can be used by the wellsite leaders and wellsite engineers as a quick reference during rig site operations of 'best practice' derived over many years from our most experienced wellsite personnel. The handbook is not intended as textbook, it is an attempt to pass on rigsite knowledge and 'tricks of the trade', to plug the gap between "theoretical" and "practical" knowledge. It's also about sharing tools that are considered as Best Practice. The writing style is less about being "prescriptive" and more about being "advisory"; it highlights the things which should be considered before doing a particular task. The Handbook is a Guidance Document as defined by the D&C Document Architecture, and is defined as the 'Preferred way'.

1.2 Planned Future Content The next release of this Handbook (planned for July 2011) will contain sections on: • • • • • • • •

Data Acquisition Completions Workovers Well Testing Well Services Wellheads and Trees Sub Sea Operations Reporting Guidelines (Openwells, etc.)

1.3 Amendments Suggestions for alterations, additions or corrections to the Handbook should be emailed to Richard Smith at [email protected]. Please also contact him if you would like to be involved in contributing to the planned future content detailed above.

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1.4 Amendment Record Amendment Date

Rev. No.

April 2010

1

page 2

Amender Name

Amendment First Issue of Handbook

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2. Functional Expectations of Well Site Leaders The role of the Wellsite Leader (WSL) is to ensure that the well operations which are under their control are carried out safely and efficiently, following good BP and industry practices. Good practice includes, but is not limited to, the expectations below based on the North Sea Functional Expectations of Wellsite Leaders (Rev. 4, April 2008).

2.1 General The WSL shall: 1.

Determine for which disciplines a written handover is required and ensure this takes place on a daily basis between day shift and night shift and at the end of each trip offshore.

2.

Ensure that an accurate account of workplace activity is recorded in DIMS.

3.

Ensure that a process for Well Handover and Ownership is in place and adhered to (this is to include ownership of wells for cuttings reinjection, CRI, if used).

4.

Ensure that appropriate levels of communication are occurring with production departments (particularly with respect to annulus pressure monitoring and injection on adjacent wells while drilling a reservoir section).

2.2 HSE The WSL shall ensure: 1.

Adherence to GHSER, BP's Golden Rules of Safety, any legislative lifting regulations and the Installation safety management system, SMS. An auditing programme shall be in place to confirm compliance with this.

2.

That visitors meet the Minimum Standards of Training.

3.

That BP staff and Contractors participate in the rig Safety Observation and Safety Intervention systems that are being used.

4.

That all incidents are reported, investigated, the root cause established and actions tracked through the Tr@ction system. A culture of open reporting should be encouraged.

5.

That all planned activities are risk assessed and adequate mitigations are in place.

6.

That there is a process for assessing and controlling risks associated with Simultaneous Operations.

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7.

That there is a programme in place for Safety Critical Maintenance and that it is being followed.

8.

That there is an effective process in place to manage all lifting equipment and that the equipment is fully certified.

9.

That lifting operations are carried out in accordance with local BP and legislative regulations.

10. That all portable equipment supplied for use on the rig is inspected and assessed in line with legislation requirements. 11. The transportation, storage and use of Radioactive sources is in line with the installation SMS requirements. 12. That all chemicals used on site are in accordance with local environmental legislation 13. That procedures exist for the segregation of waste and that all waste materials backloaded from the rig are done so in accordance with company and legislative requirements. 14. The DROPS process is implemented and adhered to throughout the rig. 15. There is adequate spill preparedness. 16. Active participation in or lead safety meetings, such as JSAs, prejob safety meetings, weekly HSE meetings. 17. Implementation of the installation's EMS (environmental management system). 18. Encouragement of people to "Stop the Job" if they have any safety concerns and to immediately address any reported unsafe acts or behaviours. In addition to the expectations listed above, following a world-wide Control of Work Review completed in autumn 2009, the following Recommended Practices for the WSL have been added to the HSE Functional Expectations: • Ensure that you fully understand the Drilling Contractor's and BP's (BP owned sites) SMS in use at your site, with particular attention to the requirements related to hazard identification, risk assessment, work authorisation, lifting, isolations and confined space entry. • Ensure that the BP Golden Rules are visible, understood and being fully complied with by everyone on site. • Ensure the Bridging Document is fully understood by site leadership team and that any requirements are being implemented at the site.

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• Support the Drilling Contractor in communicating clear expectations on the application of the SMS to both BP's and the Drilling Contractor's Third Party service providers. • Complete a minimum of one Control of Work Audit every day (this can be part of an existing STOP tour or previously agreed audit plan). Focus on the quality of the hazard identification, the controls in place and the involvement of the supervisor. Use a “coaching” style to work with the team/individuals to help them raise their standards. Where possible, complete this audit with a member of the Drilling Contractor's leadership team. • Ensure that the third party service providers are not ignored. Support them as detailed above at least once per week. • Take part in Tool Box Talks. Facilitate REAL engagement in the TBT by asking questions (e.g. Have all of the hazards been identified? What if….? How are you going to do that? Do you understand what your role is? Are you authorised to approve this work? What would prompt you to STOP the job? Etc.). Coach the TBT leader by holding a follow-up Lessons Learned review with the leader of the TBT after it is complete, aiming to improve the standard of engagement and the quality of the hazard identification. • Perform an act of positive recognition of good HSE behaviour/leadership particularly in the areas of hazard identification, lifting and isolations. • Ensure Major Accident Risks are not ignored but considered in Risk Identification (i.e. Well Control, Fire, Marine Risks, H2S, Lifting, High Pressure, Structural Failure).

2.3 Cost Management The WSL shall: 1.

Ensure there is a process in place to track and optimise expenditure on high cost rental tools.

2.

Ensure that boats, helicopters and POB are managed to ensure that personnel and equipment are available when required but not for longer than necessary.

3.

Review the daily CTX report to identify unnecessary expenditure through purchase of tangibles, bulks and rental of equipment.

4.

Ensure they have an awareness of the contractual arrangements for the remuneration of service providers.

5.

Ensure service provider performance is monitored and accurately reported, NPT is captured and the UFR process is utilised.

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6.

Drive the Continuous Improvement / Technical Limit process.

7.

Ensure that the offshore leadership team are engaged and active in managing costs.

8.

Ensure that there is an efficient operational planning process that minimises rig downtime.

9.

Identify opportunities to manage peripheral operations off the critical path.

10. Assist the Drilling Contractor with the scheduling of critical maintenance to minimise operational impact. 11. Ensure there is an awareness of NPT statistics and the offshore team are engaged in continuously improving NPT. 12. Encourage the planning and execution of SIMOPs when this can be done without introducing significant or unmanageable risk. 13. Ensure that equipment is ready and accessible prior to and during periods of inclement weather.

2.4 Well Control The WSL shall: 1.

Ensure that the agreed well control procedures are adopted, practiced and understood (BP's preferred method is the "Fast" shut in). This shall include posting of well control procedures in the doghouse and auditing of D1-D6 drills.

2.

Ensure that containment of the wellbore is possible at all times and that a kick sheet is updated daily.

3.

Ensure that the well is always flowchecked prior to tripping, after pulling into the casing shoe and before the BHA enters the BOP. The minimum length of a flowcheck will be 15 minutes.

4.

Ensure that the BOP testing procedure is designed so that there is a leak path below the test plug which will prevent pressure from being applied to the casing/open-hole. The WSL shall witness the first test to ensure that the plug has landed properly. If BOP testing is done without a leak path being available then volumes for subsequent tests shall be clearly communicated with an instruction not to proceed if these volumes are exceeded.

5.

Be present on the rig floor to observe the first 10 stands pulled on every trip out of the hole, and until such times as he/she is satisfied that the hole fill volume is correct. The WSL should continue to monitor the trip until back into old hole or inside casing.

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6.

Verify the integrity of the pressure tests and operation of all well control equipment and all pressure containing equipment installed in the well (casing, plugs, packers, completion, etc.). This shall include witnessing of all downhole tests by the WSL during the drilling phase and by either WSL or WSS/CS during the completion phase.

7.

Be familiar with the operation of any equipment installed on the rig for stripping operations. This equipment should be kept in good working condition.

8.

Ensure pressure containment barrier policy compliance.

9.

Witness and sign off FITs and LOTs.

10. Ensure adequate kick tolerance calculations for next 24 hours. 11. Witness SCRs each tour. 12. When pressure test witnessing is delegated (e.g. BOP testing), the testing procedure and acceptance criteria shall be agreed and the WSL shall check the test records/charts and sign them to confirm acceptance of the test.

2.5 Drilling and Completion Operations The WSL shall: 1.

Ensure that all downhole tools are visually inspected prior to running in hole (i.e. thread conditions, seal areas, jet size and bit type). Any new tools should be drifted.

2.

Be aware of the hole condition at all times and be able to communicate this to the onshore team as required.

3.

Ensure that the dimensions of any item run in the hole are recorded, correct for their application and a fishing diagram is available.

4.

Ensure that first line fishing equipment is available at the wellsite.

5.

Brief the BP Contractors as they arrive on the installation regarding their duties and BP's expectations for HSE and Operational Performance.

6.

Ensure that a copy of the Drilling Programme (plus any subsequent amendments) is distributed to the Drilling Contractor, Key Service Company Personnel and Other BP Supervisors (e.g. WSS/CS).

7.

Ensure that equipment is run within its operating limits and is rated for the intended purpose.

8.

Ensure that adequate communication occurs and as a minimum daily meetings are held between the WSL, Rig Site Geologist (if present), service company per-

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sonnel and contractors' personnel to discuss topics including the forward programme, equipment out of commission that may affect drilling operations and any other matter that may affect ongoing operational or safety performance. 9.

Verify that the personnel conducting operations understand the written work instructions and are conducting the operations in accordance with them.

10. Ensure that Well Surveying is conducted in line with the programme. In particular travelling cylinder limitations should be adhered to. 11. Ensure that deviations from the approved programme/plan are discussed with town. Operations shall only continue after an agreed forward programme is established, with risks understood and the Management of Change process completed if required. 12. Ensure that adequate precautions are being taken to prevent anything from being dropped down the hole. 13. Ensure that a planning process is established to ensure that rig equipment and tools are inspected and prepared before they are required. Best endeavours should be made to prepare equipment, procedures and plans off the operational critical path. 14. Ensure that any pressure applied during operations or testing does not exceed the pressure rating of the casing or associated equipment. 15. Ensure that the Cement/Test pump has been checked and pressure tested in advance of it being required for critical path operations. 16. Ensure that the drilling contractor is given written instructions prior to performing any operation on the well. These instructions shall include: a) The sequence of operations. b) The parameters to be used (WOB, tripping speed, etc.). c) The maximum overpulls to be applied to the string while tripping or jarring. d) Contingency operations if a known problem could be encountered (losses, connection overpull, etc.). e) Instructions on when the WSL should be informed at specific milestones or deviations from the plan. f) The instructions shall be signed by the WSL and Toolpusher. The instructions should be made available to all rig personnel. 17. Verify drill pipe tallies.

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18. Ensure procedures for stuck pipe are available and known. 19. Ensure alternative breaks in trip schedule. 20. Review BHA make-up and lay down.

2.6 Casing/Tubing Running Operations The WSL shall: 1.

Ensure that all equipment has been ordered and is on-site prior to the start of a casing job.

2.

Ensure that all pipe has been strapped and drifted (this may be done onshore, but the WSL should have written verification of this).

3.

Ensure that a pipe tally is prepared and that the number of casing/tubing joints on deck is known at all points in the operation (the running tally shall be checked by at least one independent source).

4.

Ensure that all running tools and equipment are in good condition, are the correct rating for the job and have valid certification.

5.

Witness the make-up and testing of the float equipment as the shoe-track is being run, ensuring that the required joints are Baker-Locked as per the programme.

6.

Ensure that the casing is made up to the correct torque.

7.

Verify correct centralizer installation and placement.

8.

Issue written instructions for casing running speeds and circulation requirements, giving due consideration to swab and surge calculations.

9.

Complete a deck check to confirm the remaining number of joints before picking up the hanger.

10. Ensure that the relevant Service Providers have checked their tools and equipment in preparation for use. This should include operability and critical measurements. 11. Verify critical wellhead measurements. 12. Where possible, any tight spots should be wiped out on the trip before running casing. The depth of ledges etc. should be recorded and included on the casing tally. 13. If differential float equipment is being used, the WSL shall ensure it is tripped prior to entering a hydrocarbon bearing zone. Rev. 1, April 2010

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2.7 Cementing The WSL shall: 1.

Supervise the cementers and drilling contractors in the performance of their duties.

2.

Prepare the calculations for the cement job to include slurry volumes, displacement volumes and cement/additive quantities. The calculations shall be verified by a minimum of two independent sources including the Cementing Service Provider.

3.

Agree pit management plan.

4.

Ensure that 100% back-up chemicals for the cement slurry are available onsite.

5.

Ensure that the mud loggers and drillers are informed of the volume and type of mix water for the lead and tail slurries, which mud pit will be used for each mix water, expected total volume of returns during the cement job and the increase in pit volume.

6.

Co-ordinate the execution of the cement job, ensuring that all relevant personnel are issued with a detailed programme highlighting individual responsibilities. This must include volumes, pressures and pump rates for the cementing and displacement operations. Contingency plans should be drawn up for any equipment failure, etc.

7.

Ensure that the cement recipe has been approved by the SDE onshore, mix water has been checked for contamination and where possible samples of cement, mix water and additives have been sent into town for testing.

8.

Be aware of the setting times for the cement, monitoring the remaining time available throughout the cement job.

9.

Ensure that the correct amount of cement is pumped during the cement job (this should include checking of bulk and additive usage).

10. Witness the loading of the cement head and supervise the release of darts and plugs. 11. Witness the shearing and bumping of the plugs, if applicable. 12. Supervise the hanger setting. 13. Ensure that chemicals and volumes to be used for a cement job are in accordance with local environmental legislation. Ensure that at all times during a cement job the bottom hole circulating pressure when pumping spacer and slurry is greater than formation pressure. page 10

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14. Where a computer based liquid additive system (LAS) is used, the WSL will verify that the correct information has been loaded on the computer system.

2.8 Fluids The WSL shall: 1.

Ensure that the mud is maintained in specification and suitable materials are held onboard to enable the system to be weighted up by 1 ppg.

2.

Ensure that a detailed plan is available for the displacement of a well to completion fluid. This shall include a plan to clean pits and surface lines to ensure no contamination of clean fluids pumped into the well.

3.

Ensure there is no single point failure mechanism within the fluids containment system. This should include mud pit valves, flow line valves and overshot packers.

4.

Monitor and optimize shaker screen usage, residual oil on cuttings, cutter dryer efficiency monitoring (if applicable).

5.

Confirm correct fluid testing and QA/QC procedures, LCM contingency and sweep plans.

Where CRI is used, the WSL shall ensure that procedures for this operation are in place and adhered to. This shall include maximum pump rates, pressures and post injection flush requirements.

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3. General Practices 3.1 Flow-Checks References: Functional Expectations of WSL • 2.4.3 The WSL shall ensure that the well is always flow-checked prior to tripping, after pulling into the casing shoe and before the BHA enters the BOP. The minimum length of a flowcheck will be 15 minutes.

3.1.1 Planned Flow-Check, i.e. Before POOH 1.

Make sure the mud weight in and out are balanced.

2.

Position the string as low as possible however leave sufficient height to be able to slump down if necessary.

3.

Whenever possible, break off the TDU to help stop the drill pipe contents UTubing into the annulus.

4.

Should hole conditions dictate e.g. potential differential sticking, then keep the TDU installed and slowly rotate the string.

5.

On fixed installations do not rely on sensors or floats while flow-checking. A physical check must be made. On floating rigs the trip tank may be the only accurate method of flow-checking. a) Position one man on the flowline to watch for flow. b) Position a second man, looking down the well, to monitor for losses. c) WSL to check both the Flowline and Downhole during the flow-check.

6.

If returns are seen at the flowline, then check the fluid level in the drill pipe.

7.

When displacing to cold brine, a certain amount of thermal expansion can be expected.

8.

If necessary, time return flow using a quart cup and monitor for a decreasing trend.

9.

After the flow-check, move the string down to confirm the pipe is free.

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3.1.2 Unplanned Flow-Check, i.e. Pit Gain While Drilling 1.

Driller to pick up and space out the string for closing the BOP.

2.

Make sure the mud pump and charge pumps are switched off.

3.

If TDU height could cause the mud to U-Tube then close in the auto kelly-cock.

4.

Shaker hand to check at the flowline that the well stops flowing.

5.

Compare last mud weight in with the last mud weight out.

6.

If flow is confirmed, then shut in the well.

7.

If no flow is seen, then notify the WSL and go back drilling.

3.2 Washouts in the String References: Functional Expectations of WSL • 2.4.6 The WSL shall verify the integrity of the pressure tests and operation of all well control equipment and all pressure containing equipment installed in the well (casing, plugs, packers, completion, etc.). This shall include witnessing of all down hole tests by the WSL during the drilling phase and by either WSL or WSS/CS during the completion phase. • 2.4.11 Witness SCRs until confident the correct procedure is being used and thereafter ensure SCRs are taken on each tour. • 2.4.12 When pressure test witnessing is delegated (e.g. BOP testing), procedure and acceptance criteria shall be agreed and the WSL shall check the test records/charts and sign them to confirm acceptance of the test. • 2.5.1 The WSL shall ensure that all down hole tools are visually inspected prior to running in hole (i.e. thread conditions, seal areas, jet size and bit type). Any new tools should be drifted. • 2.5.7 Ensure that equipment is run within its operating limits and is rated for the intended purpose. • 2.5.19 Ensure that alternative breaks are made while tripping.

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Best Practice When Dealing with a Washout

Best Practice when dealing with a washout includes: 1.

As with all down hole problems, prevention is better than cure. The best way to prevent washouts is to handle all tubulars correctly: • All threads and seal faces are to be inspected before make-up. • Correctly clean and dope all tool joints. • Ensure the correct make-up torque is being applied. • Always use protectors to prevent damage to threads and seal areas. • Maintain good drilling practice to prevent all string vibrations. • All tubulars are to be inspected to a standard and at a frequency commensurate with operating conditions and in accordance with both business unit requirements and API RP7G.

2.

While washing to bottom, check that the actual system pressure drop matches the calculated figure.

3.

Both the Driller and Data Engineer must be kept aware of any mud weight changes or work being done on the mud system which may affect the system pressure loss. (Circulating a heavy slug down hole can closely mimic the pressure drop normally associated with a washout.)

4.

Both the Driller and Data Engineer must stay alert and report any unexplained pressure fluctuations.

5.

Washouts will typically display a characteristic sudden pressure drop followed by a slower yet continual reduction in circulating pressure.

6.

If a washout is suspected then the following action should be taken. • Check that the pressure drop is not associated with a drop in the pump strokes. • Come off bottom and stop circulating immediately. • Have the surface system, e.g. rotary hose, drag chains, HP pipework, etc., checked for leaks and potential spills to sea. • Stop rotating but continue working the pipe. • Check the string weight has not changed. • If no leak is found, then restart the pumps, but keep people clear of the floor while pulling the stand back up through the rotary.

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• Derrickman to sound the pumps and check the pop-offs, etc. • Driller to change over to a second pump or pump combination and double check the pressures. • Checking against previous SCR figures is unlikely to be of help as the circulating pressures involved are often too low to be of value. • Well Site Leader to check the pressure chart and look for signs of characteristic pressure drops or indication that the pressure loss may be attributed to a nozzle clearing or a heavy slug being circulated around the system. • If an MWD tool is in the string, check to see if it is still pulsing OK (lack of a pulse could indicate a washout has taken place above the tool). • Is the system pressure fluctuating more than normal as the string is worked up and down? (Longitudinal cracks can open and close as the string goes from tension into compression.) • If unable to establish any problems with the surface equipment, then consider carrying out a pump test as detailed in section 3.2.2 below. • If no pump test data is available, then close in the IBOP (or Standpipe valve if the IBOP is not designed to hold pressure from above). Then using the mud pump, pressure test the surface system to the previous circulating pressure. 7.

Once it has been established that the pressure loss is indeed down hole than the Well Site Leader must decide whether to circulate clean or not. This decision can only be taken at the time and with the full understanding of hole conditions etc. (Normal practice would be to pull straight out without circulating, however circumstances such as having Nuclear Sources sitting in the reservoir, may dictate otherwise. String rotation should be avoided with a washout in the string.)

8.

A better understanding of the position of the washout may be established by using one of the techniques detailed in section 3.2.2 below.

9.

In order to allow for easier detection, do not pump a slug but make sure the floormen are not at risk of being sprayed with mud when the wash arrives back at surface.

10. Floormen should inspect each tool joint as it is broken and pay particular attention to the connection upsets and slip areas.

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3.2.2 Considerations when Dealing with a Washout Considerations when dealing with a washout include: 1.

When trying to find a washout, it is often useful to pressure test the surface system against the IBOP or standpipe valve, as mentioned in step 3.2.1.6 above. It is important however, that the WSL has witnessed this test in advance and understands the normal leak rate which can be expected when testing against mud pumps.

2.

A more accurate and potentially less damaging option to carrying out a static pressure test is to conduct a dynamic surface test through a fixed choke. The base line pressures can be checked while RIH, but should only be carried out while still inside casing: • Line up to have only one pump online. • Close off the rotary hose and line up to circulate from the standpipe through the fully open fixed choke. • Bring in the pump and establish what pump rate is achieved against a fixed pressure of 2000 psi. • Test each pump in turn and record the pump rate achieved in each case. • This test will need to be repeated when a new size of Liner is fitted or if a significant change is made to the mud weight.

3.

If deemed appropriate, then the WSL may try to find where the washout is by using either of the following methods: • If a water-based mud is in use, then a carbide bomb may be dropped and the resulting gas peak lagged to show the depth of the washout. • If there is no MWD in the string, then a softline tell-tale may be used. Tie a large stopper knot in a 12" length of softline and then unravel the strands. Pump the softline down the string and watch for a slight pressure rise as the string partially plugs the washout. The pump strokes at this point can then be used to calculate the position of the wash (additionally the softline will make it easier to spot the wash while POOH).

4.

After POOH and if no sign of a wash can be found, then consideration should be given to running back to bottom making and breaking each connection. If this again proves unsuccessful, then it may be necessary to pressure test the string in stages.

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3.3 Pressure Testing (General) References: Functional Expectations of WSL • 2.4.4 The WSL shall ensure that the BOP testing procedure is designed so that there is a leak path below the test plug which will prevent pressure from being applied to the casing/open hole. The WSL shall witness the first test to ensure that the plug has landed properly. If BOP testing is done without a leak-path being available, then volumes for subsequent tests shall be clearly communicated with an instruction not to proceed if these volumes are exceeded. • 2.4.6 WSL shall verify the integrity of the pressure test and operation of all well control equipment and all pressure containing equipment installed in the well (casing, plugs, packers, completion, etc.). This shall include witnessing of all down hole tests by the WSL during the drilling phase. • 2.4.12 When pressure test witnessing is delegated (e.g. BOP testing), the testing procedure and acceptance criteria shall be agreed and the WSL shall check the test records/charts and sign them to confirm acceptance of the test. • 2.5.14 The WSL shall ensure that any pressure applied during operations or testing does not exceed the pressure rating of the casing or associated equipment. • 2.5.15 The WSL shall insure that the Cement/Test pump has been checked and pressure tested in advance of it being required for critical path operations. SMS Documentation • GP 10-45 - Working with Pressure. • UKCS-SSW-001 - Safe Isolation and Reinstatement of Plant. • UKCS-TI-026 - Pressure (Strength) Testing Procedures.

3.3.1 Considerations while Pressure Testing Considerations while pressure testing include: 1.

Is a Permit To Work required for the testing operation?

2.

Who or what other activity may be affected by the pressure testing?

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3.

Have the flexible hoses and temporary lines been inspected and tagged in the last 12 months?

4.

Are all flexible hoses and temporary pipework hobbled?

5.

What is the setting of the PSV or emergency shutdown system?

6.

Has the chart recorder been calibrated in the last 12 months?

7.

Are the gauges and chart recorder suitable for both low and high pressure testing?

8.

Has a TBT been held to discuss; Roles and Responsibilities; Tannoy Announcements; Barrier Requirements; Minimum Manning Levels, Spotter Duties?

9.

Is it possible to pressure test surface lines in advance?

10. Are there any High Pressure to Low Pressure interfaces within the system? 11.

Are there any check valves in the system?

12. Are there reservoir fluids involved and if so could hydrates become an issue? 13. What is the burst rating of the weakest component? 14. What is the density of the fluid inside and outside the test envelope? 15. What are the minimum design factors for the casing? 16. What effect will the testing have on the casing tensile load? 17.

Is the test pump emergency stop button fully functional?

18. Is there likely to be a system temperature change during the test? 19. If the casing has already been drilled through, what affect will wear have on the maximum safe test pressure?

3.3.2 Best Practice when Pressure Testing Best Practice while pressure testing includes: 1.

All testing is to be recorded on a calibrated Chart Recorder which is capable of recording both Low and High pressure tests.

2.

When closing valves make sure to count the turns and/or measure the actuator volumes pumped or returned.

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3.

Make sure that potential leak paths are opened and being monitored from a safe distance during the test.

4.

All pressure tests will include a low pressure test of typically 200 - 300 psi before going onto the high pressure test.

5.

A satisfactory test during routine testing operations, e.g. pressure testing BOPs, is held for a minimum of 5 minutes after the pressure has stabilised (allowable drop rate is 10 psi/min).

6.

A satisfactory test on well integrity equipment, e.g. casing strings will be held for a minimum of 30 minutes or as directed in the programme after the pressure has stabilised (allowable drop rate is less than 5 psi/min over the last 15 mins).

7.

The preferred test medium is water. If it is not possible to turn the entire volume over to water then try at least to have water in the pump.

8.

Always flush through the system to clear any air from the lines.

9.

Have the expected test volume calculated before starting to pump.

10. PSVs will not be set above 95% of the maximum operating pressure of the testing equipment. 11. Never test tubulars to over 90% of API burst, or to over 80% of the triaxial stress nominal yield. 12. Never test connections to above the connection rating or 75% of the tensile rating. 13. The WSL should confirm that the line up on the pump is correct and make sure that a minimum of two independent pressure readings are available. 14. Start the pump in the highest gear possible and listen to the pump/engine note to confirm when the unit comes under load. 15. Build pressure in stages, to the low pressure value and allow the pressure to steady at each stage. 16. Record the volume pumped against the pressure attained at each stage. 17. Build pressure in 1000 psi or 25% stages to the high pressure value, again record the volume against pressure reached at each stage. 18. By pumping at a constant rate, an early indication of a leak will be seen as the rate of pressure increase will slow down. 19. While staging up the pressure, check the gauges agree with the chart.

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20. Pressure pulses or "bounce" on a high volume test is a good indication that the integrity of the system is sound. 21. If testing long rotary hoses etc., reduce the pumping rate to allow for expansion of the elastomers and wire core. 22. Air in the system will be evident if the pressure dips but then starts to steady. If this air effect is seen, then simply bump the pressure back up and compare the result. 23. Should the pressure leak off, then record the drop rate seen. 24. Do not allow crew members to investigate a leak with full pressure on the system. 25. Before bleeding off the pressure, ensure the trace on the chart is acceptable. 26. At the end of the successful test, bleed back the test pressure slowly so as to avoid shocking the system. 27. While bleeding down the pressure, check the volume returned against the pressure reading. 28. Once all pressure is bled down compare the volume pumped against the volume returned. 29. Finally examine and sign off the chart.

Note: Test Volume (bbls) =

Pressure Increase (psi) x Volume to be pressured (bbl) Compression Factor

Common Compression Factors:

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Water/Brine = 275,000 OBM = 250,000 Base Oil = 200,000

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3.4 Leak-Off Testing References: Functional Expectations of WSL • 2.4.6 The WSL shall verify the integrity of the pressure tests and operation of all well control equipment and all pressure containing equipment installed in the well (casing, plugs, packers, completion, etc.). This shall include witnessing of all down hole tests by the WSL during the drilling phase and by either WSL or WSS/CS during the completion phase. • 2.4.9 Witness and sign off on FITs and LOTs. • 2.4.12 When pressure test witnessing is delegated (e.g. BOP testing), procedure and acceptance criteria shall be agreed and the WSL shall check the test records/charts and sign them to confirm acceptance of the test. • 2.5.14 Ensure that any pressure applied during operations or testing does not exceed the pressure rating of the casing or associated equipment. • 2.5.15 Ensure that the cement/test pump has been checked and pressure tested in advance of it being required for critical path operations. SMS Documentation • Drilling Operations Guidance - Section 8100 .

3.4.1 Leak-Off Tests - General Leak-Off Testing and Formation Integrity Testing is performed by pumping at a constant slow rate (max. 0.25 BPM) while recording pressures versus volume pumped on graph paper. This test is the equivalent of strength testing of metals. The four phases when pressure is being applied to a formation are: 1.

Elastic Phase: where pressure increases at a constant rate per unit of volume pumped (straight line on pressure versus volume pumped graph). The analogy for tensile testing of a piece of metal is that in the elastic phase the tensile force can be applied and then removed without deforming the metal as it would return to it's original dimensions.

2.

Plastic Phase: where pressure increase per unit volume pumped is less than recorded in elastic phase (the data points deviate from a straight line). The leakoff point is defined as the last point on the straight line before deviation is

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observed. Leak-off test will be stopped after pumping a maximum of 0.75 to 1 bbls past the leak-off point. The test should be stopped immediately deviation is observed to prevent going to third phase. The analogy for tensile testing of a piece of metal is that in the plastic phase the tensile force applied and then removed will result in permanent deformation of the metal as it would be longer and narrower (necking) than it's original dimensions. 3.

Breakdown Phase: If the Leak-Off or Formation Integrity Test is not stopped when leak-off is observed (deviation from the straight line) then the pressure will reach a point where the formation catastrophically fails and the pressure the formation can support will be significantly less than before the test. If the formations are broken down then this could compromise the ability to the drill the well. The point at which the pressures suddenly drop is called the Fracture Initiation Gradient. The analogy for tensile testing of a piece of metal is this is the tension at which the metal fails and parts into two pieces. If the leak-off test is taken to Formation Breakdown then it could significantly impact the ability to drill the well.

4.

Injection Phase: If fluid is continued to be pumped into the formation then the pressures will stabilize at a constant injection pressure value which is called the Fracture Propagation Gradient.

Note: Unless completing an extended LOT, all formation testing (both leak-off and formation integrity tests) must stop when the end of the Elastic Phase is identified (i.e. when observing deviation from a straight line) and before the Breakdown Phase is entered.

Four Phases as Pressure is Applied to a Formation

Pressure

Plastic

Breakdown (Fracture Initiation)

Elastic Injection (Fracture Propagation)

Barrels Pumped

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Leak-Off Testing: After drilling out of the casing or liner shoe 3 to 4m of formation is drilled below the rat hole. Pressure is then applied above the mud weight until deviation from a straight line is observed. Once deviation from a straight line is observed the test should be stopped to prevent breaking down the formation. The leak-off pressures is the last point of the elastic phase (end of straight line). Formation Integrity Testing (Limit Test): After drilling out of the casing or liner shoe 3 to 4m of formation is drilled below the rat hole. Pressure is then applied above the mud weight to a defined pressure limit (if no deviation from a straight line) or test stopped early if deviation from a straight line is observed (leak-off). If leak-off is observed during the Formation Integrity Test, then the test must be reported as a "Leak-Off Test" to avoid confusion. Formation integrity pressure achieved or the leak-off pressure applied to the formation is then used in the Kick Tolerance calculations to determine the volume of influx that can be circulated out without exceeding the strength of the formations at the shoe when drilling to the planned section depth.

3.4.2 Considerations when Conducting Leak-Off Tests 1.

Leak-off tests (also known as Formation Intake tests or Formation Integrity tests) are carried out for three main reasons: • To test the cement job. • To determine the leak-off gradient of the open formation. • To collect regional data to optimise future well design.

2.

"Limit tests" are those where the formation is tested to a pre-determined pressure or Equivalent Mud Weight (EMW) that is known will be sufficient to cover any potential mud weight increases.

3.

Leak-off or Formation Integrity tests are carried out on each casing and liner shoe (except conductor shoes) before drilling ahead.

4.

Leak-off and Formation Integrity tests will be limited to the lesser of the following factors: • • • • •

5.

Formation leak-off, i.e. deviation from the straight line on the Psi/Barrels graph. Casing test pressure. Wellhead test pressure. BOP test pressure. 75% of the casing burst pressure.

The requirement to carry out an integrity test may be relaxed in certain circumstances, however relaxation will only be granted if there are good indications of a

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successful cement job and once a documented risk assessment has been carried out. Some situations where dispensation to policy may be given include: • Casing string is not a pressure containment string. • Exposed formations are very vulnerable to damage and such damage will subsequently increase the level of risk. • Casing shoe is set by design within the target reservoir. • Where air or under balanced fluids are the primary circulating medium. 6.

If the formation integrity test fails to meet the prerequisite standard then remedial corrective action may well be required.

7.

Only suitably accurate pressure gauges are to be used for leak-off testing and all results will be recorded on a chart.

8.

Only the cement pump or a similar low volume pumping unit will be used for leakoff testing. Rig pumps are never to be used for leak-off testing.

9.

The displacement tanks on the cement unit are to be calibrated in ½ bbl increments in such a way as to allow for a good estimate of ¼ bbl to be made.

10. The back pressure of the column of test fluid between the cement unit and the rig floor should be calculated before the job. If this value is significant then it should be subtracted from the pressures recorded at the unit during the test. 11. It is not normal practice to take the gelation effect of the mud into account, however cross-referencing the leak-off test results against the PWD readings will help guard against any gross errors being made.

3.4.3 Best Practice when Conducting Leak-Off Tests There are two acceptable methods of carrying out a leak-off test. The "hesitation" method involves increasing the pressure in stages and recording both dynamic and static pressures whereas the "constant pump" method only stops when a deviation from the straight line is seen. The constant pump method is more useful in elastic formations whereas the hesitation method can offer earlier detection as both the dynamic and static pressure trends can be monitored. It is the hesitation method which is described below. Best practice is to pump down both the drill string and the annulus to prevent formation debris being sucked into the bit nozzles when the pressure is bled down.

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1.

Drill 4m of new formation, then if drilling with a rotary steerable system, downlink and set the tool to "Ribs Off" before carefully pumping back up inside the shoe.

2.

Once safely inside the shoe, set the tool to "Steer Force Zero", and circulate till clean and the mud weight in and out are balanced. If vibration is a problem then do not rotate while circulating.

3.

While circulating, carry out the following preparations: • Assistant Driller to confirm we have fluid to surface but no pressure reading on the casing annulus. • Cementer to pressure test surface lines to 2000 psi and function test his overpressure limit. • Toolpusher to confirm that all pressure gauges are online and working. Well Site Leader to be made aware of any gauge discrepancies. • Well Site Leader to calculate the expected leak-off pressure and test volumes. Drilling Engineer to check these figures. • Use the previous casing pressure test details to help verify these calculated figures and prepare a graph charting barrels pumped on the "X" axis and pressure on the "Y" axis. • Hold a Toolbox Talk with everyone concerned. • Position a man at the wellhead to monitor the casing annulus pressure. • Space out the string in readiness for closing in the well. Have the TDU as low in the derrick as possible. • Erect signs and barriers and make tannoy announcements alerting personnel to the risks of pressure testing. • Derrickman to transfer Active mud to the Cement unit. • Mud Engineer to confirm the final mud weight in and out.

4.

Once the mud system is in balance, flowcheck the well looking for both losses and gains.

5.

Driller to close off the mud pumps and line up the cement unit to pump down both the Kill Line and the Drillstring.

6.

Cementer to flush active mud down through the Kill Line till returns are seen at the shakers. Once returns are seen, then stop pumping and close in the Kill HCR.

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7.

Cementer to flush active mud down the Drillstring till returns are seen at the Shakers. Once returns are seen, then stop pumping, close in the Upper Pipe Rams and open the Kill HCR. Well Site Leader to record both the Cement Unit and the Cameron Choke Manifold pressure gauge readings.

8.

Cementer to pump at a slow and steady pace aiming at ¼ bbl/min but certainly no faster than ½ bbl/min.

9.

Once pressure registers on the Choke Manifold gauge, stop pumping. Well Site Leader to record volume pumped and all gauge readings. An adjustment for rig floor height, mud gelation pressure and gauge inaccuracy can now be made.

10. Position a man at the Shakers to watch for any fluid by-passing the Upper Pipe Rams. Be aware of the possibility of ballooning from the next casing annulus. 11. Using the same slow and steady pump rate of around ½ bbl/min, pump away ¼ bbl active mud. Well Site Leader to record the "dynamic" pumping pressure just before the pump is stopped and then the semi stabilised "static" figure after 2 minutes. Plotting the test results on the run will often give the first indication that leak-off has been reached. 12. Continue pumping in these ¼ bbl increments plotting both the dynamic and static pressures. By continuing to pump at the same slow and steady pace, a reduction in the rate of pressure increase will be the first sign that leak-off has been reached. This is particularly notable when using a digital pressure gauge. 13. Once the leak-off or limit pressure is reached, stop pumping and hold the pressure for a further 10 minutes. N.B. The point of leak-off is taken as the moment where the pressure plot deviates from the straight line. Well Site Leader to confirm with the Shaker hand and the man at the wellheads that no flow is being seen through either of these potential leak paths. 14. Calculate the Equivalent Mud weight using: EMW (ppg) =

Leak-Off Pressure (psi) + Hydrostatic of Mud to Shoe (psi) TVD of Shoe (ft) x 0.052

15. Bleed back the pressure slowly to the cement unit and record the volume returned and lost downhole. N.B. Take care to allow for line returns during this exercise. 16. Driller to open up the well and line back up for drilling, meanwhile again flowcheck the well looking for both losses and gains.

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17. Restart the pumps and if available have the MWD engineer confirm the maximum pressure recorded by the downhole tools. Well Site Leader to compare this pressure with the surface leak-off value.

Typical Leak-Off Profile below a 13 3/8" Shoe 300

Static Pressure

250 200 150

Pressure (psi)

100 50 0 0

0.5

1

1.5

2

2.5

Barrels Pumped

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4. North Sea Practices and Regulations 4.1 Golden Rules BP's safety policy states no harm to people and no accidents. Everyone who works for, or on behalf of, BP is responsible for their own safety and the safety of those around them. The following safety rules will be strictly enforced to ensure the safety of our people and our communities. Although embedded in each of these rules, it is important to emphasize that: • Work will not be conducted without a pre-job risk assessment and a safety discussion appropriate for the level of risk. • All persons will be trained and competent in the work they conduct. • Personal protection equipment will be worn as per risk assessment and minimum site requirements. • Emergency response plans, developed from a review of potential emergency scenarios, will be in place before commencement of work. • Everyone has an obligation to stop work that is unsafe.

4.1.1 Permit to Work Before conducting work that involves confined space entry, work on energy systems, ground disturbance in locations where buried hazards may exist, or hot work in potentially explosive environments, a permit must be obtained that: • Defines scope of work. • Identifies hazards and assesses risk. • Establishes control measures to eliminate or mitigate hazards. • Links the work to other associated work permits or simultaneous operations. • Is authorized by the responsible person(s). • Communicates above information to all involved in the work. • Ensures adequate control over the return to normal operations permit to work.

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4.1.2 Energy Isolation Any isolation of energy systems (mechanical, electrical, process, hydraulic and others) cannot proceed unless: • The method of isolation and discharge of stored energy are agreed and executed by a competent person(s). • Any stored energy is discharged. • A system of locks and tags is utilized at isolation points. • A test is conducted to ensure the isolation is effective. • Isolation effectiveness is periodically monitored.

4.1.3 Ground Disturbance Work that involves a man-made cut, cavity, trench or depression in the earth's surface formed by earth removal cannot proceed unless: • A hazard assessment of the work site is completed by the competent person(s). • All underground hazards, i.e. pipelines, electric cables, etc., have been identified, located and if necessary isolated. Where persons are to enter an excavation: • A confined space entry permit must be issued if the entry meets the confined space definition. • Ground movement must be controlled and collapse prevented by systematically shoring, sloping, benching, etc., as appropriate. • Ground and environmental conditions must be continuously monitored for change.

4.1.4 Confined Space Entry Entry into any confined space cannot proceed unless: • All other options have been ruled out. • Permit is issued with authorization by a responsible person(s). • Permit is communicated to all affected personnel and posted, as required. • All persons involved are competent to do the work. • All sources of energy affecting the space have been isolated.

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• Testing of atmospheres is conducted, verified and repeated as often as defined by the risk assessment. • Stand-by person is stationed. • Unauthorized entry is prevented.

4.1.5 Working at Heights Working at heights of 2 metres (6 feet) or higher above the ground cannot proceed unless: • A fixed platform is used with guard or hand rails, verified by a competent person, or… Fall arrest equipment is used that has: • A proper anchor, mounted preferably overhead. • Full body harness using double latch self. • Locking snap hooks at each connection. • Synthetic fibre lanyards. • Shock absorber. • Fall arrest equipment will limit free fall to 2 metres (6 feet) or less. • A visual inspection of the fall arrest equipment and system is completed and any equipment that is damaged or has been activated is taken out of service. • Person(s) are competent to perform the work.

4.1.6 Lifting Operations Lifts utilizing cranes, hoists, or other mechanical lifting devices will not commence unless: • An assessment of the lift has been completed and the lift method and equipment has been determined by a competent person(s). • Operators of powered lifting devices are trained and certified for that equipment. • Rigging of the load is carried out by a competent person(s). • Lifting devices and equipment have been certified for use within the last 12 months (at a minimum). • Load does not exceed dynamic and/or static capacities of the lifting equipment. page 30

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• Any safety devices installed on lifting equipment are operational. • All lifting devices and equipment have been visually examined before each lift by a competent person(s).

4.1.7 Driving Safety All categories of vehicle, including self-propelled mobile plant, must not be operated unless: • Vehicle is fit for purpose, inspected and confirmed to be in safe working order. • Number of passengers does not exceed manufacturer's design specification for the vehicle. • Loads are secure and do not exceed manufacturer's design specifications or legal limits for the vehicle. • Seat belts are installed and worn by all occupants. • Safety helmets are worn by riders and passengers of motorcycles, bicycles, quads, snow-mobiles and similar types of vehicle. Drivers must not be authorized to operate the vehicle unless: • They are trained, certified and medically fit to operate the class of vehicle. • They are not under the influence of alcohol or drugs, and are not suffering from fatigue. • They do not use hand-held cell phones and radios while driving (best practice is to switch off all phones and two-way radios when driving).

4.1.8 Management of Change Work arising from temporary and permanent changes to organization, personnel, systems, process, procedures, equipment, products, materials or substances, and laws and regulations cannot proceed unless a Management of Change process is completed, where applicable, to include: • A risk assessment conducted by all impacted by the change. • Development of a work plan that clearly specifies the timescale for the change and any control measures to be implemented regarding: • Equipment, facilities and process. • Operations, maintenance, inspection procedures.

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• Training, personnel and communication. • Documentation. • Authorization of the work plan by the responsible person(s) through completion.

4.2 Lifting Operations and Lifting Equipment Regulations (LOLER), (UK) References: Functional Expectations of WSL • 2.2.8 The WSL shall ensure that there is an effective process in place to manage all lifting equipment and that the equipment is fully certified. • 2.2.9 The WSL shall ensure that lifting operations are carried out in accordance with LOLER and BP's North Sea Lifting Rules. SMS Documentation • UKCS-SOP-043 - Crane Lifting and Slinging Safe Operating Procedures. • UKCS -TI-10 - Practical Guide to LOLER. • UKCS-TI-012 - Guidance on Lifting Equipment Supply, Control and Operations. • UKCS-TI-013 - Colour Coding procedure for Portable, Fixed and Circulating Lifting Equipment. • UKCS-TI-014 - Guidance on the Categorisation/Planning/Risk Assessment and Implementation of Lifting Operations.

4.2.1 North Sea Lifting Rules The following fundamental rules will be applied to all lifting operations with zero tolerance: 1.

All personnel must keep out of any area where they might be injured by a falling or shifting load. Do not stand below loads. Never stand between loads and walls/bulkheads, etc. Always ensure an escape route is available.

2.

Immediately a lift deviates from plan or any complication arises, the lifting operation must be stopped and made safe. All personnel should remain in positions clear of the lift until reassessment/replanning of the lift is carried out.

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3.

Lifting operations will be undertaken by a minimum of three competent people: crane operator, banksman/flagman and load handler.

4.

The banksman/flagman controls the initial lifting of the load, laydown of the load and lifts that are out of the line of vision of the crane operator. The crane operator is responsible while the load is in the air. The banksman must: a) Ensure that he/she is easily identifiable from other personnel by wearing a hivis jacket or waistcoat, which is clearly marked to indicate that he/she is the authorized crane banksman. b) Not touch the load. He/she must stand back from the load being handled in a prominent position where he/she has a good view of the lifting activities. c) Remain in communication with the load handler and crane operator at all times. d) Keep the load handler in sight during the lifting operation.

5.

The load handler must: a) Stand clear while a load is lifted clear of the deck and landed, while slack is taken up with or without a load on the hook and must confirm to the banksman that he is clear. b) Not touch a load being landed until it is below his/her waist height and never attempt to manually stop a swinging load. c) Be easily identifiable, and distinct from the banksman.

6.

For BP operated installations and onshore sites there will be no stacking of containers, baskets, tanks and half heights.

4.2.2 LOLER Regulations Lifting incidents account for a significant number of all serious accidents. BP recognises the importance of safe lifting practices and has included Lifting Operations within its "Golden Rules of Safety". Lifting is controlled under the Lifting Operations and Lifting Equipment Regulations (LOLER), which came into force in December 1998. The regulations deal with both portable and fixed equipment and apply on any site where the Health and Safety at Work Act operates. All lifting equipment and accessories are covered and once more it is the employer, who shoulders the main responsibility.

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A comprehensive list of roles and responsibilities is available within UKCS-TI-10, however the main responsibility of the employer ensures: • that competent people are appointed to risk assess, plan, supervise and carry out all lifting operations; • that sufficient, suitable and certified lifting equipment is supplied, checked and sited by competent persons; • that lifting equipment is suitably marked with SWL and comprehensive records of certification are maintained; • that examinations are carried out by an impartial inspector and that any equipment which fails examination is immediately withdrawn from service; • that only equipment deemed suitable as per Regulation 5 will be used for the lifting of personnel.

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4.2.3 LOLER - Risk Assessments and Lift Plans An example of a typical Risk Assessment and Lift Plan, in this case covering a wireline logging run, is detailed below. 4.2.3.1 Risk Assessment Form for Rigging and Lifting Operations

Risk Assessment Form for Rigging and Lifting Operations Assessment No./Job Title: Rig-up of the Wellserv Slick Wire Line Unit

Lift Plan No. A1D. 012

The object of the risk assessment is to identify and eliminate any hazards in the lifting operation, define the level of difficulty of the task and determine the skill level of the personnel required to perform that particular activity safely. This document will also highlight any needs for further training. Category of lifting operation:

ROUTINE DRILLING & WELL SERVICES LIFT

Person responsible for lifting operation:

DRILLER

Performing Authority:

DRILLER

Personnel to be involved:

Drillcrew and Wellserv Service Hands

Date of lift: Please complete the result table below once the relevant parts of the risk assessment have been completed. Result of risk assessment (tick appropriate box) 1. STOP! - Further engineering input required

NO

2. CAUTION! - Rigging personnel must perform operation

NO

3. GO - Proceed with lifting operation If the lift is to proceed, please enter in the box below, any special instructions and/or safety measures to be taken.

Name: JOCKY RIDDOCH

Job Title: Sparrows Lifting Co-ordinator

Date: 12-11-04

Once the lift has been safely completed, please note in the box below any problems encountered and how they were overcome, also any suggestions for doing the lift more efficiently/safely. Job Completion Feedback:

Name:

Rev. 1, April 2010

Job Title:

Date:

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4.2.3.2 Lift Categorisation Assessment Part 1 - Routine Lifts

Yes

Seven Basic Questions 1.

Has the lifting operation been performed before?

2.

Is there a documented procedure?

3.

Are you experienced with all the lifting equipment to be used?

4.

Has the load been checked and made ready for lifting (e.g. sea fastenings released, hold-down bolts removed)?

5.

Have you the experience to lift a load of this weight?

6.

Is the lift in an area free from obstructions and other possible hazards?

7.

Can the lifting operation be carried out without the use of soft eye flat webbing slings?

No

If the answer to any of the above is 'No', go to Part 2 of the Lifting Operation Assessment Procedure. If the answer to all seven questions above is 'Yes', proceed with the routine lifting operation in accordance with the relevant lifting plan and/or risk assessment. Assessment Part 1 performed by:

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JOCKY RIDDOCH Job title: Sparrows Lifting Co-ordinator Date: 12-11-04

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4.2.3.3 Lift Categorisation Assessment Part 2 - Simple Lifting Operations Yes

Questions 1.

Is the lifting operation to be undertaken by a single lifting appliance?

2.

Do you know the weight of the load and does the lifting operation appear to be straightforward?

3.

If the load is heavier than you normally handle, do you have the relevant permission and/or permit?

4.

Is there a crane or certified support steelwork (e.g. runway beam or lifting eye) directly above the load?

5.

Does the load have certified lifting points (lifting eyes/collar eyebolts, etc.) fitted and if not, can slings be wrapped around easily (e.g. no sharp edges, load not fragile, etc.)?

6.

Is there ample headroom for the lifting appliance and slings?

7.

Is the lift stable (e.g. centre of gravity below lifting points)?

8.

Is the lift balanced (e.g. centre of gravity in the middle) or fitted with special slings to compensate?

9.

Is the load free to be lifted (e.g. sea fastenings released, all hold-down bolts removed, not jammed etc.)?

10.

Is the removal route clear of any obstructions?

11.

Can the removal (lift, transfer and landing) be performed without cross hauling?

12.

Is there a suitable laydown area and does the load come within the allowable load bearing capacity of the ground/deck?

13.

Are you experienced in using all the lifting equipment and gear involved?

14.

Can the lifting operation be carried out without the use of soft eye flat webbing slings?

No

If the answer to any of the above is 'No', go to Part 3 of the Lifting Operation Assessment Procedure. If you can answer 'Yes' to all the above, proceed with the lift as per the BP requirements for simple lifts. Assessment Part 2 performed by:

JOCKY RIDDOCH Job title: Sparrows Lifting Co-ordinator Date: 12-11-04

Note (1): To Supervisors: If you can give solutions to the above negatives to allow the lift to proceed safely, write the instructions in the box below. If you cannot supply a solution, seek guidance from the Lifting Co-ordinator before proceeding with the lifting operation. Solutions to overcome the above problems: Refer to Lifting plan A2G.018 (Transfer of Equipment Under 5te from Pipe Deck to Rig Floor).

Rev. 1, April 2010

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4.2.3.4 Lift Categorisation Assessment Part 3 - Complicated Lifts Must be carried out by qualified Riggers, or personnel with similar qualifications and skills in dealing with awkward loads. The personnel about to perform the lifting operation shall complete the table below. Tick against factors which are applicable to this specific lifting operation and indicate whether or not you have the relevant experience to deal with them. Experience Identified Hazard 1.

Load has C of G above the lifting points or a high C of G.

2.

Load has an offset centre of gravity.

3.

Load has to be cross-hauled or restrained.

4.

Load does not have specific lifting attachments.

5.

Load is fragile.

6.

Load has a large surface area which may act as a sail.

7.

Load requires two sets of rigging or two appliances for tandem lifting.

8.

Load has to be rotated (overturned).

App

Yes

YES

YES

YES

YES

No

If you answer "No" to any of the above, go to Part 4 of the Lifting Operation Assessment Procedures. If you answer 'Yes' to all of the above, proceed with the lift as per the BP Requirements for complicated lifts. (N.B. This text has been corrected from TI-014.) Assessment performed by: JOCKY RIDDOCH Job title: Sparrows Lifting Co-ordinator Date: 12-11-04 Endorsed by: Job title: Date: Note (1): To Supervisors: If you have any experience and can advise personnel involved in the lifting operation how to deal with the complication, allow the task to proceed but only under your guidance. However, if you decide that the operation is outwith the scope of your competence, please indicate the reasons applicable in the table in Part 4 - Complex Lifts before passing it to the nominated Technical Authority for lifting operations on the site.

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4.2.3.5 Lift Categorisation Assessment Part 4 - Complex Lifts Lifting operations or conditions which would merit additional engineering input.

Reasons for Requesting Engineering Input 1.

The lifting operation involves divers.

2.

The lifting operation is subsea.

3.

The load will be travelled over unprotected process plant/machinery.

4.

The load is extremely heavy.

5.

The lift involves a floating crane.

6.

The load is extremely valuable >£10,000.

7.

The lift is in a confined space.

8.

The lift is in an area with very restricted headroom.

9.

Other reason:

Tick box where applicable

Lifting Plan/Method Statement and Risk Assessment Part 4 Performed by: Job title: Date: Approved/Endorsed by (delete as applicable): Date:

Rev. 1, April 2010

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Lifting Operations Plan

Page 1 of 2

Description Of Lifting Operation: Remove and install Wellserv slickline unit on pipe deck - rig up lubricator and required accessories. Location: Clair

Plan Number: A1D.012.

Area: Drill Floor and Pipe Deck

Is a diagram/sketch of lifting operation enclosed? Yes Weight of load: Slickline unit - assessed - 2000 kg.

Lubricator - assessed - 2000 kg.

Lifting equipment and accessories to be used (specify type, SWL and colour code): 2 x 16” 4Te SWL sheaves, varied amount of 3.25Te, 4.75Te, 12Te, 25Te SWL bow shackles, 1 x 10Te SWL T-bar lift nubbin, 2 x 1.8Te SWL x 6 metre Dyform soft eye wire slings. 500Te SWL travel block, 50Te SWL North Pedestal Crane. 2 x 8Te SWL x 8 metre crane pennants. 500Te SWL bales. 2 x 3Te SWL lever hoists, various lengths of 3Te SWL soft eye wire slings. All lifting operations require the following to be considered but this list is not exhaustive: • Is the lifting equipment designed for the task? • Weight, size, shape and centre of gravity of load. • Method of slinging/attaching/detaching the load. • Availability of approved lifting points on load. • Pre-use equipment checks by operator. • Proximity hazards, obstructions, path of load. • Conflicting tasks in area.

• Is the SWL marked on all lifting equipment and accessories? • Working under suspended loads. • Overturning/load integrity/need for tag lines. • Environmental conditions including weather. • Experience, competence and training of personnel. • Number of personnel required for task. • Communication requirements.

Pre-task activity: Remove conveyor (refer to Lifting Plan - A1D.003). Transfer equipment under 5Te from pipe deck to rig floor (refer to Lifting Plan - A2G.017). Pre-assemble lubricator and BOP on catwalk. Pre-rig load cell and sheave. Transfer of wire line BOP and accessories from pipe deck to drill floor: 1. Adhere to Clair Lifting Plan A2G.017 - Transfer of Loads under 5Te SWL from Pipe Deck to Drill Floor using Draw Works. Installation of slick wire line unit: 2. Attach the slick line unit to the north 50Te SWL pedestal crane using the pre-rigged 5 leg SWL bridle assembly and land the unit on the pre-fabricated base frame on the pipe deck, at the designated worksite, south of the knuckle boom crane. Unhook the 50Te SWL pedestal crane and de-rig the 5 leg SWL bridle assembly. Slick line unit may need to be anchored to the pipe deck using 2 x 3Te SWL lever chain hoists and 4 x 3Te SWL of suitable length soft eye wire slings.

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Installation of Lubricator: 3. Attach 2 x 1.8Te SWL x 6 metre Dyform soft eye wire slings to the pre-assembled lubricator with a double turn and choke method. 4. Attach suitable length of tag line. Attach the 2 x 1.8Te SWL x 6 metre soft eye wire slings to the 2 X 8Te SWL x 8 metre crane pennants on the north crane and hoist up to the required height and slew in a westerly direction, towards the drill floor and hold. Lower off on the crane and land the lubricator on suitable dunnage and unhook the 2 x 8Te SWL x 8 metre pennants. Attach the 500Te SWL travelling block to the 10Te SWL T-bar lift nubbin assembly master link using a suitable length 2 x 3Te SWL soft eye wire slings choked round the 500Te SWL bales and joined with a 3.25Te SWL safety pin bow shackle. 5. Attach 1 x 8Te swl x 8 metre pennant to the lubricator at the opposite end, using 1 x 1.8Te swl x 6 metre soft eye wire sling double wrapped and choked. Hoist up on the crane and travelling block in unison to the required height and hold. Transfer the lubricator by lowering off on the crane and hoisting up on the travelling block. Once the total weight of the lubricator is on the travelling block, lower off on the crane and unhook. Lower off on the travelling block and land the lubricator on the BOP and secure. Take the agreed amount of strain on the travelling block and hold. Maintain the tension on the travelling block throughout the wire line operation. TO REMOVE OR RE-INSTATE, USE THE ABOVE METHOD IN REVERSE. Steps taken to eliminate danger to personnel involved and others, including barriers where appropriate: • Crane operations to be carried out in accordance with SOP-043. Wear correct PPE. Barrier the work area. Safety Harness and Inertia to be worn if working at a height where there is a possibility of falling. Maintain good communication between all work parties involved in the task. Use correct manual handling techniques. De-brief and learning points:

Prepared By:

Jocky Riddoch

Authorised By: Gary Taylor

Rev. 1, April 2010

Signature:

Date: 22-11-04

Signature:

Date: 18-07-08

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4.3 Provision and Use of Work Equipment Regulations (UK) References: Functional Expectations of WSL • 2.2.7 The WSL shall ensure that there is a programme in place for Safety Critical Maintenance and that it is being followed. • 2.2.10 The WSL shall ensure that all portable equipment supplied for use on the rig is inspected and assessed in line with legislative requirements. • 2.5.7 The WSL shall ensure that equipment is run within its operating limits and is rated for the intended purpose. SMS Documentation • UKCS-SOP-005 - Control of Hired and Transportable Equipment. • UKCS-TI-017 - Guidance On PUWER.

4.3.1 PUWER Statutory Instrument The Provision and Use of Work Equipment Regulations (PUWER) was first introduced in 1992 and then updated through SI 2306 in 1998. The Statutory Instrument stipulates that any risk arising from equipment used in the workplace is to be eliminated or controlled. Mitigation of risk may be achieved by using either "hard controls" such as guards, interlocks, etc., or by using "soft controls" such training or procedures. PUWER covers both fixed and mobile equipment and requires that all tools, devices and plant are: • Suitable for their intended use. • Safe for use, that it is maintained in a safe condition and when necessary, inspected to ensure that this remains the case. • Used only by people who have received adequate information, instruction and training. • Accompanied by suitable safety measures, e.g. protective devices, markings and warning signs.

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The regulations apply to any site where the Health and Safety at Work Act operates. All equipment, from a sledgehammer to the Topdrive, is covered and it is the employer alone who is deemed the responsible party. The full life cycle is covered, including equipment construction, installation, starting, stopping, repairing, modifying, maintaining and transportation. 4.3.1.1 PUWER Assessments PUWER assessments are typically carried out using structured checklists. Two examples are shown below; one covers temporary or hired equipment, while the other deals with permanent rig equipment.

Hired or Temporary Equipment PUWER Assessment Checklist Equipment Description and ID ................................................................................................... Intended Installation ................................................................................................................... Assessment Carried Out By ....................................................................................................... Date of Assessment ................................................................................................................... Requirement

Yes

No Comments/Exclusions

Is the equipment of a suitable design and intended for the task and location for which it is to be used? Is there documentary proof of regular maintenance? Can all required maintenance be carried out? Is use and maintenance of the equipment restricted only to authorised, trained personnel? Are persons who will use the equipment, including standby/watchkeeping personnel, adequately trained? Has equipment been inspected before first use? Has sufficient, easy to understand information been provided to enable safe use of the equipment? Have risks of using this equipment been fully identified, assessed, documented and controlled? Is protection provided to protect persons from danger caused by moving, rotating, hot or cold parts?

Rev. 1, April 2010

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Wellsite Leader’s Handbook Requirement

NSDC-00X-001.00U Yes

No Comments/Exclusions

Are controls provided to start, stop and isolate the equipment from power sources, in both normal and emergency situations? Is equipment subject to CE marking and if so is it affixed? Are systems in place to ensure no persons are exposed to risk as a result of equipment starting or operating? Where appropriate, have visible or audible warning devices and barriers been put in place? Is there sufficient lighting? Is equipment stable and properly anchored in place? Are passengers prohibited from riding on equipment? Is equipment provided with a means to stop unauthorised use? Are controls fitted for braking and stopping? Are there emergency controls to brake and stop if main controls fail? Does the equipment operator have an unrestricted view of the work environment? Has the equipment itself and the area in which it will be used been checked for potential dropped objects? Equipment Supplier: Name: ................................. Sign: ................................. Date: .................... Equipment Supplier: Name: ................................. Sign: ................................. Date: ....................

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PUWER Assessment Checklist (Rig Equipment) Asset

Assessment No.

Assessor

Equipment System No.

Equipment/System Description Item Question 1.

Are there any dangerous parts of machinery? If work equipment could cause injury if it is being used in a foreseeable way, it can be considered a dangerous part.

2.

Is the equipment unsuitable for its intended use? Typically, incorrectly rated, there is a requirement for improvisation, etc.

3.

Is there alternative equipment that could be used that may prove to be less hazardous? Example: scissors instead of knives, electrical as opposed to pneumatic power, etc.

4.

Is there a requirement to modify the design, equipment layout, access, working height, reach distances, etc. to make the equipment (more) compatible for equipment users?

5.

Are there any hazards associated with using this work equipment in the proposed or existing work location? Example: exhaust fumes build-up in an enclosed space.

6.

Is there a reasonable likelihood of any article or substance being ejected or falling from the equipment, any part of the equipment rupturing or disintegrating, the equipment catching fire or overheating, or of the equipment or any article or substance produced, stored or used by it exploding?

7.

Are there any other likely foreseeable uses this equipment could be used for, for which it is not suitable? Non-intended use/abuse.

8.

Is there still a requirement for the equipment to be tested and commissioned?

9.

If testing has been performed and there is a requirement for the test status to be known, is the test status unclear?

10.

If this is temporary portable equipment, is the last inspection report unavailable?

11.

Are the means of access for performing maintenance, inspection or test activities likely to put personnel at risk?

12.

Does this equipment appear to be poorly maintained or has it deteriorated into a hazardous condition?

13.

Are there likely to be any hazardous substances generated by the equipment, or nearby equipment, that may cause harm when performing maintenance, inspection, cleaning tasks, etc. Typically, brake dust, decomposed oils, etc.

14.

Are the anticipated tools and processes necessary to perform maintenance, inspection, testing, etc. likely to be unsuitable for the area where the equipment is located, e.g. electrical test equipment?

Rev. 1, April 2010

Yes

No

N/A

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Item Question 15.

Is there a requirement to have operating instructions attached/placed near to the work equipment? Information and instructions require to cover health and safety aspects arising from the use of the equipment, limitations on the equipment’s use(s) and any foreseeable difficulties that could arise and the methods to deal with them.

16.

Are additional warning or prohibitive signs required for the reasons of safety?

17.

Is there a requirement to deny the use of this equipment to non competent/ trained personnel through locks, passwords, etc?

18.

Could personnel be injured through contact with hot or very cold equipment, parts of work equipment, or articles or substances in the equipment?

19.

Do you consider that there is a requirement to have personnel trained in the use of this equipment? Typically, training, or further training is required when the risks to personnel change due to changes in their working tasks, when new technology or equipment is introduced, or if the system of work changes.

20.

Do the equipment's controls/isolations fail to activate the equipment's functions as intended? Alternatively, could the activation of the controls result in the equipment performing in a hazardous manner? Answer NO if you have had the opportunity to function check the controls and the controls reacted as intended. Answer YES if you have not had the opportunity to function check all the controls, or you have function checked the controls and they did not perform as required.

21.

Can the equipment be started by any other means other than that of the control purposely fitted for starting the equipment?

22.

Upon restoration of the power supply, or for example after an interlocked hatch has been closed, will the equipment start up without a control being activated?

23.

Is it possible to change the operating conditions of this equipment (speed, pressure, temperature, power) without the activation of a control, unless the change does not increase risk to personnel?

24.

Is the operator of this equipment put at risk by the location of the controls?

25.

Is there a requirement to add any markings or signs to the controls in order to clearly identify their function?

26.

Is it possible for the stop functions not to override the start functions? Answer YES if you have not had the opportunity to function check all the stop controls.

27.

Is the position of this equipment's controls likely to result in the controls being inadvertently activated?

28.

Are the controls likely to become inoperable due to damage, contamination or build-up of residue, dust or other contaminants?

29.

Are any of the required indicators out of sight of the operator stationed at a control position?

30.

Is there a requirement to give a warning of imminent start-up of the equipment to personnel on or around the equipment?

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Yes

No

N/A

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Item Question 31.

Where equipment is fitted with more than one start control, is it possible for operators to put each other in danger? Typically, if there are two start buttons at different locations.

32.

Does the equipment require an emergency stop?

33.

Does the equipment require additional emergency stops? Typically when the equipment is located between 2 rooms, or, danger zones are located in several areas not in view of the operator.

34.

Does the location or visibility of controls, i.e. emergency stop(s)/isolation(s) make them obscure to persons requiring to activate them?

35.

Could the location of the controls, i.e. emergency stop(s)/isolation(s) be improved in anyway to enable them to be activated more expediently?

36.

If the equipment is linked, or works in conjunction with other equipment, is there a requirement for the emergency stops to be linked?

37.

Does the emergency stop permit any function or control of the equipment to continue after it has activated? Answer NO if there is a continued function or control if it is for the purposes of reducing risk. Answer YES if you cannot function the emergency stop(s).

38.

Would the failure of one power supply when the equipment has multiple power supplies leave the equipment in a hazardous situation? Example: If there was a loss of air supply, would the fact that the electrical supply remained cause a hazardous situation?

39.

Would the failure of the power supply result in a dangerous situation? Typically, dropping of a load or leaving the equipment out of sequence.

40.

Is lighting in the area where the equipment is located, will operate in , inadequate for all foreseeable operations?

41.

Is the lighting likely to dazzle personnel, cause dangerous shadows, or obscure monitor screens?

42.

Is there a requirement for suitable lifting points to be fitted in order for the equipment to be moved in a safe manner if necessary? Example: maintenance activities.

43.

If the equipment is hand portable, is there a need for suitable handles or handholds to be fitted in order for the equipment to be moved in a safe manner?

44.

Does it appear that the equipment is, or could become, unstable during any stage of the equipment's life cycle?

45.

Could feeds/returns to/from the equipment constitute a trip or snag hazard?

46.

Could feeds/returns to/from the equipment become unsafe due to insufficient support or routing?

47.

Could the equipment’s power supply become unsafe due to insufficient support or routing?

48.

Is it likely that the equipment's power supply could be inadvertently reconnected due to the lack of suitable, clearly marked, lockable isolation point(s)?

Rev. 1, April 2010

Yes

No

N/A

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Item Question 49.

Is it likely that residues, cuttings, etc., will be discharged/disposed of in an unsafe and/or environmentally unacceptable manner?

50.

Does the location of this equipment produce or contribute to any collision points, restrictions to emergency exits, block LOS detectors, etc? It should be noted that the location of work equipment will have some impact upon the immediate vicinity.

51.

Is it possible to bypass any guards or protection devices without the need for tools, keys or passwords? Guards should be assessed to ensure the possibility of contact between the guard and moving part(s) is excluded; in addition, personnel should not be able to reach dangerous parts of machinery through the guard.

52.

Are there any additional guards/barriers required to be fitted to exclude/ shield personnel from other hazards associated with the equipment? Typically, radiation, high/low temperature surfaces, etc.

53.

If plugs, adapters or couplings are used to transfer power or control functions, is it possible to inadvertently connect to an incorrect power source or control line? Factory made connections are not likely to be an issue if the equipment has been commissioned.

54.

Is the equipment unsuitably rated for the zone of use?

55.

If it is undesirable in the location where the equipment is sited/will operate, is it possible that the equipment could discharge static electricity or produce arcs or sparks?

56.

Do you consider that the equipment produces high noise levels? If YES, a noise survey should be considered in accordance with the Noise at Work Regulations.

57.

Do you consider that the equipment produces vibration that may be harmful or hazardous to personnel? If YES, a vibration study should be considered to confirm that levels of whole-body vibration to which personnel are exposed are within limits as defined by HSE guidance.

58.

Do any associated work platforms, walkways, etc., have any slip, trip or fall hazards?

59.

Is it likely that any warning signals generated by the equipment (visual or audible) could be overlooked/misinterpreted by the person(s) the warning is aimed at?

60.

If this equipment is used for lifting or hoisting purposes, is there a requirement for the maximum lifting/hoisting conditions to be clearly marked on the equipment? Answer NO if the equipment is already suitably marked.

61.

Is there still a requirement for the equipment to be assessed to the requirements of EC Directives providing for CE marking?

62.

Does the CMMS require updating to include new tagged equipment and new/amended scheduled maintenance?

63.

Are there Safety Critical Elements yet to be identified in the CMMS?

Yes

No

N/A

N.B. If the scope of assessment includes self propelled, mobile equipment or power presses, please revert to the WGE Integrity Engineer as there are additional requirements to be included in the assessment. page 48

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Wellsite Leader’s Handbook Item No.

NSDC-00X-001.00U

Comments/Non-Compliant Items from above Details of Findings/Comment

Risk Reduction Measure

Date Clear

GENERAL NOTES This check list can be used to test any equipment's compliance with PUWER and does not replace any formal audit, (external or internal) but may be used to prompt one. PUWER Compliance Questions to be addressed to the Equipment(s) suppliers representatives and/or authorised agent/authority. Identified/presumed breaches of PUWER will be assessed by the relevant BP authority. If an Engineering Query (EQ), Technical Query (TQ) or Request For Information (RFI) is raised as a result of a non-compliant item being identified, the item will remain on the System Punch List until the EQ, TQ or RFI is answered, complete and closed out. In order to be assessed as PUWER compliant, all questions on the checklist must answer ‘No’ or ‘N/A’. Any questions that answer ‘Yes’ or have not been answered will require controls to be put in place (see Risk Reduction Measures) before the equipment is brought into service. Any questions that are greyed out are unanswerable until the equipment is installed offshore, and will therefore automatically be added to the Final Commissioning Punch List. Questions indicated in the "Item" column by white writing on a black background have been assessed and answered by a Visual Check, carried out by competent person. Items indicated in the "Item" column by black writing on a white background have been assessed and answered by the use of appropriate documentation (vendor data books, etc.) or other appropriate means, e.g. statements by competent personnel. 4.3.1.2

BP OPERATING ACCEPTANCE AUTHORITY

I HEREBY DETAIL THE FINDINGS OF THE PUWER COMPLIANCE INSPECTION AND CONFIRM THAT FINAL ACCEPTANCE IS SUBJECT TO RESOLUTION OF ANY LISTED NON-COMPLIANCE ITEMS. SIGNED _______________________________________________

4.3.1.3

DATE _______________

PUWER PERFORMING/CLEARANCE AUTHORITY

I HEREBY ACCEPT THE FINDINGS OF THE PUWER COMPLIANCE INSPECTION AND RESPONSIBILITY FOR RESOLUTION OF LISTED NON-COMPLIANCE ITEMS IDENTIFIED . SIGNED _______________________________________________

Rev. 1, April 2010

DATE _______________

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4.4 COSHH Requirements References: Functional Expectations of WSL • 2.2.5 The WSL shall ensure that all planned activities are risk assessed and adequate mitigations are in place. • 2.2.12 That all chemicals used on site are in accordance with local environmental legislation. • 2.2.13 That procedures exist for the segregation of waste and that all waste materials backloaded from the rig are done so in accordance with company and legislative requirements. • 2.2.15 That there is adequate spill preparedness. • 2.2.17 That the installation's EMS (Environmental Management System) is fully implemented. SMS Documentation • UKCS-HH-009 - COSHH Management. • HSE Guidance on COSHH - INDG 136 Rev 4.

4.4.1 COSHH Regulations The Control of Substances Hazardous to Health (COSHH) Regulations came into effect on the 1st October 1989. COSHH sets out the principles of occupational health and safety in relation to solid, liquid and gaseous substances. The Statutory instrument covers all substances, including bacteria, which may constitute a hazard to the health of people working with them. The three noted exceptions are radioactive sources, asbestos and lead which were already covered under separate legislation. The regulations apply to any site where the Health and Safety at Work Act operates and the responsibility for compliance lies with the employer. Employees do have duties under the regulations; they are required to make full and proper use of any control measures, including personal protective equipment (PPE), provided by their employer and also to report any defects found in this equipment. A comprehensive list of roles and responsibilities is available within UKCS-HH-009; however the main responsibilities under the COSHH regulations are that: page 50

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• A COSHH Co-ordinator is appointed for each installation who will report to management on all aspects of the local COSHH programme including achievements, failings and problems for which management action may be required. • A system exists to maintain site chemical inventories and Material Safety Data Sheets (MSDS). • COSHH assessments are carried out where there is a likelihood of any employee being exposed to any substance hazardous to health. • The correct hierarchy of risk control is applied, i.e. elimination, substitution, engineering, procedural and then only as a last resort, PPE. • An LEV Register is maintained and that levels are checked at a maximum of 14 month intervals. • A system exists whereby employees are made aware of the hazards associated with their work activities and of the necessary precautions to be taken. • A system of monitoring exists to confirm the adequacy of the control measures. Health surveillance will be carried out where appropriate. • Alignment exists with Contractors and third party COSHH processes. • A process exists to review and audit the site COSHH system and that actions arising are linked within the SMS tracking system.

4.4.2 COSHH Assessments It is both company policy and a legal requirement that all activities are risk assessed, that hazards are identified and adequate controls introduced to mitigate such hazards. Various systems are available to help the offshore team assess and control hazardous chemicals. BP's “COSHH net” system holds a large library of assessments carried out on a variety of installations and is available on the web at: http://coshh.bpweb.bp.com The style of assessment is unimportant. However people must have been properly trained and be competent to act as COSHH assessors. It is vital they have a proper understanding of maximum Exposure Limits (MEL) and Occupational Exposure Standards (OES). A COSHH assessment should not be seen as a glorified MSDS sheet. It is not sufficient to assess a single chemical; it is the overall activity in which this chemical is to be used which must be considered.

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It is important that the correct team carry out the assessment. As well as the formal training required of the assessor, the team should be made up of suitably qualified people to be able to introduce the correct hierarchy of control, i.e. elimination, substitution, engineering, procedural and then only as a last resort, PPE. A suggested flow diagram is shown opposite covering the steps needed to create an effective COSHH assessment and an example of an actual COSHH assessment.

4.5 Chemicals and Bulks Requirements (OCR and OPPC etc.) References: Functional Expectations of WSL • 2.2.5 The WSL shall ensure that all planned activities are risk assessed and adequate mitigations are put in place. • 2.2.12 That all chemicals used on site are in accordance with local environmental legislation. • 2.2.13 That procedures exist for the segregation of waste and that all waste materials back loaded from the rig are done so in accordance with company legislative requirements. • 2.2.15 That there is adequate spill preparedness. • 2.8.3 Ensure that there is no single point failure mechanism within the fluids containment system. This should include mud pit valves, flow line valves and overshot packers. SMS Documentation • Offshore Chemical Regulations, OCR for Wells, 2002. • Oil Pollution Prevention and Control, Regulations, OPPC 2005. • UKCS-DWO-002 Communications with UK Government Agencies. • UKCS-ENV-020 Procedure for compliance with OPPC Regulations. • UKCS-ENV-026 Procedure for compliance with OCR Regulations. • GP-10-25 Group Practice on Waste and Fluids Pollution Risk Mitigation.

4.5.1 OCR Regulations The Offshore Chemical Regulations (OCR) came into effect in 2002. The OCR regulations require a permit for the use and discharge of all chemicals that are used in offpage 52

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COSHH Process Summary STEP 1

Hazard and Task Identification Gather information on the: G individual tasks G chemical agents present G hazardous effects (MSDSs etc.), exposure potential by inhalation, ingestion and skin contact G existing controls

STEP 2

STEP 3

Risk Assessment

Additional Measures

Make a balanced and informed judgement on the: G risks to health for each task G adequacy of existing controls Utilise any or all of the following techniques to assist with this step: G observation G inquiry G workplace monitoring (where appropriate)

STEP 4

Specify any additional measures necessary to: G prevent or adequately control the identified exposure potential G meet any additional regulatory requirements, such as: - maintenance of control measures - exposure monitoring - health surveillance - provision of information, instruction and training to persons likely to be exposed

Record Keeping Record the Risk Assessment, with all findings and recommendations, in a format suitable for easy use, retrieval and long term archiving.

STEP 5

Review Risk Assessments are "living" documents and must be reviewed when no longer valid, i.e. due to: G any changes to chemical agents, tasks, controls, people, etc. G the defined review frequency, e.g. every 3 years

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shore oil and gas operations. The use or discharge of a chemical without a permit, or not meeting the permit conditions, is an offence. BP rules go beyond the legal requirement and state that no chemical will be shipped to an offshore installation without being covered under an approved permit. Any non-compliance with the Offshore Chemical Regulations, e.g. using more than 110% of the stated amount of chemical on the Permit, must be reported to the Department of Energy and Climate Change (DECC) within 2 days. Chemicals included within the OCR requirements are: pipe and casing dopes, water based and oil based muds and chemicals, cementing chemicals, completion chemicals, workover chemicals, hydraulic fluids discharged from Xmas trees and wellheads, treatment chemicals, rig wash, casing and tubing thread-lock compounds. Chemicals excluded from the OCR requirements include: lubricants and fuel oils, firefighting foams and oil spill response chemicals, wireline/braided line greases, general hydraulic fluids, paints and lab chemicals. Onshore applied dopes, thread protection and locking compounds are also excluded. Fluids for closed system BOPs, DHSVs and Xmas trees are excluded, but they must be CEFAS approved. The OCR permits are called Petroleum Operations Notices or "PONs". Various PONs are issued to cover different aspects of the business. PON 15B

Term Permit (e.g. one well)

Drilling and Completion chemicals used on new wells.

PON 15C

Term Permit

Subsea and pipeline chemicals.

PON 15D

Life Permit

Production and Utility Chemicals (including routine Well Intervention chemicals).

PON 15E

Term Permit

Decommissioning chemicals.

PON 15F

Term Permit

Well Intervention and Workover chemicals.

4.5.2 OPPC Regulations The Oil Pollution, Prevention and Control Regulations (OPPC) came into effect in 2005 and replaced the old Prevention of Oil Pollution act (POPA). The OPPC Regulations require a permit to control the discharge of oil to sea, or the re-injection of drilled cuttings which contain reservoir hydrocarbons. The permits are again issued by DECC and cover either "life" tasks such as the discharge of produced water, or "term" permits which cover short duration activity such

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as the non-routine discharge of water based mud contaminated with reservoir fluids. Oil discharge permits are not required for the discharge of hydrocarbons already covered under a PON 15. An application for an OPPC permit must be made at least 28 days before being required. Any spill to sea (i.e. unplanned release of oil or chemicals to sea), regardless of the volume or whether it is on the PON or Permit, must be declared to the DECC using a PON 1 form within 6 hours of the incident. The regulations require that samples are taken of any oils discharged and that the exact volumes and details of the discharge are reported back to DECC as the regulatory authority.

4.5.3 Chemical Tracking Offshore; Roles and Responsibilities Chemical usage against permitted volumes on the PON is tracked offshore using the system from the company Metoc. The system accounts for chemicals, both used and discharged, and measures these quantities against those allowed within the PON. The Pontrax system will also generate the EEMS report (Environmental Emissions Monitoring System) which is a legislative requirement of the DECC. Clear roles and responsibilities required by the OCR and OPPC Regulations are detailed within, UKCS-ENV-020 and UKCS-ENV-026. The offshore responsibilities associated with compliance with the PON permit are as follows: • Wellsite Leader: Responsible for ensuring that all chemicals stored and used are on the PON 15B, properly tracked and reported to the PON administrator at the end of the well. Responsible for ensuring PON 1s are issued as necessary. Notes: - On rigs not owned by BP, such as semi-submersibles, the rig OIM is responsible for submitting PON 1s, not the Wellsite Leader. - The Senior Drilling Engineer (not the Wellsite Leader) is responsible for reporting non-compliances to DECC. • Night Wellsite Leader: Responsible for management of the PON 15B tracking system and ensuring that inputs are made or supplied by relevant offshore supervisors and for reporting any issues to the Wellsite Leader. Typically as a minimum should perform an audit of the system (and chemicals on board) each hole section once the new chemicals are onboard and the previous hole section chemicals have been backloaded.

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• Mud Engineer: Inputs weekly usage of fluids and chemicals into Pontrax and alerts Wellsite Leaders if nearing a limit for a hole section. Note that in some places he or she also enters used volumes of pipe dope (from a weekly summary given by the offshore Materials Co-ordinator) and casing dope (from a summary after each casing job given by the casing hands). • Cementing Engineer: Inputs or supplies weekly usage of cementing fluids and chemicals for tracking and alerts wellsite leaders if nearing a limit for a hole section.

4.5.4 Best Practice when Transferring Bulk Fluids The majority of mud spills to sea happen during bunkering operations. Group Practice GP 10-25 recommends the following practices be written into the bunkering procedure for the transfer of bulks to and from offshore installations: • The integrity of the bulk hoses, connections, lines, tanks, valves and pumps is to be checked before the start of bunkering operations. • Double valves are to be fitted to any system capable of discharging hazardous materials. Similarly tanks are to be fitted with high level alarms and all overflow points are to be bunded. • The transfer pressure is to be controlled and monitored so as not to exceed the maximum safe working pressure of the loading system. • The actual volume being transferred is to be monitored throughout the operation. •

Adequate and direct communications are to be maintained between the people controlling the transfer on the vessel and on the installation. Good communication is vital so that the transfer can be shut down immediately problems arise.

• Personnel are to remain on continuous duty throughout the operation and monitor the loading hose along its entire length. • Bulk hoses must be leak tested following the change-out of any component. • The preference is to bunker during hours of daylight, however should night-time bunkering be unavoidable then a formal risk assessment should be carried out. • Similarly a risk assessment should be carried out if it is planned to bunker two hydrocarbon products at the same time. • Fluids transferred should be sampled for any signs of contamination and a final delivery figure reconciled with the vessel. • The written procedures are to give guidance on the actions to be taken should a leak or a spill occur. page 56

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Company policy is to change out hoses after a maximum of two years. However the following table offers a risk based approach to the testing and routine change-out of bunkering hoses.

Hose Testing and Change-Out Frequency (N.B. All hoses are to be thoroughly examined before bunkering)

Hose Service

Pre-Bunker Test Medium

6 Monthly Test Medium

Test Pressure

Change-Out Frequency

Water

Visual only

Drill Water

5 bar

24 months

Brine

Visual only

Drill Water

5 bar

18 months

Cement

Visual only

Air

5 bar

18 months

Barite

Visual only

Air

5 bar

18 months

Mud

Drill Water

Drill Water

5 bar

12 months

Base Oil

Nitrogen

Nitrogen

5 bar

12 months

Diesel

Nitrogen

Nitrogen

5 bar

12 months

When backloading slops and other waste fluid to supply vessels, the following precautions are to be taken: • The Mud Engineer is to test the slops for H2S and enter the result in the fluid analysis form. The form, complete with the test results, will be passed to the boat along with the relevant COSHH and MSDS information. • Even if no H2S is found, any fluid which has the potential for producing H2S will be dosed with biocide (Mud Engineer to confirm the exact dose rate required, however 0.2 litres/bbl Safecide or Starcide would be typical). • Clean fluids such as unused brines do not need to be dosed unless a dirty tank is being used. • The COSHH and MSDS information for the biocide used must also accompany the analysis form. • The chemicals used to dose the slops are to be tracked through the PON 15 system.

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4.5.5 Emergency Discharge of Whole Cement Although it is a legal requirement to comply with both the OCR and OCCP Regulations, DECC recognise that at times, operations will require the unplanned discharge of chemicals to sea. If, for example, a cement job has gone badly wrong and the WSL needs to discharge the mix to sea, then a facility does exist to raise an emergency variation to the permit. In the first instance the WSL should phone the DECC emergency call number and let the duty contact know that an emergency variation is required. DECC “day” emergency number 01224 254058 DECC “out of hours” number 020 7215 3505 or 3234 Once initial contact is established, then a written variation request is made by E-mail to [email protected]. If the request is successful, then permission is granted by return e-mail. There are 14 questions that the DECC inspector will require answering, so it is advisable that the WSL has these facts and figures to hand: 1.

Date of the variation request?

2.

Full company name as appears on the Permit?

3.

PON 15 Permit Number?

4.

Installation Name?

5.

Full chemical names?

6.

Chemical type and reasons for use/discharge?

7.

Are chemicals being requested for operational use/discharge, or disposal?

8.

Are chemicals included on the CEFAS approval list?

9.

Are chemicals PLONOR (Pose Little Or No Risk) as defined by OSPAR?

10. What is the chemical OCNS category (A to E) for non-CHARMable chemicals or Hazard Quotient, HQ, for CHARMable chemicals (or Risk Quotient for comparable CHARMable chemicals)? 11. Quantities to be used, in kg? 12. Quantities to be discharged, in kg? 13. Are the requested chemicals replacing those of the same OCNS category/HQ ranking, and are the discharge quantities the same or less than those being replaced? page 58

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14. Provide health and safety and/or technical/or operational reasons why this emergency chemical variation is required. A formal permit variation is then required within 2 working days of the incident.

4.6 Working with Radiation References: Functional Expectations of WSL • 2.2.11 The WSL shall ensure that the transportation, storage and use of Radioactive sources is in line with the installation SMS requirements. SMS Documentation • UKCS-SOP-004 Working with Radioactive Materials.

There are many possible forms of radiation at a wellsite, including nuclear sources used in downhole logging tools, naturally occurring radioactive material (NORM) on equipment pulled from older wells and pip tags run in hole for depth correlation at a later date. A specific requirement of the Regulation 17 of the UK Ionising Radiations Regulations 1999 (IRR99) is written local rules (i.e. procedures) for work with ionising radiation. It also states that the radiation employer, i.e. BP, shall: • Take all reasonable steps to ensure that relevant rules are observed. • Ensure that all relevant rules are brought to the attention of employees and those who may be affected by them. • Appoint one or more radiation protection supervisors to secure compliance with these rules (and record their names in the local copy of the rules). UKCS-SOP-004 details 19 local rules for working with radiation onshore and 29 local rules for offshore. BP has prepared these procedures for work with the sources which it owns or controls and for work with NORM. Contractors who work with their own sources are covered by their own procedures, but these must comply with BP's required working practice for the operation being undertaken and BP will check that these procedures are being adhered to. The working practices for common operations of contractor-owned sources are included in these procedures.

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4.7 Reporting of Injuries, Diseases and Dangerous Occurrence Regulations, (UK) The Reporting of Injuries, Diseases and Dangerous Occurrence Regulations 1995, SI 1995/No. 3163 (known as RIDDOR) lays down requirements for reporting injuries and occupational diseases and dangerous occurrences to the Health and Safety Executive. Under RIDDOR, an injury is reportable to the HSE or its local enforcing authority if: 1.

It is a “major” injury as defined in the regulations. This includes amputation, fractures other than fingers, thumbs or toes and injuries requiring a stay in hospital of more than 24 hours.

2.

It incapacitates the injured person from work “of a kind which he might reasonably be expected to do under his contract of employment or in the normal course of his work” for more than 3 consecutive days.

In some cases therefore, an injury that is classified as a recordable work injury under OSHA definitions, and therefore reportable to BP Group Business Centre, will not be reportable under RIDDOR. Further information can be found at: www.hse.gov.uk/riddor.

Reportable Event

Form

Who Submits

To Whom

Onshore death, injury or dangerous occurrence

F2508

Person in charge of the premises

HSE Local Area Office

Onshore workrelated disease

F2508/A

Employer of the person (Manager Occupational Health for BP employees)

HSE Local Area Office

Offshore death, injury or dangerous occurrence (except diving)

OIR/9B

Fixed Installation Operator or MODU owner

HSE Hazardous Industries Inspectorate, Aberdeen Office

Offshore workrelated disease

F2508/A

Employer of the person (Manager Occupational Health for BP employees)

HSE Hazardous Industries Inspectorate, Aberdeen Office

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Offshore workrelated or divingrelated disease

F2508/A

Employer of the person

HSE Hazardous Industries Inspectorate, Aberdeen Office

Death, injury or dangerous occurrence during diving operations

OIR/9B

Diving Contractor

HSE Hazardous Industries Inspectorate, Aberdeen Office

Dangerous occurrence during pipeline operations

OIR/9B

Pipeline owner

HSE Local Area Office or HSE Hazardous Industries Inspectorate, Aberdeen Office

4.8 Master Equipment List (MEL) Procedures, Roles and Responsibilities The process described below, or a slight variant of it, is used for equipment on rigs in the North Sea. As an example of a variation, Clair uses the offshore Challenge Drilling Engineer (CDE) as an offshore DMC (in co-ordination with an offshore Matco and Platform Matco).The CDE manages the whole MEL system from offshore, creates section MRs, co-ordinates MRs and CNs from Service Hands offshore, physically checks that BP and Weatherford equipment is on board, provides information to Service Hands to help them to check if their equipment is on board and updates the tracker on a day-to-day basis.

4.8.1 North Sea MEL Process The Master Equipment List (MEL) is created by the onshore Drilling Engineer based on supplier requirements and cross-checked against BP owned inventory. Once finalized onshore, the MEL is e-mailed to the Wellsite Leader. A blank inventory and certification tracker is created from the MEL by the offshore Drilling Materials Co-ordinator (DMC). Existing equipment remaining from the previous well (e.g. core rental equipment) is transferred onto it. Required MRs for upcoming sections are created offshore from the MEL by the Wellsite Leader and offshore DMC. The offshore DMC then e-mails the MRs to the onshore engineer for checking and the onshore DMC who then informs the suppliers. The onshore DMC creates a 48 hour notice loadlist with details and then updates it to a 24 hour notice loadlist with details of container serial numbers, certificate expiry

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dates and MR serial numbers for each piece of equipment. Equipment is sent offshore. The offshore DMC copies data on serial numbers etc. from the supplier MR to the inventory and certification tracker. Once equipment is received and physically checked offshore, the manifest number and date received are also added to the tracker. The offshore DMC notes equipment consumed or run down hole on the inventory and certification tracker. They then prepare a consignment note to ship equipment back onshore that is not used or required (based off the inventory tracker). These CNs then form the basis of the inbound manifest which they prepare and then update the tracker accordingly with dates and manifests that the equipment left the rig.

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5. Well Control 5.1 Kick Tolerance References: Functional Expectations of WSL • 2.4.1 The WSL shall ensure that the agreed well control procedures are adopted, practiced and understood (BP's preferred method is the "Fast" shutin). This shall include posting of well control procedures in the doghouse and auditing of D1-D6 drills. • 2.4.2 Ensure containment of the wellbore is possible at all times and that a kick sheet is updated daily. • 2.4.3 Ensure that the well is always flowchecked prior to tripping, after pulling into the casing shoe and before the BHA enters the BOP. The minimum length of a flowcheck will be 15 minutes. • 2.4.10 Ensure that adequate kick tolerance calculations are made for the next 24 hours. • 2.5.14 Ensure that any pressure applied during operations or testing does not exceed the pressure rating of the casing or associated equipment. • 2.8.1 Ensure that the mud is maintained in specification and suitable materials are held onboard to enable the system to be weighted up by 1 ppg. SMS Documentation • Casing and Tubing Design - GP-10-01. • Well Control - GP-10-10. • Well Control Manual - BPA-D-002. • Casing Design Manual - BPA-D-003. • Well Incident Response Plan - UKO-D-001. • Well Activity Reporting Guidelines - UKO-D-003. • Well Control Pocket Book.

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5.1.1 Considerations Over Kick Tolerance 1.

Kick tolerance is defined as the maximum volume of influx which can be circulated out of a well without breaking down the formation at the open-hole weak point.

2.

It is now accepted casing design practice, to position the casing seat using the “Limited Kick Method”. Once the first pressure containment string is set, the kick tolerance is continuously monitored and the figure referenced on the morning drilling report.

3.

Continual monitoring of the kick tolerance is required as the calculation is a function of drilled depth, BHA geometry, mud weight, influx pressure, influx type, etc.

4.

Kick tolerance will be calculated as per the procedure set out in the Well Control Manual, BPA-D-002 (see Section 5.1.2 below for detail).

5.

On all planned wells, the kick tolerance will always be over 25 bbls based on the maximum anticipated formation pressure and the programmed mud weights (assuming formation pressure is equal to or greater than the existing mud weight).

6.

In practice, if the calculated kick tolerance falls to between 100 and 25 bbls then approval to drill ahead must be sought from the Wells Team Leader. Should the kick tolerance drop to below 25 bbls then dispensation against policy would be required, which would involve both the Wells Examiner and Wells Manager Engineering.

7.

The larger the influx the more difficult it will be to kill. In reality, drill crews will rarely catch an influx of below 10 bbls, however it is vital that all crews understand the importance of catching kicks early and are regularly drilled in well control techniques.

8.

The Well Site Leader must make the Driller and Toolpusher aware of the calculated kick tolerance figure.

9.

As several assumptions are required when making kick tolerance calculations, e.g. safety factors etc., the Well Site Leader must personally check the calculation methodology and in particular confirm that any assumptions made are indeed valid.

5.1.2 Best Practice when Calculating Kick Tolerance 1.

Several definitions of kick tolerance are used in the industry. Within BP, kick tolerance is defined as the maximum volume of influx that can safely be shut-in and then circulated out of the well without breaking down the open-hole weak point.

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The calculation below considers the straight forward situation of a kick being taken on bottom, while drilling a straight hole. For more complex worked examples, refer to the Well Control Manual, BPA-D-002 and the Well Control Pocket book. N.B. The kick tolerance formulae given below will only work if the formation pressure is equal to or greater than the mud weight, i.e. it will not work for a swabbed kick! Similarly if using the Kick Tolerance calculator within “Toolkit” then the minimum pore pressure input must be either equal to, or greater than, the mud weight in use.

Kick Tolerance Schematic

Pmax = Pfb - SF expressed as EMW (sg/ppg)

V2

Hi

V3 V1

Hi

Pf expressed as EMW (sg/ppg)

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3.

Estimate the Safety Factor to be applied to the leak-off pressure: The act of circulating out a kick increases the overall pressure on the wellbore. An estimation is made to allow for the combined effect of annular friction losses, choke line friction losses and choke operating error margin. Typically this SF would be ~200 psi.

4.

Calculate the Maximum Allowable Weakpoint Pressure: PMax = Leak-Off Pressure (Pfb) - Safety Factor (SF)

5.

Calculate the Maximum Allowable Height (Hi) of Influx in open hole: Hi = _____________________________ Dwp (PMax - MW) + TD (MW - Pf_) (MW - Gi) where: Hi

= maximum allowable height of influx (m/ft)

Dwp

= vertical depth of the open hole weak point (m/ft)

PMax (EMW) = maximum allowable pressure expressed as an EMW (sg/ppg)

6.

MW

= mud weight (sg/ppg)

Gi

= gradient of influx converted to sg or ppg

TD

= bit depth (m/ft)

Pf

= formation pressure expressed as an EMW (sg/ppg)

Calculate the Volume (V1) of Height (Hi) at initial shut-in: Volume 1 = Height of Influx (Hi) x Annular Capacity (C1) where: V1 = volume of kick tolerance at initial shut-in (bbls) Hi = maximum allowable height of influx (m/ft) C1 = annular capacity over height Hi (bbls/m or bbls/ft) N.B. Should height Hi extend beyond the BHA, then both DC/OH and DP/OH annuli will need to be calculated.

7.

Calculate the Volume (V2) of Height (Hi) at the open hole weak point which is normally at the shoe: V2 = Height of Influx (Hi) x Annular Capacity (C2) where: V2 = volume of kick tolerance with kick at the shoe (bbls) Hi = maximum allowable height of influx (m/ft)

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C2 = annular capacity below the shoe (bbls/m or bbls/ft) N.B. Should height Hi extend over two hole or pipe diameters then both volumes will need to be calculated. 8.

Convert Volume (V2) to bottom hole conditions using Boyle's Law: PFormation x VFormation = PWeakpoint x VWeakpoint or Pf x V3 = (PMax x Dwp x 1.421or 0.052) x Vwp or V3 = (P Max x Dwp x 1.421or 0.052) x Vwp ________________________________________ Pf where: V3

= kick tolerance V2 at initial shut-in condition (bbls)

Vwp

= volume of influx below the open hole weakpoint (bbls)

Pf

= formation pressure (psi)

PMax

= maximum allowable EMW at open hole weakpoint (sg/ppg)

Dwp

= vertical depth of the open hole weak point (m/ft)

1.421 = conversion factor from SG to psi/m 0.052 = conversion factor from ppg to psi/ft 9.

The kick tolerance is therefore the lesser of either V1 or V3.

5.2 Shallow Gas References: Functional Expectations of WSL • 2.2.15 The WSL shall ensure that there is adequate spill preparedness. • 2.4.3 Ensure that the well is always flow-checked prior to tripping, after pulling into the casing shoe and before the BHA enters the BOP. The minimum length of a flowcheck will be 15 minutes. • 2.4.5 The WSL will be present on the rig floor to observe the first 10 stands pulled on every trip out of the hole, and until such times as he/she is satisfied

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that the hole fill volume is correct. The WSL should continue to monitor the trip until back into the old hole or inside casing. • 2.4.6 Verify the integrity of the pressure tests and operation of all well control and pressure containment equipment installed in the well. • 2.5.2 Be aware of the hole condition at all times and be able to communicate this to the onshore team as required. • 2.5.9 Verify that personnel conducting operations understand the written work instructions and are conducting the operations in accordance with them. • 2.5.14 Ensure that any pressure applied during operations or testing does not exceed the pressure rating of the casing or associated equipment. • 2.8.1 Ensure that the mud is maintained in specification and suitable materials are held onboard to enable the system to be weighted up by 1 ppg. • 2.8.5 Confirm correct fluid testing and QA/QC procedures, LCM contingency and sweep plans. SMS Documentation • Well Control, GP-10-10. • Well Control Manual, BPA-D-002. • Casing Design Manual, BPA-D-003. • Well Incident Response Plan, UKO-D-001. • Well Activity Reporting Guidelines, UKO-D-003. • Offshore Site Investigation Manual, BPA-D-005.

5.2.1 Considerations for Dealing with Shallow Gas 1.

Shallow gas represents one of the major hazards in drilling operations. Gas kicks taken at shallow depths cannot generally be shut in for fear of breaking down the formation around the conductor shoe and causing an underground blowout.

2.

Shallow gas can be defined as being any gas accumulation encountered at any depth before the first pressure containment casing string is set.

3.

During the planning stage of a well, the potential for shallow gas will be identified as part of a "shallow hazard assessment" which will include a seismic study looking for "bright spots" to a depth of around 1000m.

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As part of the shallow hazard assessment, the potential for shallow gas shall be classified using the following criteria: Classification

Description

High

An anomaly showing all the seismic characteristics of a shallow gas anomaly, that ties to gas in an offset well, or is located at a known regional shallow gas horizon.

Moderate

An anomaly showing most of the seismic characteristics of a shallow gas anomaly but which could be interpreted as not being gas and, as such, reasonable doubt exists over the presence of gas.

Low

An anomaly showing some of the seismic characteristics of a shallow gas anomaly but that is interpreted as not being gas although some interpretive doubt exists.

Negligible

Either there is no anomaly present at the location, or the anomaly is clearly due to other, non-gaseous causes.

If an anomaly is seen as being greater than negligible, then the spud location will be moved. If an acceptable location cannot be found, then shallow gas will be assumed as being present and a fully documented risk assessment will be required. 5.

For bottom supported units, a shallow hazards analysis will be carried out within which the rig foundation, the adjacent infrastructure, the Drilling Programme and the Well Control Procedures will be assessed.

6.

Most accumulations of shallow gas tend to be normally pressured, however pressure gradients of over 0.52 psi/ft or 1.2 sg (10 ppg) equivalent have been seen in the North Sea.

7.

Whenever the diverter is installed and has the potential for use, then the rig is classed as being in a "critical" drilling phase. During periods of "critical" drilling, there will be no Hot Work carried out and controls will be placed on Spark Potential Work, Wireline, Coiled Tubing, Heavy Lifts and the use of Radioactive Sources and Explosives (refer to the individual installation SIMOPS manual).

8.

Before starting to drill, mutually agreed, rig-specific, shallow gas procedures will be established between BP and the Drilling Contractor.

9.

Following installation and before drilling any hole section where diverting is the planned means of well control, the diverter will be function tested. Depending on local environmental constraints, the diverter lines will also be flushed.

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Thereafter the diverter system shall be function tested at least once every seven days. Diverter lines with rupture discs shall be inspected only. 10. For systems with a nominal bore of 20" or less, the control system will function all necessary valves and close the diverter element within 30 seconds. For systems having more than 20" nominal bore, the operating time will not exceed 45 seconds. 11. Neither the diverter assembly nor the conductor itself are designed for pressure containment, however on installations where the system will allow, then best practice is to body test the diverter assembly after it is nippled up and then to rely on regular function checks thereafter. When pressure testing diverter assemblies, the normal closing logic needs to be overcome. It is vital that after the successful pressure test, the system logic is returned to normal and the Well Site Leader witnesses a full function test. 12. Before starting to drill top hole, the Well Site Leader should confirm the condition of adjacent well annuli. Particularly on multi-well installations, surface well control situations can be caused by the formation becoming charged as a result of seal failure on another well.

5.2.2 Best Practice for Dealing with Shallow Gas 1.

Precautions to be taken when Shallow Gas is a known risk: • Whenever there is a possibility that a well may need to be diverted, then "Critical Drilling" considerations will apply. No Hot Work will be allowed and controls will be placed on other high risk activity. • An 8½" pilot hole should be considered so as to reduce the surface area of the hole and consequently reduce the rate of any influx. • A non-ported float valve will be used in all drilling BHAs run before the BOPs are operational. • Calculations should be made to investigate the flow rates required for a dynamic kill. • Shallow gas procedures will be clearly posted in the Doghouse and contingency plans will have been discussed with the Drilling Contractor and OIM. • A minimum of two hole volumes of 1.2 sg (10 ppg) kill weight mud should be available on surface. • As losses can be a major contributor to shallow gas kicks, the crew are to be ready to quickly top fill the hole using a high rate transfer pump.

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• Similarly high flowrates are to be used while drilling so as to better disperse the cuttings and reduce the risk of overloading the annulus. • ROP is to be controlled so as to guard against overloading the annulus and also to minimise the effect of a high pressure lens. • Ensure that both the rig equipment and personnel are in a state of readiness and will be able to closely monitor the hole volume and catch any signs of gas cutting as early as possible. • Shallow gas and diverter drills are to be held before spud and at regular intervals until the first pressure containment string is set. • The locking of the diverter insert will be witnessed before the start of drilling and the system will be function tested each time the insert is locked in. • Whenever the diverter is locked in place, a highly visible sign, stating that the insert is in and locked will be positioned in the doghouse. • Well Site Leader to be on the rig floor for flowchecks and trips. • Particular care will be taken while POOH to prevent any swabbing. Should gas have been seen while drilling the hole, then consideration should be given to pumping out. 2.

Procedure for diverting a Shallow Gas kick: • Preservation of life is the overriding priority in any well control situation. • The diverting procedure will be posted in the Doghouse and before spud the Well Site Leader will satisfy himself that all crews are fully aware of and practiced in the handling of shallow gas. • Because of the short travel time involved, the situation may deteriorate very quickly and so early and decisive action is vital for the safety of everyone onboard. • If a kick is taken then maintain or increase the pump rate to the maximum available. • Space out the string to position any tool-joints clear of the diverter. • Function the diverter thereby opening the overboard line and closing both the shaker valve and the diverter. • The Driller is to confirm that the well is diverting and where appropriate, he will close the upwind vent line.

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• The Driller is to switch to kill weight mud on the run and pump this away again at the maximum pump rate. • The Driller will inform the Control Room of the situation and request that production and all non-essential equipment is shutdown and that personnel be evacuated to the Temporary Safe Refuge (TSR). • Only if safe to do so will the Driller remain in the safety of the Doghouse and pump away all his available mud stocks before swapping back over to seawater. • If possible, monitor the discharge on camera and be aware of the possibility of well bore collapse. • If unsafe to remain in the Doghouse, then the Driller should evacuate to the TSR but leave the pumps running on direct seawater feed. • Driller/CCR to activate the deluge system and/or deploy fire hoses on the flow. • Well Site Leader to liaise with the OIM and consider the down-manning of nonessential personnel. • Standby vessel to monitor the surrounding area for signs of gas in the sea and deploy oil dispersant from a safe distance and upon the advice of the Onshore Duty Environmental Advisor. Should evidence of gas be seen in the water, then plans for an immediate down-man by air should be instigated. • Only if safe to do so, the Well Site Leader should ascertain the condition of adjacent well annuli as the kick may be as a result of the formation being charged from another well. • Once under control, then plans should be made to run the pressure containment string. To help recover the situation, then a barite or gunk plug may be set on bottom before the BHA is pumped out of the hole.

5.3 Well Control Practice and Procedures References: Functional Expectations of WSL • 2.4.1 The WSL shall ensure that the agreed well control procedures are adopted, practiced and understood (BP's preferred shut-in method is the "Fast" shut-in). This shall include posting of well control procedures in the doghouse and auditing of D1 - D6 drills.

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• 2.4.2 Ensure containment of the wellbore is possible at all times and that a kick sheet is updated daily. • 2.4.3 Ensure that the well is always flowchecked prior to tripping, after pulling into the casing shoe and before the BHA enters the BOP. The minimum length of a flowcheck will be 15 minutes. • 2.4.5 The WSL will be present on the rig floor to observe the first 10 stands pulled on every trip out of the hole, and until such times as he/she is satisfied that the hole fill volume is correct. The WSL should continue to monitor the trip until back into the old hole or inside the casing. • 2.4.6 Verify the integrity of the pressure testing and operation of all well control equipment and all pressure containment equipment installed in the well (casing, plugs, packers, completion, etc.). This shall include the witnessing of all downhole tests by the WSL during the drilling phase and by either the WSL or WSS/CS during the completion phase. • 2.4.7 Be familiar with the operation of any equipment installed on the rig for stripping operations. This equipment should be kept in good working order. • 2.4.8 Ensure compliance with the company's pressure containment barrier policy. • 2.4.10 Ensure that adequate kick tolerance calculations are made for the next 24 hours. • 2.4.11 Witness SCRs until satisfied procedures are correct and then ensure they are carried out on each tour. • 2.5.7 Ensure that equipment is run within its operating limits and is rated for the intended purpose. • 2.5.9 Verify that personnel conducting operations understand the written work instructions and are conducting the operations in accordance with them. • 2.8.1 Ensure that the mud is maintained in specification and suitable materials are held onboard to enable the system to be weighted up by 1 ppg. • 2.8.3 Ensure there is no single point failure mechanism within the fluids containment system. This should include mud pit valves, flow line valves and overshot packers. • 2.8.5 Confirm the correct fluid testing and QA/QC procedures are carried out and that LCM contingency and sweep plans are available.

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SMS Documentation • Casing and Tubing Design - GP-10-01. • Well Control - GP-10-10. • Well Control Manual - BPA-D-002. • Casing Design Manual - BPA-D-003. • Well Incident Response Plan - UKO-D-001. • Well Activity Reporting Guidelines - UKO-D-003. • BP Well Control Pocketbook.

5.3.1 Considerations when Dealing with Well Control Incidents 1.

Preservation of life is the overriding priority in any well control situation.

2.

During Well Control operations the rig is classed as being in a "critical" drilling phase. During periods of "critical" drilling there will be no Hot Work carried out and controls will be placed on Spark Potential Work, Wireline, Coiled Tubing, Diving, Heavy Lifts and the use of Radioactive Sources or Explosives (refer to the installation SIMOPS Manual).

3.

Clear roles, responsibilities and accountabilities will be established for all positions within the drilling and well operations organisations.

4.

Incident response plans will be maintained at every wellsite, and emergency drills will be regularly conducted and reported.

5.

All offshore installations shall have procedures in place for full evacuation in the event of an emergency.

6.

A detailed assessment of the pore and fracture pressures shall be conducted during drilling operations on both exploration and appraisal wells.

7.

Kick tolerance is defined as the maximum volume of influx which can be circulated out of a well without breaking down the formation at the open-hole weak point. Kick tolerance will be continually monitored during drilling operations.

8.

All drilling breaks shall be flow-checked and reported.

9.

For conventional rotary drilling operations, as a minimum, flowchecks shall be performed while POOH:

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• When pulling off bottom. • After pulling into the casing shoe. • Before the BHA enters the BOP stack. 10. Consideration should be given to colour coding the choke manifold valves so as to identify which valves are normally open and which are normally closed. 11. Drill crew should always confirm the number of turns required to open and close wellhead, BOP and manifold valves. Similarly the crew must be instructed on the correct procedure for relaxing the back seat on gate valves. 12. For conventional rotary drilling operations, trip sheets shall be filled out by the Driller on every trip in and out of the hole. Any deviation from the expected hole fill volumes shall be investigated. 13. The WSL shall be on the rig floor before each trip to flowcheck the well and then observe, as a minimum, the first 10 stands out and then until such time as he/she are satisfied that the hole fill is correct. 14. A minimum quantity of weighting material shall be readily available onsite during all phases of the well, to weigh up the circulating volume by 1 ppg. Individual programmes should define acceptable stock levels based on the nature of the operation and the frequency of supply. 15. A sufficient amount of cement and cement additives shall be kept on board the rig so that an appropriate isolation plug can be set in the current hole size. 16. All well operations personnel, normally down to and including Assistant Driller level, shall hold a valid and recognised well control certificate. 17. Kick detection, circulating, stripping and shut-in drills shall be held regularly until the WSL is satisfied that each crew meets BP's established standards. 18. A shut-in method shall be established, communicated and practiced. The generally preferred method is the “Fast” shut-in. The Driller is responsible for and authorised to shut the well in and the WSL is the only one authorised to open up the well. 19. A kick sheet will be updated daily and again after a change of mud weight, bottom hole assembly or formation integrity. 20. Contingency plans need to be written in case power is lost during a well control incident. The practice of running a float in the string will help to protect against being unable to stab-in a TIW valve, however rig specific plans are needed to cover the possibility that power is lost with either drill collars or stabilisers sitting across the BOP.

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21. A well control incident report will be completed immediately after any well control incident (see Well Activity Reporting Guidelines - UKO-D-003). 22. All well control equipment, except the annular BOP will be tested to the lowest of the following criteria: • The maximum anticipated wellhead pressure that will be encountered in the hole section. • 90% of the casing burst pressure. • Wellhead rated pressure. • BOP rated pressure. 23. In the event that the maximum anticipated wellhead pressure is not known with reliability, then the well control equipment should be tested to the lowest of the other three criteria. 24. Annular BOPs will be tested to a maximum of 70% of their rated working pressure if not otherwise specified. 25. Pressure testing and full function testing of well control equipment will normally be carried out every 14 days. This 14 day interval may be extended, after an appropriate risk assessment has been endorsed by the SPU Well Control TA and approval given by the Wells EA. 26. When testing the BOP after installing a new casing pack-off, it is important to monitor the seal void during the test. There is no need to unscrew the check valve, simply push the ball off its seat by using the specialist stinger cap supplied by the wellhead manufacturer. 27. The lower-most ram will be preserved as a master valve and shall only be used to close in the well when no other ram is available.

5.3.2 Best Practice when Dealing with Well Control Incidents 1.

The WSL will issue written instructions detailing the preferred shut-in method and other relevant well control details, e.g. Kick Tolerance figures.

2.

The larger the influx the more difficult it will be to kill. In reality, drill crews will rarely catch an influx of below 10 bbls, however it is vital that all crews understand the importance of catching kicks early and are regularly drilled in well control techniques.

3.

The company's preferred method of well control is to use the “Fast” shut-in procedure:

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• With the choke closed and one upstream valve to the choke also closed (make sure that this upstream valve does not isolate the pressure transducer). • Both HCR valves closed. • Come off bottom and space out to close the BOP. • Stop rotating. • Shut down the pumps. • Open the choke line HCR. • Close in the annular. N.B. Depending on the situation, e.g. when working on a platform where the exact space-out is known, consideration should be given to using the upper pipe rams rather than the annular. 4.

The Driller's responsibility is: • To fully understand the drilling instructions as explained by the Well Site Leader and practiced during well control drills. • To ensure on each shift, that the BOP and choke manifold are lined up in readiness to deal with a well control situation. • To establish SCR readings on each pump once per shift at a time agreed suitable by the Well Site Leader. • To inform his Toolpusher should any problems arise with the well control equipment. • To be aware of the most recent gauge comparison figures (actions should never be taken based on only the one pressure gauge reading). • To set his alarms in such a way, so as to catch any increase in return flow or pit level at the earliest opportunity. • To know exactly the space-out needed to position all tool joints clear of the BOP. Should the configuration of the string mean that the normal BOP spaceout is affected, than the Driller must inform his relief of this in his written handover. • The Driller will flowcheck any drilling break. • Ensure that the pop-offs are set over and above the expected circulating pressures.

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• Understand the Maximum Allowable Annular Surface Pressure (MAASP) and ensure the current figure reflects the present mud weight. • On confirmation that the well is flowing, the Driller will close in using the “Fast” shut-in method as detailed in 5.3.2.3 above. N.B. It is vital that the Driller shuts down the pumps completely. It has been known for a crew to be monitoring an ever increasing SIDPP only to discover that the mud pump is still ticking over. • Once closed in, the Driller will double check the valve line-up and confirm that there is no fluid passing the BOP. The trip tank should be run over the top of the well to check for leaks. • The Driller will record the initial shut-in drillpipe and casing pressures and then arrange to have these pressures recorded every two minutes on an event log. • The Driller will then inform the Well Site Leader and his Toolpusher of the situation. • While preparing for the kill, the Driller will continue to monitor the drillpipe and casing pressures and advise the Well Site Leader should these pressures rise. • To aid understanding and ease communication, the Driller should create a marked up schematic on a white board which clearly shows the valve line-up and current valve positions. • During the well kill, the Driller and his crew will operate the mud pumps, choke manifold and other rig equipment as directed by the Toolpusher. 5.

The Toolpusher's responsibility is: • To ensure that all personnel under his charge are trained and competent in their role, that they have a full understanding of expectations made of them and are fully practiced in their role. • To inform the Well Site Leader of any malfunction discovered on well control equipment. • To make sure that a pre-kick sheet is filled out every day. • To have all well control valves available on the rig floor. • To have spares stock available for all safety critical equipment. • To confirm that the well is secure and the valve line-up is correct. • After consultation with the Well Site Leader, the Toolpusher will lock closed the rams, and shut a secondary preventer.

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• The Toolpusher will arrange to barrier off the area around the wellhead, riser and BOP. He will position men at strategic points to watch for leaks and ensure the integrity of the system is not threatened. The wellhead pressures, including the other annulus readings, must be monitored. • He will stop all Hot Work and Spark Potential Activity in the area and organise the crews to best support the well control situation. • He will have the Barite silos charged in readiness for the well kill and have the mud weight increased as per the Well Site Leader's instruction. • He will check the setting of the pop-offs and make sure they are suitable for the kill operation. • He will make sure the mud pits are organised in such a way as to be able to handle the increased volumes and potential for dealing with hydrocarbons on surface. • The Toolpusher shall prepare the liquid seal within the poor-boy degasser. • He will check that all gas detection equipment is fully functional and that additional gas detectors are deployed as required. • He will consider the need to inhibit any fixed gas detectors in the area which may cause a system shutdown should they alarm. • The Toolpusher will complete a well kill sheet. • During the well kill operation, the Toolpusher will organise the drill crew and make sure that both crew and equipment function correctly. 6.

The Well Site Leader's responsibility is: • For the safe execution of all well control activity. • He will ensure that the rig is in compliance with all company expectations over well control equipment, practices and procedures. • He will ensure that all crews are drilled and fully competent in the handling of well control situations. • The Well Site Leader will issue written instructions detailing the preferred shutin method, the kick tolerance and his clear expectations should a well control situation arise. • He will discuss the malfunction of any safety critical equipment with his Wells Team Leader.

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• He will agree with the drilling contractor, the timing and requirement for taking SCRs. • He will make sure a kick sheet is updated daily. • Should a well control situation arise, then the Well Site Leader, in conjunction with the Toolpusher, will agree on the locking of the pipe rams and the need to close a secondary preventer. • The Well Site Leader will inform the OIM that the rig has entered a “critical” drilling phase and he will advise on whether spark potential, hot work, vessel operations or helicopter landings need to be restricted during the well kill and specifically while cold flaring. • The Well Site Leader will liaise with his Wells Team Leader, agree the forward plan and keep town informed as the situation develops. • The Well Site Leader will assess the nature of the kick and then have a kick sheet and annular pressure profile prepared using “Toolkit” or some similar well control software. • The WSL should consider the chances of bringing sour gas back to surface. • Once the nature of the kick is understood then the Well Site Leader will advise on the maximum safe liquid seal pressure that the poorboy degasser can be operated at. The maximum safe liquid seal pressure (for seals system with no hot mud flush system) = 0.3 psi/ft x seal height (ft) x safety factor. • Use 0.3 psi/ft as the gradient (based on maintaining a liquid seal with a hydrocarbon liquid influx) as specified by the HSE Offshore Safety Division Safety Notice 11/90. If the liquid seal has a hot mud flush system where the liquid seal is flushed with new mud at a higher rate than the kill rate, then the maximum safe liquid seal pressure (for seals systems with hot mud flush system) = mud weight psi/ft x seal height (ft) x safety factor. Safety factor to be decided by BP Well Site Leader. • He will monitor the drill pipe and casing pressures throughout and advise on any concerns over gas migration and the risks of exceeding MAASP. Note: MAASP is only a consideration when the influx is in the open hole; once it is inside the casing then it can be ignored completely. • He will check the completed kick sheet and decide on the factor of safety to be used during the kill (this factor of safety, or “trip overbalance” will usually be at least 200 psi). page 80

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• The Well Site Leader will arrange for the preparation of the kill fluid and will advise on the potential for dealing with hydrocarbons on surface. • He will hold a pre-kill meeting with all concerned and discuss the following detail: • • • • • • • • • • •

Individuals' roles and responsibilities during the kill. The condition of the equipment including any limitations. The planned kill method, speed and timeline. The procedure for starting and stopping the pumps. Considerations over the static and dynamic MAASP. The overbalance or factor of safety to be applied. The safe working limit of the liquid seal. The expected annular pressure profile. The pit plan during and after the operation. The plan for dealing with hydrocarbons on surface. Contingency plans in the event of equipment failure.

• During the well kill, the Well Site Leader will take overall charge of the operation. N.B. It is only the Well Site Leader who can instruct the opening of the well. • Following the well control incident, the Well Site Leader will complete an incident report within the Tr@ction system. This report will form the basis of the well incident report required by the HSE and issued by the onshore support team. 7.

As with most drilling operations the key to success in well control is good preparation. The Well Site Leader must continually consider the “what if” scenario so that he is prepared to deal with any eventuality.

8.

The Well Site Leader is looked upon to provide leadership during well control incidents and each individual will bring differing attributes to the situation. Being well prepared, aware of the strengths and weakness of team members, having the ability to listen to others and to delegate are all part of this leadership role. However the Well Site Leader must also give himself the space to be able to think through a situation and decide on the best course of action.

9.

If there is a delay before the start of the kill operation, then should gas start migrating and increasing the shut-in pressures, the Well Site Leader may want to consider lowering the annulus pressures by allowing the gas to expand. The simple way of achieving this and still balance bottom hole pressure is to bleed mud from the annulus and reduce the increased drill pipe pressure back to just above the SIDPP. See Section 5.3.4 below on volumetric well control.

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10. If the dynamic MAASP becomes an issue during a well kill, then shut in the well, check pressures and re-start well kill operation at a lower rate to help reduce the overall circulating pressures. Note: MAASP is only a consideration when the influx is in the open hole; once it is inside the casing then it can be ignored completely. 11. If the kick tolerance guidelines have been followed and the drill crew have shut in the well early enough, then there should not be a risk of exceeding the static MAASP. However should the unexpected occur, then the Well Site Leader should be prepared for this situation. If we exceed MAASP, there is a risk of breaking down the open hole weak point and the Well Site Leader would need to consider: • • • • • •

What is the nature of the kick? Are we seeing gas migrating? If so see 5.3.2.9 above. What and where is the weak point? Where is the casing shoe in relation to the weak point? Has a “Factor of Safety” been applied to the MAASP figure? Could the MAASP have improved since the leak-off test?

If we bleed down the casing pressure to stay below the MAASP, then we risk taking a further kick. Again the Well Site Leader would need to consider: • Has the kicking zone got high or low permeability? • What is the gradient of the influx - is it a gas, oil or a brine? • Where is the influx in relation to the shoe? Although circumstances will vary, unless the permeability is very low the preferred course of action would be to exceed MAASP. However this course of action must be agreed with the Wells Team Leader. 12. As the overriding concern during well control is the preservation of life, then any thoughts of working or rotating the pipe during a well control incident would need the most careful consideration. The Well Site Leader should only consider working the pipe after fully considering the possible effect on the drillpipe and the BOP sealing element.

5.3.3 Best Practice when Using Conventional Well Kill Techniques The company's preferred method for killing a well, on vertical and low angle wells, is the Wait and Weight method. The company's preferred method for killing a well, on high angle and horizontal wells, is the Driller's method.

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If the rig's mixing ability is impaired or gas starts migrating quickly up the annulus, then the Driller's method should be used. The description set out below provides a very simple outline of the two methods. For more detail on these and other kill procedures, refer to the Well Control Manual - BPAD-002 and the Well Control Pocketbook. For both methods, the Surface to Bit plus the Bit to Surface volumes are recorded in both barrels and pump strokes. The following calculations are then made: A. Initial Circulating Pressure (ICP) = SIDPP (psi) + SCR (psi) B. Kill Weight W2 (ppg) = (SIDPP(psi) ÷ TVD (ft) ÷ 0.052) + W1 (ppg) or Kill Weight W2 (sg) = (SIDPP(psi) ÷ TVD (m) ÷ 1.423) + W1 (sg) C. Final Circulating Pressure (FCP) = SCR (psi) x W2 (ppg or sg) ________________________ W1 (ppg or sg) 5.3.3.1 Wait and Weight Method 1.

This method is slightly more complicated than the Driller's method, however it does result in lower pressures at the shoe (unless the open hole volume is less than the string volume). Because the kill is achieved on the one circulation, then the Wait and Weight method results in pressure being held on the well and equipment for a shorter period of time.

2.

Once the kill weight mud is prepared then: • Bring the pump up to speed by keeping the casing/wellhead pressure constant. • Reduce the drill pipe pressure from ICP to FCP as the kill mud travels from surface to bit. • With the kill weight mud at the bit, hold the FCP on the drill pipe until the influx is out and the kill weight mud is back on surface.

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Annulus Pressure Profile for the Wait and Weight Method Bubble at Surface

Annulus Pressure

Gas Out Kill Mud to Bit Gas Migration Light Mud

Kick

Well Dead

Barrels/Time

Driller’s Method 1.

This method is easier to learn, has fewer calculations and has the big advantage of being able to circulate immediately after the kick is taken. However, the Driller's method will involve higher pressures on the shoe (unless the open hole volume is less than the string volume, i.e. the influx reaches the shoe before the kill mud can reach the bit). As the Driller's Method requires two circulations, then pressure is also held on the well for longer.

2.

The First Circulation, as it is known, is only really just a bottom's up: • Bring the pump up to speed by keeping the Casing/Wellhead pressure constant. • Maintain the ICP constant on the drill pipe till the influx is out of the well.

3.

The second circulation of the Driller's Method involves: • Again, bring the pump up to speed by keeping the casing/wellhead pressure constant. • Maintain the casing pressure constant until the kill mud reaches the bit (alternatively step down from ICP to FCP). • With kill mud at the bit, maintain the FCP until the kill mud returns to surface.

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Annulus Pressure Profile for the Driller's Method

Annulus Pressure

Gas Influx to Surface

Water Influx

First Circulation

Second Circulation

Barrels/Time

Although we draw straight lines on our step-down charts this will only be true for a uniform drillstring in a vertical well. Following a straight line in a deviated well gives an additional factor of safety, however following a straight line with a tapered string may risk going underbalance.

Annulus Pressure

5.3.3.2 Step-Down Chart for Deviated Wells and Tapered Strings

True Line for 6 5/8" pipe above 5", i.e. potential for going underbalance.

True Line for Directional Well, i.e. potential for over-kill.

Barrels/Time

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5.3.4 Best Practice when Using the Volumetric Method of Well Control 1.

The Volumetric Method of well control is strictly not a kill method but simply a procedure for controlling the release of an influx from the well. The Volumetric Method simply co-ordinates the increase and decrease of casing pressures with the amount of mud adjustment required for the bubble to migrate to surface. As it depends on the influx migrating up the well, it can only be used when significant migration is actually happening.

2.

This method can be used to reduce the well pressures while waiting to start a conventional well kill. If the bit is on or near bottom and the SIDPP can be relied upon, then the well can be controlled by simply keeping the SIDPP constant (constant BHP) by bleeding volume from the annulus. This is achieved by allowing the gas to rise and applying an overbalance margin of between 50 and 200 psi to the SIDPP. Then an operating margin of again between 50 and 200 psi is allowed to build up before the choke is opened and the SIDPP is reduced back to the overbalance margin. The procedure is then repeated until the gas arrives on surface where it is lubricated out of the BOP by: • Equalising the pressure across, and then opening the kill line HCR. • Pump 1 to 2 bbls of active mud down the kill line. • Allow the mud at least 10 minutes to fall down through the gas and then bleed down through the choke according to the following formula: Pressure to Volume Pumped (bbls) = x Mud Gradient (psi/ft or m) Bleed (psi) Annular Capacity (bbl/ft or m) • Repeat the process until all the gas has been replaced by mud at which point the pit volume should return to the level it was before the kick was taken.

3.

In circumstances where the bit is off bottom, or the SIDPP cannot be established, then the expansion of the gas can be controlled by using the Static Volumetric Method: Step 1. First establish the migration rate of the gas bubble. This is done using: Migration Rate (ft or m/hr) =

Pressure Increase (per hour) Mud Gradient (psi/ft or m)

N.B. The rate of migration will generally increase as the gas bubble approaches surface.

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Step 2. Apply an "Overbalance Margin" to the annulus by allowing the gas to migrate and increase the SICP by between 50 and 200 psi. Step 3. Then allow the gas to migrate and apply a further "Operating Margin" of again between 50 and 200 psi. Step 4. In order to allow the gas bubble to expand, we need to bleed pressure from the annulus. Calculate the equivalent hydrostatic pressure per barrel of mud for when the bubble is initially below the bit and then when the bubble is moving up the drillstring annulus: With the influx below the bit: Hydrostatic Equivalent (psi/bbl) =

Mud Weight (sg) x 445.7 Hole Diameter2 (in2)

With the influx in the Drillstring Annulus: Hydrostatic Equivalent (psi/bbl) =

Mud Weight (sg) x 445.7 Hole Diameter2 (in2) - String OD2 (in2)

or Hydrostatic Equivalent (psi/bbl) =

Mud Weight (ppg) x 0.052 Annular Capacity (bbl.ft)

Now knowing the hydrostatic equivalent of where the bubble is in the hole, we can calculate the volume to bleed down to allow expansion using: Barrels of Mud to Bleed Down =

Pressure rise in SICP (psi) Hydrostatic Equivalent (psi/bbl)

Step 5. Once the Operating Margin is reached then bleed down the volume of mud equal to the operating margin. While bleeding down this volume the SICP must be kept constant. This may be a lengthy process, however bleed times will successively reduce as the bubble migrates up the hole. Step 6. Once the correct volume has been bled from the annulus, close the well back in and allow the gas to migrate without expanding until a second incremental Operating Margin is reached. This procedure is then repeated until the gas arrives on surface where the gas is lubricated out of the BOP by: • Equalising the pressure across, and then opening the kill line HCR.

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• Pump a small volume of active mud down the kill line. • Allow the mud to fall through the gas and then bleed down through the choke according to the following formula: Pressure to Bleed (psi) =

Volume Pumped (bbls) x Mud Gradient (psi/ft or m) Annular Capacity (bbl/ft or m)

• Repeat the process until all the gas has been replaced by mud at which point the pit volume should return to the level it was before the kick was taken.

Annulus Pressure

Volumetric Pressure Profile

Volumetric Rise Lubricating Drop

Time

5.3.5 Best Practice when Stripping Back to Bottom 1.

Three quarters of all well control incidents happen when the string is off bottom. If the well does start to flow during a trip then it may be necessary to strip back down through the annular or rams so that the kick may be controlled from deeper in the well.

2.

If a kick is taken while off bottom, then it is important to establish at what depth the kick entered the well, i.e. has it come from bottom or is there a potential kick zone higher up the well that we have now swabbed in?

3.

Whenever a well is shut in, it is vital that the shut-in drill pipe and casing pressures are closely monitored. If it is not possible to immediately start stripping

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operations then we should consider using the Volumetric Method to allow the gas to expand (see Section 5.3.4 above). 4.

While stripping pipe back into the well, it will be necessary to bleed down pressure from the annulus. The bleed down process has to take account of five variables: • We need to establish if the influx is a gas bubble or some other type of fluid. • It will be necessary to bleed mud from the well to compensate for the closed end displacement of the pipe being run in. • We need to track the influx as it moves up the well. • If a bubble is migrating, then we will need to bleed down the surface pressure to allow the gas to expand. • As the BHA enters the influx, we will need to increase the shut-in pressure to compensate for the loss in bottom hole pressure as the gas column grows in height and the mud hydrostatic is replaced by the gas hydrostatic.

5.

The following procedure outlines the steps involved in stripping back to bottom. For a more detailed and worked example, refer to the BP Well Control Pocketbook or the Well Control Manual - BPA-D-002. Step 1. If the influx is gas then we will need to allow the bubble to expand as it migrates up the hole. Calculate the gradient of the influx using: GI = Gm -

SICP - SIDPP Influx TVD

where: SICP = Shut-In Casing Pressure (psi) SIDPP = Shut-In Drill Pipe Pressure (psi) TVD

= True Vertical Depth in (ft) or (m)

For ease of calculation use: TVD = Cos. Inclination x Measured Depth Gm

= Gradient of Mud in psi/ft or psi/m

GI

= Gradient of Influx in psi/ft or psi/m

If the Gradient of Influx (GI) cannot be calculated, then look for signs of the shutin pressures continuing to rise after initial stabilisation which would show that gas is migrating up the well (the shut-in pressures should stabilise after around 5 minutes given a reasonably permeable kick zone).

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Step 2. To compensate for the closed end displacement of pipe being run in the hole, use the following formulae. N.B. An allowance for tool joint volume should also be added. Displacement (bbls/m) = OD2 x 0.003187 or Displacement (bbls/ft) =

OD2 1029

where OD = the outside diameter of the drillpipe in inches. Step 3. For any stripping operation to be successful, it is important that we closely track the progress of the gas bubble as it migrates up the hole. Well kill software can be used for this, however it is important that the person tasked with the responsibility of following the bubble's progress fully understands the principles behind gas migration. Gas will migrate at differing rates depending on the geometry of the hole and the type of fluid being used. A typical migration rate in mud might be around 300 m/hr whereas in a vertical well containing clean brine, the migration rate might be as high as 1800 m/hr. If the bubble rises without expanding, it will take bottom hole pressure up with it. As the gas migrates, the shut-in pressures will be seen to rise and we can use this pressure increase to back calculate the distance the bubble has moved up the well. The increase in surface casing pressure caused by the migrating gas will be equal to the weight of the mud column which has now moved to below the bubble. First calculate the change in TVD using: Height of Migration in TVD (ft) =

Pressure Rise (psi) Mud Weight (ppg) x 0.052

or Height of Migration in TVD (m) =

Pressure Rise (psi) . Mud Weight (sg) x 1.423

Then convert TVD to MD using MD (ft or m) =

TVD (ft or m) . Cosine of Inclination

Step 4. In order to allow the gas bubble to expand, we need to bleed pressure from the annulus. Calculate the equivalent hydrostatic pressure per barrel of mud for when the bubble is initially below the bit and then for when the bubble is moving up the drillstring annulus: page 90

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With the influx below the bit: Hydrostatic Equivalent (psi/bbl) =

Mud Weight (sg) x 445.7 Hole Diameter2 (in2)

With the influx in the Drillstring Annulus: Hydrostatic Equivalent (psi/bbl) =

Mud Weight (sg) x 445.7 Hole Diameter2 (in2) - String OD2 (in2)

or Hydrostatic Equivalent (psi/bbl) =

Mud Weight (ppg) x 0.052 Annular Capacity (bbl.ft)

Now knowing the hydrostatic equivalent of where the bubble is in the hole, we can calculate the volume to bleed down to allow expansion using: Barrels of Mud to Bleed Down =

Pressure rise in SICP (psi) Hydrostatic Equivalent (psi/bbl)

Step 5. Estimate the required increase in surface pressure needed to compensate for the loss in bottom hole pressure caused as the bubble lengthens in the drillstring annulus and the mud hydrostatic is replaced by the gas hydrostatic. N.B. Due to the difficulty of predicting exactly where the bubble is, it may be advisable to apply this pressure rise right at the start of the stripping operation. Pressure Rise = (Influx TVD in Annulus - TVD in Open Hole) x (Gmud - GI) where: Pressure Rise is in psi TVD = True Vertical Depth in (ft) or (m) For ease of calculation use: TVD = Cosine Inclination x MD Gmud = Gradient of mud in psi/ft or psi/m GI = Gradient of Influx in psi/ft or psi/m Step 6. Prepare the equipment and ready the crews for stripping operations. • Appoint a suitably qualified person to monitor the progress of the gas bubble as it migrates up the annulus. • Prepare a stripping sheet to record the following information:

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Time

Operation and Bit Depth

SICP

Change in SICP

Pipe RIH (bbl)

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Pressure Volume Rise Bled due to (bbl) Migration

Mud to Bleed to Expand Gas

Top of Gas Bubble

Total Mud Bled

• Well Site Leader to confirm the plan with the onshore support team and inform the OIM of the planned course of action. • Hold a Toolbox Talk and discuss the forward plan with all concerned. • Install a Gray valve onto the string and carefully open the IBOP. • Install a gas detector beside the stripping tank and make sure the stripping tank volume is being accurately monitored. • Reduce the annular closing pressure to the manufacturer's recommended minimum figure which will be typically between 400-500 psi. Run the trip tank over the top of the well to monitor for any leaks through the annular. • Rig mechanic to confirm that the annular stripping bottle is online and is in good working order. • Position men at the wellhead and BOP deck to monitor for leaks and advise on any adverse effect caused by the stripping operation. • Floormen to check tool joints for sharp edges and dress off with file then clean and grease the pipe and then remain in the "Safe Area" until otherwise instructed. • Erect barriers and make tannoy announcements to keep non-essential personnel clear of the well. Stripping Procedure: 6.

First allow the SICP to rise by an overbalance margin of between 50 and 200 psi. This may be done by either running pipe in the hole or allowing the migrating gas to increase the well pressure. Consider applying the pressure required for when the gas moves from the open hole to the drillstring annulus (see Step 5 above).

7.

Slowly strip pipe into the hole watching the annular read-back pressure as tool joints pass through the BOP (normally an increase of over 200 psi will be seen as the tool joint passes the BOP). Record the rise in annular pressure as each stand is run in. N.B. The rise in SICP may take time to get established as the gas bubble will first have to be compressed.

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8.

Stop after a number of stands have been run in the hole; this figure will depend on the hole volume and the pressures involved. These stripping stages can be done in whole or part stands, however more commonly the SICP is allowed to increase to an established operating pressure, e.g. 200 psi.

9.

Record the volumes and pressures and then calculate the volume of mud to be bled to compensate for the volume of pipe RIH (see Step 2 above). If not already accounted for, then calculate the pressure increase required to compensate for the gas getting strung out in the drillstring annulus and reduce the volume bled for expansion accordingly.

10. Once the closed end volume is bled, record the new SICP and then calculate the volume of mud to be bled to allow the gas to expand as per Step 4 above. Once an established “Expansion Operating Pressure Margin” is reached then bleed down the volume of mud equal to this pressure margin. While bleeding down this volume the SICP should be kept constant (see the Volumetric Method in Section 5.3.4 above). This may be a lengthy process, however bleed times will successively reduce as the bubble migrates up the hole. N.B. As the time taken to strip to bottom is critical, then consider extending the “Expansion Operating Pressure” accordingly. 11. Continue with stripping operations, bleeding down to allow for both the pipe run in and to allow the gas to expand. The drillstring should be filled every 5 stands. Once back on bottom, the new shut-in casing pressure can be checked using: New SICP = Old SICP + ∆H (Gm - GI) where: SICP = Shut-In Casing Pressure (psi) ∆H

= Increased TVD of the Influx (m or ft)

Gm

= Gradient of Mud in psi/ft or psi/m

GI

= Gradient of Influx in psi/ft or psi/m

12. Once back on bottom the upper pipe rams should be closed and the influx circulated out using conventional well killing techniques.

5.3.6 Well Control Drills Kick detection, circulating, stripping and shut-in drills will be held regularly until the WSL is satisfied that each crew meets BP's established standards.

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5.3.6.1 D1 - Kick Whilst Tripping The purpose of this drill is to have the crew practice the shut-in procedure carried out when a kick is taken while tripping. The D1 drill should only be practiced when inside casing and should be done at least once per week. • Without notice, the Well Site Leader will initiate the exercise by either raising the float in the trip tank, or by simply announcing “Kick Drill”. • The Driller will have his crew stab-in and close the safety valve. • Open the choke HCR. • Close in the annular. • Install the top drive and then re-open the safety valve. • Record the SIDPP and SICP. • Report the situation to the Well Site Leader. • Record the time taken to secure the well and record this on the IADC report. 5.3.6.2 D2 - Kick While Drilling The D2 drill is carried out to practice the correct procedure for closing in a well while drilling. It is best carried out while drilling out the shoe track and again should be practiced until the Well Site Leader is confident that all crew members are competent in their role. If practiced in open hole, then the well should not be shut in. • Without notice, the Well Site Leader will initiate the exercise by either raising the float in the Active Pit or by simply announcing “Kick Drill”. • The Driller will come off bottom and space out to close the BOP. • He will stop rotating and shut down the pumps. • Open the choke line HCR. • Close the annular. • Record the SIDPP and SICP. • Report the situation to the Well Site Leader. • Record the time taken to secure the well on the IADC report. 5.3.6.3 D3 - Diverter Drill The diverter drill is to be carried out before drilling out of the conductor shoe. The exact format of the drill will vary depending on the type of diverter assembly installed page 94

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on the rig. The flushing of the diverter is an important part of the drill, however this may be omitted should there be concerns over a spill to sea. • Without notice, the Well Site Leader will initiate the exercise by announcing “Kick Drill”. • The Driller will come off bottom and space out to close the diverter. • As it is a drill the pump will be stopped at this stage. • The Driller will activate the ”Diverter Close” function. • The Well Site Leader will witness the correct cycling of the valves. • Where appropriate the Driller will select the down wind overboard line. • Report the situation to the CCR. • Record the time taken to close the diverter on the IADC report. • When possible and only under the supervision of the Well Site Leader will the Driller then bring in his pump and check that seawater is seen to divert correctly from each overboard line. • Following the Drill, the diverter valving will be reset and the Well Site Leader will witness the valves swing back to their normal operating position. 5.3.6.4 D4 - Accumulator Drills The purpose of the accumulator drill is to check the operation of the BOP closing system. The following specific tests should be carried out: 5.3.6.4.1 Accumulator Precharge Pressure Test This test should be carried out on each well before spud and then approximately every 30 days after that. • Shut-off all the accumulator pumps. • Drain the hydraulic fluid from the accumulators back into the tank. • Rig Mechanic to check the precharge pressure on each bottle and bleed or recharge accordingly. 5.3.6.4.2 Accumulator Closing Test This test should be carried out as part of the normal BOP test. • Position a joint of pipe across the BOP.

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• Close off the power supply to the accumulator pumps. • Record the initial accumulator pressure (normal manifold pressure for the main bank and 1500 psi for the annular bottles). • Cycle the minimum functions as per the Rig Type, i.e. for a land or platform rig operation, close the annular and one pipe ram then open the choke line HCR. For floating rigs, close and then open all functions (duplicating the function of the shear rams). After each function, record the volume used, the time taken and the residual accumulator pressure. The residual accumulator pressure after completing the test must be at least 200 psi over the accumulator pre-charge pressure. • Turn on the accumulator pumps and recharge the accumulator to its designed operating pressure and record the time taken to recharge the system. 5.3.6.4.3 Closing Unit Pump Test The closing unit pump test should be carried out as part of BOP test. This test can be conveniently scheduled either immediately before or after the accumulator closing time test. • Position a joint of pipe across the BOP. • Close off the accumulator bank from the manifold. • If air pumps are installed, then close off the rig air supply and use the air accumulator only for the test. If both air and electric pumps are fitted, then both power supplies should be tested separately. • Close the annular and open one HCR valve. Record the time taken for the pumps to close the annular and open the HCR and then reach 200 psi above the precharge pressure on the manifold (required within 2 mins). • Close the HCR valve and open the annular. Open the valves to the accumulators and allow the system to recharge. 5.3.6.5 D5 - Well Kill Drill The Well Kill Drill should be carried out before drilling out of the intermediate and production casings. It is often practiced in conjunction with the D2 drill, but should never be carried out when formation is exposed. The combined D2 and D5 drills offer an excellent opportunity for the drill crew to gain hands on experience. It is important that the choke operator develops a feel for the choke opening point and also the lag time between manipulating the choke and its subsequent effect on the drill pipe pressure. Both the opening point and the lag time should be recorded for future use. page 96

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Care needs to be taken when applying pressure to the casing to make sure more than one gauge is online. • Carry out the D2 drill as per the above procedure. • Once the BOP is closed and under Well Site Leader supervision, apply 200 psi to the well. • Drill crew then to practice choking on and off while keeping bottom hole pressure above 200 psi. The combined D2 and D5 drills allows the crew to become familiar with the control of their choke and gives the Well Site Leader the opportunity to coach the crews on a variety of well killing techniques. 5.3.6.6 D6 - Stripping Drill A stripping drill may be combined with a D2 or D5 drill. Because of the potential for wear on the BOP components, it will only be done following the joint agreement of the Toolpusher and Well Site Leader. See Section 5.3.5 for full description of stripping best practice. • Inspect the stand of pipe to be used and make sure no metallic burs are present. • Carry out a D1 drill as per the above procedure. • Once the BOP is closed and under Well Site Leader supervision, apply 200 psi to the well. • Run the trip tank over the top of the well to check for fluid passing the annular. • Drill crew to dope the pipe to provide lubrication for the annular. • Reduce the annular operating pressure to minimum, typically between 300 and 450 psi. • RIH taking care as the tool joint passes through the annular. Record the increase in drag as the string is RIH. • Monitor the annular regulator readback and record the increase as the tool joint passes the annular. • Monitor the rise in the well pressure as the pipe is stripped in. • Stop RIH and practice bleeding down pressure to the stripping tank. The combined D1 and D6 drills allows the crew to become familiar with the practice of stripping through the BOP and gives the Well Site Leader the opportunity to coach the crews on a variety of well killing techniques. Rev. 1, April 2010

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6. Mud Property Trends 6.1 Mud Property Changes and Trend Analysis Changes in mud properties are an indication that something abnormal is taking place. The following tables suggest common reasons for changes:

6.1.1 Water Based Mud Property Trend Analysis Mud Property Units (usual range)

Trend Change

Possible Cause

Mud Weight SG (1.1 - 1.8)

Increase

Drill solids increase, heavy spot from barite sag, over treatment during weight-up.

Decrease

Formation fluid influx, light spot from barite sag, excessive water additions.

Funnel Viscosity cP (varies with density)

Increase

Reactive shale drilled, drill solids increase, low water content, calcium contamination from cement, anhydrite formation drilled.

Decrease

Formation water influx, excessive water content.

Increase

Unconsolidated sand drilled, drill solids increase, low water content.

Decrease

Formation water influx, excessive water additions, solids content decrease.

Increase Yield Point lb/100 ft2 (increases with hole Decrease diameter)

Reactive shale drilled, anhydrite formation drilled, low water content, calcium contamination from cement.

Plastic Viscosity cP (varies with density)

Gel Strength lb/100 ft2 (minimum 3/6)

Increase

Reactive shale drilled, anhydrite formation drilled, low water content, calcium contamination from cement.

Decrease

Formation water influx, excessive water additions, additions of chemical thinners.

API/HPHT Fluid Loss Increase cc (5 - 8cc) pH (8 - 10)

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Formation water influx, excessive water additions, decrease in low gravity solids, additions of chemical thinners.

Low gravity solids increase, flocculation from cement, chloride, calcium contamination, low bentonite or filtration chemical content.

Decrease

Mud treatment taking affect.

Increase

Addition of pH control additives, calcium contamination.

Decrease

Addition of mud products, anhydrite formation drilled, acid gas influx. Rev. 1, April 2010

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Trend Change

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Possible Cause

Chloride mg/l (20 - 80k, 180k s.sat)

Increase

Salt formation drilled, pressure transition shale drilled, formation water influx.

Decrease

Water additions.

Total Hardness mg/l (below 200 mg/l)

Increase

Salt or calcium formation drilled, formation water influx.

Decrease

Addition of fresh water, chemical addition.

Cation Exchange Capacity (CEC) mEq/100ml

Increase

Reactive shale is drilled, addition of bentonite.

Decrease

Water additions, solids removal equipment taking effect.

6.1.2 Oil/Synthetic Based Mud Property Trend Analysis Mud Property Units (usual range)

Trend Change

Possible Cause

Increase

Drill solids increase, heavy spot from barite sag, over treatment during weight-up.

Decrease

Formation fluid influx, light spot from barite sag, excessive base oil additions.

Increase Plastic Viscosity cP (as low as possible, Decrease varies with density)

Addition of water, calcium carbonate, primary emulsifier, low gravity solids increase.

Increase Yield Point lb/100 ft2 (increases with hole Decrease diameter)

Increase in organophilic clay, additions of emulsified water or synthetic polymer.

Gel Strength lb/100 ft2 (minimum 3/6)

Increase

Addition of organophilic gel, addition of water.

Decrease

Large base oil additions, increase in mud temperature.

Oil/Water Ratio (50:50 to 90:10)

Change

Large addition of water or water influx, large additions of base oil, high bottom hole temperature.

Electrical Stability (ES) volts (400V+)

Increase

Increase in emulsifier concentration, addition of wetting agent or base oil.

Decrease

Decrease in emulsifier concentration, newly prepared OBM has low ES, but increases with time.

Mud Weight SG (1.1 - 1.8)

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Addition of base oil, decrease in low gravity solids.

Addition of base oil or degellant, decrease in organophilic clay.

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Trend Change

Water Phase Salinity Increase mg/l (180k - 275k mg/l) Decrease

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Possible Cause Water % of O/W ratio decreasing. Addition of calcium chloride. Water % of O/W ratio increasing from water addition or formation water influx.

HPHT Fluid Loss cc (below 5cc)

Increase

Addition of base oil, decrease in emulsifier concentration, water present in filtrate.

Decrease

Increase in primary emulsifier concentration.

Excess Lime ppb (3 - 5 ppb)

Increase

Addition of lime, drilling calcium formation (anhydrite).

Decrease

CO2 or H2S kick, additions of base oil or water.

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7. Drilling Practices 7.1 General Drilling Practices Keep an up-to-date set of drilling practices for each hole section and keep a copy on the rig floor. These should outline the general drilling practices for your area to the driller. An example is shown overleaf. Further examples are included in the Appendices.

7.2 Tripping Practices References: Functional Expectations of WSL • 2.4.3 The WSL shall ensure that the well is always flow-checked prior to tripping, after pulling into the casing shoe and before the BHA enters the BOP. The minimum length of a flowcheck will be 15 minutes. • 2.4.5 Be present on the rig floor to observe the first 10 stands pulled on every trip out of the hole, and until such times as he/she is satisfied that the hole fill volume is correct. The WSL should continue to monitor the trip until back into old hole or inside casing. • 2.5.1 Ensure that all downhole tools are visually inspected prior to running in hole (i.e. thread conditions, seal areas, jet size and bit type). Any new tools should be drifted. • 2.5.2 Be aware of the hole condition at all times and be able to communicate this to the onshore team as required. • 2.5.3 Ensure that the dimensions of any item run in the hole are recorded, correct for their application and a fishing diagram is available. • 2.5.19 Ensure alternative breaks in the trip schedule. • 2.5.20 Review the BHA make-up and laydown plans. • 2.6.12 Where possible, any tight spots should be wiped out on the trip before running casing. The depth of ledges etc should be recorded and included on the casing tally. SMS Documentation • GP-10-35 - Well Operations.

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*Recommended Minimum of 1 Bottoms Up

150rpm

7.

5. 6.

2. 3. 4.

1.

2.

1.

7.

6.

5.

4.

1. 2. 3.

As many as required

Do not circulate the hole clean at depths where the BHA components (eg stabilisers) are adjacent to stringers or where previous circulations were carried out Max. 150 rpm is the limit of the AutoTrak/MWD assembly Monitor for vibration and slip/stick Monitor Hook Load trends, torque, shakers, ECD and ESD for indications of sub-optimal hole cleaning Monitor ECD levels to minimize Swab & Surge effects while cleaning the hole After the first bottoms up, rack back a stand every 30mins – continuing to rotate (i.e. backream). Do not work or ream a stand down unless resistance is observed. Circulate at drilling rate (note that normal tripping indicators will be masked and avoid unnecessary delays at connections). Circulate until hole clean. Perform minimum of one bottoms up inside the shoe, should be performed at WSL discretion.

Break circulation with 20 spm without inducing large pressure spike Verify flow out Increase flow to drilling rate in 100 gpm stages (minimum 30 sec/stage) At each stage, once stabilised, record & compare all data with trends. Stage up rotation to 80 rpm, hold for 2 minutes, then stage up to drilling rate or cleaning rate (Note: This is most likely pack-off point) When specified rotation is obtained & stabilised, record & compare data with trends.

Be alert for Early Warning Indicators and take action to prevent worsening of conditions Accurately record & report MW every 15mins When trends indicate unacceptable ECD/ESD increases, reduce ROP to half the Drilling ROP until favourable trends resume. If no improvement is seen after 2 stands then drilling should cease & the well circulated to clean the hole. Do not reduce the Drilling Flow Rate or RPM in an attempt to maintain ECD level below the Alarm Level. Maintain steady ROP & control instantaneous drilling rate, to avoid overloading annulus & CRI. Monitor surface Slip-Stick & downhole vibration and modify the surface rotary within the defined operating window accordingly especially at changes of rpm. Attempt to increase rotary speed in the first instance. Ensure current operational parameters are communicated across handover time – use a handover procedure

1

Look for increasing trend on connections compared to mud weight

ESD (effective static density)

Bottoms up before trip

Ensure ECD Alarm is set to 0.02 sg above the expected trend line value

10-22 OR 26-30klbs (beware of running jar in neutral point)

Refer to ROP vs Flow chart for allowable ROP for a given flow rate but evidence from ESD trends should supersede modelled values NOTE: MaxROP for CRI processing cuttings 4 >0m/hr

Optimum RPM: 140 for Drilling Ahead / 120 for Hole Cleaning NOTE: 90RPM will only be used in special circumstances noted below

110rpm (90rpm see below)

MAXIMUM 1090gpm (BCPM limited)

ECD

WOB

ROP

MINIMUM

605gpm (BCPM limited)

6. 7.

5.

4.

1. 2. 3.

4.

3.

1. 2.

10. 11. 12. 13.

7. 8. 9.

6.

Circulate minimum of one bottoms up before tripping out of hole or until hole clean Commence trip out of hole If overpull encountered: work up to 25 k overpull limit in stages, checking that the pipe is free each time we reach 25 k overpull If consistent 25 k overpull– run down well clear of resistance (guide – distance between bit and top stabilizer) Break circulation slowly (“Break Circulation” procedures) & build up to drilling flow rate then bring rotary up to 120 rpm Circulate to clean hole and reciprocate pipe before attempting to pull through tight spot. Continue to trip out of hole, if unable to progress go to level 2 responses.

Slowly reduce flowrate to 900 gpm. Note: This is a special case GPM only Slowly reduce rotation to 90 rpm Note: This is a special case RPM only – monitor for vibration, particularly slip/stick Time drill on stringer by slowly increasing WOB to a max of 24klbs There is a high risk of a pressure spike when breaking through stringers with high WOB. Use Cyberbase auto-ROP function for drilling stringers Record stringer depths on the Driller’s Log When through the stringer, return to base-line drilling parameters, pumps first then rotary and monitor

Drill stand down using “Drilling Parameters”. Pick up slowly to 1-2m off bottom with drilling parameters, do this before allowing weight to completely drill off ( i.e. with 5-10k WOB remaining) Allow 2-3 minutes to clear any cuttings from around the BHA Stop rotation Wash up enough to confirm up weight: If overpulls are noted, do not make connection. Wash or Ream the Stand or Single as required: Minimum Wiped distance at BP Wellsite Leader’s discretion. ECD, ESD and hook load trends to be monitored. Wash down to connection height, recording down weight. Reduce flowrate to zero over 30 seconds. Set slips (minimising pipe movement to avoid masking ESD) and make connection (survey taken over connection). Monitor volume flow back to identify any wellbore breathing. Stage the pumps up to drilling rate in increments, then stage up the rotary to drilling rate Monitor and record ECD/ESD/torque/pressure/flow levels throughout. Drill ahead.

1st

March 2010

NOTE: DEVIATION FROM THESE PRACTICES MUST HAVE PRIOR APPROVAL FROM THE BP WELLSITE LEADER

The “25k Rule”

Tripping ProceduresNegotiating Tight Spots

*Only if lasting 5+minutes

Drilling Limestone Stringers

Buttons

Stop/Resume

Do NOT use the

Connection Procedures

3. 4. 5.

1. 2.

Wellsite Leader’s Handbook

Circulating to Clean the Hole

after wiper trips or after mud has been Stationary *NOT Applicable to Connections

Break Circulation Procedures

Comments

Drilling Parameters

Rotary

Flow Rate (D/L @7 25gpm)

PARAMETERS

Clair Drilling Practices – Cretaceous 12-¼” Section

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7.2.1 Considerations Before POOH Preparation • Check the pipe count and pipe figures are correct. • Well Site Leader to review the Driller's trend sheet and Mud/MWD Logs and then create a section schematic for the trip. • Section Schematics should include: -

Previous Bit Trip details. Formation Tops. Stringer detail. Directional detail including dogleg and tangent depths. Known trouble spots, e.g. hole instability, differential sticking, etc. BHA details, e.g. stabiliser sizes and spacing.

• Check the jar hours and issue written instructions on firing loads and times. • Will the weather play a part in the trip, e.g. do you need to rig up storm lines? • Can new bits, BHA equipment, etc. be sited on or close to the catwalk? • Are the turbine fumes or flare direction going to cause problems? • Is a “slip and cut” or a well control exercise planned for this trip? • Both the Driller and the Data Engineer are to make out trip sheets. The previous trend sheets are to be used to record pressures and torques against every 5 stands in open hole. • If gas has been seen while drilling, consider doing a swab test while circulating before POOH. • Plan to change the break on each trip. • Make sure to have a single on the catwalk. Equipment • Is the power supply guaranteed for the trip? • Is there any outstanding maintenance needed while circulating? • Consider a sweep of the derrick and TDU if string vibration has been an issue. • Have the crews check the following equipment: - Roughneck and TJB dies.

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Mud bucket seals. Trip Tank pump. Crown-O-Matic, Crown/Floor Saver or KEMS system. Flowshow. TDU or hook to be unlocked for tripping operations. If using an electronic system, have the overpull limits set at a realistic limit so the system does not end up hunting around at too low a setting. - Clean the cameras and windows. -

Trip Plan • Hold a pre-trip meeting and discuss the plan for the trip. • The Trip Plan will depend on the next activity, i.e. a POOH for a new bit will be viewed differently from POOH to run casing. • The Trip Plan should cover the following issues: - Is there a need to stage circulate? - Do we plan to slug the pipe? Consider the hole condition and length of open hole section. - Do we need a logging repeat section to overlap new tools? - Are there any requirements for Test-Trak points? - Is there any possibility of junk in the hole? - Should we pump out through any hydrocarbon bearing zones? - Does everyone who needs a copy of the Section Schematic have one?

7.2.2 Best Practice when Circulating, Before POOH • Only under exceptional circumstances would we not circulate a bottom's up. • Minimum circulation would be 120% bottom's up with no upper limit. • Plan to circulate using maximum flowrate and revs to help clean the hole. • If using a rotary steerable assembly, after taking the final survey, set the assembly to "Steer Force Zero" to help stabilise the BHA while circulating. • Do not undercut the hole. If you are drilling with a motor, then consider not rotating and setting the motor on high-side to prevent undercutting the hole. • Both the Driller and Data Engineer are to monitor gas levels while circulating. • Have the Data Engineer monitor the drop in the active system while circulating to give an indication of how the hole is cleaning up. • Monitor the ESC and ECD trends for signs of the hole cleaning up. page 104

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• For reasons of continuity, have one man, e.g. the Mud Engineer, monitor the volume of cuttings returned throughout the circulation. Have him check the size and quantity of cuttings at the shakers on each bottom's up. Have the shaker returns described again at each bottom's up, i.e. % Cuttings, % Cavings, % mush, discreet, blocky, good, dry, etc. • Watch for evidence of cavings which will become more evident as the volume of cuttings drops away. Could working the pipe be creating the cavings? • Look for signs of hole instability: it is best to catch breakout as early as possible. • Don't allow the shaker hand to flush the header box while watching the hole clean up. • Be aware that when rotating and working the pipe all drag will turn to torque. Should any increase in torque be seen, then stop and ream straight back down. • Stop the string at a different point on the stand on each wipe. Consider racking a stand every 30 minutes or so, to prevent wearing the same section of hole. • If a swab test is required, then after circulating the first bottom's up, stop the pump and pull a stand dry at normal tripping speed. Run the stand back in and circulate a further bottom's up to check for any sign of gas. • Before flowchecking make sure the mud weight is balanced in and out. • If using a Rotary Steerable assembly, toggle it to "Ribs Off" to collapse the tool before POOH. • Flowcheck for 15 mins. This is a good time to hold the pre-trip meeting.

7.2.3 Best Practice while POOH • Hole condition is important, however hole fill is the overriding concern. • Tripping technique will be driven by past experience and the potential for hole problems as detailed on the Section Schematic. The biggest factor in tripping technique will normally be the type of mud system in use. • A figure of the maximum first over-pull is to be been given to the Driller. This will again be driven by past experience and the potential for hole problems. The maximum first over-pull should never be more than half the BHA weight. • Well Site Leader to supervise the trip until back into old hole or inside the casing. • Both the Driller and the Data Engineer are to fill out trip sheets. • The tripping speed will depend on any swabbing risk but can increase once back inside old hole and again once inside back inside the casing. Rev. 1, April 2010

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• The trip plan mentioned above will have decided on how much effort will be taken to wipe the hole clean, i.e. when POOH to run casing, more time will be spent wiping than if the trip is simply for a bit change. • Each stand should be wiped as high as possible to check the hole condition at the start of the next stand. The pipe is then lowered into the slips in the knowledge that the first section of the next stand will pull OK. • It is good practice to periodically wipe down a stand and check the pick-up weight coming back up is the same as on the first pass. • Always break the string down after a prolonged period of time as this will help dislodge any debris before once more POOH. • Make sure the crew is not distracted during the trip: good communication is the key to a safe operation. • Make sure the hookload follows the expected figures as detailed on the Driller’s Trend Sheet. • Look for signs of the hole swabbing or the string wanting to rotate. Either of these signs may suggest the hole condition is beginning to deteriorate. • If regular flickers are seen on the weight indicator, take extreme care as this could be caused by tool joints being pulled through a potential key-seat. • Watch when pulling the BHA back inside the previous shoe. Resistance at the shoe may be caused by cement debris or even key-seating of the casing. It is often a safer option to dry rotate back inside a troublesome shoe, rather than to start the pump and risk a pack-off. N.B. Working BHAs back inside casing is one of the few places where limited dry back-reaming is acceptable. • Take care at the top of any tangent section but especially around the critical inclinations of 40° to 65°. Although less of a risk this practice does still apply when inside casing. • If POOH with water based mud, then throwing a bucket or two of water down the pipe will prevent the setback area from becoming a slip hazard.

7.2.4 Best Practice when Resistance is Met • A figure of maximum first over-pull will have been given to the Driller. This figure will be driven by past experience and the potential for hole problems. The maximum first over-pull should never be more than half the BHA weight.

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• When resistance is met it's important for the Well Site Leader to quickly identify the cause. - First check the Section Schematic for any mention of hole problems. - Confirm that it is actual overpull and not just an increase in drag caused by the profile of the well. - Resistance at the shoe may be caused by cement debris or actual keyseating/damage to the casing. It is often a safer option to dry rotate back inside a troublesome shoe, rather than to start the pump and risk a pack-off. N.B. Working BHAs back inside casing is one of the few places where limited dry back-reaming is acceptable. - Look at the stabiliser and BHA upset spacing to see if anything is sitting opposite a known ledge. - If it's a sudden and sharp increase in overpull then it's likely to be caused by a stringer. If it's more of a gradual build-up, then this is more likely to be caused by formation debris. - To check the likely cause, break the string down and run well below the resistance (preferably two singles). Work back up and see if the problem moves or does it look exactly as it did on the first pass? - When breaking the string down, record the break over weight against the initial overpull as this will determine the ultimate overpull figure to work to. - If it takes very little weight to break the string down, then this points to the problem being a "ledge" more than a "wedge". - Base the second attempt on what has been learned from the first. - If possible run an upper stabiliser past the point of resistance to help clear the obstruction. - If the position of the pipe in the derrick is making the working of the pipe awkward, then pick up the single from the catwalk and change the position of the top of the stand in relation to the trouble spot. - Having made repeated attempts to pass the obstruction, the Well Site Leader will have a better understanding of the nature of the problem and a decision on whether to increase the pipe speed and/or increase the overpull can be made. - If setting the slips, make sure to allow the jars to stroke open, rather than have them fire while sitting in the slips. - Once passed, log the problem on the section schematic and if coming out to run casing or go logging then go down and wipe the area clear. Rev. 1, April 2010

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7.2.5 Best Practice when Breaking Circulation During a Trip • Breaking circulation during a trip will often be as a result of meeting resistance. Every care must be taken not to make a bad situation worse. • Only break circulation after having run well below the point of resistance. As a guide, this distance should be at least equal to the distance from the bit back to the top stabiliser. Make sure you break circulation away from any trouble spot logged on the Section Schematic. • The risks associated with breaking circulation should have been talked about at the pre-trip meeting so individuals should be aware of their exact roles and responsibilities. - Have a man positioned at the header box to confirm when returns start/stop/ increase or decrease. - Make the last movement of the pipe down and then get to rotating weight so that the BHA will not move up or down as rotation is started. - Rotate slowly at between 20 and 30 RPM and check the torque and weights are similar to when the section was drilled. - Bring in the pump slowly and break circulation at 100 gpm. Know what pressure to expect and make sure the hole does not try to pack-off. - Once returns are confirmed then build the flowrate in 100 gpm intervals. The pump pressure must be checked at each interval and only when the pit level steadies is the pump rate to be increased to the next stage. - Build the pump rate up to between half and full flowrate (this figure will depend on the severity of the situation and what the next step is to be). • Once the desired flowrate is reached, then increase the rotation in stages but take care when passing the critical speed of between 80 and 90 RPM (at this point cuttings will be lifted from the low-side of the hole). • The procedure for recovering from a pack-off is the same as above, however circulating stages and times are to be increased as hole problems are now a reality. • Once full circulation is achieved, then circulate a minimum of 120% bottom's up before stopping the rotary and working back up towards the resistance.

7.2.6 Best Practice when Having to Pump Out of Hole • Having to pump out of the hole will most likely be as a result of having met resistance. This operation carries a risk of getting packed off. A pack-off can cause irreparable damage to the hole and must be avoided at all costs. page 108

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• Before starting to pump out of hole, hold a TBT with all concerned, make sure everyone understands the risks involved and what their particular role is to be. Every care must be taken not to make a bad situation worse. • Consider pumping out of the hole using a reduced pump rate to allow more time to react and to help reduce the risks of a catastrophic pack-off. If the string does become stuck using a lower flowrate, then it will be stuck with less force and so should be easier to free. Remember, without rotation we won't be cleaning the hole and so the pump rate becomes less critical. • Reduce the pulling speed to take account of the risks and use the pump pressure and flow-show in combination with the weight indicator to give a better picture of the downhole conditions. • As well as pumping as far as possible into the next stand, stop at the highest point and circulate for a minute or two to help clear any debris before the pump is switched off. • After racking each stand, break circulation in the manner described in 7.2.5 above. It is vital that the string is not moved until the pump is up to the required rate and the pit levels are seen to be steady. • If flowrates allow, then use the ECD and ESD values as early warning signs of more trouble. • If using a rotary steerable assembly, make sure that the directional Driller does not downlink to his tool without the knowledge of the Well Site Leader. Even the slightest variation in flow can confuse and complicate an already difficult situation. • When pumping out of the hole it's important to have the shakers monitored so that evidence of cuttings and cavings can be recorded. • As this operation carries a significant risk to the delivery of the well, it is vital that shift handovers are managed correctly. The Toolpusher should cover on the brake while the Drillers do their handover. • It is also important to make sure that the Driller gets sufficient breaks as the levels of concentration needed while pumping out of the hole cannot be over estimated. • If a pack-off does occur then the torque, pressure and return flow will change at varying speeds depending on the depth of the hole and the volumes involved. It is important to catch a potential pack-off as quickly as possible: - Stop the pump immediately but try to maintain rotation. - Do not slump the string for fear of surging and damaging the well.

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- Bleed off the trapped pressure in a controlled manner to avoid sucking formation debris back through the nozzles. If there is a float in the string then it may only be possible to bleed down the drillpipe. - Once the pressure is bled off then work/slump the string down, however take care as the string may well be stuck. - Continue working down and try to clear the pack-off using the upper stabilisers or tool joints. - Once a sweet spot is found then try to break circulation as per section 7.2.5 above. - If necessary, and only if the formation strength allows, hold 200 psi on the formation and work the string down until a drop in pressure and mud returns show that the hole condition is improving. - Once circulation is regained, circulate a bottom's up before moving the string. - The first movement of the string must be down. • If pumping back inside the shoe, take extreme care as debris sitting in the sump will lift and can itself cause a pack-off. If the sump is known to be a trouble spot then consider dry rotating into the shoe before once more breaking circulation. N.B. Working BHAs back inside casing is one of the few places where limited dry back-reaming is acceptable. • Once having committed to pumping out of the hole, then the Well Site Leader must decide at what point it will be safe to stop pumping out. This will be at a suitably safe area in the well, e.g. the start of old hole or even when back inside the casing. After deciding to stop pumping out, it is good practice to circulate a bottom's up before then continuing to pull on the elevators. • When opting to simply pull out, it is sometimes best to continue pulling with the TDU made up until the hole is seen to be in good condition. By doing this it means that circulation and/or rotation can be regained quickly if required.

7.2.7 Best Practice when Having to Back-Ream Out of Hole • Having to back-ream out of the hole will, in most cases, be done as a last resort. Because of the sidewall forces involved, back-reaming in some situations can cause more damage than good. • Remember that when rotating, all drag turns into torque: if an increase in torque is seen then ream back down immediately.

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• Back-reaming carries a risk of getting packed off. A pack-off can cause irreparable damage to the hole and must be avoided at all costs. • Should the hole problems get worse while back-reaming, then the resulting packoff will be more severe and the chances of recovery will be reduced. • Before starting to back-ream out of hole, hold a TBT to make sure that everyone involved fully understands what is expected of them. Every care must be taken not to make a bad situation worse. Before starting to back-ream reduce the torque limit to a comfortable level over the free rotating torque value. • Consider back-reaming using reduced pump rate and RPM so as to allow more time to react and less chance of a serious pack-off from happening. Consult the allowable torque versus pull charts to make sure the drillpipe is not at risk. • Reduce the pulling speed to a crawl to take account of the risks and use the pump pressure, flow-show and torque reading in combination with the weight indicator to give a better picture of what is happening downhole. • As well as back-reaming as far as possible up into the next stand, stop at the highest point and circulate for a minute or two to help clear any debris before the pump is switched off. • After racking each stand, break circulation in the manner described in 7.2.5 above. It is vital that the string is not moved till the pump is up to the required rate and the pit levels are seen to be steady. • If flowrates allow, then use the ECD and ESD values as early warning signs of potential trouble. • Make sure that the directional Driller does not downlink to his tool without the knowledge of the Well Site Leader. Even the slightest variation in flow can confuse and complicate an already difficult situation. • When back-reaming out of the hole, it's important to have the shakers monitored so that evidence of cuttings and or cavings can be recorded. • As this operation carries a significant risk to the delivery of the well, it is vital that shift handovers are managed correctly. The Toolpusher should cover on the brake, while the Drillers do their handover. • It is also important to make sure that the Driller gets sufficient breaks as the levels of concentration needed while back-reaming cannot be over estimated. • If a pack-off does occur then torque, pressure and return flow will change at varying speeds depending on the hole depth and volumes involved. It is important to catch a potential pack-off as quickly as possible: Rev. 1, April 2010

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- Stop the pump immediately but try to maintain rotation. - Do not slump the string for fear of surging and damaging the well. - Bleed off the trapped pressure in a controlled manner to avoid sucking formation debris back through the nozzles. If there is a float in the string then it may only be possible to bleed down the drillpipe. - Once the pressure is bled off then work/slump the string down, however take care as the string may well be stuck. - Continue working down and try to clear the pack-off using the upper stabilisers or tooljoints. - Once a sweet spot is found then try to break circulation as per Section 7.2.5 above. - If necessary, and only if the formation strength allows, hold 200 psi on the formation and work the string down until a drop in pressure and a surge in returns show that the hole condition is improving. - Once circulation is regained, circulate a bottom's up before moving the string. - The first movement of the string must be down. • If back-reaming the BHA into the shoe, take extreme care as debris sitting in the sump will lift and can itself cause a pack-off. If the sump is known to be a trouble spot, then consider dry rotating into the shoe and then once more breaking circulation. N.B. Working BHAs back inside casing is one of the few places where limited dry back-reaming is acceptable. • Once having committed to back-reaming the Well Site Leader must decide at what point it will be safe to stop. This point may be at a suitably safe area such as the start of old hole, at the top of a tangent section, at or around 40 degree inclination or even when back inside casing. After deciding to stop back-reaming, it is good practice to circulate a bottom's up before continuing out of the hole. • Again after stopping back-reaming out, the Well Site Leader should consider trying to pump a few stands out to further check the hole condition before committing to pull on the elevators.

7.2.8 Best Practice when Handling BHA • The well is to be flowchecked before handling BHA. This break in operations gives a good opportunity to hold a pre-job meeting with all concerned.

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• If the BHA has radioactive sources in it, the RPS is to make sure that radioactive barriers are erected and tannoys are made in plenty of time. As the RPS will not be as familiar with the rig as the core crew, then make sure the barriers are checked to make sure that no areas have been missed. • The Directional Driller must plan to break the BHA so as to reduce the time and potential for exposure to radioactive sources. • If the BHA is being worked in high winds then have the barriers policed as the sources are pulled up through the lower decks. • The Assistant Driller is to personally check that the correct size of elevators are available on the rig floor. • The Driller should position a copy of the BHA so that the Roughnecks can be prepared for any changes to handling equipment.

7.2.9 Best Practice while RIH • Hole condition is important however correct hole fill is the overriding concern. • Tripping technique will be driven by past experience and by the potential for hole problems as outlined on the Section Schematic. • Consider what changes have been made to the BHA and whether these make it easier or more difficult to get to bottom. • The Well Site Leader should check the first stand of BHA to help visualise the configuration should hole problems be encountered. • Is a surface pulse test required while RIH and where is this best achieved? • If using rotary steerable tools, the Directional Driller is to make sure they are set to "Ribs off" while RIH. • Were the bit and stabilisers pulled out of the hole in gauge? If not, then consider reaming down from where the previous ROP slowed down. • Both the Driller and the Data Engineer are to fill out trip sheets. • As was done while POOH, mark up the trip sheet to cover expected weights and pressures for every 5 stands in open hole. • A figure of maximum set down weight will be given to the Driller. This will again be driven by past experience and the potential for hole problems. • When a float is included in the string then the pipe will be filled every 10 stands while inside casing and every five stands when in open hole. Rev. 1, April 2010

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• When top filling the pipe allow the air to escape. Trapped air can cause problems when circulated round the system. • It is good practice to periodically pick back up and check the drags are OK. • Make sure the crew is not distracted during the trip; good communication is the key to a safe operation. • Make sure the string weight follows the expected figures taken from the Driller’s Trend Sheets. • Look for signs of losses or the string wanting to rotate; either of these signs may give early warning to potential hole problems. • Watch when running down through previous casing shoes and sumps. • If problems are encountered while RIH, be aware of the stabiliser sizes and distances between them. • If breaking circulation above a trouble spot, then pull well clear and follow the procedure detailed in Section 7.2.5 above. • All trouble spots are to be recorded on the Section Schematic. • Are there any survey or logging overlaps required before getting to bottom? • No matter how good the hole condition appears to be, always wash and rotate the last 2 stands to bottom. • If using a rotary steerable assembly, while breaking circulation the Directional Driller is to toggle to "Steer Force Zero" to help centralise the BHA and reduce vibration while reaming to bottom. • An SCR is to be taken as soon as possible after reaching bottom.

7.3 Bits 7.3.1 Rock Bits 7.3.1.1 Running In • Make up the bit to the correct manufacturer's recommended torque. • Run and pull the bit slowly through ledges, doglegs and liner tops. • Most rock bits are not designed for heavy reaming. If you do have to ream then use light weight and low RPM (minimum 60 RPM) so as to reduce the risk of crimping the shirt-tails. page 114

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• Protect nozzles from plugging by using jet plugs or a float in the string. 7.3.1.2 Establish a Bottom Hole Pattern • Rotate the bit and circulate when approaching bottom. This will prevent plugged nozzles and will clear out any fill. • Lightly tag bottom with low RPM. • Gradually increase the RPM. • Gradually increase the weight. 7.3.1.3 Before Re-running Green Bits • Make sure that the bit is in gauge. • Check the bit for complete cutting structure. • Check any sealed bearing bit for effective seals. • Soak any sealed bearing bit in water or diesel to loosen formation packed in the reservoir cap equalization ports. • Re-grease open bearing bits of 14-3/4" diameter and larger.

7.3.2 PDC/Diamond Bits 7.3.2.1 Running the Bit (Rotary Assembly) • Handle the PDC or diamond bit with care. Do not set the bit down without placing wood or a rubber pad beneath the cutters. • The correct bit breaker should be used and the bit should be made up to the correct torque as determined by the manufacturer. • Care should be taken in running the bit through the rotary table and through any known ledges or tight spots. • Reaming is not recommended however, if necessary, pick up the Kelly or TDU and use as much circulation as possible. Rotate at a minimum of 60 RPM. The maximum weight on bit while working through tight spots should be 2 - 5 Klbs. • When approaching bottom, the last stand should be slowly washed and rotated down using full pump and a minimum of 60 RPM. • Watch for a combination of both weight and torque as bottom is tagged.

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• Once TD is tagged, pick back up 1 ft and jet bottom for 5 to 10 minutes using maximum pump and slow rotary. • After flushing bottom, ease back down and be patient establishing the new bottom hole pattern. • When ready to start drilling, increase the rotary speed to about 100 RPM and start cutting the new gauge pattern with approximately 1,000 - 4,000 lbs WOB. • Cut at least one foot in this manner before determining the optimum bit weight and RPM for drilling using a drill off test. 7.3.2.2 Running a PDC/Diamond Bit with a Motor or Turbine • Break in the bit as per the guidelines above. • As weight is increased, pump pressure will also rise so the differential pressure and WOB must be kept within the recommended downhole Motor/Turbine limits. • The drillstring should still be rotated to smooth the application of weight and prevent differential sticking. • All other operating practices are as per standard practices. Common PDC/Diamond Bit Drilling Problems and Actions Problem

Probable Cause

Preferred Action

Difficulty going to bottom.

Previous bit undergauge. New bottom hole assembly.

Ream with roller cone bit. When reaming to bottom, pick up and ream section again. If difficulty remains, check stabilizers. Roll casing with smaller bit. Use bi-centred bit, or reduce bit size. Gauge bit with API gauge; if not in tolerance, replace bit. Replace with correct size stabilizer.

Collapsed casing. Out of drift. Bit oversized. Stabiliser oversized. Low differential pressure across nozzles or bit face.

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Flow area too large. Flow area too small (flowrate?). Different drilling parameters than designed for. Washout in drill string.

Increase flowrate and correct on next bit. Increase flowrate/strokes or change liners. Attempt to optimize flow area on next bit change. Check bit pressure drop, drop softline, trip to check pipe and collars.

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Problem

Probable Cause

Preferred Action

High pressure differential across nozzles or bit face.

Flow area too small. Excessive flowrate. Diamonds too small for formation.

Reduce flowrate, change flow area on next bit. Reduce flowrate. If ROP acceptable, change on next bit. If ROP unacceptable, pull bit and use bit with correct diamond size. Check off bottom standpipe pressure. Let bit drill off, circulate full volume for 10 minutes while rotating and checking pressures. Pick up, circulate, resume drilling at higher RPM, reset, drill off test On and off bottom pressure test, pull bit. Refer to manufacturer's handbook.

Bit partially plugged (Formation impaction). Formation change. Ring out. Downhole motor stalled. Fluctuating standpipe pressure.

Drilling through fractured formation. Formation breaking up beneath bit. Stabilisers hanging up. Equipment failure.

Bit won't drill.

Bottom not reached. Stabilisers hanging up or too large. Formation too plastic Establishing bottom hole pattern. Core slump left. Bit balled.

Slow rate of penetration.

Not enough weight on bit; hydraulic lift. RPM too low/high. Plastic formation. Change in formation. Overbalanced. Diamonds flattened off. Cutters flattened. Pressure drop too low. Wrong bit selection.

Rev. 1, April 2010

If ROP acceptable, continue. If ROP acceptable, continue. Check equipment. Try combination of lighter weight and higher RPM. Check overpull. Check stabilisers on next trip. Repair equipment. Check tally. Check torque and overpull. Check pressure: increase flowrate, decrease/ increase bit weight and rpm. Can take up to an hour. Attempt to carefully drill ahead with low bit weight. Back off and increase flowrate, then slug with detergent or oil. Increase weight on bit. Increase/decrease RPM. Reset drill off or reset weight. Reset drill off or accept ROP or pull bit. Accept ROP or pull bit. Compare beginning and present pressure drops - new bit may be required. Increase weight or pull bit. Increase flowrate - new bit may be required. Pull bit.

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Problem

Probable Cause

Preferred Action

Excessive torque.

Excessive weight on bit. Slow rotary speed. Stabilisers too large. Collars packing off. Bit undergauge.

Reduce weight and RPM. Increase RPM, or decrease weight. Check BHA, stabilisers should be 1/32” to 1/16” under hole size. Increase flowrate and work up and down. Pull bit.

Slip-stick action. Broken formation. Pump off force.

Change RPM/weight combination. Reduce RPM and weight. Increase weight or decrease pump rate.

Bit bouncing.

7.4 Rules for Optimising Hydraulics 7.4.1 Flowrate • Maintain 30 to 60 gpm per inch of bit diameter, or more. • Too low a flowrate will “ball” the bit and reduce effective hole cleaning. • To high a flowrate increases ECD and erodes soft or unconsolidated zones. • Slow drilling with mud requires a minimum of 30 gpm per inch of bit diameter. • Fast drilling with low mud weights requires 50+ gpm per inch of bit diameter, especially at high inclinations. • Typically 35% to 50% of pump pressure is lost through the drill string and annulus. Hydraulic calculations are required to determine these losses. • If pressure losses in the drill string exceed 50% of pump pressure, bit pressure drop should be sacrificed to gain flowrate and improve hole cleaning.

7.4.2 Hydraulic Horsepower at Bit • Based on flowrate and pressure drop at the bit. • Higher flowrates and smaller nozzles will increase hydraulic horsepower (HHP) at the bit. • HHP per square inch of bit face (HSI) is a measure of hydraulic energy used at the bit. • Optimum HSI values vary widely depending on formation type, bit type and BHA configuration. page 118

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• Higher HSI values are not always better. • Higher HSI should be considered when pump horsepower is available. • Many rigs do not have enough horsepower to provide the recommended horsepower and flowrate.

7.4.3 Jet Velocity • Maintain jet velocity between 350 and 450 feet per second. • Jet velocity (ft/sec) is the velocity of the fluid exiting the jets. • Impact force - the product of fluid jet velocity and fluid weight. Impact is the force the drilling fluid exerts to the formation to assist bottom hole cleaning. • Jet velocity will influence chip-hold-down and penetration rate. • Do not operate with a jet velocity below 250 ft/sec. • For small holes, (9½" and smaller) and slow drilling, consider running 2 jets versus three to improve bottom hole cleaning and penetration rate. Two large jets are less likely to plug than three small jets (same total flow area, TFA). • If a long hole section is planned for the next bit, consider running 3 jets and dropping a diverting ball in the lower part of the hole section to maintain jet velocity. • Asymmetrical jets are often run to improve penetration rate versus using two jets.

7.5 Hole Cleaning Hole cleaning guidelines are taken from DOGS 4900/GEN and Hole Problem Data Package TS-D-003. The single most important factor relating to hole cleaning in deviated wells is flowrate (i.e. annular velocity). During directional drilling operations, drilled cuttings will settle on the low side of the hole and form a stationary bed if insufficient annular fluid velocity is used. The critical flowrate (CFR) required to prevent cuttings bed formation can be determined from the BP Hole Cleaning Model. When planning a well it is imperative that mud pumps of sufficient size and capacity are selected to achieve this required rate. Typically few hole cleaning problems exist in vertical or horizontal sections. Most problems associated with hole cleaning are seen on deviated wells and occur in the 50 - 60 deg section where gravity effects can cause cuttings beds to slump down the hole. The BP Hole Cleaning Model should be used in the planning of all wells and in particular Extended Reach applications.

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Typical flowrates to aim for in ERD wells are given below. Hole Size

Typical Flowrates

17½”

1100 gpm minimum. Some rigs achieve 1250 - 1400 gpm.

12¼”

Aim for 1100 gpm (although 800 - 1000 gpm is typically achieved). If 1000 gpm is not achievable, ensure tripping procedures are in place for poorly cleaned hole.

8½”

Aim for 500 gpm.

7.5.1 Circulating Prior to Tripping The BP model simply predicts the minimum flowrate required for adequate cuttings transport. No predictions are available for the rate at which cuttings are removed. Because the cuttings move more slowly than the circulating mud, it is essential that sufficient bottoms-up are circulated prior to tripping. A SINGLE BOTTOMS-UP IS NEVER ENOUGH! The minimum on bottom circulation time prior to tripping will be influenced by hole size, inclination and flow history (i.e. mud properties and flowrate). These factors will affect the height of any residual cuttings beds. Before tripping, monitor the shakers to ensure the cuttings return rate is reduced to an acceptable background level. If available, use the PWD data to determine that the ECD has leveled out to a minimum value. When drilling a well with a long horizontal tangent such as an S-shaped well, consider circulating bottoms-up in stages, for example from TD, from the bottom of the horizontal section and at 60 degree inclination. The circulation times in the table below are guidelines based on simple slip velocity considerations and field experience: Range

17½ inch Hole

12¼ inch Hole

8½ inch Hole

6 inch Hole

0° - 10°

1.5

1.3

1.3

1.3

10° - 30°

1.7

1.4

1.4

1.4

30° - 60°

2.5

1.8

1.6

1.6

60°+

3.0

2.0

1.7

1.7

7.5.1.1 Procedure 1.

Effective Length = Section Length x Section Length Factor.

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Circulation Time = Effective Length (MD) x B/U Actual Length (MD)

7.5.1.2 Example Since in practice not all of the section back to surface will be deviated at the same angle, the overall minimum circulation time prior to tripping should be apportioned in direct relation to the relative lengths of section at each angle. This is illustrated in the following example for tripping out of 17½ inch hole at 7,710 ft (2,350m).

Number of Circulations 850m x 1.5 (0 deg)

(850m x 1.5) + (300m x 1.7) + = (400m x 0.25) + (800m x 3.0) 850 + 300 + 400 + 800 = 5185m 2350m = 2.2 x B/U

18 5/8" csg 300m x 1.7 (10-30 deg)

400m x 2.5 (30-60 deg)

800m x 3.0 (60 deg)

7.5.2 High Angle Hole Cleaning Guidelines 7.5.2.1 While Drilling • Maintain sufficient mud weight to stabilize the wellbore as hole angle and/or formation pressure increases.

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• Use proper low end rheology for hole size and angle to maximize hole cleaning. • Circulate at maximum rate for hole size and hole angle. • Limit the ROP to the maximum recommended for hole size and angle. • Ream each stand (or half stand) drilled with a down-hole motor. • Rotate at high RPM (100+ if possible). Raise the drill string slowly (e.g. 5 mins/ stand). Lower the drill string at a safe, but fast rate (i.e. 1 min/stand). • Continue reaming if hole conditions dictate. • Consider a wiper trip after drilling a long section with a downhole motor to mechanically agitate and remove cuttings beds. • Consider reducing ROP or stopping drilling and circulating until hole conditions improve. 7.5.2.2 At Connections • Make sure the hole is adequately clean before making the connection. • Start and stop rotation slowly. • Prepare the crew and equipment to minimize connection time. • Record free rotating weight, pick-up weight, slack-off weight, off-bottom torque and circulating pressure for trend indications of inadequate hole cleaning. • Pull the slips and slowly rotate the drill string first (to break the gels), then increase pump speed slowly. Carefully lower the drill string to bottom (this exact procedure will depend on the Survey Tools in use at the time).

7.5.3 Lost Circulation References: See BP's Lost Circulation Manual or relevant section of Hole Problem Data Package. For all drilling operations, lost circulation prevention procedures should be considered. Listed below are measures which can be taken to prevent losses occurring. • Increase in annular mud weight due to drilled cuttings can result in formation breakdown, particularly in surface holes. The effective increase in annular mud weight must be calculated and taken into account. page 122

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• Viscosity and gel strengths of the mud should be maintained within the programme specification. If the yield point is too high, breaking circulation may induce losses. On breaking circulation, always start circulation slowly and speed up the pump only after returns are obtained. If viscosities are very high, circulation should be broken at stages whilst running through the open hole. High viscosity can increase the ECD to a level which will break down the formation whilst circulating. When calculating ECD values in critical situations, account should be taken of the OD of pipe connections. The effect of drill pipe rubbers should also be considered in such situations. • Excessive surge pressure whilst running in the pipe can fracture the formation. In areas of potential lost circulation, surge pressure calculations should be performed and the driller instructed as to the maximum allowable speed for running pipe. Note: Surge pressure is placed on the formation the moment the string is run in the hole. In areas of potential lost circulation, tripping speeds must be controlled all the way to/from surface. • In areas of hole instability sloughing or swelling shales can pack off around the pipe reducing or preventing circulation. If the pump is not slowed or stopped at this point, the formation can be broken down. The driller should be made aware of areas of potential hole instability.

7.5.4 Spotting Procedures for Lost Circulation Material (LCM) Pill • Locate the loss zone. • Mix 50-100 barrels of mud with 25-30 ppb of bentonite and 30-40 ppb LCM. • Position the drill string +/-100 feet above the loss zone. • If open ended, pump ½ of the pill into the loss zone. Stop the pump, wait 15 minutes and pump the remainder of the pill. • If pumping through the bit, pump the entire pill and follow with 25 barrels of mud. • If returns are not regained, repeat procedure. If returns are still not regained, wait 2 hours and repeat procedure. • If returns are not regained after pumping 3 pills, consider other options to regain circulation.

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7.5.5 Spotting Procedures for Speciality Lost Circulation Material (LCM) Pill • If possible, drill through the loss interval. • Pull out of the hole and return open ended. • Position the string +/- 100 feet above the loss zone. • Clean the mixing pit thoroughly. Mix 50 barrels of desired speciality pill. • Pump down the drill string and place in suspected zone. If annulus is not full, pump mud down the annulus while pumping pill down drill string. • When annulus fills and squeeze is in place, apply 150-200 psi on annulus. This will “soft” squeeze the material into the loss zone.

7.5.6 Spotting Procedure for Cement • The cement slurry formulation should be tested by the cement company to determine the thickening time. • If possible, drill through the entire loss circulation interval. • Pull out of hole and return with open ended drill pipe. • Position the string +/- 100 feet above the loss zone. • Mix and pump 50-100 barrels of cement slurry. • Follow the slurry with a sufficient volume of mud or water to balance the U-tube. • POOH and wait 6-8 hours and attempt to fill the annulus. • Repeat the procedure if returns are not regained. • It may be necessary to drill out the cement before repeating the procedure.

7.5.7 Loss Circulation Prevention Guidelines • Prevention of lost circulation must be considered in the well planning, drilling and post analysis phases. • Design the casing program to case-off low pressure or suspected lost circulation zones. • Maintain mud weight to the minimum required to control known formation pressures. High mud weight is one of the major causes of lost circulation.

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• Pre-treat the mud system with LCM when drilling through known lost circulation intervals. In extreme cases, 40+ ppb LCM concentrations have been successfully used in drilling applications. • Maintain low mud rheology values that are still sufficient to clean the hole. • Rotating the drill pipe when starting circulation helps to break the gels and minimise pump pressure surges. • Start circulation slowly after connections and periods of non-circulation. • Use minimum gpm flowrate to clean hole when drilling known lost circulation zones. • Control drill known lost circulation zone to avoid loading the annulus with cuttings. • Reduce pipe tripping speeds to minimise swab/surge pressures. • Plan to break circulation at 2 to 3 intervals while tripping in the hole. • Minimize annular restrictions. • Consult motor and MWD/LWD vendors for LCM compatibility. • Consider using jet sizes or TFA that will allow the use of LCM pills (12/32"+ jets). • Be prepared for plugging pump suctions, pump discharge screen, drill string screens, etc. • Be prepared for mud losses due to shaker screen plugging.

7.5.8 Precautions While Drilling Without Returns Circumstances may dictate drilling blind until 50 feet of the next competent formation is drilled and casing is set to solve the lost circulation problem. A blind drilling operation MUST have Drilling Manager approval. • Ensure an adequate water supply is available. • Use one pump to drill and the other pump to continuously add water to the annulus. • Assign a person to monitor the flowline at all times. • Closely monitor torque and drag to determine when to pump viscous sweeps. • Closely monitor pump pressure while drilling for indications of pack-off. • Control drill if possible at one joint per hour.

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• Pick up off bottom every 15 feet (3m) drilled to ensure the hole is not packing off. • Keep the pipe moving at all times. • Maintain a 400-500 barrel reserve of viscous mud ready to pump. • Consider spotting viscous mud on bottom prior to tripping or logging. • Stop drilling and consider pulling to the shoe if pump repairs are required. • Start and stop pipe slowly and minimize pipe speed. • Prior to each connection, circulate and wipe the hole thoroughly. • Consider spotting a viscous pill above the BHA prior to each connection. • Do not run surveys when drilling blind. • If circulation returns, stop drilling. Raise the drill string to the shut-in position. Stop the pumps and check the well for flow. • If flow is observed, close the BOP and observe shut-in pressures: • No pressure - slowly circulate bottoms-up through 2 open chokes. • Pressure observed - slowly circulate the kick with the Driller’s Method and current mud weight. Be prepared for an underground blowout condition. • Be prepared at all times to pump cement into the well.

7.6 BHA Design The checklist opposite has been designed for use by either our onshore DEs or our offshore WSLs to ensure the BHAs being proposed by our suppliers have considered the drilling environment in its entirety and document the assumptions and inputs that have been made to inform the BHA design.

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Well Typ e

Rev. 1, April 2010 TFA

Max

ID

TVD

MD

Yes / No

Yes / No

Design considers survey requirements

STP Dis pensation in place for BHA

Yes / No

Critical RPM

Critical RPM to avoid

RT / Mem RT / Mem

RT / Mem

NMR Sonic

BHA operating hrs

Yes / No

Yes / No

BSRs computed a nd reviewed

Conne ction review: Cross-overs minimis

No LWD / E-Line overlap:

RT / Mem

RT / Mem

FPWD

RT / Mem

RT / Mem

RT / Mem

RT / Mem

RT / Mem

RT / Mem

RT / Mem

RT / Mem

RT / Mem

Jar distance from bit

Jar placement modelling acceptable

RT /Mem RT / Mem

Neutral Point distance from bit

Neut

RES

GR

APWD

Bending

DH Torque

DH WOB

ECD limit (max allowable)

Yes / No

Yes / No

Yes / No

Torsional vib:

Axial Vib

Lateral Vib

Den

Yes / No

Yes / No

Yes / No

Yes / No

Hole cleaning flo w rate

< rig limit + safety factor

Yes / No

Hydraulics

Tendency OK

Yes / No

Bending

Fishing Diagrams

Planned SPP

Yes / No

Stres s

ECD vs depth

SPP vs Depth

Surface Torque

Stick-slip

OK for ROP

Tool Face

Yes / No

Yes / No

.

Bit-Sensor

BHA limits

Fishable sourc Yes / No

Battery life OK Yes / No

Fmn Slownes s

# Press Pts

Yes / No

Yes / No

Yes / No

Azi

Yes / No

Yes / No

Yes / No

Yes / No

Data density Pot. Haz ard

cDnI Yes / No

Ye s / No

Ye s / No

Yes / No

Temp

Min downlink flow

Pla nned

Max

Pla nned

Max

Rig Limi t

:

Jar ID:

PV

Mud Weight

Mud Type

Dart Sub ID:

Rig Limi t

Target

Max

Pl anned K Revs

W OB limits acceptable

:

: Ye s / No

H 2S :

YP

Max

Min

Plan ned

Circ.

Static

Formatio n fluid pressure

Max Flo w for pumping LCM (tool off)

BHA/Tool LCM limit

Max

CConcentration

LCM name

BHA/Tool te mp limit

L imiting factor DWOB

Yes / No

Yes / No

En vironment accepta ble for all tools

Bo ttom Hole Temp :

Max Ove rpull

Pla nned

Max Surface WOB (avoid bu ckling)

B HA / Too l RPM limit

RPM range :

B HA/Tool Hydrostatic P ressure limit

CO2

Maximum San d content Maximum Sol ids conten t pH :

P ump strokes rang e

Drill Pipe # 2

Location

Len gth

Connection

OD / ID

HWDP

Adjusted wt

Nominal wt

Len gth

Pipe Class

Connection

OD / ID

Float Sub

Pipe class

LCM Grade

Temp lower limit

Yes / No

Mu d Type

Accel ID:

Valve Type Float Valve

Location

Float #2

Location

Max particle size

Yes / No

Minimum BHA pa ss-thro ugh

P ump Liners

Limiting fa ctor

Float Sub

Va lve Type Float Valve

Lo cation

Float #1

Totco / UB HO

Su rface screen

Filter flow range

BHA Downhole fil ter

Le ngth

Connection

OD / ID

Chloride concentration

Ye s / No

Ye s / No

Pipe class

Drill Coll ar (BHA Default)

Adjusted wt

Nominal wt

Le ngth

Pip e Class

Connection

Rig SPP Limit

Tool flow r ange acceptable

P lanned flow ra nge:

Antic ipated Torque range:

Turbine OD

RSS + MTR - Motor wi red

Ye s / No

Ye s / No

Ye s / No

Drill Pipe #1 OD / ID

Wellsite Leader’s Handbook

BHA tendenc y Yes / No

Yes / No

Yes / No

Yes / No

Torque

Fatigue

Plots Provided

Drag plot (crows foot)

Yes / No

Tens ion True/

Side forces

Yes / No

Yes / No

Non-mag protection adequate: MWD Stab in limits for SAG correction.

Yes / No

Too lface

RRotating Fric

Azi

Inc

MWD flow range

MWD Telemetry rate

UR (%)

Bi t (%)

Measurements (GR, Inc, Azi, Dynamics, To

Flow distribution

A ctivation ball size

B ack p ressure required RT Comms to MWD

TFA

Q ty / Size

V ertical RSS

Flex requi red

Reamer Nozzle s (min for L CM?)

RSS Type

Ye s / No

Motor type

Motor environment

Ye s / No

B HA Type

B HA Type

Max achievab le DLS

Upper & Bit box connection

Underre amer type

Bit features

Type

S tabilisation on RSS (OD)

Bit features

Max Build force Bit features

Motor Nozzle

Delta Pr essure

Rotor catcher

S leeve Stabiliser Size

B it-box sta biliser Size

Bend (AKO) range & angle required

Underre amer / Hole opener Size

Bit features

Environment

Upper & Bit box connection

Motor type

Rotor / S tator Config.

Motor OD

Other fe ature s Bit features

Bearing

Bit Type

B HA Type

B HA offset provided

S tabilisation principle

RSS OD

:

Bit Type

Bit Type

Diamo nd typ e

Gauge length (side c utting capability)

SSliding Drag

Rotating Fric

Sliding Drag

Engineering Conducted

Open Hole Friction Factor

Cased Hole Friction Fa ctor

Well Tortuosity

Yes / No

Major ris k scan report

Well tortuosity

Yes / No

Anti-collis ion Travelling Cylinder plots

Plots / Repo rts Pro vided :

Yes / No

:

Cutter size

:

RPM Range

:

Bit co nnection

H.S.I.

Qty / Size

Blade s hape

:

:

:

:

Max K Revs (Roller cone)

Pressure Drop

TVD

# of b lades

MD

Previo us csg sho e in build section

Last Casing Shoe

Section length (ft / M)

Section TD (ft / M)

Bit Nozzl es

Min

Manufacturer

Inclination

Yes / No

A chievable w/BHA:

Bi t Type

Bearing (Roll er, Fri ction, Seale d):

Roller Cone - Bit Type

DOR

Yes / No

A chievable w/BHA:

BUR

Yes / No

Diamond type

Bit Size Diamond Bit Type

Max

Well Typ e

P lanned

Slide / rotate DLS limits not exceeded

Dog-L eg Se verity

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8. Directional Drilling and Surveying References: Functional Expectations of WSL • 2.2.5 The WSL shall ensure that all planned activities are risk assessed and adequate mitigations are in place. • 2.3.1 Ensure that there is a process in place to track and optimise expenditure on high cost rental tools. • 2.5.1 Ensure that all downhole tools are visually inspected prior to running in hole (i.e. thread conditions, seal areas, jet sizes and bit type). Any new tools should be drifted. • 2.5.3 Ensure that the dimensions of any item run in the hole are recorded, correct for their application and a fishing diagram is available. • 2.5.5 Brief the BP Contractors as they arrive on the installation regarding their duties and BP's expectations for HSE and operational performance. • 2.5.6 Ensure that a copy of the Drilling Programme (plus any subsequent amendments) is distributed to the Drilling Contractor, Key Service Company Personnel and other BP Supervisors (e.g. WSS/CS). • 2.5.7 Ensure that all equipment is run within its operating limits and is rated for the intended purpose. • 2.5.10 Ensure that Well Surveying is conducted in line with the programme - in particular that travelling cylinder limitations are adhered to. • 2.5.11 Ensure that deviations from the approved programme/plan are discussed with town. Operations shall only continue after an agreed forward programme is established, with risks understood and the Management of Change process completed as required. SMS Documentation • GP 10-05 Directional Drilling and Surveying. • GP 10-35 Well Operations. • BPA-D-004 Directional Survey Handbook.

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8.1 Roles and Responsibilities 1.

Survey programmes will be designed so that the well location is known with sufficient accuracy to: • • • • •

Meet with local government regulations. Penetrate the geological target(s) as set in the well's objectives. Minimise the risk of intersection with any adjacent well. Drill a relief well. Avoid the location of any shallow hazards.

2.

Survey programmes shall be carried out by the contractor in accordance with a predefined quality assurance programme. All procedures, directional software settings and tool specifications are part of the Joint Operating and Reporting Procedures (JORPs) set up between BP and its contractors. This procedure shall be available at the wellsite.

3.

Where operational problems occur, any modifications to the programme shall be shown to fulfil the same requirements as did the original design.

4.

A database will be kept of planned and actual well trajectories including all project data including slots, targets, locations and projections. This safety critical database shall be the subject of a written plan which describes how it will be managed throughout the life of the field.

5.

It is the responsibility of the Wellsite Leader to: a) Follow the survey programme. b) Observe the ant-collision tolerances while drilling. c) Report any non-conformances with either the program or JORPs.

6.

It is the responsibility of the Directional/Surveying Contractor to: a) Design well trajectories and survey programmes in accordance with an agreed process for technical integrity and the appropriate BP policies and guidelines. b) Compile and retain Directional Drilling Planning packages for the purposes of traceability and subsequent audit. c) Monitor operational conformance with the programme and initiate any required design reviews or changes. d) Ensure the definitive survey database is used correctly and kept up-to-date. e) Check all survey data used in the programme for compliance against JORPs.

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f) Compile comprehensive well survey files. g). Create the final definitive survey.

8.2 General 1.

A vertical well is one which at no point in its path reaches 10 degrees inclination. Once 10 degrees is reached the well is then classed as directional.

2.

The geological target boundary is laid down by the subsurface team and describes the actual geological constraints which are to be imposed on the well. The Operations Drilling Engineer takes the geological target and shrinks it in accordance with the likely survey errors. It is this boundary that is used as the drilling target.

3.

Isotropic rocks, such as sandstone, behave in the same manner no matter from which direction they are approached and provide a predictable formation when directional drilling.

4.

Anisotropic rocks, such as shales, do not exhibit the same properties in all directions. As the bit rotates, larger chips are formed on one side of the bit than the other, and so the bit will be turned away from its original axis.

5.

As with any BHA it is important to make sure that all first line fishing gear is available. Special consideration must be given to large bodied motors and other directional equipment.

6.

“Dog-leg severity” or DLS is a measure of the total three-dimensional change in angle between two given directions and is normally measured over 100ft or 30m. The higher the DLS the more difficult it will be to get casing to bottom and also the greater will be the subsequent casing/drillpipe wear and fatigue. The maximum acceptable DLS will increase with depth. The following table gives a general rule of thumb for the maximum DLS per hole section.

7.

Hole Size

DLS (°/30m)

17½”

3.5

12¼”

5

8½”

6.5

The build and drop characteristics of a particular BHA will be determined by the relative size and position of the first two or three points of contact above the bit. The following assemblies would tend to build:

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Bit - Stab - DC - DC - Stab - DC - Stab. Bit - Stab - DC - DC - DC - Stab. Whereas the flowing assemblies would be expected to drop: Bit - DC - Stab - DC - Stab - DC. Bit - DC - DC - Stab - DC - Stab. 8.

Whenever possible, do not make up the bit before testing a mud motor. If there is no option, then make sure the bit is well centralised and will not damage either itself or any part of the BOP, Wellhead or Riser equipment.

9.

If the well or sidetrack modelling shows that high torque may be experienced towards TD, then mobilise friction reducing mud additives, drillpipe rubbers or lofriction subs in plenty of time.

10. If torque becomes a serious problem, then oil based mud and/or a tapered drillstring may be required to overcome high TD torques. 11. When running directional equipment such as Andergauge or rotary steerable equipment, make sure that all components are compatible with each other and that tool settings or ball sizes will not conflict. 12. Before running a motor and bent sub assembly, check with the service company as to any rotary speed or torque limitations which could affect the ability to clean the well. 13. To reduce vibration and survey inaccuracies, try to avoid running the MWD and FEWD tools in the belly of a directional rotary assembly. 14. When drilling with a combination of slides and rotation, hole cleaning will only be effective when rotating. Make sure that the Driller and Data Engineer lag each bottoms-up from when starting to rotate, so that shaker and CRI hands are prepared for the next wave of cuttings. 15. Reducing the pump rate will help prevent washing out ahead of the bit and will help with the BHA directional response. If flowrates are reduced to help achieve the required build, then spend more time clear of bottom circulating to clean the hole before making the connection. 16. When sliding with a motor assembly, as the bit spins to the right there will be an opposite Left Hand reactive torque imparted on the drill string. This reactive torque must be allowed for when setting up a toolface. PDC bits are more aggressive and will lead to more reactive torque being seen, whereas using larger OD drill pipe will help counteract this effect. As a rule of thumb in soft formations, between 30 and 35 degrees of reactive Left Hand torque can be expected per 1000m of hole depth. Rev. 1, April 2010

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17. The following rules of thumb can be applied for Highside Toolface settings in soft to medium homogeneous formations: For angles up to 30° inclination: 0°

= Maximum Build

45°

= Build and Right Hand Turn

90°

= Maximum Right Hand Turn

135° = Drop and Right Hand Turn 180° = Maximum Drop For angles of over 30° inclination: 0°

= Maximum Build

0 - 40°

= Build and Right Hand Turn

40 - 60° = Hold Inclination and Turn Right 60 - 90° = Drop and Turn Right With increasing angle, the tendency to drop between 60° and 90° will be increased. 18. When using an automatic kick-off (AKO) motor, ensure that the scribe line to the MWD tool is taken from the toolface high side reading, not the bend angle. 19. A motor will stall when the power the motor supplies is insufficient to overcome the torque needed to turn the bit. The stall will cause the pump pressure to rise as the mud is forced passed the now static rotor and the toolface will spin violently to the left. Repeated stalling will lead to premature damage being done to the stator element and sections of rubber should be looked for at the shakers. To help prevent stalling the WOB can be reduced and/or the flowrate can be increased. As stalls are often caused as a result of hitting a stringer, increasing the flowrate could cause a washout to be formed above the stringer. The Driller will need to be briefed over the best, or often least damaging option to be followed. 20. When circulating clean with a bent housing or bent sub in the string, circulate the first two bottom's up and then set the tool on high side to reduce the undercutting effect of rotation and also reduce the stress induced on the equipment. 21. When drilling a directional well be careful that all team members are aligned and focussed on the same goal of delivering a quality section with casing run and cemented on depth. An over-enthusiastic Directional Driller can waste valuable time in trying to stick to the line and in the process cause hole cleaning, tripping and casing running problems. page 132

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22. Be careful that the Directional Driller does not introduce a high dog-leg immediately below the previous shoe in his attempt to get “ahead of the line”. 23. When using rotary steerable tools, the Directional Driller must set up his surveying technique to suit the hole conditions. If ESD and ECD are of concern then downlinking may be safer done off bottom or after wiping the stand clean. 24. When circulating clean and working the pipe with a Rotary Steerable assembly, then toggle the tool to "Steer Force Zero" while circulating and then to "Ribs Off" for the trip out of the hole. 25. When using survey calculation programmes, make sure that the azimuth being used is referenced to the correct North value. Different instruments are referenced to different North values. For instance, an MWD or Magnetic Single Shots read relative to Magnetic North whereas a Gyro will read relative to True North. Before inputting the raw data the Azimuth results may need converting. 26. The following sketch shows the different “North” definitions and gives the calculation required to convert from one to another: True North:

The direction of a line pointing straight at the North Pole.

Grid North:

Properly referred to as a Projection or Mapping Grid North. It refers to the North direction used on maps.

Magnetic North: The direction in which a compass points: parallel to “force field” lines of geomagnetic field. Convergence:

The angle between True North and Grid North.

Declination:

The angle between True North and Magnetic North.

True North Magnetic North

DECLINATION West = -ve East = +ve

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Grid North

CONVERGENCE West = -ve East = +ve

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8.3 QA Checks and Survey Procedures 1.

Only qualified survey instruments or those approved by the Drilling Technology Group are to be used.

2.

The WSL must ensure that the Surveyor carries out his QA checks against the particular survey instruments being supplied. These checks must include a cross reference of serial numbers against the bench test calibration certificates.

3.

Once a survey has met the Surveying Contractors' individual QA criteria it is then checked against the Joint Operating and Reporting Procedures (JORPs) criteria for that particular instrument. Once the survey has satisfied this criteria then all the well survey results are collated into one definitive Survey. This survey represents the best estimate of the well's position that can be made from the available survey data.

4.

When kicking-off in a zone of known magnetic interference, Gyro single shots will be used. Cluster shots will be taken every 30 feet or as directed by the individual survey programme. Gyro surveys will be used through to the end of magnetic interference at which point sufficient overlay will be required between the Gyro and the Magnetic survey instruments.

5.

When preparing to nudge or kick-off a well using gyro instruments, the WSL should witness the setting up of the UBHO orientation key and confirm that the leading edge of the sleeve has not become worn and flattened. If a bent sub is being used the WSL should also confirm that the scribe line is actually machined on high side.

6.

When kicking off from a multi-well location, have the Directional Driller follow the scribe line down by marking each stand run to seabed. This can then be used as a double check when carrying out the all important initial set. Another useful check is to have the ROV log the toolface direction before starting the spud. Both these techniques are useful checks but are never to be used as a substitute for the correct seating procedure as detailed below.

7.

When using a wire line Gyro, the initial orientation check is critical to the success of the operation and indeed the safety of the rig. The following procedure should be adopted to check that both the seating and subsequent set are indeed correct: a) Check that the lead slug is fitted correctly. b) RIH and land off in the UBHO. c) Repeat the seat and confirm the toolface reading is as per the first attempt. d) Take a gyro cluster shot and orient the toolface to the required setting.

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e) Pull the survey instrument and check the slug is marked correctly. f) Re-slug the tool and rerun. Seat once and confirm the toolface is as was. g) POOH and check the slug is correctly marked. 8.

On subsequent runs and after orienting the string, the tool should be re-seated to confirm the toolface before the instrument is pulled and the telltale checked.

9.

Once over 2° inclination, the surveyor should set up a checkshot point and take a check survey on both the in-run and the out-run of all subsequent surveys. This procedure should continue and a second checkshot added after every 150m drilled. Checkshots should be continued at both stations for three or four surveys and then if all is in order, the upper checkshot can be dropped. Individual Gyro survey tools should be changed out after every fourth run.

8.4 Clustershot Surveys 1.

When using normally oriented single shot Gyros, BHA misalignment errors can be significantly reduced by taking four (or more) surveys at different toolfaces and combining them to give a single result. The four surveys should aim to cover each of the four toolface quadrants.

2.

To calculate the corrected azimuth and inclination from a four point cluster shot, use the following procedure: a) Calculate the X-Term and the Y-Term: X-Term = Inclination x Cosine Azimuth and Y-Term = Inclination x Sine Azimuth Shot No. Inclination a. b. c. d.

0.5° 1.2° 1.5° 0.4°

UTM Azimuth

X-Term

Y-Term

060° 115° 190° 320°

0.5 x Cos 060° = 0.250 1.2 x Cos 115° = -0.507 1.5 x Cos 190° = -1.477 0.4 x Cos 320° = 0.306

0.5 x Sin 060° = 0.433 1.2 x Sin 115° = 1.088 1.5 x Sin 190° = -0.261 0.4 x Sin 320° = -0.257

b) Find the Averages of the four X-Terms and four Y-Terms: _ -1.428 Averaging the X-Terms (X) = 0.25 - 0.507 -1.477 + 0.306 = 4 = - 0.357 _ 1.003 Averaging the Y-Terms (Y) = 0.433 + 1.088 - 0.261 - 0.257 = 4 = 0.2508 c) Calculate the True Centre Inclination: _ _ True Inclination = √ (X2 + Y2) = √ (-0.3572 + 0.25082) = √ (0.127 + 0.0629) = 0.4358° Rev. 1, April 2010

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d) Calculate the value of the True Centre Azimuth: _ _ Value of the True Azimuth = Tan -1 (Y / X) = Tan -1 (0.2508 / -0.357) = Tan -1 (- 0.7025)° = - 35.08° e) Determine the quadrant of the True Centre: _ If the Average X Term, X > 0, then the True Azimuth Quadrant = 360° + True Azimuth Value _ If the Average X Term, X < 0, then the True Azimuth Quadrant = 180° + True Azimuth Value _ Now the Average X Term, X = - 0.357, Therefore 180° + (-35.08° ) = 144.92° Therefore the Cluster Shot above gives the survey: 0.4358° Inc. at an Azimuth of 144.92°

8.5 Anti-Collision 1.

By the nature of the drilling operation, the exact position of the bit is uncertain. The magnitude of this positional uncertainty is a function of the type of survey tools and the techniques being used, along with the measured depth, the hole inclination and azimuth.

2.

Before starting to drill any well, the planned well path's separation from existing wells will be determined using anti-collision scans. From this analysis a minimum separation is calculated that will determine which adjacent wells, if any, are to be shut in. The minimum separation criteria are laid down in the Directional Survey Policy and Standards Manual (BPA-D-004).

3.

Each adjacent well will be classified as presenting either a Major or Minor risk. A nearby well presents a Major risk if a collision with it would carry a significant risk to personnel and/or the environment. A well presents a Minor risk if the risk to personnel and the environment in the event of a collision would be negligible.

4.

The BP method of anti-collision control requires that all technical decisions about the placing of tolerance lines are made prior to spud. The key steps are: a) A collision scan is performed to locate nearby wellbores. b) The survey position uncertainty of the planned well and of all nearby wellbores is calculated using BP-validated survey Instrument Performance Models.

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c) Minimum separations and shut-in requirements are calculated for each well. d) Using these minimum separations, tolerance lines are marked on a travelling cylinder plot of the planned well. A copy of this plot, and of any shut-in requirements, is then sent to the wellsite. e) As drilling progresses, the survey programme is carried out according to the programme and the standard running procedures (JORPs) for each tool. After each survey is taken, the “as-drilled” position of the well is marked on the travelling cylinder diagram. 5.

The Travelling Cylinder diagram is presented as a cross-section of the well centred on the “as planned” well plan, meaning that should the well be drilled exactly to plan then at any point along the well path the position of the well would not move from the centre point of the plot.

6.

The diagram has North and not “Highside” as the 12 o'clock position. Each actual or planned well is marked on the diagram so that the distance in feet or metres to the closest wells can be easily measured. After each survey is taken, and independently checked by the contractor's onshore support team, the as-drilled position of the well, expressed as a distance and relative bearing from the planned well centre, will be marked on the anti-collision diagram.

7.

When following the progress against the plan, the surveyors must “look ahead” to the present bit position and then again by the distance of at least one course length to establish if the existing build and turn rates are sufficient to prevent an approach being made on the adjacent tolerance lines. The inability to match the planned build and turn rate will quickly result in accelerating divergence between the planned and actual well positions. Well Site Leaders must be aware that when falling behind the line, the actual well path will not start to approach the planned centre until the planned inclination figure is bettered.

8.

Wellsite staff do not have permission to cross any tolerance line before drilling beyond its respective depth. In the event that lookaheads show a tolerance line is in danger of being crossed, then drilling must stop until the situation has been assessed by the onshore support team.

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9. Sidetracking References: Global Recommended Practice (GRP): Sidetracking, by Mark O. Johnson https://epti.bpglobal.com/C8/C6/Sidetracking/default.aspx

As the planning for sidetracks is usually carried out onshore by the Drilling Engineer, this section includes both offshore lessons and the best practices from the GRP. For a guide to sidetracking location selection etc. please refer to the GRP.

9.1 Open Hole Sidetracking 1.

The sidetracking of a well can be achieved using a wide range of equipment and techniques. Jet deflection bits and simple pendulum assemblies can be used to undercut and so sidetrack a well in soft formations. Unfortunately neither of these techniques offer much in the way of directional control. Open hole whipstocks are to be avoided because of the concern for the tool turning and making re-entry impossible. The most common technique is to set a kick-off cement plug and then use either a motor assembly, or a rotary steerable system to achieve the desired sidetrack.

2.

The following factors should be considered when choosing the position to sidetrack the well: a) The need to minimise the deviation from the original well plan so that the original well objectives can still be met. b) Formation characteristics, e.g. look at the ROPs achieved on the original well and choose a suitable and homogeneous section of formation. c) The need to avoid collision risk with other wells. d) The desire to keep inclinations low but still achieve the original casing shoe target. e) The original wellpath may offer a suitable dogleg at which a successful sidetrack may be achieved. f) Lowside sidetracks will always be easier than coming off on the highside.

3.

When planning to sidetrack using a conventional motor assembly, do not try to meet too many objectives at the same time. Trying to optimise the assembly so

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as to be able to drill ahead, may compromise the primary objective of achieving a successful sidetrack. 4.

When designing the kick-off plug, a minimum of 300 ft should be set. Even when using good placement techniques the top and bottom 75 ft can be expected to be contaminated. Use a slurry weight of 17 ppg (2.14 sg) or if the mud itself is more than 16 ppg, use a slurry that is at least 1 ppg over the mud weight. The kick-off plug should ideally reach a compressive strength of 2000 psi before being drilled on.

5.

Using a mud motor and bent sub will give a more aggressive side cutting action and should be used in preference to a bent housing. Make sure that the bent sub BHA is modelled to check on any rotational limitations caused by the bend. If a bent housing is to be used, consider running an undergauge string stabiliser above the motor to help the side cutting action.

6.

Milled tooth bits, and insert bits in hard formation, are preferred over PDC bits. The bit must be capable of a side cutting action to allow the hole to be undercut and the gauge length must be short enough to allow the bit to follow the new path and not the old hole.

7.

A typical assembly for sidetracking in 12¼" hole with a bent sub would be: Milled Tooth Bit - Mud Motor - 1¾º Bent Sub - NMDC - MWD - 2 x NMDC - 3 x DC - HWDP.

8.

When using a bent housing rather than the bent sub, an undergauge string stabiliser should be run immediately above the motor. It might be possible to run the MWD directly above the bent sub if “In Hole Referencing” can be applied or if the azimuth control is not essential. The bent sub can impact serious stresses on connections and rotational limitations must be modelled by the Directional Drilling contractor.

9.

Dress off the plug down to the required depth. Ideally the cement should be capable of withstanding 10 - 20,000 lbs WOB and 50 RPM before attempting to sidetrack. However this requirement will vary depending on the compressive strength of the formation.

10. Orient the assembly to the required toolface and allow for the reactive torque as detailed in section 8.2.16 above. 11. Time drill at between 1m - 2m/hr then work up and down over the newly drilled section maintaining the toolface at the desired setting. Repeat this process for the next 4 to 5 metres and check for increasing formation cuttings being returned at the shakers. The sidetracking process cannot be rushed, much better to take

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an extra hour or two while control drilling rather than being forced into setting a second cement plug. 12. Confirmation of the sidetrack can be difficult using the MWD. The sidetrack should be called when an increasing trend in formation returns is seen at the shakers and a nominal figure of 30% is recorded at surface. 13. If drilling ahead then there is no need to wipe back up through the sidetrack. On this occasion, the risk of doing damage outweighs the benefit and the passing tooljoints will serve to consolidate the junction. If pulling out of the hole to go back with a drilling assembly and it is desired to wipe the sidetrack, then orient the string to the correct toolface and cut the pumps to minimum strokes before carefully wiping down through the sidetrack. 14. Take extreme care while tripping through the sidetrack especially when running less limber drilling assemblies. Both the Wellsite Leader and Directional Driller should plan to be on the rig floor to witness the safe re-entry into the new hole.

9.2 Casing Exits 9.2.1 Whipstock Windows For cased hole exits, whipstocks are the most cost effective, reliable technique and generate only about 8% of the metal cuttings compared to section milling. However, whipstock window problems can still occur when there is poor cement behind casing (whipstock mill could track down the outside of the casing), harder metallurgies (requiring more than one mill run), or early exits creating a lip at the bottom of the window (often due to improper milling technique). • Good idea to visually show the desired whipstock orientation toolface on a clock face in the well plan as it helps to avoid setting errors. • Always drift the casing prior to RIH with the whipstock. The drift run BHA often includes an in-gauge used bit or whipstock mill, watermelon mill, and casing scraper while picking up drillpipe. • Always double check and gauge ring all whipstock equipment and mills prior to RIH. Ensure that whipstock is set up for proper casing weight range. Verify with the service hand that all equipment has been personally inspected by that person and that all components in the system are well understood. Surprises in what was thought to be going in the hole versus what actually went in the hole continue to cause NPT in BP operations.

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• In rotary milling BHAs a flex joint is typically run between upper and lower string mills - this is found to provide a smoother window and puts less stress on mill connections. • Require that the primary vendor service hand or their relief remains on the rig floor from whipstock BHA makeup to POOH after window milling. • HSE - never use nylon slings to pickup a whipstock as the whipstock edges can cut the sling. Most vendors now have attachment points on back of tray for a safe deployment. Confirm with the vendor. • WSL should witness alignment of whipstock tray with MWD. • Avoid sudden starts and stops while RIH to avoid premature shearing of the shear bolt and loss of whipstock. Extra care needs to be taken on setting and pulling slips to avoid any jolting of the string. This subject is emphasized because there have been several cases of dropped whipstocks reported by BP over the years. Recommend starting with new slip dies. Typical wording in instructions is as follows: RIH with the assembly at a maximum rate of 2 minutes per stand taking care not to spud or catch the slips. Ensure string is stationary prior to insertion of the slips and that slips are removed slowly when releasing the string to continue RIH. These precautions are required to avoid any weakening of the whipstock shear mechanisms. • On bottom trip systems, orient whipstock well above bridge plug or cement top (100 ft above). Diligently avoid errors in depth control, but if they occur whipstock will be close to desired toolface if inadvertently set due to depth control error. • Space out to avoid making a connection while milling the window. • The milling fluid should be circulated at a minimum annular velocity of 150 fpm and have a minimum yield point of 40 lbs/100ft2 for cuttings removal. • HSE - ensure any personnel working around the metal shavings have proper eye protection (goggles/face shield). A recent best practice passed along was to ensure that all hands that may come into contact with these metal shavings should also wear proper metal piercing resistant gloves such as Kevlar lined rubber gloves. • Avoid high WOB during the last 4 feet of the window to avoid jumping off the tray early and leaving a ledge. • If upper watermelon mill is >1/8” under gauge, make dedicating window reaming trip. • A FIT is usually performed after milling the window when kickoff point is above the targeted formation.

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• Avoid rotation of bit or BHA stabilizers on tray of whipstock as they may catch the edge of the tray and dislodge it. • For rotating liner across the whipstock with high dog leg severity (e.g. 12°/100 in 9 5/8”casing) during liner running or cementing, Baku recommends performing a fatigue life estimation to define rotations limit and avoid liner failure. • Uncemented casing - there is no technique available that will guarantee a successful sidetrack on the first attempt. (If this has to be the sidetrack point, add money in AFE for contingency remedial cementing operations.) • Favor a straight section of hole (low DLS) to reduce potential bending torsional stress. • Mill windows with same or higher mud weight than what was used in original wellbore if fracture gradient and lost circulation permits.

9.2.2 Section Milling Section milling followed by a cement kick-off plug to create a sidetrack window is not common anymore since whipstock technology has improved and is usually a lower cost operation. Whipstocks should generally be the first choice. Metal swarf handling is an operation hassle when section milling. However, section milling is still considered for operations where a lowside exit is ideal for hitting the target and/or when very poor cement exists behind parent wellbore casing. For example, a 2008 sidetrack operation in the BP NAG Anadarko basin was having problems with whipstock mills tracking down the outside of poorly cemented 5½" casing. They have since been successfully section milling 30 foot windows in the 5½" casing with an additional benefit of providing a more gradual kickoff to facilitate the running of a 4½" flush joint drilling liner later in the operation. Section milling is also used in offshore platform slot recovery to maintain large hole size when required for multiple casing strings or downhole equipment. This often involves much more casing milling footage and specialized systems for swarf handling. • Set cast iron bridge plug deep enough such that all section milling cuttings could fall downhole and still be below bottom of planned section. • Need to place emphasis on proper milling fluid properties for metal swarf hole cleaning and mitigation of stuck pipe events (e.g. YP > 50, minimum AV of 270 fpm, and sweeps). • Metal swarf from milling can plug surface lines and equipment causing spills. Evaluate restrictive areas in system and remove restriction if possible (e.g. replace

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butterfly valve with knife valves). Additional monitoring of fluid system is warranted during milling operations. Dealing with swarf is a common problem in section milling operations. • Incorrectly sized casing cutter knives have caused significant trouble time in the past. Double check correct size for casing size, weight, and grade. • It is recommended to start the top of the section less than 10 feet above a collar to minimize the chance of backing off casing. That means a collar will always be milled up in section milling operations. • If less than 80% of metal back by weight, pump more sweeps. • At end of job, flush BOPs with side jetted nozzle. • Mill cement down to 5 feet below top of section in preparation for directional kickoff BHA. One disadvantage of section milling is that a lot of formation is exposed that could become destabilized - an important point to consider in selecting the section milling location. Definitely avoid known areas that may be sensitive to destabilisation from even an inhibited milling fluid. 9.2.2.1 Section Milling for Offshore Platform Slot Recovery • Try to confirm top of cement, stringers, and fill with USIT, CBL, etc. prior to making casing cuts to maximize chance of success of pulling casing without multiple cuts. • For long distance section milling and swarf handling refer to the Chirag A-02z slot recovery procedure. It includes good lessons learned for handling swarf, shaved couplings, vibration, stumps, cement sheaths, and mud contamination. • As a guideline, piloted section mills were found to last ~150m (500 feet) at which time it is advisable to POOH to clear BHA of shaved couplings and change out the mill. • Recommended minimum length of 9 5/8" casing to be section milled below a 13 3/8” shoe for sidetracking with a 12¼” bit is: 30m (100 feet) for a motor BHA and 50m (165 feet) for a RSS BHA.

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10. Stuck Pipe and Fishing Operations References: Functional Expectations of WSL • 2.3.11 The WSL will ensure that there is an awareness to the cost of non productive time and that the offshore team are engaged in continuously driving down such NPT. • 2.4.5 Be present on the rigfloor to observe the first 10 stands pulled on every trip out of the hole, and until such times as he/she is satisfied that the hole fill volume is correct. The WSL should continue to monitor the trip until back inside the old hole or inside casing. • 2.5.1 Ensure that all downhole tools are visually inspected before use (i.e. thread connections, seal areas, jet size and bit type). Any new tools should be drifted. • 2.5.2 Be aware of the hole condition at all times and keep the onshore team updated as to this condition and any deterioration. • 2.5.3 Ensure that the dimensions of any item run in the hole are recorded, are correct for their application and that a fishing diagram has been prepared. • 2.5.4 Ensure that first line fishing equipment is available at the well site. • 2.5.7 Ensure that equipment is rated for its intended purpose and is run within its operating limits. • 2.5.12 Ensure that adequate precautions are being taken to prevent anything from being dropped down the well. • 2.5.16 Ensure that the Drilling Contractor is given written instructions before performing any well operation. These instructions will include: • The sequence of operations. • The parameters to be used (WOB, tripping speed, etc.). • The maximum over pulls to be applied to the string while tripping or jarring. • Contingency plans should a problem be encountered (losses, connection over-pulls, etc.). • Instructions on when the WSL should be informed; at specific points in the operation or when deviating from the plan.

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• 2.5.18 Ensure procedures for dealing with stuck pipe are available and known. • 2.5.19 Ensure alternative breaks are made on each trip out of the hole. • 2.6.4 Ensure that all casing running tools and equipment are in good condition, are the correct rating for the job and have valid certification. • 2.6.12 Where possible, any tight spots should be wiped out on the trip before running casing. The depth of ledges etc. should be recorded and then included on the casing running list. SMS Documentation • Well Operations Group Practice, GP-10-35. • BP Stuck pipe Handbook, TS-D-001. • Drilling Operations Guidelines, EUR-D-001. • GIS 02-208 Inspection and Classification of Used Casing and Tubing. • Well Activity Reporting Guidelines, UKO-D-003.

10.1 Considerations when Dealing with Stuck Pipe 1.

As stuck pipe and fishing operations are non-routine, difficult and often frustrating operations, it is vital that focus is not lost on the safety aspects of the job. Jarring and back-off operations carry their own particular risks and sufficient emphasis must be placed on getting safety right.

2.

Similarly, because stuck pipe and fishing operations are not common activities, consideration needs to be given to the training and competency levels of the crews involved.

3.

The best policy with stuck pipe is avoidance. Refer to Section 7.2 of this handbook which outlines the best practice while tripping, how to deal with overpulls and considerations to be made for when the hole tries to pack-off.

4.

Clear roles, responsibilities and accountabilities will be established for all positions when dealing with stuck pipe. It is vital that clear expectations in the form of maximum pulls and jarring forces are given by the WSL and that these guidelines are stuck to by the Driller and his crew.

5.

Before the start of jarring operations it is important that any equipment problems or weaknesses are recognised and that every effort is made to rectifying these problems.

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6.

The WSL must make the crews aware of where the weakpoint is in the string and explain the reasoning behind this limitation. It is dangerous to make assumptions when considering the maximum pull. Components such as the Drill-line or the Saver-Sub can be weaker than the string itself.

7.

When calculating the maximum figure that can be pulled on stuck pipe, the Factor of Safety (FOS) suggested by API RP7G is as high as 90%, however 85% is the figure more commonly used throughout the industry.

8.

When calculating the actual pull being exerted on the stuck point, which is important when preparing to fire a back-off shot etc., it is the weight of the string in air which must be used and not the previously indicated buoyed string weight.

9.

Consider a drill string stuck on bottom which is made up of 10,000 ft of 6 5/8” x 25.2 ppf Grade S135 drill pipe. To calculate the maximum safe indicated pull: The yield of new 6 5/8” x 25.2# S135 pipe The yield of premium 6 5/8” pipe

= 881,035 lbs = 697,438 lbs

Applying a FOS of 85% to give the safe pull Adding the Block weight of 70,000 lbs Gives a maximum safe indicated pull of

= 592,822 lbs....(a) = +70,000 lbs = 662,822 lbs

To calculate the effective pull on the BHA: Maximum safe indicated pull Subtracting the Block weight of 70,000 lbs Actual pull on the top joint of drill pipe As the pipe is stuck there is no buoyancy and so we need to consider the weight of the pipe in air, i.e. 10,000 ft x 25.2 ppf Gives the actual pull on the BHA

= 662,822 lbs = -70,000 lbs = 592,822 lbs = -252,000 lbs = 340,822 lbs

Now given a similar situation but this time with the string made up of 4000 ft of 5” x 19.5# S135 pipe below 6000 ft of 6 5/8” pipe: To calculate the maximum safe indicated pull: The safe pull on the 6 5/8” pipe The yield of new 5” x 19.5# S135 pipe The yield of premium 5” pipe

= 592,822 lbs….(a) = 712,070 lbs = 560,764 lbs

Applying a FOS of 85% to give the safe pull The weight of 6000 ft of 6 5/8” pipe in air The surface pull needed to risk the 5” pipe

= 476,649 lbs….(b) = +151,200 lbs = 627,849 lbs….(c)

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However this figure (c) is over the safe pull on the top joint of 6 5/8” which was calculated in (a) above. This means that with 6000 ft of 6 5/8” pipe in the hole it is the top joint of 6 5/8” pipe which is the limiting factor and the figure of 592,822 lbs or 662,822 lbs (indicated) is as much as we can pull. It would only be after pulling 1,390 ft of 6 5/8” pipe out of the hole that the 5” drill pipe would become the limiting factor. It is often useful to make a sketch of the string, to help visualise the various limitations at play. In addition, keeping a partially completed calculation at the back of a tallybook can help the Well Site Leader quickly arrive at the correct limiting factor. 10. When looking at stuck casing the maximum total surface load (not overpull) should not exceed either: a) Yield Strength of the Top Joint or Thread (whichever is weaker) 1.6 b) Lowest Yield Strength of String + Weight of Casing in Air Above 1.6 N.B. When working stuck casing and pumping at the same time using a Le Fleur type circulating head, the resultant force on the bails will be the total of the pull plus the vertical component of the circulating pressure. 11. The safe working load of the elevators must be double checked before starting to work stuck pipe or casing. Do not rely on a rating as stated on a delivery note, the actual marked value must be checked. N.B. Most elevators are marked using the American Short Ton convention (1 Short Ton = 2000 lbs). 12. Regardless of the calculated allowable loads mentioned above, the safety factor for the drill line must never be less than 3. This could well be the limiting factor instead of the drill pipe or casing and this figure must be calculated before starting to work the string. For example, 1.5” x 6 x 19 IPS drill line has a breaking strain of 197,800 lbs. With ten lines strung, this gives an ultimate lifting capacity of 1,978,000 lbs - however with a three times factor of safety, the maximum pull on the drill line drops to only 659,333 lbs. The current ton-miles figure should be checked before and during any jarring operation. If there is concern over the wear-point on the drill line, then this can be changed by simply picking up a single. If the ton-mile figure is running high, then

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a slip and cut should be made. While slipping and cutting the drawworks, the brakes and deadline anchor can be checked and serviced. 13. The 85% FOS should also be used when looking at the torsional yield value of pipe: The tensile yield of premium 5” S135 drill pipe = 560,764 lbs Applying a FOS of 85% to give the safe pull

= 476,649 lbs

The torsional yield of premium 5” S135 pipe

= 58,113 ft.lbs

Applying a FOS of 85% to give safe torque

= 49,396 ft.lbs

These figures are valid when applying either pull without torque, or torque without pull. However, the pipe will inevitably be under load when we want to rotate the string and this needs to be considered. If we have a string weight of 300,000 lbs on the 5” premium S135 then the safe torque figure will drop from 49,396 ft.lbs to just 39,000 ft.lbs. Formulae can be used to calculate this reduction, however for ease of use on the rig, charts are readily available. 14. It is the responsibility of the WSL to make sure that equipment is inspected before use. These checks should not only involve making sure the DS1 (or similar) inspection report is available from town, but also that the equipment is checked on deck for possible transportation damage and finally that all threads and seal areas are being checked while tripping. 15. The drill string inspection frequency is vital to the safe delivery of the well. The actual frequency will be directed by town and will be determined by the type of well being drilled. Some typical limits for drill pipe being used in North Sea directional wells are: 1500 rotating hours or 30,000 ft drilled or after every 6 months. For HWDP and Drill collars the limit is usually set between 150 and 250 rotating hours. Whatever inspection frequency is used, the WSL must make sure that proper and workable procedures are put in place to manage the pipe. 16. The total circulating hours on the drilling jars should be recorded daily on the IADC report. The typical change out frequency used for jars is 200 circulating hours, however the manufacturers recommendations, which factor in mandrel size, hole angle etc must be consulted. 17. In addition to the first run fishing equipment held on the rig, the WSL needs to make sure that there are sufficient spare HWDP and Drill Collars kept onboard to cover a possible fishing run.

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18. It is vital that sufficient focus is placed on the correct dimensions being recorded on the BHA sheet. As well as checking the overall BHA length, the WSL should himself make periodic checks of fishing neck dimensions. 19. The inside of all downhole equipment should be confirmed free of debris by being drifted as it is lifted to the rig floor. Some reluctance is often expressed about the drifting of drilling jars. It is just as important to drift the jars as it is to drift the pipe, it is vital to know that an 1 11/16” back-off shot will pass through all downhole equipment. 20. The length and complexity of BHAs is to be minimised. Jars should be run either in compression or tension however they must be kept away from the neutral point in the string. Connections are a weakness and these should be minimised especially around the transition points in the string. 21. The advantages of using an accelerator are that it: • Allows optimum jar placement. • Intensifies the jar blow. • Protects the drill string and rig surface equipment from high impact loads. • Compensates for insufficient drill string stretch in shallow holes. • Compensates for excessive drag in high angle holes. Jars and accelerators must be matched to each other. Running jars and accelerators from two different manufacturers is to be avoided. 22. It is often helpful for the WSL to have witnessed the BHA as it is run in hole. To have good drawings of lost downhole tools can be vital to the success of recovering the situation, similarly if the WSL has actually seen the bit, stabilisers and other BHA stand-offs then this picture in his mind is invaluable when it comes to a fishing job. 23. A useful technique is to have a schematic of the BHA drawn on the same scale as the mud log. When working tight hole the Well Site Leader can overlay the BHA on the mud log and thereby quickly check to see if it is the bit or some other component which is lying next to a trouble spot. 24. As mentioned above, the importance of using visual aids during stuck pipe and fishing operations cannot be over emphasised. The WSL should arrange for a drawing to be prepared showing the stuck pipe within the well schematic. This is most useful for handover purposes between crews and also for sending to town to help form a common understanding. During the actual fishing operation, full scale drawings on the sackroom floor have been used successfully to help the team visualise the down hole conditions. Rev. 1, April 2010

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25. Even before the situation moves from being a stuck pipe problem to a fishing job, the WSL must consider the consequence of loosing a fish in hole. Factors such as the size and position of radioactive sources will play a large part in determining the time spent trying to recover the fish. The WSL will discuss contingency requirements, e.g. people and equipment with the onshore team as early as possible. 26. Should there be no regulatory concerns, such as having radioactive sources stuck in a reservoir section, then the decision over how long to continue fishing becomes one of pure economics. To calculate the optimum fishing time, we can use one of the following formulae: If loosing the fish would involve a sidetrack: CR =

1.4 R . V + 56R + 8.75D + (7RD ÷ 1250) + 12250 +TR

If loosing the fish would involve a re-spud: CR =

1.4 R V + Cost of Re-spud

.

where: CR R D V T

= Cost Ratio = Hourly Rig Rate ($) = Estimated Depth of the stuck point (m) = Value of the string below the stuck point ($) = Time to drill from the stuck point to the existing TD (hrs)

Once the Cost ratio is calculated then determine the optimum fishing time by using the chart below:

Optimum Fishing Time 140 120

Hours

100 80 60 40 20 0 0. 00 40 0 0. 00 60 0 0. 00 80 0 0. 01 00 0 0. 01 20 0 0. 01 40 0 0. 01 60 0 0. 01 80 0 0. 20 00 0

0

30

00

0.

0

20

00

0.

5

00

0.

07

05 00

00 0.

0.

10

0

0

Cost Ratio

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10.2 Stuck Pipe Mechanisms and Responses Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

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Differential Sticking. None. Unaffected. Permeable sandstones and limestones. Torque to 75% MUT. If this fails, slump and jar down. Pump pipe releasing pills and/or U-Tube free. Lower mud overbalance to below 500 psi. Minimise the length and better stabilise the BHA. Keep pipe moving. Keep mud in check, control LGS, add Lubricants and Rheology modifiers. Unconsolidated Formation. Possibly downward. Hole may pack-off. Cavings and debris seen at shakers. Slump and jar in the opposite way to when the string became stuck. Once free do not aggravate. Improve mud filter cake. On top hole consider soaking with XC polymer. Do not use excessive pump for fear of causing further formation damage. Plug with cement in extreme cases. Fractured/Faulted Formations. Possibly downward. Possible losses and packing off. Cavings and debris seen at shakers. Slump and jar in the opposite way to when the string became stuck. Once free do not aggravate. Difficult to prevent so minimise the effect. Increasing the mud weight is unlikely to help. Slow tripping speed and do not work over problem area. Acid pill can clear limestone debris. Mobile Formations. None. Possibly reduced circulation. Salt or shales. In Halite/salt formations spot a freshwater pill. In creeping shales, use a base oil and detergent pill. Watch for increased ROP when hitting salt sections. Increase mud weight to reduce creep. Drill/underream oversized hole. Run roller reamers. Increase wiper trips. Keep pipe moving.

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Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

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Reactive Formations. Should improve with wiping. Hole may pack-off. Sticky clays with WBM. Watch for Gumbo blocking the flowline jar in the opposite direction. Wipe hole clean. Keep mud in check. Increase water based mud inhibition or change to oil base mud. Increasing mud weight is unlikely to help. Drill and case off the section as soon as possible. Geopressured Formations. Possibly downward. Hole may pack-off. Pressured cavings at shakers. Slump and jar in the opposite way to when the string became stuck. Once free do not aggravate. Monitor pore pressure closely. Increase the pump rate and improve hole cleaning. Increase the mud weight (additional 0.5 ppg required for every 30 degree increase in inclination).

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

Poor Hole Cleaning. Possibly downward. Hole may pack-off. Cuttings seen on circulation. Increase pump rate. Consider pumping weighted/combination pill. Increase pump rates and time spent cleaning the well. Stage circulate on trips, e.g. at top of tangent. Run larger OD pipe.

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

Undergauge Hole. Possibly upward. Minimal effect. Hard/abrasive formations. Jar in the opposite direction. Once free ream the undergauge section. Run gauge protected bits, watch for jamming PDC bits and coreheads; also take care not to pinch tri-cones. Run reamers.

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response:

Wellbore Geometry. Possibly up or down. Circulation unaffected. Not helped by interbedding. Jar in the opposite direction. Once free, ream through restriction.

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Forward Plan:

Minimise doglegs, trip more slowly in problem areas, be prepared to ream out dog legs. Limber up BHA to suit.

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

Key Seating (Casing or Formation). Possibly downward. Minimal effect. HCI acid for limestones. Slump and jar down heavily. Once free, ream through restriction. Trip carefully. Run only well tapered X/Os etc. Run string reamers or keyseat wipers. Minimise ratholes below casing.

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

Junk or Cement Blocks. Possible up or down. Circulation unaffected. HCI acid for cement. Jar in the opposite direction. Once free carefully ream through area. Trip carefully. Possibly push restriction into open hole. Consider making a junk run. Drill out rathole in 1m stages.

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

Collapsed Casing. Possible up or down. Circulation unaffected. Stuck point inside casing. Jar in the opposite direction. Then attempt to ream past restriction. Minimise casing wear, use only smooth or polished hardbanding. Mobilise specialist milling equipment.

Sticking Mechanism: Movement: Circulation: Formation: Immediate Response: Forward Plan:

Green Cement. None. Hole may pack-off. Stuck point inside casing. Jar heavily upward as quickly as possible. Increase pump rate. Do not tag cement till hard. Drill out slowly. Circulate clean and treat mud for cement contamination.

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10.3 Best Practice when Dealing with Stuck Pipe 1.

As mentioned above, the best practice when dealing with stuck pipe is avoidance. Section 7.2 of this manual describes in detail the best practice over cleaning the hole, tripping, what to do in the event of meeting resistance and most importantly, how to prevent the hole from packing off. The ten rules below, represent the best practice in avoiding stuck pipe: a) Prepare a hole schematic showing potential trouble spots and BHA spacings. b) Hold a pre-trip meeting and discuss the plans and contingency actions. c) Issue written instructions detailing maximum pulls and jarring forces. d) Have all equipment serviced and have a single sitting on the catwalk. e) If resistance is seen then try to establish what is causing it before reacting. f) Always wipe well down below the tight spot before then working back up. g) If breaking circulation, make sure the BHA is well below any problem area. h) Break circulation in stages checking pressures against the trend sheets. i)

Build the pump rate to the desired value before bringing the revs above 80.

j)

If you pack-off, stop the pump, bleed the pressure and slump/rotate down.

2.

If the pipe does become stuck, then what happens in the first few minutes is crucial to a successful outcome. The WSL and his crew must be prepared for this eventuality and have discussed their contingency plans. The driller must record the last movement of the string before getting stuck. This may sound simplistic however in the heat of the moment the true facts often become hazy.

3.

Once he has recorded his last free movement, the Driller must be aware of whether the jars are cocked or stroked. An already bad situation will be made all the worse should the jars fire accidentally at the wrong moment. If doubt exists, the Driller must assume the jars are cocked before proving otherwise.

4.

If the string stalls out on bottom and there is no significant change in circulating pressure, then the chances are that the bit or a stabiliser has become wedged in a stringer. The Driller should first release the torque from the string and then pickup to some 20K over his last breakover weight and give the jars time to fire. (N.B. It can take as much as eight minutes to fully stroke the jar however the driller should see the weight dropping off long before this, as the mandrel begins to extend.) Once the jar has stroked then the driller is safe to overpull and try to pop the bit free. Jarring may have a detrimental effect on downhole MWD tools. Pulling a bit free by using a 50K straight overpull can often be less damaging to MWD tools than jarring.

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If a straight pull does not work, then the Driller should cock the jars and then jar free with an increasing overpull the value of which will depend on the hole size, depth and jar type. (A typical jarring force in a normal 12¼" hole section when the bit stalls on bottom would be in the order of 30 - 50K.) It is not good practice to jar using 18° tapered elevators. The Top Drive or Kelly should always be used. The equipment manufacturers recommended jarring procedures e.g. removal of the Kelly Spinner or the clamping of the Tooljoint Breaker must always be followed.

6.

If prolonged, or heavier jarring is required, then the Driller will need to carry out his pre-jarring checks: a) All work is to stop in the derrick and exposed areas around the rig. b) A derrick sweep should be made to check for potential dropped objects. c) Barriers are to be erected and personnel kept within the designated “Safe Area”. d) The Control Room, Toolpusher and WSL are to be informed of the situation. e) Tannoys are to be made to tell people to stay clear of the derrick. f) Have jarring checks done on the TDU and fit retention devices as required. g) Check the deadman anchor and confirm the hookload reading is correct. h) Before starting to jar, the Driller should mark the pipe.

7.

If stuck off bottom, then the golden rule of working and jarring in the opposite direction to that when the pipe became stuck cannot be overstated. All too often a bad situation is made worse by people jarring in the wrong direction. Jarring in the same direction as the last pipe movement should only be undertaken after many hours of jarring in the opposite direction has failed to produce results. An accepted rule of thumb states that you don't start jarring in the same direction as your last movement, until after firing the jars 100 times in the opposite direction.

8.

If the string was stationary when it became stuck then the cause could be a hole collapse, mobile or reactive formations or most likely, differential sticking. Regardless of which mechanism is the cause the solution in this case is always the same; apply Right Hand torque and slump the string down.

9.

Jarring forces should normally start low and be built up only once confidence is gained in both crew and equipment. For an 8” jar in a 12¼" hole, a jarring force of 20 - 50K would be a good starting point.

10. The driller should increase the jarring force in line with the manufacturer's recommendations and as advised by the WSL. After the jar has fired then the Driller

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should continue to slump or overpull to a limit set by the WSL. Once confident of stroke lengths, etc. the jarring speed should be increased to maximise the effectiveness of the jarring action. By checking the mark on the pipe, the success of the operation can be measured. It is important to monitor the shakers throughout the jarring operation as useful clues about the causes of the stuck pipe may be learned by when and what formation debris is returned. 11. Examples of jarring action calculations are available from all the jar manufacturers. So long as the maximum jarring forces are not exceeded, then try not to overengineer the situation at the start of the jarring operation. Much better to devote this valuable time, to making sure the safety aspects of the job are right. This said the following generalisation over the effect of circulating on jars is worth remembering: Hydraulic Jars:

Jar Up - Harder to cock but Larger Impact. Jar Down - Easier to cock and Smaller Impact.

Mechanical Jars:

Jar Up - Harder to cock, easier to trip but forces unaffected. Jar Down - Easier to cock, harder to trip but forces unaffected.

12. The jar manufacturer's recommendations should be available in the Doghouse. The following table shows the recommended limits for Dailey jars. N.B. When calculating the allowable maximum loads on the jar, remember to take the weight of pipe in air rather than the buoyed weight. Tool OD

Tool ID

Max Jar Load

Tensile Strength

Torsional Strength

4¾”

2¼”

85,000 lbs

500,000 lbs

20,000 ft.lbs

6½”

2¾”

175,000 lbs

934,000 lbs

56,200 ft.lbs

8”

3”

300,000 lbs

1,750,000 lbs

105,000 ft.lbs

13. If after repeated attempts, no jarring action is available and if the hours on jars are not excessive, then the chances are that you are stuck above the jars. 14. Derrick and equipment checks should be repeated every three hours. This timing also gives the opportunity to rest both people and equipment. When jarring for extended periods the cumulative Ton-Mile figure should be checked. 15. Before pumping a treatment pill, the WSL must calculate the effect the pill will have on bottom hole pressure. Migration and contamination will reduce the effectiveness of the pill however this can be overcome by pumping a high viscosity spacer before and after the pill. 16. If pumping a releasing pill to help breakdown filter cake when differentially stuck, then pump sufficient volume to cover the BHA inside and out plus a suitable page 156

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excess to allow movement of the pill by ½ to 1 bbl ever 30 minutes for approximately six hours. N.B. To help prevent the pill dispersing, the weight of the pill should be between 0.1 and 0.2 sg heavier than the mud. When differential sticking is likely, then the WSL must ensure that sufficient stock of material is kept to be able to mix up to 200 bbls of treatment pill. 17. If differentially stuck and there is no float or other restriction within the string, then it may be possible to drop the bottom hole pressure which will reduce the sticking force and allow the string to be jarred or worked free. When using this method, there is a risk of going underbalance and taking a kick. The U-Tube method should only be used after getting guidance from town to verify the most likely bottom hole pressure. Taking a worked example of a string being stuck at a depth of 9000 ft TVD with a mud weight in the hole of 10.5 ppg and an expected formation pressure equivalent to 9.0 ppg. Mud Weight = 10.5 ppg, Base Oil = 6.7 ppg. a) Require to drop the effective mud weight to 9.5 ppg, i.e. 1 ppg x 9000 ft x 0.052 = 468 psi. Using Base Oil gives us a differential of 10.5 ppg − 6.7 ppg = 3.8 ppg. Now 468 psi ÷ 3.8 ppg ÷ 0.052 = 2368 ft of Base Oil (TVD).

0.107 bbl/ft

b) 2368 ft TVD = 2415 ft MD. Giving an annular volume of 2415 ft x 0.107 = 258 bbls.

0.0345

c) Calculate the level of the mud inside the pipe after the U-Tube: i.e. 468 psi ÷ 10.5 ppg ÷ 0.052 = 857 ft. d) Given that the top of the hole is vertical, 857 ft of drill pipe equates to 29 bbls of air.

Sand

9000 ft TVD

e) To give us a 29 bbls air gap, we need to pump an additional 29 bbls Base Oil down the annulus. 258 + 29 = 287 bbls total. f)

This additional 29 bbls will push the Base Oil down a further 29 ÷ 0.107 = 271 ft.

g) Now this 271 ft will give an additional 10.5 ppg − 6.76 ppg x 271 ft x 0.052 = 53 psi. h) Therefore the total back pressure before the U-Tube = 468 psi + 53 psi = 521 psi.

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18. The actual procedure used to U-Tube the base oil pill is: a) Establish the neutral weight at the stuck point and calculate the number of turns required to work torque down to that point. b) Have the Mud Engineer confirm the exact mud weight in and out are balanced at 10.5 ppg and also that the weight of the base oil is 6.7 ppg. c) Draw a chart showing expected U-Tube pressure against barrels pumped. d) Hold a Toolbox Talk with all concerned and discuss the procedure that will be used and the contingency plans should a kick be taken. e) Driller to then record his SCRs, stop pumping and close in the annular at its minimum sealing pressure. f) Line up to pump base oil down the annulus using the cement unit while taking returns at the HP standpipe. g) Cementer to pump 287 bbls of base oil down the annulus at 2 bbls/min. The slow displacement rate is used to reduce the risk of plugging the bit nozzles. The displacement chart should be checked while pumping and if any discrepancy is seen then stop pumping and investigate the cause. h) Stop pumping with 287 bbls base oil pumped down the annulus and compare the theoretical U-Tube of 521 psi against the actual figure. i)

Monitor for any leaks passing the annular and then wind down the maximum torque to the stuck point and set down 50K.

j)

Keep the standpipe open to atmosphere. Watch the weight and torque and quickly allow the base oil to U-Tube back up the annulus by quickly opening the auto choke valve. The expected volume of base oil to be returned will be 29 bbls. Check that the open standpipe is sucking. Should returns continue after the 29 bbl, then the well may be flowing.

k) If the pipe comes free, continue to rotate slowly while circulating the remaining 258 bbls of base oil up the annulus. Catch the base oil in a separate pit and then open the annular and circulate bottom's up watching for any signs of an influx. N.B. Watch for the 29 bbls of compressed air as it comes back to surface: do not confuse this with an actual kick. Also, only rotate with the annular closed if the equipment in use is suitable for this purpose. l)

If the pipe is still stuck, then hold both the torque and the set down weight for one hour. If there is still no response then release the torque and pick up to

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neutral weight. Repeat the process by pumping the 29 bbls base oil back down the annulus and consider increasing this volume and further reducing bottom hole pressure. m) Should a kick be taken, then release the torque and pick up to neutral weight. Increase the closing pressure on the annular or alternatively go to a ram. Top fill the drillpipe and circulate out the kick by using the SCR figures taken above as the Final Circulating Pressure (FCP). 19. If pumping freshwater to help free pipe from a moving salt formation, then pump a total of 30 - 50 bbls. Displace the water into the annulus at 2 bbls/min and stop for 5 minutes every 10 bbls to allow the water to saturate. 20. If pumping inhibited hydrochloric acid to help clear limestones, chalk or cement then displace the pill into the annulus and allow the pill to soak. Acid pills should work quickly so if there is no result after 2 hours, then circulate the pill out and take care with the contaminated mud and spent acid returns.

10.4 Best Practice when Dealing with Stuck Wireline 1.

When wireline gets stuck downhole, it is important that the WSL takes charge of the recovery operation in the same way as he would if it were pipe that was stuck. The Logging Engineer and even the Logging Witness, although experts in their equipment and log interpretation, are rarely experienced in working stuck tools.

2.

Again safety is of prime importance during any fishing operation. Follow the same good practice as detailed in Section 10.3.6 above, in holding TBTs, erecting barriers, making tannoys, informing town, etc.

3.

As with stuck pipe, it is important to understand where the stuckpoint is. The cable head tension reading should be used to establish if it is the cable or the toolstring itself which is stuck. It is similarly important to understand what is it that has caused the wireline to get stuck.

4.

Before the start of any logging run, the WSL must know if there are any splices in the cable being used and what is the maximum safe pull that can be applied.

5.

The figure used for the maximum pull is derived in a similar way to that with stuck pipe. The example below shows the maximum pull for Dresser 0.378 Slammer cable: Breaking Strain of Cable Elastic Limit Manufacturers Safe Pull

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Weak Point Set at = 5,700 lbs Recommended Maximum = 5,700 lbs x 0.85 = 4,845 lbs 6.

Never suddenly release tension on a braided cable as this will cause severe damage to the wire. Tension should be released slowly and should never drop below half the normal running tension. If fitted to the toolstring, calliper arms can be cycled to help “lift” the tool over an obstruction.

7.

If the toolstring does not come free after pulling to the maximum allowable figure, then a technique that may be tried is: • Pull to the maximum allowable figure. • Slack off as quickly as is safe down to the cable weight. • Pull to the maximum allowable figure minus 200 lbs. • Slack off as quickly as is safe down to the cable weight. • Pull to the maximum allowable figure minus 400 lbs. • Slack off as quickly as is safe down to just the cable weight. • Pull to the maximum allowable figure minus 600 lbs. • Continue to work the cable, reducing the pull by 200 lbs on each attempt. • Then work back up to the maximum allowable pull in 200 lbs stages relaxing the pull down to the cable weight after each attempt. • Repeat this procedure until the string comes free.

8.

Never part a wireline weakpoint without first gaining permission from town. If the hole is in good condition, or if the tool is stuck inside casing and there are no radioactive sources in the string, then permission may be given. The weakpoint is parted either by simply overpulling using the wireline winch itself or else by clamping the line in a “T” bar which is then secured in the drill pipe elevators complete with a safety sling. The blocks are then used to part the weakpoint. Whichever method is used then the cable head tension should be used to help gauge that the correct pull is being applied on the weakpoint. Once the wire is recovered to surface, then an overshot is run on drill pipe and the toolstring fished back to surface. See section 10.6.2 below which outlines the procedure for using an overshot.

9.

If there are radioactive sources in the string, or if it has been decided not to pull the weakpoint, then the toolstring can be recovered by stripping a fishing

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assembly over the wire. The Logging company will provide their own procedure however an outline method is shown below. A full risk assessment, including an onsite visit and Toolbox Talk will be needed to identify and then to mitigate any safety concerns. Only logging company personnel should handle the cable and good communication must be maintained between the Driller and the Wireline Unit. a) The toolstring is first collapsed and a pull of some 2000 lbs taken on the wire before the string is then powered down. b) Support the wire using a “T” bar at the rotary table. c) Cut and then re-terminate the ends using the spear and latch mechanism. d) Run the latch down through the first strand of the fishing assembly. e) Make up the latch to the spear head and allow the winch to take tension. f) Strip the stand over the wire and continue in this fashion until just above the fish. g) The cable can be fed through a side entry sub and re-terminated so that the cable head tension can once again be read. h) Carefully monitor the cable head tension then wash-down, latch and recover the fish.

10.5 Best Practice when Required to Back-Off 1.

If there is no success in trying to free the stuck pipe, a decision will be taken to back-off the string. After the string is successfully backed off, then either a fishing assembly will be run, or else the section will be sidetracked. The formula shown in Section 10.1.26 can be used to calculate when it becomes uneconomical to continue with fishing operations.

2.

Before running the explosive charge to back-off the pipe, the stuck point needs to be established. There are two ways of doing this: a) The stretch test is the simplest method and involves measuring the amount of stretch seen against a given overpull and then using the formula: 735294 x Wdp x E L = ________________ P where:

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= Length of free pipe in ft

Wdp = Plain end pipe weight in lbs/ft E

= Stretch in inches

P

= Pull in lbs

The string is pulled to the calculated weight in air and marked. If it is possible, then the marking and measuring of the pipe should be done away from the rotary, e.g. at the bell nipple. If this is not possible, then a graduated measurement scale can be positioned at the rotary and the stretch measured without the need to have anyone approach the rotary. The pipe is then overpulled and the stretch recorded. Several pulls should be made and the results averaged. The length of free pipe is then calculated using the formula above. b) Running a free point indicator (FPI) is the more accurate way of establishing where the pipe is stuck. An electronic strain gauge is run on wireline inside the pipe. A test measurement is taken in a section of pipe that is known to be free. The tool locates inside the pipe and the string is torqued and stretched. This first response is then used as a datum for subsequent and deeper readings. 3.

Once close to the stuck point, the FPI may show that the pipe responds to tension but not to torque. A back-off in straight hole should only be tried where the FPI is showing 80% free pipe in both torque and tension, however in highly deviated holes back-offs have been successful with readings as low as 25% of free stretch and 50% of free torque. The downhole response at the given hookload and torque are recorded and it is these figures which are then used during the actual back-off run. The back-off will normally be done at the first connection above the free point and on a connection which was made on the last trip in the hole. N.B. Whenever a Free Point Indicator or Back-Off shot are in the string, it is vital that the jars do not fire.

4.

With the free point and back-off weight now established, the left hand torque has to be worked down. As accidentally backing off the string above the explosive charge would complicate an already difficult situation, right hand torque should first be applied to the string.

5.

The application of Right-Hand and then Left-Hand torque must be carefully controlled. As always safety is paramount and so the procedure to be used should be explained at a Toolbox Talk with everyone concerned. The rig floor should be barriered off and tannoys made advising everyone to keep clear. The crew must check that the TDU or Kelly, Tongs, Slips and Snub Lines are all in good condition.

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6.

To apply Right-Hand torque the string should be worked between just over the back-off weight and up to the maximum safe pull. As the string is being held in tension throughout this operation, there is no risk of an accidental trip of the jars. First check the acceptable torque and pull charts and then apply Right-Hand torque and work the pipe until 75% of the make-up torque (or to the safe limit if that figure is less) is wound all the way down. Once we have confirmed that the Right-Hand string torque is good, then we can run the back-off charge to around 2000 ft above the stuckpoint.

7.

To apply the required Left-Hand torque, the string should again be worked between just over the back-off weight and up to the maximum safe pull. Make sure that the string weight is not allowed to go as low as the back-off weight as this would risk a premature back-off and could damage the wireline. As it is vital that the Driller is watching for the safety of his crew, mark the pipe and have the Driller work between two chalk marks rather than using the weight indicator.

8.

Working in Left-Hand torque using an AC top drive is simple and safe, however if rig tongs need to be used to apply and hold the torque then extreme care must be taken. It is often safer and more convenient to have both the Driller and the Toolpusher working the string while applying and holding torque with rig tongs. Whatever procedure is used, good three-way communication between Doghouse, the drill floor and the logging shack is vital at this stage.

9.

The maximum Left-Hand torque applied must never exceed 80% of the drill pipe make-up torque. The chosen value will have to be applied and worked down in increments. The number of left hand turns required will depend on the type, size, length and condition of the pipe being worked. As a general rule of thumb: • Drill pipe from surface to 4000 ft will require ¼ to ½ turn per 1000 ft. • Drill pipe from 4000 ft to 9000 ft will need ½ to ¾ turn per 1000 ft. • Drill pipe below 9000 ft will need ¾ to 1 complete turn per 1000 ft.

10. Should an accidental back-off happen while working in the Left-Hand torque, then pick up the string about 40 ft and slowly pull the wireline back up and into the pipe. If this does happen, then use the CCL to confirm where the back-off has happened. If it is deep enough, then the upper section of pipe can be retrieved and fishing operations begun. If the back-off is near surface then the tool joint can be made back-up and the Right-Hand torquing process repeated. 11. Once the desired Left-Hand torque is applied, then keep tension on the string at just above the back-off weight and run the back-off charge downhole. Use the CCL to locate the required tool joint, lower the string to the back-off weight and then fire the charge. Rev. 1, April 2010

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12. Even if only a partial back-off has taken place, then buoyancy will now take effect. Pull the wireline out of the hole and then try rotating the string to the right. If the pipe turns freely then the back-off has been a success. If the torque is above the expected free rotating torque then complete the back-off by applying half the original Left-Hand torque to the string and work the neutral point over the loose connection. Watch for any loss in torque which will indicate that the neutral point is at the loose connection and the pipe is backing out. 13. Once the back-off is complete, then do not circulate unless the string was originally plugged. Pull out of the hole checking the torque of each connection before racking the stand. With the pipe safely back on surface, closely examine the recovered end and look for signs of a wash, belling or other damage which might affect the choice of the fishing equipment to be used.

10.6 Best Practice when Fishing 1.

The exact fishing inventory to be held onboard will depend on the section being drilled. The expectation is that enough equipment will be held on the rig so that the “First Run” can be made to recover any diameter of fish left downhole. It is vital that the BHA component sizes are checked against the fishing tool inventory. It is also important that the WSL is familiar with the equipment and is confident in its use.

2.

Good depth control is vital to the success of the fishing operation. BHAs, Pipe Counts and Pipe Tallies need to be checked and checked again. Accidentally tagging a fish high and potentially before the Kelly has been picked up can bring a fishing run to a premature and embarrassing end.

3.

Similarly, knowing the condition of the top of the fish is equally important. When damaged equipment is pulled from the hole, a detailed examination should be made of the recovered end and photographs taken. Fishing runs are to be numbered in sequence and a detailed report kept on the success of each run. Detailed drawings of the fish and updates should be kept on the rig floor to help with any subsequent runs and also with the handover between crews. Each fishing assembly should be photographed and painted internally and externally to help highlight any marking which may happen downhole.

4.

In order to have the best chance of being successful, fishing gear should be run close to the gauge size of the hole. Running and pulling large diameter BHAs carries an increased risk of surging losses or even swabbing an influx. Fishing assemblies must be run and pulled at a steady pace.

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5.

As many fishing operations require both Right-Hand and Left-Hand torque to be worked downhole, safety joints are only run with “non-release” tools such as taper taps or dies.

6.

Conversely a circulating sub is quite often run in fishing assemblies especially when there is a chance of seeing losses. Make sure that the circ-sub ball is checked against the inside diameter of the pipe and also that dropping the circ sub ball will not compromise other equipment or ultimately affect the ability to run an 1 11/16” back-off shot. Do not forget to check the ID of the Kelly Cock itself.

7.

If the hole is in poor condition then it may be necessary to make a clean-out run before going in with the fishing assembly. If a clean-out run is made then circulate and condition the mud above the fish but do not tag the top of the fish to avoid causing damage.

8.

In order to clean up the well and also to check for gas, we should always plan to circulate through the fish. For this reason, spear and overshot assemblies should always be run with packers and seals.

9.

During milling operations it is often difficult to tell exactly what progress is being made downhole. One method of depth control that works well on a surface stack is to rotate down and lightly tag the fish. Stop the pump and rotary then close the upper pipe rams. Open the BOP back-up and strap the pipe out to the mark that the ram has made. If this procedure is repeated at the end of the milling run then a very accurate measurement of progress can be made.

10. When any equipment is lost downhole, then an exact list should be made and an order sent to replace the complete assembly. Even if the fishing operation is a success, then it is good practice to lay down the recovered equipment for inspection and so replacements need to be ordered as soon as possible. 11. If a Kelly becomes stuck below the rotary then it may be possible to ballast or jack the rig down to get to the saver sub. When on a land rig or platform, then the Kelly can be backed off by closing in two pipe rams and setting down the weight of the string. The Kelly can then be backed out by torquing the string to the left.

10.6.1 Junk Subs/Boot Baskets 1.

Junk subs or "Boot Baskets" are a most efficient tool when fishing for junk in straight holes. This said, their use in directional wells should not be discounted. The neck of the junk sub provides a substantial increase in annular volume and as the mud passes from the restricted annulus around the basket the velocity slows dramatically and so any junk being carried by the mud drops back down and into the skirt.

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2.

Junk subs are typically run immediately above the mill or the bit. However they can be run in a drilling assembly just above the near bit stabiliser. If drilling or milling is planned with a junk sub in the string, then it is recommended to limit the WOB to no more than 70% of normal. When larger volumes of junk are expected, e.g. during packer milling operations, it is quite common to run two or more subs in tandem.

3.

When running a junk sub in the string always make sure the basket is empty before being run in the hole. Depending on the circumstances, it is good practice to work the junk sub as soon as the fish is tagged, also during any milling operation and again before pulling out of the hole.

4.

The best practice to use when working a junk sub is: a) Jet the bottom of the hole clear using maximum pump rate. b) Pull back 10m and reduce the pump speed to half rate. c) Rotate back to bottom using 20 to 30 RPM. d) Watch for any erratic torque which would indicate junk sitting on bottom. e) Set 5K down on the junk with 20 - 30 RPM and try to break it up. f) Come off bottom and stop rotating then stop the pump 1m off bottom. g) Continue to pick back up, again to 10m off bottom. h) Repeat this procedure varying the pump rates, RPM, stopping points and string speeds all in an attempt to hit the right conditions to catch the junk. i)

This routine should be continued for a full 15 minutes.

j)

When coming out of the hole, take care as the basket passes the shoe, wellhead and BOP in case any junk is trapped in the top of the basket.

k) When out of hole the junk should be weighed and photographed.

10.6.2 Overshots 1.

When fishing drillpipe or BHA components, then an external catch overshot is the tool of choice. Should there be sufficient room between the outside of the fish and the hole diameter, then a full strength “FS” overshot can be run. When the diameter of the fish begins to approach the hole size then a slim hole “SH” tool will be needed. Refer to the manufacturer's procedures, e.g. Bowens' Instruction Manual No. 5/1150 which shows the available sizing combinations and also gives the strength of the various tools.

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2.

The overshot has a top sub with an API threaded box and typically a Bowen style, 8 round threaded pin. The top sub, also known as a "drive sub" when used with wash pipe, should always be machined with an internal API box so that a pin-pin sub can be fitted and the tool then used to simply wash over and screw into the top of a fish.

3.

Below the top sub is the overshot bowl which holds the grapple assembly. The bowl is cut with Bowen style 8 round threads. A 3 ft extension sub should always be run between the bowl and the top sub as this allows the grapple to latch further down the neck of the fish and so keeps it away from any damaged areas at the top of the fish.

4.

The grapple assembly sits inside the bowl and mates with the large internal tapered and helical thread. There are two types of grapple available. The first is the spiral grapple which is run to catch tubulars with an outside diameter close to the internal diameter of the overshot. The second type is the basket grapple which is made of a much heavier construction and is run to catch tubulars that are considerably smaller than the overshot outside diameter. Both spiral and basket grapples will catch +/- 1/8” either side of their nominal size. A standard control ring is run with a spiral grapple, however the larger basket grapple has the option of running a mill control which is useful for dressing the top of the fish. Both types of grapple are equipped with sealing elements which allow for circulation down through the fish.

5.

The Lip Guide is screwed onto the bottom of the overshot and again has an 8 round thread. The heavily stepped profile and internal taper of the guide is designed to help work the tool over the fish. The guide is normally sized at around 1” under the hole size to reduce the chance of the overshot passing the top of the fish in a washed-out section of hole.

6.

The helical thread inside the overshot is cut in such a way that to release the tool you must turn it to the right; this means that the overshot can transmit Left-Hand torque and can therefore be used to back-off connections further down the fish.

7.

A typical overshot assembly when fishing in 12¼” hole would be: 11¼” Overshot, 8" Bumber Sub, 8" Fishing Jar, 6 x 8" Drill Collars, 8" Fishing Accelerator, 2 x 8" Drill Collars, 15 HWDP. If an accelerator is not available, than match the weight of the drill collars to the weight of the fish. Only use a fishing oil jar with an overshot, as any downward jarring is likely to release the grapple.

8.

The make-up torque for Bowen overshots is:

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Size and Type

Top Sub

Extension

Bowl

Lip Guide

11¼” FS No. C12822

40,000 lbs

40,000 ft.lbs

40,000 ft.lbs

14,900 ft.lbs

8 1/8” SH No. 9217

15,700 ft.lbs

15,700 ft.lbs

15,700 ft.lbs

4,700 ft.lbs

8 1/8” FS No. C5342

23,100 ft.lbs

23,100 ft.lbs

23,100 ft.lbs

6,400 ft.lbs

The best practice to use when running an overshot is: a) The size of the fish will determine the type of grapple to be run. Choose a grapple either on size or slightly smaller than the fishing neck. b) If practical, try the chosen grapple over the recovered section of fish. c) Paint the inside of the top sub and overshot to help confirm swallow. d) Make up the overshot and photograph the assembly for later reference. e) RIH slowly, check the pop-off setting will cover a plugged string. f) Watch for the mud backflowing and pump a slug if necessary. g) Slow down in open hole so as to reduce the surging affect. h) Make a good pipe count and double check the BHA and pipe tally. i)

Break circulation one stand above the fish and condition the mud.

j)

Establish the torque and drag figures both with pump on and pump off.

k) Set the torque limit at 10K over the free rotating torque. l)

Rotate at about 20 RPM or as required to give a smooth torque profile.

m) Have the Data Engineer increase his logging speed for future reference. n) Wash and rotate down looking for resistance, torque or pressure. o) Work down over the top of the fish until resistance is seen. p) Watch for the pressure rise if the string or hole is packed-off. q) Stop rotating and carefully release any trapped in torque. r) Set down half the BHA weight to check the engagement. s) Pick up and confirm the fish is latched. t) Do not “drop and catch” the fish as this is not good practice. u) Circulate, jar up and overpull as required to free the fish.

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v) Circulate clean, then POOH slowly so as to prevent swabbing. w) While POOH, do not rotate or move the string down into the slips. x) To come off the fish downhole, beat down and turn to the right. y) When back on surface release the overshot in the same way. z) If difficulty is found in releasing the tool then break the bowl from the extension then unscrew the bowl to the right to leave only the grapple in place.

10.6.3 Spears 1.

When fishing casing and other thin walled tubulars then an internal catch spear and grapple is the tool to be used. The spear is made up of an inner mandrel which is cut on a tapered helix. The grapple then screws onto the mandrel and will move up and down the helix as the string is rotated.

2.

Two types of grapple are available. The one piece grapple is sized to catch small to medium sized tubing and casing whereas the segment type grapple is designed for larger bore casing and conductor.

3.

Grapples are supplied for a nominal size of casing or tubing and will be stamped with the weight range they can catch. Right hand rotation will move the grapple to the bottom of the mandrel which is the release position. Conversely left hand rotation will move the grapple to the top of the mandrel which is the catch position.

4.

An elastomer cup is normally run on the mandrel to allow for circulating through the fish. Above the mandrel a spear stop or ring is positioned to provide a “NoGo” on the top of the casing.

5.

A typical spear assembly when fishing 9 5/8” casing would be: 9 5/8” Spear c/w Cup and Stop Ring, 8” Bumper Sub, 8” Fishing Jar, 6 x 8” Drill Collars, 8” Fishing Accelerator, 2 x 8” Drill Collars, 15 HWDP.

6.

The best practice to use when running a spear is: a) The spear and grapple will be sized for the particular casing being run. b) Ensure the equipment sizing is confirmed as part of the casing checks. c) Paint the stop ring to confirm full entry into the fish. d) Make up the spear and photograph the assembly for later reference. e) Screw the grapple up the mandrel and into the catch position.

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f) Secure the grapple in the catch position using the lock pin (if fitted) or divers tape. g) RIH slowly, check the pop-off setting will cover a plugged string. h) Make a good pipe count and double check the BHA and Pipe Tally. i)

Break circulation one stand above the fish and condition the mud.

j)

Establish the drags with pump on and off but do not rotate.

k) Wash down looking for resistance or an increase in pressure. l)

Do not run a Kelly below the rotary when using a spear.

m) Work down inside the fish until resistance is seen. n) Watch for the pressure rise if the casing or hole is packed-off. o) Set down half the BHA weight to check engagement. p) Pick and confirm the fish is latched. q) Do not “drop and catch” the fish as this is not good practice. r) If the spear is not latched, work down torque and turn the mandrel one turn to the left then try again. s) Circulate, jar up and overpull as required to free the fish. t) Circulate clean, then POOH slowly so as to prevent swabbing. u) While POOH, do not rotate or move the string down into the slips. v) To come off the fish inhole, simply turn the string to the right. w) When back on surface release the spear in the same way.

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10.6.4 Jar Cocking Formulae - Minimum Weight Indicator Reading to Cock the Mechanical/Hydraulic Jar Cocking from Closed Position Last recorded pick-up weight 330,000 - BHA weight below jar - 30,000 + Internal jar friction + 10,000 = Weight indicator load = 310,000

Cocking from Open Position lbs lbs lbs lbs

Pump open force assists cocking the jar. The force required to move the inner mandrel through the seals.

Last recorded slack-up weight 290,000 - BHA weight below jar - 30,000 - Internal jar friction - 10,000 - Pump open force - 20,000 = Weight indicator load = 230,000

lbs lbs lbs lbs lbs

Pump open force opposes cocking the jar, slow down or stop the pumps or bleed off trapped pump pressure.

10.6.5 Trip Load Formulae - Mechanical Jar Down-Jar Blow Last recorded slack-off weight 290,000 - BHA weight below jar - 30,000 - Down jar trip load setting - 40,000 - Pump open force - 20,000 = Weight indicator load = 200,000

Up-Jar Blow lbs lbs lbs lbs lbs

Slow down or stop the pumps or bleed trapped pressure to reduce the slack-off weight required to trip the jar.

Last recorded pick-up weight 330,000 - BHA weight below jar - 30,000 + Up jar trip load setting + 80,000 - Pump open force - 20,000 = Weight indicator load = 360,000

lbs lbs lbs lbs lbs

After cocking the jar, pump pressure can be increased to reduce pick-up weight required to trip the jar.

The force required to move the inner mandrel through the seals.

10.6.6 Trip Load Formulae - Hydraulic Jar Down-Jar Blow Last recorded slack-off weight 290,000 - BHA weight below jar - 30,000 - Desired* trip load - 50,000 - Pump open force - 20,000 = Weight indicator load = 190,000

Up-Jar Blow lbs lbs lbs lbs lbs

Slow down or stop the pumps or bleed trapped pressure to reduce the slack-off weight required to trip the jar.

Last recorded pick-up weight 330,000 - BHA weight below jar - 30,000 + Desired trip load + 80,000 - Pump open force - 20,000 = Weight indicator load = 360,000

lbs lbs lbs lbs lbs

After cocking the jar, pump pressure can be increased to reduce pick-up weight required to trip the jar.

*Desired - the trip load selected by the jar operator. Rev. 1, April 2010

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10.6.7 Tripping the Jar - Mechanical Jar Down-Jar Blow

Up-Jar Blow

After cocking the jar, slack off to the calculated weight indicator load.

After cocking the jar, pick up to the calculated weight indicator load.

No delay time is required; the latch will trip when the preset trip load is applied to the jar.

No delay time is required; the latch will trip when the preset trip load is applied to the jar.

If the jar does not trip, slow down or stop the pumps or bleed trapped pump pressure to reduce pump open force.

If the jar does not trip, increase circulating pressure to maximum to increase the pump open force. Do not apply trapped pressure.

If the jar still does not trip, slack off additional weight (10,000 to 20,000 lbs).

If the jar does not trip, pick up additional weight (10,000 to 20,000 lbs).

10.6.8 Tripping the Jar - Hydraulic Jar Down-Jar Blow

Up-Jar Blow

After cocking the jar, slack off to the calculated weight indicator load.

After cocking the jar, pick up to the calculated weight indicator load.

Lock down the brake and wait for the jar time delay to elapse. See your jar manual (30-60 sec short cycle, 2-8 min long cycle).

Lock down the brake and wait for the jar time delay to elapse. See your jar manual (30-60 sec short cycle, 2-8 min long cycle).

If the jar does not trip, stop pumping or bleed trapped pressure. Recock the jar and apply trip load.

If the jar does not trip, circulate at maximum rate and allow additional time (do not apply trapped pressure).

If the jar still does not trip, slack off more weight and allow more time.

If the jar still does not trip, stop pumping, recock the jar and apply trip load.

10.6.9 Reasons for Jar Not Tripping Mechanical Jar

Hydraulic Jar

• • • • • • • •

• • • • • • •

Jar not cocked. Stuck above jar. Jar failure. Pump open force not considered. Pick-up slack-off weight not correct. Unknown/incorrect trip load setting. Excessive hole drag. Right hand torque trapped in torque sensitive jar.

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Jar not cocked. Not waiting long enough. Stuck above jar. Jar failure. Pump open force not considered. Pick-up slack-off weight not correct. Excessive hole drag.

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10.6.10 Jar Handling Recommendations • If a service connection is found loose, consult the supplier immediately. Do not use tool joint torque on these connections. • Do not tie the chain hoist, apply the tongs or set the slips on the exposed polished section of the inner mandrel. A mechanical jar is shipped in the cocked position. Run the jar in the extended or cocked position. • Rack a mechanical jar in the derrick in the cocked position at any position in the stand. A hydraulic jar is shipped with the safety clamp on the inner mandrel. • The jar must be run in the open position. • Where possible rack jars at the top of the stand or middle (never at the bottom of a stand).

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11. Casing Running References: Functional Expectations of WSL • 2.2.16 The WSL will actively participate in JSAs and prejob safety meetings. • 2.3.9 Identify opportunities to manage peripheral activity off the critical path. • 2.3.13 Ensure that equipment is accessible during periods of bad weather. • 2.4.2 Ensure that containment of the wellbore is possible at all times. • 2.6.1 Ensure that all equipment has been ordered and is onsite before the start of the casing job. • 2.6.2 Ensure that all casing has been strapped and drifted (this may be done onshore but the WSL should have written verification of it having been done). • 2.6.3 Ensure that a casing tally is prepared and that the number of joints on deck is known at all stages in the operation (the tally is to be independently checked). • 2.6.4 Ensure that all running tools and equipment are in good condition, are the correct rating for the job and carry valid certification. • 2.6.5 Witness the make-up, testing and Bakerloking of the shoe track. • 2.6.6 Ensure that the correct torque is used when making up the joints. • 2.6.7 Verify the correct centralizer installation and placement. • 2.6.8 Issue written instructions on casing running speeds and circulation requirements giving due consideration to the swab and surge calculations. • 2.6.9 Complete a deck count to confirm the remaining number of joints before picking up the Hanger. • 2.6.10 Ensure that service providers have checked the operability and critical dimensions of their tools. • 2.6.11 Verify critical wellhead measurements. • 2.6.12 Where possible any tight spots should be wiped out on the trip before running casing. The depth of ledges etc. should be recorded and included on the casing tally.

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• 2.6.13 If differential float equipment is being used, the WSL will make sure that it is tripped before entering a hydrocarbon bearing zone. SMS Documentation • Casing Design Manual BPA-D-003. • Well Operations Group Practice, GP-10-35. • Drilling Operations Guidelines, EUR-D-001. • Inspection and Classification of Used Casing and Tubing, GIS 02-208.

11.1 Preparation of Casing on Deck 1.

Casing normally arrives on the rig having been prepared and measured onshore. The overall “threads on” length is marked twice at around 4 ft from the box end and again twice at about 4 ft from the pin end. The threads are prepared with Rust Veto 33x which is a light protective oil which does not need to be removed before the threads are doped. The onshore tally should also include an ID check on a representative number of joints. It is this internal diameter which is then used for calculating cement displacement volumes.

2.

Modern casing running techniques and tighter procedural controls have cut down on the number of rejected joints seen while running casing. This means that we no longer need to order 10% excess and can often make do with only a handful of spare joints.

3.

The well programme will detail the required casing weights, grades and thread types. If a mixed string is being run, then the joints may need to be positioned on the vessel in a particular order. If this is the case, then written instructions, preferably including a sketch, should be issued by the rig so that there is no confusion on the quayside and the stows are laid out in the correct order.

4.

A pipe deck plan will be drawn up between the Drilling Engineer and the Deck Foreman. Typically 5 rows of 13 3/8” casing and 6 rows of 9 5/8” can be safely accommodated within a 2m working height limit.

5.

The casing should be laid out and numbered to suit the mechanised handling equipment on the rig. Typically this will mean that the lowest number on the row is furthest from the catwalk. If there are two different batches of casing being run, then the second batch should be numbered using a different sequence, e.g. start numbering the second batch with 101, 102, etc.

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6.

Shoetrack equipment is to be numbered Shoes 1 and 2, Float Collars 1 and 2 and Bakerloked Joints, B/L 1 and B/L 2. Pups are marked as Pup A, Pup B, etc. with Hangers and Wellheads labelled as Primary and Secondary.

7.

It is vital that the programmed size, weight and grade of casing is checked off against what is on the Boat Manifest and then physically against what arrives on the deck.

8.

Although the casing is measured onshore, a check must be carried out as the pipe is laid out on deck. Depending on the confidence of the onshore measuring process, up to 10% of joints will be checked. To reduce the risk to personnel when measuring the casing, these checks should be made on the first few rows that are laid out. If a discrepancy is found then it may be necessary to measure all subsequent joints.

9.

The casing lengths are recorded by one person and checked by another. The Drilling Engineer or WSL will record all the lengths from one end of the pipe while the Roustabout Pusher will record the lengths on the other end. One list is then compared with the other and any discrepancies corrected before the next row is laid out.

10. No thread cleaning or drifting is required on the pipe deck. However if there is any cause for concern, e.g. if the casing had experienced heavy seas on the way to the rig, then a drift check should be considered. 11. If protectors have been removed while carrying out the measurement checks, then make sure these are replaced as soon as possible so as to reduce the risk of foreign objects being placed inside the open joints.

11.2 Preparing the Casing Tally 1.

It is important to have the tally and running list prepared as early as possible. Ideally the running list should be ready for the crews as they reach section TD which will then give them enough time to prepare the decks for the start of the run.

2.

It is the Drilling Engineer's responsibility to keep track of who has been issued a copy of the running list. Should the running order then change, it is up to the Engineer to issue the new revision and most importantly to make sure that the original copies are destroyed.

3.

The joint numbers and lengths are transferred from the Drilling Engineer's tally book into the rig tally book which is held in the Company office. An independent check of the transferred figures is then carried out.

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4.

Once all the pipe is measured, then the total length should be calculated and this figure checked against the total length on the laser tally sent from town.

5.

The tally book figures are then transferred onto an Excel spreadsheet and once more an independent check is made on the transfer of figures.

6.

The make-up loss figure is then subtracted from each joint to give the actual string length.

7.

The tally is then laid out as per the programme requirements. The depth of sump, length of shoe-track, centraliser positions and crossover requirements are all accounted for.

8.

A physical check is needed to establish the exact distance of the wellhead hangoff point below the rotary. The height of the wellhead should be tracked at each stage of the well's construction and the slump figures reported each time a hanger is landed.

9.

With the hang-off point established, and an allowance made for the elevator stickup (typically at least 1.7m) the space-out pups and landing string requirements are then calculated. N.B. The optimum landing string space-out will vary from rig to rig, however the general rule of minimising the number of pups run should be followed whenever possible.

10. A running total of shoe depth is then applied to the tally and all points of interest, e.g. thread types, joint weight or grading changes, centraliser types and fitting instructions, previous shoe depth, changes of formation, previous trouble spots, etc. are all added to the comments section. 11. With the running order now established, the joints remaining on deck are listed both at the point of picking up the hanger and again for when the hanger is actually landed. 12. Finally the tally is then converted into a useable running list for the crew. It is important not to make the list too “busy”. The Driller simply needs to know the number and overall length of each joint, his current shoe depth, plus the detail contained in the comments section.

11.3 Casing Tallies Versus Liner Tallies There are two different types of tubular tallies: 1) a casing tally and 2) a liner tally. See Appendices for examples of different types. A casing tally works from a fixed point at the wellhead (e.g. hanger landing point) and the formulae in the spreadsheet calculates the shoe depth by adding the length of each joint below the wellhead to the shoe. Rev. 1, April 2010

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A liner tally is run until the shoe tags the bottom of the hole, then the liner is picked up 2m. The known depth for a liner tally (fixed point) is therefore the liner shoe depth which is equal to the total depth of the hole drilled minus a rathole, e.g. 2m. The liner tally works from a fixed point at the shoe and the formulae in the spreadsheet calculates the liner hanger and packer depths by subtracting the length of each joint above the shoe back to the top of the liner hanger/polished bore receptacle. The best practice and quality control checks required for preparing a tally are detailed below: 1.

Check the formulae in the spreadsheet to determine if it is a “casing type” or “liner type” tally.

2.

Casing is commonly now measured in town using a laser. The laser measurements are generally full joint length (i.e. including threads or “threads on”), sometimes maybe effective length measurements (i.e. full joint length minus thread length - “threads off”). Check to make sure which was measured and painted on!

3.

The deck crew record the laser measurements that were painted on in town and the running numbers which they painted on when laying the joints out in rows on the rig.

4.

The DE or Drilling Supervisors should check 1 in 8 of the joints using the rig tape and compare it with the laser measurements as a QA check. If there are significantly longer or shorter joints than the average, then the lengths of these joints should be double checked.

5.

To save time, 1 in 8 of the total joints can be checked from the first row (e.g. check the first 10 joints laid out from 80 total joints).

6.

Input the measurements provided by the deck crew into the spreadsheet.

7.

Arrange an independent double check of the spreadsheet to ensure that the measurements provided by the deck crew have been correctly input into the spreadsheet tally.

8.

Check the casing tally thread make-up loss length in the spreadsheet.

9.

Note: the shoe joint does not have any make-up loss applied to it as there are no threads at the bottom of the joint.

10. Check the total length of all the joint measurements input into the spreadsheet against the onshore laser measurement total length for all the joints sent to the rig. These two numbers should be the same. If not then either the deck crew have recorded an incorrect laser tally measurement or an incorrect value has been input into the spreadsheet.

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11. The following quality control checks should be included in the spreadsheet to ensure that the formulae in the spreadsheet are correct: 12. Sum the effective length of all tubulars in the tally (including landing string to rotary table). 13. Record the final depth in hole measurement from the tally. 14. Record the final shoe position. 15. All of these numbers should be the same; if they are not then there is a mistake in the formulae in the spreadsheet.

11.4 Example Casing Checklist

Well Section Preparation Checklist

Well No. A08 (15) CP23 : 13 3/8" Casing 1. Well Information/Goals Objectives

• Drill 17½” hole to section TD. Circulate clean. POOH and wipe clear any resistance. • TD criteria = 13 3/8” shoe ~ 60m MD into top Cretaceous + 3m sump. • Run and cement 13 3/8” casing without inducing losses.

Major Risks

• Overpulls while POOH (ledges at around 710m and cement blocks at 26” shoe). • No shallow gas on previous wells. Risk assessment will be prepared to cover the running of the 13 3/8” casing with the diverter insert removed. • Lost circulation, A02 and A03 had losses as soon as we ran casing into open hole! • Mud pump problems - spares, pump tools, JSA and PTW to be prepared. • Hole instability - take care around stringers 700-850m. • Hole cleaning, this is a high angle section. Mud Engineer will confirm when shakers clean. • Hole packing off - WSL to be on the Rig Floor whenever we break circulation. • Wellhead packing off - be prepared to lift the hanger to regain circulation. • New crews - recent promotions mean several people are new to their role.

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2. Preparation Checklist Note: Responsible persons are to lay their hands on the equipment before signing below that the check has been made. Driller to get master copy signed when task is complete. Who is Responsible RSTC RSTC Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Drilling Engineer Drilling Engineer Drilling Engineer Drilling Engineer

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Who is Responsible To update and issue copy of the Section Checklist. To pull Lessons Learned from the database and present these at the Technical Limit meeting. To order casing and cementing equipment and have it onsite before starting to drill the section. To chair the Technical Limit meeting for both the casing and cement job. To make sure the Cementing Programme is signed and issued by the onshore LDE. To prepare a Risk Assessment covering the removal of the diverter insert while running the casing. To prepare and issue the Casing Running Instructions. To prepare and issue the Cementing Instructions. To check both the Casing Tally and Running List.

Comments

Initials

Weather forecast? What is the best timing for this meeting?

ORA to be signed by the WTL.

TD section to suit Tally!

To witness the loading of the cement plugs. To check the Cementer's calculations. If a stage collar is to be run, then check it is in the closed position and that all threads, plugs and baffles are OK. To ensure Programmes, Amendments and Ops Notes are issued to all offshore copy holders. To prepare the Deck Plan before the casing arrives. To supervise the unloading and measuring of casing. To prepare the Running List.

Liaise with Deck Foreman! Liaise with Deck Foreman! Needed at section TD!

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Who is Responsible

Drilling Engineer

To issue and track the changes to the Running List.

Drilling Engineer Drilling Engineer Drilling Engineer Rig Manager

Calliper the ID of 10 joints to help establish the correct capacity. Confirm the pups above and below the hanger are the correct grade/weight and thread form. To issue the drag charts to the Driller and Mud Logger. Check ton-miles on drill line and slip/cut if required. If running a long string of casing, check the maximum available pull and advise Well Site Leader on limitations. Prior to running casing, ensure the mud pump strainers are cleaned to ensure there is no loss of suction for the cement displacement. Get the original copy of this Preparation Checklist initialled by all responsible parties. Ensure BOP controls are isolated to prevent use. Run the 13 3/8” shoe on pick-ups or else the VDM will see a down force and get stuck as the FMS set.

Rig Manager

Rig Manager

Driller Driller Driller

Driller

Driller

AD

AD

AD

Strap out of the hole and report strap measurements to both the Rig Manager and the Well Site Leader. Wipe clear any resistance on the final trip out and report all trouble spots to the Well Site Leader. Check the combination tool is in the Wear Bushing Mode (lugs at the bottom) and racked ready for quick recovery. “Small jetting sub” assembly to be made up and racked back in readiness for pulling the wear bushing. Prepare Rig Equipment: • Rig Tongs - Dies sharp, correct jaws, greased and easily moved. Snubline condition OK. • Hydraulic catheads - function tested, Cyberbase calibrated for tong arm length, etc.

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Comments

Initials

Ensure all old copies are destroyed. Measured from the pin end.

FOS not to be reduced below 3. One pump at a time! Return to RSTC.

Never pull a joint out of the well using P/Ups on TDU.

Do not get confused with BOP test mode.

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AD

AD

AD

Who is Responsible Ensure JSA in place for using rig tongs and manual slips. Check Drill Floor Equipment: • VDM - check the alignment, function test the assembly, dies sharp, correct size jaws fitted? • Check function of MAB/Stabbing Platform. • Check function of link tilt. • Check the function of the conveyor belt and table. Review equipment requirements with the Deck Foreman and highlight the order required on rig floor. Site as much equipment on the floor as is safe and practical: Casing Tong; Hoses and Control Panel; JAM equipment; Spiders; 22 ft bails; 250T Side Door elevators; Single Joint Elevators; Hand Slips; Le Fleur; Swedge; Water Bushing; Casing Dope; Bakerlok; Barite; Wire Brush, Rags and the Cement Head. Ensure all Rigid centralisers, spare stop collars and nails, are on the drill floor.

AD

Check the contingency casing spear is on board and the listing is as per the Group Loading.

AD

Ensure that the chicksan line is rigged up from the D-annulus to the A-annulus outlet and CRI holding tank. Mud pumps: • All pumps to be dressed with 6½” liners. • Discharge and suction strainers to be cleaned out. • Check the running hours for swabs and pistons, and change as necessary.

Derrickman

Deck Foreman

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Lay out, number and measure casing as per WIM Deck Procedure D-013E. • Joints to have numbers painted clearly in centre. • Pups to be numbered Pup A, Pup B, etc. • Shoes to be marked “Primary” and “BU Shoe”. • Floats to be marked “Primary” and “BU Collar”.

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Comments

Initials

All equipment operating and ZMS correctly set up.

Rigids can't be run on the conveyor. Check the tools are in good condition. Used as bypass around the 13 3/8” Hanger. Everything needs to be done to minimise the risk of pump failure. Leak test pump after checks. Keep joints which have preinstalled centralisers in a separate bay if deck space allows.

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Wellsite Leader’s Handbook Who is Responsible Deck Foreman Deck Foreman Deck Foreman Deck Foreman

Deck Foreman Deck Foreman Weatherford

Weatherford

Weatherford

Weatherford Cameron

Mud Engineer

Mud Engineer Mud Engineer

Who is Responsible Check the function of the KBC and inspect the gripper head. Remove all casing thread protectors and inspect - lay aside any joints with obvious damage. Whilst laying out the casing, check the overall length of 10% of the joints. Check all the pre-installed centralisers are secure (nails bent over properly, etc.) and undamaged. Ensure centralisers are installed between 10 ft and 14 ft down from the box end so the KBC will grip in the middle. Check 13 3/8” float shoe and float collar joints are clear of junk/debris. Keep all pin and box protectors onboard till the casing is run. Physically fit the single joint and side door elevators onto a joint of casing. Check the side door elevators for uneven wear on the bearing surface and correct operation of the latch. Carry out dimensional and function checks on the casing tong, elevators and spiders on the deck. Move the access platforms to the rig floor and erect and check all fitments are secure. Check the Casing Hanger, Running Tool, Spare Running Tool, Seals, Pack-Off with it's Running Tool, Jetting Tool and Middle Wear Bushing.

Make sure there are enough contingency chemicals (Bentonite, Polymer, KCl and contingency LCM chemicals) on board to cover a redrill of the section. Ensure the shakers are dressed correctly for the casing and cement job. Create a pit plan to cover the running of the casing and cementing operations. Plans to include a provision for dealing with severe losses.

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Comments

Initials

Get AD involved for JSA and Toolbox Talk.

Permit needed for the diesel power pack.

All gear to be within easy reach of drill floor in case cranes down.

Discuss plan with the WSL before issuing to the crews.

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Who is Responsible

Comments

Mud Engineer Mud Engineer

Site Citric Acid at pits and CSU to cover the possibility of getting cement returns to surface. Liaise with the Cementer then prepare spacer and mix fluids as per programme.

Mud Loggers

Ensure copies of the mud log are made available to the Driller to highlight stringers, loss zones and other points of interest.

Initials

Test all drillwater for chlorides before use.

11.5 WSL’s Casing Checks The table below has been prepared solely for the use of the Well Site Leader. It helps confirm that all critical steps have been completed and is particularly useful for when Well Site Leader's crew-change immediately before a casing job. No.

Check

Comments

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Casing Weight, Grade, etc. Casing ID Casing Yield Casing Burst Casing Collapse Casing Capacity (Town Tally) Metal Displacement Closed End Displacement Make Up Loss Minimum Make Up Torque Optimum Make Up Torque Maximum Make Up Torque Bakerlok Torque Value Open Hole Centralisers Cased Hole Centralisers Will Centralisers pass FMS? Jamming Required? Special Drift Joints? Planned Shoe Depth Sump

13 3/8” x 72#, L80, DINO VAM 12.347” as per the book and 12.4196” as per Town Tally 1,661,000 lbs 5380 psi 2668 psi 0.1481 bbls/ft or 0.4859 bbls/m (1.499 bbls/ft) 0.0257 bbls/ft or 0.0843 bbls/m 0.1738 bbls/ft or 0.5702 bbls/m 4.761” = 0.1209294m 18,450 ft.lbs 21,700 ft.lbs 24,950 ft.lbs 24,950 - 21,700 + 24,950 = 28,200ft.lbs 1 x 16 1/8” Spiraglider/Joint up to TOC @ 600m 1 x 17½” Spiraglider/Joint, Mudline to Hanger 16 1/8” Spiragliders will 17½” Spiragliders will not Overdrive and Jam unit to be used None! 1298.567m Minimum 5m

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Check

21 22 23 24 25 26 27

TD Shoe Type Float Type TOC Running Speed

28

Maersk Fighter Manifest No. CLA-0122: 53 Joints Casing c/w 16 1/8” Spiragliders 35 Joints Bare Casing 15 Joints Casing c/w 17½” Spiragliders 2 Joints Bakerloked Casing c/w 16 1/8” S'glider 2 Shoe Joints c/w 16 1/8” Spiragliders 2 Float Collar Joints c/w 16 1/8” Spiragliders 3 Bare Landing Joints 8 x Pups 1 x Casing Hangers (Clair 479 and 481) 122 pieces in total

29 30 31 32 33 34 35 36 37 38 39 40

Check Wellhead HOP Compare Seawell Tally Tally Book vs. Running List Running Number Sequence Check Shoe Depth Check MUL Subtraction Check Stick-Up Check Centralisers to TOC Check Cents. 40m to 211m Check Addition Joints Remaining On Deck Check Comments on R/List

Fill requirements Casing Test

1305m Composite up-jet pencil type Halliburton Float Collar 600m BRT, i.e. 200m above 18 5/8” shoe 2 minutes per joint slips to slips Top up each joint and completely fill every 5th joint 4000psi over seawater Deck Count: 53 Joints Casing c/w 16 1/8” Cents. 35 Bare Joints Casing 15 Joints Casing c/w 17½” Cents. 2 x Casing Shoe Joints 2 x Float Collars 2 x Bakerlok Joints 3 x Landing String 8 x Pups 2 x Casing Hangers 122 pieces in total

HOP measured at 39.269m BRT Checked on deck between WSL and Deck Foreman Checked by AB Checked by AB - (No Joint No. 113!) Shoe at 1299m (TD at 1305m) 0.1209294m MUL checked throughout by AB 39.3 - 4.8 - 7.924 - 2.926 - 12.65 - 12.699 = -1.699m 16 1/8” Spiraglider on every joint up to 600m 1 x 17½” Spiraglider from 211m to 39m Shoe Depth OK at 1299m; checked by GT 104 pieces in hole and 18 pieces on deck after run Shoe and Stringers OK - Need to add Top Cretaceous!

11.6 Best Practice when Running Casing 1.

As with many aspects of Drilling and Completions activity, the key to a successful outcome is in the preparation. The quality of the hole as drilled, combined with the wiping clear of any trouble spots on the last trip out, is vital for a trouble-free

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casing run. An over-zealous Directional Driller who puts in a high dog-leg immediately below the previous shoe may still achieve his goal, however it has been futile if the casing doesn't get to bottom. Similarly once TD is reached then everyone is keen to get the casing in the ground, however an additional hour or two spent cleaning up the hole, or even making a check trip, can in the long run prove to be cheap insurance. 2.

Equipment must be mobilised and thoroughly checked well ahead of the operation. There is little that can be done about bad weather, however equipment can be lifted to the floor early to reduce the impact of any crane outage.

3.

Written casing instructions should be issued as early as possible to give the crew advanced notice and the time to prepare for the task ahead.

4.

The Well Site Leader should take an active part in the pre-job Toolbox Talk so that the safest and most efficient rig-up plan is followed. All work procedures and lift plans should be reviewed during the meeting. The WSL should pay particular attention to the crew mix. Some crews will have run casing several times, whereas it may be some time since a particular crew has run Conductor or a Liner. Casing Size

Rotary Insert Bowls

Dog Collar Links

Dog Collar Dies

Slip Segments

7”

No. 3

8

9

11

9 5/8”

No. 2

11

12

14

13 3/8”

No. 1

14

15

18

5.

We no longer change pipe rams to run casing, however it is vital that the Driller sets up his annular closing pressure to suit the size of the pipe being run. If an Overdrive is being used, then make sure the Driller resets his floor saver accordingly.

6.

If using an Overdrive or even the Le Fleur system then these will be used as a first choice method of well control. This said, make sure a Full Opening Safety Valve and casing swedge are also available on the floor.

7.

WSL to witness the make-up and Bakeloking of the shoe track. Physically check inside each joint to make sure it is clear of debris. All float equipment is to be checked, make sure the shoe and the float collar are clear of debris and that the check valve in the shoe is holding before the joint is filled up. Raise the float and shoe in the air to make sure the valves are free to drain.

8.

The WSL should inspect the first few torque make-up graphs to check that the make-up torque and shoulder torques are correct.

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If it is necessary to make up the float collar on the rig floor, then make sure it is screwed into the pin end of a joint and not the box end. (It is extremely difficult to fish a joint of casing should it be dropped down hole with a float collar screwed into the top.)

10. If using a crane and hold-back tugger to lift joints of conductor into the floor, then make sure the crane operator is aware of the complexity of a three point lift and he gives due attention to the position of his boom tip. 11. Never lift a joint of casing out of the rotary using pick-up elevators on the blocks. If centralisers or a coupling hang up, then it is very easy to part the 5 Te lifting bridle. 12. Check the rating of all equipment to make sure the maximum pull is understood. N.B. Most elevators are marked in the American (Short Ton) convention, i.e. 1 Short Ton = 2000 lbs. 13. If a joint is rejected, then layout both that joint and the joint below as damage to the coupling is at times difficult to spot. 14. Bevelled couplings are never to be run with square shouldered elevators. 15. It is important to periodically stop and check the integrity of all bridles, slings and shackles and in particular to check any rigging gear which is overhead as any wear or chafing to this equipment can be more difficult to spot. 16. When picking up casing with side door elevators, never load up the door mechanism. Turn the elevators so that the door is uppermost as the joint is lifted from the horizontal. Similarly never allow a side-door elevator to be shock loaded as the latch can spring open. 17. The Mud Loggers should record the drag and hole fill at a suitably fast data rate. The pick-up weight should be checked after completely filling every fifth joint. The Mud Logger should alert both the Driller and WSL should either the drag or hole fill deviate from the expected trend. 18. If changes are made to the Running List then the Drilling Engineer must make sure that the changes are made to all copies of the list and that the old copies are seen to be destroyed. 19. Take care at meal breaks to make sure that not too many people change roles at the same time. 20. The desired running speed is to be included in the Driller's Instructions. It is important to keep below the maximum speed given by the surge calculations. In addition, the Driller must be aware of the dangers of the initial surge when starting to move down. Rev. 1, April 2010

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21. The Drill Crew must check the size of each centraliser run in hole and make sure all screws, pins and nails are secure. 22. If differential fill equipment is being run, then both the Mud Loggers and Driller must be alert to the signs of the float equipment beginning to block up. If displacement suddenly goes to closed end, then stop and break circulation to make sure that everything is clear. Make sure that differential fill equipment is tripped before entering a hydrocarbon bearing zone. 23. Do not break circulation as a matter of course. Modern mud systems should not need to have the gels broken and unless the well is absolutely clean then breaking circulation brings with it a risk of packing off either around the wellhead or around tight spots in the open hole. 24. If it is deemed necessary to break circulation then use the following procedure: a) Work the string over at least the height of a joint to make sure the hole condition is good. b) Move the string up hole and stop at a clear section of hole with the string at the up weight. c) Start circulating at 100 gpm but do not exceed 300 psi until returns are seen. d) Once full returns are achieved, build the pump rate to 150 gpm and then to 200 gpm. Again allow the flow to settle before then moving the string down. 25. Whenever resistance is seen, it is advisable to break circulation before setting down too much weight. The jetting action of most shoes is limited so better not to compact any fill or resistance before getting circulation established. The other advantage of circulating is that it is often possible to see fluctuations in pressure and returns which will help establish if the resistance is at the shoe or higher up the string. 26. Excessive set-down weights should not be used. If resistance is seen, consult the expected drag charts and compare this with the actual figures recorded over the last few joints. Watch for an overpull after setting down weight and if seen then reduce the next set-down weight accordingly. Under normal circumstances 50K should be used as maximum set-down weight. 27. If the problem is known to be stringers or ledging, then it may be possible to bounce the string over the obstruction using varying running speeds. Failing this then try to re-orient the shoe. 28. Turning the string may help to re-orientate the shoe. Never use more than 80% of the make-up torque when working rotation into the pipe.

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29. The maximum pull to be used in the event of stuck pipe should be known by the WSL before the need arises. Refer to Section 10.1.10 of this handbook for guidance. 30. It is important to make and break the Wellhead Running Tool and then confirm the seals are holding by breaking circulation. Washing down the landing string is not always necessary or advisable. However if any resistance is seen near bottom, then it is advisable to minimise the set-down weight, and therefore also any compression of fill, before the pumps are brought up to speed as per the procedure in 11.6.24 above. 31. Before picking up the hanger, two independent checks are to be made of the joints remaining on deck. This check should then be repeated after picking up the last joint. Before landing off, record the pick-up and slack-off weights and measure the squat as the weight is landed on the wellhead. Measure the stick-up on surface to confirm that land-off is correct. 32. Once the casing is run to depth, the Drilling Engineer will issue the “as run” tally to town and also reconcile the usage of casing dope and Bakerlok. A backload manifest is then prepared and all surplus joints and any damaged joints will be clearly marked up and returned to town.

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12. Cementing Practices References: Functional Expectations of WSL • 2.2.5 The WSL shall ensure that all planned activities are risk assessed and adequate mitigations are put in place. • 2.3.5 Ensure that service providers’ performance is monitored and accurately reported, NPT is captured and the UFR process is used. • 2.5.11 Ensure that deviations from the approved programme/plan are discussed with town. Operations shall only continue after an agreed forward programme is established, with risks understood and the Management of Change process completed as required. • 2.5.15 Ensure that the cement/test pump has been checked and pressure tested in advance of it being required for critical path operations. • 2.7.1 Supervise the cementers and drilling contractors in the performance of their duties. • 2.7.2 Prepare the calculations for the cement job to include slurry volumes, displacement volumes and cement/additive quantities. The calculations shall be verified by a minimum of two independent sources including the Cementing Service Provider. • 2.7.3 Agree pit management plan. • 2.7.4 Ensure that twice the required volume of chemicals for the cement slurry is available onsite. • 2.7.5 Ensure that the Mud Loggers and Drillers are informed of the volume and type of mix water required for the lead and tail slurries, which mud pit will be used for each type of mix water, the expected total volume of returns during the cement job and the increase in pit volume. • 2.7.6 Co-ordinate the execution of the cement job, ensuring that all relevant personnel are issued with a detailed programme highlighting individual responsibilities. This must include volumes, pressures and pump rates for the cementing and displacement operations. Contingency plans should be drawn up for any equipment failure, etc.

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• 2.7.7 Ensure that the cement recipe has been approved by the LDE onshore, mix water has been checked for contamination and where possible, samples of cement, mix water and additives have been sent to town for testing. • 2.7.8 Be aware of the setting times for the cement and monitor the remaining time available throughout the job. • 2.7.9 Ensure that the correct amount of cement is pumped during the cement job (this should include the checking of bulk volumes and additives used). • 2.7.10 Witness the loading of the cement head and supervise the release of darts and plugs. • 2.7.11 Witness the shearing and bumping of the plugs. • 2.7.13 Ensure that chemicals and volumes to be used for a cement job are in accordance with local environmental legislation. Ensure that at all times during a cement job the bottom hole circulating pressure, when pumping spacer and slurry, is greater than the formation pressure. • 2.7.14 Where a computer based liquid additive system (LAS) is used the WSL will verify that the correct information has been loaded into the computer system. • 2.8.3 Ensure that there is no single point failure mechanism within the fluids containment system. This should include mud pit valves, flowline valves and overshot packers. BP Drilling and Well Operations Policy, BPA-D-001: Policy Numbers: 1.8, 2.2, 2.4, 3.1.5, 3.3.5, 3.3.6, 4.1, 4.3, 7.1, 8.1, 8.12, 8.13, 8.15, 14.1, 14.2, 14.3, 14.4, 25.3, 25.4 and 26.1. SMS Documentation • Offshore Chemical Regulations, OCR for Wells, 2002. • UKCS-ENV-0206 Procedure for Compliance with OCR Regulations. • GP 10-60 Zonal Isolation Requirements. • SRP 4.1-001 Plug Cementing. • SRP 4.1-002 Squeeze Cementing. • SRP 4.1-003 Cement Lab Testing.

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12.1 2009 Wellsite Cementing Checklist for WSLs The BP global WSL/DE cementing checklist is on the following website: https://epti.bpglobal.com/C3/C6/Cementing/default.aspx

12.2 Example Cementing Checklist

Well Section Preparation Checklist

Well No. A08 (15) CP23 : 13 3/8" Casing 1. Well Information/Goals Objectives

• Cement 13 3/8” casing as per programme. • Displace using seawater, bump plugs and pressure test casing to 4000 psi. • Bleed down pressure and confirm floats are holding.

Major Risks

• No shallow gas seen on previous wells. • Lost circulation, heavy losses seen on most wells requiring displacement rate to be dropped to as low as 2 bbl/min. • Whole cement seen back at surface - citric acid to be positioned at shakers and pits. • Mud pump problems - filters to be checked and pumps tested while running casing. • Hole packing off - Well Site Leader to be on the Rig Floor when we break circulation. • Wellhead packing off - be prepared to lift the hanger to regain circulation. • New crews - recent promotions mean several people are new to their role.

2. Preparation Checklist Note: Named persons are to complete the checklist and return it to the RSTC.

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Wellsite Leader’s Handbook Who is Responsible RSTC RSTC Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader

Well Site Leader

Well Site Leader Well Site Leader Well Site Leader

Who is Responsible To update and issue copy of the Cementing Checklist. To pull Lessons Learned from the database and present these at the Technical Limit meeting. To chair the Technical Limit Meeting. To supervise all companies involved in the safe execution of the cement job. Verify that the final slurry recommendation meets the job requirements, DWOP policy and ETP compliance. The specifications given in the Drilling programme are to be checked against the actual well conditions. Ensure sufficient cover of Cementers, SWACO, etc. Approve all plans, worksheets, reports and job tickets. Ensure all chemicals to be used are within the PON15. Ensure cement recipe is based on actual field samples. Ensure that sufficient cement and chemicals are onboard so as to be able to do the job twice. Check the thickening time against the expected job duration. Thickening time to 50 Bc, at bottom hole circ. temp should be at least 2 hours over the mix and pump time. Review the expected compressive strength profile and check against planned activity timings. Check that all Cement Unit maintenance is upto-date and all relevant equipment is in certification. Check float equipment integrity as it is picked up. If a stage collar is used, then check it is closed, that it is clear of debris and the threads are undamaged.

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Comments

Initials

Any new technologies?

Review Pit Plans.

Make sure the expected pumping rate is achievable. Compressive strength on drilling out the shoe?

Check the plugs and baffles are fitted OK.

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Who is Responsible

Well Site Leader

When using a subsea system, check the plugs are correctly assembled, the swivel is OK and the plugs are compatible with the launching balls/darts and landing collar. Drift all tubulars in the landing string and check that the balls and darts are correctly loaded.

Well Site Leader

Check the pumping schedule and ECD predictions as issued by the cementing contractor.

Well Site Leader

Check the excess figure and calculate what error margin would take cement back to surface. Check the spacer reflects the mud properties in use. Ensure any changes to programme are run past town. Check the loading of the cement head.

Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader Well Site Leader

Well Site Leader Well Site Leader Well Site Leader Well Site Leader

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Review the casing test requirements against the actual annulus contents. Discuss clean-up and disposal plans with cementer. Independently verify the cement calculations. Issue the cementing instruction sheet which should contain volumes, pressures and pump rates. Contingency plans must be established to cover an alternative mixwater supply, rig pump failure, elevated circulating pressures and losses. If a viscous/reactive pill is to be set, make sure that the hole contents have been circulated above the pill. Plan to displace at the maximum allowable rate. Consider the mud compressibility figures. Displace from a separate pit to check stroke counters. Slow down the pump before 100% efficiency. Only stop after pumping 95% pump efficiency.

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Comments

Initials

Make sure that there are no profiles in any of the equipment that could stop the plug or dart. Point of discussion at the Tech. Limit meeting.

Check tell-tale function.

Check with cementer.

Do not add half the shoetrack volume.

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Who is Responsible

Well Site Leader Well Site Leader

Always use the cement unit to displace small jobs. Make sure the Driller and Mud Loggers are monitoring displacement volumes, rates and pressures and are checking all parameters against the expected trends.

Well Site Leader Well Site Leader Cementer

Have a displacement vs. pressure plot prepared. Make sure the pressured mud balance is calibrated. Ensure all cementing chemicals to be used are allowed for within the well PON15 Permit. Make sure that both cement and mixwater samples are sent to town for analysis in plenty of time. Check the compatibility of the wiper plugs and the Float Collar. Check the double plug cement head is suitable for the casing couplings.

Cementer

Cementer Cementer

Cementer

Ensure we have sufficient cement and chemicals to do the job twice.

Cementer

Check the drift and function of all valves on the Cement Head. Also test tell-tale and launching system. The top and bottom seal to be checked and that spare seals are kept onboard. Load the plugs into the Head. If a subsea style launching system is being used, then check that the plugs are correctly assembled, that the swivel is free to turn and that all plugs, darts and balls are compatible and that no bevelled edges will interfere with their travel. Calculate the cement mix requirements and compare these figures against the programme.

Cementer

Cementer

Cementer

Liaise with the Mud Engineer and prepare spacer and mix fluids as per programme.

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Make sure the Mud Loggers are informed at all the key stages. Issue with Instructions.

Check there are no bevelled couplings. Cement to be split between both “P” tanks. Well Site Leader to witness the loading of the cement plugs. Well Site Leader to witness the loading of the cement plugs, darts, etc. Well Site Leader to check the cement calculations. Test all drillwater for chlorides before use.

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Cementer Cementer

Cementer

Cementer

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Who is Responsible Check that the discharge hose is made up to the cement vent line and the skip is in place for catching excess dust. Ensure radio head sets are available and that all batteries are fully charged ahead of the job. Ensure the bulk cement system is blown through and clear of blockages, also that the vent line and surge tanks are clear of old cement. Make sure the following equipment is ready for the job; pressured mud balance, rags, a minimum of six sample cups and cans prepared to take both mixwater and slurry samples. Make the following checks on the Unit and Lines: • Unit and lines to be tested to 1000 psi over the casing test pressure. • The unit displacement tank scale is accurate and readable. • No leaks on the displacement tank valves. • The low pressure mix system is to be flushed. • The packings on the mix pumps are good. • The delivery pressure on the mix pumps is adequate for mixing on the system. • The correct jets are fitted to the mixer. • Packings on the main pumps are good. • The HP mix system is also flushed through. • The by-pass valve on the mix manifold is working. • Engine oil and water levels are checked OK. • All hoses are in good condition. • Hopper is serviceable and the sight glass is clear. • LAS system is OK and no supply lines meet. • Physically check the volume in each LAS tank. • Roll all Liquid Additives before the job. • Flush all delivery lines from the pits. • Is the water and mixwater supply rate sufficient? • Batch mix system is operating correctly. • Ensure that the data recorder is working correctly.

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Comments

Initials

Empty the dust collector and check all tank weight readings are correct.

Confirm all checks have been made with the Well Site Leader.

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Wellsite Leader’s Handbook Who is Responsible Cementer Cementer Cementer Cementer Cementer Cementer Cementer

Cementer Cementer Cementer

Cementer Cementer Cementer Cementer Cementer

Cementer

Who is Responsible Check the drillwater supply for chloride content. Check the PPE locker is fully stocked and replenish as required. Ensure that all equipment carries valid certification. When was the radioactive densometer last checked? Check chicksans for connection compatibility. Check that proposed chemical usage is on the PON15. Track the bulk cement to make sure the cement that was sampled is the cement that will be used. Agree the bulk tank sequence with the Well Site Leader. Ensure that no interruptions are expected on both power and the air supply. Check that the PSV on the unit is rated at below the weakest component in the string. Check the measured bottom hole temperature is in line with the cementing programme. Discuss the clean-up/discharge plan with the Well Site Leader. Retain samples of mixwater and cement slurry till after the top of cement is tagged. Witness the mixing of all spacer chemicals. Discuss contingency plans at the pre-job meeting. Cover losses, low weights, contamination, etc. Complete all reports including NPT and ILT.

Rig Manager

Ensure that all maintenance tasks on the cement unit and the bulk system are up-to-date and no equipment malfunction exists.

Rig Manager

Liaise with the Platform and confirm that there are no planned outages of either the air or water systems.

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Initials

Governors are not to be relied upon!

Discuss any ILT/NPT with the Well Site Leader. Confirm with Well Site Leader that all is OK.

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Who is Responsible

Rig Manager

Confirm that the system instrumentation, i.e. load cells pressure gauges, etc. are all in good working order. Confirm that the mud pump strainers have been checked and that the pump has been charged and leak tested before the start of cementing operations. Ensure the wellhead bypass line is hooked up, open and manned throughout the cementing operation. Be prepared to lift the hanger from the wellhead should the bypass flutes pack-off. Make sure the MAB is functional so that safe and easy access is available to the cement head valves. Liaise with the Mud Engineer and Cementer and make sure that any pit and lines used to mix, store or transfer cementing mix fluids are secure from potential contamination. Liaise with the Mud Engineer and review the proposed pit plan covering the cement job and displacement. Fluff the tanks ahead of the job as per the cementing procedures and Cementer’s requirements. Pressure up the tanks the day before the cement job and then repeat 2 hours before the start. Blow through all bulk lines ahead of the job to check the vent system and all lines are clear.

Rig Manager

Driller

Driller Driller

Derrickman

Derrickman

Derrickman

Derrickman

Derrickman

Derrickman Mud Engineer

Mud Engineer Mud Engineer

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Blow through all lines after the job and confirm all are clear. Liaise with the Cementer and Derrickman and create a pit plan covering both cementing and displacement.

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Comments

Initials

Check the transfer rate to the surge tank is OK.

Verify the pit plan with the Well Site Leader.

Make sure the pit plan is explained to the Mud Logger. Discuss the contingency plans for dealing with severe loses and/or cement returns to surface.

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Who is Responsible Mud Engineer Mud Engineer Mud Engineer

Check the mixwater for any contamination.

Mud Engineer

Supervise the pit plan throughout the job and liaise with the Mud Logger and Well Site Leader throughout. Check for cement contamination in the returns during the cement displacement. Liaise with the Mud Engineer over the proposed pit plan. Liaise with both the Driller and Mud Engineer during the actual job and displacement. Monitor the volumes and pressures during the displacement and inform the Well Site Leader should the trend deviate from the prepared chart. Ensure that all data is recorded throughout the job and that the recording rate is suitable for post job analysis.

Mud Engineer Mud Logger Mud Logger Mud Logger

Mud Logger

Ensure that any spacer which is left behind pipe contains a biocide. Supervise the building of spacers and mixwater as per the Cementer’s requirements.

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Comments

Initials

Weight the spacer and check rheology.

12.3 Best Practice when Loading the Cement Head 1.

The loading of the double plug cement head is best achieved with the assembly laying flat on its side. This allows for viewing at each end and means that the work is carried out at deck level rather than at height.

2.

The handling of the cap can be an awkward job and should be set up with whatever mechanical handling aids are available. Having the cap supported at the right height with wooden dunnage is often the simplest and safest option.

3.

First check the condition of the top and bottom seals to make sure they are in good condition. Spare seals should have been ordered with the equipment and these should also be checked to make sure they are of the correct size.

4.

Check the Quick-Latch connector is free and travels smoothly.

5.

Check the function of the Lo-Torque valves and drift the valve assemblies using a suitable length of dowel.

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6.

Function the tell-tale, note its launch position and check the travel of the lever.

7.

Wind the bottom plug launching spindle in, out and then in again and count the number of turns. Once fully in, then secure the handle with tape.

8.

Examine the bottom plug, confirm the size, type and shear rating, then load it into the head.

9.

Wind the top plug launching spindle in, out and then in again and count the number of turns. Once fully in, then secure the handle with tape.

10. Examine the top plug, confirm the size, type and pressure rating then load it into the head. 11. Finally re-instate and knock up the top cap.

12.4 Best Practice when Cementing Casing 1.

Ensure the checklist is distributed well in advance of the job and use the pre-job Technical Limit meeting to discuss any equipment problems or programme issues.

2.

Traditionally 120% casing contents has been circulated ahead of the job, however so long as there is no risk of swabbed gas in the well and the bottom hole temperature will allow, then it is more efficient to simply break circulation and record the pressures at the planned cementing pump rate.

3.

While circulating, hold a Toolbox Talk with everyone concerned and confirm the final preparations have been made: a) Confirm that the bulk system has been fluffed and blown through. b) Check that a slack tugger line is still attached to the cement head and that the string can be lifted should the wellhead pack-off. c) Make sure the chicksan by-pass line is opened to increase the flow by area across the hanger. d) Make sure that the dust collectors are emptied and all weight sensors are functioning correctly. e) Make sure radios are available and that batteries are charged. f) Set the mud pump pop-offs at over the required bump pressure but below 90% of the lowest burst pressure in the string. g) Make sure that everyone is aware of the proposed pit plan and that the Mud Engineer is set up to monitor the returns. h) Establish if there have been losses seen during the casing run or while circulating ahead of the job.

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i)

Confirm that the overboard discharge line is ready to go but that double valves will remain closed until the end of the job.

j)

Ensure that the Control Room has been informed and that both power and air supplies are as guaranteed as possible.

k) Discuss contingency plans, e.g. planned response should losses be seen and/or if problems are encountered with the cement pumps. l)

Has citric acid been positioned in case of cement returns being seen on surface.

m) Is the manriding tugger or cherry picker basket available to access the cement head? n) Do smoke detectors need to be inhibited in the cement room? 4.

In some areas the dumping of whole cement requires legislator's approval. If this is the case then ensure that an e-mail is prepared with the appropriate information so as to expedite the process should discharge be required.

5.

Stop the rig pump and then line up to the cement unit. Using the rig pump to apply 200 psi on the standpipe to help prevent cement slurry from passing any closed valves.

6.

Have the cement unit pump away part of the pre-flush then stop and pressure test the lines to 500 psi over the bump pressure. Take this opportunity to set up and test the governor on the unit. Bleed back the pressure to between 100 and 200 psi then have the cement head opened back up. As the valve is opened then check the cement line pressure does indeed fall away. This check will confirm that the cementing line-up is correct.

7.

WSL to witness the releasing of the bottom plug and confirm the cement head valving is correct. Mix and pump cement as per programme: a) The flowmeter on the unit should be zeroed after the preflush is away. b) WSL should note the time the mix commences. c) WSL needs to ensure that the mix is started correctly. Make sure the LAS dumps are right and that the mix tank count is being recorded correctly. d) Once the mix is established, then the WSL can leave the Drilling Engineer on the unit and spend time checking with the Driller and Mud Engineer that all is going to plan. e) Make sure that both “P” tanks are pressured and ready to go. Mix cement from the first tank and then swap to the second and leave enough cement in the first to cover the tail cement if necessary. f) Samples of both the mixwater and slurry should be taken at intervals and kept till the cement is tagged.

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g) Mud Engineer to reconcile volume pumped against the volume returned and liaise with the WSL, Driller and Mud Loggers. h) If losses are seen then the pump rate should be reduced accordingly. i)

The number of mixwater tanks pumped, the amount of cement left in the “P” tank and the barrel counter itself should be checked one against the other.

j)

When swapping to the tail cement, again check the time and calculate which slurry will have the limiting thickening time.

k) WSL to witness the launching of the top plug leaving the Drilling Engineer to confirm the post-flush volume is pumped correctly. 8.

With the mud pump stroke counters set at zero, equalise the pressure over the standpipe then again confirm the line-up is correct by noting the pressure dropoff as the last valve is opened.

9.

Chase the cement with mud or seawater if this gives sufficient kill weight. Watch for the bottom plug shearing and then monitor the pressure rise as the cement moves up the annulus.

10. Maintain the programmed displacement rate throughout. However should losses occur, refer to the rate of pressure build-up to help establish if the losses are mud or cement. 11. If the displacement rate is dropped to contain losses, then leave sufficient margin to the theoretical thickening time. Cement should remain pumpable to 50 Bc, however this figure should never be relied upon. 12. During the displacement the Mud Engineer is to position himself at the shakers and continuously test the returns for cement. 13. Lower the displacement rate to 2 bbls per minute when 100% efficiency is reached. Continue pumping to the 95% figure and then stop. Do not pump ½ the shoetrack. While displacing with the rig pump, the Cementer should open the discharge lines and clean up the unit. 14. Bump the plugs and build the pressure in 1000 psi increments. N.B. If driven by DC motors, the pumps are better brought up in ¼ then ½ and then steadily to full pressure. While building the pressure, check the volume pumped is as calculated. 15. Hold the pressure for 15 minutes (30 minutes for critical strings) and then the pressure should be bled down at a steady rate. Measure the returns and confirm that the correct volume is returned. If pressure will not drop below the pressure at bump then the floats may be passing. If this is the case then build the pressure back over the recorded bump pressure and hold till the cement firms up. page 202

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16. After the job, make sure that all lines are flushed and all PSVs, relief lines and dead ends are knocked off and cleaned.

12.5 Typical Cement Calculations for a 13 3/8” Cement Job Lead Slurry: 1.58 sg = 13.2 ppg slurry at 1.88 Ft3/Sk. (3605' - 2625' x 0.1238 x 1.2 xs) + (2625' - 1969' x 0.1325) = 145.7 bbls + 86.9 bbls = 232.6 bbls x 5.6146 = 1306 Ft3 1306 Ft3 ÷ 1.88 Ft3/Sk = 695 Sx. x 94 ÷ 2204 = 30 MT. Total Mix Fluid = 10.544 g/sk x 695 = 175 bbl = 17.5 Tanks 10.125 g/sk Sea Water = 167.5 bbls = 9.6 bbl/10 bbl Tank 0.02 g/sk B143 Defoamer = 14 galls = 0.8 gall/10 bbl Tank 0.15 g/sk D075 Extender = 104 galls = 6.0 gall/10 bbl Tank 0.25 g/sk D197 Retarder = 174 galls =10.0 gall/10 bbl Tank Lead Slurry Thickening Time = 7 hrs 53 min. Tail Slurry: 1.92 sg = 16.0 ppg slurry at 1.15 Ft3/Sk. (4262' - 3605' x 0.1238 x 1.2 xs) + (4262' - 4154' x 0.1499) = 97.6 bbls + 16.2 bbls = 113.8 bbls x 5.6146 = 639 Ft3 639 Ft3 ÷ 1.15 Ft3/Sk = 556 Sx. x 94 ÷ 2204 = 24 MT Total Mix Fluid = 5.096 g/sk x 556 = 67.5 bbl = 6.75 Tanks 4.686 g/sk Fresh Water = 62 bbls = 9.2 bbl/10 bbl Tank 0.01 g/sk B143 Defoamer = 5.6 galls = 0.82 gall/10 bbl Tank 0.11 g/sk B165 Dispersant = 61 galls = 9.0 gall/10 bbl Tank 0.04 g/sk D197 Retarder = 22 galls = 3.2 gall/10 bbl Tank 0.25 g/sk D197 Retarder = 139 galls = 20.6 gall/10 bbl Tank Tail Slurry Thickening Time = 4 hrs. Spacer: 80 bbls Mud Push II Ahead at 1.32 sg = 11.0 ppg. Chase: Seawater to Chase = 4154' x 0.1499 bbl/ft = 622.7 bbls in total minus 20 bbl from cement unit gives 602.7 bbls from the Mud Pump. Now 6½" liners at 100% efficiency give 0.1436 bbl/stk or 6.9637 stks/bbl. Efficiency Strokes

100% 4197

99% 4239

98% 4282

97% 4327

96% 4372

95% 4418

Point at which the Bottom Plug will shear: 4154' x 0.1499 bbl/ft = 622.7 bbls into the job. Subtract 232.6 bbls Lead, then 113.8 bbls Tail, giving the point at which the bottom plug will shear will be 276.3 bbls into the chase volume, i.e. after 256.3 bbls from the Mud Pump. Static Differential Pressure when the plugs bump: (1) Hydrostatic in annulus given a Vertical well is: 1969' - 604' x 11.4 ppg x 0.052 = 809 psi. 604' x 11.0 ppg x 0.052 = 346 psi. 3605' - 1969' x 13.2 x 0.052 = 1123 psi. 4154' - 3605' x 16.0 x 0.052 = 457 psi. Total annular hydrostatic to Float = 2735 psi (1). (2) Hydrostatic inside casing = 4154' x 8.6 x 0.052 = 1858 psi Now 2735 - 1858 = 877 psi Static Differential. Worst case reduction in BHP with spacer in annulus: 80 bbls ÷ 0.1238 bbls/ft = 647 ft x (11.4 ppg - 11 ppg x 0.052) = 14 psi. Volume required to bump plugs to 4000 psi: ∆V = ∆p x V = 4000 x 623 = 8.3 bbls K 300.000 (SW)

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12.6 Best Practice when Pumping Cement as a Plug 12.6.1 General Setting kick-off plugs in high inclination wells, using a tapered string of drillpipe with small diameter pipe on bottom, high mud weights and the lack of calliper data may all add to the challenge. However if the following practices are used, then there should not be a reason to expect an unsuccessful outcome. 1.

Plugs can be set using a variety of techniques; Pump and Pull, IBOP and the Sacrificial Stinger method are all recognised within the company. However it is the Balanced Plug which is used most commonly and it is this technique that we investigate here.

2.

As a minimum, sufficient bulk cement, additives and chemicals must be kept onboard at all times to be able to pump two 500 ft plugs.

3.

When setting a plug in open hole, whenever possible, choose an in-gauge section of hole as plugs that are set in a washed out section have much less chance of success.

4.

When setting a plug in and around reactive shales, use an inhibited spacer.

5.

When setting a kick-off plug, use a slurry weight of 17 ppg (2.14 sg). However, if the mud itself weighs more than 16 ppg, use a slurry that is at least 1 ppg over the mud weight.

6.

Slurries must be lab tested using the appropriate temperature estimates. Using incorrect or overly conservative temperature estimates is a common reason for the failure of cement plugs.

7.

Most cement plugs are set on depth using the pipe tally figures. Because there is no physical tag involved, it is vital that a good pipe count is made and that the pipe figures are double checked before the start of cementing. Always use the cement unit to displace cement plugs.

8.

Plugs can be set to any length. The industry standard is normally 500 ft or 150m, however plugs of twice this length are successfully set within the company. However when considering plugs of over 300m, a sacrificial stinger will offer the best chance of success.

9.

It is contamination and not incorrect placement that is the most common cause of plug failure.

10. When designing a plug then expect to see 75 ft or 25m of contamination at both the top and the bottom. page 204

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12.6.2 Hardware 1.

If available, then a batch mixer should be used to best guarantee the result. If spotting a plug in slim hole conditions, it may be prudent to limit the plug length to the available tank space on the unit.

2.

If planning to pull back through the cement, do not use centralisers on the pipe and try to choose a stinger with minimal external upsets.

3.

The following diameters of stinger should be considered in the given hole sizes. Should washed out sections, ledging or high inclinations be a problem then it is better to opt for a larger stinger size: Hole Size

Stinger OD

6” to 8¾“

2 7/8”

9¼” to 12¼“

3½“

17½” and above

5 - 6 5/8”

4.

The length of the stinger is a balance between keeping it short to avoid the risk of buckling, but at the same time long enough to keep the top of cement below the crossover. Ideally, choose the stinger length to place the top of cement (with stinger in) right at the crossover.

5.

When running a cement stinger always use a diverter sub.

6.

The diverter sub should ideally have sufficient slots cut in it to give a cross sectional area of twice that of the stinger. Individual holes or slots should be cut no smaller than 3/8”.

7.

Whenever possible, use a barrier to prevent the cement slipping downhole. The Para-Bow has an established track record in the North Sea. When deploying this tool, follow the pump open instructions carefully. However do not get overly concerned if the resulting pump pressures do not exactly follow those quoted by the manufacturer.

8.

If no mechanical barrier is available, then the next best option is a reactive viscous pill. 10-15 ppb pre-hydrated gel mixed with barite to be 0.8 ppg or 0.1 sg above the mud weight and 5 g/bbl Sodium Silicate is the preferred mix.

9.

If no Sodium Silicate is available, then use a weighted viscous pill. Mix the pill to between the mud weight and the slurry density (closer to the cement slurry weight is preferred) and with a YP of more than 50.

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12.6.3 Mixing and Pumping the Slurry 1.

Make sure that all calculations are done by at least two people. It is not enough to simply check the calculations, all figures including the pipe and hole volumes are to be independently derived.

2.

As with all cementing calculations, it is important to calculate the potential worst case drop in bottom-hole pressure and make sure this will not lead to a well control problem.

3.

While circulating to balance and condition the mud, work the pipe and rotate to allow the diverter sub to jet the formation. Before rotating a stinger, make sure to check the allowable connection torque is sufficient. In difficult wells, limit rotation to when moving up the well and set the torque limiter to just above the free rotating torque.

4.

Sufficient spacer should be pumped ahead of the pill. Typical volumes would be 30 bbls in a 12¼” hole increasing to 50 bbls in a 17½” hole.

5.

Make sure that the spacer is compatible with the mud system and is capable of water wetting in oil based fluids.

12.6.4 Placement 1.

Correct placement is the key to a successful cement plug. All the Lab testing, the checking of the spacer compatibility and the use of density and rheology hierarchies will amount to nothing if we don't get the slurry in the right place.

2.

The most important part with getting the placement right is in knowing the exact capacity of the drill-string. Ignoring the effect of plastic coating on pipe will be exaggerated with depth and it is vital to know all such figures with confidence. The best way of establishing the exact pipe contents is to record the volumes used during liner displacements. The volume pumped to bump the dart should be recorded and then back calculated so that the actual drill pipe capacity is derived.

3.

Using flowrates to give an annular velocity of over 200 ft/min and so maintain turbulent flow also working and rotating the pipe at between 30 and 60 RPM and making the correct allowance for surface line volumes will all help in getting the placement right.

4.

For complex strings, software modelling is available to better calculate the required displacement volume. Under-displacing is always better than over-displacing as this leads to less contamination because the diverter sub will most likely reach the top of the cement in the annulus first. A rule of thumb which has been used successfully is to under-displace by a figure of:

page 206

Rev. 1, April 2010

BP North Sea SPU Drilling & Completions

Wellsite Leader’s Handbook

NSDC-00X-001.00U

Desired length of plug (ft) x (Drillpipe Cap. bbl/ft - Stinger Cap. bbl/ft) + ½ bbl 5.

Slow down the displacement over the last five barrels pumped so as to reduce the inertia of the fluid column.

12.6.5 POOH and Circulate 1.

With the cement now on depth it is important keep the thickening time in mind. The WSL should take a sample of slurry to the floor so that it can be checked for signs of setting while pulling out of the cement. Cement slurry should remain pumpable to 50 Bc but this figure should not be replied upon.

2.

As we have planned to underdisplace the cement, then expect the pipe to suck as the cement head is broken. If correctly positioned, then the pipe should pull dry.

3.

The slower the stinger is pulled from the cement, the less contamination will be seen. The recommended pulling rate is between 3 minutes and 5 minutes a stand. The higher the deviation, the slower the pipe should be pulled.

4.

While pulling back above the cement, check the tooljoints for cement rings. The pipe used to get above the cement should be racked separately and not used in subsequent drillstrings which contain MWDs or other sensitive drilling equipment.

5.

Pipe should be pulled two stands clear of the top of cement. Confirm circulation then drop a sponge ball to wipe the pipe. If a sponge ball is not available or if several plugs are to be set one on top of another, a 30 bbl pill containing Calcium Carbonate or some similar abrasive material can be used. Beware of the potential to plug the diverter sub with either a wiper dart or a sponge ball. Plug indicators are available for repeated plug setting.

6.

Rotate and move the string uphole while circulating clean. Have the Mud Engineer at the shakers and continuously test the returns for cement.

7.

After clearing out any contamination and if it is planned to stay in the hole while waiting on cement, then pull back to the safety of the shoe before continuing circulation.

8.

Plugs should not be tagged till they have developed a compressive strength of 500 psi. Similarly a kick-off plug should ideally reach 2000 psi compressive strength before being drilled on.

Rev. 1, April 2010

page 207

BP North Sea SPU Drilling & Completions

Wellsite Leader’s Handbook

NSDC-00X-001.00U

12.7 Example Cement Calculations for a Balanced Cement Plug Programme: 500 ft x 16 ppg Plug required. Cement yield = 1.49 ft3/sk. Mixwater to be fresh water, total fluid = 6.14 g/sk with 0.17 g/sk HR-4L. 2 7/8” Stinger below 5” Drillpipe. 20 bbl spacer ahead and equivalent to balance. Mud weight in hole is 10 ppg. Cement Volume: 500 ft Cement Plug to be set on bottom. 10,000' - 9,500'. 8½” Open Hole washed out to 9” average. 0.0787 bbl/ft x 500 = 39.3 bbl Plug. Slurry Mix: 39.3 bbls x 5.6146 = 220.7ft3 ÷ 1.49 ft3/sk = 148 sx. x 6.14 g/sk = 909 gall = 21.6 bbl Total Mix Fluid. 0.17 g/sk x 148 = 25.1 gall HR-4L. Top Cement with Stinger Out: 9500 ft Top Cement with Stinger In: The height of cement with the 2 7/8” Stinger inside the plug is 0.0707 bbl/ft + 0.00535 bbl/ft = 0.0761 bbl/ft = 13.14 ft/bbl x 39.3 bbls = 516 ft therefore the top of cement with the stinger in is 9,484 ft. Top Spacer with Stinger In: 20 bbl spacer in 9”-2 7/8” annulus = 20 ÷ 0.0707 bbl/ft = 283 ft. Therefore top spacer with stinger in is 9,484 ft - 283 ft = 9201 ft. Volume of Spacer to Balance: 283 ft x 0.00535 bbl/ft = 1.5 bbls. Displacement to Balance: Combined string volume = (9000 x 0.01776) + (201 x 0.00535) = 161 bbls to chase. Required Underdisplacement: Using the rule of thumb (see section 12.5.28 above): Plug length x (Pipe - Stinger capacity) + ½ bbl 500 ft x (0.01776 bbl/ft - 0.00535 bbl/ft) + ½ bbl = 6.7 bbls plus 2 bbls surface line volume = 8.7 bbls Total Underdisplacement. Worst Case Reduction in BHP: Worst case would be if the spacer needed to be circulated out, maximum drop in BHP (Straight Hole) 20 bbls ÷ 0.0489 bbl/ft = 409ft. Now (10 - 8.3) x 0.052 x 409 = 37 psi.

page 208

Rev. 1, April 2010

BP North Sea SPU Drilling & Completions

Wellsite Leader’s Handbook

NSDC-00X-001.00U

13. Appendices 13.1 Appendix A - Clair Drilling Practices Examples from Clair are attached on the following pages:

Rev. 1, April 2010

page 209

page 210

Break circulation with 20spm without inducing large pressure spike. Verify flow out prior to step 2 below Increase flow to drilling rate in 300gpm stages (minimum 30 sec/stage) At each stage, once stabilised, record & compare all data with trends. Gradually increase rotary to full drilling rate When specified rotation is obtained & stabilised, record & compare data with trends

Do not circulate the hole clean at depths where the BHA is adjacent to stringers, where previous circulations have been carried out, or in high DLS regions. Ensure the mud specifications are within the “Critical Mud Properties”. Pump rate is more crucial than rotary speed in this hole size Monitor trends in hook load, torque, ECD and ESD for indications of sub-optimal hole cleaning. If discrete cuttings are not seen at the shakers: the hole may not be cleaning up. After bottoms up, rack back a stand every 45min to 1 hour – continue to rotate (i.e. backream, review with DD prior to carrying this out, as in some instances we may opt NOT to rotate to protect the tools) and circulate at drilling rate (note that normal tripping indicators will be masked and avoid unnecessary delays at connections). Circulate hole clean. When the bit enters the Cretaceous pressure cavings may be observed. Should these be observed circulate 4 x bottoms up in the Cretaceous prior to POOH then pull above Cretaceous and circulate until shakers are clean.

1.

7.

5. 6.

2. 3. 4.

2.

•

•

1.

As required (rack back 1 stand/hr)

Pumps should be dressed with 6.5” liners Don’t cut back flow rate unless a stringer is encountered (or direction being compromised) Maintain steady ROP & control instantaneous drilling rate, to avoid overloading annulus & CRI Don’t reduce the Flow Rate or RPM in an attempt to maintain ECD level below the Alarm Level. Ensure current operational parameters are communicated across handover time – use a handover procedure Can use Cyberbase auto-WOB through fast drilling sections, but ensure Cyberbase is set to auto-ROP when drilling stringers to mitigate stabiliser jamming/surging formation when through stringer

One BU plus pump 50 bbl hi vis pill. Rack back 1 stand/hr (45 min)

• • • •

Bottoms up before trip

ECD

Ensure CRI is not overloaded when in operation

10-30 klbs (dependent on max for bit in hole)

Avoid stopping drilling to clean up the hole, reduce ROP (if possible) whilst maintaining directional control

WOB

150rpm (90rpm max AutoTrak off bottom)

Max allowed by liners / tools (~1200gpm)

ROP

90rpm

MAXIMUM

Stop rotation Record string weights Slowly stop pumps over 30 secs Make connection

[* Wiped distance at BP Wellsite Leader’s discretion to be determined via Pres-Tek monitored ECD, ESD and hook load trends.]

6. 7. 8.

5.

4.

1. 2. 3.

5.

4.

1. 2. 3.

Circulate one bottoms-up or until shakers are clean before tripping out-of-hole Commence trip out-of-hole. If overpull encountered: work up to 25 klbs overpull limit in stages, checking that the pipe is free each time 25 klbs overpull is reached. If consistent 25 k overpull, or the overpull is trending up: run down well clear of resistance (guide – distance between bit and top stabiliser). Break circulation slowly (as per “Break Circulation” procedures) and build up to drilling flow rate. Stage rotary up to 140 rpm. Circulate to clean hole before attempting to pull through tight spot. Continue to trip out of hole, if unable to progress go to level 2 responses.

React to stringers immediately; do not allow large WOB increase. Slowly reduce rotation, monitoring for vibration. Slowly reduce flowrate. Drill on stringer by slowly increasing WOB desired There is a high risk of a pressure spike when breaking through stringers with High WOB. Record stringer depths on the Driller’s Log. Whilst drilling softer formation Cyberbase auto-WOB can be used, however set Cyberbase to auto-ROP function when drilling stringers to prevent instantaneous high ROPs once through the stringer When through the stringer, return to base-line drilling parameters, pumps first then rotary.

If more than 15k increase in string weight trends: 1. Drill stand down using “Drilling Parameters” 2. Continue to circulate & rotate (e.g. 5-10 mins) to clear any cuttings from around the BHA Maintain circulation & rotation at drilling rate 3. Slowly stop rotation 4. Wipe up full stand and ream down full stand faster than drilled ROP (x 2) 5. Check string weights 6. If increased string weight reduced to normal then make connection as above, otherwise: 7. Wash back to top of stand at full drilling rate no faster than 5 m/min 8. Ream down full stand to connection height no faster than 5 m/min 9. Slowly reduce flow rate to zero over 30 seconds 10. Make connection (take gyro survey before connection and MWD survey after) 11. Following connection: bring pumps up to 300gpm (verify flow out). Commence rotating at 30 rpm. 12. Bring the pumps up to drilling rate, then bring up the rotary to drilling rate. 13. Monitor and record ECD/ESD/torque/pressure/flow levels throughout.

14th April 2009

The “25k Rule”

Tripping ProceduresNegotiating Tight Spots

*Only if lasting 5+minutes

Drilling Limestone Stringers

Buttons

Stop/Resume

Do NOT use the

Connection Procedures

4. 5. 6. 7.

If no increase in string weight trends: 1. Drill stand down using “Drilling Parameters” 2. Slowly stop rotation over 30 secs 3. Wipe up full stand* and ream down full stand faster than (2 x drilled ROP)

Wellsite Leader’s Handbook

*Recommended Minimum of 4 Bottoms Up

Circulating to Clean the Hole

*NOT Applicable to Connections e.g. after wiper trips Or after mud has been stationary

Break Circulation Procedures

Comments

Drilling Parameters

800gpm

Rotary

MINIMUM

Flow Rate

PARAMETERS

Clair Drilling Practices: Tertiary 17-1/2” Section

BP North Sea SPU Drilling & Completions

NSDC-00X-001.00U

13.1.1 17½” Section Drilling Practices

Rev. 1, April 2010

Rev. 1, April 2010

Stuckpipe Procedures

Pack-off Procedures

4.

2. 3.

1.

7.

6.

5.

4.

3.

2.

1.

Use jarring decision tree to determine appropriate jarring response depending on block height Use Jar Calculation Procedures to calculate required cocking and jarring weights In the event of stuckpipe while tripping out, jar down. Do not jar up until repeated down jarring has had no affect If no jarring action is observed, check jarring calculations to ensure enough time (up to 3 mins) and correct weights have been applied before moving to up jarring Do not work torque into drillstring and jar down. It doesn’t work and it can cause the drillpipe to snap In the event of stuckpipe while tripping in, jar up. Do not jar down until repeated up jarring has had no effect If no jarring action is observed, check jarring calculations to ensure enough time (up to 3 mins) and correct weights have been applied before moving to down jarring

In the event of a pack-off – stop the pumps immediately and bleed off standpipe pressure to zero in a controlled manner to prevent blocking the nozzles. Attempt to move in opposite direction to that when pack-off occurred. Beware of risk of blocking nozzles without circulation or rotation Remain clear of section TD Establish or reduce drillstring rotation to 20 rpm. Beware frictional heating risk – do not rotate at high rpm’s without circulation Attempt to break circulation with 20 spm or hold 200 psi on the drillstring Confirm flow out prior to next step. If can’t regain Circulation return to step 2 above and/or consider trying to break circulation without rotation Increase flow rate to 1100 gpm Stage up as per “Break Circulation” procedures but proceed cautiously and use more steps to stage up e.g. 15 At each level ensure no pressure spikes before proceeding to next stage up Increase surface rotary in stages to 80 rpm Do not reciprocate until previous circulating rate achieved (Note: High risk of pack-off again at this stage). Having re-established circulation, stage up to drilling parameters without reciprocating and circulate to clean hole.

-unable to trip without rotation

Tripping Procedures

What does a clean 17.1/2” hole look like?

Irreducible trend, continued cavings

Circulating to Clean the Hole

e.g. Pumps failed, TDU failed

Equipment Failure Procedures

6.

5.

3. 4.

2.

1.

1. 2.

3. 4.

2.

1.

Clair Drilling Practices: Tertiary 17-1/2” Section Level 2 responses

Unable to trip without rotation and overpulls have not responded to “Negotiating Tight Spots” Run down well clear of resistance (expect a couple of stands) to establish baseline for coming back up again Break circulation slowly (“Break Circulation” procedures) & build up to drilling flow rate. Go to neutral wt and start rotating, building up to 140 rpm but not exceeding make up torque of topdrive saver sub (37 kftlbs) Work back up slowly through the restriction with full flow rate (if possible) and minimum rpm Repeat steps 3-5 until clear of resistance (may have to continue until the shoe is reached)

Assumption Minimum of one BU circulated Flow rate 1100 gpm RPM 120-140 Not drilling Indicators Mud weight in equals mud weight out Shakers clean No cuttings slugging observed over last 2 BUs

Perform a further bottoms up continuing to rack a stand every 1 hour If trends not reducing after a further four bottoms up, inform Drill Rep.

If one pump failed, pull back off bottom, circulate with remaining pump at max flowrate with reduced rotation (20rpm) for 10minutes (until BHA clear). Pull back to top of stand, stop rotation and reduce flow to 200gpm. Periodically (15mins) move pipe down by 1m to ensure that drags not increasing If two pumps failed, do the same as 1 and 2 above, but using cement unit to pump If TDU failed, do the same as 1 and 2 above, but without rotation

BP North Sea SPU Drilling & Completions

Wellsite Leader’s Handbook NSDC-00X-001.00U

page 211

page 212

120 ft

Top Drive Position

80 ft

Zone A

Zone B

20 ft

Jarring Up or Down Us the Jarring Force formula to get a good estimate of the hook loads needed to get the jars to work. Remember Pump open force makes it harder to close the jars (ie fire down or recock from firing up). Jarring up with torque in the string is not recommended. Any jarring with torquer in the string will increase Jar internal friction and make it harder for the jar to operate.

Stretch in Feet

Zone C

0.00

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

9.00

5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 Free String Length 17000 18000

10k

30k

90k

Overpull

70k 50k

Typical String Stretch

Wellsite Leader’s Handbook

0 ft

Pull & Torque Jar Up

Jar up Jar Down

Pull & Torque Slump & Torque

Pull & Torque

Slump & Torque When applying pull and Torque it is important to stay within the limits of the strength of the string. Tensile Rating is reduced when applied at the same time as torque. The following graph is for 5 7/8” pipe.

Slump & Torque Work 75% MUT into the string by working between Normal up weight + 10k lbf and Down weight – 10k lbf for the string at the stuck depth. Once the torque holds in, slump the string to the maximum allowable slack off weight repeatedly. Not a problem if the Jars go off – but could indicate the torque is not getting to bottom as jars are more difficult to fire with applied torque.

Stuck after being stationary. Stuck in an area with permeable formations Full and unrestricted circulation with no pressure spikes Possibly already had signs of overpull after connections

Identify and Confirm Differential Sticking

Procedures – Single String

Options

ID and Confirm Diff Sticking Then initially use the options below

Differential Sticking Tree

BP North Sea SPU Drilling & Completions

NSDC-00X-001.00U

Rev. 1, April 2010

Rev. 1, April 2010

*Recommended Minimum of 1 Bottoms Up

150rpm

7.

5. 6.

2. 3. 4.

1.

2.

1.

7.

6.

5.

4.

1. 2. 3.

As many as required

Do not circulate the hole clean at depths where the BHA components (eg stabilisers) are adjacent to stringers or where previous circulations were carried out Max. 150 rpm is the limit of the AutoTrak/MWD assembly Monitor for vibration and slip/stick Monitor Hook Load trends, torque, shakers, ECD and ESD for indications of sub-optimal hole cleaning Monitor ECD levels to minimize Swab & Surge effects while cleaning the hole After the first bottoms up, rack back a stand every 30mins – continuing to rotate (i.e. backream). Do not work or ream a stand down unless resistance is observed. Circulate at drilling rate (note that normal tripping indicators will be masked and avoid unnecessary delays at connections). Circulate until hole clean. Perform minimum of one bottoms up inside the shoe, should be performed at WSL discretion.

Break circulation with 20 spm without inducing large pressure spike Verify flow out Increase flow to drilling rate in 100 gpm stages (minimum 30 sec/stage) At each stage, once stabilised, record & compare all data with trends. Stage up rotation to 80 rpm, hold for 2 minutes, then stage up to drilling rate or cleaning rate (Note: This is most likely pack-off point) When specified rotation is obtained & stabilised, record & compare data with trends.

Be alert for Early Warning Indicators and take action to prevent worsening of conditions Accurately record & report MW every 15mins When trends indicate unacceptable ECD/ESD increases, reduce ROP to half the Drilling ROP until favourable trends resume. If no improvement is seen after 2 stands then drilling should cease & the well circulated to clean the hole. Do not reduce the Drilling Flow Rate or RPM in an attempt to maintain ECD level below the Alarm Level. Maintain steady ROP & control instantaneous drilling rate, to avoid overloading annulus & CRI. Monitor surface Slip-Stick & downhole vibration and modify the surface rotary within the defined operating window accordingly especially at changes of rpm. Attempt to increase rotary speed in the first instance. Ensure current operational parameters are communicated across handover time – use a handover procedure

1

Look for increasing trend on connections compared to mud weight

ESD (effective static density)

Bottoms up before trip

Ensure ECD Alarm is set to 0.02 sg above the expected trend line value

10-22 OR 26-30klbs (beware of running jar in neutral point)

Refer to ROP vs Flow chart for allowable ROP for a given flow rate but evidence from ESD trends should supersede modelled values NOTE: MaxROP for CRI processing cuttings 4 >0m/hr

Optimum RPM: 140 for Drilling Ahead / 120 for Hole Cleaning NOTE: 90RPM will only be used in special circumstances noted below

110rpm (90rpm see below)

MAXIMUM 1090gpm (BCPM limited)

ECD

WOB

ROP

MINIMUM

605gpm (BCPM limited)

6. 7.

5.

4.

1. 2. 3.

4.

3.

1. 2.

10. 11. 12. 13.

7. 8. 9.

6.

Circulate minimum of one bottoms up before tripping out of hole or until hole clean Commence trip out of hole If overpull encountered: work up to 25 k overpull limit in stages, checking that the pipe is free each time we reach 25 k overpull If consistent 25 k overpull– run down well clear of resistance (guide – distance between bit and top stabilizer) Break circulation slowly (“Break Circulation” procedures) & build up to drilling flow rate then bring rotary up to 120 rpm Circulate to clean hole and reciprocate pipe before attempting to pull through tight spot. Continue to trip out of hole, if unable to progress go to level 2 responses.

Slowly reduce flowrate to 900 gpm. Note: This is a special case GPM only Slowly reduce rotation to 90 rpm Note: This is a special case RPM only – monitor for vibration, particularly slip/stick Time drill on stringer by slowly increasing WOB to a max of 24klbs There is a high risk of a pressure spike when breaking through stringers with high WOB. Use Cyberbase auto-ROP function for drilling stringers Record stringer depths on the Driller’s Log When through the stringer, return to base-line drilling parameters, pumps first then rotary and monitor

Drill stand down using “Drilling Parameters”. Pick up slowly to 1-2m off bottom with drilling parameters, do this before allowing weight to completely drill off ( i.e. with 5-10k WOB remaining) Allow 2-3 minutes to clear any cuttings from around the BHA Stop rotation Wash up enough to confirm up weight: If overpulls are noted, do not make connection. Wash or Ream the Stand or Single as required: Minimum Wiped distance at BP Wellsite Leader’s discretion. ECD, ESD and hook load trends to be monitored. Wash down to connection height, recording down weight. Reduce flowrate to zero over 30 seconds. Set slips (minimising pipe movement to avoid masking ESD) and make connection (survey taken over connection). Monitor volume flow back to identify any wellbore breathing. Stage the pumps up to drilling rate in increments, then stage up the rotary to drilling rate Monitor and record ECD/ESD/torque/pressure/flow levels throughout. Drill ahead.

1st

March 2010

NOTE: DEVIATION FROM THESE PRACTICES MUST HAVE PRIOR APPROVAL FROM THE BP WELLSITE LEADER

The “25k Rule”

Tripping ProceduresNegotiating Tight Spots

*Only if lasting 5+minutes

Drilling Limestone Stringers

Buttons

Stop/Resume

Do NOT use the

Connection Procedures

3. 4. 5.

1. 2.

Wellsite Leader’s Handbook

Circulating to Clean the Hole

after wiper trips or after mud has been Stationary *NOT Applicable to Connections

Break Circulation Procedures

Comments

Drilling Parameters

Rotary

Flow Rate (D/L @7 25gpm)

PARAMETERS

Clair Drilling Practices – Cretaceous 12-¼” Section

BP North Sea SPU Drilling & Completions

NSDC-00X-001.00U

13.1.2 12¼” Section Drilling Practices

page 213

page 214

Stuckpipe Procedures

Pack-off Procedures

4.

2. 3.

1.

7.

6.

5.

4.

3.

2.

1.

Use jarring decision tree to determine appropriate jarring response depending on block height Use Jar Calculation Procedures to calculate required cocking and jarring weights In the event of stuckpipe while tripping out, jar down! Do not jar up unless as a last resort or until instructed by WSL, repeated down jarring has had no affect (this is expected to be multiple hours rather than minutes) If no jarring action is observed, check jarring calculations to ensure enough time and correct weights have been applied before moving to up jarring Do not work torque into drillstring and jar down. It doesn’t work and it can cause the drillpipe to snap In the event of stuckpipe while tripping in, jar up! Do not jar down unless as a last resort or until instructed by WSL, repeated up jarring and straight pulling has had no effect (this is expected to be multiple hours rather than minutes) If no jarring action is observed, check jarring calculations to ensure enough time and correct weights have been applied before moving to down jarring

In the event of a pack-off – stop the pumps immediately and bleed off standpipe pressure to zero in a controlled manner to prevent blocking the nozzles. Attempt to move in opposite direction to that when pack-off occurred. Beware of risk of blocking nozzles without circulation or rotation Remain clear of section TD Establish or reduce drillstring rotation to 20 rpm. Beware frictional heating risk – do not rotate at high rpm’s without circulation Attempt to break circulation with 20 spm or hold 200psi on the drillstring Confirm flow out prior to next step. If can’t regain Circulation (do NOT exceed LOT in first instance) return to step 2 above and/or consider trying to break circulation without rotation Increase flow rate to 1000 gpm (minimum) Stage up as per “Break Circulation” procedures but proceed cautiously and use more steps to stage up At each level ensure no pressure spikes before proceeding to next stage up Increase surface rotary in stages to 90 rpm Do not reciprocate until previous circulating rate achieved (Note: High risk of pack-off again at this stage). Having re-established circulation, stage up to drilling parameters without reciprocating and circulate to clean hole..

-unable to trip without rotation

Tripping Procedures

What does a clean 12-1/4” hole look like?

e.g. Pumps fail, TDU fails

Equipment Failure Procedures

6.

5.

3. 4.

2.

1.

3. 4.

2.

1.

Unable to trip without rotation and overpulls have not responded to “Negotiating Tight Spots” Run down well clear of resistance (expect a couple of stands) to establish baseline for coming back up again Break circulation slowly (“Break Circulation” procedures) & build up to drilling flow rate. Go to neutral Wt and start rotating, building up to 120 rpm but not exceeding make up torque of 5 7/8” VX 57 Drill Pipe (42.4kftlbs) Work back up slowly through the restriction with full flow rate (if possible) and minimum rpm Repeat steps 3-5 until clear of resistance (may have to continue until the shoe is reached)

Assumption Minimum of one BU circulated Minimum flow rate 1000 gpm RPM 120-140 Not drilling Indicators ESD equals Mud weight Mud weight in equals mud weight out Shakers clean No cuttings slugging observed over last B/U

If one pump fails, pull back off bottom, circulate with remaining pump at max flowrate with reduced rotation (20rpm) for 10 minutes (until BHA clear). Pull back to top of stand, stop rotation and reduce flow to 200 gpm. Periodically (15mins) move pipe down by 1m to ensure that drags not increasing OR if in the Cretaceous rotate at 20rpm to avoid differential sticking If two pumps fail, do the same as 1 and 2 above, but using cement unit to pump If TDU fails, do the same as 1 and 2 above, but without rotation

Clair Drilling Practices – 12-¼” Cretaceous Section Level 2 Responses

BP North Sea SPU Drilling & Completions

Wellsite Leader’s Handbook NSDC-00X-001.00U

Rev. 1, April 2010

Rev. 1, April 2010

*Recommended Minimum of 4-5 Bottoms Up

Do not circulate the hole clean at depths where the BHA components (eg stabilisers) are adjacent to stringers or where previous circulations were carried out . Ensure the mud specifications are within the “Critical Mud properties” . Max. 150 rpm is the limit of the AutoTrak/MWD assembly complete with nuclear sources. Monitor for vibration and slip/stick. Monitor Hook Load trends, torque, ECD and ESD for indications of sub-optimal hole cleaning. Monitor ECD levels to minimize Swab & Surge effects while cleaning the hole. After the first bottoms up, rack back a stand every 45mins to 1 hr – continuing to rotate (i.e. backream, review with DD prior to carrying this out, as in some instances we may opt NOT to rotate to protect the tools) and circulate at drilling rate (note that normal tripping indicators will be masked and avoid unnecessary delays at connections). Circulate until hole clean. Perform minimum 2x bottoms up at shoe, continue to circulate at shoe if required. If solids not reducing at shakers, and cavings are observed, go to Level 2 responses

1.

7. 8.

4. 5. 6.

2. 3.

2.

Break circulation with 20spm without inducing large pressure spike (Note: For use in avalanche zone) Verify flow out prior to step 2 below Increase flow to drilling rate in 100gpm stages (minimum 30 sec/stage) At each stage, once stabilised, record & compare all data with trends. Logging unit to confirm PWD reading is as expected as per fingerprinting. Stage up rotation to 80rpm, hold for 2 minutes, then stage up to drilling rate (Note: This is most likely pack-off point) When specified rotation is obtained & stabilised, record & compare data with trends.

Be alert for early warning indicators and take action to prevent worsening of conditions Maintain good communication with shaker hand and Logging Engineers Monitor surface slip-stick and downhole vibration: modify the surface rotary within the defined operating window accordingly. Pay particular attention at changes of rpm. Attempt to increase rotary speed in the first instance Maintain steady ROP and control instantaneous drilling rate, to avoid overloading annulus and CRI operations. When trends indicate unacceptable ECD/ESD increases, reduce ROP to ½ drilling ROP until favourable trends resume. If no improvement is seen after 2 stands then drilling should cease and the well circulated to clean hole Do not reduce flow rate or rpm in an attempt to maintain ECD level below the alarm level Try and keep the same people in the shakers for the whole shift for consistency Ensure current operational parameters are communicated across handover time: use a handover procedure Monitor up and down weights every 5 stands: if found to diverge, wash/ream full stand until hole clean

As many as required

1.

6. 7. 8. 9.

4. 5.

1. 2. 3.

4-5

Look for increasing trend on connections compared to mud weight

Bottoms up before trip

Ensure ECD Alarm is set to 0.02sg above the expected trend line value

ESD (effective static density)

8-21klbs

WOB

150rpm 200rpm

600gpm

MAXIMUM

ECD

up to 30 m/hr

ROP

60rpm (shoetrack) 150rpm

450gpm

MINIMUM

The “15k Rule”

Tripping ProceduresNegotiating Tight Spots

*Only if lasting 5+minutes

Drilling Stringers

Buttons

Stop/Resume

Do NOT use the

Connection Procedures

React to stringers immediately and prevent large WOB increase. Minimise change of drilling parameters to prevent damage to Reservoir higher in the hole from altered drillstring behavior. Slowly reduce rotation, monitor for vibration and slip/stick. Time drill on stringer by slowly increasing WOB to 25 lKbs and allow WOB to drill-off. There is a high risk of a pressure spike when breaking through stringers with high WOB: use Cyberbase auto-ROP function when drilling stringers. Record stringer depths on the Driller’s Log. When through the stringer, return to previous base-line drilling parameters.

Drill stand down using “Drilling Parameters” Pick up slowly to 1-2m off bottom with drilling parameters, do this before allowing weight to completely drill off to ( i.e. with 5-10k WOB remaining) Allow 2-3 minutes to clear any cuttings from around the BHA Stop rotation Wash up enough to confirm up weight If overpulls are noted, do not make connection. Wash OR Ream the Stand OR Single as required. Wash down to connection height, recording down weight Reduce flowrate to zero over 30 seconds Set slips (minimising pipe movement to avoid masking ESD) and make connection (survey taken over connection) Monitor volume flow back to identify any wellbore breathing Stage the pumps up to drilling rate in 300 gpm increments, then stage up the rotary to drilling rate Monitor and record ECD/ESD/torque/pressure/flow levels throughout Drill ahead

7th July 200 9

1. Circulate minimum 4 bottoms up before tripping out of hole or until hole clean 2. Commence trip out of hole. If problems occur, they should generally be expected in the first 10 stands tripped. 3. If overpull encountered: work up to 15 k overpull limit in stages, checking that the pipe is free each time 15 klbs overpull is reached. 4. If consistent 15 klbs overpull, or the overpull is trending up: run down well clear of resistance (guide – distance between bit and top stabilizer). 5. Break circulation slowly (as per “Break Circulation” procedures) and build up to 550 gpm; then bring rotary up to 140 rpm. In OH: a second pass at 550 gpm can be attempted: to back ream. 6. Circulate to clean hole before attempting to pull through tight spot. 7. Continue to trip out of hole, if unable to progress go to level 2 responses.

4.

2. 3.

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11. 12.

9. 10.

6. 7. 8.

3. 4. 5.

1. 2.

Wellsite Leader’s Handbook

Circulating to Clean the Hole

*NOT Applicable to Connections e.g. after wiper trips or after mud has been stationary

Break Circulation Procedures

Comments

Drilling Parameters

Surface Rotary RPM Motor

Flow Rate

PARAMETERS

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Stuckpipe Procedures

Pack-off Procedures

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Use jarring decision tree to determine appropriate jarring response depending on block height Use Jar Calculation Procedures to calculate required cocking and jarring weights In the event of stuckpipe while tripping out, jar down. Do not jar up until repeated down jarring has had no affect
If no jarring action is observed, check jarring calculations to ensure enough time (up to 3 mins) and correct weights have been applied before moving to up jarring
Do not work torque into drillstring and jar down. It doesn’t work and it can cause the drillpipe to snap In the event of stuckpipe while tripping in, jar up. Do not jar down until repeated up jarring has had no effect
If no jarring action is observed, check jarring calculations to ensure enough time (up to 3 mins) and correct weights have been applied before moving to down jarring

In the event of a pack-off – stop the pumps immediately and bleed off standpipe pressure to zero in a controlled manner to prevent blocking the nozzles. Attempt to move in opposite direction to that when pack-off occurred.
Beware of risk of blocking nozzles without circulation or rotation
Remain clear of section TD Establish or reduce drillstring rotation to 20 rpm.
Beware frictional heating risk – do not rotate at high rpm’s without circulation Attempt to break circulation with 20 spm or hold 200psi on the drillstring
Confirm flow out prior to next step.
If can’t regain Circulation (do NOT exceed LOT in first instance) return to step 2 above and/or consider trying to break circulation without rotation Increase flow rate to 550 gpm (minimum)
Stage up as per “Break Circulation” procedures but proceed cautiously and use more steps to stage up e.g. 15
At each level ensure no pressure spikes before proceeding to next stage up Increase surface rotary in stages to 80 rpm
Do not reciprocate until previous circulating rate achieved (Note: High risk of pack-off again at this stage). Having re-established circulation, stage up to drilling parameters without reciprocating and circulate to clean hole.

-unable to trip without rotation

Tripping Procedures

What does a clean 81 /2” hole look like?

Irreducible trend, continued cavings

Circulating to Clean the Hole

e.g. Pumps failed, TDU failed

Equipment Failure Procedures

Clair Drilling Practices: 8-1/2" Section Level 2 Responses

6.

5.

3. 4.

2.

1.

2.

1.

3.

1. 2.

Unable to trip without rotation and overpulls have not responded to “Negotiating Tight Spots” Run down well clear of resistance (expect a couple of stands) to establish baseline for coming back up again Break circulation slowly (“Break Circulation” procedures) & build up to drilling flow rate. Go to neutral Wt and start rotating, building up to 140rpm but not exceeding make up torque of topdrive saver sub (37kftlbs) Work back up slowly through the restriction with full flow rate (if possible) and minimum rpm Repeat steps 3-5 until clear of resistance (may have to continue until the shoe is reached)

Assumption
Minimum 4-5 BU circulated
Minimum flow rate 400gpm
RPM 140
Not drilling Indicators
ESD equals Mud weight
Mud weight in equals mud weight out
Shakers clean
No cuttings slugging observed over last 2 BU’s

Increase bottoms up to minimum of 8 and increase flow rate if possible. Ensure rotary is minimum of 140rpm, monitoring for vibration/slip-stick. Continue racking a stand every hour If trends not reducing after 10 bottoms up, inform Drill Rep.

If one pump fails continue to drill ahead on 1 pump. (400 gpm required to clean the hole.) If two pumps fail: slowly pull back to top of stand, stop rotation and circulate at 200gpm using the cement unit. Periodically (15mins) move pipe down by 1m to ensure that drags not increasing OR if the BHA is across any sand interval rotate at 20 rpm to avoid differential sticking. If TDU failed, do the same as 2 above, but without rotation.

BP North Sea SPU Drilling & Completions

Wellsite Leader’s Handbook NSDC-00X-001.00U

Rev. 1, April 2010

BP North Sea SPU Drilling & Completions

Wellsite Leader’s Handbook

NSDC-00X-001.00U

13.2 Appendix B - Examples of Casing Tallies 13.2.1 Example Casing Tally from Mungo: 9 7/8” - 9 5/8”

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13.2.2 Example Liner Tally from Mungo: 4½”

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13.2.3 Example Semi-Sub Casing Tally from Foinaven: 13 3/8”

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14. Reference Documents and Links BP D&C Knowledge Library - containing ETPs, Guidance Documents, etc. https://epti.bpglobal.com/DandC/default.aspx

New BP Drilling Operations Guidelines, DOGS (EUR-D-001) http://dwo.bpweb.bp.com/documents/EUR-D-001/default.htm

Old BP Drilling Operations Guidelines http://northsea.bpweb.bp.com/ask/pw/weo_w06/0120-g1.pdf

North Sea Rig Operations Guidelines and Group Recommended Practices http://northsea.bpweb.bp.com/SPU/ourorganisation/ourunitsandteams/drillingandcompletions/whatwedo/knowledgecentre/rigopsguidelinesgrps.aspx

BP Well Control Manual http://dwo.bpweb.bp.com/documents/BPA-D-002V1

BP Stuck Pipe Manual (1997) https://epti.bpglobal.com/C11/C6/Stuck%20Pipe/Document%20Library/Manuals/Stuckpipe %201997%20BP%20Manual.DOC

Wellbore Stability (WS) https://epti.bpglobal.com/C5/C6/Wellbore%20Stability/default.aspx

20 WS Commandments: http://northsea.bpweb.bp.com/dwo/documents/TS-D-009/TS-D-009_bodyParas.htm#para5

Sidetracking Guidance https://epti.bpglobal.com/C8/C6/Sidetracking/default.aspx

Leak-Off Testing (e.g. Clair Drillers Instructions for the 13 3/8” Leak-Off Test):

Loss Circulation Manual http://northsea.bpweb.bp.com/dwo/documents/TS-D-010/default.htm

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BP Drilling and Well Operations Practice (DWOP) https://epti.bpglobal.com/C17/C4/GlobalDocLib/Document%20Library/NEW%20DWOP% 20REV%206.pdf

Clair Drilling Practices http://ukcpol.bpweb.bp.com/livelink/llisapi.dll?func=ll&objId=16579799&objAction=brows e&sort=name&viewType=1

Clair Drillers Instructions (2Q 2008) http://uk-cpol.bpweb.bp.com/livelink/llisapi.dll/open/13571798?Redirect=1

Environmental Group Defined Practice (OMS) GDP 3.6-0001 https://wss2.bp.com/HSSE/Central_HSSE/OMS_library/OMS%20Library/Environment%2 0for%20Access,%20Major%20Projects,%20Non%20Major%20Projects%20in%20Sensi tive%20Areas%20and%20Acquisition%20Activities%20GDP%203.6-0001.pdf

Drilling Contracting Standards (EUR-D-003) http://dwo.bpweb.bp.com/documents/EUR-D-003/default.htm

UK Regional Safety Management System (SMS) http://uksms.bpweb.bp.com/SMS_Live/index.cfm

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SIS 111778580