77072452 eni completion procedures manual

ARPO

ENI S.p.A.Agip Division

ORGANISINGDEPARTMENT

TYPE OFACTIVITY'

ISSUINGDEPT.

DOC.TYPE

REFER TOSECTION N.

PAGE. 1

OF 192

STAP P 1 M 7120

The present document is CONFIDENTIAL and it is property of AGIP It shall not be shown to third parties nor shall it be used forreasons different from those owing to which it was given

TITLE

COMPLETION PROCEDURES MANUAL

DISTRIBUTION LIST

Eni - Agip Division Italian Districts

Eni - Agip Division Affiliated Companies

Eni - Agip Division Headquarter Drilling & Completion Units

STAP Archive

Eni - Agip Division Headquarter Subsurface Geology Units

Eni - Agip Division Headquarter Reservoir Units

Eni - Agip Division Headquarter Coordination Units for Italian Activities

Eni - Agip Division Headquarter Coordination Units for Foreign Activities

NOTE: The present document is available in Eni Agip Intranet (http://wwwarpo.in.agip.it) and aCD-Rom version can also be distributed (requests will be addressed to STAP Dept. inEni - Agip Division Headquarter)

Date of issue:

Issued by M. Bassanini C. Lanzetta A. Galletta28/06/99 28/06/99 28/06/99

REVISIONS PREP'D CHK'D APPR'D

28/06/99

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IDENTIFICATION CODE PAGE 2 OF 192

REVISIONSTAP -P-1-M-7120 0

INDEX

1. INTRODUCTION 9

1.1. PURPOSE OF THE MANUAL 9

1.2. IMPLEMENTATION 9

1.3. UPDATING, AMENDMENT, CONTROL & DEROGATION 9

2. RESPONSIBILITIES 10

2.1. DRILLING COMPLETION AND WORKOVER MANAGER 10

2.2. WELL OPERATIONS SUPERINTENDENT 11

2.3. COMPLETION AND WORKOVER ENGINEER 11

2.4. FLUIDS SPECIALIST 12

2.5. OFFSHORE INSTALLATION MANAGER (OIM) 13

2.6. WELL OPERATIONS SUPERVISOR 13

2.7. PRODUCTION SUPERVISOR 14

3. DOCUMENTATION 15

3.1. PRELIMINARY INFORMATION 15

3.2. WELLSITE REPORTS 15

3.3. FEED BACK REPORTS 15

3.4. OTHER REPORTS 16

3.5. PERMIT PROCEDURES 163.5.1. Guidance For Permits 16

3.6. WELL HANDOVER PROCEDURES 173.6.1. Well Handover Certificate 173.6.2. Well Intervention Handover Certificate 18

4. HOLE PREPARATIONS 23

4.1. PRELIMINARY CHECKS 23

4.2. WELL CLEAN UP PROCEDURES 23

4.3. BOP STACK CONFIGURATION AND TESTING 24

4.4. WELL CONTROL 24

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4.5. OIL BASED MUD DISPLACEMENT 244.5.1. Displacement Objectives 244.5.2. Logistical Considerations 254.5.3. Drilling Fluid Preparation 254.5.4. Surface Equipment Preparation 264.5.5. Well Clean Up Pill Sequence 264.5.6. Pill Functions 274.5.7. Pit Requirements 274.5.8. Pumping Sequence 27

4.6. DISPLACEMENT OF WATER BASED MUDS 284.6.1. Drilling Fluid Preparation 284.6.2. Surface Equipment Preparation 284.6.3. Well Clean Up Pill Sequence 284.6.4. Pill Functions 294.6.5. Pit Requirements 294.6.6. Pumping Sequence 29

4.7. COMPLETION AND WORKOVER FLUIDS 294.7.1. Brines Transportation 294.7.2. Completion And Workover Fluid Quality 30

4.8. FILTRATION SYSTEMS 304.8.1. Fluid Cleanliness 30

4.9. LOST CIRCULATION 314.9.1. Viscous Pills 314.9.2. Sized Salt Pills 314.9.3. Calcium Carbonate Pills 32

4.10. CASING GAUGE CONTROL 33

5. PERFORATING PROCEDURES 34

5.1. GENERAL 34

5.2. METHODS OF PERFORATING 35

5.3. GENERAL SAFETY PROCEDURES 35

5.4. WIRELINE CONVEYED PERFORATING 375.4.1. Casing Guns Run In Overbalance 375.4.2. Perforating Procedures For Through Tubing Conveyed Guns 38

5.5. SAFE SYSTEM 395.5.1. SAFE System Description (Slapper Activated Firing Explosives) 40

5.6. TCP PROCEDURES 405.6.1. Well Preparation for TCP Operations 415.6.2. Ancillary TCP Equipment 415.6.3. Firing Systems for TCP Operations 435.6.4. General TCP Safety Precautions and Running Procedures 445.6.5. Firing Procedure for Tubing Installed Pressure Activated Head 455.6.6. Firing Procedure for Wireline Installed Pressure Activated Head 455.6.7. Firing Procedure for Mechanical Impact Activated Head 455.6.8. Firing Procedure for Electrically Activated TCP Guns 465.6.9. Procedure For TCP Anchor Running 475.6.10. TCP Anchor Firing Head Installation 48

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5.7. MISFIRE PROCEDURES 515.7.1. Mechanical Firing Head 515.7.2. Hydraulic Firing Head 525.7.3. Fixed Hydraulic Firing Head 535.7.4. Retrievable Hydraulic Firing Head 53

5.8. COILED TUBING PERFORATING 53

6. GRAVEL PACKING PROCEDURES 54

6.1. GRAVEL PLACEMENT OBJECTIVES 54

6.2. SCREEN SIZE 54

6.3. GRAVEL CALCULATIONS 556.3.1. Sand Volume Required 556.3.2. Carrier Fluid Volume 56

6.4. COMMON GRAVEL PACK PROCEDURES 56

6.5. OPEN HOLE GRAVEL PACK PROCEDURE 57

6.6. CASED HOLE GRAVEL PACK PROCEDURE 59

7. PACKER INSTALLATION 64

7.1. HOLE PREPARATION 64

7.2. WIRELINE PACKER SETTING PROCEDURE 647.2.1. Running Procedure 65

7.3. TUBING INSTALLED PACKER SETTING PROCEDURE 667.3.1. Workstring Running Procedure 667.3.2. Completion String Running Procedure 67

8. COMPLETION INSTALLATION 68

8.1. CARBON STEEL AND PLASTIC COATED TUBING 68

8.2. CHROME TUBULARS 688.2.1. Transportation 688.2.2. Transport From The Mill 698.2.3. Road Transport 698.2.4. Marine Transport 698.2.5. Handling At The Wellsite 698.2.6. Thread Compounds 718.2.7. Running Chrome Tubulars 728.2.8. Retrieving Chrome Tubulars 73

8.3. EQUIPMENT PRE-INSTALLATION PROCEDURES 748.3.1. Material Requisition Lists 748.3.2. Completion Sub Assemblies 748.3.3. Tubing Hanger 758.3.4. Landing Joint 758.3.5. Control Line 758.3.6. Xmas Tree 758.3.7. Flowline 76

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8.4. COMPLETION ASSEMBLIES 768.4.1. Workshop Make-up and Test Procedures 768.4.2. Sub-Surface Safety Valves 768.4.3. Wireline Nipple Assemblies 778.4.4. Side Pocket Mandrels 77

8.5. COMPLETION RUNNING PROCEDURES 788.5.1. General 788.5.2. Running Procedure 798.5.3. TRSCSSV Installation Procedure 808.5.4. WRSCSSV Installation Procedure 81

8.6. XMAS TREE INSTALLATION 828.6.1. Installation Procedures 82

8.7. POST COMPLETION TEST PROCEDURES 838.7.1. SCSSV Test Procedure 838.7.2. Xmas Tree Valve Test Procedure 83

9. GAS LIFT INSTALLATION 85

9.1. MANDREL INSTALLATION 859.1.1. SPM Installation Procedure 859.1.2. Gas Lift Valve Installation Procedure 87

9.2. UNLOADING PROCEDURE 88

9.3. TROUBLESHOOTING 88

10. DOWNHOLE PUMP INSTALLATION 89

10.1. ELECTRICAL SUBMERSIBLE PUMPS 8910.1.1. Handling 8910.1.2. Installation 8910.1.3. Pulling Procedure 9310.1.4. Troubleshooting 93

10.2. ROD PUMPS 9610.2.1. Completion Installation 9610.2.2. Tubing String Installation 9610.2.3. Rod Installation 98

10.3. HYDRAULIC PUMPS 9810.3.1. Jet Pump 9910.3.2. Turbine Pump 10110.3.3. Piston Pump 101

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11. SUBSEA COMPLETIONS 102

11.1. SUBSEA EQUIPMENT PRE-DEPLOYMENT TESTING 10311.1.1. Guidewire Establishment Tool 10311.1.2. Guidewire Latchess 10311.1.3. Diverless Guideposts 10311.1.4. Casing Hanger Elevation Test Tool 10411.1.5. Tubing Hanger System 10411.1.6. Tubing Hanger Running/Orientation Tools 10611.1.7. Tubing Hanger Verification Tool 10911.1.8. Tubing Hanger Isolation Plugs 11011.1.9. Subsea Tree And Workover Equipment 11011.1.10. Install the LRP/TRT onto the XT 11511.1.11. Production Riser 11711.1.12. Surface Xmas Tree 118

11.2. DEPLOYMENT PROCEDURES 11811.2.1. Running The Completion And Tubing Hanger 11811.2.2. Pull The Drilling BOPs 120

11.3. WORKOVER AND PRODUCTION CONTROLS SYSTEM PRE-DEPLOYMENT TESTING 12011.3.1. Workover Controls Equipment 12011.3.2. Production Controls Equipment 12011.3.3. WOCS Pre-Deployment Testing 12111.3.4. Production Controls Pre-Deployment Testing 12411.3.5. Function Test using SEM B 12811.3.6. Pressure Test Tree Valves 131

11.4. RUNNING THE SUBSEA XMAS TREE 13611.4.1. Unplugging The Well 13611.4.2. Perforating And Well clean-Up 137

11.5. PULLING THE LRP 13711.5.1. Disconnect The LRP And Tree Running Tool 137

11.6. DEPLOYMENT OF THE TREE CAP 138

11.7. DEPLOYMENT AFTER COMMISSIONING ACTIVITIES 138

12. WELL UNLOADING 139

12.1. UNLOADING BY CIRCULATION 139

12.2. UNLOADING BY BULLHEADING 141

12.3. UNLOADING BY COILED TUBING 141

13. COILED TUBING OPERATIONS 14213.1.1. PREPARATION 142

13.2. SAFETY CONSIDERATIONS 14213.2.1. Tubing 14313.2.2. Risers and BOPs 14313.2.3. H2S Considerations 144

13.3. PERMIT REQUIREMENTS 144

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13.4. RIG UP PROCEDURES 14513.4.1. Equipment Preparation and Siting 14513.4.2. Coiled Tubing Rig-Up 14513.4.3. Pressure Testing 14613.4.4. Treating Lines 14813.4.5. Injector Frame 14813.4.6. Rigging Down 148

13.5. RUNNING PROCEDURES 149

13.6. OPERATING PROCEDURES 15013.6.1. Gas Lifting 15013.6.2. Well Treatment 15113.6.3. Sand Cleanout 153

14. NITROGEN PROCEDURES 155

14.1. PREPARATION 155

14.2. SAFETY CONSIDERATIONS 155

14.3. NITROGEN HANDLING 15614.3.1. Safety Equipment 15614.3.2. Safety Data Sheets 15714.3.3. Pressurised Lines 157

14.4. RIG-UP PROCEDURES 15714.4.1. Equipment Preparation and Siting 15714.4.2. Equipment Rig-up 15714.4.3. Pressure Testing 15814.4.4. Treating Lines 15814.4.5. Rigging Down 158

14.5. NITROGEN TREATMENT PROCEDURES 15914.5.1. Pressures 15914.5.2. Pump Rates 15914.5.3. Coiled Tubing Gas Lift 15914.5.4. Nitrogen Cushion - Tubing Conveyed Perforation 16014.5.5. Nitrified Treatment 161

14.6. NITROGEN TECHNICAL INFORMATION 161

14.7. EMERGENCY PROCEDURES (During Nitrogen Operations) 16214.7.1. Production Shutdown 16214.7.2. General Platform Alarm 16214.7.3. Prepare to Abandon Platform 16214.7.4. Liquid Nitrogen Spill 16314.7.5. Injury to Personnel 163

15. STIMULATION PROCEDURES 164

15.1. INTRODUCTION 164

15.2. SAFETY CONSIDERATIONS 16415.2.1. Chemical Handling 16515.2.2. Pressure 166

15.3. PERMIT REQUIREMENTS 167

15.4. RIG-UP PROCEDURES 16715.4.1. Equipment Preparation and Siting 16715.4.2. Equipment Rig-Up 168

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15.4.3. Pressure Testing 16815.4.4. Treating Lines 16915.4.5. Rigging Down 169

15.5. TREATMENT PROCEDURES 16915.5.1. Matrix Acidising 17015.5.2. Fracture Acidising 17015.5.3. Acid Wash 17015.5.4. Scale Dissolver 17015.5.5. Bullhead 17115.5.6. Coiled Tubing 17115.5.7. Asphaltene and Wax/Dissolvers 171

15.6. STIMULATION TECHNICAL INFORMATION 17115.6.1. Factors Affecting Acid Reaction 17215.6.2. Acid Properties 174

15.7. ACID ADDITIVES 175

APPENDIX A - REPORT FORMS 177

A.1. Initial Activity Report (ARPO 01) 177

A.2. Daily Report (ARPO 02) 178

A.3. Cementing Job Report (ARPO 04B) 179

A.4. Waste Report (ARPO 6) 180

A.5. Perforating Report (ARPO 07) 181

A.6. Gravel Pack Report (ARPO 08) 182

A.7. Matrix Stimulation Report (ARPO 09) 183

A.8. Well Problem Report (ARPO 13) 184

A.9. Malfunction & Failure Report(FB-1) 185

A.10. Contractor Evaluation (FB-2) 186

APPENDIX B - ABBREVIATIONS 187

APPENDIX C - BIBLIOGRAPHY 192

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REVISIONSTAP-P-1-7120 0

1. INTRODUCTION

1.1. PURPOSE OF THE MANUAL

The purpose of the Completions Procedures Manual is to guide technicians and engineers,involved in Eni-Agips Drilling & Completion worldwide activities, through the Proceduresand the Technical Specifications for general completion operations which are part of theCorporate Standards.

Such Corporate Standards define the requirements, methodologies and rules that enable tooperate uniformly and in compliance with the Corporate Company Principles. This, however,still enables each individual Affiliated Company the capability to operate according to locallaws or particular environmental situations.

The final aim is to improve performance and efficiency in terms of safety, quality and costs,while providing all personnel involved in Drilling & Completion activities with commonguidelines in all areas worldwide where Eni-Agip operates.

It is intended to guide users towards using procedures which have been found to providethe most efficient and cost effective operations.

1.2. IMPLEMENTATION

The policies included in this manual apply to all Eni-Agip Division and Affiliates operations.

All supervisory and technical personnel engaged in Eni-Agips completion and workoveroperations are expected to make themselves familiar with these and comply with thepolicies and procedures specified and contained in this manual.

1.3. UPDATING, AMENDMENT, CONTROL & DEROGATION

This is a live controlled document and, as such, it will only be amended and improved bythe Corporate Company, in accordance with the development of Eni-Agip Division andAffiliates operational experience. Accordingly, it will be the responsibility of everyoneconcerned in the use and application of this manual to review the policies and relatedprocedures on an ongoing basis.

Locally dictated derogations from the manual shall be approved solely in writing by theManager of the local Drilling and Completion Department (D&C Dept.) after theDistrict/Affiliate Manager and the Corporate Drilling & Completion Standards Department inEni-Agip Division Head Office have been advised in writing.

The Corporate Drilling & Completion Standards Department will consider such approvedderogations for future amendments and improvements of the manual, when the updating ofthe document will be advisable.

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2. RESPONSIBILITIES

The following job descriptions outline the individual responsibilities and duties of specifickey personnel involved in Eni-Agip Completion operations. These are generalised summaryof the individual responsibilities and duties which are specific to completion operations andas such augment, but do not supersede their current employers approved job descriptions.

2.1. DRILLING COMPLETION AND WORKOVER MANAGER

The Drilling/Completions and Workover Manager reports directly to the District Manager andsupervises the Well Operations Superintendent, Completions and WorkoverSuperintendent, Drilling Engineering/Completions and Workover Engineering.

His duties include the following:

Ensuring the definition of scope of work and requisitioning of drilling andcompletion/workover contracts are correctly processed by the contractsdepartment and approved first by the District Manager, in order to comply withtime schedule, quality and technical conditions as defined in the programme.

Ensuring the pre-qualification and technical tender evaluation phases complywith company policies and procedures and to provide the Contracts departmentwith all technical details necessary for a thorough commercial evaluation.

Approving the completions programmes, ensuring they fully meet the prognosistarget, pursuing the best results in terms of safety, time schedule and costeffectiveness.

Managing day-to-day completions operations, co-ordinating the activities ofcontractors and units/positions involved, in order to guarantee that operationsmeet the company policies and standards.

Controlling operational costs and provides the technical approval for invoicepayment. Verifies the consistency of the expenditure with AFEs and with theadministration validity of the contracts.

Liaising, timely and effectively, with the regulatory bodies in order to obtainconsent for well related operations.

Instituting, monitoring and reviewing completions safety policies within theSafety Management System, in order to maximise effectiveness and safety ofthe operations.

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2.2. WELL OPERATIONS SUPERINTENDENT

The Well Operations Superintendent reports to the Drilling, Completion and WorkoverManager and supervises rig site supervisors.


Ensuring operational progress follows the approved well programme andprovides technical advice to the rig site on a daily basis, as required.

Ensuring the correct scheduling of completion materials and services, provides atimely supply to the rigs while optimising the cost of transport, materials andmanpower within established programmes and budgets.

Administering service contracts, providing the technical control of contractorperformance giving the first authorisation to the payment of invoices andensuring the control of current total expenditure on each contract.

Ensuring that operations comply with current legislation and companystandards.

Preparing scopes of work and technical specification for services to be tenderedand review those for services and equipment.

Providing technical advice during pre-qualification and tender evaluationphases, in order to ensure that the selection of contractors and suppliers fullymeet technical targets and company standards.

Providing timely and accurate requisitions for all services and materials relevantto well operations.

Ensuring, in liaison with AQS, the correct interface of the Contractorsprocedures are to Eni-Agips policies and procedures.

Ensuring simultaneous completion and production procedures are reviewed.

2.3. COMPLETION AND WORKOVER ENGINEER

Reports to the Drilling, Completion and Workover Manager.


Preparing and reviewing technical specifications and scopes of work forequipment to be tendered and services for completion, workover, wireline andwell testing operations.

Co-operating with the Well Operations Superintendent for providing adviceduring pre-qualification and tender evaluation phases, in order to ensure that theselection of contractors and suppliers fully meet technical targets and companystandards.

Supplying well cost estimates for future operations budgets and currentoperations AFEs, ensuring the reliability of the data provided.

Contributing, in liaison with the Petroleum Engineer and with the ReservoirEngineers, to the planning of development projects, providing technical input tothe project teams, in order to optimise cost and effectiveness of the project.

Monitoring, in liaison with the Petroleum Engineer and with the ReservoirEngineers, the performance of wells and reservoirs, in order to provide technicalexpertise and advice for identifying and initiating enhancements to wellpotential.

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Appraising new completion, workover, wireline and well testing technology andproducts to determine their application to Eni-Agips completion operations, inorder to improve time cost performance and safety conditions.

Preparing and reviewing completion, workover, wireline and well testingprogrammes and final reports and to ensure the production of adequatefeedback about the operations as per the Safety Management System corporaterequirements.

Reviewing daily the operations versus the programme, providing a thoroughinvestigation of operational times.

Providing engineering assistance to the Well Operations Superintendent in thefollow up of operations.

Providing reports and analysis on the operated and non-operated activities forpresentation, meetings and reporting to the management and to ensure theoperational feedback reporting system is consistent with Eni-Agip and corporaterequirements.

Assisting his supervisor in contacts with partners and regulatory bodiesproviding the necessary documentation and reports.

Providing the monthly updates on the variance between actual and estimatedexpenditures for each job centre for each class of cost, also to liaise with theCompletion/Workover Superintendent, in order to update the expenditure oneach contract.

Ensuring the production and review of the Completions Procedure Manual inorder to comply with company policies and the current legislation.

2.4. FLUIDS SPECIALIST

Reports to the Drilling, Completions and Workover Manager for routine operational matters.


Preparing technical specifications for tenders. Advising on pre-qualifications and tender evaluations exercises. Preparing programmes ensuring the compliance with regulatory requirements. Ensuring the compilation of final fluids reports and the feedback documents

relevant to the activities under his scope of work. Maintaining up to date knowledge of the technical and regulatory evolutions for

the activities under his scope of work. Liaising with logistics department for ensuring the provision of services,

transportation and materials to well site. Liaise with the appropriate service companies and suppliers on a daily basis.

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2.5. OFFSHORE INSTALLATION MANAGER (OIM)

If applicable, his duties include the following:

Reporting directly to Asset Operations Manager. Co-ordinating and supervising all operations on the installation. The senior

representatives for each discipline are responsible for the activities of their owndiscipline and must keep the OIM informed on their own respective operations.The Production Supervisor will keep the OIM informed on the status ofproduction operations.

Authorise all work permits in accordance with the Permit to Work System, andwill ensure countersignature by the Well Operations Supervisor, or otherDiscipline Heads.

For completion operations, he will delegate responsibility to the Well OperationsSupervisor or another Company Representative (e.g. Production Supervisor) asdictated by asset ownership or control at the time of the ongoing operations.

Is responsible for the actions to be followed under the various installationoperating modes. The OIM will require advice from the WellOperations/Production Supervisor or other Discipline Heads, e.g. MaintenanceSupervisor, etc.

2.6. WELL OPERATIONS SUPERVISOR

Represents Eni-Agips interests on the installation with respect to the Drilling Contractor andService Companies.

The Senior Well Operations Supervisor is directly responsible for the drilling and completionequipment and all operations conducted during the drilling completion and workover phase.


Ensuring all Company policies relating to drilling and completing operations andemergency situations are adhered to at all times for the safety of personnel, rigequipment, well stability and control.

Directing the Drilling Contractor and Service Company representatives in theoperations to be performed and supervises the conduct of the operations.

Ensuring all operations, detailed in the Drilling and Completion Programme, areperformed efficiently and safely using the procedures detailed in the programmeand/or Completion Procedures Manual.

Responsibility for the Hot Permit System when hot work is being conducted inthe drilling module.

Requisitioning the equipment and materials required to complete the operations.He will requisition the materials when appropriate and liaise with the Completionand Workover Superintendent to ensure arrival at the rig-site in ample time toallow inspection and preparation prior to use.

Ensuring all tools are suitable for purpose, inspected and dressed prior torunning in the well.

Introducing changes to the Drilling and Completion Programme but only in anemergency or when operating conditions do not allow for communication withthe Drilling and completion Workover Department.

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Ensuring all reports required, are accurate in content and are submitted asrequired. Reporting requirements are outlined in section 3.

Liaising with the OIM, Company Production Supervisor, and other operationalHeads on a daily basis to discuss operational considerations and the possibleimpact on the other operations.

Supervising and directs well control operations in accordance with the Eni-AgipWell Control Manual.

Liaising with the OIM to give advice on what actions to take, if any of thePlatform Operating Modes are associated with the drilling operation, or arisefrom operations in the drilling module.

On completion of the programme, i.e. Xmas tree is secured with all operationscompleted, officially handing over the well to the Production Department(Production Supervisor). Both parties must sign the relevant well handoverdocument.

Co-ordinating all completion activities including wireline and/or coiltubing/nitrogen, acid stimulation, perforating as well as all preliminary pressuretesting of equipment.

Ensuring the safe and correct installation of all tubulars and completion sub-assembly components, i.e. in the correct order and proper depth as per thecompletion programme.

2.7. PRODUCTION SUPERVISOR

Reports to the Company Production Superintendent (Office).


Representing Eni-Agips interests on the platform with respect to production,and when dealing with service companies involved with operations during theproduction phase.

Ensuring that, during heavy lift operations such as handling Xmas trees etc.,neighbouring wells are closed-in to minimise risk to wellheads, flowlines,production equipment, the platform and personnel.

Informing the Well Operations Supervisor, OIM and other Discipline Heads onthe status of the production operations and the possible impact on otheroperations in general.

Prior to a workover being carried out, handing the well over toDrilling/Completion (Well Operations Supervisor) stating the exact condition ofthe well. Both parties must sign the handover document.

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3. DOCUMENTATION

This section outlines the documentation necessary for conducting efficient completionoperations and reporting of these operations.

3.1. PRELIMINARY INFORMATION

Before performing any well operations the following documentation and information must beavailable:

A detailed programme including:

Name of Field Name of Well Well Code Well Co-ordinates (wellhead and bottom hole) Cost Centre Number RKB Elevation Completion String Schematic (completion components ID, length, tubing

size/weight, depths, etc.) Intervals to be perforated Specifications of Completion Equipment.

3.2. WELLSITE REPORTS

To schedule future operational programmes, all operations must be properly documentedand kept on file to maintain the history of operations performed on any well.

The operations performed during rig operations (completion string gauging, packer setting,etc.) will be reported in the Daily Well Report. This and other service reports for gravelpacking, stimulation and other well operations are shown in Appendix A.

It is responsibility of the Well Operations Supervisor to compile and forward the reports(indicated below) to the Well Operations Superintendent. The Superintendent will thencheck and approve the reports before distribution and filing.

3.3. FEED BACK REPORTS

The following reports are compiled at the end of the operations:

a) FB-01 Report on Equipment Damage and Malfunctions

b) FB-02 Service Company Evaluation Report

Refer to Appendix A for copies of appropriate reports.

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3.4. OTHER REPORTS

The Eni-Agip Representative must sign the Service Reports of the Service Companieswhich must include the following information :

Name of Well Name of Field Order Number Date Personnel and equipment used Description of the operations conducted Starting and completion dates for service company charges.

3.5. PERMIT PROCEDURES

No work can be performed without a valid permit to work. All requirements as laid out in theCompany Permit to Work Procedures must be adhered to at all times. Although theoperation of a permit system is the responsibility of the installation manager, safe operatingpractice is compulsory and the responsibility of all personnel involved in completionoperations.

The Permit to Work System is drawn up in accordance with standard Oil Industry practicesin order to improve offshore safety during all phases of operations. All personnel involved incompletion operations should clearly understand the particular installation Permit to WorkSystem, and be aware that the issuing of a permit in itself cannot guarantee that any job issafe.

As each installation will have its own distinct PTW system according to the type ofinstallation, location and country, it is not possible to describe a generic system in thismanual.

3.5.1. Guidance For Permits

Examples of activities which require permits to work (hot and cold) must listed in Permit toWork Procedures. Those activities not normally requiring a work permit must also be listed.It should be stressed however, that some of these activities will be brought within the Permitto Work System from time to time as circumstances dictate. It remains the responsibility ofthe Area Authority to ensure that the correct permits and certificates are in force during allphases of operations. The responsibilities of those individuals involved in the administrationof the Permit to Work System should be clearly defined in the Permit to Work Procedures.

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3.6. WELL HANDOVER PROCEDURES

Operations performed on a well will be the responsibility of a designated Area Authority.The Well Operations Supervisor will be the responsible person for drilling, completion,workover, wireline, coiled tubing, and stimulation operations. The Production Supervisor willbe the responsible person for production operations.

The Production Supervisor will be the competent person during Xmas tree repairs orchange-outs even when these works are performed by maintenance personnel with theassistance of a vendor service engineer.

The action of transferring the responsibility for a well between area authority will bedocumented and recorded on the Well Handover Certificate or Well Intervention HandoverCertificate. All preparatory work and the status of the well when handed over will bedescribed in the appropriate Handover Certificate. A typical example of a HandoverCertificate (Eni-Agip) with the information to be recorded is shown in figure 3.a and figure3.b.

The completed Handover Certificate must be signed by the responsible persons handingover and receiving the well. It must be placed in the appropriate well file. Copies are to befaxed to the Well Operations Superintendent when a new well is handed over.

There are two types of Well Handover Certificates:

Well Handover Certificate Well Intervention Handover Certificate.

3.6.1. Well Handover Certificate

The well Handover Certificate is to be used for all new wells and wells worked over (Drilling,Completion through to Production).

New Wells

Following the successful drilling and completion of a new well, the Operations departmentwill complete a Well Handover Certificate. Prior to handover of the well to Production, thewell status should be outlined as below:

Xmas tree installed and fully pressure tested Swab cap installed and pressure tested SCSSV installed and fully tested All wireline plugs removed All obstructions removed, the wellhead and Xmas tree areas are clean and tidy Written procedure for the venting of annular pressure, if necessary.

Once the Production Supervisor is satisfied that the status of the well is satisfactory, he willsign the handover certificate in acceptance of the well. Examples of Well HandoverCertificates are shown in figure 3.a and figure 3.b.

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Workover Wells

Workover is defined in this instance as any well operation which involves the change-out ofany completion component from the wireline re-entry guide to the Xmas tree.

Following the successful completion of a well which has been worked over, Well Operationsdepartment will complete a Well Handover Certificate. Prior to handover of the well toProduction the well status should be outlined as below:

Xmas tree installed and fully pressure tested Swab cap installed and pressure tested SCSSV installed and fully tested All wireline plugs removed All obstructions removed, the wellhead and Xmas tree areas are clean and tidy Written procedure for the venting of annular pressure, if necessary

Once the Production Supervisor is satisfied that the status of the well is satisfactory, he willsign the handover certificate in acceptance of the well.

3.6.2. Well Intervention Handover Certificate

The Well Intervention Handover Certificate is to be used for all interventions such as:

Mechanical wireline operations Electric wireline operations Coiled tubing operations Snubbing operations (except where these constitute a Workover) Well stimulation operations.

Prior to handover of the well by Production to Well Services the Production Supervisor willcomplete a Well Intervention Handover Certificate and ensure the following procedures arecompleted:

1) All chemical injection lines on the flowline will be bled down and isolated.

2) The test and production, or injection, header isolating valves will be closed, and theflowline bled down to the closed drains and isolated when no liquid or gas is observedat the sample point. Blind flanges should be installed on the flowline termination.

3) The SCSSV control lines will be bled off ready to be disconnected. All lines from thewellhead to the remote control panel will also be bled down.

4) If the tree is to be removed all instrumentation and control lines will be removed fromthe well.

5) All obstructions (e.g. scaffolding) all instrumentation and control lines will be removed.

Once the Well Operations Supervisor is satisfied that the status of the well is satisfactory hewill sign the Well Intervention Handover Certificate in acceptance of the well.

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Following an intervention operation the Well Operations Supervisor will complete a WellHandover Certificate. Prior to handover of the well to Production, the well status should beoutlined as below:

Xmas tree installed and fully pressure tested. Swab cap installed and pressure tested. SCSSV installed and fully tested. All wireline plugs removed. All obstructions removed, the wellhead and Xmas tree areas are clean and tidy Written procedure for the venting of annular pressure, if necessary.

Once the Production Supervisor is satisfied that the status of the well is satisfactory, he willsign the Well Intervention Handover Certificate in acceptance of the well. An example of aWell Intervention Handover Certificate is shown in figure 3.c.

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WELL HANDOVER CERTIFICATE

Well No: Date:

WELL DETAILS

Well Type: Producer/Injector/Gas Lift/__________________

PERFORATION DETAILS

ft MD/TVD ft MD/TVD

ft MD/TVD ft MD/TVD

ft MD/TVD ft MD/TVD

ft MD/TVD ft MD/TVD

Last Hold Up Depth: ft MD/TVD Date:

Details of Junk:

Bridge Plug(s) ft MD/TVD

TUBING DETAILS

TubingSize

TubingGrade

Condition Producingor Injecting

TubingFluid

Shut in WellheadPressure

Date last on line

SAFETY VALVE DETAILS

String Valve Open orClosed

Type Date Last

Tested

Remarks

TUBING PLUG DETAILS

String PlugType

Depth DateTested

TestPressure

Remarks

Figure 3.A - Example Handover Certificate (Eni-Agip UK)

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XMAS TREE DETAILS

Type: Pressure Rating:psi

Tested to: Date Tested:

S/N of Block

Valve S/N Status Valve S/N Status

Swab Valve Manual Master

Hydraulic Master Hydraulic Wing

Manual Wing(prod)

Manual Wing(kill)

ANNULUS DETAILS

Annulus Pressure Fluid Statuse.g. Shut-in, Open, Venting,

Seized Valves, etc.

Flowline Status:

ADJACENT WELLS

Well No SCSSV Plugs XmasTree

Flowline

Status Tested Date Status Tested Date Depth Status Status

All Production/Operations equipment removed from area ? Y/N

Remarks:

Changes From Programme Status:

Authorised By: Production/Operations

Accepted By: Production/Operations

Figure 3.B - Example Handover Certificate (Continued)

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WELL INTERVENTION HANDOVER CERTIFICATEWell No: Date:Well Details : Producer/Injector : Single/Dual String :Permit Order No:Description of Operation

BARRIERS REQUIRED BARRIERS REMOVED (SITE TIDY)

SAFETY VALVE DETAILSHandover Handback

String Status** Remarks** String Status** Remarks**

XMAS TREE DETAILSHandover Handback

Valve Status**

Valve Status**

Valve Status**

Valve Status**

Prod Side Ann Side Prod Side Ann Side

Flow Wing Man Wing Flow Wing Man Wing

Choke Choke

Swab Valve Man Master Swab Valve Man Master

Hyd. Master Hyd Master Hyd. Master Hyd Master

Man. Master Man. Master

**OPEN/CLOSED, HYDRAULICS ISOLATED/DE-ISOLATED

ANNULUS DETAILSHandover Handback

Annulus Pressure Fluid Status Annulus Pressure Fluid Status

Above P-Off Above P-Off

DOWNHOLE TUBING DETAILS(e.g.: equipment set in nipple/component failures/fish in hole etc.)

Handover HandbackString Detail Depth Remarks String Detail Depth Remarks

Authorised By : Production/Well Services Authorised By : Production/Well ServicesAccepted By : Production/Well Services Accepted By : Production/Well ServicesTime/Date : Time/Date :

Figure 3.C - Example Handover Certificate (Continued)

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4. HOLE PREPARATIONS

The procedures in this section described the preparation of the hole and surface facilitiesfor completion operations.

4.1. PRELIMINARY CHECKS

Sometime prior to completions operations, the following equipment should be checked toconfirm availability and to specification for the forthcoming operations:

a) Workstring of the appropriate grade and size in sufficient length, taking intoconsideration if a tapered string is to be used.

b) BOPs are equipped with the correct size-pipe/variable (single or dual) rams tocover all the range of tubulars to be run in the hole.

c) Wear bushing for the tubing hanger spool, equipped with the running/pullingtool.

d) BOP test tool with the appropriate running and pulling tools and a sufficientquantity of seals.

e) All relevant handling tools for the workstring including elevators and slipsverifying they are in good working condition.

f) Safety valves have been tested and are available already made up with thecrossovers to the workstring and Weco connections to suit the kill lineconnection.

g) The rig has been equipped with the safety and emergency systems as per thecontract and that they are fully operational.

h) Rig pumps are equipped with the appropriate liner sizes and that they havebeen tested.

i) Mud logging or monitoring system is installed and operational.

4.2. WELL CLEAN UP PROCEDURES

After the production casing, or liner, has been cemented in place, a bit and scraperassembly will be run. The purpose of this trip is to clean out any excess cement within thecasing, and particularly to remove any cement that may be on the casing wall at the packersetting depth.

A suitably sized bit, or junk mill, and tandem scraper assembly will be run to clean out thecasing or liner of any excess cement, and to scrape the intended perforated interval(s). Thepacker setting depth will also be scraped during this operation to ensure it will have a goodsetting area. Precise details of packer setting depths, perforation intervals and maximumclean out depth will be given in the well operations/drilling programme.

Note: The casing and liner string may be pressure tested at this point, and aninflow test on liner laps and shoe tracks performed.

For detailed procedures on how to perform inflow and pressure tests refer to the DrillingProcedures Manual.

If a liner lap is a found to be leaking it may be necessary to run a tie back packer into thetop of the liner lap, otherwise it will be necessary to perform a remedial cement squeeze.The decision on which method to adopt will depend on the location and nature of the leak.

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4.3. BOP STACK CONFIGURATION AND TESTING

a) The BOP stack configuration including ram sizes should be in accordance withthe Well Programme.

b) All components must be fully certified and will be tested with water inaccordance to company policy or local regulations, whichever is the moststringent. testing on a new completion will be accomplished by using either thetest tool or the tubing hanger with the tubing hanger plug installed.

c) Duration of pressure tests will be 10min with a maximum allowable pressuredrop of 100psi unless local legislation dictates otherwise.

d) If it is necessary to use a cup tester for testing the BOP stack, the test pressuremust not exceed the safe working pressure of the casing.

e) The test schedule will be according to local regulations but will be at least every14 days. If operational constraints prevent a scheduled pressure test, adispensation will be requested and issued by the authorities and held on file.

f) The function and pressure tests will be recorded on a chart recorder and thecharts held in file.

g) In workover operations prior to pulling the tubing, the BOP stack will be testedagainst plugs set in the tubing hanger.

h) Function test at the same time as the BOP stack the surface control panel,accumulator package and remote control panel. if using a subsea BOP stack,check from both blue and yellow pods.

4.4. WELL CONTROL

Well control procedures will be in accordance with the Company Well Control PolicyManual, a copy of which must be kept available on the rig.

4.5. OIL BASED MUD DISPLACEMENT

Prior to displacing the well to the completion brine, it will be necessary to displace thedrilling mud from the well. In order to ensure that circulation time, rig time and filtration timeare kept to an absolute minimum, it is essential that the well clean up is as efficient (andeconomical) as possible in removing the mud, solids and any other associated debris in thewell.

4.5.1. Displacement Objectives

Displace oil based mud out of the well with a minimal interface between the oilbased mud and the clean up chemicals.

Keep the brine interface to an absolute minimum. Minimise filtration time and cost. Change the wetability of all downhole surfaces from oil wet to water wet. Prevent the discharge of oil based mud, contaminated water and/or

contaminated brine to the environment. Minimise the requirement for back-loading oily water for disposal. Remove pipe scale, solids, mud solids and other contaminants from the

wellbore.

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4.5.2. Logistical Considerations

In advance of the displacement, the logistics of the operation from start to finish should beaddressed. The areas which should be addressed include (but are not limited to) thefollowing:

a) Vessel(s) for back-loading mud and taking on the clean up chemicals, brine andkill pill material.

b) The quantities of clean up chemicals, brine and kill pill material requiredincluding any contingency material that may be required.

c) Pit space requirements for mud and brine and the permits required for cleaningthe appropriate pits and lines.

d) The equipment required to install and operate the filtration equipment.

e) Personnel requirements and available accommodation.

4.5.3. Drilling Fluid Preparation

1) Pick up the workstring with scrapers placed in it to ensure that the liner or casingpacker setting depths are thoroughly scraped during the trip. Once on bottom,bottoms up should be circulated to remove any additional debris.

2) Circulate and condition the oil based mud with oil mud thinner or oil wetting agent inorder that the yield point and gel strengths are reduced but not to a point where thefluid loses the ability to keep barite/drilled solids in suspension. Typically, the yieldpoint should be reduced to 12 lbs/100 ft2 and the 10min gel to

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4.5.4. Surface Equipment Preparation

As much of the surface volume of mud should be sent back to the base leaving only onetank into which the mud returned from the displacement can be dumped:

1) Wash and scrub all of the pits and storage tanks designated for the completion fluidwith steam cleaners. Once the top and sides are scrubbed, the bottom of each tankshould be swept to the suction line and the contents sent to a contaminated fluidstorage pit.

2) All pits, sandtraps, gumbo traps, flowlines, ditches and in particular areas where theaccumulation of solids can be overlooked such as underneath lines and grates, aboveand behind angle irons, in the corners and crevices of beams should all be thoroughlycleaned.

3) Once everything has thoroughly been cleaned, fill one pit with fresh water and add therecommended volume of surfactant/flocculant. Agitate the pit to keep the productdispersed.

4) Circulate the surfactant/flocculant pill at the maximum possible flow rate (for +/-20mins) throughout the entire surface system including all pits, pumps, lines or otherareas that the completion fluid may contact.

5) Provided the water is not contaminated it can be dumped. If the water iscontaminated, it should be diverted to a pit designated for contaminated fluid.

6) As before, the pits should all be swept clean and dry.

7) Once all of the above has been done, dump valve seats should be inspected andreplaced wherever necessary and then guided into place to ensure they seal properlybefore filling with brine.

8) Once sealed, all dump valves should be locked shut.

4.5.5. Well Clean Up Pill Sequence

The following is the normal sequence for pumping the various fluids and pills.

a) Weighted hard surface detergent pill

b) Viscous hard surface detergent pill

c) Drill water or seawater

d) Solvent pill

e) Drill water or seawater.

f) Surfactant/flocculant pill

g) Viscous hard surface detergent pill

h) Drill water or seawater (water should be pumped until returns are below 60 NTU,usually 1-2 circulations).

i) Viscous pill.

j) Filtered completion brine

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4.5.6. Pill Functions

a) The weighted detergent pill is pumped directly behind oil based mud to initiateoil and filter cake removal.

b) The solvent pill has a solvating action on oil based mud residue and filter cakeresidue. This is the main pill for actually removing the mud residue. It should notbe mixed with any water or base oil to cut it back as this reduces the efficiencyof the pill.

c) The surfactant/flocculant pill is used as a chemical flocculating agent to dislodgeany residue loosened by the solvent. A large pill is required to ensure adequatecontact time to remove all solids.

d) The viscous detergent pill is a detergent pill used to convert the surfaces into awater wet state.

4.5.7. Pit Requirements

Pits/storage tanks will be required for the following:

a) Mud pit for the detergent pill

b) Mud pit for the surfactant/flocculant pill

c) The solvent pill in the cement unit

d) Drill water or seawater

e) The viscous pill in the pill tank

f) Completion brine.

4.5.8. Pumping Sequence

The pumping sequence and direction should be in accordance with the well programme.The Mud Engineer should confirm the depths, volumes and rates provide the correctcontact times for the various pills.

Seawater should be pumped until returns are clear (1-2 circulations) after which time theseawater can be displaced out with a viscous pill by the completion brine.

The viscous pill ahead of the brine should be built using the brine as the base.

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4.6. DISPLACEMENT OF WATER BASED MUDS

The displacement of a water based to a clear fluid is an easier procedure requiring fewersteps. This is due mainly to both fluids being compatible and all surfaces already water wet.

As with the clean up of oil based mud, it is essential that the well clean up is as efficient(and economical) as possible.

As before the logistical aspect of the displacement from start to finish should be addressed.The areas to be addressed include:

1) Transportation for taking well clean up chemicals, brine and filtration equipment/consumables to the rig.

2) Personnel requirements.

3) Surface equipment cleaning.

4.6.1. Drilling Fluid Preparation

1) The mud properties should be reduced to the levels specified for oil based mud,namely YP of 12 lbs/100 ft2 and 10min gel

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4.6.4. Pill Functions

a) Drill water/caustic soda pill is used as a preflush to strip away and denature theheavy, concentrated water based mud filter cake and solids.

b) Surfactant/flocculant pill is used as a chemical flocculating agent to remove theresidues dislodges by the drill water/caustic soda pill. A large pill is required toensure an adequate contact time to remove all solids.

c) Detergent pill is a polishing pill to ensure all downhole surfaces are thoroughlycleaned prior to pumping the seawater.

4.6.5. Pit Requirements

a) Mud pit for the Caustic Soda Pill.

b) Mud pit for the surfactant/flocculant pill.

c) Pill tank for the detergent pill.

d) Drill water or seawater as required.

e) Pill tank for the viscous pill.

f) Completion Brine.

4.6.6. Pumping Sequence

The pumping sequence and direction should be in accordance with the well programme.The Mud Engineer should confirm the depths, volumes and rates provide the correctcontact times for the various pills.

4.7. COMPLETION AND WORKOVER FLUIDS

4.7.1. Brines Transportation

Prior to loading any brine at the suppliers facility the vessel tanks and manifolds will beinspected for cleanliness and dryness.

Note: Boat manifolds may contain residual materials that could contaminate thebrine. Therefore all manifolds, pumps, etc. that will be involved in brinedelivery will be thoroughly flushed and dried.

Brine will not be loaded onto a vessel or truck until the Companys responsible person issatisfied that the brine will arrive at the rig site with the same clarity, density, and solidscontent as originally loaded.

Samples of the brine will be taken during the loading operation from the loading tanks andthe vessel's receiving tanks or truck. The volume, density and clarity of the fluid afterloading must be identical to the fluid from the suppliers tanks.

Prior to transferring the brine to the installation from the tanks all hoses, connections, dumpvalves, etc. will be checked for leaks.

The volume and density of the brine will be monitored as it is transferred from the vessel.Any discrepancies in density and volume will be recorded.

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4.7.2. Completion And Workover Fluid Quality

The quality of the fluid used during a completion and workover operation cannot be over-emphasised as the productivity is governed not only by the damage caused by visiblecontaminants such as solids but also the damage caused by invisible contaminants such ascalcium ions, sulphate ions and dissolved iron. It is, therefore, essential that all of these andother similar contaminants are controlled to as low a level as feasible and, whereverpossible, completely removed (Refer to the Drilling Fluids Manual).

Other contaminants such as iron and sulphates can be controlled on surface by chemicaltreatment but can be avoided altogether by ensuring that the quality of the fluid supplied iscorrect, the quality of all the sacked and drummed material meets the required specificationand the rig is thoroughly cleaned before taking on the completion brine.

During well completion and workover operations, all steps must be taken to ensure that, ifany fluid is in contact with the formation, it is both clean and filtered. A fluid in any othercondition will, for the reasons stated above, result in some degree of formation impairment.

4.8. FILTRATION SYSTEMS

The prime filtration system is the Diatomaceous Earth filter press with a bag filter system foruse as a downstream guard filter. Sometimes, on standby is a low pressure, Cartridge Filterunit.

Both the DE and the cartridge units are capable of filtering down to 2 microns.

The DE is preferable as the prime equipment as it is more suited to high solids loadingwhich can be removed using various different grades of DE to form a porous, permeablefilter cake on a filter cloth. The nature of the DE is such that it must be added using a safehandling system to ensure that there is a totally dust free environment thereby eliminatingany hazard to the operator or any other personnel in the vicinity. On no account shouldloose DE be used.

4.8.1. Fluid Cleanliness

Before filtering, all the tanks should be thoroughly cleaned out and any mud residueswashed out (as per the pit cleaning procedure described earlier in section 4.5.4).

a) A pit of brine will not be filtered by circulation on itself.

b) Brine will be filtered from the dirty pits to a clean empty tank.

c) All filtered brine will be checked to ensure that it meets the required level ofcleanliness. Normal specifications are:

By laser particle counter: < 250ppm total undissolved solids By turbidity meter: < 20NTU By centrifuge: < 0.01% by volume solids.

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4.9. LOST CIRCULATION

The use of lost circulation materials may be necessary if the well has suffers any seriousfluid losses as can be experienced such as on open hole, gravel pack or wells which areperforated prior to running the completion, etc.

The types of LCM pills preferred for the various uses from slow seepage to high losses inparticular situations are fully described in the Drilling Fluids Manual along with theformulations and placement procedures.

Prior to using an LCM pill, consideration will be given to reducing the hydrostatic head byreducing the brine weight (with drill water) and so reduce the level of losses. This will onlybe attempted if the reduction in weight does not compromise the safety of the well.

Obviously the LCM pills used in completion operations should be selected in order minimisepotential damage to producing formations. Some of the most common LCM pills used incompletion operations are described below.

4.9.1. Viscous Pills

These can be built, either, using drill water, completion brine or a higher weight brine as abase and adding a predispersed liquid viscosifier to increase the funnel viscosity accordingto the well programme. The addition of a predispersed liquid viscosifier is preferable as itwill yield rapidly without forming fish eyes which may cause a problem when it comes timefor the removal of the pill downhole.

There are both advantages and disadvantages is using high viscosity pills for controllingfluid loss. These are as follows:

1) Advantages

They contain no particulate material to impair the formation. They can be built quickly and easily. They can be removed by thermal degradation, acid, chemical breakers or by

flowing the well.

2) Disadvantages

They are limited normally to temperatures

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Notes:

1) The above formulation will give a final weight of 10.5ppg assuming that a 10ppg NaClbrine is used as the base.

2) If a higher density is required, the formulation will require modification by the additionof FL-7 Plus and Watersal A. The specific formulation will be determined by the FluidsEngineer on the rig. However, typical formulations are as follows (see table below).

3) Mixing order of products should be listed.

4) A small amount of defoamer is required (0.2gal/bbl) to minimise foaming.

Density

11 ppg

Density

12 ppg

Density

12.5 ppg

Composition*Saturated Brine (bbl)Bridesal Plus (lbs/bbl)FL-7 Plus (lbs/bbl)Watersal A (lbs/bbl)

0.88402

57

0.75304

164

0.69304

210

Properties

Plastic Viscosity (cp)Yield Point (lbs/100 sq.ft)10 sec Gel Strength (lbs/100 sq.ft)10 min Gel Strength (lbs/100 sq.ft)pH

30358

107.4

626110137.1

776711147.2

4.9.3. Calcium Carbonate Pills

Calcium carbonate can be used as a drilling fluid and for LCM pills to control fluid losses. Incompletion operations it is now the most commonly used fluid for controlling fluid losseswithin Eni-Agip operations.

The composition of a calcium carbonate LCM pill is dependent upon the formation porosity,permeability and temperature. A range of particle sizes is available which may be mixed toprovide the ideal mixture for the formation pore size. The calcium carbonate uses a viscouspill as a carrier (Refer to section 4.9.1 above).

Typical of a calcium carbonate fluid is Baker Hughes Inteqs reservoir drill-in fluid systemcalled Perflow that is designed to lower overall well completion costs while improving long-term production rates.

Used as a drill-in fluid, Perflow maintains the properties of a drilling fluid while protecting thewell's pay zone against damage. It provides lubricity, inhibition, solids suspension, cuttingsremoval, and wellbore stability. In its protective role, the fluid bridges on pore openingsexposed to the wellbore, remains intact during completion and workover operations, and iseasily removed with production.

The system's performance has made it effective in a number of wellsite applications. Theseapplications include use as a drill-in fluid, coring fluid, fluid loss pill, underreaming fluid, TSO(Tip Screen Out) prepad fluid, and as a kill fluid.

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The system's simplified cleanup reduces rig time during completion and workoveroperations. While other fluids require costly processes for removal, removal is simplyaccomplished by flowing the well.

The system utilises very pure calcium carbonate with a broad particle size distribution toeffectively bridge the pore openings of the formation. The bridging agent and polymerchemistry form a thin filter cake to protect the pay zone from damage caused by fluidinvasion. The filter cake is effectively removed by low break-out pressures, leaving nosignificant residual material to inhibit the well's production.

Before using a calcium carbonate pill, any potential damaging effects from the calciumcarbonate needs to be assessed as any particles trapped in pore spaces can only beremoved by an HCl acid treatment.

4.10. CASING GAUGE CONTROL

Prior to running any completion equipment, it is necessary to ensure the hole is withingauge to allow passage of tools such as packers and TCP guns.

Checking the hole gauge is carried out by electric line services by running a gauge ring of asize according to the casing drift size. It is normal practice to run the gauge ring inconjunction with a junk basket after the well clean out procedure. The junk basket is run tocatch junk which has not been circulated out of the hole during the well clean out operation(typically rubber, pieces of cement, etc.).

Any tight spots should be logged and reported. Ultimately the casing may require furtherscraping. It is extremely important that the casing is drifted as the sticking of completionequipment can incur high costs in retrieval, loss or damage to equipment and may evencause a side-track.

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5. PERFORATING PROCEDURES

5.1. GENERAL

Two methods are currently used to perforate wells: wireline conveyed guns and tubingconveyed guns (Refer to the Completion Design Manual). In the drive to obtain maximumperforating efficiency, tubing conveyed perforating is the preferred method for mostcompletion operations as the zones to be tested can be perforated underbalanced in onerun with a large size charges, if possible. However, under some circumstances wirelineconveyed guns may still be preferred. The procedures for both methods are described inthe following sections.

The type of explosive to be used will depend mainly on the bottom hole temperature andthe length of time the guns are likely to be on bottom before firing. Refer again to theperforating section in the Completions Design Manual and to suppliers technicalspecification sheets.

The BOPs and the rig manifolds should have undergone a recent full programme ofpressure testing.

At the safety meeting, the perforating operation should be discussed in fine detail. Apartfrom outlining the sequence of operations and contingency plans, all present should beclearly aware of the extent to which their own area of responsibilities may affect, and beaffected by, the special requirements of a perforating operation.

The perforating engineer should have a diagram of the well, clearly indicating the interval(s)to be perforated, the fluids present, the pressures/temperatures expected and the depths,diameters and angles of any changes in the well geometry. There must be no doubt aboutthe method of referencing the top shot and the settings of the tools (e.g. shear pin settings,timer delays, etc.). These must be discussed with the Completions Supervisor and fullyunderstood.

No crane lifts should be made over loaded perforating guns or over the logging cable.

Only essential personnel will be permitted in the vicinity of loaded guns, especially at theloading area, catwalk, drill floor and spider deck. All personnel, except the perforatingengineer, should be clear of these areas while the guns are being armed.

Diving activities are not permitted during the perforating operation.

Electrical Activation

In addition, whenever the gun firing sequence is initiated by electrically operated detonators, thefollowing will apply:

Weather forecasts (two independent sources) must confirm there will be nolikelihood of electrical storms for the duration of the perforating operation.

Offshore, the perforating engineer should remain on the drill floor at all timeswhen TCP guns are in the hole still above ground level.

The perforating engineer must verify there are no stray voltages (greater than0.25 V) between the rig and the casing or riser.

Radio silence must be in force before connecting the firing head and until theguns are 100m below ground level, unless the Schlumberger SAFE firingsystem or similar is used (Refer to section 2)).

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The firing head detonator must not be installed until the Completion Supervisorconfirms to the Perforating Engineer that the rig is on radio silence.

On recovery of the guns, regardless of any indications that the guns have fired,radio silence must be reinstated prior to the guns being retrieved above 100metres below the sea bed. This period will end only after the detonator sub-system has been removed and the perforating engineer has confirmed to theCompletion Supervisor that the guns have been made safe.

No electric/MIG welding is permitted during the perforating operation. Cathodic protection should be shut down and isolated during the period of

radio silence. No diving is to be allowed during perforating. No crane lifts should be made over the wire during perforating, if applicable. No boats should be alongside during perforating. No helicopter landings should be allowed during radio silence. All non-essential personnel should be excluded from the areas affected,

including the gun loading area, the catwalk, the drill floor and the moonpool,around the riser below the drill floor.

5.2. METHODS OF PERFORATING

The perforating procedure is dependent upon the type of gun system used for theapplication in the completion process. The six main methods are:

Wireline-conveyed carrier guns inside casing - perforating overbalance Wireline-conveyed through tubing guns - perforating underbalance TCP run on a temporary well test string - perforating underbalance TCP guns run on the permanent completion string - perforating underbalance TCP guns run on a perforating anchor - perforating underbalance TCP guns run on coiled tubing - perforating underbalance

Common to all perforating operations, a safety meeting should be held before theoperation commences. This is important because perforating will impose restrictions onother rig operations, such as radio silence, diving and use of the cranes. These proceduresare to be used as a guideline. They should be used only in conjunction with other companyprocedures for these operations.

5.3. GENERAL SAFETY PROCEDURES

The following comments are applicable to both TCP and wireline conveyed methods.Additional comments are given in section specific to wireline conveyed perforating.

a) All perforating operations, since they involve the handling and use of explosivesand possibly radioactive materials, require special safety procedures to bestrictly observed at all times.

b) Perforating operations should be carried out strictly according to the safetypolicies of Eni-Agip and the perforating Contractor. In the event of anyinconsistency between policies, the most conservative policy will apply.

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a) Operations involving the use of explosives shall only be performed byContractors specialised personnel responsible for perforation and similaroperations. The number of persons involved shall be as low as possible.

b) Only perforating Contractors personnel are allowed to remain in the hazardousarea (gangway, rig floor etc.) during arming of guns. The number of personnelshould be limited when the guns are within 500ft of surface when tripping in andout of the hole.

c) Any operation involving the use of explosives is not allowed in the presence ofthunder, lighting and thick fog, as these are sources of electric potential.

d) Explosives shall be kept on site for the shortest possible time, any remaining atthe end of the operation shall be removed from the installation.

e) Explosives shall be stored on site in proper containers, within a confined area onthe rig. Detonators shall be stored in separate boxes, in the same area asexplosives.

f) Warning signs must be placed around the hazardous area where explosives areused.

g) All radio transmitters, radio beacons included, within a radius of 500ft from thewell, shall be turned off, (since they may detonate blasting caps), starting fromgun arming until perforating guns are 500ft below the sea bottom (similarly,when pulling guns out of hole and guns above 500 ft). All portable transmitters(both Eni-Agips and Contractors) shall be placed inside the Eni-Agip office andturned off to avoid accidental transmission. Avoid critical periods of perforatingcoinciding with arrival and take-off of helicopters.

h) Cranes and welding machines shall be put out of service starting from gunarming till gun pulling out and unloading.

i) District Office shall be advised by the Well Operations Supervisor on theestimated time of radio silence two hours before starting operations. The RadioOperator shall communicate actual timing.

j) Casing perforating can be performed during daylight or at night. However, thefirst series of shots must be carried out in daylight hours. Before perforatingcasing, the acceptable cement job quality shall be ascertained by means ofCBL/VDL and/or by squeeze jobs.

k) Explosives are to be transported unarmed and clearly labelled to the site insecure and protective containers. Extreme care must be applied during loadingand off-loading.

l) At the rig it is the responsibility of the Installation Manager to ensure that theseprecautions are taken.

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5.4. WIRELINE CONVEYED PERFORATING

There are two alternatives to be considered when perforating using wireline conveyed guns:casing guns and through-tubing guns. In both cases depth control is provided by running aGamma Ray/CCL above the gun, and the guns are fired by electrical signal.

Casing Guns

Casing guns are large diameter perforators which cannot be run through normal tubingsizes. Therefore they must be used prior to running the test string and usually inoverbalance conditions (completion brine or drilling mud). A shooting nipple should be usedwhen using this method.

Through-Tubing Guns

Through-tubing guns are small diameter guns run through the test string. They can be usedto perforate underbalanced, and hence eliminate the risk of damaging the formation withwellbore fluids immediately after perforating. Also, and especially in production situations,they can be run and fired with the well nippled up and intrinsically safe. The gun size whichcan be run is limited by the tubing size.

5.4.1. Casing Guns Run In Overbalance

1) A safety meeting should be held before perforating. The safety aspects of perforatingwith casing guns are:

The well must be stable with an overbalance mud There must be an adequate surface supply of kill fluid The BOPs should have been recently tested Radio silence must be in force before connecting the cable head until the guns

are 100 metres below the sea bed.

On recovery of the guns, regardless of any indications that the guns have fired, radiosilence must be in force before the guns are pulled back past 100 metres below groundlevel and until the cable head is removed.

2) The logging engineer should be given a diagram of the well showing the depths of allrestrictions or changes in diameter.

3) Wireline should be rigged up as per the procedure in the Wireline Procedures Manual.

4) If perforating inside casing ensure the length of the gun assembly is less than thedistance between the blind rams and the grease head.

5) The distance between the top shot and the GR/CCL should be measured. It maysometime no be necessary to run a record the depth by GR or CCL if depth can becorrelated to a sump packer or bridge plug.

6) The logging engineer must not connect the cable head until the Well OperationsSupervisor, or his designated representative, has confirmed that radio silence isinstated.

7) There is no restriction on running speed but care must be taken at any restrictions andwhen applying the brake.

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1) The Logging Engineer must inform the Completion Supervisor, or his designatedrepresentative, when the guns are deeper than 100 metres below ground level.

2) Tie on depth to the CBL/VDL/GR/CCL log. Record a short section of film across theinterval to be perforated showing at least five casing collars and the pup joint at thetop of the reservoir section. The well should be perforated from the bottom upwards.

3) When the gun is on depth and ready to be fired, the logging engineer must inform theWell Operations Supervisor, or his designated representative, and the driller, whoshould observe the well for losses or gains when the gun is fired.

4) Pull out at less than 5,000 ft/hour to avoid swabbing.

5.4.2. Perforating Procedures For Through Tubing Conveyed Guns

This operation will only be done once the cushion has been circulated into place.

Since only the first run can be perforated underbalance, it is common practice to perforate thebest (highest permeability) zone first, otherwise the well should be perforated from the bottomupwards to minimise the chance of picking up debris on the cable.

1) A safety meeting will be held to review procedures and safety, specifically:

The well is in underbalance and will be live after the first run The wireline BOPs should have been pressure tested The surface rig up must be pressure tested before each run Ensure the GR/CCL log across zone of interest is available.

2) The logging engineer should be given a diagram of the well and test string showingthe depths of all restrictions or changes in diameter and he should check that he hassufficient weights for the maximum anticipated wellhead pressure.

3) Rig up wireline for a full bore drift run. Run in the hole and drift the tubing.

Note: Prior to arming the guns, the Offshore Installation Manager will ensurethat conditions for safe operations exist. He should then inform base,standby vessels, supply boats and any relevant persons that the rig ispassing into radio silence.

4) The wireline should be rigged up with the lubricator system, grease flow tubes,hydraulic stuffing box, tool trap, ball check valve and line wiper. Once radio silencehas been obtained, rig up the perforating guns into the lubricator and pressure test.

5) Monitor the pressure in the A annulus.

6) Ensure the surface tree master and swab valves are open and run in the hole with theperforating gun tool string.

7) Correlate the GR/CCL to the original GR log. Record a short section of film across theinterval to be perforated showing at least five casing collars and the pup joint at thetop of the reservoir zone. Do not run down into the perforations on subsequent runs.

8) Position the string at the desired perforating interval and fire the guns.

9) Observe and record WHSIP to confirm the guns have fired.

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1) Pull out of the hole with the perforating string, taking care when passing throughrestrictions.

2) Repeat steps until the total required interval has been perforated. Do not flow the wellwhile pulling the guns back through the tubing to surface.

2. Stop when the guns are at 100 metres below ground level until the CompletionsSupervisor, or his designated representative, confirms that there is radio silence.

1) The gun should be inspected at surface to check that all charges have detonated.Care should be taken as pressure can be trapped by debris behind the gun ports. Afilm record should be made of the job and the explosion register should be updated.

2) Open the well to flow and continue as per the Completion Programme.

5.5. SAFE SYSTEM

The SAFE system was developed for wireline conveyed perforating systems and will beused unless otherwise authorised.

5.5.1 General

There are two types of detonators in general use today:

a) The Electric Detonator or Blasting Cap (which is classed as an Electro ExplosiveDevice).

b) The Percussion Detonator or Percussion Cap.

Both of these systems contain primary high explosives which are initiated by an electriccurrent heating a filament wire in the case of the blasting cap and a direct mechanical shockin the case of percussion cap. The blasting cap can also be initiated by shock as it containsprimary high explosives.

In order to store and handle these detonators, special safety precautions must be taken.These precautions include, in the case of electro explosive devices, the elimination of strayelectric potential differences while arming guns at surface and when returning to surfaceafter perforating.

Stray electric potential differences can originate from:

RF Radiation Impressed Current Cathodic Protection Electric Welding Electric Generators and Motors Lighting Storms.

The SAFE system was developed to preclude the loss of radio communication and othervital equipment during perforating operations.

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5.5.1. SAFE System Description (Slapper Activated Firing Explosives)

The two main components of the SAFE system are the EFI (exploding foil initiator) and theESIC (electronic secondary-explosive cartridge). All the guns are shot from the bottom upwith the exception of the Enerjets and Back-off.

The EFI contains no primary high explosives and so cannot be set off with the application ofheat or mechanical shock.

With the guns on setting depth, DC power( positive or negative) is applied from the surfaceto the ESIC, which steps up the voltage and stores this energy in a capacitor. The capacitoris controlled by a triggering device. When the trigger threshold is reached, the capacitordischarges rapidly into the EFI, thereby initiating the explosion chain.

The SAFE system is based on a series of basic units. These are manufactured in sizesthat allow a range of guns to be fired from 11/16ins to 7ins. Several guns can be runsimultaneously in the hole and selectivity of shooting these is achieved by connecting anESIC cartridge to each gun.

Advantages:

Operates without shutting down radios, electric welding and cathodic protection. Explosive components contain no primary-high explosive. Overall operating time reduced. Operates safely next to radio transmitters and powerlines.

5.6. TCP PROCEDURES

TCP perforating is now the most common method of perforating today as it has manyadvantages over wireline conveyed perforating. These advantages include:

The guns can be made up and run in the hole on the completion string or on anindependent anchor system.

The packer is set and the string fully tested and completed before guns are tobe fired.

The well can be perforated underbalanced to increase the perforating efficiencyfor completion.

Various methods of detonation can be utilised depending on well conditions. Long perforation intervals can be fired in a singe run. Accurate placement and efficient detonation in high deviation wells with

selective zonal perforations can be achieved. Guns and charge size can be maximised for optimum perforating efficiency. Guns can be loaded to perforate specific target intervals.

Perforating systems are available which allow several different intervals to be independentlyperforated and tested during one trip in the hole.

Ensure that the casing/liner has been gauged and junk basket/junk sub trip has been madeprior to running the TCP guns.

Note: If the guns are to be dropped into the sump, it is essential that the depthof the rat hole is sufficient to swallow the guns.

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5.6.1. Well Preparation for TCP Operations

Cleanliness is of prime importance in being able to obtain optimum perforating efficiency.Dirty tubulars and well conditions may lead to serious problems, therefore the followingpoints should be carefully considered.

Clean Casing

This helps prevent problems with packer setting. A bit and scraper run to clean up thecasing and condition the hole is essential, followed by a gauge ring run before TCP guninstallation (Refer to section 4.10). This provides a good clean area for the packer to setand seal off in, hold high differentials and withstand the shock of the gun detonation.

Clean Tubing

This is also a vital factor that assists in a trouble free firing operation. Tubing should alwaysbe rabbited before being run. This prevents any pipe scale, mud cake or general debrisfrom falling down to settle out and create a barrier around and over any firing head orstinger. This is critical if bar drop methods or wireline conveyed firing heads are used.

Any preventative methods employed in the area of scale/dope are strongly recommended.

Clean Fluids

These are important in any perforating operation. By keeping the downhole fluidenvironment as clean as possible, less problems will be encountered later in the operation.As stated above, solids settling out can cause problems/delay/cost, so an emphasis wherepossible on clean, filtered well fluids is essential. Perforation tunnel and near wellboredamage are also a consideration (Refer to the Drilling Fluids Manual for Eni-Agipsrecommended fluids policies, recipes and cost considerations.

BOP Tests

It must be taken into consideration that the perforating/testing and killing procedures maytake a considerable time to conduct, therefore the next scheduled BOP test may berescheduled to take this into account.

5.6.2. Ancillary TCP Equipment

The following is a list of the most common equipment used in conjunction with the gunsections to help installation and firing.

Bullnose

Allows the test string to enter liner tops easily. It may also be ported to allow pressurecommunication with a pressure activated firing head on the bottom of the guns.

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Circulating Sub

This sub is optionally run above the mechanically activated firing head. It is a ported subwhich allows circulation and beneath the ports is a brass or glass disc preventing debrisfrom dropping onto the mechanical firing head. The drop bar must pierce the disc beforepassing on to the firing head. The ported sub acts as a perforated anchor after the gunshave fired.

Gun Drop Sub

If the perforated zone is to be production logged or stimulated with coil tubing a gun dropsub should be incorporated into the string. This releases the guns, which fall into the sumpfor which sufficient sump must be provided. Gun drop subs can be operated; mechanically,using slickline, hydraulically by pressuring up on a dropped ball, or automatically on gundetonation.

The recommended method is to use slickline as it is less complicated and less liable to fail.With any of the methods, it is prudent to make a conformation check run to ensure the gunshave dropped.

Spacer Tubing

Spacer tubing is inserted between the gun drop sub and the top of the guns. The distancebetween the gun drop sub and the top perforation should be at least 50ft if productionlogging is to be performed.

Shock Absorber

This is an optional tool which may be run to protect downhole equipment from the shock ofgun detonation. This is important when, in particular, downhole gauges are run below thepacker. Both radial and longitudinal force shock absorbers are available.

Radioactive Sub

A radioactive tag in a sub should be installed in the string within the proximity of the packer.This sub is used as a marker when performing the GR/CCL correlation for depth control. Ifthe formation has little GR character, radioactive collars can also be included in the casingstring for definitive depth control. If chrome tubulars are being used consideration must begiven to the non magnetic properties of the pipe with regard to the CCL.

TCP String

If using a test string to conduct a shoot and pull procedure, the full range of stringcomponents such as packer, test tubing, tester valve, circulating valves, etc. need to beemployed as per the Company Well Test Manual.

Shot Detection

Shot detection equipment comprises acoustic detectors (hydrophones), vibration detectors(accelerometers) and the normal surface pressure gauges. Using a combination of the datadetected by these sensors it is usually possible to confirm gun detonation.

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5.6.3. Firing Systems for TCP Operations

It is normal practice to run the TCP guns with two firing systems, whenever possible, to improvethe chance of a successful operation especially when running the guns on the bottom of acompletion. A common combination is to use a tubing pressure actuated system as the primarymeans of detonating the TCP guns with a mechanical system as the back up. There are fourmain types of firing mechanisms for TCP guns. Only top down firing mechanisms should beused for safety when arming the guns. The operation of each firing mechanism is:

Tubing Pressure Activated

The guns are fired by pressuring up the test string and then bleeding off the pressureimmediately. A time delay device is incorporated to allow time to bleed off. This device canbe either hydraulic or a slow burning fuse. Some of the firing heads for this system arewireline retrievable which gives another back up option. However, this would preclude theuse of the drop bar system as a back up. Although this technique could be expensive onnitrogen, it is well suited to the use of a nitrogen cushion but the time delay on the systemwill have to be increased to allow time for the nitrogen cushion to be bled off.

Mechanical Impact

The TCP guns are detonated by the mechanical impact of a firing bar, which for safety mustbe run on wireline. (This system is colloquially known as the drop bar system.) Since thesystem can be affected by debris in the tubing, the completion fluid must be kept clean. Thesystem is preferred as a back up instead of the primary firing mechanism because of theneed to use wireline.

Electrically Activated

With this system, the guns are fired with an electrically-initiated detonator which must be runon a logging cable. Therefore the pressure control system must be rigged up. Since aninductive or wet electrical connection must be made at the firing head, the system is alsosusceptible to debris. T

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