ENI - Completion Procedures Manual

ARPO

ORGANISING DEPARTMENT

ENI S.p.A. Agip Division

TYPE OF ACTIVITY'

ISSUING DEPT.

DOC. TYPE

REFER TO SECTION N.

PAGE.

OF

STAP

P

1

M

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192

7120

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 a CD-Rom version can also be distributed (requests will be addressed to STAP Dept. in Eni - Agip Division Headquarter) Date of issue:

28/06/99

„ ƒ ‚ • € Issued by

REVISIONS

M. Bassanini 28/06/99

C. Lanzetta 28/06/99

A. Galletta 28/06/99

PREP'D

CHK'D

APPR'D

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

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INDEX 1.

2.

3.

4.

INTRODUCTION

9

1.1.

PURPOSE OF THE MANUAL

9

1.2.

IMPLEMENTATION

9

1.3.

UPDATING, AMENDMENT, CONTROL & DEROGATION

9

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

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 3.5.1. Guidance For Permits

16 16

3.6.

WELL HANDOVER PROCEDURES 3.6.1. Well Handover Certificate 3.6.2. Well Intervention Handover Certificate

17 17 18

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 4.5.1. Displacement Objectives 4.5.2. Logistical Considerations 4.5.3. Drilling Fluid Preparation 4.5.4. Surface Equipment Preparation 4.5.5. Well Clean Up Pill Sequence 4.5.6. Pill Functions 4.5.7. Pit Requirements 4.5.8. Pumping Sequence

24 24 25 25 26 26 27 27 27

4.6.

DISPLACEMENT OF WATER BASED MUDS 4.6.1. Drilling Fluid Preparation 4.6.2. Surface Equipment Preparation 4.6.3. Well Clean Up Pill Sequence 4.6.4. Pill Functions 4.6.5. Pit Requirements 4.6.6. Pumping Sequence

28 28 28 28 29 29 29

4.7.

COMPLETION AND WORKOVER FLUIDS 4.7.1. Brines Transportation 4.7.2. Completion And Workover Fluid Quality

29 29 30

4.8.

FILTRATION SYSTEMS 4.8.1. Fluid Cleanliness

30 30

4.9.

LOST CIRCULATION 4.9.1. Viscous Pills 4.9.2. Sized Salt Pills 4.9.3. Calcium Carbonate Pills

31 31 31 32

4.10. CASING GAUGE CONTROL

33

PERFORATING PROCEDURES

34

5.1.

GENERAL

34

5.2.

METHODS OF PERFORATING

35

5.3.

GENERAL SAFETY PROCEDURES

35

5.4.

WIRELINE CONVEYED PERFORATING 5.4.1. Casing Guns Run In Overbalance 5.4.2. Perforating Procedures For Through Tubing Conveyed Guns

37 37 38

5.5.

SAFE SYSTEM 5.5.1. SAFE System Description (Slapper Activated Firing Explosives)

39 40

5.6.

TCP PROCEDURES 5.6.1. Well Preparation for TCP Operations 5.6.2. Ancillary TCP Equipment 5.6.3. Firing Systems for TCP Operations 5.6.4. General TCP Safety Precautions and Running Procedures 5.6.5. Firing Procedure for Tubing Installed Pressure Activated Head 5.6.6. Firing Procedure for Wireline Installed Pressure Activated Head 5.6.7. Firing Procedure for Mechanical Impact Activated Head 5.6.8. Firing Procedure for Electrically Activated TCP Guns 5.6.9. Procedure For TCP Anchor Running 5.6.10. TCP Anchor Firing Head Installation

40 41 41 43 44 45 45 45 46 47 48

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5.7.

MISFIRE PROCEDURES 5.7.1. Mechanical Firing Head 5.7.2. Hydraulic Firing Head 5.7.3. Fixed Hydraulic Firing Head 5.7.4. Retrievable Hydraulic Firing Head

51 51 52 53 53

5.8.

COILED TUBING PERFORATING

53

GRAVEL PACKING PROCEDURES

54

6.1.

GRAVEL PLACEMENT OBJECTIVES

54

6.2.

SCREEN SIZE

54

6.3.

GRAVEL CALCULATIONS 6.3.1. Sand Volume Required 6.3.2. Carrier Fluid Volume

55 55 56

6.4.

COMMON GRAVEL PACK PROCEDURES

56

6.5.

OPEN HOLE GRAVEL PACK PROCEDURE

57

6.6.

CASED HOLE GRAVEL PACK PROCEDURE

59

PACKER INSTALLATION

64

7.1.

HOLE PREPARATION

64

7.2.

WIRELINE PACKER SETTING PROCEDURE 7.2.1. Running Procedure

64 65

7.3.

TUBING INSTALLED PACKER SETTING PROCEDURE 7.3.1. Workstring Running Procedure 7.3.2. Completion String Running Procedure

66 66 67

COMPLETION INSTALLATION

68

8.1.

CARBON STEEL AND PLASTIC COATED TUBING

68

8.2.

CHROME TUBULARS 8.2.1. Transportation 8.2.2. Transport From The Mill 8.2.3. Road Transport 8.2.4. Marine Transport 8.2.5. Handling At The Wellsite 8.2.6. Thread Compounds 8.2.7. Running Chrome Tubulars 8.2.8. Retrieving Chrome Tubulars

68 68 69 69 69 69 71 72 73

8.3.

EQUIPMENT PRE-INSTALLATION PROCEDURES 8.3.1. Material Requisition Lists 8.3.2. Completion Sub Assemblies 8.3.3. Tubing Hanger 8.3.4. Landing Joint 8.3.5. Control Line 8.3.6. Xmas Tree 8.3.7. Flowline

74 74 74 75 75 75 75 76

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8.4.

COMPLETION ASSEMBLIES 8.4.1. Workshop Make-up and Test Procedures 8.4.2. Sub-Surface Safety Valves 8.4.3. Wireline Nipple Assemblies 8.4.4. Side Pocket Mandrels

76 76 76 77 77

8.5.

COMPLETION RUNNING PROCEDURES 8.5.1. General 8.5.2. Running Procedure 8.5.3. TRSCSSV Installation Procedure 8.5.4. WRSCSSV Installation Procedure

78 78 79 80 81

8.6.

XMAS TREE INSTALLATION 8.6.1. Installation Procedures

82 82

8.7.

POST COMPLETION TEST PROCEDURES 8.7.1. SCSSV Test Procedure 8.7.2. Xmas Tree Valve Test Procedure

83 83 83

GAS LIFT INSTALLATION

85

9.1.

MANDREL INSTALLATION 9.1.1. SPM Installation Procedure 9.1.2. Gas Lift Valve Installation Procedure

85 85 87

9.2.

UNLOADING PROCEDURE

88

9.3.

TROUBLESHOOTING

88

10. DOWNHOLE PUMP INSTALLATION

89

10.1. ELECTRICAL SUBMERSIBLE PUMPS 10.1.1. Handling 10.1.2. Installation 10.1.3. Pulling Procedure 10.1.4. Troubleshooting

89 89 89 93 93

10.2. ROD PUMPS 10.2.1. Completion Installation 10.2.2. Tubing String Installation 10.2.3. Rod Installation

96 96 96 98

10.3. HYDRAULIC PUMPS 10.3.1. Jet Pump 10.3.2. Turbine Pump 10.3.3. Piston Pump

98 99 101 101

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11. SUBSEA COMPLETIONS

102

11.1. SUBSEA EQUIPMENT PRE-DEPLOYMENT TESTING 11.1.1. Guidewire Establishment Tool 11.1.2. Guidewire Latchess 11.1.3. Diverless Guideposts 11.1.4. Casing Hanger Elevation Test Tool 11.1.5. Tubing Hanger System 11.1.6. Tubing Hanger Running/Orientation Tools 11.1.7. Tubing Hanger Verification Tool 11.1.8. Tubing Hanger Isolation Plugs 11.1.9. Subsea Tree And Workover Equipment 11.1.10. Install the LRP/TRT onto the XT 11.1.11. Production Riser 11.1.12. Surface Xmas Tree

103 103 103 103 104 104 106 109 110 110 115 117 118

11.2. DEPLOYMENT PROCEDURES 11.2.1. Running The Completion And Tubing Hanger 11.2.2. Pull The Drilling BOPs

118 118 120

11.3. WORKOVER AND PRODUCTION CONTROLS SYSTEM PRE-DEPLOYMENT TESTING 11.3.1. Workover Controls Equipment 11.3.2. Production Controls Equipment 11.3.3. WOCS Pre-Deployment Testing 11.3.4. Production Controls Pre-Deployment Testing 11.3.5. Function Test using SEM B 11.3.6. Pressure Test Tree Valves

120 120 120 121 124 128 131

11.4. RUNNING THE SUBSEA XMAS TREE 11.4.1. Unplugging The Well 11.4.2. Perforating And Well clean-Up

136 136 137

11.5. PULLING THE LRP 11.5.1. Disconnect The LRP And Tree Running Tool

137 137

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 13.1.1.

PREPARATION

142 142

13.2. SAFETY CONSIDERATIONS 13.2.1. Tubing 13.2.2. Risers and BOPs 13.2.3. H2S Considerations

142 143 143 144

13.3. PERMIT REQUIREMENTS

144

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13.4. RIG UP PROCEDURES 13.4.1. Equipment Preparation and Siting 13.4.2. Coiled Tubing Rig-Up 13.4.3. Pressure Testing 13.4.4. Treating Lines 13.4.5. Injector Frame 13.4.6. Rigging Down

145 145 145 146 148 148 148

13.5. RUNNING PROCEDURES

149

13.6. OPERATING PROCEDURES 13.6.1. Gas Lifting 13.6.2. Well Treatment 13.6.3. Sand Cleanout

150 150 151 153

14. NITROGEN PROCEDURES

155

14.1. PREPARATION

155

14.2. SAFETY CONSIDERATIONS

155

14.3. NITROGEN HANDLING 14.3.1. Safety Equipment 14.3.2. Safety Data Sheets 14.3.3. Pressurised Lines

156 156 157 157

14.4. RIG-UP PROCEDURES 14.4.1. Equipment Preparation and Siting 14.4.2. Equipment Rig-up 14.4.3. Pressure Testing 14.4.4. Treating Lines 14.4.5. Rigging Down

157 157 157 158 158 158

14.5. NITROGEN TREATMENT PROCEDURES 14.5.1. Pressures 14.5.2. Pump Rates 14.5.3. Coiled Tubing Gas Lift 14.5.4. Nitrogen Cushion - Tubing Conveyed Perforation 14.5.5. Nitrified Treatment

159 159 159 159 160 161

14.6. NITROGEN TECHNICAL INFORMATION

161

14.7. EMERGENCY PROCEDURES (During Nitrogen Operations) 14.7.1. Production Shutdown 14.7.2. General Platform Alarm 14.7.3. Prepare to Abandon Platform 14.7.4. Liquid Nitrogen Spill 14.7.5. Injury to Personnel

162 162 162 162 163 163

15. STIMULATION PROCEDURES

164

15.1. INTRODUCTION

164

15.2. SAFETY CONSIDERATIONS 15.2.1. Chemical Handling 15.2.2. Pressure

164 165 166

15.3. PERMIT REQUIREMENTS

167

15.4. RIG-UP PROCEDURES 15.4.1. Equipment Preparation and Siting 15.4.2. Equipment Rig-Up

167 167 168

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15.4.3. 15.4.4. 15.4.5.

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Pressure Testing Treating Lines Rigging Down

168 169 169

15.5. TREATMENT PROCEDURES 15.5.1. Matrix Acidising 15.5.2. Fracture Acidising 15.5.3. Acid Wash 15.5.4. Scale Dissolver 15.5.5. Bullhead 15.5.6. Coiled Tubing 15.5.7. Asphaltene and Wax/Dissolvers

169 170 170 170 170 171 171 171

15.6. STIMULATION TECHNICAL INFORMATION 15.6.1. Factors Affecting Acid Reaction 15.6.2. Acid Properties

171 172 174

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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INTRODUCTION

1.1.

PURPOSE OF THE MANUAL

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The purpose of the Completions Procedures Manual is to guide technicians and engineers, involved in Eni-Agip’s Drilling & Completion worldwide activities, through the Procedures and the Technical Specifications for general completion operations which are part of the Corporate Standards. Such Corporate Standards define the requirements, methodologies and rules that enable to operate uniformly and in compliance with the Corporate Company Principles. This, however, still enables each individual Affiliated Company the capability to operate according to local laws 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 common guidelines in all areas worldwide where Eni-Agip operates. It is intended to guide users towards using procedures which have been found to provide the 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-Agip’s completion and workover operations are expected to make themselves familiar with these and comply with the policies 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 by the Corporate Company, in accordance with the development of Eni-Agip Division and Affiliates operational experience. Accordingly, it will be the responsibility of everyone concerned in the use and application of this manual to review the policies and related procedures on an ongoing basis. Locally dictated derogations from the manual shall be approved solely in writing by the Manager of the local Drilling and Completion Department (D&C Dept.) after the District/Affiliate Manager and the Corporate Drilling & Completion Standards Department in Eni-Agip Division Head Office have been advised in writing. The Corporate Drilling & Completion Standards Department will consider such approved derogations for future amendments and improvements of the manual, when the updating of the document will be advisable.

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RESPONSIBILITIES The following job descriptions outline the individual responsibilities and duties of specific key personnel involved in Eni-Agip Completion operations. These are generalised summary of the individual responsibilities and duties which are specific to completion operations and as such augment, but do not supersede their current employer’s approved job descriptions.

2.1.

DRILLING COMPLETION AND WORKOVER MANAGER The Drilling/Completions and Workover Manager reports directly to the District Manager and supervises the Well Operations Superintendent, Completions and Workover Superintendent, Drilling Engineering/Completions and Workover Engineering. His duties include the following: •

• • • • • •

Ensuring the definition of scope of work and requisitioning of drilling and completion/workover contracts are correctly processed by the contracts department and approved first by the District Manager, in order to comply with time schedule, quality and technical conditions as defined in the programme. Ensuring the pre-qualification and technical tender evaluation phases comply with company policies and procedures and to provide the Contracts department with all technical details necessary for a thorough commercial evaluation. Approving the completions programmes, ensuring they fully meet the prognosis target, pursuing the best results in terms of safety, time schedule and cost effectiveness. Managing day-to-day completions operations, co-ordinating the activities of contractors and units/positions involved, in order to guarantee that operations meet the company policies and standards. Controlling operational costs and provides the technical approval for invoice payment. Verifies the consistency of the expenditure with AFEs and with the administration validity of the contracts. Liaising, timely and effectively, with the regulatory bodies in order to obtain consent for well related operations. Instituting, monitoring and reviewing completions safety policies within the Safety Management System, in order to maximise effectiveness and safety of the operations.

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WELL OPERATIONS SUPERINTENDENT The Well Operations Superintendent reports to the Drilling, Completion and Workover Manager and supervises rig site supervisors. His duties include the following: • • • • • • • • •

2.3.

Ensuring operational progress follows the approved well programme and provides technical advice to the rig site on a daily basis, as required. Ensuring the correct scheduling of completion materials and services, provides a timely supply to the rigs while optimising the cost of transport, materials and manpower within established programmes and budgets. Administering service contracts, providing the technical control of contractor performance giving the first authorisation to the payment of invoices and ensuring the control of current total expenditure on each contract. Ensuring that operations comply with current legislation and company standards. Preparing scopes of work and technical specification for services to be tendered and review those for services and equipment. Providing technical advice during pre-qualification and tender evaluation phases, in order to ensure that the selection of contractors and suppliers fully meet technical targets and company standards. Providing timely and accurate requisitions for all services and materials relevant to well operations. Ensuring, in liaison with AQS, the correct interface of the Contractor’s procedures are to Eni-Agip’s policies and procedures. Ensuring simultaneous completion and production procedures are reviewed.

COMPLETION AND WORKOVER ENGINEER Reports to the Drilling, Completion and Workover Manager. His duties include the following: • •

• • •

Preparing and reviewing technical specifications and scopes of work for equipment to be tendered and services for completion, workover, wireline and well testing operations. Co-operating with the Well Operations Superintendent for providing advice during pre-qualification and tender evaluation phases, in order to ensure that the selection of contractors and suppliers fully meet technical targets and company standards. Supplying well cost estimates for future operations budgets and current operations AFEs, ensuring the reliability of the data provided. Contributing, in liaison with the Petroleum Engineer and with the Reservoir Engineers, to the planning of development projects, providing technical input to the project teams, in order to optimise cost and effectiveness of the project. Monitoring, in liaison with the Petroleum Engineer and with the Reservoir Engineers, the performance of wells and reservoirs, in order to provide technical expertise and advice for identifying and initiating enhancements to well potential.

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Appraising new completion, workover, wireline and well testing technology and products to determine their application to Eni-Agip’s completion operations, in order to improve time cost performance and safety conditions. Preparing and reviewing completion, workover, wireline and well testing programmes and final reports and to ensure the production of adequate feedback about the operations as per the Safety Management System corporate requirements. Reviewing daily the operations versus the programme, providing a thorough investigation of operational times. Providing engineering assistance to the Well Operations Superintendent in the follow up of operations. Providing reports and analysis on the operated and non-operated activities for presentation, meetings and reporting to the management and to ensure the operational feedback reporting system is consistent with Eni-Agip and corporate requirements. Assisting his supervisor in contacts with partners and regulatory bodies providing the necessary documentation and reports. Providing the monthly updates on the variance between actual and estimated expenditures for each job centre for each class of cost, also to liaise with the Completion/Workover Superintendent, in order to update the expenditure on each contract. Ensuring the production and review of the Completions Procedure Manual in order to comply with company policies and the current legislation.

FLUIDS SPECIALIST Reports to the Drilling, Completions and Workover Manager for routine operational matters. His duties include the following: • • • • • • •

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 evolution’s 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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OFFSHORE INSTALLATION MANAGER (OIM) If applicable, his duties include the following: • •

• • •

2.6.

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 own discipline and must keep the OIM informed on their own respective operations. The Production Supervisor will keep the OIM informed on the status of production operations. Authorise all work permits in accordance with the Permit to Work System, and will ensure countersignature by the Well Operations Supervisor, or other Discipline Heads. For completion operations, he will delegate responsibility to the Well Operations Supervisor or another Company Representative (e.g. Production Supervisor) as dictated by asset ownership or control at the time of the ongoing operations. Is responsible for the actions to be followed under the various installation operating modes. The OIM will require advice from the Well Operations/Production Supervisor or other Discipline Heads, e.g. Maintenance Supervisor, etc.

WELL OPERATIONS SUPERVISOR Represents Eni-Agip’s interests on the installation with respect to the Drilling Contractor and Service Companies. The Senior Well Operations Supervisor is directly responsible for the drilling and completion equipment and all operations conducted during the drilling completion and workover phase. His duties include the following: • • • • •

• •

Ensuring all Company policies relating to drilling and completing operations and emergency situations are adhered to at all times for the safety of personnel, rig equipment, well stability and control. Directing the Drilling Contractor and Service Company representatives in the operations to be performed and supervises the conduct of the operations. Ensuring all operations, detailed in the Drilling and Completion Programme, are performed efficiently and safely using the procedures detailed in the programme and/or Completion Procedures Manual. Responsibility for the Hot Permit System when ‘hot work’ is being conducted in the drilling module. Requisitioning the equipment and materials required to complete the operations. He will requisition the materials when appropriate and liaise with the Completion and Workover Superintendent to ensure arrival at the rig-site in ample time to allow inspection and preparation prior to use. Ensuring all tools are suitable for purpose, inspected and dressed prior to running in the well. Introducing changes to the Drilling and Completion Programme but only in an emergency or when operating conditions do not allow for communication with the Drilling and completion Workover Department.

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Ensuring all reports required, are accurate in content and are submitted as required. Reporting requirements are outlined in section 3. Liaising with the OIM, Company Production Supervisor, and other operational Heads on a daily basis to discuss operational considerations and the possible impact on the other operations. Supervising and directs well control operations in accordance with the Eni-Agip Well Control Manual. Liaising with the OIM to give advice on what actions to take, if any of the Platform Operating Modes are associated with the drilling operation, or arise from operations in the drilling module. On completion of the programme, i.e. Xmas tree is secured with all operations completed, officially handing over the well to the Production Department (Production Supervisor). Both parties must sign the relevant well handover document. Co-ordinating all completion activities including wireline and/or coil tubing/nitrogen, acid stimulation, perforating as well as all preliminary pressure testing of equipment. Ensuring the safe and correct installation of all tubulars and completion subassembly components, i.e. in the correct order and proper depth as per the completion programme.

PRODUCTION SUPERVISOR Reports to the Company Production Superintendent (Office). His duties include the following: • • • •

Representing Eni-Agip’s interests on the platform with respect to production, and when dealing with service companies involved with operations during the production 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 on the status of the production operations and the possible impact on other operations in general. Prior to a workover being carried out, handing the well over to Drilling/Completion (Well Operations Supervisor) stating the exact condition of the well. Both parties must sign the handover document.

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

3.1.

PRELIMINARY INFORMATION Before performing any well operations the following documentation and information must be available: A detailed programme including: • • • • • • • • •

3.2.

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.

WELLSITE REPORTS To schedule future operational programmes, all operations must be properly documented and 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 gravel packing, 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 then check 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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OTHER REPORTS The Eni-Agip Representative must sign the Service Reports of the Service Companies which must include the following information : • • • • • • •

3.5.

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.

PERMIT PROCEDURES No work can be performed without a valid permit to work. All requirements as laid out in the Company Permit to Work Procedures must be adhered to at all times. Although the operation of a permit system is the responsibility of the installation manager, safe operating practice is compulsory and the responsibility of all personnel involved in completion operations. The Permit to Work System is drawn up in accordance with standard Oil Industry practices in order to improve offshore safety during all phases of operations. All personnel involved in completion operations should clearly understand the particular installation Permit to Work System, and be aware that the issuing of a permit in itself cannot guarantee that any job is safe. As each installation will have its own distinct PTW system according to the type of installation, location and country, it is not possible to describe a generic system in this manual.

3.5.1.

Guidance For Permits Examples of activities which require permits to work (hot and cold) must listed in Permit to Work 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 Permit to Work System from time to time as circumstances dictate. It remains the responsibility of the Area Authority to ensure that the correct permits and certificates are in force during all phases of operations. The responsibilities of those individuals involved in the administration of the Permit to Work System should be clearly defined in the Permit to Work Procedures.

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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 will be the responsible person for production operations. The Production Supervisor will be the competent person during Xmas tree repairs or change-outs even when these works are performed by maintenance personnel with the assistance of a vendor service engineer. The action of transferring the responsibility for a well between area authority will be documented and recorded on the ‘Well Handover Certificate’ or ‘Well Intervention Handover Certificate’. All preparatory work and the status of the well when handed over will be described in the appropriate Handover Certificate. A typical example of a Handover Certificate (Eni-Agip) with the information to be recorded is shown in figure 3.a and figure 3.b. The completed Handover Certificate must be signed by the responsible persons handing over and receiving the well. It must be placed in the appropriate well file. Copies are to be faxed to the Well Operations Superintendent when a new well is handed over. There are two types of Well Handover Certificates: • •

3.6.1.

Well Handover Certificate Well Intervention Handover Certificate.

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 department will complete a Well Handover Certificate. Prior to handover of the well to Production, 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 will sign the handover certificate in acceptance of the well. Examples of Well Handover Certificates 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 of any 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 Operations department will complete a Well Handover Certificate. Prior to handover of the well to Production 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 will sign 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 will complete a Well Intervention Handover Certificate and ensure the following procedures are completed: 1) 2)

3) 4) 5)

All chemical injection lines on the flowline will be bled down and isolated. The test and production, or injection, header isolating valves will be closed, and the flowline bled down to the closed drains and isolated when no liquid or gas is observed at the sample point. Blind flanges should be installed on the flowline termination. The SCSSV control lines will be bled off ready to be disconnected. All lines from the wellhead to the remote control panel will also be bled down. If the tree is to be removed all instrumentation and control lines will be removed from the well. 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 he will 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 Well Handover Certificate. Prior to handover of the well to Production, 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 will sign the Well Intervention Handover Certificate in acceptance of the well. An example of a Well 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

Tubing Size

Tubing Grade

Condition

Producing or Injecting

Tubing Fluid

Shut in Wellhead Pressure

Date last on line

SAFETY VALVE DETAILS String

Valve Open or Closed

Type

Date Last

Remarks

Tested

TUBING PLUG DETAILS String

Plug Type

Depth

Date Tested

Test Pressure

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

Swab Valve

Manual Master

Hydraulic Master

Hydraulic Wing

Manual (prod)

Manual (kill)

Wing

Status

Wing

ANNULUS DETAILS Annulus

Pressure

Fluid

Status e.g. Shut-in, Open, Venting, Seized Valves, etc.

Flowline Status: ADJACENT WELLS Well No

SCSSV Status

Plugs Tested

Date

Status

Tested

Date

All Production/Operations equipment removed from area ?

Depth

Xmas Tree

Flowline

Status

Status

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 CERTIFICATE Well No:

Date:

Well Details : Producer/Injector :

Single/Dual String :

Permit Order No: Description of Operation BARRIERS REQUIRED

BARRIERS REMOVED (SITE TIDY) SAFETY VALVE DETAILS

Handover String

Status**

Handback Remarks**

String

Status**

Remarks**

XMAS TREE DETAILS Handover Valve

Status **

Handback Valve

Valve

Status **

Status **

Valve

Prod Side

Ann Side

Prod Side

Ann Side

Flow Wing

Man Wing

Flow Wing

Man Wing

Choke

Status **

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 DETAILS Handover Annulus

Pressure

Handback Fluid

Above P-Off

Status

Annulus

Pressure

Fluid

Status

Above P-Off

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

Detail

Depth

Handback Remarks

String

Detail

Depth

Authorised By : Production/Well Services

Authorised By : Production/Well Services

Accepted By :

Accepted By :

Time/Date :

Production/Well Services

Production/Well Services

Time/Date :

Figure 3.C - Example Handover Certificate (Continued)

Remarks

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HOLE PREPARATIONS The procedures in this section described the preparation of the hole and surface facilities for completion operations.

4.1.

PRELIMINARY CHECKS Sometime prior to completions operations, the following equipment should be checked to confirm availability and to specification for the forthcoming operations: a) b) c) d) e) f)

g) h) i) 4.2.

Workstring of the appropriate grade and size in sufficient length, taking into consideration if a tapered string is to be used. BOPs are equipped with the correct size-pipe/variable (single or dual) rams to cover all the range of tubulars to be run in the hole. Wear bushing for the tubing hanger spool, equipped with the running/pulling tool. BOP test tool with the appropriate running and pulling tools and a sufficient quantity of seals. All relevant handling tools for the workstring including elevators and slips verifying they are in good working condition. Safety valves have been tested and are available already made up with the crossovers to the workstring and Weco connections to suit the kill line connection. The rig has been equipped with the safety and emergency systems as per the contract and that they are fully operational. Rig pumps are equipped with the appropriate liner sizes and that they have been tested. Mud logging or monitoring system is installed and operational.

WELL CLEAN UP PROCEDURES After the production casing, or liner, has been cemented in place, a bit and scraper assembly will be run. The purpose of this trip is to clean out any excess cement within the casing, and particularly to remove any cement that may be on the casing wall at the packer setting depth. A suitably sized bit, or junk mill, and tandem scraper assembly will be run to clean out the casing or liner of any excess cement, and to scrape the intended perforated interval(s). The packer setting depth will also be scraped during this operation to ensure it will have a good setting area. Precise details of packer setting depths, perforation intervals and maximum clean 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 an inflow test on liner laps and shoe tracks performed.

For detailed procedures on how to perform inflow and pressure tests refer to the Drilling Procedures Manual. If a liner lap is a found to be leaking it may be necessary to run a tie back packer into the top 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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BOP STACK CONFIGURATION AND TESTING a)

The BOP stack configuration including ram sizes should be in accordance with the Well Programme.

b)

All components must be fully certified and will be tested with water in accordance to company policy or local regulations, whichever is the most stringent. testing on a new completion will be accomplished by using either the test tool or the tubing hanger with the tubing hanger plug installed.

c)

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

d)

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

e)

The test schedule will be according to local regulations but will be at least every 14 days. If operational constraints prevent a scheduled pressure test, a dispensation 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 the charts held in file.

g)

In workover operations prior to pulling the tubing, the BOP stack will be tested against 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.

WELL CONTROL Well control procedures will be in accordance with the Company Well Control Policy Manual, 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 the drilling mud from the well. In order to ensure that circulation time, rig time and filtration time are kept to an absolute minimum, it is essential that the well clean up is as efficient (and economical) as possible in removing the mud, solids and any other associated debris in the well.

4.5.1.

Displacement Objectives • • • • • • •

Displace oil based mud out of the well with a minimal interface between the oil based 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.

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

4.5.3.

a)

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

b)

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

c)

Pit space requirements for mud and brine and the permits required for cleaning the appropriate pits and lines.

d)

The equipment required to install and operate the filtration equipment.

e)

Personnel requirements and available accommodation.

Drilling Fluid Preparation 1)

2)

3)

4)

5)

6)

Pick up the workstring with scrapers placed in it to ensure that the liner or casing packer setting depths are thoroughly scraped during the trip. Once on bottom, bottoms up should be circulated to remove any additional debris. Circulate and condition the oil based mud with oil mud thinner or oil wetting agent in order that the yield point and gel strengths are reduced but not to a point where the fluid loses the ability to keep barite/drilled solids in suspension. Typically, the yield point should be reduced to 12 lbs/100 ft2 and the 10min gel to <15 lbs/100 ft2. The actual quantity of material required to do this must be determined by pilot testing performed by the mud engineer to determine the most cost effective treatment. Throughout the drilling fluid conditioning process, the flow rate used should be the maximum practical rate. At a very minimum, the circulation rate should be just within the turbulent flow regime. Whilst conditioning the mud, the drill string should be reciprocated and rotated. The combined effect of the scrapers being run in the hole, the high flow rate and the reciprocation/rotation will help to remove/disperse large quantities of mud solids and general debris. The reciprocation stroke should be +/-30ft and the rotation speed should be +/-15rpm. Near the end of the conditioning operation, temporarily shut down the pumps and stroke each set of pipe rams to clear any debris from the ram cavities except any pipe rams which are smaller than the workstring. Continue circulation to remove the debris. During this operation, as much of the surface volume of mud should be removed from the pits to accommodate the completion fluid and the well clean up chemicals. Once the mud has been back-loaded, surface preparation can be carried out.

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4.5.4.

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Surface Equipment Preparation As much of the surface volume of mud should be sent back to the base leaving only one tank into which the mud returned from the displacement can be dumped: 1)

2)

3)

4)

5) 6) 7)

8) 4.5.5.

Wash and scrub all of the pits and storage tanks designated for the completion fluid with steam cleaners. Once the top and sides are scrubbed, the bottom of each tank should be swept to the suction line and the contents sent to a contaminated fluid storage pit. All pits, sandtraps, gumbo traps, flowlines, ditches and in particular areas where the accumulation of solids can be overlooked such as underneath lines and grates, above and behind angle irons, in the corners and crevices of beams should all be thoroughly cleaned. Once everything has thoroughly been cleaned, fill one pit with fresh water and add the recommended volume of surfactant/flocculant. Agitate the pit to keep the product dispersed. Circulate the surfactant/flocculant pill at the maximum possible flow rate (for +/20mins) throughout the entire surface system including all pits, pumps, lines or other areas that the completion fluid may contact. Provided the water is not contaminated it can be dumped. If the water is contaminated, it should be diverted to a pit designated for contaminated fluid. As before, the pits should all be swept clean and dry. Once all of the above has been done, dump valve seats should be inspected and replaced wherever necessary and then guided into place to ensure they seal properly before filling with brine. Once sealed, all dump valves should be locked shut.

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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Pill Functions a)

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

b)

The solvent pill has a solvating action on oil based mud residue and filter cake residue. This is the main pill for actually removing the mud residue. It should not be mixed with any water or base oil to cut it back as this reduces the efficiency of the pill.

c)

The surfactant/flocculant pill is used as a chemical flocculating agent to dislodge any residue loosened by the solvent. A large pill is required to ensure adequate contact time to remove all solids.

d)

The viscous detergent pill is a detergent pill used to convert the surfaces into a water wet state.

Pit Requirements Pits/storage tanks will be required for the following:

4.5.8.

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.

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 correct contact times for the various pills. Seawater should be pumped until returns are clear (1-2 circulations) after which time the seawater 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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DISPLACEMENT OF WATER BASED MUDS The displacement of a water based to a clear fluid is an easier procedure requiring fewer steps. 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) 2) 3)

4.6.1.

Drilling Fluid Preparation 1)

2) 3) 4)

4.6.2.

Transportation for taking well clean up chemicals, brine and filtration equipment/ consumables to the rig. Personnel requirements. Surface equipment cleaning.

The mud properties should be reduced to the levels specified for oil based mud, namely YP of 12 lbs/100 ft2 and 10min gel <15 lbs/100 ft2. The most cost effective method of treatment is by adding water to the system. However, this should only be done under the direction of the Mud Engineer and only after pilot testing. As per section 4.5.3. As per section 4.5.3. The surface volume of water based mud can be dumped overboard (providing the constituents allow) as can the mud returns from the displacement.

Surface Equipment Preparation Same as section 4.5.4.

4.6.3.

Well Clean Up Pill Sequence The following is the normal sequence for pumping the various fluids and pills. a)

Drill water/caustic pill.

b)

Surfactant/flocculant pill.

c)

Viscous detergent pill (un-weighted).

d)

Water, pump until returns are below 60 NTU (usually 1-2 circulations).

e)

Viscous pill, using the completion brine as the base fluid.

f)

Filtered completion brine.

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4.6.4.

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Pill Functions a)

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

b)

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

c)

Detergent pill is a polishing pill to ensure all downhole surfaces are thoroughly cleaned prior to pumping the seawater.

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.

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 correct contact 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 be inspected for cleanliness and dryness. Note:

Boat manifolds may contain residual materials that could contaminate the brine. Therefore all manifolds, pumps, etc. that will be involved in brine delivery will be thoroughly flushed and dried.

Brine will not be loaded onto a vessel or truck until the Company’s responsible person is satisfied that the brine will arrive at the rig site with the same clarity, density, and solids content as originally loaded. Samples of the brine will be taken during the loading operation from the loading tanks and the vessel's receiving tanks or truck. The volume, density and clarity of the fluid after loading must be identical to the fluid from the suppliers tanks. Prior to transferring the brine to the installation from the tanks all hoses, connections, dump valves, 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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Completion And Workover Fluid Quality The quality of the fluid used during a completion and workover operation cannot be overemphasised as the productivity is governed not only by the damage caused by visible contaminants such as solids but also the damage caused by invisible contaminants such as calcium ions, sulphate ions and dissolved iron. It is, therefore, essential that all of these and other similar contaminants are controlled to as low a level as feasible and, wherever possible, completely removed (Refer to the Drilling Fluids Manual). Other contaminants such as iron and sulphates can be controlled on surface by chemical treatment but can be avoided altogether by ensuring that the quality of the fluid supplied is correct, the quality of all the sacked and drummed material meets the required specification and 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, if any fluid is in contact with the formation, it is both clean and filtered. A fluid in any other condition 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 for use as a downstream guard filter. Sometimes, on standby is a low pressure, Cartridge Filter unit. 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 loading which can be removed using various different grades of DE to form a porous, permeable filter cake on a filter cloth. The nature of the DE is such that it must be added using a ‘safe handling system’ to ensure that there is a totally dust free environment thereby eliminating any hazard to the operator or any other personnel in the vicinity. On no account should loose DE be used.

4.8.1.

Fluid Cleanliness Before filtering, all the tanks should be thoroughly cleaned out and any mud residues washed 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 of cleanliness. Normal specifications are: • • •

By laser particle counter: By turbidity meter: By centrifuge:

< 250ppm total undissolved solids < 20NTU < 0.01% by volume solids.

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LOST CIRCULATION The use of lost circulation materials may be necessary if the well has suffers any serious fluid losses as can be experienced such as on open hole, gravel pack or wells which are perforated prior to running the completion, etc. The types of LCM pills preferred for the various uses from slow seepage to high losses in particular situations are fully described in the Drilling Fluids Manual along with the formulations and placement procedures. Prior to using an LCM pill, consideration will be given to reducing the hydrostatic head by reducing the brine weight (with drill water) and so reduce the level of losses. This will only be 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 minimise potential damage to producing formations. Some of the most common LCM pills used in completion 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 a base and adding a predispersed liquid viscosifier to increase the funnel viscosity according to the well programme. The addition of a predispersed liquid viscosifier is preferable as it will yield rapidly without forming ‘fish eyes’ which may cause a problem when it comes time for the removal of the pill downhole. There are both advantages and disadvantages is using high viscosity pills for controlling fluid loss. These are as follows: 1)

Advantages • • •

2)

Disadvantages • •

4.9.2.

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.

They are limited normally to temperatures <280 F. They are only effective in low permeability formations where seepage losses are low to moderate (<1.5 - 2bbl/min).

Sized Salt Pills The actual composition of the sized salt pill will be determined primarily by the porosity, permeability and temperature of the formation to be bridged. Sized salt pills must be formulated in a saturated brine base to prevent solution of the bridging material. A typical formulation for a sized salt pill in a 10ppg sodium chloride brine is as follows: Volume Formulation

per bbl - Vol. as required Saturated Brine 0.94bbl Bridgesal Plus 500lbs

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Notes: 1) 2)

3) 4)

The above formulation will give a final weight of 10.5ppg assuming that a 10ppg NaCl brine is used as the base. If a higher density is required, the formulation will require modification by the addition of FL-7 Plus and Watersal A. The specific formulation will be determined by the Fluids Engineer on the rig. However, typical formulations are as follows (see table below). Mixing order of products should be listed. A small amount of defoamer is required (0.2gal/bbl) to minimise foaming.

Composition* Saturated Brine (bbl) Bridesal Plus (lbs/bbl) FL-7 Plus (lbs/bbl) Watersal A (lbs/bbl) 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 4.9.3.

Density

Density

Density

11 ppg

12 ppg

12.5 ppg

0.88 40 2 57

0.75 30 4 164

0.69 30 4 210

30 35 8 10 7.4

62 61 10 13 7.1

77 67 11 14 7.2

Calcium Carbonate Pills Calcium carbonate can be used as a drilling fluid and for LCM pills to control fluid losses. In completion operations it is now the most commonly used fluid for controlling fluid losses within 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 to provide the ideal mixture for the formation pore size. The calcium carbonate uses a viscous pill as a carrier (Refer to section 4.9.1 above). Typical of a calcium carbonate fluid is Baker Hughes Inteq’s reservoir drill-in fluid system called ‘Perflow’ that is designed to lower overall well completion costs while improving longterm production rates. Used as a drill-in fluid, Perflow maintains the properties of a drilling fluid while protecting the well's pay zone against damage. It provides lubricity, inhibition, solids suspension, cuttings removal, and wellbore stability. In its protective role, the fluid bridges on pore openings exposed to the wellbore, remains intact during completion and workover operations, and is easily removed with production. The system's performance has made it effective in a number of wellsite applications. These applications 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 workover operations. While other fluids require costly processes for removal, removal is simply accomplished by flowing the well. The system utilises very pure calcium carbonate with a broad particle size distribution to effectively bridge the pore openings of the formation. The bridging agent and polymer chemistry form a thin filter cake to protect the pay zone from damage caused by fluid invasion. The filter cake is effectively removed by low break-out pressures, leaving no significant residual material to inhibit the well's production. Before using a calcium carbonate pill, any potential damaging effects from the calcium carbonate needs to be assessed as any particles trapped in pore spaces can only be removed by an HCl acid treatment. 4.10.

CASING GAUGE CONTROL Prior to running any completion equipment, it is necessary to ensure the hole is within gauge 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 a size according to the casing drift size. It is normal practice to run the gauge ring in conjunction with a junk basket after the well clean out procedure. The junk basket is run to catch 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 further scraping. It is extremely important that the casing is drifted as the sticking of completion equipment can incur high costs in retrieval, loss or damage to equipment and may even cause a side-track.

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5.

PERFORATING PROCEDURES

5.1.

GENERAL

0

Two methods are currently used to perforate wells: wireline conveyed guns and tubing conveyed guns (Refer to the Completion Design Manual). In the drive to obtain maximum perforating efficiency, tubing conveyed perforating is the preferred method for most completion operations as the zones to be tested can be perforated underbalanced in one run with a large size charges, if possible. However, under some circumstances wireline conveyed guns may still be preferred. The procedures for both methods are described in the following sections. The type of explosive to be used will depend mainly on the bottom hole temperature and the length of time the guns are likely to be on bottom before firing. Refer again to the perforating section in the Completions Design Manual and to suppliers technical specification sheets. The BOPs and the rig manifolds should have undergone a recent full programme of pressure testing. At the safety meeting, the perforating operation should be discussed in fine detail. Apart from outlining the sequence of operations and contingency plans, all present should be clearly aware of the extent to which their own area of responsibilities may affect, and be affected 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 about the 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 fully understood. 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 the loading area, catwalk, drill floor and spider deck. All personnel, except the perforating engineer, 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, the following will apply: • • • •

Weather forecasts (two independent sources) must confirm there will be no likelihood of electrical storms for the duration of the perforating operation. Offshore, the perforating engineer should remain on the drill floor at all times when TCP guns are in the hole still above ground level. The perforating engineer must verify there are no stray voltages (greater than 0.25 V) between the rig and the casing or riser. Radio silence must be in force before connecting the firing head and until the guns are 100m below ground level, unless the Schlumberger SAFE firing system or similar is used (Refer to section 2)).

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The firing head detonator must not be installed until the Completion Supervisor confirms 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 100 metres below the sea bed. This period will end only after the detonator subsystem has been removed and the perforating engineer has confirmed to the Completion 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.

METHODS OF PERFORATING The perforating procedure is dependent upon the type of gun system used for the application 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 the operation commences. This is important because perforating will impose restrictions on other rig operations, such as radio silence, diving and use of the cranes. These procedures are to be used as a guideline. They should be used only in conjunction with other company procedures 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 explosives and possibly radioactive materials, require special safety procedures to be strictly observed at all times.

b)

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

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a)

Operations involving the use of explosives shall only be performed by Contractor’s specialised personnel responsible for perforation and similar operations. The number of persons involved shall be as low as possible.

b)

Only perforating Contractor’s personnel are allowed to remain in the hazardous area (gangway, rig floor etc.) during arming of guns. The number of personnel should be limited when the guns are within 500ft of surface when tripping in and out of the hole.

c)

Any operation involving the use of explosives is not allowed in the presence of thunder, 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 at the end of the operation shall be removed from the installation.

e)

Explosives shall be stored on site in proper containers, within a confined area on the rig. Detonators shall be stored in separate boxes, in the same area as explosives.

f)

Warning signs must be placed around the hazardous area where explosives are used.

g)

All radio transmitters, radio beacons included, within a radius of 500ft from the well, shall be turned off, (since they may detonate blasting caps), starting from gun 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-Agip’s and Contractors) shall be placed inside the Eni-Agip office and turned off to avoid accidental transmission. Avoid critical periods of perforating coinciding with arrival and take-off of helicopters.

h)

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

i)

District Office shall be advised by the Well Operations Supervisor on the estimated time of radio silence two hours before starting operations. The Radio Operator shall communicate actual timing.

j)

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

k)

Explosives are to be transported unarmed and clearly labelled to the site in secure and protective containers. Extreme care must be applied during loading and off-loading.

l)

At the rig it is the responsibility of the Installation Manager to ensure that these precautions are taken.

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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 a Gamma 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 tubing sizes. Therefore they must be used prior to running the test string and usually in overbalance conditions (completion brine or drilling mud). A shooting nipple should be used when using this method. Through-Tubing Guns Through-tubing guns are small diameter guns run through the test string. They can be used to perforate underbalanced, and hence eliminate the risk of damaging the formation with wellbore 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 which can 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 perforating with 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, radio silence must be in force before the guns are pulled back past 100 metres below ground level and until the cable head is removed. 2) 3) 4) 5)

6)

7)

The logging engineer should be given a diagram of the well showing the depths of all restrictions or changes in diameter. Wireline should be rigged up as per the procedure in the Wireline Procedures Manual. If perforating inside casing ensure the length of the gun assembly is less than the distance between the blind rams and the grease head. The distance between the top shot and the GR/CCL should be measured. It may sometime no be necessary to run a record the depth by GR or CCL if depth can be correlated to a sump packer or bridge plug. The logging engineer must not connect the cable head until the Well Operations Supervisor, or his designated representative, has confirmed that radio silence is instated. There is no restriction on running speed but care must be taken at any restrictions and when applying the brake.

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The Logging Engineer must inform the Completion Supervisor, or his designated representative, when the guns are deeper than 100 metres below ground level. Tie on depth to the CBL/VDL/GR/CCL log. Record a short section of film across the interval to be perforated showing at least five casing collars and the pup joint at the top of the reservoir section. The well should be perforated from the bottom upwards. When the gun is on depth and ready to be fired, the logging engineer must inform the Well Operations Supervisor, or his designated representative, and the driller, who should observe the well for losses or gains when the gun is fired. Pull out at less than 5,000 ft/hour to avoid swabbing.

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 the best (highest permeability) zone first, otherwise the well should be perforated from the bottom upwards to minimise the chance of picking up debris on the cable. 1)

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

2)

3) Note:

4)

5) 6) 7)

8) 9)

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.

The logging engineer should be given a diagram of the well and test string showing the depths of all restrictions or changes in diameter and he should check that he has sufficient weights for the maximum anticipated wellhead pressure. Rig up wireline for a full bore drift run. Run in the hole and drift the tubing. Prior to arming the guns, the Offshore Installation Manager will ensure that conditions for safe operations exist. He should then inform base, standby vessels, supply boats and any relevant persons that the rig is passing into radio silence. 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 silence has been obtained, rig up the perforating guns into the lubricator and pressure test. Monitor the pressure in the ‘A’ annulus. Ensure the surface tree master and swab valves are open and run in the hole with the perforating gun tool string. Correlate the GR/CCL to the original GR log. Record a short section of film across the interval to be perforated showing at least five casing collars and the pup joint at the top of the reservoir zone. Do not run down into the perforations on subsequent runs. Position the string at the desired perforating interval and fire the guns. Observe and record WHSIP to confirm the guns have fired.

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Pull out of the hole with the perforating string, taking care when passing through restrictions. Repeat steps until the total required interval has been perforated. Do not flow the well while pulling the guns back through the tubing to surface. Stop when the guns are at 100 metres below ground level until the Completions Supervisor, or his designated representative, confirms that there is radio silence. 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. A film record should be made of the job and the explosion register should be updated. Open the well to flow and continue as per the Completion Programme.

SAFE SYSTEM The SAFE system was developed for wireline conveyed perforating systems and will be used 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 Explosive Device).

b)

The Percussion Detonator or Percussion Cap.

Both of these systems contain ‘primary high’ explosives which are initiated by an electric current heating a filament wire in the case of the blasting cap and a direct mechanical shock in the case of percussion cap. The blasting cap can also be initiated by shock as it contains primary 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 stray electric potential differences while arming guns at surface and when returning to surface after 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 other vital equipment during perforating operations.

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SAFE System Description (Slapper Activated Firing Explosives) The two main components of the SAFE system are the EFI (exploding foil initiator) and the ESIC (electronic secondary-explosive cartridge). All the guns are shot from the bottom up with the exception of the Enerjets and Back-off. The EFI contains no primary high explosives and so cannot be set off with the application of heat or mechanical shock. With the guns on setting depth, DC power( positive or negative) is applied from the surface to the ESIC, which steps up the voltage and stores this energy in a capacitor. The capacitor is controlled by a triggering device. When the trigger threshold is reached, the capacitor discharges rapidly into the EFI, thereby initiating the explosion chain. The SAFE system is based on a series of ‘basic units’. These are manufactured in sizes that allow a range of guns to be fired from 11/16ins to 7ins. Several guns can be run simultaneously in the hole and selectivity of shooting these is achieved by connecting an ESIC cartridge to each gun. Advantages: • • • •

5.6.

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.

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

The guns can be made up and run in the hole on the completion string or on an independent anchor system. The packer is set and the string fully tested and completed before guns are to be fired. The well can be perforated underbalanced to increase the perforating efficiency for 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 independently perforated and tested during one trip in the hole. Ensure that the casing/liner has been gauged and junk basket/junk sub trip has been made prior to running the TCP guns. Note:

If the guns are to be dropped into the sump, it is essential that the depth of the rat hole is sufficient to swallow the guns.

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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 following points should be carefully considered. Clean Casing This helps prevent problems with packer setting. A bit and scraper run to clean up the casing and condition the hole is essential, followed by a gauge ring run before TCP gun installation (Refer to section 4.10). This provides a good clean area for the packer to set and 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 always be rabbited before being run. This prevents any pipe scale, mud cake or general debris from falling down to settle out and create a barrier around and over any firing head or stinger. 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 fluid environment 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 where possible on clean, filtered well fluids is essential. Perforation tunnel and near wellbore damage are also a consideration (Refer to the Drilling Fluids Manual for Eni-Agip’s recommended fluids policies, recipes and cost considerations. BOP Tests It must be taken into consideration that the perforating/testing and killing procedures may take a considerable time to conduct, therefore the next scheduled BOP test may be rescheduled 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 gun sections to help installation and firing. Bullnose Allows the test string to enter liner tops easily. It may also be ported to allow pressure communication 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 sub which allows circulation and beneath the ports is a brass or glass disc preventing debris from dropping onto the mechanical firing head. The drop bar must pierce the disc before passing on to the firing head. The ported sub acts as a perforated anchor after the guns have fired. Gun Drop Sub If the perforated zone is to be production logged or stimulated with coil tubing a gun drop sub should be incorporated into the string. This releases the guns, which fall into the sump for 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 gun detonation. 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 guns have dropped. Spacer Tubing Spacer tubing is inserted between the gun drop sub and the top of the guns. The distance between the gun drop sub and the top perforation should be at least 50ft if production logging is to be performed. Shock Absorber This is an optional tool which may be run to protect downhole equipment from the shock of gun detonation. This is important when, in particular, downhole gauges are run below the packer. 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. If the formation has little GR character, radioactive collars can also be included in the casing string for definitive depth control. If chrome tubulars are being used consideration must be given 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 string components such as packer, test tubing, tester valve, circulating valves, etc. need to be employed 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 data detected by these sensors it is usually possible to confirm gun detonation.

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Firing Systems for TCP Operations It is normal practice to run the TCP guns with two firing systems, whenever possible, to improve the chance of a successful operation especially when running the guns on the bottom of a completion. A common combination is to use a tubing pressure actuated system as the primary means of detonating the TCP guns with a mechanical system as the back up. There are four main types of firing mechanisms for TCP guns. Only top down firing mechanisms should be used 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 pressure immediately. A time delay device is incorporated to allow time to bleed off. This device can be either hydraulic or a slow burning fuse. Some of the firing heads for this system are wireline retrievable which gives another back up option. However, this would preclude the use of the drop bar system as a back up. Although this technique could be expensive on nitrogen, it is well suited to the use of a nitrogen cushion but the time delay on the system will 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 must be run on wireline. (This system is colloquially known as the drop bar system.) Since the system can be affected by debris in the tubing, the completion fluid must be kept clean. The system is preferred as a back up instead of the primary firing mechanism because of the need to use wireline. Electrically Activated With this system, the guns are fired with an electrically-initiated detonator which must be run on a logging cable. Therefore the pressure control system must be rigged up. Since an inductive or wet electrical connection must be made at the firing head, the system is also susceptible to debris. This system is rarely used on well tests as the only is that the firing heads for this system are wireline retrievable, hence the guns can be run unarmed and, in the case of a misfire, the firing head can be recovered on wireline to determine the cause of the misfire. Retrievable Slickline Firing Head This type of head was primarily designed to overcome the concerns over about the possibility of guns being denoted by stray pressure or tools/debris/unnamed articles which could fall down through the tubing string and force the detonating pin into the initiator. With this type of head, this possible problem has been completely eliminated due to the design of the system. The guns are run in the hole without the firing head. Then, when ready to arm the guns, the head is run to depth on slickline and latched on to the firing stem or stinger. This system provides its own back-up in that if the firing head does not work, it can be retrieved and a replacement run. Retrievable firing heads are available with mechanical, hydraulic or electric triggering.

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General TCP Safety Precautions and Running Procedures A safety meeting should be held before running the guns. The following safety aspects of perforating with TCP guns should be discussed: • •

• • •

The well is underbalance and will be live after firing. Radio silence must be in force before connecting the firing head until the guns are 100 metres below ground level. On recovery of the guns, regardless of any indications that they have past 100m below ground level until the firing head is removed. A 3m spacer should be installed on top of the gun so that it will be armed with the guns below the rig floor. Firing heads must be removed before the guns are pulled back above the drill floor. The guns must include a pressure bleed off so that any trapped pressure can be released.

Running procedure 1)

2)

3)

4) 5)

6)

7) 8) 9)

10) 11)

The elevators should be changed out to match the special lift sub and the correct slips for the gun size must be used together with a dog clamp. The perforating engineer will provide a list of the correct torque for each component of his equipment. After clearing the area of non-essential personnel, pick up the guns on a tugger with the special lift sub. The guns are made up just as tubing singles but avoid mechanical shock because the internal carriers can be displaced. Check the booster positions and 'O' rings before making up guns. The firing head delay will have previously been set according to the test programme and agreed by the Perforating Engineer. Before connecting the firing head, clear the drill floor and cellar deck areas of all nonessential personnel. A spacer sub must be installed so that the top shot is well below the rig floor when the gun is armed. Do not pull the gun back above the drill floor once the firing heads are installed. Run the rest of the test string but take special care that no debris shall fall down on top of the firing head. If tubing is in poor condition, ensure it is cleaned and rabbitted to remove all loose rust and scale. The string must be run without jarring to avoid premature detonation because most firing heads use shear pins. Run the string to set the guns approximately on depth. Rig up the main logging cable and run a gamma ray logging tool down to the correlation depth. Tie on depth to the reference log and record sufficient film to show both radioactive pip markers and any zones of gamma ray character on the log. The required spacing out should be calculated according to the completion installation procedures in section 8.5. Set the packer and land the completion string. If there is any doubt about the space out, re-run the gamma ray tool to ensure that the guns are set on depth.

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Install the surface equipment (Xmas tree or flowhead) and pressure test as per the well programme. Circulate the cushion into place and line up the well to flow.

Firing Procedure for Tubing Installed Pressure Activated Head Complete the steps in section 5.6.4. 1) 2) 3) 4)

5) 6) 5.6.6.

Start recording wellhead pressure. Pressure up on the tubing with the cement pump, or with the nitrogen unit, if a nitrogen cushion is employed. Hold the pressure for one minute. Close the kill wing valve and bleed off pressure via the choke manifold to provide the desired underbalance. If there are no indications that the guns have fired after a reasonable amount of time, re-pressure up the string in stages to 1,000 psi above the firing pressure, observe for leak off then bleed back to the underbalance. If there are still no signs of gun detonation after a further hour, use the back up firing system. Continue with the completion programme.

Firing Procedure for Wireline Installed Pressure Activated Head The procedure for perforating with a wireline retrievable pressure operated firing head is exactly the same as that in section 5.6.5 except that the head is run into the receptacle after the string has been installed and pressure tested. In the event that there is no indication of firing with this system, the head is simply retrieved for checking and another head reinstalled.

5.6.7.

Firing Procedure for Mechanical Impact Activated Head Complete the steps in section 5.6.4. 1) 2) 3) 4) 5) 6) 7)

Rig up the slickline lubricator. Ensure that there is sufficient weight on the wireline toolstring and inspect/clean the firing bar impression nose. Pressure test the lubricator, equalise, open the tree valves and run into the hole. Slow down 100m above the debris barrier and very gently tag the barrier confirming the depth reading. Pull back up and run in at moderate speed to break the debris barrier. Start recording the wellhead pressure which may be rising due to the string contents warming up; establish the trend. Run in at reasonable speed to detonate firing head. The slickline operator should note the depth and time.

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5.6.8.

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If there are definitive signs of the guns firing, continue pulling out. If there are no indications of detonation, check the tag depth of the firing head to check for debris. If there is debris, attempt to jar through it. If there is no debris, observe the well for 30min, after which if there is no change, jar down twice again before pulling out. Pull the tool back into the lubricator. Close the tree upper master valve and bleed off pressure through the flowline. •

3) 4)

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Close the swab valve and recover and inspect the firing bar impression nose. If there is an impression, it is very likely that the guns have fired. But if there is no impression of the firing head then the string is blocked by debris. If there is a back up firing system, it should be employed. Otherwise reverse circulate or attempt to bail the well.

Rig down the wireline lubricator system. Continue with the completion programme.

Firing Procedure for Electrically Activated TCP Guns Complete the steps in section 5.6.4. 1) 2)

3) 4) 5) 6) 7)

8) 9)

10)

Rig up the electric wireline lubricator, double BOPs, grease flowtube, stuffing box, tool catcher, ball check valve and line wiper. Ensure that there is sufficient weight on the wireline toolstring. If the firing head is to be run as well as the wet connection activator, radio silence and the other safety procedures must be observed until it is 100m below ground level. Pressure test the lubricator against the swab valve. Equalise, open the tree valves and run in the hole. Slow down 100m, start recording the wellhead pressure which may be rising as the string contents warm up, establish the trend. Run in and tie on depth with the casing collar locator. Latch onto the firing head, and detonate the guns. The winch operator should note the depth. If there are indications of gun detonation, continue pulling out. If there are no indications of detonation, check the latch depth of the firing head to check for debris. If there is debris, the logging engineer may attempt to jar through it. If there is no debris, observe the well for 30min, after which if there is no change, attempt to relatch and fire the guns, before pulling out. Pull the tool back into the lubricator. Close the upper master valve and bleed off through the flowline. If a wireline retrievable firing head was used, pull it, observing the radio silence precautions when it is above 100m below ground level. If this is not possible, employ the back up firing system. Continue with the programme.

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Procedure For TCP Anchor Running General 1) 2) 3) 4) 5) 6)

There is no requirement for radio silence in the use of hydraulic firing heads. A hot work permit is required. A cold work permit may be required. A safety meeting should be held to advise all relevant personnel of the required procedures. Clear all non-essential personnel from the rig floor and lower deck level. Use barriers and warning signs to keep all non essential personnel away from the danger area.

Pick Up Procedure Refer to figure 5.a TCP Anchor System. 1)

2)

3) Note:

4) 5)

The guns should be pre-loaded and spaced, and laid out in numerical order on the pipe rack. The bottom gun (#1) should be next to the catwalk and the top gun, hanger and firing system furthest away. The 20ft section gun will be lifted up the V-door by the platform crane, using slings double wrapped. Alternatively, if lift subs are attached to the guns, single joint elevators and an air winch may be used. Do not lift by means of the thread protectors. Never move a gun section that does not have protection on each connection. Use a tag line to guide the guns. The guns will be lifted in numerical order, with the bottom gun (#1) being lifted first and the firing system last.

TCP Anchor Make Up The TCP contractor will have a detailed procedure for make up and arming the guns and firing system used. The following are to be used as a guide only: 1) 2) 3) Note:

With the gun set in the slips, the TCP representative will visually inspect to see if the booster is correctly aligned, and check the height using a measuring gauge. The guns should be made up using 36 ins pipe wrenches or chain tongs. Rig power tongs will not be used to make up the gun assembly. The guns will be supported using drill collar slips and dog collar as backup. The dog collar must always be made up prior to unlatching the elevators. (As the gun assemblies have no external set up) Radioactive sources are present within the gun. These pip tag positions have been labelled on the outside of the carrier and no contact should be made at these markings by the rig crew. (Radiation levels will be monitored by an Instruments Engineer)

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Make up the anchor assembly complete with setting tool and a 27/8 ins EUE pup joint. Make up a 30ft joint of 27/8in EUE tubing, crossover and RA marker sub. Check gun assembly weight. In order to prevent surging or mechanical shock when running or pulling armed guns, running speeds should be restricted, particularly through downhole restrictions. The guns should be handled carefully at all times to avoid shock, and time taken to make connections etc. Slips should be set gently. In bad weather, use tag lines when lifting. Try to keep the lift subs clean. Do not set a gun down on an unprotected pin.

TCP Anchor Setting Procedure Refer to figure 5.a TCP Anchor System. 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16)

Run the guns in the hole on drill pipe. When entering the guns into a liner, great care must be taken prior to and entering the TCP anchor. Continue to run into depth. Set the slips. Rig up wireline and run in with a GR/CCL. Correlate the guns on depth. Pull out of the hole and rig down wireline. Re-latch the elevators and move the string to position the guns on depth. Mark the pipe at the rotary table (re-check string weight). 7 Move up the string to a more workable level and drop in the /16ins ball into the work string (the ball falls at around 1,000 ft/5 mins in brine). Make up a circulating head or top drive onto the work string. Re-position the string on depth and start to pressure up the string once the ball has seated. Increase the pressure using the cement unit to set the anchor and release setting tool. Re-check the string weight up and down. Gently slack off weight to lightly tag the top of the anchor (6,000lbs approx.). Pick up string weight plus 5ft. Pump a slug and pull out of hole.

5.6.10. TCP Anchor Firing Head Installation Pre-Installation checks 1) 2) 3) 4) 5) 6) 7)

Rig up slickline lubricator and pressure test against swab valve. Run in hole with dummy firing head sinker bars and spang jars to ensure clear path. Continue slowly running in the hole and stop 30ft above the receptor. Pull up and record pull weight. Continue to run in hole and locate receptor and jar down gently to get an imprint on the lead insert. Pull out of the hole and confirm latch by checking for receptor impression. If no problem is encountered proceed as follows.

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Running Procedure 1) 2) 3) 4) 5) 6) 7) 8)

Note:

9)

Rig up slickline lubricator and pressure test against swab valve. Care must be exercised not to exceed the minimum shear pin rating of the firing head. Run in with firing head, sinker bars and spang jars. Continue slowly going in the hole and stop 30ft above the receptor. Pull up and record pulling weight. Continue to run in hole and locate receptor and jar down gently to latch confirm latch by over pulling 300-500lbs above pulling weight. Jar down to release firing head. Recover toolstring to surface. Before commencing the pressuring up operation, the shot detection chart recorder should be set and running. Tubing pressure can now be applied to fire the guns. Pressure the tubing steadily up to the predetermined level to shear the pins (upper limit), hold for 1 min, then bleed off swiftly to the required tubing pressure (for correct underbalance). Once the pins have sheared, the hydraulic time delay begins and the guns will fire when the delay is complete. If no shot is detected, wait 11/2 times the estimated delay. Slowly increase the tubing pressure until the pressure below the packer is just above formation pressure. Shut in the well and monitor for fluid leak-off. If there is no leak-off into the formation, increase tubing pressure to the tubing test pressure or leak-off pressure, whichever is lower.. Hold briefly and bleed off swiftly to the required underbalance pressure and continue 1 to monitor for firing. If no shot is detected after 1 /2 times estimated delay, resort to secondary firing system.

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Figure 5.A- TCP Anchor System

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5.7.

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MISFIRE PROCEDURES In the event of any total misfire or no-fire of the perforating guns, it is imperative that the perforating contractor is contacted immediately. The perforating contractor should, after assessing the sequence of events, prepare a detailed procedure for recovery of the guns.

5.7.1.

Mechanical Firing Head 1) 2)

3)

Due to the nature of the mechanical system, the guns can be fired during any subsequent fishing operations and this should be taken into account. Adequate time should be allowed for the detonating bar to reach the firing head before a misfire is suspected. Allow twice the estimated time. If the guns do not fire, it is probably due to the detonating bar hanging up on debris on top of the firing head, or in a restriction further up the tubing. Once a misfire has been established fishing operations will commence in an attempt to fire the guns. Record the following data: • • • • •

4)

OD of fishing neck ID of the smallest restriction in the string Depth of the firing head. Length of the detonating bar Distance from the top of the firing head to the communication ports in the tubing.

Ensure that the following slickline tools are available and on site: • • • •

Overshot designed to catch the fishing neck 11/4 ins OD bailer 11/4 ins lead impression block Chisel point bailer bottom for the 11/4 ins bailer.

5)

Make sure that the length of the lubricator is adequate to accommodate the toolstring and the length of the detonating bar if recovered.

6)

Confirm the distance from the firing head to the ports in the tubing string. This should be sufficient to allow both the toolstring and detonating bar to remain below the ports.

7)

Rig up slickline and prepare the toolstring with an overshot to catch the detonating bar. When running in hole confirm the fluid level in the well. Record this depth. Shot detection equipment will be used and it should be monitored during all fishing operations and attempts to fire the guns. When the detonating bar is located, spud down as hard as possible. Do not pick up straight away. If the bar moves, chase it to the firing head as quickly as possible. This will ensure that the slickline tool will not be above the entry ports (should the guns fire) and be blown up the well. Repeat this process three times. If the guns do not fire fish the detonating bar and pull out of the hole. Rig up with 11/4 ins bailer and ‘Chisel Point’ bailer bottom. The bailer should be dressed to a sharp point.

8) 9) 10)

11) 12)

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3) 4) 5) 6) 7)

9) 10) 11)

5.7.2.

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Run in the hole and jar down as hard as possible on the firing pin. Again ensure that the toolstring does not get pulled above the entry ports. Pull out of the hole and inspect the leading edge of the chisel point. Damage will indicate whether or not something hard (firing pin or foreign object) is being struck. Carefully observe for any material recovered in the bailer, it may indicate what is preventing the detonating bar from reaching the firing pin. Fine black powdery deposits are an indication that the guns have fired and will be associated with a smell of burnt cordite. Hydrocarbons may also be present. Repeat bailing operations until it is certain that the bailer is striking the firing pin. If it becomes obvious that the bailer is striking something other than the firing pin, run a lead impression block. Check the fluid level in the well during every wireline run. Monitor carefully for losses/gains. When it has been determined that the firing pin has been struck, and the guns have not fired, pull out of the hole with the drop bar. In the event that a retrievable head has been used, this should be retrieved at this point and inspected. • •

8)

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If it has not fired, run another firing head on slickline and repeat the procedure. If the head has fired, rig down wireline.

Top up the well with fluid, and if not already done so, rig up circulating lines from the cement unit to the production string. Attempt to pump into the formation to confirm that the guns have not fired. The leak-off pressure should be taken into consideration. Unseat the packer and circulate the well contents to kill fluid. Circulate and condition the brine. Prepare to pull the completion and retrieve the guns. Once the firing head has been retrieved the guns are safe, and can be pulled from the well. If it proves impossible to retrieve the detonating bar, the string and guns will have to be pulled. This is potentially very hazardous. Refer to base and seek the advice of the TCP gun manufacturer and senior Company personnel. No further action should be taken without written instructions endorsed by all parties concerned.

Hydraulic Firing Head The hydraulic firing head (tubing pressure) is normally run with a time delay to allow underbalance conditions to be re-established after the tubing pressure is increased. 1) 2) 3) 4)

If no indication of the guns firing is observed, twice the duration of the time delay should be allowed before repeating. If the guns will not fire at the design pressure, increase the pressure (in increments of 500 or 1,000psi) and re-apply, allowing twice the time delay before repeating. Monitor any fluid gains or losses. Monitor the shot detection equipment. In the event that it is established that the guns will not fire, the TCP representative on location will evaluate the situation in conjunction with the Well Operations Supervisor. Both Eni-Agip and the TCP company onshore will be consulted. A detailed procedure will be prepared based on the current status of the operation, prior to any further action.

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Fixed Hydraulic Firing Head With this type of firing head, a misfire is potentially the most hazardous situation and both Eni-Agip and the TCP contractor operations management staff must endorse any further instructions or procedures for recovery of the guns.

5.7.4.

Retrievable Hydraulic Firing Head The firing head must be recovered using slickline, thus disarming the guns prior to their recovery. The TCP contractor will at this point must provide a procedure based on the current status of the operation. Once the firing head has been recovered, the guns are entirely safe and can be retrieved from the well.

5.8.

COILED TUBING PERFORATING Perforating procedures using coiled tubing has been extensively employed to fully take advantage of perforating long intervals underbalanced and possibly in high angle or horizontal wells. The procedures used are contractor equipment and field specific and need to be drafted for each individual situation.

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GRAVEL PACKING PROCEDURES There are two gravel pack applications, one for open hole completions and the other for inside cased hole. This section contains the common procedures for both open hole and internal gravel packing. For perforating gun applications and gun design options, refer to the Company Completions Design Manual.

6.1.

GRAVEL PLACEMENT OBJECTIVES It is imperative that the perforation tunnels and the screen to casing annulus, or screen to open hole annulus, be completely filled with clean, highly permeable gravel pack sand. In addition a gravel reserve above the top perforation should be created to allow for any settling of the pack that may occur. Completely filled perforation tunnels and annular areas result in minimal pressure losses through the gravel packed completion, which in turn enables maximum productivity. While pumping the gravel pack slurry, after it passes the crossover tool, there are only two paths for the carrier fluid to flow. One flow path for the fluid is through the gravel pack screen then returning to surface. The other flow path for the fluid is through leak off to the formation. In internal gravel packs, carrier fluid leak off to the formation through the perforations is essential to carry the gravel pack sand into and efficiently pack off the tunnels. If insufficient leak off is caused, the perforations will not be filled with gravel pack sand. However on the other hand, if excessive leak-off is encountered, the gravel pack sand may bridge prematurely in the annulus, resulting in voids throughout the length of the gravel pack. These voids may fill from above due to gravity settling of the pack but if the voids do not fill with gravel pack sand, two results may occur: • •

6.2.

Produced sand will erode holes in the screen and the gravel pack will fail. The voids will fill with much lower permeability formation sand and productivity will be reduced.

SCREEN SIZE The sand grade used in gravel pack designs is selected usually to be 5 to 6 times greater size than the average formation sand particle size which is determined by sieving. The space between the wires in a screen are termed the ‘Gauge’ which in turn is selected according to the grade of pack sand the screen must retain. The gauge is usually 0.5 - 0.9. of the smallest pack sand grain. Tables of the various sand grades, grain sizes and recommended screen gauge is available from any of the gravel pack service providers. The OD of the screen is selected according to the production casing size in order that there is enough annulus clearance whilst running and fishing with an overshot, if necessary. The recommended annulus clearance is circa 1.000ins. The Well Operations Supervisor should check the screen clearance and fishing capability before running.

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GRAVEL CALCULATIONS The fluids programme to be used will be detailed in the Completions Programme including pre-pad and slurry recipes. The slurry and sand volumes contained in the programme need to be verified before the gravel pack operations using the calculations given below.

6.3.1.

Sand Volume Required The first stage of a sand volume calculation is to prepare a spreadsheet with information about the well geometry and should focus on the spaces to be occupied by pack sand. The standard issue of pack sand is in 100lb sacks which occupies 1ft3, therefore the volume of the spaces should also be calculated in ft3. This calculation depends on whether it is an open hole or internal gravel pack job and if a sump packer is used. Open Hole Step 1 Calculate the total annular volume outside the screen to the planned height of the sand: Total Annular Volume = Screen/Hole Annulus + Blank Pipe/Hole Annulus + 40-60ft volume surplus If the planned sand height was up into the casing, this reduced volume would need to be considered. Step 2 Calculate the volume of sand in the rat hole, if applicable: Hole volume below screens. Step 3 Calculate total sand required: Add the calculated volumes from steps 1 and 2. Internal Step 1 Calculate the annular volume outside the screen to the planned height of the sand: Screen/Casing Annulus + Blank Pipe/Casing Annulus + 40-60ft volume surplus Step 2 Calculate the volume of sand in the rat hole, if applicable: Hole Volume below screens Step 3 Calculate the volume required for the perforations: Length of Perforations x Volume factor (usually 1ft3/ft) Calculate total sand required: Add the calculated volumes from steps 1 2 and 3.

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Total Sand Weight Total Volume ft3 x 100lb/ft3 6.3.2.

Carrier Fluid Volume The weight of carrier fluid is dependent upon the weight of fluid required to control the well. An amount of the carrier fluid is usually set aside for use as pre-pad and sometimes a postpad or push pad to segregate if from the other wells fluids. The pre-pad is normally about 10bbls and the post pad 5bbls. The total volume of the slurry then depends upon how much sand can be carried by the carrier fluid at for that particular weight of fluid to be used. This will be confirmed in the well programme or by the gravel pack technician. The total volume (galls) of slurry then required is simply the total sand volume required divided by the sand carried per gal. Total Slurry Volume (galls) = Total Sand Volume lbs/Sand Volume (lbs per gall) Some of the early part of the gravel pack procedure should be conducted in the squeeze position to pack it into the perforations. If no losses are caused, there will be no sand packed to the end of the tunnels.

6.4.

COMMON GRAVEL PACK PROCEDURES Refer to the well clean up procedures in section 4. 1) 2)

Note:

3)

4) 5) 6)

Thoroughly clean all rig circulating system equipment. Prepare a dedicated active pit for filtered completion fluid. Filter the completion fluid with a Diatomaceous Earth (DE) filter press and downstream absolute cartridge filters to remove all potential damaging particles. Pump from the storage pit and return the filtered completion fluid into the active clean pit. All fluids pumped downhole during the completion phase must be filtered prior to use. Run in hole with casing scrapers and a short open ended tailpipe on workstring. Thoroughly scrape the casing through all intervals to be perforated and all packer setting depths (Refer to section 4.2). Displace the wellbore fluid with the filtered completion fluid. Circulate with filtered completion fluid till returns are clean according to the well programme. Rig up electric line. Make gauge ring and junk basket run to TD. Pull out of the hole with the gauge ring and junk basket, if necessary. Verify screen gauge and gravel delivered is correct according to the well programme.

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OPEN HOLE GRAVEL PACK PROCEDURE The procedure described herein is based on Baker’s gravel pack systems. 1) 2) 3) 4) 5) 6) 7) 8)

Pick up the hole opener and trip to the bottom of the production casing. Establish circulating rates and pressures, then drop the activating ball to open the hole opener. Drill the open hole length with the hole opener. Pull out of the hole. Conduct any stimulation treatment that may be necessary for the particular formation (this may be done post gravel pack, if desired). Ensure the fluid in the hole has been properly filtered and cleaned before running the gravel pack (Refer to section 6.3.2 above). Drift all BHA tubulars including GP equipment and wash pipe. Pick up and assemble the gravel pack assembly in the rotary table as follows, from bottom up, running at a slow speed to prevent damage to the packing element and to prevent prematurely setting the packer. • • •

9)

Run flush joint washpipe inside, and to the bottom of, the screen and blank pipe. The assembly consisting of the following items is then picked up and made up onto the screen assembly. • • • • • • •

10)

11) 12) 13) 14)

Knock Out Isolation Valve Blank pipe Shear Out Safety Joint Indicating Sub Crossover Sub Gravel Pack Extension with Sliding Sleeve Gravel Pack Packer.

The gravel pack service toolstring assembly is then made up to the previous assembly: • • •

Note:

Blank bull nosed plug Sand screens Blank pipe.

Shifting Tool Gravel Pack Crossover Tool Hydraulic Setting Tool. Apply thread compound sparingly to the pin ends of the connections only.

Run in the hole slowly with the completion assembly (90sec per 90ft stand). Set down into, and pick up gently out of, the slips. Record the pick-up and slack-off weights when reaching the packer setting depth. Once the assembly is positioned on depth, rig up the gravel infuser pumping equipment, manifold and lines. Test to 5,000psi. Establish circulation, record circulating pressure and drop the packer setting ball. Allow time for ball to gravitate to the ball seat in the crossover tool, roughly 5min/1,000ft.

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5)

6)

7)

Note:

22)

23)

24)

25)

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Set the packer by slowly pressuring up the workstring according to the steps and pressures stated in the well programme. Verify slip anchoring of the packer by alternately setting down and picking up 10,00015,000lbs weight. Slack off to the neutral position and test the packer by pressuring the casing to 1,000psi. for 5min. Since 1,000psi annular pressure releases the crossover tool from the packer, the crossover tool may now be snapped out of the packer. Alternatively, the crossover tool may be released from the packer by turning 15 rotations to the right at the packer depth holding a slight upstrain. Raise the crossover tool to the reverse circulating position. Apply the appropriate workstring pressure to shear the ball seat in the crossover tool. Break circulation in the reverse direction at 3bpm and record the pump pressure. Pickle the workstring by circulating the pickling agent to the end of the workstring. 1 Reverse circulate 1 /2 workstring volumes of filtered completion fluid until returns are clean. Lower the crossover tool and set down 10,000lbs on the packer. This is the squeeze position, mark the pipe at the rotary table level. Establish injection pressures at 3, 2, 1, 1 and /2bpm. Do not exceed the formation fracture pressure. If injectivity is low, an acid stimulation treatment may be conducted prior to performing the gravel pack. Raise the crossover tool to neutral weight plus an additional 2ft. This is the circulating position, mark the pipe at the rotary table level. Establish circulating pressures at 3, 2, 1 1, and /2bpm. Monitor the return rate with a flowmeter to determine the leak-off rate to the zone. If full returns are observed, partially close the annular BOP to hold backpressure and induce leak-off. Do not exceed the formation fracture pressure. Raise the crossover tool to the reverse circulating position. Infuse gravel pack sand into completion fluid at the desired mix ratio and pump a circulating rate of 3bpm.1 A pump rate of 3bpm must be maintained to achieve a fluid velocity of 500ft/min in 3 /2” workstring. When the sand is 5-10bbls above the packer, lower the crossover tool into the circulating position. Continue displacing the gravel with filtered completion brine until an initial pressure increase is observed due to gravel covering the screens. While pumping, allow the pressure to build to 1,500-2,500psi. over the initial circulating pressure at a1 given rate. Maintain this sandout pressure while slowing the pump rate to 2, 1, and /2bpm. Allow the pressure to bleed off to the formation. Calculate the gravel height above the screen top using the linear flow equation. Do not re-stress the pack. Close the annular BOP and apply 500psi to the annulus. Raise the crossover tool to the reversing position. Reverse out excess gravel plus two workstring volumes. Divert the gravel returns to the slurry dehydration tank and determine the volume of gravel reversed out. The volume of gravel placed can then be calculated by subtracting the volume reversed out and the screen/open hole, blank pipe/open hole and blank pipe/casing annular volumes from the total volume of gravel pumped.

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To test the gravel pack, lower the crossover tool into the circulating position and attempt to circulate at the same rate and pressure achieved earlier. If sandout pressure cannot be achieved, mix and pump another batch of gravel. Reverse out excess gravel. Repeat this step until final sandout occurs. Pull out of the hole with the service toolstring. Revert to the completion procedures in the completion programme.

CASED HOLE GRAVEL PACK PROCEDURE The procedure described herein is based on Baker’s gravel pack systems. 1) 2)

3) Note:

4) Note:

5) 6) 7) 8) 9) 10) 11) 12) 13) 14)

Prepare the hole as per section 6.3.2. Run in hole with the sump packer on electric line. Correlate with the GR/CCL to the reference log and set the packer at approx. 6ft below the planned depth of the bottom perforation. Pull out of the hole and rig down the electric line. Pick up the perforating assembly and run in the hole (Refer to section 5). Use a Tubing Conveyed Perforating system with the highest possible shot density (typically 12spf), with Gravel Pack or ‘Big Hole’ charges. Establish the desired underbalance. This operation should be performed with the underbalance stated in the well programme (normally 500-1,000psi depending on the formation strength. Verify the proper positioning of the perforating guns by tagging the sump packer and space out the string at the correct depth. Set the packer. Rig up the control head and surface lines (if on a floater this will be done before step 6 above). Detonate the perforating guns by appropriate procedure. Flow the well to sufficiently remove all debris from the perforations. Reverse circulate two workstring volumes with filtered completion fluid to stabilise the well. Continue circulating and filtering until returns are clean. Monitor the well to determine if it has stabilised. Record any fluid losses or gains. If necessary to control fluid loss, spot a fluid loss control pill. Unseat the packer and reciprocate the string to fully release the packer and repeat one more complete circulation. Pull out of the hole with the TCP assembly, monitoring for fluid losses. If there is evidence of formation sand in the returns, pick up and run a scraper with a tailpipe to enter and wash down to the sump packer.

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18) 19) 20)

21)

22) 23) 24) 25)

Knock Out Isolation Valve Shear Out Safety Joint Crossover Sub Gravel Pack Extension with Sliding Sleeve Gravel Pack Packer.

The gravel pack service toolstring assembly is then made up to the previous assembly: • • •

Note:

Snap Latch Seal Assembly Sand screens Blank pipe

Run flush joint washpipe inside, and to the bottom of, the screen through the blank pipe. The assembly consisting of the following items is then picked up and made up onto the screen assembly. • • • • •

3)

0

Pick up and assemble the gravel pack assembly in the rotary table as follows, from bottom up, running at a slow speed to prevent damage to the packing element and to prevent prematurely setting the packer. • • •

2)

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Shifting Tool Gravel Pack Crossover Tool Hydraulic Setting Tool. Apply thread compound sparingly to the pin ends of the connections only.

Run in hole slowly with the completion assembly (90sec per 90ft stand). Set down into, and pick up gently out of, the slips. Record the pick-up and slack-off weights when reaching the packer setting depth. Record pick-up and slack-off weights one stand above the sump packer. Tag the sump packer and set down sufficient weight to force the latch of the snap latch to engage the packer. If desired, the latch may be snapped out of the packer with pull to verify correct operation. Once the assembly is positioned on depth, rig up the gravel infuser pumping equipment, manifold and lines. Test to 5,000psi. Establish circulation, record circulating pressure and drop the packer setting ball. Allow time for ball to gravitate to the ball seat in the crossover tool, roughly 5min/1,000ft. Set the packer by slowly pressuring up the workstring according to the steps and pressures stated in the well programme. Verify slip anchoring of the packer by alternately setting down and picking up 10,00015,000lbs weight. Slack off to the neutral position and test the packer by pressuring the casing to 1,000psi for 5min. Since 1,000psi annular pressure releases the crossover tool from the packer, the crossover tool may now be snapped out of the packer. Alternatively, the crossover tool may be released from the packer by turning 15 rotations to the right at the packer depth with a slight upstrain.

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3)

Note:

29)

30)

31)

32)

33)

34)

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Raise the crossover tool to the reverse circulating position. Apply the appropriate workstring pressure to shear the ball seat in the crossover tool. Break circulation in the reverse direction at 3bpm and record the pump pressure. Pickle the workstring by circulating the pickling agent to the end of the workstring. 1 Reverse circulate 1 /2 workstring volumes of filtered completion fluid until returns are clean. Lower the crossover tool and set down 10,000lbs on the packer. This is the squeeze position, mark the pipe at the rotary table level. Establish injection pressures at 3, 2, 1, 1 and /2bpm. Do not exceed the formation fracture pressure. If injectivity is low an acid stimulation treatment may be desired prior to performing the gravel pack. Raise the crossover tool to neutral weight plus an additional 2ft. This is the circulating position, mark the pipe at the rotary table level. Establish circulating pressures at 3, 2, 1 1, and /2bpm. Monitor the return rates with a flowmeter to determine the leak-off rate to the zone. If full returns are observed, partially close the annular BOP to hold backpressure and induce leak-off. Do not exceed the formation fracture pressure. Raise the crossover tool to the reverse circulating position. Infuse gravel pack sand into completion fluid at the desired mix ratio and at a circulating rate of 3bpm. A pump 1 rate of 3bpm must be maintained to achieve a fluid velocity of 500ft/min in 3 /2” workstring. When the sand is 5-10bbls above the packer, lower the crossover tool into the circulating position. Continue displacing the gravel with filtered completion brine until an initial pressure increase is observed due to gravel covering the screens. While pumping, allow the pressure to build to 1,500-2,500psi over the initial circulating pressure at a1 given rate. Maintain this sandout pressure while slowing the pump rate to 2, 1, and /2bpm. Allow the pressure to bleed off to the formation. Calculate the gravel height above the screen top using the linear flow equation. Do not re-stress the pack. Close the annular BOP and apply 500psi to the annulus. Raise the crossover tool to the reversing position. Reverse out excess gravel plus two workstring volumes. Divert the gravel returns to the slurry dehydration tank and determine the volume of gravel reversed out. The volume of gravel placed behind the casing can then be calculated by subtracting the volume reversed out and the screen/casing and blank pipe/casing annular volumes from the total volume of gravel pumped. To test the gravel pack, lower the crossover tool into circulating position and attempt to circulate at the same rate and pressure achieved earlier. If sandout pressure cannot be achieved, mix and pump another batch of gravel. Reverse out any excess gravel. Repeat this step until final sandout occurs. Pull out of the hole with the service toolstring. Revert to the completion procedures in the completion programme.

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Service Seal Unit With X-Over Open Automatic J-Latch

Shear Pins Tying Seal Unit to Packer PermanentRetrievable Packer

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Production Seal Unit

Swivel Saftey Joint Gravel Pack Sand Screen

Figure 6.A - Typical Open Hole Gravel Pack Installation

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Service Seal Unit With X-Over Open Automatic J-Latch

Shear Pins Tying Seal Unit to Packer PermanentRetrievable Packer

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Production Seal Unit

Swivel Saftey Joint Gravel Pack Sand Screen

Figure 6.B - Typical Cased Hole Gravel Pack Installation

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PACKER INSTALLATION In some completion programmes, packers may be set on electric wireline, such as when installing reference packers for gravel packs or using a packer as a plug. Normally it is preferred to install a production packer on the completion tubing string in order to obtain single trip installation saving unwarranted wireline trips and, hence, reduce cost. Refer to the Completion Design Manual for various packer completion designs and installation methods. An advantage of setting a packer on wireline is it is quick and simple and accurate setting. This ensures that the packer is not set across a casing coupling or can be used as a reference for TCP gun depth correlation. A disadvantage, other than trip cost saving, is that the packer is not pressure tested until the tubing string is installed. Packers to be set in highly deviated wells may be installed on a workstring where wireline would not reach. The packers set on a workstring can be set mechanically or hydraulically by applying pressure to the workstring. Selective completions may have a number of tubing retrievable type packers installed in a single trip which are set in sequence. Eni-Agip’s policies for the use of retrievable and permanent packers is fully outlined in the Company’s Completion Design Manual. Both tubing and wireline set packer installation procedures are described in this section.

7.1.

HOLE PREPARATION Before running any packer (wireline or tubing installed), a junk basket with a gauge ring should be run to below the depth at which the packer is to be set. This is to ensure that the packer can successfully reach the setting depth. The gauging/junk basket procedure is: 1) 2) 3) 4)

5)

7.2.

Rig up the electric line for running in cased hole. Confirm that the gauge ring is the correct size for the production casing or liner. Run the junk basket and gauge ring slowly observing the CCL to confirm that the tool is moving at the same speed as the cable. If the junk basket is run to TD, when pulling out of the hole, it is important not to slack off on the cable as this will open the junk basket and release the contents. Speed and tension should be closely monitored while pulling out. If the junk basket is full of junk, repeat the procedure until no more debris is recovered.

WIRELINE PACKER SETTING PROCEDURE In this method the packer is run on a setting tool and is set by application of controlled pressure from a slow burning powder charge acting through a piston which, in turn, forces the packer through its setting sequence. When the sequence is completed the packer setting tool is automatically released from the packer and is confirmation of correct operation. The procedures given below are generic and not specific to any particular packer manufacturer, therefore alterations to these procedures may be necessary to suit a particular packer.

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Running Procedure As the setting tool is operated using an explosive charge, radio silence will be required when making up and running the tool. Also, when the tool has been fired the body will contain high pressure gas, hence special care will have to be taken when it is being rigged down at surface. 1)

2)

3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16) 17) 18)

Note:

19) 20) 21)

The Company Supervisor shall verify that the completion equipment, including the packer system, corresponds to the details in the completion programme and has the appropriate correct part numbers, serial numbers and certification. Assemble the packer adapter kit and setting tool. Each packer will have an appropriate packer kit to fit between the specific type and size of packer and the type and size of setting gun. Rig down the gauge ring/junk basket. Pick up the lower packer tailpipe assembly and set it in the rotary table installing a collar clamp above the slips as there is little weight at this time. Pick up the other tailpipe sub-assemblies and make up them up in sequence according to the well programme. Make up the packer to the top of the packer tailpipe. Install a plug by wireline in the packer tailpipe landing nipple, fill up the assembly with brine. Install the packer test adapter and pressure test the packer/packer tailpipe assembly to the pressure stated in the Completion Programme. Remove the test adapter and retrieve the wireline plug. Obtain radio silence and make up the cable head to the setting tool/packer assembly. Pick-up the packer running tool assembly and make it up to the packer. Pick up the assembly and remove the collar clamp and pull the slips. Conduct a weight check. Run in the hole at the recommended speed given by the packer supplier or the logging contractor whichever is applicable. Make a correlation logging pass over a suitable interval and record the GR/CCL log. Correlate the depth measurements to the reference log depths. Position the assembly at the correct setting depth. After the Logging Engineer and Well Operations Supervisor have satisfied themselves that the toolstring is at the correct depth, the setting charge will be fired. Do not tag the packer after setting as the adapter kit may become stuck in the packer, resulting in a fishing job. Pull the tool back to surface carefully, ensuring that all radio silence procedures are followed. When the toolstring is back at surface, inspect the adapter kit and setting tool to verify the proper setting of the packer, handling carefully in case there has been a misfire. Release any pressure from the setting tool and rig down.

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TUBING INSTALLED PACKER SETTING PROCEDURE If the packer is to be set on a workstring, a packer adapter is required to allow connection between the packer and the workstring. If the packer is to be set by hydraulic pressure, a setting tool similar to that describe for wireline setting is required and attached to the workstring. If the packer is to be installed on the completion tubing string, all the completion components will be installed in the string as it is run. This includes the packer tailpipe, tubing movement device, landing nipples, circulating devices, SSSV, etc.

7.3.1.

Workstring Running Procedure The hole will be gauged according to section 7.1. 1)

2)

3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16)

17) 18)

The Company Supervisor shall verify that the completion equipment, including the packer system, corresponds to the details in the completion programme and has the appropriate correct part numbers, serial numbers and certification. Assemble the packer adapter kit (and setting tool, if hydraulic set). Each packer will have a appropriate packer kit to fit between the specific type and size of packer and the type and size of setting gun or workstring. Pick up the lower packer tailpipe assembly and set it in the rotary table installing a collar clamp above the slips as there is little weight at this time. Pick up the other tailpipe sub-assemblies and make up them up in sequence according to the well programme. Make up the packer to the top of the packer tailpipe. Install a plug by wireline in the packer tailpipe landing nipple, fill up the assembly with brine. Install the packer test adapter and pressure test the packer/packer tailpipe assembly to the pressure stated in the Completion Programme. Remove the test adapter and retrieve the wireline plug. Pick up the setting tool and first joint of tubing and make up onto the packer. Pick up the assembly and remove the collar clamp and then the slips. Run in the hole at the recommended speed given by the packer supplier. Trip to depth according to pipe measurement. If accuracy is required, rig up electric line and run a GR/CCL and correlate the workstring to the casing. Set the packer mechanically or hydraulically according to the packer setting procedure. If possible, pressure test the packer according to the programme. Shear off the workstring from the packer and pull the workstring. The hydraulic running tool usually self releases from the packer similar to the wireline setting procedure, therefore do not set back down to check the packer otherwise the adapter may be come stuck. Pull the workstring with the adapter kit back to surface and check the shear pins to verify the setting of the packer. Rig down.

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Completion String Running Procedure The hole will be gauged according to section 7.1. 1)

2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12)

13) 14) 15) 16) 17) 18) 19) 20) 21)

The Company Supervisor shall verify that the completion equipment, including the packer system, corresponds to the details in the completion programme and has the appropriate correct part numbers, serial numbers and certification. Pick up the lower packer tailpipe assembly and set it in the rotary table installing a collar clamp above the slips as there is little weight at this time. Pick up the other tailpipe sub-assemblies and make up them up in sequence. Make up the packer to the top of the packer tailpipe. If it is felt necessary to pressure test the packer tailpipe, run a wireline plug and conduct the test as per the manufacturer’s procedure. Pick up the other packer accessories and install onto the packer. Pick up the assembly and remove the collar clamp and then the slips. Run in the hole and set the slips and collar clamp again. Pick up the first joint of tubing and make up onto the string. Run in the hole at the recommended speed given by the packer supplier installing all completion components. Trip to depth according to pipe measurement. Rig up electric line and run a GR/CCL and correlate the string depth, hence packer depth to the casing. If the tubing is high chrome content, consideration must be given to a different method of depth correlation Determine spacing out for the tubing hanger and install pup joints and the tubing hanger. Trip into the hole, record string weight and place the packer on the correct depth. Conduct a tubing string gauging procedure to confirm nipple depths and sizes. Either, drop the packer setting ball or rig up wireline and run the packer setting plug/ standing valve (Refer to the Wireline Procedures Manual). Rig up the pump line to the test head and fill up the string with brine. Pressure up on the string to set the packer, according to the manufacturer’s procedure. Set the tubing hanger, if not already set, and conduct all other completion pressure and function test procedures. Pull the packer setting plug/standing valve, if necessary. Continue with the completions programme.

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COMPLETION INSTALLATION The procedures in this section describe the procedures for equipment pre-installation checking and completion installation.

8.1.

CARBON STEEL AND PLASTIC COATED TUBING 1) 2) 3) 4)

5) 6)

7)

8.2.

Tally and number the tubing joints as soon as they are unloaded from the transport. On the pipe rack remove the thread protectors to allow inspection and cleaning. All pin and box ends should be inspected for damage paying particular attention to the seal areas. All joints must be drifted with a suitable tubing drift. Drifts should be 42ins long to standard API specification, blunt nosed, and plastic coated or with rubber ends to prevent damaging the seal areas on the connections. Rejected joints should be clearly marked with red paint and prepared for back-loading as per API RP5A5. While the tubing is being laid out on the pipe deck, the pin and box threads should be cleaned with, either, a suitable detergent, steam, or high pressure water. Avoid using water, if at all possible. Ensure the detergents used are in accordance with personnel Safety Policies. When preparing a tubing tally, measurements should be carried out twice, preferably by two independent personnel with different measuring tapes. When a comparison of the measurements is made, if any length is off by more than 0.01ft, recheck the tally. Simple errors of +/- 1ft are sometimes made where the tape has been mis-read.

CHROME TUBULARS Chrome tubulars are extremely susceptible to galling and to local cold working if improperly stressed or impacted during shipping and handling. Excessive bending during lifting of single joints, or bundles of joints, can also cause unacceptable levels of stress to be imparted. Improper handling can lead to an increase in hardness or change in mechanical properties which may result in detrimental forms of corrosion such as sulphide stress corrosion cracking and uneven corrosion.

8.2.1.

Transportation Handling, transportation, and temporary storage of tubular goods will comply with Section 3 of API RP 5C1.

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Transport From The Mill Chrome tubulars will be dispatched from the mill in special transport frames. These will be loaded into wooden crates for shipment. The tubulars will be covered by nylon sheets, and wrapped with Drilltec Econorap. The transport boxes are designed to prevent movement of, and contact between individual joints during transportation. The wrapping will also minimise the risk of the tubing coming into contact with seawater during transportation. The transport frames will be removed from the wooden crates prior to shipment offshore. Note:

8.2.3.

Webbing type strops for cargo handling is not permitted.

Road Transport • • •

• • 8.2.4.

Marine Transport • • • •

8.2.5.

The transport boxes will be properly loaded, and supported along their entire length. Chrome tubulars will not be removed from their transport frames until arrival on the installation. Security of the bolts on the transport frames will be checked by a Company representative, or an approved designate, before lifting to ensure that the tubulars are secured, and so prevent movement of the tubulars within the transport frames. The transport frames will be secured using nylon straps. Any loose tubing should also be secured by nylon straps.

The transport frames will be arranged on deck in order to prevent longitudinal movement. Protection, such as tyres or heavy rope, will be used to protect the transport frames from other cargo. The transport frames will not be stacked more than three high. No other cargo will be placed on top of the transport frames.

Handling At The Wellsite 1) 2) 3) 4) 5)

Chrome tubulars must not be allowed to contact other metallic material, including supports and tubulars of the same material. Chains, monkey wrenches, hooks, shackles, etc. will not be used for handling chrome tubulars. Where metal impact or handling devices have inadvertently been used the tubing joint will be set aside for further checking. Only lift tubulars with nylon strops. Plastic supports will be used to support chrome tubulars and prevent rolling. Wood and rope are not recommended as they tend to retain moisture, and may become contaminated with chlorine or other chemicals harmful to chrome tubulars.

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1)

The recommended stacking heights for various sizes of tubing are: 7” 29 lbs/ft 6 rows 51/2” 17 lbs/ft 8 rows 41/2” 12.6 lbs/ft 9 rows.

7)

Chrome tubulars will have sufficient supports to accommodate the weight and number of pipe, and will be laid out with enough space for a full 360o revolution for cleaning and inspection purposes. The supports will be properly spaced to prevent bellying of the pipe, and so prevent water accumulation.

8)

Where possible the pipe should be racked at a 20o incline to ensure proper drainage of water, with the box end being raised to prevent accumulation of water in the threads.

Note:

9)

As each row is laid out the thread protectors will be removed and cleaned and the threads cleaned and inspected by an approved thread inspector, i.e.: • • • •

10) 11) 12)

13) 14) 15)

16)

17) 18)

Clean the threads using a steam jet. Do not use oil based solvents and wire brushes. Dry the threads with compressed air. Apply a thin coating of Molycote to the clean threads.

If driftable open ended protectors are provided then they will be installed (after cleaning as above), and the tubing drifted with the appropriate size drift. If closed end protectors are provided then they will be installed after drifting the tubing. The tubing will be drifted from end to end using a nylock drift to API spec. The drift dimensions will be as per (API RP 5A5): 7" 29 lbs/ft 6.059" (153.9 mm) 51/2 " 17 lbs/ft 4.767" (121.1 mm) 41/2" 12.6 lbs/ft 3.833" (97.3 mm). The diameter of the drifts will be checked regularly during the drifting operation. Extreme care should be taken at pin and box sealing areas. If a joint is rejected for any reason, i.e. fails to drift, or if the threads are damaged, the joint will identified with red paint. It will then be repackaged and sent back onshore. A report detailing the reason for rejection will be sent to the Workover Superintendent in the Company office. The tubing will be measured from the end of the coupling to the pin threads by the designated Company Representative and the entire length corrected for make up loss. For shouldered connections measure the length from box end to the shoulder on the pin. Record the joint number as per stencilled description. The measurements will be recorded on the tubing tally form. Make up loss details should be sourced from manufacturer’s technical data sheets.

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8.2.6.

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Thread Compounds Only API Modified thread compounds with a friction factor of 1 will be used as per (API Bul. 5A2). Note:

1) 2)

3) 4)

5)

Note:

7)

A thread compound described as API Modified does not necessarily have a friction factor of 1. Avoid contamination of the thread compound by water, rain, snow, etc. whilst it is being applied. Do not use thread compounds which have been contaminated by any kind of extraneous matter. e.g. sand, dirt, water, solvent, drilling fluid, etc. It is recommended to use a new can of compound and new brushes for application Thread compound should be kept warm to ensure even distribution. Thread compound should be applied with an automatic pipe dope applicator when available. This is used on the box end, and will apply only a thin film of thread compound, as recommended both for joint make-up, and to avoid extrusion of excess pipe dope into the tubing. If no pipe dope applicator is available, apply thread compound sparingly to the entire pin end and to only the shoulder seal and first three threads of the box using a new, clean, 1 ins fibre brush, ensuring that it fills the thread roots and covers the seal faces and torque shoulder adequately. When using a brush, it is easy to over apply the joint with thread dope. By applying thread compound to the pin end only the amount extruded into the tubing as the connection is made up will be minimal, thus minimising any build up on wireline tools, and contamination of the formation. For VAM connections the minimum quantity of dope required is given by the following relationship: •

8)

9)

Minimum weight (grams) = 10 x pipe OD (ins) e.g. 51/2” pipe requires 55 grams or 2 ounces.

Store thread compounds in a clean, warm, dry environment away from direct sunlight. Upturn the compound containers periodically while in storage to prevent solids separating out. A thread inspector must inspect all threads.

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Running Chrome Tubulars Before running any chrome tubulars, a pre-job meeting will be held with all relevant personnel, i.e. drill crew, tong operators, deck crew, crane operator, etc. to ensure that they are aware of their responsibilities. 1) 2) 3) 4) Note: 5)

6)

Note:

Padding material will be fitted to the V-door and catwalk areas to prevent damage to the tubulars. The power tongs will be fitted with the correct size non-marking dies. Single joint and side door elevators will be fitted with non metallic inserts. Confirm that the torque turn analyser has been correctly set-up. Calibrate the tong on a spare joint of tubing. Pick up lines to the single joint elevators will be arranged to allow the joint to be stabbed to hang vertically over the hole, so that no undue pull will be exerted on one side during make up. The tubulars will be transferred to the catwalk with thread protectors installed. Nylon slings wrapped around the joints will be used for lifting purposes. On no account will metal slings be used when handling chrome tubulars. All new tubulars will be supplied with Econowrap LE.

7) 8) 9)

Use single joint pick up elevators for handling tubulars onto the drill floor. Tubing slips will be dressed with low stress dies. Care will be taken when setting pipe in the slips to prevent shock loading and impact damage. 10) After removing the thread protector the threads will be cleaned and inspected (if not already done on the pipe deck). Note: 11) 12) 13) 14)

15)

16)

Note:

Do not use a wire brush for cleaning chrome thread forms. Any joints with damaged threads will be laid out, and clearly identified (Refer to section 8.2). Apply API Modified thread compound with a friction factor of 1, using an automatic pipe dope applicator (Refer to section 8.2.6) A non-metallic (i.e. plastic) stabbing guide will be used to guide the pin correctly into the box. The joint will be lowered slowly into the stabbing guide to allow the man on the stabbing board, and the man on the rig floor to guide the pin into the stabbing guide. Throughout the stabbing operation the pipe should be kept as vertical as possible. If the stabbing operation was unsuccessful both pin and box threads will be inspected for damage. If the box was damaged consideration will be given to replacing it. If the pin was damaged the joint will be laid out. After successfully stabbing the pipe the first four or five turns of the make up will be done by hand using a nylon strap wrench. The use of chain wrenches is not permitted.

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The last turns will be made using a torque turn unit with a graphical torque turn analyser to confirm the correct make up value. The make up speed should be between 3 to 10rpm. Final make up should be at 5 RPM. The running speed will be limited to a maximum of 14 joints per hour.

Retrieving Chrome Tubulars 1)

2)

3) 4) 5) 6) 7) 8) 9)

10)

Note:

11)

Before retrieving any chrome tubulars a pre-job meeting will be held with all relevant personnel i.e. drill crew, tong operators, deck crew, crane operator, etc. to ensure that they are aware of their responsibilities. As a field matures it is possible that scale deposition may occur in production wells. Some of this scale may be LSA (low specific activity), and special handling techniques and precautions will be required. Padding material will be fitted to the V-door and catwalk areas to prevent damage to the tubulars as they are being laid out. Ensure that the power tongs are fitted with the correct size non-marking dies. Tubing slips will be dressed with low stress dies. Care will be taken when setting pipe in the slips to prevent shock loading and impact damage. The connection will be broken using a power tong at a low speed of 2 RPM. Once the thread has been broken the connection will be backed off using a strap wrench. The threads will be cleaned using a high pressure jet of fresh water, or a quick evaporating petroleum solvent (chlorine free), and then dried. High pressure cleaning equipment must be used in accordance with platform procedures. After inspection of the threads storage compound will be applied, and clean thread protectors installed. If LSA scale is present closed end protectors will be installed, and the joints clearly identified as being LSA contaminated. The designated responsible person will check all tubing joints for LSA scale contamination, and will ensure that the correct action, documentation, manifesting and notifications are adhered to for shipment of all LSA scale contaminated tubulars. The tubulars will be transferred from the rig floor using nylon slings wrapped around the joints.

Note:

On no account will metal slings be used, or hooks inserted into the pin and box ends.

Note:

If possible the crane will be used to lift the joints from the rig floor to the transport boxes.

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Each joint will be clearly marked, and an 'as pulled' tally prepared by the Well Operations Supervisor. Before placing the tubulars in their transport frames they will be flushed with fresh water. Any joints with damaged threads will be clearly identified and laid out for back-loading in a separate transport frame. A detailed report will be prepared by the Well Operations Supervisor on the condition of the recovered tubulars. This report shall contain details of thread damage, corrosion, scale build up, position in well of damaged tubulars, etc., and will be forwarded to the Completions and Workover Superintendent in the Company office.

EQUIPMENT PRE-INSTALLATION PROCEDURES The activities outlined below are to be conducted as soon as completion equipment is received on the well site to allow sufficient time to correct for damaged or missing items.

8.3.1.

Material Requisition Lists Confirm that all of the required completion equipment is available on site. Reference should be made to the Material Requisition Lists provided for each individual completion. The Company Supervisor shall verify that the completion equipment, corresponds to the details in the completion programme and has the appropriate correct part numbers, serial numbers and certification.

8.3.2.

Completion Sub Assemblies The on site equipment manufacturer’s representative will have copies of the sub-assembly drawings for identification purposes. Sub-assemblies containing chrome tubulars require special handling procedures as per section 8.2. 1)

2)

3)

4)

Remove the sub-assemblies from the completion basket and lay them out on the deck for inspection. Check that the workshop numbering of the sub-assemblies is correct or number them for the correct running order if this has not already been done. This is of particular importance with nipple sub-assemblies. Compare the sub-assemblies with the preliminary completion diagrams provided with the individual well programme. Check that flow couplings are installed in the correct places. For production completions these should be located above nipples, gas lift mandrels, crossovers, and SCSSVs. Injection completions will have flow couplings installed below nipples, crossovers and SCSSVs. Measure the overall sub-assembly lengths and correct if in error by more than 0.01ft. Check that the equipment part numbers stamped on the equipment agree with those on the completion diagram. If they do not agree, report the discrepancy to the Well Operations Supervisor. The final completion diagram must be corrected to depict the actual part numbers on the completion sub-assemblies. Clean and inspect the connections and thread protectors. Refer to the specific guidelines for handling chrome tubing. Confirm that all sub-assemblies have the correct crossovers as required.

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Look through each sub-assembly to confirm that all test plugs have been removed. Ensure that no items of debris remain inside the sub-assemblies, and that all protective wrappings and coatings are fully removed before final assembly of the completion string. Inspect the packer rubber and seals on the tubing anchor for any signs of damage.

Tubing Hanger The tubing hanger and running tool should have been prepared in the workshop. Relevant information is contained in the manufacturer’s Wellhead Manual. 1) 2) 3)

8.3.4.

Inspect and drift the assembly. Measure the pup joint installed in the bottom of the hanger, confirming the thread type, grade, and condition. If the running tool was not installed previously, check the condition of the threads before having the Wellhead Engineer make it up to the hanger.

Landing Joint Make sure that a suitable landing joint is available, made up from pups to a length sufficient for the required stick-up above the rig floor. The assembly must be drifted with a suitable drift prior to each use. Ported slick joints are available which have ports for the SCSSV control lines through the BOP stack.

8.3.5.

Control Line The control line should be visually inspected for any signs of damage received during transit and then pressure tested to 1,000 psi above the maximum expected wellhead pressure or maximum test pressure, whichever is the least, for 15 mins. Report this test on the daily drilling report. Ensure the test fluid is the same as that used in the control system.

8.3.6.

Xmas Tree Check that the tree components and fittings are on location. Make sure that all necessary seals and ring gaskets are available and in good condition. Reject any suspect items as unfit for service. Plan the method of lifting the tree in place and confirm that the required lifting equipment, including the drawworks, is available. Confirm with the Production Superintendent that all pressure vessels and flowlines with the drop radius have been isolated have been bled off and vented. Also check the tree orientation with the Production Supervisor. Check that the bolts and ring joint are of the correct material composition.

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Flowline Check with the Production Supervisor that the flowline is on site and that it is the correct length (the amount of curvature applied to coflexip flowlines is critical) and that it is ready to be connected to the Xmas Tree. Also confirm that the tree choke valve is present on site.

8.4.

COMPLETION ASSEMBLIES All completion assemblies will arrive at site after being fully prepared, assembled and pressure tested by the supplier and witnessed by a Company Representative. Back up assemblies should be available and on site in case of damage/failure during running and testing. If any of the assemblies should require further work, due to damage in transit for example, the procedure outlined in section 8.1 should be observed.

8.4.1.

Workshop Make-up and Test Procedures Prior to being transported, all completion sub assemblies will be made up, drifted and pressure tested in the suppliers workshop. Completion components are made up using torque turn equipment to ensure smooth make up and application of the correct amount of torque. All pressure tests are to WP for 15min, unless otherwise stated. For detailed technical specifications, see the manufacturer’s literature.

8.4.2.

Sub-Surface Safety Valves Tubing retrievable SCSSVs or wireline retrievable SCSSV landing nipples will be made up as assemblies with flow couplings and/or tubing pup joints. Both will be tested as follows: TRSCSSV Test Procedure 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11)

Flush the control line through with proper clean control line fluid. Attach the control line to the valve. Cycle the valve open and closed to ensure proper operation. Record the volume to open the valve against the pressure and check to ensure it is within specification. Install test subs, open the valve and fill the assembly with test fluid. Pressure test the body to WP for 10min Close the valve and pressure test from below to WP for 10min. Remove the test subs. Drift the assembly with the API drift. Record all component serial numbers and stencil the sub-assembly with ID number. Complete the ‘Documentation Package’ and ensure all torque and pressure charts are included.

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WRSCSSV Test Procedure 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11)

8.4.3.

Attach the control line to the nipple. Flush the control line through with the proper clean control line fluid. Install the valve in the nipple assembly. Cycle the valve open and closed to ensure proper operation. Record the volume to open the valve against the pressure and check to ensure it is within specification. Install test subs, open the valve and fill the assembly with test fluid. Close the valve and pressure test from below to WP for 10min. Remove the test subs. Drift the assembly with the API drift. Record all component serial numbers and stencil the sub-assembly with ID number. Complete the ‘Documentation Package’ and ensure all torque and pressure charts are included.

Wireline Nipple Assemblies Wireline nipples will normally be made up as an assembly with adjoining tubing joints or pup joints. The test below ensures computability of the lock mandrel and pressure integrity of the connections. 1) 2) 3) 4) 5) 6)

8.4.4.

Drift the assembly with the API drift. Set the appropriate positive plug in the landing nipple. Install test subs, fill up with test fluid and pressure test to WP for 10min both above and below the plug. Remove the test subs and retrieve the plug. Record all component serial numbers and stencil the sub-assembly with the ID number. Complete the ‘Documentation Package’ and ensure all torque and pressure charts are included.

Side Pocket Mandrels 1) 2) 3) 4) 5) 6)

Drift complete assembly with the correct size API drift. Ensure the correct SPM valve or dummy valve is installed. Install test subs, fill up with test fluid and pressure test the assembly to WP for 10min. Re-drift assembly with the API drift. Record all component serial numbers and stencil sub assembly with the ID numbers. Complete the ‘Documentation Package’ and ensure all torque and pressure charts are included.

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8.5.

COMPLETION RUNNING PROCEDURES

8.5.1.

General

2)

3) 4) 5)

6) 7)

8) 9)

10)

11) 12)

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15)

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Assemblies should be made up on the rig floor and landed off low in the rotary table. The correct torque should be applied according to the manufacturer’s instructions. Connections are to be made up with a hydraulic casing tong fitted with an internal back-up tong. The tong should be calibrated for torque turn readings. Rig tongs must never be used to make up the completion sub assemblies. Ensure that a safety valve is located on the rig floor complete with crossover to suit the tubing thread being run. If a two sizes of tubing are being installed, two safety valves are required. Make sure that the appropriate retrieving/fishing tools are on site when running the completion. Ensure that collar clamps are used when running the tailpipe assembly. Drift each nipple with the appropriate standing valve, lock mandrel or equalising sub (without packing or keys) when the packer/tailpipe assembly is suspended in the rotary table. Drift through the complete packer/tailpipe assembly with an appropriate gauge cutter. Run the tubing as specified in the well completion programme. Extreme care should be observed when running the completion, run in the hole at a steady uniform speed and apply the brake slowly. Do not jerk the completion string when applying the brake. After lowering the slips into the rotary bushing, slack off the string weight with care. Check the composition of the completion fluid at regular intervals, and maintain the required levels in the tubing and annulus. If running chemical injection or downhole gauge systems, attach an across-coupling and mid joint protectors (one each per joint) to secure the lines to the tubing. Do not over-tighten to allow movement for stretch induced by temperature changes. Pay particular attention to the lines when lowering the slips. When changing tubing sizes, count all the remaining previous tubing left on the pipe rack. Make sure that this agrees with the running list. If there is a problem do not proceed until it has been resolved. Continue running the completion to depth where the SCSSV is to be installed. Pressure test the tubing string to the pressure given in the well programme. Make up the SCSSV. Install the control line and pressure test to the pressure stated in the well programme for 15min. Bleed off the pressure to WP and maintain this pressure whilst running in the hole. Secure control lines with the across-coupling and mid joint protectors. When running tubulars with control lines attached, take care to ensure that the string is properly centralised to prevent stripping off the protectors. When pressure testing equipment, build up pressure slowly. Pressure should be built up in a series of stages to the required maximum. Maintain pressure for the required time and record on a suitable chart recorder. After the final space out, drift the complete string using an appropriate drift.

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Running Procedure The following is a generic procedure for a single trip packer completion. 1) 2)

3)

4)

5) 6) 7) 8) 9) 10)

11) 12)

13) 14)

15)

16) 17)

18)

Pick up the tailpipe packer assembly. Do not install a standing valve. The completion should be run in open ended. Pick up and run the completion assemblies as per the running list. Ensure that the correct torque is applied. Remake any connection identified as suspect by the JAM unit. Reject tubing joints as required. In gas lift completions, an intermediate pressure test will be performed after running all the gas lift mandrels. Set a standing valve in the appropriate nipple in the tailpipe, and pressure test to the pressure stated in the well programme. Do not exceed this pressure. After making up the hanger assembly, the wellhead engineer will supervise the operation of setting the hanger. The setting sequence will have been determined earlier and be described in the well programme. No deviation from this procedure is allowed. Run in the completion until the packer is almost at setting depth. Rig up electric wireline and correlate the packer setting position according to section 7.3, if required. Pull back and space out the tubing string as required according to the log correlation results. Check continuity of electric cables, if applicable. Run back into depth for packer setting. All completion equipment should now be in the hole. The packer should be at setting depth, and the tubing hanger should be oriented and proud of its hang off point if the tubing is to be set in compression. Check the completion running list, make sure that all remaining equipment left on deck agrees with the running list. Rig up slickline and set a standing valve in the tubing nipple. Pressure test the tubing integrity to the pressure stated in the well programme. The SCSSV control line pressure must be increased to the appropriate pressure when conducting this test (test pressure + valve opening pressure + margin), refer to the following sections on SCSSV installations. Retrieve the standing valve. Set a standing valve in the packer tailpipe nipple. Check that the packer is at the correct setting depth. Slowly pressure up the tubing to the specified differential pressure according to the programme. The shear screws locking the packer setting mechanism will shear with the applied tubing pressure differential, then the setting cycle of the slip mechanism will be complete, and the pack off element fully set. Hold the setting pressure for 10min. After setting the packer, pressure up to pressure test the entire completion string. Hold the pressure until a 15min ‘straight line’ is recorded on the recorder. Records of this test are to be retained in the well files. Run in hole with slickline and retrieve the standing valve. Pressure up the well through the production string to pressure test the packer from below. This test should be according to the programme (or the same as the casing test pressure), observe the pressure is stable for 15min. Pick up to shear out the tubing movement device, if applicable. This should be observed at surface.

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Set down and slack off string weight, land and set the surface hanger as per the manufacturer’s instructions. This operation may sometimes be carried out prior to setting the packer. Pressure test the annulus according to the programme, observe the pressure is stable for 15min. If the well has been perforated, set a wireline plug in the tubing string and the plug in the tubing hanger profile.

An alternative procedure for testing the packer without having to remove the tailpipe plug, is to utilise a ported slick joint in the landing string on which the pipe rams or annular can be closed. The packer is then pressure tested by applying 500psi to the annulus. This saves installation time. 8.5.3.

TRSCSSV Installation Procedure When running the completion, the SCSSV will be installed at the appropriate point so that it will be positioned at the correct depth when the completion string is landed off. 1) 2) 3) 4) 5) 6)

7) 8)

9)

10) 11) 12) 13)

Pick up and make up the SCSSV assembly onto the completion string. Lower it through the rotary table to waist height and set the slips where they will not cause any damage to the valve. Flush through the control line from the pump manifold for a short period of time to ensure the fluid is clean. Attach the control line to the valve and cycle the valve open and closed observing that it fully opens and closes, recording the volumes required meet with specification. Pressure test the control line according to the pressure stated in the programme. Lock and monitor the pressure in on the reel keeping the valve open as it is run in the hole preventing pressure locking, allowing the string to self fill and checking for control line leaks. Attach an across-coupling protector at the first connection and ensure the control line is flat against the tubing and is in tension. Run in the hole on tubing applying the protectors at every connection and mid joint, keeping tension on the control line. Never rotate the tubing with control line in the hole. When the spacing out procedure has been completed, wrap the control line around the pup joint below the hanger to provide contingency if the line is damaged during make up and landing. Bleed the pressure off the control line, cut it and connect it to the hanger control line port. Attach the remaining control line from the reel to the exit port in the hanger and pressure test the line according to the completion programme. Reduce the pressure to the required calculated operating pressure. Land off the completion, install barriers, perform all hydraulic tests and close the valve prior to rigging down the BOPs.

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Remove the control line. Install the Xmas tree, pressure test and function test. Cycle the SCSSV, checking the returns are per specification ensuring the valve is fully opening and closing. Continue with the Completion Programme.

WRSCSSV Installation Procedure When running the completion, the SCSSV landing nipple will be installed at the appropriate point so that it will be positioned at the correct depth when the completion string is landed off. 1) 2) 3) 4) 5) 6) 7) 8)

9)

10) 11) 12) 13) 14) 15) 16)

Install the dummy valve into the landing nipple assembly. Pick up and make up the SCSSV landing nipple assembly onto the completion string. Lower it through the rotary table to waist height and set the slips where they will not cause any damage to the valve. Flush through the control line from the pump manifold for a short period of time to ensure the fluid is clean. Attach the control line to the valve and pressure test the connection and the dummy seals according to the pressure in the programme. Lock and monitor the pressure in on the reel to check if any leaks occur. Attach an across-coupling protector at the first connection and ensure the control line is flat against the tubing and is in tension. Run in the hole on tubing applying the protectors at every connection and mid joint, keeping tension on the control line. Never rotate the tubing with control line in the hole. When the spacing out procedure has been completed, wrap the control line around the pup joint below the hanger to provide contingency if the line is damaged during make up and landing. Bleed the pressure off the control line, cut it and connect it to the hanger control line port. Attach the remaining control line from the reel to the exit port in the hanger and pressure test the line according to the completion programme. Reduce the pressure to the required calculated operating pressure. Land off the completion, install barriers, perform all hydraulic tests and close the valve prior to rigging down the BOPs. Remove the control line. Install the Xmas tree, pressure test and function test. Continue with the Completion Programme, pulling the dummy valve and installing the SCSSV according to the procedures in the Wireline Procedures Manual.

If direct acting SSSVs (storm chokes) are being used, they will be calibrated and then installed also according to the procedures in the Wireline Procedures Manual. An option to steps 5 through 8 is to install a check valve on the SCSSV control line port and open the valve locking in the pressure. this then allows tripping in the hole to space out without the control line in the hole.

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XMAS TREE INSTALLATION The variety of Xmas trees and the various configurations are too wide to be covered in this manual. The procedure given below is generic but manufacturer specific procedures must be provided, either, in the well programme or in technical manuals available on site.

8.6.1.

Installation Procedures Specific procedures for installing the wellhead and Xmas tree are given in the relevant Manufacturer’s Wellhead Manual (Refer to figure 8.a for a typical Eni-Agip wellhead and Xmas tree. The following are general precautions which should be observed: 1) 2) 3) 4) 5)

6) 7) 8) 9) 10) 11)

12)

13) 14) 15) 16)

All personnel are to be aware of the dangers involved in the lifting of heavy equipment. Ensure that the correct lifting apparatus is available and has been checked. use a lifting flange on top of the Xmas tree for handling. Close in all neighbouring wells and depressurise flowlines as necessary, before commencing heavy lift operations. Check all sealing or mating surfaces for damage before they are made up. All sealing elements, metal ring gaskets etc. should be carefully examined for any sign of damage. Clean all mating surfaces and ensure freedom of movement in grooves and recesses. Check that the tubing hanger is landed off correctly, and is both centrally and vertically aligned. Use flange protectors where recommended. Ensure that a pressure tested plug is installed in the hanger before removing the BOP. Use the block whenever possible to lower the tree. Ensure that all the tree valves are open before installation. Orientate and lower the tree into position using bolts or alignment bars in position to provide guidance. Tighten the bolts in the specified sequence ensuring that correct torque is applied, and the seals energised. All pressure testing of energised seals should be carried out according to the procedures stipulated in the manufacturer’s manual or well programme procedures. When testing is complete, bleed off pressure from the test port, remove test apparatus, replace the check valves and plugs. Pressure test the tubing hanger seals by pressuring through the Xmas tree bore. The test port in the flange must be open during this test to monitor for leaks. Pressure test the tubing hanger seals and ring joint from the test port of the flange, ensuring the casing side outlet valves are open during this test. Record all the pressures on a chart recorder for file. Install the flow wing and kill wing valves. Liaise with the Production Superintendent to have the choke and control lines connected.

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At this stage the Xmas tree should be API pressure tested to the required pressure against the hanger plug in the tubing hanger. This test should be carried out in two stages: 1) 2)

With the flow and kill wing valves closed and the choke open. With the valve downstream of the choke and kill wing valve closed, and the flow wing valve and choke open.

When all tests are complete, the hanger plug should be removed from the tubing hanger and the tubing plug retrieved by wireline. 8.7.

POST COMPLETION TEST PROCEDURES

8.7.1.

SCSSV Test Procedure Even though the frequency of SSSV testing will be determined independently for each development, the criteria should be reviewed periodically. This is considered necessary due to changing well conditions (water cut, wax formation, gas composition) which could adversely affect valve performance. The routine closure test will be performed after the well has been closed in (not a slam shut test) as this reduces the stress on the valve component parts which will not, therefore, be weakened as a result of regular testing. It also provides a more stringent test of the valves ability to hold pressure. The SCSSV routine closure test procedure will be as detailed in the Completion Design Manual. The procedure is as follows: 1) 2) 3) 4) 5)

6) 7)

Close in the well using the flow wing valve. Depressurise the control line pressure. Conduct a pressure test across the closed SCSSV, to a maximum of 1,000psi pressure differential, by bleeding off pressure above the valve. If there is a rapid leak, cycle the valve and repeat the test. Maintain the pressure differential for 30min, recording the tubing head pressure. This allows the leakage rate to be calculated and determining the leak is less than the maximum allowable leak across the valve according to API specification. Equalise pressure across the SCSSV, preferably by applying pressure from another well, open the SCSSV and return the well to production. If an SCSSV fails the routine closure test, the well will be returned to production/ injection. A pre-tested wireline valve will be inserted in the nipple profile as soon as operationally practicable.

The results of all SCSSV tests will be forwarded to the Completion and Workover Superintendent, and a copy retained in the onsite production well file. 8.7.2.

Xmas Tree Valve Test Procedure The closure time of the Xmas tree, UMGV and wing valves will be checked in conjunction with the SCSSV testing.

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Figure 8.A - Typical Wellhead and Xmas Tree Assembly

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GAS LIFT INSTALLATION As nearly all gas lift designs use Side Pocket Mandrels (SPM) for gas lift valve installation, the procedures in this section are concentrated on this basis and ignores earlier less effective methods (Refer to figure 9.a). The gas lift method and applications are thoroughly described in the Completion design Manual.

9.1.

MANDREL INSTALLATION On production of the gas lift design, the depths of the mandrels will be specified in the well programme. It is essential to have them accurately positioned in the string (to within the nearest joint connection) for optimum well performance providing the gas lift design is based on accurate well parameters and well data. The side pocket mandrel may be installed during the initial completion or during a recompletion sometime later. Once the mandrels have been installed, the valves can be run and installed on wireline at any time it is desired to place the well on gas lift.

9.1.1.

SPM Installation Procedure Make up the mandrel sub-assemblies as described earlier in section 8.1. The subassemblies should be checked and drifted before installation and generally are run with dummy valves installed in order that the completion string can be pressure tested from both the tubing and annulus sides. The dummy valves are left in situ until the well is placed on gas lift when the dummies will be replaced with gas lift valves. The gas lift valves installed on all upper SPMs above the operating point are termed ‘unloading valves’ and their function is to allow unloading of the annulus from completion fluid to gas lift gas. The valve installed at the operating depth is the ‘operating valve’ through which the gas is injected into the tubing. Ensure the SPM depths are stated in the well programme. it will be noted that the SPM spacing is closer towards the bottom becoming wider towards the top of the hole. The installation procedure for the SPMs is as follows: 1)

2) 3) 4) 5)

When running the tubing, on reaching the tubing connection nearest the depth at which the lowest SPM should be installed, pick up the first mandrel according to the running list. Do not use pup joints to place the mandrel exactly on depth as the design is not accurate to that degree. Install the mandrel onto the string and continue running tubing. On reaching the connection closest for the second mandrel, repeat step 2. Repeat until all mandrels are installed. Continue with the Completion Programme.

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Tubing Pressure

Latch Packing

Casing Pressure Packing

Retrievable Mandrel (pressure valve shown)

Figure 9.A - Typical Side Pocket Mandrel

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Gas Lift Valve Installation Procedure As previously stated, the upper gas lift valves are unloading valves and only the lower valve is the gas lift operating valve. The sequence of installation is not important but it is normal practice to install the valves from the bottom to the top. A good practice is to install a gas lift valve catcher in the bottom of the tubing below the lower SPM to catch valves which may be accidentally dropped during the wireline operations. The catcher is usually a lock mandrel set into a landing nipple with a long sump on it which will accommodate two valves. If a valve is dropped, operations can continue until a second valve is dropped requiring the catcher to be pulled to retrieve the dropped valves. If a catcher is not used the valves would probably be lost into the rat hole. The installation running tool termed, a ‘kick-over’ tool, sometimes is furbished with a catcher below on the bottom of the tool but even then it is still good practice to install a catcher sub as contingency. The calibration/setting of the unloading valves and operating valve is normally carried out in the workshop before shipment to the well site due to the equipment complexity. The valves will be set in accordance to the gas lift design. Extra valves are usually supplied as contingency for dropping or damage during transporting and operations. The wireline procedures for a gas lift valve installation and retrieval are fully described in the ‘Wireline Procedures Manual’ (Refer to figure 9.a). Normally the procedure is: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13)

Rig up W/L according to the ‘Wireline Procedures Manual’. Install the gas lift valve catcher sub. Install the kickover tool with the appropriate dummy valve pulling tool. If possible, ensure the pressure across the SPM is equalised before step 5 below. Run in the well, locating the lowermost SPM and pull the dummy valve. The tubing and annulus will now be in communication. Pull out of the hole and retrieve the valve. Pick up and install the operating gas lift in the lubricator, run in the hole and install it in the lower SPM. Pressure up on the tubing to check the valve is correctly located. Do not pressure up on the annulus as the valve allows circulation annulus to tubing. Repeat the procedure in sequence bottom to top for all the other unloading valves. Retrieve the catcher sub. Rig down wireline. Check the operation of all of the surface gas lift system. Unload the well in accordance to the well specific programme.

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UNLOADING PROCEDURE Gas lift installations can be damaged in the first hour or two of unloading by uninformed or impatient operators. All of the liquid above the top valve must go through the top valve during unloading. The gas pressure must be increased slowly during the U-tubing process to prevent high differential pressure across the top valve. Desirably, this differential pressure should be kept less than 100psi. The following guidelines are recommended for kicking off a continuous flow installation. 1) 2) 3) 4) 5) 6) 7)

Remove the choke from the choke tee on the production side of the Xmas tree. Make sure all valves between the well and separator are open. Start injecting gas slowly so the gas pressure increase at the rate of 5psi/min until the gas pressure is 300psi greater than the production pressure at the wellhead Increase the gas injection rate so the pressure increases by 10psi/min until gas is circulated through the top valve. Adjust the choke on the injection gas for the desired unloading rate. Continue the unloading process for all the other valves until reaching the operating valve. After the well is unloaded, adjust the choke on the injection gas to meet with the desired production rate through the operating valve.

Record and monitor all production and gas injection data including pressures to enable comparison of the well performance versus the design. If production is not as expected, conduct a fault finding exercise. The gas lift design can be optimised by making adjustments to the injection rates, pressures or changing the operating valve settings (by changing out the existing valve). Complex software programmes are available to optimise gas lift production. 9.3.

TROUBLESHOOTING Gas lift installations are designed to unload and operate with a minimum amount of manual control. Constant observation of the well’s performance is necessary to maintain maximum production. These observations include well tests, casing-tubing pressures, gas input volumes, flowing pressure-temperature surveys, acoustical surveys, static bottomhole pressures and producing characteristics. Should an installation fail to function satisfactorily, it should be analysed carefully before changing gas lift valves. Most problems can be determined while the well is still gas lifting Many problems can be corrected or minimised at the surface by changing the surface parameters. Should it be necessary to pull valves, the new installation should be based on the analysis of the previous installations. Well test data, flowing parameters are most commonly tools used for gas lift analysis. A two pen pressure recorder should be used every time a well is unloaded.

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DOWNHOLE PUMP INSTALLATION This section contains generic procedures for downhole pump installations, namely ESP, Rod Pumps and Hydraulic Pumps.

10.1.

ELECTRICAL SUBMERSIBLE PUMPS There are a number of different applications and ESP installations which are fully described in the Completions Design Manual. This section provides recommended practice on the handling, installation and operation of a generic ESP system. Because both safety and economic run life are dependent on correct procedures, the importance of following the recommended practices cannot be overemphasised.

10.1.1. Handling The downhole components, motor, pump, protector, and intake are usually shipped in a metal shipping box for protection. The shipping boxes are painted red on the end that should be placed towards the wellhead when the equipment is delivered to the wellsite. The shipping boxes should be lifted with a spreader chain or bridled with a sling at each end. Severe equipment damage can result from dropping, dragging, or bouncing the boxes. The shipping boxes should never be lifted by the centre of the box only. The cable reel should be lifted by using an axle and a spreader bar. If a fork lift is used, the forks should be long enough to support both reel rims when the reel is picked up from an end. The ends of the cable should be covered or sealed to protect them from the elements. Transformers and switchboards are provided with lifting hooks. To avoid damage, the recommended practice is to lift with a spreader bar to maintain a vertical position. Variablespeed drives are normally skid-mounted with fork lift slots and lifting eyes. Some VSD models are manufactured with pull bars. Additional information on ESP handling and installation procedures is available in ‘API Recommended Practices for Electric Submersible Pump Installation’. 10.1.2. Installation There are five phases to every ESP installation. These are: • • • • •

Well preparation Site layout Equipment preparation Assembly and installation Start up of the equipment.

The well-preparation procedure involves determining the downhole clearance conditions. Site layout prescribes equipment and rig locations as well as size and capacity. Running equipment in the well and start-up procedures define the steps in equipment handling, test procedures, and responsibility of the rig crew and servicemen.

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4 3 2 1

4 4

3

3

2 1

2

4 3

1

Typical Onshore ESP Completion - No SSV Or Packer - Downhole Gas Seperation

Common Components 1. Motor 2. Seal 3. Intake/Gas Separator 4. Pump - Cable - Flat Cable - Cable Clamps

2 1

Offshore Sumersible Pumping Completions - No Downhole Gas separation - Retrievable Packer - SCSSV

- Downhole Gas Separation - Permenant Packer Sleeve Type Deep SSCSSV - SCSSV - Wireline Bypass

Reservoir Fluid

Figure 10.A - Typical ESP Installations

- Downhole Gas Separation - High-Set Packer With Annular Vent - Annulus SCSSV - SCSSV

Completion Fluid

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Well Preparation 1)

2)

3)

4)

Prior to beginning installation of the ESP equipment, the well must be cleared of any tubing, rods, packers, etc., that would prevent the downhole equipment from reaching target depth. The casing flange and wellhead should be examined for burrs and sharp edges. This is very important in small-diameter casing because cable damage can be caused by burrs and sharp edges catching cable bands. A gauge ring should be run in (particularly in 4.5” casing) to below the setting depth of the downhole equipment. If gauging indicates tight spots, a scraper or reamer run should be conducted to remove the obstruction (scale, paraffin, burrs, or partially collapsed casing). This will ensure adequate clearance for the ESP downhole equipment as it is run into the well. The BOP, if used, should be checked for adequate clearance as well as burrs and sharp edges. Cut-out profiled rams are available for most tubing and cable sizes. They should be installed in the BOP for well control in the event of a kick during equipment installation.

Site Layout 1)

2)

3)

The pulling rig should be centred over the well as close as possible. The guide wheel/cable sheave should be secured safely to the rig mast no higher than 30 to 45ft above the wellhead. The guide wheel should be at least 54” in diameter. The cable reel or spooling truck should be positioned about 100ft from the wellhead in direct line of sight of the rig operator or driller. One person should be responsible for the cable operation. The responsibilities of this person are to ensure that there is minimum tension on the cable (the cable should be run at the same speed as the tubing), that the cable is kept clear of the power tongs during tubing makeup or break, and that no one stands in front of the cable reel/spooler. The cable junction box must be located at least 15ft from the wellhead. The switchboard must be located a minimum of 50ft from the wellhead and 35ft min from the junction box. The junction box normally is located 2 to 4ft above ground level to ensure there is adequate air circulation and easy access. The junction box must never be located inside a building.

Equipment Preparation The ESP manufacturer’s field representative must thoroughly check all equipment before installation. During installation his responsibility is to supervise the pulling and/or running of the downhole equipment. All equipment delivered to the wellsite is checked to determine that all components necessary to complete the installation have arrived and are not damaged. The ESP manufacturer’s field representative will perform the following checks and procedures. 1) 2) 3)

Remove the shipping box covers and record all component serial numbers from name plates Check the casing, wellhead and pack-off materials. Check the switchboard for proper fuses, potential transformer set-up, and current transformer ratios.

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Check all couplings for shaft diameter and spline match. Check that the shaft is centred correctly (as impact can cause misalignment). Check the flat cable length, size, and pothead type. Check power transformers for correct primary and secondary voltage rating Confirm that the pump design setting depth and capacity match the well conditions and the specification in the Completion Programme. Check the power cable and flat cable with instruments and a high voltage megger.

Assembly And Installation Procedures Once the equipment, cable, and verification procedures are completed, the assembly and installation of the downhole equipment can begin. The manufacturer’s field representative must direct the assembly and check the equipment as it is being run-in. The steps of assembly and checks of equipment can be summarised as follows 1) 2) 3) 4)

Assemble the motor, protector, intake, and pump. Fill the motor/protector assembly with motor oil. Mechanically check the free rotation of downhole components. Check the electrical connection and test the motor, power cable, and flat cable pothead. 5) Check the torque of connecting bolts is correct (use spring washers to prevent loosing of the bolts). 6) Run the pump in the hole installing all the various completion assemblies. 7) Terminate the cable to any pre-made up pigtails through packers, etc. 8) Clamp the cable to tubing string with protectors. 9) Splice the cable or repair any damaged cable. 10) Test the cable continuity and isolation at various depths as it is being run. 11) Terminate the cable to the hanger pigtail. 12) Land the hanger, test the cable integrity and complete the other completion operations. 13) Connect the power cable to junction box and switchboard. 14) Complete the flowline connections. 15) Once the run-in procedures are completed and final electrical tests completed, the manufacturer’s representative will complete the electrical connections. 16) The switchboard settings will be performed and verified by the manufacturer’s specialist according to the conditions expected for each well. 17) Phase rotation should be checked carefully to ensure that the pump will rotate in the correct direction. Start the pump. Fluid pump-up time, load and no-load voltage and amperage on each phase must be recorded. 18) Monitor the wellhead pressure while the string is still full of completion fluid to verify correct pump operation. 19) The quantity of production oil, gas, and water should be monitored on start up and regularly for the time required to achieve stability. A careful study should be made on any pump installation that does not produce at the designed rates. As much information as possible should be gathered to aid in specific identification of problems and appropriate remedial actions. This will help ensure that subsequent ESP installations will provide satisfactory run life.

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10.1.3. Pulling Procedure Pulling the equipment out of a well involves essentially the reverse process of the installation procedure. If the equipment failure is judged to be premature, the condition of cable, flat cable, pump rotation, and motor/protector fluid will be useful in determining the cause of the failure. 10.1.4. Troubleshooting This section outlines a recommendations to identify typical ESP problems and provide solutions. The sole method that a failure can be analysed and its cause determined, is by data collection. When problems occur, obtaining as much data as possible is essential. Data Collection Information that should be routinely compiled on each ESP installation includes: • • • • • •

Production data (such as water, oil, and gas rates) Run life in days Number of unit start ups and stoppages Dynamic and static fluid levels Pump setting depth Perforation depths.

Information also should be obtained on: • • • • • •

Ammeter charts Well conditions (abrasives, corrosives, H2S, etc.) Electric power quality (surges, sags, balance, negative sequence voltages, etc.) Visual observations of equipment and cable condition on prior workovers Reasons for equipment workover (failure, workover, size change, etc.) BHT recordings

When an ESP well is first placed on production, data should be collected daily for the first week, weekly for the first month, and a minimum of monthly after the first month. Production data during the first month are very important because they will indicate whether the pump is performing as designed. If a downhole pressure instrument is installed, operating BHP is equally if not more important. The major source of information when troubleshooting an ESP installation is the recording ammeter. The recording ammeter is a circular strip-chart accessory mounted in the switchboard that records the amperage drawn by the ESP motor. A number of changes in operating conditions can be diagnosed by interpreting ammeter records. The following addresses ammeter chart ‘reading’ and typical problem situations.

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Normal Operation A normal chart is smooth, with amperage at, or near to the motor specification amperage draw. Actual operation may be, either, slightly above or below the specification amperage, however, as long as the curve is symmetric and consistent over a period of time, operation is considered normal. Normal Start-up The start-up ‘spike’ is caused by the inrush surge as the pump comes up to operating speed. The subsequent amperage draw is high but trending towards the normal level. This is principally a result of the fluid level being drawn down to the design TDH, resulting in a high but declining amperage draw. Using the modern variable speed units this problem has been overcome. Power Fluctuations Operating ESP amperage will vary inversely with voltage. If system voltage fluctuates, the ESP amperage will fluctuate inversely to maintain a constant load. The most common cause of this type of fluctuation is a periodic heavy load on the primary power system. This load usually occurs when starting up another ESP or other large electric motor. Simultaneous start-up of several motors should be avoided to minimise the impact on the primary power system. Ammeter spikes also can occur during a thunderstorm that is accompanied by lightning strikes. Gas Locking Gas locking occurs as fluid level drawdown approaches the pump intake and intake pressure is lower than the bubble-point. There are three possible remedies for gas locking: • • •

Install a gas intake and/or a motor shroud Lower the setting depth of the pump (but not lower than the perforation unless the motor is shrouded) Reduce the production rate of the pump by using a surface choke (but ensure that the production rate remains within the recommended range for that pump).

It is entirely feasible that none of these solutions is satisfactory, then the pump should be replaced with a pump that does not draw down the fluid level or reduce intake pressure below the bubble-point. Another possible solution is to add a variable speed drive (VSD) to the existing system. The VSD controls the speed of the pump, which in turn controls the pump capacity. Thus the pump output can be fine-tuned to protect against pump-off and gas lock while contributing to improved pump life. If the problem is confirmed to be due to reservoir conditions, then a stimulation operation may be considered to reinstate the original PI and therefore allow operation of the current ESP design.

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Fluid Pump-Off Fluid pump-off occurs typically when an ESP is too large in relation to the inflow capacity of the well. The remedial actions are much the same as those listed for a gas lock and, in addition, a well simulation treatment may increase the well’s productivity closer to a match with the pump. In general, cycling an ESP will have an adverse effect on optimal run life. As a temporary measure, the amount of time delay before automatic restart can be increased if the switchboard is equipped with a Redalert Motor Controller. This may allow the fluid volume to build up to prevent a high frequency of shutdown occurrence. Nevertheless, the pump and well are not compatible and the pump size should be checked on the next change-out or the well worked over to improve productivity. Gassy Conditions Or Emulsion Continuos amperage fluctuation results from alternating free gas and heavy fluid pumping. Generally this condition results in a reduction of stock tank barrels in relation to the pump design rate. This is also typical of emulsion conditions. The fluctuations are caused by the frequent, temporary blockage of the pump intake. If it is an emulsion block, spikes are normally lower or below the normal amperage line. Solids and Debris When solids or debris are produced in a well, the amperage will display fluctuations immediately after start-up. Typically, when solids such as sand, scale, or weighted mud are produced, special care must be taken on start-up to avoid pump damage. It may be necessary to apply back-pressure on the well to prevent excess amperage until the kill fluid is removed and/or sand production begins to decline to a safe volume. Overload Shutdown A pump will automatically shut down when it reaches an overload condition. When an overload condition shutdown does occur the unit must not be restarted until the cause of the overload has been identified and corrected. Some motor controller overload-detection circuits contain a built-in time delay, ranging from 1 to 5 secs at 500% of the set point to 2 to 30 secs at 200% of the set point. However, they will not automatically restart the unit on an overload condition. A restart attempt in an overload condition can destroy the downhole equipment if the cause of the overload is not identified and corrected first. The most common causes of overload conditions are: • Fluid pump-off • Increased fluid specific gravity • Sand production • Emulsion formation • Scale • Electric power supply problems • Worn equipment • Lightning damage Many of the problems outlined above have been reduced due to the use of VSD.

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ROD PUMPS There are two separate phases to a rod pump completion, the installation of the completion tubing string and the installation of the rod pump and power mover.

10.2.1. Completion Installation There are two common types of completion string configurations which are described in the ‘Completion Design Manual’. The first is when the tubing is simply suspended in the well from a tubing hanger and the other is run with a tubing anchor to anchor the bottom end of the tubing string. A tubing anchor counters tubing movement caused by the reciprocation of the rods and pump plunger within the tubing and pump barrel saving wear and tear. There are also two types of pumps designs, where the barrel is installed, either, in the tubing (tubing installed pump) or run in on the sucker rods (rod installed pump). (Refer to figure 10.b). The installation procedures for both options are described below. 10.2.2. Tubing String Installation The well specific and pump manufacturer’s installation procedures should be provided in the well programme. 1)

2) 3) 4) 5) 6) 7) 8) 9)

10) 11) 12) 13) 14)

Prepare the hole for the completion by conducting any stimulation operations and ensuring the well completion fluid is clean and in proper condition (Refer to section 4.2). Prepare the rig for running the completion string. Ensure all the completion assemblies have been pressure tested, function tested and drifted. Ensure the tubing has been properly cleaned and drifted and the connections inspected for damage. Prepare the tubing for running as per section 7.3.2. Pick up the tubing anchor and tubing anchor assemblies, whichever is applicable, and place in the rotary table setting the slips with a dog collar. Pick up and make up the pump barrel assembly or the pump barrel landing nipple assembly (if the pump barrel is installed on the rods). Pick up the first joint of tubing, make up to the barrel, or barrel nipple, and begin running in the hole. Continue running tubing until reaching the design depth. Attach the tubing hanger and landing joint. If the tubing is to be placed in tension to prevent tubing movement, run to the calculated depth which will apply the correct tension, set the tubing anchor, pull the tubing into tension and set the tubing hanger. If the tubing is to be set in neutral, land off the hanger then set the tubing anchor. Pressure test the tubing hanger. Rig up wireline and make a drift run with a gauge cutter. Run and install the standing valve. Rig up the test head and pressure test the valve and tubing to the pressure specified in the well programme. Rig down wireline.

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Tubing

Sucker Rods

Working Barrel

Plunger

Travelling Valve

Working Barrel (Heavy Wall) Standing Valve Shoe

Tubing Pump

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Rod Pump

Figure 10.B - Types of Bottom Hole Rod Pumps

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10.2.3. Rod Installation 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16) 17) 18) 19) 20) 21) 10.3.

Prepare the rig for running the sucker rods. Ensure that the rods and pump assemblies have been properly checked and tested. Pick up the pump plunger (with or without the pump barrel) and set in the rotary table. Pick up the first sucker rod and make up to the pump plunger. Run the plunger in the hole on the rods. When near the barrel or barrel landing nipple, run very slowly in the hole and tag the barrel confirming the depth correlates correctly. Pull back to space out the rods so that the polished rod will be positioned correctly through the stuffing box. Attached the polished rods and stuffing box. Make up the stuffing box to the wellhead and pressure test through the flowline against the standing valve. Suspend the polished rod and move the rig off the well. Clear the area to allow the prime mover to be positioned. Bring in the prime mover, locate and check the position of the horse head over the well centre. Bolt down the prime mover. Conduct tests on the mover to ensure its correct operation prior to connection to the polished rods. Attach the bridle and carrier bar to the polished rod and adjust to the correct height/stroke position. Connect up the flowline to the production facility. Connect the annulus gas outlet line into the flowline. Pressure test according to the programme. Begin the pump commissioning process bringing the well onstream. Monitor that the initial produced fluid volumes is as per the design. Collect data of production and prime mover current consumption. Optimise the pump speed to maximise stable production flowing conditions.

HYDRAULIC PUMPS There are three main types of hydraulic pump installations, jet pump, turbine pump and the piston pump. The applications and installation methods for each of these is fully described in the ‘Completion Design Manual’. The installation procedures are addressed below.

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10.3.1. Jet Pump Jet pumps are usually installed in a ported receptacle such as a wireline ported landing nipple or a sliding side door as communication between the tubing and annulus is necessary to provide a flow path for the power fluid. A completion in not usually specifically designed for jet pump lift but is designed for both natural flow and with the jet pump ported landing nipple or SSD installed for contingency during later well life. The flow areas of the completion, however, also need to be considered in the design stage for the efficiency of the pump design. Jet pump designs include the use of the annulus or a second tubing string to deliver the power fluid to the pump. If a second tubing string was to be employed, the well would need to be re-completed as a dual or concentric completion. A pump design will have been produced specifying the pump nozzle size, power fluid pressure and volume requirements, and production target. The major work to convert to jet pump is in the provision and recycling of the power fluid which will require additional pumping facilities in conjunction with separation equipment to recover the power fluid. 1) 2) 3) 4) 5) 6) 7) 8) 9)

Install all surface jet pump facilities, make connection to the annulus, function and pressure test, and commission. Rig up wireline on the well according to the procedures in the ‘Wireline Procedures manual’. Install the required shifting tool to open the SSD or expose the port in a ported landing nipple. Check for communication by pumping on the annulus or tubing. Pull out of the hole. Install the jet pump having ensured it is correctly set up and attached to the proper lock mandrel. Run in the hole and set it in the receptacle. Pull out of the hole and rig down wireline. Begin pumping slowly gradually increasing the rate, monitoring and measuring power fluid returns and production rates. Gather all pump and production data and analyse the data to ensure the pump system is performing within the design parameters. Optimise pump performance by tuning the injection pressure to obtain the highest possible stable flowing production. This may involve retrieval of the jet pump and changing the nozzle size.

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Figure 10.C - Hydraulic Pump Design Options

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10.3.2. Turbine Pump The surface facilities described for the jet pump apply to the turbine pump also. However the installation of the downhole turbine pump usually requires re-completion of the well as the pump is tubing installed and retrieved. As the turbine pump is capable of pumping much higher volumes than the jet pump, the flow path area is more critical to pump capacity and efficiency. The completion design options, could require a second flow conduit (Refer to figure 10.c). 10.3.3. Piston Pump The piston pump completion procedure is exactly like that of the jet pump except that a positive piston pump is installed into the ported receptacle. The procedure for installation of the pump and commissioning is the same as the jet pump. Scheduled maintenance change-outs of the pump should be planned as the pump design is more complex than the jet pump and more susceptible to wear and tear.

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SUBSEA COMPLETIONS The design and installation procedures for subsea wells is significantly different from land and platform wells. Although the downhole completion equipment is generally the same, the subsea wellhead and subsea Xmas tree systems are totally different and are also manufacturer specific. Similarly, well interventions methods from floating vessels are much more complex requiring specialised well intervention or workover systems. In today’s technology, there are two main types of subsea Xmas tree and intervention systems termed ‘Conventional’ and ‘Horizontal’. The conventional subsea completion system utilises a Xmas tree with valving configurations similar to dual surface Xmas trees, to which a dedicated well intervention riser, run from the vessel, can be attached. After latching to the subsea Xmas tree and testing the integrity of the system, well servicing operations such as wireline and coiled tubing can be safely conducted through the riser into the wellbore. This riser system is also utilised for the installation and retrieval of the subsea tree. This design, however, has some drawbacks in that the dedicated riser systems are extremely costly to purchase and maintain, especially for fields with only a few wells over which to share the costs. Nowadays, some standardisation has been adopted between manufacturers and riser systems which are adaptable to various manufacturers subsea trees are offered on a rental basis, however their availability at critical times may not always be guaranteed. Further to this, in order to re-complete or workover a well, the conventional system requires the subsea tree to be recovered and a marine riser system deployed to be able to pull the completion string. A less costly alternative to the conventional subsea tree system, is the ‘Horizontal’ (sometimes refereed to as ‘Spool’) system. This only requires the use a conventional drilling marine BOP riser system for re-completion or workover. Tie-back strings and tooling back to surface are deployed through the riser to enable access to the tubing bores. The horizontal system design uses a casing head spool through which casing and the completion string can be installed (with the tree production valves equivalent to two master valves on the horizontal flowline bore). This enables re-completion or workover operations to be conducted without having to pull the subsea tree and without having to purchase a dedicated riser system. The drawback of these systems is the complexity of the re-entry tools used inside the marine riser for wellbore re-entry (dual subsea tree, tubing running tool, etc.). Note:

As subsea completion systems designs and procedures are specific to the project/manufacturer, the conventional Cooper system is described in this section which was used on the Eni-Agip UK Toni Field which is typical example of a subsea completion system.

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SUBSEA EQUIPMENT PRE-DEPLOYMENT TESTING Refer to specific field downhole, and subsea completion equipment, contained in the completion programme. The pre-deployment procedures given in this section are intended to be generic, however some designations or abbreviations used may tend to reflect the Eni-Agip UK Toni development which was the first development on the T-block.

11.1.1. Guidewire Establishment Tool Guidewires can be run and attached to the guideposts separately by lowering the latches attached with a suitable clump weight and having a diver or ROV aligning them to each post, in turn. The alternative method is to use a guidewire establishment tool. This tool is simply a frame deployed on drill pipe which correctly spaces out the latches and attaches all four guidewires at once after a diver or ROV has aligned the frame. • • •

The tool should be checked to ensure it has not been damaged and is intact. Check that the connectors fit the tool. Check the lower/pulling pad eyes and shackles, etc.

An alternative guidewire running tool for use in deep water, combines a camera and guide frame deployed on drillpipe which is steered by fluid jets. Pumping down the drillpipe steers the tool via the jetting nozzles, and the camera allows the observation of the positioning and orientation of the collet connector above the guide post. One draw back of this tool is the ability to run only one guideline connector at a time. The tool should be checked to ensure that it has not been damaged and is intact. • Check that the connectors fit the tool. • Check the nozzles operate correctly. • Attach the camera umbilical and ensure the camera is operational. 11.1.2. Guidewire Latchess Ensure that the collet latches are in good serviceable condition and that the guidewires have been correctly attached. Ensure that contingency attachment and retrieval procedures are available in the event a post is damaged, unless retrievable guideposts are installed (Refer to section 11.1.3). 11.1.3. Diverless Guideposts Diverless guideposts are run and installed in the permanent guidebase or production guidebase and should be check prior to running. • •

Check the latching mechanisms or post retainer pins to observe that they are fully operational (by ROV). Check the latching profiles on the posts to ensure they are not corroded or damaged.

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11.1.4. Casing Hanger Elevation Test Tool Some systems have an elevation test tool to check the casing hanger has been correctly installed. It is run through the drilling riser to check the hanger before committing to pulling the BOP stack. The tool usually consists of a locating shoulder and lead impression blocks which when landed off and pumped out will establish the vertical position of the hanger in the wellhead, once the impressions are inspected and measured. With this type of tool it is necessary to close the divertor or a set of pipe rams and pressurise the annulus to 500psi to ensure full retraction of the impression blocks. •

Ensure the impression block system is operative and set in the retracted running position. Check the connection and that any crossovers required, are on hand.

11.1.5. Tubing Hanger System The tubing hanger assembly consists of the hanger and a pup joint, typically 10ft long, and necessitates the hanger stand being located over a suitable hole in the deck or drill floor. A typical configuration of tubing hanger equipment including the running tool, prior to running, is shown in figure 11.a. The following sequence of pre-deployment testing is typical for a tubing hanger. 1)

2)

3)

Locate the tubing hanger stand in a suitable location over a hole on the deck for the pup joint/joints. This location must be within the reach of a crane which can access the derrick V-doors. Proceed to set up the seals, inspect and check the tubing hanger as per the manufacturer’s operating manual. In addition, note the following: • Ensure that anti-rotation pins are fitted. • Check that the hanger bores are clean and undamaged. • Check landing nipple profiles where fitted. • Check that the correct orientation key is fitted, if applicable. • Grease the appropriate parts of the hanger lock-down parts. • Fit the control line tubing connectors to the tubing hanger. • Inspect electrical cable tails where fitted. • There is a considerable risk of causing damage to the tubing hanger nose seal area when installing or retrieving a hanger in the tubing hanger stand, therefore, the hanger should be installed in the stand a minimum number of times. When preparation of the tubing hanger is complete, leave the tubing hanger in the tubing hanger stand or remove the hanger from the stand and lay back down in its shipping box. Protect the tubing hanger from mechanical and weather damage.

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Figure 11.A - Typical Tubing Hanger Configuration Prior to Running

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11.1.6. Tubing Hanger Running/Orientation Tools This section details the pre-testing of a typical production tubing hanger running tool system consisting of the following items of equipment (shown with common abbreviations): • •

Tubing Hanger Running Tool, (THRT) Tubing Hanger Orientation Tool, (THOJ).

Some systems have the THRT and THOJ as separate tools, whilst other systems have a single run/set and orientation tool. For setting up of the orientation of the THRT/THOJ refer to the Manufacturer’s Operations Manual. Pre-deployment testing may be performed, either on the rig deck or drill floor, and involves stack-up of the THRT on the tubing hanger and utilises the test stands. Tests, according to the manufacturer’s operating procedures manual, will be required to verify the integrity of the system. These will cover the following aspects: • • •

Cleanliness of the hydraulic systems meets with the specification, especially the sub-surface safety valve line, usually to NAS 1638 class 6 or better. Operation of all of the THRT functions. Pressure integrity and operation of all hydraulic lines from the panel to the tubing hanger.

The following tests are required to test the integrity of the system. Afterwards the THRT and tubing hanger assembly will remain as one unit stored on the rig floor, connected to the utility umbilical, if possible. A second or back-up system must be available for testing. The testing procedure can be modified as long as the overall testing requirements are satisfied: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15)

Check the tubing hanger in its shipping box (Refer to previous section). Install the tubing hanger in the tubing hanger stand over a suitable hole in the deck. Position the THRT tool stand. Install the THRT in its stand and test. Interface test and flush the THRT with the tubing hanger in the stand. Check and position the tubing hanger body seal. Check the THOJ and flush through the tool. Move the THRT and stand up to the rig floor. Move the THOJ to the rig floor with the handling tool and make up to THRT. Return the complete assembly to the deck and test. Before running the tubing, return the complete tool to the rig floor. Run through the rotary and make up to enough joints of tubing or 5” DP to stand the assembly back in the derrick. Hook up the utility umbilical. Stand back in the derrick. Test the function lines.

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These activities are described in more detail in the following sections. Refer to the specific manufacturer’s Operation and Maintenance Manual for additional instructions. It should be noted that pressure tests conducted through flexible hoses will be subject to some pressure decay caused by umbilical expansion. For this reason, an acceptable pressure decay should be established during chart recorded tests. All site received inspections and ECR punch list items relating to this equipment must have been satisfactorily addressed before proceeding. THRT Preparation 1) 2) 3) 4) 5)

Locate the THRT stand adjacent to the tubing hanger stand on the rig deck and within hot-line range of the control panel. Perform THRT preparation according to the Manufacturer’s Operating Manual. Perform LATCH/UNLATCH and LOCK/UNLOCK tests. Check the orientation key function and that the correct key is selected to ensure correct orientation of the hanger. Install the running tool back onto the stand.

Interface THRT with the Tubing Hanger 1)

2)

3) 4) 5) 6) 7)

8) 9) 10)

If not already done, install the tubing hanger in it’s stand. Ensure that all seal pockets are clean and lubricated with control fluid. Install a connector (or dummy) into the top of the downhole pressure transducer bore, if not already fitted, to enable a peripheral test to be conducted and the connector to be tested. (Beware of damaging any nose seal components against the tubing hanger stand). Using hotlines connected to the THRT, proceed to remove the tool from it’s stand and interface it with the tubing hanger according to the operating procedures. The tubing hanger must be in the locked position prior to this activity. The TH/THRT interface should now be tested (by chart or gauge) in order to verify the interface and all functions. Additionally, all TH lines must be flushed to the correct cleanliness specification. Fill the TH/THRT cavity. Proceed to function and pressure test. Pump control fluid through the sub-surface safety valve line and injection lines to check continuity. Cap the pre-installed fittings in each bore in the bottom of the tubing hanger and pressure test each line. Unlock the tubing hanger. Disconnect the THRT from the tubing hanger. Pick up and land in the nose protector. Secure and vent all pressure to the THRT. Leave the tubing hanger in it’s stand and remove the electrical connector. Ensure that the hanger top face is protected against damage and weather.

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THOJ Preparation 1)

2) 3) 4)

Check end connections and seals when horizontally located on the deck. Check that there is no evidence of orientation sleeve and slot damage. Check the orientation sleeve securement pins and field welds for damage or distortion. Check the downhole pressure transducer connectors. Fit the flushing tool to the bottom end of the joint, hook up the utility or test umbilical to the top and circulate/flush as necessary to achieve the required hydraulic cleanliness. Disconnect the utility or test umbilical and cover/protect any quick couplers. Fit the handling tool to the top end of the joint.

Connect THOJ to THRT (if required) 1) 2) 3) 4) 5)

The THRT and its nose protector must be moved to a position close to the rotary table to enable stabbing of the orientation joint. Check all faces, seals and alignment pins and replace as necessary. Check the downhole pressure transducer connector. Pick up the prepared THOJ and pre-fitted handling tool and make up to the THRT checking all seals and connectors, etc. Pick up the assembly and return to the test area on the deck where access to the utility umbilical is available.

THOJ and THRT Interface Tests 1)

Temporarily connect the utility umbilical to the THOJ, securing the umbilical termination.

WARNING: Do not bend the umbilical beyond it’s minimum specified bend radius. 2) 3) 4) 5)

6)

Function and test all lines. Vent all pressure after the testing. Insert a test plug in each of the lower end stab pockets in turn and pressure test and flush to specification. Check the transducer connections for continuity and resistance from the utility reel to the lower end of the running tool. If necessary, test the THOJ/THRT interface during the electrical test and record on a chart. Recheck all seals at the base of the THRT after testing, replace as necessary and refit the nose protector.

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Make Up and Testing the THOJ/THRT 1) 2) 3) 4) 5) 6)

Make-up a handling string of tubing joints or 5” drillpipe and lay down on the catwalk. Disconnect the utility umbilical from the THOJ, ensuring minimum contamination to the hydraulic system. Pick up the riser handling tool/THOJ/THRT assembly and move to the rig floor. Make-up the handling string of tubing joints or drillpipe to the riser handling tool. Pick up the assembly, taking extreme care not to damage the electronic/hydraulic quick couplers when pulling out, until the couplers are 3ft above the rotary table. Connect up the utility umbilical. Ensure that hydraulic contamination is minimised during hook-up.

WARNING: Do not bend the umbilical beyond it’s minimum specified bend radius. 7) 8) 9) 10) 11) 12) 13)

Ensure the umbilical clamps are a tight fit. Ensure that the installed clamp dimensions are within the BOP diameter. Umbilical tails must be plaited as necessary to take up any excess length and to provide protection. Protect hoses as much as possible by tying back to the riser pipes. Fit a hose protector if provided. While handling the sheave and paying out the umbilical, stand the assembly back in the derrick and secure to protect from unnecessary damage. When stood back, the final pressure and function tests of the lines from the panel to running tool can be performed in order to save time later. The THOJ/THRT assembly is now ready for use.

11.1.7. Tubing Hanger Verification Tool The tubing hanger verification tool is used to check the positioning of the hanger within the wellhead after being set, with regards to orientation and height. This ensures that the subsea Xmas tree’s stabs will correctly align with the bores in the hanger thus saving them from being damaged if misaligned or if the tubing hanger is set too high. Note:

Some subsea tree designs have extension subs that can be shimmed and/or slide within seal pockets to adjust for any incorrect stack up heights of the casing hanger or tubing hanger assemblies. Typically this adjustment is limited to a maximum of 1 to 2ins.

Mechanical probes, sleeves, lead impression blocks are all used in various tool designs with some being diver assist. • • •

The tool’s probes or shear sleeves must be set and pinned according the Manufacturer’s Operating Manual. Care should be exercised so as not to accidentally clash with other equipment and inadvertently move the probes or sleeves thus giving a false indication/impression. If diver assist, the diver must be fully versed in the tool operation.

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11.1.8. Tubing Hanger Isolation Plugs The tubing hanger isolation plugs are wireline installed and are described in the specific well programme. •

Profiles should be inspected for any damage.

11.1.9. Subsea Tree And Workover Equipment This section describes in outline the pre-test activities to be performed on: • Subsea Xmas Tree (XT) • Lower Riser Package (LRP) • Tree Running Tool (TRT) or Emergency Disconnect Package (EDP) • Tree Cap • Tree Cap Running Tool (TCRT). Preparation of this equipment, up to the end of the main and utility umbilicals, is addressed in the following sections. After each of the above items is loaded onto the rig, a Site Received Test should have been performed. Thereafter, the equipment will be stacked, function and pressure tested on deck to verify equipment performance prior to running. Assuming that all the necessary equipment is available, SRTs are complete and ECR Punch Lists are acceptable, pre-deployment testing should commence as defined below. Note:

The manufacturer’s Operation and Maintenance manual should be followed for detailed specific procedures.

Pre-test activities should be performed on deck and conducted according to a plan provided in the well programme. 1)

2)

Place the XT on the XT test base and the tree cap on the LRP test base ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned. Flush the control lines to the specified cleanliness standard. XT XT

+

XT BASE

=

XT BASE

TCRT TCRT CAP CAP + LRP BASE = LRP BASE 3) Test the XT/XT base interface, i.e. AX/VX gasket, production, annulus and flowline bores. 4) Integrate the XT and tree cap ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned.

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Test production, annulus bores and peripheral area. TCRT CAP XT XT BASE

TCRT CAP

XT 7) 8) 9)

XT + = BASE Flush all XT and cap control lines. Pressure test lines. Assemble the Subsea Control Module (SCM) to the tree assembly ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned.

TCRT CAP

TCRT CAP

SCM

SCM XT + = XT XT BASE XT BASE 10) Function and test via the Portable Electronic Simulator Unit (PESU): • • • 11)

LRP

12)

If the LRP and TRT control fluids are acceptably clean, stack p as shown and test the interface ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned. +

TRT LRP LRP BASE Flush all lines. Hook up to Workover Control System (WOCS) and perform: • • •

13)

DHPTT and sensor readings Platform PCS commands and shutdown sequences Hydro-test both sides of actuated valves.

LRP BASE

+

TRT

=

Pressure test of bores and AX/VX cavities Pressure test of control lines at TRT/LRP interface Hydro-test both sides of LRP valves.

Integrate the LRP on the XT assembly ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned.

TCRT CAP

TRT LRP

SCM -

XT XT BASE

TCRT CAP

+

TRT LRP

SCM

= XT XT BASE

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Pressure and/or function test through the WOCS: • • •

15) 16)

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LRP AX/VX line, production and annulus bores. All XT/LRP control lines. Ensure that any accumulators fitted to the LRP are charged and charging following functioning of the valves supplied by the accumulator. The accumulator vent function (to the sea or to an atmospheric cylinder to improve valve response times) should be checked on surface.

Drift production and annulus bores through entire stack-up. Re-check SCM functions by operating against the LRP.

This completes the XT/SCM/LRP/TRT preparation. Flushing XT and Tree Cap 1) 2) 3)

4)

Note:

Prepare the XT for interfacing with the tree test base in accordance with the Manufacturer’s Operating Manual. Completely fill the production and annulus flowline hub bores with water. Lift the tree using the handling tool and lock the XT onto the XT test base using hotlines ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned. Flush and sample the lines as necessary. Clean the tree control lines to the specified cleanliness to enable the tree and cap to be interfaced. This step may be omitted if the tree is known to be clean through previous flushing. Hydraulic cleanliness must be verified by sampling 3 lines at random within each assembly. All three samples must all meet hydraulic cleanliness criteria. The combined XT and cap will be flushed together later. This activity should be conducted with the assistance of a tree schematic which will show all the lines on the tree.

5)

6) 7) 8)

9) 10)

Note:

Hotline open the ASV and AMV and drift the tree production bore valves. Close the valves after drifting. Valve indicator pins where fitted should be observed for correct action and travel. Pressure test the XT/test stump interfaces through the test skid lines. If required, hook up the DHPTT simulator to the electrical lines emerging from the base of the tubing hanger simulator and check. Fill the tree and test stump with water to aid later testing when the cap is installed on the tree by using hotlines to open all necessary valves. Valve indicator pins where fitted should be observed for correct action and travel. Bleed air from test stump connections as necessary. Prepare the tree cap on the maintenance stand for interface with the LRP/Tree cap test and flushing skid. Tree cap flushing may be omitted if the cap is known to be clean from previous flushing. Hydraulic cleanliness must be verified by sampling any

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3 lines at random. All three samples must meet with hydraulic cleanliness criteria. 11)

12) 13) 14) 15) 16) Note: 17)

Place the cap on the cap test and flush stand and pressure test the production and annulus bores ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned. Prepare the cap for TCRT interface according to the Manufacturer’s Operating Manual. Prepare the TCRT according to the Manufacturer’s Manual. Install the test sub into the top of the TCRT and torque up tight on the drill floor. Install a 15ft pup joint above the sub. Use hotlines or the TCRT umbilical to function and pressure test the tool. There is no hydraulic cleanliness requirement for this equipment. Leave the pressure locked in the tool running string.

XT Cap Installation on Tree 1)

2) 3)

Pick up the TCRT using the lifting sub and interface with the XT according to the Manufacturer’s Operating Manual ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Check the cap position indicator and adjust as necessary. Pressure test the TCRT/Tree Cap/XT interface. Be sure to vent adjacent volumes during the test. After the test, vent pressure from the TCRT running string. Leave the XT Base/XT/Tree Cap/TCRT as a stack up for further testing. Do not remove the TCRT.

Flushing and Testing the XT and Tree Cap Hydraulic Lines 1) 2) 3)

Note:

Use clean hotlines on the tree to flush all lines on the assembled XT and tree cap to the specified cleanliness. Flush the methanol line by opening the necessary valves using a hotline. Valve indicator pins where fitted should be observed for correct action and travel. Pressure test all control lines to the working pressures stated in the operating manual using a test pump and chart recorder. Visually check for leaks. Extreme care must be exercised to avoid inadvertently over-pressuring return lines. This can occur if the return relief isolation valves are closed or the return line is blocked when functioning valves. Over pressurisation can be avoided by ensuring that the return line relief isolation valve on the trees are open during testing activities.

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Integrate Tree/Tree Cap with Surface Control Module (SCM) and Test Stump 1) 2)

3)

Ensure the SCM has been fully inspected and tested upon the SCM test and flushing skid according to the relevant procedures. Pick up the SCM, check all the connections, and without the use of the SCM running tool, land on the XT mobile mounting base (MMB) ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned. This is a very critical activity and extreme care must be taken to avoid damage. Lock the SCM to the MMB by setting weight on the locking bar.

Prepare the LRP and TRT 1) 2) 3)

4)

5) 6)

Note:

7)

8) 9) 10) 11)

Assemble the TRT drill pipe adapter to the TRT. Ensure that a lifting sub has been torqued into a TRT drill pipe adapter on the drill floor. Pick up the TRT and land on the stand. Check the hydraulic cleanliness of any 3 TRT control lines and, if better or equal to specification, no further flushing will be necessary before integration with the LRP. If not, wash down couplers with solvent and check all TRT seals in preparation for interface with the LRP/Tree cap test and flushing skid. Assuming that no flushing of the TRT in isolation is necessary. Check and replace production and annulus lower stab seals, if necessary. Replace the TRT AX/VX gasket with a new gasket. This is the final opportunity to install a new gasket in the TRT. Remove the TRT from the stand and set on the deck. Install the LRP on the stand. Check both LRP connector stab seals and replace as necessary. Check the AX/VX gasket and replace, if necessary. The seals and gaskets will be rechecked later before stacking the LRP/TRT onto the tree. Pick up the LRP using slings or the tree handling tool and land over the LRP/Tree cap test skid. Use hotlines to lock the LRP to the skid ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned. Perform a brief pressure gauge test of the LRP/Test skid hub interface to obtain confidence in the interface sealing. Flush the control lines through the skid until the required cleanliness is achieved. When hydraulic line cleanliness is satisfactory, remove the tree handling tool. Ensure that the WOCS is fully flushed and tested, then connect the main umbilical to the TRT.

WARNING: Do not bend the umbilical beyond it’s minimum bend radius. 12)

13)

Pick up the TRT and carefully set over the LRP ensuring that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned. Test the LRP and TRT connector control lines.

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Flush the combined LRP/TRT as a unit. Test and chart record the TRT AX/VX test. Test the LRP AX/VX gasket. Test all the functions per the Operating Manual. Open all the LRP valves and fill the LRP with water. Valve indicator pins where fitted should be observed for correct action and travel. Pressure test and chart record either side of the LRP valves. Vent all pressure after the tests and check that all LRP valves are closed. Valve indicator pins where fitted should be observed for correct action and travel. Pressure test the SCSSV1 line. At the LRP/tree cap test stump, perform a hydro-test.

The LRP/TRT/WOCS system is now tested as a unit and is ready to be integrated with the tree, (Refer to Section 8 for details on WOCS). 11.1.10. Install the LRP/TRT onto the XT 1) 2) 3) 4)

Remove the tree cap from the tree then lift up the TCRT to remove the cap. Land the Tree Cap/TCRT on the deck. There is no need to separate these items. Prepare the tree as per the Manufacturer’s Operations Manual. Lift the LRP/TRT stack from the LRP/Tree cap test skid using the TRT drill pipe adapter and place it onto the test/flushing stand: Prepare the underside of the LRP for final assembly on the tree. • Pick up the LRP/TRT stack from the test flushing stand and carefully land on the tree in the correct orientation, checking that the ROV faces correspond. Ensure that the connectors are fully unlocked prior to interface and correctly locked following interface. Connector indicator pins should be observed to be correctly positioned. Test XT/LRP/TRT Stack Note:

1) 2) 3) 4) 5) 6)

Throughout all tests check that return flows generally match and that there is no visible return line leakage. Because of line expansion and effects from adjacent lines in the umbilical, inconsistent supply and return flows can occasionally be experienced. Verify LCP status. Open the LRP valves. Pressure test the LRP AX/VX cavity. Open the LRP XOV. Fill the tree above the swab valves with water. Hydro-test the production and annulus bores.

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Pressure test the tree AX/VX line. Pressure test below the seals and controlled landing blind stabs in the base of the tree. At the LCP, operate the following functions in the order shown: Valve Function IUMV OPEN IWV OPEN AMV OPEN AWV OPEN XOV OPEN When pressure has stabilised, zero the LCP and return flow meters and monitor. Also check visually for leaks. Close valves after the test. Valve indicator pins where fitted should be observed for correct action and travel.

10) 11) 12) 13)

Pressure test the SCSSV1 line from above and below. Check line continuity, then close the tree AX/VX test line isolation valve. Pressure test the tree connector AX/VX line. Pressure test below the tree AX/VX isolation valve. After the test, open the tree AX/VX test isolation valve to prove HPP to test base continuity.

Drift Tree/LRP/TRT Stack 1)

2) 3)

Check that all LCP functions are vented at the LCP with the exception of: Function Status

6) 7)

LOCK

LRP connector

LOCK

ESD supply

at correct pressure

Remove the TRT drill pipe adapter. Open the following vertical bore valves. Valve indicator pins where fitted should be observed for correct action and travel: • • • • • •

4) 5)

TRT connector

LRP PV LRP AV ISV ASV IUMV AMV

Check that the manual PLMV is open. Measure the depth from the top of the TRT to the test base production and annulus pockets and mark drift lines accordingly. Vent lines on the tree test stump to drain the bores of test water. If necessary, clear the bores of excess grease using a rubber disc on drain rods. Drift the Tree/LRP/TRT stack from top to bottom with the drifts specified in the manual. Close the valves after drifting is complete. Replace the TRT drill pipe adapter on the top of the TRT.

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Final Tree/LRP/TRT Preparation 1) 2) 3) 4) 5) 6)

7) 8) 9) 10) 11) 12) 13)

Refit the TRT drill pipe adapter to the top of the tree assembly. Flush the SCSSV1 and AX/VX test lines from the LCP to the tree test stump. At the LCP, unlock the flowline and wellhead connectors. Verify LCP status for other functions. Verify visually that the wellhead and flowline connectors are unlocked. Pick up the full Tree/LRP/TRT stack with the main umbilical attached, taking extreme care not to exceed the minimum umbilical bend radius or over-stress the umbilical attachment point on the TRT. Land the assembly in the correct orientation on the handling/support skid. Replace all gaskets and seals in the underside of the wellhead and flowline connectors. Set the tree manual valves as per the Operating Manual. Perform a final pre-submergence check according to the Operating Manual. When all checks are complete, pick up the Tree/LRP/TRT/main umbilical stack, and land out on the handling/support hub or skid beams. When landed on a handling/support hub, lock the tree to the mandrel. Remove the TRT drill pipe adapter in preparation for later fitting of the stress joint.

Summary of Tree System Pre-deployment Testing A summary of the pre-deployment testing should be confirmed by checking off the checks/tests in a table. 11.1.11. Production Riser 1) 2) 3) 4) 5)

Carefully remove the sections of riser from the shipping baskets and lay out on the pipe rack. Check that all joints, stress joint and surface joint are present. Remove the protectors and check the connectors and connection seals for damage and replace, if necessary. Ensure the connections are suitably covered in grease for weather protection. Replace the protectors. Ensure sufficient riser handling tools are available and check connectors and connection seals. Ensure riser handling tools have current certification.

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11.1.12. Surface Xmas Tree The surface Xmas tree or terminal head should be removed from the shipping frame and all valves tested from above and below to working pressure. Ensure that the lift frame (if applicable) has been shipped and is undamaged. If long bails are utilised, ensure they are located, identified and have current certification. These items may be stored out of the way until immediately before they are required. Check that the lifting frame will not clash with the derrick structure. If coiled tubing services are required later, it is recommended that a lift frame be utilised rather than long bails. Where wireline adapters are fitted to the crown flange ensure that the necessary seals are in good order and any required crossovers are like wise identified. 11.2.

DEPLOYMENT PROCEDURES The following procedures are guidelines only and therefore engineers must ensure that equipment specific procedures from the manufacturer’s Operating Manuals are used for equipment deployment.

11.2.1. Running The Completion And Tubing Hanger 1) 2) 3) 4) 5)

6) 7) 8) 9) 10)

11) 12)

Clear the rig floor of all non-essential tools and equipment. Assemble well control crossovers to the safety or Kelly cock valves and clearly mark for easy identification. Set aside in an easily accessible place on the drill floor. Move the TH handling string dual handling equipment to the rig floor. Rig up the torque/turn analysis with powered tubing tongs equipped with integral back up tongs and stand back in the derrick. Position the electrical cable/control line protectors in a drum on the rig floor and use only from the drum as required. Tubing protectors must be removed placed in a basket immediately when removed from running joints. Rig up the dual landing string elevators. Pick up the THRT/THOJ/handling sub assembly and install on to a dummy or used hanger, making up the THRT umbilical if not already made up. Lock the THRT to the hanger, lock in the pressure at the umbilical reel and disconnect the umbilical jumper. Attaching the umbilical to the strings, run in the hole on drillpipe/tubing stands. Run in the hole and on the compensator, gently tag the hanger in the wellhead recording the exact depth that the weight drops off and marking the pipe at the rotary table. Repeat the procedure ensuring the depth remains the same. Pull up until the tool is 10ft above the orientation key/slot (for whichever type of system is being used. Hydraulically activate the orientation key and slowly lower the handling string observing for orientation of the string. If the string does not turn, apply a chain tong and check that it is correctly engaged in the slot. check the depth is the same as found in step 10 above. Repeat the procedure if it is felt there may be any uncertainty.

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10) 11) 12) 13) 14)

15)

16) 17) 18)

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If necessary to check the ram sealing ability on the THOJ, close the rams, install the safety valves on the landing strings and test down the kill line to the appropriate pressure, usually 1,500psi. Painting the THOJ white will give confirmation that the tool has been correctly positioned within the stack. Bleed off the test pressure, open the rams and pull the landing string, strap the pipe if necessary. Observe the paint on the THOJ and for signs on the dummy hanger that it was properly positioned. Close the blind rams and disconnect the dummy hanger. Pick up the allocated TH and pack off into the rotary table and attach the THRT/THOJ to the hanger. Check that the TH seals have not been damaged and install the protection cap. Stand the complete assembly back in the derrick. Rig down the dual elevators and rig up the single completion handling equipment. Ensure the completion sub-assemblies have been laid out in correct running order and appropriately numbered. Refer to completion installation procedures in section 8. Run the string to the hanger installation point and, according to the completion design and procedures in the well programme, conduct the spacing out operations or install the hanger/THRT assembly. Terminate and connect up the control line and electrical cable. Pressure test the SCSSSV control line on the control panel. Check electrical continuity. Conduct the final tubing pressure test and any other necessary tests according to the Operating Manual. Run the completion string to depth on the hanger landing strings, locking pressure in all the correct functions. When 10ft above the hang off point, activate the orientation mechanism and lower the hanger until soft landing into the wellhead. Check the depth marks on the landing string confirming proper depth location. Check with chain tongs that the orientation slot is engaged. Repeat the procedure only if absolutely necessary as damage to the control line or cable may be caused by cycling in and out of the hole. Ensuring all the completion string weight has been hung off, proceed with the hanger setting and testing procedures as per the manufacturer’s Operating Procedures Manual which will test: • Production string • Annulus string • Above the hanger • Below the hanger • All control or injection lines • DHPTT cable. Rig up wireline and plug the well for BOP removal according to the well programme. Unlatch the running tool from the hanger and retrieve the landing string to surface. If applicable, run the TH orientation or verification tool.

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11.2.2. Pull The Drilling BOPs Displace the riser to seawater and pull the stack as per the Eni-Agip Drilling Procedures Manual. 11.3.

WORKOVER TESTING

AND

PRODUCTION

CONTROLS

SYSTEM

PRE-DEPLOYMENT

11.3.1. Workover Controls Equipment This section describes in outline the pre-test activities to be performed on: • • • • • • • • • • • • •

Workover Hydraulic Power Pack (HPP) Local Control Panel (LCP) Remote Control Panel (RCP) Remote ESD Panel (RESDP) Surface Tree ESD Panel (STESDP) Main Workover Umbilical Reel (MUR) Utility Workover Umbilical Reel (UUR) TCR Umbilical Reel (TUR) Hydraulic Interconnection Jumpers Electrical Interconnection Jumpers ESD Radio Link Remote Telemetry Unit (RTU) ESD Radio Link Battery Unit ESD Radio Link Antennae ‘A’ and ‘B’.

The arrangement of these are shown in figure 11.b. The WOCS usually operates on three modes to accommodate running or retrieving: a)

Tubing Hanger System.

b)

Subsea Xmas tree and workover riser.

c)

Tree Cap.

11.3.2. Production Controls Equipment This section describes in outline the pre-test activities to be performed on: • • • •

Subsea Control Module (SCM) Subsea Control Module Running Tool (SCMRT) Subsea Control Module Flushing and Testing Unit (SCMFTU) Portable Electronic Simulator Unit (PESU).

After each of the items are received onboard, a Site Received Test should first be performed. It is then to be tested to confirm operation before use. The pre-deployment test procedures for both systems is detailed in the following sections.

11.3.3. WOCS Pre-Deployment Testing

TRT

Control Lines

Control Lines

Figure 11.B - Typical WOCS Layout XT

THRT

THOJ

Air

TCRT Umbilical Reel

TCRT

STAP -P-1-M-7120

SCM RT

SXT

PAGE

XT

Air

Utility Umbilical Reel

Control Lines

Remote ESD Panel

RCP

Battery

IDENTIFICATION CODE

LRP

Main Umbilical Reel

Hydraulic Power

LCP

Hydraulic Power

HPP

Safe Area

Antenna 'B'


Air

Air Supply

Elecrtical Supply

SXT ESD Panel

ESD Radio Link

Antenna 'A'

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All tests will be in accordance to the manufacturer’s Operating and Maintenance Manual and should meet the guidelines below. System Test Procedure Check and prepare the hydraulic supply panel as follows: 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16) 17) 18) 19)

Ensure that all Site Received Inspections have been carried out and that ECR punch lists have been actioned. Locate and secure all equipment in the locations shown in the Well Programme. Ensure they are properly earthed. Check the status of all valves, adjustable controls and switches. Attach dedicated air and electrical supplies to the HPP. These should be appropriately marked or locked to ensure they are not accidentally disconnected. Connect air supplies to the MUR, UUR, and TUR. Ensure the HPP has sufficient reserves of control fluid, and that accumulators are fully charged. Hook up to the HPP with the jumpers to the MUR and UUR. Connect the electrical jumpers. Establish the radio link with the Tiffany platform and function test. Hook up the RCP, RESDP, STESDP and RTU. Check the operation of the LCP functions. Check the operation of the RCP functions. Check the operation of the RESDP functions. Check the operation of the STESDP functions. Check the operation of the MUR functions. Check the operation of the UUR functions. Check the operation of the LCP functions. Flush and test all control lines within jumpers and umbilicals, but not TCRT umbilical lines. Check the operation of all reel air motors.

WOCS ESD Tests This procedure tests the workover ESD function using the LCP, RCP and RESDP panels and should be conducted after the full stack up integrity tests described in Section 7.10. Note:

During the following tasks the subsea ESD accumulator should re-charge after each ESD test, but allow 5min between tests to provide sufficient time for re-charging.

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Perform WOCS ESD sequences as follows: 1)

2)

Ensure that the ESD accumulator on the LRP is fully charged and attach a suitable range pressure gauge to the SCSSV1 line on the tree test stump. Check that the LCP and tree is correctly set according to the Manufacturers Instruction Manual. Depress the workover ESD push-button at the LCP. a) Verify that the following valves close: • • •

LRP PV LRP XOV LRP AV.

Record that the operating time until the last valve closes is according to the time specified in the manual and within tolerance. b)

Verify that the next set of valves close: • • • • • • •

PWV AWV XOV PSV ASV Methanol Injection Valve Scale inhibitor Injection Valve.

Record that the operating time until the last valve closes is according to the time specified in the manual and within tolerance. c)

Verify that the next set of valves close: • PUMV • AMV Record that the operating time until the last valve closes is according to the time specified in the manual and within tolerance.

3)

e)

Verify that the SCSSV1 line depressurises at the correct time after the workover ESD button was pressed on the LCP.

f)

Unlock the workover ESD push-button at the LCP.

g)

Operate the workover ESD, reset push-button on the LCP after the ESD sequence is completed.

h)

Verify that the workover ESD lamps at the LCP, RCP, and RESDP switch off.

Enable the RCP at the LCP and re-open all the actuated valves as per step 1 above at the RCP. Verify at the LCP gauges, SCSSV1 test base gauge and by visual inspection. Also check that the ESD supply is fully charged.

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Depress the workover ESD push-button at the RCP. a) Valve closure should be identical to that monitored in step 2 overleaf. b)

Unlock the workover ESD push-button at the RCP.

c)

Operate the workover ESD reset push-button on the LCP, after the ESD sequence is completed.

d)

Verify that the workover ESD lamps at the LCP, RCP and RESDP switch off.

Disable the RCP at the LCP. Re-open all the actuated valves as per step 1 overleaf at the LCP. Verify at the LCP gauges, SCSSV1 test base gauge and by visual inspection. Also check that the ESD supply is fully charged. Depress the workover ESD push-button at the remote ESD panel. a) Valve closure should be identical to that monitored in step 2 overleaf. b)

Unlock the workover ESD push-button at the remote ESD panel.

c)

Operate the workover ESD reset push-button on the LCP, after the ESD sequence is completed.

d)

Verify that the workover ESD lamps at the LCP, RCP, and RESDP switch off.

11.3.4. Production Controls Pre-Deployment Testing This test sequence must be done during the pre-deployment testing on the subsea tree in section 11.1.9. Function Test the Tree through the PESU Hook-Up 1) 2) 3)

4)

Using the dedicated electrical cable provided, set up the PESU and hook up to the tree test stump electrical connection plate. Power up the system and perform electrical checks. Connect up LP, HP and return hydraulic lines to the tree test stump bulkhead plate taking supplies from either the HPP or the outboard end of either the main or utility umbilical jumpers. Power up the tree hydraulically.

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Check Sensors 1)

2) 3)

Configure the PESU as a surface unit with the supplier’s protocol. Send a BREAK STATE REQUEST COMMAND to SEM A. Verify that all valves and indicators are shown as ‘OK’. Send an ANALOGUE DATA REQUEST COMMAND to SEM A. Verify that all transmitters are indicated as ‘(tick)’. Verify that readings for Annulus Pressure and Production Pressure are correct. Ensure that the bores are vented at the block elbows by opening the wing valves, hence ensuring pressure is not locked in. Injection Pressure Ambient pressure = __________ barg PESU reading Converted PESU reading

= =

__________ mA

350 x (PESU reading diff. from 4.00) 16

= (Acceptance criterion is +/- 2.2 bar) Annulus Pressure Ambient pressure PESU reading Converted PESU reading

=

= =

__________ barg __________ mA


=

(Acceptance criterion is +/- 2.2 bar) 4)

__________ barg

__________ barg

Verify that reading for production temperature is correct by comparing it against a calibrated mercury-in-glass thermometer. _________oC

Mercury-in-glass thermometer reading (Calibrated thermometer to be accurate to +/-0.5 oC) PESU reading Converted PESU reading

= =

_________ mA


=

_________ oC

(Acceptance criterion is +/- 1.1 degrees C) 5) 6) 7)

Switch on the DHPTT Simulator and set it to PANEX: 32 mA. Send a number of DHPTT DATA REQUEST COMMANDS to SEM A until a DHPTT DATA MESSAGE is received. Select Range Option 1 on the DHPTT Simulator, wait 20 seconds for stabilisation and send a DHPTT DATA REQUEST COMMAND to SEM A. Check that valid data is received (i.e. the same frequencies as shown in the DHPTT simulator). Repeat for Range Option 2.

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Functional Tests using SEM A Complete the following tests on the PUMV, then repeat them for the SCSSV1, PWV, AMV, AWV, XOV, SIV and MIV. a) Note:

Record the results of these tests in table 11.a The operation of the SCSSV1 will be simulated by monitoring/manipulating a needle valve/gauge on the SCSSV1 at the tree test base.

Take the opportunity to check the tree valve position indicators during these tests. 1)

2) 3) 4) 5)

6) 7) 8) 9) 10)

Check the displayed readings of LP supply and return volumes by sending an ANALOG DATA REQUEST COMMAND. If the readings are not zero, transmit commands to RESET the readings. Record that the readings have been reset in the table. Transmit a VALVE COMMAND to open the Production Tree valve specified in the table. Send a FUNCTION/STATUS REQUEST COMMAND to SEM A and check that the tree gate valve is indicated in the OPEN position. Obtain the displayed readings of LP supply and return volumes by sending an ANALOG DATA REQUEST COMMAND and record readings in the table. Check on the XT that the valve actuator has moved to the energised position. In the case of the simulated SCSSV1 valve, check on the gauge on the hook-up line coming from the tree test stump that the line has been energised. Transmit RESET FLOW COUNTER COMMANDS to reset the LP supply and return volumes. Transmit a VALVE COMMAND to close the production tree valve. Send a FUNCTION/STATUS REQUEST COMMAND to SEM A and check that the tree gate valve is now indicated in the CLOSED position. Obtain the displayed readings of LP supply and return volumes by sending an ANALOG DATA REQUEST COMMAND and record readings in the table 11.a. Check on the XT that the valve actuator has moved to the de-energised position. In the case of the simulated SCSSV1 valve, check the needle valve/gauge on the tree test base.

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TREE No: . . . . . . . . .

0

SEM A FUNCTION TESTS IUMV

SCSSV1

IWV

AMV

Reset LP Supply and Return Flowmeters Send Open Command to SEM (Record Operating Time) LP Supply Flowmeter Reading Return Flowmeter Reading Check Screen for Actuator on Check Tree for Actuator on Check for visible signs of leakage Reset LP Supply and Return Flowmeters Send Close Command to SEM (Record Operating Time) LP Supply Flowmeter Reading Check Screen for Actuator Off Check Tree for Actuator Off NAME SIGNATURE DATE SERVICE COMPANY: AGIP: Table 11.A - Function Test of Production Valves (SEM A)

AWV

XOV

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11.3.5. Function Test using SEM B Record the results of these tests in table 11.b. 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16) 17) 18)

Set the PESU to operate SEM B. Transmit a VALVE COMMAND to open the PUMV valve. Send a FUNCTION/STATUS REQUEST COMMAND to SEM B and check that the PUMV valve is indicated in the OPEN position. Check on the tree that the PUMV valve actuator has moved to the energised position. Transmit a VALVE COMMAND to open the SCSSV1 valve. Send a FUNCTION/STATUS REQUEST COMMAND to SEM B and check that the SCSSV1 valve is indicated in the OPEN position. Check the gauge on the tree test base that the SCSSV1 line has been energised. Transmit a VALVE COMMAND to open the PWV valve. Send a FUNCTION/STATUS REQUEST COMMAND to SEM B and check that the PWV valve is now indicated in the OPEN position. Check on the tree that the PWV valve actuator has moved to the energised position. Transmit a VALVE COMMAND to close the open PWV valve. Send a FUNCTION/STATUS REQUEST COMMAND to SEM B and check that the PWV valve is now indicated in the CLOSED position. Check on the tree that the PWV valve actuator has moved to the de-energised position. Transmit a VALVE COMMAND to close the open PUMV valve. Send a FUNCTION/STATUS REQUEST COMMAND to SEM B and check that the PUMV valve is now indicated in the CLOSED position. Check on the Tree that the PUMV valve actuator has moved to the de-energised position. Transmit a VALVE COMMAND to close the open SCSSV1 valve. Send a FUNCTION/STATUS REQUEST COMMAND to SEM B and check that the SCSSV1 valve is now indicated in the CLOSED position. Check the gauge on the tree test base that the line has been de-energised.

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TREE No: . . . . . . . . .

0

SEM B FUNCTION TESTS IUMV

SCSSV1

IWV

AMV

AWV

Reset LP Supply and Return Flowmeters Send Open Command to SEM (Record Operating Time) LP Supply Flowmeter Reading Return Flowmeter Reading Check Screen for Actuator on Check Tree for Actuator on Check for visible signs of leakage Reset LP Supply and Return Flowmeters Send Close Command to SEM (Record Operating Time) LP Supply Flowmeter Reading Check Screen for Actuator Off Check Tree for Actuator Off NAME SIGNATURE DATE SERVICE COMPANY: ENI-AGIP: Table 11.B - Function Test of Production Valves (SEM B)

XOV

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Simulation of Level 1 Shutdown 1) 2) 3) 4)

Transmit VALVE COMMANDS to open all production and chemical injection valves. Send a FUNCTION/STATUS REQUEST COMMAND to SEM A and check that all valves are indicated in the open position. Check that all valves on the tree are energised. Simulate a Level 1 Shutdown by transmitting VALVE COMMANDS as follows:

5)

• CLOSE PWV • After 20sec CLOSE PUMV. Confirm that the valves on the tree follow the same sequence. Send an FSR to verify.

Simulation of Level 2 Shutdown 1) 2) 3) 4)

Transmit VALVE COMMANDS to open all production and chemical injection valves. Send a FUNCTION/STATUS REQUEST COMMAND to SEM A and check that all valves are indicated in the open position. Check that all valves on the Xmas tree are energised. Simulate a Level 2 Shutdown by transmitting VALVE COMMAND as follows: • • • • • • •

5)

CLOSE PWV After 5sec CLOSE AWV After 5sec CLOSE AMV After 5sec CLOSE CV After 5sec CLOSE PUMV After 5sec CLOSE SIV After 5sec CLOSE MIV.

Confirm that the valves on the tree follow the same sequence. Send an FSR to verify.

Simulation of Level 3 and Level 4 Shutdowns 1) 2) 3) 4)

Transmit VALVE COMMANDS to open all production and chemical injection valves. Send a FUNCTION/STATUS REQUEST COMMAND to SEM A and check that all valves are indicated in the open position. Check that all valves on the XT are energised. Simulate Level 3 and Level 4 Shutdowns by transmitting VALVE COMMANDS as follows: • • • • • • • •

5)

CLOSE PWV After 5sec CLOSE AWV After 5sec CLOSE AMV After 5sec CLOSE CV After 5sec CLOSE PUMV After 5sec CLOSE SIV After 5sec CLOSE MIV After 5sec CLOSE SCSSV1.

Confirm that the valves on the tree follow the same sequence. Send an FSR to verify.

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11.3.6. Pressure Test Tree Valves This section describes the procedure for pressure testing each side of every valve on the tree. This activity should be performed according to the Manufacturers Operating Manual but with the tree connected to the tree test base and the tree cap and SCM installed. In all cases, valve control will be effected from the PESU, and tests must be chart recorded. The XT/Tree cap controls interfaces will have been previously tested, however, the SCM/MMB interface should also be checked during these tests for leakage. This is achieved by monitoring the flow of hydraulic fluid at the PESU. 1) 2) 3)

Test the valves according to the sequence shown in table 11.a and check off each test performed on chart in table 11.d. The SCSSV1 and tree AX test line manual isolation valves will be tested later when the LRP/TRT are stacked on the tree. When tests are complete, vent down the LP and HP supplies and power down the SCM. Leave all functions vented.

Recheck SCM Operation Re-test SCM functions against the blanked snaptite couplers at the top of the tree as follows: 1) 2)

Check that the PESU and hydraulic supplies are hooked up per section 11.3.4. Check tree sensors also according to section 11.3.4. Function

Check

Production Pressure Annulus Pressure Production Temperature DHPTT 3)

Verify SCM valve functions using SEM A. As the LRP is installed to the top of the tree, the tree valves will not function when operated through the SCM and PESU, however, valve supply lines will be pressurised up to the tree receiver plate and the SCM will give a 'pressurised' status for that line. Check valve functions in the following order:

• IUMV • SCSSV1 • IWV • AMV • AWV • XOV. Record the results in table 11.e.

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Test No. 1 ISV & ASV From Above Open valves: AMV, IUMV, ILMV Monitor at: (Lines according to the Operating Manual) Pressurise From: (Lines according to the Operating Manual) (NOTE: Actual tree has left hand Injection bore) Test No. 2 Open valves: Monitor at: Pressurise from: Hold and continue with Test 2A

IUMV From Above, ISV & XOV From Below IWV, ILMV (Lines according to the Operating Manual) (Lines according to the Operating Manual)

Test No. 2a Open valves: Monitor at:

ILMV From Above As Test No. 2, then open IUMV, close ILMV (Lines according to the Operating Manual)

Pressurise from:

(Line according to the Operating Manual)

Test No. 3 Open valves: Monitor at:

IWV, AWV and XOV From Above AWV, IUMV, ILMV (Lines according to the Operating Manual)

Pressurise from:

(Lines according to the Operating Manual)


IUMV and AMV From Below AWV, XOV, ILMV (Lines according to the Operating Manual)

Pressurise from:



IWV, ASV and AWV From Below IUMV, ILMV, AMV (Lines according to the Operating Manual)

Pressurise from:



ILMV From Below IUMV, IWV (Lines according to the Operating Manual)

Pressurise from:

(Line according to the Operating Manual)

Test No. 7 Open valves: Monitor at: Pressurise from:

AMV From Above AWV (Lines according to the Operating Manual) (Line according to the Operating Manual) Table 11.C - Valve Test Sequence

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Valve

ILMV IUMV IWV ISV AMV AWV ASV XOV

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Above/ Below

Test Ref.

A B A B A B A B A B A B A B PROD ANN

2A 6 2 4 3 5 1 2 7 4 3 5 1 5 2 3

Pressure Sensor Readings

0

PESU LP Flow (ML leakage)

Completed

Table 11.D - Valve Test Check List 4)

Proceed as follows for the PUMV: a)

Check the displayed readings of the LP supply and return volumes by sending an ANALOG DATA REQUEST COMMAND. If the readings are not zero, transmit commands to RESET the readings. Record that the readings have been reset in the table.

b)

Transmit a VALVE COMMAND to open the Production Tree valve specified in the table.

c)

Send a FUNCTION/STATUS REQUEST COMMAND to SEM A and check that the tree gate valve is indicated in the OPEN position.

d)

Obtain the displayed readings of LP supply and return volumes by sending an ANALOG DATA REQUEST COMMAND and record the readings in the table 11.e.

Note:

The readings will not be representative as the tree cap is not fitted. e)

Transmit RESET FLOW COUNTER COMMANDS to reset the LP supply and return volumes.

f)

Transmit a VALVE COMMAND to close the Production Tree valve.

g)

Send a FUNCTION/STATUS REQUEST COMMAND to SEM A and check that the tree gate valve is now indicated in the CLOSED position.

h)

Obtain the displayed readings of LP Supply and Return Volumes by sending an ANALOG DATA REQUEST COMMAND and record readings in table 11.e.

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5) 6) 7)

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Repeat for the remaining valves. Repeat step 4 above using SEM B, similarly tabulating results in Table . At the end of the tests, power down the SCM, both electrically and hydraulically.

TREE No: . . . . . . . . .

SEM A IUMV

SCSSV1

IWV

AMV

Reset LP Supply and Return Flowmeters Send Open Command to SEM (Record Operating Time) LP Supply Flowmeter Reading Return Flowmeter Reading Check Screen for Actuator on Check for visible signs of leakage Reset LP Supply and Return Flowmeters Send Close Command to SEM (Record Operating Time) LP Supply Flowmeter Reading Return Flowmeter Reading Check Screen for Actuator Off Table 11.E - Functional Test of SCM (SEM A)

AWV

XOV

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TREE No: . . . . . . . . .

0

SEM B IUMV

SCSSV1

IWV

Reset LP Supply and Return Flowmeters Send Open Command to SEM (Record Operating Time) LP Supply Flowmeter Reading Return Flowmeter Reading Check Screen for Actuator on Check for visible signs of leakage Reset LP Supply and Return Flowmeters Send Close Command to SEM (Record Operating Time) LP Supply Flowmeter Reading Return Flowmeter Reading Check Screen for Actuator Off Table 11.F - Functional Test of SCM (SEM B) 8)

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Repeat for the remaining valves.

AMV

AWV

XOV

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11.4.

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RUNNING THE SUBSEA XMAS TREE Ensure all pre-deployment testing in accordance to the guidelines in 11.1 and the specific Operations Manuals has been fully completed. 1)

2) 3)

4) 5) 6)

7)

8) 9) 10) 11) 12) 13) 14) 15)

16) 17)

If the hanger orientation or verification tool is a post BOP removal type, run the tool and check the hanger. This tool is also sometimes used to jet out above the hanger prior to running the tree. Ensure the rig is position over the safe deployment area (at least 50 ft away from any wellhead). Move the tree/LRP/TRT assembly directly under the rotary table on the moonpool trolley, ensuring the proper orientation of the assembly to the guidewires and, hence, the permanent guidebase. Lower the riser adapter and stress joint through the rotary table and make up to the TRT. Connect up the main umbilical and sheaves hanging them from a pre-selected fixing point. Activate the tree connector unlock and release it from the stump. Lock pressure in other connectors as necessary per the Operations Manual. Pick up the complete assembly and install the guidewires. Remove the stump and moonpool trolley. Lower the riser through the rotary and land off on the riser spider. Pressure test the riser adapter by applying pressure through the riser bores via the test sub against the LRP valves. Remove the test sub and open the tree bore and LRP valves. Lock them open at the umbilical reel then disconnect the jumper umbilical. Proceed and run the tree on riser sections clamping the umbilical to the riser below the rig floor over the safe deployment area. Land the upper tension joint on the spider which will position the tree +/-30ft above the wellhead. Install the surface tree and lift frame, long bails or strops. Pull off enough umbilical for landing off the tree and reconnect the jumper hose. On the compensator, lower the riser until the tree is approx. 10ft above the wellhead. Pressure test the surface tree and riser against the LRP valves. Open all the tree bore valves and LRP valves, move the rig over the well and gently lower and soft land the tree on the wellhead. Lock the tree connector to the wellhead and observe the indicator by ROV. Conduct an overpull to confirm the connector is properly engaged. Transfer the riser weight to the tensioners and maintain a top tension as per the figures from the Operations Manual. Pressure test all seals and function test as per the Operations Manual. Function all tree hydraulic valves to check for proper operation confirmed by the ROV.

11.4.1. Unplugging The Well 1) 2)

Rig up wireline and pressure test. Run and pull the wireline plugs.

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11.4.2. Perforating And Well clean-Up The normal shut-in and flow will be performed through the surface tree while the gate valve on the lower master is designed to cut wireline and coiled tubing in the case of an emergency. To create an underbalance and conduct the well clean up, refer to the completion section 12. 1) 2) 3) 4)

11.5.

Initiate perforating operations. Bring the well onstream through the surface well test package and clean the well up testing the DHPTT. Close in the well at surface. Install wireline plugs for temporary suspension and commissioning activities on the tree and flowlines.

PULLING THE LRP 1)

2) 3) 4) 5) 6) 7) 8) 9) 10)

After installing the wireline plugs, bleed off pressure in the production bore and inflow test the plugs. Close the tree swab and upper master valve. Close the lower master by ROV. Check the valves are closed by ROV camera. Displace the riser to seawater and close the LRP XOV. Set down weight (Refer to the Operating Manual) and unlock the LRP connector. Pick up the LRP from the tree and rig down the surface tree and surface riser joint. Pull the riser. When the LRP reaches surface with the stress joint through the rotary table, move the LRP stump below the LRP on the BOP transfer trolley. Lower the LRP onto the stump and lock using a hotline if necessary. Disconnect the stress joint and pull to the drill floor. Move the LRP/tree running tool to the storage/work area.

11.5.1. Disconnect The LRP And Tree Running Tool 1) 2) 3) 4) 5) 6)

Disconnect all control jumpers and umbilicals. Attach the TRT lift cap to the TRT mandrel. Unlock the TRT from the LRP and pick up the TRT from the LRP. Set the TRT on it’s storage frame. Attach the cap to the LRP. Disconnect all control jumpers and umbilicals.

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DEPLOYMENT OF THE TREE CAP 1) 2) 3) 4) 5) 6) 7) 8) 9) 10)

11.7.

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11.6.

PAGE

Rig up the THOJ/tree cap umbilical reeler to the WOCS and connect to the tree cap running tool. The TCRT will be connected to the tree cap ready for deployment. Move the TCRT/cap to below the rotary table on the BOP transport trolley. Run drillpipe through the rotary table and connect to the IF sub on the TCRT. Install the guidelines and pick up the TCRT/tree cap and remove the trolley. Run the cap to depth on drillpipe and on the compensator land the tree cap onto the tree. Conduct all integrity tests to ensure the cap is properly installed including a pull test. Unlatch the TCRT from the tree cap and retrieve to surface. Rig down the TCRT onto the BOP trolley and move to the storage area. Rig down the control system.

DEPLOYMENT AFTER COMMISSIONING ACTIVITIES Repeat procedures above in reverse for the removal of the tree cap, reconnection of the riser system for wireline plug removal and bringing the well into production.

Figure 11.C - Cooper Subsea Xmas Tree on WS II Wellhead

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12.

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WELL UNLOADING Following the successful completing of a well, it will normally have been left with the completion fluid left in both the tubing and annulus. To enable the well to produce under natural flow conditions (i.e. non artificial lift) the overbalance pressure exerted by the completion fluid must be removed, sometimes referred to as ‘unloading’. The well may be brought onstream direct into the production facility but is often tested with a well test package to be cleaned up prior to placing it on production (this is normal practice for subsea completions where the production of the well straight into the subsea flowline system without cleaning up may plug and perhaps damage the facilities). If losses have occurred during the drilling and completion phases, the hydrostatic pressure in the tubing needs to be reduced to such an extent that the replenishing losses flowing back into the wellbore does not kill the well again. It is normal practice to circulate an underbalanced fluid into the tubing using a circulating device or coiled tubing service, which will provide sufficient underbalance to enable the well to flow under the conditions stated. The fluid used is usually selected to provide as large drawdown as possible at low cost. Under some circumstances, an underbalance can be achieved by simply bullheading a lighter fluid into the tubing relying on produced gas to maintain the underbalance during flowback. This is a cost effective method if bullheading is acceptable for a particular formation. The fluids normally used may be water, base oil, diesel or nitrogen. Nitrogen can be circulated by deploying the coiled tubing and continuously gas lifting the well until natural flow is established. It may also be installed like the other fluids by pumping it into the tubing taking returns through a circulating device and out of the annulus. The depth to which the underbalance fluid is circulated depends upon the drawdown which can be achieved. Continuous gas lifting a well is preferred if there has been large losses otherwise the circulation process may have to be repeated more than once causing higher costs, this needs to be evaluated. The procedures for circulation are given in this section. The procedures for nitrogen lifting are given in section 14 and coiled tubing procedures in section 13.

12.1.

UNLOADING BY CIRCULATION It is assumed that any suspension plugs in the well above the circulation device have been removed and that the completion fluid occupies the tubing. It may be prudent to leave or install a plug or standing valve in the packer tailpipe to prevent losses during this procedure. If it is planned to place the maximum amount of fluid in the well to obtain the highest drawdown, ensure that it is not over-displaced into the annulus. 1) 2) 3)

Rig up wireline in accordance to the procedures in the Company Wireline Procedures Manual. Rig up the circulating pump to the Xmas tree kill wing and pressure test to 1,000psi above the maximum anticipated wellhead pressure or to WP. Rig up a return line from the annulus to a returns tank of sufficient capacity. pressure test these lines against the side outlet valves with a pump..

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2) 3) 4) 5)

6) 7) 8)

9)

10) 11) 12) 13)

14) 15) 16) 17)

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1)

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Pressure test the wireline lubricator to a minimum of 1,000psi above the maximum anticipated wellhead pressure or to WP. Install the circulating device opening or shifting tool. If using a SPM, install the SPM dummy valve pulling tool. Run in the hole and open the circulating device. There should be no differential pressure across the device as there is completion fluid on both sides. Confirm the circulation path is open by pumping up on the tubing and observing pressure on the annulus. Pull out of the hole. With some particular SSDs, it is sometimes possible to run two tools in one run to open and close the sleeve in one trip (parking it below the SSD during circulation). If a SPM is being used, run and install a circulating valve in the pocket and pull out of the hole. With the return system from the annulus open, begin to pump the underbalance into the tubing monitoring the volume pumped and the volume of returns from the annulus. Continue pumping until the calculated amount of fluid has been pumped. Check that the surface ‘U’ tube pressure is correct for the volume of underbalance fluid pumped according to calculation and hold this pressure on the pump. Run in the hole and close the circulating device. In the case of a SPM, reinstall the dummy valve. Confirm closure by pressuring up on the annulus and observing no pressure on the tubing or any significant volume is pumped. Pull out of the hole. Rig up, run in the hole and pull the packer tailpipe plug or standing valve, if used. Rig down wireline and the pump lines. Ensure the production flowline is lined up to flow to the production facilities and that the production operators are informed that the well will produce back through their facilities. Open the production wing valve. Gradually open the production choke to flow the well. Monitor the wellhead pressure, slowly opening the choke as it is assured that the well is successfully unloading. Continue until the well has stable flowing conditions at a reasonably high rate (reservoir engineering will provide the flowing parameters).

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12.2.

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UNLOADING BY BULLHEADING If bullheading and if reservoir conditions allow, the following procedure could be used. 1) 2)

3) 4) 5)

6) 7) 8) 9)

12.3.

Rig up the pump to the Xmas tree kill wing and pressure test to 1,000psi above the maximum anticipated wellhead pressure or to WP. Open the kill wing and with the pump lined up to the supply of underbalance fluid, (liquid or nitrogen) begin displacing the tubing. Never pump at a pressure to exceed bottomhole fracture pressure. Monitor the pressure trend is consistent. When the calculated volume has been pumped, shut down the pump and record the static surface pressure confirming the correct amount of fluid has been pumped. Close the kill wing valve. Ensure the production flowline is lined up to flow to the production facilities and that the production operators are informed that the well will produce back through their facilities. Open the production wing valve. Gradually open the production choke to flow the well. Monitor the wellhead pressure, slowly opening the choke as it is assured that the well is successfully unloading. Continue until the well has stable flowing conditions at a reasonably high rate (reservoir engineering will provide the flowing parameters).

UNLOADING BY COILED TUBING Refer to section 14.

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COILED TUBING OPERATIONS

13.1. PREPARATION Coiled tubing (C/T) operations will not be allowed to commence without an approved work programme. The Completions and Workover Superintendent will confirm that the well to be worked on is available and accessible. Should the rig be required, then he will confirm its availability and the manning requirements. A pre-job meeting should be held well in advance of the actual operation. The purpose of this meeting is to: • • •

Discuss the programme of operations. Establish channels of communication and define responsibilities. To discuss any special requirements or circumstances that may arise e.g. procedures in the case of emergency, adverse weather conditions, ID of string components versus tool OD, escape of hazardous treatment fluids, etc. • Additional topics will be discussed as required and may include working in confined spaces, working with pressurised equipment, handling of heavy equipment, etc. Make sure a completion diagram of the well is available. This should include the location of casing, tubing shoe, packers, perforations, etc., as well as KOP and maximum angle of deviation. A brief written outline of previous relevant well operations should be given to the coiled tubing supervisor. The Completions and Workover Superintendent will ensure that all relevant equipment and materials for the job are on site in a timely manner. 13.2.

SAFETY CONSIDERATIONS Safety during C/T operations, in common with most operations in a potentially dangerous environment, is largely dependent on sound operating procedures and effective communication. The following points are, essentially, common sense and should be observed during all phases of the operation: • • • • • • •

Keep well clear of the tubing at all times. Tubing can part due to excess pressure and tubing wear. Beware of the physical damage due to thrashing pipe, as well as spraying treatment fluids. If the tubing becomes stuck and excessive pressure and pull are to be applied, clear the area as required. Make an announcement over the PA system to inform personnel. Do not stand near treating lines, pumps, tanks, reel, injector, or under the tubing. There should be no overhead lifts across or near the tubing. Safety harnesses will be used when operating above ground level. This includes working on top of the reel and injector as well as in the derrick. When treating the well with hazardous chemicals the relevant safety wear must be worn by all personnel in the work area (Refer to section 15.2).

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•

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Before rigging up coiled tubing, a safety meeting will be held with all relevant personnel. The topics to be covered will include, but are not be limited to: a) Working with pressurised equipment b)

Handling of heavy equipment

c)

Use of hazardous chemicals

d)

Safe working areas

e)

Emergency procedures

f)

Protective clothing

g)

etc.

Communication with the operator in the C/T control cabin, the drill floor/skid deck and the control room will be maintained throughout the operation. All personnel should be aware of the Emergency Procedures for C/T operations.

13.2.1. Tubing The coiled tubing should be treated like a pressure vessel. While operating or pressure testing it will contain several cubic meters of gas, fluid, or energised fluid. Unlike a pressure vessel however, it undergoes considerable stress during running and also suffers from both internal and external corrosion. Therefore, ensure that the reel carries a full and up-to-date operational history, which should include the following information: • • • • •

The cycle history of the whole reel length (one cycle being a run in followed by the run out). The treatment history, i.e. what fluids have passed through the reel. The well conditions. What fluids and gases were in the well being treated, e.g. H2S, Acid. The condition of welds or joins in the reel, i.e. are they original, are X-rays available of the welds, etc. The records showing when was the last non-destructive test of the full reel length.

13.2.2. Risers and BOPs As the riser and BOPs are, in effect, a pressure vessel situated above the Xmas tree, subjected to the wellhead shut in pressure and test pressures, it is essential that the seals are regularly checked and that they are pressure tested every time the BOPs are broken out for tool recovery etc. 1) 2)

3)

When pulling coiled tubing tools into the riser, it should be at the slowest possible speed to be selected. The riser must be depressurised and any gas/fluids bled off via the choke to the test separator. The toolstring must be pulled up against the BOPs, prior to breaking out the BOP connection. After the riser has been depressurised, the riser, or BOP bleed off needle valve must be opened to verify that all pressure and fluids have been vented, prior to breaking the BOP connection to remove the tool string.

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After de-pressuring the Xmas tree and riser but before the BOP is broken out, the swab valve must be closed. This is to prevent any possible hazardous condition arising due to the inadvertent opening of a wing valve, or flow from a leaking master valve.

13.2.3. H2S Considerations When working on wells which are known H2S producers, or those in which H2S is anticipated, ensure that hydrogen sulphide detectors and portable breathing apparatus sets are available and on site. Safety aspects of well operations in the presence of H2S must be addressed in the pre-job safety meeting. This applies to all wells where the presence of H2S is known or anticipated. When H2S bearing wells are to be entered for C/T workover purposes, the Xmas tree is to be flushed with water/glycol to remove all traces of H2S prior to rigging up on the well. All personnel involved in these operations will wear automatic H2S detectors and be equipped with self contained breathing apparatus. 13.3.

PERMIT REQUIREMENTS Note: 1) 2) 3) Note: 4) 5)

6) 7) 8)

9) 10)

All permits will be issued in accordance with the Permit to Work System. No operations can begin without the relevant work permits. Obtaining and distribution of the permits is the responsibility if the Contractors Representative. All permits will be revalidated at the end of each shift. Permits may not be valid for 12 hours on crew change days. Obtain the relevant Permits to Work in accordance to the PTW system. The Contractor Representative will ensure that all relevant work permits have been signed and distributed, and inform the Well Operations Supervisor that this has been done. The Area Authorities/Safety Officer may, if required, will make an inspection to ensure that there is no other work going on which may affect the operation. The Well Operations Supervisor will confirm the well status and accept the well handover certificate from the Production Supervisor. Certain operations may require lifting of heavy equipment over live wells. Wherever possible this will be avoided. If circumstances make the lift unavoidable, then the Production Supervisor will be informed. He will decide if any live well needs to be shut in and if scaffolding of other protective structure needs to be erected. Only equipment with valid test certificates will be used for rigging up and during the operation. All well control equipment must have current certification of conformity issued by the certifying authority.

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13.4.

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RIG UP PROCEDURES

13.4.1. Equipment Preparation and Siting 1) 2)

3)

Ensure that the equipment has been visually checked for defects prior to starting rigup. If time allows, a permit should be obtained and the equipment run and tested, prior to the commencement of the operation, to check equipment function and confirm the operation of the shut down systems on the power pack. The Well Operations Supervisor should ensure that: • • • •

The work area is suitably guarded (e.g. safety barriers, safety signs, etc.). Any scaffolding is secure, safe and properly certified. The crane operator and roustabouts are aware of the equipment weights and hazards (e.g. liquid nitrogen or acid, etc.). All lifts should have tag lines attached.

13.4.2. Coiled Tubing Rig-Up Note:

The C/T unit will be function tested on the deck prior to it being made up in the well.

Note:

It is Company policy to run a remote hydraulic control shear seal BOP at the bottom of the riser immediately above the tree.

Refer to figure 13.a General rig up arrangement. 1) 2) 3) 4)

5) 6)

7) 8)

Confirm that the tree has been de-pressurised and the controls have been isolated from the main control system. Take control of the well from Production Department. Remove the swab cap and inspect the thread and seal areas. Run the riser (with the shear seal BOP at the bottom) onto the tree and pressure test with water to 500 psi above the maximum anticipated surface pressure or to the maximum test pressure of 5,000 psi, whichever is lower. Do not exceed the maximum allowable tree rating. Position the tubing reel and power pack so that the coiled tubing has an unrestricted path to the injector head. Move the BOP assembly onto the rig floor or skid deck, make up to riser and pressure test. Function test the BOP with both panels, fill up the riser and BOP with glycol/water, close the blind rams and pressure test the riser, return lines and blind rams to 500psi above the maximum anticipated surface pressure, or to the maximum test pressure of 5,000psi, whichever is lower. Clamp the coiled tubing at the reel using a certified clamp but not molegrips or other similar tools. The injector head may be rigged up and the tubing stabbed through the injector head on the catwalk or drill floor depending on space available.

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3) 4)

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1)

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When picking up the injector head, use tugger lines to keep the assembly vertical. Tugger lines must not be attached to the injector body, as this will interfere with the weight indicator readings. Fill the reel with water. The reel should be flushed with water and pigged with a no-go prior to running packers and other sensitive tools to gauge reel volume, ensure that there are no restrictions to the ID of the coil and to purge any debris form the tubing. Make-up and fit the end connector and test sub. Test reel to full test pressure and perform pull test before stabbing on to BOP. Attach the C/T BHA, and stab the injector onto the BOP. The assembly will be pressure tested with the BHA across the BOP.

13.4.3. Pressure Testing Pressure testing of the coiled tubing assembly, which includes the BOPs, tubing, treating lines and the pump, should be carried out in a logical sequence to eliminate all possible leaks. 1)

2)

3)

4)

5)

6)

7)

The Blind Rams and Riser will have already been tested while rigging up the BOPs, therefore it is certain the BOP to riser seal, riser to tree seal, swab valve, BOP kill wing valve and blind rams have pressure integrity. If using an in-line tubing connector, the Stripper/Packer and Toolstring will be tested with the tools across the BOP and the straight bar in the energised stripper. With the whole system full of water, pressure is applied from the pump in stages of 500psi up to a maximum of 5,000psi. The pump and treating lines up to the reel will have been tested already. Do not exceed the maximum allowable tree rating. If using an out-line tubing connector, the Stripper/Packer and Toolstring will be tested with the tools below the BOP. With the whole system full of water, pressure is applied through the tubing in stages of 500psi up to a maximum of 5,000psi, to prevent collapse of the tubing. The Pipe Rams are now tested by closing the pipe rams and bleeding the pressure down to zero via the circulating port on the BOP. Once the test is complete, close the circulating port and equalise the pressure across the pipe rams. The Check Valves in the toolstring are now checked using the pressure already in the system. With the straight bar still across the still energised stripper, bleed down the pressure at the reel. The check valves should seal, and pressure will remain in the riser and BOPs while the reel pressure is zero. When bleeding down reel pressure, ensure external pressure does not exceed the collapse pressure rating of the reel. Alternatively, bleed down the whole system at the BOPs and with the reel valve open, using the cement or pressure test pump, pressure test check valves via a pump-in tee below the BOPs while stripper is energised. The BOPs should be bled down after the testing is completed.

Control Cab

Coiled Tubing Reel

IDENTIFICATION CODE

Figure 13.A - General C/T Rig Up Arrangement Wellhead

Wellhead Combination BOP's

Lubricator/Riser

STAP -P-1-M-7120

Power Skid

Quad BOP's

Stripper/Stuffing Box


Hydraulic Hose

Injector Head

Goose Neck

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REVISION

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13.4.4. Treating Lines • • • • • •

On all C/T operations, treating lines should be rigged-up using certified Fig.1502 integral lines. Any bent lines or damaged unions will be marked, registered as unfit for use and returned to base. Ensure that the lines are tied with safety cables and attached at regular intervals to secure fixing points. Ensure that check valves are used on wellheads, reels and each pump. Ensure that a certified relief valve is installed in the surface line circuitry. The relief valve setting is to be confirmed between the Company and Contractor Representative prior to equipment load out. All valves should be tested from the well side including the last valve on the reel.

13.4.5. Injector Frame An injector frame is used to steady and position an injector when operated rigless. It may also be used when operating through the rig although this is not recommended as it serves no purpose and requires additional rig-up time. On floaters a special lifting frame or extra long bails should be attached to the block to the surface tree to maintain tension through the compensation system. The injector is then installed inside the lift frame or bails. This enhances the safety of personnel and enables easy rig up of the injector head on a heaving rig. The injector frame is not designed to withstand the weight of the injector and the weight of the coiled tubing in the hole. This combined weight, which can be in the region of 20 tonnes, is carried by the wellhead. The purpose of the frame is only to ensure lateral stability. Most frames have hydraulic height adjustment and should include hydraulic compensation systems to allow for any vertical movement of the wellhead in relation to the deck. The frame should be pegged to the injector and tied back at the four top corners using certified chains and come-alongs, to secure fastening points on the deck. The injector should remain connected to the crane or overhead gantry crane during the operation to add stability to the structure and to facilitate rapid removal of the injector during rig down. Due to possible contraction of the riser due to well cooling, no tension should be applied to crane sling during operations. 13.4.6. Rigging Down To rig down: 1) 2) 3) 4) 5)

Pull out of the hole until the tubing end connector tags the stripper. Use no more than 4,000lbs overpull. Close off the well isolation valve. Bleed off pressure in the coiled tubing and surface lines through the closed line drain in case of any hydrocarbon discharge. Rig down the coiled tubing and associated equipment. Ensure all equipment is stowed safely for transport.

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13.5.

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RUNNING PROCEDURES The following procedures are guidelines, the actual toolstring configuration, running speeds and operating procedures will vary depending on the work being performed. 1)

2) 3) 4) 5) 6) 7)

8) 9) 10)

11)

The basic toolstring configuration for conventional circulation operations is, from the bottom up: • Circulating nozzle • Two check or flapper valves • Straight bar • Tubing connector. Refer to the toolstring configuration in the well programme for specific operations. The weight indicator must be tested before running coiled tubing in to a well. Ensure the mechanical and electronic depth counters are set to zero at the appropriate zero datum reference. Standard running speed should be 50ft/min, running or pulling through unobstructed tubing, slowing to 15ft/min within 50ft either side of obstructions. Running speeds will be reduced when running through the riser, Xmas tree, SCSSV and any other downhole restrictions. Ensure that the tubing internal pressure is maintained at all times by pumping. On specifically sanctioned operations, a differential of 1,000psi will be allowed across the tubing. At any indication of the tubing hanging up, pull up well above hang up depth and liaise with the Eni-Agip representative before taking further steps. Particular care must be exercised when pulling the assembly out through the SCSSV and the Xmas tree and into the lubricator. The C/T contractor will provide plots of pipe weight, pipe loading and buckling stress against depth for the particular job to be performed. Any significant deviations from these plots during the operation must be investigated. Pulling weight tests/checks should be performed every 1,000ft regularly during running in.

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13.6.

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OPERATING PROCEDURES

13.6.1. Gas Lifting Gas lifting may be required to kick-off a well, which contains a kill fluid, in low pressure producers when production has been temporarily halted. It is also used to remove a dead column of fluid from closed tubing. Each specific condition requires an exact programme, however the basic procedure still applies. When kicking off a well containing a kill fluid follow the basic procedure in this section. Allow sufficient nitrogen to remove any kill fluid that may have entered the formation during the kill operation. As a rule do not use excessive pump rates as this will lead to high annulus friction and nitrogen may be lost to the formation. In wells exceeding 40o deviation nitrogen slippage is likely to occur. You should allow sufficient nitrogen to compensate for this slippage. When restoring production in low pressure wells that have been temporarily shut in, use low nitrogen rates and only run to a maximum of 50% of well depth. These wells only require encouragement until water cut has been reduced and temperature has risen. When removing a fixed dead column of fluid from a well, as when creating a nitrogen cushion prior to DST or TCP, follow the main procedure, except that the well will not flow and dry gas should be produced at surface. The procedures in this section are guidelines only, specific operational programmes will be issued by the Company. Safety A safety meeting will be held with all relevant personnel prior to any job. The meeting will address the hazards inherent with handling liquid nitrogen (Refer to section 14.7). The meeting will also address the actions to be taken in the event of an emergency. Procedures 1) 2) 3) 4) 5) 6) 7)

Rig up and test the coiled tubing (Refer to section 13.4) The nitrogen tanks, converter and pumping unit should be positioned close to the tubing reel in order to minimise the length of pressurised lines. Reduce the test separator pressure according to the coiled tubing contractors procedures, and line up the well to the test separator. Allow any gas cap on the well to vent off through the test separator. Confirm that the tree and SCSSV controls have been isolated from the main control system. Equalise pressure across the swab valve then open. Run in the well carefully, stopping to establish nitrogen injection at a low rate, increasing the rate slowly as the coiled tubing is further run in. • •

8)

If the well begins to slug nitrogen, reduce the injection rate Shut down the nitrogen unit at the first indication of any rapid build up in wellhead pressure. Once the tubing has reached the predetermined depth, stop running in and continue pumping nitrogen until nearly all the nitrogen is pumped, or the well is flowing strongly.

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Pull the tubing out of the well before the nitrogen supply is completely exhausted. This is to ensure that the pressure differential across the tubing wall does not exceed 1,000psi. Rig down and hand the well over to the Production Department. The following data will be recorded throughout the nitrogen lift operation: • • • • • • •

3)

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Wellhead flowing pressure Nitrogen injection pressure Nitrogen injection rate Wellhead flowing temperature Separator level Separator pressure Separator temperature.

Fluid samples will be taken from the flow line sample point by the Well Operations Supervisor.

13.6.2. Well Treatment Well treatments can be performed using various acid and solvent formulations to improve production or injection rates. Coiled tubing is often used to perform well treatments, because it allows for the direct application of the treatment to the zone or area requiring treatment. The main types of treatment are as follows: • • •

Removal of scale from well tubulars and SCSSV Matrix acidisation of the formation Well bore clean-up using solvents and or acid.

Scale removal can be achieved by circulating acid across the area requiring treatment. Note:

Much of the acid may remain unspent and that this may have an effect on surface flowlines and production equipment. Specific formulations may be recommended by the contractor to remove sulphate scale, and scale containing hydrocarbons.

Matrix acidisation of the formation can take the form of a small acid wash injected from the coiled tubing directly to the zone requiring treatment, or for larger treatments, with the coiled tubing being used to circulate the acid to fill the tubing prior to direct high rate injection from surface. If leaving the coiled tubing in the well ensure that it is sufficiently inhibited and that the internal pressure of the C/T remains equal to or above the external pressure. Well bore clean-ups are performed to remove scale, debris and waxes from the perforation tunnels. They are not intended to penetrate the formation, which could lead to additional damage. The treatment is applied by jetting the treatment fluid into the perforations while slowly cycling the nozzle across the perforations. The treatment is performed with the well balanced or slightly underbalanced to prevent treatment fluid penetration.

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Safety Prior to rigging up the acid equipment a safety meeting will be held with all relevant personnel (Refer to section 15.5). The meeting will address the hazards inherent with handling acids, particularly under pressure. The meeting will also address the actions to be taken in the event of an emergency. Procedure The following details the basic procedures to be followed when performing acid treatments through coiled tubing: 1)

Rig up and test coiled tubing (Refer to section 13.4).

2)

Suggested BHA is, from the bottom up: • • • •

3) 4) 5) 6) 7) 8)

Confirm that the tree and SCSSV controls have been isolated from the main control system. Pig the reel to determine accurate reel volume. Equalise pressure across the swab valve then open. Run in the well carefully, circulating at minimum rate. Perform regular pull tests/checks at 1,000 ft intervals. Once the area to be treated has been reached, pump treated injection quality seawater in order to establish the circulating pressure. If an acid wash or solvent treatment is to be performed then: • • • •

9)

Jetting nozzle 2 dart type check valves 6ft straight bar Tubing connector.

Circulate the coiled tubing to treatment fluid ϑet the area to be treated while reciprocating the coiled tubing slowly Circulate the tubing to injection quality seawater Pull out of the hole.

If matrix acidising is to be performed the treatment formulation and volume will be advised in a separate programme. However the basic procedure is: • • •

Circulate the treatment fluid into the well at the maximum rate. Pull the tubing assembly above the acid and inject at a high rate via the tubing and the tubing annulus simultaneously. (Alternatively the coiled tubing can be pulled out of the well before injecting the acid.) Pull out of the hole and if required flow the well with nitrogen.

Inhibition It is essential that a sufficient quantity of inhibitor is used in the acid system. If a mutual solvent is being used, the inhibitor content must be doubled due to the detrimental effect that the solvent has on inhibitor efficiency. A slug (5-10bbl), with 5% inhibitor in injection quality seawater, should be circulated ahead of the acid treatment. This will give protection to both the inside and outside of the tubing.

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13.6.3. Sand Cleanout General 1)

2)

3)

It may be necessary to clean out sand fill from a well to provide a sufficient sump for production logging, additional perforating and to exposed covered perforations. Sand clean out is best carried out using C/T. The clean out is carried out by running the tubing and pumping viscous fluid (gel) to lift the sand from the sump. The clean-out operation may be carried out with the well flowing to assist the return of sand to the surface. This is especially useful when the well is highly deviated, has a large bore production string or when the well is unable to support a column of gelled seawater without incurring losses. It is essential to keep circulating when there is a sand column in the production tubing. This is especially important when the well is not flowing, otherwise the C/T will become surrounded in sand and stuck.

Safety Prior to rigging up the coiled tubing and circulating equipment a safety meeting will be held with all relevant personnel. The meeting will address the hazards of handling chemicals and use of pressurised equipment. The meeting will also address the actions to be taken in the event of an emergency. Procedure 1)

Ensure that the well is lined up to take returns to the test separator.

Note:

The separator should be sand washed prior to the operation.

1) 2) 3)

A sample point will be installed in the return line. Rig up and test the coiled tubing (Refer to section 13.4). Suggested BHA is, from the bottom up: • • • •

4) 5) 6) 7)

8) 9)

Jetting Nozzle 2 dart type check valves 6ft straight bar Tubing connector.

The required gel system should be prepared in a mixing tank and transferred to a holding tank containing agitators once it is fully hydrated. Confirm that the Xmas Tree and SCSSV controls have been isolated from the main control system. Equalise pressure across the swab valve then open it. Begin running in carefully with the well producing at a reduced rate. Keep the tubing string filled full of treated sea water by circulating at the minimum rate. Carry out regular pull tests/checks at 1,000ft intervals. Once the string is below the SCSSV, increase the production rate to its normal level. Break circulation when well above the last recorded hold up depth and establish a minimum circulation rate while pumping gel.

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2) 3)

4) 5) 6) 7)

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Monitor the pump pressure, wellhead pressure and coiled tubing string weight continuously throughout the operation. If there are any indications of problems pull back above the last hold up depth immediately and evaluate the situation. Run in slowly to the top of the fill, stopping to note the hanging weight. Slow down when the weight begins to drop off the tubing and flag pipe at surface as a reference. The tubing must be kept in tension at all times. After penetrating 20ft, pick-up to the tubing shoe then run back in to repeat the process in stages of 20ft, pumping continuously. Having reached the required depth, continue to pump gel while reciprocating the tubing back to the tubing shoe twice. Carefully monitor fluctuations in pick-up weights. If an increase is seen, wash back until weight corresponds with the initial running weight. Pull up above the perforations and displace the tubing to treated seawater. Pull out with the well flowing to ensure that all sand moving up as the tubing is removed. Rig down and hand control of the well back to Production. Sand wash the test separator and record the volume of sand removed.

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14.

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NITROGEN PROCEDURES The use of nitrogen is potentially hazardous and many precautions need to be taken to obtain a successful safe operation.

14.1.

PREPARATION 1) 2)

3)

No nitrogen operations will be allowed to commence without an approved work programme. The Completions and Workover Superintendent will confirm that the well to be treated is available and accessible. Should the rig be required then he will confirm its availability and the manning requirements. A pre-job meeting should be held well in advance of the actual operation. The purpose of this meeting is to: • • •

4)

14.2.

Discuss the programme of operations. Establish channels of communication, and define responsibilities. To discuss any special requirements or circumstances that may arise, e.g. procedures in the case of emergency, adverse weather conditions, safety data sheets, escape of gaseous or liquid nitrogen or energised fluids, etc. • Additional topics will be discussed as required, and may include working in confined spaces, working with energised fluid, extreme low temperatures, handling of heavy equipment etc. A brief written outline of previous relevant well treatments should be given to the stimulation supervisor, or nitrogen operator.

SAFETY CONSIDERATIONS Safety during a nitrogen operation, in common with most operations in a potentially dangerous environment, is largely dependent on sound operating procedures and effective communication. The following points are essentially common sense and should be observed during all phases of the operation. • • • • •

•

Do not stand near treating lines, cryogenic hoses, nitrogen converters/pumps, liquid nitrogen tanks, or any other treating equipment during operations. There should be no overhead lifts across or near the liquid nitrogen tanks, treating lines or nitrogen converters/pumps. Safety harnesses will be used when operating above ground level. This includes working on top of the liquid nitrogen tanks, as well as in the derrick. When treating the well with hazardous chemicals in conjunction with nitrogen refer to the Stimulation Section regarding the wearing of additional safety wear. Before rigging up treating equipment a safety meeting will be held with all relevant personnel. The topics to be covered will include, but not be limited to, working with pressurised equipment, gas pressure and energised fluids, handling of heavy equipment, handling of liquid nitrogen and gaseous nitrogen, use of hazardous chemicals, safe working areas, emergency procedures, protective clothing, etc. Only authorised personnel wearing adequate protective clothing will be allowed in the vicinity of the equipment while a nitrogen operation is being performed.

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•

• •

14.3.

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Good communications between the nitrogen operator, rig floor, wellhead area and coiled tubing or stimulation operator where applicable must be maintained throughout the operation. All personnel should be aware of the Emergency Procedures for C/T operations. All work areas will be chained or roped off, and warning signs placed at access routes. The exact requirements will be specified on the work permits. Fire hoses will be available in the areas where liquid nitrogen is to be used. The hoses will be fully charged, so that they can be used immediately should a spill occur. The nitrogen tanks and nitrogen converter/pump will be positioned as close to the well as possible to minimise the length of pressurised lines. Gaseous nitrogen will escape from nitrogen tanks continuously as the tank is warmed. Do not stand in the immediate vicinity of escaping nitrogen and do not attempt to plug or block the escaping gas. Nitrogen is not toxic (it represents about 80% of the air we breathe) but if released in a confined area it will displace some of the oxygen present leading to an oxygen poor atmosphere and possibly asphyxiation of people present. (The effect is like putting a plastic bag over one’s head.) Do not enter or work in a confined area where nitrogen is escaping. Liquid nitrogen is very cold being a cryogenic fluid. It will freeze flesh on contact almost instantly, especially if the surface is water wet. The freezing effect is anaesthetic and may not be immediately noticed. The flesh or eye once frozen is effectively destroyed. The affected area will be treated as a serious burn. Lines carrying liquid nitrogen are also very cold and should only be handled with dry insulated gloves. On contract with steel, liquid nitrogen causes embrittlement and shrinkage of the surface leading to fracture generation. Thus if nitrogen is split on a steel deck, it will quite rapidly freeze and crack the deck, allowing the liquid to spill to the next level. Apply a fine spray of water to the spill immediately. As in a liquid fire, do not apply a fierce jet to the liquid as this will disperse it to other areas. The fine spray will lay down an insulating layer of ice on the deck and help evaporate the liquid nitrogen.

NITROGEN HANDLING

14.3.1. Safety Equipment •

•

When handling or working in the vicinity of a nitrogen operation, suitable safety equipment must be made available and used. The type of safety equipment required will depend on whether the person expects to operate the equipment or simply remain in the vicinity. As standard procedure when in the vicinity of nitrogen operations, chemical goggles should be worn in preference to safety spectacles. Nitrogen operators must be equipped with dry thermal gloves for handling cryogenic hoses and valves.

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14.3.2. Safety Data Sheets • •

• •

When operating with nitrogen or any kind of chemical, ensure that the safety data sheets are available both at the safety meeting and in the work area. During the safety meeting the Safety Officer should be shown each of the safety data sheets. The safety officer should analyse the sheet and point out the hazards and handling instructions for nitrogen and any other chemical being utilised. The control and disposal of spills of liquid nitrogen and escapes or leakages of liquid or gaseous nitrogen should be explained. In the event of injury from nitrogen burn or asphyxiation the safety data sheets will be available to enable the Medic and Safety Officer to determine the best action.

14.3.3. Pressurised Lines • •

14.4.

During nitrogen operations pressure will be used to inject the nitrogen as gas into the well and for the pressurised transfer of liquid nitrogen between tanks and from tank to pump. The pressure will either be gas pressure or energised fluid pressure. It is important to note that when operating with energised fluid pressure, it is essential to keep the operational personnel in safe areas when ever possible. The effect of energised fluid pressure release is explosive.

RIG-UP PROCEDURES

14.4.1. Equipment Preparation and Siting • • • • •

The contractor will have a rig up procedure that has been approved by the Company in advance. The equipment will be situated such that the length of pressurised lines, and liquid nitrogen hoses, are minimised. All high pressure lines will be pressure tested with water according to the values stated in the nitrogen programme. Where possible the nitrogen operator will have an unobstructed view of the rig floor, or wellhead area, and the coiled tubing operator where relevant. Personnel involved in the operation will carry radios at all times.

14.4.2. Equipment Rig-up • • • • •

When rigging up equipment, ensure that all pressure operating items carry valid test certificates. Inspect all items for wear or damage and do not use any defective items. Ensure equipment location has sufficient clear escape routes. Liquid nitrogen lines should be supported off steel decks with wood or rubber matting to prevent deck freezing. Drip trays of stainless steel construction should be placed under all hose unions. Liquid nitrogen tanks may not be stacked, either while being stored or during operation.

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14.4.3. Pressure Testing • • • Note:

Pressure testing should be performed with all lines and spaces to be tested full of water. Testing with nitrogen should be avoided. Pressure testing will take place to 1.5 times the maximum operating pressure. The pressure testing will be witnessed by the Well Operations Supervisor.

• •

Pressure tests will be monitored for 15 mins on a chart recorder. The chart will be labelled and stored for reference. The PRV is to be isolated during pressure test.

14.4.4. Treating Lines • • •

• • • •

Inspect all treating lines thoroughly. Mark and set aside defective treating equipment. Ensure treating line runs are kept as short and direct as possible without causing unnecessary obstruction. When treating at high rates and as a general practice, ensure sufficient flexibility in the treating line by incorporating chicksan bridges in the line. Cavitation and high pump rates can stress lines and back off unions by vibration unless the line is flexible. Lines should be tied together using a steel cable and clamps. Each individual line, swing or other treating pipe, should be clamped to the cable. The lines should also be tied off where possible to fixed objects such as pad eyes. Ensure that each fluid or nitrogen pump is fitted with a check valve. A check valve should also be fitted to the treating point, i.e. coiled tubing reel, well head, kill line. Check valves should be fitted with bleed-off needle valves.

14.4.5. Rigging Down • •

Rigging down will only take place once the Workover Superintendent or company representative has given permission. The existing Hot Work permit may be used if still valid otherwise a new Cold Work permit may be obtained.

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14.5.

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NITROGEN TREATMENT PROCEDURES When preparing a nitrogen programme, note should be taken of the quantity of nitrogen required by calculation to complete the operation. To this should be added considerable excess for ordering, to ensure that sufficient nitrogen is available to complete the job. Evaporation of stored nitrogen, due to shipping and job delays, multiple pressure test cooldowns, job restarts and other unexpected losses, suggest an excess allowance of at least 50% over the calculated volume. The following operational factors should be considered: • • • • •

The maximum flow rate required and the number of nitrogen converter/pumps required. Contingency for unit breakdowns. Space on the pipe deck to store the nitrogen beside the nitrogen converters and pumps. Quantity of nitrogen required to prevent restocking being craned in during the operation. Safety transfer of nitrogen between tanks during the operation.

A nitrogen pumping schedule will be prepared in advance by the service company. If during the nitrogen operation there are any significant variations from this schedule the job will be shut down and the cause investigated. If necessary, the operation will be adjusted and restarted. 14.5.1. Pressures •

•

Nitrogen pump pressures should be determined before the start of a job. This is of particular importance with gas lifting. If the job is not correctly designed the combined coiled tubing friction pressure and negative hydrostatic effect can lead to high surface pump pressure which may exceed the maximum allowable coiled tubing pressure. The maximum working pressure of wellheads and production equipment should also be considered when designing nitrogen operations. High pressure gas pockets may return to surface.

14.5.2. Pump Rates •

Pump rates will be clearly stated in the individual stimulation programme. Generally the analogue gauges on nitrogen pumps and tanks are not very accurate and allowance should be made for this.

14.5.3. Coiled Tubing Gas Lift A detailed programme is available in the Coiled Tubing Section 13.6.1

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14.5.4. Nitrogen Cushion - Tubing Conveyed Perforation Nitrogen is used to allow control and adjustment of the drawdown pressure during tubing conveyed perforation operations. The general term used here is differential perforating. The standard procedure follows: • • • •

•

Once the tubing has been pressure tested for integrity using water, a circulating sleeve is opened above the packer and nitrogen is injected down the tubing. Nitrogen displaces the water out of the circulating port until the desired fluid height is achieved. The port is closed and nitrogen is pumped until the correct pressure is achieved on top of the water cushion. Normally 500-1,000 psi drawdown is required to ensure that, when the guns are fired, the perforation debris is ejected from the perforation tunnels and fluid is prevented from entering the perforation. Alternatively if circulation is not possible, coiled tubing may be used to circulate out the fluid used to pressure test the tubing. Coiled tubing should be run to about 500 ft below the desired top of water cushion to ensure that sufficient water is expelled. An amount of fluid will fall back after nitrogen lifting has ceased. The precise calculations for the amount of nitrogen required will be provided by the service company by customised computer design packages.

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14.5.5. Nitrified Treatment •

• • •

• • •

14.6.

Nitrified treatments are performed when the well being treated is unable to support a full column of treatment fluid. The nitrogen is injected into the treatment fluid thus reducing the density of the fluid and, hence, allowing the fluid to return from the formation. Treatment fluids commonly nitrified include acid, surfactant acids and surfactant or solvent treatments. A rate of 400 to 1,000 scf/bbl of nitrogen per barrel of treatment fluid is normally advised. When designing nitrified treatments, note should be taken of the additional surface pressure expected due to the reduced hydrostatic head of the nitrified fluid and the additional friction due to the two phase flow. The specific pump rates, and expected pressures, should be calculated using the service company’s stimulation programme. Energised fluid should be treated with caution. Nitrogen and treatment fluids are commingled at the surface and injected through the tubing. The treatment is fully, or partially, displaced using nitrogen to ensure sufficient drawdown on the formation to allow the nitrified fluid to return.

NITROGEN TECHNICAL INFORMATION Nitrogen is used for three main reasons: • • •

•

Nitrogen is an inert gas which does not readily react with other substances, for example flammable well fluids. Nitrogen does not dissolve readily in water as does CO2 thus improving efficiency. Nitrogen is relatively cheap and readily available in Liquid form. The added advantage of liquid nitrogen, rather than gaseous nitrogen, is that it can be pumped efficiently as a liquid then vaporised using heat from a heat source such as an engine with hydraulic heat. Several large pumps would be required to produce the rates and pressures available from one nitrogen converter/pump. When turning from cryogenic liquid to gas at room temperature the nitrogen will expand almost 700 times. It is clear, therefore, that trapped liquid could be highly explosive. All liquid nitrogen handling equipment is fitted with relief valves to prevent the trapping of liquid.

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EMERGENCY PROCEDURES (During Nitrogen Operations) All personnel must be familiar with the facility alarm system and know the course of action to be followed in the event of the alarm being sounded. These procedures are intended for platform operations

14.7.1. Production Shutdown 1) 2) 3) 4) 5) 6) 7) 8)

Stop pumping nitrogen immediately. Close the SCSSV (Refer to section 13.5 for procedures when coiled tubing is being used). Close the wing valve. Bleed down the surface nitrogen pressure, secure tanks and depressurise. Return all work permits to the control room. Inform the control room that the well has been secured. If the SCSSV is left open, the control panel will be checked frequently. Work will only resume once the stand down has been announced, and work permits have been re-issued.

14.7.2. General Platform Alarm 1) 2) 3) 4) 5)

6)

Stop pumping and, time permitting, depressurise the surface lines and tanks. Close the SCSSV (Refer to section 13.5 for procedures when coiled tubing is being used). Close the wing valve. All non-essential personnel must report to their muster stations. The Well Operations Supervisor will inform the control room of the well status and the names of the personnel remaining at the nitrogen unit (which will be a maximum of two). The Well Operations Supervisor and the nitrogen operator will remain at the well site to ensure that the well and equipment remains in a safe condition during the alert. They will be able to act should the situation deteriorate.

14.7.3. Prepare to Abandon Platform Time permitting the following actions should be followed: 1) 2) 3) 4) Note:

Stop pumping and shut down the nitrogen pump unit immediately, depressurise lines and tanks only if time permits. Close the SCSSV. Secure the well by closing the wing and master valves. All personnel will report to their muster stations and follow tannoy instructions. Safety of personnel is paramount, and the above actions should only be followed if it is considered safe to do so. Therefore if there is ANY doubt ALL personnel will report to their muster stations IMMEDIATELY.

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14.7.4. Liquid Nitrogen Spill 1) 2) 3) 4)

5)

Prior to handling nitrogen all personnel must be familiar with the Safety Data Sheets, and the actions to be taken in the event of a spill. In the event of a major liquid nitrogen spill or equipment failure the operation will be shut down and the control room informed immediately. The point of leakage will be identified and isolated immediately, without endangering life. Spilt liquid nitrogen should be sprayed with a fine spray of water. Do not flush to drains. Try to contain the spill using fine water sprays to vaporise the spill and insulate the deck. In the event that the tank has a small but uncontrollable rupture, personnel should be cleared from the area and the tank should be lifted by crane over the sea. Any spills being immediately sprayed with water.

14.7.5. Injury to Personnel 1) 2) 3) 4) 5)

The rig medic must be informed immediately of any incident. Remove the victim to a safe area and apply first aid as required. In the event of a person coming into contact with liquid nitrogen the area contacted should be treated as a serious burn and kept clean, dry and aseptic. If the contact is around the eyes flush them with copious amounts of water or with an eye bath if it is available. If the victim is suffering from asphyxiation, immediately apply artificial respiration while the victim is dragged clear of the effected area. Apply oxygen if available. Do not spend time in the area as the rescuer may will become a victim.

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15.

STIMULATION PROCEDURES

15.1.

INTRODUCTION

2)

3)

•

15.2.

0

Stimulation Treatments will not be allowed to commence without an approved work programme. The Completions and Workover Superintendent will confirm that the well to be treated is available and accessible. Should the rig be required then he will confirm its availability and the manning requirements. A pre-job meeting should be held well in advance of the actual operation. The purpose of this meeting is to: • • •

4)

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Discuss the programme of operations. Establish channels of communication and define responsibilities. To discuss any special requirements or circumstances that may arise e.g. procedures in the case of emergency, adverse weather conditions, chemical safety data sheets, escape of hazardous treatment fluids, etc. Additional topics will be discussed as required and may include working in confined spaces, working with pressurised equipment, handling of heavy equipment, etc.

A brief written outline of previous relevant well treatments should be given to the stimulation supervisor.

SAFETY CONSIDERATIONS Safety during stimulation treatments, in common with most operations in a potentially dangerous environment, is largely dependent on sound operating procedures and effective communication. The following points are essentially common sense and should be observed during all phases of the operation. • • • • •

•

Do not stand near treating lines, pumps, tanks, or any other treating equipment during operations. There should be no overhead lifts across or near the storage or mixing tanks. Safety harnesses will be used when operating above ground level. This includes working on top of the mixing tanks, as in the derrick. When treating the well with hazardous chemicals the relevant safety wear must be worn by all personnel in the work area. Before rigging up treating equipment a safety meeting will be held with all relevant personnel. The topics to be covered will include, but not be limited to, working with pressurised equipment, handling of heavy equipment, use of hazardous chemicals, safe working areas, emergency procedures, protective clothing, etc. Only authorised personnel wearing adequate protective clothing will be allowed in the vicinity of the equipment while an acid treatment is being performed.

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Good communications between the pump operator, tank operator, rig floor, wellhead area and coiled tubing or nitrogen operator where applicable must be maintained throughout the treatment. All personnel should be aware of the Emergency Procedures for coiled tubing operations . All work areas will be chained, or roped off, and warning signs placed at access routes. The exact requirements will be specified on the work permits. Fire hoses will be available in the areas where acid is to be used. The hoses will be fully charged, so that they can be used immediately should a spill occur. Acid showers and eye baths will be available should any personnel come into contact with acid. Sacks of soda ash or calcium carbonate will be available for absorbing small spills of acid. The acid tanks and pumping unit will be positioned as close to the well as possible to minimise the length of pressurised lines.

15.2.1. Chemical Handling Safety Equipment • •

•

• •

When handling or working in the vicinity of hazardous chemicals, suitable safety equipment must be made available and used. The type of safety equipment required will depend on the type of chemical or chemicals being handled. As standard procedure when handling any fluid or powder that may have toxic, harmful or irritant properties ensure that a chemical suite, chemical handling gloves and chemical goggles or visor are worn. In addition when handling powders ensure that a dust mask is worn. When handling chemicals which produce fumes, ensure that the work area is well ventilated and not enclosed. Operators should not be subjected to fume levels which require the use of fume masks or respirators, however wear a fume mask if necessary. It should be noted that not all fuming chemicals produce noticeable odours, therefore refer to the chemical safety data sheet for information regarding fumes. When safety wear is contaminated with chemicals, the safety wear should be changed at once to avoid contact with the contaminant later. A shower should be located within easy reach of the operational area.

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Safety Data Sheets • •

• •

When operating with chemicals of any kind ensure that the safety data sheet for each chemical is available both at the safety meeting and in the work area. During the safety meeting the Safety Officer should be shown each of the safety data sheets. The safety officer should analyse the sheet and point out the hazards and handling instructions for each chemical. Details such as LD50s and flash points do not need to be conveyed to the operators. It is the responsibility of the Safety Officer to indicate to the operators items such as the flammability, amount of fumes, general level of hazard, compatibility with other chemicals and method of handling. The control and disposal of spills and leakages of all the chemicals used should be explained. In the event of chemical injury the safety data sheets will be available to enable the Medic and Safety Officer to determine the best action.

15.2.2. Pressure • •

•

• •

During Stimulation operations pressure will be used to inject the fluid into the wellbore and for the transfer of fluids between tanks and pumps. The pressure will either be fluid pressure or energised fluid pressure. It is important to not that when operating with energised fluid pressure, it is essential to keep the operational personnel in safe areas when ever possible. The effect of energised fluid pressure release is explosive. It is essential that all pressure handling equipment carry up to date certification for use in the pressure range specified. A pressure test and wall thickness certificate is only proof that the equipment was acceptable on that date. Full visual inspections should be carried out on all pressure handling equipment during rig up. Any defects at all should result in the item being marked defective and laid aside. Follow the rig up and pressure test procedures rigorously for all items operating under pressure. Any leakages should be dealt with by replacing the defective item, followed by a re-test. Ensure that all operational personnel in the work area are made fully aware of the pressure hazard and are told to keep clear of the area when not actually performing duties.

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PERMIT REQUIREMENTS Note:

All permits will be issued in accordance with the Installation Permit to Work System. • • • • • • •

Note:

No work can be performed without an authorised work programme, and the relevant work permits. The Completions and Workover Superintendent will confirm that the well to be worked on is available, and accessible. Should the rig be required then he will confirm its availability, and the manning requirements. The Completions and Workover Superintendent will ensure that all relevant equipment and materials are on site in a timely manner. The Area Authorities, together with the Safety Officer will make an inspection to ensure that there is no other work going on which may affect the operation. Only equipment with valid test certificates will be use for rigging up and during the operation. All work will be conducted according to the Permit to Work System. All permits will be revalidated at the end of each shift. Permits may not be valid for 12 hours on crew change days.

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PAGE

The stimulation company will be provided with well details, and the nature of the operations. The stimulation company will provide details of the equipment and chemicals required. This will include dimensions and weights of individual items, together with data sheets for all chemicals that are to be used. The stimulation company will also provide details of their quality assurance and safety procedures. These procedures will be approved by the Company.

RIG-UP PROCEDURES

15.4.1. Equipment Preparation and Siting • • • • • •

The stimulation company will have a rig up procedure that has been approved by the Company in advance. The stimulation equipment may be rigged up on the pipe deck or skid deck. The equipment will be situated such that the length of pressurised lines, and lines carrying acid, are minimised. All manifolding and valves will be within easy reach of the stimulation crew members. All lines will be pressure tested with water according to the values stated in the stimulation programme. Where possible the pump unit operator will have an unobstructed view of the rig floor, or wellhead area, and of his tank operators. Personnel involved in the operation will carry radios at all times.

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15.4.2. Equipment Rig-Up • • •

When rigging up equipment ensure that all pressure operating items carry valid test certificates. Inspect all items for wear or damage and do not use any defective items. Ensure equipment is rigged-up with sufficient clear escape routes.

15.4.3. Pressure Testing • • • Note:

Pressure testing should be performed with all lines and spaces to be tested full of water. Testing with nitrogen should be avoided. Pressure testing will take place to 1.5 times the maximum operating pressure. The pressure testing will be witnessed by the Well Operations Supervisor.

• •

Pressure tests will be monitored for 15 mins on a chart recorder. The chart will be labelled and stored for reference. The PRV is to be isolated during pressure test.

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15.4.4. Treating Lines • • •

• • • •

Inspect all treating lines thoroughly. Mark and set aside defective treating equipment. Ensure treating line runs are kept as short and direct as possible without causing unnecessary obstruction. When treating at high rates and as a general practice, ensure sufficient flexibility in the treating line by incorporating chicksan bridges in the line. Cavitation and high pump rates can stress lines and back off unions by vibration unless the line is flexible. Lines should be tied together using a steel cable and clamps. Each individual line, swing or other treating pipe, should be clamped to the cable. The lines should also be tied off where possible to fixed objects such as pad eyes. Ensure that each fluid or nitrogen pump is fitted with a check valve. A check valve should also be fitted to the treating point, i.e. coiled tubing reel, well head, kill line. Check valves should be fitted with bleed-off needle valves.

15.4.5. Rigging Down • •

15.5.

Rigging down will only take place once the Workover Superintendent or company representative has given permission. The existing Hot Work permit may be used if still valid otherwise a new Cold Work permit may be obtained.

TREATMENT PROCEDURES The parameters for any job will be dependent on several factors: • • • •

Capacity of the surface equipment Injectivity of the formation Formation pressure Formation breakdown pressure.

A pumping schedule will be prepared in advance by the service company. If during the stimulation treatment there are any significant variations from this schedule the job will be shut down and the cause investigated. If necessary the treatment will be circulated out of the well, and a revised treatment performed. Pressures If a matrix acid treatment is to be carried out an injection test will be performed before any treatment. This test will establish the injectivity of the formation and will give a baseline on which to provide a preliminary estimate of the treatment effectiveness. The maximum allowable pump pressure will be determined during the design phase of the job. Normally the limiting factor will be the formation breakdown pressure. It is normally undesirable to fracture the formation while performing a matrix acid treatment. Therefore a maximum allowable surface pressure will be clearly stated in the stimulation programme. Normally this pressure will include a safety factor.

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Pump Rates Pump rates will be clearly stated in the individual stimulation programme. The rate of dissolution will depend on the nature of the deposits, and the speed at which the acid is being pumped. Some treatments will require a soak period, and a slow pump rate may be required. Other treatments may require rapid pump rates to ensure that any reaction products are removed quickly. 15.5.1. Matrix Acidising Matrix acidising is commonly used in mud or clay damaged sandstone formations. Mud damage is due to the bentonite in the mud coating the formation face, or invading the formation. Normally this type of damage is shallow, i.e. little more than an inch or so deep. 15.5.2. Fracture Acidising Fracture acidising is not recommended in sandstone reservoir units. Success of fracture acidising depends on the creation of a conductive fracture. HCl does not react with sandstone. HF does react with sandstone, but large quantities of acid, and excessive contact times are required before significant quantities of sandstone are dissolved. Therefore it is unlikely that adequate fracture flow capacity would be obtained economically by reaction of the acid. 15.5.3. Acid Wash Acid washes are used primarily for cleaning up of scaled tubulars. The best method for acid washing is to use coiled tubing to spot the acid precisely across the area to be treated. The acid may then be left to soak for a pre-determined period, and then displaced out of the well. The soak time will be dependent on the volume of scale to be removed, acid concentration, and acid volume. 15.5.4. Scale Dissolver HCl can be used for dissolving carbonate based scales, but proprietary blends of scale dissolver are required for sulphate based scale. The types of treatment that can be implemented are: • •

Spot the dissolver, and allow it to soak before back flushing the well Run coiled tubing and jet the scale with dissolver.

The particular method used will depend on the nature of the scale in the well. The methods for the placement of acid are given below. the method to be used will be dependent on prevailing circumstances. As no two jobs will be the same the procedures given below are guidelines only. The actual procedures will be dependent on the nature of the work to be done.

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15.5.5. Bullhead Bullheading acid can be potentially wasteful of the amount of acid used for a treatment. It is possible that some of the acid will react with scale and other products deposited on the inside of the tubing. These products may then be pushed into the formation resulting in damage. Back-flushing of spent acid may be more difficult and time consuming if bullheading is used. An advantage with bullheading is that high rates can be pumped and rig up is more straightforward. 15.5.6. Coiled Tubing This method is preferred to bullheading as placement of the acid is more precise than if it was bullheaded into place. Use of coiled tubing also minimises the amount of contamination in the preflush and so saves time and chemical costs. Should a job go wrong (e.g. formation plugs up) it is easier to remove unspent acid from the well by straight forward circulation. Clean up is also more effective with coiled tubing, as the well can be lifted with nitrogen if the reservoir pressure is low. A disadvantage with using coiled tubing is that the displacement rate may be restricted. 15.5.7. Asphaltene and Wax/Dissolvers Asphaltenes and waxes are high molecular weight compounds that can occur in some crude oils. The presence of these compounds can either cause an increase in the viscosity of the crude (reducing vertical lift performance) or can be deposited when the temperature is reduced. Deposition may occur in the production conduit and/or topside processing facilities. Such compounds can be dissolved by introducing an aromatic solvent (e.g. TROS 94-19) in the production conduit, either by bullheading or by placement with coiled tubing. 15.6.

STIMULATION TECHNICAL INFORMATION Stimulation is used for two main reasons. i.e. remove damage due to drilling and workover fluids, and improve productivity by increasing the effective permeability around the well bore. Acid may also be used for removing scale deposits in the perforations and completion equipment. The damage may result from: • • • • •

Filtrate invasion forming stable emulsions with oil, or causing high water saturations leading to water blocking. Naturally occurring clays being adversely affected by mud filtrate or brine causing swelling, or migration to take place. Mud solids plugging the pore space, or if the reservoir is naturally fractured whole mud lost to the formation. Perforating damage when perforating overbalanced. Scale formation across the perforations.

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The type of damage will have to be assessed prior to the job. Once this has been done the procedure can be finalised. Where possible the stimulation company will be provided with details of formation fluids, completion fluids, production history and, if possible, a core or scale sample. 15.6.1. Factors Affecting Acid Reaction Pressure As pressure increases to 500psi reaction rate is reduced, above 750psi pressure has little effect on reaction rate. Temperature The speed of any chemical reaction is directly affected by temperature. For instance acid will react three times faster at 300oF than at 150oF. Increasing temperature will cause a reduction in viscosity, which will have a role in reaction kinetics. Increase in temperature will also lead to more severe corrosion of the well bore tubulars. Acid Concentration The greater the strength of hydrochloric acid the longer it will take to react to completion. However the initial reaction rates are faster. The increase ion by-products resulting from the stronger acids acts as a retarder to the acid as its strength reduces. For example: • •

25% HCl reacts faster than 10% HCl in a limestone. But when the strength of the 25% acid is reduced to 10% its reaction rate is less than that of a 10% acid concentration. For temperature from 75oF to 250oF, 30% HCl will take approximately three times longer to react than 15% HCl.

Velocity In general increasing velocity will reduce the time it takes for acid to react. This may be offset by the increase in penetration rate. Surface Area The greater the surface area exposed to acid the faster the acid will react, so limiting the depth of penetration of the acid. However in anisotropic formations (e.g. limestone) the acid may tend to 'wormhole', and so penetrate to a greater depth than might be thought. Formation Composition The chemical and physical composition of the formation will have an effect on the reaction rate, the greater the volume of calcium carbonate the faster the reaction. The main types of acid used in sandstone acidising are hydrochloric acid (HCl), and hydrofluoric acid (HF). Organic acids, such as acetic acid and formic acid, can also be used in conjunction with HF and HCl.

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HCl will not dissolve sand or clays. It will dissolve any carbonates present in the formation (e.g. from LCM material, or scale build up). It will also partially dehydrate any water swollen clays that may be present. When hydrated bentonite is in contact with HCl an ion exchange occurs. This results in the sodium bentonite being altered to hydrogen bentonite. This can result in up to 80% loss of water, and shrinkage are of the clay particles. HF does have the ability to dissolve silica (sand) or silicates such as clay, shale, silt and feldspar. As bentonite is a silicate it can be dissolved by HF acid. Formations with damage due to clay migration, or bentonite from drilling mud can be treated with HF. HF is usually pumped as an HCl-HF acid mixture, with the HF being liberated by the reaction of HCl on ammonium bifluoride. Excess HCl is used as it tends to increase the solubility of some of the secondary reaction products, and also has a significant effect on the rate of the reaction. A summary of commonly used acids and their reactions is presented in figure 15.a.

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15.6.2. Acid Properties

Figure 15.A - Properties of Commonly Used Acids

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PAGE

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ACID ADDITIVES Several chemicals may be added to the acid in order to alter its chemical or physical characteristics (Refer to the Drilling Fluids Manual). The most commonly used are: Friction Reducer These are added to reduce the frictional pressure drop while displacing acid into the well. They are particularly important when coiled tubing is being used, as the frictional pressure drop can be considerable. They are added in concentrations varying from 1 to 4lb/1,000 gals in order to achieve a reduction in friction pressure of 65-80%. Normally they are natural or synthetic polymers, such as guar, cellulose, etc. Diverting Agents To ensure that the total interval of interest is to be properly stimulated it will be necessary to limit the amount of acid penetrating any zones of high permeability and/or low pressure. This is done by adding a diverting agent to the treatment. Diverting agents available are both mechanical and chemical in nature. Mechanical means, such as ball sealers of high specific gravity are pumped at sufficient velocity to plug off the perforations. They then drop off and fall into the sump when pumping stops. Chemical diverting agents bind together to form an impermeable skin across the perforations, or within the formation. They must be soluble in hydrocarbons or water to allow clean-up on back flushing. Fluid Loss Additives Fluid loss additives are mainly used in fracture treatments as an aid to extending the fractures by minimising bleed off of the treating fluid into the faces of the fracture. They may be used for the same function as blocking agents. Surfactants Surfactants lower the surface tension of the acid solutions. They assist acid penetration into microscopic pores in tight formations, or in removing scale or cement particles from sand faces. They aid acid penetration of oil films present in the pores, or formation surfaces so improving contact. They also aid back flushing and return of spent acid during clean up by decreasing the resistance of the formation to acid flow. Retarders Retarders are used to decrease the reaction rate to achieve increased penetration away from the wellbore. This is done by using chemicals which deposit a film over the rock after initial acid contact, or through increased viscosity by using natural or artificial gums to thicken the acid.

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Demulsifiers Demulsifiers are used to reduce the tendency of the acid to form an emulsion with oil within the formation. This is particularly important, as the formation of an emulsion may block the pores completely. Corrosion Inhibitors Corrosion inhibitors are used to minimise damage of the downhole tubulars by the acid. They can be complex organic substances which can inhibit both the anodic and cathodic reactions at the same time. Iron Retention Additives Iron hydroxides that form during a stimulation job may tend to deposit in both existing and newly created flow channels. Iron sequestering additives, or a synergistic blend of sequestering and pH control agents together may help prevent the precipitation of iron and other metallic salts or bases as the acid reacts. Sequestering is achieved by complexing the ions of the iron with the additive so they remain in solution. Additional Additives Other additives which may be used are: • • • •

Alcohol (aids clean up in water blocked gas zones) Clay stabilisers Scale inhibitor Paraffin inhibitors.

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Appendix A - Report Forms A.1.

Initial Activity Report (ARPO 01)

District/Affiliate Company DATE:

INITIAL ACTIVITY REPORT

ARPO 01

Permit/Concession N°

Cost center

Well Code

General Data On shore

WELL NAME FIELD NAME

Depth Above S.L .

Off shore

Joint venture

Ground Level[m]

AGIP:

%

%

Latitude:

Water Depth [m]

%

%

Longitude

Rotary Table Elev.[m]

%

%

Reference

First Flange[m]

Rig Name

Top housing [m]

Type of Operation

Reference Rig

Rig Type Contractor

Ref. Rig RKB - 1st Flange

Program TD (Measured)

[m]

Program TD (Vertical)

[m]

Cellar Pit

Rig Heading [°] Offset FROM the proposed location

Rig Pump

Depth [m]

Manufacturer

Distance [m]

Length [m]

Type

Direction [°]

Width [m]:

Liner avaible [in] Major Contractors

Type of Service

Company

Contract N°

Type of Service

Company

Contract N°

Mud Logging D. & C. Fluids Cementation Waste treatment Operating Time

Jack-up leg Penetration

Supply Vessel for Positioning

Moving

[gg:hh]

Leg

Air gap

Penetration

Positioning

[hh:min]

N°

[m]

[m]

Anchorage

[hh:min]

Rig-up

[hh:min]

Delay

[hh:min]

Lost-time Accidents

[hh:min]

N°

Name

Horse

Bollard pull

Power

[t]

Rig Anchorage Anchor Bow N°

Angle

Mooring Line Weight

Type & Manufacturer

[t]

Piggy Back

Length Cable

Chain

[m]

[m]

Weight N°

[t]

Mooring Line Chain

Cable

Length

Ø

Length

Ø

[m]

[mm]

[m]

[mm]

Tension Operative

Total

[Tested]

Tension

Time

[t]

[t]

[hh:min]

1 2 3 4 5 6 7 8 9 10 11 12 Note:

Supervisor

Superintendent

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Daily Report (ARPO 02)

DAILY REPORT

WELL NAME

Completion - Work Over

FIELD NAME

District/Affiliate Company DATE: Completion

ARPO 02 Modified Cost center

Work Over

Well Code

Report N°

of

Rig Name

Well Type

RT Elevation

[m]

Type of Rig

Well Drilled On

Ground Lelel / Water Depth

[m]

Contractor

Last Intervention Date Well Head

BOP

Type W.P.

[psi] Production casing

Ø nom. ID

[inch] [inch]

Steel Grade

Type

RT - 1st flange Ø

w.p. [psi]

Costs

Stack Diverter

Rig Service

Annular

Materials

Annular Upper Rams

Logistic Personnel

Middle Rams

Thickness

[lb/ft]

Middle Rams

Agip

Top

[m]

Middle Rams

Rig

Bottom

[m]

Lower Rams

Others

Top cmt

[m]

Last Test

Total

From [hr]

To [hr]

[m] Daily

Boarding

Cumulative

Leaving

OP. Code OPERATION DESCRIPTION

Operations at 07:00 Mud Situation

Visc. [s/l]

Mud Type

Cl- / O/W

Density [kg/l]

pH / ES

Contractor

Stock

Mud in pits

Type of Service

Quantity

Losses

Additives

[g/l]

Working Stand by Hours Hours

UM

Stock

Arrived on Loc. Date Hour

Quantity

Left Loc. Date Hour

UM

Supervisor:

3

Daily

[m ]

Progr.

[m3]

Daily Service Cost

Cumulative Serv. Cost

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Cementing Job Report (ARPO 04B)

CEMENTING JOB REPORT



ARPO-04 / B

Cost center

Ø [in]

Operation type

Stage / No.:

SQUEEZE / PLUG Type

Ø

Length [m]

Cap.[ l/m]

Bottom [m]

Cement retainer

Manufacturer

Injectivity Test with:

Pump Rate [l/min] [kg/cm 2]

Test

Ø

Depth

[inch]

[m]

Model / Type

Squeeze packer

Testing Pr.

Tot. Vol.

Final Sqz Pr.

Returns Vol

[kg/cm 2]

pumped [l]

[kg/cm 2]

[l]

[mins]

Stinger Pressure test Annular pressure CEMENTATION [kg/cm 2]

Operation (y/n) Casing Reciprocation

Bump Plug

Casing testing pressure

Casing Rotation

Valve holding

Annulus pressurization

[mins]

Inner string GENERAL DATA Slurry Displacement With

Losses [m3]

To Surface

pumps

Density

Fluid type:

[kg/l]

pH

Dumped [m 3]

During csg run Circulation

Volume

[m3]

Mud

Density:

[kg/l]

Spacer

Displacement

Duration:

[mins]

Slurry

Opening DV

Final pressure:

Mix/Pump Slurry

[kg/cm 2]

Circ. through DV Total Circulation / Displacement / Squeeze

Time [mins.] Partial

Supervisor

Progr.

Flow Rate

Pressure

Total Volume

[l/min]

[kg/cm 2]

[l]

Operation Description

Superintendent

Final Press.

Returns

[kg/cm 2]

Vol. [l]

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Waste Report (ARPO 6)

WASTE DISPOSAL

WELL NAME

Management Report

FIELD NAME


ARPO-06 Cost center

Report N° From [m]

Depth (m) Interval Drilled (m)

To [m]

Drilled Volume [m ]

Mud Type Density (kg/l)

Phase size [in]

Cumulative volume [m ]

3

Cl- concentration (g/l ) 3

3

Water consumption Usage

3

Phase /Period [m ] Fresh water

Recycled

Cumulative [m ] Total

Fresh water

Recycled

Total

Mixing Mud Others Total

Fresh water [m3]

Readings / Truck

3

Mud Volume [m ]

Phase

Recycled [m3]

Service

Cumulative

Mixed

Company

Contract N°

Mud Company

Lost

Waste Disposal

Dumped

Transportation

Transported IN Transported OUT

Waste Disposal

Period

Water base cuttings

[t]

Oil base cuttings

[t]

Dried Water base cuttings

[t]

Dried oil base cuttings

[t]

Water base mud

[t]

Oil base mud transported IN

[t]

Oil base mud transported OUT

[t]

Drill potable water

[t]

Dehidrated water base mud

[t]

Dehidrated oil base mud

[t]

Sewage water

[t]

Transported Brine

[t]

Cumulative

Remarks

Remarks

Supervisor

Superintendent

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Perforating Report (ARPO 07)

PERFORATING REPORT

District/Affiliate Company DATE: Well location Onshore


ARPO-07

Cost center

Formation name:

Pool:

Lithology

Offshore Total Depth

Rotary Table Measurement [m]

[m]

Final Completion Report [date]

M.D.

Drilling Rig RKB - 1 st Flange

Final Workover Report [date]

Vertical

T.V.D.

Workover Rig RKB - 1 st Flange

Reference Logs:

Deviated

Max. inclination

Well Type

Horizontal

at

Well

Size [Ø]

Situation

[°]

Workover Rig RKB - Sea Level

[m]

Workover Rig RKB - Sea Bottom

Steel

Thickness

Grade

[lb/ft]

Measured Depth Top [m]

Bottom [m]

Recorded on: Vertical Depth Top [m]

Bottom [m]

Cement Top M.D. [m]

T.V.D. [m]

Liner Casing Casing Service Company

Tubing Packer Tubing shoe Perforation System Wireline

Overbalance

Completion fluid

Density

TCP

Underbalance

Fluid in front of Perforation

Density

Thru Tubing

Differential Pressure [kg/cm2]

Fluid Losses after Perforation

Data

Gun

Gun

Gun

Charge

Type

Specific.

Ø

Type

S.P.F


Bottom [m]

[kg/l] [m3]

Vertical Depth Top [m]

Bottom [m]

Note:

Supervisor

[kg/l]

Superintendent

Pool

Remarks

ARPO

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Gravel Pack Report (ARPO 08)

GRAVEL PACK PERFORATING REPORT

District/Affiliate Company DATE: Well Location


ARPO-08

Reservoir Parameter

Cost center

Formation name:

Onshore

Reservoir fluid

Lithology:

Offshore

Density [Kg/l]

Pool:

Well Type Vert. < 30°

Viscosity [Cps][ppm] Water Salinity

Ø [inch]Production casing

Dev. >30°

Pay Zone Inclination [°]

Weight [lb/ft]

Hor. > 80°

Porosity [%]

Type of job

Layer :

N/G [%]

Shoe T.V.D.[m]

OHGP

SBHT [°C]

at m

Fluid losses

ICGP

SBHP [kg/cm 2]

at m

Losses [m 3/h]

F&P

Permeability [mD]

Pilot hole Underreamed

Gravel

Caliper

Top [m] Bottom [m]

Ø max Ø med

Underream

Completion

After Back Surging

Annulus

Volume [m3]

LCM

Pad

Carrier

Well Schetch

Displacement

Visc. [Cp] Polymer

Dens. P.V. [Kg/l]

Visc.[cps]

Y.P.

NTU

Concentr.[µm] [pptg] Filtration Breaker Type

Circulation test

Name

RCP

Pann

0.00

P

psi at

Q

bpm

BOP

Pann

0.00

P

psi at

Q

bpm

open

Pann

0.00

P

psi at

Q

bpm

Pann

0.00

P

psi at

Q

bpm

RCP

Pann

P

psi at

Q

bpm

BOP

Pann

P

psi at

Q

bpm

closed Pann

P

psi at

Q

bpm

Pann

P

psi at

Q

bpm

Pann

P

psi at

Q

bpm

Pann

P

psi at

Q

bpm

MCP Pann

P

psi at

Q

bpm

Pann

P

psi at

Q

bpm

Pann

P

psi at

Q

bpm

Pann

P

psi at

Q

bpm

LCP

After Perforating

Name / Salt Density [Kg/l]

Type

UCP

Underreaming

Fluids

Ø min

Drilling

Drilling

Losses Control

Ø

Fluid

UB/OB [psi]

Total [m3]

to [ ] HC [ ] Brine

Well data

Perforation Bottom [m]

Shoe M.D. [m]

Net Pay (VD) [m]

TTGP

Top [m]

Concentr. [pptg] Completion assembly Tools

Type

Size

I.D.

From

To

[inch]

[inch]

[m]

[m]

Gravel Pack operation S. Tool

Fluid

Gravel

Position

Type

[ppa]

Flow rate [bpm] IN

OUT

Gravel Packing Details

Remarks:

Comments:

Gravel Type: Gravel Size:

Time [hh:mm]

ASCII files: [US mesh]

#1

Total Gravel left in hole:

[lb]

#2

Gravel injected into the formation:

[lb/ft]

#3

Gravel volume reversed out:

[lb]

#4

Top Gravel [Log] :

[m]

#5

Content

ARPO

IDENTIFICATION CODE


PAGE


0

Matrix Stimulation Report (ARPO 09)

MATRIX STIMULATION HYDRAULIC FRACTURING



ARPO - 09

Well Location Onshore Offshore Well Type Vertical

M.D. [m] T.V.D. [m] Open hole Ø Prod. casing / liner Ø

Open hole Perfor. interval Slotted liner From [m]

Deviated Horizontal

Shoe M.D. [m] Top liner [m]

To [m]

Treatment Type Matrix stimulation Acid Solvent Other Hydraulic Fracturing Foam Water base Oil base Other

Reservoir Parameters Reservoir fluid Density [Kg/l] 2 Gradient [Kg/cm /10 m.]

Acid Fracturing Acid Gelled acid Acid + Gel Other

Main Frac Treatment Proppant type: API Mesh Size Amount of Propant [t] 3 Total Frac Fluid Vol. [m ]

Fluid Ref.

Cost center

General Data

Fracturing gradient [calculated] Fracturing gradient [tested] Porosity % SBHT [°C] at m 2 SBHP [kg/cm ] at m

Interval to be Treated Tot. net perf.: Formation name: Pool: Lithology:

Treatment Data Service Company HHP avaible Initial Shut-in pressure [psi] Annulus pressure [psi] Pressure test [psi] Max. injection rate [bpm] Max. injection pressure [psi] Pumping time [min] Pumping time [min]

Completion Data Bottom hole gauge [Y / N] Type Wellhead type Packer type Packer fluid Density Fluid in well at operation beginning

Equipment Coiled Tubing [Y / N] Ø Stimulation vessel / Other equipment

String capacity [l] Packer - Top perforation Volume [l]

String O.D. [in]

Operation Description Fluid Schedule Fluid Composition

Fluid Type

Density [kg/l]

1 2 3 4 5 6 7 8 9 10 N° Fluid Ref.

Injected Circulated

A.7.

183 OF 192

Starting Time

Pumping Rate

Volume

[bbl/1']

[m ]

3

Progr. Volume 3

[m ]

Pumping Parameter Progr.Vol. Proppant Initial Entering in Concentr. Press. Formation [lb/gal] [psi]

Final Press.

Injection Index

Casing Press.

[psi]

[bbl/day/psi]

[psi]

Notes / Remarks: Supervisor

Superintendent

Notes

Mixed Volume [m 3]

ARPO

IDENTIFICATION CODE


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A.8.

184 OF 192

0

Well Problem Report (ARPO 13)

WELL PROBLEM REPORT

District/Affiliate Company DATE: Problem

WELL NAME Cost center

Top [m]

Code Well

ARPO -13

FIELD NAME

Start date

Bottom [m] Ø

Situation

End date


Vertical Depth

Bottom [m]

Top [m]

KOP

Bottom [m]

Open hole

Mud in hole

[m]

Max inclination [°]

Type

@m

Dens.[kg/l]:

DROP OFF [m]

Last casing Well problem Description

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Solutions Applied:

Results Obtained:

Supervisor

Supervisor

Supervisor

Remarks at District level:

Superintendent Lost Time Remarks at HQ level

hh:mm Loss value [in currency] Pag. Of

ARPO

IDENTIFICATION CODE


PAGE


A.9.

185 OF 192

0

Malfunction & Failure Report(FB-1)

MALFUNCTION & FAILURE REPORT (FEED BACK REPORT 01) District/Subsidiary Report Date: Well Name:

Well Code: General Information

Contract No: Service/Supply: Drilling

Contract Type: Completio n

Workover

Contractor: Duration Dates of Failure:

Distributed By:

RIG SITE Description of Failure:

Drilling & Completions Company Man: Adopted or Suggested Solution(s):

Contractor Contingency Measures:

Contractor Representative: DISTRICT OR SUBSIDIARY NOTES:

Failure Classification

Status

Technical

Normal

Management/Organisation

Extreme

Safety/Quality

Innovative Adverse

Operations Manager:

Time Lost:

Estimated Cost of Failure:

MILAN HEAD OFFICE NOTES:

Analysis Code:

ARPO


IDENTIFICATION CODE

186 OF 192


A.10.

PAGE

0

Contractor Evaluation (FB-2)

CONTRACTOR EVALUATION (FEED BACK REPORT 02) District/Subsidiary Report Date:

Well Name:

Well Code: General Information Contract No.: Contract Type: Contractor: Service/Supply: Distributed By: R1 Technical Requirements FB_01 REPORT REFERENCES FB Report No.: Time Lost (Hr.Min): Economic Cost (£M): Category Evaluation Score (0-9) Suitability of Equipment and Materials Compliance of Equipment and Materials to the Contract Adequacy of Personnel Meeting with Operational Programme Requirements Meeting with Contract Operation Timings Equipment Condition/Maintenance R2 Management and Organisational Requirements FB_01 REPORT REFERENCES FB Report No.: Time Lost (Hr.Min): Economic Cost (£M): Category Evaluation Score (0-9) Availability of Equipment and Materials Technical and Operational Support to Operations Capability and Promptness to Operational Requests R3 Safety and Quality Assurance Requirements FB_01 REPORT REFERENCES FB Report No.: Time Lost (Hr.Min): Economic Cost (£M): Category Evaluation Score (0-9) Meeting with the Contract Agreement DSS Availability and Validity of Requested Certificates Meeting with Contract Quality Assurance Terms Event Support Documentation Type of Subject: Issued By: Document:

Notes:

Failure Status Normal Extreme

Operations Manager Drilling & Completions Manager Adverse Innovative

Date:

ARPO


IDENTIFICATION CODE

187 OF 192


Appendix B - ABBREVIATIONS AC/DC AHTS API BG BHA BHP BHT BJ BMT BOP BPD BPM BPV BSW BUR BWOC BWOW C/L CBL CCD CCL CDP CET CGR CMT CP CR CRA CSG C/T CW DC DE DHM DHSV DIF DLP DLS D&CM DOB DOBC DOR DP DPHOT DRLG

PAGE

Alternate Current, Direct Current Anchor Handling Towing Supply American Petroleum Institute Background gas Bottom Hole Assembly Bottom Hole Pressure Bottom Hole temperature Blast Joint Blue Methylene Test Blow Out Preventer Barrel Per Day Barrels Per Minute Back Pressure Valve Base Sediment and Water Build Up Rate By Weight Of Cement By Weight Of Water Control Line Cement Bond Log Centre to Centre Distance Casing Collar Locator Common Depth Point Cement Evaluation Tool Condensate Gas Ratio Cement Conductor Pipe Cement Retainer Corrosion Resistant Alloy Casing Coiled Tubing Current Well Drill Collar Diatomaceous Earth Down Hole Motor Down Hole Safety Valve Drill in Fluid Dog Leg Potential Dog Leg Severity Drilling & Completion Manager Diesel Oil Bentonite Diesel Oil Bentonite Cement Drop Off Rate Drill Pipe Drill Pipe Hang off Tool Drilling

0

ARPO


IDENTIFICATION CODE

188 OF 192


DST DV E/L ECD ECP EMS EMW EOC EP ESD ESP ETA ETU FBHP FBHT FC FINS FPI/BO FTHP FTHT GCT GLR GLS GMS GOC GOR GP GPM GPS GR GRA GSS HAZOP HDT HHP HO HP/HT HSI HW/HWDP IADC IBOP ICGP ID IFR IP IPR JAM

PAGE

Drill Stem Test DV Collar Electric Line Equivalent Circulation Density External Casing Packer Electronic Multi Shot Equivalent Mud Weight End Of Curvature External Pressure Electric Shut-Down System Electrical Submersible Pump Expected Arrival Time Endless Tubing Unit Flowing Bottom Hole Pressure Flowing Bottom Hole Temperature Flow Coupling Ferranti International Navigation System Free Point Indicator / Back Off Flowing Tubing Head Pressure Flowing Tubing Head Temperature Guidance Continuous Tool Gas Liquid Ratio Guidelineless Landing Structure Gyro Multi Shot Gas Oil Contact Gas Oil Ratio Gravel Pack Gallon (US) per Minute Global Positioning System Gamma Ray Guidelines Re-Entry Assembly Gyro Single Shot Hazard and Operability High Resolution Dipmeter Hydraulic Horsepower Hole Opener High Pressure - High Temperature Horsepower per Square Foot Heavy Weight Drill Pipe International Drilling Contractor Inside Blow Out Preventer Inside Casing Gravel Packing Inside Diameter Imposta Fabbricazione Ridotta Internal Pressure Inflow Performance Relationship Joint Make-up Torque Analyser

0

ARPO


IDENTIFICATION CODE

189 OF 192


KMW KOP L/D L/S LAT LC 50 LCDT LCM LCP LEL LMRP LN LOT LQC LTA LTT LWD M/D M/U MAASP MD MLH MLS MMS MODU MOP MPI MSCL MSL MSS MUT MW MWD N/D N/U NACE NB NDT NMDC NSG NTU OBM OD OEDP OH OHGP OIM

PAGE

Kill Mud Weight Kick Off Point Lay Down Long String Lowest Astronomical Tide Lethal Concentration 50% Last Crystal to Dissolve oC Lost Circulation Materials Lower Circulation Position (GP) Lower Explosive Limit Low Marine Riser Package Landing Nipple Leak Off Test Log Quality Control Lost Time Accident Lower Tell Table (GP) Log While Drilling Martin Decker Make Up Max Allowable Annular Surface Pressure Measured Depth Mudline Hanger Mudline Suspension Magnetic Multi Shot Mobile Offshore Drilling Unit Margin of Overpull Magnetic Particle Inspection Modular Single Completion Land Mean Sea Level Magnetic Single Shot Make up Torque Mud Weight Measurement While Drilling Nipple Down Nipple Up National Association of Corrosion Engineers Near Bit Stabiliser Non Destructive Test Non Magnetic Drill Collar North Seeking Gyro Nephelometric Turbidity Unit Oil Base Mud Outside Diameter Open End Drill Pipe Open Hole Open Hole Gravel Packing Offshore Installation Manager

0

ARPO


IDENTIFICATION CODE

190 OF 192


OMW ORP OWC P&A P/U PBR PCG PDC PDM PGB PI PKR PLT POB POOH PPB PPG ppm PTR PV PVT Q Q/A Q/C R/D R/U RBP RCP RFT RIH RJ RKB ROE ROP ROU ROV RPM RPSP RT S (HDT) S/N SBHP SBHT SCC SD SDE SF SG

PAGE

Original Mud weight Origin Reference Point Oil Water Contact Plugged & Abandoned Pick up Polished Bore Receptacle Pipe Connection Gas Polycrystalline Diamond Cutter Positive Displacement Motor Permanent Guide Base Productivity Index Packer Production Logging Tool Personnel On Board Pull Out Of Hole Pounds per Barrel Pounds per Gallon Part Per Million Piano Tavola Rotary Plastic Viscosity Pressure Volume Temperature Flow Rate Quality Assurance, Quality Control Rig down Rug up Retrievable Bridge Plug Reverse Circulating Position Repeat Formation Test Run In Hole Ring Joint Rotary Kelly Bushing Radius of Exposure Rate Of Penetration Radios Of Uncertainty Remote Operated Vehicle Revolutions Per Minute Reduced Pump Strokes Rotary Table High Resolution Dipmeter Serial Number Static Bottom Hole Pressure Static Bottom Hole Temperature Stress Corrosion Cracking Separation Distance Senior Drilling Engineer Safety Factor Specific Gravity

0

ARPO


IDENTIFICATION CODE

191 OF 192


SICP SIDPP SIMOP SPM SR SRG SSC ST STG TCP TD TFA TG TGB TOC TOL TVD TW UAR UGF UR VBR VDL VSP W/L WBM WC WL WOB WOC WOW WP YP

PAGE

Shut-in Casing Pressure Shut-in Drill Pipe Pressure Simultaneous Operations Stroke per Minute Separation Ratio Surface Readout Gyro Sulphide Stress Cracking Steering Tool Short trip gas Tubing Conveyed Perforations Total Depth Total Flow Area Trip Gas Temporary Guide Base Top of Cement Top of Liner True Vertical Depth Target Well Uncertainty Area Ratio Universal Guide Frame Under Reamer Variable Bore Rams (BOP) Variable Density Log Velocity Seismic Profile Wire Line Water Base Mud Water Cut Water Loss Weight On Bit Wait On Cement Wait On Weather Working Pressure Yield Point

0

ARPO


IDENTIFICATION CODE

PAGE

192 OF 192


0

Appendix C - BIBLIOGRAPHY Document:

STAP Number

Completion Design Manual

STAP-P-1-7100

Drilling Procedures Manual

STAP-P-1-6140

Drilling Fluids Manual

STAP I N 6051

Well Control Policy Manual

STAP-P-1-6150

Well Test Manual

STAP-P-1-7130

Wireline Procedures Manual

STAP-P-1-7110

Other API Specification No 811-05CT5

ENI - Completion Procedures Manual

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