Guidelines: Well Life Cycle Integrity

Well Life Cycle Integrity

Guidelines

Issue 4 March 2019

Acknowledgments All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without prior written permission of the publishers. Crown copyright material is reproduced with the permission of the Controller of Her Majesty’s Stationery Office. Copyright © 2019 The UK Oil and Gas Industry Association Limited trading as Oil & Gas UK The information contained herein is given for guidance only. These guidelines are not intended to replace professional advice and are not deemed to be exhaustive or prescriptive in nature. Although the authors have used all reasonable endeavours to ensure the accuracy of these guidelines neither Oil & Gas UK nor any of its members assume liability for any use made thereof. In addition, these guidelines have been prepared on the basis of practice within the UK Continental Shelf and no guarantee is provided that these guidelines will be applicable for other jurisdictions. While the provision of data and information has been greatly appreciated, where reference is made to a particular organisation for the provision of data or information, this does not constitute an endorsement or recommendation of that organisation. ISBN: 978-1-9164677-3-6 PUBLISHED BY OIL & GAS UK London Office: 6th Floor East, Portland House, Bressenden Place, London, SW1E 5BH Tel: 020 7802 2400 Fax: 020 7802 2401 Aberdeen Office: Exchange 2, 3rd Floor, 62 Market Street, Aberdeen, AB11 5PJ Tel: 01224 577250 Fax: 01224 577251 [email protected] www.oilandgasuk.co.uk

Well Life Cycle Integrity Guidelines Issue 4

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Well Life Cycle Integrity Guidelines Issue 4 March 2019 Contents 1

Summary

12

2

Key Regulatory Requirements for Well Integrity 2.1 The DCR definition of well-operator 2.2 DCR – general duty for well-operators 2.3 DCR – specific duties for well-operators 2.3.1 Regulation 15 – Design with a view to suspension & abandonment 2.3.2 Regulation 16 – Materials 2.3.3 Regulation 17 – Well Control 2.3.4 Regulation 18 – Arrangements for examination 2.3.5 Regulation 19 – Provision of drilling etc information 2.3.6 Regulation 21 – Information, instruction, training and supervision 2.4 Duties of the well-operator under SCR 2015 2.4.1 Regulation 11 – Establishment of well examination scheme 2.4.2 Regulation 12 – Other Provisions as to well examination schemes 2.4.3 Regulation 13 – Description of well examination 2.4.4 Schedule 4, Part 2 – Matters to be provided for in a well examination scheme 2.4.5 Regulation 21 – Notification of well operations 2.5 Installation safety case duty holders 2.5.1 Definition of Duty holder 2.5.2 SCR 2015 Regulation 16 Management & Control of Major Accident Hazards 2.5.3 Other duties of installation safety case duty holders 2.6 Offshore environmental protection regulations 2.7 Borehole Sites and Operations Regulations 1995 (BSOR) 2.7.1 Regulation 7 – The health and safety document 2.7.2 Regulation 6 – Notice of the commencement of drilling operations and the abandonment of boreholes 2.8 Other relevant Onshore Regulatory Considerations

14 14 15 15

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16 16 16 17 18 18 18 18 18 19 19 19 20 20 21 22 23 24 24

25 25

2.9 2.10

2.11 2.12

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2.8.1 Onshore Environmental Regulation 25 2.8.2 Coal Authority 25 Control of Major Accident Hazard Regulations (COMAH), 2015 26 Management of Health and Safety at Work Regulations 1999 26 2.10.1 Regulation 5 – Health and safety arrangements 26 The Reporting of Injuries, Diseases and Dangerous Occurrences Regulations (RIDDOR) 2013 26 The Petroleum Act 1998 (as amended by the Infrastructure Act 2015) 27

3

Process Safety and the Well Integrity Management System 3.1 Process Safety 3.2 Well Integrity Management System 3.3 Process Safety Key Performance Indicators

28 28 28 30

4

Well Integrity, Barriers, BOPs and Well Control 4.1 Well pressure containment boundary 4.2 Structural well integrity 4.3 Well barriers 4.3.1 Number of well barriers 4.3.2 Type of well barriers 4.3.3 Shearing and barriers 4.3.4 Describing well barriers 4.3.5 Immediacy of hazards after barrier failure 4.3.6 Barrier components and associated equipment 4.3.7 Barrier selection and qualification 4.3.8 Barrier installation 4.3.9 Testing well barriers 4.3.10 Maintenance and monitoring of barriers 4.3.11 Response to degradation of barriers 4.3.12 Response to failure of barriers 4.3.13 Cemented shoe track as a well barrier 4.3.14 Effects of different installations on well integrity 4.3.15 Use of PTFE tape 4.4 Blowout Preventers 4.4.1 Retirement of O&GUK BOP Guidelines 4.4.2 Good practice for UKCS wells vs. API S53 4.5 Pressure testing guidelines 4.5.1 Risk assessment 4.6 Positive pressure testing guidelines 4.6.1 Pressure test planning 4.6.2 Calculations of fluid volumes 4.6.3 Pressure test operations 4.6.4 Success/failure criteria 4.7 Pressure Test Acceptance Criteria 4.8 Inflow testing guidelines

32 32 32 33 33 33 34 35 35 35 36 36 36 37 37 37 38 39 39 39 39 40 41 42 43 43 44 45 45 46 49

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4.8.1 4.8.2

4.9

4.10

5

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Introduction 49 Specific problems to be considered for inflow tests 50 4.8.3 Inflow test planning 50 4.8.4 Negative pressures across BOP 51 4.8.5 Inflow testing of downhole safety/xmas tree valves 51 4.8.6 Flow checks as inflow tests 52 Well integrity/control of well 52 4.9.1 Primary control of well 52 4.9.2 Secondary well control 52 4.9.3 Well control equipment 53 4.9.4 Well control procedures 54 4.9.5 Tertiary well control 55 Management of change 55 4.10.1 General 55 4.10.2 Design MoC 55 4.10.3 Equipment MoC 56 4.10.4 Programme/procedure MoC 56 4.10.5 Personnel MoC 56 4.10.6 Change request and approval 56 4.10.7 ‘Material changes’ to be notified to the Competent Authority 57

Well Design and Operations Planning 5.1 Risk identification and assessment – the ALARP principle 5.1.1 Review 5.2 Risk Assessments 5.2.1 Assessment of subsurface conditions 5.2.2 Aquifers 5.2.3 Presentation of subsurface assessment 5.2.4 Assessment of other well hazards 5.2.5 Well examination 5.3 Well design 5.3.1 Estimate of maximum pressure 5.3.2 Conductor 5.3.3 Surface casing 5.3.4 Intermediate casings 5.3.5 Production casing 5.4 Casing design 5.4.1 General 5.4.2 Design basis, premises and assumptions 5.4.3 Load cases 5.4.4 Casing design factors 5.5 Cement design 5.5.1 Factors to be considered in annulus cementing 5.5.2 Considerations for inner string cementing

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58 58 58 58 59 60 60 60 61 61 61 61 62 63 63 64 64 65 65 66 66 67 68

5.6 5.7

5.8

5.9 5.10 5.11 5.12 5.13

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Materials for wells 69 5.6.1 Wellhead equipment 69 Designing a well for primary control 69 5.7.1 Overbalanced drilling and operations 69 5.7.2 Pore pressure prediction 69 5.7.3 Maintaining overbalance 70 5.7.4 Safety margin on mud weight 70 Formation integrity/kick tolerance 70 5.8.1 Background 70 5.8.2 Leak Off Test / Formation Integrity Test 71 5.8.3 Kick tolerance 71 Design for suspension of operations, plugging and abandonment 72 Well path and anti-collision 72 Relief well considerations 74 Dispensation / deviation during design 74 Well operations planning 75 5.13.1 General 75 5.13.2 Equipment procurement 75 5.13.3 Rig contracting for mobile drilling units 75 5.13.4 Service Company – well control equipment 75 5.13.5 Information, instruction and training 76 5.13.6 Site surveying for offshore wells 76

Drilling 6.1 Primary control of the well/active barriers 6.1.1 Pore Pressure monitoring 6.1.2 Monitoring mud weight 6.1.3 Reacting to lost circulation 6.1.4 Loss/gain situation 6.1.5 Roles and responsibilities for primary control of the well 6.2 Potential barriers 6.2.1 Roles and responsibilities for potential barriers 6.3 Pressure containment boundary 6.3.1 Roles and responsibilities for pressure containment boundary 6.4 Other responsibilities for drilling operations 6.4.1 Other roles of the drilling supervisor 6.5 Installation and testing of barriers 6.5.1 Conductor 6.5.2 Surface casing 6.5.3 Wellhead 6.5.4 Setting BOP 6.5.5 Intermediate casings 6.5.6 Production casing 6.5.7 Inner barriers

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77 77 77 78 78 79 79 80 80 81 81 81 82 82 82 83 83 84 86 87 88

6.6 6.7 7

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Managed Pressure Drilling / Under Balanced Operations Drilling before BOP installed

88 89

Well Testing 7.1 General 7.2 Primary control of the well/active barriers 7.2.1 Pressure containment boundary 7.2.2 Potential barriers during well testing 7.3 Responsibilities for testing operations 7.3.1 Well control procedures during testing 7.4 Well test planning 7.4.1 Risk assessment and mitigation 7.5 Installation and testing of barriers 7.5.1 Running liner or lower completion 7.5.2 Liner lap 7.5.3 Test string and tubing 7.5.4 Annulus barriers (packer and BOP) 7.5.5 Inner potential barriers (tester valve and surface tree) 7.6 Well testing operations 7.6.1 Perforating 7.6.2 Flow and shut-in periods 7.6.3 Killing the well 7.6.4 Suspension of operations, plugging and abandonment

91 91 91 91 92 92 93 93 94 94 94 95 95 96 96 98 98 98 98 99

8

Completion 8.1 Primary control of well/active barriers 8.1.1 Fluid column 8.1.2 Mechanical barriers 8.1.3 Removing the rig BOP/installing the xmas tree 8.2 Pressure containment boundary 8.3 Installation and testing of barriers 8.4 Completion design and planning 8.4.1 Packer 8.4.2 Tubing 8.4.3 Tubing hanger 8.4.4 Downhole Safety Valve 8.4.5 Wellhead 8.4.6 Xmas tree 8.5 Artificial lift 8.5.1 Gas lift 8.6 Completion operations 8.6.1 Displacement to light fluid

100 100 100 100 101 101 101 103 103 103 104 104 105 106 106 106 108 109

9

Commissioning 9.1 Summary 9.1.1 Well Integrity

110 110 110

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9.2 9.3 9.4 9.5

Initial well handover information Life of well information Surface equipment considerations Well examination and verification

110 111 112 112

10 Operate and Maintain 114 10.1 Well integrity assurance 114 10.1.1 Well integrity management systems 114 10.1.2 Roles and responsibilities 114 10.1.3 Competency 114 10.1.4 Well files and operational histories 115 10.1.5 Well stock performance review 115 10.1.6 Risk Assessment and Management 115 10.2 Operating procedures 116 10.2.1 Special precautions for start-up and shutdown 116 10.2.2 Operating parameters and monitoring 116 10.2.3 Verification of control measures 116 10.3 Visual inspection of wells 117 10.4 Annulus management 117 10.4.1 Key Requirements of an Annulus Management Process 117 10.4.2 MAASP and Annulus Operating Limits 118 10.4.3 Pressure Testing & Topping up annuli 118 10.4.4 Factors affecting annulus pressure 119 10.4.5 Sustained annulus pressure 119 10.4.6 Annulus depressurisation and bleed down 120 10.5 Xmas tree and wellhead valves 121 10.5.1 Barriers within wellheads 121 10.5.2 Wellhead valves 121 10.5.3 Xmas tree valves 121 10.5.4 Testing xmas tree valves 122 10.5.5 Example of valve failure matrix 123 10.5.6 Valve removal plugs 123 10.5.7 Xmas tree and wellhead instrumentation and accessories 123 10.5.8 Potential damage to subsea xmas trees 124 10.6 Downhole Safety Valves 126 10.6.1 Types of DHSV 126 10.6.2 Testing of DHSV 126 10.7 Testing of gas lift valves 126 10.8 Deviation control/management of change 127 10.8.1 Repairs/corrective actions 127 10.9 Operating conditions affecting well integrity 127 10.9.1 Failure of well equipment 127 10.9.2 Failure of risers/conductors 129 10.9.3 Non-well equipment that could impact on well integrity 129

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10.10 Review of degradation and life extension 129 10.11 Management of late-life wells 131 10.11.1 Shut-in well 131 10.11.2 Plugged well 132 10.11.3 Suspended (abandonment phases 1 and 2) 132 10.11.4 Review of the availability and continued use of wells 132 11 Intervention/Workover 134 11.1 Primary control of the well/active barriers 134 11.1.1 Well barriers during intervention/workover 134 11.1.2 Completion fluid as a barrier 135 11.1.3 Downhole safety valve as a well barrier 135 11.1.4 Full bore tool strings 136 11.1.5 Long tool strings 136 11.1.6 Installation and testing of well barriers 136 11.1.7 Well control equipment/barriers 137 11.1.8 Intervention/workover well integrity matrices 138 11.2 Responsibilities for the well 140 11.2.1 Isolation from installation emergency shutdown system 140 11.3 Intervention/workover planning 141 11.3.1 Risk assessment 141 11.3.2 Well control planning 141 11.3.3 Emergency planning 142 11.3.4 Information, instruction, training and supervision 142 11.4 Intervention/workover operations 143 11.4.1 Well handover 143 11.4.2 BOP/well control panel 143 11.4.3 BOP installation and testing 143 11.4.4 Removing xmas tree 144 11.4.5 In-situ tubing repairs 144 11.4.6 Recovery of equipment from well 145 11.5 Wireline operations 145 11.6 Coiled tubing operations 145 11.6.1 Coiled tubing pressure control equipment 145 11.6.2 Annulus barriers 146 11.6.3 Inner barriers 146 11.6.4 Coiled tubing life cycle 146 11.7 Fluid pumping operations and stimulation 147 11.7.1 General Considerations 147 11.7.2 Stimulation Operations 148

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12 Abandonment

150

13 Special cases 13.1 Multi-Lateral and Multi-Branched Wells 13.1.1 Junction Integrity

151 151 151

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13.2

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13.1.2 Well Control 13.1.3 Multi-Lateral Abandonment Cuttings re-injection/disposal wells (offshore only)

151 152 152

Appendix 1 – Background to these guidelines

153

Appendix 2 – Divestment Information

155

Abbreviations and Glossary

157

References and useful reading

162

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1 Summary All duty holders shall comply with their duties under all relevant regulations. These guidelines will help but are not a substitute for a full understanding of the regulations. The most important role of the well-operator is to ensure the integrity of its wells, barriers and the pressure containment boundary throughout the well life cycle from design to final abandonment. The well-operator should have a policy defining its commitments and obligations to safeguard health, environment, assets and reputation by establishing and preserving well integrity. This well integrity policy should be endorsed at a senior level within the well-operator’s organisation. The well-operator’s system for managing well integrity should clearly indicate how the policy is interpreted and applied to well integrity. As a minimum, the system for managing well integrity should cover: • • • • • • • • •

Accountability and responsibility Well design and construction Well operations/production including Well monitoring and reporting Tubing/annulus programme Wellhead/tree maintenance and testing Safety valve maintenance and testing Well interventions Well plugging and abandonment and suspension of operations

Integrity can be assured by keeping adequate barriers between the hazards in the well and the surface. The selection, installation, monitoring, checking, testing, maintenance and repair of barriers are the most important aspects of well planning and operations. There should be at least two well barriers available throughout the well life cycle. For overbalanced drilling, primary control of the well is maintained by an active barrier (hole full of the correct weight fluid), backed up by Blowout Preventer (BOP) equipment. Barriers should be explicitly described in procedures and plans. The description may be a schematic, a matrix (in these guidelines) or descriptive text. Operations reports should explicitly describe the installation and testing of barriers. The removal, or degradation, of a well barrier should be carefully considered to ensure that well integrity risks remain as low as reasonably practicable (ALARP) [Ref 16]. A cemented shoe track is not a barrier unless it is specifically designed to be one and proven by adequate testing. All well designs should start with an assessment of the potential hazards that may be encountered throughout the entire lifecycle of the well. The design should ensure the risks are ALARP. The well should be designed for all anticipated uses. The hazards should be reviewed throughout the life cycle of the well and any significant changes should be assessed.

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The well-operator is responsible for assessing the well risks and reducing them to ALARP. This should be demonstrated to the offshore installation duty holder who has primary responsibility for the safety of the installation and the personnel on board. All wells should be designed to facilitate plugging, suspension of operations and abandonment. Extra care is needed during well testing and completion stages as the reservoir is open and hydrocarbons are brought to the surface. Well-operators should have a system for ensuring well integrity throughout the life cycle. Management of operations may be devolved but the responsibility for the integrity of the well remains with the welloperator. Well-operators should have a Management of Change (MoC) procedure covering wells and well operations throughout the full life cycle from initial design to final abandonment, supported by a suitable and sufficient risk assessment. Duty holders should provide an effective management system and ensure that personnel are competent in the tasks they are required to do. A vital part of the competence is the ability to recognise significant changes and to ensure programmes are modified to deal with these changes. The ‘human element’ is very important in all aspects of well integrity. Further information can be found in the Oil & Gas UK Guidelines on competency of wells personnel [Ref 30].

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2 Key Regulatory Requirements for Well Integrity All duty holders must comply with their legal obligations in terms of all relevant legislation. These guidelines are intended to help duty holders meet their legal obligations regarding well integrity but are not a substitute for understanding and complying with the relevant legislation. Well-operators should satisfy themselves (including through effective audits where required) that their procedures and processes for complying with all relevant legislation are effective. Key regulations that apply to oil and gas wells in Great Britain include: The Offshore Installations and Wells (Design and Construction, etc) Regulations 1996, as amended, hereafter referred to as DCR [Ref 1] which apply to all oil and gas related wells both onshore and offshore; The Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015 hereafter referred to as SCR 2015 [Ref 3] which apply offshore in external waters of UK territorial waters and the UK Continental Shelf. The Offshore Installations (Safety Case) Regulations 2005 hereafter referred to as SCR 05 [Ref 5] which apply offshore in UK internal waters; and The Borehole Sites and Operations Regulations 1995 hereafter referred to as BSOR [Ref 11] which only apply onshore.

2.1

The DCR definition of well-operator The "well-operator”, in relation to a well, in Great Britain (i.e. wells on land or in internal waters) means the person appointed by the licensee for a well to execute the function of organising and supervising all operations to be carried out by means of such well or, where no such person has been appointed, the licensee; and in relation to a well situated or to be situated in external waters, has the meaning given by regulation 2 of the Offshore Petroleum Licensing (Offshore Safety Directive) Regulations 2015 (Licensing Regulations). Regulation 2, DCR (as amended).

The “well-operator” (in external waters) in relation to a well or a proposed well means a person appointed in accordance with regulation 5 or 6 to conduct the planning or execution of well operations. Regulation 2, The Offshore Petroleum Licensing (Offshore Safety Directive) Regulations 2015 [Ref 4]

Regulations 5 and 6 of Licensing Regulations set the requirements for appointing the well-operator and stipulate in effect that the OGA must be given three months written notice of the proposed appointment. The well-operator may then be appointed if OGA advises in writing of no objection, or after three months if OGA has not objected in writing. These regulations define a well-operator as the person appointed by the licensee to organise and supervise operations associated with the well. The licensee is usually a consortium of oil companies, granted a licence by OGA and they usually appoint from amongst themselves the operator to operate

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the licence and exploit the field and who in most cases, will also be the well-operator. They may also choose to appoint another party as well-operator. The license operator and well-operator must be approved by the OGA. The well-operator will have control of the organisation and supervision of well operations. A contractor would have to be provided with all the information necessary to discharge the duty of well-operator and achieve the safe design, construction, maintenance, operation and eventual abandonment of the well.

2.2

DCR – general duty for well-operators The well-operator shall ensure that a well is so designed, modified, commissioned, constructed, equipped, operated, maintained, suspended and abandoned that – a) so far as is reasonably practicable, there can be no unplanned escape of fluids from the well; and b) risks to health and safety of persons from it or anything in it, or in strata to which it is connected, are as low as is reasonably practicable. Regulation 13, DCR.

In these guidelines, well integrity is the application of people, equipment and processes to comply with this general duty throughout the well life cycle. The well-operator should ensure the safe condition of the well at all stages in its life. The focus overall should be on the safe physical condition of the well rather than the actual operation being carried out on the well. These guidelines concentrate on maintaining physical barriers between the well (and any hazards it may contain) and both the surface and, other than intended production or injection intervals, the subsurface throughout the well life cycle.

2.3

DCR – specific duties for well-operators Regulation 14 – Assessment of conditions below ground 1) Before the design of a well is commenced the well-operator shall cause – a) the geological strata and formations, and fluids within them, through which it may pass; and b) any hazards which such strata and formations may contain, to be assessed. 2) the well-operator shall ensure that account is taken of the assessment required by paragraph (1) when the well is being designed and constructed. 3) the well-operator shall ensure that while an operation (including the drilling of a well) is carried out in relation to the well, those matters described in sub-paragraphs (a) and (b) of paragraph (1) shall, so far as is reasonably practicable, be kept under review and that, if any change is observed in those matters, such modification is made where appropriate, to – a) The design and construction of the well; or b) Any procedures,

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as are necessary to ensure that the purposes described in regulation 13 (1) will continue to be fulfilled. These issues are covered in the following sections of these guidelines: • • •

2.3.1

Section 5 (Well Design and Operations Planning); (Section 5.2.1 Assessment of subsurface conditions) Section 6: (Drilling) Section 10 (Operate and Maintain)

Regulation 15 – Design with a view to suspension & abandonment The well-operator shall ensure that a well is so designed and constructed that, so far as is reasonably practicable – a) b)

it can be suspended and abandoned in a safe manner, and after its suspension and abandonment there can be no unplanned escape of fluids from it or from the reservoir to which it led.

This is covered in Section 5.9 (Well design/planning; Design for suspension of operations, plugging and abandonment) and Sections 10.11 and 12 which reference the Oil & Gas UK Well Decommissioning Guidelines. [Ref 24]

2.3.2

Regulation 16 – Materials The well-operator shall ensure that every part of a well is composed of material which is suitable for achieving the purposes described in regulation 13 (1). This is covered in Section 5 and 5.6 (Well design, operations planning and materials for wells) and Oil & Gas UK Guidelines on qualification of materials for the abandonment of wells. [Ref 25]

2.3.3

Regulation 17 – Well Control 1)Before an operation in relation to a well (including the drilling of a well) is begun elsewhere than at a borehole site to which the Borehole Sites and Operations Regulations 1995 apply, the well-operator shall ensure that suitable well control equipment is provided for use during such operations to protect against blowouts. Well control equipment includes equipment whose primary purpose is to prevent, control or divert the flow of fluids from the well. As such, well control equipment includes blowout preventers, downhole preventers, Christmas trees, wireline lubricators and stuffing boxes, rotating heads, tubing injection heads, circulating heads, internal blowout preventers and kelly cocks, choke and kill lines, choke manifolds and diverters. Plugs and other isolating devices installed in a borehole to prevent the well from flowing are also included; Paragraph 34, DCR guidance [Ref 2]

Well-operators can make sure they are discharging their duty for ensuring the provision of well control equipment under this regulation, by reviewing the contractor’s arrangements. This means taking

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reasonable steps to make sure that the contractor has the equipment specified for well control (e.g. checking that the necessary equipment is available at the site, asking the contractor providing equipment to produce evidence that the equipment to be provided is what is needed and is suitable for conditions in the well). If necessary, the well-operator should check that the contractor has suitable policies, procedures and management controls to ensure suitable equipment is supplied; Paragraph 35, DCR guidance [Ref 2]

2) In the case of an operation to which paragraph (1) applies which is begun – a) b)

from an installation, the duty holder; and otherwise than from an installation, the well-operator,

shall ensure that equipment provided pursuant to paragraph (1) is deployed when the prevailing well and operational conditions so require. The requirement for deploying the well control equipment of the well is placed on the duty holder for the installation (who has primary responsibility for the safety of the installation). In instances where the well operations are to be conducted from a vessel not defined as an offshore installation, the duty is placed on the well-operator. In the latter case, well-operators can discharge their duty by checking that the specialist contractor carrying out the operations has suitable policies, procedures and management controls for the installation, testing and use of the specified well control equipment. A similar approach may be used by the installation duty holder for equipment supplied and operated from an installation by third parties. Paragraph 36, DCR guidance [Ref 2]

“Deployment” of well control equipment covers the installation and use of the equipment on the well. Paragraph 37, DCR guidance [Ref 2]

Well control equipment should be deployed on all wells where there is a risk of release of flammable, explosive or toxic fluids or gases from the well. It should also be deployed where there is a risk of highpressure water flow. Paragraph 38, DCR guidance [Ref 2]

These issues are covered in Sections 4, 5, 7, 8, 10 and 11. For onshore activity the well control requirements are covered by the BSOR (Schedule 2(7)) [Ref 11 and 12]

2.3.4

Regulation 18 – Arrangements for examination Regulation 18 of DCR applies only to wells in UK internal waters and to landward wells. Regulation 11 of SCR 2015 (Establishment of well examination schemes), Regulation 12 of SCR 2015 (Other provision as to well examination schemes) and Schedule 4, Part 2 (Matters to be provided for in a well examination scheme) apply to wells in external waters. Well examination is covered in the following Oil & Gas UK guidelines:

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Guidelines for well-operators on well examination [Ref 26] Guidelines for well-operators on competency of well-examiners [Ref 27].

2.3.5

Regulation 19 – Provision of drilling etc information 1) Where an operation to which this paragraph applies is being carried out on a well the well-operator shall cause to be sent to the [Health and Safety] Executive, at such intervals as may be agreed or, failing agreement, at intervals of one week calculated from its commencement, a report comprising the following information – a) b) c)

the identifying number, and any slot number, of the well; the name of any installation or vessel involved; a summary of the activity in the course of the operation since its commencement, or the previous report; d) the diameter and true vertical and measured depths of – i. any hole drilled; and ii. any casing installed;

e)

the drilling fluid density immediately before making the report; and

f)

in the case of an existing well, its current operational state.

2) Paragraph (1) applies to – a) b) c) d) e)

2.3.6

a drilling operation; a workover operation; an abandonment operation; an operation consisting of the completion of a well; any other operation of a kind involving substantial risk of the unplanned escape of fluids from a well.

Regulation 21 – Information, instruction, training and supervision This is covered in the Oil & Gas UK Guidelines on competency for wells personnel [Ref 30].

2.4 2.4.1

Duties of the well-operator under SCR 2015 Regulation 11 – Establishment of well examination scheme Well examination is covered in the following Oil & Gas UK guidelines: Guidelines for well-operators on well examination [Ref 26].

2.4.2

Regulation 12 – Other Provisions as to well examination schemes Well examination is covered in the following Oil & Gas UK guidelines: Guidelines for well-operators on well examination [Ref 26].

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Guidelines for well-operators on competency of well-examiners [Ref 27].

2.4.3

Regulation 13 – Description of well examination See Guidelines for well-operators on well examination [Ref 26].

2.4.4

Schedule 4, Part 2 – Matters to be provided for in a well examination scheme See Guidelines for well-operators on well examination [Ref 26].

2.4.5

Regulation 21 – Notification of well operations 1) The well-operator must ensure that no well operation is commenced from a production installation in external waters unless – a)

in the case of a well operation that does not involve drilling, but involves: i. insertion of a hollow pipe in a well; or ii. altering the construction of a well,

the well-operator has sent a notification containing the particulars specified in Schedule 9 to the competent authority at least 10 days (or such shorter period as the competent authority may specify) before commencing that operation; or b)

in any other case, the well-operator has sent a notification containing the particulars specified in Schedule 9 to the competent authority at least 21 days (or such shorter period as the competent authority may specify) before commencing that operation.

2) The well-operator must ensure that no well operation is commenced in external waters (other than a well operation falling within paragraph (1)) unless the well-operator has sent a notification containing the particulars specified in Schedule 9 to the competent authority at least 21 days (or such shorter period as the competent authority may specify) before commencing that operation. 3) The well-operator must include with the notification sent to the competent authority a statement, made after considering reports by the well examiner under 11(2)(b), that the risk management relating to well design and its barriers to loss of control are suitable for all anticipated conditions and circumstances. 4) Where the well-operator plans or prepares a material change to any of the particulars notified pursuant to paragraph (1) or (2) the well-operator must consult the well examiner under the well examination scheme about the planned or prepared material change. 5) Where there is a material change in any of the particulars notified pursuant to paragraph (1) or (2) prior to completion of the relevant well operation, the well-operator must notify the competent authority as soon as practicable. 6) A notification of a material change under paragraph (5) must contain sufficient details fully to update the previously submitted notification and be accompanied by the report of the well examiner following the consultation under paragraph (4), addressing in particular the matters in paragraph 6(c) to (e) of

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Schedule 9. (These matters are: barriers against loss of well control, directional control of the well path and limitations on safe operation.) 7) The well-operator must not commence a well operation (of any description) where the competent authority expresses objections to the content of the notification sent in respect of a well notification or to any of the change to that content notified to the competent authority pursuant to paragraph 5. (i.e. a material change). Schedule 9 requires the name and address of the well-operator to be stated to the Offshore Safety Directive Regulator. This is the formal notification to the relevant Competent Authority that the named company is the well-operator under SCR 2015 and DCR for the operations described on that well. Stand-alone wireline interventions on a production installation are deemed to be well operations. To avoid unnecessary bureaucracy, routine wireline notifications or other operations that do not involve drilling, inserting hollow pipe through the well head or alter the well should be covered by a single generic one-off notification for the installation. Details of major hazard controls should be included in the installation safety case. Where wireline activity is required to alter the well construction, this is notifiable each time. Any change to the existing barriers that will remain in place at the conclusion of the activity are likely to be regarded as ‘altering’ the well construction. Inserting hollow pipe includes inserting coiled tubing. Paragraphs 256 to 258, SCR 2015.

Refer to HSE website for the publications Understanding Offshore Oil and Gas Notifications (2017/329870) [Ref 18]. and Understanding Onshore Oil and Gas Notifications [Ref 19]

2.5 2.5.1

Installation safety case duty holders Definition of Duty holder “duty holder” means – a) b)

in relation to a production installation, the operator; and in relation to a non-production installation, the owner;

Regulation 2, SCR 2015.

The expression “duty holder” is used in these Regulations to refer to the person (whether the owner or the operator of an installation) on whom duties are placed by SCR 2015 in respect of installations, particularly to prepare the safety case. It does not mean that these are the only people with duties under health and safety law. Paragraph 67, SCR 2015 guidance.

“operator” means, in relation to a production installation, an “installation operator” as defined in regulation 2(1) of the Offshore Petroleum Licensing (offshore Safety Directive) Regulations 2015; “owner” means the person who controls or is entitled to control the operation of a non-production installation;

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Regulation 2, SCR 2015.

The owner of a non-production installation is also a main duty holder under SCR 2015. The owner is the person who contracts with the licensee/-field operator to use the installation for oil- and gas-related activity and is in direct operational control of that activity. This may not be the owner in the ordinary financial sense. The term does not refer to the operator (who contracts with the owner) or to the installation manager, who is appointed by the owner. Paragraph 83, SCR 2015.

2.5.2

SCR 2015 Regulation 16 Management & Control of Major Accident Hazards (1) A duty holder who prepares a safety case pursuant to these Regulations must, subject to paragraph (2), include in the safety case sufficient particulars to demonstrate that— (a) the duty holder’s management system is adequate to ensure— (i) (ii)

that the relevant statutory provisions will, in respect of matters within the duty holder’s control, be complied with; and that the management of arrangements with contractors and sub-contractors is satisfactory;

(b) the duty holder has established adequate arrangements for audit and for the making of reports of the audit; (c) all hazards with the potential to cause a major accident have been identified; (d) all major accident risks have been evaluated, their likelihood and consequences assessed, including any environmental, meteorological and seabed limitations on safe operations, and that suitable measures, including the selection and deployment of associated safety and environmental-critical elements have been, or will be, taken to control those risks to ensure that the relevant statutory provisions will be complied with; and (e) in the case of a non-production installation, all the major hazards have been identified for all operations the installation is capable of performing. Demonstrations should include evidence to show: That hazards with the potential to cause a major accident have been identified and that risks arising from those hazards are or will be adequately controlled. The evidence should show that reasoned arguments have been used to make professional judgements about the nature, likelihood and consequences of potential major accident events that may occur, and the means to prevent these events or minimise their consequences should they occur. The evidence should also show that the dutyholder’s risk acceptance criteria are appropriate. Paragraph 210c SCR 2015 guidance

Duty holders will typically utilise several key process safety techniques to identify, manage and mitigate major accident hazards and satisfy regulation 16. These may include HAZID, HAZOP, LOPA and the principle of inherent safety in design.

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2.5.3

Other duties of installation safety case duty holders Under Regulations 17 and 18 of SCR 2015, duty holders shall prepare a safety case for the installation and put in place a Safety and Environmental Management System (SEMS) for that installation. The Well-Operator’s Safety and Environmental Management System should be submitted with the Well Notification where it has not already been submitted under Regulations 17 and 18 of SCR. For a production installation (which by definition in Management and Administration (MAR) guidance [Ref 7] includes all bridge-linked platforms, and platforms and subsea wells that are connected to that platform) the duty holder is the installation operator. The ‘installation operator’ means a person appointed in accordance with regulation 5 or 6 (of the Licensing Regulations) to conduct any offshore petroleum operations, other than the planning or execution of any well operations. The requirements for appointing the installation operator (i.e. notifying OGA three months in advance etc.) are the same as for appointing a well-operator. See paragraphs 83–84 SCR 2015 guidance [Ref 6]. If a modular rig is installed on a production installation, the operations should be covered in the safety case. If these modular rig operations were not included in the original safety case, this is classed as a ‘material change’, see Regulation 24(2), SCR 2015. The duty holder for a non-production installation (including mobile drilling rigs) is the ‘owner’. The owner means the person who controls the operation of a non-production installation, see paragraphs 83 and 75 SCR 2015 guidance [Ref 6].

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2.6

Offshore environmental protection regulations Full Title

Requirements

Offshore Petroleum Production and Pipelines (Assessment of Environmental Effects) Regulations 1999 (as amended)

Environmental Statement (ES) or Application for a Direction from the SoS (PETS DRA DR) for drilling operations

The Offshore Petroleum Activities (Conservation of Habitats) Regulations 2001 (as amended)

Habitats Regulations Assessments for well operations in protected European sites (HRA)

Offshore Chemicals Regulations 2002 (as amended)

Use and Discharge Permit for all offshore chemicals (PETS DRA CP and WIA CP) for well operations involving use and discharge of offshore chemicals

Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (as amended)

Oil Discharge Permits (PETS DRA OTP and WIA OTP) for well operations involving discharge of oils

CtL

Energy Act 2008, Part 4A Consent to Locate

Navigational Consent to Locate (CtL) for all well operations undertaken by Mobile Drilling Units

OPRC

Merchant Shipping (Oil Pollution Preparedness, Response Co-operation Convention) Regulations 1998 (as amended)

Oil Pollution Emergency Plans (OPEPs) for all well operations

Offshore Installations (Emergency Pollution Control) Regulations 2002

Involvement of SOSREP (supplementary provisions covered in OPEPs)

Offshore Petroleum Licensing (Offshore Safety Directive) Regulations 2015

Demonstration or Declaration of Financial Liability Arrangements (FLA) for all well operations

EIA [Ref 93]

HRA

OCR [Ref 91]

OPPC [Ref 92]

[Ref 90] EPC [Ref 94]

FLA

Table 1. Principle Environmental Protection Regulations Applicable to Offshore Well Operations

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Duty holders are not recognised in the environmental legislation, but the term covers Installation Operators and Well-Operators appointed under the Offshore Petroleum Licensing (Offshore Safety Directive) Regulations 2015. For well operations the Well-Operator is responsible for complying with the environmental regulations, although the OPEP and FLA provisions may be underwritten by the licensee(s), and the Well-Operator should understand and comply with all the requirements of the regulations relevant to wells and well operations. Further information and guidelines in relation to the legislative requirements relevant to the environmental legislation can be found on the GOV.UK and Offshore Safety Regulator websites at https://www.gov.uk/guidance/oil-and-gas-offshore-environmental-legislation and http://www.hse.gov.uk/osdr/index.htm respectively. Following these guidelines should help the well-operator comply with the: • •

OPPC Regulation 3A on the prohibition to release any oil. OCR Regulation 3A on the prohibition to release an offshore chemical.

The guidelines will also help well-operators develop relief well planning for OPEPs.

2.7

Borehole Sites and Operations Regulations 1995 (BSOR) BSOR [Ref 11] apply onshore.

2.7.1

Regulation 7 – The health and safety document 1) No borehole operation shall be commenced at a borehole site unless the operator has ensured that a document (in these Regulations referred to as “the health and safety document”) has been prepared, which – a)

b)

c)

demonstrates that the risks to which persons at the borehole site are exposed whilst they are at work have been assessed in accordance with regulation 3 of the Management Regulations; demonstrates that adequate measures, including measures concerning the design, use and maintenance of the borehole site and of its plant, will be taken to safeguard the health and safety of the persons at work at the borehole site; and includes a statement of how the measures referred to in sub-paragraph (b) will be coordinated.

2) In addition to the matters referred to in paragraph (1), the health and safety document shall also include where appropriate – a)

b)

an escape plan with a view to providing employees with adequate opportunities for leaving work places promptly and safely in the event of danger and an associated rescue plan with a view to providing assistance where necessary; a plan for the prevention of fire and explosions including in particular provisions for preventing blowouts and any uncontrolled escape of flammable gases and for detecting the presence of flammable atmospheres;

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c) d)

2.7.2

a fire protection plan detailing the likely sources of fire and the precautions to be taken to protect against, detect and combat the outbreak and spread of fire; and in the case of a borehole site where hydrogen sulphide or other harmful gases are or may be present, a plan for the detection and control of such gases and for the protection of employees from them.

Regulation 6 – Notice of the commencement of drilling operations and the abandonment of boreholes In the case of petroleum, the operator of a borehole site shall ensure that no drilling operation, abandonment operation or other operation on a well which would make a significant alteration to it, or involve a risk of the accidental release of fluids from the well or reservoir, is commenced at that site unless he has notified to the [Health and Safety] Executive the particulars specified in Part I of Schedule 1 at least 21 days in advance, or such shorter time in advance as the [Health and Safety] Executive may agree. 2) The operator of a borehole site or, in the case of particulars previously notified under paragraph (3), the person entitled to drill the borehole shall ensure that the [Health and Safety] Executive is notified as soon as reasonably practicable of any material change of circumstances which would affect particulars previously notified under paragraph (1), (2), (3) or (4).

2.8 2.8.1

Other relevant Onshore Regulatory Considerations Onshore Environmental Regulation There are some circumstances where the Competent Authority for regulation of wells falls to the Environment Agency or, in Scotland, SEPA. These include: 1.

2. 3.

Where there is a credible source-pathway-receptor (SPR) linkage to an environmental receptor (e.g. a loss of well integrity adjacent to a groundwater-bearing formation such as the Sherwood Sandstone), or; After well abandonment, where EA or SEPA are responsible for ensuring the environment is protected “in perpetuity”, or; Where there is a relevant Best Available Techniques conclusion under the Environmental Permitting Regulations 2016 [Ref 141] or IED Regulations, following these guidelines will generally provide a demonstration that BAT have been applied

Wherever potential implications for groundwater or the environment are identified, such as cross-flow, the well-operator should seek advice from a groundwater specialist and discuss the situation with their local EA (or SEPA) Area hydrogeologist.

2.8.2

Coal Authority Where wells intended for hydrocarbon extraction exist within mining areas within the UK additional considerations related to mining activities may be required. The Coal Authority should be contacted for further information.

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2.9

Control of Major Accident Hazard Regulations (COMAH), 2015 COMAH cover gas storage sites including the associated wells, and certain land well sites. Operators should consult the regulations directly [Ref 20].

2.10 2.10.1

Management of Health and Safety at Work Regulations 1999 Regulation 5 – Health and safety arrangements 1) Every employer shall make and give effect to such arrangements as are appropriate, having regard to the nature of his activities and the size of his undertaking, for the effective planning, organisation, control, monitoring and review of the preventive and protective measures. Employers should ensure that they have a plan to make adequate routine inspections and checks to ensure that the preventative and protective measures that they identified are in place and effective. Employers have a responsibility to adequately investigate incidents and accidents (HSWA). The results of these investigations should be shared across their organisation in a timely manner (Maitland Panel Report, page 45) [Ref 127]. The investigation should try to identify underlying trends by comparison with other incidents, both company and industry wide. Employers should consider publicising the investigation results more widely throughout industry, if it is legally appropriate to do so. This could be done by issuing a safety alert, by discussion at industry forums (e.g. the Oil & Gas UK Wells Forum or Well Services Contractor Forum, or via the International Association of Drilling Contractors (IADC), or other industry forums) or by presenting the results in a technical paper.

2.11

The Reporting of Injuries, Diseases and Dangerous Occurrences Regulations (RIDDOR) 2013 Reporting regulations are applicable both onshore and offshore however the reporting requirements are different for onshore and offshore incidents and dangerous occurrences. Onshore incidents require reporting via an online report form. [Ref 23a] Offshore incidents and dangerous occurrences should be reported via the ROGI form. The ROGI form replaces HSE forms OIR8, OIR9b and OIR 12, which have been withdrawn. The form can be found at: http://www.hse.gov.uk/osdr/reporting/incidents-to-osdr.htm [Ref 23b] The following five types of dangerous occurrence must be reported (the wording of each of the five types of event has been extended to include the guidance provided in the official version, and that provided by HSE inspectors for wells): •

A blowout (i.e. an uncontrolled flow of fluids from a well) which is to include events of a limited duration.

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•

• •

•

The coming into operation of a blowout prevention or diverter system to control flow from a well, where normal control procedures fail. This includes 'underground blowouts', where the well fluids flow to subsurface rock formations rather than to the surface. Reports are not required where flow is due solely to variations in the density of fluid across pipe installed in the wellbore, an effect commonly known as ‘U-tubing’, nor where it is known that mud previously lost to the formation is subsequently returned, an effect commonly known as ‘ballooning’ or ‘breathing’. When Hydrogen Sulphide (H2S) is detected during operations or in samples of well fluids (this is not applicable to development wells exploiting reservoirs with a known H2S content). When precautions, in addition to those contained in the original drilling programme, must be taken following failure to maintain planned minimum separation between wells drilled directionally from an installation. ‘Near misses’ should also be reported if normal drilling operations have to be interrupted for remedial action to reduce the risk of collision. The mechanical failure of any Safety and Environmental Critical Element (SECE) of a well (and for this purpose the SECE of a well is any part of a well whose failure would cause or contribute to, or whose purpose is to prevent or limit the effect of, the unintentional release of fluids from a well or a reservoir being drawn on by a well). Failures of the primary pressure containment envelope of a well, or of safety devices, namely BOPs, or surface, subsea and subsurface safety valves, should be reported where there is a major loss of pressure integrity requiring immediate remedial action. It is not necessary to report minor leaks or failures found and rectified during routine maintenance, including replacement of worn components. Significant leakages around a well of hydrocarbon gas from shallow formations should also be reported.

In respect to the latter point, for failures occurring in completed wells, the following guiding principles should be followed: • •

2.12

Not all mechanical failures are reportable No distinction is made between hydrocarbon or water service wells

The Petroleum Act 1998 (as amended by the Infrastructure Act 2015) The Petroleum Act 1998, as amended by the Infrastructure Act 2015, places a duty of the Secretary of State to produce one or more strategies for enabling the Principal Objective of “maximising the economic recovery of UK petroleum to be met”. This is the first MER UK Strategy and came into force on March 18th, 2016. [Ref 137] The Energy Act established the OGA as a Government Company and equipped the body with additional powers to maximise economic recovery of oil and gas from beneath UK waters. These powers give the OGA the ability to issue enforcement notices and financial penalties, and to revoke licences for clear or persistent breaches of the MER UK Strategy. Therefore, the MER UK Strategy should be read as a legal document containing obligations with which those bound by it are required to comply. The Strategy is binding on the OGA, petroleum licence holders, operators appointed under those licences, the owners of upstream petroleum infrastructure, and those planning and carrying out the commissioning of upstream petroleum infrastructure.

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3 Process Safety and the Well Integrity Management System 3.1

Process Safety IOGP have issued 3 reports that are relevant to process safety in wells: IOGP 415: Asset integrity – the key to managing major incident risks. [Ref 138] IOGP 456: Process safety recommended practice of key performance indicators. [Ref 139] IOGP 556: Process safety - leading performance indicators. [Ref 140] “Process safety is a disciplined framework for managing the integrity of operating systems and processes handling hazardous substances. It is achieved by applying good design principles, engineering, and operating and maintenance practices. It deals with the prevention and control of events that have the potential to release hazardous materials and energy. Such incidents can result in toxic exposures, fires or explosions, and could ultimately result in serious incidents including fatalities, injuries, property damage, lost production or environmental damage” IOGP 456: Process safety recommended practice of key performance indicators [Ref 139]

The disciplined framework referred to above, with regards to wells, is the Well Integrity Management System (WIMS). The primary objective of a WIMS is to prevent the loss of containment of hydrocarbons from the wellbore throughout all stages of the life of the well. Therefore, the principles of process safety as applied to wells are to have: • • •

a systematic approach to establishing well barriers a clear process for maintaining well barriers a robust method of verifying the barrier condition and effectiveness

In well operations a significant number of process safety practices and procedures depend on human actions and behaviours, reacting to changing well conditions. Well-operators should refer to “Guidelines on competency of wells personnel, Issue 2, August 2017” [Ref 30]. In the Operate and Maintain phase of the well life cycle (section 10) it is equally important that the relevant production personnel are competent in well integrity matters. Step Change in Safety have developed useful material related to understanding and learning from human factors in recent incidents. Refer to “Human Factors First Steps [Ref 37] and Human Factors Toolkit [Ref 38].

3.2

Well Integrity Management System The well-operator should have a policy defining its commitments and obligations to safeguard health, environment, assets and reputation by establishing and preserving well integrity. This well integrity policy should be endorsed at a senior level within the well-operator organisation. An effective Well Integrity Management System is integral to the whole life of a well from design to final abandonment.

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Figure 1. Typical Activities in the Well Lifecycle Addressed by a Well Integrity Management System An effective Well Integrity Management System should be designed to ensure all well activities are performed to minimise risk under ALARP principles, as illustrated in Figure 1. The Well-Operator’s Well Integrity Management System should clearly indicate how the policy is interpreted and applied to well integrity. Within the Well Integrity Management System, the following elements should be addressed as a minimum: • • • • • • • • • • • • • • • • • • •

Well integrity policy and strategy Resources, roles, responsibilities, competencies and authority levels Risk assessment aspects of well integrity management Well examination and verification requirements Well design and barriers Well component performance standards Definition of well operating limits Well monitoring and surveillance requirements Annulus pressure management Requirements to monitor the effects of aging and degradation of barriers Well integrity failure management Requirements and schedule for performing well stock performance reviews Well handover requirements Documents required during the well life cycle (see Appendix 2) Duration of retaining well records (see below) Management of change processes Typical activities in the well lifecycle captured by a WIMS include: Construction and verification of barriers Recording of non-conformances

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• • • • •

Anomaly identification, reporting and management Compliance auditing and monitoring the performance of the well integrity management systems Well maintenance Assessment of replacement or downrating of barriers Investigating, learning & continuous improvement

The well-operator should have complete and accurate records for all wells. The well-operator should have a policy on the retention of well records. As part of the Well Examination scheme, details and sufficient records should be kept to form an auditable trail showing what work has been done, its findings, any recommendations made, and any work carried out as a result. DCR specifies keeping records for a period of six months after the relevant scheme ceases to be current (for example, after the well has been abandoned). Earlier records pertinent to a new scheme should be retained for as long as they are relevant. All wells, including suspended wells, should have a defined monitoring and maintenance strategy, with clear responsibility and accountability, to give continuous well integrity assurance until the final well decommissioning. The well-operator should develop a scheme for the transfer of well records in the event of asset transfers etc. See Appendix 2 - Divestment Information.

3.3

Process Safety Key Performance Indicators To manage process safety, the well-operator should develop an auditable system for measuring and recording the robustness of its equipment, procedures, well designs, people and safety leadership. IOGP Report 456: Process safety recommended practice of key performance indicators [Ref 139] recommends a 4-tier framework for process safety KPIs. Level T3 and T4 KPIs are primarily intended for monitoring and review of barriers, especially at the operational level. They should comprise a mix of “leading” and “lagging” indicators for each topic area, as further developed in IOGP Report 556: Process safety - leading performance indicators. [Ref 140] Table 2 gives some examples of process safety barriers related to well integrity and the corresponding leading and lagging indicators of barrier performance. Well-operators may choose from these examples and/or may develop other KPIs suitable to their well stock and well operations activities.

Barrier

Competence of personnel in well integrity-critical roles*

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Example Lagging KPI (Tier 3) Example Leading KPI (Tier 4) •

Number of personnel whose training is overdue.

• •

% personnel assessed to be competent. % of well kick kill drills completed per plan

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• Well Design & Procedures

• • •

Safety & Environmentally Critical Equipment

• •

•

Number of kicks incurred (without LOPC). Number of spills recorded (from LOPC). Numbers of well stock with integrity issues. Number of failures of well control equipment under routine testing. Number of non-routine and emergency maintenance work orders. Number of overdue critical maintenance routines.

Number of overdue action items from audits & visits.

Safety Leadership

• •

• • •

•

•

% well barriers installed without issue, per plan. Annual review of well integrity completed on schedule. % of well control equipment tests completed on schedule % maintenance of equipment completed on schedule % of planned preventative maintenance versus total maintenance (including unplanned). % Management visits to wellsite completed per schedule and actions tracked to closure. % Audits completed per schedule and actions tracked to closure.

LOPC = Loss of Primary Containment * See Ref 30 – Guidelines on competency of wells personnel

Table 2. Example well integrity-related process safety KPIs

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4 Well Integrity, Barriers, BOPs and Well Control Loss of containment from a well can be determined as a Major Accident Hazard (MAH) in terms of a threat to the safety of the installation or personnel on it and a Major Environmental Hazard (MEH) in terms of a threat to the environment. The guidance to DCR in Section 2 states that the well is defined in terms of its pressure containment boundary. This concept is used in these guidelines. Maintaining the pressure containment boundary should ensure well integrity throughout the life cycle. The most important role of the well-operator’s representative on the rig (e.g. drilling supervisor or well services supervisor) is to ensure the integrity of the well.

4.1

Well pressure containment boundary A pressure containment boundary can be described as the safety and environmentally critical equipment whose failure could cause, or contribute substantially to, or whose purpose is to prevent or limit the effect of, a major accident. The pressure containment boundary equipment includes downhole pressure-containing equipment (e.g. casing, cement, production packer) as well as pressure containing equipment on top of the well, such as a xmas tree and wellhead or BOP, usually referred to as well control equipment. The operating limits of a pressure containment boundary are defined by the design limits as stipulated in the well basis of design, the properties of the equipment and barriers installed during construction, construction verification testing and the final reservoir conditions. Gas storage wells and water injection wells should define the maximum allowable injection pressure derived from the cap rock strength. Pressure containment boundaries are classified as primary or secondary. The classification does not imply the relative importance of one boundary over another; rather the distinction is made to convey the proximity of the pressure containment boundary to the reservoir.

4.2

Structural well integrity The Conductor and Surface Casing strings have two sets of functional requirements: one is related to structural design and one is related to well design. The full well lifecycle needs to be addressed for both sets of requirements. Multiple conductor / surface casing failures across the global offshore well-stock suggest that additional focus needs to be given to this area. Structural failure may adversely affect the well pressure containment boundary. See section 5.3.2 and 5.3.3 for further details. Any proposed changes to the well or facilities should consider the corresponding impact on the conductor and surface casing for structural and fluid/pressure retention requirements. Ongoing maintenance and monitoring should identify any fluid content changes in the annulus and any mechanical degradation which could affect the ability of the conductor / surface casing to maintain structural integrity.

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Information from monitoring routines should be used to re-assess the ability of the conductor and surface casing to sustain the anticipated loads. Also see Section 10.1.6.

4.3

Well barriers A barrier prevents unplanned movement of fluids in, from, or to the well and is part of the pressure containment boundary. The design, selection, installation, testing, checking, monitoring and maintenance of these barriers are the focus of these well integrity guidelines. The design, selection, installation, testing and checking, monitoring and maintenance of well barriers should be documented in the well design and well operating procedures. Identified well barriers are required to be verified against performance standards to ensure they remain effective in mitigating the major hazard threat. The well-operator should ensure there are sufficient and suitable barriers between the hazards in the well and the surface throughout the well life cycle.

4.3.1

Number of well barriers The well should be designed and constructed so that no single failure of a well barrier (including the formation) will ever result in an uncontrolled flow of fluids to the environment for the expected life of that well. There should be at least two well barriers available throughout the well life cycle which may be a combination of one active and, where appropriate, one potential barrier in place between the reservoir and the environment. To carry out operations with fewer than two barriers available, requires careful consideration by the well-operator to demonstrate that the risks are ALARP.

4.3.2 4.3.2.1

Type of well barriers Active versus potential barriers An ‘active’ barrier actively prevents unplanned escape of fluid from the well without being functioned, e.g.: • • • • •

Overbalanced drilling – a hole full of the correct weight fluid (providing the overbalance is maintained). Underbalanced wireline logging – the stuffing box Producing wells – the xmas tree and wellhead Managed pressure drilling – the rotating control device A known fluid level (e.g. via echo meter) where reservoir pressure conditions are known.

Active barriers always provide well pressure containment, and verification of their integrity condition is achieved by appropriate well condition monitoring which may be defined as real-time monitoring and interpretation of well data such as: tubing/casing pressures; annulus pressures; flowing and shut-in

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tubing pressures; temperature; H2S and CO2 production, and fines or solids production to assure that the well remains within its defined operating limits. Whilst drilling in gas storage reservoirs, or in reservoirs with active water injection, the reservoir pressure should be maintained under control to ensure that the active barrier (overbalanced drilling fluid) is not compromised. Potential barriers will not prevent an unplanned escape of fluids from the well until they have been functioned. Verification of their integrity condition is achieved by testing on a set frequency. For more details see Section 4.3.9. The main potential barrier during drilling is the BOP, which is open during normal operations but can be closed quickly when needed. Examples of other potential barriers are: xmas tree flow wing valve and lower master gate valve, and the downhole safety valve. Different standards and guidelines may describe barriers in different ways. For example, “primary” and “secondary.” 4.3.2.2

Well Pressure Containment Boundary Reliability The multiple redundancy provided by a combination of individual potential barriers enhances well isolation reliability. The competence of the pressure containment boundary is then not compromised by the failure of a single potential barrier.

4.3.2.3

Inner versus annulus and other flow path barriers During most phases of the well life cycle there is pipe inside pipe. Barriers need to be considered for both the inner pipe (e.g. drill string or completion) and all outer well annuli potential flow paths. In a completed well, a xmas tree valve is an inner potential barrier and a production packer is an annulus active barrier.

4.3.2.4

Permanent versus temporary barriers Permanent barriers are needed for well abandonment and are defined in the Oil & Gas UK Well Decommissioning Guidelines [Ref 24] as a “verified barrier that will maintain a permanent seal”, (e.g. a cement plug across the width of the well). All other barriers are considered temporary.

4.3.3

Shearing and barriers In some situations, there is a need for equipment in the well to be sheared to seal the well if the active barrier fails. For example: • • •

Blind shear rams (BSR) that cut drill pipe and seal the wellbore are included in drilling rig BOP stacks Casing shear rams that cut tubulars, but do not seal the well, are included in some BOPs. These need to be backed up by a separate blind ram that seals the well Some xmas trees valves may be designed to shear wireline

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•

Wireline shear seal BOPs that cut wireline and seal the wellbore may be rigged up when wireline is run through a xmas tree

For further information refer to section 4.4 BOPs and API S53 [Ref 39].

4.3.4

Describing well barriers Barriers should be explicitly described when planning and carrying out operations for all stages of the well life cycle. This is to encourage all personnel involved to think about well barriers and to recognise the significance if a barrier is not installed or tested as planned. This description may be in the form of a well integrity matrix which may be included in operations programmes or status reports. Examples for each stage of the well life cycle are included in following sections of these guidelines. Barriers may also be described with schematics and in engineering diagrams. Examples of barrier schematics may be found in Section 6.6.4 and Section 11.1.8 Further information is given in NORSOK D-010 [Ref 110]. Alternatively, the barriers may be described by text descriptions.

4.3.5

Immediacy of hazards after barrier failure The failure of an active barrier can lead to fluid flow from the well. This flow is an immediate hazard to personnel if the fluid is under pressure and/or hazardous (e.g. hydrocarbons or H2S). The immediacy of the hazard should be considered when assessing the risks during well planning and operations. The failure of an active barrier with pressured hydrocarbons (e.g. a coiled tubing stripper packer on a producing well) can cause an immediate hazard to personnel before potential barriers can be activated. By contrast if a kick is taken, there is a hazard. Often there may be time to activate potential barriers, preventing the release of hydrocarbons or fluid under pressure, if the crew is alert and responds to the kick indicators.

4.3.6

Barrier components and associated equipment A barrier may need several components to be considered a complete barrier. For example, the rig BOP has multiple components (e.g. pipe rams, chokeline valves) and associated equipment such as control systems, hydraulic power supply. It is considered a single barrier. A single point of failure (e.g. of the BOP/ wellhead connector) can negate the barrier. Where a barrier (such as a BOP) is categorised as ‘safety and environmentally-critical', because the associated equipment is needed to activate the barrier, individual components should be considered ‘safety and environmental-critical elements’ (as defined in Regulation 2, SCR 2015).

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4.3.7

Barrier selection and qualification The well design process should include the selection of adequate barriers throughout the well life cycle to ensure well integrity, and this should be explicitly described in the well planning documents and operational programmes. Part of this process may be formal qualification of barriers for equipment such as downhole safety valves (DHSV). Barrier selection is covered in Section 5 (Well Design and Operations Planning) of these guidelines.

4.3.8

Barrier installation The procedures for installing barriers during well operations should be explicitly described in all operations plans and procedures. Steps for checking that barriers are in the right place should be described in the operations procedures. There should be criteria for how to check the location of the barrier and a description of how failure (e.g. barrier not in the right place) would be indicated. Confirmation that barriers are in the correct location should be included in operations reports.

4.3.9

Testing well barriers After a well barrier is installed, it should be tested to ensure: • •

It is functioning correctly (e.g. BOP function test) It can withstand the maximum potential differential pressure by: • a pressure (positive) test (see Section 4.6 for details); • an inflow (negative) test (see Section 4.8 for details).

Barriers should be tested in the direction of flow whenever possible. If this is not possible, the welloperator should assess the probability and consequences of failure of the barrier to align with principles of ALARP [Ref 16]. Where barriers are established using equipment designed to hold pressure from both directions, such as cement plugs, or packers with a bi-directional locking mechanism and bi-directional seals (O-rings or solid seal elements), they may be considered bidirectional barriers if tested from the opposite direction to flow. Plugs dressed with chevron seals (or ‘V’ packing), or valves with separate sealing faces, should be considered uni-directional. They should be tested in the direction of flow to be considered a barrier. Test procedures should include: • •

Success/failure criteria Reaction to trends (e.g. increase in annulus pressure)

Barrier tests should be witnessed by the representative of the well-operator who is responsible for the integrity of the well.

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The results of the installation and testing of barriers should be described in operations reports (daily and final). This information should be included in reports to the well-examiner. If reporting to the HSE is required [Ref 20] by Regulation 19, DCR, it should include brief details of barrier installation and the results of tests. Records of the tests should be kept in the well files. Testing to confirm the well pressure containment envelope should be repeated, as necessary, throughout the well life cycle to ensure that the barrier is still functioning as a well barrier.

4.3.10

Maintenance and monitoring of barriers Barriers should be monitored and maintained during the life of the well. This may be described in wellspecific programmes and/or in standard operations procedures. The ability of operations personnel to recognise barrier failure, and react to it, is a very important aspect of their competency. The results of the barrier monitoring, and any required maintenance, should be communicated to the well-examiner. See Oil & Gas UK Guidelines for well-operators on well examination [Ref 26].

4.3.11

Response to degradation of barriers If barriers become degraded (not fully functional) the well-operator should have a management system for recognising and reacting to the situation. Degradation can be described as signs that there are problems with a barrier, but it has not yet definitely failed, and it should still function as a barrier. Examples of barrier degradation include: • • •

• •

4.3.12

In overbalanced drilling – severe lost circulation making it difficult to keep the hole full of mud In underbalanced wireline logging – the grease injection system fails but the flow tube is still full of grease In production – a valve that is showing a trend of increasing leak rate during testing but is still within the acceptance criteria; minor leaks in the control system for xmas tree valves indicate that activating the valve might take more time than normal In production – ingress of well fluids to control lines In production – unexplained annulus pressure

Response to failure of barriers If an active barrier fails, other potential barriers should be activated at once to seal the well. For some situations, immediate repair of a barrier should be carried out, or operations on the well should stop until the barrier is reinstated. For other situations, mitigation may be possible before the barrier is reinstated. There should be a defined timescale for delayed repair of barriers.

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The well-operator should carry out a specific risk assessment for continuing operations with a failed or degraded barrier in place. This should be described in the well-operator’s MoC procedure.

4.3.13

Cemented shoe track as a well barrier A cemented casing or liner shoe track is not an acceptable barrier after installation without adequate design, placement and testing. The failure of ‘cemented’ shoe tracks to prevent flow has been a key factor in several blowouts. Shoe tracks should be treated as open-ended casing unless they are designed and can be verified to demonstrate they are an adequate barrier to flow from the well. All the following aspects should be considered to qualify the shoe track as a well barrier.

4.3.13.1

Length of cement in the shoe track If the shoe track is being designed as a barrier, the length of shoe track should be considered. With the dual plug cementing technique, the lower plug is designed to wipe mud and the top plug to wipe cement from the inside of the casing. The well-operator usually chooses a shoe track length to contain any cement contaminated by mud during the displacement process.

4.3.13.2

Quality of cement in the shoe track Good cement in this context is a slurry which has been properly mixed and is uncontaminated. Any leakage around plugs or over displacement may reduce the quality and volume of uncontaminated cement in the shoe track.

4.3.13.3

Adequacy of cement placement An internal (or positive) pressure test of the casing does not qualify the shoe track as a barrier, because, typically the top wiper plug holds pressure from above but not from below. Even if the shoe or collar float valves are pressure-tested before installation, they may be damaged or washed out during the cementing process [Ref 53]. An inflow test should be carefully planned and carried out to provide a robust demonstration that the shoe track is an adequate barrier (see Section 4.6 for inflow testing guidelines). Specific problems are: • •

The top plug may be held in place by a small amount of cement which may fail as the casing flexes with temperature or pressure changes or with time The float valves may seal against cement slurry initially but if hydrocarbon, (especially gas), builds up under the float valve the barrier may fail

The following actions may help to improve the adequacy of the barrier: • •

Set a mechanical plug inside the casing above the float collar and test from below Set a cement plug on top of the float collar and pressure test from above

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•

4.3.14

Drill out the plugs and casing collar floats to demonstrate that there was cement inside the casing. If the remaining length of ‘good’ cement was verified this could qualify it as a cement plug barrier

Effects of different installations on well integrity The ability to maintain well integrity will, in part, be influenced by the characteristics of the installation to which the well is connected. Each type of installation, whether fixed or floating, will present risks to well integrity which will need to be identified, assessed and managed. Factors that may directly or indirectly lead to well integrity problems include: • • • •

Structural failure Loss of station keeping ability Foundation failure (e.g. punch through or scour related movement) Excessive topside motions (e.g. related to heave, pitch and roll)

For drill ships, well intervention vessels and semi-submersibles held on station by dynamic positioning (DP), or mooring systems, or a combination of both, the total or partial loss of station-keeping ability during an operation can, if not recognised and addressed at an early stage, escalate to a significant well integrity challenge. The motions of a floating drilling platform should be considered with a view to determine the conditions at which certain actions need to be taken to limit damage to drilling equipment and consequential impacts on well integrity. These limitations are often expressed in the form of ‘well specific operating guidelines’, which are agreed between the well-operator and installation duty holder prior to commencement of a drilling operation.

4.3.15

Use of PTFE tape PTFE tape should not be used on threaded plugs or threads that may see hydrocarbons. The use of PTFE tape should be restricted to pipework that will not see hydrocarbons where the nominal bore of the pipe is less than or equal to 1.1/2” inches, design pressure up to 100 Bar, design temperature range 1900C to 2000C and the PTFE tape used conforms to British Standard 7786 Grade H. The use of PTFE tape should be kept to an absolute minimum and where possible eliminated in favour of liquid thread compounds.

4.4 4.4.1

Blowout Preventers Retirement of O&GUK BOP Guidelines After the Macondo blowout in 2010 O&GUK introduced good practice guidelines for subsea BOPs on the UKCS. Guidelines on subsea BOP systems, Issue 1 was published in July 2012. These were extensively revised and expanded to include offshore surface BOPs and issued as Guidelines on BOP Systems for Offshore Wells, Issue 2 in May 2014. [Ref 31]

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The API similarly revised its Recommended Practice API RP53 Blowout Prevention Equipment Systems for Drilling Wells and issued it as a Standard, API S53 Blowout Prevention Equipment Systems for Drilling Wells, Fourth Edition in November 2012. [Ref 39]. The fifth edition was being finalised as this edition of the Guidelines were developed and includes an improved focus on onshore BOPs. The O&GUK guidelines largely replicated the API standard. With the publication of this Issue 4 of the Well Life Cycle Integrity Guidelines the opportunity is being taken to retire the O&GUK BOP Guidelines. Well-operators should refer to API S53 [Ref40] for further detailed guidance. There remain several areas where the good practice previously defined for the UKCS in Ref 31 is different to that proposed by API S53. These differences are described in the next section.

4.4.2

Good practice for UKCS wells vs. API S53 The well-operator should undertake a risk assessment against the BOP configuration requirements of API S53 to confirm whether this guidance is suitable for its planned well operations. Sub-hydrostatic well operations should be risk assessed and, if a Class 1 system is in place, the annular type preventer should be a type capable of closing on open hole Where it is planned to re-enter an existing well, previously drilled with a lighter Class 4 BOP stack, the well-operator should assess its suitability for a heavier (API S53-compliant) BOP stack. This is to confirm that the conductor and wellhead will not be overloaded. Table 3 lists the areas of recommended good practice for UKCS wells [Ref 31] that differ from API S53.

API S53 (4th Edition**, Nov 2012)

UKCS Good Practice from the retired Ref 31

Subsea BOP Subsea BOPs shall be Class* 5 or greater and Subsea BOPs should have at least three pipe have at least two pipe rams (excluding test rams). rams. Subsea BOPs shall have at least one annular preventer.

Subsea BOPs should have two annular preventers.

DP subsea BOP stacks shall have a minimum of two sets of shear rams (at least one capable of sealing) for shearing the drill pipe and tubing in use.

Moored rigs with a riser margin and BOPs with four cavities should have three pipe rams and one BSR.

For Moored rigs, a minimum of one set of BSRs (capable of shearing DP) may be used after conducting a RA.

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Moored rigs without a riser margin should conduct a risk assessment for the need for two shear rams. DP rigs, and rigs with five or more ram cavities, should have a minimum of two shear rams, at least one of which should seal.

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API S53 (4th Edition**, Nov 2012)

UKCS Good Practice from the retired Ref 31

Autoshear shall be installed on all subsea BOP stacks.

All DP rigs should have an autoshear system that should shear the pipe and seal the well if the Lower Marine Riser Package (LMRP) unlatches from the BOP.

A deadman system shall be installed on all subsea BOP stacks.

All DP rigs should have a deadman system. This automatically shears the pipe and seals the well on loss of both the electrical signal and the power supply to the control pods.

Offshore Surface BOP Surface BOP systems <3K psi Rated Working Pressure (RWP) / Class 2 or where ram preventers are planned a minimum of one set of blinds / BSRs shall be included.

All surface BOP systems should adopt a minimum of one set of blind rams. BSRs should be capable of shearing drill pipe in use and sealing the wellbore.

Surface BOP systems 5K psi rated shall include a Class 3 system. A minimum of one set of blinds / BSRs must be used and the third device may be ram or annular type.

Surface BOP systems 5K psi rated should utilise a Class 3 system and should have as a minimum one set of blind / BSRs capable of shearing drill pipe in use and sealing the wellbore. The third device should be an annular type device.

A minimum of Class 4 BOP system is to be used on 10K psi systems and shall include a minimum of one set of blind / BSRs capable of shearing the drill pipe in use and sealing the wellbore.

Class 4 / 10K psi rated surface BOP systems should utilise as a minimum one set of BSRs capable of shearing drill pipe in use and sealing the wellbore, one annular type device and the fourth device should be a ram or annular type device.

Onshore BOP Note that API S53 permits the use of a blind ram in BOP systems rated to 5K psi and less. *The classification or “class” of a BOP stack is the total number of ram and annular preventers in the BOP stack. [Ref 39] ** Will be updated to 5th Edition prior to publication

Table 3. UKCS BOP good practice vs. API S53

4.5

Pressure testing guidelines Where possible, pressure testing should be carried out with liquid (hydraulic testing) rather than air or gas (pneumatic testing). This is because the lower stored energy in hydraulic testing reduces the risk of personal injury in the event of failure during testing [Ref 21]. Consideration should be given to the test medium, bearing in mind that viscous fluids containing solids and fluid loss control additives might mask small leaks.

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Pressure tests should be covered by written procedures. These may be standard operating procedures for routine tests such as BOP testing. Otherwise the testing procedures should be included in the operations programme. Pressure tests should be completed with calibrated test equipment with a suitable pressure and time range which allows accurate monitoring of the test. Users should be aware of the factors affecting the accuracy of pressure tests, such as: • • • • • • • • • •

Volume of ‘system’ being assessed for leakage Pressure Temperature (thermal effects and thermal stability) Compressibility of fluid (presence of mixed fluids) Change in volume/deformation of system (e.g. casing ballooning) Duration Type of barrier Compound/multiple barrier Pressure source and potential leak path Measurement range and accuracy

Pressure tests should be the subject of a suitable and sufficient risk assessment process. Test results should be recorded with an auditable trail (e.g. all pressure tests graphed and signed off by a competent person). If circumstances in the well change (e.g. if the closed-in tubing head pressure for a well to be worked over is higher than predicted) the test procedures should be revised in line with the well-operator’s MoC procedures.

4.5.1

Risk assessment Pressure testing risk assessments should cover the following two distinct aspects:

4.5.1.1

Well integrity The most important aspect of designing a well and planning well operations is assuring well integrity. This is done by the selection, installation, verification, testing, maintenance and repair of suitable barriers through the life cycle of the well. The risk assessment covering barrier testing should include: • • • • • •

Maximum differential pressure across the barrier throughout the well life cycle Fluids to which the barrier could be exposed (hydrocarbon gas, H2S, CO2 etc) Frequency of testing Criteria for success of a pressure test Criteria for failure of a pressure test Contingency plans if the barrier cannot be successfully tested as required

It is important that the assessment of permanent barriers (e.g. cemented production casing) covers the full life cycle through production operations to final abandonment, including all the different conditions

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to which it might be subjected. For example, if there is a possibility that a production well may be gas lifted, even if this is not the original design, the production casing connectors should be gas tight. The risk assessment should consider the consequences of the test not fulfilling its objective. The lack of a test, or an inadequate test, may mean the well is left with an inadequate barrier that may fail during operations. The risk assessment should also consider the consequence if a barrier fails and exposes another part of the well to higher pressure than it is designed to contain. 4.5.1.2

Operational This covers the immediate hazards to rig personnel carrying out the test. The main hazard during positive pressure testing is the unintentional release of stored energy. A failed inflow test may release reservoir fluids. The installation duty holder should ensure that a suitable and sufficient risk assessment has been carried out. The assessment should consider: • • • • • • • • •

4.6 4.6.1

Competence of personnel Hazards of fluid released if a barrier fails Protection from projectiles if there is a sudden barrier failure Hazards if the test fluid is released to the atmosphere Potential for escalation (other parts of the well may be damaged) Simultaneous operations (SIMOPS) Safe systems of work (permits, barriers, etc) Securing pipework used in tests Temporary pipework service and rating

Positive pressure testing guidelines Pressure test planning A written procedure should be available covering: • • • • •

The test objectives Test acceptance criteria Duration of tests Bleeding down pressures to desired operational status Calculated volumes especially if testing a plug where a deeper set plug is already present in the same string

This may be a standard operating procedure for repeated tests (e.g. stump test for a rig BOP). Before each regular test, any specific circumstances (e.g. weather, changes to equipment, new personnel etc) should be reviewed to ensure the standard procedures are still applicable.

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For operation specific tests, procedures may be included in an operations programme or a specific test procedure may be issued. These procedures should be checked well before the testing starts to ensure that the assumptions made when designing the test are still valid. If there are significant changes (e.g. actual reservoir pressure is higher than predicted or a plug setting depth is shallower), the test procedures should be revised under the well-operator’s MoC procedures. The test arrangements should be checked to ensure there are no barriers upstream or downstream of the barrier to be tested as this could mask a leak. For some barriers, a schematic showing valves and their status will be needed. For multi-element barriers (e.g. a rig BOP or a xmas tree), a series of tests will be needed to qualify the separate elements in the barrier. The sequence of steps and the success/failure criteria for each step should be clear in the procedures.

4.6.2

Calculations of fluid volumes For large fluid volumes (e.g. a casing pressure test), the procedures should include a calculation of the volume of fluid that is required to raise the pressure to the required level. It is understood that this simple calculation is approximate. However, it should indicate gross mistakes (in order of magnitude) if a much smaller, or larger, volume is being pressured up than planned.

4.6.2.1

Compressibility calculation Compressibility calculation is as follows: Volume pumped

initial volume

pressure

fluid Compressibility

(bbl)

(bbl)

(psi)

(psi-1)

Compressibility (psi-1) of neat fluids that may be used are: Water = 2.8 x 10-6 Diesel = 4.6 x 10-6 Base oil = 5.1 x 10-6 (varies by type of oil and supplier) Compressibility of oil-based mud should take account of the relative proportions of constituents. The following equation may be used to calculate the effective compressibility: Effective Compressibility (psi-1) = WCW% + OCO% +SCS% Where W%, O% and S% are the relative percentages of water, oil and solids in the mud by volume and Wc, Oc and Sc are the compressibility of the water, oil and solid components respectively. A typical value for the compressibility of solids (SC) is 0.2 x 10-6 psi-1 The presence of gas in the fluid should be considered as this may have a considerable effect on the compressibility.

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4.6.3

Pressure test operations A pre-job safety meeting (or equivalent) should be held before the test with those involved to check: • • • • • • •

Understanding of the objectives of the test Test procedures Review of risk assessment results Worksite and equipment Contingency plans Safety precautions required (e.g. barriers, area clearance, Public Address (PA) announcements etc) A low-pressure test should be considered. It is prudent to perform a low pressure test as an initial integrity check before performing a high pressure test that may be more hazardous in the event of a failure.

Where possible the pressure behind the component being tested should be monitored to ensure there is no leak and the correct component is being tested (e.g. monitoring the 13 3/8” x 9 5/8” annulus when testing the 9 5/8” casing). The low pressure test, generally 250 to 350 psi, should be just high enough for measuring and monitoring with equipment available, and it should remain stable for the length of time specified in the programme, at least 5 minutes [Ref 110]. Tests where the pressure acts on a large area (e.g. a 20” casing circulating swage) are more hazardous, as force is a function of pressure multiplied by cross sectional area. If the low-pressure test is successful, the pressure should be increased to the full test pressure. The procedures should state if this is done in one step or in a series of steps with checks at intermediate stages. The volume of fluid pumped should be noted and compared to the value calculated in the procedures. The final pressure should be held for the length of time specified in the programme. This will depend on the trapped volume being monitored. The procedures should explain how the pressure is released safely, and at what stage the test is over. If possible, the volume returned should be measured and compared with the actual volume pumped.

4.6.4

Success/failure criteria Positive pressure tests raise the pressure in an enclosed space upstream of the barrier. The main confirmation is given by checking that the pressure upstream of the barrier does not reduce. This may be supplemented by monitoring for flow or pressure increase downstream of the barrier. The best success criterion is that there is zero change in the pressure over the specified time. It may not be possible to achieve this, and the well-operator should define the acceptance criteria for each pressure test. The procedures should state how long the pressure should be held for both low and high tests.

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It may not be possible to remove all trapped gas and so there may be an initial pressure change. The system should be recharged to the test pressure and monitored. After allowing for any minor pressure decline associated with residual trapped gas, any further pressure drop may indicate a failure of the barrier. Any identified problems in the procedure or equipment should be remedied and the pressure test repeated. Problems that may occur include: • •

4.7

Gas within pressured void (gas or air should be removed before testing as far as possible) Temperature effects (cold fluid pumped into a warmer void may result in a pressure increase). If this creates a problem, the temperature should be left to stabilise before a final monitoring of the pressure.

Pressure Test Acceptance Criteria Acceptance criteria for pressure tests vary widely [and have traditionally failed to consider the differences in the physical properties of the systems being tested for integrity]. The compressibility calculation, in paragraph 4.6.2.1, provides an indication of the volume change which is likely to be associated with a pressure change during a pressure test. In addition to understanding this relationship for every pressure test, it is necessary to establish acceptable leak rates as part of the pressure test design. The two graphs in Figure 2, below, demonstrate the pressure increase in annuli, associated with two different leak rates from an external pressure source. The graphs also demonstrate that the pressure build up is significantly influenced by the compressibility of the fluid and the volume of the annulus. The lower leak acceptance criteria of 2 cm3 per minute (see below) may be difficult to detect even over many hours.

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Figure 2. Pressure Change associated with leakage into an annulus

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It can be difficult to select appropriate acceptance criteria for pressure tests. The industry has some standards which are summarised in Table 4 below. ‘Leak tight’ means that no change in pressure or leakage is observed during the test, which should be conducted with specified conditions that would permit leakage to be observed. ‘Operator Specific’ requires that a leak acceptance criterion is specified by the operator e.g. leak tight, 2cm3 per minute per inch of valve, 15psi per 30 minutes, etc.

Well Component

Manufacturing Leakage

Cement Barrier

Construction Phase Operational Phase Leakage Leakage Leak Tight

Leak Tight

PFO and PBU

PFO and PBU

Casing & Tubing Connections

ISO13679

Leak Tight

Leak Tight

Fully Cased Annulus

ISO13679

Leak Tight

Leak Tight

Leak Tight FIT

Leak Tight FIT

Leak Tight

Leak Tight

PFO and PBU (plugged)

Monitor ‘A’ Annulus

Operator Specific

Operator Specific

Annulus with Open Shoe Injector or Producer Tubing

ISO13679

Gas or Hydraulic Lift Producer Tubing

Qualification testing of gas lift valve.

Leak Tight Gas or Hydraulic Lift Production Casing

ISO13679

DHSV

API 14A API Standard 598

Tree & Wellhead Valves API 6A Wellhead Seals

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API Specification 6A

PFO and PBU (plugged)

Monitor ‘B’ Annulus

Leak Tight Monitor ‘B’ Annulus

PFO and PBU (plugged)

PFO and PBU (plugged)

API 14B

API 14B

API RP14H

API RP14H

Operator Specific

Operator Specific

Leak Tight

Leak Tight

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Intervention Equipment

Operator Specific

PFO = Pressure Fall-Off. PBU = Pressure Build-Up

Table 4. Potential leak acceptance criteria for different components of a well at different well life cycle phases Definitions of the various acceptable rates include: • • • • • • • •

Leak Tight FIT = Formation Integrity Test (FIT) – nominal pressure at which no leak-off would be expected ISO 13679 = 0.9cm3/15 minute for each connection (internal & external) API RP 14A = 5scf/minute API RP 14B = 15scf/minute or 400cm3/minute API 598 = 3cm3/minute/inch of bore maximum, but varies with valve type and size API 6A = Specification does not indicate leakage acceptance of tests performed Seeps and weeps - No Industry Standard. Sometimes Gas <20% LEL measured 0.1m from the leak source or <0.1 litre per second or Liquid <4 drops per min Leak Tight = to be determined by the well-operator

If the barrier will not contain the pressure specified in the procedures, the barrier has failed the test. It should be replaced, repaired or adequately addressed through a MoC procedure. Operations may include: • • •

4.8

Unseating a mechanical plug and resetting it Setting an additional mechanical plug above the first Setting a cement (or other competent material) plug on top of the failed plug

Inflow testing guidelines These are also referred to as negative or drawdown tests.

4.8.1

Introduction Inflow tests are used to test a barrier in the direction of flow. An inflow test is needed when a barrier cannot be adequately tested by: • •

A positive test from the downstream side (because the barrier is not bidirectional) Direct pressure applied to the upstream or reservoir side (no access)

Barriers that may need an inflow test include: • • • • •

Liner hangers/liner top packers (unless bi-directional) Production casing shoe track Mechanical plugs inside casing Downhole safety and xmas tree valves Formation isolation valves

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• • •

4.8.2

Casing hanger seal assemblies Inflatable packers Mechanical plugs inside tubing

Specific problems to be considered for inflow tests The pressure upstream of the barrier may not be known and it may change over time. For a plug set in a production well, the reservoir pressure acting on the upstream side of the barrier will increase after production has stopped. If the barrier is inflow tested immediately after setting the plug, this will not reflect the maximum differential pressure to which the plug will be exposed. The fluid on the upstream side of the barrier may change. If there are formation fluids, gas may migrate to the upstream side of the barrier. Therefore, an immediate inflow test may be done with liquid upstream and this may be replaced by gas after some time. It can be difficult to measure pressure increase or flow in a large void downstream of the barrier. This is relevant to barriers at the bottom of the well where some or all of the well volume is between the barrier and any measurement. There may be temperature changes during the inflow test. Horner plots may be used to differentiate between pressure build up due to a leak and thermal effects. For overbalanced operations, the active barrier is deliberately degraded or removed to create the differential pressure. If the barrier being tested fails, the well is in an underbalanced condition and there may be an influx or kick. This may happen during the test or afterwards. Inflow tests can merge into displacement operations (where the well is completely displaced to a lighter fluid). It is important that the two phases are planned and managed as separate operations. The welloperator’s site representative should review the results of the inflow test (ideally with the onshore supervisors) and ‘sign-off’ the test before continuing with displacement operations. If the well is to be displaced to a lighter fluid, the displacement should be planned with a step-down chart of pressure versus volume, with clear notification of the point at which the well is underbalanced. Any deviation should be reviewed, and if there are concerns the displacement should be stopped and the well closed in at the BOP. The situation should then be assessed. An inadequate inflow test or a ‘false positive’ (that is a test that is wrongly thought to have qualified a barrier) may lead to a major well control problem if the well is then displaced to light fluid. To verify a successful test, all final fluid volumes may be closely monitored. A Horner plot analysis may be used to assist this process.

4.8.3

Inflow test planning To create a differential pressure to test the barrier, the pressure needs to be lowered on the downstream side of the barrier. The differential pressure should reflect the foreseeable use of the well during the life cycle.

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Lowering the pressure, typically by displacing to a lighter fluid, removes the active barrier for overbalanced operations. If the barrier being inflow tested fails, there will be an influx requiring activation of potential barriers and secondary well control. Important points for inflow test planning are that there should be: • • •

Clear indications of success if the barrier holds Clear indications of failure if the barrier leaks A safe way of returning the well to an overbalanced condition if the barrier fails

The criteria should as a minimum stipulate: • • • • •

The minimum time for the test The maximum time for the test The maximum allowable volume to be bled-off. The maximum allowable flowrate at the end of the test That the fluid flowrate should be on a clearly decreasing trend

Keeping the volume of lighter fluid to a minimum by pumping the fluid down the drill pipe rather than the annulus, is preferable to achieve the above objectives for deep-set barriers. The hydrostatic head of the annulus needs to be isolated for the inflow test. A suitable way of achieving this is setting a multi-use packer on an open-ended drill pipe, after the lighter fluid has been pumped down the drill pipe. Alternatively, a multi-use circulating valve may be placed in the string above the packer, and the packer is then set before opening the valve and circulating fluid. If using a packer, this should be run as deep as possible into the well, though it should be set no lower than the component(s) to be inflow tested. Note that the integrity of the annulus above the packer is not verified as part of this test.

4.8.4

Negative pressures across BOP These guidelines suggest introducing light fluid down the drill pipe for inflow tests. It is possible to reduce pressure in the well by introducing light fluid into the annulus or down a choke line. If this is done, care should be taken that: • •

4.8.5

The BOP sealing elements are not subject to excessive pressure from above (riser mud hydrostatic > wellhead pressure) causing damage. It does not cause a leak. Seals and gaskets are not designed for inward acting pressures (the external (seawater) pressure may be higher than the internal BOP pressure).

Inflow testing of downhole safety/xmas tree valves Commissioned production wells will have formation fluids in the tubing. For naturally flowing wells, closing the in-line production valves allows them to be inflow tested. The pressure downstream will be monitored to qualify the valves. It should be noted that the upstream pressure will gradually increase as the reservoir pressure builds up.

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The ‘test medium’ will be whatever fluid is flowing from the well which is likely to contain hydrocarbon gas. This will be a more severe test than hydraulic tests with liquid. Refer to Section 10.5.4 for more information on testing xmas tree valves.

4.8.6

Flow checks as inflow tests Flow checks during drilling are a type of inflow test. The bottom hole pressure is reduced to hydrostatic head when circulation stops. The hole is then checked for flow by monitoring the trip tank/flowline for any returns, or for pressure increase below a closed BOP. If there is flow, this may indicate that the well is underbalanced under static, non-circulating conditions. The potential barrier, rig BOP, should be closed and the well observed. Bottoms up should be circulated under well control (through the choke). If conditions indicate that the well is underbalanced, the mud weight should be increased to ensure the well is over-balanced under static conditions before further operations are carried out. It should be noted that, even where static mud hydrostatic gradient exceeds formation Pore Pressure, mud returned from the borehole may have picked up hazardous formation fluids such as gas or H2S by diffusion. Before performing controlled bleed-offs, assess the most likely worst case for the nature of the influx. Mitigations against hazardous influx of fluids should include limiting the volume bled back to a level likely to be well within the capacity of surface gas-handling equipment when circulated out. The process of controlled bleed-offs should continue only if shut-in pressures indicate a continued reduction in bottom hole pressure.

4.9 4.9.1

Well integrity/control of well Primary control of well Primary control of the well is maintained by the active barrier. Planning to ensure primary control of the well throughout its life cycle (by ensuring there is an active barrier in place) is the main function of well design and planning. Ensuring primary control of the well throughout its life cycle (by monitoring and maintaining active barriers) is the main function of operations personnel responsible for the well.

4.9.2

Secondary well control If an active barrier fails, primary control of the well is lost. Secondary well control is needed immediately, and this involves the activation of potential barriers such as: • • •

Overbalanced drilling: the drilling BOP Underbalanced wireline logging: wireline BOP Production: master valve in xmas tree

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Ensuring suitable well control equipment is available throughout the well life cycle is the responsibility of the well-operator. See Regulation 17(1), DCR; paragraph 35, DCR guidance; Regulation 9(1) and Schedule 2, BSOR. Deploying the well control equipment and ensuring it is ready when needed is a vital part of all operational phases of the well life cycle. It is the responsibility of the installation safety case duty holder or the well-operator. See Regulation 1(2), DCR and paragraph 33 of DCR guidance. Identifying when well control procedures are needed, and carrying them out, is an important aspect of well operations management as required by Regulation 21 of DCR [Ref 2].

4.9.3

Well control equipment The well-operator should ensure that suitable well control equipment is available at the well site before operations start. Operations include: • • •

Drilling, testing, completion Intervention/workover Operations and maintenance

Checking the ‘suitability’ of temporary well control equipment should take place during contracting of services, or with drilling contractor and service companies. The following points should be considered: • • • • • • • • •

Pressure rating of equipment compared to the maximum anticipated pressure Temperature rating compared to the maximum anticipated temperature Suitability of equipment for service (e.g. CO2, H2S) Number, type and location of rams in the BOP Where shear rams are used, understanding what equipment can be sheared and the associated conditions Suitable connection to the wellhead or xmas tree Adequacy of the primary control system Requirement for secondary and/or emergency control systems Inspection of certification

Arrangement drawings and flow diagrams for well control equipment should be easily accessible for users of this equipment, ensuring that it is possible to determine the position of non-shearable components relative to the shear rams/valves at all times. These drawings and flow diagrams should include: • • •

Geometrical description (e.g. location, size, distances to rig floor, between rams, etc) Operational limitations (e.g. pressure, temperature, type of fluid, flow rates) Overview of the fluid circulation system (pump, including choke and kill manifold)

The specification of well control equipment should be reviewed by an independent and competent person under the well-operator’s well examination scheme. See the Oil & Gas UK Guidelines for welloperators on well examination [Ref 26].

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The adequacy of the equipment owner’s maintenance and testing arrangements should be reviewed by the well-operator. See API S53 [Ref 39] where applicable. For offshore operations, all well control equipment should be considered SECE under SCR 2015. They should have an independent review under the installation verification scheme. See Step Change in Safety: Assurance & verification guidance suite [Ref 32].

4.9.4

Well control procedures The company responsible for managing the well control equipment (e.g. the drilling contractor’s rig BOP on a mobile rig) should provide the well control procedures for using that equipment. The well-operator should review these procedures. This will be part of the procedures to align the welloperator and contractor’s Safety and Environmental Management Systems (SEMS). There should be an interface document between the two systems. It is the responsibility of both the well-operator (under Regulation 13, DCR, and Regulation 9(1) and Schedule 2 of BSOR) and the installation duty holder (Regulation 21, DCR) to ensure that rig site personnel directly involved in well control have: • • • •

Clear responsibilities Clear procedures to follow to prevent well control incidents Clear procedures to identify/manage incidents – particularly initial response Sufficient competence to fulfil their responsibilities and carry out the procedures

Offshore, the installation duty holder should ensure that well control procedures are available, appropriate and understood by all relevant parties on the installation. The parties should have the relevant competencies and training to carry out the procedures. Equipment and systems should be put in place, and responsibilities assigned, such that well behaviour is continuously monitored at surface to the extent necessary to identify any unplanned movement of fluids. The driller, or other appointed person (e.g. coiled tubing operator), has the authority to shut the well in, if they consider it necessary, without authorisation from anyone else. This should be formally noted in operations plans and emphasised in conversations with site management personnel (e.g. drilling supervisor, toolpusher and Offshore Installation Manager (OIM)). The well control procedure should include drills and exercises covering all phases of the operations to ensure the team understand their responsibilities. It is important that immediate responses are carried out quickly and correctly and that these are recorded accordingly. The drills and exercises should cover reasonably foreseeable situations and non-standard situations. The latter could include: • •

Power system loss Kick without pipe in the hole, etc

For some well operations specific additional training may be required.

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4.9.5

Tertiary well control If secondary well control fails there may be an unplanned release of fluids from the well, i.e. a blowout. People, equipment and procedures to regain control of the well are outside the scope of these guidelines. Refer to O&GUK Guidelines on relief well planning for offshore wells [Ref 29].

4.10

Management of change Well-operators should have an MoC procedure covering wells and well operations throughout the full life cycle from initial design to final abandonment. Duty holders should design their procedures to suit their methods of working but all MoC systems should have: • •

Definitions of changes that need to go through the MoC procedure Levels of approval for different levels of changes

Changes to well integrity, the pressure containment boundary or well barriers should go through the MoC process. For example, rig ups for annulus bleed down should be subject to management of change that includes addressing any HP/LP interfaces e.g. between the annulus and a closed drain system

4.10.1

General There are likely to be deviations from well operations programmes due to uncertainties in the subsurface environment, or problems encountered during operations. The well-operator should have an MoC policy and procedures to define what needs to be done in the event of these deviations. Minor changes to the well operations programme should be discussed at the rigsite and agreed with the off-site supervisor (e.g. drilling superintendent). This may be done by a specific call or at a regular operations meeting/morning call. Minor programme changes should be recorded in the daily reports. These minor changes do not affect the final well status, for example: • • •

Change in running order of the bottomhole assembly (BHA) Formation top high but within the error band given by subsurface team Function testing of a downhole tool before running in the hole

A vital part of well operations is recognising when a significant change has occurred. The well basis of design and operations (drilling) programme should include the definition of a significant change. In some cases, this may be done by giving a range for important values (e.g. 13-3/8” casing to be set at 5,800 feet +/- 300 feet). In this example, if the casing setting depth was changed to <5,500 feet or >6,100 feet it would be classed as a significant change, and therefore need to go through the well-operator’s MoC procedure.

4.10.2

Design MoC A significant change would be any alteration to design that results in a change to:

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• • • •

4.10.3

Primary control of the well (fluid type/weights, pore pressure prediction) Well duty (exploration to development, injection or gas lift) Well barriers (casing or tubing design) Well control equipment (rig BOP, DHSV, etc)

Equipment MoC A significant change would be: -

4.10.4

Any proposed use outside the equipment’s certified design or operating envelope Design change to equipment designed to a recognised standard or code Any design change in equipment that is part of the well pressure boundary

Programme/procedure MoC A significant change would be: • • •

4.10.5

Any alteration that results in a significant change to an approved well operations programme, or regulatory notification Any alteration that results in a change to an approved standard or procedure Any alteration that may result in a significant change to the risk profile and require additional control measures

Personnel MoC Any change to the personnel team in a safety critical role should be reviewed under the MoC procedures.

4.10.6

Change request and approval The programme change should be written out as an amendment to the approved programme. The originators of the amendment may be either the well engineers who wrote the original programme or operational, rigsite personnel. Changes to the well or well programme should be assessed to ensure that risk of unplanned release of well fluids remains ALARP. Risk assessment of altered downhole hazards needs to be carried out to ensure the new plan meets ALARP criteria. Significant changes should be reviewed and approved to at least the same authority level as the original programme. Well-operators should consider specific approvals by a technical authority (or equivalent title) outside the line management of the operations team, as well as review by installation duty holder. The well-examiner should be informed of significant changes and be copied on the change request. There should be enough time for the well-examiner to comment before the operations are started (or restarted).

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4.10.7

‘Material changes’ to be notified to the Competent Authority ‘Material changes’ should be reported to the OSDR as required by SCR 2015 [Ref 3] and to the HSE as required by BSOR [Ref 11]. The requirements are described in Section 2 of these guidelines.

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5 Well Design and Operations Planning 5.1

Risk identification and assessment – the ALARP principle The primary responsibility for identifying, assessing and mitigating well hazards rests with the welloperator. The well-operator should ensure that the personnel assigned to the well design and operations planning are competent. The first step for well design should be the assessment of subsurface conditions and identification of potential hazards. Identified risks should be recorded (e.g. in a risk register) and any actions required to reduce the residual risk to ALARP tracked to closure. Making sure a risk has been reduced to ALARP is about weighing the risk against the sacrifice needed to further reduce it. The decision is weighted in favour of health and safety because the presumption is that the duty-holder should implement the risk reduction measure. To avoid having to make this sacrifice, the duty-holder must be able to show that it would be grossly disproportionate to the benefits of risk reduction that would be achieved. Thus, the process is not one of balancing the costs and benefits of measures but, rather, of adopting measures except where they are ruled out because they involve grossly disproportionate sacrifices. ALARP at a glance [Ref 16].

Environmental, as well as health and safety hazards should be considered during well design and planning. The risks and measures to reduce them to ALARP should be discussed with supervisors, and outside experts as needed, during the design process.

5.1.1

Review The draft well design (basis of design) should be reviewed. The reviewers may be other well engineers in the same company, but not involved in the design, partner personnel, service company specialists, drilling contractors and/or external experts. From a Well Integrity viewpoint, the objectives of this review include: • • •

5.2

Substantiate the well integrity aspects of the well design, Validate the pore pressure /fracture gradient estimate, Review and endorse the well integrity related aspects of the planned operations.

Risk Assessments Formal risk assessment, Hazard Identification Studies (HAZIDs) and/or Hazard and Operability Studies (HAZOPs) should be carried out during the well design and planning process. These may be both:

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• •

A further challenge to the design, assumptions and operations planning A demonstration that risks have been identified and reduced to ALARP

Risk assessments should be suitable and sufficient. They should include an assessment of conditions below ground and other well hazards. Well-operators should update their risk assessment after acquiring new data. Further information on risk assessments and risk management may be found in References 36, and 79.

5.2.1

Assessment of subsurface conditions The well design should consider an assessment of subsurface conditions so that the hazards contained within the geological strata and fluids are properly assessed. The assessment team should be multi-discipline (e.g. geologists, geophysicists, reservoir and drilling engineers). For well integrity purposes, the assessment should include: • • • • • • • • • • • •

Purpose of the well (e.g. exploration, appraisal, development, gas storage) A full geological prognosis Depths and formation type of potential hydrocarbon-bearing zones Type of hydrocarbons expected (e.g. oil or gas) Potential for other hazardous fluids (e.g. H2S or CO2) Potential hazardous formations (e.g. salt or reactive clays) Estimate of potential overpressure (depth and intensity) Estimate of temperature gradient in the well Estimate of fracture gradient and potential lost circulation zones Shallow hazard assessment (gas + shallow water flows) Potential for natural or induced seismic events (e.g. fault slip), particularly onshore For gas storage wells, consideration of the alternating injection and production pressures.

Inputs to the assessment should include: • • • • • •

Output from seismic surveys and interpretations ‘Deep’ (exploration) seismic ‘Shallow’ (site survey) seismic Geological review of the basin, area and well Review of offset wells The proximity of operating wells at the reservoir interval and the pressure regime when drilling into the reservoir.

The assessment should take account of the anticipated full well life cycle, including: • • • •

Potential for pressure increase in later field life due to injection or fracturing Formation movement due to injection or depletion Well movement caused by thermal growth or contraction, and mechanical movement e.g. due to wave action Long term changes to reservoir pressure

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• • • • •

Increasing water cut Reservoir souring (and effect on tubulars) Change of well purpose (e.g. from producer to injector) Implementation and impact of cuttings re-injection (CRI) The potential for field subsidence

The statement of subsurface hazards should provide the wells team with information in a form that they can use to enhance the well planning process. The range of potential outcomes should be provided together with most likely outcomes in quantitative terms such that both a base case and contingencies can be part of the well design process. There may be significant ranges on both pore and fracture pressure predictions. Subject to the guidance on maximum pore pressure in Section 5.3.1 the well should be designed based on the most likely outcome with contingencies, commensurate with the risks, to address the range of potential outcomes.

5.2.2

Aquifers Aquifers which require specific isolation should be identified by considering: • • • • •

5.2.3

Fluid content (fresh water, brine etc.) Formation pressure Depth Current or potential domestic usage Specific, local, regulatory requirements

Presentation of subsurface assessment The results of the assessment should be included in an approved document and presented directly to the well design personnel at a meeting to allow discussion. Any significant changes to the assessment of subsurface conditions (either in the planning or operations phases) should be identified. The changes should be formally brought to the attention of the well design or operations team via the MoC process.

5.2.4

Assessment of other well hazards All available data sources should be reviewed to identify well hazards including: • • • •

Offset wells reports (for well hazards and operations problems) Site survey (for seabed conditions) Metocean reports (weather and environmental conditions) Platform or project HAZIDs/HAZOPs for relevant wells

The results of these hazard assessments should be recorded and considered during well design. The record may be in the form of a risk register, which may also note mitigation and closeout of items. For re-entry or sidetrack wells, the records of the existing well (e.g. construction, operation, intervention, suspension) should be reviewed.

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5.2.5

Well examination An independent check should be carried out by an independent and competent person under the well examination scheme. See Guidelines for well-operators on well examination [Ref 26].

5.3

Well design The process should start with a definition of the type of well being designed. The types include: • • • • •

Exploration Appraisal Development (e.g. production, injection, CRI) Combination (e.g. water injection with CRI) Gas storage

Well-operators should have their own process for designing wells which should include the following steps (Sections 5.3.1 to 5.3.5). These steps may be in another order and different terms may be used.

5.3.1

Estimate of maximum pressure The subsurface assessments should predict a maximum downhole pressure at a given depth. A range of uncertainty may be provided. If data is limited, the estimate should err on the side of caution. From this value a maximum wellhead pressure is calculated. If detailed data is not available, worst case assumptions should be used, e.g. that the hole is filled with the lightest possible fluid. Typically, 0.1 psi/ft is used. The maximum estimated wellhead pressure will be used to define the pressure rating of equipment (wellhead and production casing) and well control equipment. The regulations do not distinguish between High Pressure High Temperature (HPHT) and ‘standard’ wells. The duty is to identify the hazards and design the well accordingly. Well-operators may categorise some wells as HPHT and have specific design and operations procedures if they wish. HPHT well guidance is provided by the Energy Institute model codes of safe practice Part 17 Volume 1 [Ref 60, 61 and 62]. Casing setting depths and sizes (sometimes called well architecture) are the starting point of well design. This defines how the pressure containment boundary is installed downhole by cementing casing in place to ensure integrity during the well construction and throughout its life cycle.

5.3.2

Conductor The conductor cases off the shallow, often unstable, formations. Depending on the specific application, a conductor may also provide structural support. Onshore the conductor and/or surface casing may be used for aquifer isolation. When aquifer isolation is required the well-operator should ensure that the conductor, and/or surface casing, and associated cementation are designed to achieve aquifer isolation. The risk of fluid broaching to the seabed (or surface on a land well) outside the conductor should be reduced to ALARP. Figure 3 shows typical arrangements.

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Design of the conductor / surface casing requires structural and well design input, to decide the pipe size, wall thickness, connection type, material, centralisation and cementation that satisfies the requirements for fluid retention/isolation and structural loading, including bending and cyclic loads. On land wells, connection to the cellar should also be considered. The design should be suitable for the full well lifecycle, for all structural and fluid/pressure retention potential load cases that can be envisaged. For subsea wells this includes structural loading from the riser during drilling and snagging loads from trawling and other offset forces. An estimate of the maximum bending load provides input to the calculation of the required diameter, length and wall thickness of the top conductor joint. The criticality of load sharing between the conductor and surface casing should be understood. The suitability of the connectors to withstand all life cycle loads should be reviewed. ‘Quick connect’ types should have a means of confirming they are fully made up and locked. The potential for long-term corrosion of the conductor and surface casings from external environmental influences should be considered. The method of protection should be defined. There are several methods of installing conductors including driving, auguring, drilling in, jetting and cementing in a drilled hole. For a drilled hole the top of the cement in the annulus should be brought back to the seabed (or surface on a land well). The well design should specify a minimum acceptable depth below the seabed for the cement top. Specific techniques for verification of Top of Cement (TOC) and cement top-up may be considered during well planning. Reference may be made to the Energy Institute Guidelines for Routine and Non-Routine Subsea Operations from Floating Vessels [Ref 64] and Guidelines for the Analysis of Jack-up and Fixed Platform Well Conductor Systems [Ref 65]. The basis of design should be used by structural and well engineers to define the requirements for ongoing maintenance and monitoring. Fluid content changes in the annulus together with mechanical degradation could impact the ability of the conductor / surface casing to maintain structural integrity. Typically, a conductor or surface casing will hold the full well loading throughout the well lifecycle, and its condition should be known. Information from monitoring routines should be used to re-assess the ability of the conductor and surface casing to sustain the anticipated loads. Also see Section 10.1.6.

5.3.3

Surface casing For the purposes of these guidelines the surface casing is assumed to be attached to the high-pressure wellhead. The rig BOP or xmas tree is installed on the wellhead, forming the first part of the pressure containment boundary. It may provide structural support to the BOP and xmas tree. The high-pressure wellhead should be locked into the low-pressure wellhead on subsea wells to maximise wellhead stability for the life of the well. Surface casing should be set above any predicted hydrocarbon traps or where there is a risk of highpressure water flows. This should take account of significant anomalies identified by the shallow seismic review.

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If the well-operator decides to set surface casing below a potential shallow gas horizon then suitable precautions should be taken. Precautions may include drilling a pilot hole through the potential shallow gas horizon whilst ensuring that procedures to deal with any flow are in place and understood. These procedures may include the following: • • • •

Pumping mud at maximum rate Continuous Remotely Operated Vehicle (ROV) bubble watch at the seabed Continuous monitoring of the sea surface for any indications of gas Dropping the drill string and moving off location

The predicted fracture gradient should then be considered, with any potential hole problems identified from offset wells or by the subsurface team. The surface casing is set at a depth where formation strength is adequate to allow a workable kick tolerance in the next hole section. The potential for long-term corrosion of the conductor and surface casings from external environmental influences should be considered. The method of protection should be defined. The criticality of load sharing between the conductor and surface casing should be understood.

5.3.4

Intermediate casings The number and setting depths of intermediate casings will depend on a review of the subsurface hazards and the predicted fracture pressure and pore pressure in the formations between the surface casing depth and the production casing setting depth.

5.3.5

Production casing This is the innermost casing at the wellhead and is part of the pressure containment boundary. It should be designed for the highest internal pressure load. It may be set across the reservoir at Total Depth (TD) or the casing shoe may be set above the reservoir. If drilling is carried out after setting the casing, casing wear should be considered. Since the production tubing may leak, design of the production casing should recognise the potential for exposure to reservoir fluids. If the production casing may be exposed to erosion and corrosion this should be considered during the design. The potential for production casing hanger seal movement when exposed to anticipated loads throughout the well lifecycle, and the implications for well integrity, should be assessed. The production casing hanger should be locked into the high-pressure wellhead if calculations indicate this is necessary to ensure the seals stay in position for the life of the well.

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Figure 3. Well diagrams showing conductor and surface casing

5.4 5.4.1

Casing design General Casing should be specified, manufactured, inspected and tested to the appropriate standard e.g. [Ref 70, 71 and 76]. All components of the casing string, including connections, circulation devices and landing string, should be subject to load case verification. The worst case (that is lowest) physical properties should be used in calculations. The weakest points in the string with regards to burst, collapse and tensile strength rating should be clearly identified.

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Casings should be designed to withstand the worst conditions of burst, collapse, tensile and tri-axial loadings during the full life cycle of the wells and for any reasonably foreseeable well operations, with adequate allowance for deterioration in service including wear, corrosion and erosion. For through tubing drilling operations, the tubing and accessories should be reclassified to casing and reassessed against drilling loads.

5.4.2

Design basis, premises and assumptions The design process should include the following: • • • • • • • • • • • • • • • • • • • • •

Planned well trajectory, bending stresses from doglegs and hole curvature Maximum allowable setting depth with regards to kick margin Estimated pore pressure development Estimated formation strength Estimated temperature gradient Drilling fluids and cement programme Loads induced by well services and operations Completion design requirements Estimated casing wear Setting depth restrictions due to formation evaluation requirements Potential for H2S and/or CO2 Metallurgical considerations Annulus pressure build up Well abandonment requirements Equivalent Circulating Density (ECD) and surge/swab effects due to narrow annulus clearances Isolation of weak formation, potential loss zones, sloughing and caving formations Protection of reservoirs Protection of aquifers Geotectonic forces if applicable Cyclic forces on gas storage wells Any other requirements that may influence casing string loads or service life

Normally, rupture disks should not be included in a casing string. In certain circumstances, the well-operator may decide that rupture disks may be included in a casing design (e.g. to reduce the risk of casing collapse due to annulus pressure build-up). The reduction in strength of the casing string should be fully assessed and mitigation put in place to ensure risks are ALARP. Data from previous wells in the area or similar wells should be evaluated to determine additional design requirements.

5.4.3

Load cases When designing for burst, collapse and axial loads, the following load cases may be considered: •

Gas kick

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• • • • • • • • • •

Gas-filled or evacuated casing Production or injection tubing leaks Cementing operations Pressure testing casing Thermal expansion or contraction of fluid in enclosed annuli Dynamic loads from running of casing, including overpull to free stuck casing Squeezing by plastic salt Well kill loads, (e.g. bullheading) Life of well operations (e.g. fracture, perforation, stimulation) Cyclic forces on gas storage wells

This list is not comprehensive. All load cases for the planned activity, plus possible changes in design loads and stresses during the life cycle of the well, should be assessed. The assumptions and load cases used in the well design should be explicit and clearly stated in the well basis of design document.

5.4.4

Casing design factors Stress design or stress verification programs may be used to demonstrate the presence of appropriate design factors. Minimum design factors (for burst, collapse and axial loads) should be greater than the load induced stress/capacity. The well-operator would normally have approved internal design factors. Table 5 illustrates typical design factors which may be used [from Ref 110]. Burst

1.1

Collapse

1.1

Tension (stuck pipe, cementing and pressure testing)

1.25

Tri-axial stress

1.25

Table 5. Typical design factors from Ref 110

5.5

Cement design Conductors and surface casings should be designed to be cemented (where not driven or jetted) back to surface or the seabed. If the structural integrity of the conductor needs the TOC to be at a specific height, a means of carrying out a top up job to achieve this should be included in the planning. Casings below the surface casing should be cemented back into the previous casing unless: • •

It would preclude a subsequent sidetrack In a subsea production well where the annulus cannot be bled down to relieve overpressure caused by thermal expansion of trapped fluid during production

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• • •

The section is too long to be fully cemented To prevent losses or breakdown of weak formations exposed in the annulus It is planned to reinject cuttings down the annulus

If the cement is not brought back into the previous casing, there should be at least 1,000 feet (300 metres) Measured Depth (MD) of cement above the shallowest hydrocarbon interval, if the top is calculated indirectly (displacement pressures and volumes). This 1,000-foot column is considered adequate for two permanent barriers or a combination permanent barrier for the eventual abandonment of the wellbore. See Oil & Gas UK Well Decommissioning Guidelines [Ref 24]. If the height of cement in the annulus is planned to be verified by direct measurement (sonic logs, etc) this height may be reduced. If the design height is not achieved, then consideration should be given to any necessary remedial action. For high inclination or horizontal wells, the vertical height of the top of the cement above a hydrocarbon zone, should be considered. Where reasonably practicable, non-hydrocarbon-bearing permeable formations should be sealed by cement in the annulus to reduce the risk of flow outside the casing and potential corrosion, or flow from one formation into another. The density of the slurry and spacer should be designed so that the well remains overbalanced throughout the cementing operation. The density and planned height of the cement should be designed so that the formation is not fractured during cementing. The cement job should be designed to: • • •

5.5.1

Prevent influx whilst the cement is setting Provide compressive strength as quickly as possible in the context of the application Provide a long-term (permanent) barrier to flow in the annulus

Factors to be considered in annulus cementing The most important factor is to completely fill the annulus around the casing with cement from the shoe, to a high enough level to provide the required barrier. The following should be considered: • • •

Preventing over-gauge hole sections forming during drilling Centralising the casing. The pipe should be held off the hole walls to ensure a complete sheath of cement around the pipe Mud displacement by prejob circulation, spacer and lead cement slurry

It is also important to place uncontaminated cement around the shoe, and to avoid any contamination from mud during the cementing and displacement operations. Bottoms up should be circulated after running casing to ensure there is no gas in the well.

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The cement placement/displacement method should be chosen to provide the most reliable means for placing uncontaminated cement to the right place. This is likely to be the dual plug method for smaller (≤ 13-3/8 inch) casings. Normally float valves should not be locked open when the casing is being run in the hole. In certain circumstances, the well-operator may decide that self-fill equipment may be used. The following should be considered: • • • • •

Risk of influx up the casing while running and mitigation Contingency if floats do not convert when needed Contingency if floats convert unexpectedly Potential problems if cuttings or junk enters the shoe track Advantages of the float shoe and collar being separated by several joints

The shoe track should be a big enough volume to contain all cement contaminated by mud displaced from the casing by the top plug. As a minimum, assuming range 3 pipe, this should be two joints for large (≥ 13-3/8 inch) diameter casing and at least three joints for smaller inside diameter (ID), but longer, casing strings. There should be accurate displacement calculations to prevent cement being pumped out of the shoe track in the event of the plug not bumping. There should be clear instructions in the operations procedures on what to do if the plug does not bump. Cement jobs should be designed to achieve a greater hydrostatic pressure in the annulus than in the casing at the end of the operation, to reduce the risk of over displacement of cement. The cement slurry design may include specific additives to improve integrity: • • •

Gas migration control Fibrous material for greater toughness Silica for improved performance at high temperature

Where possible, for liner cementing, the liner should be rotated while placing the cement. Advice on testing cement slurries may be found in API 10 series [Ref 42].

5.5.2

Considerations for inner string cementing The internal height of cement left above the shoe should be considered and specified when the inner string/stab-in float shoe methods are used. This should be a volume large enough to ensure uncontaminated cement around the outside of the shoe. The potential impact of annulus bridging on casing collapse should be considered when inner string cementing. The severity of this risk increases with longer/deeper casing.

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5.6

Materials for wells The metallurgy, manufacture, inspection and testing of well tangibles should be selected with due consideration for the possible presence in wellbore fluids of corrosive elements such as H2S and/or CO2 e.g. [Ref 71]. The effects of corrosive fluids on non-metallic materials should also be considered. All materials should be designed, manufactured, and supplied to an applicable standard (e.g. API, ISO, etc). If a standard does not exist, the well-operator should define their own standards, based on the requirements necessary to assure suitability for the well, along with appropriate implementation of quality assurance processes. For all material supplied for the well, whether by the well-operator, rig contractor or service companies, the well-operator should assure itself of the suitability of the material. The specification of any replacement part, component or assembly within the pressure containment boundary should be carefully considered to ensure that they match, or exceed, the design criteria or relevant standard throughout the life cycle of the well.

5.6.1

Wellhead equipment Wellhead equipment should be manufactured, inspected and tested to the appropriate standard e.g. [Ref 40 and 72]. Within each standard, the well designer should assess the service environment against the performance option, for example in references 40 and 72: • •

5.7 5.7.1

PSL3G for gas testing trees PR2 for HPHT applications

Designing a well for primary control Overbalanced drilling and operations Designing a well for primary control has two elements: • •

5.7.2

Predicting the mud weight window based on the pore pressure and fracture gradient at all depths through the drilling phase of the well Ensuring the hole is kept full of drilling mud of the correct weight

Pore pressure prediction Part of the assessment of subsurface conditions (see Section 5.2.1) should include an estimate of the potential overpressure in the well. For exploration wells in a new area, this will be based on seismic interpretation and geological review of the basin. In drilled areas, there should also be an offset wells review for mud weights, log data and any kicks or well control problems.

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For development wells, note should be taken of any injection operations as these may raise pressures in the injection zones. Reservoir engineering input is required for assessment. The prediction should describe the estimated start depth of the overpressure, any specific seals, and any pressure ‘ramps’ (rapid increases in overpressure).

5.7.3

Maintaining overbalance The well design should state mud weights for each hole section. The recommendation should consider pore, sand fracture, shale fracture and overburden pressures. The uncertainties associated with the prediction should be documented.

5.7.4

Safety margin on mud weight For overbalanced drilling, the mud weight should be high enough to prevent flow when there is no circulation. Well-operators should plan to use a higher mud weight as a safety factor (either riser margin or trip margin) as described below.

5.7.4.1

Trip/safety margin A trip (or safety) margin should be used to ensure that the hydrostatic pressure in the hole stays above the pore pressure. This margin may be expressed as pressure (e.g. 200 psi at the bottom of the hole) or a density/weight (e.g. Specific Gravity (SG) of 0.1).

5.7.4.2

Riser margin for floating rigs A riser margin is a specific safety factor (based on the loss of hydrostatic head if the drilling riser is lost) to keep the well overbalanced. A riser margin should be included in the mud weight for floating rig operations if possible. If it is not possible to have a riser margin, the well-operator should put in place alternative arrangements to reduce the risk of a well flow if the riser is lost.

5.8 5.8.1

Formation integrity/kick tolerance Background The maximum mud weight used in a hole section will depend on the strength of formations exposed in that section. If the bottomhole pressure is higher than the fracture strength of the formation, there will be mud losses to the formation. The basic well design (casing setting depths) is affected by the predictions of pore pressure and fracture gradient. At each casing shoe the estimated fracture gradient at the shoe (leak off) is used to define a maximum mud weight for the next hole section. If primary well control is maintained, the rising pore pressure is matched by increasing the mud weight until close to the leakoff. The next casing is planned to be set at this depth.

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However, there may be a kick (primary well control is lost). Secondary well control operations always lead to higher pressures in the well. As a kick is circulated out, the imposed pressure at the surface (choke pressure) compensates for the lower density of the oil or gas in the influx. This additional pressure may cause lost circulation.

5.8.2

Leak Off Test / Formation Integrity Test The well design should include taking Leak Off Tests (LOT) after drilling out the surface and deeper casing shoes. This provides a measure of the maximum pressure that the formation just under the shoe can withstand when circulating out a kick; the highest imposed pressure relative to rock strength is usually just below the shoe. It also serves to confirm the integrity of the cement at the casing shoe. Current understanding is that a correctly conducted LOT does not reduce the strength of clay or shale, and so this is usually the preferred option. There may be formations deeper in the section that are weaker than the casing shoe (e.g. fractured limestone below a shoe set in clay). In a known area, or where the formation strength is high compared to the maximum planned mud weight for the section, a FIT may be done. A FIT raises the internal pressure to a specified level without initiating leakoff.

5.8.3

Kick tolerance Kick Tolerance is an estimate of the largest volume of influx (at a given intensity) that can be circulated out of the well without fracturing the formations below the shoe. This value is used to calculate the maximum length of section that can be drilled before setting another string of casing. Unless the risk of gas in the next hole section is negligible, the kick fluid should be modelled as dry gas at a hydrostatic gradient of 0.1 psi/ft. Alternatively the kick fluid may be modelled as oil, brine or water if such fluids are predicted to a high degree of confidence. The assumed kick intensity should, in areas with a known pore pressure gradient, be equivalent to the predicted pore pressure gradient plus an appropriate safety margin. If the pore pressure gradient in the next hole section is unknown, or carries significant uncertainty, the assumed kick intensity should be equal to the maximum proposed mud weight for the section plus an appropriate safety margin. For kick tolerance modelling purposes, it should be assumed that the influx occurs while drilling at planned TD in the next hole section. Kick tolerance calculations should take account of the expansion of gas when circulating out the kick under constant bottom hole pressure conditions, and should consider two possible cases for maximum pressure at the casing shoe: • •

When the kick is taken on bottom and is opposite the drill collars When the top of the gas bubble has been circulated to the casing shoe

The well-operator should state the maximum estimated kick volume that can be accepted for each hole section.

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During well design several assumptions are made for this calculation. The kick tolerance estimate should be recalculated when the actual casing depth and LOT/FIT values are known. The values should then be recalculated in response to changes in significant factors such as the mud weight in use. If the recalculated kick tolerance is less than the well-operator’s stated minimum, then a formal risk assessment should be done. This should include consideration of: • • • • • • •

Likelihood of an influx nature of the influx potential “worst-case” scenario ability to detect the influx rapidly speed with which the well can be shut-in ability to circulate out the influx rig type

It should be noted that the weakest part of the well may not be just below the shoe. Well-operators may wish to calculate the kick tolerance based on an estimate or measurement of the open hole weak point.

5.9

Design for suspension of operations, plugging and abandonment The well-operator shall ensure that a well is so designed and constructed that, so far as is reasonably practicable: It can be suspended or abandoned in a safe manner After its suspension or abandonment there can be no unplanned escape of fluids from it or from the reservoir to which it led Regulation 15, DCR See Oil & Gas UK Well Decommissioning Guidelines [Ref 24].

5.10

Well path and anti-collision A hazard for some wells is drilling into another well. For new wells and sidetracks close to existing wells, or future planned wells, an important part of the design is the well path. This should be designed to minimise the risk of collision with both existing wells and future planned well profiles. The well-operator should work closely with a directional drilling and surveying specialist to design a well for: • •

Minimum risk of collision Reducing the well location uncertainty so a relief well can intersect the well if necessary [Ref 29]

The well-operator should have a documented system for managing well trajectory information with: •

Surface coordinates, slot details, trajectory details and their respective uncertainties

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• •

Survey redundancy (overlap) Quality Assurance (QA) / Quality Control (QC) of survey procedures and data to ensure the accuracy of the data and the avoidance of material error

Accurate and up to date information should be maintained for all wells, including: wells being drilled, completed wells, during suspension of well operations and for plugged and abandoned wells – including sidetracks. The well-operator should record the location of any abandoned radioactive sources in its wells and the position of any radioactive pip-tags installed during the well construction. Surveying techniques that do not rely on magnetism should be considered where wells being drilled may be affected by magnetic materials (e.g. steel) in other wells. The well-operator should use a model for quantifying well bore positioning uncertainty. The probability of the well being drilled being within the ellipse of uncertainty of an existing well should be <5%. The Industry Steering Committee for Wellbore Surveying Accuracy (ISCWSA) has established models which may be used for this purpose. Before drilling, the likelihood of a well to well collision should be analysed to confirm if this is a significant risk. This should be analysed by: • • •

•

Verifying the existence of wells within a reasonable vicinity of the well to be drilled Performing a scan to confirm the proximity of the well to be drilled with all respective offset or adjacent wells (e.g. centre to centre, or sidewall to sidewall distance) Verifying the relative positional uncertainty of the well to be drilled with the offset wells. Separation Factor (SF) or similar techniques may be used to quantify this as a ratio of the distance between the two wells divided by the combined positional uncertainty of those two wells. Considering whether a collision poses a risk e.g. an isolated pilot hole may be of no concern.

Clear metrics (side wall to side wall distance and separation factor) should be established with respect to these criteria which trigger the requirement to manage the collision risk to an acceptable level. If the likelihood of a collision is deemed as unacceptable then the following precautions may be considered: • • • •

Re-plan the well trajectory with an anti-collision nudge to increase the distance from respective offset wells to an acceptable level Stipulate a stopping point during drilling, if a certain well collision risk becomes unacceptably high (e.g. SF <1) Improve the survey accuracy of the well to be drilled Improve the survey accuracy of respective adjacent wells, possibly by re-surveying said wells

In high risk cases, magnetic or other physical ranging techniques may be considered. To mitigate against a collision the following actions should be considered: • •

Control the drilling parameters Monitor changes in drilling parameters for indication of drilling into a well

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• • • • • • •

Monitor returns for cement or casing swarf in mud returns Change annulus pressure in completed wells e.g. depressurise, cease gas lift, or stop cuttings reinjection. Monitor the offset wellheads for noise and vibration. A stethoscope may be used Utilise a less aggressive drilling assembly In high risk cases, adjacent wells may need to be plugged Monitor annuli pressures. In particular the first annulus likely to be intersected. Note: this may require applying positive pressure on the annulus. In fields with water or gas injection, including gas storage fields, shutdown injection on selected wells and monitor wellhead pressures.

If there are any indications of collision with an adjacent well, drilling should be stopped immediately, the potential collision investigated, and action taken as required to ensure that life cycle well integrity of the impacted wells is maintained.

5.11

Relief well considerations The requirements of a relief well should be considered during the well design. This forms part of the OPEP required by OPRC [Ref 90]. The Oil & Gas UK Guidelines on Relief Well Planning for Offshore Wells [Ref 29] should be consulted. A relief well may be needed if: • • •

Primary well control fails Secondary well control fails leading to a blowout Tertiary well control is unsuccessful, unavailable or unable to be used to effect a well kill, reentry and recovery of the blowing well

Wells with a long open hole section below surface or intermediate casing, might pose problems for relief well drilling, especially if the section is through a potential reservoir. Furthermore, a shallow casing shoe may make a relief well kill more difficult.

5.12

Dispensation / deviation during design Well-operators should have a system for designing wells that includes a dispensation/deviation policy. This system should specify who is responsible for reviewing and approving dispensation/deviation. If a well design does not comply with the well-operator’s internal or other relevant industry standards, specific dispensation should be sought. This application should: • • • •

Describe the dispensation requested Specify the well operation to which the dispensation applies, or the start date and length of time the dispensation will be in force, whichever is more appropriate Justify why it does not comply with standard Describe the risk mitigating measures to be taken

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After the request has been reviewed it should be submitted for formal approval. Where appropriate, this may require a competent person out-with the well planning team (e.g. technical authority, QHSE manager or managing director of the well-operator) and a senior representative of the installation duty holder (drilling contractor for a mobile rig). Dispensations should be reviewed by the well examiner under the well-operator’s well examination scheme. The dispensation should be closed out when it is no longer required.

5.13 5.13.1

Well operations planning General The planning phase of the well lasts from approval of the well design until operations start. It includes equipment specification, procurement, contracting and detailed operations planning.

5.13.2

Equipment procurement All equipment and material should be specified, manufactured, inspected and tested to the appropriate standards, with appropriate quality assurance, to ensure that it is fit for the intended purpose over the full well life cycle.

5.13.3

Rig contracting for mobile drilling units The suitability (pressure rating, etc) of the well control equipment supplied by the rig owner should be assessed by the well-operator as part of the contracting process. An independent inspection/audit of the equipment may be carried out. The installation owner’s SEMS should be reviewed, and a bridging document issued to align this with the well-operator’s SEMS. The installation owner’s well control procedures should be reviewed. A full well life cycle wellhead bending analysis and riser analysis, which covers local environmental conditions, should be available for floating operations. This analysis should take account of wellhead stickup. Limits for the allowable wellhead angle should be set that are applicable to the equipment in use. A full well life cycle riser stress analysis and conductor analysis, which cover local environmental conditions, should be available for bottom supported offshore operations.

5.13.4

Service Company – well control equipment The well-operator should assess the suitability of any well control equipment to be provided by a service company. For offshore wells, this information should be provided to the installation owner or operator to comply with their verification scheme for SECEs. See Step Change in Safety: Assurance & verification guidance suite [Ref 32].

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5.13.5

Information, instruction and training The detailed operations programme (e.g. drilling, completion, intervention) should describe in detail how the well objectives will be achieved while keeping risks ALARP. For well integrity, the planning should concentrate on: • •

Maintaining primary control of the well during all operations, Installation, removal, testing and monitoring of barriers during all operations.

Drilling contractor and service company personnel should be involved in the detailed planning, both to take advantage of their specialist knowledge and to encourage ‘ownership’ of the finished programme. The operations programme should be accepted by a representative of the installation duty holder, or site operator, as they have the primary responsibility for safety on the installation or borehole site. Drilling contractor and service company personnel should attend risk assessments, drill (or test, complete or intervene) the Well on Paper (DWOP) and/or pre-spud meetings.

5.13.6

Site surveying for offshore wells An adequate site survey should be carried out as soon as practicable after the well objectives and targets have been agreed. If shallow hazards are identified during the survey, the survey area may be increased, or the well location moved to avoid these hazards. The survey area should be large enough to cover potential relief well drilling locations. Offshore drilling hazard site surveys should be conducted in accordance with the guidance contained within IOGP Report No. 373-18-1 Guidelines for the conduct of offshore drilling hazard site surveys. [Ref 129] Reference may also be made to the HSE guidance Jackup (self-elevating) installations: review and location approval using desk-top risk assessments in lieu of undertaking site soils borings, Offshore Information Sheet No 3/2008 [Ref 15].

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6 Drilling The drilling stage begins when rig operations start on a new well or a sidetrack. It ends when testing or completion operations start, or when there is suspension of operations for an extended period, or well abandonment is initiated. Operations in this stage should be described by a drilling programme (the names of which will vary between companies) produced by the well-operator. The drilling programme should be supported by some or all of the following: • • • • • •

6.1

Well-operator standing instructions or manuals (e.g. drilling manual) Specialist programmes provided by service companies (e.g. mud programme) Well control bridging document that clarifies control barriers and clarifies roles and responsibilities and whose well control procedures are to be followed Drilling contractor manuals covering standard operational procedures (e.g. BOP running) Site or operation specific instructions (e.g. daily orders, section guidelines) An assessment of all subsurface risks that have been identified (see Section 5.2)

Primary control of the well/active barriers The drilling programme should explain how primary control of the well will be maintained. For overbalanced drilling, this means keeping the hole full of mud of a high enough weight to prevent an influx. The role of the drilling team, with respect to integrity of the well, should be to: • • • • • • • •

Monitor and predict the pore (formation) pressure in the well Measure the mud weight and maintain the specified weight Monitor and respond to gas levels (background, trip, connection) Check primary control with flow checks as needed Keep the hole correctly filled on all trips React immediately to suspected kicks by shutting-in the well Recognise and respond to lost circulation Ensure that there is always enough drilling fluid and weighting material available at the wellsite.

For operations that do not rely on overbalance, a mechanical active barrier is always needed to prevent flow from the well. For Managed Pressure Drilling (MPD) / Under Balanced Operations (UBO) this is usually a Rotating Control Device (RCD). The role of the well-operator, supported by equipment specialists, is to provide appropriate planning, testing, regular inspection and preventative maintenance for this equipment.

6.1.1

Pore Pressure monitoring Direct checks on the pore pressure compared to the mud weight may be made by checking that the well is not flowing. A flow could confirm that the pore pressure is more than the bottomhole pressure (if there is a permeable zone exposed in the well).

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The well should be monitored for flow whenever circulation stops during drilling (e.g. connection). The active surface volume of mud, also known as the Pit Volume Total (PVT), should be monitored as well as any flow indicators to check the well is not flowing. Connection gas levels which increase with depth may be an important indicator of increasing pore pressure compared to the bottomhole pressure. Indications of an underbalanced well (with no permeable formation exposed) could include: • • •

Cavings (‘sloughing shale’) size (large) and shape (splintery) Tight hole (increased torque and drag when moving pipe) Hole fill after connections or trips

Logging tools may also be used to directly measure the formation pressure. Pore pressure prediction while drilling means measuring the properties of the formations and plotting them to identify normal compaction trends with depth and any deviations from this. Properties that may be measured include: • • •

Drill rate, drilling exponent, DCS (mud logging) Gas reading, connection gas (mud logging) Sonic, density, resistivity, Measurement While Drilling (MWD) or wireline loggings

These predictions are based on the changing properties of clay rich sediments with depth. Clays are deposited with high water content. With burial, the increasing weight of the overburden forces water out of the sediments. With increasing depth, normally pressured sequences are denser and harder to drill. This trend is reflected by sonic, density and resistivity logs. In these normally pressured conditions, the pore pressure is equivalent to a seawater gradient. Where the adjacent geology prevents the expulsion of water from the sediment and limits normal compaction, overburden stress creates overpressured zones with a pore pressure greater than a seawater gradient. As a result, the sub-compacted sediments are easier to drill, are seen as less dense on sonic / density logs and less resistive to electricity on resistivity logs. These are recognised by deviations from a depth based normal compaction trend.

6.1.2

Monitoring mud weight Direct measurement of the returned mud weight (coming out of the hole) should be taken on a regular basis by the drill crew and checked by the mud engineer, if available.

6.1.3

Reacting to lost circulation Lost circulation is when mud (rather than filtrate) is lost to the formation, and is indicated by less mud coming out of the hole than is being pumped in. If the hole stays full of fluid, this is only an operational problem. If the hole cannot be kept full of mud, it becomes a well integrity problem for overbalanced drilling, because the active barrier cannot be adequately maintained or monitored. No new formation should be drilled before the active barrier (keeping the hole full of mud) is reinstated and can be maintained.

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If a pipe is plugged by lost circulation material the well cannot be circulated. This may prevent the active barrier (mud) being adequately maintained.

6.1.4

Loss/gain situation In some situations, especially HPHT wells, it is difficult to know for certain if the hole is losing mud or flowing. This is probably due to factors including: • •

The narrow window between fracture gradient and pore pressure results in alternating losses and gains. Thermal expansion or contraction and dynamic effects due to wellbore ballooning.

This potential situation should be considered when planning the well. Specific procedures should be put in place to cover this situation and should be discussed at pre-start meetings or training (e.g. pre-spud meetings or HAZIDs). The rig should be set up to measure the volumes returning from the well (e.g. calibrated trip tank) as accurately as needed. There can also be a masking effect due to the expansion of gas. Small downhole volumes may expand to large volumes at surface pressures. Long circulating periods may be needed to reduce gas levels at surface, and to confirm there is no influx.

6.1.5

Roles and responsibilities for primary control of the well The drilling supervisor should ensure that the relevant operations personnel are aware of their general duties, and any specific responsibilities to maintain primary control of the well at all times. See Oil & Gas UK Guidelines on competency of wells personnel [Ref 30]. The drilling contractor (informing the drilling supervisor) should: • • • • • • • • • •

Monitor that the hole stays full of mud Measure and report drilling parameters (e.g. a drilling break) that might indicate pore pressure increases React to and report increases or decreases in return mud flow React to and report lost circulation Monitor and report active mud volume Monitor and react to any flow at connections or flow checks and report actions Monitor correct hole fill during trips, and react to and report discrepancies Measure, record and report mud weight in and out Monitor and report any significant changes in hole conditions (torque, drag, etc) Monitor mud return flow rate

The mud loggers (informing both the driller and drilling supervisor) should: • • • •

Monitor and record active mud volume (independently) and report discrepancies Monitor and record mud flow back at connections and report discrepancies Monitor, record and report lost circulation Monitor and record system pressure loss and report discrepancies;

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• • • • • •

Measure, record and report drilling parameters (e.g. a drilling break) that might indicate pore pressure increase Monitor and report gas readings (background, connection and trip gas) Immediately report significant changes in gas readings Monitor and record torque and drag, and report any significant changes Estimate and report pore pressure estimates and record trends Monitor and describe cuttings, record in mud log and report significant changes

The drilling fluid (mud) engineer (informing the driller and the drilling supervisor) should: • • • •

Monitor mud properties and return flow for any abnormalities Co-ordinate the building and maintenance of the mud system Check and confirm all volumes of mud and chemicals on board Check and confirm calibration of mud balance

The MWD/logging engineer (informing drilling supervisor and wellsite geologist) should: • •

Monitor factors that may be pore pressure indicators (e.g. density, resistivity, sonic) Record trends and report significant changes

The wellsite geologist (informing the drilling supervisor) should: • •

Monitor and describe cuttings, record in geological log and report significant changes Compare actual formations with prognosis and report significant discrepancies

The well-operator should ensure that there is adequate communication between all parties concerned with well integrity, including the OIM. This may be helped by a rigsite organisation chart or schematic. The driller should be the focal point for communications.

6.2

Potential barriers The annulus potential barrier for all drilling operations is the rig BOP and associated equipment. Internal potential barriers include: • • • •

6.2.1

Drill pipe float valves (non-ported) in the BHA Dart sub installed above the BHA (to hold a drop-in dart) Internal BOP Stab-in manual valve (with suitable crossover for the drill string) at the drill floor

Roles and responsibilities for potential barriers The drilling contractor (communicating to the drilling supervisor) should: • • • •

Install, function and pressure test well control equipment according to agreed programme Monitor and maintain well control equipment Ensure suitable stab-in valves and circulating swage are available for all connection sizes and types in use Carry out well control drills and record results

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• •

Visually inspect surface BOP and report any leaks or problems Monitor shakers and report significant debris including pieces of rubber or steel

The mud logger (communicating to both the driller and the drilling supervisor) should: •

Monitor shakers and report significant debris including pieces of rubber or steel

The ROV crew (communicating to both the driller and the drilling supervisor) should: • •

6.3

Inspect the subsea BOP, record on electronic media, and report any leaks or problems Inspect marine riser where possible, record on electronic media, and report any leaks or problems

Pressure containment boundary The first part of the well pressure containment boundary is the surface casing, the cement in the annulus and the associated wellhead. Subsequent casing strings, annulus cement and casing hanger seals become part of the pressure containment boundary.

6.3.1

Roles and responsibilities for pressure containment boundary The drilling contractor (communicating to the drilling supervisor) should: • •

Visually inspect surface wellhead and report any leaks or problems Monitor annulus pressures for surface wellhead, record trends and report changes

The mud loggers (communicating to both the driller and the drilling supervisor) should: • • •

Monitor and record system pressure loss Report changes/trends that might indicate a hole in the drill string; Report any change in downhole conditions

The ROV crew (communicating to both the driller and the drilling supervisor) should Inspect seabed around well, monitor scouring and gas bubbles, record on electronic media, and report any leaks.

6.4

Other responsibilities for drilling operations The well-operator is responsible for well design and planning, including issuing the drilling programme, and managing all drilling operations. A rigsite drilling team is made up of specialists who have specific roles in the operations. It is managed by the well-operator’s representative (e.g. the drilling supervisor). The drilling contractor and third-party service companies should carry out the required operations as directed by the well-operator’s representative. The installation duty holder (the drilling contractor on a mobile drilling rig) has overall responsibility for:

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• •

The integrity of the installation The health and safety of all personnel on board

These responsibilities, for installation integrity and occupational safety, are very important, but are distinct from well integrity. Investigations into major accidents [e.g. Ref 115] have shown the importance of focusing on well integrity. All personnel on the installation, including the well-operator, have a duty of cooperation with the installation duty holder’s appointed OIM.

6.4.1

Other roles of the drilling supervisor In addition to managing the integrity of the well, the role of the drilling supervisor is to: • • • • • • • • •

6.5

Help the drilling contractor and rig OIM ensure that health and safety risks in well operations have been identified and reduced to ALARP Ensure the drilling contractor and third-party services have enough information to carry out their specific roles efficiently Monitor the competency of drilling contractor and service company personnel for their assigned roles Identify and report any circumstance that prevents the approved programme being carried out. Ensure a suitable programme amendment is approved and followed Manage any unplanned events so that remedial operations are carried out safely, and operations return to the planned programme as safely as possible Comply with specific conditions imposed by the regulator Ensure that all required personnel, equipment and materials are available on the rig in good time for all planned operations and foreseeable contingency operations Act as the focal point for all well-operator communications to and from the rig Ensure that the well is drilled in accordance with the drilling programme and any changes are managed through MoC procedures.

Installation and testing of barriers The installation, checking and testing of all barriers should be in compliance with the drilling programme. Any proposed changes should be covered by the well-operator’s MoC procedure.

6.5.1

Conductor Typically, the conductor is the first stage of the structural integrity of the well. The drilling programme will specify the setting depth and installation technique. Checks on important steps should be made, e.g.: • • • •

Connector makeup – (observation/approval by drilling supervisor and toolpusher) Shoe at correct depth – verified casing tally and count remaining joints Wellhead at correct height – running string tally. ROV check (before cementing) Cement quality (if not driven or jetted) – slurry density monitoring and sample collection

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• • • • •

TOC outside conductor – observation (for subsea wells, indicators such as mica flakes, may be added to spacer or slurry) The annulus outside the conductor may be tagged with a stinger, if necessary, to identify cement top and, if required, carry out a top up job Wellhead inclination and movement Good shoe cement – hardness of cement inside conductor On onshore wells – the integrity between the conductor and the cellar.

No pressure testing of the conductor is needed. The seabed around the conductor should be monitored by ROV, if visibility allows, to check that fluids do not broach to the seabed.

6.5.2

Surface casing The surface casing is attached to the wellhead which supports the BOP and is the first part of the well pressure containment boundary.

6.5.2.1

Barrier installation/checking The barrier depends on the quality of the annulus cement which is improved by: • • • •

Minimising hole wash outs/adequate clearance of mud from hole Adequate centralisation of casing at critical intervals API 65 part 2 [Ref 51] Quality of cement and quantity to fill annulus to desired TOC Suitable placement technique to place uncontaminated cement at shoe (calculated displacement volume or stab-in shoe or dual cement plugs)

The following verification checks on important steps should be made: • • • • • 6.5.2.2

Connector makeup – observation by drilling supervisor, casing contractor (if used) and drill crew Shoe at correct depth – verified casing tally and count remaining joints High pressure wellhead landing – loss of weight on landing and pull test Wellhead inclination and movement TOC – monitoring returns at wellhead, monitoring cement displacement pressures or post job logging to identify top

Barrier testing The casing should be pressure tested to check the integrity of the pipe body and connections after the BOP has been installed and before drilling out the shoe track. The test pressure should be higher than the maximum potential pressure to which the casing can be subjected (calculated during well design and included in the programme). The cement seal around the shoe should be tested by LOT or FIT.

6.5.3

Wellhead Casing hangers should be locked in the wellhead where assessment indicates this is required to prevent movement that could break the seals.

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Surface wellheads should have access to annuli (sidearms) for monitoring and bleeding off pressures; each should be fitted with two barriers. Surface wellheads that require the BOP to be removed to gain access for installing seal assemblies should not be used for new wells, because of the potential for well flow up the annulus without potential barriers. For existing wells, sidetracks, including those with emergency slips (where needed), on surface wellheads that require the BOP to be removed to gain access for installing seal assemblies: • •

• •

6.5.4

There should be adequate procedures to ensure the casing annulus is fully isolated before BOP removal The annulus should be flow checked for a long enough period to ensure that the well is stable before lifting the BOP. Well flow may occur many hours or even days after cementing and/or problems may occur mechanically sealing the annulus. The risk assessment should recognise that these situations may occur and address the possibility of well flow There should be barriers in place before lifting the BOP There should be a procedure for nippling down the BOP (including a lift plan as per Lifting Operations and Lifting Equipment Regulations (LOLER) [Ref 17] for a complicated lift)

Setting BOP The BOP system should be function and pressure tested before being put into operation. After landing, the connection between the BOP and the wellhead should be pressure tested to the highest potential pressure that may be experienced in the next well section. Information needs to be passed to offshore personnel about: • •

Shearing capability of the shear rams [Ref 39]. The procedures in place if a tubular is across the BOP and cannot be sheared, and the well needs to be closed in

Inner barrier Active

kill weight mud

Potential

IBOP (drilling) Stab-in (connection)

Shearing

Annulus barrier kill weight mud

Pressure containment boundary casing(s) cement outside casing

valve BOP

wellhead casing hanger seals

BSR

Table 6. Well Barrier Matrix Example – Overbalanced Drilling with BOP

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If a well barrier matrix table (Table 6) or a schematic (Figure 4) is used, it should be updated as each casing string is installed.

Figure 4. Example Barrier Schematic for Overbalanced Drilling Figure 4 (5.8.1) from NORSOK D-010 Well integrity in drilling and well operations (Rev. 4, June 2013) [Ref 110] are reproduced by Oil and Gas UK in this Issue 4 of the Oil and Gas UK Well Integrity Guidelines under licence from Standard Online AS 11/2013 © All rights are reserved. Standard Online makes no guarantees or warranties as to the correctness of the reproduction. In any case of dispute, the NORSOK original shall be taken as authoritative. See www.standard.no.

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6.5.5 6.5.5.1

Intermediate casings Cementing operations The active annulus barrier during intermediate cementing operations consists of the mud, spacer and liquid cement slurry. If the spacer and slurry are heavier than the mud, the well will be overbalanced until the slurry stops transmitting hydrostatic pressure provided there are no losses during the placement and the annulus is kept full.

6.5.5.2

Installation/checking of casing and cement barrier The casing, plus the cement around the shoe, forms the next section of the pressure boundary. This cement quality depends on: • • • • • • •

Setting the casing shoe in a gauge section of impermeable formation Adequate removal of mud from hole Adequate centralisation in cemented sections Quality of cement, and quantity to fill annulus to desired TOC Cement slurry recipe Suitable placement technique to place uncontaminated cement at shoe (calculated displacement volume with dual cement plugs) An accurate placement temperature to inform the cement slurry design.

Reference may be made to API S65- part 2 [Ref 51]. The following checks on important steps should be made: • • • • • •

6.5.5.3

Review slurry properties, optimising placement techniques, pump rates, displacement rates, spacer design Laboratory test of slurry recipe with materials from the rigsite (a check by an independent laboratory may be considered) Connector makeup/clear acceptance criteria and responsibilities Shoe at correct depth – verified casing tally and count remaining joints Casing hanger locked in wellhead – loss of weight on landing and pull test Top of cement (TOC) o monitor mud returns to rig o monitor cement displacement pressures o post-job logging to identify the TOC may be considered

Testing of the casing barrier The casing hanger seal assembly should be pressure tested. The casing should be pressure tested to check the integrity before drilling out the casing shoe track. Test pressures should be higher than the maximum potential pressure to which the casing can be subjected. These values should be calculated during well design and included in the programme.

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The effects of heavy drilling fluid inside the casing should be considered when specifying the test pressure.

6.5.6

Production casing The production casing is the innermost casing at the wellhead. It would be exposed to formation fluids during testing or production if the tubing leaked. In gas lifted production wells (Section 8.5.1) the casing is exposed to hydrocarbon gas under pressure. It is vital that optimum installation is achieved to ensure protection of the outer annuli over the life time of the well. Therefore, additional consideration should be given to: • • •

6.5.6.1

Good centralisation, avoiding over-gauge hole, especially in reservoir The cement quality, additives and design (including transition time and fluid loss rates) to reduce gas migration The height of the planned TOC above the top reservoir

Casing/cementing operations If a permeable hydrocarbon-bearing formation is exposed during a casing running operation, the dangers of a kick are increased. These hazards should be assessed during the planning stage and then reviewed when actual conditions (hole, weather, etc) are known. Monitoring the surface mud volume and comparing the actual displacement with calculated values is very important. An agreed response to any discrepancies should be provided. If there is a kick during casing running or cementing, an agreed well control procedure is needed. This is a non-standard operation, and these are not always adequately covered by procedures, training or drills. Specific well control decisions need to be considered before running casing: • • •

How the well will be closed in (special casing rams or annular) The circumstances in which the shear rams would be used What emergency procedures to use if the shear rams cannot cut the casing

If the cement is to be displaced by non-kill weight mud or brine, then a provision (full-bore valve) should be in place to permit removal of the cement head to carry out remedial operations (e.g. wireline set bridge plug). If a full-bore valve cannot be installed below the cement head, then either the cement should not be displaced with non-kill weight mud, or the risks should be evaluated, and mitigation measures put in place. 6.5.6.2

Installation of casing and cement barrier Production casing that may be exposed to hydrocarbon gas should have gas tight (premium) connections. It should be assumed that the casing will contain gas, unless it is only to be used for injection or an exploration well that will be abandoned without testing. Therefore, in addition to the points listed for intermediate casing in the previous section:

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• • •

•

6.5.7

The makeup of the connections should be monitored (torque/turn equipment) to check that the connections are made up correctly to make the gas tight seal High specification casing or stainless materials may require special handling and make up to prevent damage that would reduce integrity If the cement in the annulus is planned to provide a long-term seal, consideration should be given to direct measurement of the TOC (cement bond log) and quality of the cemented section (cement evaluation log) Remediation plan if the TOC does not reach the planned height

Inner barriers During conventional drilling the hydrostatic pressure of the mud in the drill string is the active inner barrier. If the drill string is not kept full, or the mud weight is too low, fluid can flow up the drill string. A potential inner barrier while drilling is either the top drive safety valve or kelly valve. These valves should be rated to the same pressure as the BOP. Another inner barrier is an inside BOP, or Internal Blowout Preventer (IBOP), which is either a surface installed back pressure check valve (e.g. Gray valve), or a drop-in dart which seats in a landing sub positioned above the drill collars in the drilling assembly (dart sub). Float valves should be included in the BHA, in addition to any surface valves or IBOPs. Ported float valves (with a hole) do not constitute a barrier. Non-ported valves may wear and cannot be tested in use. During connections and trips, potential inner barriers should be provided by manual valves that are stabbed into the top of the drill string and made up. There should be a suitable valve for all elements of the drill string and a way to install it quickly. If valves are installed manually, this should be practiced in drills. Mud provides an active barrier, and the casing should be topped up with mud during running. The level should always be high enough to prevent an influx if the floats fail. During casing running, float valves run in the shoe track may be considered inner active barriers. If so, consideration should be given to pressure and function testing before running. Potential inner barriers are provided by crossover/valve sets or internal packers. These should be rated for any potential differential pressure and installation methods should be tested to ensure they can be put onto the casing quickly.

6.6

Managed Pressure Drilling / Under Balanced Operations The annulus active barrier for MPD / UBO may be an RCD. There are other names for equivalent equipment. The RCD seals the annulus while allowing the drill string to rotate and reciprocate. For MPD, the differential pressure is low, and the fluid in the well is drilling mud, therefore failure of the RCD will result in a leak of drilling fluid and a kick. The rig BOP is a potential barrier. Inner barriers are important because the mud in the drill string is not an active barrier. Tested nonported float valves should always be run.

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For Under balanced drilling (UBD), the bottomhole pressure is designed to be less than the pore pressure, and so any permeable formations will flow during drilling. There are likely to be hydrocarbons in a release if the active barrier fails. The rig BOP is a potential barrier.

Active

Inner barrier

Annulus barrier

Pressure containment boundary

Pump pressure (drilling)

Drilling fluid &

Casing(s)

RCD

Cement outside casing

Check valves (connection)

Potential

Shearing

IBOP (drilling) Check valves (connection)

Wellhead BOP

Casing hanger seals

BSR

Table 7. Well Barrier Matrix Example – MPD/UBO (see above text)

6.7

Drilling before BOP installed Before the BOP is installed, the active barrier is provided by the drilling fluid, but there are no potential annulus barriers during well operations. These operations include: • • •

Installing conductor (e.g. drill, cement, drive or jet) Drilling surface hole Running and cementing surface casing

If there is a riser back to the rig (jackup with riser and land operations), and the conductor shoe is strong enough, mud may be used to drill with returns to the rig. This should not be done if there is any risk of a shallow gas kick, as a riser will bring the gas directly to the rig. It is possible to connect a riser from a floating rig to the wellhead (pin connector) without the BOP. This should not be done, because it takes away the safety feature of being able to move the rig away quickly from above the well if there is a shallow gas flow to the seabed. Options exist for better primary control when drilling top hole for subsea wells: • • • •

Drill with weighted mud and discharge it at the seabed Drill with weighted mud and subsea pumping system to return mud and cuttings Drill with seawater and sweeps A small diameter pilot hole may be drilled to check for shallow gas. If there is a shallow gas kick in the pilot hole, the smaller diameter increases the chances of a dynamic kill by pumping kill mud at a high flow rate

For all subsea drilling operations before the BOP has been installed, the following precautions should be taken:

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• • • •

Continuous bubble watch with ROV Observation of sea from the rig Preparation to move the rig away from the well (drills)

Inner barrier Active

Potential

Shearing

Kill weight mud IBOP (drilling) Stab-in valve (connection)

Annulus barrier

Pressure containment boundary

Kill weight mud

None

None

None

Table 8. Well Barrier Matrix Example – Top Hole Drilling (see above text)

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7 Well Testing 7.1

General This phase covers temporary production or injection operations to gather information. This may be a high-risk activity and is therefore included in the well life cycle considerations. The following is based on offshore operations; however, the general principles apply to onshore operations. Offshore extended well tests should be considered as a ‘temporary’ completion under the completions section. For these guidelines, it is assumed that an offshore production installation will use a completion and the installation production facilities. Section 8 (completions) covers these operations. If well testing operations include stimulation activities refer to Section 11.7 for guidance.

7.2

Primary control of the well/active barriers If there is kill weight fluid filling the well, this is the active barrier when running in the test string. The fluid level should be monitored to ensure the hole stays full, especially if there is open hole. If the plan is to displace the cased hole to light fluid (less than kill weight), the active barrier will be the casing, liner, plugs inside casing and liner top packer. These barriers should be inflow tested before displacement. The fluid level in the well and the surface volume should be monitored as a check on the integrity of these barriers. If the reservoir is not cased (openhole), a subsurface barrier valve (formation isolation valve) should be installed if the well is to be displaced to light fluid. When the test string is installed, the active annulus barriers are typically the completion or Drill Stem Test (DST) packer plus the BOP ram closed around the slick joint (below Subsea Test Tree (SSTT) for floating rigs). During the well test there is no active inner barrier, as formation fluid is allowed to flow to surface. When pulling the test string after the test, the active barrier will be the kill weight fluid in the hole. The hazards at this stage are greater than for drilling operations because: • • •

7.2.1

The reservoir is open and is likely to contain hydrocarbons There may be pockets of hydrocarbons remaining in the well or test string The design of the test string may not allow full circulation of the well

Pressure containment boundary The pressure containment boundary is formed by the: •

Cemented production casing and/or liner

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• • •

7.2.2

Casing hanger landed and sealed in the high-pressure wellhead Rig BOP with ram closed around string, slick joint or SSTT slick joint Riser and flowhead

Potential barriers during well testing The inner potential barriers during well testing include: • • • •

The main tester valve Other test string valves Subsea test tree valves Surface test tree valves

The annulus potential barrier is the rig BOP (other rams and annulars).

7.3

Responsibilities for testing operations The following is based on offshore operations; however, the general principles apply to onshore operations. The well-operator is responsible for well integrity during testing. The primary duty of the well-operator’s representative (e.g. well test supervisor or drilling supervisor) is supervising the installation, checking, testing and monitoring of well barriers to ensure well integrity. The well-operator is responsible for planning and managing the well test operations. The well-operator should ensure that the additional well control equipment used in testing is suitable for the planned operations. This will involve reviewing the contractor’s procedures and standards. Offshore, this information should be provided to the safety case duty holder for verification [Ref 32]. Well test equipment should be classed as SECEs. The well-operator should also ensure that all personnel with safety critical functions are competent to carry out their tasks, and that they have suitable information and instruction concerning the well test. Refer to the Oil & Gas UK Guidelines on competency for wells personnel [Ref 30]. The installation duty holder should ensure that third party equipment can meet the installation’s performance standard for well test equipment. If it is equipment which is to be used on the installation for the first time, then the independent competent person should carry out enough verification activities to ensure it is suitable prior to use. The installation OIM should: • • •

Be involved in the well test planning Be aware of the installation and commissioning of the well test package Check that it has been installed as per the Piping and Instrumentation Diagram (P&ID) seen by the Independent Competent Person (ICP)

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• •

7.3.1

Check that any post-installation changes have gone through the supplier’s MoC procedure and been verified by the ICP Check that the drilling contractor is aware of changes and any further mitigation measures needed

Well control procedures during testing The well control procedures should be reviewed to ensure that the proposed well testing operations are covered. The review should cover: • • • • • • • • • •

7.4

How the well will be opened up to flow and shut in, in order to conduct the well test How to circulate through test string (running and retrieving) The potential for trapped hydrocarbons in string and annulus after testing Which ram or annular should be used to close the well in on different test tools The circumstances in which the shear rams would be used The requirements to release the rig from well due to unsuitable weather on a floating installation Procedures if screens or fired TCP guns, or components that communicate from inside to outside the string, are at the BOP Any requirements for wire cutters at the rig floor (e.g. for cables) Requirement for Slow Circulating Rates (SCR) at different times How the well will be killed or perforations isolated in order to recover the test string

Well test planning Well test planning should start as soon as the well objectives are known, to ensure specialist equipment is available and the risks are thoroughly assessed. The information needed for planning well tests includes: • • • • • •

General well information (see 9.2) Predicted reservoir fluids (oil, gas, H2S, H20 etc) Reservoir temperatures and pressures Objectives of the test Potential for solids production Predicted flow rates and productivity

There should be an Emergency Shutdown (ESD) system to close in the well. The location of the controls, and the authority to use them, should be considered during planning and operations. Well control equipment planning requirements are similar to the well intervention phase. See section 11.3.2 for further details. Detailed test planning should include input from the installation duty holder and the main (downhole tools and surface equipment) service companies. The final programme should be reviewed and accepted by the offshore installation duty holder (or the BSOR site operator for onshore). A tubing stress analysis should be carried out on the test string.

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7.4.1

Risk assessment and mitigation Hazards, which can be more immediate during production well testing, are due to the following: • • • • •

There are volatile hydrocarbons at surface Potential for H2S and other dangerous substances There is an open reservoir containing pressured hydrocarbons The active barrier (fluid column) has been replaced by potential barriers at surface Testing requires a lot of temporary people and equipment (including well control)

Consideration should be given to the prevention of hydrates, and the consequences if hydrates do form. An initial risk assessment and HAZOP should be carried out as soon as the surface conditions for the test have been calculated using predicted reservoir conditions. Both the drilling contractor and the testing service companies should be involved in the planning/risk assessments. After the well has been drilled and evaluated, the well test plan and risk assessment should be reviewed to ensure they are adequate for the actual conditions in the well. During the well test, actual flowing conditions will be recorded. These should be compared with the predicted values, and the risk assessment reviewed if there are differences. In addition to well integrity, the risk assessment should also consider the risks of leaks from the surface well test equipment, as this is a major hazard. Some additional precautions that may be considered are: • • • • • •

Additional gas detectors (hydrocarbons and H2S) in the well test area Temporary deluge and fire-fighting equipment in the well test area Fire watch in the well test areas Cooling for rig sides from flare radiant heat Special precautions for methanol/glycol (if used) Sand monitoring and control equipment

Erosion may be caused by entrained solids. Consideration should be given to erosion modelling and physical measurement of pipe wall thickness (e.g. at critical elbows) to detect wear and erosion during/after flow periods, and flow simulations through temporary packages to determine maximum acceptable flowrates. This is particularly relevant to testing and cleaning up high rate gas wells. Small bore pipework and fittings such as needle valves may be susceptible to wall loss and failure due to erosion.

7.5 7.5.1

Installation and testing of barriers Running liner or lower completion Running the liner or lower completion may be treated as part of the drill phase (operations to run a solid liner or casing are covered in Section 6.6) or as part of the test phase.

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The risks are higher because the reservoir is exposed in open hole. There is a danger that any gas in the well (especially high angle or horizontal holes) can migrate upwards when there is no circulation. If the pipe rams do not seal around the liner or casing, the potential annulus barrier is provided by the annular preventers or casing rams (unless slotted liner or screens are being run). The ability of the shear rams to shear the casing or liner should be considered. If the BSRs are not capable of shearing the pipe, there should be alternative secondary well control procedures to cover this situation. The presence of an inner washpipe string should be considered when assessing the shearing capability of the BOP. Alternative arrangements may include running or stripping the string below the BOP on drill pipe so that pipe rams can be used. A triple bushing that can connect to the liner, inner string and surface stab-in valve may be considered.

7.5.2

Liner lap If the well is displaced to a light fluid before running the test string, the active barrier is no longer the fluid column (see Section 8.1.1). The test packer should be set in the casing above the liner top, if possible, to put the well barrier above the liner lap. A leak past the lap will not then affect the integrity of the well. If the liner lap is above the test packer, it becomes an active annulus barrier. The well-operator should ensure that it will not leak during the well test. It should be adequately tested before the test string is run in the hole.

7.5.3

Test string and tubing The test string should be considered in light of the ability of the pipe rams to close around it, and the capacity of the shear rams to cut through it. If standard well control procedures are not suitable, specific procedures should be agreed with the installation duty holder and put in place. This may need special training and drills to ensure adequate well control. The tubing is an active barrier. A tubing leak above the BOP would be a major hazard because it contains pressurised hydrocarbons. The tubing should be checked by pre-shipment inspection, and a visual inspection of the pipe, tools and connections as it is being run. The coupling manufacturer’s recommended makeup procedures and torque specifications should be reviewed and applied before running. The makeup of the tubing connections should be monitored (torque/turn equipment) to check that the connections are made up correctly to ensure a gas-tight seal. Any anomalous connections should be rejected. High specification tubing or stainless materials may require special handling and makeup to prevent damage that would reduce integrity.

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The complete string should be pressure tested internally from below the depth of the packer to the surface test tree. This will also test the tools that are part of the string.

7.5.4

Annulus barriers (packer and BOP) The active annulus barriers are the test packer and the BOP sealing around the test string. Rams may need to be changed to suit the tubulars in use. BOP elastomers should be checked to confirm they are compatible with predicted flowing conditions, especially temperature. The internals of the casing at the setting depth may be scraped to provide a better surface for the packer elements to seal against. A check of the packer setting depth is by a tally of the test string. This may be confirmed by logging radioactive tags in the casing or liner and test string. After setting the packer, it should be pressure tested from below to above the maximum bottomhole pressure, if possible. The potential casing wear at the proposed setting depth should be considered, especially in wells where multiple sections have been drilled through that casing. The rig BOP should be function and pressure tested before running the test string. The BOP should then be closed around the test string (or SSTT) to provide the second barrier. Before starting the test, the annulus should be pressured up (taking care not to exceed operating pressures for test tools or burst disc ratings) to test the external integrity of the string and the BOP closure on the test string If annulus pressure operated tools are included in the test string, the casing pressure test should be greater than the highest operating pressure. During well test operations, the pressure in the annulus should be monitored to identify if the packer is leaking. This annulus may be kept at a specific pressure to keep the main tester valve open during flow periods.

7.5.5

Inner potential barriers (tester valve and surface tree) The tester valve is the main working valve during a well test, opening to allow flow, and closing to shut the well in for pressure build-up in the reservoir. In an emergency it would be used to shut the well in, but unless it can be tested from below, it cannot be fully qualified as a barrier. There are normally other downhole valves that may be used as barriers. Some are manipulated by direct annulus pressure and some by cycling. Some open a port to the annulus after closing to allow hydrocarbons to be displaced out of the tubing by mud or brine. If these are pressure tested from below, they may be qualified as barriers. Tests carried out from floating rigs need a means of sealing the well and allowing the rig to move off in the event of bad weather. This is provided by a SSTT which lands in the BOP with a disconnect sub. This allows the rig to release from the well. The dual in-line valves in the SSTT should be tested in the direction of flow before running.

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The inner potential barrier at surface is the test tree. The flow wing valve is a fail-safe valve held open by hydraulic pressure. This should be tested from the well side. There should be an ESD system for this valve so that it can be closed remotely if there are indications of a problem (or there should be a dedicated isolation valve). This should be function tested as part of the surface equipment rig up and test. The other valves on the test tree (swab and kill wing) should also be tested from the well side.

Inner barrier

Active

NONE

Annulus barrier

Pressure containment boundary

BOP ram

Casing(s)

Test packer

Cement outside casing Wellhead

Main tester valve Potential

Shut-in valves

BOP annular

Riser from BOP to rig on floating rigs

SSTT valves

Shearing

SSTT ball valve or dedicated shear valve1

Casing hanger seals

BSR2

Surface test tree

Table 9. Well Barrier Matrix Example – Well Testing Note 1 – If wireline is run through the test string, these valves may be used to cut the wire in an emergency. Note 2 – The test string should be designed to put a shear sub opposite the BSR when the string is landed. The shear capability of the BSR should be reviewed to check that the ram will cut that shear sub. The preferred emergency release is to close the SSTT dual in-line valves, disconnect the test string at the SSTT and pick up the string above the BOP rams. The BSR (as a blind ram) can then be closed as an additional barrier. There may be test tools in the string that cannot be sheared by the BSR. These situations should be reviewed during the risk assessment or HAZOP and alternative procedures should be in place to cover these situations. Barrier matrices or schematics should be produced for each stage of the test: • • •

Running in test string Testing Pulling out test string after killing the well

The use of a valve status board on the rig floor is considered to be good practice to help monitor the well test system.

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7.6

Well testing operations There should be extra (compared to making up drill pipe) emphasis on the makeup and verification of the tubing connectors, because they are an active barrier when the well is flowing. SCRs (see Section 7.3.1) should be taken and recorded, as required.

7.6.1

Perforating For cased hole tests, the casing or liner needs to be perforated. This may be done using perforating guns on wireline, drillpipe or coiled tubing, either before the test string is run, or through the test string. More commonly the TCP guns are run as part of the test string. Risks of premature detonation should be considered in the risk assessments, including detonation in the riser. Consideration should also be given to ensuring the test packer has not been unset by shock loads due to perforating gun firing. Procedures need to be considered if problems develop when running the guns through the rig BOP. This is especially important if long strings of guns are to be run. Special precautions need to be taken if the guns are retrieved from the hole (rather than dropped and left downhole) as some of the charges may not have detonated. Special care will be needed when pulling the fired guns through the BOP as the holes in the guns will bypass the pipe rams and the reservoir will be open.

7.6.2

Flow and shut-in periods Conditions should be carefully and constantly monitored during flow and shut-in periods (both surface and downhole shut-in) including surface pressure/temperatures, pressures both sides of the choke, annulus pressure, flow rates, fluid types, condition of flare, etc. The need to inject glycol and methanol to mitigate the risk of hydrate formation should be considered. The flow should be monitored for sand production and the efficacy of any sand filters, if used.

7.6.3

Killing the well After the final shut-in, the well should be killed before pulling the test string. There should be detailed procedures on displacing the well back to kill weight fluid and ensuring there are no pockets of hydrocarbons left in the well. It is vital to check the hole fill when pulling the test string, because the reservoir is open. This is especially important for sections of the string that cannot be sheared.

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7.6.4

Suspension of operations, plugging and abandonment If another test is to be carried out in the same well, the perforated section should be plugged off. This may be done with a mechanical plug as a temporary measure while another test is carried out. For longer term suspension of operations, plugging and abandonment, permanent cement plugs should be set as described in Oil & Gas UK Well Decommissioning Guidelines [Ref 24].

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8 Completion The completion stage is between drilling or testing the well (or finishing a workover) until it is ready for commissioning as a production or injection well. It may be considered in three parts; lower completion, upper completion and xmas tree. If completion operations include stimulation activities refer to Section 11.7 for guidance. Responsibilities in this phase are similar to the well test phase, refer to section 7.3. Well control equipment planning requirements are similar to the well intervention phase. See section 11.3.2 for further details. The well hazards are usually greater for completion operations than for drilling because: • • • • • •

8.1 8.1.1

The reservoir is exposed if there is open hole (uncased) For producers, and some injectors, the reservoir will contain hydrocarbons Horizontal reservoir sections may contain gas which can migrate to surface The design of some lower completions will mean the BOP is not a potential barrier when the lower completion is opposite the BOP rams The design of some upper completions prevents conventional circulation The main potential barrier, the rig BOP, has to be removed in order to be replaced by a xmas tree

Primary control of well/active barriers Fluid column For overbalanced operations the active barrier is keeping the hole full of kill weight fluid. During completion operations, drilling mud may be replaced by kill weight brine which does not have fluid loss control, and so the risk of losing fluid to the formation is higher. With clear brine, close monitoring may be needed to ensure the hole stays full of fluid if the reservoir is open. Contingency plans may be needed if the losses are too high to control. If a cased hole is displaced to a light (lower than kill weight) fluid, the active barrier is no longer the fluid column. It is the casing or liner, and any mechanical plugs that have been installed. There are increased hazards during displacement operations needing careful planning and supervision (see Section 8.6.1). Shoe tracks should be treated as open-ended casing, unless they are designed and can be tested to demonstrate they are an adequate barrier to flow from the well. Refer to Section 4.3.13.

8.1.2

Mechanical barriers A subsurface barrier valve (formation isolation valve), or equivalent, may be run on top of the lower completion (especially for gravel pack or similar openhole completion equipment techniques). After successful testing, this becomes an active barrier. If the well is displaced to light (less than kill weight) fluid, it becomes the only active barrier when running the upper completion.

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The potential for the subsurface barrier valve being damaged, or opened inadvertently, should be considered during planning and risk assessments. The bottom profile of a cleanout string should be incapable of opening a subsurface barrier valve.

8.1.3

Removing the rig BOP/installing the xmas tree When removing the main potential barrier (the rig BOP) active barriers (in addition to the completion fluid) are needed. There should be at least two independent, tested barriers for all flow paths from the reservoir to surface. There should be deep-set barriers (e.g. completion packer and tubing plug) as well as near-surface barriers (e.g. tubing hanger and seals plus tubing hanger plug). These should be tested in the direction of flow where possible. The well-operator should consider a contingency plan in case one or more barriers fail during the operations to replace the BOP with a xmas tree.

8.2

Pressure containment boundary While installing the upper and lower completions the pressure containment boundary is the same as for drilling and testing operations. When completion operations are finished, the xmas tree will have replaced the rig BOP as part of the pressure containment boundary.

8.3

Installation and testing of barriers The important elements from a well integrity standpoint include: • • • • •

Completion packer Tubing Tubing hanger DHSV Any device installed with the tubing that permits communication with the annulus (e.g. sliding sleeves, gas lift mandrels and injection subs)

Operations for installation and testing of barriers for the lower and upper completions are the same as in Section 7.5 – Installation and testing of barriers in the well test phase, except for the artificial lift and downhole safety valve aspects.

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Inner barrier

Active

Kill weight fluid Internal plug

Potential

Stab-in valve

Shearing

BSR2

Annulus barrier

Pressure containment boundary

Kill weight fluid

Casing(s)

Formation valve

isolation Cement outside casing

BOP1

Wellhead Casing hanger seals Liner, cement and lap

Table 10. Well Integrity Matrix Example – Upper Completion Running Note 1 – Pipe ram or variable bore rams (VBR) if they fit tubing in use, otherwise annular preventers. If there are cables (including fibre optic) or control lines being run with the tubing, the adequacy of the annular to seal the well should be reviewed and tested if required. With screens or slotted liner across the BOP, it is not a potential barrier Note 2 – BSR if it can cut the tubing (plus lines if applicable); otherwise casing shear rams to cut, plus a blind ram to seal the well.

Inner barrier

Active

Kill weight fluid1 Deep set plug Tubing hanger plug

Potential

None

Shearing

Not required

Annulus barrier

Pressure containment boundary

Kill weight fluid1 Completion packer

Casing(s)

Cement outside casing Tubing hanger and Wellhead seals Casing hanger seals Liner, cement and lap

Table 11. Well Integrity Matrix Example – Removing the BOP Note 1 – Kill weight fluid may be in both the tubing and annulus. However, this may not be possible to monitor during this operation. There should be two independent, tested barriers in place before BOP removal operations are started.

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8.4

Completion design and planning The construction of a development well (i.e. drilling plus completion) may be designed and planned as one operation. Risk assessments and DWOPs should consider the overall construction process. Some well-operators have a definite split between the drilling and completion stages. Close cooperation is required between the teams and responsibility for overall well integrity should be made clear. A ‘complete well on paper’ (CWOP) may be carried out for the separate stage of the operations. The starting point for the completion design will be the subsurface conditions anticipated through the life cycle of the well, and operations planned for the well. Other factors to be considered include: • • • •

Temperature, pressure, fluid type Injection pressure from water/gas Suspension of operations, plugging and abandonment Potential changes in condition during the well life cycle (e.g. tertiary recovery schemes)

Where applicable, equipment should be specified, manufactured, inspected and tested to the appropriate standard (e.g. [Ref 73 and Ref 42]). All completion equipment should be qualified for its planned service life. This may require specific testing where API or ISO standards are not adequate.

8.4.1

Packer The packer should be designed for the anticipated downhole conditions of differential pressure, temperature, production or injection fluids (including entrained solids and/or gas) and packer fluids, including hydrocarbons if used for lift gas. Consideration should be given to full life cycle conditions. For example, near end-of-life conditions should also be assessed when the reservoir may be depleted leading to a higher differential pressure across the packer. The packer should be set in cemented casing. The packer should be set as close to the reservoir as practicable, ideally above any production liner lap, in which case the packer is an active barrier between the liner lap and the surface. If the packer is to be set below a production liner lap, the liner lap needs to be adequately tested. In some completions the upper completion may be stabbed into a liner top packer. The seals on the liner top packer become an active annulus barrier for this style of completion.

8.4.2

Tubing For completions that will contain hydrocarbons, the tubing and equipment connectors should be gas tight under expected load conditions. Any completion components (e.g. nipples) should be designed for the same loadings as the tubing, to ensure the components are not a weak link in the completion.

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Tubing and connectors should be designed for worst case burst, collapse, tensile and triaxial loading. For deterministic calculations of loads and ratings, the well-operator-approved design factors should be used. Table 12 has examples from NORSOK Standard D-010 Rev4, June 2013 [Ref 110]:

Burst

1.1

Collapse

1.1

Axial

1.25

For well testing a design factor of 1.50 should be used to cater for pulling the packer free at the end of the test.

Tri-axial

1.25

Tri-axial design factors are not relevant for connections

Table 12. Tubing Design Factors (taken from NORSOK Standard D-010 [Ref 110]) The well-operator may use existing approved internal standards. Special handling requirements for high specification (e.g. corrosion resistant alloy) tubing should be considered at the planning stage, as well as equipment for making up connectors correctly. The potential tubing movement should be calculated for all anticipated temperatures and service loads for the well. The resultant loads on the packer and tubing hanger should be included in the analysis. Polished Bore Receptacles (PBR) and floating seals may be used to avoid high loads due to tubing movement. The completion design should permit the installation of a mechanical plug deep in the completion, just above the reservoir. Consideration should also be given to the potential requirement to plug the completion as a precaution against well collision.

8.4.3

Tubing hanger This is a second active annulus barrier for development wells. An important factor is to be able to monitor the annulus pressure below the tubing hanger.

8.4.4

Downhole Safety Valve The DHSV is an inner potential barrier designed to shut-in the well in the event of a catastrophic failure of the xmas tree. Requirements for DHSV are set out in the relevant standards [Ref 74 & 72].

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The DHSV should be appropriate to the functional requirements of the well. In water injection wells it may be acceptable to install injection valves (rather than surface-controlled valves), provided a risk assessment concludes that it is safe to do so. The depth at which the valve is set will be decided by assessing the potential risks. For platform wells, the most severe risk is a catastrophic loss of the platform to which the well is attached (cratering). Other factors include: • • • • • •

Hydrate formation capability Inventory of hydrocarbons above the DHSV Adjacent slot drilling activities and well shut-in requirements Valve specification Operability Recovery method

Land wells designed for production using beam pumps, or any well with a mechanical downhole drive mechanism (e.g. Progressive Cavity Pump (PCP)) cannot have a conventional DHSV installed. At the design stage, well integrity should be reviewed and any measures necessary to reduce risk to ALARP implemented. For sub-hydrostatic sweet oil wells produced using a beam pump a surface stuffing box and control valves will typically be adequate.

8.4.5

Wellhead The well-operator should have a policy covering surface wellhead sidearm valve and plug configurations. These should have the same ratings as the wellhead. Wellhead sidearm valves should be configured to enable isolation and pressure bleed off for removal or changeout of instrumentation or gauges. Assemblies should be mounted directly on to sidearms to minimise the risk of damage to extension pipework. Configuration should be such that a sidearm valve can be closed to effect isolation should the instrumentation or gauge assembly be knocked off the wellhead. Surface wellheads should usually be equipped with two side outlets for each annulus between casings. Wellhead components above the surface casing housing should have a valve removal (VR) capability. Protection sleeves or plugs should be fitted to any VR profile on an annulus outlet which sees regular flow (e.g. gas lift wells). Where annuli are exposed to open formations, both casing spool side outlets should have valves fitted, and should not be blanked off. This is to allow circulation across the annulus. For annuli not exposed to open formation, the minimum configuration should be that at least one side outlet has a valve installed. If sidearm valves are likely to be cycled on a regular basis, a second valve should be installed on the outlet, and the outer valve used preferentially. The tubing head should have both outlets fitted with double valve configurations. The outlets, valve apertures and annulus between casing and tubing should be sized appropriately to allow well kill.

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If wells are gas lifted, the surface wellhead should be designed to reduce the risk of loss of ‘A’-annulus gas containment to ALARP.

8.4.6

Xmas tree The xmas tree should be thoroughly pressure and function tested before opening up the well to flow or injection. The testing should include the connection to the wellhead and all associated equipment and control systems. The xmas tree valves should be hydraulically tested from below. Since there are multiple valves, the procedures should detail the sequence of testing to ensure all valves are tested to the required pressure. The function testing should include the primary control for all the systems plus the emergency shutdown systems.

8.5

Artificial lift The need for artificial lift should be assessed during the well design stage. The well integrity and barriers should be considered as part of this assessment. The main types of artificial lift include: • • • • • •

Gas lift – gas injected into ‘A’ annulus and then into tubing via a gas lift valve Electric submersible pump (ESP) – downhole pump powered by electricity Hydraulic submersible pump (HSP) – downhole pump powered by fluid Foamer injection and velocity strings Beam pump – downhole pump connected to surface beam pumping unit (nodding donkey) by rods in onshore wells Progressive cavity pump (PCP) – generally used onshore (replacing rod pumps)

The means of artificial lift should be reassessed on a regular basis to confirm that risks relating to the selected options are ALARP, and that any new developments in technology or understanding of hazards are considered.

8.5.1

Gas lift Gas lift systems fill the ‘A’ annulus with hydrocarbon gas under pressure. This volume of pressurised gas should be regarded as a potential major accident hazard. It is important to consider containment of lift gas in the event of failure of the primary barrier e.g., production casing string or surface gas lift pipework. The following should be considered: To ensure containment if there is a leak from A to B annulus, the gas injection pressure should not exceed the fracture pressure at the B annulus shoe. For wells that do not meet these requirements, a risk assessment is required to operate the pressure in excess of the fracture pressure. The well should be designed to minimise the gas inventory below the wellhead that would be released by wellhead failure.

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A fail-safe safety device should be incorporated on the gas lift side on all platform gas lift wells. This may be a surface controlled downhole valve or an internal valve in the wellhead. The option selected should be the one that reduces risk to ALARP. Examples of downhole valves include an annulus safety valve or a Surface Controlled Sub-Surface Safety Valve (SCSSSV) installed in the gas lift string of a dual-string completion. In the latter case, and located above the uppermost gas lift valve, there should be a dual-string packer, and / or available barriers installed in the VR profiles of A annulus outlets. A valve installed in the wellhead should be protected from dropped objects and risk assessed for other potential failure mechanisms and wellhead vulnerabilities. The wellhead should have a double barrier on the non-active side of the wellhead (i.e. the dead side) with ability to test both barriers independently. The requirements for subsea wells will depend on hazards to personnel during well entry, and the potential for leaks to the environment if the gas lift inventory is not minimised. Gas lift systems should be designed, constructed and operated to comply with the requirements of Prevention of Fire and Explosion, and Emergency Response (PFEER) [Ref 9]. There should be provision for monitoring the gas lift pressure in the well. Where feasible all wells should have continuous monitoring of the ‘B’ annulus with alarms. For subsea wells, the ‘B’ annulus should be designed to withstand the effect of thermally induced pressure and pressure due to A to B annulus communication in the event of a leak. There should be adequate means for blowing down the annulus or gas lift injection string. This is essential for testing the gas lift downhole safety device. Well tubing and critical casings should have premium gas tight connections. These should be properly made up and tested to achieve a gas tight seal. In exceptional situations, there may be mitigating circumstances for using completions with single gas lift valves for well kick-off without installing an annulus protection system. To ensure that the potential volume of vented hydrocarbon is as low as possible, conditions imposed on gas lift kick-off from unprotected wells should include: • •

Production annuli are depressurised and filled with brine after each kick-off On platforms with multiple wells with no annulus safety valves, well kick-off operations should only be carried out on one well at a time

The gas lift annulus should be hydraulically tested before gas lift or orifice valves are installed. This should be to a pressure above the worst-case annulus pressure. Whenever gas lift is first introduced to the well, the annulus side should be inflow tested with gas below the barrier, and the pressure above bled down. Some wells may not be originally designed for gas lift but changing reservoir conditions may lead to it being considered. In exceptional situations, it may not be practicable to retrofit premium type connectors to an existing well without major modifications to the wellhead, or risking damage to the

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pressure integrity of the well. In such circumstances, it may be appropriate to introduce gas lift down casing with non-premium connections, but only after rigorous risk assessment has been conducted, indicating that the risk is reduced to ALARP. In this case, it would be necessary to demonstrate that the probability of gas leaking into the ‘B’ annulus, and any consequences, would be ALARP. The risk assessment should consider several factors including: • • • • • • •

The presence of other platform gas lift wells on-stream The annulus design being capable of containing gas lift pressure Lift gas composition (water, H2S, CO2) Stable annulus response Comprehensive arrangements for monitoring annulus conditions A lift gas bleed down system of adequate capacity and responsiveness The ability to monitor the B annulus

If it is planned to retro-fit gas lift to an installation, the safety case should be reviewed and modified. Since this may significantly affect the hazards, a ‘material change’ may need to be submitted to the HSE as required by Regulation 21 of SCR 2015 [Ref 3]. Other well integrity-related considerations for gas lift include: • •

•

•

8.6

Moisture content of the gas lift gas – gas injected through the wellhead and into the production annulus should be dry to reduce the risk of casing corrosion or hydrate blockage. Gas lift valve check valves – gas lift operating valves should contain one or more check valves to prevent reservoir fluids entering the annulus when gas lift shuts down. The consequence of reservoir fluids in the gas lift annulus include: casing corrosion, loss of barriers and damage to gas lift valves through liquid erosion. Gas lift materials – to reduce the risk of premature failure, gas lift valve materials (e.g. elastomers and metallurgy) should be checked for compatibility with injection fluids (e.g. scale inhibitors) misted into the lift gas. Gas lift casing design – the casing forming the outer envelope of the gas lift annulus should be designed for loads including full evacuation down to the deepest gas lift mandrel. The next/adjacent casing should be pressure tested in excess of the gas lift pressure.

Completion operations Well control procedures should be reviewed before starting completion operations. Factors to be considered include: • • • • •

Ability of BOP to close around tubing and completion equipment Ability of BOP to shear completion equipment and alternative procedures if shearing is not achievable Ability to circulate through completion string when running Well kill methods if a kick is taken when running completion Complications due to control lines/cables run outside the completion string

If the reservoir is open, consideration should be given to measuring SCR pressure drops, in case there is a kick when running in the hole with the completion.

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8.6.1

Displacement to light fluid A well may be displaced to a light fluid (less than kill weight) at some point during completion operations. The active barrier is no longer the fluid column but the casing or liner and any mechanical barriers in the well. Casing and any cement plugs should be pressure tested before starting displacement. If possible, the casing hanger seal assemblies should be inflow tested before displacement starts. For downhole barriers that cannot be adequately tested by an internal casing pressure test (e.g. a liner lap or isolation valve), a successful inflow test is needed before displacement starts. There should be a clear distinction between the inflow test and subsequent displacement or well cleanup operations. An inflow test should be formally accepted by the representative of the well-operator before starting any other operations. On offshore installations, the results of the test should be reviewed with the installation safety case duty holder or their representative. The displacement operations should be covered by approved procedures. If circumstances change and prevent the operations being carried out as planned, new procedures should be written under the welloperator’s MoC system. During displacement, the volume of fluid returned should be monitored and compared with the volume of fluid pumped. The rig pit system should be set up so that these measurements can be done. Ideally there should be independent checks (e.g. mud loggers and rig crew). Simultaneous displacement and transfer operations have been a contributory factor in several serious incidents. Therefore, other fluid transfer operations (such as offloading mud to a supply boat) should not be carried out at the same time, unless sufficient personnel and control measures are available to adequately monitor both operations. The pump pressures and volumes should be estimated before starting operations. The actual pressures and volumes during displacement should be compared to the estimates and any differences reviewed. If the well is to be displaced to a lighter fluid, the displacement should be planned with a step-down chart of pressure versus volume, with clear notification of the point at which the well is underbalanced. Any deviation should be reviewed. If there are concerns during displacement, or discrepancies in volume or pressure measurements, the displacement should be stopped and the well closed in at the BOP to review the situation. There should be a contingency plan if there are indications of an influx during displacement operations. The well should be shut-in at the BOP and the well circulated back to kill weight fluid under controlled conditions (through the choke system).

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9 Commissioning 9.1

Summary Commissioning starts when the completion (or intervention/workover) stage ends. It covers tying in the well to production or injection systems and may include handing over operational responsibility for the well to the production department. It ends when steady state production/injection operations start. Well-operators should ensure that the relevant people at the site e.g. the production control room operators. have the key information from the handover process, such as the MAASP data, prior to well start-up.

9.1.1

Well Integrity Suitable and sufficient barriers should be installed in the well and tested before commissioning. An important part of the handover of operational responsibility for the well is a review of the barrier status and pressure containment boundary.

9.2

Initial well handover information The following information should be readily available to the well-operator before the well is brought on line and should be included in the initial handover document. General well information: • • • • • • •

Quadrant, block, field, well number, surface coordinates and slot reference if applicable Platform or rig drilling contractor, rotary table elevation Well type description (e.g. water injector) Spud date, completion date TD, hold-up or plug-back depth, maximum inclination at depth Any obstructions (e.g. ‘fish’) left in the wellbore should be documented and indicated in the appropriate well schematics Definitive survey of the well including the type of equipment the survey used (i.e. error and accuracy) and any well path that is near the ellipse of uncertainty.

Maximum Allowable Annulus Surface Pressures (MAASP). For each annulus, with information on the fluid type and weight in each annulus. The MAASP should be defined for each annulus. Equipment limits (including wellhead internal components, seals, etc), burst/collapse ratings, leakoff or FITs, estimated casing wear, or post-construction pressure tests may all be factors that determine the MAASPs. Additionally, a Maximum Allowable Operating Pressure (MAOP) may be defined for each annulus to provide an operating margin (i.e. the MAOP is less than the MAASP). This should be carefully selected, and not just based on a percentage of the MAASP. It is a trigger to take executive action and to review what is going on in the well. Valve status. Operating parameters and any isolations that are in place. For all manual valves the number of turns to open and close should be stated. For actuated valves the volume of fluid required to open

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and close the valve should be stated with opening and closing times. There should be a record of any plugs installed in the well, including wellhead VR plugs. Well completion. Schematic showing installed components with: manufacturer, component description, depth, serial number, material, maximum Outside Diameter (OD), minimum ID, drift, connections, working pressure and temperature; test pressure, completion fluids, hold up depth with a description of the tool string; and any required operating data (e.g. release mechanism for downhole packers). Information should be included on any remedial work (including stimulation), anomalies encountered, or material left in hole. Wellhead and xmas tree. Schematic showing installed components with manufacturer, component description, serial number, material, maximum OD, minimum ID, working pressure, test pressure, and any required operating data. Casing and cement. Schematic showing installed casing strings with setting depth, grade, weight (lb/ft), connection, cement top and method of verification (e.g. cement bond log, calculated, etc); annulus fluid, pressure test, LOT or FIT; and information on any installed components (e.g. diverter (DV) collar, liner hanger). Control system. Information on any hydraulic or electrical control systems including function test results. Information on DHSV control line pressures (min and max) and maximum injection pressures for water injection or gas lift. Well site clearance. For subsea wells: certificate with information on the status of the area around the well, including any material left on the seabed and the status of any well protection devices. Operating risks and conditions. Any identified well operating risks (e.g. anticipated thermal growth/contraction or lateral movement) or conditions attached to the well operating consents (e.g. PON 15B/F requirements). Pressure containment barriers. All the barriers and well integrity controls should be described. A barrier schematic may be produced for the well to illustrate all the barrier and well integrity controls.

9.3

Life of well information Within one month (or other reasonable timeframe as determined by the well-operator) of the completion of a well, or an intervention/workover that changes the status of the well, the following additional information should be available to facilitate life of well integrity. Contact details - Key personnel involved in the design and construction of the well. Well data - Reservoir pressure, reservoir temperature, gas oil ratio or gas condensate ratio; shut-in wellhead pressure and temperature; flowing wellhead pressure and temperature; produced/injected fluid data (gravity/density and composition). For multi-zone wells information should ideally be available for each zone. Well Numbering - It is important for the well-operator to have an effective system for well numbering, especially during handovers between different departments.

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As-built drawings - Engineering drawings and operating manuals for all equipment installed on or in the well, and all materials left in the well, including cement. This would include the definitive wellbore survey, including any sidetracks. Valve status and valve manipulation sequence during start up and shut down should be noted. All the barriers and well integrity controls should be described. End of well reports - Details of the design and construction of the well or intervention, including geological data and any information relevant to future well integrity e.g. kicks and losses.

9.4

Surface equipment considerations All operating and testing procedures for the surface equipment should be in place and readily available to those personnel operating the equipment. Equipment installed on, or around, the well should not restrict access to the well and components required to operate, maintain or intervene in the well. Personnel should have access to operate valves and hand wheels for manual valves. Access should be available to use VR plug lubricator assemblies. Gauges should be specified to match the anticipated pressure range and should be sited such that personnel can read them easily. Pin stops may be useful on some types of gauges to help verify that the pressures are within the gauge range. Consideration should be given to using real time wireless gauges. Valves and bleed arrangements should be installed such that pressure can be bled off safely and gauges changed out with two barriers in place. Gauges should be calibrated for first use and have a periodic maintenance routine to ensure that they are calibrated in line with the manufacturer’s recommendation. Any lines and fittings should be specified to meet the conditions (fluid, pressure and temperature) to which they may be exposed during the life of the well. Removable well fittings (e.g. plugs, bleed nipples, tie down bolts and VR plugs) should be identified on schematics which should be available to operational personnel. In some cases, it may be suitable to label fittings, but it is important that the labels are correct. Incorrect labels are worse than no labels. Allowance should be made for well movement, both thermal growth or contraction, and mechanical movement (e.g. due to wave action). Equipment attached to the well that is part of the pressure containment boundary should be sited as close to the well as practicable and protected against damage. The well interface with the topsides equipment should be explicitly stated (e.g. flowline hub, gaskets, instrumentation). It should be clear what is covered by the platform verification scheme and the well examination scheme.

9.5

Well examination and verification The well-operator should have a well examination scheme that covers all wells throughout their life cycle.

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How this duty is fulfilled may change when the well is commissioned. Different companies have different methods, but the important point is that well examination, as described in the scheme, should continue into the ‘operate and maintain’ stage. Offshore, the installation duty holder should have a verification scheme that covers all SECEs, which will include wells that are connected to the installation. The commissioning stage is a good time for the installation duty holder to check that the well is included in the installation verification scheme. Offshore, it is vital that there are no gaps between the examination and verification schemes. The well, and any operations carried out on it, should be examined by an independent and competent person throughout its life cycle.

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10 Operate and Maintain This section covers well integrity during the operational phase of the life cycle of a well, from well handover at the end of construction (or commissioning) through to late-life. It ends with a handover back to the wells team for intervention, workover or abandonment. This section is written to cover all types of wells: where a requirement is specific to a type of well, then the well type is specified. The main well integrity function is to monitor and maintain the well barriers and pressure containment boundary installed during previous operations, and to continue to demonstrate that risks from the well are ALARP. During the operational phase the original risk assessments and basis of design documents should be referenced, and routines set to address and reflect failure data. Well-operator routines for inspection, maintenance and testing should be conducted at a frequency that is based on reliability data.

10.1 10.1.1

Well integrity assurance Well integrity management systems This should include methods of inspection, maintenance and testing of well related SECE for every well. These should be documented in the performance standard for each SECE. Refer to Section 3 for an overall description of a well integrity management system.

10.1.2

Roles and responsibilities The well-operator should define who has responsibility for wells covering: • • • •

Day-to-day operation, flow assurance and condition monitoring Routine inspection, maintenance and testing Verification of well related SECEs/well examination Anomaly/deficiency identification and MoC

See [Ref 32] and the Oil Spill Prevention and Response Advisory Group (OSPRAG) report [Ref 34] for further information.

10.1.3

Competency The well-operator should ensure that the personnel undertaking the work are competent to do so. This is particularly important given the potential hazards of trapped pressure and hydrocarbon release, combined with the safety critical nature of well equipment. Equipment operating and testing procedures should be readily available to personnel operating the equipment.

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10.1.4

Well files and operational histories Detailed design, construction, commissioning and operational records are important to ensure the well is operated within design criteria. Operational records should include: • • •

Monitoring of operating parameters (condition monitoring) Inspection, calibration and testing findings Planned maintenance records, investigation and intervention reports

Schematics and installed equipment records should be current. These records should be controlled and updated when well equipment is modified or replaced. Wellhead manuals should be controlled documents.

10.1.5

Well stock performance review The well operator should conduct performance reviews to assess the application of the WIMS to its well stock. The primary objectives of a performance review are to: assess whether the well stock is performing in accordance with the WIMS and its objectives and; assess how the well stock conforms to the WIMS processes and adheres to the policies, procedures and standards defined in the WIMS and; identify areas of improvement. Where areas for improvement are identified, any changes required to address these improvements should be specified and implemented. Implementation of any changes should follow the well-operator’s risk assessment and MoC processes. Performance reviews should be carried out at a defined frequency determined by the well-operator based upon associated risks. In addition, ad hoc reviews should be performed as and when deemed necessary when new information becomes available that can have a significant impact on well integrity risk or assurance processes. The review should be performed by a group of personnel deemed competent in well integrity principles and who are familiar with the well-operator’s WIMS. It is recommended that, where practicable, at least some personnel involved in the review not be directly involved in well integrity management of the well stock under review.

10.1.6

Risk Assessment and Management Well-operators should have a process to review well hazards and assess any significant changes, throughout the life cycle of the well. In the operational phase, factors to be considered include: • •

Barrier degradation and repair (see section 4.3.11 and 4.3.12) Changes in production parameters or production plant pressures (e.g. sand production, separator operating pressure)

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• • • • • • •

Unrecorded creeping change Modifications to SECE Changes in structural well loading, or the ability to withstand the loads (see section 4.2) Changes to annulus pressures and MAASP (see section 10.4) Sustained annulus pressures Other changes affecting the original well design premise (e.g. tertiary production schemes) Well maintenance backlog

Well-operators may also wish to refer to the OGA Stewardship Expectations document: SE-06 Production Optimisation Implementation Guide, June 2017 [Ref 142] which has relevant information. Well-operators should have a process to confirm that mitigating actions are in place, are tracked and are time-bound. See Section 10.8.

10.2

Operating procedures Procedures should be available to describe how the different types of wells associated with each installation/field are operated.

10.2.1

Special precautions for start-up and shutdown • • •

10.2.2

Annulus monitoring to avoid over-pressurisation associated with thermal affects Monitoring of wellhead movement (thermal effects causing growth or slumping) Initiation of chemical treatments to control hydrates, scaling, waxing or asphaltene deposition that could affect well valves

Operating parameters and monitoring Well operating parameters that impact on well integrity should be clearly defined, readily available to personnel operating and maintaining wells, and routinely monitored. Examples include: • • • •

Pressure (e.g. to avoid bubble point deposition of scale and asphaltene) Fluid flow rate (e.g. to avoid exceeding erosion limits) Sand production rate (e.g. to avoid unacceptable erosion) Water compositions for scaling tendency which could impair valve operation

The frequency of monitoring should consider: • • • •

10.2.3

Pressure limits Rates of pressure build-up Allowable leak rates Age of the well

Verification of control measures Well-operators should have a process to verify that the correct information and control data, such as MAASP data for all wells, is available and correctly implemented at site.

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10.3

Visual inspection of wells Wells should be subject to routine visual inspection for signs of damage and leaks. Whenever possible, digital images (or video) should be used to record the visual inspection and create a history of impairments for each well. For subsea wells, vessels should be alert to any surface signs of leakage, considering the type, age and condition of the well. A frequency for visual subsea inspection should be set by the well-operator based on risk assessment. In the absence of any prior history, as a guide, a two-year inspection frequency is recommended. This inspection should be undertaken, where possible, at the same time as the well integrity testing, to visually confirm valve status and operation.

10.4 10.4.1

Annulus management Key Requirements of an Annulus Management Process The well-operator is responsible for the monitoring of well annuli and reassessment of MAASP over the lifetime of the wells. There should be a MAASP for each annulus that is monitored. The well-operator should understand the specific operating requirements and annulus pressure management of each well design. Annulus management procedures should document how annulus pressures are recorded, monitored and trended to ensure pressure variations and anomalies are detected. Pressure trending of annuli enables the well-operator to determine the integrity of the pressure containment envelope and potentially identify degrading components. The well-operator should define acceptance criteria for annulus leakage. Absence of pressure in an annulus does not mean that the annulus is pressure containing. A minimum positive pressure may be maintained in an annulus to provide an indication of annulus containment. It may not be possible to maintain a positive pressure in some annuli. Regular measurement of liquid levels, or refilling of annuli, combined with pressure testing, should be used to verify the integrity of all annuli or identify leaks. Operating changes and thermal affects associated with them, may affect annulus pressures. Increase or decrease of annulus pressure should be assessed to ensure that the cause is understood. Procedures should document how to react to changes in annulus pressure, and how changes may be related to potential annulus barrier failure. Sampling and analysis of fluids should be done whenever annulus pressures need to be reduced. Excessive rates of depressurisation or repetitive bleeding of liquid should be avoided since this may exacerbate the leak path or increase fluid ingress from external sources.

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Modification of a well design can potentially result in an annulus that cannot be monitored at surface. Since pressure in ‘blind’ annuli cannot be monitored or controlled, the well-operator should ensure that the resultant limitations and their potential consequences are understood. The management of sustained pressure should have more intensive monitoring and pressure control processes to confirm conditions are stable and at an acceptable level.

10.4.2

MAASP and Annulus Operating Limits The MAASP is the maximum pressure that is allowed at the wellhead of an annulus to avoid compromising the integrity of any of the component barriers of that annulus. The MAASP should be determined for each annulus of a well. The basis of each MAASP should document: - design factors used in calculations, component specifications, the design of trapped / nonmonitorable annuli, and pressures applied during tests, including those of open-hole formations. MAASP should be recalculated if any of the following criteria is evidenced: • • • • •

There are changes in the integrity of components of an annulus or adjacent annuli There are changes in the test acceptance criteria e.g. reduced test pressure There are changes in the service or operation of the well that is at variance from assumed load cases, temperatures and pressures There are changes of annulus fluid density Tubing, casing or other annulus component has degraded or has been down rated due to age

The well-operator should determine upper and lower operating limits for each annulus that can be monitored. The upper operating limit is normally lower than the calculated MAASP (MAOP-see Section 9.2), to enable reaction to avoid a potentially damaging increase of pressure. This is particularly relevant during well start-up or shut-down when thermal affects may significantly affect annulus pressure, or (due to lack of access to control annulus pressure) during an installation emergency situation. A lower annulus operating pressure limit may be implemented for the following reasons: • • • • • • • • •

Observation pressure for the annulus Providing hydraulic support to an annulus barrier component Avoiding casing collapse of adjacent or ‘blind’ annuli Avoiding hydrate formation Balancing pressure to minimise degradation of small leaks Variability of fluid properties Temperature fluctuations Avoiding vapour phase generation (corrosion acceleration) Preventing air ingress if the annulus pressure is lower than atmospheric

For subsea wells, the lower annulus operating pressure limit should be above the sea water hydrostatic pressure at the wellhead.

10.4.3

Pressure Testing & Topping up annuli Well-operators should have a documented procedure for pressure testing and topping up annuli.

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Annulus pressure testing, or integrity verification by other methods, should be considered when: • • • •

Changing the well functionality, i.e. from producer to injector, etc There is a risk of external casing corrosion because of aquifer penetration Hydraulically fracturing the well There is a lack of evidence from positive pressure monitoring

This procedure should include details of the composition of the fluid to be used for topping up annuli including: • • • • •

10.4.4

Fluid type Fluid density Chemical composition Corrosion inhibition Biocide concentration

Factors affecting annulus pressure Pressure in annuli may occur or change for several reasons: •

•

• •

•

10.4.5

Normal Operating Pressure is a pressure deliberately applied to an annulus as part of its function or to enable monitoring. Examples of this are: o gas lift in the ‘A’ annulus o an applied pressure in the ‘A’ annulus to protect against collapse risk from pressure in the ‘B’ annulus o small positive pressure applied to monitor the integrity of the annulus Thermally Induced Pressure is generated when the well heats up due to production flow or when water injection is stopped. This pressure is not bled off unless it reaches a defined limit (trigger) related to the annulus pressure limit (or MAASP) Ballooning or compression of tubing or casing due to changes of pressure in an adjacent flow conduit or annulus. Sustained Annulus Pressure is a pressure in an annulus that rebuilds after having been bled off, which cannot be attributed to an applied pressure or to thermal effects. Sustained annulus pressure is typically due to a shallow, charged formation at an open shoe, or damage to casing primary cement after setting. Leakage of an Annulus Containment Barrier. This may result from a leak across the casing, tubing, packer, wellhead or other barrier component

Sustained annulus pressure The management of sustained annulus pressure (may also be known as; Annulus Charging, Sustained Casing Pressure or Annulus Vent Flow) should have more intensive monitoring and pressure control processes to confirm conditions are stable and at an acceptable level. Sustained annulus pressure should be investigated with consideration being given to the following: •

Establish the source of the sustained pressure by sampling and fingerprinting the annulus fluid

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•

•

• • • • •

10.4.6

Establish the leak rate into the annulus. This is usually achieved by measuring pressure build up (or drop off) in an annulus. The annulus fluid composition will have a large impact on the pressure build up, particularly if liquid is passing into a gas filled annulus The casing tubing and cement conditions of the annuli should be assessed, either by sampling or full engineering assessment. The MAASP of the adjacent annulus with casing shoe formation leak-off strength, should be confirmed based on most recent data The consequences of large volumes of gas in an annulus, and annulus barrier component failure, and loss of containment should be considered The annulus liquid level should be checked on a regular basis Well logs, such as temperature logs, may provide useful information Consider installation of second wellhead annulus sidearm valves, with a corresponding update to the performance standard. Actions taken in response to sustained annulus pressure are likely to be well and/ or installation specific and should be informed by risk assessment.

Annulus depressurisation and bleed down Annulus depressurisation or ‘bleed down’ may be required to maintain the annulus pressure below the upper operating pressure limit. Annulus pressure management procedures should clearly define the constraints of depressurisation and consider the following: • • • • • • • • • • • • •

Minimizing the number of bleed downs and volume of fluids bled off to limit flow erosion and degradation of leak paths Bleed downs may introduce fluids into an annulus that could accelerate corrosion or erosion of casing strings Bleeding off liquids which are replaced by gas or lighter liquids can result in higher annulus pressure and increased hydrocarbon mass in the annulus The risk of hydrate formation during bleed-off of hydrocarbon gas should be addressed Contingency plans should be in place to manage annulus pressure during shut downs when bleed off facilities may not be available When pressure is bled from an annulus, the following information should be recorded: Date and time Well, slot number and annulus bled down Time to bleed down Pressure bled down Estimated volume of fluid drained Type of fluid (gas, liquid, mixture) bled off and weight, if possible If the fluid bled off changes state (e.g. from gas to liquid)

This information should be reported to the person accountable for evaluating well integrity and recommending further investigation or action.

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10.5 10.5.1

Xmas tree and wellhead valves Barriers within wellheads Wellhead designs and seal configurations provide void spaces within the wellhead. On surface wellheads, these should be accessed to confirm the integrity of barriers between different annuli and the environment. Casing void spaces on surface wellhead systems should be tested at installation to ensure the integrity of packoff seals and ring gaskets. The well operator should determine the frequency of further testing based on an assessment of the risks e.g. personnel potentially exposed to a release of pressurised fluids vs. the benefits of confirming integrity by stinging. The risk assessment should be informed by reliability findings specific to the asset and the wellhead type. The pre-job risk assessment should include potential mitigation if the check valve fails to hold pressure after stinging operations. Positive pressure testing should be carefully considered in relation to the wellhead design and the function that some seals provide within the wellhead. A variety of bleed, test and other port fittings and buried check valves may have been installed. Most wellhead voids should be isolated from pressure sources and therefore the presence of pressure may indicate seal failure and potential communication. When testing wellhead plugs and fittings due consideration should be given to the potential for pressure behind the fitting, for example trapped in a void, and the hazard this may present. The use of fittings where pressure can be measured before removal is advantageous in this situation.

10.5.2

Wellhead valves Valves associated with annulus gas lift and jet pumps should be tested and maintained on the same basis as xmas tree valves. Wellhead valves installed on annuli should be tested and maintained at appropriate intervals. Commonly this is at the same time, and using the same methods, as for xmas tree valves. Valves installed within the wellhead profile may be simple Non-Return Valves (NRV), or actuated surface annulus safety valves.

10.5.3

Xmas tree valves The xmas tree valves provide several individual potential barriers between process systems and the well. During normal operation of the well the flowline is an active barrier, and the header valves provide potential barriers for the containment of well fluids. It may then be acceptable that individual xmas tree valves do not have to provide a ‘leak tight’ barrier. The well-operator may accept that the actuated xmas tree valves that are part of the ESD system may have leak rate acceptance criteria.

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10.5.4

Testing xmas tree valves The frequency of testing valves should be validated by reliability findings specific to the asset and type of valve or location. The test method(s) to assess valve leakage should detail how the tests are performed. Several ways of testing may be required to validate the condition of every valve on a xmas tree and wellhead. Inflow testing using natural (or applied gas lift) well pressure, and measuring pressure build up or pressure fall off in cavities adjacent to the valve, may be used. Alternatively, split gate valves or wells without pressure may be tested using a test pump. There are currently no industry-wide standard leak rate acceptance criteria for subsea xmas tree valves. Alternatives may be specified in the method or performance standard for example: • • • •

[Ref 46, 72 and 74] 2cm3 per minute per inch of valve bore Operator specific ‘rules of thumb’ Leak tight

The time to closure for actuated valves should be a performance standard. This may be included in the Installation verification scheme. If a valve fails to test ‘as found’ (i.e. before greasing and cycling), this should be recorded and reported. If the valve passes the test after being functioned and lubricated several times, this should also be recorded. The aim of the testing is not just to get a valve to pass the test, but to gauge how effective the valves would be if they were used in an emergency. If the full information is not reported, then the installation duty holder and well-operator will not be given the full picture of the valve status. They may also miss generic issues and latent defects of valves. Valves that fail to test after lubrication, multiple functioning, and attempts to test, should be identified for corrective action in the test report, and a repair order raised with a timescale for repair/replacement and retesting.

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10.5.5

Example of valve failure matrix A matrix may be drawn as an illustration of valve status and reactions to problems. DHSV

Lower

Upper

master

master

Flow wing

Failure Type

X Single

X

Failure

X X X

X Dual failure or single

X

X

DHSV

X

X

X

Failure with

X

X

X X

X

X

DHSV or triple failure

Notes Risk assessment. + Changemanagement policy. Continued production with timetable for repair Shut-in well + risk assessment. Restart production only with dispensation from a technical authority and positive outcome from risk assessment. Definite repair date Shut well in. Plan repairs. Consider installing deep set plug immediately

X = Failed valve Table 12. Example Valve Failure Matrix This is a generic example, and well-operators may wish to produce matrices for their wells. These should reflect their internal standards and procedures.

10.5.6

Valve removal plugs Well-operators should have policies and procedures in place covering the use of VR plugs on surface wellheads. Where VR plugs are used on wellhead side outlets to effect the inner isolation of a double isolation, solid bull plugs should not be used to effect the outer isolation. In such a configuration, failure of the VR plug could lead to trapped pressure which could not be safely vented. Where VR plugs are used to effect isolations, procedures should be in place to routinely check the integrity of such plugs and change them out if required. Well-operators should have procedures in place for the safe installation and removal of VR plugs using the correct tooling. Unless there is an alternative way to monitor annulus pressure, VR plugs should not be routinely installed in both side outlets of an individual casing spool since this leads to an inability to monitor annulus pressure.

10.5.7

Xmas tree and wellhead instrumentation and accessories Ancillary equipment may also be critical to maintaining well integrity, including: •

Pressure and temperature gauges/transducers

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• • •

Sand and corrosion monitors Chemical injection facilities Valve actuation systems

Well instrumentation should be included in installation instrumentation verification schemes. The instrumentation should be calibrated and functionally verified to conform to appropriate performance standards. Well equipment should be included in either the well examination or verification processes. Well-operators should have procedures in place to ensure that fittings are not removed without first safely checking for, and venting off, any trapped pressure behind them. Fittings (e.g. plugs, bleed nipples, tie down bolts and VR plugs) should be correctly identified and recorded on schematics. In some cases, it is useful to label the fittings, especially where fittings with different functions and modes of operation may look the same. Fittings should be subject to controlled maintenance and inspection to ensure their continued fitness for purpose. Wellhead accessories (e.g. lubricators, test pumps and stingers) should be subject to independent certification that the equipment design is suitable for the intended purpose, and this equipment should be subject to maintenance and inspection to ensure continued fitness for purpose. Duplication of assurance by well operation and production operations teams may be a benefit to ensure continuous fitness for purpose.

10.5.8 10.5.8.1

Potential damage to subsea xmas trees Over-trawling by fishing boats The probability of a wellhead/xmas tree being damaged by fishing activity depends on: • • •

Fishing vessels trawling in area (a study should be carried out by the well-operator) Vessels ignoring or unaware of well position (recorded on Kingfisher charts) http://www.seafish.org/industry-support/kingfisher-information-services Dynamic snagging load from boat

The planned and as-built wellhead/xmas tree should be assessed to estimate the minimum load that would be likely to lead to loss of containment. See [Ref 77] for more details. A review of the lateral and torsional resistance should be carried out for all wellhead/xmas trees and compared to the potential trawling loads. Well-operators should check that all their wells (operating or suspended) are included in current versions of the Kingfisher charts and ‘Yellow card’.

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10.5.8.2

Dropped connector assembly Xmas tree assemblies should be assessed to estimate their resistance to dropped objects damage. Previous studies have indicated that xmas trees should withstand up to 300 kilojoules of impact energy without xmas tree failure. The well-operator should ensure that the connector assembly is run and pulled over a ‘safe area’ some distance from the wellhead. The connector should only be moved over and away from the xmas tree at a small height (i.e.1-2 metres) above the top of the tree. Dropped objects onto wellheads are also a hazard during completion operations as well as intervention/workover operations.

10.5.8.3

Other dropped objects Other potential dropped objects include: • • •

Dropped anchors Dragging anchor Dropped load at sea surface from a Mobile Offshore Drilling Unit (MODU) in attendance at the well site

Impact energies from anchors (including anchor drag) are likely to be much less than the required wellhead/tree failure energies. The small size of the tree footprint makes the probability of contact very low in the extremely unlikely event of anchor drag. Drilling rig anchors could possibly damage the wellhead but no examples of complete loss of rig position are recorded anywhere in the UK Continental Shelf (UKCS) where mooring analysis is applied. The rig will have an emergency mooring release mechanism, which would be activated in a drift situation, especially near the subsea infrastructure. Dropped objects from the MODU at the sea surface leading to impact to the wellhead are considered to be of very low frequency. It is assumed that lifting of loads in excess of the above levels would be managed by special procedure. Cranes should work within safe areas dependent on the type of load being handled. This may require shifting the rig to a safe area away from the wellhead for heavy loads such as xmas trees, etc. 10.5.8.4

Installation failure Subsea wells connected to a Floating Production Storage and Offloading Unit (FPSO) may be at risk, due to a failure of the installation’s mooring or dynamic positioning systems. Depending on the field layout, the production riser load may be transferred to the xmas tree.

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10.6 10.6.1

Downhole Safety Valves Types of DHSV A variety of emergency shutoff valves may be installed within the completion, wellhead or annulus, to prevent inventory loss in the event of catastrophic damage to the xmas tree and wellhead. The main types of DHSV are: • • • • •

10.6.2

Surface controlled subsurface safety valve – hydraulic control line operated Subsurface controlled subsurface safety valves - storm chokes Water injection valves – inject through, failsafe closed Surface controlled annulus safety valves or alternatives Storm chokes or flow activated subsurface safety valve.

Testing of DHSV Testing of the DHSV and control system usually includes inflow testing of closed DHSV, and monitoring of the closure time and volume returns of the control line. Valve leakage may be assessed for compliance with [Ref 74]. Testing standards should be defined by the well-operator and clearly documented. DHSVs should be tested at least every six months, unless local conditions or documented historical data indicate a different testing frequency see [Ref 74]. The integrity of the control line should be tested at the same time as the DHSV. ‘Lock-in’ pressure testing and testing for hydrocarbon ingress into the line may be used to confirm containment within the downhole control system. Personnel should be made aware of the possibility of pressure and hydrocarbons in the control line if the control line has to be opened. Contingency procedures to deal with the situation should be in place. Ingress could occur slowly over a period of days or weeks in a depressurised or vented control line. Consideration should also be given to the potential for over-pressuring control lines and the DHSV especially as the wellhead pressure declines; if the control line pressure is maintained at the initial value unacceptably high-pressure differentials may be created.

10.7

Testing of gas lift valves Testing of annuli on wells with gas lift should be performed when the gas lift valves are part of a well barrier. The objectives of the test are to confirm that the non-return valves of the gas lift valves are functioning and to confirm tubing and packer integrity.

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10.8

Deviation control/management of change Deficiencies identified from monitoring, inspection, testing and maintenance should be handled in accordance with the well-operator’s dispensation/deviation and MoC processes. This would typically include: • • •

10.8.1

Investigation and risk assessment Policy/standard/procedure compliance review Definition of on-site management of deviations, including additional controls

Repairs/corrective actions When a well barrier, or element, fails (in service or during test), or it is identified that failure could be expected to occur before the next scheduled inspection, the well-operator should review the well status to ascertain that there are at least two available barriers in place. If there are not two available well barriers in place, the well-operator should undertake remedial work to reinstate at least two available barriers. The timing of the work will depend on the results of the welloperator’s risk assessment and the performance standards for the equipment. In addition, the welloperator should undertake a risk assessment to determine the way forward for the well until the remedial work has been completed. Well-operators should have a process to escalate the level of management approval required for repeated deferral of remedial work.

10.9

Operating conditions affecting well integrity If well logging, or similar operations, are being planned for operational reasons, consideration should be given to including tools to assess the condition of the tubing and the rest of the completion. If there are concerns about the downhole integrity of the well, specific logging may be carried out for assessment purposes. The value of the information gained should be balanced against the hazards of entering a well, and the potential for causing damage by the logging process.

10.9.1 10.9.1.1

Failure of well equipment Temperature and pressure The implications of temperature and pressure changes of an operating well should be carefully considered and controlled for: • • •

Re-perforation of virgin reservoir layers Conversion of well service (e.g. from natural to gas-lifted production or production to injection) Pumping of treatment fluids

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10.9.1.2

Corrosion Logging (calliper, sonic, etc) of production tubing may indicate the location and extent of corrosion. Monitoring of produced fluids may clarify causes and potential for control. The effects of corrosive substances (e.g. CO2 and H2S) should be considered. These include: • •

The souring of reservoirs after water injection activities Lift gas containing CO2 at the interface with the static completion fluid in the ‘A’ annulus

Preventative treatments to minimise potential corrosion of the well include: • • • 10.9.1.3

Injection water and lift gas treated and maintained within strict quality limits Produced fluids treated using downhole chemical injection Cathodic protection to limit external corrosion

Erosion and sand production Production of abrasive solids should be monitored and controlled. Circulating sand subsurface should be considered. Wells with high risk of sand ingress may need additional downhole monitoring to ensure integrity of subsurface components.

10.9.1.4

Scale/asphaltene/hydrates/wax Produced fluids, in combination with specific operating conditions, can result in deposition of contaminants that can directly affect well valves and compromise integrity.

10.9.1.5

Biological erosion Biological erosion should be considered. Specification of annulus fluids may need to include biocides, etc., to prevent or reduce biological effects.

10.9.1.6

Downhole chemical injection issues Selection of incompatible downhole injection chemicals, e.g. scale inhibitor, can lead to increased corrosion rates. Consideration should be given to the possible effect of these chemicals on the production casing string in the event of injection line failure.

10.9.1.7

Seismicity and Other Geological Movement Loss of well integrity may occur because of natural or induced seismicity, for example due to compaction-related fault slippage. Consideration should be given to casing and cement design and performance standards, and placement in relation to zones where geo-mechanical movement is possible, to ensure that if such movement occurs the well retains sufficient integrity that containment is not lost.

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10.9.1.8

Downhole seal failure Over time downhole seals may fail. For example, downhole safety valve seals may start to allow gas to enter the control line. In this scenario the gas can migrate into the surface storage tank for the control line fluid, and thence to atmosphere, or cause a pressure build up in the holding tank if the tank is sealed. Operators should evaluate this risk and put mitigations in place e.g. gas detectors, ventilation etc.

10.9.2

Failure of risers/conductors For offshore platform wells external corrosion and failure of risers/conductors, from the seabed to the platform, is a concern, particularly in the splash zone area. In the original design, consideration should be given to soil strengths and the possibility of fatigue failure in later life. A strategy should be put in place for monitoring and managing the conductor and surface casing throughout the well life cycle, including any centralisation and platform guides. Conductors and/or surface casing may have been designed as main load bearing elements for the well and/or the platform structure. The well-operator should ensure that the load bearing function of the conductor/riser/surface casing is clearly documented, and the implications of failure understood, with mitigations in place. See section 5.3.2.

10.9.3

Non-well equipment that could impact on well integrity The well-operator should be aware of non-well equipment that may impact on well integrity and should ensure that this equipment is maintained, and mitigations are in place in case of failure. Examples of equipment to consider include: • • •

Caissons (e.g. for seawater lift pumps) that could fall and damage adjacent well structures Flowline hangers that could fail and thereby cause flowline failure or load transfer onto the xmas tree Heavy equipment that could fall onto a well (e.g. crane lifts over wells or rig operations on adjacent wells)

Non-well equipment that may impact on well integrity should be considered in the well integrity management scheme.

10.10

Review of degradation and life extension Mature assets may be older or have an expected lifespan beyond that originally anticipated. The welloperator should ensure that every well is structurally and operationally competent irrespective of age. Well integrity monitoring processes should adequately address additional types, and potentially increased frequency, of failures that may be associated with age related degradation of components.

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Increasing age should prompt consideration of undetected degradation or the onset of failure mechanisms that may well be un-noticed as wells age. Additional indicators and tests to establish changes of well condition should be considered. For example, performing a casing wall thickness assessment prior to a heavy workover. It is important to consider degradation processes that could result in failure, so that management plans are put in place to mitigate degradation or pre-emptively repair or replace ageing components, fixtures and fittings etc. The key elements of a program to manage the degradation, ageing and the potential extension of life of wells which should be included in the Well Integrity Management System (WIMS) are: • • • •

Proactive approach to Asset Life Extension (ALE). Well integrity failure trending and component degradation analysis. Degradation and failure assessments to ensure well integrity management processes remain fit for purpose. Examination and assessment of the ongoing competency of processes and personnel to continue the management of well integrity into the future.

WIMS should specifically consider ALE, degradation and well component failure during well life cycle. The well-operator should be aware of ‘creeping changes’ that occur over time that may not be identified through MoC processes. As far as practicable the integrity management system should identify creeping changes, the adverse effects of which may not be immediately apparent. Creeping change may be weakening not only well structures and components, but also the knowledge and experience of operating the wells of an asset over an extended period. Degradation may lead to well component failures. Interpretation of failures will help to clarify the mechanisms, potential consequences and the development of strategies to minimize the potential effects of degradation and component failure. The well-operator should develop strategies to manage the degradation and failure of wells. Strategies in the early years of production may be very different from those in later life as the production profile evolves and will vary from field to field. Each operator may develop a combination of strategies, based on the operating environment of their assets. Potential strategy types are described below: Reactive

reacting to failures and repair / replace as soon as reasonably practicable with known spares availability

Proactive

gathering and analysis of data, monitoring trends and predicting failures allowing maintenance prior to failure

Pre-emptive

regularly workover wells, replace trees before degradation becomes an issue thus minimizing downtime

Review and assessment of the degradation and failure of well components is essential to ensure the continuing efficacy of inspection and maintenance strategies. Any additional failure mechanisms that are identified through well life should be reflected in WIMS revisions.

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Operators may find it effective to include a regular (typically annual), forward-looking life extension review of the well stock, as part of the Well Examination scheme, so that integrity can be managed in a way which is always consistent with the ALARP principle.

10.11

Management of late-life wells Late-life wells are simply an extension to the operating phase of the well life cycle, where the commercial value of a well is declining over time. Degradation of the well and cost of maintenance and repair will eventually exceed the value of the well and result in cessation of operation. All wells, regardless of value and operational status, should continue to be subject to the well-operator’s WIMS and Well Examination scheme, until they are abandoned. One of the key requirements of well integrity management is to minimise the risk of loss of well containment to ALARP. A well that is no longer operated and is redundant should be assessed to determine whether the major accident hazards and risks associated with the well can be reduced below what was considered acceptable for a well which was flowing. Reassessment of: available and additional barriers; disconnection and isolation; and revised monitoring and verification may identify potential risk reduction measures and a requirement to change the operating status of the well. A well that is no longer operating but is not decommissioned (abandoned phase 3) is in one of three statuses: • • •

1. Shut-in 2. Plugged 3. Suspended (abandonment phases 1 and 2)

For more information well-operators may refer to the Oil & Gas Authority document: Guidance for applications for suspension of inactive wells, October 2018 [Ref 143].

10.11.1

Shut-in well A shut-in well is one with one or more valves closed in the direction of flow. Reinstatement of the operation of the shut-in well should be possible at any time without the requirement for intervention or the reconnection of facilities or control systems. Shut-in should be considered as a temporary well status and is usually associated with process system outage or planned installation shut-downs. The installation operator will be expected to define: which xmas tree, wellhead and downhole valves will be shut, and the requirement for the cessation of artificial lift; isolation of sources of water or gas injection, and gas lift inventory removal, appropriate to the reason for well(s) shut-in. If a well is shut-in due to impairment of well operability or failure of components and barriers, the well should be shut-in in a manner that minimises the risk of loss of well containment. An increasing proportion of wells are being shut-in for reasons such as commercial considerations and water handling issues. For prolonged periods of well shut-in the well-operator should define in

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regulatory applications and notifications a date when the operation of the well is expected to resume or when plugging or abandonment will be implemented. A well that is shut-in should be monitored and maintained according to a risk-based schedule defined by the well-operator with due consideration of the risk profile brought about by the change in flow- and non-flow-wetted components irrespective of whether the well is hooked up to production facilities. The status and monitoring requirements of a shut-in well are not determined by whether it is hookedup to production and ESD facilities. The well-operator should clearly define how each of the well operating parameters will be monitored and recorded during periods when the well is shut-in.

10.11.2

Plugged well A well is plugged when an object or material is placed in the well with intention to function as a qualified barrier to isolate the wellbore from the reservoir. Guidance on the isolation of a well by plugging will need to cover: • • • • • •

The purpose of the plugging the number and location of plugs (e.g. deep-set, shallow) the type(s) of plug material (e.g. cement) the mechanical design the permanence or expected life of the plugs (individually and in combination) the verification requirements to assure the competence of the plug(s) as a barrier.

A well with a back-pressure valve or tubing-hanger plug installed may be considered as plugged, however a down hole safety valve (SCSSSV) is not considered a down-hole isolation device. The well-operator should define how the well operating parameters and applicable limits should be monitored and recorded when the well is plugged. The planned preventative maintenance routine and frequency should also be defined. Components above the isolation device are no longer flow wetted, however degradation mechanisms that may influence the competence and longevity of plugs should be considered.

10.11.3

Suspended (abandonment phases 1 and 2) Phase 1 and 2 well abandonment refers to the permanent isolation of the reservoir and intermediate zones with flow potential. The wellhead is still in place. Refer to Oil & Gas UK Well Decommissioning Guidelines [Ref 24] for further details. Suspended wells are temporary. The well-operator should establish a periodic review process that documents and details the intended plan for the well, which may include its permanent abandonment.

10.11.4

Review of the availability and continued use of wells The well-operator should conduct a regular (annual) review of the status of each well (i.e. operating, shut-in, plugged or suspended).

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The review should establish whether the wells that are no longer operating are: • • •

Available for continued operation (fully connected and functional) Have potential further use and will be required for operation in the next year Redundant and will never be used again.

The well-operator should establish a plan for each well which identifies restoration to operation, plugging or abandonment.

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11 Intervention/Workover This section covers the entry of a completed well for any purpose. Intervention/workover operations may be carried out by drilling rigs, vessels, snubbing units, coiled tubing units, electric wireline/braided/slickline units and pumping/stimulation units.

11.1

Primary control of the well/active barriers On a production well, potential barriers will have been activated to shut-in the well before the workover/intervention starts. A well barrier may be damaged or unavailable and the intervention/workover is needed to repair or replace it. The lack of the well barrier should be considered in the planning and operations. Pressure Control Equipment (PCE) (for example rig BOP, workover riser, snubbing unit BOP) should be installed on top of the xmas tree or tubing spool top flange and tested, before any well barrier is opened, compromised or removed. Gas lifted wells will have hydrocarbon gas in the annulus between the completion packer and the wellhead or annulus safety valve. This should be displaced out of the well before workover starts. The gas lift valves may be replaced by dummy gas lift valves. If these dummy valves can be tested adequately, the tubing can be considered a well barrier.

11.1.1

Well barriers during intervention/workover An active barrier is needed during workover/intervention operations such as: • •

Riser/lubricator/stuffing box for wireline operations Stripper rubbers (annulus) and work string check valves (internal) for coil tubing

Running wire or pipe into a well may compromise some of the well barriers, e.g. the DHSV or master valve in a ‘conventional’ xmas tree (that is a tree with in-line valves). Alternative potential barriers are needed during the intervention operations such as: • • • •

Wireline BOP/valves Shear seal BOP Coiled tubing BOP Hydraulic workover (HWO) BOP

Installation safety case duty holders should have performance standards for workover/intervention PCE. These standards should include closure times as identified in associated risk assessment. Emergency closure times for shear seal BOP (measured from initiation to closure) should be less than 45 seconds, to align with typical closure time of actuated surface xmas tree valves. Closure time for coiled tubing or HWO unit BOP and wireline valves should be designed to avoid a release sufficient to create either an explosive or life-threatening composition of fluid or gas.

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Testing may be conducted before installation on the well to demonstrate closure within the design time. It may be necessary for the wire or pipe to be sheared for two barriers to be activated. It may be necessary to lift the pressure control equipment during a well intervention to perform a repair or to fish equipment. For these situations two barriers may be attained by closing one mechanical barrier and having a second mechanical barrier available to close if required. For example, when removing the pressure control equipment above a single closed mechanical barrier to perform repair operations such as dropping a cutter bar, repairing a greasehead or removing wire with a broken strand, the shear device can act as the second barrier, remaining open during the operation but being available to close if the first barrier fails. The well-operator may rely on the shearing capability of the completion/xmas tree valves or the intervention BOP. More commonly, an additional blind/shear or shear/seal BOP is installed as part of the intervention rig up. If shearing is required, the sequencing of activating the barriers is important, and should be included in the intervention procedures/preparation. All affected barriers should be re-instated and tested at the end of workover/intervention operations.

11.1.2

Completion fluid as a barrier Completion fluid is usually solids-free brine which is designed to minimise damage to the formation. It does not form a filter cake like drilling mud. When brine is used as a column of fluid to provide hydrostatic overbalance, the fluid needs to be supported (by a packer or plug) to prevent it dissipating into the formation. The plug plus brine can be considered a single barrier. The fluid reduces or reverses the pressure differential across the plug. The level of fluid in the well and the surface volume of fluid should be monitored continuously to identify any losses or gains of fluid. Fluid loss control materials or fluid loss control pills may be used in clear brines to reduce fluid loss to the formation, and to keep the well full of fluid. Care should be taken during intervention, not to create a swabbing effect in the well. In wells without flow potential in either direction (e.g. a well open to an impermeable formation such as a shale gas well prior to stimulation) a brine may be considered to be a barrier without a plug provided the level of fluid in the well is continuously monitored and can be maintained sufficient to prevent any flow from the well.

11.1.3

Downhole safety valve as a well barrier A DHSV may be used as a well barrier provided: • • •

It is the lower barrier with a closed tree valve or mechanical plug above it preventing dropped objects accidentally opening the DHSV The DHSV has been tested to demonstrate it has zero leak rate The tubing integrity is confirmed

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11.1.4

Full bore tool strings Any tool string that contains full bore components (i.e. work on or above the safety valve) should be short enough to be contained between the xmas tree swab valve and the BOP. This may not always be feasible when operating without rig support (stand alone on jacket top deck) and should be reviewed on a case-by-case basis. Precautions should be taken to avoid the hazards of fouling or sticking full bore tools across the xmas tree. Examples of full bore tools are: • • • •

Shallow set bridge plugs (above DHSV) Wireline insert safety valves Hanger plugs Back pressure valves (BPV)

Mitigation may include running a full-bore drift which simulates the full-bore tool. Other considerations may include a mechanism of release from the running tool, should the running tool pre-shear, allowing locking dogs to partially expand and prevent withdrawal of the tools. Consideration should be given to tool string length to ensure that barriers can be initiated if full bore tools, such as a wireline insert safety valve or hanger plugs, become stuck across the xmas tree. Mitigation may include well kill capability with a contingency plan in place.

11.1.5

Long tool strings Tool strings for general work below the DHSV may, on occasion, be designed to be longer than the distance between the swab valve and the BOP. In such instances, a thorough risk assessment should be carried out to consider additional mitigation.

11.1.6

Installation and testing of well barriers The barriers in the completed well may be degraded (not in full working order) or have failed: this may be the reason for the workover. Additional barriers may therefore be required to maintain two barriers at all stages of the operations. If two tested barriers cannot be installed, alternative precautions should be planned. The risk assessment covering these procedures should thoroughly consider all aspects, including identifying any suitable mitigations and contingencies. The first stage of an intervention/workover may be to displace formation fluids from the tubing. This may be done through production facilities. The displacement fluid is usually water, seawater offshore, but may be brine at a higher density. The formation fluid in the tubing may be circulated out of the well to the production facilities, or bullheaded back into the formation. In any case, sufficient flow rate and pump capacity are required to ensure removal of all the hydrocarbons from both the tubing and annulus. There have been incidents caused by hydrocarbon releases from wells classified as being unable to flow to surface.

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The connection between the xmas tree and the PCE should be tested to the maximum potential wellhead pressure, plus safety factor if needed. If possible, a deep-set plug (at the bottom of the completion near the packer) should be set to provide a second active inner barrier. The well above the deep-set plug and packer may be filled with kill weight fluid to provide another active barrier (if the fluid can be monitored). Well barriers should be monitored throughout the operation and should include reporting of annulus pressures.

11.1.7

Well control equipment/barriers Potential well control barriers are those used as a backup to the active devices and include a BOP (variable, pipe, blind and shear rams). They need activation to close in the well. Shearing is for use in an emergency, when it is necessary to shear whatever is in the hole and then seal the well. This could include: • • • •

A wire cutting device located on the deck (backed by a blind ram or a valve to seal the wellbore) BSR – designed to shear pipe or wire and seal the well Shear rams – designed to shear but not seal Blind rams – these seal on open hole (required after non-sealing shear rams are used)

Shear rams on a wireline valve will cut wire or cable only. Some xmas tree valves have a cutting capability and are designed to seal after cutting. If valves are used for emergency closure, or they have closed on wire, they should be inspected and redressed as required. Installation safety case duty holders should have performance standards for workover and intervention PCE. These standards should include closure time. Key variables influencing BOP closure time are: hose internal diameter, hose length, control fluid viscosity and temperature. As temperature decreases hose internal diameter, hose length and fluid viscosity have an increasing impact. When operating in temperatures below 50 degrees Fahrenheit consideration should be given to using a low viscosity fluid and/or hoses of ½” internal diameter or greater.

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11.1.8

Intervention/workover well integrity matrices Barriers Active

Stuffing box Wireline BOP

Potential

DHSV1 Xmas tree master valve1

Pressure containment boundaries Casing(s) Cement outside casing Wellhead Casing hanger and seal Tubing hanger and seal

Shearing

Shear seal BOP

Tubing and gas lift valves

Xmas tree valves2

Completion packer

Table 14. Wireline/Slickline Operations Example Matrix Note 1 – may only be effective after the wire is cut by other means. Note 2 – depends if the valves can cut the wire.

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Figure

5.

Example Barrier Schematic for Wireline Operations Figure 5 (10.7.2) from NORSOK D-010 Well integrity in drilling and well operations (Rev. 4, June 2013) [Ref 110] are reproduced by Oil and Gas UK in this Issue 4 of the Oil and Gas UK Well Integrity Guidelines under licence from Standard Online AS 11/2013 © All rights are reserved. Standard Online makes no guarantees or warranties as to the correctness of the reproduction. In any case of dispute, the NORSOK original shall be taken as authoritative. See www.standard.no.

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Inner barrier

Annulus barrier

Coil Active

Check valves

Potential

Pressure containment boundaries Casing(s)

Stripper rubbers

Cement outside casing Wellhead

Coil Tubing BOP

Casing hanger and seal Tubing and gas lift valves

Shearing

Coil tubing shear rams

Completion packer Tubing hanger and seal

Table 15. Example of a Coiled Tubing Operations Matrix

11.2

Responsibilities for the well The well-operator is responsible for the integrity of the well throughout its life cycle. Operational responsibility for the well may be handed over to a different team for intervention/workover operations. There should be a formal handover with a written status report covering at least the well integrity and barriers. Personnel responsible for the well in its ‘operate and maintain’ stage should be consulted in the planning and preparation of the intervention/workover operations.

11.2.1

Isolation from installation emergency shutdown system The xmas tree of the well being worked on may be isolated from the main facility installation control and ESD systems. However, as ESD systems become more reliable, the requirement to isolate the xmas tree from the ESD system should be addressed in the individual risk assessment. The primary control panel should be sited in a safe area away from any hazards that could impede operations. This equipment should be classified as safety critical and should be covered by the installation verification scheme. The operation of the control panel for the well is vital. The persons controlling the panel: • •

Should always be able to activate the panel during operations Should always be in contact with the equipment operators, driller, well supervisor and control room

The panel operator should be competent to recognise an emergency and if appropriate in the circumstances to shut-in the well without consultation.

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The risk assessment may require a second control panel or emergency button to be sited remotely from the primary control panel. These should be located along pre-defined escape routes. Examples of where secondary controls should be available include: • • •

11.3

Bridge-linked platforms (on the accommodation side of the bridge) Installations or wells with high levels of H2S New installations where the costs of permanent installation of such a system are minimal

Intervention/workover planning The well-operator should issue an approved programme or operational procedures covering: • • • • • • • • •

Current status of well Objectives of intervention/workover Responsibility for well (may be handed over from production) Responsibility for managing operations Risk identification and mitigation The operational sequence with enough detail for the proposed activity Contingency plans (well conditions are likely to be different from predictions) Emergency plans (in response to well or associated installation emergency) A diagram showing the PCE arrangement

Modelling, including appropriate fatigue modelling, should be carried out to ensure there is a good understanding of the medium (wire/tubulars) limitations in terms of potential failures.

11.3.1

Risk assessment Extra consideration is required if the reason for the intervention/workover is to replace or repair a failed barrier.

11.3.2

Well control planning The well-operator is responsible for ensuring that suitable well control equipment is provided for the operations. The suitability of the equipment covers: • • • • • • • • • •

Pressure rating Internal diameter (correct size for the wireline, coil or jointed pipe to be used) Number and placement of rams Number and capacity of shear/seal rams Material to suit well or introduce a fluid e.g. H2S Condition (maintenance and testing) of equipment and primary controls Emergency and backup controls Associated equipment (lubricator, crossovers, control skid) Temperature rating Non-metallic materials (elastomers)

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Offshore installation duty holders should include the well control equipment in their verification scheme, which will provide an additional check. If equipment to be run in the well cannot be sheared by the well control equipment, special precautions need to be taken. Contingency plans should be in place if there is a problem with unshearable equipment across the BOP.

11.3.3

Emergency planning Well kill facilities should be available during intervention/workover operations where fluid is part of the well control arrangements. If not immediately available, contingency plans should be made to provide the equipment. Well kill facilities should be available on mobile units (with riser to surface) when connected to a subsea well. There should be an emergency plan covering activating potential barriers in an emergency. This should include recognising when the wire/pipe should be cut, and the sequence for activating the barriers. There should also be remote shutdown button(s) so that the well can be shut-in, even if the well control panel is disabled. Regular and realistic well control drills should be carried out before starting the intervention/workover. These drills should be repeated as needed to ensure a suitable response. There should be a plan of action in the event of an installation alarm not connected with the intervention/workover operations. This will include making the well safe, mustering for nonessential personnel and contacting the installation control room with a roll call of essential personnel at the site.

11.3.4

Information, instruction, training and supervision In all offshore operations from installations, it is the OIM who has overall charge of the safety of the intervention/ workover operation. The OIM should be involved in the handover of the well and be kept aware of the intervention/workover operations. For operations from vessels that are not installations, the well-operator has the overarching duty for the health and safety of the operations. For land operations, the operator of the borehole site has the overarching duty for the health and safety of the operations. For all operations, everyone has a duty of cooperation with the main duty holder. The intervention/workover should be planned and supervised by a competent person to ensure that procedures and plans are followed in a safe manner. The roles and responsibilities for pressure control and well integrity should be defined and communicated to all involved personnel. If required, specific training should be organised. This may be needed for unusual conditions in the well or non-standard operations. For example, using a snubbing unit on a production installation will need

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training for the workover personnel on the platform systems, and training for installation personnel on how to coordinate with the snubbing unit.

11.4

Intervention/workover operations

11.4.1

Well handover Control of the well should be formally transferred to the intervention/workover team. Information to be transferred at handover includes: • • • • •

The status condition and designation of all valves Wellhead pressure Annulus pressures Control line (DHSV and Annulus Safety Valve (ASV)) pressures and status (i.e. pressure locked in or bled off) The flowline pressure

Handover information should be written down and accepted by the intervention/workover team. If appropriate, this handover may be completed at the well so that the physical location of the valves can be confirmed. The personnel responsible for the operations and maintenance of the well should have leak tested the xmas tree valves.

11.4.2

BOP/well control panel A temporary control panel is used for control of the completion/xmas tree valves when they are isolated from the installation controls. The same panel may control the intervention/workover BOP, or it may be a separate panel. Good communication between the well control panel operator and the intervention/workover unit personnel is essential.

11.4.3

BOP installation and testing The BOP maybe tested on a suitable test stump before installation on the well to: • • • • •

Check condition of ram inserts Check correct line size guide if fitted for wireline Check rams meet centrally when functioned (note closing times) Pressure test each set of rams from below Check function of BOP equalising valve

System verification should be carried out after installation, including a function test of all rams via the dedicated control system. If shear seal or BOPs are removed temporarily or any hose connection broken, a repeat verification function test should be done.

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11.4.4

Removing xmas tree For some workovers, the xmas tree needs to be removed for repair, or as the first step in a continued operation. Conventional xmas trees may be removed with the tubing in the well, providing the well is plugged with two barriers typically: • •

Deep, completion packer and deep-set plug Shallow, tubing hanger and plugs

At least one of the barriers should be tested in the direction of flow (from below), if possible, as there will be no potential barriers when the xmas tree has been removed and before installation of the BOP. It may not be possible to test the second plug in the direction of flow. In this case it is necessary to ensure the plug: • • •

Is in the correct position Is firmly locked in place Will withstand pressure from above

Consideration should be given to the effect of wellhead penetrations being potential leak paths e.g. fluid flow in control lines, etc. In addition, consideration should be given to the isolation of the xmas tree from the flowline and production facility.

11.4.5

In-situ tubing repairs In-situ repairs may be used to seal off a leak in the tubing. They will reduce the internal diameter of the completion tubing. Configuration of a wireline set straddle packer assembly or other repair should not compromise the safe operation of the well. Use of a straddle packer should not prevent installation of a deep-set plug to isolate the reservoir interval, even though it may not be possible to run a fixed OD plug to the original nipple through the straddle. Alternative ways of installing a deep-set plug include: • • •

Retrievable straddle assemblies to allow for future deep-set plug installation Installation of an insert in the original nipple so that a smaller OD plug can be used Use of expandable plugs that will pass through the straddle and seal the completion

Tubing repairs should be tested with an internally applied pressure greater than maximum shut-in wellhead pressure. If it is impossible to set a deep plug in the well, the repair should be externally tested to a suitable pressure which considers the worst-case differential pressure across the patch.

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11.4.6

Recovery of equipment from well Equipment recovered from a well should be inspected to ascertain downhole conditions with respect to well integrity and the future life of the well. The results of the inspections and analysis should be recorded, and any learnings considered for future design improvements.

11.5

Wireline operations Slickline is externally smooth single strand wire which is used: • •

To convey tools in and out of the well As a single coaxial conductor or optical core for data transmission

Braided or electric wireline is a multistrand line with a conductor wire, armour and insulation. This construction makes it more difficult to achieve a seal around the wire compared to slickline. If it breaks it tends to collapse into bundles, or birds-nests, which are difficult to fish out of the hole. Braided cable may require seasoning to effect a gas tight seal. The active barrier for wireline operations is: • •

A stuffing box or liquid seal for slickline operations A grease injection head for braided line operations

The effects of ambient temperature, well fluids, well pressure and temperature on the grease should be considered during planning. The equipment should be monitored during operations to ensure it maintains a seal.

11.6

Coiled tubing operations Coiled (or reeled) tubing is continuous pipe, of various diameters, which is spooled on large reels. The inner end is connected, via a rotating joint, to the axle. Fluid can be pumped down the tubing and balls pumped down the pipe for operating downhole tools. These operations are covered by API RP 16ST [Ref 45]. The tubing is pushed in and pulled out of the hole by a tubing injector head. It is important that the correct pressure is kept on the gripper blocks: too much might crush the pipe, and too little could allow the pipe to slide into or out of the well without control.

11.6.1

Coiled tubing pressure control equipment All connections from the xmas tree to the top of the CT BOP should be flanged or clamped and have metal to metal seals. For coiled tubing and HWO operations, a riser analysis should be conducted to identify any issues with loading and buckling from the tree flange to the BOP. For coiled tubing operations, a shear seal BOP should be installed as close as possible to the xmas tree.

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There is a risk of quick connectors backing off during offshore operations due to sea movement. For offshore operations, all connections should either be flanged or clamped, and have metal to metal seals. Alternative connections and seals should only be used where they are qualified for the intended purpose or have been subject to a comprehensive risk assessment and mitigating actions. For example, if a quick connect is used on a coiled tubing rig up to minimise working at height, then that quick connect should be marked and regularly monitored for signs of backoff, with remedial actions identified should a backoff occur.

11.6.2

Annulus barriers The active barrier for coiled tubing operations on a live well is the stripper packer/stuffing box. The use of two stripper packers in one stack of coiled tubing pressure containing equipment may be used, with the lower stripper packer in reserve and not energised. The potential barrier for coiled tubing is a BOP, a smaller scale version of a rig’s drilling BOP. It is usually a quad (four ram bodies) and may have pipe, slip, blind or shear rams installed.

11.6.3

Inner barriers When using coiled tubing on a live well, check valves (nonreturn valves) should be used in the BHA to prevent backflow, unless operational requirements such as reverse circulating preclude their use. There are two forms of check valve: • •

Dart type Flapper type

When NRVs are not run (e.g. when reverse circulating operations are being carried out), then the welloperator should ensure appropriate mitigations are in place. The flapper type valve is designed for use with ball operated tools (such as a shear sub to release the BHA). The dart type valve will not allow the passage of a ball. Typically, two valves are run in tandem, or a dual flapper valve is used to give backup in case of one flapper failing to seal. The coil tubing itself can be a barrier, so its condition should be closely monitored by the service company to prevent failure during operations.

11.6.4

Coiled tubing life cycle Four coiled tubing limitations need to be monitored: • • • •

Life limits – when being run on and off the reel and over the goose neck Tension limits – vary with the weight of coiled tubing and length run Pressure limits – burst and collapse pressures vary with tension and compression Diameter and ovality limits – real time monitoring of the pipe is required to ensure that the pipe is not ballooned, ovalled, or mechanically damaged

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•

Corrosion and abrasion should be considered, and the pipe inspected if coiled tubing is used in a corrosive or abrasive environment

To track fatigue loading conditions, coiled tubing companies should have computer-based systems to quantify and record the historical job exposure of each string. Depending on the internal pressure present in each section of the coiled tubing while reeling, unreeling or travelling over the goose neck, varying factors are applied to the cycle count to adjust the cycle life of that section. Past and present job data should be merged and kept on file to maintain up-to-date records for each string. This data should be reviewed by the well-operator during the planning of well intervention/workovers with coiled tubing.

11.7 11.7.1

Fluid pumping operations and stimulation General Considerations There may be a need to pump fluid into a well for operational or reservoir stimulation reasons and such operations require planning and consideration of well barriers. To gain access to the well requires breaking into the pressure containment envelope or well pipework downstream of the production master valve(s). The effects of the fluid being injected, and the pressures generated on the well pressure containment boundary should be part of the well design and should be reviewed as part of the planning for fluid pumping operations. Facilities should be available to monitor adjacent annuli for pressure build up; the cause of any pressure increase (temperature, pipe expansion or leak) should be verified. After pumping, all annuli (that can be monitored) should be monitored regularly until temperature equilibrium is reached. Pumping operations should be conducted in accordance with written procedures/standards agreed between the well-operator and the installation (or vessel) operator (or borehole site operator) considering the following: • • • • • • •

Fitment of pressure relief valves Pressure bleed off arrangements Communication especially if the pump unit is in a different or remote location “Make Safe” procedure if the pumping operation is suspended Use of a check valve in the pump in line Selection of appropriate temporary piping (size, pressure rating, fluid composition etc.) Anchoring and restraining of temporary piping

The above is not an exhaustive list of the issues to be considered

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The connection from the pumping equipment should be tested before opening any valves in the pipework. All the well barriers and pipework should be reinstated and tested after the operations.

11.7.2

Stimulation Operations For stimulation operations consideration should be given to the containment of induced fractures and the risk of induced seismicity.

11.7.2.1

Fracture Containment Well integrity during hydraulic fracturing operations should always be maintained. The induced fracture should be contained so that it does not create an unplanned flow path. The hydraulic fracturing programme should describe the control and mitigation measures for fracture containment and the proposed design of the fracture geometry including: • • •

Fracturing target zones Aquifers (both fresh and saline water) Sealing mechanisms preventing fracturing fluids migrating from the designed fracture zones

Performance standards should be documented which characterise the basis for the sealing mechanism and demonstrate that adequate control measures will be implemented. Examples of control measures include modelling and by exception micro-seismic or tiltmeter monitoring of hydraulic fracture growth. Fracturing operations should be monitored and recorded and compared with the hydraulic fracturing programme performance standards. Faults that may impact the hydraulic fracturing seal mechanism should be thoroughly researched and documented and referenced in the hydraulic fracturing programme to demonstrate that fracturing fluids cannot migrate, via faults, beyond the designed fracturing zones. 11.7.2.2

Induced Seismicity Risk The risk of induced seismic events should be considered when planning a hydraulic fracturing operation and adequate controls put in place to eliminate or to minimise any potential impact; this is particularly important for onshore operations. Wellbore pressures during fracturing operations are a key factor in determining induced seismicity risk. Consideration should be given to the following factors that affect pressure in the well during fracturing operations: • • • •

The volume of injected fluid, larger volumes generate higher pressures. The volume of flow back fluid, larger flow-back volumes reduce the pressure. The injection rate, more rapid injection generates higher pressures. The flow-back rate, more rapid flow-back reduces the pressure.

The induced seismicity risk assessment control and mitigation measures identified should be included in the hydraulic fracturing programme.

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Particular attention should be paid to hydraulic fracturing in the presence of a pre-stressed fault and, where practicable, induced seismicity risk should be mitigated by identifying pre-stressed faults and avoiding fracturing fluids entering such faults. The risk assessment should consider the following: • • •

Geological knowledge of the play area Actual field experience in the area The depth of fracturing operations

To adequately evaluate the area and the associated induced seismicity risk sufficient geological information should be gathered; this information should include an understanding of the in-situ stresses. Site specific surveys should be carried out prior to hydraulic fracturing to characterise local stresses and identify nearby faults and stress data from nearby boreholes should be integrated. The potential presence of faults that cannot be detected within the limitations of seismic reflection surveys should be considered. 11.7.2.3

Pre-fracturing injection test A pre-fracturing injection test should be considered to characterise the fracture behaviour of a particular formation and inform subsequent operations. Enough time should be allowed following the test to ensure no seismic activity occurs as injected fluid migrates away from the well and stresses in the surrounding rocks are redistributed. Further information on hydraulic fracturing may be found in API RP 100-1 Hydraulic Fracturing – Well Integrity & Fracture Containment [Ref 54].

11.7.2.4

Matrix acidisation If matrix acidisation operations are planned, particular attention should be paid to the following: • • •

inhibition requirements to mitigate corrosion when live acids are being injected during acid backflows, verification that corrosion levels are tolerable, particularly as the spent acid may still be corrosive and may no longer be fully inhibited monitoring during both injection and flowbacks to ensure that the strength and concentration of the acid does not have the potential to cause excessive corrosion.

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12 Abandonment Well integrity during the ‘abandon’ phase is covered in the Oil & Gas UK Well Decommissioning Guidelines [Ref 24].

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13 Special cases 13.1

Multi-Lateral and Multi-Branched Wells The Technical Advancement of Multilateral Wells guidance (TAML) [Ref 135] makes a distinction between multi-lateral and multi-branched wells as follows: A multi-lateral well is one in which there is more than one open horizontal or near -horizontal lateral well drilled from a single site (or mother bore) and connected back to a single bore. A multi-branched well is one which has more than one open branch well drilled from a single site connected back to a single bore. The branch may be vertical, horizontal, inclined or a combination of all three. Well integrity considerations for these well types concern junction integrity, well control and abandonment. More detailed information may be found in the TAML guidance [Ref 135].

13.1.1

Junction Integrity The multi-lateral or multi-branch junction should be considered an integral part of the casing design. It should be designed to ensure the junction construction, however formed, and including any exposed formation adjacent to the junction, can withstand the anticipated loads during construction, operation and abandonment of the multi-lateral well. During well construction and subsequent operations, consideration should be given to the potential for damage to the junction (e.g. casing wear) and the potential consequences and their mitigation.

13.1.2

Well Control Consideration should be given to well control for multi-branched and multi-lateral wells which may require a different response to conventional single bore operations. One important aspect is how well control is addressed in the operational programme and rig crew training. Kick indications, such as pit gain and increasing flow out of the well, and the causes of kicks, such as swabbing and insufficient mud weight, will be the same as conventional single bore wells. On a well with multiple branches or laterals particular care should be taken: •

• •

When re-entering a bore that has not been entered for some time and in which hydrocarbons may be present. Poor fluid condition and/or diffusion of hydrocarbons into the well while static may result in the presence of a bubble of gas. To consider the potential for underbalanced conditions on the static bores due to pressure changes on the active bore (e.g. swabbing or insufficient hole fill). Programme instructions should contain guidance on assessing which bore has taken the influx (i.e. the active or static bores).

Provided reliable hydraulic isolation between the bores is maintained, existing well control methods may be applicable and well control in each bore managed separately.

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If hydraulic isolation is not maintained however, when planning for well control operations consideration should be given to the following: • • •

The weakest formation in each bore and the potential for formation breakdown at this point. The potential for influx from each bore and the presence of multiple kicks. The potential for different mud weights in each bore and the potential for different bottom hole pressures for a given surface pressure during a well kill.

Given the number of different multi-lateral systems the well programme should also provide guidance for well control considerations specific to the multi-lateral system being deployed (e.g. how to manage a kick with a particular whip-stock or anchoring system and with debris in the hole).

13.1.3

Multi-Lateral Abandonment The design of a multi-lateral or multi-branch well should consider the abandonment of the well such that each lateral, and ultimately the whole well, can be abandoned in accordance with the Oil and Gas UK Well Decommissioning Guidelines [Ref 24].

13.2

Cuttings re-injection/disposal wells (offshore only) CRI/disposal wells are designed and used to inject liquids (water, brines, slurries or similar) into dedicated formation(s). These wells enable well-operators to achieve zero discharge targets. Such wells need to be carefully managed for the following reasons: • • • • •

Plugging due to improper slurry rheology Plugging due to improper operational procedures Failure to reseal the fracture resulting in high casing pressure Excessive erosional wear from long-term slurry injection Corrosion from long-term injection.

Plugging of the injection conduit can lead to rapid pressure build-up, and possibly cause casing collapse or tubing burst. Consideration should be given to the annuli adjacent to the cuttings re-injection annulus. If these are not full of fluid cuttings re-injection may increase the risk of casing failure. Well-operators should have procedures in place covering: • •

• •

Slurry design: slurry rheology design includes ensuring the correct slurry viscosity, solid carrying capacity, and optimal particle size distribution. Operational procedure design: the injection rate should be high enough to avoid cuttings plugging off the fracture or settling and forming solid beds along the injection annulus or tubular. Monitoring and verification: monitoring and verification of CRI operations are integral parts of the operation’s quality assurance process. Disposal well capacity.

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Appendix 1 – Background to these guidelines In May 2010 the UK offshore oil and gas industry set up the OSPRAG to review the UK’s well control practices and oil spill response capability following the Macondo tragedy on 20 April 2010. One of OSPRAG’s four review groups, the Technical Review Group (TRG), carried out a review of industry practices and procedures relating to well examination, verification, and primary well control; BOP competency, behaviours, and human factors. The unanimous conclusion was that there is a high degree of confidence in the UKCS regulatory regime and that it drives the right health, safety and environmental behaviours. Several recommendations to the Industry were proposed which were primarily based upon the best practices observed during the TRG review. A TRG recommendation was for Oil & Gas UK to form a project team to compile a series of well life cycle integrity guidelines similar to those prepared for well abandonment. For more information, please refer to the OSPRAG final report which is available from the Oil & Gas UK website: http://oilandgasuk.co.uk/product/final-report-of-the-uk-oil-spillprevention-and-response-advisory-group/ The Well Life Cycle Practices Forum (now called the Wells Forum) was set up in December 2010 by Oil & Gas UK as a vehicle for implementing the TRG recommendations and as a permanent forum in which well-related pan-industry issues can be identified and discussed. The Wells Forum is also the interface of choice for HSE, the OGA, and the Department for Business, Energy & Industrial Strategy (BEIS) to engage the UK offshore industry on well-related matters. The Wells Forum has representatives from over 60 different operators and well management companies, who have been involved in the various workgroups and review cycles. The WLCIG had its first meeting in January 2011 and continued with at least monthly meetings through 2011. A first draft was reviewed internally and at a review day 24 August 2011 with input from United Kingdom Onshore Oil and Gas (UKOOG) and Norwegian operators (OLF). In 2012 the guidelines underwent a full review by the WLCPF member companies. Following approval by the Board of Oil & Gas UK, Issue 1 was published in July 2012. After Issue 1 of the Guidelines, the UKOOG issued the UK Onshore Shale Gas Well Guidelines in February 2013. The UKOOG Guidelines [Ref 131] reference the Oil & Gas UK Well Integrity Guidelines for all aspects of well integrity covered by these guidelines. Through 2013 the Oil & Gas UK well integrity workgroup undertook reviews of annulus pressure management and pressure testing to identify potential updates to the Guidelines. Workgroup members provided input to the development of NORSOK D-010 Rev 4 and International Oil and Gas Producers Association (IOGP) Technical Specifications for well integrity. A workshop for Oil & Gas UK member companies and representatives from the Norwegian well integrity forum, IOGP well integrity workgroup, BEIS, HSE and UKOOG was held in June 2013. Feedback on the Guidelines and proposed changes were reviewed and draft content for Issue 2 of the Guidelines was agreed. Gap analyses were performed against the current NORSOK D-010 and the draft IOGP Technical Specification for well integrity during the operational phase. An updated draft Issue 2 was circulated to Oil & Gas UK members and the wider industry for review in December 2013. Issue 2 was published in June 2014.

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Issue 3 of the Guidelines was developed based on feedback from Issue 2 and a workshop held in June 2015. Four sub-teams were formed to work specific issues: ISO, Asset Life Extension, Legislation and General Well Integrity. Issue 3 was discussed with the Norwegian Well Integrity Forum and with the IOGP workgroup producing the ISO standard for full life cycle well integrity to confirm there were no significant gaps between Issue 3 and their work. The document also benefitted from input and review by UKOOG to include input from the UKOOG Shale gas Guidelines. A draft of Issue 3 was issued for industry review in November 2015. Issue 3 was issued in March 2016. Issue 4 of the guidelines was developed based on feedback and learnings from Issue 3. Alignment with API S53, the IOGP process safety guidance documents, and ISO Well Integrity guidelines [Ref 80 & 81] have been reviewed and incorporated. Retirement of the O&GUK offshore BOP guidelines whilst retaining the good practices developed for the UK sector has been considered and incorporated. Input has also been incorporated from the onshore UK gas storage industry. The well life cycle integrity workgroup and its sub-teams included: • • • • • • • • • • • • • •

Co-leads: Steve Bedford (BP), Mike Richardson (Spirit Energy) Taylor Begnaud (Chevron Upstream Europe) Bill Barrows (CNOOC International Limited) Gavin Mundie (Taqa Bratani Ltd) Ian Taylor (Shell Upstream International) Joseph From (iGas) David McGuckien (CNOOC International Limited) Mike Hartley (Neptune Energy Limited) Peter Irvine (ConocoPhillips (U.K.) Limited) Ronald Schutz (Wintershall Noordzee B.V.) Carl Johnson (Schlumberger) Stuart Connon (Total E&P U.K. Limited) Huw Roberts (Premier Oil) Laura Bennie (Oil & Gas UK)

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Appendix 2 – Divestment Information BS EN ISO 16530-1:2017 provides guidance in section 5.10 on reporting and documentation for wells. Oil and gas wells have been drilled in the United Kingdom since the late 19th century. Reporting and documentation requirements have varied over time. Multiple systems have been used to store information including: paper, microforms, fax and computer-based document management systems. Some of the storage systems are not robust e.g. text on fax paper can fade over time. As information has been transferred between various systems (e.g. computer system upgrades) there is a risk that information has been lost. The purpose of this Appendix is to provide guidance on the minimum information on wells that should be provided by the seller divesting an asset to enable the purchaser to manage well integrity. This guidance supports the OGA guidance on information and sample plans by providing a summary of the minimum information required in a table that can be used as checklist if desired. Well-operators should also use this list to define the information they should retain throughout the well’s life. Minimum Well Information for Divestment

Item

Description

Master wells list

A list of all the wells in the asset being divested (including abandoned wells) with the current and previous well status as per WONS (e.g. a water injection well may have formerly been a production well), OGA well number, local well number, field and installation to which the well is connected.

Well location map

Map showing the location of each well which is being divested, including abandoned wells. For offshore platforms this could be a slot diagram, for land wells this could be a well site diagram or for subsea manifold it could be a manifold schematic. GPS coordinates should be included to aid future location of the wellbore if required.

Definitive wellbore survey

For every well, including abandoned wells, a survey (reference point, measured depth, true vertical depth, inclination and azimuth) of the complete wellbore and any sidetracks that includes the surface co-ordinates of the well and survey tools used.

Well intervention records

Activity summaries, logs and/or pictures from the most recent well interventions since the current completion was installed.

Well maintenance records

Work undertaken and results from the last well maintenance undertaken, including any local monitoring such as visual inspections of subsea wells and groundwater surveys around land wells

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Well completion diagram / information

One or more documents that provide the following for each well: Rig name, rotary table elevation, spud date and completion date. Total depth, hold up or plug back depth. Leak off or Formation integrity test results. Fish left in hole with: description of the fish, length, depth and dimensions. Conductor/casing/liner shoe depth and top with: OD, grade, connection type, weight, test pressure and information on any installed components (e.g. conductor centralisers, liner hanger system, burst disc and/or stage collar) for each string. Cement top and method of verification e.g. log, calculated. Completion components (including control lines, gauges and clamps) with: manufacturer, description, depth, maximum OD, minimum ID, connection type and any operating instructions with status e.g. direction to shift a sleeve open or closed and current position, downhole safety valve operating pressure Wellhead (including associated valves) and xmas tree manufacturer, type, rated working pressure, test pressure, minimum IDs, test ports, seal types, internal profiles, valve turns to open/close or fluid volume required for actuated valves to open/close. Pressure containment barriers, including contents, design and operating limits for each annulus. Operating risks and conditions e.g. thermal movement or conditions attached to the well operating consents. Anomalies e.g. failed valves.

Well Examination

The Well Examiner’s reports specified in the O&GUK guidelines for well-operators on well examination issue 2 [Ref 26]

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Abbreviations and Glossary Abbreviation

Definition

A annulus

Inner most annulus

ALARP

as low as reasonably practicable

ALE

Asset Life Extension

API

American Petroleum Institute

ASV

Annulus Safety Valve

BEIS

Department for Business, Energy & Industrial Strategy

BHA

Bottomhole Assembly

BOP

Blowout Preventer

BPV

Back Pressure Valves

BSOR

Borehole Sites and Operations Regulations 1995

BSR

Blind Shear Ram

CDA

Common Data Access (a not for profit subsidiary of Oil and Gas UK http://cdal.com)

CRI

Cuttings Re-Injection

CT

Coiled Tubing

CWOP

Complete Well on Paper

DCR

Offshore Installations and Wells (Design and Construction, etc) Regulations 1996

DHSV

Downhole Safety Valve (Can also be referred to as a Sub-surface Safety Valve (SSSV) and other derivations)

DP

Dynamically Positioned

DST

Drill Stem Test

DWOP

Drill Well on Paper

EA

Environment Agency

ECD

Equivalent Circulating Density

EEMS

Environmental and Emissions Monitoring System

ES

Environmental Statement

ESD

Emergency Shutdown

ESP

Electric Submersible Pump

Well Life Cycle Integrity Guidelines Issue 4

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Abbreviation

Definition

FIT

Formation Integrity Test

FIV

Formation Isolation Valve

FPSO

Floating Production Storage and Offloading Unit

H2O

Water

H2S

Hydrogen Sulphide

HAZID

Hazard Identification Study

HAZOP

Hazard and Operability Study

HP

High Pressure

HPHT

High Pressure High Temperature

HSE

Health and Safety Executive

HSP

Hydraulic Submersible Pump

HWO

Hydraulic Workover

IADC

International Association of Drilling Contractors

IBOP

Internal Blowout Preventer

ICP

Independent Competent Person

ID

Inside Diameter

ISCWSA

Industry Steering Committee for Wellbore Surveying Accuracy http://iscwsa.org/

IOGP

International Oil and Gas Producers Association

ISO

International Organization for Standardization

LEL

Lower Explosive Limit

LOPA

Layer of Protection Analysis is a risk assessment and hazard evaluation method which provides a simplified balance between qualitative process hazard analysis and detailed and costly quantitative risk analysis.

LOT

Leak Off Test

MAASP

Maximum Allowable Annulus Surface Pressure

MAOP

Maximum Allowable Operating Pressure

MD

Measured Depth

MoC

Management of Change

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Abbreviation

Definition

MODU

Mobile Offshore Drilling Units

MPD

Managed Pressure Drilling

MWD

Measurement While Drilling

NORSOK

Standards Norway

NRV

Non-Return Valve

OD

Outside Diameter

OGA

Oil and Gas Authority

OIM

Offshore Installation Manager

OPEP

Oil Pollution Emergency Plans

OPOL

Offshore Pollution Liability Agreement

OSDR

Offshore Safety Directive Regulator

OPPC

Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005

PA

Public Address

P&ID

Piping and Instrumentation Diagram

PBR

Polished Bore Receptacles

PBU

Pressure Build-Up

PCE

Pressure Control Equipment

PCP

Progressive Cavity Pump

PFO

Pressure Fall-Off

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Abbreviation

Definition

pressure containment boundary / envelope

The well is defined in terms of its pressure containment boundary. Any equipment that is vital to controlling the pressure within the well is therefore covered. This would include downhole pressurecontaining equipment and the pressure-containing equipment on top of the well such as BOPs or Christmas trees, but excludes well control equipment downstream that can be isolated from the well by valves. Examples of where the well ends are: • • •

above the top BOP in the BOP stack and outside the choke and kill valves downstream of the swab and production wing valves of an xmas tree at the top of the wireline stuffing box of a wireline BOP Regulation 2, paragraph 14, DCR Guidance

PVT

Pit Volume Total

QA

Quality Assurance

QC

Quality Control

QHSE

Quality Health Safety Environment

RCD

Rotating Control Device

ROV

Remotely Operated Vehicle

SECE

Safety and Environmental-Critical Element

SEMS

Safety and Environmental Management System

SCR

Slow Circulating Rate

SCR 2005

Offshore Installation (Safety Case) Regulations 2005

SCR 2015

Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015

SCSSSV

Surface Controlled Sub-Surface Safety Valve

SF

Separation Factor

SG

Specific Gravity

SMS

Safety Management System

SSTT

Subsea Test Tree

SSSV

See DHSV

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Abbreviation

Definition

Swage

A short crossover joint used between two sizes or specifications of casing. A circulating swage is an adapter that enables a temporary circulating line to be rigged to the top of the casing string, allowing circulation of fluids to help properly locate the casing string.

TCP

Tubing-Conveyed Perforating

TD

Total Depth

TRG

Technical Review Group

TOC

Top of Cement

UBD

Under Balance Drilling

UBO

Under Balanced Operation

UKOOG

UK Onshore Operators Group

UKCS

United Kingdom Continental Shelf

VBR

Variable Bore Rams

VR

Valve Removal

Well

A well made by drilling or a borehole drilled with a view to the extraction of minerals through it or another well. [Regulation 2, DCR]

well-examiner

In this document ‘well-examiner’ means an independent and competent person who performs functions in relation to a well examination scheme. [Regulation 2, SCR 2015]

Well examination scheme

Has the meaning given in regulation 11(1) of SCR 2015.

well-operator

In relation to a well, means the person appointed by the licensee for a well to execute the function of organising and supervising all operations to be carried out by means or, where no such person has been appointed, the licensee (DCR guidance)

WIMS

Well Integrity Management System

WLCIG

Well Life Cycle Integrity Guidelines

WLCPF

Well Life Cycle Practices Forum (an Oil & Gas UK forum)

WONS

Well Operations Notification System

Workover

A term used to describe activity that changes the completed status of a well. Typically, the term covers non-drilling activity undertaken with a rig but may also be used to describe intervention operations that change the completed status of the well.

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References and useful reading #

Reference to

Health and Safely Executive (HSE) regulations and guidance 1

[DCR] The Offshore Installations and Wells (Design and Construction, etc) Regulations 1996, (SI 1996/913) as amended. http://www.legislation.gov.uk/uksi/1996/913/contents/made

2

[DCR guidance] A guide to the well aspects of the Offshore Installation and Wells (Design and Construction, etc) Regulations 1996 – L84, Second edition 2008, ISBN 978 0 7176 6296 8, www.hse.gov.uk/pubns/books/l84.htm

3

[SCR 2015] The Offshore Installations (Offshore Safety Directive) (Safety Case etc.) Regulations 2015 (SI 2015/398). http://www.legislation.gov.uk/uksi/2015/398/contents/made

4

[FLA] The Offshore Petroleum Licensing (Offshore Safety Directive) Regulations 2015 (SI 2015/385) https://www.legislation.gov.uk/uksi/2015/385/contents/made

5

[SCR 05] The Offshore Installation (Safety Case) Regulations 2005 (SI 2005/3117) as amended. http://www.legislation.gov.uk/uksi/2005/3117/contents/made

6

[OSCR guidance] A guide to the Offshore Installation (Safety Case) Regulations 2005 – L30, Third edition 2006, ISBN 978 0 7176 6184 8, www.hse.gov.uk/pubns/books/l30.htm

7

[MAR] A guide to the Offshore Installations and Pipeline Works (Management and Administration) Regulations 1995 – L70, Second edition 2002, ISBN 9 7807 1762 5727, www.hse.gov.uk/pubns/books/l70.htm

8

[HSG 65] Successful health and safety management. HSG 65, Second edition 1997, ISBN 0 7176 1276 7, www.hse.gov.uk/pubns/books/hsg65.htm

9

[PFEER] Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations 1995 – L65, Approved Code of Practice and guidance, Second Edition 1997, ISBN 9 7807 1761 3861, www.hse.gov.uk/pubns/books/l65.htm

10

[HSG 48] Reducing error and influencing behaviour HSG 48, Second edition 1999, ISBN 0 7176 2452 8, www.hse.gov.uk/pubns/books/hsg48.htm

11

[BSOR] Borehole Sites and Operations Regulations 1995 (SI1995/2038) http://www.legislation.gov.uk/uksi/1995/2038/contents/made

12

[BSOR guidance] A guide to the Borehole Sites and Operations Regulations 1995 – L72, Second edition 2008, ISBN 978 0 7176 6287 6, www.hse.gov.uk/pubns/books/l72.htm

13

[PUWER] Safe use of work equipment. Provision and use of Work Equipment Regulations 1998. Approved Code of Practice and guidance – L22, Third Edition 2008, ISBN 978 0 7176 6295 1, http://www.hse.gov.uk/pubns/books/l22.htm

Well Life Cycle Integrity Guidelines Issue 4

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#

Reference to

14

[HSWA] Health and Safety at Work etc Act 1974, http://www.legislation.gov.uk/ukpga/1974/37/contents

15

Jack-up (self-elevating) installations: review and location approval using desk-top risk assessments in lieu of undertaking site soils borings, Offshore Information Sheet No 3/2008, http://www.hse.gov.uk/offshore/infosheets/is3-2008.pdf

16

ALARP - HSE internet guidance (accessed October 2011), http://www.hse.gov.uk/risk/theory/alarpglance.htm

17

[LOLER] Lifting Operations and Lifting Equipment Regulations 1998. Approved Code of Practice and guidance – L113, ISBN 978 07176 -16282, www.hse.gov.uk/workequipment-machinery/loler.htm

18

Understanding Offshore Oil and Gas Notifications (2017/329870), https://www.google.com/url?q=http://www.hse.gov.uk/osdr/assets/docs/understanding -offshore-oil-and-gas-wellsnotifications.pdf&sa=U&ved=0ahUKEwjescrO57vZAhVIDCwKHSBYBkMQFggIMAE&client= internal-udscse&cx=015848178315289032903:hqkynptgd1o&usg=AOvVaw0pNTB13PwvIJg8e7Om4u vu

19

Understanding Onshore Oil and Gas Notifications https://www.google.com/url?q=http://www.hse.gov.uk/foi/internalops/og/og00094.pdf&sa=U&ved=0ahUKEwjescrO57vZAhVIDCwKHSBYBkMQFggKMAI&client=intern al-uds-cse&cx=015848178315289032903:hqkynptgd1o&usg=AOvVaw1NmdhrgRtrgKfO32IFakq

20

[COMAH] Control of Major Accident Hazards Regulations 2015, http://www.hse.gov.uk/comah/

21

Safety in pressure testing, Guidance Note GS4, ISBN 978 0 7176 1629 9, http://www.hse.gov.uk/pubns/gs4.htm

22

[RIDDOR] The Reporting of Injuries, Diseases and Dangerous Occurrences Regulations 2013 http://www.legislation.gov.uk/uksi/2013/1471/contents/made

23a

Report of an incident or dangerous occurrence onshore https://extranet.hse.gov.uk/lfserver/external/F2508DOE

23b

Report of an incident or dangerous occurrence offshore http://www.hse.gov.uk/osdr/reporting/incidents-to-osdr.htm

Oil & Gas UK and Step Change in Safety documents Oil & Gas UK guidelines can be accessed at the publications website https://oilandgasuk.co.uk/publications-shop/ Members of Oil & Gas UK can access the guidelines free of charge.

Well Life Cycle Integrity Guidelines Issue 4

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#

Reference to

Step Change in Safety documents can be downloaded from https://www.stepchangeinsafety.net/safety-resources/publications 24

Well Decommissioning Guidelines, Issue 6, June 2018 ISBN 1 903 004 92 6.

25

Guidelines on qualification of materials for the abandonment of wells, Issue 2, October 2015. ISBN: 1 903 004 56 x

26

Guidelines for well-operators on well examination, Issue 2, August 2017. ISBN 1 903 004 88 8

27

Guidelines for well-operators on competency of well-examiners, Issue 2, August 2017, ISBN 1 903 004 89 6

28

Well integrity guidelines, Issue 1, July 2012, ISBN 1 903 003 82 9.

29

Guidelines on relief well planning for offshore wells, Issue 2, March 2013, ISBN: 1 903 003 92 4.

30

Guidelines on competency of wells personnel, Issue 2, August 2107, ISBN 1 903 004 90 X

31

Guidelines on BOP Systems for Offshore Wells, Issue 2 May 2014, ISBN 1 903 004 27 6

32

Step Change in Safety: Assurance & verification guidance suite (tier 1, 2 and 3).

33

HS011–OCES–Operators Cooperative Emergency Services Agreement (2011), http://oilandgasuk.co.uk/wp-content/uploads/2015/05/OP076.pdf

34

OSPRAG – Technical Review Group Final Report. Updated September 2011 http://oilandgasuk.co.uk/wp-content/uploads/2015/05/EN022.pdf

35

Report on risk assessment workshop (1st November 2011). Which UKCS operations need two Blind Shear Rams? Part of reference 31.

36

Step Change in Safety: Task Risk Assessment Guide. https://www.stepchangeinsafety.net/safety-resources/publications/task-riskassessment-guide

37

Step Change in Safety: Human Factors First Steps https://www.stepchangeinsafety.net/safety-resources/publications/human-factors-firststeps

38

Step Change in Safety: Human Factors Toolkit https://www.stepchangeinsafety.net/safety-resources/human-factors

American Petroleum Institute (API) documents

Well Life Cycle Integrity Guidelines Issue 4

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#

Reference to

API documents are available from http://www.api.org/publications-standards-andstatistics/publications-catalog 39

[API Std 53] Blowout Prevention Equipment Systems for Drilling Wells, Fourth Edition. Published 1st November 2012.

40

[API Spec 17D] Design and Operation of Subsea Production Systems-Subsea Wellhead and Tree Equipment (ISO 13628-4), 2nd edition: 1 May 2011.

41

[API Spec 14A] Subsurface Safety Valve Equipment (ISO 10432), 12th edition: 2015.

42

[API 10] Recommended practices for testing well cements: series, various dates.

43

[API Spec 11D1] Packers and Bridge Plugs (ISO 14310), 3rd edition: 2015.

44

[API S 598] Valve inspection and testing, 9th edition: 1 September 2009.

45

[API RP 14B] Design, Installation, Repair and Operation of Subsurface Safety Valve Systems, Sixth Edition, (2015)

46

[API Std 6AV2] Installation, maintenance and repair of surface safety valves and underwater safety valves offshore. 1st edition: August 2014.

47

[API RP 17H] Remotely Operated Tools and Interfaces on Subsea Production Systems (ISO 13628-8) 2nd edition (includes errata) January 2014.

48

[API Spec 16A] Drill-Through Equipment (ISO 13533), 3rd edition 2004.

49

[API Spec 6A718] Nickel Base Alloy 718 (UNS N07718) for Oil and Gas Drilling and Production Equipment, Second Edition, 2009

50

[API S65 – part 2] Isolating Potential Flow Zones During Well Construction, 2nd Edition: Dec 2010.

51

[API 16ST] Coiled tubing well control equipment systems, 1st edition: March 2009.

53

[API RP 10F] Recommended Practice for Performance Testing of Cementing Float Equipment (ISO 10427), 3rd edition: 2002 (Reaffirmed 2010)

54

API RP 100-1 Recommended Practice for Hydraulic Fracturing – Well Integrity and Fracture Containment, 1st edition: October 2015.

Energy Institute (EI) documents These documents are available from https://publishing.energyinst.org/ 60

Model code of safe practice Part 17 Volume 1: High pressure and high temperature well planning, First edition April 2009, ISBN 978 0 85293 529 3.

61

Model code of safe practice Part 17 Volume 2: well control during the drilling and testing of high pressure and high temperature offshore wells, Second edition April 2009, ISBN 978 0 85293 507 1.

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#

Reference to

62

Model code of safe practice Part 17 Volume 3: High pressure and high temperature well completions and interventions, First edition April 2009, ISBN 978 0 85293 530 9.

63

Guidelines for the management of safety critical elements, Second edition March 2007, ISBN 978 0 852293 462 3.

64

Guidelines for routine and non-routine subsea operations from floating (drilling) vessels, 1995 ref: 978-0-85293-156-1, ISBN 0 85293 156 5.

65

Guidelines for the analysis of jackup and fixed platform well conductor systems, 2001 ref: 978-0-85293-284-1, ISBN 0 85293 284 7.

International Organisation for Standardisation (ISO) documents These documents are available from the International Oil and Gas Producers Association (IOGP) website (in addition to the ISO website) https://www.iogp.org/bookstore/ 70

[BS EN ISO 11960] Petroleum and natural gas industries – steel pipes for use as casing or tubing for wells, 2014

71

[BS EN ISO 15156] Materials for use in H2S-containing environments in oil and gas production, 2015.

72

[BS EN ISO 10423] Petroleum and natural gas industries – drilling and production equipment – wellhead and christmas tree equipment, 2009.

73

[BS EN ISO 14310] Petroleum and natural gas industries – downhole equipment – packers and bridge plugs, 2008.

74

[BS EN ISO 10417] Petroleum and natural gas industries – subsurface safety valve systems – design, installation, operation and redress, 2004.

75

[BS EN ISO 4406] Hydraulic fluid power – Fluids - Method for coding the level of contamination by solid particles, 1999.

76

[BS EN ISO 13680] Specification for corrosion resistant alloy (CRA) seamless tubes for use as casing, tubing and coupling stock, 2010.

77

[BS EN ISO 13628-4:2010] Design and operation of subsea production systems -- Part 4: Subsea wellhead and tree equipment.

78

[PD ISO/TR 12489:2013] Petroleum, petrochemical and natural gas industries. Reliability modelling and calculation of safety systems

79

[ISO 31000:2009] Risk management – principles and guidelines.

80

[BS EN ISO 16530-1:2017] Petroleum and natural gas industries - Well integrity. Part 1: Life cycle governance

81

[BS EN ISO 16530-2:2014] Well integrity - Part 2: Well integrity for the operational phase

Department for Business, Energy & Industrial Strategy regulations and guidance.

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#

Reference to

Guidance on BEIS regulations is available from the following website: http://og.decc.gov.uk/en/olgs/cms/environment/leg_guidance/leg_guidance.aspxhttps://www.g ov.uk/guidance/oil-and-gas-offshore-environmental-legislation 90

[OPRC] Merchant Shipping (Oil Pollution Preparedness, Response Co-operation Convention) Regulations 1998 http://www.legislation.gov.uk/uksi/1998/1056/contents/made

91

[OCR] Offshore Chemicals Regulations 2002 (as amended 2011) http://www.legislation.gov.uk/uksi/2011/982/contents/made

92

[OPPC] Offshore Petroleum Activities (Oil Pollution Prevention and Control) Regulations 2005 (as amended 2011) http://www.legislation.gov.uk/uksi/2011/983/contents/made

93

[EIA] Offshore Petroleum and Production & Pipelines (Assessment of Environmental effects) Regulations 1999 (as amended 2007) http://www.legislation.gov.uk/uksi/1999/360/contents/made

94

[EPC] Offshore Installations (Emergency Pollution Control) Regulations 2002 http://www.legislation.gov.uk/uksi/2002/1861/contents/made

95

[PON] Oil and Gas: Petroleum Operations Notices https://www.gov.uk/guidance/oil-andgas-environmental-alerts-and-incident-reporting#pon-1

Other documents 110

NORSOK Standard D-010 Well integrity in drilling and well operations, (Rev.4, June 2013), http://www.standard.no/en/webshop/ProductCatalog/ProductPresentation/?ProductID= 644901

111

Norwegian Oil and Gas Recommended guidelines for well integrity – No:117, Revision 6 June 2011, https://www.norskoljeoggass.no/contentassets/e8f7a98e933b43feb76f823097e2e7b8/1 17-norwegian-oil-and-gas--recommended-guidelines-well-integrity---rev-6-final.pdf

112

Developing and maintaining staff competence, Railway Safe Publication 1; Office of rail regulation, Second edition 2007, ISBN 07176 1732 7.

113

Competence management systems – guide to approval, OPITO 004.04B, Rev.09 – December 2009.

114

Supervisor competency guidelines, Enform: The (Canadian) safety association for the oil and gas industry 2010, http://www.enform.ca/files/pdf/publications/Supervisor_Competency_Guideline_Final.p df

115

Disastrous Decisions: The Human and Organisational Causes of the Gulf of Mexico Blowout, Andrew Hopkins, 2012, ISBN 978 1 921948 77 0

116

[NOS] National occupational standards, UK Commission for employment and skills (accessed October 2011), http://www.ukstandards.co.uk/Pages/index.aspx

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#

Reference to

117

Capping and Containment – IOGP Global Industry Response Group recommendations. Report No. 464, May 2011, https://www.iogp.org/bookstore/product/capping-andcontainment-global-industry-response-group-recommendations/

118

Deepwater Wells – IOGP Global Industry Response Group recommendations. Report No. 463, May 2011, https://www.iogp.org/bookstore/product/deepwater-wells-globalindustry-response-group-recommendations/

119

Oil Spill Response – IOGP Global Industry Response Group recommendations. Report No. 465, May 2011, https://www.iogp.org/bookstore/product/oil-spill-response-globalindustry-response-group-recommendations/

120

SQA (Scottish Qualifications Agency), Accreditation/ awarding body in Scotland for vocational qualifications (SVQ), https://www.sqa.org.uk/

121

EAL: Specialist awarding organisation for the engineering & related sectors, http://www.eal.org.uk/

124

Deepwater Well Control Guidelines, IADC 1998 / 2000.

125

SPE/IADC 140365 Low Force Shear Rams: The Future is More, Frank Springett, Eric Ensley, Darrin Yenzer, NOV, Scott We130 aver Noble Drilling; 2011.

127

[Maitland report] Offshore Oil and Gas in the UK, - an independent review of the regulatory regime. Published December 2011, https://www.gov.uk/government/publications/offshore-oil-and-gas-in-the-ukindependent-review-of-the-regulatory-regime

128

[NAS 1638] Cleanliness requirements of parts used in hydraulic systems, http://global.ihs.com/search_res.cfm?RID=Z56&MID=5280&input_doc_number=NAS%2 01638&s_kwcid=TC|5891|NAS%201638||S|p|7783878794&gclid=CIW-97gjq8CFVEjfAod9Eum0Q

129

Guidelines for the conduct of offshore drilling hazard site surveys: April 2013, https://www.iogp.org/bookstore/product/guidelines-for-the-conduct-of-offshoredrilling-hazard-site-surveys/

130

[PPDM Association] What is a Well? Rev 2.4 October 2014 http://ppdm.org/ppdm/PPDM/Standards/What_is_a_Well/PPDM/What_is_a_Well.aspx? hkey=9568903b-44b9-4993-b333-3387cfea43b9

131

[UKOOG] UK Onshore Shale Gas Well Guidelines, Issue 1, February 2013. http://www.ukoog.org.uk/onshore-extraction/industry-guidelines

132

[OPOL] Offshore Pollution Liability Agreement (amended 27 June 2013). http://www.opol.org.uk/agreement.htm

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Reference to

133

SPE 166142 Environmental Risk Arising From Well Construction Failure – Differences Between Barrier and Well Failure, and Estimates of Failure Frequency Across Common Well Types, Locations and Well Age, G E King, D E King, SPE Production & Operations Journal, November 2013, p 323.

134

Oil and Gas Wells and their integrity: Implications for shale and unconventional resource exploitation, R.J. Davies, S. Almond, R.S. Ward, R.B. Jackson, C. Adams, F. Worrall, L.G. Herringshaw, J.G. Gluyas, M.A. Whitehead., Marine and Petroleum Geology 56 (2014) 239-254.

135

Technical Advancement of Multilateral Wells (TAML) (JIP Project) April 1999.

136

Oil & Gas UK Liability Provision Guidelines for Offshore Petroleum Operations 2018 https://oilandgasuk.co.uk/product/liability-provision-guidelines-for-offshore-petroleumoperations-2018/

137

Oil & Gas Authority March 2016. Maximising economic recovery of UK petroleum: the MER UK strategy https://www.ogauthority.co.uk/newspublications/publications/2016/maximising-economic-recovery-of-uk-petroleum-themer-uk-strategy/

138

IOGP 415: Asset integrity – the key to managing major incident risks. https://www.iogp.org/bookstore/product/asset-integrity-the-key-to-managing-majorincident-risks/ December 2008

139

IOGP 456: Process safety recommended practice of key performance indicators.https://www.iogp.org/bookstore/product/process-safety-recommendedpractice-on-key-performance-indicators/ November 2011

140

IOGP 556: Process safety - leading performance indicators. https://www.iogp.org/bookstore/product/process-safety-recommended-practice-onkey-performance-indicators/

141

Environment Agency: The Environmental Permitting (England and Wales) Regulations 2016 http://www.legislation.gov.uk/uksi/2016/1154/contents/made

142

Oil & Gas Authority: SE-06 Production Optimisation Implementation Guide, June 2017. https://www.ogauthority.co.uk/news-publications/publications/2017/stewardshipexpectations-implementation-guides/

143

Oil & Gas Authority: Guidance for applications for suspension of inactive wells, October 2018. https://www.ogauthority.co.uk/news-publications/publications/2018/guidancefor-applications-for-suspension-of-inactive-wells/

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oilandgasuk.co.uk/guidelines

Guidelines Oil & Gas UK works together with member companies to produce a suite of industry-leading guidelines, drawing on a wealth of specialist resources and technical expertise. This guidance is continually reviewed to improve the performance of all offshore operations. Guidelines are free for our members.

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