OFFSHORE MAJOR ACCIDENT REGULATOR

Offshore Petroleum Regulator for Environment & Decommissioning

The Offshore Well Control Inspection Guide Open Government Status

Fully Open

Publication Date

19 January 2021

Review Date

23 April 2029

Review History Date Changes

19/01/21 Issue 4 of the IG – additional questions added to Driller, Company Rep / Toolpusher and Mud Logger questions sets. Transferred onto new IG format. 24/02/22 Issue 5 – OSDR to OMAR rebranding. 14/12/22 Issue 6 – Addition of inspection guide for High Pressure High Temperature (HPHT) (Appendices 2 & 3) and Managed Pressure Drilling (MPD) (Appendices 4 & 5) well operations. 23/04/26 Issue 7 – Minor updates.

Target Audience

OMAR Inspectors / ED Offshore Inspectors / ED Specialist Inspectors

Contents

Summary......................................................................................................................................... 2 Introduction .................................................................................................................................... 2 Relevant Legislation ...................................................................................................................... 3 Action .............................................................................................................................................. 4 Background .................................................................................................................................... 6 Other Relevant Inspection Guides ............................................................................................... 6 Organisation ................................................................................................................................... 6

Recording and Reporting .......................................................................................................... 6 Appendix 1 Conventional Well Operations Inspection Questions and Success Criteria .................. 7 Appendix 2 High Pressure High Temperature (HPHT) Well Operations Onshore Inspection Questions and Success Criteria .............................................................................................. 18 Appendix 3 High Pressure High Temperature (HPHT) Well Operations Offshore Inspection Questions and Success Criteria .............................................................................................. 24 Appendix 4 Managed Pressure Drilling (MPD) Well Operations Onshore Inspection Questions and Success Criteria ...................................................................................................................... 36 Appendix 5 Managed Pressure Drilling (MPD) Well Operations Offshore Inspection Questions and Success Criteria ...................................................................................................................... 45 Appendix 6 Application of EMM and Dutyholder Performance Assessment .................................. 67 Appendix 7 References / Further Reading ..................................................................................... 69

Summary This inspection guide (IG) outlines an approach to the inspection of dutyholder’s arrangements with respect to operational well control and the key areas that inspectors should consider when inspecting this topic. It also sets out the criteria for satisfactory and unsatisfactory performance factors against which dutyholder performance will be rated. References are made to technical standards and guidance that inspectors will use to form an opinion of legal compliance.

The Offshore Installations and Wells (Design and Construction, etc) Regulations 1996 (DCR) and the Borehole Sites and Operations Regulations 1995 (BSOR) requires the Well Operator and Borehole Site Operator to ensure that suitable well control equipment is provided and deployed as required dependent upon the well operations that are to be undertaken.

Introduction The purpose of this IG is to provide information and guidance to OMAR / ED Inspectors to support the delivery of consistent and effective inspection of dutyholder arrangements to comply with DCR and BSOR.

This IG highlights key areas for inspection and provides a framework against which inspectors can judge compliance, assign performance ratings, and determine what enforcement action should be taken with respect to legislative breaches that may be found.

A separate inspection guide details inspection of Wells Personnel Competency.

This IG covers well control during well construction and maintenance including drilling, testing, completion and other well intervention or maintenance / repair (work over) operations, including final decommissioning where the drilling blowout preventers (BOP) are in use. There are also separate appendices for High Pressure High Temperature (HPHT) well operations and Managed Pressure Drilling Operations (MPD). It does not include drilling or well intervention activities where wireline, or under-balanced drilling pressure control equipment is in use.

The large topic of well control has for this purpose been broken down into sub-topics with sample questions for each:

a) well control procedures b) well control equipment c) well control training d) well control drills e) communications

Model answers are provided for each question so that the extent of compliance can be gauged.

Relevant Legislation For all oil and gas well operations, DCR Regulation 13 requires the Well Operator to ensure that a well is so designed, modified, commissioned, constructed, equipped, operated, maintained, suspended, and abandoned that, so far as is reasonably practicable, there can be no unplanned escape of fluids from the well.

For offshore operations, DCR Regulation 17(1) requires the Well Operator to ensure that suitable well control equipment is provided, while DCR Regulation 17(2) requires that the installation safety case dutyholder deploys it when the well operations require it.

BSOR Regulation 9 Schedule 2(7) stipulates similar requirements for onshore oil and gas well operations.

DCR Regulation 21 requires that all personnel working on a well should be suitably informed, instructed, trained, and supervised so that risks associated with the well operation are reduced to as low as is reasonably practicable.

Action Inspectors should review relevant well control documentation such as well control policy and procedures, prior to the installation visit and test compliance during the installation visit against the “success criteria” given in Appendix 1 for conventional well operations, Appendix 2 & 3 for HPHT well operations and Appendix 4 & 5 for MPD well operations.

Note: The success criteria in the Appendices shall be used for HPHT and MPD dependant on the operations or combination of operations inspected.

High Pressure High Temperature (HPHT) Well Operations Due to the complex and higher risk nature of HPHT well operations it requires more rigorous preparations compared to conventional well operations. Therefore, the inspection should cover the preparation and the implementation phases as follows:

Onshore inspection: To ensure sufficient and adequate preparedness and readiness for the HPHT well operation. The following advance information and documentation may be requested prior to or during the onshore inspection:

• The results of HAZID / HAZOP studies specific to the well and the status of action items arising from them. • HPHT well operations and control procedures including arrangements for high pressure kill and special well operations: e.g., coring, wireline logging through the BOP stack and well testing as applicable. • Fingerprinting procedures. • The arrangements for annulus pressure management for surface wellhead systems. This is to ensure that the risk to well integrity resulting from the thermal expansion of fluids in the B and C annuli is reduced to ALARP. • The provisions for ensuring competence of offshore personnel. This may include the training and coaching programme(s).

The inspectors will review the information provided and assess preparedness using the recommended success criteria as detailed in Appendix 2.

Offshore inspection: This entails a visit to the installation where the inspector will test and confirm compliance using the stated success criteria in Appendix 3.

Managed Pressure Drilling (MPD) Operations MPD is a non-standard and non-routine drilling technology which has been used to enable drilling increasingly difficult and challenging wells. Therefore, it requires specific procedures and rigorous preparation.

In the UKCS MPD technology has been primarily used for drilling HPHT wells. If this is the case, then the HPHT inspection elements and questions remain valid and both the MPD and HPHT questions should be used.

Like HPHT operations the MPD inspection will target the preparation and implementation phases as follows:

Onshore inspection: The following information / documentation may be required prior to or during the onshore inspection:

• Copy of the results of HAZID or HAZOP studies, or equivalent detailed risk assessment technique. • A copy of well operation and well control procedures including MPD programme and equipment specifications. • Management of the interface between the Well Operator, Drilling Contractor and the MPD service provider. • A copy of the fingerprinting programme, including testing of the MPD system.

The inspectors will review and assess the information using the recommended good practice detailed in appendix 4.

Offshore Inspection: This requires a visit to the installation where the inspector will test and confirm compliance using the stated good practice given in appendix 5.

By the conclusion of the inspection, it should be possible to

• determine that the well control arrangements for the Well / Borehole Site Operator are suitable and sufficient

When carrying out inspections covered by this IG inspectors should:

• assess dutyholder responses against the success criteria in Appendix 1, 2, 3, 4 or 5 as applicable • use the performance descriptors in Appendix 6 to: o determine the appropriate performance rating o the initial enforcement expectation o consider how and when the issues raised during an inspection are to be closed out

Background Well control is a fundamental part of well operations in preventing an uncontrolled flow from the well. Therefore, it requires to be inspected by the Well Engineering and Operations inspectors, in a consistent manner.

Other Relevant Inspection Guides Wells Personnel Competency Management System.

Specialist Advice A well control inspection may be performed by the Inspection Management Team (IMT) or other non-wells specialist in accordance with this inspection guide. However, if a non-wells specialist / IMT wishes to conduct an inspection of well control it is recommended that it should be performed in conjunction with an ED2 Well Engineering and Operations inspector.

If an inspection of well control is conducted without an ED2 Well Engineering & Operations inspector in attendance and significant concerns are identified by an IMT or non-wells specialist, an ED2 Well Engineering & Operations inspector should be consulted at the earliest opportunity and appropriate action decided.

Organisation

Recording and Reporting

The dutyholder performance ratings should be entered on the Inspection Rating (IRF) Tab of the relevant installation Intervention Plan Service Order. Findings should be recorded in the post inspection report and letter.

Appendix 1 Conventional Well Operations Inspection Questions and Success Criteria

Driller Name: Date:

QUESTION MODEL ANSWER SATISFACTORY RESPONSE? / COMMENT Well Control procedures 1 Are there any standing There should be some standing instructions on how the well will be instructions for the Driller shut in. This will be by the relevant method (hard, soft, or fast method) on well shut in? of securing the well. Relevant BOP/well control equipment schematics to support standing instruction (shut in sequence) for particular well work being undertaken. Awareness of shear ram capability and sequence planned for particular project.

2 Is there a recent well This is a sheet that will be completed with actual bit depth, mud density control sheet on the rig etc at the time of a kick. However, data that will not change like the floor which is completed water depth, depth of last casing shoe, slow circulating rates should be as much as possible? on this sheet so that arriving at the kill calculations is as efficient as possible. (Note - Slow circulation rates change regularly dependent on well depth, hole / drill string configuration and mud rheology. When drilling these should be re-checked and recorded regularly every 1,000ft / 12 hours etc) and on any occasion there is a significant change in mud weight.

3 Did you receive Drillers may be involved in pre-spud meetings on or offshore and information about wells should have access to a programme to review. Well specific risks specific risks for this should be communicated to the Driller and Toolpusher as safety critical operation? personnel.

4 Describe the process for Drillers should be involved in preparing these sheets, either doing it by preparing the well control themselves or supervising the assistant Driller preparing them. The sheets? Toolpusher should then regularly verify samples of these sheets. The practice of Toolpushers preparing the sheets and passing to the Driller misses this verification step.

Well Control Equipment 5 Is the installation’s well This piece of equipment shows if the well is flowing. It is an indication flow indicator working and that primary well control has been lost. It should be working and at 0% accurate? flow when the well is static.

6 Is the mud pit gain/loss This piece of equipment monitors whether there is a loss or gain in system operating and set fluid volume in the pit and indicates whether there may be a kick or a up for correct pit and loss of situation downhole. It should be set up to monitor which pit(s) appropriate gain or loss are being used for circulating mud around the well and set to alarm at an appropriate change in volume. volume relevant to the well section being drilled?

7 Are well control valves on The Driller should be aware of which threads are in use within the drill the rig floor with string and assure that the correct crossovers are available. appropriate crossovers?

Well Control Drills 8 What types of well control There should be a variety of well control drills based on relevant drills are performed and scenarios for the well operations being undertaken. All safety critical who is tested? positions should be tested regularly including Mud Loggers, Derrickman, and Drillers.

Well Control Training 9 If they see the well flowing They should shut the well in using the specified BOP procedure, inform what would be their initial their supervisor, and then start recording pressures and volume action? gained.

10 Does the Driller require This should be no. They should have the responsibility and authority to any permission to shut in shut the well in, if there is doubt as to the primary well control and/or the well, or activate the positive signs of it flowing, and if the situation requires it, use the shear shear rams? rams as a last resort.

Communications 11 Does the Driller have good The Driller and Mud Loggers should have a very good line of communications with the communications and be in frequent contact. The Driller should have Mud Loggers and vice confidence in the abilities of the Mud Loggers and equipment they use. versa?

Are all teams aligned in which system (rig or 3rd party) is to be used and units to be recorded / reported agreed?

Senior Toolpusher and Company Representative / Drilling Supervisor The Senior Toolpusher and Well Operator representative should be asked the same questions. The answers should align with each other; it must be clearly understood by all parties on whose procedures have primacy.

Name: Job Title: Date:

QUESTION MODEL ANSWER SATISFACTORY RESPONSE? / COMMENT Well Control Procedures 1 Whose well control There must be clear understanding whose procedures are in force. procedures (Well Operator or Drilling Contractor) are being followed?

2 When was the last BOP This should be at most 14 to 21 days prior to the date you are aboard. pressure test? What was Pressure testing frequency should be specified in procedures; it should the result? not exceed 21 days. If not, was dispensation given and by whom. This is a high and low-pressure test usually 5 minutes for the low test, 10- 15 minutes is commonplace for the high-pressure test, although OEUK guidelines recommend a minimum of 5 minutes, during which time pressures should remain constant.

3 When was the last BOP This should be within a 7 to 14-day window; API standard and OEUK and BOP control unit guidelines specify every 7 days as operations allow. The function test function test? should be from different control panels to check their functionality.

What was the result?

4 Were all the BOP function A simple function test might not reveal failures of redundant tests (including redundant components. If redundant components are not tested independently ones) tested the arrangements could be vulnerable to a single point failure which in independently? electrical/electronic equipment could occur at any time.

5 Are these tests in This is to check awareness and use. accordance with their procedures?

6 What assurance activities Both Senior Toolpushers and company reps should regularly sample do you perform in relation drill floor well control paperwork to check for accuracy and compliance to well control? to procedures. These verification activities should be documented. Well Control Function Tests, BOP Pressure Test Plans, and BOP Test Records should be verified and documented. Well Control Drills should How are these recorded? be varied and based on relevant scenarios in relation to the specific well’s risks.

Well Control Equipment 7 Is the ram configuration The labelling on the control panels for what type of ram is in each identified on all the BOP cavity on the BOP should accurately reflect what is in the BOP. Need control panels the same for accurate BOP diagrams with well specific datum clearly indicated as that fitted to the various and primary hang off rams / procedure clearly visible Hang-off applies only to subsea BOPs. BOP ram cavities?

8 What pipe in the current The shear rams will not be able to cut some drill collars and may not string will the BOP shear cut some drill pipe and some specialised tubulars. What we want to rams cut? What pipe test is do the Toolpusher and Driller know what they cannot shear and cannot be cut with the are there any instructions in place / risk assessment mitigating this. Has effective communication / training been carried out? shear rams?

Well Control Drills 9 When was the last kick This should be weekly as a minimum and should be for both drill and trip drill, is there a crews. The record should state what kind of drill it was, how long it took record of it, is the to shut in the well together with any other comments. frequency and method in line with the agreed well control procedures?

10 What types of well control There should be a variety of well control drills based on relevant drills are performed and scenarios for the well operations being undertaken. All safety critical who is tested? positions should be tested regularly including Mud Loggers, Derrickman, and Drillers.

Communications 11 Do they have a copy of There should be copies of the drilling program on the installation. The the drilling programme, Driller and other key personnel on the installation should be aware of and have the relevant well hazards from the well for example, shallow gas, over pressurised hazards been zones, losses, hole instability, H2S etc, interface document? Specific actions or local procedures developed for a particular client been communicated to the communicated and visual references placed in appropriate locations? Driller?

12 When changes to the well Programme changes should occur under a management of change programme are required process, risks should be assessed and mitigated. Any changes should how are well control risks be communicated to the drill crew and included in the drilling identified and instructions issued by the company man. If changes are made to procedures or standing instructions the Senior Toolpusher should