North Sea SPU (UK) Integrity Management Strategy Well Operations Integrity Management Strategy
Issuing Authority:
Document Authority:
Margaret Copland SPU Wells Technical Authority
Document Administrator:
Janet Ross SMS Advisor
Applicability:
North Sea SPU (UK)
Issuing Department:
Engineering
Control Tier:
2
First Issue Date:
November 2008
Revision No:
Issue 1
Review Required By:
November 2011
Revision Date: Revision Summary:
First issue. For further information contact DCC at ODL on 01224 628018 or
[email protected].
Document Location:
Documentum/ABZ Federal/SMS
NSSPU-IMS-003
Well Operations Integrity Management Strategy
NSSPU-IMS-003
Contents
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Paragraph
Page
1
Introduction
1
2
Scope
2
2.1
Purpose
3
2.2
Project Phase (Design, Construct, Commission)
4
2.3
Well Operations Phase
6
3
4
Organisation
8
3.1
Ownership
8
3.2
Technical Hierarchy Model
9
3.3
Roles and Responsibilities
9
Risk Management
11
4.1
General
11
4.2
Management of Safety Critical Equipment
12
4.3
Management of Non-safety Critical Equipment
14
5
Integrity Management Process
15
6
Management of Change
17
7
IM Documentation and Data
18
8
Performance Management
19
8.1
KPIs
19
8.2
KPI Management
19
8.3
Annual Integrity Statement
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Contents (cont’d)
Table
1
Page
ETPs Relevant to Wells
5
1
Life-cycle Responsibility
8
2
Logic for Identification of Safety Critical Activities
13
3
Integrity Management Process
16
4
Documentation and Data Support
18
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Figure
Addendum 1 Addendum 2 Addendum 3 Addendum 4
ii
Technical Hierarchy Model Performance Standard Example UK Sector RACI Chart Norway Sector RACI Chart
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Introduction This document details how Well Services have a strategy in place, which demonstrates conformance with the Integrity Management Standard: Implementation in E&P document. The Group Integrity Management (IM) Standard has been developed to help prevent and mitigate integrity-related losses associated with safety, environment, business and reputation through the integration of: The Process Safety/Integrity Management (PSIM) Standard (2001) The Major Accident Risk (MAR) assessment process, introduced in 2002
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The appointment of Engineering Authorities (EAs) and Technical Authorities (TAs) The application of Engineering Technical Practices (ETPs) The Integrity Management Standard: Implementation in E&P document defines specific minimum requirements against each of the ten elements highlighted in the BP Group IM Standard. Conformance with the 10 elements are covered in detail within this document. Element 1 Accountabilities Element 2 Competence Element 3 Hazard Evaluation and Risk Management Element 4 Facilities and Process Integrity Element 5 Protective Systems Element 6 Practices and Procedures Element 7 Management of Change Element 8 Emergency Response Element 9 Incident Investigation and Learning Element 10 Performance Management and Learning The Standard requires that IM is a line responsibility and that Major Projects and Strategic Performance Units (SPUs) clearly identify the roles and responsibilities of the personnel who are accountable for delivering conformance.
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Scope This document covers all wells in the North Sea SPU. It defines the requirements to assemble a demonstrable, auditable system for the delivery of well integrity across all ten elements of the IM Standard. Non BP owned Well intervention equipment is outwith the scope of this document and is managed through Control of Hired and Transportable Equipment (UKCS-SOP-005). Although this document relates to wells in general, the primary focus in the first stage of implementation will be Safety Critical Equipment (SCE) integrity to align with the IMS implementation plan. Although links may exist with other integrity systems (eg platform shut-down systems, control panels etc.) the management of these systems are covered by other IM strategies.
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A generic listing of well related Safety Critical Equipment (SCE) that is covered by this strategy is listed below: Tier 3 Strategies for Well Services Safety Critical Equipment Wellheads/Production Trees and Sub-Sea Trees Down Hole Safety Valves (DHSVs) and Annulus Safety Valves (ASVs) Casing and Tubing Pressure Control Equipment (PCE) (which is BP owned including portable Well Control Panels) Each asset shall identify safety critical elements pertaining to their area of responsibility. Safety critical equipment for most assets in the North Sea SPU, is recorded in Maximo, where records are held of all planned maintenance and testing, carried out to satisfy the performance standards, set against the SCE`s. For the Norwegian sector, the system of recording SCE`s is through the WORKMATE system, for Foinaven STAR is the system that is used. Safety Critical Equipment Assignment Standard (UKCS-TS-019) defines what equipment should be identified as safety critical. A well is defined as the pressure containment envelope which therefore includes casing and tubing strings, downhole components, wellheads and xmas trees including tree valves and actuators. Conductors are considered structural elements and are included in the Offshore Structural Integrity Delivery Requirements (NSSPU-GP-66-00-1). Gauges and instrumentation are not part of the well envelope and are covered by instruments Fire and Gas Detection (NSSPU-GMS-I01).
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Purpose
The purpose of this strategy is to provide a system for the identification and control of risks associated with the design, construction, commissioning, operation and maintenance of safety critical wells equipment. In conformance with the objectives of the IM Standard, the Wells IM Strategy will: Confirm that materials, equipment and structures in use, are fit for purpose Avoid loss of containment by stringent practices and procedures Maintain mechanical and pressure integrity through assurance process Prevent major incidents that result from failure of equipment and systems
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Establish safe operating limits and confirm operation within these limits The strategy is developed around four fundamental processes: (a)
Risk Assessment, Verification, Mitigation and Assurance. Risk Assessment Process – to identify hazards affecting the integrity of the wells/platform from well service activities and the use of temporary equipment Mitigation Control Process – to manage the associated risks to As Low As Reasonably Practicable (ALARP) Verification of the procedures and processes relating to well operations activities Life-cycle assurance (maintenance, inspection, repair and replacement) of the wells, pressure control equipment which is bp owned, trees and wellheads
(b)
Applicable Regulatory requirements/Guidance. (i)
United Kingdom Continental Shelf (UKCS) Legislative Requirements Management of Health and Safety at Work Regulations Safety Case Regulations (SCR) Lifting Operations and Lifting Equipment Regulations (LOLER) Provision and Use of Work Equipment Regulations (PUWER) Design and Construction Regulations (DCR) Prevention of Fire and Explosion, and Emergency Response Regulations (PFEER) Borehole Regulations (Wytch Farm)
(ii)
Norwegian Requirements The Management regulations Guidelines relating to management in the petroleum activities The Activities Regulations Guidelines relating to conduct of activities in the petroleum activities
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Well Operations Integrity Management Strategy The Facilities Regulations Guidelines relating to design and outfitting of facilities etc. in the petroleum activities Norsok D-010, well integrity in drilling and well operations Guidelines for the application of IEC 61508 and IEC 61511 in the petroleum activities on the Norwegian continental shelf
(iii)
BP Governing Documents Drilling and Well Operations Practices (DWOP) Engineering Technical Practice (ETP) Integrity Management Standard
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(c)
Design and Construction Phases. Formal assurance should be provided in the well handover package from the drilling team that verifies the design and construction of the well has been carried out using good engineering practice and complies with the regulatory requirements and BP governing documents.
(d)
Verification and Annual Assurance Review. Element 10 of the IM standard, calls for ‘Implementation of verification and audit programmes to confirm IM requirements are being delivered and that learning’s are fed into the continuous improvement cycle’. Well services meet this requirement by: Review close out of PMs which relate to well head maintenance, PCE maintenance and testing and ASV/DHSV testing Audit of maintenance records relating to safety critical equipment Audit of adherence to performance standards Review of any actions raised on well integrity issues
The implementation of this strategy will ensure conformance to the requirements of Getting Health, Safety and Environment Right (GHSER) and the IM Standard.
2.2
Project Phase (Design, Construct, Commission)
Technical Integrity is a key aspect of the project phase to deliver ‘fit for purpose’ wells, as stipulated to the IM Standard, Minimum Requirement 4.3: ‘Major Projects and Drilling shall hand over to the Operating BU full life-cycle IM strategies…that conform with Engineering Technical Practices.’
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It is the responsibility of the project/drilling team to demonstrate that integrity is achieved through design, construction and commissioning of the wells in accordance with the IM Standard. Some of the processes that lead to delivering the appropriate level of integrity during the Project Phase (and may deliver integrity assurance throughout the life-cycle) are: The clear definition of roles, responsibilities and accountabilities The application of ETPs and/or International Standards Inherent safety features included in the design of well equipment Formal Safety Assessment (FSA) Hazard and Operability Study (HAZOP)
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Quantitative Risk Assessment (QRA) Project Health, Safety and Environmental review (pHSEr) Identification and management of Safety Critical Equipment (SCE) The rigorous application of the IM Standard Well handover documentation 2.2.3
Engineering Technical Practices
The design of wells, facilities, structures and equipment, is extensively covered in company ETPs, Site Technical Practices (STPs), Industry codes and Standards. The following ETPs are relevant.
ETP Number
ETP Name
Design and Construction Phase
Operations Phase *
GP 10-01
Casing and Tubing Design
*
GP 10-05
Directional Drilling and Surveying
*
GP 10-10
Well Control
*
GP 10-15
Pore Pressure Prediction
*
GP 10-16
Pore Pressure Detection During Well Operations
*
TBC
Shallow Hazards
*
TBC
Well Intervention Risers/Pressure Control
*
GP 10-25
Waste and Fluids Pollution Risk Mitigation
*
GP 10-30
Hydrogen Sulphide and Hazardous Materials in Well Operations
*
*
*
*
Table 1 ETPs Relevant to Wells
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ETP Number GP 10-35
Well Operations
GP 10-36
Breaking Containment
Operations Phase *
*
*
TBC
Well Management
TBC
Drilling Rig Audits and Rig Acceptance
*
* (Intervention Vessels)
Well Testing
*
*
Moving and Securing of Mobile Offshore Drilling Units
*
GP 10-50
Engineered Equipment
*
*
GP 10-60
Zonal Isolation Requirements during Drilling Operations and Well Abandonment and Suspension
*
*
GP 10-75
Simultaneous Operations
*
*
Working with Pressure
*
*
GP 10-80 TBC
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ETP Name
Design and Construction Phase
TBC
*
Table 1 ETPs Relevant to Wells (cont’d)
2.3
Well Operations Phase
The Operations Phase has been developed to manage ongoing well integrity during the operational life-cycle. It has been developed to demonstrate compliance with current legislation and the IM Standard and to provide an auditable system. A generic methodology to manage the wells during the operational phase is outlined below: All wells are designed and installed in conformance with ‘BP Global Drilling and Well Operations Policy’ and shall be handed over from drilling to production with a completed handover package Once the well has been handed over from Drilling, the Wells Services Manager is the Engineering Authority with accountability to ensure that processes and systems are in place for the management of well integrity A well integrity focal point is designated for each BP-operated field. Usually this is the Well Operations Engineer (WOE), who is hereafter referred to as an I.M. practitioner. Specific responsibilities are shown in the RACI charts in Addenda 3 and 4 Production start-up and operating procedures shall be developed and kept updated as required (responsibility as per RACI chart)
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The Well Services Group maintains procedures relating to the management of well integrity. The generic well integrity operational guidelines are embedded within the Well Services Operational Guidelines (WSOG). These are complimented by Well Operations Procedures which are specific to each asset Production operations personnel are responsible for the monitoring and recording of wellhead/annulus pressures and for reporting any anomalies to the WOE (Well Operations Engineer) The onshore well operations engineer shall initiate diagnostic integrity work, as required
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Maximum Allowable Annulus Surface Pressure (MAASP) and Maximum Operating Pressure (MOP) limits have been established for all wells A well experiencing sustained casing pressure above the specified MOP shall be risk assessed and solutions sought to correct the problem. Should continued production of the well be justified, dispensations shall be raised by the WOE and approved by the SPU Wells TA, with a set period for future review and renewal which shall require SPU Wells EA approval A field-by-field and well-by-well review is held on a regular basis and reported by the Well Integrity engineer IM training will be administered on a regular basis to all appropriate personnel who can influence well integrity Management oversight and accountability is provided by review of all wells with anomalies before allowing continued operation. Dispensations from policy may be issued if applicable using the approved dispensation process An audit function is in place to provide assurance. Well integrity reviews should be carried out regularly with the process being audited by the EA
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Organisation 3.1
Ownership
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‘Ownership’ of the wells, through the various life cycle stages, may transfer to and from differing disciplines depending on the work required, as shown in Figure 1. Drilling and Completions initially hand over the well to production operations, with a complete hand over package of documentation, with the operating envelope of the well set by the casing, tubing and completion design. Production operations are responsible for the day to day monitoring of well integrity activities whilst the well is on production. Well services provide the technical discipline expertise to carry out well intervention, repair and maintenance activities. Because of these cross functional activities, the asset is required to identify ownership of the well during these stages and clearly describe the responsibility areas during operations.
Handover
Drilling Drilling
Handover
Hookup Hookup
Handover
Handover
Stimulation Stimulation Operate Operate&&M Maintain aintain Repair Repair
Trees and Wellhead
Annuli
SCSSV, ASV
Casing Tubing
Handover betw een Drilling/Wells and Operations
Barriers Training Competency Dispensations Reporting
PxA PxA
Figure 1 Life-cycle Responsibility The SPU EA personally approved the appointment of both the Well Construction EA and Well Services EA, this has been officially documented and recorded in iCan. The Engineering Authority (EA) for well services has been assigned and is identified as the Well Services Manager. The SPU Wells Technical Authority (TA) has been duly appointed and has likewise been documented and recorded in iCan. For Norway and Wytch Farm, asset TAs have been identified and will be assessed and appointed. Each operational unit shall have in place a RACI chart outlining responsibilities for well integrity tasks as shown in the example Addenda 2 and 3.
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Technical Hierarchy Model
An organisational model for management of operational well integrity is illustrated in Addendum 1. It should be noted that there are differing responsibility levels between Norway and North Sea SPU Operations, as denoted by the dotted bold line. The well operations engineer (IM Practitioner) is the focal point for all initial integrity issues with regard to well operations being carried out in his/her assigned asset. In Norwegian sector the responsibility is with the Production Operations team. He/she has overall responsibility for ensuring that all activities are undertaken safely on behalf of the asset. Any anomalies related to well integrity are discussed with the Wells integrity engineer and are reported upwards to the SPU Wells Technical Authority.
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The Asset TAs in Norway and Wytch Farm will consult with the SPU Wells TA on integrity matters.
3.3
Roles and Responsibilities
An IM Standard Awareness Programme has been developed and implemented across Operating Business, Major Projects and contractors, which covers all personnel with involvement in integrity management. It is based on a three-phase approach: IM e-learning module (pre-read) IM Standard awareness course IM Standard self-assessment – based on Addendum 1 of the Integrity Management Standard: Implementation in E&P document (post-course) A register of everyone who attends the course has been produced and forms part of competency profiles. 3.3.1
Engineering Authority (EA) – Well Services
The Wells EA provides verification to the SPU EA that the ‘Engineering Expectations’ of the IM Standard are being met by the Well Services Team and are fully auditable. The principal roles of the Wells EA include: Ensures that there is a system in place that identifies and provides the required level of engineering competence to cover the required well service disciplines for the SPU Demonstrates that the Well Services team are meeting all applicable requirements of the IM Standard or have a plan to address any deficiencies Approves the selection and application of Site Technical Practices (STPs). STPs shall be consistent with the relevant Engineering Technical Practices (ETPs) unless approved by the appropriate EA Establishes, maintains and approves a control procedure for the STPs. This procedure shall specify the delegation of accountabilities from the EAs, the processes governing the approval of variations from STPs and the criteria under which variations from these STPs may be approved
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Identifies all Well Services posts in the SPU for which the competencies of the postholder must meet specific levels to ensure the effective implementation of the IM Standard Reviews (with SCM support) the role and responsibility of the major well engineering contractors and confirms implementation of a competency assurance process 3.3.2
SPU Wells Technical Authority (TA) – Well Integrity
The SPU Wells TA was appointed by the Wells EA and is accountable to the Wells EA for execution of the TA role irrespective of their line reporting relationship. Certain assets may have assigned TAs, where applicable, their role in relation to the SPU TA is defined. The SPU Wells TA is an expert within the various disciplines and is the primary source of technical advice to the Well Services EA. The principal roles of the TA include:
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Advise the EA and asset on issues relating to well integrity Advise on well operations equipment, maintenance and inspection frequencies and techniques Review and be consulted in related Management of Change efforts Advise on the use of appropriate standards, practices and design guidelines Serve as a principal resource to the Well Services EA for the development of STPs Advise the Asset and Wells EA with respect to exceptions to STPs Evaluate requests for exceptions to the STPs/Industry Standards Actively participate in networks/communities of interest, maintaining a strong awareness of relevant learning and technical advances Serve as a focal point for the Wells community in the area of well integrity Ensure that the performance standards are being met and kept up to date Act as owner of the Wells IM Strategy 3.3.3
Wells Asset Technical Authority (TA) – Well Integrity
Wells Asset TAs are engineers with specific discipline expertise appointed by the Wells EA. The primary role of the Wells Asset TA is to act as the technical integrity advisor within their designated activity by ensuring the safe and consistent application of Company and regulatory codes and standards and good engineering practices. The Wells Asset TA and Wells SPU TAs are a primary source of technical advice to the Wells EA within the SPU. The Wells Asset TA, Wells SPU TA and the Wells EA within an SPU should develop a close working relationship, with clear mutually agreed roles and responsibilities. Each Wells Asset Technical Authority shall: Advise the Wells Asset TA, Wells and SPU staff on issues relating to technical integrity Be involved/consulted in MoC efforts that relate to their area of engineering expertise
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Advise on the use of appropriate standards, practices and design guidelines Advise the asset staff and the Wells SPU TA and Wells EA with respect to exceptions to the SPU STPs Technically evaluate requests for exceptions to the STPs/industry standards as requested and provide a recommendation to the Wells EA Actively participate in BP technical networks/communities of interest, maintaining a strong awareness of technical learning’s, advances within their area of speciality, etc Advise on maintenance and inspection frequencies and techniques within their engineering speciality where appropriate
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Serve as a technical focal point for engineers within the asset in their area of engineering speciality 3.3.4
Well Integrity Engineer
The role of the Well Integrity Engineer is to lead well integrity, provide assurance and support to the North Sea Strategic Performance Unit, to ensure the integrity of the BP operated and non operated well stock. The integrity engineer is directly accountable to the SPU Wells Technical Authority. Investigating any well integrity anomalies, developing contingency plans, monitoring repair and maintenance performance and recommending improvements to materials and operating practices. This may include operational support to restore integrity Routine review and maintenance of summary records for all wells to ensure integrity standards are being maintained Preparation of reports summarizing integrity status and recommendations on any actions required Provision of general well service technical and operational support as required Application and development of technology and best practices in Well Integrity Management Transfer of best practice by use of internal and external networks
4
Risk Management 4.1
General
Risk management is an integral part of the integrity management process. Specific account of risk management is addressed in the following areas: Basis of design Inherent safety features as part of design Formal safety assessments carried out Quantitative risk assessments
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SPU S&OI risk matrix HAZOP development and revalidation process SIL assessments Selection and management of the safety critical elements Development and implementation of performance standards Development and implementation of the integrity programmes Compliance with STPs Performance management process Learning and assurance process
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Hazard Identifications (HAZIDs) and HAZOPs for each asset identify the major hazards applicable to the integrity of wells during operations. These contain a detailed description of each hazard and the mitigating control measures taken to reduce the likelihood of occurrence.
4.2
Management of Safety Critical Equipment
IMS requires the identification of SCE’s. In the UK, SI 1992/2885 Offshore Installations (Safety Case) Regulations and the associated SI 1996/913 (DCR), require the Duty Holder to identify the potential major accident hazards appropriate to an installation. Safety Critical Elements (SCEs) are those parts of the installation, or its plant, the failure of which could cause or contribute substantially to a major accident or the purpose of which is to prevent, or limit the effect of, a major accident. Safety Critical Equipment shall be identified in Maximo/Workmate/STAR and assigned inspection and maintenance activities to confirm ongoing fitness for purpose as defined by the acceptance criteria/performance standards. Performance Standard(s) should be produced for each Safety Critical Element. These compliment each element and provide a benchmark for assessing their functionality during the operational phase. An example of a performance standard is shown in Addendum 2. A process has been adopted by the SPU, under UKCS-TS-019 for the identification of Safety Critical Activities as illustrated in Figure 2. The maintenance and testing of wells Safety Critical Equipment is defined in the relevant RACI chart. These campaigns are carried out and planned through Maximo/Workmate/STAR with records produced for each asset. The regularly scheduled well integrity review held by the well integrity engineer also considers the results from the maintenance and testing campaigns from all assets and tracks the results of the testing and maintenance.
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START
No
Is the equipment location tag safety critical?
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Yes Is the activity required to demonstrate that the equipment conforms to a specified performance standard
Yes
No
No
Is this a maintenance and/or repair activity required to restore, or ensure that the equipment will perform in accordance with a specified performance standard
Yes
Yes
No Figure 2 Logic for Identification of Safety Critical Activities
Safety Critical Equipment will be managed within the overall integrity assurance process. The process will provide a demonstrable, auditable system which will provide the audit teams with the information required for verification. SMS document UKCS-TS-019 describes this process in more detail. 4.2.1
Performance Standards (PS)
The PS for each SCE should relate to its purpose and shall address the following: The Risk Management Role The PS should identify the risks that the SCE influences and how the SCE (and any other related SCE) are intended to work so as to avoid, prevent, control or mitigate these risks.
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Functionality Requirements How the SCE should perform, eg the safe operating temperature of a pressure system, the speed of closure of a valve etc. Availability Requirements When the SCE should perform, eg always available, available within 10 minutes of previous operation, etc. Reliability Requirements How well the SCE should perform, eg the ability of a valve to close on demand.
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Survivability Requirements How long it should continue to perform its intended duty under extreme loading conditions. Interaction Issues How the SCE interacts with other SCE. Performance Standards should set out the acceptable level of performance. They should be quantifiable, where possible, and measurable by implementation of the assurance process. They should also be written in terms that are readily understood by the Technical and Performing Authorities. These routines are uniquely identified and the records stored within the Maximo and STAR (Foinaven) systems in the UK and the Workmate system in Norway.
4.3
Management of Non-safety Critical Equipment
Although the primary focus and rigour is on Safety Critical Equipment, as their failure may result in a major incident, the Non-Safety Critical Equipment should also have risk management programmes associated with them. This should include the relevant maintenance, inspection, testing and operations plans as required by the IM Standard.
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Integrity Management Process The Integrity Management Process, see Figure 3, has been developed to demonstrate, in an auditable manner, the way in which the integrity of wells is managed. The process includes the following key activities for Xmas Trees and Wellheads, ASVs and DHSVs, Pressure Control Equipment (PCE) and Tubing and Casing: Develop management scheme Define inspection/maintenance routines Schedule inspection/maintenance routines Implement inspection/maintenance routines
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Implement remedial and corrective repairs Collate inspection/maintenance information Perform technical assessment Retain accurate records of all regulatory tests Recommend changes as required Enact changes This aligns with ‘The Way We Work’ which exists to: Create clarity of accountability and the role of organisational units Drive simplicity in end to end business processes and systems and how we apply governance across the SPU Drive out waste, increase efficiency and focus on continuous improvement in managing the business In the Operations Division, each asset shall have a Well Operations Engineer assigned from the Well Services team. The WOE will be the first point of contact for integrity issues within the asset. They shall be responsible for the management of the annual maintenance and testing campaigns for the wells under their stewardship. In Norway there are assigned engineers within the Production Operations team that are responsible for integrity issues within the asset. In Wytch Farm a Well Operations Engineer assigned will be the first point of contact for integrity issues within the asset. They shall be responsible for the management of the annual maintenance and testing campaigns for the wells under their stewardship. In SNS Well Operations Engineers assigned will be the first point of contact for integrity issues within the asset. They shall be responsible for the management of the annual maintenance and testing campaigns for the wells under their stewardship. Written programmes shall be produced to carry out all maintenance and testing on a campaign basis. These campaigns are called up and recorded through Maximo, STAR and Workmate. The Integrity Management Process applied to Well Services is based on a continuous plan/do/measure/learn model as shown in Figure 3.
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Figure 3 Integrity Management Process This process approach allows a set of common activities to be continuously applied through the life of the wells, across the fields in the SPU. The process and the activities are also applied to each part of the facility (eg pipelines, structures, pressure equipment, etc) while allowing the unique contribution of competencies from selected service providers and their information or data sources.
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Management of Change
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It is a mandatory requirement within the Integrity Management Standard: Implementation in E&P document that any change with possible business and/or integrity management implications does not take place without a systematic process being followed to examine the impact and manage the risks. This Management of Change (MOC) expectation is covered in more detail in Element 7 of the above document and is delivered in the NSSPU by the processes detailed within the North Sea Safety Management System (SMS). By exception, some sites use site-specific management of change procedures and systems which are aligned to the requirements of the SMS. All potential changes are required to go through the procedure detailed in Management of Change (UKCS-CHM-001). This is the initial filter for all changes and defines whether the change should take place and, if so, by what method its impact should be assessed. The procedure allows for the selection of one of three sub-processes to control the change: Technical, Administrative or Organisational. Most plant and equipment changes (eg installation of Lock out of TRDHSV and installation of an Insert Valves, change in Tree valve trim type) will go through this subprocess and it closely follows the basic CVP gated process. This process also considers the wider impact on, for example, documentation. Replacing an individual or changing the entire makeup of a team can affect the way the operation is run. A specific sub-process for this type of change exists in the system and is detailed in Organisational Change Management (UKCS-CHM-004). Where the life of a field is to be extended, the MOC process should be used to consider well integrity issues. Any changes to legislative regimes, minor modifications, PSCM change or other change types that do not conform to the above sub-processes should be routed this way. In many cases there is a relevant SPU procedure that will codify the process to be undertaken. The MOC system allows approvals and an audit trail to be captured, eg Legislation Change Process (UKCS-CHM-003). The NSSPU performance manages the implementation of the MOC process. Key Performance Indicators (KPIs) are utilised to allow the NSSPU to do this. The KPIs are discussed on a monthly basis and interventions made to ensure the level of change activity remains at a manageable level. Once an MOC has been raised, considerable focus is given to completing the total work package through to business closure. Every effort will be made to close the MOC within a reasonable timeframe, whether the change takes place or not. An MOC will not remain in an open state if there is no intention to complete the change in the foreseeable future.
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IM Documentation and Data Underpinning the IM program is a documentation and data management system that should store the relevant integrity information in a readily retrievable form (not archived) by the responsible IM practitioner. The documentation systems in use within the North Sea SPU are MAXIMO, STAR and Workmate. Business critical information is also stored in DOCUMENTUM. A generic Tier 2 SPU model for documentation and data in support of the IM Process for Well Service Equipment is shown in Figure 4 below. Legislation and BP Standards are the highest level documents, followed by the Engineering Technical Practices (ETPs) and Site Technical Practices (STPs), the Well Operations IM Strategy and the various routines.
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This documentation has been defined as the minimum requirement under the IM Standard to ensure the effective management of the key activities in an auditable manner. IM Support
Safety Case Regulations (SCR – 1992) Lifting Operations and Lifting Equipment Regulations (LOLER – 1998) Provision and Use of Work Equipment Regulations PUWER – 1998) BP Integrity Management Standard (IMS) Design and Construction Regulations (DCR – 1996) Prevention of Fire and Explosion and Emergency Response Regulations (PFEER – 1995) Borehole Regulations (Wytch Farm Norsok (D-010)
Integrity Management Standard
Integrity Management Guidance
Supporting Documentation Safety Case HAZID, HAZOPs ETPs/STPs Design Data P&IDs Equipment Registers
Well Equipment Design Reviews
Well Operations IM Strategy Requirements
Well Equipment Inspection reviews
Well Equipment Maintenance Program
Well Equipment Operations Routines
Figure 4 Documentation and Data Support
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Performance Management The Wells IM Strategy shall be periodically reviewed by the SPU Wells TA to ensure that equipment and procedures are in place and are fit for purpose. Verification of compliance with the Strategy’s objectives, relevant KPIs and the performance standards are key elements of performance management. The TA will be responsible for reporting to the EA on the performance assessments.
8.1
KPIs
Uncontrolled when Printed
Key performance Indicators (KPIs) are utilised by Well Services to measure and report integrity issues, including any MOC actions (refer to Paragraph 6). These KPIs are discussed on a monthly basis and interventions made to ensure the level of change activity remains at a manageable level. Appropriate Well Services KPIs have been established for each type of Well Integrity activity, which reflect the key risks to be managed. KPIs are reviewed at appropriate intervals and acted upon by the Engineering Authority to assure conformance with the Integrity Management Standard: Implementation in E&P document. From a reporting perspective these shall include: Number of overdue wells safety critical maintenance in given month Number of deferrals of safety critical maintenance in a given month Number of dispensations against Drilling and Well Ops Policy in a given month (this will eventually become dispensations from ETPs/STPs) Xmas tree and downhole safety valve failures in a given month (failure is measured against performance standard) IMS competency of Well Services (EA/TA and IM Practitioners) Number of wells with annuli issues in a given month (issues are operating above MOP or bleeding off hydrocarbons from annulus) At the discretion of the EA/TA, other relevant KPIs may be utilised
8.2
KPI Management
All of the above KPI measures shall be reported to the Wells TA on a monthly basis. A formal recorded KPI review meeting shall be held to identify deficiencies in performance and to agree and assign appropriate remedial activities on a regular basis.
8.3
Annual Integrity Statement
The Wells IM Strategy will be reviewed on an annual basis. The Wells TA will be responsible for the review to ensure it remains appropriate in the light of each year’s findings. A single page Annual Integrity Statement shall be prepared for and submitted to the Well Services EA.
November 2008 Issue 1
19/20
Uncontrolled when Printed
Infrastructure / Norway
Operations
Segment EA
VP Renewal
VP Infrastructure Norway
VP Operations
IMS Accountability
SPU EA
HODs
Head of Devs
Head of Quad 204
NWH Project Manager
Miller Project Manager
Decom EA ETL
Decom EA ETL
Head of Wells
Head of SNS / WYF
OCTIP Project Manager
Gas Asset Manager
Q204 EA Eng Man
Drilling EA
Wytch Farm EA ETL
Head of NSI
SNS EA ETL
OCTIP EA Eng Man
NSI EA Eng Man
PUL Norway Ops
PUL Norway MP
Ops Manager
Project Manager
BPN EA
MP EAs Eng Man
Segment TAs
Ops EA Eng Man
Eng SPU TAs
Decom TAs
Decom TAs
Q204 TAs
Operations Devs & Major Projects
(3)
(3)
(3)
(5)
D&C TAs
Wytch Farm TAs
SNS TAs
(4)
(4)
(4)
OCTIP TAs
(3)
NSI TAs
BPN TAs
(10)
(24)
MP TAs
Head of Production Eng
Subsea & Pipelines Manager
Head of HSSE
Head of Ops (4)
Safety Manager
Pipelines EA
Subsea EA
Wells Services EA
Pipelines SPU TAs
Subsea SPU TAs
Wells TA
Production Manager (8)
Process Safety TA
ACE Engs
(48)
(30)
(47)
NSSPU-IMS-003
Technical Hierarchy Model Add 1-1/2
Dev TAs
TA Population
Head of Eng / Maint / Subsea
Addendum 1
Projects EA Eng Man
Head of Decom
Well Operations Integrity Management Strategy
Renewal
Technical Herarchy Model
November 2008 Issue 1
Segment
Well Operations Integrity Management Strategy
NSSPU-IMS-003
Addendum 2
Performance Standard Example RAVENSPUR SOUTH RB PERFORMANCE STANDARD SC Element: Xmas Tree Valves Strategy: Control
RB/FEP/017 DWI No: DWI/FEP/017 SCOPE OF PERFORMANCE STANDARD
Uncontrolled when Printed
Xmas Tree Valves:- All components associated with the Xmas Tree and associated actuated valves that provide topside isolation of the platform wells. GOAL/HIGH LEVEL PERFORMANCE STANDARD The Xmas Tree valves shall provide a facility to shut in a well in accordance with a predetermined shutdown sequence. Xmas Tree valves shall be capable of surviving the identified hazards under which they have a required function. This facility specific Performance Standard is designed to meet the requirements of day to day operations related to this SCE and allow for normal verification procedures. Additional information in the referenced Generic Performance Standard may be required for changes/modifications, out of specification conditions, faults/failures or if there is any uncertainty. PERFORMANCE STANDARD DETAILS
Ref No
Associated Technical Documents and FSA References
Functionality
RB FEP01701
Actuated Xmas Tree Valve operation shall be fail safe by ensuring valve closure on loss of signal or control pressure.
RB FEP01702
The actuated Xmas Tree Valves shall have a facility for the operator to initiate closure locally.
RB FEP01703
Xmas Tree UMV/WV shall close automatically by any of the following actions:
Red Shutdown
Low hydraulic pressure
Hi/Lo wellhead pressure
Area fire detection
Wellhead flexible loop
API 6 A.
ESD and F&G Cause and Effect.
RB FEP01704
The status of the actuated Xmas Tree isolation valves shall be indicated in the control room.
RB FEP01705
Design and operating conditions shall be identified for all the Xmas Tree Valves (ie upper and lower master, wing valve, NASA and manual swab valve), including pressure ratings, fluid service and temperatures.
Completion Design Manual.
RB FEP01706
Valve closure should be a smooth operation and take less than 45 seconds. Closure time is defined as the time taken for the valve to reach the fully closed position from receipt of ‘close’ signal from the facility ESD logic panel.
Based on 60 seconds allowance for detection and closure in the QRA.
RB FEP01707
Maximum acceptable leakage rate shall be 15scf/min.
Well Services Operating Procedures.
RB FEP01708
Materials of construction shall be erosion/corrosion resistant.
API 6 A Class DD.
November 2008 Issue 1
Performance Standard Example Add 2-1
NSSPU-IMS-003
Well Operations Integrity Management Strategy
Associated Technical Documents And FSA References
Ref No
Availability/Reliability
RB FEP 017/09
Actuated tree valves should remain maintained and available during the operating life of the well. Continuing production from the well until such time as remedial work is completed shall be subject to authorisation by the OIM (or delegate) after conducting a risk assessment.
Well Services Operating Procedures Section 9.2.
The reliability of the actuated Xmas Tree Valves to achieve isolation to the required performance standard shall meet or exceed 98%. Testing shall be scheduled at 12 month intervals in order to achieve this reliability.
API 6A
RB FEP 017/10
Performance and Leakage Criteria.
Oreda ’97 Taxonomy Number 4.4.3.3. Well Services Operating Procedures:
Uncontrolled when Printed
Section 10.3, Inspection and Testing and Section 9.3, Inspection and Testing.
Ref No
Survivability
RB FEP 017/11
Xmas Tree Valves shall retain integrity for all foreseeable fire and explosion events.
Associated Technical Documents and FSA References
Interactions and Dependencies Performance Standards
Safety Critical Elements
Interactions and Dependencies
RB FEP 006
Emergency Shutdown.
Initiates valve closure.
RB HYC 010
Hydrocarbon Systems.
Interface between Wells, Wellheads, Xmas Trees and Topsides Process.
RB HYC 012
Wells, Wellheads, Xmas Trees.
Interface between Wells, Wellheads, Xmas Trees and Topsides Process.
Assumptions and Limitations 1. Examination and Testing activities carried out in accordance with the Wells Examination Scheme.
Performance Standard Example Add 2-2
November 2008 Issue 1
Well Operations Integrity Management Strategy
NSSPU-IMS-003
Addendum 3
Uncontrolled when Printed
UK Sector RACI Chart
November 2008 Issue 1
UK Sector RACI Chart Add 3-1/2
Well Operations Integrity Management Strategy
NSSPU-IMS-003
Addendum 4
Uncontrolled when Printed
Norway Sector RACI Chart
November 2008 Issue 1
Norway Sector RACI Chart Add 4-1/2
