NORSOK Standard D-010 Rev 4. August 2012

Transcription

1 NORSOK Standard D-010 Rev 4. August 2012 Changes to the section: The content of the section is by and large the same as the rev. 3 version, but we have improved the text, made some new statements and removed material that is not directly well integrity related. Below is a listing of the main changes 1. Included better description of content of well barrier schematics based on OLF guideline 117 (4.2.2) 2. Emphasized the wording regarding running non shearable components through the BOP ( ) 3. Highlighted principles in use of common well barriers in separate subchapter ( ) 4. Added subchapter on inflow testing, ref OLF recommendation no 3 ( ) 5. Added subchapter on formation integrity and testing ( ) 6. Emphasized preparation of well control bridging document between Operator and Rig contractor, ref OLF recommendation no 7 (4.2.6) 7. Emphasized content of well design basis (4.3.2) 8. Included new chapter on calculation of well design pressure (4.3.3) 9. Made statement to requirement of minimum 1.1 safety factor for well design duly taking into account the actual and future predicted wall thickness in the calculations.(4.3.5) 10. Included new chapter on Management of Change, ref OLF recommendation no 19 (4.7.2) 11. Included new chapter on maintenance (4.7.3) 12. Updated with more comprehensive chapter on blow-out contingency (4.8.1) 13. Updated with more comprehensive chapter on drilling relief wells (4.8.2) 14. Included new chapter on capping of subsea wells, ref OLF recommendation no 34 (4.8.3) 15. Rewritten chapter on competency specifically to well integrity personnel (4.9.1) 16. Added description to content of well integrity management system based on OLF guideline 117 (4.10.3) 17. Removed old Well control equipment arrangement for HPHT wells as this belongs more appropriately in Norsok D Removed old Well control equipment arrangement for deepwater wells (only for SSWs) as this belongs more appropriately in Norsok D Moved parameter table in old chapter to section 5 where it belongs more logically 20. Removed table relating to Simultaneous and critical activities under chapter 4.5 as this is a general requirement and not directly well integrity related 21. Removed table with activity program content under chapter as this is a general requirement and not directly well integrity related 22. Removed description of End of activity report under chapter as this is a general requirement and not directly well integrity related. 23. Removed description of Special well incident reporting under chapter as this is PSA prescription that they need to prescribe. Page 1 of 20

2 NORSOK Standard D-010 Rev 4. August GENERAL PRINCIPLES GENERAL WELL BARRIERS Defining well barriers Well barrier schematics Well barrier requirements Function and number of well barriers Well barrier design, selection and construction principles Common well barriers Verification of the well barrier Pressure testing of well barriers General Acceptable leak rates Pressure test direction Test pressure values and duration Inflow testing during drilling and well activities Function testing of well barriers Testing of formation Documentation of pressure and function testing of well barriers Well barrier monitoring Well barrier impairment Well barrier element acceptance criteria tables Well control equipment and arrangements Well control actions procedures and drills Well barrier re-establishment Contingency plan Re-establishment of fluid well barrier WELL DESIGN Objective Design basis, premises and assumptions Well design pressure Load case scenarios Design factors RISK ASSESSMENT AND RISK VERIFICATION METHODS SIMULTANEOUS AND CRITICAL ACTIVITIES ACTIVITY AND OPERATION SHUT-DOWN CRITERIA ACTIVITY PROGRAMMES AND PROCEDURES Preparation of activity program Management of change (MoC) Maintenance program and procedures CONTINGENCY PLANS Installation/field blow-out contingency plan Plan for drilling a relief well Plan for capping and shutting in a flowing subsea well PERSONNEL COMPETENCE AND SUPERVISION Personnel competence Supervision of operations EXPERIENCE TRANSFER AND REPORTING Experience transfer Well integrity records Well integrity management Page 2 of 20

3 NORSOK Standard D-010 Rev 4. August General principles 4.1 General This section describes generic principles, requirements and guidelines applicable to the specific well activities and operations described in the sections to follow. If there is a conflict between Section 4 and the following sections, the latter shall apply. 4.2 Well barriers Defining well barriers The well barriers shall be defined prior to commencement of an activity or operation by identifying the required well barrier elements to be in place, their specific acceptance criteria and monitoring method Well barrier schematics Well barrier schematics shall be prepared for each well activity and operation. A well barrier schematic should be made for the following; a) when a new well barrier element is acting as a well barrier element, b) for illustration of the completed well with x-mas tree (planned and as built), c) for recompletion or workover on wells with deficient well barrier elements. It is not necessary to make a new schematic for different types of running assemblies when the elements and activation of secondary well barriers are not affected. The well barrier schematics should contain the following information: d) A drawing illustrating the well barrier envelopes, with the primary well barrier shown with blue color and secondary well barrier shown with red color. e) The formation strength when the formation is part of a well barrier envelope. f) Reservoirs and potential sources of inflow. g) Tabulated listing of well barrier elements with qualification and monitoring requirements. h) All casings and cement (including TOC). Casing and cement defined as well barriers elements shall be labeled with its size and depth (TVD and MD). i) Depth of component should be shown relatively correct in relation to each other. j) Well information: field/installation, well name, well type, well status, well/section design pressure, revision number and date, Prepared by, Verified/Approved by. k) Clear labeling of actual well barrier status planned or as built. l) Any failed or impaired well barrier element to be clearly stated. m) A note field for important well integrity information (anomalies, exemptions, etc.). Samples of well barrier schematics are presented in this standard for selected situations. These well barrier schematics are guidelines and describe one possible solution for how the well barrier envelopes with well barrier elements can be established and illustrated. Page 3 of 20

4 NORSOK Standard D-010 Rev 4. August 2012 Example: x.y.z Description Well Barrier Elements See WBEAC table Verification / Monitoring Insert illustration here Primary Well Barrier - Reservoir Secondary Well Barrier - Reservoir Notes: To be updated

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6 4.2.3 Well barrier requirements Function and number of well barriers The function of the primary and secondary well barrier and well barrier elements shall be clearly defined. There shall be one (1) well barrier in place during all well activities and operations, including suspended or abandoned wells, where a pressure differential may exist that could cause uncontrolled cross flow in the wellbore between formation zones. There shall be two (2) well barriers in place during all well activities and operations, including suspended or abandoned wells, where a pressure differential may exist that could cause uncontrolled flow from a potential source of inflow to surface or external environment Well barrier design, selection and construction principles The well barriers shall be designed, selected and constructed with capability to: a) withstand the maximum anticipated differential pressure it may become exposed to, b) be pressure tested, function tested or verified by other methods, c) ensure that no single failure of well barrier envelope or well barrier element can lead to uncontrolled release of wellbore fluids or gases to the external environment, d) re-establish a lost well barrier or establish another alternative well barrier, e) operate competently and withstand the environment for which it may be exposed to over time, f) determine the physical position/location and integrity status at all times when such monitoring is possible, g) to the extent possible be independent of each other without common well barrier elements. During activities the following apply: h) One of the well barriers elements should be able to shear any workstring that penetrates the well barrier and seal the wellbore after having sheared the string. i) All non shearable components in the work-string shall be identified. j) When running non shearable components through the BOP, there shall be procedures in place for handling a well control situation. k) When running long non-shearable assemblies, there shall be an element (e.g. annular preventer) installed that can seal the well bore against any size assembly that penetrates the well barrier Common well barriers Common well barriers are sometimes unavoidable. Example: Wing valves in a x-mas tree during intervention work, casing cement in development wells. Common barrier - wing valves Common barrier - casing cement Page 6 of 20

7 When common well barrier element exists, a risk analysis shall be performed and risk reducing measures applied. This should include additional precautions and acceptance criteria when qualifying and monitoring the common well barrier element Verification of the well barrier When a well barrier has been installed, it s integrity and function shall be verified by means of: a) pressure testing by application of a differential pressure, b) functioned testing of well barrier elements that require activation, c) other specified methods. A re-verification should be performed if: d) the condition of any well barrier element could have changed since the initial or previous test, e) there is a change in loads for the remaining life cycle of the well (drilling, completion and production phase) Pressure testing of well barriers General Pressure testing of well barriers or well barrier elements shall be performed: a) before it can become exposed to well pressure differential, b) after replacement of pressure confining components of a well barrier element, c) when there is a suspicion of a leak, d) when an element will be exposed to different pressure/load than it originally was designed for, e) periodically, see EAC tables. During pressure testing, the volume downstream of the element being tested should be monitored Acceptable leak rates The acceptable leak rate shall be zero, unless specified otherwise. For practical purposes acceptance criteria should be established to allow for temperature effects, air entrapment and media compressibility. For situations where the leak-rate cannot be monitored or measured, the criteria for maximum allowable pressure fluctuation shall be established Pressure test direction The test pressure should be applied in the direction of flow. If this is not possible or introduces additional risk, the test pressure can be applied against the direction of flow, providing that the well barrier element is constructed to seal in both flow directions Test pressure values and duration A low pressure test to bar (1,5 2,0 MPa) for minimum 5 minutes should be performed prior to high pressure testing in the drilling, completion and intervention activities. For periodic testing of wells in production/injection phase, a low pressure test is not applicable. The high pressure test value shall be equal to, or exceed the maximum anticipated differential pressure that the well barrier element may become exposed to. Static test pressure shall be observed and recorded for minimum 10 minutes. In the production/injection phase, a 70 bar (7MPa) pressure differential should be applied for all well barrier elements with an allowable leak rate. Less differential pressure (i.e. if the well pressure is less) may be used provided that the allowable leak rate is changed proportionally. Inflow tests should last for a minimum of 30 minutes (or longer if needed to cater for temperature effects). The test pressure values shall not exceed the rated working pressure of exposed well barrier elements. Page 7 of 20

8 Inflow testing during drilling and well activities An inflow (negative pressure) test shall be described in a detailed procedure, which should contain the following information: a) an identification of the well barriers to be tested, b) identification of the consequences of a leak, c) the risk of inconclusive results due to large volumes, temperature effects, migration, etc, d) a plan of action in the event that leak occurs or if the test is inconclusive, e) a schematic diagram showing the configuration of test lines and valve positions, f) all operational steps and decision points, g) defined acceptance criteria for the test, h) verification of the secondary well barrier s ability to withstand differential pressure. The following apply for the execution of an inflow test: i) Volume and pressure control shall be maintained at all times during displacement and testing. j) During inflow testing it shall be possible to displace the well to back overbalanced fluid at indication of flow or in case of inconclusive results. k) During displacement, non shearable components shall not be placed across the BOP shear ram. l) Displacement to a lighter fluid should be performed with constant bottom hole pressure. m) When the displacement is complete, the well shall be closed in without reducing the bottom hole pressure. n) The inflow test should be performed by bleeding down pressure in steps, to a pre-defined differential pressure. o) The pressure development should be monitored for a specified time period for each step Function testing of well barriers A function test of the well barrier element(s) shall be performed: a) prior to installation (subsea/downhole equipment) b) after installation, c) if subjected to abnormal loads, d) after repairs, e) periodically, see EAC tables Testing of formation Rock mechanical data shall be systematically acquired in order to ensure well integrity in the drilling, production/injection and abandonment phases. The wellbore integrity test method shall be determined by the objective of the test. The most common methods are: Method Objective Comment Pressure Integrity Test (PIT, previously referred to as FIT) To confirm that the formation/cement is capable of supporting a pre-defined pressure. Leak-Off Test (LOT) Extended Leak-Off Test (XLOT) To establish the pressure the wellbore wall/cement is capable of supporting. Determine the minimum in-situ formation stress (σ 3 ). Application of a pre-determined pressure to the formation and observe if stable. The test is stopped once a deviation from the linear pressure vs. volume curve is observed. The test propagates a fracture into the formation and establishes the fracture closure pressure (FCP). Page 8 of 20

9 Sufficient wellbore integrity shall be defined and documented in order to qualify formation as a well barrier element. The following apply: Well type /Activities Exploration wells (all activities including P&A) Production wells - drilling activities Production wells - completion, production/injection operations and P&A New wells/fields (post ) Minimum wellbore integrity Existing wells/fields (after ) Sufficient wellbore integrity can be obtained by PIT/FIT or LOT Minimum formation stress/fracture closure pressure (FCP) shall exceed well design pressure Where fracture gradient (interval between FBP and FCP, see figure below) was used as part of the design basis, fracture gradient can still be used as design parameter for sufficient formation integrity. The design shall be verified prior to permanent P&A of the well(s). The graph below shows typical pressure behaviour when performing an extended leak-off test in a nonpermeable formation. Formation Break-down Pressure (FBP) Leak-off Pressure (LOP) Fracture Propagation Pressure (FPP) Shut-in Pressure Fracture Re-opening Pressure (FRP) Fracture Closure Pressure (FCP) Pressure PIT Pump-in Shut-in Flow-back Pump-in Flow-back Time Note: Concept sketch only, not to scale! Documentation of pressure and function testing of well barriers All well integrity tests shall be documented and accepted by an authorized person. The pressure test records should contain: a) type of test, b) test/differential pressure, c) test fluid, d) system or components tested, Page 9 of 20

10 e) estimated volume of pressurized system, f) volume pumped and bled back, g) time and date, h) test duration, i) observed pressure trend/observed leak rate, j) acceptance criteria, k) result of test (passed or failed). The function test records should contain: l) type of test, m) time and date, n) activation time, o) acceptance criteria, p) result of test (passed or failed) Well barrier monitoring All parameters relevant for preventing uncontrolled flow from the well shall be monitored. Methods and frequency for verifying the condition of the well barrier envelope or well barrier elements shall be defined and documented. Volume control of fluid shall be maintained at all times when the fluid is a well barrier. The pressure in all accessible annuli shall be monitored and recorded. All instrumentation used for required monitoring of parameters shall be frequently checked and calibrated Well barrier impairment Situations where the function of the well barrier is impaired (weakened), but still regarded as acceptable shall be documented and approved Well barrier element acceptance criteria tables Well barrier element acceptance criteria shall be in place for all well barrier elements used. General technical and operational requirements and guidelines relating to well barrier elements are collated in the tables in Section 15, which shall be applicable for all type of activities and operations. Page 10 of 20

11 The recommended format for describing the Element Acceptance Criteria (EAC) table is: Features Acceptance criteria References A. Description This is a description of the well barrier element. B. Function This describes the main function of the well barrier element. C. Design (capacity, rating, and function), construction and selection For well barrier elements that are constructed in the field (i.e. drilling fluid, cement), this should describe design criteria, such as maximal load conditions that the well barrier element shall withstand and other functional requirements for the period that the well barrier element will be used, construction requirements for the well barrier element or its sub-components, and will in most cases consist of references to normative standards. For well barrier elements that are pre-manufactured (i.e. production packer, DHSV), the focus should be on selection parameters for choosing the right equipment and proper field installation. Name of specific references D. Initial test and verification This describes the methodology for verifying the well barrier element being ready for use and being accepted as part of a well barrier system. E. Use This describes proper use of the well barrier element in order for it to maintain its function during execution of activities and operations. F. Monitoring (Regular surveillance, testing and verification) G. Common well barrier element This describes the methods for verifying that the well barrier element continues to be intact and fulfils the design criteria. This describes additional criteria to the above when this element is a common well barrier element Well control equipment and arrangements Equipment arrangement drawings and flow diagrams for well control equipment shall be easily accessible for operators of this equipment such that it is possible to determine the position of a tubular joint relative to the shear rams/valves at all times. These drawings and flow diagrams should include: a) geometrical description (location, size, distances to rig floor, distances between rams, etc.), b) operational limitations (pressure, temperature, type of fluid, flow rates, etc.), c) overview of the fluid circulation system (pump, including choke and kill manifold) Well control action procedures and drills There shall be a plan for activating well barrier(s)/well barrier elements (well control action procedure), prior to commencement of all well activities and operations. These plans shall be made known to all involved personnel. A well control bridging document between Operator and Contractor shall be prepared defining: a) Well control roles and responsibilities during the operation b) Shut-in procedures c) Methods for re-establishing barriers: Activation of alternative well barrier elements/envelopes Kill procedures Normalization Page 11 of 20

12 d) Specific well control configuration for the well activity (including ram configuration) In the event of a failure or loss of a well barrier, immediate measures shall be taken to prevent escalation of the situation. The situation shall then be normalized by restoring the well barrier or establishing an alternative well barrier before activities or operations can be resumed. Activation of the shear rams/shear valves or other shearing devices shall only take place when there is an emergency situation and no other options exist but to cut and seal. Regular and realistic drills pertaining to on-going or up-coming operations shall be conducted to train involved personnel in detection and prevention of a lost well barrier. The objective of the drill shall be pre-defined. Pass/fail criteria or assessment KPIs for all key well control and safety drills shall be established. All relevant personnel with emergency duties should be involved in the drills. The drills should be repeated with sufficient frequency to achieve the acceptable response. All drills shall be approved, evaluated for improvements and documented Well barrier re-establishment Contingency plan There shall be a contingency plan which describes the steps required to re-establish a lost well barrier or the establishment of an alternative well barrier for the most likely and critical incident scenarios Re-establishment of fluid well barrier The methods for killing the well or re-establishing a fluid well barrier shall be defined and described prior to execution of activities where the fluid column is one of the well barriers or is defined to be a contingency well barrier. Sufficient amount of kill fluid volumes and materials shall be available prior to commencing well killing operation. The preferred kill method for the different scenarios shall be described (this could be Driller s -, Wait and Weight -, Volumetric - or Bullheading method). Parameters required for re-establishing the fluid well barrier shall be systematically recorded and updated in a Killsheet. 4.3 Well design Objective Well design is a process with the objective of establishing, verifying and documenting the selected technical solution that fulfils the purpose of the well, complies with requirements and meets design criteria throughout the defined life cycle of the well. A well design process shall be carried out for: a) construction of new wells, b) alteration, changes or modification to existing wells (i.e from exploration to production or from producer to injector or vice versa) c) changes in the well design basis or premises (life extension, increased pressure exposure, flow media, etc.). The well design should be robust, that is: d) can handle variations and uncertainties in the design basis, e) can handle changes and failures without leading to critical consequences, f) can handle a wide range of operating conditions, g) designed for operations throughout the wells life cycle, including permanent plug and abandonment. Page 12 of 20

13 4.3.2 Design basis, premises and assumptions A Subsurface Well Design Basis shall be prepared with objectives, premises, functional requirements and assumptions prior to commencement of planning. The following elements should be assessed and documented in the Subsurface Well Design basis: a) well objective, b) design life requirements, c) restrictions related to drilling location (e.g. seasonal or environmental constraints), d) well location (location data, seabed conditions), e) target, TD criteria and tolerances, f) offset wells, g) geological depth prognosis with expected stratigraphy and lithology, including uncertainties, h) temperature, pore pressure and formation strength prognosis, including uncertainties, i) data acquisition, j) shallow drilling and location hazards, k) reservoir data summary, l) additional information for production wells. As an extension to the Subsurface Well Design Basis, a Drilling and Well design basis shall be prepared. The flowing should be assessed and documented: m) drilling requirements, n) summary of reference well data and experience, o) wellhead and conductor design, p) casing design, q) cementing requirements, r) drilling fluids, s) welltesting or completion requirements, t) well path listing, with target requirements and proximity calculations to offset wells, u) sidetrack options, v) blow-out contingency/relief well/capping requirements, w) plug and abandonment solutions, x) well studies and risk analysis Well design pressure The well design pressure shall be maximum expected shut-in surface well pressure plus a margin that will allow killing the well by bullheading. A combination of liquid and gas column may be used if it can be documented that the well cannot be fully gas filled during its lifetime. Page 13 of 20

14 Maximum expected shut-in pressure should be estimated based on the following: Well type Exploration wells Development wells in reservoir with free gas Development wells in reservoir without free gas Gas lift or injection wells Calculation basis Pore/reservoir pressure less the hydrostatic pressure from a column of methane gas or actual gas composition from offset wells. Reservoir pressure less hydrostatic pressure from actual gas gravity at virgin reservoir pressure. Dynamic simulation to determine pressure at shut-in condition based on actual reservoir fluid compositions and gas-oil-ratio. Beware of late life condition with depletion and possible free gas. Maximum applied injection pressure (pressure safety valve setting or high-high pressure shut-down) if this is higher than the reservoir generated pressure. Page 14 of 20

15 To derive the well design pressure, the following principles should apply: Design category MSDP (Maximum Section Design Pressure) used during drilling and P&A of wells METP (Maximum Expected Tubing Pressure) used in completed wells How to derive Highest of: - maximum shut-in pressure + kill margin - fracture pressure at shoe with gas above shoe depth - custom loads (i.e. TCP firing pressure, packer setting) - P&A plug test criteria (fracture pressure + 70 bar) Maximum expected shut-in pressure + a kill margin. It is recommended to estimate the actual bullhead kill rates with seawater and kill fluid respectively to verify the applied kill margin. Unless kill margin has been specifically calculated it is recommended to use 70 bar kill margin for exploration wells and 35 bar kill margin for production wells. Changes in pressures and flow capability, due to injection/production in different reservoir zones nearby or wellbore instability during the lifetime of the field, shall be accounted for in the planning Load case scenarios Static and dynamic load case scenarios for well barrier elements and other critical equipment installed or used in the well shall be established. Load calculations shall be performed and compared with minimum acceptance criteria/design factors. All calculations shall be verified and documented Design factors Minimum design factors or other equivalent acceptance criteria shall be pre-defined for: a) burst loads, b) collapse loads, c) axial loads, d) tri-axial loads. It is recommended that a minimum design factor of 1.10 is applied to all loads. The calculation of the design factor shall duly take into consideration wall thickness manufacturing tolerance, corrosion and tubular wear over the lifecycle of the well. 4.4 Risk assessment and risk verification methods An assessment of well integrity risks associated with the intended operation shall be performed. The risk of a well integrity failure or well control incident shall be assessed. When evaluating well integrity risk, the failure modes of primary well barrier elements and the availability of secondary well barrier shall be considered. If a well barrier is degraded, a risk assessment should be performed considering the following: a) cause of degradation, b) potential of escalation, c) availability and reliability of secondary well barrier envelope, d) outline plan to restore well barrier (technical and time line) Onsite safe job analysis should be conducted for: e) new or non-standard operations, f) operations involving use of new technology or modified equipment, g) hazardous operations, h) change in actual conditions which may increase the risk. NORSOK Z-013, Risk and emergency preparedness assessment may be used as reference. Page 15 of 20

16 4.5 Simultaneous and critical activities Simultaneous and critical activities and operations that may cause loss of or severe degradation to a well barrier shall be thoroughly planned, analyzed and performed with the objective of limiting additional risk imposed by multiple activities and operations. These can be lifting of heavy objects above wells, construction activities, drilling close to existing wells, or temporary shut-down of power/control system for operating well barrier elements. Acceptance of simultaneous and critical activities and operations shall be in accordance with defined acceptance criteria and shall be quality assured through risk assessments. Procedures for the control of simultaneous and critical activities and operations shall be in place prior to commencement. 4.6 Activity and operation shut-down criteria Criteria for shut-down of the activities or operations shall be established. Normal activities and operations should cease, when; a) having a weakened/impaired well barrier/ well barrier element or failure/loss of a well barrier/ well barrier element, b) there is a high probability for exceeding allowable operating limits of well control equipment and other critical equipment, c) H2S content of fluids or gases exceeds operating limits of the well control equipment and other critical equipment. 4.7 Activity programmes and procedures Preparation of activity program An activity programme shall be issued prior to commencement of: a) drilling activities, b) formation testing activities, c) completion activities, d) well intervention activities, e) re-completion or workover activities, f) suspension and abandonment activities. The main contractor(s) should be involved in the process of developing the activity programme. The programme may be supplemented by more detailed procedures relating to planning, execution and close-out of the activities. All significant deviations from the programme or procedure shall be formally documented, approved and distributed to the users of the programme or procedure. Programme, procedures and plans that have a validity period for more than one year should be regularly reviewed and updated as necessary. A new plan shall be prepared for wells that have not been put to use according to the original plan, or that have been temporarily suspended for more than three years Management of change A Management of Change (MoC) procedure covering the life cycle of the well shall be implemented. The procedure should describe the processes used to assess risk, mitigate, authorize, and document technical, operational or organizational changes to previously approved information or procedures. Changes subject to a MoC process should include the following: Page 16 of 20

17 a) safety critical systems, b) surface and downhole well control equipment, c) impact on well barriers, d) procedures, e) rig or well control equipment, f) key personnel. Whenever a change is proposed, this shall be supported by a justification that should address the following: g) reason for change, h) description of the new proposed solution, i) possible consequences and uncertainties. All appropriate and applicable disciplines shall be involved in the preparation of the proposed solution and/or endorse the proposal. Changes to programmes and procedures shall be approved at the level of the original approval and include input of those affected by the change Maintenance program and procedures A preventive maintenance program shall be prepared for all well barrier elements where the integrity status is not continuously monitored or pressure trended. All periodical inspections, pressure and function tests shall be a part of the maintenance program. Further reference is given to number F. Monitoring in the EAC tables in section 15. The test and inspection intervals shall be based on reliability data of the well barrier element as well as field and well specific conditions that may influence the reliability over time. Procedures for periodic testing and inspections shall be prepared. The procedures shall describe any preparations and how the test practically shall be carried out. Valve positions, test medium, pressures and acceptance criteria shall be clearly stated. 4.8 Contingency plans Installation/field blow-out contingency plan A blowout contingency plan shall be established for each installation, field or area. The plan shall cover drilling and well activities and the production/injection activities. The blowout contingency plan shall as a minimum address the following: a) field layout, b) well design, c) primary kill strategy in a blowout case, d) a description of, or reference to, the emergency response organization (Drilling & Well, Search and Rescue, Oil spill, etc.) A blowout and kill rate simulation study shall be performed for the well design expected to give the highest blowout and kill rates in the field and for every exploration well. The following blowout scenarios shall be covered for penetrated reservoirs: e) through casing/open hole, f) through drillpipe, g) through drillpipe/casing or casing/casing annulus, h) subsea wells only: release to seabed and to surface Page 17 of 20

18 The following data should be used for blowout and kill simulations: i) expected values for reservoir parameters (permeability, porosity, net-gross pay, etc.), j) expected top of reservoir depth, k) expected productivity index / transient productivity index, l) expected fluid type parameters (if oil is expected, but gas cannot be disregarded both cases shall be simulated), m) mechanical skin set to zero, n) no restrictions in the flow path, o) planned well design (hole size, casing setting depth, etc.). For offshore wells, the well design should enable killing a blowout with one (1) relief well. If two (2) relief wells are required, it shall be documented that such an operation is feasible with respect to logistics, weather criteria and availability of rigs. The feasibility should be supported by a risk assessment demonstrating the probability of success. An offshore well design that requires more than two (2) relief wells is not acceptable Plan for drilling a relief well An outline plan for drilling relief well(s) shall be in place for each well, field or installation. For templates and platforms it shall be demonstrated that it is possible to reach the most challenging well from each relief well location. The plan shall contain: a) minimum two (2) suitable rig locations including anchoring assessment (only applicable for anchored rigs) for the two relief locations. If blowout and kill simulations show the need for two relief wells, minimum three relief well locations shall be in place, b) the relief well locations should be up-wind and up-current location based on prevailing wind and current data, c) shallow gas assessment for the relief well locations, d) simplified relief well paths from the relief well locations to the intersection point in the blowing well, e) overview of suitable rig(s) for relief well drilling based on the necessary pumping capacity (well specific conditions, water depth, pump rate/pump pressure/mud storage volume, etc.), f) description of primary killing method. In most cases this will be a high rate dynamic kill operation through the relief well which is directly intersected with the blowing well, g) updates reflecting the current conditions and pressures in the well and reservoir The time for mobilizing relief well rig(s) shall be evaluated in the planning phase. Initiation of relief well drilling should start no later than twelve (12) days after the decision to drill the relief well(s) has been taken Plan for capping and shutting in a flowing subsea well An outline plan for capping and shutting in a flowing subsea well should be in place to demonstrate mobilization and installation of capping equipment within a reasonable timeframe. The plan should: a) evaluate the feasibility of capping a blow-out scenario at the given water depth, b) identify all connections and possible interfaces from wellhead to flexible joint, c) identify all connections and possible interfaces from X-mas tree to interface to workover equipment, d) include an overview of equipment requirements to allow installation of a capping stack/having a proper adapter available to enable connection of capping stack, e) consider additional well load cases resulting from a capping operation. Page 18 of 20

19 4.9 Personnel competence and supervision Personnel competence Competence requirements for personnel working with well integrity shall be described. Verification of the individual s competence can be done through gap analysis, tests or interviews. A training programme, which may consist of courses, e-learning, self-study programme or on-the-job training, should be conducted to close gaps. The position competence curriculum should address the following subjects: a) roles and responsibilities for well integrity management within the company, covering both construction and operation phase, b) wellbore physics (formation strength, and dynamic pressure and temperature regimes), c) well construction principles, casing design, completion design and definition of load cases, d) preparation of well handover documentation, e) establishment of a two well barrier envelope philosophy for the construction and operation phase and preparation of well barrier schematics, f) operational supervision, frequent testing, monitoring, troubleshooting, annulus pressure management and trend monitoring. Operational supervisory personnel shall hold a valid well control certificate issued by an international recognized party (i.e. IWCF or IADC). When new equipment or techniques will be used, involved personnel shall attend theoretical and practical proficiency training. All training shall be documented Supervision of operations The well site activities and operations shall be monitored and supervised by a competent person who shall ensure that procedures, programmes, plans and routines are followed in a safe and efficient manner. Roles, responsibilities and authorities for personnel and positions that are overall responsible for well integrity through the various phases of the well, shall be defined Experience transfer and reporting Experience transfer The results of, and the experience from well activities and operations shall be collected, documented and made available for future use and continuous improvement. The experience transfer and reporting system should comprise of, but not be limited to: a) drilling and well activities reporting system, b) accident and incident reporting system, c) non-conformity/deviations/management of change, d) end of well/activity/operations reports, e) risk register for monitoring of risks, f) special reports Well integrity records Information relating to well integrity shall be documented. The following records (not limited to) should be retained: Item Description Retention period Comments 1. Equipment specifications and For the period that it is in use. Dimensional size and type of Page 19 of 20

20 Item Description Retention period Comments material certificates of technical components well barriers/well barrier elements. 2. Directional survey and wellhead coordinates. 3. Pressure test and leak test records and other records relating to acceptance of well barriers or well barrier elements. Unlimited For the period that it is in use. material for wellhead, casing, liner, tubing, packers, etc. Can be used for statistical purposes. 4. Annuli pressure records Umlimited Can be used for reference purposes 5. Casing and tubing load case calculations Until the well has been permanently abandoned. Documenting scenarios and actual safety factors 6. As built well barrier schematics Unlimited Showing actual status at all times 7. Well handover document. Until the well has been permanently abandoned. This should describe the well barrier status before the responsibility for well integrity is transferred to another organizational unit. (See section 8) 8. Drills conducted and results. 1 year Can be used for statistical purposes Well integrity management A systematic approach shall be established to manage the well integrity in all stages of the life cycle of the well, from construction phase to final P&A. The system should consist of following elements: 1. Organization Roles and responsibilities Competency requirements Strategy and objectives Emergency preparedness 2. Design Use of standards Establishing well barrier Equipment requirements Safety systems Qualification 3. Operational procedures Operating limits and constraints Monitoring Transfer of information 4. Data system Collection Storage Monitoring 5. Analysis Trend monitoring Assessment of performance Risk status Continuous improvement Page 20 of 20