Below is a listing of the main changes 1. Definitions of suspension, temporary and permanent abandonment 2. Included more examples of well barrier schematics 3. Included illustrations for permanent abandonment scenarios (9.5.3) 4. Included shale formation as an annulus well barrier element (9.5.4) 5. Included flow charts for establishing permanent barriers (9.5.6 and 9.5.7) 6. Included requirements for XT removal Table of Contents 9.1 General... 1 9.2 Well barrier schematics... 2 9.3 Suspension... 2 9.3.1 General... 2 9.3.2 Well barrier schematics... 3 9.4 Temporary abandonment... 5 9.4.1 General... 5 9.4.2 Well barrier schematics... 6 9.5 Permanent abandonment... 15 9.5.1 General... 15 9.5.2 Well barrier schematics... 17 9.5.3 Examples for different permanent P&A options... 24 9.5.4 Formation as well barrier element... 26 9.5.5 Sidetracking... 26 9.5.6 Section milling to establish permanent barriers... 27 9.5.7 Alternative method to establish permanent barriers... 29 9.5.8 Materials... 30 9.6 Well control action procedures and drills... 31 9.6.1 Well control action procedures... 31 9.6.2 Well control action drills... 31 9.6.3 Well control requirements... 31 9.7 Suspension, plugging and abandonment design... 31 9.7.1 Design basis, premises and assumptions... 31 9.7.2 Load cases... 32 9.8 Other topics... 32 9.8.1 Risks... 32 9.8.2 Removing equipment above seabed... 33 9.9 Vertical Xmas tree (VXT) removal... 34 9.10 Horizontal Xmas tree removal... 35 9 Plugging, abandonment and suspension 9.1 General This section covers requirements and guidelines for well integrity during plugging of wells in connection with Page 1 of 35
a) temporary suspension of well activities and operations, b) temporary or permanent abandonment of wells, c) permanent abandonment of a section of a well (side tracking, slot recovery) to construct a new wellbore with a new geological well target. The purpose of this section is to describe the establishment of well barriers by use of WBEs and additional requirements and guidelines to execute this activity in a safe manner with focus on isolation of permeable formations/reservoirs/sources of outflow, both from each other in the wellbore, and from surface. Requirements for isolation of formations, fluids and pressures for temporary and permanent abandonment are the same. However, choice of WBEs may be different to account for abandonment time, and ability to reenter the well or resume operations after temporary abandonment. 9.2 Well barrier schematics Well barrier schematics (WBS) shall be prepared for each well activity and operation. A final verified WBS for the well status upon completion of operations shall be in place. Samples of well barrier schematics for selected situations are presented. 9.3 Suspension 9.3.1 General Suspension of a production or injection well is defined as a well status, where the well is temporarily plugged, XT is installed, and the well barriers are monitored. Suspension of a well under construction or intervention is defined as a well status, where the well operation is suspended without removing the well control equipment. Example: Disconnect due to WOW Well barriers and WBE material(s) shall have sufficient integrity to meet the suspension period, including contingency. The suspended wellbore should be monitored throughout the suspension period. The following number of well barriers shall be in place to safely suspend the wellbore: Suspension Two well barriers One well barrier Formation Potential source of inflow or reservoir exposed (hydrocarbons present) Formation with normal pressure (or less) Page 2 of 35
9.3.2 Well barrier schematics Suspended well, Hang off/disconnect of marine riser 9.3.2a 9.3.2a Suspension, Hang off/disconnect of main riser APR SSR UPR MPR LPR Drilling BOP Well barrier elements WBEAC table Verification/Monitoring Primary Well Barrier 1. Fluid column 1 Time limited barrier 2. 3. 4. 5. 6. 7. Secondary Well Barrier 1. Casing cement 22 Last casing 2. Casing 2 3. Wellhead 5 4. BOP 4 5. 6. 7. Notes: Well Integrity issues Comments/Notes Page 3 of 35
Suspended well, completed well with deep set mechanical plug 9.3.2b 9.3.2b Suspended well, Completed well with a deep set mechanical plug Well barrier elements Primary Well Barrier 1. Formation at 9 5/8 casing window 2. 9 5/8 Production casing cement (up to prod packer) 3. 9 5/8 Production casing 4. (up to prod packer) See WBEAC table n/a 22 5. Production packer 7 6. Deepset plug 6 2 Verification/Monitoring Surface casing Intermediate casing 20" csg Xxx mtvd DHSV 13 3/8" csg Xxx mtvd 10 3/4"-9 5/8" XOV Xxx mtvd Secondary Well Barrier 1. Formation at prod n/a packer 2. 9 5/8 Production 22 casing cement (above prod packer) 3. 10 ¾ x 9 5/8 2 Production casing 4. 10 ¾ Production 5 casing hanger with seal assembly 5. Tubing hanger with 10 seals 6. Tubing hanger crown 11 plug 7. X-mas tree 31 valves/connector 8. X-mas tree body 31 Notes: Well Integrity issues Comments/Notes Production casing PT 9 5/8" csg Xxx mtvd Reservoir Liner 7" csg Xxx mtvd Page 4 of 35
9.4 Temporary abandonment 9.4.1 General Temporary abandonment is defined as a well status in which the well has been temporarily plugged where the BOP or XT has been removed, and the well barriers are not continuously monitored. It shall be possible to re-enter temporary abandoned wells in a safe manner for the planned duration of the temporary abandonment. In general the following number of well barriers shall be in place to safely re-enter the wellbore. Temporary P&A Two well barriers One well barrier Formation Potential source of inflow or reservoir exposed (hydrocarbons present) Formation with normal pressure (or less) For temporarily abandoned wellbores, the selected WBE material(s) shall have sufficient integrity to meet the abandonment period times two. Prior to temporary abandonment, the future plans for the well shall be documented. Temporarily abandoned subsea wells shall be protected from external loads in areas with fishing activities, or other seabed activities. For deep water wells, temporary seabed protection can be omitted if there is confirmation of no such activities in the area and at the depth of the abandoned seabed installations. For temporary abandoned surface completed wells, it shall be possible to monitor the pressure in the A annulus and in the tubing. For temporary abandoned subsea completed wells that are planned to be abandoned for more than one year, a yearly program for monitoring and observation shall be established and implemented. The pressure in the tubing and A annulus shall be monitored if a subsea completed well is planned to be abandoned for more than one year or not tied back to a production facility. The following requirements are to be met: Production/injection packer and tubing hanger is pressure tested. Tubing is pressure tested. The DHSV is closed and pressure/function tested. All valves in the X-mas tree have been pressure tested with zero leak rate/function tested and are closed. For wells with horizontal X-mas trees, the tree cap and tubing hanger crown plug shall be pressure tested. If monitoring is not practicable, an acceptable alternative may be to install a deep set well barrier element plug. Page 5 of 35
9.4.2 Well barrier schematics Temporary abandonment, reservoir exposed 9.4.2a Page 6 of 35
Temporary abandonment, reservoir exposed - Casing 9.4.2b Page 7 of 35
Temporary abandonment, no permeable formation exposed - Liner 9.4.2c 9.4.2c Temporary abandonment, no permeable formation exposed - Liner Well barrier elements WBEAC table Primary Well Barrier Open hole 1. Cement plug 24 28 2. Casing cement 22 3. Formation at the shoe na Secondary Well Barrier Open hole 1. Casing cement 22 2. Casing cement or mechanical plug 24 28 Verification/Monitoring Set as deep as possible with verified cement in casing annulus Shallow plug 3. Liner top packer 43 Grade: V1 4. Formation Well Integrity issues Comments/Notes Page 8 of 35
Temporary abandonment, no permeable formation exposed Casing 9.4.2d 9.4.2d Temporary abandonment, no permeable formation exposed - Casing Well barrier elements WBEAC table Primary Well Barrier Open hole 1. Cement plug 24 28 2. Casing cement 22 3. Formation at the shoe na Secondary Well Barrier Open hole 1. Casing cement 22 2. Casing cement or mechanical plug 24 28 Verification/Monitoring Set as deep as possible with verified cement in casing annulus Shallow plug 3. Liner top packer 43 Grade: V1 4. Formation Well Integrity issues Comments/Notes Page 9 of 35
Temporary abandonment, non perforated well - Liner 9.4.2e Page 10 of 35
Temporary abandonment, non perforated well - Casing 9.4.2f Page 11 of 35
Temporary abandonment, impermeable formation with over pressure, non perforated 9.4.2g Page 12 of 35
Temporary abandonment, perforated well with BOP or XT removed - Liner 9.4.2h 9.4.2h Temporary abandonment, Perforated well with BOP or production tree removed Liner Well barrier elements See WBEAC table Primary Well Barrier 1. Casing (liner) cement 22 Verification/Monitoring 2. Casing (liner) 2 Liner above perforations. 3. Liner top packer 43 4. Casing 2 Below production packer. 5. Production packer 7 50 m below TOC in casing annulus. 6. Completion string 25 7. Deep set tubing plug 6 Secondary Well Barrier 1. Casing cement 22 Above production packer. 2. Casing 2 Common WBE, between liner top packer and production packer. 3. Wellhead 5 4. Tubing hanger 10 5. Tubing hanger plug 11 Notes: Well Integrity issues Comments/Notes Page 13 of 35
Temporary abandonment, perforated well with BOP or XT removed - Casing 9.4.2i 9.4.2i Temporary abandonment, Perforated well with BOP or production tree removed - Casing Well barrier elements See WBEAC table Primary Well Barrier 1. Casing cement 22 Verification/Monitoring 2. Casing 2 Above perforations. 3. Production packer 7 4. Completion string 25 5. Deep set tubing plug 6 Secondary Well Barrier 1. Casing cement 22 Intermediate casing. 2. Casing 2 Intermediate casing. 3. Wellhead 5 4. Tubing hanger 10 5. Tubing hanger plug 11 Well Integrity issues Comments/Notes Page 14 of 35
9.5 Permanent abandonment 9.5.1 General This section covers requirements and guidelines for well integrity during permanent abandonment. Permanently plugged wells shall be abandoned with an eternal perspective taking into account the effects of any foreseeable chemical and geological processes. The following number of well barriers to the external environment shall be fulfilled. Permanent P&A Two well barriers One well barrier Formation Potential source of inflow or reservoir exposed (hydrocarbons present) Formation with normal pressure (or less) The following individual or combined well barriers/isolations shall be a result of well plugging activities. Name Function Requirement to depth position Primary well barrier Secondary well barrier Crossflow well barrier Environmental isolation plug* First well barrier against a potential source of inflow. To isolate a potential source of inflow from flowing to surface/seabed Backup to the primary well barrier, against a potential source of inflow. To prevent flow between formations (where crossflow is not acceptable). May also function as primary well barrier for the reservoir below. To isolate the full cross sectional wellbore. To prevent movement of wellbore fluids to the environment. The base of the barrier shall be positioned at a depth where wellbore integrity is higher than potential pressure below, see 4.2.3.5.7 Testing of formation. As above. As above. The selected position should be documented**. *A well barrier may also function as an environmental plug. **The environmental isolation plug should be of sufficient length to ensure containment. Overburden formation should be assessed for abandonment requirements. Shallower permeable zones shall be plugged according to the same principle. Multiple reservoir zones/perforations located within the same pressure regime can be regarded as one reservoir for which a primary and secondary well barrier shall be installed (see illustration). Page 15 of 35
9.5.1.1 Permanent well barriers Permanent well barriers shall extend across the full cross section of the well, include all annuli and seal both vertically and horizontally (see illustration). The well barrier(s) shall be placed adjacent to an impermeable formation. Casing cement shall be verified to ensure a vertical and horizontal seal. If casing cement is verified by logging, minimum 30 m cumulative interval with acceptable bonding is required to act as a permanent external barrier. For the internal permanent barrier requirement, refer to WBEAC 24. An internal WBE shall be positioned over the entire interval where there is a verified external WBE (across all annuli). A permanent well barrier should have the following characteristics: a) Provide long term integrity (eternal perspective) b) Impermeable c) Non shrinking d) Able to withstand mechanical loads/impact e) Resistant to chemicals/ substances (H2S, CO2 and hydrocarbons) f) Wetting to ensure bonding to steel g) Not harmful to the steel tubulars integrity Steel tubulars are not an acceptable permanent WBE unless supported by cement or a plugging material with similar functional properties as listed above (internal and external). Elastomer sealing components in WBE s are not acceptable for permanent well barriers. Cement in the liner lap is accepted as a permanent WBE when pressure tested from above (before installation of liner top packer). Removal of downhole equipment is not required as long as the integrity of the well barriers is achieved. Control cables and lines shall be removed from areas where permanent well barriers are installed, if they can create vertical leak paths through the well barrier. Completions should be designed to facilitate the setting of annular cement plugs as a well barrier. When completion tubulars are left in the well and permanent well barriers are installed in the tubing and annulus, the position and integrity of the barriers shall be verified. Page 16 of 35
If it can be documented that placing one continuous cement (with compensating measures ref to EAC 24) plug is as reliable as two independent cement plugs to establish an internal barrier(s), this may be acceptable. 9.5.2 Well barrier schematics Permanent abandonment - Open hole 9.5.2 a 9.5.2a Permanent abandonment, open hole Liner/ reservoir Casing/ No source of outflow Well barrier elements WBEAC table Verification/Monitoring Primary Well Barrier 1. Cement plug 24 Open hole Or (Primary well barrier, last open hole) 1. Casing cement 22 2. Cement plug 24 Transition plug across casing shoe Secondary Well Barrier 1. Casing cement 22 2. Cement plug 24 Cased hole cement plug installed on top of a mechanical plug Environmental Isolation plug 1. Cement plug 24 Cased hole cement plug 2. Casing cement 22 Surface casing Well Integrity issues Comments/Notes Page 17 of 35
Permanent abandonment Perforated well, tubing left in hole 9.5.2 b 9.5.2b Permanent abandonment, perforated well, tubing left in hole Well barrier elements See WBEAC Verification/Monitoring table Primary Well Barrier 1. Liner cement 22 2. Cement plug 24 Across and above perforations Secondary Well Barrier 1. Casing cement 22 2. Cement plug 24 Inside and outside of the tubing Environmental Isolation plug 1. Cement plug 24 2. Casing cement 22 Surface casing Well Integrity issues Comments/Notes Page 18 of 35
Permanent abandonment Perforated well, tubing removed 9.5.2 c 9.5.2c Permanent abandonment, perforated well, tubing removed Well barrier elements See WBEAC table Primary Well Barrier 1. Liner cement 22 Verification/Monitoring 2. Cement plug 24 Across and above perforations Secondary Well Barrier 1. Casing cement 22 2. Cement plug 24 Across the liner plug. Environmental Isolation plug 1. Cement plug 24 2. Casing cement 22 Surface casing Well Integrity issues Comments/Notes Page 19 of 35
Permanent abandonment, Multi bore with slotted liners or sand screens with plug 9.5.2d 9.5.2d Permanent abandonment, multibore with slotted liners or sand screens with plug Well barrier elements WBEAC table Verification/Monitoring Primary Well Barrier - Reservoir 1. Cement plug 22 Across and above the perforations Secondary Well Barrier - Reservoir 1. Casing cement 22 2. Casing cement 24 28 Environmental Isolation plug 1. Cement plug 24 Across the liner plug 2. Casing cement 22 Surface casing Well Integrity issues Comments/Notes Page 20 of 35
Permanent abandonment, Multi bore with slotted liners or sand screens without plug 9.5.2e 9.5.2e Permanent abandonment, multibore with slotted liners or sand screens without plug Well barrier elements WBEAC table Verification/Monitoring Primary Well Barrier Reservoir 1. Cement plug 22 Across and above the perforations Secondary Well Barrier Reservoir 1. Casing cement 22 2. Casing cement or mechanical plug Environmental Isolation plug 24 28 1. Cement plug 24 Across the liner plug 2. Casing cement 22 Surface casing Well Integrity issues Comments/Notes Page 21 of 35
Permanent abandonment, Slotted liners in multiple reservoirs 9.5.2f 9.5.2f Permanent abandonment, Slotted line in multiple reservoirs Well barrier elements WBEAC table Verification/Monitoring Primary Well Barrier 1. Cement plug 24 Through liner and across casing shoe / open hole Secondary Well Barrier 1. Casing cement 22 2. Cement plug 24 Across the liner top Primary Well Barrier 1. Cement plug 24 Squeezed into perforated casing/annulus above potential reservoir Secondary Well Barrier 1. Casing cement 22 2. Cement plug 24 Environmental Isolation plug 1. Cement plug 24 Cased hole 2. Casing cement 22 Surface casing Well Integrity issues Comments/Notes Page 22 of 35
Permanent abandonment, Slotted liners in multiple reservoirs Intermediate casing cemented to previous casing shoe 9.5.2g 9.5.2g Permanent abandonment, Slotted line in multiple reservoirs Intermediate casing cemented to previous casing shoe Well barrier elements WBEAC table Verification/Monitoring Primary Well Barrier 1. Cement plug 24 Through liner and across casing shoe / open hole Secondary Well Barrier 1. Casing cement 22 2. Cement plug 24 Across the liner top Primary Well Barrier 1. Cement plug 24 Squeezed into perforated casing/annulus above potential reservoir Secondary Well Barrier 1. Casing cement 22 2. Cement plug 24 Environmental Isolation 1. Cement plug 24 Cased hole 2. Casing cement 22 Surface casing Well Integrity issues Comments/Notes Page 23 of 35
9.5.3 Examples for different permanent P&A options The following illustrations show permanent P&A options. Example A The last open hole section of a wellbore can be abandoned permanently by setting an open hole cement plug across/above the reservoir and an additional cement plug from the open hole into the casing (the minimum requirements are illustrated in figures below): The requirement is to have sufficient wellbore (formation) integrity at the base of both well barriers. P&A open hole and inside casing plugs Plug lengths: minimum 100 m min 30 m of verified logged cement min 50 m min 50 m min 50 m in OH and min 50 m inside csg Secondary 100 m Primary 100 m Verification: Pressure test plug inside casing Verification: Tag OH plug. Page 24 of 35
Example B The last open hole section of a wellbore or a perforated casing/liner can be abandoned permanently by setting two back to back cement plugs from the reservoir (or as close as possible to the reservoir), providing the casing cement is verified in the annulus. The internal cement plug lengths shall cover the cumulative logged interval in the annulus. P&A two back to back cement plugs 2 x 30 m verified logged cement Secondary 50 m Primary 100 m Verification: Volume control (Set on pressure tested fundament) Verification: Tag and pressure test primary plug 50 m inside casing Reservoir/perm. fm with overpressure Page 25 of 35
Example C A wellbore can be abandoned permanently by setting a mechanical plug to serve as a fundament for a single cement plug. The internal cement plug length shall cover the cumulative logged interval in the annulus P&A Single cement plug with mechanical plug foundation 2 x 30 m verified logged cement Primary Secondary Verification: Tag cement plug Verification: Pressure tested fundament Reservoir/ perm. fm with overpressure Formation as annulus well barrier element Bonded and impermeable in-situ formation (e.g. shale, salt) is accepted as an annulus well barrier element if qualified according to WBEAC 52 (Shale Formation). 9.5.4 Sidetracking The original wellbore should be permanently abandoned prior to a side-track/ slot recovery. A well barrier can be shared to function as well barrier for more than one well bore. Page 26 of 35
9.5.5 Section milling to establish permanent barriers The following method can be applied when section milling is required to establish well barriers. Log casing annulus to verify bonded formation/cement Yes Verified with sufficient length to act as barrier? No Re-establishing annulus barrier not necessary Install and test mech plug in bonded area Yes Sufficient length with bond to act as foundation? No Install and test mech plug in casing as close as possible to source of inflow Establish internal barrier Section mill and underream/wash to expose formation Perforate and perform low pressure cement squeeze to establish an external fundament (other means to establish fundament can be used) Mill 100 m Mill > 50 m No Evaluate situation. Consider further section milling Yes Place cement plug from fundament and minimum 50m across window Place cement plug from fundament to 50 m into casing WOC and tag WOC and leak test to 70 bar above leak off Place second cement plug from top of first plug and 50 m into casing WOC and leak test to 70 bar above leak off Establish secondary barrier in same manner as primary (another 50 m section mill above bonded area etc) Primary and secondary barriers established Page 27 of 35
Example For wells with poor casing cement or no access to the last open hole section, section milling (removal of casing) is an alternative method for placing cement in contact with formation to form permanent barriers. P&A section milling Milling window: minimum 100 m min 50 m min 50 m min 50 m Verification: Pressure test Verification: Tag Milling window: minimum 50 m Milling window: minimum 50 m min 50 m min 50 m max 50 m min 50 m Verification: Pressure test cement plug inside casing Verification: Pressure test cement plug inside casing Reservoir/ perm. fm with overpressure Reservoir/ perm. fm with overpressure Page 28 of 35
9.5.6 Alternative method to establish permanent barriers The use of alternative methods to establish the barriers shall be verified and documented. Log casing annulus to verify bonded formation/cement Yes Verified with sufficient length to act as barrier? No Re-establishing annulus barrier not necessary Establish internal fundament if required Yes Sufficient length with bond to act as foundation? No Install and test mech plug in casing as close as possible to source of inflow Establish internal barrier Establish annulus communication (perforate interval) Perforate and perform low pressure cement squeeze to establish an external fundament (alternative methods to establish a fundament can be used) ALTERNATIVE METHODS Squeeze cement perforations Circulate the casing annulus to create a clean, water-wet interval for bonding Place continuous plug from fundament to 50m above top perf Drill or clean out and re-log to confirm 50 m annulus seal Set internal cement plug across interval with annulus seal. Leak test to 70 bar above leak off Establish secondary barrier in same manner as primary Primary and secondary barriers established Page 29 of 35
Example For wells with poor casing cement or no access to the last open hole section, an alternative method for placing cement in contact with formation to form permanent barriers can be used. External verification may be omitted once a geological specific interval track record is established and documented. P&A alternative method Min 50 m Min 50 m Internal Verification: Pressure test External Verification: Logging Fundament: Internal and external required Min 50 m Internal Verification: Tag and pressure test External Verification: Logging 9.5.7 Materials The materials used in well barriers for plugging of wells shall withstand the load and environmental conditions the well barriers may be exposed to for the planned abandonment period. The suitability of the selected plugging materials shall be verified and documented. Degradation of the casing should be considered. Page 30 of 35
9.6 Well control action procedures and drills 9.6.1 Well control action procedures The following table describes incident scenarios in which well control action procedures should be available (if applicable) to deal with the incidents should they occur. This list is not comprehensive and additional scenarios may be applied based on the actual planned activity. Item Description Comments 1. Cutting of casing. Trapped gas pressure in casing annulus. 2. (SSW) Pulling casing hanger seal assembly. Trapped gas pressure in casing annulus. 3. Re-entry of suspended or temporary abandoned wells. Account for trapped pressure under plugs due to possible failure of suspension plugs. 9.6.2 Well control action drills The following well control action drills should be performed: Item Description Comments 1. Pressure build-up, or lost circulation in connection with a cutting casing operation. 2. Loss of well barrier while performing an inflow test. To verify crew response in applying correct well control practices. 9.6.3 Well control requirements Cutting/perforating the casing and retrieving seal assemblies shall be performed with active pressure control equipment in place to prevent uncontrolled flow from annuli between casings and into the well/riser 9.7 Suspension, plugging and abandonment design 9.7.1 Design basis, premises and assumptions All potential sources of inflow shall be documented. All well barrier elements used for plugging of wells shall withstand the load and environmental conditions they may be exposed to for the abandonment period. The following information should be gathered as a basis of the well barrier design and abandonment: a) Well configuration (original and present) including depths and specification of permeable formations, casing strings, cement behind casing status, well bores, side-tracks, etc. b) Stratigraphic sequence of each wellbore showing reservoir(s) and information about their current and future production potential, where reservoir fluids and pressures (initial, current and in an eternal perspective) are included. c) Logs, data and information from cementing operations in the well. Page 31 of 35
d) Formations with suitable well barrier element properties (i.e. strength, impermeability, absence of fractures and faulting) e) Specific well conditions such as scale build up, casing wear, collapsed casing, fill, H2S, CO2, hydrates, benzene or similar issues. The design of well barriers consisting cement or alternative materials should account for uncertainties relating to f) downhole placement techniques, g) minimum volumes required to mix a homogenous slurry, h) surface volume control, i) pump efficiency/ -parameters, j) contamination of fluids, k) shrinkage of cement or plugging material l) centralisation. 9.7.2 Load cases A combination of the functional and environmental loads shall be designed for. For permanently abandoned wells, the specific gravity of well fluid accounted for in the design shall as a maximum be equal to a seawater gradient. The following load cases should be applied for the abandonment design: Item Description Comments 1. Minimum depth of primary and secondary well barriers for each reservoir/potential source of inflow, taking the worst anticipated reservoir pressure for the abandonment period into account. Not shallower than the wellbore (formation) integrity at these depths. Reservoir pressure may for permanent abandonment revert to initial/virgin level. It should take into account redevelopment scenarios or gas storage if applicable. 2. Pressure testing of casing plugs. Criteria as given in WBEAC 24. 3. Burst pressure limitations on casing string at the depths where temporary abandonment plugs are installed. 4. Collapse loads from seabed subsidence or reservoir compaction. Cannot set plug higher than the burst rating allows (less wear factors). The effects of seabed subsidence above or in connection with the reservoir shall be included. 9.8 Other topics 9.8.1 Risks Design and operational risks shall be assessed. Typical risk could include: a) pressure and wellbore (formation) integrity uncertainties, b) time effects: long term development of reservoir pressure deterioration of materials used sagging of weight materials in well fluids c) scale in production tubing, d) H2S or CO2, Page 32 of 35
e) release of trapped pressure, f) unknown status of equipment or materials, g) environmental issues. 9.8.2 Removing equipment above seabed For permanent abandonment wells, the wellhead and casings shall be removed below the seabed. The cutting depth shall be sufficient to prevent conflict with other marine activities. Local conditions such as soil and seabed scouring due to sea current should be considered. For deepwater wells, it may be acceptable to leave or cover the wellhead/structure. Mechanical or abrasive cutting is the preferred method for removal of the casing/conductor at seabed. Use of explosives to cut casing/conductor is acceptable only if measures are implemented (Example: directed/ shaped charges providing upward and downward protection) which reduces the risk to surrounding environment to the same level as other means of cutting. The location shall be inspected to ensure no other obstructions related to the drilling and well activities are left behind on the sea floor. Page 33 of 35
9.9 Vertical Xmas tree (VXT) removal The table below describes well barrier requirements when removing a VXT. Fluid Possible to monitor primary well barrier? Primary well barrier element Secondary well barrier element Light fluid (underbalanced) Yes (downhole pressure gauge or tubing to annulus communication) Deep set mechanical bridge plug Inflow tested DHSV and drop protection device accepted if DHSV has zero leakage, or a BPV/tubing hanger plug, or a shallow set mechanical bridge plug Compensating measures Status of primary well barrier to be monitored at all times on DHPG or a-annulus pressure Heavy fluid (overbalanced) No Deep set mechanical bridge plug Yes (tubing to annulus communication) Deep set mechanical bridge plug and brine/mud above plug, or Kill pill and brine or kill mud from perforations/screen to surface a BPV/tubing hanger plug, or a shallow set mechanical bridge plug Inflow tested DHSV and drop protection device accepted if DHSV has zero leakage, or a BPV/tubing hanger plug, or a shallow set mechanical bridge plug Inflow tested DHSV as compensating measure due to not able to monitor primary barrier Fluid level or applied pressure to be monitored on A-annulus No Deep set mechanical bridge plug and brine/mud above plug Inflow tested DHSV and drop protection device accepted if DHSV has zero leakage, or a BPV/tubing hanger plug, or a shallow set mechanical bridge plug No Kill pill and brine or kill mud from perforations/screen to surface a BPV/tubing hanger plug, or a shallow set mechanical bridge plug Inflow tested DHSV as compensating measure due to not able to monitor primary well barrier Page 34 of 35
9.10 Horizontal Xmas tree removal A deep set plug shall be installed. The production tubing and production annulus shall be displaced to kill fluid. Specific gravity of the kill fluid shall give an overbalance with a safety margin at plug depth, prior to pulling the production tubing. When the tubing is removed, a shallow plug shall be installed in production casing prior to removal of the XT. Page 35 of 35