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Alaska Administrative Code (Last Updated: January 12, 2017) |
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Title 20. Miscellaneous Boards and Commissions. |
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Chapter 20.25. Alaska Oil and Gas Conservation Commission. |
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Article 20.25.2. Abandonment and Plugging. |
Section 20.25.286. Well control requirements for workstring service operations.
Latest version.
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(a) This section applies to through-tubing operations that are not subject to the requirements of 20 AAC 25.036 or 20 AAC 25.285, and that are performed with coiled tubing, small diameter drill pipe, or small diameter tubing. These operations are also subject to the requirements of 20 AAC 25.527. (b) The operator shall use a full lubricator system or open hole deployment type system. (c) The rated working pressure of the blowout prevention equipment (BOPE) and other well control equipment must exceed the maximum potential surface pressure to which it may be subjected. If an approved Application for Sundry Approvals (Form 10-403) is required under 20 AAC 25.280, the commission will specify in that approved application the working pressure that the equipment must be rated to meet or exceed. However, the rated working pressure of the annular type preventer need not exceed 5,000 psi. (d) Well control equipment must include (1) at least one positive seal manual or hydraulic valve or blind ram flanged to the wellhead or tree; (2) in rotary drilling rig operations, (A) for an operation with a maximum potential surface pressure of 5,000 psi or less, at least three preventers, including (i) one equipped with pipe rams that fit the size of drill pipe, tubing, or casing being used, except that pipe rams need not be sized to bottom-hole assemblies (BHAs) and drill collars; (ii) one with blind rams, except that a subsea BOPE assembly must have blind/shear rams in place of blind rams; and (iii) one annular type; (B) for an operation, other than a casing or liner operation, with a maximum potential surface pressure of greater than 5,000 psi, at least four preventers, including (i) two equipped with pipe rams that fit the size of the drill pipe or tubing being used, except that pipe rams need not be sized to BHAs and drill collars; (ii) one with blind rams, except that a subsea BOPE assembly must have blind/shear rams in place of blind rams; and (iii) one annular type; and (C) for a casing or liner operation with a maximum potential surface pressure of greater than 5,000 psi, at least four preventers, including (i) one equipped with pipe rams that fit the size of the drill pipe or tubing being used, except that pipe rams need not be sized to BHAs and drill collars; (ii) one equipped with pipe rams that fit the size of casing or liner being used; (iii) one with blind rams, except that a subsea BOPE assembly must have blind/shear rams in place of blind rams; and (iv) one annular type; (3) in coiled tubing unit operations, (A) for an operation with a maximum potential surface pressure of 5,000 psi or less, (i) BOPE rams providing for pipe, slip, cutting, and blinding operations on the coiled tubing in service; (ii) a high pressure pack-off, stripper, or annular type preventer; and (iii) if pressure deployment of tools is planned, a riser or lubricator sized to the BHA and providing for pressure integrity from the BOPE rams to the high pressure pack-off, stripper, or annular type preventer; and (B) for an operation with a maximum potential surface pressure of greater than 5,000 psi, (i) BOPE rams providing for pipe, slip, cutting, and blinding operations on the coiled tubing in service; (ii) two high pressure pack-offs, strippers, or annular type preventers; and (iii) if pressure deployment of tools is planned, a riser or lubricator sized to the BHA and providing for pressure integrity from the BOPE rams to the high pressure pack-off, stripper, or annular type preventer; (4) a hydraulic actuating system with (A) sufficient accumulator capacity to supply 150 percent of the volume necessary to close all BOPs, except blind rams, while maintaining a minimum pressure of 200 psi above the required precharge pressure when all BOPs, except blind rams, are closed, and all power sources are shut off; and (B) an accumulator pump system; (5) locking devices on the ram-type preventers; (6) in rotary drilling rig operations, one complete set of operable remote BOPE controls on or near the driller's station, in addition to controls on the accumulator system; (7) in coiled tubing operations, one complete set of operable remote BOPE controls on or near the operator's station and, if these controls are not in close proximity to the drilling platform floor, a second annular type preventer closing control located on the drilling platform floor; and (8) a kill line capable of being attached with flanged or hubbed connections to the BOP body, drilling spool, tree, wellhead, or other well control equipment. (e) The operator shall test the BOPE assembly as follows: (1) at least once a week, and after each repair, change, or use for well control or other equivalent purpose, or when routine use of the equipment may have compromised its effectiveness, BOP equipment must be function pressure-tested, using a non-compressible fluid, to the required working pressure specified in an approved Application for Sundry Approvals under 20 AAC 25.280 or, if that application is not required, to the maximum potential surface pressure to which they may be subjected, except that the annular type preventer need not be tested to more than 50 percent of its rated working pressure; (2) after each installation of BOPE or other well control equipment, the equipment must be pressure-tested, before wellbore entry, to the maximum potential wellhead pressure to which it may be subjected, except that when testing against the annular type preventer, pressure testing need not exceed 50 percent of the rated working pressure of the annular type preventer; (3) non-sealing equipment must be function-tested weekly, after a repair or change, and after an action that disconnects the hydraulic system lines from the BOPE, except that if the workstring is continuously in the well, function-testing must be performed as soon as possible after the workstring is pulled out of the well and the BHA clears the BOP; (4) after each well installation of the BOPE, the BOPE hydraulic connections to the rams must be visually verified before wellbore entry; (5) for each BOPE test during drilling and completion operations, variable bore rams must be function pressure-tested to the required pressure on the smallest outside diameter (OD) and largest outside diameter (OD) tubulars that may be used during that test cycle, except that variable bore rams need not be tested on BHAs and drill collars; (6) BOPE test results must be recorded as part of the daily record required by 20 AAC 25.070(1), and must be provided to the commission, in a format approved by the commission, within five days after completing the test; (7) at least 24 hours notice of each BOPE function pressure test must be provided so that a representative of the commission can witness the test; (8) the operator shall report to the commission within 24 hours any instance of BOPE use to prevent the flow of fluids from a well. (f) In a rotary drilling rig operation, the operator shall have on location a copy of the approved Application for Sundry Approvals, if that application is required under 20 AAC 25.280, and shall post on the drilling rig floor any geologic hazard information obtained while drilling the well and a copy of the operator's standing orders specifying well control procedures. In a coiled tubing operation, the operator shall post in the operator's cab a copy of the approved Application for Sundry Approvals, if that application is required under 20 AAC 25.280, any geologic hazard information obtained while drilling the well, and a copy of the operator's standing orders specifying well control procedures. If an additional or separate substructure is used in a coiled tubing operation, the operator shall post a second set of standing orders on the drilling platform floor. (g) Upon request of the operator, the commission will, in its discretion, approve a variance from the requirements of this section if the variance provides at least an equally effective means of well control.
Authorities
31.05.030