Alaska Administrative Code › Title 20 - Miscellaneous Boards and Commissions › Chapter 25 - Alaska Oil and Gas Conservation Commission › Article 3 - Production Practices › 20 AAC 25.286 - Well control requirements for workstring service operations

Current through May 31, 2024
(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.