Section 20 AAC 25.285 - Secondary well control for tubing workover operations: blowout prevention equipment requirements(a) This section applies to workover operations performed with the tree removed. These operations are also subject to the requirements of 20 AAC 25.527.(b) The rated working pressure of the 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.(c) Well control equipment must include (1) at least one positive seal manual or hydraulic valve or BOPE blind ram and one set of BOPE pipe rams flanged to the wellhead;(2) in rotary drilling rig operations,(A) for an operation with a maximum potential surface pressure of 3,000 psi or less, at least three preventers, including(i) one equipped with pipe rams that fit the size of drill pipe, tubing, liner 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(B) for an operation, other than a casing or liner operation, with a maximum potential surface pressure of greater than 3,000 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 3,000 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(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;(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(iv) at least one preventer equipped with pipe rams that fit the size of the tubing, liner, or casing being used, except that pipe rams need not be sized to BHAs and drill collars;(B) for an operation, other than a casing or liner 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;(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(iv) at least two preventers equipped with pipe rams that fit the size of the tubing used, except that pipe rams need not be sized to BHAs and drill collars; and(C) for a casing or liner 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;(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;(iv) at least one preventer equipped with pipe rams that fit the size of the tubing being used, except that pipe rams need not be sized to BHAs and drill collars; and(v) at least one preventer equipped with pipe rams that fit the size of casing or liner being used;(4) if a tapered string is used, either an additional set of rams for each size of pipe being run or a variable ram, except if small diameter tubulars are used to perform a clean-out operation through a production packer or to clean out a liner where the casing has been top set;(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;(8) 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 consisting of two or more pumps with independent primary and secondary power sources and an accumulator backup system having sufficient capacity to close all BOPs and to hold them closed;(9) a kill line and a choke line each connected to a flanged or hubbed outlet on a drilling spool or on the BOP body with two full-opening valves on each outlet, conforming to the following specifications: (A) the outlets must be at least two inches in nominal diameter, except that for rotary drilling rig operations, if the operation has a maximum potential surface pressure of greater than 3,000 psi, the nominal diameter of the choke outlets must be at least three inches;(B) each valve must be sized at least equal to the required size of the outlet to which it is attached;(C) the outer valve on the choke side must be a remotely controlled hydraulic valve;(D) the inner valve on both the choke and kill sides may not normally be used for opening or closing on flowing fluid; and(10) a choke manifold equipped with(A) two or more adjustable chokes, one of which must be hydraulic and remotely controlled from near the driller's station if the operation has a maximum potential surface pressure of greater than 3,000 psi;(B) a line at least two inches in nominal diameter downstream of each choke;(C) immediately upstream of each choke, at least one full-opening valve for an operation with a maximum potential surface pressure of 3,000 psi or less, or at least two full-opening valves for an operation with a maximum potential surface pressure of greater than 3,000 psi; and(D) a bypass line, at least two inches in nominal diameter, with at least one full-opening valve for an operation with a maximum potential surface pressure of 3,000 psi or less, or at least two full-opening valves for an operation with a maximum potential surface pressure of greater than 3,000 psi.(d) The rated working pressure of valves, pipes, rotary hoses, and other fittings, including all sections of the choke manifold that are subject to full wellhead pressure, must exceed the maximum potential surface pressure to which they may be subjected and may not be less than the required working pressure specified for the BOPE in an approved Application for Sundry Approvals, if any, under 20 AAC 25.280, except that the rated working pressure of lines downstream of the choke need not exceed 50 percent of the required working pressure of the BOPE.(e) Kill and choke lines must (1) be constructed of rigid steel pipe, fire-resistant rotary hose, or other conduit that has been approved by the commission as capable of withstanding the temperature and pressure of an ignited uncontrolled release;(2) be as straight as practical;(3) if constructed of rigid steel pipe, use targeted turns where the bend radius is less than 20 times the inside diameter of the pipe;(4) be secured to prevent excessive whip or vibration;(5) be sized to prevent excessive erosion or fluid friction; and(6) be assembled without hammer unions or internally clamped swivel joints, unless the commission determines that those joints do not compromise the maintenance of well control.(f) The BOPE must be tested as follows: (1) when installed, repaired, or changed, and at least once a week thereafter, BOPE, including emergency valves and choke manifolds, 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 the BOPE may be subjected, except that an annular type preventer need not be tested to more than 50 percent of its rated working pressure;(2) if any BOP equipment components have been used for well control or other equivalent purpose, or when routine use of the equipment may have compromised its effectiveness, the components used must be function pressure-tested before the next wellbore entry, 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 that equipment may be subjected, except that an annular type preventer need not be tested to more than 50 percent of its rated working pressure;(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) 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;(5) after they are installed in the BOP stack, the rams for casing or liner must be function pressure-tested to the required pressure before running casing or liner;(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.(g) 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.(h) 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 ensuring well control.Eff. 4/2/86, Register 97; am 11/7/99, Register 152; am 12/28/2006, Register 180; am 7/12/2007, Register 183