Section 20 AAC 25.036 - Secondary well control for through-tubing drilling and completion: blowout prevention equipment requirements(a) This section applies to drilling and completion operations performed through existing production tubing. These operations are also subject to the requirements of 20 AAC 25.527.(b) The operator shall submit the following information with the application for a Permit to Drill (Form 10-401) or refer in the application to that information if that information is already on file with the commission:(1) a diagram of each blowout preventer (BOP) stack and related well control equipment to be used;(2) a list of the blowout prevention equipment (BOPE) with specifications.(c) A well must be equipped with BOPE meeting the requirements of this subsection from the time that drilling penetrates beyond casing or liner until the drilled portion has been plugged or the well is completed, except if hydraulic communication to the open hole section has been isolated. The following provisions apply to BOPE and other well control equipment:(1) in rotary drilling rig operations,(A) for an operation with a maximum potential surface pressure of 5,000 psi or less, BOPE must have 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;(iii) one annular type; and(B) for an operation other than a casing or liner operation, with a maximum potential surface pressure of greater than 5,000 psi, BOPE must have 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, BOPE must have 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(2) in coiled tubing unit operations, the well control equipment must include (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, tubing, liner, or casing 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, tubing, liner, or casing 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 being 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, tubing, liner, or casing 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;(3) 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; the commission will specify in the approved Permit to Drill the working pressure that the equipment must be rated to meet or exceed; however, the rated working pressure of an annular type preventer need not exceed 5,000 psi, unless the commission requires a higher rated working pressure as the commission considers necessary to maintain well control; if the maximum potential surface pressure exceeds the rated working pressure of the annular type preventer, the operator shall submit with the application for a Permit to Drill a well control procedure that indicates how the annular type preventer will be used and the pressure limitation that will be applied during each mode of pressure control;(4) a BOPE assembly must include(A) a hydraulic actuating system with (i) sufficient accumulator capacity to supply 150 percent of the volume necessary to close all BOPs, except blind rams, and to open the remotely controlled hydraulic valve 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(ii) an accumulator pump system consisting of one 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;(B) locking devices on the ram-type preventers;(C) a fire wall to shield accumulators and primary controls;(D) 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;(E) 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;(F) a kill line and a choke line each connected to a flanged or hubbed outlet on a drilling spool, the BOP body, or the tree, with two full-opening valves on each outlet, conforming to the following specifications:(i) the outlets and valves must be at least two inches in nominal diameter;(ii) the outer valve on the choke side must be a remotely controlled hydraulic valve;(iii) the inner valve on both the choke and kill sides may not normally be used for opening or closing on flowing fluid;(G) for open hole deployment, an annular type preventer, unless a lubricator of sufficient length to enclose the entire BHA below a high pressure sealing element is used; and(H) for conventional open loop fluid process drilling operations, a choke manifold equipped with (i) two or more adjustable chokes, one of which must be hydraulic and remotely controlled from near the driller's or operator's station if the operation has a maximum potential surface pressure of greater than 3,000 psi;(ii) a line at least two inches in nominal diameter downstream of each choke;(iii) immediately upstream of each choke, at least one full-opening valve for an operation with a maximum potential surface pressure of 5,000 psi or less, or at least two full-opening valves for an operation with a maximum potential surface pressure of greater than 5,000 psi; and(iv) a bypass line at least two inches in nominal diameter with at least one full-opening valve immediately upstream of each choke for an operation with a maximum potential surface pressure of 5,000 psi or less, or with at least two full-opening valves immediately upstream of each choke for an operation with a maximum potential surface pressure of greater than 5,000 psi;(5) in an underbalanced drilling operation, well control equipment must have bi-directional slip capabilities;(6) the rated working pressure of the wellhead assembly and of all valves, pipes, rotary hoses, and other fittings, including all sections of the choke manifold that are subject to full wellhead pressure, must equal or exceed the required working pressure specified for the BOPE in the approved Permit to Drill, 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;(7) for lubricated drilling operations or operations below a normally closed annular type preventer, the choke line may be used for drilling returns;(8) at least one positive seal manual or hydraulic valve or BOPE blind ram, one set of BOPE pipe rams, and, if used, the drilling spool must be flanged to the wellhead or tree;(9) connections directly to the BOPE, other than connections described in (8) of this subsection, must be flanged or hubbed, except that suitably pressure-rated quick connects may be used if a positive seal manual valve, hydraulic valve, or BOPE blind ram and an annular type preventer or sealing ram are flanged to the wellhead or tree below the quick connection;(10) kill and choke lines must(A) 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;(B) be as straight as practical;(C) if constructed of rigid steel pipe, use targeted turns where the bend radius is less than 20 times the inside diameter of the pipe;(D) be secured to prevent excessive whip or vibration;(E) be sized to prevent excessive erosion or fluid friction; and(F) be assembled without hammer unions or internally clamped swivel joints, except that hammer unions and internally clamped swivel joints may be used on the kill line upstream of the valves that are flanged to the wellhead or tree.(d) A BOPE assembly must be tested as follows:(1) when installed, repaired, or changed on a development or service well and at time intervals not to exceed each 14 days thereafter, BOPE, including kelly valves, emergency valves, and choke manifolds, must be function pressure-tested to the required working pressure specified in the approved Permit to Drill, using a non-compressible fluid, except that an annular type preventer need not be tested to more than 50 percent of its rated working pressure; however, the commission will require that the BOPE be function pressure-tested weekly, if the commission determines that a weekly BOPE pressure test interval is indicated by a particular drilling rig's BOPE performance;(2) when installed, repaired, or changed on an exploratory or stratigraphic test well and at least once a week thereafter, BOPE, including kelly valves, emergency valves, and choke manifolds, must be function pressure-tested to the required working pressure specified in the approved Permit to Drill, using a non-compressible fluid, except that an annular type preventer need not be tested to more than 50 percent of its rated working pressure;(3) other well control equipment must be pressure-tested to the maximum potential wellhead pressure after each installation of the well control equipment and before wellbore entry, except that an annular type preventer need not be tested to more than 50 percent of its rated working pressure;(4) 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, to the required working pressure specified in the approved Permit to Drill, using a non-compressible fluid, except that an annular type preventer need not be tested to more than 50 percent of its rated working pressure;(5) BOP ram and annular components except blind rams must be function-tested weekly, and all BOP ram and annular components must be function-tested after an action that disconnects the hydraulic system lines from the BOPE, except that if the workstring is continuously in the well, function-testing of blind rams must be performed as soon as possible after the workstring is pulled out of the well and the BHA clears the BOP;(6) 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;(7) 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;(8) at least 24 hours notice of each BOPE function pressure test must be provided to the commission so that a representative of the commission can witness the test.(e) In a rotary drilling rig operation, the operator shall have on location a copy of the approved Permit to Drill and shall post on the drilling rig floor the drilling hazard information required by 20 AAC 25.005(c) (4) 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 Permit to Drill, the drilling hazard information required by 20 AAC 25.005(c) (4), and a copy of the 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.(f) 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.(g) The operator shall report to the commission within 24 hours any instance of BOPE use to prevent the flow of fluids from a well.Eff. 11/7/99, Register 152; am 10/24/2004, Register 172; am 12/28/2006, Register 180