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Statutory Authority:
Authority: AS 31.05.030
20 AAC 25.033. Primary well control for drilling: drilling fluid program and drilling fluid system.
(a) A drilling operation must be equipped with a drilling fluid system meeting the requirements of this section, unless the commission determines that a drilling fluid system is not necessary for primary well control. The operator shall submit with an application for a Permit to Drill (Form 10-401) a proposed drilling fluid program and a diagram with a list of equipment for a drilling fluid system designed to prevent the loss of primary well control. The drilling fluid system must be designed to maintain the wellbore in overbalanced condition except as otherwise provided under (i) of this section. A drilling operation is also subject to the requirements of 20 AAC 25.527 .
(b) A drilling fluid program and drilling fluid system intended to maintain the wellbore in overbalanced condition must be designed to provide and maintain
(1) a drilling fluid
(A) of sufficient density to overbalance the pressure of uncased formations penetrated; and
(B) with rheological properties designed to
(i) minimize the potential of a hydrostatic pressure surge or swab when the drilling assembly is run into or pulled out of the wellbore; and
(ii) enhance the drop-out of solids and the escape of entrained gas; and
(2) a volumetric capacity for drilling fluid reserves adequate for the volume of the wellbore, based on known or anticipated drilling conditions to be encountered, rig storage capacity, weather conditions, and estimated time for delivery.
(c) A drilling fluid system intended to maintain the wellbore in overbalanced condition must include
(1) a recording drilling fluid pit level indicator with both visual and audible warning devices located in the immediate area of the driller's station;
(2) a drilling fluid measuring system or trip tank for accurately determining drilling fluid volumes required to fill the wellbore on trips;
(3) a drilling fluid flow sensor with a readout convenient to the driller's station to enable the operator to determine whether drilling fluid returns equal drilling fluid pump discharge rates;
(4) equipment to keep the drilling mud conditioned as appropriate for the drilling operation being conducted; and
(5) methane and hydrogen sulfide detection equipment as required by 20 AAC 25.066 .
(d) Drilling fluid testing equipment must be on the drill site at all times. Tests to determine drilling fluid density and viscosity must be performed once each tour, or more frequently if conditions warrant.
(e) To ensure that primary well control is effectively maintained, the following practices must be employed in rotary drilling rig operations when tripping the drilling assembly out of the wellbore:
(1) the drilling fluid within the wellbore must be in balance and conditioned to maintain drilling fluid properties within close tolerance to the properties necessary for well control;
(2) the flow nipple or trip tank must be visually observed to ensure that there is no indication of formation fluid influx;
(3) the wellbore must be kept full of drilling fluid at all times;
(4) the annulus must be filled with fluid
(A) each time that five stands of drill pipe have been removed from the wellbore; and
(B) more frequently than required in (A) of this paragraph, if necessary to prevent the hydrostatic pressure from dropping by 75 psi or more;
(5) the volume of drilling fluid required to keep the wellbore full while tripping the drilling assembly out of the wellbore must be measured and recorded on the daily drilling report or trip sheet.
(f) Additional requirements that apply to exploratory and stratigraphic test wells are as follows:
(1) the operator shall include with an application for a Permit to Drill a tabulation that sets out the depths of predicted abnormally geo-pressured strata;
(2) if the operator has geophysical data from the area, the operator shall include with an application for a Permit to Drill a seismic velocity analysis constrained by germane well data to predict the potential of encountering abnormally geo-pressured strata, with the analysis displayed by plotting interval transit time versus depth; as the commission considers necessary to evaluate the potential for a well control problem, the commission will require a review from the operator of the velocity analysis and of the plot of interval transit time versus depth;
(3) if the operator does not have geophysical data from the area, the operator shall include with an application for a Permit to Drill an analysis of germane well data to predict the potential of encountering abnormally geo-pressured strata;
(4) a drilling fluid monitoring unit must be used and continuously observed during drilling rig operations, including tripping, to monitor and record
(A) gas entrained in the drilling fluid;
(B) drilling fluid density;
(C) drilling fluid salinity;
(D) the rate of penetration; and
(E) hydrogen sulfide, as required by 20 AAC 25.065 ;
(5) means for communication between the drilling fluid monitoring unit and the drill rig floor must be installed and maintained in working condition while open hole operations are taking place, and drill rig floor personnel must be notified immediately if excursions from normal trends occur for any of the parameters set out in (4) of this subsection.
(g) If drilling an exploratory or stratigraphic test well, or if drilling a development or service well while known hydrocarbon-bearing strata are exposed to open hole, the operator shall take a drilling fluid return sample and test the sample to determine density just before tripping the drill pipe. Density test results must be recorded as required by 20 AAC 25.070 (1). If the density is less than that of the drilling fluid being pumped down the drilling assembly, the drilling fluid must be circulated and conditioned until a close tolerance of the properties of the return drilling fluid with the input drilling fluid is achieved.
(h) If formation competence at the structural casing setting depth is not adequate to permit circulation of drilling fluids while drilling the conductor hole, a program that provides for safety in that drilling operation must be described and submitted to the commission for approval. This program must be supported by pertinent information including seismic and geologic data, water depth, drilling fluid hydrostatic pressure, and a contingency plan for moving off location.
(i) The commission will approve underbalanced drilling operations and associated equipment changes if the commission determines that underbalanced drilling operations can be performed without loss of well control. A request for underbalanced drilling must include a description of all equipment and procedures to ensure proper containment of formation and return fluids.
(j) Upon request by the operator, the commission will, in its discretion, approve a waiver of the requirements of (c) ' (g) of this section if the alternative drilling fluid program and drilling fluid system meet the design criteria of (b) of this section and the corresponding equipment and procedures are at least equally effective in preventing the loss of primary well control.
(Eff. 4/2/86, Register 97; am 11/7/99, Register 152)
Statutory Authority:
Authority: AS 31.05.030
20 AAC 25.035. Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements.
(a) This section applies to drilling and completion operations other than those covered by 20 AAC 25.036 . 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 the blowout preventer (BOP) stack or diverter and related equipment for each proposed casing installation;
(2) a list of the blowout prevention equipment (BOPE) and if applicable, diverter equipment with specifications.
(c) Except as provided in (d) and (h) of this section, a high capacity flow diverter system must be installed to provide safety for personnel and equipment before rotary rig drilling is performed below a well's structural or conductor casing, unless the casing is equipped with BOPE conforming with (e) of this section. The following provisions apply to a diverter system:
(1) the diverter system must consist of a remotely operated annular pack-off device, a full-opening vent line valve, and a diverter vent line with a diameter
(A) of at least 16 inches, unless a smaller diameter is approved by the commission to account for smaller hole size, geological conditions, rig layout, or surface facility constraints; and
(B) at least as large as the diameter of the hole to be drilled, unless a pilot hole with a diameter no larger than that of the vent line is drilled first; the commission will waive the requirement of this paragraph if the operator demonstrates, based on drilling experience in the near vicinity, that drilling a pilot hole would not be necessary for safety;
(2) the diverter system must be assembled as follows:
(A) the diverter vent line outlet must be located below the annular pack-off, either as an integral part of the annular pack-off device or as a vent-line outlet spool immediately below it;
(B) the actuating mechanism for the vent line valve must be integrated with the actuating mechanism for the annular pack-off device in a fail-safe manner so that the vent line valve automatically opens before full closure of the annular pack-off;
(C) the vent line must extend to a point at least 75 feet
(i) away from a potential source of ignition; and
(ii) beyond the drill rig substructure, or to a point within the reserve pit and at least 50 feet beyond the drill rig substructure;
(D) the vent line must be as straight as possible, secured to prevent movement, and designed to avoid freeze-up;
(E) the vent line may be secured to the rig and with portable cradle supports, but may not be attached to flowlines, cable trays, or other processing equipment;
(F) all turns with a bend radius less than 20 times the inside diameter of the vent line must be targeted;
(G) all valves must be full-opening;
(3) a clearly marked 'warning zone' must be established on each side and ahead of the vent line tip, and the following restrictions must be in effect within the warning zone, beginning with the function test of the diverter system immediately before drilling operations begin and ending with diverter system rig-down:
(A) a prohibition on vehicle parking;
(B) a prohibition on ignition sources or running equipment;
(C) a prohibition on staged equipment or materials;
(D) the restriction of traffic to essential foot or vehicle traffic only;
(4) the commission will, in its discretion, inspect the diverter system for compliance with the requirements of this subsection and require the operator to test the system to ensure proper operation.
(d) If the formation competence at the structural casing setting depth is not adequate to permit use of a diverter system while drilling the conductor hole, a program that provides for safety in that drilling operation must be described and submitted to the commission for approval. This program must be supported by pertinent information including seismic and geologic data, water depth, drilling fluid hydrostatic pressure, and a contingency plan for moving off location.
(e) A well must be equipped with BOPE meeting the requirements of this subsection from the time that open hole drilling operations begin below the surface casing until the drilled portion has been plugged or the well is completed, except if hydraulic communication to the open hole section is 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 3,000 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; and
(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 3,000 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;
(C) for a casing or liner operation with a maximum potential surface pressure of greater than 3,000 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
(iv) one annular type;
(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 tubing, liner, or casing being used, except that pipe rams need not be sized to BHAs and drill collars; and
(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 tubing being used, except that pipe rams need not be sized to BHAs and drill collars;
(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 the 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 what pressure limitations 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 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;
(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 or on the BOP body with two full-opening valves on each outlet, conforming to the following specifications:
(i) 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;
(ii) each valve must be sized at least equal to the required size of the outlet to which it is attached;
(iii) the outer valve on the choke side must be a remotely controlled hydraulic valve;
(iv) the inner valve on both the choke and kill sides may not normally be used for opening or closing on flowing fluid;
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(G) in rotary drilling rig operations, a fill-up line above the uppermost BOP; and
(H) 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 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 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
(iv) a bypass line, at least the diameter of the choke line, 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;
(5) 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;
(6) 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, unless the commission determines that those joints do not compromise maintenance of well control;
(7) for lubricated drilling operations or operations below a normally closed annular type preventer, the choke line may be used for drilling returns;
(8) connections attached directly to the wellhead, tree, or BOPE must be flanged or hubbed;
(9) for rotary drilling rig operations, auxiliary well control equipment must include
(A) a kelly cock valve installed below the swivel and, at the bottom of the kelly, a full-opening lower kelly valve of a design that allows it to be run through the BOP stack, with a properly sized wrench for each valve stored in a conspicuous location readily accessible to the drilling crew; and
(B) an inside BOP and a full-opening drilling assembly safety valve in the open position on the drill rig floor to fit all connections that are in the drilling assembly;
(10) the BOPE must be tested as follows:
(A) 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;
(B) 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;
(C) 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;
(D) 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;
(E) 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;
(F) 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;
(G) 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;
(H) at least 24 hours notice of each BOPE function pressure test must be provided to the commission so that a commission representative can witness the test;
(11) 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 consultation with the drilling rig supervisor, the commission will, in its discretion, require drills simulating well control problems. The commission will, in its discretion, include in the drills any combination of raising or lowering the pit level indicator, advancing or retarding the flow rate indicator, or actuating the gas detectors.
(g) 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.
(h) Upon request of the operator, the commission will, in its discretion, approve a variance
(1) from the BOPE requirements in (e) of this section if the variance provides at least an equally effective means of well control; and
(2) from the diverter system requirements in (c) of this section if the variance provides at least equally effective means of diverting flow away from the drill rig or if drilling experience in the near vicinity indicates that a diverter system is not necessary.
(Eff. 4/13/80, Register 74; am 2/22/81, Register 77; am 4/2/86, Register 97; am 11/7/99, Register 152; am 10/24/, Register 172; am 12/28/, Register 180; am 7/12/, Register 183; am 7/25/, Register 235)
Statutory Authority:
Authority: AS 31.05.030
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
(iv) one annular type;
(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.
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