(a) Requirements. Blowout preventer (BOP) and related equipment (BOPE) shall be installed, used, maintained, and tested in a manner necessary to assure well control and shall be in place and operational prior to drilling the surface casing shoe unless otherwise approved by the APD. Commencement of drilling without the approved BOPE installed, unless otherwise approved, shall subject the operator to immediate assessment under 43 CFR 3163.1(b)(1). The BOP and related control equipment shall be suitable for operations in those areas which are subject to sub-freezing conditions. The BOPE shall be based on known or anticipated sub-surface pressures, geologic conditions, accepted engineering practice, and surface environment. Item number 7 of the 8 point plan in the APD specifically addresses expected pressures. The working pressure of all BOPE shall exceed the anticipated surface pressure to which it may be subjected, assuming a partially evacuated hole with a pressure gradient of 0.22 psi/ft.

(b) Violation classifications. The gravity of the violation for many of the well control minimum standards listed in paragraphs (b)(1) through (9) of this section are shown as minor. However, very short abatement periods in this subpart are often specified in recognition that by continuing to drill, the violation which was originally determined to be of a minor nature may cause or threaten immediate, substantial, and adverse impact on public health and safety, the environment, production accountability, or royalty income, which would require it reclassification as a major violation.

(1) Minimum standards and enforcement provisions for well control equipment. (i) A well control device shall be installed at the surface that is capable of complete closure of the well bore. This device shall be closed whenever the well is unattended.

(ii) For 2M system:

(A) Annular preventer, double ram, or two rams with one being blind and one being a pipe ram (major);

(B) Kill line (2 inch minimum);

(C) 1 kill line valve (2 inch minimum);

(D) 1 choke line valve;

(E) 2 chokes (refer to diagram in appendix A to this subpart);

(F) Upper kelly cock valve with handle available;

(G) Safety valve and subs to fit all drill strings in use;

(H) Pressure gauge on choke manifold;

(I) 2 inch minimum choke line; and

(J) Fill-up line above the uppermost preventer.

(iii) For 3M system:

(A) Annular preventers (major);

(B) Double ram with blind rams and pipe rams (major);

(C) Drilling spool, or blowout preventer with 2 side outlets (choke side shall be a 3-inch minimum diameter, kill side shall be at least 2-inch diameter) (major);

(D) Kill line (2 inch minimum);

(E) A minimum of 2 choke line valves (3 inch minimum) (major);

(F) 3 inch diameter choke line;

(G) 2 kill line valves, one of which shall be a check valve (2 inch minimum) (major);

(H) 2 chokes (refer to diagram in appendix A to this subpart);

(I) Pressure gauge on choke manifold;

(J) Upper kelly cock valve with handle available;

(K) Safety valve and subs to fit all drill string connections in use;

(L) All BOPE connections subjected to well pressure shall be flanged, welded, or clamped (major); and

(M) Fill-up line above the uppermost preventer.

(iv) For 5M system:

(A) Annular preventer (major);

(B) Pipe ram, blind ram, and, if conditions warrant, as specified by the authorized officer, another pipe ram shall also be required (major);

(C) A second pipe ram preventer or variable bore pipe ram preventer shall be used with a tapered drill string;

(D) Drilling spool, or blowout preventer with 2 side outlets (choke side shall be a 3-inch minimum diameter, kill side shall be at least 2-inch diameter) (major);

(E) 3 inch diameter choke line;

(F) 2 choke line valves (3 inch minimum) (major);

(G) Kill line (2 inch minimum);

(H) 2 chokes with 1 remotely controlled from rig floor (refer to diagram in appendix A to this subpart);

(I) 2 kill line valves and a check valve (2 inch minimum) (major);

(J) Upper kelly cock valve with a handle available;

(K) When the expected pressures approach working pressure of the system, 1 remote kill line tested to stack pressure (which shall run to the outer edge of the substructure and be unobstructed);

(L) Lower kelly cock valve with handle available;

(M) Safety valve(s) and subs to fit all drill string connections in use;

(N) Inside BOP or float sub available;

(O) Pressure gauge on choke manifold;

(P) All BOPE connections subjected to well pressure shall be flanged, welded, or clamped (major); and

(Q) Fill-up line above the uppermost preventer.

(v) For 10M & 15M system:

(A) Annular preventer (major);

(B) 2 pipe rams (major);

(C) Blind rams (major);

(D) Drilling spool, or blowout preventer with 2 side outlets (choke side shall be a 3-inch minimum diameter, kill side shall be at least 2-inch diameter) (major):

(E) 3 inch choke line (major);

(F) 2 kill line valves (2 inch minimum) and check valve (major):

(G) Remote kill line (2 inch minimum) shall run to the outer edge of the substructure and be unobstructed;

(H) Manual and hydraulic choke line valves (3 inch minimum) (major);

(I) 3 chokes, 1 being remotely controlled (refer to diagram in appendix A to this subpart);

(J) Pressure gauge on choke manifold;

(K) Upper kelly cock valve with handle available;

(L) Lower kelly cock valve with handle available;

(M) Safety valves and subs to fit all drill string connections in use;

(N) Inside BOP or float sub available;

(O) Wear ring in casing head;

(P) All BOPE connections subjected to well pressure shall be flanged, welded, or clamped (major); and

(Q) Fill-up line installed above the uppermost preventer.

(vi) If repair or replacement of the BOPE is required after testing, this work shall be performed prior to drilling out the casing shoe.

(vii) When the BOPE cannot function to secure the hole, the hole shall be secured using cement, retrievable packer or a bridge plug packer, bridge plug, or other acceptable approved method to assure safe well conditions.

(2) Minimum standards and enforcement provisions for choke manifold equipment. (i) All choke lines shall be straight lines unless turns use tee blocks or are targeted with running tees, and shall be anchored to prevent whip and reduce vibration.

(ii) Choke manifold equipment configuration shall be functionally equivalent to the appropriate example diagram shown in appendix A of this subpart. The configuration of the chokes may vary.

(iii) All valves (except chokes) in the kill line, choke manifold, and choke line shall be a type that does not restrict the flow (full opening) and that allows a straight through flow (same enforcement as paragraph (b)(2)(ii) of this section).

(iv) Pressure gauges in the well control system shall be a type designed for drilling fluid service (same enforcement as paragraph (b)(2)(ii) of this section).

(3) Minimum standards and enforcement provisions for pressure accumulator system. (i) 2M system—accumulator shall have sufficient capacity to close all BOP's and retain 200 psi above precharge. Nitrogen bottles that meet manufacturer's specifications may be used as the backup to the required independent power source.

(ii) 3M system—accumulator shall have sufficient capacity to open the hydraulically controlled choke line valve (if so equipped), close all rams plus the annual preventer, and retain a minimum of 200 psi above precharge on the closing manifold without the use of the closing unit pumps. This is a minimum requirement. The fluid reservoir capacity shall be double the usable fluid volume of the accumulator system capacity and the fluid level of the reservoir shall be maintained at the manufacturer's recommendations. The 3M system shall have 2 independent power sources to close the preventers. Nitrogen bottles (3 minimum) may be 1 of the independent power sources and, if so, shall maintain a charge equal to the manufacturer's specifications.

(iii) 5M and higher system—accumulator shall have sufficient capacity to open the hydraulically controlled gate valve (if so equipped) and close all rams plus the annular preventer (for 3 ram systems add a 50 percent safety factor to compensate for any fluid loss in the control system or preventers) and retain a minimum pressure of 200 psi above precharge on the closing manifold without use of the closing unit pumps. The fluid reservoir capacity shall be double the usable fluid volume of the accumulator system capacity and the fluid level of the reservoir shall be maintained at the manufacturer's recommendations. Two independent sources of power shall be available for powering the closing unit pumps. Sufficient nitrogen bottles are suitable as a backup power source only, and shall be recharged when the pressure falls below manufacturer's specifications.

(4) Minimum standards and enforcement provisions for accumulator precharge pressure test. This test shall be conducted prior to connecting the closing unit to the BOP stack and at least once every 6 months. The accumulator pressure shall be corrected if the measured precharge pressure is found to be above or below the maximum or minimum limit specified in table 13 to this paragraph (b)(4) (only nitrogen gas may be used to precharge):

(5) Minimum standards and enforcement provisions for power availability. Power for the closing unit pumps shall be available to the unit at all times so that the pumps shall automatically start when the closing unit manifold pressure has decreased to a pre-set level.

(6) Minimum standards and enforcement provisions for accumulator pump capacity. Each BOP closing unit shall be equipped with sufficient number and sizes of pumps so that, with the accumulator system isolated from service, the pumps shall be capable of opening the hydraulically operated gate valve (if so equipped), plus closing the annular preventer on the smallest size drill pipe to be used within 2 minutes, and obtain a minimum of 200 psi above specified accumulator precharge pressure.

(7) Minimum standards and enforcement provisions for locking devices. A manual locking device (i.e., hand wheels) or automatic locking devices shall be installed on all systems of 2M or greater. A valve shall be installed in the closing line as close as possible to the annular preventer to act as a locking device. This valve shall be maintained in the open position and shall be closed only when the power source for the accumulator system is inoperative.

(8) Minimum standards and enforcement provisions for remote controls. Remote controls shall be readily accessible to the driller. Remote controls for all 3M or greater systems shall be capable of closing all preventers. Remote controls for 5M or greater systems shall be capable of both opening and closing all preventers. Master controls shall be at the accumulator and shall be capable of opening and closing all preventers and the choke line valve (if so equipped). No remote control for a 2M system is required.

(9) Minimum standards and enforcement provisions for well control equipment testing. (i) Perform all tests described in paragraphs (b)(9)(ii) through (x) of this section using clear water or an appropriate clear liquid for subfreezing temperatures with a viscosity similar to water.

(ii) Ram type preventers and associated equipment shall be tested to approved (see § 3172.4(a)) stack working pressure if isolated by test plug or to 70 percent of internal yield pressure of casing if BOP stack is not isolated from casing. Pressure shall be maintained for at least 10 minutes or until requirements of test are met, whichever is longer. If a test plug is utilized, no bleed-off of pressure is acceptable. For a test not utilizing a test plug, if a decline in pressure of more than 10 percent in 30 minutes occurs, the test shall be considered to have failed. Valve on casing head below test plug shall be open during test of BOP stack.

(iii) Annular type preventers shall be tested to 50 percent of rated working pressure. Pressure shall be maintained at least 10 minutes or until provisions of test are met, whichever is longer.

(iv) As a minimum, the test in paragraphs (b)(9)(ii) and (iii) of this section shall be performed:

(A) When initially installed;

(B) Whenever any seal subject to test pressure is broken;

(C) Following related repairs; and

(D) At 30-day intervals.

(v) Valves shall be tested from working pressure side during BOPE tests with all down stream valves open.

(vi) When testing the kill line valve(s), the check valve shall be held open or the ball removed.

(vii) Annular preventers shall be functionally operated at least weekly.

(viii) Pipe and blind rams shall be activated each trip, however, this function need not be performed more than once a day.

(ix) A BOPE pit level drill shall be conducted weekly for each drilling crew.

(x) Pressure tests shall apply to all related well control equipment.

(xi) All of the tests described in paragraphs (b)(9)(ii) through (x) of this section and/or drills shall be recorded in the drilling log.

[81 FR 81421, Nov. 17, 2016, as amended at 88 FR 74890, Nov. 1, 2023]