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shall be recemented, repaired, or an additional casing string run and the casing tested again. The above procedures shall be repeated until a satisfactory test is obtained. The time, conditions of testing, and results of all casing pressure tests shall be recorded in the driller's report.
(b) After cementing any string of casing other than structural, drilling shall not be resumed until there has been a timelapse of at least 8 hours under pressure for the conductor casing string or 12 hours under pressure for all other casing strings. Cement is considered under pressure if one or more float valves are shown to be holding the cement in place or when other means of holding pressure are used.
§ 250.265 Blowout preventer systems and system components.
(a) General. The blowout preventer (BOP) systems and system components shall be designed, installed, used, maintained, and tested to assure well control.
(b) BOP stacks. The BOP stacks shall consist of an annular preventer and the number of ram-type preventers as specified under paragraphs (e) and (f) of this section. The pipe rams shall be of proper size to fit the drill pipe in use.
(c) Working pressure. The workingpressure rating of any BOP shall exceed the surface pressure to which it may be anticipated to be subjected.
(d) BOP equipment. All BOP systems shall be equipped and provided with the following:
(1) An accumulator system that provides sufficient capacity to supply 1.5 times the volume necessary to close and hold closed all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure, without assistance from a charging system. After February 14, 1992, accumulator regulators supplied by rig air, which do not have a secondary source of pneumatic supply, shall be equipped with manual overrides or other devices alternately provided to ensure capability of hydraulic operations if rig air is lost.
(2) An automatic backup to the accumulator system. The backup system
shall be supplied by a power source independent from the power source to the primary accumulator system. The automatic backup system shall possess sufficient capability to close the BOP and hold it closed.
(3) At least one operable remote BOP control station in addition to the one on the drilling floor. This control station shall be in a readily accessible location away from the drilling floor.
(4) A drilling spool with side outlets, if side outlets are not provided in the body of the BOP stack, to provide for separate kill and choke lines.
(5) A choke line and a kill line each equipped with two full-opening valves. At least one of the valves on the choke line and one valve on the kill line shall be remotely controlled, except that a check valve may be installed on the kill line in lieu of the remotely controlled valve, provided that two readily accessible manual valves are in place and the check valve is placed between the manual valve and the pump.
(6) A fill-up line above the uppermost preventer.
(7) A choke manifold designed with consideration of anticipated pressures to which it may be subjected, method of well control to be employed, surrounding environment, and corrosiveness, volume, and abrasiveness of fluids. The choke manifold shall also meet the following requirements:
(i) Manifold and choke equipment subject to well and/or pump pressure shall have a rated working pressure at least as great as the rated working pressure of the ram-type BOP's or as otherwise approved by the District Supervisor;
(ii) All components of the choke manifold system shall be protected from freezing by heating, draining, or filling with proper fluids; and
(iii) When buffer tanks are installed downstream of the choke assemblies for the purpose of manifolding the bleed lines together, isolation valves shall be installed on each line.
(8) Valves, pipes, flexible steel hoses, and other fittings upstream of, and including, the choke manifold with a pressure rating at least as great as the rated working pressure of the ramtype BOP's unless otherwise approved by the District Supervisor.
(9) A wellhead assembly with a rated working pressure that exceeds the pressure to which it might be subjected.
(10) The following system components:
(i) A kelly cock (an essentially fullopening valve) installed below the swivel and a similar valve of such design that it can be run through the BOP stack installed at the bottom of the kelly. A wrench to fit each valve shall be stored in a location readily accessible to the drilling crew;
(ii) An inside BOP and an essentially full-opening, drill-string safety valve in the open position on the rig floor at all times while drilling operations are being conducted. These valves shall be maintained on the rig floor to fit all
connections that are in the drill string. A wrench to fit the drill-string safety valve shall be stored in a location readily accessible to the drilling crew;
(iii) A safety valve available on the rig floor assembled with the proper connection to fit the casing string being run in the hole; and
(iv) Locking devices installed on the ram-type preventers.
(e) BOP requirements. Prior to drilling below cap rock casing, a BOP system shall be installed consisting of at least three remote-controlled, hydraulically operated BOP's including at least one equipped with pipe rams, one with blind rams, and one annular type.
(f) Tapered drill-string operations. Prior to commencing tapered drillstring operations, the BOP stack shall be equipped with conventional and/or variable-bore pipe rams to provide either of the following:
(1) One set of variable bore rams capable of sealing around both sizes in the string and one set of blind rams, or (2) One set of pipe rams capable of sealing around the larger size string, provided that blind-shear ram capability is present, and crossover subs to the larger size pipe are readily available on the rig floor.
§ 250.266 Blowout preventer systems tests, actuations, inspections, and mainte
(a) Prior to conducting high-pressure tests, all BOP systems shall be tested to a pressure of 200 to 300 psi. (b) Ram-type BOP's and the choke manifold shall be pressure tested with water to rated working pressure or as otherwise approved by the District Supervisor. Annular type BOP's shall be pressure tested with water to 70 percent of rated working pressure or as otherwise approved by the District Supervisor.
(c) In conjunction with the weekly pressure test of BOP systems required in paragraph (d) of this section, the choke manifold valves, upper and lower kelly cocks, and drill-string safety valves shall be pressure tested to pipe-ram test pressures. Safety valves with proper casing connections shall be actuated prior to running casing.
(d) BOP system shall be pressure tested as follows:
(1) When installed;
(2) Before drilling out each string of casing or before continuing operations in cases where cement is not drilled out;
(3) At least once each week, but not exceeding 7 days between pressure tests, alternating between control stations. If either control system is not functional, further drilling operations shall be suspended until that system becomes operable. A period of more than 7 days between BOP tests is allowed when there is a stuck drill pipe or there are pressure control operations and remedial efforts are being performed, provided that the pressure tests are conducted as soon as possible and before normal operations resume. The date, time, and reason for postponing pressure testing shall be entered into the driller's report. Pressure testing shall be performed at intervals to allow each drilling crew to operate the equipment. The weekly pressure test is not required for blind and blindshear rams;
(4) Bind and blind-shear rams shall be actuated at least once every 7 days. Closing pressure on the blind and blind-shear rams greater than neces
sary to indicate proper operation of the rams is not required;
(5) Variable bore-pipe rams shall be pressure tested against all sizes of pipe in use, excluding drill collars and bottomhole tools; and
(6) Following the disconnection or repair of any well-pressure containment seal in the wellhead/BOP stack assembly. In this situation, the pressure tests may be limited to the affected component.
(e) All BOP systems shall be inspected and maintained to assure that the equipment will function properly. The BOP systems shall be visually inspected at least once each day. The manufacturer's recommended inspection and maintenance procedures are acceptable as guidelines in complying with this requirement.
(f) The lessee shall record pressure conditions during BOP tests on pressure charts, unless otherwise approved by the District Supervisor. The test duration for each BOP component tested shall be sufficient to demonstrate that the component is effectively holding pressure. The charts shall be certified as correct by the operator's representative at the facility.
(g) The time, date, and results of all pressure tests, actuations, inspections, and crew drills of the BOP system and system components shall be recorded in the driller's report. The BOP tests shall be documented in accordance with the following:
(1) The documentation shall indicate the sequential order of BOP and auxiliary equipment testing and the pressure and duration of each test. As an alternate, the documentation in the driller's report may reference a BOP test plan that contains the required information and is retained on file at the facility.
(2) The control station used during the test shall be identified in the driller's report.
(3) Any problems or irregularities observed during BOP and auxiliary equipment testing and any actions taken to remedy such problems or irregularities shall be noted in the driller's report.
(4) Documentation required to be entered in the driller's report may instead be referenced in the driller's
report. All records, including pressure charts, driller's report, and referenced documents, pertaining to BOP tests, actuations, and inspections, shall be available for MMS review at the facility for the duration of the drilling activity. Following completion of the drilling activity, all drilling records shall be retained for a period of 2 years at the facility, at the lessee's field office nearest the OCS facility, or at another location conveniently available to the District Supervisor.
§ 250.267 Well-control drills.
Well-control drills shall be conducted for each drilling crew in accordance with the requirements set forth in § 250.58 of this part or as approved by the District Supervisor.
§ 250.268 Diverter systems.
(a) When drilling a conductor or cap rock hole, all drilling units shall be equipped with a diverter system consisting of a diverter sealing element, diverter lines, and control systems. The diverter system shall be designed, installed, and maintained so as to divert gases, water, mud, and other materials away from the facilities and personnel.
(b) After August 14, 1992, diverter systems shall be in compliance with the requirements of this section.
The requirements applicable to diverters that were in effect immediately prior to August 14, 1991, shall remain in effect until August 14, 1992.
(c) The diverter system shall be equipped with remote-control valves in the flow lines that can be operated from at least one remote-control station in addition to the one on the drilling floor. Any valve used in a diverter system shall be full opening. No manual or butterfly valves shall be installed in any part of a diverter system. There shall be a minimum number of turns in the vent line(s) downstream of the spool outlet flange, and the radius of curvature of turns shall be as large as practicable. Flexible hose may be used for diversion lines instead of rigid pipe if the flexible hose has integral end couplings. The entire diverter system shall be firmly anchored and supported to pre
vent whipping and vibrations. All diverter control equipment and lines shall be protected from physical damage from thrown and falling objects.
(d) For drilling operations conducted with a surface wellhead configuration, the following shall apply:
(1) If the diverter system utilizes only one spool outlet, branch lines shall be installed to provide downwind diversion capability, and
(2) No spool outlet or diverter line internal diameter shall be less than 10 inches, except that dual spool outlets are acceptable if each outlet has a minimum internal diameter of 8 inches, and both outlets are piped to overboard lines and that each line downstream of the changeover nipple at the spool has a minimum internal diameter of 10 inches.
(e) The diverter sealing element and diverter valves shall be pressure tested to a minimum of 200 psi when nippled upon conductor casing. No more than 7 days shall elapse between subsequent pressure tests. The diverter sealing element, diverter valves, and diverter control systems (including the remote) shall be actuation tested, and the diverter lines shall be tested for flow prior to spudding and thereafter at least once each 24-hour period alternating between control stations. All test times and results shall be recorded in the driller's report.
§ 250.269 Mud program.
(a) The quantities, characteristics, use, and testing of drilling mud and the related drilling procedures shall be designed and implemented to prevent the loss of well control.
(b) The lessee shall comply with requirements concerning mud control, mud test and monitoring equipment, mud quantities, and safety precautions in enclosed mud handling areas as prescribed in § 250.60 (b), (c), (d), and (e) of this part, except that the installation of an operable degasser in the mud system as required in § 250.60(b)(8) is not required for sulphur operations.
§ 250.270 Securing of wells.
A downhole-safety device such as a cement plug, bridge plug, or packer
shall be timely installed when drilling operations are interrupted by events such as those that force evacuation of the drilling crew, prevent station keeping, or require repairs to major drilling units or well-control equipment. The use of blind-shear rams or pipe rams and an inside BOP may be approved by the District Supervisor in lieu of the above requirements if cap rock casing has been set.
§ 250.271 Supervision, surveillance, and training.
(a) The lessee shall provide onsite supervision of drilling operations at all times.
(b) From the time drilling operations are initiated and until the well is completed or abandoned, a member of the drilling crew or the toolpusher shall maintain rig-floor surveillance continuously, unless the well is secured with BOP's, bridge plugs, packers, or cement plugs.
(c) Lessee and drilling contractor personnel shall be trained and qualified in accordance with the provisions of subpart O of this part. Records of specific training that lessee and drilling contractor personnel have successfully completed, the dates of completion, and the names and dates of the courses shall be maintained at the drill site.
that affect the rated capacity of the unit.
(c) An APD shall include a fully completed Form MMS-331C and the following:
(1) A plat, drawn to a scale of 2,000 feet to the inch, showing the surface and subsurface location of the well to be drilled and of all the wells previously drilled in the vicinity from which information is available. For development wells on a lease, the wells previously drilled in the vicinity need not be shown on the plat. Locations shall be indicated in feet from the nearest block line;
(2) The design criteria considered for the well and for well control, including the following:
(i) Pore pressure;
(ii) Formation fracture gradients; (iii) Potential lost circulation zones; (iv) Mud weights;
(v) Casing setting depths;
(vi) Anticipated surface pressures (which for purposes of this section are defined as the pressure that can reasonably be expected to be exerted upon a casing string and its related wellhead equipment). In the calculation of anticipated surface pressure, the lessee shall take into account the drilling, completion, and producing conditions. The lessee shall consider mud densities to be used below various casing strings, fracture gradients of the exposed formations, casing setting depths, and cementing intervals, total well depth, formation fluid type, and other pertinent conditions. Considerations for calculating anticipated surface pressure may vary for each segment of the well. The lessee shall include as a part of the statement of anticipated surface pressure the calculations used to determine this pressure during the drilling phase and the completion phase, including the anticipated surface pressure used for production string design; and
(vii) If a shallow hazards site survey is conducted, the lessee shall submit with or prior to the submittal of the APD, two copies of a summary report describing the geological and manmade conditions present. The lessee shall also submit two copies of the site maps and data records identified in the survey strategy.
(3) A BOP equipment program including the following:
(i) The pressure rating of BOP equipment,
(ii) A schematic drawing of the diverter system to be used (plan and elevation views) showing spool outlet internal diameter(s); diverter line lengths and diameters, burst strengths, and radius of curvature at each turn; valve type, size, workingpressure rating, and location; the control instrumentation logic; and the operating procedure to be used by personnel, and
(iii) A schematic drawing of the BOP stack showing the inside diameter of the BOP stack and the number of annular, pipe ram, variable-bore pipe ram, blind ram, and blind-shear ram preventers.
(4) A casing program including the following:
(i) Casing size, weight, grade, type of connection and setting depth, and
(ii) Casing design safety factors for tension, collapse, and burst with the assumptions made to arrive at these values.
(5) The drilling prognosis including the following:
(i) Estimated coring intervals, (ii) Estimated depths to the top of significant marker formations, and
(iii) Estimated depths at which encounters with fresh water, sulphur, oil, gas, or abnormally pressured water are expected.
(6) A cementing program including type and amount of cement in cubic feet to be used for each casing string;
(7) A mud program including the minimum quantities of mud and mud materials, including weight materials, to be kept at the site;
(8) A directional survey program for directionally drilled wells;
(9) An H2S Contingency Plan, if applicable, and if not previously submitted; and
(10) Such other information as may be required by the District Supervisor. (d) Public information copies of the APD shall be submitted in accordance with § 250.17 of this part.