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RULE §3.13Casing, Cementing, Drilling, Well Control, and Completion Requirements

      (vi) When using a Kelly rig during drilling, the well shall be fitted with an upper Kelly cock in proper working order to close in the drill string below hose and swivel, when necessary for well control. A lower Kelly safety valve shall be installed so that it can be run through the blowout preventer. When needed for well control, the operator shall maintain at all times on the rig floor safety valves to include:

        (I) full-opening safety valve; and

        (II) inside blowout preventer valve with wrenches, handling tools, and necessary subs for all drilling pipe sizes in use.

      (vii) All control equipment shall be consistent with API Standard 53: Recommended Practices for Blowout Prevention Equipment Systems for Drilling Wells. Control equipment shall be certified in accordance with API Standard 53 as operable under the product manufacturer's minimum operational specifications. Certification shall include the proper operation of the closing unit valving, the pressure gauges, and the manufacturer's recommended accumulator fluids. Certification shall be obtained through an independent company that tests blowout preventers, stacks and casings. Certification shall be performed every five (5) years and the proof of certification shall be made available upon request of the Commission.

      (viii) All well control equipment shall be in good working condition at all times. All outlets, fittings, and connections on the casing, blowout preventers, choke manifold, and auxiliary wellhead equipment that may be subjected to wellhead pressure shall be of a material and construction to withstand or exceed the anticipated pressure. The lines from outlets on or below the blowout preventers shall be securely installed, anchored, and protected from damage.

      (ix) In addition to the primary closing system, including an accumulator system, the blowout preventers shall have a secondary location for closure.

      (x) Testing of blowout prevention equipment.

        (I) Ram type blowout prevention equipment shall be tested to at least the maximum anticipated surface pressure of the well, but not less than 1,500 psi, before drilling the plug on the surface casing.

        (II) Blowout prevention equipment shall be tested upon installation, after the disconnection or repair of any pressure containment seal in the blowout preventer stack, choke line, or choke manifold, limited to the affected component, with testing to occur at least every 21 days. When requested, the district director shall be notified before the commencement of a test.

        (III) A record of each test, including test pressures, times, failures, and each mechanical test of the casings, blowout preventers, surface connections, surface fittings, and auxiliary wellhead equipment shall be entered in the logbook, signed by the person responsible for the test, and made available for inspection by the Commission upon request.

    (C) Drilling fluid program.

      (i) The characteristics, use, and testing of drilling fluid and conduct of related drilling procedures shall be designed to prevent the blowout of any well. Adequate supplies of drilling fluid of sufficient weight and other acceptable characteristics shall be maintained. Drilling fluid tests shall be performed as needed to ensure well control. Adequate drilling fluid testing equipment shall be kept on the drilling location at all times. Sufficient drilling fluid shall be pumped and maintained to ensure well control at all times, including when pulling drill pipe. Mud pit levels shall be visually or mechanically monitored during the drilling process. Mud-gas separation equipment shall be installed and operated as needed when abnormally pressured gas-bearing formations may be encountered. The Commission shall have access to the drilling fluid records and shall be allowed to conduct any essential tests on the drilling fluid used in the drilling or recompletion of a well. When the conditions and tests indicate a need for a change in the drilling fluid program in order to insure control of the well, the operator shall use due diligence in modifying the program.

      (ii) Wells drilled with air shall maintain well control using blowout preventer systems and/or diverter systems.

      (iii) All hole intervals drilled prior to reaching the base of protected water shall be drilled with air, fresh water or a fresh water based drilling fluid. No oil-based drilling fluid may be used until casing has been set and cemented to the protection depth.

    (D) Diverter systems for bay and offshore wells. Any bay or offshore well that is drilled to and/or through formations where the expected reservoir pressure exceeds the hydrostatic pressure of the drilling fluid column shall be equipped to divert any wellbore fluids away from the rig floor. When the diverter system is installed, the diverter components including the sealing element, diverter valves, control systems, stations and vent lines shall be function and pressure tested. For drilling operations with a surface wellhead configuration, the system shall be function tested at least once every 24-hour period after the initial test. After all connections have been made on the surface casing or conductor casing, the diverter sealing element and diverter valves shall be pressure tested to a minimum of 200 psig. Subsequent pressure tests shall be conducted within seven days after the previous test. All diverter systems shall be maintained in working condition. No operator shall continue drilling operations if a test or other information indicates that the diverter system is unable to function or operate as designed.

    (E) Casinghead.

      (i) Requirements. All land and bay wells shall be equipped with casingheads of sufficient rated working pressure, with adequate connections and valves accessible at the surface, to allow pumping of fluid between any two strings of casing at the surface.

      (ii) Casinghead test procedure. Any well showing sustained pressure on the casinghead, or leaking gas or oil between the surface casing and the next casing string, shall be tested in the following manner. The well shall be killed with water or mud and pump pressure applied. The casing shall be condemned if the pressure gauge on the casinghead reflects the applied pressure. After completing corrective measures, the casing shall be tested in the same manner. This method shall be used when the origin of the pressure cannot otherwise be determined.

    (F) Christmas tree.

      (i) All completed non-pumping wells shall be equipped with Christmas tree fittings and wellhead connections with a rated working pressure equal to, or greater than, the surface shut-in pressure of the well. The tubing shall be equipped with a master valve, but two master valves shall be used on all wells with surface pressures in excess of 5,000 psi. All wellhead connections shall be assembled and tested prior to installation by a fluid pressure equal to the test pressure of the fitting employed.

      (ii) The Christmas tree for completed bay and offshore wells shall be equipped with either two master valves, one master valve and one wing valve, or two wing valves. All bay and offshore wells shall have at least five feet of spacing between the bottom of the Christmas tree and the surface of the water at high tide, where applicable. Any newly completed bay and offshore well or existing well on which the Christmas tree is being replaced shall be equipped with a back pressure valve wellhead profile at the flange where the tubing hangs on the Christmas tree.

    (G) Storm choke and safety valve.

      (i) Bay and offshore wells shall be equipped with a storm choke and/or safety valve installed in the tubing.

      (ii) An operator may request approval to use a surface safety valve in lieu of a subsurface safety valve by filing with the appropriate district director a written request for such approval providing all pertinent information to support the exception.

      (iii) The depth and type of the safety valve shall be reported in the "remarks" section of the appropriate completion report form required by §3.16 of this title (relating to Log and Completion or Plugging Report), after the well is completed or recompleted.

  (7) Additional requirements for wells on which hydraulic fracturing treatments will be conducted.

    (A) All casing strings or fracture tubing installed in a well that will be subjected to hydraulic fracturing treatments shall have a minimum internal yield pressure rating of at least 1.10 times the maximum pressure to which the casing strings or fracture tubing may be subjected.

    (B) The operator shall pressure test the casing (or fracture tubing) on which the pressure will be exerted during hydraulic fracturing treatments to at least the maximum pressure allowed by the completion method. Casing strings that include a pressure actuated valve or sleeve shall be tested to 80 percent of actuation pressure for a minimum time period of five (5) minutes. A surface pressure loss of greater than 10 percent of the initial test pressure is considered a failed test. The casing required to be pressure tested shall be from the wellhead to at least the depth of the top of cement behind the casing being tested. The district director shall be notified of a failed test within 24 hours of completion of the test. In the event of a pressure test failure, no hydraulic fracturing treatment may be conducted until the district director has approved a remediation plan, and the operator has implemented the approved remediation plan and successfully re-tested the casing (or fracture tubing).

    (C) During hydraulic fracturing treatment operations, the operator shall monitor all annuli. The operator shall immediately suspend hydraulic fracturing treatment operations if the pressures deviates above those anticipated increases caused by pressure or thermal transfer and shall notify the appropriate district director within 24 hours of such deviation. Further completion operations, including hydraulic fracturing treatment operations, may not recommence until the district director approves a remediation plan and the operator successfully implements the approved plan.

    (D) The following conditions also apply if the well is a minimum separation well, unless otherwise approved by the director:

      (i) Cementing of the production casing in a minimum separation well shall be by the pump and plug method. The production casing shall be cemented from the shoe up to a point at least 200 feet (measured depth) above the shoe of the next shallower casing string that was set and cemented in the well (or to surface if the shoe is less than 200 feet from the surface).

      (ii) The operator shall pressure test the casing string on which the pressure will be exerted during stimulation to the maximum pressure that will be exerted during hydraulic fracturing treatment. The operator shall notify the district director within 24 hours of a failed test. No hydraulic fracturing treatment may be conducted until the district director has approved a remediation plan, and the operator has implemented the approved remediation plan and successfully re-tested the casing (or fracture tubing).

      (iii) The production casing for any minimum separation well shall not be disturbed for a minimum of eight hours after cement is in place and casing is hung-off, and in no case shall the casing be disturbed until the cement has reached a minimum compressive strength of 500 psi.

      (iv) In addition to conducting an evaluation of cementing records and annular pressure monitoring results, the operator of a minimum separation well shall run a cement evaluation tool to assess radial cement integrity and placement behind the production casing. If the cement evaluation indicates insufficient isolation, completion operations may not re-commence until the district director approves a remediation plan and the operator successfully implements the approved plan.

      (v) The operator of a minimum separation well may request from the appropriate district director approval of an exemption from the requirement to run a cement evaluation tool. Such request shall include information demonstrating that the operator has:

        (I) successfully set, cemented, and tested the casing for which the exemption is requested in at least five minimum separation wells by the same operator in the same operating field;

        (II) obtained cement evaluation tool logs that support the findings of cementing records, annular pressure monitoring results or other tests demonstrating that successful cement placement was achieved to isolate productive zones, potential flow zones, and/or zones with corrosive formation fluids; and

        (III) shown that the well for which the exemption is requested will be constructed and cemented using the same or similar techniques, methods, and cement formulation used in the five wells that have had successful cement jobs.

  (8) Pipeline shut-off valves for bay and offshore wells. All bay and offshore gathering pipelines designed to transport oil, gas, condensate, or other oil or geothermal resource field fluids from a well or platform shall be equipped with automatically controlled shut-off valves at critical points in the pipeline system. Other safety equipment shall be in full working order as a safeguard against spillage from pipeline ruptures.


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