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Proposed Rule

Oil and Gas and Sulphur Operations on the Outer Continental Shelf-Oil and Gas Production Safety Systems

This document is a correction of an document that was published on 08/22/2013. View Uncorrected Document

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Correction

In proposed rule document 2013-19861, appearing on pages 52240 through 52284 in the issue of Thursday, August 22, 2013, make the following corrections:

1. On pages 52241 through 52242, the table should read as follows:

Current regulationProposed rule
§ 250.800 General requirements§ 250.800 General.
250.801 Subsurface safety devices§ 250.810 Dry tree subsurface safety devices—general.
§ 250.811 Specifications for subsurface safety valves (SSSVs)—dry trees.
§ 250.812 Surface-controlled SSSVs—dry trees.
§ 250.813 Subsurface-controlled SSSVs.
§ 250.814 Design, installation, and operation of SSSVs—dry trees.
§ 250.815 Subsurface safety devices in shut-in wells—dry trees.
§ 250.816 Subsurface safety devices in injection wells—dry trees.
§ 250.817 Temporary removal of subsurface safety devices for routine operations.
§ 250.818 Additional safety equipment—dry trees.
§ 250.821 Emergency action.
§ 250.825 Subsea tree subsurface safety devices—general.
§ 250.826 Specifications for SSSVs—subsea trees.
§ 250.827 Surface-controlled SSSVs—subsea trees.
§ 250.828 Design, installation, and operation of SSSVs—subsea trees.
§ 250.829 Subsurface safety devices in shut-in wells—subsea trees.
§ 250.830 Subsurface safety devices in injection wells—subsea trees.
§ 250.832 Additional safety equipment—subsea trees.
§ 250.837 Emergency action and safety system shutdown.
§ 250.802 Design, installation, and operation of surface production-safety systems§ 250.819 Specification for surface safety valves (SSVs).
§ 250.820 Use of SSVs.
§ 250.833 Specification for underwater safety valves (USVs).
§ 250.834 Use of USVs.
§ 250.840 Design, installation, and maintenance—general.
§ 250.841 Platforms.
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§ 250.842 Approval of safety systems design and installation features.
§ 250.803 Additional production system requirements§ 250.850 Production system requirements—general.
§ 250.851 Pressure vessels (including heat exchangers) and fired vessels.
§ 250.852 Flowlines/Headers.
§ 250.853 Safety sensors.
§ 250.855 Emergency shutdown (ESD) system.
§ 250.856 Engines.
§ 250.857 Glycol dehydration units.
§ 250.858 Gas compressors.
§ 250.859 Firefighting systems.
§ 250.862 Fire and gas-detection systems.
§ 250.863 Electrical equipment.
§ 250.864 Erosion.
§ 250.869 General platform operations.
§ 250.871 Welding and burning practices and procedures.
§ 250.804 Production safety-system testing and records§ 250.880 Production safety system testing.
§ 250.890 Records.
§ 250.805 Safety device training§ 250.891 Safety device training.
§ 250.806 Safety and pollution prevention equipment quality assurance requirements§ 250.801 Safety and pollution prevention equipment (SPPE) certification.
§ 250.802 Requirements for SPPE.
§ 250.807 Additional requirements for subsurface safety valves and related equipment installed in high pressure high temperature (HPHT) environments§ 250.804 Additional requirements for subsurface safety valves (SSSVs) and related equipment installed in high pressure high temperature (HPHT) environments.
§ 250.808 Hydrogen sulfide§ 250.805 Hydrogen sulfide.
New Sections§ 250.803 What SPPE failure reporting procedures must I follow?
§ 250.831 Alteration or disconnection of subsea pipeline or umbilical.
§ 250.835 Specification for all boarding shut down valves (BSDV) associated with subsea systems.
§ 250.836 Use of BSDVs.
§ 250.838 What are the maximum allowable valve closure times and hydraulic bleeding requirements for an electro-hydraulic control system?
§ 250.839 What are the maximum allowable valve closure times and hydraulic bleeding requirements for a direct-hydraulic control system?
§ 250.854 Floating production units equipped with turrets and turret mounted systems.
§ 250.860 Chemical firefighting system.
§ 250.861 Foam firefighting system.
§ 250.865 Surface pumps.
§ 250.866 Personal safety equipment.
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§ 250.867 Temporary quarters and temporary equipment.
§ 250.868 Non-metallic piping.
§ 250.870 Time delays on pressure safety low (PSL) sensors.
§ 250.872 Atmospheric vessels.
§ 250.873 Subsea gas lift requirements.
§ 250.874 Subsea water injection systems.
§ 250.875 Subsea pump systems.
§ 250.876 Fired and Exhaust Heated Components.

2. On page 52251, the table should read as follows:

3. On page 52254, Table 2 should read as follows:

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4. On pages 52256 through 52260, the table should read as follows:

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5. On page 52271, the table should read as follows:

You must submit:Details and/or additional requirements:
(1) A schematic piping and instrumentation diagramShowing the following:
(i) Well shut-in tubing pressure;
(ii) Piping specification breaks, piping sizes;
(iii) Pressure relief valve set points;
(iv) Size, capacity, and design working pressures of separators, flare scrubbers, heat exchangers, treaters, storage tanks, compressors and metering devices;
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(v) Size, capacity, design working pressures, and maximum discharge pressure of hydrocarbon-handling pumps;
(vi) size, capacity, and design working pressures of hydrocarbon-handling vessels, and chemical injection systems handling a material having a flash point below 100 degrees Fahrenheit for a Class I flammable liquid as described in API RP 500 and 505 (both incorporated by reference as specified in § 250.198).
(vii) Size and maximum allowable working pressures as determined in accordance with API RP 14E, Recommended Practice for Design and Installation of Offshore Production Platform Piping Systems (incorporated by reference as specified in § 250.198).
(2) A safety analysis flow diagram (API RP 14C, Appendix E) and the related Safety Analysis Function Evaluation (SAFE) chart (API RP 14C, subsection 4.3.3) (incorporated by reference as specified in § 250.198)if processing components are used, other than those for which Safety Analysis Checklists are included in API RP 14C, you must use the same analysis technique and documentation to determine the effects and requirements of these components upon the safety system.
(3) Electrical system information, including(i) A plan for each platform deck and outlining all classified areas. You must classify areas according to API RP 500, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Division 1 and Division 2; or API RP 505, Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities Classified as Class I, Zone 0, Zone 1, and Zone 2 (both incorporated by reference as specified in § 250.198).
(ii) Identification of all areas where potential ignition sources, including non-electrical ignition sources, are to be installed showing:
(A) All major production equipment, wells, and other significant hydrocarbon sources, and a description of the type of decking, ceiling, and walls (e.g., grating or solid) and firewalls and;
(B) the location of generators, control rooms, panel boards, major cabling/conduit routes, and identification of the primary wiring method (e.g., type cable, conduit, wire) and;
(iii) one-line electrical drawings of all electrical systems including the safety shutdown system. You must also include a functional legend.
(4) Schematics of the fire and gas-detection systemsshowing a functional block diagram of the detection system, including the electrical power supply and also including the type, location, and number of detection sensors; the type and kind of alarms, including emergency equipment to be activated; the method used for detection; and the method and frequency of calibration.
(5) The service fee listed in § 250.125.The fee you must pay will be determined by the number of components involved in the review and approval process.

6. On page 52272, the table should read as follows:

Item nameApplicable codes and requirements
(1) Pressure and fired vessels where the operating pressure is or will be 15 pounds per square inch gauge (psig) or greater(i) Must be designed, fabricated, and code stamped according to applicable provisions of sections I, IV, and VIII of the ANSI/ASME Boiler and Pressure Vessel Code. (ii) Must be repaired, maintained, and inspected in accordance with API 510, Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration, Downstream Segment (incorporated by reference as specified in § 250.198).
(2) Pressure and fired vessels (such as flare and vent scrubbers) where the operating pressure is or will be at least 5 psig and less than 15 psigMust employ a safety analysis checklist in the design of each component. These vessels do not need to be ASME Code stamped as pressure vessels.
(3) Pressure and fired vessels where the operating pressure is or will be less than 5 psigAre not subject to the requirements of paragraphs (a)(1) and (a)(2).
(4) Existing uncoded Pressure and fired vessels (i) in use on the effective date of the final rule; (ii) with an operating pressure of 5 psig or greater; and (iii) that are not code stamped in accordance with the ANSI/ASME Boiler and Pressure Vessel CodeMust be justified and approval obtained from the District Manager for their continued use beyond 18 months from the effective date of the final rule.
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(5) Pressure relief valves(i) Must be designed and installed according to applicable provisions of sections I, IV, and VIII of the ASME Boiler and Pressure Vessel Code.
(ii) Must conform to the valve sizing and pressure-relieving requirements specified in these documents, but (except for completely redundant relief valves), must be set no higher than the maximum-allowable working pressure of the vessel. (iii) And vents must be positioned in such a way as to prevent fluid from striking personnel or ignition sources.
(6) Steam generators operating at less than 15 psigMust be equipped with a level safety low (LSL) sensor which will shut off the fuel supply when the water level drops below the minimum safe level.
(7) Steam generators operating at 15 psig or greater(i) Must be equipped with a level safety low (LSL) sensor which will shut off the fuel supply when the water level drops below the minimum safe level.
(ii) You must also install a water-feeding device that will automatically control the water level except when closed loop systems are used for steam generation.

7. On pages 52275 through 52276, the table should read as follows:

For the use of a chemical firefighting system on major and minor manned platforms, you must provide the following in your risk assessment . . .Including . . .
(i) Platform description(A) The type and quantity of hydrocarbons (i.e., natural gas, oil) that are produced, handled, stored, or processed at the facility.
(B) The capacity of any tanks on the facility that you use to store either liquid hydrocarbons or other flammable liquids.
(C) The total volume of flammable liquids (other than produced hydrocarbons) stored on the facility in containers other than bulk storage tanks. Include flammable liquids stored in paint lockers, storerooms, and drums.
(D) If the facility is manned, provide the maximum number of personnel on board and the anticipated length of their stay.
(E) If the facility is unmanned, provide the number of days per week the facility will be visited, the average length of time spent on the facility per day, the mode of transportation, and whether or not transportation will be available at the facility while personnel are on board.
(F) A diagram that depicts: quarters location, production equipment location, fire prevention and control equipment location, lifesaving appliances and equipment location, and evacuation plan escape routes from quarters and all manned working spaces to primary evacuation equipment.
(ii) Hazard assessment (facility specific)(A) Identification of all likely fire initiation scenarios (including those resulting from maintenance and repair activities). For each scenario, discuss its potential severity and identify the ignition and fuel sources.
(B) Estimates of the fire/radiant heat exposure that personnel could be subjected to. Show how you have considered designated muster areas and evacuation routes near fuel sources and have verified proper flare boom sizing for radiant heat exposure.
(iii) Human factors assessment (not facility specific)(A) Descriptions of the fire-related training your employees and contractors have received. Include details on the length of training, whether the training was hands-on or classroom, the training frequency, and the topics covered during the training.
(B) Descriptions of the training your employees and contractors have received in fire prevention, control of ignition sources, and control of fuel sources when the facility is occupied.
(C) Descriptions of the instructions and procedures you have given to your employees and contractors on the actions they should take if a fire occurs. Include those instructions and procedures specific to evacuation. State how you convey this information to your employees and contractor on the platform.
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(iv) Evacuation assessment (facility specific)(A) A general discussion of your evacuation plan. Identify your muster areas (if applicable), both the primary and secondary evacuation routes, and the means of evacuation for both.
(B) Description of the type, quantity, and location of lifesaving appliances available on the facility. Show how you have ensured that lifesaving appliances are located in the near vicinity of the escape routes.
(C) Description of the types and availability of support vessels, whether the support vessels are equipped with a fire monitor, and the time needed for support vessels to arrive at the facility.
(D) Estimates of the worst case time needed for personnel to evacuate the facility should a fire occur.
(v) Alternative protection assessment(A) Discussion of the reasons you are proposing to use an alternative fire prevention and control system.
(B) Lists of the specific standards used to design the system, locate the equipment, and operate the equipment/system.
(C) Description of the proposed alternative fire prevention and control system/equipment. Provide details on the type, size, number, and location of the prevention and control equipment.
(D) Description of the testing, inspection, and maintenance program you will use to maintain the fire prevention and control equipment in an operable condition. Provide specifics regarding the type of inspection, the personnel who conduct the inspections, the inspection procedures, and documentation and recordkeeping.
(vi) ConclusionA summary of your technical evaluation showing that the alternative system provides an equivalent level of personnel protection for the specific hazards located on the facility.

8. On pages 52279 through 52280, the table spanning those two pages should read as follows:

If your subsea gas lift system introduces the lift gas to the . . .Then you must install a . . .Additional requirements
API Spec 6A and API Spec 6AV1 (both incorporated by reference as specified in § 250.198) gas-lift shutdown valve (GLSDV), and . . .FSV on the gas-lift supply pipeline . . .PSHL on the gas-lift supply . . .API Spec 6A and API Spec 6AV1 manual isolation valve . . .
(1) Subsea Pipelines, Pipeline Risers, or Manifolds via an External Gas Lift Pipelinemeet all of the requirements for the BSDV described in 250.835 and 250.836 on the gas-lift supply pipeline.upstream (in board) of the GLSDVpipeline upstream (in board) of the GLSDVdownstream (out board) of the PSHL and above the waterline. This valve does not have to be actuated.(i) Ensure that the MAOP of a subsea gas lift supply pipeline is equal to the MAOP of the production pipeline. an actuated fail-safe close gas-lift isolation valve (GLIV) located at the point of intersection between the gas lift supply pipeline and the production pipeline, pipeline riser, or manifold. (ii) Install an actuated fail-safe close gas-lift isolation valve (GLIV) located at the point of intersection between the gas lift supply pipeline and the production pipeline, pipeline riser, or manifold. Install the GLIV downstream of the underwater safety valve(s) (USV) and/or AIV(s).
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(2) Subsea Well(s) through the Casing String via an External Gas Lift Pipeline.Locate the GLSDV within 10 feet of the first of access to the gas-lift riser or topsides umbilical termination assembly (TUTA) (i.e., within 10 feet of the edge of the platform if the GLSDV is horizontal, or within 10 feet above the first accessible working deck, excluding the boat landing and above the splash zone, if the GLSDV is in the vertical run of a riser, or within 10 feet of the TUTA if using an umbilical).on the platform upstream (in board) of the GLSDVpipeline on the platform downstream (out board) of the GLSDV.downstream (out board) of the PSHL and above the waterline. This valve does not have to be actuated.Install an actuated, fail-safe-closed GLIV on the gas lift supply pipeline near the wellhead to provide the dual function of containing annular pressure and shutting off the gas lift supply gas. If your subsea trees or tubing head is equipped with an annulus master valve (AMV) or an annulus wing valve (AWV), one of these may be designated as the GLIV. Consider installing the GLIV external to the subsea tree to facilitate repair and or replacement if necessary.
(3) Pipeline Risers via a Gas-Lift Line Contained within the Pipeline Riserlocate the GLSDV within 10 feet of the first of access to the gas-lift riser or TUTA (i.e., within 10 feet of the edge of the platform if the GLSDV is horizontal, or within 10 feet above the first accessible working deck, excluding the boat landing and above the splash zone, if the GLSDV is in the vertical run of a riser, or within 10 feet of the TUTA if using an umbilical).upstream (in board) of the GLSDVflowline upstream (in board) of the FSV.downstream (out board) of the GLSDV.(i) Ensure that the gas-lift supply flowline from the gas-lift compressor to the GLSDV is pressure-rated for the MAOP of the pipeline riser. Ensure that any surface equipment associated with the gas-lift system is rated for the MAOP of the pipeline riser. (ii) Ensure that the gas-lift compressor discharge pressure never exceeds the MAOP of the pipeline riser. (iii) Suspend and seal the gas-lift flowline contained within the production riser in a flanged API Spec. 6A component such as an API Spec. 6A tubing head and tubing hanger or a component designed, constructed, tested, and installed to the requirements of API Spec. 6A. Ensure that all potential leak paths upstream or near the production riser BSDV on the platform provide the same level of safety and environmental protection as the production riser BSDV. In addition, ensure that this complete assembly is fire-rated for 30 minutes. Attach the GLSDV by flanged connection directly to the API Spec. 6A component used to suspend and seal the gas-lift line contained within the production riser. To facilitate the repair or replacement of the GLSDV or production riser BSDV, you may install a manual isolation valve between the GLSDV and the API Spec. 6A component used to suspend and seal the gas-lift line contained within the production riser, or outboard of the production riser BSDV and inboard of the API Spec. 6A component used to suspend and seal the gas-lift line contained within the production riser.

9. On page 52280, the second table should read as follows:

Type of gas lift systemValveAllowable leakage rateTesting frequency
(i) Gas Lifting a subsea pipeline, pipeline riser, or manifold via an external gas lift pipelineGLSDVZero leakage.Monthly, not to exceed 6 weeks.
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GLIVN/AFunction tested quarterly, not to exceed 120 days.
(ii) Gas Lifting a subsea well through the casing string via an external gas lift pipelineGLSDVZero leakage.Monthly, not to exceed 6 weeks.
GLIV400 cc per minute of liquid or 15 scf per minute of gasFunction tested quarterly, not to exceed 120 days.
(iii) Gas lifting the pipeline riser via a gas lift line contained within the pipeline riserGLSDVZero leakage.Monthly, not to exceed 6 weeks.

10. On page 52281, the table should read as follows:

ValveAllowable leakage rateTesting frequency
(i) WISDVZero leakageMonthly, not to exceed 6 weeks.
(ii) Surface-controlled SSSV or WIV400 cc per minute of liquid or 15 scf per minute of gasSemiannually, not to exceed 6 calendar months.

11. On page 52282, the first table should read as follows:

Item nameTesting frequency, allowable leakage rates, and other requirements
(i) Surface-controlled SSSVs (including devices installed in shut-in and injection wells)Not to exceed 6 months. Also test in place when first installed or reinstalled. If the device does not operate properly, or if a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the device must be removed, repaired, and reinstalled or replaced. Testing must be according to API RP 14B (ISO 10417:2004) (incorporated by reference as specified in § 250.198) to ensure proper operation.
(ii) Subsurface-controlled SSSVsNot to exceed 6 months for valves not installed in a landing nipple and 12 months for valves installed in a landing nipple. The valve must be removed, inspected, and repaired or adjusted, as necessary, and reinstalled or replaced.
(iii) Tubing plugNot to exceed 6 months. Test by opening the well to possible flow. If a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the plug must be removed, repaired, and reinstalled, or replaced. An additional tubing plug may be installed in lieu of removal.
(iv) Injection valvesNot to exceed 6 months. Test by opening the well to possible flow. If a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the valve must be removed, repaired and reinstalled, or replaced.

12. On page 52282, the second table should read as follows:

Item nameTesting frequency and requirements
(i) PSVsOnce each 12 months, not to exceed 13 months between tests. Valve must either be bench-tested or equipped to permit testing with an external pressure source. Weighted disc vent valves used as PSVs on atmospheric tanks may be disassembled and inspected in lieu of function testing.
(ii) Automatic inlet SDVs that are actuated by a sensor on a vessel or compressorOnce each calendar month, not to exceed 6 weeks between tests.
(iii) SDVs in liquid discharge lines and actuated by vessel low-level sensorsOnce each calendar month, not to exceed 6 weeks between tests.
(iv) SSVsOnce each calendar month, not to exceed 6 weeks between tests. Valves must be tested for both operation and leakage. You must test according to API RP 14H (incorporated by reference as specified in § 250.198). If an SSV does not operate properly or if any fluid flow is observed during the leakage test, the valve must be immediately repaired or replaced.
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(v) FSVsOnce each calendar month, not to exceed 6 weeks between tests. All FSVs must be tested, including those installed on a host facility in lieu of being installed at a satellite well. You must test FSVs for leakage in accordance with the test procedure specified in API RP 14C, appendix D, section D4, table D2 subsection D (incorporated by reference as specified in § 250.198). If leakage measured exceeds a liquid flow of 400 cubic centimeters per minute or a gas flow of 15 cubic feet per minute, the FSV must be repaired or replaced.

13. On page 52283, the first table should read as follows:

Item nameTesting frequency and requirements
(i) Pumps for firewater systemsMust be inspected and operated according to API RP 14G, Section 7.2 (incorporated by reference as specified in § 250.198).
(ii) Fire- (flame, heat, or smoke) detection systemsMust be tested for operation and recalibrated every 3 months provided that testing can be performed in a non-destructive manner. Open flame or devices operating at temperatures that could ignite a methane-air mixture must not be used. All combustible gas-detection systems must be calibrated every 3 months.
(iii) ESD systems.(A) Pneumatic based ESD systems must be tested for operation at least once each calendar month, not to exceed 6 weeks between tests. You must conduct the test by alternating ESD stations monthly to close at least one wellhead SSV and verify a surface-controlled SSSV closure for that well as indicated by control circuitry actuation.
(B) Electronic based ESD systems must be tested for operation at least once every three calendar months, not to exceed 120 days between tests. The test must be conducted by alternating ESD stations to close at least one wellhead SSV and verify a surface-controlled SSSV closure for that well as indicated by control circuitry actuation.
(C) Electronic/pneumatic based ESD systems must be tested for operation at least once every three calendar months, not to exceed 120 days between tests. The test must be conducted by alternating ESD stations to close at least one wellhead SSV and verify a surface-controlled SSSV closure for that well as indicated by control circuitry actuation.
(iv) TSH devicesMust be tested for operation at least once every 12 months, excluding those addressed in paragraph (b)(3)(v) of this section and those that would be destroyed by testing. Those that could be destroyed by testing must be visually inspected and the circuit tested for operations at least once every 12 months.
(v) TSH shutdown controls installed on compressor installations that can be nondestructively testedMust be tested every 6 months and repaired or replaced as necessary.
(vi) Burner safety lowMust be tested at least once every 12 months.
(vii) Flow safety low devicesMust be tested at least once every 12 months.
(viii) Flame, spark, and detonation arrestorsMust be visually inspected at least once every 12 months.
(ix) Electronic pressure transmitters and level sensors: PSH and PSL; LSH and LSLMust be tested at least once every 3 months, but no more than 120 days elapse between tests.
(x) Pneumatic/electronic switch PSH and PSL; pneumatic/electronic switch/electric analog with mechanical linkage LSH and LSL controlsMust be tested at least once each calendar month, but with no more than 6 weeks elapsed time between tests.

14. On page 52283, the second table should read as follows:

Item nameTesting frequency, allowable leakage rates, and other requirements
(i) Surface-controlled SSSVs (including devices installed in shut-in and injection wells)Tested semiannually, not to exceed 6 months. If the device does not operate properly, or if a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the device must be removed, repaired, and reinstalled or replaced. Testing must be according to API RP 14B (ISO 10417:2004) (incorporated by reference as specified in § 250.198) to ensure proper operation, or as approved in your DWOP.
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(ii) USVsTested quarterly, not to exceed 120 days. If the device does not function properly, or if a liquid leakage rate > 400 cubic centimeters per minute or a gas leakage rate > 15 cubic feet per minute is observed, the valve must be removed, repaired and reinstalled, or replaced.
(iii) BSDVsTested monthly, not to exceed 6 weeks. Valves must be tested for both operation and leakage. You must test according to API RP 14H for SSVs (incorporated by reference as specified in § 250.198). If a BSDV does not operate properly or if any fluid flow is observed during the leakage test, the valve must be immediately repaired or replaced.
(iv) Electronic ESD logicTested monthly, not to exceed 6 weeks.
(v) Electronic ESD functionTested quarterly, not to exceed 120 days. Shut-in at least one well during the ESD function test. If multiple wells are tied back to the same platform, a different well should be shut-in with each quarterly test.
End Preamble

BILLING CODE 1505-01-C

[FR Doc. C1-2013-19861 Filed 9-3-13; 8:45 am]

BILLING CODE 1505-01-D