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plication shall include information relative to the proposed design and installation features. Information concerning approved design and installation features shall be maintained by the lessee at the lessee's offshore field office nearest the OCS facility or at another location conveniently available to the District Supervisor. All approvals are subject to field verification. The application shall include the following:

(1) A schematic flow diagram showing size, capacity, design, working pressure of separators, storage tanks, compressor pumps, metering devices, and other hydrocarbon-handling vessels;

(2) A schematic flow diagram (API RP 14C, Figure E1) and the related Safety Analysis Function Evaluation chart (API RP 14C, subsection 4.3c);

(3) A schematic piping diagram showing the size and maximum allowable working pressures as determined in accordance with API RP 14E, Design and Installation of Offshore Production Platform Piping Systems;

(4) Electrical system information including the following:

(i) A plan of each platform deck, outlining all hazardous areas classified in accordance with API RP 500B and outlining areas in which potential ignition sources are to be installed;

(ii) All significant hydrocarbon sources and a description of the type of decking, ceiling, walls (e.g., grating or solid), and firewalls; and

(iii) Elementary electrical schematic of any platform safety shutdown system with a functional legend.

(5) Certification that the design for the mechanical and electrical systems to be installed was approved by registered professional engineers. After these systems are installed, the lessee shall submit a statement to the District Supervisor certifying that the new installations conform to the approved designs of this subpart; and

(6) Design and schematics of the installation and maintenance of all fireand gas-detection systems including the following:

(i) Type, location, and number of detection heads;

(ii) Type and kind of alarm, including emergency equipment to be activated;

(iii) Method used for detection;

(iv) Method and frequency of calibration; and

(v) A functional block diagram of the detection system, including the electric power supply.

§ 250.292 Additional production and fuel gas system requirements.

(a) General. Lessees shall comply with the following production safety system requirements (some of which are in addition to those contained in § 250.291 of this part).

(b) Design, installation, and operation of additional production systems, including fuel gas handling safety systems. (1) Pressure and fired vessels shall be designed, fabricated, code stamped, and maintained in accordance with applicable provisions of section I, IV, and VIII of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code.

(i) Pressure safety relief valves shall be designed, installed, and maintained in accordance with applicable provisions of sections I, IV, and VIII of the ANSI/ASME Boiler and Pressure Vessel Code. The safety relief valves shall conform to the valve-sizing and pressure-relieving requirements specified in these documents; however, the safety relief valves shall be set no higher than the maximum-allowable working pressure of the vessel. All safety relief valves and vents shall be piped in such a way as to prevent fluid from striking personnel or ignition

sources.

(ii) The lessee shall use pressure recorders to establish the operating pressure ranges of pressure vessels in order to establish the pressure-sensor settings. Pressure-recording charts used to determine operating pressure ranges shall be maintained by the lessee for a period of 2 years at the lessee's field office nearest the OCS facility or at another location conveniently available to the District Supervisor. The high-pressure sensor shall be set no higher than 15 percent or 5 psi, whichever is greater, above the high

est operating pressure of the vessel. This setting shall also be set sufficiently below (15 percent or 5 psi, whichever is greater) the safety relief valve's set pressure to assure that the high-pressure sensor sounds an alarm before the safety relief valve starts relieving. The low-pressure sensor shall sound an alarm no lower than 15 percent or 5 psi, whichever is greater, below the lowest pressure in the operating range.

(2) Engine exhaust. Engine exhausts shall be equipped to comply with the insulation and personnel protection requirements of API RP 14C, section 4.2c(4). Exhaust piping from diesel engines shall be equipped with spark arresters.

(3) Firefighting systems. Firefighting systems shall conform to subsection 5.2, Fire Water Systems, of API RP 14G, Recommended Practice for Fire Prevention and Control on Open Type Offshore Production Platforms, and shall be subject to the approval of the District Supervisor. Additional quirements shall apply as follows:

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(i) A firewater system consisting of rigid pipe with firehose stations shall be installed. The firewater system shall be installed to provide needed protection, especially in areas where fuel handling equipment is located.

(ii) Fuel or power for firewater pump drivers shall be available for at least 30 minutes of run time during platform shut-in time. If necessary, an alternate fuel or power supply shall be installed to provide for this pump-operating time unless an alternate firefighting system has been approved by the District Supervisor;

(iii) A firefighting system using chemicals may be used in lieu of a water system if the District Supervisor determines that the use of a chemical system provides equivalent fire-protection control; and

(iv) A diagram of the firefighting system showing the location of all firefighting equipment shall be posted in a prominent place on the facility or structure.

(4) Fire- and gas-detection system. (i) Fire (flame, heat, or smoke) sensors shall be installed in all enclosed classified areas. Gas sensors shall be installed in all inadequately ventilated,

enclosed classified areas. Adequate ventilation is defined as ventilation that is sufficient to prevent accumulation of significant quantities of vaporair mixture in concentrations over 25 percent of the lower explosive limit. One approved method of providing adequate ventilation is a change of air volume each 5 minutes or 1 cubic foot of air-volume flow per minute per square foot of solid floor area, whichever is greater. Enclosed areas (e.g., buildings, living quarters, or doghouses) are defined as those areas confined on more than four of their six possible sides by walls, floors, or ceilings more restrictive to air flow than grating or fixed open louvers and of sufficient size to allow entry of personnel. A classified area is any area classified Class I, Group D, Division 1 or 2, following the provisions of API RP 500B.

(ii) All detection systems shall be capable of continuous monitoring. Firedetection systems and portions of combustible gas-detection systems related to the higher gas concentration levels shall be of the manual-reset type. Combustible gas-detection systems related to the lower gas-concentration level may be of the automatic-reset type.

(iii) A fuel-gas odorant or an automatic gas-detection and alarm system is required in enclosed, continuously manned areas of the facility that are provided with fuel gas. Living quarters and doghouses not containing a gas source and not located in a classified area do not require a gas detection system.

(iv) The District Supervisor may require the installation and maintenance of a gas detector or alarm in any potentially hazardous area.

(v) Fire- and gas-detection systems shall be an approved type, designed and installed in accordance with API RP 14C, API RP 14G, and API RP 14F, Recommended Practice for Design and Installation of Electrical Systems for Offshore Production Platforms.

(c) General platform operations. Safety devices shall not be bypassed or blocked out of service unless they are temporarily out of service for startup, maintenance, or testing procedures.

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(a) Inspection and testing. Safetysystem devices shall be successfully inspected and tested by the lessee at the interval specified below or more frequently if operating conditions warrant. Testing shall be in accordance with API RP 14C, appendix D or for safety-system devices other than those listed in API RP 14C, Appendix D the analysis technique and documentation specified therein shall be utilized for inspection and testing of these components, and the following:

(1) Safety relief valves on the natural gas feed system for power plant operations such as pressure safety valves shall be inspected and tested for operation at least once every 12 months. These valves shall be either bench tested or equipped to permit testing with an external pressure source.

(2) The following safety devices shall be inspected and tested at least once each calendar month, but at no time shall more than 6 weeks elapse between tests:

(i) All pressure safety high or pressure safety low, and

(ii) All level safety high and level safety low controls.

(3) All pumps for firewater systems shall be inspected and operated weekly.

(4) All fire- (flame, heat, or smoke) and gas-detection systems shall be inspected and tested for operation and recalibrated every 3 months provided that testing can be performed in a nondestructive manner.

(5) Prior to the commencement of production, the lessee shall notify the District Supervisor when the lessee is ready to conduct a preproduction test and inspection of the safety system. The lessee shall also notify the District Supervisor upon commencement

of production in order that a complete inspection may be conducted.

(b) Records. The lessee shall maintain records for a period of 2 years for each safety device installed. These records shall be maintained by the lessee at the lessee's field office nearest the OCS facility or another location conveniently available to the District Supervisor. These records shall be available for MMS review. The records shall show the present status and history of each safety device, including dates and details of installation, removal, inspection, testing, repairing, adjustments, and reinstallation.

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tain sufficient information to demonstrate to the satisfaction of the Regional Supervisor that the method of measurement meets the requirements of paragraph (a) of this section.

§ 250.297 Site security.

(a) All locations where sulphur is produced, measured, or stored shall be operated and maintained to ensure against the loss or theft of produced sulphur and to assure accurate and complete measurement of produced sulphur for royalty purposes.

(b) Evidence of mishandling of produced sulphur from an offshore lease, or tampering or falsifying any measurement of production for an offshore lease, shall be reported to the Regional Supervisor as soon as possible but no later than the next business day after discovery of the evidence of mishandling.

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3504(h) and assigned clearance number 1010-0036. The information is being collected and will be used to monitor the progress of activities carried out under an offshore permit. The obligation to respond is mandatory.

(c) The information collection requirements contained in § 251.6 of this part do not require approval by the Office of Management and Budget under 44 U.S.C. 3504(h) because there are fewer than 10 respondents annually.

(d) The information collection requirements contained in 30 CFR 251.11 and 251.12 have been approved by the Office of Management and Budget under 44 U.S.C. 3504(h) and assigned clearance number 1010-0034. The information is being collected for regulatory compliance. This information will be used to inspect and select geological and geophysical data and information collected under a Federal permit offshore. The obligation to respond is mandatory under section 26 of the Outer Continental Shelf Lands Act (43 U.S.C. 1352).

(e) The information collection requirements contained in 30 CFR 251.62 have been approved by the Office of Management and Budget under 44 U.S.C. 3507 and assigned clearance number 1010-0049. The information is being collected for regulation compliance. This information will be used to analyze and evaluate planned drilling activities of permittees on the Federal OCS. The obligation to respond is mandatory.

(f) The information collection requirements contained in 30 CFR 251.5 have been approved by the Office of Management and Budget under 44 U.S.C. 3501 et seq and assigned clearance number 1010-0048. The information is being collected to evaluate permit applications to conduct prelease exploration offshore and to moonitor activities of scientific exploration conducted under notices to ensure there is no environmental degradation, personal harm, damage to historical or cultural sites, or interference with other uses. The response is required to obtain a benefit.

[47 FR 25331, June 11, 1982, as amended at 48 FR 37968, Aug. 22, 1983; 48 FR 43324,

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(a) The Act authorizes the Secretary to prescribe rules and regulations necessary to carry out the provisions of the Act. The primary purpose of the regulations in this part is to prescribe policies, procedures, and requirements for conducting geological and geophysical activities associated with exploration for oil, gas, or sulphur not authorized under a lease in the Outer Continental Shelf (OCS). These activities may take place on unleased lands or on lands under lease to a third party. These activities are limited to geological and geophysical exploration for oil, gas, and sulphur and geological and geophysical research related to oil, gas, or sulphur, which involves the use of solid or liquid explosives or drilling activities. The requirements of the regulations in this part implement the provisions of sections 5, 8(g), 11 (a) and (g), 19, 24, and 26 of the Act. Federal Agencies are exempt from the regulations in this part.

(b) Notwithstanding any other provisions of the regulations in this part, geological and geophysical exploration for OCS minerals other than oil, gas, and sulphur and geological and geophysical research associated with OCS minerals other than oil, gas, and sulphur are governed by the provisions of part 280 of this title.

[53 FR 25256, July 5, 1988]

§ 251.2 Definitions.

When used in this part, the following terms shall have the meaning given below:

(a) Act means the Outer Continental Shelf Lands Act, as amended (43 U.S.C. 1331 et seq.).

(b) Affected local government means the principal governing body of a locality which is in an affected State and is identified by the Governor of that State as a locality which will be significantly affected by oil and gas activities on the OCS.

(c) Affected State means, with respect to any program, plan, lease sale, or other activity proposed, conducted,

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