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Section 3112F Requirements Specific to Marine Terminals That Transfer LNG

California Building Code 2022 > 31F [SLC] Marine Oil Terminals > 3112F Requirements Specific to Marine Terminals That Transfer LNG
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3112F.1 Purpose and Applicability
Section 3112F provides minimum requirements specific to onshore marine terminals that transfer LNG. Sections 3101F through 3111F are also applicable, as appropriate. Offshore marine terminals that transfer LNG are subject to a case-by-case review and approval by the Division.
3112F.2 Risk and Hazards Analyses
  1. Prior to LNG transfer at marine terminal, a hazards identification exercise shall be carried out to isolate potential internal and external events that may cause a spill and/or impact to public health, safety and the environment.
  2. Hazards analysis shall consider every component, part of a structure, equipment item, and system, whose failure could cause a major accident, result in unacceptable incident escalation beyond the design basis, or adversely affect the potential for the passive and active systems to control or shutdown the facility. Safety Critical Components and Safety Critical Systems shall be identified.
  3. Consequence models shall be developed for credible scenarios to identify Lower Flammability Limit (LFL) hazard regions. Release diameters shall include, at a minimum, 3mm, 10mm and 50 mm sizes. Scenarios involving the marine loading arms shall consider a full bore release.
  4. Consequence models shall develop radiant heat zones from jet and pool fires for the 25 kW/m2, 12.5 kW/m2, 5 kW/m2 and 1.6 kW/m2 thermal endpoints.
  5. A Cryogenic Exposure Analysis (CEA) shall be conducted to identify equipment and structures susceptible to cryogenic spray and pool exposure due to LNG releases from different size holes.
  6. A Facility Essential Systems Survivability Assessment (ESSA) shall be conducted to determine the survivability of the Safety Critical Components.
  7. Impact on Safety Critical Components and Systems shall be mitigated.
3112F.3 Specific Berthing and Mooring Considerations
In addition to the minimum design requirements for berthing and mooring in Sections 3103F, 3105F and 3107F of this code, the following shall be satisfied:
  1. Wind force and moment coefficients for LNG vessels shall be used in accordance with Appendix A of OCIMF MEG 3 [12.1], as appropriate.
  2. The limiting environmental criteria for which the LNG carrier may safely remain berthed at the terminal shall be determined using dynamic mooring analysis.
  3. Real time monitoring and recording of environmental conditions including wind, current and waves shall be conducted to assist in mooring system management.
  4. Vessel hull pressure shall be considered in fender analyses and design.
3112F.4 Fire Protection
A Fire and Explosion Hazard Analysis (FEHA) for potential pool fires, jet fires and flash fires, considering LNG releases from different size holes, as specified in Section 3112F.2, shall be conducted and result in recommendations regarding:
  1. Type, quantity and location of fire and gas detection devices to detect potential fires and/or gas releases in a specified time frame
  2. Fire suppression coverage, including fixed and portable systems, and equipment necessary to allow the design scenarios to be mitigated and/or extinguished
  3. Design application rates for required fire protection systems
  4. Firefighting requirements, including an analysis of the capability of response by other facilities, USCG and federal, state and local agencies
Critical structural supports and equipment within the fire exposed areas identified in the FEHA shall be provided with passive fire protection designed for the duration identified in the analysis.
Emergency shutdown (ESD) systems shall be provided, in accordance with API RP 14C [12.2] and Section 12.3 of NFPA 59A [12.3], to shut down the flow of LNG to/from the terminal and shut down equipment whose continued operation could add to or prolong an emergency event.
The ESD system shall be of a failsafe design or shall be otherwise installed, located or protected to minimize the possibility that it becomes inoperative in the event of an emergency or failure at the primary control system. ESD system components that may be exposed to fire effects shall be evaluated to confirm that the actuator operation will not be impaired.
3112F.5 LNG Pipelines
  1. All pipe specified for use in cryogenic service shall be furnished in accordance with Paragraph 323.2.2A and Table A-1 of ASME B31.3 [12.4]. The extreme thickness of insulation on cryogenic piping shall be taken into consideration during piping design.
  2. All piping materials, including gaskets and thread compounds, shall be selected appropriate to the range of temperatures to which subjected. Piping that may be exposed to the low temperature of LNG or to the heat of an ignited spill, during an emergency where such exposure could result in a failure of the piping, shall comply with at least one of the following:
    1. Made of material(s) that can withstand both the normal operating temperature and extreme temperature to which the piping may be subjected during the emergency
    2. Protected by insulation or other means to delay failure due to extreme temperatures until corrective action can be taken by the operator.
    3. Capable of being isolated and having the flow stopped where piping is exposed only to the heat of an ignited spill during the emergency
  3. LNG pipelines shall be designed for cool-down with liquid nitrogen where the use of LNG is not possible.
  4. All LNG drains should be located within a containment area or piped to a collection system or containment area.
  5. LNG lines shall be analyzed for a start-up case where the top of the pipe is 90 degrees F warmer than the bottom of the pipe. The upward bowing of the pipe shall be limited to 1.25 inches.
  6. Pipe supports, including any insulation systems used to support pipe whose stability is essential, shall be resistant to or protected against fire exposure, escaping cold liquid, or both if they are subject to such exposure.
  7. Pipe supports for cold lines shall be designed to minimize excessive heat transfer, which can result in piping failure by ice formations or embrittlement of supporting steel. If icing up of piping and components is unavoidable, the weight of the accumulated ice shall be considered during piping and support design.
  8. Valves shall comply with ASME B31.5 [12.5].
  9. Cryogenic valves in liquid cryogenic service shall not be installed in vertical lines. Valves in liquid cryogenic service shall be installed in horizontal lines with the stem in the vertical position or at least 45 degrees vertically from the horizontal centerline of the pipe.
  10. All cryogenic valves (except butterfly valves, check valves and globe valves) shall have a body cavity relief to the "safe" side of the valve. All cryogenic valves with a body cavity relief shall be marked on the exterior of the body with a letter "V" and an arrow pointing to the direction of the venting side.
  11. Thermal relief valves shall be installed to protect the equipment and piping from over pressuring as a result of ambient heat input to blocked in LNG or other light hydrocarbon liquids.
  12. Cryogenic subsea pipeline designs shall be qualified by a certifying agency, acceptable to the Division, in a qualification program that demonstrates that the system has been designed, fabricated and can function as intended with safeguards provided as determined to be necessary.
3112F.6 Mechanical Components and Systems
  1. The CEA analysis shall be used to recommend acceptable cryogenic exposure durations for Safety Critical Components to produce CEA drawings.
  2. ESD system components, which are exposed to cryogenic effects, shall be evaluated to confirm that the actuators will not be impaired by the potential exposures, thereby preventing the components from failing to a safe position.
  3. Critical structural supports and equipment within the cryogenically exposed areas shall be provided with cryogenic insulation. The cryogenic insulation and passive fire protection shall be designed for sufficient incident duration.
  4. For marine loading arms in LNG service, ice formation on non-insolated arms and hoses must be taken into account. Mechanisms for venting, apex venting, purging and cool down of the marine loading arms shall be identified on the P&IDs.
  5. Areas beneath marine arms shall have restricted access during and after product transfer, until there is no longer danger of falling ice.
3112F.7 References
[12.1] Oil Companies International Marine Forum (OCIMF), 2008, "Mooring Equipment Guidelines (MEG3)," 3rd ed., London, England.
[12.2] American Petroleum Institute (API), 2001 (Reaffirmed 2007), API Recommended Practice 14C (API RP 14C), "Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms," 7th ed., Washington, D.C.
[12.3] National Fire Protection Association (NFPA), 2012, NFPA 59A, "Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG)," 2013 ed., Quincy, MA.
[12.4] American Society of Mechanical Engineers (ASME), 2015, ASME B31.3-2014 (ASME B31.3), "Process Piping," New York.
[12.5] American Society of Mechanical Engineers (ASME), 2013, ASME B31.5-2013 (ASME B31.5), "Refrigeration Piping and Heat Transfer Components," New York.
Authority: Sections 8750 through 8760, Public Resources Code.
Reference: Sections 8750, 8751, 8755 and 8757, Public Resources Code.
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