[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-2, 45 FR 70410, Oct. 23, 1980; 50 FR 45732, Nov. 1, 1985; 58 FR 14522, March 18, 1993]
193.2015 [Reserved]
[59 FR 17281, April 12, 1994]
193.2017 Plans and procedures.
(a) Each operator shall maintain at each LNG plant the plans and procedures required for that plant by this part. The plans and procedures must be available upon request for review and inspection by the Administrator or any State Agency that has submitted a current certification or agreement with respect to the plant under the pipeline safety laws (
49 U.S.C. 60101 et seq.). In addition, each change to the plans or procedures must be available at the LNG plant for review and inspection within 20 days after the change is made.
(b) The Administrator or the State Agency that has submitted a current certification under section 5(a) of the Natural Gas Pipeline Safety Act with respect to the pipeline facility governed by an operator's plans and procedures may, after notice and opportunity for hearing as provided in
49 CFR 190.237 or the relevant State procedures, require the operator to amend its plans and procedures as necessary to provide a reasonable level of safety.
[Amdt. 193-2, 45 FR 70404, Oct. 23, 1980; Amdt. 193-7, 56 FR 31090, July 9, 1991; Amdt. 193-10, 61 FR 18517, April 26, 1996]
193.2019 Mobile and temporary LNG facilities
(a) Mobile and temporary LNG facilities for peakshaving application, for service maintenance during gas pipeline systems repair/alteration, or for other short term applications need not meet the requirements of this part if the facilities are in compliance with applicable sections of NFPA 59A (1996 edition).
(b) The State agency having jurisdiction over pipeline safety in the State in which the portable LNG equipment is to be located must be provided with a location description for the installation at least 2 weeks in advance, including to the extent practical, the details of siting, leakage containment or control, fire fighting equipment, and methods employed to restrict public access, except that in the case of emergency where such notice is not possible, as much advance notice as possible must be provided.
[Amdt. 193-14, 62 FR 41312, Aug. 1, 1997; 62 FR 48952, Sept. 18, 1997]
RESEARCH AND SPECIAL PROGRAMS
ADMINISTRATION, DOT
SUBPART B -- SITING REQUIREMENTS
193.2051 Scope.
This subpart prescribes siting requirements for the following LNG facilities: Containers and their impounding systems, transfer systems and their impounding systems, emergency shutdown control systems, fire control systems, and associated foundations, support systems, and normal or auxiliary power facilities necessary to maintain safety.
[Amdt. 193-1, 45 FR 57418, Aug. 28, 1980]
193.2055 General.
An LNG facility must be located at a site of suitable size, topography, and configuration so that the facility can be designed to minimize the hazards to persons and offsite property resulting from leaks and spills of LNG and other hazardous fluids at the site. In selecting a site, each operator shall determine all site-related characteristics which could jeopardize the integrity and security of the facility. A site must provide ease of access so that personnel, equipment, and materials from offsite locations can reach the site for fire fighting or controlling spill associated hazards or for evacuation of personnel.
193.2057 Thermal radiation protection.
(a) Thermal exclusion zone. Each LNG container and LNG transfer system must have a thermal exclusion zone in accordance with the following:
(1) Within the thermal exclusion zone, the impounding system may not be located closer to targets listed in paragraph (d) of this section than the exclusion distance “d" determined according to this section, unless the target is a pipeline facility of the operator.
(2) If grading and drainage are used under §
193.2149(b), operators must comply with the requirements of this section by assuming the space needed for drainage and collection of spilled liquid is an impounding system.
(b) Measurement. The exclusion distance “d" is the horizontal distance measured from the impoundment area to the target where the following apply:
(1) The maximum calculated exclusion distance for each thermal flux level shall be used for that exposure (offsite target) in paragraph (d) of this section.
(2) The wind speed producing the maximum exclusion distances shall be used except for wind speeds that occur less than 5 percent of the time based on recorded data for the area.
(3) The ambient temperature and relative humidity that produce the maximum exclusion distance shall be used except that values that occur less than 5 percent of the time based on recorded data for the area shall not be used.
(4) Properties of LNG with the highest anticipated heating value shall be used.
(5) The height of the flame base should be that of any dike or containment in relation to the horizontal reference plane. The height of the target shall be in relation to the same reference plane.
(c) Exclusion distance length. The length of an exclusion distance for each impounding space may not be less than the distance “d" determined in accordance with one of the following:
(1) The method of calculating the exclusion distances for levels of radiant exposure listed in paragraph (d) of this section shall be the method described in Gas Research Institute report GRI-89/0176 and also available as the “LNGFIRE" computer program from GRI.
A=the largest horizontal area across the impounding space measured at the lowest point along the top inside edge of the dike.
f=values for targets prescribed in paragraph (d) of this section.
(2) Determine “d" from a mathematical model for thermal radiation and other appropriate fire characteristics which assures that the incident thermal flux levels in paragraph (d) of this section are not exceeded. The model must:
(i) Use atmospheric conditions which, if applicable, result in longer exclusion distances than other atmospheric conditions occurring at least 95 percent of the time based on recorded data for the site area;
(ii) Have been evaluated and verified by testing at a scale, considering scaling effects, appropriate for the range of application;
(iii) Have been submitted to the Administrator for approval, with supportive data as necessary to demonstrate validity; and
(iv) Have received approval by the Administrator.
(d) Limiting values for incident radiant flux on offsite targets. The maximum incident radiant flux at an offsite target from burning of a total spill in an impounding space must be limited to the distances in paragraph (c) of this section using the following values of “(f)" or “Incident Flux":
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See PDF for table 
[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57418, Aug. 28, 1980; Amdt. 193-13, 62 FR 8404, Feb. 25, 1997; 62 FR 36465, July 8, 1997]
193.2059 Flammable vapor-gas dispersion protection.
(a) Dispersion exclusion zone. Except as provided by paragraph (e) of this section, each LNG container and LNG transfer system must have a dispersion exclusion zone with a boundary described by the minimum dispersion distance computed in accordance with this section. The following are prohibited in a dispersion exclusion zone unless it is an LNG facility of the operator:
(1) Outdoor areas occupied by 20 or more persons during normal use, such as beaches, playgrounds, outdoor theaters, other recreation areas, or other places of public assembly.
(2) Buildings that are:
(i) Used for residences;
(ii) Occupied by 20 or more persons during normal use;
(iii) Contain explosive, flammable, or toxic materials in hazardous quantities;
(iv) Have exceptional value or contain objects of exceptional value based on historic uniqueness described in Federal, State, or local registers; or
(v) Could result in additional hazard if exposed to a vapor-gas cloud.
(b) Measuring dispersion distance. The dispersion distance is measured radially from the inside edge of an impounding system along the ground contour to the exclusion zone boundary.
(c) Computing dispersion distance. A minimum dispersion distance must be computed for the impounding system. If grading and drainage are used under §
193.2149(b), operators must comply with the requirements of this section by assuming the space needed for drainage and collection of spilled liquid in an impounding system. Dispersion distances must be determined in accordance with the following dispersion parameters, using the “DEGADIS" model described in Gas Research Institute report No. GRI 89/0242 titled “LNG Vapor Dispersion Predication with the DEGADIS Dense Gas Dispersion Model", or a model for vapor dispersion which meets the requirements of §193.2057(c)(2)(ii) through (iv):
(1) Average gas concentration in air = 2.5 percent.
(2) Dispersion conditions are a combination of those which result in longer predicted downwind dispersion distances than other weather conditions at the site at least 90 percent of the time, based on U.S. Government weather data, or as an alternative where the model used gives longer distances at lower wind speeds, Category F atmosphere, wind speed = 4.5 miles per hour, relative humidity equals 50.0 percent, and atmospheric temperatures = 0.0 C.
(3) Dispersion coordinates y, z, and H, where applicable, = 0.
(4) A surface roughness factor of 3 cm shall be used. Higher values for the roughness factor may be used if it can be shown that the terrain both upwind and downwind of the vapor cloud has dense vegetation and that the vapor cloud height is more than ten times the height of the obstacles encountered by the vapor cloud.
(d) Vaporization design rate. In computing dispersion distance under paragraph (c) of this section, the following applies:
(1) Vaporization results from the spill caused by an assumed rupture of a single transfer pipe (or multiple pipes that lack provisions to prevent parallel flow) which has the greatest overall flow capacity, discharging at maximum potential capacity, in accordance with the following conditions:
(i) The rate of vaporization is not less than the sum of flash vaporization and vaporization from boiling by heat transfer from contact surfaces during the time necessary for spill detection, instrument response, and automatic shutdown by the emergency shutdown system, but not less than 10 minutes, plus, in the case of impounding systems for LNG storage tanks with side or bottom penetrations, the time necessary for the liquid level in the tank to reach the level of the penetration or equilibrate with the liquid impounded assuming failure of the internal shutoff valve.
(ii) In determining variations in the vaporization rate due to surface contact, the time necessary to wet 100 percent of the impounding floor area shall be determined by equation C-9 in the 1974 AGA report titled “Evaluation of LNG Vapor Control Methods," or by using an equivalent personal computer program based on equation C-9 or by an alternative model which meets the requirements of §193.2057(c)(2)(ii) through (iv).
(iii) After spill flow is terminated, the rate of vaporization is vaporization of the remaining spillage, if any, from boiling by heat transfer from contact surfaces that are reducing in area and temperature as a function of time.
(iv) Vapor detention space is all space provided for liquid impoundment and vapor detention outside the component served, less the volume occupied by the spilled liquid at the time the vapor escapes the vapor detention space.
(2) The boiling rate of LNG on which dispersion distance is based is determined using the weighted average value of the thermal properties of the contact surfaces in the impounding space determined from eight representative experimental tests on the materials involved. If surfaces are insulated, the insulation must be designed, installed, and maintained so that it will retain its performance characteristics under spill conditions.
(e) Planned vapor control. An LNG facility need not have a dispersion exclusion zone if the Administrator, RSPA finds that compliance with paragraph (a) of this section would be impractical and the operator prepares and follows a plan for controlling LNG vapor that is found acceptable by the Director. The plan must include circumstances under which LNG vapor is controlled to preclude the dispersion of a flammable mixture from the LNG facility under all predictable environmental conditions that could adversely affect control. The reliability of the method of control must be demonstrated by testing or experience with LNG spills.
[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57418, Aug. 28, 1980; Amdt. 193-13, 62 FR 8404, Feb. 25, 1997; 62 FR 36465, July 8, 1997; Amdt. 193-15, 63 FR 7723, Feb. 17, 1998]
193.2061 Seismic investigation and design forces.
(a) Except for shop fabricated storage tanks of 70,000 gallons or less capacity mounted within 2 feet of the ground, if an LNG facility is located at a site in Zone 0 or 1 of the “Seismic Risk Map of the United States," UBC, each operator shall determine, based on a study of faults, hydrologic regime, and soil conditions, whether a potential exists at the site for surface faulting or soil liquefaction.
(b) Subject to paragraph (f) of this section, LNG facilities must be designed and built to withstand, without loss of structural or functional integrity, the following seismic design forces, as applicable:
(1) For LNG facilities (other than shop fabricated storage tanks of 70,000 gallons or less capacity mounted within 2 feet of the ground) located at a site in Puerto Rico in Zone 2, 3, or 4 of the “Seismic Risk Map of the United States," or at a site determined under paragraph (a) of this section to have a potential for surface faulting or soil liquefaction, the forces that could reasonably be expected to occur at the foundation of the facility due to the most critical ground motion, motion amplification, permanent differential ground displacement, soil liquefaction, and symmetric and assymmetric reaction forces resulting from hydrodynamic pressure and motion of contained liquid in interaction with the facility structure.
(2) For all other LNG facilities, the total lateral force set forth in UBC, Volume 1, corresponding to the zone of the “Seismic Risk Map of the United States" in which the facility is located, and a vertical force equal to the total lateral force.
(c) Each operator of an LNG facility to which paragraph (b)(1) of this section applies shall determine the seismic design forces on the basis of a detailed geotechnical investigation and in accordance with paragraphs (d) and (e) of this section. The investigation must include each of the following items that could reasonably be expected to affect the site and be sufficient in scope to identify all hazards that could reasonably be expected to affect the facility design:
(1) Identification and evaluation of faults, Quaternary activity of those faults, tectonic structures, static and dynamic properties of materials underlying the site, and, as applicable, tectonic provinces within 100 miles of the site;
(2) Identification and evaluation of all historically reported earthquakes which could affect the determination under this section of the most critical ground motion or differential displacement at the site when correlated with particular faults, tectonic structures, and tectonic provinces, as applicable; and
(3) Identification and evaluation of the hydrologic regime and the potential of liquefaction-induced soil failures.
(d) The most critical ground motion must be determined in accordance with paragraph (e) of this section either:
(1) Probabilistically, when the available earthquake data are sufficient to show that the yearly probability of exceedance of most critical ground motion is 10 -4 or less; or
(2) Deterministically, when the available earthquake data are insufficient to provide probabilistic estimates, with the objective of determining a most critical ground motion with a yearly probability of exceedance of 10-4 or less.
(e) The determination of most critical ground motion, considering local and regional seismological conditions, must be made by using the following:
(1) A regionally appropriate attenuation relationship, assuming that earthquakes occur at a location on a fault, tectonic structure, or tectonic province, as applicable, which would cause the most critical seismic movement at the site, except that where epicenters of historically reported earthquakes cannot be reasonably related to known faults or tectonic structures, but are recognized as being within a specific tectonic province which is within 100 miles of the site, assume that those earthquakes occur within their respective provinces at a source closest to the site.
(2) A horizontal design response spectrum determined from the mean plus one standard deviation of a free-field horizontal elastic response spectra whose spectral amplitudes are consistent with values expected for the most critical ground motion.
(3) A vertical design response spectrum that is either two-thirds of the amplitude of the horizontal design response spectrum at all frequencies or equal to the horizontal design response spectrum where the site is located within 10 miles of the earthquake source.
(f) An LNG storage tank or its impounding system may not be located at a site where an investigation under paragraph (c) of this section shows that any of the following conditions exists unless the Administrator grants an approval for the site:
(1) The estimated design horizontal acceleration exceeds 0.8g at the tank or dike foundation.
(2) The specific local geologic and seismic data base is sufficient to predict future differential surface displacement beneath the tank and dike area, but displacement not exceeding 30 inches cannot be assured with a high level of confidence.
(3) The specific local geologic and seismic data base is not sufficient to predict future differential surface displacement beneath the tank and dike area, and the estimated cumulative displacement of a Quaternary fault within one mile of the tank foundation exceeds 60 inches.
(4) The potential for soil liquefaction cannot be accommodated by design and construction in accordance with paragraph (b)(1) of this section.
