(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.
(g) An application for approval of a site under paragraph (f) of this section must provide at least the following:
(1) A detailed analysis and evaluation of the geologic and seismic characteristics of the site based on the geotechnical investigation performed under paragraph (c) of this section, with emphasis on prediction of near-field seismic response.
(2) The design plans and structural analysis for the tank, its impounding system, and related foundations, with a report demonstrating that the design requirements of this section are satisfied, including any test results or other documentation as appropriate.
(3) A description of safety-related features of the site or designs, in addition to those required by this part, if applicable, that would mitigate the potential effects of a catastrophic spill (e.g., remoteness or topographic features of the site, additional exclusion distances, or multiple barriers for containing or impounding LNG).
(h) Each container which does not have a structurally liquid-tight cover must have sufficient freeboard with an appropriate configuration to prevent the escape of liquid due to sloshing, wave action, and vertical liquid displacement caused by seismic action.
[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57419, Aug. 28, 1980]
193.2063 Flooding.
(a) Each operator shall determine the effects of flooding on an LNG facility site based on the worst occurrence in a 100-year period. The determination must take into account:
(1) Volume and velocity of the floodwater;
(2) Tsunamis (local, regional, and distant);
(3) Potential failure of dams;
(4) Predictable land developments which would affect runoff accumulation of water; and
(5) Tidal action.
(b) The effect of flooding determined under paragraph (a) of this section must be accommodated by location or design and construction, as applicable, to reasonably assure:
(1) The structural or functional integrity of LNG facilities; and
(2) Access from outside the LNG facility and movement of personnel and equipment about the LNG facility site for the control of fire and other emergencies.
193.2065 Soil characteristics.
(a) Soil investigations including borings and other appropriate tests must be made at the site of each LNG facility to determine bearing capacity, settlement characteristics, potential for erosion, and other soil characteristics applicable to the integrity of the facility.
(b) The naturally occurring or designed soil characteristics at each LNG facility site must provide load bearing capacities, using appropriate safety factors, which can support the following loads without excessive lateral or vertical movement that causes a loss of the functional or structural integrity of the facility involved:
(1) Static loading caused by the facility and its contents and any hydrostatic testing of the facility; and
(2) Dynamic loading caused by movement of contents of the facility during normal operation, including flow, sloshing, and rollover.
193.2067 Wind forces.
(a) LNG facilities must be designed to withstand without loss of structural or functional integrity:
(1) The direct effect of wind forces;
(2) The pressure differential between the interior and exterior of a confining, or partially confining, structure; and
(3) In the case of impounding systems for LNG storage tanks, impact forces and potential penetrations by wind borne missiles.
(b) The wind forces at the location of the specific facility must be based on one of the following:
(1) For shop fabricated containers of LNG or other hazardous fluids with a capacity of not more than 70,000 gallons, applicable wind load data in ASCE 7-88.
(2) For all other LNG facilities --
(i) An assumed sustained wind velocity of not less than 200 miles per hour, unless the Administrator, RSPA finds a lower velocity is justified by adequate supportive data; or
(ii) The most critical combination of wind velocity and duration, with respect to the effect on the structure, having a probability of exceedance in a 50-year period of 0.5 percent or less, if adequate wind data are available and the probabilistic methodology is reliable.
[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57419, Aug. 28, 1980; 58 FR 14522, March 18, 1993]
193.2069 Other severe weather and natural conditions.
(a) In addition to the requirements of §
193.2061, 193.2063, 193.2065, and 193.2067, each operator shall determine from historical records and engineering studies the worst effect of other weather and natural conditions which may predictably occur at an LNG facility site.
(b) The facility must be located and designed so that such severe conditions cannot reasonably be expected to result in an emergency involving the factors listed in §
193.2063(b).
193.2071 Adjacent activities.
(a) Each operator shall determine that present and reasonably foreseeable activities adjacent to an LNG facility site that could adversely affect the operation of the LNG facility or the safety of persons or offsite property, if damage to the facility occurs.
(b) An LNG facility must not be located where present or projected offsite activities would be reasonably expected to:
(1) Adversely affect the operation of any of its safety control systems;
(2) Cause failure of the facility; or
(3) Cause the facility not to meet the requirements of this part.
193.2073 Separation of facilities.
