Liquefied Natural Gas (LNG) facilities are constructed according to "Liquefied Natural Gas Facilities: Federal Safety Standards”1
and regulated by the Federal Energy Regulatory Commission (FERC). FERC
has worked closely with the Pipeline and Hazardous Materials
Administration (PHMSA), part of the U.S. Department of Transportation
(DOT), to provide interpretations and guidelines to meet these
regulations. The U.S. federal regulations incorporate NFPA 59A,2
which is a prescriptive standard. The objectives of the U.S. federal
regulations and NFPA 59A are to keep the fire and explosion hazards
onsite (i.e., within the facility boundaries) in the event of a loss of
When liquefied, natural gas is a refrigerated cryogenic liquid that boils at -162°C. Spills of LNG from low-source pressures can be conveyed safely to impounding areas or a sump to minimize the size of resulting flammable vapor clouds as the cold liquid boils on the warmer ground. Pressurized releases may produce liquid sprays or flashing jets, which can create larger flammable vapor clouds.
either case, natural gas vapor clouds are unlikely to produce damaging
overpressures if ignited. There have been very few major incidents
involving LNG terminals or shipping. The most severe incident occurred
in Cleveland, Ohio, in 1944. A more recent incident occurred at the
Skikda facility in Algeria in 2004 when the vapors of a flammable
refrigerant release were ingested by a steam boiler. The flammable vapor
cloud explosion killed 27 workers onsite.
prescribes a series of 10-minute-duration design spills (also called
single accidental leakage sources), which must be analyzed to prove that
the contour of the ½ LFL methane (i.e., 2.5% concentration on a
volumetric basis) vapor cloud does not cross the property boundary that
can be built upon.
Practically, the property boundary that can be built upon has been treated as the line beyond which the facility no longer has administrative control. In addition, the radiant heat flux from pool fires within impoundment areas must be shown not to exceed 5 kW/m2 (1,600 BTU/hr ft2) across this boundary. The areas within these boundaries are termed "exclusion zones” where the potential fire hazard exists, and the public cannot be exposed to this hazard.
specifies that only passive mitigation strategies can be applied to
meet the exclusion zone requirements and does not allow for active
systems to be used to meet the criteria. Thus, shorter duration releases
based on detection and emergency shutdown procedures have not been
acceptable, even though NFPA 59A does address this option, and such
technologies are widely used.
of the exclusion zone analysis requirements are stated broadly in NFPA
59A and require considerable interpretation for the spill and leak
scenarios that need to be considered. Over the past decade, FERC has
clarified its interpretation of the federal requirements by means of
formal letters, less formal precedent setting memoranda as well as data
requests to specific projects requiring certain analyses to be
performed. These interpretations continue to evolve over time, with the
continual introduction of new analytical tools and new hazard criteria
The 2013 edition of NFPA
59A and recent FERC interpretations, memos, and guidance have introduced
risk-based analysis approaches that deviate from the original
prescriptive approach in the 2001 edition of NFPA 59A. The new Chapter
15 "Performance (Risk Assessment) Based LNG Plant Siting” is not
entirely consistent with traditional Quantitative Risk Assessment (QRA)
approaches such as QRA assign risk by aggregating the likelihood or
probability of scenarios with the consequence in terms of injury or
fatality of susceptible populations. QRA is required by the European
code.4 FERC requires release scenarios to be selected ac
cording to FERC-generated generic failure rates without consideration
for the consequence portion of the risk assessment.
has also expanded the consequences to be analyzed to include vapor
cloud explosion hazards of flammable refrigerant releases from
liquefaction processes, which were not present in import terminals
because they only vaporized LNG. Although the changes to the required
analyses of fire hazards are complex, some change has been necessary due
to the anticipated growth of the U.S. LNG liquefaction infrastructure.
This article provides a brief background of changes in the LNG industry
in the U.S. and the evolution of current passive fire protection and
facility siting guidelines.
LNG IN THE U.S. BACK THEN: IMPORT TERMINALS
North American LNG industry experienced a surge in growth in about 2003
when the industry believed that existing North American natural gas
production was going to be overtaken by increasing demand from power
generation, chemical feedstock applications, and domestic use. At that
time, there were only four operating LNG import terminals to provide the
gas supply: Cove Point, MD; Everett, MA; Elba Island, GA; and Lake
The worldwide shipment
of LNG occurs via ocean-going tanker ships. Import terminals receive the
LNG, store it in large cryogenic tanks, and vaporize it into the
nation’s gas pipeline network. In 2004-2005, the need to import gas into
the U.S. prompted a major effort to develop the terminal infrastructure
to receive imported LNG.
peak, around 2006, dozens of terminals on the West, East and the Gulf
Coasts sought to receive permits for construction. The first to be
constructed was the Cheniere LNG terminal in Sabine Pass, LA, and others
followed on the East and Gulf Coasts. Unfortunately for the owners, the
expected gas demand did not materialize, causing many of the projects
to stall and new terminals to remain underutilized.
Import Terminal Fire Protection Considerations
this time period, FERC applied the 2001 edition of NFPA 59A to identify
single accidental release scenarios that needed to be analyzed as part
of the application process. Two types of hazardous outcomes were
analyzed: radiant heat flux from LNG pool fires and flammable vapor
dispersion. LNGFIREIII is the PHMSA-approved software package for
modeling LNG pool fires.5 The software calculates the
radiation heat flux for LNG pool fires based on a prescribed surface
emissive power (SEP) and a cylindrical flame geometry that is based on
the impoundment area. FERC recently confirmed that this approach
adequately represents the radiant heat from LNG pool fires based on
recent large-scale LNG pool fire tests conducted by Sandia National
Laboratories.6 LNGFIREIII remains the primary code for
calculating heat flux, but the requirements for calculating vapor
dispersion have undergone many changes.
mid-2005, at a time when only import terminals were being considered on
U.S. shores, FERC required evaluations of vapor dispersion from full
cross-section pipe breaks at the tanker ship unloading line and from
high-pressure flashing jets at small-diameter attachments to the
transfer piping for instrumentation or pressure relief, at flanges, and
at valves or other equipment connections. Based on these requirements, a
wide variety of single accidental leakage sources, ranging from valve
packing and flange leaks to full cross section ruptures of ship
unloading lines, were analyzed by applicants in their FERC submittals.
primary analytical tool used at that time for the analysis of vapor
dispersion was the integral vapor dispersion model, DEGADIS.7
DEGADIS was used to compute the vapor dispersion from evaporating LNG
that was spilled into sumps or impoundment areas. The practice was to
calculate the source term based on a rate of evaporation that was
determined by transient heat conduction from the concrete surface. This
vapor source was then input into a code called SOURCE5 that accounted
for vapor hold-up within the impoundment area.8 This gave a
time delay and a rate of spill of vapors out of the impoundment area,
which was input into DEGADIS to calculate the extent of the ½ LFL cloud.
LNG IN THE U.S. TODAY: EXPORT TERMINALS
2010, industry began to develop plans for natural gas liquefaction
facilities to export LNG as a result of the natural gas surplus from
recent production of natural gas from shale formations. Many of the
proposed liquefaction facilities were put forth by previously approved
LNG import terminals, the first being Cheniere’s Sabine Pass terminal.
It was followed by Freeport LNG and Cameron LNG, among others.
North America only had one LNG export facility. It was in Alaska on the
Kenai Peninsula, approximately 100 km from Anchorage. The Kenai LNG
plant began operating in 1969, and was recently taken offline.
processes and the associated plants that are used to liquefy natural
gas are considerably more complicated than import regasification
terminals. FERC’s limited experience with liquefaction and industry’s
rush to develop this new infrastructure forced FERC and DOT (PHMSA) to
re-evaluate their requirements. Over a period of two to three years,
FERC issued a sequence of new interpretations for required fire and
explosion hazard analyses. The most significant changes required a new
approval methodology for vapor dispersion software tools, a new method
of identifying single accidental leakage sources, and the introduction
of vapor cloud explosion calculations for flammable refrigerants.
IMPROVED VAPOR DISPERSION MODEL REQUIREMENTS
absence of consistent guidelines on the performance of vapor dispersion
software prompted a study sponsored by the Fire Protection Research
Foundation.9 The final report of this study proposed a formal
process for the approval of analytical tools for vapor dispersion at
LNG facilities. The resulting Model Evaluation Protocol (MEP) requires
prospective models to be compared to a database of spill tests on ground
and water, and associated vapor dispersion measurements that were
conducted over the past decades. The National Association of State Fire
Marshals (NASFM) commissioned an independent review of the MEP to assist
local and state emergency response officials.10 This review in part concluded that the MEP was unnecessarily long and complex.
years after publication of the MEP, two commercial software products
were approved by DOT (PHMSA) in 2011. These were the PHAST Version
6.6/6.711 and FLACS Version 9.112 computer codes.
The MEP review process was elaborate, and it took considerable time for
the respective software developers to compile their MEP cases and for
the regulators to approve them. In addition to DEGADIS, these two
software packages are approved for vapor dispersion analyses today.
PHAST is commercial software that uses the Unified Dispersion Model
(UDM) to calculate vapor dispersion following a two-phase pressurized
release or an unpressurized release. It models near-field and far-field
jet dispersion, droplet evaporation in the air, rainout (droplets
hitting the ground), liquid pool spread, vaporization and subsequent
heavy gas dispersion. These features have been essential for analyzing
FERC-required pressurized LNG or liquid refrigerant jetting and flashing
scenarios. PHAST only accounts for flat ground, and therefore cannot
accommodate complex geometries such as tanks, buildings, and walls that
are typically present at LNG facilities.
The FLACS software can model vapor dispersion scenarios and vapor cloud explosions in three dimensions. This CFD model discretizes the domain using a rectangular grid. FLACS has a routine called FLASH that can be used to model high pressure jetting and flashing releases. It also contains a liquid spill model to calculate the spread of LNG or refrigerants over the ground. The model calculates heat transfer to the liquid and its evaporation. Currently, FLACS is the only model approved by FERC that can be used to model the vapor clouds resulting from liquid spills into trenches. FLACS also is the only approved model that can be used to determine the effect of structures and vapor fences on the flammable vapor cloud dispersion.
The Latest Single Accidental Leakage Requirements
2010 and 2011, FERC’s single accidental leakage scenarios were
prescriptive in that the hole size had to be chosen based on pipe size
and later pipe length. These criteria were superseded in 2012 by the
requirement that single accidental leakage sources be selected for
analysis if the likelihood of failure is greater than 3x10-5 failures
per year.14 A detailed discussion of the criterion’s development and application is provided elsewhere.14
staff provided a table of yearly failure rates for piping and other
equipment. All single accidental leakage sources that need to be
considered are now selected based upon the length of the piping system
and the resulting failure rate for a given hole size. Once selected, the
scenarios are analyzed using the approved commercial software.
This latest change was a paradigm shift from a strict prescriptive approach to one that is based on a probabilistic criterion, even though the consequences remain prescriptive: the exclusion zones must remain within the boundaries of the facility. This paradigm shift constitutes a step closer towards the European Standard,7 which is entirely based on Quantitative Risk Analysis (QRA).
Vapor Cloud Explosion Hazards
LNG regasification - only facilities, liquefaction plants contain
flammable refrigerants in significant volumes. Common refrigerants
include chlorofluorocarbons, ammonium, carbon dioxide, and
non-halogenated hydrocarbons. In most refrigeration cycles, the mixed
refrigerant may include varying concentrations of nitrogen, methane,
ethane, ethylene, propane, and iso-pentane.
of the refrigerants are generally more reactive than natural gas. That
is particularly the case with ethylene, which can undergo vapor cloud
detonation. As a result, refrigerants introduce the risks of vapor cloud
explosions that did not previously exist with import terminals. The
Jan. 19, 2004, Skikda Algeria liquefaction plant accident involved a
refrigerant vapor cloud explosion that killed 27 workers.15
NFPA 59A does not address this risk. FERC16
now requires applicants to analyze vapor cloud explosions associated
with worst-case flammable gas releases, to identify the 1 psi (7 kPa)
over-pressure boundary and to analyze the associated offsite
consequences of 1 psi (7 kPa) and greater overpressures.
Passive Mitigation Techniques
Passive mitigation techniques that are often used to contain the ½ LFL cloud within the property include the following:
- Relocation of LNG and refrigerant storage and piping elements to increase the distance to the property boundary.
- Changes to the LNG and refrigerant flow design, by changing the size of piping, capacity and number of pumps, and process conditions. These can reduce the worst case release flow-rate.
- Changes to the refrigerant storage capacity and the amount of refrigerant that can be released.
- The use of vapor fences and other obstacles to contain the LNG and refrigerant vapor cloud during a release.
have adopted various vapor fence strategies in the past, including long
and tall fences, placing fences near the source to reduce its momentum,
as well as using short fences to increase turbulence and mixing the
cloud with air.
In conditions where
an impoundment area, sump, or conveyance trench is located near a
property boundary, the extent of the vapor cloud from a spill into this
area can be addressed by selecting a concrete mixture that has a low
thermal conductivity. Cryogenic liquid spills on concrete evaporate due
to heat conduction from the substrate to the cold cryogenic pool. This
is the dominant mode of evaporation in the early stage when evaporation
rates are at their highest. Therefore, by selecting low density, heat
capacity, and thermal conductivity concrete, the ½ LFL clouds can be
Harri Kytomaa and Trey Morrison are with Exponent, Inc.
- Title 49, Transportation, Part 193, Code of Federal Regulations, Government Printing Office, Washington, DC, 2013.
- NFPA 59A, Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG), National Fire Protection Association, Quincy, MA 2001.
- Williams T. and Assing N. "Risk-Based LNG Facility Siting and Safety Analysis in the U.S.: Recent Developments.” 17th International Conference & Exhibition on Liquefied Natural Gas (LNG 17), American Gas Association, Washington, DC, 2013.
- EN-1473, Installation and equipment for liquefied natural gas – Design of onshore installations, British Standards Institution, London, 2007.
- LNGFIRE3: A Thermal Radiation Model for LNG Fires. Gas Technology Institute, Des Plaines, IL, 2004.
- Recommended Parameters for Solid Flame Models for Land-Based Liquefied Natural Gas Spills, Federal Energy Regulatory Commission Office of Energy Projects, Docket No. AD13-4-000, Washington, DC, 2013.
- DEGADIS 2.1: Dense Gas Dispersion Model for LNG Vapor Dispersion, Gas Technology Institute, Des Plaines, IL, 2004.
- SOURCE5, Trinity Consultants, Dallas, TX, 2004.
- "Evaluating Vapor Dispersion Models for Safety Analysis of LNG Facilities Research Project,” Fire Protection Research Foundation, Quincy, MA, 2007.
- "Review of the LNG Vapor Dispersion Model Evaluation Protocol,” Prepared by AcuTech Consulting Group, Alexandria, VA, 2009.
- Phast, Det Norske Veritas, Hovik, Norway, 2011.
- FLACS, Gexcon AS, Bergen, Norway, 2010.
- "Meeting Summary, Corpus Christi Project, Docket No. PF12-3-000, LNG Engineering Conference Call, May 7, 2012,” FERC Document Accession No. 20120507-4014, Federal Energy Regulatory Commission, Washington, DC, 2012.
- Kohout A. "U.S. Regulatory Framework and Guidance for Siting Liquefied Natural Gas Facilities – A Lifecycle Approach.” Proceedings of Mary Kay O’Connor Process Safety Center, 15th International Symposium, College Station, Texas, 2012.
- "Report of the U.S. government team site inspection of the Sonatrach Skikda LNG plant in Skikda, Algeria,” FERC, Washington, DC, 2004.
- Title 40, Environmental Protection Agency, Code of Federal Regulations, Government Printing Office, Washington, DC, 2013.