LNG Risk Assessment

An LNG risk assessment is the structured study of how liquefied natural gas can escape containment at a plant, tank, jetty, carrier or bunkering point, what fire or vapor hazard follows, how likely each release is, and which safeguards and exclusion zones bring the risk within 49 CFR Part 193, 33 CFR Part 127 and NFPA 59A.

On June 8, 2022, an 18-inch transfer line carrying LNG from the storage tanks to the docks at Freeport LNG in Quintana, Texas ruptured in a boiling liquid expanding vapor explosion. The root cause report by IFO Group, published November 17, 2022, found the segment had been isolated with cryogenic LNG inside and no working overpressure protection, a scenario the plant LNG risk assessment had never studied.

A pressure safety valve had been inspected on April 26, 2022 and never returned to service; its inlet isolation valve stayed shut and no car seal was applied. Relief devices out of service are one of the process safety key risk indicators we set thresholds for in energy operations. PHMSA’s final order of April 9, 2025 cites that omission, the missing temperature monitoring, and a loading procedure that let operators block in LNG, and records a $1,540,800 civil penalty.

LNG Risk Assessment: Key Takeaways
An LNG risk assessment identifies how liquefied natural gas can escape containment at a plant, jetty, carrier or bunkering point, models the pool fire, flash fire, vapor cloud or BLEVE that follows, scores likelihood against consequence, and sets the safeguards and exclusion zones the law requires. In the US the law is 49 CFR Part 193, 33 CFR Part 127 and NFPA 59A.
Freeport LNG, June 8, 2022: an 18-inch transfer line was isolated with a pressure safety valve still blocked after an April test, the trapped LNG warmed, and the line ruptured in a BLEVE. The plant lost eight months and 17 percent of US export capacity. PHMSA’s final order of April 9, 2025 records a $1,540,800 civil penalty, paid in full.
The 2026 record makes the point again: a Delfin pipeline in Cameron Parish ruptured on February 3 when a cleaning pig struck a closed valve and released 56 million cubic feet of gas, and Ras Laffan’s Barzan facility killed 13 workers on June 21 during a restart. Both were start-up or reactivation events, which is where an LNG risk assessment is usually thinnest.
LNG risk assessment siting rules are numeric. Part 193 fixes the vapor exclusion zone at 2.5 percent methane, half the lower flammability limit, under a 4.5 mph wind and Pasquill F stability, and the thermal zone by LNGFIRE3 at the worst wind that occurs more than 5 percent of the time. NFPA 59A 2023 Chapter 19 offers a QRA route instead of prescriptive distances.
The build-out is the reason to refresh every LNG risk assessment now: US exports averaged 17.4 Bcf/d in the first half of 2026, up 23 percent, Golden Pass became the ninth terminal on April 22, 2026, and the IEA expects 300 bcm a year of new liquefaction by 2030. PHMSA’s May 2025 ANPRM is the first Part 193 rewrite since 2004.
The worked LNG risk assessment register below scores six scenarios for a generic two-train export terminal on a 5 x 5 matrix, shows the blocked-in-LNG row falling from 20 to 4, and lists the evidence each row needs before an inspector or an insurer accepts it.

 

The plant was down for eight months, removing about 2 Bcf/d, or 17 percent of US export capacity, according to the Energy Information Administration. The investigators listed three gaps an LNG risk assessment exists to close: a HAZOP that never studied a blocked-in segment, a management-of-change step skipped, and operators working excessive overtime.

What an LNG Risk Assessment Covers

LNG is methane cooled to about minus 162 degrees Celsius, which shrinks its volume roughly 600 times. That cold liquid brings four hazard mechanisms a general risk assessment never meets: cryogenic embrittlement of carbon steel, rapid phase transition when LNG hits water, rollover in stratified tanks, and pool fires that injure at hundreds of meters.

The LNG risk assessment therefore runs in layers. A hazard identification study lists release points, a HAZOP walks each node for deviations, consequence models size the fire and the cloud, and a quantitative risk assessment multiplies frequency by consequence to produce the individual and societal risk that NFPA 59A 2023 Chapter 19 and ISO/TS 16901:2022 compare against tolerability criteria.

Hazard	Mechanism	How it is modeled	Governing reference
Pool fire	LNG spreads on ground or water, vaporizes and burns as a radiating pool	LNGFIRE3 thermal radiation model; flux contours at the property line	49 CFR 193.2057; NFPA 59A
Flash fire and vapor cloud	Unignited cloud drifts downwind, ignites at a remote source and burns back	DEGADIS or FEM3A dispersion to half the lower flammability limit	49 CFR 193.2059; NFPA 59A
BLEVE and overpressure	Trapped LNG warms in a blocked-in line or vessel and ruptures it	Relief-valve sizing, blocked-outlet HAZOP node, LOPA	Freeport RCFA; NFPA 59A relief provisions
Rapid phase transition	LNG contacts water and flashes to vapor with a physical blast	Spill-on-water scenarios in carrier and jetty studies	Sandia SAND2008-3153
Rollover	Stratified tank layers mix suddenly and vent large vapor volumes	Density monitoring, tank management procedures	NFPA 59A tank chapters
Cryogenic exposure	Cold liquid or vapor embrittles steel and injures people on contact	Material selection, spill impoundment, drainage sizing	NFPA 59A; ISO/TS 16901
Asphyxiation	Cold methane vapor displaces oxygen in low or confined spaces	Gas detection layout, ventilation design	NFPA 59A fire and gas detector siting

Each hazard in an LNG risk assessment needs a named target and a named consequence, which is where the hazard versus risk distinction matters. A rollover is a hazard; the risk is the vapor volume exceeding relief capacity on a tank next to the control room. The hazard identification guide gives the walk-down routine that produces that inventory.

Practitioners at AcuTech describe the same three-layer LNG risk assessment sequence of process hazard analysis, consequence modeling and QRA, and note that the results drive layout and siting decisions before FERC filings. We agree, and would add that the register format matters as much as the models, because it is the register a surveyor reads.

Why the 2026 Build-Out Raises the Stakes

The scale of what an LNG risk assessment covers has grown. Global LNG trade reached a record 428 million tonnes in 2025, with 524 MTPA of liquefaction and 1,247 MTPA of regasification capacity, according to the GIIGNL 2026 annual report, and the IEA counts 38 bcm of supply growth in 2025 and expects over 40 bcm in 2026.

Figure 1. US LNG exports, 2016 to 2027

Figure 1. US LNG exports by period, with EIA forecasts for the second half of 2026 and the first half of 2027.

The United States carries most of that growth. Exports averaged 17.4 Bcf/d in the first half of 2026, 23 percent above the same period of 2025, as EIA reported on September 1, 2026. Plaquemines is at full capacity, Corpus Christi Stage 3 runs six of seven trains, and Golden Pass shipped the ninth terminal’s first cargo on April 22, 2026.

More capacity means more commissioning, where the 2026 incidents happened. The IEA’s October 2025 outlook expects about 300 bcm a year of new export capacity by 2030, led by the United States and Qatar, and Clarksons puts the newbuild orderbook at 44 percent of the fleet. Each new train, jetty and ship needs an LNG risk assessment before first LNG.

Incident	Date and place	What happened	LNG risk assessment lesson
Freeport LNG	June 8, 2022, Quintana, Texas	18-inch transfer line blocked in with LNG; PSV isolated since April 26 test; BLEVE and eight-month outage; $1,540,800 penalty	HAZOP every blocked-outlet node; car-seal register; return-to-service check after PSV tests
Delfin Offshore Pipeline	February 3, 2026, Cameron Parish, Louisiana	Cleaning pig struck a closed valve on a 42-inch line idle since 2012; 56 MMcf released; one worker injured; PHMSA corrective action order	Reactivation of dormant assets needs its own hazard study and valve line-up verification
Ras Laffan Barzan facility	June 21, 2026, Qatar	Explosion and fire during restart after a maintenance shutdown since December 2025; 13 dead, 66 injured	Start-up after turnaround is a distinct operating mode; pre-startup safety review is mandatory

The Delfin failure is documented in PHMSA’s enforcement record and reported by Natural Gas Intelligence: crews were locating a stalled pig, gas was reinjected, and the pig hit a closed valve. Louisiana State Police told KPLC that one worker suffered minor injuries and that only 5 to 10 feet of pipe was destroyed.

Ras Laffan is the larger loss. QatarEnergy confirmed 13 deaths and 66 injuries at the Barzan gas facility two days after a restart from a shutdown that began in December 2025, and stated the event was operational and not sabotage. The energy and utilities KRI set includes start-up hours as a leading indicator for exactly this reason.

How to Run an LNG Risk Assessment in Seven Steps

The LNG risk assessment sequence below follows ISO/TS 16901 for onshore plants and the ship-shore interface, with the regulatory checkpoints from Part 193 and NFPA 59A placed where they apply. It aligns with the generic risk assessment methodology, but the inputs are specific: release frequencies, hole sizes, weather data and population maps.

Step	Action	LNG-specific input	Output
1	Define scope and acceptance criteria	Facility type (export, import, peak-shaving, bunkering); individual and societal risk limits under NFPA 59A 19.10	Basis-of-assessment document signed by the operator
2	Build the release inventory	Every tank, pump, loading arm, transfer line and vaporizer; hole sizes and release probabilities from Chapter 19.6	Numbered release-point list with isolation and detection for each
3	Run HAZID and HAZOP	Nodes for blocked outlet, reverse flow, cold embrittlement, rollover, loss of containment at the jetty	Deviation list with causes and existing safeguards
4	Model consequences	LNGFIRE3 for thermal flux; DEGADIS or FEM3A to 2.5 percent methane; RPT and BLEVE overpressure	Hazard footprints on the site plan and property line
5	Quantify and rank	Frequency x consequence per scenario; LOPA for high-consequence nodes; 5 x 5 matrix for the register	Risk contours and a ranked register against the acceptance line
6	Select safeguards in hierarchy order	Impoundment and spacing first, then relief, detection, isolation, water spray, procedures, PPE	Action log with owner, date and residual score
7	Document, file and revalidate	Part 193 siting records; FERC Resource Report 13 for export projects; USCG letter of intent for waterfront facilities	Signed report, regulator submissions, review triggers

Freeport shows the cost of skipping step two of an LNG risk assessment. The RCFA reported that the 2016 HAZOP never evaluated a blocked-in LNG segment with inadequate overpressure protection, so no later step could have caught it. The risk identification guide explains why inventory completeness is checked before any scoring begins.

Before step four of the LNG risk assessment, the modeling team needs a short list of verified inputs. Each one is something the FERC engineering review or the state fire marshal will ask to see, and each is easier to gather before the HAZOP than after it:

• Ten years of hourly weather data for the site, so the 5 percent exceedance wind and humidity conditions in Part 193 can be demonstrated, not assumed
• The design spill for each impoundment per NFPA 59A, with the pump-out rate and the isolation time that define it
• Population and occupancy maps out to the largest modeled footprint, including roads, schools and the nearest residence
• Failure-rate data for tanks, arms and lines, taken from Chapter 19.6 of NFPA 59A 2023 or a documented operator history

Steps six and seven close the loop. The residual risk explainer describes what the after-safeguard score must show, and the assessment frequency guide lists change triggers; for LNG the mandatory ones are a new train, a change of vessel size at the jetty, a reactivated line, and any procedure change touching isolation valves.

Siting Rules: 49 CFR 193, NFPA 59A and the Exclusion Zones

Federal siting law is arithmetic, and the numbers are public. Section 193.2057 requires a thermal radiation exclusion zone calculated with the Gas Technology Institute’s LNGFIRE3 model, using the wind speed, temperature and humidity that produce the largest distances except for conditions occurring less than 5 percent of the time.

Section 193.2059 sets the vapor dispersion zone at an average methane concentration of 2.5 percent, half the lower flammability limit, modeled with DEGADIS 2.1 or FEM3A at a 4.5 mile-per-hour wind, Pasquill class F stability, and the design spill defined in NFPA 59A-2001. Those two zones decide whether a site is buildable before the LNG risk assessment moves to a QRA.

Rule	Parameter	Value or method	What it fixes
49 CFR 193.2057	Thermal radiation	LNGFIRE3; worst wind, temperature and humidity above the 5 percent exceedance	Distance from impoundment to property line and to outdoor assembly areas
49 CFR 193.2059	Vapor dispersion	2.5 percent methane; 4.5 mph wind at 10 m; Pasquill F; DEGADIS 2.1 or FEM3A	Distance the design-spill cloud may travel inside the property line
NFPA 59A 2023 Chapter 19	Performance-based siting	Release probabilities (19.6), consequence assessment (19.8), tolerability criteria (19.10)	A QRA route where prescriptive distances cannot be met
33 CFR Part 127	Waterfront facilities	Letter of intent to the Captain of the Port; waterway suitability assessment	Marine traffic, security and transfer operations at the jetty
PHMSA ANPRM, May 5, 2025	Modernization	Comments closed July 7, 2025; last major update 2004; NFPA 59A-2001 still incorporated	Whether Part 193 adopts NFPA 59A 2023 and small-scale provisions

The prescriptive rules are old. PHMSA’s advance notice of proposed rulemaking of May 5, 2025 states that the last significant Part 193 amendments date to 2004 and that the regulations rely on the 2001 edition of NFPA 59A, and asks whether to adopt the 2023 edition, including Chapter 14 mobile and temporary facilities and paragraph 17.1.2 small-scale plants.

The 2023 edition matters because Chapter 19 release and conditional probabilities were updated with new failure-rate data and hole sizes, and fire and gas detector siting was revised. An LNG risk assessment QRA built on the 2019 tables needs re-running, a point the NFPA risk assessment tool guide makes for every NFPA edition change.

Operators should run both LNG risk assessment routes now: the prescriptive Part 193 zones for the permit and a Chapter 19 QRA for the design. The ANPRM signals a risk-based regime for large facilities, which the PIPES Act of 2020 had directed by December 27, 2023. The risk assessment matrix guide shows how the two outputs sit side by side in one register.

A Worked Register for a Two-Train Export Terminal

The LNG risk assessment register below scores six scenarios for a generic two-train export terminal with two full-containment tanks, one jetty and a single LNG transfer header. It is illustrative and not a reconstruction of Freeport’s own study, but the first two rows are the mechanism the RCFA describes. Scoring uses a 5 x 5 matrix with the acceptance line at 8.

Scenario	Cause and consequence	Before	Safeguards added	After
Blocked-in LNG segment	Isolation valves closed on a filled transfer header; LNG warms, pressure rises beyond design; rupture and BLEVE	20	Procedure forbids isolation with liquid present; control logic alarms on closed valves; temperature indicators on every segment	4
PSV left isolated after test	Inlet block valve not reopened after bench test; segment loses relief	16	Car-seal register with sign-off; return-to-service checklist; quarterly car-seal audit	4
Loading-arm leak at jetty	Coupling failure during transfer; pool on water; RPT and pool fire	15	Emergency release couplings; ESD with 30-second closure; spray curtains; transfer only within weather limits	5
Tank rollover	Stratified heel and new cargo mix; vapor surge exceeds relief	12	Density profiling; fill-mode selection by cargo density; rollover prediction in the tank management system	4
Carrier allision at jetty	Vessel strikes the loading platform on approach; structural damage and release	10	Tug escort; speed limits from the waterway suitability assessment; berthing aids; mooring load monitoring	5
Vapor cloud reaches property line	Design spill in impoundment under Pasquill F conditions; cloud exceeds 2.5 percent at the fence	12	Impoundment resized; vapor fence; high-expansion foam; layout moved inboard	6

Figure 2. Register scores before and after safeguards

Figure 2. Six scenarios from the worked LNG risk assessment register for an export terminal on a 5 x 5 matrix, with the acceptance line at 8.

The first two rows are where the Freeport final order landed its three items: 193.2513(a) for a loading procedure without provisions against unintentional isolation, 193.2507 for failing to monitor the 18-inch line for temperature rise, and 193.2619(e) for not verifying the PSV was returned to service. Each maps to a safeguard column above.

The corrective actions Freeport reported to LNG Industry read like the after column: revised PSV testing and car-seal procedures, control-system logic that alerts operators to dangerous valve positions, and a staffing increase of more than 30 percent to cut the overtime the investigators named as a contributing cause. The control measure explainer describes how to classify those changes.

Figure 3. The Freeport timeline

Figure 3. Freeport LNG from incident to closed enforcement case, three years and one month.

The timeline is the cost of a missing HAZOP node. PHMSA closed the consent agreement on July 3, 2025, after approving the return to normal operations on May 21, 2025, nearly three years after the rupture. Each LNG risk assessment register row therefore needs four documents behind it:

• The HAZOP worksheet page where the scenario was raised, with the node, deviation and recommendation number
• The consequence model run, its input weather case and the plotted footprint on the site plan
• The safeguard’s design basis, such as relief capacity, ESD closure time or car-seal procedure revision
• The verification record showing the safeguard exists and works, signed and dated

The same columns serve machinery studies under the ISO 12100 template and the risk assessment example in a different industry; only the models change. A terminal also needs the business impact analysis that prices an eight-month outage, because the RCFA and the penalty were the smaller numbers at Freeport.

LNG Risk Assessment for Carriers, Jetties and Bunkering

The marine side of an LNG risk assessment has its own evidence base. Sandia National Laboratories’ 2008 breach and spill study for large carriers found the most significant impacts to people and property within about 500 meters of a near-shore spill, lower impacts beyond about 1,600 meters, and credible intentional breaches of 5 to 16 square meters.

Figure 4. Sandia hazard distances

Figure 4. LNG risk assessment hazard distances for a large near-shore LNG carrier spill, from Sandia report SAND2008-3153.

Those distances feed the waterway suitability assessment the Coast Guard requires under 33 CFR Part 127 for any waterfront facility handling LNG in bulk. The operator files a letter of intent with the Captain of the Port, who rules on transit routes, escort tugs and security zones; the transportation risk assessment guide covers the road and rail legs.

Setting	Standard or rule	Distinct hazards	Assessment deliverable
Onshore plant	49 CFR 193; NFPA 59A; ISO/TS 16901	Blocked-in lines, rollover, impoundment fires, vapor travel to the fence	Siting analysis, HAZOP, QRA with risk contours
Jetty and ship-shore interface	ISO/TS 16901; 33 CFR 127; SIGTTO guidance	Arm disconnection, allision, mooring failure, spill on water and RPT	Waterway suitability assessment, transfer risk study, ESD philosophy
Carrier in transit	IMO IGC Code; ISPS Code; NETL and Sandia spill studies	Collision or grounding breach, cargo tank failure, pool fire on water	Route risk study, security plan, spill consequence footprint
Bunkering	ISO/TS 18683:2021	Simultaneous operations, hose failure, cold spill on deck, cryogenic burns	Safety zone definition, SIMOPS matrix, bunkering procedure
Small-scale and mobile	NFPA 59A 2023 Chapters 14 and 17	Trailer transfers, temporary storage, unfamiliar crews	Site-specific assessment per deployment, not per design

Bunkering deserves a separate LNG risk assessment. ISO/TS 18683:2021 covers shore-to-ship, truck-to-ship and ship-to-ship supply and requires a structured risk assessment to set the safety zone and the simultaneous-operations rules, because a hose failure during cargo handling on a passenger ferry is a different scenario from the same failure at an export jetty.

Meanwhile Clarksons data puts the active LNG carrier fleet at about 715 vessels in early 2026, and each new ship makes a first call at a jetty studied for a different hull. Security scenarios from the physical security risk assessment template and geopolitical risk analysis for chokepoint transits belong in the same LNG risk assessment file.

The environmental scope of an LNG risk assessment is set separately, and ISO/TS 16901 says so in its own text: it does not address the environmental risks of a release. Methane emissions, marine spill effects and climate exposure belong in the environmental monitoring assessment and the climate risk assessment guide, and regulators read them as separate files.

Where LNG Safety Studies Break Down

The LNG risk assessment failures below come from the Freeport findings, the two 2026 incidents, and the questions PHMSA asked in its ANPRM. The left column is the defect as an inspector reads it in the file; the right column is the correction that would have changed the outcome. The operational risk management framework carries the same defect classes under different names.

Defect	How it shows up	Correction
HAZOP node never studied	The blocked-outlet deviation is absent from the worksheet for a liquid-full transfer line	Re-run HAZOP on every isolatable segment; add blocked-in liquid as a standard deviation
Test-and-forget on relief valves	PSV bench-tested, block valve left shut, no car seal, no return-to-service record	Car-seal register with dual sign-off; PSV status in the control system; quarterly audit
Commissioning alarms retired	Temperature indicators used for cool-down are disabled after start-up	Repurpose commissioning instruments as operating alarms; document in the alarm rationalization
Start-up treated as normal operation	No pre-startup safety review after a six-month turnaround; the Barzan restart	PSSR gate with sign-off before any hydrocarbon introduction; extra staffing for the first 72 hours
Dormant asset reactivated on assumption	A line idle since 2012 is pigged with gas reinjected and a valve line-up unverified; the Delfin rupture	Reactivation hazard study; physical valve verification; hydrotest before gas
Zones modeled once, never revisited	The 2.5 percent cloud and thermal contours date from the original permit despite new tanks and a larger jetty	Re-run Part 193 models on every layout change and every NFPA 59A edition change
Fatigue scored nowhere	Excessive overtime named as a contributing cause, but hours never appear in the register	Track overtime as a KRI; set a hard limit for control-room shifts during commissioning

The third and fourth defects share a cause: instruments and procedures built for one operating mode are dropped when the mode changes. The risk management lifecycle treats a mode change as an LNG risk assessment review trigger, and the risk factor guide explains why staffing hours are a factor to score, with a limit attached.

Frequently Asked Questions About LNG Risk Assessment

What does an LNG risk assessment include?

An LNG risk assessment includes a release inventory for every tank, line, arm and vaporizer, a HAZID and HAZOP over those nodes, consequence models for pool fire, vapor dispersion, BLEVE and rapid phase transition, a quantified register against acceptance criteria, and the safeguard and exclusion-zone decisions. For US facilities it also includes the Part 193 siting analysis and the Coast Guard’s waterway suitability assessment.

Which standards govern an LNG risk assessment in the United States?

An LNG risk assessment in the United States follows 49 CFR Part 193 and NFPA 59A for onshore plants, 33 CFR Part 127 for waterfront facilities, FERC Resource Report 13 for export projects, and ISO/TS 16901 as the international method for the ship-shore interface. Bunkering follows ISO/TS 18683; carriers follow the IMO IGC and ISPS Codes. The types of risk assessment article places these among the wider families.

How is an LNG risk assessment different from a HAZOP?

A HAZOP is one input: a node-by-node search for deviations and their safeguards. The LNG risk assessment takes those deviations, models their consequences, attaches frequencies, and compares the result with acceptance criteria and legal exclusion zones. Freeport had a HAZOP; the assessment failed because one deviation, a blocked-in liquid segment, was never raised in it.

How far do LNG exclusion zones extend?

Each zone in an LNG risk assessment is calculated, never fixed. The vapor zone runs to where the design-spill cloud falls below 2.5 percent methane under a 4.5 mph wind and Pasquill F conditions; the thermal zone follows LNGFIRE3 flux limits under the worst weather above the 5 percent exceedance. Sandia’s carrier work gives 500 and 1,600 meters as near-shore markers for spills on water.

How often should an LNG risk assessment be updated?

An LNG risk assessment is updated on every layout change, new train, jetty upgrade, vessel size change, reactivation of an idle asset and NFPA 59A edition change, and at least every five years. PHMSA’s 2025 ANPRM and the pending Part 193 rewrite will each trigger a review at every regulated facility. The risk assessment program article builds these triggers into an annual cycle.

Who is responsible for an LNG risk assessment?

The operator owns the LNG risk assessment, in law and in practice: PHMSA’s Freeport order went to the company’s chairman and chief executive, and the penalty attached to the operator’s procedures, monitoring and valve testing. Consultants model and facilitate; the operator signs the basis of assessment, owns the register and answers for it. The crisis management comparison covers what happens when that ownership is unclear.

The Road to 2030: New Trains and a Rewritten Part 193

By 2030 the IEA expects about 300 bcm a year of new liquefaction capacity, most of it in the United States and Qatar, and EIA projects US exports of 18.7 Bcf/d by the first half of 2027. Each train will need an LNG risk assessment under a Part 193 that PHMSA intends to rewrite; comments closed on July 7, 2025.

Expect the rewrite to adopt NFPA 59A 2023 or its successor, which moves the release probabilities and QRA route from voluntary to referenced. Operators who have run Chapter 19 on their layout will file an update; those still on 2001-edition distances will model from scratch. The mitigation strategies guide and the risk mitigation article cover the safeguard choices that follow.

Schedule the next LNG risk assessment around the next start-up, whatever the calendar says. Ras Laffan, Delfin and Freeport were all mode changes: a restart, a reactivation, and a routine transfer after a valve test. The risk analysis guide and the petroleum exploration risk article show how upstream and midstream teams frame the same decision.

For an operator, port or bunkering supplier that needs an LNG risk assessment register built to ISO/TS 16901 and Part 193, we facilitate the study with the site engineers and return the register, exclusion-zone summary and review calendar. The services page describes the formats and the contact page is the first step. Send the last PSV test record with the first message.