A floating liquefied natural gas (FLNG) facility is a ship-shaped or barge-like floating unit that produces LNG directly offshore by combining gas reception, treatment, liquefaction, storage, and export on one floating asset. Technically, the biggest differences versus onshore are motion and space constraints: equipment must tolerate vessel motions, limited plot area, weight limits, and tighter maintainability access. FLNG also relies on marine systems, such as turrets or spread moorings, marine offloading hardware, and shipboard utilities for power, seawater cooling, and safety systems. The design emphasis shifts toward modularized topsides, robust shutdown/isolation philosophy, and safe transfer to LNG carriers at sea without a permanent jetty.
Reference: https://www.shell.com/what-we-do/oil-and-natural-gas/liquefied-natural-gas-lng/floating-lng.html
Before liquefaction, FLNG typically pre-treats feed gas to prevent freezing, corrosion, and operational upsets in cryogenic equipment. Common steps include inlet separation to remove free liquids and solids, acid gas removal (CO₂ and H₂S), dehydration to extremely low water content, mercury removal to protect aluminum exchangers, and hydrocarbon dewpoint control (often including NGL/LPG recovery depending on the project). Offshore, pre-treatment robustness matters even more because upset recovery can be slower, equipment redundancy is limited by space/weight, and continuous operation is economically vital. Pre-treatment also stabilizes liquefaction performance: impurities increase refrigeration duty, risk hydrate/ice formation, and can cause exchanger plugging or brittle failures at low temperatures.
Reference: https://ww2.eagle.org/content/dam/eagle/rules-and-guides/archives/offshore/169-requirements-for-building-and-classing-floating-offshore-liquefied-gas-terminals-2024/169-flgt-guide-jan24.pdf
FLNG liquefaction cycles are chosen to balance efficiency, footprint, operability, and motion tolerance. Mixed-refrigerant cycles (single MR or dual MR) are widely used because they can achieve high efficiency and compactness by matching refrigerant temperature glide to natural gas cooling needs. Nitrogen expander cycles are simpler, avoid hydrocarbon refrigerants, and can be attractive for smaller capacities or where simplicity and safety are prioritized, but they are usually less energy-efficient. Selection is driven by capacity, ambient conditions, feed composition, available power, equipment modularization strategy, and how the process handles turndown and transient conditions caused by offloading or weather. Offshore execution also favors proven, modular equipment packages that can be integrated, maintained, and restarted reliably at sea.
Reference: https://www.igu.org/news/flng-report-2015-2018
Vessel motions (heave, pitch, roll, and accelerations) affect rotating machinery, liquid levels, separation efficiency, and control stability. Designers address this by selecting motion-tolerant equipment (e.g., separators and columns with higher margins), using slosh-resistant internals, adding surge volumes, and implementing advanced control strategies to dampen disturbances. Layout and module design also matter: heavy rotating equipment is positioned to minimize dynamic loads, piping is routed with flexibility for fatigue, and supports are engineered for cyclic stresses. In addition, marine engineering (station-keeping, thrusters used, and hull design) is integrated with process design to reduce motions during critical operations, such as offloading. Classification rules and risk-based design practices typically require explicit evaluation of seakeeping and fatigue for offshore gas units.
Reference: https://www.dnv.com/rules-standards/
FLNG storage must keep LNG near −162°C while safely managing thermal contraction, boil-off, and sloshing. Containment approaches include membrane systems (common in LNG carriers) and independent tanks, with selection depending on hull form, capacity, and sloshing environment. Key considerations include sloshing loads during partial fill levels, fatigue life of insulation and barriers, compatibility with offshore motions, and safe management of vapors and pressure. Designers also consider segregation distances, spill containment and drainage, fire and gas detection, and emergency shutdown isolation between storage and process areas. Because FLNG is both a production facility and a “gas carrier–like” storage unit, designs often align with marine LNG containment expectations while integrating topsides hazards and offshore safety case requirements.
Reference: https://www.imo.org/en/ourwork/safety/pages/igc-code.aspx
Boil-off gas is vapor generated as LNG absorbs heat through insulation, piping, and tank penetrations, and it can increase during loading/offloading or sloshing. On FLNG, BOG management is central because uncontrolled pressure rise is a safety issue and venting wastes product while increasing emissions. Typical strategies include compressing BOG and routing it to fuel gas systems for power generation, re-liquefaction systems that condense BOG back to LNG, or using it as refrigerant makeup in some designs. The control philosophy must coordinate tank pressure, refrigeration availability, and ship-loading schedules. Efficient BOG handling improves overall plant efficiency because liquefaction power is substantial; every avoided vent or flare event preserves saleable LNG and reduces carbon intensity. Guidance and class documents treat BOG systems as critical for both safety and operability.
Reference: https://ww2.eagle.org/en/Products-and-Services/offshore-energy/floating-liquefied-natural-gas.html
A turret mooring is a rotating connection point (often internal or external) that allows an FLNG vessel to weathervane—turn freely to align with wind, waves, and current—while staying anchored to the seabed via multiple mooring lines. The turret often also houses fluid transfer paths through swivels, enabling produced fluids and utilities to pass between the stationary mooring system and the rotating vessel. This arrangement reduces environmental loading, improves station-keeping, and supports safer operations in variable conditions, including cyclone-prone regions where design may target extreme storms. Turret systems must be engineered for fatigue, swivel reliability, and maintainability, as failures can halt production. Public project disclosures around large FLNGs highlight turret functionality as a key enabler of long-term offshore operation and 360-degree rotation capability.
Reference: https://www.sbmoffshore.com/newsroom/prelude-flng-turret-designed-sbm-offshore-fully-operational/
Offshore LNG export requires controlled transfer from the FLNG to LNG carriers using cryogenic loading arms or hoses, with strict emergency release and shutdown capabilities. Transfer configurations can include side-by-side berthing with fenders and loading arms, or tandem arrangements using cryogenic hoses and specialized connection systems, depending on sea state, vessel motions, and operability targets. Key risk-reduction technologies include redundant ESD (emergency shutdown) links, quick connect/disconnect couplers, emergency release systems that separate without major spills, continuous monitoring of relative motions, and clear exclusion zones with tug support where needed. Procedures and training are as important as hardware: transfer windows, mooring analysis, and communication protocols are tightly defined. Industry guidance for ship-to-ship transfer practices provides widely used frameworks for planning, equipment, and safe execution of liquefied gas transfers.
Reference: https://www.sigtto.org/publications/ship-to-ship-transfer-guide-for-petroleum-chemicals-and-liquefied-gases/
FLNG sits at the intersection of offshore production and gas carrier storage/transfer, so technology choices are heavily shaped by classification society requirements and international maritime safety codes. Classification rules govern structural strength, fatigue, stability, fire safety, hazardous-area classification, and the verification of critical systems such as containment, station-keeping, and transfer equipment. International codes like the IMO IGC Code establish baseline safety expectations for liquefied gas containment and associated ship systems, influencing materials, segregation, and safety equipment. In practice, these frameworks push conservative design margins and formal safety justification, often via risk assessment and safety case-style documentation. They also influence equipment selection toward proven, certifiable solutions that can be surveyed and maintained throughout life-of-field operation. Because FLNG projects involve multiple jurisdictions, aligning early with class and code requirements reduces redesign risk and schedule surprises.
Reference: https://www.imo.org/en/OurWork/Environment/Pages/IGCCode.aspx
Liquefaction is power-hungry, so FLNG typically includes large gas turbine generators or gas engines, often fueled by treated gas or boil-off gas. Power demand fluctuates with ambient temperature, feed conditions, and operating mode (start-up, steady state, offloading), so electrical systems must handle dynamic loads, harmonics, and high availability requirements. Power generation placement influences layout because turbines require air intake/exhaust routing, noise control, hazardous-area segregation, and fire protection, while also minimizing vibration and maintenance constraints. From an emissions standpoint, power generation is often the largest source of CO₂ at an LNG facility, so efficiency improvements, waste heat recovery concepts, and reduced flaring/venting through effective BOG handling can materially lower the facility's carbon intensity. Many classification and industry frameworks treat power systems as safety-critical, given their role in maintaining refrigeration, controls, and emergency systems.
Reference: https://www.datocms-assets.com/146580/1751026179-igu-world-lng-report-2025-hr_dp_c.pdf
Modularization means designing the FLNG topsides as large prefabricated modules—process, utilities, living quarters, flare, compression—built and pre-commissioned onshore, then lifted and integrated onto the hull. This approach reduces offshore hook-up work, improves quality control, and can compress the schedule by parallelizing hull construction and topsides fabrication. The technical challenge is integration: modules must connect via piping, electrical, and control interfaces while meeting weight, center of gravity, and motion limits. Designers also plan for maintainability and safe access because congested modules can complicate routine inspections and repairs. Reliability is influenced by how redundancy is distributed across modules and how isolation/shutdown boundaries are defined. Classification guides for floating liquefied gas terminals emphasize verification of structural interfaces, fatigue, and safety systems across the integrated hull–topsides system, reflecting how modularization changes failure modes and inspection planning.
Reference: https://marine-offshore.bureauveritas.com/offshore/offshore-classification/flngs-floating-liquefied-natural-gas-units
FLNG feed gas is delivered from subsea wells or nearby platforms through pipelines and risers, which must accommodate vessel motions and maintain integrity under cyclic loads. Depending on the concept, designers may use flexible risers, rigid risers with motion-compensating arrangements, and subsea flowlines with insulation or heating to manage hydrates and wax. The interface between the turret (if used) and the riser system is critical, as it combines station-keeping loads, fluid transfer, and fatigue considerations in a single location. Flow assurance is a key driver: unstable arrival conditions, slugging, or hydrate formation can disrupt pre-treatment and liquefaction. Because repairing offshore structures is costly, riser systems are designed with conservative fatigue-life targets and monitoring. Classification and offshore technical guidance frameworks generally require explicit assessment of station-keeping, coupled analyses, and integrity management for the integrated floating production system.
Reference: https://www.dnv.com/maritime/offshore-classification/floating-production/
FLNG combines complex cryogenic processing with marine operations, so automation must cover process control (liquefaction, refrigeration, compression), marine systems (position, ballast, mooring monitoring), cargo handling (tank pressure/levels), and export transfer (ESD links to carriers). Typical architecture includes a distributed control system (DCS) for normal operations, a safety instrumented system (SIS) for protective functions, and dedicated fire and gas detection tied to shutdown and deluge systems. The ESD philosophy often uses layered shutdown levels to isolate parts of the plant, stop transfer, and safely depressurize while maintaining essential utilities. Offshore, reliable communications and clear cause-and-effect matrices are essential because simultaneous hazards—process leaks, transfer operations, and weather—can escalate quickly. Class and industry guidance for floating liquefied gas terminals emphasizes the verification of safety systems, hazardous-area management, and reliable shutdown interfaces as central to maintaining tolerable risk on a densely packed facility.
Reference: https://ww2.eagle.org/content/dam/eagle/rules-and-guides/archives/offshore/169-requirements-for-building-and-classing-floating-offshore-liquefied-gas-terminals-2024/169-flgt-guide-jan24.pdf
FLNG must safely dispose of hydrocarbons during start-up, shutdown, and emergencies while managing radiant heat, smoke, noise, and dynamic loads on a moving vessel. Flare systems are positioned to keep heat and combustion products away from LNG storage, living quarters, and critical air intakes. Depressurization (blowdown) design must balance rapid pressure reduction with limits on temperature drop, vibration, and backpressure, especially given the tight module packing. Because LNG containment introduces cryogenic hazards, segregation and spill/fire protection are carefully engineered to prevent a process event from propagating to storage tanks or transfer manifolds. Offshore constraints often mean fewer disposal options than onshore, so designers emphasize minimizing routine flaring through stable operations, robust BOG handling, and controlled start-up sequences. Classification and safety guidance for floating liquefied gas terminals typically treats flare and vent systems as major hazard controls requiring rigorous verification and integration with ESD logic. Reference: https://marine-offshore.bureauveritas.com/offshore/offshore-classification/flngs-floating-liquefied-natural-gas-units
Megascale FLNG has been enabled by advances in compact, modular liquefaction trains; large-capacity refrigeration compressors and drivers; high-integrity turret mooring and swivel systems; and improved LNG containment and offloading solutions suitable for offshore conditions. Integration engineering has also matured, combining seakeeping, fatigue, and process safety into a unified design approach. Remaining bottlenecks often relate to operability and reliability at scale: maintaining high uptime in a harsh marine environment, managing complex start-up and shutdown sequences, and ensuring maintainability in congested modules over the long term. Offloading availability can be limited by weather windows, and long-term integrity management must address fatigue, corrosion, and cryogenic system aging. Industry reports tracking FLNG evolution note how concepts have differentiated over time by capacity, execution model, and risk allocation, reflecting both technological progress and ongoing constraints.
Reference: https://www.shell.com/what-we-do/oil-and-natural-gas/liquefied-natural-gas-lng/floating-lng.html
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Getting an FLNG from the yard to the site is usually a marine “sailaway” or tow-out operation planned like a major offshore campaign. Some units can sail under their own power for parts of the voyage, but many large floaters are escorted and/or towed by multiple ocean-going tugs to manage speed, redundancy, and emergency response capability. The transportation plan typically covers route selection, weather windows, towline configuration, emergency tow arrangements, bunkering, and safe-haven ports, plus class and flag requirements. Because FLNG topsides are heavy and the unit is high-value, voyage risk management is intensive, with strict limits on sea states and clear abort criteria. Reference: https://www.technipfmc.com/en/media/news/2017/06/the-shell-prelude-facility-has-sailed-away-to-australia/
“Wet tow” means the floater travels in the water, either towed or under limited own power, while “dry tow” means it is carried on a heavy-lift ship (kept out of the water). Dry tow can reduce fatigue and weather exposure for some hulls and structures, but it is constrained by floater size/weight and heavy-lift availability, and it adds complex load-out and seafastening steps. Wet tow is more common for very large floaters and typically involves tug spreads, escort arrangements, and strict metocean criteria. Self-propelled transit may be possible for some ship-shaped units, but even then, tug support is often retained for redundancy and close-quarters maneuvering near the field. Reference: https://www.dnv.com/maritime/offshore-classification/floating-production/
Conversion projects start with a trading LNG carrier hull, then add large topside modules, sponsons, and new marine systems. That can change the unit’s aerodynamic profile, displacement, stability envelope, and tow/sailaway constraints compared with the original carrier. During deployment, the converted unit often performs progressive commissioning steps—first alongside the yard, then at a deep-water anchorage, then en route, and finally at the field—so “transport” and “commissioning” are operationally linked. Conversions can shorten the schedule compared to newbuilds, but the transportation plan must explicitly account for new windage, altered motion response, and added interfaces (offloading gear, mooring hardware). Public conversion disclosures for early FLNG projects show how sailaway and staged commissioning were integral parts of the deployment concept. Reference: https://www.keppel.com/media/keppel-to-deliver-world-s-first-floating-liquefaction-vessel-conversion/
Beyond the FLNG itself, field installation commonly requires specialized marine assets. Tugs and anchor-handling tug supply (AHTS) vessels support positioning, tow-assist, and line-handling. A mooring installation vessel (or multiple AHTS) may pre-lay anchors and mooring lines, while construction support vessels handle subsea works, ROV operations, and tie-ins. Depending on the concept, heavy-lift vessels may be used earlier for module integration or occasionally for major replacements during the life-of-field. The marine spread is planned to match the station-keeping design (turret or spread moor), the subsea architecture, and the local metocean conditions. Class guidance for position mooring systems and floating liquefied gas terminals highlights how these vessel roles connect directly to verification of mooring integrity, line installation, and operational readiness. Reference: https://ww2.eagle.org/content/dam/eagle/rules-and-guides/archives/offshore/292-position-mooring-systems/292-position-mooring-reqts-july22.pdf
The most established offshore export concept for FLNG is side-by-side transfer to an LNG carrier, using marine berthing arrangements, fendering, and cryogenic loading arms designed for relative motions. This resembles terminal-style loading but is adapted for offshore use, with tight control of approach, mooring loads, and emergency shutdown linkages between the two vessels. The transfer system must manage very cold LNG, minimize spill risk, and allow rapid disconnection if conditions deteriorate. Because transfer uptime heavily affects project economics, the design usually targets an operability envelope tied to wave height, wind, current, and vessel motions. Industry discussions and guidance note that side-by-side has been more practical to mature than tandem LNG transfer in many cases, largely because rigid arms and proven manifolding concepts can be adapted with careful motion management. Reference: https://onepetro.org/OTCONF/proceedings-pdf/04OTC/04OTC/1854774/otc-16281-ms.pdf
Tandem offloading (carrier behind the FLNG) is attractive where side-by-side berthing is too limiting or risky, but LNG tandem transfer is technically demanding because cryogenic fluids and rapid emergency separation must be handled under dynamic conditions. The enabling technologies are typically cryogenic hose systems (including floating hose concepts), robust connection/disconnection hardware, and control/monitoring systems that manage relative motion and loads. Tandem arrangements can reduce collision risk versus side-by-side in some metocean regimes, but they introduce new challenges in hose dynamics, fatigue, and maintaining cryogenic integrity over distance. Engineering literature and industry articles emphasize that cryogenic hose development has been a key pathway for making tandem LNG transfer more feasible offshore, though project-specific verification and operability assessment remain essential. Reference: https://jpt.spe.org/cryogenic-hose-technology-transfer-solutions-keep-pace-march-lng
Ship-to-ship transfer is governed less by a single “LNG-only” rulebook and more by cross-industry best-practice frameworks covering planning, risk assessment, communications, mooring, equipment readiness, and emergency response. For LNG, the guidance needs to reflect cryogenic hazards and vapor management, but the operational discipline is shared with other bulk liquids: defined roles, compatible procedures, agreed shutdown logic, and a structured pre-transfer checklist culture. The STS guide, jointly developed by bodies such as ICS, OCIMF, SIGTTO, and CDI, is widely referenced for operational governance, while mooring-focused guidance (such as OCIMF’s MEG) supports the safe design and operation of mooring arrangements, which are central to STS. Together, these documents shape how offshore LNG transfers are executed safely and consistently. Reference: https://www.sigtto.org/publications/ship-to-ship-transfer-guide-for-petroleum-chemicals-and-liquefied-gases/
Carrier selection is not just commercial; it’s a marine interface engineering decision. The receiving LNG carrier must be compatible with the FLNG’s transfer configuration (manifold height/arrangement, ESD links, communications), mooring loads, and approach limits. Preparation includes verifying cargo containment readiness, ensuring crew competence with offshore transfer procedures, confirming equipment certification and testing (including ESD and emergency release functions), and aligning detailed operational procedures between the two vessels. The carrier’s maneuvering capability, tug support plan, and weather limits also matter because offloading often drives overall uptime. STS guidance emphasizes the importance of rigorous compatibility checks, agreed “who’s in charge” command structures, and disciplined pre-berthing planning to reduce human-factor and interface risks that can dominate offshore transfers. Reference: https://www.ocimf.org/publications/books/ship-to-ship-transfer-guide-for-petroleum-chemicals-and-liquefied-gases
During export, the LNG carrier must be held in a controlled relative position to the FLNG within tight tolerances, because cryogenic connections have limited allowable movement and the consequences of loss of station can be severe. Side-by-side export relies on a combination of mooring lines, fender systems, and sometimes tug assistance to manage relative motion and prevent contact damage. Mooring design needs to account for dynamic environmental loads, line strength and elasticity, winch and brake performance, and safe line-handling practices. OCIMF’s mooring guidance is frequently used as a baseline for mooring equipment capability and safe design margins, while class guides for floating liquefied gas terminals integrate mooring verification into the overall safety framework. The practical outcome is that mooring is often a first-order limiter of operability. Reference: https://www.ocimf.org/publications/books/mooring-equipment-guidelines-meg4
Offshore LNG export is fundamentally constrained by metocean conditions because both the FLNG and the carrier move, and transfer hardware has finite motion tolerance. Operators define “operability envelopes” tied to wave height/period, wind and current, visibility, and lightning risk. If conditions exceed limits, approach, berthing, or transfer is paused, and the system may need to disconnect to maintain safety. The effect is that production, storage management, and shipping schedules must be integrated: if export is delayed, tanks fill, and boil-off management becomes more stressed, potentially forcing production curtailment. This is why offshore LNG transfer studies focus heavily on motion analysis and limiting criteria, and why industry commentary often highlights the challenge of transferring cryogenic fluids between moving ships compared with conventional oil tandem offloading. Reference: https://www.bmt.org/insights/operational-considerations-of-flng/
Many FLNG developments can produce more than LNG. Depending on feed composition and process design, export streams may include condensate (stabilized liquid hydrocarbons) and, in some cases, LPG components. These products are typically exported by shuttle tankers or product tankers using marine transfer systems suited to the fluid and safety case. Condensate export is often closer to FPSO-style liquid transfer practice, with different equipment and operability considerations than cryogenic LNG. This matters for logistics because it can add vessel calls, separate transfer windows, and additional marine risk interfaces, but it can also improve project economics by monetizing liquids. Classification guidance for floating liquefied gas terminals and offshore production units addresses cargo handling and transfer as part of the integrated design, reflecting that “transport” is multi-product and concept-specific, not LNG-only.
Reference: https://ww2.eagle.org/content/dam/eagle/rules-and-guides/archives/offshore/169-requirements-for-building-and-classing-floating-offshore-liquefied-gas-terminals-2024/169-flgt-guide-jan24.pdf
Even though FLNG is a gas facility, it operates like a small floating town with continuous logistics needs. Routine transport typically uses offshore supply vessels for cargo, consumables, and spares, while helicopters may be used for crew changes, depending on the distance to shore and the availability of aviation infrastructure. Weather, deck layout, crane capacity, and marine traffic management all influence how safely and frequently these logistics runs can happen. The transport plan also includes waste backload, specialist technician mobilization, and contingency support for abnormal situations. While these movements aren’t “export,” they are essential to maintaining uptime because a critical spare part or specialist intervention can prevent extended production loss. Class and offshore guidance frameworks treat marine operations and interface management as part of the overall safety and reliability picture for floating production systems, including FLNG. Reference: https://www.dnv.com/maritime/offshore-classification/floating-production/
FLNG units create a concentrated marine operating area: LNG carriers approach and berth, supply vessels shuttle in and out, and sometimes tugs or standby vessels remain on station. To reduce collision risk, projects often establish exclusion or safety zones, define approach corridors, and use active monitoring (AIS, radar, guard vessels) with clear communication protocols. These controls are especially important because the consequences of collision near hydrocarbon processing and LNG storage can be severe, and because the unit’s ability to maneuver may be limited when moored. Traffic management is also tied to offloading operations, where specific “no-go” sectors and emergency departure paths are planned in advance. While local regulations vary, class and terminal guidance typically expect a structured marine operations plan that integrates navigational risk assessment with mooring, transfer, and emergency response arrangements.
Reference: https://ww2.eagle.org/content/dam/eagle/rules-and-guides/archives/offshore/169-requirements-for-building-and-classing-floating-offshore-liquefied-gas-terminals-2024/169-flgt-guide-jan24.pdf
Offshore projects plan for scenarios in which a vessel must be assisted quickly: loss of propulsion while approaching an LNG carrier, deteriorating weather during berthing, or abnormal mooring loads that require controlled separation. Standby tugs or support vessels can provide escort, push/pull assistance, and emergency towing, reducing the time required to regain control in fast-changing conditions. Emergency towing arrangements, towline readiness, and clear decision triggers are important because reaction time is often the difference between a safe disconnect and an escalating incident. For large floaters, even if the FLNG itself is not expected to “sail away” in an emergency, the ability to manage nearby vessel movements is critical to protecting the asset and its personnel. Marine operations guidance and STS frameworks emphasize that preparedness, drills, and equipment readiness underpin safe outcomes under time pressure.
Reference: https://www.sigtto.org/publications/ship-to-ship-transfer-guide-for-petroleum-chemicals-and-liquefied-gases/
One attraction of floating concepts is potential redeployment, but relocation or removal is still a major marine campaign. The process typically includes decommissioning and making safe (purging, isolations), disconnecting risers and subsea umbilicals, recovering or disconnecting mooring lines and anchors (or leaving some infrastructure as permitted), and then towing or sailing the unit to a new site or lay-up yard. Transport planning resembles initial deployment but can be more complex because the unit may have aging equipment, modified weight distribution, and different certification requirements after years in service. The end-of-life plan must also address environmental and regulatory obligations that vary by jurisdiction. Classification societies provide frameworks for floating production units that cover life-cycle integrity, surveys, and re-certification considerations that influence how smoothly a relocation or removal can proceed. Reference: https://www.dnv.com/maritime/offshore-classification/floating-production/
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FLNG combines a full LNG process plant, large hydrocarbon inventories, and marine operations on a single floating structure. As a result, major accident hazards combine conventional offshore gas risks with LNG-specific cryogenic effects. Key hazards are loss of containment of high-pressure gas, LNG, or refrigerant releases that cause vaporization and flammable clouds, jet fires, pool fires, and explosions in congested modules. Cryogenic spills can embrittle steel and damage equipment supports, worsening the event. Because accommodation and process areas are often close, escalation control and passive fire protection are crucial. Safety assessments show that proximity, congestion, and motion can amplify consequences unless layout, isolation, detection, and shutdown systems are exceptionally robust. Reference: https://www.aidic.it/cet/13/31/100.pdf
Cryogenic releases on FLNG are challenging because LNG (and some refrigerants) can flash rapidly, creating cold, dense gas clouds that may travel along decks and into congested areas before warming and dispersing. The cloud behavior depends on wind, obstacles, and deck geometry, and the same congestion that improves compactness can worsen dispersion and explosion potential. Cryogenic liquid can also damage coatings, insulation, and metallic structures through thermal shock and embrittlement, undermining barriers meant to prevent escalation. Offshore motion adds complexity by changing pooling patterns and affecting drainage and containment. Safety assessments typically require careful modeling of dispersion, ignition likelihood, and escalation pathways, along with robust detection, drainage, spill containment, and rapid isolation to prevent a leak from becoming a large flammable event. Reference: https://www.icheme.org/media/8585/xxiv-paper-03.pdf
Fire and explosion scenarios influence where modules, tanks, accommodation, and critical utilities are placed, because FLNG has limited deck space and short separation distances compared with onshore plants. Designers typically evaluate jet fires from pressurized gas, pool fires from condensate or LNG spills, and vapor cloud explosions in congested process areas. The key is controlling escalation: preventing a local event from impairing emergency shutdown, power, firewater, or safe evacuation routes. Explosion risk analysis is often used to assess overpressure loads on structures and to guide blast-resistant design, congestion management, and ventilation paths. These studies can inform decisions such as orienting high-risk equipment downwind of accommodation, using fire walls and passive fire protection, and ensuring that critical safety systems remain operable during credible worst-case scenarios. Reference: https://www.aidic.it/cet/13/31/100.pdf
FLNG start-up and ramp-up often reveal reliability issues that are less prominent onshore because equipment operates on a moving platform exposed to salt, humidity, vibration, and cyclic loads. Marine motions can affect the behavior of rotating equipment, liquid levels in vessels, and control stability, while corrosion and fatigue can accelerate wear. Because the facility’s value is tied to uptime, early operational milestones, such as first gas, first LNG, and sustained production rates, can be delayed by trips, power system faults, or integration issues between process and marine systems. Real-world operations history shows how commissioning is frequently iterative, with “stop, fix, validate, restart” cycles until stable operation is achieved. Managing these challenges typically requires strong condition monitoring, conservative operating envelopes, and rigorous maintenance planning from day one. Reference:https://www.shell.com.au/media/2019-media-releases/first-lng-cargo-shipped-from-prelude-flng.html
While terminology varies by operator, FLNG projects commonly track milestones that reflect progressive risk reduction. After mechanical completion and pre-commissioning at the yard, there is often tow-out or sailaway to the site, followed by hook-up and offshore commissioning. “First gas” marks initial receipt of feed gas into the facility, then “first LNG” or “first LNG drop” indicates that liquefaction and cryogenic handling have been achieved. “First cargo” is a major commercial milestone because it proves offshore offloading operations and end-to-end logistics. After the first cargo, operators typically enter a performance test and ramp-up period to demonstrate sustained rates, reliability, and product specs. Public operator releases for operating FLNGs clearly illustrate these stages, including specific dates for first gas and first cargo. Reference: https://www.petronas.com/media/media-releases/first-gas-petronas-first-floating-lng-facility-pflng-satu
Offloading is often the operational bottleneck because it depends on weather windows, vessel compatibility, mooring performance, and the integrity of cryogenic transfer systems. The dominant hazards include collision or contact during approach and berthing, loss of position leading to overstress of loading equipment, LNG leakage with vapor cloud formation, and failure to disconnect safely during a rapid weather deterioration. Human factors are also central because offloading requires precise coordination between two marine crews and the facility’s control room under time pressure. Many projects treat the first successful offloading as a milestone nearly equal to the first LNG, because it validates that the facility can reliably export product without frequent aborts. Industry guidance for ship-to-ship transfer emphasizes rigorous planning, emergency release readiness, and disciplined procedures to keep transfer risks within tolerable limits. Reference:https://www.sigtto.org/publications/ship-to-ship-transfer-guide-for-petroleum-chemicals-and-liquefied-gases/
A safety case is a structured demonstration by the operator that major hazards have been identified, risks are controlled to an acceptable level, and the facility can be operated safely with a robust management system. For FLNG, the safety case is especially important because it must integrate process safety, marine safety, emergency response, and life-saving systems for a densely packed facility with LNG-specific hazards. In safety-case regimes, acceptance by the regulator can be a hard milestone, gating commissioning, start-up, or continued operation. The safety case typically draws on hazard identification, quantitative risk assessment, fire and explosion analysis, and operational assurance, and it is updated as the facility changes. Regulatory materials outlining offshore safety case expectations demonstrate that verification, validation, and lifecycle management are embedded in the approval framework for offshore facilities. Reference:https://www.parliament.wa.gov.au/publications/tabledpapers.nsf/displaypaper/3912891aedf89f67eb735af348257e3e002eb6ca/%24file/2891.pdf
Compactness is economically attractive offshore, but congestion increases explosion risk because it can trap and accelerate flames, raising overpressure in a vapor cloud explosion. FLNG topsides often place compressors, heat exchangers, piping, and utilities within limited footprints, which can increase confinement and create complex wind flows that influence gas accumulation. As a result, designers rely heavily on explosion risk analysis to assess credible gas cloud sizes, likely ignition points, and structural vulnerability. The findings influence ventilation paths, equipment spacing, blast wall design, and the robustness of emergency shutdown and depressurization. Escalation control also includes ensuring that a blast does not disable power, communications, or fire and gas detection needed for safe response. Technical literature on explosion risk analysis for FLNG highlights how the proximity of process equipment and accommodation requires especially careful design to maintain tolerable risk. Reference: https://www.aidic.it/cet/13/31/100.pdf
On FLNG, LNG storage is not a passive terminal function; it sits adjacent to ongoing liquefaction, compression, and utilities, creating tight coupling between process upsets and cargo conditions. Storage introduces boil-off gas management needs, tank pressure control, and cryogenic integrity requirements, while processing areas introduce ignition sources and higher leak frequencies. The combined system raises escalation concerns, for example, a process fire impairing cargo systems or a cargo system event affecting utilities and safe areas. This coupling also complicates shutdown philosophy because some functions must remain alive long enough to keep tanks within safe limits even as the process is isolated. Formal safety assessments for FLNG frequently emphasize the need for strong segregation, resilient safety systems, and clear isolation boundaries to prevent a single failure from propagating across the facility. Reference: https://www.icheme.org/media/11821/hazards-26-poster-16-hazards-within-lng-floating-facilities-topside-design.pdf
Liquefaction depends on continuous, stable power for refrigeration, compression, controls, and essential safety functions. Electrical disturbances can trigger plant-wide trips, and on FLNG, a trip can cascade into production shutdown, increased flaring, and pressure management challenges as inventories and boil-off must be controlled safely. Restart can be complex because refrigeration trains, compressors, and control sequences require careful synchronization, and offshore access to specialists and spares can be limited. The operational history of large FLNGs shows that unexpected trips and subsequent investigation and repair periods can materially affect annual output and timelines for sustained performance. This is why “stable operations” after the first cargo is often treated as a milestone distinct from the first LNG itself. Reliable electrical design, redundancy, and robust black-start and restart procedures are therefore central to both safety and commercial success. Reference: https://www.rivieramm.com/news-content-hub/news-content-hub/shell-suspends-production-at-prelude-flng-71961
FLNG structures and piping face cyclic loads from waves and vessel motions, creating fatigue risks, while the marine environment accelerates corrosion. On top of that, cryogenic handling introduces thermal cycling, increased risk of insulation degradation, and potential embrittlement if spills contact unsuitable materials. These threats drive inspection and maintenance milestones such as class surveys, integrity reassessments, and periodic shutdowns for major maintenance. Operators typically develop risk-based inspection programs targeting high-consequence areas like transfer manifolds, cold boxes or cryogenic exchangers, rotating equipment foundations, and mooring/risers. Because offshore repair is expensive and downtime is costly, early detection through monitoring and planned intervention is central. Classification frameworks for floating production units set expectations for survey regimes and ongoing verification, which, in practice, become schedule-defining milestones throughout the facility’s operating life. Reference: https://www.dnv.com/maritime/offshore-classification/floating-production/
FLNG projects typically pass through a sequence of structured safety and risk milestones that mature as the design progresses. Early hazard identification helps shape layout and concept selection, followed by more detailed operability and hazard studies that test control philosophy, isolation, and maintainability. Quantitative risk assessment, fire and explosion analysis, and cryogenic risk assessment are often key gates before the final design freeze and again before commissioning. The outputs translate into tangible design requirements such as blast ratings, passive fire protection, detection coverage, depressurization capacity, and safe escape and evacuation provisions. Offshore-specific considerations, such as motion, ship-to-ship transfer, and marine traffic interfaces, are integrated into the risk picture. Technical papers discussing formal safety assessment experience for FLNG highlight recurring issues, including the need for appropriate leak frequency data, modeling of cryogenic releases, and validation of assumptions through realistic offshore scenarios. Reference: https://www.icheme.org/media/8585/xxiv-paper-03.pdf
Relocation is attractive because it can extend asset value, but it introduces a distinct set of hazards and milestones. The facility must be made safe for transit, including purging, isolating, and securing cryogenic systems, then disconnecting risers and moorings and verifying hull and topsides readiness for tow or sailaway. At the new field, re-hookup and recommissioning repeat many start-up risks, often with added complexity from equipment aging and modifications. There are also regulatory and certification milestones, because relocation can trigger new approvals, surveys, and interface requirements depending on jurisdiction. Some operating FLNGs have publicly reported relocation as part of their asset story, indicating that it is not purely theoretical. Successful relocation is therefore treated as a major lifecycle milestone comparable to initial deployment, requiring careful integrity and marine risk management. Reference: https://www.petronas.com/progressing-energy/liquefied-natural-gas
On FLNG, people live and work close to high-energy process equipment, and emergency response options are constrained by remoteness and weather. This amplifies the importance of human factors engineering: clear alarm management, usable procedures, effective control room design, and training that integrates marine and process emergencies. Evacuation, escape, and rescue systems must work under offshore conditions, and the facility must maintain safe refuge and lifesaving capability even during major events. Offloading operations add further human-factor stress because they require tight coordination with visiting LNG carriers. Many safety frameworks for offshore facilities emphasize that risk cannot be controlled solely by hardware; it depends on organizational competence, maintenance discipline, and the ability to respond quickly and correctly to abnormal conditions. In practice, drills, competency programs, and clarity of command become recurring “soft milestones” that strongly influence real safety performance. Reference:https://ww2.eagle.org/content/dam/eagle/rules-and-guides/archives/offshore/169-requirements-for-building-and-classing-floating-offshore-liquefied-gas-terminals-2024/169-flgt-guide-jan24.pdf
First cargo milestones are powerful because they prove more than liquefaction; they validate end-to-end operability under offshore constraints. Achieving the first cargo shows that feed gas processing, refrigeration stability, LNG storage containment, boil-off management, and the marine offloading interface can work together safely and reliably long enough to complete a loading operation. It also demonstrates that the operator can manage metocean limits, ship approach and mooring, emergency shutdown linkages, and product quality assurance. First cargo dates for major FLNGs highlight the reality that commissioning can be lengthy, with integration and reliability issues often stretching it out further. Once the first cargo is achieved, a ramp-up period follows to demonstrate sustained performance, which becomes the next critical milestone.cal milestone. Public operator announcements document these first cargo events and the operational context around them. Reference: https://www.shell.com.au/media/2019-media-releases/first-lng-cargo-shipped-from-prelude-flng.html
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