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LNG fuel system (onboard)

An onboard LNG fuel system is the integrated set of storage, conditioning, and distribution equipment that receives liquefied natural gas during bunkering, maintains it at cryogenic temperature, manages the pressure of boil-off gas, and delivers fuel at the pressure and temperature required by a ship’s propulsion and auxiliary engines. The system is specific to LNG-fuelled vessels - ships that burn LNG as their primary or dual fuel without carrying it as a cargo commodity - and is governed by the IGF Code (MSC.391(95)), adopted 11 June 2015 and in force from 1 January 2017 under SOLAS Chapter II-1 Part G. As of 2024, more than 200 LNG-fuelled ships were in commercial operation with over 600 on firm order, making LNG the most widely deployed alternative marine fuel in the world fleet by installed capacity. The onboard fuel gas supply system differs fundamentally from the cargo containment systems of an LNG carrier: it is designed around a much smaller storage volume (typically 100 m³ to 20,000 m³), a high-pressure Type C pressure vessel as the dominant tank type, and a fuel preparation train optimised for the engine cycle rather than cargo preservation. ShipCalculators.com provides a dedicated suite of LNG system calculators; the ShipCalculators.com calculator catalogue lists all available tools. For the fuel chemistry, energy content, and policy context of LNG as a marine fuel, see the companion article LNG as a marine fuel.

Contents

Background and regulatory development

Natural gas first entered marine propulsion through LNG carrier practice: from the early 1960s onward, steam turbine plants on LNG carriers burned boil-off gas (BOG) from the cargo tanks rather than venting or reliquefying it. This was not a purpose-designed fuel system; it was an expedient that converted an unavoidable loss into useful energy. Purpose-built LNG fuel systems for non-carrier vessels emerged in Norway during the late 1990s and early 2000s, driven by the Norwegian government’s requirement for low-emission propulsion on environmentally sensitive fjord ferry routes. The ferry MF Glutra, delivered in 2000 and operated on the Sula fjord crossing, is widely cited as the first LNG-fuelled non-carrier vessel in commercial service.

For over a decade, LNG-fuelled ships were approved individually under SOLAS Regulation II-1/55 (alternative design and arrangements), with each flag administration issuing equivalences based on classification society interim rules. IMO circulated MSC/Circ.1085 in 2003 and the more detailed MSC.1/Circ.1455 in 2013 as guidance, but these were not mandatory. The resulting regulatory patchwork limited investor confidence and inhibited bunkering infrastructure development.

The IGF Code - International Code of Safety for Ships using Gases or Other Low-flashpoint Fuels - adopted as IMO Resolution MSC.391(95) on 11 June 2015 replaced this ad hoc approach with a mandatory, goal-based instrument. It entered into force on 1 January 2017 under SOLAS Chapter II-1 Part G. The code applies to SOLAS cargo ships of 500 gross tonnes and above, and to passenger ships, constructed on or after that date. Vessels built before 2017 and operating on LNG fuel may apply the code voluntarily or follow flag-state approved arrangements based on the pre-2017 interim guidelines.

Part A of the IGF Code establishes general requirements; Part A-1 - the most technically detailed section - covers natural gas (methane-dominated LNG) fuel systems. Amendments were introduced by Resolution MSC.477(102) in November 2020, clarifying risk assessment methodology for novel arrangements. Further updates are developed by IMO’s Sub-Committee on Ship Systems and Equipment (SSE).

The regulatory context sits within a broader framework. MARPOL Annex VI governs the NOx, SOx, and greenhouse gas emissions from LNG-fuelled ships; the IMO 2020 sulphur cap of 0.5% globally was a decisive commercial driver for LNG adoption because LNG-fuelled vessels comply by default. The CII, EEDI, and EEXI frameworks create further incentives to reduce CO2 intensity, for which LNG provides a demonstrable tank-to-wake CO2 reduction over heavy fuel oil. IACS Unified Requirement UR Z23 (Safety Systems for Ships Using Gas as Fuel) overlays harmonised minimum safety system requirements across all IACS classification societies.

Tank types and storage technology

Type C pressure vessels

Type C pressure vessels are the dominant LNG fuel storage technology for vessels other than large container ships and cruise ships. They are independent pressure vessels designed to ASME Boiler and Pressure Vessel Code Section VIII Division 1, EN 13458 (cryogenic vessels), or equivalent national standards, with a design pressure set high enough that the tank itself acts as a pressure buffer between heat ingress events.

Construction is double-wall: an inner pressure vessel of cryogenic-grade austenitic stainless steel (304L or 316L) or 9% nickel steel surrounds the LNG, contained within a larger outer carbon-steel jacket. The annular space between inner and outer vessels is evacuated to a residual pressure below 0.01 mbar and filled with multi-layer insulation (MLI) blankets, perlite powder, or aerogel blankets. This vacuum-insulated construction achieves heat ingress of the order of 0.05 to 0.10 W per square metre per kelvin, producing a boil-off rate (BOR) typically between 0.10% and 0.25% per day of liquid volume for a well-maintained tank.

Maximum allowable working pressure (MAWP) for Type C LNG fuel tanks is typically four to 10 bar gauge, though purpose-built tanks for high-pressure diesel-cycle fuel supply can be rated to 10 to 18 bar. The elevated working pressure means the LNG is stored as a subcooled liquid: at six bar absolute, the saturation temperature of methane is approximately −138°C, so LNG at −162°C at that pressure is subcooled by about 24 K. This subcooling provides a thermal buffer before BOG generation accelerates. As heat ingress warms the liquid toward saturation, vapour generation intensifies and tank pressure rises. The LNG boil-off rate calculator computes daily BOG production; the LNG tank BOG production calculator converts BOG rate to mass flow at a given fill level. The LNG density (Klosek-McKinley) calculator applies the ISO 6578 Klosek-McKinley method to determine density at the storage conditions, accounting for composition, temperature, and pressure.

Type C tanks are commercially available as standard products from vendors including Chart Industries, Cryolor (Air Liquide group), and Suretank, in sizes from approximately 10 m³ to 5,000 m³ as a single unit, with larger installations achieved by manifolding multiple tanks. Their self-supporting nature and absence of a secondary barrier requirement - permitted by the IGF Code for Type C vessels - simplify installation. They can be mounted on deck, partially recessed, or enclosed in tank holds. Weather-deck installation is common on ferries, offshore supply vessels, and smaller tankers.

Tank sizing is driven by voyage range analysis: design bunker interval (days between bunkering) multiplied by engine gas consumption (mass per hour at service power) and divided by LNG lower heating value gives required LNG mass. The LNG net calorific value calculator provides LHV from composition; the m³ LNG to kg conversion and m³ LNG to MMBTU conversion handle unit conversion for tank sizing and custody transfer accounting.

Membrane-type fuel tanks for large volumes

For large containerships and cruise vessels where fuel volume requirements exceed approximately 3,000 to 5,000 m³ per tank, bespoke membrane containment systems adapted from LNG carrier cargo practice are the most space-efficient solution. GTT’s Mark III Flex system - a flat corrugated 304L stainless-steel primary barrier supported on polyurethane foam insulation panels and backed by a secondary Triplex barrier - is installed within purpose-built fuel holds in the ship structure. The tank is non-self-supporting; hull steel provides structural containment.

The CMA CGM Jacques Saadé class (18,000 TEU, delivered from 2020) represents the largest application: 19,200 m³ of LNG fuel capacity in Mark III Flex tanks, sufficient for trans-Pacific voyages. Daily boil-off rates for membrane fuel tanks are typically 0.15% to 0.40% per day, higher than for vacuum-jacketed Type C tanks because the polyurethane foam insulation system has inherently higher conductance than vacuum insulation.

Type B self-supporting tanks

Type B independent tanks use advanced structural analysis - finite element methods and fatigue assessment - to demonstrate that crack propagation rates are slow enough to allow detection before a through-crack develops, requiring only a partial secondary barrier (drip tray) rather than a full secondary barrier. Moss-Rosenberg spherical tanks (the KVAERNER design) are the most familiar Type B application on LNG carriers. In fuel-tank service, IHI’s Self-supporting Prismatic type B (SPB) tank concept has been applied for medium-capacity fuel applications, primarily in Japanese newbuildings. The regulatory coverage of LNG carrier containment and IGC Code requirements is addressed in the LNG carrier article.

Fuel-gas supply system architecture

The fuel-gas supply system (FGSS) connects the LNG storage tank to the gas admission point on each engine. Its architecture is determined primarily by the engine cycle pressure requirement: low-pressure Otto cycle or high-pressure diesel cycle.

Pressure build-up unit and low-pressure vapour supply

Low-pressure dual-fuel engines (LPDFEs) require natural gas delivered at approximately five to 16 bar, a range achievable directly from a Type C tank at operating pressure. The pressure build-up unit (PBU) is a small shell-and-tube or brazed-plate heat exchanger that circulates LNG from the tank sump through a warm service medium (seawater, jacket water, or glycol circuit), vaporising a controlled fraction to raise or maintain tank pressure at the supply level. At moderate engine gas demand, natural BOG production alone may meet consumption and the PBU remains inactive.

A submerged cryogenic centrifugal pump in the tank sump feeds LNG to the PBU when liquid feed is required. The motor operates in saturated LNG and must be wound and certified for ATEX Zone 0 (continuous hazardous atmosphere) service at cryogenic temperature. The vapour stream leaving the PBU or tank vapour dome passes at tank pressure through the main isolation valve, a coalescer/filter, and the gas valve unit (GVU) before entering the engine room through double-walled piping. Gas temperature at the engine fuel rail is typically −80°C to −40°C for LPDFEs, with a final heat exchanger on the engine raising temperature to the specified range. The LNG compressor power calculator handles the related case where a vapour compressor is used to boost BOG to the required supply pressure from a low-pressure tank.

High-pressure cryogenic pump and supercritical gas supply

High-pressure dual-fuel engines operating on the diesel cycle require gas injection at 250 to 300 bar above the cylinder peak firing pressure. The MAN ES ME-GI engine, which achieves diesel-cycle efficiency while burning natural gas, requires delivery at approximately 300 bar. At that pressure, methane is above its critical pressure (46.1 bar) regardless of temperature; above the critical temperature (−82.6°C), it is a supercritical fluid with no distinct liquid or vapour phase.

The FGSS for high-pressure supply uses a cryogenic reciprocating plunger pump to raise liquid LNG from tank pressure to delivery pressure while still in the liquid phase. Centrifugal pumps cannot deliver the required differential pressure (typically 290 bar from a suction condition near tank pressure of four to eight bar). A high-pressure vaporiser then transfers heat from engine jacket water or a glycol circuit to the pressurised LNG, converting it to a supercritical gas-like fluid before injection.

High-pressure pump manufacturers include Cryostar (Ebara Group), Burckhardt Compression, and Flowserve. Pump efficiency at cryogenic conditions is typically 60 to 75%. Power consumption per unit mass flow is derived from the Bernoulli equation for incompressible flow: pump power equals mass flow rate multiplied by the pressure differential divided by the product of LNG density and pump efficiency. At 300 bar delivery, 10 bar suction, LNG density of approximately 430 kg/m³, and 70% pump efficiency, shaft power is approximately 1 kW per kg/h of LNG flow - roughly 100 to 400 kW for a large main engine supply system.

The thermodynamic advantage of the high-pressure system is retention of the diesel cycle at all loads with high thermal efficiency and minimal methane slip. The disadvantage is mechanical complexity: the high-pressure pump requires specialist maintenance, operates at extreme pressures and cryogenic temperatures, and represents a single-point failure mode for gas supply. Redundant pump arrangements - two pumps in parallel, each capable of full flow - are standard on large tonnage.

Gas valve unit

The gas valve unit (GVU) is a certificated skid assembly constituting one of the mandatory safety barriers between LNG storage and the machinery space under IGF Code Part A-1. Each GVU contains a master gas valve (normally closed, fail-closed on loss of power or ESD signal), a double-block-and-bleed (DBB) valve arrangement, a pressure regulating valve, flow measurement instrumentation, and vent connections to a safe location. Double-block-and-bleed architecture places two independent block valves in series with a bleed valve between them: if either block valve leaks, gas entering the bleed space is detected by the bleed-space pressure sensor and vented to a safe location before reaching the downstream system.

The GVU is located as close as practicable to the engine room boundary. A fuel gas handling room (FGHR) or gas valve room houses the GVU and associated conditioning equipment; this room is a formally defined gas-safe enclosed space with mechanical ventilation at a minimum of 30 air changes per hour, continuous gas detection, automatic GVU isolation on gas alarm, and ATEX-rated electrical equipment throughout. Access requires a gas-freeing confirmation and entry logging.

The LNG Wobbe index calculator checks combustion interchangeability: the Wobbe index W equals the higher heating value divided by the square root of the specific gravity relative to air, and must fall within the engine manufacturer’s specified window for stable combustion. The LNG GCV (ISO 6976) calculator converts the molar composition from the supplier’s certificate of analysis to gross calorific value per unit volume at reference conditions, which is the primary quantity for energy billing and custody transfer.

Double-walled piping and gas-safe ducts

The IGF Code requires that gas piping within or passing through machinery spaces be enclosed in ventilated double-walled (annular) piping or within gas-safe ducts. The inner cryogenic-grade stainless steel pipe carries the gas; a larger-diameter outer pipe forms an annular space that is continuously ventilated. Gas leaking from the inner pipe accumulates in the annular space rather than in the machinery space; sensors at duct ventilation outlets detect any leakage before concentration exceeds safe limits. Ventilation rates are set to maintain gas concentration below 30% LEL under any credible inner-pipe leakage scenario.

Gas-safe machinery spaces - formally classified as Zone 1 or Zone 2 hazardous areas - are an alternative where the entire engine room is designed and equipped for gas-safe operation. Early Norwegian LNG ferries and some platform supply vessels used this approach. IGF Code rules for gas-safe spaces impose ATEX-rated electrical equipment throughout, reinforced ventilation, and elevated monitoring standards that significantly increase outfitting cost for large machinery spaces.

Boil-off gas management

BOG generation is continuous and unavoidable. Heat always flows from the ambient environment through the tank insulation into the cryogenic LNG, vaporising a fraction of the liquid. For vacuum-jacketed Type C tanks with BOR of 0.15% per day, a 500 m³ tank generates approximately 0.75 m³ of liquid per day (roughly 370 kg, yielding approximately 740 m³ of gas at standard conditions). The LNG boil-off rate calculator and LNG tank BOG production calculator compute these flows from tank geometry, insulation performance, and fill level.

On a vessel under way burning gas fuel, engine demand typically exceeds BOG production, and tank pressure falls steadily. BOG and PBU-generated vapour are consumed together; the tank provides a pressure buffer between production rate and demand rate. Problems arise in three scenarios: extended low-load operation (anchorage, manoeuvring, harbour idling) when engine gas demand drops below BOG rate; port stays of multiple days when no engine gas consumption occurs; and a warm tank shortly after bunkering, when newly loaded LNG has higher temperature and the BOG rate spikes before the tank cools to steady state.

Gas combustion unit (GCU): The GCU is a forced-draught thermal oxidiser, sized to consume all excess BOG at the minimum engine gas demand condition. It burns the gas with auxiliary diesel support at approximately 850°C and discharges through a dedicated funnel uptake. The LNG GCU capacity calculator sizes the GCU from maximum BOG flow and minimum engine demand margin. GCUs are mandatory on many LNG-fuelled ship designs as a secondary BOG disposal route whenever engines switch to diesel-only operation.

Reliquefaction: A cryogenic compression-condensation plant takes BOG from the tank vapour space, compresses it to condensation pressure, removes heat in an inter-cooler using seawater or refrigerant, and expands the resulting liquid through a Joule-Thomson valve back into the tank. Reliquefaction is standard on LNG carriers where cargo value justifies capital and operating cost; it is used on large cruise ships and ferries with substantial hotel loads and significant port dwell times. The BOG reliquefaction power calculator estimates refrigeration power from BOG mass flow and reliquefaction cycle coefficient of performance. The LNG compressor power calculator extends this to general BOG compressor sizing.

Tank pressure accumulation: The high MAWP of Type C tanks (four to 10 bar) allows the tank to absorb BOG as pressure rise rather than requiring immediate disposal. For a two-day port stay at a BOR of 0.15% per day, a 500 m³ tank accumulates approximately 1.5 m³ of LNG as BOG; the pressure rise depends on the tank’s vapour volume fraction and the thermodynamic state of the contents. Short layovers are typically managed by pressure accumulation alone.

Boiler consumption: Some ships route excess BOG to an oil/gas-fired auxiliary boiler, avoiding the need for a dedicated GCU. The boiler burner management system must accept variable-pressure gas feed; dual-fuel burners are used for this purpose.

The LNG cool-down calculator computes the LNG mass required to pre-cool the tank and supply lines before first fill - a BOG-intensive operation typically consuming five to 15% of tank capacity in LNG mass. The LNG heel return calculator determines the minimum LNG heel required between voyages to maintain cryogenic readiness and avoid a full warm-up and cool-down cycle at the next loading.

Engine combustion cycles and gas supply interaction

Low-pressure Otto-cycle dual-fuel engines

LPDFEs mix gas and air in the intake manifold or intake port, producing a lean premixed charge ignited by a small diesel pilot injection (typically three to five per cent of heat input at full load). Combustion occurs at effectively constant volume near top dead centre, approximating the Otto cycle. Engine models in this category include the Wärtsilä four-stroke X-DF series (delivery pressure approximately six to 16 bar), the Wärtsilä 50DF (approximately five bar), and the MAN ES two-stroke ME-GA (approximately 16 bar at the gas admission valve). The ME-GA uses a low-pressure gas admission valve integrated into the cylinder liner scavenging air supply, a fundamentally different arrangement from the four-stroke intake manifold injection of Wärtsilä engines.

Brake thermal efficiency of modern LPDFEs at maximum continuous rating (MCR) is approximately 46 to 50%, comparable to modern four-stroke diesel engines but lower than the best two-stroke diesel-cycle engines. Part-load efficiency falls less steeply than on diesel engines because lean-burn combustion remains stable across a wide load range. The specific fuel oil consumption article covers the SFOC metric used to compare fuel efficiency across engine types.

Methane slip is the principal limitation of the LPDFE for regulatory and climate purposes. Unburned methane escapes in the exhaust from two mechanisms: crevice trapping (premixed charge compressed into piston ring-land crevices does not fully combust and is expelled during the exhaust stroke) and end-gas quench (lean charge near cold cylinder walls fails to sustain flame propagation). Published methane slip figures from Wärtsilä indicate approximately two to four g/kWh for X-DF engines under normal operating conditions, rising at low load. MAN ES cites comparable figures for the ME-GA. The methane slip CO2-equivalent calculator and MARPOL methane slip calculator quantify regulatory and climate implications. The CH4 slip checker provides engine-level verification against manufacturer data. The HCHO/HC dual-fuel emission calculator covers associated formaldehyde and unburned hydrocarbon emissions.

The climate impact of methane slip is governed by methane’s global warming potential. The IPCC Sixth Assessment Report (AR6, 2021) gives GWP100 (100-year horizon) for methane as 29.8 times CO2, and GWP20 (20-year horizon) as 82.5 times CO2. At four g/kWh slip with GWP100 of 29.8, the CO2-equivalent methane contribution is approximately 119 g CO2eq/kWh. A 4-stroke LPDFE burning LNG at service conditions emits approximately 385 to 400 g CO2/kWh from carbon oxidation; the four g/kWh methane slip adds approximately 30% in CO2-equivalent terms on the GWP100 basis, materially eroding the tank-to-wake CO2 benefit of LNG over heavy fuel oil. The net GHG benefit is positive on a GWP100 basis when slip is below approximately three g/kWh, but can be negative on a GWP20 basis at higher slip rates. The well-to-wake LNG emissions calculator incorporates upstream methane leakage from LNG production and supply chains alongside combustion emissions, providing a full lifecycle perspective.

High-pressure diesel-cycle engines

The MAN ES ME-GI injects gaseous fuel at approximately 300 bar directly into the cylinder at a point when cylinder pressure already exceeds 200 bar. Gas combustion occurs in a diffusion flame rather than as a premixed charge; there is no unburned gas in crevice volumes before ignition. Methane slip from ME-GI engines is reported at 0.2 to 0.5 g/kWh - an order of magnitude lower than LPDFEs - making the tank-to-wake GHG advantage of LNG over HFO robust and unambiguous on both GWP100 and GWP20 bases.

Thermal efficiency of the ME-GI is essentially the same as the equivalent diesel-only ME engine: brake thermal efficiency of approximately 50 to 55% at MCR for large bore two-stroke engines, among the highest values of any heat engine in commercial service. The marine diesel engine article provides detailed coverage of two-stroke engine operating principles.

The capital and maintenance cost of the high-pressure cryogenic pump system is the main disadvantage. The pump operates simultaneously at approximately −155°C and 300 bar, requiring specialist materials, tight dimensional tolerances, and pull-out for inspection every 16,000 to 20,000 running hours. Redundant pump trains and a stock of critical spare parts are required to maintain acceptable availability on deep-sea voyages.

Single-fuel pure gas engines

Some ferries, harbour tugs, and inland waterway vessels use spark-ignited pure gas engines with no fallback to diesel operation. Engine types include the Rolls-Royce Bergen B-series gas engine and the Wärtsilä 20DF in gas-only configuration. Because there is no diesel fallback, the FGSS for single-fuel ships requires high redundancy: dual GVUs, dual isolation trains, and typically dual tank connections. Single-fuel operation also makes BOG management more critical: gas supply interruption halts propulsion entirely, which is unacceptable on scheduled ferry services.

LNG bunkering

Bunkering modes

Four LNG bunkering modes are in commercial operation:

Ship-to-ship (STS): A dedicated LNG bunkering vessel (LNGBV) comes alongside the receiving ship at berth or at anchorage. The LNGBV transfers LNG using its own cryogenic cargo pumps. STS is the most flexible mode and now operates at the ports of Rotterdam, Singapore, Zeebrugge, Jacksonville, Hamburg, and several others. LNGBV tank capacities range from approximately 1,000 m³ for small harbour barge operations to 18,600 m³ for large deep-sea bunkering vessels. Transfer rates are typically 400 to 1,200 m³/h. The LNG STS bunkering time calculator estimates transfer duration from pump rate and required volume.

Truck-to-ship (TTS): LNG road tankers (40 to 50 m³ usable capacity per tanker) deliver LNG through a shore manifold connection to the ship’s bunkering manifold. TTS is the dominant mode at smaller ports without LNGBV service. Individual truck transfer rates are limited to approximately 50 to 100 m³/h; multiple simultaneous trucks can increase effective rate. TTS is practical for tank volumes up to approximately 200 to 400 m³.

Shore-to-ship (pipeline): A fixed cryogenic loading arm or hose connects the ship to a shore LNG storage facility. This mode offers the highest sustained transfer rate (up to 2,000 m³/h at large terminals) and the best custody transfer metering accuracy. Fixed LNG bunkering infrastructure exists at Marseille-Fos (France), Rotterdam (the Netherlands), and several terminals in Singapore, South Korea, and Japan.

Portable tank: An ISO-container-format portable Type C LNG tank (20 to 40 m³) is crane-lifted onto the receiving vessel and connected to the ship’s manifold through a short flexible hose. Portable tanks suit very small vessels and emergency supply situations.

Pre-transfer preparation

Before any transfer connection is made, a compatibility check verifies that the LNG composition is within the engine and system operating limits. The LNG Wobbe index calculator and GCV calculator are applied to the supplier’s certificate of quality (composition analysis in mole per cent of methane, ethane, propane, nitrogen, and trace components). The LNG density (Klosek-McKinley) calculator provides the density at supply conditions for custody transfer mass calculation. The m³ LNG to MMBTU conversion and m³ LNG to kg conversion convert volume-metered delivery to energy and mass units for FuelEU Maritime and IMO DCS / EU MRV reporting.

Inerting and cool-down

Before any gas introduction, the transfer hose, manifold, and vapour return line are purged with dry nitrogen to displace air. The LNG purge displacement calculator computes the nitrogen volume required for displacement purging; the LNG purge dilution calculator models the residual oxygen concentration after a given number of purge volumes, verifying that the atmosphere is non-flammable before LNG introduction.

Manifold pre-cooling follows inerting. LNG is circulated through the transfer line and manifold at a controlled rate to cool the system from ambient temperature (approximately 20°C) to approximately −155°C to −160°C before bulk transfer begins. If warm LNG meets ambient-temperature piping, the sudden vaporisation creates a pressure surge and risks valve and fitting damage. The LNG cool-down calculator models the thermal mass of the manifold section and estimates the LNG mass consumed in cool-down and the time required.

Transfer, measurement, and ESD

Bulk transfer proceeds at the agreed rate with continuous monitoring of receiving tank level (radar gauging or differential-pressure sensors), tank pressure (to detect excess BOG generation), and manifold temperatures. Maximum fill level is set at or below the IGF Code maximum filling degree for the tank type - 95% by volume is typical for Type C tanks.

Vapour return is mandatory under IGF Code Part A-1: vapour displaced from the receiving tank during filling returns to the bunker source through a dedicated vapour return hose or arm. This prevents overpressurisation of the receiving tank, eliminates methane venting to atmosphere, and maintains the BOG energy balance of the bunker source.

ESD valves at the ship manifold and at the bunker source are pneumatically or hydraulically actuated fail-closed valves that isolate the transfer on: high-level alarm, high-pressure alarm, gas detection above 20% LEL, loss of communication, manual pushbutton activation at bridge, ECR, or manifold watchstation, or mechanical breakaway coupling activation. ESD activation on either side triggers simultaneous closure of all valves on both sides through a hardwired link; response time must be within the specified maximum (typically two seconds). The LNG bunkering procedure reference covers the full operational checklist including ESD compatibility verification.

For ships entering and leaving EU ports, bunkering records must satisfy EU ETS and IMO DCS / EU MRV documentation requirements. The carbon content factor (CF) for LNG under MARPOL Annex VI is 2.750 kg CO2 per kg fuel, applied to the LNG mass consumed to compute the CO2 emission figure for regulatory reports.

Post-transfer operations

On completion of bulk transfer, the delivery line is drained back to the source. Residual LNG is then blown out with nitrogen, the hose warmed, and the annular spaces of double-wall hoses purged. Drip trays under all connection points are inspected; any cryogenic liquid in trays is allowed to vaporise under natural warming before drain inspection. After nitrogen purging and disconnection, the manifold is restored to isolation. The voyage bunker fuelling plan integrates bunkering schedule, tank sizing, and engine consumption across a full voyage.

Hazardous area classification and safety systems

ATEX zone classification

The IGF Code and classification society rules require formal hazardous area (HA) classification of all spaces that may contain a flammable gas-air mixture during normal operation or credible fault conditions. HA classification follows IEC 60079-10-1 (explosive gas atmospheres) and the zone designations are:

Zone 0 applies to areas with continuous or sustained flammable atmosphere: inside the LNG tank, inside gas piping and the GVU, and the annular space of double-walled pipe under normal operation. All electrical equipment in Zone 0 must be certified to Equipment Category 1 (EEx ia intrinsic safety or equivalent).

Zone 1 applies to areas where flammable atmosphere is likely in normal operation: the FGHR, bunkering manifold areas during transfer, areas within one metre of relief valve outlets, and the airlock entrance to the FGHR. Equipment must meet Category 2 (EEx d flameproof, EEx e increased safety, or equivalent).

Zone 2 applies to areas where flammable atmosphere is unlikely but may occur in abnormal conditions: the zone extending approximately three metres from Zone 1 boundaries, areas near ventilation exhausts from gas-safe spaces, and deck areas near tank dome connections when bunkering is not in use. Category 3 equipment is required.

Mechanical equipment (pumps, compressors, valves) must carry the equivalent ATEX mechanical designation where installed in hazardous zones.

Gas detection and ventilation

Continuous fixed-point gas detection using catalytic bead or electrochemical methane sensors is required in all enclosed gas-system spaces. Alarm levels are set at 20% LEL (first alarm, notification) and 40% LEL (second alarm, automatic GVU isolation and gas supply shutdown). Sensors are calibrated against certified reference gas (typically 50% LEL CH4 in nitrogen) at intervals specified by the manufacturer, typically six to 12 months.

The FGHR, tank hold, and all gas-safe ducts must be continuously ventilated at a minimum of 30 air changes per hour by dedicated mechanical fans. Ventilation failure triggers an alarm and, after a time delay, initiates GVU shutdown. Fan duty/standby pairs ensure ventilation continuity; failure of both fans requires immediate gas supply isolation.

Oxygen monitoring in enclosed spaces that undergo inerting with nitrogen protects personnel during maintenance access. Fixed oxygen sensors are installed alongside gas detectors; a space must be confirmed above 19.5% O2 before personnel entry.

Emergency shutdown system

The ESD system provides automatic and manual isolation of the gas fuel supply on detection of any safety-critical exceedance. ESD logic is hardwired - not implemented solely in a programmable logic controller or distributed control system - and is designed fail-safe: loss of power or loss of signal to any actuator drives that actuator to the safe (closed) state. No single control system failure can leave the gas supply open.

Multiple independent ESD triggers are mandatory: manual pushbuttons at bridge, engine control room, and each bunkering station; automatic triggers from fire detectors (UV/IR flame detectors and heat detectors), gas detectors, high-level sensors, high-pressure sensors, and flooding sensors in tank holds; and mechanical breakaway coupling activation at the bunkering manifold. IACS UR Z23 requires functional testing of all ESD initiators at each annual survey.

Classification society rules (DNV GF, LR FuelGas, ABS +GP) impose functional safety requirements equivalent to SIL 2 (Safety Integrity Level 2, IEC 61511) for the master gas supply isolation function, and SIL 3 for ESD functions where a failure could lead to a catastrophic outcome. Design documentation includes a HAZID study, fault tree analysis (FTA), and a safety case submitted to the classification society for approval.

Cryogenic material requirements

Carbon steel embrittles at temperatures approaching LNG temperature. The ductile-to-brittle transition temperature for ordinary shipbuilding steel (grade A or AH32) may be above −30°C; contact with LNG at −162°C would cause immediate brittle fracture propagating across welds and structural connections. IGF Code Part A-1 and class rules specify cryogenic-grade materials for all components in direct contact with LNG: 304L or 316L austenitic stainless steel (serviceable to −196°C), 9% nickel steel (ASTM A553, to −196°C), or aluminium alloys 5083 or 6061 (to below −200°C). The LNG cofferdam temperature calculator models heat conduction across the cofferdam to verify that structural steel temperatures remain above the minimum design temperature for the steel grade used.

Classification society notations

DNV GF

DNV’s Gas Fuelled (GF) notation, issued under DNV-RU-SHIP Pt.6 Ch.2 (Gas Fuelled Ships), covers ships where LNG or another gas is used for main or auxiliary propulsion. Sub-notations specify the gas fuel type (GF-LNG) and, for bunkering vessels, GF-LNGbv. A Gas Ready (GR) notation is issued for ships with structural and piping provisions for future gas fuel installation without a complete gas system. The DNV Gas Ready class checker identifies the structural and void-space requirements for the GR notation.

Lloyd’s Register FuelGas

LR’s FuelGas notation (previously styled as LNG Fuelled) is applied under LR Rules for Ships, Chapter 16. LR also offers an LNG Ready Descriptive Note for preparation vessels. The LR LNG Ready class checker and the LR Descriptive Note LNG checker cover the respective notation criteria.

ABS +GP

ABS applies the optional class notation +GP (Gas as Propulsion fuel) under ABS Rules for Building and Classing Marine Vessels, Chapter 18. The ABS LNG bunker-ready class checker covers the structural and system readiness criteria for the ABS Bunker Ready notation for LNG, which is a prerequisite step toward the full +GP notation.

IACS UR Z23

IACS Unified Requirement UR Z23 establishes minimum requirements harmonised across all member societies for: gas detection system coverage and response time; ventilation rate and fan redundancy; ESD system architecture and functional safety level; power supply independence for safety-critical systems; and documentation standards for the safety case. UR Z23 is incorporated by reference into each member society’s class rules, ensuring that ships approved by different societies meet equivalent safety levels.

Methane slip: quantification and regulatory treatment

Methane slip is the emission of unburned methane in engine exhaust, arising from incomplete combustion in the cylinder. It is distinct from evaporative losses at bunkering or from storage tank pressure relief. The governing combustion mechanisms are crevice-volume trapping and end-gas quench, both of which are more pronounced in Otto-cycle lean-burn engines than in diesel-cycle diffusion combustion engines.

Published methane slip performance by engine type:

  • ME-GI (MAN ES, high-pressure diesel cycle): 0.2 to 0.5 g/kWh at MCR; increases at low load.
  • ME-GA (MAN ES, low-pressure two-stroke Otto cycle): approximately one to three g/kWh; varies with load and pilot quantity.
  • X-DF 2.0 (Wärtsilä, four-stroke low-pressure Otto cycle): approximately two to three g/kWh; reduction vs earlier X-DF series achieved through pre-chamber ignition and combustion chamber geometry optimisation.
  • Wärtsilä 50DF (four-stroke, Otto cycle): approximately two to four g/kWh.
  • Bergen DF gas engines (pure lean-burn spark ignition): three to six g/kWh.

The methane slip CO2-equivalent calculator converts g/kWh methane slip to g CO2eq/kWh using the IPCC AR6 GWP values (GWP100 = 29.8, GWP20 = 82.5). The MARPOL methane slip calculator applies the MARPOL Annex VI regulatory methodology. The CH4 slip checker provides an engine-level verification tool.

Under FuelEU Maritime (Regulation EU 2023/1805), methane slip is included in the well-to-wake GHG intensity calculation using default slip values per engine type, or verified actual values if operators provide third-party certified measurements. The FuelEU well-to-wake GHG intensity for fossil LNG in a typical low-pressure dual-fuel engine (including upstream leakage and approximately three g/kWh methane slip) is approximately 72 to 80 g CO2eq/MJ on a GWP100 basis, compared to approximately 91 to 93 g CO2eq/MJ for HFO. The advantage narrows substantially on a GWP20 basis. The FuelEU GHG intensity calculator and FuelEU compliance balance calculator model the ship’s compliance position against the annual GHG intensity targets that tighten progressively from 2025 to 2050.

The methane oxidation catalyst - a catalytic converter in the engine exhaust path that oxidises methane to CO2 and water - can reduce slip by 50 to 80% when exhaust temperature exceeds the catalyst light-off temperature (typically 350 to 450°C for methane). At low engine loads, exhaust temperature may fall below light-off, reducing catalyst effectiveness precisely when slip is highest. Pre-heating the catalyst with exhaust gas recirculation or electric heating extends the operational window.

Fleet status and transition fuel debate

DNV Alternative Fuels Insight reported more than 200 LNG-fuelled ships in commercial service at end-2024, with over 600 on firm order. The orderbook is dominated by large containerships (units by CMA CGM, MSC, Hapag-Lloyd, and Evergreen), car carriers (NYK, K Line, Eukor), cruise ships (Carnival AIDAcosma class, MSC World class), LNG-fuelled bulk carriers and tankers from European and Asian operators, and ferries.

The largest LNG-fuelled containerships in the 2024 orderbook have fuel tank capacities of 12,000 to 18,600 m³, using multiple large Type C tanks or Mark III Flex membrane tanks. These volumes provide sufficient range for trans-Pacific or trans-Atlantic voyages without intermediate LNG bunkering, which is a prerequisite for deep-sea deployment given the still-limited global LNG bunkering network.

LNG-fuelled ships’ CII ratings benefit from the lower CO2 per unit energy of natural gas combustion: the MARPOL Annex VI carbon content factor (CF) for LNG is 2.750 kg CO2/kg fuel, versus 3.114 for HFO. A 20 to 25% tank-to-wake CO2 reduction translates to a meaningful shift in CII rating on carbon-intensity-sensitive vessel types. However, if methane slip is significant and IMO adopts a policy of including methane in the CII denominator at full GWP100 weighting, some dual-fuel Otto-cycle ships could see their CII advantage reduced substantially. This question is under active debate at MEPC.

Bio-LNG (liquefied biomethane from waste, agricultural residue, or other biological feedstocks) can be used in any LNG fuel system without hardware modification, provided Wobbe index and methane number fall within engine specifications. Under FuelEU Maritime, certified bio-LNG from waste and residue feedstocks can achieve well-to-wake GHG intensity approaching zero or below zero (negative, for some anaerobic digestion pathways). The bio-LNG well-to-wake calculator models these pathways. The same hardware investment thus supports a long-term decarbonisation trajectory if bio-LNG supply develops at scale.

The debate over LNG as a genuine transition fuel versus a medium-term lock-in for fossil infrastructure has persisted since approximately 2015. Critics point to upstream methane leakage rates from LNG production, liquefaction, and shipping (variously estimated at one to three per cent of LNG throughput), the slow growth of bio-LNG supply relative to demand, and the capital cost of replacing LNG systems with ammonia or methanol fuel systems in the 2035 to 2050 window. Proponents note the immediate NOx and SOx benefits, the progressive improvement in methane slip through high-pressure injection cycles and catalytic aftertreatment, and the growth of bio-LNG supply in European markets. The EU ETS for shipping framework places a carbon price on CO2 emissions from LNG-fuelled ships on intra-EU voyages, directly monetising the CO2 advantage of LNG over HFO in the European trade area.

Slow steaming at reduced speed reduces fuel consumption per unit time and generally improves CII performance, but creates a BOG management challenge: lower engine gas demand means BOG is more likely to exceed consumption, requiring more frequent GCU operation or allowing tank pressure to rise to MAWP.

Maintenance and periodic survey

Cryogenic pump maintenance

Submerged cryogenic pumps require periodic pull-out for inspection of pump internals (impeller wear rings, bearing surfaces, mechanical seal face). Pull-out intervals are typically 16,000 to 20,000 running hours or at dry-dock. The procedure requires tank warm-up, nitrogen purging to atmospheric methane concentrations below one per cent, and entry into the tank dome area - a cryogenic atmosphere entry requiring full personal protective equipment including cryogenic gloves (EN ISO 15383) and face shield. Seal degradation is the principal failure mode; a leaking seal allows methane into the motor compartment, triggering the motor compartment gas detector and automatic shutdown.

Valve and actuator maintenance

GVU block valves operating at cryogenic temperatures experience thermal cycling between ambient (when the system is gas-freed) and approximately −155°C (in service). Valve stem seals - typically PTFE-backed stainless steel with cryogenic-rated secondary packing - compress and relax with each thermal cycle, leading to gradual degradation. The double-block-and-bleed arrangement allows in-service testing: the block valves are closed in sequence, and the bleed-space pressure sensor measures any leakage through the upstream block valve. Actuator solenoid valves and limit switches installed in Zone 1 must maintain their ATEX Category 2 certification; only certified replacement parts may be installed without reclassification.

Insulation vacuum integrity

The vacuum in Type C tank annular spaces and vacuum-jacketed piping must be verified periodically. A rise in annular pressure above approximately 0.1 mbar indicates a vacuum leak that increases heat ingress and BOG rate. Vacuum integrity checks involve measuring inter-space pressure at ambient temperature. Repair of vacuum leaks requires dry-dock access and specialist cold-welding or leak-sealing techniques. Perlite fill settling over time can also reduce insulation performance, evidenced by a gradually increasing measured BOG rate at constant tank conditions.

Periodic classification surveys

IGF Code ships are subject to annual, intermediate, and renewal surveys by the classification society. Survey scope covers: functional testing of all gas detection sensor channels against certified reference gas; ESD system functional test including all initiators; ventilation rate measurement; pressure relief valve setpoint verification; GVU valve tightness test; and structural inspection of tank supports, cofferdams, and drip trays. IACS UR Z23 specifies the minimum test scope harmonised across all IACS societies. After any modification to the gas fuel system, the classification society must be notified and written approval obtained before re-commissioning.

See also

LNG system calculators

Formula reference pages

References

  1. IMO Resolution MSC.391(95), International Code of Safety for Ships using Gases or Other Low-flashpoint Fuels (IGF Code), adopted 11 June 2015, entered into force 1 January 2017.
  2. IMO Resolution MSC.477(102), Amendments to the IGF Code, adopted November 2020.
  3. SOLAS 1974 as amended, Chapter II-1 Part G, Ships Using Low-flashpoint Fuels, International Maritime Organization.
  4. IMO, Fourth IMO GHG Study 2020, MEPC 75/7/15, International Maritime Organization, London, 2020.
  5. IPCC, Sixth Assessment Report (AR6), Working Group I, Chapter 7, Cambridge University Press, 2021. (GWP100(CH4) = 29.8; GWP20(CH4) = 82.5.)
  6. IACS, Unified Requirement UR Z23: Safety Systems for Ships Using Gas as Fuel, International Association of Classification Societies, current revision.
  7. DNV, Rules for Classification of Ships, Part 6 Chapter 2: Gas Fuelled Ships (DNV-RU-SHIP Pt.6 Ch.2), DNV AS, current edition.
  8. DNV, Alternative Fuels Insight Platform, DNV AS, 2024 fleet and orderbook data.
  9. Lloyd’s Register, Rules and Regulations for the Classification of Ships, Chapter 16: Ships Using Low Flashpoint Fuels, LR, current edition.
  10. ABS, Rules for Building and Classing Marine Vessels, Chapter 18: Gas Fuelled Vessels, American Bureau of Shipping, current edition.
  11. ISO 6578:1991, Refrigerated Light Hydrocarbon Fluids - Static Measurement - Calculation Procedure, International Organization for Standardization.
  12. ISO 6976:2016, Natural Gas - Calculation of Calorific Values, Density, Relative Density and Wobbe Indices from Composition, International Organization for Standardization.
  13. IMO MSC/Circ.1085, Interim Guidelines for the Use of Gas as Fuel for Ship Propulsion, IMO, 2003.
  14. Wärtsilä Corporation, Methane Slip Reduction Technology and X-DF 2.0 Performance Data, technical whitepaper, 2022.
  15. MAN Energy Solutions, ME-GI Dual Fuel MAN B&W Engines: Technical and Operational Overview, MAN ES, 2019.
  16. Regulation (EU) 2023/1805 (FuelEU Maritime), Official Journal of the European Union, L 234, 22 September 2023.
  17. IEC 60079-10-1:2020, Explosive Atmospheres - Classification of Areas - Explosive Gas Atmospheres, International Electrotechnical Commission.
  18. IEC 61511 series, Functional Safety - Safety Instrumented Systems for the Process Industry Sector, International Electrotechnical Commission.

Further reading

  • Mokhatab, S., Mak, J.Y., Valappil, J.V., and Wood, D.A., Handbook of Liquefied Natural Gas, Gulf Professional Publishing, 2014.
  • Society for Gas as a Marine Fuel (SGMF), Gas as a Marine Fuel - An Introductory Guide, SGMF, 2013.
  • EMSA, LNG Bunkering: Technical and Operational Advisory, European Maritime Safety Agency, 3rd edition, 2022.
  • SIGTTO, LNG Custody Transfer Handbook, 4th edition, Society of International Gas Tanker and Terminal Operators, 2012.