Boil-off gas (BOG) is the gas continuously generated in LNG storage tanks and transfer lines by heat leaking in from the surroundings. Left in the tank, it raises pressure, so it is drawn off and compressed, recondensed, burned as fuel, exported to a gas network or, as a last resort, flared. Measuring BOG shows how much gas takes each of these routes, which is what tank pressure management, the terminal energy balance and loss tracking all rely on. The measured fluid is not liquid LNG but a low-pressure and often very cold gas, and that alone sets BOG metering apart from liquid LNG metering.
This page deals with metering the BOG that forms continuously. Line design and pressure balancing for vapor displaced during tanker loading are covered on the LNG Vapor Return Systems page, and the general layout of gas metering stations on the Natural Gas Metering Stations page.
Where does BOG come from?
LNG typically boils at about −162 °C at atmospheric pressure and vaporizes wherever it contacts a warmer surface. The main contributors at a terminal are:
· Heat ingress: Continuous heat flow through tank insulation, piping and valves; the reason BOG forms even when nothing is moving.
· Displacement during transfer: Vapor returned while loading a tanker or ship, and gas displaced in the storage tank while unloading.
· Cool-down operations: Flash vaporization when LNG first contacts a warm line, arm or tanker.
· Energy added by the process: Heat from pumps and recirculation, and flashing across pressure drops.
Heat ingress is steady; the other sources come and go with operations. BOG flow can therefore be low and stable on a quiet night and markedly higher during busy transfer hours. Covering that wide range is the central challenge for the metering system.
Where BOG goes and why each route is metered
At a regasification terminal, BOG is typically compressed and reliquefied in a recondenser, or alternatively sent to flare through a flow meter. Smaller plants more often burn it as fuel or deliver it straight to a gas consumer. Each route has its own metering purpose:
BOG route | Why it is metered | What to watch at the meter |
Compressor and recondenser | Compressor load control and tracking of recovered gas | Suction pressure close to tank pressure; cold gas |
Fuel use (boilers, engines, generators) | Consumption tracking and terminal energy balance | Metering after fuel gas conditioning may offer steadier conditions |
Export to a network or consumer | Quantity enters commercial or allocation accounts | Meter location must match the commercial boundary |
Flare or vent | Basis for loss tracking and emissions reporting | Very wide range, often near-zero flow |
Transfer between tanks or facilities | Sharing between parties or units | Measurement method defined in the agreement |
An industry handbook on LNG custody transfer states that the energy balance of a transfer accounts for gas returned to the other party and for LNG or BOG consumed as fuel during the operation. BOG metering is therefore more than an operating indicator: it is one of the data sources that keeps unexplained differences out of the terminal energy balance.
Conditions that make BOG metering difficult
Near the tank, BOG sits at close to tank pressure, so any pressure loss created by the meter must be kept small. Gas leaving the tank is very cold and warms along the pipe, and the temperature at the meter location sets the temperature rating of the meter body and transmitters. Flow swings widely between holding and transfer. BOG composition can also differ from that of the liquid, as light components such as nitrogen and methane vaporize preferentially, and density and calorific value shift accordingly.
Density and other properties of cold gas are obtained with calculation methods covering extended temperature and pressure ranges, while calorific value is calculated from composition. Whether composition comes from a fixed value or from an online gas chromatograph depends on what the measurement is used for.
Selecting the technology and the metering point
Parameter | Why it matters in design | Effect on selection |
Pressure at the metering point | Allowable pressure loss is very small near tank pressure | Favors low-loss meter types and larger line sizes |
Gas temperature range | Cold gas challenges meter body, seal and transmitter limits | Influences metering upstream or downstream of the compressor |
Minimum and maximum flow | Holding and transfer flows differ widely | May call for a wide-rangeability meter or parallel runs |
Composition variability | Density and calorific value depend on composition | Decides between fixed composition and online analysis |
Purpose of measurement | Control, energy balance, emissions or commercial sharing need different accuracy | Sets verification method, record keeping and redundancy |
Risk of liquid carryover | Droplets in cold lines corrupt the reading | Affects separator or drain needs and meter location |
No single meter type suits every BOG point. Ultrasonic gas meters stand out for low pressure loss and wide rangeability, and the standards covering them assume single-phase, homogeneous gas flow. For near-zero, highly variable flows such as flare lines, other measuring principles are also considered. Selection should weigh pressure, temperature, flow range and purpose together.
Process measurement or commercial measurement?
Most BOG metering inside a terminal serves process control and energy balancing. Once BOG is delivered to a customer or another facility, the measurement may become commercial, and the applicable legal metrology framework needs its own review. OIML R 140 on measuring systems for gaseous fuel, for example, applies alongside a flow threshold to systems operating at 2 bar absolute or above; a BOG line near tank pressure may fall outside that scope, while a delivery point downstream of the compressor may fall inside it. The applicable framework depends on metering conditions, national regulations and the contract.
Tying BOG data into the control system
BOG flow guides operation only when read with tank pressure, compressor capacity control, recondenser LNG flow and flare valve position. Logging them on a common time base in PLC or SCADA shows afterward how transfers drove the BOG load and why gas went to flare.
TLY Enerji's role in BOG metering
TLY Enerji supports BOG metering points with engineering that starts from an assessment of process conditions and the selection of a suitable measurement technology. Depending on project scope, this can include supply of flow meters, pressure and temperature transmitters and process gas chromatographs, installation and commissioning, and monitoring and reporting through PLC and SCADA. The supply boundary is defined for each project in the technical specification.
Data to prepare for a BOG metering point
· BOG route to be metered: compressor suction, fuel line, export delivery or flare
· Expected minimum and maximum flow during holding and transfer periods
· Pressure and temperature range at the metering point and allowable pressure loss
· Gas composition data or information on its variability
· Purpose of measurement: control, energy balance, emissions reporting or commercial sharing
· Existing line size, available straight run and hazardous area classification
· Data to be passed to the control system and record-keeping requirements
Related pages
· LNG vapor return systems: How vapor displaced during loading reaches the BOG system and how pressure is balanced.
· LNG custody transfer metering: Where returned gas and BOG fit into energy-based custody transfer.
· LNG send-out metering: Metering gas delivered to the grid and the terminal energy balance.
· Fuel gas conditioning and metering skids: Conditioning and consumption metering when BOG is used as fuel.
· Gas quality measurement and analysis: Online determination of composition and calorific value.
BOG measurement FAQ
Is BOG the same as vapor return?
No. BOG is the general term for gas generated continuously by heat ingress during storage and transfer, handled by compressors, recondensers, fuel users or flare. Vapor return is a closed connection that carries vapor displaced in the tanker during loading back to the storage side through a separate line. Once returned vapor reaches the facility it adds to the BOG load, so the two systems are designed together, but they do different jobs.
Can BOG be measured with a liquid LNG meter?
No. Liquid LNG meters are selected for single-phase liquid flow, and the product is expected to stay liquid in the meter. BOG is in the gas phase and is measured with gas metering principles. Liquid and gas present together in one line corrupt both measurements, so the liquid transfer line and the BOG line are treated as separate metering points, each designed for its own conditions.
Should the BOG meter sit upstream or downstream of the compressor?
Both locations have merits. Upstream, gas is cold and close to tank pressure; the reading reflects total BOG from the tank, but pressure loss and low temperature constrain meter choice. Downstream, pressure is higher and temperature steadier, yet gas diverted to flare or elsewhere may bypass that point. The decision follows from the question the measurement is meant to answer.
Does BOG metering need a gas chromatograph?
Not always. If the meter serves only compressor control or pressure management, volumetric or mass flow may be enough. Where BOG enters the energy balance, is billed as fuel or is delivered to another party, determining composition and calorific value becomes important. Because BOG composition can differ from the liquid, applying the liquid analysis to BOG is not always correct.
Do small-scale satellite LNG plants need BOG metering?
It depends on what happens to the BOG. If it feeds on-site consumption, that consumption may need to be metered separately. Quantities sent to vent or flare may be tracked for emissions and losses. Without a meter, BOG is estimated indirectly from tank pressure and inventory change, but that approach misses short-term swings. Local regulations and operating goals decide.