Decarbonisation Technology August 2022 issue

Sulphur recovery/ thermal oxidiser

Nitrogen rejection

Nitrogen vent to ATM

Fuel gas

Water/ mercaptans removal

Mercury removal

Nitrogen rich gas

Acid gas removal

Raw natural gas

End ash Nitrogen removal

N GL recovery

LNG to storage


Inlet separation

NGLs to storage



Figure 2 Typical LNG production process flow

to liquefy it for easy storage and transportation. The LNG production process flow is as follows: natural gas from raw gas transmission pipelines, typically at relatively high pressure, is fed to the LNG plant (see Figure 2 ), where it first goes through a series of processing steps to remove the undesirable components. These include heavy hydrocarbon liquids (condensate), free water, acid gases (carbon dioxide and hydrogen sulphide), water vapour, mercaptans, mercury, and other hydrocarbons heavier than methane called natural gas liquids (NGLs) contained in the natural gas feed stream, to prevent freezing issues in the cryogenic process, and to meet final LNG product specifications. Nitrogen, a potential natural gas contaminant, will be removed in the later cryogenic process through fractionation or fuel gas purge. After the NGLs are removed, the residual natural gas stream gets liquefied (using an external refrigeration system) and then sent to the end-flash nitrogen removal unit to meet the required specification to improve its calorific value and to avoid storage problems. The flash gas stream from nitrogen removal unit can be used as fuel gas. However, to meet fuel gas requirements, excess nitrogen needs to be rejected from this flash gas stream. Emission sources in LNG export facilities To understand the decarbonisation options in an LNG export facility, one must first locate the main GHG emission sources. There are primarily two major GHG emission sources in an LNG plant facility. One is CO₂ and methane contained in the feed gas, and the other is the flue gas produced from fuel gas combustion devices, such as gas turbines, thermal oxidiser, and other process fired heaters.

CO₂ in the feed gas is typically removed by amine absorption during feed gas treatment in the CO₂ absorber in the acid gas removal unit (AGRU). The off-gas from the amine regeneration column, which typically contains CO₂ and a small amount of hydrogen sulphide (H₂S) and other light hydrocarbons, is sent to a thermal oxidiser to destroy the hydrocarbons and other hazardous components by combustion or oxidation. The thermal oxidiser is often operated with some augmented fuel gas due to the low heat value of CO₂ off-gas from the AGRU. The flue gas from the oxidiser mainly contains nitrogen, unreacted oxygen, CO₂, water vapour, nitrogen oxides (NOx), sulphur oxides (SOx), and tiny amounts of uncombusted hydrocarbons depending on the combustion efficiency of the burner. These components can be vented to the atmosphere (to the extent allowed by local regulations) at a safe location. Alternatively, a carbon capture unit for CO₂ recovery can be added if needed. The amount of flue gas produced from a gas turbine is proportional to its fuel gas consumption, which in turn is a function of the duty required (or power output), fuel gas composition, and thermal efficiency. In addition, there are other emission sources in an LNG export facility. They can be intermittent or continuous and together can sometimes make significant contributions to the overall annual emissions of an LNG facility. Those emission sources include fugitive leaks from process equipment/turbomachines, piping and valves, vents from pressure control, compressor seals, emergency relief (flaring), and venting during commissioning, start-up, maintenance, and shutdowns. They may also include fuel gas purge for nitrogen removal (usually flared), nitrogen-rich


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