LNG liquefaction plants are unusually well suited to carbon capture. They already concentrate CO₂ in a dedicated process unit — the acid-gas removal unit — long before the gas ever reaches the liquefaction cold box. That removal is not about emissions; it is about keeping CO₂ from freezing inside cryogenic heat exchangers. But it produces a ready-made, near-pure CO₂ stream that can be compressed and injected rather than vented.
Where CO₂ comes from at an LNG plant
There are two distinct sources of CO₂ at a liquefaction facility, and they matter for capture in different ways.
1. Reservoir CO₂ in the feed gas
Natural gas fields contain varying amounts of CO₂ — sometimes less than 1%, sometimes above 10%. That CO₂ must be removed before liquefaction, typically in an amine absorption unit using solvents such as MDEA. The output of this unit is a near-pure CO₂ stream at modest pressure. Venting this stream (as has historically been common) releases large quantities of fossil CO₂; capturing it instead is relatively inexpensive per tonne because the separation has already been done. This is the "easy" slice of LNG-plant CO₂.
2. Combustion CO₂ from liquefaction compressors
Liquefaction consumes roughly 8–10% of the feed gas's energy, much of which is burned in gas turbines driving the refrigerant compressors. Those turbines produce flue gas with a much lower CO₂ concentration (typically 3–4% by volume), which is harder and more expensive to capture. Options include post-combustion capture from turbine exhaust (like a power plant) and electrification of compressors combined with CCS on the upstream power source. Most integrated CCS projects at LNG plants so far have focused on the reservoir CO₂ stream rather than combustion CO₂.
The basic CCS value chain at an LNG facility
- Capture. CO₂ is separated in the acid-gas removal unit (for reservoir CO₂) or, in more advanced designs, from combustion flue gas (for turbine CO₂).
- Dehydration. Water is removed to prevent corrosion and hydrate formation in the pipeline.
- Compression. The CO₂ is compressed — typically to above 100 bar — so it becomes a dense phase that is cheaper to transport per tonne.
- Transport. Pipelines, trucks, or (for offshore projects) subsea lines carry the dense-phase CO₂ to an injection site.
- Injection and storage. The CO₂ is injected into a deep saline aquifer, a depleted gas field, or an active reservoir for enhanced oil recovery. Regulators then monitor the site for leakage over decades.
The engineering is well understood; the limiting factor is usually geology and permitting, not the capture process itself.
Facilities where CCS has been integrated
- Chevron's Gorgon project (Australia). Gorgon operates one of the largest CCS installations integrated with an LNG plant, injecting reservoir-sourced CO₂ into a saline aquifer beneath Barrow Island. The project has faced operational setbacks over start-up and storage performance; it remains the headline example of at-scale CCS at a liquefaction facility.
- Snøhvit (Norway). Equinor's Snøhvit LNG plant near Hammerfest has captured and stored reservoir CO₂ since 2008, using a dedicated offshore storage site in the Barents Sea. Long-term monitoring data from Snøhvit has informed CCS project design elsewhere.
- Qatar's North Field expansion. QatarEnergy has incorporated carbon capture and storage into its North Field East project, with publicly stated plans to capture a substantial quantity of CO₂ per year across the expanded facility.
- In-Salah (Algeria). Although not an LNG plant, In-Salah is often cited alongside LNG CCS projects as an early, long-running example of storing reservoir-sourced CO₂ from a gas-processing facility.
Beyond these, a number of announced LNG projects include CCS in their design, particularly where national policy or buyer preferences reward lower-carbon cargoes. Actual construction depends on storage availability, permitting, and the relevant carbon price or incentive.
How much of an LNG plant's emissions can CCS address?
Integrated CCS at an LNG plant addresses only a portion of the full lifecycle footprint. The chain looks roughly like this in order of magnitude:
- Upstream production and gathering — including methane leakage, typically the largest source of climate-relevant emissions per unit of gas when leak rates are high.
- Liquefaction — the reservoir-CO₂ stream (addressable by CCS now) and combustion CO₂ from turbines (harder to capture, or addressable by electrification plus grid decarbonisation).
- Shipping — marine fuel combustion and methane slip from engines.
- Regasification — vapouriser energy, small compared with the rest of the chain.
- End use — combustion CO₂ at the customer (power plants, heating, industrial users), which dwarfs everything else.
CCS integrated at the liquefaction plant can meaningfully reduce the plant's own CO₂ footprint. It does not address upstream methane leakage (which is tackled by methane reduction programmes) and it does not touch end-use combustion. This is why CCS is usually discussed alongside — not instead of — leak reduction, electrification, and the gradual substitution of gas by lower-carbon alternatives where feasible.
Economics and policy
Reservoir-CO₂ capture is comparatively cheap because the separation is already built into the plant. Published cost ranges for integrated reservoir-CO₂ CCS typically sit below flue-gas capture on a dollar-per-tonne basis. What makes or breaks a project is almost always downstream:
- Access to suitable geological storage within a reasonable pipeline distance.
- Regulatory certainty over long-term liability for the stored CO₂.
- Carbon pricing, tax credits (for example, the U.S. 45Q credit), or buyer willingness to pay a premium for lower-carbon cargoes.
Several European buyers and a growing number of Asian utilities have begun signalling preferences for carbon-reduced cargoes, either through contract structures or through public emissions reporting expectations. Whether that becomes a durable, priced premium across the market is one of the live commercial questions for the industry.