What Is Carbon Capture and Storage: Technology, Cost, and Potential

The Case for Carbon Capture: Why Removal Matters

Carbon capture and storage (CCS) refers to a suite of technologies that intercept carbon dioxide before it enters the atmosphere — or remove it directly from the air — and store it underground in geological formations where it cannot contribute to climate change. The concept is not new: geologists have injected CO2 into subsurface rock formations for oil and gas applications since the 1970s. What is new is the urgency: climate scientists and energy modelers increasingly conclude that CCS will be necessary to limit global warming to 1.5 or 2 degrees Celsius, particularly for hard-to-decarbonize sectors like cement, steel, and aviation fuel production.

The mathematics are stark. Global CO2 emissions from energy and industry exceed 37 billion tonnes per year. Even an aggressive transition to renewable electricity and electric vehicles will leave substantial emissions from industrial processes where fossil carbon is an input, not just an energy source. Cement production, for instance, releases CO2 as an inherent byproduct of calcining limestone — a chemistry-driven emission that cannot be eliminated by switching to clean electricity. Steel, chemicals, aviation, and shipping present similarly stubborn challenges. CCS is one of only a handful of tools capable of addressing these emissions directly.

Beyond preventing new emissions, some climate scenarios require removing CO2 that has already accumulated in the atmosphere — a concept called carbon dioxide removal (CDR) or negative emissions. Technologies that combine CCS with biological carbon uptake (bioenergy with carbon capture and storage, or BECCS) or that capture CO2 directly from the ambient air (direct air capture, or DAC) could in theory create net negative emissions over time. The scale required is enormous: one to ten billion tonnes of CDR per year by mid-century in most 1.5°C scenarios, compared to current global CDR capacity of only a few million tonnes annually.

How Post-Combustion Carbon Capture Works

The most mature and widely deployed CCS technology is post-combustion capture, which removes CO2 from flue gases after fossil fuel combustion. Flue gas from a power plant or industrial facility typically contains 3 to 15 percent CO2 by volume, the rest being nitrogen, water vapor, and other gases. Separating CO2 from this dilute mixture is thermodynamically challenging and energy-intensive.

The dominant separation method uses chemical absorption with amine solvents. Flue gas is passed through an absorption column where it contacts a liquid amine solution — commonly monoethanolamine (MEA) or proprietary blends. CO2 reacts with the amine to form a water-soluble salt, while the remaining flue gas (mostly nitrogen) passes through. The CO2-rich amine solution is then heated in a separate regeneration column, where the reaction reverses: CO2 is released as a concentrated stream and the regenerated amine is recycled back to the absorber. The energy required to regenerate the amine — heating the liquid and driving off the CO2 — is the primary cost driver of post-combustion capture, reducing a power plant's net electrical output by 15 to 25 percent.

Alternative separation approaches are under development. Solid sorbents can capture CO2 at lower regeneration temperatures, potentially reducing the energy penalty. Membrane separation uses polymer membranes that are selectively permeable to CO2, though achieving high purity and recovery simultaneously remains technically challenging. Cryogenic separation liquefies CO2 by cooling the gas stream, but its high energy demand limits economic viability. Oxyfuel combustion takes a different approach entirely: burning fuel in pure oxygen rather than air, producing a flue gas that is almost entirely CO2 and water vapor, easily separated by condensing the water. Each technology has trade-offs in cost, energy penalty, and applicability to different industrial processes.

Pre-Combustion Capture and Industrial Applications

Pre-combustion capture processes fossil fuels before combustion, converting them into a hydrogen-rich gas and concentrated CO2 that is easier to separate. In integrated gasification combined cycle (IGCC) power plants, coal or natural gas is partially oxidized with steam and oxygen to produce syngas (primarily hydrogen and carbon monoxide). A water-gas shift reaction then converts the CO to CO2, yielding a high-pressure stream of hydrogen and CO2 that can be separated relatively efficiently. The pure hydrogen is then burned to generate electricity with no direct CO2 emissions. Pre-combustion capture is particularly relevant to hydrogen production from natural gas — so-called "blue hydrogen" — which could be an important bridge fuel during the energy transition.

Natural gas processing is currently the largest application of CCS at industrial scale. Several natural gas fields naturally contain high concentrations of CO2 that must be removed before the gas can be sold. In these cases, capturing the CO2 and injecting it underground is economically straightforward because the capture is required regardless of climate policy. The Sleipner project in Norway, which began injecting CO2 beneath the North Sea in 1996, demonstrated that geological storage is technically feasible and has informed subsequent projects worldwide.

Cement and steel production are the industries where CCS may be most essential. Cement manufacturing accounts for approximately 8 percent of global CO2 emissions, of which about 60 percent comes from the chemical decomposition of limestone (calcination) and 40 percent from burning fuel to heat the kilns. Only CCS — or the use of alternative calcium sources that do not release CO2 upon calcination — can address the process emissions. Several cement CCS demonstration projects are underway in Europe and Asia. For steel, the ULCOS (Ultra-Low CO2 Steelmaking) program in Europe and similar initiatives in Asia are piloting CCS-integrated steelmaking processes.

Geological Storage: Where Does the CO2 Go?

Captured CO2 must be compressed to a supercritical state — a dense, fluid-like phase achieved above 31°C and 74 atmospheres — and injected into suitable geological formations at depths typically greater than 800 meters. At these depths, the reservoir pressure keeps the CO2 in its supercritical state, which has a density similar to a light liquid and is much easier to store efficiently than a gas. The most suitable storage formations include deep saline aquifers (porous rock formations saturated with salty water unfit for drinking), depleted oil and gas fields, and in some cases deep unmineable coal seams.

The security of geological storage depends on the trapping mechanisms that keep CO2 from migrating back to the surface. Physical trapping occurs when CO2 accumulates beneath an impermeable caprock layer — the same mechanism that has trapped natural gas and oil for millions of years. Residual trapping occurs as CO2 migrates through the formation and becomes immobilized in small pore spaces. Solubility trapping occurs when CO2 dissolves into the formation water; CO2-saturated water is denser than pure formation water and sinks, driving further dissolution. Mineral trapping — the slowest but most permanent mechanism — involves CO2 reacting with minerals in the rock to form solid carbonates. Over thousands of years, injected CO2 is expected to become increasingly immobilized through these mechanisms.

Monitoring, reporting, and verification (MRV) is essential to confirm that stored CO2 remains where it was injected. Seismic surveys, groundwater sampling, soil gas measurements, and satellite-based subsidence monitoring are used to track subsurface CO2 plumes and detect any unexpected migration. The Weyburn-Midale project in Saskatchewan, which has injected over 30 million tonnes of CO2 since 2000, provided comprehensive data demonstrating long-term storage integrity. No significant leakage events have been detected at any of the world's current CCS projects, though the relatively small number of operational projects means statistical confidence in large-scale performance is still developing.

Direct Air Capture: Pulling CO2 from the Atmosphere

Direct air capture (DAC) technologies remove CO2 directly from the ambient atmosphere, which contains only about 420 parts per million (0.042 percent) CO2. This extreme dilution makes DAC far more energy-intensive than point-source capture from concentrated flue gases. Nevertheless, DAC offers a unique advantage: it can remove CO2 from any source — including diffuse sources like cars, planes, and agriculture — and is independent of any specific industrial facility. Combined with permanent geological storage, DAC represents true negative emissions technology.

The leading DAC approach uses a liquid solvent (typically potassium hydroxide) or a solid sorbent (typically amine-functionalized materials) to chemically bind CO2 from air passed through the system. For liquid DAC systems, the CO2-rich solution is then processed in a calciner at very high temperatures (around 900°C) to release concentrated CO2 and regenerate the sorbent. The enormous energy requirement — roughly 1,500 to 2,000 kilowatt-hours of electricity and heat per tonne of CO2 captured — is the primary cost driver. For solid DAC systems, lower-temperature regeneration (80 to 120°C) is possible, reducing energy requirements but still requiring substantial input.

Current DAC costs are extremely high — estimated at $300 to $1,000 per tonne of CO2 captured and stored, compared to the roughly $50 to $200 per tonne needed for widespread deployment. Companies like Climeworks (Switzerland) and Carbon Engineering / 1PointFive (Canada) have built the first commercial-scale DAC plants, but their combined capacity is only a few thousand tonnes of CO2 per year — a vanishingly small fraction of what climate models require. The challenge is to achieve the kind of cost reductions through learning-by-doing and economies of scale that solar and wind energy experienced over the past two decades.

The Economics and Politics of CCS Deployment

The economics of CCS are challenging. Capturing and storing CO2 imposes costs — energy, capital, and operating — without producing a product that can be sold at market. The economic rationale depends entirely on either a price on carbon emissions (through a carbon tax or cap-and-trade system) that makes emitting CO2 costly enough to justify capture costs, or direct subsidies or mandates that support CCS deployment. The absence of sufficiently high and stable carbon prices in most jurisdictions has been the primary reason CCS deployment has lagged far behind the levels envisioned in climate scenarios from the 2000s and 2010s.

Government support has expanded significantly in recent years. The U.S. Inflation Reduction Act of 2022 expanded the 45Q tax credit to $85 per tonne of CO2 stored from industrial facilities and $180 per tonne for direct air capture, substantially improving the economics of new projects. Similar support frameworks are being developed in Europe, the UK, and Canada. Norway's Longship project — the world's first full-scale CCS chain including capture at cement and waste-to-energy plants, offshore transport, and subsea storage — received €1.8 billion in government funding and began operations in 2024.

Critics of CCS argue that it provides cover for continued fossil fuel investment, diverting resources from faster and cleaner renewable energy deployment. The energy penalty of CCS means that a coal or gas plant with carbon capture still consumes more fossil fuel per unit of electricity delivered than without capture — potentially undermining the carbon accounting unless the CO2 is genuinely and permanently stored. Concerns about storage permanence, induced seismicity from injection, and the costs of long-term liability have also been raised. Proponents counter that the scale of industrial process emissions makes CCS not a choice but a necessity in any realistic decarbonization scenario, and that dismissing it for ideological reasons is a luxury the climate cannot afford. The debate reflects genuine uncertainty about the relative costs, risks, and timescales of different climate mitigation pathways.