Post-combustion carbon capture is a process that removes CO2 from the exhaust gases (flue gas) of power plants and factories after fuel has already been burned. It’s the most widely deployed form of carbon capture because it can be added to existing facilities without redesigning the combustion process itself. Most systems target removing at least 90% of CO2 from flue gas, a baseline the industry has used for decades because anything less doesn’t justify the cost of building the equipment.
As of early 2025, just over 50 million tonnes of CO2 capture and storage capacity is operating worldwide. The technology is real and commercial, but it comes with significant energy costs and engineering complexity that shape where and how it gets used.
How the Process Works
After a power plant or industrial facility burns fuel, the exhaust travels through a smokestack as flue gas, a mixture that’s mostly nitrogen with a relatively small percentage of CO2 (around 3-15%, depending on the fuel). Post-combustion capture intercepts this flue gas and runs it through a chemical process to pull out the CO2 before the remaining gas is released into the atmosphere.
The most common method uses liquid chemical solvents, typically a class of compounds called amines. The flue gas enters a tall column called an absorber, where it flows upward while an amine solution rains downward. The amine reacts with CO2, binding to it chemically and pulling it out of the gas stream. The now CO2-rich solvent is then piped to a second column called a stripper, where it’s heated to break the chemical bond and release the CO2 as a concentrated stream. The regenerated solvent cycles back to the absorber to capture more CO2, running in a continuous loop.
Once separated, the captured CO2 needs to be compressed to very high pressures, typically between 1,500 and 2,200 psi, for pipeline transport. At these pressures, CO2 behaves as a dense, supercritical fluid that flows efficiently through pipelines to storage sites, usually deep geological formations or depleted oil and gas reservoirs.
Why Amine Solvents Dominate
The workhorse solvent in most commercial systems is monoethanolamine, or MEA. It reacts readily with CO2 through a straightforward chemical mechanism: the nitrogen atom in the amine attacks the carbon in CO2, forming a new compound that locks the CO2 into the liquid. This reaction is fast and effective, which is why MEA has been the industry standard for decades.
Other amines play different roles. Some, like diethanolamine, work through the same direct reaction but with slightly different performance characteristics. Others, like methyldiethanolamine, don’t grab CO2 directly at all. Instead, they help dissolved CO2 convert into bicarbonate ions in water, a slower but less energy-intensive pathway. Engineers often blend multiple amines together to balance capture speed against the energy needed to regenerate the solvent.
The regeneration step is the critical bottleneck. Heating the solvent to release CO2 in the stripper column requires enormous amounts of steam, and that steam has to come from somewhere, usually the power plant itself.
The Energy Penalty
The biggest drawback of post-combustion capture is how much energy it consumes. Running the capture equipment, regenerating the solvent, and compressing the CO2 all require power that the plant can no longer sell to the grid. This is known as the energy penalty.
For a coal-fired power plant using amine-based capture at 90% removal, the energy penalty typically falls in the range of 25-40% of the plant’s output, though engineers consider 29% a reasonable real-world target. Natural gas plants fare somewhat better. One detailed analysis of a natural gas combined cycle plant with 90% capture found a 21% energy penalty. The theoretical minimum, if every step were perfectly efficient, would be about 5% for a coal plant, so there’s substantial room between thermodynamic limits and current technology.
In practical terms, a coal plant with carbon capture needs about 31% more coal per unit of electricity delivered compared to the same plant without capture. That means higher fuel costs, more mining, and additional upstream emissions that partially offset the CO2 being captured at the smokestack.
Membrane Systems as an Alternative
Not all post-combustion capture relies on liquid solvents. Membrane-based systems use thin, selective barriers that allow CO2 to pass through more easily than nitrogen and other gases. Unlike amine systems, membranes separate CO2 without chemical reactions or solvent regeneration, which makes them mechanically simpler and potentially less energy-intensive.
Membranes come in several types. Polymer-based membranes are the most common, offering good CO2 selectivity and easy manufacturing. Mixed-matrix membranes embed tiny particles of highly selective materials like metal-organic frameworks into a flexible polymer base, combining the best properties of both. Ceramic membranes handle extreme heat and corrosive conditions but are more suited to other capture configurations.
Cost comparisons are promising. Amine-based absorption runs roughly $44 to $71 per ton of CO2 captured, while membrane systems range from $42 to $50 per ton. One analysis found that an optimized low-temperature membrane system could bring costs down to $57 per ton, a 55% reduction compared to conventional methods. The trade-off is that membranes struggle with low CO2 concentrations and are sensitive to impurities in flue gas, which limits where they can be deployed today.
Retrofitting Existing Plants
One of post-combustion capture’s key advantages is that it can, in principle, be bolted onto existing power plants and factories. The combustion process doesn’t change. You’re just adding equipment to treat the exhaust. In practice, though, retrofitting is a major engineering undertaking.
A capture system requires absorber and stripper columns, heat exchangers, CO2 compressors, cooling systems, water treatment equipment, and auxiliary power systems. The specific steel and cement requirements depend heavily on site conditions and how the capture system integrates with the host plant. Steam for solvent regeneration is typically extracted from the plant’s existing turbine cycle, which means the plant’s power output drops and its electrical systems need reconfiguring. A detailed engineering study for a natural gas combined cycle plant in Texas used conventional MEA-based capture and found that the balance-of-plant modifications, including substations and cooling infrastructure, were as complex as the capture equipment itself.
The supply chain is still maturing. As of recent assessments, nine companies can supply the large absorber and stripper columns, five can provide the specialized heat exchangers, and fifteen manufacture CO2 compressors. That’s enough for current demand but would need to scale significantly if carbon capture were deployed across a large share of existing fossil fuel infrastructure.
Environmental Trade-offs
Capturing CO2 prevents it from reaching the atmosphere, but the capture process itself creates secondary waste streams. Amine solvents degrade over time when exposed to oxygen and other compounds in flue gas. This degradation produces organic acids like formate and oxalate, nitrates, nitrites, and volatile compounds including ammonia and formaldehyde.
These byproducts enter the environment through three main pathways: trace amounts escape with the treated gas vented from the absorber, degraded solvent accumulates as a waste sludge (called reclaimer waste) that must be disposed of, and incinerating that waste can generate additional pollutants. Submicrometer particles containing amines and their degradation products have also been detected in emissions from capture facilities. None of these issues are unsolvable, but they add operational cost and regulatory complexity that factor into the real-world viability of any project.
Where the Technology Stands Today
The global portfolio of carbon capture and storage reached just over 50 million tonnes of annual capacity by early 2025. Eight new projects came online in 2024, though most were small, with some capturing as little as 5,000 tonnes per year. The majority of operational capacity, more than 60%, is at natural gas processing facilities, where CO2 concentrations are higher and separation is cheaper than at power plants.
Recent milestones point to broadening applications. A facility in China became the world’s first to capture CO2 from cement production, an industry responsible for roughly 8% of global emissions. Australia launched its first large-scale storage project in a depleted gas field. These are early steps, but they signal the technology moving beyond its historical concentration in oil and gas toward the harder-to-decarbonize industrial sectors where alternatives to fossil fuels are limited.