Post-combustion capture

Post-combustion capture separates CO2 from flue gas after the fuel has already burned. That ordering is the entire point. The capture plant attaches to the back of an existing boiler, kiln or turbine without altering the combustion itself, which makes it the only route available to the fleet of power stations, cement works and steel mills already standing. It is correspondingly the most studied capture technology, and the one with the most operating history behind it.

The difficulty is thermodynamic. Flue gas presents CO2 dilute and at roughly atmospheric pressure, and separating a dilute component out of a mixture costs work no matter how the separation is done. For coal flue gas, with compression of the product to 150 bar, that theoretical floor is about 0.11 megawatt-hours per tonne of CO2, with a realistic near-term target for a good solvent and process closer to 0.2 [1]. Everything interesting about the field sits in the gap between those two numbers and what real plants actually consume.

Why amine scrubbing dominates

The workhorse is aqueous amine absorption. Flue gas meets a lean amine solution in an absorber, where CO2 binds chemically rather than merely dissolving, which is what makes the process effective at low partial pressure. The rich solution then passes to a stripper, where heat reverses the reaction, releases concentrated CO2 and returns lean solvent to the absorber [1].

That heat is the cost. Reboiler duty in the stripper is the dominant energy penalty, and because the amine binds CO2 strongly enough to strip it from a dilute stream, it necessarily takes energy to unbind it. Solvent chemistry can shift the trade, but it cannot escape it, which is why the energy penalty has narrowed slowly rather than collapsed.

What the operating record shows

For most of the last decade the world's entire commercial-scale experience of coal-fired post-combustion capture consisted of two plants: SaskPower's Boundary Dam in Canada and NRG's Petra Nova in Texas. Both are retrofits, both use advanced amines, and they differ substantially in how they supply the steam and electricity the capture unit needs. A comparative analysis of the two configurations, plus alternatives, found that neither approach dominates: which one is preferable depends on the circumstances of the host plant [2].

The more sobering observation is the count itself. Two plants is a thin empirical base for a technology routinely assigned gigatonne-scale roles in mitigation scenarios.

Cost, and why published figures disagree

The most careful synthesis puts the cost of CO2 avoided at 46 to 99 dollars per tonne for a coal plant with post-combustion capture and geological storage, and 59 to 143 dollars per tonne for natural gas combined cycle [3]. The width of those bands is not sloppiness. It reflects genuine differences in plant location, capacity factor, plant size, fuel price, financing assumptions, and whether costs are quoted in constant or current dollars.

One distinction matters more than the rest. First-of-a-kind costs for real projects run significantly above estimates for a mature nth-of-a-kind plant, and the size of that gap is very difficult to predict for any particular technology [3]. A quoted capture cost is therefore close to meaningless without knowing which of the two it describes.

Alternatives to solvents

Membranes are the most developed alternative, separating CO2 by selective permeation with no thermal regeneration step and no solvent inventory to manage [4]. Solid sorbents and other contacting schemes are also under study. None has displaced amines at commercial scale, and the reason is not usually the separation itself but the enormous volumetric flow of flue gas that any post-combustion device has to process.

Open challenges

• The energy penalty is structural. It follows from binding CO2 strongly enough to capture it from a dilute stream, so improvements come incrementally from solvent and process design rather than from any single breakthrough [1].
• Solvent degradation. Amines oxidise and break down in service, and N-nitrosamines and N-nitramines formed in the process have been reviewed as an emerging concern [5]. The counter-assessment is that with water wash and standard controls these emissions are expected to have insignificant environmental and health impact, and that ammonia, a primary amine oxidation product, carries more particulate-formation potential than the amines themselves [6]. The disagreement is live and worth watching rather than resolved.
• Deployment, not technology. CCS is broadly recognised as technically mature and has still not been deployed at anything like the scale envisaged a decade ago [7]. The binding constraints are commercial and political more than chemical.