Pre-combustion capture

Pre-combustion capture removes the carbon before the fuel is burned. The fuel is first converted to synthesis gas, a mixture of carbon monoxide and hydrogen, by gasification for solids or steam reforming for methane. A water-gas shift reactor then converts the carbon monoxide and steam to CO2 and more hydrogen. What leaves the shift reactor is a pressurised binary mixture of CO2 and hydrogen, and separating those two is the capture step. The hydrogen is burned, or sold.

The thermodynamic advantage over post-combustion capture is substantial and follows from that pressure. Instead of a few percent CO2 at atmospheric pressure, the shifted syngas presents CO2 at high partial pressure, which means it can be separated by physical solvents that dissolve CO2 in proportion to its pressure rather than by chemical solvents that bind it. Regeneration is then mostly a matter of letting the pressure down instead of boiling the solvent, which is why physical solvents such as the glycol ether and methanol systems dominate this application [1].

The catch is that it is not a retrofit

Post-combustion capture attaches to an existing plant. Pre-combustion capture requires that the plant be built around it, because gasification, shift and separation are upstream of combustion and cannot be added to a boiler after the fact. That single structural fact has shaped where the technology actually exists.

It also makes the cost comparison misleading in an instructive way. Estimates put CO2 avoided at 38 to 84 dollars per tonne for coal gasification with pre-combustion capture, against 46 to 99 for a coal plant with post-combustion capture [2]. Pre-combustion looks cheaper per tonne and has still not displaced post-combustion, because the comparison silently assumes a new plant is being built either way.

Where it lives now: hydrogen

The commercial centre of gravity for pre-combustion capture is not power generation but hydrogen production. Steam methane reforming already produces most of the world's hydrogen and already separates CO2 as part of the process, so adding capture and storage means compressing and injecting a stream that is being generated regardless. Detailed process simulation coupled to life-cycle assessment is how this route has been evaluated [3].

Whether the result deserves to be called low-carbon is genuinely contested, and the dispute is worth setting out rather than resolving.

Howarth and Jacobson assessed the lifecycle emissions of blue hydrogen including fugitive methane and concluded it is not low-carbon at all. On their default assumptions of a 3.5 percent methane emission rate from the natural gas supply chain and a 20-year global warming potential, total CO2-equivalent emissions came out only 9 to 12 percent below unabated grey hydrogen, and the footprint more than 20 percent greater than simply burning natural gas or coal for heat. Fugitive methane emissions were higher than for grey hydrogen, because running the capture equipment consumes additional natural gas [4].

A large multi-institution response reached a more conditional conclusion. It found that the climate impact of blue hydrogen varies over a wide range and depends on only a few parameters: the methane emission rate of the gas supply chain, the CO2 removal rate at the plant, and the global warming metric applied. Where state-of-the-art reforming with high capture rates is combined with a low-methane gas supply, the emissions reduction against both conventional reforming and direct natural gas combustion is substantial, placing blue hydrogen at the upper end of the range for hydrogen made from renewable electricity. The same analysis is explicit that neither blue nor green hydrogen is net-zero without additional CO2 removal [5].

The two are less contradictory than they appear. Both identify upstream methane leakage and capture rate as the variables that decide the answer. They differ over what values those variables actually take in practice, which is an empirical question about gas supply chains rather than a question about capture chemistry.

Open challenges

• Upstream methane, not capture efficiency, is usually the binding term. A high capture rate at the plant does not rescue a leaky supply chain, and both sides of the blue hydrogen dispute agree on that structure [4][5].
• Which streams are counted. A reformer emits CO2 from more than one point, and a capture rate quoted for the concentrated process stream is not the same as a capture rate for the facility. The metric has to be stated before it means anything [5].
• The metric changes the verdict. A 20-year global warming potential weights methane far more heavily than a 100-year one, and the choice is a judgement about time horizons rather than a measurement [5].
• No retrofit path. Pre-combustion capture cannot decarbonise existing combustion plant, which limits it to new build and to the hydrogen sector, where CCS deployment remains far below the scale envisaged a decade ago [6].