The Outlook for Improved Carbon Capture Technology
Edward S. Rubin, Hari Mantripragada, Aaron Marks, Peter Versteeg and John Kitchin, “The Outlook for Improved Carbon Capture Technology”, Progress in Energy and Combustion Science 38(5), 630-671 (2012). https://doi.org/10.1016/j.pecs.2012.03.003
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Question
Carbon capture and storage (CCS) is expected to play a large role in cutting CO2 emissions from power plants and industry, but current capture processes are expensive and energy intensive. This review, prepared largely from work funded by the U.S. Congressional Research Service, asks how realistic the prospects are for cheaper capture: where post-combustion, pre-combustion and oxy-combustion technologies sit in the development pipeline, how much cost reduction can be expected, and how quickly. Transport and storage are outside its scope (Rubin et al. 2012).
Approach
The authors first describe the three capture routes and benchmark the energy penalty and cost of current commercial systems. They then define five maturity stages (commercial, full-scale demonstration, pilot plant, laboratory or bench scale, and conceptual design) and map them onto the nine-level technology readiness level (TRL) scale. Using public project databases (DOE/NETL, IEAGHG, MIT, GCCSI) supplemented by company data, they place solvents, solid sorbents, membranes, calcium looping, chemical looping, advanced oxygen production and other concepts on this ladder. Cost outlooks are drawn from “bottom up” engineering-economic studies by DOE and “top down” experience-curve analyses, and government and industry roadmaps (DOE, EPRI/CURC, CSLF, IEA, G8) are compared. Finally, five DOE-supported novel SO2 and NOx control processes from the 1960s to 2000s serve as historical case studies of how long new capture technologies take to mature (Rubin et al. 2012).
Key findings
Capture currently imposes a large energy penalty. Using the IPCC definition (extra energy input per net kWh), the penalty is about 43% for post-combustion capture on an existing subcritical coal plant (efficiency falling from 33% to 23% HHV), 29% for a new supercritical plant, 25% for oxy-combustion, 21% for IGCC with pre-combustion capture and 16% for natural gas combined cycle. Roughly 60% of the penalty comes from thermal energy for solvent regeneration (or water-gas shift losses, or oxygen production), about 30% from CO2 compression and 10% from pumps and fans. Because of this penalty, capturing 90% of the CO2 avoids only about 85 to 88% of emissions per kWh. CCS raises the cost of electricity by about 60 to 80% (40 to 70 $/MWh) for new supercritical coal plants and 30 to 50% (30 to 50 $/MWh) for IGCC, with avoided-CO2 costs of about 60 to 80 $/t and 30 to 50 $/t, respectively; industrial CCS ranges from about 30 to 70 $/t for high-purity CO2 sources to 55 to 150 $/t for cement (Rubin et al. 2012).
On maturity, aqueous amine scrubbing (20 to 30% amine) is commercial for gas purification and small flue gas slipstreams, but no capture system had yet treated the full flue gas of a power plant. Chilled ammonia, advanced amines and calcium looping were at pilot scale. An EPRI review found nearly all of more than a hundred post-combustion projects at TRL 1 to 5 in 2008. Laboratory work spans advanced amines such as piperazine, potassium carbonate blends, ionic liquids (low volatility, but viscosity increases on CO2 uptake and high cost), supported amines (no solvent water to heat, but thermal degradation and SO2 sensitivity), carbons, zeolites and MOFs, and membranes, which were judged not yet competitive with amines for flue gas. Electrochemical pH-swing and membrane schemes for regeneration were still conceptual. For oxy-combustion the key need is cheaper oxygen, for example ion transport membranes aiming at one third the cost and energy of cryogenic separation (Rubin et al. 2012).
On cost outlook, DOE engineering studies projected that advanced technologies could cut the total cost of electricity by 19% (IGCC) and 28% (PC) in a 2006 analysis, and by 31% and 27% in a 2010 analysis, but the authors stress that cost estimates tend to rise as a technology approaches commercial use. Experience curves applying historical learning rates (capital costs of FGD and SCR fell about 13% per doubling of installed capacity) suggest up to about 30% lower electricity cost after 100 GW of capture capacity is deployed worldwide. Roadmaps place commercial capture around 2020. The historical case studies (copper oxide, electron beam, NOXSO, furnace limestone injection, duct sorbent injection) took two to three decades from concept to large-scale demonstration, mostly failed commercially in the U.S., and saw their projected advantage erode as incumbent FGD and SCR improved. Peak historical deployment was about 15 GW/yr for FGD and 10 GW/yr for SCR (Rubin et al. 2012).
Significance
The review’s central message is that R&D alone will not deliver cheap capture: substantial cost reductions also require commercial deployment, and since capture has no value to a plant owner without a CO2 constraint, that market can only be created by government policy limiting emissions. For materials researchers it is a reminder that a new solvent or sorbent is far from a capture technology, and that advances must be judged against incumbents that keep improving (Rubin et al. 2012).