Response to Comment on “Reassessing the Efficiency Penalty from

Correspondence/Rebuttal pubs.acs.org/est

Response to Comment on “Reassessing the Efficiency Penalty from Carbon Capture in Coal-Fired Power Plants”

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generation supercritical and ultrasupercritical cycles, high levels of built-in heat recovery integration, and larger boiler and turbine sizes to comment on a paper describing energy penalties experienced by existing subcritical PC−CCS designs. Their reference to the Cansolv process used in the Boundary Dam project12 and discussed in several recent studies,13−16 is also misleading as it extends the comparative system boundary to integrate SO2 recovery with CO2 recovery.13,16 For the PC− CCS retrofits described in our paper, flue gas desulfurization units are often already in place, and consequently the additional heat recovery claimed by Herzog et al.2 is not available for the taking. Herzog et al.2 also take a misplaced aim at “Representative Scenario # 1” in our paper, which in the context of retrofits represents “capture-ready” power plants. Contrary to what they claim, our paper includes heat recovery through advanced CO2 absorber/stripper configurations such as those summarized in Boot-Handford et al.17 as well as from the CO2 compressor. Therefore, when Herzog et al.2 imply that our assumptions are biased against CCS, they fail to realize that we were being generous to CCS by modeling this level of heat recovery, especially when other studies focused on retrofits have noted the limited availability of recovered heat.18,19 They should also know that the U.S. Department of Energy study16 cited in their comment2 concludes that some of the energy recovery measures they cited are expensive relative to the benefit they provide in reducing the efficiency penalty. For this reason, our paper also included “Representative Scenario # 2” assuming no heat recovery, which represents “non-capture-ready” retrofit plants. It is surprising that, in addition to challenging these two scenarios, Herzog et al.2 claim that our results for the scenarios are unrealistic when the fuel inputs associated with our efficiency penalty estimates (11.3 and 21.4%-points) align very closely with the results of House et al.4

hile we appreciate the interest that Drs. Herzog, Rubin, and Rochelle have to respond to our paper,1 we categorically reject the assertions they make in their comment.2 We find it particularly noteworthy that while our colleagues find fault with the conclusions of the paper, they crucially do not identify errors in eq 1 from which the conclusions follow. Indeed eq 1 has been validated independently and serves as a natural extension from previous research in the literature.3−5 Their comment also fails to acknowledge that the scope of our paper was subcritical pulverized coal (PC) power plants with carbon capture and sequestration (CCS), particularly retrof its, such that they maintain the net electric output of an identical PC power plant without CCS. Our central approach, which is to compare power plants with and without CCS on the basis of equivalent net electric generation, follows from the standard practice of maintaining an equivalent functional unit when comparing technologies that could be treated as substitutes providing an identical service.6−8 Although our colleagues take issue with this approach, the very same approach was argued for elsewhere by Rubin et al.9 In fact, Rubin10 previously suggested that “the reference plant is assumed to be one that is identical or similar to the plant with CCS.” Indeed eq 1 is a direct consequence of his correct and erstwhile guidance.

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MASS BALANCE Now, for a CCS-equipped power plant to maintain the same net electrical output as an identical power plant without CCS, the loss in steam, recovered heat, and electricity that is needed to run the CCS unit must be compensated by burning additional fuel. The compensation that occurs within the CCS power plant is referred to as “replacement power” in our paper, and it creates a recursive feedback loop whereby more CO2 is generated for capture as a result of the fuel combustion, thus requiring more energy for capture and resulting in the combustion of additional fuel. This feedback effect is quantified by eq 1 and is similar in form to the analytical expression for the theoretically minimum energy penalty for postcombustion CCS provided by House et al.4 The feedback effect captured by eq 1 is also accounted for by software packages such as ASPEN Plus through the use of iterative convergence algorithms.11 Therefore, the claim by Herzog et al.2 that the concept of replacement power “... is meaningless since there is no power to replace,” is both unscholarly and grossly inaccurate. It is simply wrong to imply that the CCS equipment would not need extra power, and, as extra fuel is used to provide that power, that the CO2 emissions from combusting the extra fuel would not also need to be captured and stored. Anyone agreeing with this point must also agree with eq 1, since the statements are equivalent.

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MIXED FUEL SYSTEMS It is evident from eq 1 that supplementing some of the lowpressure steam demand of the CCS unit using natural gas would help reduce the efficiency penalty, which is consistent with the claims made by Herzog et al.2 However, this mixedfuel approach was clearly excluded from the scope of our paper as it would require a different form of eq 1. Prior to their comment we had already performed this analysis in a study that is currently in review. In that work we demonstrate that the use of natural gas instead of coal to meet the low-pressure steam demand causes a modest increase in the cost of electricity. This is consistent with findings reported by Zhai et al.20 Our work also reveals that the use of natural gas to meet some of the lowpressure steam demand is not as obvious as Herzog et al.2 claim. In key countries such as India and China with abundant and cheap coal supplies, along with gas prices between 3−4

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HEAT RECOVERY Herzog et al.2 mislead in their comment when they use performance data on advanced plants with highly efficient next© XXXX American Chemical Society

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DOI: 10.1021/acs.est.6b02022 Environ. Sci. Technol. XXXX, XXX, XXX−XXX

Environmental Science & Technology

Correspondence/Rebuttal

times those in the U.S.,21 the use of natural gas may not be attractive from a marginal cost perspective, particularly in comparison with renewables.

(7) Heijungs, R.; Guinée, J. B. An Overview of the Life Cycle Assessment Method - Past, Present, and Future. In Life Cycle Assessment Handbook: A Guide for Environmentally Sustainable Products; Curran, M. A., Ed.; John Wiley & Sons, Inc.: Somerset, NJ, 2012; pp 15−42. (8) Cost and performance of carbon dioxide capture from power generation; Finkenrath, M.; Paris, France, 2011; http://dx.doi.org/10. 1787/5kgggn8wk05l-en. (9) Rubin, E. S.; Davison, J. E.; Herzog, H. J. The cost of CO2 capture and storage. Int. J. Greenhouse Gas Control 2015, 40, 378−400. (10) Rubin, E. S. Understanding the pitfalls of CCS cost estimates. Int. J. Greenhouse Gas Control 2012, 10, 181−190. (11) ASPEN Plus Simulation of CO2 Recovery Process; Charles, W.; White, III.; Pittsburgh, PA, and Morgantown, WV, 2003; http://www. osti.gov/servlets/purl/810497-igyB4P/native/. (12) Stéphenne, K. Start-up of World’s First Commercial Postcombustion Coal Fired CCS Project: Contribution of Shell Cansolv to SaskPower Boundary Dam ICCS Project. Energy Procedia 2014, 63, 6106−6110. (13) Shaw, D. Cansolv CO2 capture: The value of integration. Energy Procedia 2009, 1 (1), 237−246. (14) Figueroa, J. D.; Fout, T.; Plasynski, S.; McIlvried, H.; Srivastava, R. D. Advances in CO2 capture technologyThe U.S. Department of Energy’s Carbon Sequestration Program. Int. J. Greenhouse Gas Control 2008, 2 (1), 9−20. (15) CO2 Capture at Coal Based Power and Hydrogen Plants; International Energy Agengy: Cheltenham, UK, 2014; http://www. ieaghg.org/docs/General_Docs/Reports/2014-03.pdf. (16) Cost and Performance Baseline for Fossil Energy Plants Vol. 1a: Bituminous Coal (PC) and Natural Gas to Electricity; National Energy Technology Laboratory, 2015; https://www.netl.doe.gov/FileLibrary/ Research/EnergyAnalysis/Publications/Rev3Vol1aPC_NGCC_final. pdf. (17) Boot-Handford, M. E.; Abanades, J. C.; Anthony, E. J.; Blunt, M. J.; Brandani, S.; Mac Dowell, N.; Fernández, J. R.; Ferrari, M.-C.; Gross, R.; Hallett, J. P.; et al. Carbon capture and storage update. Energy Environ. Sci. 2014, 7 (1), 130−189. (18) Gerbelová, H.; Versteeg, P.; Ioakimidis, C. S.; Ferrão, P. The effect of retrofitting Portuguese fossil fuel power plants with CCS. Appl. Energy 2013, 101, 280−287. (19) Carapellucci, R.; Giordano, L.; Vaccarelli, M. Studying heat integration options for steam-gas power plants retrofitted with CO2 post-combustion capture. Energy 2015, 85, 594−608. (20) Zhai, H.; Ou, Y.; Rubin, E. S. Opportunities for Decarbonizing Existing U.S. Coal-Fired Power Plants via CO 2 Capture, Utilization and Storage. Environ. Sci. Technol. 2015, 49 (13), 7571−7579. (21) OE Energy Market Snapshot; Federal Energy Regulatory Commission.; Washington, DC, 2014; http://www.ferc.gov/marketoversight/mkt-snp-sht/2014/05-2014-snapshot-central.pdf.

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CONCLUSION We respectfully submit that if Herzog et al.2 had real concerns about eq 1 and the conclusions that follow from it, they should have checked eq 1 against the papers they cited as evidence refuting our findings. Our colleagues would have found that these papers actually support our findings. For instance, if the design parameters for the subcritical 550 MW Cansolv PC− CCS plant described in the U.S. Department of Energy study16 are used in eq 1, an efficiency of 30.8% is estimated compared to the reported value of 31.2% (less than 1.5% difference). Similarly, if design parameters for the 837 MW advanced amine process supercritical PC−CCS plant discussed by Rubin et al.9 are plugged into eq 1, an efficiency of 36.1% is estimated compared to the reported efficiency of 36.2% (less than 0.5% difference). We thus reject the assertion by Herzog et al.2 that our “article [is] seriously flawed because, (1) the results presented are contradicted by actual practice and experience, and (2) the analyses presented are based on outdated data and design assumptions that are not at all consistent with how CCS projects are actually designed, constructed and operated.” In reality the studies they cite as support for their comment undermine their own assertions. Their choice of evidence firmly supports both the methods of our paper and our quantitative findings. Sarang D. Supekar Steven J. Skerlos* † Department of Mechanical Engineering, University of Michigan, 2350 Hayward Street, Ann Arbor, Michigan 48109, United States

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AUTHOR INFORMATION

Corresponding Author

*Phone: (734) 615-5253; fax: (734) 647-3170; e-mail: [email protected]. Notes

The authors declare no competing financial interest.

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REFERENCES

(1) Supekar, S. D.; Skerlos, S. J. Reassessing the Energy Penalty for Carbon Capture and Sequestration from Coal-Fired Power Plants. Environ. Sci. Technol. 2015, 49, 12576. (2) Herzog, H. J.; Rubin, E. S.; Rochelle, G. T. Comments on “Reassessing the Efficiency Penalty from Carbon Capture in CoalFired Power Plants. Environ. Sci. Technol. 2016, DOI: 10.1021/ acs.est.6b00169. (3) Koornneef, J.; van Keulen, T.; Faaij, A.; Turkenburg, W. Life cycle assessment of a pulverized coal power plant with postcombustion capture, transport and storage of CO2. Int. J. Greenhouse Gas Control 2008, 2 (4), 448−467. (4) House, K. Z.; Harvey, C. F.; Aziz, M. J.; Schrag, D. P. The energy penalty of post-combustion CO2 capture & storage and its implications for retrofitting the U.S. installed base. Energy Environ. Sci. 2009, 2 (2), 193. (5) Goto, K.; Yogo, K.; Higashii, T. A review of efficiency penalty in a coal-fired power plant with post-combustion CO2 capture. Appl. Energy 2013, 111, 710−720. (6) Environmental Management - Life Cycle Assessment - Life Cycle Impact Assessment; International Organization for Standardization.: Geneva, Switzerland, 2000; http://www.iso.org/iso/catalogue_detail. htm?csnumber=23153. B

DOI: 10.1021/acs.est.6b02022 Environ. Sci. Technol. XXXX, XXX, XXX−XXX