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### Chapter 7: Carbon Capture & Storage
Introduction Another possible approach for reducing CO 2 emissions from existing fossil fuel-fired EGUs is through the application of carbon capture and storage t echnology (CCS; sometimes also referred to as carbon capture and sequestratio n). In the recently proposed standards of performance for new fossil fuel-fired EGUs (79 FR 1430), the EPA proposed to find that the best system of emission reduction for new fossil fu el-fired boilers and IGCC units is partial application of CCS. In that proposal, the EPA found that, for new units, partial CCS has been adequately demonstrated; it is technically feasible ; it can be implemented at reasonable costs; it provides meaningful emission reductions; and its implementation will serve to promote further development and deployment of the technology. This chapter examines the potential for implementation of CCS technology at existing foss il fuel-fired utility boilers and IGCC units. Carbon Capture Options for Existing Fossil Fuel-fired EGUs In general, CO 2 capture technologies applicable to existing fo ssil fuel-fired power generation can be categorized into three appr oaches – (1) post-combustion capture; (2) precombustion capture; and (3) oxy-combustion. Each of these is described and discussed in more
detail below. Post-combustion Capture
Post-combustion CO 2 capture refers to removal of CO 2 from a combustion flue gas prior to discharging to the atmosphere. Separating CO 2 from such a gas stream can be challenging for
a number of reasons. Because CO 2 is a dilute fraction of the co mbustion flue gas – typically 13- 15 % in coal-fired systems and 3-4 % in natural gas-fired systems – a large volume of flue gas must be treated. The flue gas fr om typical combustion systems is usually at near atmospheric pressure. Therefore, most of the available capture systems rely on chemical absorption (chemisorption) options (e.g., amines) that requi re added energy to release the captured CO 2 and regenerate the solvent. Many of th e chemical solvents require a flue gas stream that is free of or has very low quantities of components – such as SO 2 , NO X , and HCl – that can degrade the solvent. The captured CO 2 must then be compressed from near atmospheric pressure to much higher pipeline pressures (about 2,000 psia).DRAFT April 4, 2014

2 Pre-combustion Capture Pre-combustion capture systems are applicable to fossil fuel gasification power plants (i.e., IGCC units) where coal or other solid foss il fuel (e.g., pet coke) is converted into a synthesis gas (or “syngas”) by applying heat under pressure in the pres ence of steam and limited
O 2 . The product syngas contains primarily H 2 and CO – and, depending on the fuel and gasification system – some lesser amount of CO 2 . The amount of CO 2 in the resulting syngas stream can be increased by “shifting” the com position via the catalytic water-gas shift (WGS) reaction. This process involves the catalytic reaction of steam (“wate r”) with CO (“gas”) to form
H 2 and CO 2 . The resulting CO 2 contained in the syngas is then captured before combustion of
the H 2 -enriched syngas for power generation in a co mbined cycle system. Contrary to the postcombustion capture flue gas, the IGCC syngas can contain a high volume of CO 2 and is pressurized. This allows the use of physical ab sorbents (e.g., SelexolTM, R ectisol®) that require much less added energy to release the captured CO 2 and require less compression to get to pipeline standards. Oxy-combustion Oxy-combustion systems for CO 2 capture rely on combusting coal or other fuels with relatively pure O 2 diluted with recycled CO 2 or CO 2 /steam mixtures. Unde r these conditions, the primary products of combustion are water and CO 2 , with the CO 2 purified by condensing the water. Challenges associated with oxy-com bustion include the capit al cost and energy consumption for a cryogenic air separation unit (ASU) to produce oxyge n, introduction of N 2 via boiler air infiltration, and excess O 2 in the CO 2 product stream.
CO 2 Transportation and Storage
CO 2 Pipeline Infrastructure Carbon dioxide has been transported via pipe lines in the U.S. for nearly 40 years. Approximately 50 million metric tons of CO 2 are transported each year through 3,600 miles of pipelines. Moreover, a re view of the 500 largest CO 2 point sources in the U.S. shows that 95 percent are within 50 miles of a possible ge ologic sequestration site, which would lower transportation costs. There are multiple factors that contribute to the cost of CO 2 transportation via pipelines including but not li mited to: availability and acqui sition of rights-of-way for new pipelines, capital costs, operating costs, length and diameter of pipeline, terrain, flow rate of
CO 2 , and the number of sources utilizing the pipeline.DRAFT April 4, 2014

3 Geologic Storage Existing project and regulato ry experience, research, and analogs (e.g. naturally existing
CO 2 sinks, natural gas storage, and acid gas injec tion), indicate that geol ogic sequestration is a viable long term CO 2 storage option. The viability of geologic sequestration of CO 2 is based on a demonstrated understanding of the fate of CO 2 in the subsurface. Geologic storage potential for
CO 2 is widespread and available throughout the U.S. and Canada. Nearly every state in the U.S. has or is in close proximity to formations with carbon storage potenti al including vast areas
offshore. Estimates based on DOE studies indicate that areas of the U. S. with appropriate geology have a storage potential of 2,300 billion to more than 20,000 billio n metric tons of CO 2 in deep saline formations, oil and gas reservoirs and un-mineable coal seams. 1 Other types of geologic formations such as organic rich shale an d basalt may also have the ability to store CO 2 ; and the DOE is currently evaluating their potential storage capacity.
Further evidence of the wide spread availability of CO 2 storage reserves in the U.S. comes from the Department of Interior’s U.S. Geological Survey (USGS) which has recently completed a comprehensive evaluation of the tech nically accessible storag e resource for carbon storage for 36 sedimentary basins in the onshore areas and State waters of the United
States. 2 The USGS assessment estimates a mean of 3,000 billion metric tons of subsurface CO 2 storage potential across the Un ited States. For comparison, this amount is 500 times the 2011 annual U.S. energy-related CO 2 emissions of 5.5 Gigatons (Gt). 3 Enhanced Oil Recovery (EOR) Geologic storage options also include use of CO 2 in EOR, which is th e injection of fluids
into a reservoir to incr ease oil production efficiency. EOR is typically conducted at a reservoir after production yields have decreasedfrom primary production. EOR using CO 2 , sometimes
referred to as ’CO 2 flooding’ or CO 2 -EOR, involves injecting CO 2 into an oil reservoir to help mobilize the remaining oil and make it ava ilable for recovery. The crude oil and CO 2 mixture is produced, and sent to a separato r where the crude oil is separa ted from the gaseous hydrocarbons

1 The United States 2012 Carbon Utilization and Storage Atla s, Fourth Edition, U.S Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory (NETL). 2 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment of geologic carbon dioxide storage resources – Results: U.S. Geological Survey Circular 1386, 41 p., http://pubs.usgs.gov/fs/2013/1386/

. 3 U.S. Geological Survey Geologic Carbon Dioxide Storage Resources Assessment Team, 2013, National assessment of geologic carbon dioxide storage resources – Summary: U.S. Geological Su rvey Factsheet 2013-3020, 6p.http://pubs.usgs.gov/fs/2013/3020/.DRAFT April 4, 2014

4 and CO 2 . The gaseous CO 2 -rich stream then is typically dehydrated, purified to remove hydrocarbons, recompressed, and re-injected into the oil or natural gas reservoir to further enhance recovery.
CO 2 -EOR has been successfully used at many production fields throughout the U.S. to increase oil recovery. The oil and natural gas indu stry in the United States has over 40 years of experience of injecti on and monitoring of CO 2 in the deep subsurface for the purposes of enhancing oil and natural gas production. This experience provid es a strong foundation for the injection and monitoring technologies that will be needed for successful deployment of CCS.
Evaluation of Retrofit CCS as BSER for Existing Fossil Fuel-fired EGUs Technical Feasibility In evaluating partial CCS as the BSER for new fossil fuel-fired boilers and IGCC units, the EPA determined that the technology is feasib le and adequately demonstrated for new units because the major components of CCS – the capture , the transportation, and the storage – are all proven technologies that have been demonstrated at large scale. While the EPA found that partial CCS is technically feasible for new fossil fuel-f ired boilers and IGCC units, it is much more
difficult to make that determination for the en tire fleet of existing fossil fuel-fired EGUs. Developers of new generating faci lities can select a physical loca tion that is more amenable to CCS – such as a site that is near an existing CO 2 pipeline or an existing oil field. Existing sources do not have the advantage of pr e-selecting an appropriate loca tion. Some existing facilities are
located in areas where CO 2 storage is not geologically favorab le and are not ne ar an existing CO 2 pipeline. Developers of new facilities also have the advantage of integrating the partial CCS system into the original design of the new fac ility. Integrating a retrofit CCS system into an existing facility is much more challenging. Some existing sources have a limited footprint and may not have the land available to add partial CCS system. Integration of the existing steam system with a retrofit CCS system can be particularly challenging. Partial CCS has been demonstrated at existing EGUs. It has been demonstrated at a pilotscale at Southern Company’s Plant Barry; it is be ing installed for large-scale demonstration at NRG’s WA Parish facility; and it will very soon be applied at commercial-scale as a retrofit at SaskPower’s Boundary Dam coal-fired EGU in Ca nada. However, all of these facilities are located in areas that are either near an existing oil field or in an areathat is geologically
favorable for CO 2 storage. Thus, at some existing facili ties, the implementation of partial CCS may be a viable GHG mitigation option and some utilities may choose to pursue that option.DRAFT April 4, 2014

5 However, the EPA does not believe that it can se rve as the best system of emission reduction for a broadly applicable GHG mitigation program. Ther efore, the EPA does not propose to find that CCS is a component of the best system of emission reduction for CO 2 emissions from existing
fossil fuel-fired EGUs.
Reasonableness of Cost In the proposed standard of performance fo r new fossil fuel-fired EGUs (79 FR 1430), the EPA found that the costs to implement partia l CCS (to a level to meet the proposed emission standard of 1,100 lb/MWh-gross) were consistent with costs for other non-natural gas-fired generating technologies – such as nuclear, biomass and geothermal – that utilities are considering
for new intermediate and base load generating capacity. The EPA also noted in the proposal, that mostof the relatively few new projects that are in the development phase are already planning to implement CCS; and, as a result, the standard would not have a significant imp act on nationwide energy prices. In contrast, the EPA noted that identifying CCS as BSER for new natural gas-fi red stationary combustion turbines, would likely result in higher nationwide electricity prices and could adversely affect the supply of electricity since the majority of new fossil-fuel fired pow er generation is projected to be natural gas combined cycle (NGCC). An emission standard fo r existing units based on CCS (or even partial CCS) would most certainly have an even more si gnificant effect on nationw ide electricity prices and could affect the reliability of the supply of electrici ty. Therefore, we do notfind that the cost to implement existing source emission standards to be reasonable, which further supports the determination that CCS is not an appropriate com ponent of the best system of emission reduction
for CO 2 emissions from existing fossil fuel-fired EGUs.
Emission Reductions and Prom otion of Advanced Technology An emission standard for existing units based on CCS (or even partial CCS) would clearly result in significant emission reductions and would certainly serve to promote further deployment, development and improvement in the most advanced technology. However, the
EPA has determined that such an emission standard is not technically feasible in all cases and
cannot be done at a reasonable cost at this time.