From: Szabo, Aaron <Aaron_L_Szabo@omb.eop.gov> 

Sent: Wednesday, July 29, 2015 10:05 PM 

To: Culligan, Kevin; Vasu, Amy; Harvey, Reid 

Cc: Frey, Nathan J.; Grossman, Andrea 

Subject: Summary of Interagency Comments Under EO 12866 and 1356 - GHG Mitigation 

TSD 

Attached please find a summary of interagency comments under EO 12866 and 13563 on the 

GHG Mitigation TSD. 

 

Thank you and please let know if you have any questions. 

<< Summary of Interagency Comments Under_EO 12866_ 13563_GHG_Mitigation_TSD.docx >> 
Chapter 7: Carbon Capture & Storage 

Introduction 

Another possible approach for reducing CO2 emissions from existing fossil fuel-fired 

steam generating EGUs is through the application of carbon capture and storage technology 

(CCS; sometimes also referred to as carbon capture and sequestration). In the final standards of 

performance for new fossil fuel-fired EGUs, the EPA has determined that the best system of 

emission reduction (BSER) for new fossil fuel-fired steam generating units is implementation of 

partial CCS (i.e., capturing a portion of the CO2 from the emission stream – in contrast to “full 

CCS” which would involve capturing > 90% of the CO2 from the emissions). The EPA has 

determined that that, for new steam generating EGUs (utility boilers and IGCC 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 fossil fuel-fired steam generating 

EGUs. 

Carbon Capture Options for Existing Fossil Fuel-fired EGUs 

In general, CO2 capture technologies applicable to existing fossil fuel-fired power 

generation can be categorized into three approaches – (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 CO2 capture refers to removal of CO2 from a combustion flue gas prior 

to discharging to the atmosphere. Separating CO2 from such a gas stream can be challenging for 

a number of reasons. Because CO2 is a dilute fraction of the combustion 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 from typical combustion systems is usually at near atmospheric 

pressure. Therefore, most of the available capture systems rely on chemical absorption 

(chemisorption) options (e.g., using amines) that require added energy to release the captured 

CO2 and regenerate the solvent. Many of the chemical solvents require a flue gas stream that is 

free of or has very low quantities of components – such as SO2 and HCl – that can degrade the 

Commented [A1]: Chapter number doesn’t match what is 

in the introduction. 
solvent. The captured CO2, if it is to be transported via pipeline for storage or use in enhanced oil 

recovery (EOR), must then be compressed from near atmospheric pressure to much higher 

pipeline pressures (about 2,000 psia). 

Pre-combustion Capture 

Pre-combustion capture systems are applicable to fossil fuel gasification power plants 

(i.e., IGCC units) where coal or other solid fossil fuel (e.g., petroleum coke) is converted into a 

synthesis gas (or “syngas”) by applying heat under pressure in the presence of steam and limited 

O2. The product syngas contains primarily H2 and CO – and, depending on the fuel and 

gasification system – some lesser amount of CO2. The amount of CO2 in the resulting syngas 

stream can be increased by “shifting” the composition via the catalytic water-gas shift (WGS) 

reaction. This process involves the catalytic reaction of steam (“water”) with CO (“gas”) to form 

H2 and CO2. The resulting CO2 contained in the syngas is then captured before combustion of 

the H2-enriched syngas for power generation in a combined cycle system. Contrary to the postcombustion capture flue gas, the IGCC syngas can contain a high volume of CO2 and is 

pressurized. This allows the use of physical absorbents (e.g., SelexolTM, Rectisol®) that require 

much less added energy to release the captured CO2 and require less compression to get to 

pipeline standards. 

Oxy-combustion 

Oxy-combustion systems for CO2 capture rely on combusting coal or other fuels with 

relatively pure O2 diluted with recycled CO2 or CO2/steam mixtures. Under these conditions, the 

primary products of combustion are water and CO2, with the CO2 purified by condensing the 

water. Challenges associated with oxy-combustion include the capital cost and energy 

consumption for a cryogenic air separation unit (ASU) to produce oxygen, introduction of N2 via 

boiler air infiltration, and excess O2 in the CO2 product stream. 

CO2 Transportation and Storage 

CO2 Pipeline Infrastructure 

Carbon dioxide has been transported via pipelines in the U.S. for nearly 40 years. 

Approximately 50 million metric tons of CO2 are transported each year through 3,600 miles of 
pipelines. Moreover, a review of the 500 largest CO2 point sources in the U.S. shows that 95 

percent are within 50 miles of a possible geologic sequestration site, which would lower 

transportation costs. There are multiple factors that contribute to the cost of CO2 transportation 

via pipelines including but not limited to: availability and acquisition of rights-of-way for new 

pipelines, capital costs, operating costs, length and diameter of pipeline, terrain, flow rate of 

CO2, and the number of sources utilizing the pipeline. 

Geologic Storage 

 Existing project and regulatory experience, research, and analogs (e.g. naturally existing 

CO2 sinks, natural gas storage, and acid gas injection), indicate that geologic sequestration is a 

viable long term CO2 storage option. The viability of geologic sequestration of CO2 is based on a 

demonstrated understanding of the fate of CO2 in the subsurface. Geologic storage potential for 

CO2 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 potential 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 billion metric tons of CO2

in deep saline formations, oil and gas reservoirs and un-mineable coal seams.1

 Other types of 

geologic formations such as organic rich shale and basalt may also have the ability to store CO2; 

and the DOE is currently evaluating their potential storage capacity. 

 Further evidence of the widespread availability of CO2 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 technically accessible storage 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 CO2

storage potential across the United States. For comparison, this amount is 500 times the 2011 

annual U.S. energy-related CO2 emissions of 5.5 Gigatons (Gt).3

                                                            

1

 The United States 2012 Carbon Utilization and Storage Atlas, 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 Survey Factsheet 2013-3020, 

6p.http://pubs.usgs.gov/fs/2013/3020/.
Enhanced Oil Recovery (EOR) 

Geologic storage options also include use of CO2 in EOR, which is the injection of fluids 

into a reservoir to increase oil production efficiency. EOR is typically conducted at a reservoir 

after production yields have decreased from primary production. EOR using CO2, sometimes 

referred to as ‘CO2 flooding’ or CO2-EOR, involves injecting CO2 into an oil reservoir to help 

mobilize the remaining oil and make it available for recovery. The crude oil and CO2 mixture is 

produced, and sent to a separator where the crude oil is separated from the gaseous hydrocarbons 

and CO2. The gaseous CO2-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. 

CO2-EOR has been successfully used at many production fields throughout the U.S. to 

increase oil recovery. The oil and natural gas industry in the United States has over 40 years of 

experience of injection and monitoring of CO2 in the deep subsurface for the purposes of 

enhancing oil and natural gas production. This experience provides 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 feasible 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-fired boilers and IGCC units, it is more difficult to 

make that determination for the entire fleet of existing fossil fuel-fired EGUs. Developers of new 

generating facilities can select a physical location that is more amenable to CCS – such as a site 

that is near an existing CO2 pipeline or an existing oil field. Existing sources do not have the 

advantage of pre-selecting an appropriate location. Some existing facilities are located in areas 

where CO2 storage is not geologically favorable and are not near an existing CO2 pipeline. 

Developers of new facilities also have the advantage of integrating the partial CCS system into 

the original design of the new facility. Integrating a retrofit CCS system into an existing facility 

Deleted: ’CO2
can be more challenging. Some existing sources have a limited footprint and may not have the 

land or space available to add the equipment needed to implement CO2 capture, compression, 

and transportation. 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 and it is being installed for large-scale demonstration at 

NRG’s WA Parish facility. SaskPower’s Boundary Dam Unit #3, a 110 MW coal-fired utility 

boiler in Saskatchewan, began operations in October 2014. The facility has retrofit postcombustion carbon capture technology that is capturing approximately 90 % of the CO2 from 

flue gas stream. All of these facilities are located in areas that are either near an existing oil field 

or in an area that is geologically favorable for CO2 storage. Thus, at some existing facilities, the 

implementation of partial CCS may be a preferred compliance option. However, for the reasons 

stated above, CCS as a system of emission reduction would be much more easily implemented at 

some existing plants relative to others, and for some would be precluded due to limited space. 

Therefore, identification of CCS as the best system of emission reduction for existing fossil fuel 

fired EGUs would require subcategorization of EGUs based on such factors. 

Reasonableness of Cost 

In the proposed standard of performance for new fossil fuel-fired EGUs (79 FR 1430), 

the EPA proposed that the costs to implement partial CCS (to a level to meet the proposed 

emission standard of 1,100 lb/MWh-gross) were consistent with costs for other non-natural gasfired 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 most of 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 

impact on nationwide energy prices. In issuing the final NSPS for new fossil fuel-fired EGUs, 

the EPA – in response to public comments and updated cost information – reevaluated the cost to 

implement partial CCS and adjusted the final emission limitation to a standard of 1,400 

lbs/MWh-gross. 

In contrast, the EPA did not propose to identify full or partial CCS as BSER for new 

natural gas-fired stationary combustion turbines noting technical challenges to implementation of 

Deleted: viable 

Deleted: GHG mitigation

Deleted: and some utilities may choose to pursue that 

option

Deleted: the EPA does not believe that it can serve as the 

best system of emission reduction as a broadly applicable 

GHG mitigation program

Deleted: the EPA did not propose to find that CCS is a 

component of the best system of emission reduction for CO2

emissions from existing fossil fuel-fired EGUs
CCS at NGCC units as compared to implementation at new solid fossil fuel-fired sources. The 

EPA also noted that, because virtually all new fossil fuel-fired generating capacity is projected to 

use NGCC technology, requiring full or partial CCS would have more of an impact on the price 

of electricity than the few projected coal plants with CCS, and the number of projects would 

make it difficult to implement in the short term. 

An emission standard for existing units based on CCS (or even partial CCS) would most 

certainly have an even more significant effect on nationwide electricity prices. Importantly, the 

approach identified as the best system of emission reduction will achieve equivalent or greater 

emission reductions at a far lower cost and provide sources and states with greater flexibility to 

ensure reliability. Therefore, as stated earlier, the EPA did not find partial CCS to be an 

appropriate component of the best system of emission reduction for CO2 emissions from existing 

fossil fuel-fired EGUs. 

Emission Reductions and Promotion 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 may not be feasible in a number of cases and 

would involve higher costs (and less flexibility) than the approach identified as the best system 

of emission reduction. 

CCS and CCU in State Plans 

Affected EGUs may utilize retrofit CCS technology to reduce reported stack CO2

emissions from the EGU.4

 Affected EGUs that apply CCS under a state plan must meet the same 

monitoring, recordkeeping and reporting requirements for sequestered CO2 as new units with 

CCS capability subject to the final CAA section 111(b) rule for new EGUs.5

 Specifically, the 

final CAA section 111(b) rule for new sources requires that, if a new affected EGU uses CCS to 

                                                            

4

 Addition of retrofit CCS technology should not trigger CAA section 111(b) applicability for modified or 

reconstructed sources. Pollution control projects do not trigger NSPS modifications and addition of CCS technology 

does not count toward the capital costs of reconstruction. 

5

 Standards of Performance for Greenhouse Gas Emissions from New, Modified, and Reconstructed Stationary 

Sources: Electric Utility Generating Units.

Deleted: and could affect the reliability of the supply of 

electricity

Deleted: that the cost to implement 

Deleted: at existing source emission standards to be 

reasonable, which further supports the determination that

Deleted: CCS is not 

Deleted: technically or logistically 

Deleted: cannot be broadly implemented at a reasonable 

cost at this time
meet the applicable CO2 emission limit, the EGU must report in accordance with 40 CFR part 98 

subpart PP (Suppliers of Carbon Dioxide), and the captured CO2 must be injected at a facility or 

facilities that report in accordance with 40 CFR part 98 subpart RR (Geologic Sequestration of 

Carbon Dioxide).6,7 See 40 CFR part 60.46Da(h)(5) and part 60.5555(d). Taken together, these 

requirements ensure that the amount of captured and sequestered CO2 will be tracked as 

appropriate at project- and national-levels, and that the status of the CO2 in its sequestration site 

will be monitored, including air-side monitoring and reporting. As detailed in the preamble for 

the CAA section 111(b) standards for new EGUs, the EPA is convinced that there is ample 

evidence that CCS is technically feasible and that partial CCS can be implemented at a new 

fossil fuel-fired steam generating EGU at a cost that is consistent with the cost of other 

dispatchable, non-NGCC generating options. 

The EPA received comments suggesting that carbon capture and utilization (CCU) 

technologies should also be allowed as a CO2 emission rate adjustment measure for affected 

EGUs. Potential alternatives to storing CO2 in geologic formations are emerging and these 

relatively new potential alternatives may offer the opportunity to offset the cost of CO2 capture. 

For example, captured anthropogenic CO2 may be stored in solid carbonate materials such as 

precipitated calcium carbonate (PCC) or magnesium or calcium carbonate, bauxite residue 

carbonation, and certain types of cement through mineralization. The carbonate materials 

produced can be tailored to optimize performance in specific industrial and commercial 

applications. For example, these carbonate materials have been used in the construction industry 

and, more recently and innovatively, in cement production processes to replace Portland cement. 

The Skyonics Skymine® project, which opened its demonstration project in October 

2014, is an example of captured CO2 being used in the production of carbonate products. This 

plant converts CO2 into commercial products. It captures over 75,000 tons of CO2 annually from 

a San Antonio, Texas, cement plant and converts the CO2 into other products including sodium 

                                                            

6

 The final CAA section 111(b) rule finalizes amendments to subpart PP reporting requirements, specifically 

requiring that the following pieces of information be reported: (1) the electronic GHG Reporting Tool identification 

(e-GGRT ID) of the EGU facility from which CO2 was captured, and (2) the e-GGRT ID(s) for, and mass of CO2

transferred to, each GS site reporting under subpart RR. As noted, the final 111(b) rule also requires that any 

affected EGU unit that captures CO2 to meet the applicable emissions limit must transfer the captured CO2 to a 

facility that reports under 40 CFR part 98 subpart RR. 

7

 Under final requirements in the CAA 111(b) NSPS, any well receiving CO2 captured from an affected source, be it 

a Class VI or Class II well, must report under subpart RR. A UIC Class II well’s regulatory status does not change 

because it receives such CO2, nor does it change by virtue of reporting under subpart RR.
carbonate and sodium bicarbonate.8

 Other companies – including Calera9 and New Sky10 – also 

offer commercially available technology for the beneficial use of captured CO2. These processes 

can be utilized in a variety of industrial applications – including at fossil fuel-fired power plants. 

However, consideration of how these emerging alternatives could be used to meet CO2

emission performance rates or state CO2 emission goals would require a better understanding of 

the ultimate fate of the captured CO2 and the degree to which the method permanently isolates 

the captured CO2 or displaces other CO2 emissions from the atmosphere. 

Several commenters also suggested that algae-based CCU (i.e., the use of algae to 

convert captured CO2 to useful products – especially biofuels) should be recognized for its 

potential to reduce emissions from existing fossil-fueled EGUs. 

Unlike geologic sequestration, there are currently no uniform monitoring and reporting 

mechanisms to demonstrate that these alternative end uses of captured CO2 result in overall 

reductions of CO2 emissions to the atmosphere. As these alternative technologies are developed, 

the EPA is committed to work collaboratively with stakeholders to evaluate the efficacy of 

alternative utilization technologies, to address any regulatory hurdles, and to develop appropriate 

monitoring and reporting protocols to demonstrate CO2 reductions. 

In the meantime, the EPA has specified that state plans may allow affected EGUs to use 

qualifying CCU technologies to reduce CO2 emissions that are subject to an emission standard, 

or those that are counted when demonstrating achievement of the CO2 emission performance 

rates or a state rate-based or mass-based CO2 emission. Approvable state plans must include 

analysis supporting how the proposed qualifying CCU technology results in CO2 emission 

mitigation and provide monitoring, reporting, and verification requirements to demonstrate the 

reductions. The EPA would then review the appropriateness and basis for the analysis and the 

verification requirements in the course of its review of the state plan. 

                                                            

8

 http://skyonic.com/technologies/skymine. 

9

 http://www.calera.com/beneficial-reuse-of-co2/process.html.

10 http://www.newskyenergy.com/index.php/products/carboncycle.