1 - TECHNICAL SUPPORT DOCUMENT –

To: Docket EPA-HQ-OAR-2013-0495
Date: July 10, 2015
Subject: Literature Survey of Carbon Capture Techn ology

Introduction

On January 8, 2014, the Environmental Protection Ag ency (EPA) proposed New Source Performance Standards (NSPS) to limit carbon dioxid e (CO 2 ) emissions from new fossil fuelfired electricity generating units (EGUs) under Cle an Air Act (CAA) §111(b). 1 Carbon capture and storage (CCS), also known as "carbon capture an d sequestration," was evaluated as an option for new steam generating boilers and integrated gas ification combined cycle (IGCC) units in developing the proposed and final NSPS. In determin ing the best system of emission reduction adequately demonstrated (BSER) to establish the sta ndards, the EPA reviewed literature covering existing projects that implement CCS, exis ting projects that implement various components of CCS, planned CCS projects, and scient ific and engineering studies of CCS. The final NSPS contains an emission limit of 1,400 poun ds CO 2 per megawatt hour on a gross basis (lb CO 2 /MWh-g) for new steam generating boilers and IGCC u nits based on partial CCS (i.e., CCS on a portion or "slip-stream" of the EGU exhaus t). Among other compliance approaches, 2
partial CCS was determined to be adequately demonst rated based on the fact that postcombustion CCS is demonstrated in full-scale operat ion within the electricity generating industry, and full-scale pre-combustion CCS has bee n demonstrated in several chemical industry plants with results that are reasonably transferabl e to the electricity generating sector. It is important to note that the NSPS does not require ne ar-term widespread use of full CCS for all electric utilities, but rather is based on partial CCS for only the subset of new fossil-fuel fired electric utility boilers or IGCC units.

The purpose of this technical support document (TSD ) is to provide an overview of CCS technology and describes the status of sources impl ementing CCS projects to date. This TSD provides information on the technological feasibili ty of CCS (including partial CCS), but does not discuss costs. The EPA's conclusions regarding the costs and emission reductions associated with implementation of partial CCS are based on in- depth studies of costs by DOE/NETL reports and recent EIA AEO projections and are documented i n a separate memorandum and the Regulatory Impact Analysis for the final NSPS. Simi larly, a separate document discusses funding mechanisms associated with CCS projects.

This document is organized as follows:

1 Standards of Performance for Greenhouse Gas Emissi ons From New Stationary Sources: Electric Utility Generating Units, 79 Fed. Reg. 1430.

2 It is noted that a new utility boiler or IGCC unit can meet the final standard of performance of 1,40 0 lb CO2/MWh by co-firing natural gas should project developers choose to delay implementation of partial CCS.2

I. Overview of CCS Technology for Fossil-fuel Fired EGUs

A. CO 2 Capture Technology

1. Post-combustion CO 2 capture

2. Pre-combustion CO 2 capture 3. Oxy-combustion CO 2 capture

B. CO 2 Compression

C. CO 2 Transportation Pipeline Infrastructure
D. Geologic Sequestration
E. Alternatives to Geologic Sequestration
F. Continuing Research and Policy Development
II. Sources Utilizing CCS

A. Post-combustion

B. Pre-combustion
C. Oxy-combustion
III. Bibliography

I. Overview of CCS Technology for Fossil-fuel Fired EGUs

Use of fossil fuel to generate electricity commonly occurs in one of the following systems:

• A steam generating unit (also referred to simply as a “boiler”) that feeds a steam turbine that spins an electric generator.

• A combustion turbine (or reciprocating internal com bustion engine) that directly drives the generator. Some modern power plants use a “combined cycle” electric power generation process, in which a gaseous or liq uid fuel is burned in a combustion turbine that both drives electrical generators and provides heat to produce steam in a heat recovery steam generator (HRSG) that drives a second electric generator to increase the overall efficiency of the electric pow er generation process.

• An integrated gasification combined cycle (IGCC) sy stem that first gasifies solid fuel and burns the resulting syngas in a combined cycle stationary combustion turbine for electric generation.

The majority of new fossil-fuel fired electric gene rating units are projected to use natural-gas combined cycle technology which results in lower CO 2 emissions per MWh of electricity produced than steam generating units or IGCC system s burning solid fossil fuels such as coal. Use of CCS was analyzed as an option for reducing C O 2 emissions from new steam generating units and new IGCC systems for purposes of the NSPS

.

Carbon capture and storage (CCS) involves the separ ation and capture of CO2 from flue gas, or syngas in the case of IGCC. CCS is a three-step pro cess that includes:

1. Capture of CO 2 from electric generating units (or other industria l processes);

2. Compression and transport of the captured CO 2 (usually in pipelines);

3. Underground injection and geologic sequestration (a lso referred to as storage) of the

CO 2 into deep underground rock formations. These forma tions are often a mile or3 more beneath the surface and consist of porous rock that holds the CO 2 . Overlying these formations are impermeable, non-porous layers of rock that trap the CO 2 and prevent it from migrating upward.

Figure 1 illustrates the typical depth at which CO 2 would be injected.

Figure 1. CCS Schematic
(Subsurface depth to scale, 5,280 feet equals one m ile) (EPA, 2013c)

Geologic sequestration is feasible in different typ es of geologic formations including deep saline formations (formations with high salinity formation fluids) or in oil and gas formations, such as where injected CO 2 increases oil production efficiency through a proc ess referred to as enhanced oil recovery (EOR). CO 2 may also be used for other types of enhanced recov ery, such as for natural gas production. Reservoirs such as unmineab le coal seams also offer the potential for geologic storage. 3

3 Other types of opportunities include organic shale s and basalt.4

A study prepared for the U.S. DOE by the Pacific No rthwest National Laboratory (Dooley, 2009) evaluated the development status of various C CS technologies. The study addressed the availability of capture processes; transportation o ptions (CO2 pipelines); injection technologies; and measurement, verification, and monitoring techn ologies. The study concluded that, in general, CCS was technically viable at the time of the report (2009) although full-scale CCS systems had not yet been installed and fully integr ated at an EGU at that time. The study also did not address the cost or energy requirements of impl ementing CCS technology. 4

In 2010, an Interagency Task Force on Carbon Captur e and Storage was established to develop a comprehensive and coordinated federal strategy to s peed the commercial development and deployment of CCS technologies (Interagency Task Fo rce, 2010). The Task Force was specifically charged with proposing a plan to overc ome the barriers to the widespread, costeffective deployment of CCS within 10 years, with a goal of bringing commercial demonstration projects online by 2016. As part of its work, the T ask Force prepared a report that summarizes

the state of CCS and identified technical and non-t echnical barriers to implementation. 5

Much research and development has occurred in the 5 years since these DOE and interagency reports were written in the 2009-2010 timeframe. As described in more detail in Section II of this report, full-scale EGU CCS demonstration projects a re underway. Research to reduce the energy requirements of CCS technologies and improve its co st-effectiveness continues, as described in section I.F of this document. A more recent report from the DOE/NETL provides a technology update and summarizes research continuing research sponsored by the DOE (NETL, 2013). The EPA's updated cost analysis for CCS systems based o n DOE/NETL analyses (from 2010-2015), EIA AEO projections (from 2014), and other recent i nformation is presented in the RIA for the

NSPS.

The following subsections provide an overview of CO 2 capture technology, CO 2 compression,

CO 2 pipeline infrastructure for transportation, geolog ic sequestration, and alternatives to geologic sequestration.

A. CO 2 Capture Technology

In general, CO 2 capture technologies applicable to fossil-fuel fire d power generation can be
categorized into three approaches:

• Post-combustion systems are designed to separate CO 2 from the flue gas produced by fossil-fuel combustion in air.

4 For up-to-date information on Department of Energy ’s National Energy Technology Laboratory’s (NETL) Carbon Sequestration Program go to the NETL web site (NETL, 2015b) at: http://www.netl.doe.gov/research/coal/carbon-storag e/research-and-development.

5 For additional information on the Interagency Task Force and its findings on CCS, go to: http://www.epa.gov/climatechange/Downloads/ccs/CCS- Task-Force-Report-2010.pdf5

• Pre-combustion systems are designed to separate CO 2 and H 2 in the high-pressure syngas produced at IGCC power plants.

• Oxy-combustion uses high-purity oxygen (O 2 ), rather than air, to combust coal and therefore produces a highly concentrated CO 2 stream.

The post- and pre-combustion CO 2 -capture processes typically use solvents, solid so rbents, and membrane-based technologies for separating and capt uring CO2. Solvents chemically absorb the

CO 2 which is separated from the solvent in a regenerat ion step. Solid sorbents capture CO2 through chemical adsorption, physical adsorption, o r a combination of the two effects. Membrane-based capture uses permeable or semi-perme able materials to produce a highly concentrated CO2 stream that does not require a sep aration/capture step.

Each of the CO 2 -capture approaches results in increased capital an d operating costs and decreased electricity output (or energy penalty 6 ), thereby increasing the cost of electricity. 7 The energy penalty occurs because the CO 2 capture process uses some of the energy produced f rom the plant (Interagency Task Force, 2010). Research is underway to reduce CO 2 capture costs and to improve performance. The DOE/NETL sponsors an ex tensive research, development and demonstration program that is focused on developing advanced technology options that will dramatically lower the cost of capturing CO 2 from fossil-fuel energy plants compared to currently available capture technologies. The large -scale CO 2 capture demonstrations that are currently planned and in some cases underway, under DOE’s initiatives, as well as other domestic and international projects, will continue to generate operational knowledge and enable continued commercialization and deployment of these technologies. The EPA is currently finalizing an NSPS limit based on partial CCS (as o pposed to CCS of the full exhaust stream) to help mitigate the energy penalty and costs of CCS a s the technology continues to emerge and be refined through further research.

Each of the CO 2 -capture systems are described and discussed in mor e detail in the subsections below. Facility-specific applications of CO 2 capture systems are discussed in Section II.

1. Post-combustion CO 2 capture

Post-combustion CO 2 capture refers to removal of CO 2 from combustion flue gas prior to discharge to the atmosphere. It is referred to as “ post-combustion capture” because the CO 2 is the

6 The energy penalty represents the percentage reduc tion in the power plant operating efficiency. For e xample, a reduction in efficiency from 30 percent to 20 perce nt represents a 10 percentage point drop in efficie ncy, which is equivalent to a 33 percent energy penalty.

7 There is on-going research sponsored by DOE/NETL a nd others to further reduce the energy requirements of the carbon capture systems. Progress is being made. For example, the heat duty (the energy required to reg enerate the capture solvent) for the amine scrubbing process us ed at the Searles Valley facility in the mid-70’s w as about 12

MJ/mt CO 2 removed as compared to a heat duty of about 2.5 MJ /mt CO 2 removed for the amine processes used in 2014 at Boundary Dam and for the amine system that will be used at the WA Parish facility.6

product of the combustion of the primary fuel and t he capture takes place after the combustion of that fuel. A simplified process schematic of post-c ombustion CO 2 capture is shown in Figure 2 (NETL, 2013).7 Figure 2: Diagram Illustrating a Pulverized Coal Bo iler with

Post-Combustion CO 2 Capture

As noted previously, in a typical fossil fuel-fired steam generating unit, fuel is burned with air in a boiler to produce steam that drives a turbine/gen erator to produce electricity. Flue gas from the boiler consists primarily of N 2 and CO 2 with other components in trace amounts (e.g., part iculate matter (PM), sulfur oxides (SOx), nitrogen oxides ( NOx), hydrochloric acid (HCl) etc.) The CO 2 capture process is located downstream of the conven tional pollutant controls for removal of PM and acid gases so these components will not interfe re with CO 2 removal. In addition to the need to remove pollutants upstream of the CO 2 capture system, challenges to separating CO 2 from steam generating unit combustion flue gas include:

• the high volume of gas to be treated because the CO 2 is dilute (13–15 volume percent in coal-fired systems);

• the low pressure [15–25 pounds per square inch (psi )] of the flue gas;

• and the large auxiliary power load to compress capt ured CO 2 from near atmospheric pressure to pipeline pressure (about 2,200 psi).

The volume of flue gas to be treated (and the assoc iated energy penalty) is reduced in partial CO 2 capture systems, where a slipstream of the flue gas is treated as opposed to the entire flue gas

stream.

The CO 2 capture process involves use of a chemical solvent , solid sorbent, or membrane to separate CO 2 from the flue gas. Amine-based solvent systems are most commonly used for postcombustion capture systems. When contacted with the combustion flue gas, then solvent participates in a chemical absorption (chemisorptio n) separation process in which the CO 2 is absorbed by the liquid solvent. Solid sorbents can be used to capture CO 2 from flue gas through8

chemical adsorption, physical adsorption, or a comb ination of the two. Possible configurations for contacting the flue gas with solid sorbents inc lude fixed, moving, and fluidized beds. Membrane-based capture uses permeable or semi-perme able materials that allow for the selective transport/separation of CO 2 from flue gas (NETL, 2015c).

Gas absorption processes using chemical solvents, s uch as amines, to separate CO 2 from other gases have been in use since the 1930s in the natur al gas industry to produce food and chemical grade CO 2 . Amine-based solvent systems are in commercial use for scrubbing CO 2 from industrial flue gases and process gases, and are av ailable for use in CCS systems at electric utilities. Following absorption into the amine-bas ed solvent, a high purity CO 2 stream is separated from the solvent in a steam stripping (so lvent regeneration) process, where the solvent is heated with low pressure steam from the power pl ant’s steam cycle. Solvent regeneration is responsible for much of the “energy penalty” of the CO 2 capture system because steam that could otherwise be used to generate electricity is instead used in the solvent regeneration process. Development of advanced solvents – those t hat are chemically stable, have high CO 2 absorption capacities, and have low regeneration en ergy requirements – continues to be an active area of research. The DOE/NETL's post-combustion CO 2 control technology R&D program includes projects directed at the use of solvents, solid sorbents, and membranes.

Amines chemically react with CO 2 via reversible reactions to form water-soluble com pounds. Despite the low CO 2 partial pressure in combustion flue gas, amines ar e capable of achieving high levels of CO 2 capture due to fast kinetics and strong chemical r eactions. However, the absorption capacity for commercially available amin es is chemically limited, requiring two

molecules of amine for each molecule of CO 2 . In addition, usable amine solution concentrations are typically limited by viscosity and corrosion. T herefore, current amine systems are only between 20 and 30 percent amine with the remaining being water. Although the water present in the solution helps control the solvent temperature during absorption, which is an exothermic reaction, the water also requires significant amoun ts of sensible heating and stripping energy upon CO 2 regeneration. Not every amine system is the same, and various vendors offer different designs. In general, depending on the amount of hea t integration, anywhere from 1,550 to greater than 3,000 British thermal units (Btu) per pound of CO 2 in the form of low pressure steam (approximately 45 psi) is required to regenerate th e solvent to produce a concentrated CO 2 stream at a pressure of approximately 25 psi (Inter agency Task Force, 2010).

An amine-based post-combustion capture process is d epicted in Figure 3

.9 Figure 3. Schematic Diagram of Amine-based CO 2 Capture Process

After conventional air pollutant (SOx, NOx, PM) cle anup, the combustion flue gas enters an absorber reactor and flows counter-currently to a C O2-lean solvent where CO 2 is absorbed into, and chemically reacts with the amine solution. The treated flue gas (mostly N 2 ) is discharged to the atmosphere, and the CO 2 -rich amine solution is pumped to a solvent regener ation column

where the CO 2 -rich solution is heated in order to reverse the ch emical reactions between the CO 2 and amine solvent. Steam extracted from the turbine cycle provides the heat for regeneration of the amine solvent in the solvent regeneration colum n. Consequently, CO 2 is released, producing a concentrated stream that exits the regeneration c olumn and is then cooled and dehumidified in preparation for compression, transport, and storage . From the solvent regeneration column, the

CO 2 -lean solution is cooled and returned to the absorb er for reuse (Interagency Task Force, 2010).

Post-combustion CO 2 capture offers the greatest near-term potential fo r reducing power sector

CO 2 emissions because it can be tuned for various leve ls of CO 2 capture (e.g., in partial capture systems as indicated by the optional bypass in Figure 2 ). Post-combustion capture technologies are available for application to conventional coal- fired power plants and the combustion flue gas from IGCC power plants (Interagency Task Force, 201 0; NETL, 2013). Many projects are in the planning stages for demonstration scale-up includin g the Alstom chilled ammonia process and several amine-based processes (e.g., Fluor [Econami ne], ABB/Lummus, Mitsubishi Heavy Industries [MHI], HTC Purenergy, Aker Clean Carbon, Cansolv, et al.) (Interagency Task Force, 2010).

The advancement of amine-based solvents is an examp le of technology development that has improved the cost and performance of CO 2 capture. Most single component amine systems are10

not practical in a flue gas environment as the amin e will rapidly degrade in the presence of oxygen and other contaminants. The Fluor Econamine FG process uses a monoethanolamine (MEA) formulation specially designed to recover CO 2 and contains a corrosion inhibitor that allows the use of less expensive, conventional mate rials of construction. Other commercially available processes use sterically hindered amine f ormulations (for example, the Mitsubishi Heavy Industries KS–1 solvent) which are less susce ptible to degradation and corrosion issues.
Several companies offering post-combustion CO 2 capture technologies have offered performance guarantees or made public statements regarding the technical feasibility of their systems for CO 2 capture from fossil-fuel fired power plants. For e xample:

• Linde and BASF offer performance guarantees for CCS technology. The two companies are jointly marketing new, advanced techn ology for capturing CO2 from low pressure gas streams in power or chemical plant s. In product literature (BASF/Linde, undated) they note that Linde will provide a turn-key carbon capture plant using a scrubbing process and solvents develo ped by BASF, the world’s leading technical supplier for gas treatment. They further note that:

o The captured carbon dioxide can be used commerciall y for example for EOR (enhanced oil recovery) or for the production of ur ea. Alternatively it can be stored underground as a carbon abatement measure. [ ...] The PCC (PostCombustion Capture) technology is now commercially available for lignite and hard coal fired power plant [...] applications.

o The alliance between Linde, a world-leading gases a nd engineering company and BASF, the chemical company, offers great benefi ts [...] Complete capture plants including CO 2 compression and drying ... Proven and tested process es including guarantee ... Synergies between process, en gineering, construction and operation ... Optimized total and operational cos ts for the owner.

• Fluor has developed patented CO 2 recovery technologies to help its clients reduce GHG emissions. The Fluor product literature (Fluor, 2015) specifically points to Econamine FG PlusSM process which uses an amine sol vent to capture and produce food grade CO 2 from post-combustion sources. The literature furth er notes that

Econamine FG Plus SM (EFG+) is also used for carbon capture and sequest ration projects, that the proprietary technology provides a proven, cost-effective process for

the removal of CO 2 from power plant flue gas streams and that the pro cess can be customized to meet a power plant's unique site requ irements, flue gas conditions, and operating parameters.

• Fluor has also published an article titled “Commerc ially Available CO 2 Capture Technology” in which it describes the EFG+ technolo gy (Johnson et. al, 2009). The article notes, “Technology for the removal of carbo n dioxide (CO 2 ) from flue gas streams has been around for quite some time. The te chnology was developed not to address the GHG effect but to provide an economic s ource of CO 2 for use in enhanced oil recovery and industrial purposes, such as in the beverage industry.”

• Mitshubishi Heavy Industries (MHI) offers a CO 2 capture system that uses a proprietary energy-efficient CO 2 absorbent called KS-1TM. Compared with the11 conventional monoethanolamine (MEA)-based absorbent , KS-1TM solvent requires less solvent circulation to capture the CO2 and les s energy to recover the captured

CO 2

.

• Shell has developed the CANSOLV CO 2 Capture System, which Shell describes in its product literature as a world leading amine based C O 2 capture technology that is ideal for use in fossil fuel-fired power plants where eno rmous amounts of CO 2 are generated. The company also notes that the technolo gy can help refiners, utilities and other industries lower their carbon intensity and m eet stringent GHG abatement regulations by removing CO 2 from their exhaust streams, with the added benefit of simultaneously lowering SO 2 and NO 2 emissions.

The DOE/NETL and private industry are continuing to sponsor research on advanced solvents (including new classes of amines) to improve the CO 2 capture performance and reduce costs.

2. Pre-combustion CO 2 capture

Pre-combustion CO 2 capture, as its name implies, takes place before t he process gas is combusted to generate steam at a power plant. Pre-c ombustion capture is applicable mainly to IGCC processes where fuel is converted into gaseous components by applying heat under pressure in the presence of steam and limited O 2 , as shown in Figure 4.12

Figure 4. Schematic of an integrated gasification c ombined cycle (IGCC) power plant. (EPA, 2010)

In an IGCC system, the fuel (usually coal or petrol eum coke at electric utilities) is heated with water and oxygen in an oxygen-lean environment. Unl ike a boiler, a gasifier carefully controls the amount of air or oxygen available insi de it so only a small portion of the fuel burns completely. This "partial oxidation" process provid es heat to drive gasification reactions. Rather than burning, most of the fuel is chemically broken apart by the heat and pressure in the gasifier, setting into motion chemical reactions that produce syngas. The fuel (carbon), water and oxygen react to form primarily a mixture of hydrogen (H 2 ) and carbon monoxide (CO) known as synthesis gas or "syngas" according to the followin g high temperature reaction:

3C + H 2 O + O 2  H 2 + 3CO

Although syngas is predominantly H 2 and CO, it can include other gaseous constituents (e.g., hydrogen sulfide (H 2 S), carbonyl sulfide (COS), and CO 2 ) in varying compositions depending on13

fuel characteristics and the conditions in the gasi fier. The amount of CO 2 in syngas depends upon the specific gasifier technology used, the operatin g conditions, and the fuel used; but is typically less than 20 volume percent. The gasification proce ss also produces inorganic materials originating from the coal (e.g., minerals, ash). A fter removal of the impurities, the syngas is combusted using a conventional combustion turbine i n a combined cycle configuration (i.e., a combustion turbine combined with a heat recovery st eam generator and steam turbine).
Most syngas streams are at higher pressure and can contain higher concentrations of CO 2 than conventional steam generating units (especially if the syngas is shifted to enrich the CO 2 concentration as described below). As such, the pre -combustion CO 2 capture systems can utilize physical absorption (physisorption) solvents rather than the chemical absorption solvents described earlier for post-combustion processes. Ph ysical absorption has the benefit of relying on weak intermolecular interactions and, as a result, the absorbed CO 2 can often be released (desorbed) by reducing the pressure rather than by adding heat. Pre-combustion capture systems have been used widely in industrial processes such as natural gas processing.

Figure 5 is a simplified process schematic for pre-combusti on CO 2 capture. Components of the pre-combustion CO 2 capture system include a water-gas shift (WGS) rea ctor, syngas cooler (to achieve optimum temperature for the CO 2 separation step), CO 2 separation system, and compressor needed to raise the captured CO 2 to pipeline pressure.

Figure 5. Pre-Combustion CO 2 Capture for an IGCC Power Plant (NETL, 2015d)

In preparation for pre-combustion CO 2 capture, the amount of CO 2 in the syngas can be increased by “shifting” the composition via the cat alytic water-gas shift (WGS) reaction. This process involves the catalytic reaction of steam (“ water”) with CO (“gas”) to form H 2 and CO 2 according to the following catalytic reaction:

CO + H2O  CO2 + H214

A WGS reactor is typically a fixed-bed reactor cont aining shift catalysts to convert CO and water

into additional H 2 and CO 2 . The resulting CO2 contained in the syngas is then separated from the H2-enriched syngas which is used for combustion in a combined-cycle turbine system for electricity generation. The CO2 separation process uses a physical solvent, solid sorbent, or membrane to separate the CO 2 from the syngas. Sulfur compounds and CO 2 can be removed either simultaneously or selectively (in a subseque nt sulfur recovery step), depending on the shifted syngas composition and conditions, as well as the end fuel gas specifications. Contrary to the post-combustion capture flue gas, the IGCC syng as can contain a high concentration of CO 2 (at high partial pressure) and is pressurized. This allows the use of physical absorbents that require much less added energy to release the captu red CO 2 and require less compression to get to pipeline standards. The lower volume of syngas t o be handled results in smaller equipment sizes and lower capital costs. (Interagency Task Fo rce, 2010); NETL 2013)

The current state-of-the-art pre-combustion CO 2 capture technologies that could be applied to IGCC systems (the glycol-based SelexolTM process and the methanol-based Rectisol® process) employ physical solvents that preferential ly absorb CO 2 from the syngas mixture. Other CO2 separation processes that have yet to be built for full-scale IGCC power plants include the pyrolidone-based Purisol process and the polypropyl ene carbonate-based Fluor solvent (Interagency Task Force, 2010). Several Rectisol an d Selexol systems are in use at commercial scale. For example, the Rectisol system is used for CO 2 capture at the Dakota Gasification Company's substitute natural gas (SNG) plant in Nor th Dakota, which is designed to remove approximately 1.5 million tons of CO 2 per year from the syngas. The CO 2 is purified, transported via pipeline and injected into the Weyburn oilfield in Saskatchewan, Canada (NETL, 2015d).

A simplified flow scheme of the Rectisol® process p rovided by technology vendor Linde is displayed in Figure 6 . This is a configuration intended for dual removal of sulfur gases and

CO 2 in separate fractions, resulting in a pure CO 2 product and an H 2 S/COS enriched gas fraction (NETL, 2015h)15 Figure 6: Rectisol Process Diagram (NETL, 2015h)

Using the two-stage SelexolTM process as an example ( Figure 7 ), in the first stage, untreated syngas enters the first of two absorbers where H2S is preferentially removed using CO 2 -rich

solvent from the CO 2 absorber. The gas exiting the H2S absorber passes through the second absorber, where CO 2 is removed using both semi-lean and lean solvent s treams. The treated syngas exits the absorber and is sent to the combus tion turbine. The CO 2 -rich solvent exits the

CO 2 absorber, and a portion is sent to the H 2 S absorber, while the remainder is sent to a series of flash drums for regeneration. The CO 2 product stream is obtained from the flash drums, a nd the

semi-lean solvent is returned to the CO 2 absorber. The H 2 S/CO 2 -rich solvent exiting the H 2 S absorber is sent to the acid gas stripper, where th e absorbed gases are released using a steam heated reboiler. The acid gas from the stripper is sent to a Claus plant to produce elemental sulfur for commercial use, and the lean solvent exiting th e stripper is returned to the CO 2 absorber. (Interagency Task Force, 2010)16

Figure 7. Schematic Diagram of the Pre-Combustion S elexol TM CO 2 Capture Process

The SelexolTM process is being used at Southern Comp any's Kemper, Mississippi IGCC facility., Southern Company’s Mississippi Power stated that, b ecause the SelexolTM process has been used in industry for decades, the technical risk of its use at the Kemper IGCC facility are minimized.

For example:
The carbon capture process being utilized for the K emper County IGCC is a commercial technology referred to as SelexolTM. The SelexolTM process is a commercial technology that uses proprietary solvent s, but is based on a technology and principles that have been in commerc ial use in the chemical industry for over 40 years. Thus, the risk associat ed with the design and operation of the carbon capture equipment incorpora ted into the Plant’s design is manageable (Anderson, 2009).

And ...
“The carbon capture equipment and processes propose d in this project have been in commercial use in the chemical industry for deca des and pose little technology risk.” (Mississippi Power Company, 2009).

3. Oxy-combustion CO2 capture17

Oxy-combustion (or oxy-fuel) refers to the replacem ent of air, either in the boiler or the gasifier, with pure oxygen (O 2 ). Using purified O2 helps eliminate unwanted bypro ducts present in air,

and also increases the CO 2 purity of the resulting syngas or flue stream, mak ing CCS more

effective.

Oxy-combustion systems for CO 2 capture rely on combusting coal (or other fuel) wi th relatively pure O2 diluted with recycled CO 2 or CO 2 /steam mixtures, as shown in Figure 8 . The primary products of combustion are water and CO 2 , with the CO 2 separated by condensing the water and removing any other gas constituents that infiltrate d the combustion system (Interagency Task Force, 2010).

Figure 8. Pulverized Coal Power Plant with Oxy-Comb ustion CO 2 Capture

(Interagency Task Force, 2010); NETL 2013)

Oxy-combustion overcomes the technical challenge of low CO 2 partial pressure normally encountered in conventional coal combustion flue ga s by producing a highly concentrated CO 2 stream (~60 percent), which is separated from water vapor by condensing the water through cooling and compression. An additional purification stage for the highly concentrated CO 2 flue gas may be necessary to produce a CO 2 stream that meets transportation and storage requirements. This purification step should have si gnificantly less cost than a conventional postcombustion capture system, due to the high CO 2 concentration and reduced flue gas volume (Interagency Task Force, 2010).

The appeal of oxy-combustion is tempered by a few k ey challenges, including the capital cost and energy consumption for a cryogenic air separati on unit (ASU), boiler air infiltration that dilutes the flue gas with N 2 , and excess O 2 contained in the concentrated CO 2 stream. Flue gas recycle (~70 to 80 percent) is also necessary to app roximate the combustion characteristics of air, since currently available boiler materials cannot w ithstand the high temperatures resulting from coal combustion in pure O 2 . Consequently, the economic benefit of oxy-combust ion compared to amine-based scrubbing systems is limited. (Interage ncy Task Force, 2010)18

The conventional ASU is a cryogenic process that ha s a significant energy requirement. However, alternative oxygen separation methods are being researched for possible commercial scale development. These alternative methods includ e ion transport membranes (ITM), ceramic auto-thermal recovery, oxygen transport membranes, and chemical looping (EPA, 2010).

Several research institutes have investigated labor atory- and pilot-scale testing of oxy-fuel combustion, including (EPA, 2010):

• Pilot test programs for the European Enhanced Captu re of CO2 (ENCAP) program and the Advanced Development of the Coal-Fired Oxy- fuel Process with CO2 Separation (ADECOS) program).

• A 30 MW oxy-firing pilot plant at the Schwarze Pump e station in Spremberg, Germany.

• A 32 MW oxy-firing demonstration project in France retrofitting an existing boiler to natural gas oxy-combustion.

• A comprehensive test program using the 15 MW tangen tially-fired Boiler Simulation Facility and 15 MW Industrial Scale Test Facility o perated by Alstom Power, Inc., in Windsor, CT.

Chemical looping is an advanced technology similar to oxy-combustion in that it relies on combustion or gasification of coal in a N2-free env ironment. However, rather than using an ASU, chemical looping involves the use of a metal o xide or other compound as an oxygen

carrier to transfer O 2 from air to the fuel. Figure 9 presents a simplified process schematic for chemical looping. Chemical looping splits combustio n into separate oxidation and reduction reactions. In the fuel reactor, the oxygen carrier releases the O 2 in a reducing atmosphere and the

O 2 reacts with the fuel. The carrier is then recycled back to the oxidation chamber, or air reactor, where it is regenerated by contact with air. Becaus e air is not introduced into the fuel (combustion) reactor, the products of combustion ar e primarily CO 2 and H 2 O. Chemical looping can be applied in either coal combustion or coal ga sification processes. (NETL, 2013)19 Figure 9: Chemical Looping Process (NETL, 2013)

B. CO2 Compression

Regardless of how CO 2 is captured from a power plant, the CO 2 must be compressed to a pressure between 1,500 and 2,200 psi to be transpor ted via pipeline and then injected into an underground storage site. As discussed in Section I .C below, compressed CO 2 is already being transported under these high pressures in a network of CO 2 pipelines used for EOR. Although compression of CO 2 to pipeline pressures is not new, research into mo re-advanced methods of

CO 2 compression is ongoing because the compression of CO 2 requires mechanical energy and represents a potentially large auxiliary power load on the overall power plant system (NETL, 2015e).

Because CO 2 separation typically occurs at low pressure, compr ession is required to reduce the volume flow making transport more practical. Carbon dioxide storage sites for geological sequestration require high pressure as well. Given the high volume flows, centrifugal compressors are typically employed, especially when the captured CO 2 is produced near atmospheric pressure. The physics to compress CO 2 in a centrifugal compressor is the same as any other gas. However, CO 2 has unique characteristics compared to other gases that must be considered in the compressor design (e.g., the high volume reduction required, avoidance of

water formation 8 ). Its high molecular weight allows CO 2 to be liquefied at relatively high temperatures permitting hybrid compression and pump ing options (NETL, 2013).
Compression of CO 2 generally occurs in multiple stages before an opti mal pressure is achieved for transport of the CO 2 . The gas temperature rises during each stage neces sitating cooling

8 Since CO2 dissolves in water and forms carbonic ac id, which is corrosive, strict control of the water content in the CO2 stream is essential for safe and efficient oper ation of the compressor20

between stages (Wong, 2006). A centrifugal compress or accommodates changes in volume flow several ways. First, the frame size of the compress or can be adjusted (smaller frame size for smaller volume flows and higher pressures) (NETL, 2 013). For example, in an August 2007 study conducted for NETL, CO 2 compression was accomplished using a six-stage cent rifugal compressor with inter-stage cooling that required a n auxiliary load of approximately 7.5 percent of the gross power output of a subcritical pressure , coal-fired power plant (NETL, 2015e)

.

Two types of centrifugal compressors typically are used for CO 2 compression. The first is an integrally geared compressor. It is typically drive n by an electric motor that drives a large bullgear which, in turn, drives multiple pinion gears t hat contain centrifugal compressors on each end. The low pressure stages run at lower speeds, a nd the speed increases for the higher pressure stages. The integrally geared design has a separate inlet and exit flange for each stage, permitting intercooling between each stage, which can approach isothermal compression and minimize the power requirement. The drawback of this design is t he sheer size and potential reliability issues with the many bearings, seals, and unshrouded impel lers.

A second type of centrifugal compressor, a beam-sty le compressor, is commonly used in the petrochemical and natural gas industry. It can be c onfigured in a straight-through or back-to-back configuration (as shown in Figure 10 ). The back-to-back design permits intercooling bet ween the two sections and intercooling between multiple compressor bodies. The beam-style compressor contains only two bearings and seals and has demonstrated reliable service in many applications including large frame sizes in liquefi ed natural gas (LNG) applications (up to 78- inch impellers) and high pressure (up to 15,000 psi ). While some intercooling is possible, the beam-style design will typically consume more powerfor a given application. New DOE/NETLsponsored research in internally cooled diaphragms is working to close this gap. In the cooled diaphragm concept, the gas is continually cooled af ter each stage in the flow path through the compressor. A cooling jacket insert is used in the diaphragm of each stage to provide continuous cooling. Figure 1 shows a conceptual design for an internally cooled compressor. The flow of the

CO 2 is shown in red, while the cooling liquid is shown in blue.21

Figure 10: Multi-Stage Back-to-Back Centrifugal Com pressor (left) and Design for an

Internally Cooled Compressor (right) (NETL, 2013)

A technology evaluation for CO 2 compression was provided in a report for the Ameri can Electric Power Mountaineer CCS Project (Usher, 2011). The re port explained options evaluated for compressing the full CO 2 product stream from the proposed nominal 235 MWe c ommercial scale application of Alstom’s chilled ammonia process (CA P) at American Electric Power’s Mountaineer generating station, in New Haven, West Virginia. The study focused on commercially available, integrally-geared, inter-co oled, gas compression systems. The scope of the study included all of the equipment required to compress and condition the captured CO 2 for sequestration. In the end, two arrangements were co nsidered technically and economically feasible for implementation on the commercial scale system. Both utilize compression of the

CO 2 to an intermediate condition, followed by variable -speed pumping to the final desired injection conditions. The compressor-pump arrangeme nt allows for greater flexibility and higher operating efficiency throughout the life of the wel l, which is important based on the expected variability in injection pressure over the life of the injection wells.

Additional information on compressors and summaries of multiple advanced compression research projects (pilot studies) to continue impro ving the efficiency of CO 2 compression as part

of CCS can be found in NETL 2013. Recent NETL-funde d projects researching improvements to

CO 2 compression relevant for CCS include the following :

• Southwest Research Institute is developing novel co mpression technology concepts to

reduce CO 2 compression power requirements by 10 percent compa red to conventional compressor designs. The basic concept is a semi-iso thermal compression process

where the CO 2 is continually cooled using an internal cooling ja cket rather than using22 conventional interstage cooling. The project has co mpleted thermodynamic (Phase I) and prototype testing (Phase II). A full-scale demo nstration of a multi-stage, internally cooled diaphragm pilot test program (Pha se III) was completed in 2014.

• Lehigh University set out to use systems analysis m odels to study the benefits of improved thermal integration for coal-fired power p lants equipped with post- or oxycombustion CO 2 capture systems.

• Ramgen Power Systems is designing and developing a unique compressor technology based upon aerospace shock wave compression theory for use as a CO 2 compressor. A shock wave-based gas turbine engine is also being developed. Ramgen’s compressor design features a rotating disk that ope rates at high peripheral speeds to generate shock waves that compress the CO 2 . Compared to conventional compressor technologies, shock compression offers several pote ntial advantages: high compression efficiency; high single-stage compressi on ratios; opportunity for waste heat recovery; and low capital cost (NETL, 2015i).

C. CO 2 Transportation Pipeline Infrastructure

Pipelines are the most economical and efficient met hod of transporting CO 2 from commercial CCS facilities geologic storage sinks such as salin e formations, coal seams, and oil and gas fields (Interagency Task Force, 2010). Technologies for th e transport of CO 2 through a regionally

extensive network of CO 2 pipelines are in use today. The Pipeline and Hazar dous Materials Safety Administration (PHMSA) reported that in 2013 there were 5,195 miles of CO 2 pipelines operating in the United States. (PHMSA, 2015)

The design, construction, operation, and safety req uirements for CO 2 pipelines are proven. Design considerations for CO 2 pipelines include pipeline material selection and fracture control; pipeline diameter and depth; valve, seal, elastomer , and pumping material selection; valve spacing; and quality considerations, such as compos ition of the stream. Construction requirements and standards are in place to protect pipelines from damage and to maximize the integrity of the system over its operating lifespan . See Interagency Task Force, 2010.

Existing and new CO 2 pipelines are comprehensively regulated by the Dep artment of Transportation’s Pipeline Hazardous Material Safety Administration. The regulations govern pipeline design, construction, operation and mainte nance, and emergency response planning. See generally 49 CFR 195.2. Additional regulations addr ess pipeline integrity management by requiring heightened scrutiny to assure the quality of pipeline integrity in areas with a higher potential for adverse consequences. See 49 CFR 195. 450 and 195.452.

In addition to the PHMSA Hazardous Liquid Pipeline Safety Regulations (49 CFR Part 195) requirements, industry design standards from the Am erican Society of Mechanical Engineers (ASME) and the American Petroleum Institute (API), which are incorporated into 49 CFR Part 195 by reference, are in place to reduce pipeline r isks from CO 2 pipeline systems. (Interagency Task Force, 2010)23

On-site pipelines are not subject to the Department of Transportation standards, but rather adhere to the Pressure Piping standards of the American So ciety of Mechanical Engineers (ASME B31), which the EPA has found would ensure that piping an d associated equipment meet certain quality and safety criteria sufficient to prevent r eleases of CO 2 , such that certain additional requirements were not necessary (See 79 FR 358-59 ( Jan. 3, 2014)). These existing controls

over CO 2 pipelines assure protective management, guard agai nst releases, and assure that captured CO 2 will be securely conveyed to a sequestration site.

D. Geologic Sequestration
Geologic sequestration (GS) – the long-term contain ment of a CO 2 stream in subsurface geologic

formations – is based on a demonstrated understandi ng of the processes that affect CO 2 fate in the subsurface. Sequestration is already well prove n. CO 2 has been retained underground for eons in geologic (natural) repositories and the mec hanisms by which CO 2 is trapped underground are well understood. The physical and chemical trap ping mechanisms, along with the regulatory requirements and safeguards of the Underground Inje ction Control (UIC) Program and complementary monitoring and reporting requirements of the Greenhouse Gas Reporting Program (GHGRP), together ensure that sequestered C O 2 will remain secure and provide the monitoring to identify and address potential leakag e using Safe Drinking Water Act (SDWA) and Clean Air Act (CAA) authorities.

Subsurface formations suitable for GS of CO 2 captured from affected EGUs are geographically widespread throughout most parts of the United Stat es. GS is technically feasible based on a demonstrated understanding of the processes that af fect CO 2 fate in the subsurface; these processes can vary regionally as the subsurface geo logy changes. GS occurs through a combination of trapping mechanisms which are well u nderstood and proven:

1. Structural and stratigraphic trapping is a physical trapping mechanism that occurs

when the CO 2 reaches a stratigraphic zone with low permeability (i.e., geologic confining system) that prevents further upward migr ation.

2. Residual trapping is a physical trapping mechanism that occurs as residual CO 2 is immobilized in formation pore spaces as disconnecte d droplets or bubbles at the trailing edge of the plume due to capillary forces.

3. Adsorption trapping is another physical trapping me chanism that occurs when CO 2 molecules attach to the surfaces of coal and certai n organic rich shales, displacing

other molecules such as methane.

4. Solubility trapping is a geochemical trapping mecha nism where a portion of the CO 2 from the pure fluid phase dissolves into native gro und water and hydrocarbons.

5. Mineral trapping is a geochemical trapping mechanis m that occurs when chemical

reactions between the dissolved CO 2 and minerals in the formation lead to the precipitation of solid carbonate minerals.

The effectiveness of long-term trapping of CO 2 has been demonstrated by natural analogs in a range of geologic settings where CO 2 has remained trapped for millions of years (Hollow ay et. al, 2007). For example, CO 2 has been trapped for more than 65 million years in the Jackson Dome, located near Jackson, Mississippi (IPCC, 2005 ). Other examples of natural CO 2 sources include Bravo Dome and McElmo Dome in Colorado and New Mexico, respectively. These24

natural storage sites are themselves capable of hol ding volumes of CO 2 that are larger than the

volume of CO 2 expected to be captured from a fossil fuel-fired E GU. In 2010, the DOE

estimated current CO 2 reserves of 594 million metric tons at Jackson Dom e, 424 million metric tons at Bravo Dome, and 530 million metric tons at McElmo Dome (DiPietro, et. al, 2012).

GS is feasible in different types of geologic forma tions including deep saline formations (formations with high salinity formation fluids) or in oil and gas formations, such as where injected CO 2 increases oil production efficiency through a proc ess referred to as enhanced oil recovery (EOR). Both deep saline and oil and gas fo rmation types are widely available in the United States. Details on the geographic availabili ty of geologic sequestration are provided in EPA, 2015.

Deep saline formations offer the greatest potential storage resource and capacity. These formations are sedimentary rock layers that are gen erally more than 800 meters deep and are saturated with waters or brines that have a high to tal dissolved solids (TDS) content (i.e., over 10,000 mg/L TDS) (Interagency Task Force, 2010). De ep saline formations are found throughout the United States, and many of these formations may be overlain by laterally extensive, impermeable formations that restrict upward movemen t of injected CO 2

.

Eight Department of Energy Regional Carbon Sequestr ation Partnership (RCSP) “Development Phase” projects have been initiated and five of the eight projects are injecting or have completed

CO 2 injection into deep saline formations. Three of th ese projects have already injected more than one million metric tons each, and one, the Cra nfield Site, injected over eight million metric

tons of CO 2 between 2009 and 2013 (NETL, 2013b). Various types of technologies for monitoring CO 2 in the subsurface and air have been employed at th ese projects, such as seismic methods (crosswell seismic, 3-D and 4-D seismic, an d vertical seismic profiling), atmospheric

CO 2 monitoring, soil gas sampling, well and formation pressure monitoring, and surface and ground water monitoring. 9 No CO 2 leakage has been reported from these sites, which further supports the availability of effective GS.

Enhanced oil recovery (EOR) is a technique that is used to increase the production of oil. Approaches used for EOR include steam injection, in jection of specific fluids such as surfactants and polymers, and gas injection including nitrogen and CO 2 . 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 to make it more amenable for recovery. The crude oil and CO 2 mixture is then recovered and sent to a separator w here the crude oil is separated from the gaseous hydrocarbons, native formation fluids, and CO 2 . The gaseous CO 2 -rich stream then is typically dehydrated, purified to remove hydrocarbo ns, re-compressed, and re-injected into the reservoir to further enhance oil recovery. Not all of the CO 2 injected into the oil reservoir is recovered and re-injected. As the CO 2 moves from the injection point to the production w ell,

some of the CO 2 becomes trapped in the small pores of the rock, or is dissolved in the oil and

water that is not recovered. The CO 2 that remains in the reservoir is not mobile and be comes sequestered.

9 A description of the types of monitoring technolog ies employed at RCSP projects can be found at DOE 2 015a.25

The amount of CO 2 used in an EOR project depends on the volume and i njectivity of the reservoir that is being flooded and the length of t ime the EOR project has been in operation. Initially, all of the injected CO 2 is newly received. As the project matures, some CO 2 is

recovered with the oil and the recovered CO 2 is separated from the oil and recycled so that it can be re-injected into the reservoir in addition to ne w CO 2 that is received. If an EOR operator will not require the full volume of CO 2 available from an EGU, the EGU has other options s uch as sending the CO 2 to other EOR operators, or sending it to deep sali ne formation GS facilities.

CO 2 used for EOR may come from anthropogenic or natura l sources. The source of the CO 2 does not impact the effectiveness of the EOR operation. CO 2 capture, treatment and processing steps provide a concentrated stream of CO 2 in order to meet the needs of the intended end use . CO 2 pipeline specifications of the U.S. Department of T ransportation Pipeline Hazardous Materials Safety Administration found at 49 CFR part 195 (Tra nsportation of Hazardous Liquids by Pipeline) apply regardless of the source of the CO 2 and take into account CO 2 composition, impurities, and phase behavior. Additionally, EOR o perators and transport companies have specifications related to the composition of the CO 2 stream. The regulatory requirements and company specifications ensure EOR operators receive a known and consistent CO 2 stream.

EOR has been successfully used at numerous producti on fields throughout the United States to increase oil recovery. The oil industry in the Unit ed States has over 40 years of experience with EOR. An oil industry study in 2014 identified more than 125 EOR projects in 98 fields in the United States (Koottungal, 2014). More than half of the projects evaluated in the study have been in operation for more than 10 years, and many have been in operation for more than 30 years. This experience provides a strong foundation for de monstrating successful CO 2 injection and monitoring technologies, which are needed for safe and secure GS that can be used for deployment of CCS across geographically diverse are as.

A DOE-sponsored study has analyzed the geographic a vailability of applying EOR in 11 major oil producing regions of the United States and foun d that there is an opportunity to significantly increase the application of EOR to areas outside ofcurrent operations (Kuuskraa, 2011). DOEsponsored geologic and engineering analyses show th at expanding EOR operations into areas additional to the capacity already identified and a pplying new methods and techniques over the next 20 years could utilize 18 billion metric tons of anthropogenic CO 2 and increase total oil production by 67 billion barrels (Kuuskraa, 2011). The study found that one of the limitations to expanding CO 2 use in EOR is the lack of availability of CO 2 in areas where reservoirs are most

amenable to CO 2 flooding. DOE’s Carbon Utilization and Storage Atl as identifies 29 states with oil reservoirs amenable to EOR, 12 of which current ly have active EOR operations (NACAP, 2012). A comparison of the current states with EOR operations and the states with potential for EOR shows that an opportunity exists to expand the use of EOR to regions outside of current areas. The availability of anthropogenic CO 2 in areas outside of current sources could drive ne w EOR projects by making more CO 2 locally available.26

Several EOR sites, which have been operated for yea rs to decades, have been studied to evaluate the viability of safe and secure long-term sequestr ation of injected CO 2 . Examples are identified

below.

• CO 2 has been injected in the SACROC Unit in the Permia n basin since 1972 for EOR

purposes. One study evaluated a portion of this pro ject, and estimated that the injection operations resulted in final sequestratio n of about 55 million tons of CO 2 (Han, 2010). This study used modeling and simulatio ns, along with collection and analysis of seismic surveys, and well logging data, to evaluate the ongoing and potential CO 2 trapping occurring through various mechanisms. The monitoring at this

site demonstrated that CO 2 can become trapped in geologic formations. In a se parate study in the SACROC Unit, the Texas Bureau of Econo mic Geology conducted an extensive groundwater sampling program to look for evidence of CO 2 leakage in the shallow freshwater aquifers (Romanak, 2010). No evi dence of leakage was detected.

• The International Energy Agency Greenhouse Gas Prog ramme conducted an extensive monitoring program at the Weyburn oil fie ld in Saskatchewan between 2000 and 2010 (the site receiving CO 2 captured by the Dakota Gasification synfuel plant discussed later in this document). During tha t time over 16 million metric tons

of CO 2 were safely sequestered as evidenced by soil gas s urveys, shallow groundwater monitoring, seismic surveys and wellbor e integrity testing. An extensive shallow groundwater monitoring program revealed no significant changes in water chemistry that could be attributed to CO 2 storage operations (Roston, 2010). The International Energy Agency Greenhouse Gas Programm e developed a best practices

manual for CO 2 monitoring at EOR sites based on the comprehensive analysis of surface and subsurface monitoring methods applied o ver the 10 years (Hitchon, 2012).

• The Texas Bureau of Economic Geology also has been testing a wide range of surface and subsurface monitoring tools and approaches to d ocument sequestration efficiency and sequestration permanence at the Cranfield oilfi eld in Mississippi (Gulf Coast Carbon Center, 2015). As part of a DOE Southeast Re gional Carbon Sequestration Partnership study, Denbury Resources injected CO 2 into a depleted oil and gas reservoir at a rate greater than 1.2 million tons/y ear. Texas Bureau of Economic Geology is currently evaluating the results of seve ral monitoring techniques employed at the Cranfield project and preliminary f indings indicate no impact to groundwater (Gulf Coast Carbon Center, 2015). The p roject also demonstrates the availability and effectiveness of many different mo nitoring techniques for tracking

CO 2 underground and detecting CO 2 leakage to ensure CO 2 remains safely sequestered.

CO 2 may also be used for other types of enhanced recov ery, such as for natural gas production.

Reservoirs such as unmineable coal seams also offer the potential for geologic storage. 10
Enhanced coalbed methane recovery is the process of injecting and storing CO 2 in unmineable

10 Other types of opportunities include organic shale s and basalt.27

coal seams to enhance methane recovery. These opera tions take advantage of the preferential chemical affinity of coal for CO 2 relative to the methane that is naturally found on the surfaces of

coal. When CO 2 is injected, it is adsorbed to the coal surface an d releases methane that can then be captured and produced. This process effectively “locks” the CO 2 to the coal, where it remains

stored.

In 2010, the EPA finalized an effective and coheren t regulatory framework to ensure the longterm, secure and safe storage of large volumes of C O 2 . The EPA developed these Underground Injection Control (UIC) Class VI well regulations u nder authority of the Safe Drinking Water Act (SDWA) to facilitate injection of CO 2 for GS, while protecting human health and the environment by ensuring the protection of undergrou nd sources of drinking water (USDWs). The Class VI regulations are built upon 35 years of fed eral experience regulating underground injection wells, and many additional years of state UIC program expertise. The EPA and states have decades of UIC experience with the Class II pr ogram, which provides a regulatory framework for the protection of USDWs for CO 2 injected for purposes of EOR.
In addition, to complement both the Class VI and Cl ass II rules, the EPA used CAA authority to develop air-side monitoring and reporting requireme nts for CO 2 capture, underground injection, and geologic sequestration through the GHGRP. Infor mation collected under the GHGRP provides a transparent means for the EPA and the pu blic to continue to evaluate the effectiveness

of GS.

Under SDWA, the EPA developed the UIC Program to re gulate the underground injection of fluids in a manner that ensures protection of USDWs . UIC regulations establish six different well classes that manage a range of injectates (e.g., in dustrial and municipal wastes; fluids associated with oil and gas activities; solution mining fluids ; and CO 2 for geologic sequestration) and which accommodate varying geologic, hydrogeological, and other conditions.

In 2010, the EPA established a new class of well, C lass VI. Class VI wells are used to inject CO 2 into the subsurface for the purpose of long-term se questration. See 75 FR 77230 (Dec. 10, 2010). This rule accounts for the unique nature of CO 2 injection for large-scale GS. Specifically, the EPA addressed the unique characteristics of CO 2 injection for GS including the large CO 2 injection volumes anticipated at GS projects, relat ive buoyancy of CO 2 , its mobility within subsurface geologic formations, and its corrosivity in the presence of water. The UIC Class VI rule was developed to facilitate GS and ensure prot ection of USDWs from the particular risks that may be posed by large scale CO 2 injection for purposes of long-term GS. The Class VI rule establishes technical requirements for the permitti ng, geologic site characterization, area of review (i.e., the project area) and corrective acti on, well construction, operation, mechanical integrity testing, monitoring, well plugging, post- injection site care, site closure, and financial responsibility for the purpose of protecting USDWs.

The EPA has issued Class VI permits for six wells u nder two projects.

• In September 2014, a UIC Class VI injection well pe rmit (to construct) was issued by

the EPA to Archer Daniels Midland for an ethanol fa cility in Decatur, Illinois. The goal of the project is to demonstrate the ability o f the Mount Simon geologic formation, a deep saline formation, to accept and r etain industrial scale volumes of28 CO 2 for permanent GS. The permitted well has a project ed operational period of five years, during which time 5.5 million metric tons of CO 2 will be injected into an area of review with a radius of approximately 2 miles. 11 Following the operational period, Archer Daniels Midland plans a post-injection site care period of ten years. 12

• In September 2014, the EPA also issued four Class V I injection well permits (to construct) to the FutureGen Industrial Alliance pro ject in Jacksonville, Illinois, which proposed to capture CO 2 emissions from a coal-fired power plant in Meredos ia, Illinois and transport the CO 2 by pipeline approximately 30 miles to the deep sal ine

GS site. 13 The Alliance proposed to inject a total of 22 mill ion metric tons of CO 2 into an area of review with a radius of approximately 24 miles over the 20 year life of the project, with a post-injection site care period of fifty years. 14

The CO 2 injection wells used for EOR are regulated through the UIC Class II program. 40 CFR §144.6(b). CO 2 storage associated with Class II wells is a common occurrence and CO 2 can be safely stored where injected through Class II-permi tted wells for the purpose of enhanced oil or gas-related recovery. UIC Class II regulations issu ed under section 1421 of SDWA provide minimum federal requirements for site characterizat ion, area of review, well construction (e.g., casing and cementing), well operation (e.g., inject ion pressure), injectate sampling, mechanical integrity testing, plugging and abandonment, financ ial responsibility, and reporting. Class II wells must undergo periodic mechanical integrity te sting which will detect well construction and operational conditions that could lead to loss of i njectate and migration into USDWs.

In addition, to complement the Class II and VI rule s, the EPA used CAA authority to develop air-side monitoring and reporting requirements for CO 2 capture, underground injection, and geologic sequestration through the Greenhouse Gas R eporting Program (GHGRP) found in 40

CFR Part 98. Information collected under the GHGRP provides a transparent means for the EPA and the public to continue to evaluate the effectiv eness of GS.

Subpart PP of the GHGRP (40 CFR 98.420 - 98.428) provides requirements to account for CO 2 supplied to the economy. This subpart requires affe cted facilities with production process units that capture a CO 2 stream for purposes of supplying CO 2 for commercial applications or that capture and maintain custody of a CO 2 stream in order to sequester or otherwise inject i t underground to report the mass of CO 2 captured and supplied to the economy. CO 2 suppliers are required to report the annual quantity of CO 2 transferred offsite and its end use, including GS.

Reporting under subpart RR (40 CFR 98.440 - 98.449) is required for all facilities that have received a Class VI UIC permit for injection of CO 2 . Subpart RR requires facilities meeting the source category definition (40 CFR 98.440) for any well or group of wells to report basic

11 http://www.epa.gov/region5/water/uic/adm/. In addi tion, Archer Daniels Midland received a UIC Class V I injection well permit for a second well in December 2014. Archer Daniels Midland had been injecting CO 2 at this well since 2011 under a UIC Class I permit issued b y the Illinois EPA.

12 http://www.epa.gov/region5/water/uic/adm/.

13 After permit issuance, and for reasons unrelated t o the permitting proceeding, DOE initiated a struct ured closeout of federal support for the FutureGen project in Feb ruary 2015. However, these are still active Class V I permits.

14 http://www.epa.gov/r5water/uic/futuregen/.29

information on the mass of CO 2 received for injection; develop and implement an E PA-approved monitoring, reporting, and verification (MRV) plan; report the mass of CO 2 sequestered using a mass balance approach; and report annual monitoring activities. The subpart RR MRV plan includes five major components:

1. A delineation of monitoring areas based on the CO 2 plume location. Monitoring may be phased in over time.

2. An identification and evaluation of the potential s urface leakage pathways and an assessment of the likelihood, magnitude, and timing , of surface leakage of CO 2 through these pathways. The monitoring program will be designed to address the

risks identified.

3. A strategy for detecting and quantifying any surfac e leakage of CO 2 in the event leakage occurs. Multiple monitoring methods and acc ounting techniques can be used to address changes in plume size and risks over tim e. 4. An approach for establishing the expected baselines for monitoring CO 2 surface leakage. Baseline data represent pre-injection site conditions and are used to identify potential anomalies in monitoring data.

5. A summary of considerations made to calculate site- specific variables for the mass balance equation. Site-specific variables may inclu de calculating CO 2 emissions from equipment leaks and vented emissions of CO 2 from surface equipment, and considerations for calculating CO 2 from produced fluids.

Monitoring programs conducted at international GS p rojects provide examples where large

volumes of CO 2 have been safely injected and securely sequestered for long periods of time at volumes and rates consistent with those expected fr om CCS at EGUs. This experience has also demonstrated the value and efficacy of monitoring p rograms to determine the location of CO 2 in the subsurface and detect potential leakage through the presence of CO 2 in the shallow subsurface, near surface and air.

The Sleipner CO 2 Storage Project is located at an offshore gas fiel d in the North Sea where CO 2 must be removed from the natural gas in order to me et customer requirements and reduce costs. The project began injecting CO 2 into the deep subsurface in 1996. The single offsh ore injection well injects approximately 1 million metric tons pe r year into a thick, permeable sandstone above the gas producing zone. Approximately 15 million me tric tons of CO 2 have been injected since inception. Many U.S. and international organization s have conducted monitoring in conjunction with the Sleipner CO 2 Storage Project. The location and dimensions of th e CO 2 plume have been measured numerous times using 3-dimensional seismic monitoring since the 1994 pre-injection survey. The monitoring data have demonstrated that although the plume is behaving differently than initially modeled due to thin layers of imperm eable shale that were not initially identified in the reservoir model, the CO 2 remains trapped in the injection zone. Numerous ot her techniques have been successfully used to monitor CO 2 storage at Sleipner. The research and monitoring a t Sleipner demonstrates the value of a comprehensive approach to site characterization, computational modeling and monitoring, as is requir ed under UIC Class VI rules. The experience at Sleipner demonstrates that large volu mes of CO 2 , of the same order of magnitude expected for an EGU, can be safely injected and sto red in saline reservoirs over an extended period.30

Snøhvit is another large offshore CO 2 storage project, located at a gas field in the Bar ents Sea. Like Sleipner the natural gas must be treated to re duce high levels of CO 2 to meet processing standards and reduce costs. Gas is transported via pipeline 95 miles to a gas processing and liquefied natural gas plant and the CO 2 is piped back offshore for injection. Approximatel y 0.7 million metric tons per year CO 2 are injected into permeable sandstone below the ga s reservoir. Between 2008 and 2011, the operator observed pressu re increases in the injection formation (Tubaen Formation) greater than expected and conduc ted time lapse seismic surveys and studies of the injection zone and concluded that the pressu re increase was mainly caused by a limited storage capacity in the formation (Grude et al., 20 14). In 2011, the injection well was modified and injection was initiated in a second interval (S tø Formation) in the field to increase the storage capacity.

CO 2 from the Great Plains Synfuels plant in North Dako ta has been injected into the Weyburn oil

field in Saskatchewan Canada since 2000. The Great Plains Synfuels plant is discussed later in this document. It is anticipated that approximately 40 million metric tons of CO 2 will be permanently sequestered over the lifespan of the pr oject. Extensive monitoring by U.S. and international partners has demonstrated that no lea kage has occurred.

At the In Salah CO 2 storage project in Algeria, CO 2 is removed from natural gas produced at three nearby gas fields in order to meet export qua lity specification. The CO 2 is transported by pipeline approximately 3 miles to the injection sit e. Three horizontal wells are used to inject the

CO 2 into the down-dip aquifer leg of the gas reservoir approximately 6,200 feet deep. Between

2004 and 2011 over 3.8 million metric tons of CO 2 were stored. Injection rates in 2010 and 2011 were approximately 1 million metric tons per year. Storage integrity has been monitored by several US and international organizations and the monitoring program has employed a wide range of geophysical and geochemical methods, inclu ding time lapse seismic, microseismic, wellhead sampling, tracers, down-hole logging, core analysis, surface gas monitoring, groundwater aquifer monitoring and satellite data. The data have been used to support periodic risk assessments during the operational phase of th e project. In 2010 new data from seismic, satellite and geomechanical models were used to inf orm the risk assessment and led to the

decision to reduce CO 2 injection pressures due to risk of vertical leakag e into the lower caprock, and risk of loss of well integrity. The caprock at the site consisted of main caprock units, providing the primary seal, and lower caprock units , providing additional buffers. There was no leakage from the well or through the caprock, but t he risk analysis identified an increased risk of leakage, therefore, the aforementioned precautions were taken. Additional analysis of the reservoir, seismic and geomechanical data led to th e decision to suspend CO 2 injection in June 2011. No leakage has occurred and the injected CO 2 remains safely stored in the subsurface. The decision to proceed with safe shutdown of injection resulted from the analysis of seismic and geomechanical data to identify and respond to stora ge site risk. The Salah project demonstrates the value of developing an integrated and comprehen sive set of baseline site data prior to the start of injection, and the importance of regular r eview of monitoring data.

Even though potentially adverse conditions were ide ntified at some projects (In Salah and Snøhvit), there were no releases to air and the mon itoring systems were effective in identifying the issues in a timely manner, and these issues wer e addressed effectively. In each case, the sitespecific characteristics were evaluated on a case-b y-case basis to select a site where the geologic31

conditions are suitable to ensure long-term, safe s torage of CO 2 . Each project was designed to address the site-specific characteristics and opera ted to successfully inject CO 2 for safe storage.

In summary, the different regulatory components, al ready in place, assure the safety and effectiveness of GS. The effective regulatory struc ture complements the analysis of the technical feasibility of GS, which together affirm that the t echnical feasibility of GS is adequately

demonstrated.

E. Alternatives to Geologic Sequestration

Potential alternatives to storing CO 2 in geologic formations are emerging. Applications where captured anthropogenic CO 2 is converted to a useable product may offer the op portunity to offset

the cost of CO 2 capture. Examples of CO 2 utilization include:

Carbonation/mineralization: Alkaline earth oxides r eact with CO 2 to create insoluble carbonates. The carbonate materials produced can be tailored to optimize performance in specific industrial and commercial applications such as for use in cons truction or cement manufacture. For example:

• Precipitated calcium carbonate (PCC) is produced th rough a chemical reaction process that uses calcium oxide (quicklime), water, and CO 2 . Some pulp and paper manufacturers supply anthropogenic CO 2 from process exhausts to nearby PCC producers, which in turn supply PCC for use in pape r manufacturing (40 CFR part 98, subpart PP).

• The combination of magnesium oxide and CO 2 results in a precipitation reaction

where the CO 2 becomes mineralized.

• The Skyonics Skymine project, which opened its demo nstration project in October 2014, captures over 75,000 tons of CO 2 annually from a San Antonio, Texas, cement plant and converts the CO 2 into other products, including sodium carbonate, s odium bicarbonate, hydrochloric acid and bleach (Skymine, 2015).

• Other companies – including Calera and New Sky – al so offer commercially available technology for the beneficial use of captured CO 2 (Calera, 2015; New Sky, 2015).

Bio-fuel production using algae: Plants convert CO 2 and water into starch using sunlight during the photosynthesis process. Although more advanced plants are not very effective in conversion of large quantities of CO 2 , micro-algae can use high concentrations of CO 2 to create starch. The biomass product can be used to recycle CO 2 into valuable industrial fuel such as methane, methanol, hydrogen and bio-diesel.

Fuel production: Most carbon-based fuels are made u p of carbon, hydrogen, and oxygen. CO 2 can be hydrogenated in the presence of a catalyst t o create low-carbon-chain fuel such as methanol. Procuring hydrogen requires energy for hy drolysis of water or partial oxidation of natural gas.32

Chemical synthesis: Ceramics, fertilizers, rubber, and many other small-scale industries require

CO 2 at some stage of their manufacturing process. The largest use of CO 2 in this area is in fertilizer plants, where CO 2 is captured from the exhaust gases of NH 3 reformer units and used to

manufacture urea.

CO 2 utilization is a promising research area. There a re currently no plenary systems of regulatory control and GHG reporting for these appr oaches, as there are for geologic sequestration. Nonetheless, CO 2 utilization technologies not only show promise, bu t could potentially be demonstrated to show permanent stora ge of CO 2

.

F. Continuing Research and Policy Development

Climate science and climate change mitigation optio ns – including CCS - are the subject of great academic interest and a large body of academic lite rature on the subjects exits. In addition, other research organizations (e.g., U.S. national laborat ories and others) have also published studies on these subjects.

The Thomson Reuters Web of Science database is a comprehensive source of academic publications from around the world. As a metric to gauge global interest and progress in CCS technologies, EPA conducted a search of the databas e using the keywords "carbon capture" and "carbon capture and sequestration" and searching by the title of the paper. After conducting the search, the data was sorted by year in order to cre ate a timeline of CCS development. The results

of this search are shown in Figure 11 below. The number of publications regarding CCS ha s grown dramatically in the past decade, from only 7 papers in 2004 to 147 publication in 2014, with a peak of 205 publications in 2013.

In order to corroborate this trend, EPA also conduc ted a search using the U.S. patent database, using the keywords "Carbon Capture". The results of this search were segmented by year, and

are shown in Figure 12 below. As with the publications, the number of pat ents issued regarding CCS technology has increased rapidly over the past decade, beginning in 2007. The number of patents issued peaked in 2014, with 160 patents iss ued. Both The U.S. patent office and Thomson Reuters confirm that industry and academia are both working towards technological advancements in all stages of CCS.33 Figure 11. Number of Publications Regarding CCS per Year

Figure 12. Number of Patents Regarding CCS per Year

Research is underway to reduce CO 2 capture costs and to improve performance. The DOE/ NETL sponsors an extensive research, development and dem onstration program that is focused on developing advanced technology options that will dr amatically lower the cost of capturing CO 2 from fossil fuel energy plants compared to currentl y available capture technologies. The large0 50 100 150 200 250

2000 2002 2004 2006 2008 2010 2012 2014 2016Number of Publications

Year 

### Number of Publications by year (2001-2014)

0 20 40 60 80 100 120 140 160 180

2002 2004 2006 2008 2010 2012 2014 2016Number of Publications

Year



### Number of Patents by year (2004-2014)34

scale CO 2 capture demonstrations that are currently planned and in some cases underway, under DOE’s initiatives, as well as other domestic and in ternational projects, will generate operational knowledge and enable continued commercialization an d deployment of these technologies. The CCS Global Consortium and National Carbon Capture C enter are examples of organizations dedicated to accelerating commercial CCS.

SaskPower created the CCS Global Consortium ( http://www.saskpowerccs.com/consortium/ ) to share the knowledge and experience from the Boundar y Dam Unit #3 facility with global energy leaders, technology developers, and project develop ers. SaskPower, in partnership with Mitsubishi and Hitachi, is also helping to advance CCS knowledge and technology development through the creation of the Shand Carbon Capture Te st Facility (CCTF) (SaskPower, 2015a). The test facility will provide technology developer s with an opportunity to test new and emerging carbon capture systems for controlling car bon emissions from coal-fired power plants.

The National Carbon Capture Center at the Power Sys tems Development Facility
(PSDF) in Wilsonville, Alabama is a consortium betw een DOE/NETL and electric power producers offering a world-class test facility and a highly specialized staff to accelerate the commercialization of advanced technologies and enab le fossil-fuel based power plants to achieve

near-zero emissions. The NCCC was established in 20 09 to build on the experience, expertise, and infrastructure in place at the PSDF, which has been in operation since 1996. In undertaking its mission, the NCCC is involved in a range of act ivities to develop the most promising technologies for future commercial deployment, ther eby maximizing the impact of project funds. A large portion of NCCC research is focused on deve lopment of post-combustion CO 2 capture for incorporation into pulverized coal power plants and pre-combustion CO 2 capture for integration into the new generation of coal gasific ation power plants. Post-combustion and precombustion CO 2 capture work has included multiple projects, such as testing of solvents, enzymes, gas separation membranes, sorbents, and ca talysts, as well as other novel processes. The testing has supported technology developers fro m both industry and universities, and in many cases has yielded the bases for process improv ements and scale-ups (Northington, et al., 2012).

In addition to research underway to accelerate comm ercial carbon capture, research is also underway to advance commercial use of geologic sequ estration. The DOE has created a network of seven Regional Carbon Sequestration Partnerships (RCSPs) to deploy large-scale field projects in different geologic settings across the country to demonstrate that GS can be achieved safely, permanently, and economically at large scal es. Collectively, the seven RCSPs represent regions encompassing 97 percent of coal-fired CO 2 emissions, 97 percent of industrial CO 2 emissions, 96 percent of the total land mass, and e ssentially all the geologic sequestration sites in the United States potentially available for GS (DOE , 2015a). The seven partnerships include more than 400 organizations spanning 43 states (and four Canadian provinces) (DOE, 2015a). RCSP project objectives are to inject at le ast one million metric tons of CO 2 . In April 2015, DOE announced that CCS projects supported by the department have safely and permanently stored 10 million metric tons of CO 2 (DOE, 2015b).35

In addition to Federal initiatives, multiple states have established emission performance

standards or other measures to limit emissions of G HGs from new EGUs. The emission levels established by these standards would effectively re quire CCS. For example,

• In September 2006, California Governor Schwarzenegg er signed into law Senate Bill 1368. The law limits long-term investments in base load generation by the state’s utilities to power plants that meet an emissions pe rformance standard jointly established by the California Energy Commission and the California Public Utilities Commission. The Energy Commission has designed regu lations that establish a standard for new and existing base load generation owned by, or under long-term contract to publicly owned utilities, of 1,100 lb C O2/MWh.

• In May 2007, Washington Governor Gregoire signed Su bstitute Senate Bill 6001,

which established statewide GHG emissions reduction goals, and imposed an emission standard that applies to any base load ele ctric generation that commenced operation after June 1, 2008 and is located in Wash ington, whether or not that generation serves load located within the state. Ba se load generation facilities must initially comply with an emission limit of 1,100 lb CO2/MWh.

• In July 2009, Oregon Governor Kulongoski signed Sen ate Bill 101, which mandated that facilities generating base load electricity, w hether gas- or coal-fired, must have emissions equal to or less than 1,100 lb CO2/MWh, a nd prohibited utilities from entering into long-term purchase agreements for bas e load electricity with out-of-state

facilities that do not meet that standard.

• New York established emission standards of CO 2 at 925 lb CO2/MWh for new and expanded base load fossil fuel-fired plants.

• In May 2007, Montana Governor Schweitzer signed Hou se Bill 25, adopting a CO 2 emissions performance standard for EGUs in the stat e. House Bill 25 prohibits the state Public Utility Commission from approving new EGUs primarily fueled by coal unless a minimum of 50 percent of the CO 2 produced by the facility is captured and sequestered.

• On January 12, 2009, Illinois Governor Blagojevich signed Senate Bill 1987, the Clean Coal Portfolio Standard Law. The legislation establishes emission standards for new power plants that use coal as their primary fee dstock. From 2009–2015, new coal-fueled power plants must capture and store 50 percent of the carbon emissions that the facility would otherwise emit; from 2016–2 017, 70 percent must be captured and stored; and after 2017, 90 percent must be capt ured and stored.

II. Facilities Utilizing CCS

Many industries, including the power generation ind ustry, are beginning to incorporate CCS into their plant designs. In the U.S. and abroad, multip le CCS projects are in various stages of development, from research and planning to currentl y operating pilot- and full-scale systems. Some of these projects are described in greater det ail below. It should be noted that this section only highlights some of the major examples of CCS i mplementation, and should not be considered an exhaustive list of all CCS projects.36

A. Post-combustion

Table 2 lists seven facilities that have experience with p ost-combustion CO 2 capture projects, including six EGUs and one soda ash production faci lity. Each project is briefly summarized in the following subsections.37Table 2. Summary of Post-combustion Carbon Capture and Storage ProjectsProjectNameDomestic orInternationalLocationFacilitytypeUnit typeCapturedetailsDatebeganoperation(Dateendedoperationif ended)Amountof CO2captured(metrictons/yr)Transport detailsFate ofcapturedCO2FateLocationAEP/Alstom-MountaineerProject DomesticNew Haven,WestVirginia EGUCoal-firedpower plant(30 MWslipstream)Full (>90%)CCS 2009 100,000 Pipeline GSMountSimon,1.5 milesin depthAES -Shady Point DomesticPanama,Oklahoma EGUCoal-firedpower plant(320 MW)Partial(<10%) 1991 66,000NottransportedPurifiedand soldas foodgradeCO2MultipleLocationsAES -Warrior Run DomesticCumberland,Maryland EGUCoal-firedpower plant(180 MW)Partial(<10%) 2000 110,000NottransportedPurifiedand soldas foodgradeCO2MultipleLocationsPetra Nova -W.A. Parish DomesticHouston,Texas EGUCoal-firedpower plant(240 MW slipsteam)Full (>90%)CCS2017(underconstruction)1,600,000 Pipeline EORHilcorp'sWestRanch OilFieldSaskPower -BoundaryDam Unit#3 InternationalEstevan,Saskatchewan, Canada EGUIGCC powerplant (110MW)Full (>90%)CCSOctober,20141,000,000 Pipeline EORWeyburnEOR, 40milesaway38SearlesValleyMinerals DomesticTrona,CaliforniaSodaAshCoal-firedpower plantgeneratingsteam/powerfor onsite usePostcombustionaminescrubbing 1978 264,898NA: usedonsiteOther use:carbonation of brinein sodaashprocessNotspecifiedFluor Corp.–Bellingham DomesticBellingham,Massachusetts EGUNatural Gasfired powerplant (40 MWslipstream of a320 MW plant)Full (>90%)CCS1991(2005) 100,000NottransportedPurifiedand soldas foodgrade CO2MultipleLocations39

1. AEP/Alstom - Mountaineer Project

AEP began a pilot CCS project at its Mountaineer Pl ant in New Haven, West Virginia in September, 2009. The project was a 20 MWe slipstrea m of the 1,300 MW plant, capturing 100,000 metric tons CO 2 /year which was sequestered 1.5 miles underground i n the neighboring Mount Simon Sandstone deposits. The project was ini tially planned to expand to 235 MW, with 150,000 metric tons CO 2 /year, a 90% capture rate; however, uncertain feder al climate regulation discouraged AEP from continuing the project (MIT, Mountaineer Fact Sheet , 2015).

2. AES – Shady Point/Warrior Run

The Shady Point (Panama, OK) and Warrior Run (Cumbe rland, MD) power plants use circulating fluidized bed reactors, and amine scrub bers developed by ABB/Lummus to capture CO2. Warrior Run began operations in 2000, and prod uces 180 MW of electricity along with

steam for the CO 2 production unit. The plant captures about 10% of i ts CO 2 emissions, which are removed post-combustion via a slipstream (IEAGHG RD &D Database, 2013). Shady Point operates in a similar manner, except on a larger sc ale. The plant produces 320 MW, and has been operating since 1991. Shady Point extracts about 66 ,000 metric tons CO 2 /day from the flue gas, which is purified to food grade levels in the CO 2 processing plant. The captured CO 2 from the Shady Point and Warrior Run plants is purified and used in food-processing and other industrial applications like fire extinguishers (NETL, What Carbon Capture Technologies are in Use Today ).

3. Fluor Corp. – Bellingham

The Bellingham, Massachusetts CCS project, which i ncorporated the Fluor Ecomaine process described in section I, ran from 1991 to 20 05 (Global CCS Institute, 2013). The project was a 40 MW slipstream of the 320 MW plant, capturi ng over 90% of CO 2 emissions totaling 100,000 metric tons of CO 2 /day. This plant is unique in that it was an NGCC i ncorporating CCS into its operations. The CO 2 was sold for use in the beverage industry, as oppo sed to geologic sequestration (Bernton, 2014).

4. Petra Nova – W. A. Parish

The W.A. Parish CCS project near Houston, Texas wil l be the world's largest post-combustion CCS retrofit once it begins operation in 2017. The plant is a joint venture between NRG and JX Nippon Oil & Gas Exploration. Captured CO 2 will be used for EOR in the Gulf Coast region.

The unit will collect 90% of the emitted CO 2 from a 240 MW slipstream of the 610 MW facility,

for a total of 1.4 million metric tons CO 2 /year. The CO 2 capture technology is provided by Kansai Mitsubishi, which has had CO 2 capture technology in commercial use since 1999, a nd currently is operating at 11 facilities across the globe (NRG Energy Inc., 2015). The plant will utilize a high-performance solvent, which was teste d at a pilot-scale project at the Alabama40

Power Barry plant, which is described below. The pr oject began as a 60 MW slipstream

demonstration and received DOE Clean Coal Power Ini tiative funding on that basis, however, the project was later expanded to the 240 MW slipst ream due to the need to capture larger

volumes of CO 2 for EOR operations.

5. SaskPower – Boundary Dam Unit #3

The Boundary Dam CCS project is the first commercia l-scale post-combustion CCS plant in the world. Located in Saskatchewan, Canada, the Boundar y Dam project incorporates EOR and Geological Sequestration into their operations, whi ch began in October of 2014. Although initially only capturing 75% of CO 2 , currently the unit produces 110 MW net (139 MW gr oss) of electricity, with 90% CO 2 capture totaling 1 million metric tons CO 2 /year at a purity of over 99.999% (Monea, 2014). The plant uses a Shell Canso lv amine-based solvent to capture CO 2 , which comes from local Saskatchewan lignite coal. I n order to mitigate the cost of the retrofit,

SaskPower sells the CO 2 to an oil drilling company for use in EOR and even tual sequestration,

and to other industries for commercial use. The bal ance of unsaleable CO2 is sequestered. The plant also sells sulphuric acid and fly ash for add ed revenue (Hussain, 2014). CO 2 that is not used in EOR is immediately stored in deep brine-fil led sandstone formations Additionally, initial indications are that the generation side is produci ng more power than estimated and that the energy penalty (parasitic load) is much lower than expected (Monea, 2015).

6. Searles Valley Minerals – Trona Soda Ash Plant

The Searles Valley Minerals soda ash plant in Trona , Ca, is the longest running carbon capture project in the U.S. The plant has been capturing CO 2 via post-combustion amine scrubbing since

1978. This CO 2 comes from the flue gas from a coal-fired power bo iler generating steam and electricity for onsite use. The CO 2 is used to for carbonation reactions to produce so da ash. Since its inception, the soda ash plant has collected rou ghly 270,000 metric tons of CO 2 per year (EPA, 2014).

B. Pre-combustion

Table 3 contains 11 facilities that are in various stages of pre-combustion CO 2 capture projects, including nine EGUs, a fertilizer manufacturing pla nt, and a coal gasification facility. Each project is briefly summarized in the following subs ections.41Table 3. Pre-combustion Carbon Capture and StorageProjectsProject NameDomestic orInternationalLocationFacility typeUnit typeCapturedetailsDate beganoperation (Dateended operationif ended)Amountof CO2captured(metrictons/yr)TransportdetailsFate ofcapturedCO2FateLocation2Co Energy - DonValley PowerProject InternationalSouthYorkshire,UnitedKingdom EGU920 MW(Gross), 650MW (Net)Full(>90%)CCS2018/2019(Planning Phase) 5,000,000 Pipeline GSThe NorthSeaCVREnergy/ChaparralEnergy -CoffeyvilleFertilizer Plant DomesticCoffeyville,KansasFertilizerPlant Not EGU 2013 1,000,000 Pipeline EOR112 kmawayDakotaGasification -Great PlainsSynfuels Plant DomesticBeulah,NorthDakotaCoalGasificationPlantCoalGasifierPartial(50%)1984 (beganoperation)2000 (began CCS) 3,000,000 Pipeline EORWeyburnEOR, 200miles awayELCOGAS, S.A. -Puertollano InternationalPuertollano,Spain EGUIGCC (14MWSlipstream)Full(>90%)CCS 2010 365,000NottransportedHydrogenproduction SpainEmirates SteelIndustries - AbuDhabi InternationalAbu Dhabi,United ArabEmirates EGUIGCC (~228MW)Full(>90%)CCS2016 (underconstruction) 800,000 Pipeline EORRumaitha,50 km awayHuaneng -GreenGen IGCCProject InternationalTianjinCity, BohaiRim, China EGUIGCC (400MW)Partial(>80%)2020 (currentlytesting pilot) 2,000,000 Pipeline EOR51-100 kmfrom theplantSouthern Company- Kemper County DomesticDe Kalb,Mississippi EGUIGCC powerplant (582MW)Partial(65%)2016 (constructioncompleted,currently testing) 3,500,000 Pipeline EOR60 milesawaySouthern Compnay- Barry Plant DomesticMobile,Alabama EGUCoal-firedpower plant(25 MWslipstream)June 2011(capture)2012 (storage) 150,000 Pipeline GSCitronelleoil field42Project NameDomestic orInternationalLocationFacility typeUnit typeCapturedetailsDate beganoperation (Dateended operationif ended)Amountof CO2captured(metrictons/yr)TransportdetailsFate ofcapturedCO2FateLocationSummit Power -Caledonia InternationalCaledonia,Scotland,the UnitedKingdom EGUIGCC (570MW)Full(>90%)CCS2022 (underconstruction) 3,800,000 Pipeline GS North SeaSummit Power -Texas CleanEnergy Project(TCEP) DomesticOdessa,Texas EGUIGCC (400MW)Full(>90%)CCS 2019 3,000,000 Pipeline EORPermianBasinVattenfall/Nuon -Willem-AlexanderPower Plant InternationalBuggenum,theNetherlands EGUIGCC (20MWSlipstrem)Full(>90%)CCS 2011NotprovidedNottransportedReturned tothe fluestream aftercompressed Netherlands43

1. CVR Energy/Chaparral Energy - Coffeyville Fertil izer Plant

Chaparral Energy and Coffey Resources Nitrogen Fert ilizers, a subsidiary of CVR Energy, have joined to capture and sequester roughly 1 million m etric tons CO 2 /year using pre-combustion technology. Chaparral manages the compression, dehy dration, and transportation facilities, while CVR owns the carbon and carbon capture sources. Thi s retrofit, completed in 2013, allows the partnership to sell CO 2 for use in EOR operations 112 km (70 miles) away ( MIT, Coffeyville
Fact Sheet, 2015). The plant utilizes absorption physical solve nt-based process using Selexol for CO2 separation. Similar to an IGCC, the plant gasif ies petroleum coke to create a hydrogen-rich syngas from which the CO 2 is removed. The syngas is used to synthesize ammon ia and urea ammonium nitrate fertilizers instead of being used for energy production (Chaparral Energy, 2015).

2. Dakota Gasification – Great Plains Synfuels Plan t

Located in Beulah, ND, the Great Plains Synfuels Pl ant began operations in 1984 and later added CCS operations in the year 2000. The plant consumes roughly 18,000 tons of North Dakota lignite coal each day and captures about 3 million metric tons of CO 2 per year, which is the most

CO 2 captured from conversion at any facility of the wo rld (Dakota Gasification Company, Great Plains Synfuels Plant, 2015). Although not an EGU, the processes at a coal gasification plant are very similar to those at an IGCC. Dakota Gasificati on uses a Rectisol® system to capture CO 2 before the gasified coal is converted into syntheti c natural gas (i.e., methane) via a methanation process (EPA, 2014). The CO 2 captured at the plant is sold to drilling companie s for EOR and permanent sequestration in Saskatchewan, Canada as part of the Weyburn CO 2 Monitoring and Storage project, which is overseen by the Internati onal Energy Agency (IEA). The plant exports about 8,000 metric tons CO 2 /day, which is about 50% of the CO 2 generated at the facility. As of

December 31 st , 2012, the facility had captured more than 24.5 mi llion metric tons of CO 2 , demonstrating how CCS can be used long term to redu ce emissions (EPA, 2014).

3. ELCOGAS, S.A. – Puertollano

Another pilot-scale project, located at the ELCOGAS Puertollano plant in Spain, was one of the first pre-combustion IGCC CCS pilot plants in the w orld when it began operations in 2008. The plant uses a slip stream to test a small scale (14 MW) IGCC unit. The plant captured its first

metric ton of CO 2 by 2010, and has since captured over 1,000 metric tons of CO 2 . The project has also produced over 6 metric tons of H 2 , as part of the project's stated goal to "obtain economic data enough to scale [the project] to the full Puertollano IGCC capacity in synthetic gas production." The Puertollano plant is part of a larger, Spanish national initiative to investigate advanced CCS technologies, including ge ological sequestration and oxy-fuel combustion (ELCOGAS, 2014).

4. Emirates Steel Industries – Abu Dhabi44

The United Arab Emirates' first CCS project is an a mbitious 800,000 metric tons CO 2 /year facility operating adjacent to a steel mill in Abu Dhabi. Set to begin operations in 2016, this facility will process a 90% pure CO 2 stream from the steel plant before piping it to an oil field for EOR 50 kilometers away (Masdar, 2015). The Abu Dhabi Future Energy Company and the Abu Dhabi National Oil Company decided to continue with the project after completing a 2 year pilot plant study which ended in 2011 (Evans, 2008) . The plant is expected to produce around 225 MW per year (Carvalho, 2011).

5. Huaneng – GreenGen IGCC Project

Scheduled to begin operations in 2020, Huaneng's Gr eenGen IGCC project is poised to be the largest EGU CCS project in Southeast Asia. The plan t aims to capture 2 million metric tons

CO 2 /year, which will come from sub-bituminous coal com ing primarily from China. The plant will provide 400 MW of electricity at this new plan t, the largest of its kind in China and one of the largest in the world. However, first it will op erate as a 250 MW IGCC while CO 2 capture technology is tested and developed. The facility wi ll operate as a pre-combustion CCS plant, utilizing an amine chemical solvent-based process. (Global CCS Institute, 2011)

6. Southern Company/Mississippi Power – Kemper Coun ty

The Kemper County IGCC CCS project completed constr uction in late 2013 and is currently in the "startup and testing" phase, with plans to begi n commercial operation in 2016. This facility, located in Kemper County, Mississippi, will provide 582 MW of lignite coal-based power while collecting 3.5 million metric tons CO 2 /year. Kemper County uses Pre-combustion IGCC technology, with unique CCS technology designed by KBR to provide 65% capture. Additionally, KRG designed (TRIG TM ) gasification technology to more efficiently conve rt lignite coal into syngas for combustion. The TRIG TM is "an advanced pressurized circulating fluidized bed gasifier that operates at moderate te mperatures (1,500-1950°F)" (Ariypadi, 2008).

The TRIG TM can utilize both oxy-fuel and ambient air as combu stion sources to mix with the lignite coal. The plant also utilizes SelexolTM, a s olvent that has also been used extensively for acid gas removal, including CO 2 , for decades (Mississippi Power Company, 2009).

7. Southern Company/Mitsubishi Heavy Industries (MH I) – Barry Plant

The Southern Company partnered with MHI to create a pilot-scale CCS project at the Plant Barry Power station in Mobile, Alabama. The plant u ses a 25 MW slip stream out of their 160 MW plant to capture 150,000 metric tons of CO 2 /year. The plant uses an MHI amine based process called KM-CDR, and incorporates MHIA's KS-1 solvent. The plant has successfully captured CO 2 since June 2011, and began sequestering it in an u nderground saline formation in August, 2012. The plant was initially selected to b e scaled up to a much larger size (100,000

metric tons of CO 2 capture/year) however Southern Company decided to opt out of the program in 2010 (MIT, Plant Barry Fact Sheet , 2015).

8. Summit Power – Caledonia45

The Caledonia plant, in Scotland, the United Kingdo m, is a large scale pre-combustion IGCC CSS project developed by Summit Power. The plant wi ll produce 570 MW (net) from gasified bituminous coal, and will collect 3.8 million metri c tons CO 2 /year, or 90% of the total CO 2 . This

CO 2 is sent via pipeline to a saline formation in the North Sea for geologic sequestration (Summit Carbon Capture, 2015). The plant is schedul ed to open in 2022, however it was granted funding from the UK and Scottish governments in Mar ch, 2015 to help conduct an industrial research and feasibility study to design, site, fin ance, and build the Caledonia Plant. The results of this study will be "shared across industry and a cademia, increasing understanding of how to develop and deploy CCS at commercial scale." (UK De pt. of Energy and Climate Change, 2015)

9. Summit Power - Texas Clean Energy Project (TCEP)

The TCEP will be a 400 MW IGCC facility located nea r Odessa, Texas. The plant will capture

90% of its CO 2 , which will be around 3 million metric tons/year. The plant will sell the CO 2 for use in EOR, and will also sell urea, sulfuric acid, argon, and inert slag for use in various chemical processes (Gureghian, 2010). The plant pla ns to begin construction in 2015, and will utilize the Linde Rectisol® gas cleanup process to capture CO 2 , the same process used at the Dakota Gasification plant. TCEP plans to begin cons truction in 2015 (Paul, 2015; MIT, TCEP

Fact Sheet , 2015), and hopes to begin operations by 2019. Bes ides CO 2 capture, the plant will capture 99% of Sulphur dioxide, 90% of Nitrogen Oxi de, and 99% of mercury.

10. Vattenfall/Nuon – Willem-Alexander Power Plant

The William-Alexander Power Plant, located in Bugge num, the Netherlands, is a coal-andbiomass-fired EGU that provides 253 MW of electrici ty. In 2011, the plant opened a pilot-scale CCS project testing IGCC technology with 90% CO 2 capture from pre-combustion technology. The plant used a slip stream of CO 2 equivalent to the amount produced by 20 MW of powe r, and then captured, compressed, and returned the CO 2 to the main stream instead of sequestering it. This process helped researchers determine feasibili ty and practicability of CCS for use in potential scale-ups to industrial size EGUs in the future. Due to the economic recession in the European Union, the project was discontinued in 201 4, however valuable lessons were learned about CCS during the three years of operation (MIT, Buggenum Fact Sheet, 2015).

11. 2Co Energy - Don Valley Power Project

The Don Valley Power Project is the most ambitious pre-combustion CCS project to date. 2Co energy will produce 920 MW gross (650 MW net) of po wer in South Yorkshire, the United Kingdom. The plant will capture over 90% of emissio ns, totaling some 5 million metric tons of

CO 2 /year, which will be sequestered in the North Sea ( 2Co Energy, Don Valley CCS Project ).

C. Oxy-combustion46

Table 4 contains four EGU facilities that are implementing or planning oxy-fuel combustion

CO 2 capture projects. Each project is briefly summariz ed in the following subsections.47Table 4. Oxy-combustion Carbon Capture and StorageProjectsProject NameDomestic orInternationalLocationFacilitytypeUnit typeCapturedetailsDate beganoperation(Date endedoperation ifended)Amount of CO2captured (metrictons/yr)TransportdetailsFate ofcapturedCO2FateLocationCapture PowerLtd. - WhiteRose InternationalNorthYorkshire,UnitedKingdom EGUCoal-firedpower plant(448 MW)Full (>90%)CCSplanning/permitting phase 2,000,000 Pipeline GSThe NorthSeaCS Energy -Callide AStation InternationalBiloela,Queensland,Australia EGUCoal-firedpower plant (30MW )Full (>90%)CCS 2012220,000(does notcontinuously run,captures 75mt/day whenoperating On Road GSVictoria,AustraliaFutureGen 2.0Alliance DommesticMeredosia,Illinois EGU 168 MWFull (>90%)CCS2017 (underconstruction) 1,100,000 Pipeline GSVariousLocationsTotal - Lacq International Lacq, France EGUHeavy oil-firedpower plant (30MW unit oflarger facility)Full (>90%)CCS of theunit's emissions,15% of theplant'semissions January, 2010 75,000 PipelineGS andnatural gasrecoveryRousse,France (27km away)48

1. Capture Power Limited - White Rose CCS project

Capture Power Limited, which is a consortium of Als tom, BOC, and Drax Power, is currently planning an industrial scale oxy-fuel CCS facility in North Yorkshire, the United Kingdom. The plant will produce 448 MW of electricity from coal, capturing over 90% of the emitted CO 2 , totaling 2 Million metric tons CO 2 /year. The CO 2 will be piped to the North Sea, where it will be geologically sequestered (White Rose, 2015).

2. CS Energy – Callide A Station

Located in Queensland, Australia, the Callide A sta tion is the first industrial-scale pilot plant in the country. The 30 MW coal-fired unit, part of the larger Callide plant, captures over 90% of its

CO 2 emissions when running the capture technology, whi ch is not done continuously because it's a pilot plant. The plant captures roughly 220,000 m etric tons of CO 2 /year. This CO 2 is pressurized and sent via trucks to Victoria, Austra lia, where it is sequestered underground. This pilot plant began operations in 2012. This project shows how old units (Callide A first began operations in 1965) can be retrofitted with CCS tec hnology to cost-effectively reduce emissions (Callide, 2015).

3. FutureGen 2.0 Alliance

The FutureGen 2.0 project is a combined effort from industry and government to produce a full scale oxy-fuel combustion CCS plant in the United S tates. Located in Meredosia, Illinois, the 168 MW EGU will implement full CCS using purified o xygen as fuel, allowing the plant to capture over 1.1 Million metric tons of CO 2 /year (FutureGen 2.0, About FutureGen 2.0 ). CO 2 captured from the plant will be sent via pipeline t o various locations for use in EOR or simple geologic sequestration. Completion of the project i s scheduled for 2017, making FutureGen the first full CCS plant using oxy-fuel combustion in t he US (FutureGen 2.0, About FutureGen 2.0 ). The EPA has issued Class VI deepwell construction p ermits for the sequestration phase.

4. Total – Lacq Plant

Total, in combination with Air Liquide, the French Petroleum Institute, the French Bureau of Geological and Mining Reseach, and Alstom, worked t o construct an oxy-fuel pilot plant at the Lacq facility in southern France. The 30 MW project runs on heavy oil, and captures over 90% of the unit's emissions, about 15% of the plant's t otal emissions. The Lacq oxfuel project began operations in January 2010, and has captured 75,000 metric tons of CO 2 /year each year since (Total, How CCS at the Lacq Pilot Works ). This CO 2 is transported via pipeline to Rousse, France, where it is used for natural gas recovery a nd geologic sequestration.49

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