can future coal power plants meet co2 emission standards

Can Future Coal Power Plants Meet CO2 Emission Standards Without Carbon Capture & Storage? October 2015

Low-Carbon Coal Technology Assessment 2 October 2015

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Power producers interested in new coal plants could explore po-tential thermal hosts for cogeneration projects or the economics of gasifying and firing high-quality coal. Greater public-private invest-ment in research and development (R&D) is needed to accelerate commercialization of gasification-based cycles and component technologies.

Executive SummaryThe U.S. Environmental Protection Agency (EPA) released its “new source performance standard” (NSPS) on August 3, 2015, requir-ing new coal power plants in the United States to emit no more than 636 kg (1400 lb) of carbon dioxide (CO2) per megawatt-hour (MWh) of gross power produced. Current state-of-the-art coal-fired plants, based on operations at ultrasupercritical (USC) steam condi-tions above 593°C (1100°F), emit approximately 800 kg (1760 lb) CO2/MWh. To reduce CO2 emissions from new coal power plants by more than 20%, EPA’s standard is assumed to require carbon capture and storage (CCS) technology to be applied. Several U.S. states and a number of countries have announced or are considering similar restrictions on CO2 emissions from new coal-fired plants.

Current CCS technologies and anticipated near-term commercial offerings will not only increase capital costs but also impose signifi-cant performance penalties, challenging the competitiveness of new coal generation. Many locations worldwide lack suitable geology for CO2 storage, one of several factors expected to constrain CCS deployment. This poses a question: Is technology available or in development that would enable power plants fueled solely by coal to operate so efficiently that a CO2 emission standard of 636 kg/MWh (1400 lb/MWh) or less could be met without partial CCS?

Based on the high-level assessment described in this white paper, EPRI has determined that the answer is a qualified “yes,” as sum-marized below and indicated in the figure at right:• Evenwithsteamtemperaturesexceeding800°C(1500°F)—some

200°C(360°F)higherthanthosecurrentlyachievable—USCcoalplants based on the conventional Rankine steam-electric cycle alone are not capable of meeting the standard.

• USCplantsusedinhigh-efficiencycombinedheat-and-powerap-plicationsarecapableofmeetingthestandard—butonlyatsiteswith “thermal hosts” capable of using large volumes of steam.

•Gasifyingcoalthenfiringthesynthesisgasinaconventionalcombined-cycleconfigurationcanmeetthestandard—butonlyfor certain types of gasifiers, and only when the integrated plant is fueled by high-quality coal.

• Assumingfurthertechnologicalprogress,coalgasificationpro-vides multiple pathways for achieving the standard, including gasifiers integrated with solid oxide fuel cells; with combined- cycle plants having firing temperatures for the combustion tur-bine approaching 1700°C (3100°F); or with novel cycle designs.

Table of Contents

Introduction .. .............................................................................. 3 Worldwide Carbon Standards ....................................................... 3 Carbon Management Challenges ............................................... 4 Rankine Cycle Plants with Higher Steam Temperatures .............. 5Combined Heat and Power Applications ........................................ 7 Coal Gasification Integrated with Combined Cycles .................... 10 Coal Gasification Integrated with Supercritical CO2 Cycles ..........11Coal Gasification Integrated with Solid Oxide Fuel Cells ............. 12 Coal Gasification Integrated with Triple Cycles ........................... 13Conclusions & Next Steps ........................................................... 13 References ................................................................................. 15Appendix: Technology Readiness Levels ........................................ 15

CO2 Emission Intensity,kg/MWh (gross)

Coal Technologies

Advanced Ultrasupercritical (USC) Steam Plant

Integrated Gasification Combined-Cycle (IGCC) Plant

Advanced USC Plant + 12.5% Steam Utilization

USC Plant + 14% Steam Utilization

IGCC Plant + High-Quality Coal

Integrated Gasification Supercritical CO2 Brayton Cycle Plant

Integrated Gasification Fuel Cell (IGFC) Plant

Advanced USC Plant + 25% Steam Utilization

IGCC Plant + 1700˚C Combustion Turbine

Integrated Gasification Triple-Cycle Plant

IGFC Plant + Catalytic Gasifier

IGFC Plant + Pressurized Solid Oxide Fuel Cell (SOFC)Advanced USC Plant + 50% Steam Utilization

IGFC Plant + Catalytic Gasifier + Pressurized SOFC

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IntroductionU.S. EPA’s NSPS for greenhouse gas emissions from power plants1 specifies the following limits under Section 111 of the Clean Air Act:

• Coalpowerplants:636kgCO2/MWh (1400 lb/MWh) of gross power output, rolling 12-month average.

• Naturalgascombustionturbinepowerplants: 454 kg CO2/MWh (1000 lb/MWh)ofgrosspoweroutput—or468kgCO2/MWh (1030 lb/MWh) of net power output, 12-month average.

According to EPA, electricity generation represents the single largest U.S. source of CO2 emissions. Fossil power plants ac-counted for about 37% of total emissions in 2013, and more than three-quarters of these emissions were produced by coal-fired plants.a However, existing plants are not subject to the new NSPS, instead being ad-dressed through EPA’s Clean Power Plan.b

From a regulatory perspective, the EPA standard’s basis on gross power output,

rather than net power output, is important because individual coal generation options offer differing heat rates and auxiliary power requirements. Gross power output is defined as follows:

Pgross = Pnet + Paux (1)

Where

Pgross = total amount of power produced at the generator terminals;

Paux = internal (or auxiliary) power con-sumed within the plant to operate pumps, motors, fans, and other equipment; and

Pnet = amount of power that is shipped to the grid.

State-of-the-art coal power plants operate at USC steam conditions to increase Pgross per fuel input, but they are not capable of meeting EPA’s standard. For example, the 600-MWJohnW.Turk,Jr.PowerPlant—located in southwestern Arkansas and majority-owned by Southwestern Electric Power Company, a subsidiary of American ElectricPower(AEP)—isthefirstUSCplant built in the United States, with both main and reheat steam temperatures exceed-ing 593°C (1100°F). Based on monthly data filed with the U.S. Department of Energy (DOE), the Turk plant’s average CO2 emis-sion rate was 823 kg/MWh gross (1811 lb/MWh) during 2013 and 802 kg/MWh gross (1765 lb/MWh) during 2014.

New natural gas plants integrating a com-bustion turbine with a heat-recovery steam generator (HRSG) should be able to meet the relevant U.S. CO2 emission standard of 454 kg/MWh gross (1000 lb/MWh) with-out additional controls. By EPRI’s estimate, state-of-the-art combined-cycle gas plants

have a CO2 emission rate of about 370 kg/MWh (814 lb/MWh) on a net output ba-sis,2 well below the U.S. limit. (1026656)

Given the inability of state-of-the-art coal power plants to meet the NSPS, EPA has specified that partial implementation of CCS at future coal plants is the “best system of emission reduction” to be used in achiev-ing a CO2 emission rate at or below 636 kg/MWh gross (1400 lb/MWh).1 EPA suggests that the standard could also be met by co-firing natural gas at coal plants.

This white paper focuses on coal-only technology options. It introduces other CO2 emission standards for coal plants, identifies key challenges associated with CCS deploy-ment, and provides detailed discussion of whether future coal-based power plants could achieve CO2 standards without CCS.

Worldwide Carbon StandardsIn the United States and around the world, governments have established or proposed CO2 emission performance standards with similar technological implications to EPA’s limit of 636 kg/MWh gross (1400 lb/MWh). Some examples are listed in Table 1. Typically based on net output delivered to the grid, they are further described below.

California, Maine, and Washington have set CO2 emission limits at no more than 500 kg/MWh (1100 lb/MWh). These state standards are based on net rather than gross power output, further increasing their strin-gency relative to EPA’s limit: Output-based emissions are not only capped at a lower level but also must be calculated after sub-tracting auxiliary consumption from gross production. In the case of a conventional coal plant, for example, a net standard of 636 kg/MWh (1400 lb/MWh) would allow

Table 1 - Recent CO2 Emission Standards for New Coal Plants

a See http://www.epa.gov/climatechange/ghgemissions/sources/electricity.html.

b See http://www2.epa.gov/cleanpowerplan.

Country or StateStandard

CO2/MWh

United States 636 kg (1400 lb) gross

California 500 kg (1100 lb) net

Maine 500 kg (1100 lb) net

Washington 500 kg (1100 lb) net

New York 420 kg (925 lb) net

United Kingdom 450 kg (992 lb) net

Canada 420 kg (925 lb) net

China 763 kg (1679 lb) net

http://www.epri.com/abstracts/Pages/ProductAbstract.aspx?ProductId=000000000001026656

http://www.epa.gov/climatechange/ghgemissions/sources/electricity.html

http://www2.epa.gov/cleanpowerplan


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units, generally defined as having reached an age of 50 years since starting to produce electricity commercially.

China’s “Action Plan of Upgrade and Reno-vation of Coal Power for Energy Conser-vation and Emission Reduction,” issued in 2014, takes a different approach. The standard is based on net power output,c but the CO2 emission rate shown in Table 1 is calculated based on China’s specified limits on fuel consumption for new power plants. Mass-based limits for bituminous coal are 282 kg fuel/MWh (620 lb/MWh) for 1000-MW power plants and 285 kg fuel/MWh (630 lb/MWh) for 600-MW power plants.d

Limits are for a standard bituminous coal with a lower heating value (LHV) of 7000 kcal/kg (or 29,288 kJ/kg = 12,600 Btu/lb), equivalent to a high-quality bitumi-nous coal similar to Pittsburgh #8. If this standard coal is assumed to have carbon content similar to that of Pittsburgh #8, then China’s fuel consumption limit for

about 5% less CO2 emissions than a gross standard set at that level.

The California and Washington standards apply to baseload power purchased by load-serving entities through new long-term contracts. The standard adopted by New York includes an output-based CO2 limit of 420 kg/MWh net (925 lb/MWh) and an input-based CO2 limit of 55 kg/million Btu (120 lb/million Btu) of fuel for new or expanded baseload fossil plants.

The United Kingdom’s Energy Act 2013 set a CO2 standard of 450 kg/MWh net (992 lb/MWh) for new fossil generation, which will apply until 2045. In 2012, Canada passed a standard for coal-fired power plants limiting the annual average CO2 emission rate to 420 kg/MWh (925 lb/MWh) based on net power output, plus the energy used for CO2 compression in a CCS system. The Canadianstandardappliestonewunits—those that begin producing power commer-ciallyafterJuly1,2015—andalsotoold

1000-MW power plants is equivalent to a CO2 emission rate of 763 kg/MWh (1679 lb/MWh). While this standard will require the use of USC steam conditions, it appears to be achievable without CCS.

Carbon Management Challenges Except in China, existing and proposed government standards for CO2 emissions cannotbemetsolelybybuildinganefficientcoal power plant using current state-of-the-art USC technology. To achieve EPA’s limit, the conventional wisdom is that more than 20% of a new U.S. coal plant’s CO2 emis-sions would have to be captured for long-term sequestration. Available CCS options pose significant challenges and limitations (see box, p. 9).

Carbon capture with underground stor-age has been deemed by EPA as the “best system of emission reduction,” but applica-tions are constrained by technology, policy, and market factors. Power plant developers

c Professor Jianxiong Mao, Tsinghua University, personal communication, April 2015. dChina’s action plan includes additional limits for power plants burning low-rank coal: 310 kg/MWh for plants between 300 and 600 MW and 303 kg/MWh for plants ≥600 MW.

Turk Power Plant in Arkansas: First U.S. plant operating at ultrasupercritical steam conditions (Credit: AEP)


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evaluating possible investments are reluc-tant to consider new coal generation due to uncertainty, the cost of capture, and the dif-ficulty in finding a suitable storage location.

Some industry executives are beginning to wonder if an easier path to regula-tory compliance might be found through advanced coal technology. The answer is clear: Without CCS, a CO2 limit of 636 kg/MWh (1400 lb/MWh) or lower can only be achievedbyincreasingthethermalefficiencyof the energy conversion processes involved ingeneratingelectricityfromcoal—achal-lenge more easily stated than accomplished. This is because the gross CO2 emission intensity of a power plant without capture is directly proportional to its gross heat rate:

mCO2 HRg 44—– = —– —– x Xc x kWgross ∆H 12

(2)

Where

mCO2= mass flow rate of CO2 emitted in kg/h or lb/h;

kWgross = gross power output in kW;

HRg = gross heat rate in kJ/kWh or Btu/kWh;

∆Hc = higher heating value (HHV) of the coal in kJ/kg or Btu/lb;

Xc = mass fraction of carbon in coal; and

44/12 = ratio between molecular weights of CO2 and elemental carbon.

For a best-in-class USC plant like Turk, EPRI estimates gross heat rates when firing Powder River Basin (PRB) sub-bituminous coal or high-quality Pittsburgh #8 bitu-minous coal are 8860 kJ/kWh (8400 Btu/kWh) or 8276 kJ/kWh (7845 Btu/kWh), respectively, on an HHV basis. Per Equation 2, these heat rates yield gross CO2 emis-sion intensities of 802 kg/MWh (1765 lb/

MWh) and 734 kg/MWh (1614 lb/MWh), respectively. Burning high-quality coal yields a lower heat rate and, in turn, lower emis-sion intensity, but achieving 636 kg/MWh (1400 lb/kWh) requires a gross heat rate of approximately 7042 kJ/kWh (6675 Btu/kWh). That corresponds to a gross thermal efficiencyofapproximately51%(HHVba-sis), far above the ~43% reached by today’s best-in-class USC units.

High-quality bituminous fuel makes up only about half of the world’s coal resource. This white paper focuses on possible tech-nology options for meeting EPA’s standard while firing PRB coal, representative of widely available lower-rank fuels. Figure 1 plots the approximate relationship between CO2emissionintensityandthermalefficien-cy (both on a gross power output basis) for a plant using PRB coal. While the shape of the curve is similar for all coals, fuel-specfic values differ depending on heating value and carbon content. Regardless, step-change increasesinthegrossthermalefficiencyofcoal generation will be required to achieve a CO2 emission intensity of 636 kg/MWh (1400 lb/kWh) or lower without CCS.

Figure 1 – Relationship between CO2 emission intensity and gross thermal efficiency for a sub-bituminous coal power plant

Rankine Cycle Plants with Higher Steam TemperaturesThe overwhelming majority of coal-fired power plants are based on the Rankine cycle, in which high-pressure steam is raised from the heat released while burning pulverized coal. The steam is used to spin a turbine, which in turn drives an electric generator. The basic thermodynamics of the Rankine cycle (and in fact of any heat en-gine)dictatethatefficiencycanbeimprovedby increasing the temperature ratio of the hottest and coldest points in the cycle.

For the Rankine cycle, this means increasing the temperature of the steam entering the turbine and/or decreasing the temperature in the condenser at the turbine exit. Ambi-entconditions,alongwiththeefficacyofthe cooling technologies used to condense steam back into liquid water, determine how low the condenser temperature can go. Thermoelectric cooling technology concepts being pursued by EPRI with support from the U.S. National Science Foundation offer modestpotentialforgrossthermalefficiencygains.3 (3002004334)

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Boosting steam turbine inlet temperature creates opportunity for more significant in-creasesinefficiency.Figure2showsthehis-tory of how steam turbine inlet temperature

has progressed from the time of Thomas Edison at the beginning of the 20th century until today. For 60 years, there was a steady advance from 260°C (500°F) to 650°C

(1200°F), culminating with construction of Philo Unit #6 in Ohio and then Eddystone Unit #1 near Philadelphia. However, no coal-fired power plant built in the past 55 years has exceeded Eddystone’s turbine inlet temperature because the power industry had reached a limit in the capabilities of ferritic-based steels.

Since 2001, a DOE-funded R&D consor-tium has been pursuing advanced materials for coal-fired boilers and steam turbines, with EPRI serving as the technical lead.4 (3002001343) Figure 3 shows that all met-als lose strength as temperature increases. A typical stress encountered by boiler steam tubing is 100 MPa. The ability of fer-ritic steels to withstand that stress level for 100,000 hours without rupturing ends at temperatures exceeding 600-620°C (1100-1150°F). Indeed, materials exposed to 650°C (1200°F) steam at Eddystone experi-enced failures after a few years of operation. Additional failures were avoided after plant operators limited steam temperatures to 610°C (1130°F) in the early 1960s.5

Figure 3 indicates that materials other than ferritic steels must be used to increase the thermalefficiencyoftheRankinecycle.In particular, nickel alloys such as Inconel 740 and Haynes 282, both of which have undergone extensive analysis and testing by the DOE consortium, show promise of al-lowing steam temperatures to rise to 760°C (1400°F).4 That would allow an increase ingrossthermalefficiencyofatleast10%,from the current ~41% for USC plants to ~45% for next-generation advanced USC plants.

Validation testing of key components under realistic advanced USC conditions hasbroughtthishigher-efficiencygenera-tion option to TRL5 on EPRI’s technol-

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Figure 2 – Timeline showing maximum steam turbine inlet temperature achieved by power plants since 1900, featuring the two units achieving the latest milestones plus the Turk plant



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ogy readiness level (TRL) scale, which is illustrated in Figure 4 and described in the Appendix on p. 15.

WouldthesignificantincreaseinefficiencybesufficienttomeetEPA’sstandard?Figure5 shows that it would not, based on results from a series of engineering evaluations EPRI has carried out on current and pos-sible future USC power plant designs.6,7,8 (1017515, 1015699, 3002001788) The plot shows that the CO2 emission rate ranges from 789 kg/MWh gross (1736 lb/MWh) to 715 kg/MWh gross (1573 lb/MWh) de-pending on steam temperature and pressure, other design variables, and fuel quality. The low end of the range represents approxi-mately a 10% decrease in CO2 emission intensity from today’s USC plants, far from the ~22% reduction that the EPA stan-dard would require. Deploying advanced Rankine cycles would, however, significantly decrease the amount of CO2 that would have to be captured and stored in order to achieve compliance.

Of course, the possibility exists for materials to be developed that would allow Rankine cycle coal power plants to reach steam tem-peratures greater than 760°C (1400°F). Us-ing commercial software, EPRI has carried out calculations based on thermodynamic

Figure 5 – CO2 emission intensities of USC plants per gross power output as a function of steam conditions at varying pressures and temperatures

properties for steam valid up to 1371°C (2500°F). A plant operating at this steam temperature is predicted to have a CO2 emission intensity of 575 kg/MWh gross (1266 lb/MWh), assuming materials could be found that tolerate such conditions. By extrapolation, a plant capable of meeting the EPA standard of 636 kg/MWh gross (1400 lb/MWh) would require steam tempera-tures around 1125°C (2050°F). This is well beyond current materials technology.

Combined Heat and Power ApplicationsAnother way to increase the thermal ef-ficiency of pulverized coal power plants is to utilize the input fuel’s energy to produce both electric power and useful heat. Com-bined heat and power (CHP) or cogenera-tion(cogen)plants—astheyarefrequentlycalled in Europe and the United States, respectively—canapproachveryhighutili-zation rates. The technology is commercially mature. Examples of typical “thermal hosts” for the exported heat from CHP plants are oil refineries, food processing facilities, and

central heating districts for commercial buildings, large hotels, hospitals, and uni-versity campuses. Because exported heat can displace the burning of fossil fuel that would otherwise have been used to generate heat at the thermal host’s location, EPA’s standard offers CHP plants full credit for any heat that is exported and put to good use, ac-cording to the following formula:

[(PeST + PeCT + PeIE - PeFW ) =

(PtHR + PtIE + PtPS )

Pgross

+/T ]

(3)

Where

Pgross = Gross energy output of affected facil-ity in MWh;

PeST = Electric energy output plus mechani-cal energy output (if any) of steam turbine(s) (ST) in MWh;

PeCT = Electric energy output plus mechani-cal energy output (if any) of combus-tion turbine(s) (CT) in MWh;

PeIE = Electric energy output plus mechani-cal energy output (if any) of affected facility’s integrated equipment (IE)

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290BAR/593C/621C + High-Quality Coal

Figure 4 - EPRI’s Technology Readiness Levels

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Pgross = PeST – PeFW / T + (Qm x H / 3.6 x109 ) (5)

To assess the CO2 emission intensity of cogen applications based on EPA’s formula, EPRI explored four CHP cases, one based on current USC steam conditions and the others starting from an advanced USC plant design with a main steam pressure of 276 bar (4000 psi) and main and reheat steam temperature of 760°C (1400°F). The latter three cases are based on extracting 12.5%, 25%, and 50% of the steam at the cross-over between the intermediate- and low- pressure turbine sections.

The results are shown in Figure 6. EPA’s standard of 636 kg/MWh (1400 lb/MWh) could be achieved by a new cogen plant based on current state-of-the-art USC tech-nology like that employed at Turk but also incorporating at least 14% steam extraction and utilization. The limit also could be met by using at least 12.5% of the steam from an advanced USC plant. Lower standards set by U.S. states and other nations could be achieved based on higher CHP fractions.

However, scale is an issue. An advanced USC plant producing nominally 750 MW of net electric power with 12.5% steam extraction would require a thermal load of approximately150MW—about50kg/s(0.4 million lb/h) of steam at 4.7 bara (68 psia) and 367°C (693°F). As a point of reference, the cogen plant supplying steam to Total’s Gonfreville refinery in Normandy, France, has a thermal load of 330 MW.12 Because only a modest number of thermal loads sized at 150 MW or larger are likely to be available, smaller advanced USC plants operating in CHP mode may represent a more widely applicable approach for achiev-ing a CO2 emission intensity of 636 kg/MWh (1400 lb/MWh) or lower.

that provides electricity or mechani-cal energy to the affected facility or auxiliary equipment in MWh;

PeFW = Electric energy used to power boiler feedwater (FW) pumps at steam generating units in MWh;

T = Electric transmission and distribution factor, set to 1.0 for most affected fa-cilities and to 0.95 only for a facility where at least 20% of Pgross consists of electric or direct mechanical output on an annual basis and 20% of Pgross consists of useful thermal energy output on a rolling 3-year basis;

PtHR = Hourly useful thermal energy output, measured relative to standard ISO conditions, from heat recovery (HR) for applications other than steam generation or performance enhance-ment of the affected facility in MWh;

PtIE = Useful thermal energy output relative to ISO conditions from any integrat-ed equipment that provides thermal energy to the affected facility or auxil-iary equipment in MWh; and

PtPS = Useful thermal energy output of steam, measured relative to ISO con-ditions, that is used for applications that do not generate additional elec-tricity, produce mechanical energy output, or enhance the performance of the affected facility.

The term PtPS is calculated in MWh as

(4)

Where

Qm = Measured steam flow in kg (lb) for the operating hour;

H = Enthalpy of the steam at measured temperature and pressure relative to ISO conditions in J/kg (Btu/lb); and

3.6 x 109 = Conversion factor in J/MWh (3.413 x 106 Btu/MWh).

Assuming that only steam is exported to a thermal host and that the FW pump is driven by an electric motor, the formula for gross power becomes:

Qm x H= ———–Pt PS

3.6 x 109

Figure 6 – CO2 emission intensities of CHP plants based on USC technology with various levels of steam extraction to a thermal host

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What Comes Up Must Go Down: Carbon Capture & Storage Challenges

Thought leaders and large-scale energy-economy modeling studies generally agree: A growing world’s needs and wants cannot be met without continued reliance on fossil fuels, for decades into the future. Mitigating CO2 emissions to the atmosphere while generating bulk quantities of electricity poses both technical and societal challenges. In particular, technologies for capturing carbon and ensuring long-term sequestration must be commercially feasible, economically viable, and publicly acceptable—and capable of operating at massive scale.

Present and near-term capture technologies scrub CO2 from flue gas using amine-based processes that impose a parasitic loss of ~20% on typical coal-fired plants. Compression of captured, concentrated CO2 for pipeline transport adds another ~10% in auxiliary load, further increasing heat rate. Adding CCS thus is projected to nearly double the levelized cost of electricity from new coal plants. Cap-ture processes with game-changing potential are being pursued by EPRI, but these early-stage innovations are at least a decade away from commercialization.9 (3002004897)

According to EPRI’s analysis, high cost is not the only obstacle to applying what EPA calls “the best system of emission reduction.” Something must also be done to prevent the eventual release of captured CO2. Beneficial utilization suffers from the inability to scale: Other than at fossil fuel extraction sites suitable for enhanced oil and gas recovery, the potential for industrial-scale use of CO2 is limited because markets are small compared to the scale of CO2 emissions, and most direct utilization options do not provide long-term sequestration. Converting CO2 into a more useful chemical form requires many times the amount of energy produced by combustion. Methods such as reacting captured CO2 with minerals to produce limestone have been shown to be feasible but impractical at pres-ent.10 Storing captured carbon in the ocean—at depths and temperatures below which the CO2 would persist in liquid or solid depos its on the seafloor—is unproven from all standpoints.11

Returning extracted fuel carbon to underground storage has the best near-term potential. Deep saline, depleted fuel reservoir, and oth-er formations potentially amenable to CO2 storage are broadly distributed in the United States and around the world. Integrated CCS technology has been tested at a number of sites and is being applied at industrial scale but on a limited basis, notably in a pioneering project at the Boundary Dam Power Station in Saskatchewan, Canada. Captured and compressed CO2 from a 110-MW coal-fired unit is transported by pipeline and injected underground for enhanced oil recovery then long-term sequestration.

However, several nations with significant coal fleets—including Japan, South Africa, and Ko-rea—appear to lack on-shore locations with suit-able geology for long-term CO2 storage. Even within the United States, few potentially suitable formations have been tested with large-scale injections to prove viability—something power plant developers and their financial backers will require before proceeding with multi-billion-dollar projects. Also, important institutional obstacles exist. For example, environmental, health, and safety concerns have created politi-cal barriers to the permitting of underground carbon storage facilities in Germany, while U.S. regulations require power producers or other responsible parties to monitor sequestration sites for 50 years after CO2 injection has ended.

The path forward for CCS remains uncertain. CCS Test Facility at Plant Barry in Alabama: Early U.S. demonstration project (Credit: Southern Company)



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IGCC deployment continues, placing the technology at TRL8.

State-of-the-art IGCC units have thermal efficienciesbasedonnetpoweroutputthatare similar to those of state-of-the-art, stand-alone Rankine cycle coal power plants. However, the auxiliary power consumption ofIGCCsisgreater—animportantconsid-eration when gross CO2 emission intensity is the parameter of merit.

EPRI has conducted engineering and performance analysis studies of several IGCC plant configurations.13,14 (1015690, 1022034) As indicated in Figure 8, IGCC plantshavingnetthermalefficienciescomparabletoUSCplants—andoperat-ingonthesamesub-bituminouscoal—of-fer significantly lower gross CO2 emission intensities. However, carbon emissions are still well above 636 kg/MWh (1400 lb/MWh), except in one case with high-quality bituminous coal and the dry-feed Shell gasifier. This scenario could increase plant efficiencytothepointthatCO2 emissions would fall just below EPA’s limit at 627 kg/MWh (1380 lb/MWh).

Coal Gasification Integrated with Combined CyclesGasifying coal to produce a synthesis gas (syngas) opens up additional potential pathways for meeting CO2 emission limits without CCS. Syngas, consisting pre-dominantly of carbon monoxide (CO) and gaseous hydrogen (H2) fuel, can be turned into electricity by many methods. One is through a combined-cycle plant, like today’s workhorse natural gas generators, which offergrossthermalefficiencyof50-54%onanHHVbasis(typically,theirefficiencyisreported at 55-60% on an LHV basis).

A simplified process diagram of an inte-grated gasification combined cycle (IGCC) power plant is shown in Figure 7. The coal is converted to syngas, which is cooled to achieve temperatures that combustion turbine materials can accommodate. Con-taminants, specifically sulfur species and ash mineral content, are removed. Clean syngas is then fired in the open Brayton cycle combustion turbine. The turbine exhaust is fed to the Rankine cycle HRSG, which also receives steam from the syngas cooler. Early

While existing IGCC technology could meet EPA’s standard under certain condi-tions, more stringent limits in the UK, Canada, and some U.S. states could not be achieved.IGCCefficiencygainscanbereal-ized by increasing the firing temperature of the combustion turbine. EPRI’s 2011 IGCC R&D roadmap concluded that going from today’s range of 1370°C–1430°C (2500°F–2600°F) to 1700°C (3100°F) would decrease heat rate by 16%.15 (1022035) If that holds true for the PRB coal “Shell” case shown in Figure 8, then the CO2 emissions intensity of an IGCC plant with a higher-tempera-ture combustion turbine (HTCT) would be approximately 567 kg/MWh (1248 lb/MWh)—wellbelowEPA’sstandard.

Japan has a national R&D program pursu-ing a combustion turbine with 1700°C (3100°F) firing temperature. The focus is on advancing the necessary materials tech-nology by developing key components, as steps toward creating a complete turbine.16 U.S. government programs have supported the development of jet engines for military aircraft with much higher turbine inlet temperatures. The Pratt & Whitney jet en-Figure 8 – CO2 emission intensities of state-of-the-art IGCCs and a future IGCC plant with a higher-

temperature combustion turbine

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Figure 7 – Simplified process diagram of an IGCC plant

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more than a 25% increase in net thermal efficiencyrelativetostate-of-the-artIGCCplants with 90% CCS. For the vented SCO2 cycle illustrated in Figure 9(b), net thermal efficiencyisestimatedtobeevenhigher,at42% (HHV basis), compared with 40.5% for the SCO2 cycle with CCS. The CO2 emission intensity of the vented process is 603 kg/MWh (1326 lb/MWh), below the EPA target as illustrated in Figure 10.

gine used in the F-35 “Joint Strike Fighter” operates at 1982°C (3600°F).17 The techni-cal feasibility of a firing temperature ap-proaching 1700°C (3100°F) thus has been established. The timeline for commercial deployment of HTCTs optimized for IGCC operation is uncertain but appears about a decade away, given the current TRL4-5.

Coal Gasification Integrated with Supercritical CO2 Brayton CyclesClosed Brayton cycles using supercritical CO2 (SCO2) as the working fluid are being investigated by several organizations as a waytoincreasethethermalefficiencyofadvanced nuclear, solar, and fossil power plants, relative to designs based on the Ran-kine steam cycle. An early demonstration of this advanced cycle is under development for natural gas and concentrating solar plant applications. When completed, this will advance the technology to TRL6.

The SCO2 cycle can also be integrated with a coal gasifier. Figure 9 shows a simplified process diagram of two possible oxy-fired configurations, one with CCS (a) and the second with CO2 venting (b). In both cases, oxygen reacts with syngas in the burner. SCO2 is introduced to the burner to dilute the mixture because firing syngas in oxygen would result in temperatures above 2750°C (5000°F), far exceeding the level current turbine technology can tolerate. Recycling a large flow of CO2, as indicated by the green-shaded portion of Figure 9, moderates the firing temperature to 1150°C (2100°F).

The stream exiting the burner includes a small amount of water vapor but consists mostly of CO2. The ratio of recycled CO2 to that produced by combustion of the syngas is about 10:1. The flow is expanded

in a turbine to drive a generator. The turbine exhaust, still at high temperature (>700°C or 1300°F), is directed to a large heat exchanger (recuperator), then cooled further to condense out the water vapor. The remaining flow, essentially all CO2, is raised up to high pressure (165 bar or 2400 psi), then preheated in the recuperator prior to reintroduction to the burner.

To maintain a mass balance, CO2 equal to the amount formed by combusting the syngas must be bled off from the flow. As shown in Figure 9(a), this CO2 may be extracted downstream of the pump at a pressure suitable for pipeline transport and carbon storage. Figure 9(b) illustrates an alternative without CCS: Rather than be-ing compressed, the bled CO2 is expanded through a small letdown turbine then vented to the atmosphere. This allows about 5% more power to be produced.

A 2014 EPRI report summarizes find-ings from an analysis of various syngas-fed oxy-fired SCO2 Brayton plant designs with 100% CCS.18 (3002003734) The con-figuration illustrated in Figure 9(a) offers

Figure 9 – Simplified process diagram of a coal gasifier integrated with a semi-closed oxy-fired SCO2 Brayton cycle and (a) CCS or (b) a CO2 letdown turbine venting to the atmosphere

Figure 10 – CO2 emission intensity of the SCO2 Brayton gasification process with venting

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Coal Gasification Integrated with Solid Oxide Fuel CellsFuel cells have long held the promise of higher-efficiencypowergenerationbasedonnatural gas, hydrogen fuel produced via the electrolysis of water, and other gaseous fuels. Combining a coal gasifier with a fuel cell offers similar opportunity. In 2011, DOE’s National Energy Technology Laboratory (NETL) issued an analysis of the projected performance of integrated gasification fuel cell (IGFC) power plants, in which solid ox-ide fuel cell (SOFC) technology essentially replaces the combustion turbine in IGCC designs.19

Figure 11 is a simplified IGFC process diagram. As with a conventional IGCC plant, the coal is converted to syngas, which is cooled to a level the SOFC can tolerate. The fuel cell can be thought of as a dry cell battery—butoneinwhichthechemicalingredients are continuously refreshed rather than depleted as energy is produced. In the case of an SOFC, the ingredients are syngas, which is fed to the anode side of the cell, and oxygen, which is supplied by blowing

air into the cathode side of the cell. This enables an electrochemical reaction that pro-duces heat and induces direct current, which is converted to grid-compliant alternating current via an inverter.

The chemical reaction in the SOFC does not fully consume the syngas. Any remain-ing CO and H2 are mixed with hot air leaving the cathode and then combusted in a burner. The HRSG applies the combus-tion exhaust from the burner to raise steam, which is mixed with steam produced in the syngas cooler to drive a steam turbine. The SOFC can operate at atmospheric pressure, in which case the auxiliary power required to blow the air through the cathode is rather modest, or at elevated pressure, which increases gross energy output. Pressurized SOFCs can employ an electric compres-sor as shown in Figure 11 or draw on an expander driven by combustion exhaust to push the air into the cathode.

NETL’s IGFC study considered two differ-ent types of gasifiers: a conventional gasifier producing syngas with 6% methane (CH4) by volume and a catalytic gasifier producing

enriched syngas with 30% CH4 by volume. IGFC designs with the SOFC operating at atmospheric pressure and at 19.7 bara (285 psia) also were considered. NETL results from these four options are presented in Figure 12, demonstrating the performance benefits of SOFCs. EPA’s standard could be achieved using a conventional gasifier with an SOFC operating at atmospheric pres-sure. More stringent standards could be met by using a pressurized SOFC or catalytic gasifier. An IGFC plant design operating on CH4-enriched syngas and at elevated pres-sure would have a CO2 emission intensity of 430 kg/MWh (946 lb/MWh).

IGFC technology is at TRL4, largely be-cause SOFCs are still at an early stage in the development cycle. A recent peer review of DOE’s SOFC R&D program indicated that the largest high-temperature SOFC module constructed to date has a rated capacity of 60 kW of power and has operated for only 1600 hours.20 According to EPRI’s analysis, megawatt-scale modules are not expected until after 2020.

Figure 12 – CO2 emission intensities of several IGFC cycles

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Figure 11 – Simplified process diagram of an IGFC power plant with pressurized SOFC

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Coal Gasification Integrated with Triple CyclesUniversity of Tokyo professor Dr. Shozo Kaneko, among others, has promoted the concept of integrating SOFCs with conven-tional combined-cycle plant configurations to create “triple-cycle” plants that could be fueled by natural gas, coal-derived syngas, or other sources.21 A simplified diagram of Dr. Kaneko’s integrated gasification triple- cycle (IGTC) plant is shown in Figure 13. Thepotentialthermalefficiencyadvantageof IGTC over IGFC designs is that hotter turbine inlet temperatures can be achieved by having the SOFC feed a combustion turbine.

To conduct an initial assessment of this design, EPRI developed a simplified IGTC model and simulated performance based on a conventional coal gasifier, a pressurized SOFC, and a G-class turbine with a 1500°C (2732°F) firing temperature. Results shown in Figure 14 indicate a possible net thermal efficiencyofgreaterthan51%(HHVbasis)and CO2 emission intensity of approximate-ly 527 kg/MWh gross (1159 lb/MWh), suf-

ficient to achieve the EPA standard. Room forimprovementinIGTCperformance—toachieveevenlowerlimits—appearstoexistthrough design optimization and perhaps eventually through the achievement of a 1700°C (3100°F) turbine firing tempera-ture. SOFC technology remains the limiting factor.

Figure 14 suggests that the triple-cycle design has a higher CO2 emission intensity than the IGFC plant with a pressurized SOFC. However, this is an artifact of both

underlying design assumptions and the EPA standard’s basis on gross power output. The pressurized IGFC configuration represented in Figure 11 employs an electric compressor to deliver air to the cathode, increasing gross output and thus artificially reducing gross emission intensity. The IGTC configuration simulated by EPRI instead pressurizes the SOFC via an air compressor with a direct mechanical connection to the expander in the combustion turbine, improving thermal efficiency.Consequently,IGTCplantsareexpected to be better performers relative to CO2 emission standards based on net power output.

Conclusions & Next StepsYes, technology has been identified that would enable new coal power plants to operatesoefficientlythataCO2 emis-sion standard of 636 kg/MWh (1400 lb/MWh) could be met without partial CCS. However, among all of the options firing sub-bituminous coal considered in EPRI’s analysis and shown in Figure 14, none with potential to meet the standard are com-mercially available, economically viable, and suitable for broad deployment.

Figure 14 – CO2 emission intensity of IGTC design

Figure 13 – Simplified process diagram of an IGTC plant

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Technologies capable of achieving EPA’s standard are highlighted in red in Table 2. State-of-the-art USC technology operating in a CHP configuration can meet the target, but only at power plant sites near a refinery or other thermal host large enough to utilize at least 14% of the steam exiting the inter-mediate-pressure turbine. CHP plants based on advanced USC steam conditions (760°C; 1400°F) represent a possible future option with potential for meeting EPA’s standard as well as the limits of 500 kg/MWh (1100 lb/MWh) and lower proposed or existing in U.S. states and nations such as the UK and Canada. Relatively small advanced USC plants, thus requiring smaller thermal hosts, have wider possible applicability.

IGCC plants may be capable of achieving EPA’s standard, depending on choice of gasifier technology and only if fueled by high-quality bituminous coal. Coal gasifica-tion integrated with higher-temperature combustion turbines, fuel cell technologies, or novel generation cycles opens up multiple possible future pathways for achieving emis-sion intensities well below EPA’s limit, but without partial CCS. While not investigated in EPRI’s recent study, applying gasification-based technologies in cogeneration mode could result in even lower emissions, assum-ing suitable thermal hosts could be found.

To help expand the available options for generating electricity with coal while achiev-ing CO2 emission standards, additional public-private R&D investment is needed to accelerate the commercialization of SOFC technologies, higher-temperature turbines capable of operating on coal-derived syngas, and SCO2 Brayton cycles. National R&D programs in the United States, Japan, and elsewhere are making progress. Greater resources and increased collaboration are recommended due to the challenges that

are facing CCS deployment. In addition, a study of existing and potential future thermal hosts capable of accommodat-ing large volumes of steam in the United States and other countries is recommended.

Technology DetailsCO2 Emission Intensity,

kg/MWh, grossEfficiency, %

USC 290BAR/593C/621C6 789 38.4

USC 276BAR/593C/616C8 777 39.5

USC 276BAR/649C/671C8 754 40.8

USC 276BAR/704C/727C8 735 42.0

USC 290BAR/593C/621C + High-Quality Coal8 734 41.2

USC 352BAR/680C/700C7 723 42.7

USC 276BAR/760C/760C8 721 42.8

USC 352BAR/680C/700C/700C7 715 43.4

USC+CHP 290BAR/593C/621C + 14% Steam Extraction 636 46.5

USC+CHP 276BAR/760C/760C + 12.5% Steam Extraction 636 49.0



IGCC Siemens/2XGE7FB13 743 38.2

IGCC E-Gas/GE7FB14 702 38.7

IGCC Shell/3XGE7FB13 676 40.0

IGCC Shell/3XGE7FB + High-Quality Coal13 627 41.9

IGCC + HTCT Shell + 1700C Combustion Turbine 567 47.6

IG+SCO2 Oxy + CO2 Venting 603 42.0

IGFC Atmospheric Pressure SOFC19 603 43.7

IGFC Catalytic Gasifier + Atmospheric Pressure SOFC19 501 54.0

IGFC Pressurized SOFC19 498 51.5

IGFC Catalytic Gasifier + Pressurized SOFC19 430 61.4

IGTC Pressurized SOFC + 1500C Combustion Turbine 527 51.3

Table 2 - Technologies Considered in EPRI’s Analysis, Relative to EPA’s Standard

This would help determine the extent to which the CHP option may be available for building new coal-fired power plants and achieving CO2 emission standards without the need for partial CCS.


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References1. U.S. EPA. “Standards of Performance for Greenhouse Gas

Emissions from New, Modified, and Reconstructed Stationary Sources: Electric Utility Generating Units,” 40 CFR Parts 60, 70, 71, and 98, August 3, 2015. See http://www.epa.gov/airqual-ity/cpp/cps-final-rule.pdf.

2. Program on Technology Innovation: Integrated Generation Technol-ogy Options 2012. EPRI, Palo Alto, CA: 2013. 1026656.

3. Program on Technology Innovation: Proceedings of the 2014 NSF/EPRI Power Plant Dry Cooling Science and Technology Innovation Program Kickoff Meeting: Washington, D.C., April 15-16, 2014.EPRI, Palo Alto, CA: 2015 3002004334.

4. Progress Report on Advanced Ultra-Supercritical Technology Devel-opment. EPRI, Palo Alto, CA: 2013. 3002001343.

5. Silvestri, G.J. Jr. “Eddystone Station 325 MW Generating Unit 1 – A Brief History.” ASME Mechanical Engineering Heritage Site Report H226, 2003.

6. An Engineering and Economic Assessment of Post-Combustion CO2 Capture for 1100°F Ultra-Supercritical Pulverized Coal Power Plant Applications. EPRI, Palo Alto, CA: 2010. 1017515.

7. Engineering and Economic Evaluation of 1300°F Series Ultra- Supercritical Pulverized Coal Power Plants: Phase 1. EPRI, Palo Alto, CA: 2008. 1015699.

8. Advanced Ultra-Supercritical Steam Cycle Optimization. EPRI, Palo Alto, CA: 2014. 3002001788.

9. Program on Technology Innovation: Carbon Capture. EPRI, Palo Alto, CA: 2015. 3002004897.

10. International Energy Agency Greenhouse Gas (IEAGHG) R&D Programme. Mineralisation – Carbonation and Enhanced Weath-ering. IEAGHG Report 2013/TR6, July 2013.

11. Intergovernmental Panel on Climate Change (IPCC). Special Report on Carbon Dioxide Capture and Storage. Prepared by IPCC Working Group III, 2005.

12. Fontaine, P., and Naessen, P. “Fresh air firing: HRSG guarantees steam supplies to French refinery,” Cogeneration & On-site Power, Vol 7, No. 5, 2006.

13. IGCC Design Considerations for CO2 Capture. EPRI, Palo Alto, CA: 2009. 1015690.

14. Engineering and Economic Evaluations of Integrated-Gasification Combined-Cycle Plant Designs with Carbon Dioxide Capture. EPRI, Palo Alto, CA: 2011. 1022034.

15. CoalFleet Integrated Gasification Combined Cycle Research and Development Roadmap: 2011 Update. EPRI, Palo Alto, CA: 2011. 1022035.

16. Tsukagoshi, K., et al. “Operating Status of Uprating Gas Tur-bines and Future Trend of Gas Turbine Development.” Mitsubi-shi Heavy Industries Technical Review, Vol. 44, No. 4, 2007.

17. Langston, L. “Fahrenheit 3,600,” Mech. Engineering, April 2007.

18. Performance and Economic Evaluation of Supercritical CO2 Power Cycle Coal Gasification Plant. EPRI, Palo Alto, CA: 2014. 3002003734.

19. U.S. DOE. “Analysis of Integrated Gasification Fuel Cell Plant Configurations.” DOE/NETL-2011-1482, 2011.

20. ASM International. “Overview Report, Clean Coal Research Program Solid Oxide Fuel Cells Program FY2014 Peer Review Meeting,” April 2014. See http://www.netl.doe.gov/File%20Library/Research/Coal/Peer%20Reviews/2014/SOFC-FY2014-Peer-Review-Overview-Report_Final.pdf

21. Kaneko, S. “Solid Oxide Fuel Cell – Gas Turbine – Steam Tur-bine: Triple Combined Cycle.” Presentation at EPRI CoalFleet for Tomorrow Workshop, Indianapolis, June 2013.

TRL Description

TRL1: Exploratory Research Exploratory research transitioning basic science into laboratory application.

TRL2: Concepts Formulated Technology concepts and/or application formulated.

TRL3: Proof of Concept Validated Proof of concept validation.

TRL4: Subsystem Validation Subsystem or component validation in laboratory environment to simulate service conditions.

TRL5: System Validated Early system validation demonstrated in laboratory or limited field application.

TRL6: Early Demonstration Early field demonstration and system refinements completed.

TRL7: Demonstration Complete system demonstration in an operational environment.

TRL8: Early Commercial Deployment Early commercial deployment (Serial Nos. 1, 2, etc.).

TRL9: Commercialization Wide-scale commercial deployment.

Technology Readiness Levels (TRLs)TRLs are a useful mechanism for estimating where technology develop-ment projects are in their maturation and for defining and prioritizing next steps toward commercialization. EPRI uses the TRL defini-tions shown at right.

Appendix

http://www.epa.gov/airquality/cpp/cps-final-rule.pdf

http://www.epa.gov/airquality/cpp/cps-final-rule.pdf

http://www.netl.doe.gov/File%20Library/Research/Coal/Peer%20Reviews/2014/SOFC-FY2014-Peer-Review-Overview-Report_Final.pdf



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