Can Future Coal Power Plants Meet CO 2 Emission Standards Without Carbon Capture & Storage? October 2015

Transcription

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

2 Executive Summary The U.S. Environmental Protection Agency (EPA) released its new source performance standard (NSPS) on August 3, 2015, requiring new coal power plants in the United States to emit no more than 636 kg (1400 lb) of carbon dioxide ( ) per megawatt-hour (MWh) of gross power produced. Current state-of-the-art coal-fired plants, based on operations at ultrasupercritical (USC) steam conditions above 593 C (1100 F), emit approximately 800 kg (1760 lb) /MWh. To reduce 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 emissions from new coal-fired plants. Current CCS technologies and anticipated near-term commercial offerings will not only increase capital costs but also impose significant performance penalties, challenging the competitiveness of new coal generation. Many locations worldwide lack suitable geology for 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 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 summarized below and indicated in the figure at right: Even with steam temperatures exceeding 800 C (1500 F) some 200 C (360 F) higher than those currently achievable USC coal plants based on the conventional Rankine steam-electric cycle alone are not capable of meeting the standard. USC plants used in high-efficiency combined heat-and-power applications are capable of meeting the standard but only at sites with thermal hosts capable of using large volumes of steam. Gasifying coal then firing the synthesis gas in a conventional combined-cycle configuration can meet the standard but only for certain types of gasifiers, and only when the integrated plant is fueled by high-quality coal. Assuming further technological progress, coal gasification provides multiple pathways for achieving the standard, including gasifiers integrated with solid oxide fuel cells; with combinedcycle plants having firing temperatures for the combustion turbine approaching 1700 C (3100 F); or with novel cycle designs. EPA Standard Power producers interested in new coal plants could explore potential thermal hosts for cogeneration projects or the economics of gasifying and firing high-quality coal. Greater public-private investment in research and development (R&D) is needed to accelerate commercialization of gasification-based cycles and component technologies. Table of Contents Coal Technologies Advanced Ultrasupercritical (USC) Steam Plant Integrated Gasification Combined-Cycle (IGCC) Plant Advanced USC Plant % Steam Utilization USC Plant + 14% Steam Utilization IGCC Plant + High-Quality Coal Integrated Gasification Supercritical Brayton Cycle Plant Integrated Gasification Fuel Cell (IGFC) Plant Advanced USC Plant + 25% Steam Utilization IGCC Plant 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 Emission Intensity, kg/mwh (gross) Introduction Worldwide Carbon Standards... 3 Carbon Management Challenges... 4 Rankine Cycle Plants with Higher Steam Temperatures... 5 Combined Heat and Power Applications... 7 Coal Gasification Integrated with Combined Cycles Coal Gasification Integrated with Supercritical Cycles...11 Coal Gasification Integrated with Solid Oxide Fuel Cells Coal Gasification Integrated with Triple Cycles Conclusions & Next Steps References Appendix: Technology Readiness Levels Low-Carbon Coal Technology Assessment 2 October 2015

3 Introduction U.S. EPA s NSPS for greenhouse gas emissions from power plants 1 specifies the following limits under Section 111 of the Clean Air Act: Coal power plants: 636 kg /MWh (1400 lb/mwh) of gross power output, rolling 12-month average. Natural gas combustion turbine power plants: 454 kg /MWh (1000 lb/ MWh) of gross power output or 468 kg /MWh (1030 lb/mwh) of net power output, 12-month average. According to EPA, electricity generation represents the single largest U.S. source of emissions. Fossil power plants accounted 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 addressed through EPA s Clean Power Plan. b From a regulatory perspective, the EPA standard s basis on gross power output, Table 1 - Recent Emission Standards for New Coal Plants Country or State United States California Maine Washington New York United Kingdom Canada China Standard /MWh 636 kg (1400 lb) gross 500 kg (1100 lb) net 500 kg (1100 lb) net 500 kg (1100 lb) net 420 kg (925 lb) net 450 kg (992 lb) net 420 kg (925 lb) net 763 kg (1679 lb) net 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: P gross = P net + P aux (1) Where P gross = total amount of power produced at the generator terminals; P aux = internal (or auxiliary) power consumed within the plant to operate pumps, motors, fans, and other equipment; and P net = amount of power that is shipped to the grid. State-of-the-art coal power plants operate at USC steam conditions to increase P gross per fuel input, but they are not capable of meeting EPA s standard. For example, the 600-MW John W. Turk, Jr. Power Plant located in southwestern Arkansas and majority-owned by Southwestern Electric Power Company, a subsidiary of American Electric Power (AEP) is the first USC plant built in the United States, with both main and reheat steam temperatures exceeding 593 C (1100 F). Based on monthly data filed with the U.S. Department of Energy (DOE), the Turk plant s average emission rate was 823 kg/mwh gross (1811 lb/ MWh) during 2013 and 802 kg/mwh gross (1765 lb/mwh) during New natural gas plants integrating a combustion turbine with a heat-recovery steam generator (HRSG) should be able to meet the relevant U.S. emission standard of 454 kg/mwh gross (1000 lb/mwh) without additional controls. By EPRI s estimate, state-of-the-art combined-cycle gas plants have a emission rate of about 370 kg/ MWh (814 lb/mwh) on a net output basis, 2 well below the U.S. limit. ( ) 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 achieving a emission rate at or below 636 kg/ MWh gross (1400 lb/mwh). 1 EPA suggests that the standard could also be met by cofiring natural gas at coal plants. This white paper focuses on coal-only technology options. It introduces other emission standards for coal plants, identifies key challenges associated with CCS deployment, and provides detailed discussion of whether future coal-based power plants could achieve standards without CCS. Worldwide Carbon Standards In the United States and around the world, governments have established or proposed 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 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 stringency relative to EPA s limit: Output-based emissions are not only capped at a lower level but also must be calculated after subtracting 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 a See b See Low-Carbon Coal Technology Assessment 3 October 2015

4 Turk Power Plant in Arkansas: First U.S. plant operating at ultrasupercritical steam conditions (Credit: AEP) about 5% less 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 limit of 420 kg/mwh net (925 lb/mwh) and an input-based 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 standard of 450 kg/mwh net (992 lb/mwh) for new fossil generation, which will apply until In 2012, Canada passed a standard for coal-fired power plants limiting the annual average emission rate to 420 kg/mwh (925 lb/mwh) based on net power output, plus the energy used for compression in a CCS system. The Canadian standard applies to new units those that begin producing power commercially after July 1, 2015 and also to old units, generally defined as having reached an age of 50 years since starting to produce electricity commercially. China s Action Plan of Upgrade and Renovation of Coal Power for Energy Conservation and Emission Reduction, issued in 2014, takes a different approach. The standard is based on net power output, c but the 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 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 bituminous 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 1000-MW power plants is equivalent to a 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 emissions cannot be met solely by building an efficient coal power plant using current state-of-theart USC technology. To achieve EPA s limit, the conventional wisdom is that more than 20% of a new U.S. coal plant s emissions would have to be captured for longterm sequestration. Available CCS options pose significant challenges and limitations (see box, p. 9). Carbon capture with underground storage has been deemed by EPA as the best system of emission reduction, but applications are constrained by technology, policy, and market factors. Power plant developers c Professor Jianxiong Mao, Tsinghua University, personal communication, April d China 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. Low-Carbon Coal Technology Assessment 4 October 2015

5 evaluating possible investments are reluctant to consider new coal generation due to uncertainty, the cost of capture, and the difficulty in finding a suitable storage location. Some industry executives are beginning to wonder if an easier path to regulatory compliance might be found through advanced coal technology. The answer is clear: Without CCS, a limit of 636 kg/ MWh (1400 lb/mwh) or lower can only be achieved by increasing the thermal efficiency of the energy conversion processes involved in generating electricity from coal a challenge more easily stated than accomplished. This is because the gross emission intensity of a power plant without capture is directly proportional to its gross heat rate: m CO2 HR g 44 = x X c x kw gross H 12 Where (2) m CO2 = mass flow rate of emitted in kg/h or lb/h; kw gross = gross power output in kw; HR g = gross heat rate in kj/kwh or Btu/ kwh; H c = higher heating value (HHV) of the coal in kj/kg or Btu/lb; X c = mass fraction of carbon in coal; and 44/12 = ratio between molecular weights of 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 bituminous 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 emission intensities of 802 kg/mwh (1765 lb/ Emission Intensity, per Gross Power Output lb/mwh % 45% 50% 55% 60% 65% 70% 75% Figure 1 Relationship between emission intensity and gross thermal efficiency for a subbituminous coal power plant MWh) and 734 kg/mwh (1614 lb/mwh), respectively. Burning high-quality coal yields a lower heat rate and, in turn, lower emission 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 efficiency of approximately 51% (HHV basis), 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 technology options for meeting EPA s standard while firing PRB coal, representative of widely available lower-rank fuels. Figure 1 plots the approximate relationship between emission intensity and thermal efficiency (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 increases in the gross thermal efficiency of coal generation will be required to achieve a emission intensity of 636 kg/mwh (1400 lb/kwh) or lower without CCS. Gross Thermal Efficiency, HHV Basis Rankine Cycle Plants with Higher Steam Temperatures The 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 engine) dictate that efficiency can be improved by 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. Ambient conditions, along with the efficacy of the 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 modest potential for gross thermal efficiency gains. 3 ( ) Emission Intensity, per Gross Power Output kg/mwh Low-Carbon Coal Technology Assessment 5 October 2015

6 Temperature, F Stress, MPa Average Temperature for Rupture in 100,000 Hours, º F CCA 617 Eddystone 1 Philo Cr Creep-Strength- Enhanced Ferritic Steels (Gr. 91, 92, 122) Standard 617 Inconel 740 Advanced Austenitic Alloys (Super 304H, 347HFG, NF709, etc.) Haynes 282 Nickel-Based Alloys Haynes Average Temperature for Rupture in 100,000 Hours, º C Figure 3 Data showing the 100,000-hour rupture strength of various classes of metals versus temperature 4 Year Turk 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 Temperature, C Stress, ksi (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 ferriticbased steels. Since 2001, a DOE-funded R&D consortium has been pursuing advanced materials for coal-fired boilers and steam turbines, with EPRI serving as the technical lead. 4 ( ) Figure 3 shows that all metals lose strength as temperature increases. A typical stress encountered by boiler steam tubing is 100 MPa. The ability of ferritic steels to withstand that stress level for 100,000 hours without rupturing ends at temperatures exceeding C ( F). Indeed, materials exposed to 650 C (1200 F) steam at Eddystone experienced 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 thermal efficiency of the Rankine cycle. 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 allowing steam temperatures to rise to 760 C (1400 F). 4 That would allow an increase in gross thermal efficiency of at least 10%, from the current ~41% for USC plants to ~45% for next-generation advanced USC plants. Boosting steam turbine inlet temperature creates opportunity for more significant increases in efficiency. Figure 2 shows the history 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 Validation testing of key components under realistic advanced USC conditions has brought this higher-efficiency generation option to TRL5 on EPRI s technol- Low-Carbon Coal Technology Assessment 6 October 2015

7 ogy readiness level (TRL) scale, which is illustrated in Figure 4 and described in the Appendix on p. 15. Would the significant increase in efficiency be sufficient to meet EPA s standard? Figure 5 shows that it would not, based on results from a series of engineering evaluations EPRI has carried out on current and possible future USC power plant designs. 6,7,8 ( , , ) The plot shows that the emission rate ranges from 789 kg/mwh gross (1736 lb/mwh) to 715 kg/mwh gross (1573 lb/mwh) depending on steam temperature and pressure, other design variables, and fuel quality. The low end of the range represents approximately a 10% decrease in emission intensity from today s USC plants, far from the ~22% reduction that the EPA standard would require. Deploying advanced Rankine cycles would, however, significantly decrease the amount of 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 temperatures greater than 760 C (1400 F). Using commercial software, EPRI has carried out calculations based on thermodynamic Proof of Concept Validated Concepts Formulated Subsystem Validated Exploratory Research TRL 2 TRL 3 TRL 1 TRL 4 System Validated TRL 5 Technology Readiness Levels TRL 6 Early Demonstration Figure 4 - EPRI s Technology Readiness Levels TRL 7 TRL 9 TRL 8 Demonstration Early Commercial Deployment Commercialization Emissions, kg/mwh, gross BAR/593C/621C 276BAR/593C/616C BAR/649C/671C 276BAR/704C/727C BAR/680C/700C 276BAR/760C/760C BAR/680C/700C/700C BAR/593C/621C + High-Quality Coal % 40% 45% 50% 55% 60% 65% 70% 75% 80% Figure 5 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 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 temperatures around 1125 C (2050 F). This is well beyond current materials technology. Combined Heat and Power Applications Another way to increase the thermal efficiency of pulverized coal power plants is to utilize the input fuel s energy to produce both electric power and useful heat. Combined heat and power (CHP) or cogeneration (cogen) plants as they are frequently called in Europe and the United States, respectively can approach very high utilization 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 Net Thermal Efficiency, HHV Basis USC central heating districts for commercial buildings, large hotels, hospitals, and university 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, according to the following formula: P gross + Where = [(Pe ST + Pe CT + Pe IE - Pe FW ) (Pt HR + Pt IE + Pt PS ) Emissions, lb/mwh, gross / T ] (3) P gross = Gross energy output of affected facility in MWh; Pe ST = Electric energy output plus mechanical energy output (if any) of steam turbine(s) (ST) in MWh; Pe CT = Electric energy output plus mechanical energy output (if any) of combustion turbine(s) (CT) in MWh; Pe IE = Electric energy output plus mechanical energy output (if any) of affected facility s integrated equipment (IE) Low-Carbon Coal Technology Assessment 7 October 2015

8 Emissions, kg/mwh, gross BAR/593C/621C + 14% Steam Extraction BAR/760C/760C % Steam Extraction BAR/760C/760C + 25% Steam Extraction BAR/760C/760C + 50% Steam Extraction % 40% 45% 50% 55% 60% 65% 70% 75% 80% Net Thermal Efficiency, HHV Basis USC USC + CHP 1760 Emissions, lb/mwh, gross P gross = Pe ST Pe FW / T + (Q m x H / 3.6 x10 9 ) (5) To assess the 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 crossover between the intermediate- and lowpressure turbine sections. Figure 6 emission intensities of CHP plants based on USC technology with various levels of steam extraction to a thermal host that provides electricity or mechanical energy to the affected facility or auxiliary equipment in MWh; Pe FW = 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 facilities and to 0.95 only for a facility where at least 20% of P gross consists of electric or direct mechanical output on an annual basis and 20% of P gross consists of useful thermal energy output on a rolling 3-year basis; Pt HR = Hourly useful thermal energy output, measured relative to standard ISO conditions, from heat recovery (HR) for applications other than steam generation or performance enhancement of the affected facility in MWh; Pt IE = Useful thermal energy output relative to ISO conditions from any integrated equipment that provides thermal energy to the affected facility or auxiliary equipment in MWh; and Pt PS = Useful thermal energy output of steam, measured relative to ISO conditions, that is used for applications that do not generate additional electricity, produce mechanical energy output, or enhance the performance of the affected facility. The term Pt PS is calculated in MWh as Pt PS Where Q m x H = 3.6 x 10 9 (4) Q m = 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 10 9 = Conversion factor in J/MWh (3.413 x 10 6 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: 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 technology 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 approximately 150 MW about 50 kg/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 achieving a emission intensity of 636 kg/ MWh (1400 lb/mwh) or lower. Low-Carbon Coal Technology Assessment 8 October 2015

9 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 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 from flue gas using amine-based processes that impose a parasitic loss of ~20% on typical coal-fired plants. Compression of captured, concentrated 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. Capture processes with game-changing potential are being pursued by EPRI, but these early-stage innovations are at least a decade away from commercialization. 9 ( ) 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. 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 is limited because markets are small compared to the scale of emissions, and most direct utilization options do not provide long-term sequestration. Converting into a more useful chemical form requires many times the amount of energy produced by combustion. Methods such as reacting captured with minerals to produce limestone have been shown to be feasible but impractical at present. 10 Storing captured carbon in the ocean at depths and temperatures below which the 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 other formations potentially amenable to 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 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 Korea appear to lack on-shore locations with suitable geology for long-term 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-billiondollar projects. Also, important institutional obstacles exist. For example, environmental, health, and safety concerns have created political 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 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) Low-Carbon Coal Technology Assessment 9 October 2015

10 Coal Gasification Integrated with Combined Cycles Gasifying coal to produce a synthesis gas (syngas) opens up additional potential pathways for meeting emission limits without CCS. Syngas, consisting predominantly of carbon monoxide (CO) and gaseous hydrogen (H 2 ) fuel, can be turned into electricity by many methods. One is through a combined-cycle plant, like today s workhorse natural gas generators, which offer gross thermal efficiency of 50-54% on an HHV basis (typically, their efficiency is reported at 55-60% on an LHV basis). A simplified process diagram of an integrated 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. Contaminants, 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 Emissions, kg/mwh, gross 800 IGCC deployment continues, placing the technology at TRL8. State-of-the-art IGCC units have thermal efficiencies based on net power output that are similar to those of state-of-the-art, standalone Rankine cycle coal power plants. However, the auxiliary power consumption of IGCCs is greater an important consideration when gross emission intensity is the parameter of merit. EPRI has conducted engineering and performance analysis studies of several IGCC plant configurations. 13,14 ( , ) As indicated in Figure 8, IGCC plants having net thermal efficiencies comparable to USC plants and operating on the same sub-bituminous coal offer significantly lower gross 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 efficiency to the point that emissions would fall just below EPA s limit at 627 kg/ MWh (1380 lb/mwh) Siemens/2XGE7FB E-Gas/GE7FB Shell/3XGE7FB Shell/3XGE7FB + High-Quality Coal Shell C Combustion Turbine % 40% 45% 50% 55% 60% 65% 70% 75% 80% USC Net Thermal Efficiency, HHV Basis USC + CHP IGCC IGCC + HTCT Figure 8 emission intensities of state-of-the-art IGCCs and a future IGCC plant with a highertemperature combustion turbine 1760 Emissions, lb/mwh, gross GAS CLEANUP AIR SYNGAS COOLER BURNER GASIFIER COAL O 2 HRSG COND Figure 7 Simplified process diagram of an IGCC plant STACK While existing IGCC technology could meet EPA s standard under certain conditions, more stringent limits in the UK, Canada, and some U.S. states could not be achieved. IGCC efficiency gains can be realized 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 ( ) If that holds true for the PRB coal Shell case shown in Figure 8, then the emissions intensity of an IGCC plant with a higher-temperature combustion turbine (HTCT) would be approximately 567 kg/mwh (1248 lb/ MWh) well below EPA s standard. Japan has a national R&D program pursuing a combustion turbine with 1700 C (3100 F) firing temperature. The focus is on advancing the necessary materials technology 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- Low-Carbon Coal Technology Assessment 10 October 2015

11 gine used in the F-35 Joint Strike Fighter operates at 1982 C (3600 F). 17 The technical feasibility of a firing temperature approaching 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 Brayton Cycles Closed Brayton cycles using supercritical (S ) as the working fluid are being investigated by several organizations as a way to increase the thermal efficiency of advanced nuclear, solar, and fossil power plants, relative to designs based on the Rankine 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 S 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 venting (b). In both cases, oxygen reacts with syngas in the burner. S 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, as indicated by the greenshaded 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. The ratio of recycled 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, 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, equal to the amount formed by combusting the syngas must be bled off from the flow. As shown in Figure 9(a), this 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 being compressed, the bled 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 findings from an analysis of various syngas-fed oxy-fired S Brayton plant designs with 100% CCS. 18 ( ) The configuration illustrated in Figure 9(a) offers Emissions, kg/mwh, gross 800 (a) TO STORAGE Figure 9 Simplified process diagram of a coal gasifier integrated with a semi-closed oxy-fired S Brayton cycle and (a) CCS or (b) a letdown turbine venting to the atmosphere more than a 25% increase in net thermal efficiency relative to state-of-the-art IGCC plants with 90% CCS. For the vented S cycle illustrated in Figure 9(b), net thermal efficiency is estimated to be even higher, at 42% (HHV basis), compared with 40.5% for the S cycle with CCS. The emission intensity of the vented process is 603 kg/mwh (1326 lb/mwh), below the EPA target as illustrated in Figure Oxy + Venting % 40% 45% 50% 55% 60% 65% 70% 75% 80% Net Thermal Efficiency, HHV Basis USC USC + CHP IGCC IGCC + HTCT IG + S Figure 10 emission intensity of the S Brayton gasification process with venting (b) GAS CLEANUP VENTED PUMP WATER GASIFIER COAL OXY RECUPERATOR COOLER BURNER AIR SEPARATION UNIT HIGH- PRESSURE 1760 Emissions, lb/mwh, gross Low-Carbon Coal Technology Assessment 11 October 2015

12 Coal Gasification Integrated with Solid Oxide Fuel Cells Fuel cells have long held the promise of higher-efficiency power generation based on natural 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 oxide 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 but one in which the chemical ingredients 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 Emissions, kg/mwh, gross 800 air into the cathode side of the cell. This enables an electrochemical reaction that produces 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 remaining CO and H 2 are mixed with hot air leaving the cathode and then combusted in a burner. The HRSG applies the combustion 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 compressor 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 different types of gasifiers: a conventional gasifier producing syngas with 6% methane (CH 4 ) by volume and a catalytic gasifier producing 750 Atmospheric Pressure SOFC Catalytic Gasifier + Atmospheric Pressure SOFC Pressurized SOFC Catalytic Gasifier + Pressurized SOFC % 40% 45% 50% 55% 60% 65% 70% 75% 80% Net Thermal Efficiency, HHV Basis USC USC + CHP IGCC IGCC + HTCT IG + S IGFC 1760 Emissions, lb/mwh, gross AIR GAS CLEANUP SYNGAS COOLER INVERTER SOFC GASIFIER BURNER COAL O2 HRSG COND Figure 11 Simplified process diagram of an IGFC power plant with pressurized SOFC STACK enriched syngas with 30% CH 4 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 pressure. More stringent standards could be met by using a pressurized SOFC or catalytic gasifier. An IGFC plant design operating on CH 4 -enriched syngas and at elevated pressure would have a emission intensity of 430 kg/mwh (946 lb/mwh). IGFC technology is at TRL4, largely because 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 Figure 12 emission intensities of several IGFC cycles Low-Carbon Coal Technology Assessment 12 October 2015

13 Coal Gasification Integrated with Triple Cycles GAS CLEANUP SYNGAS COOLER GASIFIER University of Tokyo professor Dr. Shozo Kaneko, among others, has promoted the concept of integrating SOFCs with conventional 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 triplecycle (IGTC) plant is shown in Figure 13. The potential thermal efficiency advantage of IGTC over IGFC designs is that hotter turbine inlet temperatures can be achieved by having the SOFC feed a combustion turbine. Emissions, kg/mwh, gross 800 Figure 14 emission intensity of IGTC design Figure 13 Simplified process diagram of an IGTC plant 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 efficiency of greater than 51% (HHV basis) and emission intensity of approximately 527 kg/mwh gross (1159 lb/mwh), sufficient to achieve the EPA standard. Room for improvement in IGTC performance to achieve even lower limits appears to exist through design optimization and perhaps eventually through the achievement of a 1700 C (3100 F) turbine firing temperature. SOFC technology remains the limiting factor. Figure 14 suggests that the triple-cycle design has a higher emission intensity than the IGFC plant with a pressurized SOFC. However, this is an artifact of both Pressurized SOFC C Combustion Turbine % 40% 45% 50% 55% 60% 65% 70% 75% 80% Net Thermal Efficiency, HHV Basis USC USC + CHP IGCC IGCC + HTCT IG + S IGFC INVERTER SOFC 1760 IGTC Emissions, lb/mwh, gross COAL O2 HRSG COND STACK 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, IGTC plants are expected to be better performers relative to emission standards based on net power output. Conclusions & Next Steps Yes, technology has been identified that would enable new coal power plants to operate so efficiently that a emission 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 commercially available, economically viable, and suitable for broad deployment. Low-Carbon Coal Technology Assessment 13 October 2015

14 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 intermediate-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 gasification integrated with higher-temperature combustion turbines, fuel cell technologies, or novel generation cycles opens up multiple possible future pathways for achieving emission intensities well below EPA s limit, but without partial CCS. While not investigated in EPRI s recent study, applying gasificationbased technologies in cogeneration mode could result in even lower emissions, assuming suitable thermal hosts could be found. To help expand the available options for generating electricity with coal while achieving 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 S 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 Table 2 - Technologies Considered in EPRI s Analysis, Relative to EPA s Standard Technology Details Emission Intensity, kg/mwh, gross Efficiency, % USC 290BAR/593C/621C USC 276BAR/593C/616C USC 276BAR/649C/671C USC 276BAR/704C/727C USC 290BAR/593C/621C + High-Quality Coal USC 352BAR/680C/700C USC 276BAR/760C/760C USC 352BAR/680C/700C/700C USC+CHP 290BAR/593C/621C + 14% Steam Extraction USC+CHP 276BAR/760C/760C % Steam Extraction USC+CHP 276BAR/760C/760C + 25% Steam Extraction USC+CHP 276BAR/760C/760C + 50% Steam Extraction IGCC Siemens/2XGE7FB IGCC E-Gas/GE7FB IGCC Shell/3XGE7FB IGCC Shell/3XGE7FB + High-Quality Coal IGCC + HTCT Shell C Combustion Turbine IG+S Oxy + Venting IGFC Atmospheric Pressure SOFC IGFC Catalytic Gasifier + Atmospheric Pressure SOFC IGFC Pressurized SOFC IGFC Catalytic Gasifier + Pressurized SOFC IGTC Pressurized SOFC C Combustion Turbine are facing CCS deployment. In addition, a study of existing and potential future thermal hosts capable of accommodating large volumes of steam in the United States and other countries is recommended. This would help determine the extent to which the CHP option may be available for building new coal-fired power plants and achieving emission standards without the need for partial CCS. Low-Carbon Coal Technology Assessment 14 October 2015

15 References 1. 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, See 2. Program on Technology Innovation: Integrated Generation Technology Options EPRI, Palo Alto, CA: 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, EPRI, Palo Alto, CA: Progress Report on Advanced Ultra-Supercritical Technology Development. EPRI, Palo Alto, CA: Silvestri, G.J. Jr. Eddystone Station 325 MW Generating Unit 1 A Brief History. ASME Mechanical Engineering Heritage Site Report H226, An Engineering and Economic Assessment of Post-Combustion Capture for 1100 F Ultra-Supercritical Pulverized Coal Power Plant Applications. EPRI, Palo Alto, CA: Engineering and Economic Evaluation of 1300 F Series Ultra- Supercritical Pulverized Coal Power Plants: Phase 1. EPRI, Palo Alto, CA: Advanced Ultra-Supercritical Steam Cycle Optimization. EPRI, Palo Alto, CA: Program on Technology Innovation: Carbon Capture. EPRI, Palo Alto, CA: International Energy Agency Greenhouse Gas (IEAGHG) R&D Programme. Mineralisation Carbonation and Enhanced Weathering. IEAGHG Report 2013/TR6, July Appendix 11. Intergovernmental Panel on Climate Change (IPCC). Special Report on Carbon Dioxide Capture and Storage. Prepared by IPCC Working Group III, Fontaine, P., and Naessen, P. Fresh air firing: HRSG guarantees steam supplies to French refinery, Cogeneration & On-site Power, Vol 7, No. 5, IGCC Design Considerations for Capture. EPRI, Palo Alto, CA: Engineering and Economic Evaluations of Integrated-Gasification Combined-Cycle Plant Designs with Carbon Dioxide Capture. EPRI, Palo Alto, CA: CoalFleet Integrated Gasification Combined Cycle Research and Development Roadmap: 2011 Update. EPRI, Palo Alto, CA: Tsukagoshi, K., et al. Operating Status of Uprating Gas Turbines and Future Trend of Gas Turbine Development. Mitsubishi Heavy Industries Technical Review, Vol. 44, No. 4, Langston, L. Fahrenheit 3,600, Mech. Engineering, April Performance and Economic Evaluation of Supercritical Power Cycle Coal Gasification Plant. EPRI, Palo Alto, CA: U.S. DOE. Analysis of Integrated Gasification Fuel Cell Plant Configurations. DOE/NETL , ASM International. Overview Report, Clean Coal Research Program Solid Oxide Fuel Cells Program FY2014 Peer Review Meeting, April See Library/Research/Coal/Peer%20Reviews/2014/SOFC-FY2014- Peer-Review-Overview-Report_Final.pdf 21. Kaneko, S. Solid Oxide Fuel Cell Gas Turbine Steam Turbine: Triple Combined Cycle. Presentation at EPRI CoalFleet for Tomorrow Workshop, Indianapolis, June Technology Readiness Levels (TRLs) TRLs are a useful mechanism for estimating where technology development projects are in their maturation and for defining and prioritizing next steps toward commercialization. EPRI uses the TRL definitions shown at right. TRL TRL1: Exploratory Research TRL2: Concepts Formulated TRL3: Proof of Concept Validated TRL4: Subsystem Validation TRL5: System Validated TRL6: Early Demonstration TRL7: Demonstration TRL8: Early Commercial Deployment TRL9: Commercialization Description Exploratory research transitioning basic science into laboratory application. Technology concepts and/or application formulated. Proof of concept validation. Subsystem or component validation in laboratory environment to simulate service conditions. Early system validation demonstrated in laboratory or limited field application. Early field demonstration and system refinements completed. Complete system demonstration in an operational environment. Early commercial deployment (Serial Nos. 1, 2, etc.). Wide-scale commercial deployment. Low-Carbon Coal Technology Assessment 15 October 2015