Advanced Coal Power Systems with CO 2. Capture: EPRI s CoalFleet for Tomorrow Vision

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1 A Summary of Technology Status and Research, Development, and Demonstrations

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3 Advanced Coal Power Systems with CO 2 EPRI s CoalFleet for Tomorrow Vision A Summary of Technology Status and Research, Development, and Demonstrations Interim Report, September 2008 EPRI Project Managers J. Parkes A. Maxson J. Wheeldon

4 DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM: (A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER S CIRCUMSTANCE; OR (B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT. ORGANIZATION(S) THAT PREPARED THIS DOCUMENT Electric Power Research Institute Bevilacqua-Knight, Inc. NOTE For more information, contact the EPRI Customer Assistance Center at or askepri@epri.com. Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc. Copyright 2008 Electric Power Research Institute, Inc. All rights reserved.

5 Citations This document was prepared by Electric Power Research Institute (EPRI) 3420 Hillview Avenue Palo Alto, CA Principal Investigators Neville Holt Andrew Maxson Jack Parkes Jeff Phillips Rob Trautz John Wheeldon Jeff Brehm (Editor) Bevilacqua-Knight, Inc Broadway, Suite 410 Oakland, CA Editors Richard Myhre Marian Stone Eric Worrell This document describes research sponsored by the Electric Power Research Institute. Its goal is to provide a primer on the status of the portfolio of gasification- and combustion-based advanced coal power technologies, and opportunities for increased efficiency, state-of-the-art emissions controls, and CO 2 capture and storage. This publication is a corporate document that should be cited in literature in the following manner:, EPRI, Palo Alto, CA: iii

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7 Product Description The Electric Power Research Institute (EPRI) has examined current and potential options for reducing greenhouse gas (GHG) emissions from the electric sector. EPRI s analysis shows a significant contribution from advanced coal power systems with carbon capture and storage (CCS) likely will be required to achieve economical GHG reductions. However, CCS technology is not yet commercially available. Results and Findings Proposed roadmaps for providing cost-effective and low-carbon advanced coal power for multiple technologies have been developed. Challenges and Objectives Increasing demand for cost-effective power in the face of ever more stringent environmental pressures is a significant challenge. Now, CO 2 concentrations in the atmosphere that could result in global climate change pose a new challenge. As climate change effects have become better understood, the need to limit anthropogenic emissions of CO 2 and other GHGs has become a familiar topic among policymakers and the public and ultimately may require substantial changes in the way power is produced. For coal, which is the largest producer of power in the world and emits CO 2 at high levels, the requirement to develop new technology and processes to combat CO 2 is a pressing need. The objective of this project is to outline the issues related to coal generation and carbon capture and storage, detail the current state of its technology, including pulverized coal, fluidized beds, oxycombustion, and IGCC, and discuss a plan by EPRI to develop and demonstrate advanced coal technologies. Applications, Values, and Use This document describes research sponsored by EPRI. Its goal is to provide a primer on the status of the portfolio of gasification- and combustion-based advanced coal power technologies, and opportunities for increased power generation efficiency, state-of-the-art emissions controls, and CO 2 capture and storage. EPRI Perspective A full portfolio of innovative technology approaches is needed to make substantial CO 2 emissions reductions, while minimizing economic impacts of reductions policies. A significant part of that portfolio is commercially viable CO 2 capture and storage for coal generation by EPRI has developed aggressive plans to achieve this goal, encompassing a series of large-scale demonstrations to validate new technology and processes. Approach In collaboration with other researchers, EPRI is pursuing critical-path activities to help ensure that multiple, competitive, advanced coal generation and CCS technologies become a commercial reality by The power industry is working with EPRI to launch major demonstrations of advanced coal and CCS technologies, the kinds of big steps urgently required for commercial readiness of CCS by The challenge lies in how to fast-track the development and deployment of technologies that could meet those goals.

8 EPRI s approach is to help develop and implement roadmaps for development and deployment of multiple advanced coal generation types and provide independent assessments of new technologies and processes to help accelerate their development and application. Keywords Carbon capture and storage (CCS) Coal CoalFleet for Tomorrow Greenhouse gas (GHG) Integrated gasification combined cycle (IGCC) Pulverized coal (PC) vi

9 Contents 1 Electricity Generation FOR A LOW-CARBON Future Satisfying the Demand for Affordable Electricity while Reducing CO 2 Emissions Modeling the Future: EPRI s PRISM and MERGE Studies Independent Studies Corroborate EPRI Findings Coal s Role in Global Power Generation RD&D to Prepare Coal Generation for a Low-Carbon Future The Promise of Advanced Coal Power Systems Building a Portfolio of Competitive Advanced Coal Technology Options Coal Properties Drive Generation Technology Selection and Plant Design The Importance of Early Deployment of Advanced Coal Technologies COMBUSTION-BASED SYSTEMS EXTENDING THE LIMITS OF A Mature Technology Pulverized Coal Commercial Status Environmental Controls The Promise of Near-Zero Emissions SO 2 Removal with Flue Gas Desulfurization Dual Strategies for NO X Control Technologies for Particulate Control Reducing Mercury Emissions Reducing CO 2 Emissions Through Increased Efficiency and Improved CO 2 Capture Processes Steps and Timeframe for USC PC Cost Reduction and Efficiency Gains Advanced Materials The Key to PC Efficiency Gains Ferritic/Martensitic Steels Austenitic Stainless Steels Nickel-Based Alloys Advanced Materials Research Post-Combustion Removal of CO 2 from Flue Gases Amine-Based Solvent Technologies Potential Alternatives to Amine-Based Solvent Technologies Oxy-Combustion for CO 2 Capture Circulating Fluidized-Bed Combustion Commercial Status Environmental Controls Efficiency Improvements and CO 2 Capture IGCC Technologies Transitioning to the commercial era Overview Commercial Status Emission Controls Sulfur Species Removal NO X Control Mercury and Trace Toxics Removal Particulate Removal vii

10 Steps and Timeframe for IGCC Capital Cost Reduction and Efficiency Gains Longer-Life Components for Improved Gasifier Availability Higher-Pressure Gasifiers Gas Turbines for Synthesis Gas Firing Supercritical Heat Recovery Steam Generators Liquid CO 2 -Coal Slurrying for Low-Rank Coals Ion Transport Membrane for Lower Cost, Energy-Efficient Oxygen Production CO 2 Capture for IGCC Units Hydrogen-Firing Gas Turbines New Gasifier Designs Better Suited for CO 2 Capture CO 2 Compression, Transportation, AND Storage CO 2 Purification, Drying, and Compression CO 2 Transportation CO 2 -Based Enhanced Oil and Gas Recovery Long-Term Geologic Storage Depleted Oil and Gas Reservoirs Deep Saline Formations Unminable Coal Beds Regulatory Oversight for CCS Select RD&D Programs for Geologic Carbon Sequestration IEA GHG Regional Carbon Sequestration Partnerships Implementing the Advanced Coal RD&D Roadmap EPRI Steers a Course to Advanced Coal-Based Generation with CCS Advanced Combustion with Post-Combustion Capture UltraGen Post-Combustion CO 2 Capture Scale-Up Demonstrations Oxy-Combustion for PC and CFBC IGCC with CO 2 Capture and Storage Scale-Up and Integration of ITM Oxygen Production The Resources Necessary for Success EPRI Helps Shape the Future viii

11 List of Figures Figure 1-1 Figure 1-2 Figure 1-3 Figure 1-4 Figure 2-1 Electricity Generation by Fuel for Select Countries and Continents (2004, with Projections of Growth Through 2020) EPRI s PRISM Analysis Illustrates a Path to Lowering U.S. Electricity-Related CO 2 Emissions by 30% by EPRI s MERGE Analysis Shows the Value of Employing a Full Portfolio of CO 2 -Reduction Technologies for the U.S. Electric Sector High-Efficiency Advanced Pulverized Coal Power Plants Substantially Reduce Fuel Costs and CO 2 and Other Emissions Development Status of Major Advanced Coal and CO 2 Capture and Storage Technologies Figure 3-1 Photo of MidAmerican s Walter Scott, Jr. Energy Center Unit 4 SCPC Plant Figure 3-2 Figure 3-3 RD&D Path for USC PC Power Plants with 90% CO 2 Capture (Upturning Arrows Refer to Right Axis and Downturning Arrows to the Left Axis) PC Net Power Output, Capital Cost, and COE with and without Capture (Powder River Basin Coal) Figure 3-4 Schematic of Oxy-Combustion Process Figure 4-1 Aerial View of Tampa Electric Company s 250 MW Polk Unit 1 IGCC Plant Figure 4-2 Block Flow Diagram of an IGCC Power Plant Figure 4-3 RD&D Path for IGCC Power with 90% CO 2 Capture (Upturning Arrows Refer to Right Axis and Downturning Arrows to the Left Axis) Figure 4-4 Net Power Output for IGCC with and without Capture (Illinois #6 Coal) Figure 5-1 Injection of CO 2 for Enhanced Oil Recovery (EOR) with Some Storage of Retained CO Figure 6-1 Steps in Technology Validation and Scale-Up Projects to Meet CURC-EPRI Roadmap Goals for Advanced Coal Technologies with CCS Figure 6-2 Design Parameters for EPRI s UltraGen III ix

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13 List of Tables Table 2-1 Progression of Coal Power Technology Development in the United States* Table 2-2 Advanced Coal Power Block Technologies Table 2-3 Typical Control Technologies for Air Emissions from Coal Power Plants Table 2-4 CO 2 Capture Technologies for Advanced Coal Power Plants Table 6-1 Performance Parameters for UltraGen I, II, and III xi

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15 List of Acronyms Acronym Meaning Acronym Meaning ACI activated carbon injection Hg mercury AEP American Electric Power H 2 S hydrogen sulfide AGR acid gas recovery HHV higher heating value ALWR advanced light water (nuclear) reactor HRSG heat recovery steam generator ASTM American Society for Testing and Materials IEA ASU air separation unit IGCC International Energy Agency integrated gasification combined cycle B&W Babcock & Wilcox ITM ion transport membrane CCS carbon or CO 2 capture and storage MDEA methyldiethanolamine CFBC circulating fluidized bed combustion NO X nitrogen oxides CO carbon monoxide NZE near-zero emissions CO 2 carbon dioxide PAC powdered activated carbon COE cost of electricity PC pulverized coal COS carbonyl sulfide PHEV plug-in hybrid vehicle CURC Coal Utilization Research Council PM particulate matter ECBM enhanced coal bed methane RD&D research, development, and demonstration EIA U.S. Energy Information Administration SCPC supercritical pulverized coal EOR enhanced oil recovery SCR selective catalytic reaction EPA U.S. Environmental Protection Agency SO 2 sulfur dioxide EPRI Electric Power Research Institute tpd tons per day ESP electrostatic precipitator UIC underground injection control FGD flue gas desulfurization USC ultra-supercritical GHG greenhouse gas xiii

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17 List of Units Acronym Meaning (Unit Type, System) Acronym Meaning (Unit Type, System) bara bar absolute (pressure, English) mega (M) 10 6 Btu British thermal unit (energy, English) micro (µ) 10 6 C degrees Celsius (temperature, SI) milli (m) 10 3 F degrees Fahrenheit (temperature, English) N Newton (force, SI) g gram (mass, SI) ppb parts per billion (concentration) giga (G) 10 9 ppm parts per million (concentration) J Joules (energy, SI) psi kilo (k) 10 3 psia pounds per square inch (pressure, English) pounds per square inch absolute (pressure, English) lb pound (mass, English) tons 2000 pounds (weight, English) m meter (length, SI) W Watt (power, SI) m 3 cubic meter (volume, SI) Wh Watt hours (energy, SI) xv

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19 Foreword Society demands viable solutions to global climate change that also minimize increases in energy prices and their economic impacts. The Electric Power Research Institute (EPRI) has examined current and potential options for reducing greenhouse gas (GHG) emissions from the electric sector and has concluded a full portfolio of innovative technology approaches, ranging from energy efficiency to clean generating technologies to plug-in hybrid vehicles (PHEV), will enable substantial emissions reductions while minimizing economic impacts of reductions policies. Moreover, implementation of the portfolio must start now 1. EPRI s analysis further shows a significant contribution from advanced coal power systems with carbon capture and storage (CCS) likely will be required to achieve economical GHG reductions. Also extremely important are efficiency-improving technologies that reduce emissions of all kinds, including CO 2. Such measures also can allow CO 2 reductions at existing plants that may not be able to retrofit CCS systems. However, CCS technology is not yet commercially available and requires public and private resources for its research, development, and demonstration (RD&D). Only CCS can reconcile the continued use of our enormous coal resources with the need to reduce CO 2 emissions, wrote Steven Specker, CEO of EPRI, in the Spring 2007 EPRI Journal. Other researchers have drawn similar conclusions. Their belief is exemplified by a quote from International Energy Agency (IEA) Executive Director Nobuo Tanaka: We would need to build at least 20 CCS demos by 2020, at a cost of ~$1.5 billion each. Such a construction program should be viewed as a litmus test of our seriousness towards combating climate change. 2 In collaboration with many other researchers, EPRI is pursuing critical-path activities to help ensure that multiple, competitive, advanced coal generation and CCS technologies become a commercial reality by The challenge lies in how to fast-track the development and deployment of technologies that could enable advanced coal power plants to meet society s affordable energy and environmental goals. For the last three years, the more than 60 member organizations within several EPRI programs in particular, the CoalFleet for Tomorrow group have examined in detail the technical and institutional barriers to advanced coal and CCS technologies, and have identified the critical RD&D pathways to overcome these barriers and achieve a set of competitive, commercially ready technology options. Many important development activities for advanced coal and CCS technologies already are under way, both collaboratively through EPRI and independently by multiple utilities and technology developers across the globe. Further, the power industry is working with EPRI to launch major demonstrations of advanced coal and CCS technologies. These are the kinds of big steps urgently required to meet society s need for commercial readiness of CCS by Despite these activities, there still is a need to accelerate the pace of RD&D and increase investment in advanced coal and CCS technologies to make them ready for commercial deployment. The steps to realizing CCS for coal power plants are understood and technically sound. The challenge lies in developing and deploying these new technologies before it is too late to reduce GHG emissions sufficiently to avert the projected consequences of global climate change. 1 The Power to Reduce CO 2 Emissions: the Full Portfolio, Discussion Paper by EPRI Energy Technology Assessment Center, EPRI, Palo Alto, CA: August 2007 ( 2 Enhancing Energy Resource Availability, Presented at the 11th International Energy Forum, Rome, 21 April 2008, xvii

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21 Electricity Generation for a Low-Carbon Future 1 Electricity Generation FOR A LOW-CARBON Future Electricity is the lifeblood of our modern world. Indeed, it is hard to find a single aspect of life that has not been transformed by electric power. Many advances in medicine, transportation, manufacturing, communications, and information technology were attainable because of electricity. In societies around the globe, electrification is a fundamental catalyst for economic growth and the means to improve living conditions. Around the world, electricity largely is produced from fossil fuels, and coal often is the predominant fuel choice (see Figure 1-1). In North America, Australia, and parts of Europe, Asia, and Africa, coal-fired power plants supply more than half of the electricity consumed. Coal has become the primary fuel for affordable and reliable electric power production because it is relatively easy to transport and use and because many countries have indigenous coal resources. In exploiting the benefits of electricity generated from coal and other fossil fuels, societies face many environmental quality challenges. During the last few decades, producers of coal-based electricity in North America, Europe, and parts of Asia have successfully responded to ever-more-stringent regulations to control emissions from coal plants (particulates, sulfur oxides, nitrogen oxides, and, more recently, mercury). Now, CO 2 concentrations in the atmosphere that could result in global climate change pose a new challenge. As climate change effects have become more apparent, the need to limit anthropogenic emissions of CO 2 and other GHGs has become a familiar topic among policymakers and the public. 9% 3% 19% 3% 33% 20% 5% 23% 19% 2% 20% 16% 18% 50% 20% USA Total generation: 3,975 TWh 17% electric demand growth by 2020 Coal Nuclear Gas Renewables/Hydro Other 16% 10% 3% 2%16% 69% Central/South America Total Generation: 882 TWh 54% electric demand growth by % OECD Europe Total generation: 3,250 TWh 6% electric demand growth by % 18% 25% 3% Africa Total Generation: 505 TWh 55% electric demand growth by 2020 Non-OECD Europe and Eurasia Total Generation: 615 TWh 37% electric demand growth by % 32% 20% 14% 2% 7% 2% 75% India Total Generation: 631 TWh 63% electric demand growth by % Russia Total Generation: 881 TWh 25% electric demand growth by % 0% 8% 0% 16% 1% 2% Australia Total Generation: 266 TWh 23% electric demand growth by % 79% China Total Generation: 2,080 TWh 89% electric demand growth by % Figure 1-1 Electricity Generation by Fuel for Select Countries and Continents (2004, with Projections of Growth Through 2020) 1 1 Data Source: U.S. Department of Energy, Energy Information Administration, International Energy Outlook

22 Electricity Generation for a Low-Carbon Future Satisfying the Demand for Affordable Electricity while Reducing CO 2 Emissions The challenge of reducing GHG emissions which likely will mandate substantial changes in the way we produce and consume power comes at a time when significantly more electricity is needed to meet demand growth throughout the world cost-effectively. By 2020, for example, the projected demand for electricity in the United States is approximately 17% higher than current levels (Figure 1-1); by 2030, it is projected to be as much as 30% higher. 2 Meeting this increased demand using existing generation would cause a significant rise in CO 2 emissions, increasing the risks associated with climate change. To reduce these risks, ways must be found to reduce the carbon intensity of the world s economies while still promoting productivity and maintaining the benefits of affordable electricity. Developing and deploying multiple GHG-reducing technologies is the best strategy for reducing risk. Termed the full portfolio by EPRI, it likely will include renewable energy resources, advanced light water reactor (ALWR) nuclear plants, distributed energy resources, PHEVs, and advanced coal power generation with CCS. CCS refers to processes that separate CO 2 from fuel or exhaust gases at industrial plants, which for the electric power sector is most notably coal-based plants, but also may include other fossil-fired plants. After separation, the captured CO 2 can be compressed and stored in deep underground formations capable of holding it in place for hundreds to potentially millions of years. Known as geologic sequestration, this approach for securely storing CO 2 prevents its release into the atmosphere. Lowering CO 2 emissions through a portfolio of technologies is essential because no single technology has clear-cut advantages in all circumstances. This can be seen today in the regional variations around the world, where power producers employ differing generation strategies to match local resources, needs, and markets. Projected Growth in Global Population and Electricity Consumption* The world s population is predicted to grow by 36% from 6.1 to 8.3 billion people from 2000 to The U.S. population also is forecast to grow over this period by an estimated 80 million people, or almost 30%.* World net electric power generation is projected to increase from 14,426 billion kwh in 2000 to 30,364 billion kwh in 2030 an increase of more than 110%.** The aggregate demand growth in emerging economy (i.e., non-oecd***) countries is forecast to be nearly as great as current world electricity use. * ** *** Organization for Economic Cooperation and Development. 2 Based on projections by U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook Ibid. 1-

23 Electricity Generation for a Low-Carbon Future Modeling the Future: EPRI s PRISM and MERGE Studies To examine the technical feasibility and potential economic impact of achieving large-scale CO 2 emissions reductions while meeting growth in U.S. electricity demand, EPRI developed two related analyses 3 : PRISM analysis, which determined the technical potential for reducing CO 2 emissions based on assumption of successful development and deployment of a full portfolio of advanced technologies. MERGE analysis, which modeled the economic value of deploying a full technology portfolio, and projected the least-cost combination of technologies needed to meet an economy-wide CO 2 emissions reduction requirement. The results of the PRISM study suggest that deployment of a full portfolio of advanced technologies can reduce U.S. electric sector CO 2 emissions by 2030 to a level below 1990 emissions. This would be about 45% below the U.S. Energy Information Administration s (EIA) revised 2008 base case projection for 2030, while meeting the projected increased demand for electricity. Figure 1-2 illustrates this result. The inset table lists the differences in technology performance and/or deployment levels between the EPRI and EIA base-case scenarios. As shown in Figure 1-2, substantial CO 2 emissions reductions require a balanced portfolio of technologies. CCS technologies applied to advanced coal-based power plants coming on-line after 2020 play a critical role in this portfolio U.S. Electric Sector CO 2 Emissions (million metric tons) EIA Base Case 2008 Efficiency Renewables Nuclear Generation Advanced Coal Generation CCS PHEV DER Technology EIA 2008 Reference Load Growth ~ +1.2%/yr 60 GWe by GWe by 2030 No Existing Plant Upgrades 40% New Plant Efficiency by None None < 0.1% of Baseload in 2030 Target Load Growth ~ +0.75%/yr 100 GWe by GWe by GWe Plant Upgrades 46% New Plant Efficiency by 2020; 49% in 2030 Widely Deployed After % of New Vehicle Sales by 2017; +2%/yr Thereafter 5% of Baseload in Figure 1-2 EPRI s PRISM Analysis Illustrates a Path to Lowering U.S. Electricity-Related CO 2 Emissions by 30% by 2030 Using the MERGE economic model, EPRI analyzed a CO 2 emissions constraint representative of anticipated reduction requirements described in major policy proposals. As shown in Figure 1-3, a limited portfolio scenario without advanced coal technologies and CCS (and without any expansion of nuclear power) results in wholesale electricity prices in 2050 of more than double the cost of a mix with the full portfolio of PRISM technologies. An additional result of the limited portfolio is a projected sharp rise 1-

24 Electricity Generation for a Low-Carbon Future in natural gas prices (due to higher demand from the electric sector) a double hit on households and businesses paying utility bills for both gas and electric service. In the case with the full portfolio, the U.S. gross domestic product cumulatively is roughly $1 trillion larger over the period (in present value terms measured in 2007 dollars) than in the limited portfolio case. A previous EPRI study based on real options principles (the technology equivalent of financial-market options contracts) produced a similar result. 4 Although EPRI s initial analyses focused solely on the United States, work currently under way on a global analysis is expected to show similar energy mix changes and significant economic impacts. Figure 1-3 EPRI s MERGE Analysis Shows the Value of Employing a Full Portfolio of CO 2 -Reduction Technologies for the U.S. Electric Sector EPRI s findings indicate that even with aggressive development and deployment of alternative energy sources, coal-based electricity generation will remain an important part of the power portfolio, especially in rapidly expanding economies like those of China and India. EPRI s PRISM and MERGE analyses highlight the urgent need to develop and deploy new energy technologies. Advanced coal technologies and CCS must be fully commercial by 2020 to meet the CO 2 reductions for 2030 shown in Figure 1-2 and must begin to be widely deployed by 2020 to achieve the 2050 market penetration shown in Figure 1-3. If these technologies are not developed to commercial readiness in the next years, their potential to help meet energy needs in a low-carbon future will be far less certain. Independent Studies Corroborate EPRI Findings An interdisciplinary study published in 2007 by the Massachusetts Institute of Technology examined the viability of coal power under scenarios in which mandated GHG reductions imposed an added cost on its use for power generation. 5 The report concluded that despite cost premiums for GHG controls, coal 4 Market-Based Valuation of Coal Generation and Coal R&D in the U.S. Electric Sector, EPRI, Palo Alto, CA: The Future of Coal: Options for a Carbon-Constrained World, Massachusetts Institute of Technology,

25 Electricity Generation for a Low-Carbon Future would continue to play a large and indispensable role in supplying electric power for a growing world population. The report further identified CCS as the critical enabling technology that would reduce CO 2 emissions significantly while also allowing coal to meet the world s pressing energy needs. The IEA also examined scenarios for the technical and economic potential of advanced coal technologies and CCS to contribute to GHG reductions. It concluded, a large abatement potential exists in the coming decades, notably by application of CCS. 6 Coal s Role in Global Power Generation Coal has played and continues to play a significant role in meeting global demand for energy services. Coal remains in wide use because it usually is a reliable and low-cost energy source, and because coal resources are abundant and broadly distributed geographically. Many countries view their indigenous coal resources as an essential element of their plans for national economic development and security. Coal also is relatively easy to mine, ship, and store. These qualities make coal-fired power plants important electricity price stabilizers and reliable producers, especially in electric systems using more price-volatile or intermittently available resources. If advanced coal technologies with CCS are not available, analysts suggest that pressure on natural gas supplies and prices may increase further. Worldwide, the most significant rise in coal consumption is in the rapidly developing economies of China, India, and other Asian nations. Although forecasts vary, IEA has estimated that China alone will commission about 600 GW of new coal-fired generating units between 2006 and 2030, more than doubling its coal-fired capacity. 7 Given the large investment in coal-based power plants around the world, analysts believe that many nations want to continue using coal for electricity generation for decades to come. Development and deployment of advanced coal technologies are crucial to fulfill the need for affordable energy while addressing environmental concerns. RD&D to Prepare Coal Generation for a Low-Carbon Future Technically, it is possible to incorporate equipment to capture CO 2 in all types of new coal-based power plants. Depending on available space and other considerations, such equipment also can be retrofitted to existing coal-fired plants. The drawback to adding CO 2 capture, beyond its added cost, is a reduction in plant output and efficiency. For this reason, research into less expensive, less energy-intensive, and more flexible capture technologies is the focus of major demonstration programs at EPRI and elsewhere. CO 2 capture and/or reduction is only part of the CCS picture. Important work is proceeding around the world to identify potential storage sites and capacities, verify predicted CO 2 behavior in target geologic formations, minimize or eliminate environmental impacts, and assess the cost and performance of monitoring instruments. Yet there still are only a few large-volume CO 2 storage demonstrations, and none to date involves integrated operation with a capture system at a power plant. Research organizations around the world point to such demonstrations as the crucial link to commercialization. In addition, geologic CO 2 storage requires resolution of many legal and regulatory issues. Some analysts believe these issues may prove to be the biggest obstacle to overall CCS commercialization. 6 Clean Coal Technologies for a Carbon-Constrained World, Profiles, IEA Clean Coal Centre: July PF 07-05; 7 Drivers of New Generation Development A Global Review, EPRI, Palo Alto, CA: 2008, Report

26 Electricity Generation for a Low-Carbon Future RD&D also is needed to improve the thermodynamic efficiency of coal power plants as a way to reduce CO 2 emissions. Increased thermodynamic efficiency reduces the amount of CO 2 generated per unit of plant output (see Figure 1-4), meaning that plants that are more efficient can use smaller, less-expensive CO 2 capture systems. Other emissions and equipment sizes are reduced as well. Materials development and testing to support higher efficiency designs is under way, to be followed by full-scale demonstrations. 9% Efficiency Gain = 20% CO 2 Reduction 20% reduction in CO 2 corresponds to similar reductions (per MWh) in fuel consumption, emissions, and water use (Bituminous coal, without CO 2 capture) Figure 1-4 High-Efficiency Advanced Pulverized Coal Power Plants Substantially Reduce Fuel Costs and CO 2 and Other Emissions 8 Economic analyses show that the dual strategy of improving efficiency and improving CO 2 capture system performance is the optimal path to competitive advanced coal power systems with CCS. In situations where new, highly efficient coal plants are replacing older coal units, the emissions reduction benefit even without the use of CO 2 capture equipment could be sufficient to meet near-term GHG emission reduction goals. Ongoing RD&D for air quality control systems has improved the environmental performance of coalbased plants to the point that near-zero emission (NZE) levels for traditional coal pollutants now are seen as achievable (yet still to be demonstrated) targets. In addition, because several CO 2 capture technologies require inlet flue gas with extremely low levels of SO 2 and NO X, the need for technologies that reach NZE levels has become linked to commercializing post-combustion CO 2 capture processes. 8 Efficiencies shown are for pulverized coal plants, using the fuel s higher heating value 1-6

27 The Promise of Advanced Coal Power Systems 2 The Promise of Advanced Coal Power Systems The power industry has progressively improved power plant designs to meet increasingly stringent limits for air pollution. New coal plants today are cleaner and more efficient than plants built in the past (see Table 2-1). Table 2-1 Progression of Coal Power Technology Development in the United States* Year Net Output, MW Efficiency, % HHV Main Steam Temperature, F ( C) 611 (322) 1050 (565) Main Steam Pressure, psia (bara) 315 (21.6) 3515 (242) SO 2, lb/mwh (kg/mwh) 83.6 (37.9) 1.1 (0.5) NO X, lb/mwh (kg/mwh) 9.1 (4.1) 0.6 (0.27) CO 2, lb/mwh (kg/mwh) 2850 (1290) 1840 (834) *Values for Illinois #6 Coal with Heating Value 11,000 Btu/lb (25,500 kj/kg) and 3.2% Sulfur However, the CO 2 challenge is bigger than that of other air emissions because it is a primary product of combustion, not the product of side reactions involving coal s minor constituents. Thus, the quantities of CO 2 to be removed dwarf those of SO 2 and NO X. Similarly, the cost of CO 2 removal using today s technologies far exceeds that of other air emissions. Technologies that can potentially bring down the cost of CO 2 capture already are being investigated at pilot scale. Many more are being tested in research laboratories around the world. Specifically: Three primary approaches to CO 2 capture are being considered, with competing technology developers leading the commercialization effort Pre-combustion capture technologies are applied to pressurized synthesis gas, prior to combustion in the gas turbine of an IGCC unit Post-combustion capture technologies are used to absorb CO 2 from flue gas, at atmospheric pressure, from coal-fired boilers using PC, CFBC, and other types of combustion systems Oxy-combustion technologies, applied to new or modified combustion power boilers, eliminate most of the nitrogen in air prior to combustion, thereby allowing direct compression of flue gas following any final purification steps. Some of these processes already are used in other industries, albeit at smaller scale than is needed for power plants. This experience reduces the lead time and risk for scale-up. In addition, many researchers and entrepreneurs are working on novel CO 2 capture technologies, raising the potential for new breakthroughs. Geologic injection of CO 2 for enhanced oil recovery (EOR) has been a commercial practice for 35 years. Traditional approaches now are being modified to maximize the amount of CO 2 left securely in the ground at the conclusion of injection operations. Researchers also now are investigating the viability of injection of CO 2 into porous saline formations, which are much more prevalent than depleted hydrocarbon reservoirs. 2-

28 The Promise of Advanced Coal Power Systems New alloys with high nickel and chromium content, similar to those used in jet engines and oil refineries, are being tested in gas turbines, steam turbines, and coal-fired boilers to enable a new generation of more efficient power plants. Just like energy-efficient cars and buildings, highly efficient power plants consume less fuel per unit of output, take up less space, and reduce environmental impacts, including GHG emissions. EPRI and the Coal Utilization Research Council (CURC) have formulated a roadmap for developing the technologies needed to affordably accomplish the environmental and electricity goals in EPRI s PRISM and MERGE analyses. This plan identifies and sequences the necessary RD&D activities at the component, integrated system, and power plant levels for coal power technologies. Critical links between development efforts also have been identified. Building a Portfolio of Competitive Advanced Coal Technology Options To realize the benefits of competition, and to accommodate the cost and performance risks of any one technology, the power industry will require multiple, competing technologies. In addition, because fuel properties are a major driver in designing coal-based power plants, different technologies often are needed when different coals are used (in contrast to natural gas and nuclear plants, where fuel homogeneity allows for greater standardization). EPRI s work has shown that no single advanced coal technology holds clear-cut advantages across the full range of coal types and operating environments. Because technologies do not remain static over time, each undergoing modification and improvement through operating experience and supporting research programs, their relative strengths and weaknesses do not remain constant. Thus, attempting to pick winners and focusing all investments on these select technologies is not the best strategy for meeting future electricity needs. To address environmental concerns with minimal economic impact, the best strategy lies in developing a robust portfolio of technologies from which power producers (and regulators) can select the options most suited to preferred coal types, local conditions, and compliance needs. Table 2-2 describes the fundamental types of advanced coal power block technologies in commercial application or development. For pulverized coal and circulating fluidized bed boilers, oxygen-firing ( oxy-combustion ) versions producing high purity CO 2 exhaust streams are also are in development (see Table 2-4). 2-2

29 The Promise of Advanced Coal Power Systems Table 2 Advanced Coal Power Block Technologies COMBUSTION TECHNOLOGIES Pulverized Coal (PC): Traditional coal plants in which coal is ground to the consistency of flour in a pulverizer and blown into a boiler for rapid combustion to create superheated steam, which a steam turbine uses to generate power. PC plants can be categorized into two types (subcritical and supercritical), based on the thermodynamic state of steam entering the first turbine. In the higherefficiency supercritical type, two subdesignations are used: Supercritical Pulverized Coal (SCPC): SCPC is a fully commerical technology. Plants typically employ a main steam (i.e., high-pressure turbine inlet) with a temperature of F ( C). The reheat steam (i.e., intermediate-pressure turbine inlet) temperature usually is the same as, or slightly higher than, the main steam temperature. For coals with high sulfur and/or chlorine content, these steam temperatures may require use of newer steels with high corrosion resistance. Ultra-Supercritical Pulverized Coal (USC PC): Defined to mean plants with a main steam temperature greater than 1100 F (595 C), these highly efficient plants have been built commercially in Europe and Asia, but not in North America (except for Philadelphia Electric s novel Eddystone Unit 1 from 1960). A major gain in efficiency will come from advanced USC conditions (main steam up to 1400 F or 760 C), which will require development and qualification of new nickel-based alloys with improved high-temperature strength and creep and corrosion resistance. Circulating Fluidized Bed Combustion (CFBC): This type of plant combusts coal and other solid fuels in a bed of hot sorbent particles suspended in motion (fluidized) by combustion air. The chief benefit of CFBC technology is its fuel flexibility; almost any combustible material, including biomass and municipal waste, can be readily burned. At present, only the subcritical design is commercially available, although a supercritical unit is under construction. 1 GASIFICATION TECHNOLOGIES Integrated Gasification Combined Cycle (IGCC): Although not widely deployed, the experience base for IGCC technology is sufficient to qualify these plants for nascent commercial status. An IGCC plant consists of a gasifier to convert coal to a fuel gas ( syngas ), which is cleaned up in a series of chemical processing stages. A gas turbine burns the cleaned syngas followed by a steam turbine heat recovery unit that transfers heat from the hot flue gas to raise steam. There are a variety of gasifier designs and manufacturers, each offering certain advantages, most of which use oxygen to convert the coal to syngas. The gas turbines are slightly modified versions of those used to burn natural gas. Emission control technologies for both gasification- and combustion-based power plants have been highly effective in reducing air emissions. Typical devices used for controlling emissions of standard pollutants and mercury are listed in Table 2-3, along with representative values for reductions that may be specified in permits or have been observed across a range of real-world operating conditions. Further refinement of today s emission control technologies, and in some cases introduction of secondary polishing emission control devices, should enable the industry to introduce coal-based plants with NZE. 2 1 The first supercritical CFBC plant is now under construction in Poland: 2 Although there is no precise definition of NZE, EPRI target values for coal-based plants are SO 2 and NO X levels of ~0.01 lb/mbtu (10 mg/nm³), SO 3 levels less than 1 ppm, filterable particulate levels of ~0.002 lb/mbtu (2 mg/nm³), and mercury levels less than ~ 0.01 ppb (0.1 µg/nm³). Actual values achieved may vary depending upon the coal being used. 2-

30 The Promise of Advanced Coal Power Systems Table 2-3 Typical Control Technologies for Air Emissions from Coal Power Plants NO X (nitrogen oxides): Low-NO X burners with overfire air (for boilers) or combustors with water or nitrogen injection (for gas turbines) limit maximum flame temperatures and oxygen availability in the flame core to reduce NO X formation by up to 35 55% for boilers and 70 90% for gas turbines (relative to conventional equipment). Downstream selective catalytic reduction (SCR) systems flow flue gas through a catalyst bed, along with a reagent (typically ammonia) to reduce NO X chemically to molecular nitrogen and water, reducing inlet NO X emissions by up to an additional 85 90% or more. These technology combinations yield a net overall reduction in NOX of 90 95% for boilers and 95 99% for gas turbines, respectively. SO 2 and H 2 S (sulfur dioxide and hydrogen sulfide): For boilers, flue gas desulfurization (FGD) systems or scrubbers use injected agents either as a slurry/solution or in solid form (typically finely ground limestone, lime, or sodium compounds) to react with flue gas SO 2, reducing emissions by 95 98% or more. In IGCC plants, where SO 2 is not an issue, the sulfur species of concern predominantly is H 2 S. Regenerable solvents with engineered chemical and physical properties are used to remove H 2 S and other acid gas species from the synthesis gas prior to combustion. Such processes are very effective, often removing 99.5% or more of the H 2 S. PM (particulate matter): For boiler flue gases, electrostatic precipitators (ESP), which use a series of electrically charged collector plates, or baghouses, can reduce solid particulate emissions to less than lb/mbtu of heat input to the boiler (~15 mg/nm 3 ), a reduction of more than 99%. In IGCC plants, particles are removed from syngas prior to combustion either by using water scrubbing or dry filters. Hg (mercury): Newer than other emission controls, and thus less certain in terms of long-term performance, injection of activated carbon or other additives in boiler flue gases appears capable of reducing mercury emissions by up to 90%. For boilers using some coal types, modifications to the SCR and scrubber can remove large fractions of mercury without additive injection. In IGCC units, activated carbon beds can remove 95% or more of the mercury from syngas prior to combustion. The use of dedicated systems to capture CO 2 from electric power plants is a relatively new concept that has evolved only over the last decade, along with the understanding of the effect of atmospheric buildup of CO 2 from industrialization. Historically, CO 2 separation only has been practiced in industrial coal gasification plants. This is why, today, pre-combustion CO 2 capture from IGCC plants is a more mature technology than post-combustion or oxy-combustion capture options for PC or CFBC plants. Table 2-4 describes these basic types of CO 2 capture systems for coal-based power plants and their development status. 2-

31 The Promise of Advanced Coal Power Systems Table 2-4 CO 2 Capture Technologies for Advanced Coal Power Plants Pre-Combustion CO 2 Applicable to IGCC plants, pre-combustion capture involves an additional chemical process unit to cause carbon monoxide (CO) present in the synthesis gas to react with steam to form CO 2 and hydrogen, allowing for CO 2 separation via a separate physical-solvent-based extraction and stripping process. The gas turbine then has to be designed to burn hydrogen, not a combination of CO and hydrogen. The individual processes involved in pre-combustion capture are commercially available, but their integration with an IGCC power plant has yet to be demonstrated. Post-Combustion CO 2 Best suited for combustion-based plants, post-combustion capture passes the flue gas through an absorber where a chemical solvent selectively removes the CO 2. The CO 2 -laden solvent passes to a stripper where it is heated to release a nearly pure CO 2 stream while the lean solvent is recycled back to the absorber to capture more CO 2. Amines and ammonia are among the candidate solvents now being developed for use with coal-fired boilers. There is some small-scale commercial experience, but post-combustion technology still has to be scaled up and integrated with a utility-size boiler. Oxy-Combustion CO 2 Oxy-combustion boilers burn coal in oxygen rather than air, greatly reducing the nitrogen content of the flue gas and thereby increasing its CO 2 content. This eases the task of CO 2 separation, although some purification of the flue gas still is required. To keep flame temperatures manageable and use near-conventional boiler designs and materials, a fraction of the CO 2 -rich exhaust gas is recycled back to the boiler. Oxy-combustion is an emerging technology, with the largest pilot unit currently at about 12-MW equivalent. Developers have announced plans to demonstrate units at 50 MW scale, but these will not be built for several years. Coal Properties Drive Generation Technology Selection and Plant Design Fuel properties factor significantly in the selection of coal-based generating technologies. In the United States, coal is ranked using a system established by the American Society for Testing and Materials (ASTM D 388). Coal rank generally correlates with the age of the coal, ranging from oldest to youngest (or from high to low rank) in the following order: Class I: Anthracitic: >15,000 Btu/lb (>35 MJ/kg) Class II: Bituminous: 10,500-15,000 Btu/lb (24 35 MJ/kg) Class III: Subbituminous (including Powder River Basin coals): ,000 Btu/lb (19 30 MJ/kg) Class IV: Lignitic ( brown coal ): Btu/lb (9 19 MJ/kg). As indicated, the heating value of coal generally decreases with decreasing rank, while moisture and ash (non-combustible mineral content) increase. (Note: Anthracitic coals are relatively uncommon, are harder to grind, and may have too little volatile matter for pulverized coal combustion. They seldom are used in power generation). The heating value of the coal determines the quantity of fuel needed for a given electrical energy output. As a result, lower-rank coals require higher volumes and larger boilers for a given MW rating than do bituminous coals. This also can result in increased capital and maintenance costs for plant processes such as coal and ash handling and emissions control. High-sulfur coals require additional consideration because of the corrosive nature of sulfur and the need to integrate sulfur emissions controls into plant design. 2-

32 The Promise of Advanced Coal Power Systems Where fuel flexibility is important or where lower-grade fuels (e.g., recovered coal fines) will be burned, CFBC may be selected because of this technology s ability to accommodate a wide range of fuels. Other factors that may influence technology choice include the availability of water and, where IGCC is concerned, site elevation, because less dense air at high altitudes reduces the gas turbine s maximum power output. Although it has been reported that IGCC with CO 2 capture holds an economic advantage for lowmoisture bituminous coals, studies by EPRI 3 and the Canadian Clean Power Coalition 4 show that PC plants with post-combustion CO 2 capture are competitive for subbituminous and lignite coals (which have high moisture content and relatively lower heating value). These studies underscore the need for multiple technologies, as no single advanced coal generating technology will be preferable for all coal types. Cost analyses can determine which technology will deliver the lowest levelized cost of electricity (COE) for a given fuel under the operating conditions of a specific location. Once the generation technology is selected, the unit can be specifically designed for a range of fuels (referred to as the design feed or design coal). For example, ash removal and handling systems must be sized for the highest ash content that will be encountered, while other components may be designed and critically sized for the highest sulfur content that will be encountered. 5 The furnace size for PC plants needs to be increased for lowerrank coals or coal with higher slagging potential. Thus, design decisions depend on knowledge of the extremes to which the equipment will be subjected by the design feed. Using fuels outside the range of specifications for the design feed can adversely affect the operation of the unit, which may exceed emissions limits, lose generating capacity, and experience more forced outages. The Importance of Early Deployment of Advanced Coal Technologies The typical path for commercializing a technology moves from the conceptual stage to laboratory testing, then to pilot-scale tests, larger-scale tests, full-scale demonstration, and finally to deployment of multiple systems in full-scale commercial operation. For capital-intensive technologies such as advanced coal power systems, each stage can take several years or more to complete and entails increasing levels of investment. As depicted in Figure 2-1, some advanced coal power technologies are relatively mature, but many only are in the development phase. Technologies are particularly vulnerable during this period because the projected costs often are higher than earlier estimates, assembled when less was known about the scale-up and application challenges. To maintain momentum during this critical phase, it is essential that there is clear a path to cost reduction. The historical record of technology development shows that costs, which are highest at the start of the demonstration phase, begin to fall due to: Experience gained from learning by doing Increasing economies of scale in design and production as order volumes rise Removal of contingencies covering uncertainties and first-of-a-kind costs Competition from second- and third-to-market suppliers. 3 Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site, EPRI Palo Alto, CA: October Summary Report on the Phase I Feasibility Studies Conducted by the Canadian Clean Power Coalition, Canadian Clean Power Coalition, May CoalFleet User Design Basis Specification for Coal-Based Integrated Gasification Combined Cycle (IGCC) Power Plants, Version 7, EPRI, Palo Alto, CA: June

33 The Promise of Advanced Coal Power Systems An IEA study conducted by Carnegie Mellon University and others observed this pattern for power plant emission controls. The research team predicted a similar reduction in the cost of CO 2 capture technologies as their cumulative installed capacity grows. 6 RD&D of specifically targeted technology refinements can lead to greater cost reductions in the deployment phase. Once a technology reaches maturity, its costs often are relatively close to those originally projected. Anticipated Cost of Full-Scale Application Research Development Demonstration Deployment Mature Technology Advanced USC PC Plants 1400 F (760 C) CO 2 Capture 1150 F+ (620 C+) Post- Pre-combustion combustion USC PC Plants 1150 F (620 C) 1100 F (595 C) IGCC Plants 1050 F Oxy-com- ~1100 F (~595 C) (565 C) bustion SCPC Plants CO 2 Storage CO 2 -EOR 2008 Note: Temperatures shown for pulverized coal technologies are turbine inlet steam temperatures. Figure 2-1 Development Status of Major Advanced Coal and CO 2 Capture and Storage Technologies Of the coal-based power and carbon storage technologies shown in Figure 2-1, only SCPC technology has reached commercial maturity. If all of these technologies in the portfolio can reach the stage of declining costs before being widely deployed, the cost of implementing CO 2 controls on the economy will be much lower. All advanced coal technologies with CCS will require techniques for secure, long-term CO 2 storage at large scale and associated measurement, monitoring, and verification technologies. Oil-field EOR operations offer considerable commercial experience with CO 2 injection that can aid our understanding of long-term CO 2 storage issues. However, these projects historically have been designed to maximize oil recovery while consuming as little CO 2 as possible, so modifications to traditional operating practices will be required. 6 Estimating Future Trends in the Cost of CO 2 Capture Technologies, IEA Greenhouse Gas R&D Programme (IEA GHG): February 2006/5, January. Report 2006/6. 2-

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35 Combustion-Based Systems Extending the limits of a Mature Technology 3 COMBUSTION-BASED SYSTEMS EXTENDING THE LIMITS OF A Mature Technology There are two major coal-fired technologies used for power generation pulverized coal, the major provider, and circulating fluidized-bed combustion. Figure 3-1 Photo of MidAmerican s Walter Scott, Jr. Energy Center Unit 4 SCPC Plant 1 Key Points PC plants are the predominant form of combustion-based coal-fired power generation throughout the world and have improved significantly since their inception CFBC plants are less common, but are another form of combustion-based coal power Advances in materials allow higher steam temperatures, which improve efficiency and reduce CO 2 production High levels of CO 2 capture from a PC or CFBC unit require post-combustion CCS using a chemical solvent, typically amines Post-combustion CCS requires near-zero inlet levels of emissions, which may be achievable with current emission controls Oxy-combustion is an alternative process that uses oxygen to combust coal and produces flue gas rich in CO 2. Pulverized Coal Commercial Status Pulverized coal combustion has been the prevailing mode of firing coal in power plants worldwide for more than 75 years and provides the backbone of electricity generating systems in many countries. In the U.S., there is about 300,000 MW of installed PC generating capacity. 1 Brian Mundt, Walter Scott Energy Center Unit 4, presentation at EPRI CoalFleet for Tomorrow General (Technical) Meeting, Tulsa, Oklahoma, April 15,

36 Combustion-Based Systems Extending the limits of a Mature Technology There are approximately 300 supercritical and ultra-supercritical units in the world. During the 10-year period from the mid-1990s to the mid-2000s, Japan and South Korea dominated the new plant market, while China began to show signs of rapid growth. In the U.S., MidAmerican s 790-MW Walter Scott, Jr. Energy Center (formerly Council Bluffs) Unit 4 became the first supercritical unit to be built in the U.S. in 20 years. About 9 GW of coal-fired SCPC generation is under construction in the United States in Environmental Controls The Promise of Near-Zero Emissions Emissions from PC power plants have progressively fallen over the past few decades and permits now are at levels previously thought unachievable. To meet current emission control targets, PC power plants today can use different processes for the main criteria pollutants. The most commonly used processes are: SO 2 removal with wet or dry flue FGD NO X control using low-no X burners with or without the addition of SCR Particulate control with an ESP or fabric filters ( baghouse ). Factors that influence the selection of emission control technologies include coal type, site location and conditions, plant size, emissions limits, consideration of mercury and sulfuric acid controls, and sale or disposal of solid combustion products. Progress in lowering emissions levels is expected to continue in response to the demand for near-zero emissions. At present, the ultra-low levels proposed for NZE are targets for ongoing research programs. Some of these are focused on extending the limits of current emission control technologies, while others seek to develop new sorbents and even new technologies that show promise in meeting NZE targets. These include multi-pollutant control technologies that remove all pollutants of interest in a single train at potentially lower cost. Additional equipment, maintenance and operating costs, and consumption of energy required by emissions control technologies all affect the plant s net efficiency and levelized COE. 2 Finding ways to lower capital and operating costs and limit parasitic energy losses is critical to realizing lower emissions while keeping electricity from coal-fired plants affordable. SO 2 Removal with Flue Gas Desulfurization SO 2 removal efficiencies of 95 97% were the norm in the early 2000s. Current wet FGD systems are being ordered with guarantee requirements of 98% SO 2 removal efficiency. Because of its higher removal efficiency, wet FGD typically is used for high- to medium-sulfur coals. Dry FGD typically is used only for low- and medium-sulfur coals (usually below ~2%). The wet FGD process uses alkaline slurry to contact the flue gas in an absorber vessel and remove the SO 2 through absorption and chemical reaction. The reagents used include limestone, lime, enhanced lime, ammonia, magnesium oxide, and sodium carbonate. 2 Levelized COE is the net present value of all costs associated with a plant over its economic life divided by the total generation in megawatt hours (MWh) over that period. This term, frequently expressed as $/MWh, has the virtue of being a single numeric representation of the complex cash flows associated with construction capital, financing, taxes, fixed and variable O&M, and purchase of commodities such as coal and emission allowances required to operate the plant. 3-

37 Combustion-Based Systems Extending the limits of a Mature Technology High capital costs, plot plan requirements, and balance-of-plant impacts for wet FGD typically are balanced by increased SO 2 control efficiency, reduced reagent costs, increased reagent utilization efficiency, and increased salability of fly ash and FGD by-products, which reduces disposal costs. Wet FGD systems become increasingly cost-effective as system size and flue gas sulfur content increase. Dry FGD technology injects an alkaline reagent into the flue gas, where it absorbs and reacts with the SO 2. The reagent may be injected as a dry powder or mixed in a slurry, from which the water is then evaporated. Solids from the process are collected in a particulate control device (ESP or fabric filter). Lower capital costs, a smaller footprint, and lower water use are the benefits of dry FGD. However, because dry FGD systems require reagents that are more expensive and use them less efficiently, they become less cost-effective, compared with wet FGD technology, as flue gas flow rate, SO 2 concentration, and/or required removal efficiency increases. The 2006 EPRI/CURC Technology Roadmap projects technological potential to reduce SO 2 emissions from 2005 levels of 0.08 lb/mbtu of fuel input (~80 mg/nm 3 ) to NZE levels of 0.01 lb/mbtu (~10 mg/nm 3 ) by Achieving this low of an SO 2 emission level on a consistent basis for power plant applications remains to be demonstrated. Improvements to current SO 2 removal processes that will help realize NZE levels include: More sophisticated monitoring and control of moisture, temperature, and reagent levels Advanced flow analysis techniques to ensure that gas/liquid contact is uniform and sufficient throughout the absorber vessel, and to minimize pressure drops and the resulting auxiliary power demands Fine-tuning of reagents through more precise purchase specifications, carefully designed additive packages, and adaptation for optimized co-capture performance Redundancy in sprays and pumps to achieve required availability. Dual Strategies for NO X Control Most NO X is formed during combustion from fuel nitrogen (fuel NO X ), and some results from oxidation of a small amount of the nitrogen contained in the combustion air (thermal NO X ). The production of fuel NO X depends on the amount of oxygen available, while thermal NO X, as the name implies, is highly dependent on temperature. In-furnace NO X control technologies can achieve significant reductions by properly staging combustion to control temperature and oxygen levels. The goal is to have the fuel nitrogen released in a zone of low oxygen to reduce fuel NO X, and then complete combustion in a zone of higher oxygen to reduce temperatures and minimize thermal NO X. Low-NO X burners are designed to control airflow to achieve proper zones of fuel-air ratios and facilitate mixing. Staging typically is completed in the boiler itself, in which the lower section is fuel-rich and the upper section is made air-rich by the addition of overfire air. Post-combustion NO X control technologies remove a significant amount of the remaining NO X through chemical reduction. SCR uses an ammonia or urea reagent, injected upstream of a catalyst (materials used include vanadium, molybdenum, and tungsten) to chemically reduce NO X to molecular nitrogen and water. The NO X emissions limits for coal-fired PC plants currently are as low as lb/mbtu (~50 70 mg/nm 3 ), using a combination of low-no X burners and SCR. 3 3 Status and Performance of Recently Permitted BACT/LAER Plants, EPRI, Palo Alto, CA:

38 Combustion-Based Systems Extending the limits of a Mature Technology Achieving NZE NO X levels of 0.01 lb/mbtu (~10 mg/nm 3 ) will require the resolution of operational issues, along with technological advancements in both in-furnace and post-combustion NO X controls. For units firing high-sulfur bituminous fuels, NZE for NO X may only be achievable in new boilers designed specifically for low-no X emissions. Again, achieving this consistent low-no X emission level for power plant applications remains to be demonstrated. Technologies for Particulate Control Electrostatic precipitators or baghouses installed on coal-fired boilers for particulate control typically can meet the particulate emissions limits commonly required of coal-fired power plants, which are as low as lb/mbtu (~12 mg/nm 3 ). ESP control devices exploit the electrical properties of small particles to collect them on metal surfaces. An electrical charge (generally negative) is imparted to the particles by establishing a corona current in the ESP. An established electric field then forces the charged particles to a grounded collection surface. The metal surfaces periodically are rapped to loosen the particles, which fall into collection hoppers. When a fabric filter is used, the particle-laden flue gas passes through the filter and the particles are caught on the fabric and do not pass through with the flue gas. In practice, a dust layer of accumulated particulate supported by the fabric and not the fabric itself collects the bulk of the particulate. The dust layer is removed periodically to keep the pressure drop across the filter within acceptable limits. The NZE particulate target suggested by several organizations is to lb/mbtu (~2 to 10 mg/nm 3 ). 4 It is likely that with improvements an ESP or a baghouse, or a combination of the two, can achieve these levels. Reducing Mercury Emissions U.S. mercury regulations for coal-fired power plants still are evolving. If allowable, the primary control strategy for existing plants likely will be to employ co-capture of mercury in FGD and particulate capture systems. New plants may be required to install additional mercury capture such as activated carbon injection (ACI). In ACI technology, powdered activated carbon (PAC) sorbent is injected into the flue gas at a location in the duct preceding the ESP or a baghouse. The PAC sorbent binds with the mercury in the flue gas and is captured in the ESP or baghouse. Since the mid-1990s, DOE NETL has spearheaded RD&D into the formation and capture of mercury from coal-fired power plants, including ways to enhance ACI and FGD-related processes. 5 The program seeks to develop a suite of control options to allow for cost-effective compliance with mercury regulations. Twelve projects were selected in 2006 that will focus on field testing of technologies capable of at least 90% mercury capture. Reducing CO 2 Emissions Through Increased Efficiency and Improved CO 2 Capture Processes A major thrust in advancing PC technology consists of increasing the operating temperatures and pressures of the steam cycle, which results in greater efficiencies, decreased fuel consumption, and lower emissions levels. A 2% gain in efficiency, for example, provides a reduction in fuel consumption of roughly 5% and can provide similar reductions in pollutants and CO 2. 4 Technologies to Achieve Near-Zero Emissions Goals: Concepts and Technical Challenges, EPRI, Palo Alto, CA:

39 Combustion-Based Systems Extending the limits of a Mature Technology Worldwide, operating ratings for supercritical units range from MW. The increased pressures and temperatures provide significant efficiency improvements over subcritical units with comparable availability. Ultra-supercritical steam parameters of 4350 psi and 1112 F (300 bar and 600 C) are in operation today with generating efficiencies of 42% (HHV). 6 There are several years of experience with these plants in Europe and Japan, with excellent availability, and plans have been announced for several USC PC plants in the United States. Significant CO 2 reductions can be achieved through efficiency gains, but further reductions in CO 2 emissions will require CCS. However, adding capture processes to new plants and retrofits currently imposes large net power reductions and efficiency (operating cost) penalties, because part of the plant s power must be used for CO 2 capture. Extensive RD&D is under way to improve both post-combustion capture and oxy-combustion processes. It should be noted that as a consequence of incorporating CCS, plants also would achieve NZE. Steps and Timeframe for USC PC Cost Reduction and Efficiency Gains EPRI s CoalFleet for Tomorrow research program addresses the gaps in RD&D identified for USC PC plants with CO 2 capture by supporting the development of promising emerging technologies. Figure 3-2 depicts the anticipated timeframe for achieving efficiency gains through higher operating parameters and through improvements in CO 2 capture technologies that will result in lower energy penalties Total Plant Cost ($/kw, constant dollars normalizedto 2005 plant cost) Near-Term Upgrade solvent from MEAto MHI KS-1 (or equivalent) Upgrade steam conditions from 1050 F (565 C) MS & RH to 1100 F (595 C) MS & RH Near Mid-Term Upgrade steam conditions to 1110 F (600 C) MS 1150 F (620 C) RH Mid-Term Upgrade steam conditions to 1300 F (700 C) MS & RH, then 1400 F (760 C) MS & Double RH Long-Term Upgrade solvent to <10% energy penalty and <20% COE penalty Plant Net Efficiency (HHV Basis) Figure 3-2 RD&D Path for USC PC Power Plants with 90% CO 2 Capture (Upturning Arrows Refer to Right Axis and Downturning Arrows to the Left Axis) 6 Efficiencies as high as 44% have been achieved when additional reheat and cold condenser temperatures are used. However, these efficiencies may not be available in most parts of the United States, where expected efficiency for such steam conditions would be about 40% HHV. 3-

40 Combustion-Based Systems Extending the limits of a Mature Technology In addition, EPRI s CoalFleet for Tomorrow research program has produced a Guideline for Advanced Pulverized Coal Power Plants, 7 a comprehensive overview of state-of-the art and emerging technologies. The guideline helps expedite technology selection, permitting, and design processes for advanced pulverized coal plants, offering insights into key areas of plant operations, technology updates, and lessons learned that should be addressed by engineers developing PC plant specifications. Advanced Materials The Key to PC Efficiency Gains More corrosion-resistant materials to allow for higher steam conditions is the main enabling technology needed for construction of coal-fired boilers and turbines with higher efficiencies. Ferritic/Martensitic Steels During the last two decades, research on advanced materials to withstand higher steam conditions has focused on cost-effective, high-strength ferritic-martensitic steels with crystal lattice structure in the base metal and a very hard surface structure. These improved steels are capable of operating at metal temperatures up to 1150 F (620 C), have good weldability, and fracture toughness. Researchers are working to push this limit towards 1200 F (650 C). Austenitic Stainless Steels The next class of steels that has the necessary creep strength and corrosion resistance is known as the austenitic stainless steels. These steels contain a higher percentage of nickel, and chromium well in excess of 18%. Those with more than 22% chromium are the best candidates for use with highly corrosive coals. The limiting temperature for austenitic steels is about F ( C). Austenitic stainless steels have a higher coefficient of expansion than ferritic steels, making weld joints with ferritic steels particularly challenging. Nickel-Based Alloys High-nickel-content alloys have better strength and corrosion resistance than stainless steels at very high temperatures, but are considerably more expensive and more difficult to weld. Nonetheless, researchers are working to qualify nickel-based alloys for use in high-temperature boiler and steam turbine components. Ultimately, these materials are expected to enable steam temperatures of up to 1400 F (760 C), which would allow generating efficiencies to climb to 47% (HHV basis with bituminous coal; slightly less for higher-moisture coals). This approximately 10% improvement over the efficiency of a new conventional subcritical PC plant would equate to a decrease in CO 2 and other emissions of about 25% per MWh. Advanced Materials Research 8 In the United States, the challenge of developing and testing new materials has been taken up by DOE s (Fossil Energy) Advanced Materials Research program, which consists of multiple subprograms involving laboratories, universities, and non-profit organizations. One subprogram, Evaluating Materials Technology for Ultra-supercritical Coal-Fired Plants, is dedicated to identifying, evaluating, and qualifying materials for construction of coal-fired boilers and turbines with advanced steam cycles. This activity is co-funded by the Ohio Coal Development Office and is managed and coordinated by EPRI, with the participation of several boiler and turbine manufacturers. 7 CoalFleet Guideline for Advanced Pulverized Coal Power Plants, Version 3, EPRI, Palo Alto, CA: March

41 Combustion-Based Systems Extending the limits of a Mature Technology Phase I of the program includes work to identify, fabricate, and test advanced materials and coatings with mechanical properties, oxidation resistance, and fireside corrosion resistance suitable for costcompetitive boiler operation at steam temperatures up to 1400 F/5500 psi (760 C/380 bar). These USC PC plants are anticipated to become commercially available by about In addition, materials issues that affect boiler design and operation at temperatures as high as 1600 F (870 C) 9 are being explored. Phase II of the program involves optimizing the designs of Phase I and conducting further field evaluations, as well as extending the studies to define the conditions for oxy-fuel-fired boilers and how these affect materials degradation. A similar European program is establishing materials and designs for a plant with steam temperatures of 1290 F (700 C). Work has progressed to the point where large panels of advanced material components are being tested in an in-service boiler (E.ON Energie s Scholven plant) equipped with a separate steam circuit to simulate the advanced USC PC temperature environment (this facility is known as ComTes-700 ). The program envisions constructing a showcase USC PC unit (~400 MW) to demonstrate these steam conditions. E.ON Energie also has announced its intention to build an ~450-MW USC PC unit at about 1290 F (700 C). Post-Combustion Removal of CO 2 from Flue Gases Most post-combustion CO 2 capture processes envisioned for power plant boilers draw upon commercial experience with absorption and separation using amine solvents. This currently is done at a much smaller scale (up to 20-MW equivalent) in the food and beverage and chemical industries, and in three applications of CO 2 capture from slipstreams of exhaust gas at CFBC units. These processes contact flue gas with an amine solvent in an absorber column where the CO 2 chemically reacts with the solvent. The CO 2 -rich liquid mixture passes to a stripper column where it is heated, releasing the CO 2, and the regenerated solvent is re-circulated back to the absorber column. The released CO 2 may be processed further before compression to a supercritical state for efficient transportation to a storage location. 10 After drying, the CO 2 released from the regenerator is relatively pure. However, successful CO 2 removal requires very low levels of SO 2 and NO X in the flue gas entering the CO 2 absorber, as these species also react with the solvent. Thus, high-efficiency SO 2 and NO X control systems are essential to minimizing solvent consumption costs for post-combustion CO 2 capture. The addition of current commercial amine solvent separation technologies to coal-fired PC units would impose high capital and operating costs and require steam and power inputs that would substantially reduce net plant output (see Figure 3-3). Extensive RD&D is in progress to improve the solvent and system designs for power boiler applications and to develop better solvents with greater absorption capacity, less energy demand for regeneration, and greater ability to accommodate flue gas contaminants. 9 Technologies to Reduce or Capture and Store Carbon Dioxide Emissions, The National Coal Council, June CO 2 storage is discussed in Chapter 5. 3-

42 Combustion-Based Systems Extending the limits of a Mature Technology Net Power Output, MWe No Capture Retrofit Capture New Capture Supercritical PC Total Capital Requirement, $/kw (2007$). 6,500 6,000 5,500 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 No Capture Retrofit Capture New Capture Supercritical PC 30-Yr levelized COE, $/MWh (Constant 2007$) No Capture Retrofit Capture New Capture Supercritical PC Figure 3-3 PC Net Power Output, Capital Cost, and COE with and without Capture (Powder River Basin Coal) 11 Amine-Based Solvent Technologies The two leading manufacturers of post-combustion CO 2 capture technology, Fluor and MHI, are working to meet the requirements of large-scale power plant applications by increasing the performance of their solvents and decreasing the amount of thermal energy required to regenerate them. Fluor s Econamine FG process uses a 30% aqueous solution of monoethanolamine solvent with proprietary additives. Econamine is deployed at some 20 plants supplying CO 2 to the chemical and food industries and for EOR. However, none of these units process coal-derived flue gas. As part of a Canadian Clean Power Coalition study, a more recent commercial offering, Econamine FG Plus, was retrofitted to a PC boiler fired with lignite. This reduced energy consumption by about a third from 1750 Btu/lb to 1180 Btu/lb of CO 2 captured (4070 kj/kg to 2760 kj/kg) 12 compared to the conventional Econamine FG process. MHI has successfully used an amine solvent, designated KS-1, at several large-scale commercial plants for fertilizer and heavy oil production. The first testing of KS-1 on coal-generated flue gas is under way at a 10-ton-day CO 2 pilot at J-POWER s Matsushima plant in Nagasaki, Japan. 13 An EPRI study is evaluating the use of KS-1 for power plant applications. Results are expected in late George Booras and Neville Holt, Review of New CoalFleet Engineering-Economic Evaluations, presentation at CoalFleet for Tomorrow General (Technical) Meeting, Tulsa, Oklahoma, April 16, Evaluation of Advanced Coal Technologies with CO 2 Canadian CPC Phase 1 Studies of Coal Technologies with CO 2 Capture, EPRI, Palo Alto, CA: Assessment of Post-Combustion Carbon Capture Technology Developments, EPRI, Palo Alto, CA: February

43 Combustion-Based Systems Extending the limits of a Mature Technology Three other suppliers have completed extensive pilot plant programs and are submitting proposals in response to solicitations for commercial projects. They are: Aker Clean Carbon an earlier version of the process is used to capture CO 2 on the Sleipner project Cansolv the process uses two solvents to simultaneously remove SO 2 and CO 2 HTC Purenergy the process includes a control system to optimize heat utilization. Along with modifications to the chemical properties of sorbents, research also is addressing the physical structure of the absorber and regenerator equipment, examining membrane contactors to improve gas-liquid contact and/or heat transfer, and optimizing thermal integration with steam turbine and balance-of-plant systems. Potential Alternatives to Amine-Based Solvent Technologies Extensive research is being carried out to identify new processes and liquid solvents for CO 2 capture that offer economic advantages and are suitable for scale-up and demonstration. Some notable examples of this development work include post-combustion CO 2 capture using a chilled aqueous ammonium carbonate as the solvent, currently under development and testing by Alstom and a collaborative of EPRI members. CO 2 is captured in an absorber at low temperature and atmospheric pressure, forming ammonium bicarbonate, which then is regenerated at increased temperature and high pressure to drive off a concentrated stream of CO 2. Although still to be confirmed, it is projected that the heat of regeneration will be approximately half that of amine systems. Further, because the CO 2 is released at pressure, less energy is required for the compression stage. Alstom and the EPRI consortium have constructed a 1.7-MW pilot unit connected to a flue gas slipstream at We Energies Pleasant Prairie Power Plant and testing has commenced. A 20-MW scale-up is planned at American Electric Power s (AEP) Mountaineer power plant in West Virginia, with AEP potentially hosting a 200-MW scale-up demonstration at its Northeastern station in Oklahoma. Also in development is an ammonia-based process (ECO2) that is being tested by Powerspan at 1-MW scale at FirstEnergy s R.E. Burger plant in Ohio. If successful, Basin Electric plans to test a 120-MW scale-up at its Antelope Valley station in North Dakota. Ionic liquids, a class of organic compounds, show promise for post-combustion CO 2 capture as they can be formulated to have high selectively for CO 2 relative to nitrogen and oxygen. Unlike amines, they do not react with CO 2 but form weak ionic bonds that result in a relatively low heat of regeneration. DOE-NETL currently is funding development at the University of Notre Dame. In Europe, the CASTOR (for Capture and Storage) project, a cooperative effort involving some 30 European RD&D organizations, is exploring newly developed solvents for CO 2 capture in pilot-scale tests at a coal-fired plant in Esbjerg, Denmark Start-up of the Largest Installation in the World to Capture CO 2 in the Flue Gases of a Coal-fired Power Station - Denmark - European Castor Project. Press Release, IFP. Lyon, France: March 16, 2006; 3-

44 Combustion-Based Systems Extending the limits of a Mature Technology In addition to liquid solvents, alternative approaches also are being investigated to separate CO 2 from flue gas. These include: 15 Multiple physical and chemical adsorption processes Cryogenic separation processes that freeze out the CO 2 Molecular sieve and solution-diffusion membranes Biological processes that use photosynthesis to fix the CO 2 as algae. Oxy-Combustion for CO 2 Capture Fuel combustion in a blend of oxygen and recycled flue gas rather than in air is known as oxy-fuel combustion or oxy-combustion, and it is gaining worldwide interest as a viable CO 2 capture alternative for PC (and CFBC) plants. The process is applicable to virtually all fossil-fueled boiler types and is a candidate for retrofits and new power plants. Firing coal with only high-purity oxygen would result in a flame temperature too high for existing furnace materials, so the oxygen is diluted by mixing it with a slipstream of recycled flue gas. The flue gas recycle loop may include dewatering and desulfurization processes. As a result, the flue gas downstream of the recycle slipstream take-off consists primarily of CO 2 and water vapor (with small amounts of nitrogen, oxygen, and criteria pollutants). After the water is condensed, the CO 2 -rich gas is compressed and purified to remove contaminants and prepare the CO 2 for transportation and storage. Primary flow Coal prep Coal Nitrogen Boiler Secondary flow Oxygen Oxygen plant Air Flue gas heater ESP or baghouse FGD Dried RFG To CO 2 purification and compression Wet recycled flue gas (RFG) Dryer Water Figure 3-4 Schematic of Oxy-Combustion Process Assessment of CO 2 Capture Options Currently Under Development, EPRI, Palo Alto, CA: February John Wheeldon and Des Dillon, Oxy-Combustion of Coal, EPRI CoalFleet for Tomorrow General (Technical) Meeting, Greenville, South Carolina, July 26,

45 Combustion-Based Systems Extending the limits of a Mature Technology Oxy-combustion boilers have been studied in laboratory-scale and small pilot units of up to 3 MW t. Two larger pilot units at 30 MW t are operating, one by Babcock & Wilcox (B&W), and one by the Swedish power company Vattenfall. An Australian-Japanese project team is pursuing a 30-MWe repowering project at the CS Energy s Callide A station in Queensland, Australia. 17 These larger tests will allow verification of the technology and provide engineering data useful for designing pre-commercial systems of about 300 MW. Because the oxy-fuel combustion process requires a supply of high-purity oxygen, it stands to benefit from developments in oxygen separation such as membrane-based air separation technology, which could replace energy-intensive cryogenic process air separation technology. Circulating Fluidized-Bed Combustion Commercial Status CFBC technology has been employed for power generation for only 20 years and still is evolving. In the United States, there is about 5000 MW of coal-fired generating capacity, with another 1000 MW in construction, and worldwide there is estimated to be more than 14,000 MW of capacity. The typical maximum size of the units is 300 MW, although two units can be combined to raise steam for a single 600-MW turbine. By contrast, PC units can generate more than 1,000 MW. The poorer economy of scale of the CFB results in a higher capital cost and has limited its deployment. Almost all CFB units raise sub-critical steam and are less efficient than the USC PC plants in operation. A 460-MW SC CFB under construction in Lagisza, Poland will be the largest CFB built. These two features, steam conditions and generating capacity, will improve the efficiency and economy of CFB technology and make it more competitive with PC plants. The CFB furnace operates at approximately 1550 F (843 C), much lower than the 2400 F (1320 C) achieved in a PC unit. The lower combustion temperature limits ash fouling and corrosion of the heat transfer surfaces and allows the CFB to handle fuels that are difficult to burn in a PC unit. Many CFB units are fired with waste coal and serve to clean up waste piles left over from mining activities. Its greater fuel flexibility allows CFB to use lower-grade, lower-cost fuels than a PC unit and this helps compensate for the higher capital costs. Environmental Controls In the CFB design, relatively coarse coal and limestone (for sulfur capture) are fed into the furnace and the majority of the solids present are carried over by the combustion air. Most of these solids are capture by cyclones and returned to the base of the furnace, which extends the residence time of the solids and helps increase combustion and sulfur capture efficiency. The majority of the sulfur in the coal is captured in the furnace by the calcined limestone, with an additional amount captured by a dry FGD located after the cyclones. Emissions of SO 2 as low as 0.08 lb/mbtu (~80 mg/nm 3 ) have been achieved, similar to that of a PC, but the limestone feed rate required is almost twice that of a wet FGD. The low furnace temperature results in reduced NO X formation. This can be further reduced by nonselective catalytic reduction through injection of ammonia into the upper furnace. Emission levels of 0.07 lb/mbtu (~70 mg/nm 3 ) have been achieved, again similar to those of a PC unit. SCRs are not considered practical for CFB operation as the flue gas dust loading is higher than for a PC unit and this will impair its operation. 17 Callide Oxyfuel Project, April Fact Sheet OXY01;

46 Combustion-Based Systems Extending the limits of a Mature Technology The low temperature results in a slightly lower combustion efficiency than for a PC unit, but the additional carbon present in the fly ash offers intrinsic mercury capture, and collection efficiencies of more than 90% have been measured. Particulate control is achieved using baghouses, which operate with similar collection efficiency to those used for PC units. Efficiency Improvements and CO 2 Capture The improved materials being developed primarily for USC PC applications are expected to be equally suitable for CFB designs. Presently no USC CFB units are planned but designs reportedly have been prepared. The CFB efficiency gains arising from the improved steam conditions are expected to be similar to those achieved by the PC designs. Post-combustion technologies for PC applications are expected to be equally suitable for CFB applications. A sub-critical CFB design will produce more CO 2 than the more- efficient USC PC design, however, so the capture plant will be larger, more expensive, and require increased power losses. USC CFB designs need to be demonstrated and proven if they are to play an effective role in the future. Oxy-combustion also is applicable to CFB technology and may have some advantages over PC designs. The process is similar to that shown in Figure 3-4 for PC oxy-combustion with these exceptions: Because the sulfur is captured mainly in the CFB furnace, no FGD is required. Any remaining SO 2 is removed in the cryogenic CO 2 purification stage. Ammonia injection for NO X reduction is eliminated and the NO X is removed in the cryogenic CO 2 purification stage along with the SO 2. The furnace temperature can be controlled by cooling the circulating solids and lowering the amount of flue gas that has to be recycled. Flowing less gas through the furnace allows its size to be reduced, with associated reductions in capital and operating costs. Both Alstom and Foster Wheeler are evaluating CFB for oxy-combustion. Recently, the Oxy-Coal Alliance (composed of Praxair, Foster Wheeler, and others) announced plans to build a 50-MW oxy-combustion CFB for Jamestown Board of Public Utilities in New York. This commercial project will demonstrate the viability of the technology and provide design data for scaling up to units of 300 MW and larger. 3-12

47 IGCC Technologies Transitioning to the Commercial Era 4 IGCC Technologies Transitioning to the commercial era Figure 4-1 Aerial View of Tampa Electric Company s 250 MW Polk Unit 1 IGCC Plant 1 Key Points IGCC processes are amenable to environmental controls that result in very low air emissions Lessons leaned from the first generation of IGCC plants are expected to lead to increased availability in new IGCC plants High levels of CO 2 capture from an IGCC unit require the addition of one or two water-gas shift reactors and physical or chemical solvent processes CO 2 can be captured from IGCC units at elevated pressure, which reduces the cost and energy requirements for compression to pipeline pressure Gas turbines capable of firing the high-hydrogen syngas that results after CO 2 removal are the subject of extensive RD&D efforts. Overview IGCC technology allows the use of solid and liquid fuels (typically coal, petroleum coke, a blend of coal and petroleum coke, residuum, or biomass) in a power plant that has the environmental benefits of a natural gas-fueled plant and the thermal performance of a combined cycle. In its simplest form, the solid or liquid fuel is gasified with either oxygen or air, and the resulting raw gas (called syngas, an abbreviation for synthetic gas) is cooled, cleaned of particulate matter and sulfur species, and fired in a gas turbine. By removing the emission-forming constituents from the gas under pressure prior to combustion in the power block, IGCC plants can meet extremely stringent air emission standards. The hot exhaust from the gas turbine passes to a heat recovery steam generator (HRSG) where it produces steam that drives a steam turbine. 1 The Tampa Electric Integrated Gasification Combined-Cycle Project, An Update, Topical Report Number 19. U.S. DOE Clean Coal Technology Program and Tampa Electric Company: July 2000; cctc 4-

48 IGCC Technologies Transitioning to the Commercial Era Power is produced both from the gas and steam turbines. The use of gas turbines and a steam turbine constitutes the combined cycle aspect of IGCC and is one reason why gasification-based power systems can achieve high power generation efficiencies. In a typical IGCC unit, about 60% of the net power output is generated by the gas turbine(s) and about 40% by the steam turbine. Due to the relatively high efficiencies of modern combined cycle technology, the overall thermal efficiency of an IGCC is in the 38 41% HHV range for bituminous coal. 2 A block flow diagram of an IGCC system is shown in Figure 4-3. There are many variations on this basic IGCC scheme, especially in the degree of integration. Four major commercial-sized, coal-based IGCC demonstration plants are in operation, each using a different gasification technology, gas cooling and gas cleanup arrangement, and integration scheme. All of the current coal based plants integrate the steam systems of the gasification and power block sections. Typically, boiler feed water is preheated in the HRSG and passed to the gasification section, where saturated steam is raised from cooling of the raw syngas. The saturated steam passes to the HRSG for superheating and reheating prior to introduction, with additional HRSG superheated steam, to the steam turbine for power production. The degree of integration of the gas turbine with the air separation unit (ASU) is the part of the design that varies most among the four coal-based IGCC plants. The major design variations between the two European IGCC plants and the U.S. plants lies in gas turbine selection and differences in philosophies about the importance of efficiency compared to availability. The European plants at Buggenum (Netherlands) and Puertollano (Spain) are both highly integrated designs with all the air for the ASU taken as a bleed of extraction air from the combustion turbine compressor. The U.S. plants at Tampa and Wabash are less integrated, and the ASUs have their own separate air compressors. The more highly integrated design results in higher plant efficiency, since the auxiliary power load is lowered by the elimination of the separate air compressor. However, there is a loss of plant availability and operating controllability for the highly integrated system. Startup time is longer, too, with this design, as the combustion turbine must be run on more expensive secondary fuel (natural gas or oil) before extraction air can be taken to the ASU for its cool-down and start-up. Coal Prep Gasification Gas Cooling Sulfur Removal O2 N2 Air Separation Unit Air Gas Turbine AIR Air BFW Steam HRSG Fresh boiler Freshwater (BFW) Conventionally Integrated Added for Highly Integrated Steam Turbine Figure 4-2 Block Flow Diagram of an IGCC Power Plant

49 IGCC Technologies Transitioning to the Commercial Era Commercial Status Two coal-based, commercial-sized IGCC plants currently are operating in the United States. Three more are in Europe and one is in Japan, for a total installed capacity of about 1700 MW. The U.S. projects were partially supported by DOE s Clean Coal Technology demonstration program. Although experience is limited with gasification in coal-fired power plants, it is supplemented by multiple chemical plants around the world, which have 100 years of experience in operating coal-based gasification units and related gas cleanup processes. The most advanced of these units are similar to the front end of a modern IGCC facility. Similarly, several decades of experience firing natural gas and petroleum distillate have made the basic combined cycle a mature generating technology. Recently, power companies on five continents announced plans to build (or are considering) new coalbased IGCC power plants, and provisions to encourage their construction in the United States were included in the Energy Policy Act of Much of this interest is motivated by the potential for IGCC power plants to capture the majority of their CO 2 emissions. In the United States, Duke Energy has begun construction of a new 630-MW IGCC plant in Edwardsport, Indiana. The plant is scheduled to come on-line in 2012 and will replace four older generating units of a total combined 160-MW capacity at the same site. Emission Controls The syngas fed into the gas turbine first passes through a series of clean-up steps to remove species that would harm the environment or the turbine. Sulfur Species Removal Under the reducing conditions of gasification, sulfur in the coal is converted primarily to hydrogen sulfide (H 2 S), with ~3 10% converting to carbonyl sulfide (COS). This typically necessitates the use of a COS hydrolysis reactor to convert the COS to H 2 S prior to H 2 S removal by an acid gas recovery (AGR) system. The most common AGR processes use the chemical solvent methyldiethanolamine (MDEA) or a physical solvent such as Selexol, which is a mixture of dimethyl ethers of polyethylene glycol. The chemical solvent reacts with the acid gases and requires heat to reverse the reactions and release the acid gases. Physical absorbents dissolve acid gases and require pressure as the driving force for absorption and pressure release for regeneration. IGCC plants have demonstrated sulfur removal rates of ~99%. 3 The sulfur or sulfuric acid can be sold for use in fertilizer manufacturing to help offset plant operating costs. NO X Control The main contributor to NO X emissions is thermal NO X from the uncontrolled combustion of syngas (which has a high flame temperature). The thermal NO X is controlled to very low levels by dilution of the syngas with nitrogen to lower the flame temperature. The diluent nitrogen also provides additional mass and motive force to the gas turbine that increases the MW output. The use of low-no X burners in the gas turbine will further limit the production of NO X. In the gasification process, the small amounts of fuel-bound nitrogen are readily removed from the syngas by water washing. Together, these processes significantly limit NO X emissions for IGCC plants. 3 Gasification Technology Status - December 2006, EPRI, Palo Alto, CA: December

50 IGCC Technologies Transitioning to the Commercial Era If further NO X emissions reductions are required, a SCR system could be added to the plant. Although the application of SCR is not yet commercially proven on coal-derived syngas, some proposed projects plan to use SCR. Mercury and Trace Toxics Removal All IGCC units proposed since 2004 incorporate mercury removal systems in their design. Typically, the system consists of a single bed of sulfur-impregnated activated carbon, which is expected to remove up to 94% of the syngas mercury content. Arsenic and other trace metals also are absorbed by the carbon, with varying degrees of efficiency. Particulate Removal Particulates in syngas can be removed by dry processes such as a rigid barrier, pulse-cleaned filter or by wet processes using venturi scrubbers (referred to as gas scrubbing ). The process used typically depends on the selected gasification technology. Both methods achieve extremely high levels of particulate removal. In the wet process, the solids also can be recovered and recycled to the gasifier if warranted by the carbon content. In the dry process, solids can be sold for use in cement if low in carbon, or recycled to the gasifier if high in carbon. Steps and Timeframe for IGCC Capital Cost Reduction and Efficiency Gains Members of EPRI s CoalFleet for Tomorrow research program teamed to evaluate more than 120 coalgasification-related research projects worldwide and to identify gaps or critical-path activities where additional resources and expertise could hasten the market introduction of IGCC advances. The resulting IGCC RD&D Augmentation Plan 4 describes such opportunities and how they could be addressed for IGCC plants to be built in the near term (by ) and over the longer term ( ) Total Plant Cost ($/kw, constant dollars normalized to 2005 plant cost) Near-Term Add SCR Eliminate spare gasifier F-class to G-class CTs Improved Hg detection Long-Term Membrane separation Warm syngas cleanup Mid-Term CO 2 -coal slurry ITM oxygen G-class to H-class CTs Supercritical HRSG Dry ultra-low-no X combustors Plant Net Efficiency (HHV Basis) Figure 4-3 RD&D Path for IGCC Power with 90% CO 2 Capture (Upturning Arrows Refer to Right Axis and Downturning Arrows to the Left Axis) 30 4 CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants, EPRI, Palo Alto, CA: January

51 IGCC Technologies Transitioning to the Commercial Era Figure 4-3 depicts the anticipated timeframe for select technology developments, as identified in EPRI s IGCC RD&D Augmentation Plan, that promise a succession of significant improvements in IGCC unit efficiency and costs. These include advances in gasifier, turbine, and air separation technologies, as well as opportunities to reduce the cost of CO 2 capture through better solvents and integration with other plant processes. Note that these opportunities remain to be demonstrated. The CoalFleet for Tomorrow program addresses the gaps in research and development identified in the IGCC Augmentation Plan by supporting development of promising emerging technologies and through dissemination of data on IGCC technologies. The IGCC User Design Basis Specification, 5 provides EPRI members a comprehensive guide to the major specifications needed to contract for an IGCC plant, including multiple configurations of 600-MW and 800-MW commercial IGCC power plants, using gasification processes and combustion turbine equipment from several manufacturers. Longer-Life Components for Improved Gasifier Availability 6 The availability (percent of time available to generate electricity) of IGCC plants is a concern because of the relative newness of the technology. Lessons learned from the existing plants, which are the first generation, will be incorporated in new IGCC plants through design modifications that are expected to result in improved availability. A number of new or improved IGCC plant components and processes are being developed. There are two generic types of gasifier vessel design. One uses multiple layers of refractory brick to insulate the metal wall of the pressure-containing vessel from the hot gasification reaction zone. The other uses a water-cooled membrane wall in which boiler tubes are welded together to form a continuous wall around the reaction zone. A thick, metal pressure shell behind the membrane contains the process pressure. The refractory-lined vessel design is considerably cheaper to build than the membrane- wall vessel. However, the refractory is worn down by chemical attack from gasification products and molten slag, and suffers from thermal fatigue fractures due to the large temperature cycles experienced during startups and shutdowns. Refractory replacement typically must occur every 6 to 18 months, at a cost of about $1 million including materials and labor. Research at DOE s Albany Research Center is focused on the development of improved chrome-based refractory materials. The goal is to extend the interval for refractory replacement to 36 months or more, allowing the refractory work to be carried out at the same time as the gas turbine hot section overhaul. No additional outage time would be required for the refractory change-out, which takes about 3 weeks, because the gas turbine hot section overhaul takes 6 weeks. Increasing the longevity of feed injectors for slurry-fed gasifiers also is the subject of research by several manufacturers and should result in less down time. Higher-Pressure Gasifiers Increasing the operating pressure of gasifiers allows for smaller (albeit thicker-shelled) vessels for a given capacity rating, which in turn reduces cost and space requirements. Higher operating pressure also is compatible with the physical solvent-based systems generally preferred for high efficiencies of sulfur species removal and CO 2 separation. 5 CoalFleet User Design Basis Specification for Coal-Based Integrated Gasification Combined Cycle (IGCC) Power Plants, Version 7, EPRI, Palo Alto, CA: June CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants, EPRI, Palo Alto, CA: January

52 IGCC Technologies Transitioning to the Commercial Era Gas Turbines for Synthesis Gas Firing Syngas is a low-energy-density fuel with a heating value of about 250 Btu per standard cubic foot (9.314 MJ/m 3 ), roughly one-quarter that of natural gas. As a result, operation on syngas requires a higher volumetric flow through the gas turbine combustors to achieve the same turbine-section heat input as operation on natural gas. Currently, operating advanced gas turbines on syngas requires turbine inlet temperatures to be lower than those used when firing natural gas because of differences in aerodynamics, heat transfer, and erosion issues. 7 Nonetheless, gas turbines have been designed to accommodate higher fuel mass flow and lower flame temperatures associated with firing syngas. In many cases, despite the lower firing temperature, the higher mass flow allows an increase in gas turbine power rating. Some turbine designs are modified with stronger drive shafts and larger generators to take advantage of this capacity. In addition, to control NO X, syngas is diluted with nitrogen to lower the flame temperature. The diluent nitrogen provides additional mass and motive force to the gas turbine, increasing the MW output. However, aerodynamic issues with syngas and difficulties in trying to capture the additional mass-flow energy (e.g., shaft torque and/or axial compressor surge) currently limit power gains to values below those theoretically possible. 8 IGCC plant development will benefit from new gas turbines models with higher firing temperatures, greater efficiencies, and larger power outputs, which will allow a significant reduction in the cost of electricity. For plants coming on-line circa 2015, the larger size G-class turbines Mitsubishi Heavy Industries M501G (60 Hz) and M701G (50 Hz), and the Siemens SGT6-6000G, which operate at higher firing temperatures (relative to F-class machines) can improve efficiency by 1 to 2% while also decreasing capital cost per kw capacity. H-class gas turbines, coming on-line later, will provide a further increase in efficiency and capacity. Supercritical Heat Recovery Steam Generators In IGCC plants, hot exhaust gas exiting the gas turbine is ducted into a HRSG to raise sub-critical steam to drive a steam turbine. This combination of a gas turbine and steam turbine power cycles produces electricity more efficiently than either a gas turbine or steam turbine alone. The higher exhaust temperatures of G- and H-class gas turbines offer the potential to raise supercritical steam in the HRSG, resulting in increased combined cycle efficiency. Materials for use in a supercritical HRSG are generally established. Liquid CO 2 -Coal Slurrying for Low-Rank Coals Future IGCC plants may recycle some of the recovered liquid CO 2 to replace water as the slurrying medium for the coal feed. Liquid CO 2 has a lower heat of vaporization and is able to carry more coal per unit mass of fluid. The liquid CO 2 -coal slurry will flash almost immediately upon entering the gasifier, providing good dispersion of the coal particles and potentially yielding dry-fed gasifier performance with slurry-fed simplicity. 9 7 Enabling Near-Zero Emission Coal-Based Power Generation, U.S. DOE/NETL, Turbine Program, June Brochure, September 2005; 8 Oluyede, E.O. and J.N. Phillips, Fundamental Impact of Firing Syngas in Gas Turbines, GT , Proceedings of ASME Turbo Expo 2007, May 2007, Montreal. 9 Program on Technology Innovation: Advanced Concepts in Slurry-Fed Low-Rank Coal Gasification: Liquid CO 2 / Coal Slurries and Hot Water Drying, EPRI, Palo Alto, CA:

53 IGCC Technologies Transitioning to the Commercial Era To date, CO 2 -coal slurrying has been demonstrated at pilot scale and has yet to be assessed in feeding coal to a gasifier, so the estimated performance benefits remain to be confirmed. 10 It will be necessary to update previous studies to quantify the potential benefit of liquid CO 2 slurries with IGCC plants designed for CO 2 capture. If there is a predicted benefit, a significant amount of scale-up and demonstration work would be required to qualify this technology for commercial use. Ion Transport Membrane for Lower Cost, Energy-Efficient Oxygen Production Oxygen for the gasification reactions can be provided either by air or high-purity oxygen. To obtain high-purity oxygen, IGCC units install an ASU that uses a cryogenic distillation process to produce 95% pure oxygen. The ASU adds to the plant s capital cost and results in parasitic power losses, but results in a syngas with a heating value up to twice that from an air-blown gasifier, in which the nitrogen in the air has the effect of diluting the syngas. In an oxygen-blown system, the nitrogen separated by the ASU can be used for power augmentation in the gas turbine. Separated nitrogen also can be used to convey coal, or as a stripping agent in the AGR process, or for purging and blanketing during outages. Ion transport membrane (ITM) is one of the technologies currently being developed as an alternative to ASU technology. The goal of ITM is a significant reduction in the power consumption and capital required to produce the oxygen required for the IGCC application (and potentially for oxy-fuel combustion). For an ITM unit, air is extracted from the combustion turbine, heated, and sent to the membrane where oxygen is separated for the gasifier. The non-permeate, vitiated air is returned to the combustion turbine. For IGCC, the oxygen would be compressed to the required pressure for the gasification process. Achieving the full benefits of ITM technology in IGCC applications requires integration with advanced gas turbines that can: Extract more than 50% of the gas turbine compressed air to supply the ITM system Accept the return of the non-permeate vitiated air stream from the ITM system Operate using syngas. Although currently available gas turbines may be limited with regard to one or more of the capabilities noted above, the technology developer projects that ITM still can result in a 7% reduction in the capital cost and 6% reduction in auxiliary power consumption compared with an IGCC cycle using a cryogenic ASU. CO 2 Capture for IGCC Units CO 2 can be separated from syngas by AGR, the same process used to separate sulfur species. 11 For slurry-fed gasifiers, the CO 2 in the syngas can represent 15-18% of the carbon that could be removed by adding a single-stage AGR process. This is the simplest approach to capturing some CO 2 from an IGCC unit, although it may not be the most cost-effective on a $/ton-co 2 -removed basis. Achieving higher levels of CO 2 capture will require adding a water-gas shift reactor prior to separation. This contains a catalyst that, in the presence of water, shifts carbon monoxide (CO) in the syngas to CO 2 and hydrogen: CO + H 2 O D H 2 + CO 2 11 Investigation of Low-Rank-Coal-Liquid Carbon Dioxide Slurries, EPRI, Palo Alto, CA: AP Although both sulfur species and CO 2 can be removed simultaneously, the resulting mixture of CO 2 and hydrogen sulfide will not be desirable in many instances. Separate AGR applications for sulfur species and CO 2 are likely to be more common for IGCC. 4-

54 IGCC Technologies Transitioning to the Commercial Era A single-stage shift reactor can achieve most of the CO conversion (80 85%). To achieve additional CO conversion requires additional shift reactors at increased capital cost. The CO 2 in the shifted syngas is removed via contact with the solvent in an absorber column, leaving a hydrogen-rich gas for combustion in the gas turbine. The water-gas shift reaction releases heat, which decreases the chemical energy contained in the syngas. Consequently, in order to supply the same fuel energy to the gas turbine after passing the syngas through a water-gas shift reactor, 5 10% more syngas would have to be produced. The heat released during the shift reaction can be used to preheat boiler feedwater for syngas saturation or to produce intermediate pressure steam. The water-gas shift option allows CO 2 capture to take place at the pre-combustion stage at elevated pressure, rather than at the atmospheric pressure of post-combustion flue gas, permitting capital savings through smaller equipment as well as lower operating costs. The impact of current CO 2 removal processes on IGCC plant thermal efficiency, net plant output, and capital cost is significant (see Figure 4-4). In particular, the water-gas shift reaction reduces the heating value of syngas to the turbine. Because the gasifier outlet ratios of CO to CH 4 to H 2 are different for each gasifier technology, the relative impact of the water-gas shift reactor process also varies. In general, however, it can be approximately a 10% fuel energy reduction No Capture Retrofit Capture New Capture Net Power Output, MWe GE Radiant Quench GE Total Quench Shell Gas Quench E-Gas FSQ Figure 4-4 Net Power Output for IGCC with and without Capture (Illinois #6 Coal) George Booras and Neville Holt, Review of New CoalFleet Engineering-Economic Evaluations, presentation at CoalFleet Technical Meeting, Tulsa, Oklahoma, April 16,

55 IGCC Technologies Transitioning to the Commercial Era Heat regeneration of solvents further reduces the steam available for power generation. Other solvents, which are depressurized to release captured CO 2, must be repressurized for reuse. Cooling water consumption increases for solvents needing cooling after regeneration and for pre-cooling and interstage cooling during compression of separated CO 2 to a supercritical state for transportation and storage. Heat integration with other IGCC cycle processes to minimize these energy impacts is complex and currently is the subject of considerable RD&D by EPRI and others. Hydrogen-Firing Gas Turbines When CO 2 is removed from syngas, the remaining gas consists primarily of hydrogen, which has combustion properties significantly different from those of syngas and natural gas. Although there is extensive commercial experience with hydrogen-rich fuel gas firing in gas turbines, most of this experience is for refinery gas in which methane is the other main component of the fuel gas, and the turbines are older, lower-firing- temperature gas turbines. 13 DOE s Turbine Technology RD&D Program is supporting two projects (one by GE 14 and one by Siemens 15 ) to design large-scale, high-temperature turbines capable of firing hydrogen-rich fuels. 16 Performance goals include the ability to integrate new systems into IGCC, fuel flexibility for operation using hydrogen and syngas, low-no X emissions, and efficiencies of 45-50%. GE currently offers its F-Class turbine for high-hydrogen fuels featuring diffusion flame technology and a diluent to limit NO X production. New Gasifier Designs Better Suited for CO 2 Capture The IGCC reference plant designs initially offered by the GE, ConocoPhillips, and Shell teams were positioned to compete with PC plants in the U.S. power market. The gasifier operating pressures selected were the minimum required to accomplish gasification, heat recovery, and gas clean-up. Since those initial offerings, however, the issue of CO 2 emissions has become a more dominant concern in the selection of new generation technologies. In response, those three IGCC suppliers have announced new features that will reduce capital costs and improve performance for CO 2 capture operation on an expanded range of coals: GE has acquired the exclusive rights to the Stamet solids feed pump. When fully developed, it should broaden the range of coals that can be used economically in GE gasifiers, particularly with the lower-cost, widely available low-rank coals. GE also plans to supply larger quench-type gasifiers with costs and output matching the fuel requirements of the gas turbines planned for use in IGCC applications. Quench-type gasifiers offer the most economical way of introducing moisture into syngas, which is required for the water-gas shift needed for CO 2 separation. Shell has announced the commercial offering of a partial water quench design that would eliminate the expensive syngas cooler while moisturizing the syngas upstream of the water-gas shift reactor, providing a lower-cost design option for plants capturing CO 2. Shell also is offering larger gasifiers that can supply the fuel needs of new, large 50-Hz gas turbines, which will provide further economies of scale. 13 Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change, Cambridge University Press, Jones, Bob (GE Syngas Power Island Technologies). Gas Turbine Fuel Flexibility for a Carbon Constrained World, Workshop on Gasification Technologies, Bismarck, North Dakota, June 28, 2006; technologies/coalpower/gasification/pubs/bizmark-2006/03rjones.pdf 15 Brown, P., Fadok, J., and Chan, P., Siemens Power Generation, Siemens Gas Turbine H 2 Combustion Technology for Low Carbon IGCC, 2007 Gasification Technologies Conference, San Francisco, CA, October 14-17,

56 IGCC Technologies Transitioning to the Commercial Era ConocoPhillips E-Gas gasifier s two-stage design allows flexibility in tailoring the syngas composition. For applications requiring CO 2 capture, ConocoPhillips has indicated that more water would be sent to the second stage of the gasifier to produce a syngas with more CO 2 and a higher H 2 O/CO ratio. ConocoPhillips also has indicated it is willing to design for higher operating pressures, which would improve the economics of physical solvents. 4-10

57 CO 2 Compression, Transportation, and Storage 5 CO 2 Compression, Transportation, AND Storage To successfully accomplish the goal of keeping power plant CO 2 out of the atmosphere for centuries or longer, the captured CO 2 can be compressed and injected into secure geologic formations. CCS offers the prospect of major reductions in atmospheric emissions of CO 2, particularly after By that time both capture and storage technologies may have matured, and associated legal and regulatory issues if given adequate investment, should have been resolved so that widespread deployment will become feasible. This chapter provides an overview of the post-capture side of the CCS equation, including technologies for purifying, drying, and compressing CO 2 ; the experience base and considerations for pipeline design; suitable geologic storage formations; the potential for revenue from sale of CO 2 to oil and gas producers; emerging regulatory regimes, and major ongoing research. Key Points For volumetric efficiency, CO 2 is transported and stored under pressure in a fluid-like supercritical state CO 2 transportation via pipelines is commercially established Energy requirements for CO 2 compression regardless of capture method are substantial Several large-scale CCS demonstration projects are under way Geologic storage capacity is large in many, but not all, areas Geologic storage has parallels in naturally occurring CO 2 storage sites, natural gas storage operations, and enhanced oil recovery (EOR) operations Site characterization and monitoring are critical to successful storage operations; oilfield technology gives researchers a good head start Unresolved barriers include regulatory, legal, and long-term liability issues. Addressing these issues will be critical on the path to commercialization. CO 2 Purification, Drying, and Compression Most commercial applications for long-term geologic storage will use CO 2 that has been compressed to become a supercritical fluid, a relatively dense phase that makes pipeline transportation and subsurface injection and storage more efficient. 1 The compressors required to raise CO 2 pressure to such a state are large, expensive, and consume significant amounts of power. With current technology, compression of the CO 2 produced by a PC plant may require as much as 8% of the plant s net power output. For a 1000-MW PC plant, the compression equipment may add about $150 million to the capital cost of the plant. For an IGCC plant, in which capture processes normally recover the CO 2 at various elevated pressure, the overall work required to compress the CO 2 to a supercritical state is lower (but still substantial at approximately 5% of the net plant rating). 2 1 The critical point of CO 2 is 1070 psia (74 bara) and 88 F (31 C), above which the gas and liquid phases become indistinguishable. 2 Technologies to Reduce or Capture and Store Carbon Dioxide Emissions, The National Coal Council,

58 CO 2 Compression, Transportation, and Storage The compressor will require heavy walls and strong mechanical components to contain the pressure, and stainless steel components to resist corrosion. To reach a typical overall compression ratio of 100:1, a centrifugal compressor would, for example, require about 8 handling steps (or stages ), with each one compressing the inlet gas by a ratio of about 2:1 before passing it to the next stage. Compression inherently raises CO 2 temperature (by as much as 200 F or 110 C per stage), and it is common practice to cool the CO 2 between stages to reduce the overall cost and energy requirements for compression. Such interstage cooling typically increases the overall number of plant cooling tower cells and overall cooling water requirements. For plants in arid locations using dry cooling, CO 2 compressor interstage cooling increases the number and cost of air-cooled heat exchangers. Given the expense of CO 2 compression and its potential impact on plant water demand, DOE is sponsoring several projects to explore compressor technologies that promise higher efficiencies and better integration with other plant subsystems to improve the economics of CO 2 compression. 3 The costs and choices for CO 2 compression equipment are related to the choices of generating and capture technologies. The requirements for any post-capture purification equipment also are linked to the plant and capture system type and to the final CO 2 quality specifications. In general, a capture technology that maximizes the pressure and purity of the CO 2 product from the capture system will minimize the costs of downstream purification and compression equipment. Processes that produce CO 2 at lower temperatures also can help modestly reduce compression costs. CO 2 drying and purification processes may be integrated with the compression process (or other plant systems) to economize on the space and power requirements. CO 2 from some capture processes may contain impurities that, without an added purification step, would rapidly corrode pipeline, injection well, and possibly compressor component materials. Trace gases affect the minimum miscibility pressure of the CO 2, leading to lower recovery of oil, or requiring application of EOR to deeper fields. To prevent such issues, water, oxygen, and other contaminants normally are removed in conjunction with CO 2 compression. Impurities also may affect compression requirements by raising the effective critical point, by perhaps 50% to 1600 psi (110 bar), 4 requiring a higher-powered compressor. In practice, however, this may not be problematic because commercial pipelines may require an inlet pressure of 2000 psi (140 bar) or more. CO 2 from pre-combustion physical solvent scrubbing processes may contain about 1 2% H 2 and CO, as well as traces of hydrogen sulfide and other sulfur compounds. In some applications (e.g., a dedicated pipeline for enhanced oil recovery), IGCC plants can be designed to produce a combined stream of CO 2 and sulfur compounds, which reduces capture costs and avoids the production of solid sulfur. Most IGCC plant designers, however, are planning for commercial CO 2 sale or injection specifications that require very low levels of H 2 S and other sulfurous compounds. For post-combustion recoverable solvent -type capture processes (e.g., amine-based), the CO 2 produced by the capture system typically will be at a high level of purity. Plant designers normally will have ensured that most SO 2, NO X, mercury, and other impurities are removed from the flue gas before it reaches the absorber vessel, in order to limit solvent make-up costs. The CO 2 then may require only a dewatering/dehydration process to remove most of the remaining water vapor to meet quality specifications Technologies to Reduce or Capture and Store Carbon Dioxide Emissions, The National Coal Council,

59 CO 2 Compression, Transportation, and Storage The equipment required for CO 2 purification may be greatest for oxy-combustion boiler applications. The exhaust flue gas from an oxy-fuel process typically contains (in addition to CO 2 ) moisture, nitrogen, oxygen, and trace amounts of other species such as SO 2 and NO X. If the receiving pipeline or geologic formation cannot accommodate contaminants, they must be reduced in conjunction with the compression process. The approach currently favored involves a cryogenic purification process. CO 2 Transportation Mapping the distribution of potentially suitable CO 2 storage formations across the United States and portions of Canada, as part of the research by DOE s Regional Carbon Sequestration Partnerships program, shows that some areas have ample storage capacity while others appear to have little or none. Thus, storage of carbon from some power plants may require transportation for several hundred miles to suitable injection locations, possibly in other states or provinces. CO 2 may be transported in trucks, trains, ships, and barges; however, for the large quantities of CO 2 involved in CCS, pipelines likely are the most economic mode of transportation. The technical, economic, and permitting aspects of CO 2 pipeline transport are well understood in the United States, where CO 2 pipelines currently extend over more than 3500 miles (5600 km), carrying 50 Mt/yr of CO 2 from natural sources to enhanced oil recovery projects in west Texas, New Mexico, and Wyoming. Pipeline transport for CCS may require a minimum specification for purity of the CO 2 to prevent pipeline corrosion and reduce hazards in the event of an accidental release. The design of corrosionresistant pipelines that could operate safely while conducting a less pure stream of CO 2 also is an option. However, depending upon the length of the pipeline, the costs of corrosion-resistant materials are potentially higher than the costs of purifying the CO 2. 5 Although routing new pipelines through populated areas may prove difficult and time-consuming, there is no indication that the problems for CO 2 pipelines will be any more challenging than those posed by hydrocarbon pipelines in similar areas. In some places, it may be possible to convert existing hydrocarbon pipelines to CO 2 pipelines. 6 EPRI expects that early commercial CCS projects will take place at coal-based power plants near sequestration sites or an existing CO 2 pipeline. Three of the four final sites considered for the original FutureGen project offered sequestration opportunities. As the number of CCS projects increases, regional CO 2 pipeline networks connecting multiple industrial sources to storage sites will be needed to service CO 2 point sources that do not overlie sequestration sites or have other options for CO 2 disposal. CO 2 -Based Enhanced Oil and Gas Recovery Experience relevant to geologic carbon sequestration comes from the oil industry, where CO 2 injection technology and modeling of CO 2 subsurface behavior have a proven track record. EOR has been conducted successfully for 35 years in the Permian Basin fields of west Texas and New Mexico. Regulatory oversight and community acceptance of injection operations for EOR seem well established. 5 Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change, Cambridge University Press, New York, Ibid. 5-

60 CO 2 Compression, Transportation, and Storage Figure 5-1 Injection of CO 2 for Enhanced Oil Recovery (EOR) with Some Storage of Retained CO 2 7 In CO 2 -EOR, supercritical CO 2 flows through permeable strata to contact residual oil that is dispersed in the pore spaces between sand grains and other materials. The CO 2 effectively dilutes and swells the oil and sweeps it from the pore spaces through the strata to the production wells (Figure 5-1). Although the purpose of EOR is to increase oil production, the practice can be adapted to include CO 2 storage opportunities. This approach is being demonstrated in the Weyburn-Midale CO 2 monitoring projects in Saskatchewan, Canada. 8 The Weyburn project uses captured and dried CO 2 from the Dakota Gasification Company s Great Plains synfuels plant near Beulah, North Dakota. The CO 2 is transported via a 200-mile pipeline constructed of standard carbon steel. Over the life of the project, the net CO 2 storage is projected to be 20 million metric tons, while an additional 130 million barrels of oil will be produced. The economic value of EOR with CCS represents an excellent opportunity for initial geologic sequestration projects like Weyburn. Next generation CO 2 -EOR processes could boost U.S. technically recoverable oil resources by 160 billion barrels. 9 Long-Term Geologic Storage Geologic sequestration of CO 2 is being demonstrated in multiple projects worldwide. Together with the Weyburn project mentioned above, two other relatively large projects Statoil s Sleipner Saline Aquifer CO 2 Storage project in the North Sea off of Norway 10 and the In Salah Project in Algeria 11 sequester a combined 3 to 4 million metric tonnes of CO 2 per year, which approaches the output of a baseload 500-MW coal-fired power plant. Statoil estimates that Norwegian GHG emissions would have risen incrementally by 3% if the CO 2 from the Sleipner project had been vented rather than sequestered. 7 Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change, Cambridge University Press, New York, 2005; Figure 5.15, Page In Salah Project, IEA RD&D Projects Database; php?project_id=71 5-