Advancing Technology for

Transcription

1 Advancing Technology for Phase IV, Final Report

2 Canadian Clean Power Coalition Advancing Technology for Cleaner Power The Canadian Clean Power Coalition (CCPC) is an association of responsible, leading Canadian and U.S. electricity producers that believes coal, along with a diverse mix of fuels like hydro, natural gas, wind, solar and nuclear, will play an important role in meeting the energy needs of the future. Table of Contents The progress and achievements of CCPC are due in large part to the continued support of Alberta Innovates and Saskatchewan Energy and Resources. Key Achievements of the CCPC 01 Executive Summary 02 The Case for Coal 03 CCPC Members 04 Phase I 05 Phase II 07 Phase III 09 Phase IV 12 Phase V Next Steps 14 The CCPC s Impact Member Projects 16 The CCPC s Impact Collaboration 18 Sharing Our Findings 20 Appendix A: Coal Beneficiation A01 Appendix B: Biomass Co-firing B01 Appendix C: In-situ Coal Gasification C01 Appendix D: Advanced Cycles D01 Appendix E: Post Combustion Advanced CO 2 Capture E01 Appendix F: Advanced IGCC Partial Carbon Capture F01 Appendix G: CanmetENERGY G01

3 The CCPC s mandate is to research technologies with the goal of developing and advancing commercially viable solutions that lower emissions from coal-fired power plants. The CCPC aims to find ways to generate electricity from coal that effectively and economically address environmental issues including carbon dioxide (CO 2 ) emissions and move us forward to a cleaner energy future. To-date, the CCPC and its members have spent more than $50 million furthering this objective. Key Achievements of the CCPC Provided early leadership to study carbon capture and storage (CCS) on coal plants Inspired industry to develop several CCS projects Established that significant advances and development will be required to reduce the cost of CCS before CCS will be widely adopted Accelerated understanding of cleaner coal technologies, and developed the most extensive collection of Canadian technical and economic information on the subject Sponsored the first Front-End Engineering and Design (FEED) study on integrated gasification combined cycle (IGCC) with carbon capture in Canada, and determined that low-ranked coals have a detrimental impact on IGCC costs Determined that CCS technology is expensive and requires significant cost reductions before it will be widely adopted Canadian Clean Power Coalition 01

4 Executive Summary In the past three years, the CCPC has learned about promising ways to potentially help coal plants reduce their CO 2 emissions in the future. This work may help members justify extending the life of their plants. In addition, some of the technologies considered may also lead to the development of new coal plants with partial capture should gas prices increase. The following is a short summary of the key results from studies completed in Phase IV. Advanced Cycles The Electric Power Research Institute (EPRI) completed a study reviewing more than a dozen advanced cycles for burning coal. Several of these cycles will be studied in more detail in the repowering project to be completed in Phase V. In addition, this study helped the CCPC make the decision to commit funds for Aerojet Rocketdyne-Oxy s PFBC demonstration project being conducted at Canmet. In-situ Coal Gasification This million-dollar study showed that in-situ coal gasification with partial CO 2 capture has a levelized cost of power estimated to be similar to that of a natural gas combined cycle plant operating baseloaded. There are opportunities to further optimize the plant to lower costs. This technology may be a promising way to take advantage of huge underground coal deposits in Western Canada should the price of natural gas increase. Coal Beneficiation Four coals were studied to determine if coal beneficiation would lead to half a dozen desired outcomes related to ash removal. It is not clear that the benefits of coal beneficiation exceed the costs. However, as Western Canadian mines age, poorer seams of coal may be employed, making coal beneficiation more atrractive. Advanced Post Combustion Capture EPRI reviewed 20 novel non-aqueous post combustion capture technologies. Several of these technologies look promising and may be studied in more detail in Phase V. The CCPC has been meeting with technology developers to hear more details regarding their technologies. Fuel Cell Repowering Molten carbonate fuel cells can be used to capture CO 2 and provide additional low emission power. Costs provided by Jacobs suggest that this technology may have a relatively low avoided cost. The cost of electricity retrofitted with molten carbonate fuel cells appears to be similar to a new natural gas combined cycle. This study will be completed in Phase V. Biomass Co-firing This study considered the cost of providing biomass to three plants in Canada. The avoided cost of CO 2 for biomass co-firing is generally expected to be less than that for post combustion capture. This makes it an ideal candidate for repowering coal plants if one does not wish to invest a large amount of money on CO 2 capture infrastructure. Co-firing natural gas and biomass also looks promising, particularly if volumes of biomass are insufficient to fire the plant. More work is required to better understand biomass availability and the costs to modify a coal plant to accept large volumes of biomass. IGCC with Partial Capture The CCPC commissioned Jacobs to complete one of the first studies that examined six novel configurations of CO 2 partial capture on IGCC plants. The results suggest that IGCC with partial capture may have a cost of power similar to a coal plant with partial CO 2 capture. All of the novel configurations considered also had power costs much lower than IGCC plants with full CO 2 capture. 02 Canadian Clean Power Coalition

5 The Case for Coal Coal is vital for electricity generation in Canada and internationally because it is a low-cost fuel with large proven reserves. Coal is used in roughly 10,000 MW of power plants in Canada and these plants provide cheap baseload generation. In Canada alone, there are an estimated 80 billion tonnes of proven reserves, one of the world s largest deposits and a natural resource advantage that should provide power a thousand years into the future. The industry also provides significant employment and an overall positive economic impact. Air quality issues associated with coal must be addressed. Technology will provide long-term solutions to emissions issues. The CCPC is committed to finding those solutions. Organizations such as the CCPC play a role in leading the way to cleaner power generation through partnerships between government and industry. Canada has an estimated eight billion tonnes of proven coal reserves. This resources is primarily accessed through mining, using massive, specialized equipment. Canadian Clean Power Coalition 03

6 The CCPC s membership includes responsible, leading Canadian and U.S. electricity producers. CCPC Members The CCPC s membership includes responsible, leading Canadian and U.S. electricity producers. The CCPC is always interested in expanding membership and collaborating with other entities to further our objectives. CCPC s members represent the majority of Canada s coal-fired power generation capacity. The coalition was formed out of concern about greenhouse gas emissions, and to collectively evaluate strategies for emission reductions. Phase IV CCPC Members Alberta Innovates Energy and Environment Solutions Capital Power Corporation Nova Scotia Power SaskPower Sherritt International Corporation TransAlta Corporation Associate Member The Electric Power Research Institute (EPRI) Support and Additional Funding CanmetENERGY Saskatchewan Ministry of Energy & Resources Former Members ATCO Power Luscar Limited Ontario Power Generation IEA Greenhouse Gas Programme IEA Clean Coal Centre Basin Electric Collaborative Members Coal Association of Canada ICO 2 N Lignite Energy Council Capital Power Corporation 04 Canadian Clean Power Coalition

7 Phase I At-A-Glance Timeframe: 2001 to 2004 Goal: To evaluate existing or developing technologies Budget: $4.8 million Key Findings: Substantial detail regarding existing and emerging technologies A Phased Approach The CCPC was created in 2000 to ensure that environmental public policy decisions recognize Canada s vast coal resources as an important Canadian asset. Today, the CCPC is advancing the technologies needed to build cleaner, more efficient, more economical coal-fired power plants. Phase I, which involved study of emerging technologies to reduce emissions from coal plants, commenced in The CCPC is currently completing its fourth phase of study and Phase V is scheduled to commence in fall Overview The first study work undertaken by the CCPC commenced in September The goal was to develop projects that demonstrated technology at a commercial utility scale that would allow all emissions, including CO 2, to be controlled to meet all foreseeable new regulatory requirements. The technology had to be viable for retrofitting existing plants, or for use in new coal-fired power plants. Emissions had to be reduced to a point that would allow coal-fired plants to be seen in a new light. Overall efficiency had to be maintained or improved, and costs had to remain competitive with other generation technologies. The fundamental principle underlying the goals of the CCPC was to identify processes that would produce electricity from coal in some fashion and also provide a relatively pure stream of CO 2 that could be captured, further processed as necessary, and subsequently used or stored. Conceptual engineering and feasibility studies, undertaken from mid-2001 to early 2004, were performed on the following: Technologies in development for common coalfired plant emissions, including nitrous oxide (NOx), sulphur dioxide (SO 2 ), particulates and mercury. The opportunities to capture CO 2 emissions from industrial sources and transport them to underground storage. Gasification: reacting raw material, such as coal, at high temperatures with a controlled amount of oxygen and steam. CO 2 can be removed from the resulting syngas fuel. Oxyfuel: based on the principle that if coal burns in an environment where nitrogen is absent or minimized, the resulting CO 2 will be more concentrated and therefore easier to capture. Amine scrubbing: a process where CO 2, in a flue gas, is absorbed and captured. The opportunities to store CO 2 in Canada. Canadian Clean Power Coalition 05

8 Post-Combustion Capture Nitrogen Carbon Dioxide Rich Amine Absorber Lean Amine Stripper Steam Flue Gas Implementation plans, preliminary designs and cost estimates were developed for those technologies, recognizing the diverse geographical variability of coal in Canada. The CCPC s Phase I budget was $4.8 million, $2.1 million of which was provided by participants. The remainder was provided by Canadian governments. Phase I Results Developing Emission Reduction Technologies Research showed that technologies were either available or under development to control NOx, SO 2, particulates and mercury emissions from coal-fired power plants to levels approaching that of natural gas power generation. Gasification Gasification was shown to be a potentially low cost CO 2 capture technology; however, gasification requires significant development to improve availability. Gasification is a mature technology in the chemical and petrochemical industries, but is not mature for power plant applications using sub-bituminous and lignite coals as a feed stock. Oxyfuel Oxyfuel technology is not yet mature and many issues need to be resolved prior to full scale deployment. Any application of the technology to an existing power plant would be expensive and could involve significant operational problems. At the time of the study oxyfuel appeared to be a less cost effective way to produce power and capture CO 2. Amine Scrubbing The study suggested that amine scrubbing technology provides the greatest opportunity for a demonstration project in that it is a mature technology in its own right, and has fewer issues to satisfy before one could develop a high degree of confidence of success. It also has the advantage of potentially being able to be applied as a retrofit to an existing facility. It can be scaled to process between zero and 100 per cent of a flue gas stream. The study showed that it may offer lower costs of electricity and CO 2 capture and the lowest risks compared to the technologies considered. In addition, it provides the opportunity to design and construct a plant in which the amine process could be de-coupled from the power generation plant, and provide the greatest operational flexibility should significant problems be encountered with the process. CO 2 Storage The Western Canada Sedimentary Basin provides storage capacity for a vast amount of CO 2 in British Columbia, Alberta and Saskatchewan. Storage opportunities and capacities for the Ontario and Maritime regions are less understood. Transportation and storage of CO 2 is also a challenge to a demonstration project. The reports suggest that enhanced oil recovery and geological storage are the best options, and that these choices are available principally in Western Canada. 06 Canadian Clean Power Coalition

9 Phase II At-A-Glance Timeframe: 2004 to 2007 Goal: To complete in-depth studies of top viable CCS technologies Budget: $2.6 million Key Findings: Amine scrubbing and oxyfuel processes showed improvement but capture costs were prohibitive; improvements in gasification positively impacted the cost of capture compared to Phase I Overview Phase I of the CCPC efforts identified promising CCS technologies and benchmarked the performance capabilities of each. Phase II was undertaken to gather more information through the detailed study of the most viable technologies. The goal was to study commercial or near-commercial technologies to better understand their design and costs. Ranks of Coal ANTHRACITE BITUMINOUS SUB-BITUMINOUS Increasing Carbon Phase II was initiated in 2004 and was completed in Two major areas of work were undertaken: Supercritical Pulverized Coal (SCPC) Plants with CO 2 Capture An assessment of both amine scrubbing and oxyfuel combustion processes. LIGNITE Phase II Results The type of coal used affects the performance of any technology. Gasification Technology Optimization Stage 1 Assessed IGCC technologies that were suitable for low-rank coals. Stage 2 Assessed feedstock blending as well as optimized electrical power and hydrogen production to improve the value of gasification. The gasification technologies selected were next generation technologies not commercially available. The budget for Phase II was $2.6 million, $1.4 million of which was provided by participants. The remainder was provided by various Canadian governments. There are no commercial-scale amine scrubbing, oxyfuel or IGCC plants with CCS operating on coal; as a result, CCS technologies are fairly immature. The technologies studied in Phase II were at different stages of development, making accurate comparisons challenging. Nevertheless, it was determined that the costs of all technologies studied are high. Additionally, the type of coal used and site specifics impact the technology choice for any given project. Therefore, detailed site-specific studies must be completed to make a final technology selection. For these reasons, further development of a wide variety of technologies was recommended. Canadian Clean Power Coalition 07

10 Phase II studies showed that further development of a wide variety of technologies is needed. CCPC Phase II Cost of Power Comparisons CCPC Phase II Capture Cost First Year Cost ($/MWh) Capture Cost of CO 2 ($/T) PC Reference Plant Amine Scrubbing Oxyfuel IGCC Capture Amine Scrubbing Oxyfuel IGCC Capture Polygen This study showed that adding CO 2 capture would increase the costs of power by more than 50 per cent. The cost of capture is expected to exceed $80 per ton. SCPC with CO 2 Capture Further optimization of the amine scrubbing and oxyfuel processes showed significant improvement over the results from Phase I; however, capture costs were high. Mandated greenhouse gas (GHG) compliance costs would need to be greater than $80 per tonne before CCS would be implemented. Gasification Gasification performance is dependent on coal quality, with lignite presenting the greatest challenge. Since this study, improvements in gasification processes for low-rank coals have reduced the cost of CO 2 capture. IGCC costs were higher than the other technologies studied this was unexpected given results from other recent studies. Since IGCC cases were for next generation technologies, the cost estimates may not be comparable to other cases studied. Additionally, the economics of gasification were improved by selling hydrogen rather than just power. 08 Canadian Clean Power Coalition

11 Phase III At-A-Glance Timeframe: 2008 to July 2011 Goal: To study new advances and technologies Budget: $6.7 million plus $11 million for Capital Power IGCC FEED study Key Findings: Shared Fall 2011 Overview Phase III involved the detailed study of new CCS advances and other ways to reduce the CO 2 emissions from coal plants. Five final reports containing results from phase III can be found on the CCPC website Cost of Energy for IGCC Cases with Capture IGCC FEED The CCPC, in partnership with Alberta Innovates (formerly AERI), Natural Resources Canada and Capital Power Corporation provided $33 million to conduct a FEED study to determine the feasibility of developing an IGCC facility with CCS at Capital Power s Genesee facility. The study detailed the design, technology, engineering and economic requirements to build a commercial-scale facility at the site. The study showed the cost to produce power from this configuration, at this location, was $9,500 per kilowatt or $266 per megawatt hour. First Year Cost ($/MWh) SCPC Ref Cap FEED Siemens 500 n Total CO 2 Sales Siemens 1,000 SES U-Gas PWR TPRI n Net Cost of Energy IGSC Advanced Gasification Studies Feasibility studies of 10 optimized schemes to capture CO 2 from state-of-the-art sub-bituminous coal IGCC and polygen plants have been completed. The design, costs, risks and other benefits of these technologies was considered. The gasification technologies studied include: Three 500 megawatt (MW) Siemens gasifiers (base case) Two 1,000 MW Siemens gasifiers The SES U-Gas gasifier The Pratt & Whitney Rocketdyne gasifier China s TPRI GreenGen technology Jacobs Integrated Gasification Steam Cycle (IGSC) This study showed the first year cost of energy for various IGCC cases with capture are significantly greater than a supercritical pulverized coal (SCPC) without capture. Case Studies Retrofit and greenfield cases Polygeneration cases to produce power and hydrogen for comparison to hydrogen production from a steam methane reformer with and without CO 2 capture Canadian Clean Power Coalition 09

12 Carbon capture is seen as a means to reduce the emissions produced through coal combustion. First Year Cost ($/t h2) 6,000 5,000 4,000 3,000 2,000 1,000 Cost of Producing Hydrogen With and Without CO 2 Capture SMR Ref no CCS CCPC II Polygen SMR 50% Cap. Polygen SMR 90% Cap. The cost of hydrogen production from polygen with CCS is not competitive with steam methane reformers with CCS. CCS Research The CCPC has participated in a gasification research program carried out by CanmetENERGY. In turn, Canmet has provided bench-scale and pilot-scale experimental data and modeling results for entrained flow slagging gasification of Canadian coals. The research included the gasification characteristics of various fuels, and a bench-scale oxyfuel circulating fluidized bed combustion study employing calcium oxide to capture CO 2. A new high-pressure dry feed system, warm and hot gas clean up and coal beneficiation were studied to improve gasifier efficiency. Simulations were conducted to look for breakthroughs in process efficiency and environmental performance. Models of gasifier components have been created to support scale-up to commercial implementation, and to find process improvements. Coal Cleaning Technology Coal cleaning is seen as a means to reduce the emissions produced through coal combustion. A comparative study has been completed to test raw as-received coal and beneficiated coal using gasification test facilities at CanmetENERGY as part of their gasification research program. Beneficiated coal samples from several Alberta and Saskatchewan coal beds were produced at Sherritt s Clean Coal Technology Centre. 10 Canadian Clean Power Coalition

13 The CCPC was established to research commercially viable technologies that will lower coal-fired power plant emissions. EPRI Post-combustion CO 2 Capture Retrofit Studies The CCPC is participating in an Electric Power Research Institute project that is studying retrofitting five power plants, including one in Nova Scotia, with advanced amine CO 2 capture technology. The study determined the thermal and economic impact of retrofitting and the technological barriers and limitations associated with each site. This project was completed in the summer of Biomass Use Evaluation The CCPC participated in a Nova Scotia Power research project to evaluate the potential for co-firing biomass with coal in power plant boilers to achieve cost effective CO 2 reductions. Both laboratory combustion tests and engineering studies of typical utility boiler systems have been completed. IGCC Roadmap The CCPC undertook a study conducted by EPRI CoalFleet Program staff, consisting of an engineering and qualitative economic evaluation of technological advances in processes involved in gasification including: coal preparation and feeding beneficiation, drying and feeding improvements oxygen production ion transport membranes syngas processing and CO 2 capture warm gas clean up, hydrogen (H 2 ) membranes, various novel CO 2 capture processes, and CO 2 purification the effect of increases in turbine firing temperatures developments on gas and steam turbines The base case for this study will be a 500 MW Siemens gasifier fired on Alberta sub-bituminous coal. An evaluation of the impact of individual and combined technologies advances on the base case were considered. An assessment of the development status of these technologies was produced. Biomass Co-firing KEMA Consulting has completed a study of various technologies that can be used to complete modest and significant co-firing of biomass fuels in a coal boiler. The study reviewed the characteristics of various biomass feedstocks and also describes capital costs and configurations for six co-firing and feedstock configurations. It recommended configurations for further study. Coal Beneficiation Sherritt completed a study on the costs, benefits, risks and status of several dozen coal beneficiation technologies. EPRI also looked at the economic benefits of reducing specified amounts of ash and moisture for several coals. The budget for Phase III was $6.7 million, $2.0 million of which was provided by participants. It included $2.5 million of work in kind with CanmetENERGY and the remainder was provided by various Canadian governments. Phase III also included the provision of $11 million to Capital Power s $33 million IGCC FEED study. The $11 million was provided by Alberta Innovates (formerly AERI). Canadian Clean Power Coalition 11

14 Phase IV At-A-Glance Timeframe: 2011 to 2014 Goal: To study new partial CO 2 capture options to meet new Canadian coal regulations Budget: $6.3 million Key Findings: To be shared in the Fall of 2014 Overview Near-term technologies included: The CCPC was established to research commercially viable technologies that will lower coal-fired power plant emissions. Phases I through III of the CCPC s studies have advanced the understanding of available and emerging technologies, their limitations and benefits. Phase IV had two cleaner coal study themes: Near-term technologies: retrofit and greenfield technologies that will be commercially available within 10 years New transformative technologies: designs that might be available for the new greenfield coal fleet in 2020 Near-term Technologies It is anticipated that the technologies the CCPC classified as near-term will have a low impact on power costs and be broadly applicable across the coal fleet. This study increased our confidence that these technologies will perform as expected and increased our knowledge of technologies that have not yet been extensively studied. Coal Beneficiation During this project, four coals were beneficiated using float sink processes. The data collected was used to understand how commercially available coal beneficiation technologies would likely perform on these coals and what the technical and economic benefits might be. For more details, see Appendix A. Biomass Co-firing FP Innovations focused on identifying the costs and volumes of various kinds of biomass at three plant locations in Canada. The cost of biomass with or without natural gas co-firing is likely significantly lower than post-combustion capture options and might be a viable way to extend the life of coal plants, particularly for periods of five to 10 years. The prices for most forms of biomass are likely too high to consider co-firing in the short term given prevailing carbon taxes. For more details, see Appendix B. In-situ Coal Gasification Alberta Innovates Energy and Environment Solutions, Sherritt and the CCPC funded a $1 million study evaluating several underground gasification technologies for the production of syngas. The study assessed the cost of producing this syngas and using it to produce power, Fischer-Tropsch (FT) liquids and fuel for boilers. The power configuration employed carbon capture to meet the GHG emissions requirements. For more details, see Appendix C. 12 Canadian Clean Power Coalition

15 Phase IV had two cleaner coal study themes: Near-term technologies and new transformative technologies. New Transformative Technologies New coal fleet technologies were defined as those that are designed to more economically reduce CO 2 emissions. They were in early stages of design, had lower capture costs and had broad application potential. They were also designed to meet GHG regulatory requirements. New transformative technologies included: Advanced Cycles EPRI looked at the comparative advantages and disadvantages of a dozen advanced cycles for combusting coal with lower emissions. Many of these cycles may be attractive options for building new coal plants and for retrofitting existing coal plants. For more details, see Appendix D. Advanced Post-combustion Capture EPRI evaluated 20 promising non-aqueous post-combustion capture technologies. These technologies were chosen because they may hold the promise for significantly reducing the cost of carbon capture in the future. For more details, see Appendix E. IGCC Partial Capture Jacobs completed this first-of-its kind study to evaluate several IGCC configurations employing partial capture of CO 2. The cost of power and the capture cost of CO 2 from IGCC with partial CO 2 capture was found to be significantly lower than IGCC with full CO 2 capture and comparable to the cost of a super-critical coal plant with partial CO 2 capture. For more details, see Appendix F. CanmetENERGY Task Share CanmetENERGY completed the following tasks: 1) Determined gasification characteristics of Canadian coals and petroleum coke. 2) Developed and tested gasifier component designs and materials. 3) Investigated methods for improving gasification power plant efficiency firing high ash coals. 4) Determined the efficiency and environmental performance of calcium and chemical looping systems for hydrogen, steam and power production. 5) Created computational fluid dynamics models of gasifier injectors, reactors and quench systems for technology scale-up and for process improvement. 6) Developed and tested regenerable solid CO 2 sorbents. For more details, see Appendix G. Canadian Clean Power Coalition 13

16 Phase V Next Steps Timeframe: 2014 to 2016 Goal: To identify ways to extend the life of existing coal plants and to build new coal plants while meeting emission limits Budget: $8.5 million Fuel Cell Repowering Jacobs has been commissioned to work with Fuel Cell Energy, Inc. to study the feasibility of using molten carbonate fuel cells to capture CO 2 from an existing coal plant in Nova Scotia while producing power. Initial results indicate that this approach may have a low cost of CO 2 capture and a low incremental cost of power. This work may be used to help justify funding a pilot plant. Coal Repowering EPRI will evaluate several ways to repower existing coal plants. These options may require removing large portions of the plant and installing more advanced cycles. Fuel switching to natural gas and biomass may be evaluated. Making an Additional Commodity This study will review up to a dozen options for using coal in a greenfield plant to produce both power and some other commodity. Coal could be used as a feedstock directly. Heat, steam and/or electricity could be used to support the production of another commodity such as pyrolysis products, FT liquids, fertilizers, fuels and chemicals. The objective is to find ways to continue to use coal with less reliance on power as an end product. Greenfield Studies In Phase IV, EPRI reviewed a few novel cycles that may hold promise for future development. This study builds on previous work by the CCPC. Small high efficiency biomass co-fired plants, closed Brayton cycles, etc. have been proposed. The objective is to select a few ideas for techno-economic evaluation. Novel Carbon Capture Option In Phase IV, the CCPC commissioned EPRI to review 20 novel post-combustion carbon capture options. If some of these options, or other options, look promising, the CCPC may study them in more detail. The objective is to find options that could be used to extend the life of coal plants. Demonstrating Coal Beneficiation If promising technologies are likely to yield economic benefits, the CCPC may fund the testing of several coals in coal beneficiation test facilities. Demonstrating Biomass Co-firing The CCPC may help fund efforts to test fire biomass in an existing Canadian coal plant. 14 Canadian Clean Power Coalition

17 The feasibility of using molten carbonate fuel cells to capture CO 2 from an existing coal plant in Nova Scotia while producing power is being studied. Lower Temperature Heat Recovery CanmetENERGY has been developing condensing heat exchangers that could be used to condense water and a significant amount of air emissions out of flue gas while providing heat that could be used for other purposes, such as in an organic Rankine cycle. The objective for the CCPC will be to determine whether this technology can reduce mercury and sulfur emissions while providing water and possibly useful heat. NOx and SOx Due Diligence This study will review the various new and novel ideas to reduce NOx and SOx by having a credible third party perform due diligence on them. The objective is to identify promising new lower costs options to reduce NOx and SOx so companies can study them in the context of their current plant emissions. Aerojet Rocketdyne-Oxy PFBC Demo The CCPC plans to contribute $300,000 to Aerojet Rocketdyne s demonstration of their Oxy Pressurized Fluidized Bed Combustion (PFBC) technology at CanmetENERGY in Ottawa. Aerojet plans to test two coals provided by the CCPC. The CCPC will have access to the final results for this project. Canmet Task-Share Work CanmetENERGY will develop pressurized chemical looping combustion for production of H 2, steam and power using a naturally occurring oxygen carrier, ilmenite, in a small pilot. CanmetENERGY will work towards developing gasification systems for hydrogen, power, synthetic natural gas (SNG), clean liquid fuels and chemicals production at ultra-high efficiency. The oxy-pfbc program will result in the construction and operating of a 0.25 to 1.0 MWth pressurized pilot-scale facility with oxygen firing using petcoke and coals to produce steam and power. Canadian Clean Power Coalition 15

18 Antelope Valley Station Boundary Dam Power Station Project Pioneer s generating station, Keephills 3 The CCPC s Impact Member Projects The CCPC s member companies use the research conducted by the organization to advance their own environmental performance. Read on for examples of the CCPC s research at work. Antelope Valley Basin Electric worked with HTC Purenergy and Doosan Babcock to complete a $6.2 million FEED study on post-combustion capture at the 450 MW Antelope Valley Station. Had the project proceeded it would have captured approximately one million tons of CO 2 per year from a portion of the plant s exhaust stream and sent it to oil fields in Saskatchewan to be used in existing enhanced oil recovery operations. Boundary Dam The Boundary Dam Integrated CCS Project came online in 2014 as one of the world s first and largest CCS projects on a coal-fired plant. Unit 3 of Boundary Dam power station was scheduled to reach the end of its useful life soon, but a rebuild and retrofit with carbon capture technology will extend its lifespan by decades. Once fully operational, SaskPower s capture facilities will be able to capture up to one million tonnes per annum of CO 2 that will be sold for enhanced oil recovery projects or stored deep underground at the organization s Carbon Storage and Research Centre. Construction began in Commissioning of all parts involved is currently taking place. This project represents more than 4.5 million man-hours of work, approximately half of the man-hours that went into the construction of the CN Tower in In 2013, SaskPower officially retired Unit 1 to meet federal carbon dioxide regulations. The new rules called for coal-fired units that have been operating for 50 years or more to either meet new emissions standards by July 1, 2015 or shut down. Unit 2 will follow suit in Retrofitting these units in time to meet the new regulations was not deemed economically feasible. Project Pioneer TransAlta and various partners undertook a worldscale CCS demonstration project designed to capture one million tonnes of CO 2 per year at its Keephills 3 generating station west of Edmonton. A full front-end engineering study was carried out assessing the technical and economic feasibility of several capture technologies. The company s interest in CCS was founded in part on the CCPC s Phase II studies. Unfortunately, the project was cancelled in 2012 due in part to regulatory uncertainties and market demand for CO 2 for enhanced oil recovery (EOR) injection. 16 Canadian Clean Power Coalition

19 Mock-up of an IGCC facility at Capital Power s Genesee plant IGCC FEED Capital Power Corporation, along with the federal and Alberta governments, funded a FEED project to determine the feasibility and cost of developing a commercial-scale coal-fuelled gasification power plant with CCS. Nova Scotia Power Nova Scotia Power is studying the use of biomass from sustainable resources for co-firing in both CFB and pulverized coal plants. CCS Nova Scotia, whose members include Nova Scotia Power, is preparing plans to build a CCS pilot plant with the outlook of a commercial scale project by Sherritt International Sherritt has studied underground coal gasification and also recently completed a coal cleaning laboratory in Fort Saskatchewan. The project, partially funded by Alberta Innovates, tested various techniques to determine the optimal coal cleaning technology. Both beneficiated and non-beneficiated coals have been assessed by CanmetENERGY to determine impacts on plant performance. Sherritt also developed the Dodds-Roundhill IGCC project. Canadian Clean Power Coalition 17

20 The CCPC s Impact Collaboration The CCPC, through its membership and ongoing research, fosters a collaborative and cooperative approach to advancing technology across Canadian industry. Along with sharing of research, CCPC represents its members on various other organizations. This ensures a comprehensive two-way flow of information, thereby allowing more efficient and effective advancements within individual organizations. Government and other funding ensures this work continues. Vendor Access to Industry Broad access to industry can be challenging. Through the CCPC, technology vendors are able to present technologies and projects to the CCPC technical committee, fostering learning and allowing for industry support of new initiatives. Research Collaboration The body of research that needs to be undertaken is vast. The CCPC serves as a central point through which studies from other organizations can be shared with industry and with each other. The CCPC also works with various groups to obtain funding, execute projects, share information, or to collaborate, such as: ICO 2 N Carbon Management Canada CO 2 Capture Project Lignite Energy Council Electric Power Research Institute (EPRI) Global CCS Institute CanmetENERGY Canadian Wood Pellet Association Climate Change and Emissions Management Corporation (CCEMC) Environment Canada Alberta Innovates Energy and Environment Solutions International Energy Agency National Energy Technology Laboratory North Dakota Industrial Commission Alberta Energy 18 Canadian Clean Power Coalition

21 Sharing Our Findings Educating the public about cleaner coal is an important part of the CCPC s mandate. The CCPC is committed to sharing its research findings with its members and the public. Valued as a trusted information source for carbon capture costs and other information, the CCPC frequently receives queries from teachers, government, industry and members of the public. The CCPC also undertakes structured dissemination of its study findings to interested stakeholders. Formal external communication activities have included the provision of the CCPC s website, fact sheets, industry reports, delivery of presentations and media releases. As a coalition, members also learn from each other and share studies and ideas. The CCPC has become a thought leader on CCS and other emission reduction technologies, and receives numerous questions and inquiries. Additionally, the CCPC s leadership presents current findings at conferences and to government. In the early days, the CCPC played a policy development role, providing industry expertise as needed. Today, the CCPC has evolved to become a great source of information in Canada about CO 2 reduction technologies and economics. Canadian Clean Power Coalition 19

22 The CCPC has evolved to become the best source of information about Canadian carbon capture technology and economics. 20 Canadian Clean Power Coalition

23 Appendix A Coal Beneficiation A Final Phase IV Report Prepared by Sherritt International Corporation, May 2014 Table of Contents 1. Introduction A02 2. Testing Overview A Sampling A Coal Composition A03 3. Washability Data Analysis A Float Sink Testing A Washability Data A Analysis of Washability Data A04 4. Comparison of Allmineral and FGX Air Jigs A05 5. Suitability of Test Coals for Dry Beneficiation A05 6. Impurity Rejection Air Jig Performance A07 7. Economic Analysis A07 8. Conclusions A08 9. Future Work A09 Figures and Tables Table 1: Figure 1: Table 2: Table 3: Table 4: Table 5: Coal Composition A03 Schematic Representation of a Float-sink Test, Reference Encyclopedia of Physical Science Coal Preparation R.A. Meyer et al. A03 Washability Data A04 Comparison Expected Coal Beneficiation Technologies A05 Allmineral Air Jig (fines reporting to product coal) A06 FGX Septech Air Jig (fines reporting to product coal, middlings rejected no recycle) A06 Canadian Clean Power Coalition: Appendix A A01

24 Coal Beneficiation 1. Introduction The use of Western Canadian coals for power generation depends on meeting evolving economic and environmental constraints. The ability to reduce the ash content is of importance both for upgrading the fuel and to meet current and future operating and environmental specifications. The derived benefits of beneficiation relate both to the mine (increasing the quantity of coal reserves meeting ash specifications) and to the power plant through thermal efficiency of power generation and reduced fly ash production/handling. Beneficiation, in some cases, also offers the potential to preferentially reject impurities such as mercury and sulphur, which will correspond to an economic benefit or environmental requirement. The costs of beneficiation are considerable and require a detailed economic analysis to determine the financial benefits and to whom they accrue (mine or power producer). Sound technical data is required to design the optimum coal processing plant and to allow economic modeling to be performed. The coal behavior and optimum coal beneficiation plant design will depend on the properties of the coal from the individual mines. 2. Testing Overview Conducting a thorough investigation of the physical and chemical characteristics of the coal from the individual seams is the first step towards providing the data from which the performance of individual beneficiation technologies can be estimated. As one part of a comprehensive earlier CCPC sponsored research project (Project 413 Coal Beneficiation Technology Review for Western Canadian Coals Final Report, Rev.2, July 2011, CCPC Project 413), carried out by Sherritt Technologies, potential dry beneficiation technologies were evaluated. Of the commercially proven technologies for as received coals, Allmineral and FGX Septech were identified as potential technologies to be used to beneficiate Western Canadian thermal coals. While a technological and economic evaluation of the processes was performed in the earlier project, the data available for the different Western Canadian coals was limited. Western Canadian thermal coals are broadly split into Saskatchewan lignites (e.g. Boundary Dam and Poplar River) and Alberta subbituminous coals (e.g. Highvale and Genesee), which have different chemical and physical properties that influence the performance of beneficiation processes. It is important that current data on the physical, chemical and thermal properties of the different coals be available to improve our understanding of the performance of the different dry beneficiation processes. Sherritt Technologies was commissioned to test several Canadian coals to derive data that was used to assess how commercially available coal beneficiation technologies would perform. CanmetENERGY completed further physical tests of the coals. Washability studies are a useful standardized method of determining the suitability of coal for upgrading based on coal particle size and density. While washability studies were developed to determine the suitability of the coal for wet beneficiation processes, they are also useful for assessing the suitability of coal for dry beneficiation. It is, however, intrinsically more difficult to achieve a clean separation of material using dry separation techniques and the ability to separate diminishes as the particles and density differences get smaller. Evaluation of dry beneficiation processes based on improved understanding of the physical and chemical properties of the different coals allows a more detailed evaluation of the technology and economic evaluation to be made. From this study it was intended that recommendations be made about whether further testing of the technologies is warranted for any of the coals investigated and possible flowsheets. Each coal was tested to determine the variation in the following parameters with particle size and density: HHV (Higher Heating Value) Ash Content Ash Composition Impurities Quartz Sulphur Mercury Ash Fusion Temperature Moisture reduction was not specifically studied. However, moisture reduction may occur to some extent as the coal is beneficiated. A02 Canadian Clean Power Coalition: Appendix A

25 2.1. Sampling Samples of coal were collected from four mines and tested to determine their suitability for ash and impurity rejection by dry beneficiation. Two Saskatchewan lignites (Boundary Dam and Poplar River) and two Alberta subbituminous coals (Highvale and Genesee) were tested. The coal samples were collected by a number of different techniques due to mine operation considerations. The sample techniques used to collect the different samples are summarized below. All samples were considered representative, with the exception of the first Boundary Dam sample where a second sample was deemed necessary Coal Composition The composition of the five raw coal samples tested is summarized below in Table 1. Coal Moisture % (arb) Ash % (db) S % (db) Hg ppb (db) HHV (db) kj/kg Boundary Dam n.d. n.d Boundary Dam Poplar River Highvale (Seam 1) Genesee The moisture content measured for the Saskatchewan lignites were lower than expected. 3. Washability Data Analysis Coals are typically tested to determine the variation in properties, such as ash, moisture calorific value and chemical composition, with size and density. These analyses are typically referred to as washability studies and are carried out conforming to specific ASTM standards Float Sink Testing Washability studies are normally performed by screening a representative sample of the air dried coal and then performing a series of float-sink tests in solutions of different densities (normally between specific gravity 1.2 and 2.2) on the different screen fraction. Test procedure ASTM Float Sink Analyses: ASTM D (2012) Standard Test Method for Determining the Washability Characteristics of Coal. This is shown schematically in the Figure 1 below. Each screen fraction-density sub-sample is then quantified by weighing and drying and conducting the required analyses or determinations. A large amount of data is measured or derived in a systematic washability study, especially if extensive chemical and physical analyses are performed on each of the individual size-density sub-samples collected. Figure 1: Schematic Representation of a Float-sink Test, Reference Encyclopedia of Physical Science Coal Preparation R.A. Meyer et al. Canadian Clean Power Coalition: Appendix A A03

26 3.2. Washability Data A washability study was conducted on each coal with screening and float sink tests were performed on the different size fractions to produce subsamples encompassing the range of size and density. The ash content and other coal properties of samples were measured to quantify their distribution with size and density. Chemical analyses of the coal (S and Hg) and ash were performed as well as fusion temperature measurements on select samples. The washability study data indicated that the ash and impurity concentrations varied with both density and size. Typically the density was a function of ash content varying from a relative density of about 1.3 for relatively pure coal (carbonaceous fuel) to greater than 2.0 for rock particles with little coal associated with them. Variations in sulphur, mercury, sodium and other impurities with particle size and density were found in the washability study data. Specific impurities such as pyrite (iron sulphide) and clays were found in specific size-density fractions as discrete particles in some of the coals (Poplar River and Genesee, respectively). The washability study data identified which phases or species (ash and impurities) have significant concentration variations based on size and density that would allow rejection of ash and impurities in the different coals by dry beneficiation Analysis of Washability Data The washability data was evaluated using Henry Reinhard style washability curves to determine ash rejection, product yields and ash content as well as fuel recoveries. The calculated beneficiation possible for the four test coals, using the washability curves and assuming perfect separation is made at a specific gravity of 1.9, is summarized in Table 2 below. Table 2: Washability Data Feed Ash, wt% (db) Product Yield, % Fuel Recovery, % Product Ash wt% (db) Ash Reject, wt% Boundary Dam Poplar River Highvale Seam Genesee The washability curves indicated that, for the Saskatchewan lignites, good separation of a small amount of ash material based on density should be possible while still obtaining high product yields and fuel recoveries. The curves also suggested that it should be possible to cleanly reject a significant amount of ash from the Genesee sub-bituminous coal while still recovering most of the fuel value. In contrast, the shape of the curves for Highvale sub-bituminous coal indicates appreciable amounts of fuel would be rejected with the ash, and suggests the Highvale coal (Seam 1) coal sample tested is not well suited to beneficiation by density. The data obtained for this 2012 sample of Highvale coal (Seam 1) are different from that of a 2008 TAU study on the same coal (and seam). There is considerably more ash (28.1 vs 23.8 wt%) in the sample tested in the current study, and there is a more gradual gradient in fuel and ash with density resulting in poorer predicted separation for the current sample. While the washability curve data suggests significant ash rejection can (theoretically) be achieved, by beneficiation using density, for all the coals except for the 2012 Highvale sample, the above analysis is too simplistic. Specifically, it does not consider imperfect separation or the significant influence of particle size on density separation, the effects of which are important for commercial dry beneficiation processes. For commercial dry beneficiation processes the cleanness of separation worsens with decreasing particle size. Particles below 0.5 to 3 mm in size cannot be effectively upgraded by dry beneficiation. A04 Canadian Clean Power Coalition: Appendix A

27 4. Comparison of Allmineral and FGX Air Jigs The operation and performance of two commercially proven dry beneficiation technologies, Allmineral and FGX Septech air jigs, were evaluated. The technologies were identified in a previous CCPC study Coal Beneficiation Technology Review for Western Canadian Coals Final Report, Rev.2, July 2011, CCPC Project 413. Both air jigs are in commercial operation and use air flow and oscillating forces to affect segregation based on size and density differences. There are several differences in design between the two jigs, which are summarized in the following table. Table 3: Comparison Expected Coal Beneficiation Technologies Feed Limitations Allmineral <50 mm Not sticky (clays?) <7% surface moisture <14% -0.6mm FGX Septech <80 mm Not sticky (clays?) <7% surface moisture Minimum Size for Cleaning 0.8 mm (fines to vent) 3 mm Output Streams Clean coal Refuse Fines (dust) Product coal Middlings Rejects Dust Cut Point Specific Gravity >1.7 >1.9 Cut Point Specific Gravity Adjustable Yes Air plus amplitude Nuclear density gauge Yes Air plus amplitude Table slope and discharge divider position Separation Characteristics Likely better separation of mid-size material Better at de-shaling Unit Size (Max.) 50 t/h 480 t/h Largest Plant t/h 700 1,400 The actual performance of the two technologies will depend both on the flowsheet design and coal characteristics. The flowsheet for the FGX air jig is more complex in that a semi-cleaned middlings stream is produced and incorporated in the flowsheet (typically by recycling). It is not possible to identify one of the two technologies as clearly superior for all applications. The Allmineral is a more complex jig relying on nuclear level gauge to control discharge ash content and is better suited to processing finer coal fractions. The FGX air jig appears to be a simpler device of large size; density separation appears less effective and does not remove ash effectively from feeds below about 1/4 (6.3 mm). A middling stream is therefore typically recycled to improve yield and ash rejection. In practice, piloting of the two air jigs, on representative coal samples, will be required to determine their operating characteristics. The range of density and coal particle size when the ash or impurities are concentrated may determine which of the two jigs provide superior performance. 5. Suitability of Test Coals for Dry Beneficiation The suitability of the four coals studied for ash and impurity rejection using commercial dry beneficiation technology was evaluated based on information available in the literature on commercial dry beneficiation technologies and washability data generated in this study. From data provided by Allmineral LLC and FGX Septech, separation efficiency parameters were extracted that allowed estimates of ash rejection, product yields, ash content and fuel recoveries for the different technologies and coals to be made. It must, however, be emphasized that the performance of the air jigs can be adjusted using the control parameters (air and mechanical oscillations). The estimates are therefore an indicator of air jig performance, which can be compared with the theoretical maximum predicted by the washability curves (this ratio being the confusingly named organic efficiency ). Canadian Clean Power Coalition: Appendix A A05

28 Selected results for the four test coals are summarized in the table below and can be compared with the similar data estimated using the washability curves. Results for both the Allmineral yields calculated from the Allmineral and FGX parameters are significantly lower than those predicted by the washability data. This reflects a combination of the poor separation coefficient for particles below 1mm and the varying fraction of the mass of coal and ash present as smaller particles in the different coal samples. Table 4: Allmineral Air Jig (fines reporting to product coal) Feed Ash Content, wt% (db) Product Yield, wt% Product Ash Content, wt% (db) Ash Rejected, (% of total ash) Fuel Recovered, % of Total Boundary Dam # Poplar River Highvale Genesee Table 5: FGX Septech Air Jig (fines reporting to product coal, middlings rejected no recycle) Feed Ash Content, wt% (db) Product Yield, wt% Product Ash Content, wt% (db) Ash Rejected, (% of total ash) Fuel Recovered, % of Total Boundary Dam # Poplar River Highvale Genesee For both technologies, the trends in the predicted (un-optimized) performance were similar. For ash rejection from lignites, Boundary Dam coal show greater potential for rejecting significant amounts of ash than Poplar River coal, while still obtaining (relatively) high fuel recoveries. For subbituminous coal, while actual fuel recoveries were lower, the Genesee coal showed greater potential for ash rejection and fuel recovery than the Highvale coal tested. Poplar River does not appear well suited to dry beneficiation for ash rejection, as fuel recoveries were low, at 91 per cent (94 per cent FGX), despite only rejecting 19 per cent (11 per cent FGX) of the ash. For Highvale coal, while significant ash rejection is predicted, fuel recoveries are also very low. In practice it is possible to adjust the separation density to higher (not lower) effective densities and therefore it might be possible to improve the beneficiation for the Poplar River (or Highvale) coal to increase fuel recovery with the trade-off of rejecting less ash. It is not possible to directly compare the performance of the Allmineral and FGX air jig from the calculated data, as the operation of both can be tuned for optimization. From this preliminary analysis, it could be concluded that the Allmineral Air jig provides superior ash rejection while obtaining a similar fuel recovery to the FGX Septech air jig. This is primarily due to its reported superior separation at smaller particle sizes. FGX partially addresses its inferior separation characteristics by typically splitting out a middling stream and recycling it. Comparison of the operating characteristics of the two air jigs suggest that FGX air jigs perform better with coarser material, as the top size is 80 mm as compared with 50 mm for Allmineral. Allmineral air jigs likely perform better for separating intermediate size material (0.5 to 5 mm). While FGX partially addresses this by producing a middling stream for recycle, only feeds greater than 3 mm are reported suitable for beneficiation. The uncertainties associated with the predicted performance of the different air jigs indicates the importance of experimental test work (both vendors have demonstration or mobile pilot units) to determine both the product yield and composition capabilities as well as the operational and performance issues. A06 Canadian Clean Power Coalition: Appendix A

29 6. Impurity Rejection Air Jig Performance The study indicates that sulphur and mercury in some coals could be preferentially rejected based on densitysize differences. Pyrite rejection from Polar River could result in preferential rejection of sulphur and mercury (as well as iron). Mercury in the Highvale coal (Seam 1) is associated with denser material, despite not appearing associated with sulphur. It is also possible quartz (silica) present in Poplar River coal could also be rejected, provided it is 1mm or larger; however, this was not proven in this study. The sodium in Boundary Dam coal is primarily associated with the less dense organic material and would not be preferentially rejected by dry beneficiation. When sulphur is present as pyrite, such as for Poplar River, sulphur rejection appears feasible by dry beneficiation. Estimates based on the Allmineral jig separation parameters suggested that for Poplar River rejecting about 11 per cent of the mass, 44 per cent of the sulphur would report to the reject stream and the sulphur content of the Poplar River coal could be reduced by 20 per cent from 1 to 0.8 wt%. As the pyrite represents much of the coarse dense material, it is calculated the reject stream would contain over 5.3 per cent sulphur. It has been reported (Honeker 2007) that FGX air jigs have been installed in a Texas lignite mine for sulphur and mercury rejection. It is reported that sulphur and mercury rejections of 35 and 55 per cent respectively were reported obtained in piloting tests. It is therefore expected that both the Allmineral and FGX air jigs would reject pyrite, however, the individual performance of the two jigs could vary significantly depending on the size-density distribution of the sulphur and experimental tests are required to quantify differences in performance. As the composition of ash in the coal samples is not uniform, preferential rejection of denser material will change the composition of the fly ash produced by combusting the coal. Comparison of the ash fusion temperature measurements indicates that the Saskatchewan lignites tend to have lower fusion temperature than the Alberta subbituminous coals. The results for the Genesee sub-bituminous coal suggests the intrinsic ash associated with the coal has a lower melting temperature, often associated with slagging. As the clays and denser coarser particles appear to have higher melting characteristics, it is possible overall melting temperatures will be reduced if this higher melting temperature material is preferentially removed by dry beneficiation. Selected removal of elements (iron, sulphur as pyrite) will also influence ash fusion temperatures. While it is possible to calculate the change in ash composition resulting from calculated ash deportments from dry beneficiation, and how this influences ash fusion temperatures, it is beyond the scope of this study to perform this analysis. 7. Economic Analysis For the implementation of dry beneficiation technologies to make economic sense, the overall performance and cost benefits realized in the power plant must be greater than the increase in the cost of the beneficiated coal feed. For this study, EPRI utilized their proprietary PCCost program to assess the potential performance, capital and operating cost benefits of using beneficiated coal in a new, grassroots conventional pulverized coal-fired power plant. EPRI assumed the same design and cost parameters for each of four reference coals: Genesee subbituminous coal, Highvale subbituminous coal, Boundary Dam lignite and Poplar River lignite. These key design and cost assumptions included the following: Plant size: 450 MW net Supercritical steam conditions: 3600 psi/1050f/1050f Includes FGD, SCR, and Hg control Delivered Coal Price = $25/tonne for all four coals For consistency with the 2011 study, all costs are in 2010 dollars For the beneficiated coal cases, EPRI used a simplified levelized cost of electricity (LCOE) model to calculate the delivered price of the beneficiated coal that would result in exactly the same LCOE as the reference PC plant with raw, as-received coal. This economic assessment indicated the highest price that an owner can pay for a beneficiated coal in order for the plant to produce electricity at the same levelized cost. Inputs to the LCOE model were taken from the PCCost model runs, and included: Net plant heat rate Plant availability (or capacity factor) Total plant cost Fixed and variable O&M cost Canadian Clean Power Coalition: Appendix A A07

30 Two dry beneficiated cases were evaluated for each of the four reference coals. These cases are referred to as the Air Jig and Ideal cases. Sherritt provided a proximate analysis, ultimate analysis and ash analysis for each of the reference coals, as well as for the dry beneficiated coals. For the subbituminous coals, the ash content was reduced by 19 to 20 per cent. For the lignite coals, the Boundary Dam ash content was reduced by 28 to 34 per cent, while the Poplar river ash content was only reduced by 10 to 14 per cent. Note that the Sherritt analyses did not indicate any significant sulfur or mercury reduction for any of the beneficiated coals. The beneficiation processes under consideration did not result in any reduction of moisture, and in some cases there was actually a slight increase in the percentage of moisture. Some of the key findings: There was very little reduction in capital cost for a new power plant firing dry beneficiated coals. The capital cost reduction for subbituminous coals was 2.0 to 2.5 per cent, while the reduction for lignite coals was only 0.2 to 0.5 per cent. Boiler tube erosion should be reduced as the coal ash content decreases. The PCCost availability correlation predicted a 0.80 to 0.85 percentage point increase in availability for the subbituminous coals, and only a 0.30 to 0.50 percentage point availability increase for the lignites. This small increase in availability had very little impact on the overall economic benefit. In several cases the moisture content of the dry beneficiated coals actually increased, thus leading to a slight reduction in boiler efficiency, and a slight increase in net plant heat rate, especially for lignite. As expected, the operating and maintenance (O&M) costs were slightly reduced due to handling less ash, and slightly less coal. To produce electricity at the reference plant cost, the delivered cost of the dry beneficiated coals could increase from $25 to $30-31/tonne for subbituminous coals, and from $25 to $27-29/tonne for lignite coals. 8. Conclusions The current study indicates that significant ash reductions and selective impurity rejection are predicted for several of the coals tested, especially Genesee for ash reductions and Poplar River coal for impurity rejection. The different sampling methods used to obtain the bulk sample for washability studies were considered (mostly) satisfactory, however, the first Boundary Dam sample was considered non-representative. Review of two commercially proven dry beneficiation technologies (Allmineral and FGX Septech air jigs) indicated both are best suited to the rejection of larger, denser material. While the Allmineral air jig appears to have superior separation characteristics, it is a more complex technology. Although effective separation is achieved over a smaller range of densities and particle size with the FGX air jig, a middling stream is produced and recycled to improve yields and recoveries. The actual performance of both technologies will depend on the beneficiation flowsheet, which is beyond the scope of this project. It was not evident that one technology was significantly superior and piloting of both technologies would be recommended for coals identified as suitable for testing. In general higher yields and fuel recoveries were obtained with the lignites than subbituminous coals. However, the higher moisture contents of the lignites may be less suited to dry beneficiation. The results of the calculations using separation efficiency parameters for the Allmineral and FGX air jigs suggest: Boundary Dam Coal Relatively clean separation of a fraction of the ash is possible but sodium, which is located in the lighter carbonaceous material, is not rejected. Poplar River Coal Not well suited for ash rejection by dry beneficiation, with a significant reduction in fuel recovery for modest ash rejection; significant sulphur, mercury and iron rejection is, however, possible due to the presence of larger pyrite particles. A08 Canadian Clean Power Coalition: Appendix A

31 Highvale Coal (Seam 1) Clean ash separation was not possible by dry beneficiation due to a gradient of ash concentrations with density; some preferential rejection of mercury may be possible (this differs from a 2008 study where better ash separation was predicted). Genesee Coal Significant rejection of ash is predicted while recovering much of the fuel, rejection of clay present in the coal appears possible but would need to test whether the presence of clay is detrimental to air jig operation. For the Genesee coal, the variations in ash melting temperatures with size and density fractions suggests dry beneficiation could influence ash melting properties. While some coals seem suitable for dry beneficiation to reject ash (e.g. Genesee [include clays] and Boundary Dam) or to reject impurities (i.e. Poplar River to reject S and Hg, or Hg from Highvale), testing is required to verify performance. Testing of the individual dry beneficiation technologies (Allmineral and FGX Septech air jigs) is necessary to determine precise operating performance and characteristics of the different technologies. 9. Future Work As a preliminary step, it is recommended that economic optimization modeling studies be conducted, using the washability data determined in this study and the estimates of operating performance of the different air jigs, to identify the optimum flowsheets or coals seams to process. The analysis would also determine where predicted capital and operating cost could justify further evaluation and piloting. Of the coals tested, it is recommended that further economic evaluation of flowsheets for sulphur and mercury removal from Polar River and ash removal from Genesee coal be carried out to determine if piloting of the two dry beneficiation technologies is warranted. It is also recommended that discussions are held with mine operators/personnel to determine whether specific material from the mine, best suited to dry beneficiation, can be identified, which could improve process economics. The current study suggests both the FGX and Allmineral air jig should be tested if the economic evaluation indicates piloting of dry beneficiation processes is warranted. Some fuel will inevitably be rejected by dry beneficiation, so it is important that the economics of dry beneficiation be determined for each specific coal (or seam) and flow sheet chosen, prior to piloting studies. It is important that the flow sheet incorporating the dry beneficiation technology, for either ash or impurity rejection, can be shown to be economically justified prior to testing. The operating characteristics of the different air jigs, identified in this study, provide estimates of operating parameters for these calculations. Canadian Clean Power Coalition: Appendix A A09

32 Appendix B Biomass Co-firing A Final Phase IV Report Prepared by CCPC Technical Committee, January 2014 Table of Contents 1. Introduction B02 2. Wabamun, Alberta B02 3. Shand, Saskatchewan B06 4. Trenton, Nova Scotia B09 5. Biomass, Natural Gas Co-firing with Coal B12 6. Conclusions B16 Figures and Tables Table 1: Techno-economic Modelling Assumptions for Wabamun, AB Location B02 Table 2: Biomass Availability and Cost B03 Figure 1: Biomass Cost Components 70% Co-firing Rate B04 Figure 2: Avoided Cost of Biomass Co-firing B04 Figure 3: Increase in Power Cost for 10% Co-firing B05 Figure 4: Increase in Power Cost for 70% Co-firing B05 Table 3: Techno-economic Modelling Assumptions for Shand, SK Location B06 Table 4: Biomass Availability and Cost B06 Figure 5: Biomass Cost Components 70% Co-firing Rate B07 Figure 6: Avoided Cost of Biomass Co-firing B07 Figure 7: Increase in Power Cost for 10% Co-firing B08 Figure 8: Increase in Power Cost for 70% Co-firing B08 Table 5: Techno-economic Modelling Assumptions for Trenton, NS Location B09 Table 6: Biomass Availability and Cost B09 Figure 9: Biomass Cost Components 70% Co-firing Rate B10 Figure 10: Avoided Cost of Biomass Co-firing B10 Figure 11: Increase in Power Cost for 10% Co-firing B11 Figure 12: Increase in Power Cost for 70% Co-firing B11 Table 7: Assumptions Used in Model B12 Figure 13: Proportions of Fuel Co-firing B12 Figure 14: Cost of Biomass B13 Figure 15: Increase in Power Cost B13 Figure 16: Avoided CO 2 Cost B14 Figure 17: Total Cost of Fuel B15 Figure 18: The Total Cost of Co-firing Biomass and Natural Gas B15 Figure 19: CO 2 Capture Required for Various Co-Firing Rates B16 B01 Canadian Clean Power Coalition: Appendix B

33 Biomass Co-firing 1. Introduction During Phase III of the CCPC study work it was concluded that further work on the availability and cost of various forms of biomass for co-firing in specific coals plants should be completed. FP Innovations was commissioned to complete this work in Three coal plant locations were chosen for this study: 1) Wabamun, Alberta, 2) Shand, Saskatchewan and 3) Trenton, Nova Scotia. A typical coal plant configuration was chosen for each site to determine the amount of biomass required for 10 per cent, 20 per cent and 70 per cent co-firing rates. Seventy per cent co-firing is roughly the amount of co-firing required to meet a greenhouse gas (GHG) emission intensity of.42 t CO 2 /MWh. Ten per cent to 20 per cent co-firing could be used to meet provincial GHG emission requirements in Alberta, for instance. This modest amount of co-firing could be coupled with other forms of GHG mitigation to potentially meet the federal government requirements without significant modifications to the boiler. A circle with a 150 km radius was drawn around each plant. Roughly 10 forms of potentially abundant biomass were identified within each circle. In addition, wood pellets from outside this circle were evaluated as well. The types of biomass considered are identified in the charts below. The amount of each type of biomass available in each circle was estimated. The amount of each type of biomass required to support a certain percentage of co-firing at each plant was also assessed. The study included a description of the physical, chemical and combustion attributes of each type of biomass feedstock and, at each location, information about their availability, costs and feasibility was provided. It also included a very large bibliography of relevant material related to biomass co-firing. The study also provided information on the harvesting, transportation and processing of each form of biomass. 2. Wabamun, Alberta Table 1 shows the characteristics of a typical coal plant in the Wabamun area and some of the parameters used to estimate the cost of biomass. Table 1: Techno-economic Modelling Assumptions for Wabamun, AB Location Power Plant Parameters Plant Capacity (MW) 300 Capacity Factor (%) 90% Base Heat Rate (GJ/MWh) 10.0 GHG Intensity (tco 2 /MWh) 1.0 Cost of Coal ($/GJ) 1.0 Power Price ($/MWh) 90 Coal Calorific Value (GJ/tonne) 19.0 Coal Replaced (tonnes/year) 10% Co-firing Rate 124,484 20% Co-firing Rate 248,968 70% Co-firing Rate 871,389 De-rate Factor (% of biomass capacity) 10% Co-firing Rate 0% 20% Co-firing Rate 0% 70% Co-firing Rate 3% Biomass Processing Parameters Capital Cost Pellets ($/kw) 260 Capital Cost Dry Biomass ($/kw) 1,000 Capital Cost Wet Biomass ($/kw) 1,100 Capital Recovery Factor Annual Operational Costs (% of Capital Cost) 2% GHG Intensity Hammer Milling (kgco 2 /MWh) 15 GHG Intensity Drying (kgco 2 /MWh) 8 Portion of Biomass Used at Drier (%) 18% Cost of Energy Hammer Milling ($/ODt) 2 Cost of Energy Drying ($/ODt) 1 Carbon Credit Revenue ($/tco 2 ) 15 This information was used to estimate the cost of the feedstock prior to transportation to the power plant. Feedstock expenses included all the costs to plant, tend and harvest the materials. Costs for transportation, storage, processing, drying, operating, CO 2 credits and estimates for boiler modifications were added to the feedstock cost to give a full cost of biomass. The calculations of the avoided costs and increases in the cost of power shown here are based on the cost of biomass required less the cost of coal that has been replaced by the biomass. Canadian Clean Power Coalition: Appendix B B02

34 Table 2 shows the estimated amounts of biomass available around the plant. The forms of biomass at the bottom of the table are currently not grown near the plant and therefore the number of hectares of plantations required for each type was estimated. Table 2: Biomass Availability and Cost Biomass Available (ODt) Co-firing Rate Supported (%) Transportation Costs ($/ODt) Power Plant Gate Costs ($/ODt) Point of Origin 100 km 150 km 100 km 150 km Cost 100 km 150 km 100 km Feedstock Type Radius Radius Radius Radius ($/ODt) Radius Radius Radius Barley Straw 5,776 6, % 0.4% Wheat Straw 135, , % 27.3% Flax Straw % 0.1% Oat Straw 22,895 39, % 3.2% Whole Tree Chips Woodlots 216, , % 57.5% Whole Tree Chips unused AAC 110, , % 74.3% Forest Residuals FMU 76, , % 62.9% Forest Residuals over AAC 6,591 60, % 5.1% Wood Pellets BC 1,810,000 >100% Wood Pellets AB 140, % MSW RDF with Edmonton 800,000 61% MSW RDF without MSW RDF without Enerkem 700,000 49% NA Edmonton 194,000 13% Miscanthus Reed Canary Grass Jerusalem Artichoke See area requirement table Hemp Willow Coppice Poplar Coppice km Radius Figure 1 shows an estimate of the cost components that combine to give the total cost of biomass on an Oven Dry Tonnes (ODt) basis for use as a fuel in the plant. These estimates include all costs required to allow the fuel to be combusted in the boilers. This graph shows the costs for a 70 per cent co-firing rate. The costs for 10 per cent and 20 per cent co-firing rates are similar. The top two bars show a low and high range of feedstock costs. The values shown below the X-axis represent the value of CO 2 credits in Alberta. The net fuel cost is the sum of all the positive and negative values. If biomass has a fuel content of 19 GJ/ODt, then dividing the net fuel costs by this value yields a range of fuel costs of about $2 to $7/t. B03 Canadian Clean Power Coalition: Appendix B

35 Figure 1: Biomass Cost Components 70% Co-firing Rate Biomass Cost ($/ODt) Fuel High Fuel Low Capital ($/t) O&M ($/t) Drying/Milling CO 2 Credits 0 (50) Whole Tree Biomass (WTB) Forest Residual Biomass (FRB) Wood Pellets BC Wood Pellets AB Miscanthus Reed Canary Grass Jerusalem Artichoke Hemp Willow Poplar Barley Straw Wheat Straw Flax Straw Oat Straw MSW Pellets 60% WTB + 40% Straw 70% Pellets BC + 30% MSW Pellets Biomass co-firing is one way to meet the federal government requirements to reduce GHG emissions from coal plants. Avoided cost is one way to compare the cost of various means of reducing GHG emissions. Figure 2 shows the avoided cost of biomass co-firing at a 70 per cent co-firing rate. The values for 10 per cent and 20 per cent co-firing are slightly lower than those reported below. Many of the values on this graph are lower than other forms of carbon capture. However, in the short term, if prevailing GHG mitigation costs remain at $15/t in Alberta, then it will be cheaper to pay the carbon tax than it will be to implement co-firing. The carbon tax has not been included in the graph below as it is what we are attempting to compare avoided costs against. Figure 2: Avoided Cost of Biomass Co-firing Avoided CO 2 Cost ($/t) Net Fuel High Net Fuel Low Derate O&M Drying/Milling Capex 0 Whole Tree Biomass (WTB) Forest Residual Biomass (FRB) Wood Pellets BC Wood Pellets AB Miscanthus Reed Canary Grass Jerusalem Artichoke Hemp Willow Poplar Barley Straw Wheat Straw Flax Straw Oat Straw MSW Pellets 60% WTB + 40% Straw 70% Pellets BC + 30% MSW Pellets Canadian Clean Power Coalition: Appendix B B04

36 Ultimately, the economics of biomass co-firing will be assessed based upon how they increase the price of power produced by a plant. If biomass co-firing increases the price of power from that plant above the expected sale price of power, then co-firing will not be economical. Figure 3 shows the expected increase in the cost of power from a coal plant for 10 per cent co-firing. The values for 20 per cent co-firing are roughly twice the values shown in the graph. The net fuel cost bar includes the value of carbon credits and the value of coal that is not consumed since it has been replaced by biomass. Figure 3: Increase in Power Cost for 10% Co-firing Increase in Power Cost ($/MW/h) Net Fuel High Net Fuel Low Derate O&M Drying/Milling Capex (1) Whole Tree Biomass Forest Residual Biomass Wood Pellets BC Wood Pellets AB Miscanthus Reed Canary Grass Jerusalem Artichoke Hemp Willow Poplar Barley Straw Wheat Straw Flax Straw Oat Straw MSW Pellets Figure 4 shows the increase in power cost associated with 70 per cent co-firing. This power price increase could be compared to the power price increase expected for other forms of carbon capture. Figure 4: Increase in Power Cost for 70% Co-firing Increse in Power Cost ($/MWh) Net Fuel High Net Fuel Low Derate O&M Drying/Milling Capex (10) Whole Tree Biomass (WTB) Forest Residual Biomass (FRB) Wood Pellets BC Wood Pellets AB Miscanthus Reed Canary Grass Jerusalem Artichoke Hemp Willow Poplar Barley Straw Wheat Straw Flax Straw Oat Straw MSW Pellets 60% WTB + 40% Straw 70% Pellets BC + 30% MSW Pellets B05 Canadian Clean Power Coalition: Appendix B

37 3. Shand, Saskatchewan Table 3 shows the characteristics of a typical coal plant in the Shand area and some of the parameters used to estimate the cost of biomass. Table 3: Techno-economic Modelling Assumptions for Shand, SK Location Power Plant Parameters Plant Capacity (MW) 276 Capacity Factor (%) 90% Base Heat Rate (GJ/MWh) 11.5 GHG Intensity (tco 2 /MWh) 1.18 Cost of Coal ($/GJ) Power Price ($/MWh) 90 Coal Calorific Value (GJ/tonne) 16.0 Coal Replaced (tonnes/year) 10% Co-firing Rate 156,399 20% Co-firing Rate 312,798 70% Co-firing Rate 1,094,792 De-rate Factor (% of Biomass Capacity) 10% Co-firing Rate 0% 20% Co-firing Rate 0% 70% Co-firing Rate 3% Biomass Processing Parameters Capital Cost Pellets ($/kw) 260 Capital Cost Dry Biomass ($/kw) 1,000 Capital Cost Wet Biomass ($/kw) 1,100 Capital Recovery Factor Annual Operational Costs (% of Capital Cost) 2% GHG Intensity Hammer Milling (kgco 2 /MWh) 15 GHG Intensity Drying (kgco 2 /MWh) 8 Portion of Biomass Used at Drier (%) 18% Cost of Energy Hammer Milling ($/ODt) 2 Cost of Energy Drying ($/ODt) 1 1. The fuel cost assumption used in the technical economic review may not reflect SaskPower s actual cost of fuel. Table 4 shows the estimated amounts of biomass available around the plant. The forms of biomass at the bottom of the table are currently not grown near the plant; therefore, the number of hectares of plantations required for each type was estimated. Table 4 : Biomass Availability and Cost Feedstock Type Biomass Available (ODt) 100 km Radius 150 km Radius Co-firing Rate Supported (%) 100 km Radius 150 km Radius Point of Origin Cost ($/ODt) Transportation Costs ($/ODt) 100 km Radius 150 km Radius Power Plant Gate Costs ($/ODt) 100 km Radius Wheat Straw 193, ,837 15% 36% Flax Straw 17,909 37,652 2% 4% Wood Pellets BC 1,810,000 > 100% Wood Pellets SK 100, % Reed Canary Grass 150 km Radius Altai Wildrye Grass Smooth Brome Grass Intermediate Wheat See area requirement table Grass Willow Coppice Poplar Coppice Figure 5 shows an estimate of the cost components that combine to give the total cost of biomass on an ODt basis for use as a fuel in the plant. These estimates include all costs required to allow the fuel to be combusted in the boilers. This graph shows the costs for a 70 per cent co-firing rate. The costs for 10 per cent and 20 per cent co-firing are similar. The top two bars show a low and high range of feedstock costs. If biomass has a fuel content of 19 GJ/ODt, then dividing the fuel costs by this value yields a range of fuel costs of about $5 to $13/t. Canadian Clean Power Coalition: Appendix B B06

38 Figure 5: Biomass Cost Components 70% Co-firing Rate Biomass Cost ($/ODt) Fuel High Fuel Low Capital O&M Drying/Milling CO 2 Credits 50 0 Wood Pellets BC Wood Pellets SK Reed Canary Grass Altai Wildrye Grass Smooth Brome Grass Intermediate Wheat Grass Willow Poplar Wheat Straw Flax Straw 60% Straw + 40%Pellets BC Biomass co-firing is one way to meet the federal government requirements to reduce GHG emissions from coal plants. Avoided cost is one way to compare the cost of various means of reducing GHG emissions. Figure 6 shows the avoided cost of biomass co-firing at a 70 per cent co-firing rate. The values for 10 per cent and 20 per cent co-firing are slightly lower than those reported below. Many of the values on this graph are lower than other forms of carbon. Figure 6: Avoided Cost of Biomass Co-firing Avoided CO 2 Cost ($/t) Net Fuel High Net Fuel Low Derate O&M Drying/Milling Capex 20 0 Wood Pellets BC Wood Pellets SK Reed Canary Grass Altai Wildrye Grass Smooth Brome Grass Intermediate Wheat Grass Willow Poplar Wheat Straw Flax Straw 60% Straw + 40%Pellets BC B07 Canadian Clean Power Coalition: Appendix B

39 Ultimately, the economics of biomass co-firing will be assessed based upon how they increase the price of power produced by a plant. If biomass co-firing increases the price of power from that plant above the expected sale price of power, then co-firing will not be economical. Figure 7 shows the expected increase in the cost of power from a coal plant for 10 per cent co-firing. The values for 20 per cent co-firing are roughly twice the values shown below. The net fuel cost bar includes the value of coal that is not consumed since it has been replaced by biomass. Figure 7: Increase in Power Cost for 10% Co-firing Increase in Power Cost (S/MWh) Net Fuel High Net Fuel Low Derate O&M Drying/Milling Capex 0 Wood Pellets BC Wood Pellets SK Reed Canary Grass Altai Wildrye Grass Smooth Brome Grass Intermediate Wheat Grass Willow Poplar Wheat Straw Flax Straw The following graph shows the increase in power costs associated with 70 per cent co-firing. This power price increase could be compared to the power price increase expected for other forms of carbon capture. Figure 8: Increase in Power Cost for 70% Co-firing Increase in Power Cost ($/MWh) Net Fuel High Net Fuel Low Derate O&M Drying/Milling Capex 0 Wood Pellets BC Wood Pellets SK Reed Canary Grass Altai Wildrye Grass Smooth Brome Grass Intermediate Wheat Grass Willow Poplar Wheat Straw Flax Straw 60% Straw + 40%Pellets BC Canadian Clean Power Coalition: Appendix B B08

40 4. Trenton, Nova Scotia Table 5 shows the characteristics of a typical coal plant in the Trenton area and some of the parameters used to estimate the cost of biomass. Table 5: Techno-economic Modelling Assumptions for Trenton, NS Location Power Plant Parameters Plant Capacity (MW) 150 Capacity Factor (%) 90% Base Heat Rate (GJ/MWh) 9.6 GHG Intensity (tco 2 /MWh) 0.91 Cost of Coal ($/GJ) 4.0 Power Price ($/MWh) 90 Coal Calorific Value (GJ/tonne) 25.0 Coal Replaced (tonnes/year) 10% Co-firing Rate 45,412 20% Co-firing Rate 90,824 70% Co-firing Rate 317,883 De-rate Factor (% of Biomass Capacity) 10% Co-firing Rate 0% 20% Co-firing Rate 0% 70% Co-firing Rate Dry: 3%; Wet: 7% Biomass Processing Parameters Capital Cost Pellets ($/kw) 260 Capital Cost Dry Biomass ($/kw) 1,000 Capital Recovery Factor Annual Operational Costs (% of Capital cost) 2% GHG Intensity Hammer Milling (kgco 2 /MWh) 15 Cost of Energy Hammer Milling ($/ODt) 2 1. The fuel cost assumption used in the technical economic review may not reflect Nova Scotia Power s actual cost of fuel. Table 6 shows the estimated amounts of biomass available around the plant. The forms of biomass at the bottom of the table are currently not grown near the plant; therefore, the number of hectares of plantations required for each type was estimated. Table 6: Biomass Availability and Cost Feedstock Type Biomass Available (ODt) 100 km Radius 150 km Radius Co-firing Rate Supported (%) 100 km Radius 150 km Radius Point of Origin Cost ($/ODt) Transportation Costs ($/ODt) 100 km Radius 150 km Radius Power Plant Gate Costs ($/ODt) 100 km Radius Pulpwood Chips 51, ,000 9% 35% Forest Residuals FMU 177, ,744 30% 45% Wood Pellets NS 170,000 29% Wood Pellets NB 289,000 48% Reed Canary Grass 150 km Radius Miscanthus Switchgrass See area requirement table Willow Coppice Poplar Coppice The following graph shows an estimate of the cost components that combine to give the total cost of biomass on an ODt basis for use as a fuel in the plant. These estimates include all costs required to allow the fuel to be combusted in the boilers. This graph shows the costs for a 70 per cent co-firing rate. The costs for 10 per cent and 20 per cent co-firing are similar. The top two bars show a low and high range of feedstock costs. If biomass has a fuel content of 19 GJ/ODt, then dividing the fuel costs by this value yields a range of fuel costs of about $6 to $12/t. B09 Canadian Clean Power Coalition: Appendix B

41 Figure 9: Biomass Cost Components 70% Co-firing Rate Biomass Cost ($/ODt) Fuel High Fuel Low Capital O&M Milling CO 2 Credits 50 0 Whole Tree Chips (WTC) Forest Residuals (FR) Wood Pellets Miscanthus Switch Grass Reed Canary Grass Willow Poplar 50% WTC + 50% Pellets 50% WTC + 50% FR Biomass co-firing is one way to meet the federal government requirements to reduce GHG emissions from coal plants. Avoided cost is one way to compare the cost of various means of reducing GHG emissions. Figure 10 shows the avoided cost of biomass co-firing at a 70 per cent co-firing rate. The values for 10 per cent and 20 per cent co-firing are slightly lower than those reported below. Many of the values on this graph are lower than other forms of carbon capture. Figure 10: Avoided Cost of Biomass Co-firing Avoided CO 2 Cost ($/t) Net Fuel High Net Fuel Low Derate O&M Milling Capex 0 (20) Whole Tree Chips (WTC) Forest Residuals (FR) Wood Pellets Miscanthus Switch Grass Reed Canary Grass Willow Poplar 50% WTC + 50% Pellets 50% WTC + 50% FR Canadian Clean Power Coalition: Appendix B B10

42 Ultimately, the economics of biomass co-firing will be assessed based upon how they increase the price of power produced by a plant. If biomass co-firing increases the price of power from that plant above the expected sale price of power, then co-firing will not be economical. Figure 11 shows the expected increase in the cost of power from a coal plant for 10 per cent co-firing. The values for 20 per cent co-firing are roughly twice the values shown below. The net fuel cost bar includes the value of carbon credits and the value of coal that is not consumed since it has been replaced by biomass. Figure 11: Increase in Power Cost for 10% Co-firing Increase in Power Cost ($/MWh) (1) Net Fuel High Net Fuel Low Derate O&M Milling Capex (2) Whole Tree Chips Forest Residuals Wood Pellets Miscanthus Switch Grass Reed Canary Grass Willow Poplar Figure 12 shows the increase in power cost associated with 70 per cent co-firing. This power price increase could be compared to the power price increase expected for other forms of carbon capture. Figure 12: Increase in Power Cost for 70% Co-firing Increase in Power Cost ($/MWh) (10) Net Fuel High Net Fuel Low Derate O&M Milling Capex (20) Whole Tree Chips (WTC) Forest Residuals (FR) Wood Pellets Miscanthus Switch Grass Reed Canary Grass Willow Poplar 50% WTC + 50% Pellets 50% WTC + 50% FR B11 Canadian Clean Power Coalition: Appendix B

43 5. Biomass, Natural Gas Co-firing with Coal The following analysis shows the rough economics associated with co-firing biomass with sufficient natural gas blended with coal to achieve a GHG emission intensity of.42 t CO 2 /MWh. Table 7 shows the assumptions used to construct the model. For this analysis we have assumed the capital cost of the plant has been written off. Therefore, we have assumed there will be $20/MWh for operations and maintenance (O&M) and $10/MWh to cover life extension costs. No additional capital beyond what was assumed to supply biomass has been included. There may be additional capital required to support natural gas firing. The table below shows a small derate associated with natural gas and biomass co-firing. Table 7: Assumptions Used in Model Plant Heat Rate (GJ/MWh) 10.0 Plant Capacity (MW) 400 Derate due to NG (MW) 5 Derate due to Biomass (MW) 5 t CO 2 /t Coal 1.73 Coal GHG (kg CO 2 /GJ) 89.9 NG GHG (kg CO 2 /GJ) 50.1 Biomass GHG (kg CO 2 /GJ) 1.0 Coal Heat Content (GJ/t) 19.2 Biomass Heat Content (GJ/t) 19.0 Base Emission Intensity (kg/mwh) 899 GHG Intensity Limit (kg/mwh) 420 Total Heat Required (GJ) 4,000 Total Heat Supplied (GJ) GJw + GJng + GJc % Heat Supplied by Biomass 20% Wood GJ (GJ/hr) 800 NG Required (GJ/hr) 3,133 Coal Required (GJ/hr) 67 Sub-total 4,000 Fuel Cost ($/t) 28.8 Coal Cost ($/GJ) 1.50 Nat Gas Cost ($/GJ) 4.00 Biomass Cost ($/GJ) 8.00 Biomass Cost ($/t) 152 O&M ($/MWh) 20 Life Extension ($/MWh) 10 CO 2 Credits ($/t) 15 Figure 13 shows that for 20 per cent biomass firing, only a small amount of coal is required and the other 78 per cent of fuel is supplied by natural gas. Twenty per cent is the minimum amount of biomass required to meet the GHG intensity of.42 t CO 2 /MWh. The graph also shows that the plant cannot co-fire with natural gas alone and meet the emission intensity requirement. At 40 per cent biomass firing, about 27 per cent of fuel energy is supplied by coal and 34 per cent is supplied by natural gas. The maximum amount of biomass fuel required is about 55 per cent. At 55 per cent biomass firing, no natural gas is required and the remaining 45 per cent of the fuel is provided by coal. If more biomass than this is employed, the GHG intensity of the plant will fall below.42 t CO 2 /MWh. Figure 13: Proportions of Fuel Co-firing 100% 90% 80% Nat Gas Coal 70% % Firing NG & Coal 60% 50% 40% 30% 20% 10% 0% 0% 10% 20% 30% 40% 50% 60% % Firing Biomass Canadian Clean Power Coalition: Appendix B B12

44 Figure 14 shows the cost of biomass as derived in the FP Innovations study for Alberta. These values should be used to compare against the costs in the following figures. The cost in $/GJ includes a $15/t of CO 2 credit. Figure 14: Cost of Biomass 9 8 Fuel High Fuel Low 7 Biomass Cost ($/GJ) Whole Tree Biomass (WTB) Forest Residual Biomass (FRB) Wood Pellets BC Wood Pellets AB Miscanthus Reed Canary Grass Jerusalem Artichoke Hemp Willow Poplar Barley Straw Wheat Straw Flax Straw Oat Straw MSW Pellets 60% WTB + 40% Straw 70% Pellets BC + 30% MSW Pellets Figure 15 below shows how much the cost of power for co-firing is expected to increase compared to the base case without GHG mitigation for various biomass co-firing rates with natural gas and coal. Figure 15: Increase in Power Cost Increase in Power Cost ($/MWh) (5) 20% 25% 30% 35% 40% 45% 50% 55% 60% % Biomass Firing Biomass $8/GJ $6/GJ $4/GJ $2/GJ $1/GJ Gas = $4/GJ B13 Canadian Clean Power Coalition: Appendix B

45 Figure 16 shows the cost of avoiding a tonne of CO 2 by co-firing both biomass and natural gas at several biomass prices. The $15/t credit embedded in the biomass cost has been removed in order to fairly compare the values below to the CO 2 credit. Before a coal plant reaches roughly 50 years of age, it will likely not implement biomass and natural gas co-firing unless doing so yields an economic return. Burning biomass yields $15/t of CO 2 avoided. In addition, burning biomass and natural may reduce SOX, NOx, Hg emissions and help with flue gas opacity. If the sum of the CO 2 credits and the benefits associated with lower emissions is sufficient, then biomass co-firing might be attractive in high proportions assuming biomass costs are quite low. Co-firing natural gas might also be beneficial if doing so is cheaper than mitigating coal emissions some other way. The incremental cost of burning $4/GJ natural gas or biomass displacing $1/GJ coal for half of the fuel required for a 300 MW plant is about $36 million/yr. Assuming a 10 per cent discount rate, this translates into a $360 million present value. If this helps reduce SOx sufficiently to avoid building and operating flue gas desulfurization (FGD) with a present value of $360 million then it might make sense to burn gas and or biomass. If the cost of post combustion capture is $90 to $100/t CO 2 then biomass and natural gas co-firing may be a cheaper way to avoid CO 2. The net cost of post combustion capture not only includes the CO 2 credit that would be available for co-firing but it might include the possibility of obtaining value for CO 2 for use in enhanced oil recovery (EOR). Therefore, the net cost of post combustion capture may be lower than some of the costs shown below. Figure 16: Avoided CO 2 Cost Avoided Cost ($/t) Biomass $8/GJ $6/GJ $4/GJ $2/GJ $1/GJ Gas = $4/GJ % 25% 30% 35% 40% 45% 50% 55% 60% % Biomass Firing The following figure shows the fuel cost of co-firing biomass, natural gas and coal. It is a good proxy for the marginal cost of the plant. An NGCC would have a marginal cost of about $4/GJ X 7 GJ/MWh = $28/MWh. Therefore, a coal plant operating with a fuel cost greater than $28/MWh will likely run less than an NGCC. The less the plant runs, the less biomass fuel must be secured. This may allow the plant to secure enough lower priced material to justify operating on biomass for higher priced periods. Canadian Clean Power Coalition: Appendix B B14

46 Figure 17: Total Cost of Fuel Fuel Cost ($/MWh) Biomass $1/GJ $2/GJ $4/GJ $6/GJ $8/GJ % 25% 30% 35% 40% 45% 50% 55% 60% Biomass Firing The following figure shows the total expected cost of co-firing biomass and natural gas. If the capital cost of the plant is written off and the other assumptions associated with the graph are valid, then the plant conversion makes economic sense, providing the pool price during plant operation exceeds the values in the graph. It is possible to receive significant volumes of wood pellets from BC at about $7/GJ. According to Figure 18, this would yield a power price of about $75/MWh for all proportions of biomass firing. It may make sense to co-fire with 20 per cent wood pellets. There are many other less expensive sources of biomass that could be secured to lower the costs. In addition, the plant may benefit from significantly lower sulfur and mercury emissions and may have lower flue opacity if it runs on biomass and natural gas. Biomass and natural gas co-firing might be a viable option for running a plant for a few extra years before it is shut down. Significantly less capital is required to implement co-firing compared to post-combustion capture to meet the GHG emission intensity requirement. However, it may turn out that the capital required to modify the plant and extend its life may generate a higher return when used to build an NGCC. For this reason, the economics of an NGCC should be compared to extending the life of a coal plant operating on biomass and natural gas. If an NGCC yields a higher return on capital employed than extending the life of a coal plant, the plant may be decommissioned and an NGCC may get built instead. Figure 18: The Total Cost of Co-firing Biomass and Natural Gas Power Cost ($/MWh) Biomass $8/GJ $6/GJ $4/GJ $2/GJ $1/GJ % 25% 30% 35% 40% 45% 50% 55% 60% Biomass Firing B15 Canadian Clean Power Coalition: Appendix B

47 Several technologies may possibly be employed to reduce GHG emissions to the required level. Figure 19 shows how much CO 2 capture is required for various biomass and natural gas firing rates. The emission intensity target of.42 t CO 2 /MWh was arrived at by subtracting the per cent of total CO 2 capture from the CO 2 generated by non-biomass fuels. This value is then divided by the MW of power produced less the energy required for CO 2 capture. In this case, without co-firing, about 62 per cent of CO 2 must be captured to meet regulatory requirements. Roughly speaking every one per cent increase in biomass co-firing reduces the requirement to capture one per cent less of the total CO 2. However as the per cent of CO 2 capture increases, the parasitic power losses tend to increase the GHG emission intensity. If 40 per cent natural gas firing is considered, then 20 per cent biomass co-firing requires a further 25 per cent reduction in GHG emissions by some other means. Figure 19: CO 2 Capture Required for Various Co-Firing Rates 70% 60% 50% No Nat Gas 20% Nat Gas 40% Nat Gas % CO 2 Capture 40% 30% 20% 10% 0% 0% 10% 20% 30% 40% 50% 60% % Firing Biomass 6. Conclusions Biomass co-firing without or without supplemental natural gas firing may be an economical way to extend the life of existing coal plants. This may be particularly true if these plants cannot be operated long enough to recover the cost associated with more capital intensive forms of carbon capture. However, since natural gas and biomass are generally higher cost fuels than coal, the marginal cost of co-fired plants will increase. This increase in marginal cost will likely decrease the proportion of time these plants would operate economically. Ontario Power Generation is converting several of their power plants to biomass co-firing. These plants are only expected to operate during higher priced periods of the day. Additional work is still required to refine the cost of securing biomass fuel. In addition, the costs associated with modifying specific Canadian coal plants to operate with high co-firing rates needs to be established. Perhaps the biggest outstanding issue is whether there is sufficient biomass available to supply a significant number of plants. If these plants are only expected to operate as peakers for less than 20 per cent of the time, as in Ontario, the volume of biomass required will be quite modest. Many utilities in Europe and Asia are turning to biomass co-firing as the preferred option for reducing GHG emissions from coal fired plants. As such, there is a long history of converting and operating coal plants to biomass fuel, using wood pellets in particular. Canada sends several million tonnes of wood pellets overseas each year. There is significant opportunity to provide wood pellets to domestic coal plants. Canadian Clean Power Coalition: Appendix B B16

48 Appendix C In-situ Coal Gasification A Final Phase IV Report Prepared by CCPC Technical Committee, April 2014 Table of Contents 1. Background C02 2. Objective C02 3. Scope of Study C02 4. Study Overview C Technology Consideration C Coal Resources in Alberta C05 5. In-situ Coal Gasification Technology Options C Parallel-CRIP Technology C Linear-CRIP Technology C Enhanced Linked Vertical Well (Enhanced-LVW) Technology C06 6. Power Generation from ISCG Syngas C Air vs Oxygen and Oxidant for Syngas Production C Base Cases C Study Case C07 7. Key Performance Metrics C08 8. Greenhouse Gas Emissions C08 9. Economic Results C First Year Cost for Power C Capacity Factor Sensitivity C Environmental and Regulatory Permitting of ISCG C Conclusions C Recommendations and Future Work C11 Figures and Tables Table 1: Figure 1: Figure 2: Figure 3: Table 2: Table 3: Figure 4: Figure 5: Summary of Major Alberta Coal Zones C05 Schematic of the Parallel-CRIP Configuration Showing the Location of the Process Points (Graphic Courtesy of Carbon Energy Limited) C05 CRIP Maneuvers and New Reaction Zone Ignition in Linear-CRIP C06 The Enhanced-LVW Configuration C06 Summary of Major Performance Metrics C07 Comparison of CO 2 Emissions for Different Study Cases C07 First Year Cost of Power (2016) C09 Impact of Capacity Factor on Required First Year Cost of Power C10 C01 Canadian Clean Power Coalition: Appendix C

49 In-situ Coal Gasification 1. Background In-situ coal gasification (ISCG) is an emerging, transformational clean energy technology with tremendous potential to support a long term sustainable Alberta economy by unlocking significant deep coal resources. ISCG is a method to extract energy from deep, currently unmineable coal seams. Oxygen (or air) and steam are injected into a coal seam through an injection well. The oxidants react with the coal in-situ through a set of pyrolysis, gasification and oxidation reactions to produce synthesis gas (syngas) comprising primarily CH 4, CO, H 2, CO 2 and trace gases such as H 2 S. Syngas, which is brought to the surface through a production well, can be used to produce a range of products including power and liquid fuels. 2. Objective The objective of this study was to provide sufficient background information on in-situ coal gasification to a group of diverse stakeholders to set the foundation for the development of an industry/government consortium leading to ISCG field demonstration pilot test work to support commercialization. Carbon Development Partnership, Alberta Innovates Energy and Environment Solutions and the Canadian Clean Power Coalition have jointly funded this study. The study focused on the technical requirements and economic merits of employing ISCG derived syngas for use in a Once Through Heat Recovery Steam Generator (OTSG), a Fischer-Tropsch (FT) liquids plant and a combined cycle power plant. The focus of this report is on the results for the combined cycle power plant. A future demonstration pilot test (outside the scope of this study) would: Use the most promising ISCG technology for the selected site Study syngas use Provide adequate field data to evaluate the value proposition and associated costs Demonstrate greenhouse gas reduction opportunities Support policy development Lead, ultimately, to several commercial ISCG operations in Alberta The study had the following broad objectives: Technical: To accelerate the deployment of ISCG technology in Alberta. Screening level data was compiled to educate participants on the key operational attributes, technology options and risks associated with ISCG technology. Economic: To use the technical data generated to evaluate the value proposition and business case for the ISCG technology for selected Alberta coal seams. Pathway to Commercialization: To identify follow-up activities to support the development of an industry/ government consortium leading to ISCG field demonstration pilot test work and ultimately, commercialization. The information generated could be used as part of an overall package to demonstrate the importance of developing Alberta s deep coal resources. However, the development of a demonstration pilot plant is outside the scope of this study. 3. Scope of Study The overall work completed for this study is described below. Technical ISCG Technology Comparison: An evaluation of the most promising ISCG technologies (Parallel-CRIP [controlled retraction of the injection point], Linear CRIP and linked vertical wells [or a combination thereof]). Technical/Operational Challenges: A brief review of the operational and technical challenges that may have historically limited the widespread commercial adaptation of the ISCG technology. Enabling Technologies: A review of recent advances in key technologies (e.g. horizontal drilling) that may enable the cost effective commercialization of ISCG technologies. Canadian Clean Power Coalition: Appendix C C02

50 Complementary Technologies: A high level comparison with partial combustion based bitumen extraction technology and steam assisted gravity drainage (SAGD) operations. Drilling Costs: To the extent possible, indicative costs associated with in-situ drilling requirements for each technology option and indicative cost savings from optimizing the scale-up from single modules to multiple modules for each technology were reviewed. Computer Modelling of ISCG: A review of applicable ISCG modelling techniques and a preliminary performance comparison between ISCG technologies to the extent possible. Environmental Environmental Monitoring Requirements: A high level review of environmental and process monitoring requirements for selected coal seams. Review of Environmental Factors: GHG Footprint: A proof of concept level evaluation of the greenhouse gas (GHG) reduction options from ISCG relative to regulatory requirements to reduce GHG. Groundwater: The considerations required in the plant design to avoid groundwater problems were addressed. Ground Subsidence: The considerations required in the plant design to avoid surface subsidence problems were addressed. Economics Expected CAPEX/OPEX Reductions: Screening level engineering studies were completed to further quantify the Alberta-specific value proposition for ISCG syngas to selected final products. A comparison of the expected reduction in capital expenditures/ operating expenditures (CAPEX/OPEX) and economics for the use of ISCG technology compared to the current/expected reference (base) cases for each end product identified below (power, FT-liquids, SAGD steam) was conducted. Regulatory/Permitting Roadmap for Environmental/Regulatory Permitting: An overview of the environmental and regulatory permitting requirements in the province of Alberta, based on a review of the applications for ISCG pilot plants recently approved under the experimental provisions by the province. Determined the environmental and regulatory permitting requirements for both a field demonstration facility and an eventual commercial facility. Commercialization Roadmap for Commercialization: A high level road map and progressive activity list were developed for a stage-gate pathway towards the commercial application of ISCG in Alberta. 4. Study Overview 4.1. Technology Consideration In the in-situ coal gasification (ISCG) process, oxygen (or air) and steam are injected into a deep coal seam through an injection well. The oxidants react with the coal in-situ through a set of pyrolysis, gasification and oxidation reactions to produce synthesis gas (syngas) comprising primarily of CH 4, CO, H 2, CO 2 and trace gases such as H 2 S. Syngas, which is brought to the surface through a production well, can be used to produce a range of products including power, boilers, transportation fuels and petrochemicals. The technical and economic value proposition of ISCG technology for deep Alberta coal seams is evaluated in this report. Key Findings Alberta has vast quantities of geologically continuous, currently unmineable deep coal resources that could potentially be recovered through in-situ coal gasification (1.5 trillion tonnes at depths of 250 to 3,600 m and with seam thicknesses of up to 12 m to support multiple commercial scale operations). The well drilling and completions technologies required for in-situ coal gasification are relatively well established and commercially proven for in-situ bitumen extraction from the oil sands, and could be readily adapted. C03 Canadian Clean Power Coalition: Appendix C

51 The marginal cost of syngas production from an integrated ISCG/FT liquids facility can be significantly lower than the current price of natural gas due to the high level of integration with the oxygen supply and ISCG process requirements. Once constructed, an ISCG syngas plant could become a predictable, cost stable, low-cost supplier of energy for a base load fuel or syngas processing application for: The production of FT transportation fuels, essentially eliminating the natural gas price volatility impact on the economics of a conventional gas to liquids plant; power generation while meeting new federal regulations on greenhouse gas emissions from coal based power plants and cost competitive with natural gas-fired combined cycles operating as base load units (95 per cent capacity utilization) at projected natural gas prices. Use as a boiler fuel for steam assisted gravity drainage operations, replacing natural gas. The analysis indicates that there would be essentially no change to the boiler performance due to the fuel switch to syngas and minimal retrofit costs. In addition, a 10 to 15 per cent reduction in the greenhouse gas intensity (tonne of CO 2 per barrel produced) for bitumen production could be achieved compared to using natural gas a fuel. Surface processing facilities to treat the syngas are based on commercially proven processes. Environmental and regulatory permits for an ISCG facility can be obtained; the Alberta regulatory regime is one of the most advanced jurisdictions in the world with respect to ISCG permitting. The study finds that the ISCG technology and economics look promising. However the analysis assumes a long term, consistent syngas quality and quantity, which must be confirmed through site specific field demonstration. A key limitation of the study is the reliance on computer simulations, using design conditions significantly beyond existing operating experience, such as: Deeper coal seams (> 200 m depth); and Continuous operation at greater commercial scale syngas production rates. It is therefore recommended that commercialization of the technology in Alberta be preceded by field demonstration of ISCG technology by a consortium of interested parties to generate the required performance and scale-up data to support commercialization, including: Investigating a strategy for commercialization of the ISCG technology as initially a complementary, not primary, feedstock source for an existing or new commercial scale facility where the syngas production can be gradually incorporated into commercially proven operations. Finalizing a strategy for field demonstration that stages promising ISCG Technologies, capital outlay, minimizes scale-up risk and maximizes scale-up data generation and results in an optimized ISCG Module configuration for a specific site. Conducting targeted screening level technical and regulatory work to define the requirements for a site-specific, scale-up and commercialization focused field demonstration of ISCG technology in Alberta. Developing a better understanding of ISCG technology through controlled laboratory physical test work coupled with advanced computer modelling. Canadian Clean Power Coalition: Appendix C C04

52 4.2. Coal Resources in Alberta Alberta s coal resources, at depths greater than 150 m, are estimated by the Alberta Geological Survey to be in excess of two trillion tonnes, while the surface coal resource is estimated to be 33 billion tonnes. The energy value in these resources is greater than the energy value of all of Alberta s oil and gas resources combined, including the oil sands. The major coal zones of the plains area of Alberta are the Ardley coal zone, the Drumheller coal zone, and the Mannville coal zone; the estimated tonnage in place is summarized in Table 1 (based on publicly available data from over 350,000 oil and gas boreholes that have been drilled historically, and 15,000 to 20,000 boreholes that are added to the database annually). Table 1: Summary of Major Alberta Coal Zones Coal Zones Area (km 2 ) Coal (Gt*) Depth Range (m) Seam Thickness Ardley up to 10 m Drumheller up to 5 m Mannville up to 12 m * Gt (gigatonnes or billion tonnes) 5. In-situ Coal Gasification Technology Options Alberta has the diverse technical know-how to commercialize ISCG technology because of significant expertise in drilling and completions technology, chemical processing, carbon capture and the extensive conventional and unconventional oil and gas industry in the province. Three ISCG technologies evaluated for this study are described next Parallel-CRIP Technology In the Parallel-CRIP (Controlled Retraction of the Injection Point) module shown in Figure 1, two process wells (injection and production wells) are drilled in-seam parallel to each other. The two wells are deviated towards each other at the end of the in-seam section (horizontal reach) and converged towards a third vertical borehole that is used to ignite the surrounding coal. Once the coal is ignited, the ignition point is continually retracted as the coal continues to gasify. Multiple modules operating simultaneously would be expected to generate the syngas required for a commercial scale operation. Figure 1: Schematic of the Parallel-CRIP Configuration Showing the Location of the Process Points (Graphic Courtesy of Carbon Energy Limited) C05 Canadian Clean Power Coalition: Appendix C

53 5.2. Linear-CRIP Technology The Linear-CRIP Module comprises a deviated in-seam injection linked to a vertical production well as shown in Figure 2. Coal ignition around the injection point gasifies the surrounding coal to the point in time where the quality and quantity of the syngas is not acceptable. The injection point is then retracted into fresh coal and re-ignited. Figure 2: CRIP Maneuvers and New Reaction Zone Ignition in Linear-CRIP 5.3. Enhanced Linked Vertical Well (Enhanced-LVW) Technology In this technology, modules comprise at least two vertical wells per panel (Figure 3). Linkage between the wells is achieved by enhancing permeability of the seam by additional means such as coiled tube or horizontal drilling. The exact configuration of wells required to extract energy from a panel is considered proprietary. Figure 3: The Enhanced-LVW Configuration Canadian Clean Power Coalition: Appendix C C06

54 6. Power Generation from ISCG Syngas This section summarizes the operational performance, capital and operating costs and economics for a plant to generate power from syngas produced from an in-situ coal gasification (ISCG) facility in Alberta, Canada. The potential cases of interest are based on the choice of oxidant for the ISCG process and the required level of CO 2 capture: Air blown vs. oxygen (95 mol% or 99.5 mol%) blown in-situ gasification Sufficient CO 2 capture to meet Canadian federal regulations for CO 2 emissions intensity for coal fired power generation (0.42 tonne/mwh) 6.1. Air vs Oxygen and Oxidant for Syngas Production The bulk of the parasitic power loads at the power generation facility to supply oxidant vary depending on the coal seam depth. These parasitic power loads consist of: The air separation unit (for oxygen blown ISCG) including oxygen compression Air compressors (for air blown ISCG) Diluent nitrogen compressors (if required) Syngas compressor (for shallow seams <500 m) and syngas expander (for deep seams >600 m) 6.2. Base Cases The two base cases for comparative purposes were prepared: Base Case (Base-1): Current state of the art 500 MW Gasifier IGCC (Case 1) based on surface mined coal and surface gasification technologies. Base Case (Base-2): A base loaded natural gas combined cycle (NGCC) 2 X 1 F-Class power plant. In consultation with the Study Group, the following unit operations were pre-selected for Base-1 to allow comparison to previous studies conducted: acid gas removal (AGR) (Selexol ), sulphur recovery unit (SRU) (Claus) and Gas Turbine (F-Class Syngas) technologies for syngas processing Study Case The target CO 2 emissions intensity for the partial capture cases is tonne CO 2 /MWh as stipulated by new Canadian federal regulations for coal fired power generation facilities. Sufficient cost data for the partial capture Case P2 was provided to allow the cost estimate for the other complementary case (Case P1) to be approximated through elimination of major processing blocks. None of the air blown ISCG cases (Case P4, P5 and P6) were evaluated based on the initial assessment of air fired vs. oxygen fired ISCG plant. A linear CRIP configuration was used for the economic analysis. Auxiliary power loads All other power loads at the power generation facility are expected to be essentially constant and do not impact this analysis. A thorough analysis was completed comparing the costs of operating with air rather than oxygen. It was determined that oxygen works best the greater the depth of the seam, and deeper seams have better economics. Therefore, a decision was made to incorporate the use of oxygen into the cases studied. C07 Canadian Clean Power Coalition: Appendix C

55 7. Key Performance Metrics The major operating metrics calculated in the study are summarized in Table 2. Table 2: Summary of Major Performance Metrics Pulverized Coal Power ISCG (Case # P2) IGCC Part CCS Base-2 (NGCC) No CO 2 Capture With CO 2 Capture Net Power Generation (MW) Design Life (Years) Average Capacity Factor (%) Available Pre-combustion Carbon Captured (%) ~53 GHG Intensity (tonne/mwh) Heat Rate (GJ/MWh) In all CO 2 capture cases, CO 2 is dried and compressed and sent to the battery limit. No transportation or sequestration costs are included in the analysis. Capital intensities show that an ISCG plant could reduce the required capital expenditures by 60 per cent from IGCC and almost 40 per cent from a pulverized coal plant with CO 2 capture, but would still cost more than twice as much as NGCC. 8. Greenhouse Gas Emissions Table 3 shows CO 2 emissions for each case studied. The carbon content that exists within methane was not captured and hence ends up as CO 2 emissions from the power generation facility, for both the ISCG and NGCC cases. Table 3: Comparison of CO 2 Emissions for Different Study Cases Base Case-1 Case P2 Base Case-2 IGCC (Full Capture) O 2 Blown ISCG (Partial Capture) NGCC (No Capture) % Carbon Capture N/A Carbon Intensity (Kg/MWh) Canadian Clean Power Coalition: Appendix C C08

56 9. Economic Results 9.1. First Year Cost for Power The ISCG case for power generation has been designed to capture enough CO 2 to meet the new Canadian federal regulations stipulating an emission limit of 0.42 tonne CO 2 /MWh for coal based power generation facilities. Compression costs for the captured CO 2 are included for all ISCG cases. There is a significant methane content in the ISCG syngas, and thus while 89 per cent of the CO 2 in the syngas is captured prior to combustion, this corresponds to only 51 per cent carbon capture prior to combustion. The CAPEX intensity for the ISCG syngas case is nearly 60 per cent lower than for the surface gasifier based combined cycle power generation unit; the ISCG syngas CAPEX is nearly 40 per cent lower than a pulverized coal power plant with post combustion CO 2 capture. Approximately 50 per cent of the ISCG syngas CAPEX is required for raw syngas clean-up, processing and CO 2 capture and compression. The first year cost of power is derived by setting the price for power in the first year escalated by 2 per cent in following years such that the net present value of the project equals zero. The required first year selling price for power for the ISCG syngas case is approximately onethird of the price required for a similar IGCC facility. This is comparable to that required for a traditional pulverized coal power plant, and significantly lower than for a pulverized coal power plant retrofitted with carbon capture technology at a similar capture level. The first year price of power required for an NGCC unit is very sensitive to changes in the price of natural gas (high commodity price risk). On the other hand, ISCG syngas will provide the power producer a stable cost for fuel over the long term. Figure 4 illustrates the comparison of the required first selling price (2016) of power required to achieve an after-tax un-levered internal rate of return (IRR) of 9 per cent for the six comparative cases. Figure 4: First Year Cost of Power (2016) First Year Cost ($/MWh) (20) ISCG IGCC (Partial CCSO) NGCC (50% CF) NGCC (95% CF) Coal (No CCS) Coal (Part CCS) Note from Figure 4: An NGCC plant with a 95 per cent capacity factor has a slightly lower first year cost of power than the ISCG plant. This means that for the same all hour power price, the NGCC unit operating at 95 per cent capacity factor would have a higher IRR than the ISCG plant. Given the relatively high marginal cost of the NGCC unit, it will likely only run roughly 50 per cent of the time. The ISCG plant will have a very low marginal cost and will therefore run most of the time. The required first year selling price for power for the ISCG case is comparable to that required for a traditional pulverized coal power plant, and significantly lower than for a pulverized coal power plant that deploys post-combustion carbon capture technology with a similar CO 2 emission intensity (0.42 tonne CO 2 /MWh). The required first year selling price for power for ISCG is approximately one third of the price required for a comparable IGCC facility ($82/MWh compared to $247/MWh). C09 Canadian Clean Power Coalition: Appendix C

57 9.2. Capacity Factor Sensitivity Figure 5 shows a comparison between the first year cost of power for the ISCG and NGCC cases as the capacity factor of the plant changes. The NGCC case would have to operate with a capacity factor of about 80 per cent (purple line) to have a similar first year cost as the base loaded ISCG case operating at a 95 per cent capacity factor. The capacity factor of the ISCG case would have to be reduced to about 70 per cent (green line) to match the first year cost of the NGCC case operating at a peak loaded capacity factor of 50 per cent. However, given that the NGCC case is expected to run only during higher priced periods, it is not clear whether the NGCC or the ISCG unit will be more profitable at the applicable forecasted power prices. Figure 5: Impact of Capacity Factor on Required First Year Cost of Power ISCG NGCC First Year Power Cost ($/MWh) CCGT Capacity Factor 10. Environmental and Regulatory Permitting of ISCG Permits for an ISCG facility can be obtained; the Alberta regulatory regime with respect to ISCG is more advanced than most jurisdictions in the world. The regulatory process is well laid out for the orderly development of energy related resources, including for ISCG technology demonstration and commercialization. The potential environmental impacts of ISCG are well known and technology exists to mitigate potential issues: Proper site selection is the most important mitigating factor for environmental effects Surface subsidence is mitigated by appropriate site selection Surface and groundwater protection is achievable through proper site selection, monitoring, and control of in-situ gasification operations 11. Conclusions In the in-situ coal gasification (ISCG) process, oxygen (or air) and steam are injected into a deep coal seam through an injection well. The oxidants react with the coal in-situ through a set of pyrolysis, gasification and oxidation reactions to produce synthesis gas (syngas) comprising primarily of CH 4, CO, H 2, CO 2 and trace gases such as H 2 S. Syngas, which is brought to the surface through a production well, can be used to produce a range of products including power, transportation fuels and petrochemicals. The technical and economic value proposition of ISCG for deep Alberta coal seams is evaluated in this report. Key findings include: Alberta has vast quantities of geologically continuous, currently unmineable deep coal resources that could potentially be recovered through in-situ coal gasification (1.5 trillion tonnes at depths of 250 to 3,600 m and with seam thicknesses of up to 12 m to support multiple commercial scale operations). Canadian Clean Power Coalition: Appendix C C10

58 The well drilling and completions technologies required for in-situ coal gasification are essentially all well established and commercially proven for in-situ bitumen extraction, and could be readily adapted. The marginal cost of syngas production from a stand-alone ISCG facility is significantly lower than the current or projected price of natural gas. Once constructed, a facility using ISCG syngas would switch back to natural gas only if prices dropped below this marginal cost. The marginal cost of syngas production from an integrated ISCG/FT liquids facility can be significantly lower than ISCG for power due to the significant potential for integration between the ISCG syngas production facility and the FT liquids facility. An ISCG syngas plant, once constructed, could become a predictable, stable, low-cost supplier of energy for a base load fuel or syngas processing application for power generation while meeting new federal regulations on greenhouse gas emissions from coal based power plants and cost competitive with natural gas fired combined cycles operating as base load units (95 per cent capacity utilization) at projected natural gas prices. Surface processing facilities to treat the syngas are based on commercially proven processes. Environmental and regulatory permits for an ISCG facility can be obtained; the Alberta regulatory regime is one of the most advanced jurisdictions in the world with respect to ISCG permitting. 12. Recommendations and Future Work The study finds that the ISCG technology and economics look promising. However the analysis assumes a longterm, consistent syngas quality and quantity, which must be confirmed through site specific field demonstrations. A key limitation of the study is the reliance on ISCG technology vendor computer simulation results for design conditions significantly outside their operating experience: Deeper coal seams (> 200 m depth). Continuous operation at the claimed commercial scale syngas production rates. It is therefore recommended that commercialization of the technology follow from field demonstration of ISCG technology by a consortium of interested parties to generate the required performance and scale-up data to support commercialization. This means: Investigating a strategy for commercialization of the ISCG technology as potentially a complementary, not primary, feedstock source for an existing commercial scale facility where the syngas can be gradually incorporated into the existing operations. Finalizing a strategy for field demonstration that stages promising ISCG technologies, outlines capital outlay, minimizes scale-up risk and maximizes scale-up data generation and results in an optimized ISCG module configuration for a specific site. Conducting targeted screening-level technical and regulatory work to define the requirements for a site-specific, scale-up and commercialization focused field demonstration of ISCG technology in Alberta. Evaluating additional options identified during the study (but not evaluated) for even more economically attractive flowsheet options for power generation. Developing a better understanding of ISCG technology through controlled laboratory physical test work coupled with advanced computer modelling. C11 Canadian Clean Power Coalition: Appendix C

59 Appendix D Advanced Cycles A Final Phase IV Report Prepared by Electric Power Research Institute, June 2014 Table of Contents 1. Background D02 2. Report Scope D03 3. Technologies Overview D Baseline Technologies D High Temperature Power Cycles D High Temperature Topping Cycles D Bottoming Cycles D Direct Fired Cycles D Pressurized Oxy-fuel and Chemical Looping Combustion D11 4. Recommendations D Repowering Candidates D Greenfield Candidates D13 Figures and Tables Table 1: Table 2: Figure 1: Figure 2: Figure 3: Figure 4: Table 3: Table 4: Figure 5: Figure 6: Figure 7: Figure 8: Table 5: Figure 9: Performance Summary Baseline USC Coal and Natural gas Combined Cycle (NGCC) Technologies D04 Performance Summary High Temperature Power Cycle Technologies D04 Common Closed Brayton Cycle Proposed for Power Generation using Supercritical CO 2 as the Working Fluid D05 Schematic Diagram of Repowering an Existing Sub-critical Steam Plant with an A-USC Topping Turbine D05 Repowered Closed Brayton Topping Cycle (with reheat) D06 Flow Schematic of Oxy-Natural Gas Open Cycle MHD Power Generation Combined Cycle Plant (Magnetic Field direction up/down; charge collection electrodes side to side) D07 Performance Summary High Temperature Topping Cycle Technologies D07 Performance Summary Bottoming Cycle Technologies D08 Generic Cascaded Closed Brayton Cycle Configuration for a Bottoming Cycle Application D08 Simplified Schematic of Bubbling PFBC Power Plant D09 Simplified NET Power Direct-Fired Oxy-Natural Gas Process Schematic D10 Simplified Flow Diagram for Clean Energy Systems (CES) Oxy-natural Gas with CO 2 Capture Power Plant Concept D10 Performance Summary Direct-fired Power Cycle Technologies D11 Simplified Gas-side Block Flow Diagram for Aerojet Rocketdyne Pressurized Oxy-Coal Combustion Power Process D11 Figure 10: Generic Conceptual Process Schematic for Chemical Looping Combustion with CO 2 Capture D12 Table 6: Performance Summary Advanced Oxy-Combustion with CO 2 Capture Technologies D12 Canadian Clean Power Coalition: Appendix D D01

60 Advanced Cycles 1. Background The Electric Power Institute was commissioned to study numerous advanced fossil fuel combustion technologies that have lower GHG emission intensities or could be used to retrofit existing power plants to reduce GHG emissions. Thermal-electric power plants employing steam-rankine and combustion turbine power cycles are the predominant method of supplying electric power worldwide and will continue to be for the foreseeable future. At least three factors drive research and development of technologies for use in fossil fueled electric power plants in the 21st century: 1. Higher Efficiency The drive for higher efficiency in conversion of fuel energy to electricity has been paramount since the very beginnings of producing power from thermal resources and has taken on new importance in recent years as it equates to less fuel use and lower emissions (including CO 2 ). 2. Reduced Emissions Protection of public health has been a focus of electric power plant production for a century but has been given greater focus over the last 50 years. This is particularly so in the development of environmental controls to reduce conventional pollutants produced during fossil-fuelled combustion. However, emissions regulations in many regions continue to become more stringent requiring continuing advancement towards near-zero emissions. 3. Reduced CO 2 Emissions Reducing CO 2 emissions from fossil fueled power plants as a matter of public policy has been discussed widely in public forums for only about a decade. While efficiency improvements can make significant reductions in CO 2 emitted, the deep reductions thought to be necessary will require significant changes to fossil-fired power plants. These drives are not necessarily mutually supporting. For example: dramatic reductions in CO 2 emissions are likely to constrain improving net plant efficiency. The drive to improve efficiency and lower emissions has resulted in continuing, but mainly incremental improvements in fossil-fueled power plants over time, while the underlying power production technology has remained essentially unchanged. Efficiency improvements are ultimately bounded by material limits and the underlying thermodynamic properties of the working fluids. Dramatically reducing CO 2 emissions will likely have a major impact on fossil-fueled power plant cost/ efficiency based on current state-of-the art technologies for coal-fired and natural gas-fired power. This has driven interest in novel thermal-electric power technologies that can make transformational changes in fossil-fueled power plant design. A number of the technologies assessed here are directfired, incorporating the fuel combustion products directly into the power production process. These direct-fired technologies are generally applicable to any clean-burning fossil fuel, i.e. fuels that, at a minimum, do not produce solid products of combustion. In general, these technologies may use either natural gas (or other ash-free off-specification gas resources) or coal syngas produced by gasifying coal. In the second decade of the 21st century, the rapid increase in natural gas production from unconventional sources in North America has resulted in natural gas to coal price ratios significantly lower than their historical levels. The resulting availability of low-cost natural gas in North America may facilitate development of the direct-fired technologies with this clean fuel before tackling the added challenges of fueling the respective technologies with coal or coal syngas and all of the trace contaminants contained therein. With the possible exception of the low-temperature organic/nh3-rankine cycle technology, all of the technologies included here are something other than incremental changes in state-of-the-art power plant technologies identified as the baseline technologies. As such, prior to deploying any of the technologies assessed here, they will need to achieve sufficient technical readiness to warrant the potential risks of making a fundamental change in how power is produced. Achieving the requisite technical readiness to risk the large capital expenditures associated with bulk power plants will require development programs that will cost a significant fraction of the cost of a full scale power plant, but without significant return on the investments prior to the first full scale deployment. This is a public policy challenge that is not addressed in this report, but must be addressed at some time in the future if any of these technologies are to be widely deployed. D02 Canadian Clean Power Coalition: Appendix D

61 2. Report Scope The final report reviews the current status of a slate of candidate novel power cycles that might be alternatives to the incumbent steam-rankine cycle and combustion turbine combined cycle power plants used for bulk power applications (>100 MWe). The list of technologies assessed here is not intended to be exhaustive; it consists of technologies for which some level of development has been undertaken as defined by achieving a minimum Technology Readiness level (TRL) based on lab or field trials of at least TRL-5, or have real prospects of doing so shortly. Other candidate technologies can be added to this list as information on their development becomes available. For each candidate novel technology assessed here, the following are provided in the final report: Technology Description A description of the technology and the range of implementations most commonly anticipated Process Operations Extra-ordinary process operations required for deployment of the candidate technology Potential Benefits of Exploiting the Technology The potential performance of the candidate technology and a general description of the development required to achieve commercial deployment Electrical Efficiency Assessment The reported or calculated electrical efficiency of a power plant employing the candidate technology Greenfield Plant Scope of Supply The system level Scope of Supply required to implement the candidate technology Suitability and Scope for Repowering Existing Steam-Electric Power Plants How the candidate technology might be deployed at existing power plants Technical Maturity Technical readiness of the technology achieved to date based on the respective development efforts and what might be required to advance the technologies to the first commercial installation Barriers to Overcome Technical and/or economic barriers to full scale deployment of the candidate technology Reported Cost Estimates Capital and operating costs estimates for the candidate technology Multi-Pollutant Emissions Performance Reported impact of the technology on emission of criteria pollutants Suitability for Partial/Full CO 2 Capture The impact of the candidate technology on CO 2 emissions. Estimates of CO 2 emission intensity (kg/mwh, net) are included along with the suitability of the technology for biomass-fueling to reduce fossil fuel CO 2 emissions intensity 3. Technologies Overview 3.1. Baseline Technologies The electrical efficiency and CO 2 emissions intensity performance of the technologies assessed here are summarized in a series of tables below. Table 1 summarizes the baseline technologies and retrofit-to-new variations on these technologies that reduce CO 2 emissions, including atmospheric pressure oxy-pulverized coal combustion with CO 2 capture. The several options evaluated are for a nominal 90 per cent CO 2 capture. Adding CO 2 capture plants to the baseline power plants reduces their efficiency significantly. All of the post-combustion CO 2 capture options could be implemented for partial CO 2 capture with associated increases in net plant efficiency. The oxy-coal with CO 2 capture option cannot be effectively implemented for partial CO 2 capture. Oxy-combustion technologies are suitable only for high (>~90 per cent) CO 2 capture. Canadian Clean Power Coalition: Appendix D D03

62 Table 1: Performance Summary Baseline USC Coal and Natural gas Combined Cycle (NGCC) Technologies Technology Coal-fired USC Steam Electric Net Plant Efficiency (HHV) CO 2 Emissions Intensity (Net Output Basis) Baseline 39.2% 836 kg/mwh MW gross generation, Retrofit to New PCC 27.2% 111 kg/mwh PRB coal, 604 C TIT, 90% CO 2 Capture Atmospheric Pressure Oxy-coal 31.5% 106 kg/mwh Natural Gas Combined Cycle Baseline 51.5& 351 kg/mwh F-class CT, 566 MW Retrofit to New PCC 45.1% 38 kg/mwh gross generation With PCC and CO 2 Recycle 45.7% 40 kg/mwh Notes 3.2. High Temperature Power Cycles Table 2 summarizes the performance of two very high temperature (~700 C) power cycles, the advanced, ultra-supercritical (AUSC) steam cycle and a closed Brayton power cycle using supercritical CO 2 as the working fluid. The net plant efficiency of power plants employing these power cycles is commensurate with the increase in turbine inlet temperature. As they are not gas-side technologies, they do not directly impact CO 2 emissions intensity other than a reduction due to reduced fuel use associated with higher net efficiency. The most basic version of the Super Critical CO 2 Brayton (SCO 2 ) cycle being investigated is shown in Figure 1 as the Simple Cycle. The steps of the cycle include: Compression CO 2 near ambient temperature and at a pressure above the critical pressure (1) is compressed to high pressure (2). As the density change is modest, there is only a modest temperature rise due to compression Recuperative Heat Recovery The warm, high pressure CO 2 (2) is pre-heated by the hot turbine exhaust (5) Heat Addition The pre-heated, high pressure CO 2 (4) is heated to turbine inlet temperature by the heat source Expansion The hot, high pressure CO 2 (4) is expanded to a pressure marginally above the critical pressure (5) to produce power Heat Recovery The hot, lower pressure CO 2 (5) is pre-cooled by the cool, high pressure CO 2 (2) in the recuperator Cooling The cool, lower pressure CO 2 (6) is further cooled to near ambient temperature by cooling water or ambient air There are other configurations employing reheat and recompression. Table 2: Performance Summary High Temperature Power Cycle Technologies Technology Net Plant Efficiency (HHV) CO 2 Emissions Intensity (Net Output Basis) AUSC Baseline, ~700 C TIT 42.7% 768 kg/mwh MW gross generation, PRB coal High Temperature Closed Brayton Power Cycle, 700 C TIT Up to 45% As low as 730 kg/mwh Notes Dependent on thermal integration with a fired CO 2 heater, designs yet to be prepared. D04 Canadian Clean Power Coalition: Appendix D

63 Figure 1: Common Closed Brayton Cycle Proposed for Power Generation using Supercritical CO 2 as the Working Fluid 3.3. High Temperature Topping Cycles Table 3 summarizes the performance of three high temperature topping cycles. Adding an AUSC steam topping cycle, as shown in Figure 2 increases the capacity of a sub-critical bottoming cycle by approximately 22 per cent with a corresponding increase in net plant efficiency of 8-9 percentage points. The same is generally true for adding a closed Brayton topping cycle as shown in figure 3. As neither of these are gas-side technologies, they do not directly impact CO 2 emissions intensity other than a reduction due to reduced fuel use associated with higher net efficiency. Figure 2: Schematic Diagram of Repowering an Existing Sub-critical Steam Plant with an A-USC Topping Turbine Repowering&InstallaNon& ExisNng&Plant Steam& Reheater& A"USC& Main& Steam& Generator A"USC& Topping& Turbine IP&Turbine LP&Turbine HP& Turbine Condenser FW8 (New) FW7 FW6 FW5 Feedwater& Pump DEA FW3 FW2 FW1 Condensate& Pump Canadian Clean Power Coalition: Appendix D D05

64 In this configuration, as shown in Figure 3, an additional Closed Brayton cycle provides heat to existing steam turbines. Heat in the super-critical CO 2 working fluid exiting the IP turbine provides heat to produce steam supplied to existing turbines are points nine and 11 below. Natural gas is used to provide the heat required before points one and three below. Figure 3: Repowered Closed Brayton Topping Cycle (with reheat) Figure 4 shows a magneto-hydrodynamic (MHD) topping cycle. Direct current (DC) power is produced by an MHD generator when: The high temperature gas plasma containing positive ions and free electrons is accelerated through the MHD flow channel. Plasma is produced by high temperature oxy-combustion of fuel The positive ions and electrons are forced in opposite directions to collector electrodes by the magnetic field imposed on the flow channel The electrons from the anode flow through an external circuit to combine with the positive ions at the cathode There are reasonable prospects that an oxy-natural gas MHD plant with CO 2 capture will perform better than an NGCC plant with CO 2 capture. The MHD technology, however, will require significant development to achieve this better performance. D06 Canadian Clean Power Coalition: Appendix D

65 Figure 4: Flow Schematic of Oxy-Natural Gas Open Cycle MHD Power Generation Combined Cycle Plant (Magnetic Field direction up/down; charge collection electrodes side to side) Inverter To&CO 2 & Compression Fuel&Gas Oxygen Combustor Magnet HRSG Seed& Recovery Magnet Seed&Regenera>on&and&Reinjec>on Steam&Turbine-& Condenser All of these topping cycle technologies could be used to repower existing plants. The AUSC and closed Brayton cycle technologies are not gas-side technologies and do not directly impact CO 2 emissions intensity other than a reduction due to reduced fuel use associated with higher net efficiency. The oxy-natural gas MHD technology is, like other oxy-combustion technologies, suitable for plants that require high levels of CO 2 capture. Table 3: Performance Summary High Temperature Topping Cycle Technologies Technology Net Plant Efficiency (HHV) CO 2 Emissions Intensity (Net Output Basis) AUSC Topping Cycle 40.7% 10% reduction ~22% increase in net plant capacity. Dependent on existing steam cycle efficiency Closed Brayton Topping Cycle 42.4% 17% reduction ~24% increase in net plant capacity. Dependent on existing steam cycle efficiency MHD Topping Cycle (Oxy-natural Gas) Notes 41%-53% <40 kg/mwh Steam-electric bottoming cycle Canadian Clean Power Coalition: Appendix D D07

66 3.4. Bottoming Cycles Table 4 summarizes the performance of two bottoming cycle technologies. The closed Brayton bottoming cycle is an alternative to the standard steam-rankine bottoming cycles used for combustion turbine combined cycles. The closed Brayton bottoming cycle as shown in Figure 5, may be an attractive option for adding to small 30 to 50 MW simple cycle gas turbines since they may be less expensive than comparable steam-rankine bottoming cycles at this size. While commonly used to convert lower temperature heat resources to power, the ammonia/organic Rankine bottoming cycle application assessed here is as a replacement for (and amendment to) the last few low pressure stages of a steam turbine. The most likely application for this technology is for those plants that require dry cooling. In these applications, there may be a capital cost benefit for the bottoming cycle technology. The technology may also be suitable for exploiting very low condensing temperatures as are found in high latitudes. Various configurations employing heat from flue gas, condensing steam and other sources of low grade steam have been studied. Table 4: Performance Summary Bottoming Cycle Technologies Technology Closed Brayton Bottoming Cycle (NG-fueled Aero-derivative CT) Ammonia/Organic Rankine Bottoming Cycle Net Plant Efficiency (HHV) CO 2 Emissions Intensity (Net Output Basis) 50% 33% reduction Up to 5 percentage point increase at 4 C condensing temperature Reduction commensurate with efficiency increase Notes Benefits are maximized for air-cooled condensers Figure 5: Generic Cascaded Closed Brayton Cycle Configuration for a Bottoming Cycle Application Flue&Gas Combus6on& Turbine&Exhaust Recuperators Power&Turbine&1 Compressor Power&Turbine&2 D08 Canadian Clean Power Coalition: Appendix D

67 3.5. Direct Fired Cycles If a fluidized-combustor is operated at pressure, as shown in Figure 6, the flue gas can be expanded through a gas turbine to generate electricity in addition to that generated by the steam turbine. This combined cycle arrangement raises generating efficiency approximately four percentage points higher than the steam cycle alone. The only pressurized fluidized-bed combustors (PFBC) plants that have entered commercial service are bubbling beds. The 850 C (1560 F) flue gas leaving the PFBC cyclones is cooled going into the CO 2 capture process and reheated coming out of the CO 2 capture process in a tubular recuperator. The CO 2 capture technology proposed by Sargas is based on the Benfield process which uses a potassium carbonate/bicarbonate chemistry. The absorption and desorption are conducted at approximately the same temperature, near 100 C (212 F). Absorption is conducted at flue gas pressure (~12 bar). Desorption is conducted at a lower pressure. Thermal use is between 680 and 910 Btu/lb CO 2 (1,580-2,120 kj/kg CO 2 ). The cooled flue gas passes through the capture plant and the CO 2 -depleted flue gas flow passes back through the recuperator to be reheated to 815 C (1500 F) before being expanded through the turbine. Figure 6: Simplified Schematic of Bubbling PFBC Power Plant Fuel/Sorbent CO 2 * Capture * Compressor Gas*Turbine HP*Steam* Turbine LP*Steam* Turbine Air Condenser Flue*Gas Ash* coolers FW5 FW4 Feedwater* Pump DEA FW2 FW1 Condensate* Pump Inter2cooler Fly*Ash Canadian Clean Power Coalition: Appendix D D09

68 The CO 2 -cooled technology being pursued by NET Power, as shown in Figure 7 below, is a direct-fired version of the closed Brayton cycle technology. It may have an efficiency with CO 2 capture as high as the baseline NGCC technology without CO 2 capture; a notable feat, if it can be achieved. Figure 7: Simplified NET Power Direct-Fired Oxy-Natural Gas Process Schematic Oxygen Natural-Gas Carbon-Dioxide Auxiliary--heat-recovery Fuel/O 2 -compressors Inter8coolers Combustor Compressors Power-turbine Water Recupera=ve-Heat-Excahngers In the Clean Energy System (CES) process shown in Figure 8, fuel is combusted with pure oxygen in the presence of steam. This produces a high purity stream of CO 2 flue gas, which can be dried and compressed. Figure 8: Simplified Flow Diagram for Clean Energy Systems (CES) Oxy-natural Gas with CO 2 Capture Power Plant Concept O 2 $ compressor Fuel$gas$ compressor HP$ Combustor Reheat$ combustor LP$turbine HP$ turbine IP$ turbine CO 2 $to$storage CO 2 $pipeline$ compressor CWS CWR Net$water$produc2on Feedwater$pump Condenser D10 Canadian Clean Power Coalition: Appendix D

69 Table 5 summarizes the performance of one direct, coal-fired technology and two direct-fired oxy-natural gas combustion turbine technologies. The turbo-charged boiler technology is being advanced for coal-fired power with CO 2 capture. The data in Table 5 should be compared to the corresponding coal-fired CO 2 capture cases in Table 1. It appears that the turbocharged boiler (Bubbling PFBC) technology might have higher net plant efficiency at high CO 2 capture than the retrofit-to-new baseline technologies. Both of the oxy-natural gas combustion turbine technologies (CES, NET Power) are expected to have negligible CO 2 emissions. The water-cooled technology being pursued by CES looks to be approximately as efficiency as NGCC with CO 2 capture. Table 5: Performance Summary Direct-fired Power Cycle Technologies Technology Turbo-charged, Coal-fired Boiler with Benfield CO 2 Capture Net Plant Efficiency (HHV) CO 2 Emissions Intensity (Net Output Basis) 36.3% 94 kg/mwh CO 2 -cooled Oxy-natural Gas CT 53.1% nil NET Power Water-cooled Oxy-natural Gas CT 35%-45% nil Depends on final configuration. Clean Energy Systems Notes 3.6. Pressurized Oxy-fuel and Chemical Looping Combustion Table 6 summarizes the performance of two classes of advanced oxy-coal with CO 2 capture technologies. These performance results should be compared with the retrofit-to-new PCC and atmospheric pressure oxy-coal results in Table 1. Both of these technologies have the potential for higher efficiency than either of the baseline technologies with CO 2 capture. As with all oxycombustion technologies for CO 2 capture, these options cannot be effectively implemented for partial CO 2 capture and are suitable only for high levels of CO 2 capture. Figure 9 shows a schematic for an oxy-fueled pressurized fluidized bed combustion process. Coal is combusted at high pressure with oxygen. Steam is created by the heat in the fluidized bed and is used to drive steam turbines. Figure 9: Simplified Gas-side Block Flow Diagram for Aerojet Rocketdyne Pressurized Oxy-Coal Combustion Power Process Coal. Limestone. Moist.N 2. to.vent Vent.Gas ASU.Air. Compressor ASU. Cold. Box N 2 O 2 Milling Feeders CO 2.Recycle. HRSG.Heat. Recovery. ParCculate. Filter Latent.Heat. Recovery/wash CO 2. PurificaCon. Unit CO 2.Pipeline. Compressor CO 2.to. Pipeline Air O 2. Compressor ConvecCon. Heat. Transfer Bubbling. Bed.Heat. Transfer BFW Steam) Cycle Steam. Cycle Fly. Ash Condensate. to.waste BFW Canadian Clean Power Coalition: Appendix D D11

70 Figure 10 shows a schematic of a chemical looping combustion process. An oxygen carrier in the fuel reactors liberates oxygen to combust the fuel. A hot flue gas consisting of mainly CO 2 and water is produced. The gas is used to produce steam that is then used to drive steam turbines. Once it is cooled, the flue gas is dried to remove water and compressed for delivery to a pipeline. The spent oxygen carrier is set to the air reactor where it is exposed to air. Oxygen is added to the carrier and it is returned to the fuel reactor. Figure 10: Generic Conceptual Process Schematic for Chemical Looping Combustion with CO 2 Capture Vi,ated$ Air Vent$Gas CO 2 $ Purifica,on$ Unit CO 2 $to$ Pipeline Air$Reactor Fuel$Reactor CO 2 $Pipeline$ Compressor Air BFW Steam$ Cycle Fuel Steam$ Cycle BFW Table 6: Performance Summary Advanced Oxy-Combustion with CO 2 Capture Technologies Technology Net Plant Efficiency (HHV) CO 2 Emissions Intensity (Net Output Basis) Notes Pressurized Oxy-coal Combustion 33%-37% kg/mwh Aerojet-Rocketdyne and WUSTL Technology Chemical Looping Combustion 35.2% 27 kg/mwh B&W / OSU Technology 4. Recommendations 4.1. Repowering Candidates Repowering and life extension of existing power plants are very similar options. Decisions to undertake either strategy rather than build new capacity depend on a wide variety of factors including condition of existing equipment, electrical market conditions, permitting (or re-permitting) costs, etc. A number of the technologies assessed here will be technically suitable for repowering. Whether they are economically suitable for repowering must be made on a case by case basis. The technologies suitable for repowering are listed below along with recommendations for CCPC involvement in development of the respective technologies. Advanced, Ultra-Supercritical (AUSC) Steam Topping Cycle Materials meeting the ASME boiler and pressure vessel code and the ASME piping code have been developed. These materials have not yet been shown to be durable in coal-fired boiler service. This is the major challenge to serious consideration of repowering an existing sub-critical steam-electric plant with an AUSC topping turbine. While achieving lower CO 2 emissions associated with the higher D12 Canadian Clean Power Coalition: Appendix D

71 efficiency AUSC steam power cycle, by itself, this repowering option will not result in a coal-fired power plant achieving CO 2 emissions of 420 kg/mwh (net). A gas-side technology change would be required to meet this emissions standard. Recommendation: Maintain a watching brief on worldwide activities that seek to assess durability of AUSC materials in coal-fired service. Closed Brayton Topping Cycle In addition to the scope identified for AUSC Topping cycle indicated above, closed Brayton cycle technology will also need to be developed in order to adopt this repowering option. Recommendation: In addition to maintaining a watching brief on high temperature heat transfer materials, a watching brief should be maintained on development of closed Brayton cycle technology. Participation in one or more pilot deployments of this technology might also be considered. MHD Topping Cycle A considerable amount of research and development will be required to bring MHD technology to sufficient technical readiness for a field deployment. On the other hand, early deployments of this technology are likely to be repowering projects. Recommendation: Maintain a watching brief on development of MDH technology, and look for opportunities to nominate suitable power plants for scoping studies. Closed Brayton Bottoming Cycle This technology is probably suitable only for repowering aero-derivative combustion turbines and is not a suitable technology for repowering coal-fired steam-electric plants. Recommendation: No recommendation. Organic/Rankine Bottoming Cycle The economic feasibility of deploying this technology has not been rigorously assessed. In addition to the efficiency/ capacity benefit at low ambient temperatures, there may be a significant capital/maintenance benefit if air-cooling is required. Nonetheless, consideration of this technology for repowering will entail significant assessment of the existing steam turbine and condenser. It is likely that deploying this technology in a repowering application will be necessary before it can be seriously considered for net-build. Recommendation: One or more site-specific studies should be undertaken to detail the costs of repowering with a bottoming cycle. This study should include capital, fuel operating and non-fuel operating benefits with projections for the new-build case. Turbocharged Boiler with CO 2 Capture The base turbocharged boiler technology has achieved technical maturity but has not achieved widespread commercial acceptance. The addition of partial pressurized post-combustion CO 2 capture to the f low sheet results in an overall package that might be suitable for repowering to achieve CO 2 emissions of 420 kg/mwh (net). (The scope may also include installing a topping turbine to increase capacity/efficiency). Recommendation: The next step for evaluating this technology is to conduct a site-specific engineering and economic evaluation to scope the repowering effort and develop capital costs as well as overall operating benefits. Pressurized Oxy-coal and Chemical Looping Combustion The scope of a repowering project will be nearly the same for these technologies; the existing boiler is demolished along with much of the air quality control system. A new steam generator is installed to supply the existing steam turbine. (The scope may also include installing a topping turbine to increase capacity/efficiency.) Both of these technologies are best suited for high CO 2 capture; the partial capture benefits are modest to achieved 420 kg/mwh (net), rather than <100 kg/mwh (net) for which the technologies are well-suited. On the other hand, if there is an enhanced oil recovery (EOR) market for the captured CO 2, these technologies may be very suitable for repowering. Recommendation: Maintain a watching brief on the several development efforts for this technology. Any systematic evaluation of repowering options should include these options, particularly if an EOR market for the captured CO 2 is anticipated Greenfield Candidates The primary constraint to deployment of new coal-fired power plants in Canada will be achieving CO 2 emissions under 420 kg/mwh (net). It will not be possible to achieve these emissions levels by improving power cycle efficiency; active measures on the combustion side will be required. Canadian Clean Power Coalition: Appendix D D13

72 The technologies suitable for greenfield coal-fired power plants are listed below, along with recommendations for the CCPC to be involved in development of the respective technologies. Advanced, Ultra-supercritical (AUSC) Steamelectric Plants Materials meeting the ASME boiler and pressure vessel code and the ASME piping code have been developed. These materials have not yet been shown to be durable in coal-fired boiler service. This is the major challenge to serious consideration of repowering an existing sub-critical steam-electric plant with an AUSC topping turbine. While achieving lower CO 2 emissions associated with the higher efficiency AUSC steam power cycle, by itself, an AUSC power plant will not result in a coal-fired power plant achieving CO 2 emissions of 420 kg/mwh (net) without a gas-side technology change. Recommendation: Maintain a watching brief on worldwide activities that seek to assess durability of AUSC materials in coal-fired service. Closed Brayton Power Cycle Plants In addition to the scope identified for AUSC Steam-electric power plants indicated above, closed Brayton cycle technology will also need to be developed in order to adopt this repowering option. Recommendation: In addition to maintaining a watching brief on high temperature heat transfer materials, a watching brief should be maintained on development of closed Brayton cycle technology. Participation in one or more pilot deployments of this technology might also be considered. Closed Brayton Bottoming Cycle This technology is suitable for increasing the capacity of an aeroderivative combustion turbine-generator. It will compete with the steam bottoming cycles commonly supplied with these combustion turbines. Recommendation: If and when an aeroderivative combustion turbine acquisition is contemplated, an engineering and economic evaluation of deploying this technology should be conducted to assess costs and benefits in comparison with the options of installing no bottoming cycle and installing the steam bottoming cycles commonly supplied. Participation in one or more field deployments of prototype closed Brayton bottoming cycle power plants should be considered. Organic/NH 3 Bottoming Cycle The economic feasibility of deploying this technology has not been rigorously assessed. In addition to the efficiency/ capacity benefit at low ambient temperatures, there may be a significant capital/maintenance benefit if air-cooling is required. It is likely that deploying this technology in a repowering application will be necessary before it can be seriously considered for new-build. Recommendation: The next step for advancing this technology is to conduct an engineering and economic evaluation of deploying the technology in a new plant. This study should include capital, fuel operating and non-fuel operating benefits with projections for the new-build case. Pressurized Oxy-coal and Chemical Looping Combustion Both of these technologies are best suited for high CO 2 capture; the partial capture benefits are modest to achieved 420 kg/mwh (net), rather than <100 kg/mwh (net) for which the technologies are well-suited. On the other hand, if there is an EOR market for the captured CO 2, these technologies may be very suitable for repowering. It is likely that pressurized oxy-coal technology can be deployed sooner that can chemical looping combustion technology for a greenfield application. Early deployment should, at a minimum, include a high-efficiency ultra-supercritical steam power cycle. Recommendation: Maintain a watching brief on the several development efforts for this technology. Any systematic evaluation of new-build options should include these options, particularly if an EOR market for the captured CO 2 is anticipated. Turbo-charged Boiler with CO 2 Capture The base turbocharged boiler technology has achieved technical maturity but has not achieved widespread commercial acceptance. The addition of partial pressurized post-combustion CO 2 capture to the flow sheet results in an overall package that might be suitable for greenfield power plants to achieve CO 2 emissions of 420 kg/mwh (net). The scope should also include, at a minimum, a high-efficiency ultrasupercritical steam cycle. Recommendation: The next step for evaluating this technology is to conduct an engineering and economic evaluation to scope the plant and develop capital costs as well as overall operating benefits. If the results of this study are favorable, pilot plant trials of candidate coals would likely be the follow-up step. D14 Canadian Clean Power Coalition: Appendix D

73 Appendix E Post Combustion Advanced CO2 Capture Processes Review A Final Phase IV Report Prepared by Electric Power Rearch Institute, July 2014 Table of Contents 1. Background E02 2. CO 2 Capture Technology Basics E Absorption E Adsorption E Membranes E Cryogenic Processes E Calcium Looping E05 3. Status of Post-Combustion CO 2 Capture Technologies E Absorption (Solvents) E Adsorption (Solids) E Membranes E Cryogenic Processes E Calcium Looping E08 4. Conclusion E08 Figures and Tables Figure 1: Figure 2: Figure 3: Figure 4: Figure 5: Absorption and Adsorption of CO 2 E02 Absorption Process E03 Adsorption Processes E03 Membrane E04 Calcium Looping CO 2 Capture Process Schematic E05 Canadian Clean Power Coalition: Appendix E E01

74 Post Combustion Advanced CO 2 Capture Processes Review 1. Background Since 2006, the Generation Sector of the Electric Power Research Institute (EPRI) has been conducting an ongoing, comprehensive effort to investigate the field of emerging technologies for capturing carbon dioxide (CO 2 ) from post-combustion flue gas. The Canadian Clean Power Coalition (CCPC) has entered into a contract with EPRI to provide them updated information on 21 processes. This report is a summary of that effort. The assessment of the individual technologies listed below remains confidential. The processes summarized in this report were selected in cooperation with the CCPC, and the summaries included in this report reflect that selection. The processes are presented in the same format as the database entries in the EPRI CO 2 Capture Database. They consist of 21 developing processes generally at early stages of development: Advanced Solvents (7), Adsorbents (7), Membranes (4), Cryogenic (2) and Calcium Looping (1). The specific processes are listed below: Advanced Solvents 3H Company, LLC: Self-concentrating solvent Dupont: Advanced amine-based solvent Cefco Global: Potassium carbonate, shockwaves CO 2 Solutions: Enzyme-enhanced solvent Codexis: Enzyme development Ion Engineering: RTIL solvent University of Notre Dame: Ionic liquids Adsorbents ADA-ES: Adsorbents and process concept Cachys: Metal carbonate salt Innosepra: Proprietary adsorbent InvenTyS: Veloxotherm (activated carbon adsorbent) SRI International: Carbon-based sorbent TDA Research: Alkalized Alumina University of California at Berkeley: MOFs Membranes GTI: Hybrid membranes MTR: Polaris membrane RTI International: Hollow fiber polymeric membranes University of Colorado: Gelled ionic liquid membrane Cryogenic ATK: Inertial CO 2 Extraction System (ICES) Sustainable Energy Solutions: Cryogenic CO 2 Capture Calcium Looping Several researchers 2. CO 2 Capture Technology Basics CO 2 capture refers to separation of carbon dioxide from the remaining constituents of flue gas. Many separation technologies are mature and widely applied in the chemical, petroleum and other industries. In some cases, these technologies form the core of the entire industry itself. For CO 2, the vast majority of capture approaches rely on traditional separations technologies: absorption, adsorption and membranes. These and other approaches are discussed broadly in this Appendix Absorption Absorption refers to the uptake of CO 2 into the bulk phase of another material for example, dissolving CO 2 molecules into a liquid solution. This contrasts to adsorption, where CO 2 molecules adhere to the interior and exterior surface of a solid particle (see Figure 1). Although absorption and adsorption both rely on chemical and physical interactions between CO 2 and a separating material (solution or solid) to selectively separate CO 2 from the other constituents in flue gas, the interaction, mathematical treatment and process configurations differ. Both processes are used widely in the chemical, petrochemical and other industries, with absorption being more common than adsorption. Figure 1: Absorption and Adsorption of CO 2 (a) Absorption (b) Adsorption (a) Absorption refers to CO 2 dissolving in a liquid solution. (b) Adsorption refers to CO 2 adhering onto exterior and interior surfaces of a solid particle. Figure 2 shows a typical process configuration employing an absorber. Flue gas and the liquid absorption solution contact each other in a column that provides interfacial area between the gas and liquid phases. The separation of CO 2 from flue gas occurs primarily through the high solubility of CO 2 in the solution relative to that of other flue gas constituents. The CO 2 -loaded solution is then sent to a regenerator, where it is typically heated to liberate CO 2 from the solution. The warm, CO 2 -lean solution is sent to a heat exchanger and then back to the absorber for reuse. E02 Canadian Clean Power Coalition: Appendix E

75 Figure 2: Absorption Process Figure 3: Adsorption Processes (a) Packed Bed (b) Fluidized Bed Flue gas is contacted with a solution that selectively absorbs CO 2 in a tower. The CO 2 -containing solution is then sent to a regenerator column where it is heated to desorb the CO 2 from the solution Adsorption Adsorption refers to uptake of CO 2 molecules onto the surface of another material, to which they adhere via weaker Van der Waals forces (physisorption) or stronger covalent bonding (chemisorption). This contrasts to absorption, where CO 2 molecules dissolve into the bulk of the material itself, also using Van der Waals or covalent bonding. Adsorption processes can be implemented several different ways. The most common are packed beds and fluidized beds, as shown in Figure 3. In a packed bed, adsorbent is loaded into a column and flue gas flows through the void spaces between the adsorbent particles. In fluidized beds, flue gas flows at higher velocities such that the adsorbent particles are suspended in the gas flow. In both approaches, the adsorbent selectively adsorbs more CO 2 relative to the other constituents passing through the column. (a) In a packed bed, flue gas flows through the interstitial spaces between adsorbent particles packed tightly in a column. (b) In a fluidized bed, flue gas flows at sufficiently high velocities to suspend the adsorbent particles within the column. During operation, particles in a packed bed gradually become saturated with CO 2 and are unable to adsorb more, after which CO 2 breaks through the bed. In practice, feed gas flow is switched to a second packed bed before the first becomes fully saturated. While this second bed is being loaded, the first bed is regenerated by heating the adsorbent or lowering the pressure to release the adsorbed CO 2, which then exits the column. The cycle is then repeated. This cyclic process can be operated so that CO 2 is continually removed from flue gas and is commonly referred to as Pressure Swing Adsorption (PSA), Vacuum Swing Adsorption (VSA), or Temperature Swing Adsorption (TSA), depending on which approach is used to regenerate the bed. The adsorbent properties and mass transfer coefficients dictate the process design and how effectively CO 2 is separated from flue gas. The CO 2 -loaded adsorbent can also be regenerated in a fluidized bed. In general, a portion or all of the saturated solids in the bed are removed, regenerated by temperature or pressure, and fed back into the reactor. Note that in either process, the energy for separation in adsorption comes from changes in temperature or pressure imposed on the adsorbent when operating in a cyclic process. Canadian Clean Power Coalition: Appendix E E03

76 2.3. Membranes Membranes can separate CO 2 from flue gas because the transport speed of a gas constituent through the membrane is related to its solubility in the membrane material (analogous to solubility in a liquid solvent) and its diffusivity through the membrane material. If CO 2 has a higher solubility in the membrane or has a higher diffusion coefficient than other constituents of flue gas, then CO 2 preferentially permeates it. Figure 4 shows a schematic. In some cases, chemical agents that selectively react with CO 2 are added to the membrane to facilitate CO 2 transport. Figure 4: Membrane Flue gas is contacted with a membrane that selectively transports CO 2. CO 2 will transport across a membrane only if the partial pressure of CO 2 is higher on the side of the membrane that contacts the flue gas than on the other. A partial pressure gradient of CO 2 can be obtained by pressurizing the flue gas on one side of the membrane, applying a vacuum on the other side of the membrane, or both. In effect, this pressure differential supplies the energy for separation Cryogenic Processes Cryogenic CO 2 capture is the separation of CO 2 from a gas stream via chilling of the gas stream to the point that solid CO 2 forms and can be collected. Because the CO 2 is captured as a solid, the majority of the compression can then be accomplished by heating the CO 2 back up to the gaseous state within a fixed volume and does not require significant compression equipment or energy. Cryogenic carbon capture does not require a chemical separation or separation material that has to interact with the CO 2. Instead, the main consideration is the efficient and effective heat transfer to chill the gas stream to the point that CO 2 undergoes deposition and forms a solid that can be collected as well as the collection of that solid. Unlike traditional cryogenic processes, such as cryogenic distillation of air in which the chilled products are liquid, CO 2 forms a solid when chilled below its triple-point pressure of 5.1 bar. This means that traditional heattransfer exchangers cannot be used because of the formation of solid buildup on the cold surfaces. Instead, the CO 2 -containing stream must be cooled using alternate cooling methods. The development of alternate cooling and chilling methods are the primary research activities in the area of cryogenic CO 2 capture. Some of the methods that have been proposed include using a chilled liquid as the heat transfer medium, chilling the CO 2 stream through expansion in a turbine, and chilling the CO 2 stream through expansion and acceleration to supersonic speeds. There are several advantages to cryogenic CO 2 capture. Because the CO 2 is captured as a solid, the need for significant compression is eliminated. Further, cryogenic capture requires only electrical input, not steam, which means that there does not have to be any modification of the steam cycle or power plant operation with the addition of cryogenic capture. Another benefit is that there is no separation medium that comes into contact with the flue gas that can be poisoned or that needs to be replaced, potentially making operation simpler. With additional testing, the claims that the energy penalty can be significantly lowered through heat integration in cryogenic CCS can also be evaluated. There are also several drawbacks to cryogenic capture. Currently cryogenic CCS is a fairly new technology, and many of the system integrations and full demonstrations have not been tested at a meaningful scale. In addition, because CO 2 capture from a gas stream through deposition is a new and complex issue, seemingly simple solutions may require additional process or integration steps to become technically feasible. In order to prevent ice and moisture formation, the flue gas stream must be dehydrated prior to cryogenic capture. Also, because the entire energy requirement is supplied via electricity as opposed to low grade steam, the energy impact on the power plant may be higher than other processes. Often cryogenic processes rely on extensive heat integration, which makes start up and shutdown potentially difficult. E04 Canadian Clean Power Coalition: Appendix E

77 2.5. Calcium Looping CO 2 is chemically captured by reaction with lime (CaO) at temperatures above about 600 C (1110 F). The calcium carbonate formed is then calcined at a temperature above about 870 C (1600 F). A flow schematic is shown in Figure 5. Particular features of this process: The reactors are likely to be circulating fluidized beds similar to CFBC boilers in common use. The heat of calcination is supplied by an oxy-fuel flame to avoid diluting the product CO 2 with atmospheric nitrogen. The high temperatures dictate careful integration with the steam generation process to ensure that thermal energy is recovered to the steam side at usefully high temperatures. In an optimal thermal design, the energy cost for CO 2 capture will largely come from two sources: auxiliary power used in the air separation unit serving the calciner, and exergy losses from the temperature difference between calcination and carbonation. The former reduces net power directly. The latter produces a subtle effect in how heat is transferred from the gas side to the steam side and may be a minimal effect as both calciner and carbonator operate at or above steam temperatures in common use. Figure 5: Calcium Looping CO 2 Capture Process Schematic Canadian Clean Power Coalition: Appendix E E05

78 3. Status of Post-Combustion Co 2 Capture Technologies Post-combustion CO 2 capture refers to the separation of CO 2 from flue gases. Common technologies for separating CO 2 are absorbents (solvents), adsorbents (solids) and membranes. A review of these technologies is provided in Appendix D Absorption (Solvents) Of all major separation processes, absorption is essentially mature from a process perspective. Absorption processes are common in the chemical process industries, and there is significant commercial experience with their operation. This stems from the fact that absorption processes are generally less expensive for large-scale separations, easier to operate and more robust than other processes. Additionally, compared to solids, solvents offer more opportunities to exploit chemical differences in components of a mixture in order to separate them. As a result, all of the more-developed CO 2 capture processes are solvent based. Example processes and products include aqueous monoethanolamine (MEA), Fluor s Econamine Plus, Mitsubishi s KM-CDR, Cansolv s CO 2 capture process and Alstom s chilled ammonia process. During the period of this study, we observed no breakthrough developments in solvent-based CO 2 capture processes. In aqueous solvents, no new classes of chemistries were introduced. The existing approach of reacting the acidic CO 2 with a basic nitrogen atom in aqueous solutions of amines, ammonia and amino acids has largely continued. Process developers rarely disclose their specific chemistry, but most will identify the class of chemistry, e.g., primary amines, secondary amines, blends, etc. Though these chemistries have been widely studied already and keep advancing, they offer only incremental gains over each other. Additional incremental gains are offered by improvements in process design. Like the chemistry counterparts, these process improvements also tend to be proprietary. Still, because of widespread use of absorption processes, even such incremental advances are commercially significant. Other solvents include non-aqueous ones such as ionic liquids or phase separation materials. They offer potential advantages of reduced regeneration energy consumption and are being developed at largely academic institutions or very small companies. The major challenges include little operational data of such systems at large scales even in other industries, their potential cost and a longer time needed to achieve commercial scale. There are vast numbers of such chemistries possible, as in the case of ionic liquids, and the challenge is often which subset to focus on. Water in flue gas can also sometimes reduce the performance of such non-aqueous solvents. Other challenges could include high viscosity, slower kinetics and a potential high cost. Overcoming these challenges is a part of the ongoing research activity at various institutions. Remaining approaches to absorption, which have a longer path to commercialization, involve changing the absorption chemistry itself or using promoters (catalysts) to enhance the rate of absorption, a common one being the use of carbonic anhydrase as a catalyst to increase the kinetics of aqueous CO 2 reactions. Most of these are at early-lab scale testing. All of these remaining approaches also aim to reduce the energy of regeneration, while some offer the additional advantage of potentially reducing the gas-liquid contactor volume Adsorption (Solids) Adsorption is less commonly practiced in the chemical process industry. Because adsorption can be used in different process configurations, both adsorbent properties and process design can strongly influence the effectiveness of a separation. Consequently, developing adsorption processes for very large-scale CO 2 capture requires development of both adsorbent materials and corresponding processes. Adsorbents being developed for CO 2 capture exhibit a variety of origins, characteristics and chemistries. EPRI s own work has characterized a class of adsorbents in collaboration with University of California at Berkeley, Lawrence Livermore National Labs and Rice University. 1 Based on this work, we have identified several hundred potential new zeolites that could lower the energy consumption of CO 2 capture. Additional computational work is currently underway that will further screen the promising materials. 1 L. C. Lin, A. H. Berger, R. L. Martin, J. Kim, J. A. Swisher, K. Jariwala, C. H. Rycroft, A. S. Bhown, M. Deem, M. Haranczyk, and B. Smit. In Silico Screening of Carbon-Capture Materials. Nature Materials, 11, (2012). doi: /nmat3336. E06 Canadian Clean Power Coalition: Appendix E

79 As was the case with ionic liquids in solvents, other types of materials are also being investigated at early stages for adsorbents. Examples include metal organic frameworks (MOFs), but none of these have yet advanced beyond lab-scale testing, with large-scale production and accompanying process development largely unknown. In addition, it is not yet known whether the benefits of using better novel adsorbents will be sufficient to offset their cost. Additional advances are being made in process improvement, and these could be as impactful as advances in novel materials. Virtually all of these process improvements are considered proprietary. Like absorption, a combination of materials and process improvements combined with close integration with a power plant is going to be needed to significantly advance adsorption technology. Unlike absorption, however, adsorption is not as widely used in chemical process industries at large scales and therefore large-scale operations may present additional challenges Membranes Industrially, membrane separation processes are much less common than either absorption or adsorption. With few exceptions, such as reverse osmosis for desalination, large-scale membranes are not commonly used in the chemical process industries. For gas separations, only one utility-scale equivalent commercial membrane facility is operational: a UOP (Separex) membrane system that removes CO 2 from natural gas with a gas flow rate equivalent to the flue gas flow rate from a 300-MW power plant. Though this polymer is not suitable for separating CO 2 from flue gas, it does show that the general scale of existing membranes is within the range required for coal-fired power plants, even though membrane applications at utility-scale are exceedingly rare. Membrane technologies advanced somewhat in 2012 for CO 2 capture. Examples include gelled ionic liquids, facilitated transport and hollow fibers for use as gas-liquid contactors. These are not new technologies, but in general, they do represent the slight uptick in membrane research for CO 2 capture relative to previous years. Additional activity can be seen in process development with membranes. However, like absorbents and adsorbents, much of the membrane materials development and process development are proprietary. Coal-fired power plants present some unique challenges for membranes. One challenge is particulates that can deposit on the membrane surface, decreasing its permeability or damaging it physically over time. Another issue is that membranes deployed at utility-scales will be modular using tens of thousands of membrane modules arranged in an array that distributes flue gas through the networked array. These types of challenges have not yet been addressed by membrane developers since they have not yet reached any meaningful scale. The DOE-NETL has funded membrane projects that started to address these issues in 2013 and Cryogenic Processes Cryogenic gas separation is a mature technology that has been used for air separation since the early 1900s. However, cryogenic capture of CO 2 from power plant flue gas has very different requirements than existing cryogenic capture processes. While air separation systems cool the air to create liquid N 2, O 2, Ar and other trace components, carbon dioxide forms a solid when chilled at atmospheric pressure, or any pressure below the triple-point pressure of 5.1 bar. As such, the main issues with CO 2 capture are the heat transfer with solid CO 2 deposition and subsequently collecting the CO 2. Currently, the largest pilots for capturing CO 2 from flue gas using cryogenic capture are still on the 15 kw scale and do not have full integration of all heat exchange streams, which is vital for energy recovery and calculating the energy consumption of a full process. While there are only a couple of companies looking at developing cryogenic CO 2 capture technologies from power plant flue gas, there are several different methods of active development that are currently under investigation. These capture routes include cooling the incoming flue gas via contact with a heat exchange liquid, cooling the gas stream through expansion, and cooling via accelerating the flue gas to supersonic speeds. In each case these are early stage concepts, but have the possibility of breakthroughs compared to processes that rely on advances in separation materials. While cryogenic CCS from flue gas is still a new technology, cryogenic CO 2 capture has been deployed for non-flue gas applications at large scale. Cryogenic CCS has been used for acid gas removal from natural gas since the 1980s. The current largest installation is at the Shute Creek natural gas processing plant near LaBarge, Wyoming at a scale of six million tonnes of CO 2 per year 2. CO 2 separation from liquefied natural gas can make use of a modified distillation column that uses the cooled liquid to collect solid CO 2 as a slurry and then further purify the CO 2 in a slurry separator. This is not possible with the gas/solid separation of CO 2 from flue gas, and would require an external heat-transfer fluid to accomplish, which introduces many additional complexities. 2 Condon, C. and Kelman (ExxonMobile), S. Shute Creek Facility and Control Freeze Zone Updates. Wyoming EORI 6th Annula CO 2 Conference, July 2012 Canadian Clean Power Coalition: Appendix E E07

80 While cryogenic CO 2 capture from flue gas is still at early technology readiness levels, there are plans for larger pilots to be built in 2014 and 2015 that would be able to test larger, scale and more integrated pilots that are still less than one MW. There are opportunities for significant breakthroughs in cryogenic CCS, especially regarding the size and complexity of capture units, though testing on more meaningful scale with heat and process integration is required to evaluate developers claims Calcium Looping Calcium Looping CO 2 capture is a temperature swing absorption process. It is similar to solid sorbent CO 2 capture technology in that CO 2 reacts exothermically with a solid and then is endothermically regenerated at a higher temperature. The major difference between calcium and other sorbents is the temperatures are which the reactions occur. CO 2 capture occurs by carbonation, formation of calcium carbonate, at temperatures greater than about 600 C (1110 F). The sorbent regeneration is essentially the same as calcining limestone to produce lime (calcium oxide) and occurs at temperatures in excess of 870 F (1600 F). Heating the calcium carbonate to this temperature (from 600 C) is likely to be accomplished by oxy-coal firing of the regenerator to keep the product CO 2 from being diluted with atmospheric nitrogen. Circulating fluidized bed reactors, similar to those used for steam generation, are anticipated for both the CO 2 capture and regeneration reactors. The very high temperatures involved require the CO 2 capture process be intermediate to the combustion/heat transfer that generates steam or for other high temperature heat recovery. The overall combustion/heat transfer scheme will, in many ways, be similar to that employed for fluidized bed power plants employing limestone for SO 2 capture. It is also strongly related to production of lime from limestone for Portland cement manufacture. Managing the chemistry of calcium-based CO 2 capture and regeneration is informed by the long history of lime production from limestone. Lab-scale studies of the chemistry as it might be applied to CO 2 capture have largely focused on sorbent utilization in the capture process, the fraction of the lime that actually reacts with CO 2 over many carbonation-calcination cycles. These lab studies include pre- and in-service treatments that can achieve acceptable CO 2 utilization. Low calcium utilization results from sintering of the solids as well as consumption of calcium to form calcium sulfate from fuel sulfur. Lower utilization requires larger calcium inventories as well as addition of fresh calcium/removal of unreactive calcium. The spent calcium might be acceptable for Portland cement production. For this reason, initial deployments of this technology are anticipated to be co-located with Portland cement plants. The largest deployment of a complete calcium looping CO 2 capture plant is the CaOling project 3, a 1.7 MWth process development unit in La Perida, Spain. Operations began in Conclusion All of the processes summarized here have significant potential advantages but they also all have significant challenges to overcome. In our review, none of these processes appear to have potential to provide major breakthroughs. Of those presented, the concepts that could benefit from help in moving their development forward would be ionic liquids, enzyme promotion of solvents, solid sorbents in the form of MOFs, the cryogenic processes and those concepts that employ phase-change materials. Future work in this area that might be considered could include: Updating of status of the processes and identification of previously unknown processes Investment into one or more of the developing processes Through working with EPRI Through funding independent projects Fuel cell project This is a concept that uses flue gas to feed a molten carbonate fuel cell. It separates the CO 2 from the flue gas and produces new power. 3 E08 Canadian Clean Power Coalition: Appendix E

81 Appendix F Advanced IGCC Partial Carbon Capture A Final Phase IV Report Prepared by CCPC Technical Committee, June 2014 Table of Contents 1. Background F02 2. Summary of Cases F03 3. Performance Conclusions F04 4. Economic Conclusions F04 5. Conclusion F05 Figures and Tables Table 1: Table 2: Figure 1: Figure 2: Figure 3: Figure 4: Technologies Evaluated F02 Description of Cases F03 First Year Cost of Power Components F05 First Year Cost of Power Net F06 Capture Cost Components F06 Avoided Costs Components F07 Canadian Clean Power Coalition: Appendix F F01

82 Advanced IGCC Partial Carbon Capture 1. Background Jacobs Engineering was contracted by the Canadian Clean Power Coalition (CCPC) to perform a study to develop project cost, performance and emissions data for a number of alternative green field Integrated Gasification Combined Cycle (IGCC) configurations, all with partial carbon capture. The quantity of carbon captured meets the Canadian government s recent regulations for fossil fuel based power plant carbon emissions, which includes gasification plants, of 420 kgco 2 /MWhnet, excluding CO 2 compression power. The study consists of six cases using two coals and three gasification technologies. Two of the gasification technologies were part of the Advanced Gasification Technology Study completed by Jacobs for CCPC in 2010 and showed potential for significantly reducing cost and providing high efficiency. These are the Aerojet Rocketdyne (AR) compact gasification system and the SES U-Gas gasifier. Aerojet acquired the Rocketdyne portion of Pratt and Whitney Rocketdyne (PWR) in the first half of 2013 and the company is now known as Aerojet Rocketdyne. The third technology is the CB&I Entrained-Slagging Transport Reactor (E-STR) gasifier. CB&I recently acquired the gasification technology from Phillips 66 and is again marketing the E-STR gasification configuration, which was previously evaluated in the Phase 2 CCPC study issued in 2008 by Jacobs. The AR and SES cases use the subbituminous Alberta coal used in Phases II and III at a site location near Edmonton, Alberta, Canada. The CB&I case uses a lignite coal that Saskpower has available in the Coronach area in Saskatchewan. Within these areas, technologies have been identified for evaluation as shown in Table 1. A comparative analysis was completed on more than 100 configurations employing these technologies. Jacobs identified the pros and cons of the various configurations and why they were or were not selected for the detailed analysis. Table 1: Technologies Evaluated Unit Operation Air Separation Gasifier Shift Sulphur Removal CO 2 Removal Sulphur Recovery Technology Cryogenic ASU Air Products ITM AR Compact Gasifier (formerly PWR) SES U-Gas CB&I ESTR (formerly Phillips 66) Sweet Sour Partial Full RTI WGCU Selective Solvent CO 2 Selective Membrane High Recovery PSA Sour PSA Selective Solvent Non-selective Solvent H 2 Selective Membrane Cryogenics Claus Wet Sulphuric Acid Modified Claus RTI Direct Sulphur Recovery Process (DSRP) LoCat CCPC has selected the following process areas for evaluation to construct configurations more amenable to partial CO 2 capture: Air Separation Unit (ASU) Gasifier Sulphur Removal Full or Partial Shift Sweet or Sour Shift Catalyst CO 2 Removal Sulphur Recovery F02 Canadian Clean Power Coalition: Appendix F

83 2. Summary of Cases Based on the preliminary screening of the technologies in Table 1, the following case configurations were selected for detailed analysis within this report. Case 5 was developed for both AR and SES U-Gas gasifiers using Cases 2 and 4 to provide a direct comparison of the advantages of ITM compared to a standard cryogenic ASU. Table 2 provides a description of the technologies used in each the cases. Table 2: Description of Cases Case Air Separation Cryogenic Cryogenic Cryogenic Cryogenic Air Prod ITM Air Prod ITM Cryogenic Gasifier AR AR AR SES AR SES CB&I Shift Sour Sour Sour Sour, with Sour Sour, with None bypass bypass Sulphur Recovery LO-CAT LO-CAT LO-CAT LO-CAT LO-CAT LO-CAT Selexol Claus/ SCOT CO 2 Recovery Partial PSA Membrane Selexol PSA Selexol Selexol Condensation Gas Turbine GE 7F Syngas GE 7F Syngas GE 7F Syngas GE 7F Syngas GE 7F Syngas GE 7F Syngas GE 7F Syngas Steam Turbine 3 Pressure Reheat 3 Pressure Reheat 3 Pressure Reheat 3 Pressure Reheat 3 Pressure Reheat 3 Pressure Reheat 3 Pressure Reheat Case 1 AR Partial Condensation Case Case 1 uses AR gasification technology with sour shift, LoCat and partial condensation out of the syngas with bypass for CO 2 removal. It comprises two AR compact gasifiers feeding two GE 7F syngas gas turbines operating in combined cycle. Case 2 AR PSA Case Case 2 uses AR gasification technology with sour shift, LoCat and PSAs with bypass for CO 2 removal. It comprises two AR compact gasifiers feeding two GE 7F syngas gas turbines operating in combined cycle. Case 3 AR Membrane Case Case 3 uses AR gasification technology with sour shift, LoCat and CO 2 Absorbing Membranes with bypass for CO 2 removal. It comprises two AR compact gasifiers feeding two GE 7F syngas gas turbines operating in combined cycle. Case 4 SES U-Gas Gasifier Case Case 4 uses SES U-Gas gasification technology feeding a split flow two stage shift followed by LoCat and Selexol for CO 2 removal. It comprises three U-Gas gasifiers feeding two GE 7F syngas gas turbines operating in combined cycle. Case 5-2 AR ITM Case 2 Case 5-2 is identically configured to Case 2 except that an ITM ASU is used instead of a cryogenic ASU. The additional load of the ITM requires a third gasifier. Case 5-4 SES ITM Case 4 Case 5-4 is identically configured to Case 4 except that an ITM ASU is used instead of a cryogenic ASU. Case 6 CB&I E-STR Lignite Case Case 6 uses the E-STR gasifier with a lignite coal feed, no shift, Selexol AGR for acid gas and CO 2 recovery. It comprises two E-STR gasifiers feeding two GE 7F syngas gas turbines operating in combined cycle. Canadian Clean Power Coalition: Appendix F F03

84 3. Performance Conclusions The reduction in CO 2 capture requirements allows for a 2.3 per cent increase in efficiency. This is simply the reduced parasitic power loads of the CO 2 removal, CO 2 compression and diluent N2 compression. Using alternative technologies more than doubles this increase and significantly increases performance and overall efficiency for all cases. On average a 5 per cent increase in efficiency is realized, which translates into a 20 per cent increase in performance of the plants. Additionally, replacing a cryogenic ASU with an ITM ASU increases the efficiency 2.4 per cent for AR and 1.7 per cent for SES U-Gas. For the AR comparison (Case 2 vs. 5-2) ITM adds another 7 per cent to the plant performance. Case 6, the CB&I E-STR gasifier, also shows significant efficiency gains considering the high moisture, high ash lignite that has been used. This is due to the combination of the improved efficiency of the E-STR technology and the reduced carbon capture requirements. 4. Economic Conclusions The following economic results, in Figure 1, are based on un-levered economics employing a WACC of 9.2 per cent. Generally, first year levelized costs are provided. First year levelized costs are the price power must be sold for in the first year, when escalated by 2 per cent per year thereafter, which sets the net present value (NPV) of a project equal to zero. CO 2 credits are generated based on the sum of CO 2 captured less 12 per cent of the GHG emissions that would have otherwise been emitted by the technology without CCS. No value for the sale of CO 2 for use in enhanced oil recovery (EOR) has been included. The in-service date for all cases is assumed to be January Coal costs were assumed to be $1.25/GJ in the first year. No cost for CO 2 pipelines or storage has been included. Figure 1 shows the components that make up the first year cost of power. The first three columns shows the results for the PWR, SES and Siemens technologies with 90 per cent capture taken from the Phase III study work. The Phase III costs were escalated to The final two cases are costs estimates for a new super critical coal plant with and without CCS. The final case assumes that post combustion capture will be used to meet the.42 t CO 2 /MWh threshold. The cases in the middle are the partial capture IGCC cases. The partial capture cases have first year costs much lower than their base cases technologies configured to capture 90 per cent of CO 2. The best PWR Case 2 has a first year cost of power which is 74 per cent of the PWR case with 90 per cent capture. The best SES Case 5-4 has a first year cost 76 per cent of the SES case with 90 per cent capture. Case 5-4 has a first year cost of $136/MWh. This is almost half the cost for the Siemens case with 90 per cent CO 2 capture. The partial capture cases have significantly lower capital expenditure (CAPEX) and operations and maintenance (O&M) costs. They may also be more efficient reducing coal costs to a small extent. The partial capture cases, however, also have smaller CO 2 credits sales. All of the cases shown in the graphs below employ sub-bit coal except the ESTR case, which has been modelled to operate on lignite as a fuel. However, a separate price for lignite nor the cost of a SCPC operating on lignite was modelled. Therefore all costs for fuel and for SCPC plants were based on sub-bit. F04 Canadian Clean Power Coalition: Appendix F

85 Figure 1: First Year Cost of Power Components First Year Cost ($/MWh) Taxes Sequestration Costs Capex CO 2 Compliance Costs Transmission F and V O&M Fuel Costs CO 2 Credit Revenue (20) Base PWR Base SES Base Siemens PWR Part Cond Case 1 PWR S PSA Case 2 PWR Memb. Case 3 SES Partial Case 4 PWR Case 5-2 SES Case 5-4 ESTR Case 6 Coal Coal w Partial CCS Figure 2 shows the first year cost of power net of any revenue associated with the sale of CO 2 credits. All of the first year costs for the partial capture IGCC cases, except Case 5-4, have first year costs of power similar to the estimated cost for a new supercritical coal plant with partial post combustion capture. Case 5-4 has a lower first year cost than that estimated for a coal plant with post combustion capture. However, all the partial capture cases are still significantly greater than $100/ MWh and are therefore unlikely to compete with natural gas combined cycle (NGCC) plants, given prevailing natural gas prices. Figure 2: First Year Cost of Power Net First Year Cost ($/MWh) Base PWR Base SES Base Siemens PWR Part Cond Case 1 PWR S PSA Case 2 PWR Memb. Case 3 SES Partial Case 4 PWR Case 5-2 SES Case 5-4 ESTR Case 6 Coal Coal w Partial CCS Canadian Clean Power Coalition: Appendix F F05

86 Figure 3 shows the components that comprise the cost of capture. The value of CO 2 credits sold or the cost of mitigating CO 2, in the instance of the reference coal case, have not been included. The cost of capture for the coal plant with CCS was estimated to be $90/t and is loosely based on Phase II estimates. The reference for all the cases is a super critical coal plant without CCS. The cost of capture and avoided cost are based on a reference plant without CCS. The reference plant employed runs on sub-bit. We have not constructed a reference plant operating on lignite for the ESTR case was not modelled. One would expect that the cost of power for the lignite SCPC plant should be greater than that for a plant operating on sub-bit. Therefore, the cost of capture and avoided costs for the ESTR case are likely too high and would be lower if a SCPC operating on lignite were used as its reference case. For instance, if the cost of power for the SCPC case increases by $10/MWh, the capture cost decreases from $160/t to $148/t for the ESTR case. Likewise, the avoided cost decreases from $235 to $217/t for the ESTR case. Notice also that the cost of capture on the coal plant is dominated by CAPEX, whereas the cost of capture for the partial capture IGCC cases is mostly CAPEX but also includes a fixed and variable O&M component almost as large as the CAPEX components. Figure 3: Capture Cost Components Capture Cost ($/t) Taxes Capex F and V O&M Fuel Costs Base PWR Base SES Base Siemens PWR Part Cond Case 1 PWR S PSA Case 2 PWR Memb. Case 3 SES Partial Case 4 PWR Case 5-2 SES Case 5-4 ESTR Case 6 Coal w Partial CCS Figure 4 shows the components that make up the avoided cost. As with the capture values above, no benefit associated with the sale of CO 2 credits or the cost to mitigate CO 2 have been included. The avoided cost values add back the CO 2 that is emitted by the energy used to capture CO 2. Avoided costs also account for the fact that if a plant is derated by carbon capture then additional plant capacity emitting CO 2 must be built to replace the lost power. The avoided costs for all partial capture IGCC cases, except Case 1, are greater than the estimated cost for post combustion capture on a super critical coal plant. Case 4 has a lower avoided cost than Cases 2 and 3. Case 4 has a higher capture cost than Cases 2 and 3. Case 5-2 has a significantly lower avoided cost than Cases 2 and 3. F06 Canadian Clean Power Coalition: Appendix F

87 Figure 4: Avoided Costs Components Avoided Cost ($/t) Taxes Capex F and V O&M Fuel Costs 40 (10) Base PWR Base SES Base Siemens PWR Part Cond Case 1 PWR S PSA Case 2 PWR Memb. Case 3 SES Partial Case 4 PWR Case 5-2 SES Case 5-4 ESTR Case 6 Coal w Partial CCS 5. Conclusion Case 4 is based on post gasification syngas processing technologies that are commercially available. Most of the other cases include technologies that are either unproven or significantly modified versions of commercial technology. While Case 4 has the lowest first year cost of power of the partial capture cases employing an ASU, it is not materially lower than these other cases. Given the accuracy of the cost estimation involved in the study, Cases 1 to 4 have essentially the same first year cost of power. It may be true, however, that replacing an ASU with an ITM may materially decrease the first year cost of power. Partial capture of CO 2 is expected to significantly reduce the cost of producing power from IGCC plants compared to plants capturing 90 per cent of the CO 2. Many of the cases have a first year cost of power similar to a SCPC plant with 60 per cent capture. Case 5-4 has a cost of power less than that expected for a SCPC with CCS. These results are encouraging. However, if it is assumed that a combined cycle plant has a non-fuel first year cost of power of $45/MWh and a heat rate of 7 GJ/MWh, we can derive the gas price that sets the cost of power to about $140/MWh. If the price of gas is about $14/GJ, the cost of power from this combined cycle plant would be about $140/MWh. That is, the natural gas price would have to rise to $14/GJ before any of these partial capture cases would be economically attractive. Clearly further advances are required before IGCC with partial capture can complete with NGCC. In Phase III, EPRI completed work to estimate the impact of advances in IGCC technology, which may help reduce the cost of IGCC in the future. Some of those advances, such as advances in gas turbine technology, may reduce the cost of the partial capture IGCC cases even further. Canadian Clean Power Coalition: Appendix F F07

88 Appendix G CanmetENERGY A Final Phase IV Report Prepared by CanmetENERGY, August 2014 Table of Contents 1. R&D Activities to Support a Comprehensive Evaluation of Potential Beneficiation Technologies G Coal Drying Process Characterization G Predicted Properties of Slag Generated from Beneficiated Coals G02 2. The Scientific and Engineering Basis for Advancing Calcium Looping Cycle Technology from Pilot Scale to Demonstration Scale G Calcium Looping Combined With Chemical Looping Combustion G04 3. Experimental and Modeling Activities to Support the Development of Short Residence Time Gasification G Slag and Inorganic Element Science G Dry Fuel Feeding G Gasification Modeling G Gasification Process Integration and Control G08 4. Experimental Activities to Support the Development of Oxy-fuel Circulating Fluidized Bed Combustion G08 Figures and Tables Table 1: Figure 1: Figure 2: Figure 3: Figure 4: Figure 5: Figure 6: Slag characteristics by coal type G02 CanmetENERGY dual fluidized bed pilot-scale facility G03 Fuel delivery, fuel dispersion, and gasifier arrangement G06 Image of solid fuel being injected from a gasifier burner at ambient temperature and 15 bar(g) pressure using a high speed camera G06 Initial gasifier simulation shows strong upward flow near the burner, opposing incoming petroleum coke and nitrogen G07 Preliminary results for char reactions (left) and temperature (right) give a rough indication of the size and position of the flame G07 Gasifier slag model results: (left) particle deposition profile and (right) slag layer thickness in the upper portion G08 G01 Canadian Clean Power Coalition: Appendix G

89 CanmetENERGY 1. R&D Activities to Support a Comprehensive Evaluation of Potential Beneficiation Technologies 1.1. Coal Drying Process Characterization Test work has been performed at CanmetENERGY to establish the performance and power plant implications of coal drying technologies. A small pilot unit (10 cm ID, ~ 200 cm in height) has been used to dry coal and characterize the produced vapour, condensate and dried coal. The pilot unit has been operated to emulate waste heat utilization (WTA) drying technology and DryFining drying technology. Two temperatures were used for the test work. Temperature 1 (55 C) required low grade heat commercially that was extracted from waste heat streams with relatively low capital investment requirements. This temperature was sufficient for removing surface moisture, but insufficient for substantial inherent moisture removal. Temperature 1 is similar to the temperature of operation of Dryfining technology. Temperature 2 (115 C) required steam extraction and/or more substantial capital investment in using waste heat streams commercially. The higher temperature was suitable for the removal of a substantial portion of inherent moisture. Temperature 2 is similar to the temperature of operation of RWE s WTA technology. Three coals were considered in the test work: Highvale sub-bituminous, Boundary Dam lignite and Poplar River lignite. A study of the kinetics of coal drying was performed to determine the effect of drying temperature and particle size on the rate of coal drying to create a UniSim model of the process. The kinetics of coal drying were studied under a nitrogen environment, with plans to continue the work with dry and humid air. Kinetic expressions were developed, dependent upon the drying temperature and the particle size of the coal being dried Predicted Properties of Slag Generated from Beneficiated Coals Properties of slag (density, surface tension and viscosity) were modelled based on data from Sherritt s GAMS report for various beneficiated coals. A summary of the results is presented below, indicating the changes between the feed and beneficiated fuels for each coal and property combination. Table 1: Slag characteristics by coal type Coal Slag Density (kg/m 3 ) Slag Surface Tension (mn/m) Slag Viscosity Poplar River Small reduction Small increase ~50 No change Boundary Dam Small increase Large increase ~200 Large decrease at T<1600 K Highvale Small increase No change Moderate decrease at T<1800 K Genesee Small increase, ~50 No change Moderate decrease at T<1800 K The change in ash composition could result in lower operating temperatures for slagging equipment, such as oxy-fired IGCC facilities and oxy-fired combustors, hence improving the efficiency of these systems for the Boundary Dam, Highvale and Genesee coals. Canadian Clean Power Coalition: Appendix G G02

90 2. The Scientific and Engineering Basis for Advancing Calcium Looping Cycle Technology from Pilot Scale to Demonstration Scale CanmetENERGY s pilot-scale dual fluidized bed facility was renovated and successfully commissioned in the summer of 2013 to test solid looping cycles for CO 2 capture. The facility has the unique ability to operate in full oxy-fuel mode with flue gas recycle (either wet or dry), allowing for production of a flue gas stream with a CO 2 concentration greater than 90 per cent. Figure 1: CanmetENERGY dual fluidized bed pilot-scale facility Gas Analysis BAG FILTER CONDENSER Flare / Stack Gas Analysis SOLIDS TRANSFER CYCLONE CALCINER / COMBUSTOR CFBC CYCLONE Stack BFB CYCLONE Air FUEL HOPPER CARBONATOR RETURN LEG BAGHOUSE LIMESTONE HOPPER Air / Recycle Flue Gas DIVERTER VALVE CONDENSER Manual Solids Loading SOLIDS TRANSFER AUGER EDUCTOR Air / CO 2 / Simulated or Real Flue Gas WINDBOX Solids to CFBC WATER COOLED FEED SCREW Air Solids from BFB STEAM SUPERHEATER Secondary O 2 Primary O 2 / Mixed Gases RECYCLE BLOWER Air KO VESSEL ELECTRIC BOILER Drain WINDBOX A test campaign with continuous CO 2 capture and various levels of steam in the oxy-fired calciner was completed in the pilot plant using calcium based sorbents. The calciner was operated with steam concentrations of 0 per cent, 15 per cent and 65 per cent at the inlet of the windbox. The increase in steam in the calciner decreased the fresh sorbent make-up rate; for instance, a 78 per cent reduction in make-up was observed with 65 per cent steam in the calciner. In commercial operation, the increase in steam concentration could be achieved by taking a slip stream of low quality steam from the steam cycle or by operating a wet flue gas recycle system, depending on the desired extent of dilution. G03 Canadian Clean Power Coalition: Appendix G

91 2.1. Calcium Looping Combined With Chemical Looping Combustion Scenarios have been studied to evaluate carbon capture and storage (CCS) applications including post-combustion CO 2 capture and pre-combustion biomass gasification, with chemical looping combustion, as well as sorptionenhanced reforming for hydrogen production with simultaneous CO 2 capture. Calcium Looping (CaL) is a developing technology for reduction of CO 2 emissions from power plants using fossil fuels for electricity production that is being intensively examined. However, the production of the required oxygen for sorbent regeneration is costly, as typical cryogenic air separation units are highly energy intensive and expensive to build. Chemical looping combustion (CLC) could replace oxy-fuel combustion via the use of a metal oxide acting as an oxygen carrier (such as copper(ii)- oxide, CuO), which provides the oxidant for burning the fuels required in the sorbent regeneration stage. The integration of the two technologies could result in a higher net efficiency and lower capital cost for CCS as cryogenic air separation is not required and the CO 2 stream is oxygen free. The feasibility and performance of integrated calciumchemical looping pellets were with three types of structures, i.e., integrated CuO core-in-cao shell pellets; integrated homogeneous CaO/CuO pellets; and mixed CaO and CuO pellets. The mixed pellets appear to be more promising than those of integrated pellets due to their relatively better performance. Additionally, mixed pellets are easier to produce with good quality control than core-inshell pellets. 3. Experimental and Modeling Activities to Support the Development of Short Residence Time Gasification 3.1. Slag and Inorganic Element Science Slag viscosity models are applied in many industries. However, the models are only applicable to a limited range of slag compositions and conditions, and their performance is not easily assessed. During this phase of work, CanmetENERGY published a journal paper that described the tools that were developed to assist slag viscosity model users in the selection of the best model for given slag compositions and conditions. It also helped users determine how well the model would perform. The tools, which are in the form of several publicly available files and programs, include a slag viscosity prediction calculator with 24 slag viscosity models, and a database of 4124 slag viscosity measurements. The database includes more than 750 compositions from 53 published studies. New slag viscosity models, integrated into the tools, include an artificial neural network for fully molten slags, and a viscosity prediction modifier for slags containing solid particles. Glass forming, entrained flow gasification and blast furnace case studies were developed to demonstrate how the slag viscosity modeling tools can be applied and to highlight certain features that should be considered when using slag viscosity models and experimental data. Petroleum coke may be used as a fuel for entrained-flow slagging gasification. It may be blended with coal to provide a more attractive feedstock. The coal provides the benefits of enhancing reactivity and increasing the amount of slag coating the gasifier walls, while the petroleum coke increases the heating value of the fuel blend. The slagging behaviour of the petroleum coke or blend must be known to determine if it is a suitable feedstock. During this phase of work CanmetENERGY published a journal publication providing results on the slag viscosities of coal, petroleum coke and coal/petroleum coke blends measured in the temperature range of C. Two different viscosity measurement apparatuses were used in separate laboratories (CanmetENERGY and CSIRO in Australia). Some viscosity measurements were repeated to test reproducibility of the results. Also, slags with and without sulphur were tested to determine whether the effect of sulphur can be neglected. Slag chemistry is important for the assessment of flow behaviour of slags produced during gasification of coal and coal petroleum coke blends. Slags containing vanadium species react readily with the crucible and spindle materials used for viscosity measurements. Interaction of vanadium-rich slags with various materials has been investigated in collaboration with CSIRO in order to obtain a better understanding of the impact of containment materials on the resulting slag chemistry and viscosity. The bulk and phase compositions of two petroleum coke slags in Al 2 O 3, Mo, Pt and Ni crucibles produced under different laboratory conditions were analysed, and kinetics of slag composition changes at 1400 C were determined. Canadian Clean Power Coalition: Appendix G G04

92 Mechanisms of the slag interactions with crucibles were determined. They involve exchanging of crucible and slag constituents, formation of interfaces with distinct compositions, and continuously changing phase equilibria in the system. For slag processed in Ni and Pt crucibles, reduction of Fe and Ni from oxide to metallic form occurs and is followed by dissolution into the crucible materials. Viscosity of slags with Mo, Ni and Al 2 O 3 crucibles are determined in the temperature range C. Resulting changes in the bulk composition of the processed slag has an impact on the slag viscosity. At given temperatures, viscosities of the slags produced in different crucibles are different. The impact of crucible materials and their applicability in viscosity measurements of high vanadium-containing slags have been determined in order to define the optimal conditions. In entrained flow gasifiers, non-volatile impurities from feedstocks form liquid slag, contributing to degradation of the refractory liner and potential slag flow issues. To understand thermodynamics of the slags, NETL and CanmetENERGY investigated phase equilibria in synthetic slags (Al 2 O 3 -CaO-FeO-SiO 2 -V 2 O 3 ) corresponding to industrial coal/petcoke feedstock blends in simulated gasifier environments. Samples were equilibrated at 1500 C in a CO/CO 2 atmosphere (po 2 =10-8 atm) for 72 hours, then analyzed by ICP, XRD, SEM-WDX and TEM. With increasing CaO and FeO contents, the homogeneous slag phase field was found to expand, while the phase field containing mullite (Al 6 Si 2 O 13 ) became smaller. The effect of high vanadium content (up to 20 wt.%) on the phase stability was determined. Pseudo-isothermal phase diagrams based on the equilibration experiments have been generated on CaO-V 2 O 3 coordinates. Physical properties of slag, such as viscosity, density, interfacial tension, heat conductivity and heat capacity, are important for mineral processing, metal processing, slagging combustion and slagging gasification. In the case of slagging gasification, slag properties will impact the efficiency, reliability, maintenance cost and environmental performance of the overall process. The majority of the inorganic matter (i.e. oxides of elements excluding hydrogen, carbon, nitrogen and sulphur) present in the fuels will deposit on the reactor hot face as liquid or semi-liquid slag. The slag will flow down into a quench zone and be collected as solidified slag. Within the gasifier, slag coating can decrease heat transfer, which may or may not be desired in the process, and also protect or corrode the hot face. In some cases the slag is too viscous and can lead to reactor plugging issues if corrective actions, such as temperature increases, fuel blending or flux addition, are not taken. Notably the wear of refractory and plugging issues are two of the greatest concerns in the gasification industry. CanmetENERGY developed methods to measure slag density and interfacial tension during this phase of work by applying the sessile drop technique with a tensiometer. Three different image analysis software packages were evaluated: SCA20, LBADSA and ADSA. A suite of emerging IGCC technologies provide the promise of both high efficiency and reduced capital costs. Many of these operate at elevated temperature and hence a number of inorganic elements (i.e. elements other than C, H, O, N and S) may be present in the syngas at later stages of processing than is typical of conventional processing arrangements. CanmetENERGY analyzed experimental results for inorganic element distribution in slag and fly ash from seven entrained-flow slagging gasification plants. Data for the Siemens, Louisiana Gasification Technology Inc. (LGTI), Wabash River, ELCOGAS and Shell gasification systems were taken from literature. Data for the CanmetENERGY and Pratt & Whitney Rocketdyne (PWR) systems were presented for the first time. Mass balances and enrichment factors were calculated. Challenges in data interpretation and general trends were highlighted. Mass balance closures for low volatility elements are within the range of 80 to 120 per cent for the PWR, LGTI and Shell systems. Closures for the CanmetENERGY, Wabash River and ELCOGAS systems are further from 100 per cent. Accumulation, unaccounted streams, measurement inaccuracy and sampling imperfections can cause poor mass balance closures. Comparison of enrichment factors for slag and fly ash demonstrate that many elements have similar fates in gasification systems as they do in combustion systems, although several elements are less volatile in gasification systems. Partitioning can vary for a given element when comparing different gasification systems and different operating conditions. The assessments of several elements that are of environmental or technological concern were provided as examples. G05 Canadian Clean Power Coalition: Appendix G

93 3.2. Dry Fuel Feeding Figure 2: Fuel delivery, fuel dispersion and gasifier arrangement During this phase of work CanmetENERGY extended their optical spray techniques for use with dry feeds being injected in high pressure vessels as shown in Figure 2. In order to optimize control of dense-phase conveying systems, an understanding of the system and particle fluid properties affecting the flow behaviour is required. In order to do this, two existing models of dense-phase conveying were evaluated: the Sprouse and Schuman model (1983) and the Geldart and Ling model (1990). These models were compared to experimental data using the dense-phase conveying system at CanmetENERGY and three pulverized solids: biomass (sawdust), lignite coal and petroleum coke. These solids were chosen as they have different particle properties, and they are potential fuels for use in the Canadian gasification industry. It was found that the Sprouse and Schuman model was a good representation of the petroleum coke and coal flows, while the Geldart and Ling model was less representative. Laser sheet visualization of biomass sprays was conducted in the cold-flow, high-pressure spray characterization vessel. A pulsed laser was used with a high-speed camera to capture freeze-motion images of the particles, providing almost instantaneous snapshots of the spray along the cross-section of interest. The edge detection technique was successfully used to determine spray edges. Figure 3: Image of solid fuel being injected from a gasifier burner at ambient temperature and 15 bar(g) pressure using a high speed camera Canadian Clean Power Coalition: Appendix G G06

94 3.3. Gasification Modeling A computational fluid dynamics (CFD) model of short residence time gasification is being developed. A validation of the modelling approach is underway, based on experimental petroleum coke gasification tests performed at CanmetENERGY on the pilot scale entrained flow gasifier in September The geometry and mesh for the model are complete and include heat transfer through the solid refractory liner and the walls of the burner for a short distance upstream of the inlet. A separate simulation of flow through the burner was done to estimate a heat transfer boundary condition where cooling water flowed through the burner. These results are being applied to the main gasifier model. Figure 5: Preliminary results for char reactions (left) and temperature (right) give a rough indication of the size and position of the flame Figure 4: Initial gasifier simulation shows strong upward flow near the burner, opposing incoming petroleum coke and nitrogen Slag deposition, flow, and corrosivity are key phenomena that affect the heat transfer and reliability of the reactor. Therefore, a validated slag flow model is a useful tool for the design of these systems. CanmetENERGY developed a model that includes ash deposition, running slag flow and immobile slag layer formation. The ash deposition is determined from a computational fluid dynamics (CFD) model of the reactor. This model was applied to the operation of the CanmetENERGY entrained flow gasifier and compared to the operational measurements, which included slag layer thickness and reactor wall temperatures. The effects of uncertainty in key parameters were investigated. G07 Canadian Clean Power Coalition: Appendix G