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beneficial use of co2 for north dakota lignite-fired plants
BENEFICIAL USE OF CO2 FOR NORTH DAKOTA LIGNITE-FIRED PLANTS Final Report Prepared for: Michael L. Jones Lignite Energy Council 1016 East Owens Aven ue, Suite 200 PO Box 2277 Bismarck, ND 58502-2277 Prepared by: Jason D. Laumb Robert M. Cowan Alexander Azenkeng Sheila K. Hanson Loreal V. Heebink Peter A. Letvin Melanie D. Jensen Laura J. Raymond Energy & Environmental Research Center University of North Dakota 15 North 23rd Street, Stop 9018 Grand Forks, ND 58202-9018 2012-EERC-01-28 January 2012 EERC DISCLAIMER LEGAL NOTICE This research report was prepared by the Energy & Environmental Research Center (EERC), an agency of the University of North Dakota, as an account of work sponsored by Lignite Energy Council. Because of the research nature of the work performed, neither the EERC nor any of its employees makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement or recommendation by the EERC. NDIC DISCLAIMER This report was prepared by the EERC pursuant to an agreement partially funded by the Industrial Commission of North Dakota, and neither the EERC nor any of its subcontractors nor the North Dakota Industrial Commission nor any person acting on behalf of either: (A) Makes any warranty or representation, express or implied, with respect to the accuracy, completeness, or usefulness of the information contained in this report or that the use of any information, apparatus, method, or process disclosed in this report may not infringe privately owned rights; or (B) Assumes any liabilities with respect to the use of, or for damages resulting from the use of, any information, apparatus, method, or process disclosed in this report. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the North Dakota Industrial Commission. The views and opinions of authors expressed herein do not necessarily state or reflect those of the North Dakota Industrial Commission DOE DISCLAIMER This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government, nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. BENEFICIAL USE OF CO2 FOR NORTH DAKOTA LIGNITE-FIRED PLANTS ABSTRACT A study was commissioned to identify the most promising technologies for the utilization of CO2 produced by North Dakota’s lignite-fired utilities. Current carbon capture and storage technologies were summarized and a survey of current CO2 utilization technologies was conducted. Technology types that were surveyed include the direct use of CO2, mineralization of CO2, use of CO2 as a feedstock in the manufacture of chemicals, photosynthesis-based technologies, and novel technologies. The applicability of the technologies to North Dakota lignite was determined and the likely best technology options for North Dakota lignite were identified. Preliminary market assessments were conducted for potential products, providing an indication of the economic benefit of the best technology options for North Dakota lignite users. Outside of the obvious potential for use of captured and compressed CO2 for enhanced oil recovery, enhanced coalbed methane, or other direct uses which were not considered for study as part of this project, mineralization and greenhouse agriculture were identified as the only two potential opportunities for the use of CO2 produced by the lignite-fired power plants in North Dakota. Of these, greenhouse agriculture is the most promising technology that appears currently to be both technically and economically feasible. TABLE OF CONTENTS LIST OF FIGURES ....................................................................................................................... iii LIST OF TABLES .......................................................................................................................... v NOMENCLATURE ...................................................................................................................... vi EXECUTIVE SUMMARY ............................................................................................................ x INTRODUCTION .......................................................................................................................... 1 NORTH DAKOTA LIGNITE-FIRED POWER PLANTS ............................................................ 3 Fort Union Lignite .................................................................................................................3 North Dakota Power Plants ....................................................................................................4 Nearby CO2 Sources ............................................................................................................10 OVERVIEW OF CURRENT CCS TECHNOLOGIES ............................................................... 11 CO2 Capture Technology Platforms ....................................................................................11 Precombustion Carbon Capture ................................................................................. 11 CO2 Capture During Combustion .............................................................................. 12 Postcombustion Carbon Capture ............................................................................... 13 CO2 Storage Technologies ...................................................................................................13 CO2 UTILIZATION TECHNOLOGIES ...................................................................................... 15 Types of CO2 Utilization Technologies ...............................................................................16 Direct-Use Technologies......................................................................................................16 CO2 EOR ................................................................................................................... 17 CO2 ECBM ................................................................................................................ 18 Direct Use of CO2 as a Solvent, Refrigerant, or in Beverage Carbonation ............... 18 Mineralization Technologies................................................................................................19 Mineralization Technologies Using Brines and Electrochemical Generation of Alkalinity ............................................................................................................... 20 Mineralization Technologies Using Waste Materials................................................ 25 Mineralization Technologies Using Alkaline Minerals ............................................. 32 Other Mineralization Technologies ........................................................................... 33 Potential Use of Mineralization Technologies by North Dakota Power Plants ...................35 Market Analysis and Economic Feasibility of Mineralization Technologies ......................37 Chemical Manufacturing......................................................................................................40 Chemical Conversion Processes ................................................................................ 40 Thermodynamic Considerations for CO2 Conversion ............................................... 41 Reduction of CO2 to Fuels and Other Chemicals ...................................................... 42 Direct Conversion of CO2 to Chemicals .................................................................... 43 Continued… i TABLE OF CONTENTS (contents) Potential for Use of Chemical Conversion Technologies by North Dakota’s Power Plants .............................................................................................................. 51 Photosynthesis-Based Technologies ....................................................................................51 Algae and Microalgae ................................................................................................ 52 Algae Cultivation Companies Using Externally Sourced CO2.................................. 56 Microalgae Economic Studies ................................................................................... 64 Algae Economic Summary ........................................................................................ 65 Microalgae Carbon Capture Status ............................................................................ 65 Controlled-Environment Agriculture – Greenhouses for Vegetable Production ...... 66 Market Assessment of Commercial Greenhouse Agriculture..............................................73 Market Overview ....................................................................................................... 73 Competitive Environment .......................................................................................... 76 Competitive Advantages ............................................................................................ 77 Barriers to Market Entry ............................................................................................ 81 Labor and Capital Requirements ............................................................................... 82 Market Opportunities ................................................................................................. 84 Market Assessment Conclusion ................................................................................. 86 Economic Feasibility of Greenhouse Agriculture ................................................................88 Novel CO2 Utilization Processes under Development .........................................................89 Electrochemical Conversion Processes ..................................................................... 89 Status of Novel CO2 Utilization Processes under Development ............................... 92 SUMMARY AND CONCLUSIONS ........................................................................................... 93 Technology Options for North Dakota Lignite-Fired Power Plants ....................................95 Market Assessment of the Products of Promising Technologies .........................................96 RECOMMENDATIONS .............................................................................................................. 96 REFERENCES ............................................................................................................................. 97 ii LIST OF FIGURES 1 Antelope Valley Station ........................................................................................................ 6 2 Coal Creek Station ................................................................................................................ 6 3 Coyote Station ....................................................................................................................... 7 4 Leland Olds Station ............................................................................................................... 8 5 Milton R. Young Station ....................................................................................................... 9 6 R.M. Heskett Station ............................................................................................................. 9 7 Stanton Station .................................................................................................................... 10 8 IEA Blue Map emissions reductions targets ....................................................................... 14 9 Calera CO2 capture and mineralization process .................................................................. 21 10 Electrochemical generation of alkalinity for the Calera CO2 capture and mineralization process ......................................................................................................... 21 11 Carbon-neutral chemical and carbon-negative products from the New Sky process.......... 23 12 Ag-Water New Sky integrated process ............................................................................... 24 13 Alcoa’s carbon capture system ............................................................................................ 25 14 Accelerated carbon mineralization of high-magnesium-content minerals .......................... 27 15 Schematic showing various chemicals that can be made from CO2 ................................... 41 16 Novomer polycarbonate production .................................................................................... 45 17 MHI CO2 capture reference plants ...................................................................................... 49 18 World consumption of sodium bicarbonate in 2008 ........................................................... 50 19 Power plant and CO2 capture tower at Cyanotech .............................................................. 57 Continued . . . iii LIST OF FIGURES (continued) 20 Algae production raceways at Cyanotech ........................................................................... 57 21 Seambiotic microalgae cultivation ponds ........................................................................... 58 22 Large tubs used for PGE’s small-scale pilot algae cultivation study .................................. 60 23 Conceptual design of proposed photobioreactor at PGE’s Boardman plant ....................... 60 24 Pond Biofuels’ algae PBRs ................................................................................................. 61 25 Nature Beta Technologies Ltd., Eilat, Israel ....................................................................... 62 26 Earthrise spirulina ponds ..................................................................................................... 63 27 Greenhouse agriculture facility in the Netherlands ............................................................. 70 28 Greenhouse farming in British Columbia, Canada ............................................................. 71 29 U.S. fruit and vegetable market value 2006–2010 .............................................................. 74 30 U.S. fruit and vegetable market volume 2006–2010 ........................................................... 75 31 U.S. top 10 greenhouse vegetable-producing states by area 2007 ...................................... 78 32 Farmers’ local food marketing 2008 ................................................................................... 79 33 U.S. average on-highway diesel fuel prices ........................................................................ 80 34 U.S. average on-highway diesel fuel prices and truck rates................................................ 81 35 North America greenhouse tomato and fresh field tomato shipping seasons by region ..... 82 36 SUPERVALU’s retail and independent business network ................................................. 87 37 FSA locations ...................................................................................................................... 87 38 U.S. producer price for tomatoes ........................................................................................ 89 iv LIST OF TABLES 1 Characteristics of Three Typical Fort Union Lignites .......................................................... 4 2 Summary of North Dakota’s Power Plant Features .............................................................. 5 3 CO2 Emissions from Sources in Close Proximity to North Dakota’s Power Plants ........... 11 4 Alkaline Fly Ash Reaction Phases with CO2 ...................................................................... 29 5 Ash Major Elements Reported as Oxides by XRF .............................................................. 36 6 North Dakota Power Plant Ash and CO2 Emission and Mineralization Potentials ............ 37 7 Electricity Cost for Alkalinity Generation for Mineralization of CO2 ................................ 40 8 MHI Postcombustion CO2 Capture Initial Operations ........................................................ 48 9 Commercial Algae and Production Agriculture Economics ............................................... 64 10 Annual Productivity of Various Vegetables in Low-Tech Greenhouses in Almeria, Spain, Versus Higher-Tech Greenhouses in the Netherlands .......................... 67 11 Estimated U.S. Greenhouse Tomato Production and Area ................................................. 72 12 U.S. Fruit and Vegetable Market Value 2006–2010 ........................................................... 74 13 U.S. Fruit and Vegetable Market Volume 2006–2010........................................................ 75 14 North American Greenhouse Production Area Acres ......................................................... 76 15 Imports of Vegetables 2010 ................................................................................................ 76 16 U.S. Top 10 Greenhouse Vegetable-Producing States by Area 2007 ................................. 77 17 Large U.S. Greenhouse Vegetable Operations.................................................................... 78 18 Vegetable Yield in Greenhouses, Annual Productivity ...................................................... 88 v NOMENCLATURE °C °F ABLE degrees Celsius degrees Fahrenheit Calera’s electrochemical process for producing NaOH and HCl from brine ac acre = 43,560 ft2 Ag silver aluminum oxide Al2O3 ANC acid-neutralizing capacity Ar argon ARMS Agricultural Resource Management Survey ARPA-E Advanced Research Projects Agency – Energy As arsenic atm atmospheres of pressure (1 atm = 0.1 MPa = 14.696 psi) BaO barium oxide bicarb sodium bicarbonate Btu British thermal unit C carbon Ca calcium Ca6Al2(SO4)3(OH)12·26H2O ettringite CaCO3 calcium hydroxide Ca(OH)2 calcium carbonate CAGR compound annual growth rate Can$ Canadian dollar CANMET Canada Centre for Mineral and Energy Technology CaO calcium oxide CAPEX capital expense CCP coal combustion product CCS carbon capture and storage CCTF Clean Coal Task Force CFBC circulating fluid-bed combustor CHP combined heat and power Cl chlorine CLC chemical-looping combustion CO carbon monoxide carbon dioxide CO2 enhanced oil recovery using CO2 CO2 EOR Cr chromium CSM Colorado School of Mines Cu copper DIC Dainippon Ink and Chemicals, Inc. DOE U.S. Department of Energy ECBM enhanced coal bed methane e-chem electrochemical vi EDTA EERC EO EOR EPA ESP Fe FGD FSA ft2 FY g g/L GLA GPCRC GRE Gt Gtonnes H H2 H2S ha HCl Hg HHV IEA IGCC IPCC K2O kg kJ km KM CDR KS-1 kWe kWh L LANL lb LEC LED LNB LOI m2 ethylenediaminetetraacetic acid Energy & Environmental Research Center ethylene oxide enhanced oil recovery U.S. Environmental Protection Agency electrostatic precipitator iron flue gas desulfurization Food Service of America square feet fiscal year gram gram per liter gamma-linolenic acid, an omega-6 fatty acid Greenhouse and Processing Crops Research Centre Great River Energy gigaton, or 1 billion tons gigatonnes, or 1 billion tonnes hydrogen molecular hydrogen hydrogen sulfide hectare = 2.417 acre hydrochloric acid mercury higher heating value International Energy Agency integrated gasification combined cycle Intergovernmental Panel on Climate Change potassium oxide kilogram kilojoule kilometer Mitsubishi Heavy Industries Kansai-Mitsubishi carbon dioxide recovery process Mitsubishi Heavy Industry’s sterically hindered amine carbon dioxide capture solvent kilowatt, electrical kilowatt hour liter Los Alamos National Laboratory pound Lignite Energy Council light-emitting diode low-NOx burner loss on ignition square meter vii MAP MEC meq/g Mg mg mg/L MgCO3 MgO MHI MIT MJ MnO2 MPa MW MWe N N2 Na2CO3 Na2O NAFTA NAGHVG NaHCO3 nahcolite NaOH NESHAP NETL NH3 (NH2)2CO Ni NOx NREL NSE NYSERDA O O2 OFA OPEX OPXBIO OSCAR P2O5 PBR pc PC pCO2 PCOR Pd Calera’s mineralization via aqueous precipitation process microbial–electrocatalytic milliequivalents per gram magnesium milligram milligram per liter magnesium carbonate magnesium oxide Mitsubishi Heavy Industries Massachusetts Institute of Technology megajoule manganese oxide megapascal, or 1 million pascals (1 MPa = 145 psi) megawatt megawatt, electrical nitrogen molecular nitrogen sodium carbonate sodium oxide North American Free Trade Agreement “The North American Greenhouse/Hothouse Vegetable Growers” sodium bicarbonate a mineral rich in sodium bicarbonate sodium hydroxide National Emission Standards for Hazardous Air Pollutants National Energy Technology Laboratory ammonia urea nickel nitrogen oxides National Renewable Energy Laboratory New Sky Energy New York State Energy Research and Development Authority oxygen molecular oxygen overfire air operating expense OPX Biotechnologies, Inc. Ohio State Carbonation Ash Reactivation lead oxide photobioreactor pulverized coal polycarbonate partial pressure of CO2 Plains CO2 Reduction (Partnership) palladium viii PGE PO ppm PRB psi psig R&D Rh Ru S sc-CO2 SCM SDA Se SiO2 SO2 SO3 SOFA SrO SSS syngas TCEP Tcf T-fired Ti TiO2 tonnes tons UAE UAN US$ USDA USGS UW WAG Wh Wh/mol XRD XRF yr Zn ZnO Zr ZrO2 Portland General Electric propylene oxide parts per million, a gas concentration of 10,000 ppm = 1% Powder River Basin pounds per square inch pounds per square inch gauge research and development rhodium ruthenium sulfur supercritical CO2 supplementary cementation materials spray drying absorption selenium silicon dioxide sulfur dioxide sulfur trioxide separated overfire air strontium oxide stainless steel slag synthesis gas Texas Clean Energy Project trillion cubic feet tangentially fired titanium titanium oxide metric tons = 1000 kg short tons = 2000 lb United Arab Emirates urea ammonium nitrate U.S dollar U.S. Department of Agriculture U.S. Geological Survey University of Wyoming water alternating gas (an approach to operating a CO2 EOR flood) watt hour watt-hour per mole x-ray diffraction x-ray fluorescence year zinc zinc oxide zirconium zirconium oxide ix BENEFICIAL USE OF CO2 FOR NORTH DAKOTA LIGNITE-FIRED PLANTS EXECUTIVE SUMMARY Global climate change is perceived to be one of the most significant environmental challenges facing the world in the 21st century. While there are scientists who argue that there is too much uncertainty to know for sure what the effects of increased carbon dioxide levels in the atmosphere actually have on the climate, it is scientific fact that atmospheric CO2 concentrations are increasing and that this increase correlates well with CO2 emissions associated with the use of fossil fuels as an energy source. As a result of the potential environmental consequences of CO2 emissions and the fact that power plants are significant point sources of CO2 emissions, it is almost certain that any new environmental regulations that may be promulgated to address CO2 control will include requirements for decreased emissions from fossil-fueled power plants. The anticipated regulations will likely pose significant economic challenges for both new and existing power plants. Approximately 30.25 million tons/year (27.4 million tonnes/yr) of Fort Union lignite is mined from four mines in North Dakota and one mine in Montana. These mines supply coal to six of the seven North Dakota coal-fired power plants, the Great Plains Synfuels Plant, and a small power plant and sugar beet-processing plant in Montana. Together, these facilities emit approximately 35 million tons/yr (32 million tonnes/yr) of CO2. Approximately 3 million tons/year (2.7 million tonnes/yr) of CO2 is captured at the Great Plains Synfuels Plant and is sold for use/geological storage in enhanced oil recovery (EOR) operations. To limit the economic impact on North Dakota, it is important that various ways of addressing the CO2 emissions issue in a sustainable manner be explored. While CO2 capture and storage technologies are developing rapidly worldwide and possess the potential to offer a significant contribution to CO2 mitigation, there is interest in also exploring the possibility of using CO2 as a commodity that can help decrease the amount of CO2 that needs to go to geological storage and can, therefore, help defray the cost of CO2 capture. CO2 utilization technologies include those that can make use of low-concentration and low-pressure sources of CO2 such that they also serve as a form of postcombustion capture, those that need purified CO2 but can use it from a low-pressure source, and those that require a high-purity and high-pressure source. This study was commissioned to identify the most promising technologies for the utilization of CO2 produced by North Dakota’s lignite-fired utilities. Several activities were performed, including summarizing current carbon capture and storage (CCS) technologies, conducting a survey of current CO2 utilization technologies, determining how applicable the technologies would be to North Dakota lignite, identifying the likely best technology options for North Dakota lignite, performing preliminary market assessments for potential products, and providing an indication of the economic benefit of the best technology options for North Dakota lignite users. The information collected and documented in this report was designed to answer x the questions, What CO2 use technologies exist or are under development? How much of the CO2 from coal-fired power plants can they use? and Do any of them have the potential to make money or at least help offset some of the costs of CO2 capture? There are three CO2 capture technology platforms: precombustion capture, capture during combustion, and postcombustion capture. Capture during combustion is often referred to as oxyfiring or oxycombustion because one of its approaches involves the use of pure oxygen rather than air as the source of molecular oxygen that is fed to the boiler. In general, precombustion capture yields high-purity, high-pressure CO2; combustion capture yields purified low-pressure CO2; and postcombustion capture yields high-purity, low-to-moderate pressure CO2. Some beneficial-use technologies can be used to provide for postcombustion capture. CO2 utilization technologies can be divided into six broad categories: the direct use of CO2, the mineralization of CO2, use as a feedstock in the manufacture of chemicals that require the reduction of the carbon to a less oxidized form, use as a feedstock in the manufacture of chemicals that do not require chemical reduction of the carbon, photosynthesis-based technologies, and novel technologies. Direct-use technologies include use of CO2 for EOR, enhanced coalbed methane (ECBM) production, and as a solvent, refrigerant, or in foods and beverages. These technologies are well known, have been extensively documented elsewhere, and the Lignite Energy Council (LEC) specifically excluded them from being considered as part of this project; therefore, these technologies are not discussed in detail in this report. However, it should be noted that the supply of CO2 for EOR and ECBM projects could represent a good near-term opportunity for North Dakota lignite users. Mineralization to form products from CO2 is a relatively new concept. It is the formation of a carbonate or bicarbonate solid from CO2; thus the CO2 becomes a part of the solid product. CO2 captured from any source can be used as a feedstock for mineralization reactions. The process also requires a source for the alkalinity required by the reaction; lignite fly ash could potentially provide this alkalinity. The most advanced of the mineralization technologies is still only at a pilot scale of development, and the products that will be generated by the various technologies, should they become commercial, are more likely to fill niche markets than be widely employed. Nineteen mineralization technology developers were identified. Most of the companies working in the area of CO2 mineralization have provided lists of potential products but have not provided a clear path to making and marketing those products. The market will dictate the type and quantity of products that are made. The entry-level product for most mineralization companies will likely be aggregate that can be used for roads and/or as a component of concrete. Although the concept shows promise, it does not appear to offer an economically viable opportunity for the lignite industry in the near term because 1) aggregate made from mineralization of CO2 is estimated to cost roughly double the current rate for gravel aggregate because of the value of the materials required to supply the metal cations and alkalinity for the mineralization and 2) lignite fly ash is more valuable as a raw material used for solidification of waste pits in the western North Dakota oil fields than as a source of alkalinity for mineralization reactions. xi CO2 can be used in the production of chemicals and fuels. Many approaches are being developed to utilize CO2 captured from various sources to produce useful fuels, chemical feedstocks, and in the direct conversion of CO2 to chemical products such as polycarbonate plastics or urea. The potential for these technologies to use CO2 from coal-fired power plants is limited because 1) substantial energy input is needed to convert the carbon in CO2 from its fully oxidized state into a reduced state where it can serve as a fuel and 2) the industries using CO2 as a feedstock in chemical production also perform upstream processes that produce CO2 either directly (typically at high temperature and pressure) or when they consume fuel in order to provide energy for the overall process. The status of CO2 reduction to fuels is currently limited to research and development studies mostly in academic laboratories. When a fuel is made from CO2, energy is used to reduce the carbon from a fully oxidized state to a more reduced state. The amount of energy required for this reduction process is greater than the amount of energy that can be obtained either from the process or from use of the newly produced fuel. A CO2-to-fuel process only makes sense where the product formed is of very high value, the fuel is used as a storage product made from an intermittent energy supply source (e.g., wind, solar), and/or the fuel produced is useful in ways that the original source fuel was not (e.g., production of a transportation fuel from coal-derived CO2). When CO2 is directly converted into chemicals, it is reacted with another feedstock that had to be produced in an upstream process. The quantity of CO2 produced in this upstream process along with the CO2 produced from energy generation associated with this upstream process will exceed the CO2 demand of the step that uses CO2. Therefore, most companies performing these processes will not use externally supplied CO2. Additionally, most of the CO2use processes, or the upstream processes used to generate the reactive intermediates, require reaction conditions such as high pressure and/or high temperature, with fossil fuel combustion typically used to provide the heat and power necessary to meet these needs. In fact, more CO2 is produced during polycarbonate plastic or urea production than is used to make the products. Some of the largest postcombustion CO2 facilities operating in the world are located at urea plants where CO2 is captured from natural gas combustion flue gas in order to supply some of the CO2 used for converting ammonia to urea. Photosynthesis-based processes using externally sourced CO2 include algae production and greenhouse agriculture. In order for these technologies to provide a favorable CO2 demand, the energy input for CO2 reduction to organic carbon needs to be primarily from sunlight rather than from electric lights unless the electricity is derived from a zero-carbon source (i.e., wind, solar, nuclear). Greenhouse agriculture and algae systems can use low-concentration CO2 streams. In algae production, CO2 must be supplied both as a source of carbon for growth of the algae and to control the pH of the growth media. In greenhouse agriculture, CO2 serves as the carbon source for plant growth and can increase plant growth rates. CO2 supply to greenhouses is particularly important in colder climates where increasing air exchange to supply CO2 from the outside air would result in excessive heating costs. The microalgae production industry is a small and well-developed industry that has a proven ability to make money. The industry purchases externally sourced CO2, but the size of its xii markets is small relative to the amount of CO2 that is potentially available from power plants. Less than 20,000 tons/yr (18,150 tonnes/yr) of algae is produced worldwide, primarily for use as nutritional supplements (Benemann, 2011)1. There has been a recent explosion of algae start-up companies (some estimate more than 200 since 2005) that are trying to break into potential algae product markets that promise to be much larger than the nutritional supplement market but require much less expensive algae. These larger markets include the production of biofuels, animal feeds, and fish meal replacements. Since these products have a relatively low value, production costs must be substantially reduced from current commercial production costs. Production of these lower-value products cannot be performed in an economically viable manner even under the most favorable conditions. Algae and microalgae technologies are not economically feasible for North Dakota. The successful algae-producing companies are located in environments that favor the manufacture of their products (i.e., moderate temperatures and sunlight are available without extra cost). Their high-value nutrient supplement products are dry, shelf-stable and, therefore, relatively inexpensive to transport, making them readily available to the local population even without local producers. Irrespective of location, algae and microalgae products that could utilize a substantial amount of CO2 (e.g., fuels and feed) are currently more expensive to produce than their potential market value can fetch. Greenhouse agriculture, or controlled-environment agriculture, involves growing plants in a greenhouse. High-technology greenhouses are supplied with CO2, heat and humidity control, and supplemental light as required to ensure high productivity. The common products from this type of agriculture include flowers, specialty fruits, and vegetables. North Dakota power plants may potentially benefit from the development of greenhouse agriculture operations in the state. These facilities can use both CO2 and low-grade heat from the power plants and will also be customers for electricity used in supplemental lighting. The total demand for CO2 is unlikely to be high, but the market and economic indicators investigated appear to indicate that a profitable venture could be developed based on this CO2 use technology. Twelve novel CO2 utilization technologies were evaluated. These are primarily conceptual and laboratory-scale proof-of-concept processes of the type being supported by the U.S. Department of Energy’s ARPA-E (Advanced Research Projects Agency-Energy) Program. They include processes that involve the electrochemical conversion of CO2 to fuels and/or other chemicals, bioelectrochemical systems such as reverse microbial fuel cells that combine microbial processes and electrochemistry to produce chemicals, the use of microorganisms that convert H2 and CO2 to desirable chemicals, and other processes that use sunlight to power chemical synthesis reactions. All of the novel CO2 utilization technologies are at a very early stage of development and are not close to moving out of the laboratory. In addition, these processes require the input of energy to convert CO2 into a useful product. The hope is that some of these concepts will, at the very least, contribute to the development of useful technologies that can be commercially relevant sometime in the future, perhaps within the next 25 years. A great 1 Benemann, J.R. “Microalgae Biofuels and Animal Feeds: An Introduction” johnbenemann@microbioengineering.com (accessed Nov 2011). xiii deal of work and the investment of substantial time and money will be required if that is to happen. The amount of CO2 produced by the North Dakota lignite-fired power plants dwarfs the needs of any of the utilization technologies, even if they were to be performed on a very large scale. It was found that the technologies that can use flue gas concentrations of CO2 as the source (assuming it has been cleaned of contaminants that might harm the process or product) include some mineralization technologies and the photosynthesis technologies. Some of the novel technologies may also fall into this category, although their early stage of development makes this unclear at best. Most of the direct-use (i.e., EOR and ECBM operations) and chemical synthesis technologies require high-purity, high-pressure CO2. Very few CO2 utilization technologies appear to be viable possibilities for North Dakota lignite-fired power plant CO2. The novel technologies are too early-stage and the chemical technologies do not require externally sourced CO2. Algae and microalgae technologies are not economically feasible in North Dakota. Mineralization technologies suffer from the lack of a well-defined product and the current economics that estimate that any products would be more expensive than those that are currently available. Greenhouse agriculture appears to be the only promising technology that is currently both technically and economically feasible in North Dakota. Greenhouse agriculture is not expected to utilize more than a very small fraction of the CO2 produced by North Dakota power plants, but it has potential because of the high market value of its products. Facilities would be required to offer supplemental heat and lighting for many months each year, but the productivity of such greenhouses is several times higher than traditional farming, so the extra cost could be recovered through the sale of the additional product. Transport of fresh produce to North Dakota and surrounding states and provinces from other locales is expensive, and the market study confirmed that consumers and food distributors preferred locally sourced, high-quality vegetables to the imports. This study showed that there are three potential opportunities for use of CO2 produced by the lignite-fired power plants in North Dakota: supply of captured, compressed, and purified CO2 for use in EOR and/or ECBM operations; mineralization; and greenhouse agriculture. To better define the opportunities and provide necessary information for decision makers, LEC may wish to consider investing in 1) advancement of mineralization technologies that show promise toward development of a marketable product, particularly if the technologies can also use coal combustion residuals to produce a high-value product, and 2) further assessment of the economic potential of greenhouse agriculture in North Dakota. xiv BENEFICIAL USE OF CO2 FOR NORTH DAKOTA LIGNITE-FIRED PLANTS INTRODUCTION Global climate change is perceived to be one of the most significant environmental challenges facing the world in the 21st century. Most climate scientists believe that anthropogenic emissions of carbon dioxide are the dominant contributor to global warming/global climate change. This broad acceptance by many of the link between greenhouse gas emissions and global climate change has been confirmed by the Intergovernmental Panel on Climate Change (IPCC) in its Fourth Assessment Report, which concludes that “Most of the observed increase in global average temperatures since the mid-20th century is very likely due to the observed increase in anthropogenic greenhouse gas concentrations” (Intergovernmental Panel on Climate Change, 2007). The qualification of this as “very likely” (i.e., with more than 95% chance of certainty) represents an upgrade from the “likely” (>66% chance of certainty) that was referred to 6 years earlier in the Third Assessment Report. While there are scientists who argue that there is too much uncertainty to know for sure what effects increased CO2 levels in the atmosphere really have on the climate, it is scientific fact that atmospheric CO2 concentrations are increasing and that this increase correlates well with CO2 emissions associated with the use of fossil fuels as an energy source. The difficulty in correlating CO2 concentration to global warming derives chiefly from the fact that water vapor in the atmosphere is the dominant greenhouse gas. The simple description of the concept behind CO2 acting as the dominant driver is: an increase in CO2 concentrations causes a small increase in temperature which increases water evaporation and the saturation vapor pressure of water in the atmosphere. This multiplies the effect of the increased CO2 concentration. Scientists who argue against the dominant position that CO2 is causing global warming argue that it is unlikely that the increased CO2 concentration can drive global warming. Unfortunately, it is not possible to know if CO2 is a major driver or how severe climate change effects might be. One can think of it as a grand global experiment with potentially severe consequences. The best tools we have to predict what might happen are complex computer models that must be formulated and calibrated to the best of the abilities of the scientists working on them. These models, like all models, will never be perfect, which allows detractors to argue that the models are wrong. The fact that the models are wrong is true, because all models are wrong in that they cannot exactly match reality in all situations. The question is not if they are right or wrong but if they are useful. The consensus is that the models are useful in warning us that CO2 emissions are likely leading to significant changes in the global climate and society should take notice and make efforts to decrease the potential of having to deal with these consequences by decreasing CO2 emissions. Increased atmospheric CO2 concentrations are also responsible for another environmental impact that is too often ignored and is much less complicated to predict or understand: ocean acidification. In reality, it is a reduction in the alkalinity of the surface ocean. The mechanism involved is simple acid–base chemistry where the increased CO2 concentration in the atmosphere increases the dissolution of CO2 into the ocean (approximately 50% of anthropogenic CO2 emissions are not retained in the atmosphere but have dissolved into the ocean). The CO2 1 dissolved acts as an acid that neutralizes ocean alkalinity. This decreases the saturation index for calcium carbonate (CaCO3) which, in turn, makes it more difficult for organisms that use CaCO3 to form their shells and/or skeletons to do so. Biologists believe this decreases the productivity of the ocean by affecting the energy budget of planktonic organisms that have to spend more energy to form CaCO3. It is also considered to be an additional stressor to coral reefs for the same reason. Currently, the primary source of anthropogenic CO2 emissions is the use of fossil fuels for electricity generation, transportation, and industrial processes. Another significant source is fuel combustion in residential and commercial buildings. About 97% of anthropogenic CO2 emissions is produced from energy-related activities. CO2 emissions from coal-fired power plants contribute a significant share of the anthropogenic CO2 emissions in the United States, with CO2 from coal-fired electricity-producing utilities being the single largest contributor of all stationary emitters. In 2009, estimates of CO2 emissions from fuel combustion show that 43% was produced from coal, 37% from oil, and 20% from natural gas (International Energy Agency [IEA], 2011). Although growth trends for these fuels varied somewhat and such variations are expected to continue in the future, CO2 emissions from coal combustion increased by 2% between 2007 and 2009. The increase in coal-related CO2 emissions is mostly due to increased use of coal to fill much of the growing energy demand of developing countries, such as China and India, where energy-intensive industrial production is growing rapidly and where large coal reserves exist with limited reserves of other energy sources. According to a recent IEA report, while CO2 emissions from oil dropped by nearly 2.2% in 2008, gas-related emissions in 2009 represented a 2.2% increase from 2008 levels (International Energy Agency, 2011). The slow growth of emissions from oil was related to the increased use of coal and gas as primary energy supplies, a trend that could potentially continue in the United States for several years because of increasing political pressure to refrain from importing foreign oil. As a result of the potential environmental consequences of CO2 emissions and the fact that power plants are significant point sources of CO2 emissions, it is almost certain that any new environmental regulations that may be promulgated to address CO2 control will include requirements for decreased emissions from fossil-fueled power plants. The anticipated regulations will likely pose significant economic challenges for both new and existing power plants. The abundant supply of coal resources means that it is likely that the United States will rely on the use of coal and other fossil fuels to meet most of its energy needs for many years to come. North Dakota enjoys abundant fossil fuel resources, with lignite being the dominant one used for electricity generation. Its widespread use, coupled with the facts that lignite produces more CO2 per unit of energy than other fossil fuels and North Dakota lignite is rarely shipped out of state, it is likely that the economy of North Dakota will be significantly impacted by any regulation focused on cutting CO2 emissions from power plants. To limit the economic impact on the state, it is important that ways of addressing the CO2 emission issue in a sustainable manner be explored. Approaches that focus on CO2 capture and reuse are attractive, particularly where use of the CO2 might generate additional revenue to help offset some of the costs associated with CO2 capture. 2 Therefore, the overall goal of this study was to identify the most promising technologies for the utilization of CO2 from North Dakota lignite-fired utilities. To meet this goal, several specific objectives were carried out, including summarizing current carbon capture and storage (CCS) technologies, conducting a survey of current CO2 utilization technologies, determining how applicable the technologies would be to North Dakota lignite, identifying the likely best technology options for North Dakota lignite, performing market assessments for potential products, and providing an indication of the economic benefit of the best technology options for North Dakota lignite. The results of these findings are presented as follows. NORTH DAKOTA LIGNITE-FIRED POWER PLANTS Approximately 30.25 million tons/year of Fort Union lignite is mined from four mines in North Dakota and one mine in Montana. These mines supply coal to six of the seven North Dakota coal-fired power plants, the Great Plains Synfuels Plant, and a small power plant and sugar beet-processing plant in Montana. An additional lignite-fired power plant is currently under construction that is expected to increase the annual use of lignite in North Dakota by about 610,000 tons/year (553,400 tonnes/yr). All of the existing facilities are either minemouth plants or are located within a very short distance of the mines. Currently, CO2 is captured only at the Great Plains Synfuels Plant where a precombustion physical solvent process, the Rectisol® process, is employed. Part of the reason lignite is used only at minemouth plants and not at power plants at great distances from the mines is because of the relatively low energy density of the coal. This low energy density is due to a combination of high moisture content and a higher average oxidation state of the carbon in the coal. Together, these result in a relatively higher level of CO2 emissions per unit of power generation for facilities using lignite rather than higher ranks of coal. Hence, North Dakota Lignite Energy Council (LEC) members foresee a potential problem, how to remain economically competitive and continue to provide low-cost power in an economy that includes regulations, taxes, or other mechanisms designed to encourage or demand reductions in atmospheric CO2 emissions. The purpose of this project is to consider whether or not technologies that use CO2 can help address the problem by providing either a significant CO2 sink or a means to generate income to offset a portion of the costs associated with managing the CO2 that is generated during lignite combustion. Fort Union Lignite Table 1 provides typical characteristics of Fort Union lignites from three mines in North Dakota based on proximate and ultimate analysis data. The high moisture content (~30% to 34%) and high oxygen content (~10% to 15%) lead to the low higher heating value (HHV) (~6000 to 7400 Btu/lb, or 14 to 17 MJ/kg), which results in high ratios of CO2 emissions from electricity generation for facilities using this coal. 3 Table 1. Characteristics of Three Typical Fort Union Lignitesa Coal Mine: Freedom Center Coal-Firing Power Antelope Valley, Milton R. Young Plants: Leland Olds Moisture Content, % 30.44 31.99 HHV, Btu/lb (MJ/kg) 6903 (16.1) 7376 (17.2) Fixed Carbon, wt% 31.33 32.75 Volatile Matter, wt% 27.55 30.19 Ash Content, wt% 10.68 5.08 C, wt% 41.70 44.04 H, wt% 2.67 3.04 N, wt% 0.63 0.75 S, wt% 1.18 0.60 O, wt% 12.67 14.5 Cl, ppmw 100 NAb 0.13 0.10 Hg, ppmw a b Falkirk Coal Creek 33.9 5965 (13.9) 25.27 24.70 16.13 35.33 2.73 0.63 0.47 10.79 70 0.077 As-received basis; the H and O values have been adjusted to eliminate contributions to H and O from moisture. Not available. North Dakota Power Plants North Dakota has seven power plants that provide baseload electric service. Six of them fire lignite and one burns Powder River Basin (PRB) subbituminous coal. One additional lignitefired power plant is under construction, and lignite is also used to supply the Great Plains Synfuels Plant. The features of North Dakota’s power plants are summarized in Table 2. Two main types of plant configurations are common for North Dakota coal-fired power plants: cyclone boilers with electrostatic precipitators (ESPs), wet flue gas desulfurization (FGD), and/or fabric filters and tangential wall-fired boilers, which also typically have the same types of pollution control devices. Additional details on these power plants and the Great Plains Synfuels Plant follow. Antelope Valley Station (Figure 1) is located 7 miles northwest of Beulah, North Dakota. The station, which is owned by Basin Electric Power Cooperative, burns more than 5 million tons (more than 4.5 million tonnes) of lignite from the adjacent Freedom Mine each year. The plant has two pulverized coal (pc) tangentially fired boilers, each unit rated at 450 MW (Lignite Energy Council, 2011a). Dry scrubbers at the plant use lime to capture and remove SO2 emissions from the flue gas, while fabric filters remove particulate (Basin Electric Power Cooperative, 2011a). Low-NOx burners (LNBs) with overfire air (OFA) reduce the NOx emissions (Nelson et al., 2009). The plant is adjacent to the Great Plains Synfuels Plant and emits nearly 7.8 million tons (7.1 million tonnes) of CO2 annually (U.S. Environmental Protection Agency, 2011a). Coal Creek Station is owned by Great River Energy (GRE) and is located near Underwood, North Dakota. It consists of two pc-fired tangential boilers, with each unit rated at 550 MW for a total of 1100 MW (Lignite Energy Council, 2011b). The station burns 7.5 to 4 Table 2. Summary of North Dakota’s Power Plant Features 5 Plant/Unit Leland Olds Unit 1 Leland Olds Unit 2 Antelope Valley 1 Antelope Valley 2 Coal Creek 1 Coal Creek 2 Stanton Station Stanton Station 10 Heskett Unit 1 Heskett Unit 2 a Milton R. Young 1 Milton R. Young 2 Coyote Lignite Mine Freedom Approximate amount of coal used, Mtons/yr (Mtonnes/yr) 3.3 (3.0) Freedom Freedom >5 (>4.5) Freedom Falkirk Falkirk PRB coal 7.5–8 (6.8–7.3) 0.85 (0.77) Rated MW 216 Beulah Beulah 0.5 (0.45) Center >4 (>3.6) Center 2.5 (2.3) Particulate Control Fabric Filter CO2 Emissionsa, Mtons/yr (Mtonnes/yr) 4.6 (4.2) 7.8 (7.1) 440 Boiler Type Wallfired Cyclone 450 T-firedb LNB/OFA X X 450 T-fired LNB/OFA X X 550 550 188 T-fired T-fired Wallfired T-fired LNB/SOFAc LNB/SOFA LNB LNB X None None FBC 250 Stoker Fluid bed Cyclone None 455 Cyclone None 420 Cyclone None –d PRB coal Beulah SO2 Control 25 75 Emissions for 2010 from U.S. Environmental Protection Agency (2011a). b Tangentially fired. c LNB with separated OFA (SOFA). d “Supplemental” boiler. NOx Control LNB Dry FGD Wet FGD None Cold-Side ESP X X X X X X X X 10.0 (9.1) 1.5 (1.4) X X X 0.5 (0.45) X X 5.5 (5) X X X 3.8 (3.45) Figure 1. Antelope Valley Station (taken from Basin Electric Power Cooperative, 2011b). 8 million tons (6.8 to 7.3 million tonnes) of lignite from the nearby Falkirk Mine each year (Great River Energy, 2011a). The plant has wet scrubbers that remove SO2 as well as ESPs to remove particulate from the flue gas (Jones et al., 2007). LNBs and SOFA reduce NOx emissions (North Dakota Department of Health Division of Air Quality, 2010). A new technology that reduces the moisture content in lignite was added to the plant in 2009. The lower moisture content requires less coal to generate the same amount of power, resulting in lower SOx, NOx, mercury, and CO2 emissions (Lignite Energy Council, 2011b). The process is called Dry Fining™ (Great River Energy, 2011a). The Blue Flint Ethanol Plant is collocated with Coal Creek Station (Great River Energy, 2011a). Coal Creek Station (Figure 2) emits almost 10 million tons (9.1 million tonnes) of CO2 each year. Figure 2. Coal Creek Station (taken from Lignite Energy Council, 2011b). 6 Coyote Station, which is located 2 miles (3.2 km) south of Beulah, North Dakota, is operated by Otter Tail Power Company, which shares ownership with Montana–Dakota Utilities Co., Northern Municipal Power Agency, and Northwestern Energy. The station has one unit rated at 420 MW that uses a cyclone burner (Lignite Energy Council, 2011c). Each year, the station burns about 2.5 million tons (2.3 million tonnes) of lignite from the nearby Beulah Mine (Lignite Energy Council, 2011c). The station utilizes a dry scrubber to remove SO2 and a fabric filter to remove particulate from the stack gas (Lignite Energy Council, 2011c). Coyote Station, which is pictured in Figure 3, emits about 3.8 million tons (3.45 million tonnes) of CO2 annually. Leland Olds Station is located 4 miles (6.4 km) southeast of Stanton, North Dakota, along the Missouri River. The station is Basin Electric Power Cooperative’s first power plant (Basin Electric Power Cooperative, 2011b) and has a power production capacity of 656 MW (Lignite Energy Council, 2011d). Leland Olds Station has one pc wall-fired boiler and one cyclone boiler (Lignite Energy Council, 2011d). The plant burns 3.3 million tons (3 million tonnes) of lignite from the Freedom Mine each year and features LNBs on the wall-fired boiler and a wet limestone scrubber to reduce NOx and SOx, respectively (Basin Electric Power Cooperative, 2011b). ESPs are used to collect particulate from the flue gas. Figure 4 shows Leland Olds Station, which emits about 4.6 million tons (4.2 million tonnes) of CO2 each year. Milton R. Young Station, located 4 miles (6.4 km) southeast of Center, North Dakota, is operated by Minnkota Power Cooperative (Lignite Energy Council, 2011e) and consumes more than 4 million tons (3.6 million tonnes) of lignite from the Center Mine each year (Lignite Energy Council, 2011e). The station consists of two units. The first, owned by Minnkota Power Cooperative, has a lignite-fired cyclone boiler and is rated at 250 MW (Minnkota Power Cooperative, 2011a). The second unit is owned by Square Butte Electric Cooperative (Minnkota Figure 3. Coyote Station (taken from Otter Tail Power Company, 2011). 7 Figure 4. Leland Olds Station (taken from Lignite Energy Council, 2011d). Power Cooperative, 2011a). It has a lignite-fired cyclone boiler and a power production capacity of 455 MW (Minnkota Power Cooperative, 2011a). Both units are equipped with ESPs. Unit 2 employs a wet sulfur scrubber to remove SO2 from the flue gas. A wet scrubber is being added to Unit 1 (Lignite Energy Council, 2011e). Figure 5 shows Milton R. Young Station, which emits about 5.5 million tons (4 million tonnes) of CO2 annually. R.M. Heskett Station is located 2 miles north of Mandan, North Dakota, and is owned by Montana–Dakota Utilities Co. (Power of Coal, 2011a). It has two boilers, a smaller 25-MW spreader stoker and a larger 75-MW fluidized bed (Lignite Energy Council, 2011f). The station burns about 500,000 tons (454,000 tonnes) of lignite from the Beulah Mine annually (Lignite Energy Council, 2011f). The fluidized bed allows for reduced SO2 emissions and an ESP removes particulate from the stack gas (Lignite Energy Council, 2011f). R.M. Heskett Station, pictured in Figure 6, emits about 0.5 million tons (0.45 million tonnes) of CO2 each year. Stanton Station is located 1 mile (1.6 km) south and 2.5 miles (4 km) east of Stanton, North Dakota (Power of Coal, 2011b). Owned by GRE, Stanton Station is rated at 188 MW and has two boilers, one of which is a “supplemental” boiler (Great River Energy, 2011b). Stanton Station can burn either lignite or PRB subbituminous coal; it currently burns PRB coal (Great Plains Energy Corridor, 2011). Approximately 850,000 tons (771,000 tonnes) of coal is burned each year (Great River Energy, 2011b). The primary boiler is a wall-fired boiler equipped with an ESP for particulate control (Laudal, 2000). The boiler has no SO2 control (Holmes, 2005). The supplemental boiler is tangentially fired and is equipped with a spray dry scrubber and a baghouse to control SO2 and particulate (Holmes, 2005). Both boilers are equipped with LNBs (Great River Energy, 2008). Figure 7 shows Stanton Station, which emits roughly 1.5 million tons (1.4 million tonnes) of CO2 annually. 8 Figure 5. Milton R. Young Station (taken from Minnkota Power Cooperative, 2011b). Figure 6. R.M. Heskett Station (taken from Lignite Energy Council, 2011f). 9 Figure 7. Stanton Station (Great River Energy, 2011b). Nearby CO2 Sources Lignite is also used at nearby CO2 emission sources. The Freedom Mine supplies about 6.57 million tons/year to the Great Plains Synfuels Plant (Basin Electric Power Cooperative, 2012) with annual CO2 emission of 2.8 million tons/yr (2.5 million tonnes) (U.S. Environmental Protection Agency, 2012) and annual CO2 capture and compression of approximately 3.2 million tons/yr (2.9 million tonnes/yr) (Basin Electric Power Cooperative, 2012). The Savage Mine supplies about 250,000 tons/year of coal to a sugar beet-processing plant and the Lewis & Clark Station in Sidney, Montana. The Blue Flint and Red Trail Ethanol Plants, the Great Plains Synfuels Plant, and the Tesoro Refinery are all located near the cluster of power plants. The Blue Flint Ethanol Plant is collocated with Coal Creek Station, while Antelope Valley Station is located on the same campus as the Great Plains Synfuels Plant. The Tesoro Refinery is very near the R.M. Heskett station. Red Trail Energy is roughly 50 miles (80 km) from the power plants. Gas-processing facilities are within a range of about 50 to 200 miles (80–322 km), depending upon which two facilities are being discussed. Table 3 summarizes the CO2 emission levels from these nearby sources. The ethanol plants produce a nearly pure CO2 stream that requires only dehydration and compression. Depending upon the method used to separate the CO2 from the raw natural gas stream, the CO2 stream from a gas-processing facility may be nearly pure as well, also requiring only dehydration and compression. The Great Plains Synfuels Plant produces bone-dry CO2 that contains 96.8% CO2, 1.1% H2S, 1.0% ethane, 0.3% methane, and 0.8% other compounds (Perry 10 Table 3. CO2 Emissions from Sources in Close Proximity to North Dakota’s Power Plants Facility CO2 Emissions, mt/yr (mtonnes/yr) Blue Flint Ethanol Plant 0.285 (0.258)a Red Trail Energy 0.285 (0.258)a Great Plains Synfuels Plant 2.8 (2.5)b,c Tesoro Refinery 0.93 (0.84)a a b c Estimated according to methodology listed in Pavlish et al., 2009. Emissions for 2010 from U.S. Environmental Protection Agency (2012). The amount listed here is the estimated amount that is emitted. An equal amount of CO2 is transported to Canada and sequestered. and Eliason, 2004). The Tesoro Refinery would likely use a solvent-scrubbing system to capture its CO2, meaning that its product stream composition would be very similar to that of one of the power plants equipped with a similar solvent-scrubbing system. OVERVIEW OF CURRENT CCS TECHNOLOGIES Carbon dioxide capture and storage is used globally to refer to capture of CO2 from point sources combined with storage of the captured CO2 in geologic or underground formations. While CCS technologies are developing rapidly worldwide and possess the potential to offer a significant contribution to CO2 mitigation, there is still much work to be done to reduce the costs associated with these technologies, which have the potential to alter the cost of electricity and, ultimately, the cost of living. Nonetheless, great strides are being made, and some commercialscale CCS technologies are already available. Brief descriptions of the major carbon capture technology platforms and their technology development status are provided as follows. The reader desiring greater detail is encouraged to consult the Plains CO2 Reduction (PCOR) Partnership document entitled “Current Status of CO2 Capture Technology Development and Application” (Cowan et al., 2011) for greater detail. CO2 Capture Technology Platforms Three CO2 capture technology platforms exist: precombustion capture, capture during combustion, and postcombustion capture. Capture during combustion is often referred to as oxyfiring or oxycombustion because one of its approaches involves the use of pure oxygen rather than air as the source of molecular oxygen which is fed to the boiler. In general, precombustion capture yields high-purity, high-pressure CO2, combustion capture yields purified low-pressure CO2, and postcombustion capture yields high-purity low-to-moderate-pressure CO2. Some beneficial-use technologies can be used to provide for postcombustion capture. Precombustion Carbon Capture In precombustion capture, CO2 is separated from the fuel gas prior to its combustion. In some cases this can be a partial recovery of the carbon such as happens when CO2 is captured during natural gas processing and when CO2 is captured during the production of synthetic natural gas at the Great Plains Synfuels Plant. In a coal-fed facility where full precombustion 11 capture is performed, the coal is gasified, to produce a mixture of gases consisting largely of CO and H2. This product is called synthesis gas, or syngas. A subsequent water–gas shift reaction is used to convert the CO to CO2 and produce more hydrogen. The CO2 and hydrogen are then separated and the hydrogen used as the combustion gas. Commercially available processes that are available for performing the CO2–H2 separation include the Selexol™ and Rectisol processes, which rely on the use of a physical solvent to perform the separation. These processes perform the separation under high-pressure and low-temperature conditions because the solvents used have a high capacity for dissolution of CO2 under these conditions. These processes are popularly used for natural gas processing and treatment of syngas at refineries and other industrial facilities. The Rectisol process is used at the Great Plains Synfuels Plant. Other precombustion technologies include the use of other physical and chemical solvents, CO2adsorbing solids, and hydrogen-permeable membranes. Some of the alternative solvents are used commercially in natural gas-processing and industrial hydrogen production applications. The hydrogen-permeable membrane technologies show particular promise but are still several years from being ready for use in full-scale commercial power generation systems. Combining coal gasification and precombustion CO2 capture technology into an electrical generation power plant would involve combustion of the hydrogen produced in a combustion turbine and further electrical generation using a steam cycle supplied with heat taken from the combustion step. This type of power plant is known as an integrated gasification combined-cycle (IGCC) power plant with carbon capture. No full-scale IGCC facilities with carbon capture exist today, but the Texas Clean Energy Project (TCEP) 400-MW IGCC with capture is nearing initiation of construction (Texas Clean Energy Project, 2012). This facility, near Penwell, Texas, will use the Rectisol process for CO2 capture and sell CO2 for use in enhanced oil recovery (EOR). The fuel planned for use in the plant is PRB coal. CO2 Capture During Combustion With process modification, a concentrated stream of CO2 can be generated during combustion in a process called oxygen combustion, or oxycombustion. Substitution of pure oxygen for the combustion air produces a CO2-rich flue gas that requires minimum processing before use or permanent storage. Typically, the CO2 can be recovered by compressing, cooling, and dehydrating the gas stream to remove traces of water that are generated during combustion. When the end use requires it, any noncondensable contaminants that may be present such as N2, NOx, O2, and Ar can be removed by flashing in a gas–liquid separator. The oxycombustion processes that are being developed include technologies represented by modified or retrofitted combustion units, new combustion units, and other processes that incorporate membranes into the combustion chamber, combine high-pressure combustion and exhaust gas condensation, or utilize oxygen provided by metal oxide oxygen carriers to combust the fuel (chemical looping). Oxycombustion can be performed at elevated temperature, which requires the use of specially designed combustion chambers (new construction) or the recirculation of flue gas so that combustion temperatures are controlled at or near those typically used in air-fed boilers. Recirculated flue gas-based oxycombustion has the potential to be applied as a retrofit technology, but its application will require eliminating virtually all leakage of air into the combustion chamber and flue gas treatment path. Chemical-looping combustion (CLC) 12 technologies use solid oxidant materials (e.g., metal oxides) that are recirculated from air contact chambers to the combustion chamber through the use of moving beds or circulating fluidized beds. It is unlikely that CLC will be applied as a retrofit technology. All of the “during combustion” technologies are currently in the developmental stage. Leading organizations and/or companies involved in the testing and further development of this technology include Canada Centre for Mineral and Energy Technology (CANMET), Mitsui Babcock, American Air Liquide, Babcock & Wilcox, Foster Wheeler North America, Vattenfall, Air Products and Chemicals, Praxair, Hitachi, Alstom, and the Energy & Environmental Research Center (EERC). Postcombustion Carbon Capture Postcombustion capture involves separation of CO2 from the flue gas stream of a pc power plant, which is then purified, compressed, and shipped through a pipeline to geologic storage locations or to be used for EOR applications. Three main types of postcombustion capture technologies are under development: chemical absorption processes, adsorption processes using solid sorbents, and adsorption processes using membranes. Of the three primary types of postcombustion CO2 capture technologies, the most advanced is the use of chemical absorbents such as aqueous solutions of alkanolamines. Several companies have developed and patented or hold proprietary a variety of different chemical solvent formulations and/or process configurations, but they all work in a similar manner. The flue gas containing the CO2 is contacted with the chemical solvent in an adsorption tower where the CO2 reacts with an amino functional group to form a carbamate or a bicarbonate ion. The rich solvent is transported to a stripper tower where heat is added to drive the reverse reaction to yield a purified CO2 stream. This purified CO2 stream is cooled, dried, and compressed. Currently, there are no companies that offer performance guarantees for full commercial-scale systems that would operate on coal combustion flue gas, but several companies (e.g., Alstom, Fluor, Mitsubishi Heavy Industries [MHI], SNC Lavalin-Cansolv) are involved in large pilot- to small commercial-scale demonstrations, including the 110-MW commercial-scale demonstration project at SaskPower’s Boundary Dam facility. MHI does provide performance guarantees for CO2 capture from natural gas combustion flue gas, and several industrial-scale systems are in operation. All but one of these is located at a urea fertilizer production plant where the captured CO2 is used to convert anhydrous ammonia to urea. The reader interested in greater detail on the development of postcombustion capture technologies is encouraged to consult the PCOR Partnership document entitled “Current Status of CO2 Capture Technology Development and Application” (Cowan et al., 2011). CO2 Storage Technologies Once CO2 has been captured, it is compressed to pressures exceeding 1450 psi (10 MPa) so that the CO2 is a supercritical fluid having a density similar to that of liquids. This highpressure, dense-phase CO2 can then be more efficiently transported from its source to a storage site. Transportation can be performed by pipeline, rail, truck, or ship. Pipelines are considered the best option for terrestrial CO2 transportation. The reader should refer to the PCOR Partnership report entitled “Opportunities and Challenges Associated with CO2 Compression and Transportation During CCS Activities” (Jensen et al., 2011) for further details on CO2 compression and CO2 pipelines. Currently, the primary option for storing captured CO2 is 13 injecting it into geologic formations deep underground. The three primary options for geological storage are injection into deep saline formations (Pew Center on Global Climate Change, 2009), use of CO2 for EOR with subsequent storage (U.S. Department of Energy [DOE] National Energy Technology Laboratory [NETL], 2008), and use of CO2 for enhanced coalbed methane (ECBM) recovery with subsequent storage (Robertson, 2010). Storage in depleted oil and gas reservoirs without enhanced fossil fuel recovery is also possible. Obviously, it is would be economically much more favorable to use CO2 for the enhanced recovery of oil and gas rather than simply to store the CO2 in deep saline formations. However, the reality is that the total potential demand for CO2 for use in EOR and ECBM operations is very small in comparison with the magnitude of the CO2 emissions. The Global Carbon Capture and Storage Institute has estimated that the global potential demand for CO2 for use in EOR and ECMB operations falls in the range of 66 to 660 million tons/yr (60 to 600 million tonnes/yr). This may look like a lot of demand for CO2, but it is only 1.78 to 17.8 times the current annual CO2 emissions of North Dakota’s coal-fired power plants and only a tiny fraction (0.37%) of the 10 Gt/yr (9.12 Gtonnes/year) of CO2 that IEA estimates will need to be injected for geological storage in order to meet its targeted CO2 emission reductions by 2050 (International Energy Agency, 2008). This value is equivalent to 19% of all emission reductions IEA has predicted will be needed by 2050 in order to control atmospheric CO2 levels according to the 2005–2050 IEA BLUE Map scenario (Figure 8). These findings clearly indicate that, although there is some potential for revenue generation from the use of CO2 combined with geological storage, the amount of CO2 that will be used for this purpose will be very small in comparison with the amount that must be stored in saline formations should the magnitude of the need for carbon capture and storage become anywhere close to that projected by IEA. Figure 8. IEA BLUE Map emission reduction targets (International Energy Agency, 2008). 14 CO2 UTILIZATION TECHNOLOGIES The information collected and documented in this report was designed to answer the questions, What CO2 use technologies exist or are under development? How much of the CO2 from coal-fired power plants can they use? Do any of them have the potential to make money or at least help offset some of the costs of CO2 capture? CO2 utilization technologies can use purified CO2 (use technologies) or they can be used to capture CO2 from flue gas while providing for beneficial use (capture and use technologies). CO2 utilization technologies can provide for a short-term use of the CO2 before it is emitted into the atmosphere or they can use the CO2 in a way that ensures the CO2 is not emitted back to the atmosphere for a sufficiently long period of time that the use also provides for permanent storage. Regulatory action will likely define if a particular use qualifies as a means of decreasing a facility’s CO2 emissions. Many intermediate uses will likely qualify if they replace alternative emissions, although some may not. The CO2 utilization technology provider or user should be aware that there may be some risk to selection and use of a CO2 utilization technology that does not provide for long-term storage. In order for a CO2 utilization technology to be of benefit to a particular producer of CO2, it will be necessary for that technology to be reasonably likely to use CO2 that can be sourced from that facility. Some of the reasons a particular technology would not be applicable for the use of CO2 from a particular facility will be based on the location of that facility because of restrictions related to climate, available resources, and market opportunities. These issues are addressed later in this document, with a focus on the impact on North Dakota power plants. However, a more fundamental issue must be addressed before considering local environment, resources, and market concerns—whether the technology is likely to require externally sourced CO2. This is a critical issue for fossil energy-based power producers. In general, the literature on CO2 utilization technologies often ignores from where the CO2 that will be used for a particular process is likely to come. Is it likely that the CO2 will come from coal-fired electrical power plants or will it come from other processes integral to the industry that is likely to use the CO2 in the beneficial-use process? This is a very important issue for the North Dakota LEC because the membership is made up predominantly of coal producers and electricity generators. The CO2-use technologies that are likely to be of the greatest interest to them are those that require externally sourced CO2, not those where associated precursor processes and heat and power generation needed to perform those processes will likely generate the CO2 that will be used. Widely advertised CO2-use technologies that are unlikely to require externally sourced CO2 are the production of urea and polycarbonate plastics. Few of the other fuel and chemical technologies will require externally sourced CO2 unless they use sunlight directly or they use solar- or wind power-derived electricity. The technologies that will need externally sourced CO2 are those that use the CO2 directly as a gas, supercritical fluid, or solvent; those that use sunlight to grow algae or plants; and many of the mineralization technologies. In a carbon emission-constrained regulatory environment, it is unlikely that the cement industry will use CO2 sourced from power plants because they will almost certainly have produced sufficient CO2 from cement manufacturing to meet their needs. 15 Types of CO2 Utilization Technologies While CCS technologies are developing rapidly worldwide and possess the potential to offer a significant contribution to CO2 mitigation, there is interest in also exploring the possibility of using CO2 as a commodity that can help decrease the amount of CO2 which needs to go to geological storage and can help defray the cost of CO2 capture. The CO2 utilization technologies will include those that can use low-concentration and low-pressure sources of CO2 such that they also serve as a form of postcombustion capture; those that need purified CO2 but can use it from a low-pressure source; and those that require a high-purity and high-pressure source. CO2 utilization technologies can be divided into six broad categories: The direct use of CO2, such as in carbonated beverages, as a dry cleaning solvent, or for energy recovery processes like EOR or ECBM production. The mineralization of CO2 by reacting it with metal oxides or metal hydroxides to form metal carbonates or metal bicarbonates that may be used in construction materials. Use as a feedstock in the manufacture of chemicals, including chemical products or precursor chemicals that require chemical reduction of the carbon to a less oxidized form. Use as a feedstock in the manufacture of chemicals, including chemical products of precursor chemicals like urea or bicarbonate that do not require chemical reduction of the carbon. Photosynthesis-based technologies that reduce the carbon in CO2 to organic carbon for use as food, fuel, or a chemical feedstock. Novel technologies based on the direct use of engineered microorganisms, electricity, and/or the direct use of sunlight for the production of fuels and/or chemical precursors. Recent research on these technology areas is summarized as follows. Direct-Use Technologies Direct-use technologies include the use of CO2 for EOR, ECBM production, and as a solvent, refrigerant, or in foods and beverages. These technologies are well known and are extensively documented elsewhere. Given that this report was commissioned to discuss less well-defined uses for CO2, direct-use technologies are merely summarized in this report so as to provide a more complete picture of the opportunities for use of the CO2 from North Dakota’s power plants. 16 CO2 EOR CO2 EOR involves injecting CO2 into an oil reservoir with the aim of improving the flow of oil out of the reservoir. The injected CO2 is miscible with the oil and swells stranded oil droplets, decreasing the oil-phase viscosity and increasing the amount of oil that can be produced. In CO2 EOR, some of the injected CO2 is recovered with the oil and can be separated and reused while some remains permanently sequestered in the reservoir. Water injection is sometimes alternated with CO2 injection in what is known as a WAG, or water alternating gas, flood. This approach provides a better sweep efficiency and reduces gas channeling from injector to producer (Schlumberger, 2012). Once the recoverable oil has been extracted, continued injection is possible in order to increase the amount of CO2 that can be permanently stored in the reservoir using the existing equipment and facilities. Concerns over CO2 as a greenhouse gas have focused attention on methods to reduce or eliminate CO2 emissions from industrial sources, and it is not surprising that the use of anthropogenic CO2 for EOR has been identified as a means of increasing U.S. oil production (Advanced Resources International, Inc., and Melzer Consulting, 2010). In 2010, 114 CO2 EOR projects provided 281,000 barrels of oil a day in the United States and Canada. While natural CO2 fields accounted for 80% of the CO2 used in these projects, coal gasification (at the Great Plains Gasification Plant in Beulah, North Dakota), natural gas processing, and fertilizer and ammonia production provided the other 20% of the CO2 (Advanced Resources International, Inc., and Melzer Consulting, 2010). Some companies have already used this approach, including ExxonMobil Corporation, which has sold CO2 from its La Barge, Wyoming, gas-processing facility to area oil producers for use in CO2 EOR projects for years (U.S. Department of Energy National Energy Technology Laboratory, 2011a). The company currently captures 4.4 million tons (4 million tonnes) of CO2 a year for this purpose. Another major CO2 EOR project using industrially sourced CO2 is located at the Weyburn oil field, just across the U.S.–Canada border in Saskatchewan, Canada. Cenovus Energy, a Canadian oil company, owns the Weyburn Field. About 5000 metric tons of CO2 is injected each day into the Weyburn Field, contributing an additional 5000 barrels of oil/day to the total daily production of 20,560 barrels/day for the entire Weyburn unit (IEA Greenhouse Gas R&D Programme, 2012). The CO2 used in the Weyburn oil field is produced by the North Dakotabased, lignite-fired Great Plains Synfuels Plant and is delivered via a 205-mile (330 km) pipeline. It is estimated that 22 million tons (20 million tonnes) of CO2 will be injected over the lifetime of the project (IEA Greenhouse Gas R&D Programme, 2012). According to a DOE NETL study other CO2 EOR projects are in the offing that are expected to utilize CO2 captured from industrial sources, and proposals to capture CO2 from coal-fired power plants, ethanol plants, and other industrial processes to supply EOR projects are being considered for funding in a number of states (U.S. Department of Energy National Energy Technology Laboratory, 2011a). 17 CO2 ECBM CBM is natural gas that has adsorbed in coal seams and many coal beds, especially unminable ones, that contains commercial quantities of adsorbed natural gas. In recent years, injecting CO2 into unminable coal beds has been proposed as a method of enhancing the production of methane from CBM operations in a process called CO2 ECBM (Robertson, 2010). Typically, recovery of CBM is around 40%–50%, and CO2 injection can improve this to 90%– 100% (Tondeur, 2011). Thus the CO2 ECBM process is also effectively a CO2 utilization technology, and the produced methane is expected to generate additional revenue that can offset the costs associated with the injection and sequestration of CO2 in coal beds. In the CO2 ECBM process, CO2 is used to displace the adsorbed methane molecules and increase methane production without lowering reservoir pressure. As CO2 is injected into a coal seam containing methane, the CO2 molecules compete with the methane molecules for adsorption sites. Methane molecules detach from the adsorption sites because of a decrease in methane partial pressure in the free gas phase. The displaced methane is then free to flow to a production well, while the injected CO2, which has a greater adsorption affinity than methane, is adsorbed onto the coal. According to the U.S. Geological Survey (USGS) Energy Resources Program, CBM accounts for about 7.5% of U.S. natural gas production, and more than 700 Tcf of CBM gas is in place, with over 100 Tcf economically recoverable – enough for a 5-year supply at present rates of consumption (U.S. Geological Survey Energy Resources Program, 2011). Therefore, 100 Tcf of natural gas could be potentially recovered by using CO2 captured from power plants, which reduces carbon emissions into the atmosphere. A recent study of the Powder River coalbed methane basin, which extends across Wyoming and Montana and includes some of the deeper Fort Union coals, has identified about 61 Tcf of natural gas in place, of which an estimated 39 Tcf is technically recoverable (Advanced Resources International, Inc., 2002). In most ECBM recovery operations as well as in EOR, the cost of CO2 and transportation from the source to the end-user site plays a key role in determining the economic feasibility of such operations. Given that natural sources of CO2 are mostly located in the southern parts of the United States, North Dakota CO2 sources from coal-fired power plants could potentially become viable options. Direct Use of CO2 as a Solvent, Refrigerant, or in Beverage Carbonation CO2 has been directly used for many years in a variety of industries that are well known. It is used as a refrigerant in the food industry and is an energy-conserving, selective, and wastereducing alternative to organic solvents (U.S. Environmental Protection Agency, 2012). As a solvent, it is employed to decaffeinate coffee and dry-clean clothing, is an extraction solvent in laboratories, and is used in the medical and pharmaceutical fields as well. Most people are familiar with CO2 as the carbonation in mineral water and soda pop. Because these uses are so well known, they will not be discussed in detail here. The global market for CO2 for these purposes is currently met with existing supplies of CO2 and is not likely to offer any beneficialuse opportunities to North Dakota’s power plants. 18 Mineralization Technologies Mineralization technologies are still relatively new. Most do not have well-defined products that can be accurately priced, and significant questions exist concerning the availability and cost of the required metal ions and alkalinity. Metal oxides and alkalinity are sometimes found in coal ashes, but high-alkalinity coal ash is currently used beneficially, and its value is unlikely to increase after reacting it with CO2. Other technologies that use sources of metal ions such as brines require the electrochemical generation of alkalinity, which consumes a significant amount of electricity. Mineralization is the formation of a carbonate or bicarbonate solid from CO2. This type of process leaves the carbon in a fully oxidized state, as it is in CO2. Because the CO2 is used to form the carbonate or bicarbonate, it becomes a part of the solid product. CO2 captured from any source could be used as a feedstock for mineralization reactions. CO2 is an acid anhydride, meaning that it displays acidic properties, especially in solution. Therefore, a CO2 mineralization process requires a source of alkalinity for the reaction to take place. In most mineralization technologies, there must be a source of basic cations such as those of alkaline-earth metals (Ca, Mg, etc.) that will form a stable mineral carbonate or bicarbonate, as well as sufficient alkalinity to neutralize the acidity of dissolved and hydrated CO2 (i.e., carbonic acid). Although the cations commonly used are Ca and Mg, which form CaCO3 and MgCO3 with very low solubilities, sodium has also been explored because of the readily available high-sodium-concentration brines, i.e., saline water. The cations could be obtained by various methods, including mining earth minerals, pumping them from a well or water body, capturing them from an industrial waste product stream, or they could be manufactured specifically for this purpose. The use of existing alkalinity is clearly preferable to the use of manufactured alkalinity, especially from an energy-use standpoint. Alkalinity can be produced using a variety of electrochemical methods, but the electricity cost for doing so is relatively high. It was determined that mineralization based on electrochemically generated alkalinity would have a minimum electricity input cost of about $22.68/ton ($25/tonne) of CO2 mineralized to bicarbonate or $45.36/ton ($50/tonne) of CO2 mineralized to carbonate, assuming the cost of electricity were 5 cents/kWh. Details of this calculation are presented in the “Cost of Electricity for Generation of Alkalinity for CO2 Mineralization” section of this document. Mineralization processes can be categorized by the source of the cations, the source of the alkalinity, or the target product(s). It is difficult to strictly follow any single categorization approach because some of the technology developers are working with multiple material sources and/or developing methods for producing multiple products. The following text discusses carbonate-forming technologies as well as the use of coal combustion products (CCPs), silicatecontaining materials, and feldspar for mineralization of CO2. It should be noted that the most advanced of the mineralization technologies is still only at a pilot scale of development and that the products that will be generated by the various technologies, should they become commercial, are more likely to fill niche markets than to be widely employed. 19 Several technology developers have presented information indicating they are considering the use of alkaline waste materials including alkaline fly ash or alkaline wastes for industrial processes for the purpose of capturing CO2 and making a useful product. Because there is significant breadth in source material and/or potential product type/process type of, it is difficult to organize the technologies into clear categories. Therefore, although the technologies have been divided into three categories, the reader should recognize that several of the technologies could be categorized into at least two of the categories: technologies based on use of brine with electrochemical generation of alkalinity, technologies based on the use of alkaline wastes including alkaline fly ash, and technologies based on the use of alkaline minerals that can be mined (e.g. ultramafic rocks). A fourth category, other mineralization technologies, holds mineralization technologies that do not clearly fit into any of the three categories. These include the use of CO2 for concrete curing, a technology provider focused on developing new materials and methods for making those materials, and a few others. Mineralization Technologies Using Brines and Electrochemical Generation of Alkalinity Calera Corporation – Calera Technology Calera Corporation is capturing CO2 through mineralization. A schematic of its process is shown in Figure 9. The CO2 is combined with alkalinity from waste products such as fly ash or from natural sources that include seawater and/or brines (potentially waste brine from seawater desalination or from inland aquifers). Alternatively, alkalinity can be produced electrochemically (All Business, 2010; Calera Corporation, 2009) based on Calera’s low energy (ABLE) electrochemical process shown in Figure 10. ABLE is an undisclosed proprietary process, most likely based on the use of bipolar membrane-based electrochemical splitting of water. If the brine used to feed the process is sodium chloride, the electrochemical process produces caustic soda (NaOH) and hydrochloric acid. Hydrochloric acid would be sold as an additional product (Calera Corporation, 2011). Caustic soda would serve as a source of alkalinity in Calera’s carbon mineralization via aqueous precipitation (MAP) process (Calera Corporation, 2010a), which should produce Na2CO3 as the product of CO2 capture. Alternatively, calcium and magnesium chlorides can be used in the electrochemical process. The corresponding carbonates would be produced, which could be used to manufacture building materials such as cement, supplementary cementitious materials (SCM), aggregates, and sand (All Business, 2010). Calera’s carbon capture and sequestration process can capture up to 90% of CO2 from power plant flue gases, with an energy penalty ranging from about 10% to 40% (Zaelke et al., 2011). Calera notes on its Web site that the company has attained the minimum goal of 80% CO2 capture with less than 10% power consumption, verified independently (Calera Corporation, 2011). The process also provides a high level of SO2 removal and can capture particulates, mercury, and other metals (All Business, 2010; Zaelke et al., 2011). The Scientific Synthesis Team noted that the economics of the Calera technology are most feasible when power plants are sited near appropriate brines, alternative alkalinity, and mineral sources (Zaelke et al., 2011). 20 Figure 9. Calera CO2 capture and mineralization process (Calera Corporation, 2010b). Figure 10. Electrochemical generation of alkalinity for the Calera CO2 capture and mineralization process (Calera Corporation, 2011). 21 Calera performed a pilot-scale investigation of the process at Moss Landing, California, at a site formerly used to extract magnesium from seawater and located adjacent to Dynegy’s Moss Landing gas-fired power plant, which served as the CO2 source. The Moss Landing pilot test utilized a gas–liquid contacting system from Neumann Systems Group to contact the flue gas with the brine (Calera Corporation, 2009). Calera has also operated a 0.3-MWth-equivalent coalfired boiler simulator. In September 2009, DOE awarded a grant for expansion of the Moss Landing facility to demonstration scale, treating a 50-MW-equivalent slipstream from the Dynegy plant (All Business, 2010). In July 2010, Calera was awarded a DOE NETL Phase 2 grant to complete the design, construction, and operation of a building material production system to produce carbonate-containing aggregates. The building material production system will ultimately be integrated with the CO2 absorption facility (U.S. Department of Energy National Energy Technology Laboratory, 2011a). The company claims that its aggregates contain approximately 0.5 tons (0.45 tonnes) of sequestered CO2 per ton of aggregate. Through the process of using CO2-sequestered materials (Calera SCM and aggregates), Calera claims a savings of 1146 lb CO2 per cubic yard (680 kg/m3) of concrete versus a release of 537 lb (319 kg/m3) CO2 during production of a cubic yard of conventional concrete (Calera Corporation, 2011). Naturally occurring brines and waste materials with ideal characteristics have been demonstrated in the Calera process at the laboratory- and pilot plant-scale levels and are undergoing improvements in process efficiency and optimization (Zaelke et al., 2011). It has been found that the use of seawater alone requires too much energy and that alkaline industrial waste is too limited for sustainable operations at a significant scale (Zaelke et al., 2011). Cemtrex – Carbondox Process Cemtrex is developing a mineralization-based CO2 capture process called the Carbondox process. The process captures CO2 from coal-fired flue gas using a corona catalyst and bicarbonate mechanisms in an aqueous medium. The process would be installed after the FGD equipment at a pc-fired power plant (Cemtrex, 2010). New Sky Energy Process New Sky Energy (NSE) is a Colorado-based company that is working on a CO2 mineralization process based on electrochemical processing of brine and conversion of CO2 to Na2CO3. According to an NSE patent application (Little et al., 2008), the system is designed to produce hydrogen, oxygen, base, and acid using electrochemical processes fed with power that can be derived from a renewable energy source (most likely solar and/or wind power). The company also has submitted a patent application that reveals a direct solar-to-water hydrolysis process that would eliminate the need for photovoltaic solar- or wind-generated electricity. Simplistically, the process uses water, inexpensive salts, and CO2 to produce hydrogen, oxygen, sulfuric acid, and sodium hydroxide. NSE claims that the process can trap 1.1 tons of CO2 per ton of NaOH. The materials produced can be used in the manufacture of plastics, glass, resins, fertilizers, building materials, and other goods (Jaffe, 2010; Peterson, 2010). Figure 11 displays the variety of potential carbon-neutral and carbon-negative materials the company anticipates for manufacture from the carbonates produced in the process. 22 Figure 11. Carbon-neutral chemical and carbon-negative products from the New Sky process (Little, 2009b). In January 2010, NSE and the Colorado School of Mines (CSM) announced that NSE would fund a project at CSM to build a fully operating, scalable model of the New Sky electrochemical and carbon capture technology (Colorado School of Mines, 2010). New Sky, as part of Ag-Water New Sky, LLC, was reported to have teamed up with the Westlands Water District in California, the largest agricultural water management agency in the United States, to build a desalination plant that would process approximately 240,000 gallons (908 m3) of drainage water daily (Little, 2009a). The process would yield 8 to 10 tons (7.3 to 9.1 tonnes) of solid waste per acre-foot of water treated, which would be converted to chemicals such as acid, caustic soda, and solid carbonates. The project would reportedly trap about 2.8 tons (2.5 tonnes) of CO2 daily (Kaye, 2010; Zing, 2010). Figure 12 shows that sodium sulfate from the desalination process is introduced into the New Sky process. SkyMine® Mineralization Technology Skyonic Corporation, based in Austin, Texas, has developed the SkyMine process, a technology that uses brine as a source of mineral ions for precipitation of solid carbonates and bicarbonates. Electrolysis is used to produce hydroxide alkalinity for the formation of the carbonates and bicarbonates upon absorption of CO2. The CO2 ends up as solid bicarbonate products (Jones, 2010). Skyonic also claims that the process removes SOx, NO2, mercury, and other heavy metals (U.S. Department of Energy National Energy Technology Laboratory, 2011a; Skyonic, 2011a). Scalability is noted as a key advantage of the SkyMine process, allowing a 23 Figure 12. Ag-Water New Sky integrated process (Little, 2009). configuration to achieve 10%–99% removal of CO2 from industrial plants and power plants. The process produces salable products, including solid carbonates and bicarbonates for use in bioalgae applications, and green chemicals such as hydrochloric acid, bleach, chlorine, and hydrogen (Skyonic, 2011a). U.S. Patent 7,727,374 B2 entitled “Removing Carbon Dioxide from Waste Streams Through Co-Generation of Carbonate and/or Bicarbonate Minerals” related to the SkyMine process has been granted to Skyonic (Jones, 2010a). A Phase 1 DOE NETL grant was awarded to Skyonic, which funded activities in preparation for construction of a commercial-scale SkyMine Plant to capture CO2 from a cement-manufacturing plant (Skyonic, 2011a). In April 2010, Skyonic announced the start of operation of its pilot demonstration facility at the Capitol Aggregates, Ltd., cementmanufacturing plant in San Antonio, Texas (Skyonic, 2011b). Skyonic received Phase 2 funding from DOE NETL to support construction of the Capitol–SkyMine Plant as well as to continue development of the SkyMine technology (U.S. Department of Energy National Energy Technology Laboratory, 2011a; Skyonic, 2011b). Construction of this facility was expected to begin in the fall of 2010 and be fully operational the first half of 2012. The plant is targeted to capture 82,700 tons (75,000 tonnes) of CO2 from the cement plant by mineralizing the emissions as high-purity baking soda and to offset an additional 165,000 tons (150,000 tonnes) of CO2 in the manufacture of chemical by-products (Skyonic, 2011b). The SkyMine process was listed as a multipollutant control option for fossil fuel power plants as part of the U.S. Environmental Protection Agency’s (EPA’s) Commercial Demonstration Permit Program in the National Emission Standards for Hazardous Air Pollutants 24 (NESHAP, or the “utility air toxics rule”) (Skyonic, 2011c; U.S. Environmental Protection Agency, 2011b). Mineralization Technologies Using Waste Materials These technologies include the use of alkaline waste materials from industrial processes such as the production of aluminum and iron as well as alkaline wastes derived from coal combustion activities like fly ash. Numerous reports are available in the literature related to CCPs as CO2 capture materials that have not been commercialized. Lignite fly ashes are noted to have high acid-neutralizing capacities of up to 7 meq/g (Back et al., 2008). Alcoa, Inc. – Carbon Capture with Bauxite Waste Alcoa, Inc., has developed a CO2 capture and bauxite waste disposal process that involves mineralization and disposal of CO2 as a carbonate solid. The “carbon capture” process, shown in Figure 13, was developed at Alcoa’s facility in Kwinana, Australia, to capture CO2 from a nearby ammonia plant (Alcoa, 2007; Alcoa, 2011a; Alcoa, 2011b). The bauxite waste, which is a by-product of the alumina-refining industry, is highly alkaline, with variable physical, chemical, and mineralogical characteristics that are based primarily on the composition of the bauxite ore (Dilmore et al., 2008). In the process, the waste is contacted with flue gas and the CO2 in the flue gas reacts with hydroxide ions in the waste to form bicarbonate ions that are then sequestered as Figure 13. Alcoa’s carbon capture system (Alcoa, 2011b). 25 mineral carbonates (U.S. Department of Energy National Energy Technology Laboratory, 2011b). The process reduces the alkalinity of the material, reducing residue-drying time and providing a sink for the CO2 (Alcoa, 2011a). The neutralized waste is dried and disposed of in a landfill or used to refill the bauxite mine. It can also be used beneficially as road base, building materials, or as a soil amendment (Alcoa, 2011b). In a cooperative research project between DOE NETL and Alcoa, a mixture of bauxite residue and oil/gas wastewater brine was tested for its ability to capture CO2 (Dilmore et al., 2008; U.S. Department of Energy National Energy Technology Laboratory, 2006). A 90:10 (by volume) bauxite residue-to-brine mixture exhibited a CO2 sequestration capacity of greater than 9.5 g/L when exposed to pure CO2 at 20°C and 0.689 MPa (100 psig). The laboratory tests demonstrated that bauxite residue as a caustic agent added to acidic brine solutions improved CO2 sequestration and that the trapping of CO2 is achieved through both mineralization and solubilization. Effective CO2 sequestration is enriched by fixing the pH at relatively high values to counteract the loss of alkalinity (i.e., the production of H+) during mineral precipitation and CO2 dissolution. The laboratory test also suggested that the CO2 sequestration capacity of the samples increases with aging because of a noted increase in the pH value with time. Alcoa has continued to improve the process and was selected to receive Phase 2 funding from DOE NETL for a 4-year pilot-scale demonstration project from 2009 to 2013 (U.S. Department of Energy National Energy Technology Laboratory, 2006). Based on the information provided, it appears that the exact process being used has changed from that shown in Figure 13, although the source of alkalinity and the metal cations used for mineral formation remain the same. The project team expects to optimize the operating conditions such that greater than 75% CO2 removal is achieved from a boiler flue gas. In steel-manufacturing industries, steel slag can be beneficially utilized as an aggregate and filler for cement to avoid disposal. However, the steel slag must be conditioned to minimize the free CaO, which can lead to swelling of concrete via hydration and carbonation reactions. Research at Columbia University has used the two-step process discussed in the Accelerated Weathering section and shown schematically in Figure 14. The process is used to capture CO2 in stainless steel slag (SSS) as a means of accelerating carbonation in the material through both extraction of Ca from SSS and the capture of CO2 using a high-pH, Ca-rich solution. Several reaction conditions have been evaluated to produce precipitated calcium carbonate (Columbia University, 2011a). Columbia University – Accelerated Carbonation of Industrial Wastes Aqueous Slurry Use of Dry FGD Materials Dry FGD materials were evaluated as CO2 capture materials from natural gas by researchers at the University of Kentucky Center for Applied Energy Research. The dry FGD materials included cyclone/baghouse ash and bed ash from utility fluidized-bed combustors, spray dryer absorber (SDA) material from a utility boiler, and dry FGD material from a coolside duct injection technology demonstration run at a pilot plant. The materials were prepared for 26 Figure 14. Accelerated carbon mineralization of high-magnesium-content minerals (Columbia University, 2011a). CO2 capture experiments through hydration or preparation of aqueous slurry. Standard gas blend mixtures containing CO2 were used for the studies. Hydration increased the affinity for CO2 as compared to the as-received samples, and the various fly ash samples absorbed more CO2 than the coarse bed materials. CO2 absorption was calculated at up to about 0.15 tons CO2/ton dry FGD material (80 m3 CO2/tonne dry FGD material). This value was up to nearly 0.23 ton CO2/ton (125 m3/tonne) in the slurry samples. The total absorption was higher in the slurry samples but required a greater length of time than the hydrated solids. The researchers believed that design changes could improve the efficiency of the slurry process. A linear relation between available calcium and CO2 absorption was noted for most of the materials. The decreased CO2 absorption capacity of the bed ash was attributed to the larger particle size and potential blockage of particle pores by SO2. X-ray diffraction (XRD) analyses showed that the portlandite, Ca(OH)2, reacted with the CO2 to form calcite (Taulbee et al., 1997). Augmented Brine Solutions Researchers at DOE NETL evaluated the use of Class C fly ash and an FGD fly ash (assumed by the present reviewers to be circulating fluid-bed combustor [CFBC] ash) in combination with oil field brine as CO2 mineralization materials. One of the fly ash samples was obtained from GRE’s Coal Creek Station located in North Dakota (Soong et al., 2006; Soong et al., 2005). Coal Creek fly ash is commonly mistaken for Class C fly ash but can actually be classified as either a Class C or a Class F fly ash, more commonly Class F (Great River Energy, 2006; Grupo Cementos Chihuahua, 2011; Minnesota Department of Transportation, 2010; 27 Tikalsky et al., 2007). A variety of conditions were evaluated with the brine and CCP samples. The brine was used as-received or mixed with a fly ash to adjust the pH prior to experimentation with CO2. The fly ash was then separated from the brine for recycling or was used as the reactant with brine for further reaction with CO2. Additional experiments were performed using NaOH as an additive for pH adjustment. The pH enhancement of the brine with fly ash was attributed to the CaO, which is known to have a high neutralizing value. The experiments showed that the Ca content in the brines and CCPs contributed to the formation of CaCO3 with the addition of CO2. Consumption of up to 0.546 mol/L CO2 was reported. XRD analyses showed that the solid produced was commonly >90% CaCO3, which the authors noted may be used for beneficial use on land (Soong et al., 2006; Soong et al., 2005). An estimate was provided indicating that, with one of the conditions tested, 20 billion barrels of brine could sequester 763 million tons (692 million tonnes) of CO2 and consume 150 million tons (136 million tonnes) of fly ash (Soong et al., 2006). The use of fly ash, brine, and CO2 for carbonation is viewed not only as a method to sequester CO2 but also as an environmental remediation method at South African power plants. Waste brine streams are produced in power plants from pretreatment of raw water for boiler feed through processes such as reverse osmosis and electroreversal dialysis. The disposal of fly ash and brine raises environmental concerns because of the potential for these materials to leach inorganic constituents, including soluble salts and trace metals. The studies evaluated fractionated fly ash, brine/fly ash/CO2 chemistry, and carbonation efficiency. The fly ash fractions had different CaO contents, with the >150-µm size fraction containing the lowest level of CaO (5.9 wt%); the other fractions ranged from 8.6 to 10.3 wt% CaO. The highest CO2 sequestration potential was observed in the 20–150-µm size fraction at 144 lb CO2/ton fly ash (71.84 kg CO2/tonne fly ash), while 73 lb CO2/ton fly ash (36.47 kg CO2/tonne fly ash) was observed as the lowest potential in the >150-µm particles. The results showed that the elemental concentrations in the brine were considerably reduced after carbonation experiments using fly ash and brine, with the exception of B, Mo, and V, which was attributed to fly ash leachate (Muriithi et al., 2011; Muriithi et al., 2009). Fly Ash Aqueous Suspensions Deposited in Underground Coal Mines The use of fly ash–water suspensions in underground mines in Poland is widespread. This approach is used to fill excavations as well as fill, caulk, and reconsolidate mine collapses, with the benefits of improved efficiency of underground mine ventilation and a reduction of methane and fire hazards. Experiments were performed with various ash–water ratios using four types of fly ash samples from Poland, which included fly ash with desulfurization products from hardcoal combustion, from hard-coal combustion in powder boilers, from hard-coal combustion in fluidized-bed boilers, and from lignite combustion in fluidized-bed boilers. Results showed that up to 0.088 tons CO2/ton fly (8.8 g CO2/100 g fly ash) ash was absorbed after up to 25 days in the various suspensions evaluated (Uliasz-Bocheńczyk et al., 2009). German Lignite Fly Ash in Aqueous Suspension Experiments were performed in Germany to evaluate the reaction kinetics of lignite fly ashes and CO2 in aqueous suspension (Back et al., 2008). A summary of the three reaction 28 phases based on predominating buffering systems and CO2 uptake rates is provided in Table 4. The experiments were set up to evaluate CO2 storage by lignite fly ash in aqueous suspensions at low temperature (25°–75°C) and CO2 partial pressures (pCO2) comparable to flue gas observed from lignite combustion (0.01–0.03 MPa). The researchers noted that the acid-neutralizing capacity (ANC) seems to be controlled by the dissolution of lime. The Mg in the sample becomes relevant at pH <8. The precipitation of ettringite, Ca6Al2(SO4)3(OH)12·26H2O, was noted. The carbonation reaction consumes the alkalinity and lowers the pH of the system. Variable pCO2 evaluations indicated that higher pCO2 values altered the pH regime, which significantly affected the pathways of CO2 uptake. The solid-to-liquid ratio affects the pH, availability of Ca and Mg, and the rate of CO2 uptake. An increase in temperature extended the reaction times for Phases 1 and 2, which leads to enhanced carbonation mainly because of an enhanced release of Ca from the mineral compounds and an increased rate of calcite precipitation. A maximum CO2 uptake (approximately 0.23 kg CO2 per kg fly ash) was observed at 75°C, 50 g fly ash/L, 0.01 MPa pCO2, and 600 rpm stirring rate. “More than 75% of the available Ca was converted into calcite, 90% of the total uptake could be related to the precipitation of calcite, and almost 90% of the neutralizing capacity determined as ANC was consumed by the reaction with CO2” (Back et al., 2008). Michigan Technological University Process A patent has been assigned to the Michigan Technological University describing methods to capture CO2 to form a bicarbonate solution and then sequester the CO2 in a carbonate form (Kawatra et al., 2011). A variety of options are provided in the patent. Preferably, a dilute sodium (or potassium) carbonate-containing solution (optimally 2% Na2CO3 w/w) is reacted with CO2 to form a bicarbonate solution. It was noted that a fresh absorbent solution could remove 90% of the CO2 (from the air) passed through it. The bicarbonate solution is then either heated to decompose and release the CO2 as a concentrated gas for utilization or is injected into mineral and industrial wastes that contain calcium or magnesium in noncarbonate forms or iron Table 4. Alkaline Fly Ash Reaction Phases with CO2 (adapted from Back et al., 2008) Reaction Phase pH Time, min Reaction Characteristics Reaction Product(s) 1 >12 <30 Dissolution of lime, the onset of Calcium carbonate calcite precipitation, and a maximum uptake (limited by dissolution of CO2) 2 <10.5 10–60 Carbonation reaction and Calcium carbonate alkalinity consumption 3 <8.3 30+ Dissolution of periclase (MgO) Dissolved magnesium bicarbonate 29 in the Fe2+ oxidation state. Examples of these materials include wollastonite; pyroxene minerals; serpentine minerals; epidote; and Ca-rich, Mg-rich, and Fe-rich compounds such as cement kiln dusts, metallurgical slags, and certain mine tailings; or other high-volume wastes with the correct composition (Kawatra et al., 2011). The research group hopes to build a pilot plant in cooperation with an industry partner, Carbontec Energy Corporation (Goodrich, 2011). Production of Calcite and Calcite–Se0 Red Nanocomposite Aqueous carbonation using coal combustion fly ash containing about 4.1 wt% CaO to sequester CO2 under pressure was evaluated by a group of international researchers. The research showed that the CaO carbonation efficiency was independent of the initial CO2 pressure (10– 40 bar) and was not significantly affected by reaction temperature (room temperature, 30°C, and 60°C) or by fly ash dose (50, 100, or 150 g). The results of the study indicated that 1 ton CO2 could be sequestered in 38.18 tons fly ash (26 kg CO2/ton fly ash) as compared to a theoretical value of 32.17 kg CO2/ton fly ash containing 4.1 wt% CaO. The process produces a recyclable CaCO3-rich fly ash material (Montes-Hernandez et al., 2009). In subsequent research, two alkaline materials, coal combustion fly ash and paper mill waste, were used to produce pure calcite or calcite/Se0 red nanocomposite via coutilization of the materials and CO2 (Montes-Hernandez and Renard, 2011). The free lime contained in the fly ash or the free portlandite in the paper mill waste was extracted from the materials in water at atmospheric pressure. The unreacted solids were separated from the aqueous portion, which had pH values of 12.2–12.5 and Ca concentrations of 810–870 mg/L. Compressed or supercritical CO2 was then applied to the alkaline solution under heat and pressure. The solid calcite product was then separated and dried. In a similar manner, with variations in heat and pressure, seleno-Lcystine was added to the alkaline solution following the initial separation to produce a calcite– Se0 red nanocomposite. It was noted that optimization is needed because the process produced only approximately 1.7 g of pure calcite or calcite–Se0 composite from 1 L of alkaline solution in each batch. The researchers proposed that the synthesized powdered calcite could be used as an active ingredient in antacid tablets and as mineral filler in printing inks and the papermaking industry. The unreacted solid from the initial separation is proposed as a component in construction materials, aerogel fabrication, etc. The synthesized carbonate–selenium composite could be used as a pigment and as a dietary supplement. SequesTechTM Process Reddy et al. (2010a, b) are studying the use of alkaline materials, primarily coal combustion fly ash, to simultaneously capture (without prior separation) and mineralize flue gas CO2 in a fluidized-bed reactor. Experiments suggest that the flue gas CO2 is converted into calcite and other carbonates (Reddy and Argyle, 2011). In a pilot-scale study using subbituminous coal, the coal combustion flue gas CO2 concentration was observed to decrease from 13.6% to 9.6%, and the total carbon (as CaCO3) content of the fly ash increased from <0.02% to 3.9%. Hg and SO2 removal and mineralization were also observed. Results of laboratory-scale and small pilot-scale accelerated mineral carbonation experiments have 30 demonstrated that significant mineralization of CO2 (about 25%–30% removal from the flue gas) occurs with fly ash residence times of a few minutes. The reaction temperature and moisture content affected the experimental results. The mineralization capacity was found to be 35– 38.8 lb CO2/ton fly ash (17.6–19.4 kg CO2/tonne fly ash), with an estimated mineralization capacity of 414 lb CO2/ton fly ash (207 kg CO2/tonne fly ash) based on the fly ash oxide content. A preliminary economic analysis of the process for 90% CO2 capture from a 532-MW power plant yielded a mineralization cost of $10/ton ($11/tonne) CO2 at a mineralization capacity of 414 lb CO2/ton fly ash (207 kg CO2/tonne fly ash) (Reddy et al., 2010a, b). The apparatus and process for this technology are described in U.S. Patent 7.879,305 B2 (Reddy and Argyle, 2011). The apparatus can be retrofitted to existing industrial plants, such as coal-fired power plants (Reddy and Argyle, 2009). Suggested uses for the fly ash resulting from the process (carbonated ash) include as a concrete additive, for immobilizing contaminants at hazardous waste disposal sites, and as a soil amendment for reclamation of acidic and sodic soils (Reddy et al., 2011a; Reddy and Argyle, 2011). U.S. Patent Application Publication Nos. 2009/0280046 A1 (Reddy and Argyle, 2009) and WO 2010/114566 A1 (Reddy and Argyle, 2010) provide greater details than U.S. Patent 7.879,305 B2. Included is an extensive background of related art methods and apparatuses that are generally described as requiring a pure CO2 stream and are energy-intensive. Applicable alkaline materials include hospital solid waste incinerated ash, municipal solid waste incinerated ash, paper mill solid waste ash, steel slag ash, and oil shale solid waste ash. Ranges of preferred operating parameters (solid reactant, solid particle size of alkaline material, flue gas volume, solid residence time, flue gas space velocity, contact type, solid-to-flue gas mass ratio, temperature, absolute pressure, source of flue gas, and moisture content of flue gas) are noted. Limited experimental data suggest that As(g) and Se(g) may also be removed from the flue gas. In 2011, the University of Wyoming (UW) Department of Renewable Resources was awarded a UW-based Clean Coal Task Force (CCTF) project to conduct a 3-year test of the SequesTech process to capture postcombustion carbon dioxide from flue gas using fly ash from the Jim Bridger Plant. The investigators will enhance and optimize process parameters such as temperature, moisture, and reaction time; determine the efficacy of the process in the removal of flue gas CO2, SO2, and Hg; evaluate cost economics of the process; and derive cost benefits versus traditional CCS (Wyoming Business Report, 2011). Additional information on the technology available for licensing can be found on the UW Research Products Center Web site (University of Wyoming, 2011a). An update of the process field test at the Jim Bridger Plant, owned by PacifiCorp, was provided in 2011 (University of Wyoming, 2011b). According to an article published in Clean Technica (Kraemer, 2011), SequesTech has been used in a 2120-MW coal plant, removing 25%– 30% of the CO2 from a 300–500-scfm slipstream of flue gas with a concentration of 11%–12.5% CO2. Reddy is anticipating commercial status within a year or so. The technology is estimated to cost $10–$12 per ton of mineralized (sequestered) CO2. If the ratio of fly ash to CO2 is as described, i.e., 414 lb CO2/ton fly ash (207 kg CO2/tonne fly ash), approximately 4.8 tons of fly ash would be needed to sequester each ton of CO2. 31 Mineralization Technologies Using Alkaline Minerals Columbia University – Accelerated Weathering The idea of using accelerated weathering (i.e., artificial formation of minerals) of rocks containing high magnesium and calcium concentrations was first popularized in the 1990s by Dr. Klaus Lackner when he was at Los Alamos National Laboratory (LANL) (Lackner et al., 1998; Lackner et al., 1995). The method is based on the chemical fixation of CO2 in the form of carbonate minerals that remain naturally in the solid state. Two approaches to the carbonation of magnesium and calcium oxides explored were direct carbonation, which binds CO2 from its gaseous form with minerals in the solid state, and aqueous processes, which extract magnesium and calcium ions from minerals using a solution followed by precipitation of either the carbonate or an intermediate product that is carbonated in a separate step (Lackner et al., 1995). In that work, Lackner and his colleagues identified basaltic ultramafic rocks as a good source, but difficulties with accelerated weathering stalled progress toward commercialization. Dr. Ah-Hyung Park, one of Dr. Lackner’s colleagues at Columbia University, has researched mineral carbonation (Park et al., 2003). Magnesium-rich serpentine was chosen as the potential reactant using an aqueous mineral carbonation process. The work focused on the use of chelating agents to accelerate weathering. The weathered mineral produces the calcium and magnesium as metal hydroxides. It was noted that further studies were under way to look into the feasibility of a swing to a higher pH to achieve a higher conversion of the carbonation process (Park et al., 2003), suggesting the potential use of additional hydroxide alkalinity. Lackner and Park have received funding from the New York State Energy Research and Development Authority (NYSERDA) Environmental Monitoring, Evaluation, and Protection Program to investigate the use of wollastonite, a calcium silicate mineral, from deposits in New York State for CO2 sequestration. The process has been proven but has not been optimized. Experimental studies will be performed using chemical additives such as citric acid, ethylenediaminetetraacetic acid (EDTA), ammonium chloride, acetic acid, and phosphoric acid for the dissolution and carbonation of wollastonite (New York State Energy Research and Development Authority, 2010). With partial funding from NYSERDA and ORICA Ltd., Mgbearing minerals such as serpentine and olivine are also being investigated. The research is focused on the chemical and physical dissolution and carbonation of these minerals in the tailored synthesis of high-purity precipitated magnesium carbonate and iron-based nanoparticles. The physical properties of the precipitated magnesium carbonate are controlled to mimic commercially available CaCO3-based filler materials. A life-cycle analysis of the process will be completed (Columbia University, 2011b). The conceptual process can lead to minerals for disposal or beneficial use, as illustrated in Figure 14. Feldspar Feldspar minerals are proposed as a means to neutralize CO2 emissions by forming bicarbonates, quartz, and alumina (Nurmia, 2011a, b). Feldspar minerals are essential components in igneous, metamorphic, and sedimentary rocks and are primarily used in industrial applications for their alumina and alkali content (Industrial Minerals Association – North 32 America, 2011). In the proposed process, flue gas is washed to dissolve CO2 in water. The CO2 solution is passed through crushed feldspar, and aluminum compounds settle in a settling tank. The bicarbonate solution then exits the process or can be recycled into the CO2 dissolution process (Nurmia, 2011a, b). Silicate-Containing Materials Numerous properties of various silicate-containing materials related to carbonation potential have been summarized by Renforth et al. (2011). Properties such as free energy calculations, global mining rates of igneous rocks, production estimates of other materials, and carbonation potential were described. The materials included in the summary encompass Ca- and Mg-containing rocks, cementitious materials, and waste/by-product streams. Materials included in the waste/by-product stream category are fines from aggregate production, mine wastes, cement kiln dust, construction and demolition wastes, blast furnace slag, steelmaking slag, and fuel ash and combustion products. The carbonation reaction free energy calculations indicate that a wide variety of the materials are predicted to undergo carbonation reactions under ambient conditions. However, the calculations do not express kinetic factors such as dissolution rate and reactive surface area. Additionally, other components are often present in the materials of interest for carbonation that may reduce the carbonation potential. Mining of igneous rocks for use in construction is not greatly documented. Mining, aggregate production, and mineral extraction activities produce fines that may have potential for use in carbonation reactions (Renforth et al., 2011). Other Mineralization Technologies CCS Materials, Inc. – Low-Temperature Solidification Process CCS Materials, Inc., is developing an energy-efficient, CO2-consuming inorganic binder intended to be suitable as a high-strength portland cement substitute in concrete. The process is based on carbonation chemistry instead of the hydration chemistry used in portland cement concrete. It is estimated that the process could reduce concrete-making energy requirements by about 60%, primarily from the use of lower temperatures. In addition, it has the potential to reduce total CO2 emissions by approximately 90% through the addition of CO2 to the cementprocessing sequence. The concrete product is reportedly stronger than product created with traditional portland cement processing (U.S. Department of Energy National Energy Technology Laboratory, 2011c). The concrete is reported to have compressive strength values exceeding 14,500 psi (100 MPa) and fully hardens within hours (Tayabji et al., 2010). This is in contrast to portland cement hydration reactions, which take months to years to reach completion. CCS Materials’ process was awarded funding by DOE NETL within the CO2 utilization focus area to further develop its concept, which is currently at laboratory scale. 33 C-Quest Technologies – Chemical Sorbent System The C-Quest Technologies chemical sorbent system is designed to significantly reduce CO2 emissions from utility and industrial boilers. The sorbent ingredients are widely available, and the by-product is a recyclable solid that can be disposed of safely. Capture rates are dependent on several factors, including gas-to-sorbent ratios, temperatures, and retention times, although CO2 capture rates as high as 90% were obtained during laboratory testing at the EERC (Pavlish et al., 2008). The sorbent captures other pollutants as well. In the laboratory, capture rates as high as 99% SO2, 90% mercury, and 15% NOx were observed concurrently with the CO2 capture. Further testing is being performed to determine capture efficiencies and other information required to determine an ultimate cost per ton of CO2 captured (Pavlish et al., 2008). McGill University – Accelerated Concrete Curing McGill University, in partnership with 3H Corporation, was awarded a project by DOE NETL within the CO2 utilization focus. Research at McGill University is aimed at the development of a precast concrete-curing process utilizing CO2 as a reactant to accelerate strength gain, reduce energy consumption, and improve the durability of precast concrete products. The project will include the design and testing of reaction chambers that are intended to replace existing concrete production curing processes. A net process cost of less than $10/ton ($11/tonne) of CO2 sequestered is projected (U.S. Department of Energy National Energy Technology Laboratory, 2011d). Previous work at McGill University was reported in a 2007 master of engineering thesis (Wang, 2007). Either pure CO2 or cement manufacturing flue gas containing 13.8% CO2 was used for carbonation of four cement products, including cement paste, concrete, bead board, and cellulose fiberboard. Pure gas carbonation served as a reference for the flue gas carbonation. The cement-based products were made following industry formulation and process. Carbonation curing took place in a chamber under a pressure of 72.5 psi (0.5 MPa), at ambient temperature for 2 to 20 hours. The CO2 uptake of cement-bonded cellulose fiberboard ranged from 13.5% to 23.6% using pure CO2, compared to 13.5% for cement paste, 12.2% for bead board, and 9.8% for concrete. The CO2 uptake from carbonation using flue gas was 7.0%–8.1% for the fiberboard, 6.8% for the cement paste, 6.3% for the concrete, and 4.4% for the bead board. Both early-age and long-term strengthes produced were comparable for the two carbonation gases. The flue gas carbonation rate was slow and, therefore, generated low heat, evaporated less water, and resulted in an instant strength gain from subsequent hydration. Carbonation of concrete pipe has been reported recently by McGill University researchers (Rostami et al., 2011). Various steam- and carbonation-curing schemes were evaluated. Results showed that following a 2-hr steam curing, 8%–9% CO2 uptake (by cement mass) was observed during a 2-hr carbonation period. Benefits from carbonation were noted in sulfate and acid resistance, pH control, and chloride penetration and sorption. In this study, carbonation did not seem to affect rapid strength gain. The researchers concluded that steam seemed necessary to facilitate carbonation. It is estimated that 303,136 tons (275,000 tonnes) of CO2 could be 34 consumed each year in the United States through an uptake of 10% CO2 by cement mass in concrete pipes containing 12.5% cement. Ohio State University – Carbonation Ash Reactivation (OSCAR) Process Members of the Department of Chemical Engineering at Ohio State University developed a process to reactivate calcium-based sorbents for subsequent use for SO2 removal from coalfired boilers/combustors (Agnihotri et al., 1999; Fan and Agnihotri, 2003; Fan et al., 2001; Gupta et al., 2007). Two calcium-based sorbents were tested in a pilot-scale study (in a furnace sorbent injection mode on a slipstream of a bituminous coal-fired stoker boiler) to demonstrate their reactivity toward sulfur and trace heavy metal (As, Hg, and Se) capture. The sorbents were created by bubbling CO2 through aqueous slurry using one of two types of starting materials. A dispersant was added to the sorbent materials during the carbonation stage to reduce agglomeration. During the carbonation batch process, a complete conversion of Ca to CaCO3 was noted when the pH decreased from about 12 to about 6. Spent lime spray dryer ash was regenerated in aqueous slurry by bubbling CO2 through it to convert the unreacted calcium to calcium carbonate. The researchers noted available calcium within the sorbent particle was redistributed more effectively when reactivated via carbonation than hydration alone. XRD analyses showed complete conversion of the unreacted Ca(OH)2 in the spent lime spray dryer ash to CaCO3. The sorbent utilization for sulfur removal increased from roughly 40% to nearly 85% for the regenerated bottom ash and fly ash samples. The second sorbent has been referred to as reengineered precipitated calcium carbonate or supersorbent and is created from Ca(OH)2 slurry. Prior to the carbonation step, the slurry is subjected to a sulfation step. The sorbent utilization for sulfur removal increased from 50% to more than 95% for the reengineered precipitated calcium carbonate. Potential Use of Mineralization Technologies by North Dakota Power Plants The potential use of mineralization technologies for North Dakota coal-fired power plants and all other uses in general lies in the readily available source of alkalinity in any waste or byproduct streams. The most promising source of existing alkalinity in North Dakota is coal fly ash, especially lignite fly ash. Table 5 provides a list of the major ash metal oxides based on reported x-ray fluorescence (XRF) analysis of coal fly ash from systems with and without dry FGD–SDA. The concentrations of CaO and MgO are highlighted because these represent the target alkalinity for use in CO2 mineralization. The data show that bituminous coal fly ash has very little value to the mineralization technology, while lignite ash shows some promise with elevated levels of basic alkaline-earth metal oxides. However, because some of these metal oxides may be held up as carbonate rocks, more studies are required to determine the actual amount of available alkalinity in lignite fly ash that can be used for mineralization. 35 36 a Table 5. Ash Major Elements Reported as Oxides by XRF, dry basis wt%a–f Elemental Lignite Fly Lignite FGD–SDA, Subbituminous Fly Oxides Ash contains fly ash Ash SiO2 15–50 10–35 18–60 Al2O3 7–25 5–12 14–30 Fe2O3 2–15 3–6 3–10 CaO 13–45 24–35 5–33 MgO 3–10 3–5 1–9 Na2O 0–8 3–5 0–9 0–4 0–2 0–4 K2O TiO2 0–1 0–0.5 0–2 MnO2 0–0.3 0–0.3 0–0.2 0–0.4 0–0.3 0–1.5 P2O5 SrO 0–0.5 0–0.5 0–1 BaO 0–1 0–1 0–1.5 SO3 0–30 10–30 0–8 g LOI 0–5 1–4 0–4 American Coal Ash Association, 2006. Coal Ash Resources Research Consortium, 2011. c Folkedahl and Zygarlicke, 2004. d Goodarzi, 2006. e Manz et al., 1989. f Murphy, 2005. g Loss on ignition. b Subbituminous FGD–SDA, contains fly ash 24–31 13–18 3–6 25–33 2–4 1–2 0–1 0–1.5 0–0.1 0–1 0–0.5 0–0.5 13–15 1–4 Bituminous Fly Ash 20–60 5–35 3–40 1–12 0–5 0–4 0–3 0.5–1 0–0.2 0–0.5 0–0.4 0–0.3 0–4 0–15 Table 6 provides ash and CO2 emission data for North Dakota power plants, which were used to calculate the percentage of annual power plant CO2 emissions that might be mineralized using the amount of available lignite fly ash (i.e., annual production of ash product minus its current usage). These values assume 100% utilization of the MgO and CaO and that gasifier ash has the same composition as fly ash. The calculations show that mineralization using annually produced fly ash will not provide a substantial reduction in CO2 emissions, but it may provide some financial reward through production of a salable product and reduction or elimination of fly ash disposal costs. Market Analysis and Economic Feasibility of Mineralization Technologies A fairly brief analysis of the economic feasibility of mineralization technologies was performed because none of the technology providers are currently making a marketable product. The findings are presented as follows. Value of Mineralization Products Most of the companies working in the area of CO2 mineralization have only provided lists of potential products and have not provided a clear path to making and marketing those products. The market will dictate the type and quantity of products that are made. Calera and CCS Table 6. North Dakota Power Plant Ash and CO2 Emission and Mineralization Potentials Station Antelope Valley Leland Olds Coal Creek Milton R. Young Heskett Coyote Great Plains Synfuels Plant Total a CCP Type Fly ash + SDA material Fly ash Fly ash Fly ash FBC ash Fly ash + SDA material Gasifier ash Produced, tons, tonnes 419,260 Used, Available, tons, tons, tonnes tonnes 140,334 278,926 CO2 Emissions,a Mt/yr, Mtonnes/yr 7.8 Mineralization Mineralization Potential as % Potential as % of Emissions, of Emissions, high low 0.8 1.1 122,124 493,398 148,000 17,575 390,000 0 104,549 103,398 148,000 4.6 10.0 5.5 0.3 0.1 0.3 1.0 0.4 1.2 34,810 0 34,810 0.5 0.9 3.1 200,000 0 200,000 3.8 1.1 1.6 454,347 0 454,347 2.8b 3.0 4.4 0.7 1.3 1,871,939 547,909 1,324,030 2010 emissions from U.S. Environmental Protection Agency (2010, 2011a). 37 35.4 Materials are the leading companies that have identified specific products or are working directly on technology primarily designed to produce products. Only Calera has provided significant detail concerning the actual products and their markets. While methods for making cement substitutes, ceramic replacements, and other higher-value products will likely be developed, the entry-level product for most mineralization companies will likely be aggregate that can be used for roads and/or as a component of concrete. There is a substantial need for aggregate in North Dakota, particularly in the Devils Lake Basin and in the Bakken–Three Forks shale oil development area. The Pennington County Highway Department in South Dakota has published bids it received for aggregate (Pennington County Highway Department, 2011a, b). The bids cover the cost of obtaining aggregate from five locations. Quotes for the work were obtained from three to six companies, depending on the location. It is not clear from the available documents if the county owns the quarry and/or pits that the material will come from, nor is it clear if the cost is only for the work of harvesting, processing, and delivering the aggregate or if the cost of the material is included. Regardless, the values should supply an order of magnitude estimate of the ¾" gravel-surfacing material. The quoted prices ranged from $2.39 to $4.25/ton for material listed as coming from Howie Pit, $2.39 to 4.15/ton for material from Talty Pit, $2.39 to $4.75/ton for material from Huether Pit, $3.35 to $4.90/a ton for material from Paulsen Pit, and $4.58 to $6.75/ton for material from Benchmark Quarry. This is an overall price range of $2.39 to $6.75/ton ($2.63 to $6.75/tonne). Another source used for estimating the cost of aggregate is the February 2009 CostEstimating Guide for Road Construction published by the U.S. Department of Agriculture (2009). The report suggests that cost estimates be adjusted for local conditions. Costs are not given as the cost of the material but rather as the cost for harvesting and processing the material. One of the greater variables in cost appears to be the amount of processing required (e.g., screening and/or crushing) to produce material of the correct size. The cost in Idaho and Montana for crushing and screening ranges from $2.05/ton ($2.26/tonne) for material that only needs to be screened to $3.80/ton ($4.19/tonne) for crushed quarry rock. When all other costs are included, the total price for the crushed quarry rock is $7.18/ton ($7.91/tonne). Another use for mineralization products might be as solidifying agents for drilling waste pits formed during oil field operations. Currently, the price of fly ash sold by some coal country utilities to the oil field for this purpose is $30/ton ($33/tonne) (Donovan, 2011). This price makes the fly ash more valuable as is than as an alkalinity source for a mineralization process. The cost of applying the Calera process to produce building materials (i.e., aggregate and/or cement) for the Latrobe plant in Australia was estimated. Models showed that the process broke even if the product was sold at $13.60/short ton ($15/tonne) if local brine could be used as the source of alkalinity (Kolstad and Young, 2010). It is obvious that this cost cannot compete with the cost of gravel. 38 Cost of Electrochemically Produced Alkalinity If a source of appropriate alkalinity is not readily available to a mineralization reaction such as Calera, New Sky, or SkyMine, the alkalinity must be manufactured using an electrochemical process. This process can be energy-intensive and, therefore, fairly expensive. All methods of electrochemical generation of alkalinity are based on splitting water into hydroxyl ions and hydrogen ions or hydrogen gas. The least energy-consuming method is the use of a bipolar-based membrane for splitting water. If the bipolar membrane is used in an appropriately designed and operated system fed a solution of NaCl, the electrochemically split water can be used to produce a high-pH, high-alkalinity solution of NaOH (caustic) and low-pH, high-acidity solution of HCl. In the following calculation, all of the electricity cost is applied as the electricity cost of making the NaOH solution that can be used to capture CO2 and making NaHCO3 (sodium bicarbonate) or Na2CO3 (sodium carbonate). The calculation is idealized (i.e., provides the minimum theoretical amount of electricity required) because it is based on an assumption that the electricity is used only for splitting the water and all of the produced hydroxide is used for capturing and mineralizing CO2 as bicarbonate or carbonate solids. In any real process, there will be losses and inefficiencies that will decrease the yield of mineralized CO2 derived from use of the electricity. The minimum electrical potential needed to split water using a bipolar membrane is 0.83 volts (Fumatech, 2011). This required electrical potential works out to a theoretical minimum energy consumption of 22 Wh/mol of H2O split into H+ and OH- ions and separated to different sides of the bipolar membrane. The electrical potential and energy consumption values for the electrolytic production of NaOH are 1.23 volts and 55 Wh/mol of H2O split, respectively. Reacting NaOH with CO2 can yield 0.5 mol of Na2CO3 per mol of NaOH or 1.0 mol of NaHCO3 per mol of NaOH, so under ideal conditions, the minimum electrical energy cost of producing alkalinity for mineralizing CO2 to NaHCO3 is 22 Wh/mol of CO2. For mineralization to Na2CO3, the minimum is 44 Wh/mol of CO2. Eisaman and coworkers (2011) performed experiments using a bipolar-based electrochemical cell for the purpose of capturing CO2 as solutions of potassium bicarbonate or potassium carbonate. The results showed slightly higher electrical use than the minimum values calculated above, with electrical energy requirement values between 28 and 61 Wh/mol of CO2 for capture as KHCO3 and 60 to 127 Wh/mol of CO2 as K2CO3. Table 7 shows the calculated cost of the electricity in $/tonne of CO2 mineralized for the production of mineral bicarbonates or mineral carbonates as a function of the cost of electricity and the process used. 39 Table 7. Electricity Cost for Alkalinity Generation for Mineralization of CO2 Theoretical Minimum Theoretical Minimum Bipolar Membrane-Based for Bipolar Membrane- for Electrolytic-Based Experimental Work of Based Process Process Eisaman et al. (2011) Cost of NaHCO3, Na2CO3, NaHCO3, Na2CO3, KHCO3, K2CO3, Electricity, $/tonne $/tonne $/tonne $/tonne $/tonne $/tonne $/kWh CO2 CO2 CO2 CO2 CO2 CO2 0.05 25 50 62.5 125 31.57 63.13 0.1 50 100 125 250 63.13 126.26 0.15 75 150 187.5 375 94.70 189.39 Kolstad and Young (2010) estimate that a price of $22.68/ton ($25/tonne) for aggregate and/or cement would be sufficient to cover the cost of the Calera process if its proprietary echem method to electrochemically produce alkalinity were employed. It is uncertain if the brine available in the vicinity of North Dakota power plants could serve as an appropriate source of alkalinity. It should, therefore, be assumed that the sales price of any aggregate produced might need to be as high as $22.68/short ton ($25/tonne), which would not compete well with the cost of gravel aggregate. Chemical Manufacturing Chemical Conversion Processes Many approaches are being developed to utilize CO2 captured from various sources to produce useful fuels and chemical feedstocks. Energy production from carbonaceous fuels involves exothermic oxidation reactions that yield CO2, water, and heat. Since CO2 is fully oxidized, it must be converted back to a reduced state in order to produce fuel compounds from it. CO2 can be used to make other useful chemicals as well via direct conversion or transformation. Conversion of CO2 to either chemicals or fuels requires a net energy input, which must come from renewable energy sources such as wind or solar if the process is to avoid yielding additional CO2 emissions. In many instances, highly selective catalysts are also required in order to obtain efficient conversion. A majority of the chemicals produced from CO2 are useful intermediate compounds (e.g., organic carbonates, carbamates, and low-molecular-weight organic acids and esters) that are, in turn, used to manufacture desired end products, such as polymers. Figure 15 gives an overview of the CO2 utilization avenues that are currently being pursued. The addition of a chemical conversion process could produce value-added products with the ability to offset some of the costs of the implementation of CCS. Unfortunately, the current status of development is limited to laboratory- or pilot-scale technologies that have the potential to be scaled up for more rigorous technical and economic evaluation. Continuous development of reactor technology and new active and selective catalysts will need to be developed if chemical conversion is to play a role in reducing CO2 emissions at the commercial scale. 40 Figure 15. Schematic showing various chemicals that can be made from CO2 (Styring et al., 2011). Thermodynamic Considerations for CO2 Conversion Because CO2 is fully oxidized and is a nonpolar molecule, it is electronically less reactive and is thermodynamically a very stable compound. Highly reactive metal-based catalysts, mostly transition metal compounds of Ni, Fe, Ti, Zr, Ru, Rh, etc., and a few nontransition metals such as Mg, Ag, Zn, and Cu, are required to facilitate the reactions. The extreme thermodynamic stability of CO2 lends itself to a high energy penalty in the process of converting CO2 to useful chemicals and plays a key role in determining whether such a conversion process would be economically feasible. Many CO2 conversion reactions proceed with a positive change in enthalpy (i.e., they are endothermic); hence, a sizable energy input, appropriate reaction conditions, and highly reactive metal catalysts are required for CO2 conversion into useful chemical products (Song, 2006). The key chemical reactions for reforming CH4 using either steam or CO2 are shown in Reactions 1 and 2, respectively. Both reactions are endothermic and require over 200 kJ of energy input per mol of CH4, but CO2 reforming requires an input of about 20% more energy than does steam reforming. Although the two reactions result in synthesis gas products having different H2/CO molar ratios, both are useful for certain applications. Steam reforming is already used at a large scale in the gas and fertilizer industries worldwide. Even though the thermodynamics of this process are unfavorable, it is implemented when the economic incentives for doing so are sufficient. Several other large-scale industrial processes have a similar net positive enthalpy change for the relevant chemical reactions, including pyrolysis or thermal 41 cracking of hydrocarbons for manufacture of ethylene and propylene, manufacture of petrochemicals such as styrene from ethylbenzene by dehydrogenation, and steam reforming of hydrocarbons to produce syngas. Strong economic incentives, coupled with the possibility of using waste heat in a power plant to offset some of the energy demands, make this approach a potentially valuable option as a CO2 utilization technology. CH g H O g → CO g 3H g ∆H 206.3kJ/mol [Eq. 1] CH g CO g → 2CO g 2H g ∆H 247.3kJ/mol [Eq. 2] Reduction of CO2 to Fuels and Other Chemicals Reduction of CO2 is a chemical transformation of the oxidized carbon to a reduced state with input of energy from chemical, photochemical, electrochemical, and/or biological processes. This transformation incorporates the CO2 into an organic compound such as a fuel or chemical (e.g., methane, carbon monoxide, methanol, or ethanol). All of these processes require energy to form at least one carbon–carbon or carbon–hydrogen bond. When a fuel made from reduced CO2 is used to provide the energy for the reduction process, more energy is required to make the fuel or other product than is present in the product. Therefore, the process is only feasible with regard to energy if the reduced carbon product is of high value, the fuel is effectively an energy storage product made from an intermittent energy supply source (e.g., wind, solar), and/or the fuel produced is useful in ways that the original source fuel was not (e.g., production of a transportation fuel from coal-derived CO2). The status of CO2 reduction to fuels is currently limited to research and development (R&D) studies mostly in academic laboratories. The compounds most widely investigated include formic acid and formic acid esters, formamide, and methanol (Omae, 2006). Both heterogeneous and homogeneous metal-based catalysts have been employed in supercritical CO2 solutions. The application of heterogeneous catalysts can offer several technical advantages, including stability, separation, handling and reuse of the catalysts, and ease of reactor design. Despite these beneficial practical features, the range of compounds that have been synthesized from CO2 by heterogeneous catalysis is still relatively small (Baiker, 2000). Most of the studies currently reported have been carried out mainly with homogeneous catalysts of Ru and Rh, which have shown high turnover numbers in supercritical CO2 solutions. Attempts to produce chemicals via reduction of CO2 have been limited; the few products obtained include mostly CH4, CO, methanol, and ethanol. Current efforts in the production of these chemicals are described as follows. Reduction of CO2 to Hydrocarbons and CO The reaction that has been explored the most in the production of fuels is hydrogenation using supercritical CO2 solutions. Omae (2006) investigated the reduction of CO2 to CO, CH4, and some higher hydrocarbons. The production of CO is essentially the reverse water–gas shift reaction, which produces water as a coproduct, while CH4 and occasionally higher hydrocarbons are obtained from prolonged hydrogenation of CO2 beyond formic acid, formaldehyde, and CO. Although the thermodynamics of producing CO and CH4 from supercritical CO2 (sc-CO2) 42 solution have been reported as either neutral or favorable because of the production of liquid water from hydrogen, the economics are unfavorable for the same reason expensive H2 is being converted to water (Jessop et al., 2005). Reduction of CO2 to Methanol and Ethanol There are also studies that have attempted to produce methanol from the hydrogenation of CO2 in a sc-CO2 solution in the presence of a suitable catalyst. The preparation of methanol has been reported on a laboratory scale using a Cu–Zn–Cr–Al–Pd catalyst at 480°F (250°C) and under 735 psi (5 MPa) pressure; a CO2 conversion of about 21.2% was achieved (Soma and Fujiwara, 1992; Inui and Takeguchi, 1991). Ethanol has also been prepared in 44.4% conversion of CO2, with about 20% ethanol selectivity using a K/Cu–Zn–Fe catalyst at 570°F (300°C) and under 1000 psi (7 MPa) pressure (Arakawa and Okamoto, 1994; Okamoto et al., 1994; Higuchi and Takagawa, 1988). In all of these studies, the catalyst activity and lifespan have been key limiting factors. However, a high-selectivity and long-life catalyst for manufacturing methanol from CO2 has been reported based on a study at a 50-kg/day methanol plant in Japan (Watanabe, 2000; Kubota et al., 2001; Wu et al., 1998). The catalyst used in this study is a Cu/Zn-based multicomponent catalyst (Cu–ZnO–ZrO2–Al2O3–SiO2), and the reaction was carried out at 482°F (250°C) at 735 psi (5 MPa) pressure. The selectivity of methanol was more than 99.8 mol%, and the catalyst life exceeded 1 year. Direct Conversion of CO2 to Chemicals The direct conversion of CO2 into chemicals has been used in the industry both to produce some major products such as urea and urea–ammonium nitrate and prepare useful intermediate compounds that allow subsequent production of major end-use products. Virtually all of these direct conversions react CO2 with compounds that are normally produced using processes which generated CO2 from a fossil fuel-derived feedstock. This means that most companies performing these processes will not use externally supplied CO2 but will use CO2 obtained from some earlier step in the process used to make the intermediate which reacts with CO2. Additionally, most of these processes or the upstream processes used to generate the reactive intermediates require reaction conditions such as high pressure and/or high temperature. Typically, fossil fuel combustion is used to provide the heat and power required to meet these needs. In a carbonconstrained world, the industry will likely be required to capture at least a portion of these emissions or pay a tax or fine or purchase emission credits. Under those conditions, it is unlikely that the industry will purchase externally supplied CO2 rather than capture and use CO2 produced on-site. Some of the currently reported chemical compounds are described as follows. Organic Acids and Esters Formic acid, formic acid esters, and formamides have been produced from CO2 by hydrogenation in the presence of a suitable catalyst. 43 Salicylic Acid and Aspirin The pharmaceutical industry makes salicylic acid from the reaction of CO2 and phenol. The salicylic acid is subsequently used as the main precursor for the manufacture of aspirin. Organic Carbonates Carbonic acid esters are important intermediate chemicals derived from CO2 that are used as the raw materials for the manufacture of polycarbonates (PCs) or isocyanates, alkyl agents, solvents, and fuel additives. These are synthesized by the reaction of sc-CO2 with alcohols in the presence of catalysts. The process has been shown in laboratory studies to have high product selectivity in 50% CO2 conversions (Omae, 2006). CO2 has also been shown to react with cyclic oxiranes to produce propylene carbonates in excellent yields (~93%) and high selectivities (~99%) (He et al., 2003). This reaction system also shows a prominent feature: the propylene carbonate spontaneously separates out of the sc-CO2 phase. The practical implication of this is that the catalyst could be recycled while maintaining a high CO2 pressure and temperature by separating the propylene carbonate from the bottom of the reactor, followed by supplying the reactants (propylene oxide and CO2) to the upper sc-CO2 phase containing the catalyst. The engineering design of such a process would thus be simplified greatly. Polymers Polymerization involving CO2 is one of the most important uses of CO2 that is already being applied at the commercial scale in the manufacture of polycarbonate polymers without using phosgene, as well as in the alternating copolymerization process with epoxides. Other important polymerization processes include condensation with benzenedimethanol and alternating copolymerization with diynes. Alternating copolymerization is a particularly attractive process because it produces copolymers that are biodegradable and have high oxygen permeability. Consequently, this polymer has been investigated by the pharmaceuticals industry for an application of sustained-release drugs (Nakano and Gosei, 1984). Sugimoto et al. (2003) have reported the first successful demonstration of an alternating polycarbonate polymer made from reacting CO2 with cyclohexene oxide at a modest pressure of 14.7 psi (1 atm), compared to other sc-CO2 conditions that operate at pressures of more than 2940 psi (200 atm). Additional details were investigated concerning the potential for use of externally sourced CO2 for polycarbonate plastics production because DOE is sponsoring work in this area and there was the perception that it might be possible to combine resources (i.e., ethane and propane) from the natural gas industry in North Dakota with CO2 from the power industry in order to develop a polycarbonate plastics production industry that would provide for beneficial use of CO2 from coal-fired power plants. The analysis performed concluded that there is almost no potential that externally sourced CO2 would be needed for production of polycarbonate plastics. A summary of the details of that analysis are provided here. 44 Since 2002, Asahi Chemical Industry has been commercially producing polycarbonate at 50,000 tons/year using an “environmentally benign” process that uses CO2 and does not use phosgene and methylene chloride (Fukuoka and Kawamura, 2004; Takeuchi et al 2004; Fukuoka et al., 2003). GE Plastics and Bayer use similar processes in much smaller facilities (Nexant, 2003). Omae (2006) provides a detailed description of the chemical synthesis steps of Asahi’s process. The raw materials are CO2, ethylene oxide, and bisphenol-A, and the products are polycarbonate and ethylene glycol, methanol, and dichloromethane. A significant amount of the carbon comes from bisphenol-A and ethylene oxide, but the process uses CO2 and it decreases CO2 emissions for polycarbonate production by 17.3% (Omae, 2006) as compared to polycarbonate production using the traditional phosgene and dichloromethane-based process. Others groups have been working to improve on the Asahi process through the use of other catalysts and by eliminating the use of the bisphenol-A. The goals are production of polycarbonate plastics that contain up to 50% of their mass sourced from CO2. One of those groups is a joint project involving Novomer Inc., Albemarle Corporation, and the Eastman Kodak Company and funded as part of DOE’s American Reinvestment and Recovery Act – Industrial Sources into Useful Products Program (U.S. Department of Energy National Energy Technology Laboratory, 2010). The goal is to develop a process to convert waste CO2 into a number of plastics for use in the packaging industry. It is based on use of Novomer’s novel catalyst technology that reacts CO2 with petrochemical epoxides, creating a family of thermoplastic polymers that comprise up to 50 wt% CO2. As shown in Figure 16, the Novomer process requires input of CO2 and ethylene oxide or propylene oxide. The key to the potential need for externally sourced CO2 will be the carbon balance associated with ethylene oxide (EO) and propylene oxide (PO) production. Figure 16. Novomer polycarbonate production (Novomer, 2011). 45 EO is produced from ethylene, which is primarily produced from ethane (similarly, PO is produced from propylene, which is produced from propane). Ethylene is produced by steamcracking ethane. Total energy and process emissions of CO2 for ethylene production from ethane is 1 ton CO2/ton of ethylene produced (Tallman, 2009). EO is produced by direct oxidation of ethylene with air or oxygen (oxygen is preferred). This process results in the loss of 20‒25 mol% of the ethylene to carbon dioxide and water. Together, these suggest more process CO2 will result from making EO than can be incorporated into the product, even at the maximum target of 50% of polycarbonate mass coming from CO2. In addition to this process CO2, the facility performing the process will certainly have CO2 generated from fuel consumed to supply heat and pressure for the energy-intensive ethane-to-ethylene and ethylene-to-ethylene oxide steps. It should be expected that in a carbon-constrained economy, the company will capture its own CO2. Therefore, there appears to be little potential demand for an external CO2 source for the production of polycarbonates. Urethanes and Polyurethanes Urethanes belong to the class of organic compounds called carbamates. Derivatives of urethanes, otherwise known as carbamic acid esters, constitute important precursors of pharmaceuticals, herbicides, fungicides, and pesticides in the agricultural field and as the precursors of isocyanides, which in turn, are intermediates in the production of high-performance plastics, polyurethanes, elastomers, and adhesives (Dell’Amico et al., 2003). Urethanes are synthesized by reactions of the CO2–amine mixture with organic compounds such as organic halides, alcohols, organic carbonates, acetylenes, olefins, epoxides, and organometallic compounds (Omae, 2006). Cyclic carbamates, which are frequently employed as fragments in biologically active materials for pharmaceutical and agricultural uses, are prepared slightly differently by carbonylation of amino alcohols using phosgene or by oxidative carbonylation using CO (Dinsmore and Mercer, 2004). Urea and Polyurea Urea is an important N-containing chemical that can be quantitatively derived from CO2. The largest share of the estimated 100 million tons/yr of global production is consumed by the agriculture industry as a source of nitrogen in fertilizers (International Fertilizer Industry Association, 2004). The second largest application is in the polycondensate industry (Ludanyi and Kem, 1999). An interesting and, perhaps, environmentally friendly application of urea suggested by some researchers is to use it as a deicer on the streets during winter instead of applying corrosive and environmentally unfriendly compounds such as NaCl or CaCl2 (Caglioti et al., 2009), which may find some traction in North Dakota and neighboring states. Urea is made primarily by reacting ammonia with CO2 to yield ammonium carbamate, which is then dehydrated to urea with about 50%–80% CO2 conversion, while polyureas can be prepared under mild conditions in high yields by the direct polycondensation of CO2 with diamines in the presence of diethyl N-acetyl-N-methylphosphoramidites or its analogs containing P–N bonds (Rokicki, 1988). Urea and derivative products such urea ammonium nitrate (UAN) are often used commercially as a source of nitrogen in fertilizers. The technology for making nitrogen-rich fertilizers is available commercially as there are many urea plants around the world 46 producing some 100 million tons/yr. The industrial manufacture of nitrogen-rich fertilizers is discussed in more detail in the section for commercially available CO2 utilization technologies. Additional details were investigated concerning the potential to use externally sourced CO2 for urea production. There was the perception that it might be possible to combine the production of anhydrous ammonia from methane from the natural gas industry in North Dakota with CO2 from the power industry to develop urea production capacity in North Dakota. The analysis performed concluded that there is almost no potential that externally sourced CO2 would be needed for production of urea. A summary of the details of that analysis are provided here. The current worldwide production of urea, (NH2)2CO, is approximately 100 million tons/year, which is the equivalent of 73.3 million tons of CO2/year. Because global urea production is so high and the use of anhydrous ammonia presents transportation, safety, and security challenges, it looks at first glance as if urea production is a promising outlet for captured CO2. Unfortunately, a closer look at the ammonia production process reveals that enough CO2 is produced at ammonia plants to allow them to be self-sufficient with respect to CO2, even when that ammonia plant uses methane from natural gas, the lowest-carbon fossil fuel, as the source of hydrogen and as the fuel for providing heat and power at the ammonia plant. Therefore, urea production is unlikely to use CO2 sourced from a lignite-fired facility, except in two situations: Wind- or solar power-based ammonia production. Conversion of ammonia derived from gasification of lignite. Dakota Gasification Company might consider converting ammonia it produces to urea using the CO2 it captures. Conversion of NH3 to urea directly consumes CO2 according to Equation 3: N2 + CH4 + ½ O2 → (NH2)2CO (simplified equation) [Eq. 3] Theoretically, CO2 produced from methane meets the urea CO2 demand, although losses preclude this from happening. Some beneficial-use-of-CO2 documents list CO2 use when making urea as a potential benefit. Unfortunately, it is not likely that any ammonia producer will buy CO2 from another source in order to produce urea because ammonia producers emit excess CO2, even if producing CO2 from methane (fuel and feedstock). Ammonia plants also require heat and power, thereby producing fuel-derived CO2 in excess of that needed for urea production. Urea manufacturers will most likely capture their own CO2 for use rather than buy CO2 from another source. This is actually happening globally. Almost all of the full-scale commercial MHI KS1 CO2 capture plants are capturing CO2 from natural gas combustion at fertilizer plants where the capture of CO2 is used for urea production. MHI currently has nine commercial postcombustion capture plants in operation, all of which capture CO2 from natural gas combustion. Table 8 summarizes these capture plants, including the year of initial operation, country, size (tonnes/day), and CO2 use target. The following text describes the MHI Kansai-Mitsubishi carbon dioxide recovery (KM CDR) process in more detail. 47 Table 8. MHI Postcombustion CO2 Capture Initial Operations Year Location Size, tonnes/day CO2 Use 1999 Kedah, Malaysia 200 Urea production 2005 Fukuoka, Japan 330 General use, food grade 2006 Aonla, India 450 Urea production 2006 Phulpur, India 450 Urea production 2009 Kakinada, India 450 Urea production 2009 Bahrain 450 Urea and methanol production 2010 Abu Dhabi, UAE1 400 Urea production 2010 Phu My, Vietnam 240 Urea production 2011 Ghotoki, Pakistan 340 Urea production 2012 Vijaipur, India 450 Urea production 1 United Arab Emirates. The KM CDR process offered by MHI is an intercooled absorber–thermal desorption stripper (steam-fed reboiler) CO2 capture process that uses the sterically hindered amine KS-1. The process flow diagram is very similar to that for any other absorber–stripper process. The hindered amine chemical absorbent KS-1 is reported to have a molecular structure that is tailored to enhance its reactivity toward CO2. Reported benefits of the process include low-regeneration heat requirements, low solvent degradation without the use of additives or inhibitors, and low amine losses (Jansen et al., 2007). The history and capacity of MHI’s research, demonstration, and commercial plants for CO2 capture from natural gas and coal are shown in Figure 17. MHI has a significant and aggressive history with development and demonstration of large-scale CO2 capture plants. The company currently offers the KM CDR at full commercial scale, with performance guarantees for natural gas-fired power plants. MHI expects to be able to offer similar full-commercial-scale KM CDR plants with performance guarantees once it gains sufficient operational experience with largescale facilities run on coal-derived flue gas (Iijima et al., 2010). Operation of the planned facilities shown in Figure 17 would likely provide the desired operational experience necessary to allow MHI to provide performance guarantees. More detailed information on MHI’s KM CDR process is available from numerous sources (Iijima et al., 2010; Kamijo et al., 2004; Mitsubishi Heavy Industries, 2006, 2010; Mimura et al., 2000; Ronald, 2008; Ohishi et al., 2006; Yagi et al., 2006). Sodium Bicarbonate Sodium bicarbonate, also commonly known as baking soda or bicarb, is a member of the chlor-alkali family of chemicals and is prepared by reacting brine, limestone, ammonia, and CO2 in water via the Solvay process. Baking soda is usually produced commercially as a by-product of the production of soda ash, mined in the form of the ore trona, or by dissolving some of the soda ash in water and treating it with CO2 to precipitate the sodium bicarbonate from solution. Another common commercial process for producing sodium bicarbonate is by solution mining, where the bicarb is obtained from the naturally occurring ore nahcolite. In solution mining, hot 48 Figure 17. MHI CO2 capture reference plants (the yellow-circled points represent planned facilities) (taken from Iijima and others, 2010). water is pumped into a naturally occurring nahcolite basin to dissolve the ore and bring it to the surface for further purification and recrystallization. Sodium bicarbonate is produced commercially in the United States using both nahcolite and soda ash (trona) as raw materials. As of 2000, the capacity of the bicarb industry in North America was estimated at 700,000 tons, with Church & Dwight Company, Inc., leading the market with a nameplate capacity of about 480,000 tons (Capone, 2000). Church & Dwight Company still tops the bicarb market in the United States (Church & Dwight Company, 2011). According to its marketing director, the industry’s capacity in 2011 should stand at nearly 1 million tons a year (Capone, 2000). This is based on an estimated growth rate of about 4% (20,000 tons) a year. According to a study by SRI Consulting, IHS Inc. (Schlag and Funada, 2009), the major use of bicarb is in animal feed, accounting for roughly one-third of all bicarb consumption globally. China is currently the second-largest feed producer in the world and has seen a significant increase in sodium bicarbonate consumption for animal feed. The demand for specific grades of bicarb differs among the United States, Europe, and Japan. In the United States, two-thirds of domestic bicarb use is for differentiated (higher-value) grades; in Europe, less than half of total domestic use is for differentiated grades, and in Japan, just over one-third. Figure 18 shows world consumption of sodium bicarbonate in 2008 by end use. Based on estimates by SRI Consulting, the average growth in consumption of bicarb during 2008–2013 is expected to be 2.7% a year globally (Schlag and Funada, 2009). 49 Figure 18. World consumption of sodium bicarbonate in 2008 (Schlag and Funada, 2009). Sodium bicarbonate in the United States is produced commercially by six companies: four in Wyoming, one in California, and one in Colorado. Collectively, they produce over 14 million tons of soda ash annually. The Colorado-based company, Natural Soda, Inc., is focused on the production of bicarb from nahcolite by solution mining, while the other companies are major soda ash production facilities, with bicarb also produced as a by-product. Natural Soda’s operations are currently focused on what it perceives as sizable deposits of nahcolite in the Piceance Creek Basin (Natural Soda, Inc., 2011). Natural Soda’s current production capacity stands at 125,000 tons of sodium bicarbonate a year. Because this approach is based on naturally occurring deposits, the process does not need any externally sourced CO2. Hence, bicarb production by the solution-mining process is not a CO2 utilization process. The bicarb process that utilizes some CO2 is the Solvay process (SBIO Informatics, 2011). In this process, CO2 is bubbled through an ammoniated brine solution to form sodium bicarbonate under controlled conditions. The bicarb is then carefully precipitated, separated from the solution, and refined for marketing. This process is seldom practiced now owing to many modified and more efficient processes. For example, the largest trona deposit in the world is in the Green River Basin of Wyoming, and General Chemical Industrial Products has been mining it for soda ash production for several decades (General Chemical Industrial Products, 2011). General Chemical uses the monohydrate process, which involves calcining the trona ore to drive off some of the gases (predominantly CO2), dissolving the crude sodium carbonate in water to remove the insoluble impurities, and then purifying and recrystallizing the soda ash product. Although the major focus of the General Chemical process is the production of soda ash, sodium bicarbonate can also be produced in the process. 50 In the context of CO2 utilization technologies, some CO2 is generated in a commercial process when trona is calcined as well as in the ammonia synthesis process. In fact, the CO2 captured from the ammonia plant and from the trona calciners (lime gas) is pressurized and fed to a mixing column to produce sodium bicarbonate for the facilities that still use the Solvay process. Ammonium chloride and calcium chloride are typical by-products with additional market value. Given that most commercial plants do not use the Solvay process anymore and that the few that do recycle the CO2 from the ammonia plant and the calciner section of the process, sodium bicarbonate production is not likely to be a feasible option for CO2 utilization. There is no significant need for externally sourced CO2 such as from a power plant. Potential for Use of Chemical Conversion Technologies by North Dakota’s Power Plants Some of the technologies discussed in this report have the potential to require externally sourced CO2, while most of the more developed processes utilize CO2 generated in commercial facilities that has been captured. Examples of products that do not require externally sourced CO2 are urea and urea derivatives, polycarbonate-based plastics, and some pharmaceutical intermediate chemicals that are derived from natural gas or petroleum. Only reduction to fuel processes shows some potential to need externally sourced CO2. However, these technologies are still at the R&D stage and would require a substantial investment to advance to the commercial scale. Lignite-specific properties are likely to pose significant challenges to the highly sensitive, complex catalyst systems used by most of the reduction processes. Finally, the reduction processes use H2 as the reducing agent, which is expensive to obtain, potentially making the reduction technologies economically unfeasible. Photosynthesis-Based Technologies Photosynthesis-based processes using externally sourced CO2 include algae production and greenhouse agriculture. In algae production, CO2 must be supplied both as a source of carbon for growth of the algae and to control the pH of the growth media. In greenhouse agriculture, CO2 serves as the carbon source for plant growth and can provide for increased plant growth rates. CO2 supply to greenhouses is particularly important in colder climates where increasing air exchange to supply CO2 from the outside air would result in excessive heating costs. Both autotrophic growth of algae and growth of higher plants in greenhouses can use energy from sunlight via photosynthesis to reduce the carbon in CO2 to organic carbon that can be sold for food or other uses. Two main approaches are under development, including conventional microalgae conversion processes (in open ponds, raceways, or photobioreactors) and greenhouse agriculture. While the energy input for microalgae conversion processes is derived from sunlight, in greenhouse agriculture, heat, light, and CO2 are supplied to growing plants or algae in a controlled environment that facilitates natural photosynthetic reactions in the plants. The common products from this type of agriculture include flowers, specialty fruits, and vegetables. Specific projects or technologies currently being developed in this area are described herein. 51 Algae and Microalgae Background Evidence exists that algae have been harvested as a food and/or food component for as long as humans have existed. The Aztecs used algae harvested from a freshwater lake to make bread and cheeselike foods (Aztec-History.com, 2012), and archeological evidence exists that Neanderthals used algae as a food (Edwards, 2010). The modern cultivation of microalgae as a food and/or nutritional supplement traces back more than 60 years. According to Edwards (2010), a key paper summarizing previous research on the use of algae as a food for humans was published in the Journal of Nutrition in 1961. The information published in that paper helped solidify the use of algae as a food supplement but also inhibited its growth as a major food source. Today, a healthy algae growth industry exists that produces microalgae for use as a food supplement and for other specialized uses. The microalgae production industry is a small and well-developed industry which is proven to make money. This industry purchases externally sourced CO2, but the size of its markets is small relative to the amount of CO2 that is potentially available from power plants. Less than 20,000 tons/yr (18,150 tonnes/yr) of algae is produced worldwide, primarily for use as nutritional supplements ((Benemann, 2011) Some of these algae companies make products by growing the algae in fermentors where the algae are fed sugars and/or organic acids. This heterotrophic growth of algae does not require the feeding of CO2, rather it produces CO2 as a by-product of algae growth. This is important to note because algae growth this way will not require externally sourced CO2. Recently, there has been an explosion of algae start-up companies (some estimate 200+ since 2005). All of these companies are trying to reduce the costs to produce algae in order to break into potential algae product markets which promise to be much larger than the nutritional supplement market but require much less expensive algae. These larger markets include the production of biofuels, animal feeds, and fish meal replacements. Since these products have a relatively low value, production costs must be reduced 11–35 times from current commercial production costs as discussed later in this report. The capital expense (CAPEX) and operating expense (OPEX) estimates performed by start-ups are difficult to confirm since there are a variety of new processes and associated assumptions. The technical reasons that microalgae are so interesting as a biofuel feedstock is that algae and microalgae can have a much higher productivity of biomass and oil compared to terrestrial crops, can be cultivated on nonarable land, can utilize wastes for nutrients, and can grow in salty water (many species). It has been reported that 1.8 tons of CO2 is absorbed per ton of algae biomass produced (this is based on the assumption that dry algae biomass is 50% carbon and recognizing that 27.3% of the mass of CO2 is carbon) (Styring et al., 2011). These characteristics are being explored to enable the sustainable production of products such as bio-oils, chemicals, fertilizers, and fuels to replace fossil fuel-based and petrochemical products. These products range in value from $443 to $1400/ton ($488 to $1543/tonne). Current algae products (mostly for human consumption) are valued from $22,000/ton ($24,251/tonne) for 52 spirulina (purebulk.com, 2012; nuts.com, 2012) to $182,000/ton ($200,621/tonne) for Dunaliella salina for beta carotene and other vitamins/phytonutrients (ben-Amotz, 2011). Algae produced for DHA such as Life’s DHA from Martek Biosciences Corporation (Martek, 2012), is not advertised in a bulk price per ton, but the DHA extracted from Martek algae is highly valued in health products. Therefore, it is suspected that the price of the bulk algae preextraction is likely to be highly valued. The microalgae production process that has the longest track record of economically successful operation is the use of open-raceway algal ponds for the production of nutritional supplements. The economics of open-raceway pond-raised algae is well known, and while it is economically feasible for high-value products, it is not economically feasible for lower-valued products. The potential that photobioreactors (PBRs) can be developed that can operate at lower cost than open-raceway ponds is quite low because efforts at using PBRs for production of highvalue products have failed in the past because of high capital and operating costs (Benemann, 2008a, b; Weismann et al., 1988). Despite this, several companies are developing closed PBRs in order to try to increase productivity and reliability and to hopefully drive down costs. The costs of production on these newer PBRs are unknown because all start-up companies are still in the R&D phase and only state forward-looking costs of production. Conditions for Algae Cultivation There are three main options for the production of biofuels such as biodiesel and alcohols from microalgae cultivation. These are based on raceway or open-pond technology, PBR technology, and fermentation processes. Fermentation processes basically use engineered microorganisms to digest cellulosic and simple or nonreducing sugars to biofuels. Consequently, this technology does not use CO2 obtained from an external source and was not considered in the analysis in this report. PBR and raceway technologies rely on externally sourced CO2 and, hence, are eligible candidates for the purpose of this study; however, for completeness, the fermentation option has been briefly discussed. Growth of photosynthetic microalgae requires an abundance of solar radiation, a narrow range of temperatures, available water, available nutrients, and available CO2. These requirements drive the siting of algae facilities to only a few places in the United States. North Dakota is not listed among these places because of the extreme seasonality. Like all plants, algae grow and convert CO2 into organic compounds, especially sugars, using the energy from light via photosynthesis. CO2 can be supplied from high-concentration streams (i.e., already captured CO2) so that algae growth serves only as a beneficial use or through the use of low concentration streams (e.g., flue gas) so that algae growth serves as a means of capture and beneficial use. Transfer of the CO2 from the gas stream to the algae culture can occur in the raceway-pond or PBR by sparging the gas through the water column or the algae growth media, generally with the algae culture, and can be pumped from the bioreactor to an absorption tower where gas–liquid contact occurs before the media is pumped back to the bioreactor. The former requires a huge gas distribution system, especially in the case where dilute flue gas is used. This method also provides for relatively low capture rates when it is used in shallow open-raceway pond systems. Capture rates can be as low as 1%–3% during daylight 53 hours (Letvin, 2011), and no capture will occur at night. The latter requires a collection and distribution system to get the culture to and from the absorption tower but provides for much higher absorption rates (50%–70% during daylight hours) (Pedroni et al., 2001). It should be recognized that this adsorption tower method requires that the water used as the culture media have relatively high alkalinity in order to ensure sufficient absorption capacity, that some of the captured CO2 will be lost to the atmosphere from the bioreactor, and that the use of multiple, separate adsorption towers would likely be required and desirable for a very large-scale system. Use of multiple towers would limit the size required for each tower and would be helpful in inisolating different parts of a large production facility to allow for better production scheduling and to decrease the potential that problems with a culture (e.g., infection with an undesirable organism) in one section would be transmitted to other sections. The desirable pH range for growth of most cultured algal species is between 7 and 9 (Richmond, 2004). Complete culture collapse because of the disruption of many cellular processes can result from a failure to maintain an acceptable pH. In the case of high-density algal culture, the pH can increase rapidly during sunlight hours (to pH 10 or higher) as algae utilize dissolved CO2. Addition of CO2 to the culture is required in order to maintain optimal pH levels. At night, the culture undergoes respiration rather than photosynthesis. This produces CO2 which tends to lead to decreasing pH values. Therefore, CO2 addition is not required or desirable at night. Furthermore, while during the daylight hours the algal culture produces oxygen which must be vented, it requires a supply of oxygen at night when light is not available. This venting of O2 and supply of O2 is not a problem for open-pond systems but must be considered in the design and operation of PBRs. Light intensity plays an important role. Growth increases can be achieved with increases in light intensity up to fairly high values. Light saturation level will depend on the culture, the culture density, and the depth of the culture. At greater depths and cell concentrations, the light is not intense enough to support growth. Generally, light saturation will not be an issue and light availability will be a significant limiting factor on production rate. Light may be supplied as natural sunlight or it can be supplied through the use of electric lamps. However, if the goal of the process is to capture CO2, the use of electric lamps will negate the benefit unless the electricity is sourced from a zero-carbon generation source. It will always take much more energy to produce the algae biomass than can be captured as chemical energy in the biomass. Lamps should not be considered for any low-value products such as fuel or animal feeds but could be beneficial for use as supplemental lighting for production of very high value products (similar to using supplemental lighting in greenhouse agriculture). Another issue which must be considered, especially for PBR systems, is that overheating of the culture can occur. Even with open-raceway pond systems the heat input from solar radiation can exceed the loss of heat by evaporation. This can be a major issue in the summer months. Mixing is necessary to prevent sedimentation of the algae to ensure that all cells of the population are equally exposed to the light and nutrients and to avoid thermal stratification. Mixing is generally accomplished by the use of paddle wheel mixers in open-raceway ponds or by sparging in ponds and PBRs. It is common for the air sparged or bubbled through the culture 54 to be supplemented with CO2. Sparging is used in Raceway ponds for CO2 supplementation, especially when growing very dense cultures. Typically, the CO2 concentration of the supplemented air is increased to between 1% and 1.5% to provide for appropriate pH control, but higher or lower concentrations can be used (Letvin, 2011; Richmond, 2004). The optimal concentration of CO2 to use for pH control will depend on culture activity, the alkalinity of the culture media, and the desired pH. For typical open systems, much of the CO2 delivered in this manner is not captured into algae biomass but is lost to the atmosphere (some companies are working on ways to get higher capture rates). Mixing power is a huge cost to most operations. If sparging is used to mix, then the CO2 uptake rate suffers. If mechanical mixing is used, the power to move water around acres of ponds or reactors or pump culture to an absorption tower can be very expensive. The optimal temperature for most microalgae cultures is generally between 64° and 82°F (18° and 28°C), although this may vary with the species cultured (Richmond, 2004). Temperatures lower than 60°F (16°C) will generally slow down growth, whereas those higher than 91°F (33°C) are often lethal for most species. With all of the thousands of known species of microalgae, these ranges obviously vary over a wide range. The ranges listed are general to most mass-cultured species and species of interest to fuel production. Heating is generally not required because algae growth is typically performed in warm environments and/or the source of light supplied adequate heating. This would not likely be true if algae growth associated with CO2 capture were to be attempted in North Dakota. Supplemental heating would likely be desired in order to extend the growth season. Cooling of algae cultures can be performed by allowing for evaporative cooling or through the use of refrigeration. The energy and/or water use expense can be a significant operating cost. Marine phytoplankton is extremely tolerant to changes in salinity. The best algae-growing conditions for most species are at a salinity level that is slightly lower than that of their native habitat. For algae growth in regions where seawater is readily available, it is common to use seawater diluted with some freshwater in order to obtain optimal salinities of 20–24 g/L (Richmond, 2004). Again, these ranges vary greatly with species. However, for inland environments, this means that saline waters that cannot be used as potable water or for agriculture can be used as a source of water for algae cultivation. This suggests that the Dakota aquifer, a regional saline aquifer, could serve as a water supply for algae cultivation operations if they were to be built in North Dakota. Nutrients are a large cost for algae production (Richmond, 2004; ben-Amotz, 2008, 2011). Several companies are attempting to use waste nutrients in the form of sewage or animal wastes. These approaches may work for production of algae-based fuel but are not likely to be permissible if the algae production system is used to produce any type of feed or food because of concerns associated with potential contamination by pathogenic microbes. Additional concerns that can limit the potential of this approach even for fuel production systems include contamination with organisms that are not human or animal pathogens but that disrupt growth of the target organism, issues with material handling, nutrient quality and consistency, and potential for chemical contamination. Careful selection and management of the waste stream can be performed in order to control these problems, but companies attempting to do this are finding 55 that monitoring to prevent these problems and taking steps to resolve them when they occur are proving to be very expensive. Algae Cultivation Companies Using Externally Sourced CO2 Current estimates are that there may be over 200 algae start-ups in the world at various stages that are researching systems and methods to grow algae and economically produce less expensive products such as biofuels. Most of these companies are very small, with only a few employees. Some however, have laboratory or pilot demonstration facilities. A few of the more prominent companies that are profitable are discussed as follows as well as a few examples of algae companies that have used flue gas CO2 in their process. Cyanotech Corporation – Kona, Hawaii Cyanotech Corporation (Cyanotech Corporation, 2012) is a profitable algae production company which makes nutritional supplements and uses flue gas to supply CO2 to its process. The CO2 is obtained from a combined heat and power (CHP) fuel oil/diesel generator system (Figure 19) that the company operates to provide heat for drying its product and electricity to run its process. The CO2 is captured into the algae growth medium using a flue gas CO2 scrubber (Figure 20). The growth media containing the captured CO2 is delivered to open-raceway ponds used for algal growth. The raceway ponds serviced by the CO2 scrubber are used to grow spirulina. CO2 is supplied for growth of the algae by contacting the growth medium with flue gas containing about 8% CO2 (roughly equal to 414 lb/hr, or 188 kg/hr, CO2) in an absorption tower. According to Pedroni et al. (2001), a CO2 capture efficiency of 75% is achieved for a capture rate of 67 tons of CO2/month (61 tonnes/mo). This amount of CO2 is used to grow approximately 32 tons/month (32 tonnes/mo) of spirulina in approximately 80 ac (32 ha) of algal ponds (Pedroni et al., 2001). It is unknown what the typical percent of the generated CO2 is captured into the algal product. If the capture efficiency in the adsorption tower is 75%, then 112 tons/month of CO2 is generated which equals about 30.5 tons/month as carbon. If the 32 tons/month of spirulina produced is assumed to be 50% carbon, that makes 16 tons/month of carbon in the product. This provides an estimated 52% capture of flue gas carbon into the algae product. The major products of Cyanotech Corporation are BioAstin® and Spirulina Pacifica®. Natural Astaxanthin (from BioAstin) is produced from the growth of Haematococcus pluvialis in raceways shown at the bottom of Figure 20 (red and green ponds showing the two growth stages’ lipid production requires a similar two-step growth process). Astaxanthin is a powerful antioxidant with benefits surpassing many of the leading vitamins and beta-carotene and with indications of health benefits for joints, skin, and immune response, while Spirulina Pacifica is a nutrient-rich dietary supplement; Cyanotech’s unique strain is a vegetable-based, highly absorbable source of phytonutrients, B vitamins, gamma linolenic acid (GLA), protein, and essential amino acids. Little is known publicly about the costs of production for the algae produced by Cyanotech. 56 Figure 19. Power plant and CO2 capture tower at Cyanotech (Benemann, 2008a). Figure 20. Algae production raceways at Cyanotech (Benemann, 2008b). 57 There is some discrepancy in the literature concerning the size of the Cyanotech CHP system. Benemann (2008a) indicates the facility is 2 MWe, but greater detail in Pedroni et al. (2001) indicates the system consists of two 180-kWe fuel oil/diesel generators, with one in use and the other available as an emergency backup. Flue gas is captured into recirculated algae growth medium using a packed-bed absorption tower which contains 6.4 m (21 ft) of packing in a 2.8-m (9.2-ft)-diameter column. Using 180 kWe for the 12 ha (30 ac) of spirulina algae ponds yields ~42 ac/MWe (17 hectares/MWe). This helps indicate that the 180-kWe rather than the 2-MWe CHP system is correct because a 2-MWe system would produce far more CO2 than required. Seambiotic – Tel Aviv, Israel Seambiotic was founded in 2003 and maintains its headquarters in Tel Aviv, Israel, with research sites in Ashkelon, Israel, and China. Seambiotic has been developing a process that uses flue gases from coal-fired power stations as a source of CO2 for algae cultivation, which is used to produce mainly food additives, animal and fish feed, and biofuels (Seambiotic, 2010). Figure 21 shows a picture of the ponds (left) and a close-up shot of one of them (right) with paddle wheels. According to the company’s Web site, Seambiotic possesses unique technology for gas transfer and cleaning, command and control of its concentration in cultivation ponds, and absorption in the algae for energy-rich products. The algae “feed” comes from the supply of CO2, which is the biggest cost item in the long-term algal cultivation based on Seambiotic’s analysis. Seambiotic cultivates a few selected species of marine autotrophic microalgae with a high content of lipids and carbohydrates as Figure 21. Seambiotic microalgae cultivation ponds (Seambiotic, 2011). 58 equivalent to the production of biodiesel and bioethanol. These algae species include Nannochloropsis sp., Phaeodactylum, tricornutum, Amphora sp., Navicula sp., Dunaliella sp., Chlorococcum sp., Tetraselmis sp., and Nannochloris sp. The company currently operates pilot-scale, 1000-m2 (0.25-ac) ponds at the power plant of the Israeli Electric Corporation in Ashkelon, Israel, and is in the process of scaling up to largescale industrial algae cultivation and production. Currently, no algae biomass is for sale, and they are still in the pilot phase. Seambiotic estimates that they have to produce algae for a cost of less than $0.34/kg ($0.154/lb) for it to be economically feasible as a fuel (ben-Amotz, 2011). Portland General Electric Company (PGE) (2011) is an investor-owned utility engaged in the generation, transmission, and distribution of electricity to industrial, commercial, and residential customers in Oregon. Operating in 52 Oregon cities, PGE serves over 800,000 customers, including nearly 100,000 commercial customers, with a combined power supply of about 2766 MW from 13 power plants. With a commitment to address greenhouse gases that contribute to global climate change, the company is investigating algae technology as an option to capture and sequester CO2 from power plant flue gases. Thus PGE is among the first utilities in the United States to investigate the use of algae to capture CO2 from coal-fired power plant flue gases in a small-scale pilot study in Boardman, Oregon (Portland General Electric Company, 2011). They have partnered with BioAlgene and others in their algae research. In the pilot study, PGE and its partners investigated the growth of algae in two different environments: ambient air and with a supply of CO2 from the Boardman power plant. The results of the study showed that algae that were fed CO2 emissions grew significantly faster than algae that were exposed only to air. This is likely because of the pH control by the CO2 content of the flue gas but may also be partially because of the N content of the flue gas. The company’s literature is unclear on this subject. For the study, PGE diverted gas produced during power generation, including CO2, to an outgoing pipe in the side of the exhaust stack. After it traveled through a cooling bath, an aboveground piping system delivered the gas to three of six large tubs (see Figure 22), where the CO2 was absorbed by the algae. The other three tubs were exposed only to air. The resulting algae were skimmed from the water for harvesting into biomass. A conceptual design of the full pilot-scale demonstration facility using PBR technology is shown in Figure 23. The research at PGE appears to be in the very early stages. No biomass is being produced for sale. To prepare for a larger pilot study, PGE, in partnership with Oregon State University, proposes to conduct further research using closed-system, vertical PBRs. In the process, a method for measuring the amount of nitrous oxide consumed by algae will be developed, and the best suitable algae strains for CO2 capture purposes will be identified. Currently, PGE is helping fund research at Oregon State University to investigate different strains of algae that could be used as part of this project. 59 Figure 22. Large tubs used for PGE’s small-scale pilot algae cultivation study (Portland General Electric Company, 2011). Figure 23. Conceptual design of proposed photobioreactor at PGE’s Boardman plant (Portland General Electric Company, 2011). 60 Pond Biofuels Inc. – Ontario, Canada Pond Biofuels Inc. was founded in May 2007 and currently maintains one office in Ontario, Canada. It is a Canadian-controlled private corporation, supported by investment from the government and the private sector (MBD Energy Ltd., 2011). Pond Biofuels has designed, constructed, and is operating a large-scale process validation facility using CO2 derived from the St. Mary’s cement kiln to grow algae (MBD Energy Ltd., 2011). The system is designed to use energy from sunlight in a type of PBR (see Figure 24) and is said to be a cost-effective method for scrubbing CO2. The algae will be dried using waste heat from the cement plant and burned as fuel in the cement kilns. Alternatively, the algae could be processed into fuel for the cement company’s fleet of trucks (Pond Biofuels, Inc., 2011). According to the company’s Web site, the Pond Biofuels process uses raw, untreated smokestack flue gases from the cement kiln; hence, the process can also remove other flue gas pollutants such as NOx and SOx (MBD Energy Ltd., 2011). Pond Biofuels asserts to have a scalable, industrially deployed, algal production system, which is designed to perform process validation and seamlessly connect to any industrial CO2 emitter. The design is said to be a closed-loop continuous harvest system that consumes CO2 from existing raw stack emissions and transforms it into value-rich algal biomass. Pond Biofuels believes its approach provides the lowest-cost, highest-yield, and smallest-footprint solution. It appears that its system is still in research phase, with more research planned. Figure 24. Pond Biofuels’ algae PBRs (Pond Biofuels Inc., 2011). 61 Nature Beta Technologies Ltd. – Eilat, Israel Nature Beta Technologies Ltd. in Eilat, Israel (established in 1988) grows Dunaliella salina in highly saline water to produce beta-carotene to sell to health food markets. The dried algae are sold for about $200/kg ($91/lb) for a total annual revenue of about $14 million (benAmotz, 2011). The cost of production is $8.16/lb ($18/kg) algae (ben-Amotz, 2011). The price paid for bulk CO2 is from $551/ton ($550/ton) (ben-Amotz, 2008) to $918/ton ($833/ton) (benAmotz, 2011). At its usage rates, this equates to $150,000/yr (ben-Amotz, 2008) to $250,000/yr (ben-Amotz, 2011). Almost all of its salable algae is sent to Far East markets where it is sold as a nutritional supplement by door-to-door salespeople. Nature Beta produces about 70 tons of algae a year on more than 24 acres (10 ha) at an average growth rate of 17.8 lb/ac/yr (2 g/m2/d), as shown in Figure 25 (ben-Amotz, 2008, 2011). Earthrise® Nutritionals, LLC – Irvine, California Earthrise Nutritionals, LLC, is based in Irvine, California, and has two other branches in Thailand and China. The company was founded in 1976 to develop spirulina blue-green algae as a food resource and began cultivation in the hot desert area in southeastern California in the late 1970s. In 1982, Earthrise developed a partnership with a Japanese company, Dainippon Ink and Chemicals, Inc. (DIC), a global, diversified chemical company with a commitment to developing microalgae for food, biochemicals, and pharmaceuticals that had just begun growing spirulina in Thailand. According to the company’s Web site, the company owns one of the world’s largest spirulina farms and together with its sister company farms in Thailand and China, the DIC group is the largest spirulina producer in the world (Earthrise Nutritionals, LLC, 2011). Figure 25. Nature Beta Technologies Ltd., Eilat, Israel (Solar, 2011). 62 Earthrise operates a 108-acre (43.7 ha) algae farm in California (Figure 26) using technology from both its U.S. and Japanese affiliates. The algae are ecologically grown, i.e., in a natural environment far from the city area, in the clean, sunny California desert, and Earthrise spirulina is said to yield more nutrition per acre than any other food (Earthrise Nutritional, LLC, 2011). By growing the algae ecologically, the product is free of pesticides and herbicides, and once harvested, it is dried in a few seconds to preserve full nutritional value. Daily quality control tests are performed to ensure the quality of the product and to meet international food standards for local and international customers. Because the ponds are situated in a natural environment in open sunshine, unwanted microscopic algae also grow alongside the desired strains. Preventing weed algae from taking over the pond can be challenging, and Earthrise has designed a special pond system for removing weed algae without using toxic chemicals and thus balancing the pond ecology. Situated in a remote and sunny part of California, far from cities, highways, and airports, the air around the farm is clean, and water from the mineral-rich Colorado River is pumped through canals to large settling ponds and then through filters into the growing ponds. The 30 spirulina ponds have food-grade liners, each 5000 m2 (1.24 ac) in size and larger than a football field. Clean freshwater and nutrients are added daily to feed the algae and mixed by paddlewheels. High-purity CO2 similar to that used in carbonated drinking water is pumped directly into the ponds to keep up with the fast algae growth rate, since atmospheric CO2 cannot diffuse fast enough into the water to sustain growth. The typical growing season is from April through October, and during this period, ponds are harvested every day. In the peak summer sun, harvesting occurs 24 hours a day to keep up with the explosive growth rate with a small portion Figure 26. Earthrise spirulina ponds (Algal Aquaculture Professionals, 2012). 63 of the pond being harvested. The harvested algae is then quickly processed, dried, and sealed in special oxygen barrier containers or pressed into tablets and bottled as finished product. The two main products produced by Earthrise are Spirulina Natural® and Spirulina Gold Plus®. Microalgae Economic Studies Microalgae technology is commercial and can make a profit, but only for higher-value products for small markets (<1000 tons/yr). They are users of CO2, and in some cases, the CO2 comes from fossil fuel combustion. The real technology challenge is to decrease the cost of production in order to break into much larger markets with lower-value products. The ultimate task is to reduce production costs by more than 40 times in order to reach break-even costs for production of algae for fuel and soy meal replacement. This 40 times reduction in cost is calculated by taking the value of $443/ton ($488/tonne) for fuel and soy meal replacement from Table 9 and the most reliable commercial operating costs of $16,363/ton ($18,038/tonne) from NatureBeta Tech (ben-Amotz, 2008, 2011). Benemann (2011) provides a lowest possible cost of $5000/ton ($5,512/tonne) for Spirulina platensis production but that is a “best guess,” not a number from a company’s balance sheet, but from a forward-looking statement. While it is possible to get other values by using cost/acre, values reported in the literature and combining these with productivity in tons/acre there are so many other issues that affect these numbers that this method of calculation is not recommended. It is common for companies to report maximum production rates from operation under optimal conditions. Table 9. Commercial Algae and Production Agriculture Economics Product Algae As fuel and soy meal replacement As 100% fish meal replacement (65% protein) As beta carotene, Dunaliella salina As Spirulina sp. production Crops Canola Soybeans Gross Revenue $/ton $/ac $443 a $3,544 a,b $1,400 d $181,800 e $11,200 b,d $566,600 e $106,000 f Gross Production Costs $/ton $/ac ? ? ? $16,360 e ? 14.5 b, c $50,990 e 5.6 c, e $5,000 g $237 h $159 h $210 h $138h $217 i $206 i $177 i $161i a Based on $320/ton soy meal replacement and $150/bbl crude, 20% lipid content. At 8 tons/ac annual average from 10 g/m2/d 6-month seasonal average in North Dakota. c Algae is 50% carbon (m/m). d Prices online. e ben-Amotz (2011). f Online retail prices from Earthrise Nutritionals, USA, www.earthrise.com. g Benemann (2011). h Metzger (1999). i Metzger (2009). b 64 North Dakota CO2 Captured, tons/acre/season 14.5 b, c Many researchers estimate costs based on forward-looking assumptions and best-case data. The best-case scenarios that economists, scientists, and engineers can realistically think of often fall short of economical commercial algae production for product markets of less value such as fuels and animal feeds (Alabi et al., 2009). In preparing this report, the best-known real-world data from existing commercial algae facilities and crop production were gathered (Table 9); it is believed that the best comparisons and definition of where the commercial algae industry and technology exist today are shown. Algae, if successful in less valuable markets, will eventually reach the profit margins of commodity agriculture as seen in Table 9, not the margins that appear for special algae markets (it should be noted that costs may not reflect other costs of business such as overhead and marketing). Today, there exists a chasm that will require game-changing technology to overcome the economics of low-cost algae production. Algae Economic Summary Current knowledge seems to suggest a significant investment is required to bring algae growth technologies to full commercial demonstration for use of coal-derived CO2. One of the dilemmas is whether to develop open-raceway pond technology or closed-PBR systems. It is important to note that the latter are considered more expensive but can consume a higher percentage of the delivered CO2 and provide higher productivities and, therefore, higher CO2 utilization rates per unit of land area. The costs of production definitely need to be reduced to open up fuel and feed markets to microalgae (Table 9). Many algae processes use a significant amount of water, mostly through evaporation and evaporative cooling. This topic, while not considered in depth in this report, will undoubtedly be an issue of concern. Similarly, available and inexpensive nutrients will also be a major topic of concern both in the availability and use of potential waste nutrient sources. Microalgae Carbon Capture Status CO2 is a large cost for current commercial algae producers; some pay $500 to $833/ton for bulk CO2 (ben-Amotz, 2008; ben-Amotz, 2011). The issue for North Dakota lignite users to consider is that algae have a low annual CO2 uptake efficiency in North Dakota. This is because algae only utilize CO2 when the sun shines and when it is sufficiently warm. Night times and long winter seasons will not provide carbon capture for North Dakota utilities. The often-quoted uptake rate of 60%–70% is only for the scrubber device during high light intensity. A CO2 scrubber and storage farm would be impractical to capture night time and winter produced CO2 from North Dakota utility boilers. It is also unknown how much CO2 is released from the culture medium into the atmosphere after the culture is returned from the scrubber to the pond. Most power plants in North Dakota are located close to the coal mine, otherwise known as minemouth power plants. Because most of these plants are collocated with the mines, the large space needed for significant algae cultivation is a challenge. Most commercial algae farms today cover 20–120 acres (8–49 ha) of land, which would not be impossible to site near a North Dakota power plant. However, much more land would be required in order to capture a significant amount of CO2. Using the information above and the same assumptions as were used in Table 9 65 (89 lb/ac/d or 10 g/m2/d for 180 days), the area around each power plant to be covered in algae ponds can be calculated. 1 Mt/yr CO2 output from a power plant is equal to 2,750,000 lb CO2 (1247 tonnes/day) during a 12-hour day of sunlight (CO2 is not used at night so it would be difficult to achieve capture at night). If algae cultures can capture that CO2 at 70% without parasitic loss during a 12-hour day, then 1 Mt/yr CO2 would require 12,000 acres, or 18.8 mi2 (4856 ha), of algae ponds. North Dakota power plants would then require a radius of 1.7–7.7 miles (2.7–12.4 km) (for Heskett and Coal Creek respectively; see Table 2). This level of land development would then average an annual capture rate of 18% at best (70% capture during a ½ day over the course of a ½ year). This will likely not meet any future reduction targets unless this technology is combined with geologic sequestration for night times and winter seasons. Two main types of plant configurations are common for North Dakota coal-fired power plants: cyclone boilers with ESPs, wet FGDs, and/or fabric filters and tangential wall-fired boilers, which also typically have more or less the same types of pollution control devices. A summary of North Dakota power plant features was provided in Table 2 and the accompanying text. To use coal-derived flue gas directly in algae ponds will likely require cleaning to remove particulates and other acidic components such as HCl and SO2, which have the potential to harm some algae species. Thus plants without efficient particulate and acid gas control technologies are not likely to be suitable unless additional investment is made to clean the gas further. Facilities such as Leland Olds Units 1 and 2 and Heskett Unit 1 may not be suitable without SO2 control options. Particulate matter will not be a severe issue for North Dakota utilities because all of them have some form of particulate control. Controlled-Environment Agriculture – Greenhouses for Vegetable Production The production of many types of agricultural crops such as ornamental plants, specialty fruits, and vegetables can be performed in an economically favorable manner by using structures known as greenhouses. These controlled environments allow the producer to more accurately schedule production of agricultural products, grow plants that would not do well on open fields in that region, and/or to extend the growing season. There is a broad range in the sophistication of environmental control used in controlled-environment agriculture from relatively simple systems that involve relatively little active control to highly controlled systems where sensors and automated control systems monitor and control temperature, humidity, CO2 light, nutrient addition, and light levels. Although these intensive systems are more expensive to construct and operate they are capable of achieving much higher rates of production per unit area and can typically produce a product that has a higher market value due to better control of product quality and better production scheduling. Additionally, it is intensive greenhouse production facilities that make use of CO2 supplementation to increase plant productivity and are most applicable for use in less temperate environments. Low-technology greenhouses are very simple and are typically little more than a simple structure with sheet plastic covering. No heating system is supplied, but a fan-based ventilation system is used to provide some temperature control. Medium-technology greenhouses are more complex and typically are made with rigid plastic or glass panels. Active climate control systems 66 are used as are more advanced growing techniques, including hydroponics, and many include CO2 supplementation. High-technology greenhouses include sophisticated climate control, supplemental lighting and shading systems, and well-controlled CO2 enrichment systems. They may also include systems that minimize labor costs and maximize space use efficiency. According to Pardossi et al. (2004), the low-technology greenhouses are typically used to produce vegetables and low-value cut flowers; medium-technology greenhouses are typically used to produce out-of-season vegetables, high-value cut flowers, and ornamental plants; and high-technology greenhouses are most commonly used to produce ornamental plants and for nursery production in cold climates. The relative investment cost for building and outfitting the different types of greenhouses (1999 costs) are $2.32–$2.79/ft2 ($25–30/m2) for low-tech, $2.79– 9.29/ft2 ($30–100/m2) for medium-tech, and $9.29–18.58/ft2 ($100 to $200/m2) for high-tech facilities. The director of the closed-environment agriculture center at the University of Arizona was contacted to obtain his opinion as to the approximate cost for construction of a greenhouse for vegetable production in North Dakota. He indicated that the cost for greenhouse systems of the quality and technology level that should be considered would be in the range of $18.59–23.23/ft2 ($200–250/m2) for the construction of the facilities and their crop production components (Giacomelli, 2012). This cost assumes a generic hydroponic system. Dr. Giacomelli further stated that “the technology is available, and production would mostly depend on the solar radiation available at your location. So it can work technically, while the difficult question is whether it makes economic sense, primarily based on an available market at price points that give a reasonable return.” Table 10 illustrates the productivity increases that can be obtained through the use of the higher-technology greenhouse systems. Greenhouses in Almeria, Spain, are low-tech systems without heating, supplemental lighting, or addition of CO2; those in the Netherlands are mediumto high-technology systems that include temperature and humidity control, supplemental lighting, and the use of CO2. From the values given by Pardossi et al. (2004), it appears the cost of building the higher-tech system is about 3 times the cost of the lower-tech system. The data in Table 10 reveal productivity increases of 3.5 to 4.2 times for tomato production and 6.4 to 7.25 times for cucumber production, suggesting that the increase in productivity is greater than the increase in the initial investment cost. Obviously, this is not a complete analysis because operating costs for the higher-tech greenhouses will almost certainly also be higher than those for the low-tech greenhouses, but it is encouraging information. Table 10. Annual Productivity (kg/m2) of Various Vegetables in Low-Tech Greenhouses in Almeria, Spain, Versus Higher-Tech Greenhouses in the Netherlands (from Cantliffe and Vansickle, 2003) Almeria, Spain The Netherlands Ratio of Crop (low-tech) (medium- to high-tech) Productivity Tomato 10–12 42 3.5–4.2 Pepper 6–7 26 3.7–4.3 Cucumber 8–9 58 6.4–7.25 Snap Beans 5 32 6.4 67 CO2 supplementation of greenhouses is typically performed in one of two ways: through the purchase of purified CO2 which is metered into the greenhouse by a system that controls the concentration at a setpoint that is typically between 800 and 1200 ppm or by combustion of natural gas or propane in a similarly controlled system. Some larger systems use flue gas from the boiler or furnace which is used to heat the greenhouse. CO2 supplementation is performed even in warmer climates and in warmer months because elevated CO2 concentrations increase plant growth rates, but it is particularly important in colder environments where it also acts as an energy-saving technique by decreasing the need for ambient air exchange. The cost of CO2 supplementation of greenhouses in Ontario, Canada, was studied by Blom et al. (2002). This cost depends on the price of supplying the CO2 and the rate of application. The cost of the CO2 is primarily dependent on the source (liquid CO2, natural gas combustion, propane combustion). The application rate is primarily dependent on the type of greenhouse because the type of greenhouse influences the leakiness or air exchange rate (higher air CO2 application rates are required for less well sealed greenhouses. The two types of greenhouses considered by Blom et al. (2002) were “standard” glass greenhouses and the more energyefficient double-glazed greenhouses which can be constructed using glass or plastic panels. The CO2 supply prices used by Blom et al (2002) were Can$110 to Can$200/tonne for liquid CO2, natural gas priced at Can$0.10 to Can$0.33/m3, and propane priced at Can$0.20 to Can$0.3/L. The Canadian dollar was worth US$0.62 in January 2002, so these prices convert to US$61.87 to US$112.49/ton and US$1.75 to US$5.79/1000 cf, respectively. CO2 application rates used by Blom et al. (2002) were 44.6–53.5 lb/hr/acre (0.5–0.6 kg CO2/hr/100 m2) for “standard” glass greenhouses and 22.3–31.2 lb/hr/acre (0.25–0.35 kg CO2/hr/100 m2) for double-glazed greenhouses. The authors report that approximately 10.7– 21.4 lb/hr/acre (0.12 to 0.24 kg CO2/hr/100 m2) of CO2 applied is used for plant growth and the rest is lost to air exchange. The values suggest that standard glass greenhouses may be able to provide for capture of 24% to 40% of the supplemented CO2 and double-glazed greenhouses may be able to provide for capture rates of 48% to 69%. Using the cost and CO2 supply rates stated above, Blom et al. (2004) calculated the range of costs for supplying CO2 as follows: Liquid CO2 supply cost was found to be Can$66 to Can$120/ha/day. Natural gas-based CO2 supply cost was found to be Can$33 to Can$100/ha/day. Propane-based CO2 supply cost was found to be Can$67 to Can$100/ha/day. Thus given that 1 hectare is equivalent to 10,000 m2, liquid CO2 supply at Can$66/ha/day is approximately equal to Can$0.66/m2-day or Can$2.41/m2-year at a liquid CO2 price of Can$110/tonne. Based on Can$0.77 to US$1, this equals US$20.57/acre/day. The use of 0.25 kg CO2/hr/100 m2 corresponds to approximately 0.135 mi2 of greenhouse/MW of power generation from lignite coal, based on an emission rate of 8500 tons CO2/year/MW. The CO2 application rate of 0.25 kg CO2/hr/100 m2 of greenhouse is equivalent to 21.9 kg CO2/ m2-yr of CO2, or 97.7 tons CO2/acre-yr . 68 Greenhouse Agriculture Around the World The total estimated world greenhouse vegetable production area is 405,841 ha (1,002,820 acres) (Hickman, 2012). This is a best estimate which includes low-tech, mediumtech, and high-tech greenhouses but attempts to remove protected agriculture that gets listed as greenhouse agriculture in some regions of the world. No statistics were found to be available regarding the use of CO2 in the supplementation greenhouses. The estimate of the area of hydroponic production is 86,500 ac (35,000 ha), but even this does not provide an estimate for how much greenhouse area involved CO2-supplemented vegetable production because hydroponic growth is often used without CO2 supplementation. The Netherlands and Canada are major locations with cold climates where mid-tech and high-tech greenhouses are common and CO2 supplementation can be considered standard practice. The Netherlands has a reported 11,300 ac (4600 ha) of vegetable-growing greenhouses, and Canada has 2854 ac (1154 ha) (Hickman, 2012). The Canadian greenhouse vegetable industry is located primarily in Ontario and British Columbia, but operations do exist in most provinces, including Alberta and Manitoba. The U.S. greenhouse vegetable production area is currently 1636 ac (662 ha), with some production reported in 25 states including North Dakota (1 ac). The vegetable greenhouse in North Dakota appears to be a passive solar greenhouse at North Star Farms in Carpio, North Dakota, approximately 25 miles northwest of Minot. How widespread the use of CO2 supplementation for greenhouse growth of vegetables is in the United States is less certain than for the Netherlands or Canada because many of the major production areas are in warmer environments where lower-tech greenhouses are more common, but the top 10 greenhouse vegetable-producing states include four northern states: New York (No. 5) with 70 ac (28 ha), Pennsylvania (No. 8) with 42 ac (17 ha), Minnesota (No. 9) with 33 ac (13 ha), and Maine (No. 10) with 30 ac (12 ha). It is likely that many of the greenhouses in these states use systems for CO2 supplementation. The Netherlands is the leading country when it comes to vegetable growth in greenhouses with CO2 supplementation and the world leader in the use of energy-efficient, high-tech greenhouses. Energy efficiency increases have been obtained by using better-insulated and sealed structures and moving to more efficient lighting (e.g., use of LEDs). The better-sealed structures require the use of CO2 supplementation and increase the efficiency of CO2 use. The Netherlands is also home to the first large-scale commercial greenhouse operation that is directly using CO2 and waste heat from an industrial source in a manner similar to the way CO2 and waste heat might be used from a North Dakota power plant. The company formed in order to develop that project is WarmCO2 in Terneuzen, the Netherlands. Warm CO2 – Terneuzen, the Netherlands WarmCO2 is a major greenhouse agriculture company in Terneuzen, the Netherlands (WarmCO2, 2011). The WarmCO2 project was developed as a joint venture between Zeeland Seaports, the port authority of Terneuzen and Flushing, and Yara, a fertilizer producer with an ammonia plant in Terneuzen, with participation by the engineering and construction firm Visser & Smit Hanab. The project integrates greenhouse agriculture with the use of industrial waste heat and CO2 from an anhydrous ammonia fertilizer production facility. The company built a set of parallel waste heat and CO2 transportation pipelines to transport these resources from the 69 ammonia plant to the site of the greenhouses and, to date, has constructed at least 60 ha of a planned 250 ha (618 ac, ~1 mi2) of greenhouse production space. According to a press release posted on the WarmCO2 Web site (WarmCO2, 2011; Rijckaert, 2009), when the greenhouse size reaches 170 ha, it will be using 1800 TJ (500,000 MWh, 57 MWth) of residual heat and 77,200 tonnes (70,000 tons) of pure CO2 every year. A yearly consumption of 70,000 tonnes of CO2 per 170 ha is roughly equivalent to a CO2 application rate of 41.2 kg/m2-year. The large facility provides spaces that are leased to growers to grow mainly tomatoes, bell peppers, and eggplants; a tomato-growing section of the facility is shown in Figure 27. Greenhouse Agriculture in Canada Canadian production of greenhouse agricultural produce is concentrated in Ontario, British Columbia, Quebec, and Alberta. Ontario and British Columbia account for 90% of Canadian production; Ontario produces 66%, and British Columbia produces 24% (British Columbia Ministry of Agriculture, 2003). The Greenhouse and Processing Crops Research Centre (GPCRC) (Ministry of Agriculture, 2011), located at Harrow, Ontario, operates the largest greenhouse (0.7 hectares, 1.7 ac) research facility in North America and manages two field sites: one on sandy soils at Harrow and a second one on clay–loam soils at the Honorable Eugene F. Whelan Experimental Farm close to Woodslee, Ontario (Greenhouse and Processing Crops Research Centre, 2011). GPCRC focuses on new technologies for producing greenhouse crops, including vegetables and ornamentals, and field-grown processing crops, including soybeans, edible beans, corn, winter wheat, and tomatoes. One of the main focuses of GPCRC is to reduce nutrient losses and greenhouse gas emissions. Many of the greenhouses are built with varying degrees of sophistication in technology, which also depends on the local weather conditions and size of the greenhouse. Larger greenhouses have sophisticated computerized climate control systems that continuously monitor and regulate temperature, light, humidity, irrigation, and nutrient levels to optimize plant growth. The most common form of heating is natural gas-fired hot-water boilers. Liquid carbon dioxide and carbon dioxide extracted from boiler flue gas condensers are used to supplement CO2 levels in the crop. Crops are grown hydroponically in soilless media (mostly in sawdust growing Figure 27. Greenhouse agriculture facility in the Netherlands (WarmCO2, 2011). 70 medium), with drip irrigation systems that provide an efficient water/nutrient supply. An image of a vegetable greenhouse in British Columbia, Canada, is shown in Figure 28. Greenhouse Agriculture in the United States The U.S. vegetable greenhouse industry is largely for the growth of tomatoes; however, imports if greenhouse-grown tomatoes exceed domestic production (Cook and Calvin, 2005). In 2003, four large firms—Eurofresh, Inc., Village Farms, Houweling Nurseries, and SunBlest (which now owns most of the former Colorado greenhouse operations)—dominated the industry, operating high-technology greenhouses and producing on a year-round basis. The ability to produce year-round has been a key strength of the U.S. industry, although strong winter competition from Mexico and summer competition from Canada remain a challenge for the profitability of the U.S industry. The issue of profitability has remained front and center for the U.S. greenhouse industry and has caused the industry to go through a period of adjustment, with firms looking for the most profitable business model. Firms have changed locations, production seasons, marketing alliances, and product lines, and most of the large firms that do their own marketing are now looking further afield to Canada and/or Mexico to acquire additional production to achieve more year-round consistency in production volumes or to expand product lines. As of 2003, U.S. greenhouse tomato growers produced an estimated 176,000 tons (159,700 tonnes) (compared to 309,000 tons, or 280,200 tonnes imported) on 330 ha of greenhouses (see Table 11) (Cook and Calvin, 2005), with production ranging from 84 to Figure 28. Greenhouse farming in British Columbia, Canada. The facility is shown on the right, and a bell pepper plant is shown on the left (British Columbia Ministry of Agriculture, 2003). 71 Table 11. Estimated U.S. Greenhouse Tomato Production and Area (Cook and Calvin, 2005) Item 1998 1999 2000 2001 2002 2003 Total Production, tons 117,500 143,000 136,500 145,500 165,250 176,000 (tonnes) (106,600) (129,725) (123,825) (132,000) (149,900) (159,650) Total Area, acres (ha) 635 761 739 726 766 815 (257) (308) (299) (294) (310) (330) Large Firms with 410 519 489 477 462 502 42+acre (17+ ha), (166) (210) (198) (193) (187) (203) acre (ha) Medium-Sized Firms 40 74 57 57 111 121 with 7–40 acre (3–16 (16) (30) (23) (23) (45) (49) ha), acre (ha) Small-Sized Firms with 188 166 193 193 193 193 < 7 acre (<3 ha), (76) (67) (78) (78) (78) (78) acre (ha) 166 ac (34 to 67 ha) by each of the four major firms, a small number of medium-sized greenhouses ranging from 7.4 to 39.5 ac (3 to 16 ha) each, and a large number of very small greenhouses. The four major firms operate greenhouses in different parts of the country. In 2003, Village Farms had a total of 130 ac (53 ha) in Marfa and Ft. Davis, Texas, and in Ringgold, Pennsylvania. Eurofresh had 67 ha in Willcox and Snowflake, Arizona. SunBlest operated 79 ac (32 ha) in Colorado and a 42-ac (17-ha) greenhouse in Virginia, and Houweling operated an 84-ac (34-ha) greenhouse in coastal Oxnard, California. Eurofresh was started by Dutch greenhouse growers and investors, and Houweling Nurseries is owned by a Canadian greenhouse grower. Three of the four major firms grow and market their own production, while Houweling markets through firms located in British Columbia. A group of seven medium-sized firms are located throughout the United States, i.e., two firms in New York and one each in Minnesota, Nebraska, New Mexico, Arizona, and Nevada, with a combined production area of about 49 ha. Some of these firms market their own production in local or regional markets and some sell via larger U.S. and Canadian marketers. Many other small greenhouse growers, with a total estimated production area of 190 acres (78 ha), are assumed to be spread throughout the United States and accounted for about 22% of greenhouse tomato production in 2002 (Cook and Calvin, 2005). These small producers usually concentrate on local sales to farmers’ markets and retailers interested in offering local produce to their customers. Because of the focus on local sales, these small growers can harvest at a very ripe stage and still get their tomatoes to market at their peak. Very little is known about these small greenhouse growers. The technology used in greenhouses by the medium- and large-sized U.S. firms is the same as that used in the Netherlands and British Columbia, i.e., glass greenhouses with active climate control and hydroponics. Although some of the earliest Colorado greenhouse operations were plastic, they are no longer in tomato production and have given way to glass greenhouses, which have an advantage when trying to maximize winter sun reaching the plants and controlling the 72 environment if it is necessary to cool in the summer. Average yields for the large firms are typically high, 238 tons/ac (534 tonnes/ha), with top yields reaching about 312 tons/acre (700 tonnes/ha). Small-sized greenhouses use a range of technologies, with some using low- or medium-technology greenhouses. All early greenhouses were cogeneration operations collocated with and, in fact, owned by power plants. Such power plants could gain exemptions from some federal regulations by producing heat to be used in another business activity such as greenhouse production, and the greenhouses received heat at a lower cost than available from other sources. The power plants that owned the greenhouse then leased it to the greenhouse operators or growers. As a result, the locations were not necessarily selected with greenhouse objectives in mind With recent and increasing concerns about global warming potential and the need to cut CO2 emissions, power plants would benefit from such cogeneration businesses by using part of their captured CO2 to supplement greenhouse agriculture. Since North Dakota experiences typically longer winter months and also very hot summers, the glass greenhouse technology is the most feasible technology for the region because it has the design tools that allow for better temperature controls. However, with very little information available for modern designs that use CO2 derived from coal power plants, more research is needed to better evaluate the potential of greenhouse agriculture collocated with a coal-fired power plant. Market Assessment of Commercial Greenhouse Agriculture The market area of commercial greenhouse agriculture was evaluated by considering the top three fresh vegetables that are commonly grown in greenhouses: 1) tomatoes, 2) peppers, and 3) cucumbers. This market assessment addresses the following areas: market overview, competitive environment, requirements for market entry, market opportunities, and market segments. Two of the inputs to greenhouses are heat and CO2. Both of these inputs are potentially readily available from a lignite-fired power plant if commercial greenhouse operations were sited near a power plant. For the majority of greenhouse crops, net photosynthesis increases as CO2 levels increase from ambient levels of 340 ppm up to approximately 1300 ppm. Most crops show that for any given level of photosynthetically active radiation, increasing the CO2 level to 1000 ppm will increase the photosynthesis by about 50% over ambient CO2 levels (Blom et al., 2009). For most crops, the saturation point will be reached at about 1000–1300 ppm (Blom et al., 2009). A lower level (800–1000 ppm) is recommended for raising seedlings of tomatoes, cucumbers, and peppers as well as for lettuce production (Blom et al., 2009). Yield increases of 20% or more have been reported for tomatoes under certain conditions (Oregon State University, 2002). Market Overview The market overview contains an industry overview and the approximate market size for the leading products. The U.S. greenhouse vegetable industry is a mixture of small, family-run operations in the 2500- to 10,000-square-foot range to large, multiacre facilities 10 acres or more in size (Greer and Driver, 2000). The greenhouse vegetable industry falls within the larger fruit 73 and vegetable industry. In 2010, the U.S. fruit and vegetable market experienced moderate growth. As listed in Table 12 and illustrated in Figure 29, the U.S. fruit and vegetable market had total revenues of $108.4 billion in 2010, representing a compound annual growth rate (CAGR) of 3.8% for the period spanning 2006–2010 (Datamonitors, 2011). In comparison, the European and Asia–Pacific markets grew with CAGRs of 3.4% and 6.3%, respectively, over the same period, to reach respective values of $152.3 billion and $265.2 billion in 2010 (Datamonitors, 2011). Worldwide, the vegetable segment of the produce market was the most lucrative in 2010, with total revenues of $72.4 billion, equivalent to 66.8% of the market’s overall value (Datamonitors, 2011). The fruit segment contributed revenues of $35.9 billion in 2010, equating to 33.2% of the market’s aggregate value (Datamonitors, 2011). In the United States, the fruit and vegetable market grew by 1.3% in 2010 to reach a volume of 43.6 million tonnes. Market consumption volumes increased with a CAGR of 0.5% between 2006 and 2010, to reach a total of 43.6 million tonnes in 2010, as shown in Table 13 and depicted in Figure 30. Table 12. U.S. Fruit and Vegetable Market Value 2006–2010 Year US$, billion €, billion 2006 93.2 70.2 2007 95.5 72.0 2008 102.7 77.4 2009 102.3 77.0 2010 108.4 81.6 Figure 29. U.S. fruit and vegetable market value 2006–2010. 74 % Growth 2.5 7.5 (0.4) 6.0 Table 13. U.S. Fruit and Vegetable Market Volume 2006–2010* Year million tonnes 2006 42.8 2007 42.8 2008 42.4 2009 43.0 2010 43.6 % Growth 0.0 (0.8) 1.4 1.3 * CAGR: 2006–2010 0.5%. Figure 30. U.S. fruit and vegetable market volume 2006–2010. Economic conditions have increased grocery prices overall and likewise the cost of fresh produce. The average retail prices of fresh produce were higher in third quarter 2011 (July 2 – September 24) compared to the same quarter in 2010 (United Fresh Foundation, 2011). Prices were higher in all but two of the top 10 fruit and vegetable categories, which hurt volume for many categories as consumers purchased less fresh produce from supermarkets than a year ago. Because of the price increases, even though volume was down somewhat, sales revenue did not decline. The produce market is predicted to grow very slightly in the next few years. The projected CAGR is 0.3% for the 2010–2015 period (Datamonitors, 2011). That translates into a produce market volume of 48.8 million tons (44.3 million tonnes) by the end of 2015 (Datamonitors, 2011). 75 The largest segment of the fruit and vegetable market in the United States is vegetables, accounting for 66.8% of the market’s total value, while the fruit segment accounts for the remaining 33.2% of the market. The size of the vegetable market in the United States in 2010 was 29.1 million tonnes (Datamonitors, 2011). There are 124 countries worldwide producing greenhouse vegetables commercially. Some crops are grown directly in the soil and others are in soilless/hydroponic systems (Hickman, 2012). The major greenhouse crops include tomatoes, cucumbers, lettuce, sweet peppers, and culinary herbs. The term greenhouse includes only permanent structures. The total estimated world greenhouse vegetable production area is 1,002,820 ac (405,830 ha) (Hickman, 2012). The averages for North American production are shown in Table 14. Worldwide, 90% of these greenhouses are covered with plastic, with 10% in glass. In northern Europe, glass-covered greenhouses make up 61% of the total; the Americas, 20%; and Asia only 2% (Hickman, 2012). Of the total world greenhouse vegetable area, soilless/hydroponic culture systems account for 235,000 ac (Hickman, 2012). Much of the vegetables in the United States are imported. The value and amount of imported tomatoes, cucumbers, and peppers are shown in Table 15. Mexico and Canada are the leading countries from which the United States imports vegetables. The fresh tomato industry in Florida is the largest in the United States and supplies 45% to 50% of all domestic tomatoes to American consumers (Roberts, 2007). Competitive Environment Vegetables are a commodity. Greenhouse vegetables are competing with field-grown vegetables. Tomatoes, cucumbers, and peppers were chosen as the leading three products, as they have a steady demand and are amenable to greenhouse growth (Campbell, 2011; Gamble, 2011; Roberts, 2011). Lettuce is another product to consider in the future. Industry interviews Table 14. North American Greenhouse Production Area Acres (data from Hickman, 2012) Product Canada United States Mexico North America Tomatoes 1068 1009 4820 7019 Cucumbers 696 259 815 1566 Peppers 733 150 1360 1940 Total 2500 1418 6995 10,525 Table 15. Imports of Vegetables 2010 (data from Hickman, 2012) Cost, US$ lb Tomatoes 831,079 3,378,560 Cucumbers 370,028 1,290,971 Peppers 686,781 1,682,379 Total 1,887,888 6,351,910 76 indicated that lettuce can be challenging, as the precut, bagged lettuce is becoming a leading product and would add complexity to a greenhouse venture. Hydroponic lettuce is not particularly well known in the Midwest and demands a premium price. Herbs are another area to consider, as they are a high-value product. The top U.S. greenhouse vegetable-producing states by production acres and sales value are listed in Table 16. Figure 31 illustrates the North American greenhouse trade area. The largest North American greenhouse vegetable-producing facilities are in Mexico. One operation is located in Sinaloa, Mexico, with 865 ac in a single location, and is currently expanding (Hickman, 2012). Another operation in Mexico has 1413 acres across multiple locations (Hickman, 2012). The largest U.S. greenhouse vegetable operations are shown in Table 17, along with their locations and production acreage. Competitive Advantages Buying Local A produce buyer for Food Services of America (FSA), when presented with the idea of greenhouse agriculture in North Dakota, said, “Build it, and they will come. I’m all for it. I think it would be ideal” (Roberts, 2011). Approximately 10% of FSA purchases are from greenhouses. The cost can range anywhere from 20% to 75% higher. In North Dakota, 97% of fruits and vegetables are trucked into the state. FSA currently purchases much produce from Mexico and Canada, including produce from greenhouses just east of Winnipeg, Manitoba. Table 16. U.S. Top 10 Greenhouse Vegetable-Producing States by Area 2007 (Hickman, 2012) State Acres Value of Sales, US$ million Arizona 129 123 California 297 112 Texas 120 47 Colorado 90 35 New York 70 18 Florida 64 16 Virginia 43 24 Pennsylvania 42 24 Minnesota 33 15 Maine 30 12 Total 918 422 Average sales/acre from above: $388,000. NOTE: Acreage and sales data for several significant states have been withheld by the U.S. Census and are not reported here as official numbers, including Arizona, Colorado, Florida, Texas, and Virginia. This is because of confidentiality requirements by the Census Bureau, when only a few large growers are the principal producers in a state. The “totals” in the U.S. Census reports apparently do include this withheld data. However, public information is available on individual large companies in four of these omitted states, and this has been included here. The Census definition of a farm is gross sales of over $1000. Operations smaller than this are not included in the data. 77 Figure 31. U.S. top 10 greenhouse vegetable-producing states by area 2007 (Cook and Calvin, 2005). Table 17. Large U.S. Greenhouse Vegetable Operations (Hickman, 2012) Company Size, ac Location Eurofresh 318 Arizona Wijnen 138 California Houwelings 124 California Village Farms 122 Texas Sunblest 90 Colorado Intergrow 45 New York Backyard Farms 42 Maine Consumer preference leans toward local produce; big-box stores such as Wal-Mart and SuperTarget have responded by expanding their locally sourced produce selections. Local produce is fresher than produce shipped long distances from other states or countries. The average fruit or vegetable at a chain grocery store may have traveled more than 1500 miles. According to the 2008 Agricultural Resource Management Survey (ARMS), small local food farms (gross farm sales less than $50,000) represented almost 81% of all local food farms; medium-sized farms (gross farm sales $50,000–$249,999) represented 14%; and large farms (sales of $250,000 or more) accounted for almost 5% of all local food farms (Low and Vogel, 2011). Local farm sales utilize direct-to-consumer outlets, exclusive use of intermediated channels, or marketing through both channels (Figure 32). 78 Figure 32. Farmers’ local food marketing 2008 (Low and Vogel, 2011). The 2008 ARMS estimates shed light on two characteristics of local food supplies (Low and Vogel, 2011). First, gross sales of locally marketed food (to consumers and local intermediaries) are four times larger than previous census and ARMS estimates suggested, representing 1.9% of total gross farm sales, primarily because intermediated sales were included for the first time. Secondly, most local foods are marketed through intermediated channels, accounting for 50%–66% of the value of all local food sales. Attitudes of Restaurants and Food Service Institutions A study examined purchasing practices of locally produced fresh vegetables among restaurants and food service institutions. The sample for the study included managers of 75 restaurants and dining centers in the Midwest (Rimal and Onyango, 2011). The study findings show differential preferences between national/regional chains and the local independently owned restaurants. Although managers across the board expressed willingness to buy local, actual purchasing decisions were largely driven by freshness, quality, and availability. Price was not as critical a factor as others, including variety and selection. The results suggest that local vegetable producers should use regularity, quality, and freshness to differentiate themselves (Rimal and Onyango, 2011). As a producer of small volumes of fresh vegetables, local farmers have much higher probability of success if they supply to locally and independently owned restaurants. These restaurants use small volumes of vegetables in a broader variety. Producers stand to gain a competitive edge through greenhouse agriculture. Transportation Supplying greenhouse vegetables to the region would be advantageous from a transportation perspective. An industry contact working in produce distribution in the Midwest felt that a 600-mile radius would be a reasonable trade area for a commercial greenhouse(s) sited in western North Dakota (Campbell, 2011). Fuel costs are a major factor in today’s marketplace. Diesel fuel prices averaged $3.87 per gallon in FY2011 Q3, as shown in Figure 33, 4% lower 79 Figure 33. U.S. average on-highway diesel fuel prices (U.S. Department of Agriculture, 2011a). than last quarter but 32% higher than the same quarter last year. Average truck rates were $2.64 per mile, 4% higher than the previous quarter and 10% higher than the same quarter last year. The U.S. average on-highway diesel fuel prices and truck rates are shown in Figure 34. The effect of a change in diesel fuel prices is compounded for produce haulers because the fuel is needed to run the refrigeration unit as well as the truck. Many trucking companies and owner– operator independent drivers are not able to pass on the full increase in fuel cost to shippers because of existing contracts and competition. Industry Partnerships A consortium of five U.S. and Canadian greenhouse vegetable producers formed a group called “The North American Greenhouse/Hothouse Vegetable Growers” (NAGHVG) to “protect and support superior standards of excellence in food safety and quality” (Reuters, 2011). The producer members are Windset (75 ac), Village Farms (232 ac), Eurofresh (318 ac), Houweling’s (170 acres), and Gipaanda (18 ac). The five producers have a total of 813 ac of greenhouse area for a total of 10,527 ac, which is about 8% of production acreage in North America (Hickman, 2012). This North American group does not include any Mexican, Central American, or Caribbean producers. 80 Figure 34. U.S. average on-highway diesel fuel prices and truck rates (U.S. Department of Agriculture, 2011b). NAGHVG has proposed a definition of greenhouse-produced vegetables. Some of the “certified greenhouse” standards include the mandatory use of “computerized irrigation and climate control,” “including heating,” and “must use hydroponic (soilless) methods” (Hickman, 2012). Since most southern latitude greenhouses do not need heat, this definition would exclude them. However, as noted for the California definition, a small heater in each greenhouse would meet this qualification. Also, the majority of Mexican, Central American, and Caribbean greenhouse vegetable producers are currently growing in soil, so they are further excluded by this standard. Most large operations currently using soil culture have research areas with soilless methods. Barriers to Market Entry Seasonality Seasonality is a major force affecting the North American fresh tomato industry, both greenhouse and field tomatoes. In the winter, field tomatoes are only available from Florida and Mexico. Over time, the industry has developed relationships that cross national borders and provide a relatively seamless supply of field tomatoes from different regions across the seasons (Roberts, 2011). While greenhouse tomatoes can be grown anywhere at any time of the year, in order to establish a profitable venture, seasonality is an important concern. The growing season in western North Dakota will need to be determined based on daylight available. This concern was 81 stated by an industry contact at Nash Finch interviewed for this study (Gamble, 2011). Ontario is quite successful in the greenhouse industry, but its location is farther south. Leamington, Ontario, in the heart of greenhouse activity, lies on the 42nd parallel, the same latitude as Chicago, Rome, and the northern border of California. Greenhouses are designed to minimize the cost of achieving the ideal tomato-growing conditions for the targeted market window. Following the pattern established by the field tomato industry, the greenhouse tomato industry has also developed a web of business relationships that provide greenhouse tomatoes from various regions in different seasons. Monthly availability in the tomato industry is depicted in Figure 35. Marketing firms use marketing agreements, joint ventures and, to a lesser extent, foreign direct investment to ensure smooth supplies across seasons. Meet Industry Standards The greenhouse production needs to meet U.S. Department of Agriculture (USDA) standards. The USDA Agricultural Marketing Service has grade standards for greenhouse-grown tomatoes, cucumbers, and lettuce as well as grade standards for sweet peppers. These standards are available from USDA (U.S. Department of Agriculture, 2011). Labor and Capital Requirements Capital requirements for entry into food retail markets are generally not very high, and government regulations are relatively light, which tends to encourage new companies entering the market. However, the presence of large supermarket chains, which exercise great bargaining power, acts as a significant barrier to entry (Datamonitors, 2011). Greenhouse vegetable production is a highly intensive enterprise requiring substantial labor and capital inputs. Because of this, potential growers should carefully consider all of the factors necessary for a successful enterprise. Figure 35. North America greenhouse tomato and fresh field tomato shipping seasons by region (Cook and Calvin, 2005). 82 Greenhouse vegetable production is a 24-hour-a-day commitment. Greenhouse maintenance, crop production, and handling emergencies require constant vigilance. Every 4000 square feet of greenhouse space requires an estimated 25 to 30 hours of crop care and upkeep (Boyhan et al., 2009). Greenhouse structures require constant maintenance and repair. Many of the selected greenhouse covers must be replaced on a regular basis. Heating, cooling, and watering systems must be maintained and routinely serviced. In addition, contingency plans and backup systems must be in place in case any of these major systems break down. Even a 1-day loss of cooling, heating, or water during a critical period can result in complete crop failure. Economic Feasibility Greenhouse tomato production is more expensive than field production because of dramatically higher investment costs, as well as higher variable, or operating, costs. For example, a high-technology greenhouse may cost from $600,000 to over $1 million in construction (plus site purchase and improvement) costs per hectare just to begin operation, excluding variable growing costs (Cook and Calvin, 2005). U.S. industry experts estimate that an initial investment of $1.25 million per hectare is required when also including the inputs for the hydroponic growing system, such as the artificial growing medium. These greenhouse costs compare with average preharvest costs (including overhead, depreciation, and capital costs) of $2155/ac ($3100/ha) in the California Central Valley and $5060–6475/ac ($12,500–$16,000/ha) in Florida, depending on the region and season. Of course, substantial variation in per-unit production costs can exist between growers in the same growing regions, based on individual cost and yield performance, regardless of whether production is open field or protected. Per-unit production costs can also change significantly over time as growers gain experience. Average U.S. and Canadian greenhouse yields frequently approach 500 tonnes/ha/season (233 tons/ac/season), compared with U.S. average field tomato yields of 34 tonnes/ha in California and 36 tonnes/ha in Florida. The most efficient and experienced greenhouse growers in the United States and Canada may reach 700 tonnes/ha (312 tons/ac). But higher yields do not offset the higher investment and variable costs, making per-unit greenhouse production costs higher than field in all three North American Free Trade Agreement (NAFTA) countries and for all technology levels. In the past, greenhouse tomatoes generally received a hefty price premium over field tomatoes that helped compensate for higher per-unit costs of production. But with the rapid increase in greenhouse production, prices have declined, and the differential between field and greenhouse tomato prices has diminished. Market Development Along with the essential skills, capital, and labor to build, maintain, and grow a crop, producers must develop markets willing to pay the relatively high prices necessary to make the enterprise economically viable. Greenhouse-grown vegetables cannot compete with comparable 83 field-grown crops based on price; therefore, greenhouse-grown vegetables often are marketed to buyers based on superior quality and off-season availability. Midwinter greenhouse tomato production is not generally recommended for western Oregon. Poor light intensity and high humidity often result in poor fruit set and quality. Effective lighting and humidity control are not considered to be economical. Heating and other production and marketing costs; competition from outdoor production from California, Arizona, and Mexico; and the availability of greenhouse tomatoes from Canada at competitive prices make profitable greenhouse production in western Oregon difficult. Greenhouse production in British Columbia is possible because of the high inputs and the technical level of management possible in large operations (the trend is to shift to operations of over 2 ac), the high-quality glass greenhouses being used in the great majority of the operations, and a strong marketing organization (Oregon State University, 2002). Market Opportunities Greenhouse agriculture could supply a number of existing markets and potential niche markets. Several wholesale, retail, and direct outlets have been identified. Representatives within the industry were interviewed regarding the feasibility and potential demand for greenhouse agriculture sited in western North Dakota. Wholesale, food service, retail, and direct-toconsumer are all opportunities. Direct-to-consumer via farmers’ markets is also an opportunity, with the consumer trend toward buying local. One industry representative suggested that North Dakota contact the large farmers’ markets in the Minneapolis–St. Paul, Minnesota, area to gauge interest (Campbell, 2011). He stated that the large farmers’ markets in Chicago, Illinois, are supplied by producers from the state of Michigan. The retail produce market is concentrated, with large supermarket chains using their bargaining power and brand strength to establish their domination. In the United States, the produce market is dominated by large supermarkets, such as Walmart, Safeway, and Kroger. Buyer power is considered to be weak because of the product’s indispensable nature, and as suppliers are typically quite small and supply only a small number of products, they are vulnerable to players sourcing alternatives from competing suppliers. Walmart Walmart has a global commitment to sustainable agriculture. It has pledged to sell $1 billion in food sourced from 1 million small- and medium-sized farmers by 2015 (McMillon, 2011). The rationale is to give producers more direct access to markets so they can get a better return. Walmart is also striving to produce more food with less waste and providing customers with affordable and locally grown produce. Walmart is the largest retail company in the world. The company operates retail stores and offers its products through various e-commerce Web sites, including walmart.com and samsclub.com. Walmart operates three business segments: Wal-Mart Stores U.S., the international segment, and Sam’s Club. Wal-Mart Stores U.S. operates three different retail 84 formats in the United States: discount stores, supercenters and neighborhood markets. The segment has retail operations in all 50 states of the United States. Walmart operates 803 discount stores, each with an average store size of 108,000 square feet, in 47 states. The company also operates 2747 supercenters (average size of 185,000 square feet) in 48 U.S. states and 158 neighborhood markets (average size of 42,000 square feet) in 16 U.S. states. In addition, the segment also markets its products through its e-commerce Web site walmart.com. To support the retail operations of the Wal-Mart Stores U.S. segment, Walmart operates 120 distribution facilities across the United States, of which the company owns 105; the remaining are owned and operated by third parties. A few of these distribution centers also service Walmart’s Sam’s Club for certain items. During FY2010, these distribution centers shipped approximately 79% of the merchandize sold by Wal-Mart Stores U.S. The remaining merchandise was shipped directly by the suppliers to the company’s stores. Sam’s Club operates Walmart’s warehouse membership clubs in the United States. Sam’s Club also operates the Web site www.samsclub.com. Walmart operates 596 Sam’s Clubs (average store size of 133,000 square feet) in 48 U.S. states. Sam’s Club serves both individuals and businesses. There are 26 distribution facilities across the United States to support the Sam’s Club retail operation, of which the company owns eight and the remaining are third-party-owned facilities. Walmart has made a priority of buying from local growers. Walmart has several food distribution centers throughout the United States. From 2006 to 2008, Walmart’s partnerships with local farmers grew by 50%, and it is committed to expanding local buying. During the last 2 years, partnerships with suppliers based in the United States make the company the biggest customer of American agriculture (Thornberry, 2011). During the summer months, locally produced fruits and vegetables available for purchase at Walmart stores in the same state where they were grown make up a fifth of Walmart’s produce. The retailer purchases more than 70% of its produce and vegetables grown and shipped from local farms across the United States (Thornberry, 2011). To offset the rising cost of fuel, Walmart plans to expand its offerings of fresh fruits. Between 2006 and 2008, Walmart partnerships with local farmers grew by 50%. Within the United States, Walmart claims to be the largest buyer of produce that is grown and sold within a state’s borders (Thornberry, 2011). Buying local allows Walmart to save millions in fuel costs. The company estimates more than 70% of its produce originates in the United States. Produce, in general, travels an average of 1500 miles from farms to consumers (Thornberry, 2011). Nash Finch Company The Nash Finch Company operates as a wholesale food distributor in the United States. The food distribution segment sells and distributes various branded and private label grocery products and perishable food products to approximately 1800 independent retail locations through its 14 distribution centers (Datamonitors, 2011). The company’s military segment 85 distributes grocery products to U.S. military commissaries and exchanges in the United States, the District of Columbia, Europe, Puerto Rico, Cuba, the Azores, and Egypt. The company’s retail segment operates over 200 corporate-owned conventional grocery stores such as Sun Mart and Econofoods primarily in the Upper Midwest in the states of Colorado, Iowa, Minnesota, Nebraska, North Dakota, Ohio, South Dakota, and Wisconsin (Datamonitors, 2011). The Nash Finch Company is based in Minneapolis, Minnesota, and also has a distribution center in Fargo, North Dakota. SUPERVALU SUPERVALU is one of the largest companies in the U.S. grocery channel, with approximately 140,000 employees and FY2011 annual sales of approximately $37.5 billion (SUPERVALU, 2011). SUPERVALU operates 1114 traditional retail food stores under the Acme, Albertsons, Cub Foods, Farm Fresh, Hornbacher’s, Jewel-Osco, Lucky, Shaw’s, Shop ’n Save, Shoppers Food & Pharmacy, and Star Market banners (SUPERVALU, 2011). The map of SUPERVALU’s retail and independent business network is found in Figure 36. Food Service of America FSA is a food service supplier in the Midwest and West. Its main office is in Fargo, North Dakota, along with a warehouse in Minot, North Dakota. FSA locations are presented on the map in Figure 37. Vicki Roberts, who purchases produce for FSA, indicated strong interest in North Dakota-grown greenhouse vegetables, as discussed in a previous section (Roberts, 2011). FSA supplies restaurants, colleges, hospitals, and nursing homes in the region shown in Figure 37. US Foods A leading foodservice distributor, US Foods is the tenth largest private company in America. With nearly $19 billion in annual revenue, the company is headquartered in Rosemont, Illinois (Marketwire, 2011). US Foods offers more than 350,000 national brand products and its own “exclusive brand” items, including fresh produce. The company employs approximately 25,000 people in more than 60 locations nationwide (Marketwire, 2011). US Foods has more than 250,000 customers, including independent and multiunit restaurants, healthcare and hospitality entities, government, and educational institutions (Marketwire, 2011). US Foods is jointly owned by funds managed by Clayton, Dubilier & Rice Inc. and Kohlberg Kravis Roberts & Co. (Marketwire, 2011). Market Assessment Conclusion At this stage of the project, about 80% to 90% of the market research on the produce market has been completed. Additional industry interviews will be conducted as indicated. If updated statistics become available shortly after January 1, 2011, selected data will be updated. 86 Figure 36. SUPERVALU’s retail and independent business network (SUPERVALU, 2011). Figure 37. FSA locations (Food Service of America, 2012). 87 Based on the market assessment information obtained, it is known that greenhouse agriculture can produce larger yields of some vegetable crops than traditional agriculture. The capital and operating expenses for such an enterprise could be large, and the amount of daylight during the winter in North Dakota could pose a seasonal production issue. However, people and companies are interested in buying locally sourced vegetables such as tomatoes, peppers, and cucumbers because they are fresher and transportation costs are lower (although the added expense associated with greenhouse agriculture probably eliminates the cost advantage to the individual consumer). Large grocery chains and food service companies that are headquartered in or near the region have expressed interest in the availability of produce from this type of regional source. Finally, there are few greenhouse agriculture enterprises in the region around western North Dakota, so the competition would be minimal. These positives indicate that a preliminary economic analysis of the opportunity is warranted. Economic Feasibility of Greenhouse Agriculture Product value that can be derived from the greenhouse depends on how productive the operation is and the price of the product. Table 18 shows average productivities for two of the major greenhouse agriculture areas: Almeria, Spain, and the Netherlands. As seen in Table 18, the greenhouses in the Netherlands are much more productive. This is a function of the intensity and sophistication of the greenhouse operations. Figure 38 shows the U.S. producer price for tomatoes from 1991 through 2007 reported for all farm operations. For a producer price of $8/kg for tomatoes and a productivity of 42 kg/m2-year, the potential production cost would be $336/m2-year. If this production is performed using liquid CO2 priced at $110/tonne and the supply of CO2 costs $2.41/m2-year, then the CO2 cost represents only 0.7% of the producer cost, providing a good price for the CO2 supply. In light of the above analysis, North Dakota power plants will potentially benefit from any greenhouse agriculture operations in the state. In most cases, these greenhouses have been subsidiary companies owned by the power plants themselves so as to facilitate integration with the current plants and to derive additional synergistic benefits such as supply of low-grade heat for maintaining the temperature in the greenhouses in the winter or supply of power to cool the greenhouses in the hot summer months. Also, collocation removes extra transportation requirements and associated costs, which makes the operation even more economically feasible. Based on 2003 estimates, the United States imports a total of about 280,000 tonnes of greenhouse-grown tomatoes annually (Cook and Calvin, 2005). In 2009, the U.S. imported a Table 18. Vegetable Yield in Greenhouses, Annual Productivity (kg/m2) (Cantliffe and Vansickle, 2003) Crop Almeria, Spain The Netherlands Tomatoes 10‒12 42 Peppers 6‒7 26 Cucumbers 8‒9 58 Snap Beans 5 32 88 Figure 38. U.S. producer price for tomatoes (Food and Agriculture Organization of the United Nations, 2010). total of 1.3 million tons (1.2 million tonnes) of tomatoes (not all of which were greenhousegrown) (U.S. Department of Agriculture, 2010). This high demand, coupled with very good prices, could mean a significant revenue source for North Dakota power plants. Novel CO2 Utilization Processes under Development This section on novel CO2 utilization processes under development refers primarily to conceptual and laboratory-scale proof-of-concept processes of the type being supported by the DOE’s Advanced Research Projects Agency – Energy (ARPA-E) Program. They include processes that involve the electrochemical conversion of CO2 to fuels and/or other chemicals, bioelectrochemical systems such as reverse microbial fuel cells that combine microbial processes and electrochemistry to produce chemicals, the use of microorganisms that convert hydrogen and CO2 to desirable chemicals, and other processes that make direct use of sunlight to power chemical synthesis reactions. Electrochemical Conversion Processes The primary objective of electrochemical conversion processes, also known as electrofuels technologies, is to seek new ways to make liquid transportation fuels—without using petroleum or biomass—by using microorganisms to harness chemical or electrical energy to convert CO2 into liquid fuels. Many methods of producing advanced and cellulosic biofuels are under development to lessen our dependence on petroleum and lower carbon emissions. Most of the methods currently under development involve converting biomass or waste, while there are also 89 approaches to directly produce liquid transportation fuels from sunlight and CO2. Although photosynthetic routes show promise, overall efficiencies remain low. Therefore, it is becoming increasingly important to develop new approaches for the production of liquid fuels that could overcome the challenges associated with current technologies. The ARPA-E Program is currently leading this effort in the United States (Clean Technology and Sustainable Industries Organization, 2011) and is funding innovative proposals to overcome these challenges through the utilization of metabolic engineering and synthetic biological approaches for the efficient conversion of CO2 to liquid transportation fuels. In particular, the ARPA-E Program seeks the development of organisms capable of extracting energy from hydrogen; from reduced earth-abundant metal ions; from robust, inexpensive, readily available organic redox active species; or directly from electric current. These approaches are, in principle, expected to be about 10 times more efficient than current photosynthetic biomass approaches to liquid fuel production. At the last ARPA-E Energy Innovation Summit held in Washington, D.C., in March 2011, about 12 different industries/organizations throughout the United States showcased currently available technology concepts/prototype projects (Clean Technology and Sustainable Industries Organization, 2011), which are summarized as follows. Massachusetts Institute of Technology – Bioprocess and Microbe Engineering The Massachusetts Institute of Technology (MIT) is developing a process known as bioprocess and microbe engineering for total carbon utilization in biofuel production. It is said to be at the prototype stage. This technology combines anaerobic and aerobic oil production systems from CO/CO2 and hydrogen, or electrons from a bioelectrochemical system, for the production of biodiesel. Sun Catalytix Corporation – Affordable Energy from Sunlight and Water Sun Catalytix Corporation is the developer of the affordable-energy-from-sunlight-andwater process, which is currently still a prototype. The company is focused on using newly discovered, low-cost catalytic materials to enable generation of affordable renewable fuel from sunlight and water. The company’s technology builds on breakthrough water-splitting discovery work from the lab of Professor Daniel Nocera at MIT. The company’s ARPA-E Program is continuing the advancement of the catalytic technology in two directions in parallel: in electrolysis cells and in photoelectrochemical cells. University of California, Los Angeles – Electro-Autotrophic Synthesis The University of California, Los Angeles, is developing a prototype process called electro-autotrophic synthesis of higher alcohols. Current technologies using biological photosynthesis to convert sunlight to liquid transportation fuels are relatively inefficient. Conversely, humanmade solar cells are more efficient in energy conversion, but the electricity generated presents a storage problem. As a result, this project seeks to develop microorganisms 90 using synthetic biology and metabolic engineering to derive energy from electricity instead of light for CO2 fixation and fuel synthesis. University of Massachusetts – Microbial Electrosynthesis The University of Massachusetts is developing a process called microbial electrosynthesis, which is at the prototype stage. Microbial electrosynthesis is an artificial form of photosynthesis in which microorganisms convert CO2 and water to transportation fuels or other desirable organic compounds, with solar-generated electricity as the energy source. Microbial electrosynthesis is expected to be more efficient and results in significantly less environmental degradation than biomass-based energy processes. Other Concepts Columbia University – Biofuels from CO2 Columbia University has proposed a concept entitled biofuels from CO2 using ammoniaoxidizing bacteria in a reverse microbial fuel cell, which is expected to use microorganisms to convert CO2 and NH3 to biofuels. The technology will create a reverse microbial fuel cell using genetically modified N. europaea cells. These cells are expected to grow on electrochemically generated NH3 and fix CO2 into biofuels. Ginkgo BioWorks – Electrfuels Process An electrofuels process concept has been proposed by Ginkgo BioWorks to engineer organisms to convert CO2 to fuel chemicals using energy from electricity. This technology involves engineering organisms to convert CO2 and electricity to isooctane or other chemicals. The technology is also being extended to use H2S, a major waste product from desulfurization in petroleum refining and natural gas processing, as an energy source. Harvard University Wyss Institute – Engineering a Bacterial Reverse Fuel Cell Wyss Institute at Harvard University has proposed a process called engineering a bacterial reverse fuel cell. This is still a concept, with the aim to genetically engineer a bacterium to absorb electricity from an electrode, fix CO2, and synthesize a biofuel. A physical system to house the bacteria will be constructed. Lawrence Berkeley National Laboratory – Development of an Integrated Microbial– Electrocatalytic System Lawrence Berkeley National Laboratory has proposed a concept for a process entitled development of an integrated microbial–electrocatalytic (MEC) system for liquid biofuel production from CO2. This technology idea seeks to develop a combined microbial and electrochemical catalytic system to transform electricity and CO2 to generate energy-dense biofuels. A novel metal complex that converts water to H2 at high rates with input of electricity will be used to generate H2 for microbial growth and biofuel production. 91 North Carolina State University – Electrofuels North Carolina State University has proposed another concept called electrofuels, which is aimed at using enzymes to fix CO2 into liquid fuels. Pathways and enzymes from extremely thermophilic archaea are used to fix CO2 into liquid biofuels, with molecular H2 as the reducing agent. Oak Ridge National Laboratory – Biofuels Production via Electrotrophic Biosynthesis Oak Ridge National Laboratory has proposed a concept entitled biofuels production via electrotrophic biosynthesis. Conversion of CO2 to energy-dense fuels is done via a hybrid biochem route using electricity. CO2 is converted to an intermediate via a novel bioprocess and then to hydrocarbons via chemical catalysis. The bioprocess involves multienzyme pathways in an electrotrophic microorganism and an efficient bioreactor for intermediate production. A catalytic reactor then transforms the biological intermediate into fuels. OPX Biotechnologies, Inc. – Novel Biological Conversion of H2 and CO2 to Biodiesel OPX Biotechnology, Inc. (OPXBIO), is developing a process known as novel biological conversion of hydrogen and carbon dioxide directly into biodiesel. This technology is still a concept. OPXBIO, National Renewable Energy Laboratory (NREL), and the U.S. subsidiary of Johnson Matthey intend to develop and optimize a novel, engineered microorganism that directly produces a biodiesel-equivalent electrofuel from renewable hydrogen and CO2. OPXBIO’s proprietary genomics technology, coupled with NREL’s directed and improved H2 utilization and CO2 fixation, will allow rapid metabolic engineering of a microbe to achieve the fuel production metrics necessary for commercial success. Ohio State University – Bioconversion of CO2 to Biofuels Ohio State University is developing a concept called bioconversion of CO2 to biofuels by facultatively autotrophic hydrogen bacteria. The aim of this technology is to convert CO2 into infrastructure-compatible biofuels via engineered microbes that are able to grow on mixtures of CO2, oxygen, and hydrogen in the absence of photosynthesis. Status of Novel CO2 Utilization Processes under Development All of these novel CO2 utilization technologies are at a very early stage of development. Some are merely conceptual ideas, while others have advanced to the small lab-scale proof-ofconcept stage. None is anywhere close to moving out of the lab to even small-scale development. It is also important to remember that all of these processes require the input of energy in order to convert CO2 into a useful product. Most are based on the use of electricity or molecular hydrogen but a few rely on the use of sunlight. All are funded through the ARPA-E Program because they represent high-risk investments, meaning most of the ideas are likely to fail before they can become commercially available. The hope is that some of these ideas will, at the very 92 least, help contribute to development of useful technologies that can be commercially relevant sometime in the future—perhaps within the next 25 years. A great deal of work and the investment of substantial time and money will be needed in order for that to happen. SUMMARY AND CONCLUSIONS The overall goal of this study was to identify the most promising technologies for the utilization of CO2 from North Dakota lignite-fired utilities. The information collected and documented in this report was designed to answer the questions, What CO2-use technologies exist or are under development? How much of the CO2 from coal-fired power plants can they use? and Do any of them have the potential to make money or at least help offset some of the costs of CO2 capture? The following summarizes the key findings of this study. In the context of this report, the best technology is defined as one that would require externally sourced CO2 and provide a marketable product. Ideally, this technology would be able to capture the CO2 from the lignite-fired power plants’ flue gas and use it in a manner that would be sufficiently permanent to be considered equivalent to geological storage. None of the currently available CO2 utilization technologies can meet all of these requirements. By specific request of the North Dakota Industrial Commission’s LEC, technologies related to EOR and ECBM were not considered for detailed study as part of this project; however, it appears that EOR and ECBM could meet three of the four requirements (the CO2 must first be captured). It should be noted that the total estimated annual global CO2 demand for use in EOR and ECBM is very small compared to the estimated annual storage requirements for a carbon-constrained world. Approximately 30.25 million tons/year (27.4 million tonnes/yr) of Fort Union lignite is mined from four mines in North Dakota and one in Montana. These mines supply coal to six of the seven North Dakota coal-fired power plants, the Great Plains Synfuels Plant, and a small power plant and sugar beet-processing plant in Montana. Together, these facilities emit approximately 35 million tons/yr (32 million tonnes/yr) of CO2. Approximately 3 million tons/year (2.7 million tonnes/yr) of CO2 is captured at the Great Plains Synfuels Plant and is sold for use/geological storage in EOR operations. CO2 utilization technologies can be divided into six broad categories: The direct use of CO2, such as in carbonated beverages, as a dry cleaning solvent, or for energy recovery processes like EOR or ECBM production. The mineralization of CO2 by reacting it with metal oxides or metal hydroxides to form metal carbonates or metal bicarbonates that may be used in construction materials. Use as a feedstock in the manufacture of chemicals, including chemical products or precursor chemicals that require chemical reduction of the carbon to a less oxidized form. 93 Use as a feedstock in the manufacture of chemicals, including chemical products of precursor chemicals like urea or bicarbonate that do not require chemical reduction of the carbon. Photosynthesis-based technologies that reduce the carbon in CO2 to organic carbon for use as food, fuel, or a chemical feedstock. Novel technologies based on the direct use of engineered microorganisms, electricity, and/or the direct use of sunlight for the production of fuels and/or chemical precursors. Each of these technology categories can be classified concerning its potential to use externally sourced CO2, provide a marketable product, and produce a product that has a reasonable potential to store the CO2 for a long period of time. They can also be classified as to their potential to capture CO2 from postcombustion flue gas (assuming it has been cleaned of contaminants that might harm the process or product). Technologies with excellent potential for use of externally sourced CO2 include the direct use of CO2 and photosynthesis technologies. There is also good potential for the use of externally sourced CO2 as a supply for many of the mineralization technologies and for the novel technologies (assuming that sunlight or carbon-free electricity or hydrogen are supplied). In general, the companies using the chemical synthesis technologies will supply their own CO2 from earlier process steps and/or from on-site heat and power generation. This lack of need for externally sourced CO2 applies to processes such as the production of urea and polycarbonate plastics. The production of marketable products is clearly defined for the direct use of CO2 and photosynthesis technologies because industries based on these technologies already exist and currently purchase externally sourced CO2. This includes CO2 used in EOR and ECBM; for carbonated beverages, fire extinguishers, coffee decaffeination, and as a dry-cleaning solvent; and by greenhouse operations and algae producers. One caution concerning the algae production industry is that while profitable companies exist to manufacture nutritional supplements, this market is small. The potential large-market products (e.g., fuel and feed) are of much lower value and cannot be profitably produced. While the mineralization companies have identified several types of products that can be made, few data are available to support the technology developers’ ability to make these products and achieve market acceptance. The chemical manufacturing technologies can, and in some cases do, make marketable products. Marketable products can come from the novel CO2 utilization technologies but these technologies are all at very early stages of development (i.e., conceptual to small laboratory-scale proof of concept). The use of CO2 for EOR and ECBM can result in permanent storage but CO2 used in other direct-use applications is released during use. Products made from CO2 captured in photosynthesis-based processes also have a short lifetime before the carbon is converted back into CO2. Mineralization technologies can produce materials that are sufficiently stable that the carbon could be considered to be permanently stored. Some chemical synthesis technologies 94 produce very stable products such as plastics that might also have very long lifetimes, but many of the other products will have short lifetimes. There is some uncertainty as to how future regulations might credit or not credit the use of CO2 in products with short lifetimes. The technologies that can use flue gas concentrations of CO2 (assuming it has been cleaned of contaminants that might harm the product) as the source include some mineralization technologies and the photosynthesis technologies. Some of the novel technologies may also fall into this category, although their early stage of development makes this unclear at best. Most of the direct-use and chemical synthesis technologies require high-purity, high-pressure CO2. Technology Options for North Dakota Lignite-Fired Power Plants Other than the use of CO2 in EOR or ECBM applications, none of the CO2 utilization options is currently ready for implementation or integration with North Dakota power plants. Mineralization technologies suffer from the lack of a well-defined product. The alkalinity in lignite fly ash is sufficient to react with 0.7% to 1.3% of the CO2 produced, but no known method exists that can produce a product from this reaction that is more valuable than the fly ash itself. The novel technologies are too early a stage. The chemical technologies do not need externally sourced CO2. Use of captured and compressed CO2 for EOR and ECBM should be considered, but the LEC requested that further investigation of that option not be explored as a part of this project. Algae and microalgae technologies are not economically feasible for North Dakota. The successful algae-producing companies are located in environments that favor the manufacture of their products (i.e., moderate temperatures and sunlight are available without extra cost). Their high-value nutrient supplement products are dry, shelf-stable and, therefore, relatively inexpensive to transport, making them readily available to the local population even without local producers. Irrespective of location, algae and microalgae products that could utilize a substantial amount of CO2 (e.g., fuels and feed) are currently more expensive to produce than their potential market value can fetch. Greenhouse agriculture has potential in North Dakota because of the high market value of its products. Although greenhouse agriculture in North Dakota would require facilities that offer supplemental heat and lighting for many months each year, the productivity of such greenhouses is several times higher than traditional farming, so the extra cost could be recovered through the sale of the additional product. Transport of fresh produce to North Dakota from other locales is expensive, and the market study confirmed that consumers and food distributors preferred locally sourced, high-quality vegetables to the imports. 95 Market Assessment of the Products of Promising Technologies The CO2 mineralization technologies do not yet have well-defined products. The market will dictate the type and quantity of products that are made, but the entry-level product for most mineralization companies will likely be aggregate that can be used for roads and/or as a component of concrete. There is a substantial need for aggregate in North Dakota, particularly in the Devils Lake Basin and in the Bakken–Three Forks shale oil development area. The cost of gravel is roughly one half of the developer-estimated cost of aggregate formed by mineralization, indicating that product improvements are needed for this technology to compete economically. Another use for mineralization products might be as solidifying agents for drilling waste pits formed during oil field operations. The fly ash is currently more valuable for this use than as an alkalinity source for a mineralization process. Greenhouse agriculture appears to be the only promising technology for which products are obvious and can be assessed for potential markets. Based on the market analysis conducted as part of this study, it is known that greenhouse agriculture can produce much higher yields of some vegetable crops than traditional agriculture. The market price for greenhouse tomatoes is quite high, and there is also a high demand in the United States, which imports nearly 1.3 million tons (1.2 million tonnes) of tomatoes annually (U.S. Department of Agriculture, 2010). The capital and operating expenses for such an enterprise could be large and the amount of daylight during the winter in North Dakota could pose a seasonal production issue. However, people and companies are interested in buying locally sourced vegetables such as tomatoes, peppers, and cucumbers because they are fresher and transportation costs are lower (it should be noted that the added expense associated with greenhouse agriculture probably eliminates the cost advantage to the individual consumer). Large grocery chains and food service companies that are headquartered in or near the region have expressed interest in the availability of produce from this type of regional source. Finally, there are few greenhouse agriculture enterprises in the region around western North Dakota, so the competition would be minimal. These positive attributes indicate that a more detailed economic analysis of the opportunity is warranted. RECOMMENDATIONS The recommendations by the authors are that the LEC should consider: Investment in the advancement of mineralization technologies that show promise toward development of a marketable product, particularly if the technologies can also use coal combustion residuals to produce a high-value product. The value of that product would need to substantially exceed the high price obtained for fly ash used as a solidifying agent in drilling waste pits or in other oil-related activities. 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