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A selection of recent and current research projects conducted by CONSOL R&D, click below to view a topic:
Coal-Fueled Power Plant Pollutant Emissions Reduction
Greenhouse Gas Emissions Reduction
Waste Coal Utilization
Coal-Fired Combustion Boiler Technology
Air Quality
Advanced Technology
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The Greenidge Multi-Pollutant Control Project Background CONSOL Energy Inc. Research & Development led a team that included AES Greenidge LLC and Babcock Power Environmental Inc. to install and test an integrated multi-pollutant control system on one of the nation's smaller existing coal-fired power plants - the 107-MWe AES Greenidge Unit 4. The multi-pollutant control system included a NOxOUT CASCADE® hybrid selective non-catalytic reduction / selective catalytic reduction (SNCR/SCR) system and a Turbosorp® circulating fluidized bed dry scrubbing system. The overall goal of the approximately 2.5-year Greenidge Multi-Pollutant Control Project, which was conducted as part of the U.S. Department of Energy’s Power Plant Improvement Initiative, was to demonstrate that this multi-pollutant control system can cost-effectively reduce emissions of NOx, SO2, Hg, acid gases (SO3, HCl, HF), and particulate matter from coal-fired electric generating units with capacities of 50 MWe to 300 MWe. The project sought to be the first to demonstrate: The project will be the first to demonstrate:
The multi-pollutant control system has a capital cost of about $340/kW and occupies an approximately 0.4-acre footprint for the AES Greenidge Unit 4 application, both substantially less than would have been required to retrofit a conventional stand-alone SCR and wet scrubber on a unit of this size. Benefits There are more than 400 coal-fired units in the United States with capacities of 50-300 MWe that currently are not equipped with SCR or flue gas desulfurization systems. These smaller units, which represent almost 60GW of installed generating capacity, are increasingly vulnerable to retirement or fuel switching as a result of progressively more stringent state and federal environmental regulations. The Greenidge Project demonstrated the commercial readiness of an emissions control system that is particularly suited, because of its low capital and maintenance costs and small space demands, to meet the requirements of this large group of existing electric generating units. Accomplishments Construction of the multi-pollutant control system at AES Greenidge was completed in November 2006, and start-up and commissioning were completed during early 2007. Performance testing data collected through June 2008 showed average removal efficiencies of 96% for SO2, 95% for SO3, 97% for HCl, and 98% for Hg. NOx emissions were reduced by more than 50% and particulate matter emissions were reduced by more than 98% relative to the emission rates achieved prior to installation of the technology. The project was completed on schedule in October 2008, and the final report was issued in April 2009. As a result of the successful demonstration at AES Greenidge, Turbosorp® retrofits have been announced for three additional units in the 50-300 MWe size range.
Pilot Testing of the Low-Temperature Mercury Control (LTMC)
Process Background CONSOL Energy Inc. developed a potentially low-cost method for controlling mercury emissions from coal-fired power plants. Working with Allegheny Energy Supply, Alstom Power, Environmental Elements Corp., Carmeuse Lime, and DOE, CONSOL erected and operated a 2 MW slip-stream pilot plant at the Allegheny Energy Mitchell Station to test and further develop the LTMC process. The testing also showed the important operating variables and their effects on process performance. Benefits The LTMC process controls mercury by cooling the flue gas temperature to approximately 200-220 °F and absorbing the mercury on the carbon inherent in the fly ash. In order to protect against corrosion, a problem at such low flue gas temperatures, magnesium hydroxide is injected to absorb sulfur trioxide, a precursor of sulfuric acid. Accomplishments The pilot tests showed that the LTMC process can capture up to 90% of the mercury in the coal before it can be emitted. Follow-on tests conducted through the first half of 2006 for a private client confirmed the SO3 control effectiveness of the process. Plans The DOE pilot program was completed in 2005. The results of the pilot testing were sufficiently promising to justify a full-scale field trial of the LTMC process (see next item).
Full-Scale Field Trial of the Low Temperature Mercury Control
(LTMC) Process Background CONSOL R&D, Jamestown (NY) Board of Public Utilities (BPU), Lechler, and Martin Marietta teamed together to conduct a Department of Energy (DOE) field trial of the Low-Temperature Mercury Control (LTMC) process at Unit 12 of the BPU Samuel A. Carlson Station. LTMC has the ability to reduce mercury emissions by over 90%, as was recently demonstrated by CONSOL R&D on a slip-stream pilot plant at the Allegheny Energy Mitchell Station under DOE contract (see above). The next step is to demonstrate the performance, operability, and economics on a full-scale utility boiler. In addition this project will demonstrate that water spray humidification can maintain the electrostatic precipitator (ESP) performance under low-SO3 conditions. The LTMC process controls mercury by cooling the flue gas temperature to approximately 220 °F and absorbing the mercury on the carbon inherent in the fly ash. The host site will be the BPU Samuel A. Carlson Unit 12, which is a nominal 18 MW bituminous coal-fired unit. The host unit fly ash, with an LOI between 7 to 15%, is ideally suited for mercury capture. The LTMC process controls mercury by cooling the flue gas temperature to approximately 220 °F and absorbing the mercury on the carbon inherent in the fly ash. The host site will be the AE R. Paul Smith Unit 4, which is a nominal 88 MW bituminous coal-fired unit. R. Paul Smith fly ash, with an LOI between 15 to 20%, is ideally suited for mercury capture. The flue gas exiting the boiler from this unit is divided into two ducts, each equipped with its own air heater and ESP. Benefits This technology has the potential to remove over 90% of the flue gas mercury at a cost at least an order of magnitude lower (on a $/lb mercury removed basis) than activated carbon injection. The technology is suitable for retrofitting to existing and new plants, and, although it is best suited to bituminous coal-fired plants, it may have some applicability to the full range of coal types. Accomplishments The project was originally planned for the PPL Martins Creek Station, but reduced funding by DOE prevented completion of the original plan. The project was relocated to the Allegheny Energy R. Paul Smith Station and much of the project components were in place when Allegheny Energy announced plans to install fabric filtration to comply with particulate emission regulations, which would also increase baseline mercury removals to levels approaching 100%, obviating the need for further reduction by LTMC. The project was then relocated to Jamestown BPU. Baseline testing was completed and the LTMC system was designed and installed, and early testing was completed in March 2009. Modifications were made to the system to provide better control of operations and improve mercury control. Modifications were completed in March 2010, and the system is presently awaiting further testing. Plans The flue gas temperature will be reduced to, nominally, 220 °F using water sprays inserted into the existing duct work. A three-week test will collect operating data on mercury removal and balance-of-plant impacts from the process. The project will include an economic analysis, including estimates of capital costs, and fixed and variable operating and maintenance (O&M) costs. The project is scheduled for completion in the autumn of 2010.
Evaluation of Mercury Emission from Coal-Fired Facilities
With SCR and FGD Systems
Background CONSOL Research & Development (CONSOL R&D), with support from the U.S. Department of Energy, National Energy Technology Laboratory (DOE) and the Electric Power Research Institute (EPRI), evaluated the effects of selective catalytic reduction (SCR) on mercury (Hg) capture in coal-fired plants equipped with an electrostatic precipitator (ESP) - wet flue gas desulfurization (FGD) combination or a spray dyer absorber - fabric filter (SDA-FF) combination. In this program CONSOL determined mercury speciation and removal at 10 coal-fired facilities. Benefits The principal purpose of this work was to develop a better under¬standing of the potential mercury removal "co-benefits" achieved by NOx, and SO2 control technologies. Accomplishments The project was completed. The results of this study likely to have the most impact in the scientific, engineering, and regulatory communities are:
Enhanced Coal Bed Methane Production and Sequestration of
CO2 in Unmineable Coal Seams
Background CONSOL R&D is demonstrating a drilling and production process that reduces potential methane emissions from coal mining, produces usable methane (natural gas), and creates a sequestration sink for carbon dioxide (CO2) in unmineable coal seams. CONSOL R&D's project employs horizontal drilling to drain coalbed methane (CBM) from a mineable coal seam and an underlying unmineable coal seam. Upon drainage of 50-60 percent of the coalbed methane, some of the wells will be used for CO2 injection to sequester the CO2 in the unmineable seam, while stimulating addition methane production. The primary goal of this project is to evaluate the effectiveness and economics of carbon dioxide sequestration in an unmineable coal seam. The project involves development of a 200 acre area involving two coal seams. CO2 is being injected into the lower, unmineable seam to enhance the ultimate production volume of CBM by preferentially displacing absorbed methane. The upper, mineable seam is isolated from the lower, unmineable seam by 600' of shale and other rock that prevents CO2 migration from the unmineable seam into the mineable seam. Benefits This project will provide a documented case study of the effectiveness and economics of carbon dioxide sequestration in an unmineable coal seam. The results can be used by mining and power generation companies who wish to sequester CO2 in unmineable coal seams and also by regulatory agencies and the public to aid in policy and permitting decisions.
Accomplishments Horizontal wells extending up to 3000 ft. long were drilled at three sites in the northern panhandle (Marshall County) of West Virginia, into the mineable seam (Pittsburgh seam) and the unmineable seam (Upper Freeport seam). CBM has been produced from these wells since 2004. An Underground Injection Control (UIC) permit was obtained from WVDEP. Baseline monitoring, required prior to injection to verify existing gas and groundwater compositions, was completed. Periodic CO2 injection commenced in September 2009, and continuous injection beginning in January 2010. The total volume injected through March 2010 was 450 tons. The present injection rate is about 11 tons per day. As the injection continues, we have been working closely with the WVDEP, WVU and NETL on an expanded monitoring scheme for the CO2 injection project. Plans The present injection rate, less than half the originally planned injection rate of 27 tons per day, is limited by the maximum pressure established by the UIC permit of 700 psig. CONSOL received permission from WVDEP to increase the maximum injection pressure to 933 psig. Various components must be replaced to operate at this pressure, and we are working to install them in 2010.
Capture and Use of Coal Mine Ventilation Air Methane
Background CONSOL Energy Inc., Research & Development, in conjunction with MEGTEC Systems and the U.S. Department of Energy, designed, built, and operated for thirteen months a commercial-size regenerative thermal oxidizer (RTO) to destroy methane in simulated coal mine ventilation air. Coal mining, and particularly coal mine ventilation air, is a major source of anthropogenic methane emissions, a powerful greenhouse gas. Until now, it has not been reasonably possible to either reduce or use ventilation air methane (VAM) because of its large volumes and low concentrations. The performance guarantee of the RTO is to oxidize 95% of the methane in the input simulated VAM to carbon dioxide. Benefits Three critical issues were resolved by this demonstration: 1) Designed a safe, effective interface between the RTO and the mine, 2) Verified the ability of the RTO to oxidize the low and variable concentrations of methane, effectively in long-term operation, 3) Completed an engineering/economic evaluation of the technology as applied to both methane oxidation and energy recovery. Accomplishments Startup and commissioning of the system were completed in Spring of 2007, as was the parametric experimental tests program, in which the system operating parameters were varied. Official unattended operation of the equipment began in May 2007 and continued until November 2007. During the seven months, 1300 hours of operation at 0.6% methane and a maximum flow rate of 30,000 scfm were logged. Modifications were made to the device to improve the operation, and the equipment was re-commissioned in April 2008. Long-term unattended operation continued from May 2008 to October 2008 with 2833 hours of operating hours. This equated to an equipment availability of 84%, excluding all “non-core” problems. Three emission test campaigns were conducted throughout the operating time that confirmed greater than 95% conversion of the feed methane to carbon dioxide and water. During the 13 months of operation, 894 short tons of methane emissions were reduced which is equivalent to 14,849 metric tonne of carbon dioxide. Accomplishments The demonstration project proved the RTO technology was viable for mitigating ventilation air methane. The full scale system on a mine bleeder fan is economically feasible when there is a value for greenhouse gas emission reductions. A positive return is possible at a carbon credit of $7.00/tonne CO2e. Adding power generation to the RTO system requires a higher value for carbon credits before it is economically feasible. The final report summarizing the experimental and economic results was submitted to DOE in September 2009. Plans The demonstration program described above is complete. However, CONSOL has partnered with Green Holdings Corporation to install and operate a commercial RTO system on an operating ventilation fan at CONSOL’s Enlow Fork mine in 2010. This will require approval from several regulatory agencies before installation of the equipment can begin.
Power Generation from Coal Mine Methane
Background CONSOL Energy Inc., Research & Development, in conjunction with Ingersoll-Rand Energy Systems and the Pennsylvania Department of Environmental Protection, installed an ultra-low-emission 70 kW microturbine generator on a large underground coal mine in Pennsylvania to reduce emissions of methane by capturing them and converting them into usable electricity. The unit was fueled with coal mine methane that was originally being vented as part of the mine’s ventilation system. Coal mine methane is one of several major sources of anthropogenic methane, accounting for about 10% of anthropogenic methane emissions in the United States. Methane is the second most important non-water greenhouse gas, with a global warming potential 21 times as great as that of carbon dioxide (CO2) on a mass basis. Thus, the coal mine methane that was utilized simultaneously represented a lost potential resource and an emission of a powerful greenhouse gas. Benefits: The project objectives were to: 1) convert the low and variable concentrations of methane contained in coal mine methane gas that would otherwise be vented to the atmosphere to electricity; 2) provide the generated electric power to an existing electric power grid; 3) donate the value of the electricity generated during the project period to a local school district; and 4) determine the quantity of useful energy that can be economically produced when processing coal mine methane from a working coal mine and perform a techno-economic evaluation of the system. When operating at 95% capacity factor and a heat rate of 13,550 Btu/kWh, the 70 kW generator would produce 583 MWh of electricity as it consumes 7,778,000 cubic feet of methane, with a net global warming potential equivalent to 3,001 short tons of carbon dioxide, each year. Accomplishments: The project was completed. Startup and commissioning of the system was completed in September 2006. Official unattended operation of the equipment began in October 2006 and continued until October 2007. The system performance was continuously monitored and evaluated through a web-based system. After twelve months of operation, the unit logged 4870 operating hours and generated a total of 330,027 kWh of electricity with an average capacity factor of 52.1%. Operating capacity was frequently curtailed because of excessively low methane concentration (<35%) in the mine gas. Operation of the microturbine prevented 4,345,000 cubic feet of methane from being emitted into the atmosphere, which equates to a net 1,672 short ton of CO2 equivalent. At the conclusion of the project, CNX Gas made a contribution of $8,581 to West Greene School District, which represented the value of the electricity that was generated for the year of operation. The technology as-installed in the demonstration test is not economically attractive without a subsidy. However, a sufficiently large carbon credit value ($6.00/ton CO2e) or a larger-size microturbine (250 kW) would allow this technology to be economical. Plans Bailey Preparation Plant personnel continue to operate the equipment at its original site. Due to low methane concentration (<35%) in the mine gas and required equipment maintenance, the unit had limited hours of operation in 2009.
Midwest Regional Carbon Sequestration Partnership (MRCSP)
Phase I, of the program (September 2004 through December 2005), CONSOL R&D had two roles:
Funding for Phase I included $14,000 costs share from CONSOL R&D and $69,000 from DOE (via Battelle as prime contractor).
The MRCSP team will then evaluate the amount and rate of carbon sequestration that has occurred and that will occur for several years on those lands. Funds for this work would include $228,000 of CONSOL R&D cost share and $298,000 of DOE (via Battelle as prime contractor) cost share Accomplishments CONSOL extended the depth of one core-hole well in Washington County, PA. A 2.85 inch core was drilled from ground level to 1554 ft below the surface to reach the Mississippian Formation. Below the Upper Freeport seam, seven coal seams were identified with thicknesses ranging from 0.55 ft to 3.3 ft. The coal cores were desorbed of methane (CH4) using the U.S. Bureau of Mines Direct Method. The methane desorbed ranged from 60 scf per ton of as-received coal to 194 scf/ton. Five of the coal samples were further tested to determine their storage capacity for carbon dioxide (CO2). Carbon dioxide Langmuir isotherms showed adsorption ranging from 354 scf/ton to 717 scf/ton on an as-received coal basis at the estimated pressure of the coal seam. The coals were capable of storing from 2.9 to 5.6 times as much CO2 as CH4 on a scf/ton of dry, ash-free coal. Petrographic properties of the coals ranked them as high-volatile A bituminous coals. The final report was submitted in April 2010. Partners and Costs The funds authorized for Phase II project activities include $85,000 from Battelle and $65,400 from CONSOL. To date, Battelle has spent $25,884 and CONSOL has spent $18,952.
Southeast Regional Carbon Sequestration Partnership (SECARB) Background CONSOL is one of the members in SECARB, one of seven regional partnerships sponsored partially by DOE to evaluate the potential for carbon sequestration to alleviate the emissions of greenhouse gases to the atmosphere. The Southern States Energy Board is the prime contractor to DOE and Marshall Miller and Associates is a subcontractor to SSEB charged with identifying potential sites in central Appalachia for a large-volume CO2 injection test to validate the carbon sequestration and enhanced coalbed methane recovery potential of the Central Appalachian Basin. CONSOL is a subcontractor to MMA and has the role of consultant on numerous tasks, including permitting, monitoring, verification, and assessment, injection design, etc. Status The two-year contract was signed with MMA in December 2008. CONSOL has completed a detailed assessment of the permitting requirements for drilling, operating, sealing and abandoning CO2 injection wells in Virginia. The final report on this activity is being prepared
FutureGen Background FutureGen is a government-industry cost-shared project to design, build, and operate a first-of-a-kind coal-fueled, near-zero emission power plant. The FutureGen power plant will be an integrated gasification combined cycle (IGCC) power plant equipped with a carbon capture and sequestration (CCS) system. It will produce electricity from coal while capturing and permanently storing 90% of the produced carbon dioxide (CO2) in a deep geologic formation. The nominal 275-megawatt prototype plant will operate as a production plant, generating commercially significant levels of electric power. It will also provide a large-scale engineering laboratory for testing new and clean power generation and CO2 capture. FutureGen will be the cleanest coal-fueled power plant in the world. On December 2, 2005, the U.S. Department of Energy (DOE) entered into a cooperative agreement with the FutureGen Alliance, Inc. (Alliance) to begin the site selection process and prepare a conceptual design for the facility. The Alliance consists of a group of 13 U.S. and international coal mining and power generation companies, including CONSOL Energy Inc. Accomplishments The site selection process resulted in the selection of a site in Mattoon, IL. The Alliance purchased the land for the power plant and the rights to allow the sequestration of CO2 into the subsurface. The Environmental Impact Statement was released in November 2007, and the Record of Decision (ROD) was released by DOE in July 2009 indicating that the project complies with the National Environmental Policy Act and allowing DOE to proceed with financial assistance. Approximately $1.1 billion has been allocated by DOE. The underground injection control permit request was submitted to the Illinois DEP in September 2009. The original conceptual design was refined into a preliminary plant design. Plans On the basis of the preliminary design, the budget, and finances, a go/no-go decision will be made on mid-2010. The FutureGen plant will be final-designed and erected over the four years following a “go” decision. The will be a four-year operating campaign during which 1 to 2.5 million tonnes per year of CO2 will be sequestered. This will be followed by a two-year post operation monitoring period.
Mountaineer Station Commercial-Scale CCS Project Background American Electric Power (AEP) is leading a team consisting of the U.S. Department of Energy National Energy Technology Laboratory, Alstom Power, Battelle Memorial Institute, Schlumberger Carbon Services, CONSOL, and others to design, build, and operate a 235 MW slipstream chilled ammonia carbon capture system on the existing 1300 MW coal-fired Mountaineer Power Station in New Haven, WV, and to sequester the captured CO2 into deep saline reservoirs. This ~$670MM project was awarded in January 2010 under Round III of the DOE Clean Coal Power Initiative. CONSOL is participating in two aspects of Phase 1 of the project. A CONSOL representative will chair the Geologic Experts Team, which is being assembled to provide advice to the project team on subsurface (i.e., sequestration, monitoring, verification, etc.) aspects of the project. CONSOL will also advise and assist the AEP team on administrative and technical reporting aspects of the DOE cooperative agreement, and will provide 20% cost share as a contribution to the project. Status The subcontract was signed with AEP in March 2009. The Geologic Experts Team is currently being organized.
In-Situ MVA of CO2 Sequestration Using Smart Field Technology CONSOL participates on the Industrial Advisory Committee for this project, which is primarily funded by West Virginia University (WVU) under their prime contract with the U.S. Department of Energy. CONSOL is also providing access to the site and data of its own CO2 sequestration field test in Marshall County, WV. CONSOL’s subcontract was signed with WVU in April 2010. CONSOL’s work is funded by CONSOL Energy ($6,031) and WVU ($24,125) under its DOE contract.
Southeast CO2 Sequestration Technology Training Program CONSOL participates as a consulting partner in this three-year project, which is one of the seven Regional Sequestration Technology Training Projects funded by the U.S. Department of Energy (DOE). Southern States Energy Board (SSEB) was selected for the prime award by DOE in August 2009. CONSOL’s subcontract with SSEB is not yet in place, but it is anticipated that CONSOL will provide $6,000 in supporting effort to this project.
PFBC Process Test Facility Background PFBC Environmental Energy Technology, Inc. (PFBC-EET) of Monessen, PA, and its project team have designed, constructed, and are currently operating a pilot scale Process Test Facility (PTF) at CONSOL R&D's R&D facility at South Park, PA. Pressurized Fluid Bed Combustion (PFBC) technology, the third generation of fluid bed development, was originally developed by Swedish-based ABB Carbon. PFBC-EET has licensed this technology from Alstom Power and Siemens to develop plants that will utilize wet fine coal waste from operating mines and from abandoned mine sites. PFBC is based on known, proven components: fluidized beds, and gas and steam turbines. It is a process for converting coal into power, with a number of benefits over conventional coal-fired plants. Benefits The pressurized, fluidized bed offers high combustion efficiency, independent of fuel heating value. The combined cycle process further increases efficiency. The fluidized bed inherently eliminates a high percentage of potential pollutants, avoiding the generation of thermal NOx while capturing SOx in the ash byproduct. This pilot plant was designed for the testing of process parameters and fuels. While small in size, the pilot plant’s main process operating parameters (bed temperature, pressure and height, and excess air) match those of a full-scale commercial plant. The plant tests combustion efficiency, sintering/fouling propensity, emissions, fuel screening, ash handling/utilization, all while yielding O&M information and acting as a platform for operator training. The results from the PTF can be used to give a direct prediction of a full-scale plant, as well as compare operating (or “calibration”) data from a commercial facility. Accomplishments The PTF was first operated November 30, 2006. Twenty-two one-day hot commissioning test runs were completed on CONSOL wet fine coal waste fuel and commercial coal in 2007 and 2008 to resolve equipment problems paste plugging and pumping problems. A 72-hour commissioning test run was completed March 2009, demonstrating continuous operation. A 72-hour “calibration” run was completed in July 2009 using the same coal and sorbent as the commercial Vartan plant in Stockholm, Sweden. Plans A Sargas CO2 capture pilot plant was recently integrated into the PTF and operated during the most recent test run. A slip stream of combustion flue gas from the PTF is sent to the Sargas unit to capture the carbon dioxide with a potassium carbonate solution. The project team is currently testing a biomass fuel consisting of waste coal blended with biomass (sawdust). Upcoming tests include a “commercial test” of a CONSOL waste fuel. Partners and Cost PFBC-EET's waste coal expertise comes from its partner Farnham & Pfile that designs and builds turnkey coal processing plants. Personnel from Alstom Power and Siemens are directly involved in the engineering and commissioning. CONSOL R&D has provided engineering assistance and operates and maintains the PTF. The total cost of the PTF program is estimated to be $4.5 to $5.5 million. Federal and State grant money, totaling $3M, supplement investments from the partners.
PFBC CO2 Capture Pilot Test Program Background PFBC Environmental Energy Technology, Inc. (PFBC-EET) of Monessen, PA, with its partners CONSOL Energy, Inc. and Sargas AS submitted a proposal to the PA Energy Development Authority (PEDA) to demonstrate a carbon dioxide capture technology for the aforementioned PFBC PTF located at CONSOL R&D’s site in South Park, PA. The flue gas from the PFBC combustor, in comparison with conventional coal plants, has lower mass flow, lower volumetric flow, higher pressure, higher CO2 partial pressure, and very low excess oxygen content. It is therefore well suited for integration with proven potassium carbonate CO2 capture technology such as that offered by Sargas. Benefits The next phase of emissions controls for power generation will likely be for carbon dioxide. The combination of pressurized fluidized-bed combustion (PFBC) technology with CO2 capture will not only remove waste coal impoundments from the Commonwealth, but also utilize their energy content for electricity generation with the lowest emissions and greatest efficiency as compared to other, atmospheric pressure, power generation technologies. Accomplishments PFBC-EET was awarded $1.64M in PEDA grants to install a slip-stream CO2 capture pilot plant. Sargas integrated a slip stream pilot plant on the PFBC pioot plant at CONSOL’s R&D site. Initial testing showed that the system gave very high CO2 removal efficiency and very high CO2 quality. A 50-hour commissioning test of the integrated PFBC and Sargas units was completed May 6, 2010 with a blend of waste coal and biomass (sawdust). This test run was designed to demonstrate that such a system can be “carbon neutral”; i.e., that it will emit no net CO2. Some of the captured CO2 was pressurized and stored for later testing. Plans It is planned to use the captured and pressurized CO2 as a carbon source for growing algae. Partners and Cost Pennsylvania grants, totaling $1.64M, supplement investments from PFBC-EET and CONSOL.
The Steubenville Comprehensive Air Monitoring Program (SCAMP)
Background The Steubenville Comprehensive Air Monitoring Program (SCAMP) was a $6.35 million ambient air monitoring and exposure characterization program focusing on fine particulate matter (PM2.5) in Steubenville, Ohio, and the surrounding region. Steubenville was chosen for the study because of its historically elevated ambient PM2.5 concentrations, and because it was one of the six cities examined by the landmark Harvard Six Cities Study, which reported an association between PM2.5 and mortality and served as a driving force for the promulgation of the PM2.5 National Ambient Air Quality Standards (NAAQS). SCAMP included two interrelated components. As part of the ambient air monitoring component, which was led by CONSOL Energy Inc. Research & Development, PM2.5 mass, PM2.5 composition, gaseous pollutant concentrations, and meteorological conditions were measured from May 2000 through May 2002 at a central outdoor monitoring site in Steubenville. PM2.5 mass and composition were also determined during this period at four surrounding satellite sites. As part of the indoor and personal exposure component, which was led by the Harvard School of Public Health, personal, indoor, and outdoor exposures to PM2.5, PM2.5 components, and gaseous pollutants were characterized for a panel of older adults and a panel of children living in Steubenville. Each panel was monitored in two distinct seasons during the 2000-2001 period. The program also provided data to support concurrent studies evaluating the health effects of PM2.5 and gaseous pollutants. Each panel was monitored in two distinct seasons during the 2000-2001 period. The program also provided data to support concurrent studies evaluating the health effects of PM2.5 and gaseous pollutants. Benefits The NAAQS for PM2.5 are based on measurements made at outdoor monitoring stations. However, most people spend the majority of their time indoors. To fully understand the relationship between ambient PM2.5 and human health effects, there is a need to define how ambient concentrations of PM2.5, its chemical components, and co-pollutants compare to those actually breathed by humans during normal daily activities. Moreover, because the NAAQS require reductions in ambient PM2.5 concentrations in many areas of the United States, including Steubenville, there is a need to better understand the factors (e.g., anthropogenic and natural sources, meteorological conditions, etc.) that affect these concentrations so that effective State Implementation Plans (SIPs) can be developed. SCAMP responded to both of these needs, and contributed important conclusions regarding the temporal and spatial variability of PM2.5, the effect of meteorology and various emission sources on PM2.5 concentration and composition, the potential for confounding by gaseous pollutants in PM2.5 epidemiology studies, and the relationships between outdoor concentrations and personal exposures to PM2.5 and gaseous pollutants. Accomplishments The final report for SCAMP was issued in 2007. Results from the project were presented in eight peer-reviewed journal articles and 22 conference proceedings. The project also generated a comprehensive database of air quality and exposure information for use in subsequent epidemiological studies, long-range transport studies, and State Implementation Plan development.
Design and Feasibility Assessment of a Retrospective Epidemiologic
Study of Coal-Fired Power Plant Emissions in the Pittsburgh, PA, Region Background CONSOL R&D collaborated with a team led by the University of Pittsburgh's Graduate School of Public Health to develop a strategy to better define the possible public health implications of airborne fine particulate matter (PM2.5) originating from coal-fired power plants and other emission sources in the Pittsburgh region. The team also included Ohio University and the Allegheny County Health Department. The goal of this project, which was sponsored by the U.S. Department of Energy's National Energy Technology Laboratory, was to determine whether a retrospective epidemiological study can be conducted to elucidate the health implications of chemical components of PM2.5 that originate from various types of emission sources in the Pittsburgh region. The project included an inventory of health endpoints data available for the Pittsburgh region, which was assembled by the University of Pittsburgh, as well as a comprehensive inventory and assessment of air quality data collected in the region since 1999, which was performed by CONSOL . CONSOL also worked with the project team to evaluate the applicability of advanced statistical techniques that may permit a better assessment of the associations between PM2.5 emission sources and health outcomes, while controlling for confounding explanatory factors. Benefits In 1997, the U.S. Environmental Protection Agency (EPA) promulgated new National Ambient Air Quality Standards (NAAQS) for PM2.5, based largely upon epidemiological evidence that suggests an association between total ambient mass concentrations of PM2.5 and adverse human health effects. More recently, in September 2006, a more stringent 24-hr NAAQS for total PM2.5 mass was adopted by the EPA. However, fine particulate matter is a complex mixture of many diverse chemical constituents, and it is still unclear whether a subset of these constituents, rather than total particle mass, is responsible for the observed health effects. The epidemiology study design developed as part of this project contributes an innovative method for elucidating the health effects of individual chemical constituents of PM2.5 by leveraging data that have already been collected in the Pittsburgh region, thereby providing a cost-effective way to address a PM2.5 research need that has major public policy implications. Accomplishments The project was completed in December 2006. The team determined that it would be feasible to conduct a retrospective epidemiological study to assess possible health effects of PM2.5 from coal-fired power plants and other sources in the Pittsburgh region, and developed a detailed design for such a study. The design includes the use of sophisticated geostatistical and latent variable modeling techniques to develop exposure estimates from PM2.5 and co-pollutant data. Plans were developed to chemically analyze archived PM2.5 samples in order to generate additional PM2.5 speciation data for the Pittsburgh region during the time period of interest. Innovative statistical techniques will also be used to estimate the associations between PM2.5 and health outcomes. The Electric Power Research Institute is now funding the University of Pittsburgh and CONSOL to perform an actual retrospective epidemiology study based on the design developed as part of the DOE-sponsored feasibility assessment. (See the project description on the next page). Plans The team is now seeking funding to carry out an actual retrospective epidemiology study based on the design developed as part of the DOE-sponsored feasibility assessment.
The Pittsburgh Aerosol Research and Inhalation Epidemiology Study Background The Pittsburgh Aerosol Research and Inhalation Epidemiology Study (PARIES) will provide the first-ever large-scale characterization of the health effects of airborne fine particulate matter (PM2.5) and its chemical components in the Pittsburgh region by leveraging existing air monitoring and health outcomes data that have been collected in the region since 1999. The feasibility of conducting a retrospective epidemiology study using these data was evaluated and confirmed as part of a DOE-funded project described on the previous page. This retrospective time-series study will focus on three counties in southwestern Pennsylvania – Allegheny, Washington, and Westmoreland – that have a combined population of about 1.8 million (2006). Associations of PM2.5 mass and co-pollutant (i.e., PM10-2.5, SO2, CO, O3, NO2) concentrations with human health will be studied over an approximately 8-year period (1999-2006); and associations of PM2.5 chemical components (e.g., sulfate, nitrate, elemental carbon, organic carbon, and various trace and crustal elements) with human health will be studied over a 5-year period (August 1999 – August 2004). The project is being led by the University of Pittsburgh, with funding provided by the Electric Power Research Institute (EPRI). CONSOL is a subcontractor to the University of Pittsburgh and is responsible for assembling the database of daily air monitoring data that will be used to estimate exposures in the study. The database is being constructed from existing datasets and from the results of the chemical analysis of archived PM2.5 samples that were collected in the region during the time period of interest. CONSOL will also assist the University of Pittsburgh with statistical analyses and with interpreting the results of the study. Benefits In 1997, the U.S. Environmental Protection Agency (EPA) promulgated new National Ambient Air Quality Standards (NAAQS) for PM2.5, based largely upon epidemiological evidence that suggests an association between total ambient mass concentrations of PM2.5 and adverse human health effects. More recently, in September 2006, a more stringent 24-hr NAAQS for total PM2.5 mass was adopted by the EPA. However, fine particulate matter is a complex mixture of many diverse chemical constituents, and it is still unclear whether a subset of these constituents, rather than total particle mass, is responsible for the observed health effects. The PARIES study will elucidate the health effects of individual chemical constituents of PM2.5 by utilizing sophisticated statistical techniques to leverage tens of millions of dollars worth of data that have already been collected in the Pittsburgh region, thereby providing a cost-effective way to address a PM2.5 research need with major public policy implications. Accomplishments Work on the project began in early 2009. The existing air monitoring data and archived PM2.5 samples that are required for the study have been obtained. CONSOL is now working to chemically analyze the archived samples and to construct the air monitoring database that will be used to represent exposures in the study. Plans CONSOL will complete the archived sample analyses and air monitoring database development in 2010 and 2011. Meanwhile, the University of Pittsburgh will assemble health outcomes data and validate the statistical techniques that will be used in the study. Statistical analyses and data interpretation will be completed in 2011-2012. The overall project is expected to be completed in 2012.
The Evaluation of the Emission, Transport and Deposition of
Mercury, PM2.5, and Arsenic in the Ohio Valley from Coal-Fired Power Plants Background CONSOL Energy Inc. collaborated with Ohio University, the U.S. Department of Energy, and ATS Chester on a $1.5 million project titled “The Evaluation of the Emission, Transport and Deposition of Mercury, PM2.5, and Arsenic in the Ohio Valley from Coal-Fired Power Plants.” The objective of the program was to assess the contribution of coal-fired power plants to ambient concentrations of mercury, PM2.5, and arsenic in the Ohio River Valley. In addition, it included an evaluation of the influences of meteorology, season, time, and emission sources (both local and regional) on mercury, PM2.5, and arsenic concentrations. Ambient mercury concentrations, mercury wet deposition, ambient PM2.5 mass and chemical speciation, gaseous pollutant concentrations, and meteorological conditions were monitored in 2004 and 2005 at a surface air monitoring station in Athens, Ohio, for use in the evaluations. CONSOL oversaw the sampling and analytical components of the program as a subcontractor to Ohio University. Benefits The research contributes significant insight into factors that affect mercury deposition and airborne mercury, PM2.5, and arsenic concentrations in the Ohio Valley. In addition, the data collected as part of the project are being used to validate a regional-scale pollution model that was developed concurrently with the data collection tasks. The model will be offered to industry and policymakers for use in developing control strategies for mercury, PM2.5, and arsenic. Accomplishments CONSOL’s scope of work, including all air monitoring, laboratory analyses, and descriptive data analyses, is complete. Preliminary results from the Athens monitoring site were published in a peer-reviewed journal article. Ohio University is now working to complete the regional-scale pollution modeling tasks using the data from the Athens site.
High-Purity Hydrogen Production with In-Situ Carbon Dioxide and Sulfur Capture in a Single-Stage Reactor Background Pure hydrogen is a potential energy carrier for the future, and it may be produced from hydrogen-containing materials such as water and fossil fuels. Coal is a likely feedstock for large-scale hydrogen production in the United States, because it is an abundant domestic resource and offers the potential to generate hydrogen in an economically competitive way. The Ohio State University (OSU) is developing a Calcium Looping Process (CLP) to produce high-purity hydrogen from coal-derived synthesis gas in a single-stage reactor. The process uses a calcium-based sorbent to remove carbon dioxide from synthesis gas by forming calcium carbonate. The calcium carbonate is then calcined to produce a pure stream of carbon dioxide, which can be sent for sequestration, and calcium oxide, which is recycled for reuse in the process. The continuous removal of carbon dioxide enhances the "water-gas shift" reaction - the conversion of synthesis gas and water into hydrogen and carbon dioxide - and improves the purity and yield of hydrogen. Hydrogen sulfide and hydrogen halides are also removed by the calcium-based sorbent. CONSOL Energy is performing techno-economic evaluations to guide and assess the process development effort. Benefits The large-scale production of hydrogen from coal faces several technological challenges that must be overcome before its widespread use becomes a reality. This centralized, large-scale approach will combat climate change by allowing for the capture, and subsequent sequestration, of carbon dioxide generated during hydrogen production. The concept would also be applicable to electric power generation via IGCC with carbon capture. The novel OSU approach is one of several being developed at the pre-commercial stage. Accomplishments The project began in 2007. CONSOL worked with OSU throughout 2008 and 2009 to develop the flow sheet for the Calcium Looping Process and to perform process simulations. A preliminary techno-economic evaluation was completed in early 2010, and it indicated that the CLP has the potential to reduce the cost of producing hydrogen from coal. Initial results from the project have been presented at several national or international technical conferences. Plans OSU is constructing a 25 kWt fluidized-bed reactor for use in further testing the performance of the Calcium Looping Process. CONSOL will update the techno-economic evaluation to incorporate experimental data from this reactor. CONSOL is also completing sensitivity analyses for the coal-to-hydrogen case and performing techno-economic evaluations for several alternate applications of the CLP, including its application to an IGCC plant for electricity production and its application to a steam methane reforming plant for hydrogen production. The project is scheduled to conclude in late 2010.
Coal Direct Chemical Looping Retrofit for Pulverized Coal-Fired Power Plants with In-Situ CO2 Capture Background The Ohio State University (OSU) is developing a Coal Direct Chemical Looping (CDCL) technology to facilitate carbon dioxide capture from coal-fired power plants. Unlike conventional combustion processes, the CDCL process never permits the coal to mix with the combustion air. Rather, a patented, regenerable, iron oxide-based carrier particle is circulated between an air reactor, where it is oxidized by reaction with oxygen contained in air, and a fuel reactor, where it is reduced by reaction with coal. Because the coal never contacts the air, the fuel reactor produces a relatively pure CO2 stream that can be sequestered without the need for costly downstream CO2 capture processes. The U.S. Department of Energy is funding OSU to develop the CDCL technology through experimental testing at the bench and sub-pilot scales. CONSOL Energy has been subcontracted by OSU to develop a techno-economic model for evaluating the retrofit application of the CDCL process to pulverized-coal power plants. Model results will be used to guide the development of the process. Benefits Coal-fired power plants are a major source of carbon dioxide emissions, and it is becoming increasingly likely that future legislation or regulations will require a reduction in these emissions. Although it is technically feasible to capture CO2 from coal-fired power plants using commercially available or near-commercial technologies, current state-of-the art technologies have very high capital and operating costs and consume a large portion of the energy generated by the plant. Hence, there is a need for new approaches that enable CO2 to be captured with less impact on a plant’s efficiency and cost of producing electricity. The CDCL concept is one of several innovative, emerging technologies that show potential for meeting this need. Accomplishments The project began in January 2009. OSU conducted experimental work throughout the first project year to improve the iron oxide-based carrier particle and determine optimum process operating conditions. Work on developing the techno-economic model is now beginning. Plans CONSOL will complete an initial techno-economic evaluation of the CDCL process in 2010. The evaluation will then be refined as additional experimental data become available, and the results will be used to guide improvements to the process design. The project is scheduled to conclude in December 2011.
Pilot Scale Testing of the Carbon Negative, Product-Flexible Syngas Chemical Looping Process Background The Ohio State University (OSU) is developing a Syngas Chemical Looping (SCL) process for converting coal into electricity, hydrogen, or liquid fuels with zero or negative net CO2 emissions. As with the Coal Direct Chemical Looping Process, the SCL process is based on the use of iron-based oxygen carrier particles. In Syngas Chemical Looping, however, the iron oxide particles react with syngas produced by gasifying the coal, rather than with the coal itself. The process consists of three main reactors: the reducer, the oxidizer, and the combustor. The syngas, which contains carbon monoxide and hydrogen, is sent to the reducer, where it reacts with iron(III) oxide (Fe2O3) to form carbon dioxide, water vapor, and reduced iron particles (Fe or FeO). The reduced iron particles are transferred to the oxidizer, where they are partially oxidized by reacting with steam to form Fe3O4 and hydrogen. Finally, the Fe3O4 is further oxidized to Fe2O3 by reacting with air in the combustor, completing the chemical loop. The hydrogen produced in the oxidizer can be sold commercially or used to produce electricity. If biomass is blended with the coal, the process can achieve negative net CO2 emissions. The SCL process can also be integrated with the Fischer-Tropsch process to produce liquid fuels and chemicals from coal. OSU has successfully tested the SCL process at the bench (2.5 kW) and sub-pilot (25 kW) scales. The Advanced Research Projects Agency-Energy (ARPA-E) is now funding a pilot-scale (250 kW) demonstration of the process at Southern Company’s Power Systems Development Facility. As part of this project, OSU will let a subcontract to CONSOL to evaluate the technical and economic performance of various configurations of the SCL process. Benefits Given the prospect of mandatory reductions in greenhouse gas emissions, numerous technologies are being evaluated for reducing the cost and energy penalty associated with capturing CO2 from coal-based power plants. The SCL process provides a unique new pathway for producing electricity from coal, with zero or negative net CO2 emissions. This pathway shows potential for improving the economics and efficiency of CO2 capture. Successful development of this versatile technology could also open new opportunities for utilizing coal as a feedstock for hydrogen, liquid fuels, or other chemicals, improving energy security in the U.S. Accomplishments ARPA-E selected the project for award in October 2009, and the project officially began in April 2010. Plans CONSOL expects to begin subcontract negotiations with OSU in mid-2010. Work on the project will continue through 2013.
Selection and Characterization of Illinois Coals for Use in the C-Foam Process Background Touchstone Research Laboratory, Ltd. (TRL), with partial funding from the Illinois Clean Coal Institute, evaluated the use Illinois coals as feedstocks for its C-Foam process. TRL subcontracted CONSOL Energy to advise and consult in the selection, procurement, and characterization of various Illinois coals. The C-Foam process produces carbon foam that has a myriad of potential applications in the defense, aeronautic, and construction industries. Benefits Before this project, acceptable C-Foam product had only been produced from Appalachian Basin bituminous coals., but Illinois Basin coal has never been evaluated as a feedstock. Accomplishments Four samples of Illinois coal were secured from several Illinois mines. The samples were analyzed by CONSOL for chemical, thermoplastic, and petrographic properties, and shipped to TRL for production of C-Foam. CONSOL’s work was completed in 2009. Plans Test
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