Energy & Environmental Research Center Research Articles

Enhanced oil recovery through alternating gas Re-injection to reduce gas flaring in the Bakken

Environmental performance is a significant driver of energy production today, and providing attractive methods to reduce flaring remains a high priority for oil producers. The Energy & Environmental Research Center (EERC), with support from the Bakken Production Optimization Program (BPOP), is investigating the reinjection of the associated gas into producing wells to reduce flaring.The project's main objectives are to evaluate technically and economically the feasibility of deploying alternating gas re-injection in the Bakken formation as a means to increase oil recovery, reduce flaring and maintain compliance. The approach addresses the compression capacity constraints, mineral ownership types, and gas availability. Gas reinjection has the added benefit of producing incremental oil that can offset installation and operational costs associated with gas compression and nonproducing time for a well during injection. A flow simulation model is created to investigate alternating gas injection of a four-well pad and to assess the possibility of incremental oil production. Extensive numerical simulation is conducted. Capital expenditure, operating costs and the revenue from oil recovery were considered. Results indicate that gas injection within rates of 100–200 Mcfd can produce incremental oil. The gas volume needed is greater than what is typically flared from a facility, however, less than the total produced gas volume, and, therefore, possible. Communication of gas is likely to occur between wells within 1500 feet and wells positioned heel to heel that are common to the well-pad facility. The most promising injection period appeared to be within a 2-week to 1-month cycle. Thus, the proposed approach can be employed as an efficient Enhanced Oil Recovery (EOR) technique, alternating gas injection of 3 MMcfd may potentially increase the produced oil rate by 70 %. The findings support continued work to further investigate well configurations that can best benefit from the technique and to mature economic case studies.

Application of Active Reservoir Management to Enable Geologic CO2 Storage

Active reservoir management (ARM) can enhance geologic CO2 storage activities via strategic extraction of formation water and can provide site operators with a means of managing risks and costs associated with carbon capture, utilization, and storage (CCUS) projects. Implementation of ARM strategies for CCUS can provide several advantages to a project, including 1) reducing stress on sealing formations and separating pressure from the CO2 footprint; 2) geosteering of injected fluids away from hazards or permitted storage facility boundaries; 3) reducing area of review (AOR) and/or amalgamated lease area; and 4) improving injectivity, capacity, and storage efficiency to reduce infrastructure and operating requirements. The Energy & Environmental Research Center (EERC) is conducting field tests of ARM strategies for CCUS at a commercial saltwater disposal facility in western North Dakota, USA. Ongoing commercial injection of oilfield produced brine serves as a proxy for CO2 injection at the site. Initial interference testing has substantiated connectivity between project wells and that extraction response should be observable in the injection wells. A water treatment development and test facility has also been established at the North Dakota Brine Extraction and Storage Test (BEST) site to enable the development and demonstration of new and emerging water treatment technologies on produced or extracted waters. The test bed facility enables pilot testing, demonstration, and performance monitoring of novel water treatment technologies capable of treating high-salinity (average of 180,000 mg/L total dissolved solids [TDS]) fluids associated with CO2 storage in deep saline formations (DSFs).

First North Dakota CCS Project: Advancing North Dakota Ethanol Economics

The Energy & Environmental Research Center (EERC), in partnership since 2016 with North Dakota ethanol producer Red Trail Energy (RTE), the North Dakota Industrial Commission (NDIC), the U.S. Department of Energy, and Trimeric Corporation, has determined that commercial carbon capture and storage (CCS) is a technically viable option for the significant reduction of CO2 emissions from ethanol production at the RTE site near Richardton, North Dakota. In addition, CCS may be economically viable for RTE should pathways be approved for this lower-carbon-intensity ethanol in developing low-carbon fuel (LCF) programs. Current activities are allowing project partners to move closer to creating the first integrated CCS effort in North Dakota. Capture Facility Moves Closer to Construction. Project partner, Trimeric Corporation, developed process flow diagrams (PFDs), heat and material balances, piping and instrumentation diagrams (P&IDs), and utilities documents specific to the RTE project site to prepare a bid package for potential vendor response. Three vendor bids for the potential liquefied CO2 system were received and evaluated. A CO2 capture process design package document was developed, compiling the PFDs, heat and material balances, and P&IDs, including recommendations from the vendor bids received. Geophysical Survey Provides More Clarity of the Subsurface. An 8-square-mile 3-D geophysical survey was conducted at the RTE site near Richardton, North Dakota, in March 2019. Data processing and interpretation from the seismic acquisition survey have been completed. Results were incorporated into the geologic modeling simulation efforts from the first stage of the project to determine recommended locations for the future stratigraphic test. Baseline Near-Surface Monitoring Begins. The EERC is investigating seasonal changes related to the natural carbon cycle of regional soil and groundwater in the study region near Richardton, North Dakota. Groundwater- and soil gas-monitoring activities included meter readings on location as well as sample collection for a full suite of laboratory analyses to establish natural water and soil gas conditions through several seasons. Three sampling events were conducted in May, August, and November 2019. Preparing the First North Dakota Underground Injection Control (UIC) Class VI Permit Application. North Dakota’s Class VI Program requires all owners/operators applying to inject CO2 for the purpose of geologic storage to obtain a storage facility permit, a permit to drill, and a permit to operate prior to commencement of injection activities. The storage facility permit covers multiple design aspects such as technical evaluation, area-of-review delineation, a corrective action plan, an emergency and remedial response plan, a casing and cementing program, a testing and monitoring plan, a well-plugging plan, and a postinjection site care and facility closure plan. Draft plans are currently under development using existing regional data available and the recently acquired seismic survey results. The permit-to-drill application for a stratigraphic test hole was also prepared, submitted, and approved in December 2019. Results from the test hole will provide the necessary data to finalize the storage facility permit for submittal. Building CCS Support in North Dakota Through Outreach. Significant outreach activities for this rural North Dakota project have included two community open houses, presentations at local commission meetings, and maintaining up-to-date materials to communicate project information and progress. The first open house was organized and held in March 2019. About 30 community visitors were hosted, including participation by the EERC, RTE, and North Dakota permitting agents; feedback was generally positive and supportive for the project. RTE and the EERC also presented at county and city commission meetings several times throughout 2019. Outreach materials were prepared such as a RTE CCS fact sheet, Geophysical Survey FAQs and Sampling FAQs, and Geophysical Survey Results. A follow-up open house was conducted in December 2019. Next Steps in 2020: Drilling a Stratigraphic Test Hole. A next step in development toward implementation is to drill a stratigraphic test hole at the RTE site by summer 2020. The EERC will provide technical assistance to conduct reservoir characterization through analysis of collected core and interpretation of downhole tests from the drilling effort. Downhole monitoring technology will also be installed to begin collection of baseline data. These activities will generate the necessary scientific data for CO2 storage predictions and development of the numerous plans (e.g., monitoring, testing, reporting, etc.) required to finalize the first North Dakota Class VI Program permit application.

The PCOR Partnership Initiative: The State of the Region

The PCOR Initiative, a 5-year project beginning in early 2020, is one of four newly selected regional initiative awards funded by the U.S. Department of Energy (DOE). The PCOR Initiative will accelerate the deployment of carbon capture, utilization, and storage (CCUS) in the central and northwestern region of North America, comprising ten U.S. states and four Canadian provinces. With extensive fossil fuel resources, large-scale anthropogenic CO2 sources, and geologic storage options, this region provides all of the essential elements necessary for infrastructure development and widespread CCUS deployment. The project builds on 16 years of applied research undertaken by the Plains CO2 Reduction (PCOR) Partnership throughout the northern Great Plains, including the successful assessment and monitoring of over 6 million metric tons of associated CO2 storage, incidental to enhanced oil recovery (EOR) operations at the Bell Creek oil field in southeastrn Montana. Managed by the Energy & Environmental Research Center (EERC) in Grand Forks, North Dakota, the PCOR Initiative is supported by the North Dakota Industrial Commission, through the Oil and Gas and Lignite Research Programs, and by research partners at the University of Alaska at Fairbanks and the University of Wyoming. Many of the 120+ previous PCOR Partnership member organizations are supporting this new initiative, with additional members also expected. Our team also includes the partners associated with Project Tundra, which constitutes the largest planned capture of CO2 in the world from a power generation facility. With many partners actively engaged in commercial projects, the PCOR Initiative draws together a powerful team to advance and accelerate CCUS deployment in the region and satisfy the objectives put forth by DOE. The PCOR Initiative will identify and address onshore regional storage and transport challenges facing commercial deployment of CCUS within its region. To achieve this, the PCOR Initiative will 1) address key technical challenges by advancing critical knowledge and capabilities; 2) facilitate data collection, sharing, analysis, and collaboration; 3) evaluate regional infrastructure challenges and needs; and 4) promote regional technology transfer. The PCOR Initiative will engage federal and state regulators in the region to support the continued development and knowledge transfer of regulatory policies to accelerate the deployment of CCUS. The regulatory efforts will focus on understanding the federal and state permitting processes and timing and address major regulatory topics, including pore space ownership, practical approaches to defining the area of review, and management of the long-term liability associated with a closed storage site. The PCOR Initiative will facilitate dialogue regarding the status of CCUS projects and regulatory challenges, with an emphasis on knowledge transfer between states with active CCUS projects and Class VI primacy and states with less CCUS development and no CCUS regulations established. North Dakota is the only state currently with Class VI primacy, and Wyoming has a pending Class VI primacy application. These states can provide valuable insight to other states by sharing their learnings from the Class VI primacy application process and Class VI regulatory program implementation at the state level. The expected outcomes of the PCOR Initiative include: • Solving technical challenges through collaboration, and addressing issues including stacked storage; storage optimization; effective monitoring, verification, and accounting strategies; and risk assessment resulting in increased regulator and industry confidence. • Advancing knowledge transfer and data sharing to develop key technologies, including National Risk Assessment Partnership tools and machine-learning applications, through collaboration with the DOE National Laboratory Network complex. • Accelerating CCUS through the evaluation and promotion of infrastructure requirements, building stakeholder support through techno- and socioeconomic assessments. • Promoting regional technology transfer to accelerate infrastructure development and deployment of CCUS, and building regulatory confidence and supporting business case developments that support the CCUS goals of the DOE Fossil Energy Program.

Application of CO2 injection monitoring techniques for CO2 EOR and associated geologic storage

The Energy & Environmental Research Center (EERC), through its efforts leading the Plains CO2 Reduction (PCOR) Partnership, has successfully developed practices and technologies that can be used in future commercial-scale CO2 storage projects in different geologic formations, including both dedicated CO2 storage in saline formations and associated CO2 storage incidental to enhanced oil recovery (EOR). In this work, reservoir monitoring activities have been conducted in a large-scale CO2 EOR project to understand performance and associated storage. The activities include pulsed-neutron well logs (PNLs), 4D (time-lapse 3D) seismic surveys, and numerical simulation of injection and production. This enabled monitoring at different scales, from individual wells to field-scale reservoir assessments. The oil, water, and CO2 saturations were profiled to identify bypassed oil and high-conductivity CO2 migration pathways in the reservoir. These techniques provided actionable information, enabling better management of CO2 flooding, diagnosing performance and sweep efficiency while ensuring injected CO2 remained within the reservoir.

Coal drying study for a direct syngas fired supercritical CO2 cycle integrated with a coal gasification process

The Allam Cycle is a semi-closed, oxy-fuel, supercritical carbon dioxide (sCO2) Brayton power cycle fueled with natural gas or syngas derived from coal, biomass or other carbonaceous fuels, offering advantages over simple cycle and combined cycle arrangements. For the coal based Allam Cycle, a gasification system is required to convert coal to clean syngas for downstream power generation. These systems require heat input to dry as-delivered coal to certain specifications. Produced steam is typically used for this purpose, but since the Allam Cycle is based on use of sCO2, and not steam, it is preferable to utilize alternative methods for coal drying. An experimental study was carried out at Energy & Environmental Research Center (EERC) to determine the heat energy required for drying lignite coal down to moisture levels acceptable for the operation of different gasifiers (range of moisture levels inserted here), and to investigate the effect of the heat transfer medium (steam and/or N2) and heat transfer type (direct or indirect) on the lignite drying performance. The results show that optimal operating temperature of coal drying is 90 °C. For direct heating system, the result shows a relatively linear trend of drying energy versus the coal’s moisture content, and the drying data suggests that individual parameters of velocity, residence time, and bed temperature are of secondary importance compared to how they combine to determine energy transfer to the coal. When the results of the direct heating tests using different heat transfer medium were compared, they were in good agreement, in that they indicate an approximate heat of evaporation around 2791.2 kJ/kg moisture removed. The energy consumption of the indirect heating steam coil tests is about 4652–5815 kJ/kg moisture removed, which is much higher than direct heating test data since not all the steam can condense at the exit of the steam coil. All the test results are important for designing the lignite drying process for the Allam Cycle. In the coal based Allam Cycle power generation system, low grade energy at the temperature of 70–100 °C from the turbine exhaust stream is sufficient for the coal drying process. Nitrogen from air separation unit can be used via direct heating and coal fluidization medium. For an indirect heating coal dryer system, a closed loop high pressure water system can be designed to transfer low grade heat from turbine exhaust stream to the dryer to remove moisture from coal.

An Improved Numerical Modeling and Simulation Study of the Aquistore CO2 Storage Project

The Plains CO2 Reduction Partnership (PCOR) Program, led by the Energy & Environmental Research Center (EERC), regularly updates a numerical model of the Aquistore storage site and conducts simulation work as more injection and monitoring data become available for integration. The significance of the latest work presented in this paper is related to the integration of periodic monitoring data (CO2 flow profile at the injection well and CO2 breakthrough profile at the observation well) into the history-matching workflow using an assisted history-matching workflow to calibrate the simulation model further and provide a better predictive model to help optimize CO2 storage performance.

Integrated CCS Pre-Feasibility Study For Western Nebraska

The Energy & Environmental Research Center (EERC) has conducted a pre-feasibility study for a commercial-scale carbon dioxide (CO2) geologic storage complex in western Nebraska, integrated with potential CO2 capture at the coal-fired Gerald Gentleman Station (GGS). This pre-feasibility project has been executed as part of the U.S. Department of Energy (DOE) CarbonSAFE (Carbon Storage Assurance Facility Enterprise) Program, where projects are required to demonstrate the potential to capture and store at least 50 million tonnes (Mt) of CO2 over a minimum 25-year operational period. Using publicly available data, this study has shown that western Nebraska has potential to host a commercial-scale carbon capture and storage (CCS) project. However, three key challenges would need to be overcome. Firstly, the business case for deploying CCS projects is uncertain; recently announced federal tax credits and sales for enhanced oil recovery might not cover full project costs. Secondly, the potential dedicated storage site defined in this study is at a low level of readiness to support a CCS project. Thirdly, public outreach would be a vital element in western Nebraska, where sensitivities around such environmental issues as water resource protection and pipeline construction would need to be carefully addressed.

Pre-feasibility study of CCS in western Nebraska

The Energy & Environmental Research Center (EERC) has conducted a pre-feasibility study for a commercial-scale carbon dioxide (CO2) geologic storage complex in western Nebraska, integrated with potential CO2 capture at the coal-fired Gerald Gentleman Station (GGS). This pre-feasibility project has been executed as part of the U.S. Department of Energy (DOE) CarbonSAFE (Carbon Storage Assurance Facility Enterprise) Program, where projects are required to demonstrate the potential to capture and store at least 50 million tonnes (Mt) of CO2 over a minimum 25-year operational period.Using publicly available data, this study has shown that western Nebraska has potential to host a commercial-scale carbon capture and storage (CCS) project. However, three key challenges would need to be overcome. Firstly, the business case for deploying CCS projects is uncertain; recently announced federal tax credits and sales for enhanced oil recovery might not cover full project costs. Secondly, the potential dedicated storage site defined in this study is at a low level of readiness to support a CCS project. Thirdly, public outreach would be a vital element in western Nebraska, where sensitivities around such environmental issues as water resource protection and pipeline construction would need to be carefully addressed.

Reducing the Carbon Footprint of Coal-to-liquids Technologies Through Coal–biomass Gasification

The Energy & Environmental Research Center (EERC) is providing gasification test support to the Connecticut Center for Advanced Technology, Inc. and the U.S. Defense Logistics Agency toward development of alternative liquid fuel options for U.S. military applications. The EERC is testing of various gasification systems to obtain data on fuel effects, syngas composition, gas cleanup, liquid fuel production, and system operation. Testing has been performed using two existing gasifiers at the EERC: the transport reactor development unit and the entrained-flow gasifier. This paper summarizes results of testing and the technology impacts on carbon footprint.

Characterization and time-lapse monitoring utilizing pulsed-neutron well logging: associated CO2 storage at a commercial CO2 EOR project

Abstract The Plains CO 2 Reduction (PCOR) Partnership, led by the Energy & Environmental Research Center (EERC), is working with Denbury Onshore LLC (Denbury) and Schlumberger Carbon Services to study monitoring, verification, and accounting (MVA) of CO 2 storage associated with a commercial enhanced oil recovery project at the Denbury-operated Bell Creek oil field located in southeastern Montana. MVA techniques such as time-lapse pulsed-neutron logs (PNLs) have helped to update the local stratigraphy, guide a repeat vertical seismic profile, monitor changes in oil and gas saturations near the wellbore, and further guide additional PNL monitor passes.

Pilot-scale Evaluations of Advanced Solvents for Postcombustion CO2 Capture

Abstract The Energy & Environmental Research Center (EERC) is leading the Partnership for CO2 Capture (PCO2 C) Program, which focuses on demonstrating CO2 separation and capture technologies at the pilot scale for fossil fuel-fired systems to help identify the key challenges associated with each technology. The program is sponsored by the U.S. Department of Energy, the North Dakota Industrial Commission, and several electric utilities and technology vendors. Phases I and II aimed to provide key technical and economic information to examine the feasibility of selected CO2 capture technologies. Phase III of the project is under way. This paper briefly summarizes the program.

Advanced CO2 Separation Technologies: Coal Gasification, Warm-gas Cleanup, and Hydrogen Separation Membranes

To facilitate the use of hydrogen in integrated gasification combined-cycle applications, hydrogen-from-coal technologies capable of managing carbon will be needed. Many technologies are under development for the separation of hydrogen from coal-derived syngas. Among the most promising are hydrogen separation membranes. The Energy & Environmental Research Center (EERC), together with the U.S. Department of Energy National Energy Technology Laboratory and the state of Wyoming, completed a project evaluating the performance of hydrogen separation membranes on coal-derived syngas. EERC small pilot-scale gasifiers were used to produce the syngas, and solid sorbents were used for warm-gas cleanup and water–gas shift.

An overview of the IEA greenhouse gas R&D programme regional geologic storage capacity studies

Abstract Mapping of CO 2 geological storage resources provides an important element in the planning of widespread CO 2 capture and storage (CCS) deployment. Recent high-level studies by the IEA Greenhouse Gas RD in both, a storage coefficient, E (or efficiency factor), is used to derive resource estimates. The E coefficient takes account of various geological and technical factors that could restrict the amount of pore space available for storage but does not take into account economic, regulatory, and source-sink matching considerations. IEAGHG and DOE commissioned a study in 2008 by the Energy & Environmental Research Center (EERC), to improve the accuracy of storage coefficients for DSF. As there was insufficient real-world CO 2 injection data to derive a representative range for E, geological input parameters were derived from global hydrocarbon reservoir data as a proxy for DSF. Modeling allowed derivation of probabilistic ranges of storage coefficients at both site-specific and formation levels for clastic, carbonate, and dolomite lithologies. The overall mean value of E for all lithologies was calculated as 2.6% at the formation level. A key assumption made in the study was that DSF will predominantly act as “open” systems, whereby pressure and displaced formation fluids can be safely dissipated through the wider storage formation and adjacent strata.

Mercury control testing in a pulverized lignite-fired system

The Energy & Environmental Research Center (EERC) is evaluating and developing advanced and innovative concepts for controlling Hg emissions from North Dakota lignite-fired power plants with the goal of achieving 50%–90% Hg removal at one-half to three-fourths the current estimated costs. Pilot-scale tests were performed to evaluate potential sorbents and fuel additives for removing Hg from North Dakota lignite (Freedom and Center Mines) combustion flue gases. The Hg sorbents and Hg 0 oxidation and sorbent enhancement additives were evaluated separately, and most were also tested in combination. A 580 MJ/h (550,000 Btu/h) pulverized coal combustion system was used to conduct sorbent injections and/or lignite additive additions upstream of three particulate control devices (PCDs): 1) an electrostatic precipitator (ESP), 2) a spray dryer and fabric filter, and 3) a retrofit advanced hybrid particulate collector (AHPC) filter (an ESP followed by an AHPC filter). ASTM International Method D6784-02 (Ontario Hydro method) and continuous Hg monitors were used to measure Hg species concentrations across the control devices. The effects of sorbent injection and coal additive addition rates on Hg removal were evaluated for each PCD option. The effects of continuous injection and batch addition of sorbents on the Hg removal performance of the ESP/AHPC filter system were also investigated. Increasing injection and additive rates and improving contact between the sorbents and flue gases generally promoted Hg capture. Most of the coal additives tested significantly enhanced PCD Hg removal, especially in the presence of a sorbent.

Activated carbon for mercury control: Implications for fly ash management

As more utilities begin to use activated carbon injection (ACI) for mercury control, the potential for the presence of elevated concentrations of mercury, other air toxic elements, and activated carbon to impact fly ash management needs to be evaluated. Several Energy & Environmental Research Center (EERC) projects have allowed the collection of comparative baseline fly ash samples and associated fly ash–activated carbon (AC) samples from full-scale demonstrations of ACI for mercury emission control. These samples were evaluated for mercury and air toxic element content and mobility and for performance criteria to facilitate a better understanding of the impact of these components to specific utilization applications, including use as a mineral admixture in concrete. These data are compared with published data from samples collected at similar large-scale mercury emission control tests. The data presented are in agreement with previous results from the EERC, the U.S. Environmental Protection Agency, and elsewhere that mercury associated with fly ash is stable and unlikely to be released under most management conditions. Additionally, this paper will discuss the potential for fly ash–AC samples to be used as a mineral admixture in concrete and other large-volume use applications.

Advanced high-temperature, high-pressure transport reactor gasification

The U.S. Department of Energy (DOE) National Energy Technology Laboratory Office of Coal and Environmental Systems has as its mission to develop advanced gasification-based technologies for affordable, efficient, zero-emission power generation. These advanced power systems, which are expected to produce near-zero pollutants, are an integral part of DOE's Vision 21 Program. DOE has also been developing advanced gasification systems that lower the capital and operating costs of producing syngas for chemical production. A transport reactor has shown potential to be a low-cost syngas producer compared to other gasification systems since its high-throughput-per-unit cross-sectional area reduces capital costs. This work directly supports the Power Systems Development Facility utilizing the KBR transport reactor located at the Southern Company Services Wilsonville, Alabama, site. Over 2800 hours of operation on 11 different coals ranging from bituminous to lignite along with a petroleum coke has been completed to date in the pilot-scale transport reactor development unit (TRDU) at the Energy & Environmental Research Center (EERC). The EERC has established an extensive database on the operation of these various fuels in both air-blown and oxygen-blown modes utilizing a pilot-scale transport reactor gasifier. This database has been useful in determining the effectiveness of design changes on an advanced transport reactor gasifier and for determining the performance of various feedstocks in a transport reactor. The effects of different fuel types on both gasifier performance and the operation of the hot-gas filter system have been determined. It has been demonstrated that corrected fuel gas heating values ranging from 90 to 130 Btu/scf have been achieved in air-blown mode, while heating values up to 230 Btu/scf on a dry basis have been achieved in oxygen-blown mode. Carbon conversions up to 95% have also been obtained and are highly dependent on the oxygen-coal ratio. Higher-reactivity (low-rank) coals appear to perform better in a transport reactor than the less reactive bituminous coals. Factors that affect TRDU product gas quality appear to be coal type, temperature, and air/coal ratios. Testing with a higher-ash, high-moisture, low-rank coal from the Red Hills Mine of the Mississippi Lignite Mining Company has recently been completed. Testing with the lignite coal generated a fuel gas with acceptable heating value and a high carbon conversion, although some drying of the high-moisture lignite was required before coal-feeding problems were resolved. No ash deposition or bed material agglomeration issues were encountered with this fuel. In order to better understand the coal devolatilization and cracking chemistry occurring in the riser of the transport reactor, gas and solid sampling directly from the riser and the filter outlet has been accomplished. This was done using a baseline Powder River Basin subbituminous coal from the Peabody Energy North Antelope Rochelle Mine near Gillette, Wyoming.

Mercury Mass Balances: A Case Study of Two North Dakota Power Plants

ABSTRACT The Energy & Environmental Research Center (EERC) conducted a mercury-sampling program to provide data on the quantity and forms of Hg emitted and on the Hg removal efficiency of the existing air pollution control devices at two North Dakota power plants—Milton R. Young Station and Coal Creek Station. Minnkota Power Cooperative, Great River Energy, the North Dakota Industrial Commission, and EPRI funded the project. The primary objective was to obtain accurate measurements of Hg released from each plant, as verified by a material balance. A secondary objective was to evaluate the ability of a mercury continuous emission monitor (CEM) to measure total Hg at the stack. At both plants, speciated Hg measurements were made at the inlets and outlets of both the electrostatic precipi-tators (ESPs) and the flue gas desulfurization (FGD) systems. A Semtech Hg 2000 (Semtech Metallurgy AB) mercury CEM was used to measure the total Hg emissions at the stack in real time. Using these measurements and plant data, the measured Hg concentrations in the coal, FGD slurries, and ESP ash, a Hg mass flow rate was calculated at each sampling location. Excellent Hg mass balances were obtained (±15%). It was also found that the Hg was mostly in the elemental phase (~90%), and the small amount of oxidized Hg that was generated was removed by the FGD systems. Insignificant amounts of particulate-bound Hg were measured at both plants. However, 10-20% of the elemental Hg measured prior to the ESP was converted to oxidized Hg across the ESP. The data show that, at these facilities, almost all of the Hg generated is being emitted into the atmosphere as elemental Hg. Local or regional deposition of the Hg emitted from these plants is not a concern. However, the Hg does become part of the global Hg burden in the atmosphere. Also, the evidence appears to indicate that elemental Hg is more difficult to remove from flue gas than oxidized Hg is.

97/00970 Solvent recyclability and hydrotreatment severity in direct liquefaction of low-rank coal

A multistep direct liquefaction process specifically aimed at low-rank coals (LRCs) has been developed at the Energy & Environmental Research Center (EERC). The process consists of a preconversion treatment to prepare the coal for solubilization, solubilization of the coal in the solvent, and polishing using a phenolic solvent or solvent blend to complete solubilization of the remaining material. The product of these three steps can then be upgraded during a traditional hydrogenation - step. Research was performed to address two questions necessary for the further development and scaleup of this process: (1) determination of the recyclability of the solvent used during solubilization, and (2) determination of the minimum severity required for effective hydrotreatment of the liquid product. The research was performed during two tasks, the first consisting of ten recycle tests and the second consisting of hydrotreatment tests performed at various conditions.