Energy And Environmental Research Center Research Articles

An Integrated Frac Geometry Control Approach To Prevent H2S Production

_ Hydrogen sulfide (H2S) production has in recent years become a mounting issue facing operators and midstream companies in major US basins. At present, H2S production appears to be random and poorly understood. As such, H2S is considered by many to be an unpreventable nuisance and one that is largely addressed by treating the dangerous gas at surface before putting it to a sales line. This article highlights impacts of H2S, possible sources, and a successful case study of a completions operation designed specifically to prevent H2S production in North Dakota’s Williston Basin. H2S and Its Impacts H2S is a colorless gas known for its pungent “rotten egg” odor at low concentrations. It is extremely flammable, highly toxic, poisonous, and corrosive. H2S is commonly encountered during the drilling and production of crude oil and natural gas, as well as in wastewater treatment, utility facilities, and sewers. H2S is well-known for its significant health and safety risks, along with substantial financial implications in the event of an accidental release. The substance ranks as the second leading cause of workplace gas inhalation deaths in the US. This is according to the US Bureau of Labor Statistics, which concluded that H2S caused 46 worker deaths between 2011 and 2017. Due to its corrosiveness, wells that produce even small volumes of H2S may compromise wellbore integrity and lead to premature failure of production equipment. Sour oil and gas is considered to have about 10% lower profit margin than traditional sweet Bakken crude (SPE 141434). An electrical submersible pump replacement can cost an operator up to $250,000, plus production downtime. Additionally, according to one leading chemical company, it costs $2,250 per day to treat 200 ppm H2S at a typical gas production rate of 2,000 Mcf/D. H2S Sources A recent study, URTeC 3852794, published by the Energy and Environmental Research Center (EERC) at the University of North Dakota suggests three possible causes of H2S: geo-mechanical, thermochemical, and biogenic. Geo-mechanical: Mission Canyon organic-rich intervals could be a source of H2S for a limited number of the Bakken producing wells via communication between reservoirs caused by out-of-zone stimulation work. This conclusion was evidenced by matching the δ34S isotope between 30 H2S producing wells and formation cores. Thermochemical sulfate reduction (TSR): Another possible mechanism of H2S generation involves the presence of anhydrites and hydrocarbons at a higher reservoir temperature of 110° to 150°C. This mechanism is plausible for wells with the δ34S in the range from +10 to +19‰. The EERC research team is currently investigating the TSR existence in the Williston Basin. Biogenic: This third mechanism of reservoir souring is questionable in the Bakken because of the high reservoir temperatures (110° to 150°C) and elevated salinity of the formation water (TDS 200,000 mg/L) making microbial growth unlikely, especially in the context of the predominance of heavier 34S isotope (δ34S of +2 to +19‰) in produced H2S.

Round-Robin Interlaboratory Study on Rare-Earth Elements in U.S.-Based Geologic Materials

In a study funded by the U.S. Department of Energy (DOE) National Energy Technology Laboratory (NETL), the University of North Dakota (UND) Energy and Environmental Research Center (EERC) performed a first-of-its-kind round-robin interlaboratory study (RRIS) to determine lab-to-lab and method-to-method variability in analyzing the rare earth element (REE) content of domestic resources. Analyses of REEs on eleven different materials were accomplished by the laboratories using four different procedures: ASTM D6357 (Procedure A), ASTM D4503 (Procedure B), an alternate in-house procedure for digestion and REE analysis (Procedure C), and neutron activation analysis (NAA). The results of the RRIS suggest that NAA is the most accurate and reliable method for many of the REEs in these types of materials; however, the method is limited in that it is able to determining only ten of the sixteen REEs. Five of the seven labs reporting data for Procedure A and three of the five labs reporting for Procedure B showed excellent performance in terms of repeatability, reproducibility, agreement with NAA, and SRM recoveries based on AOAC International guidelines on method performance. This indicates that when strictly followed these methods are suitable for REE determination in most materials, although are subject to the overall capabilities and experience of individual laboratories.

Water-Plus-Gas Injection on a Bakken Well Pad May Solve Problems That Stymied Shale EOR

_ After years of enhanced oil recovery (EOR) tests in the Bakken, one method finally appears to have added to a well’s ultimate production. The Liberty Resources well “is perhaps the first one that had clear, indisputable evidence of incremental oil. I do firmly believe we are on the right track for cracking the code for Bakken EOR,” said Jim Sorensen, director of subsurface R&D for the University of North Dakota Energy and Environmental Research Center (EERC) which provided technical support and funding. The gain predicted after the treatment with water alternating with gas injection (WAG) is not huge. A paper on the test, which was limited to a single 30-day injection cycle, estimated it added 7,000 bbl to the ultimate production, based on decline curve analysis (URTeC 3722974). An updated analysis from EERC is expected in early 2023. While there are endless arguments over the accuracy of decline curve analysis, Gordon Pospisil, development advisor for Liberty, said incremental oil estimates look solid: “The oil rate response to water alternating gas injection was clearly measurable at over 7,000 bbls over the baseline trend.” The bigger news may be an injection method that can overcome two barriers to EOR in the Bakken and elsewhere. One is finding a way to keep the injected gas around the wellbore, and the other is significantly lowering the cost, primarily by slashing the volume of gas required. “Overall, we were pleased with the project outcome to date as we were able to build pressure, contain the injection within the DSU (drilling spacing unit), and make incremental oil,” Pospisil said. For the test, Liberty used a novel, computer-controlled injection system from a startup company, EOR ETC. This system can rapidly switch from gas to water injection based on the control system the company developed. This reduces the surface injection pressure required to significantly increase the downhole pressure level and helps contain the gas in the target zone. “I have never seen anything like that. It performed as advertised,” Sorensen said. The estimated long-term gain looks small compared to the 800,000 bbl of oil prior to the test. But Brian Schwanitz, president of EOR ETC, said the income from those barrels covered what they billed for pumping the job, which was a discounted rate reflecting Liberty’s willingness to be the first operator to use the device. What it accomplished stands out compared to the futility of past Bakken tests where far more gas was injected with little impact on the downhole pressure because so much of it leaked off through the fractured formation. The Bakken Debacle For a decade, companies in the Bakken, often in partnership with the EERC, have searched for ways to get more oil out of the play where the ultimate recoveries are usually below 10% of the oil in place, which is in line with other unconventional oil plays. Gas-injection EOR tests in oil-producing shale plays have been hit or miss, with most of the results in the Bakken in the miss column. The problem has been that much of the gas escapes from the target zone, making it impossible in some cases to achieve the pressure levels needed for effective EOR and it increases the volume of gas needed to uneconomic levels for gas-only projects to achieve improved ultimate recoveries.

Enhanced Oil Recovery in Liquid–Rich Shale Reservoirs: Laboratory to Field

Summary Production of tight oil from shale reservoirs in North America reduces oil imports and has better economics than natural gas. Currently, there is a strong interest in oil production from Bakken, Eagle Ford, Niobrara, and other tight formations. However, oil-recovery fraction for Bakken remains low, which is approximately 4–6% of the oil in place. Even with this low oil-recovery fraction, a recent United States Geological Survey study stated that the Bakken and Three Forks recoverable reserves are estimated to be 7.4 billion bbl; thus, a large volume of oil will remain unrecovered, which was the motivation to investigate the feasibility of enhanced oil recovery (EOR) in liquid-rich shale reservoirs such as Bakken. In this paper, we will present both laboratory and numerical modeling of EOR in Bakken cores by use of carbon dioxide (CO2), methane/ethane-solvent mixture (C1/C2), and nitrogen (N2). The laboratory experiments were conducted at the Energy and Environmental Research Center (EERC). The experiments recovered 90+% oil from several Middle Bakken cores and nearly 40% from Lower Bakken cores. To decipher the oil-recovery mechanisms in the experiments, a numerical compositional model was constructed to match laboratory-oil-recovery results. We concluded that solvent injection mobilizes matrix oil by miscible mixing and solvent extraction in a narrow region near the fracture/matrix interface, thus promoting countercurrent flow of oil from the matrix instead of oil displacement through the matrix. Specifically, compositional-modeling results indicate that the main oil-recovery mechanism is miscible oil extraction at the matrix/fracture interface region. However, the controlling factors include repressurization, oil swelling, viscosity and interfacial-tension (IFT) reduction, diffusion/advection mass transfer, and wettability alteration. We scaled up laboratory results to field applications by means of a compositional numerical model. For field applications, we resorted to the huff ’n’ puff protocol to assess the EOR potential for a North Dakota Middle Bakken well. We concluded that long soak times yield only a small amount of additional oil compared with short soak times, and reinjecting wet gas, composed of C1, C2, C3, and C4+, produces nearly as much oil as CO2 injection.

Carbon Dioxide May Offer An Unconventional EOR Option

As the daily oil output of the Bakken and Eagle Ford formations rose toward 1 million B/D, researchers were seeking a way to push the ultimate recoveries in these formations, where producing 6% of the oil in the ground is now considered good. One line of attack on the problem is using carbon dioxide (CO2) to get more oil from tight formations where rapid production declines are the norm. In laboratories at the Energy and Environmental Research Center (EERC) at the University of North Dakota and at Texas A&M University, experiments have shown that carbon dioxide circulated around a small sample of source rock can remove a significant amount of oil. Now, the scientists are trying to understand how it works and if those lab results can be applied in the real world. “It is incredible what CO2 can do,” said John Harju, associate director for research at the EERC, while describing the center’s research program at the annual CO2 Flooding Conference in Midland, Texas. “The really big prize is (overcoming) the innately low recovery rate in these shale plays,” said David Schechter, an associate professor of petroleum engineering at Texas A&M University who is turning his expertise in conventional enhanced oil recovery to unconventional reservoirs. While laboratory results normally show much higher recovery than field results, even a 1% improvement of recoveries in the Bakken formation could yield more than 1 billion bbl of oil, according to an EERC paper. Previous SPE papers, based on reservoir simulation work at Montana Tech of the University of Montana and the Colorado School of Mines, concluded that significant increases in ultimate oil recovery might be possible using CO2 injections. One of the biggest backers of the work in North Dakota has been Harold Hamm, the chief executive officer at Continental Resources, which pioneered unconventional liquids development and is the biggest acreage holder in the Bakken, Harju said. On the basis of early tests using CO2 and similar positive results from using chemical surfactants, Texas A&M is working to recruit support from oil companies for a joint industry project called the Enhanced Oil Recovery in Unconventional Reservoirs Joint Industry Project. Both the EERC and Texas A&M have tested samples ranging in size from Chiclets—square bits of reservoir rock about the size of the popular chewing gum—to small core samples about the size of a disposable lighter. The tests produced significant amounts of oil from samples exposed to CO2 flowing through a test chamber simulating reservoir conditions.

Hitachi’s carbon dioxide scrubbing technology with new absorbent for coal fired power plants

Babcock Hitachi has been developing a new amine-based scrubbing technology for capturing carbon dioxide in the flue gas of coal-fired power plants. The development program includes testing of commercial and new combinations of absorbents and additives. More than thirty kinds of amines have been evaluated and characterized by both fundamental tests in the laboratory and slipstream pilot plant tests. The pilot plant tests of the CO2 scrubbing system were conducted at a coal-fired power plant in co-operation with Tokyo Electric Power Company. Two thousand hours of continuous operation was achieved with more than 90% CO2 reduction on average during the entire operation. Energy consumption with the original absorbent blend was much less than that with typical MEA. Since then the CO2 scrubbing system has been further advanced to reduce the energy consumption as well as absorbent degradation drastically by improving the amine-based absorbent in a bench-scale test facility. Pilot tests at Energy and Environmental Research Center (EERC), University of North Dakota, were conducted in 2010 and the test results indicated high performance of the improved amine-based absorbent, H3-1. This latest advanced solvent is also scheduled to be demonstrated in a large mobile test facility at several coal-fired power plants in Europe starting 2010. In parallel, conceptual designs of the CO2 scrubbing system for commercial plants up to 800 MWe in size are being developed.

Activated Carbon from Biomass for Mercury Capture: Effect of the Leaching Pretreatment on the Capture Efficiency

Activated carbons were produced from two European biomasses such as olive residue and wheat straw. The leaching pretreatment is used to study the effect of chlorine and alkali metals on the mercury capture efficiency. The activated carbons were tested for mercury capture in a bench scale reactor against the commercial grade activated carbon NORIT DARCO Hg as well as an activated carbon developed at the Energy and Environmental Research Center (EERC) from lignite. The mercury capture tests showed that the untreated biomass-derived activated carbons performed fair-to-very good compared to the commercial catalyst and better compared to the lignite-derived activated carbon. The leached biomass-derived carbons were seen to have poor performance in the case of the olive residue and similar performance to that of the lignite-derived carbon in the case of the wheat straw.

Energy Recycling by Co-Combustion of Coal and Recovered Paint Solids from Automobile Paint Operations

Experiments were carried out in a pilot-scale pulverized coal combustor at the Energy and Environmental Research Center (EERC) burning a Powder River Basin (PRB) subbituminous coal. A scanning mobility particle sizer (SMPS) and an electrical low-pressure impactor (ELPI) were used to measure the particle size distributions (PSDs) in the range of 17 nm to 10 μm at the inlet and outlet of the electrostatic precipitator (ESP). At the ESP inlet, a high number concentration of ultrafine particles was found, with the peak at approximately 75 nm. A trimodal PSD for mass concentration was observed with the modes at approximately 80-100 nm, 1-2 μm, and 10 μm. The penetration of ultrafine particles through the ESP increased dramatically as particle size decreased below 70 nm, attributable to insufficient or partial charging of the ultrafine particles. Injection of nanostructured fine-particle sorbents for capture of toxic metals in the flue gas caused high penetration of the ultrafine particles through the ESP. The conventional ESP was modified to enhance charging using soft X-ray irradiation. A slipstream of flue gas was introduced from the pilot-scale facility and passed through this modified ESP. Enhancement of particle capture was observed with the soft X-ray irradiation when moderate voltages were used in the ESP, indicating more efficient charging of fine particles.

A comprehensive slagging and fouling prediction tool for coal-fired boilers and its validation/application

RMT, Inc., a subsidiary company of Alliant Energy Corporation, and the University of North Dakota Energy and Environmental Research Center (EERC) have developed an ash behavior prediction tool, called AshProSM, to assess slagging and fouling in coal-fired boilers. This tool integrates boiler computational fluid dynamic (CFD) simulations with ash behavior models including ash formation, transport and deposition, as well as deposit growth and strength development. AshProSM was applied to a 512-MW tangentially-fired boiler at Wisconsin Power & Light's Columbia Energy Center to evaluate the localized slagging on furnace walls and fouling in convective pass. The predicted boiler ash deposition pattern is reasonably consistent with that observed on the furnace walls and super heater division panels. The prediction of slag state transition (solid/liquid) through deposit viscosity was verified by the observation in the plant.

Alkali influences on sulfur capture for North Dakota lignite combustion

Pilot-scale testing was performed at the University of North Dakota Energy and Environmental Research Center (EERC) to determine the levels and mechanisms of sulfur capture on fly ash. Core samples of lignite having low-, medium-, and high-sulfur levels were sampled and analyzed from a potential lignite mine area in western North Dakota. Computer-controlled scanning electron microscopy (CCSEM) analysis revealed that sulfur levels were strongly associated with pyrite content; however, organic sulfur was also significant. Combustion tests of the three lignites revealed SO 2 in the flue gas at levels ranging between 700 and 2300 ppm. Sulfur levels were 2–5% in the fly ash. Higher-sulfur retention or capture was evident in the medium-and low-sulfur lignite, which also had greater quantities of alkali inorganics that were organically bound in the lignite. Sulfur capture was mostly influenced by the presence of sodium and, secondarily, by calcium as oxides or hydroxides in the flue gas or on surfaces of porous char particles. Gas–particle interactions that led to sulfur capture most likely involved the heterogeneous condensation of sulfur on fine alkali particles or on fine alkali-rich fly ash particles in cooler condensing zones of the combustion system. No direct correlation is evident between sulfur quantity in the coal and capture levels. Regression analysis indicated that an earlier model developed for alkali-rich coal gave an adequate representation of the sulfur capture and emissions expected from low-rank coals; however, an improved model was devised.

Use of continuous mercury monitors at coal-fired utilities

In December 2000, the U.S. Environmental Protection Agency (EPA) published a notice of its determination that regulation of coal-fired utilities for mercury is appropriate and necessary as part of the hazardous air pollutant emission regulation for electric utility steam-generating units. To aid in the determination of mercury emissions from these sources, on-line mercury semicontinuous emission monitors (Hg SCEMs) have been developed and tested in recent years. Although Hg SCEMs have shown promise during these previous tests, rigorous field or long-term testing has not been done. In the past year, commercially available and prototype Hg SCEMs have been used by the Energy and Environmental Research Center (EERC) and others at several power plants. As part of the EERC work, Hg SCEMs were operated at a range of conditions and locations. In addition, the Hg SCEMs were operated for up to 1 month. The use of Hg SCEMs at these plants allowed for near-real-time data to be collected under changing plant conditions, as well as during normal ranges of operating conditions. Mercury emission data were obtained from different plants with different configurations. The plant configurations incorporated various pollution control technologies, including selective catalytic reduction (SCR), selective noncatalytic reduction, ammonium sulfate injection for flue gas conditioning, and flue gas desulfurization (FGD). The particulate control devices included electrostatic precipitators (ESPs), a fabric filter (FF), and a venturi scrubber. The testing at these sites included the operation of Hg SCEMs before and after particulate control devices, in wet and dry stack conditions, and at high temperatures (343 °C). The results from these field measurements have provided data that have been evaluated to determine the reliability, variability, biases, and overall capability of Hg SCEMs for monitoring mercury at coal-fired utilities. Even under the best conditions, operation of Hg SCEMs is by no means simple. Their operation at high-dust-condition locations (i.e., prior to the particulate control device), wet stack conditions, and high temperatures has tested the ruggedness of the Hg SCEMs. As a result of this testing, some of the critical factors affecting accuracy, precision, and reliability have been made apparent. The overall capability of Hg SCEMs to produce near-real-time data (data every 5 min) was also evaluated under these conditions. The duration of the tests ranged from short-term periods (1–2 h) up to 1 month. Evaluation of the data over the longer-term tests shows the range of mercury emissions due to the variability of mercury in the coal and the normal range of operating parameters for the unit. The range of data is important when control strategies and managing emission inventories are considered. EPA has not determined what type of monitoring or testing requirements will be included in the upcoming electric utility mercury regulations. There is, of course, interest in requiring the use of Hg SCEMs. However, our research to date has shown that commercially available Hg SCEMs are not capable of operating unattended to produce reliable and accurate emission data.

Application of sorbents for mercury control for utilities burning lignite coal

The Energy and Environmental Research Center (EERC) is conducting the first phase of a 3-year, two-phase U.S.–Canadian consortium project to develop and demonstrate mercury control technologies for utilities burning lignite coal. Control of mercury from lignite-fired plants is much more difficult in comparison to plants burning other ranks of coal. The overall project goal is to provide utilities that burn lignite coal with low-cost technology options for meeting future mercury emission regulations. Phase I objectives are to develop a better understanding of mercury interactions with flue gas constituents, test a range of sorbent-based technologies targeted at removal of elemental mercury from flue gases, and demonstrate the effectiveness of the most promising technologies at the pilot scale. The Phase II objective is to demonstrate and quantify technology, performance, and cost at a sponsor-owned/operated power plant. Preliminary results are presented for Phase I bench- and pilot-scale tests, and results are encouraging for continuation of Phase II activities.

Potential for mercury vapor release from coal combustion by-products

Determination of the mechanisms of mercury release from coal combustion by-products (CCBs) is one area of research at the Energy and Environmental Research Center (EERC). One task of this research is to determine the level of mercury that would offgas from various CCBs. In these experiments, six CCB samples were tested for mercury vapor release at ambient and near-ambient temperatures. The results have shown no clear evidence that the rate of mercury release is related to the bulk mercury concentration. The six samples are being retested for ambient temperature release. These new experiments are being done in duplicate in an improved version of the apparatus to verify previous results. Because of improved methods, results indicate that the vapor release of mercury is an order of magnitude lower than previously thought. It is estimated that an annual coal-fired power plant production of 200,000 tons of fly ash a year would potentially offgas less than 0.3 g of mercury.

Effects of flue gas constituents on mercury speciation

Beginning with the 1990 Clean Air Act Amendments, there has been considerable interest in mercury emissions from coal-fired power plants. This past year, the U.S. Environmental Protection Agency (EPA) issued both the Mercury Study Report to Congress and the Study of Hazardous Air Pollutant Emissions from Electric Utility Steam-Generating Units, which make clear that EPA views mercury in the environment as a serious issue and that coal-fired utilities are a major source of mercury. For the past 4 years, EPRI and the U.S. Department of Energy (DOE) have funded research on mercury measurement, control, and chemistry at the Energy and Environmental Research Center (EERC). The primary goal of bench-scale work was to determine what flue gas constituents affect mercury speciation, specifically how mercury speciation affects measurement methods and the ability of mercury sorbents to absorb mercury. A bench-scale test rig was designed and built to simulate flue gas conditions. The baseline simulated flue gas consisted of O 2, CO 2, H 2O, and N 2. Other flue gas constituents tested include SO 2, HCl, NO, NO 2, HF, Cl 2, and fly ash. The mercury was delivered to system as either elemental mercury (Hg 0) or mercury(II) chloride (HgCl 2) via temperature-controlled permeation tubes. EERC bench-scale data clearly show that the type of fly ash is important in determining mercury speciation in flue gas streams. Not surprisingly, there appear to be a number of interactions between various flue gas constituents that affect mercury speciation. Depending on concentration, there is clearly an interaction between NO–NO 2 and fly ash, and it is possible that the interaction may be related to the ratio of NO:NO 2. However, it has been shown that when NO–NO 2 is tested without fly ash, there is no conversion of Hg 0 to Hg 2+. Bench-scale tests clearly show that the chemistry of mercury is very complex and that more research is needed to understand what is occurring. However, it is equally clear that the development of effective mercury sorbents and the ability to accurately model mercury speciation are dependent on understanding mercury chemistry, thermodynamics, and kinetics.

99/02556 Reducing phosphorus export from croplands with FBC fly ash and FGD gypsum

A study was performed at the Energy and Environmental Research Center (EERC) to test the hypotheses that (1) different carbon types contained in coal combustion fly ash have variable sorption capabilities relative to mercury and (2) the inorganic fraction of coal combustion fly ash may sorb mercury through mechanisms distinct from sorption by carbon in the ash. The purpose of this study was to conduct laboratory experiments to better understand the phenomenon of mercury sorption on coal combustion fly ash. Tests were conducted on the laboratory scale using samples generated from both commercial-scale utility boilers and pilot-scale combustion equipment at the EERC. Selected samples represented ash from various coal sources, of varying loss-on-ignition (LOI) content, and exhibiting different combinations of carbon types. Results indicate a direct correlation between carbon content and mercury partitioning among individual ash samples. The direct relationship between carbon content and mercury-sorbing capacity of the bulk ash samples demonstrated in the loading experiments is not reflected by the low- and high-carbon fraction data. The mercury-sorbing capacity of the inorganic fraction is extremely low with respect to carbon present in the ash. There are likely to be significant differences between the mercury-sorbing capacities of these various carbon forms. The mercury-sorbing capacity of ash studied in this research was highly temperature dependent. Additional work is needed on experimental design to evaluate the loading of high-carbon ash samples with particular attention to the phenomenon of sorptive capacity regeneration, which should be further investigated.

99/02549 Method for discharging of fused slag

Pilot-scale testing was performed at the University of North Dakota Energy and Environmental Research Center (EERC) to determine the levels and mechanisms of sulfur capture on fly ash. Core samples of lignite having low-, medium-, and high-sulfur levels were sampled and analyzed from a potential lignite mine area in western North Dakota. Computer-controlled scanning electron microscopy (CCSEM) analysis revealed that sulfur levels were strongly associated with pyrite content; however, organic sulfur was also significant. Combustion tests of the three lignites revealed SO2 in the flue gas at levels ranging between 700 and 2300 ppm. Sulfur levels were 2–5% in the fly ash. Higher-sulfur retention or capture was evident in the medium-and low-sulfur lignite, which also had greater quantities of alkali inorganics that were organically bound in the lignite. Sulfur capture was mostly influenced by the presence of sodium and, secondarily, by calcium as oxides or hydroxides in the flue gas or on surfaces of porous char particles. Gas–particle interactions that led to sulfur capture most likely involved the heterogeneous condensation of sulfur on fine alkali particles or on fine alkali-rich fly ash particles in cooler condensing zones of the combustion system. No direct correlation is evident between sulfur quantity in the coal and capture levels. Regression analysis indicated that an earlier model developed for alkali-rich coal gave an adequate representation of the sulfur capture and emissions expected from low-rank coals; however, an improved model was devised.

99/02868 Tensile strength of ash cake beds at high-temperature conditions

The Energy and Environmental Research Center (EERC) is working with Electric Power Research Institute (EPRI) and a consortium of companies in partnership with the US Department of Energy (DOE) to perform the research necessary to determine the factors that cause hot-gas cleanup filters to be blinded by ash or to develop deposits that can bridge the filters and cause them to fail. The primary deliverable will be a graphics-driven computer model that can be used as an engineering tool to help predict ash-related hot-gas filter problems based on analyses of coal and sorbent, as well as system operating parameters. This paper presents preliminary testing data on determining the tensile strengths of coal ash particles at elevated temperatures and simulated combustor gas conditions. The range in temperatures for tensile testing is ambient to 900 C. The simulated gas atmosphere includes carbon dioxide, water vapor, oxygen, sulfur dioxide, sodium chloride, hydrochloric acid, and nitrogen. At present, all testing has been performed using ash from the Westinghouse advanced particle filter (APF) at the American Electric Power Service Corporation (AEP) Tidd pressurized fluidized-bed combustor (PFBC) demonstration plant in Ohio. Other sources of filter ashes, including several from non-American PFBC systems, will also be evaluated.

Mercury capture on coal combustion fly ash

A study was performed at the Energy and Environmental Research Center (EERC) to test the hypotheses that (1) different carbon types contained in coal combustion fly ash have variable sorption capabilities relative to mercury and (2) the inorganic fraction of coal combustion fly ash may sorb mercury through mechanisms distinct from sorption by carbon in the ash. The purpose of this study was to conduct laboratory experiments to better understand the phenomenon of mercury sorption on coal combustion fly ash. Tests were conducted on the laboratory scale using samples generated from both commercial-scale utility boilers and pilot-scale combustion equipment at the EERC. Selected samples represented ash from various coal sources, of varying loss-on-ignition (LOI) content, and exhibiting different combinations of carbon types. Results indicate a direct correlation between carbon content and mercury partitioning among individual ash samples. The direct relationship between carbon content and mercury-sorbing capacity of the bulk ash samples demonstrated in the loading experiments is not reflected by the low- and high-carbon fraction data. The mercury-sorbing capacity of the inorganic fraction is extremely low with respect to carbon present in the ash. There are likely to be significant differences between the mercury-sorbing capacities of these various carbon forms. The mercury-sorbing capacity of ash studied in this research was highly temperature dependent. Additional work is needed on experimental design to evaluate the loading of high-carbon ash samples with particular attention to the phenomenon of sorptive capacity regeneration, which should be further investigated.

97/04558 Preparation and gasification of a Thailand coal-water fuel: Ness, R. O. et al. Proc. Annu. Int. Pittsburgh Coal Conf., 1996, 13, (1), 443–448

In response to an inquiry by the Department of Mineral Resources (DMR) in Thailand, the Energy and Environmental Research Center (EERC) prepared a four-task program to assess the responsiveness of Wiang Haeng coal to the temperature and pressure conditions of hot-water drying (HWD). The results indicate that HWD made several improvements in the coal, notably increases in heating value and carbon content and reductions in equilibrium moisture and oxygen content. The equilibrium moisture content decreased from 37.4 wt% for the raw coal to about 20 wt% for the HWD coals. The energy density, determined at 500 cP, indicates an increase from 4450 to 6650 Btu/lb by hydrothermal treatment. Raw and HWD coal were then gasified at various mild gasification conditions of 700 C and 30 psig. The tests indicated that the coal is probably similar to other low-rank coals and will produce high levels of hydrogen and be fairly reactive.

97/03553 Pipeline transportation of upgraded Yugoslavian lignite fuels

Hydraulic transport and handling procedures for coal are not widely used, but when practiced, they result in a technically and economically successful operation. Potentially the most attractive way to utilize lignitic coals for power generation would be to combine hydraulic mining techniques with aqueous ash removal, hydrothermal processing, solids concentration, and coal-water fuel (CWF) combustion. Technical and economic assessment of this operation is being implemented within the Yugoslavian-American Scientific Technical Cooperation Agreement. The Energy and Environmental Research Center (EERC), Grand Forks, North Dakota, with support from the U.S. Department of Energy, has entered into a jointly sponsored research project with Electric Power of Serbia (EPS), Belgrade, Yugoslavia, to investigate the application of the nonevaporative hydrothermal drying procedure, commonly called hot-water drying (HWD), developed at the EERC, to the lignite from the Kovin deposit. Advances in hydrothermal treatment of low-rank coals (LRCs) at the EERC have enabled cheaper, more reactive LRCs to be used in coal-water fuels (CWFs). HWD is a high-temperature, nonevaporative drying technique carried out at high pressure in water that permanently alters the structure of LRC. It solves the stability problems by producing a safe, easily transported, liquid fuel that can be handled and used like oil. Formore » continued or increased success, it is necessary to evaluate carefully all aspects of slurry technology that permit further optimization. This paper discusses some aspects of low-rank coal hydraulic transport combined with hydrothermal treatment as an alternative energy solution toward less oil dependence in Yugoslavia.« less