AndreaBozzo/ceres-open-data-index huggingface dataset:
Bench scale retorting of Kentucky oil shale: comparison of a fixed bed to 1 1/2 and 3 inch fluid bed retorts

Bench scale fluid bed retorting of Kentucky oil shale has provided evidence that for the small particle sizes used in this study increases in oil yield, which have been shown to be feasible for eastern US shale, is primarily due to decreased cracking of oil vapors and that release of hydrocarbons from the shale depends on pyrolysis temperature and not the retorting technology used. The following information presented supports this statement: Under fluid bed conditions where oil vapors are rapidly removed from the retort more oil and less gas are produced than any fixed bed retorting conditions. Under fluid bed conditions, the proportion of CH/sub 4/ in the gas increases with increasing bed temperature at the expense of a lower proportion of C4's in the hydrocarbon gas. CH/sub 4/ produced under modified Fischer Assay conditions is greater than that obtained at a comparable bed temperature in the fluid bed. Oil yield from the fluid bed retorting Ohio Oil Shale is maximized at a bed temperature of 575/sup 0/C under retorting conditions used in this study. Removal of volatile matter as measured by TG from the shale depends on retorting temperature and not retorting method. Increases in the fixed carbon content of the spent shale relative to the raw shale are accompanied by decreased oil yields, increased gas make and increased CH/sub 4/ production in both fixed and fluid bed retorts. Under modified Fischer Assay conditions, 10% more carbon as determine by elemental analysis is left on the spent shale than a fluid bed run at the same maximum bed temperature; TG analysis of the spent shale indicates that this residual carbon is coke.

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An underground coal gasification experiment, Hanna, Wyoming

In the fall of 1972, the U.S. Bureau of Mines began an experiment to investigate the technologic, economic, and environmental considerations of underground gasification of a W. subbituminous coal. The gasification site is near the town of Hanna, Wyo., approx. 70 miles northwest of Laramie. The test results indicate that gas volumes and gas heating values have fluctuated over a wide range depending on operating conditions. The ranges have been from 50,000 to over 3 MMscfd of produced gas with a composite heating value from 30 to 465 btu per scf. Even though these fluctuations have occurred, a semisteady state condition existed for a 6-mo. period. From Sept. 1973 through Feb. 1974, a low btu gas averaging about 130 btu per scf was produced at an average rate of 1.6 MMscfd. A material balance made during this period indicated:  (1) there was little or no underground gas leakage from the site; (2) about 80 bbl of formation water were consumed each day; (3) between 13 and 46 tons of dry coal were affected each day depending on the assumptions made; and (4) from 23 to 65% of the energy of the coal being subjected to carbonization and/or gasification is being recovered.

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Natural gas production from coal seams

The estimated 4 trillion tons of coal which lie buried beneath the U.S. at depths of less than 3,000 ft are thought to contain nearly 300 tcf of pipeline-quality natural gas. The mechanism by which this gas is released is believed to result from the diffusion of adsorbed gas through the microporous bulk matrix into the natural fractures where mass transport is governed by the principles of Darcy flow. This 2-step process may ultimately be controlled by conditions of critical flow, choked flow, in the micropores adjacent to the fractures. Several techniques have been developed to determine the gas content of a coal seam based primarily on the analysis of exploratory cores. Such methods generally yield quite different results when applied to the same core sample. A new technique which relies upon the analysis of decline curves constructed from gas desorption data obtained from a core, appears to give the most reliable results, and indirectly indicates that the Darcy flow mechanism controls the desorption process. (29 refs.)

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Leachate migration from an in situ oil-shale retort near Rock Springs, Wyoming

Geohydrologic factors influencing leachate movement from an in situ oil shale retort near Rock Springs, Wyoming, were investigated by developing models of groundwater flow and solute transport. Leachate, indicated by the conservative ion thiocyanate, has been observed 1/2 mi downgradient from the retort. The contaminated aquifer is part of the Green River Formation and consists of thin, permeable layers of tuff and sandstone interbedded with oil shale. Groundwater flow in the study area is complexly 3-D and is characterized by large vertical variations in hydraulic head. The solute transport model was used to predict the concentration of thiocyanate at a point where groundwater discharges to the land surface. Leachates with peak concentrations of thiocyanate - 45 mg/L or approximately one-half the initial concentration of retort water - were estimated to reach the discharge area during January 1985. Advantages as well as the problems of site specific studies are described. Solute migration in the study area primarily occurs in thin permeable beds rather than in oil shale strata. Because of this behavior, leachate traveled far greater distances than might otherwise have been expected. A major problem in site specific studies is identifying model boundaries that permit the accurate estimation of aquifer properties. If the quantity of water flowing through a study area cannot be determined prior to modeling, the hydraulic conductivity and groundwater velocity will be estimated poorly. 30 refs., 13 figs., 4 tabs.

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Site visit report:  Central Illinois Public Service Company Grand Tower Power Station, Grand Tower, Illinois. Final report

This report details the activities, facilities, and equipment used to sample raw feedstock and waste solids at the Grand Tower Power Station during the period October 19 through October 23, 1981. Explanation of sampling locations, deviations from the test plan, sampling techniques (in accordance with the Fossil Energy Waste General sampling Guideline), and plant design are reviewed.

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Effects of aqueous effluents from in situ fossil fuel processing technologies on aquatic systems. Annual progress report, January 1-December 31, 1979

This is the third annual progress report for a continuing EPA-DOE jointly funded project to evaluate the effects of aqueous effluents from in situ fossil-fuel processing technologies on aquatic biota. The project is organized into four project tasks: (1) literature review; (2) process water screening; (3) methods development; and (4) recommendations. Our Bibliography of aquatic ecosystem effects, analytical methods and treatment technologies for organic compounds in advanced fossil-fuel processing effluents was submitted to the EPA for publication. The bibliography contains 1314 citations indexed by chemicals, keywords, taxa and authors. We estimate that the second bibliography volume will contain approximately 1500 citations and be completed in February. We compiled results from several laboratories of inorganic characterizations of 19 process waters: 55 simulated in situ oil-shale retort waters; and Hanna-3, Hanna-4B 01W and Lawrence Livermore Hoe Creek underground coal gasification condenser waters. These process waters were then compared to a published summary of the analyses from 18 simulated in situ oil-shale retort waters. We completed this year 96-h flow-through toxicity bioassays with fathead minnows and rainbow trout and 48-h flow-through bioassays with Daphnia pulicaria exposed to 5 oil-shale process waters, 1 tar-sand process water, 2 underground coal gasification condenser waters, 1 post-gasification backflood condenser water, as well as 2 bioassays with fossil-fuel process water constituents. The LC/sub 50/ toxicity values for these respective species when exposed to these waters are given in detail. (LTN)

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Yield loss from oil retorts with zones of contrasting permeability and use of external fuel to improve yield

This report documents test conditions and results from the last two tests in a series used to study yield losses caused by permeability contrasts in modified in situ oil shale retorts. Zones of contrasting permeability are created by loading particles of one size distribution into part of the retort and those of another size distribution into the remainder. Shale for tests S78 and S80 was loaded using identical shale grade, particle size, and bed geometry to create duplicate shale beds. Tests S78 and S79 were conducted using a 70% air and 30% steam mixture flowing at 1.25 standard cubic feet of gas per square foot of empty bed each minute. Test S80 was conducted with air flowing at 0.875 standard cubic feet per square foot per minute while injecting propane into the top of the high permeability zone to maintain 1600 to 1800/sup 0/F in the high permeability zone behind the retorting combustion front. The high temperature in the high permeability zone in test S80 increased resistance to flow by increasing the viscosity and reducing the density of gases flowing through that zone. The increased resistance reduced gas flow and slowed the retorting front advance rate in the high permeability zone while increasing the advance rate in the zone having low permeability. The overall effect was to cause a more uniform retorting front which improved sweep efficiency and increased oil yield. We found the use of external fuel in test S80 increased the sweep efficiency from 50% in test S78 to 80% and increased the oil yield from 16.5 to 32.2% of Fischer assay yield. The increase in oil and gas yield from test S80 over S78 resulted in a net energy ratio of 2.4 based on the gross calorific values of the increases in oil yield and gas yield compared to the propane consumption. 8 refs., 5 figs., 8 tabs.

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Isolation and characterization of saturates from tar sand bitumens and thermally produced oils

A desorptive Soxhlet extraction technique and a high-performance liquid chromatographic procedure were used to isolate saturates from tar sand bitumens and produced oils. The oils had been thermally recovered by combustion and hot-gas injection from samples of the Asphalt Ridge and the Tar Sand Triangle deposits in Utah. The distributions of the saturates in the produced oils and in the tar sand bitumens have been identified, and the effects of thermal processing conditions on bitumen composition have been evaluated. Oil recovered by reverse combustion of Asphalt Ridge tar sand contained a lesser amount of saturates compared with the amount in the bitumen; oil recovered by forward combustion of Tar Sand Triangle tar sand contained a greater amount of saturates compared with the amount in the bitumen. The hot-gas injection process at temperatures greater than 493/sup 0/C recovered more oil high in saturate content than either combustion process. Results from field ionization mass spectrometric analysis indicated larger amounts of saturates with a mass-to-charge ratio (m/z) of less than 400 were present in the product oil from forward combustion than were present in the bitumen from the Tar Sand Triangle. The saturates in the oil from forward combustion were comprised mostly of acyclic alkanes, and mono- and dicycloalkanes. The saturates in the product oil from reverse combustion of Asphalt Ridge tar sand were comprised of nearly equal amounts of acyclic alkanes, and mono-, di-, and tricycloalkanes. Greater amounts of material with an m/z from about 200 to 500 were present in oils recovered by hot-gas injection than in the bitumens. The product oil yields were due, in part, to low- or high-temperature oxidation reactions. The extent of thermal cracking of the tar sand bitumens was found to be a function of the pyrolysis temperature, and the distribution of saturates reflected the severity of thermal cracking. 24 refs., 8 figs., 4 tabs.

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Underground gasification for steeply dipping coal beds. Phase I report:  Appendix C. Parametric cost estimate, September 30, 1977--February 28, 1978

Gulf Research and Development Company has developed a proprietary computer program to calculate economics for a conceptual commercial UCG plant as applied to horizontal coal seams. The present program cannot provide steeply dipping bed (SDB) economics. However, various factors related to the coal seam, to operating conditions, and to process results may be independent of whether the coal bed is horizontal or tilted. A number of factors have been varied over a considerable range to show their effect on economics for a horizontal bed application. These results should be helpful in designing experimental field studies in steeply dipping beds. The computer calculations show that the most effective way to reduce the cost of gas from UCG is to increase its heating value. This decreases the plant size, number of wells, coal consumed, and fuel requirements. The next most effective ways are to increase product gas recovery and air utilization, i.e., to minimize leakage. To express these effects in another way, each 2 percent increase in either air or gas leakage increases the sales gas price by 1 percent. Also, decreased leakage results in smaller plants, fewer wells, less coal consumption, and lower fuel requirements all of which reduce final costs. An increase of 50 percent in either the methane or the hydrogen content of the product gas has about the same effect on sales gas price. The decrease in price is due to the increase in heating value of the gas. The essential element appears to be increased heating value and the manner in which this is accomplished does not greatly matter from a cost per unit of heat standpoint. Increased production wellhead pressure has a beneficial effect on gas price because the conceptual plant design requires that the production gas be compressed to 1135 kPa (150 psig) for pipelining to the main plant. The remaining parameters have only moderate effects on the gas price.

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1978 herbaceous production study

Herbaceous productivity studies on the Geokinetics Oil Shale Project Research site in Uintah County, Utah were begun during the summer of 1978. These studies were designed to assess the amount of biomass produced by herbaceous vegetation in each of the vegetation types occurring on the site. Measurements were made in each of the control and treatment plots established for these types. The results given in this report are those obtained from the analysis of data collected during 1978. The chief objective of the herbaceous productivity study is to determine the amount of herbaceous biomass that is potentially available for use by herbivores on the LOFRECO site. As such, these studies are an intergral part of determining the carrying capacity of the site. The data collected from the 1978 study will be used together with other ecological information to provide a functional description of the site. Of particular importance in this synthesis are the data obtained from shrub utilization studies, phytosociological data, and the quantitative descriptions of the physical environment derived from ecoclimatic measurements. Herbaceous productivity will be monitored during the pre and post disturbance phases of the research site development.

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Analytical chemistry of liquid fuel sources:  tar sands, oil shale, coal, and petroleum. Chapter 16. Olefin analysis in shale oils

The classical silica gel chromatographic method for determination of percent olefins in shale oils was studied and found wanting, mainly because of cross-contamination from high levels of olefins and heteroatom-containing compounds. This paper describes a new hydroboration oxidation procedure for olefins, and reports its use in hydrocarbon-type analysis of both whole shale oils and distillate fractions. Percent composition values for three whole oils ranged as follows: saturates, 13-26; olefins, 16-20; aromatics, 5-14; polar compounds, 41-62. A discussion of IR analysis for relative amounts of specific olefin types such as terminal, internal trans, and methylene structures is included.

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Operation of a process development unit for the preheating, retorting, combustion and cooling of oil shales

Allis-Chalmers has designed, built and successfully utilized a Process Development Unit for the testing of hydrocarbon-containing material. Over 55 tests have been conducted with western and eastern shales. In addition, successful retort tests have been completed using Utah tar sands and California diatomaceous earth. Problems encountered with the oil collection system have shown that the oil is not as easy to collect or account for as first anticipated. In solving this problem, however, valuable experience was gained to be used in larger-scaled projects. The PDU has also been used to develop pressure drop and heat transfer coefficient correlations that are the basis for scale-up. In addition, data obtained from the PDU on size effects, gas temperatures, solids temperatures and combustion requirements complete the information required to design demonstration, semi-works or commercial-scale plants.

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Application of hydropyrolysis to the hydroconversion of Eastern oil shale. Final technical report

The two major objectives of the project were: (1) testing, data reduction, and chemical analysis to determine the performance of Eastern oil shale in a hydropyrolysis reactor; and (2) selection of an operating point suited to high yields of shale oil and performance of a preliminary process analysis and economic assessment of the process. Six tests were conducted in the 1-TPH process development unit (PDU) at 1100 and 1400/sup 0/F, nominal reactor residence times of 75 and 200 ms, and a reactor pressure of 1000 psig. A blend of Cleveland Member of the Ohio shale, pulverized to 70% through 200 mesh, was used as feedstock. Excellent material balances were obtained for the test series, which had an average test duration of 68 min and an average shale throughput of 1688 lb. Total carbon conversions as high as 70.0% and carbon conversions to liquids as high as 55.5% were found. Production of raw shale oil ranged from approximately 13.5 to 19.0 gal/ton of shale fed compared with a Fischer assay of approximately 13 gal/ton. Nitrogen and sulfur concentrations in the untreated whole oil were approximately 2.2 and 1.6 wt. %, respectively, and very low hydrogen consumption in the reactor was observed. Excellent data correlation was obtained as a function of reactor severity, expressed as carbon conversion to methane. Based on a selected operating point, a conceptual design was developed for a commercial-scale plant producing 50,000 bbl/day of partially hydrotreated shale oil, suitable as refinery feedstock. Product oil yield is approximately 21 gal/ton of dry shale. Input to the plant consists of 4150 TPH of dry shale and imported methane. The estimated plant investment is approximately $2 billion in first-quarter 1983 dollars, including a 15% project contingency. The calculated average product selling price is $35.20/bbl.

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Organic and pyritic sulfur determination in oil shale

Sulfur forms in oil shale are defined according to their reduction rates to H/sub 2/S in the presence of hydrogen-donor solvents. A linear increase in temperature with time is applied to a reaction system of oil shale and hydrogen-donor solvents. The different temperatures at which H/sub 2/S is detected corresponds to specific sulfur-functionality reductions and produces a reaction profile, or kinetogram. The kinetograms of 10 standards and 13 different oil shales are given. The method of analysis is simple. Aromatic and aliphatic disulfides, sulfides, thiols, and pyrite can be detected, however we are not yet sure about the detection of thianthrene structures and thiophenic structures. Our present results indicate that this is a promising approach, but improvements in the procedure must be made to optimize the analytical technique.

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The effect of programmed heating on yields and oil quality in retorting of Green River oil shale

Three large blocks of oil shale from the Hell's Hole Canyon outcrop were selected and graded with Fischer assay at 18, 45 and 73 US gal/ton. Smaller cubes with similar bedding planes were cut from these blocks, with side dimensions of around 0.12 m. These cubes were heated under a nitrogen atmosphere, with constant heating rates of 2, 1, and 0.5 C/min, respectively, from ambient temperature up to 600 C. Two additional runs were performed for each block holding the temperature constant for 24 hours at 200 C and 300 C (soaking conditions). In all cases the liquids collected during the retorting process had a higher hydrogen to carbon ratio (1.7 to 1.8) at the beginning of the runs than near their end (1.35 to 1.6). Their nitrogen content increased from 1.5 to 1.8 weight percent initially to 3 to 3.8 weight percent at the end of the runs. For the 200 C soaking condition the oil produced was lighter (i.e., lower density and better yield of lower boiling point components) than the oil produced in the other two cases (no soaking and 300 C soaking). A mathematical model was written to simulate the oil production for the 18 US gal/ton cubes. The comparison between the experimental results and the model postulates that the decomposition of the organic matter in the oil (kerogen) follows a parallel reaction sequence to form bitumen with several intermediate components.

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Antrim oil shale:  brine removal

Over 63,000 gallons of brine were removed from a ten well system on the front forty acres of Dow's Sanilac County Oil Shale Field Site using airlift and Reda pumps from December 17, 1976, to June 30, 1977. Brine continues to enter the system at 4,000 - 6,000 gallons/month, for the most part in a four well zone highly fractured by explosives. The system will be periodically airlifted or pumped from July until the conclusion of a combustion experiment scheduled from August, 1977 - February, 1978.

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Chemical equilibria model analysis of Hope Creek eastern oil shale lysimeter leachate data

Recently, a five-year field lysimeter study designed to evaluate the reclamation and leachate generation characteristics of eastern oil shale material was completed. Leachates from the lysimeters were subjected to detailed chemical analyses, and the elemental release patterns were examined as a function of time. The objectives of the present study are to provide a more detailed characterization of the chemistry of lysimeter leachates by subjecting the leachate concentration data to chemical equilibria model analysis.

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Investigation of the Geokinetics horizontal in situ oil shale retorting process. Quarterly report, October, November, December 1980

The ignition of Geokinetics first full-sized prototype retort (Retort 24) was completed on December 1, 1980. Recovery of oil from Retort No. 24 began about midway through December, and 531 barrels of oil had been recovered by the end of the quarter. A cold oil effect resulted in the accumulation of oil within the retort. Five thousand one ninety one barrels of oil were shipped to WESRECO, Salt Lake City, Utah during the quarter, and the shale oil was blended into No. 5 fuel oil, which was sold to industrial users. The Retort No. 25 post-blast core drilling program was completed in October. A total of seven core holes were drilled. Evaluation of the core samples was underway. Preliminary analysis indicated good breakage in the lower portion of Retort No. 25. A new technique for sealing retort surface fractures was designed and implemented on Retort No. 25. A layer of bentonite with gas and steam retention properties was applied to the retort surface and covered with a layer of topsoil.

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