AndreaBozzo/ceres-open-data-index huggingface dataset:
Sulfur in petroleum. II. Boiling points, freezing points, densities, and refractive indices of some sulfur compounds

Although the presence of sulfur causes many petroleum to be classified as “low-grade” because of the difficulties encountered in manufacturing products to meet rigid specifications, the petroleum industry is finding it necessary to use such crude oils to satisfy present needs. As the demand for petroleum products increases, and available reserves diminish, this utilization of high-sulfur crude oils will be accentuated. Programs designed to supplement the supplies of fuel available from petroleum by the manufacture of synthetic fuel from natural gas, shale oil, and coals are in progress. Such fuels, especially shale oil and, less so, oil from the hydrogenation of coal, also contain sulfur compounds which must be effectively removed. Thus, the need for fundamental research on the sulfur compounds that may be expected in petroleum and allied products is becoming greater as the industry is forced to call upon all available resources to meet the demand for petroleum products. In recognition of this need, the Bureau of Mines has inaugurated a long-range program designed to furnish fundamental data concerning the presence, characteristics, and effects of sulfur compounds in petroleum and its products.

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Liquid fuels from oil shale. Bureau of Mines program. [Survey article]

There were oil-shale and coal-oil plants in the U. S. when the first well was drilled for oil in Pennsylvania  in 1859.  These soon succumbed to the competition of petroleum, and there was little activity in this country until World War I.  The Bureau of Mines began its study of oil shale in a small way before the U. S. entered World War II and resumed  the study in 1919. This phase of the Bureau's oil-shale work terminated with the closing of the Bureau of Mines Oil Shale Experimental  Plant near Rifle Colorado on June 30, 1929. Closing of this plant was Motivated mainly by the discovery of large oil fields in California, Oklahoma, and Texas, and the likelihood of an abundance of petroleum rather than a scarcity.

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Some chemical and physical techniques for separation and identification of nitrogen compounds in petroleum

The segregation and analysis portion of API Research Project 52 is concerned with the separation and identification of the nitrogen compounds which occur in virgin petroleum. Protecting these compounds from changes caused by cracking, oxidation, polymerization, or hydrogenation during the separation processes requires diligence and ingenuity. Some of the precautions are detailed in this paper. Two exploratory approaches to the segregation of nitrogen compounds are described and some data collected in these experiments are presented. These data subsequently were used in selecting an approach for future work involving separation of the crude oil into specific boiling-range fractions.

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Monitoring in situ retorting processes of oil shale by reflected and transmitted electromagnetic waves

A theoretical model for an in situ oil shale retort with three distinct zones surrounded by the wall of oil shale deposits, the overburden and underburden, is considered to study monitoring the progression of retorting processes by means of the electromagnetic wave propagation. The overall power reflection and transmission coefficients for both transverse electric and transverse magnetic waves are obtained as a function of position of a combustion zone in the retort based upon the assumption of straight line propagation of monocromatic plane waves through layered lossy dielectric media.

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Motor gasoline from shale oil. [Review of selected research on upgrading shale gasoline]

Shale oil produced from oil shale of the Rocky Mountain region by many of the usual retorting processes consists mainly of high coiling compounds of nitrogen, sulfur, and oxygen, less than half of the oil, consists of hydrocarbons. Thermal cracking of the oil followed by acid and caustic treating of the gasoline fraction has produced stable gasoline with low to moderate octane numbers. Hydrogenating the raw crude oil has produced higher yields of stable gasoline, also with low to moderate octane numbers. The yields and octane numbers of the gasoline are dependent on the hydrogenation temperatures used. Low-octane hydrogenated gasoline has been catalytically reformed over platinum-containing catalyst to produce high-octane motor fuel.

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Hydrogenating shale oil to catalytic reforming stock. [At 543/sup 0/ and 3000 lb. pressure]

"Gasoline having higher octane numbers than any previously reported from ordinary Colorado shale oil were obtained during high temperature hydrogenation of gas-combustion crude at 3000 pounds pressure. Single-pass operation at 1010 degrees F produced gasoline in yields approximating the best reported for recycle thermal cracking of crude shale oil but the leaded Research octane number of 92.4 and low sulfur and nitrogen content are superior.  The effects of hydrogenation temperatures between 760 degrees and 1010 degrees F were studied. Gasoline obtained at the higher temperatures has better properties but total liquid yields are better at lower temperatures. Operation at about 900 degrees F appears best for producing catalytic reforming stocks."

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Hydrofining thermally cracked shale-oil naphtha. [At 510 to 538/sup 0/ and 400 to 800 lb/in/sup 2/]

"Hydrofining thermally cracked shale-oil naphtha at high temperatures, pressures, and space velocities has been investigated for reducing high sulfur and gum content and improving stability, volatility, and octane characteristics.  Specification gasoline in high yields may be produced at 950 degrees to 1000 degrees F. and 400 to 800 pounds per square inch. The higher pressure is more favorable for removing sulfur and gum-forming compounds at the higher temperatures desirable for increasing octane numbers. Hydrofining heavy naphtha and blending with caustic-washed light naphtha gives lower hydrogen consumption, better gasoline yield, and gasoline with better volatility and sensitivity than hydrofining whole naphtha."

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Hydrocracking prehydrogenated shale oil

Shale oils with lowered carbon residue and metals contents were prepared by prehydrogenating crude gas-combustion shale oil at 1000 pounds’ pressure and 600 degrees to 660 degrees F. The prehydrogenated oils were once-through hydrocracked at 1000 or 1500 pounds with temperatures from 800 degrees to 900 degrees F. At a given conversion, naphtha yields were about the same at both pressures, but sulfur and nitrogen percentages were lower at 1500 than at 1000 pounds. At 900 degrees F., naphthas obtained at 1000 pounds averaged below 0.10% nitrogen and those obtained at 1500 pounds averaged 0.02%. These percentages were reduced to below 0.01% when the tar bases were removed. A 66-hour recycle hydrocracking run at 1000 pounds and 907 degrees F produced 80.6 and 106.4 volume % of conversion as, respectively, C5  and C4  naphthas.

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LOW BTU GAS PRODUCED BY UCG IN THE WESTERN US - ECONOMICS AND PROSPECTS

"Underground coal gasification (UCG) to produce low Btu gas (LBG) has been tested successfully on numerous coal seams in several countries. Further tests will be useful in improving the technology and examining environmental effects. However what is most needed now is commercial demonstration of LBG production by UCG on a large scale.  In this paper the economics and marketplace competitiveness of UCG are examined. The economics of LBG production are attractive based on conservative assumptions drawn from the Hanna test results. The required price for LBG produced by underground gasification of western subbituminous coal is estimated to be about $1.30 per million Btu. The principal unproved assumption in arriving at this price is that the Hanna results can be extended economically to gasification across a large array of wells.  The most important use of LBG produced in sparsely populated western coalfields is the generation of electric power. Base-load electric power produced by firing strip-mined coal in the west is estimated to cost about 26 mills per kWh at the mine mouth. This is slightly more than the price of power from firing LBG produced by UCG. For much of the west both these prices are lower than prices required for nuclear power or oil-fired produced power.  The key to the competitiveness of “mine-mouth” conventional or UCG-based power plants is the cost of power transmission. The cost of power transmission is dependent upon high capacity. For example, a typical cost of transmitting 5,000 megawatts of power is about 1 mill per 100 miles, but the cost of transmitting 500 megawatts is about 5 mills per 100 miles. These costs suggest that “in-situ power” generated in Wyoming may someday be competitive as far away as southern California."

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Distribution of nitrogen in hydrocracked in situ shale oil

Crude shale oil from underground in situ retorting of Wyoming oil shale was hydrocracked over a nickel-molybdena catalyst in a single-pass operation at 800 degrees F, 1500 psig pressure, and 0.5 vol of oil/ (vol of catalyst/h). The liquid product was fractionally distilled into naptha and heavier oil. The 54 fractions distilling above naphtha were collected at 5 degrees F intervals (at 10 mm absolute pressure), and nitrogen percentages were determined on these. Thy hydrocracking eliminated 98% of the nitrogen from the oil, but the boiling-range distribution of the nitrogen compounds remaining in the oil resemble that of the nitrogenous components in raw shale oil and in hydrocracked gas-combustion shale oil.

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Diesel and burner fuels from hydrocracking in situ shale oil

"For several years, the Bureau of Mines has conducted research in recovering shale oil through in situ retorting by the underground combustion method. Crude shale oils produced by this method normally have lower specific gravities, viscosities, and pour points than do crude shale oils produced in the gas combustion or N-T-U retorts. They also contain somewhat less nitrogen, but the sulfur content is not greatly different from that of the crude oils from these above-ground retorts. Percentages of both elements are higher than desirable in liquid fuels or in feed-stocks that are to be processed to high-quality liquid fuels by most catalytic refining processes.  Catalytic hydrogenation at cracking conditions, referred to here as “hydrocracking”, has been found by previous experiments to be a suitable method for producing low-sulfur, low-nitrogen “synthetic crude” oils from in situ crude shale oils (1-3). One of the primary objectives of these previous experiments has been to increase the quantity of gasoline contained in the hydrocracked synthetic crudes. A limited investigation of the suitability of fractions of the hydrocracked oils as catalytic reforming and catalytic cracking feedstocks for the production of gasoline has been made (1,2,10944 ); however, little attention has been given to the types of diesel fuels and fuel oils that can be prepared from the fractions.  The purpose of the present work was to investigate the quantity and quality of diesel fuels and fuel oils that could be prepared from the liquid product obtained by hydrocracking of in situ combustion shale oil. A sample of the in situ crude oil was hydrocracked at operating conditions that had been found by previous experiments to be effective in eliminating most of the nitrogen and sulfur from the oil and in greatly reducing the average boiling point of the oil. The hydrocracked oil was distilled into a 350 degrees F end-point reforming stock and small-volume heavier fractions. Diesel fuels, suitable for use also as fuel oils, were prepared by blending of small-volume fractions."

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Depleted uranium as a catalyst for hydrocracking shale oil. [Use with cobalt molybdate at less than or equal 940/sup 0/F and alumina at approx 990/sup 0/F]

"Uranium compounds have, at various times, been tested as hydrogenation catalysts. Prior to World War II, uranium was generally believed to occupy a position in the periodic table as a member of the chromium subgroup of elements together with chromium, molybdenum, and tungsten. In forming a characteristic solid trioxide and in displaying oxidation valences from 3 to 6 (11, 13), uranium resembles molybdenum and tungsten, whose compounds have found considerable application as catalysts for hydrogenation-dehydrogenation reactions. These facts prompted the testing of uranium compounds for similar uses, and several patents were issued for these uses (1). Modern versions of the periodic table place uranium in the actinide series of elements in a position analogous to that of neodymium in the lanthanide series, which also has been reported to be a catalyst for hydrogenation-dehydrogenation reactions (14).  As a result of the atomic energy program, the Federal government has accumulated a large stockpile of “depleted uranium” – the material remaining after the U-235 isotope has been removed. The extraordinary purification procedures used in its preparation encourage applications, such as catalyst the, where relatively high freedom from contaminants might be advantageous.  This paper reports the preparation and testing of two depleted uranium oxide catalysts for se in hydrocracking rude shale oil. The objectives of the hydrocracking experiments were to convert high-boiling shale oil into gasoline-boiling-range products and to eliminate sulfur and nitrogen from the gasoline produced."

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Depleted uranium as catalyst for hydrocracking shale oil

"As a result of the atomic energy program, the federal government has accumulated a large stockpile of “depleted uranium”—the material remaining after approximately half of the U-235 isotope has been removed from natural uranium (Parker, 1971). The extraordinary purification procedures used in its preparation encourage applications, such as catalyst use, where relatively high freedom from contaminants might be advantageous. Chemically, it is identical to highly purified natural uranium.  Uranium catalysts have recently been finding important uses. Several of Britain’s regional gas boards use a uranium-based catalyst to produce town gas by steam reforming of naptha, and Mobil A.G. uses uranium-containing catalyst to make town gas from refinery gases. Uranium oxide is reported to contribute high catalytic activity and resistance to deactivation by carbon for the nickel-uranium catalyst on a corundum support. Also, a Standard Oil Co. (Ohio) catalyst consisting of oxides of antimony and uranium on a silica support is said to produce a 20% better yield in the production of acrylonitrile from propylene and ammonia than the former bismuth catalyst (Chem. Eng., 1968).  This paper reports the preparation and testing of two depleted uranium oxide catalysts for use in hydrocracking crude shale oil. The objectives of the hydrocracking experiments were to convert high-boiling shale oil into gasoline-boiling-range products and to eliminate sulfur and nitrogen from the gasoline produced."

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Catalytic gasification of shale oil

Crude shale oil was hydrogasified at 1000 lbs. pressure over depleted uranium and cobalt molybdate catalysts at temperatures in the range 880 degrees – 1102 degrees F with depleted uranium and 974 degrees -1196 degrees F with cobalt molybdate. With both catalysts, the higher reaction temperatures produced greater hydrocarbon gas yields, greater percentages of methane in the gas, and greater methane yields expressed as percentage of conversion of the feedstock. The larges methane yields—4340 cu. Ft. per barrel—and largest hydrocarbon gas yield—of 5725 cu. Ft. per barrel—were obtained at the highest temperature (1196 degrees F) and lowest space velocity (0.25 Vo/Ve/hr.) used. At these conditions, methane yield was 75.8 vol.% of the hydrocarbon gas and 49.7 percent of stoichiometric.

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Technical and economic feasibility of oil shale beneficiation by heavy media

A study to evaluate physical beneficiation processes was undertaken to assess the efficacy of beneficiating oil shale, and to measure its impact on the economics of shale oil production. Analysis of the data show that froth flotation is the preferred technique of beneficiating shales as opposed to heavy media separations. Maximum separations of kerogen and clays occur at particle sizes below 20 microns.

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Natural cementation of retorted oil shale. Final report, February 1978-May 1979

The natural cementation strength of retorted oil shale is the focus of this study. The optimum retorting temperature and residence time for development of cementation strength of minus 0.5-inch Green River oil shale are direct mode at 1,510 degrees F and 2.0 hours or indirect mode at 1,530 degrees F and 2.9 hours. Maximum obtained compressive strengths developed during moist curing were 270 and 326 psi, respectively. Use of a differential oil shale retort allowed close control and measurement of the retorting conditions. Correlations were developed for compressive strength as a function of curing time at 100 degrees F, for compressive strength as a function of direct mode retorting temperature and times, and for compressive strength as a function of indirect mode retorting temperature and time. Other information developed as functions of retorting temperature, time, and mode include optimum Proctor density, optimum Proctor moisture content, effect of compaction water composition (tap water versus oil shale retort water), leachate composition from the retorted shale, and permeability of compacted but uncured retorted shale. The retorted shale apparently acted as an effective filter for many of the ions in the retort water. A petrographic analysis including optical microscopy, scanning electron microscopy, X-ray diffraction, and X-ray fluorescence indicated that the cementing mechanism is the interlocking growth of acicular crystals on the surface of the retorted shale fragments. The crystals appear to be composed of a hydrated calcium aluminum sulfate.

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Steam cracking of shale oil liquids

"Shale oil liquids produced by steam pyrolysis of oil shales from Anvil Points and from the leached zone of the Parachute Creek member of the Green River Formation were cracked in the superheated steam in a one-liter autoclave. Steam pressures to 100 atm and temperatures to 454 degrees C were employed. Gas samples were withdrawn and analyzed by gas chromatography and liquid samples were analyzed by GC-MC, C^13 NMR, and elemental analyses for carbon, hydrogen, nitrogen, and sulfur and oxygen.  Sulfur content was reduced 98.7% and nitrogen content was reduced 35% in the cracked liquids. Pour points were reduced from 10 degrees C – 32 degrees C (50 degrees F-90 degrees F) for the starting material to less than -18 degrees C (0 degrees F). Most of the unsaturated hydrocarbons were hydrogenated during cracking and the C/H ratio dropped from 7 after steam pyrolysis to 6.5 after cracking.  An observed pressure recovery during sampling has been explained as a readjustment of the chemical equilibria following the abrupt pressure reduction during sampling."

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Mathematical modeling of modified in situ and aboveground oil shale retorting

"A one-dimensional mathematical model has been developed for simulating the chemicophysical processes involved in the vertical retorting of a rubblized bed of oil shale. Included in the present model are those processes believed to have the most important effects in either the hot-gas retorting mode or the forward combustion mode. The physical processes are axial convective transport of heat and mass, axial thermal dispersion, gas-solid heat transfer, intraparticle shale thermal conductivity, water vaporization and condensation, wall heat loss, and movement of shale countercurrent to the flow of gas. The chemical reactions within the shale particles are release of bound water, pyrolysis of kerogen, coking of oil, pyrolysis of charm decomposition of carbonate minerals, and gasification of residual organic carbon with CO2, H2O, and O2. The chemical reactions in the bulk-gas stream are combustion and cracking of oil vapor, combustion of H2, CH4, CHx, and CO, and the water-gas shift.  The governing equations for mass and energy balance are solved numerically by a semi-implicit, finite-difference method. The computer program is written in LRLTRAN (an extended version of FORTRAN) for use on a CDC-7600 or CRAY computer. The bulk-gas flow rate as well as the composition and temperature of both the gas stream and the shale particles are calculated as a function of time and location in the retort."

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Electrothermal recovery of petroleum

For many years petroleum engineers have contemplated utilizing some form of thermal energy in the recovery of petroleum from the untapped resources of the American continent. Much of this oil occurs in bituminous sands and oil shale's where well established recovery methods are futile. The recovery of this oil may exist as an economic possibility from these presently marginal source beds if some efficient means can be devised for the application of thermal energy to the formation.

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Processing in-situ oil shale retort offgas with a Stretford plant at Geokinetics

The EPA transportable Stretford process pilot plant was used on a 700 ACFM slipstream o in-situ shale oil retort offgas to investigate H2S removal efficiency ;and process compatibility.  This was the fourth application of the pilot plant which had demonstrated a continuously improving performance.  During this test the pilot plant was operated first with a venturi contactor alone and then with the venturi followed in series by a packed tower contactor.  With the venture alone, the plant achieved  95 percent removal efficiency, but its average performance was lower.  With the addition of the packed tower, the removal efficiency reached 99  percent.  Excessive foaming of the process solution was experienced which was attributed to the presence of organic aerosol in the retort offgas.

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PYROLYSIS KINETICS OF TEXAS LIGNITE

"This research has consisted of a study of the pyrolysis kinetics of Texas lignite. The objective of this research was to obtain kinetic data for the production of gaseous species form Texas lignite, and incorporate those data into a model which could predict the production rate of each species as a function of heating rate and temperature.  Evolution rate data, for hydrogen, carbon monoxide, carbon dioxide, methane, ethane, and ethylene, were obtained with Texas lignite, of the Wilcox group and fitted to a kinetic model. The results were compared with other kinetic data presented in the literature."

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