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By G. S. Hume

Introduction O WING to the mineral discoveries which have recently been made in the Great Bear Lake region and the possibility of the need for fuel for transportation and development, it seems.timely ro review available information regarding the oil prospects in the vicinity of Great Slave lake and Mackenzie river, where a vast area is underlain by Palreozoic and younger sediments that undoubtedly are petroliferous. Exploratory surveys were carried out in this area by the Geological Survey and others in the latter part of the 19th century, but it was not until 1920, when drilling for oil actually began, that any serious attention was paid to the oil prospects. This is readily accounted for by the remoteness of the region, the lack of quick transportation facilities, and the shore summer season. Numerous and copious oil seepages had been reported, however, from widely separated localities, and interest was stimulated by the knowledge that these occurred in Devonian strata which had given a remarkable record of sustained production of high-grade oil in the oil-fields of southwestern Ontario. . Accordingly, during the four years 1920 to 1923, inclusive, several parties sent out by the Geological Survey made as thorough an investigation of various parts of the area as seemed warranted at that time, and from these surveys most of our information regarding the details of the stratigraphy is derived. In such a large area, it is inevitable that the lithology and thickness of rocks of the same age would show wide variations, and hence it should be recognized that conditions as regards oil prospects in the vicinity of the west end of Great Slave lake are quite distinct from those that occur near Fort Norman, 400 miles farther to the northwest, and these again are in all probability quite different from those in the less well known Arctic Red River area, 250 to 300 miles still farther north.

Jan 1, 1932

By John L. Rich

A New Field for the Mining Industry A new field for the mining industry is in prospect. This is the recovery of the petroleum which has been left in the ground in the older oil fields whose yield has declined until they are no longer profitable to operate in the ordinary way. The fact that an oil field has reached the economic limit for operation by pumping does not necessarily 'mean that the oil has ? been exhausted. In many such cases not over one-fifth, or even one-tenth, of the total oil content of the field may have been taken out when this stage has been reached. This means that there exists a large reserve of oil which can be recovered by whatever process best takes advantage of the natural conditions under which the oil occurs. Mine drainage is one of the processes by which this oil may be recovered. Its relative importance will depend partly on the ingenuity and wide-awakeness of mining engineers, and on mining capital. The opportunity is undoubtedly at hand. In order that we may be in a position to judge the possible advantages of mining methods for the recovery of this oil, I have reviewed, on the following pages, the methods now in use, and have discussed the physical conditions of the reservoir rocks in which the oil is found, and the suitability of the various recovery processes, in use or proposed, in the light of these reservoir conditions.

Jan 1, 1927

By Joseph Chalmers, J. S. Desmond, R. Van A. Mills

[Because of the limited space in this volume and the fact that a description covering the oil recovery buildings and equipment (see page 4, Technical Publication No. 144) will be given in a forthcomnig U. S. Bureau of Mines publication, and because the paper was published in detail as Technical Publication No. 144, and is available as a separate at the Institute, it is impossible to include here more than the following brief extract.] Problems Being Studied The selection of the first problems to be studied was based largely upon the following very practical questions asked by several of the largest operators in the Mid-Continent field. 1. What are the causes for the formation of excessive amounts of bad thick oil on properties that are being repressured with compressed air and how can this trouble be prevented? 2. Why, in some areas, does the oxygen in the air injected into an oil sand during repressuring operations apparently change to carbon dioxide? Is carbon dioxide formed by the oxidation of some of the oil in the sand'? How can the formation of inert or low B.t.u. casinghead gas, loaded with nitrogen, carbon dioxide and oxygen, be prevented? 3. What percentage of the oil originally present in an oil sand can be recovered by the ordinary methods of operation when the gas originally dissolved in the oil is the main propulsive agent? 4. What percentage of the amount of oil produced by ordinary methods can be recovered under average conditions by repressuring a so-called depleted oil sand? 5. What are the relative propulsive efficiencies of compressed air and natural gas in repressuring operations? 6. What are the practical advantages of pressure maintenance and early repressuring as compared with late repressuring?

Jan 1, 1929

By Gustav Egloff

AN unexpected and unprecedented demand for its products now challenges the petroleum industry. Between 1939 wand 1946, domestic oil demand increased nearly 45 per cent and in the first half of 1947 it was 10 per cent higher than in 1946. In 1939 the United States produced 1,264,962. 000 bbl of crude oil and indications are that about 1,860,000,000 bbl will be produced in 1947, a 47 per cent increase. Runs to stills are more than keeping pace with production. The crude capacity of 365 operating refineries is rated as 5,400.000 bbl daily and almost 100 per cent of this capacity was running crude oil in August 1947. The oil industry is cognizant of our need for a greater volume of petroleum products and is expending the huge stun of four billion dollars on exploration. production. transportation, refining. and marketing of petroleum. Of this amount about half will be spent on exploration and production. a billion on refining. and another billion on transportation and marketing facilities.

Jan 1, 1947

By Elisabeth Schmidt

The conventional Canadian oil sand processing, the Clark Rowe process, is associated with many risks for the environment and high energy costs. To recover the bitumen from the oil sand (tar sand), large quantities of water have to be heated up and mixed with caustic soda and the oil sand. During this process, tailings with stabilized clay colloids are formed and dumped in tailings ponds. To avoid these disadvantages, a new, non-aqueous extraction process is to be established. Organic solvents are used instead of water and caustic soda to mobilize the bitumen from the sand-clay mixture. Pressure filtration, washing and steam pressure filtration are part of the new concept. A mixture of organic solvents and the oil sand is first pressure filtrated in a nutsch filter until a saturation level of one is obtained. After the cake has been formed, the filter cake is washed with organic solvent to flush the bitumen loaded solvent out of the cake. The following steam pressure filtration mechanically and thermally removes the remaining volatile components of the solvents from the filter cake. The filtrates from the pressure filtration, the washing phase and partly from steam pressure filtration are subsequently thermally treated to recover the organic solvents and obtain a higher bitumen concentration in the mixture. This mixture is then lead to an upgrader to win synthetic crude oil (SCO). The recovery of bitumen in the conventional hot water extraction process based on the Clark Rowe process can, in highly optimized plants, achieve between 88 and 92 %. Variation of oil sand properties leads to an actual range of between 80 and 90 % of bitumen recovery. With the alternative process based on organic solvents, the bitumen recovery exceeds the recovery of the conventional process by up to 16 percentage points. The composition of the two organic solvents in the first step of forming a suspension with the oil sand is important. The aromatic component is crucial for liberating and solving the asphaltenes, which tend to flocculate. The order of the two components of organic solvents is also important in the washing step. The paraffinic component is essential to achieve successful steam pressure filtration with respect to fast steam breakthrough and a filter cake free from organic compounds, as a result of its lower boiling point. Keywords: oil sand, filtration, organic solvents, pressure filtration, steam pressure filtration, filter cake washing

Sep 1, 2012

By Tim Grain Joseph

This paper considers the duty cycle of an electric cable shovel and correlations with measured passive seismic responses of the underfoot oil sand material in-pit. It has been observed that the cyclic activity during operation of any shovel in the oil sands environment causes the material to deteriorate and provide a less than ideal footing for this large item of equipment, whose dead weight approaches 1500 tons with a footprint of merely 75 square yards. Consequences are manifest in the form of carbody and side frame cracks, and associated downtime, maintenance activity, cost, and subsequent loss of availability. The objective of these considerations, as part of the Oil sands Equipment Interaction Program (OsEIP); currently a joint venture between Syncrude Canada Ltd., JPi Ltd., Caterpillar Inc., P&H MinePro and the University of Alberta; is to identify and provide feedback to the manufacturer and end user adverse shovel - ground conditions. This would enable the manufacturer to incorporate greater knowledge into the design process and the end user to direct operations in an enhanced proactive maintenance stance.

May 1, 2002

By Celine Y. Zhang, Chloe J. Feng, Charles Q. Jia, Donald W. Kirk

Oil sands petroleum coke (OSPC) is a by-product of coking - a high-temperature process that converts the mined bitumen to the synthetic crude oil (SCO). For every barrel of the SCO produced, about 20 kg of OSPC are generated. Over 70 million metric tons of OSPC have been produced and stockpiled as a result of the development of oil sands industry in the past few decades. Unlike conventional petroleum coke, OSPC has uniquely high impurity contents, particularly sulphur (~ 7 wt%) and metals (e.g. vanadium at ~0.15 wt%), which has hindered its large-scale applications as a solid fuel. Vanadium is a valuable metal that is widely used as an alloy for strengthening steels. The stockpiled OSPC contains about 100,000 tons of vanadium, while the world’s production in 2013 was only 75,600 tons. At the current price of $25US/kg, the OSPC-bound vanadium represents a total value of $2.5 billion US dollars. In this work, we investigate the technical feasibility of extracting vanadium from OSPC. The work focuses on the characterization of vanadium in OSPC and the conditions for effective extraction of vanadium from the OSPC.

Jan 1, 2015

By N. A. Beier, N. Slingerland

"Oil sands tailings impoundments rank among the largest (spatially) in the world, covering a total of approximately 220 km2 of northern Alberta, Canada. A preliminary geomorphic design for an oil sands tailings storage facility (TSF) landform was completed with the goal of eventual closure and delicensing in mind. This paper outlines methods identified during the design process that streamline closure when implemented early in the mine planning and TSF design stages. With most oil sands TSFs currently in active operation (and some still in the planning stages), geotechnical engineers and mine planners have the opportunity to make operational and design decisions, such as those outlined herein, that are likely to improve the geotechnical and environmental performance of the landform post closure. ¦ KEYWORDS Alberta, Athabasca oil sands (AOS), Landform design, Reclamation, Sand dam, Tailings storage facility (TSF) RÉSUMÉ Les bassins d’accumulation des résidus issus des sables bitumineux font partie des plus grands (en termes d’espace) au monde, et couvrent au total environ 220 km2 dans le nord de l’Alberta, au Canada. Une conception géomorphologique préliminaire a été réalisée pour le modelé d’une installa¬tion de stockage des résidus (ISR) issus des sables bitumineux en gardant à l’esprit la fermeture et le retrait de permis à terme. Cet article présente les méthodes identifiées pendant le processus de conception qui simplifient la fermeture lorsqu’elles sont mises en oeuvre dès les premières étapes de planification de la mine et de conception de l’ISR. La plupart des ISR issus des sables bitumineux se trouvent dans des exploitations actives (dont certaines en sont encore aux étapes de planification), aussi les ingénieurs géo¬techniques et les planificateurs miniers ont la possibilité de prendre des décisions en termes d’exploita¬tion et de conception, telles que celles présentées ici, qui pourraient améliorer la performance géotechnique et environnementale de la phase suivant la fermeture du modelé. ¦ MOTS CLÉS Alberta, assainissement, barrage de sable, conception du modelé, installation de stockage des résidus (ISR), sables bitumineux de l’Athabasca (SBA)INTRODUCTION The Athabasca oil sands (AOS) underlie 140,200 km2 of land in northeastern Alberta, Canada. Oil sands located within 100 m of the original surface account for 4,800 km2 of the total area and are considered to be economically mineable (Figure 1; ERCB, 2009). Bitumen, the thick, tar-like substance contained in the AOS, is extracted through open-pit mining and in-situ methods. During mining, the overburden is first removed as waste and the sandy, bitumi¬nous ore (“oil sand”) is transported to processing facilities via conveyor belts and 400 t trucks. Warm and hot water, as well as process aides such as caustic soda, are mixed with the oil sand, creating a slurry from which bitumen is mobilized and extracted. The resulting slurry waste product is called “tailings” and contains mineral solids, process water, and small proportions of unrecovered bitumen (Masliyah, Zhou, Xu, Czarnecki, & Hamza, 2004; Sobkowicz & Morgenstern, 2009)."

Jan 1, 2019

By NORMAN EBBLEY

NUMEROUS references have been made recently to "Alaska's oil reserves," and in view of the wartime petroleum situation sober thinking demands a dispassionate and scientific study and investigation of these reserves or supposed reserves. The question naturally arises, "Is there actually oil in Alaska, or are the reserves there a supposition?" True, in 1923 President Harding established Naval Petroleum Reserve No. 4 in Alaska, certainly implying that oil was there. This reserve, embracing about 35,000 sq. mi., was set aside on the advice of the Bureau of Engineering of the Navy Department and was based upon the existence of known petroleum seepages at Cape Simpson on the Arctic coast. The Cape Simpson seepages have been known for more than fifty years, but in spite of persistent rumors of other seepages in northern Alaska no definite evidence of their existence has been available.

Jan 1, 1944

By Harry Perry

A technology for producing liquid fuels from oil shale at prices competitive with crude oil prices is a necessary but not exclusive prerequisite for the development of a shale oil industry. Many other factors will affect the timing and the rate at which oil shale is commercially developed. Among the more important are: governmental policy concerning oil shale and oil resources (including the Outer Continental Shelf) that are under Federal control; oil import policy; Federal taxation of shale oil production including depletion allowances; regulatory practices; competition from other energy sources, both synthetic and natural; Federal treatment of factors affecting competing energy resources; and present legislation under which the public resources must be leased. Significant changes in any of the foregoing factors could have a controlling effect on the timing and rate of oil shale development. The effect of changes in each of these factors is evaluated.

Jan 1, 1969

By Clifford B. Farris

Introduction Shale Mining Problems The mining problems an oil shale operator will face are largely determined by the process. Candidate oil recovery processes are surface (above ground processing of mined oil shale), modified in situ (underground with some shale removed), and true in situ (completely underground with no shale removed). The shale removed for modified in situ (MIS) is generally processed by surface techniques. The mining problems are different for each category. Fig. 1 depicts the diversity of western shale deposits. Mining for surface operations will employ underground mining techniques in common use but the scale will be larger. A typical oil shale operation is expected to require 75,000 to 250,000 st (68 000 to 226 800 tons) a stream day of crushed oil shale. This is above the upper limit of current mining operations. Major problems in¬clude: (1) lack of good engineering design properties for oil shale, especially when interbedded with saline minerals at depths below 1,000 ft (305 m); (2) presence of water, hydrogen sulfide, and methane in some areas; (3) necessity for mine disposal of as much retorted oil shale waste as possible; and (4) control of en¬vironmental impacts of mining. Portions of the oil shale deposits in Colorado, Wyoming, and Utah and significant portions of the Devonian shales in the eastern U.S. are adapted to surface mining. No major technological problems are apparent outside overburden thicknesses up to 1,000 ft in the West. However, numerous political and environmental dif¬ficulties have arisen. One major oil shale developer cancelled a planned surface mining operation and currently is pursuing a modified in-situ plan. The eastern shales are closer to the surface than the western, but suffer from many of the same environmental and political problems. Modified in-situ operations face much more severe mining problems than surface efforts. Because the mined stope (called an in-situ "retort" by processors) acts as a retorting process vessel subject to gas flow, combustion, and temperatures between 1,500° and 2,000°F, mining is under highly restrictive limitations. This processing method involves removing between 20 and 40% of the shale deposit and then blasting the roof and walls into the mined space, where the oil is recovered by retorting. Major problems are: (1) swell factor severely limited; (2) need for consistent size distribution of blasted shale; (3) even filling of stope (in-situ retort) by blasted shale with consistent permeability throughout; (4) scaleup of blasting techniques, after optimization; (5) protection of retort pillars and roof during and after retorting; (6) prevention of groundwater percolation; (7)use of ANFO explosive in wet holes; (8) disposing of surface-retorted shale waste in stope; and (9) restoration of site. True in-situ operations are less well developed than surface or MIS processes. No actual mining is done, as the true in-situ processes generate permeability in the highly

Jan 1, 1980

By Clifford B. Farris

Introduction Shale Mining Problems The mining problems an oil shale operator will face are largely determined by the process. Candidate oil recovery processes are surface (above ground processing of mined oil shale), modified in situ (underground with some shale removed), and true in situ (completely underground with no shale removed). The shale removed for modified in situ (MIS) is generally processed by surface techniques. The mining problems are different for each category. Fig. 1 depicts the diversity of western shale deposits. Mining for surface operations will employ underground mining techniques in common use but the scale will be larger. A typical oil shale operation is expected to require 75,000 to 250,000 st (68 000 to 226 800 tons) a stream day of crushed oil shale. This is above the upper limit of current mining operations. Major problems include: (1) lack of good engineering design properties for oil shale, especially when interbedded with saline minerals at depths below 1,000 ft (305 m); (2) presence of water, hydrogen sulfide, and methane in some areas; (3) necessity for mine disposal of as much retorted oil shale waste as possible; and (4) control of environmental impacts of mining. Portions of the oil shale deposits in Colorado, Wyoming, and Utah and significant portions of the Devonian shales in the eastern U.S. are adapted to surface mining. No major technological problems are apparent outside overburden thicknesses up to 1,000 ft in the West. However, numerous political and environmental difficulties have arisen. One major oil shale developer cancelled a planned surface mining operation and currently is pursuing a modified in-situ plan. The eastern shales are closer to the surface than the western, but suffer from many of the same environmental and political problems. Modified in-situ operations face much more severe mining problems than surface efforts. Because the mined stope (called an in-situ "retort" by processors) acts as a retorting process vessel subject to gas flow, combustion, and temperatures between 1,500° and 2,000°F, mining is under highly restrictive limitations. This processing method involves removing between 20 and 40% of the shale deposit and then blasting the roof and walls into the mined space, where the oil is recovered by retorting. Major problems are: (1) swell factor severely limited; (2) need for consistent size distribution of blasted shale; (3) even filling of stope (in-situ retort) by blasted shale with consistent permeability throughout; (4) scaleup of blasting techniques, after optimization; (5) protection of retort pillars and roof during and after retorting; (6) prevention of groundwater percolation; (7)use of ANFO explosive in wet holes; (8) disposing of surface-retorted shale waste in stope; and (9) restoration of site. True in-situ operations are less well developed than surface or MIS processes. No actual mining is done, as the true in-situ processes generate permeability in the highly

Jan 9, 1980

By Jerry M. Whiting

Greater awareness of the increasing need to develop supplementary energy sources is accelerating us towards many basic decisions regarding future utilization of mined energy materials -- uranium, coal, oil sands and oil shale. The latter material comprises a major potential source of oil which will require creation of unusually large and low-cost underground mining systems. In this paper, the author briefly outlines and analyzes several of the factors which continue to provide the somewhat unique character of oil shale nine planning and mine operation.

Jan 1, 1974

By Robert B. Crookston

This paper presents a resume and status report: of mining technology appropriate to commercial oil shale development in the United States today. The nature and extent of oil shale in Colorado and Utah are discussed. A look at most of the prominent activities now underway emphasizes the questions "where are we now?" and "where are we going?" Various alternate mining methods are reviewed and a bibliography of oil shale mining is included.

Jan 1, 1980

By R. B. Crookston

This paper presents the status and mining method chosen by each of the active underground oil shale projects in the united States today. Potential improvements in equipment and methods on the near-term horizon are discussed. The problems and potentials that lie in the long-term future of oil shale mining are examined in light of the demands which must be met by this developing technology.

Jan 1, 1981

By Gordon B. French

In order to better understand the relation- ship of underground and surface oil shale processing systems, a block flow chart is presented in Fig. I. From this figure only modified in-situ and Room and Pillar underground mining are currently committed and into the Detailed Design and Construction phases. Figure II illustrates the times required (Federal land site) to bring oil shale operation into production. As this example shows, only those companies having progressed beyond the exploration stage have a chance to obtain oil shale production within the next 10 years. A more detailed breakdown of the oil shale development for those on private lands or having already obtained Federal lease lands is shown in Fig. III for shale oil development (without major regulatory changes).

Jan 1, 1981

By M. T. Atwood

For more than sixty years the rich oil shale formations of Colorado, Utah and Wyoming have been evaluated as a future source of petroleum. After many false starts the commercial production of shale oil is near. Union Oil and Colony (Exxon and Tosco) have begun construction of commercial plants. Occidental and Rio Blanco (Gulf and Standard of Indiana) are well along in the development of modified in situ (underground) processes. A number of other companies and groups are in advanced stages of development. This paper will review some of the major elements involved in the production of shale oil with emphasis on means available to express the efficiency of production of pyrolysis liquids and gases from oil shale rock.

Jan 1, 1982

The most extensive oil shale development program ever undertaken in the United States has been that carried out by Colony Development Operation at Para- chute Creek in western Colorado. Field development goals were completed this spring, with the remainder of the $24 million joint venture program, primarily engineering, environmental and economic analysis, due to be finished by the end of 1972. Upon completion of the overall program, a decision concerning a commercial venture is expected. This program points up the increasing attention being focused on oil shale as a source of crude oil and energy for the U.S. at a time when the nation's supply of oil produced by conventional methods is far from adequate to meet the demand. The oil shale reserves of the Green River formation in Colorado, Utah and Wyoming are the largest hydrocarbon reservoir. The Piceance basin of Colorado, alone, contains some 80 billion bbl of shale oil recoverable by modern methods in reserves more than 30 ft thick and containing at least 30 gal of oil per ton. The U.S. Geological Survey has estimated that the total shale oil reserves of the Green River formation in the states of Colorado, Utah and Wyoming is more than 600 billion bbl of oil in deposits containing at least 25 gal per ton of shale oil.

Jan 10, 1972

By J. G. Reid

Nickel is second only to aluminium, of all non-ferrous metals, in energy required to convert the ore to metal. Nickel Laterite ores, which constitute the feed source for approximately 40% of world nickel production, are at a particular disadvantage because of the absence of sulphur, as an energy source, in the ore and because lateritic ores general 1 y are not amenable to beneficiation. The dramatic escalation of oil prices which commenced in 1973 and continued for a decade meant that Nickel Laterite refineries using oil as a primary energy source were placed at a distinct disadvantage relative to refineries utilizing nickel sulphide concentrate feeds. By the late 1970's the continuing large difference in oil and coal prices caused Greenvale to consider converting certain high oil consuming areas of the refinery to coal. These investigations confirmed that the areas of ore drying and power generation, which together consumed 50% of total Plant oil requirements, could be economically converted from oil to coal firing. Construction of the coal conversion facilities commenced in October 1980 and the first ore drying air heater came on line in August 1981. Construction was completed with the commissioning of the coal fired boiler in June 1982. This paper outlines the additions required to receive and utilize coal in ore drying and power generation and how the changeover was completed with minimal process disruption.

Jan 1, 1988

By F. F. Peng

A unique collector dispersion techniques was developed and used to improve the flotation rate and recovery of coarser and ultrafine coal-rich particles in the froth flotation processes. In this novel collector dispersion method, the collector such as hydrocarbon-oil is gasified and transported by gas phase (air stream) into the pulp. In addition to the excellent mode of collector dispersion, the collector-encapsulated air bubbles are generated in the pulp. This approach alters the surface properties of air bubbles and provides the fast rate of flotation compared to that of direct liquid collector addition froth flotation. Using gasified kerosene as the collector, the effect of altering surface properties of bubbles on the recovery of larger and finer coal-rich particles of -1.7 mm (-12 mesh) and -600 µ m (-30 mesh) raw coal samples were studied. The Redstone seam coal obtained from Northern Central region of West Virginia was used in this work. The effect of particle size on oil-coated bubble flotation rate and recovery were also evaluated. The conventional froth flotation test with a liquid form of kerosene addition was also conducted for comparison purpose.

Jan 1, 1991