bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development Status Of The Taciuk Oil Sands Processor
Authors: Taciuk W. 
Published: March 2010

Abstract
The Taciuk Direct Thermal Processor has been under research and development since late 1974 in Calgary, Alberta, Canada. This work has been carried out by the UMATAC Industrial Processes Division of Underwood McLellan Limited, Consulting Engineers, under funding agreements with the Alberta Oil Sands Technology and Research Authority (AOSTRA).
Original research work and small-scale testing was completed by 1977 when a financing agreement for pilot plant construction and testing was signed with AOSTRA. Under this agreement a pilot plant was constructed in 1977-78, and has been operating for a period of 6 years using the following feed stocks:Athabasca Oil Sandslow grade - 6% oil contentmedium low grade - 9% oil contentaverage grade - 11–13% oil contenthigh grade - + 13% oil contentU.S. Semi Consolidated Sand-Shale low grade - 6–8% oil contentHeavy Oil from Lloydminster FieldHeavy Oil Atmospheric Tower Bottoms from Local Refineries.
During 1981 and 1982 the pilot plant was operated on heavy oil and oil sands to provide confirmation data, and oil product samples for detailed oil analysis which resulted in hydrotreating requirement projections.
During 1983 UMATAC has completed the design and cost estimates for a 100 ton/ hour demonstration plant to be located in the Fort McMurray area. UMATAC has also completed the conceptual design and cost estimates associated with use of the process in a commercial oil sandplant with an output of approximately 115,000 barrels of synthetic crude per calendar day.

Processor Description
The Taciuk Processor consists of a horizontal rotating vessel containing compartments which house individual process steps. Figure 1 schematically shows the arrangement and process flows. As-mined oil sand feed is introduced into the preheating section of the processor where connate water is evaporated as steam, frozen material is ablated, oversize is removed and the oil sand is heated by heat exchange with the hot outgoing tailings sand. The heated oil sand is then transported into the reactionzone where it is mixed with hot combusted sand from the combustion zone. The resulting temperature is adequate to thermally crack the hydrocarbons yielding a vapour stream containing the cracking reaction gases and liquids (in vapour form), and a coke residue coating on the sand. The vapour stream is passed through cyclones to remove fine solids and then enters a fractionating tower where various liquid fractions are separated for further processing. The off-gases are then passed to a central gas processing plant for light end recovery and desulphurization.
The coke-coated sand dicharges into the combustion zone where preheated air is injected to burn most of the coke. Auxiliary burners provide heat for startup and trim control. The hot sand from the combustion zone passes through arecycling arrangement that ensures an adequate supply of heat to the reaction zone while allowing net sand to move Into the cooling zone. In this zone the sand and combustion gases are cooled by heat exchange with the incoming oil sand.
Leduc, A New Life At 38
Authors: Barfoot G.L. , Rodgers R.J. , Scarth B.R. 
Published: March 2010

Abstract
Discovery of oil in well Imperial Leduc No.2 on May 10, 1947, marked not only a long-awaited success for Imperial Oil Limited in western Canada, but also provided a major impetus for the subsequent explosive growth of the Alberta petroleum industry.
Unique among its Devonian neighbours on the active Cooking Lake Aquifer, the Leduc D-3A Pool had a thin, areally-extensive oil leg, and a large gas cap. Balancing the thinning oil zone between the gas cap and aquifer has been an unrelenting challenge of reservoir management. Reducing the oil zone from its original 11.6 metres to 1.5 metres has been a 37-year success story. However, the operator is about to lose the upper hand.
Two years of appraisal and planning have focussed on the future of the remaining hydrocarbon reserve. This paper summarizes the past and present of the Leduc pool, and looks futuristically toward the day of final depletion.

Introduction
The Leduc D-3A Pool is located 20 kilometres southwest of Edmonton (Fig. 1). Discovered in May 1947, It is one of a series of reef structures located on the Rimbey-Meadowbrook geologic trend which extends some 480 kilometres in a southwest-northeast direction across central Alberta. Leduc is located on the southern portion of the trend, which also includes the major hydrocarbon-bearing pools of Homeglen Rimbey. Westerose South, Westerose, Bonnie Glen, Wizard Lake, Glen Park, Acheson, Big Lake and St. Albert (Fig. 2). All pools receive strong pressure support from the Cooking Lake Aquifer.
Based on geological data, the Leduc D-3A Pool is divided into three distinct areas (Fig. 3):the Main Pool, the focus of this paper;the Saddle Area; andthe Southeast Extension
The three areas of the Leduc D-3A Pool originally contained die hydrocarbon accumulations shown in Table 1. Since discovery, 63 per cent of the 50.4 × 106m3 of original oil-in-place, or 98 per cent of estimated reserves have been recovered from the Main Pool. At present, it is estimated that a thin 1.5 metre oil leg remains.
While the challenge of managing oil production from a thin oil sandwich has been successful, the continually diminishing oil zone and near-depletion of reserves necessitates planning and executing the next phase of Main Pool depletion-a rapid gas cap production, commonly referred to as a blowdown.
This paper familiarizes the reader with the past and present of the Leduc D-3A Pool, and provides forward-looking insight into the reservoir at times referred to as the genesis of the Canadian oil industry.

Reservoir Geology

General
The Leduc D-3A Pool is one of the many Devonian reefs (Fig.2) enclosed in basinal shales of the Ireton and Duvernay Formations that grew upon the extensive Cooking Lake carbonate platform (Fig. 4). Fluids derived from compaction of the adjacent basinal sediments are thought to be the source of the dolomitization of all the bioherms or pools along the chain, as well as the western margin of the Cooking Lake platform.
Geology, Geophysics And El1Lgineering: A Case For Synergism
Authors: Gretener Peter E. 
Published: March 2010

Abstract

Introduction
My prediction (Table 1) has been previously published in "The Wavelet", the newsletter of the geophysics group at The Department of Geology and Geophysics of The University of Calgary.
To make predictions that range ten or more years ahead is quite obviously risky. This article is an expression of my personal bias, so the readership is cautioned to treat the content as a base for further debate. Most recently, to the consternation of many, crystal balls have proved murky. Economic and political experts, much like weather forecasters, cannot be trusted with predictions that extend beyond a year. There is no reason to believe that long-range technical or scientific predictions are less fragile. As one famous scientist (his name escapes me) once stated: "One cannot predict the future but one can explore its possibilities". It is hoped that this will prove to be a reasonable exploration.
With this caveat firmly in mind, let us establish that all three professional groups are dealing with rocks and their fluid contents. Initially, these three operated independently with a competitive spirit that often bordered on hostility. Today geology and geophysics have been united. Any geological or geophysical meeting bears testimony to that fact. To deny it, only proves that one has acquired the status of a fossil before physical death.
It is my view that geologists and geophysicists must close ranks with the engineers and abolish the current state of separation which is being perpetuated by both sides. Geology and geophysics schools gear their curricula toward the exploration for natural resources, whereas engineers consider exploitation as their exclusive domain. There is no doubt that resource exploitation requires solid engineering knowledge yet one must remember that this phase also involves rocks and for their fluid contents, and this is where geologists and geophysicists can and should fit in. Now that the term "Ultimate Recovery" equally applicable to oil production and hard rock mining-assumes a new importance, particularly in North America; all three can only benefit from cooperation. The intent is, of course, not to make an engineer out of a geologist or vice versa, but rather to upgrade each other's knowledge in the respective fields to the point where a meaningful dialogue becomes possible.
One is now tempted to carry this paper further with an arm-waving campaign in favour of the interdisciplinary dialogue-another buzzword of our days-but I prefer to illustrate my point with a specific example. I choose artificial well fracturing to demonstrate how both geologists and engineers can benefit from such studies, with a direct applicability to both pure and applied science.
Some readers may think I have chosen a very special subject and might be hard pressed to find another example. To set such suspicions at rest, an equally good case could be made for the concept of effective stress. Terzaghi introduced this idea into soil mechanics in 1923 (see Skempton, 1960).
Shacks, People And Petroleum
Authors: Finch David A. 
Published: March 2010

Abstract
Tents, shacks and small houses served as the first living quarters in Turner Valley Heat, water, sanitarian, business, leisure, entertainment and crime were to develop in due course. But at first it was a lot like an extended campout.
Dingman No. 1 made the Valley famous in 1914. The closest town was Black Diamond, a farming community centre. Even by 1924 when the spectacular Royalite NO.4 well blew in, only a few buildings existed at the present site of the town of Turner Valley.
A panorama photograph, one of those mind-bending photos that looks south at one end and north at the other, shows only a few buildings near those famous wells in 1925.
Seventeen derricks or well heads dot the panorama view. Sam Coultis lived on the hill which became known as Snob Hill across the river and southeast from the plant. Just below the riverbank sat the houses of his workmen. Each day they walked across a foot bridge to the small plant.
A school, some company offices and warehouses, a few homes near the wells where the men were employed and the famous flare in the coulee called Hell's Half Acre complete the picture. This was the beginning of the boomtime for Turner Valley.
Housing at first consisted of tents. As the permanence of the oilfield became obvious, some people built houses but many just lived in tar paper shacks. That is, tar paper was the only covering on the small frame buildings, built on skids, that were hauled from one work site to the next.
Some shacks eventually got a protective coat of siding but still, they were small. One lady commented that the cars were bigger than the houses so that the cars could pull the houses around.
Full sized houses were built for the plant management at the top of Snob Hill. Other people rented or bought land but many just squatted, with no thought or care for a title, until they moved to the next worksite. The only settlement to survive the years since the 1920s was Black Diamond. Even there many of the houses had come from many other communities before settling down for good.
Heat was an important commodity when you lived in a tar paper shack, years before insulation or central heating. Most buildings were heated with waste gas from anyone of the numerous nearby wells.
Seldom did the gas cost much, if anything, but the unscrubbed fuel exacted other payments. First it just plain stank. A high sulphur content made the valley smell like rotten eggs when the gas was burned. Next the pressure was highly unpredictable. One lady boasted she could cook a turkey in 20 minutes when the pressure was up to 220 pounds per square inch. Another lady died when her house blew up after a gas leak filled her house with gas.
Not only did the gas smell. One story says that when the vicar was coming for tea the silver tea service was highly polished and then covered carefully to keep it bright.
New Technology For Cold Lake
Authors: Whelan W.J. 
Published: March 2010

Abstract
Carlyle Energy Ltd. became involved in 1981 when the U.S. owners of the technology were attempting to raise funds in Canada for a heavy oil pilot project.
Cold Lake Heavy Oil Ltd. (CLHO) was formed: 45% by Carlyle (55% of the voting control) and 55% by three parties in the U.S. who own and developed the technology. Carlyle commissioned studies by A.J. Gruy & Associates, Inc. of Dallas and McCallum, Stewart and Associates in Calgary to study and review the material available relative to the application of the process to Cold Lake type reservoirs. A pilot project was beyond their financial resources so time was spent interesting others in CLHO.
In late 1982 and early in 1983, AOSTRA financed a laboratory study of the technology by the Alberta Research Council. Their recommendation was that a field pilot project be undertaken.
CLHO was able to negotiate a staged farm-in of the Gulf lease and Bow Valley Industries Ltd. agreed to participate and operate Phase A of the pilot project. The technology, if successful, will greatly enhance the recovery of these heavy oils.

Project
Bow Valley Industries Ltd. and CLHO (a 45% subsidiary of Carlyle Energy Ltd.) has initiated Phase A of an in-situ oil sands bitumen recovery project located approximately 30 km north of Grand Centre, Alberta. The project known as the "ABC Cold Lake Pilot" involves three participants, AOSTRA (Alberta Oil Sands Technology and Research Authority), BVI (Bow Valley Industries Ltd.), and CLHO.
The pilot project is located on a BVI / CLHO farm-in from Gulf Canada Resources (Heavy Oil Lease 84) and covers approximately 5,000 hectares (12,500 acres) bordering on the north-west shore of Cold Lake. The location is 16 km east of Esso's Marie Lake project.
Total expenditures in Phase A will be approximately $15,000,000 over the next two years. Capital costs for 1984 will be $7,000,000, with the remaining funds being operating expenses for the next one and a half years. All costs will be shared 75 per cent by AOSTRA and 25 per cent by BVI.
To date, seven directional wells have been drilled in a hexagonal configuration from a central pad. Steam injection and well satellite facilities were installed during late August and September. Steam and carbon dioxide injection was scheduled to commence in late September.
Over 85 per cent of capital costs represent Canadian material and tabor, the majority of which will be expended in Alberta. Drilling, equipment, fabrication and installation have been awarded to local contractors in the Cold Lake area.
A field office at the pilot site has been opened and will employ 12 full time staff and contract personnel to conduct the project, the majority of whom are presently area residents. Bitumen produced by the project will be trucked to L1oydminister. Phase A of the project will evaluate a new technology, which relies upon the use of superheated steam, carbon dioxide and other additives to recover bitumen from the Clearwater formation at a depth of about 1,400 feet (430 m).
Canadian Natural Gas Export Policies And Prospects
Authors: Angevine G.E. 
Published: March 2010

Introduction
Over the past 15 years Canada has exported over 13 Tcf [13.6 EJ (exajoules)] of natural gas to the United States but gas exports have been running considerably below authorized levels since 1979. If U.S. gas demand increases, with little change in the gas reserves-to-production ratio (Fig. 1), exports of Canadian gas will probably regain and surpass their earlier levels. The compatibility of gas export pricing rules with those for gas consumed domestically will continue to challenge Canadian government policy.

Canadian Gas Reserves
Remaining non-frontier established Canadian gas reserves at the end of 1982 were about 84 EJ. National Energy Board procedure limits "remaining reserves" to those with demonstrated viable delivery systems.
Very significant quantities of "tight" gas (in place) (as high as 400 EJ) are known to exist in the "Deep Basin" of western Canada. They are also excluded even though a portion may be contiguous to conventional, producible, gas reserves.
An improved market situation, in terms of both price and volume as U.S. requirements for Canadian gas accelerate, should elicit 44 to 50 EJ of conventional gas in the next 15years with an expected concentration in the late 19805 and early 1990s.
Table 1 breaks out total reserves of gas. Frontier resources are expected to be drawn on as the more accessible non-frontier reserves are depleted. Canada's combined ultimate potential may be as much as 6 times greater than currently established non-frontier reserves of 84 EJ.

Domestic Natural Gas Consumption
Figure 2 projects trends in Canadian oil, natural gas and electricity shares of secondary energy demand (i.e. energy commodities sought by energy users for consumption as energy by them) to the year 2000. Total annual energy demand growth is expected to continue slower than growth of Real Domestic Product over the balance of this decade as conservation measures contribute to further decline in the energy-output ratio. By the 19905, the effects of the price shocks of the early 19805 should have been absorbed. Barring further major price disruptions, energy demand will begin to track output growth more closely.
Both natural gas and electricity shares of the Canadian energy market will almost certainly increase. Most of the increase in the gas portion will come from the penetration of new markets-in Quebec, if the Trans Quebec and Maritimes Pipeline makes natural gas available to regions east of Montreal; in Saskatchewan, due to expansion of the distribution system in rural areas; in the Maritime Provinces, as Sable Island gas comes on stream; and in British Columbia, through possible extension of the natural gas pipeline system to Vancouver Island.
By the year 2000, natural gas is anticipated to supply about one-third of the needs of the Canadian energy market compared with 27.5 per cent in 1983 and 20 per cent in 1970. Domestic gas requirements will then be about 2.8 EJ, compared with the current level of about 1.8 EJ.
Enhanced Oil Recovery Design For The Pembina Cardium Field
Authors: O&apos;keefe J.J. , Boutette M.J. , Howes B.J. 
Published: March 2010

Abstract
The design of a hydrocarbon miscible flood is presented for areas of file Pembina Cardium field where there is little or noonglomerate present. A procedure for describing the reservoir for use in simulation is also discussed.
The indicated optimum miscible flood design is to infill drill to 8-hectare well spacing and to inject at a solvent-water ratio of 2.5. A solvent slug size in the range of 10% HCPV, followed by about 20% HCPV of chase gas, is recommended.

Introduction
The Pembina Cardium oilfield is located 120 kilometres southwest of Edmonton, as shown in Figure I, and is the largest oilfield in Canada, covering an area of 1900 square kilometres. It has an original oil-in-place (OOIP) of 1.2 billion cubic metres and approximately 70% of the reservoir is being water flooded. The average water flood recovery is about 23%(1). This low recovery and high OOIP combine to make the Pembina Cardium reservoir a significant target for enhanced oil recovery.
A study was undertaken to identify areas favourable for miscible flood implementation, to analyze their potential and the parameters which control miscible flood performance, to determine the most favourable conditions, and to evaluate the resulting economics.
This paper describes the design of an enhanced recovery scheme suitable for the parts of the Pembina Cardium field that have little or no conglomerate present. It includes the description or the reservoir for use in simulation and the evaluation of various factors in the operation of the proposed EOR scheme.

Nature of the Reservoir
The Cardium formation in the Pembina area has been divided into four zones(2), as shown in Figure 2. Zone 1, at the top of the section, is a conglomerate which varies in thickness and reservoir quality. Its permeability can vary from 1 mD in thin deposits to more than 1 Darcy in thick, well-developed areas. Zone 2, a sandstone, is one of the two main producing zones. It is present in the central and eastern parts of the field. The third zone is a bioturbated sand-shale which is usually not productive. It isolates Zone 2 from Zone 4, which is the other main producing zone. Zone 4 is also a sandstone and ispresent in the west-central portion of the field. Figure 3 shows the areal extent of Zones 2 and 4.
Kerr(3) has correlated fluid properties with geology and has established the presence of two distinct fluid, a low bubble point oil in Zones 1 and 2 and a higher bubble point oil in Zone 4. The properties or these two oils, as used in this study, are shown in Table 1.
A directional flow trend, oriented southwest to northeast, has been described by McLeod(4) and Hassan(5). This trend may be the result of directional permeability within the reservoir rock or, more probably, may be the result of induced fractures oriented southwest to northeast. Virtually all of the Pembina Cardium wells are hydraulically fractured upon completion and fractures may also be induced as the result of injecting above formation parting pressure.