bluuebunny/crossref_metadata_2025_split huggingface dataset:
Heavy Oil Sand In.-Situ Pilot Plants In Alberta (Past And Present)
Authors: Nicholls J.H. , Luhning R.W. 
Published: March 2010

Abstract
This paper will review the history of in situ pilot plant efforts towards the recovery of bitumen from the major oil sand deposits of Alberta. The review will be based on published information and will describe the location of the plants, the manner of operation, the estimated costs involved and the technical area under investigation. The currently operating pilot plants and future plans for new in situ pilots will also be described.

INTRODUCTION
This paper will present a survey of the planned, current and completed in situ pilot plant operations in the Alberta Oil Sands. The aim of the review is to provide an overview of the current field projects and to provide background concerning completed in situ pilot plant programs. Before beginning a consideration of the individual plants it is necessary to set the stage for the review by looking at some of the problems and formation properties which are encountered in the Alberta on Sands. Note that the term bitumen, tar and heavy oil are used interchangeably in this paper to describe hydrocarbon material with gravity less than 12 °API.
The oil sands of Alberta, as shown in Figure 1, are located in four major deposits which cover an area of about 10.8 million acres in the northern half of the province. The total in place reserves are estimated to be 950 billion barrels(1) of which, 74 billion barrels or 8% of the total are covered by less than 150 feet of overburden and are considered suitable for economic surface mining. The surface mineable reserves are all located within the Athabasca deposit as indicated by the heavily shaded area in Figure 1. The amount of in place bitumen which has more than 500 feet of overburden and must be recovered by in situ methods is 10 times the surface mineable reserves; 741 billion barrels or 78% of the deposit. The remainder, 135 billion barrels are overlain by 150–500 ft. of overburden and it is uncertain at this time whether the heavy oil in these sands will be recovered by some form of mining or by novel in situ recovery methods. The consideration of the depth of the deposits points out the need for development of in situ recovery techniques in order to tap the majority of the reserves in the Alberta Oil Sands.

RESERVOIR PROPERTIES
The Alberta Oil Sand Reserves are situated in the Mannville Group of the Lower Cretaceous strata. All the oil sand deposits are quite heterogeneous, both laterally and vertically, with wide variations in oil, water and gaseous content. Some of the average oil sand formation properties are shown in Table 1.
The Athabasca deposit has the largest in place reserves; 626 billion barrels or 66% of the total. The Cold Lake deposit is next largest with 164 billion barrels followed by the Wabasca and Peace River deposits. The Athabasca deposit is the only one inwhich the oil sand outcrops at the surface.
The M6 Steam Drive Project Design And Implementation
Authors: Herrera A.J. 
Published: March 2010

Abstract
The M-6 steam drive project is located in the Tia Juana field, Bolivar Coast, Venezuela and is scheduled to go on stream towards the end of 1977.
Primary production started in 1948 followed by a period of stea1n soak from 1969 onwards. Steam soak is favoured by the compaction process. At the start of steam drive it is estimated that the remaining reserves by compaction is some 4% STOIIP compared to a total recovery by comparison of some 20% STOIIP.
The past performance amt the prediction of future performance will be discussed on the basis of the results obtained from an earlier, smaller scale steam drive project, laboratory investigations on physical models and compaction drive theory.
During 1975 and 1976 an extensive programme of data gathering in the field and special production/ injection tests in wells were carried out, and a detailed geological/petrophysical study is being made.
In three inverted seven spots steam is being injected continuously, the first hexagon started in November 1975 and the other two in July and August 1976.
Tracers in the gaseous and aqueous phase have been injected to detect preferential flow. The results of these tests a1'e discussed.

Introduction
The heavy oil fields on the eastern coast of Lake Maracaibo (see Figure 1) - known as the Bolivar Coast -initially contained some 33.8 billion barrels of oil-in-place, of which only about 11% can be recovered by primary means; this figure represents an average which comprises 0% recovery for the very viscous crudes (up to 50,000 cp) in North Tia Juana, 6–7 %, in the Upper Lagunillas Heavy and up to 20% in the coastal areas.
The current proven and possible reserves by primary and steam soak production is on average 18% STOIIP, therefore leaving in the ground some 28 billion barrels of oil as a vast potential for additional recovery methods.
Since 1959 various methods have been tested, such as steam drive 1,3, in-situ, combustion2 and steam soak.4,5. Reservoir compaction is the main production mechanism in the Bolivar Coast reservoirs. It is proposed to make full use of this natural source of energy by applying the steam soak process. When compaction reserves are exhausted, other drive processes will be applied; the most appropriate being steam drive based on pilot tests. The M-6 steam drive is intended to evaluate the application of this recovery method on a large scale as the follow-up process for the Bolivar Coast after steam soak.
Based on the results of laboratory experiments and the performance analysis of the C-3/C-4 steam drive test, discussed below, the large scale M-6 steam drive project has been designed.

LABORATORY MODEL EXPERIMENTS
Physical model studies were undertaken in 1971 in the Koninklijke/Shell Laboratorium. Rijswijk, the Netherlands, to obtain additional technical information on the steam drive process under Bolivar Coast heavy oil reservoir conditions. The investigations took place in one twelfth of an inverted seven spot proto-type (closed hexagon) with a distance of 230 m from corner well to centre injection well.
Government Sponsored Petroleum Recovery Research In Alberta
Authors: Govier G.W. 
Published: March 2010

Abstract
I welcome the opportunity to review for you some of the government sponsored research related to recovery of petroleum and natural gas in Alberta, The title of my review refers to recovery research but I will broaden this somewhat and discuss research in related areas as well. I hope especially that the review will be of interest to our friends from Venezuela participating in this symposium as well as to the many Canadians who may not be familiar with much that has been done and is planned.
A recent article which appeared in newspapers in Eastern Canada stated that there has been little research in Western Canada and certainly no new research, I would be extremely pleased if my message reaches this part of Canada.
Early research work in Alberta related to petroleum was initiated by the Federal Government but from about 1920 onwards there has been increasing involvement of Alberta and the two Governments are continuing to co-operate.
My brief review will deal mainly with research carried on here in Alberta and mostly supported by the Alberta Government, I do recognize the very great importance of work done by the Federal Government and 'particularly by the Department of Energy, Mines and Resources and by the National Research Council in Ottawa but I am not in a position to review this.
Perhaps I could mention at the outset that the Alberta Research Council has been prominent in the research area related to energy resources since the 1920's. However, I will only touch on its achievements and leave the provision of details to Dr. Wiggins, the Director of the Alberta Research Council, in his paper on the work of this important institute which he will be presenting later this morning.

PRINCIPLE AREAS OF ALBERTA RESEARCH
Let me first make a few remarks about the principle areas of research carried out in Alberta and their importance, As I see it, as it affects the petroleum scene there are five important areas of research activity.ExplorationExcept in the case of the oil sands, the job of finding our oil and gas resources comes first. Alberta's geology, especially in the foothills, is unique and complex and a knowledge of this geology and its interpretation is of obvious importance.Recovery
Recovery is the principle area of concern to us this morning, From the earliest days the need to improve the recovery processes for conventional oil and gas and to develop viable ones for the bitumen contained in the oil sands has been recognized. I think the importance of recovery research can be put in perspective if we recall that Alberta has some 29 billion barrels of proved remaining crude oil in place, that is in the reservoirs, of which we now expect to recover only 5,5 billion barrels. This means that there are 23 billion barrels of crude hydrocarbons that we expect cannot be recovered with our present technology.
Preliminary Geostatistical Investigations Of Tar-Bearing Sands, Lease-13, Athabasca Tar Sands
Authors: Zwicky R.W. 
Published: March 2010

Abstract
Preliminary geostatistical studies of the tar sand measures in the Lower Cretaceous McMurray formation have shown that variograms of net thickness and grade of tar sand are well formed. These show that the variogram ranges (radii of influence) of net thickness and grade are 4,000-5,000 feet, much wider than the sampling density.
Fines, the clay and silt fraction within the orebody, were studied in conjunction with tar grade for one of the orebodies. The best estimation of fines was found to be from a combined, correlation of tar grade and natural radioactivity (gamma-ray emission). The variogram of fines in this orebody indicated that fines are randomly distributed.
It was concluded that the sampling done on Lease-1S was sufficient for locating all major orebodies and for estimating the tar reservoirs accurately. The sampling was also sufficient for initial mine planning. One use of the geostatistical data, to estimate the 'Variance of tar grade and fines in the mill feed based on one mining method, is described.

Introduction
THE ATHABASCA TAR SANDS of Western Canada represent a large potential reserve of liquid hydrocarbon which is only now being developed. One commercial mine is in operation and a second is under construction. Tar, or bitumen, the objective mineral, is a black hydrocarbon so viscous that it Is immobile at normal in-situ rock temperatures. The tar occurs as pore filling in the sand portion of a sand shale series of Cretaceous age. The depositional environment of the formation is deltaic to near-shore where it lies close enough to the surface to be mined. In these areas, the tar sands are overlain mainly by a thin mantle of Pliestocene glacial till and underlain by Devonian carbonates.
The material for this study comes from Shell Canada's Lease-13, located about 50 miles north of the town of Fort McMurray. Lease-13 is a block roughly 6 by 13 miles.

One-Dimensional Variograms
We decided to undertake statistical studies of the sands to give us a better predictive tool for ore reserves and for use in mine planning. At the time, we had information from 350 sample holes in which a foot-by-foot analysis of 40,000 feet had been made. In the analysis, overburden and other rejects had been identified, and a base to the ore picked. Further, within the ore, ore grade and fines had been determined. This material was available on a computer tape data file. The sampling pattern for the 350 holes is shown on Figure l.
Our first approach, to see whether geostatistics would be useful, was to make a simple one-dimensional non-directional test of values. For this test, we determined for each hole a single value for each of the parameters we were to study - tar sand net pay, tar grade thickness, overburden thickness, total reject thickness and quality factor. Quality factor is an economic parameter relating overburden thickness, ore thickness and ore grade.
The variograms for this study were developed using the onewdimensional form of Matheron's (1,2) formula, as follows:
Improved Reservoir Description: Swan Hills Unit No.1
Authors: Sears J.R. 
Published: March 2010

Abstract
Oil production in the Swan Hills A & B Pools is taken from the Swan Hills Formation of the Beaverhill Lake Group of Devonian age. The reservoir rock is a carbonate formed ill a bioherm. The rock mass is rather complex, with at least seven major porous zones having been identified. Tile field was discovered in 1957 and steady oil production commenced ill January, 1959, after a pipeline became available.
Swan Hills Unit No.1 was formed ill January, 1963. About 80% of the pool's oil in place and about 40% the developed area are contained within the unit limits. Water injection commenced in August. 1963. The reservoir description used in the early engineering studies was rather simple and bore scant resemblance to the complex reservoir geology. As the water-flooding operation has become more mature, it has been necessary to use increasingly more complex geologic models in order to reconcile reservoir performance prediction with observed reservoir performance data.

Introduction
The Swan Hills Field was discovered in the spring of 1957 by Home Regent Swan Hills 08-l1-068-10 W5M, which encountered 12 feet of pay in a gross interval of 124 feet in a limy carbonate section in the lower portion of the Beaverhill Lake Group. In the fall of 1957, a confirmation well, Home Regent Edith Lake 11-19-067-10 W5M, drilled 6 miles to the southwest, encountered 141 feet net pay in a gross interval of 312 feet in the same zone. This pay interval is now known as the Swan Hills Formation of the Beaverhill Lake Group of Devonian age.
For administration purposes, the Alberta Energy Resources Conservation Board (ERCB) defines the producing formation as the Swan Hills Beaverhill Lake A & B Pools. The A & B Pools designation dates back to the carly history of the field development, when it was demonstrated that the lowermost porous interval (Coral Zone) was a separate hydrocarbon accumulation the "B" Pool. The remainder of the vertical sequence of oil productive intervals was defined as the "A" Pool. This pool separation move was carried out in an attempt to gain an allowable advantage. The advantage disappeared with prorationing rule changes and the ERCB subsequently approved commingling production from the two pools; however, the A & B definitions still persist. (Sec Figure 1 for position of Coral Zone.)
Steady oil production commenced in January, 1959 after a pipeline was laid to Edmonton, a distance of 125 miles to the southeast. Commencement of steady production caused reservoir pressure to decline rapidly because of the undersaturated nature of the reservoir fluid. It became obvious that pressure maintenance would be needed in order to effectively recover the oil in place.
The Swan Hills Unit No.1 was formed in January, 1963, and water injection commenced in August. 1963. About 80% of the pool's oil in place and 40% of the developed area are contained within the unit outlines. The reservoir description used in the early engineering studies was oversimplified and bore scant resemblance to the complex: reservoir geology.
Energy Conservation In Natural Gas Plants - Thelll And Now
Authors: Dick J. , Stephens G.W. 
Published: March 2010

Abstract
Because of the current emphasis on the limited supplies and increasing costs of energy. Canadians as a whole have only recently become aware of the importance of conserving lire country's energy supplies. The oil and gas industry, however, has made progress in energy conservation over tile years.
Since its inception prior to the Leduc oil discovery, the gas processing industry in Western Canada has been influenced by both economics and government regulations in its approach to energy conservation. The role played by these two factors, from the time of Leduc to the present, is discussed in this paper. Examples are given of energy conservation practices that stem from government conservation and environmental requirements such as gas conservation and sulphur recovery and of steps taken by industry to reduce fuel consumption such as improved operational and equipment efficiencies in utilities and processes.

Introduction
During the past few years there has been increasing emphasis on the need for energy conservation. Substantial increases in the price of crude oil, natural gas and electricity have had a dramatic effect on the energy consumer. Industry, and the public at large, faced with increased costs for energy are searching for more efficient means of using energy. Governments concerned with limited supplies of energy are coming to realize that, along with the need to provide incentives to develop additional supplies of traditional energy and new forms of energy, they must also give increasing attention to encouraging energy conservation.
It has become obvious that the days of cheap and plentiful energy supply created a society that was wasteful in its use of energy. Conservation was given little or no consideration. Consequently energy use was, in general, wasteful and inefficient.
As producers of oil and natural gas, what impact does energy conservation have on our operations today and has it had any influence on our operational practices in the past? To answer these questions, let us briefly examine the growth of the natural gas producing industry from its inception and discuss the influence of energy conservation practices on its development both past and present.

History
In 1947, the year the Leduc oilfield was discovered, there were only two gas plants operating in Alberta, namely the Royalite Turner Valley processing plant, now owned and operated by Western Decaha, and the B.A. Longview absorption plant which was shut down in 1950. Built in the early 1930's, these plants, along with the then operating Gas and Oil Products Hartell plant, processed sour Mississippian gas for the recovery of natural gasoline. A portion of the residue gas was sweetened in the Royalite plant and compressed for winter sales to Calgary and summer injection at Bow Island. After crude oil was discovered on the west flank of the Turner Valley field, gas in excess of Canadian western natural gas market requirements was injected into the oil field gas cap for pressure maintenance.
Fracture Mechanics Analysis in In-Situ Oil Sands Recovery
Authors: Settari A. , Raisbeck J.M. 
Published: March 2010

ABSTRACT
The success of in-situ recovery of oil from the Alberta Oil Sands depends inlarge measure on the success of formation fracturing to create the initial flowpaths. This paper reviews some of the factors which possibly contribute to theinitiation, development and orientation of fractures and pursues the idea ofapplying the theory of fracturing in elastic materials to un- consolidatedsands. Experimental data are compared with results from a numerical model whichemploys a nonisothermal, single-phase fluid.

Background
Any in-situ recovery process designed to recover oil from the Alberta Oil Sands must overcome the following major inherent constraints: low or nopermeability in oil-saturated sands; low or no oil mobility; and low reservoirtemperatures and pressures. Accordingly, there are several basic steps to mosttypes of heavy oil in-situ recovery methods(l), but for the purpose of thisdiscussion we need only consider the following:communication;mobilization; anddisplacement.
Figure 1 summarizes some of the methods available to accomplish these steps.The selection of one or more categories under each step (and consequently therecovery method) depends largely on the reservoir characteristics. For example, at Cold Lake, Esso Resources, Norcen and Gulf Canada have used steam to part orfracture the formation and thereby improve reservoir injectivity. On the otherhand, because the reservoir has reasonable injectivity, BP Canada (also at Cold Lake) have used the connate water as the transport medium in one of their steampilots. Alternatively, one could use a permeable bottom water sand as thechannel of communication (e.g., Shell Canada at Peace River).
Figure 2 shows that certain companies (e.g., Texaco and Amoco) have usedsteam or air (combustion) in dual capacity to:preheat and mobilize the oilin the reservoir; anddisplace oil to production wells.
Other companiessuch as BP Canada, plan to use a combination of steam and air in theirviscosity reduction/fluid displacement process.
Canada's Technological Capability to Meet'its Future Energy Requirements
Authors: Govier G.W. 
Published: March 2010

Abstract

Introduction
It is well recognized that the pattern of supply of Canada's energy requirements will change in the future. Some people refer to a crisis developing in the 1980's, while even those of a more optimistic view see a need for a conscious and early effort to develop new supplies and alternatives to our heavy demand for crude oil.
Conservation at the point of energy use is widely supported as a concept and will, I hope, be further practised in the years ahead. However, more important in the long run is adding to our developed supply of energy. This means continuing the search for conventional hydrocarbons both in established producing areas and on the frontiers, increasing our efforts to improve recovery of known hydrocarbon resources and accelerating the development of alternatives- especially to crude oil.
Canada is the most fortunate country in the world in terms of the energy alternatives which are open to it- However, we must soon make our choices and develop the supplies we will need. An important question is whether we have the necessary technological capability to do so.

Energy Sources For the Future
First, what choices do we have and which ones or combinations should we, or are we likely to, select?
I accept that we will, and of course we must, continue our efforts to discover and develop new supplies of conventional crude oil and gas in the Western Basin, the Beaufort Sea the Arctic Islands, the Davis Strait and off our eastern shores. So far, only the Western Basin has yielded substantial reserves of both oil and gas; the Beaufort Sea and the Arctic Islands show promise of becoming commercially viable sources of gas (perhaps of oil too), but the development problems are enormous. The Davis Strait and the eastern shelves are of great geological interest, but significant commercial- discoveries have yet to be made and, if they are, the problems of production will still have to be faced.
Another choice which we must select is to develop methods to increase the recovery of light and medium crude oil from our known fields. At our average recovery level of about 33 per cent, Canada has over 28 billion barrels of known light and medium crude oil which will not be recovered by present producing methods. There are good prospects that 2 or more billion barrels of this could be recovered by applying advanced enhanced recovery methods.
In the case of heavy crude oil, present production methods recover only about 10 per cent of the oil in place and the proved deposits contain over 6 billion barrels of oil which will not be recovered by these methods. More sophisticated production techniques are being tested and show promise of increasing the recovery by up to a billion barrels. In its natural state, however, heavy oil is suitable only for production of asphalt and heavy fuel oil with a modest yield of middle distillate.