bluuebunny/crossref_metadata_2025 huggingface dataset:
Overpressure Detection And Control At Imp ImmerkB-48 Using A Wellsite LVlud Gas Detector
Authors: Daw R.N. , Mercer R.F. , Myers D.L.
Published: March 2010

Continuous 1nud gas detection was used at Imp Immerk B-48 in the Mackenzie Delta during drilling operations to assist in the detection and control of overpressure due to undercompaction of fine-grained sediments.

Special techniques used in conjunction 'with the gas detector data improved the ability to relate the increase in formation pore pressure to the required mud weight as drilling proceeded.

Careful interpretation of the mud gas response to the drilling actions showed a repetitive cycle of events. Knowing the ca1we of these repetitive cycles and recognizing current position in the cycle increased drilling safety by providing better cont1'ol of mud weight.

Introduction

THIS PAPER describes the mud gas logging techniques used by Imperial Oil to assist in detecting and controlling overpressure due to under compaction at Imp Immerk B-48. We do not imply that these are the only techniques or the best techniques to detect and control overpressure, but we do believe that they are an important supplement to our pressure-monitoring program. In fact, we are now confident that we can safely penetrate over pressured sections.

Overpressure due to undercompaction results when pore waters which cannot escape from rapidly deposited, fine-grained, poorly permeable sediments support part of the weight of the overburden. Hydrocarbons dissolved in these pore waters, as well ns free hydrocarbons, affect the amount of gas detected in the mud. We will show specific examples of the relationships between overpressure due to undercompaction, mud gas and the mud weight required to maintain pressure balance.

To assure clarity of the terminology used in this paper, the following definitions are presented.

Mud gas is the total hydrocarbon gas removed from the mud (not from the rock formation) by a gas trap and measured with a detector. The amount of gas is expressed in Canadian Gas Units; 100 units equals the instrument response to 1% methane in air*. Mud gas is measured at the surface one lagtime after the down-hole event. One method of keeping the mud gas measurement current with bit penetration is to wash "bottoms-up"; i.e, stop drilling, but pump the mud from the bottom of the hole to the surface. This mud gas enters the mud stream as either:liberated gas from mechanical liberation or crushing of rock by the bit; orproduced gas, which is produced from the rock formation when the mud-column pressure is less than the formation pore pressure.

A dummy trip is a short trip, only part-way out of the hole, which simulates in a short period of time what would happen if a full trip was made.

A dummy connection is made by lifting the pipe off bottom and stopping circulation for a short time to simulate the conditions of a normal connection.

A flow check is made by shutting off the pump and stopping rotation to see if the well is flowing or taking fluid. A flow check is an extremely important safety measure, because it provides an immediate surface expression of the down-hole action.
Heavy Oil Sand In.-Situ Pilot Plants In Alberta (Past And Present)
Authors: Nicholls J.H. , Luhning R.W.
Published: March 2010

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

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

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

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

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

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

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

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.
Tunnels In Oil Sand
Authors: Harris M.C. , Poppen S. , Morgenstern N.R.
Published: March 2010

Deep oil sand deposits may require shafts and tunnels either as access for in-situ oil methods or for direct mining, Only one tunnel, Saline Creek tunnel, has been constructed in oil sand to date (1978). Recent research has made significant contributions to the understanding of oil sand behaviour, but empirical design methods may still have to be used until more experience is gained. Mathematical relationships show some promise in providing a framework for assessing stand-up time and the effects that in-situ recovery processes, such as steam drive, may have.

Introduction

There are several projects which are being considered for the feasibility or mining oil sand where the depth of overburden exceeds economical mining by open-pit methods (EMR 1977). In these methods shafts, tunnels and underground mining are proposed either to provide access for in-situ processes or for direct mining of oil sand as an ore, However, to date only one Jarge diameter tunnel has been constructed in the oil sands of Alberta and hence the underground behaviour of oil sand poses some uncertainties. The purpose of this paper is to assess tunnel construction in oil sand based on the experience gained from the Saline Creek tunnel (Smith et al. 1978), from observations of the behaviour of oil sand both in natural exposures and man-made excavations and from a review of information available in the literature.

The characteristics of oil sand arc discussed, first within the framework of its geological selling and second as a material with unique engineering properties. Consideration is given to the effects of weak clay layers, water-bearing sands and other geological features such as cemented stringers, gas pockets and sink holes as they might affect tunnel construction.

Background

The construction of shafts and tunnels in Alberta's Athabasca and Cold Lake oil sand deposits has recently assumed practical significance because they may be necessary for access to oil sand under overburden depths too great for economical open-pit mining. A recent study (EMR, 1977) indicates that mining of oil sand as an ore may not be practical until world oil prices are higher than they are at present, but it seems likely that in-situ mining, using shafts and tunnels for access only is feasible. At-least one scheme the Rabbitt Kinetic In-Situ Method (Oilweek, 1978), requires shafts through the oil sand to the underlying Devonian limestone.

Conventional design and the construction of shafts and tunnels in soil and in weak or strong rock is a skill largely based on practical experience obtained from previous work. Although oil sand is an oil-impregnated sandstone, observations from present open-pit mine operations have shown that the oil sand does not behave like most sandstones. The oil sand swells and experiences a significant loss of strength as it is exposed by excavation. Recent research at the University of Alberta has provided an understanding of the physical behaviour of oil sand under stress change, and has provided a framework for predicting behaviour.
Solution of a Non-linear Gas Flow Equation By the Perturbation Technique
Authors: Kale Dilip , Mattar Louis
Published: March 2010

The flow of gas in porous media is represented by a non-linear differential equation, even when the pseudo-pressure concept is used. Analytical solutions, in the past, involved linearization of the coefficient by assuming µc constant at initial conditions. This paper solves the non-linear equation by the method of Perturbation, and demonstrates that the effect of linearization is, for all practical purposes, equivalent to having a small negative skin. The validity of the pseudo-pressure approach using µici instead of µu is thus confirmed.

Introduction

The flow of gas through porous media is represented by the well-known diffusivity equation. In the past (Aronofsky and Jenkins, 1953), assumptions of ideal gas behaviour led to the use of "pressure squared" as the variable for analysis of gas flow rate. The standard approach was to use the same fluid flow equations for gas or oil flow, but in terms of p for oil flow and in terms of p2 for gas flow. Later it was shown that the use of p instead of p2 was appropriate under certain conditions for gas flow relationships (Mathews and Russel, 1967). Al-Hussainy and Ramey (1966) introduced yet a third variable, ψ, known as the pseudo-pressure or real gas potential, which allowed for variations in µ and Z2 the viscosity and compressibility factor of natural gas. The relationship of p and p2 to ψ is explained in Aziz et al. (1976).

Because the diffusivity equation for gas flow in terms of the pseudo-pressure involves the least number of assumptions, it is considered to be the most rigorous of the three treatments (p, p2, ψ). However, even though ψ accounts for variations in µ z (viscosity x compressibility factor), the resulting differential equation, Equation 1 (ERCB 1975), still contains a non-linear term, µ c (viscosity x compressibility).

(Equation Available In Full Paper)

where ΔPD is a dimensionless pressure drop, and is defined in the nomenclature along with the other symbols. Because µc is a function of ψ, this equation is non-linear and cannot be solved analytically. AI-Hussainy and Ramey (1966) assumed µc to be constant at initial conditions, uici, and solved the resulting ice linear partial differential equation. The solution is the familiar exponential integral. Ei, solution.

The dependence of µc on p, p2 or ψ was investigated in a paper by Mattar (1979) and it was found that, under certain circumstances, the change in µc can be substantial Therefore, the assumption of a constant µC to obtain a solvable differential equation may be questionable.

It is the intent of this paper to solve the non-linear Equation 1 by the method of perturbation without assuming µc to be a constant. Because it is the variable that introduces the least number of assumptions, it will be used in preference to p or p2.

Extent of Non-linearity-Variation of µc with ψ

The variation of µc with ψ for natural gas is discussed in detail by Mattar (1979). However, a typical relationship is shown in Figure 2.
Economic Modelling a Game of Chance
Authors: Reath Peter F.
Published: March 2010

The requirements for project evaluation and acquisition analysis grow more complex daily, and demand the use of sophisticated computer assistance. What farm do the systems and models take? Can they really predict the future?

The author sets "out a scenario for the use of computer models in this field and, while recognizing their value, cautions that such systems are only extensions of their human creators. As such, they contain not only the rigidity of machines, but also the fallibility of homo sapiens.

INTRODUCTION

The Rules of the Game

In 1866, William Gladstone addressed Parliament with the words, "You cannot fight against the future. Time is on our side." Just over a century later, the future is certainly no more amenable to control, but there is a considerable question as to whether time is on our side. We are in an era of energy mega-projects the lifespans of which can exceed the working lives of those mortals who initiate them. The destinies of many corporations are entwined with these ventures into the uncharted future, and the risks are copious enough to test the most resilient captains of industry.

This situation has in turn created a sharp increase in the importance of economic evaluations using advanced computer systems: a development which may" have far-reaching consequences for the traditional engineering role in projects. To see what is happening, consider some of the following points: The construction of an oil sands plant later in this decade may require average disbursements of around, eight million dollars per day during peak construction years. It may take six years from first production until the capital expenditure has been recovered (eleven years after detailed engineering design is completed), and this is against a background of reasonably proven technology and experience from two working oil sands plants. Estimates of Beaufort Sea and East Coast developments provide similarly mind-numbing statistics.

Even these projections are made within a "comfort zone" which excludes such assumptions as wars or major catastrophes, wide divergences in price versus cost inflation or social revolution which might damage the fabric of free enterprise beyond repair. Thus, the worst ravages of the future are instantly negated by the elementary assumption that economic variables must be constrained within boundaries established by our current experience. Proponents of "Murphy"s Law" are silenced by the wisdom that major diversions from economically reasonable assumptions will either be offset by man"s infinite capacity to survive or we all go down the tube together (a convenient but hardly comforting, point to begin).

Having defined the boundaries for our projections of future possibilities, we have to face up to reality number two: the rules of this game are complex and never static. As a starting point, we have a fundamental equation:

Profit = Revenue - Costs - Taxation

However, a glimpse at Figure I will show that this particular game is run by the state, and the house advantages are several.
The Elimination of the Constraint Equation And Modelling of Problems With a Non-condensable Gas In Steam Simulation
Authors: Forsyth P. , Rubin B. , Vinsome P.K.W.
Published: March 2010

The numerical formulation previously used in CMG's (Computer Modelling Group) steam simulator used an equation set consisting of flow equations and a constraint equation. The effect of analytically eliminating this constraint equation from the basic equation set, thereby reducing the number of primary variables by one, is investigated. It is found that an alternating use of the two equation sets according to certain switching criteria yields the best results.

A problem of convergence to non-physical answers, which arises in the simulation of steam displacement with a non-condensable gas, is described, and a method for circumventing this problem is proposed. The results of various test runs are included.

INTRODUCTION

The equations used to describe the steam or in-situ combustion processes can be divided into two groups. The "flow" equations (energy and mass balance) contain inter-block flow terms; the "constraint" equations (saturations and mole fraction constraint) depend only on variables in a single block(1). It is possible to eliminate the constraint equations analytically from the equation set, and thereby reduce the number of equations per grid block. However, previous in-situ combustion and steam simulators have retained the constraint equations in the basic equation set(2–4). These authors have reported that the addition of constraint equations to the basic equation set results in better stability and convergence rate, and permits larger time steps. As the amount of computation per time step is increased for a larger equation set, it is not clear that the addition of constraint equations will result in a net saving in computing cost.

This 4-equation formalism has been discussed because it is a natural subset of CMG"s in-situ combustion model ISCOM(5), which is a fully implicit simulator. When ISCOM is run on combustion problems, the constraint equations are eliminated analytically. No difficulties have been observed with this procedure(5–6). Consequently, it was decided to investigate the effect of eliminating the constraint equation (1) from the steam model.

Description of the Model

If equation (1) is eliminated from the set (1–4), there are only three "basic" equations left, which express the conservation of oil, water and energy. In order to reduce the equation set, it is necessary to perform variable substitution on the appearance or disappearance of steam, while the equation set remains the same. This is in constrast to the previous method(5), where the independent variables remain the same, but the equation set is switched.

For the situation in which there is no steam in a given grid block, the primary variables associated with each equation are:

(Equation in full paper)

The disappearance of the water phase is avoided using the pseudo k value method(4). The only other fully implicit steam simulator reported in the literature is that developed by Coats(l) as a subset of an in-situ combustion simulator.
Harsh New Rules For Employee And Shareholder Loans
Authors: Parsons Robert B.
Published: March 2010

This month, "Tax Topics" examines the changes proposed in the November 12, 1981 federal budget relating to the taxation of stock purchase and housing loans. The changes, if enacted, will come into effect in 1982 to tax the benefits derived from low-interest and interest-free loans. As a result of public pressure, some transitional rules have been announced since the budget date to phase-in the new rules.

Introduction

Since November 12, 1981, whim Finance Minister Allan MacEachen introduced his proposed sweeping tax changes, there has been a public outcry at the breadth of tax changes and the lack of public discussions preceding the budget. In addition, the original budget was notable in its lack of transitional rules regarding the implementation of many important changes.

The proposed taxation of stock purchase loans and honsing loans is one of the few areas that, due to the furor created, has seen some substantive changes since November 12, 1981. However, the draft legislation is not expected until April or May of this year. so it is quite conceivable that the rules may change yet.

Many taxpayers associated with the oil and gas industry will be particularly hard hit by these proposals, because of the relatively widespread use of interest-free loans in the industry. For junior oil com panies needing maximum amounts of cash resources to finance exploration and development, the use of interest-free loans to enable employees to acquire company shares has been an attractive compensation device.

As the accompanying examples illustrate, although Mr. MacEachen has lowered the top personal income tax rates, the additional amounts that will be included in taxable income can create a greater tax liability.

The New Rules

According to the budget proposals beginning in 1982, employees and shareholders will be fully taxed on benefits derived from certain loans and other forms of indebtedness. The benefits will be determined by deducting actual interest paid, if any, in the year and within 30 days of the end of the year from imputed interest to be calculated at prescribed rates.

The prescribed rate, in future, will be adjusted every three months in relation to the average interest rate on 90-day treasury bills during the first month of the preceding quarter.

Although it was orginally announced that the prescribed rate for the first quarter of 1982 would be set at 19%, because of a decline in interest rates since the budget, the prescribed rate was subsequently reduced to 16% for this quarter. Although a loan bearing interest at a rate below the prescribed rate will usually give rise to a taxable benefit, there will be no income inclusion unless the rate charged is also below the prevailing rate available in financial markets at the time the loan was made.

The proposed new rules will generally apply to all loans and indebtedness regardless of whether issued before or after the November budget date.
Heavy Oil Production By Carbon Dioxide Injection
Authors: Klins Mark A. , Ali S.M. Farouq
Published: March 2010

Currently, there is a great deal of interest in carbon dioxide for the recovery of both heavy and light oils. This paper deals with an investigation of the efficiency of gaseous carbon dioxide as a recovery agent for moderately viscous oils. The paper gives numerical model results, and compares and contrasts the findings with laboratory and field test observations, pointing out the range of conditions over which carbon dioxide is likely to be effective.

The carbon dioxide injection simulator used simulates three- phase flow, and was checked out for numerical dispersion grid effects, material balance, etc. It was then employed for a variety of carbon dioxide injection simulations. The base cases were in qualitative agreement with the reported experimental data.

It was found that over the viscosity range of J 10 1000 mPa.s, carbon dioxide was superior to natural depletion, inert gas injection or water flooding, jar oil viscosities above 70 mPa. s. The gain over water flooding was as much as 9 per cell· tiles in oil recovery, being greater for the more viscous crudes. Oil saturation was an important variable, as oil recovery decreased rapidly with a decrease in saturation. Another significant factor affecting ultimate oil recovery was the critical gas saturation. Viscous oils showed a 27% increase in recovery as the critical gas saturation varied from 0 to 10%. The blow down recovery on curtailment 0/ carbon dioxide injection was about 1 percentile; field values are as high as 4 percentiles. Reasons for this discrepancy are outlined. The amount of carbon dioxide left in the reservoir was used as a measure of the efficiency of the process; it was high for low oil saturations, especially for the more viscous oils.

An economic analysis of the carbon dioxide injection process showed that the economics are tenuous; a variety of factors in addition to the oil price would determine the economic viability of the process.

Introduction

Although there is little debate that a significant amount of oil remains held in the ground by current technical and economic constraints, opinion is widespread as to the proper recovery technique or techniques to unlock these reserves. (Infill drilling and a handful of alternative recovery methods, such as thermal, miscible and improved mobility floods, compete for the over 52 billion cubic metres of United States and Canadian oil (<980 Kg/m3) that remains in place.

Carbon dioxide injection, as one of these processes, has long been thought of as a miscible process best applied in light oils with densities less than 930 Kg/m3. However, immiscible carbon dioxide flooding as part of the suite of enhanced oil recovery methods being tested may be promising in the case of heavy, moderately viscous oils where carbon dioxide injection improves recovery by lowering oil viscosity and promoting swelling.

Deposits of heavy oil total over one-half trillion metres3 in the U.S., Venezuela and Canada. In the U.S. alone, there are over 2,000 heavy oil reservoirs occurring in 1500 fields in 26 states.
Coping With Change'' Customs Issues Upstream
Authors: Parsons Robert B.
Published: March 2010

The complications of the National Energy Program have satisfied even the most gregarious appetites: now customs duty issues related to exploration, development and production of Canada's non-renewable energy resources are promising to excite the palate. The menu offers a wide selection: legislative amendments for the conventional; exotic constitutional issues ifyou delight in the offshore. But watch out. it's not always a free meal!

This month, Tax Topics reviews some of the emerging issues in the customs area on matters related to resource exploration, development or production. We focus on what's ahead: traps and pitfalls opportunities and savings.

Introduction

In recent years coping with tax changes has become a daily preoccupation at companies operating in Canada's oil and gas industry. Life as the tax administrator has not been easy or dull. If recent developments in the customs area hold true, the tax administrator will soon have to buy a "customs" hat and, in some cases, he may want to put it on retroactively. This article intends to describe in non-technical terms, a few of the emerging customs issues as they might affect the oil and gas industry, especially the players upstream. Furthermore, for easy reference, a few guidelines to the administration of customs duties are set out in the Appendix.

Tariff rates-oil & gas industry

Until recently, customs duties have not been of significant concern to companies engaged in conventional drilling programs. As a rule, a series of specific end use tariff items providing low or free rates of duty has governed the importation of a broad range of goods intended for use in the chain of exploration development- production of Canada's oil and gas reserves. The majority of these end use items are found in the 49XXX series of the Customs Tariff.

Except where specifically named elsewhere, goods imported for a qualifying end use are dutiable at the rate set out for these end-use classes. Depending on the use, duty is assessed either at rates that range from 8.4% to 12.1% or, as often the case, no duty is assessed. In some cases, the' end use class names the goods (e.g., blow-out preventors, derricks for drilling rigs, draw works); other end use classes refer to a basket clause (e.g., all other machinery and apparatus for use in...). Rates of duty also vary depending on whether or not the named goods or a good falling within a basket clause, "is of a class or kind made/not made in Canada." Finally, so as not to discourage the manufacture in Canada of goods qualifying for low or duty-free end use rates, materials imported for use in their manufacture are allowed duty-free entry.

As a result, duty-free status has been gained by companies engaged in conventional drilling programs (or their suppliers) on the purchase or importation of a large portion of their capital acquisitions, including:masts or derricks for drilling, servicing or work-over rigs;drilling, servicing or work-over rigs;well logging equipment;