bluuebunny/crossref_metadata_2025 huggingface dataset:
Predicting the Price of Oil In Canada
Authors: Godsoe Gerald
Published: March 2010

Introduction

When our recent economic history has been definitively written, the price of oil may well prove to havebeen the dominant factor not only in energy developments, but in world economics as a whole. The price of oil has been a major determinant of the rate of growth of industrial and lion-industrial nations, the timing of our recessions and their depth, and the distribution of economic power between nations, and therefore it has directly affected the exercise of political power.

The future price of oil will be a pertinent factor in every sector of our industrial economy. The tremendous success of industrialization has largely depended on cheap energy. As our food becomes more and more processed and the agricultural industry more efficient, a higher and higher energy content is represented by what we put on our tables.

Because it is such a basic factor, this article proposes to comment on the future price of oil.

The Pricing of Oil

To assess where the price of oil will go in the next few years, you must know how it is determined. In Canada our price is set by the Federal Government once or twice a year and this has been the case since January, 1974. The world increase in oil price was from $3 to $10 over a four-month period at the end of 1973. For Canadian consumers, a cross subsidy has kept the increase much more gradual.

There is no doubt that eventually we too will be paying the international price of oil This is part of the current Canadian oil policy and a quick look at our decreasing exports of oil and increasing imports will show that the Federal Government cannot finance the oil subsidy for more than the next few years.

Not only will we have to pay each future increase in international oil price as it comes along, but the gap between international price and our own price in Canada will close at a fairly rapid rate.

For example, the Canadian price was frozen at a new level in July, 1975 for twelve months. During that period, in October, 1975, OPEC increased the international price by $1.05. The Canadian price was then increased by $1.05 in July, 1976 to incorporate the OPEC increase. Finally, the Canadian price will increase again by $0.70 in January, 1977. The Canadian subsidy, the gap between our cost and the international price, is thereby reduced by about 40%, from $4.60 to $2,65 (see Fig. 1).

The first factor to evaluate is the international price of oil and how that is set by OPEC.

The price of oil has long been of strategic concern to governments. Ever since oil substantially supplanted coal as a prime energy source, governments have shown a proclivity to interfere with its price.
Importance of Reservoir Description In Evaluating In-Situ Recovery Methods For Cold Lake Heavy Oil
Authors: Kendall G.H.
Published: March 2010

The huge reserves of heavy oil in Alberta are found in a Variety of complex reservoir. Recovery, excluding mining, will require application of some form of in-situ method, primarily in the better reservoir. The proper selection of an in-situ method, applicable to the various reservoir type, requires a basic understanding of reservoir description, and the engineering aspect of the reservoirs. In Part 1 of this paper, reservoir description in the Cold Lake heavy oil deposits is discussed under three headings:rock properties;fluid saturation; andreservoir geometry.

Based on these parameters, five selected reservoir types are discussed and compared.

Part 2 considers the application of the reservoir description in evaluating in-situ methods. The significance of the reservoir parameters is discussed in general terms and related to the four most important in-situ recovery mechanism: steam stimulation, steam drive, combustion and solvent. The reservoir description is then used as the basis of comparison of the recovery mechanisms for each of the five Cold Lake reservoir types described in Part 1.

Introduction

OVER 900 BILLION BARRELS (143 × 109 m3) of heavy oil, known as the Alberta oil sands deposits, are found in a variety of complex reservoirs in sands of Lower Cretaceous age. Knowledge of the presence of these resources may be very comforting in these times of concern over Canada's future energy supplies. However, this oil is only of value if, and when, it can be recovered from the reservoirs.

Recovery has started in the Athabasca area where oil is being extracted from the reservoir by 'surface mining methods. Great Canadian Oil Sands Ltd. has a mine and an upgrading plant in operation and Syncrude Canada Ltd. has the second extraction facility under construction. Mining methods, however, are applicable to but a small portion of the Athabasca areas and these methods may yield, as currently estimated, 38 billion barrels (6 × 109 m3) or 4% of the total oil in place in the deposits*. The remainder of the oil in place outside of the mineable area of Athabasca, the heavy oil deposits in the Cold Lake area and the other oil sands deposits will have to be extracted by in-situ recovery techniques.

In-situ recovery processes basically consist of increasing the mobility of the oil and then driving the fluids to a production well. The successful application of any of these techniques depends on a profound knowledge of the characteristics of the reservoir. Part 1 of this paper discusses the nature of the oil sands in terms of rock properties, fluid saturations and reservoir geometry. Based on these parameters, five selected reservoir types in the Cold Lake area are identified and compared. In Part 2, those parameters are related to a number of in-situ recovery methods for heavy oil, with specific reference to application in the Cold Lake deposit.

In the papers, no distinction is made among the terms "heavy-oil sands", "oil sands" or "tar sands".
Pool Description And Performance Analysis Leads to Understanding Golden Spike's Miscible Flood
Authors: Reitzel G.A. , Callow G.O.
Published: March 2010

Reservoir description was a key factor in analyzing the performance of the Golden Spike vertical gravity controlled miscible L.P.G. bank scheme. Understanding the performance of the pool was enhanced by including a detailed reservoir description in a computer model study of the miscible scheme. The originally designed 7% pore volume L.P.G. bank was injected between the gas and oil zones from 1964 through 1975. Extensive monitoring of fluid distribution in this 1,385-acre, 480-foot-thick reef complex indicated that the miscible flood improved the oil recovery until 1979. A geological study, incorporating data from infill wells drilled during the 1970's, shows that the reservoir contains many local barriers to vertical flow. Located in the interior of the reef, these barriers range in size from less than 5 to over 600 acres. The barriers were not recognized prior to infill drilling, because the early development wells were drilled mainly in more homogeneous sections of the reefcomplex. Recent performance analysis indicates the barriers resulted in by-passing of oil and loss of miscible flood benefits after 1978. As a result of the loss of miscibility, the pool is currently under gas drive and the miscible scheme has been terminated. Performance analysis results are confirmed by a cross-section computer model study of the pool. The cross-section model also indicates that the vertical flow barriers combined with the designed bank size results in poor sweep efficiency by solvent. However, future sweep efficiency by gas is predicted to be high due to continued drainage of oil off the barriers.

Introduction

THE GOLDEN SPIKE D3 "A" Pool, located 18 miles southwest of the City of Edmonton in Central Alberta, was discovered in 1949 (Fig. 1). The pool is located on the western, seaward side of a trend of productive Leduc reefs. This limestone reservoir is a Leduc-age Woodbend reef complex, covering an area of 1,385 acres. Within the crestal area of 1,000 acres, average oil pay thickness is 550 feet. Initial oil-in-place was 319 MMSTB, with no gas cap or water leg present.

As indicated in Figure 2, the Leduc Formation at Golden Spike is divisible into three members, designated Lower, Middle and Upper Leduc, Oil occurrence in the Golden Spike D3 ‘A’ Pool is restricted to the Middle and Upper members which, together, make up the reef complex, The underlying Lower Leduc is a shallow-water carbonate bank, more extensive in area than the reef build-up, but limited in reservoir development. This carbonate bank is not in communication with the oil zone.

Initial production of this reservoir by fluid expansion resulted in a rapid pressure decline. Pressure maintenance by gas injection commenced in 1953. Analysis of the available well data and gas flood performance up to 1963 indicated a relatively homogeneous reservoir. The apparent good quality of the reservoir and the availability of a suitable, inexpensive hydrocarbon solvent (LPG) prompted installation of a miscible flood in 1964 (Fig. 3).
A New Model For Fracture Gradient
Authors: Althaus Voy E.
Published: March 2010

For the past eighteen years, fracture gradient has been thought to be some junction of overburden stress, horizontal stress und internal fluid pressure. Each author that has published in the intervening years has refined this idea. This paper derives such a model, but then uses the same data to turn the entire relationship around to derive (and support a new model with the following attributes.Fracture gradient is equal to the least stress field n the earth.Fracture graadient is independent of the fluid pressure gradient; it depends only on the earth's stress field.Fluid pressure gradient is dependent on fracture gradient. If the fluid pressure gradient equals the fracture gradient, the earth fractures and the thud is released to permeable beds.Most abnormal fluid pressure systems may be pressured to the fracture gradient at their structurally highest point.

Introduction

SINCE the puhlication of Hubhert and Willis(11) on hydraulic fracturing in 1957, most authors have held that fracture gradient is a function of overburden stress, horizontal stress and internal fluid pressure, although the exact relationship has remained in dispute. A recent article, however, by MacPherson and Berry(12) states that in calculating fracture gradient from sonic and density logs, they found no evidence that the formation fluid pressure gradient affects the fracture gradient. This strikes a sympathetic point with this author and the result is this paper.

The data gathering and the original curve fitting for this project were done in 1967; but because a number of papers were published that year on fracture gradient, one more paper giving essentially the same results did not seem warranted. The original work is included; however, the purpose of this paper is to show that the same data that were used to relate fracture gradient to pressure gradient can be used to turn the entire equation around and relate pressure gradient to fracture gradient as the independent variable. This solution suggests that fracture gradient is dependent only on minimum regional stress. A body of theory has been derived that indicates that this solution is possible.

Sampling Procedure

The sample for this project included most of the lost returns encountered by Exxon while drilling in South Louisiana and the Louisiana Offshore from 1964 to mid-1967. A total of sixty-six cases were used, which is considered to be a statistically satisfactory sample. The geological section sampled ranged from Lower Miocene to Recent in age, with the bulk of the data being Upper Miocene.

A basic assumption was made in gathering data that the point of fracture in each well was at the highest exposed depth and the lowest exposed formation fluid pressure below the deepest casing set in the well at the time of lost returns. As no cases were 'found in this sample where the formation fluid pressure decreased with depth, the fracture point was picked in all cases as the first exposed point below casing.
A Role For Nuclear Energy In the Recovery Of Oil From the Tar Sands of Alberta
Authors: Puitagunta V.R. , Sochaski R.O. , Robertson R.F.S.
Published: March 2010

This report briefly describes techniques of oil recovery from the tar sands and the energy requirements of this operation. Fossil fuel, such as coal, and CANDU* nuclear reactors are examined as competitive sources of energy for the tar sands plants. This study indicates the feasibility of both sources. Among the nuclear reactors, the organic-cooled version of the CANDU reactor appears to have the necessary flexibility to fit into many of the possible methods of recovering oil from the tar sands.

Cost comparisons of fossil and nuclear sources show that, for the supply of process steam, the nuclear source is competitive under the criteria of debt financing or low discount rates on capital, continued escalation, and long plant capital write-off period.

A strategy is discussed for the recovery of oil from the tar sands with a view to optimizing the costs and, in tile long run, to conserving the fossil fuels at the expense of nuclear fuels. This scheme involves supplying process heat and electricity from organic-cooled CANDU reactors (CANDU-OCR) built at the tar sands site, making hydrogen from coal at the coal fields and piping it to the bitumen upgrading plants. This strategy would require further development of the CANDU-OCR.

INTRODUCTION

Liquid fuels are the form of energy best suited to power the transportation sector, which represents about 25 percent of the total energy consumed in Canada (Present liquid fuel consumption actually exceeds 50 percent of the total energy consumed in Canada). No economic alternative to these fuels has yet been found. Currently, these liquid fuels are derived from petroleum which is expected to be in short supply in theory near future. Recently Canada became a net importer of oil and this situation is expected to continue at least for a decade at a continually increasing rate. The current high prices of crude oil in the international market and the unreliability of the supply are great incentives for any country to become self-sufficient in oil.

Canada has large supplies of tar sands bitumen, coal, uranium, and thorium. It is theoretically possible to convert the energy from any of these fuels into liquid fuel energy. The efficiency, complexity and the capital expenditures required to achieve these conversions vary with the source of energy. For example, no more than 10 percent of the energy in nuclear fuels can be obtained as liquid fuel energy in tile direct cycle which is:

Similarly, two-thirds of the energy content of coal is lost in the process of making liquid fuels from coal.In comparison, only a third of the energy content islost when liquid fuels are derived from the tar sands with present technology. The lower efficiency conversion cycles discussed are complex and require high capital investments.

Recovery of liquid fuels from tar sands involves an energy input in the form of electricity, process heat, and hydrogen.
Trapping Of Heavy Oil At Lloydminster
Authors: Vigrass L.W.
Published: March 2010

Most of the oil in the Lloydminister area occurs in the Sparky and General Petroleums (G.P.) sandstones. These sandstones are widespread tabular sheets which are probably marine delta-front deposits over much of the area. Detailed studies show that the bulk of the Sparky and G.P. oil is trapped downdip from gullies or channels that are filled with upper Marmville shaly rocks. The grillies are as much as 235 ft (72 m) deep and were formed by sub-aerial erosion on an imra-Mannville disconformity. The time involved in uplift, erosion, Subsidence and burial was short - probably less than a million years. The shaly fill in the gullies and the Mannville strata younger than Sparky are mainly fluviatile sediment derived from the Cordillera.

Recognition of the presence and nature of the disconformity is extremely important ill exploration, in development, and in evaluating heavy oil resources for enhanced recovery.

In the Lloydminster area, situated on the inter-provincial boundary between Saskatoon and Edmonton (Fig. 1), important reserves of medium and heavy oil occur in sandstones of the Lower Cretaceous Mannville Group. The oil area was discovered more than 50 years ago, but there have always been problems because of the nature of the oil; viscous asphaltic crude that is difficult to recover, troublesome to handle and hard to market. Interest in the area has increased because of the large amounts of oil-in-place and the potential for increasing recovery by thermal" or other exotic recovery methods. There have also been problems in deciphering the geology and defining the trapping mechanism, largely due to poor collection of geological data and lack of interset of most petroleum geologists. Most earlier geological workers, in published accounts at least, have interpreted the heavy oil sands as part of a delta complex, with the oil trapped in lenticular sand bodies or trapped behind distributary channels on the delta surface. Detailed log examination and mapping suggest a contrary interpretation: the important oil reservoirs are sheet-like sandstones, an important disconformity occurs within the Mannville and most of the oil is trapped downdip from gullies on this intra-Mannville erosion surface. Gullies on the unconformity are as much as 235 ft (72 m) deep and are filled with shaly beds and muddy sandstones.

This paper is dedicated mainly to providing evidence for the disconformity and showing examples of how the disconformity traps the bulk of the oil in the Lloydminster area. For additional details On stratigraphy, sedimentology and geological history, the reader is referred to Vigrass (1977).

Oil Fields of Lloydminster Area

Defined oil and gas pools of the map area (Fig. 2) are all in sandstones of the Mannville Group, the sandy sequence at the base of the Lower Cretaceous. Gas fields; stippled on Figure 2, are of minor importance and will not be discussed. Oil pools are of two classes: those that occur in the middle and lower part of the Mannville (Sparky or older) are shown solid, whereas those in the upper part of Mannville are shown by an outline only.
Automatic Kriging And Contouring In The Presence Of Trends (Universal Kriging Made Simple)
Authors: Davis Michael W.D. , David Michel
Published: March 2010

The main purpose of this paper is to present a new automatic interpolation and contouring technique which automatically recognizes the spatial structure of the dam to be contoured even when, trends are present and data are not regularly spaced. A brief relief of contouring problems is presented the idea of spatial structure and its characterization by a generalized covariance is then introduced and the POLYPAC program is described. Applications in various areas (oil shales, sulphide mines, coal field, cement industry, geophysical data) are illustrated and a detailed appendix covers the mathematical theory of the intrinsic random functions of order k, which is the basis for the program. References to other similar programs are included.

Conceptual Background

Introduction

Attempting to survey everything that has been written on the subject of automatic contouring is a challenging task as ideas are generated in various fields with little communication between each other, such as coal reserves, ore reserve estimation or geophysical mapping, not to mention geography and meteorology. Also, the concern of contouring packages for high cosmetic quality like G.P.C.P., CSPL. Stampede, etc... tends to push people away from the fundamentals of the problem and its conceptualization, Most of the time the interpolation method used in a program is unknown to the map user, or he is left with the choice of up to 32 different interpolation subroutines in the same package, with no further hint at which method is adapted to his problem. It is our opinion that most mapping problems can be encased in the frame of a unifying theory which will allow the generation of the most adequate map for a given purpose. This theory has been known as kriging or simply geostatistics and was developed by Matheron, The full name of the most complete version of it is "theory of intrinsic random functions of order k", and all its intricacies have now been turned into another black box, which produces the best theoretical maps within the framework of distance weighted and trend-surface interpolation. It is one of the purposes of this paper to show which concepts are needed to understand why a given interpolation algorithm is good in certain cases and unacceptable in others. These concepts of spatial structure, drift, trend, high-frequency noise, estimation variance have been known for a long time, but we must admit that map users should be presented with something else than a truckload of equations. The contouring problem is easily split in two; the first problem is that of the generation of II. regular grid of points, the second being that of aesthetically contouring this fine grid. So far only the first problem retained the attention of geostatisticians, with few exceptions. Broken contours are not acceptable even if the theory behind the grid generation technique is faultless (Olea, 1972). There now exists a program matching the most sophisticated theory and superb contours.
Analyzing Well Performance X
Authors: McCoy James N.
Published: March 2010

After a general discussion of fluid flow, this paper reviews the data which are necessary for well analysis. The acoustic liquid level instrument is described, well producing rate efficiency (with and without gas) is discussed and an analysis of downhole equipment is given.

Introduction

Analyzing well performance is an important step toward increasing profits by improving production techniques. The analysis is made by field tests and examination of well data. The acoustic liquid level instrument offers valuable information, because downhole pressures can be determined from the depth-to-liquid measurement.

Fluid Flow (generalized)

Fluid flow in a reservoir is caused by movement of fluid from a high-pressure area to a low-pressure area. Fluid flow into a wellbore occurs when fluids, present in the wellbore are removed so that the pressure is decreased. Then? fluid from an area of higher pressure flows into the lower-pressure wellbore (Fig. 1).

Fluid flow into a wellbore is approximately proportional to the drawdown pressure, which is the difference in pressure between the higher pressure reservoir and the low-pressure wellbore. The greater the difference, the greater the fluid flow. Figure 2 represents some ideal cases of fluid flow in a reservoir.

The lower the wellbore pressure the greater the inflow rate. Generally, in the past, the inflow rate has been assumed to be proportional to the drawdown pressure. This procedure is still used in wells which produce liquid without gas. Vogel(I) presents a curve for predicting flow rates in 2-phase flow (liquid and gas). This curve is shown on the Well Analysis sheet and should be used when predicting flow behaviour in wells making liquid and gas.

Necessary Data for Well Analysis

Four factors are extremely important in analyzing well performance:static bottom-hole pressure (or reservoir pressure),producing bottom-hole pressure,well test andpump capacity.

For maximum withdrawal, the producing bottom-hole pressure must be low compared to the static bottom-hole pressure. A producing bottom-hole pressure of 75 psi is low compared to a static reservoir of 2300 psi, and practically all of the production is beng obtained. However, if the static reservoir pressure is 100 psi, approximately one-fourth of the production is being obtained. The well test must also be known. If the producing wellbore pressure is low compared to the static reservoir pressure, maximum inflow is occurring. However, if the maximum inflow is less than commercial production, action must be taken. Last, the pump capacity must be known. If the pump capacity is not matched suitably to the well's production, excessive wear and a mechanical loss of efficiency are occurring if the pump capacity greatly exceeds the production rate. A production loss occurs if the, pump capacity is less than the well's producing capacity.

Note the importance of each item, by trying to determine the proper action on each of the wells in Table 1 when only one of the four items on each well is omitted.
Wellbore Transmission Of Electrical Power
Authors: Newbold F.R. , Perkins T.K.
Published: March 2010

In-situ electrical heating of viscous oils depends on the passage of large electrical currents through a subsurface formation. It is essential to the design of such a process to know the percentage of power applied at the wellhead which actually heats the object formation below. This in turn requires that there exist some convenient and reliable method for predicting the power loss which occurs in the wellbore. Although the determination of the power loss is straightforward for a DC system, it is often desirable to use readily available AC current to minimize corrosion. On the other hand, use of AC current can lead to a significant increase in transmission power loss in the presence of steel tubular goods, primarily because of magnetic hysteresis and eddy current losses.

It is the purpose of this paper to present an experimental method for determining the wellbore transmission power loss in AC systems. Theory related to AC power loss is discussed, and general laboratory experiments are described which determine the losses in complex wellbore systems. Power loss data obtained from a shallow well test installation are presented for two distinct modes of operation: one in which copper cables are used to conduct power down hole, and a second which utilizes the steel pipe as the conductor. Additional laboratory experiments are then described which were designed to duplicate the data taken in the shallow wells. The laboratory results are shown to be in good agreement with power measurements made in the two 500-foot wells of the shallow well installation, demonstrating that the method can predict power loss for field-scale systems.

Introduction

Electrical heating of subsurface formations has frequently been proposed as a means of enhancing oil recovery(1,2,3) In particular, electrical heating has been proposed(4) as a means for in-situ heating of a subsurface oil sand formation in order to mobilize the viscous oil contained therein. A schematic for this process appears in Figure 1 and is discussed in detail in Reference 4. Basically, the concept is to conduct large AC currents down a wellbore, through the object formation, and back up an adjacent well. Formation brine provides the conductive medium in most of the formations, and "bound" water in the shales accounts for their (high) conductivity. These currents heat the formation by virtue of resistance (Joule) heating, creating a mobile fluid path between the wells where little or no flow was possible before heating. Once the viscous oil has been mobilized, it can be recovered by a more conventional fluid displacement process. Note that although heat conduction will occur and must be taken into account, this is not the principal means by which fluid mobility is achieved. Also note that Joule heating occurs throughout the formation from the moment power is applied so that the critical area midway between the electrode wells is being heated and mobilized from the outset.
The Canadian Outlook And Priorities For Energy
Authors: Scotland W.A.
Published: March 2010

This paper was presented under the "Energy Options" theme during the Plenary Session at the 29tb Annual Technical Meeting of The Petroleum Society of CIM, Calgary, Alberta, June 14.

Introduction

THE National Energy Board is in the midst of a bearing into the supply and demand for oil in Canada, and various related matters, and we will hold a similar enquiry on natural gas supply and demand this fall. A number of matters I will touch on will be the subject of industry and public discussion through the hearing process. Once the hearings are completed, the Board will be in a position to become more specific in its views in these areas. In the meantime, it may be useful for us to consider an overview of certain aspects of the Canadian energy situation.

In recent years, perceptions of the energy situation by industry, the public and government have changed to adapt to the reality that the days of low-cost energy are behind us. All sectors of the economy are now in the process of modifying past practices to bring themselves into line with that reality. The overriding priority in energy at this time is to ensure the availability of an adequate energy supply to meet the needs of a healthy and vigorous economy and society, in order to have an acceptable quality of life in Canada. This includes planning to meet the possibility of an eventual constraint on world oil supplies, which could occur in the mid or late 1980's. This supply constraint could be either physical or political and could cause economic upheaval if energy shortages occur or if world oil prices increase too rapidly. Accordingly, the federal government has set a goal of achieving the highest possible degree of self-reliance in energy.

To meet this self-reliance goal, a whole series of energy policies have been formulated. It is difficult to single out a particular policy as having priority over other government measures, because it is the net effect of the entire set of policies that is intended to allow Canada to meet its self-reliance target. However, increased emphasis has been given to some policy areas and it is this shift in emphasis I will try to outline here.

Increased Reliance

On Oil Imports

A major area of federal government concern is Canada's growing net imports of oil and oil products. In 1975, Canada was self-sufficient in the sense that we exported more oil than we imported. Today, net imports are about 300,000 barrels a day. By 1985, net imports may grow to much higher levels unless action continues to be taken to reduce the rate of growth of oil demand and to increase the level of effective domestic supply. If net oil imports were to reach extremely high levels, this could create difficulties in Canada's balance-of-payments situation, and could be most detrimental to living standards and general economic activity throughout the country.
Stress Analysis Of Bent Sucker Rods
Authors: Bellow D.G. , Kumar A.
Published: March 2010

This paper describes an elastic analysis which can be applied to bent sucker rods to determine the effect of this imperfection on the stress behaviour or load-carrying capacity of the rod. It is shown that if the location of the bend in the rod is close to the sucker rod coupling, then high stresses can occur on the surface of the bend and this can seriously reduce the working capacity of the rod. Also, it is shown that for rods with bends in them a significant compressive stress can occur at the bend even though the rod is subjected to a large axial load. Experimental results are shown to agree quite favourably with the theory.

The problem of residual stresses in the rod is also discussed and a mechanism for analyzing this, problem is described along with some experimental results.

Introduction

A sucker rod passes through many operations and handling procedures from the time it originally takes its shape in the manufacturing industry until it is placed in a well in the field. To what extent do bends in a sucker rod influence the life of that rod when placed down a well? When a rod is permanently bent, plastic deformation has taken place; this not only reduces the flexibility of the rod, but, in the area of the, bend, the residual stresses can accelerate corrosion.

The object of this paper is to describe a means of evaluating the significance of bends on the -elastic behaviour of a sucker rod and provide a design formula for use in determining an acceptable degree of bend. Some experimental results are also presented which show the extent of plastic deformation that has occurred as a function of observable bends in a rod.

Theoretical Considerations

In the theoretical analysis, it was assumed that the initial shape of a bent rod could be represented by two straight lines, A-C and C-B, which meet at an apex called the bend position. The bend position is identified by dimension "a" and its location from one of the ends "c", as shown in Figure 1. It was also assumed that such a rod was bent before final heat treatment and therefore no residual stresses would be present when an axial load was applied. Thus, the analysis is a simple one of elastic behaviour of an initially bent circular rod. When the rod has been bent after heat treatment, there will be residual stresses and the total stress picture must be obtained by considering the elastic stresses added to the residual stresses. This is discussed in the treatment of the experimental program.

The procedure for the elastic analysis was based on attempting to provide a mathematical model which could be checked by experiment. Because the experimental apparatus available for loading a sucker rod was limited to one of the testing machines in the laboratory it meant that the segment of the rod had to be kept within 6 feet.
Deep Well Casing Cathodic Protection Requirements
Authors: Schellenberger Brian G. , Ingram William O.
Published: March 2010

Failures of well casings as a result of external corrosion on bothcathodically protected and unprotected wells in the South Swan Hills Unit havebeen investigated. Previous testing indicated that an instantaneously appliedcurrent of 30.0 amperes would not provide adequate protection throughout thecorrosive Wabamun D-1 water-bearing zone which exists throughout the unit atdepths ranging between 1,676 m (5,500 ft) and 2,195 m (7,200 ft).

A four-well pilot project was initiated in early 1977 to determine if 30.0amperes and polarization would provide adequate cathodic protection throughoutthe D-1 zone. The results of the pilot project indicated that cathodicprotection with 30. 0 amperes and polarization is possible throughout thecorrosive zone and that cathodic protection currents can be successfullyprojected below high-resistance zones.

Introduction

The South Swan Hills Unit is located approximately 225 km (140 miles)northwest of Edmonton, Alberta (Fig. 1). The field was discovered in 1961 andwas placed on production the following year. The total daily Unit production isapproximately 9,540 m3 (60,000 barrels) of oil and 9,540m3 (60,000 barrels) of water from 161 producing wells. The Unitcontains a total of 228 wells.

A typical downhole diagram of a South Swan Hill Unit well is depicted in Figure 2. The average total depth of the wells in the Unit is 2,469 m (8,100ft) and the average calculated cement top is 1,280 m (4,200 ft). The wellsproduce from the Beaverhill A and B formations.

A total of 13 leaks attributed to external corrosion have been experiencedin Unit wells since 1966. As shown in Figure 2, the leaks have occurred in twodistinct ranges: 8 between 894 m (2,900 ft) and 1,340 m (4,400 ft) on wellsdrilled with low-pH gyp starch mud, and 5 between 1,890 m (6,200 ft) 2,286 m(7,500 ft) on both non-gyp starch and gyp starch mud wells. The corrosionoccurring over the lower level is attributed to the water-bearing Wabamun D-1zone. Previous testing had indicated that cathodic protection over the D-1 zonemay not be possible in the South Swan Hills field.
Deep-hole, High-temperature Submersible Pumping
Authors: Mustard R.W. , Van Heukelom J.C.
Published: March 2010

There were 96 electric submersible pumps operating in the harsh environment of the 230 °F (110 °C) Beaverhill Lake formation of the South Swon Hills Unit at the end of 1977. Here 95% of the pumps are installed in 4-1/2-in. (114-mm) and 5-1/2-in. (140-mm) casing at an average depth of 8,000 ft (2,438 mi. A miscible flood covering half of the Unit contributes to an average producing GOR of 1,100scf/STB (195) and a number of wells produce with GOR's in excess of 2,000 scf/STB (354). These conditions of close tolerances, high temperature and high GOR have resulted in many operational problems. A number of procedures which have been developed to improve pump performance are presented.

Introduction

The Swan Hills oil field is located 140 miles (225 km) northwest of Edmonton, Alberta (Fig. 1). The Amoco-operated South Swan Hills Unit (Fig. 2) was formed in 1962, with 193 wells on 160-acre (64.8-hectare) spacing. Production is from the 230 °F (110 °C) Swan Hills formation of the Beaverhill Lake group, a limestone reef complex. Waterflooding commenced in 1963, and was expanded from 5 to 22 injection wells by 1972.

In 1973, a secondary recovery miscible flood project was initiated in the central portion of the field. This project consists of alternate injection of enriched gas solvent and water (1973-1978), dry gas (1979-1987) and then water (198B-200B). The first electric submersible pump was run in January, 1971. By the end of 1977 there were 96 submersible pump installations. The Unit was producing approximately 60,000 BOPD (9,540 m3/day) and 60,000 BWPD (9,540 m3/day) at this time.

Production History

Production performance for the miscible flood area, since the first submersible pump was installed in 1971, is detailed in Figure 3. There are 95 producing wells in this area. By the end of 1977, 63 (66%) were submersibly pumped, producing 80% of the oil. Twelve of the producers were flowing, and the remainder were beam pumped. The average GOR's has risen from the solution GOR of about 750 scf/STB (133) to as high as 1,330 scf/STB (229) in 1976. Miscible fluid breakthrough in several wells has resulted in periodic GOR's as high as 10,000 scf/STB (1,772). The combination of small production casing I.D.'s and high GOR's has caused severe submersible pump operating problems.

Figure 4 is a production plot for the west waterflood area. There are 52 producers in this area. By the end of 1977, 33 (63%) were submersibly pumped, producing 85% of the oil. The remaining producers were beam pumped. No submersible pumps have been installed in the east waterflood area of the South Swan Hills Unit- This area is located off the main reef build-up and total production averages less than 200 BOPD (32 m3/d).

Submersible Pump

Equipment Configuration

The downhole submersible pumping equipment (Fig. 5) consists of the pump assembly (centrifugal pump, gas separator, motor protector and motor), No. 4 lead sheathed flat cable to the top of the pump, and high-temperature No.6 flat cable to the pothead connection at the motor.
A Reserves Review of the Pembina Cardium Oil Pool
Authors: Purvis R.A. , Bober W.G.
Published: March 2010

The Pembina Cardium pool was divided into 43 study areas having more or less similar properties and production characteristics. A performance forecast was made for each study based on its average properties and historical decline. Estimates of initial established reserves were made for economic limits of 8, 6 and 4 b/d/well. A production and performance forecast for the entire pool was then made by summing the forecasts for each study area. Harmonic decline was observed for many of the study areas and for the pool as a whole. Consequently, plots of fluid rates and 1 + WOR versus cumulative oil recovery facilitated extrapolation of the historical decline.

The estimates of the pool reserve are very sensitive to the economic limit and vary from 1.3 to 1.5 billion barrels for the 8- and 4-b/d/well cases, respectively. The limiting water-oil ratios depend on rock quality and are forecast to vary from 0.3 to over 40. Although the predominance of laboratory flood data indicate a residual oil saturation of about 35 per cent, values of 44 and 50 per cent were used for the Upper and Lower Sand members, respectively. The latter values were based on a recent special core analysis for a well drilled 300 feet from a water injection well.

Introduction

The Pembina Cardium pool was discovered in 1953 with the successful completion of Socony-Seaboard Pembina No. 1 (4-16-48-8 W5M), some 70 miles southwest of Edmonton. The early development and performance history of the pool has been the subject of several papers (1,2,3,4). The pool currently has some 4400 operated wells and has produced over 876 million barrels of oil and 700 billion cubic feet of solution gas.

The most distinguishing feature of the pool is its large area, stretching 60 miles east to west and 40 miles north to south. The reservoir is an immense stratigraphic trap which, despite its size, has neither a bottom water zone nor a gas cap. The Cardium zone is extremely heterogeneous, and is composed of two easily recognizable sand members which in places are overlain by a highly permeable conglomerate member. The bulk of the displaceable oil is in the Upper Sand, a fine grained, well-sorted quartzose sandstone interbedded with shale laminae. The thickness of the Upper Sand ranges from 0 to 25 feet, having been completely eroded in places. The Lower Sand is 10 to 35 feet thick, is generally very fine grained, and contains numerous shale lenses.

Some 2800 wells have been cored, including 27 with oil-base mud. The Cardium formation has a low connate water saturation despite the low permeability throughout much of the pool. Based on oil-base core data, and correlations of connate water saturation with porosity and permeability, net sand pay has generally been defined as having a porosity greater than 9 per cent and a permeability greater than 0.1 millidarcy. The net pay is very sensitive to the level of the permeability cutoff.
International Energy Financing-implications For Canadian Energy Developments*
Authors: White N.A.
Published: March 2010

This paper identifies and discusses the principal determinants of the future financial requirements of the energy resource industries for their world-wide operations. Factors discussed include the amount of finance required, alternative methods of financing and sources of funds.

Comparisons are made between Canada's energy industries requirements and those of the U.S.A. and the U.K. It concludes that Canada's requirements are propornonately greater on a per-capita basis.

Similarly, the Canadian petroleum producing industries requirements are examined in the context of those of the international petroleum industry. This shows that the unit investment cost of Canadian petroleum supplies is likely to be considerably higher than the average unit cost of Western World*** supplies. It also demonstrates a sharp? divergence between the financing patterns of the Canadian and international industries.

The paper also discusses the role of international capital markets in providing funds for Canada's energy developments in the future and suggests that such sources may not be as helpful as might initially be expected and that competition for such funds may be quite strong.

The paper concludes that a larger amount of finance in the future will have to be in the form of project-related loans. It suggests that these may be assisted if a new form of private-sector financial institution could be formed to provide third-party guarantees for such loans. Without this, it is feared that greater government intervention may be unavailable.

Introduction

The theme assigned to me for this address embraces a wide range of issues, including questions such as: What will be the capital requirements of the world's energy industries to the year 2000? Where will the necessary funds come from? Will there be a need for new methods of financing? What factors might frustrate the efficient development and financing of the world's energy resources? These are important issues, and the answers are far from obvious at first glance, but for this occasion I have been asked to examine the implications of these issues for Canadian energy resources and especially for the future development of the Canadian petroleum producing industry. For a visitor to talk about the future development of domestic industries is always a daunting and often a hazardous task. I therefore approach it with a certain degree of trepidation. I am also reminded of the Arab proverb:

"Those who foretell the future lie, even if they tell the truth."

Determinants of Financial Requirements

The future financial requirements of the energy resource industries will be primarily determined by the following basic factors:

market needs for energy; technological! geological complexity of resource recovery; environmental hostility at resource location; level of annual rate of inflation; political costs.

Based on past trends, the growth rate in market needs for energy will match (or at least be linked with) the prospective rate of growth in economic activities.
Obtaining Open-hole Cement Plugs On The First Attempt
Authors: Salahub W.F. , Ripley H.E.
Published: March 2010

The four common reasons for setting open-hole cement plugs are reviewed. Factors which influence the condition of a cement plug, as well as the various plugging techniques, are outlined. The effects of auxiliary equipment, spacers, flushers, drilling fluid and the cement slurry are discussed individually with emphasis on techniques and materials that eliminate the uncertainty of plug placement. A recommended job sequence for a typical cement plug placement is presented. Supportive data in the/arm of case histories from Western Canadian wells are reviewed.

Introduction

There are many reasons why an operator may decide to set a cement plug in his well. Regardless of the reason, he wants a plug that will satisfy the required conditions on the first attempt. Unfortunately, this is not always obtained.

Many people consider the setting of a cement plug to be one of the simplest operations performed on a well. This attitude is easy to acquire if the only cement plugs previously placed were those for abandonment purposes. Often abandonment plugs are recorded "as found" when they will support a few points on the weight indicator.

The stresses placed on a cement plug for sidetracking or testing, however, are much more demanding. Cement that is diluted and contaminated with drilling fluids will not gain sufficient strength to support DST tools or a whipstock, or prevent the bit from re-entering the original hole. Setting an open? hole cement plug for sidetracking or testing requires planning and precise execution or it can develop into an expensive, timeconsuming operation.

This paper will review the main purposes for setting openhole cement plugs and the well conditions that are often present during the placement operation. The various techniques that are used to place cement plugs and the problems that are encountered are discussed. Field-proven techniques and equipment used to ensure competent cement plugs are presented in point form and discussed in detail. Finally case histories of plugging procedures and results on wells in Western Canada are given (Appendix).

Purposes of Wellbore Plugs

A cement plug is set in an open wellbore for one of at least four reasons. These are:to provide a solid bottom and plug while sidetracking the drilled hole, while bypassing unrecoverable junk or while straightening a crooked hole(l);to seal open hole below a casing seat or zone to be tested;to overcome a lost circulation problem;to abandon a dry or depleted well.

During a drilling operation, problems may develop which make it desirable to sidetrack the drilling. This can be due to loss of junk in the hole, such as tools or pipe, which cannot be recovered by fishing methods. Sidetracking may also be necessary to ensure that the drilling target is reached. Regardless of the reason for sidetracking, the cement plug in the original wellbore should be harder to drill than the formation around it. The cement must be given adequate time to allow it to gain sufficient compressive strength before the sidetracking operation begins.