Energy Resources Conservation Board Research Articles

Declaratory Relief under Alberta Oil and Gas Legislation

This paper discusses the applicable legislative and regulatory provisions in Alberta respecting applications for declarations of common purchaser, carrier and processor and orders for rateable take of natural gas, including the implementation of the objec tives ofsuch remedies through decisions of the Energy Resources Conservation Board. Reference is also made to the historical development of these remedies and comparable U.S. legislation (Texas, Oklahoma and Louisiana) in reaching conclusions and recom mendations.

Government Incentives to Exploration

Abstract Alberta's oil and gas resources extend over most of the province and constitute a major source of energy. The Exploratory Drilling Incentive System was designed to encourage high-risk exploratory drilling and increase the drilling activity in remote locations at a time when this type of drilling was declining in the province. The Exploratory Drilling Incentive System has progressed through several amendments and there has been a considerable increase in the number of exploratory wells drilled. The Alberta Government implemented the Geophysical Incentive Program to stimulate the level of seismic exploratory activity in Alberta. The Geophysical Incentive Program has progressed through several modifications since inception and there has been a considerable increase in the amount of seismic activity. The costs to the Alberta Government for credit, royalty exemptions, cash refunds and administration of the programs have increased considerably along with the increase in both types of exploratory activity. Introduction Alberta's oil and gas resources extend over most of the province and constitute a major source of energy (Fig. 1). To expedite the location of such resources, the Government of Alberta on July 28, 1972, approved the Natural Resource Revenue Plan. A main feature of this plan was an increase in annual revenues to the Government of about $70 million commencing in 1973. The Alberta Government felt this to be a fair and reasonable additional return to the citizens of Alberta for their ownership of a depleting and non-renewable resource. This dollar figure has increased since the initiation of the program due to the escalating price of crude oil. To offset this increase in revenues from industry and to stimulate increased exploratory activity in Alberta, the Government implemented the Exploratory Drilling Incentive System. The program has undergone several modifications since it was introduced, but essentially consists of a monetary credit for an exploratory well drilled for oil or gas. The credit may be applied against taxes payable under the Freehold Mineral Taxation Act, royalties, rentals, fees and bonuses on petroleum and natural gas Crown mineral rights. A producing incentive exploratory well may also qualify for royalty or mineral taxation exemptions. The Exploratory Drilling Incentive System is administered jointly by the Alberta Department of Energy and Natural Resources and the Alberta Energy Resources Conservation Board. Determination of qualifying footage on completion or abandonment of the incentive exploratory well is made by the Board. Determination of the credit to be established is made by the Department. Due to the close relationship between geophysical and drilling activity, it was found desirable to provide incentives for geophysical exploration. It is considered vital to maintain a high level of geophysical work to ensure the continuity of the search for new oil or gas reserves. Therefore, the Alberta Government, in taking a second step toward maintaining the necessary level of petroleum activity in the province implemented on January 1, 1975, the Geophysical Incentive Program.

Compositional Simulation to Develop an Optimnum Gas Cycling Scheme At The Kaybob Beaverhill Lak C Pool, Alberta

Abstract This paper discusses the application of a compositional model to develop an optimum exploitation scheme for the C Pool gas condensate reservoir. Performance predictions of a straight blowdown and three cycling schemes involving different replacement ratios have been obtained. Considerable emphasis was placed on predicting the reservoir rock properties in a highly heterogeneous reservoir such as the Kaybob Beaverhill Lake C Pool, and on the phase-behaviour matching of data derived from laboratory studies. Also, a productivity loss factor which results from condensate accumulation in the vicinity of the wellbore was incorporated in the model. These special features were necessary to increase the reliability of model predictions while cycling. During the development of the compositional model, a good match of phase behaviour of the reservoir fluid was obtained and so ensured a reliable prediction of gas cycling. Predictions indicated that cycling was technically feasible and that recovery of an additional two million barrels of hydrocarbon liquids will occur when compared to a straight blowdown scheme. This simulation study formed the basis of an application filed with the Energy Resources Conservation Board of Alberta requesting approval to implement a gas cycling scheme in the Kaybob Beaverhill Lake C Pool. Introduction The Kaybob Beaverhill Lake C Pool, discovered in 1961, is approximately 180 miles northwest of Edmonton, Alberta (Map 1) It is a gas condensate or dew-point reservoir having a hydrocarbon liquid content of approximately 190 bbl/MMcf. The volumetric original raw gas-in-place is estimated at 82 Bcf. Exploitation of the pool is expected to commence early in 1979 through five wells located in Townships 63 and 64, Range 18 west of the Fifth Meridian. Originally, it was believed that this gas condensate reservoir was in communication with an oil reservoir toward the northwest of the Kaybob Beaverhill Lake area. However, reservoir fluid analyses from wells 12-24-63-18 and 10-4-64-18 as well as pressure surveys in wells 2-4, 10-4 and 4-10-64-18 led to the conclusion that [he East Kaybob Beaverhill Lake area consisted of a saturated volatile oil reservoir and a gas condensate reservoir which do not communicate(1). This was further confirmed with the drilling of 11-3-64-18 well, which encountered the early postulated permeability barrier. The well was then subsequently abandoned. Because production from this gas condensate reservoir under a straight blowdown could be detrimental to hydrocarbon liquids recovery due to retrograde liquid loss during depletion, gas cycling can be carried out to maintain the reservoir pressure and minimize retrograde loss by simultaneously changing the reservoir fluid composition. Data for the Model Study Reservoir Description & Fluid Properties The Kaybob Beaverhill Lake C Pool is part of the Swan Hills reef limestone development. The reservoir dips toward the south and west, as indicated by the structure contour map of the bottom of the pool (Map 2). Maximum net pay thickness, based on the reef section encountered in the 12–24 well, is 195 feet (6875–7070 ft subsea). The hydrocarhon-porosity-foot.ge distribution is shown in Map 3.

A Computer File Of Oil Reservoir Fluid Property Data

Abstract This paper describes a recently developed computer file for the data in conventional oil reservoir fluid study reports. The data from 107 studies conducted on samples taken from Alberta oil reservoirs were selected from the public files maintained by Alberta's Energy Resources Conservation Board and were transcribed to this file. For each reservoir fluid study, data were grouped into several different types. A standardized computer record was designed for each type. Twenty different record types were used, each having a card image format to permit reading of the file from cards, tape or disc by the same FORTRAN programs. The data were edited to find any transcription errors and to evaluate the internal consistency of the reservoir fluid study measurements. These consistency tests found that several of the reports on the file contained data of questionable accuracy. Based on the limited use of the data file, several recommendations are made regarding the conduct and reporting of fluid studies. Various data on the files have been used in evaluating viscosity and phase-equilibrium correlating schemes. Introduction Volumetric and phase-behaviour data for petroleum reservoir fluids are used routinely by practicing petroleum engineers to estimate petroleum reserves, calculate reservoir withdrawals and conduct reservoir depletion studies. These data are also required to design improved oil and gas recovery schemes, wellbore flow systems, flow lines, separation and other fluid handling systems. The industry has in the past 'relied on the data obtained by laboratory measurements conducted on a sample of reservoir fluid. The laboratory tests are intended to simulate typical conditions of an oil reservoir, or the combination of a reservoir and surface facilities, as nearly as is practical. However, actual depletion mechanisms may be quite different from those used in the laboratory. For some time, researchers have been attempting to develop methods of performing vapour-liquid equilibrium calculations which are sufficiently accurate for reservoir fluid systems. However, only recently have the results been sufficiently accurate for complex naturally occurring mixtures at reservoir temperatures and pressures. There is now a need for comparative investigations of the accuracy of available techniques for the prediction of volumetric and phase-behaviour properties of reservoir fluids. The prerequisite for such studies is the development of a suitable data base for the testing of the various methods. This paper reports on the development of a computer file to serve as such a data base 6f reservoir fluid property data. The data for the file were taken from reservoir fluid studies conducted on fluid samples obtained from Alberta's oil and gas reservoirs. As a result of the requirements of Alberta's Oil and Gas Conservation Regulations, copies of many such studies have been forwarded to the Energy Resources Conservation Board (ERCB), where they are filed and, subject to the ERCB's rules for release of information, are made available to the public. The ERCB's Conventional PVT Analyses Index (1976) lists nearly 1000 laboratory reports of conventional reservoir fluid studies conducted on samples taken from crude oil pools in Alberta.

Improved Reservoir Description: Swan Hills Unit No.1

Abstract Oil production in the Swan Hills A & B Pools is taken from the Swan Hills Formation of the Beaverhill Lake Group of Devonian age. The reservoir rock is a carbonate formed ill a bioherm. The rock mass is rather complex, with at least seven major porous zones having been identified. Tile field was discovered in 1957 and steady oil production commenced ill January, 1959, after a pipeline became available. Swan Hills Unit No.1 was formed ill January, 1963. About 80% of the pool's oil in place and about 40% the developed area are contained within the unit limits. Water injection commenced in August. 1963. The reservoir description used in the early engineering studies was rather simple and bore scant resemblance to the complex reservoir geology. As the water-flooding operation has become more mature, it has been necessary to use increasingly more complex geologic models in order to reconcile reservoir performance prediction with observed reservoir performance data. Introduction The Swan Hills Field was discovered in the spring of 1957 by Home Regent Swan Hills 08-l1-068-10 W5M, which encountered 12 feet of pay in a gross interval of 124 feet in a limy carbonate section in the lower portion of the Beaverhill Lake Group. In the fall of 1957, a confirmation well, Home Regent Edith Lake 11-19-067-10 W5M, drilled 6 miles to the southwest, encountered 141 feet net pay in a gross interval of 312 feet in the same zone. This pay interval is now known as the Swan Hills Formation of the Beaverhill Lake Group of Devonian age. For administration purposes, the Alberta Energy Resources Conservation Board (ERCB) defines the producing formation as the Swan Hills Beaverhill Lake A & B Pools. The A & B Pools designation dates back to the carly history of the field development, when it was demonstrated that the lowermost porous interval (Coral Zone) was a separate hydrocarbon accumulation the "B" Pool. The remainder of the vertical sequence of oil productive intervals was defined as the "A" Pool. This pool separation move was carried out in an attempt to gain an allowable advantage. The advantage disappeared with prorationing rule changes and the ERCB subsequently approved commingling production from the two pools; however, the A & B definitions still persist. (Sec Figure 1 for position of Coral Zone.) Steady oil production commenced in January, 1959 after a pipeline was laid to Edmonton, a distance of 125 miles to the southeast. Commencement of steady production caused reservoir pressure to decline rapidly because of the undersaturated nature of the reservoir fluid. It became obvious that pressure maintenance would be needed in order to effectively recover the oil in place. The Swan Hills Unit No.1 was formed in January, 1963, and water injection commenced in August. 1963. About 80% of the pool's oil in place and 40% of the developed area are contained within the unit outlines. The reservoir description used in the early engineering studies was oversimplified and bore scant resemblance to the complex: reservoir geology.

OIL SPILL CONTROL IN ALBERTA

ABSTRACT Alberta is a major oil-producing region in North America. In excess of one-half billion barrels per year are produced from 10,000 oil wells. Oil and produced salt water are transported through 20,000 miles of pipelines. More than 600 oil and salt water spills per year occur, generally on land. The Energy Resources Conservation Board is responsible for the administration of the oil and gas industry. The board's policies and regulations relating to spill prevention, oil spill contingency planning, containment and cleanup are broad and flexible to permit industry a relatively high degree of freedom to operate in this area of rapidly-changing technology. While each company is held responsible for containment and cleanup of its own spills, the board supports the oil spill cooperative concept in spill equipment maintenance, contingency plan preparation and spill response training. Careful containment and cleanup of oil and salt spills will minimize soil and vegetation damage. This, followed by comprehensive evaluation of spill effects, enables implementation of more effective rehabilitation programs.

Enhanced Recovery In Alberta-A Review, And the Role of the Energy Resources Conservation Board

Abstract There are opportunities to encourage or assist enhanced recovery from the time of initial development until abandonment of an oil pool. The Energy Resources Conservation Board has developed a data base and, in consultation with industry, has evolved a system of regulations and procedures which plays a significant role in the development of optimum enhanced recovery operations. Among the effective incentives has been the proration plan whereby production is allocated largely in proportion to recoverable reserves. Some 11.5 of the 35.5 billion barrels of initial proved oil in place in Alberta is recoverable by methods currently being applied. About one-third of the proved initial recoverable reserves is the result of enhanced recovery operations, The remaining 240 billion barrels presents a substantial challenge. The Energy Resources Conservation Board, industry and the Alberta Government have initiated an extensive research program in Alberta with a view to increasing the portion of the in-place reserves which is recoverable. Economic incentives are equally important in increasing oil recovery and also are being reviewed. Introduction I am pleased to have the opportunity of presenting one of the keynote addresses at this important joint meeting of CSPG and PS of CIM stressing "Enhanced Recovery of Crude Oil." No aspect of the petroleum industry, in my opinion, is more urgent or more important than increasing the recovery of our known crude oil resources. The very creation and the continued existence of the Energy Resources Conservation Board is because of the broad concerns of the public, the government and the petroleum industry for conservation and the prevention of waste, The best of good conservation calls for the use of enhanced recovery techniques. Whether introduced early in the production life of a reservoir, or later as "secondary recovery", or even later as "tertiary recovery", or whatever the name, the matter of importance is that such techniques can increase the proportion of the in-place resource which is recovered and available for use. With a depleting and non-renewable resource such as crude oil, the highest practically attainable recoveries are of special importance. The new public and world-wide awareness of conservation is directed mostly at efficient use and prevention of waste at the stage of ultimate consumption. This is of obvious importance. Those of us who are associated with crude oil production, however, may take some pride in the knowledge that conservation has been a keyword in our vocabularies, with respect to production operations, at least since the early 1940's. In reviewing enhanced recovery in Alberta and commenting on the role of the Energy Resources Conservation Board, I thought it might be appropriate to deal briefly with the following:reservoir and production data;regulation of pool development and production operations;the growth and level of enhanced recovery operations in Alberta. From this background, I would like to comment on the opportunities and challenges today and for the future and the importance of expanding our effect on application-directed research.

Current And Required Economics In Relation to Further Alberta Enhanced Recovery of Conventional Crude

Abstract The status of Alberta crude oil reserves is reviewed briefly in respect to currently established recovery factors and the technical potential for additional recovery enhancement. A hypothetical pool is evaluated, with consideration given to the economics of pressure maintaining the pool by water flood, solvent flood and micellar solution flood. In each case, the technology is assumed to be proven and the recovery factor for each mechanism is established at a level generally believed applicable for a flood of that genre. Projected proration factors are applied to determine the comparative allowable that would result from depletion of the example pool by each of the cited depletion mechanisms. These are then extended into future cash flows and discounted rates of return, using the appropriate capitol cost, operating costs, royalties and taxes associated with each scheme. The schemes are then analyzed on an incremental basis to determine comparative economic potential related to the ultimate recovery of each scheme. The technical practicality of "exotic" depletion schemes is considered in terms of the need to proceed with theexotic scheme early in the producing life of the pool. Economic calculations for the hypothetical pool show that exotic schemes frequently cannot compete economically with waterflood operations. Therefore, under current economic conditions, exotic recovery is normally not feasible and, where it is feasible, would proceed only after the water-flood reserves of the pool have been totally, or almost totally, recovered. This deferment could seriously reduce the incremental tertiary economics to the point of making tertiary recovery entirely impractical. Consideration is given to methods of improving the economic attractiveness of enhanced recovery schemes throughroyalty and tax relief. A simplified cost-benefit analysis of the impact of such relief is presented. Introduction THE ENERGY RESOURCES CONSERVATION BOARD (ERCB) estimated that the year-end 1975 initial recoverable conventional reserves of the Province of Alberta amounted to some 11.5 billion barrels, This represents a recovery factor of 32.5 per cent of 35.4 billion barrels initially in place. The ERCB estimates that without the subsisting enhanced recovery projects, which are mostly water flood and solvent flood, the primary depletion recovery would be some 21.4 per cent. Thus subsisting enhanced recovery projects in Alberta have increased recoverable reserves by 50 per cent. Nonetheless, about 65 per cent of the oil in place discovered to date will not be recovered under current operations. The National Energy Board, in its 1975(1) report Oil Canadian Oil Supply and Requirements, estimated that by 1985 Canadian demand for indigenous feed stocks would exceed available supply by about 500,000 barrels per day. Under such circumstances, it is incumbent upon industry and government to ensure that the recovery of oil from established reserves is optimized. Alberta currently accounts for over 85 per cent of Canada's 6.65 billion barrels of proven remaining crude oil reserves and about 85 percent of its oil producibility. Enhanced recovery can and must play a vital role in meeting Canada's future supply problems. In order to do so, technical research and its application must proceed expeditiously and the economic environment must be favourable.

Performance of a Miscible Flood in the Bear Lake Cardium Unit, Pembina Field, Alberta, Canada

Field data and interpretation of project performance are given on a rich gas-drive miscible flood project that has been in progress for more than 5 years. Production has been good, but early solvent breakthrough occurred at two wells. In developing explanations for the breakthrough, computer models were used to analyze field data and the displacement mechanism. Introduction In Feb. 1968, a secondary recovery project was begun in the Pembina Bear Lake Cardium Unit 1 in Alberta, Canada. The major part of the secondary scheme was a rich gas-drive miscible flood conducted in the central region of the unit. The miscible process was used because of its potential for recovering oil unrecoverable by conventional waterflooding. This potential results from displacement efficiencies approaching 100 percent in the region of the reservoir swept by the solvent. Presented here is a general description of the reservoir, followed by a discussion of the miscible project scheme. The performance of the project is reported and analyzed. Information derived from reservoir simulation studies is also presented. The paper is a summary of several engineering studies and progress reports that are on file as public documents with the Energy Resources Conservation public documents with the Energy Resources Conservation Board of Alberta. These documents contain detailed reservoir data not reported in this paper. General Description of the Reservoir Reservoir Location and Layout The Pembina Bear Lake Cardium Unit 1 is located in the northwest portion of the Pembina field in Alberta, Canada, as shown in Fig. 1. The unit boundary and well locations are indicated in Fig. 2. Originally, the wells were developed on 160-acre spacing, but in the last 2 years some infill wells have been added. Currently, there are 29 wells in the unit; three are used as injectors, 25 are producers, and one well has been shut in. producers, and one well has been shut in. Formation Description The Cardium oil reservoir occurs at an average depth of 4,857 ft (-2,054 ft subsea). The oil accumulation is found in a sand bar development about 1 1/2 miles wide and 6 miles long. The Cretaceous sand was deposited under a deltaic condition and then was deeply eroded over most of the unit area. A highly permeable conglomerate-type chert was deposited over the eroded area. Fig. 3 is a cross-section of the reservoir showing the geometry of the sand and conglomerate layers. Maximum thickness of the conglomerate along the major axis of the bar is 41 ft. The underlying sand varies in thickness from 0 to 35 ft. The conglomerate layer is thickest in the northwest, and thins down and disappears in the southeast. It is important to note the vertical scale exaggeration on Fig. 3. The reservoir is actually extremely thin compared with its areal extent. Fig. 4 shows the depth to the top of the pay zone. The crest of the structure follows close to the major axis and dips downward from southeast to northwest. The amount of relief is small compared with the areal extent. Typical or average characteristics for the formation are included in Table 1. In the conglomerate layer, the average horizontal permeability is about 700 md. Permeability in the sand averages only about 20 md. The Permeability in the sand averages only about 20 md. The porosity is about 11 percent in both the conglomerate and porosity is about 11 percent in both the conglomerate and the sand. Permeability data taken from tests on core samples indicate that horizontal permeability of the conglomerate is generally 10 to 20 times greater than the vertical permeability. Geological analysis of core samples indicates that this difference results from the presence of essentially horizontal lithologic zones (beds) of relatively low permeability. In most cases, these zones consist of permeability. In most cases, these zones consist of conglomerate containing abundant sandstone matrix. JPT P. 672

Belly River Waterfloods Conception to Success

Abstract The oil-bearing Belly River pools of the Pembina area of Alberta were discovered in the search for Cardium oil and developed under skepticism by many operator. The indicated high connate water saturation, the presence of swelling clays within the formation and the lack of readily available source water provided poor waterflood potential. After producing the pools for 10 years under a primary solution gas drive mechanism, the operators initiated three water-flood projects. As a result of the outstanding performance of these projects, two reservoir simulation studies were prepared to determine the optimum waterflood scheme. These studies recommended the extension of the waterflood to the majority of the Belly River reservoirs in the area and justified an extensive infill drilling program. An analysis of the Belly River flood performance is presented and the simulation studies are reviewed. The proposed infill drilling and surface facility expansion programs are also illustrated. Introduction THE BASAL BELLY RIVER SANDSTONE is found in the central plains and south-central mountains and foothills of Alberta. Although the sand occurs commonly in these areas and is often hydrocarbon-bearing, it is generally considered as a secondary objective. The Alberta Energy Resources Conservation Board currently estimates a total of 526 million barrels of oil in place in recognized Belly River pools. Ninety per cent of this recognized Belly River oil is located in the Keystone and Buck Creek areas of the Pembina Field, which were developed in the early sixties (Fig. 1 and 2). The Belly River sand has a high connate water saturation and is infilled with kaolinitic clays. For these reasons, a cautious approach to waterflooding the Belly River reservoirs was taken and it was not until 1970 that waterflood projects were initiated in the Pembina Keystone Belly River "B", "M" and "U" pools. Within two years of the start of injection, excellent GOR and production response was observed. In some cases, the production rate had a three to four-fold increase. Consequently, the Pembina Belly River "B" North Unit ' waterflood project was restudied with a numerical simulation model to investigate infill drilling, as was the Pembina Belly River "C" Pool, which was still on primary depletion. Both studies indicated that infill drilling was extremely attractive. Accordingly, an estimated 100 infill wells will be drilled in the Keystone Belly River pools and waterflood projects will be extended to the remaining major Belly River pools in the area. Reservoir Description GEOLOGY The Upper Cretaceous Basal Belly River Sandstone is contained in a progradational sequence between the Marine Lea Park Shale and the overlying continental strata. The reservoir rock is a light grey, fairly well sorted fine to medium-grained sandstone with high clay content and interbedded calcareous sands and dark grey silty shales(1,2). The sand was deposited as offshore bars and infilled channels. Bar and channel sands of different depositional ages are discernible in the Pembina Keystone area, with communication apparent between bars and channels of common age.

Energy Resources For Future Electric Power Generation In Alberta, 1972-2001

Abstract Alberta's requirements for electrical energy a.re expected to increase almost ten-fold over the next 90 years. The Province has substantial reserves of gas, coal, conventional and synthetic oil as well as a number of potential hydro sites which could be utilized to meet future requirements for electrical energy. This paper examines a number of alternate allocations of resources to electrical generation in the over-all Alberta public interest. The analysis concentrates primarily on the utilization of coal or gas as a fuel source for thermal generation and examines the resultin impact on the Province's coal, natural gas and pipe-line industries as 'well as the costs to consumer of electricity. Introduction DURING THE PERIOD from September 19 to September 28, 1972, the Energy Resources Conservation Board (ERCB) held public hearings on Alberta's present and future requirements of energy and energy resources. A major issue was the extent to which future requirements of electric energy would or should be met from coal or from gas. This question is of considerable importance in the effective conservation and use of Alberta's energy resources and the public interest generally, and the Board's consideration of this matter resulted in the publishing of a report on the "Choices Among Energy Resources for the Generation of Electric Energy in Alberta".(1) The report contains a recommendation to the Lieutenant Governor in Council that the Government make certain broad policy decisions relating specifically to the choices among energy resources for future electric energy generation in Alberta. This paper is a summary of the fun report, with a few minor changes to reflect the most recent ERCB forecast of Alberta electric energy requirements. During the early part of the century electric energy was generated in Alberta by small hydro plants or small coal-fired thermal plants, each located near the load it served and with no electrical connection to other generating plants. Between the ends of the first and second world wars, a hydro energy storage and generation system was developed by Calgary Power Ltd. on the Bowe River. Transmission lines were built to interconnect the Bow Hydro system and the coalfired thermal plants at Edmonton, Calgary, Drumheller and in the Crowsnest Pass. The Lethbridge and Medicine Hat areas were served by gas-fired thermal plants and many towns had small local plants with internal combustion engine generating units. Since 1945, industrial expansion in Alberta, particularly the oil and gas industry, farm electrification, high-intensity lighting in urban centers and the proliferation of electric appliances, has caused a rapid increase in the demand for electric energy and has made the electrical interconnection of most load areas of the Province both desirable and economically feasible. It has now become advantageous to generate the base load energy with a few large thermal units running at nearly full load and maximum efficiency. The trend is to an interconnected generating system in which base load energy is generated from the most advantageous fuels and intermediate generation from units with the most advantageous operating characteristics and capital costs.

A Three-Dimensional Model For Predicting Natural Gas Reserves And Availability

Abstract A model is presented which analyzes the discovery and subsequent appreciation of natural gas in Alberta using data compiled by the Alberta Oil and Gas (now Energy Resources) Conservation Board. This model is then used for the prediction of new discoveries and subsequent appreciation of existing discoveries. This means that the volumes of gas discovered are analyzed and predicted both as a function of discovery year and year since discovery. Introduction PREVIOUS ATTEMPTS at statistically estimating natural gas reserves have dealt with the problem as a process which analyzed and subsequently predicted reserves as a cumulative quantity. No attempt was made at separating the appreciation of present reserves and the prediction of new reserves. Noteworthy of the studies that have been performed are two approaches. The first approach, presented by Hubbert(1) and Moore(2), uses cumulative gas reserves tabulated by calendar year and involves the fitting and extrapolation of S-shaped curves of either logistic or Gompertz form, respectively, with the latter curve giving a slightly better fit to the data presented here. The second approach, presented by the Alberta Oil and Gas Conservation Board(3,4) uses cumulative gas reserves tabulated by years since discovery and analyzes the growth pattern of the appreciation of existing gas reserves. This method does not predict an ultimate initial established marketable gas reserves, but does provide a very good fit on a cumulative basis of the appreciation of existing reserves. This paper is aimed at statistically analyzing the way estimates of natural gas reserves grow. The model used for the analysis is referred to as a three-dimensional model because it is a function of three factors - the calendar year, the year since discovery and the amount of reserves known at these times. Alberta Oil and Gas Conservation Report data(3) used in this study are shown in Table 1. The Table shows) by year since discovery and by calendar year, the recognized reserves of some 400 natural gas pools discovered subsequent to 1950 which have initial reserves greater than 10 billion cubic feet. In total, it is estimated that these pools represent 72 per cent of the total reserves that have been recognized as being discovered prior to December 30, I970. GENERAL STRUCTURE OF THE MODEL Appreciation of Existing Reserves Once given the amount of gas discovery in any one particular year (t), the appreciation of this gas is a very regular process which slows down exponentially with time and hence the cumulative growth has the form of a limited exponential of the following form. (Equation Available In Full Paper) Applying this model to the data presented in Table 1 for the years of discovery 1951 to 1960, the following results were obtained by non-linear least-squares techniques. (Equation Available In Full Paper) As can be seen from the above results, each individual model as well as the cumulative model provides a good description of the data.

Oil Reserves In Alberta

Abstract Introduction IT IS OF CONSIDERABLE INTEREST TO KNOW the total amount of conventional crude oil which can be recovered in Alberta. The Energy Resources Conservation Board has estimatedl J1 this quantity at 20 billion barrels; it also estimated the annual increase of proved reserves at 450 million barrels. These estimates were obtained by considering the curve of proved reserves of the province over the past 25 years and extrapolating linearly. This is similar to the methods applied to the crude oil reserves of the U.S. by Hubbert(1) and Moore (see Lovejoy and Homan(2)) though the curves fitted by Hubbert and Moore were somewhat more complicated. Such curve-fittings have their disadvantages. There may be many reasons why a trend which has been present for many years suddenly changes. It is much better to formulate a relationship between the reserves and some other variables which explains the development of these reserves, To estimate such a relationship and to use it for projections is the main purpose of this article. The increase of the initial recoverable proved reserves (that is all oil known to be recoverable plus all oil produced so far) in any year consists of reserves (that is all oil known to be recoverable plus exploratory wells and additions to and revisions of reserves of oil pools found previously; these additions and revisions are called the appreciation of reserves. Let us indicate the total proved reserves of the province in year t by Pt and proved reserves in year t of an oil pool discovered in year τ by P (τ) it is obvious that P (τ)t = 0 for t < τ. We have then (Equation Available In Full Paper) P(t), are the proved reserves of pools discovered in year t and P(t0)?.P(t-1), are the proved reserves of pools discovered in previous years to, ..., t-l, where to is the year in which the first reserves were discovered. The appreciation of oil reserves over the years is quite erratic. Nevertheless, it is possible to estimatethe average appreciation of reserves as a function of the years since discovery. The Energy Resources Conservation Board has used(3) the formula (Equation Available In Full Paper) where r(t) is the average multiple of the proved reserve in the year of discovery after t years, and a and b are estimated from curve 1 in Figure 1, which gives the averages resulting from the data available. Curve 2 gives the curve fitted in to curve 1, taking into account some other information which* results in the values a = 8.495, b*= 4.4505 or b = 0.7988. Because the fit of curve 2 is not very good, the author of this article used a nonlinear least-squares procedure to fit (1,2) to curve 1, which resulted in a = 8.7711 and b = 0.88381.