The figures and table mentioned in this paper are not available in thispdf file. Abstract The performance of horizontal and vertical wells in 12 Canadian oil pools wasreviewed to determine the likely range of ultimate recovery for individualwells. These pools were dissimilar in terms of their lithology, drivemechanisms and oil density. Productivity Improvement Factors (PIF, the ratio of production of a horizontalwell to a vertical well for the first 12 months) and the key benefit(incremental oil recovery versus acceleration) of horizontal wells were alsoexamined. Overall, the horizontal wells declined rapidly within the first year to about40 percent of the peak rate and subsequently a flatter decline becameestablished. PIFs for the horizontal wells appear distributed in a log normalfashion, in spite of many variables affecting their performance. It also becameobvious that, in general, the best horizontal wells were drilled first in eachpool. These findings are expected to be of value in decisions on continuing orterminating a pool development program involving horizontal wells and inestimating reserves based on limited production information. Introduction The performance of twelve oil pools, which now have enough production to makereasonable estimates of ultimate recovery from both horizontal and verticalwells, has been reviewed in order to determine what likely range of ultimaterecoveries might be expected from horizontal wells in similar pools. Forecasting of production and ultimate recovery from vertical oil wells hasbeen undertaken for many years, and there are many thousands of wells fromwhich to make comparisons. This is not the case for horizontal wells, since thetechnology of drilling and producing these wells is more recent, and the database of wells with sufficient production for analysis much smaller. Because ofthe high initial production rates associated with many horizontal oil wells, itis easy to assume large oil reserves will be recovered. This paper is anattempt to determine a likely range of production profiles, and ultimatereserves for a number of oil pools from which a methodology can be developedfor future analysis of horizontal well performance. The methodology will be described in some detail as applied to the Tatagwa North Midale pool in Saskatchewan and overall results compared to those fromthe eleven other pools: Bellshill Lake Ellerslie A, Alberta Jenner Upper Mannville F, Alberta Morgan Sparky A, Rex A & Lloyd A, Alberta Senex Keg River, Alberta Suffield Upper Mannville J (Pool 1), Alberta Suffield Upper Mannville J (Pool 2), Alberta Swan Hills Beaver Hill Lake C, Alberta Birch Baldonell C, British Columbia Buick Creek Lower Halfway, British Columbia Innes Frobisher, Saskatchewan Kisbey Frobisher Alida, Saskatchewan TATAGWA NORTH MIDALE, SASKATCHEWAN GEOLOGY The production formation in the Tatagwa area is the Midale Beds. The formationis a dolomitic limestone in the Madison group of the Mississippian period. Oilproductivity is not necessarily determined by structure. Occasionally, highwater saturations are encountered at high structural positions, making itdifficult to assess optimal locations for horizontal wells.

Abstract It is a well established fact that finding rates of natural gas in western Canada have declined over the last thirty or so years. However, statistical analyses of the declining trends have, to date, failed to provide a generally acceptable estimate of the conventional natural gas resources of the Western Canada Sedimentary Basin. This paper provides an explanation of why decline analysis appears to provide a valid method for estimating the conventional crude oil resources of the basin while the same is not true for natural gas. The paper proposes solutions to the problems encountered in the natural gas data and provides an estimate of the conventional natural gas resources of the basin by statistical analyses of the declining finding rate trends. Introduction The Western Canada Sedimentary Basin (WCSB) occupies an area of 1.4 million square kilometres of southwestern Manitoba, southern Saskatchewan, Alberta, northeastern British Columbia and the south-west corner of the Northwest Territories (Figure 1). Petroleum resources of the basin range from natural gas at the light end of the spectrum through conventional crude oil to bitumen. Conventional natural gas is that portion of this spectrum which exists in solution in crude oil or in the gaseous state in reservoirs having a permeability greater than about 0.1 md. Unconventional natural gas resources are those contained in low permeability reservoirs (tight gas), those associated with coal deposits (coalbed methane) and those contained in shale deposits (shale gas). Costs of extraction and transportation and natural gas prices are important determinants in the assessment of recoverable natural gas resources. However, consideration of the economic aspects of natural gas recovery is avoided by assuming a high natural gas price, in the order of $3.00 per mcf, so that estimates of recoverable resources are not constrained by price considerations. The Canadian Gas Potential Committee (CGPC) in its recent inaugural report1, focused on conventional natural gas in the WCSB. However, an analysis such as that reported in this paper was not included. CATEGORIES OF RESOURCES Definitions for categories of resources are taken from the Petroleum Society Monograph Number 1, Determination of Oil and Gas Reserves 2 . The definitions of primary interest in this paper are as follows: Resources of conventional natural gas are the total quantities of gas that are estimated, at a particular time, to be contained in, or that have been produced from, known accumulations, plus those estimated quantities in accumulations yet to be discovered. Discovered resources of conventional natural gas, which also may be referred to as initial volumes in place, are those quantities of gas that are estimated, at a particular time, to be initially contained in known accumulations that have been penetrated by a wellbore. They comprise those quantities that are recoverable from known accumulations and those that will remain in known accumulations, based on known technology under specified conditions that are generallyaccepted as being a reasonable outlook for the future. Undiscovered resources, which may also be referred to as future initial volumes in place, are those in-place quantities of gas that are estimated, at a particular time, to exist inaccumulations yet to be discovered.

Abstract It is becoming more and more difficult to add new reserves to replace annual production from depleting oil and gas resources. Most of the "easy" oil and gas fields have been discovered and now we must look/or the more elusive accumulations, and also become more creative in devising improved or new production practices, Although advances in 3-D seismic, horizontal drilling, completion techniques and computer applications have improved our ability to find and produce new reserves, risks have, unfortunately, increased In addition to the technical risks, economic risks are also becoming more burdensome. Various groups have attempted to develop some form of standards to deal with this increasing uncertainty, but are encountering a great reluctance to change. The Petroleum Society of the CIM Standing Committee on Reserves Definitions has been actively trying to promote a revised reserve classification system to form a standard foundation for all reserves evaluations. The Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, The World Petroleum Congress and the Canadian Securities Commissions are all looking at upgrading their respective Reserve Definitions. Every factor used in the evaluation of oil and gas assets has varying degrees of uncertainty associated with it, and thus, evaluators must have some knowledge of statistical methods in dealing with the problem. There are many statistical techniques available to deal with the problem of uncertainty, such as Monte Carlo Simulation, Expected Value and Decision Tree Analyses. These can be sophisticated or simple, depending upon the data, the resources, and the need to derive statistical measurements. The purpose of this paper is to emphasize the need to incorporate and standardize the application of risk and to propose a revised Expected Value Concept for the economic evaluations of reserves and dispel the myths that statistical procedures are difficult, time consuming and expensive. INTRODUCTION In the evaluation of oil and gas properties, there is always uncertainty. There are two types of oil and gas assets which form the upstream values of oil and gas companies, reserves and exploratory lands. Reserves usually provide the most value in a company's portfolio, but exploratory lands have value and must also be included. The uncertainty associated with the latter is much greater than that associated with the evaluation of oil and gas reserves. Since "the value of any asset is a function of the ability of that asset to generate future income" (1) , the process of evaluating either reserves or exploratory lands should follow the same procedure. The first step in an evaluation is to estimate how much oil gas and by-products can be produced from an entity. In the evaluation of an exploratory land, where reserves have not been discovered, several reserve estimates may have to be evaluated; whereas, in the evaluation of reserves, the amount f hydrocarbons to be recovered may be fairly well established. The second step is to prepare a "discounted cash flow" analysis for the reserves that are estimated to be recovered. The final step in the evaluation is to incorporate the probabilities of occurrence of the cases considered. The risk-weighted result is an evaluator's best estimate of the reserves to be recovered and their respective values. These best estimates are the "Expected" values.

Abstract In many oil and gas companies, capital allocation decisions typically involve the ranking of proposed projects by net present value and/or internal rates of return along with some subjective criteria. However, traditional present value or discounted cash flow (DCF) analysis methods used in petroleum economics do not properly account for risks associated with commodity price volatility and how they affect the particular project under analysis. Commodity price sensitivity can differ widely from project to project, due to the inherent cost structure, extent of product price hedging, tax and royalty structures, etc. These are issues which directly affect the risk of project cash flows and are difficult to address with the use of constant discount rates for all analyses. This presentation will outline a methodology based on techniques which are used in securities markets to evaluate some simple resource development example projects. The results will show that a constant discount rate analysis can potentially provide a misleading bias n project selection. In particular, we show how, under circumstances where costs are less risky than revenue, discounted cash-flow (DCF) methods, that use the same discount rate in the valuation of all projects, undervalue low cost natural gas relative to high cost natural gas, may undervalue long life natural gas relative to short life natural gas; and how DCF methods tend to undervalue (or not value) the advantages of risk absorbing activities such as price risk management or hedging. INTRODUCTION Consulting experiences suggest that many managers in the petroleum industry would like better financial analysis methods to assist in the management of their business opportunities. Some believe that discounted cash-flow (DCF) methods, at least as they are currently used, tend to hamper long term or strategic decision making by discounting the future excessively or arbitrarily and by undervaluing the effects of the active management of future contingencies. Moreover, many organizations do not understand (for good reasons) the issues behind their choice of discount rates, which is crucial to the use of DCF methods. Finally, current DCF methods lead managers to consider risk in ad hoc ways through some combination of their choice of a discount rate and their opinion of the spread in valuation results across "sensitivity" scenarios. Some managers would like an integrated approach to risk and its effects on value. There has been speculation that modem asset pricing (MAP) methods (sometimes called "option pricing" methods or "synthetic valuation" methods) can provide organizations with better tools for financial analysis. Some managers believe (quite rightly) that the use of these methods may allow more precise comparative analyses of the effects of: time; uncertainty; project structure; and the potential for active management on the value of the decision alternatives that they face. Indeed, modem asset pricing can provide petroleum producers with better tools for financial analysis by making possible more precise comparative analyses of the effects of time, uncertainty, project structure, and the potential for active management on the value of the decision alternatives that managers face.

Abstract The pressures used in constructing the traditional material balance (p/z) plotmust be fully built-up reservoir pressures, usually obtained by shutting-in thewell The procedure described in this presentation does NOT require the well tobe shut-in. Instead, it utilizes information obtained from standard goodoperating practices (production and flowing pressure) to quantify thegas-in-place, without having to shut-in the well. The classical pseudo-steady state analysis and its shortcomings are discussed.In addition, a new procedure known as the "flowing" Material Balance isintroduced. This procedure consists of p/z plot of the "flowing" pressure (asopposed to the "shut-in average" reservoir ressure) versus cumulativeproduction. A straight line can be drawn through the data and then, a parallelline, drawn through the initial reservoir pressure, gives the initialgas-in-place, ariations of this method, using wellhead pressures (tubing andcasing) re discussed, along with field examples. The method is a very PRACTICALand powerful tool for the early quantification of reserves. Introduction The determination of gas reserves is a fundamental calculation in reservoirengineering. This information is of critical importance in determiningproduction strategy, design of facilities, contracts and the value of thereserves. Reserves can be estimated in three ways - Volumetric, Production Decline and Material Balance. The Production Decline gives an estimate ofrecoverable gas, whereas the ther two give an estimate of gas-in-place, In thereservoir engineering literature, the word "reserve refers" to the rawgas-in-place whereas in the commercial world, the word "reserve" often meansthe recoverable sales gas. In this paper, the word "reserve" is used to denotethe raw gas-in-place. Volumetrically determined reserves can be very imprecise, because they dependon the areal extent of the pool, which is often unknown Production Declinemethods give the "recoverable" gas volumes under the existing operatingconditions. A change in these operations, for example a lowering of thecompressor suction pressure can change the magnitude of the recoverable gas.The original gas-in-place is difficult to ascertain. The Material Balancemethod (given well-behaved data) gives the most accurate estimate of originalgas-in-place. Once this value is known, it can be used to forecast therecoverable gas under various operating scenarios. Classical Material Balance The classical material balance expresses a relationship between the averagepressure in the reservoir and the amount of gas produced. When there has beenno production, the pressure equals the initial reservoir pressure, when all thegas has been produced, the pressure in the reservoir is zero. This assumes thatthe reservoir acts like a tank and there is no external pressure maintenance.The relationship between pressure and cumulative production is approximatelylinear. If the compressibility factor z, is taken into account, then thematerial balance plot of p/z versus cumulative production, Q, is a straightline going from the initial pressure p/z to the initial gas-in-place, IGIP.Deviations from this straight line can be caused by external recharge or offsetdrainage. For the purposes of this resentation, we are only consideringreservoirs which have straight line material balance plot of p/z versus Q.

Abstract After solvent breakthrough, vertical miscible floods are characterized by rapid increases in producing gas-oil ratios which in turn are accompanied by rapid declines in oil production. Al this advanced stage of depletion, the vertical floods have a low reserve life index and hence, major investments cannot be justified to attend the producing life of these floods. Imperial Oil Resources Ltd. in its search for new low cost techniques to increase reserves while maintaining increasing oil production began to examine concept of oil re-injection in its Pembina Nisku reservoirs. Exploratory laboratory tests and numerical simulation work demonstrated that a dual completion to re-inject part of the produced oil back into the formation, a few meters above the producing perforations could lead to incremental recoveries of two to three percent of the original-oil-in-place (OOIP). A field test to evaluate the benefits of the oil re-injection process is presently being conducted in the Pembina Nisku "Q" pool Initial results indicate that oil re-injection is successful in controlling solvent production while maintaining oil rates. As a consequence, additional piloting to expand the applicability of the oil, re-injection process is being planned for other Nisku and Imperial Oil Resources Ltd. reservoirs. Introduction The Pembina Nisku area is located approximately 120 km west of th city of Edmonton, Alberta. Canada (Figure 1). The Pembina Nisku discoveries were me result of a seismic exploration play initiated by Chevron in me mid 1970's 1 . Imperial Oil Resources Ltd. operates seven vertical miscible floods in this area. These pools are relatively small in areal extent (130 ha - 325 hal) with OOIP ranging from a low of 1700 km 3 10 a high of 5000 km 3 . Vertical miscible floods were initiated in these pools in th 1982 to 1987 time frame. Figures 2 and 3 show me oil production and GOR performance of the Imperial Oil operated miscible floods. Oil production from these pools peaked in 1987 at approximately 5100 m 3 /day. The gas-oil ratio's (GOR) remained at the base level of 150 m 3 /m 3 through 1987 but then, as a result of solvent breakthrough, started increasing rapidly 10 the present level of 280 m 3 /m 3 . As is the case with all vertical miscible floods, the increase in the GOR was accompanied by a rapid decline in the oil production rates. The pools presently produce approximately 1900 m 3 /day and this represents a decline of mare than sixty percent from their peak rates. The Nisku pools have now recovered approximately 88 percent of their reserves with individual pool recoveries approaching 70 percent of the OOIP. The low remaining reserves combined with high individual pool recoveries make it difficult to justify major capital investments to extend the producing life of these pools. In the past, various techniques to reduce coning (gas and water) have been proposed and tested. The conventional options have ranged from relocating perforations, managing production rates and periodically shutting in wells to allow the cone to heal. The non-conventional methods included wellbore modifications such as applying gravel packs and the placement of barriers created by the injection of diverting and blocking agents.

Abstract Material balance methods of determining reservoir parameters such as the original oil in place are sensitive to uncertainties in the input data. Traditionally, regression techniques have been used to determine the "best-fit" values of the reservoir parameters and these have been used as a good representation of the "true" values. The effect of errors in the reservoir pressure measurements on the Havlena-Odeh 4 method are examined using a gas cap drive reservoir as an example. The errors in the measured pressures are estimated from the available data. These errors are propagated through the calculations and show that the resulting error bars vary with the size of the relative pressure drop. Weighted linear regression is used to determine both the best fit values and the standard deviation, which serves as a measure of the statistical confidence limits. An alternative approach using the material balance method is to calculate the expected pressures from a model and vary the parameters of the model until the pressures match the observed pressures. Minimization of a suitable objective function by non-linear regression provides the best estimates of the reservoir parameters and the confidence limit contours can be derived. These are then used to draw correct inferences from the results - in the example, the possible communication between two oil pools is investigated. The 95% confidence limits are found to cover a wide range in the OOIP and gas cap fraction, thus the "best fit" has limited usefulness. The confidence limits can be used to compare the results of volumetric calculations and to restrict the range of variables used in subsequent reservoir studies.- e.g., numerical simulation. The methods outlined in this paper are general and are not limited to two parameters thus they can be used for any material balance problem. Introduction Material balance is one of the fundamental tools of reservoir engineering.In essence, measurements of the pressure changes in a reservoir as fluids are withdrawn are used to derive the reservoir parameters such as OOIP, gas cap fraction and the water influx characteristics. The significant effect of errors in the data on the derived parameters, such as the OOIP, gas cap fraction and aquifer characteristics was recognized early in the development of the subject, and the equation has been examined by numerous authors 1,5 . Random errors are present in all the input parameters: the average reservoir pressure at any time, the total withdrawals from the reservoir and the PVT properties of the reservoir fluids. Usually, errors in reservoir pressure are the most significant, and only these will be addressed in this paper. Systematic errors (as opposed to random) are also present. These arise from numerous sources e.g., the PVT data not representing the reservoir fluids accurately, a single pressure not representing the reservoir (due to lack of continuity). These will not be discussed in this work, although corrections applied for reservoir pressures in the field example are an example of reducing a set of systematic errors arising from insufficient shut-in time. In this paper a general method for assessing the uncertainties is described.

Abstract There are currently almost as many definitions for reserves as there are evaluators, oil and gas companies, financial agencies, securities commissions, and government departments. Each one uses its own version of the definitions for its own purposes. But today, with the unstable economic conditions in the oil and gas industry, the lower quality of reservoirs that are being discovered, and the new recovery methods that are being developed, estimating the reserves is becoming more unpredictable. These factors have made it imperative to develop a universal set of definitions for reserves that will meet the needs of all users. Also important is the need for guidelines so that all evaluators and users will understand the process of calculating and subsequently classifying reserves of oil and gas and related substances. The task of writing the reserves definitions was undertaken by the Petroleum Society's Standing Committee on Reserves Definitions. This document comprises the committee's 1993 report. The definitions developed by this committee are similar to those currently in use, particularly in North America. They have been reviewed by users in the oil and gas industry, and representatives from regulatory agencies, government departments, industry associations, and technical and professional organizations. This document presents the definitions of oil and gas resources and reserves and a recommended reserves classification system. The definitions are given in Sections 2.2 to 2.5 of Chapter 2. Guidelines to illustrate the application of the definitions are presented in Chapter 3. At the end of the document is a glossary of related terms that have been prepared in conjunction with the definitions. The Standing Committee believes the recommended definitions and guidelines are suitable for use with respect to all types of oil and gas and related substances, including offshore situations and oil sands. Although those segments of the industry have used somewhat different terms and definitions, the principles reflected in the recommended definitions are applicable. The fundamental principle is that those quantities that are known to exist and to be economically recoverable are reserves. The total quantities, whether or not they have been discovered, are resources. Reserves and resources are further categorized depending on the level of certainty that they will be recovered. It is the view of the Standing Committee that current reserves estimation methods and categories, in general, match the recommended definitions and guidelines. The committee, therefore, does not expect that major changes to reserves estimates would result from adoption of the definitions, although it recognizes that for some specific reserves estimates (generally for small pools) changes could be significant. The committee hopes that, over time, reserves evaluators will increasingly conform to the recommendations and thus contribute to the overall quality and consistency of reserves estimates. This document has been prepared by the Standing Committee on Reserves Definitions and sponsored by the Petroleum Society of the Canadian Institute of Mining, Metallurgy and Petroleum. The committee is composed of representatives of oil and gas companies, geological and petroleum engineering consulting firms, Canadian industry associations, financial and accounting organizations, regulatory agencies, and government.

Abstract Material balance analysis of production performance data for an abnormally-pressured gas reservoir is complicated because of water and rock compressibility effects in addition to gas compressibility effects. Usually, a p/z vs. G p graph for an abnormally pressured gas reservoir yields a significantly overestimated value of the initial gas-in-place. Several researchers have presented material balance analysis methods to obtain reasonably accurate estimates of the initial gas-in-place for abnormally-pressured gas reservoirs. These methods can be broadly grouped into two sets. The first set of methods requires a knowledge of compressibilities and analyzes production performance data to estimate the initial gas-in-place. The second set of methods attempts to obtain both an effective system compressibility and the initial gas-in-place by analyzing production performance data. This study presents an evaluation of several material balance analysis methods for volumetric, abnormally pressured gas reservoirs. The interrelationship between the initial gas-in-place estimates from the two methods by Hammerlindl (1) has been derived theoretically. Non-uniqueness problem in analyzing production performance data of abnormally-pressured gas reservoirs is emphasized. An example problem demonstrates that a small error in the initial reservoir pressure can account for a typical flat portion corresponding to the early production data on the Roach (2) plot. The preceding observation suggests that a hypothesis of changing formation compressibility with pressure as advanced by Poston and Chen (3) is not necessary to explain the shape of the Roach (2) plot. This paper should enhance an analyst's capabilities to perform meaningful material balance analysis of production performance data from an abnormally-pressured gas reservoir. Introduction Material balance analysis of production performance data for an abnormally-pressured gas reservoir should include water, rock, and gas compressibility effects. For a volumetric, abnormally-pressured gas reservoir, a p/z vs. G p graph shows two straight lines of distinctly differenl slopes. An extrapolation based on an early straight line on a p/z vs. G p graph for an abnormally pressured gas reservoir yields a significantly overestimated value of the initial gas-in-place. This paper discusses and evaluates several material balance analysis methods proposed for volumetric, abnormally- pressured gas reservoirs to obtain reasonably accurate estimates of the initial gas-in-place. Material Balance Analysis Methods All material balance analysis methods proposed for volumetric, abnormally-pressured gas reservoirs are based on a material balance equation of the following general form: Equation (Available In Full Paper) Different authors have used different expressions for effective system compressibility (C e ) depending on the drive mechanisms Incorporated In their analyses. The following discusses the two sets of methods proposed for analyzing production performance data for abnormally-pressured gas reservoirs. Methods Based on a Knowledge of System Compressibility Hammerlindl (1) presented two melhods to correct apparent gas-in-place (G app ) obtained from an extrapolation of early straight line on a p/z vs. Gp graph for an abnormally-pressured gas reservoir. Using two pressures, P i and P 2 , actual gas-in-place (G act ) is computed according to Hammerlindl's (1) method I as: <Equation Available In Full Paper>

Abstract A unified treatment of materials balance computations to estimate hydrocarbons in place is presented. This method generalizes the normal procedures for gas reservoirs to all fluids of interest to the petroleum industry. We show that a plot of average pressure divided by a two-phase deviation factor can be used to compute hydrocarbons in-place. A simple procedure to estimate the required two-phase deviation factors for black oils and volatile oils is discussed. This extends the method of Vo et. al. for gas condensates to these other systems. We concluded, in particular, that data above the phase envelope (single phase information) can be extrapolated and combined with data inside the phase envelop (two-phase information) to obtain initial hydrocarbons in place. The need for accurate fluid property description is emphasized and potential information that is obtainable from accurate fluid descriptions is noted, It is shown that data above the phase envelope can be extrapolated to obtain initial hydrocarbons in place. Introduction Historically, materials balance computations for oil and gas reservoirs have been done differently, probably due to the fact that problems involved in considering the appearance of a second phase are not germane to the evaluation of dry gas reservoirs. The purpose of this paper is to present a unified method for the conduct of materials balance studies for the entire range of fluids of interest (black oils, volatile oils, gas condensates and dry gases) to petroleum production engineers. This objective is attained by computing two-phase compressibility factors from composition data. The principal advantage of our method is that extrapolations to estimate initial hydrocarbons in place can be done with data measured entirely above the phase envelope. Furthermore, our procedure avoids problems associated with properly accounting for mass transfer as fluids separate in the wellbore and in surface equipment. Theoretical considerations are also addressed, in that, errors involved in computations are discussed. A field example for a volatile oil reservoir is presented to justify theoretical conclusions. Mathematical Model, Assumptions, and Fluid Description Most simulations in this work were done using the model developed by Jones. 1 This model is a fully implicit compositional model and simulates the isothermal flow of fluids in a cylindrical reservoir with the well located at its centre. The reservoir is assumed to be a homogeneous system except for the existence of a skin zone which is modeled as a region of permeability distinct from that or the reservoir. 2 The Redlich-Kwong equation of state as modified by Zudkevitch and Joffe 3 is used to simulate phase behavior and mass transfer. Fluid viscosities are computed from the Lohrenz, Bray and Clark 4 correlations. Gravitational effects are ignored and the well is produced at a constant molar rate or at a constant wellbore pressures. We have used this model for approximately six years in a number of studies (e.g. References 5–7). Verification procedures to ensure the accuracy of simulations done with this model are discussed in Reference 1. Three fluids are examined in this study: a gas condensate, a volatile oil, and a black oil.

Abstract Matrix acid stimulations with hydrochloric acid have been instrumental in maximizing the production of crude oil from the Bonnie Glen D-3A Pool since 1951. This type of acid treatment has been the main source of reservoir stimulation for this pool. However, changing reservoir conditions have necessitated significant acid additive and procedural modifications. This paper discusses: the changing reservoir conditions; the modifications to the acid and stimulation procedures the results of acid treatments after the changes were made; and the ongoing acid stimulation monitoring program in Bonnie Glen. Introduction Texaco Canada Resources operates 75% of the Bonnie Glen D-3A Pool located 40 km south and 25 km west of Edmonton, Alberta (Figure 1). The pool vas discovered by Texaco in December, 1951. The oil zone is under primary depletion and recovery of 85 × 108m 3 , or 6BZ of the 125 × 108m3 original oil in place is expected. To date approximately 80 × 108m 3 , or 95Z of the estimated recoverable oil reserves, have been produced. The Bonnie Glen D-3A Pool originally had a 91 m oil zone overlain by a 123 m gas cap. As the oil was produced the gas/oi1 contact moved down and the oil/water contact moved up. At present, the remaining oil zone Is only 3 m thick as indicated in Figure 2. The original reservoir pressure was 17 100 kPag as compared to the current pressure of 8 700 kPag. This significant decreases in net pay and reservoir pressure necessitated major revisions to operational and workover strategies at Bonnie Glen. Matrix stimulation with hydrochloric acid continues to be an integral part of the workover strategy; however, changes to the acid additives and acidizing procedures were required to maintain its effectiveness. A comprehensive monitoring program is maintained to identify Bdditional changes vhich may become necessary as reservoir conditions continue to change. GEOLOGY AND RESERVOIR CHARACTERISTICS The Bonnie Glen D-3A Pool is contained in an Upper Devonian Ledue reef in the Acheson-Homeglen- Rimbey Ledue reef trend (Figure 3). The reef is a dolomitized carbonate structure. It has good to excellent pinpoint, Intercrystalline and vuggy porosity. Reef porosity is generally in the range of 9 to 14 percent. The average horizontal and vertical permeabilities are 2000 md and 20 md, respectively. The reef is approximately 11.3 km long and 3.2 km wide, running in a north-south direction (Figure 4). Underlying the Bonnie len D-3A Pool is the Cooking Lake aquifer. HISTORICAL METHOD OF STIMULATION IN THE BONNIEGLEN D-3A, POOL Due to the reservoir rock characteristics in the Bonnie Glen Leduc reef, matrix stimulation with hydrochloric acid has proven to be the most effective form of reservoir stimulation. Dolomite is easily dissolved in hydrochloricacid and responds readily to one of two methods of stimulation; matrix or fracture acidizing fracture acidizing is the preferred method of stimulation in carbonates with very low permeability. During fracture treatments, a high fluid injection pressure is maintained to create fractures along which the stimulation fluid can travel. [2 ]

Abstract The terminology used in classifying petroleum substances and the various categories of reserves has been the subject of much study and discussion for many years. The need for an increased degree of standardization has been long recognized but significant difficulty has been encountered in achieving this objective. A Study Group, comprised of representatives of five member countries of the World Petroleum Congresses (Canada, the Netherlands, the United Kingdom, the United States and Venezuela), reviewed the classification and nomenclature systems for oil and gas and for reserves as used by various countries and recommended systems for universal adoption. Its Interim Report was presented at the 11th Congress held in London In 1983. It has been revised on the basis of comments since that time, and was presented to the 12th Congress held in Houston in 1987. The recommended systems are scientifically sound, and yet at the same time, practical and simple enough to be readily understood even by those not involved on a daily basis in technical aspects of the industry. The recommended terminology Is as close to current common usage as possible in order to minimize the changes necessary to bring about wide acceptance. The system recommended by the Group for petroleum reserves refers to Proved Reserves, Unproved Reserves which are categorized as Probable Reserves or Possible Reserves), and Undiscovered Potential Recovery. Further Potential Recovery is the sum of the Proved Reserves, the Unproved Reserves and the Undiscovered Potential Recovery, and the Ultimate Potential Recovery is the sum of the Cumulative Production and the Future Potential Recovery. Introduction The classification of hydrocarbons and the nomenclature of oil and gas reserves have featured in several World Petroleum Congresses (WPC) in one form or another. In 1980, the Executive Board of the UPC decided to set up, for the first time, a Study Group for the 11th Congress in London In 1983, to review the oil and gas classification systems in current use, and focus on the development of a universal system embracing all types of naturally occurring hydrocarbons of present and potential commercial interest, and the nomenclature used by various countries and organizations in reporting estimates of reserves, and focus on the development of a simple, practical, readily understandable system which would receive general acceptance. This paper deals only with the second item, the nomenclature for reserves. Canada, the Netherlands, the United Kingdom, the United States of America and Venezuela were invited to nominate one person to the Group, and did so. The individual members are listed at the end of this paper. National Committees of the WPC were asked for pertinent information about aspects of the Study. The Study Group members exchanged research material and lists of primary definitions and references, and sought opinions from a wide circle of contacts. The Interim Report was discussed at the llth WPC in London (1983). Additionally, comments were requested from all of the National Committees of the WPC and from certain other organizations.

Abstract The reserve definitions and terminology being used by the petroleum industrytoday have evolved over several decades. During the last decade, there havebeen several attempts at standardization. In spite of these efforts, there aremany different reserve definitions and terminology in use today. Part of thereason for this situation relates to the use of the resulting reserveestimates. This paper will review the current situation and some of the factorsthat should be considered in future standardization discussions. Introduction Reserves data as of a certain date can provide a snapshot of the crude oil, natural gas and natural gas products inventory of an oil or gas pool, acompany, a nation or even the world. A time series of reserves data can provideinformation on progress performance and trends. Reserves data has many usessuch as a basis for security of loans, depreciation and plant exhaustioncalculations, evaluating potential mergers and acquisitions, oil and gasproperty rationalization, supply forecasting, planning exploration anddevelopment activities regulatory measures, security of supply, public policyand financial soundness, to name just a few. These are very diverse uses whichis one of the fundamental reasons for the diversity of reserve definitions andterminology. During the last decade or so, several groups have worked on "standardizing"reserve definitions and terminology. However, there continues to be manydifferent definitions and terminology in use today. Many of these differentdefinitions use the term "proved" although they are not all intended for thesame use. This leads to confusion, even to those within the industry. Oil and gas companies are faced with attempting to deal with this diversity. Itcan be a confusing, frustrating and even costly process. We need to"standardize" but we first should understand what definitions and terminologyare in use today and what the probable intended major uses of the resultingreserves data are. CURRENT RESERVE DEFINITIONS This review will focus on the reserve categories of proved , probable and established . There are other categories such aspossible and potential that would al so need consideration but it is the formercategories that there is the largest divergence in definition meaning, understanding and use. The definitions will be reviewed for the most part in chronological order. Theygenerally fall within one of two general use groupings. This will be discussedfurther but one should consider the organization that created the definitionand their probable focus in regards to the use of the resulting data. The Appendix contains excerpts of all the definitions reviewed in this paper. The first definition is that of the U.S. Department of Energy. Their "proved"reserves definition was first published in their 1977 Annual Report in whichthey began to take over the task of determining oil and natural gas reservesin the United States. Their definition is similar to that used by the APIduring the previous decade. The Energy Information Agency of the DOE whichcompiles these reserves does so to provide accurate estimates of U.S. reservesof crude oil, natural gas and natural gas liquids which are consideredessential to the development, implementation and evaluation of energy policyand legislation in the U.S.

Abstract A secondary hydrocarbon miscible flood was initiated in an area of the South Swan Hills Unit in 1973. The 15 years of performance encompassing both solvent and chase gas injection has provided an extensive basis for performing a history matched simulation study. The problem of evaluating and optimizing the volumes of solvent and chase gas used in a field scale hydrocarbon miscible flood has been analyzed with a three-dimensional, fully compositional simulator wherein physical dispersion effects and the development and loss of miscibility were investigated. The analysis resulted in value information on the conditions required for simulation of the slug process and on sizing of the banks as well as the effects of other operational parameters. Introduction The South Swan Hills Unit is located 190 km northwest of Edmonton near the townsite of Swan Hills. The Field is a limestone reef of upper Devonian age at a subsurface depth of 2700 m discovered in 1959 with 132.2 106m 3 of original oil in place. The Unit consists of three separate projects; a west side waterflood project started in 1963 and converted to a tertiary miscible Flood in 1982, a central area secondary miscible flood which commenced in 1973, and an east side waterflood project which was initiated in 1976. A study was undertaken of the secondary miscible flood project to evaluate performance and recovery and to optimize operating strategy, including the determination of the optimum chase gas bank size. A three-dimensional, history matched compositional simulator was used for the analysis, with dispersion effects approximated by manipulation of grid block sizes. BACKGROUND The secondary miscible flood, located in the central part of the Unit is the largest of the three projects. [n the secondary flood area, there are 109 production and 34 injection wells forming 30 patterns, most of which are inverted nine spot patterns drilled on 64 hectare (Figure 1). This secondary project area contained 84.3 l06m 3 OOIP, and has an estimated ultimate recovery of 58%. The peak production from the project was 10000 m 3 /d oil. The current productive capacity is 1 800 m 3 /d oil, 2 100 103m 3 /d gas and 18 000 m 3 /d water. Cumulative recovery to date, excluding migration effects from the west side projects, is estimated to be 43%. The first phase of the miscible flood was injection of a 15%-20% hydrocarbon pore volume (HCPV) solvent bank which was injected alternately with water in ratios varying from 0.40 to 1.25. The solvent was a rich hydrocarbon gas with a C 2 + enrichment in excess of 50~. Placement of the solvent bank was complete in most patterns by 1980. The injection wells were then placed on lean hydrocarbon chase gas injection. Slightly less than two-thirds of the 30% HCPV design chase gas slug has been placed alternately with water in ratios varying from 0.33 to 1.00. The wells will be placed on water injection at the completion of chase gas injection and remain on waterflood until the economic limit of the field is reached.

Abstract This paper discusses the feasibility of using crosslinked polymer technology and alkaline/polymer technology to improve recovery in the Grand Forks Lower Mannville 'D' pool. The Grand Forks 'D' pool is a good quality channel sand with an original oil-in-place of 100 × 10 6 STB (15.9 × 10 6 m 3 ). The rock has a porosity of 25 % and the permeability ranges from 1000 md to 10,000 md with an average of 3,000 md. The reservoir crude has a viscosity of 11 cp at the reservoir temperature of 88 ºF (31 ºC) and a stock tank gravity of 26 º API. Primary and waterflood oil production has produced 25.5 % of the original oil-in-place as of January, 1986. Previous model studies and historical pool performance indicated that up to 60 % of original oil-in-place could be left in the reservoir after waterflooding due to gravity effects and high vertical permeability. A scheme of combining the cross1inked polymer technology and the alka1ine/polymer technology has been developed to optimize the ultimate oil recovery. The crosslinking technology was investigated using cationic and anionic polymers with various crosslinking agents through linear coreflood and viscosity monitoring studies. The alkaline/polymer technology was studied through interfacial tension, fluid compatibility, phase behavior, chemical adsorption, rock dissolution, and coreflood studies. Coreflood studies included injectivity as well as oil recovery studies. The results of the laboratory studies indicate that the alkaline/polymer system can recover incremental oil over waterflooding of approximately 30 % of original oil-in-place. With an addition of 0.1 % by weight of surfactant, up to 41 % of original oil-in-place can be recovered. No injectivity and fluid incompatibility problems were detected. The test results also indicate that the residual resistance factor can be increased significantly by cross-linking. This should help improve the vertical sweep efficiency by diverting the injection fluids into the unswept lanes. It was concluded that a chemical flood is technically feasible for the subject pool. Introduction The Grand Forks Lower Mannville "D" pool is located in Southeastern Alberta, as shown in Figure1. Figure 2 shows the well configuration of the pool. The pool, which is a lower cretaceous channel sand, is one of the most productive oil reservoirs in the area. The original oil-in-place is estimated to be 100 MMSTB or 15.9 × 10 6 m 3 . Table 1 lists some of the reservoir rock and fluid properties. The reservoir has yielded more than 25 million barrels of oil from the Lower Mannville sand since Hs discovery 1n 1968. The field has been waterflooded For more 9 years and watercut has been increasing steadily since then. The pool now has 34 producers and 4 water injectors with a total 1njection rate of 19,500 bid (3,100 m 3 /d). Current oil production rate is approximately 6,000 bid (950 m 3 /d) with an average watercut of 80 %. Previous waterflood simulation study 1 and recent production logs ind1cated that there is a substantial volume of moveable oil still in place. The study also showed that the existing waterflood has a good sweep efficiency in the bottom layers, but poorer in the upper layers due to the effects of gravity segregation, high vertical permeability and reservoir heterogeneity.

Abstract The Falher Formation in the Deep Basin area of Western Canada contains severaltight gas bearing sands overlain by permeableconglomerates. Because of the lowpermeability, the gas cannot be drained from the sands by horizontal flow tothe well bore. However, drawdown of the conglomerate could cause the gas tomove upwards into the conglomerate and subsequently to the well bore. As thiscould occur over a relativelylarge area it could provide an effective method ofdraining the tight sands. Reservoir simulation calculations using a simple model of a homogenous sandoverlainby conglomerate, yield a recovery factor of about 80% for a one sectiondrainage area. With an average drainage area of 3.7 sections per well, basedupon current well spacing, the recovery factor would decrea3e to 45%. Visual examination, and porosity measurements of core material, suggestthatexcept for occasional obvious shale breaks, the sands are homogenous. However, log evaluation shows that shaly zones and zones of higher watersaturation are present, both of which are less permeable to gas than the cleansands. Correlation of these low permeability zones between wells wasunsuccessful, and their lateral extent is therefore assumed to be less than thecurrent well spacing. A reservoir model containing the low permeability zones was constructed bystatistical analysis. Their lateral extend was assumed to be equal to half thewell spacing, and their position in the vertical sequence derived from theresults of log analysis of 142 conglomerate/sand intervals. Simulations run using these models indicated that with the current welldensity, the recovery factor would probably be about 35%, but could be as lowas 25%. Introduction The Cretaceous Falher Fomration in the Deep Basin of Western Canada containsseveral tight gas bearing sands overlain by permeable conglomerates. Because ofthe low permeability of the sands, the gas cannot be drained by horizontal flowto the well bore. However, draw-down of the conglomeratecould cause the gas tomove upwards into the conglomerate and subsequently to the well bore. As thiswould occur over a relatively large area it could provide an effective methodof draining the tight sands. In the absence of a significant production history, the determination of arecovery factor for the tight sands depends on reservoir simulationcalculations. Theresult of the simulation procedure depends on the input inparticular on the reservoir model used. Models used in previous studies have assumed: homogeneous sand directly under1ying conglomerate, giving recoveries of lipto 80%, (10) an impermeable barrier between the conglomerate and sand in most Hells, recovery factor zero. (2) Within the area studied in this report (Fig. 1) a model between the twoextremes described above, with some degree of reservoir inhomogeneity, wasconsidered to be more appropriate. The sands are not homogeneous, as inWinter's study (10), but contain lower permeability layerswhich imhibit thevertical flow of gas.

SUMMARY AND CONCLUSION Canada's east coast play is worthy of the investor's consideration, as it still affords him the opportunity of participating at a relatively early stage in the area's exploration history. All multi-billion dollar world energy projects contain many inherent uncertainties which cloud the investment picture. Canada' s east coast is no exception. We have attempted to summarize these points for consideration: Negative Features the potential Canadian jurisdictional problem on ownership; the potential international ownership through the Law of the Sea Conference; the tax features which will replace the super depletion allowance, and the date they will become effective; stringent Newfoundland and Nova Scotia regulations; the technical problems associated with discoveries on the Labrador Coast and Davis Strait; and the National Energy Program. In comparison, we believe that the positive considerations to this play dwarf the present negative uncertainties. Positive Features the size of Canada's east coast offshore area, in relation to the drilling activity and results that have taken place to date; the relatively short period of time before production could commence from the Grand Banks and the Scotian Shelf areas; the development costs in relation to the estimated daily production volumes; the ready natural markets for both oil and gas; future drilling results (which can be both positive and negative); the estimated rate of return; and the potential rewards. FOREWORD Fish and lumber, the two principal staples which have played such a significant role in the economy of Atlantic Canada are about to be joined by a newcomer: petroleum, which will permit the region finally to obtain its long desired goal of a fully supportive economy. Many authorities believe that the Hibernia discovery well could become as famous as the 1947 Leduc wildcat which placed Alberta on the world oil map. The Canadian Government has termed Hibernia "the most significant discovery ever made in the Canadian offshore". Merrill Lynch Royal Securities Limited believes that the Hibernia discovery has made the east coast of Canada the number one offshore play in the world, and that it will remain so in the near future. With continued unrest in the Middle East, the importance of oil and gas reserves on Canada's east coast will obtain increased investor recognition. Although it is the government's intention to increase crude oil imports from Venezuela and Mexico, the Persian Gulf countries will continue to be the dominant supplier. Investor interest in the east coast play will primarily focus on oil; a field offshore Newfoundland with recoverable reserves of one half to one billion barrels will have immediate possibilities. Production could be on stream in four to five years, as natural markets are at hand. A natural gas discovery of sufficient size on either the Scotian Shelf at offshore Prince Edward Island would also be favourably considered. Production could commence within a reasonable time due to the fact that markets are at hand.

Abstract In mid-l980, Kloepfer Coles Nikiforuk Pennell Associates Ltd. prepared an estimate of Alberta's ultimate natural gas reserve potential under the perceived economical, geological and technical constraints at that time (1). The study was commissioned by Trans Canada Pipelines Limited (TCPL) and Petro Canada for presentation to the 1980 NEB Energy Inquiry (NO. EHR-l-BO). This paper will discuss the methodology used to derive that estimate and, in particular, the economic and technical considerations. The initial marketable gas reserves of Alberta recognized by the Alberta Energy Conservation Board (ERCB) increased from 1867.2 to 2554.7 billion cubic metres (66.3 TCF to 90.7 TCF) over the period year end 1973 to year end 1979. Although many factors played a role in this increase of reserves, the change in economic expectations throughout that period was likely the most significant. The estimate of ultimate reserve potential at any given point-in-time is a function of the available resources and perceived current and future economics at that point. The subject of the economics portion of this paper is the effect of the economic conditions of mid-l980 on the ultimate potential estimate. Most ultimate potential estimates are based on anticipated economics and current technology. In the technology portion of this paper the influence of advances in exploration; drilling, coring and logging; and completion and stimulation technology on Ultimate potential has been analyzed and the magnitude of the various contributions estimated. The results of certain case studies have been included to substantiate the findings of both the economics and technology sections of the paper. Introduction Estimates of the Ultimate natural gas reserve potential for a given area are continually revised to reflect variations in economic expectations, technological advances, and trends in exploration successes. At year end 1973 the ERCB estimated Alberta's ultimate potential at 3.1 trillion cubic metres (110 TCF) (2). By 1980 the estimate had been revised upwards to between 3.5 to 3.7 trillion cubic metres of actual heating value gas (12b to 133 TCF) (3). Although a certain portion of this upward revision is the result of new discoveries, economic and technological changes during the 1970's played an important role in the conversion of resources to reserves. An ultimate potential estimate consists of these elements. The base of the estimate is the recognized initial marketable gas reserves of the day which can be produced by proven technology from known geological reservoirs under generally accepted economic expectations. The ERCB recognized 1867.2 billion cubic metres (66.3 TCF) at year end 1973 and 2554.7 billion cubic metres (90.7 TCP) at year end 1979. The influence of economics and technology on this increase is apparent as follows (4): during 1973 some 85 billion cubic metres (3.0 TCP) of marketable gas were added to the reserve estimates as a re3ult of recovery factor adjustments due to higher gas prices. (A subsequent adjustment in 1976 reduced recovery factors of pools with less than:282 million cubic metres (10 BCP) by a total of 39 billion cubic metres (1.4 TCP))

Abstract Commercial exploitation of the large unconventional gas reserves of the lower portion of the "Resources Triangle" such as the tight Cretaceous Sands of the Elmworth-Wapiti deep basing and the S.E. Alberta Milk River-Medicine Hat low grade formations has proven that prediction of gas well performance utilizing commonly accepted methods and short term well test data can lead to serious errors due to the unsteady-state effects. The need for alternative approaches capable of extending the range of applicability beyond the limitations incurred by the former method, reinforced by seven years of fully documented anomalous performance of the multilayered, tight Debolt carbonate of the Dunvegan field, prompted the development of the unsteady-state deliverability model presented in this paper. This program utilizes the Laminar Inertial Turbulent approach suitably modified to accommodate the effect of time on the deliverability factor "A" in accordance with recent theories described in the literature and confirmed by the author's empirical observations. The model features a complete suite of routines designed to effectively endow it with diagnostic powers comparable to those afforded by grid-based simulators, While providing for easier handling and fasterprocessing of the data base. When future appreciation of reserves is anticipated as a result of development or infill drilling, the initial gas in placeterm of the material balance equation can optionally be revised at each time step to include a proper estimate of the inherent volume accruals. The periodical update ofthe pool's average back pressure parameter "A" subsequent to attainment of pseudo-steady-state regime is also advocated as the proper means to account for dynamic readjustment of flow patterns resulting from development and production practices (i. e. infill and/or development drilling, shut-ins etc.) An example run using Alberta & Southern's tank-type deliverability model as a basis for comparative analysis illustrates the ability of the proposed program to readily pinpoint optimistic estimates of productive capacity arising from the application of steady-state assumptions and short term AOF tests results to the solution of an essentially unsteady-state problem. This can prove instrumental in an operator's assessment of its ability to meet contract obligations and to devise remedial measures aimed at insuring adequate supply. Reliability of results is enhanced by a built-in calibration technique based on inputted "control points" (bottom hole or wellhead pressure measurements that generates appropriate corrections to initial controlling parameters so as to insure general compliance with the actual combined performance of the reservoir and gathering system. COMPARATIVE ANALYSIS Test runs designed to compare conventional tank type projections with the unsteady state deliverability forecasts proposed by the subject model revealed that: Short falls as highs as 20–30% of the flow rates predicted by conventional methods may be expected in low permeability heterogeneous reservoirs commencing in the early years of production. This is largely due to the failure of a tank type model to recognize inevitable future deteriorations of productivity determined by prevailing unsteady-state flow regimes and inherent time-dependency of deliverability parameters.

Abstract This paper discusses the application of a numerical model to investigate the effect of water coning on the sweep efficiency and ultimate recovery from gas reservoirs with active aquifers similar to those found in the Middle Devonian of north east British Columbia. Reservoir properties typical of this type of pool were selected to cover the range of properties normally found. The properties used in the numeric simulator were systematically varied to produce a complete range of reservoir performance that might be expected for a standard gas production rate. The parameters that were varied were those indicated by literature and previous studies to be factors that contribute to the coning of water into a gas well. The resulting data were analysed to yield an equation that evaluates sweep efficiency and consequently ultimate gas recovery from given values of the reservoir parameters. The study shows that the ultimate recovery of gas from a water driven Middle Devonian gas pool in northeast British Columbia can vary from 36% to 70% of the original gas in place. Background to the Study The effect of water influx into a gas reservoir has been poorly documented. Many papers deal with the problem piece meal. The Petroleum Resources Branch of the British Columbia Ministry of Energy, Hines and Petroleum Resources decided to conduct studies to gain a betterunderstanding of the gas recovery from the Middle Devonian gas fields. To this end a study was made on the Clarke Lake gas field. 1 The results of that study indicated that gaswas trapped by the encroaching water and that reservoir volume cut off by coning (poor sweep efficiency) was not a significant factor in the ultimate recovery of gas. A second study was made on the Cabin Slave Point ‘C’ gas pool. 4 The purpose here was to evaluate the effect of a poorer rock type in a thinner reservoir with a stronger water drive. In this study coning of water was a significant factor in the recovery of gas and because of the strong water drive very little depletion of the reservoir took place by pressure reduction. The results of the two studies seemed to conflict. In the case of the Clarke Lake study it appeared that more gas could be recovered by drawing down the reservoir as quickly as possible to maximize the depletion effect. On the other hand in Cabin a high rate of drawdown adversely affected ultimate recovery. It was decided that further studies should be conducted. The prior Branch studies and a literature search indicated that overall gas recovery is a function of formation thickness, rock properties and the strength of the encroaching aquifer. It should be noted here that the manner in which the strength of the aquifer and sweep efficiency affects the ultimate gas recovery is shown in Appendix A which is derived from Reference NO. 1. Obviously a method to predict sweep efficiency is required in order that an estimation of recoverable reserves in a variety of water driven gas fields can be made.