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 In the present paper 3D analytical simulator for modeling horizontal well (HW) and slanting well (SW) performance is presented. Hydrodynamic characteristics of the development process are treated in terms of Newton's and heat potentials, and the developed simulators provide the ability for modeling both stationary and non-stationary states. The computational experiments allowed to analyze the impact of the geometry of the system «reservoir + HW » on performance indexes and to infer new flow rate formulas for stationary and non-stationary drainage. The proposed method is based on iterative algorithms and domain decomposition principle reducing the drainage problem in domains with complicated structure to problems in standard (simple) domains, such as ball, cylinder, etc. The developed numerical methods and flow rate formulas have been validated and proofed to be highly precise. Introduction The fluids drainage in the neighborhood of one or several HW is still less fully studied than in the case of vertical wells (VW). This default may be accounted for by the essentially 3D nature of the hydrocarbons influx toward the well in a reservoir limited by its top, bottom, and the no flow barrier. The main problem consists in determining the dependency of the well's productivity on the reservoir geometry and on the wells interference. A number of analytical formulas and charts [1–8] linking production rate and differential pressure in relation to geometric and hydrodynamic parameters of the system «reservoir + HW » are available. Analytical formulas are mostly obtained by reduction of the authentic 3D model to 2D flow. Precise solution of essentially 3D drainage problems is, very complicated and can be constructed only for special cases (see e.g., [9–10]). Another efficient approach consists in development of computational models to simulate drainage processes in 3D reservoirs [11–13]. In the present paper an'explicit method [14,16] is presented to solve the problem of one-phase incompressible elastic fluid inflow toward a single HW or a group of HW in a 3D reservoir limited by top, bottom, and no-flow barrier. The wellbore is modeled as a superposition of Source Functions (SF) such that in each inner reservoir point these functions satisfy Laplace equation in case of stationary drainage or heat equation in the non-stationary case; the boundary conditions are satisfied on the reservoir top, bottom, and on the no-flow barrier. The solution is sought in terms of discrete density distribution subject to one of the following conditions: the pressure on the wellbore or the flow rate at discrete points of the well is given. In view of the maximum principle (see [15]) it is easy to check that for the approximate solution the deviation from the precise solution in each inner point of the reservoir doesn't exceed the deviation from the given value on the boundary of the well. Thus, the main issue consists in construction of Green's function possessing the outlined properties. Development of a highly precise algorithm for construction of this function in the stationary case and of a parabolic analogue of Schwarz's algorithm [16], utilizing standard Green's function and introducing image well in the non-stationary case, is the main achievement of the presented work.

Abstract The author has worked on a number of fractured reservoirs in Western Canada, which show a number of common characteristics. Evaluating this type of pool is normally very complex and presents a number of difficulties. Production performance is discussed. They also exhibit distinct types of pressure transient response, which do not correspond to Warren and Root type dual porosity description. Stimulation results have proven difficult to predict. A reservoir characterization is presented which is consistent with observed production performance, pressure transient responses, production logging results, core analysis and well stimulation. A key component is structural geological style. This description has been applied to a number of different reservoir situations. It has application to stimulation design, predicting reservoir performance, numerical simulation and pressure transient analysis. An example is highlighted for a gas condensate reservoir. Introduction The material in this paper was derived from a number of large detailed reports. Such a detail and volume of material cannot be covered in a single technical paper. The paper therefore only presents a summary of a number of key concepts derived based on the author's experience. The following is discussed: Systematic Approach Core Descriptions Structural Style Fracture Patterns Effect Of Stress Discrete Element Analysis Pressure Transient Observations Mechanisms Example Application: Gas Condensate This paper is complemented with a companion paper 1 "Optimization of the Blueberry Debolt Oil Pool: Significant Production Increases for a Mature Field", which is also presented at this conference. Systematic Approach Evaluating a fractured reservoir (after Nelson 2 ) involves four main steps: Interpreting the origin of the fracture system. This information allows one to predict geometry and the extent of communication. Determining petro-physical properties of the fractures and matrix. This allows for prediction of the variation in reservoir response. The relative storage (i.e. porosity) must be determined as well as effective permeabilities. Another important property is compressibility. The flow interaction between the matrix and fracture system is evaluated to determine ultimate reserves from the reservoir. Classification of the reservoir. Depending on the type of flow interaction the reservoir will fit one of several depletion strategies. Note that most of the variations in strategy apply to waterflooding oil reservoirs. Conventional Core Analysis To obtain most of the base information requires some basis of observation, which for most reservoirs starts with core. Information can be derived from the following conventional core analysis data and plots: Core permeability vs core porosity - all data. Core permeability vs core porosity - sorted by lithology. Vertical permeability vs horizontal permeability. K90 plotted vs Kmax. Fractured reservoirs do not show the typical straight line relation on core permeability vs core porosity (semilog) plots. Typically lower porosity rock is more prone to fracturing. Fractured reservoirs also tend to have higher anisotropy, which is seen as large variation in K90 vs Kmax. Core Description Example From Central Foothills In the author's experience, based a number of studies in Western Canada, there is a typical core permeabiliy vs core porosity relati

Abstract This paper investigates the time-dependent effect of drilling fluids on the shear strength properties of Fernie Formation shales. Direct shear tests were conducted on samples that were split along their bedding planes and soaked in four different drilling fluids systems for varying periods of time: oil based mud, gel chern, TAME and PHPA. Distilled water was used as a base fluid line in this study. The shear tests were conducted at a normal stress range of 0 -1 MPa. For each fluid, five samples were tested, four of which had their natural rough surface, whereas, the surface of one was artificially smoothened. The test results show that both TAME and PHPA fluids increase the angle of shearing resistance of the smoothened shale samples indicating that these may be absorbed into the shales at least at the surface. The distilled water, oil based and gel chern muds have no effect on the angle of shearing resistance of smooth shale samples, whereas, the angle of shearing resistance of the rough samples decreased. The angle of shearing resistance of the rough samples in the TAME fluid showed both increases and decreases, whereas rough samples in the PHPA fluid had a general increase in the angle of shearing resistance with period of soaking. Introduction Shales from the Ctetaceous and Jurassic periods are found at depths of thousands of metres in the Rocky Mountain Foothills region of British Columbia and Alberta, Canada. In undisturbed conditions, these shales exist in equilibrium under high in-sim stresses. However, when drilled for oil and gas, these shales tend to become unstable in boreholes 1,2,3 . This loss in stability is due to the mechanical stresses induced while drilling as well as the physico-chemical effects of the drilling fluids. The relative contribution of each of the two effects in causing instability is not well understood in some brittle shales like the Fernie Formation. Mechanical stresses are caused by the excavation ofthe wellbore, whereas some physico-chemical effects are the result of capillary action due to absorption of the fluid and interaction between the constituents of the rock and that of the fluid 4 . To our knowledge, the physico-chemical effects of the various drilling fluids on Fernie Formation shales have not been studied in the laboratory. Hence, a study was initiated to determine the shear strength parameters of Fernie shales along pre-failed bedding planes when exposed to different drilling fluids for varying periods of time. The time-dependent effect of the fluid on the shear strength properties of the shales was examined by conducting direct shear tests on samples soaked in the fluid for periods of 1, 7 and 28 days. There are several different parameters that affect the shear resistance of natural rock discontinuities. The surface roughness and interlocking of protrusions (asperities) are considered major obstacles in objectively determining rock discontinuity shear strength. The problems are compounded by the apparent effects of fluid induced lubrication including softening of asperities, fluid composition, rock mineral content, base frictional properties and normal stress levels.

Abstract An experimental and numerical study was conducted to investigate the effect of the variable aperture system of an oil sand fracture on its two-phase flow response. The oil sand fracture was induced in core samples along the axis of the sample using the Brazilian tensile test. A Computer Assisted Tomography (CAT) scanning analysis was performed to determine the fracture geometry. The fracture was shown to be a variable aperture system- which, when coupled with capillary dominated conditions, governed the occupancy of each phase in a two-phase system. A numerical program was used to investigate the occupancy and two-phase flow response of the derived aperture distribution. Phase interference was found to be significant with the interface between phases showing an unsteady nature. The impact of this unsteadiness may affect the assumption of relative permeability being a function of saturation alone. INTRODUCTION Heavy oil and bitumen are a major energy resource in Canada, and have become a major focus for the oil and gas industry. The fact that the heavy oil deposits of Canada contain 30 % of the world's recoverable oil indicate the potential is certainly present. 4 The challenge in developing this resource is the difficulty in recovering these highly viscous substances. Thermal recovery has become an accepted method with steam-based recovery drawing much attention. Steam-based recovery methods involve the injection of steam into the reservoir to heat up the reservoir, lowering the viscosity of the bitumen, which increases production rates. Cyclic steam-based recovery processes have become common practice in the thermal operations of the Cold Lake heavy oil reservoirs. 1 The steam injection approach used at Cold Lake encourages fracturing of the reservoir each steam cycle, exploiting the permeability of the fracture instead of relying on a layer of bitumen depleted, permeable oil sand. The high hydraulic conductivity of the fracture enables heat transfer to take place further away from the well, thus, accessing more undisturbed reservoir material instead of depositing most of the heat in a previously heated and bitumen depleted area of the reservoir. In order to optimize this steaming approach an understanding of the medium used to carry the heating agent, the fracture, is essential. The geometry of the fracture, characterized by surface roughness and aperture distribution plays a key role in the permeability of the fracture as well as the flow channels available to the injected mass. A detailed picture of an oil sand fracture, its surface characteristics and their relation to the two-phase flow is needed to better understand and possibly exploit the flow phenomena taking place during and after the hydraulic fracturing process of steam stimulation. According to the authors' knowledge, no work is currently available characterizing an oil sand fracture or proving that fractures in this material can be characterized in a similar manner as to what has been previously studied in rock fractures 1,3,5 . The following study presents an experimental, physical characterization of an oil sand fracture using a Computer-Assisted Tomography (CAT or CT) scanning analysis to visualize the fracture geometry.

Abstract There currently exists a large supply of heavy crude oils which are relatively uneconomical to produce. However, there are processes available which can be used in a downhole environment to upgrade them, resulting in significantly less sulfur and lowered densities and viscosities. A process which is especially favorable for downhole implementation is the use of in situ combustion to generate reactive upgrading gases, such as CO 2 and to drive oil over a near-wellbore heated bed of catalyst. Two laboratory combustion tube runs were completed to test this concept. These differed from normal combustion experiments in that they employed a heated processing zone over which combustion gases and fluids passed prior to production. The first run used sand in the processing zone, and the second a bed of catalyst. The Middle Eastern heavy crude oil used was amenable to combustion, and the presence of a heated production-end processing zone did not affect the combustion performance. Passing oil and combustion gases over the catalyst prior to production resulted in substantial upgrading of the produced oil, including a 50% level of hydrodensulfurization and substantial decreases in oil gravity and viscosity. The catalyst efficiently converted CO 2 generated at the combustion front, to H 2 , which then reacted with the oil to effect upgrading. The catalyst-bearing zone appeared to have a very low residual water saturation and was effectively oil wet, thus assuring that good oil-catalyst contacting occurred. However, it was found that the presence of a large amount of coke on the catalyst may indicate the need for periodic regeneration. INTRODUCTION Although there exists a large supply of heavy crude oil throughout the world, most of these reserves tie untapped for various reasons, chief among them being the poor economics of recovering heavy oils. The authors have recently described processes that could be used for significant downhole (in situ) upgrading of heavy crude oils 1,2 , despite previous reports which found that in situ processing has limited potential 3 . In situ processing has several advantages over conventional surface upgrading technologies. Because in situ upgrading can be implemented on a well-by-well basis, there is no needed for large capital-intensive projects. Rather, the size of an in situ project, for a particular field, can be tailored to available production rates; thus, upgrading is practical even for those fields deemed too small to provide sufficient production for conventional processing. Additional advantages for in situ upgrading include the production of a more desirable and valuable product, increased ease in shipping and pipelining, and less-demanding downstream processing. The requirements for in situ upgrading include: provision for a downhole bed of catalyst, achieving appropriate reaction temperatures and pressures at the catalyst bed, and mobilization of oil and co-reactants over the catalyst. Although the technologies to accomplish each of these tasks are fairly well known, their combination into a unified process has yet to be demonstrated. A bed of catalyst can be placed by conventional gravel pack or proppant injection methods 4,5 .

Abstract Extended production decline analysis utilizes meter pressure data combined with production data to better estimate gas reserves, reservoir quality, and long term gas well deliverability under a variety of operating scenarios. Down hole pressures are calculated from meter pressures and wellbore parameters through the use of multi-phase flow calculations. A one-dimensional gas reservoir simulator is used to determine the resulting reservoir pressures after each monthly production withdrawal based on parameters for reservoir size, quality and geometry. Reservoir inflow coefficients are calculated based on production rates and calculated sand face and reservoir pressures. Reservoir and/or wellbore parameters are then adjusted until inflow coefficients remain roughly constant for the production data available. Inflow coefficients are assumed to remain constant over the life of the well. The reservoir, wellbore, and inflow parameters are tested, by history matching existing production data, and used to forecast future production under different operating conditions. This process allows optimization options for incremental production and increased recovery to be evaluated. Numerous reservoir descriptions can be tested for each well in order to establish limits on reservoir quality and volumes which will provide an adequate history match. In this way, ranges can be established for original gas in place, reservoir permeability, and reservoir geometry. The technique is applicable to gas wells producing under gas expansion drive from either single well pools, or pools with limited off setting production. Introduction The purpose of this paper is to demonstrate how extended production decline analysis (EPDA) can be used to estimate original gas in place, recoverable reserves, and well productivity for deep (>750 m total vertical depth) gas wells using production data combined with surface pressure and bottom hole shut-in pressure (BHSIP) data. By comparing forecasted production under a variety of operating scenarios, production and recovery can be optimized. Background This work was initiated in an attempt to supply our 3rd party gas field deliverability program with representative reservoir data for the wells being modeled in the Bassano Lathom area of Alberta. The gas field deliverability program runs with a tank type reservoir model and required the original gas in place (OGIP), as well as coefficients for the simplified gas deliverability equation (A-I) for each well in the model. Equation(A-l) (Available in full paper) The user was required to input values for OGIP, 11 and wellbore tubing configuration for each well, and the gas field deliverability program would then calculate the sand face inflow coefficient C using surface pressure data supplied from a single production test. The field being modeled, however, contained numerous low permeability hydraulically fractured gas wells, and the author was concerned about the reliability of the OGIP estimates being made for these wells, as well as the choice of a "representative" production test. Conventional production decline analysis using rate versus cumulative production (exponential decline) gave quite different values for recoverable reserves when compared with production decline analysis using log rate versus cumulative production (hyperbolic decline).

Abstract Many people question whether executives are overpaid or whether they actually earn the high salaries and bonuses reported in the popular press. Whether they are overpaid or fairly paid has little to do with the absolute size of the compensation package and everything to do with the way the compensation package is determined Compensation based on the ability to "attract and retain" does not ensure value is being created and shareholders being rewarded. Executive compensation should instead be tied directly to a value creation measure such as Economic Value Added. It is only when this connection is enforced through the compensation strategy that shareholders can be assured that executives are indeed "worth it". Many people already have an immediate answer to this question, despite the fact the question as posed is really quite meaningless. The question of "Are executives worth it?' is about as capable of being answered rationally as the question "How long is a piece of string". The only difference apparently is that most people have fewer strongly held opinions on string than they do on executive salaries. Judging by the absolute glee with which large executive salaries are generally reported by the popular press, this observation is not lost on your average journalist. How likely is it we would ever see a headline like: Acme Corporation revealed today, they have in their possession piece of string 8 miles long. A company spokesman was quoted as saying, "We believe an 8 milelong piece of string is a reasonable length for a company of Acme's size. Although 8 miles is lot of string we are aware of many smaller companies who possess even longer strings and we feel compelled to remain competitive." I think we can all agree that on at least one level, 8 miles is a heck of a lot of string. After all, who really needs a piece of string that long. However without a frame of reference we have no way of determining whether it is too much or too little. My aim in this paper is to develop a basic framework that can be used to separate emotional arguments from logical ones and that can be used as a basis for a reasonable approach to executive compensation. "I don't know much about art, but I know what I like". This approach may get us through an art gallery opening with our ego intact, but is a dangerous strategy at an art auction at Sotheby's. Similarly we cannot rely on "instinct" to assess executive compensation, secure in the belief we will somehow know when it is right because it is too easy for emotional responses to affect our judgment. compensation framework is with something similar to a mission statement. If asked to describe the purpose of an executive compensation strategy, companies generally respond along one of two lines. "The purpose of the compensation strategy is to attract and retain top quality talent". or "The purpose of the compensation strategy is to enhance shareholder value".

Abstract Enhancing oil extraction from oilsand by hydraulic fracturing technique hasbeen widely used in practice. Due to the complexity of the actual process. Modeling of hydraulic fracturing is far behind its application. Effects of highpore pressure and high temperature combined with complex stress changes in theai/sand reservoir requires a comprehensive numerical model which is capable ofsimulating the fracturing phenomenon. To capture all of these aspects in theproblem three partial differential equations. i.e. equilibrium. flow and heattransfer should be solved simultaneously in a fully implicit (coupled) manner. A fully coupled thermo-hydro-mechanical fracture finite element model isdeveloped to incorporate all of the above features. The model is capable ofanalyzing hydraulic fracture problems in axisymmetric or plane strainconditions with any desired boundary conditions, e.g constant rate of fluidinjection, pressure, temperature and fluid flow/thermal flux. Fractures can beinitiated either by excessive tensile stress or shear stress. The fractureprocess is simulated using node splitting technique. Once a fracture is formed, special fracture elements are introduced to provide in-plane transmissivity offluid. Effectiveness of the model is evaluated by solving simple examples andcomparing the numerical results to analytical solutions. The model is also usedto simulate large scale laboratory hydraulic fracturing experiments. Introduction Hydraulic fracturing technique has been a fast growing technology since itsfirst application in 1947. By 1988 more than one million hydraulic fracturingtreatment had been performed[1], and today this technique is one of the mostimportant methods in enhancing oil extraction from wells. Hydraulic fracturingin oilsand reservoirs plays an even more important role. Due to low temperatureand low permeability of oilsand deposits and high viscosity of bitumen, oil isvirtually immobile[2]; hence any attempt for in-situ oil extraction shouldemploy one of the techniques such as cyclic steam stimulation, in-situcombustion or hydraulic fracturing. Despite the fact that hydraulic fracturing technology has advancedsignificantly over the past fifty years, our ability to design the process hasnot change rapidly. As a matter of fact this technique has been so successfulthat in the past designing the treatment with a high degree of precision wasnot of interest. But as the industry moved towards applications of very highvolume/rate and highly engineered and sophisticated hydraulic fracturingtreatments, the demand for more rigorous designs in order to optimize theprocedure have become more important. On the other hand without a thoroughunderstanding of the physical process and the factors that are involved, ourability for an optimal design is limited. Modeling of fluid flow combined withheat transfer in the reservoir has been used by the industry for a long timeand fracturing process often was designed based on two dimensional closed formsolutions such as Geertsma-deKlerk[3] or GdK in brief and Perkins-Kern[4] and Nordgren[5] or PKN. Most of the flow and heat transfer models are based on thefinite difference method and effects of stresses and deformations in theground, if not totally ignored, is solved in a decoupled or partially coupledmanner with other elements.

Abstract The Mannville Q Pool is one of a group of Glauconitic oil and gas pools located in the Gadsby area of east-central Alberta. This paper outlines the recent devewpment of this pool and presents the advantages ofutilizing a synergistic approach involving detailed geological, geophysical and reservoir engineering analyses. Particular emphasis is given to the practical application and implementation of the recommendations formulated by the development team. Streamlined project management allowed planning and construction of field facilitie,. drilling of a horizontal re-entry well and testing of an enhanced recovery scheme within a 4-month period. Field results before and after this recent development are also discussed. INTRODUCTION The Gadsby Mannville QPool (the "Pool") is located in east-centra1 Alberta in Section 6, Township 38, Range 18 west of the Fourth Meridian (Figure 1). Light gravity oil of 31 °API is being produced from the Glauconitic sandstone reservoir. Oil production commenced in 1991. Since the pool is located under Lonepine Lake in the Gadsby area, all wells were drilled directionally into the formation. In September 1995, before commencement of additional pool development, only four of the eight wells were producing due to a gas-oil ratio (GOR) penalty which restricted oil production from the Pool. Two wells (08–01 and 09–01) located in Section 1 of Township 38, Range 19 west of the Fourth Meridian were producing at much lower rates of I to 2 m 3 of oil per day. Recent pressure surveys suggest that they are in a separate reservoir, in concurrence with additional geological and geophysical analyses. In the main pool, located in Section 6, only two wells (02–06 and 06–06) were producing at a combined oil rate of about 24 m 3 per day with a GOR of about 250 m 3 /m 3 . However, with an assigned base GOR of 100 m 3 /m 3 , these wells could only be produced for two weeks per month to avoid overproduction as a result of the GOR penalty. The total penalized oil production from the Pool in September averaged 16 m 3 per day (100 BOPD). Gas was not conserved at the time. In September 1995, Best Pacific Resources Ltd. became the operator of the Pool as well as several gas wells producing from separate Glauconitic pools in the Gadsby area. A detailed geological, geophysical and reservoir engineering evaluation was initiated to investigate the potential of creating additional value through further development of the field by horizontal drilling and pressure maintenance. Based on a detailed geological study, three dimensional (3-D) seismic and reservoir simulation, a horizontal re-entry candidate was chosen at 05–06–38–18 W4M. The horizontal well was drilled in November 1995 and placed on production in December 1995. Initial production results from the horizontal re-entry well were significant as it flowed at a sustained rate of 90 m 3 per day with a 2% watercut in a two-day flow test. In January 1996, it was equipped to pump and tied in to the recently constructed central battery.

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 This paper outlines the basic requirements for Environmental, Health and Safety (EH&S) Guidelines infield operations, and how they relate to the overall E,H&S management plan for an organization. The paper addresses the delivery of specific guidance to field personnel. The main segments of field procedures are briefly described, including: Policy and guiding principles General Principles and Administration Hazard Identification, Hazard Control and Operating Procedures Environmental Protection Emergency Response Training and Education Contractor Requirements In section 8, the paper also discusses new methods to deliver updated or new guidance to personnel in a cost effective and efficient manner. Section 9 contains a partial listing of relevant reference information. 1. Policy And Guiding Principles There must be agreement between the various stakeholders to save and protect the public, employees and company property with respect to environment health and safety. This requires development and implementation of an overall policy statement and a set of general guiding principles by the company and acknowledgement by all employees to accept and work within these ?rules" and to proactively promote them within the company and its operations. It is important to realise that at the present time the structure of organizations has changed dramatically and the lines between management and employees have become blurred, if indeed they have not disappeared. For certain operations, frontline employees or contractors may carry a high degree of responsibility and may be considered management if this is orally understood or outlined in employment or contractual agreements. Typically a company policy contains a commitment to: Safeguard human health and protect the environment in all of its operations; Assess the effects on worker safety as well as potential impairment of the environment and public health resulting from development activities; Comply with all laws and regulatory requirements in business activities. Reduce to an absolute minimum the final reclamation cost. Implement remedial measures in an efficient and effective manner in the event of mishap. The policy must be signed by the chief executive officer of the company and publicly displayed to be effective. Underlying the policy are guiding principles which address responsibility of all workers, priority of EH&S, recognition of excellent performance and emphasis on continuous improvement. It is important to recognise the limitations of guidelines, the possibility of human error and the need to be constantly on the alert for hidden or poorly understood risks. Finally, it is important to obtain the signed commitment of all employees and contractors to abide by these principles. 2. General Principles And Administration These are required to convert the policy into specific and workable guidelines with definition of expected performance and measurement of same. These may be broken down into the following topics. 2.1 Responsibility. There are three levels of responsibility that encompass all work situations - Management, Supervisors and Employees or Workers. Management is responsible for development and implementation of EH&S Policies which meet or exceed all applicable government laws and regulation, communication of the above through supervisors to the workforce, identifying and providing training programs for all personnel, reviewing and evaluating EH&S programs and revising as require

Abstract The Hibernia Field, located in about 80 metres of water, 315 km ESE of St. John's, Nfld., was discovered i" 1979. Of the 10 wells drilled, seven wells tested a 150 to 290 metre thick section of rock interpreted to have been deposited in a fluvio-deltaic environment. Located between depths of 3450 and 3890 metres subsea, the Early Cretaceous-age Hibernia Formation contains an estimated 1.4 BBbls of STOOIP. Petrophysical properties obtained from wireline logs and core were evaluated using mathematical and statistical techniques to create alternative permeability profiles and to characterize the Hibernia Formation into "Hydraulic Units". A hydraulic unit is defined as a volume of the total reservoir rock within which geological and petrophysical properties that affect fluid flow (e.g. pore tortuosity, surface area per unit grain volume, and shape factor) are internally consistent and predictably different from those properties of other rock volumes. A derivation of the Kozeny-Cannan equation which utilizes overburden core-derived porosity and permeability, was used to construct "Flow Zone Indicator" (FZI) curves. The resulting curves were related to other log attributes using a quantitative probabilistic model to predict hydraulic flow units (and permeability) in wells that had poor or no care recovery. Groupings of flow zones, derived by histogram analysis, were found to be generally coincident with intervals of rock types derived from lithological and paleoecological interpretation. Involving more than just magnitudes of permeability, hydraulic zones provide a fundamental unit for subsequent reservoir characterization and simulation. Discrimination of flow zones will also prove to be helpful in defining future well completion and workover practices. Introduction The Hibernia Field is an offshore oil development located in 80 metres of water, 315 Ion ESE of St John's, Newfoundland. Following its discovery in 1979, nine appraisal wells were drilled from 1980 to 1984. Construction of the Gravity Base Structure (GBS) production platform started in 1990, with initial production scheduled to start in 1997. The Hibernia structure is a complexly faulted, rollover anticline created or influenced by extensional faulting and salt diapirism. The primary reservoir, contained within the Early Cretaceous Hibernia Formation, occurs at an average drill depth of 3700 metres. Of the seven wells which tested the reservoir, five were cored. Sedimentological interpretation of 386 metres of recovered conventional core indicates the Hibernia Formation to be a preserved fluvially-dominated deltaic complex. Quantitative core analysis of 143 metres resulted in reservoir property ranges of 14.5 to 18 percent for porosity, 150 to 2000mD for permeability, and an average water saturation of 13 percent. An integrated geophysical and geological study resulted in the mapping of a reference case distribution of an oil in place resource estimated to be 1.4 billion barrels. As part of a reservoir characterization process, HMDC and CORE Lab investigated the petrophysical attributes of the Hibernia Formation with regard to identifying flow zones. The results of the study provided an alternative assessment of the wells, complementing traditional log analyses that had been done previously. The objectives of the study were twofold: To identify flow zone indicators (FZI) that would characterize the cored intervals in the Hibernia reservoir.

Abstract Horizontal drilling is a core technology for reservoir development. This paper is an overview of today's horizontal drilling technology and a discussion of how the technology may be used in the future, The following technologies will be discussed: Geosteering. Most horizontal wells drilled today are placed in the reservoir based upon reservoir or geological parameters. MWD logging tools are being used to guide the well path as the well is being drilled This paper will discuss the various logging sensors available and how they can be used for geosteering Under balanced Drilling Systems These systems are being developed to minimize formation damage and ensure that the maximum production potential of each horizontal well is realized. Under balanced drilling is being used primarily in pressure depleted reservoirs. This paper will review the different techniques being used and discuss the relative merits of each. Multiple Lateral Wells. These wells are being used to drain single reservoirs more efficiently and to drain multiple reservoirs. Use of multiple laterals can also reduce the number of surface locations, which lessens environmental impact and reduces overall project cost, The multiple laterals can be drilled using either open hole sidetracks, or newly developed casing systems that will permit controlled reentry into each of the laterals. This paper presents an overview of the types of wells being drilled today and discusses potential uses of the technology in the future Short Radius Drilling Systems. Short Radius Drilling Systems have been in use for many years. These systems have, however, had some significant limitations. New systems have been developed which include MWD tools for steering control, The development of composite fibre drills/ring components will permit the use of steerable systems for drilling the horizontal interval. This paper discusses the potential uses of short radius systems and how they will interface with other emerging technologies. These emerging technologies enhance the production capabilities of horizontal wells making them more effective for oil recovery than conventional vertical wells. In addition to improved recovery, field development costs are often reduced since fewer wells are required to drain the reservoir. The above emerging technologies will have an impact on the number and type of horizontal wells drilled in the future. Introduction Until 1994, the number of horizontal wells drilled in Canada had approximately doubled each year (Figure I). For 1995, approximately 900 to 1000 horizontal wells will be drilled, which is similar to the number drilled in 1994. Most horizontal wells are development wells. When the number of horizontal wells drilled is compared to the number of development wells drilled, we notice that horizontal wells are becoming a larger percentage of the development wells. This would tend to indicate that horizontal drilling technology is becoming or has become a core technology for reservoir development. Horizontal Drilling Trends The following horizontal drilling trends have been observed: an increase in build rates a reduction in hole sizes an increase in re-entry drilling an increase in geosteering The first three are related while the fourth is influenced by the first three.

Abstract The process ofinjecti1lg water above the fracture opening and closing pressure (P foc ) has enjoyed liberal use and abuse. Since injection above (P foc ) is rarely designed for, it has received little attention from a modelling perspective. Recent interest, particularly in the North Sea in the design and implementation of pressure induced fracturing, has resulted in a series of numerical simulation studies that investigate this process in detail. The work has identified both pros and cons for pressure induced fracturing. Water flood projects can benefit from increased injectivity improved frontal contact area and increased producer to injector ratios, all of which can lead to improved economics. Potential pitfalls include reduced areal sweep efficiency, loss of injected fluids to up/downhole thief zones and wellbore failure due to altered stress states. This paper describes the techniques used to analyse lab data and field tests that can be used to help design and evaluate pressure induced fracturing. Both numerical modelling and field examples will be used to demonstrate the factors controlling fracture geometry, growth rates likelihood of length stabilization and more. Introduction Injection of fluid under fracturing conditions occurs when the bottomhole pressure exceeds the fracturing opening and closing pressure. This situation has been traditionally avoided for fear of opening a fracture that could result in either a loss of injected fluids to another formation or generation of a fracture which, due to excessive length, could result in a loss of sweep efficiency and hydrocarbon recovery. The deliberate operation of injectors above P foc is rare and the modelling of the consequences even less common. Injection of low viscosity fluids, such as water, differs dramatically from traditional high viscosity fracture completion fluids, due to higher leak-off rates encountered in the case of water injection. Recent work in the North Sea has led to a new understanding of waterflood pressure induced fracturing and modelling techniques that can be used to predict fracture growth rates and geometries. Knowledge of such behavior can be used to the economic benefit of the operator by reducing the number of injectors required and by increasing recovery via contact of additional reserves. Due to the many parameters controlling fracture propagation, the evaluation of the problem is complex. A systematic evaluation of field tests, combined with numerical modeling can be used to quantify dominating parameters. This paper describes the nature of the problem and procedures which can be used to design for waterflooding above P foc Nature of the problem Semantics Since the fracturing industry is fraught with conflicting terminology the following brief review is warranted: Equations (available in full paper) The fracture propagation pressure (FPP) is the bottomhole pressure at the well under fracturing conditions. The minimum horizontal stress (σ H ) is the initial confining stress exerted on a vertical fracture. The orientation of σ H detennines the fracture orientatlon (perpendicular to σ H ). Values for σ H range typically between 14.7 and 21.5 kPa/m of depth (0.65 and 0.95 psi/ft) for vertical fractures.

Abstract A general analytical method is developed to calculate the potential in a rectilinear reservoir for any completion interval, well location, wellbore radius and drainage ratios. By I/sing a transformation rule, the cone shaped no flow boundaries are transformed into a straight line to transfer the reservoir domain into a rectilinear domain. This analytical solution, provides the exact solution for the potential distribution inside the reservoir due to the presence of the cone, the critical production rate the critical Carle height, the shape of the Carle, and the optimum penetration length and location for both single and double coning. Introduction The potential drop due to production from an oil reservoir causes coning of the underlying water or overlying gas towards the well It also causes breakthrough into the producer, if the production rate exceeds a critical value. To prevent breakthrough of the undesired fluids into the well, The production rate must be kept less than the critical rate. The critical production rate is not a unique value; rather it depends on the completion interval as well as the well location. Knowing the potential distribution in the reservoir One can calculate the production rate and cone height. On the other hand, the potential itself depends On the shape of the cone. Once the cone forms, the domain ceases to be rectilinear. Therefore, the potential, which is a solution of Laplace's equation, can not be solved for deformed boundaries. In most analytical solutions, a simplified model has been used. Muskat et al. 1 employed the potential for a rectilinear reservoir2 to study the water coning problem. Wheatly 3 , who first considered the W.D.C. (water and oil contact) as a stream line, developed a method to calculate the critical production rate. In this investigation, The potential distribution due to any arbitrary well completion interval and location with a constant potential at the wellbore in a rectilinear reservoir is studied. The results and outcomes are presented in Section 1. To consider the effect of the presence of the cone on the potential, a transformation rule is used to transform The deformed domain into a rectilinear one. Coning studies and the transformation rule are discussed in Section-2. Coning phenomena, and its basic concepts were first explained by Muskat et al. 1 . The potential due to a partially penetrating well in a rectilinear domain was used to calculate the critical production rate. This study was only undertaken for a limited number of penetration depths and drainage ratios. The authors did not consider the effect of the presence of a cone on the potential. However, they explained that their results would have been lower if the water cone had been considered. Previous studies Arthur 4 modified the potential values presented by Muskat 1 for wellbore radii and drainage ratios, and presented the production rate calculation through a series of graphs. Meyer et al. 5 , assuming that the bead of the cone reaches to the bottom of the producer at breakthrough, employed Hubbert's definition for potential and presented an equation to calculate the critical production rate.

Abstract Split title leases in which oil rights and gas rights are divided, have resulted in disputes over solution gas ownership. A recent judgment of the Alberta Court of Appeal in Prism Petroleum Ltd. et al v. Omega Hydrocarbons Ltd. 1 affirmed earlier decisions including the Borys 2 case. This paper discusses some of the relevant engineering and legal issues, including issues that have not been fully addressed or resolved by the recent court decision. Engineering issues include terminology, PVT behaviour, producing mechanisms, the significance of an initial GOR, how gas is evolved in the reservoir, concurrent production, classification of oil and gas wells, enhanced recovery requirements, solution gas conservation, and the effects of offset production. The impracticality of periodic testing of reservoir conditions is outlined. Legal issues include previous case law, the specific wording of the lease considered in the recent decision and its interpretation. and issues where some uncertainty remains. These issues include the responsibility for costs of drilling, completion, surface facilities and operations where there has been a trespass or conversion, the related issue of unjust enrichment, estoppel (by deed, conduct and representation) and limitation periods_ It is suggested that improvements could be made to agreements to more clearly define oil and gas rights. Organization This paper represents the experience gained in preparing for a specific litigation case. It has, however, been written lo address problems that can arise in general. The organization is therefore as follows: Split titles and how they arise is outlined; A basic explanation of the relevant engineering issues; The general legal issues are presented, followed by an explanation of these issues; The background, legal process, technical preparation, trial results and appeal decisions of Prism et al v. Omega 1 is discussed in detail; A number of issues that have not been resolved by the Courts are discussed; Recommendations and Conclusions are made. This paper has a number of purposes. First, to report the results of a recent decision. Second, we hope to show some of the problems that can occur with split leases and to provide an overview of a complex issue. Finally, we recommend some changes which may mitigate some of these problems. The paper is multi-disciplinary covering both legal and engineering issues. Wherever possible, an attempt has been made 10 make the paper suitable to be read by either discipline. The paper is not a substitute for legal or technical advice, and readers should seek such advice in relation to the unique circumstances applicable to their case. Introduction Split titles where the natural gas rights and the petroleum (oil) rights have been separated, occur from three sources: The Crown has the right to reserve either the oil or natural gas rights (egg. Section 92(2)(a) and (b) of The Alberta Mines and Mineral Act). Hence split leases or licenses may be granted by the Crown; An oil company may farm out a portion of its Crown Petroleum and Natural Gas (P&NG) lease 10 another operating company (or individual); On freehold land, The lessor may sell part of its P&NG rights and reserve the remaining portion.

Abstract Utilizing all information and technologies available is the key to successful application of horizontal wells in Oil industry. Recent advances in horizontal drilling, measurement-while drilling (MWD) and three-dimensional (3-D) seismic techniques have made horizontal well drilling a routine practice. In today's drilling decisions, horizontal wells are always strong alternatives to vertical wells. Due to higher costs associated with horizontal wells, proper selection of a candidate is a prerequisite. The use of a simplified or ‘generic’ model approach to estimate horizontal well performance for various reservoir drive mechanisms is discussed in this paper. Typical horizontal drilling projects are multi-disciplinary; involving geological, geophysical, reservoir, drilling, completion and production engineering support. A good geological description of the reservoir is critically important. Reservoir simulation and 3-Dseismic analysis can improve the chances of success. Improper placement of an initial horizontal borehole in the reservoir could lead to subsequent drilling of a second leg side/racking from the original hole in an attempt to find more productive reservoir rock. This could be avoided if effective geosteering and real-time control drilling were applied when drilling the horizontal section. If proven successful, this approach could be applied in exploration. Post-drilling analysis is also important to optimize and ensure future success of similar projects. Field examples are presented to illustrate the need for an integrated approach for horizontal well developments. Introduction The need for integrating advances in information technology, horizontal drilling technology, measurement-while-drilling (MWD), logging-while-drilling (LWD) and 3-D seismic is an important aspect of making horizontal drilling a routine practice. Numerous technologies are converging which can significantly decrease the cost and improve the effectiveness of horizontal well development. These include advances in bit and drilling motor design, MWD Data gathering, transmission and processing, vertical well re-entry options, geological computer applications and geosteering. Information technology ties together advances in3-D seismic, logging and geosteering with real-time control drilling and computer visualization techniques to precisely track bit location and minimize the need for sidetracking. Applications of current communications technology could permit experienced home office personnel to assist field drilling personnel in real-time adjustments of drilling operations. The resultant increase in drilling speed and accuracy, and the effective processing and interpretation of substantially larger amounts of drilling data, should minimize exposure of the horizontal wellbore to drilling fluids and over pressurization, reducing drilling and completion costs and minimizing wellbore damage. Cost control is critical in older and depleted reservoirs, where vertical wells are not economic and horizontal wells can be justified only if they perform up to expectations. In many cases vertical wells are have watered out and precision drilling is necessary) to control or delay water production in these oil-over-water reservoirs. Recovery of additional hydrocarbons can be accomplished in these reservoirs, with the proper application of horizontal drilling technology. The business environment is also changing rapidly the ongoing process of downsizing, "de-layering" and mergers has created a need for rapid and accurate screening of horizontal well prospects.

Abstract Reservoir wettability characterization is often important for planning and predicting depletion strategies, including primary and enhanced recovery schemes. This paper compares wettability evaluations of water-advancing contact angle (WACA) using the recently developed "Dual-Drop- Duo-Crystal (DDDC)" technique(l) with the traditional "modified sessile drop" procedure. The DDDC technique was found to be a more reliable method for the Elk Point crude oil/brine/rock systems. The DDDC experimental procedure is less time consuming because this technique achieves rapid adsorption equilibrium between two crude oil drops and two crystal surfaces. Moreover, if is reproducible as it is designed to overcome the difficulties commonly associated with the traditional contact angle methods. On the basis of the DDDC contact angle experiments, conducted in 1993, it was concluded that both the Lindbergh and Frog Lake Cummings heavy oil reservoirs of the Elk Point field exhibit intermediate wettability near the native resen10ir conditions (characteristic of primary depletion). The water-advancing contact angles for the crude-oil//brine/quartz systems (near the reservoir conditions of 4400 kPa and 28 °C) were determined to be 92 °and 90 ° for Lindbergh and Frog Lake, respectively. These angles were reproducible within 1 °. This reproducibility is the result of meticulous application of water-advancing contact angle definition by means of a procedure that recognizes the effects of adhesion and buoyancy and allows shifting of the lower crystal so that the brine advances over an area that was previously exposed to crude oil. In addition, careful monitoring of three-phase (oil/water/solid) contact line (TPCL) movements ensures conformance to the definition of water-advancing contact angle. Contact angles at elevated temperatures were also measured using the DDDC technique. The results showed that the Frog Lake system shifts to oil-wet behaviour at a temperature of 97 °C or higher. Introduction Reservoir wettability characterization is important to nderstand fluid flow, recovery mechanisms and production behaviour of petroleum reservoirs containing either light or heavy oil. A knowledge of reservoir wettability is also required to design drilling and completion programs to avoid formation damage as well as under-balanced drilling, particularly for horizontal wells. Reservoir wettability plays an important role in such tertiary recovery processes as gas injection (miscible/immiscible) and chemical flooding as well as thermal EOR processes for heavy oils. The primary purpose of this paper is to analyze, evaluate and compare experimental procedures as well as contact angle measurement results of the modified sessile drop technique with those of the "Dual-Drop-Dual-Crystal" (DDDC) technique(l) based on the tests conducted on the Lindbergh Cummings heavy oil crude-oil brine/rock system. The DDDC technique was recently developed by the Petroleum Recovery Institute (PRI) to improve contact angle wettability characterization. Results from the DDDC technique for the Frog Lake heavy oil system at native reservoir conditions as well as at elevated temperatures will be discussed. First, a brief overview on reservoir wettability as currently encompassed by reservoir engineering practice is provided to give a perspective on the importance of wettability characterization (for laboratory and field practices), significance of water-advancing contact angle (WACA) definition and the status of wettability knowledge for heavy oil reservoirs.

Abstract An analytical composite model using non-linear least square regression technique for estimation of real parameters of naturally fractured reservoirs, utilizing well test data is presented. The problem of alteration of fracture properties due to acidizing or damage called by drilling fluid is taken into account by introducing two concentric media of different fractures. In this work correlations amongst fracture permeability and porosity, ω, λ, skin factor and matrix block size together with field examples are also presented. Introduction The double porosity models presented by Barenblatt et al l and many others 2–4 treat naturally fractured reservoirs by superimposing two continua, One for the fracture system and another for the porous matrix. The flow of fluid in the fracture system toward the wellbore is assumed to be radial. This holds only for infinisimal matrix block dimensions. For real cases where the matrix blocks are of finite dimensions, several fee~ the flow in the fractures near the wellbore is linear. It has been shown 5 that the pressure drop in the fractures with linear flow is less than the pressure drop caused by a radial system with a bulk permeability identical to that of the fractures. This is why the analysis of well test data obtained from naturally fractured reservoirs usually show negative skins by semilog analysis. The flow behavior of a two dimensional fracture network with nonporous identical parallelepiped matrix blocks under steady state conditions 5 has shown that the negative skin is proportional to the logarithmic of the matrix block size and the flow system starts exhibiting radial flow behavior from a radial distance of one matrix block from the wellbore. Drilling and workover operations may alter the width of the fractures around the wellbore resulting in two damaged and undamaged zones. The damage zone may be assumed circular and the fractures in this zone of uniform thickness. In order to study the behaviour of the flow system with the above mentioned features a composite model consisting of three regions is considered. Composite systems have been the subject of considerable attention in the petroleum literature. In general, the composite model consists of a well completed in the centre of a circular inner region with fluid and rock properties different from those in an outer region. This approach has been used to study interference between oil fields in a common aquifer of different permeabilities6. A two region composite model has been used to study the behavior of wells intersected by fractures extending over a limited area 7 , It also has been used to study the behavior of wells intersected by infinite conductivity vertical fracture in dual porosity reservoirs 8 . In this work a general flow equation for a composite system consisting of three (inner, intermediate and outer) regions is presented to describe the near wellbore linear flow and the outer radial flow in the two damaged and undamaged regions.