Abstract There are three critical elements to success in the oil and gas industry. People, Opportunity, and Capital. It's obvious that capital is required in any venture but what prompts us to raise capital? Opportunities and ideas promote the need for capital. These ideas and opportunities are derived from a very important source, one that is often overlooked, seldom credited, yet essential to the equation. The source is people. They are the creators of opportunity. They contribute the largest amount of time, energy, and talent to any project. Without people, the opportunities we all enjoy would not exist. All data and ideas are useless without people. Geophysics just a bunch of squiggly lines, pressure build-ups just a graph. To make successful use of the myriad of information available today, we need very qualified people. Many of us spend countless hours looking at the bottom line. How many of us take the time to examine the people behind the line. These are the assets of our companies. A simple equation in cost analysis can demonstrate the cost effectiveness of people. Ideas equal opportunities, which require capital. They create, produce, and market our organizations. It's simple to see that people, opportunities, and capital are synonymous with success. It is important to spend as much time finding effective people as we do looking for new ventures and capital gain. People will provide the opportunity we seek and the potential for the future. When we think or talk about the "bottom line", we often think only of quarterly or yearly financial statements. This is probably quite true considering the way these words are used by the general public and the media, but there are many aspects to the bottom line of which this is just one. Some cultures have a financial bottom line which, is not measured in months or years, but in decades and generations. Another bottom line is shareholder value and increase in stock price, which may not be related to earnings, the usual bottom line, but to prospects of future growth. Some other bottom lines might be an enterprise's contribution to the community and its regard for people, safety, and the environment. In analyzing the critical elements of success in oil & gas, the three most important seem to be Opportunity, Capital and People. Opportunity is the door through which the capital and people move to perform their work. Most people, when they look around, see more opportunities than they can deal with. The opportunities may be oil & gas geological prospects, an asset that one may be available for purchase or a supply opportunity for a new product or service. People who can visualize the value of moving ahead with projects, or of providing a service, evaluate, select and develop these opportunities. Capital, the second spoke in the wheel of success, is also very tied to the human component. Capital will flow to projects, services and businesses where there is a potential for growth.

Abstract The Canadian Oil and Gas industry is quite unique in many ways. Out of this uniqueness there has been significant growth among emerging technology-based companies in Canada. Consider that the Canadian oil patch is spearheading applications of horizontal drilling, coil tubing, underbalanced drilling and the top drive system. Although innovations in these emerging technologies are focused on drilling applications, it is the author's assessment that similar innovative approaches for production applications will come out of Canada. Reservoir management and production optimization (RMPO) is less glamorous and often returns on the work are long-term in nature. This paper attempts to list necessary ingredients for an emerging technology for RMPO applications. After carefully examining the cost structure of production and a typical production operation, key functions that must exist in order to achieve the producers' objective, which is to "produce more while reducing the cost to produce," are listed. Introduction The Canadian Oil and Gas industry is going through stages of development at a fast pace. As described in the book "Corridors of Time" 1 , the development of Canadian Oil and Gas can be traced back to the 1800s. However, significant progress started in the early to mid-1900s. Uniquely located right next to the world's largest economy, i.e. the United States, Canadian Oil and Gas has been able to accelerate the industry's development. Today, the rate of decline 2 in the overall reserve of both oil and gas in Canada (excluding the oil sands) has become rather steep, with the new finds often small and marginal. In addition, the attention of major oil and gas producers is moving from conventional oil wells to oil sands, even while overall oil sand economics is still in the process of being improved. The associated economic factors force the industry to make decisions involving a new paradigm by which to maintain sound economics in the business. On one hand, the Canadian Oil and Gas industry appears to be going through similar stages of rise and fall at a faster pace than in other parts of the world. On the other hand, Canadian Oil and Gas is producing a phenomenal level of business success and opportunity that is closely tied to technological innovations. The Canadian oil patch was first in the world to embrace horizontal drilling, coil tubing, UBD (underbalanced drilling), rotating blowout prevention and top drive. Despite the fact that many technical papers and works were presented earlier in other parts of the world, it was in the Canadian oil patch that these innovations turned into successful businesses. One peculiar fact is that the innovations which have surfaced so far are primarily related to exploration (mainly drilling) activities. These innovations are induced by many factors in the industry environment. Observable factors are: The geographical location of Canada being adjacent to the United States is preferable both economically and technologically. There is also willingness in the industry to readily accept a new approach/technology when the economic benefit is measurable. Depletion in oil and gas is steep.

Abstract The success of stimulation (fracturing) treatments can be greatly improved by using real-time modeling and optimization techniques. With increasing workloads in the office and budget restraints, both service and producing companies search for more cost effective and reliable alternatives to on-site fracturing engineering. One alternative is to monitor a fracture from the home office using communications to deliver the required real-time data. With limited coverage in many areas of Western Canada, cellular communications is not consistently reliable. As a result, communications shifted to geosynchronous satellites and new technology was developed to allow remote, real-time monitoring and optimization of well site stimulations. The new technology addresses the major issues such as data integrity, communication protocols, and confidentiality. To date, in excess of 300 treatments have been monitored using the satellite system. A case study for a stimulation treatment was conducted and is presented. Introduction As with most companies who are involved with production, oil and gas producers are constantly looking for ways to improve productivity and reduce costs. This applies to all phases of well development including hydraulic fracturing treatments. Major gains in productivity were achieved with the introduction and evolution of computer systems as part of the fracturing process. Computers provide the tools for data collection and treatment analysis. Data collection computers used in conjunction with real-time modeling software give the service company the ability to generate a downhole "picture" of the fracturing treatment. Along with a downhole picture, the modeling software generates trends that allow engineers to make "on-the-fly" changes to a treatment for optimum results. Engineers at the well site interpret the data being modeled and provide guidance during the fracturing process. Further gains in cost reduction and productivity would occur if the engineers who guide the fracturing process did not have to go to site but could guide from head office. The client and engineering staff would then monitor the fracture process as it was occurring without having to make expensive field trips. THE SOLUTION Original Fracture System To gather and display data from a stimulation treatment (Figure 1), a PC-based, software package (1,2) is used which gathers data from a number of site instruments. As it is gathered, the data is displayed and evaluated by using real-time software modeling packages (3,4) . The modeling packages reside on a separate PC. The data gathering PC communicates with the modeling PC through an RS-232 port. The data being transmitted is in an ASCII record format and has no protocol for integrity nor any data flow control. New Approach To allow the engineers to guide the fracturing process more efficiently, the modeling PC was moved to the home office. A fundamental requirement becomes reliable communications between the data gathering PC on site and the modeling PC in the office. Communications Cellular and satel1ite communications were both investigated. Since well sites are typically in remote areas where conventional communications such as telephone and cellular may be unavailable or unreliable, geosynchronous satellite systems were given preference.

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 Samotlor Services is an international joint venture formed by Canadian Fracmaster Ltd., PanCanadian Petroleum Ltd. and Samotlorneft (Russian operating company). The objective of the joint venture is production rehabilitation of a portion of the Samotlor field in the Western Siberian basin. Operating in the international environment poses many technical problems that can be amplified by language differences and translation problems. There are also cultural considerations between staff that create obstacles for providing timely technical solutions. A common link for problem resolution and developing teamwork is the establishment of jointly shared information that can be understood by all staff. Samotlor Services 1 engineerig staff in association with Lowe & Associates developed a data system that allows simple and rapid access of well and operational data by both English and non-English speaking technical staff. The data system has saved time by allowing expeditious generation of routine reports in a dual language format thereby facilitating faster data analysis of operating problems. An unforeseen benefit of the data system is that it has increased teamwork and synergism not only between the Canadians and the Russians, but also between the Russians because It allows data sharing by all technical staff. Additionally, engineers were able to take a proactive stance to problem resolution as opposed to the reactive process that previously existed. This paper will discuss: Operational considerations associated with the international environment, Design and implementation of the data access and sharing system The areas that were optimized as a result of the data system Recommendations for international operations Introduction With the globalization of today's marketplace, many companies are looking beyond domestic borders to expand their business opportunities. When operating in the international environment, there are many pitfalls and problems that staff can encounter. The technical tools and operating procedures that are taken for granted domestically are often not available, when operating internationally. This paper profiles from an engineering viewpoint, the design and implementation of a technical data system that operates in two languages in Western Siberia (Figure 1). Typical operations in the Russian oil patch will be discussed. Of interest to technical staff is the resolution of operating problems specific to translation procedures and cultural considerations. International joint ventures must deal with problems caused by cultural complications as well as language differences. These factors in conjunction with the logistical concerns can create a difficult business environment. Consolidation of information in a format that both cultures that can access and understand will resolve many problems associated with international joint ventures. The use of micro-computers can be used to resolve the data exchange problems in manner that was previously thought to be difficult or impossible. The use of a properly designed system can enable rapid collection of field data and divestment of this data as formal reports. A proper interface ith technical analysis programs will enable rapid analysis of data required for project optimization. Further, incorporation of query mode will enable the technical staff to analyze data in a format that is suitable for the engineer's objective.

Abstract Well test analyses are normally performed using a combination of type-cun1e and semi-log analysis. Unfortunately, calculated values of reservoir rock properties such as permeability (transmissivity) or near wellbore damage can vary by a significant amount between the two methods, Unless a history match is conducted, the best value to use is ambiguous. A practical approach is introduced in this paper which requires a single solution to two or more well test analysis methods, This is accomplished by coupling the multiple solution parameters to derive a testing criterion for a unique solution, i.e. first combining two equations into one, then using this single formulation to determine whether the analyzed data points meet certain requirements simultaneously between the two or more solutions. It is assumed that initial boundary conditions used in deriving the previously separate solutions are the same or very similar. Two examples are presented, one from a high transmissivity groundwater flow (water source) and one from a low permeability oil sands reservoir. The purpose is to demonstrate the universality of the method and show the actual change in results. For example, a previously reported value of formation compressibility was changed by 100 percent. Introduction We present a new, practical approach to well test analysis with the intent of improving the confidence in, and the accuracy of, reservoir properties generated from such tests. Whether a geologist is analyzing a falloff well test from a permeable confined aquifer to estimate water supply or, an engineer is analyzing a production buildup test from a twenty-year old producing oil well, to identify any formation damage, the problems encountered during analysis are quite similar. Standard practice is to perform at least two types of analyses: type-curve fitting on log-log or semi-log paper and, semi-log straight line plots. One tries to arrive at comparable values for transmissivity (hydrogeological term) r permeability (petroleum engineering term) from each method and normally report what is thought to be the best answer. The method outlined below is intended to give a generalized approach to the coupling of H 2 O or more analytical techniques so that only one answer is feasible, while the requirements of curve matching or drawing of proper slopes are still met. The more unique the answer, the greater the confidence in using the values for formation and economic evaluations. The technique used to essentially lock analysis methods together is described by example rather than as a stepwise procedure, the reason being that each set of analysis pairs, or groups, usually provide a slightly different or even uniqueapproach to obtaining the correct solution. For example, nalysis could concentrate on time intercepts rather than pressure match points or slopes. Two examples are presented here, the first is well testing from a hydrogeologist's view of flow through an aquifer and the second is well testing from an engineer's perspective on water (or steam) injection into a highly oil saturated, very viscous oil sands reservoir.

Abstract Engineers routinely use heavy oil viscosity as one criterion for selection ofoptimum heavy oil exploitation methods, and to help predict the resultingproduction rates and project economics. Recent field and lab data suggest theseuses of oil viscosity haw been both over simplified and over valued. This maybe particularly true for empirically derived exploitation methods such as coldproduction using progressive cavity (PC) pumps. In some cases the consequencesof this misuse were poorer than expected field results and an anti-heavy oilsentiment among management. Techniques for obtaining the most representative heavy oil Viscositymeasurements for a reservoir are discussed. Topics covered include: sampling, handling, cleaning, lab procedures, oil compositional effects, live vs dead oilviscosities, and oil viscosity variation within a reservoir. This informationcan be used to determine if the existing oil viscosity data are valid, and toprovide guidelines for future heavy oil viscosity measurements. Introduction Western Canadian heavy oil and bitumen reservoirs have been exploited withvarying degrees of success for more than 45 years 1 . During that timeproducers searched for easily measured parameters that allowed accurateprediction of oil production rates and cumulative volumes. Oil viscosity hasbeen used for this purpose, but the accuracy of the resulting productionforecasts was often disappointing. From the perspective of the engineer, understanding and trusting viscosityvalues is challenging. He or she probably has a limited background in organic, physical, and analytical chemistry, and little time for formal training inthese areas. This situation is likely even more difficult in smaller oilcompanies, where in-house experts are not available for consultation. Ifviscosity data exist, but you feel they may not be accurate, another challengeis management's tendency to resist spending money for ‘duplicate lab tests’ orfor more costly ‘excessively rigorous’ data collection methods. This study was conducted to address these concerns. The selected approach wasto de-emphasize theory, as it is well documented in theliterature 2–4 . Instead, we have emphasized a practical approach foruse by production and reservoir engineers. Factors other than viscosity that affect heavy oil and bitumen producibility are not considered in this paper due to spaceconsiderations, but the reader should be aware of them. Examples are: reservoirheterogeneity 5 , water encroachment 6 , formation of viscousemulsions 7 , pumping problems 8 , and scaleformation 9 . Recommended Procedures For Heavy Oil Viscosity Measurement Sampling General Considerations: If your employer is not willing to pay for a'best effort' collection of a representative sample, there is little point inconducting an oil viscosity study. The viscosity obtained will be more likelyto mislead than guide you. Unless you are willing and able to go to the field and collect the sample(s)yourself this exercise must be entrusted to field personnel. The best methodof assuring the task is completed correctly is through clear communication.Everyone is busy in the leaner oil patch, and staff must be informed of thesignificance of the procedures you request.

Abstract A number of articles and books have been written about evaluating and assessing the risk and uncertainty associated with oil reserve evaluation and acquisition. Very little has been included in the standard texts regarding evaluating Enhanced Oil Recovery (EGR) projects in particular miscible floods. Due to the size and scope of most tertiary recovery projects, standard evaluation rules and techniques are too general and vague to adequately model these schemes. Therefore, it is incumbent upon the Engineer to familiarize himself with the risks and uncertainties associated with a prospective EOR project This paper presents a procedure for identifying the risks associated with miscible EOR projects. And moreover, evaluation techniques will be discussed which will assist the analyst in evaluating, qualifying and quantifying the uncertainties associated with EOR. Introduction Acquisitions of oil and gas properties at the moment appear to be a highly favoured method for companies to increase their own reserve base. There have been a great number of acquisitions in the last two years and this trend is likely to continue into the future. In Canada, acquisitions and divestitures include EOR projects, particularly miscible flood schemes. Evaluating these projects is complex. The objectives of an Evaluation Engineer have changed little since the first evaluation was reported in 1928 1 . The basic tool for the evaluator is, and will continue to be, Cash Flow analysis. Determining the parameters involved in setting up a Cash Flow model is based on sound engineering principles and good business judgement. An evaluation needs to answer fundamental questions 2 : What will be gained if a venture is successful? What is being risked and what are the uncertainties? What is the probability of success? Answers to these questions are the basis for Cash Flow model and analysis. Basic components of the Cash Flow model are: production forecast, revenue generated by production, expenses and capital incurred recovering production, royalty, taxes, incentives and the relation of present value techniques (ie discount rate). Each of these components require certain definitive evaluation techniques pel1aining to and associated with miscible flood projects. An analyst must use sophisticated evaluation techniques to determine the fair market value or viability of an EOR project. The intricacy of a miscible flood project magnifies the complexity of an evaluation. Frequently, time and budget constraints placed on an analyst rule out the possibility of a complete simulation study to aid with an evaluation. Thus there has to be considerations that sUPPOI1 the development of an evaluation format which will prudently and adequately represent the performance of a miscible EOR project. Miscible Flood Methods Evaluating an active miscible flood involves determination of the miscibility criteria that were originally established for the project. For example, "Is the project first contact (FCM) or multi contact (MCM) miscible?", and "Is the solvent vaporizing or condensing?" In general if a reservoir has high pressure a leaner (lower molecular weight), less expensive solvent might be used to achieve miscibility.

Abstract As reserves dwindle and exploration/development cost escalates particularly in frontier regions, the need for effective prevention and/or treatment of formation damage to maximize well productivity, has become apparent to prudent operators. This paper discusses economic implications, reviews various origins and forms, and provides methods for recognition of formation damage. Geological and engineering tests for proper assessment of the problem, and optimization schemes for effective solution are also described. Introduction Formation damage is a condition which occurs when barriers to flow develop in the near-wellbore region to give rise to a lower than expected production rate from or injection rate into a hydrocarbon bearing reservoir rock. This problem has been recognized for several decades as a major contributor to anomalous production and/or abnormal decline in productivity or injectivity in hydrocarbon reservoirs. Many potential pay zones have been misdiagnosed as nonproductive, and payout on investment has been delayed because or formation damage. Understanding formation damage requires a multidisciplinary approach that involves such diverse specialty fields as inorganic/organic chemistry, physical chemistry, colloid and interfacial sciences, chemical kinetics, mineralogy, diagenesis and fluid transport through porous media. Unfortunately, the primary interest of the various field groups involved in reservoir definition and exploitation often seem to be in conflict. For instance, the driller is typically interested in reaching the targeted depth quickly(increased ROP), and safely (overbalance pressure condition), while maintaining a gauged bole. Avoidance of formation damage when appears to be of secondary concern. However, if a project team is formed at the outset to include drillers, mud engineers, geologists, production and reservoir engineers, then proper objectives of a safe drilling program can be set to protect the formation and to ensure that the reservoir will be exploited to its maximum productive capacity to generate a maximum return on investment. Once, formation damage has occurred, proper assessment and Treatment will require the cooperative efforts of geologists and engineers both in the field and in the laboratory. This synergistic approach is necessary to develop effective solutions to this expensive problem. Better understanding of the mechanism of formation damage is required in order to develop effective preventive and mitigative procedures. With recent advances in technology, laboratory geological and engineering measurementscan provide the necessary insights into the mechanism, prevention and effective treatment of formation damage. ECONOMIC IMPLICATIONS OF FORMATION DAMAGE Formation damage is a very expensive headache to the oil and gas industry. Before the drill bit penetrates the reservoir domain, the reservoir rock and its constituents minerals and resident fluids ore essentially in a state of physico-chemical and thermodynamic equilibrium. This equilibrium is disturbed during the drilling process when extraneous mud solids/fluids are introduced into the wellbore giving rise to pressures in excess of the reservoir pore pressure. The resultant differential pressure, usually referred to as overbalance pressure, promotes the invasion of fine colloidal materials and filtrates into the near-wellbore region of the formation where they reduce the intrinsic permeability. An artistic rendition of a wellbore model with associated mud and filtrate invaded zones is shown on Figure 1.

Abstract Vapour-liquid equilibrium properties of methane-Cold lake bitumen and ethane-Cold lake bitumen mixtures were measured using a modified Ruska rocking cell apparatus. The measured data of these two pseudo-binary systems at three isotherms were used to develop a predicting method by means of equations of state. Two equations of state; the modified Soave-Redlich- Kwong and the Peng-Robinson, were chosen in this study. With an appropriate choice of bitumen characterization parameters and binary interaction coefficients, it is shown that both the equations of state can adequately represent the vapour liquid equilibrium properties of the two systems studied. Binary interaction coefficients of the modified Soave-Redlich-Kwong equation of state for the two systems were determined and correlated with temperature. Introduction Methane and ethane are commonly found in the native Cold Lake oil sands bitumen and these gases are considered as possible additives to the steam-based in situ bitumen recovery methods. Thus, the phase behaviour of the methane-Cold Lake bitumen and the ethane-Cold Lake bitumen mixtures under in situ conditions are important to reservoir engineers for determining the recovery of bitumen from the oil sand deposits as well as to process engineers for developing an adequate numerical simulation model. However, the experimental data for these systems are not reported in the literature. One of the major objectives of this study is to measure the vapour liquid equilibrium (VLE) properties of methane-ColdLake bitumen and ethane-Cold Lake bitumen mixtures. Experimental measurements are time consuming and costly for the bitumen containing systems. For the purpose of data reduction, it is desirable to find methods which can predict the VLE properties for these systems with high accuracy. In this investigation, two cubic equations of state were selected for the purpose of representing phase equilibrium properties. These are the modified Soave-Redlich-Kwong (MSRK) equation of state 1–3 and the Peng-Robinson (PR) equation of state 4,5 . A commercially available "EQUI-PHASE" software package developed by he DB Robinson & Associates 6 6 was applied in vapour liquid quilibrium calculations for the PR equation of state. Calculations were also performed with PR equation of state using the bitumen characterization parameters developed by Fu et al. 10 and binary interaction coefficients determined in this study. The VLE properties measured in our laboratory compared to the calculated values for the two systems using both equations of state. EXPERIMENTAL ASPECTS Apparatus A schematic diagram of the apparatus, which has been verified for VLE measurements in the previous study 7 , is shown in Figure 1. The apparatus consists of a charging and discharging unit, a constant temperature bath with a rocking equilibrium cell, and a sampling and analysis unit. The heart of the whole apparatus is the equilibrium cell which is located in the constant temperature bath container as shown in Figure 2. During the measurement, the rocking cell, 4, is driven by a motor, 2. while the stirrer, L circulates the bath oil and keeps the oil in the tank homogeneous. In this design, the temperature was tested up to 423.2 K with an accuracy of ±0.01 K and the pressure range tested was 13.8 MPa with an accuracy of ±1.0 KPa.

Abstract The recovery of bitumen from oil sands deposits, such as those at Cold Lake, Alberta, is ultimately dependent on the ability to inject large amounts of steam into the ground. Oilfield steam generators have been used to provide this steam for many years in heavy oil fields in California, Venezuela and Western Canada. This paper describes some of the factors to be considered in the design, construction and operation of these once-through steam generators. In particular, the design parameters which define the size, shape and ultimate performance of very large steam generators will be outlined with reference to some of Esso Resources Canada Limited's requirements for the Cold Lake area. One of these requirements is that the generators must be designed to permit the reuse of produced water, an essential water conservation measure. Esso currently has three of the largest once through generators in the world installed at the Leming Pilot Plant near Cold Lake. Two of these units have been in continuous operation for over two years, generating steam from treated produced water. A third unit was installed in December of 1983. These units are prototypes of the steam generators to be installed in the phased Cold Lake Production Project (CLPP) which is currently under construction. Introduction This paper discusses the design considerations for very large steam generators, such as those which Esso is currently using at Cold Lake. Many steams generator vendors in the past have given written papers on the same topic. However, I will be addressing the design from the point of view of the end user, rather than the supplier. First, I will review the general reservoir and process requirements which set the basic design parameters in all oilfield steam generator applications. Secondly, I will review the main steam generator design parameters which define the size, shape, performance and operation of steam generators for thermal recovery operations. This will include some discussion of the basis for the specifications of the very large steam generators installed at Esso's Pilot Plants and planned for our Cold Lake Commercial development. Finally, I will review some of the equipment options which are available on the market, and where these options can best be applied. I. Application The main design parameters are usually specified by the Reservoir Engineers and Geologists who evaluate potential oil sands leases for possible development. After finding a suitable site for a heavy oil production project, they have to come up with a development plan. They decide how many wells will be drilled, the pattern of drilling and spacing. Usually, the capacity of the steam generation facility will then be based upon a calculated injection rate per well or an overall expected oil/steam ratio. As well as capacity, they would also decide on an injection pressure and steam quality (i.e. the percent of the injected water that is in the vapor phase). If the reservoir oil is mobile, a steam flood may be suitable with relatively low injection pressures, rates and steam qualities to aid displacement and prevent steam breakthrough.

Abstract An analytical method based on the finite element variation principle and fracture mechanics is proposed to assess the in-situ fracture of oil sands formations. The concept on which the method is based involves the optimization of: (1) the wellbore geometry with "fracture starters", and (2) the stress fields ahead of the crack fronts produced by the optimized fracture driving forces originating from the fracture starters. The primary function of the fracture starters is to control the direction of the initial crack propagation, while the driving forces will create desirable stress fields ahead of the propagating crack, and thus control the subsequent propagation paths. While there is no explicit fracture criteria available for the in-situ oil sands at the present time, two models for determining oil sands fracture are proposed. Numerical results from a case study will provide engineers with a comprehensive description of the fracture pattern in the oil sands formation with given geometries of the wellbore and the fracture starter, as well as the loading history. It will be demonstrated that extensive horizontal fracture is possible with particular combinations of initial geometry and loading conditions. Introduction The enormous amounts of deep oil sands reserves make a suitable in-situ recovery technique extremely attractive. There are however, two major problems associated with this method [1,2]: These are: (1) the lack of communication between wells, due to low effective permeability of the deposit; (2) the high viscosity of the in-place bitumen. The methods which are currently used to overcome the first problem include [3 – 5]: inducing hydraulic fracture by hot steam or cold gelled water; using natural communication channels, e.g., a high permeability water zone; using existing solid permeability, if it exists. In some areas where a zone having a high water saturation underlies the oil sands formation, it is possible to heat the oil zone by heat conduction from the steam flooded water zone without fracturing the formation. This approach, however, requires a thin water zone underlying a relatively thick oil zone. Such a condition exists only in a few areas among the vast oil sands deposits in Canada. For the majority of Canadian oil sands in-situ projects which have been carried out or have been planned for, a type of hydraulic fracture process has been included as a necessary first step for inter-well communication which facilitates, mainly through heat conduction, a more efficient mobilization and displacement of the oil. However, in most cases it induces a limited fracture system through which fluids could flow. Consequently, in some cases, sweep efficiency tended to be very low [2,6]. Many in-situ processes such as fire flooding, in-situ combustion, in-situ hydrogenation, and the use of an aqueous emulsifying fluid have been considered as potential recovery tools of viscous fluids. However, such processes necessitate a prior extensive fracture of the sands in order to provide the necessary distribution of the active agent, a condition which is not provided by the classical hydrofracture processes.

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 Inflatable packers have been used in the oil field for many years. The primaryadvantages are that they do not require weight to expand and that they are morefunctional in larger, washed out holes than conventional weight operatedpackers. Their use in drill stem testing requires the application of a downhole pump since surface pump pressure cannot be utilized with an empty orpartially empty drill pipe. A new inflation type testing packer system has recently been introduced withexcellent success and customer acceptance. The purpose of this paper is todiscuss the developmental efforts and more specifically to describe the fieldexperience gained since introducing the system in August 1978. Introduction Drill stem testing has long been recognized as an effective method of formationevaluation and has progressed significantly since its introduction in 1926. Anumber of important characteristics of a prospective producing well can bedetermined by proper interpretation of data obtained from a drill stem test(DST). In open hole a DST is sometimes called a temporary completion because theformation is allowed to flow into the drill pipe in order to gatherinformation. Economy is a principal advantage of the DST since this procedureprovides information about a well's potential before the well iscompleted. Curves of pressure versus time and other data obtained during the various flowand shut-in periods of a DST, can be used to determine the static reservoirpressure, production rate, transmissibility, indicated flow capacity, averageeffective permeability, damage ratio, approximate radius of investigation andpotentiometric surface. This information plays a very important role indetermining the economics of completing a well. In addition, when a decision ismade to complete a well, the interpretation of a DST can often be of assistancein designing the completion and possible stimulation treatments used in puttingthat well into production. 1 In some oil and gas producing areas, including areas in the province of Alberta, hydrocarbon bearing formations are rather shallow and soft. Welldrilled in these formations tend to be washed out or over-sized. Conventionaldrill stem testing techniques might require relatively large amounts of pipeweight to obtain a good packer seat. Weight required will vary with the number, durometer and Size of the packer elements used, temperature, and other factors. In addition, the expansion of conventional testing packer elements is limited. These aspects of conventional drill stem testing pose particular problems intesting the shallow, washed out formations described earlier. In areas wherethese formations are present, DSTs can often be performed with inflatablestraddle packers. Such packers are inflated with the drilling fluid in the wellto be tested and this requires a special down hole pump. Pipe movement operatesthe pump which inflates and sets tile packers. Inflatable packers do notrequire pipe weight for setting and can expand much more than conventionalpackers. Thus, they are ideally suited for use in testing shallow, softformations.

Abstract The Alberta Oil Sands comprise the bulk of Canada's petroleum reserves. The bitumen in these deposits is too viscous to flow naturally and cannot be produced by conventional oilfield techniques. Where the deposits are close to the surface, mining can be employed to recover the Oil Sands. In many areas, however, the over burden thickness is such that in-situ recovery techniques provide the only means of recovering bitumen. This paper describes the drilling details of a well which will be used in an in-situ recovery pilot at Cold lake. The well, Imp 78 Horizontal Leming Ex 9-6-65-3 was spudded conventionally and then deviated so that its final wellbore path was horizontal in the Clearwater formation. Over 1000' of pay section was contacted by this well in a zone which is only 160' thick. Details about the well planning, drilling equipment, drilling fluid, survey program, casing and problems encountered are discussed. Introduction The Alberta Oil Sands are one of the world's largest known reserves of petroleum. The main deposits. Athabasca, Cold Lake, Peace River and Wabasca contain about 900 × 10 9 barrels, 95% of the petroleum discovered to date in Canada. The heavy oil in the sands is very viscous and cannot be recovered in its natural state by conventional production methods. The two commercial plants presently in operation surface mine the oil sands and upgrade the bitumen recovered into light oil. The reserves in the Cold Lake deposit (Figure 1) cannot be recovered by mining techniques because l000' of over burden overlies the oil bearing sands. Here, in-situ recovery methods provide the only means of extracting the heavy bitumen. There are many recovery pilots in operation in the area and most involve the application of external energy, such as steam, to reduce the viscosity of the heavy crude and allow production. To introduce heat into, the oil sands, vertical or moderately deviated wells are drilled into the oil bearing formation. Because the wells have limited drainage capabilities, the well spacing is closer than in conventional producing fields and large numbers of wells are required. A well ill which a large section of oil sand can be contacted may provide increases in both production rates and recovery levels. The only means by which such lengths of reservoir can be reached is with a highly deviated well which enters the reservoir at a near horizontal inclination. Imp 78 Horizontal Leming Ex 9-6-65-3 is such a well. It was spudded conventionally on March 21, 1978 and then deviated so that its final wellbore path was horizontal, 1558 below the surface. This paper discusses the methods and techniques employed to drill this well. PLANNING (a) Pre-Program Esso Resources (formerly Imperial) has operated pilot studies in the Cold Lake area since 1964. Over 100 evaluation wells and 190 pilot related wells have been drilled to date. The initial pilot wells were vertically drilled but more recent wells have been deviated up to 35 ° from vertical.

Abstract Fracture stimulations with foamed acid have een instrumental in significantly improving the producing rates of gas well is in the crossfield D-1 formation. Because of improved clean-ups after the treatment, well stimulations with foamed acids tend to give better results than conventional acid treatments, especially in reservoirs with declining pressures such as the D-1. This paper discusses various aspects of job design and summarizes treatment results. Introduction Amoco Canada Petroleum company Ltd is Unit Operator of the Cast Crossfield D-1 Unit located 25 miles (40 km) north of Calgary near the town of Crossfield (Fig. 1). The Cast Crossfield D-1 field was discovered in l960 and currently produces from 35 sour gas wells (Fiq. 2). In 1960, the East Crossfield Plant was constructed and the field was brought on stream. Although the plant is capable of processing 120 MMSCFD (3 2 × 10 6 m 3 /d) of some gas, the field Cannot support this inlet rate due to declining pressures and wellhead deliverabilities (Fiq. 3). As a result, an extensive stimulation program is being carried out to increase deliverability and optimize drainage of economic reserves. GEOLOGY AND RESERVOIR CHARACTERISTICS The Cast Crossfleld D-1 reservoir is made up of the Crossfield Member of the Stettler Formation in the Wabamun (D-1) Group and is of Upper Devonian Age. The Crossfield Member is a sour gas producing zone which averages 100 ft. (30.5 m) in thickness and varies in width from 2 to 12 miles (3.2 to 19.3 km). This geological feature extends in a north-south direction close to the Fifth Principle (Meridian of Alberta from olds to Okotoks, a distance of about 90 miles (l44.B km). The average producing depth of the East Crossfield D-1 reservoir is 8800 ft. (2682 m). The gas stream contains 39%, H 2 S, 10% C0 2 and 2% N 2 (Table 1). Approximately 4 barrels of condensate per MHSCF of gas (22_6 × 10 −6 m 3 /m 3 ) is also produced. The average reservoir temperature and pressure are 185 °F (85 °C) and 2050 psi (14 100 kPa), respectively. The Crossfield member is a shelf deposit between intertidal and supratidal anhydrite deposits to the east and all open marine basin to the west (Fig. 4). Gas comes from porous dolomitized stromatoporoidal and algal bank rock, Pores consist of vugs of algal origin and original stromatoporoidal organic porosity (vugular and pinpoint porosity) produced by ground water solution. Partial filling of the original pore spaces with calcite cement has greatly reduced total porosity and in certain areas of the field, has reduced effective porosity. Average porosity and permeability are 6.1% and 5.2 md respectively, with an average water saturation of 18%. Porosity footage and permeability footage isopachs of the D-1 for the East Crossfield field are shown by figure 5 and 6 respectively. Although the Crossfield D-1 reservoir has localized areas of high porosity and permeability due to vugs and natural fractures, drainage of large portion of the reservoir is largely dependent upon matrix permeability which is generally low.

Abstract Bank financing can significantly influence the economics and feasibility of purchasing producing oil and gas properties and the ability of a company to develop its existing oil and gas properties. The most: frequently used and conventional method of financing in the Petroleum Industry in Canada is through Section 82 of the Bank Act. The purpose of this paper is to briefly review the powers of the Bank under Section 82, the method of milking application for credit, the supporting data required and the type of interests that quality for Section 82 loans. Appraisal techniques for establishing loan values, repayment schedules and interest rates employed by Banks will also be presented. Section 82 OF THE BANK ACT In 1954, the Bank Act was amended by the addition of Section 82 Which empowered Banks to lend against the security of hydrocarbons in, under, or upon the gound in place or in storage. The security may also include the rights, licences, or permits to remove or s ell hydrocarbons and equipment and facilities used in producing and storing any hydrocarbons. Section 82 Security which can only be registered by a Canadian Chartered Bank (no other lending institution qualifies) is in a form prescribed by the stature and charges the borrowers interest in the hydrocarbon property. Assignments made under Section 82 are registerable by Caveat at the Land Titles Office if it relates to a mineral title or at the Department of Energy and Natural Resources for Crown leases. For reason of nonpayment of the loan or for failure to take care of, maintain, protect or preserve the property registered, the Bank may take possession 0f, seize, care for, maintain, use, operate or sell the property covered by the security. The Bank would return to the title holder any surplus proceeds of any such operation or sale remaining after payment of all loans and advances with interest and expenses. Project That Quality Under Section 82 To qualify for registration under Section 82 of the Bank Act, any interest in a property must contribute an interest in land. This rarely presents a problem for holdings of freehold mineral titles. Frequently, however overriding royalties and net profit and revenue interests are simply contractual agreements and not being an interest in land, will not support a statuary mortgage under Section 82 of the Bank Act. It is advisable that, when negotiating and preparing these agreements, they be structured so as to represent an interest in hydrocarbon thereunder rather than result solely in a contractual obligation to pay a sum of money. Production loans made against Section 82 of the Bank Act are designed to the self-liquidating from income of the properties pledged. Accordingly, only proven producing reserves are generally considered acceptable as security for Section 82 loans. No loaming value is given for probable or speculative reserves such as those that may be of a secondary recovery scheme or from stimulation of existing wells.

Introduction The use of solar or exotic forms of energy may not seem of particular significance to those whose business is in hydrocarbon and fossil fuel energy resource development. At least, public interest in this technology as a supposed alternative to the scarcer and scarcer fossil fuels does not carry much weight with most technical people involved in the energy business. Nevertheless, it has been estimated that the use of direct solar energy in the form of low-grade heat could provide perhaps as much as four percent of Canada's total energy needs somewhere in the period 1985 to 1995. This could be done by equipping buildings with simple passive solar collectors that would deliver low-grade heat as a substitute for the normal heating fuel. This is apparently the most optimistic of the credible estimates and figures were not found to substantiate the claims of some that exotic renewable energy resources could supply a substantial part of our energy needs. Interestingly enough, even the most ardent advocates of solar energy, tidal power and wind energy often ignore the one established renewable energy technology that has been with us for the better part of 100 years and gives a very efficient conversion to electric energy from what is essentially solar energy, i.e. hydro electric energy generation. Early in this century there were many small steam, diesel or other internal combustion generating plants scattered coast to coast, and even some small isolated wind-electric generators: but the major sources of electric energy were almost always hydro electric. So much so in fact that in large parts of Canada the local population developed a tradition of referring to electricity as "the hydro" and this habit has carried on to the present day. Today hydro electric energy is still significant in meeting Canada's electric energy needs but it does not play the major role in meeting Canada's total energy demand. In 1977 for example, the hydro electric energy generated totaled about 225 thousand gigawatt hours or about one quarter of Canada's total energy requirement for the year. To generate an equivalent amount of electric energy in oil-fired power plants would have required about one million barrels of oil per day. Assuming an international price of about $13 per barrel implies an annual saving of about five billion dollars of fuel cost. Now of course it could be argued that if the government taxed water resources the way it taxes production of other resources then there would not be that fuel saving. To a degree this is true since annual water rentals on the water used to produce the hydro electric energy equivalent of a barrel of oil would be only a fraction of a dollar. However, five billion dollars of equivalent cost in oil is perhaps a reasonable perspective of the 1977 value of this energy generation to the Canadian economy. There are still considerable reserves of hydro energy in North America, and in Canada in particular.

Abstract When conducting a reservoir simulation study, the simulation engineer should recognize not only the accuracy and applicability of the data input, but the simulator as well. This paper discusses grid orientation, time-step size, and omega effects on the accuracy and speed of the calculations for a reservoir depletion study of the Pembina Keystone Belly River M Pool. Also of interest in this study was the usefulness of a fence diagram in helping to understand the producing characteristics of some of the wells in the field. The method of history matching is also discussed. As there is no unique set of reservoir parameters which produce a history match, it is important that the simulation engineer describe in the report both the reservoir parameters required to achieve a history match, and to what degree these parameters were adjusted from the core, log, and laboratory data used to initialize the model. This paper outlines the detail of presentation required to describe thoroughly the adjustments needed to achieve a history match for the Pembina Keystone Belly River M Pool. Introduction Reservoir simulation models are powerful tools for evaluating field development potential. Development schemes involving enormous amounts of capital are recommended based on computer output from mathematical models. It is therefore imperative that the simulation engineer understands not only basic reservoir engineering, but also the accuracy and applicability of the mathematical equations in the model which describe the physical processes active in the reservoir. Also, since a reservoir simulation study is so detailed and intricate, it is difficult for both management and other working interest owners to evaluate the technical aspects of the study. Therefore, the onus is on the simulation engineer to ensure technical validity and to provide the working interest owners with as much information about the study as is reasonably possible. The objectives of this paper are: to illustrate how to evaluate the effects grid orientation, time-step size, and mathematical solution technique have on the results computed by the simulator, to suggest methods of data presentation which describe the adjustments to the core, log, and laboratory data needed to achieve a history match, and to provide some reservoir and development information on the Pembina Keystone Belly River M Pool. These objectives will be accomplished within the framework of a discussion of a reservoir simulation study of the Pembina Keystone Belly River M Pool. The Pembina Belly River M field history and reservoir description will be presented briefly, followed by the steps involved in model initialization, history matching and performance predictions. Common simulation detail such as a cross-sectional model for generation of pseudo relative permeability curves will be noted, but less common aspects of the study, such as time-step size optimization and minimization of computer execution time will be discussed more thoroughly. Historical Background The Pembina Keystone Belly River M Pool was discovered in 1962.

Abstract As rig time and completion costs continue to rise, it is increasingly important that reliable reservoir data be gathered rapidly, economically, and safely. A properly conducted Formation Test or Drill Stem Test will provide the reliable reservoir data. Todays technology has made available safe and dependable equipment for testing offshore both from platforms and floating vessels. Equipment such as quick closing remotely operated surface valves, down-hole safety valves, and down-hole pressure responsive tools are now available for safely obtaining adequate reservoir data. Criteria for the equipment was established to promote safety, dependability, and compatibility with existing equipment. The criteria for testing from floating vessels was that the equipment must provide: A safe system for testing incorporating multiple back-up equipment. Minimum amount of ‘rig-up’ time, on the well. Properly run Formation and equipment. Remotely controlled surface equipment. Down-hole safety valves that would close automatically, or intentionally, when required. Minimum amount of rotation during the test. "Hang-off" points at ocean floor to prevent down-hole drill pipe movement during the test. An optional means to trap a sample at final flow pressure and bring it to the surface for analysis. Introduction Obtaining meaningful reservoir data safely by Formation Testing is an economical necessity today. The time to evaluate a reservoir is when a minimum amount of permanent expenditures has been made on the well. Properly run Formation Tests, i.e., two equal flow periods of sufficient duration to clean up the well and to establish a flow rate, each followed by a closed-in-pressure period long enough to provide a minimum of 65% closure of the closed-in-pressure curve, should provide adequate reservoir data, including reservoir extent. Character of each individual well should dictate the times allocated the flaw and closed-in-pressure periods. Experienced personnel on location are in the best position to evaluate formation behavior patterns, and thus adjust the time periods for the test. A big savings in rig time is possible when time periods are properly chosen. Unnecessarily long closed-in-periods, for example, could be eliminated by an experienced well-site judgment. Conversely, proper well-site judgment can assure you that adequate flows and closed-in-pressure times are obtained. Safety of personnel equipment, and the ecology must also enter into theeconomical realm. Technology has moved safe offshore testing into the era of practically. Tools to help protect man, equipment, and ecology', are available and wilI be discussed in the following paragraphs. Background In mid-1968, increased deep water orilling from floating vessels coupled with ecologicaI concern, fostered development of a new technique of Formation Testing. Criteria for this technique envisioned a progressive development of equipment starting simply and continuing today with a completely new concept in Formation Testing tool operation. A review of the criteria used in developing the equipment for testing offshore can best point out the technological advancements made in the last three years. Criteria for testing from floating vessels was that the equipment must provide: A safe system for testing, incorpc, rating multiple back-up equipment.