Abstract In excess of 6400 new gas wells per year will be required to meet future demand, well above the current tie in levels. Total deliveries of gas from the province of Alberta increased by 56% to 127 E9M3 from 1990 to 1997. Pipeline expansions in late 1997 to 2000 are expected to add a further 26 E9M3. The total demand by 2002 is expected to reach 177 E9M3. A study was conducted to examine the decline trend of gas wells over the last eight years with a view to predicting the future tie in requirements and the ability of Alberta to meet the increasing demand for gas. The study showed that new sources of gas are coming on at rates of less than 30 E3M3/D and gas wells rates are declining at 27% the first year. Using the gas well productivity and performance results of the study, predictions were made of future tie in requirements. Introduction In 1997, total deliveries of gas from Alberta wells amounted to some 127 E9M3, an increase of some 56% over 1990 values. The volumes exported to the US almost doubled (Fig. 1). (1) The Northern Border Pipeline and the Trans Canada Pipelines expansions in late 1997 and 1998, and the Alliance Pipeline in 2000 are expected to add another 31 E9M3 to the annual demand for gas from the Western Canada Sedimentary Basin of which some 26 E9M3 will come from Alberta. The EUB estimates that the annual total deliveries of gas from Alberta in 2002 will be 177.4 E9M3. PART I - PRODUCING GAS WELL STATISTICS In order to accommodate the increase in production, an increasing number of gas wells have been tied in. At yearend 1997 there were 43 262 producing gas wells (Fig. 2), 13 491 more than in 1990. There was a net increase of 3600 wells in 1994, 1800 in 1995, 1900 in 1996 and 3200 in1997. (2) From 1994 through to 1997, more gas wells were being placed on production than in any previous year. In 1994, 4456 wells were placed on production and in 1997, 4529 wells were placed on production (Fig. 3). GAS WELL REPLACEMENT By comparing the total number of gas wells placed on production in a given year with the incremental net increase in the number of gas wells on production, the number of new wells that replaced gas wells ceasing production can be determined. As expected, as the number of wells placed on production increased, the number of wells ceasing production in any one year has increased. Over 1300 wells ceased production in each of the last three years (Fig. 4). The average proportion of gas wells required to replace wells ceasing production over the past ten years was 44.8% and over the last three years 39.5%F. TIE IN TIME FOR GAS WELLS FROM FINISHED DRILL DATE New wells are being tied in at a faster rate but there is still a significant elapsed time before some wells are placed on production.

Abstract The 25 cases of oil well blowout, which happened in the oil field in China from 1962 to 1993[1], were analyzed. some conclusions about the factors related to the human error are drawn from the statistic data. The peak of the blowout frequency happened on Monday or Friday during the week and around 3:00am during the day. These are possible related to the disturbance of circadian rhythm. Because the management error, especially the human error, is one of the major factors in the oil well blowout accidents. However, the least of the blowout frequency happened on Wednesday. From these conclusions, we call learn a lesson of proper arrangement in the schedule of duty in drilling operations. A training program of the well blowout operation and methods of prevention will be provided to drilling operators, in order to improve their ability of dealing with the blowouts and avoiding the misoperation due to the short limited time before making a right decision. Introduction Studies of actuarial records of industrial experience have shown that human-system interactions are extremely important to safety, However, the oil and gas production industry which maybe is not so commonly well known, is indeed a potentially dangerous one due to its nature. A study by McNabb el al [2] in 1994 found that non-fatal injuries among field workers in this industry were 49% higher than among workers in all other US industries combined, and that these injuries were more severe. The drill occupation is acknowledged as being one of the more dangerous within this industry, and therefore worthy of efforts to reduce the well blowout rate. Theories of how accidents are caused have endured four stages of development. The first stage existed at the period of time when developments in technology were rapid and the majority of accidents were caused by technological malfunctions. The second stage focused on human error where blame and responsibility were assigned to the person directly involved in the unsafe act. The third stage involved understanding why people behave in the way they do and delving deeper to understand the cause of accidents. The last one focused on the contribution of management to safety [3]. Now in order to obtain the underlying causes of these accidents and demonstrate what types of human error were involved in these blowouts. Six [4] of the 25 cases of blowouts were analyzed in detail, some statistics data were analyzed of the 25 blowouts, Some conclusion were drawn. FACTORS ANALYSIS OF SOME CASES Introduction While documents of the six blowouts of the 25 cases were analyzed in details, an attempt was always made to work back to the fundamental human error which contributed to the failure. A failure code was then allocated to each possible type of error [5]. Only if a failure could not be directly attributed to a human error was given the code E, for equipment failure. Human error leading to equipment failure could be of five different types: Design error (D), Operating error (O), Production error (P), Management error (M), Testing error (T).

Abstract Calculations of water saturation were carried out for the A Sand of the Bridger Lake Field using techniques based on: capillary pressure measurements, old well logs and old conventional interpretation charts, and cross plot and pattern recognition. It was found that approaches (1) and (3) provided very close results for average water saturations (31.0 and 30.7 per cent). Calculations using method (2) gave misleading results (65 and 100%). It is concluded that techniques based on capillary pressure measurements and cross plot pattern recognition provide reliable values of average water saturation. The former has the major disadvantage of being susceptible to error in the determination of the volumetric midpoint of the reservoir. The latter has the advantage of accounting for water saturations in different zones, which still allow us to determine an average water saturation for the whole sand. It is recommended to exercise special care in the use of conventional "cook book" interpretation charts and computer programs. The indiscriminate use of these charts/programs can result in serious error. Introduction The Bridger Lake Field is located about 95 miles east of Salt Lake City (Utah) at the northern foot of the Uinta Mountains on the extreme south flank of the Green River Basin. The legal location according to Utah, regulations is Range 14 East, Township 3 North. Figure 1 shows the location of the Field. The A Sand is located in the lowest part of the Cretaceous Dakota formation. The Dakota formation lies between the Mowry formation and the Morrison formation at an average depth of 6500 feet below mean sea level. Core analyses of these zones indicated good oil show with very erratic values of mean permeability. The sand grains are basically light brown, and their size varies from fine to medium. The purpose of this study was to compare the values of water saturation determined from capillary pressure measurements and logs. The former requires knowledge of the geometric mean permeability and the volumetric mid-point of the reservoir. The latter is based on the following relationships: 1 Equation (1) (Available in full paper) Equation (2) (Available in full paper) Equation (3) (Available in full paper) where S w = water saturation, fractional I = resistivity index n = saturation exponent R t = true formation resistivity F = formation resistivity factor Φ = porosity, fractional R o = resistivity of a non-shaly sample 100% saturated with water of resistivity R w WATER SATURATION FROM CAPILLARY PRESSURE MEASUREMENTS For the calculation of the average water saturation, capillary pressure measurements were made on 13 samples for different water saturations as shown in Figures 2, 3, 4 and 5. Table 1 summarizes the properties of these samples. The logarithm of permeability for each sample was plotted against water saturation holding capillary pressure constant. This plot yield approximate straight lines as shown in Figure 6. The next step was to calculate geometric mean permeability. This was accomplished by mean the equation: 3 Equation (4) (Available in full paper) where k g = geometric mean permeability millidarcies F j = frequency of j interval, fraction

Abstract Permeabilities from layer to layer can vary significantly in naturally fractured reservoirs. This study makes a comparison of geometric mean fracture permeability with permeabilities from well testing data in a layered naturally fractured reservoir. The research was conducted with a model that contains 10 layers that are naturally fractured. The 10-layer model is validated by comparing its drawdown and buildup behavior against the behavior of a single-layer model. It is shown that permeability of the 10-layered reservoir calculated using a single-layer method will be much larger than the geometric mean and even the arithmetic mean, and will reflect the 2 layers with the largest permeabilities. If this is used in reservoir studies, it can lead to very optimistic forecasts. The problem of multi-layered permeability behavior may be recognized during a drawdown by a pressure derivative indicating partial completion effects even if the well is perforated in all fractured layers. During a buildup this recognition is more difficult because the shape of the buildup curve is affected by the length of the flow period previous to shutin. Introduction Outcrop information, imaging logs and production logs, have shown that in some cases naturally fractured reservoirs are composed by many layers 1 . The thinner the layer the smaller the fracture spacing (or distance between natural fractures). Under these circumstances some of the fractures might be intersected by the wellbore and some might not as shown on Figure 1 . A production log would show only the fluid entrance points into the wellbore. It is important to emphasize that the production log would not give an indication of net pay in the naturally fractured reservoir, only an indication of where the wellbore intersects the most important fractures. It is not unusual to see from a production log that out of 100 ft perforated in a fractured reservoir only 5 to 10 ft contribute production into the wellbore even if the 100 ft are true net pay. This is the result of a typical situation in most naturally fractured reservoirs I am familiar with, i.e., that the matrix has a very low permeability which does not permit efficient fluid flow into the wellbore. The same tight matrix, however, can flow very efficiently into the natural fractures 1 . One of the first papers dealing with pressure behavior of layered reservoirs was published by Leftkovits et al 2 . There was no communication between layers except at the wellbore. Later Russell and Prats 3 studied the practical aspects of interlayer cross flow, and concluded that the early time response would be similar to the response of a well draining a layered reservoir with no cross flow. Prijambodo et al 4 studied the early time performance of a well in a reservoir with cross flow and concluded that the pressure behavior was remarkably different from that of an equivalent single layer system. They indicated that the early time response could be divided in flow periods.

Abstract Steam-stimulation processes are the viable insitu thermal recovery techniques for heavy oil and oil sand reservoirs. These thermal recovery processes introduce many complex geomechanical problems in oil sand and overburden formations. This paper addresses the geomechanical response of Colorado shale near a cased wellbore due to heating. The temperature, pore pressure and stresses response in Colorado shale near a cased wellbore due to heating are analyzed using a coupled thermal-mechanical-hydraulic solution. The possibility of failure or fracturing of the shale due to heating is assessed. Introduction Thermal recovery processes such as cyclic steam stimulation and steam assisted gravity drainage are the viable techniques for oil recovery from oil sand reservoirs. These thermal recovery processes cause many complex geomechanical problems in the oil sand layer and the geologic overburden strata because elevated temperature and pressure are involved in steam injection. The study in this paper focuses on the effect of heating on Colorado shale near a cased well. Analytical solutions developed by Booker and Savvidou 1 are used to analyze the induced pore pressure, temperature, and stresses distributions in Colorado shale near a heated wellbore. These results will be used to investigate the potential occurrence of any tensile fracture in the heated shale. Conclusions will be drawn, along with the limitations of the analysis and recommendations for further studies. PROBLEM DESCRIPTION Figure I provides a schematic sketch of the problem. Steam is injected into a cased well such that the inside temperature is elevated to a constant temperature. Heat is continually conducted away from the well into its metal casing, cement annulus and shale formation. Heating of shale causes thermal expansion of the shale structural matrix and pore fluid. Expansion of structural matrix induces total stress change. Thermal expansion of pore fluid increases the pore pressure, thereby generating pore pressure gradient and pore fluid flow. Hence, the heating process results in thermal-hydraulic- mechanical coupled process. Calculation of the temperature, pore pressure and stresses changes near the heated well will require solution to this complex coupled problem. ANALYTICAL TECHNIQUE Equilibrium Equation and Constitutive Law For a saturated thermo-elastic geological medium, the equilibrium equations are: Equation (1.a) (Available in full paper) Equation (1.b) (Available in full paper) Equation (1.c) (Available in full paper) where σ xx , σ yy , ..... σ yz are the increase of total stress components (compressive stresses and strains are considered to be positive). In the present study, the stiffness of the solids and pore fluid are assumed to be infinite in comparison to the shale skeleton stiffness. Thus, volume changes are due to changes in temperature and effective stresses. For an isotropic thermo-linear elastic material, the stress-strain relations are given by: Equation (2.a) (Available in full paper) Equation (2.b) (Available in full paper) Equation (2.c) (Available in full paper) Equation (2.d) (Available in full paper) Equation (2.e) (Available in full paper) Equation (2.f) (Available in full paper)

Abstract Approximate equations are presented for evaluation of naturally fractured gas condensate reservoirs represented by dual-porosity models in radial systems. The reader is cautioned that this work is in progress. Additional research will help to corroborate and refine these techniques. The solutions have not been published previously in the petroleum engineering literature. The solutions are presented for drawdown and buildup tests. The model assumes flow of gas condensate from a tight matrix into permeable natural fractures. The fractures conduct the fluids to the wellbore. It is preliminary shown that a conventional cross plot of m(p) vs. time on semi logarithmic coordinates results in approximately two parallel straight lines with a separation that is related to the storativity ratio between fractures and matrix. This plot allows determination of key parameters such as absolute permeability, effective permeability's to oil and gas, skin, storativity ratio (ω), fracture porosity (Φ 2 ), average distance between natural fractures (h m ), radius of investigation, and extrapolated pressure (p 1 or p). In addition the method permits generating a liquid saturation profile and a general composition profile around the wellbore at shutin. Introduction Naturally fractured reservoirs have been the object of intensive research during the last few years in the geologic as well as the engineering fields. Transient pressure analysis has received particular attention. Barenblatt and Zheltov (1) and Warren and Root (2) handled naturally fractured reservoirs by assuming pseudo steady-state (restricted) interporosity flow in a model made out of cubes with spaces in between. Flow toward the wellbore was assumed to be radial via the natural fractures. Their work led to the conclusion that a conventional cross plot of pressure vs. log of time should result in two parallel straight lines with a transition period in between. The separation of the two straight liens allowed calculation of the storativity ratio omega, i.e. the fraction of the total storage within the natural fractures. Kazemi (3) used a numerical model of a finite reservoir with a horizontal fracture under the assumption of unsteady state interporosity flow and substantiated Warren and Root's conclusion with respect to the two parallel straight lines. The transition period, however, was different due to the unsteady rather than pseudo steady-state interporosity flow assumption. de Swaan (4) developed a diffusivity equation and analytical solutions to handle the first and last straight lines. His method, however, could not analyze the transition period. Najurieta (5,6) developed analytical solutions of de Swaan's radial diffusivity equation which could handle the transition period as well as the first and last straight lines. Streltsova (7) used a gradient flow model and indicated that the transition period should yield a straight line with a slope equal to ½ the slope of the early and late straight lines. Her examples showing the ½ slopes gave values of storativity ratios approximately equal to 0.37, 0.26, and 0.48. Serra et al. (8) reached the same conclusion with the use of a stratum model for the cases in which the storativity ratio, omega, was smaller than 0.0099. Various type curves have been developed to analyze naturally fractured reservoirs with transient (9,10) and pseudo steady-state (11) interporosity flow.

Abstract Field measurements and surveys are taken routinely and the data stored for future retrieval and analysis. However, often this information, collected with some degree of difficulty and expense, is not used effectively because the production analyst is lacking a straightforward means of organizing and interpreting the data. This paper presents the design and application of an automatic production monitoring system that provides the user with a completed ‘first pass’ screening of the producers in a field. The review results in a list of the opportunities to improve production. Wells are sorted according to the type of rate restriction and, where possible, prioritized using ranking criteria. This simple and powerful tool quickly quantifies the potential production increases that may be realized by working over candidates in a typical oil field, and identifies where the analyst should begin focusing their efforts. The program is set up on a spreadsheet using the existing system's data operation and graphical capabilities. It is operated from a central control panel that consists of a series of buttons, each supported by a macro or module that manages data I/O, graphics generation, and technical analysis. A special feature that allows the analyst to perform more detailed technical analysis to support the conclusions of the screening review is the program's ability to do multi-scale plotting and field-wide mapping. Introduction Today's competitive business environment requires that decisions be made at an ever-increasing pace. As a first step in accommodating these demands, advances in computer technology have provided for improved graphics capabilities and comprehensive spreadsheet applications. These developments now allow for the manipulation and plotting of large amounts of data. However, the analytical skills of a trained individual are still required to enable any meaningful conclusions to be made. The situation is complicated by the conundrum that as the volume of available data increases, the more difficult it is to derive its benefits due to the time required for review and evaluation. The objective of the automatic production monitoring system is to provide a program that will replicate the preliminary steps which the typical analyst would take in doing a performance review of an oil field. That is, the system retrieves the data, presents it in a logical and concise manner, and then reviews each well for indications that it is performing in a less than optimum manner. Once each well has been reviewed, workover candidates are identified and, where possible, ranked in order of their potential contribution to improvement in oil rates. The analysis is performed automatically and presented to the user for further review and verification. The program also has the capability of presenting commonly collected information such as pressure and production data in a logical easy-to-view format using multi-scale plotting and field-wide mapping techniques. [1] Time permitting, once the initial screening has been completed and summarized, the analyst can use these additional facilities to assist in further detailed technical evaluation to confirm the conclusions from the screening review.

Abstract One of the methods to measure the displacement pressure of a core is by the centrifuge capillary pressure experiment. It is generally accepted that this is the capillary pressure at the inlet end at the initial entry of the non-wetting fluid into the core in the primary drainage portion of the experiment. The objective of this paper is to show that this is valid unless the pressure drop across the interface between the fluids at the exit end is zero. As this quantity was considered negligible right at the initial theoretical development of the centrifuge method no measurement had been reported in the literature. There is, of course, no provision in the currently available centrifuges for such measurements. We have performed stepwise displacement experiments to show that this pressure drop may not be negligible. It is, therefore. necessary to confirm this result in the centrifuge. Introduction The measurement of capillary pressure saturation relation of a core by the centrifuge was proposed by Hassler and Brunner 1 . They formulated the governing set of equations for the equilibrium distribution of two fluids under constant centrifugal acceleration and presented two approximation methods to calculate capillary pressure saturation relation from measured data. Since then there were a large number of attempts to improve on these approximate solutions. Only four of these works 1–4 will be discussed in this study. Interested readers are referred to Ruth and Chen's 5 review article on centrifuge capillary pressure experiment. The underlying theory as derived by Hassler and Brunner were accepted by all these authors. In spite of the general acceptance of the original formulation, a number of authors 6–10 have some concern with the boundary condition at the exit end. Based on Hassler and Brunner the capillary pressure should be zero at the exit end, and it was interpreted 6–10 as equivalent to water saturation being 100 % there. When Wunderlich 6 found that it could be less than 100 at high centrifuge speeds, he considered it as an indication that the boundary condition was being violated. In this set of experiments epoxy was used as one of the fluids, and it was allowed to solidify while the centrifugal arm was in motion. Water saturation was determined by image analysis of the cut up sections of the core. Wunderlich's 6 concern was taken up by a number of other authors 7–10 Theoretical derivations by Wunderlich 6 , Melrose 7 , and O'Meara et. al. 8 were obtained for a critical pressure above which the saturation at the exit end would be reduced to less than 100 %. In the indirect experiments by O'Meara et. al. 8 , and Melrose and Mallinson 9 they could not see any evidence of the violation of the assumption of zero capillary pressure at the exit end. They, therefore, concluded that it was only possible at centrifugal speeds much higher than the capability of their machines. This conclusion was in direct contradiction to Wunderlich's 6 experimental results. Another experimental measurement of core saturation report by Baardsen et. al. 10 , however, found lower than 100 % saturation at the exit end at normal centrifugal speeds.

Abstract Actual production data of Winter field were examined for production rates, oil cut, cumulative oil produced and reserves per well in relation to well length. The log oil cut vs. cumulative oil production per well of groups of wells plots showed that the reserves at a 2% oil cut was the same despite the different lengths of these wells. Published data ", ere next examined to establish the relationship between well length and reserves. It is obvious that the relation between reserves as a function of well length is not a linear relationship for the entire well length examined. This relations shows that as the well length increases from 200 m to roughly 500 m there is a linear increase in reserves, The slope of the line is less than I (0.7); as the length increases beyond the 600 m there is very little increase in the reserves. This could be an explanation for the Winter wells showing the same reserves as the groups of wells examined varied in length from 574 m to 1110 m; they are all in the length range (greater than 500 m) that gives the maximum reserves. In order to verify this conclusion and utilize it to increase the reserve from existing and future wells a series of well work over's and treatment programs were carried out. New drilled wells were completed in such a way that uses the conclusions and recommendations of these programs. INTRODUCTION The Winter field (Figure I) has been developed utilizing horizontal wells to produce heavy oil (13.7 API oil of 2800–3800 cp. viscosity) in a 12 m thick Cumming sand underlain by a very strong aquifer. The oil cut vs. oil cum. per well plots for each phase (wells drilled in a specific year) are shown in Figure 2. It is obvious that the reserves per well at an economic oil cut of 2% are essentially the same for the different phases. It is interesting to notice that the average well length for the different phases ranges from 574m to 1111m. Data for over 250 horizontal wells producing oil over water reservoir in Saskatchewan published in SEM publication were analyzed and the reserves as a function of length are shown in Figure 3. This figure illustrates the non linear nature of the relationship between reserves and well length. For example a well of 200–300 m length has a reserves of 9000 m3 while a well of 1000–1100 m has a reserves of 15000 m3; rather than the 30–40Em3 expected in a linear correlation. Detailed analysis of every well in the Winter Field was carried to identify potential reasons for better or worse performance. A series of water shut-offs treatments and work over's were carried out. External casing packers were utilized for formation isolation and proved to be effective. Finally the information gained from all of the above is being tested in some of the 1995 drilling program through a new completion practice targeting reserves maximization with minimum effect of initial rate.

Abstract This study examines the effect of influx into a two-phase, liquid-liquid flow system, as occurs in many horizontal wells. The purpose of the research was to analyze the pressure drop behaviour of oil-waterflow in a physical pipe model with influx. A closed-loop pipe flow model was designed and constructed for the purpose of these experiments. Varying turbulent oil-water pipe flow and influx flow rates were generated using the apparatus, with the experiments recorded using photographic and video equipment. Comparative modeling of the experimental pressure drop and holdup data was performed using a widely recognized pipe flow correlation model. A pipe flow correlation method was developed for analysis of oil-water flaws. The significance of the influx disturbance with respect to wellbore pressure drop was examined. An analysis of the experimental results leads to the adaptation and development of field-scale predictive models for horizontal wellbore pressure drop and specific inflow profile. Based on the experimental results, it is concluded that: the pipe flow correlation method examined provides adequate pressure gradient predictions for oil-water flows; an accelerational model of pressure drop across a single perforation is inadequate in its prediction capability for the experimental range used; and at sufficiently high perforation-to--axial flow velocity ratios, the dominant factor determining the pressure drop across a single perforation is a constriction disruption, or venturi-type effect. INTRODUCTION Horizontal wells have gained wide acceptance in the petroleum industry in recent years. Many studies have been carried out that examine the superior recovery performance of horizontal wells, especially in comparison with their conventional counterparts. In their analytical models, researchers originally treated the horizontal wellbore as being analogous to a vertical fracture having infinite or near infinite conductivity. Dikken1 was the first to demonstrate the potential limitations to production imposed by pressure drop across horizontal wells. That study initiated a great deal of interest in wellbore hydraulics that has carried forward until the present. A pressure drop across the length of a horizontal well will always occur as a necessity for flow. For the pressure drop in a particular well to be problematic certain flowing conditions are necessary (such as turbulent flow). The pressure drop is an important consideration in horizontal well performance in certain situations, including low drawdown thin zones with overlying gas and/or underlying water, high production rates, multiphase flow, etc. This study is an attempt to contribute to the understanding of horizontal wellbore hydraulics. The study is expressly concerned with the mechanisms of the pressure gradient, in both single-phase liquid and two-phase liquid-liquid flow, and with or without confluent influx from flow through a single perforation. For this purpose a pipe model was designed and constructed, and a series of experiments was carried out- Also, a small number of numerical programs were developed in order to make comparisons with the experimental data and to aid with the analysis. This paper is focused on the experimental aspects of the study performed. A later paper will detail the field-scale predictive modeling development.

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 The oil and gas industry in Canada has experienced tough, competitive environment over the last decade andcontinues to do so, The issues affecting the industry are complex, and it becomes very difficult to be able to plan and reactappropriately to the changes. To survive and grow in this tough environment an oil and gas producer must have a good understanding of the key components of the business in which it is operating and how one area influences the other components of the system. Being good at one or two components of the system may not be enough to survive in the industry. This paper uses the system thinking model to highlight the relationships between key components of the business. Current trends in the industry in Canada are identified and how they are affecting the producer today. Companies may want to adopt different measures of performance and strategies to be able to survive and grow in the business. Introduction The oil and gas industry in Canada is now experiencing the same tough, highly competitive environment that many other industries experienced earlier. This "environment" has the following characteristics. Continuing low growth requires a company operate with a low margin of error or it may suffer the painful consequences for any mistakes made. The share of the market (in this case the energy market) becomes fixed and it becomes very difficult and expensive to Increase the market share, There is an uneven distribution of resources (people, material, technology, and money.) Resources are always scarce and thus must be carefully allocated to where they will do the most good. The industry is taking on an ever increasing international flavor and as a result is becoming increasing more complex to understand and plan for, The industry is experiencing irreversible inflation (particularly on the cost side) which continues to eat at the margins. (ref. I) The complexity of this operating "environment" makes selection of an appropriate strategy for an Canadian oil and gas producer very difficult. The oil and gas business In Canada has had some relief from the tough conditions. This relief has come about because Canada is part of the North American energy market. Even though the conditions are true for Canada, we have seen some relief as exports to the United States has provided an expanding market for our oil and gas products. (Figures 1 and 2) These additional exports have been welcome relief to the producers. At the same time the prospects available Lo the oil and gas producer in Canada are changing. The old "theory of business" (ref. 2) of chasing large reserve additions requiring significant capital expenditures and significant risk is no longer appropriate. The reserve addition targets are now much smaller requiring moderate capital and moderate risk. Capital requirements are now within the capabilityof a mid-sized company. All companies - big, medium, and small are now competing on a more even plain on the development and production side of the business.

Abstract Over the years gas injection design has undergone an evolution in the types of laboratory tests used to design a gas injection project as well as the interpretation of the experimental testing. In the recent past, there has been much written in the area of immiscible and near-miscible gas flooding. Often, some of these applications appear to be very effective and somewhat less expensive than the so-called "miscible" floods. In this paper the authors discuss some of the consideration which are germane to gas injection and provide evidence that suggests that many of the previously accepted laboratory techniques were not really providing what they were intended to. It is important that one understands the significance of these considerations when designing a gas injection project. The authors indicate that specific testing can be made to gain insight into the most important features of a gas injection project which concerns the interaction between the level of interfacial tension and the mobility 'effects. By appropriately quantifying whether a reservoir is going to be IFT or mobility-dominated, the operator can concentrate on designing a gas to optimize the factor which is dominant. It is important to mow what that dominant factor is so that gas injection processes are the best that they can be. In answer to the question asked in the title of this paper, the authors suggest that most gas injection projects would involve a gas which exhibits properties in the so-called "near-miscible" range. Techniques for determining how miscible one needs to be are provided in this paper. Introduction With the vicissitudes in the oil industry, many times enhanced oil recovery schemes are reviewed with an optimistic or pessimistic attitude. It commonly seems that there is no middle ground. The thought of high initial costs associated with enhanced oil recovery schemes sometimes dissuades some operators from considering what may be their only hope. Whereas, at other times, larger corporations, because of the "charisma" associated with high technology implementation, have spent money needlessly on EOR schemes which from the beginning were not suited to their application. Take, for example, the winter of 1994–95. Gas prices were low and therefore the production of energy from reservoirs was of much greater value when obtained as a liquid phase rather than as a gas. At times like this, it would be synergistic to have a reservoir where one knows that gas injection would be beneficial and thus have an idea of what is the optimal gas design. Indeed, many companies considered shutting in their gas production and some did reduce gas production due to gas prices. Some of the gas could be used for injection into reservoirs which were declining in productivity. It is important that the research needed to identify good gas injection candidates must be synchronized so that when an opportunity arises, one can apply the principle of serendipity and make these market conditions work for you. No matter what the history of gas injection has been, which is viewed with different conclusions depending upon to whom you speak, the question still remains of what is the best way to optimize cash flow from a given reservoir.

Abstract The paper discusses the design. The field operations of drilling and completing a high productivity horizontal well in the Sirte basin of North Africa as well as the productive results obtained. In Oct. - Nov. 1994. the Arabian Gulf Company (AGOCO) drilled, tested and put into production a horizontal well in the Elgiza formation (Eocene) of the An Nafurah field in the Sahara Desert. The main objectives were to increase the production rates and to alleviate water coning. To update the existing information (the reservoir was considered partially depleted after over 14 years of production) a vertical pilot hole was drilled and logged, then plugged back, before kicking the well off. After drilling the curve (medium radius) and turning the well horizon/al. a bottom hole assembly (BHA) twist-off occurred while the build section was being reamed. This resulted in a short "fish" in the hole at 78 ° angle. A fishing attempt with a hydraulic junk retriever proved unsuccessful and had to be followed by two sidetrack cement plugs The first one was a very typical case of "cement slip off' and had to be repeated with a different slurry' formulation and placement procedure. The lower part of the curve was successfully sidetracked from 52 °and re-drilled to 90 ° without incidents. Running without difficulties to the end of the curve (EOC) and successfully cementing the stiff production casing (9 5 .8' diameter) despite the highly bent build section (actual BUR of 14 ° to 16 ° 30m were important achievements. This was mainly due to the special drilling fluid (an oil based inverted emulsion ype). a well-designed casing and cementing program, a skillful drilling crew. A 1400ft. long horizontal lateral was drilled in three days' and left as an open hole completion. The well was flow tested on clean-up (at a very high rate) by using coiled tubing (CT) and small volumes of N 2 , At present, the well is flowing through a 12" choke. The paper reviews the main steps in the design and field execution of this high productivity Saharan horizontal well focusing on some particular aspects of the field operations: the fishing job at 78 ° angle in the curve; the sidetrack operation from a high angle borehole; re-drilling the lower section of the curve; running a rigid 9 5 8" casing (without premium connections) through the high curvature build section; an inexpensive technological package to minimize formation damage. a special procedure to keep the horizontal lateral clean. The technical and economic success of this horizontal project can be attributed to the "integrated technology approach" used throughout the entire project development. Introduction In Oct. - Nov 1994, AGOCO has drilled and completed a high productivity horizontal well in the Eigiza West reservoir well G I90H-51, Elgiza W Zone, NNU. The reservoir is located in the Nafurah Field of the Sirte Basin, in N. Sahara, about 450km south of the Mediterranean Coast, in the G.S.P.L.A.J. Located in a mature field, with all twenty offsetting wells drilled and completed 14–15 years ago(the field was discovered over 18 years ago), the horizontal well had to answer several questions put forward by the Company:

Abstract Scaling of spontaneous imbibition measurements is important to characterizationof wetting properties and to modelling mass transfer between rock matrix andfractures. A scaling equation proposed by Malrax and Kyre (1962) has beenwidely applied to prediction of field-scale oil recovery rom fracturedreservoirs. The scaling equation involves many assumptions including identicalcore-sample shapes and viscosity ratios. In this paper, the effect o/viscosityand viscosity ratio on rate of spontaneous imbibition is investigated.Imbibition data is reported for systems with two orders of magnitude variationin viscosity ratio. The results show, for systems of similar geometry, that theimbibition time is proportional to the square root of viscosity ratio. Thisobservation combined with a new definition of characteristic length is used todefine a modified scaling group which allows for differences in viscosityratio, and the shapes and boundary conditions of the coresamples. Introduction Spontaneous imbibition is a natural physical process driven by capillary forceswhereby a nonwetting phase is displaced by a wetting phase from a porous medium(Morrow, 1970). Examples of practical significance may be found in civil andchemical engineering, soil science, and numerous other areas. In petroleumengineering, imbibition is considered especially important in oil recovery fromfractured eservoirs, where the rate of mass transfer between rock matrix andthe associated fractures controls the oil production. However, much remains tobe learned about the combined effect of imbibition, gravity, and bothmicroscopic and macroscopic fluid distribution on oil recovery from fracturedsystems. Development of analytical functions or other computational schemeswhich account for mass transfer between rock matrix and fractures is of specialimportance to mathematical modelling of fractured reservoirs (Aronofsky et al.,1958; Warren and Root, 1963; Kazemi et al., 1976; Kazemi et al., 1992, Chen etal., 1995) Scaling of spontaneous imbibition henomena is a critical step inthis development. Provided that gravity effect can be safely neglected, capillary pressure is the driving force for spontaneous imbibition.Permeability and relative permeabilities in the two phase region of flowdetermine the rate of imbibition. Both capillary pressure and relativepermeability are functions of saturation. Thus many factors enter into scalingof imbibition rates. The effect of fluid viscosity is of primary concern inthis study. The effect of core sample shapes and boundary conditions will alsobe discussed. Imbibition In Tubes Most analyses of imbibition consider behavior in cylindrical tubes. For acylindrical tube of radius r, the Laplace equation gives the capillarypressure, P C P C = Equation (1) Available in full Paper where s is the interfacial tension and ? is the contact angle. The relationship between permeability, k, porosity, f and tortuosity, tfor aparallel bundle of equal size cylindrical tubes with radius r is given by Leverett (1939). r = Equation (2) Available in full Paper Thus the capillary pressure, Eq 1, can be expressed as P C = Equation (3) Available in full Paper The ratio of permeability to pore size gives a characteristic pore structurelength

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

Abstract Closed-loop drilling operations in environmentally sensitivity areas require integration of conventional solids control system with the chemically-enhanced centrifugation, a continuous dewatering process. The paper presents a design method for continuous dewatering. The method is based on the rigsite mud dewaterability testing and the breakeven cost economics. The protocol for dewaterability test describes instrumentation and stepwise procedure to measure dewatering cake's moisture content and evaluate efficiency of volume reduction. Emphasized is preparation of weighted mud samples through removal of weighting material and correction for residual burite. The presented testing protocol eliminates volumetric measurements and replaces them with weight measurements which improve accuracy by an order of magnitude. The paper explains how to use results from dewaterability tests to analyze cost efficiency of the dewatering component in closed-loop drilling operations.. The analysis is based upon all analytical model of breakeven cost. The model combines dewatering with depth-related quantities representing drilling progress and rates of waste generation, recycling and disposal. The paper shows: 1-How to evaluate dewatering performance while drilling: 2-How to set up technical requirements soliciting bids for dewatering services: and 3-How to predict drilling depth below which the process is not economical. Introduction Continuous dewatering of drilling mud is a well site process for separating and recycling the mud liquid phase and minimizing the volume: of drilling waste. The process has been already patented [1] and used in field operations [2,3,4]. The analysis of published reports from these applications shows that economic performance of the dewatering process depends primarily upon three factors: 1-high cost of off-site disposal: 2-restricted disposal on-site (a ban on the annular injection, for example): and. 3-the degree of volume reduction attained through dewatering [5]. Therefore, any successful implementation or The dewatering process requires testing the mud dewaterability and combining the test results with cost factors to analyze process economics. Dewaterability is the ability of a drilling fluid to release its water phase if subjected to mechanical expression. Before the expression, the drilling fluid has to be chemically conditioned in order to destabilize the suspension and free the water phase. (The design of chemical conditioning and its optimization has been described elsewhere [6].) Like other characteristics of drilling muds - the API filtration, for instance - dewaterability results from complex physical mechanisms but can be determined simply by measuring relative volume of released water and moisture content of the dewatering drilling fluid to calculate volume reduction efficiency E VB . The objective of this paper is to present the dewaterability testing procedure. Currently, the only method for evaluation of dewatering performance is based on post-well or monthly recaps. In this method, cumulative volume of waste drilling mud is used to average cumulative expenditures and calculate the cost of dewatering per one barrel of waste mud [7]. Then, this cost is compared with the hypothetical disposal cost or the same barrel without using dewatering process. Finally a conclusion is made whether the use of dewatering would result in savings or losses.

Abstract Only a few recent thermal projects targeting the extensive heavy oil and bitumen deposits in Alberta and Saskatchewan have been technical successes, and even fewer yielded acceptable economics. One cause appears to be an engineering approach which neglects existing geologic data, and resists collection of additional data. When incorrect reservoir models are adopted, most tasks initiated to improve project performance are severely impeded. For example, lab tests and conceptual and numerical modelling predictions are often misdirected to solve the wrong problems. Studies done in-house, by universities, and at government facilities are affected. Technical contributions from this paper are: (1) Recognition that you cannot force a reservoir to respond in agreement with a preconceived simplistic descriptive model, (2) Enhanced awareness of the level of knowledge required to adequately describe reservoirs being considered for thermal EOR projects, or to better understand the performance of existing projects, and (3) Recommendations for obtaining the information required to better describe reservoirs during the current challenging economic environment. Introduction Numerous Alberta and Saskatchewan thermal EOR field projects were initiated during the early 19BO's, but few survived the oil price drops of the mid-to late 1980's. Many workers were removed from this technical area without an opportunity to document their theories regarding possible technical and economic improvements, The large volumes of heavy oil and bitumen in place, but not yet economic, merit more documentation, and one objective of this paper is to stimulate interest in this task. It is the author's opinion that the two major causes of project failure were: inadequate understanding of the geologic features of the reservoir, and hesitancy to take the steps required to obtain the information required to remedy the problem. Recent technical literature describes methods of greatly enhancing understanding of reservoir geology (for example, see Hong (1) , Chopra (2) , Olea (3) , and Dusseault (4) ) . However, these methods appear to be economically impractical for Western Canadian heavy oil and bitumen reservoirs, which are thin in areas such as Lloydminster (Figure 1) and produce low priced liquids. If the reservoir is owned by a small oil company, with limited operating capital, cost limitations would be even more restrictive. Discussion Who Says Predicting Reservoir Geology is a Problem? Most articles or papers discussing Western Canadian thermal field projects contain statements about the detrimental affect of unexpected geologic features. Recent examples are. AOSTRA's book summarizing their first 15 years of operation (5) , and recent articles discussing Shell's Peace River project (6) , the Ipiatic Heavy Oil pilot (7) , and Imperial's Cold Lake project (8) . Perhaps some solace can be obtained from a recent statement by SPE President Jaques Bosio that one of the primary reasons EaR projects fail is "... the lack of knowledge of our reservoirs (heterogeneity) ...." (9) , and from learning that geologic surprises are also encountered in Venezuela (10) . . Why Wasn't Reservoir Geology Adequately Described Initially? In selected cases it probably was. Some reservoirs were apparently deposited uniformly, and require less information to develop an accurate description. And, major oil companies had the capital to dedicate geologists

Abstract More than 500 horizontal wells have been drilled in Western Canada during the period January 1988 to July 1992. The number of wells drilled each year has increased exponentially. Production data from these wells is providing useful information which could be used to evaluate the performance of these wells. In this paper, we review a cross-section of the more successful wells and the not-so successful wells. We examine the more important parameters responsible for the performance. Some of these parameters are (1) Reservoir Permeability; (2) Length of the Horizontal Lateral; (3) Drainage Area; (4) Fluid Viscosity; (5) Drive Mechanism; (6) Orientation of the Horizontal Well and (7) Formation Damage from drilling. Based on the performance we attempt to develop screening criteria for wells in the various areas. Finally, we look at some of the recent innovations. In particular longer horizontal laterals (greater than 1000 meters) underbalanced drilling and re-entries; and the impact they are having on horizontal drilling. Introduction The horizontal drilling activity in Western Canada is impressive, from less than 30 wells in 1988 to 741 wells by the end of 1992. The cumulative production to date from horizontal wells is approximately 5.4 million cubic metres (34 million barrels) In 1992, the production rate was 7,600 cubic metres per day (48,000 Bbls/day). What have we learned from our half-billion-dollar field experiment? What is Western Canada's real resource base for Horizontal Well Technology (HWT)? Over the next ten to fifteen years can we expect 10,000 horizontal wells to be drilled, enhancing Western Canada's ultimate recovery factor by 2% from about 28% to 30% and thus producing an incremental 300 million cubic metres. This paper reviews a cross-section of the wells drilled to date in Western Canada and examine some factors that contribute to their success or failure. A detailed review of technical papers and discussions by the operators on the different projects was conducted. These included, presentations at CIM Conferences, Horizontal Well Special Interest Group seminars and monthly meetings, and other local meetings and seminars. A questionnaire was sent to operators most active in horizontal drilling requesting various field and production data. Responses to the questionnaire in conjunction with production data from individual wells and our technical review provided the basis for our discussions and conclusions. In addition, an attempt was made to provide some general "screening criteria" for horizontal wells in the various areas. Why Horizontal? The primary advantage of a horizontal well over a vertical well is the increased contact with the pay zone. Instead of a few metres of the wellbore being in contact with the formation, a horizontal well can have several hundred meters of net pay and a correspondingly higher production rate. Other reasons for drilling horizontal wells are to reduce coning and help produce low permeability reservoirs. Another Important and topical question is, do horizontal wells actually increase the ultimate reserves? How are these concepts standing up to field application? We will discuss these concerns mainly from the Western Canadian Basin perspective.

Abstract Isochronal, modified isochronal, and LIT testing are used routinely as a basisto forecast deliverability of gas reservoirs. This paper shows an applicationof this technique to the naturally fractured Palm Valley gas field in central Australia. Results are corroborated with the use of a dual-porosity numericalsimulator. The initial isochronal tests of 4 wells are presented together with thedeliverability equations. This is followed by a comparison with 40 months ofproduction history. The data show that values of "e" in the Rawlins and Schellhardt equation have been declining continuously for all 4 wellsthroughout the 40 months of production history. The conclusion is reached that conventional isochronal test analysis is notreliable to forecast deliverability References and illustrations at the end ofpaper of gas wells in naturally fractured reservoirs. Use of this approach caneasily lead to optimistic forecasts. Introduction The Palm valley Gas Field is situated in the central-northern Amadeus Basin, Northern Territory, Australia (Fig.1) approximately 120 km. southwest of Alice Springs. The structure is an arcuate anticline mapped from surface expressionand seismic data (Fig.2). The western and eastern plunges are poorly defined, however, the anticline axis can be traced for over 40 km. Production from the field commenced in August 1983 with the completion of an 8"pipeline to Alice springs. Natural gas has been used as a replacement forliquid fuels in electricity generation. Gas production from the field hasincreased steadily currently averaging 141,000 standard m 3 /d (5MMSCFD) to Alice Springs. In September 1986 a fourteen inch trunk pipeline was completed connecting thefield to the city of Darwin, 1300 km to the norch, and to several major townsen-route. Production for this pipeline has reached 622,000 standardm 3 /d (19 MMSCFD) and again has been used as a liquid fuelreplacement in electric power generation. Development of the field has followed the definition of reserves and during thepast 24 years, estimation of the gas reserves has been the subject of manystudies. The most significant being by Strobel et al. ' in 1976; areservoir simulation study by van poollen and Associates in 1985 and a recentreserves study by servipetrol Ltd. in 1990. These studies quantified reservesof 1.08 × 10 9 standard m 3 (3B.2 × 10 9 SCF),9.2 × 10 9 , m 3 (325 × 10 9 SCF), and 19.25 x10 9 m 3 (680 × 10 9 SCF), respectively andreflect the increasing contribution of production history and technologicaladvances. To July 1991, 1.20 × 10 9 standard m 3 (42.3 x10 9 SCF) has been produced from the field over its 24 year life andthis now provides valuable history for reserve studies. A recent paper by these authors 2 presented drawdown and buildupanalysis of the Palm Valley field using type curves for dual-porosity systems, 3 pressure derivatives, specialized semilogarithmic crossplots, anda numerical simulator for dual-porosity systems. The results of the analysiswere highly satisfactory. Another publication by these authors presented thenumerical simulation of Palm valley_ 4