Abstract Miscible flooding is considered unsuitable for some reservoirs in southeast Saskatchewan because of high CO, minimum miscibility pressure or operating pressure constraints. Therefore, the effectiveness of near-miscible CO 2 injection was assessedfor Steelmnn reservoir in a laboratory study. The minimum miscibility pressures (MMP) were estimatedfor Steelman reservoir fluids with pure CO 2 and CO - - hydrocarbon gas mixtures, the partially flashed reservoir fluids and the dead oils with pure CO 2 The results of MMP studies demonstrated i) addition of ethane orpropane can reduce CO, MMP greatly; and ii) achieving a miscible CO 2 flood in the Steelman reservoir could be possible at a lower operating pressure than the measured CO, MMP, by partially depleting the reservoir. Asphaltene flocculution tests showed that, after the onset point, flocculation increased linearly with gas concentration, but that the presence of brine had a negligible effect. Three tertiary CO, coreflood tests were conducted with Steelman reservoir fluids at the reservoir temperature. These results showed that the microscopic displacement efficiency during the CO, injection stage improved with the operating pressure in the near-miscible region, but no dramatic change in oil recovery was observed with a change in operating pressure. Introduction The Steelman pool, located about 200 km southeast Regina, Saskatchewan, was discovered in 1954. Covering approximately 370 km 2 , the field was estimated to contain over 134 million m 3 of light oil in the Frobisher and Midale beds located at about 1,400 meters. Most of the reservoirs in the Midale beds, which contain about 83% of the reserves of the pool, have been under waterflood for over 20 years and have nearly reached the estimated production limit by primary and waterflood.' For achieving additional oil recovery and consequent financial benefits, the development of tertiary enhanced oil recovery (EOR) techniques, such as CO, flooding, is essential. Miscible CO, flood is a proven enhanced oil recovery technique.' Over the last decade, CO injection has become the leading EOR process for light oil. 3 In Canada, the industry interest in CO, flooding is evidenced by Shell Canada's CO, pilot tests, a Miscible CO, flood at Joffre field in Alberta, 6 and the implementation of PanCanadian's Weybum CO, injection project.' Additional field applications are expected to be initiated in southeast Saskatchewan and other regions when CO, sources are available. Miscible CO 2 displacement offers the greatest oil recovery potential but can only be achieved at a pressure greater than a certain minimum referred to as minimum miscibility pressure (MMP). The effect of solution gas on the development of miscibility is not well understood, as reflected by the lack of a consensus in the literature. Rathmell et al. 8 found that CO 2 MMP is related to the volatile and intermediate fractions ofthe oil. Yelling and Metcalfe 9 found from their experimental study that, for a saturated reservoir oil, areal variation in gas-oil ratio (GOR) will result in an areal variation in the CO 2 MMP.

Abstract Bentonite organo-clay/anthracite mixture in the granular form (EC-1 00) wasused in filtration (column) studies in treating four representativeoil-in-water emulsions. The oilin- water emulsions used were as follows:standard mineral oil (SMO); Kutwell45 (KUTJ and Valcool (VAL), two cuttingoils; and refinery efluent (RE) from the Co-operative Oil Refinery, Regina, Saskatchewan The concentrations of oil in oily waters varied from 8.3 to 69.3mg/L. Eight-hour column studies were conducted in a 19 mm ID, 450 mm/l200 mmlong cast acrylic pipe with organo-clay/anthracite depth of 300 mm/l000 mm. The SMO, KUT, and VAL oil-in-water emulsions were pumped into the column at fourflow rates of 3, 6, 9, and 12 mL/min (0.3, 0.5, 0.8, and I.0gpm/ft 2 , respectively). Column breakthrough studies were conductedin a 19 mm ID, 1200 mm long cast acrylic pipe using the organo-clay/anthracitemixture of IO00 mm depth. The study was conducted for SIUO, KUT, VAL and REoil-in-water emulsions with a flow rate of 12 mUmim (I gpm/ft 2 ). Theeight-hour column tests with 300 mm bed depth and all oilin- water emulsionsindicated that generally, the oil removal efficiencies decreased with anincrease in flow rate. The percentage redaction in oil removal efficiency was29 and 37 for SMO, 51 and 59 for Km, and 9 and 57 for VAL when the flow ratewas increased from 3 mUmin to 6 and 9 mLJmin, respectively. The results of theeight-hour experiments with 1000 mm depth of organo-clay/anthracite bed andwith a flow rate of I2 mUmin showed that oil removal eficiency for SMO, KUT, and VAL varied between 65 and 70 percent. In the case of RE which is a treatedand highly stable emulsion, the oil removal efficient was found to be 99.5percent. The results from the breakthrough studies clearly indicated that theThomas' equation provides a reasonable fit of the data. The oil-sorptioncapacities (x/m) based on a mass balance analysis were found to be 0.0036,0.0019, 0.0015, and 0.0018 for SMO, KUT VXL, and RE, respectively. The analysisof breakthrough data using Thomas model resulted in similar values of x/m. Theresults also showed that uptake of oil by organo-clay/anthracite mixture canwell be described by a simple equation involving time such as Weber and Mowismodel. Introduction Organo-clay can be described as modified bentonite. The modification processbecomes complete by exchanging the inorganic cations (sodium and calcium)present on the surfaces and interlayer spaces of clays by the nitrogen end of aquaternary amine, and thus changing the hydrophilic nature of clays toorganophilic 1,2 , As a result, organo-clays become excellent sorbentsfor hydrophobic organics such as oie. An advantage of organo-clay compared toother sorbents is that it can selectively remove organic pollutants fromcontaminated waters. The sorptive nature of bentonite organo-c1ay for some organic pollutants hasbeen extensively studied 4,s,6,7,8 . However, the effectiveness oforgano-clay/anthracite mixture as a filter in the removal of oil from water hasnot been studied extensively. Alther (1995/found bentonite organo-clayeffective in the removal of oil from oily waters.

Abstract A new approach to workovers using large-amplitude excitation of the wellbore fluid has proven successfir in establishing or restoring well productivity in Cold Heavy Oil Production (CHOP) wells in Alberta and Saskatchewan. The workover Qpically takes from five to 12 hours, and involves large amplitude pressure pulses achieved by sudden stroking of a downhole piston. A great deal of strain energy is input to the reservoir by the aggressive stroking, and this unblocks the near-wellbore, loosens and liquefies the unconsolidated formation, and even affects the interwell region, where stable large-scale sand arching can be perturbed so that sand production can recommence. A fluid such as dead oil from the same field, can be simultaneously introduced during pulsing, or it can proceed without net fluid addition. The method has proven useful as a means of bring a well onto reasonable production by initiating sand influx where other methods have failed. It is different than swabbing, which may reconsolidate the unconsolidated sand. Pressure pulsing instead pushes the sand vigorously away from the perforations with an aggressive liquid pulse, and this leads to permanent porosil), perturbations. These perturbations, which propagate gradually out into the reservoir, loosen precipitated asphaltenes and fines, as well as loosening the sand, so that when the well is placed back on production, a disturbed zone that is sufficiently large to lead to continuous sanding is generated. In several cases, wells that had never produced more than I m 3 /d because of a failure to initiate sand injlux were converted into reasonable CHOP wells (4–8 m 3 /d). In a number of cases, pressure pulsing has even reconnected the wellbore to high pressures that existed in the far field. The mechanisms are relatively well understood, as a theoretical model exists to explain them. In practical terms, we Us generally become better producers, and the method can also be applied to conventional well workovers in all cases where mechanical skin exists or chemicals are to be placed. Introduction Although it is generally applicable to any case of mechanical blockage or chemical placement, the PE-TECH P ulse E nhancement TECH nique) workover approach was initially developed for oil wells that use the method of Cold Heavy Oil Production l,2 (CHOP). It has been applied in 30 cases in 9 different fields since the first experimental trials in June 1998 in Alberta and Saskatchewan (Table 1). A reasonable success ratio has been given the developmental nature of initial efforts and because many of the initial candidates were generally wells that we now consider poor candidates through our rigorous selection criteria. The PE-TECH workover method is beneficial in wells where production cannot be initiated by standard well completion methods, where mechanical blockage (fines, asphaltenes, perforation plugging) and near wellbore damage due to drilling mud or cement invasion inhibit flow into the wellbore. As well, given that pressure pulsing promotes fluid dispersion rather than fmgering, the PE-TECH workover method is the best technique to introduce a chemical in a uniform, well-dispersed manner into a reservoir.

Abstract Three years experiences of solids disposal using Slurry Fracture Injection (SFI) are reviewed Seven separate projects in Saskatchewan and Alberta have provided an experience base in waste management using SFI. and a regulatory framework is evolving. The article addresses the technological and regulatory environment necessary for the safety operation of SFI to give the best possible environmental security and resource protection in the long-term. The regulatory agencies involved in permitting SFI of non-hazardous oilfield wastes must assure that there are no long-term effects related to potable water contamination or degradation. surface land use impairment. or loss of current or potential future natural resources. The hest way to achieve these goals is first to establish a flexible yet appropriate set of guidelines which guarantee that applicants have carried out appropriate site. reservoir. well. and SF! process operations planning before a permit is issued. Thereafter. the major regulatory tasks are to maintain audit control of waste volumes. enforce a minimum monitoring level which will give a high confidence of waste containment in the target zone. assure that any near-by resources are not being impaired. and that only the permitted wastes are being injected. At a minimum. stream volumes. bottom-hole pressures. well integrity demonstration. independent proof of containment. and regular auditing and reporting requirements are suggested Over-regulation is to be avoided to allow SFI to take place under the most effective operating conditions. Introduction Slurry Fracture Injection (SFI) for the deliberate disposal of large quantities of waste sand was first tried by Mobil Canada in Saskatchewan at the Celtic Pilot northeast of Lloydminster in the period 1988–1990. In the period 1993–1997, a number of SFI operations have been permitted in Alberta and Saskatchewan to dispose oily sand, "slops", and produced or waste water. The technology is now widely understood, and a regulatory framework is evolving in Alberta to permit SFI projects to proceed in an environmentally secure manner to meet the goals of the regulatory bodies as well as the goals of the oil companies. To understand the need for regulatory control and enforcement, it is necessary to understand the basic technological aspects of SFI, the arguments levied to justify its environmental security, and the capabilities of monitoring and analysis. This article will address these issues in terms of the geological structures and the industrial practices of Western Canada. Then, recommendations for a specific approach to regulatory management will be made and justified. OILFIELD WASTE STREAMS Large volumes of non-hazardous oilfield wastes (NOW) are produced during oil and gas exploration, drilling, production, and refining. Table 1 describes some typical NOW streams generated during oil and gas development, although some of the refinery streams may have high levels of-metals and other compounds which may result in a hazardous classification. The two largest NOW streams in Canada are produced water and sand from cold production of heavy oil. Most produced water is filtered and injected into disposal formations at pressures below natural fracture pressure. Cold production involves letting sand enter the wellbore during heavy oil production to increase production efficiency 1 .

Introduction Horizontal wells have helped in advancing the oil industry since it was first introduced in 1980 1 . As useful as horizontal wells have become, the need for careful preparation become even more imperative before drilling can begin. As a result. the oil industry wants to be sure that a horizontal well is the right choice and will be economical. This reassurance is obtained through the use of field simulators which simulate a well's operation and production. These computer simulations require careful preparation and accurate input data with the results being within accepted tolerances. Engineers and oil companies also require a quick and easy method (plug and solve) of calculating production rates with "ballpark" results. Thus the question arises. what variables should be used and what models should be used? The answer is to simply use horizontal flow rate equations based on a few reservoir and fluid properties and reservoir and well dimensions. This paper will examine the result of a number of calculations using four horizontal flow rate equations (Borisov 2 , Giger 3 , Renard and Dupuy 4 , and Joshi 5,6 ) and compare the predicted results to actual daily averaged oil flow rates and cumulative oil production figures. HORIZONTAL WELL HISTORY Horizontal drilling and production started in Saskatchewan in the 1950's. These early oil wells consisted of only vertical wells. This conventional method of oil recovery initially met the production needs and oil recovery percentages ofthe time. Under favorable conditions (no formation damage, high initial reservoir pressure, no gas or water coning, etc.) vertical wells would recover no more than 60 percent of the original oil in place (OOIP) 1 . As oil needs increased and existing oil reservoirs were being abandoned before the reservoirs were depleted because no further oil could be recovered using conventional vertical wells or enhanced oil recovery (EOR) methods. another oil recovery methods were required The latest method is the use of horizontal wells. The use of horizontal wells in Saskatchewan began in 1987 and have greatly influenced the province's oil production. As of December 1994, there were 1385 producing horizontal wells and 14138 producing vertical wells in Saskatchewan. 7 Although horizontal wells accounted for only 8.9 percent of the total number of wells, horizontal wells accounts for 33.8 percent of the total oil production. More specifically, the annual production ofheavy oil increased to almost 6 million m 3 ofoil per year. The quarterly provincial oil production for horizontal wells steadily increased to where it is approximately a third ofthe total oil production. Figure 1 shows the provincial monthly oil production from horizontal wells with the total oil production broken down into heavy oil and light/medium oil production with a noticeable substantive increase in well production occurring in the middle of 1992. Figure 2 shows the number of horizontal wells drilled per year in Saskatchewan and the type of oil being produced since 1987. The number of horizontal wells broke the 500 barrier in 1993. Figure 2 also shows the total cumulative number of horizontal wells in Saskatchewan and the number of wells drilled for heavy and light/medium oil.

Abstract Weyburn reservoir, Located in southeast Saskatchewan and operated by PanCanadian PetroLeum Ltd., has reached its economic Limit of production by waterflooding. The reservoir is a target for tertiary CO 2 miscible flooding to enhance oil recovery and extend its production Life. A comprehensive study has been conducted by the Saskatchewan Research Council and PanCanadian to assess the suitability of the process for Weyburn. This paper presents a technical evaluation of CO 2 near miscibleinjection for Weyburn reservoir. This is based on laboratory studies conducted with three Weyburn oils collected from different regions of the reservoir. These studies included: measurement of minimum miscibility pressure for the reconstituted reservoir fluids for pure and impure CO 2 , determination of PVT properties for reservoir fluid-CO 2 mixtures. and assessment of recovery behaviour from uniquely designed Laboratory coreflood tests representing the permeability contrast of the reservoir. The studies indicated that the CO 2 minimum miscibility pressure for the Weyburn reservoir oils varied from about 11.5 to N.5 MPa. indicating suitability for CO 2 miscible flooding. PVJ data generated for the three Weyburn reservoirfluid-CO 2 mixtures showed that viscosity reduction and oil swelling by CO 2 also contributed to oil recovery. A slight manipulation of he measured PVT properties of the mixtures made it possible to obtain single property curves for the three Weyburn oils. This feature can be used to estimate the PVT behaviour for any Weyburn oil from the reservoir. Coreflood studies showed that CO 2 injected into the Vuggy zone could rise to the upper Marly zone and heLp enhance oil recovery. A separate simulation and modelling study conducted by PanCanadian Petroleum Ltd. satisfactorily matched the experimental PVT propenies. MMP values and recovery mechanism suggested by the coreflood behaviour. Introduction The total oil reserves of Saskatchewan are estimated at over 3 billion m 3 of initial oil-in-place (lOIP). The light and medium oil (LMO) reserves contribute approximately 1.6 billion m 3 IOIP. 1 Over 10% of the LMO reserves, or 178 million m 3 IOIP, are held in Weyburn reservoir. The Weyburn field is located approximately 130 km southeast of Regina in Saskatchewan and covers over 180 km 2 of production area. The field was discovered in 1955 and PanCanadian Petroleum (PCP) Ltd. is the major operator. It has over 627 producing wells and 162 water injection wells on approximately 24 ha spacing. 2 . The oil production from the Weyburn field comes from Midale beds of the Mississippian Charles Formation in the Williston Basin at a depth of 1310 to 1500 m. The field was produced by primary depletion for about 9 years until 1964. Waterflood was started thereafter using a nine-spot pattern. In 1985, to optimize the waterflood performance, both horizontal and vertical infill drilling programs were initiated. The combined oil recovery by primary and secondary production was approximately 28% IOIP by 1994. Waterflooding has almost reached its economic limit for the Weyburn reservoir. The ultimate conventional recovery is expected to be 31% IOIP, leaving a large target for tertiary recovery techniques. 3 A similar situation exists for the majority of Saskatchewan's LMO reservoir. 1,4

Introduction TransGas Limited (TGL) currently owns and operates 24 salt caverns for the storage of natural gas. These storage caverns were developed in an extensive salt bed running through the province of Saskatchewan called the Prairie Evaporite, see figure 1 in the appendix. TransGas was the owner, operator, and user of all our storage caverns until 1988. In 1988 TransGas was split from the provincial crown electric utility and became a separate crown corporation. The new company had two components, a local distribution company (LDC) and a transmission & storage company. Initially the only storage customers were the electric utility and the LDC. In 1990 TransGas started to market our storage services to other customers. This meant increased demand for our storage services. TGL usually produced gas during the winter season and injected gas in the summer months, (one injection/production cycle per year). With the market expansion more frequent cycling of gas in storage was anticipated. The expansion in market also meant maximizing the useable volume of the storage facilities. TransGas traditionally set the minimum cavern operating pressure of our storage caverns at the expected transmission pipeline pressure. The resultant minimum bottomhole pressures were 0.12 to 0.13 psi/ft of depth to the cavern roof. The minimum cavern pressure was rarely reached prior to 1990. The maximum bottomhole cavern pressure was based on the depth to the cavern roof, 0.70 psi/fool. We had experienced some problems with three of our Regina caverns. Roof falls and side wall falls had resulted in the derating of these caverns. We decided the time was right to closely examine the design pressure of our caverns. Specifically we wanted answers to the following questions: Was our minimum design pressure acceptable? Was our maximum design pressure acceptable. Could we lower our minimum design pressure? Could we raise our maximum design pressure? Could we increase the useable volume of our caverns by changing the operating pressures? What impact did cycling have on the caverns. To determine the answers to these questions TransGas hired two consultants to assist with modeling our caverns. The two consultants were Dr. Gabe Fernandez and Murray Forster. Dr Fernandez is a Geotechnical Consultant and professor at University of Illinois Murray Forster is a Geotechnical Consultant in Saskatchewan. Doug Ruse, a local consultant, also reviewed the results of theses studies. This report summarizes the fmdings of these studies. Prairie Evaporite Salt Bed Material Properties Salt is a unique material. Salt's material properties depend on how it is loaded. When salt is loaded at low levels it will creep and deform. This creep and deformation ability is what makes salt "self-healing". Potash mines in Saskatchewan have experienced failure at stress levels well below that indicated by lab analysis. Dr. Malcolm Reeves of the University of Saskatchewan published a paper on "Dynamic brittle-rupture stable creep criteria in evaporite mine design". In his paper Dr. Reeves discusses the effect of stress on strain rate.

Abstract In order to sustain the current production capacity of conventional oil in Western Canada, enhanced oil recovery (EOR) technologies must be increasingly applied. Among these, carbon dioxide (CO 2 ) flooding is a highly attractive possibility A large amount of CO 2 is being produced by coal-fired power plants in this region. The CO 2 is currently discharged into the atmosphere and could be a major contributor to the so-called greenhouse effect, which would lead t0 global warming. 'Thus, the concept of capturing CO 2 and utilizing it as a flooding agent in EOR processes is currently generating much interest among oil, utility and coal companies. This paper demonstrates how cogeneration concepts, together with process optimization strategies, help to reduce the CO 2 production cost by utilizing low-pressure steam and waste heal from various sections of the power generation process. Based on these concepts and strategies, results from this study show that the recovery cost of CO 2 from a coal-fired power plant can range between ﹩O.50-2.00/mscf. Therefore cost is approximately S1.25/mscf, the production cost of a barrel of incremental oil would be less than ﹩18. Therefore, even at today's modest oil prices, there is room for profit to be made operating a CO 2 flood with flue gas extracted (,OJ. The technical and economical feasibility of the concepts are evaluated and the practical implications for the Saskatchewan resources are discussed. Introduction The concept of capturing carbon dioxide from coal-fired power plants and utilizing it as a flooding agent for enhanced oil recovery (EOR) processes is currently drawing much interest from oil, utility and coal companies in Western Canada. Implementation of such a scheme would provide two important benefits: the captured CO 2 , could be marketed as a flooding agent which would generate revenues and CO 2 emissions to the atmosphere would be reduced. Since CO 2 emissions arc considered to be the main contributor to the possible serious environmental problem of global warming, the proposed scheme could become an important instrument to reduce such emissions at minimal incremental cost to the environment. In the past few years a few pilot test projects on CO 2 extraction from the Canadian coal-fired power plants (such as the Sundance and Boundary Dam projects) were organized by consortia of oil companies in collaboration with government organizations and utility companies these projects were primarily aimed at using the recovered CO 2 for EOR applications. A variety of process technologies available from gas processing including chemical gas absorption, cryogenic separation, dry bed adsorption, and membrane separation processes were screened. The lc1ection process resulted in the chemical gas absorption process being chosen as it had better overall economical advantages and a proven operability record over other processes l,2 . However the pilot plant results demonstrated that eyen though this process technology was technically feasible chemical gas absorption capital and operating costs were too high for EOR applications in the current crude petroleum market. The primary reason for the high cost of CO 2 extraction was that a substantial amount of energy was required for the process.

Abstract Heavy oil accumulations in A1ississipian carbonate rocks, immediately subjacentto the sub-A1esozoic unconformity in southwestern Saskatchewan, have been knownfor more than forty years. Until late 1993, sporadic attempts using verticalwells to recover oil trapped at Battle Creek have attained about 17, 000m 3 in 15 years of production. However, recently drilled horizontalwell indicate there is potential for much higher yields over shorter timeperiods. The reservoir rocks were deposited on a ramp that prograded over olderMississippian deeper water and basin slope carbonates. The ramp rocks includecrinoidal grains/ones and packs/ones, interbedded with lime muds/ones andcrinoid-rich wackestones About 15–20 m below the unconformity the grainstones and packstones have beensealed by calcite Cf!JlJeI1B. However subjacent to it, they were extensivelyaltered. Skeletal components of the grainstunes and packstones were micritized, and in places, preexisting particles and interparticle cements have been wholly01' partically dissolved, exhuming original porosity or creating enlarged vugs.Furthermore, the paleotopograplucally positive features on the unconformityhave been dolomized. Lithologies affected include: micritized skeletalcomponents of grains/ones and packstones and micrites of packstones, wackestones and lime mudstones. Diagenesis has created two suites of non-reservoir rocks and three of reservoirgrade. Porosities of 8–41%, permeabilities of 8–5/2 md, and entry pressuresless than 4 kg/m 3 make up the reservoir rock properties found atBattle Creek and several other poorly exploited localities Introduction The Mississippian rocks of southwestern Saskatchewan unlike their counterpartson the eastern flank of the Williston Basin, have been known to exclusivelycontain heavy oil shows, The shows in cores, drill cuttings and drillstem testshave been recognized since the early days of drilling in both southeastern Alberta and southwestern Saskatchewan. However, their producibility wascommonly overlooked because of the extremely low gravity of the oil (in theorder of 11 ° API). In a study for the Saskatchewan Department of Energy andMines, Kent and MacEachern 1 identified twenty-four heavy oil showsin Mississippian core and drillstem tests from the area between range 20 westof the third meridian and the Alberta/Saskatchewan Interprovincial Boundary andtownship 1 to township 15, inclusive. The most impressive of these shows was adrill stem lest from the Coop et al.. Battle Creek 1–27 well (Lsdl27-3-26w3)thaI recovered 1262 m (4140 ft) of 11 ° API oil from an interval inMississippian rocks immediately beneath the sub-Mesozoic unconformity.Subsequent tests in the same well yielded mainly water and it was eventuallyabandoned. However, this discovery identified the Battle Creek area as apotential heavy oil producing area and in 1966. Western Decalta offset the 1-27well with two boreholes at IA-27-3-26W3 and 6-27-3-26W3. The former wasabandoned shortly after completion but the latter produced oil from theMadison at the same stratigraphic level as the discovery well for about one anda half years (1966 to 1968) until a fire at the treated caused the operator toabandon the well.

Abstract The changing political circumstances surrounding carbon dioxide and other greenhouse gas emissions due to their potential impact on climate change are discussed. Greenhouse gas emissions are the basis for substantial effort at the international level to reach consensus on targets for reducing emissions. While these targets are currently non-mandatory, the possibility exists that more enforceable regulations could be implemented in the future. Continued political and public support for stricter measures to reduce emissions will depend on more conclusive scientific evidence for serious social and economic impacts from climate change being proven. A number of companies in developed nations have decided that the risk of enforceable measures to reduce emissions are such that they have begun action to if effectively cut their release of greenhouse gases. These projects are usually reforestation projects, using biomass to capture and store atmospheric carbon, in less developed tropical nations. Such action does, however, implicitly provide a value for CO 2 . International action in the future could extend the application of these individual projects by providing some form of recognition. This would implicitly raise the value of CO 2 and potentially provide benefits to CO 2 EOR projects. Government action to reduce emissions through the taxation system or by regulation would increase the value of CO 2 further and have greater beneficial impacts on the economics of EOR projects. Introduction It is the purpose of this paper to describe some of the issues facing government and industry decision makers as they develop energy and environmental policy or plan longterm projects, such as the Weyburn EaR project in South Eastern Saskatchewan, that will impact on the production, use and economics of CO 2 . Other papers presented during this conference will provide detail on the Weybum EOR project and technologies for the production of CO 2 . Additionally, it is not the intent of this paper to debate the reality of climate change and the part anthropogenic CO 2 or other greenhouse gas emissions) emissions play in this potentially major environmental issue - there is already substantial material available on this debate in the popular and scientific literature. Saskatchewan and the provincial oil industry were interested in CO 2 as an agent for enhanced oil recovery in Saskatchewan reservoirs before climate change became an issue on the world political stage. In 1987, Shell Canada, Dome Petroleum and Saskoil, with the support of the federal and provincial governments and SaskPower, agreed to test the amine technology for extracting CO 2 from the flue gases of a coal-fired power plant at SaskPower's Boundary Dam electrical generating station. This test was a follow-up to the test at TransAlta's Sundance power plant where the flue gases contacted the amine without pre-treatment. While the process worked, amine losses were such that the CO 2 recovered would have been prohibitively expensive. The pilot was operated in Saskatchewan in 1988, at that time the hottest year on record and the summer that convinced some people that climate change had occurred, providing a test for the plant under extreme weather conditions.

Abstract Large volume underground storage of hydrocarbons has been developed and practiced in Saskatchewan. Canada for many years. Use of these facilities has gained importance in recent years, due mainly to economical and environmental reasons. TransGas Limited currently has 42.8 billion cubic feet (Bcf) or 1206 million cubic meters (10 6 m 3 ) of working storage capacity. Of this total 14.1 Bcf (397 10 6 m 3 ) is held in solution mined bedded salt caverns and the remaining 28.7 Bcf(809 10 6 m 3 ) is held in depleted gas pools and gas caps. The total gas storage capacity, is 83.97 8cf(2366 10 6 m 3 ) of which 16.46 Bcf (463 10 6 m 3 ) is held in caverns and 67.51 Bcf (1902 10 6 m 3 ) is held in depleted pools. All of the depleted gas pools are located on the western side of Saskatchewan, mainly in Lower Cretaceous sandstone reservoirs. The washed salt caverns are scattered across Saskatchewan, all developed in the halite portion of the Middle Devonian Prairie Evaporite salt bed. Traditionally, TransGas Limited has developed its solution mined salt storage caverns from start to finish to supply Saskatchewan customers.. However, in the increasingly competitive North American natural gas storage market, TransGas Limited has had to look for innovative methods to develop cost effective storage facilities while providing new market development opportunities, One method of prodding natural gas storage service, used in two recent cases, is to convert existing salt caverns, previously used to Store Liquefied Petroleum Gas (LPG) products, to natural gas storage. TransGas Limited currently owns, leases and operates twenty-one (21) bedded sail caverns, of which six (6)caverns are currently LPG products, Three (3) additional bedded salt caverns are currently in the process of being Solution milled. This paper presents a general overview of TransGas Limited's present experiences with the conversion of LPG salt caverns to sweet natural gas storage service. Introduction Some of you today will have knowledge of the storage operations within Saskatchewan. TransGas pioneered the development of underground solution mined bedded salt caverns in Canada (and the United States as well) in the early 19605 at Melville, Saskatchewan. The sole purpose was for the dry or brine-free storage of natural gas. The equivalent caverns in the United States Were developed at Eminence, Mississippi in 1970. Prior to that time, salt caverns had been utilized by other companies for life storage of Liquefied Petroleum Gas (LPG) and other hydrocarbon liquid. Salt caverns permitted the highest rate of gas delivery; provided a secure and environmentally safe form of storage; permitted full product recovery; and required the least cost for construction; factors which still hold true today. In the 1990s, TransGas purchased outright or leased a total of six(6) former solution mined bedded salt, LPG caverns and converted them to natural gas storage. Three (3) of these caverns are located at Regina North and three(3) at Melville South (see Figure 1). One quarter of all TransGas cavern storage comes from converted LPG caverns. The pre-requisites for cavern conversions are identified in Figure 2.

Abstract As part of a larger project, the relationship of horizontal well productivity and reserves to geology and reservoir properties has been examined at the Winter and Senlac heavy oil fields in Saskatchewan and at the Pembina field in Alberta. In the Winter Cummings Sand pool, vertical wells have not been successful in exploiting 36 million m 3 of heavy oil that occurs in a thick sand bar. Horizontal wells have average production of 22 m 3 /well/day and indicated ultimate reserves of 15.000 m 3 /well in the portion of the pool studied. Developed reserves are strongly dependant on standoff of the wellbore above the oil-water contact with at least 4.5 m of standoff required to produce beyond payout. In the Senlac Cummings-Dina pool, vertical wells are unsuccessful whereas horizontal wells are producing heavy oil at economic rates, The main sand body is possibly an estuarine deposit that occurs in a channel between continental and marine depositional realms. In the portion of the field studied, horizontal wells have ultimate reserves of 25,000 m 3 /well. Standoff of the wellbore above the oil-water contact IS not an obvious control of reserves developed but there is a positive correlation between reserves and wellbore length. Success of horizontal wells in the Pembina Cardrum light oil pool is strongly dependant on geology and reservoir properties. Horizontal wells located In areas of thick permeable conglomerate and permeable sandstone are successful whereas those drilled in low permeability reservoirs are failures. Introduction As part of a larger study, the authors have investigated the results of horizontal drilling in three sand pools in western Canada, The three pools are: Winter Cummings Sand Pool a producer of heavy oil in the L1oydminister area of western Saskatchewan Senlac Cummings-Dina Sand Pool which also produces heavy oil near L1oydminister and the Pembina Cardium Pool an important producer of light oil in western Alberta (Figure I). Winter and Senlac each have original oil-ill-place in occurs In thick sands having excellent reservoir properties. Both pools have extensive bottom water zones so that water coning has been a severe production problem in vertical wells because of the adverse mobility ratio of oil to water. Generally vertical wells have been uneconomic whereas there has been successful cold production from horizontal wells. The Pembina Cardium light-oil pool was discovered in 1953 and contains approximately 250 million m 3 (1.600 million STH) of recoverable reserves. The Cardium oil reservoirs are of interest for horizontal development because or their vast size and because there is a large amount of unrecovered oil-in-place despite secondary recovery being in place for a long period of time. At the time this project was undertaken. Amoco had drilled several horizontal wells in the study-area in the southwest part of Pembina field. Eight of these horizontal wells, drilled in areas of poor reservoir were unsuccessful whereas a horizontal well drilled in an area of good reservoir appears to be economic. This report is drawn from a larger study conducted under the sponsorship of Saskatchewan Research Council.

Abstract Thermal recovery of heavy oil has been a tantalizing prospect for Saskatchewan's heavy oil reservoirs. Over the past 30 years, many thermal methods have been tested in Lloydminster area, ranging from electrical heating and cyclic steam stimulation (CSS) in the early sixties, to tailor-made steam injectionprocesses. Along the way, many in situ combustion tests were also carried out, with limited success. The question is: will thermal methods ever work in the thin, relatively deep formations of Saskatchewan, many now riddled with horizontal wells? The answer is yes, if one is willing to approach each specific field situation on its own merits, and design a thermal process to suit the conditions. Selected thermal recovery projects, specifically steam injection, in Saskatchewan are reviewed to determine what worked and what did not. For example, CSS did not have a chance in the thin formations, but it did work in thicker sands; in situ combustion was unsuccessful in many field tests, but it has been a qualified success in one or two cases; steamflooding as such has been unsuccessful, but it can be made to work under some apparently unfavourable conditions. The extensive laboratory work done supporting thermal processes is also mentioned. The paper does not give another screening guide. Rather, an attempt is made to identify the conditions for the application of steam in typical Saskatchewan heavy oil reservoirs. The conclusion is that there is definitely a place for thermal methods in Saskatchewan. Extensive horizontal well drilling has not made the task any easier, and good laboratory work is the key to success, as shown by current experience. Introduction Steam injection is the most successful heavy oil recovery method. At present, the total oil production by steam in North America is 530,000 BID 1 (84,200 m 3 /day), of which approximately 110,000 BID is in Canada. Most of this production is by steam. In situ combustion accounts for 2,520 BID in the U.S. and 5,200 BID in Canada. (The largest steam injection project is in Indonesia, producing 250,000 BID; in Venezuela production is 277,000 BID). But the application of steam injection technology is far from uniform in the different areas. In some cases, such as Peace River and Tangleflags, great ingenuity is used to make steam workable under adverse conditions. In other case, such as Cold Lake, the steam injection technology has been dictated by the reservoir response, and has evolved accordingly. This paper addresses the question of whether steam injection is likely to be viable in the thin formations of Lloydminster area, and if so, what forms it might take. In 1960's, cyclic steam stimulation (CSS) was tested in a number of thin sands in Saskatchewan. In most cases, the first cycle was relatively good, with an oilsteam ratio of over 0.5, but subsequent cycles produced very little oil, because solution gas, which provided the drive, was depleted. Desirable aspects of steam injection Steam is a unique fluid: it is the best heat carrier (with the exception of certain exotic substances), with a mix of sensible and latent heats.

Introduction In the early 1900's electric power was generated near to the demand centers. Many cities, including small ones like Moose Jaw, contained a central power plant that often supplied waste heat as steam to heat nearby buildings or a downtown core. The first district heating system in North America (a steam system) was installed in Lockport N.Y. in 1878. The first system in Canada (also a steam system) was installed in Winnipeg in 1924. Then technology changed, making large plants more economical and making it feasible to transmit power over long distances. People also became concerned about central power producers polluting the air near the core of city. Power production was removed to large, remote plants, powered by coal, oil, hydro or nuclear. Central district heating systems were shut down. The trends are now changing again. After many years of reducing real electricity prices, in the early 1970's real prices began to increase in most areas in North America. Over construction due to optimistic demand growth forecasts, significant reduction in demand growth due to conservation, and environmental safety concerns increased electricity costs. For most utilities, demand growth increments were no longer measured in multiples of world-scale power plants (500–1000 MW). At the same time, since its initial development in the 1940's, gas turbine technology has improved so that smaller turbines are now cost effective and reliable for base load power generation. Also, since the late 1970's, in most jurisdictions, power generation is no longer considered a natural monopoly. Utility monopolies are being redefined and eroded. Hot water district-heating technology was developed and perfected in Europe. Cooling water district drilling systems were developed in North America. New technology has recently been developed that reduces pollutants in gas turbine exhausts to near zero. People and governments are now concerned with CO 2 emissions causing global warming. It is now feasible and attractive to move power generation back into the community to produce electricity, heat and cool local buildings and improve local, regional and global environments. Saskoil, through its subsidiary Moose Jaw Community Energy Ltd., has proposed to construct and operate a cogen plant at Moose Jaw, Saskatchewan, to produce electricity for the SaskPower grid and heat and cooling for a district energy system ('Trigeneration'). The plant and energy distribution system will cost about $44 million. produce about 25MW of electricity, supply about 50 MMBTU/hr. of heat and cooling. as required, for Saskoil's adjacent asphalt refinery, two hospitals and several buildings in the downtown core of Moose Jaw. In order to optimize project economics and to make the most efficient use of energy, Saskoil will produce power using a combined- cycle plant (gas turbine + steam turbine) and use residual waste heat to produce steam and hot water for the district energy system. This project has been described in more detail elsewhere and is awaiting approval by SaskPower. Saskoil is investigating several other similar projects in Saskatchewan, Western Canada and North America, using this technology.

Abstract The Rosebank olida Beds pool of southeast Saskatchewan, discovered in 1955, has produced more than 4.8 × 10 6 m 3 of light oil to December, 1990. Oil occurs in the Mississippian Alida Beds in a subcrop trap. The oil reservoir consists of the Skeletal Wackestone unit, 25 to 30 m thick, overlain by the Upper Oolitic unit, up to 26 m thick. The two reservoir units are quite dissimilar in reservoir properties. The Upper Oolite has vuggy and coarse intergranular porosity with high horizontal permeability and low capillarity and water saturation. The Skeletal Wackestone has fine intercrystalline porosity with relatively low permeability and high capillarity and water saturation. The pool has performed well under natural water drive and it is expected that at least 32 percent of the oil will be recovered. From late 1990 to September, 1993, eight horizontal wells were drilled in the northern part of the pool. The performance of a recent horizontal well (Saskoil Unit D9--I D3-10) and surrounding vertical wells was studied. The horizontal well has maintained rates of over 50 m 3 /dwilh a WOR of 0.3 m 3 / m 3 / since April, 1992. The horizontal well is expected to recover 190,000 m 3 / of oil an incremental 24% of the original oil in place. To date there are no signs of detrimental effects on the offsetting vertical wells. High initial production and high recoveries from horizontal wells at Rosebank are considered to result from two mechanisms.: In the Skeletal Wackestone. characterized by a network of fine intercrystalline porosity of low permeability, increased production and reserves result from the greater length of borehole opened; In the Upper Oolite, the porous streaks with high permeability are erratic and it is considered likely that the horizontal borehole connects to isolated or semi-isolated "compartments" that otherwise would be produced slowly if they were produced at all. Introduction The Rosebank pool occurs along the subcrop of the Mississippian Alida Beds on the sub-Watrous uncooformily approximately 225 km southeast of Regina, Saskatchewan (Fig. 1). The carllonate-hosled oil pool at a depth of 1070 m was discovered in 1955 and had produced 4.8 × 10 6 m 3 (30.2 × 10 6 STB) of oil having a density of 828 to 841 kg/m 3 (37 ° to 39 ° API) to December 31, 1990. Oil production was from about 90 vertical wells; about 50 of the vertical wells are in the unitized south portion of the pool (Rosebank Voluntary Unit No. I) and about 40 wells are in the non-unitized northern part of the pool. This paper concerns the geology and the development through horizontal wells of the northern part of the Rosebank Alida Beds pool in Tp 5, Rge. 32 WIM. Horizontal development began in late 1990 with drilling of the CN et al. Rosebank HZ A9-14-AI5-14-5-32 well from 09-14 to 15-14-5-32. Results on the first well were reported by Jamieson in 1991 1 and additional results were given in June, 1993. 2 This Rosebank study is part of a larger project that is examining the effects of geology. drilling practices and completion practices on horizontal well productivity and reserves.

Abstract Mercury injection capillary pressure (MICP) analyses applied to modelling reservoir rock pore systems was popularized a little more than a decade ago. However, MICP analyses are time consuming and there is a need to utilize existing MICP databases to determine the pore geometry parameters for unanalyzed reservoir rocks. Recent studies have demonstrated that pore throat sorting and displacement pressure are two MICP parameters that may be used to characterize reservoir pore systems. These two parameters can be quantified by one value, R35, the pore throat size at 35% mercury saturation in an MICP analysis. The relationship between R35 and porosity and permeability may be determined using multiple regression, making data from core analyses a useful means of quantifying pore geometry in a reservoir interval and graphs of R35 vs core analyses depths can be used to characterize pore geometry variations in those intervals. Two hundred and thirty jive MICP analyses from reservoir studies in Saskatchewan make an excellent database to characterize the pore geometry a reservoir and non-reservoir rocks using R35/depth plots. The combination of these plots and detailed lithologic studies, including facies and diagenetic analyses, promote a better understanding of the factors influencing reservoir quality in some Middle Devonian Winnipegosis and Mississippian Frobisher and Midale reservoirs. Introduction The implementation of enhanced recovery techniques to improve reservoir productivity mitigates that the geology of the reservoir rocks, is well understood. Two elements of the geology, lithotypes and diagenesis, can significantly influence reservoir pore geometry, and thus reservoir quality. Pore geometry can be characterized using components of mercury injection capillary pressure analyses (MICP), particularly uniformity of pore throat sizes and displacement pressure (entry pressure). Mercury injection capillary pressure analyses have been an integral part of carbonate rock hydrocarbon reservoir studies carried out by graduate students and faculty of the Department of Geology, University of Regina, during the past 16 years. From the beginning, it was anticipated that by including this procedure in the reservoir studies, it would helped, firstly, to develop a better understanding of the geometry of an assortment of pore networks in carbonate reservoir rocks; and secondly, it would establish a database of MICP components that in the future might be employed. in some way, in the evaluation other carbonate reservoirs. The intent of this paper is to employ an empirical method based on an existing MlCP database Lo characterize carbonate reservoir pore networks, using core analyses data. The database consists of 230 MICP analyses from studies done at the University of Regina on carbonate reservoirs from the Mississippian of southeastern Saskatchewan. The empirical procedure in this study is applied to reservoir rocks from three stratigraphic levels: the Middle Devonian Winnipegosis in the Tableland-Hitchock-Macoun area, and Mississippian Frobisher and Midale Beds in the South Workman Pool and the North Tatagwa area, respectively. Background to MICP Analyses Figure I demonstrates the basic elements of an MICP analysis and the principles are listed below: I) - MICP analyses are conducted on core-plugs, 20cm in diameter by 40cm long.

Abstract There are extensive deposits of heavy oil in Saskatchewan and Alberta which can only be recovered with low efficiency by conventional methods. Primary recovery in the best of these heavy oil reservoirs can yield about 6 percent of the OOIP. Waterflooding can improve the recovery, but only to an extent of f-2 percent because of the adverse mobility ratio. Thermal recovery processes using steam can be effective, but these are uneconomic in many Lloydminster type reservoirs because the deposits are relatively thin and heat losses to the overburden and underburden are excessive. One potential means for overcoming the problem of heat loss is to make use of vapourized hydrocarbon solvents at their dew point. This paper discusses the results of experiments with Tangleflags heavy oil and propane carried out in a large, scaled, physical model. It focuses on the area of potential problems encountered with the use of saturated hydrocarbon vapours as a solvent. In particular, it addresses the issue of precipitation of asphaltenes which may lead to reduced permeability and lower production rates. Rates, recoveries, gas to oil ratios and other important parameters will be presented and field performance of the process will be predicted from the data obtained in the scaled laboratory model. Introduction Production of heavy oils and bitumens from the extensive deposits in Alberta and Saskatchewan is hampered by the high viscosity of these materials caused by the high content of asphaltenes. After these heavy crudes have been produced, often by thermal methods, dilution with light hydrocarbons is required to facilitate transport through pipelines to upgrading plants and refineries. The cost of steam injection to mobilize the heavy crude is large, mostly because there are inherent heat losses associated with heating surrounding rock formations that do not bear oil. This situation is further exacerbated in thinner reservoirs. A new idea is to recover heavy oils using saturated hydrocarbon vapours under carefully controlled conditions which lead to separation of asphaltenes from the heavy crude. The asphaltenes are thus left behind deposited on the reservoir matrix while the much lighter oil is recovered. The handling, processing and transport of such in situ upgraded oil is easier and more economical. In our previous paper[l] we described a new process for recovering heavy oil with the aid of a saturated hydrocarbon vapour. In this paper we present further experimental data to support the feasibility of the process and explore the benefits of in situ upgrading by asphaltene removal and deposition on the rock matrix. EXPERIMENTAL WORK HOT WATER-PROPANE INJECTION INTO A PACKED CELL: APPARATUS DEVELOPMENT The purpose of this work was to extend the body of knowledge obtained in our original development of the Vapex process (1) to a larger physical model in which problems not apparent in a small cell come into focus. The previous work was carried out with a small cell with inside dimensions 7 × 7 × 2.5cm. The results were encouraging.

Abstract A study was undertaken to characterize the surfactants that stabilize emulsions occurring in enhanced recovery operations of heavy oil in Saskatchewan. Knowledge about the nature of the stabilizing compounds may help improve emulsion treating technologies and, ultimately, recovery operations. Both oil-in-water emulsions, found in steamflood operations, and difficult-to-break water-in-oil emulsions typical of fireflood-produced crudes were included in this investigation. Fresh emulsions were collected from five thermal projects in Saskatchewan and the produced (free) water phases subjected to ultra filtration using membrane permeation. Following chemical analysis of the raw permeates, three methods were used to extract and/or isolate the dissolved organic matter from the permeates: water removal by freeze drying or rota-evaporation; extraction of the acidified permeates with ethyl acetate, followed by removal of the solvent; and separation by column chromatography into acidic, neutral and basic fractions. The identification of compounds or compound classes in the isolated products was mainly based on C NMR, GC/MS and IR analyses, but other characterization methods were also employed. The major constituents in all five sample cases were aliphatic carboxylic acids, benzoic acid and derivatives, and phenol and derivates. Differences were observed in the relative proportions of these constituents and these differences could be related to the origin of the material. Fireflood materials tended to be more aromatic, have a higher benzoic acids content, an average-to-low aliphatic carboxylic acids content, and contain only small amounts of phenols. Steamflood materials, on the other hand, tended to be more aliphatic, have a higher aliphatic carboxylic acids content, a moderate-to-low benzoic acids content, and contain high levels of phenols. Some samples fell in between these two extremes. Because the isolated organic materials could not be redissolved in water, their surface active properties and, hence, their possible efficacy as a surfactant could only be measured indirectly using the original raw permeate solutions. Interfacial tension measurements on these solutions were inconclusive. Introduction Much attention is being given in recent years to the mechanics and economics of the recovery and use of heavy oil and bitumen. The sizeable reserves of heavy oil and bitumen in Alberta and Saskatchewan cannot be extracted by conventional means to any significant degree due to the high viscosities of these oils. Improved recovery is, however, possible with enhanced recovery techniques such as steamflooding and In-situ combustion, both of which are presently in use in the field. The oil recovered using these methods is almost always produced in the form of oil-water emulsions. While in-situ combustion or fireflooding usually produces very stable water-in-oil (w/o) emulsions, both w/o emulsions and stable, reverse, oil-in-water (o/w) emulsions can be formed in steamflooding operations. The stability and persistence of these emulsions are due to the presence of natural or in situ created surfactants, which are partially soluble in both oil and water phases. Surfactant molecules reside at the interfaces between the liquid phases, with a polar portion of the molecule in the water phase and a nonpolar portion of the molecule in the oil phase.

Abstract Prior to 1985 October 31, the natural gas industry was one of the most regulated industries in Canada. In Saskatchewan, the only place producers could sell their natural gas was to the Saskatchewan Power Corporation (SaskPower) at Provincial Government regulated prices. Also, the only place consumers could buy natural gas was from SaskPower., again at regulated prices. On 1985 October 31, Canada, Saskatchewan, Alberta and British Columbia signed the Agreement on Natural Gas Markets and Prices to deregulate the Canadian natural gas industry. Deregulation in Saskatchewan was introduced in two phases. Under Phase I in 1987 February, government regulation of prices for gas sold to SaskPower was eliminated. Under Phase II, in 1987 October, the merchant and transportation functions of SaskPower's natural gas system were separated allowing consumers to purchase natural gas directly from producers and only contract with SaskPower for the transportation service. At the same time, the government addressed the issue of exporting natural gas from the province. They allowed a significant increase to the amount of gas which could be exported. The transportation of natural gas using utility systems was something quite new to the gas industry and many made-in-Saskatchewan solutions had to be developed to overcome some problems unique to Saskatchewan. What evolved was a Saskatchewan natural gas transportation po1icy. As well as the new transportation policy which had to be put in place very rapidly to accommodate deregulation, significant physical facilities had to be built to handle the increased requirements for natural gas transportation. In 1988, approximately $91 000 000 was spent on new transmission facilities. System capacity increased by approximately 6200 10 3 m 3 per day (220 MMcf per day). A more modest expansion program is planned for 1989 which should bring on stream au additional capacity of approximately 3325 10 3 m 3 per day (118 MMcf per day). Deregulation has had a significant impact on the natural gas industry in Saskatchewan. Any number of criterion can be used and they all show the impact which it has had. Natural gas well drilling, Saskatchewan natural gas production, employment, and Provincial royalty revenue have all increased. Also, due to the rise in activity in the field, the remaining established natural gas reserves have a1so grown. Natural gas transportation, which was a necessity for deregulation, has very rapidly changed the natural gas Industry and markets 1n Saskatchewan. From all perspectives, the changes, so far, seem positive. Introduction One of the significant aspects of our western economies over the last decade has been the move towards deregulation of various sectors of the economies. There has been a striving to allow the free market forces to guide the various sectors towards efficient allocation of resources and towards optimization rather than relying on the very slow and, at times, inefficient regulation of these sectors. The natural gas industry is one of the industries in North America which has recently moved towards deregulation. This first began in the United States and is still evolving there. In the last few years, deregulation began in the Canadian gas industry.

Abstract A waterflood prediction study has been developed for the Dodsland Viking field in Saskatchewan, Canada. This study demonstrates the importance of the geological description used to account for fieldwide variations in PVT properties. The methodology identifies the significance of local wellbore effects (hydraulic fracture stimulations). The increased power of SimBest II which is fully implicit and uses an improved matrix solver, 'ESPIDO", enables modelling of this problem where older technology fails (Beta 11). Finally, the results are compared against actual offset production performance and models which do not account for local wellbore effects. Introduction The Dodsland-Hoosier Viking field was discovered in 1953. The location of the field in southwestern Saskatchewan is shown in Figure 1. The field consists of a complex series of oil and gas pools, as depicted in Figure 2. Development of the field occurred rapidly during the late 1950's, followed by unitization and subsequent waterfloods. A resurgence of development occurred during the early 1980's in response to government incentives. The Kiyiu Lake Voluntary Unit No.1 was developed in 1983 and 1984. A waterflood was planned, and government approval obtained during 1985. However, the dramatic dip in oil prices in early 1986 delayed implementation of the project. A detailed re-evaluation was commissioned by the client, J.C. International Petroleum Ltd. to more closely evaluate waterflood economics under the more severe economic conditions of 1988. GEOLOGY The geology of the field was comprehensively documented in a paper by W.E. Evans 1 . Two main factors control the occurrence of oil and gas in this field: the separate linear sandstone bodies, which overlap. the structure, which is controlled by underlying solution collapse and post depositional compaction. Figure 3 shows the axes of the overlapping members and Figure 4 displays the stratigraphic relationship of the sandstone bodies. Cross sections through the center of the members (Figure 5) demonstrate how both of the above factors resulted in a system of oil and gas accumulations shown earlier (Figure 2). The lithology in the field has been studied in detail by Tooth et al 2 . The vast majority of reservoir rock consists of finely interlaminated sands, siltstones, and shales. These laminations are typically 1/2" thick. Core analysis near the study area yields porosities from 16 to 24% and permeabilities ranging from 0.1 mD to 40 mD. The average porosity and permeability are 20.7% and 6.3 mD, respectively. A basal chart conglomerate is also found in some members, but is not thought to be present in significant amounts within the study area. Overall, the Viking formation in this field is of poor reservoir quality. PRODUCTION CHARACTERISTICS Production from such a low permeability reservoir requires hydraulic fracture stimulation, and results in a characteristic production profile. Economic evaluations have been conducted for a number of companies with substantial production from this field. Reserves are determined using type curves, an example of which is shown in Figure 6. The production profile is determined by multiplying the initial production times the normalized rates in Figure 6. After two years an exponential decline is used.