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 Many mobile heavy oil reservoirs in Saskatchewan and Alberta are unsuitable for the application of thermal recovery methods, such as steam injection, for a number of reasons including formation thicknesses less than 10 m. Oil recovery from such reservoirs can be accomplished by the use of non-thermal methods, among which chemical flooding has considerable importance. This paper discusses recent laboratory results using chemical flooding techniques. At the same time, limitations of such methods, limited field experience in heavy oil formations, and possible improvements are also considered. Among the chemical flooding methods, alkaline and surfactant flooding techniques are more important, partly because the chemicals involved are less expensive, and also much has been learnt from past experience in laboratory and field. The laboratory studies discussed consisted of surfactant floods and huff n'puff of two Lloydminster heavy oils. The recoveries in the floods were as high as 33%. The other recovery method discussed involved cyclic stimulation using these chemicals. Oil recoveries as high as 12% were achieved. Though low, such an approach can be cost-effective in special circumstances. Introduction Much of the heavy oil in Saskatchewan and Alberta is mobile under reservoir conditions to the extent that primary production and waterflooding is economically feasible, although the recovery factors are low, 5 to 10% in most cases. Furthermore, the formation thickness is small (85% of the oil in Saskatchewan occurs in formations less than 5 m thick), so that larger spacings are needed, which makes the application of thermal methods, notably steamflooding, doubly unattractive. Non-thermal recovery methods, such as chemical recovery processes and immiscible carbon dioxide WAG (Water-Alternating-Gas) process can be economically viable in such reservoirs, even though the recovery factor is low. This paper discusses primarily the more promising non-thermal chemical flooding methods, selected laboratory and field results, and their limitations. Results of a few experiments involving chemicals with hot water are also added. PRINCIPLES OF OIL RECOVERY The two important concepts involved in oil recovery are Mobility Ratio, M, and the Capillary Number, N,. Mobility ratio, M, is usually defined as the mobility λ ing (=k/ µ, where k is effective permeability and µ is viscosity) of the displacing fluid divided by the mobility λ ed of the displaced fluid (assumed to be oil in this discussion). If M>l, the displacing fluid will flow past much of the displaced fluid, displacing it inefficiently. Thus the mobility ratio influences "displacement efficiency", i.e. the (microscopic) efficiency of oil displacement within the pores. For M> > 1, the displacing fluid will channel past oil ganglia. This is often called "viscous fmgering". For maximum displacement efficiency, M should be ≤1, usually denoted as "favourable" mobility ratio. If M>1 (unfavourable), then, in the absence of viscous fingering, it merely means that more fluid will have to be injected to attain a given residual oil saturation in the pores.

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

Abstract The Steam-Assisted Gravity Drainage (SAGD) process, which usually employs horizontal injection and production wells has been applied successfully in producing heavy oil reservoirs. It allows high recoveries to be obtained, at high rates without significant bypass of steam. However, SAGD process. due to, the heat loss to the overburden and adjacent formations can only be used for thick reservoirs with relatively high porosities and oil saturations if there is to be an economic oil/steam ratio. The Vapex process, which uses light hydrocarbon vapours 10 extract heavy oil from the reservoir is studied experimentally in the work described in this paper using a new, longer, scaled, packed model. In the process that evolved from the work. liquid solvent (propane, butane or mixtures) is injected with a small amount of non-condensible gas through a horizontal well at the top of the reservoir to contact and mobilize oil by dilution. The diluted oil is produced by a horizontal well. laterally separated from the injector. and located at the bottom of the reservoir. With this configuration. practical production rates can be achieved without appreciable gas bypass. Solvent is separated easily from the produced liquid by distillation and recycled and this results in relatively low net solvent requirements. Gas fills the vacated pores. The objective of the experiments was to develop process conditions to give high oil production rates with economic solvent requirements. To achieve this major parameters affecting the Vapex performance were investigated: temperature, pressure. solvent injection rates, types of solvent. mixed solvents, well spacing and configurations etc.. The major finding has been that wider lateral well spacings allow higher production rates and make the process more economic. Experimental results indicate that. under suitable conditions. the net solvent injection is about 0.2 B per B of produced oil and that high recoveries and practical rates are achievable. For example. a field prediction based on the experimental data indicates an average oil production rate of450 BID per horizontal well pair. 1000 m long. drilled in a pressure depleted. heavy-oil reservoir that is 10 m thick, to give a recovery of over 50% OOIP for a 70 acre pattern. Introduction The concept of Vapex evolves from the Steam Assisted Gravity Drainage (SAGD) process in which two closely spaced horizontal wells are employed with steam injected from an upper horizontal injector to form a steam chamber in the formation and heated oil drains downwards, driven by gravity, to a horizontal producer located near the base of reservoir. Another form of the process involves the use of multiple vertical injection wells instead of the horizontal injector. In the Vapex process, light hydrocarbon vapours or their mixtures with non-condensible gases are employed instead of steam to extract heavy oil or bitumen from the formation. Compared to thermal processes, the Vapex process can be operated at reservoir temperature with almost no heat loss. Vapex can be used as an alternative to recovery the heavy oil and bitumen from reservoirs which are not suitable for thermal processes such as reservoirs with bottom water and/or high water saturation, vertical fractures, low porosity and low thermal conductivity.

Abstract A new equation of sate-based technique for predicting minimum miscibilitypressures for CO 2 cured old systems has been developed. To verifythe technique, a total of 33 slim tube displacement tests were conducted.Reservoir fluids from four different pools were included in the testing. Slimtube displacement test results included measurement of oil recovery, pressuredrop, phase observations and effluent gas compositions, all of which wererequired to infer the experimental miscibility conditions. The application ofthe new technique successfully matched the experimental results over a widerange of reservoir temperature, 21.1 ° c to 78.3 °c, and fluid bubble pointpressures, 3490 kPA to 17330kPa. Introduction Within the literature there are many correlations (1–4) available to predict CO 2 miscibility pressure, However, these correlation do notadequately reflect oil composition and oil characterization. From previousexperience in hydrocarbon miscible solvent design (5), at any temperature thecontribution of each hydrocarbon component is different so hat solventmiscibility is a function of the oil composition. To overcome the limitationsof the current approaches, a new technique is proposed for predicting CO 2 miscibility pressureswhich uses a "tuned" equation of slate forprediction, The advantages of the technique are that cursory assessments onapplying CO 2 can be made inexpensively and the number of slim tubetests needed to verify prediction can be minimized, This paper describes thenew technique and documents all slim tube test data obtained to date such asoil recovery, pressure drop, phase observations and the effluent gascompositions required to experimentally determine miscibility conditions. Reservoir Fluids Table 1 gives the five oil compositions form the four pools examined in thisstudy. The specific gravity and molecular weight of the C 7 + fraction which were used in the equation of statecharacterization (6) are also shown in the table. The range of temperaturebeing tested is from 21 to 78 ° C and the bubble point pressure changes from3490 to 17,330 kPa for Oil-1 and Oil-4 crude respectively. New Prediction Technique The procedure used in this new technique is an extension of the pseudo ternarydiagram construction technique (7) for predicting miscible solvent gascompositions. That technique is based on blending tow hydrocarbon streams, drygas (DG) and LPG, at a specified design pressure and reservoir temperature todetermine the correct solvent composition. Since either pure CO 2 orCO 2 that contact impurities represents only a single identifiablestream, it is more difficult to identify separate stream compositions needed toconstruct the pseudo ternary diagram using an approach similar to that forhydrocarbon miscible processes. Based on an examination of the problem, arecommended approach for selection of the second stream needed for ternarydiagram construction is as follows: As a logical choice, the CO 2 -rich stream (Either pure CO 2 or CO 2 with impurities) is selected to be equivalentto a dry gas stream. This includes and CI and N2 impurities in theCO 2 stream. The second stream, which in the hydrocarbon miscible process is the LPGcomposition. Is made up of intermediates in the oil itself.

Abstract A new equation of sate-based technique for predicting minimum miscibility pressures for CO 2 cured old systems has been developed. To verify the technique, a total of 33 slim tube displacement tests were conducted. Reservoir fluids from four different pools were included in the testing. Slim tube displacement test results included measurement of oil recovery, pressure drop, phase observations and effluent gas compositions, all of which were required to infer the experimental miscibility conditions. The application of the new technique successfully matched the experimental results over a wide range of reservoir temperature, 21.1 ° c to 78.3 °c, and fluid bubble point pressures, 3490 kPA to 17330kPa. Introduction Within the literature there are many correlations (1–4) available to predict CO 2 miscibility pressure, However, these correlation do not adequately reflect oil composition and oil characterization. From previous experience in hydrocarbon miscible solvent design (5), at any temperature the contribution of each hydrocarbon component is different so hat solvent miscibility is a function of the oil composition. To overcome the limitations of the current approaches, a new technique is proposed for predicting CO 2 miscibility pressureswhich uses a "tuned" equation of slate for prediction, The advantages of the technique are that cursory assessments on applying CO 2 can be made inexpensively and the number of slim tube tests needed to verify prediction can be minimized, This paper describes the new technique and documents all slim tube test data obtained to date such as oil recovery, pressure drop, phase observations and the effluent gas compositions required to experimentally determine miscibility conditions. Reservoir Fluids Table 1 gives the five oil compositions form the four pools examined in this study. The specific gravity and molecular weight of the C 7 + fraction which were used in the equation of state characterization (6) are also shown in the table. The range of temperature being tested is from 21 to 78 ° C and the bubble point pressure changes from 3490 to 17,330 kPa for Oil-1 and Oil-4 crude respectively. New Prediction Technique The procedure used in this new technique is an extension of the pseudo ternary diagram construction technique (7) for predicting miscible solvent gas compositions. That technique is based on blending tow hydrocarbon streams, dry gas (DG) and LPG, at a specified design pressure and reservoir temperature to determine the correct solvent composition. Since either pure CO 2 or CO 2 that contact impurities represents only a single identifiable stream, it is more difficult to identify separate stream compositions needed to construct the pseudo ternary diagram using an approach similar to that for hydrocarbon miscible processes. Based on an examination of the problem, a recommended approach for selection of the second stream needed for ternary diagram construction is as follows: As a logical choice, the CO 2 -rich stream (Either pure CO 2 or CO 2 with impurities) is selected to be equivalent to a dry gas stream. This includes and CI and N2 impurities in the CO 2 stream. The second stream, which in the hydrocarbon miscible process is the LPG composition. Is made up of intermediates in the oil itself.

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 In a CO 2 miscible displacement process, asphaltenes from the oil can flocculate in the presence of CO 2 and can cause numerous production problems with a detrimental effect on oil recovery. A five-year multiclient research project was initiated in 1988 to evaluate the suitability of CO 2 as an enhanced oil recovery (EOR) agent for a southeast Saskatchewan reservoir, Weyburn. The initial asphaltene content of the oils collected from the Weyburn pool was about 5% and suggested the possibility of formation plugging and wettability alteration during CO 2 injection. A laboratory study was undertaken to assess the extent of asphaltene flocculation during a CO 2 miscible flood In the Weyburn field. A prototype high pressure PVI cell was used to quantify the asphaltene flocculation. A photometric technique was developed to determine the asphaltene content of the flashed CO 2 -saturated test oils. The effect on the asphaltene flocculation of operating pressure, CO 2 -oil contact time, CO 2 concentration, gas contaminants such as N 2 and CH 4 in CO 2 and the presence of formation brine was investigated for three different oil samples (approximately 29 ° APl) collected from the pool. Results of the study indicated that the onset of asphaltene flocculation occurred at about 42–46 mol% CO 2 concentration. There was a linear increase in asphaltene flocculation with CO 2 concentration after the onset. The asphaltene flocculation pattern seemed to be relatively insensitive to the operating pressure in the pressure range studied. The normalized asphaltene flocculation data showed a negligible effect of brine and contaminants in CO 2 tested. For the experiments conducted in the single-phase region, the effect of CO 2 -oil contact time on asphaltene flocculation during the 4–19 day period was negligibly small. However, the mixing time required to achieve equilibrium in the two-phase region was significantly high. Introduction The majority of the Saskatchewan light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology (primary and secondary recovery methods). 1 Miscible flooding with carbon dioxide is shown to be a promising enhanced oil recovery (EOR) technique for southeast Saskatchewan reservoirs. 2 A study 3 undertaken by Saskatchewan Energy and Mines has shown that the successful development of the miscible displacement process using CO 2 and hydrocarbon gases can lead to a significant increase in Saskatchewan LMO reserves and substantially extend the production life of these pools. Crude oil normally consists of a conglomeration of waxes, resins, asphaltenes, and other semisolid materials. Because of their different physical and chemical characteristics, and when subjected to slight changes in equilibrium conditions, paraffins and asphaltenes often precipitate. One of the problems confronting researchers and field operators is asphaltene deposition during a CO 2 miscible flood. This concern with asphaltene deposition and problems arising from it during CO 2 miscible flooding was one aspect of a comprehensive five-year multiclient research project 4 . It was started in 1988 at the Saskatchewan Research Council (SRC) to evaluate the Suitability of CO 2 as an EOR agent for a southeast Saskatchewan reservoir, Weyburn. Asphaltene deposition and flocculation can change the wettability of the reservoir matrix and consequently affect the flood performance. It can also cause formation damage and wel

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 The immiscible carbon dioxide flooding process has considerable potential for the recovery of moderately viscous oils, which are unsuited for the application of thermal recovery techniques. Approximately 95% of Saskatchewan's heavy oil formations are less than 10m thick, and often have an underlying water sand. Under these conditions, thermal methods are inefficient and uneconomical due to excessive vertical heat loss and steam scavenging by the bottom water. This provides the motivation for searching an alternative to thermal recovery techniques for thin, moderately heavy oils. Laboratory research conducted in the 1950s identified several aspects of carbon dioxide flooding such as viscosity reduction, oil swelling, miscibility effects, and solution gas drive. Both laboratory and field studies have been conducted to determine the effectiveness of the carbon dioxide process for heavy oil recovery. This paper concentrates on the laboratory and field studies conducted in the past as well as the future of the immiscible carbon dioxide flooding process for the recovery of heavy oils. Introduction Moderately viscous heavy oils lack the necessary extractable hydrocarbons [C 5 - C 30 ] for miscible conditions with carbon dioxide to be economically attained. In some cases, moderately light oils [25–35 °API] are displaced immiscibly because the high pressures required to achieve miscibility with carbon dioxide would lead to formation fracturing. This is undesirable in that it leads to gas channeling and early carbon dioxide breakthrough. Both laboratory and field studies have been conducted to determine the effectiveness of the immiscible carbon dioxide process. Laboratory studies are used to determine and optimize the recovery process mechanisms. Field studies, both pilot and conventional, have been conducted in two modes, namely: primary and tertiary. Primary recovery methods have been the most successful to date while tertiary methods have helped greatly in reducing water and gas cuts in late flood life projects 1 . The objectives of this paper are to give a resume of the dominant mechanisms in the immiscible carbon dioxide displacement process, and to analyze field data in order to develop the minimum criteria for process selection. Transport of Carbon Dioxide in Heavy Oil and Reservoir Water How does the carbon dioxide mix with the reservoir fluids, namely: oil and water? Three mass transfer mechanisms are discussed in this section. Solubility is the most important mechanism of carbon dioxide transport in the reservoir. Diffusion and dispersion also affect, to a lesser extent, the transport of carbon dioxide. The most important property of heavy oil-carbon dioxide, systems is carbon dioxide solubility. "Solubility of one substance in another depends fundamentally upon the ease with which the two: molecular species are able to mix. 2 Klins 3 stated: that for low pressure application [<7 MPa), the major effect would be the solubility of carbon dioxide in crude oil. The solubility of pure carbon dioxide in Lloydminster Aberfeldy 115-l7 °API] oil at 5.5 MPa and 20.6 °C is approximately 70 sm 3 /sm 3 of oil. Solubility is a strong function of pressure, and to a lesser degree, temperature and oil composition. Solubility increases with pressure and decreases with temperature and reduced API gravity.

Abstract Many oil reservoirs in Alberta and Saskatchewan have a bottom-water cone which leads to poor efficiency under a waterflood. A possible means of improving waterflood performance in these reservoirs would be to precede the waterfloor with a slug of a mobility control agent. This possibility was extensively investigated in this study using a laboratory flow model, with polymer as a mobility control agent. Twenty four experimental runs were conducted using polymer in various slug sizes. Core floor experiments were conducted to study the effect of permeability contrast, relative oil-water layer thickness, oil viscosity, and slug size. Oils of viscosities ranging from one to 200 mPa.s were used as different displacement tests. The blocking mechanism for polymer was investigated in detail. The flow stability and displacement pattern is discussed for polymer and the waterflood that followed. It is show that in order to have effective mobility control polymer slugs do not have to be displaced as an entity. Even though the waterflood following the polymer slug injection is highly unstable, the improvement over conventional waterflood is remarkable. However, the ultimate oil recovery depends on variables such as permeability contrast, relative oil-water layer thickness, oil viscosity, injection time interval. It is also shown that the injection of polymer as a slug is more efficient than alternating it with water. The effect of slug size is discussed and an optimum slug size is proposed. It is shown that polymer injection is particularly effeicent in cases for which waterflood performance is very poor. For instance, in the case of a thick (h b / h o =1) and very permeable (k o / k w = 0.06) bottom-water zone, about 2 % IOIP was recovered by a waterflood, whereas by the use of polymer as a mobility control agent, more than 45% IOIP was recovered. Also presented are numerical simulation results for polymer flow in an oil reservoir with a bottom-water zone. Experimental evidence suggest that polymer reduces the effective permeability to water without altering that to oil. Experimental investigations also show that the flow mechanism with polymer is dominated by effects like instability, mechanical entrapment, etc. In order to stimulate these effects the concept of 'selective resistance factor' is introduced for the waterflood following a polymer slug a model for the effective permeability to water is developed. This information was used in numerically simulating polymer blockage in the framework of a three-phase, two-dimensional reservoir simulator. Good agreement was obtained between numerical and experimental observations. Introduction Many reservoirs in Alberta and Saskatchewan contain a high water saturation zone underlying the oil reservoir. Such reservoirs show very poor performance under a conventional waterflood. There is a need to develop a technique that would improve the performance of a waterflood in such reservoirs. This problem has received attention for more than two decade and several techniques have been proposed in the literature 1–2 to control the mobility of water or gas. One of these techniques is the use of polymer solutions as a slug.