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.

Introduction The Weybum Unit is one of the largest medium-sour crude oil reservoirs in Canada, containing approximately 207 E6 m3 of original oil in place. The field was discovered in 1955 and has been on water flood since 1964. The Weyburn Unit includes 530 production wells and 170 water injectionwells. This includes the vertical infill wells added in the mid 1980's and over 140 horizontal wells which were added over the past seven years. The Weybum Unit has been a successful operation for PanCanadian Resources and for the many working interest owners in the Unit. However, the field is a mature water flood with high water cuts and decreasing oil production.Without some kind of tertiary recovery, it would soon become necessary to suspend or abandon large blocks of production wells in the Unit. The development of a large scale CO, flood in the Weybum Unit will be the most significant development in the SE Saskatchewan oil patchsince the discovery of the Weybum field. The Weybum Unit covers 180 km2 in southeastern Saskatchewan. The Weybum oil pool produces 25 to 34 degree API medium gravity sour crude from the Midale beds of the Mississippian Charles formation. The are twolayers in the Midale beds, the Marly zone and the Vuggy zone. The Marly is a chalky dolomite with low permeability. Below the Marly is the Vuggy zone, a highly fractured and permeable limestone. The water flood whichwas developed in the 1960's has recovered most of the oil from the Vuggy zone but much less of the oil from the MarIy zone. The production responsibilities of the Weybum field operators have been well defined for the water flood operation. Water injection rates are optimized in many parts of the field to maximize oil production. Water distribution is adjusted to maintain the target voidage replacement ratios. Pump-off controllers have been installed on many wells to improve rod pump reliability and to minimize the production well down hole pressure. The construction of a commercial scale CO 2 flood will cause a step change in the complexity of the Weyburn production operation. The operator will be managing a valuable commodity, that is the CO 2 itself, in order to maximize the production of oil. At the same time, the safe operation of the pipeline and satellites will be of utmost importance as high pressure sour gas is transported throughout the field. The field operator will become an important part of the commercial and social success of this project. The stakes are high. By improving the recovery of oil in this Unit from the 30% anticipated with conventional water flood, an incremental 21 000 000 m3 of oil will be produced over the next 20+ years. This compares to the 53 000 000 m3 of oil which have been produced in the 40 years since the field was discovered. 1 Two priorities in the execution of this project are training and safety. Training will be required to give the operating team the best understanding of the principles of CO 2 miscible flooding.

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 solubility of carbon dioxide, nitrous oxide, methane and ethane in a physical solvent, triethylene glycol monomethyl ether (TEGMME) were recently measured by Henni and Mather (1.2.3.4) at 40, 70 and 100 °C at pressures up to 10.9 MPa. TEGMME was found to be the best solvent for CO 2 removal among physical solvents used in the gas processing industry. In order to compare these solubility data with those of other polar solvents, a literature search was done to gather solubility data in solvents with a wide range of dielelectric constants. The solubility data compiled were for pressures higher than atmospheric pressure. The Peng-Robinson (1976) ISI equation of state was used to correlate the data for the solubility of CO 2 in the polar solvents. The Henry's constants are then derived using the Kritchevsky-Kasarnovsky (6) or the Kritchevsky- Illenskaya equation m. The results show that ethyl acetate and propyl acetate are the two solvents that absorb CO 2 the most. But, among the best solvents for CO 2 removal, TEGMME has the lowest boiling point. Dimethyl ether is among the best solvents for CO 2 absorption is also among solvents that absorbs methane the most. Diethyl ether has the highest capacity for methane absorption. The study confirms the fact that the best physical solvents for absorbing acid gases have the disadvantage of absorbing the largest amounts of ethane. The solubility data in the CO 2 , N 2 O, CH 4 and C 2 H 6 systems were generally well-correlated by the Peng-Robinson equation of state even for those systems that are highly nonideal. Introduction The Government of Canada has been an active participant in the development of international agreements and protocols for emissions reduction. It has committed the country to meeting national emission caps for anthropogenic air emissions. Just how these national targets will be met is a critical question to provincial governments but also to oil, coal and utility companies in Canada. As carbon dioxide is a major contributor to the global warming phenomena, the process of carbon dioxide removal from coal-fired power plants and its utilisation as a flooding agent for enhanced oil recovery (EOR) is the focus of a lot of attention. The CO 2 captured will generate revenues and help reduce emissions that contribute to the greenhouse effect. Zawacki et al. (1981) (8) have screened more than 100 solvents for their potential of removing acidic gases (CO 2 , H 2 S). The dimethyl ether of tetraethylene glycol (DMETEG) was chosen as one of two most promising solvents. In an attempt to provide the industry with better physical solvents, a study was initiated to test new solvents. Triethylene glycol monomethyl ether [TEGMME, c.A. Registry No. 112-35-6] belongs to the same family as DMETEG but it costs four times less. In order to combine the advantages of both physical and chemical solvents, mixed solvents have been proposed. This combination allows for a higher CO 2 loading, a low solution circulation rate and regeneration energy.

Abstract This paper describes research and development activities at the University of Regina, Saskatchewan, Canada on " Optimization of CO 2 Extraction Process Technologies". The ultimate goal of this research is to develop better and more effective CO 2 separation processes which can he used to recover CO 2 from industrial sources such as coal-fired power plants and coal gastification complexes at the lowest possible capital and operating costs. The research program has been supported by Saskatchewan Power Corporation, Saskatchewan Energy and Mines, Prairie Coal Ltd., the Canada Centre for Mineral and Energy Technology (CANMET). Fluor Daniel Inc. (USA.), Sulzer Chemteeh (Switzerland), Wascana Energy Inc., and Natural Sciences and Engineering Research Council of Canada (NSERC). Currentlv, six parallel and complementary projects have been carried out at the Process Systems Laboratory. These projects are: Searching for new sterically hindered animes for high capacity absorption carbon dioxide, Formulation of high carbon dioxide absorption capacity Solvents using chemical and physical absorbents, Searching for high performance random and structured packings for absorption and regeneration towers, Studies of material corrosion by gas treating solvents (including the use of corrosion inhibitors). Parameter estimation of gas absorption with chemical reaction processes using optimization techniques, Process optimization and cost studies of co-production of CO 2 and electricity using co-generation concepts. Results and progress of these research projects will be reported. Their economics and technical feasibility Will be described and their practical implications will be discussed. Introduction A large amount of carbon dioxide (CO 2 ) is being produced from industrial sources such as coal-fired power plants and is suspected to be a major contributor to the greenhouse effect and global warming To overcome the CO 2 emission problem, there is great interest, especially in Western Canada, in capturing carbon dioxide and utilizing it as a flooding agent for enhanced oil recovery (EOR) This approach for solving the problem would have two important benefits: we can market the captured Cal as a commodity chemical for generating revenue and we will be able to reduce CO 2 emission to the atmosphere and help alleviate a serious environmental problem at minimum cost. A significant number of economic evaluations of C02 production from coal-fired power plants ha\'e been reported in recent years. The most significant ones are from the lEA greenhouse gas R&D program [1] and AOSTRA [2]. Based on current technologies, the reports have shown that the gas absorption with a chemical reaction process using amine is the most cost effective and has the best proven operability record. However, these studies have also concluded that the cost is still relatively high for producing CO 2 for enhanced oil recovery (EOR) applications, under the current crude petroleum market. A major reason for the high cost is that the solvent used in these studies is monoethanolamine (MEA). This solvent has a high rate of absorption: however, it introduces a variety of practical problems including: (i) it requires a large amount of steam or heat for regeneration because of its low absorption capacity:

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 The possibility of using high efficiency structured packing in CO 2 absorption processes with a newly proposed solvent, 2-amino-2-methyl-l-propanol (AMP) was investigated. The evaluation of packing performance was performed by CO 2 absorption into sodium hydroxide solutions and aqueous AMP solutions in 1.77 m high and 0.019 in ID absorption column. The performance of structured packing representing in term of the overall mass transfer coefficient (K G a) is reported as junctions of the main operating variables, namely CO 2 partial pressure, gas flow rate liquid flow rate, and liquid composition. An excellent performance of structured packing over random types in CO 2 absorption process was found in this study. Introduction Carbon dioxide (CO 2 ) absorption is an essential step in many industrial processing operations such as natural gas purification manufacture of hydrogen and coal gasification. For industrial purposes the absorption process helps in removing CO 2 , from gas streams so that higher quality gas stream products can be achieved and operational difficulties can be minimized. Environmentally this process can alleviate the global warming problem by reducing net CO 2 emission from waste gases which would otherwise be vented to the atmosphere. In the absorption process. CO 2 in gas streams is basically absorbed into liquid solvents. The used solvents can be simply classified as physical and chemical solvents. Chemical solvents are however, preferred for the processes because of their higher absorption capacity at a low partial pressure of CO 2 . Alkanolamines are considered the most commonly used chemical solvents for CO 2 removal applications. [1] Among these monoethanolamine (MEA) belonging to the primary class is the most popular absorption solvent. [2] A new class of acid gas absorbents, the sterically hindered amines has recently been disclosed by EXXON Research and Engineering Company. [3] Among these chemicals. 2amino- 2-mcthyl-l-propanol (AMP) is the most promising solvent since it provides higher CO 2 , absorption capacity on a molecular basis when compared with that of MEA. the most commonly used conventional alkanolamine. [3] In addition absorption of CO 2 , in AMP solutions causes less corrosion (which is considered the most severe operational problem in alkanolamine plants). [4] The above considerations show that the replacement of conventional alkanolamine MEA with the hindered amine AMP is very attractive. One limitation for use of AMP is that its absorption rate is lower than that of MEA, by approximately 10 times. [5] To make the replacement feasible, the rate of CO 2 absorption into the new AMP solution must be improved. An approach that might lead to the improved efficiency of a CO 2 absorption process using AMP solution is modification of the interior of the absorber. Previous experiences in using structured packing for distillation and gas dehydration application [6,7] show that use of structured packing may improve mass transfer performance in the new CO 2 -AMP absorption system. The primary objective of this study was therefore to investigate the possibility of using high efficiency structured packing in CO 2 absorption processes with a newly proposed solvent 2-amino-2-methyl-l-propanol (AMP). The performance of the studied packing was evaluated by performing CO 2 absorption into sodium hydroxide (NaOH) solutions which are commonly used to characterize

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 A series of experiments were performed in physical models saturated with heavy oils of 0.6 to 12.7 Pa.s. The oil was displaced by gravity drainage at constant pressure and it was produced using horizontal wells. The pressure was maintained either using a vacuum pump or by injection of an inert gas at low injection pressures. Computer Assisted Tomography was used for the visualization of the displacement front. Additional gravity drainage tests were performed in long vertical columns and in two dimensional glass micromodels. In this paper a detailed description of the performed experiments is presented. Production characteristics are shown and images of the gravity drainage process are a/so included. The recoveries varied from 20 % to 50 % recovery of the original oil in place. The pressure difference was maintained between 10 and 30 kPa. In the cases where sand parting was not observed, a uniform displacement front was formed. In the cases where parting was observed the experiment was temporarily shut in. Substantial amounts of oil were produced following the shut in period. Temporary shut in was also implemented at gas breakthrough with considerable increase in the oil recovery.. Introduction In the Lloydminster area of west central Saskatchewan and east central Alberta, large reserves of heavy oil exist which can be mobilized at reservoir conditions. Conventional primary production of these reservoirs has utilized mainly vertical wells on relatively large spacings, resulting in recoveries of 5–10 % OOIP. Recent applications of horizontal wells in these reservoirs hold some promise of increasing recoveries, but thin pay intervals, low reservoir pressures and low GOR's limit the effectiveness of recovery mechanisms based on gravity, natural pressure depletion and solution gas drive. The work described in this paper considers the enhancement of gravity drainage in LIoydminster reservoirs through injection of immiscible gas and production via horizontal wells. In addition to presenting results of lab experiments in various physical models, an extensive review of relevant literature is included. LITERATURE SURVEY The LIoydminster heavy-oil accumulation is the southern extension of a discontinuous trend of Lower Cretaceous bitumen and heavy-oil-sand deposits extending from Athabasca through Cold Lake to Lloydminster. Detailed reviews about the geology of the various reservoirs in the arca have presented by MacCallum (1981), Orr et al. (1977) and Putnam (1982). The Sparky Formation of the Lower Crctaceous Mannville Group is a northeastward prograding, wave-dominated deltaic system which contains up to 60% of the oil in place for the Lloydminster area. Its geological characteristics have been reviewed by van Hulten and Smith (1984). The geology of the Waseca Formation channel sands at Pikes Peak, a north-south oriented sand body up to 35 m thick has been reviewed by van Hulten (1984). The main focus of non-thermal immiscible gas injection for the recovery of heavy oil is CO 2 , Klins (1983) discussed CO 2 injection for enhancing heavy oil production. Immiscible rather than miscible CO 2 displacement was considered. He presented a number of different strategies and injection schemes.

Abstract Most of Saskatchewan's light and med1um oil (LMO) reservoirs have reached economic limits of production under waterflooding 1eaving seventy to eighty percent of the initial oil-in-place (IOIP) in the reservoirs. The miscible displacement process using carbon dioxide, hydrocarbon and other gases as solvents appears to be one of the most promising method for these reservoirs. A laboratory study was conducted to evaluate the applicability of various solvents for the recovery of oil from a southeast Saskatchewan reservoir. The physical, chemical and phase behavior (PVT) properties of wellhead and reservoir fluids were determined. Slim tube displacement tests were conducted between the reconstituted Pinto reservoir f1uid and carbon dioxide, ethane and wellhead gas from the Steelman gas plant as solvents at various pressures and the reservoir temperature of 56 °C. The minimum miscibility pressures (MMP) determined for the above three systems demonstrated that the MMP for ethane is much lower than that for carbon dioxide. which is lower than that for Steelman gas. The MMP for ethane and carbon dioxide are below the reservoir fracture pressure. Introduction Most of Saskatchewan's light and medium oil (LMO) reservoirs have reached their economic limit of production under current technology. Primary and secondary methods together recover about 21% of the initial oil-in-place (IOIP). Although the rema1ning 1ight and medium oil-in-place in Saskatchewan is 1135 million cubic metres, the remaining producible reserves under primary and secondary recovery are only 65 million cubic metres. 1 Medium oil in southwest Saskatchewan has not been considered here, but if it is 1ncluded then up to 17 million cubic metres of additional oil (through primary and secondary recovery) may be recovered. 2 The development of tertiary recovery techniques, therefore, is essential to increase the production 1ife of these reservoirs and to maintain current production. Application of the miscible oil displacement process using CO 2 , hydrocarbon and other gases as injection fluids is expected to increase the LMO reserves threefold and extend the production life of these pools by two decades. 3 Miscible flooding with carbon dioxide and hydrocarbon solvents is considered to be one of the most effective enhanced oil recovery (EOR) processes applicable to LMO reservoirs. Current industry interest in CO 2 miscible flooding is high, as evidenced by the level of activity in field testing 2 and CO 2 source development in the United States. It should be noted that since the world oil price collapse in 1986, the number of EOR projects in the United States has decreased markedly from 512 in 1986 to 366 in 1988, but the number of CO 2 misib1e projects increased from 38 in 1986 to 49 in 1988, a 29% rise during these two years. 3 Oil production in early 1988 by the CO 2 miscible process showed a 125% increase over the same period in 1986. In spite of the great potential of the CO 2 process and the growing number of field CO 2 projects, the mechanisms of CO 2 /crude oil displacement are not understood fully. 4