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 In situ combustion, and its modified forms, continue to be important oil recovery processes. The applicability of in situ combustion to a wide range of reservoirs, and the recent advances, show that this process has unique advantages (and disadvantages). Laboratory studies of in situ combustion are hampered by the lack of suitable scaling criteria for the design of experiments. Apart from that, the experiments are usually labour-intensive and costly This paper provides useful guidelines for the design of such experiments, and also discusses the laboratory methods currently used. The general problem of in situ combustion in a three-dimensional system is formulated, with attention to reaction kinetics and non-equilibriwn phenomena. Appropriate boundary conditions, both for field and laboratory, are stated. Next, the partial differential equations are used to derive a set of scaling criteria. A number of alternative schemes are considered in this regard. Suggestions are offered concerning the use of the various options available for experimental design. The scaling criteria derived are. used to examine the validity of results derived from "fire tube tests, which are widely used to obtain basic information on the combustion bevaviour of crude oils. It is shown that among the parameters measured in such experiments, only a few, such as fuel content, have validity. Results of laboratory fire tube tests of wet combustion can be misleading. Introduction The in situ combustion process has been a source of interest, effort, and, at times, frustration for at least 30 years. The concept of burning heavy fractions of the reservoir oil in order to generate heat in situ is attractive and consequently has led to over 100 field tests of such processes [40 listed in Chu and Crawford 1 ]. However, due to very unusual complications only a few of these have reached commercial status. Even though operational problems have been pointed out as the major cause of such economic failures, a more subtle reason is the selection of reservoirs for in situ combustion applications. Selection criteria used in the past appear to be inadequate in the face of growing recognition of the complexity of the mechanisms involved. Although there has been extensive laboratory study of most aspects of in situ combustion, there remain several areas which are poorly understood. The objective of this paper is to elucidate the mechanisms involved in in situ combustion processes and to present various scaling options in order to model such a process. Mechanisms of In Situ Combustion Recently Islam, Chakma and Farouq Ali 2 revealed the mechanisms involved in in situ combustion and proposed a new mathematical model in order to model some extraordinary features which have been largely ignored by previous researchers. In situ combustion is based on burning the coke deposit laid down by the crude oil. The mechanism of in situ combustion varies depending on whether forward or reverse combustion is taking place. In all cases, however, oxygen containing gas (most commonly air) is injected into the reservoir to achieve combustion.

Abstract Heavy oil reservoirs of Saskatchewan are characterized by thin pay, shaley sand, heterogeneity, low productivity and bottom water. Thermal recovery processes are not expected to be economically feasible for reservoirs containing approximately eighty percent of the heavy all in the province. The carbon dioxide immiscible flooding process 15 considered to be the most promising among the non-thermal recovery methods for these reservoirs. This paper presents a survey of the recent laboratory and field studies of the heavy oil-carbon dioxide immiscible process and the results obtained from phase behavior and core displacement experiments. Viscosity, density, bubble point pressure, Gas-oil ratio (GOR) and swelling factor for the reconstituted reservoir fluids and CO 2 -saturated wellhead oil and reservoir fluid were measured at 28 °C and pressures up to 8.27 MPa. A forty-fivefold reduction in Viscosity and a 16% Increase In the swelling factor were observed in the heavy oil-CO 2 system. Carbon dioxide once dissolved in the heavy oil at a high pressure remains in solution even when the pressure is reduced. Waterflooding of the oil-saturated core produced 31.5 to 46.2% initial oil-In-place (IOIP). The Incremental recovery from the CO 2 Injection Into the water flooded core was between 12.7 and 38.6% residual oil-in-place (ROIP) in the water-alternating gas (WAG) mode and between 23.1 and 33.2% ROIP for the slug process. The total recovery appeared to level off at 60% IOIP. The CO 2 injection into the core at the initial oil saturation recovered 29.9% IOIP in the WAG mode and 41.6% IOIP for a slug process where CO 2 was allowed to soak for 69 h. There appears to be considerable merit in soaking with CO 2 prior to water injection. Introduction Saskatchewan has an extensive gesture of heavy all. The proven resource 1.0 × 10 9 m 3 and the probable oil-in-place 3.4x10 9 m 3 . 1 The heavy all reservoirs of Saskatchewan ate characterized by thin pay, shaley sand, heterogeneity, low productivity and bottom water. Fifty-five percent of the Initial heavy oil-in-place is contained in reservoirs less than 3 m thick and ninety-five percent in less than 7 m thick. 2 Primary and secondary methods together recover less than ten percent of the initial oil-In-place. The development of appropriate recovery techniques specific to Saskatchewan reservoirs is necessary If the full potential of this resource is to be realized. Saskatchewan's heavy oil enhanced recovery projects have centered around steam injection and in-situ combustion. While steam Injection has been very successful, it is not expected to be economically feasible for those reservoirs which contain approximately eighty percent of the heavy oil. 3,4 In-situ combustion, although applicable to thin reservoirs, has been and marginally successful thus far. Recovery of heavy oil using carbon dioxide immiscible flooding is considered to be the most promising among the non-thermal EOR processes, particularly for those reservoirs having such undesirable geology as found in Saskatchewan. 4–6 Since 1982 the number of carbon immiscible projects in the United States has grown from zero to eighteen. 3