TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA comprehensive set of experimental data from preserved reservoir sandstone is used to demonstrate features important to oil-wet systems not usually included in water-wet three-phase relative permeability models. The data are described by a generalized version of the relative permeability model developed by Jerauld (1997). The impact of these features on immiscible and miscible water-alternating-gas performance is estimated with type pattern simulations.The sandstone reservoir studied shows large amounts of spontaneous imbibition of oil and traps water during secondary drainage. Oil relative permeability is almost a function of oil saturation alone while water relative permeability is significantly lower in the presence of trapped gas. Unlike most systems, the trapped gas saturation depends on the relative amounts of oil and water. While two-phase trapped gas values are consistent with values in the literature for similar sandstones, three-phase trapped gas levels are approximately a factor of two lower. The residual oil saturations for waterflooding and gasflooding followed by waterflooding are the same. Furthermore, the incremental oil production during the waterflood following gasflooding was minimal.Two different lithologies show the same general behavior. Experiments run with different pressure drops demonstrate that the low trapped gas saturations are not due to capillary desaturation. CT scans show that little redistribution of gas occurs during trapping.

Summary Core data from a sidetrack well 250 ft from an old injection well showed intervals of excellent miscible-gas sweep, with miscible-flood residual oil saturations (ROS's), Sorm, of ˜5% PV. Less-well-swept intervals had intermediate Sorm values. Numerous intervals had not been contacted by miscible injectant (MI). Chromatographic analyses of the Dean-Stark core extracts quantified miscible-gas alteration of the oil and was especially valuable in the interpretation of intermediate oil saturations. Compositional reservoir simulations showed that high-permeability thief zones and a number of thin shales controlled sweep efficiency near the cored well. Background The Prudhoe Bay field on the north coast of Alaska is the largest oil field in North America, with total estimated reserves of ˜ 12 billion bbl and a current production rate of ˜ 1.1 million STB/D. The field is overlain by a large gas cap, and most of the field is being produced by gravity drainage. Waterflood operations at Prudhoe Bay, which are confined to the downstructure and peripheral areas of the field, are producing ˜ 400,000 STB/D. The Sadlerochit group, the major productive interval of the field, includes a thick section composed of high-permeability fluvial sands and interbedded shales.1 In the Flow Station 2 area, where the sidetrack core was taken, these shales create up to five completely isolated flow intervals. Prudhoe Bay EOR began in late 1982 with an 11-pattern pilot project. Expansion of EOR operations began in 1987, and now more than 100 patterns are operating. As Fig. 1 shows, the unit plans significant further expansion of the Prudhoe Bay Miscible Gas Project (PBMGP) over the next few years. The PBMGP currently has a solvent injection rate of ˜ 600 million scf/D at an average water-alternating-gas (WAG) ratio of ˜ 3 : 1. The solvent is manufactured by the central gas facility (CGF), which has a nominal processing capacity of 7.5 billion scf/D. Residue gas from the CGF is reinjected into the gas cap. The design and installation of the Prudhoe Bay gas-handling facilities have been described previously.2–4 EOR evaluation and optimization have been complicated by immature waterflood development, infill drilling, and extensive fracturing and workover programs. Numerous field measurements have been made to evaluate miscible-flood displacement and sweep efficiency, including water- and solvent-injection profiles, logging data from a fiberglass-cased observation well, single-well tracer-test data for waterflood and miscible-gas ROS's, and separator-gas-sample compositional analyses.5 The available field and laboratory data indicated favorable EOR response, but more conclusive data were needed to justify additional projects. Sidetrack Core Acquisition A very poor injection profile and operational problems in Drillsite 3 Well 18 (Well DS 3-18) led to a redrill of this injector in April, 1993, as Well DS 3-18A. This was the first sidetrack of an existing WAG injector at Prudhoe Bay, and it provided an ideal opportunity to obtain conclusive data on miscible-flood sweep efficiency and ROS's. Cumulative solvent injection into Well DS 3-18 was 8.4 Bscf before the redrill, which was 2.7% of the pattern total PV; cumulative water injection was 64 million res bbl. Table 1 shows the spinner profile data, and Fig. 2 shows a cross-section of Wells DS 3-18 and DS 3-18A. Most of the injection went into the high-permeability conglomerate of Zone 3; very little injection went into Zone 2. Most of the injection into Zone 4 was at the very top of the interval, where gravity segregation would prevent the MI from contacting new oil. Because of this inefficient profile, no solvent had been injected into Well DS 3-18 since May 1992. Compositional simulation results of a detailed near-well model with a similar reservoir description were used to determine the optimal placement of the sidetrack. These results showed that, after a similar volume of solvent injection, the maximum amount of "character" in oil saturation should occur ˜ 200 to 300 ft from the injection well. If the sidetrack were placed closer to the original well, solvent sweep would be more or less uniform and little would be learned about gravity segregation of the MI. If the sidetrack were placed farther from the original well, it would encounter only a few solvent fingers. We therefore planned to put the sidetrack 250 ft from the old injector to gather the maximum possible sweep efficiency and residual-saturation data. This modeling data proved critical in the proper location of the sidetrack well. Table 2 lists the MI and water throughput at the 250-ft radius. A total of 467 ft of conventional core was cut at the DS 3-18A sidetrack well over a 7-day period. Total core recovery was 459.5 ft, or 98.4%, from 12 cores. Typically, 60-ft aluminum core barrels were used; core diameter was 4 in. Directional surveys indicated that the sidetrack, which had a 35 ° hole angle, was within the target of 250± 50 ft from the old wellbore. Coring rates averaged ˜ 40 ft/hr in sandstones and ˜ 5 ft/hr in conglomerates and shales. A 30,000-ppm KCl mud with bentonite, starch, polymers, and calcium carbonate solids was used to obtain both low invasion and good shale stability. Mud weight was 9.8 lbm/gal. NaBr was used as a tracer to monitor filtrate invasion. Refs. 6 and 7 provide details of the coring procedures. Although overall core recovery was excellent, a significant fraction of the conglomeratic intervals were disaggregated in coring and/or surface processing. Whole core porosity and oil saturation could be obtained on almost every foot of core, but permeability data were unavailable in ˜ 20 ft of the conglomerate. Unfortunately, the most-permeable intervals probably were included in this 20 ft. Geologic and operational studies have shown that effective permeabilities of some conglomerates are much higher than have been measured in the cores. Open-framework conglomerates, which have very little sand matrix material and virtually no cementation, appear to be responsible for the extremely high permeabilities observed from injection and production profiles.8,9 These open-framework conglomerates appear to be a few inches to about a foot thick and could easily be represented in the numerous rubble intervals observed in the core.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper summarizes the acquisition, conventional and compositional core analysis, and reservoir simulation history match of a core taken roughly 300 ft from a production well in the most mature area of the Prudhoe Bay Miscible Gas Project (PBMGP). Fine-gridded reservoir simulations yielded a good match of the offset well production rates and also of the observed compositional behavior of the core. The data showed that roughly 70% of the cumulative EOR came from reducing the residual oil saturation near the injection well. The remaining 30% was due to oil swelling. The swelling mechanism was especially important near the production well where the core was taken. Both simulation and field data show that additional miscible gas injection into this area would yield very little incremental EOR.

This paper summarizes the acquisition, conventional and compositional core analysis, and reservoir simulation history match of a core taken roughly 300 ft from a production well in the most mature area of the Prudhoe Bay Miscible Gas Project (PBMGP). Fine-gridded reservoir simulations yielded a good match of the offset well production rates and also of the observed compositional behavior of the core. The data showed that roughly 70% of the cumulative EOR came from reducing the residual oil saturation near the injection well. The remaining 30% was due to oil swelling. The swelling mechanism was especially important near the production well where the core was taken. Both simulation and field data show that additional miscible gas injection into this area would yield very little incremental EOR. Background The Prudhoe Bay field, located on the north coast of Alaska, is the largest oilfield in North America, with total estimated reserves of roughly 13 billion barrels and a current production rate of approximately 600 Mstb/D. The field is overlain by a large gas cap, and the majority of the field is being produced by gravity drainage. Waterflood and miscible EOR operations at Prudhoe Bay, which are confined to the downstructure and peripheral areas of the field, are producing roughly 250 Mstb/D. Prudhoe Bay EOR began in late-1982. The Flow Station 3 Injection Project (FS3IP) was an 11-pattern pilot project in the Drillsite 13 area. The PBMGP was initiated in 1987 with 43 additional patterns. Currently there are about 130 total EOR patterns at Prudhoe Bay (Figure 1). The patterns are typically inverted nine-spots with 80-acre well spacing. The PBMGP currently has a miscible injectant (MI) rate of over 500 million scf/D at an average water-alternating-gas (WAG) ratio of about 3:1. The Sadlerochit Group, the major productive interval of the field, includes a thick section composed of moderate-to-high permeability fluvial sands and interbedded shales.1In the Flow Station 3 (FS3) area the dominant pay interval is Zone 4, which is overlain by the Shublik limestone and the low permeability Sag River sandstone. Although the Sag River is perforated in both injection and production wells in the FS3 area, it contributes very little production and receives very little injection at FS3, and will not be discussed further in this paper. An extensive non-pay heavy oil/tar zone (HOT) underlies the oil column and prevents aquifer influx in most of this area. Figure 2 is a detailed map of the FS3 area showing the cored well. A log cross-section of this area is shown in Figure 3. The PBMGP has been a very successful EOR project. However, many of the existing EOR patterns are becoming mature, and are making less efficient use of the limited MI supply.2,3 New miscible targets and processes are being tested.4 Solvent for these new projects must be taken away from existing mature patterns, so it was necessary to determine the impacts of terminating solvent injection into those patterns. The sidetrack of one of the original FS3IP injectors provided an ideal opportunity to measure sweep efficiency and residual oil saturations in a mature pattern.

Much effort has been devoted to understand the mechanisms responsible for the variation of CO2 flood residual oil saturations found both in the laboratory and in the field. Some of the many possible explanations are the detailed nature of CO2 possible explanations are the detailed nature of CO2 /oil phase behavior, trapping of oil by mobile water, viscous fingering, and bypassing of oil due to the micro-pore structure of a given porous medium. The purpose of this study was to investigate the influence purpose of this study was to investigate the influence of rock characteristics alone on miscible displacement behavior through a combination of displacement testing and modeling. Modeling was used to characterize the displacements and to extrapolate the observed phenomena to untestable conditions. The displacement phenomena to untestable conditions. The displacement tests were used to calibrate the model and to test the model's predictive capabilities. A number of stabilized CO2 displacements and xylene displacing iso-octane tests were conducted in both outcrop sandstones and San Andres reservoir carbonate core samples. By flooding with xylene displacing iso-octane, phase behavior complications and viscous fingering were avoided. Such an idealized displacement represented the "best case" laboratory miscible displacement. Effluent concentration profiles for the xylene displacing iso-octane floods profiles for the xylene displacing iso-octane floods were matched to the capacitance-dispersion model of Coats and Smith to estimate the magnitude of axial dispersion and so-called "dead-end" pore volume or capacitance. The latter quantity was found to be essentially zero in outcrop sandstones but quite variable in the highly heterogeneous San Andres carbonates, attaining values as high as 50%. Axial dispersion followed similar trends. The carbonates displayed more variable and larger axial dispersion than the sandstones. First contact and CO2 miscible flooding residual oil saturations were compared in the same core samples. Both measures of residual oil saturation were in agreement and depended on the particular sample. These data suggest microscopic heterogeneity is a primary determinant of residual oil saturation to miscible flooding when viscous fingering is controlled. Microscopic heterogeneity resulting from a non-uniform pore structure was characterized by the level of dispersion and capacitance in the rock sample. In addition, both laboratory data and model prediction showed that the effect of dispersion and capacitance on residual oil saturation decreased as the displacement was extrapolated to reservoir rates and system lengths of a few feet. This implies that microscopic heterogeneity is more important in laboratory systems than in field displacements. Introduction Carbon dioxide miscible flooding is one of the most promising tertiary recovery techniques. Considering the expense and complexity of the process, applicability to a given candidate reservoir process, applicability to a given candidate reservoir can, at this time, only be determined by a thorough laboratory, numerical and economic analysis. Usually, the results of such an evaluation depend heavily on an estimate of the CO2 unit displacement efficiency. The unit displacement efficiency is measured by field pilot testing or from laboratory core displacement tests in which a laboratory CO2 -flood residual-oil saturation, S, is compared to a waterflood residual-oil saturation, S. A wide variation in CO2 S has been observed in both field pilot tests and laboratory displacements conducted above the multi-contact miscibility pressure. This work was undertaken to further understand the reasons for this variation. A better understanding of the mechanisms responsible for the variability of S in the laboratory would guide interpretation of field pilot data and possibly eliminate the need for extensive field pilot testing to obtain unit displacement efficiency. Variability of S from laboratory data has been attributed to such factors as CO2 /oil phase behavior, rock tore structure trapping of oil by mobile water, flooding rate, and rock wettability as well as experimental technique.