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.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractA novel EOR method, Viscosity

This pawr was prepmwcf for pmsentafion at the t998 sPGDOE Improved oil Recoww SwnposRttm held in Tulsa, Oklahoma, f9-22 April 19!38, his papar was selected for presentation by an SPE Program Comm"tiee following review of information confained in an absf roct submfttckf by the author(s). Contents of the paper, as presented, hava not been revfewed by fhe %&fy of Petroleum Engineers and are subject to .xmucifon by the authoi[s). I'fffi nmtwfal, as pr&mted, does not necessanfy reflect any pcdion of the Society of PefroIeum Engineer8, ifs ofiicem, or members. Papers presented at SPE meetings am subJecf ?O pubficafion re@ew by Mforial Commiffeea of the Society of Petroleum Engineers. Efecfronic reproduction, distniution, or storage of any part of this paper for commerclat purposes wffhouf the wrfften consent of the Society of Petroleum Engineers is prohibied. Permission to reproduce In prfnf Is restricted to an abstract of not more fhan 300 words illustrations may not ba copied. The abstract must contain conaplcuoua acknowfedgmon~of%%=e~ntf by whom the papar was presenf ed. W rite Librarian, SPE, P.O. Box 833838, Richardson,~7S083-3E3S, U. S.A., fax 01-972-952-9435.Abstract"

Full-field EOR performance predictions are generally obtained from scale-up tools, since three-dimensional finite-difference simulations would be too CPU intensive. Existing scale-up techniques require the user to define pattern elements and then to derive performance curves to apply to each injector-producer pair in the elements. Accurate assignment of these elements is difficult because the actual shape and size of the swept volumes are sensitive to reservoir faulting, well rate changes, and regional flux. In reality, the actual sweep region is not an input parameter, but should be determined by the regional pressure field which changes as well rates vary and new wells are drilled. Thus, a major source of error in using existing scale-up tools is trying to define representative pattern elements. In the current paper, we describe a scale-up technique in which the user does not have to define pattern elements or injector-producer pairs. In the new technique, the pressure field is computed at each time step and then a front-tracking algorithm propagates water and miscible injectant throughout the reservoir. By using an analogy between oil mobilization and adsorption/desorption of tracers, the miscible-gas process is modeled. The parameters for the model are obtained by fine-scale, two-dimensional, compositional, finite-difference simulations in a vertical cross-section. In the new approach, the injected solvent is divided into an effective and an ineffective portion. This approach reduces a three-dimensional problem to a two-dimensional, areal one in which the declining displacement efficiency of the solvent, which is caused by vertical effects, is captured by decreasing the injected concentration of effective solvent with time. In this paper, we show how the new scale-up tool has been used to model the miscible WAG process in the Eastern Peripheral Wedge Zone of the Prudhoe Bay field. We show a comparison between field response and model predictions. Introduction Good reservoir management requires the prediction of reliable oil and gas rates. In general, the degree of difficulty in making these predictions depends on the displacement process. For example, good predictions of primary depletion or gravity drainage by gas-cap expansion can usually be obtained by coarsely gridded finite-difference simulations. However, processes where injected water or gas must be tracked from injector to producer typically require finely-gridded simulations. Accurate prediction of oil and gas rates frequently require finely gridded simulations which contain (1) rock-measured relative permeabilities and (2) a reservoir description that accurately predicts high-permeability zones (thieves) and low-permeability barriers (e.g., shale location, size, and continuity). At Prudhoe Bay, modeling of miscible gas processes generally requires vertical grid blocks of the order of one foot to match field-measured saturation profiles. At the present time, three-dimensional, compositional modeling of gas displacement processes that satisfy these two requirements require at least a week of CPU time on IBM-590 workstation for a single pattern. Thus, it is not currently practical to use finely gridded finite-difference simulators to model large sections of a field. Traditionally, three approaches have been used to address this problem -- pseudo relative permeabilities, tank models, and streamtubes. Pseudo relative permeabilities are generally successful only when the saturation history experienced in the coarse-grid simulation will always be similar to the fine-grid simulation. Tank models can be difficult to apply when the original pattern changes by infill drilling or well conversions, and streamtube models have had difficulty when the initial conditions are not homogeneous along each streamline. To address the above problems, a new approach was created that can reproduce the response and timing characteristics of the produced components, but also has the ability to propagate and track injected fronts. In addition, the model does not require user-supplied injector-producer allocation factors. We explain, below, our new front-tracking technique and how this new scale-up tool has been used to model the miscible WAG process in the Eastern Peripheral Wedge Zone of Prudhoe Bay. P. 329

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.