El Bunduq reservoir is located in the offshore area of Abu Dhabi and Qatar. The field was shut-in in July 1979 due to production with high gas-oi 1 ratios. Pressure differences of 200-400 psi between the flanks and the central part of the reservoir were sti 11 present almost four years after the field was shut-in. A comprehensive reservoir engineering study determined that the reasons for this behavior were the deteriorating qualities of the reservoir rock downstructure and the presence of a tar mat around the field.After the field behavior was history matched, model studies of a representative sector of the field indicated that peripheral waterflooding would recover 1 ess than 15 percent of the 001 Pin a peri od of 30 years.However, pattern injection recoveries were calculated to be at least twice as high.Several full field alternatives were investigated to optimize the development of the reservoir under a pattern waterflood. This paper summarizes the various studies that led to the acceptance of the idea of pattern development over peripheral injection, as a result of the unique characteristics of this field.

Performance predictions of a proposed miscible CO2 injection project for the Wellman Field, Terry County, Texas were made using an enhanced oil recovery process numerical simulator. The study investigated the potential of injecting a relatively small, gravity stable CO2 slug with nitrogen as the drive gas into the crest of the cone-shaped reservoir. The effects of slug size, injection rate and reservoir pressure were evaluated for an optimum future operating plan. The differences in fluid densities at reservoir conditions were conducive to gravity segregation of the nitrogen, CO2 and miscible oil bank. Assuming that most of the produced CO2 would be reinjected, a CO2 slug as small as 15 % of the initial hydrocarbon pore volume appeared to be sufficient to mobilize the remaining recoverable oil in-place. Oil production performance during the early years of the project was similar production performance during the early years of the project was similar for CO2 injection rates of 10 MMSCF/D and 20 MMSCF/D so the lower rate case appeared economically more attractive. Since the massive carbonate reef, having a vertical oil column of over 800 feet, exhibited no major barriers to impede horizontal or vertical fluid flow, an excellent sweep of the reservoir was predicted in all cases. The shape and integrity of the thin CO2 slug depended to a to a great extent on the location of the producing wells and the magnitude of their drawdowns. The successful implementation of the proposed CO2 flood in the field will require a continuous pressure and production monitoring system with an ongoing workover and recompletion program to stay ahead of the gas front. The results of this study indicated that the concept of the proposed CO2 flood was reasonable and could provide an economic tertiary oil recovery process for the Wellman Field. Though most Middle East oil reservoirs have remaining many years of primary and secondary recovery the potential benefits of tertiary recovery primary and secondary recovery the potential benefits of tertiary recovery methods should be investigated thoroughly before future action is necessary. A miscible CO2 injection scheme similar to the one studied for the Wellman Field may be applicable to some of the reservoirs in that area if the proper conditions exist. Introduction The objective of the study was to analyze the historical behavior of the Wellman Field and predict future performance by both continued waterflood and by gravity-stable, miscible CO2 injection. The complete study included analysis of the geology, the well logs, and the production and injection history of the 39 wells in the Field. The contents of this paper will emphasize the engineering aspects of the study, and in paper will emphasize the engineering aspects of the study, and in particular the results of the CO2 prediction cases. The study investigated particular the results of the CO2 prediction cases. The study investigated the potential of injecting a relatively small, gravity stable CO2 slug with nitrogen as the drive gas into the crest of the cone-shaped reservoir. The effects of slug size, injection rate and reservoir pressure were evaluated to determine an optimum future operating plan. The numerical simulation phases of the project involved the construction of a representative model of the reservoir which would be capable of meeting the objectives of the study. A three-dimensional, full field model with 1,320 cells was determined to be adequate for the conditions expected in the reservoir.