A simulation study of horizontal well performance in a mature cyclic steam injection project in California is presented in this paper. Decline of production rates was observed in the field. This decline forced the operator to look into strategies of infill drilling and recompletion of existing wells. Horizontal infill wells, recompleted vertical wells, and mixed strategies were considered as the alternatives for further development of the reservoir. In 1997 Al-Hadrami et al. presented the results of a simulation study for this field, where horizontal well strategies have been proven more productive than vertical well recompletion strategies. In the presented simulation study, performance of a single horizontal infill well has been studied in detail. A model simulating a section of the reservoir was developed with a refined grid around the horizontal well. The model includes all the key features of the reservoir. Using the developed model, a number of scenarios of horizontal well production were simulated in the range of applicable parameters (well location, injection rate, schedule). Details and description of simulated scenarios are presented in the paper. Scenarios are compared on the basis of cumulative oil production. Results indicate strong dependence of the cumulative oil production on the well location with reference to Water Oil Contact (WOC). Effects of injection rate, and well and injection timing are also illustrated. All the presented strategies result in an increase in cumulative production.
The Midway Sunset field is located in Kern County. Southern California (Fig. 1). It is a large oil field, with ultimate reserves of 2.75 billion barrels. Due to the low gravity (14 API) and high viscosity (2,300 cp. at 95 F), thermal recovery techniques have been employed to produce oil from this field.
Berry Petroleum Company has been operating this field using steam assisted gravity drainage, with approximately 7, 500 STB/D of oil production. The geology of the Monarch Sands consists of thin units (2 to 10 ft.) aggregating about 1,000 ft. in stratigraphic thickness. The beds dip 60 to 70 degrees and the trap is provided by a truncating unconformity with 20 degrees dip (Fig. 2). The sands show high porosity (about 30%), high oil saturation (approx. 80%), and high OOIP of 1,800 barrels/acre-It with an original oil column from 0 to 1,000 ft. Wells are tightly spaced (1/4 acre well spacing on average). A cyclic steam assisted gravity drainage with vertical wells at small spacing has been effective. Residual oil saturation is typically 10% in the depleted zones.
During the operation, a large steam chest in the upper part of the reservoir has developed. The average steam chest pressure is low (about 18 psi) as the result of steam cycling with balanced injection and production rates. A decline of production rates was observed in the field.
Past simulation studies by Chona et al, and Al-Hadrami et al revealed that horizontal infill wells may offer superior reservoir performance as opposed to recompleted vertical wells (see Fig. 3). In this study, the major objective was to evaluate conditions for an optimal single horizontal well performance. A model of a reservoir section containing a single horizontal well was developed. The model accounts for all key features of the reservoir and includes the actual reservoir dip of 60 degrees. Using the model, current average oil and water production rates were simulated for a number of acceptable scenarios. From the results, optimal operational conditions for horizontal well production were determined.
The 3D reservoir model used for this study represents a section of the field. The simulation grid of size 11x24x24 was used in the simulation (see Fig. 4). The model simulates eight different sand layers, each 100 ft. thick.