This paper presents the results of a study that optimizes the performance of a horizontal infill well in a cyclic-steam project in the Midway-Sunset field. The field has vertical wells on 1/4 acre well spacing and many of the wells are completed through most or all of the entire 1,000 ft. thick pay. Currently, the upper part of the reservoir exists as a steam chest with remaining reserves occupying the lower portion of the reservoir. Possible production strategies are recompletion of the existing vertical wells in the lower half of the existing oil column and drilling new horizontal infill wells. As part of a larger study, we simulated the performance of the horizontal cyclic-steam wells after history matching production from the current operation.

The productivity of the horizontal wells is strongly affected by their location in the oil column, steaming schedule and injection rate, and the interaction with vertical wells undergoing cyclic operations. The results of the simulation study of the horizontal infill well performance are presented in this paper. Effects of the above mentioned variables on cumulative oil production, rates during each cycle, and steam-oil ratio (SOR) are presented.


The Midway Sunset field is located in the southwest portion of the San Joaquin Basin in southern California. It is classified as a "super giant" 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 a steam assisted gravity drainage project in the Monarch sands of the Midway Sunset field, with an approximate production of 7,500 bopd. The Monarch sands consist of thin 2 ft. to 10 ft. units aggregating about 1,000 ft. in stratigraphic thickness. The beds dip at 60 to 70 degrees and the trap is provided by a truncating unconformity that dips 20 degrees. The sands are high porosity (greater than 30%) and high oil saturation (approximately 80%), with a high OOIP of 1,800 barrels/acre-ft. With an original oil column from 0 to 1,000 ft. vertical and the high barrels per acre foot, the oil in place is very large for relatively small acreage. Over time, Berry Petroleum has developed its properties with tightly spaced wells (1/4 acre well spacing on average). Given the high dip angle of the Monarch sands (60 degrees or more), the use of cyclic steam assisted gravity drainage with vertical wells at small spacing has been effective, with residual oil saturations typically down to 10% in the depleted zones. The high efficiency of thermal recovery techniques has resulted in a recovery factor of 40% to date.

Due to reservoir depletion, a large steam chest of 500 ft. or more has developed over some areas of the reservoir. Current cyclic steam operation practices with balanced injection and production rates have resulted in low reservoir pressures with the steam chest at or above atmospheric pressure (about 18 psia). As the upper portion of the reservoir becomes depleted, cyclic steaming with existing vertical wells, which are completed with slotted liners through both the steam chest and the oil column, is becoming less effective. Much of the injected steam goes to the steam chest while the recovery per cycle has declined and the steam oil ratio (SOR) has increased. Recompleting wells in the oil zone, currently 200–400 ft. thick has been effective. Because of the cost associated with recompletions and the age of many of the wells, recompletion of all of the wells may not be practical or economical.

The initial phase of this study involved building a conceptual model that matched current oil and water production rates in a section of Berry Petroleum's field, comparing the production performance of a series of recompletion alternatives of existing vertical wells, and studying the effectiveness of new horizontal well producers. The complete results of this larger study will be presented in a future paper.

This paper focuses on the optimization of horizontal infill wells drilled perpendicular to the strike (exposing many stratigraphic layers), as to the optimal location of the horizontal section in the oil column, the quantity of steam injected per cycle, and steam-soak length. A numerical simulation study, using Western Altas' VIP-THERM simulator, was conducted to initialize the model, generate the history match and investigate horizontal well parameters.

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