Horizontal Well Development of a Gravity Drainage Reservoir, 26R Pool, Elk Hills Field, California

Abstract

Abstract Eighteen horizontal wells have been completed in the 26R reservoir, Elk Hills Field, CA, through January 1995. The horizontal wells have been critical in maintaining high oil production rates from the reservoir and have significantly increased ultimate recovery. The 26R reservoir is a steeply dipping, layered, turbidite channel-sand deposit in the Miocene Monterey Formation. The high dip and low kv/kh ratio make gravity drainage the dominant production mechanism. The reservoir operating policy has been full pressure maintenance through updip gas injection since 1976. Horizontal drilling was first undertaken to develop reserves that could not be effectively recovered by conventional vertical wells in the thinning 26R oil column overlain by an expanding gas cap. Gravity drainage along the dipping bedding planes into horizontal wellbores placed just above the oil-water contact provides an effective recovery mechanism in such an environment. Over time, the horizontal wells have become the principal factor in determining the development/depletion strategy for the mature 26R reservoir. They have been successful not only in increasing oil production rates and ultimate recovery but also in controlling gas production, reducing injection requirements, and minimizing related operating costs. This paper discusses the evolution of the reservoir development strategy utilizing horizontal wells, the geologic factors dictating changes in the design of the wells, and the operating efficiencies afforded by the horizontal wells. Field data illustrating the critical importance of the horizontal development program to 26R reservoir performance is provided. Introduction The Elk Hills Field is at the south end of the San Joaquin Valley in central California. The 26R Sand is one of the most prolific of the many Stevens zone reservoirs found in the field. It is a massive complex of turbidite channel sands on the southwest flank of the 31S anticline (Fig. 1), dipping as much as 70 degrees. The oil column was initially about 1800 feet thick. The high dip angle makes gravity drainage the dominant drive mechanism. Full pressure maintenance through updip gas injection has been the operating policy since the 26R reservoir was put on sustained production in 1976. The reservoir was originally developed with conventional vertical wells on 10-acre spacing. Production rates in these wells were initially very high due to the thick pay interval, permeable reservoir sands, and high formation dip. The reservoir was undersaturated when production began, so that gas was initially produced at the solution gas-oil ratio (GOR) of 600-800 SCF/BO. Oil production peaked in 1981 at 53,000 BOPD and began declining steadily in 1983 (Fig. 2). The oil column became progressively thinner as withdrawals continued, and with corresponding growth in the gas cap free gas production steadily increased. As part of the pressure maintenance strategy, the vertical wells were produced until reaching a GOR of 12,000- 15,000 SCF/BO. Gas isolation work was then attempted, if feasible. Most of the wells were equipped with multiple packers and sleeves to accommodate this work. Controlling gas production became increasingly difficult as the oil column became thinner and the oil was overridden by the more mobile free gas. By 1988, the oil column had been drawn down to approximately 250 feet or less. Many of the wells were producing inefficiently at high GORs and no longer had enough oil productive interval left to attempt gas isolation work. The pressure maintenance strategy required that wells with no further gas isolation potential be shut in when gas production became excessive. Drilling additional vertical wells to recover the remaining reserves from the thinning 26R oil column in the presence of a high pressure gas cap was considered a marginal economic prospect. Thus, horizontal drilling was proposed as an effective means to exploit these reserves.