Summary The Conroe Field was unitized on Jan. 1, 1978 and Exxon Co. U.S.A., as the unit operator, assumed the producing responsibilities of 26 operators in the field. This paper describes the operator's approach to consolidation and automation of the facilities of all operators to provide more efficient field operations and surveillance to meet reservoir management objectives. Introduction The Conroe oil field is 40 miles (64 km) north of Houston on the upper Texas gulf coast. The 30-sq mile (78 km) field was discovered in 1931 and is developed on 20-acre (81 x 10 M) spacing with about 1,100 wells. The major producing horizon occurs at an average depth of 5,000 ft (1500 m). Total Conroe field maximum efficient rate (MER) is 60,000 B/D (9540 M /d). Before unitization, those leases that joined the unit included 520 active oil wells with an assigned MER allowable of 58,300 B/D (9268 M /d).The Conroe field has experienced severe gas cap shrinkage, resulting in loss of recoverable oil as residual saturation in the original gas caps. From extensive technical studies, it was apparent that major changes in the operation of the field were necessary to arrest gas cap shrinkage and increase ultimate oil recovery. Operation on a reservoir basis (as opposed to a competitive lease basis) was required, and this could be achieved only through unitization. A fieldwide unit was formed on Jan. 1, 1978, following more than 5 years of negotiations. The unit included 218 tracts and 26 operators.A unit operating plan, which was developed during preunit negotiations, included actions to accomplish both reservoir- and facility-operating objectives. To maintain maximum unit production, it was imperative that production facilities be operationally flexible and impose no constraints on changing liquid withdrawal targets. To meet reservoir management objectives, liquid withdrawals were redistributed to reduce production from gas cap expansion zones and to increase withdrawals from higher pressured sands and those experiencing gas cap shrinkage. Where possible, withdrawals were made by transferring oil allowables and aided by an extensive workover and drilling program. Where even greater withdrawals were needed, the deficit was made up by continuing to produce high water-cut oil wells and, in some cases, by producing 100% saltwater wells.The unit operator's production facilities, which processed approximately 58 % of preunit production, had been consolidated previously and automated during 1971 (Figs. 1 and 2). Approximately 250 wells produced into 24 automated metering sites where (1) production was measured, (2) most gas and salt water was separated, and (3) the remaining emulsion (oil, water, and gas) was transferred to a central treating station for clean oil processing and automatic custody transfer (ACT) to a pipeline company. All wells were either flowing or gas lifted. Low pressure gas was gathered by a gas gathering system and processed at one of two gas plants in the field for product recovery. Gas-lift gas was supplied from gas plant compression. Salt water was disposed in two disposal systems.In contrast, the facilities of the 25 other operators consisted of 89 conventional tank batteries. Production from approximately 270 wells produced into conventional separation and heat treating equipment and then to gunbarrels and settling tanks for clean oil processing. JPT P. 771^
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Feb 1, 1998
Yun‐Chul Chung + 3
Open Access