Water and gas coning is a serious problem in many oil field applications. In reservoirs with bottom water, vertical wells are normally completed in the top section of the pay zone to minimize water coning. Similarly, in a reservoir with a gas cap, a vertical well is perforated as low as possible to delay gas coning. Oil production from thin oil layers sandwiched between a gas cap and bottom water, such as one finds in the Amber Field in the Gulf of Mexico presents difficult coning problems in vertical wells.

This paper describes Texaco's efforts to evaluate, justify and drill a horizontal well in Amber Field. The target reservoir contains a very thin pancake oil zone sandwiched between a large gas cap and a strong bottom water aquifer. The production wells were expected to exhibit critical oil rates of approximately 10 STB/day (calculated). Due to the gas and water coning, the vertical wells in the field produce at low oil rates and recovery was in the range of 3% to 4%. This paper details efforts to numerically model the optimum case for vertical and horizontal wells to allow for economic comparisons. The effect of the length of the horizontal wells, their location relative to the current fluid contacts, and the change in performance with production rate are all investigated.

The simulation process involves four individual steps: (1) history matching the adjacent well with coning problems, (2) assessing the current fluid distribution by a coarse-grid model with single-phase producers, (3) calculating the initial rate of a horizontal well, and (4) horizontal-well performance prediction. It is demonstrated that the optimal well position depends on the development term. A horizontal well penetrating the oil column produces more oil and water during the early stage of horizontal well production. In the long run, it appears to be beneficial to place the horizontal well in the gas cap, which gives the highest oil recovery and significantly reduces water coning.

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