Secondary Gas Recovery From a Moderately Strong Water Drive Reservoir: A Case History

Summary Blowdown performance of several south Texas water drive gas reservoirs indicated that a substantial quantity of gas was trapped in water invaded regions. Pressure support in many of these reservoirs is from limited aquifers. Depressuring the reservoir by withdrawing large volumes of water to recover trapped gas was evaluated. Evaluation, implementation, and results of this secondary gas-recovery (SGR) technique are discussed for one of these reservoirs. Introduction Increased gas recoveries from water drive reservoirs operated under accelerated blowdown are documented in reservoir case histories.1 Analysis of H-21 resservoir's blowdown performance from 1978 through 1979 attributes 7.7 Bcf (218×106 m3), or 10% of the cumulative gas production, to accelerated blowdown. After accelerated blowdown, much gas often is trapped in water drive reservoirs. One proposed method3 to increase gas recovery is to depressure a water drive reservoir by withdrawing large volumes of water. This causes the release of trapped gas and permits recovery from producing wells. Secondary gas recovery projects are defined as those that utilize some sort of fluid injection or fluid production to achieve increased ultimate gas recoveries. The withdrawal of large volumes of water from the North Alazan H-21 reservoir and its adjacent aquifer to reduce reservoir pressure and to recover more gas than could be realized by conventional operations demonstrates a practical application of one SGR technique that is discussed in this paper. The North Alazan H-21 is a moderately strong water drive gas reservoir that trapped 44 Bcf (1.2×109 m3) of gas in the water invaded region at an abandonment pressure of 2,200 psi (15.2 Mpa) (62% of original pressure). Producing water at 30,000 B/D (47×103 m3) should reduce abandonment pressure to 500 psi (3.4 Mpa) and allow the additional recovery of 22 Bcf (620×106 m3) of trapped gas. Despite efforts to "outrun" water influx from the aquifer by reducing the reserves/production ratio (R/P) to 1.5, the H-21 gas cap watered out completely in July 1980, recovering 64% of the 121 Bcf (3.4×109 m3) of gas initially in the reservoir. The remaining 44 Bcf (1.2×109 m3) of trapped gas provided the additional recovery incentive for this project. Four artificially lifted large casing wells completed in the H-21 aquifer near the original oil/water contact and three wells located in the water invaded gas cap region are the main water producers, with individual water production rates ranging from 3,000 to 8,000 B/D (477 to 1272 m3/d). In addition, 10 small casing wells positioned on the structural crest collectively withdraw 3,000 B/D (477 m3/d) and function in the project as the principal gas producing wells. Computer simulation of the North Alazan H-21 reservoir utilized two-dimensional (2D) radial and three-dimensional (3D) rectangular models to match historical reservoir performance and provide gas recovery predictions for various water production rates. Reservoir response data obtained through surveillance activities provides basic input for these two numerical simulators, which generate updated predictions to guide long term management of the H-21 SGR project. Design and installation of water production facilities together with well test methods used to acquire high volume artificial lift design parameters are described for the project. Electric submersible pumps are installed in high-rate water wells completed in the H-21 aquifer, with gas lift used to produce high water rates from wells completed in the water invaded region. Typical operational problems and solutions and early results of water production from the reservoir are included.