The paper was presented at the SPE/DOE Unconventional Gas Recovery Symposium of the Society of Petroleum Engineers held in Pittsburgh, PA, May 16-18, 1982. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy., Dallas, TX 75206.

Abstract

A simple mathematical model was developed to simulate production out of a geopressured reservoir about 15,000 ft. deep and injecting the water into a shallow zone of about 6,000 ft. The model represents a two phase (gas/water) flow in a radially symmetric system. Pressure drawdown curves vs. time for a 30-year period are obtained for a constant drawdown rate or a constant wellbore pressure. A sensitivity analysis was performed on some key parameters to determine the impact of gas accumulation in the formation on production. The impacts of various completion choices on the productivity of the well are also discussed. A successful program for gas production linked to withdrawal of large volumes of water from a geopressured reservoir will require that the well be designed to keep pressure losses in and near the wellbore within acceptable ranges. Effects of tubing size, perforation program, and gravel packing are discussed. packing are discussed

Introduction

A study of the characteristics of flow near the wellbore in a geopressured/geothermal aquifer has been made for the Gas Research Institute as part of their R and D activities leading toward eventual recovery of economic quantities of gas from water-dominated geopressured sands. The study focused on identification of flow effects that will have an impact on the selection of completion design for wells designed to co-produce large quantities of gas and water. Complications in assessment of formation damage were also looked at. Co-production of gas and water from a geopressured aquifer will involve recovery of much greater volumes of brine than are routinely handled in gas production. Maximizing recovery of the resource will require minimizing the pressure losses in and near the wellbore.

This will be especially true if dispersed free gas is present so that the goal of the co-production operator is to enhance free gas mobility by drawing down the reservoir pressure. Pressure losses resulting from the flow of the two phases through the formation and the pressure drops associated with water production on the scale of tens of thousands of barrels per day need to be considered in well planning and completion design to achieve good well performance.

RESERVOIR FLOW CHARACTERISTICS

In a water-filled aquifer with gas initially present only in solution, flow performance will be similar to that in a single phase reservoir at short times. As pressure drops and gas is released from solution, the free gas phase accumulates near the borehole as it is released from the water flowing toward the well and begins to effect the flow. For a given rate of water withdrawal from the aquifer, the accumulation of the free gas will depend on the critical gas saturation of the formation and on the variation of gas permeability with gas saturation. The impact of the free gas accumulation near the borehole was examined to determine its impact on well performance. A numerical model for radial flow in the aquifer based on a finite difference approximation of the coupled Darcy flow equations for the gas and water phases was used. Formation parameters (Table 1) for a base case were selected, based on data on aquifer properties in the Gulf Coast Frio formation. The base case represents an aquifer with good permeability and substantial size, capable of sustaining production on the order of 25,000 Bpd over a thirty year period. These reservoir parameters fulfill the requirements estimated in period. These reservoir parameters fulfill the requirements estimated in various economic studies in the literature for a commercially-viable reservoir. Disputes on the issues of resource economics and size are not relevant to this study. The critical gas saturation was set at six percent. The relative permeability relationship was computed following percent. The relative permeability relationship was computed following Corey, et. al. Figure 1 illustrates the relative permeability curve. Figure 2 shows drawdown vs. time for the assumed base case Frio reservoir.

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