Abstract

The South Cowden Unit was selected for one of three mid-term field demonstration projects being conducted under the DOE Class II Oil Program for shallow-shelf carbonate reservoirs. The South Cowden project is designed to demonstrate the technical and economic viability of using horizontal CO2 injection wells and centralization of surface facilities to optimize CO2 project economics. If successful, this approach will help to improve the economic viability and application of CO2 flooding for many smaller fields which might otherwise soon face abandonment.

Successful design and implementation of the project requires a focused, cost-effective reservoir characterization effort to identify those reservoir characteristics and field areas best suited to application of this technology. Integration of production and well test data with geologic reservoir description information was necessary to develop a sufficient understanding of the permeability distribution at South Cowden. A predictive history matching approach was used in modeling historical field performance to further refine the reservoir description.

Field History

The South Cowden Unit (SCU), located in Ector County, Texas, produced from the Grayburg Formation at an average depth of approximately 4550 feet. A summary of reservoir and fluid characteristics is presented in Table 1. Initial production from the Unit area began in 1948 and a total of approximately 100 wells have been drilled at SCU on 20-acre spacing. The field was unitized for secondary recovery waterflood operations in 1965 with initial water injection going into peripheral wells located around the edge of the producing structure near the oil/water contact. Leaseline cooperative water injection was added in the early 1970's along the northern boundary of the Unit. From the late 1970's through the mid-1980's, several additional water injection wells were added at selected locations in the interior of the Unit, however there was no formal injection pattern at SCU.

In spite of the lack of a regular flood pattern, waterflood performance at SCU has been excellent (Fig. 1). The Unit is currently nearing its economic limit for waterflood operations. At the end of 1995 there were 11 active injectors and 39 active producers and Unit production was a little over 400 BOPD at a watercut approaching 95%. Selective infill drilling over the past few years has met with only limited success, leaving tertiary CO2 enhanced oil recovery as the only viable prospect remaining for extending field life and adding significant reserves.

Project Overview

Two earlier CO2 flood feasibility studies both indicated SCU to be an excellent technical candidate for CO2 flooding, but the project could not meet requisite economic criteria. The capital costs for new injection wells and related facilities to implement a conventional pattern CO2 flood development were too high relative to the recoverable oil volumes at SCU. Most of the current wells are not suited for conversion to CO2 WAG injection service because of mechanical or completion problems. The situation at SCU is one which will confront operators of many smaller fields in the Permian Basin.

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