This paper describes the combined use of volumetric and material balance analysis to understand and predict performance of a large West Texas oil and gas field currently under coproduction.

The Keystone Ellenburger Field, located in Winkler County in the Permian Basin of West Texas, is a large field originally containing both an oil column and a gas cap, along with a moderate to strong water drive. The reservoir is a fractured carbonate with associated vugs and low matrix porosity but high effective permeability due to the natural fracturing. It has undergone a complex development history: primary oil production, gas reinjection and water injection, but since 1992 has been produced by coproduction of large volumes of water to increase gas and oil recovery. As the field matures and the operators confront lower pressures and productivities, along with higher operating and capital costs, we saw the need to develop a reliable predictive model of future performance. Prior efforts with conventional material balances and reservoir simulation have failed to meet expectations.

Because the field has high effective permeability, fluids in the reservoir appear to be in vertical equilibrium. Since 1992 we have acquired pressure and gas-liquid contact information through observation wells. This data, coupled with reservoir maps and production history, have allowed us to build and calibrate a spreadsheet which tracks fluids in place and estimates other parameters such as net water influx.

Reservoir maps were used to generate horizontal slices through the reservoir in order to estimate reservoir pore volume for a given slice through the reservoir. As reservoir pressure declines and the gas-liquid contact moves up or down, we can calculate water influx as well as refine such parameters as effective porosity, original oil and gas in place, and trapped gas saturation.

Based on the historical pressure decline and gas-liquid contact changes we have seen, and using the combined volumetric/material balance approach, we can predict much more accurately how the reservoir will behave under different future production schemes.

The method has shown us that significant gas remains to be recovered, but most of it exists as trapped gas in the water/oil leg of the reservoir. Continued coproduction will lower the reservoir pressure and the gas-liquid contact, both of which will allow additional gas to be produced.