Abstract

The naturally fractured Spraberry Trend Area in West Texas covers an area greater than 2,500 square miles. Of the 10 Bbbl of initial oil, less than 10% has been recovered from this vast reservoir. For many years, Spraberry operators have perforated and stimulated intervals based on gamma ray response which indicated sandstone pay zones. Due to the marginal nature of many Spraberry wells after depletion of the fracture system, core-log correlation and detailed reservoir characterization was generally neglected. In recent years, the Spraberry Trend Area has been extensively infill drilled and plans for a CO2 pilot project have been implemented. This mature reservoir with world class volumes of unrecovered oil has become the target of intensive reservoir characterization. Although more than 50 Spraberry publications are available, mostly from the 50's and 60's, there is no core-log correlation defining the actual net pay of Spraberry reservoir rock and there is very little core that has been preserved over the years. The most recent whole core data demonstrated that zones with comparable gamma-ray response could either be oil-saturated pay that was strongly fluorescent or non-pay that was weakly to non-fluorescent. Further investigation into the comparison between such zones led to the conclusion that dolomitic cement could completely occlude porosity in low clay/high silt zones which would otherwise appear as pay if only gamma-ray were considered. Obviously, porosity logs are necessary to distinguish between pay and non-pay in these zones that exhibit low gamma-ray response. In this paper, we have developed a log-based rock model utilizing petrophysical and geological data which distinguishes such zones. Calibration of open-hole gamma ray through cored intervals with porosity logs and cased-hole logs allows extrapolation of a porosity log where none is available. With this methodology, we are now able to map the extent and pinch-off the thin fractured layers of siltstone in which Spraberry reserves are found.

Introduction

Located in the Permian basin, the Spraberry Trend Area was once deemed "the largest uneconomic field in the world." With extensive natural fractures throughout the reservoir, Spraberry performance has confounded operators for 40 years with low recovery during primary recovery due to rapid pressure depletion, disappointing waterflood results and low ultimate recovery. Yet, the tremendous areal coverage and large amount of remaining oil warrant further investigation to expend all possible options before large numbers of Spraberry wellbores need to be plugged and abandoned (Schechter et al.). Identification and mapping of the thin pay zones that comprise Spraberry pay is an important first step when considering any IOR technique in the future.

On a lease basis, the pay sands are relatively easy to recognize yet correlation of pay sands throughout the Trend has not been attempted. Thousands of wells have been completed in the Spraberry Trend Area in the last 45 years. The logs run in many of these wells are old, cased-hole gamma-ray, sometimes with a porosity log and in many cases, a porosity log may not be available. We therefore need to develop methodology whereby pay zones can be distinguished in areas where 1) no core is available, 2) a porosity log may or may not be available and 3) perhaps the only logs available might be vintage, old cased-hole gamma-ray and neutron logs.

This paper will clearly show that true reservoir rock (primarily massive/clean siltstone) in the Spraberry Trend Area cannot be identified by gamma-ray response alone. We also provide (Banik & Schechter) simple methodology to calibrate old cased-hole neutron log (API or counts per second or even no units) into meaningful porosity logs. Finally, a rock model is presented which identifies essentially three rock types: P. 715^

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