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Abstract
Rick
Sarg
2004. The American Association of Petroleum Geologists. All rights reserved.
Three-Dimensional Seismic Attributes Help Define Controls on Reservoir Development: Case Study from the Red River Formation, Williston Basin
R. A. Pearson,1 B. S. Hart2
1New Mexico Institute of Mining and Technology, Socorro, New Mexico, U.S.A.; Present address: Anadarko Petroleum Corporation, The Woodlands, Texas, U.S.A.
2New Mexico Bureau of Mines and Mineral Resources, Socorro, New Mexico, U.S.A.; Present address: Earth and Planetary Sciences, McGill University, Montreal, Qubec, Canada.
ACKNOWLEDGMENTS
Funding for this project was provided by Los Alamos National Laboratory through their Advanced Reservoir Management Project. Data and local knowledge of the Red River Formation were supplied by Flying J Oil Company. Software was provided by Landmark Graphics Corporation and Hampson-Russell Software Services. We thank these organizations and companies for their support and Guido Bracco Gartner, Gregor Eberli, and an anonymous reviewer for their suggestions that helped improve the focus of this chapter.
ABSTRACT
The use of three-dimensional (3-D) seismic attributes to predict reservoir properties is becoming widespread in many areas. One of the most underutilized aspects of the methodology is that the property-prediction maps
can help geoscientists understand depositional and postdepositional controls on reservoir development. We illustrate this point via a case study that examines partially dolomitized, restricted to open-marine carbonates of the Ordovician Red River Formation in the Williston Basin. We tied log and seismic data, mapped key reflection events in the 3-D seismic volume, calculated the porosity thickness (thickness
sonic porosity) for the porous zone, and then correlated those data with 21 attributes. We derived a relationship between two attributes (the spectral slope from peak to maximum frequency and the ratio of positive to negative samples) and porosity thickness that yielded a 0.88 correlation coefficient between predicted and actual values. This relationship was used to predict the porosity thickness throughout the 3-D seismic area. The resulting porosity distribution shows (1) good porosity development along the flanks of structures that are associated with visible faulting or steep dips at the underlying Winnipeg level, (2) thin (
17
28 ft [
5
8.5 m]) porous zones throughout much of the field, (3) a large, off-structure porosity zone in an area without well control, and (4) small, irregularly distributed porous zones (most likely the result of noise and/or error in the predictive relationship). In areas where faults and flexures are associated with enhanced porosity development, the slope of spectral frequency attribute may be responding to fractures, with more rapid attenuation of high frequencies occurring in these areas. These observations support a diagenetic model where faults and fractures acted locally as preferential pathways for dolomitizing fluids. Away from these zones, the porosity distribution shows some porosity thickness over the entire area that is consistent to drillstem test data that shows depleted pressures in wells drilled in the early 1990s on otherwise isolated structures.
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