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AAPG Bulletin, V.
Prediction of lithofacies and reservoir quality using well logs, Late Cretaceous Williams Fork Formation, Mamm Creek field, Piceance Basin, Colorado
1Department of Geological Sciences, John A. and Katherine G. Jackson School of Geosciences, University of Texas at Austin, Austin, Texas 78712; present address: Shell International Exploration and Production, Bellaire Technology Center, P.O. Box. 481, Houston, Texas 77001; [email protected]
2Bill Barrett Corporation, Denver, Colorado 80202; [email protected]
3Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences, University of Texas at Austin, Austin, Texas 78713; [email protected]
4Bureau of Economic Geology, John A. and Katherine G. Jackson School of Geosciences, University of Texas at Austin, Austin, Texas 78713; [email protected]
Understanding the controls and distribution of reservoir quality is important for the economic success of tight-gas reservoirs in which diagenesis interacts with primary depositional variations in environment and texture to exert a strong control on pore networks, rock mechanical properties, and natural fractures. In the Upper Cretaceous Williams Fork Formation of the Piceance Basin, framework grain composition is a major control on compaction and the occurrence of authigenic phases. Alteration of volcanic grains in the upper Williams Fork led to grain-coating clay precipitation. Ferroan dolomite cement is found only in the deeper marine-influenced intervals in which dolostone fragments are present.
This study shows that careful petrographic assessment of lithofacies heterogeneity can be upscaled by correlation with log properties to yield tools for field-scale reservoir quality prediction. Twelve lithofacies are identified based on sand-grain populations, cement types, and clay matrix content. Sandstones of the highest reservoir quality are those with grain-coating clays that inhibit quartz cementation; these sandstones can be identified based on high-density porosity log values. Sandstones with the poorest reservoir qualities are tightly cemented with carbonate and quartz cement or are rich in clay matrix. Carbonate-cemented intervals are identified by low-density porosity. Clay matrix–rich samples have high gamma-ray and low-density porosity values. The presence of abundant potassium feldspar in the upper intervals results in high gamma-ray readings even in the clean (clay matrix–free) sandstone.
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