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Xu, C., 2010, Porosity partitioning and permeability quantification in vuggy carbonates, Permian Basin, west Texas, U.S.A., in M. Poppelreiter, C. Garcia-Carballido, and M. Kraaijveld, eds., Dipmeter and borehole image log technology: AAPG Memoir 92, p. 309319.


Copyright copy2010 by The American Association of Petroleum Geologists.

Porosity Partitioning and Permeability Quantification in Vuggy Carbonates, Permian Basin, West Texas, U.S.A.

Chunming Xu1

1Shell International Exploration and Production, Woodcreek, Houston, Texas, U.S.A.


This chapter was modified from ldquoPorosity partitioning and permeability quantification in vuggy carbonates using wireline logs, Permian Basin, west Texasrdquo published in the Petrophysics Journal, Society of Petrophysicists and Well Log Analysts (SPWLA), v. 47, no. 1, p. 13–22. The author thanks ExxonMobil Production Company for the permission to publish these data. Special thanks go to Bill Newberry of Schlumberger for his contribution of the porosity partitioning analysis.


Using high-resolution Previous HitelectricalNext Hit borehole images and other open-hole log data in 13 wells, a case study was conducted to analyze the porosity and permeability heterogeneity in the Means field in the Permian Basin, west Texas. Because of negligible clay and other conductive minerals in the predominantly dolomitic rocks, the Previous HitelectricalNext Hit images are converted into microporosity maps of the boreholes using a modified Archie equation. The vug porosity is then partitioned from the total porosity by analyzing the porosity spectra around the boreholes in the sliding windows of 1-in. (2.5-cm)-thick interval. A practical workflow was also developed to compute a sonic vug-porosity index using the sonic, neutron, and density logs. The two vug porosities based on the independent measurements support each other in the Means field except that the sonic vug-porosity index has much lower resolution than the image-derived porosity. Through iterative experiments, a synthetic permeability model is established using the total porosity and vug-porosity logs. The core permeability in the vuggy dolomites varies exponentially with the product of the vug-porosity and vug-connectivity factor. Thin superpermeable vuggy zones below the resolution of the conventional logs are revealed by the Previous HitelectricalTop images and the permeability quantification. These superpermeable zones sandwiching thick oil-bearing reservoir rocks are the primary cause for the early high water cut and the bypassed oil. Integration of the continuous high-resolution permeability logs, the petrophysical facies from supervised neural network (SNN) processing, and the production data from both producers and injectors provide valuable insights to reservoir modeling.

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