Porosity and permeability heterogeneity in vuggy carbonate reservoirs is quantified through an optimized workflow of borehole image and conventional log processing with calibration to core data. In a pilot study, 13 wells in the Means oil field of the Permian Basin, West Texas, were analyzed to determine the porosity and permeability relationships in the Permian Queen, Grayburg, and San Andres formations. In different vuggy zones of San Andres at similar total porosity of about 8%, permeability varies by 2 to 3 orders of magnitude. This variation was modeled by an exponential relationship between permeability and the vuggy porosity partitioned from borehole image processing. A methodology is shown for estimating the vuggy porosity index using a modified sonic porosity analysis. Permeability estimation using both the vug porosity partitioning from borehole image logs and the vuggy porosity index from conventional logs provides thief-zone identification for optimized well completion. In the San Andres Formation, vugs developed in thin zones and resulted in layer-cake structures of thin superpermeable zones sandwiching the thicker nonvuggy zones with bypassed oil. The averaged conventional log porosity in the thin zones below log resolution resulted in an erroneous permeability profile because of the exponential vug porosity and permeability relationship. Similarly, the thin-bedded Grayburg siliciclastics and dolomites, which were generally thought to be poor reservoirs in this field, exhibit significant vertical porosity and permeability variation. Petrophysical rock types were identified from images and conventional logs through neural network processing. Integration of these log-derived permeability and rock types together with production data provided the basis for interwell heterogeneity prediction and fieldwide completion strategies.

This content is only available via PDF.
You can access this article if you purchase or spend a download.