Abstract

The McElroy field produces approximately 17,000 BOPD (barrels of oil per day) under a mature waterflood from the Permian Grayburg Formation. The main pay zone in the reservoir is primarily peloidal dolograinstones/packstones with interparticle/intercrystalline porosities. The central portion of the field is more heterogeneous because of thin high-porosity and high-permeability vuggy zones. The occurrence of these zones is confirmed by core description and measurements, porosity logs, tracer studies, and injectivity measurements. These thin high-porosity and high-permeability vuggy zones diminish waterflood effectiveness and leave millions of barrels of bypassed oil in the lower permeability matrix. A method was developed to identify the vuggy zones on logs, create geostatistical models of porosity and permeability incorporating the vuggy zones, and characterize them in simulation models. The methodology involved the following: (1) developing a log trace to identify zones of high secondary porosity, mainly vuggy porosity, in the area of the field that was modeled, (2) creating a detailed geostatistical model (1 million cells) of total porosity using well-log data, (3) creating a geostatistical permeability model based on total porosity, (4) creating a separate detailed geostatistical model of secondary porosity, and (5) superimposing exceptionally high permeability in areas of the permeability model defined by high secondary porosities. The detailed permeability models were scaled-up to 12,000-cell models for simulation studies. The models incorporating vuggy permeability distributions showed a far superior history match of primary and waterflood processes than did models that did not incorporate vuggy permeability; these models also showed good-quality history matches for individual wells. Successful history matching of the simulation models validates our method and indicates that core data underestimate the permeability of vuggy zones due to sampling and measurement issues.

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