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AAPG Bulletin, V. 83 (1999), No. 1 (January 1999), P. 19-42.

Modeling a Vuggy Carbonate Reservoir, McElroy Field, West Texas1

Kaveh Dehghani,2 Previous HitPaulTop M. (Mitch) Harris,2 Kelly A. Edwards,3 and William T. Dees3
 

©Copyright 1999.  The American Association of Petroleum Geologists.  All Rights Reserved
 

1Manuscript received July 15, 1997; revised manuscript received April 27, 1998; final acceptance May 27, 1998.
2Chevron Petroleum Technology Company, 1300 Beach Boulevard, La Habra, California 90631-6374; e-mail: [email protected]; [email protected]
3Chevron North America Production Company, 15 Smith Road, Claydesta Plaza, Midland, Texas 79705; e-mail: [email protected]; [email protected]

Many of our co-workers at Chevron provided input at various stages in our work. We are especially grateful to Minhtrang Doan for conducting some of the simulation runs; Ed Donovan for SEM photos and thin section preparation; Leon Roe, Robert Meyer, Robert Ehrlich, and Alan Bernath for their help and constructive comments. Chevron Petroleum Technology Company and Chevron North America Exploration and Production Company gave permission to publish.

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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