AAPG Bulletin, V. 83 (1999), No. 7 P. 1031-1056.

A Predictive Model for Reservoir Distribution in the Permian (Leonardian) Clear Fork and Glorieta Formations, Robertson Field Area, West Texas¹

Stacy C. Atchley,² Michael G. Kozar,³ and Lyndon A. Yose⁴

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

¹Manuscript received April 20, 1998; revised manuscript received January 25, 1999; final acceptance February 18, 1999.
²Baylor University, Department of Geology, Waco, Texas 76798-7354; e-mail: [email protected]
³Exxon Exploration Company, P.O. Box 4778, Houston, Texas 77210-4778.
⁴Exxon Production Research Company, P.O. Box 2189, Houston, Texas 77252-2189.
 

This manuscript summarizes applied research completed by an integrated team of geoscientists and reservoir engineers. Additional team members included R. J. Amstadt, A. J. Coker, M. G. Gorski, P. A. Larabee, M. W. Longtine, P. A. Merkley, P. Morales, and M. W. Roffal. We thank Exxon Company, U.S.A., and Exxon Production Research Company for sponsorship and permission to publish. Logistical support was provided by Dale Harris, Lisa Moore, Edward Perez, Glenda Taylor, and Riva Whiteside. Technical support was provided by Dave Cantrell, Brian Reid, and Kevin Silva. Special thanks are extended to Joe Sinner and Leslie Harman of ARCO Permian, Joe Walker of Santa Fe Resources, and Scott Germann of Nadel and Gussman Permian for assistance in compiling production statistics from wells recently drilled at North Jenkins field. 

ABSTRACT

Through the collaborative efforts of a multidisciplinary team, various subsurface data types have been integrated to produce a conceptual geologic model for reservoir prediction within the upper Clear Fork and Glorieta formations of the Robertson field area, west Texas. Detailed description of 1434 m of core, 109 thin sections, and 241 line-kilometers of 2-D (two-dimensional) seismic indicates the stratigraphic interval accumulated as a progradational succession of platform-interior subtidal and intertidal facies. Reservoir intervals preferentially occur within subtidal facies having intercrystalline porosity associated with replacement by coarsely crystalline dolomite. Intertidal facies were replaced by a finely crystalline phase of fabric-preserving dolomite and are dominated by an ineffective fenestral pore system.

Facies and reservoir distribution is largely controlled by antecedent topography. Structural highs generated during the terminal phase of Ouachita-Marathon compression were the preferred site of intertidal facies deposition. Adjacent structural lows have a higher proportion of reservoir-prone subtidal facies. Analysis of compensated-neutron log porosity indicates that subtidal-prone intervals may be broadly characterized as having less than 11% porosity, whereas intertidal-prone intervals generally exceed 11% porosity. From this observation, a simple computer algorithm allows facies interpretation within wells lacking core. Intertidal-subtidal facies ratio maps generated from this algorithm closely match the distribution of pre-Wolfcampian structural elements and present-day structure. Intertidal facies are more common across the crest of structural highs.

Future drilling in the North Jenkins area should pursue structural-flank positions where subtidal facies are volumetrically more abundant. Care should be taken, however, to avoid completions below the composite oil-water contact. Subtidal facies are compartmentalized within individual sequences of a progradational sequence set. Progradational stacking and compactional drape over deeper structures produces discrete flow units with potentially independent oil-water contacts.