AAPG Bulletin, V. 82 (1998), No. 11 (November 1998), P. 1985-2002.

Permian Clear Fork Group, North Robertson Unit: Integrated Reservoir Management and Characterization for Infill Drilling, Part II-Petrophysical and Engineering Data 

Scott L. Montgomery,¹ David K. Davies,² Richard K. Vessell,² James E. Kamis,³ and William H. Dixon⁴

©Copyright 1998.  The American Association of Petroleum Geologists.  All Rights Reserved

¹Petroleum Consultant, 1511 18th Avenue East, Seattle, Washington 98112; e-mail: [email protected]
²David K. Davies & Associates, Inc., 1410 Stonehollow Drive, Kingwood, Texas 77339.
³BTA Oil Producers, 600 17th St., Suite 2230 South, Denver, Colorado 80202.
⁴Fina Oil and Chemical, 14950 Forest Pkwy., Suite 300, Houston, Texas 77205.

Grateful acknowledgment is offered to the following individuals for their support and information relevant to the writing of this paper: Jerry Nevans, Fina Oil and Gas, and Ken McGee, David K. Davies and Associates.

Gratitude is also expressed toward the following reviewers who helped improve the quality of this article: S. J. Mazzullo, Wichita State University, and Neil Hurley, Colorado School of Mines. 

ABSTRACT

Located in the Permian basin of west Texas, North Robertson unit (NRU) produces from highly heterogeneous carbonate reservoirs of the Permian (Leonardian) Clear Fork Group and lowermost Glorieta Formation. Discovered in 1955, the productive area encompasses 5366 ac (2173 ha) along the northern border of the Central Basin platform and contains an estimated 262 MMbbl original oil in place (OOIP). Total recovery from the unit, including 30 yr of primary production and 10 yr of waterflood production, is only 10.1% OOIP. A recent integrated reservoir characterization effort in NRU suggests that previous recovery efforts were inadequate to achieve maximum production from the reservoir. Analysis of petrophysical properties in the Clear Fork has allowed for pore-level modeling, leading to identifying rock types and delineating flow units. Maps constructed of various reservoir parameters, including OOIP, primary and secondary ultimate recovery, and flow capacity, were compared with rock-type distribution within individual flow units and the results of reservoir simulation to estimate portions of the unit suitable for targeted 10-ac (4-ha) infill development. Related data also suggested the importance of completion techniques in helping improve conformity between producers and injection intervals in pay intervals in nearby wells. Results of 14 producing wells and 4 injector wells drilled on the basis of the new reservoir model and improved completion techniques were impressive and confirmed the value of using such an approach to optimize the economics and production of infill development in such a complex reservoir.