--> ABSTRACT: Use of Integrated Reservoir Description in Upper Wolfcampian Carbonate, Midland Farms Deep Unit, Andrews County, Texas--Example of Effective Teamwork, by Barbara A. Lanan and David C. Lenig; #91022 (1989)

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Use of Integrated Reservoir Description in Upper Wolfcampian Carbonate, Midland Farms Deep Unit, Andrews County, Texas--Example of Effective Teamwork

Barbara A. Lanan, David C. Lenig

A cooperative geological-engineering evaluation of cores, core data, well logs, and production data made it possible to rapidly determine net pay limits, calculate original oil in place and recovery factors, and formulate reservoir development plans. The resulting detailed reservoir description and performance characterization of upper Wolfcampian fossiliferous and oolitic limestones were used successfully to optimize an existing waterflood operation and to initiate an additional water-flood program. Geologic input consisted of (1) identifying lithostratigraphic zones in cores that are also recognizable on well logs, (2) interpreting depositional environments, (3) documenting the origins and vertical distribution of pore types, and (4) identifying and correlating individual reservoir units. Engineering input consisted of (1) identifying the productive strata, (2) determining net pay criteria, and (3) mapping net pay.

The upper Wolfcampian section in the Midland Farms deep unit consists of an unconformity-bound shelf-margin sequence (zone I) which can be subdivided into five correlative lithofacies, including platform-edge carbonate sandstones (subzones A, B, and C); downslope, low-relief, Tubiphytes-phylloid algae-rich mounds (subzone D); and foreslope talus (subzone E). Subzones A, B, and C each represent a shoaling-upward cycle. The best reservoir pore systems are developed in the skeletal and ooid grainstones of the platform-edge sandstones and consist of oomoldic, intergranular, and dissolution-enhanced intergranular porosity. Vertical segregation of the three dominant pore types makes possible further subdivision into five mappable reservoir units (A1, A2, B, C1, and C2). Net pay in these res rvoir units is determined from (1) log porosity pay cutoffs established by comparing core porosities to fluid saturations in cores and (2) current oil-water contacts indicated by selective tests. Subsequent mapping of net pay made it possible to optimize reservoir potential through additional waterflood development/expansion and to establish the framework for future reservoir simulation studies.

AAPG Search and Discovery Article #91022©1989 AAPG Annual Convention, April 23-26, 1989, San Antonio, Texas.