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The AAPG/Datapages Combined Publications Database
AAPG Bulletin
Abstract
AAPG Bulletin, V.
David
K. Davies,2
Richard K. Vessell,2 James E. Kamis,3 and William
H. Dixon
1Petroleum Consultant, 1511 18th Avenue East, Seattle, Washington
98112; e-mail: [email protected]
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.
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.
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.
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