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The AAPG/Datapages Combined Publications Database
AAPG Bulletin
Abstract
(Begin page 149)
AAPG Bulletin, V.
Density
and mineralogy variations as a function of porosity in Miocene
Monterey Formation oil and gas reservoirs in California
Density and mineralogy variations as a function of porosity in Miocene
Monterey Formation oil and gas reservoirs in CaliforniaCaren Chaika,1 Loretta Ann Williams2
1Department of Geological and Environmental Sciences,
Stanford University, Stanford, California, 94305-2115; current address: Occidental of Elk
Hills, Inc., P. O. Box 1001, Tupman, California, 93276-1001; email: [email protected]
2Independent Consultant, 2354 Moline Street, Aurora, Colorado, 80010; email: [email protected]
AUTHORS
Caren Chaika received her B.A. degree in geology from Rice University in 1993 and her Ph.D. from Stanford University in 1998, where she combined geology and rock physics to better understand physical property changes during silica diagenesis. She has been a summer geologist for the Naval Research Laboratory at Stennis Space Center, Mississippi, and for the U.S. Geological Survey in Menlo Park, California. She is currently a production geologist with Occidental of Elk Hills, located near Bakersfield, California.
Loretta Ann Williams has specialized in fine-grained carbonate and silica source rocks that serve as reservoirs. A past Sproule Award recipient, she holds a B.S. degree from SUNY-Stony Brook, an M.B.A. degree from University of Denver, and a Ph.D. from Princeton University. She served as a Stanford University postdoctoral research affiliate from 1981 to 1983 and as an exploration geologist for Champlin Petroleum from 1984 to 1986. Her career has spanned exploration, production, and remediation consulting. She is with PARSEC Group in Denver, Colorado.
ACKNOWLEDGMENTS
We appreciate the time and effort that Jim Rogers and Mark Longman have
put into preparing this volume. We thank Mobil for core from South Belridge field and
Chevron for cores from Cymric, Asphalto, and McKittrick fields and for funding for
mineralogic analysis. The California State University at Bakersfield Core Repository
provided a Shell core from North Belridge field, and we are grateful to this valuable
facility, which would not have existed without the efforts of the late Vic Church. Loretta
Ann Williams dedicates her work in this article to his memory. Caren Chaika expresses her
gratitude to the Stanford Rock Physics Project for use of laboratory facilities, funding,
and equipment training, and she appreciates the guidance of Jack Dvorkin, J. G. Liou,
and Stephan Graham in her thesis project. We also thank Tony Reid and Jana McIntyre of
Occidental Petroleum for allowing us access to their data for Elk Hills field. We are
grateful for the work of John Compton and Caroline Isaacs, which supplied our coastal
California data. Finally, we are thankful for the work of the numerous investigators who
have studied the Monterey Formation, California tectonics, and oceanic upwelling systems
before us. Without the body of knowledge their work has provided, this article would not
have been possible. This work was supported by the Petroleum Research Fund of the American
Chemical Society Grant ACS-PRF #32743-AC2.
ABSTRACT
The Miocene Monterey Formation, long known as the critical source
rock in California, also includes significant fractured chert and porous diatomite
reservoirs. What is not widely recognized is that there are high matrix porosity
reservoirs within the opal-CT and quartz-phase rocks. Using density, porosity, and
mineralogy data, we have identified two distinct groups of Monterey Formation reservoirs.
group 1 porosity changes gradually during silica diagenesis--porosities of 55-70% exist
not only in opal-A-dominated samples but also in samples that have undergone the
transition from opal-A to opal-CT. In group 2, porosity decreases abruptly at the
transition, and rocks below the transition are tight.
The main mineralogic difference between groups 1 and 2 is a higher
clay content in group 1, resulting in different silica diagenesis pathways for the two
groups. This led us to expect all San Joaquin basin samples to fall into group 1, and all
coastal California samples to fall into group 2, because of the different depositional
histories of the two areas. Although our prediction holds in most instances, we discovered
that some San Joaquin basin samples exhibit group 2 characteristics. Therefore, it is
important to use petrophysical, seismic, and/or geological information to determine if a
Monterey Formation reservoir is likely to be a fracture-dominated type (group 2) or if
there might be a matrix production component (group 1).
Once one has made this diagnosis, the characteristic density/porosity
relationships of each group allow one to easily calculate an accurate matrix porosity.
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