Caren J. Chaika1, Loretta Ann Williams2
(1) Occidental of Elk Hills, Tupman, CA
(2) PARSEC Group, Aurora, CA
ABSTRACT: Density and Mineralogy Variations as a Function of Porosity in Miocene Monterey Formation Oil and Gas Reservoirs in California
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. While 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 allows one to easily calculated an accurate matrix porosity. Our method avoids theoretically unsound assumptions inherent in standard porosity estimation techniques.
AAPG Search and Discovery Article #90906©2001 AAPG Annual Convention, Denver, Colorado