Miocene Monterey Formation reservoirs of California contain unique reservoir rocks and additional complexity from fractures. The rocks contain a high proportion of biogenic silica derived from diatoms. Porcelanite, chert, and siliceous shale, along with dolomite, are the primary reservoir rocks of these fine-grained siliceous reservoirs. Strata are typically thinly-bedded and heterogeneous, and are difficult to adequately describe using standard reservoir characterization techniques. Our approach focuses on opal CT and quartz-phase rocks, and relies on an integration of tools to characterize both the matrix and the fractures. We attempt to quantify rock and reservoir properties, and examine the controls these factors exert on reservoir performance with field examples from Hondo (offshore), offshore Santa Maria, Elk Hills, and North Shafter.

Matrix properties are affected by two primary factors, the ratio of silica to fine-grained detritus (mostly clay), and the silica phase of the rocks. The best matrix properties are found in quartz-phase porcelanite with low clay content. Rocks with higher clay volumes, or those with a high proportion of opal CT silica, have smaller pore throats, lower oil saturation, and lower permeability. In most cases, well-log techniques relying on porosity logs and spectral gamma ray logs successfully predict the clay volume and silica phase of rocks in the subsurface.

Fractures are common in nearly all Monterey Formation reservoirs. Fracture distribution is controlled by mechanical stratigraphy and structural position. Cores and outcrops have traditionally supplied data and analogs for fracture characterization. This data set has been vastly expanded by the use of borehole image logs, particularly from horizontal wells. Organizing fracture data using a fracture network model enhances our predictive capability for fracture distribution and the ability to visualize likely flow paths in the reservoir.

Fluid properties are also an important factor influencing Monterey reservoir behavior. Low-gravity, high-viscosity oils are generated by high-sulfur Monterey source facies, and are difficult to produce economically even from some reservoirs with excellent matrix and fracture properties. Knowledge of source facies distribution, burial history, and generation kinetics is needed to predict the hydrocarbon properties of Monterey reservoirs.