Pore Microstructure and Fluid Distribution in a Diatomaceous Reservoir

Abstract

Abstract This study was undertaken to improve our understanding of fluid distribution and flow behavior by quantifying pore type, pore body size, shape attributes, and throat sizes of pore networks in diatomaceous reservoir rock. This work is a first step toward providing a means of integrating different measurement types and establishing an interpretive tool for understanding laboratory results and field behavior. This project lays the groundwork for developing a predictive tool that can be utilized to generate input for reservoir simulator studies. The pore microstructure of 11 diatomite samples from Lost Hills Field (Kern Co., CA) and one quarry sample was quantified using image analysis of photomicrographs collected with a Scanning Electron Microscope (SEM) in backscattered electron (BSE) mode. Six distinct pore types were identified ranging from small, irregularly shaped pores to large moldic and intraskeletal pores as well as large interconnected, intergranular pores. The throat size average and size range for each pore type was established by combining image analysis information with high-pressure mercury injection measurements. Once this relationship is determined, the pore body size and throat size serve as the basis for a predictive model allowing capillary pressure curves and fluid saturations to be calculated from pore type data. In this study, the relationship between pore types, fluid flow, and fluid distribution indicate a dual porosity system. Permeability is primarily controlled by three pore types, which represent 1 to 28% of the total core porosity and 0.67 to 9.75% of the total volume. Fluid saturation models were developed to provide an accurate means of calculating oil and water saturations as well as their distribution within the pore network for both the reservoir and core samples. From the model, we found that the most permeable pore types have oil saturations that are 5 to 35% lower than reservoir saturations. This indicates that the oil is moveable and can be swept from permeable pore types. Alternatively, there was no net change in saturations for the remaining pore types between core- and log-derived saturations. For these pore types, spontaneous imbibition is the most likely production mechanism. The smallest pore type is predominately water filled with oil saturation values of about 32% in both the reservoir and core samples. The proportion of each pore type can be predicted from wireline log data and used as input for the predictive capillary pressure model and fluid saturation models. This allows the models to be applied to the rest of the field providing data for field development decisions and simulator input.