Pore Network Heterogeneity in Tight Oil Reservoir Rocks— Analysis from 3D Confocal Laser Scanning Microscopy (CLSM)

Abstract

Visualizing and quantifying heterogeneity in pore networks is important for predicting reservoir performance in tight hydrocarbon reservoirs. However, it is difficult to capture the full extent of pore network heterogeneity and pore types with the visualization and quantification methods most commonly used, including micro-CT and FIB-SEM. Confocal Laser Scanning Microscopy (CLSM) has shown promise as a method to produce representative volumetric pore data from tight hydrocarbon reservoirs. Here we present results of a multi-basin confocal microscopy study to better visualize and quantify micropore networks in tight oil reservoir rocks, and to add to the understanding of reservoir behavior in these basins.

We used CLSM to generate non-destructive, reproducible, optical sections through rock samples down to a resolution limit of ~200 nm in the horizontal directions and ~300nm in the vertical direction in samples from a variety of major oil producing basins, including the Powder River, Williston, and Permian Basins.

3D visualization and quantification of pore networks shows a significantly heterogeneous pore network distribution in the reservoir samples included in this study. This heterogeneity was observed for pore scales ranging from the micron scale down to the optical resolution limit of CLSM. For example, average porosity from the Parkman Sandstone of the Powder River Basin was calculated at ~10% using CLSM, but micron-scale porosity varies between <2% and >30%. The large range of porosity heterogeneity is less pronounced in similar samples with higher permeability. For the Frontier Sandstone of the same basin, average porosity was calculated at ~8%, but the heterogeneity of porosity values only varied between ~6% and ~18%. These high-porosity zones are important in that they can create potential high-permeability fluid pathways. These might result in higher flows or induced fractures if stimulated correctly. Our calculated image data were independently confirmed by RCA permeability and porosity measurements of the samples.

Results from our study suggests that pore network anisotropy must be taken into consideration in tight oil sandstones and that commonly used pore characterization methods may not capture the full heterogeneity of pore networks. The results of this study can serve as input parameters for models and simulations of flow, and contribute to a better understanding of the heterogeneity of reservoir performance in tight oil basins.

AAPG Datapages/Search and Discovery Article #90350 © 2019 AAPG Annual Convention and Exhibition, San Antonio, Texas, May 19-22, 2019