Pore-Scale Characterization of Oil-Rich Monterey Shale: A Preliminary Study

Abstract

Summary URTeC 1582139 In recent years, both shale gas and shale oil have been predicted to potentially fill the increasing void between the growing demand and declining supply of conventional oil and gas, and are thus attracting a significant economic interest from the oil and gas industry. In unconventional oil-shales, the oil is thought to be trapped in the pores of these tight rocks at the sub-micron level. In order to extract this oil in a more economic and efficient manner, it is important to understand the pore-size distribution and the pore connectivity that dictate fluid flow and mass transfer at the sub-micron scale. Standard core analysis techniques are not always applicable to unconventional systems. Measurement of liquid permeability in tight pore systems is a very time consuming task, and when the aim is to extract e.g. oil-water relative permeability data, direct measurements become even more tedious. For characterizing pore throats as small as a few nanometers, mercury injection capillary pressure (MICP) experiments require pressures of up to 60,000 psi (or higher); material integrity under these high injection pressures is a key concern. In this work, we compare and discuss the insight and understanding about the pore structure characteristics of these complex rocks, specifically Monterey shale samples that can be obtained from various characterization techniques. The characterization techniques considered here include: (i) Mercury injection capillary pressure experiments (MICP), (ii) Brunauer, Emmett and Teller (BET) – Nitrogen adsorption experiments, (iii) High-Resolution X-ray CT (HRXCT), and (iv) Focused Ion Beam – Scanning Electron Microscopy (FIB/SEM). The HRXCT and FIB/SEM characterization data are utilized to reconstruct (visualize) the 3-D structures of these rocks; these are then used to calculate the permeabilities of these shale samples via LBM flow simulations. Our analysis of HRXCT data indicates that about one third of the sample porosity is represented by pores that are larger than 0.5μm. LBM flow simulations on the inter-connected pore structure indicate a permeability of about 1 mD, which is in good agreement with other experimental results (gas permeability measuremets). The pore size distribution calculated from the FIB/SEM images and the MICP experiments do not completely agree, however, which is likely due to the assumptions made in the analysis of MICP data and the limitations imposed by the image resolution. The BET analysis shows that the porosity from pores smaller than 45 nm (lower range of FIB-SEM resolution) is ~13% out a total porosity of ~40%. Since the rock matrix is shaly-silica, this porosity is believed to be clay porosity, which does not significantly contribute to flow in the presence of a connected siliceous pore structure. Furthermore, the calculated permeability from FIB/SEM images indicates that, for this type of rock, a resolution of 60 nm is good enough to capture the flow backbone of the shale matrix.