SPE 144050 Submicron-Pore Characterization of Shale Gas Plays

Gas storage and flow behavior in the shale gas rocks are complex and hard to identify by conventional core analysis. This study integrates clustering analysis techniques from material science, petrophysics, and petrology to characterize North American shale gas samples from Utica, Haynesville, and Fayetteville shale gas plays. High pressure (up to 60,000 psi) mercury porosimetry analysis (MICP) determined the pore size distributions. A robust, detailed tomography procedure using a dual-beam (Scanning Electron Microscope and Focused Ion Beam, also called SEM-FIB) instrument successfully characterized the submicron-pore structures. SEM images revealed various types of porosities. Pores on a scale of nanometers were found in organic matter; they occupy 40−50% of the kerogen body. Two-hundred two-dimensional SEM images were collected and stacked to reconstruct the original pore structure in a three-dimensional model. The model provided insights into the petrophysical properties of shale gas, including pore size distribution, porosity, tortuosity, and anisotropy. This paper presents the pore model constructed from Fayetteville shale sample. The work used X-ray diffraction (XRD) to semi-quantify shale gas clay and non-clay minerals. The Haynesville and Utica (Indian Castle formation) shale samples have a high illite content. The Utica (Dolgeville formation) shale samples show high calcium carbonate (calcite) content. Moreover, wettability tests were performed on the shale samples, and the effect of various fracturing fluid additives on their wettability was tested. Most additives made the shale gas surfaces hydrophilic-like (water-wet). Introduction Unconventional natural gas resources have grown in importance as a complement to conventional fossil fuels as world energy demand has increased. Shale gas is the second largest unconventional energy resource after heavy oil. Recently, the United States Geological Survey (USGS) estimated that tight sands and gas shale in the United States may hold up to 460 Tcf of gas. There are about 200,000 unconventional gas wells in low-permeability sands, coal-bed methane deposits, and shale gas in the lower 48 states. Shale gas is more environmentally friendly and attractive compared to other energy resources due to its ecological advantages (low levels of carbon dioxide CO2 emission) and safety qualities (insignificant sulfur dioxide contents, H2S%). Many petrophysical properties of the unconventional tight gas formations are significantly different from those of conventional reservoirs. In particular, such formations have nano-scale pores and channels, a unique pore structure, and the unusual wettability, transport, and storage properties. These differences produce the fluid flow mechanisms different from those in conventional gas plays, especially when the size of the pore throats differs from the size of the saturating fluid molecules by only slightly more than one order of magnitude. Despite the practical importance of this topic, very little is known about it. Commercial production from extremely low permeability gas reservoirs requires hydraulic fracturing stimulation at the beginning of well production. Proper selection of a fracturing fluid is key to successful stimulation. Currently, selection of hydraulic fracturing fluids for unconventional gas wells borrows from conventional oil and gas techniques. However, shale gas plays have unique properties. For example, the size of the pore throats in shale may differ from the size of the saturating fluid molecules by only slightly more than one order of magnitude. The physics of the fluid flow in these rocks, with permeabilities in the nanodarcy range, is poorly understood.