Characterizing Pore-Scale Geochemical Alterations in Eagle Ford and Barnett Shale from Exposure to Hydraulic Fracturing Fluid and CO2/H2O

• Published in: Energy & fuels Vol. 35; no. 1
• Main Authors: Sanguinito, Sean, Cvetic, Patricia, Goodman, Angela, Kutchko, Barbara, Natesakhawat, Sittichai
• Format: Journal Article
• Language: English
• Published: United States American Chemical Society (ACS) 12-12-2020
• Subjects: 04 OIL SHALES AND TAR SANDS; clays; CO2 storage; ENVIRONMENTAL SCIENCES; fluids; fracturing fluid; GEOSCIENCES; petrophysical; pyrites; shale
• ISSN: 0887-0624; 1520-5029

As demand increases for an affordable energy source that is tied to an environmental obligation to reduce greenhouse gas emissions and water usage, there is a growing consideration in shale production utilizing processes such as 1) enhancing hydrocarbon recovery via carbon dioxide (CO2) flooding, 2) using CO2 as a fracturing agent to minimize water use, and 3) storing CO2 in depleted shale formations to mitigate emissions to the atmosphere. Understanding the geochemical reactions and alterations that occur as shale is exposed to fluids and CO2 is necessary to develop and optimize each of these processes for field applications. While the majority of shale formations are stimulated using traditional fracturing fluid, some may be fractured using CO2 or other non-traditional means. We examine the effect fracturing fluid has on shale and how it behaves with secondary exposure to dry CO2 or CO2-saturated water using in situ Fourier Transform infrared spectroscopy (FTIR), feature relocation scanning electron microscopy (SEM), and surface area and pore size analysis using volumetric gas sorption. These techniques were performed on Eagle Ford and Barnett shale samples that were exposed to fracturing fluid and unexposed (as received). Shales that have been exposed to traditional fracturing fluid experienced two reaction fronts. The first reaction front was formed during exposure to the fracturing fluid (pH of ~1.4). A secondary reaction front was formed as a result of CO2-saturated fluid exposure in the form of carbonic acid (pH ~5.6). These two different reaction mechanisms drove multiple dissolution and precipitation cycles which altered petrophysical properties of the shale and could lead to a significant impact on flow pathways. FTIR showed that equilibration of carbonate dissolution and precipitation cycles could take as long as 35 days. Samples exposed to fracturing fluid showed significantly less carbonate reactivity compared to those exposed to water. Pore size analysis results indicate exposure to fracturing fluid blocked small nanopores (10-15 nm) reducing BET surface area and total pore volume. SEM results show barite precipitated heavily during exposure to fracturing fluid. It appeared that carbonic acid was able to extract sulfur from organic matter to form gypsum evaporites. The mineralogical (barite precipitation and calcite dissolution/precipitation) and pore-scale alterations observed in these samples may lead to enhancement of flow pathways for injected CO2 or produced hydrocarbons.