CO₂ sequestration in shales is controlled by the intrinsic properties of shale and external factors shown in grey and green boxes, respectively. The adsorption capacity (orange box) is influenced by both intrinsic properties and external factors.

Natural gas extracted from tight shale formations, such as the Marcellus Shale, represents a significant and developing front in energy exploration. By fracturing these formations using pressurized fracturing fluid, previously unobtainable hydrocarbon reserves may be tapped. While pursuing this resource, hydraulic fracturing operations leave chemically complex fluids in the shale formation for at least two weeks. This provides a substantial opportunity for the hydraulic fracturing fluid (HFF) to react with the shale formation at reservoir temperature and pressure. In this study, we investigated the effects of the carbonates on shale-HFF reactions with a focus on the Marcellus Shale. We performed autoclave experiments at high temperature and pressure reservoir conditions using a carbonate-rich and a decarbonated or carbonate-free version of the same shale sample. We observed that carbonate minerals buffer the pH of the solution, which in turn prevents clay dissolution. Carbonate and bicarbonate ions also scavenge reactive oxidizing species (ROS), which prevents oxidation of shale organic matter and volatile organic compounds (VOCs). Carbonate-free samples also show higher pyrite dissolution compared to the carbonate-rich sample due to chelation reactions. This study demonstrates how carbonate minerals (keeping all other variables constant) affect shale-HFF reactions that can potentially impact porosity, microfracture integrity, and the release of heavy metals and volatile organic contaminants in the produced water.

Kerogen is the insoluble component of organic-rich shales that controls the type and amount of hydrocarbons generated in conventional and unconventional reservoirs. Significant progress has recently been made in developing structural models of kerogen. However, there is still a large gap in understanding the evolution of the molecular components of kerogen with thermal maturation and their hydrocarbon (HC) generative potential. Here, we determine the variations in different molecular fragments of kerogen from a Marcellus Shale maturity series (with VRo ranging from 0.8 to 3) using quantitative ¹³C MultiCP/MAS NMR and MultiCP NMR/DD (dipolar dephasing). These molecular variations provide insight into the (1) evolution of the molecular structure of kerogen with increasing thermal maturity and, (2) the primary molecular contributors to HC generation. Our results also indicate that old model equations based on structural parameters of kerogen underestimate the thermal maturity and overestimate the HC generation potential of Marcellus Shale samples. This could primarily be due to the fact that the kerogen samples used to reconstruct old models were mostly derived from immature shales (VRo <1) acquired from different basins with varying depositional environments. We utilized the kerogen molecular parameters determined from the Marcellus maturity series samples to develop improved models for determining thermal maturity and HC potential of Marcellus Shale. The models generated in this study could also potentially be applied to other shales of similar maturity range and paleo-depositional environments.

Natural gas extraction from the Appalachian Basin has significantly increased in the past decade. The push to properly dispose, reuse, or recycle the large amounts of produced fluids associated with hydraulic fracturing operations and design better fracturing fluids has necessitated a better understanding of the subsurface chemical reactions taking place during hydrocarbon extraction. Using autoclave reactors, this study mimics the conditions of deep subsurface shale reservoirs to observe the chemical evolution of fluids during the shut-in phase of hydraulic fracturing (HF), a period when hydraulic fracturing fluids (HFFs) remain confined in the reservoir. The experiment was conducted by combining a synthetic hydraulic fracturing fluid and powdered shale core samples in high temperature/pressure static autoclave reactors for 14 days. Shale samples of varying maturity and mineralogy were used to assess the effect of these variations on the proliferation of inorganic ions and low molecular weight volatile organic compounds (VOCs), mainly benzene, toluene, ethylbenzene and xylenes (BTEX) and monosubstituted carboxylic acids. Ion chromatography results indicate that the relative abundance of ions present was similar to that of water produced from HF operations in the Marcellus Shale basin. There was an increase of SO₄ ²⁻ and PO₄ ³⁻ and a decrease in Ba²⁺ upon fluid-shale reaction. Major ionic shifts indicate calcite dissolution in two of the fluid-shale reactions and barite precipitation in all fluid-shale reactions. Toluene, xylene, and carboxylic acids were produced in the shale-free control experiment. The most substantial increase in BTEX analytes was observed in reactions with low maturity shale, while the high maturity shale reaction produced no measurable BTEX compounds. Total organic carbon decreased in all reactions including fracturing fluid and shale, suggesting adsorption onto the organic matter (OM) matrix. The results from this study highlight that both the nature of OM and mineralogy play a key role in determining the fate of inorganic and organic compounds during fluid–shale interactions in the subsurface shale reservoir. Overall this study aims to contribute to the growing understanding of complex chemical interactions that occur in the shale reservoirs during HF, which is vital for determining the potential environmental impacts of HF and designing more efficient HFF and produced water recycling techniques for environmentally conscious natural gas production.

It is generally accepted that in mature shales, biomarkers and pyrolysis proxies are not very helpful in understanding the source/type of organic matter (OM), paleo-redox conditions during deposition, and thermal maturity. This study was to test the efficacy of these proxies in mature Marcellus Shale (VRo > 1). Samples were collected from oil-prone (WV-7) and gas-prone (WV-6) wells in Wetzel and Monongalia Counties, West Virginia, respectively. These wells were chosen for this test study because high-resolution geochemical and isotopic studies have previously been conducted on these cores and a depositional model had been proposed. The model suggests that sediments in WV-6 well were more mature, received higher terrestrial OM influx and were deposited in less anoxic environment as compared to those in WV-7 well. We used an improved method to extract a small amount of biomarkers preserved in the samples. Further, the extracts were analyzed by a high-resolution GC × GC-FID method to quantify the distribution of aliphatic biomarkers. The hydrogen and oxygen indices (HI vs. OI plot) determined by Source Rock Analysis could not be used to determine the kerogen type due to their very low values. However, interpretations were derived from S1 vs. S2 and S2/S3 vs. TOC cross plots, thermal maturity parameter (Tmax), fraction conversion of OM to hydrocarbon (HC), and residual carbon/pyrolyzable carbon (RC/PC) ratio. The conclusions drawn from the biomarkers and SRA data are in agreement with the HC production data from these wells as well as interpretations derived from geochemical and isotopic studies conducted on these cores. Therefore, we propose that despite some limitations, biomarker and pyrolysis proxies can be used to determine the thermal and depositional history of mature shales like the Marcellus Shale.