Improved Kerogen Models for Determining Thermal Maturity and Hydrocarbon Potential of Shale

Chemical and Reactive Transport Processes Associated with Hydraulic Fracturing of Unconventional Oil/Gas Shales

Hydraulic fracturing of unconventional oil/gas shales has changed the energy landscape of the U.S. Recovery of hydrocarbons from tight, hydraulically fractured shales is a highly inefficient process, with estimated recoveries of <25% for natural gas and <5% for oil. This review focuses on the complex chemical interactions of additives in hydraulic fracturing fluid (HFF) with minerals and organic matter in oil/gas shales. These interactions are intended to increase hydrocarbon recovery by increasing porosities and permeabilities of tight shales. However, fluid-shale interactions result in the dissolution of shale minerals and the release and transport of chemical components. They also result in mineral precipitation in the shale matrix, which can reduce permeability, porosity, and hydrocarbon recovery. Competition between mineral dissolution and mineral precipitation processes influences the amounts of oil and gas recovered. We review the temporal/spatial origins and distribution of unconventional oil/gas shales from mudstones and shales, followed by discussion of their global and U.S. distributions and compositional differences from different U.S. sedimentary basins. We discuss the major types of chemical additives in HFF with their intended purposes, including drilling muds. Fracture distribution, porosity, permeability, and the identity and molecular-level speciation of minerals and organic matter in oil/gas shales throughout the hydraulic fracturing process are discussed. Also discussed are analysis methods used in characterizing oil/gas shales before and after hydraulic fracturing, including permeametry and porosimetry measurements, X-ray diffraction/Rietveld refinement, X-ray computed tomography, scanning/transmission electron microscopy, and laboratory- and synchrotron-based imaging/spectroscopic methods. Reactive transport and spatial scaling are discussed in some detail in order to relate fundamental molecular-scale processes to fluid transport. Our review concludes with a discussion of potential environmental impacts of hydraulic fracturing and important knowledge gaps that must be bridged to achieve improved mechanistic understanding of fluid transport in oil/gas shales.

Geochemical controls on CO2 interactions with deep subsurface shales: implications for geologic carbon sequestration

One of the primary drivers of global warming is the exponential increase in CO₂ emissions. According to IPCC, if the CO₂ emissions continue to increase at the current rate, global warming is likely to increase by 1.5 °C, above pre-industrial levels, between the years 2030 and 2052. Efficient and sustainable geologic CO₂ sequestration (GCS) offers one plausible solution for reducing CO₂ levels. The impermeable shale formations have traditionally served as good seals for reservoirs in which CO₂ has been injected for GCS. The rapid development of subsurface organic-rich shales for hydrocarbon recovery has opened up the possibility of utilizing these hydraulically fractured shale reservoirs as potential target reservoirs for GCS. However, to evaluate the GCS potential of different types of shales, we need to better understand the geochemical reactions at CO₂-fluid-shale interfaces and how they affect the flow and CO₂ storage permanence. In this review, we discuss the current state of knowledge on the interactions of CO₂ with shale fluids, minerals, and organic matter, and the impact of parameters such as pressure, temperature, and moisture content on these interactions. We also discuss the potential of using CO₂ as an alternate fracturing fluid, its role in enhanced shale gas recovery, and different geochemical tracers to identify whether CO₂ or brine migration occurred along a particular fluid transport pathway. Additionally, this review highlights the need for future studies to focus on determining (1) the contribution of CO₂ solubility and the impact of formation water chemistry on GCS, (2) the rates of dissolution/precipitation and sorption reactions, (3) the role of mineralogical and structural heterogeneities in shale, (4) differences in reaction mechanisms/rates between gaseous CO₂vs. brine mixed CO₂vs. supercritical CO₂, (5) the use of CO₂ as a fracturing fluid and its proppant carrying capacity and (6) the role of CO₂ in enhanced hydrocarbon recovery.

Understanding controls on the geochemistry of hydrocarbon produced waters from different basins across the US

The most massive waste stream generated by conventional and unconventional hydrocarbon exploration is the produced water (PW). The costs and environmental issues associated with the management and disposal of PW, which contains high concentrations of inorganic and organic pollutants, is one of the most challenging problems faced by the oil and gas industry. Many of the current strategies for the reuse and recycling of PW are inefficient because of varying water demand and the spatial and temporal variations in the chemical composition of PW. The chemical composition of PW is controlled by a multitude of factors and can vary significantly over time. This study aims to understand different parameters and processes that control the quality of PW generated from hydrocarbon-bearing formations by analyzing relationships between their major ion concentrations, O, H, and Sr isotopic composition. We selected PW data sets from three conventional (Trenton, Edwards, and Wilcox Formations) and four unconventional (Lance, Marcellus, Bakken, and Mesaverde Formations) oil and gas formations with varying lithology and depositional environment. Using comparative geochemical data analysis, we determined that the geochemical signature of PW is controlled by a complex interplay of several factors, including the original source of water (connate marine vs. non-marine), migration of the basinal fluids, the nature and degree of water-mineral-hydrocarbon interactions, water recharge, processes such as evaporation and ultrafiltration, and production techniques (conventional vs. unconventional). The development of efficient PW recycle and reuse strategies requires a holistic understanding of the geological and hydrological history of each formation to account for the temporal and spatial heterogeneities.

Effect of maturity and mineralogy on fluid-rock reactions in the Marcellus Shale

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 SO42- and PO43- 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.