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At least 19 records
All sourcesNASA NTRSDOE OSTI
DOE OSTI2021

Compositional Control on Shale Pore Structure Characteristics across a Maturation Gradient: Insights from the Devonian New Albany Shale and Marcellus Shale in the Eastern United States

The pore structure characteristics of shales are controlled by their mineralogical and organic matter (OM) composition. However, the contributions by different components in shales at varying thermal maturities remain poorly understood. In this study, Devonian New Albany Shale and Marcellus Shale samples spanning a thermal maturity from marginally mature (vitrinite reflectance R o 0.55%) to post-mature (R o 2.41 %) were selected to study the control of composition on the pore structure properties of shales at different stages of thermal maturation. Scanning electron microscope (SEM) imaging was used to examine pore types in shales, and low-pressure N 2 and CO 2 adsorption analyses were used to quantitatively characterize the mesopore and micropore characteristics of bulk shales and major components in shales. The results show that matrix-associated pores including interparticle pores between silt-sized mineral grains, phyllosilicate framework pores, and intraparticle pores within mineral grains exist in all samples but become less common with increasing maturity, which is likely caused by elevated compaction, cementation, and occlusion with bitumen. Secondary organic pores were not observed under SEM at marginal maturity but were detected in the condensate–wet gas and dry gas windows, with more organic pores in the dry gas window. At marginal maturity, OM has large amounts of mesopores and micropores as demonstrated by low-pressure N 2 and CO 2 adsorption analyses of OM isolated from shales, even though no OM-hosted pores were observed under SEM. With increasing thermal maturity, the mesopore and micropore specific surface area of OM increase and make greater contributions to the pore structure properties of bulk shales. The mesopore and micropore properties of shales are controlled by OM content and maturity as well as by clay mineral type and content, and they can be estimated from the contribution of each component at different stages of thermal maturation. In conclusion, accurate evaluation of the pore volume and SSA of shales will have important implications for assessing gas adsorption and transport in shales.

03 NATURAL GAS↗
DOE OSTI2021

Effects of Carbonate Minerals on Shale-Hydraulic Fracturing Fluid Interactions in the Marcellus Shale

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.

58 GEOSCIENCES↗
DOE OSTI2021

Convergence of micro-geochemistry and micro-geomechanics towards understanding proppant shale rock interaction: A Caney shale case study in southern Oklahoma, USA

As a direct outcome of economic development coupled with an increase in population, global energy demand will continue to rise in the coming decades. Although renewable energy sources are increasingly investigated for optimal production, the immediate needs require focus on energy sources that are currently available and reliable, with a minimal environmental impact; the efficient exploration and production of unconventional hydrocarbon resources is bridging the energy needs and energy aspirations, during the current energy transition period. The main challenges are related to the accurate quantification of the critical rock properties that influence production, their heterogeneity and the multiscale driven physico-chemical nature of rock–fluid interactions. A key feature of shale reservoirs is their low permeability due to dominating nanoporosity of the clay-rich matrix. As a means of producing these reservoirs in a cost-effective manner, a prerequisite is creation of hydraulic fracture networks capable of the highest level of continued conductivity. Fracturing fluid chemical design, formation brine geochemical composition, and rock mineralogy all contribute to swelling-induced conductivity damage. The Caney Shale is an organic-rich, often calcareous mudrock. Many studies have examined the impact that clay has on different kinds of shale productivity but there is currently no data reported on the Caney Shale in relation to horizontal drilling; all reported data on the Caney Shale is on vertical wells which are shallow, compared to an emerging play that is at double the depth. Here, in this work we develop geochemical–geomechanical integration of rock properties at micro-and nanoscales that can provide insights into the potential proppant embedment and its mitigation. The novel methodology amalgamates the following: computed X-ray tomography, scanning electron microscopy, energy dispersive spectroscopy, micro-indentation, and Raman spectroscopy techniques. Here, our results show that due to the multiscale heterogeneity in the Caney Shale, these geochemical and structural properties translate into a variation in mechanical properties that will impact interaction between the proppant and the host shale rock.

03 NATURAL GAS↗
DOE OSTI2022

Impact of Concurrent Solubilization and Fines Migration on Fracture Aperture Growth in Shales during Acidized Brine Injection

Acidic hydraulic fracturing fluid chemically and physically alters shale rock fabric during injection and shut-in, creating a “reaction-altered zone” along the fracture faces. To better characterize the variable thickness and composition of this reaction-altered zone under advective flow, we take a coupled experimental and modeling approach. A fluidic cell, with six fiducial markers, is first fabricated to keep the rock sample in place during the core floods and to allow image alignment of acquired images. Then, we conduct a series of reactive core floods in a clay-rich siliceous Wolfcamp shale sample with 10 wt % carbonate, using a synthetic fracturing fluid under no confining stress and at room temperature. High-resolution computed tomography (CT) scans are periodically conducted to observe the spatial alteration of the fracture network. We then perform scanning electron microscopy (SEM-EDS) on the two orthogonal surfaces (fracture surface and freshly cut profile face) to generate high-resolution elemental maps that show the change in mineralogy, both with distance along a given flow path along a fracture surface and with depth from the fracture surface into the shale matrix. These results are contrasted against a two-dimensional (2D) advection-diffusion reaction model developed previously for batch reactions between shale and synthetic fracturing fluids. The model simulates the geochemical interaction occurring at the fracture/matrix interface and penetrating into the shale matrix during the reactive core flood. Both model and experimental results show that the acidic brine is neutralized during the core flood, corresponding to an increase in fracture aperture as a function of fluid volume injected with the greatest change near the inlet. SEM-EDS scans reveal significant dissolution of carbonates on the fracture surface without pyrite oxidation. The reactive transport model indicates that carbonate depletion into the shale interior should be observable, yet SEM-EDS shows no discernible loss of carbonate in the orthogonal profile face. The combination of these observations suggests an additional fracture evolution mechanism in the reactive system, i.e., fines migration. We show that fines migration enhances the access of fracturing fluid to the matrix resulting in a more pronounced fracture widening. Finally, we conclude that coupled mineral dissolution and fines migration govern fracture aperture growth during acidized brine injection. In this work, we effectively show the underlying risk of relying solely on models that do not include an important (transport) process that can alter the system significantly and propose a combined chemomechanical mechanism for fracture evolution appropriate for this shale mineralogy.

58 GEOSCIENCES↗
DOE OSTI2023

Developing Methods to Assess Changes in Mechanical Properties of Shale Modified by Engineered Mineral Precipitation

Fractures in subsurface shale formations serve multiple purposes, for example, in the recovery of resources in hydraulic fracturing or as potential harmful leakage passages through caprocks that may contribute undesired fluids to the atmosphere or functional groundwater aquifers. A proposed method to seal or influence fracture properties is Ureolysis-Induced Calcium Carbonate Precipitation (UICP), a bio-mineralization technology driven by the enzymatic hydrolysis of urea, resulting in the formation of calcium carbonate. The resulting calcium carbonate can bridge the gaps in fractured shale and reduce fluid flow through fractures. This study represents the first step toward determining the influence of UICP treatment on shale material and its subsequent mechanical strength properties. The goal of this preliminary work is twofold: first, we aim to identify a method to test tensile strength along a core axis and second, we seek to assess the effect of temperature on the tensile strength of intact, unfractured shale cores (2.54 cm (1 in) diameter, 5.08 cm (2 in) long for comparison with future fractured and UICP-treated cores. A modified Brazilian indirect tensile strength test successfully measured splitting tensile strength of shale cores from Eagle Ford and Wolfcamp formations at room temperature and 60°C.

clastic rock↗
DOE OSTI2022

Effect of oxidative breakers on organic matter degradation, contaminant mobility and critical mineral release during shale-fracturing fluid interactions in the Marcellus Shale

Oil and gas production from organic-rich shale formations has become viable through advancements in multistage hydraulic fracturing. However, fluctuations in oil and gas prices, coupled with the sharp decline in gas production after the initial days of fracturing operations, drive operators to devise strategies for enhancing hydrocarbon production. The use of highly reactive fracturing fluids that include strong oxidizing agents, also known as breakers, can potentially increase well productivity. The oxidative breakers are used to reduce the viscosity of gel-based fluids after the proppant is transported into fracture zones of the target formation. These breakers can also degrade the organic matter, enhancing the release of hydrocarbons. However, chemical byproducts generated by the interaction of oxidative breakers with the shale matrix have not been extensively studied. Here, this study investigated the fluid-rock interactions between Marcellus Shale and synthetic hydraulic fracturing fluid (HFF) solutions comprising three different oxidative breakers, i.e., ammonium persulfate, sodium bromate, and sodium hypochlorite, commonly used in the Appalachian Basin, USA. Our results demonstrate that the type of oxidizing breakers used in the HFF controlled the type and amount of volatile organic compounds (VOCs) and semi-volatile organic compounds (SVOCs) produced. In all HFF reacted effluents, we observed the transformation of VOCs and the presence of organic acids in variable amounts. However, effluents from HFF containing sodium bromate and sodium hypochlorite breakers showed the presence of several halogenated organic compounds. Changes in major ions and mineralogy indicate that carbonate dissolution and barite precipitation were ubiquitous in all shale reacted effluents. Our results also demonstrate that the addition of oxidative breakers increased the concentration of several major and trace elements in the effluents. These elements fall under the critical mineral (CM) or critical element category due to their high demand in emerging technologies and susceptibility to supply chain disruption due to variety of factors. However, before oxidative breakers can be used at a larger field scale to enhance the release and recovery of CM and hydrocarbons, a better understanding is required of the potential environmental impacts associated with the generation and transformation of contaminants during breaker-fluid-rock interaction.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2021

Core-flood Effluent and Shale Surface Chemistries in Predicting Interaction between Shale, Brine, and Reactive Fluid

We report field and laboratory observations to date indicate that the efficiency of hydraulic fracturing, as it relates to hydrocarbon recovery, depends significantly on geochemical alterations to rock surfaces that diminish accessibility by partial or total plugging of the pore and fracture networks. This is caused by mineral scale deposition such as coating of fracture surfaces with precipitates, particle migration, and/or crack closure due to dissolution under stress. In reactive flow-through experiments, mineral reactions in response to acidic fluid injection significantly reduced system porosity and core permeability. The present study focuses on changes to fluid chemistry and shale surfaces (inlet and fracture walls) resulting from shale-fluid interactions and integrating these findings for an improved estimate of transport-related consequences. The reacted shale surfaces were examined by spatially-resolved scanning electron microscopy - energy dispersive spectroscopy (SEM-EDS) analysis. Importantly, inductively coupled plasma - mass spectrometry/optical emission spectroscopy (ICP-MS/OES) was utilized to probe the chemical evolution of the core-flood effluents. The three study cores selected from the Marcellus formation represent different mineralogies and structural features. In flow-through experiments, lab-generated brine and HCl-based fracture fluid (pH=2) were injected sequentially under effective stress (up to 500 psi) at reservoir temperature (80°C). SEM-EDS results confirmed by the ICP concentration trends showed significant Fe hydroxide precipitates in clay- and pyrite-rich outcrop samples due to partial oxidation of Fe-bearing phases in the case of intrusion of low salinity water-based fluids. Porosity reduction in the MSEEL (Marcellus Shale Energy and Environmental Laboratory) carbonate-rich sample is related to compaction of cores under stress due to matrix softening with substantial dissolution, and pore-filling by hydroxides, as well as barite and salts. Despite the same fluid compositions and experimental conditions used for both MSEEL samples, barite precipitation was much more intense in the MSEEL clay-rich sample due to its greater sorption capacity and additional sulfate source as well as fissile nature with multiple lengthwise cracks. ICP tests revealed time-resolved concentration trends in produced brine and reactive fluids that in turn complemented the pre-/post-reaction SEM-EDS observations.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2025

Reactivity of Shale to Supercritical CO 2 : Insights from Microstructural Characterization and Mineral Phase Evolution in Caney Shales for CCUS Applications

Understanding mineral–fluid interactions in shale under supercritical CO 2 (scCO 2 ) conditions is relevant for assessing long-term geochemical containment. This study characterizes mineralogical transformations and elemental redistribution in five Caney Shale samples serving as proxies for reservoir (R1, R2, R3) and caprock (D1, D2) facies, subjected to 30-day static exposure to pure scCO 2 at 60 °C and 17.23 MPa (2500 psi), with no brine or impurities introduced. SEM-EDS analyses were conducted before and after exposure, with mineral phases classified into silicates, carbonates, sulfides, and organic matter. Initial compositions were dominated by quartz (38–47 wt.%), illite (16–23 wt.%), carbonates (12–18 wt.%), and organic matter (8–11 wt.%). Post-exposure, carbonate loss ranged from 15 to 40% in reservoir samples and up to 20% in caprock samples. Illite and K-feldspar showed depletion of Fe 2+ , Mg 2+ , and K + at grain edges and cleavages, while pyrite underwent oxidation with Fe redistribution. Organic matter exhibited scCO 2 -induced surface alteration and apparent sorption effects, most pronounced in R2 and R3. Elemental mapping revealed Ca 2+ , Mg 2+ , Fe 2+ , and Si 4+ mobilization near reactive interfaces, though no secondary mineral precipitates formed. Reservoir samples developed localized porosity, whereas caprock samples retained more structural clay integrity. The results advance understanding of mineral reactivity and elemental fluxes in shale-based CO 2 sequestration.

geochemical CO2 sequestration↗
NASA NTRS2016

Fugitive Emissions from the Bakken Shale Illustrate Role of Shale Production in Global Ethane Shift

Ethane is the second most abundant atmospheric hydrocarbon, exerts a strong influence on tropospheric ozone, and reduces the atmosphere's oxidative capacity. Global observations showed declining ethane abundances from 1984 to 2010, while a regional measurement indicated increasing levels since 2009, with the reason for this subject to speculation. The Bakken shale is an oil and gas-producing formation centered in North Dakota that experienced a rapid increase in production beginning in 2010. We use airborne data collected over the North Dakota portion of the Bakken shale in 2014 to calculate ethane emissions of 0.23 +/- 0.07 (2 sigma) Tg/yr, equivalent to 1-3% of total global sources. Emissions of this magnitude impact air quality via concurrent increases in tropospheric ozone. This recently developed large ethane source from one location illustrates the key role of shale oil and gas production in rising global ethane levels.

ethane↗
DOE OSTI2023

Creep Properties of Shale and Predicted Impact on Proppant Embedment for the Caney Shale, Oklahoma

The Caney shale is an emerging hydrocarbon play located in southwest Oklahoma, USA. Within the Caney shale exist facies which were initially dubbed “reservoir” and “ductile” based on evaluation of well logging data. While past work has shown the distinction of “brittle” and “ductile” is not mechanically justifiable according to formal definitions, here the current work shows some important differences between nominally ductile and reservoir zones. First, the “ductile” zones are more clay rich and have textural differences which can be expected to lead to differences in mechanical properties. One important impact of these differences is observed in triaxial creep experiments showing the “ductile” zones are more prone to creep deformation. Numerical simulations predict the “reservoir” zones will experience very little proppant embedment due to creep deformation of hydraulic fractures around proppant particles. On the other hand, “ductile” zones can be expected to undergo creep-driven proppant embedment leading to loss of fracture aperture ranging up to 100% loss, depending upon the spatial density of the proppant distribution. Hence, this research shows the identification of nominally “ductile” zones from well logs, while a misnomer, can be useful in finding clay-rich, creep-prone zones which will be the most prone to proppant embedment and hence vulnerable to greater production decline over time.

58 GEOSCIENCES↗
DOE OSTI2022

Opening-mode fracturing and cementation during hydrocarbon generation in shale: An example from the Barnett Shale, Delaware Basin, West Texas

Relative timing of fracturing is a key input for predictive fracture models, but timing information for fractures is commonly difficult to obtain. In this study, we used crosscutting relations and fluid inclusion assemblage temperatures from fracture cements from a few well-documented sampled fractures, combined with a one-dimensional burial history model, to establish timing for three generations of opening-mode fractures in a Barnett Shale core from the southern part of the Delaware Basin, Pecos County, West Texas. A burial history model is presented for the cored well and matched to measured vitrinite reflectance in samples from the core, and bottomhole temperature in the well. Here, the earliest fractures (group 1) likely formed due to early fluid-expulsion events (ca. 300 Ma) and were folded during host-rock compaction. Later group 2 fractures are sealed with fibrous barite containing primary, liquid hydrocarbon inclusions (mean homogenization temperature [T h ] = –9°C) and aqueous fluid inclusions (mean T h = 108.1°C). Group 2 fractures likely formed in response to fluid overpressure associated with cracking of type II kerogen to oil. Group 3 vertical fractures are up to 2 m in height with kinematic apertures ranging from less than 0.05 to 1.4 mm, partly open, and strike dominantly 010°–020°. Sequentially trapped aqueous fluid inclusions in fracture-spanning quartz cement bridges (mean T h = 110°C in crack-seal texture and 128°C in post-crack-seal fracture cement) record fracture opening under increasing temperature, inferred to reflect increasing burial, with continued overpressuring during the Triassic to Late Cretaceous. Some group 3 fractures may have continued to fill during Cenozoic uplift.

02 PETROLEUM↗
DOE OSTI2024

Mineral and fluid transformation of hydraulically fractured shale: case study of Caney Shale in Southern Oklahoma

This study explores the geochemical reactions that can cause permeability loss in hydraulically fractured reservoirs. The experiments involved the reaction of powdered-rock samples with produced brines in batch reactor system at temperature of 95 °C and atmospheric pressure for 7-days and 30-days respectively. Results show changes in mineralogy and chemistry of rock and fluid samples respectively, therefore confirming chemical reactions between the two during the experiments. The mineralogical changes of the rock included decreases of pyrite and feldspar content, whilst carbonate and illite content showed an initial stability and increase respectively before decreasing. Results from analyses of post-reaction fluids generally corroborate the results obtained from mineralogical analyses. Integrating the results obtained from both rocks and fluids reveal a complex trend of reactions between rock and fluid samples which is summarized as follows. Dissolution of pyrite by oxygenated fluid causes transient and localized acidity which triggers the dissolution of feldspar, carbonates, and other minerals susceptible to dissolution under acidic conditions. The dissolution of minerals releases high concentrations of ions, some of which subsequently precipitate secondary minerals. On the field scale, the formation of secondary minerals in the pores and flow paths of hydrocarbons can cause significant reduction in the permeability of the reservoir, which will culminate in rapid productivity decline. This study provides an understanding of the geochemical rock–fluid reactions that impact long term permeability of shale reservoirs.

58 GEOSCIENCES↗