Engineering Papers⌕ Search

SEARCH · Engineering Papers

Results for “Shale”

Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 55 records · Page 3
All sourcesNASA NTRSDOE OSTI
DOE OSTI2022

Fe Oxidation and Species Distribution at the Rock–Fluid Interface of Marcellus Shale Reacted with Hydraulic Fracturing Fluid

Hydraulic fracturing of shale reservoirs resulted in significant opportunity for increased oil and gas production in the United States. Rock-fluid interactions can cause mineral dissolution and precipitation reactions that lead to permeability changes in the shale matrix, which ultimately may affect transport pathways and hydrocarbon production. Understanding the distribution of secondary precipitates, such as barite and Fe(III) (hydro)oxides, and cation leaching at the rock-fluid interface is an important step to further investigate how these geochemical processes can change permeability and transport pathways. In this study, thin sections of the fracture-matrix interface were made from reacted Marcellus shale cores. The thin sections were characterized using synchrotron X-ray fluorescence imaging and synchrotron X-ray absorption spectroscopy. Fe species with different oxidation states were identified in the maps, together with barite and Ca distribution. The results show that ferrihydrite, as newly formed Fe(III)-bearing precipitates, aligned well with the border of the Ca (e.g., calcite) leaching region in the reaction front. Some Fe-containing clay also dissolved, but the dissolution region for the clay was not as deep as the calcite. Further, the reaction front is about three times deeper in the direction parallel to the shale bedding than that perpendicular to the bedding. The Ca leaching region can be an index for reaction front detection for Marcellus shale. Reactive transport modeling was conducted and the predicted Ca leaching boarder align well with ferrihydrite precipitation, consistent with the experimental observation. The carbonate mineral dissolution can be crucial to promote fluid access into the shale matrix. Together with our previous study on the shale reactive surface, this follow-up study showed similar Ca leaching region and Fe(III) precipitates distribution in the reaction front regardless of barite precipitation on the surface, indicating that the barite coatings on the surface may not pose a significant impact on reactive transport at the shale-fluid interface.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Biogeochemistry of the Antrim Shale Natural Gas Reservoir

The Antrim Shale, located in the Michigan Basin, United States (U.S.), is a major U.S. shale play having produced over 2.5 Trillion Cubic Feet (Tcf) of unconventional shale natural gas as of 2010. The shallow nature of this formation sets it apart from other, more characterized unconventional shale gas plays. The depth of gas production of the Antrim ranges from approximately 150 to 600 m and it is typically vertically drilled, contrary to deeper, horizontally drilled shales. A thorough understanding of the biogeochemistry and microbiology of this complex system will be advantageous for improving well performance, produced water management, and potential biocidal treatment as microbial community composition can vary substantially even among closely spaced wells. In this study, we analyzed produced water collected from nine different wells in the Antrim Shale by investigating the geochemical and microbial community composition of the produced water to gain greater insight into the overall biogeochemistry of this unique shale system. The majority of the wells from this study had high total dissolved solids (TDS) primarily composed of chloride and sodium, averaging 86,804 mg/L with a maximum 116,223 mg/L; however, three of the wells sampled along the northern margin of the basin exhibited significantly lower TDS ranging from 4932 to 6496 mg/L. Overall, our microbial community analysis revealed relatively low abundance within our samples and high variability of the microbial community among the sampled wells. The majority of bacterial sequences were identified within Proteobacteria, Firmicutes, and Actinobacteria phyla and metagenomic sequencing revealed the low presence of Methanobacteriaceae within each sample. We also investigated potential microbial community drivers and found that TDS, sodium, chloride, iodide, bromide, ammonium, potassium, and strontium were significantly correlated with the observed microbial community. The varying geochemical conditions between wells demonstrate different subsurface environmental niches, potentially driving the heterogeneous microbial communities we observed from well to well. This analysis suggests an important relationship between both well location and geochemistry and the observed microbial community that can persist in the reservoir. Continued studies of the Antrim Shale will improve our understanding of the complex interdependencies of this ecosystem.

03 NATURAL GAS↗
DOE OSTI2020

Fundamental Understanding of Methane-Carbon Dioxide-Water (CH 4 -CO 2 - H 2 O) Interactions in Shale Nanopores under Reservoir Conditions (Quarterly Report)

Shale is characterized by the predominant presence of nanometer-scale (1-100 nm) pores. The behavior of fluids in those pores directly controls shale gas storage and release in shale matrix and ultimately the wellbore production in unconventional reservoirs. Recently, it has been recognized that a fluid confined in nanopores can behave dramatically differently from the corresponding bulk phase due to nanopore confinement. CO 2 and H 2 O, either preexisting or introduced, are two major components that coexist with shale gas (predominately CH 4 ) during hydrofracturing and gas extraction. Note that liquid or supercritical CO 2 has been suggested as an alternative fluid for subsurface fracturing such that CO 2 enhanced gas recovery can also serve as a CO 2 sequestration process. Limited data indicate that CO 2 may preferentially adsorb in nanopores (particularly those in kerogen) and therefore displace CH 4 in shale. Similarly, the presence of water moisture seems able to displace or trap CH 4 in shale matrix. Therefore, fundamental understanding of CH 4 -CO 2 -H 2 O behavior and their interactions in shale nanopores is of great importance for gas production and the related CO 2 sequestration. This project focuses on the systematic study of CH 4 -CO 2 -H 2 O interactions in shale nanopores under high-pressure and high temperature reservoir conditions. The proposed work will help develop new stimulation strategies to enable efficient resource recovery from fewer and less environmentally impactful wells.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2024

Changes in environmental and engineered conditions alter the plasma membrane lipidome of fractured shale bacteria

ABSTRACT Microorganisms that persist in fractured shale reservoirs cause several problems including secreting foul gases and forming biofilms. Current biocontrol measures often fail due to limited knowledge of their in situ activities. The plasma membrane protects the cell, mediates many of its critical functions, and responds to intracellular cues and ecological perturbations through physicochemical modifications. As such, it provides valuable insight into the physiological adaptation of microorganisms in disturbed environmental systems. Here, we (i) demonstrate how changes in salinity and hydraulic retention time (HRT) influence the plasma membrane intact polar lipid (IPL) chemistry of model bacterium, Halanaerobium congolense WG10, and mixed microbial consortia enriched from shale-produced fluids and (ii) elucidate adjustments in membrane IPL chemistry during biofilm growth relative to planktonic cells. We incubated H. congolense WG10 in chemostats under three salinities (7%, 13%, and 20% NaCl), operated under three HRTs (19.2, 24, and 48 h), and in drip flow biofilm reactors under the same salinity gradients. Also, mixed microbial consortia in produced fluids were enriched in triplicate chemostat vessels under three HRTs (19.2, 24, and 72 h) and biofilm reactors. Lipids were analyzed by ultra high performance liquid chromatography-tandem mass spectrometry (UPLC-MS/MS). Our results show that phosphatidylglycerols, cardiolipins, and phosphatidylethanolamines were predominantly enriched in planktonic H. congolense WG10 cells grown at hypersalinity (20%) compared to optimum (13%). In addition, several zwitterionic phosphatidylcholines and phosphatidylethanolamines were higher in abundance during biofilm growth. These observations suggest that microbial adaptation and biofilm formation in fractured shale are enabled by strategic plasma membrane IPL chemistry adjustments. IMPORTANCE Microorganisms inadvertently introduced into the shale reservoir during fracturing face multiple stressors including brine-level salinities and starvation. However, some anaerobic halotolerant bacteria adapt and persist for long periods of time. They produce hydrogen sulfide, which sours the reservoir and corrodes engineering infrastructure. In addition, they form biofilms on rock matrices, which decrease shale permeability and clog fracture networks. These reduce well productivity and increase extraction costs. Under stress, microbes remodel their plasma membrane to optimize its roles in protection and mediating cellular processes such as signaling, transport, and energy metabolism. Hence, by observing changes in the membrane lipidome of model shale bacteria, Halanaerobium congolense WG10, and mixed consortia enriched from produced fluids under varying subsurface conditions and growth modes, we provide insight that advances our knowledge of the fractured shale biosystem. We also offer data-driven recommendations for improving biocontrol efficacy and the efficiency of energy recovery from unconventional formations.

03 NATURAL GAS↗
DOE OSTI2021

Striving to translate shale physics across ten orders of magnitude: What have we learned?

Shales will play an important role in the successful transition of energy from fossil-based resources to renewables in the coming decades. Aside from being a significant source of low-carbon intensity fuels, like natural gas, they also serve as geologic seals of subsurface formations that may be used to isolate nuclear waste, sequester CO 2 , or store intermittent energy (e.g., solar hydrogen). Despite their importance, shales pose significant engineering and environmental challenges due to their nanoporous structure and extreme heterogeneity that spans at least ~10 orders of magnitude in spatial scale. Two challenges inhibit a system-level understanding: (1) the physics of fluid flow and phase behavior in shales are poorly understood due to the dominant molecular interactions between minerals and fluids under confinement, and (2) the apparent lack of scale separation that prevents a reliable (closed) description of the physics at any single scale of observation. In this review, we focus on the latter issue and discuss scale translation, which in its broadest sense is transforming data or simulations from one spatiotemporal scale to another. While effective scale translation is not exclusive to shales, but all geologic porous media, the need for it is especially acute in shales given their high degree of heterogeneity. Classical theories like homogenization, while indispensable, fail when scales are not separated. Other methods, like numerical upscaling, scale-translate in only one direction: small to large, but not the reverse, called downscaling. However, the confluence of advances in three areas are bringing challenging problems such as shales within reach: increased computational power and scalable algorithms; high-resolution imaging and multi-modal data acquisition; and machine learning to process massive amounts of data. While these advances equip geoscientists with a wide array of experimental and computational tools, no individual tool can probe the entire gamut of heterogeneity in shales. Their effective use, therefore, requires an ability to bridge between various data types obtained at different scales. The aim of this review is to present a coherent account of computational and experimental methods that may be used to achieve just that, i.e., to perform scale translation. We provide a broader definition of scale translation, one that transcends classical homogenization and upscaling methods, but is consistent with them and accommodates notions like downscaling and data translation. After a brief introduction to homogenization, we review hybrid methods, numerical upscaling and its recent extensions, multiscale computing, high-resolution imaging, and machine learning. We place particular emphasis on multiscale computing and propose an algorithmic framework to bridge between the pore (micro) and Darcy (macro) scales. Throughout the paper, we draw comparisons between the various methods and highlight their (often hidden) similarities, differences, benefits, and pitfalls. We finally conclude with two case studies on shales that exemplify some of the methods presented.

58 GEOSCIENCES↗
DOE OSTI2022

Experimental Investigation of Barium Sources and Fluid–Rock Interaction in Unconventional Marcellus Shale Wells Using Ba Isotopes

Produced waters from unconventional Marcellus Shale gas wells have anomalously high barium (Ba) concentrations and yield some of the isotopically heaviest Ba measured to date. Experiments were conducted to constrain the source of Ba in these fluids and the controls on barite (BaSO 4 ) precipitation and dissolution in oil and gas wells. Experiments simulating the acidizing stage evaluated the solubility of pure barite and drilling mud in 2 M HCl at 80 °C for periods of 2, 6, and 48 h and resulted in <0.01% barite dissolution with no appreciable change in δ 138 Ba ( 138 Ba/ 134 Ba normalized to NIST standard 3104a). Static autoclave experiments conducted at 66 °C and 20.7 MPa with combinations of ground Marcellus Shale solids and/or barite-bearing drilling mud with synthetic low-Ba fracturing fluid resulted in decreased Ba concentrations in the fluid, with the largest decrease in the shale-only run. Fluid δ 138 Ba values increased by about 0.5‰ as Ba concentrations decreased, consistent with closed-system Rayleigh fractionation. Flow-through experiments in Marcellus Shale core conducted for 28 days resulted in effluent Ba concentrations an order of magnitude lower than the influent, while sulfate concentrations increased over time. Effluent δ 138 Ba values increased over the first 12 days and plateaued at about 1‰ higher than the influent. Modeling suggests a combination of the release of labile shale Ba and barite precipitation. This work indicates that the processes of Ba release from fluid–shale interactions and barite precipitation in fractures and the well bore, while capable of producing high δ 138 Ba fluids, are unlikely to generate fluids with high-Ba concentrations and δ 138 Ba values like those in Marcellus-produced waters. As a result, we find that the release of sulfate from shale pyrite oxidation rapidly catalyzes barite precipitation and that dissolution of drilling mud barite or natural barite in the shale is unlikely to be the major source of Ba in Marcellus-produced waters.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2021

Thermo-mechanical characterization of shale using nanoindentation

Abstract Shale can be a potential buffer for high-level radioactive nuclear wastes. To be an effective buffer while subject to waste heat, shale's mechanical response at elevated temperature must be known. Many researchers have experimentally characterized the mechanical behavior of various shales at different length scales in adiabatic conditions. However, its mechanical performance at elevated temperatures at the nano-scale remains unknown. To investigate the temperature dependency of nanomechanical properties of shale, we conducted both experimental and numerical studies. In this study, we measured mechanical and fracture properties of shale, such as hardness, elastic modulus, anisotropy, and fracture toughness from 25 °C up to 300 °C at different bedding planes. Statistical analysis of the results suggests that hardness and fracture toughness significantly increased at temperatures from 100 to 300 °C; while, temperature does not have a significant impact on elastic modulus. Data also shows that the bedding plane orientations have a substantial impact on both mechanical and fracture properties of shale at the nano-scale leading to distinct anisotropic behavior at elevated temperature below 100 °C. Additionally, we numerically investigated the mechanical performance of the shale samples at room temperature to gain an insight into its mechanical response through the thickness. Numerical results were validated against the experimental results, confirming the simulation can be used to predict shale deformation at the nano-scale or potentially be used in multi-scale simulations.

36 MATERIALS SCIENCE↗
DOE OSTI2023

Dissolution and reprecipitation of amorphous silica in silica Rich shales induces Non-Monotonic evolution of porosity in acidic reactive environments

Advances in sustainable subsurface energy technologies are crucial for meeting our energy and resource needs for a climate-resilient future. Novel strategies to harness subsurface shale reservoirs for recovering valuable metals and for enabling CO 2 storage are influenced by the morphological and mineralogical heterogeneities of these materials. In this context, delineating the interactions of highly acidic solutions such as wet supercritical CO 2 on shales with varying mineralogy is crucial to inform the stability of caprock seal for CO 2 storage and enhancements in permeability for fluid transport, reactivity, and storage. The feedback chemical effects associated with the interactions of acidic solutions on the morphologies and mineralogies of shales have not been extensively investigated. These insights are crucial for assessing temporal changes in the reactivity and the fate of the fluids in subsurface environments. In this study, we investigate the effect of 1M HCl solution on the chemistry and morphology of three different shale samples with varying carbonate, clay and silica contents. An increase in the amorphous content, from 37% to 41.3%, of silica-rich and carbonate/clay lean shale is noted due to reactions with an acidic solution which is attributed to the dissolution of Si-bearing phases such as clays, accompanied by SiO 2 precipitation. In shales bearing high content of clays and carbonates, significant increase in the pore volumes and surface areas are noted. Non-monotonic changes in the micron-scale porosity of silica rich–carbonate/clay lean (e.g., Mowry shale) are noted using in-situ X-ray microtomography experiments. Due to the initial mobilization of silica and dissolution of carbonate/clay phases, the total porosity slightly increases from 6.7% to 10.7% followed by a decrease to similar to 4% caused by SiO 2 reprecipitation. In conclusion, these findings suggest that even though silica is less reactive in acidic environments, the changes in the amorphous and crystalline content due to dissolution and reprecipitation alter the porosity and fluid flow paths.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2024

Field Evaluation of the Caney Shale as an Emerging Unconventional Play, Southern Oklahoma

The Mississippian-age Caney Shale is an emerging unconventional oil and gas (UOG) resource play in the southern Midcontinent and is prospective in the Anadarko, Ardmore, Marietta and western Arkoma basins. This play is enigmatic in that time equivalent Fayetteville Shale in the eastern Arkoma basin and Barnett Shale in the Ft. Worth Basin are major unconventional plays, whereas Caney Shale production is sparse and unpredictable (Cardott, 2017). In the Anadarko, Ardmore and Marietta basins, the Caney Shale is in the oil window, but its resource potential has not been adequately assessed. The Caney reservoir is about 60-300 m thick, is rich in total organic carbon, contains a large oil resource base, and has a strong natural gas drive; however, development has been hampered by high clay content and reactivity of the formation with water. The main objective of this initial four-year research project was to address these issues by establishing a Caney Shale Field Laboratory in the Ardmore Basin of southern Oklahoma to (a) conduct a comprehensive field characterization (b) perform field experiments, and (c) validate cost-effective technologies that will lead to a comprehensive and efficient development strategy plan for Caney Shale.

02 PETROLEUM↗
DOE OSTI2021

SEM petrography of dispersed organic matter in black shales: A review

Organic matter (OM)-hosted pores are important constituents of the pore system of black shales and play a crucial role in determining their methane adsorption capacity and porosity. OM-hosted pores are generally observed and described with scanning electron microscope (SEM) on Ar ion-milled surfaces. However, SEM imaging is not able to reliably distinguish OM types and relate the observed pores to specific macerals. Partly because of this inability to relate organic pores to macerals, the evolution of organic porosity during thermal maturation remains poorly understood. In this paper, we review the petrographic characteristics of dispersed organic matter (DOM) in black shales under the SEM. Organic petrographic classification of DOM developed for reflected-light microscopy is so far the most practical method when describing DOM in black shales under the SEM because this classification has information on the origin of DOM. Therefore, correlative microscopy (combination of reflected-light and electron microscopy) is the most effective method to identify both OM types and OM-hosted pores. This method, however, is not readily available to most researchers. Although identifying OM on the basis of SEM observations is a challenging task, it is achievable provided there is a good understanding of the studied shales, especially their thermal maturity and original OM composition. Therefore, the overall objective of this paper is to review petrographic characteristics of DOM in black shales under the SEM to provide some guidelines for identifying DOM from SEM observations. We also review factors that control the formation and preservation of OM-hosted pores. OM-hosted pores consist of primary and secondary organic pores. Primary organic pores are pores inherited from the biological structure of the original OM. Secondary organic pores develop during hydrocarbon generation and expulsion from oil-prone OM and are hosted by solid bitumen or pyrobitumen. The development of secondary organic pores is controlled by thermal maturity and OM type, and their preservation is subject to thermal maturity, OM content, and mineralogical composition. The presented view of the evolution of micropore and mesopore characteristics of OM with thermal maturity is based on data from the literature. The specific surface area and pore volume of OM in black shales follow a parabolic pattern with increasing thermal maturity (quantified via vitrinite reflectance, R o ). The initial increase reflects development of OM-hosted pores, and the subsequent decrease is due to denser stacking of aromatic units in the macromolecular structure of OM, with maximum values (specific surface area ~ 300 m 2 /g and pore volume ~ 0.3 cm 3 /g) reached at R o values in the 2.5-3.5% range. The contribution of OM-hosted pores to the pore characteristics of black shales depends on OM content, OM type, and thermal maturity.

03 NATURAL GAS↗
DOE OSTI2021

Coupling dynamic in situ X-ray micro-imaging and indentation: A novel approach to evaluate micromechanics applied to oil shale

Oil and gas shales are a system where understanding the mechanical properties at the microscale is of paramount importance, e.g. to better understand the behavior of proppant-shale contacts and their role in the evolution of propped fractures in unconventional reservoirs. Here we show for the first time an experiment coupling indentation testing with in situ X-ray imaging in a Green River shale sample. A full compliance curve has been measured with the sample in water, allowing to visualize the indentation of the sample in function of axial load, in a purpose-built system for combined in situ indentation and X-ray imaging. A series of 3D datasets were used for a digital volume correlation study to obtain local strain fields. This analysis has been complemented with the analysis of cracks. Finally, geomechanical modeling has been carried out to replicate and generalize the observed behavior in the shale. This study validated this experimental approach, providing a breakthrough in understanding micro-mechanics in shales, and demonstrates how this class of experiments can be important for studies involving the prediction of the evolution of propped fractures in shale reservoirs, with possible applications in a much larger number of application fields (geothermal, materials science, etc.)

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Measurement of Deformation Heterogeneity During Shale Swelling Using Digital Image Correlation

Abstract Rock-fluid interactions in shale formations are one of the main sources of wellbore instability issues and inadequate stimulation performance. For better planning of fracturing operations and optimizing production from these reservoirs, it is important to understand the mechanisms behind these interactions. These issues are especially prevalent in clay-rich shales, such as Tuscaloosa Marine Shale, which is the subject of this study. Conventional techniques to quantify these shale-fluid interactions comprise of measuring swelling in powdered rock grains or measurement of deformation in the whole pieces of the core using a linear variable differential transformer and strain gages. However, the contribution from individual laminae to overall deformation cannot be evaluated using these methods. In this study, we developed an experimental setup to evaluate the spatial deformation in shale during interaction with water using digital image correlation (DIC). Deformation of two shale samples, with 34 wt% to 51 wt% clay content, was studied. White paint was used to generate a random speckle pattern on the specimen and then immersed in deionized water. The deformation process was captured using a digital camera and images were analyzed using DIC to quantify the deformation. The implementation of the DIC technique enables the visualization and quantification of spatial deformation in the specimen during interacting with water. The results show the localization of large strains in select laminations. The results provide a better understanding of shale deformation when interacting with water in comparison to traditional measurements that can provide only an average strain value.

Energy & Fuels↗
DOE OSTI2024

Comparison of Geochemical Reactivity of Marcellus and Caney Shale Based on Effluent Analysis

ABSTRACT: In this comparative study, we analyzed the changes in elemental concentrations of hydraulic fracturing fluids after interaction with the Marcellus and Caney Shale formations. The focus was on assessing the inherent risks and environmental implications associated with flowback waters, including their impact on soil, ground, and drinking water quality, and human health safety. The chemical compositions of effluents were determined through Inductively Coupled Plasma Optical Emission Spectroscopy (ICP-OES) and Mass spectrometry (ICP-MS). The Marcellus Shale, showed concentrations of Cd, averaging 0.380 ppm far exceeding safe water thresholds. Significant levels of As, Se, B, and Pb were detected in both shales, raising concerns about soil and water contamination. Analyzing the effluents from representative samples of sections of the Marcellus (S2 and S7) and Caney (R1 and R2) indicates different geochemical responses over 4 weeks of experiments. This comparison underscores the chemical changes and environmental considerations linked to hydraulic fracturing across shale formations, suggesting the value of tailored monitoring and regulatory measures for each type. 1. INTRODUCTION The Caney and Marcellus shales, differing in geology and geochemistry, represent distinct unconventional reservoirs. The Caney shale, is more ductile, with higher produced water volumes, (Smith et al., 2022) contrasts with the brittle Marcellus shale known for lower brine production but significant data availability. This study aims to elucidate the possible environmental health and safety issues that may arise from the hydraulic fracturing processes. The interaction between fracturing fluids and clays presents a significant challenge. The primary base of these fluids is water, which, when introduced to clay, can induce swelling and constrict flow pathways. This phenomenon is attributed to water molecules infiltrating the layers of clay, particularly in 2:1-type clays, leading to an increased distance between layers. To counteract this, clay stabilizers are employed (Awejori et al., 2021). Despite their effectiveness, these stabilizers are considered temporary solutions. Upon completion of the fracturing process, a concomitant amount of contaminated waters (flow back), with varied content is collected at the surface. From these, we can infer the geochemical reactions and the environmental challenges associated with these waters. Flowback waters can be reinjected or used for other purposes such as irrigation. This requires adequate screening and treatment for safe use.

Dje, L. B.↗
DOE OSTI2024

Beyond the Surface: Non-Invasive Low-Field NMR Analysis of Microbially-Induced Calcium Carbonate Precipitation in Shale Fractures

Microbially-induced calcium carbonate precipitation (MICP) is a biological process in which microbially-produced urease enzymes convert urea and calcium into solid calcium carbonate (CaCO 3 ) deposits. MICP has been demonstrated to reduce permeability in shale fractures under elevated pressures, raising the possibility of applying this technology to enhance shale reservoir storage safety. For this and other applications to become a reality, non-invasive tools are needed to determine how effectively MICP seals shale fractures at subsurface temperatures. In this study, two different MICP strategies were tested on 2.54 cm diameter and 5.08 cm long shale cores with a single fracture at 60 °C. Flow-through, pulsed-flow MICP-treatment was repeatedly applied to Marcellus shale fractures with and without sand (“proppant”) until reaching approximately four orders of magnitude reduction in apparent permeability, while a single application of polymer-based “immersion” MICP-treatment was applied to an Eagle Ford shale fracture with proppant. Low-field nuclear magnetic resonance (LF-NMR) and X-Ray computed microtomography (micro-CT) techniques were used to assess the degree of biomineralization. With the flow-through approach, these tools revealed that while CaCO 3 precipitation occurred throughout the fracture, there was preferential precipitation around proppant. Without proppant, the same approach led to premature sealing at the inlet side of the core. In contrast, immersion MICP-treatment sealed off the fracture edges and showed less mineral precipitation overall. This study highlights the use of LF-NMR relaxometry in characterizing fracture sealing and can help guide NMR logging tools in subsurface remediation efforts.

MICP↗
DOE OSTI2022

Tuscaloosa Marine Shale: Seal or Source? Petrophysical Comparative Study of Wells in SE Louisiana and SW Mississippi

The Tuscaloosa Marine Shale (TMS) is a versatile Late Cretaceous shale formation present in central and SE Louisiana and SW Mississippi, which drew attention because of the various roles played within the Tuscaloosa Group. In this paper, it is debated whether the Tuscaloosa Marine Shale can act as a source, reservoir, or seal all throughout the shale play or only in certain areas. Well log and core data from Adams County, Mississippi, are compared to data from East Feliciana Parish in Louisiana. Conclusions were drawn based on the results of well log analysis, X-ray Diffraction (XRD), porosity–permeability measurements, programmed pyrolysis, and fracture analysis. It was shown that the Tuscaloosa Marine Shale interval in SE Louisiana consists of important amounts of calcite, exhibits multiple natural fractures, has porosity values as high as 9.3%, and shows a TOC content of up to 2.8 wt%. On the other hand, samples from a well at the Cranfield field, MS, are characterized by considerably lower TOC values of around 0.88 wt%, porosities between 0.33% and 4%, and no serious fracturing. The formation demonstrates better reservoir and source potential in SE Louisiana and reliable CO2 sealing capacity in SW Mississippi. The analysis presented in this paper represents a holistic approach to the characterization of shale formations, is applicable to other plays around the world, and can be used as an integral part of CO2 sequestration or hydraulic fracturing programs.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2022

Water Imbibition and Oil Recovery in Shale: Dynamics and Mechanisms Using Integrated Centimeter-to-Nanometer-Scale Imaging

Water imbibition, and the associated oil displacement, is an important process in shale oil reservoirs after hydraulic fracturing and in water-based enhanced oil recovery (EOR). Current techniques for water imbibition measurement are mostly “black-box”-type methods. A more explicit understanding of the water imbibition/oil recovery dynamics and geological controls is in demand. In this paper, a multiscale imaging technique that covers centimeter to nanometer scale (i.e., core to pore scale), integrating neutron radiography, microcomputed tomography (micro-CT), and scanning electron microscope (SEM) is applied to investigate the water imbibition depth and rate and the cause of heterogeneity of imbibition in shale samples. The dynamic processes of water imbibition in the 1-in. (25.4-mm) core sample were explicitly demonstrated, and the imbibition along the matrix and imbibition through microfractures are distinguished through neutron radiography image analysis. The causes of observed imbibition heterogeneity were further investigated through micro-CT and SEM image analysis for 1.5-mm diameter miniplug samples from different laminas of the 1-in. core samples. Imbibition depth and rate were calculated on the basis of image analysis as well. Estimation of oil recovery through water imbibition in shale matrix was performed for an example shale field. Here this innovative and integrated multiscale imaging technique provides a “white/gray-box” method to understand water imbibition and water-oil displacement in shale. The wide span of the length scale (from centimeter to nanometer) of this technique enables a more comprehensive, accurate, and specific understanding of both the core-scale dynamics and pore-scale mechanisms of water imbibition, oil recovery, and matrix-fracture interaction.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2024

Splitting tensile strength of shale cores: intact versus fractured and sealed with ureolysis-induced calcium carbonate precipitation (UICP)

Ureolysis-induced calcium carbonate precipitation (UICP) is a biomineral solution where the urease enzyme converts urea and calcium into calcium carbonate. The resulting biomineral can bridge gaps in fractured shale, reduce undesired fluid flow, limit fracture propagation, better store carbon dioxide, and potentially enhance well efficiency. The mechanical properties of shale cores were investigated using a modified Brazilian indirect tensile strength test. An investigation of intact shale using Eagle Ford and Wolfcamp cores was conducted at varying temperatures. Results show no significant difference between shale types (average tensile strength = 6.19 MPa). Eagle Ford displayed higher strength at elevated temperature, but temperature did not influence Wolfcamp. Comparatively, cores with a single, lengthwise heterogeneous fracture were sealed with UICP and further tested for tensile strength. UICP was delivered via a flow-through method which injected 20–30 sequential patterns of ureolytic microorganisms and UICP-promoting fluids into the fracture until permeability reduced by three orders of magnitude or with an immersion method which placed cores treated with guar gum and UICP-promoting fluids into a batch reactor, demonstrating that guar gum is a suitable inclusion and may reduce the number of flow-through injections required. Tensile results for both delivery methods were variable (0.15–8 MPa), and in some cores the biomineralized fracture split apart, possibly due to insufficient sealing and/or heterogeneity in the composite UICP-shale cores. Notably in other cores the biomineralized fracture remained intact, demonstrating more cohesion than the surrounding shale, indicating that UICP may produce a strong seal for subsurface application.

58 GEOSCIENCES↗
DOE OSTI2022

Origin of organic matter and organic pores in the overmature Ordovician-Silurian Wufeng-Longmaxi Shale of the Sichuan Basin, China

Organic matter (OM)-hosted pores play important roles in controlling the porosity and gas content of gas shales. However, the control of organic pore development and preservation remains poorly understood, partly because of the inability to distinguish OM types under the scanning electron microscope (SEM). In this study, seven over-mature Wufeng-Longmaxi Shale samples (equivalent vitrinite reflectance 1.93%–3.07%) were investigated with organic petrography and scanning electron microscope to study the origin of OM and development of organic pores in this black shale succession. Correlative light and electron microscopy was employed to examine pore development in individual macerals. Organic petrographic observations show that OM in these over-mature black shales is dominated by pyrobitumen and graptolites (> 90 vol.% of total OM based on point counting). Pyrobitumen mainly occurs as matrix bitumen in the fine-grained matrix, and also as a mixture with clay minerals and fossil cavity infillings. Vitrinite-like particles are minor constituents of OM in the Wufeng-Longmaxi Shale, and their average reflectance, reflectance distribution, and morphology suggest that they may be derived from graptolite fragments lacking diagnostic features and acritarchs. OM type critically controls the development of organic pores. Here, organic pores primarily occur in pyrobitumen, whereas other macerals are mostly non-porous when examined under the SEM. Results of this study provided important insights into OM thermal evolution and organic pore development in source-rock reservoirs, calling for a critical appraisal of OM in black shales with organic petrography in addition to SEM.

03 NATURAL GAS↗