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At least 127 records · Page 7
All sourcesNASA NTRSDOE OSTI
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

Reduced methane recovery at high pressure due to methane trapping in shale nanopores

By 2050, shale gas production is expected to exceed three-quarters of total US natural gas production. However, current unconventional hydrocarbon gas recovery rates are only around 20%. Maximizing production of this natural resource thus necessitates improved understanding of the fundamental mechanisms underlying hydrocarbon retention within the nanoporous shale matrix. In this study, we integrated molecular simulation with high-pressure small-angle neutron scattering (SANS), an experimental technique uniquely capable of characterizing methane behavior in situ within shale nanopores at elevated pressures. Samples were created using Marcellus shale, a gas-generative formation comprising the largest natural gas field in the United States. Our results demonstrate that, contrary to the conventional wisdom that elevated drawdown pressure increases methane recovery, a higher peak pressure led to the trapping of dense, liquid-like methane in sub-2 nm radius nanopores, which comprise more than 90% of the measured nanopore volume, due to irreversible deformation of the kerogen matrix. These findings have critical implications for pressure management strategies to maximize hydrocarbon recovery, as well as broad implications for fluid behavior under confinement.

58 GEOSCIENCES↗
DOE OSTI2020

Integrated Mid-Continent Stacked Carbon Storage Hub Project Phase II (Final Summary Report)

The Phase II Integrated Midcontinent Stacked Carbon Storage Hub (IMSCS-HUB) is part of the Carbon Storage Assurance Facility Enterprise (CarbonSAFE) established by the United States Department of Energy (DOE) National Energy Technology Laboratory (NETL). CarbonSAFE is phased to support the development of commercial-scale (50 million metric tonnes [Mt] over a 30-year period) carbon capture, utilization, and storage (CCUS) in the United States. The IMSCS-HUB study area comprises carbon dioxide (CO 2 ) sources in Iowa, Kansas, and Nebraska (the source corridor), and CO 2 sinks in Kansas and Nebraska (the storage corridor), representing the first large-scale project for the Midcontinent region. The stacked storage corridor is characterized by alternating sequences of deep saline formations, oil-bearing reservoirs, shale, and evaporite units that are conducive to vertically stacked CO 2 injection for geologic storage and enhanced oil recovery (EOR). Three sites within the IMSCS-HUB stacked storage corridor were evaluated in Phase II for commercial CCUS feasibility: one in southwest-central Nebraska, Sleepy Hollow Field (SHF), a second in southwestern Nebraska near Madrid (Madrid), and a third in southwestern Kansas, the Patterson Site (composed of the Patterson, Heinitz, Hartland, and Oslo fields). In Phase II, the team assessed the feasibility of storage complexes at the potential storage sites in Nebraska and Kansas to support a commercial-scale storage hub that integrates proven CO 2 capture technology and transport from nearby ethanol sources. Building on lessons learned from the DOE-NETL Regional Carbon Sequestration Partnerships (RCSPs), the Project Team has identified a clear strategy to meet DOE’s 2025 objective of commercial carbon capture and storage (CCS) implementation by developing a CO 2 market and infrastructure that relies on multiple ethanol-based CO 2 sources in the short term and the incorporation of multiple coal-fired power plant CO 2 sources when commercial capture is economically viable. The team also leveraged the updated 45Q tax credit to develop capture and transport infrastructure. Commercial-scale CCUS is feasible at two candidate storage sites studied, the Madrid, Nebraska Site and the Patterson Site in Kearny County, Kansas. The Sleepy Hollow Field in Nebraska was found to be an attractive candidate for stacked storage with CO 2 -EOR (Battelle 2020e). Outreach efforts facilitated engagement from industry, government, and research sectors (Battelle and GPI, 2020) and an outreach plan for future phases of the project was developed to address issues that are of concern in the IMSCS-HUB project area (Battelle, 2020f). All components of a CCUS project were determined to be feasible in the IMSCS-HUB region and Risk Mitigation Plan was developed and includes strategies to mitigate risks associated with each project component (Battelle, 2020j). A roadmap was developed to obtain the required UIC permits for an integrated CCUS project (Battelle, 2020k). The regional storage resource characterization demonstrated significant opportunity for commercial-scale projects in the IMSCS-HUB storage corridor with 577.4 Mt of stacked CO 2 storage capacity and the potential to produce 181.9 MMbbls of oil via EOR across 17 individual storage areas (Battelle and ARI, 2020). The pipeline assessment study found viable pipeline routes that connected 45Q-eligible ethanol plants, coal fired power plants, and other sources in the IMSCS-HUB corridor. The comprehensive results of subsurface characterization, modeling efforts, outreach assessment, and regulatory analysis from were integrated to develop a Detailed Commercial Development Plan for the IMSCS-HUB (Battelle, 2020n). Commercialization efforts will involve obtaining Class VI UIC permits, establishing and finalizing the pipeline route, and evaluating capture projects at participating CO 2 sources. Phases I and II of the IMSCS-HUB CarbonSAFE provide a strong foundation for safely, efficiently, and cost-effectively characterizing and permitting commercial-scale project sites in the region. The plan for implementation of commercial-scale CCUS projects in the IMSCS-HUB is aligned with the objectives of CarbonSAFE Phase III: Site Characterization and CO 2 Capture Assessment.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2021

A New Modeling Framework for Multi-Scale Simulation of Hydraulic Fracturing and Production from Unconventional Reservoirs

This paper describes a new modeling framework for microscopic to reservoir-scale simulations of hydraulic fracturing and production. The approach builds upon a fusion of two existing high-performance simulators for reservoir-scale behavior: the GEOS code for hydromechanical evolution during stimulation and the TOUGH+ code for multi-phase flow during production. The reservoir-scale simulations are informed by experimental and modeling studies at the laboratory scale to incorporate important micro-scale mechanical processes and chemical reactions occurring within the fractures, the shale matrix, and at the fracture-fluid interfaces. These processes include, among others, changes in stimulated fracture permeability as a result of proppant behavior rearrangement or embedment, or mineral scale precipitation within pores and microfractures, at µm to cm scales. In our new modeling framework, such micro-scale testing and modeling provides upscaled hydromechanical parameters for the reservoir scale models. We are currently testing the new modeling framework using field data and core samples from the Hydraulic Fracturing Field Test (HFTS), a recent field-based joint research experiment with intense monitoring of hydraulic fracturing and shale production in the Wolfcamp Formation in the Permian Basin (USA). Below, we present our approach coupling the reservoir simulators GEOS and TOUGH+ informed by upscaled parameters from micro-scale experiments and modeling. We provide a brief overview of the HFTS and the available field data, and then discuss the ongoing application of our new workflow to the HFTS data set.

58 GEOSCIENCES↗
DOE OSTI2022

Effects of Supercritical CO 2 Injection on the Shale Pore Structures and Mass Transport Rates

Characterizing the pore structures and transport properties of low-permeability shales is critical for evaluating these formations as potential seals or storage sites for geological CO 2 sequestration. Here, we use low-pressure gas adsorption in conjunction with nuclear magnetic resonance (NMR) to characterize the pore-size distribution of shales before and after injection of supercritical CO 2 . Nitrogen gas was used as the detecting phase for the adsorption experiments and pentane liquid was used for the NMR experiments. We also performed time-resolved NMR and gravimetric microbalance measurements to observe mass transport during desaturation. We use these data to estimate the self-diffusion coefficient of pentane and changes in the saturation state of the pore network. We analyzed samples with a range of compositions from the Wolfcamp shale before and after exposure to supercritical CO 2 for 3 days. Integrating the gas adsorption and NMR data shows how supercritical CO 2 injection alters the pore-size distribution for pore sizes <1 nm to 1 mm. Finally, our results provide insights on how the pore structure and mass transport properties of different shale lithologies may evolve during storage of supercritical CO 2 .

58 GEOSCIENCES↗
DOE OSTI2024

Estimating Lithium Fluxes from Produced Water: Marcellus Shale and Beyond

This talk summarizes the potential for critical minerals extraction from produced water and the current data constraints on making these evaluations. First, we present results from production simulations carried out using data from the Marcellus shale showing the lithium resource potential from this formation. Second, we broaden our estimations to show the critical mineral resource estimates from U.S. domestic shale operations. Lastly, we conclude with an overview of the NEWTS database and dashboard where we host the data used in our assessments.

Mackey, Justin↗
DOE OSTI2022

Experiments and Modeling of Proppant Embedment and Fracture Conductivity for the Caney Shale, Oklahoma, USA

ABSTRACT: The ultimate aim of hydraulic fracturing is to have a long and conductive flow path that extends from the wellbore into the formation. The effective fracture length is part of a hydraulically propped fracture which contributes to production. The difficulty in achieving economical production targets from shale reservoirs is at the forefront in many exploration companies. Fracture conductivity loss is related to; proppant embedment under depletion, proppant crushing, damage as a result of fracturing fluid, fines migration and proppant-pack permeability-damage are some of the factors that contribute to production decline after hydraulic fracturing in shale reservoirs. The Caney Shale is a calcareous organic-rich mudrock. Various studies have investigated the effect that clay on shale well productivity, however, there is currently no literature on the Caney shale in relation to horizontal wells; all available literature exists in vertical wells as well as on formations of the Caney that are shallow in comparison to an emerging play which is twice the depth. In this paper we investigate stress-dependent fracture conductivity of proppant-filled fractures and proppant embedment in Caney shale through laboratory and modeling studies. API fracture conductivity tests were conducted using 2% KCl on five locations within the Caney shale that consisted of selecting three brittle(reservoir) zones and two ductile zones. Confining pressures range from 1,000 psi to 12,000 psi at 210°F. Conductivity, permeability as well as embedment were measured during the test. Our experimental results have confirmed that improved fracture conductivity is attributed to; proppant size, the increase in porosity of the proppant pack, closure pressure changes and the reduction in fracture conductivity are a function of many factors such as fracture closure stress. The findings from this study could help the stimulation design by providing new insights into the critical factors that are to be determined to facilitate the choice of proppants as well as fracturing fluids for long term production and recovery from shale reservoirs. 1 INTRODUCTION The development of low permeability formations, like shales, has been aided by hydraulic fracturing of horizontal wells (Radonjic et al., 2020). Hydraulic fracturing fluid is injected at a high pressure to induce tensile fractures that can link to and stimulate natural fractures (Katende et al., 2021a,b). Preserving adequate conductivity in hydraulic fractures over the life of the wells is required for economic production; nevertheless, conserving such conductivity can be difficult in some circumstances, particularly in soft, clay-rich formations (Wang et al., 2021). Proppant particles help to keep the fractures open when the pumping stops and the fracturing fluid returns to the wellbore, producing one or more propped hydraulic fractures of varying length, breadth, and height (Katende et al., 2021a). The proppant pack within the hydraulic fracture boosts well output by providing a greater permeability flowpath for hydrocarbons (Duenckel et al., 2016). Proppant in the fracture is under complicated stress conditions, and the interplay between the rock formation and the proppant pack has a significant impact on proppant-pack permeability (Karazincir et al., 2019). Proppant may be embedded (Katende et al., 2021a) in the rock or crushed into small pieces if the proppant size and strength characteristics are not specified appropriately, resulting in a loss in proppant-pack permeability and fracture aperture, and consequently a fall in well output.

Katende, A.↗
DOE OSTI2022

Preparation of illite coated geomaterial microfluidic surfaces: Effect of salinity and heat treatment

Unique characteristics of clay (e.g., high surface area, deficiency in positive charges) make any clay abundant shales a good source of adsorbed gas. However, the presence of clay in porous media can also affect shale rock's producibility. The clay-water interaction can cause significant swelling and fines migration in the formation and impair the overall hydrocarbon recovery from shale. Geomaterial micromodels, developed by functionalizing traditional glass or PDMS surfaces with geomaterials (e.g., calcite, Quartz, clay), can represent the physicochemical properties of the natural porous media and have been used during the last few years to understand and evaluate the solid-fluid physicochemical interactions. Here, this study focuses on developing a clay-coated geomaterial surface and investigates the effect of base fluid's salinity on clay adsorption to the glass surface. Glass capillary tubes and straight channel borosilicate glass micromodels are coated with Illite clay to represent the pore-scale clay chemistry of Caney Shale, a Mississippian unconventional play in Southern Oklahoma, USA. 10 wt% of Illite clay slurries made with brines of four different salinities are used to coat the glass-capillary tubes to understand the effect of salinity in clay adsorption on the glass surface and overall coating quality. To achieve a stable coating and evaluate the impact of heat treatment on coating's stability, straight channel glass flow cells coated with Illite clay are heat-treated at low (25 °C) and high temperature (125 °C), and the results are compared with an untreated coated surface. Flooding tests were carried out with brines of different salinities on the coated surface to evaluate the stability of the coating. The experimental results indicated a strong relationship between the brine's salinity and the adsorption of clay particles on the glass surface. An increase in brine concentration resulted in improved adsorption of clay particles on the glass surface. Experiments involving heat treating the glass surface following the coating demonstrated significant improvement in the stability of the coating.

02 PETROLEUM↗
DOE OSTI2024

Caprock Remains Water Wet Under Geologic CO 2 Storage Conditions

Abstract Carbon storage technology is primarily targeted in saline formations, which is a porous rock matrix filled with brine, sealed with a low permeability caprock. There are significant variations of CO 2 wetting properties, typically reported in the literature as contact angle of CO 2 and brine interacting with a rock material, suggesting that CO 2 could become wetting under geostorage conditions and negatively impact containment effectiveness. Here, we performed the first controlled laboratory measurements of CO 2 ‐brine contact angles on shale rocks from low permeability sealing formations with distinctive mineralogic properties—calcite‐rich, quartz‐rich, and dolomite‐rich. We targeted temperatures at 40° and 100°C, pressures at 8.3, 34.5, and 62.1 MPa, and salinity at 35,000 and 260,000 ppm. Results show no significant change in contact angle with mineralogy, temperature, pressure, salinity, and CO 2 bubble size. We conclude that caprocks will remain water‐wet at geologic CO 2 storage conditions and will not lose their capillary sealing capacity.

Tapriyal, Deepak↗
DOE OSTI2022

Geochemical Modeling of Celestite (SrSO 4 ) Precipitation and Reactive Transport in Shales

Celestite (SrSO 4 ) precipitation is a prevalent example of secondary sulfate mineral scaling issues in hydraulic fracturing systems, particularly in basins where large concentrations of naturally occurring strontium are present. Herein, we present a validated and flexible geochemical model capable of predicting celestite formation under such unconventional environments. Simulations were built using CrunchFlow and guided by experimental data derived from batch reactors. These data allowed the constraint of key kinetic and thermodynamic parameters for celestite precipitation under relevant synthetic hydraulic fracturing fluid conditions. Effects of ionic strength, saturation index, and the presence of additives were considered in the combined experimental and modeling construction. This geochemical model was then expanded into a more complex system where interactions between hydraulic fracturing fluids and shale rocks were allowed to occur subject to diffusive transport. We find that the carbonate content of a given shale and the presence of persulfate breaker in the system strongly impact the location and extent of celestite formation. The results of this study provide a novel multicomponent reactive transport model that may be used to guide future experimental design in the pursuit of celestite and other sulfate mineral scale mitigation under extreme conditions typical of hydraulic fracturing in shale formations.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2020

SECARB 2020 Semi-Annual Field Review Reports - Anthropogenic Test

The Southern States Energy Board (SSEB) managed the overall Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III project and the Electric Power Research Institute (EPRI) managed all activities associated with the Anthropogenic Test site. Advanced Resources International, Inc. (ARI) assisted EPRI with the management of site activities. EPRI and ARI followed reporting procedures that included monthly and quarterly technical progress reports, as well as periodic reporting on key field activities. Subsequent sections of this report catalog the field activities and are organized in a semi-annual chronology. The SECARB Anthropogenic Test was the largest demonstration of a fully integrated, pulverized coal-fueled carbon capture and storage (CCS) project in the United States as of 2012 and supports a commercial prototype of CO 2 capture; transportation; subsurface storage; and monitoring, verification, and accounting (MVA); and assessment. The demonstration-scale, post-combustion CO 2 capture facility at Alabama Power Company’s Plant Barry diverted flue gas (25MW equivalent) from its Unit #5 coal burning facility and captured the CO 2 using Mitsubishi Heavy Industries (MHI) KM-CDRTM advanced amine technology. The captured CO2 was compressed at Plant Barry and transported by pipeline to the injection location southeast of Citronelle, Alabama. The Citronelle Project’s geologic storage and MVA sites were located on the flanks of the Citronelle Dome, approximately three miles southeast of the city of Citronelle. The injection zone, the Paluxy Formation, a saline formation that occurs at approximately 9,400 feet and overlies the oil production horizon of the Citronelle oilfield, presents a favorable injection reservoir in terms of areal extent and petrophysical characteristics. The confining zone, the basal shale of the overlying Washita-Fredericksburg Formation, is persistent throughout the Citronelle area and possesses the appropriate criteria to act as an effective CO 2 seal.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2020

Characterization of elastic mechanical properties of Tuscaloosa Marine Shale from well logs using the vertical transversely isotropic model

To avoid steep declines in the Tuscaloosa Marine Shale (TMS) production, wells are fracture-stimulated to release the hydrocarbons trapped in the matrix of the formation. An accurate estimation of Young’s modulus and Poisson’s ratio is essential for hydraulic fracture propagation. In addition, ignoring the highly heterogeneous and anisotropic character of TMS can lead to erroneous stress values, which subsequently affect hydraulic fracture width estimates and the overall hydraulic fracturing process. We have developed an empirical 1D geomechanical model that takes into account VTI anisotropy, and it is used to characterize the elastic mechanical properties of TMS in two wells. In the analyzed formation, the vertical Poisson’s ratio is less than the horizontal Poisson’s ratio, which suggests the necessity of an alternative to the ANNIE equations. The stiffness coefficients [Formula: see text] and [Formula: see text] were estimated using the relationships developed from the ultrasonic core data available for the two TMS. Further, correlations between the static and dynamic properties from laboratory tests were used to improve the minimum horizontal stress calculation. We compare VTI Young’s moduli, Poisson’s ratios, and minimum horizontal stress with the isotropic solution. VTI modeling improves the estimation of the elastic mechanical properties. The isotropic solution underestimates the minimum horizontal stress in the formation. Moreover, it was shown that the 20 ft shale interval below the TMS base is characterized by a low Young’s modulus (the vertical Young’s modulus is equal to 20 GPa, whereas the horizontal Young’s modulus is equal to 40 GPa) and may be a frac barrier.

Geochemistry & Geophysics↗
DOE OSTI2022

Effects of time-dependent deformation of shale on the integrity of a geological nuclear waste repository

Safety assessment of geological nuclear waste repositories is essential for the permanent disposal of spent nuclear fuels and high-level radioactive waste. The long-term integrity of the host rock as well as the engineered barrier system (e.g., bentonite buffer) surrounding nuclear waste canisters is of particular importance as decay heat from nuclear waste canisters, which will last over thousands of years, significantly disturbs the thermo-hydromechanical (THM) state of the repository. In this study, THM coupled simulations were carried out to investigate the effect of time-dependent deformation (i.e., creep) of shale on the long-term integrity of a generic subsurface nuclear waste repository. The Norton-Bailey creep model, which is also known as the Lemaitre-Menzel-Schreiner model, was employed to simulate the power-law type creep that is observed in shales. The TOUGH-FLAC simulator was employed for the THM coupled modeling of the repository. The objective of this study is to assess the effect of creep in different shales (i.e., high creep shale vs. low creep shale) on long-term stress and permeability changes in the repository. Results show potential advantages of constructing repositories in the high creep shale, as deviatoric stress levels in the formation decreased to zero in 100 years since the emplacement of nuclear waste canisters and the permeability also decreased to the undamaged, intrinsic levels in 10,000 years. Also, mean effective stress levels in the bentonite buffer increased by 100% in the high creep shale case relative to the low creep shale case at 10,000 years due to creep-induced contraction of the nuclear waste disposal tunnel. However, in earlier periods (e.g., 1000 years), the stress levels in the bentonite buffer were twice smaller in the high creep shale case than in the low creep shale case, which shows a tradeoff between the intermediate- (~1000 years) and long-term (>10,000 years) compaction levels in the bentonite buffer depending on the creep characteristics of the host shale.

12 MANAGEMENT OF RADIOACTIVE AND NON-RADIOACTIVE W↗
DOE OSTI2020

Surface and bulk characterization of reservoir and cap-rocks: Past, present, and future

Geologic formations provide potentially some of the largest volume capacities for CO 2 storage or sequestration. Potential storage sites can be deep saline aquifers, depleted oil reservoirs, and coal seams, surrounded by sealing layers to prevent CO 2 from leaking. It is therefore critical to understand mechanisms contributing to CO 2 trapping and CO 2 leaks. Both phenomena are governed by reactions at the interfaces of the reservoir and cap-rocks and are controlled by the complex chemistry and pore structures of rocks. Mechanisms at the macroscale are affected by the processes occurring at the nanoscale. This review highlights the necessity of multitechnique, multiscale characterization of rocks and points to the importance of surface analysis and surface science studies. Two shale rocks (seals) from Niobrara and Agardhfjellet formations with complex surface chemistry are used as examples throughout the paper. Typically, evaluation of rocks with x-ray diffraction, thermogravimetric analysis, Rock-Eval pyrolysis, gas adsorption, and electron microscopy combined with energy dispersive x-ray spectroscopy is conducted to provide valuable information about the bulk mineralogy, elemental composition, pore volume, and adsorbed species on the sample surface. These studies are necessary prior to designing surface sensitive experiments with x-ray photoelectron spectroscopy (XPS), guiding both sample preparation and sample analysis. XPS has been widely used to study the surface composition of rocks during the investigations of their fine-scale wettability, and the main findings are highlighted here. This paper also reviews the existing literature on ambient-pressure XPS, which provides new opportunities to study in situ chemical alteration due to interactions with CO 2 and offers recommendations for adapting this technique to study rock-fluid interactions, allowing for the identification of fundamental interactions during CO 2 sequestration and guide selection of formation sites for improved storage.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2022

FECM/NETL Unconventional Shale Well Economic Model (UShWEM): Production Data for UShWEM

The Production Data for UShWEM.xlsx is an Excel file that is formatted and organized similarly to the Production Streams sheet of the FECM/NETL Unconventional Shale Well Economic Model (UShWEM). The purpose of this file is to allow the user to import completion design and time-series production data for hundreds of wells into the UShWEM easily and quickly, and have their well data saved safely in an external location. For instructions on how to use the Production Data for UShWEM.xlsx file, see section 2.3 of the FECM/NETL Unconventional Shale Well Economic Model: User’s Manual.

Sheriff, Alana↗
DOE OSTI2022

Carbon dioxide-enhanced metal release from kerogen

Heavy metals released from kerogen to produced water during oil/gas extraction have caused major environmental concerns. To curtail water usage and production in an operation and to use the same process for carbon sequestration, supercritical CO 2 (scCO 2 ) has been suggested as a fracking fluid or an oil/gas recovery agent. It has been shown previously that injection of scCO 2 into a reservoir may cause several chemical and physical changes to the reservoir properties including pore surface wettability, gas sorption capacity, and transport properties. Using molecular dynamics simulations, we here demonstrate that injection of scCO 2 might lead to desorption of physically adsorbed metals from kerogen structures. This process on one hand may impact the quality of produced water. On the other hand, it may enhance metal recovery if this process is used for in-situ extraction of critical metals from shale or other organic carbon-rich formations such as coal.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2024

Investigating Material Properties of Subsurface Rock Formations Modified by Engineering Mineral Precipitation (Final Scientific and Technical Report)

Montana State University’s (MSU) Energy Research Institute (ERI), in collaboration with the Center for Biofilm Engineering (CBE) and the Department of Civil Engineering (CE), has conducted a long‐term research program aimed at developing a novel cementing agent to address wellbore integrity and reduce the unwanted upward migration of fluids and greenhouse gases from the subsurface. The primary technology developed through this research program is known as ureolysis‐induced calcite precipitation (UICP), which harnesses bio‐chemical processes to precipitate calcium carbonate (CaCO 3 ). The same general process can also be called microbially-induced calcium carbonate precipitation (MICP) when microbes provide the process-catalyzing urease enzyme. Both terms are used in this report. Results have conclusively demonstrated that, if properly controlled, UICP can successfully seal fractures, high permeability zones, and compromised cement in the vicinity of wellbores and in nearby caprock. This technology has been successfully deployed to mitigate annular leakage in two test wells and over sixty commercial wells with a 100% success rate. This success in downhole deployment generates consideration of other subsurface applications where UICP could provide benefit to the energy sector, such as shale property modification for unconventional oil and gas recovery. The focus of this research project was to investigate fundamental material and mechanical properties of select shale cores and analyze how these properties change due to engineered mineral precipitation with the intent to control these properties to achieve a range of engineering objectives. Ultimately, the project aim was to identify valuable new areas where application of UICP might contribute to national energy security and environmental protection. The research workplan coupled UICP treatment of core samples, nuclear magnetic resonance (NMR) characterization, and mechanical strength testing at MSU with advanced X‐Ray micro-computed tomography (μCT) imaging and numerical modeling performed by collaborators at two national laboratories, the National Energy Technology Laboratory (NETL) and Lawrence Berkeley National Laboratory (LBNL). Experimental results are useful to inform geo-mechanical models which could be applied to predict mineralized rock formation behavior at field scale. Our findings suggest that NMR and μCT methods to detect and quantify biomineral formation in shale fractures are complementary and consistent with each other. Either could be used to estimate the volume of new mineral formed by UICP in shale fractures. The use of surfactants and guar gum to enhance biomineral precipitation in shale fractures merits further research. UICP can, under some conditions, increase the tensile strength of sealed shale fractures beyond that of the intact shale. These findings demonstrate that continued research in this area may be valuable to understanding and improving shale resource recovery techniques.

58 GEOSCIENCES↗
DOE OSTI2021

Factors controlling pore network development of thermally mature Early Palaeozoic mudstones from the Baltic Basin (N Poland)

Understanding the formation of pore space, especially in low porosity shales (as source rocks and as unconventional resources), is critical to the oil and gas industry, since pores control the space available for hydrocarbon and participate in hydrocarbon transport. We examined 87 Ordovician and Silurian mudstone samples collected from four wells located in the Pomeranian part of the Baltic Basin (northern Poland), one of the primary Polish targets for hydrocarbon exploration. These samples represent the Pelplin, the Paslek, the Jantar, the Prabuty, and the Sasino Formations, which still requires more detailed porosity studies. Our study aimed to identify factors controlling porosity development, by applying bulk techniques (organic petrology and TOC analyses, quantitative mineralogy, and porosimetry) as well as nano- to microscale techniques (thin section petrography, electron microscopy). The studied samples are mainly argillaceous mudstones. The results of porosimetry measurements, combined with image analysis, indicate that the pores of all studied rocks are dominated by micropores (pores < 2 nm in diameter), mesopores (2-50 nm in diameter) and small macropores. The SEM images showed three main pore types: a) voids related to clay mineral aggregates, b) pores inside organic matter particles, and c) pores between other mineral grains. In the Jantar and Sasino mudstones, the organic matter content and its thermal maturity control porosity. The occurrence of solid bitumen in the rocks from these formations reduces samples’ mesoporosity because of the pore-clogging effect. In contrast, in the Paslek and Prabuty Formations, there is low organic matter content and specific surface area and the volume of mesopores increase with clay minerals content. In the Pelplin mudstones, there are no prevailing factors controlling porosity. As a result, we suggest that a combination of SEM image analysis and dual liquid porosity (DLP) measurements is a powerful method to assess porosity available for petroleum flow in mudstones.

03 NATURAL GAS↗