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At least 145 records · Page 8
All sourcesNASA NTRSDOE OSTI
DOE OSTI2023

Pore Structure and Wettability of Bossier Shale, East Texas, United States: Insights from Integrated Porosimetry, Scattering, and Imbibition Approaches

In this study, ascertaining the pore geometry and wettability characteristics of tight shales is of great significance for revealing the mechanisms of occurrence, migration, and production of shale resources. Taking the Bossier Shale collected from Well A, East Texas, USA, as an example, the pore geometry and wettability behavior in a broad nm-& μm scale pore spectrum were quantified based on integrated techniques, including water immersion porosimetry (WIP), mercury intrusion porosimetry(MIP), (ultra)small-angle X-ray scattering [(U)SAXS], contact angle, and liquid spontaneous imbibition (SI). Mainly owing to differences in the sample sizes used, data interpretation, as well as the detectable pore type (e.g., connected or not) and pore diameter ranges among different methods, sample porosities derived from WIP, MIP, and (U)SAXS were quite different, which range from 7.70 to 13.34%, 5.12 to 9.52%, and 2.48 to 6.44%, respectively. Therefore, a comparison of the porosities derived from different methods must be handled with utmost care. Additionally, although (U)SAXS is an effective technique for detecting both connected and non-connected pores, the fraction of non-connected pores could be underestimated by directly comparing the pore size distribution derived from (U)SAXS and MIP tests. This is because the sample sizes used for and pore information reflected by these two methods are different. Furthermore, the studied Bossier Shales exhibited various contact angle values and imbibition behaviors when using differently polarized liquids, revealing their mixed-wet characteristics. Comprehensively considering the differences in contact angle, imbibition slope, and imbibed liquid volume, three sub-categories of wettability behavior, with respect to more oil-wet, more water-wet, and intermediate mixed-wet, were qualitatively identified.

(U)SAXS↗
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 OSTI2024

Aromatic amino acid metabolism and active transport regulation are implicated in microbial persistence in fractured shale reservoirs

Abstract Hydraulic fracturing has unlocked vast amounts of hydrocarbons trapped within unconventional shale formations. This large-scale engineering approach inadvertently introduces microorganisms into the hydrocarbon reservoir, allowing them to inhabit a new physical space and thrive in the unique biogeochemical resources present in the environment. Advancing our fundamental understanding of microbial growth and physiology in this extreme subsurface environment is critical to improving biofouling control efficacy and maximizing opportunities for beneficial natural resource exploitation. Here, we used metaproteomics and exometabolomics to investigate the biochemical mechanisms underpinning the adaptation of model bacterium Halanaerobium congolense WG10 and mixed microbial consortia enriched from shale-produced fluids to hypersalinity and very low reservoir flow rates (metabolic stress). We also queried the metabolic foundation for biofilm formation in this system, a major impediment to subsurface energy exploration. For the first time, we report that H. congolense WG10 accumulates tyrosine for osmoprotection, an indication of the flexible robustness of stress tolerance that enables its long-term persistence in fractured shale environments. We also identified aromatic amino acid synthesis and cell wall maintenance as critical to biofilm formation. Finally, regulation of transmembrane transport is key to metabolic stress adaptation in shale bacteria under very low well flow rates. These results provide unique insights that enable better management of hydraulically fractured shale systems, for more efficient and sustainable energy extraction.

04 OIL SHALES AND TAR SANDS↗
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 OSTI2021

Computed Tomography Scanning and Geophysical Measurements of the Caney Shale Formation from the Tomaney #1-35-34-27 Well

Evaluation of reservoir samples can support resource estimation and determination of effective extraction methodologies. While it is common for commercial entities to perform these characterizations, the resources necessary to conduct these analyses are not always available to the broader interest base, such as state agencies, universities, and research-based consortiums. To meet the growing need for comprehensive and high-quality lithologic data for collaborative research initiatives, the U.S. Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) has used available resources in conjunction with previous techniques and new, innovative methodologies to develop a systematic approach for the evaluation of cores. This report focuses on the Tomaney #1-35-34-27 well. Tomaney #1-35-34-27 was drilled in southwestern Stephens County, Oklahoma within section 35, township 2S, and range 4W. The Tomaney #1-35-34-27 was drilled in January/February of 2020 and targeted the Devonian Woodford Shale Formation and cored the Mississippian Caney Shale formation within the Ardmore Basin.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2023

Industrial Requirements Status Report and Down-Select of Candidate Technologies

The report discusses the potential for implementing Integrated Energy Systems (IES) using advanced nuclear reactors to provide thermal and electrical energy to carbon-emitting industries while reducing their carbon footprint. Nine different industries were reviewed to determine their decarbonization potential, how nuclear power can fit in, and the carbon footprint of each. The report also identifies specific integration points and streams for most processes, including temperature and pressure requirements of integrating nuclear power with industrial processes. The report also provides insights on advanced nuclear reactors and their potential for us in IES for decarbonization. The target audience for the report is broad, but mainly addressed to the industry leads and nuclear reactor developers. The report recommends that in the short term, a few processes should be identified to continue research and investigation so that front end engineering design work can provide technical analysis for integrating nuclear heat and replacing existing carbon-emitting thermal sources. The work emphasized the significant decarbonization opportunity across each of the technologies looked at as well as how novel and useful nuclear integration is to reduce the environmental impact of these significant industries.

02 PETROLEUM↗
DOE OSTI2022

LANL Activities on Mechanistic Approach to Analyzing and Improving Unconventional Hydrocarbon Production

Hydrocarbon production from shale reservoirs is inherently inefficient and challenging since these are low permeability plays. In addition, there is a limited understanding of the fundamentals and the controlling mechanisms, further complicating how to optimize these plays. Herein, we summarize our experimental and computational efforts fully and partially supported by the fundamental shale portfolio to reveal unconventional shale fundamentals and devise development strategies to enhance extraction efficiency with a minimal environmental footprint. Integrating these fundamentals with machine learning, we outline a pathway to improve the predictive power of our models, which enhances the forecast quality of production, thereby improving the economics of operations in unconventional reservoirs. For instance, we have developed science informed workflows and platforms for optimizing pressure-drawdown at a site, which allow operators to make reservoir-management decisions that optimize recovery in consideration of future production. Recently, our work relies on the hybridization of physics-based prediction and machine learning, whereby accurate synthetic data (combined with available site data) can enable the application of machine learning methods for rapid forecasting and optimization. Consequently, the workflow and platform are readily extendable to operations at other sites, plays, and basins.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2026

Improving Production in the Emerging Paradox Oil Play (Final Technical Report)

This report documents the results of the DOE-funded project Improving Production in the Emerging Paradox Oil Play, focused on integrating geological characterization, petrophysical analysis, reservoir simulation, and field development planning to improve hydrocarbon recovery from the Paradox Basin. Project activities included core and log analysis, assessment of reservoir heterogeneity and compartmentalization, evaluation of completion and stimulation strategies, and development of an uncertainty-aware field development framework. Findings highlight the importance of selective completions, geology-driven well placement, and targeted stimulation in vertically heterogeneous carbonate reservoirs.

02 PETROLEUM↗
DOE OSTI2024

Electrofracturing of Shale at Elevated Pressure

Electrofracturing deeply buried shale formations could be used to increase reservoir permeability and improve reservoir production without requiring large volumes of freshwater. This paper describes a novel experimental system and initial test results to electrofracture shale under high confining pressures. Core-scale laboratory testing was performed on twelve rock samples recovered from a shale gas reservoir. Each sample was subjected to confining pressures of 20.7 MPa (3000 psi) or 58.6 MPa (8000 psi), representative of overburden pressures at depth. Samples were then subjected to application of high voltage until specimen fracture. The experiments produced deformed samples with multiple fracture types, both parallel and oblique to bedding planes. Electrofracturing increased permeabilities by up to nine orders of magnitude for extended time periods. Rock fracture and throughgoing fractures were demonstrated. Computed tomography images revealed the creation of fractures and tube/tunnel flow channels, which resisted closure under hydrostatic pressures up to 58.6 MPa. The breakdown energy and permeability changes in the sample were independent of applied confining pressure. The cumulative energy input required for fracture depended on applied confining pressure and sample length. The energy required to fracture samples up to 9 cm in length is generally more than 0.5 kJ/cm, but no greater than 1 kJ/cm. Our results show that electrofracture of shales under confining pressure is possible and could be a possible water-free mechanism for reservoir stimulation.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2024

Understanding Water Controls on Shale Gas/Oil Mobilization into Fractures (FY 2019-2021(FY2022, No Cost Extension), Final Report)

The large volumes of injected and produced water, and costs associated with both hydraulic fracturing fluids and produced water treatment motivate development of hydraulic fracturing strategies that use water more efficiently. The overall objective of this project is to improve understanding on how water is distributed within unconventional shales during and after hydraulic fracturing in order to provide a more rational basis for reservoir stimulation strategies that increase hydrocarbon recovery per unit of water used. The strong capillary imbibition of water into shale matrix pores and immiscibility with hydrocarbons makes it highly desirable to reduce water use during reservoir development. Given the importance, and competing influences of capillarity and gravity in controlling water in fractured porous media, this project also seeks to understand how these factors interact to obstruct or allow gas flow.

04 OIL SHALES AND TAR SANDS↗
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 OSTI2022

Integrated Experimental and Modeling Study of Geochemical Reactions of Simple Fracturing Fluids with Caney Shale

Interactions between rock minerals and hydraulic fluids directly impact the geochemical and geomechanical properties of shale formations. However, the mechanisms of geochemical reactions in shale unconventional reservoirs remain poorly understood. Here, to investigate the geochemical reactions between shale and hydraulic fracturing fluids, a series of batch reactor experiments were undertaken. Three rock samples with different mineralogical compositions and three fluid samples of different compositions (deionized water, deionized water + 2% potassium chloride (KCl), and deionized water + 0.5% choline chloride (C 5 H 14 ClNO) were used. Experiments were undertaken at reservoir temperature and atmospheric pressure. Elemental compositions of effluents after 1, 3, 7, 14, 28 days were analyzed using Inductively Couple Plasma Mass Spectrometry (ICP-MS). Medical Computed Tomography (CT) scan and X-ray Fluorescence (XRF) were conducted on the entire core run to help upscale results obtained from rock-fluid interaction experiments. Geochemical modeling using a reactive simulator, TOUGHREACT, was undertaken to corroborate experimental results. Results show that lower pH triggered high dissolution rates in the rock samples, especially the carbonate components. As pH increased, the rate of dissolution declined significantly, though for most cases dissolution still continued. Observed dissolved silica concentrations were much higher than the quartz solubility, suggesting that much of the silica originates from more soluble silica polymorphs and possibly desorption from clay mineral exchange sites. Concentration of most elemental species in solution increased but aluminium and magnesium concentrations declined rapidly following initial entry into solution. Geochemical modeling corroborated the conclusions regarding mineral dissolution and precipitation observed from experiments, notably; the dissolution of calcite and oxidation of pyrite in reacted shale samples, the likely presence of silica polymorphs such as opal, chalcedony or amorphous silica in these samples, and the reduction of Al and Mg concentrations in solution by precipitation of secondary aluminosilicate phases. The de-flocculation of clay minerals during reaction implies fines migration after hydraulic fracturing. This is detrimental to reservoir productivity as clay fines are displaces and lodged within the micro and nano-fractures created during fracturing. The immediate consumption of aluminium and magnesium also has implications on blockage of hydrocarbon pathways due to precipitation of new minerals in these locations.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2020

Science-informed Machine Learning to Increase Recovery Efficiency in Unconventional Reservoirs

Production of hydrocarbons from fractured, unconventional reservoirs is inherently inefficient. But machine learning offers a pathway both to increasing recovery efficiency at a site and to improving forecasts of production, thereby improving the economics of operations in unconventional reservoirs. Los Alamos—in partnership with DOE, NETL, and WVU—has been developing a science-informed workflow and platform for optimizing pressure-drawdown at a site, which will allow an operator to make reservoir-management decisions that optimize recovery in consideration of future production. This work relies on a hybridization of physics-based prediction and machine learning, whereby accurate synthetic data (in combination with available site data) can enable the application of machine learning methods for rapid forecasting and optimization. The physics-based prediction is built upon experimental and theoretical work to determine transport characteristics in shale at various scales, with an emphasis on materials from MSEEL-I; this fundamental shale R&D was conducted in partnership with DOE, NETL, and several other national labs. This work has resulted from a coordinated leveraging of developments across several projects within DOE FE30, along with internal investments from Los Alamos via LDRD. The development has utilized data from the MSEEL–I site for calibration and demonstration; however, the workflow and platform are readily extendable to operations at other sites, plays, and basins. This machine-learning method can aid operators to improve both recovery efficiency and competitiveness; to this end, future work would quantify processes for other plays/basins and integrate production details with economics.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Marcellus Shale Energy and Environment Laboratory (MSEEL) (Final Report)

The objective of the Marcellus Shale Energy and Environment Laboratory (MSEEL) was to provide a long-term field site to develop and validate new knowledge and technology to improve recovery efficiency and minimize environmental implications of unconventional resource development. MSEEL initiated in October 2014 and completed in September 2021. Total project value was $\$29,765,067$, support from the US Department of energy totaled $\$16,608,355$ with a cost share of $\$13,156,712$ primarily from Northeast Natural Energy. This report in a departure from previous reports summarizes the overarching results and outlines the approach taken. We cover two recent efforts in machine learning and reservoir characterization and simulation. Numerous quarterly reports, public presentations and numerous external publications cover specific results by subtopic and in detail. Publications are listed in the Appendix.

03 NATURAL GAS↗
DOE OSTI2020

Characterizing Pore-Scale Geochemical Alterations in Eagle Ford and Barnett Shale from Exposure to Hydraulic Fracturing Fluid and CO 2 /H 2 O

As demand increases for an affordable energy source that is tied to an environmental obligation to reduce greenhouse gas emissions and water usage, there is a growing consideration in shale production utilizing processes such as 1) enhancing hydrocarbon recovery via carbon dioxide (CO 2 ) flooding, 2) using CO 2 as a fracturing agent to minimize water use, and 3) storing CO 2 in depleted shale formations to mitigate emissions to the atmosphere. Understanding the geochemical reactions and alterations that occur as shale is exposed to fluids and CO 2 is necessary to develop and optimize each of these processes for field applications. While the majority of shale formations are stimulated using traditional fracturing fluid, some may be fractured using CO 2 or other non-traditional means. We examine the effect fracturing fluid has on shale and how it behaves with secondary exposure to dry CO 2 or CO 2 -saturated water using in situ Fourier Transform infrared spectroscopy (FTIR), feature relocation scanning electron microscopy (SEM), and surface area and pore size analysis using volumetric gas sorption. These techniques were performed on Eagle Ford and Barnett shale samples that were exposed to fracturing fluid and unexposed (as received). Shales that have been exposed to traditional fracturing fluid experienced two reaction fronts. The first reaction front was formed during exposure to the fracturing fluid (pH of ~1.4). A secondary reaction front was formed as a result of CO 2 -saturated fluid exposure in the form of carbonic acid (pH ~5.6). These two different reaction mechanisms drove multiple dissolution and precipitation cycles which altered petrophysical properties of the shale and could lead to a significant impact on flow pathways. FTIR showed that equilibration of carbonate dissolution and precipitation cycles could take as long as 35 days. Samples exposed to fracturing fluid showed significantly less carbonate reactivity compared to those exposed to water. Pore size analysis results indicate exposure to fracturing fluid blocked small nanopores (10-15 nm) reducing BET surface area and total pore volume. SEM results show barite precipitated heavily during exposure to fracturing fluid. It appeared that carbonic acid was able to extract sulfur from organic matter to form gypsum evaporites. The mineralogical (barite precipitation and calcite dissolution/precipitation) and pore-scale alterations observed in these samples may lead to enhancement of flow pathways for injected CO 2 or produced hydrocarbons.

04 OIL SHALES AND TAR SANDS↗