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At least 19 records
All sourcesNASA NTRSDOE OSTI
DOE OSTI2018

Quantifying dry supercritical CO 2 -induced changes of the Utica Shale

Traditionally, shale formations have been studied as sealing layers that prevent vertical migration of hydrocarbons and CO2 due to their low permeability and fracture porosity. Recent research has focused on storing CO2 in hydrocarbon-bearing shale formations that have already undergone depletion through primary production and using CO2 as a potential fracturing agent for unconventional reservoirs. The injected CO2 will interact with shale components (i.e. clays, organic matter) and affect rock properties through chemical alteration, matrix swelling/shrinkage, and related geomechanical effects. As changes in rock properties will impact both anthropogenic CO2 storage and hydraulic fracturing, it is imperative to increase our understanding of the CO2-shale interactions. In-situ Fourier Transform infrared (FT-IR) spectroscopy coupled with high temperature and pressure capability was used to examine the interaction of dry CO2 on Utica Shale, clay, and kerogen samples at the molecular scale and characterize vibrational changes of sorption bands sensitive to the gas-solid environment. The Utica Shale was also analyzed for micro and macro-scale chemical and physical changes before and after exposure to dry CO2 at subsurface storage conditions using surface relocation techniques via high-resolution field-emission scanning electron microscopy (FE-SEM). Brunauer-Emmett-Teller (BET) surface area/pore size analysis and quantitative adsorption isotherms were applied to understand changes in surface area, pore volumes, and understand the storage potential of CO2 in the Utica Shale sample. FT-IR and feature relocation via FE-SEM indicate carbonate formation and dissolution occurs in shale exposed to dry CO2. Results indicate that etching and pitting occur, with minor calcite precipitation along the surface of the shale sample. Quantitative isotherm results indicate that shales with a higher content of kerogen and illite-smectite clays would be expected to have the highest CO2 storage capacity provided these constituents were accessible for interaction.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Evaluation of Technically-Recoverable Resources in the Marcellus and Utica Shale Gas Plays of the Appalachian Basin

Well production estimates are evaluated to provide estimates of total and remaining technically-recoverable gas resources in the Marcellus and Utica shale gas plays of the Appalachian basin. Domestic gas resources are critical contributors to the United States (U.S.) economy and will be key to enabling the sustainable and carbon-neutral fuel systems of the future. Recent assessments by the Energy Information Administration (EIA) continue to identify resources of the Appalachian region as critical to meeting energy demand, with the Marcellus and Utica- Point Pleasant (“Utica”) shale plays combining for more than 30 percent of projected U.S. domestic natural gas production through 2050.

03 NATURAL GAS↗
DOE OSTI2019

Investigating the role of water on CO2-Utica Shale interactions for carbon storage and shale gas extraction activities – Evidence for pore scale alterations

In this work, we probed the physical and chemical alteration of the carbonate-rich Utica Shale following CO 2 exposure when thin films of water were present at the shale surface. All reaction conditions were examined at 40 °C and CO 2 pressures up to 10.3 MPa for 14 days. CO 2 dissolution in the water layer at 2342 cm -1 and carbonate dissolution and precipitation at 1424, 874, and 712 cm -1 were discerned with in-situ Fourier Transform infrared spectroscopy (FT-IR). Significant etching and pitting from exposure to CO 2 and water were observed with feature relocation scanning electron microscopy (SEM). Application of the density function theory (DFT) for pore size analysis showed that micropores between approximately 0.9 and 2 nm disappeared while the mesopore volume increased after dissolution of carbonate. These results may provide new insights that carbonate rich shales such as the Utica may have a greater potential for alterations of pore space due to the reactivity of CO 2 which may affect 1) how CO 2 storage in shale formations plays a role in Carbon Capture and Storage (CCS) activities, 2) if CO 2 can be utilized as a potential fracturing agent, and 3) whether CO 2 is an effective fluid for enhanced hydrocarbon extraction.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2020

Quantifying Fluid-Wettable Effective Pore Space in the Utica and Bakken Oil Shale Formations

Combined (ultra-) small angle neutron scattering measurements [(U)SANS] and a contrast matching technique were employed to quantify the porosity and pore size distribution from 1 nm to 10 μm and to differentiate accessible (open) pores and inaccessible (closed) pores with respect to organophilic and hydrophilic fluids for two Utica and two Bakken shale samples. Overall, the results indicate that around 40–70% of the pores in the Utica oil shales (mixed carbonate mudstone) are accessible to oil, and 34–37% of the pore surfaces are water-wet. In contrast, the Bakken oil shales (mixed siliceous mudstone and carbonate/siliceous mudstone), which have high total organic carbon contents, have a higher proportion of isolated pore space that is not preferentially wet by oil or water, with less than 36% of the pores accessible to both fluids. In addition, for both formations, pores less than 3 nm in diameter are not oil accessible (organic matter related) but water accessible (clay tactoids related).

58 GEOSCIENCES↗
DOE OSTI2018

A Feature-Based Stochastic Permeability of Shale: Part 1—Validation and Two-Phase Permeability in a Utica Shale Sample

Estimate of permeability plays a crucial role in flow-based studies of fractured tight-rocks. It is well known that most of the flow through tight-rocks (e.g., shales) is controlled by permeable features (e.g., fractures, laminations, etc.), and there is negligible flow through the matrix. However, current approaches in the literature to model permeability of tight-rocks do not account for such features present within the rock ranging from micro-scale to field-scale. Current permeability modeling approach assumes a single continuum without considering the presence of permeable features within the matrix (e.g., micro-fractures) or outside the matrix (e.g., natural fractures). Although the laboratory-measured permeability implicitly captures discrete features present in that sample (e.g., fractures, laminations, micro-fractures), most of the permeability models proposed for shale do not account for these features. Fracture permeability in the literature is typically modeled using an ideal slit assumption; however, this highly overestimates its permeability because fractures in real medium are non-ideal in terms of their porosity and tortuosity, which affect their permeability. Additionally, the transition zone between fracture and matrix also affects the permeability of fracture. Here in this study, part of a two-part series, a new method to predict permeability of fractured shale by discretizing the medium into matrix (inorganic and organic) and fractures is presented. New analytical expressions of permeability are derived to account for non-ideal nature of porous medium and two-phase flow in fractures. Rock feature in each cell of the grid is identified as one of the three elements (organic matter, inorganic matter, or fracture), and permeability of that cell is estimated using a suitable analytical expression. This method allows estimating permeability at any scale of interest and more robustly than by a pure analytical approach. The proposed method is validated against local and global-scale measurements on three fractured samples from laboratory. Finally, the method is used to predict two-phase flow permeability of supercritical CO 2 displacing water within a fracture in a Utica shale sample. The proposed two-phase flow permeability equations can be used as a quick analytical tool to predict relative permeability estimates of two-phase flow in fractured shale samples. In Part 2, the proposed method is used to estimate field-scale permeability through an optimization process that uses field-scale production and other readily available information.

58 GEOSCIENCES↗
DOE OSTI2021

Reactivity of CO 2 with Utica, Marcellus, Barnett, and Eagle Ford Shales and Impact on Permeability

We report that in order to reduce greenhouse gas emissions while recovering hydrocarbons from unconventional shale formations, processes that make use of carbon dioxide to enhance oil recovery while storing carbon dioxide (CO 2 ) should be considered. Here, we examine samples from three shale basins across the United States (Utica and Marcellus Shales in the Appalachian Basin, Barnett Shale in the Bend Arch-Ft. Worth Basin, and Eagle Ford in the Western Gulf Basin) to address the following questions: (1) do changes from reaction with CO 2 and fluids at the micrometer and nanometer scale alter flow pathways and, in turn, impact hydrocarbon production, CO 2 storage, and seal integrity and (2) can CO 2 or fluid reactivity be predicted based on physical or chemical properties of shale formations? Experiments were conducted at 40 °C and 10.3 MPa to characterize the interaction between CO 2 and shale using X-ray diffraction (XRD), carbon and sulfur analysis, in situ Fourier transform infrared spectroscopy (FT-IR), feature relocation scanning electron microscopy coupled with energy-dispersive spectroscopy (SEM-EDS), mercury (Hg) intrusion porosimetry, and Brunauer-Emmett-Teller (BET) surface area and pore size analysis coupled with density functional theory (DFT) methods. Changes in mechanical, physical, and flow properties of shale cores due to CO 2 exposure were addressed using a New England Research Autolab 1500 and Xenon X-ray computed tomography (CT) scanning. Results showed that CO 2 did not promote significant reactivity with the shale if water was not present; only shales with swelling clays or residual interstitial pore water reacted with dry CO 2 to promote reactivity in shale. When water was added as a reactant, CO 2 formed carbonic acid and reacted with the shale to dissolve carbonate pockets, etched and pitted the shale matrix surfaces, and increased the microporosity and decreased nanoporosity. Porosity and permeability increased appreciably in core shale samples after exposure to CO 2 saturated fluid due to dissolution of carbonate. Shale mechanical properties were not altered. Trends were not observed that could tie CO 2 or fluid reactivity to physical or chemical properties of the shale formations at the basin scale from the samples we examined. However, if the shale contained significant amounts of carbonate and water was available to react with the CO 2 , pore sizes were altered in the matrix and permeability and porosity increased.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2022

Chemical and isotopic evolution of flowback fluids from the Utica Gas Shale Play, Eastern Ohio USA

For this work, hydraulic fracturing flowback fluids were collected from two Utica/Point Pleasant well pads in eastern Ohio. One site was in the wet gas zone (UPPW), while the site ~50 km south consisted of four wells on the same pad in the dry gas zone (UPPS). Samples of input fluids also were collected before and during hydraulic fracturing. Flowback fluids are Na-Ca-Cl brines with total dissolved salt (TDS) concentrations that increase over several months from ~100 to 200 g/L. The slightly higher TDS of the dry gas fluids are in part due to recycled flowback used as input fluids, and in part due to lower volume of water used in hydraulic fracturing. Concentrations of most major ions (Ca 2+ , Mg 2+ , Na + , Sr2 + , Fe, Mn, Cl – , Br – ) are similar for the five wells sampled, although small but systematic changes occur in the major element ratios over time. Most notably, an increase in the Sr/Cl ratio corresponds to an increase in the 87 Sr/ 86 Sr ratio in the fluids, suggesting interactions with a more radiogenic Sr source in the subsurface. Dissolved Ba concentrations and Ra activities were different between the two sites, reflecting a high SO 4 2– fluid used at the UPPW site, and water-rock reactions occurring during hydraulic fracturing at the UPPS site. Water oxygen (δ 18 O) and hydrogen (δD) isotopes for input fluids used in the UPPW4 well and fresh water used for the UPPS wells fall on the Global Meteoric waterline (GMWL). Flowback fluids from both sites are relatively enriched in δ 18 O and δD compared to the input, but do not appear to follow a simple mixing trend, suggesting reaction and isotopic exchange with carbonates and fractionation due to imbibition in the rock. Cl isotopes, δ 37 Cl in the FP fluids varied from ~ –0.43 to +0.13‰, the largest variation was observed in the earlier stages of flowback, while in the later stages δ 37 Cl exhibited a small but systematic increase over time, suggesting diffusion control of isotopic composition. Some of the trace species measured (dissolved Fe, Mn, thiosulfate and organic acids) do not follow the same trends as the major ions, suggesting contributions from input fluids, or microbially mediated reactions are exerting control on their concentrations. Input water chemistry exerts an important control on the Sr and Ba concentrations in flowback water. High SO 4 2– in the input fluids used for hydraulically fracturing the wet gas well leads to precipitation of barite-celestite in flowback fluids.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2022

Using Natural Gas Liquids to Recover Unconventional Oil and Gas Resources (Final Report)

This document presents final technical findings for the project Using Natural Gas Liquids to Recover Unconventional Oil and Gas Resources (FE0031782). The project is part of the U.S. Department of Energy Oil and Gas Program to develop and advance technologies that can significantly improve the recovery efficiencies of unconventional oil and gas resources. The overall objective of this project is to improve the ultimate recovery from unconventional oil and gas (UOG) resources in the United States by developing a method for using unrefined natural gas liquids (NGLs) as treatment fluids to improve hydrocarbon production. Horizontal extended-lateral drilling coupled with high volume hydraulic fracturing has significantly increased production from UOG resources in the U.S. However, the recovery efficiency is low compared to the estimated oil and gas in place. Recent data indicate that less than 10% of the oil in the liquid-rich UOG reservoirs is produced. Alternative completion methods using NGLs could increase production (Battelle, 2016; Wan et al., 2013; Wan, 2013; Downey et al, 2021); however, field validation tests are needed to develop an approach that is economical, efficient, and compatible in the UOG setting to advance towards commercial deployment. This project aims to develop and field test a method to improve recovery of oil resources in UOG shale plays by using Y-Grade NGLs, or a similar combination of NGLs, as treatment fluids. Refined NGLs have been used as a hydraulic treatment fluid in UOG plays for decades and are shown to be particularly effective because their miscibility with oil allows oil to flow more freely; however, the use of Y-Grade (unrefined) NGLs has not been studied. The use of Y-Grade NGLs would be advantageous over refined NGLs because Y-Grade NGLs do not require infrastructure or investment in refining and are already being produced from many UOG reservoirs. The concept was tested and monitored in the field at a commercial well site owned by project partner Hopco, Ltd. The project team, which consists of multiple oil and gas operators, Linde Gas North America LLC (Linde) and the Ohio Division of Geological Survey (ODGS), has extensive experience with oil and gas production in the Appalachian basin and the ability to work together quickly to solve technical issues and research needs. A key part of the proposed work was the use of existing wells for field testing and monitoring. A total of four wells (three vertical and one horizontal) were available for this project. One of the vertical wells was utilized as the test well for the NGL treatment test. A nearby vertical well was used for microseismic monitoring. The remaining vertical well and the horizontal well provided a baseline for typical UOG production in the oil window of the Utica/Point Pleasant (UPP). Major technical tasks of the project include characterization of the geotechnical properties of the UPP with an emphasis on the field site; design and planning for the NGLs testing; field testing and monitoring; analysis and integration of field data; and economic and resource/reserve assessment. The Shoman monitoring well and Doughty NGL treatment well were successfully plugged back during September-October 2020 in preparation for treatment and monitoring. A nitrogen diagnostic fracture injection test (DFIT) was completed on the Doughty well on July 22, 2021, consisting of 133,000 scf (91 Bbl.) of nitrogen. A nitrogen foam frac was completed in the Utica-Point Pleasant interval on August 17, 2021 with funding from outside sources. A microseismic monitoring array was installed in the Shoman well and monitored microseismic activity during the Doughty well frac job. Y-Grade NGL injection commenced on August 26, 2021. A total of 215 Bbl. was injected but the job was shut down due to a small leak on the suction hose on the pump truck. The Y-Grade treatment resumed on August 27, 2021 and an additional 726 Bbl. of Y-Grade NGL was injected at a well head pressure of 3850 psi. Total volume of injected Y-Grade over the two days of injection was 941 Bbl. The well was shut-in for 17 days following injection to allow the Y-Grade NGLs to soak on the formation. Y-Grade treatment flow back commenced on 9/13/2021 on a weekly basis. Production data, including surface pressures, oil, nitrogen, natural gas, and flow times was measured and recorded. Periodic gas samples were collected and analyzed to determine composition of flowback gas. As of July 2022, the treatment well had produced 726 Bbl of oil and 2,888 mcf gas. In August 2022, tubing and packer in the well were removed and a pump was installed to enhance oil recovery. Currently, the operator is producing the well about 2 days a week for a few hours. The performance of the NGL treatment test was evaluated based on reservoir simulations of the treatment process, processing of well testing data, analysis of micro seismic monitoring data, and production data analysis. This analysis suggested that oil production in the small test would continue through 2025. Upscaling the treatment to a horizontal Utica Point-Pleasant well would allow more oil recovery, but the process would involve more investment, services, and operational support. An economic analysis was conducted for scenarios aimed at upscaling the NGL treatment process for more typical horizontal UPP wells in the Appalachian Basin.

02 PETROLEUM↗
DOE OSTI2018

Discontinuities in effective permeability due to fracture percolation

Motivated by a triaxial coreflood experiment with a sample of Utica shale where an abrupt jump in permeability was observed, possibly due to the creation of a percolating fracture network through the sample, we perform numerical simulations based on the experiment to characterize how the effective permeability of otherwise low-permeability porous media depends on fracture formation, connectivity, and the contrast between the fracture and matrix permeabilities. While a change in effective permeability due to fracture formation is expected, the dependence of its magnitude upon the contrast between the matrix permeability and fracture permeability and the fracture network structure is poorly characterized. We use two different high-fidelity fracture network models to characterize how effective permeability changes as percolation occurs. The first is a dynamic two-dimensional fracture propagation model designed to mimic the laboratory settings of the experiment. The second is a static three-dimensional discrete fracture network (DFN) model, whose fracture and network statistics are based on the fractured sample of Utica shale. Once the network connects the inflow and outflow boundaries, the effective permeability increases non-linearly with network density. In most networks considered, a jump in the effective permeability was observed when the embedded fracture network percolated. We characterize how the magnitude of the jump, should it occur, depends on the contrast between the fracture and matrix permeabilities. For small contrasts between the matrix and fracture permeabilities the change is insignificant. However, for larger contrasts, there is a substantial jump whose magnitude depends non-linearly on the difference between matrix and fracture permeabilities. A power-law relationship between the size of the jump and the difference between the matrix and fracture permeabilities is observed. In conclusion, the presented results underscore the importance of fracture network topology on the upscaled properties of the porous medium in which it is embedded.

36 MATERIALS SCIENCE↗
DOE OSTI2018

Herrick Well

Data generated at the National Energy Technology Laboratory, Morgantown WV from the Herrick 3HM well. API 34-111-2-4401-00-00 Lat/Long = 39.6572 N/80.9847W Monroe County, Ohio Core obtained by Eclipse Resources. Please see the following report for additional details: Brown, S.; Crandall, D.; Moore, J.; Mackey, P.; Carr, T.; Panetta, B. CT Scanning and Geophysical Measurements of the Utica Formation from the Herrick 3H Well; NETL-TRS-X-2018; NETL Technical Report Series; U.S. Department of Energy, National Energy Technology Laboratory: Morgantown, WV, 2018; p 94.

Computed Tomography↗
DOE OSTI2021

A machine-learning inverse model framework for rapid forecasting and history matching in unconventional reservoirs

Model-based optimization for real-time forecasting in unconventional reser-voirs requires novel methods and work?ows since the strategies and work?ows used in conventional reservoirs are either inapplicable, or prohibitively expen-sive and time-consuming. Insu?cient site data and computational expense of high-?delity simulations mean that work?ows with high-?delity simulations are not ideal for usage in comprehensive uncertainty quanti?cation stud-ies that require 1000s of forward model runs. We present an alternative, novel work?ow for unconventional reservoirs, based on the interplay between reduced-order models and machine-learning. Our physics-informed machine-learning (PIML) work?ow addresses the challenges to real-time reservoir management in uncoventionals, namely lack of data (the time-frame for which the wells have been producing), and computational expense of high-?delity modeling. We use the machine-learning paradigm of transfer-learning to bind together fast but less accurate reduced-order models with slow, but accurate high-?delity models and circumvent the di?culties inherent in the current state-of-the-art for unconventionals. Such a PIML work?ow, grounded in physics, is a viable candidate for real-time history matching and production forecasting in a fractured shale gas reservoir. The signi?cance of our approach is that while it is developed for a particu-lar well and site in the Marcelus Shale gas reservoir of the Appalachian basin (MSEEL), it is not wedded to it. We expect the same work?ow can be ap-plied to other shale formations (e.g., Woodford, Barnett, Utica, EagleFord) should site-data become available, using the same set of machine-learning techniques from transfer learning. Some ?ne-tuning (or minimal retraining of the neural networks) will be required to transfer knowledge across shale gas sites/formations but it is a clearly superior alternative to developing a new machine-learning model altogether when considering a di?erent site.

Srinivasan, Shriram↗
DOE OSTI2021

Toxicity of hydraulic fracturing wastewater from black shale natural-gas wells influenced by well maturity and chemical additives

Hydraulic fracturing of deep shale formations generates large volumes of wastewater that must be managed through treatment, reuse, or disposal. Produced wastewater liberates formation-derived radionuclides and contains previously uncharacterized organohalides thought to be generated within the shale well, both posing unknown toxicity to human and ecological health. Here, we assess the toxicity of 42 input media and produced fluid samples collected from four wells in the Utica formation and Marcellus Shale using two distinct endpoint screening assays. Broad spectrum acute toxicity was assessed using a bioluminescence inhibition assay employing the halotolerant bacterium Aliivibrio fischeri, while predictive mammalian cytotoxicity was evaluated using a N-acetylcysteine (NAC) thiol reactivity assay. The acute toxicity and thiol reactivity of early-stage flowback was higher than later produced fluids, with levels diminishing through time as the natural gas wells matured. Acute toxicity of early stage flowback and drilling muds were on par with the positive control, 3,5-dichlorophenol (6.8 mg L -1 ). Differences in both acute toxicity and thiol reactivity between paired natural gas well samples were associated with specific chemical additives. Samples from wells containing a larger diversity and concentration of organic additives resulted in higher acute toxicity, while samples from a well applying a higher composition of ammonium persulfate, a strong oxidizer, showed greater thiol reactivity, predictive of higher mammalian toxicity. Both acute toxicity and thiol reactivity are consistently detected in produced waters, in some cases present up to nine months after hydraulic fracturing. These results support that specific chemical additives, the reactions generated by the additives, or the constituents liberated from the formation by the additives contribute to the toxicity of hydraulic fracturing produced waters and reinforces the need for careful consideration of early produced fluid management.

03 NATURAL GAS↗