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At least 163 records · Page 9
All sourcesNASA NTRSDOE OSTI
DOE OSTI2018

Armstrong well

Computed tomography and multi-sensor core logger data for the Armstrong well, primarily Marcellus shale, described in Paronish, T.; Mackey, P.; Crandall, D.; Moore, J.; Brown, S.; Carr, T.; Dinterman, P; Jarvis, K. Computed Tomography Scanning and Geophysical Measurements of the Marcellus Formation from the Armstrong #1 Well; NETL-TRS-17-2018; NETL Technical Report Series; U.S. Department of Energy, National Energy Technology Laboratory: Morgantown, WV, 2018; p 60. DOI: 10.18141/1471662.

Core logging↗
DOE OSTI2022

Supplementary Data for "Evaluation of the Economic Implications of Varied Pressure Drawdown Strategies Generated Using a Real-time, Rapid Predictive, Multi-fidelity Model for Unconventional Oil and Gas Wells" by Bello, K., Vikara, D., Sheriff, A., Viswanathan, H., Carr, T., Sweeney, M., O'Malley, D., Marquis, M., Vactor, R.T., and Cunha, L.

The Bello et al. study evaluates the impact of contrasting pressure drawdown on gas productivity and the resulting economics of a well in the Marcellus Shale of the Appalachian Basin. This research applies a techno-economic analysis approach to help identify potential ways pressure management strategies can be used to improve cumulative recovery of hydraulically fractured horizontal wells while maintaining project profitability. Gas production forecast outlook scenarios of the Marcellus Shale Energy and Environment Laboratory Laboratory's MIP-3H well were generated under varying pressure drawdowns using two approaches: 1) a novel physics-informed machine learning (PIML) workflow and 2) via traditional reservoir simulation in Computer Modeling Group’s (CMG) GEM Compositional & Unconventional Simulator. Cash flow and other economic metrics of interest were compiled on the production outlook using the U.S. Department of Energy's (DOE) National Energy Technology Laboratory (NETL) Unconventional Shale Well Economic Model (UShWEM).The sheets within this Microsoft ExcelTM workbook provide the economic metric outputs for the baseline condition and the one-at-a-time (OAT) sensitivity analysis of UShWEM's input parameters for each of the production scenarios evaluated.

Fracture Network Model↗
DOE OSTI2025

"Mining" for Critical Minerals: Critical Minerals from Fossil Energy Waste Byproducts

NETL researcher Mengling Stuckman is an invited speaker for the panel discussion session of "Mining for Critical Minerals" at the Marcellus Shale Coalition event, "Shale 2.0: Learn the Facts about Upstream, Midstream and Downstream". Recent studies from DOE have shown that produced water and drill cuttings from the development of unconventional shale in Appalachia has a significant source of valuable critical minerals and will support bolstering America's supply chain security, putting Pennsylvania in a unique position to capitalize. The panel discussion facilitates obtaining an overview of pipeline capacity needs, downstream users for natural gas and effectively educating and engaging the public relevant to the Marcellus Shale community. The event also offers opportunities for local oil and gas industries, water and waste management companies to work with NETL and participate in FECM’s Critical Mineral program. Industrial feedbacks and participation as outcomes of this invited talk will accelerate the technology and knowledge transfer for the DOE’s Critical Mineral program and for DOE’s mission to unleash American Energy and lead in energy innovation.

critical minerals↗
DOE OSTI2020

Completion design improvement using a deep convolutional network

Maximizing stimulated natural and hydraulic fracture network is one of the primary hydraulic fracturing concerns for economic production from a horizontal shale gas well. Geomechanical facies and preexisting fractures in each stage are identified based on similarities in formation characteristics to optimize the locations of perforation clusters. This often requires analyzing large volumes of drilling, Logging While Drilling (LWD) and Measurement While Drilling (MWD) data. In this paper, we develop a methodology that calculates the mechanical specific energy (MSE) using real-time drill string acceleration signals directly from its definition. High resolution vibration signals have been collected using a tri-axial accerlometer, which was an auxiliary tool included in acoustic borehole imager. This technique provides a cost-efficient solution for engineered completion design. Furthermore, we adopt deep Convolutional Neural Network (CNN) with signal processing to build a data pipeline that effectively extracts patterns from dynamic acceleration signals for rock lateral MSE classification. First, we apply discrete wavelet transform and Short-Time Fourier Transform (STFT) for signal denoising and pattern recognition. Then we construct an image dataset using multi-scale image fusion at pixel level from 3 sensor channels, including axial, lateral acceleration spectrograms and zero-padded revolutions per minute (RPM). The resulted RGB image dataset includes 4,000 images of 5 MSE ranges with various rock strength conditions. Our results demonstrate that the proposed deep learning model can achieve more than 90% classification accuracy. The deep learning results, as a reference source, were applied in selected Marcellus Shale Energy and Environmental Lab (MSEEL) wells engineered completion located in the Marcellus shale gas site.

03 NATURAL GAS↗
DOE OSTI2019

Rare earth elements and radiogenic strontium isotopes in carbonate minerals reveal diagenetic influence in shales and limestones in the Appalachian Basin

Rare earth element (REE) signatures are often applied to interpret paleoenvironmental conditions in sedimentary basins, however the complicated diagenetic histories in dynamic depositional environments can affect interpretation of measured REE signatures. Prior studies on REE content in shales and limestones indicated that REE in specific mineral phases may provide unique information concerning diagenetic reactions occurring in sedimentary rocks during burial and compaction. Application of sequential extraction techniques to target REE signatures in specific mineral fractions may provide greater insight into the complex processes that occurred during diagenesis and catagenesis. Thus, using this technique, this study provides a detailed account for REE, 87 Sr/ 86 Sr, and δ 13 C in the carbonate fraction of the Marcellus Shale and adjacent formations in the Appalachian Basin. A suite of 49 rock samples collected from two cores recovered from Monongalia County, West Virginia, USA was analyzed. The results showed that the carbonate concretions in calcareous shales and carbonate cements in black shales were very distinct. The REE plus yttrium (REY) were more concentrated in the carbonate concretions than in the carbonate cements. The carbonate concretions displayed REY patterns that are closely similar to modern seawater, while MREE-enrichment was observed in the carbonate cements. Likewise, the 87 Sr/ 86 Sr values in the carbonate concretions were similar to those measured for unaltered Middle Devonian carbonates, while the 87 Sr/ 86 Sr in the carbonate cements were much more radiogenic. This observation indicates that the carbonate cement could have been inherited radiogenic 87 Sr expulsed from clays during illite-smectite transition. Overall, this study demonstrated two distinct processes involved with controlling the carbonate geochemistry within Appalachian Basin shales and limestones: one fraction displaying minimal diagenetic alteration relative to depositional conditions (carbonate concretions in calcareous shales and limestone carbonate in limestones), and another fraction displaying the evidence for extensive chemical alteration during illite-smectite transition and catagenesis (carbonate cements in black shales). Here, in addition, highly variable and significant enrichments of U and Mo demonstrate that the Union Spring member and the Lower Oatka Creek member of the Marcellus Shale in the southwestern Appalachian Basin (MSEEL site) were deposited under mainly anoxic environment whereas intermitted episodes of dysoxic to perhaps oxic conditions occurred during the deposition of the Upper Oatka Creek member.

58 GEOSCIENCES↗
DOE OSTI2023

Aperture size distribution, length, and preferential location of bed-parallel veins in shale

Bed-parallel, calcite-filled veins (BPVs) are common in shale formations, and although they have been widely described in other studies, little is known about their population aperture size distribution. To address this knowledge gap, we analyzed BPV sizes in outcrops and cores from the Vaca Muerta Formation, Neuquén Basin, Argentina; in two cores from the Marcellus Formation, Appalachian Basin, northeast Pennsylvania; and in one core from the Wolfcamp Shale, Delaware Basin, West Texas. Nine out of ten aperture size populations follow a negative exponential distribution, with one following a weak power law. Bed-parallel vein size distribution and intensity vary among formations and within the same shale. We define three groups of distributions: (1) Vaca Muerta outcrops, with the highest BPV intensity and the largest BPVs (cumulative frequency of 4.9 BPVs per meter [BPVs/m] for apertures 0.265 mm to 8.7 cm); (2) Vaca Muerta cores with a similar BPV intensity overall but with no apertures wider than 1.2 cm; and (3) Vaca Muerta, Wolfcamp, and Marcellus cores with the fewest BPVs (cumulative frequency up to 0.63 BPVs/m) and very few wider than 1 cm. Aperture and length in two outcrop data sets are weakly positively correlated and follow power laws with exponents of 0.44 and 0.49. Mechanical interfaces at boundaries between different lithologies exert a strong control on BPV location, with 65–75% of observed interfaces having BPVs along them. Only 25–30% of the BPVs occur at observed material interfaces, however, and unless subtle, unobserved mechanical layering is present, other factors must also control location. BPV intensity and organic richness (TOC) from Vaca Muerta well logs are correlated in some instances but not in others, indicating TOC is not always a good proxy for BPV location or intensity. Furthermore, these findings provide useful information for modeling of hydraulic fracture treatments where BPVs may influence development of the stimulated fracture network, for example by limiting height growth.

58 GEOSCIENCES↗
DOE OSTI2019

Shale-fluid interactions during forced lmbibition and flow-back

One way to minimize the need for disposal of flow-back waters produced during the hydraulic fracturing of unconventional reservoirs is, potentially, to recycle these fluids by recovering and re-injecting them during hydraulic fracturing of nearby new wells. These flow-back waters contain, however, large concentrations of dissolved salts. During hydraulic fracturing of unconventional reservoirs, a well may undergo extended shut-in periods, following the initial hydraulic-fracture stimulation. The concern here, therefore, is that the salts dissolved in the re-injected flow-back waters may precipitate in the subsurface, thus promoting scale formation; or alternately, because of their high salinity, these same fluids may cause the dissolution of various minerals present in the subsurface. Large divalent cations (e.g., Ca²⁺, Ba²⁺ and Sr²⁺) and anions (e.g., CO3²⁻ and SO4²) may chemically interact with and cause the swelling of clay fractions, thus blocking pores in certain pore size ranges. All these phenomena (i.e., scale formation, clay swelling, minerals dissolution) can influence the petrophysical properties of the formation, including its permeability, porosity, contact angle, etc. One way to potentially overcome some of these technical challenges, is to pre-treat these flow-back waters, prior to re-injection (e.g., via chemical precipitation, followed by membrane filtration) in order to remove unwanted salts. However, such pre-treatment is costly, and the degree of salt removal needed to prevent formation damage is important in determining the economic viability of flow-back water recycle via re-injection. A key focus of this work, therefore, is to study the impact that the injection of flow-back waters, that have undergone varying degrees of pre-treatment and clean-up, will have on the flow-through characteristics of a tight-gas reservoir, particularly of the Marcellus Shale formation. To do so, we have carried-out forced-imbibition experiments with shale samples from various depths in the Marcellus formation, whose properties span high to low ranges of TOC, clay content and matrix permeabilities. We have studied the forced-imbibition characteristics, at an injection pressure of 24,233 kPa (3500 psig), of various flow-back fluids into shale cores saturated with methane at a pore pressure of 17,338 kPa (2500 psig) and a confining stress of 27,680 kPa (4000 psig). Following the forced imbibition experiments, we analyzed the cores for potential changes in permeability and porosity. Quantification of the ion content of the injected and recovered fluids was also performed using Ion Chromatography (IC). The IC analysis of the recovered fluids indicates substantial interactions and geochemical reactions between the invading fluids and the shale cores. The injection of flow-back fluids shows significant impact on the flow-through characteristics, with untreated flow-back fluids, which have the highest cation and anion content, also exhibiting the highest observable reductions in permeability (>90%).

defects, mechanical behavior, carbon sequestration↗
DOE OSTI2025

Strain-Based Assessment of Shale Caprock during Cyclic Underground Hydrogen Storage

Successful large-scale underground hydrogen storage (UHS) in depleted gas reservoirs depends on the integrity of the overlying caprock to prevent hydrogen loss during cyclic injection and depletion. Prior studies on crushed Marcellus shale, a potential caprock, indicate that cyclic hydrogen injection and depletion induces microstructural changes, increasing porosity and permeability. However, the extent of these changes in intact shale remains unclear. This study presents a strain-based experimental approach to quantify volumetric strain evolution in intact Marcellus shale matrix under unconstrained stress conditions. A quadrant-shaped shale sample without visible fractures underwent eight hydrostatic pore-pressure cycles (injection to 1500 psi and depletion to 500 psi in 250 psi steps). Linear strain gauges measured strain in three orthogonal directions. Results indicate progressive plastic strain accumulation, leading to an ∼12% increase in matrix porosity after eight cycles, with an estimated 19% increase after 30 cycles. This porosity increase follows a logarithmic trend, suggesting a diminishing effect in later cycles. Additionally, permeability and diffusive mass flux are projected to rise by ∼70% over 30 cycles, enhancing hydrogen migration risk. The shale matrix also exhibited mechanical stiffening over successive cycles, limiting large-scale deformation but not preventing porosity enhancement. A new parameter, α, was introduced to characterize shale sensitivity to cyclic loading, aiding UHS caprock assessments. These findings underscore the necessity of incorporating cyclic loading effects in UHS site selection and operational strategies to ensure long-term storage integrity.

08 HYDROGEN↗
DOE OSTI2019

Investigation of Accessible Pore Structure Evolution under Pressurization and Adsorption for Coal and Shale Using Small-Angle Neutron Scattering

Pore structure is an important parameter to quantify the reservoir rock adsorption capability and diffusivity, both of which are fundamental reservoir properties to evaluate the gas production and carbon sequestration potential for coalbed methane (CBM) and shale gas reservoirs. In this study, we applied small-angle neutron scattering (SANS) to characterize the total and accessible pore structures for two coal and two shale samples. We carried out in situ SANS measurements to probe the accessible pore structure differences under argon, deuterated methane (CD 4 ), and CO 2 penetrations. The results show that the total porosity ranges between 0.25 and 5.8% for the four samples. Less than 50% of the total pores are accessible to CD 4 for the two coals, while more than 75% of the pores were found to be accessible for the two shales. This result suggests that organic matter pores tend to be disconnected compared to mineral matter pores. Argon pressurization can induce pore contraction because of the mechanical compression of the solid skeleton in both the coal and shale samples. Hydrostatic compression has a higher effect on the nanopores of coal and shale with a higher accessible porosity. Both methane and CO 2 injection can reduce the accessible nanopore volume due to a combination of mechanical compression, sorption-induced matrix swelling, and adsorbed molecule occupation. CO 2 has higher effects on sorption-induced matrix swelling and pore filling compared to methane for both the coal and shale samples. Gas densification and pore filling could occur at higher pressures and smaller pore sizes. In conclusion, the compression and adsorption could create nanopores in the San Juan coal and Marcellus shale drilled core but could have an opposite effect in the other samples, namely, the processes could damage the nanopores in the Hazleton coal and Marcellus shale outcrop.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2020

Chemical Speciation and Stability of Uranium in Unconventional Shales: Impact of Hydraulic Fracture Fluid

Uranium and other radionuclides are prominent in many unconventional oil/gas shales and is a potential contaminant in flowback/produced waters due to the large volumes/types of chemicals injected into the subsurface during stimulation. In this work, to understand the stability of U before and after stimulation, a geochemical study of U speciation was carried out on three shales (Marcellus, Green River, and Barnett). To do so, two types of samples for each shale were subjected to sequential chemical extractions: unreacted and shale-reacted with a synthetic hydraulic fracture fluid. Furthermore, a significant proportion of the total U (20–57%) was released from these three shales after reaction with fracture fluid, indicating that U is readily leachable. The total U released exceeds labile water-soluble and exchangeable fractions in unreacted samples, indicating that fluids leach more recalcitrant phases in the shale. Radiographic analysis of unreacted Marcellus shale thin sections shows U associated with detrital quartz and the clay matrix in the shale. Detrital zircon and TiO2 identified by an electron microprobe could account for the hot spots. This study shows that significant proportions of U in three shales are mobile upon stimulation. In addition, the extent of mobilization of U depends on the U species in these rocks.

58 GEOSCIENCES↗
DOE OSTI2019

Effect of Water on Fracture Mechanical Properties of Shales

Abstract Recognition of the potential for subcritical fracture growth of rocks is essential for the evaluation of long‐term stability of fluids trapped in geologic structures. In shales, subcritical fracture growth may control migration of hydrocarbons in source rock and unconventional reservoirs and of sequestered CO 2 across top seals. Using the double torsion method, we investigated the mode‐I fracture mechanical properties of three shales of different composition, namely, Woodford Shale, Mancos Shale, and Marcellus Shale, under water‐saturated conditions, in ambient air, and in dry CO 2 gas conditions to systematically investigate the effect of water on the fracture growth properties of shales. The clay‐rich (illite with minor kaolinite) Woodford and Mancos Shales demonstrate a strong water‐weakening effect despite their low smectite content, with the fracture toughness reduced by up to 54% and the subcritical fracture growth index by up to 77% under water‐saturated conditions compared to tests in ambient air. Carbonate‐rich Marcellus Shale, in contrast, displays negligible water‐weakening effects. The clay‐CO 2 interaction is minor for the three shales. Specimens treated with a hydrophobic surface coating were also tested to limit water‐weakening effects to the fracture tip. Data from these tests reveal rate‐dependent stress intensity factor‐velocity curves for clay‐rich Woodford and Mancos Shales suggesting a competition between mechanical fracture growth and physicochemical water‐rock interactions. Our results suggest that subcritical failure by water‐enhanced subcritical fracture growth could significantly increase brittle failure in clay‐rich shales.

Chen, Xiaofeng↗
DOE OSTI2021

Scale–Bridging in Three–Dimensional Fracture Networks: Characterizing the Effects of Variable Fracture Apertures on Network–Scale Flow Channelization

Here, we incorporate observations of real fracture aperture variability observed in laboratory experiments into an ensemble of three-dimensional discrete fracture network (DFN) simulations to characterize how variations of this micro-scale feature can influence flow and transport behavior at the network scale. A shear fracture is created within a Marcellus shale sample, and the fracture aperture is measured using a triaxial direct-shear device coupled with real-time X-ray imaging at in-situ stress conditions. We construct an ensemble of fracture networks based on natural fractures in Marcellus shale and project regions of the experimental aperture field onto each fracture in the networks. Our calculations demonstrate that the degree of flow channelization, a network-scale flow field structure, is dramatically increased by local changes in the aperture field that in turn affects flow and transport properties.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗
DOE OSTI2021

Evaluation of Energy Storage Potential of Unconventional Shale Reservoirs Using Numerical Simulation of Cyclic Gas Injection

Compressed air energy storage (CAES) stores energy as compressed air in underground formations, typically salt dome caverns. When electricity demand grows, the compressed air is released through a turbine to produce electricity. CAES in the US is limited to one plant built in 1991, due in part to the inherent risk and uncertainty of developing subsurface storage reservoirs. As an alternative to CAES, we propose using some of the hundreds of thousands of hydraulically fractured horizontal wells to store energy as compressed natural gas in unconventional shale reservoirs. To store energy, produced or “sales” natural gas is injected back into the formation using excess electricity and is later produced through an expander to generate electricity. To evaluate this concept, we performed numerical simulations of cyclic natural gas injection into unconventional shale reservoirs using cmg-gem commercial reservoir modeling software. We tested short-term (diurnal) and long-term (seasonal) energy storage potential by modeling well injection and production gas flowrates as a function of bottom-hole pressure. First, we developed a conceptual model of a single fracture stage in an unconventional shale reservoir to characterize reservoir behavior during cyclic injection and production. Next, we modeled cyclic injection in the Marcellus shale gas play using published data. Results indicate that Marcellus unconventional shale reservoirs could support both short- and long-term energy storage at capacities of 100–1000 kWe per well. The results indicate that energy storage in unconventional shale gas wells may be feasible and warrants further investigation.

25 ENERGY STORAGE↗
DOE OSTI2021

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

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

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2017

Geomechanical Framework for Secure CO 2 Storage in Fractured Reservoirs and Caprocks for Sedimentary Basins in theMidwest United States

This report presents final technical results for the project Geomechanical Framework for Secure CO 2 Storage in Fractured Reservoirs and Caprocks for Sedimentary Basins in the Midwest United States (DE-FE0023330). The project was a three-year effort consisting of seven technical tasks focused on defining geomechanical factors for CO 2 storage applications in deep saline rock formations in Ohio and the Midwest United States, because geomechancial issues have been identified as a significant risk factor for large-scale CO 2 storage applications. A basin-scale stress-strain analysis was completed to describe the geomechanical setting for rock formations of Ordovician-Cambrian age in Ohio and adjacent areas of the Midwest United States in relation to geologic CO 2 storage applications. The tectonic setting, stress orientation-magnitude, and geomechanical and petrophysical parameters for CO 2 storage zones and caprocks in the region were cataloged. Ten geophysical image logs were analyzed for natural fractures, borehole breakouts, and drilling-induced fractures. The logs indicated mostly less than 10 fractures per 100 vertical feet in the borehole, with mostly N65E principal stress orientation through the section. Geophysical image logs and other logs were obtained for three wells located near the sites where specific models were developed for geomechanical simulations: Arches site in Boone County, Kentucky; Northern Appalachian Basin site in Chautauqua County, New York; and E-Central Appalachian Basin site in Tuscarawas County, Ohio. For these three wells, 9,700 feet of image logs were processed and interpreted to provide a systematic review of the distribution within each well of natural fractures, wellbore breakouts, faults, and drilling induced fractures. There were many borehole breakouts and drilling-induced tensile fractures but few natural fractures. Concentrated fractures were present at the Rome-basal sandstone and basal sandstone-Precambrian contacts at the Arches and East-Central Appalachian Basin sites. Geophysical logs were utilized to develop local-scale geologic models by determining geomechanical and petrophysical parameters within the geologic formations. These data were ported to coupled fluid-flow and reservoir geomechanics multi-phase CO 2 injection simulations. The models were developed to emphasize the geomechanical layers within the CO 2 storage zones and caprocks. A series of simulations were completed for each site to evaluate whether commercial-scale CO 2 could be safely injected into each site, given site-specific geologic and geomechanical controls. This involved analyzing the simulation results for the integrity of the caprock, intermediate, and reservoir zones, as well quantifying the areal uplift at the surface. Simulation results were also examined to ensure that the stress-stress perturbations were isolated within the subsurface, and that there was only limited upward migration of the CO 2 . Simulations showed capacity to inject more than 10 million metric tons of CO 2 in a single well at the Arches and East Central Appalachian Basin sites without excessive geomechanical risks. Low-permeability rock layers at the Northern Appalachian Basin study area well resulted in very low CO 2 injection capacity. Fracture models developed for the sites suggests that the sites have sparse fracture network in the deeper Cambrian rocks. However, there were indicators in image logs of a moderate fracture matrix in the Rose Run Sandstone at the Northern Appalachian Basin site. Dual permeability fracture matrix simulations suggest the much higher injection rates may be feasible in the fractured interval. Guidance was developed for geomechanical site characterization in the areas of geophysical logging, rock core testing, well testing, and site monitoring. The guidance demonstrates that there is a suitable array of options for addressing geomechanical issues at CO 2 storage sites. Finally, a review of Marcellus and Utica-Point Pleasant shale gas wells and CO 2 storage intervals indicates that these items are vertically separated, except for the Oriskany sandstone and Marcellus wells in southwest Pennsylvania and northern West Virginia. Together, project results present a more realistic portrayal of geomechanical risk factors related to CO 2 storage for existing and future coal-fired power plants in Ohio.

58 GEOSCIENCES↗
DOE OSTI2017

Analyzing Solutions High in Total Dissolved Solids for Rare Earth Elements (REEs) Using Cation Exchange and Online Pre-Concentration with the seaFAST2 Unit; NETL-TRS-7-2017; NETL Technical Report Series; U.S. Department of Energy, National Energy Technology Laboratory: Albany, OR, 2017; p 32

The accurate quantification of the rare earth element (REE) dissolved concentrations in natural waters are often inhibited by their low abundances in relation to other dissolved constituents such as alkali, alkaline earth elements, and dissolved solids. The high abundance of these constituents can suppress the overall analytical signal as well as create isobaric interferences on the REEs during analysis. Waters associated with natural gas operations on black shale plays are characterized by high salinities and high total dissolved solids (TDS) contents >150,000 mg/L. Methods used to isolate and quantify dissolved REEs in seawater were adapted in order to develop the capability of analyzing REEs in waters that are high in TDS. First, a synthetic fluid based on geochemical modelling of natural brine formation fluids was created within the Marcellus black shale with a TDS loading of 153,000 mg/L. To this solution, 1,000 ng/mL of REE standards was added based on preliminary analyses of experimental fluids reacted at high pressure and temperature with Marcellus black shale. These synthetic fluids were then run at three different dilution levels of 10, 100, and 1,000–fold dilutions through cation exchange columns using AG50-X8 exchange resin from Eichrom Industries. The eluent from the cation columns were then sent through a seaFAST2 unit directly connected to an inductively coupled plasma mass spectrometer (ICP-MS) to analyze the REEs. Percent recoveries of the REEs ranged from 80–110% and fell within error for the external reference standard used and no signal suppression or isobaric interferences on the REEs were observed. These results demonstrate that a combined use of cation exchange columns and seaFAST2 instrumentation are effective in accurately quantifying the dissolved REEs in fluids that are >150,000 mg/L in TDS and have Ba:Eu ratios in excess of 380,000.

03 NATURAL GAS↗
DOE OSTI2024

Understanding caprock behavior during underground hydrogen storage in depleted gas fields

The poster presents the results of pycnometric analysis of Marcellus and Wolfcamp shales subject to cyclic hydrogen exposure. Results indicate that continued hydrogen exposure results in the increase in matrix permeability and porosity in certain shale types, such as Marcellus. This change is physical in nature, due to the likely creation of microfractures at grain boundaries.

08 HYDROGEN↗
DOE OSTI2026

Innovations Driven by Advanced Characterization to Strategize Critical Mineral Production and Beneficial Reuse from Fossil Energy Waste

Critical minerals (CM), such as rare earth elements (REE), cobalt, nickel, and lithium, have important uses in modern electronics and advanced manufacturing, yet are vulnerable to potential supply chain disruptions. Relatively abundant and readily available fossil energy (FE) wastes, such as coal combustion ash, acid mine drainage (AMD) and treatment solids (AMD solids), and Oil and Gas (O&G) drilling wastes (drill cuttings and produced waters) are under consideration as CM feedstocks. The National Energy Technology Laboratory (NETL) has studied CM resources for various FE wastes as part of the U.S. Department of Energy’s mission of bolstering the domestic CM supply, and makes the data available to the public on EDX at sites such as the NEWTS group. Advanced characterization utilizing synchrotron x-ray techniques coupled with laboratory extractions has been performed to identify CM hosting phases in these FE wastes to inform CM recoverability mechanisms. Novel methods to selectively recover CMs while co-producing other valuable byproducts have been developed. Successful examples discussed here include: (1) The identification of REE/Co/Ni/Sc binding and hosting phases in select FE waste (coal combustion ash and AMD solids), resulting in the development of a patented CM step-extraction process, (2) coupled production of functional sorbents from these extraction wastes and for CM recovery. A pilot-scale testing to evaluate the patent’s technical feasibility for extracting REE from coal ash on a barrel scale has been successfully performed. Additionally, (3) evaluation and measurements of brine geochemistry from U.S. O&G produced waters has informed a high Li recovery potential from Marcellus Shale produced water. NETL researchers have been developing tailored pre-treatment processes, an innovative and highly durable lithium sorbent, and geochemical model guided precipitation to accelerate Li production from the Marcellus Shale produced waters. These innovations driven by characterization are integral for maximizing and advancing the potential for CM recovery while offsetting the cost and environmental footprint for FE waste management.

critical mineral processing↗