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At least 145 records · Page 8
All sourcesNASA NTRSDOE OSTI
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 OSTI2020

Predicting the potential for mineral scale precipitation in unconventional reservoirs due to fluid-rock and fluid mixing geochemical reactions

Mineral precipitation within hydraulically fractured shale may affect fluid flow pathways and impact longterm hydrocarbon production. The ability to predict geochemical reactions that lead to problematic mineral precipitation will lead to active reservoir management strategies to improve overall production. Using the Marcellus Shale as a case study, a combination of laboratory experiments and reaction path modeling was applied to determine which reactions are likely to occur upon introduction of hydraulic fracturing fluid into the shale reservoir. Experimental results indicate that contact between fracturing fluid and shale will result in dissolution of primary minerals (quartz, feldspars, kaolinite, chlorite, pyrite) and secondary mineral precipitation over time periods of less than one week. Precipitation of barite, Fe-oxides, feldspars, amorphous silica and clay is likely to occur within the reservoir during shut in and early flowback due to mixing between fracturing fluid and reservoir brine as based on modeling saturation indices using experimental fluid data. Reaction path modeling of the experimental scenarios corroborates the specific dissolution and precipitation reactions observed experimentally. Comparison of the results to injected and produced waters from a Marcellus Shale well pad in Greene County, PA, USA, shows that the mineral reactions occur during the hydraulic fracturing, shut in, and early flowback periods. The results presented in this paper demonstrate the value in applying experimental approaches to identify mineral precipitation/dissolution reactions that may significantly impact reservoir performance. The good agreement between geochemical models and experimental results provides confidence that numerical models can be applied to screen the potential fluid-mineral and fluid-mixing reactions in unconventional reservoirs that result in undesired mineral scale precipitation.

58 GEOSCIENCES↗
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 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 OSTI2017

TA [2] Continuous, regional methane emissions estimates in northern Pennsylvania gas fields using atmospheric inversions

Natural Gas (NG) production activities in the northeastern Marcellus shale have significantly increased in the last decade, possibly releasing large amounts of methane (CH 4 ) into the atmosphere from the operations at the productions sites and during the processing and transmission steps of the natural gas chain. Based on an intensive aircraft survey, leakage rates from the NG production were quantified in May 2015 and found to be in the order of 0.5% of the total production, higher than reported by the Environmental Protection Agency (EPA) but below the usually observed leakage rates over the shale gases in the US. Thanks to the high production rates on average at each well, leakage rates normalized by production appeared to be low in the northeastern Marcellus shale. This result confirms that natural gas production using unconventional techniques in this region is emitting relatively less CH 4 into the atmosphere than other shale reservoirs. The low emissions rate can be explained in part by the high productivity of wells drilled across the northeastern Marcellus region. We demonstrated here that atmospheric monitoring techniques can provide an independent quantification of NG leakage rates using aircraft measurements. The CH 4 analyzers were successfully calibrated at four sites across the region, measuring continuously the atmospheric CH 4 mixing ratios and isotopic 13 Ch 4 . Our preliminary findings confirm the low leakage rates from tower data collected over September 2015 to November 2016 compared to the aircraft mass-balance estimates in may 2015. However, several episodes revealing large releases of natural gas over several weeks showed that temporal variations in the emissions of CH 4 may increase the actual leakage rate over longer time periods.

03 NATURAL GAS↗
DOE OSTI2013

Assessment of Factors Influencing Effective CO 2 Storage Capacity and Injectivity in Eastern Gas Shales

Building upon advances in technology, production of natural gas from organic-rich shales is rapidly developing as a major hydrocarbon supply option in North America and around the world. The same technology advances that have facilitated this revolution - dense well spacing, horizontal drilling, and hydraulic fracturing - may help to facilitate enhanced gas recovery (EGR) and carbon dioxide (CO 2 ) storage in these formations. The potential storage of CO 2 in shales is attracting increasing interest, especially in Appalachian Basin states that have extensive shale deposits, but limited CO 2 storage capacity in conventional reservoirs. The goal of this cooperative research project was to build upon previous and on-going work to assess key factors that could influence effective EGR, CO 2 storage capacity, and injectivity in selected Eastern gas shales, including the Devonian Marcellus Shale, the Devonian Ohio Shale, the Ordovician Utica and Point Pleasant shale and equivalent formations, and the late Devonian-age Antrim Shale. The project had the following objectives: (1) Analyze and synthesize geologic information and reservoir data through collaboration with selected State geological surveys, universities, and oil and gas operators; (2) improve reservoir models to perform reservoir simulations to better understand the shale characteristics that impact EGR, storage capacity and CO 2 injectivity in the targeted shales; (3) Analyze results of a targeted, highly monitored, small-scale CO 2 injection test and incorporate into ongoing characterization and simulation work; (4) Test and model a smart particle early warning concept that can potentially be used to inject water with uniquely labeled particles before the start of CO 2 injection; (5) Identify and evaluate potential constraints to economic CO 2 storage in gas shales, and propose development approaches that overcome these constraints; and (6) Complete new basin-level characterizations for the CO 2 storage capacity and injectivity potential of the targeted eastern shales. In total, these Eastern gas shales cover an area of over 116 million acres, may contain an estimated 6,000 trillion cubic feet (Tcf) of gas in place, and have a maximum theoretical storage capacity of over 600 million metric tons. Not all of this gas in-place will be recoverable, and economics will further limit how much will be economic to produce using EGR techniques with CO 2 injection. Reservoir models were developed and simulations were conducted to characterize the potential for both CO 2 storage and EGR for the target gas shale formations. Based on that, engineering costing and cash flow analyses were used to estimate economic potential based on future natural gas prices and possible financial incentives. The objective was to assume that EGR and CO 2 storage activities would commence consistent with the historical development practices. Alternative CO 2 injection/EGR scenarios were considered and compared to well production without CO 2 injection. These simulations were conducted for specific, defined model areas in each shale gas play. The resulting outputs were estimated recovery per typical well (per 80 acres), and the estimated CO 2 that would be injected and remain in the reservoir (i.e., not produced), and thus ultimately assumed to be stored. The application of this approach aggregated to the entire area of the four shale gas plays concluded that they contain nearly 1,300 Tcf of both primary production and EGR potential, of which an estimated 460 Tcf could be economic to produce with reasonable gas prices and/or modest incentives. This could facilitate the storage of nearly 50 Gt of CO 2 in the Marcellus, Utica, Antrim, and Devonian Ohio shales.

03 NATURAL GAS↗
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 OSTI2018

CT Scanning and Geophysical Measurements of the Marcellus Formation from the Tippens 6HS Well

The computed tomography (CT) facilities and the Multi-Sensor Core Logger (MSCL) at the National Energy Technology Laboratory (NETL) Morgantown, West Virginia site were used to characterize core of the Marcellus Shale from a vertical well drilled in Eastern Ohio. The core is from the Tippens 6HS Well in Monroe County, Ohio and is comprised primarily of the Marcellus Shale from depths of 5550 to 5663 ft.

58 GEOSCIENCES↗
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↗
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 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

Geochemical characterization of lithium deposition in fossil energy wastes

Lithium is a critical mineral used in rechargeable batteries for electric vehicles (EVs) and future modernization of electric grids with sensitive supply chains that are subject to volatility. Therefore, methods to recover lithium from domestic unconventional sources are actively being pursued in the United States. Herein, we report on the lithium recovery potential from four fossil energy waste feedstocks: oil and gas drill cuttings (sample number n = 16); oil and gas produced waters (n > 200) from Marcellus, Bakken and Permian basins; coal byproducts (n>20), such as coal ash; and acid mine drainage treatment solids (AMD solids). Select solid samples underwent sequential extraction to explore lithium hosting phases and simple organic and inorganic acid extraction to explore lithium recovery potential. Our preliminary results found lithium concentrations up to 440 mg/kg in select AMD treatment solids and up to 300 mg/L in Marcellus Shale produced waters, demonstrating these sources have lithium yield potentials comparable to conventionally mined lithium ores and brines. Sequential extractions revealed that lithium is mostly associated with clay and silicate phases in shale drill cuttings, whereas lithium resides in Fe,Mn-oxide reducible phases in AMD solids. Further, the lithium content in produced waters has a strong linear relationship with total dissolved solid (TDS) levels in three separate oil and gas basins. At the same TDS level, Marcellus Shale produced waters contain more lithium compared to Bakken Shale and Permian Basin waters, with higher percentages of Ca and Mg, major cations that might impact lithium recovery efficiencies. Our study demonstrates the heterogeneity of lithium hosts from different fossil energy wastes. Characterization results will inform future lithium recovery from these different feedstocks.

Stuckman, Mengling↗
DOE OSTI2012

Zero Discharge Water Management for Horizontal Shale Gas Well Development

Hydraulic fracturing technology (fracking), coupled with horizontal drilling, has facilitated exploitation of huge natural gas (gas) reserves in the Devonian-age Marcellus Shale Formation (Marcellus) of the Appalachian Basin. The most-efficient technique for stimulating Marcellus gas production involves hydraulic fracturing (injection of a water-based fluid and sand mixture) along a horizontal well bore to create a series of hydraulic fractures in the Marcellus. The hydraulic fractures free the shale-trapped gas, allowing it to flow to the well bore where it is conveyed to pipelines for transport and distribution. The hydraulic fracturing process has two significant effects on the local environment. First, water withdrawals from local sources compete with the water requirements of ecosystems, domestic and recreational users, and/or agricultural and industrial uses. Second, when the injection phase is over, 10 to 30% of the injected water returns to the surface. This water consists of flowback, which occurs between the completion of fracturing and gas production, and produced water, which occurs during gas production. Collectively referred to as returned frac water (RFW), it is highly saline with varying amounts of organic contamination. It can be disposed of, either by injection into an approved underground injection well, or treated to remove contaminants so that the water meets the requirements of either surface release or recycle use. Depending on the characteristics of the RFW and the availability of satisfactory disposal alternatives, disposal can impose serious costs to the operator. In any case, large quantities of water must be transported to and from well locations, contributing to wear and tear on local roadways that were not designed to handle the heavy loads and increased traffic. The search for a way to mitigate the situation and improve the overall efficiency of shale gas production suggested a treatment method that would allow RFW to be used as make-up water for successive fracs. RFW, however, contains dissolved salts, suspended sediment and oils that may interfere with fracking fluids and/or clog fractures. This would lead to impaired well productivity. The major technical constraints to recycling RFW involves: identification of its composition, determination of industry standards for make-up water, and development of techniques to treat RFW to acceptable levels. If large scale RFW recycling becomes feasible, the industry will realize lower transportation and disposal costs, environmental conflicts, and risks of interruption in well development schedules.

03 NATURAL GAS↗
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 OSTI2024

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

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

Dje, L. B.↗
DOE OSTI2017

Mineral Reactions in Shale Gas Reservoirs: Barite Scale Formation from Reusing Produced Water As Hydraulic Fracturing Fluid

Hydraulic fracturing for gas production is now ubiquitous in shale plays, but relatively little is known about shale-hydraulic fracturing fluid (HFF) reactions within the reservoir. To investigate reactions during the shut-in period of hydraulic fracturing, experiments were conducted flowing different HFFs through fractured Marcellus shale cores at reservoir temperature and pressure (66 °C, 20 MPa) for one week. Results indicate HFFs with hydrochloric acid cause substantial dissolution of carbonate minerals, as expected, increasing effective fracture volume (fracture volume + nearfracture matrix porosity) by 56-65%. HFFs with reused produced water composition cause precipitation of secondary minerals, particularly barite, decreasing effective fracture volume by 1-3%. Barite precipitation occurs despite the presence of antiscalants in experiments with and without shale contact and is driven in part by addition of dissolved sulfate from the decomposition of persulfate breakers in HFF at reservoir conditions. The overall effect of mineral changes on the reservoir has yet to be quantified, but the significant amount of barite scale formed by HFFs with reused produced water composition could reduce effective fracture volume. In conclusion, further study is required to extrapolate experimental results to reservoir-scale and to explore the effect that mineral changes from HFF interaction with shale might have on gas production.

03 NATURAL GAS↗