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

Fluid inertia controls mineral precipitation and clogging in pore to network-scale flows

Mineral precipitation caused by fluid mixing presents complex control and predictability challenges in a variety of natural and engineering processes, including carbon mineralization, geothermal energy, and microfluidics. Precipitation dynamics, particularly under the influence of fluid flow, remain poorly understood. Combining microfluidic experiments and three-dimensional reactive transport simulations, we demonstrate that fluid inertia controls mineral precipitation and clogging at flow intersections, even in laminar flows. We observe distinct precipitation regimes as a function of Reynolds number (Re). At low Reynolds numbers (Re < 10), precipitates form a thin, dense layer along the mixing interface, which shuts precipitation off, while at high Reynolds numbers (Re > 50), strong three-dimensional flows significantly enhance precipitation over the entire intersection, resulting in rapid clogging. When injection rates from two inlets are uneven, flow symmetry-breaking leads to unexpected flow bifurcation phenomena, which result in enhanced concurrent precipitation in both downstream channels. Finally, we extend our findings to rough channel networks and demonstrate that the identified inertial effects on precipitation at the intersection scale are also present and even more dramatic at the network scale. This study sheds light on the fundamental mechanisms underlying mixing-induced mineral precipitation and provides a framework for designing and optimizing processes involving mineral precipitation.

Utica/Point Pleasant brine isotopic compositions (δ7Li, δ11B, δ138Ba) elucidate mechanisms of lithium enrichment in the Appalachian Basin

Global Li production will require a ∼500 % increase to meet 2050 projected energy storage demands. One potential source is oil and gas wastewater (i.e., produced water or brine), which naturally has high total dissolved solids (TDS) concentrations, that can also be enriched in Li (>100 mg/L). Understanding the sources and mechanisms responsible for high naturally-occurring Li concentrations can aid in efficient targeting of these brines. The isotopic composition (δ7Li, δ11B, δ138Ba) of produced water and core samples from the Utica Shale and Point Pleasant Formation (UPP) in the Appalachian Basin, USA indicates that depth-dependent thermal maturity and water-rock interaction, including diagenetic clay mineral transformations, likely control Li concentrations. A survey of Li content in produced waters throughout the USA indicates that Appalachian Basin brines from the Marcellus Shale to the UPP have the potential for economic resource recovery.

Environmental impact of solution pH on the formation and migration of iron colloids in deep subsurface energy systems

Deep subsurface stimulation processes often promote fluid-rock interactions that can lead to the formation of small colloidal particles that are suspected to migrate through the rock matrix, partially or fully clog pores and microfractures, and promote the mobilization of contaminants. Thus, the goal of this work is to understand the geochemical changes of the host rock in response to reservoir stimulation that promote the formation and migration of colloids. Two different carbonate-rich shales were exposed to different solution pHs (pH = 2 and 7). Iron and other mineral transformations at the shale-fluid interface were first characterized by synchrotron-based XRF mapping. Then, colloids that were able to migrate from the shale into the bulk fluid were characterized by synchrotron-based extended X-ray absorption structure (EXAFS), scanning electron microscopy (SEM), and single-particle inductively coupled plasma time-of-flight mass spectrometry (sp-icpTOF-MS). When exposed to the pH = 2 solution, extensive mineral dissolution and secondary precipitation was observed; iron-(oxyhydr)oxide colloids colocated with silicates were observed by SEM at the fluid-shale interfaces, and the mobilization of chromium and nickel with these iron colloids into the bulk fluid was detected by sp-icpTOF-MS. Iron EXAFS spectra of the solution at the shale-fluid interface suggests the rapid (within minutes) formation of ferrihydrite-like nanoparticles. Thus, we demonstrate that the pH neutralization promotes the mobilization of existing silicate minerals and the rapid formation of new iron colloids. These Fe colloids have the potential to migrate through the shale matrix and mobilize other heavy metals (such as Cr and Ni, in this study) and impacting groundwater quality, as well produced waters from these hydraulic fracturing operations.

Controls on Barite (BaSO4) Precipitation in Unconventional Reservoirs

Barite (BaSO4) precipitation is one of the most ubiquitous examples of secondary sulfate mineral scaling in shale oil and gas reservoirs. Often, a suite of chemical additives is used during fracturing operations to inhibit the accumulation of mineral scales, though their efficacy is widely varied and poorly understood. This study combines experimental data and multi-component numerical reactive transport modeling to offer a more comprehensive understanding of the geochemical behavior of barite accumulation in shale matrices under conditions typical of fracturing operations. A variety of additives and conditions are individually tested in batch reactor experiments to identify the factors controlling barite precipitation. Our experimental results demonstrate a pH dependence in the rate of barite precipitation, which we use to develop a predictive model including a pH-dependent term that satisfactorily reproduces our observations. This model is then extended to consider the behavior of three major shale samples of highly variable mineralogy (Eagle Ford, Marcellus, and Barnett). This data-validated model offers a reliable tool to predict and ultimately mitigate against secondary mineral accumulation in unconventional shale reservoirs.

Hydrochemistry, Sources and Management of Fracturing Flowback Fluid in Tight Sandstone Gasfield in Sulige Gasfield (China)

Hydraulic fracturing technologies have been frequently utilized in the oil and gas industry as exploration and development efforts have progressed, resulting in a significant increase in the extraction of natural gas and petroleum from low-permeability reservoirs. However, hydraulic fracturing requires a large amount of freshwater, and the process results in the production of large volumes of flowback water along with natural gas. In this study, three tight sandstone gas wells were fractured in the Sulige gasfield (China), and a total of 103 flowback fluid samples were collected. The hydrochemical characteristics, water quality and sources of hydrochemical components in the flowback fluid were discussed. The results show that the flowback fluid is characterized by high salinity (Total dissolved solids (TDS) up to 38,268 mg/L, Cl^- up to 24,000 mg/L), high concentrations of metal ions (e.g., Fe, Sr²⁺, Ba²⁺) and high chemical oxygen demand (COD). The flowback fluid is a complex mixture of fracturing fluid and formation water, and its composition is impacted by water-rock interactions that occur during hydraulic fracturing. The major contaminants include COD, Fe, Ba²⁺, Cl^-, Mn and pH, which constitute a high risk of environmental pollution. Meanwhile, chemical elements such as K, Ba and Sr are unusually enriched in the flowback fluid, which has an excellent potential for recycle of chemical elements. The Sulige gasfield's flowback fluid recovery methods and treatment scenarios were discussed, taking into consideration the pollution and resource characteristics of the flowback fluid. Options for dealing with the flowback fluid include deep well reinjection, reuse for making up fracturing fluid, recycling of chemical elements and diverse reuse of flowback water. This research offers guidance for managing the fracturing flowback fluid in unconventional oil and gas fields.

Development and Performance Evaluation of Scale-Inhibiting Fracturing Fluid System

The injection water and formation water in the Mahu oil field have high salinity and poor compatibility, which leads to scaling and blockage in the formation or fracture propping zone during production. In this paper, a scale-inhibiting fracturing fluid system is developed which can prevent the formation of scale in the reservoir and solves the problem of scaling in the fracture propping zone at the Mahu oil field. Firstly, based on scale-inhibition rate, the performances of six commercial scale inhibitors were evaluated, including their acid and alkali resistance and temperature resistance. Then, the optimal scale inhibitors were combined with the fracturing fluid to obtain a scale-inhibiting fracturing fluid system. Its compatibility with other additives and scale-inhibition performance were evaluated. Finally, the system’s drag-reduction ability was tested through the loop friction tester. The results showed that, among the six scale inhibitors, the organic phosphonic acid scale inhibitor SC-1 has the best performance regardless of high-temperature, alkaline, and mixed scale conditions. In addition, SC-1 has good compatibility with the fracturing fluid. The scale-inhibiting fracturing fluid system can effectively prevent scaling inside the large pores in the propping zone, and a scale-inhibiting efficiency of 96.29% was obtained. The new fracture system maintained a drag-reduction efficiency of about 75%, indicating that the addition of the scale inhibitor did not cause a significant influence on the drag-reduction efficiency of the fracturing fluid.

Chemical and Reactive Transport Processes Associated with Hydraulic Fracturing of Unconventional Oil/Gas Shales

Hydraulic fracturing of unconventional oil/gas shales has changed the energy landscape of the U.S. Recovery of hydrocarbons from tight, hydraulically fractured shales is a highly inefficient process, with estimated recoveries of <25% for natural gas and <5% for oil. This review focuses on the complex chemical interactions of additives in hydraulic fracturing fluid (HFF) with minerals and organic matter in oil/gas shales. These interactions are intended to increase hydrocarbon recovery by increasing porosities and permeabilities of tight shales. However, fluid-shale interactions result in the dissolution of shale minerals and the release and transport of chemical components. They also result in mineral precipitation in the shale matrix, which can reduce permeability, porosity, and hydrocarbon recovery. Competition between mineral dissolution and mineral precipitation processes influences the amounts of oil and gas recovered. We review the temporal/spatial origins and distribution of unconventional oil/gas shales from mudstones and shales, followed by discussion of their global and U.S. distributions and compositional differences from different U.S. sedimentary basins. We discuss the major types of chemical additives in HFF with their intended purposes, including drilling muds. Fracture distribution, porosity, permeability, and the identity and molecular-level speciation of minerals and organic matter in oil/gas shales throughout the hydraulic fracturing process are discussed. Also discussed are analysis methods used in characterizing oil/gas shales before and after hydraulic fracturing, including permeametry and porosimetry measurements, X-ray diffraction/Rietveld refinement, X-ray computed tomography, scanning/transmission electron microscopy, and laboratory- and synchrotron-based imaging/spectroscopic methods. Reactive transport and spatial scaling are discussed in some detail in order to relate fundamental molecular-scale processes to fluid transport. Our review concludes with a discussion of potential environmental impacts of hydraulic fracturing and important knowledge gaps that must be bridged to achieve improved mechanistic understanding of fluid transport in oil/gas shales.

A single column separation method for barium isotope analysis of geologic and hydrologic materials with complex matrices

The increasing significance of barium (Ba) in environmental and geologic research in recent years has led to interest in the application of the Ba isotopic composition as a tracer for natural materials with complex matrices. Most Ba isotope measurement techniques require separation of Ba from the rest of sample prior to analysis. This paper presents a method using readily available materials and disposable columns that effectively separates Ba from a range of geologic and hydrologic materials, including carbonate minerals, silicate rocks, barite, river water, and fluids with high total dissolved solids and organic content such as oil and gas brines, rapidly and without need for an additional cleanup column. The technique involves off-the-shelf columns and cation exchange resin and a two-reagent elution that uses 2.5 N HCl followed by addition of 2.0 N HNO₃. We present data to show that major matrix elements from almost any natural material are separated from Ba in a single column pass, and that the method also effectively reduces or eliminates isobaric interferences from lanthanum and cerium.

A Critical Review of the Physicochemical Impacts of Water Chemistry on Shale in Hydraulic Fracturing Systems

Hydraulic fracturing of unconventional hydrocarbon resources involves the sequential injection of a high-pressure, particle-laden fluid with varying pH's to make commercial production viable in low permeability rocks. This process both requires and produces extraordinary volumes of water. The water used for hydraulic fracturing is typically fresh, whereas "flowback" water is typically saline with a variety of additives which complicate safe disposal. As production operations continue to expand, there is an increasing interest in treating and reusing this high-salinity produced water for further fracturing. Here we review the relevant transport and geochemical properties of shales, and critically analyze the impact of water chemistry (including produced water) on these properties. We discuss five major geochemical mechanisms that are prominently involved in the temporal and spatial evolution of fractures during the stimulation and production phase: shale softening, mineral dissolution, mineral precipitation, fines migration, and wettability alteration. A higher salinity fluid creates both benefits and complications in controlling these mechanisms. For example, higher salinity fluid inhibits clay dispersion, but simultaneously requires more additives to achieve appropriate viscosity for proppant emplacement. In total this review highlights the nuances of enhanced hydrogeochemical shale stimulation in relation to the choice of fracturing fluid chemistry.

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

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

Review of Synthesis and Evaluation of Inhibitor Nanomaterials for Oilfield Mineral Scale Control

Oilfield flow assurance is the subject to study the impact on the flow of production fluids due to physicochemical changes in the production system. Mineral scale deposition is among the top 3 water-related flow assurance challenges in petroleum industry, particularly for offshore and shale operations. Scale deposition can lead to serious operational risks and significant financial loss. The most commonly adopted strategy in oilfield scale control is the deployment of chemical inhibitors. Although conventional chemical inhibitors are effective in inhibiting scale threat, they have the drawbacks of short transport distance and limited squeeze lifetime due to their intrinsic chemical properties. In the past decade, as an alternative to conventional chemical inhibition, research efforts have been made to prepare functional nanomaterials with different chemical compositions to overcome the drawbacks of conventional chemical inhibitors. These synthesized nanomaterials can serve as delivery vehicles to deploy inhibitors into the target location in the production system. These nanomaterials are reported to have multiple advantages over the conventional inhibitors in terms of transportability, controlled release, and functionality, evidenced by a series of experimental studies. This review presents an overview of scale inhibitor nanomaterial development and the current methods to synthesize and to evaluate these nanomaterials in a systematic and comprehensive manner. This review focuses on the chemistry principles and methodologies underlying inhibitor nanomaterial synthesis and also the chemical instrument and strategies in evaluating the physiochemical properties of these materials in terms of inhibition effectiveness, transportability, and inhibitor return. The scale inhibitor nanomaterials (SINMs) presented in this review exemplify the continuous development in our capabilities in adopting novel nanotechnology in combating actual engineering challenges in petroleum industry.

A rapid method to determine 226Ra concentrations in Marcellus Shale produced waters using liquid scintillation counting

Concentrations of naturally occurring radioactive material (NORM) in Marcellus Shale produced water presents a challenge for effective management and treatment, because of the vast fluid volumes generated. With an increased emphasis on beneficial reuse and resource recovery from the produced waters, a rapid, yet reliable, method for quantifying radium in these produced waters is needed. The high total dissolved solids (TDS) concentration introduces difficulties when measuring ²²⁶Ra by recommended EPA methods that were specifically developed several decades ago for drinking water. While other techniques for measuring radium in these high-TDS fluids have since been developed, these newer techniques often require extensive and complicated pre-concentration steps; and they thus require extensive analytical chemistry skills, utilize hazardous chemicals like hydrofluoric acid, demand long holding times or measurement times, and require high sample volumes. We present a rapid method for ²²⁶Ra measurements in high-TDS produced waters by liquid scintillation counting, which has been corroborated herein by concurrent gamma spectrometry analyses. Samples were prepared for analysis by evaporating the fluid and re-suspending the evaporate with acidified distilled deionized water prior to liquid scintillation counting for 1 h. This protocol yielded radium recoveries ≥93%. Per this protocol, the alpha and beta spectra of ²²⁶Ra and its daughters were computationally separated by alpha-beta discrimination and spectrum deconvolution. The minimum detectable activities of ²²⁶Ra was 0.33 Bq/L (9.0 pCi/L) when the counting time was 60 min and the sample volume was 4 mL. Nine produced waters of varying TDS and radium concentrations from the Marcellus Shale Formation were analyzed by this method and compared with gamma spectroscopy; and these yielded comparable results with an R² of 0.92. The reduced sample preparation steps, low cost, and rapid analysis position this as a well-suited protocol for field-appraisal and screening, when compared to comprehensive radiochemical analysis. We offer that for a given produced water region, routine and local liquid scintillation analyses can be compared and calibrated with infrequent gamma spec analyses, so as to yield a near-real time protocol for monitoring ²²⁶Ra levels during hydrofracturing operations. We present this as a pragmatic and efficient protocol for monitoring ²²⁶Ra when produced water samples host low levels of ²²⁸Ra-since the progeny of ²²⁸Ra can significantly confound the LSC analyses.

Geochemistry and Microbiology Predict Environmental Niches With Conditions Favoring Potential Microbial Activity in the Bakken Shale

The Bakken Shale and underlying Three Forks Formation is an important oil and gas reservoir in the United States. The hydrocarbon resources in this region are accessible using unconventional oil and gas extraction methods, including horizontal drilling and hydraulic fracturing. However, the geochemistry and microbiology of this region are not well understood, although they are known to have major implications for productivity and water management. In this study, we analyzed the produced water from 14 unconventional wells in the Bakken Shale using geochemical measurements, quantitative PCR (qPCR), and 16S rRNA gene sequencing with the overall goal of understanding the complex dynamics present in hydraulically fractured wells. Bakken Shale produced waters from this study exhibit high measurements of total dissolved solids (TDS). These conditions inhibit microbial growth, such that all samples had low microbial loads except for one sample (well 11), which had lower TDS concentrations and higher 16S rRNA gene copies. Our produced water samples had elevated chloride concentrations typical of other Bakken waters. However, they also contained a sulfate concentration trend that suggested higher occurrence of sulfate reduction, especially in wells 11 and 18. The unique geochemistry and microbial loads recorded for wells 11 and 18 suggest that the heterogeneous nature of the producing formation can provide environmental niches with conditions conducive for microbial growth. This was supported by strong correlations between the produced water microbial community and the associated geochemical parameters including sodium, chloride, and sulfate concentrations. The produced water microbial community was dominated by 19 bacterial families, all of which have previously been associated with hydrocarbon-reservoirs. These families include Halanaerobiaceae, Pseudomonadaceae, and Desulfohalobiaceae which are often associated with thiosulfate reduction, biofilm production, and sulfate reduction, respectively. Notably, well 11 was dominated by sulfate reducers. Our findings expand the current understanding of microbial life in the Bakken region and provide new insights into how the unique produced water conditions shape microbial communities. Finally, our analysis suggests that produced water chemistry is tightly linked with microbiota in the Bakken Shale and shows that additional research efforts that incorporate coupled microbial and geochemical datasets are necessary to understand this ecosystem.

A geospatially resolved database of hydraulic fracturing wells for chemical transformation assessment

Hydraulically fractured wells with horizontal drilling (HDHF) accounted for 69% of all oil and gas wells drilled and 670 000 of the 977 000 producing wells in 2016. However, only 238 flowback and produced water samples have been analyzed to date for specific organic chemicals. To aid the development of predictive tools, we constructed a database combining additive disclosure reports and physicochemical conditions at respective well sites with the goal of making synthesized analyses accessible. As proof-of-concept, we used this database to evaluate transformation pathways through two case studies: (1) a filter-based approach for flagging high-likelihood halogenation sites according to experimental criteria (e.g., for a model compound, cinnamaldehyde) and (2) a semi-quantitative, regionally comparative trihalomethane formation model that leverages an empirically derived equation. Study (1) highlighted 173 wells with high cinnamaldehyde halogenation likelihood based on combined criteria related to subsurface conditions and oxidant additive usage. Study (2) found that trihalomethane formation in certain wells within five specific basins may exceed regulatory limits for drinking water based on reaction-favorable subsurface conditions, albeit with wide uncertainty. While experimentation improves our understanding of subsurface reaction pathways, this database has immediate applications for informing environmental monitors and engineers about potential transformation products in residual fluids, guiding well operators' decisions to avoid unwanted transformations. In the future, we envision more robust components incorporating transformation, transport, toxicity, and other physicochemical parameters to predict subsurface interactions and flowback composition.

Maximum Removal Efficiency of Barium, Strontium, Radium, and Sulfate with Optimum AMD-Marcellus Flowback Mixing Ratios for Beneficial Use in the Northern Appalachian Basin

Mixing of acid mine drainage (AMD) and hydraulic fracturing flowback fluids (HFFF) could represent an efficient management practice to simultaneously manage two complex energy wastewater streams while reducing freshwater resource consumption. AMD discharges offer generally high sulfate concentrations, especially from the bituminous coal region of Pennsylvania; unconventional Marcellus shale gas wells generally yield HFFF enriched in alkaline earth metals such as Sr and Ba, known to cause scaling issues in oil and gas (O&G) production. Mixing the two waters can precipitate HFFF-Ba and -Sr with AMD-SO₄, therefore removing them from solution. Four AMD discharges and HFFF from two unconventional Marcellus shale gas wells were characterized and mixed in batch reactors for 14 days. Ba could be completely removed from solution within 1 day of mixing in the form Ba_xSr_1-xSO₄ and no further significant precipitation occurred after 2 days. Total removal efficiencies of Ba + Sr + SO₄ and the proportion of Ba and Sr in Ba_xSr_1-xSO₄ depended upon the Ba/Sr ratio in the initial HFFF. A geochemical model was calibrated from batch reactor data and used to identify optimum AMD-HFFF mixing ratios that maximize total removal efficiencies (Ba + Sr + SO₄) for reuse in O&G development. Increasing Ba/Sr ratios can enhance total removal efficiency but decrease the efficiency of Ra removal. Thus, treatment objectives and intended beneficial reuse need to be identified prior to optimizing the treatment of HFFF with AMD.

Application of isotopic and geochemical signals in unconventional oil and gas reservoir produced waters toward characterizing in situ geochemical fluid-shale reactions

Optimizing hydrocarbon production and waste management from unconventional oil and gas extraction requires an understanding of the fluid-rock chemical interactions. These reactions can affect flow pathways within fractured shale and produced water chemistry. Knowledge of these chemical reactions also provides valuable information for planning wastewater treatment strategies. This study focused on characterizing reservoir reactions through analysis of produced water chemistry from the Marcellus Shale Energy and Environmental Laboratory field site in Morgantown, WV, USA. Analysis of fracturing fluids, time-series produced waters (PW) over 16 months of operation of two hydraulically fractured gas wells, and shale rocks from the same well for metal concentrations and multiple isotope signatures (δ²H and δ¹⁸O of water, δ⁷Li, δ¹¹B, ⁸⁷Sr/⁸⁶Sr) showed that the chemical and isotopic composition of early (<10 days) PW samples record water-rock interactions during the fracturing period. Acidic dissolution of carbonate minerals was evidenced by the increase in TOC, B/Na, Sr/Na, Ca/Na, and the decrease in ⁸⁷Sr/⁸⁶Sr in PW returning in the first few days toward the ⁸⁷Sr/⁸⁶Sr signature of carbonate cement. The enrichment of ⁶Li in these early (e.g., day 1) PW samples is most likely a result of desorption of Li from clays and organic matter due to the injection of fracturing fluid. Redox-active trace elements appear to be controlled by oxidation-reduction reactions and potentially reactions involving wellbore steel. Overall, PW chemistry is primarily controlled by mixing between early PW with local in-situ formation water however certain geochemical reactions (e.g., carbonate cement dissolution and desorption of ⁶Li from clays and organic matter) can be inferred from PW composition monitored immediately over the first ten days of water return.

Barium Isotopes Track the Source of Dissolved Solids in Produced Water from the Unconventional Marcellus Shale Gas Play

Waters coproduced with hydrocarbons from unconventional oil and gas reservoirs such as the hydraulically fractured Middle Devonian Marcellus Shale in the Appalachian Basin, USA, contain high levels of total dissolved solids (TDS), including Ba, which has been variously ascribed to drilling mud dissolution, interaction with pore fluids or shale exchangeable sites, or fluid migration through fractures. Here, we show that Marcellus Shale produced waters contain some of the heaviest Ba (high ¹³⁸Ba/¹³⁴Ba) measured to date (δ¹³⁸Ba = +0.36‰ to +1.49‰ ± 0.06‰) and are distinct from overlying Upper Devonian/Lower Mississippian reservoirs (δ¹³⁸Ba = -0.83‰ to -0.52‰). Marcellus Shale produced water values do not overlap with drilling mud barite (δ¹³⁸Ba ≈ 0.0‰) and are significantly offset from Ba reservoirs within the producing portion of the Marcellus Shale, including exchangeable sites and carbonate cement. Precipitation, desorption, and diffusion processes are insufficient or in the wrong direction to produce the observed enrichments in heavy Ba. We hypothesize that the produced water is derived primarily from brines adjacent to and most likely below the Marcellus Shale, although such deep brines have not yet been obtained for Ba isotope analysis. Barium isotopes show promise for tracking formation waters and for understanding water-rock interaction under downhole conditions.

Combination of MRI and SEM to Assess Changes in the Chemical Properties and Permeability of Porous Media due to Barite Precipitation

The understanding of the dissolution and precipitation of minerals and its impact on the transport of fluids in porous media is essential for various subsurface applications, including shale gas production using hydraulic fracturing (“fracking”), CO2 sequestration, or geothermal energy extraction. In this work, we conducted a flow through column experiment to investigate the effect of barite precipitation following the dissolution of celestine and consequential permeability changes. These processes were assessed by a combination of 3D non-invasive magnetic resonance imaging, scanning electron microscopy, and conventional permeability measurements. The formation of barite overgrowths on the surface of celestine manifested in a reduced transverse relaxation time due to its higher magnetic susceptibility compared to the original celestine. Two empirical nuclear magnetic resonance (NMR) porosity–permeability relations could successfully predict the observed changes in permeability by the change in the transverse relaxation times and porosity. Based on the observation that the advancement of the reaction front follows the square root of time, and micro-continuum reactive transport modelling of the solid/fluid interface, it can be inferred that the mineral overgrowth is porous and allows the diffusion of solutes, thus affecting the mineral reactivity in the system. Our current investigation indicates that the porosity of the newly formed precipitate and consequently its diffusion properties depend on the supersaturation in solution that prevails during precipitation.

Effects of Aqueous Solubility and Geochemistry on CO2 Injection for Shale Gas Reservoirs

In shale gas reservoirs, CH₄ and CO₂ have finite aqueous solubilities at high-pressure conditions and their dissolutions in water affect the determination of the original gas in place and the CO₂ sequestration. In addition, the dissolution of CO₂ decreases the pH of connate water, and the geochemical reactions may thus occur in carbonate-rich shale reservoirs. The comprehensive simulations of this work quantify the effects of aqueous solubility and geochemistry on the performance CO₂ huff-n-puff process in shale gas reservoir. Accounting for the aqueous solubility of CH₄ increases the initial natural gas storage and natural gas production. The effect of the aqueous solubility of CO₂ enables to sequester additional CO₂ via solubility trapping. Considering the geochemical reactions, the application of the CO₂ huff-n-puff process causes the dissolution of carbonate minerals and increases the porosity enhancing the gas flow and the gas recovery. Incorporation of geochemistry also predicts the less CO₂ sequestration capacity. Therefore, this study recommends the consideration of aqueous solubility and geochemical reactions for the accurate prediction of gas recovery and CO₂ sequestration in shale gas reservoirs during the CO₂ huff-n-puff process.

In situ transformation of hydraulic fracturing surfactants from well injection to produced water

Chemical changes to hydraulic fracturing fluids (HFFs) within fractured unconventional reservoirs may affect hydrocarbon recovery and, in turn, the environmental impact of unconventional oil and gas development. Ethoxylated alcohol surfactants, which include alkyl ethoxylates (AEOs) and polyethylene glycols (PEGs), are often present in HFF as solvents, non-emulsifiers, and corrosion inhibitors. We present detailed analysis of polyethoxylates in HFF at the time of injection into three hydraulically fractured Marcellus Shale wells and in the produced water returning to the surface. Despite the addition of AEOs to the injection fluid during almost all stages, they were rarely detected in the produced water. Conversely, while PEGs were nearly absent in the injection fluid, they were the dominant constituents in the produced water. Similar numbers of ethoxylate units support downhole transformation of AEOs to PEGs through central cleavage of the ethoxylate chain from the alkyl group. We also observed a decrease in the average ethoxylate (EO) number of the PEG-EOs in the produced water over time, consistent with biodegradation during production. Our results elucidate an overlooked surfactant transformation pathway that may affect the efficacy of HFF to maximize oil and gas recovery from unconventional shale reservoirs.

Geochemical conditions conducive for retention of trace elements and radionuclides during shale-fluid interactions

Produced water generated during unconventional oil and gas extractions contains a complex milieu of natural and anthropogenic potentially toxic chemical constituents including arsenic (As), chromium (Cr), and cadmium (Cd), naturally occurring radioactive materials (NORMs) including U and Ra, and a myriad of organic compounds. The human-ecological health risks and challenges associated with the disposal of produced water may be alleviated by understanding geochemical controls on processes responsible for the solubilization of potentially hazardous natural shale constituents to produced water. Here, we investigated, through a series of batch treatments, the leaching behavior of As, Se, Cu, Fe, Ba, Cr, Cd, and radioactive nuclides U, Ra from shale to produced water. Specifically, the effect of four major controls on element mobility was studied: (1) solution pH, (2) ionic strength of the solution, (3) oxic-anoxic conditions, and (4) an additive used in fracking fluid. The mobilization of metals and metalloids from shale was greatest in treatments containing sodium persulfate, an oxidant and a commonly used additive in fracture fluid. In the high ionic strength treatments, dissolved Ba concentrations increased 5-fold compared to low ionic strength treatments. Overall, anoxic conditions superimposed with low pH resulted in the largest increase of dissolved metals and radionuclides such as Ra. Overall, our results suggest that (1) limiting pore water acidification by injection of alkaline fluid in carbonate-low shale and (2) minimizing strong oxidizing conditions in shale formations may result in cost-effective in situ retention of produced water contaminants.

Geochemical and sulfate isotopic evolution of flowback and produced waters reveals water-rock interactions following hydraulic fracturing of a tight hydrocarbon reservoir

Although multistage hydraulic fracturing is routinely performed for the extraction of hydrocarbon resources from low permeability reservoirs, the downhole geochemical processes linked to the interaction of fracturing fluids with formation brine and reservoir mineralogy remain poorly understood. We present a geochemical dataset of flowback and produced water samples from a hydraulically fractured reservoir in the Montney Formation, Canada, analyzed for major and trace elements and stable isotopes. The dataset consists in 25 samples of flowback and produced waters from a single well, as well as produced water samples from 16 other different producing wells collected in the same field. Additionally, persulfate breaker samples as well as anhydrite and pyrite from cores were also analyzed. The objectives of this study were to understand the geochemical interactions between formation and fracturing fluids and their consequences in the context of tight gas exploitation. The analysis of this dataset allowed for a comprehensive understanding of the coupled downhole geochemical processes, linked in particular to the action of the oxidative breaker. Flowback fluid chemistries were determined to be the result of mixing of formation brine with the hydraulic fracturing fluids as well as coupled geochemical reactions with the reservoir rock such as dissolution of anhydrite and dolomite; pyrite and organic matter oxidation; and calcite, barite, celestite, iron oxides and possibly calcium sulfate scaling. In particular, excess sulfate in the collected samples was found to be mainly derived from anhydrite dissolution, and not from persulfate breaker or pyrite oxidation. The release of heavy metals from the oxidation activity of the breaker was detectable but concentrations of heavy metals in produced fluids remained below the World Health Organization guidelines for drinking water and are therefore of no concern. This is due in part to the co-precipitation of heavy metals with iron oxides and possibly sulfate minerals.

Effect of maturity and mineralogy on fluid-rock reactions in the Marcellus Shale

Natural gas extraction from the Appalachian Basin has significantly increased in the past decade. The push to properly dispose, reuse, or recycle the large amounts of produced fluids associated with hydraulic fracturing operations and design better fracturing fluids has necessitated a better understanding of the subsurface chemical reactions taking place during hydrocarbon extraction. Using autoclave reactors, this study mimics the conditions of deep subsurface shale reservoirs to observe the chemical evolution of fluids during the shut-in phase of hydraulic fracturing (HF), a period when hydraulic fracturing fluids (HFFs) remain confined in the reservoir. The experiment was conducted by combining a synthetic hydraulic fracturing fluid and powdered shale core samples in high temperature/pressure static autoclave reactors for 14 days. Shale samples of varying maturity and mineralogy were used to assess the effect of these variations on the proliferation of inorganic ions and low molecular weight volatile organic compounds (VOCs), mainly benzene, toluene, ethylbenzene and xylenes (BTEX) and monosubstituted carboxylic acids. Ion chromatography results indicate that the relative abundance of ions present was similar to that of water produced from HF operations in the Marcellus Shale basin. There was an increase of SO42- and PO43- and a decrease in Ba2+ upon fluid-shale reaction. Major ionic shifts indicate calcite dissolution in two of the fluid-shale reactions and barite precipitation in all fluid-shale reactions. Toluene, xylene, and carboxylic acids were produced in the shale-free control experiment. The most substantial increase in BTEX analytes was observed in reactions with low maturity shale, while the high maturity shale reaction produced no measurable BTEX compounds. Total organic carbon decreased in all reactions including fracturing fluid and shale, suggesting adsorption onto the organic matter (OM) matrix. The results from this study highlight that both the nature of OM and mineralogy play a key role in determining the fate of inorganic and organic compounds during fluid-shale interactions in the subsurface shale reservoir. Overall this study aims to contribute to the growing understanding of complex chemical interactions that occur in the shale reservoirs during HF, which is vital for determining the potential environmental impacts of HF and designing more efficient HFF and produced water recycling techniques for environmentally conscious natural gas production.

Organic sulfur fingerprint indicates continued injection fluid signature 10 months after hydraulic fracturing

Hydraulic fracturing requires the injection of large volumes of fluid to extract oil and gas from low permeability unconventional resources (e.g., shale, coalbed methane), resulting in the production of large volumes of highly complex and variable waste fluids. Shale gas fluid samples were collected from two hydraulically fractured wells in Morgantown, WV, USA at the Marcellus Shale Energy and Environment Laboratory (MSEEL) and analyzed using ultrahigh resolution mass spectrometry to investigate the dissolved organic sulfur (DOS) pool. Using a non-targeted approach, ions assigned DOS formulas were analyzed to identify dominant DOS classes, describe their temporal trends and their implications, and describe the molecular characteristics of the larger DOS pool. The average molecular weight of organic sulfur compounds in flowback decreased and was lowest in produced waters. The dominant DOS classes were putatively assigned to alcohol sulfate and alcohol ethoxysulfate surfactants, likely injected as fracturing fluid additives, on the basis of exact mass and homolog distribution matching. This DOS signature was identifiable 10 months after the initial injection of hydraulic fracturing fluid, and an absence of genes that code for alcohol ethoxysulfate degrading proteins (e.g., sulfatases) in the shale well genomes and metagenomes support that these additives are not readily degraded biologically and may continue to act as a chemical signature of the injected fluid. Understanding the diversity, lability, and fate of organic sulfur compounds in shale wells is important for engineering productive wells and preventing gas souring as well as understanding the consequences of unintended fluid release to the environment. The diversity of DOS, particularly more polar compounds, needs further investigation to determine if the identified characteristics and temporal patterns are unique to the analyzed wells or represent broader patterns found in other formations and under other operating conditions.

Raw material recovery from hydraulic fracturing residual solid waste with implications for sustainability and radioactive waste disposal

Unconventional oil and gas residual solid wastes are generally disposed in municipal waste landfills (RCRA Subtitle D), but they contain valuable raw materials such as proppant sands. A novel process for recovering raw materials from hydraulic fracturing residual waste is presented. Specifically, a novel hydroacoustic cavitation system, combined with physical separation devices, can create a distinct stream of highly concentrated sand, and another distinct stream of clay from the residual solid waste by the dispersive energy of cavitation conjoined with ultrasonics, ozone and hydrogen peroxide. This combination cleaned the sand grains, by removing previously aggregated clays and residues from the sand surfaces. When these unit operations were followed by a hydrocyclone and spiral, the solids could be separated by particle size, yielding primarily cleaned sand in one flow stream; clays and fine particles in another; and silts in yet a third stream. Consequently, the separation of particle sizes also affected radium distribution - the sand grains had low radium activities, as lows as 0.207 Bq g-1 (5.6 pCi g-1). In contrast, the clays had elevated radium activities, as high as 1.85-3.7 Bq g-1 (50-100 pCi g-1) - and much of this radium was affiliated with organics and salts that could be separated from the clays. We propose that the reclaimed sand could be reused as hydraulic fracturing proppant. The separation of sand from silt and clay could reduce the volume and radium masses of wastes that are disposed in landfills. This could represent a significant savings to facilities handling oil and gas waste, as much as $100 000-300 000 per year. Disposing the radium-enriched salts and organics downhole will mitigate radium release to the surface. Additionally, the reclaimed sand could have market value, and this could represent as much as a third of the cost savings. Tests that employed the toxicity characteristic leaching protocol (TCLP) on these separated solids streams determined that this novel treatment diminished the risk of radium mobility for the reclaimed sand, clays or disposed material, rendering them better suited for landfilling.

Degradation of hydraulic fracturing additive 2-butoxyethanol using heat activated persulfate in the presence of shale rock

Changes in fluid composition during hydraulic fracturing (HF) for natural gas production can impact well productivity and the water quality of the fluids returning to the surface during productivity. Shale formation conditions can influence the extent of fluid transformation. Oxidizers, such as sodium persulfate, likely play a strong role in fluid transformation. This study investigates the oxidation of 2-butoxyethanol (2-BE), a surfactant used in HF, by sodium persulfate in the presence of heat, pH changes, Fe(II), and shale rock. Increasing temperature and Fe(II) concentrations sped up 2-BE oxidation, while pH played little to no role in 2-BE degradation. The presence of shale rock impeded 2-BE oxidation with increasing shale concentrations causing decreasing pseudo-first-order reaction rate constant to be observed. Over the course of reactions containing shales, dissolved solids were tracked to better understand how reactions with minerals in the shale impact water quality.

Aging effects on chemical transformation and metal(loid) removal by entrapped nanoscale zero-valent iron for hydraulic fracturing wastewater treatment

In this study, alginate and polyvinyl alcohol (PVA)-alginate entrapped nanoscale zero-valent iron (nZVI) was tested for structural evolution, chemical transformation, and metals/metalloids removal (Cu(II), Cr(VI), Zn(II), and As(V)) after 1-2month passivation in model saline wastewaters from hydraulic fracturing. X-ray diffraction analysis confirmed successful prevention of Fe⁰ corrosion by polymeric entrapment. Increasing ionic strength (I) from 0 to 4.10M (deionized water to Day-90 fracturing wastewater (FWW)) with prolonged aging time induced chemical instability of alginate due to dissociation of carboxyl groups and competition for hydrogen bonding with nZVI, which caused high Na (7.17%) and total organic carbon (24.6%) dissolution from PVA-alginate entrapped nZVI after 2-month immersion in Day-90 FWW. Compared to freshly-made beads, 2-month aging of PVA-alginate entrapped nZVI in Day-90 FWW promoted Cu(II) and Cr(VI) uptake in terms of the highest removal efficiency (84.2% and 70.8%), pseudo-second-order surface area-normalized rate coefficient k_sa (2.09×10^-1Lm^-2h^-1 and 1.84×10^-1Lm^-2h^-1), and Fe dissolution after 8-h reaction (13.9% and 8.45%). However, the same conditions inhibited Zn(II) and As(V) sequestration in terms of the lowest removal efficiency (31.2% and 39.8%) by PVA-alginate nZVI and k_sa (4.74×10^-2Lm^-2h^-1 and 6.15×10^-2Lm^-2h^-1) by alginate nZVI. The X-ray spectroscopic analysis and chemical speciation modelling demonstrated that the difference in metals/metalloids removal by entrapped nZVI after aging was attributed to distinctive removal mechanisms: (i) enhanced Cu(II) and Cr(VI) removal by nZVI reduction with accelerated electron transfer after pronounced dissolution of non-conductive polymeric immobilization matrix; (ii) suppressed Zn(II) and As(V) removal by nZVI adsorption due to restrained mass transfer after blockage of surface-active micropores. Entrapped nZVI was chemically fragile and should be properly stored and regularly replaced for good performance.