Flowback Fluids Research Articles

A thermodynamics-based coupled model for multi-phase flowback in deformable dual-porosity shale gas reservoirs

Over the past decades, there has been growing interest in modelling multi-phase flowback in shale gas reservoirs during hydraulic fracturing, primarily due to the significant risk of groundwater pollution. However, the lack of fully coupled simulations and a unified theoretical model has hindered the study of coupled adsorptive hydro-mechanical behaviour and its influence on fluid flowback prediction. In this paper, we have extended the non-equilibrium thermodynamics-based Mixture Coupling Theory to derive the constitutive relationship and governing equation for adsorptive multi-phase fluid flows in deformable dual-porosity media. Helmholtz free energy density has been used to establish the relationship between solids and fluids. The interaction of adsorptive fluids in the pore and fracture space has been fully considered, leading to a new form of constitutive equation, which obtained the molecular adsorptive effect on the rock by introducing adsorption entropy production. The proposed governing equations determine the fully coupled evolution of solid deformation and multi-phase flow, with the consideration of adsorption as well as pore and fracture porosity change. Numerical simulation is then performed to study the flowback of a real shale gas well and the influence of coupled behaviour on model prediction. The simulation shows that the flowback flux is mainly by the fracture (more than 99.9 %) and the overall cumulative volume is 2427.1 m3 within 225 h which accounts for about 5.3 % of the total injected fracturing fluid, and the sensitivity analysis reveals that the manual fracture porosity is the most sensitive factor to the cumulative flowback. This work provides new insights into the flowback process of shale reservoirs in a fully coupled view and the proposed theoretical tool should contribute to the modelling of other adsorptive multi-phase flow problem in deformable dual-porosity media such as carbon storage and coalbed methane production.

The Indicative Role of Geochemical Characteristics of Fracturing Flowback Fluid in Shale Gas Wells on Production Performance

The Indicative Role of Geochemical Characteristics of Fracturing Flowback Fluid in Shale Gas Wells on Production Performance

Study on the Mechanism of Algae Bacteria Symbiotic System in Treating Fracturing Flowback Fluid

Fracturing operations in oil and gas wells are one of the main measures to increase production. Fracturing flowback fluid has the characteristics of high viscosity, high COD value, and containing multiple chemical reagents, making it difficult to treat. It has become one of the main pollutants in oil fields. Directly discharging untreated fracturing fluid can cause serious pollution to the environment and soil. Therefore, in-depth research on the treatment methods of fracturing flowback fluid is of great significance for environmental protection and cost reduction in oil and gas fields. This article systematically analyzes the sources, components, pollution characteristics, and treatment status of fracturing flowback fluid. The efficient treatment of fracturing flowback fluid using a microalgae aerobic bacteria mixed culture system was conducted, and the mechanism of algae bacteria symbiotic treatment of oily wastewater and the mechanism of microalgae aerobic bacteria mixed culture purification of fracturing flowback fluid were analyzed in depth.

3D DEM investigation on macro-meso mechanical responses of gas hydrate-bearing sediments in process of unloading confining pressure

Well drilling, gas production, and reservoir stimulation can disrupt stress states of gas hydrate-bearing sediments (GHBSs) surrounding wellbores, potentially inducing wellbore instability due to confining pressure unloading. Therefore, it is very important to know about the macro-meso mechanical responses of GHBSs under an unloading confining pressure path (UCPP). Herein, a discrete element method (DEM) was used to perform triaxial tests on three-dimensional numerical GHBSs under the UCPP and a conventional drained path (CDP) to bridge the knowledge gap. Results show that GHBSs under the UCPP are more prone to failure and dilatation than under the CDP, due to the reduced bearing capacity of contact force chains, relatively unstable particle assembly, and rapid cementation breakage development. Additionally, the stress path has little effect on the cohesion and friction angle of GHBSs. Furthermore, under the UCPP, the failure and dilatation risk of GHBSs are positively correlated with unloading confining pressure rate, inversely related to hydrate saturation and initial effective confining pressure. The grey relational analysis illustrates that compared to hydrate saturation and initial effective confining pressure, the unloading confining pressure rate minimally affects the unloading confining pressure effect. These findings can serve for experimental studies and field applications (e.g., optimizing drilling mud density, sand production rate, and fracturing fluid flowback rate) concerning the unloading confining pressure responses of GHBSs.

Advances in effective utilization of fracturing flowback fluids, Part I: Direct reuse technology

Advances in effective utilization of fracturing flowback fluids, Part I: Direct reuse technology

The quantitative study of residual acid damage of low permeability carbonate rock based on NMR test

The Leikoupo carbonate reservoirs in the West Sichuan gas field generally exhibit low porosity and permeability characteristics. After acidizing, the fluid flowback rate is only 46%, and a large amount of residual acid remains in the reservoir, causing damage to the pores. In this study, the rheological tests were first carried out to reveal the rheological characteristics of fresh and residual acid with different thickener contents. Then, the change in core permeability before and after acid flooding was tested by core-flood tests, and the effects of acid on pore structure in various scales were analyzed in nuclear magnetic resonance (NMR) tests. The research results show that the average viscosity of residual acid increased to about 157.14% of the fresh acid and exhibited large viscosity fluctuations, which may be caused by the formation of aggregates combined with thickener and insoluble. The change rate of core permeability (both improvement and damage) decreased with the increase in thickener content, and the effect was more significant when the thickener content changed from 0.6% to 0.8%. Under different thickener addition amounts, fresh acid mainly improved the core permeability. After core-flooding, micropores and mesopores (51.26–632.15 μm) were dissolved and enlarged, forming mesopores and macropores (632.15–3597.73 μm); when the thickener content increased to 0.8%, the solubility of acid decreased, and the pore volume increment and maximum pore size both decreased. On the other hand, residual acid mainly damages the core, thickener molecules in the acid occupying mesopore, leading to an overall shift in pore distribution from mesopores (145.24–335.53 μm) to micropores (20.59–126.32 μm), with the thickener content increased to 0.8%, the damage volume of mesopore increased by 723.90%. Based on the research results, the reduced thickener content was initially applied to the West Sichuan gas field, achieving a better acidizing effect.

Integrated membrane process of tubular ultrafiltration-nanofiltration-electrodialysis-reverse osmosis for treating fracturing flowback fluid

As an underground source of natural gas, shale gas is important for ensuring national energy security and promoting the “dual carbon” target. However, shale gas extraction produces flowback fluid that requires efficient treatment to avoid negative impacts on the environment and human health. In this study, a pilot plant was constructed to implement a novel membrane-integrated process to treat fracturing flowback fluid. This process employs an aeration reaction sedimentation (ARS) tank and a tubular ultrafiltration (TUF) membrane for pretreatment, followed by three separate membranes for nanofiltration (NF), electrodialysis (ED), and reverse osmosis (RO). The pretreatment removed 99.3% of total hardness, 99.4% of total suspended solids (TSS), and 88.1% of total organic carbon (TOC). Four different types of TUF membranes were tested and compared. It was also found that physico-chemical cleaning of the TUF membrane using the ceramic particle technology resulted in a flux recovery rate of up to 98%. In addition, the NF and ED membranes can remove 99.4% of Na2SO4 and 90% of NaCl, respectively, resulting in an 85.6% decrease in TSS. Water recovery rate of the total system can reach 90%. Based on concept of sustainable green development, carbon footprint of integrated membrane process for treating fracturing flowback fluid was approximately 86.7 kgCO2 eq lower than that of traditional process. Low carbon emissions and no generation of secondary pollutants have become the keys to treat fracturing wastewater. In summary, the integrated TUF-NF-ED-RO process based on membranes is very promising for treating fracturing flowback fluid.

Superior long service life of a porous Ti-foam/TiOxHy-NTs/SnO2-Sb anode for highly efficient degradation of the pretreatment polyacrylamide-containing fracturing flowback fluid

Doped-SnO2 electrodes have shown outstanding performances in electrochemical oxidation (EO), but limitations in long service life and high durability have necessitated further advances in electrode design. Herein, this study proposes a porous Ti-foam/TiOxHy-NTs/SnO2-Sb anode with superior long service life for efficient degradation of polyacrylamide (PAM) - containing fracturing flowback fluid. The Ti-foam/TiOxHy-NTs/SnO2-Sb anode was designed by preferably choosing reduced TiO2 nanotube arrays grown in situ on porous Ti foam (Ti-foam/TiOxHy-NTs) as substrate coated with SnO2-Sb coating through the sol-gel method. The superiority of the design concept is verified by achieving a superior long service life of 735.2 h (0.5 M H2SO4) and 53.2 h (0.5 M HCl) at a current density of 1.0 A cm−2 by the tests of accelerated service life. The superior long service life originates from multidimensional and hierarchical architecture for lowering electrical resistance by shorting the transport path of electrolyte ions and electrons, and loading more active material without aggregation. Furthermore, the Ti-foam/TiOxHy-NTs/SnO2-Sb electrode displays excellent ability in efficiently degrading the real and simulated PAM-containing fracturing flowback fluid, achieving a chemical oxygen demand decomposition of above 90.0 % after 120 min of EO process. Therefore, the synthesized Ti-foam/TiOxHy-NTs/SnO2-Sb electrode exhibits great potential industrial application for efficient decomposition of PAM-containing fracturing flowback fluid using in EO process.

Flowback Additive for Acidizing Fluid to Stimulate Carbonate Gas Reservoirs

Summary Acidizing of oil- and gas-bearing carbonate reservoirs is generally undertaken by using strong mineral acids such as hydrochloric acid (HCl) to enhance permeability. One of the major challenges associated with HCl injection is tuning the reactivity profile to favor the transport of live acid deep into the reservoir while achieving a minimum rock face dissolution. The mineral acid is therefore emulsified in a hydrocarbon phase (e.g., diesel) to retard its reactivity with the rock matrix. The use of emulsified acid is hindered by several limitations such as low emulsion stability at high temperatures, pumping limitations due to high viscosity, the potential of formation damage, and cumbersome mixing procedures at the field scale. In addition, the brines formed as a result of this reaction can be difficult to produce due to higher density and capillary pressures, unfavorable wettability, and low formation pressure. Here, we report on the development of dual-purpose additives that were specifically designed to enhance the recovery of high-density brines and retard the acid/rock reactivity upon addition to the stimulation treatment. Accordingly, seven new additives with fluid flowback properties were developed for use in a single-phase acidizing fluid consisting of HCl (15 wt% and 28 wt%) with the required additives, such as corrosion inhibitor and intensifier, and H2S scavenger. The flowback enhancers (FBEs) were formulated from a blend of water, ester or terpene solvents, alcohols, and surfactants to form optically clear nano- and microemulsions. Surfactant selection was driven by the need to exhibit demulsification properties with condensate, high chemical and thermal stability, compatibility in strongly acidic media, and high-density brines under harsh reservoir conditions. To assess the FBE performance in acidizing formulations (i.e., to serve as both an FBE and retarder), screening studies consisting of static rock dissolution tests and surface tension measurements were performed to downselect FBEs suitable for this application. This was coupled with brine displacement tests in addition to compatibility and stability studies. FBEs that demonstrated superior performance were then selected for further evaluation under reservoir conditions [i.e., core flow matrix acidizing to measure regained permeability and computed tomography (CT) scan for analyzing the wormhole propagation]. The droplet size of the as-prepared nano- and microemulsions was found to be between 10 nm and 850 nm. The FBEs formulated in this study were found to prevent emulsion formation in the presence of condensate and demonstrated remarkable chemical and thermal stability in concentrated acid at temperatures up to 300°F for a duration of up to 24 hours, as confirmed by the consistent low surface tension values (21–29 mN/m). With regard to fluid displacement, column tests performed under ambient conditions revealed quick brine displacement with recovery exceeding 75 vol% in comparison with 16 vol% in the absence of the FBE. Interestingly, the addition of a select FBE from this study to 28 wt% HCl was found to retard the reaction of carbonate dissolution at room temperature. This led us to assess the performance under reservoir conditions utilizing core flow testing. Accordingly, the addition of FBE-F to 28 wt% HCl led to an improvement in permeability by up to 267% as compared with 15% without FBE added. These results are further supported by the CT scan images of the acidized cores, which revealed the formation of a deeper wormhole in the presence of a select FBE.

Electrochemical analysis of ion-exchange membranes fouling during electrodialysis treatment of real shale gas flowback water

Electrodialysis (ED) is considered an effective technology for desalinating shale gas flowback fluid toward environmental risk control and resource recovery. However, membrane fouling remains a significant challenge and the particular fouling behavior of ion-exchange membranes (IEMs) in real scenario remains unclear. In this study, we employed interface characterization techniques including electrochemical impedance spectroscopy (EIS) to investigate the fouling behavior of both anion-exchange membranes (AEMs) and cation-exchange membranes (CEMs) during the desalination process. Notably, a positive correlation was observed between the transmembrane electric potential (TMEP) of the target membrane and the extent of membrane fouling during ED processing. EIS data revealed the membrane bulk exhibited the most pronounced increase in modeled electrical resistance, suggesting that internal fouling more significantly inhibited mass transfer compared to external fouling. Under varying current densities, the resistance of the AEM and CEM membrane bulk increased from an initial value of 3.93–16.53 Ω cm2 and from 3.90 to 9.87 Ω cm2, respectively, corresponding to their maximum TMEP increase by factors of 6.0 and 2.0 during the ED treatment. Our results demonstrate that AEM undergone a more severe organic fouling than CEM (scaling) during desalination of real shale gas flowback fluid. Effective strategies to mitigate the fouling issue in IEMs were finally proposed. These findings provide valuable guidance on future process optimizing and fouling mitigation in the ED treatment of real shale gas flowback fluid.

Preparation of Biochar Composite Graphene Oxide for the Removal of Boron in Simulated Fracturing Flowback Fluid

Preparation of Biochar Composite Graphene Oxide for the Removal of Boron in Simulated Fracturing Flowback Fluid

Ion migration effects during hydro-fracturing of deep high salinity coal seam

Hydraulic fracturing enables effective exploitation of deep coalbed methane. During the hydraulic fracturing process, high salinity flowback fluid is generated, and this poses a significant challenge for water treatment. Therefore, we investigate the effect of hydraulic fracturing on ion migration in deep coal seams and its underlying mechanisms. In this study, nuclear magnetic resonance, inductively coupled plasma mass spectrometry, scanning electron microscopy, and energy dispersive x-ray spectroscopy were utilized to systematically study the diffusion behavior of ions and its correlation with water imbibition. Our results show that imbibition equilibrium was reached before ion diffusion finished. Ion diffusion displays three linear stages followed by a plateau part, and the second segment is the fastest one. The water–coal interactions result in the diffusion of ions into solution, with the most significant increases in Ca2+, Mg2+, Na+, K+, Li+, Cu2+, V5+, Hg2+, Pb2+, B3+, Mo6+, Cr3+, Sn4+, Cd2+, Cs+, Sr2+, and Ba2+. The dissolution of calcite, sodium feldspar, and kaolinite are the main contributions for ion migration. In addition, these reactions not only cause the release of ions into the solution but also lead to the formation of secondary pore-fractures and secondary precipitation. The results of this work help to understand better the ion migration induced by the water–coal interaction and to evaluate the fluid properties in deep coal formations.

Impact mechanism of active nanofluid on oil–water two-phase seepage during and after fracturing fluid invasion in tight oil reservoirs

Due to damage caused by fracturing fluid invasion, tight oil reservoirs exhibit slow post-hydraulic fracturing production recovery and low productivity. This study investigates the impact of a nanoclay-based active agent system on oil–water two-phase flow during and after fracturing fluid invasion, emphasizing its potential for enhancing recovery in tight oil reservoirs. Laboratory experiments using crude oil and natural core samples analyze the mechanism of how nanofluids affect oil–water distribution and flow characteristics during fracturing fluid invasion and oil recovery stages. Results show that nanofluids rapidly disrupt the emulsified state of “water-in-oil” emulsions, reducing emulsion viscosity by 84.19% and oil–water interfacial tension by two orders of magnitude, facilitating oil droplet dispersion and deformation and altering the wettability of oil-wet rock surfaces to aid crude oil detachment. Nanofluids increase the accessible volume of the water phase in pores and throats, enlarging flow paths for fracturing fluid flowback and oil recovery. The oil recovery process post-fracturing fluid invasion is delineated into three stages: substantial fracturing fluid flowback in the first stage, with nanofluids reducing the fluid return rate by 11.08% upon crude oil breakthrough; emulsion droplets occupying pores and throats in the second stage, with nanofluids reducing additional resistance during emulsion flow; and continuous oil production in the third stage, with nanofluids consistently and stably altering rock surface wettability to reduce invaded rock matrix resistance to oil flow. The findings of this study hold potential value in mitigating damage from fracturing fluid invasion in tight oil reservoirs.

Mechanism of enhanced oil recovery by nanoparticles extracted from flowback fluids of acidizing oil wells

The silicates in flowback fluids from acidizing oil wells can be used as raw materials for the synthesis of nanomaterials, that are beneficial for the treatment of produced water and enhanced oil recovery. In this paper, the nanomaterials were synthesized from acidizing flowback fluids by sol-gel method and the reaction conditions were optimized. The interfacial tension, wetting angle and surface tension of the solution were measured. The test of displacement efficiency and flooding experiments were conducted in two dimensional flat cores to reveal the mechanism of enhanced oil recovery by nanoparticles. The results indicated that the nanoparticles with a diameter of 351 nm could be extracted and synthesized from acidizing flowback solution at low pH. Compared with other nanomaterials, the synthesized nanoparticles could change the interfacial properties between oil and water due to the complex acidizing process. When the injection concentration of nanoparticles reached 300 mg/L, the decrease of water cut reached the maximum, up to 27.16%, and the recovery rate during subsequent water flooding was 32.25%. Appropriately increasing the injection concentration of nanoparticles extracted from acidizing flowback fluids was beneficial to improve the recovery rate, so that realizing the efficient development of oil and gas resources. The research results can provide a new method for the treatment of oilfield wastewater.

Two-Level Self-Thickening Mechanism of a Novel Acid Thickener with a Hydrophobic-Associated Structure during High-Temperature Acidification Processes.

Two acid thickeners, ADMC and ADOM, were prepared by aqueous solution polymerization using acrylamide (AM) and methacryloyloxyethyl trimethyl ammonium chloride (DMC) as raw materials, with or without the introduction of octadecyl polyoxyethylene ether methacrylate (OEMA). It was characterized by FTIR, 1H NMR, and the fluorescence spectra of pyrene. The double-layer thickening mechanism of ADOM was proved by comparing the thickening and rheological properties of ADMC and ADOM tested by a six-speed rotary viscometer and a HAKKE MARSIV rheometer during the acidification process. The results showed that the synthetic product was the target product; the first stage of the self-thickening ADOM fresh acid solution during high-temperature acidification was mainly affected by Ca2+ concentration, and the second stage of self-thickening was mainly affected by temperature. The residual viscosity of the 0.8 wt% ADOM residual acid solution was 250, 201.5, and 61.3 mPa·s, respectively, after shearing at 90, 120, and 150 °C for 60 min at a shear rate of 170 s-1. The thickening acid ADOM with a hydrophobic association structure has good temperature resistance and shear resistance, which can be used for high-temperature deep-well acid fracturing. In addition, no metal crosslinking agent was introduced in the system to avoid damage to its formation, and ADOM exhibited good resistance to Ca2+, which could provide ideas for the reinjection of the acidizing flowback fluid. It also has certain advantages for environmental protection.

Preparation, characterization and application of a composite bioflocculant.

Composite flocculant PAFS-PDM was prepared from Polymeric aluminium ferric sulphate (PAFS) and Poly (diallyl dimethyl ammonium chloride) (PDM) in this study. A bacterium was selected from the soil near the shale gas exploitation platform as a bioflocculant-producing bacterium, and polysaccharide was extracted and combined with PAFS-PDM to obtain composite bioflocculant (CBF) to treat shale gas fracturing flowback fluid. The prepared CBF was characterized and the results showed that the prepared PAFS-PDM contained aluminium-iron hydroxyl polymer, which was a cationic flocculant. By measuring the turbidity removal rate and chemical oxygen demand (COD) removal efficiency, the function mechanism of CBF on the shale gas fracturing flowback fluid was discussed. The results showed that CBF had a stable treatment effect on fracturing flowback fluid when the pH value was about 7.0. With the increase of dosage, the coagulation efficiency increased first and then decreased. When the dosage of the CBF was 2500 mg·L-1, the treatment effect of shale gas fracturing flowback fluid was the best, and COD removal rate reached 89.43%. Through Zeta potential analysis, it was concluded that one of the coagulation mechanisms was electrical neutralization. According to the characterization results, it could be concluded that both adsorption bridging and charge neutralization mechanisms played important roles in the treatment of shale gas fracturing flowback fluids.

Hydrogeochemistry and indicators of flowback and produced water from wells that are hydraulically fractured with recycled wastewater: A case study of the Changning gas field in the Sichuan Basin

With the increasing number of shale gas wells being hydraulically fractured with recycled flowback and produced water to reduce the consumption of fresh water, geochemical indicators of hydraulic fracturing flowback fluids (HFFFs) from such wells need to be found to evaluate the potential pollutants caused by shale gas development. To fill this knowledge gap, we analysed 64 HFFF samples from 3 Changning wells (fracked with recycled wastewater) to form a time series and compared them to HFFF samples from 3 Weiyuan wells (fracked with fresh water). We also made comparisons of HFFFs from two types of wells in the Appalachian Basin with reported data. The results indicated that regardless of the fracturing fluid being used, the water‒rock reaction caused by the hydraulic fracturing process resulted in the release of exchangeable phase elements, such as lithium, boron, with relatively depleted δ7Li and δ11B, and strontium with relatively enriched 87Sr/86Sr values on the shale surface, into the HFFFs. The composition of the injected fracturing fluid affected the strength of the water‒rock reaction, but the effect is negligible, as the fracturing process can still form the unique Sr, Li, and B isotope ratios of the HFFF. Thus, the elemental signatures (B/Cl and Sr/Cl) and isotopic fingerprints (δ11B, δ7Li, and 87Sr/86Sr) derived from HFFFs can be used to distinguish between HFFFs from wells hydraulically fractured by either fresh water or recycled wastewater and flowback water from conventional oil and gas wells. The results are important for the environmental evaluation of the large number of wells being fracked with recycled wastewater each year.

Boron removal by iron-aluminum combined anodes from fracturing flowback fluid: Advantages and mechanisms

During the process of oilfield wastewater reuse, residual Boron in fracturing flowback fluid will lead to premature crosslinking with gelling agents, resulting in excessive viscosity at the front end of the fracturing fluid configuration. This phenomenon has heavily influenced the reuse of wastewater. Electrocoagulation (EC), as an effective approach to decreasing Boron concentration, has been widely studied, while further research of Boron removal from complicated wastewater is required to optimize. EC parameters were investigated to explore the optimal Boron removal effect of Fe, Al and Fe-Al three combined anodes. Under 46.3–57.2 mA/cm2, 90 min and pH of 9, Fe-Al anodes exhibit the best effect of Boron removal (84% ± 1.5%). Furthermore, high adaptive capacity of low current density and suitable pH confirm the best choice of Fe-Al combined anodes. Scanning electron microscopy (SEM), Fourier transform infrared spectroscopy (FTIR) and X-ray photoelectron spectroscopy (XPS) demonstrate the complexation between Boron and metallic oxide. Finally, the common removal of various pollutants including Ca, Cl, K and Na further conduces to the reuse of oil wastewater.

Impact of unrecovered shale gas reserve on methane emissions from abandoned shale gas wells

Shale gas, with its abundance and lower carbon footprint compared to other fossil fuels, is an important bridge fuel in the ongoing energy transition. However, a notable concern in shale gas exploration is fugitive methane emissions during the extraction, development, and transport of natural gas. While most existing works evaluate methane emissions released by well fracking, completion and operation, the greenhouse footprint of unproductive shale gas wells (often abandoned or orphaned) has received little scrutiny. A large fraction of these emissions from abandoned shale gas wells are due to the diffusive transport of methane trapped in nanoporous shale matrix, which is poorly understood. Here, we develop a theoretical kinetic approach to predict methane diffusive flux from heterogeneous shale matrix. Our theoretical model is based on a layer sequence formulation and accurately considers multiple flow mechanisms, including viscous flow, gas slippage, and Knudsen diffusion and their mutual interactions. The model is validated against the observed methane diffusion data obtained from high-pressure and high-temperature experimental measurements on Marcellus shale. We find that methane diffusive flux increases as reservoir pressure decreases. We estimate methane emission due to diffusive transport up to 20 × 103 m3 per well per day, which is comparable to emissions from flowback fluid. For the first time, unrecovered natural gas in the shale matrix is demonstrated to be the main source of methane emissions from abandoned shale gas wells. Given the long-lasting nature of diffusive transport to shale gas seepage, it is suggested that regulatory requirements should be implemented to provide long-term monitoring of methane emissions from abandoned shale gas wells.

In vivo exposure to electronic waste (e-waste) leachate and hydraulic fracturing fluid adversely impacts the male reproductive system

Human health effects can arise from unregulated manual disassembly of electronic waste (e-waste) and/or hydraulic fracturing fluid spills. There is limited literature on the effects of e-waste and hydraulic fracturing wastewater exposure on the male reproductive system. Thus, this proof-of-concept study begins to address the question of how wastewater from two potentially hazardous environmental processes could affect sperm quality. Therefore, three groups of eight-week-old adult mice were exposed (5 d/wk for 6 wks) via a mealworm (Tenebrio molitor and Zophabas morio) feeding route to either: (1) e-waste leachate (50% dilution) from the Alaba Market (Lagos, Nigeria); (2) West Virginia hydraulic fracturing flowback (HFF) fluid (50% dilution); or, (3) deionized water (control). At 24-hours (hr), 3 weeks (wk), or 9-wk following the 6-wk exposure period, cohorts of mice were necropsied and adverse effects/persistence on the male reproductive system were examined. Ingestion of e-waste leachate or HFF fluid decreased number and concentration of sperm and increased both chromatin damage and numbers of morphological abnormalities in the sperm when compared to control mice. Levels of serum testosterone were reduced post-exposure (3- and 9-wk) in mice exposed to e-waste leachate and HFF when compared to time-matched controls, indicating the long-term persistence of adverse effects, well after the end of exposure. These data suggest that men living around or working in vicinity of either e-waste or hydraulic fracturing could face harmful effects to their reproductive health. From both a human health and economic standpoint, development of prevention and intervention strategies that are culturally relevant and economically sensitive are critically needed to reduce exposure to e-waste and HFF-associated toxic contaminants.