Flowback Fluids Research Articles

Ion composition of produced water from coalbed methane wells in western Guizhou, China, and associated productivity response

The chemical composition of produced water from coalbed methane (CBM) wells provides abundant information regarding the production dynamics of coal reservoirs. In this study, hydro-chemical analyses were conducted on 70 water samples collected in five batches of 21 CBM wells in China’s western Guizhou region. The ion composition of the produced water was used to evaluate the fracturing fluid flowback degrees and to predict the productivity of the CBM wells. The results indicate that the water samples could be sorted into two types: (1) the water samples from the Zhijin Block, which had exhibited the characteristics of the original coal seam water, and (2) the water samples from the Songhe and northern Guizhou Blocks, which had been affected by the fracturing fluid. The Na+/Cl− and alkalinity/Cl− ratios, and the Na+/Cl− and Na+/alkalinity ratios exhibit a positive relationship and an exponentially decaying relationship, respectively. In addition, when the concentrations of Cl− are <20 mEq/L, the residual alkalinity shows little variation with the increasing in the Cl− concentrations, which is discretely distributed between 28 and 57 mEq/L. Meanwhile, the other ionic concentrations also tend to be stable. Therefore, in this study, the Cl− concentration of 20 mEq/L is used as the criterion for complete flowback of fracturing fluid. Moreover, the source of the Cl− in the original coal seam water is related to the organic-bound chlorine complexes within the coal. Furthermore, there is a positive correlation between the HCO3− concentrations and the daily gas production.

A numerical model for fractured horizontal well and production characteristics: Comprehensive consideration of the fracturing fluid injection and flowback

Currently, many investigations on fractured well productivity are conducted. However, all this productivity studies are conducted based on the initial pressure and fluid distribution. In this work, taking the reservoir damage caused by fracturing fluid and the effect of fracturing fluid injection on pressure and saturation into consideration, a flow model of multistage fractured horizontal well is built, which is composed of fracturing fluid injection model and fracturing fluid flowback and production model. Numerical solving method is utilized to solve the model and model verification are presented through comparing with the test results of 12 fractured well. The effects of fracture fluid injection rate and fracturing fluid viscosity on pressure and saturation at the end of fracturing fluid injection are analyzed. And the effects of the reservoir oil viscosity, porosity, permeability, heterogeneous and reservoir damage on flowback and production characteristic are analyzed. The results show: (1) The distances of saturation and pressure variation area from the fracture are respectively 10 m and 20 m after the fracturing fluid injection is finished. When the fracturing fluid viscosity increases from 10 mPa s to 30 mPa s, the distance of pressure variation area from the fracture decrease. But the pressure and saturation near the hydraulic fracture increases. When the injection rate increases from 0.28 m3/min to 28 m3/min, the fracture length increases and the distances of pressure and saturation variation area from the fracture increase. The pressure near the fracture with a high injection rate is larger than that with a small injection rate. (2) With the development of reservoir, the water flow rate and water cut decreases, and the oil flow rate increases firstly and then decreases. When the reservoir oil viscosity increases from 1.5 mPa s to 2.5 mPa s, water cut increases. The maximum oil flow rate decreases from 16.4 to 6.2 m3/d. With the increase of reservoir permeability, the water cut decrease. When the reservoir porosity increases, the oil flow rate, water flow rate and cumulative fluid volume increase. While, the water cut decreases with the increase of reservoir porosity. When the residual resistance factor (RRF) increases from 1 to 1.08, the oil flow rate of when the RRF equals 1 is slight larger than that of when the RRF equals 1.08. The reservoir damage has slight effect on the water flow rate and water cut. (3) The development of heterogeneous reservoir is poorer than that of homogeneous reservoir when the development conditions are the same. This work provides a more accurate method to investigate the flowback and production characteristics of fractured well.

Technology Focus: Water Management (December 2019)

Technology Focus Recent trends in water management have taken a more-comprehensive and holistic approach toward the stewardship of water as a critical resource. The industry has broadened its view to address the complete life cycle of water, from the effect of water use, to the reuse or recycling of water, to the final disposal of•water. In unconventional reservoirs, the use of fresh water for fracturing fluids has been reduced greatly by the development of chemistries that facilitate the use of nonfreshwater sources and flowback fluids. In recent years, the participation of midstream water companies has changed the dynamics of water management, improving the processes by which water is conveyed and increasing the use of flowback or produced water. These companies are playing an increasing role in the infrastructure and operation of water management, sometimes owning and operating water pipelines and water-storage, produced-water-treatment, and produced-water disposal facilities.• Operators such as Southwestern Energy are taking a progressive approach in an effort to become freshwater-neutral, as outlined in paper SPE 187123.• This company, as an example, defines “freshwater-neutral” as a status in which the total water used is less than the sum of the alternative water and offsets. This company is using a combination of water-treatment technologies, aggressive water-reuse strategies, and conservation projects in local communities to achieve this goal. Technological advances have enabled a better understanding of the potential environmental impact of final disposal of produced water. This understanding derives from improved modeling and a deeper understanding of the relationship between water-disposal techniques and the environment, including the potential effect of injection wells on induced seismicity. Similarly, operators on the Norwegian Continental Shelf are using an environmental impact factor (EIF) to identify potential risks from specific produced-water discharges. The goal is to achieve an EIF known as “zero effects release.” The EIF can also be used to quantify the beneficial effects of different water-treatment methods. Recommended additional reading at OnePetro: www.onepetro.org. SPE 194575 A Case Study on Treating•Oil Contaminants and Heavy•Metal of Produced Water Through•Phytoremediation Using Reed-Bed Technology: A Success Story•of•15 Years of Operation of Heglig•Oil•Field•of Sudan by•Ajay Kumar, GNPOC Sudan, et al. SPE 191529 Fit-for-Purpose Water Treatment in Permian Shale—Field Data,•Laboratory Data, and Comprehensive•Overview by John Walsh,•CETCO Energy Services, et al. OMC 2019 1101 Analysis and Comparison•of Different Solutions for•Produced-Water Management—LCA•and Biodiversity Impact Assessment•by•Martino Pedullà, RINA•Consulting, et al.

A framework to determine sensitive inorganic monitoring indicators for tracing groundwater contamination by produced formation water from shale gas development in the Fuling Gasfield, SW China

Potential environmental impacts on shallow groundwater from shale gas development facilitated by horizontal drilling and hydraulic fracturing is a widely debated “hot topic”. In terms of potential aqueous phase contamination (including flowback fluids and produced water), there is a large gap in knowledge of the indicators for routine monitoring and contamination tracing, which should be considered critical and should be prioritized for analysis. Since formation water from shale formations is the main source of flowback fluids and produced water, and there are significant differences in some specific inorganic geochemical and isotopic compositions between shallow groundwater and formation water, this study has provided a framework to determine sensitive monitoring and diagnostic indicators for tracing potential groundwater contamination from produced water using end-member analysis. The results from a case study of the Fuling Gasfield, Sichuan Basin, SW China as the first and largest commercial shale gas development site in China, shows that produced authentic formation water with similar Br/Cl and Na/Cl ratio with seawater and low δ2H and δ18O values compared to the evaporated seawater might originate from evaporated seawater modified by water-rock interactions and be mixed with fresh meteoric water. The inorganic geochemical and isotopic indicators, such as Ba, Li, Na, Cl, Br, 87Sr/86Sr (as εSrsw) and δ11B are sensitive to the detection of contamination of fresh shallow groundwater by produced formation water, even in very small fractions (0.05%). Meanwhile, we present a groundwater contamination case related to shale gas development in the Fuling Gasfield. The robust conservative geochemical (Cl and Br) and isotopic (δ11B and εSrsw) mass balances show that 0.2–0.9% of formation water entered the shallow groundwater causing contamination. The case has also confirmed the effectiveness of those indicators. Findings from this study may help to improve groundwater monitoring and environmental regulations in countries with shale gas exploration and development.

Retention time prediction of hydrocarbons in cryogenically modulated comprehensive two-dimensional gas chromatography: A method development and translation application

Thermodynamic modeling of GC × GC separations provides a tool for rapid method evaluation and optimization. Separations of 95 hydrocarbons on two cryogenically modulated GC × GC systems (atmospheric outlet and vacuum outlet) are modeled, displaying average second dimension retention time modeling absolute errors of 0.17 s and 0.12 s respectively, and generating modeled chromatograms which sufficiently represent experimental data. A web-based GC × GC modeling routine is presented which allows users to model separations, currently focused on hydrocarbons, with full control over all system parameters. The method translation capabilities of the application are further demonstrated by replicating Piotrowski et al.’s GC × GC-HRT temporal distribution plots of hydraulic fracturing flowback fluid hydrocarbons [28].

Rapid water-rock interactions evidenced by hydrochemical evolution of flowback fluid during hydraulic stimulation of a deep geothermal borehole in granodiorite: Pohang, Korea

Flowback water from the 4215 m deep (True Vertical Depth) PX-1 borehole, following the August 2017 hydraulic stimulation of a granodiorite geothermal reservoir in Pohang, South Korea, was monitored for a suite of physicochemical, chemical and isotopic parameters. The results provide unique insights into mixing processes, fluid evolution and rapid water-rock interaction in a deep geothermal system. Injected water for stimulation was relatively fresh, oxidising surface water, with temperature 29.5 °C and pH c. 6.5. The flowback water showed an increasing content of most solutes, with the evolution conforming to an exponential ‘flushing’ model for conservative solutes such as chloride. Flowback water became progressively Na–Cl dominated, with a circumneutral pH (7.1) and negative oxidation-reduction potential (c. −180 mV). Some solutes (including, Na, K and Si) increased more rapidly than a flushing model would suggest, implying that these had been acquired by the flowback water due to mineral hydrolysis. Stable isotopes of O and H indicate that initially meteoric waters have undergone geothermal oxygen isotope exchange with minerals. Evolution of redox species in recovered water suggests progressively oxidising zonation around the injection borehole in an otherwise reducing reservoir. Rapidly increasing silica concentrations in flowback water suggests extensive quartz dissolution and indicated a reservoir temperature of up to 169 °C. This lends plausible, if equivocal support to the hypothesis that quartz dissolution by injection water may have contributed to triggering movement on the pre-stressed fault associated with the November 2017 Mw 5.5 Pohang earthquake.

Investigation of a critical choke during hydraulic-fracture flowback for a tight sandstone gas reservoir

Abstract Low porosity and permeability in a tight sandstone gas reservoir can cause problems during fracturing. If the fracturing fluid cannot be discharged in a timely fashion after fracturing, the fracturing fluid will move into the deep formation and result in secondary damage. Conversely, if the flowback rate of the fracturing fluid is too high, it will cause the proppant to backflow and reduce the efficiency of fracturing operation. Therefore, it is very important to control the choke sizes and flowback rates for the flowback process of a tight sandstone reservoir. In this study, a model of the time of the closed fracture considering the principle of material balance is built. Subsequently, the relationship between the wellhead pressure and the optimum diameter of the choke at different times is obtained using hydrodynamics and particle dynamics theory. Finally, the proposed optimization method is applied to an actual well from the Xinjiang tight gas reservoirs. Results show that a choke diameter can be reasonably optimized under different wellhead pressures, and that fracturing fluid flows back as much as possible and without proppant backflow. A sound design of a fracturing fluid flowback system is also provided. This study presents the mechanism of post-fracturing management and provides a better understanding of the flowback system in tight gas reservoirs.

Study of GLR and Inlet Velocity on Hydrocyclone for Fracturing Flow-Back Fluids

In this work, based on the Reynolds stress model (RSM) of the computational fluid dynamics (CFD) software Fluent and experimental method, the velocity field, pressure characteristics, split ratio, and separation efficiency of the hydrocyclone are analyzed under different gas-liquid ratios (GLRs). For the inlet velocity, the lower limit is ascertained by the flow field stability, the upper limit is largely determined by the energy consumption, and the optimum range is 4 m/s to 10 m/s. Within the optimum range, the peak value of tangential velocity increases while the GLR increases, whereas the pressure and pressure drop decrease. With the increase in the GLR, the axial velocity decreases, and the locus of zero vertical velocity shifts inward. The increase in the GLR causes more gas to collect at the vortex finder, which hinders the discharge of the solid-liquid mixture from the overflow, and the larger the GLR, the faster the decrease in the split ratio. The separation efficiency of particles with a particle size of 15 μm is increased by 6.75%, and the separation efficiency of particles with a particle size of 30 μm is increased by 0.57%. Meanwhile, the separation efficiency is increased by 2.43%, and the cut size d50 is reduced as the GLR increases.

Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells.

Fracture characterization is necessary to evaluate fracturing operations and forecast well performance. However, it is challenging to quantitatively characterize the complex fracture network in shale gas reservoirs because of the unknown density and reactivation of natural fractures. The flowback water transients can provide useful information about the complexity of the fracture network after the fracturing operations. In this paper, a mathematical model for modeling fracturing fluid flowback of hydraulically fractured shale gas wells is established. This proposed model characterizes the flow of water and gas in a hydraulic fracture-induced natural fracture–shale matrix system. Hydraulic, capillary, and osmotic convections; gas adsorption; and natural fracture closure are considered in this model. Flowback simulation of a hydraulically fractured shale gas well is conducted using the developed numerical simulator, and the water/gas transients between hydraulic fractures, natural fractures, and matrix are obtained. Finally, two field cases from the Longmaxi Formation, Southern Sichuan Basin, China, are used for comparison of the flowback data with the model results. The good match of the two water transients provides a group of fracture network parameters, that is, the effective length and conductivity of main hydraulic fractures and the density of induced natural fractures. The proposed model for describing the flowback process and its meaningful relationship with the fracture–network complexity provides an alternative approach for post-stimulation evaluation.

Mechanism of fracture damage induced by fracturing fluid flowback in shale gas reservoirs

In this paper, the Lower Silurian Longmaxi shale samples and the backflow fracturing fluid in the Changning Block of the Sichuan Basin were selected to investigate the damage mechanism of retained fracturing fluid to fractures in shale gas reservoirs. Thus, experiments were conducted on fracturing fluid backflow and gas-driving fracturing fluids. The changes of liquid permeability of shale samples, solid particle size distribution and turbidity of the backflow fracturing fluid were monitored. The gas permeability before and after fracturing fluid gas drive was compared, and the damage degree and mechanism of the backflow fracturing fluid to the fractures in shale samples were analyzed. And the following research results were obtained. First, the damage rate of shale permeability after the fracturing fluid backflow is between 53.1% and 97.6%, and the range of the solid particle size of the flowback fluid is significantly reduced. The main reservoir damage modes include phase trapping damage caused by liquid phase retention, blockage caused by the solid phase residue, particle migration induced by gas-carrying liquid and salt precipitation. Second, in the stage of gas phase flow, the damage rate of permeability drops to 23.1–80.2%, and the damage caused by liquid phase retention is relieved, but the damage caused by the blockage of solid phase residue and the salt precipitation of flowback on the facture surface is inevitable. Third, based on the damage mechanism of fracturing fluid backflow in shale gas wells to fractures, considering the treatment difficulty of the flowback and its damage to reservoir fractures, it is recommended to give a full play to the fracturing capacity of fracturing fluid and optimize the properties and dosages of fracturing fluid so as to reduce the flowback of fracturing fluid as much as possible.

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.

Geological characteristics and enrichment laws of normal-pressure shale gas in the basin-margin transition zone of SE Chongqing

The southeastern Sichuan Basin and its basin-margin transition zone (hereinafter referred to as “the basin-margin transition zone of SE Chongqing”) is the focus of normal-pressure shale gas exploration in China. In order to summarize the geological characteristics and enrichment laws of shale gas in the basin-margin transition zone of SE Chongqing, we analyzed the geological characteristics of shale gas reservoirs in the Nanchuan–Wulong area of this transition zone from the aspects of sedimentary formation, tectonic reworking and production characteristics by using geophysical, drilling, logging and testing data, and then we compared it with the overpressure shale gas reservoirs in the Jiaoshiba Block. Finally, we explored the main factors controlling the enrichment & high yields of normal-pressure shale gas in this transition zone and their hydrocarbon accumulation patterns. And the following research results were obtained. (1) Different from the over-pressure shale gas reservoirs in Jiaoshiba Block, the normal-pressure shale gas reservoirs in this transition zone are characterized by lower organic porosities, more developed micro-fractures, higher ratios of adsorbed gas, greater differences of stresses in two directions, lower geothermal gradients, lower formation pressure coefficients, higher initial fluid production rates and higher fluid flowback rates. (2) The enrichment & high yields of normal-pressure shale gas in this area is mainly controlled by three factors, i.e., carbon-rich, silicate-rich and graptolite-rich shale, organic pores, and tectonic stress field, among which, the first factor controlled by deepwater continental shelf facies is the basis of shale gas enrichment, the second is the main controlling factor of shale gas enrichment, and the third is the key factor of high-yield shale gas. (3) The hydrocarbon accumulation patterns of normal-pressure shale gas reservoirs in the transition zone can be divided into four types, including the anticline type, the syncline type, the slope type and the reverse fault type. And the enrichment & high-yield characteristics of shale gas in different hydrocarbon accumulation patterns are also clarified. In conclusion, the research results enrich the geological theory of enrichment & high-yield laws of normal-pressure shale gas and provide a support for the exploration and development of normal-pressure shale gas in complex structures.

Production data analysis of shale gas using fractal model and fuzzy theory: Evaluating fracturing heterogeneity

The development of shale-gas reservoirs has been dramatically accelerated with the technical breakthroughs made in the fields of horizontal well drilling and multistage hydraulic fracturing. After being restructured by hydraulic fracturing, the shale reservoir would have a complicated fracture network featuring great randomness. The accurate evaluation of the fracture network structure and the quantitative calculation of the fracturing fluid flowback are keys to the efficient development of shale-gas fields. In this paper, a new fractal seepage model of single fracturing section was established based on the conversion relationship of gas-liquid flow fractal dimension. Then, the sensitivity of model parameters and the flow characteristics of single fracture section were analyzed to determine the reason that gas production “rises first, and then drops down” at the initial production phase. Finally, the mathematical description of the heterogeneity of fracture networks was further proposed based on Fuzzy theory. Case studies in Fuling shale-gas field were performed by means of the Extended Monte Carlo Simulation and the optimal fracturing heterogeneity factors of typical wells are 0.25, 0.10 and 0.15. Compared with the homogeneous model, the accuracies of gas production and water production calculated by heterogeneous model are increased by up to 15% and 20%, respectively.

Research on the reuse technology of fracturing flowback fluids in fracking

ABSTRACTIt is necessary to develop a friendly method for reusing the fracturing flowback fluids (FFFs) because it could lead to toxic chemicals. It is investigated that all of the FFFs could be reused. The reused fracturing fluid system was optimized base on the treated FFFs. The viscosity of the reused fracturing fluid system could maintain 120 mPa∙s under 170 s−1, 120 °C. The ratio of storage modulus and loss modulus is 2.592 in the linear viscoelastic zone. The sedimentation velocity of proppant was 0.0424 mm/s at 90 °C. Therefore, it makes a very significant contribution to environmental protection and sustainability.

Shales Leaching Modelling for Prediction of Flowback Fluid Composition

The object of the paper is the prediction of flowback fluid composition at a laboratory scale, for which a new approach is described. The authors define leaching as a flowback fluid generation related to the shale processing. In the first step shale rock was characterized using X-ray fluorescence spectroscopy, X-ray diffractometry and laboratory analysis. It was proven that shale rock samples taken from the selected sections of horizontal well are heterogeneous. Therefore, the need to carry a wide range of investigations for highly diversified samples occurred. A series of leaching tests have been conducted. The extracts were analyzed after leaching to determine Total Organic Carbon and selected elements. For the results analysis significant parameters were chosen, and regression equations describing the influence of rocks and fracturing fluid parameters on the flowback fluid composition were proposed. Obtained models are described by high values of determination coefficients with confidence coefficients above 0.99 and a relatively low standard deviation. It was proven that the proposed approach regarding shale leaching can be properly described using shale models at a laboratory scale, however scaling up requires further investigations.

Multipurpose Usage of Magnetic Proppantsduring Shale Gas Exploitation

Abstract Magnetic material may be added to proppant, as the magnetic marker allows to determine the range and efficiency of hydraulic fracturing. However, magnetic proppant may be also used in flowback fluid treatment and monitoring of environmental pollution. As a result of shale gas hydraulic fracturing, large volume of flowback fluid is created. Flow back fluid have similar properties to fracturing fluid, but it is potentially enriched with large amount of salts and organic compounds leached from shale. Magnetic proppant may serve as a heterogeneous catalyst during organic pollutants decomposition. Additionally, in case of leakage and consequently the fracturing fluid pollution, magnetic proppant is placed into the soil environment. It can be detected using magnetometric methods. This article discusses the above-mentioned issues based on the knowledge and experience of the authors and the literature review.

A New Quantitive Predicting Model of Fracturing Fluid Flow-back: Based on Fractal Theory and Fuzzy Statistic Method

With the dramatically expanding of the horizontal well drilled and hydraulic fracturing technology, the exploitation of shale gas has entered a new phase. The complex fracture network will be formed during the massive hydraulic fracturing, which is difficult to be described precisely in mathematical models. Based on Fractal theory, a new mathematical description of gas and liquid flow in single stage of hydraulic fracture network is proposed and a BHFP superposition model of multistage fracture network is established to describe the fracture development and distribution information. This BHFP superposition model characterizes the reservoir heterogeneity by Fuzzy statistical method and can easily accomplish the historical matching task of production data by genetic algorithm. Our model has achieved good prediction results in the application of typical production wells in Fuling shale gas field.

Analysis of the influence factors of tight reservoir start-up pressure difference

Tight gas reservoir is not only characterized by low permeability, but also by high water saturation. This paper was studied on the basis of tight reservoir microscopic pore structure analysis, through gas depletion-drive development simulation experiments of constant rate production and constant pressure difference two ways, analyzed the influence factors of reservoir starting pressure difference, to explore the change law of tight reservoir start-up pressure. The study suggests that the pore structure throat radius of tight reservoir is small, and the throat occupies a large proportion of pore volume, and the throat is not only the seepage channel but also the important storage space. The experiment also shows that the throat radius, water saturation and effective stress are the main factors to determine the starting pressure difference of reservoir. So in the development process, some measures have been taken to reduce or control the start-up pressure near wellbore area such as well location optimization, perforating optimization, increasing fracturing fluid flowback rate and drainage gas recovery measures optimization, these measures have achieved positive effect in Sulige gas field.

Effects of hydration on fractures and shale permeability under different confining pressures: An experimental study

Water-rich fracturing fluids are injected into gas shale formations to promote the effective development of gas. However, the relationship between gas production decreases and the variability flow-back fluid behavior (rate and amount) remains a significant challenge to the industry. This study focused on the effects of water hydration on the rock fracture properties of a major gas shale formation in China. Shale from hydration experiments was characterized for a number of key parameters including length, volume, width, surface area, thickness and fracture frequency. X-ray computed tomography (CT) scanning was conducted on shale reservoir samples exposed to water at zero overburden stress and under three different confining pressures (725 psi, 2175 psi, and 2900 psi). CT scanning images were obtained to evaluate fracture evolutions during hydration for both the connected and unconnected fracture networks. In addition, permeabilities before and after hydration were also quantified. Results from the ambient condition experiment revealed the propagation of fractures, the formation of new fractures, and the formation of better connectivity caused by a more complicated fracture network. However, the fracture evolution of the other three samples under confining pressures are markedly different, including: more unconnected fracture networks, less fracture volume, and a poorer connectivity of fractures.

One-Step Preparation of Surface-Modified Particle Electrodes via Sol–Gel Method and Its Performance in Fracturing Flowback Fluid Treatment

One-Step Preparation of Surface-Modified Particle Electrodes via Sol–Gel Method and Its Performance in Fracturing Flowback Fluid Treatment