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Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

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Hydraulic fracturing is used in shale reservoir production, with low flowback rates and a large amount of fracturing fluid retained inside the reservoir. In this study, a stress sensitivity analysis experiment on the fracture inflow capacity was implemented to investigate the relationship between the hydraulic fracture (HF) and natural fracture (NF) inflow capacities and effective stress. A three-dimensional shale reservoir model was also constructed to couple the experimentally obtained laws with the numerical model to investigate the effects of the connection and closure of the fracture network on the retention of the fracturing fluid. The results show that the stress sensitivity of natural fractures is two orders of magnitude higher than that of hydraulic fractures. The seepage-absorption effect of capillary forces is not the whole reason for the large amount of fracturing fluid retention. The closure of the fracture network formed by natural and hydraulic fractures during the production process led to the storage of a large amount of fracturing fluid, and this process maintained the stability of the water production rate during the steady water production period. [ABSTRACT FROM AUTHOR]

Surfactants find utility in hydraulic fracturing operations for their ability to modify rock wettability and increase the flowback of fracturing fluid following proppant delivery. The performance of a series of nonionic and anionic surfactants was evaluated by gravity drainage displacement testing. Alkylbenzenesulfonates having alkyl chains possessing at least 16 carbons were among the best performers, yet a similar surfactant having an alkyl chain possessing only ~12 carbons performed quite poorly. These data illustrate that a critical chain length exists for this series. Lauryldimethylamine oxide also performed well. In general, those surfactants possessing the greatest ionic character outperformed nonionic surfactants. Critical micelle concentration, surface tension, contact angle, relative solubility number, and hydrophilic–lipophilic balance were determined for each surfactant studied. Unexpectedly however, few correlations between any of these physical and surface properties and performance in gravity drainage displacement tests were identified, underscoring the complexity of selecting surfactants suitable in the application. These data suggest that more real‐world test methods, employing stationary phases, temperatures and pressures that better mimic the fields and individual wells being considered, are needed to better guide surfactant selection. [ABSTRACT FROM AUTHOR]

The global shale gas resources are huge and have good development prospects, but shale is mainly composed of nanoscale pores, which have the characteristics of low porosity and low permeability. Horizontal drilling and volume fracturing techniques have become the effective means for developing the shale reservoirs. However, a large amount of mining data indicate that the fracturing fluid trapped in the reservoir will inevitably cause hydration interaction between water and rock. On the one hand, the intrusion of fracturing fluid into the formation causes cracks to expand, which is conducive to the formation of complex fracture networks; on the other hand, the intrusion of fracturing fluid into the formation causes the volume expansion of clay minerals, resulting in liquid-phase trap damage. At present, the determination of well closure time is mainly based on experience without theoretical guidance. Therefore, how to effectively play the positive role of shale hydration while minimizing its negative effects is the key to optimizing the well closure time after fracturing. This paper first analyzes the shale pore characteristics of organic pores, clay pores, and brittle mineral pores, and the multi-pore self-absorption model of shale is established. Then, combined with the distribution characteristics of shale hydraulic fracturing fluid in the reservoir, the calculation model of backflow rate and shut-in time is established. Finally, the model is validated and applied with an experiment and example well. The research results show that the self-imbibition rate increases with the increase in self-imbibition time, and the flowback rate decreases with the increase in self-imbibition time. The self-imbibition of slick water is the maximum, the self-imbibition of breaking fluid is the minimum, and the self-imbibition of mixed fluid is the middle, and the backflow rates of these three liquids are in reverse order. It is recommended the shut-in time of Longmaxi Formation shale is 17 days according to the hydration and infiltration model. [ABSTRACT FROM AUTHOR]

Multiple fractured horizontal wells (MFHWs) currently are the only possible means of commercial production from the low and ultra-low permeability unconventional gas reservoirs. In early production time, flowback fluid, which constitutes of hydraulic water and gas flow within fractures, is collected and analyzed. Flowback analysis has been shown to be a useful tool to estimate key properties of the hydraulic fracture such as conductivity and pore volume. Until date, most tools of flowback analysis rely on empirical and approximate methods. This study presents an improved Green-function-based semianalytical solution for performance analysis of horizontal gas wells during flowback and early production periods. The proposed solution is derived based on coupling the solutions of two domains: a rigorously derived Green’s function-based integral solution for single-phase gas flow in matrix, and a finitedifference, multiphase solution for gasewater two-phase flow in the fracture. The validity of proposed semi-analytical solution is verified by finely gridded numerical models built in a commercial simulator for a series of synthetic cases considering a variety of fluid and reservoir property combinations, as well as various different production constraints. Comparisons against available empirical and approximate methods are also provided for these cases. [ABSTRACT FROM AUTHOR]

Copyright of Journal of Northeast Petroleum University is the property of Journal of Northeast Petroleum University Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Fault slip induced by gas injection and extraction cycles in underground gas storage (UGS) sites have been reported in many countries. Knowledges of the contemporary in situ stress condition and its evolution with gas injection and extraction cycles are crucial to estimate the fault-slip tendency ( T s ). Using the Wx-1 UGS reservoir in the Turpan Basin (China) as an example, we studied the evolution of the stress state and fault-slip tendency associated with the injection and extraction cycles. To assess the minimum horizontal stress (Shmin) in the storage reservoir and its caprock, we conduct flowback-assisted minifrac tests to measure the magnitudes. The magnitudes of maximum horizontal stress (Shmax) were estimated and constrained by multiple sources. The 3D in situ stress field was constructed by the finite-element method (FEM), constrained by field stress measurements. Using coupled reservoir–geomechanical simulations, we estimated the changes in stress state over time and the tendency for fault slip in response to gas injection and extraction. The results showed that (1) the in situ stress state at Wx-1 UGS field is a strike-slip (SS) faulting stress state; (2) for fault-slip analysis, decoupled analysis considering only the pore pressure-induced fault slip can overestimate the pore pressure needed to cause the fault slip ( P sf ), while coupled analysis using a poroelastic FEM formulation considers both pore pressure and injection-induced shear stress changes and can provide more reasonable estimates of P sf ; (3) both the mean effective stresses ( p ′ ) and shear stresses (τ ) changes with the injection and extraction cycles; (4) the fault-slip tendency increases continuously with gas injection and decreases with gas extraction; (5) the faults striking at low angles with respect to the orientation of Shmax are critically stressed in the contemporary in situ stress field, and the possibility of injection-induced fault slippage is the controlling factor of the maximum operation pressure (MOP) of this UGS site. Highlights: Flowback-assisted minifrac tests were conducted in the low-permeability caprock formations to measure the in situ stress conditions efficiently. 3D in situ stress field was constructed by FEM simulations and constrained by minifrac tests. Coupled reservoir–geomechanics simulations were used to investigate the in situ stress evolution with gas injection and production cycles and to analyze the fault-slip tendency. The slip tendency undergoes temporal changes due to the fluctuation of both shear stress and mean effective stress during injection and extraction cycles. The maximum operation pressure (MOP) of this UGS site is determined by the likelihood of fault slippage caused by injection. [ABSTRACT FROM AUTHOR]

More accurate characterization and prediction of the in-situ distribution of fracturing fluid in fractured reservoirs are needed for enhancing well productivity. In this study, an implicit-sequentially coupled flow/geomechanics simulator incorporating an efficient discrete fracture model is developed to model fluid distribution and recovery performance of ultra-low permeability gas reservoirs. The finite-volume and finite-element methods are used for space discretization of the flow and geomechanics equations, respectively, while the backward Euler method is employed for time discretization. The flow and geomechanics equations are solved sequentially based on fixed-stress splitting. An efficient discrete-fracture model is used to explicitly model the fractured system. Flexible unstructured gridding is employed to model arbitrarily-oriented fractures. The interrelations among pore volume, permeability and geomechanical conditions are considered dynamically using two-way coupled flow and geomechanics computations. The geometry of fracture (networks) due to hydraulic fracturing has significant impacts on the fracturing fluid recovery efficiency and ensuing fluid distribution. Under the same injection volume, the fracturing fluid recovery is higher when the fracture geometry is planar. Fluid recovery is relatively lower whenever natural fractures are activated during fracturing treatments; flowback time is also shortened when complex fracture network with enlarged fracture interface is present. Fracturing fluid in hydraulic fractures may leak off into the natural fractures and subsequently imbibes into the surrounding matrix due to capillarity effects. The fracturing fluid recovery and in-situ fluid distribution are sensitive to the shut-in duration and fracture closure behavior. This study analyzes the coupled flow-geomechanical responses of fractured gas reservoirs during the post-fracturing periods. Understanding the fate of the fracturing fluid can provide insights on, to some extent, the stimulated fracture volume, size of the water invasion zone, and efficiency of the fracturing design. The simulation predictions can also provide more accurate initial reservoir conditions (e.g. distributions of different phases and pressure) for long-term well performance estimation.

More accurate characterization and prediction of the in-situ distribution of fracturing fluid in fractured reservoirs are needed for enhancing well productivity. In this study, an implicit-sequentially coupled flow/geomechanics simulator incorporating an efficient discrete fracture model is developed to model fluid distribution and recovery performance of ultra-low permeability gas reservoirs. The finite-volume and finite-element methods are used for space discretization of the flow and geomechanics equations, respectively, while the backward Euler method is employed for time discretization. The flow and geomechanics equations are solved sequentially based on fixed-stress splitting. An efficient discrete-fracture model is used to explicitly model the fractured system. Flexible unstructured gridding is employed to model arbitrarily-oriented fractures. The interrelations among pore volume, permeability and geomechanical conditions are considered dynamically using two-way coupled flow and geomechanics computations. The geometry of fracture (networks) due to hydraulic fracturing has significant impacts on the fracturing fluid recovery efficiency and ensuing fluid distribution. Under the same injection volume, the fracturing fluid recovery is higher when the fracture geometry is planar. Fluid recovery is relatively lower whenever natural fractures are activated during fracturing treatments; flowback time is also shortened when complex fracture network with enlarged fracture interface is present. Fracturing fluid in hydraulic fractures may leak off into the natural fractures and subsequently imbibes into the surrounding matrix due to capillarity effects. The fracturing fluid recovery and in-situ fluid distribution are sensitive to the shut-in duration and fracture closure behavior. This study analyzes the coupled flow-geomechanical responses of fractured gas reservoirs during the post-fracturing periods. Understanding the fate of the fracturing fluid can provide insights on, to some extent, the stimulated fracture volume, size of the water invasion zone, and efficiency of the fracturing design. The simulation predictions can also provide more accurate initial reservoir conditions (e.g. distributions of different phases and pressure) for long-term well performance estimation.

We aim at the development of a general modelling workflow for design and optimization of the well flowback and startup operation on hydraulically fractured wells. Fracture flowback model developed earlier by the authors is extended to take into account several new fluid mechanics factors accompanying flowback, namely, viscoplastic rheology of unbroken cross-linked gel and coupled "fracture-reservoir" numerical submodel for influx from rock formation. We also developed models and implemented new geomechanical factors, namely, (i) fracture closure in gaps between proppant pillars and in proppant-free cavity in the vicinity of the well taking into account formation creep; (ii) propagation of plastic deformations due to tensile rock failure from the fracture face into the fluid-saturated reservoir. We carried out parametric calculations to study the dynamics of fracture conductivity during flowback and its effect on well production for the set of parameters typical of oil wells in Achimov formation of Western Siberia, Russia. The first set of calculations is carried out using the flowback model in the reservoir linear flow regime. It is obtained that the typical length of hydraulic fracture zone, in which tensile rock failure at the fracture walls occurs, is insignificant. In the range of rock permeability in between 0.01 mD and 1 D, we studied the effect of non-dimensional governing parameters as well as bottomhole pressure drop dynamics on oil production. We obtained a map of pressure drop regimes (fast, moderate or slow) leading to maximum cumulative oil production. The second set of parametric calculations is carried out using integrated well production modelling workflow, in which the flowback model acts as a missing link in between hydraulic fracturing and reservoir commercial simulators. We evaluated quantitatively effects of initial fracture aperture, proppant diameter, yield stress of fracturing fluid, pressure drop rate and proppant material type (ceramic and sand) on long-term well production beyond formation linear regime. The third set of parametric calculations is carried out using the flowback model history-matched to field data related to production of four multistage hydraulically fractured oil wells in Achimov formation of Western Siberia, Russia. On the basis of the matched model we evaluated geomechanics effects on fracture conductivity degradation. We also performed sensitivity analysis in the framework of the history-matched model to study the impact of geomechanics and fluid rheology parameters on flowback efficiency. [ABSTRACT FROM AUTHOR]

• Novel approach extends Soliman. • Craig model for after-closure analysis. • Innovative analysis technique addresses the gap in hydraulic fracturing testing. • The model detects flow regimes, estimates permeability, and reservoir pressure. • Simulations reveal a time advantage of flowback tests in permeability assessment. In this study, our primary objective is to introduce a novel approach for estimating permeability and reservoir pressure during the after-closure period of pump-in/flowback tests. While existing techniques primarily focus on Diagnostic Fracture Injection Tests (DFIT) for formation parameter estimation, no methods have been developed for analyzing the shut-in period following pump-in/flowback tests. We extend the after-closure analysis based on the Soliman and Craig model to make it applicable to pump-in/flowback tests. Our analysis involves studying after-closure data to calculate formation permeability and reservoir pressure. During the after-closure period, we introduce a model to identify the flow regime and estimate permeability, particularly during the pseudo-radial flow period. To validate our model, we compare its performance with conventional DFIT cases using a finite difference numerical simulator. Our simulations reveal a time advantage for pump-in/flowback tests over traditional DFIT in permeability estimation. This pioneering approach represents a significant advancement in the field, providing a unique and efficient method for estimating reservoir properties during radial flow in pump-in/flowback tests. [ABSTRACT FROM AUTHOR]

This study presents an analytical model for estimating minimum horizontal stress in hydraulic fracturing stimulations. The conventional Diagnostic Fracture Injection Test (DFIT) is not practical in ultra-tight formations, leading to the need for pump-in/flowback tests. However, ambiguities in the results of these tests have limited their application. The proposed model is based on the linear diffusivity equation and material balance, which is analytically solved and verified using a commercially available numerical simulator. The model generates a linear graph in which the pressure drop and its derivative are plotted versus the developed solution time function. The closure pressure is determined when the slope of the derivative deviates from linearity. The model was applied to several cycles of field flowback tests and found to eliminate the ambiguity associated with identifying the fracture closure. Furthermore, the minimum In-situ stresses estimated using this approach are verified via downhole strain measurement and synthetic data from a fully 3D commercial fracturing simulator. The proposed technique outperformed other conventional methods in analyzing challenging injection/shut-in tests, showing improved results and reducing uncertainty in estimated fracture parameters. This model is expected to scale down the need for multiple field trials and provide a reliable estimation of minimum stress. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing of shale gas reservoirs is characterized by large fracturing fluid consumption, long working cycle and low flowback efficiency. Huge amounts of fracturing fluid retained in shale reservoirs for a long time would definitely cause formation damage and reduce the gas production efficiency. In this work, a pressure decay method was conducted in order to measure the amount of fracturing fluid imbibition and sample permeability under the conditions of formation temperature, pressure and adsorbed methane in real time. Experimental results show that (1) the mass of imbibed fracturing fluid per unit mass of shale sample is 0.00021–0.00439 g/g considering the in-situ pressure, temperature and adsorbed methane. (2) The imbibition and flowback behavior of fracturing fluid are affected by the imbibition or flowback pressure difference, pore structure, pore surface properties, mechanical properties of shale and mineral contents. (3) 0.01 mD and 0.001 mD are the critical initial permeability of shales, which could be used to determine the relationship between the formation damage degree and the flowback pressure difference. This work is beneficial for a real experimental evaluation of shale formation damage induced by fracturing fluid. [ABSTRACT FROM AUTHOR]

Currently, volume fracturing of horizontal wells is the main technology for shale oil development. A large amount of fracturing fluid is injected into the formation, but the flowback efficiency is very low. Besides, the impact of fluid retention on productivity is not fully clear. There is still a debate about fast-back or slow-back after fracturing, and the formulation of a reasonable cleanup scheme is lacking a theoretical basis. To illustrate the injected-fluid recovery and production performance of shale oil wells, an integrated workflow involving a complex fracture model and oil-water production simulation was presented, enabling a confident history match of flowback data. Then, the impacts of pumping rate, slick water ratio, cluster spacing, stage spacing and flowback rate were quantitatively analyzed. The results show that the pumping rate is negatively correlated with injected-fluid recovery, but positively correlated with oil production. A high ratio of slick water would induce a quite complex fracture configuration, resulting in a rather low flowback efficiency. Meanwhile, the overall conductivity of the fracture networks would also be reduced, as well as the productivity, which indicates that there is an optimal ratio for hybrid fracturing fluid. Due to the fracture interference, the design of stage or cluster spacing is not the smaller the better, and needs to be combined with the actual reservoir conditions. In addition, the short-term flowback efficiency and oil production increase with the flowback rate. However, considering the damage of pressure sensitivity to long-term production, a slow-back mode should be adopted for shale oil wells. The study results may provide support for the design of a fracturing scheme and the optimization of the flowback schedule for shale oil reservoirs. [ABSTRACT FROM AUTHOR]

In this study, flowback-assisted minifrac tests were conducted in low-permeability shale and salt formations to measure the in situ stress. An injection/flowback testing protocol was implemented in each test to achieve accuracy and efficiency. Accurate and efficient injection/flowback testing is very important, given the impermeable nature of these formations and the need to complete each test as quickly as possible. Each flowback cycle yields a distinct and repeatable fracture closure signature, simplifying the interpretation of the fracture closure pressure. The objective of this paper is to share our field experience and to present a numerical analysis of the flowback test pressure responses, fracture closure behaviors, and fracture closure diagnostic methods. Examples from open-hole and cased-hole minifrac tests are used to demonstrate site operation procedures. Then, two numerical models are presented for simulating the fracture closure behavior during a flowback test. Field evidence is provided to demonstrate that the fracture closure pressures from the flowback tests are identical to those from tests without flowback. The fracture closure diagnostic methods for flowback tests are discussed, and it is found that the G-function diagnostic method yields a distinct fracture closure signal during the flowback tests. This study is intended to provide additional insights regarding flowback tests by sharing our successes, experience, and knowledge, thereby benefiting the industry.

Abstract Hydraulic fracturing has been successfully employed for unconventional oil and gas recovery for decades. During flowback, the closure of the fracture may exhibit with the pressure drop of fracturing fluid dewatering. However, fracture closure always is ignored or treated as stress‐dependent fracture properties in previous flowback models. This paper presented a dynamic fracture model, which can comprehensively capture the dynamic behavior of hydraulic fractures during the flowback. A nonlinear relationship between fracture aperture and contact stress acting on the fracture surfaces is adopted to simulate fracture closure. The fracture aperture calculated by the displacement discontinuity method (DDM) is used to characterize the fracture pore volume and fracture conductivity, which will be dynamically updated in the flow model. Then, the pressure and saturation of each phase, along with the displacement on the fracture surface, are calculated by solving flow equations and geomechanics equations with iterative coupling approach. The new semi‐analytical model is validated by comparing it with a fully coupled stress‐porosity pressure numerical simulation model setup by ABAQUS® and CMG. Then, the dynamic behaviors of hydraulic fractures are investigated in detail by several cases. Results show that fracture closure is an important reason for the decline in production during the flowback and early production. And it is more important to enhance the properties of the stimulated reservoir volume (SRV) than to only create a fracture with high conductivity. Lastly, the key parameters (the fracture effective length and fracture conductivity under variable contact stress) can be interpreted by history‐matching the field flowback data.

Water blockage after hydraulic fracturing is one of the major challenges in shale oil recovery which affects the optimal production from the reservoir. The water blockage represents a higher water saturation near the matrix-fracture interface, which decreases the hydrocarbon relative permeability. The removal of water blockage in the field is typically carried out by soaking the well (i.e., shut-in) after hydraulic fracturing operation is finished. This soaking period allows water redistribution, which decreases the water saturation near the matrix-fracture interface. However, previous field reports show that there is not a strong consensus on whether shut-in is beneficial in terms of production rate or ultimate oil recovery. Due to the large number of parameters involved in hydraulic fracturing and tight formations, it is challenging to select which parameter plays the dominant role in determining the shut-in performance. Furthermore, literature on field case studies does not frequently report the parameters which are of researchers’ interest. In other words, the challenge of evaluating shut-in performance not only lies on the complexity of parameters and effects involved within the reservoir, but also the limited number of field case studies which report a comprehensive list of fracturing and reservoir parameters.This paper aims to investigate the effect of well soaking timing on shut-in performance. This idea to investigate the shut-in timing effect is motivated by the fact that in the field, shut-in can take place either immediately after hydraulic fracturing but before the first flowback (i.e., pre-flowback) or sometime after the first flowback (i.e., post-flowback). The timing of shut-in is believed to influence the production performance, because it dictates how much water is allowed to imbibe from the fractures to the matrix before the extended production. A numerical model is built and validated by a successful history match with numerous data from core-flood experiments. Our previous study shows that shut-in performance depends heavily on the desiccation state of the formation: in non-desiccated formations, longer shut-in (pre-flowback) results in a lower regained hydrocarbon relative permeability, but in desiccated formations, longer shut-in (pre-flowback) does not affect the regained hydrocarbon relative permeability.In this study, our model further demonstrates that shut-in performed after the first flowback (i.e., post-flowback) can help ensure a higher regained oil relative permeability than shut-in performed before the first flowback (i.e., pre-flowback) in such non-desiccated formations. A mechanistic analysis on the water blockage mitigation from these two shut-in timings is also presented. As a result, this study proposes that flowback should be carried out immediately following hydraulic fracturing, even if an extended shut-in is to be performed later.

Acidified hydraulic fracturing technology is a technical measure that uses acid liquid to react with minerals in near wells or reservoirs to enhance permeability, oil well and shale gas extraction, and increase the injection volume of wells. After the acidification construction is completed, the residual acid liquid will be discharged to the ground, which forms acidified waste liquid with low pH and complex composition. Recent studies providing snapshots of processing technology on the acidified waste have highlighted the need to convert the high concentration of Fe(II) in the acidified wastewater into flocculating components through advanced oxidation process. Here we report the discovery of the oxidation kinetics of ferrous ion in simulated acidified waste system, which based on the analysis of major pollutants and high iron content. We show that the change of concentration of ferrous ions was determined by chemiluminescence in tandem with flow injection, and the reaction of hydrogen peroxide with Fe(II) is a pseudo-first-order reaction. The reaction rate constants at Fe(II) of 50, 100 and 150 mg/L are 0.12612, 0.41686, 1.18230 s−1 respectively. In addition, we evaluated the adaptability of the catalytic oxidation system to acidified waste liquid. This offers a theoretical basis for treatment of acid hydraulic fracturing flowback and a series of treatability of tests, which serves to guide the selection of suitable treatment approach.

During hydraulic fracturing, thousands of barrels of fluid are injected into the rock surrounding the created fractures. Observations show that later during flowback, only a small fraction of the injected fluid volume is produced back. In tight naturally fractured formations, this can be explained by the leading role of preexisting rock discontinuities in the transport of fluids in such rocks. In this work, we investigate the mechanics of injected fluid flow in and out of preexisting rock discontinuities during a typical operational sequence of fracturing treatment, well shut-in and flowback. The mechanics of fluid flow in compliant discontinuities, where conductivity is sensitive to stress changes, is different from that in a stiff rock matrix. To understand and quantify rock pressurization, fluid leakoff and flowback rates, we develop a numerical model of fluid flow in a system of arbitrarily oriented discontinuities. Using this model, we predict spatial distribution of the injected fluid in a naturally fractured rock at any time after the beginning of the fracturing treatment as well as after the well shut-in and during flowback. The model explains the trapping of injected fluid in the discontinuities during production. We validate the model by comparison with field data and provide rough estimates of the volumetric fracturing fluid accumulation in the rock discontinuities after the treatment. The spatial extent of rock "flooding" around hydraulic fractures is found to depend on the density and orientation of rock discontinuities. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing has been successfully employed for unconventional oil and gas recovery for decades. During flowback, the closure of the fracture may exhibit with the pressure drop of fracturing fluid dewatering. However, fracture closure always is ignored or treated as stress‐dependent fracture properties in previous flowback models. This paper presented a dynamic fracture model, which can comprehensively capture the dynamic behavior of hydraulic fractures during the flowback. A nonlinear relationship between fracture aperture and contact stress acting on the fracture surfaces is adopted to simulate fracture closure. The fracture aperture calculated by the displacement discontinuity method (DDM) is used to characterize the fracture pore volume and fracture conductivity, which will be dynamically updated in the flow model. Then, the pressure and saturation of each phase, along with the displacement on the fracture surface, are calculated by solving flow equations and geomechanics equations with iterative coupling approach. The new semi‐analytical model is validated by comparing it with a fully coupled stress‐porosity pressure numerical simulation model setup by ABAQUS® and CMG. Then, the dynamic behaviors of hydraulic fractures are investigated in detail by several cases. Results show that fracture closure is an important reason for the decline in production during the flowback and early production. And it is more important to enhance the properties of the stimulated reservoir volume (SRV) than to only create a fracture with high conductivity. Lastly, the key parameters (the fracture effective length and fracture conductivity under variable contact stress) can be interpreted by history‐matching the field flowback data. [ABSTRACT FROM AUTHOR]

Due to the complex microscope pore structure of shale, large-scale hydraulic fracturing is required to achieve effective development, resulting in a very complicated fracturing fluid flowback characteristics. The flowback volume is time-dependent, whereas other relevant parameters, such as the permeability, porosity, and fracture half-length, are static. Thus, it is very difficult to build an end-to-end model to predict the time-dependent flowback curves using static parameters from a machine learning perspective. In order to simplify the time-dependent flowback curve into simple parameters and serve as the target parameter of big data analysis and flowback influencing factor analysis, this paper abstracted the flowback curve into two characteristic parameters, the daily flowback volume coefficient and the flowback decreasing coefficient, based on the analytical solution of the seepage equation of multistage fractured horizontal Wells. Taking the dynamic flowback data of 214 shale gas horizontal wells in Weiyuan shale gas block as a study case, the characteristic parameters of the flowback curves were obtained by exponential curve fittings. The analysis results showed that there is a positive correlation between the characteristic parameters which present the characteristics of right-skewed distribution. The calculation formula of the characteristic flowback coefficient representing the flowback potential was established. The correlations between characteristic flowback coefficient and geological and engineering parameters of 214 horizontal wells were studied by spearman correlation coefficient analysis method. The results showed that the characteristic flowback coefficient has a negative correlation with the thickness × drilling length of the high-quality reservoir, the fracturing stage interval, the number of fracturing stages, and the brittle minerals content. Through the method established in this paper, the shale gas flowback curve containing complex flow mechanism can be abstracted into simple characteristic parameters and characteristic coefficients, and the relationship between static data and dynamic data is established, which can help to establish a machine learning method for predicting the flowback curve of shale gas horizontal wells.

Flowback and produced water generated by the hydraulic fracturing of unconventional oil and gas plays contain a suite of cations (e.g., metals) typically in a high salt (e.g., NaCl) matrix. Here, we analyzed the chemical (cation) composition of production fluids associated with natural gas and oil development (e.g., flowback, produced water, impoundment fluids), along with mine drainage, and surface and ground water samples using ICP-OES and ICP-MS. ICP-MS and ICP-OES analytical performance and interference effects were evaluated. Both platforms exhibited excellent analytical spike recoveries, detection limits for blank and spiked solutions, and accuracy for standard certified reference materials. Mass ratio analyses using Ca/Sr, Ca/Mg, Ba/Sr, Mg/Sr, and B and Li, were assessed for their efficacy in differentiation among brines from conventional oil wells, produced water from unconventional oil and gas wells and impoundments, mine drainage treatment pond water, groundwater, and surface water. Examination of Mg/Sr ratios when compared with Li concentrations provide clear separation among the different types of samples, while Ca/Mg versus Ca/Sr correlations were useful for distinguishing between conventional and unconventional oil and gas fluids. [ABSTRACT FROM AUTHOR]

Unconventional natural gas extraction by hydraulic fracturing requires millions of gallons of water and generates flowback water, produced water and recycled fluids of varying chemical composition. Ion chromatography (IC) is a relatively low cost and efficient means to determine the anionic composition, however, the wide range in anionic content of these fluids poses a challenge to analytical methods developed for "natural" waters. We report here that the combination of UV and conductivity detectors increased detection sensitivity (e.g., 10–50 ppb) and expanded the number of anions detectable in a single sample run. Samples from four unconventional shale gas wells, two impoundments, nine conventional oil wells, two freshwater streams and mine drainage samples were analyzed in this study. All produced water samples and impoundment samples had high chloride (17,500–103,000 mg L−1, 93,900 to 134,000 mg L−1, 27,700 and 30,700 mg L−1), bromide (178–996 mg L−1, 183–439 mg L−1, 230 and 260 mg L−1) and conductivity (38,500–160,000 μS/cm3, 95,300 to 183,000 μS/cm3, 61,500 and 103,000 μS/cm3), respectively, relative to mine drainage and freshwater stream samples. Molar ratio analysis using Cl−/Br− to Cl− and SO42−/Cl− to Br− revealed significant differences between the samples, providing a simple means for distinguishing water impacted by different sources of contamination. [ABSTRACT FROM AUTHOR]

Identifying the types of contamination and their sources in surface and groundwater is fundamental for effective protection of private and public source waters. Here we employed mass ratio analyses of a variety of anion and cation pairs to characterize flowback, produced water, and mine drainage. These endmembers were used to evaluate the source contributions of natural surface and ground water samples. A total of 1,177 ground water and surface water samples were analyzed including high-quality source waters and waters suspected of being impacted by drilling and mining activity. We found the following chemical ratios resolved different sources of contamination: Mg/Na vs SO4/Cl; SO4/Cl vs Mg/Li; Br/SO4 vs Ba/Cl; and Br vs Mg/Li. While no single parameter or mass ratio pairing by itself was definitive it was possible to converge on a likely source of contamination using multiple lines of analytical evidence. Further, this process clarified sources in impacted samples where one or more parameters commonly considered diagnostic of specific sources (e.g., Br, Ba), were below detection limits (e.g., too dilute) or not tested for. Ultimately, movement of sample values within the mass ratio space allows tracking of changes in water quality and contamination source dynamics as the water chemistry evolves. [ABSTRACT FROM AUTHOR]

• A supercritical CO2 fracturing flowback wellbore flow model is developed. • The heat source term and sink are considered in the model. • The coupling solution of tubing-annulus-formation is carried out. • The effects of construction parameters are discussed. Supercritical CO 2 fracturing is a new type of waterless technology developed in recent years. When the supercritical CO 2 flows back after fracturing, the formation water is lifted by the upward movement of CO 2. Since the pressure gradually decreases along the wellbore and the temperature also decreases due to the CO 2 expansion, it is easy to result in the formation of hydrate under the conditions of high pressure and low temperature. In order to prevent the clogging of the wellbore due to CO 2 hydrate, the wellbore temperature and pressure need to be predicted and regulated. Based on the Span-Wagner CO 2 gas state equation and the Fenghour gas transport equation, combined with the classical wellbore flow heat transfer model, a supercritical CO 2 fracturing flowback wellbore flow model with heat source and sink considered is developed, the dual coupling solution of axial and radial borehole is realized by iterating the pressure and temperature and coupling of tubing-annulus-formation. The results show that the wellbore pressure and temperature both decrease from the bottom to the top of the well, which is similar to the flow in oil and gas production. The parameters such as discharge output, tubing size, formation temperature gradient and pressure gradient have a great influence on the wellbore temperature and pressure. The reduction of the discharge output and the increase of the tubing size can effectively keep the wellbore temperature high and reduce the risk of CO 2 hydrate formation. The discharge time has almost no effect on the wellbore pressure, and only slightly affects the wellbore temperature. The results can provide guidance for the study of supercritical CO 2 fracturing flowback. [ABSTRACT FROM AUTHOR]

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• Demonstrated transport and biodegradation of hydraulic fracturing wastewater components. • Characterized a microbial consortium capable of degrading all target compounds. • Extractive membrane bioreactor achieved successful remediation of organic contaminants. • Performance comparison revealed advantages of Hytrel™ over PDMS membranes. The biodegradation of selected organic constituents present in hydraulic fracturing wastewater were examined in an extractive membrane bioreactor (EMB) operating with Hytrel™ 3548 tubing. Synthetic hydraulic fracturing wastewater was generated via an extensive literature review and contained high concentrations (1000 mg L−1) of contaminant compounds of varied hydrophobicity, viz. methyl ethyl ketone, benzene, phenol and acetic acid, as well as 30–120 g L−1 of Cl− at low pH. This hostile wastewater was circulated through the polymeric tubing, selectively transporting the organic compounds through the membrane for biological degradation by an enriched bacterial consortium. 16S rDNA analysis revealed the presence of five dominant microbial strains within the consortium, including: Pseudomonas sp., Comamonas sp., Achromobacter sp., Lysinibacillus sp., and Oxalobacter sp. EMBs in batch operation achieved 99% removal of methyl ethyl ketone, benzene, and phenol after 72 h and effectively removed acetic acid up to its ionization point. Continuous EMB operation provided 99% removal of benzene and phenol, 96% removal of methyl ethyl ketone, and 53% of acetic acid. The treatment of synthetic hydraulic fracturing fluid demonstrated the effectiveness of carefully selected amphiphilic polymers in EMBs for treating the hydrophilic and hydrophobic organic profile found in hydraulic fracturing wastewaters. [ABSTRACT FROM AUTHOR]

Abstract Quantitative analysis of flowback data provides an early opportunity to interpret hydraulic fracture properties of fractured wells in unconventional reservoirs. In recent years, a number of studies have been dedicated to the analysis of single-phase flow data prior to hydrocarbon breakthrough and multi-phase flow data after hydrocarbon breakthrough during flowback. This study provides a new model to simulate flowback of fractured tight oil wells with planar fractures or a complex fracture network. In the model, fractures are discretized into a number of segments and the fully numerical method is used to model fracture flow. It is assumed that the pressure interference in the matrix caused by these fracture segments can be accounted using a no-flow boundary condition and that the drainage volumes of fracture segments form isolated regions to allow for linear flow from the matrix to each segment. To model this behavior, matrix flow is simulated using the analytical transient linear flow solution which is dynamically coupled with the fracture flow model by imposing continuity of pressure and flux on the fracture surfaces. The model is simple, but rigorous enough to take into account the important physics of the fracture system, including arbitrary fracture geometries and fracture conductivity distributions. The pressure and saturation gradients of each phase in fractures are accounted for. The ease of model setup and improved computational performance makes it convenient for practical application. The new model is verified with a commercial reservoir simulator. Investigation of the assumption of no-flow boundary condition for the pressure interference in the matrix caused by the fracture segments reveals that the assumption becomes poorer with increasing matrix permeability and decreasing fracture permeability. Flow regime analysis demonstrates that, for planar fractures, water exhibits an early transient linear flow period (first linear flow in the fracture) followed by boundary-dominated flow (first boundary-dominated flow in the fracture) prior to hydrocarbon breakthrough, after which a second transient linear flow in the fracture develops. The final flow period is boundary-dominated flow (second boundary-dominated flow in the fracture), indicating the end time of the flowback period. At this stage, oil will be the dominant phase in the fracture, and will exhibit transient linear flow in the matrix, which is the first flow-regime typically observed during the long-term production period. The case of a complex fracture network exhibits a similar sequence of flow regimes. The second transient linear flow for this case has not been discussed in the literature. The development of this flow period may be caused by the maintenance of fracture pressure, and decrease of water relative permeability due to hydrocarbon contribution from the matrix. A field example from western Canada exhibits the flow regimes noted above and is history-matched successfully using the new model. The results demonstrate the practical application of the new model for deriving reservoir/fracture properties from flowback data and for forecasting. Highlights • New models are developed by use of the linear flow solutions. • The system exhibits five flow regimes during flowback. • Fracture network exhibits a similar sequence of flow regimes with planar fracture. • Fracture parameters can be derived from the single- and multi-phase flowback data. [ABSTRACT FROM AUTHOR]

This work investigates the fracturing fluid cleanup mechanisms of post-hydraulic fracturing in unconventional gas formations by studying a large number of wide-ranging parameters simultaneously. In this work, different scenarios of the cleanup operation of the hydraulic fracturing process are considered. This study consists of investigating the post-fracturing cleanup operation of hydraulically fractured vertical wells (VW) and multiple fractured horizontal wells (MFHWs). Additionally, the impact of soaking time, the range of the matrix permeability, applied drawdown pressure, injected fracturing fluid (FF) volume, fracture spacing and horizontal well length has been investigated by running different sets. Results show that the trend of the impact of relevant parameters for VWs and MFHWs are analogous excepting the matrix permeability, k m. That is, in the MFHW base reference set, the effect of matrix permeability on capillary pressure is more significant than that on fluid flow while the reverse is observed for VW. The difference in the impact of k m in VWs and MFHWs is attributed to the geometry of the fluid flow towards the production well and different well completion scheme. It is also concluded that the impact of parameters affecting the capillary pressure in the matrix is more significant for MFHWs whereas matrix and fracture mobility pertinent parameters are more important for VWs than MFHWs. As a result, larger matrix capillary pressure values are more vital in the cleanup of MFHWs because of more imbibition of FF into the matrix and subsequently lower conflict between the flow of gas and FF in the fracture. The other part of this research concentrates on the impact of IFT reducing agents on the post-fracturing production in different formations. In hydraulic fracturing operations, these agents are commonly used as an additive in fracturing fluid to facilitate its backflow by reducing Pc and subsequently enhancing gas production. The results of this work recommend that using such agents enhances the gas production rate for ultratight formations but not for tight formations (it reduces the gas production rate). Therefore it is not suggested to use such agents in tight formations. The findings of this work improve the understanding of fracture cleanup leading to better design of hydraulic fracturing operations in unconventional formations. • An integrated investigation of clean-up efficiency of fractures was performed (in 30 new sets). • Near wellbore choking effect in multiple fractured horizontal wells affects the cleanup mechanisms in a different way compared to vertical wells. • Using IFT reducing agents is not recommended in tight formations whilst it is highly recommended to use such agents in ultratight formations. • Although the impact of fracture interference/fracture spacing on flow is significant, its impact on clean-up performance is minimal. • Latin Hypercube is a more realistic and reliable sampling approach compared to the two-level full-factorial design. [ABSTRACT FROM AUTHOR]

Abstract Water blockage is a type of formation damage that occurs because of capillary discontinuity at the interface between high-capillarity matrix and low-capillarity fracture. This water blockage causes a reduction in oil relative permeability and the need for higher drawdown to allow flowback after hydraulic fracturing. To remove this blockage, shut-in is believed to be effective because it dissipates the water blockage from the matrix-fracture interface deeper into the matrix through capillary imbibition. However, field data demonstrates mixed results – Some field data report shut-in as beneficial, whereas others detrimental. This paper investigates desiccation as one of the main reasons for the mixed shut-in implications. From the perspective of multiphase flow in porous media, our history-matched core-scale model reveals that shut-in can offer some benefits in desiccated water-wet cores but cause further damage in non-desiccated ones. Regardless of the desiccation, our simulation results show that immediate flowback can help ensure high oil relative permeability and remove the trapped water at the matrix-fracture interface more quickly. In a desiccated core, both immediate flowback and shut-in result in the same maximum regained oil relative permeability; however, in a non-desiccated core, immediate flowback results in a higher maximum regained oil relative permeability than shut-in. [ABSTRACT FROM AUTHOR]

Abstract Diagnostic Fracture Injection Tests (DFITs) have become commonplace in low-permeability (unconventional) reservoirs to obtain parameters used in hydraulic fracture stimulation design and reservoir characterization. However, the time taken to acquire reliable estimates of these parameters may be excessive. As a result, pump-in/flowback tests, as opposed to the more conventional pump-in/shut-in tests, have been applied in the industry to accelerate the closure process and to estimate closure pressure, which is used in hydraulic fracture design. However, this comes at the expense of losing after-closure data, which is required to estimate reservoir pressure and flow properties. The goal of this paper is to accelerate the closure process during a DFIT, without sacrificing the after-closure data and derived parameters. The proposed DFIT procedure includes flowing back the fracturing fluid, after opening and propagation of the fracture, at a very low and constant rate. The flowback process is continued for a few hours after fracture closure. The well is then shut-in and the pressure falloff is monitored. The main purpose of the ultra-low rate flowback is to remove or reduce the afterflow caused by wellbore storage. The new DFIT procedure is applied to two field examples performed in a low-permeability reservoir in western Canada. The data are analyzed using well-established pressure-transient analysis methods. An estimate of closure pressure was obtained in less than two hours for both field examples, despite the low-permeability of the reservoir (several hundred nanodarcies). For one of the field examples, estimates of reservoir pressure and transmissibility were obtained after just 4 days of shut-in following the flowback process. Finally, a conceptual model is presented to analyze the conventional pump-in/flowback tests for determination of reservoir pressure. The conceptual model is validated against synthetic simulation results. Using this method, reservoir pressure is obtainable with just a few hours of flowback data. Highlights • A new DFIT procedure is presented and applied in the field. • A conceptual method is presented for estimation of reservoir pressure in pump-in/flowback tests. • The procedure and analysis method provide reliable estimates of in-situ stress and reservoir pressure in a short period. [ABSTRACT FROM AUTHOR]

Conventionally, high-pressure water-based fluids have been injected for hydraulic stimulation of unconventional petroleum resources such as tight gas reservoirs. Apart from improving productivity, water-based frac-fluids have caused environmental and technical issues. As a result, much of the interest has shifted towards alternative frac-fluids. In this regard, n-heptane, as an alternative frac-fluid, is proposed. It necessitates the development of a multi-phase and multi-component (MM) numerical simulator for hydraulic fracturing. Therefore fracture, MM fluid flow, and proppant transport models are implemented in a thermo-hydro-mechanical (THM) coupled FLAC3D-TMVOCMP framework. After verification, the model is applied to a real field case study for optimization of wellbore x in a tight gas reservoir using n-heptane as the frac-fluid. Sensitivity analysis is carried out to investigate the effect of important parameters, such as fluid viscosity, injection rate, reservoir permeability etc., on fracture geometry with the proposed fluid. The quicker fracture closure and flowback of n-heptane compared to water-based fluid is advantageous for better proppant placement, especially in the upper half of the fracture and the early start of natural gas production in tight reservoirs. Finally, fracture designs with a minimum dimensionless conductivity of 30 are proposed.

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 δ 11B, 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 (δ 11B, 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. [Display omitted] • δ 11B and 87Sr/86Sr can be used as indicator for HFFF in Changning field. • Hydraulic fracturing caused the release of minerals enriched in 10B, 6Li, and 87Sr. • Shale formation water composition determined the ratio between Na, Ca, Cl, and Br. • Fracturing fluid composition impact the major elements of HFFFs in the first dozens of days. [ABSTRACT FROM AUTHOR]

In this research, seven chemicals substances selected from the families of inorganic salts and dyes commonly used in hydrology were evaluated as potential tracers for hydraulic fracturing using economic analytical methods implemented for their detection and quantifi cation and that also can be performed in situ. From adsorption tests, compatibility between the fracture gel and formation fl uids and core fl ooding tests, three substances responded acceptably, after being subjected to physical and chemical conditions of a hydraulic fracturing process which enable them to be used as tracers.

Shale gas reservoirs generally need to be fractured massively to reach the industrial production, however, the flowback ratio of fractured shale gas wells is low. In view of this issue, the effects of natural fracture spacing, fracture conductivity, fracturing scale, pressure coefficient and shut-in time on the flowback ratio were examined by means of numerical simulation and experiments jointly, and the causes of flowback difficulty of shale gas wells were analyzed. The results show that the flowback ratio increases with the increase of natural fracture spacing, fracture conductivity and pressure coefficient and decreases with the increase of fracturing scale and shut-in time. From the perspective of microscopic mechanism, when water enters micro-cracks of the matrix through the capillary self-absorbing effect, the original hydrogen bonds between the particles are replaced by the hydroxyl group, namely, hydration effect, giving rise to the growth of new micro-cracks and propagation of main fractures, and complex fracture networks, so a large proportion of water cannot flow back, resulting in a low flowback ratio. For shale gas well fracturing generally has small fracture space, low fracture conductivity and big fracturing volume, a large proportion of the injected water will be held in the very complex fracture network with a big specific area, and unable to flow back. It is concluded that the flowback ratio of fractured shale gas wells is affected by several factors, so it is not necessary to seek high flowback ratio deliberately, and shale gas wells with low flowback ratio, instead, usually have high production.