Hydraulic Fracturing Process Research Articles

RETRACTED: Application of Symmetry Law in Numerical Modeling of Hydraulic Fracturing by Finite Element Method

In this paper, influential parameters on the hydraulic fracturing processes in porous media were investigated. Besides, the simultaneous stimulation of solids, fluids and fractures geomechanical equations were numerically analyzed as a developed 3D model. To do this, the Abacus software was used as a multi-objective program to solve the physical-mechanical symmetry law governing equations, according to the finite element method. Two different layers, A (3104–2984 m) and B (4216–4326 m), are considered in the model. According to the result of this study, the maximum fracture opening length in the connection of the wall surface is 10 and 9 mm for layer B and layer A, respectively. Moreover, the internal fracture fluid pressure for layer B and layer A is 65 and 53 Mpa. It is indicated that fracture fluid pressure reduced with the increase in fracture propagation length. Consequently, the results of this study would be of benefit for petroleum industries to consider several crucial geomechanical characteristics in hydraulic fractures simultaneously as a developed numerical model for different formation layers to compare a comprehensive analysis between each layer.

New Closed Blender Reduces Footprint, Gasification of CO2in Waterless Fracturing

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19770, “Design, Optimization, and Application of a Closed Blender for CO2 Waterless Fracturing,” by Qinghai Yang, Siwei Meng, and Chuan Yu, PetroChina, et al., prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. Carbon dioxide (CO2) waterless fracturing uses liquid CO2 to replace water as the fracturing fluid in reservoir stimulation. The continuity and reliability of the blender are key factors determining performance of the operation. The complete paper proposes a novel closed blender that uses a vertical, rather than horizontal, tanker. This modification can reduce the footprint and effectively suppress CO2 gasification. The field practice suggests that the developed closed blender combines the advantages of both vertical and horizontal blenders and ensures successful implementation of CO2 waterless fracturing operations. Introduction The CO2 waterless fracturing process, as an alternative technology for developing unconventional reservoirs, greatly reduces consumption of water resources in the development of unconventional resources. In addition, compared with traditional fracturing measures, this technology has the advantages of low reservoir damage, complex artificial fractures, good energy-storage effect, and a high degree of recovery because of the unique physical and chemical properties of CO2. The CO2 waterless fracturing process requires the following equipment: CO2 tank trucks, booster pump trucks, sand blenders, high-pressure pump trucks, and low-and high-pressure manifolds. The blender acts as the core equipment for dry fracturing of liquid CO2, its main function to mix CO2 with proppant. It then feeds the mixed sand fluid to the fracturing pump truck for CO2 water-less fracturing. In the fracturing process, CO2 on the ground is required to be under low temperature and high pressure continuously to maintain its liquefaction. In addition, CO2 fluid has characteristics of low viscosity, high friction resistance, corrosiveness, and poor lubrication. Compared with traditional hydraulic fracturing processes, the sand blender for CO2 waterless fracturing has specific requirements. Components of the Closed Blender Drawing lessons from design of internationally available closed blenders for CO2 waterless fracturing, the authors have developed independently a new generation of closed blender, mainly composed of a sand tanker, a sand-mixing system, a blender manifold (a discharge manifold and a suction manifold), a chemical-addition system, a hydraulic system, an electronic control system, and a data-acquisition system (Fig. 1).

Experimental Investigation and Performance Evaluation of Modified Viscoelastic Surfactant (VES) as a New Thickening Fracturing Fluid.

In hydraulic fracturing, fracturing fluids are used to create fractures in a hydrocarbon reservoir throughout transported proppant into the fractures. The application of many fields proves that conventional fracturing fluid has the disadvantages of residue(s), which causes serious clogging of the reservoir’s formations and, thus, leads to reduce the permeability in these hydrocarbon reservoirs. The development of clean (and cost-effective) fracturing fluid is a main driver of the hydraulic fracturing process. Presently, viscoelastic surfactant (VES)-fluid is one of the most widely used fracturing fluids in the hydraulic fracturing development of unconventional reservoirs, due to its non-residue(s) characteristics. However, conventional single-chain VES-fluid has a low temperature and shear resistance. In this study, two modified VES-fluid are developed as new thickening fracturing fluids, which consist of more single-chain coupled by hydrotropes (i.e., ionic organic salts) through non-covalent interaction. This new development is achieved by the formulation of mixing long chain cationic surfactant cetyltrimethylammonium bromide (CTAB) with organic acids, which are citric acid (CA) and maleic acid (MA) at a molar ratio of (3:1) and (2:1), respectively. As an innovative approach CTAB and CA are combined to obtain a solution (i.e., CTAB-based VES-fluid) with optimal properties for fracturing and this behaviour of the CTAB-based VES-fluid is experimentally corroborated. A rheometer was used to evaluate the visco-elasticity and shear rate & temperature resistance, while sand-carrying suspension capability was investigated by measuring the settling velocity of the transported proppant in the fluid. Moreover, the gel breaking capability was investigated by determining the viscosity of broken VES-fluid after mixing with ethanol, and the degree of core damage (i.e., permeability performance) caused by VES-fluid was evaluated while using core-flooding test. The experimental results show that, at pH-value (), 30 (mM) VES-fluid (i.e., CTAB-CA) possesses the highest visco-elasticity as the apparent viscosity at zero shear-rate reached nearly to 10 (mPa·s). Moreover, the apparent viscosity of the 30 (mM) CTAB-CA VES-fluid remains 60 (mPa·s) at (90 C) and 170 (s) after shearing for 2-h, indicating that CTAB-CA fluid has excellent temperature and shear resistance. Furthermore, excellent sand suspension and gel breaking ability of 30 (mM) CTAB-CA VES-fluid at 90 (C) was shown; as the sand suspension velocity is 1.67 (mm/s) and complete gel breaking was achieved within 2 h after mixing with the ethanol at the ratio of 10:1. The core flooding experiments indicate that the core damage rate caused by the CTAB-CA VES-fluid is (), which indicate that it does not cause much damage. Based on the experimental results, it is expected that CTAB-CA VES-fluid under high-temperature will make the proposed new VES-fluid an attractive thickening fracturing fluid.

Experimental Investigation of the Impacts of Fracturing Fluid on the Evolution of Fluid Composition and Shale Characteristics: A Case Study of the Niutitang Shale in Hunan Province, South China

Hydraulic fracturing is a widely used technique for oil and gas extraction from ultra-low porosity and permeability shale reservoirs. During the hydraulic fracturing process, large amounts of water along with specific chemical additives are injected into the shale reservoirs, causing a series of reactions the influence the fluid composition and shale characteristics. This paper is focused on the investigation of the geochemical reactions between shale and fracturing fluid by conducting comparative experiments on different samples at different time scales. By tracking the temporal changes of fluid composition and shale characteristics, we identify the key geochemical reactions during the experiments. The preliminary results show that the dissolution of the relatively unstable minerals in shale, including feldspar, pyrite and carbonate minerals, occurred quickly. During the process of mineral dissolution, a large number of metal elements, such as U, Pb, Ba, Sr, etc., are released, which makes the fluid highly polluted. The fluid–rock reactions also generate many pores, which are mainly caused by dissolution of feldspar and calcite, and potentially can enhance the extraction of shale gas. However, precipitation of secondary minerals like Fe-(oxy) hydroxides and CaSO4 were also observed in our experiments, which on the one hand can restrict the migration of metal elements by adsorption or co-precipitation and on the other hand can occlude the pores, therefore influencing the recovery of hydrocarbon. The different results between the experiments of different samples revealed that mineralogical texture and composition strongly affect the fluid-rock reactions. Therefore, the identification of the shale mineralogical characteristics is essential to formulate fracturing fluid with the lowest chemical reactivity to avoid the contamination released by flowback waters.

Machine Learning Approach to Model Rock Strength: Prediction and Variable Selection with Aid of Log Data

Comprehensive knowledge and analysis of in situ rock strength and geo-mechanical characteristics of rocks are crucial in hydrocarbon and mineral exploration stage to maximize wellbore performance, maintain wellbore stability, and optimize hydraulic fracturing process. Due to the high cost of laboratory-based measurements of rock mechanics properties, the log-based prediction is a viable option. Nowadays, the machine learning tools are being used for estimation of the in situ rock properties using wireline log data. This paper proposes a machine learning approach for rock strength (uniaxial compressive strength) prediction. The main objectives are to investigate the performance of data-driven predictive model in determining this vital parameter and to select features of predictor log variables in the model. The backpropagation multilayer perception (MLP) artificial neural network (ANN) with Levenberg–Marquardt training algorithm as well as the least squares support vector machine (LS-SVM) with coupled simulated annealing (CSA) optimization technique is employed to develop the dynamic data-driven models. Capturing nonlinear, high dimensional, and complex nature of real field log data, the rock strength models’ performances are evaluated using statistical criteria to ensure concerning the model reliability and accuracy. The model predictions are compared and validated against the measured values as well as the results obtained from existing log-based correlations. Both the MLP-ANN and the CSA-based LS-SVM connectionist strategies are able to predict the rock strength so that there is a very good match between the model results and corresponding measured values. The input log parameters are ranked based on their contributions in prediction performance. The acoustic travel time and gamma ray are found to have the highest relative significance in estimating rock strength. New correlations are also developed to obtain the in situ rock strength of the siliciclastic sedimentary rocks using the most important log parameters such as dynamic sonic slowness, formation electron density, and shalyness effect. The developed correlations can be used to obtain quick estimation of dynamic uniaxial compressive strength profile using wireline logging data, instead of static data from the surface measurements or laboratory data. It is expected that the proposed models and tools will enable oil and gas engineers to better predict rock strength and thus enhance wellbore performance.

An NMM-based fluid-solid coupling model for simulating rock hydraulic fracturing process

Simulation of hydraulic fracturing process based on numerical manifold method (NMM) is a valuable research direction considering its advantages in dealing with continuous-discontinuous deformation problems. In this paper, an NMM-based fluid-solid coupling model is proposed, including numerical solution of unsteady fracture flow, hydraulic pressure-load conversion algorithm, rectification of hydraulic aperture and programming realization of arbitrary crack growth increment etc. In terms of the fluid phase, the fracture flow network is constructed based on the closed loops formed by cutting the mathematical mesh with fractures; in order to eliminate the sensitivity of explicit algorithm to time-step size, an unconditionally stable numerical solution scheme for unsteady flow is established. In terms of the solid phase, for the sake of realizing coupling process of hydraulic pressure to solid deformation, hydraulic pressure is converted into load vector by hydraulic pressure-load conversion algorithm to calculate the deformation of fractured surrounding rock; and Delaunay triangulation algorithm is introduced to subdivide manifold elements with multiple kinks, which effectively solves the problem that the crack tip cannot stop or kink in the same manifold element in the subsequent growth steps, realizes arbitrary crack growth increment. Several benchmark examples are utilized to demonstrate the accuracy of the proposed hydraulic fracturing model in simulating fracture fluid flow and solid deformation. Finally, the developed fluid-solid coupling model is used to simulate rock hydraulic fracturing processes under different conditions. The ability and reliability of the proposed model to describe the hydraulic fracture propagation laws are verified by comparing with previous experimental and numerical results.

A generalized finite element method for three-dimensional hydraulic fracture propagation: Comparison with experiments

In this article, 3-D simulations of hydraulic fracture propagation with the Generalized Finite Element Method (GFEM) are compared with several experiments. The GFEM in this work uses mesh adaptivity and a quadratic basis to control discretization error while avoiding the mapping of 3-D solutions between propagation steps. Linear Elastic Fracture Mechanics is adopted and geometrical singular enrichments are used around the fracture front for robust and accurate stress intensity factors extraction. The time step that leads to satisfaction of the propagation criterion is computed automatically using a simple and yet computationally efficient algorithm. The laboratory experiments used in this article include planar and nonplanar fracture geometries as well as propagation in toughness- and viscosity-dominated regimes. The time evolution of fracture radius and opening, and wellbore fluid pressure are compared with experimental data. They show that the GFEM captures well the relevant physics of the hydraulic fracturing process. A modification is proposed to one of the experimental setups to explore and demonstrate the 3-D capabilities and robustness of the method.

A poromechanical model of hydraulic fracturing volumetric opening

In the present study, the hydraulic fracturing volumetric opening is referred to the volumetric opening in per unit bulk volume of rocks, in fact, the increment of porosity due to hydraulic fracturing, including the pore volumetric opening and fracture volumetric opening. The former is an idealized representation of elastic volumetric opening of widely distributed microcracks, fissures, and pores due to porous flow, and the latter is the volumetric opening of newly generated trunk fracture due to breakdown of rock skeleton. The poromechanical model is a set of mechanical formulas to model the evolutions of these volumetric openings in a hydraulic fracturing process, so that to give a proper evaluation of hydraulic fracturing openings in RVE scale. Firstly, a three-staged hydraulic fracturing process is proposed, based on which, staged expressions of volumetric openings are established using the theory of poroelasticity and the damage model of cohesive breakdown. Then, the precise evolutions of these volumetric openings are obtained by incorporating hydraulic fracturing propagation regimes into those expressions aforementioned. Therefore, the poromechanical model proposed in the present study is bridging the gaps between the two classic theories, the poroelasticity and hydraulic fracture in a RVE scale. As examples, four limiting cases of hydraulic fracturing are chosen to show how to use this model to calculate the hydraulic volumetric openings. These limiting cases are corresponding to the four limiting propagation regimes of hydraulic fracturing, the storage-viscosity regime, leak-off-viscosity regime, storage-toughness regime, and leak-off-toughness regime.

A time-lapse CSEM monitoring study for hydraulic fracturing in shale gas reservoir

Hydraulic fracturing has been widely used in shale gas production. During the hydraulic fracturing, microcracks are open and filled with the conductive fluid, which enhances the overall hydraulic conductivity of the shale formulation. Undoubtedly, the monitoring of the fracturing process is crucially important for shale gas production. The controlled source electromagnetic method (CSEM) is sensitive to the electric conductivity change and can potentially be used for monitoring hydraulic fracturing. In this paper, we carried out numerical modeling and a field test on the CSEM monitoring of hydraulic fracturing at the Fuling shale gas field in southern China. Firstly, we perform the numerical modeling based on a synthetic model derived from the logging data of the field test site to investigate the effect of the steel-cased well on EM responses. Then, we investigate EM responses at the surface caused by the shale gas reservoir for different configurations to optimize survey parameters. Subsequently, the optimal broadside survey system is applied to investigate the effectiveness of CSEM monitoring on a synthetic hydraulic fracturing process. Finally, a real application is applied to carry out the time-lapse CSEM monitoring of the hydraulic fracturing during the shale gas production. Both the modeling results and the field data show the optimistic potential of use CSEM monitoring on the hydraulic fracturing process applied in the shale gas production.

The performance of complex-structure fractured reservoirs considering natural and induced matrix block size, shape, and distribution

This paper introduces an analytical approach for the performance of the fractured reservoir considering the impact of the matrix block size, shape, and distribution. The objective is better understanding the roles of the variable interporosity flow systems, fracture flowing systems, and reservoir matrix heterogeneity in the responses of the wellbore pressure drop, flow rate, cumulative production, and productivity index. This understanding could help to eliminate the uncertainties and increase the accuracy in characterizing the conventional and unconventional reservoirs where very complex structures of a significant disorder in the matrix block size, shape and distribution could be existed in the porous media.The study uses the well documented multilinear flow model to describe the pressure distribution in the naturally fractured reservoirs depleted by multiple hydraulic fractures considering different matrix block sizes, shapes, and distributions. The analytical models of the flow rate, cumulative production, and the productivity index are also developed in this study from the multilinear flow model. The reservoirs of interest are assumed to have stimulated porous media extending between hydraulic fracture and unstimulated volume extending beyond the fracture tips toward the reservoir boundary. The unstimulated reservoir volume is assumed consisting of uniformly distributed single matrix block size and shape because there is no impact for the hydraulic fracturing process. While the stimulated reservoir volume is considered consisting of a variable matrix block size, shape, and distribution because of the impact of hydraulic fracture propagation. The petrophysical properties of the two porous media, as well as the storativity and interporosity flow coefficient, are assumed functions of the matrix characteristics in the two volumes. The matrix block dimensions (radius or length) are correlated exponentially with the distance from the hydraulic fracture face toward the no-flow boundary between these fractures. Three fracture-matrix fluid flux functions are developed for the reservoirs where the matrix blocks could have a spherical, slab, and cylindrical configuration.The study has reached several conclusions. A positive impact on the reservoir performance is seen when the matrix block size becomes small or when the small size matrix blocks control the distribution of the blocks in the porous media. Reservoir performance is enhanced also when there are several matrix block sizes compared to a single size or very few sizes. It is observed that the reservoirs with spherical blocks may give better performance than the reservoir with slab or cylindrical matrix blocks. In terms of matrix block size and distribution, heterogeneous reservoirs may have a higher productivity index than homogenous reservoirs. The variable matrix block size and distribution in the stimulated reservoir volume is more beneficial than the unstimulated volume. The novel point presented in this paper is developing several analytical models for the wellbore pressure drop, flow rate, cumulative production, and productivity index of hydraulically fractured reservoirs with a consideration given to the matrix block size, shape, and distribution.

A criterion for identifying a mixed-mode I/II hydraulic fracture crossing a natural fracture in the subsurface

Hydraulic fracturing has been proven to be an effective technique for stimulating petroleum reservoirs. During the hydraulic fracturing process, the effects of the natural fracture, perforation orientation, stress reorientation, etc. lead to the production of a non-planar, mixed-mode I/II hydraulic fracture. In this paper, a criterion for a mixed-mode I/II hydraulic fracture crossing a natural fracture was first proposed based on the stress field around the hydraulic and natural fractures. When the compound degree (KII/KI) approaches zero, this criterion can be simplified to identify a pure mode I hydraulic fracture crossing a natural fracture. A series of true triaxial fracturing tests were conducted to investigate the influences of natural fracture occurrence and in situ stress on hydraulic fracture propagation. These experimental results agree with the predictions of the proposed criterion.

Application of Koopman operator for model-based control of fracture propagation and proppant transport in hydraulic fracturing operation

This work explores the application of the recently developed Koopman operator approach for model identification and feedback control of a hydraulic fracturing process. Controlling fracture propagation and proppant transport with precision is a challenge due in large part to the difficulty of constructing approximate models that accurately capture the characteristic moving boundary and highly-coupled dynamics exhibited by the process. Koopman operator theory is particularly attractive here as it offers a way to explicitly construct linear representations for even highly nonlinear dynamics. The method is data-driven and relies on lifting the states to an infinite-dimensional space of functions called observables where the dynamics are governed by a linear Koopman operator. This work considers two problems: (a) fracture geometry control, and (b) proppant concentration control. In both cases, an approximate linear model of the corresponding dynamics is constructed and used to design a model predictive controller (MPC). The manuscript shows that in the case of highly nonlinear dynamics, as observed in the proppant concentration, use of canonical functions in the observable basis fails. In such cases, a priori system knowledge can be leveraged to choose the required basis. The numerical experiments demonstrate that the Koopman linear model shows excellent agreement with the real system and successfully achieves the desired target values maximizing the oil and gas productivity. Additionally, due to its linear structure, the Koopman models allow convex MPC formulations that avoid any issues associated with nonlinear optimization.

Joint microseismic event location and anisotropic velocity inversion with the cross double-difference method using downhole microseismic data

We have applied the cross double-difference (CDD) method to simultaneously determine the microseismic event locations and five Thomsen parameters in vertically layered transversely isotropic media using data from a single vertical monitoring well. Different from the double-difference (DD) method, the CDD method uses the cross-traveltime difference between the S-wave arrival time of one event and the P-wave arrival time of another event. The CDD method can improve the accuracy of the absolute locations and maintain the accuracy of the relative locations because it contains more absolute information than the DD method. We calculate the arrival times of the qP, qSV, and SH waves with a horizontal slowness shooting algorithm. The sensitivities of the arrival times with respect to the five Thomsen parameters are derived using the slowness components. The derivations are analytical, without any weak anisotropic approximation. The input data include the cross-differential traveltimes and absolute arrival times, providing better constraints on the anisotropic parameters and event locations. The synthetic example indicates that the method can produce better event locations and anisotropic velocity model. We apply this method to the field data set acquired from a single vertical monitoring well during a hydraulic fracturing process. We further validate the anisotropic velocity model and microseismic event locations by comparing the modeled and observed waveforms. The observed S-wave splitting also supports the inverted anisotropic results.

Self-training and learning the waveform features of microseismic data using an adaptive dictionary

Microseismic monitoring is an indispensable technique in characterizing the physical processes that are caused by extraction or injection of fluids during the hydraulic fracturing process. Microseismic data, however, are often contaminated with strong random noise and have a low signal-to-noise ratio (S/N). The low S/N in most microseismic data severely affects the accuracy and reliability of the source localization and source-mechanism inversion results. We have developed a new denoising framework to enhance the quality of microseismic data. We use the method of adaptive sparse dictionaries to learn the waveform features of the microseismic data by iteratively updating the dictionary atoms and sparse coefficients in an unsupervised way. Unlike most existing dictionary learning applications in the seismic community, we learn the features from 1D microseismic data, thereby to learn 1D features of the waveforms. We develop a sparse dictionary learning framework and then prepare the training patches and implement the algorithm to obtain favorable denoising performance. We use extensive numerical examples and real microseismic data examples to demonstrate the validity of our method. Results show that the features of microseismic waveforms can be learned to distinguish signal patches and noise patches even from a single channel of microseismic data. However, more training data can make the learned features smoother and better at representing useful signal components.

ANALYSIS OF NEGATIVE CONSEQUENCES DURING A HYDRAULIC FRACTURING

Background Currently, the share of hard-to-recover natural oil reserves in the development of oil and gas-oil fields is increasing, and the volume of work to increase the oil recovery ratio is increasing. Hydraulic fracturing is one of the effective methods of production enhancement and enhanced oil recovery. Aims and Objectives To determine the qualitative geological and physical information about the structure of the development object when designing the processes of geological and technical measures. To prove the negative consequences arising after the work on intensification and increase of oil recovery factor. To establish the effect of water-cut wells on the effectiveness of hydraulic fracturing. Results The main aspects of the correct construction of the geological and hydrodynamic model are selected. The possible negative consequences arising due to improper design of the hydraulic fracturing process are analyzed, and ways to prevent them are justified. The influence of the aquifer interlayers was noted during hydraulic fracturing in production wells with a high level of irrigation.

Numerical simulation analysis of vertical propagation of hydraulic fracture in bedding plane

Hydraulic fracturing is one of the principle technologies employed for achieving the efficient development of shale oil and gas reservoirs, and the bedding plane of the reservoir is a key factor affecting the geometrical distribution of hydraulic fractures in three dimensions. The present study adopts cohesive force unit theory to construct a multi-layer hydraulic fracture propagation model with coupling stress damage filtration, and the effects of changes in the reservoir stress field, angle of the bedding planes relative to vertically propagating hydraulic fractures, and tensile strength of the bedding planes on the vertical propagation of hydraulic fractures are analyzed. The simulation results show that the hydraulic fracturing process of penetrating the bedding planes can be divided into three stages. Here, the hydraulic fracture propagates in the rock matrix and intersects with the bedding planes with continuous injection of fracturing fluid in stages I and II, while the vertical stress, bedding plane angle, and tensile strength of the bedding planes determine the direction of hydraulic fracture propagation in the third stage. Reservoirs with low vertical stress differences and nearly horizontal bedding planes with low dip angles are found to be favorable for opening the bedding planes, and reservoirs with high vertical stress differences and bedding plane dip angles are favorable for the longitudinal expansion of hydraulic fractures. Simultaneously, the degree of opening of the bedding planes also increases as the tensile strength of the bedding planes decreases. This is mainly because the energy consumption of the bedding layer opening process decreases as the tensile strength of the bedding planes decreases.

Phase-field modeling of hydraulic fracture network propagation in poroelastic rocks

Modeling of hydraulic fracturing processes is of great importance in computational geosciences. In this paper, a phase-field model is developed and applied for investigating the hydraulic fracturing propagation in saturated poroelastic rocks with pre-existing fractures. The phase-field model replaces discrete, discontinuous fractures by continuous diffused damage field, and thus is capable of simulating complex cracking phenomena such as crack branching and coalescence. Specifically, hydraulic fracturing propagation in a rock sample of a single pre-existing natural fracture or natural fracture networks is simulated using the proposed model. It is shown that distance between fractures plays a significant role in the determination of propagation direction of hydraulic fracture. While the rock permeability has a limited influence on the final crack topology induced by hydraulic fracturing, it considerably impacts the distribution of the fluid pressure in rocks. The propagation of hydraulic fractures driven by the injected fluid increases the connectivity of the natural fracture networks, which consequently enhances the effective permeability of the rocks.

Numerical investigation of water retention in secondary fractures and apparent permeability modeling in shale gas production

During the hydraulic fracturing process, the fracturing fluid may cause water retention, if the nearby secondary fractures subsequently close and get disconnected due to changes in effective stress distribution during flowback and production. The circumstances and detailed mechanisms associated with this phenomenon are still poorly understood. In this work, a coupling scheme for incorporating a pressure-dependent apparent permeability model in reservoir simulation is implemented. The numerical models are subsequently used to investigate the impacts of water retention and apparent permeability modeling on gas production and water flowback.A high-resolution 3D reservoir model is constructed based on the field data obtained from the Horn River shale gas reservoir. Stochastic 3D discrete fracture netsork (DFN) model is upscaled into equivalent continuum dual-porosity dual-permeability (DPDK) model by analytical techniques. An apparent permeability (Kapp) model is employed to model transport mechanisms in nano-sized pore systems. In order to capture the pressure dependency, a novel coupling scheme is developed to facilitate the updating of Kapp and effective stress after a certain designated time interval. In addition, a novel method involving rock-type indicators is introduced to represent the open and closed states of secondary fractures, facilitating the modeling of stress-dependent closure of the secondary fracture system. Two secondary fracture closure behaviors (i.e., abrupt closure and gradual closure) are considered in our study.The results indicate that fracture closure would affect the gas production and water recovery, particularly if the near-well fractures are disconnected; the effect would be further exaggerated for a denser fracture network; fracture closure would also affect the matrix water retention near the well. Neglecting the effects of Kapp could essentially overestimate the contribution of hydraulic fracture for a certain observed gas production. The existence of secondary fractures could also enhance water loss during flowback. It is concluded that gas and water production would increase if less water is imbibed into the matrix during the shut-in period in the presence of disconnected secondary fractures. It is also observed that a shorter shut-in period may be beneficial to both water and gas recovery.This work presents a novel, yet practical, scheme for coupling stress-dependent matrix apparent permeability and fluid flow, as well as modeling pressure-dependent fracture closure. This modeling scheme can be readily integrated in most commercial reservoir simulation packages. The results have revealed several potential scenarios of water loss, along with the associated implications on optimal operational strategies and estimation of stimulated reservoir volume.

Numerical analysis on the mechanism of hydraulic fracture behavior in heterogeneous reservoir under the stress perturbation

Hydraulic fracturing is the key technology employed to alter the permeability of tight reservoirs. In this article, the discrete element fluid–solid coupling method is improved, and sinusoidal stress waves are applied at the boundary of a heterogeneous reservoir to simulate perturbation. The influence of stress wave frequency on the mode of crack propagation in the hydraulic fracturing process and the internal stress changes in specimens under different in situ stress ratios are investigated. The simulation results suggest that (1) under a constant injection rate, an increased frequency is associated with a gradual increase in the breakdown pressures, an increase in the time required for cracking breakdown, and faster propagation of cracks propagating; and (2) the hydraulic fracture propagation direction obviously deflects towards the stress wave propagation direction, and the failure mode becomes more complicated under the combined action of the ground stress and the stress wave; and (3) the maximum principal stress inside the specimen is compressive stress, and the curves of the maximum principal stress and maximum shear stress are periodic vibration, with the characteristics of a large amplitude at a low frequency and a small amplitude at a high frequency. The initiation of cracks near the injection hole results from a reduction in the maximum principal stress and an increase in the maximum shear stress. The analysis indicates that the stress wave has a non-negligible influence on hydraulic fracturing and provides a better guideline for understanding the mechanical nature of hydraulic fracturing under the influence of stress perturbation.

Numerical investigation of the hydraulic fracturing mechanisms in oil sands

This paper presents a numerical investigation of hydraulic fracturing in oil sands during cold water injection by considering the aspects of both geomechanics and reservoir fluid flow. According to previous studies, the low shear strengths of unconsolidated or weakly consolidated sandstone reservoirs significantly influence the hydraulic fracturing process. Therefore, classical hydraulic fracture models cannot simulate the fracturing process in weak sandstone reservoirs. In the current numerical models, the direction of a tensile fracture is predetermined based on in situ stress conditions. Additionally, the potential transformation of a shear fracture into a tensile fracture and the potential reorientation of a tensile fracture owing to shear banding at the fracture tip have not yet been addressed in the literature. In this study, a smeared fracture technique is employed to simulate tensile and shear fractures in oil sands. The model used combines many important fracture features, which include the matrix flow, poroelasticity and plasticity modeling, saturation-dependent permeability, gradual degradation of the oil sands as a result of dilative shear deformation, and the tensile fracturing and shear failure that occur with the simultaneous enhancement of permeability. Furthermore, sensitivity analyses are also performed with respect to the reservoir and geomechanical parameters, including the apparent tensile strength and cohesion of the oil sands, magnitude of the minimum and maximum principal stress, absolute permeability and elastic modulus of the oil sands and ramp-up time. All these analyses are performed to clarify the influences of these parameters on the fracturing response of the oil sands.