ABSTRACT: Hydraulic fracturing is one of the most effective conventional reservoir-stimulation techniques currently utilized in the petroleum industry. Hydraulic fracture (HF) – Natural fracture (NF) interactions during the hydrofracturing process are complex in space and time. Although in the past five decades, several numerical, analytical and experimental studies have explored and characterized the interactions between natural fractures and hydraulic fractures, there remains differing opinions on the fundamental behaviors of hydraulic fractures when and where they interact with natural fractures. Here, we present a comprehensive review of the propositions and limitations of these studies in order to emphasize the need for further studies on NF-HF interactions and highlight the important fundamental questions that are yet to be answered. Our review focuses on previous experimental, analytical and numerical studies that investigated the impact of geomechanical and geometrical properties, and operational parameters on the result of NF-HF intersections during fracture initiation and propagation. We envisage that advancement in our understanding of NF-HF interactions will help in optimizing the fracture-stimulation processes during hydrofracturing operations.

ABSTRACT: We revisit the problem of the propagation of a plane-strain fluid-driven fracture in a quasi-brittle impermeable medium accounting for the presence of a fluid lag. The fracture process zone is simulated using a linear-softening cohesive model while lubrication flow accounts for the possible occurrence of a fluid lag. The solution is obtained numerically via a fully implicit scheme based on a boundary element method for the fracture deformation and finite difference for fluid flow. The fluid lag is first automatically captured using the Elrod-Adams lubrication cavitation model during the initiation and early stage of fracture growth. We then switch to an algorithm tracking the fluid front for computational efficiency. Using dimensional analysis, we show that the propagation is governed by a dimensionless toughness and a time scale characterizing the disappearance of the fluid lag (both similar to the linear elastic fracture mechanics case) and a ratio between the in-situ minimum confining stress and the material tensile strength. The cohesive forces reinforce the suction effect associated with a fluid lag, and leads to the further localization of the fluid pressure drop near the tip. This ultimately results in a slight increase of fracture opening and net pressure.

ABSTRACT: A laboratory hydraulic fracture experiment was conducted on a Montney shale specimen under the conventional triaxial compressional stress condition. Acoustic emissions (AEs) were recorded using 7 piezoelectric transducers throughout the duration of the test to investigate the hydraulic fracture propagation processes. Distilled water was injected at an average rate of 2.5 mL/min until the sample failed. As expected, a hydraulic fracture formed perpendicular to the externally applied minimum principal stress. Due to the nature of tensile fractures, the relative plasticity of the Montney shale lithology compared to more brittle granitic specimens used in many previous studies, and the reverberatory character of the recorded waveforms, AE seismicity was relatively sparse (600 events) and only a small fraction (about 6%) of AE events could be located. Nevertheless, the hydraulic fracture plane in the middle of the specimen was clearly evident through the hypocenter location plot. In general, locating the AE hypocenters is very challenging compared with granitic materials due to the low signal-to-noise ratio of the waveforms emitted from shale during the hydraulic fracturing process. Moreover, event amplitudes recorded in this experiment are significantly lower than in a previously reported AE experiment where failure occurred under compression.

ABSTRACT: Horizontal well drilling and hydraulic fracturing have been widely applied to enhance the shale oil production in the Bakken Formation. The stimulated volume of the shale as a result of hydraulic fracturing contributes to increase of the relative conductivity and large folds of increase in productivity. However, the side effect is the fast depletion of the reservoir. Therefore, more and more operators and service companies start applying refracturing treatments to enhance productivity after primary production. An integrated model is presented in this paper to simulate the full process of hydraulic fracturing, shale oil production, and refracturing in a horizontal Bakken well. A new, lattice-based software XSite was used to simulate the hydraulic fracturing process. The resultant fracture geometry was imported into FLAC3D to simulate pore pressure depletion. The pore pressure distribution was imported back to XSite to calculate stresses and simulate the propagation of the refracture. The simulation results indicated that the production from the horizontal well leads to stress reversal near the initial hydraulic fracture. This effect is favorable for the refracture to propagate perpendicular to the initial hydraulic fracture for growth of branches of secondary fractures at the tip of the initial hydraulic fracture.

ABSTRACT: The fracture energy of the shale possesses a significant anisotropy due to the shale bedding and has great effects on the fracturing path. To investigate these effects, three types of the shale specimens are applied in fracturing test with three-point bending. The Digital Imaging Correlation (DIC) and Acoustic Emission (AE) methods are also integrated to analyze the damage processes. According to the AE energy, the damage process of the shale can be divided into three parts using the proportion between the loading value and the peak value of the specimen. In Part I, the sample does not damage. In Part II, the damage begins to appear in the sample, and the work of the external forces is mainly contributed to create the new cracks in the rock layers and to promote the opening and dislocation of the layer interfaces. In Part III, the cracks develop because the damages in the shale are accumulated to an extreme value. Fracture energy anisotropy extent of the shale has been obtained from these partitions, which can be further applied to optimization of the perforation and hydraulic fracturing direction.

ABSTRACT: Hydraulic fracturing is the best method to improve production in deep shale, and the complex natural fracture affects the fracture propagation. In this study, numerous true tri-axial experiments were conducted on hydrostone to study the effect of the natural fracture complexity. The position and the relative angle of natural fracture were mainly studied. The acoustic emission was used to detect the fracture propagation and the pumping curve was analyzed. The results showed that the three-dimensional fracture morphologies can be classified into five ways: arresting, bypassing, crossing, vertical extension and slipping. Symmetrical natural fracture around the wellbore helped to increase the fracture height extension. When natural fractures distributed asymmetrically, the hydraulic fracture showed obvious single wing crack. The hydraulic fracture tended to activate the natural fracture and changed direction along the natural fracture with a small approaching angle. The pumping curve rising in the propagation stage showed the fracture arresting the natural fracture. More complex fracture network corresponded to more fluctuated curve. The results give a deep understanding of the effect of the natural fracture complexity in 3D and help to predict the fracture intersection morphology in the field.

ABSTRACT: In this study, a 3D DEM lattice simulator is utilized to model the simultaneous growth and mechanical interference among members of an array of hydraulic fractures along a horizontal well. The deformation and fracturing of the rock matrix are simulated by the lattice. Fluid flow is implemented within the fractures and fully coupled with the mechanical deformation. Simulation results demonstrate non-planar fracture propagation behaviors induced by the stress shadowing effect in a full 3D setting without restriction on the fracture trajectory. Indeed, the simulation shows one fracture can be dominant in growth due to local heterogeneity and take in most of the fluid flow. The simulation also captures complex fracture front segmentation and asymmetric growth both in length and height under the combined impact of stress shadowing effect and perforation/in-situ stress misalignment, which could not be explicitly considered in previous pseudo-3D or parallel-planar 3D models. 1. INTRODUCTION Multi-stage hydraulic fracturing is the preferred method for effective reservoir stimulation in unconventional hydrocarbon reservoirs (e.g. King 2010). Within each stage, multiple hydraulic fractures are placed and promoted to propagate simultaneously in an array distribution along consecutive sections of wellbores. However, research from field data analysis and numerical simulation both indicate that a significant proportion of fractures from perforation clusters within a fracturing stage can be largely suppressed (Fisher et al. 2004; Miller et al. 2011; Bunger and Peirce 2014). Evaluation of production logs shows that almost one-third of perforation clusters from 100 horizontal shale wells in multiple basins are not contributing to production (Miller et al. 2011). One main factor is the geomechanical interactions (stress shadowing effect) between growing fractures and the resulting disturbance on local stress field. Hydraulic fractures may grow asymmetrically, with some fractures becoming dominant while the others are suppressed and hence do not contribute to the stimulation effect. There are several recent investigations that aim generally at reducing the negative impact of stress shadowing and thereby optimizing multistage completions. Less stress shadowing effect would generally be expected for uniformly distributed clusters with larger cluster spacing. For closely-spaced hydraulic fractures, the dynamics of geomechanical interactions between fractures can be substantially changed by perturbing the locations of perforation clusters away from the uniform distribution, which may potentially promote uniform distributions of fractured surface (Germanovich and Astakhov 2004; Bunger and Peirce 2014; Lecampion and Desroches 2015; Peirce and Bunger 2015; Wu et al. 2016). It has been shown numerically that an approximately 50 to 75% increase in hydrocarbon recovery, if scaled with the fractured area, is possible by specially choose the locations of the interference fractures (Peirce and Bunger 2015).

ABSTRACT: Casing deformation in shale gas wells during multi-fracturing has seriously affected the efficiency and safety of shale gas production in China. Firstly, the characteristics of casing deformation in Weiyuan shale gas field were statistically analyzed, and main influence factors were obtained. Second, the influence of the induced stress from crack is analyzed, and a stress analysis model for casing-cement-formation system stress field nearby wellbore during fracturing is established. Finally, the loads near wellbore in shale gas wells is studied, incorporating variation fracturing methods and operation parameters. The results show that the casing deformation in shale gas wells mainly occurs near the heel of the horizontal section, and shear failure is the main type of casing deformation; The initiation and expansion of crack can lead to the accumulation of non-uniform stress nearby wellbore during fracturing. Further, this will induce formation slip and cause the shear and collapse failure of casing; Accurate identification of faults, natural cracks and improved fracturing technology can alleviate the stress concentration of the casing and reduce the risk of casing deformation failure. This study further reveals the mechanism of casing deformation during multi-fracturing in shale gas wells, and proposes fracturing measures for casing integrity. The results demonstrated in this paper can provide the theoretical basis for preventing casing deformation during fracturing in shale gas wells. 1. INTRODUCTION With the development of unconventional gas reservoirs for shale gas in the world, Significant progress in the exploration and development of shale gas has been made in China recent years, including the construction of the Changning-Weiyuan shale gas field of CNPC and the Chongqing Fuling shale gas field of Sinopec. However, in the national shale gas demonstration area of the Changning-Weiyuan, southwestern Sichuan Basin, since the exploration and development in 2013, some shale gas wells have had some problems, such as poor cementing seal integrity and serious casing deformation. Difficulties in the entry of casings in horizontal well sections, especially in the process of fracturing stimulation and transformation, the impact of casing deformation on the smooth entry of bridge plugs has caused some reservoir sections to be forced to abandon, and even the bridge plugs cannot be drilled smoothly. The emergence of these problems has affected the improvement of single well production in shale gas horizontal wells.

ABSTRACT: Hydraulic fracturing is the principal stimulation technique used to improve the oil and gas recovery and enhance production from unconventional resources. In open hole completion, the direction of the initiated hydraulic fracture around the wellbore is mostly influenced by existence of natural fractures or rock inhomogeneity. After passing the stress perturbed zone near wellbore, the fracture will propagate perpendicular to the minimum principal stress direction. The fracture turning and tortuosity around the wellbore significantly increases the pressure drop and difficulty in placement of proppant. The use of a notch, as a predefined crack in the preferred fracture propagation direction is commonly done in lab experimental studies to assist the fracture to initiate more easily and direct the fracture propagation near wellbore. The use of notch in field hydraulic fracturing applications has also been reported. In this study we numerically simulate the impact of the notch geometry on fracture initiation and propagation pressure and geometry. The XSite, a lattice based model was used to simulate some lab experimental data and the results showed the importance of notch length and its orientation on fracture propagation.

ABSTRACT: Pre-existing natural fracture networks in unconventional reservoirs present at least two major challenges for refracturing and infill well design. First, spatial characteristics of pre-existing natural fracture networks impact how a hydraulic fracture will propagate. Second, the mechanical/chemical characteristics of a natural fracture impact how the reservoir depletes, which might lead to the reservoir's anisotropic effective permeability and depleted zone profile not being as predicted when only considering isotropic reservoir permeability. This paper uses an integrated approach to investigate the challenges imposed by pre-existing natural fractures and their depletion effect on refracturing, as well as completion plans for placing and fracturing infill wells in naturally fractured unconventional reservoirs. Single-well multiple-stage refracturing, parent-child well interference, and infill wells under different scenarios are simulated with consideration to natural fracture networks. Then, engineering options are evaluated to optimize fracture placement to help minimize negative depletion effects and maximize hydrocarbon recovery in parent-child naturally fractured unconventional reservoirs.

ABSTRACT: Various fracturing fluids have been used for coalbed methane (CBM) stimulations. The fracturing fluid can potentially cause permeability damage with an adverse impact on CBM production. In this study, we investigate the permeability damage behavior resulted from commonly used guar-based gel fracturing fluid. The anthracite specimens with the natural fracture and the hydraulic fracture were prepared and used. A series of seepage experiments were conducted to test the fracture permeability evolution after gel injection and during water flushing. The result shows that the guar gel can cause serious damage to the coal permeability for both hydraulic and natural fractures regardless of the guar concentration. The gel residue leads to more serious permeability damage to the natural fracture compare with the hydraulic fracture. Under good gel breaking conditions, the fracture permeability can rebound through water flushing. However, high guar concentration of the gel was found to result in the uncompleted gel breaking, thereby making it difficult for the hydraulic fracture and natural fracture to get good permeability recovery during water flushing. The findings of this study can provide guidance for the technology optimization of the guar-gel fracturing in CBM reservoirs. 1. INTRODUCTION

ABSTRACT: Stimulation of pre-existing natural fractures is considered to contribute significantly to hydrocarbon production from unconventional shale reservoirs. An effective natural-fracture simulation may occur in mixed normal and shear modes due to the misalignment of the natural fractures with respect to the principal stresses. This mixed-mode failure is triggered especially upon intersection of these natural fractures with hydraulic fractures and the fracturing fluid infiltration into the natural fractures. Among various influential parameters on the fracture intersection behavior, hydraulic-natural fracture intersection angle and initial reservoir pore pressure carry the highest uncertainty in shale resources characterization. To address this uncertainty, we adopted poroelastic fracture-intersection and propagation models on the basis of a commonly used pore-pressure cohesive zone model. For the natural fracture reactivation, we obtained a threshold horizontal stress contrast beyond which the natural fracture does not undergo slip. We propose an iterative algorithm using numerical experiments to retrieve the threshold horizontal stress contrast for 16 permutations of initial reservoir pore pressure and intersection angle. Our simulations reveal that with increasing intersection angle, the natural fracture reactivation may occur at a higher or lower horizontal stress contrast depending on the initial reservoir pore pressure.

ABSTRACT: Pre-existing natural fracture networks (NFNs) are ubiquitous in many unconventional oil and gas formations. Hydraulic fracturing (HF) is used to stimulate these formations; many traditional HF analyses and modeling efforts have largely ignored (or highly simplified) the NFN effect on HF stimulation results. NFNs are characterized by geometric properties (including spatial distribution, length, and height) and mechanical properties (including tensile strength, cohesive strength, and shear stiffness). This paper explicitly represents NFNs in a validated, state-of-the-art geo-mechanical simulation model, which couples rock mechanics, fluid mechanics, and proppant transport to enable HF stimulation process modeling. Simulations are used to systematically study NFN properties and their effect on HF stimulation outcomes, including fracture length, propped area, and fracture complexity. All NFN properties (and other formation and stimulation treatment variables) together affect the final stimulated network; examples from the US Eagle Ford and Spraberry formations demonstrate some of these effects. In addition to NFN properties, fracture toughness and horizontal stress anisotropy properties were varied to provide additional insight into the results. Study results demonstrate that NFNs may crucially affect HF stimulation outcomes and, therefore, indicate the importance of mapping NFNs and their mechanical properties, and considering them in designing optimal HF stimulation jobs in particular formations.

ABSTRACT: The geometry of hydraulic fractures is a major concern, especially in highly fractured reservoirs, once it can severely affect oil productivity. Furthermore, interaction of hydraulic fractures with natural fractures can affect locally the in-situ stress state that may cause slippage of the natural fracture. In some cases, stress shadowing effects can even close the hydraulic fracture. Stress rotation around the natural fracture can make hydraulic fracture geometry complex, demanding more computational capacity and time to run numerical simulations. The neural network is a tool that can help real time daily operations when a quick decision is necessary and there is no time to run numerous simulations. This paper focuses on the development of an artificial neural network to predict the interaction between natural and hydraulic fractures. The artificial neural network predicts if hydraulic fractures cross or open natural fractures. In-situ stresses, fracture energy, friction angle of the natural fracture, and angle of approach between fractures are the required input for the artificial neural network, while mode of interaction such as opening, or crossing is the output. The database to train the neural network includes experimental data available in literature and results from numerical simulations. A considerable number of numerical simulations using interface elements to represent fractures provide a suitable database to build an accurate neural network. The neural network was trained for predicting fracture interaction with more than 90% accuracy for opening or crossing behavior. Results were compared with experimental data available in literature and numerical simulations. The results show that for higher angles of approach and higher stress differential, there is a strong tendency to fracture crossing. This is in agreement with the experimental conclusions presented by previous publications in the literature. Additionally, intermediary stress differentials, low values of cohesion and friction angle, and approach angle below 60° define conditions with a strong tendency to open the natural fracture. The scenarios predicted by the neural networks is in agreement with the rock mechanics concepts and with the expected tendencies, which gives more reliability to the neural network.

ABSTRACT: A series of fracture and flow tests are being performed at the Sanford Underground Research Facility (SURF) as part of the EGS Collab project. The tests involve generating a communicating fracture(s) between two boreholes, and monitoring flow through the generated fracture(s). A long-term flow test was performed at the end of October 2018 through early November of 2018 between the injection and production wells at the EGS Collab site on the 4850 Level of SURF. This paper will present an analysis of the pressure, and flow during this test. Analysis and interpretation of the variation in the efficiency of the connection as the injection conditions changed is presented. Recovery of injected fluid is between 70 and 85%. Injection conditions varied from constant pressure, to constant rate, with formation induced pressure rise at constant flow rate, and multiple flush cycles to induce pressure decrease from apparent fracture plugging.

ABSTRACT: In view of the complicated flow mechanism of shale gas flow, multi-scale media and multiple pressure systems of organic matter/inorganic matrix pores/natural fractures and discrete hydraulic fractures are established to accurately describe the gas flow in shale reservoir. The mathematic model considers mechanisms of non-equilibrium desorption of the adsorbed gas, the viscous flow and Knudsen diffusion of the free gas, and the influence of inorganic matrix pores, natural fractures and hydraulic fractures pressure system on shale deformation. A fully coupled solid-fluid coupling model is established, and it is solved with finite element method. It is found from the results that the pressure drop in natural fractures and matrix pores is the main influence factor that causes stress sensitivity during production, and natural fractures play a more important role. With the increase of stimulated reservoir volume, the stress sensitivity is more significant, especially in the early production stage. The proposed fully coupled solid-fluid model of shale gas flow have the ability to study the influence of solid deformation on different pore pressure systems, which consider the non-linear flow mechanisms. The model is also of great value for predicting the shale gas production more accurate.

ABSTRACT: Two 0.3 m × 0.3 m × 0.3 m shale blocks, one representing a homogeneous sample while the other representing a naturally fractured sample, are modelled using the lattice based DEM code, XSite. The synthetic rock mass approach (SRM), which assigns the smooth joint contacts (SJM) to the weakness planes, is used to represent the natural fractures in shale block-2. Firstly, the developed models are compared with the findings of previously conducted true-triaxial hydraulic fracturing experiments with acoustic measurements, and their subsequent computed tomography (CT) and seismic velocity tomography results. The 3D model results confirmed the curved shape hydraulic fractures, which propagated perpendicular to the minimum stress directions in both shale blocks. Model results also captured the natural fracture (NF) and hydraulic fracture (HF) interaction, particularly the arrest, the dilation of major NFs, followed by crossing with offset mechanism, in shale block-2. Secondly, the parametric studies are carried out to investigate the role of fluid flow rate (q), and fluid viscosity (µ) on different NF/HF interaction mechanisms. The effects of q and µ are discussed based on the total stimulated area including the tensile and shear microcracks, the pipe apertures, and the pressure evolutions within NFs.

ABSTRACT: A large scale of true triaxial simulation test is used to simulate natural fracture reactivation, and Fiber Bragg Grating (FBG) strain sensors are placed in cement specimens of 300 × 300 × 300 mm 3 to monitor the slipping process of natural fractures. The research indicated that the maximum slipping of natural fractures in laboratory achieves millimeters, and possibly centimeters in fields by scale laws. The slipping process can be divided into three stages: shear-slipping, open-slipping and extension-slipping. In shear-slipping stage, with the pressure in hydraulic fracture increasing slowly, fracturing fluid insinuate into the natural fracture which reduce the friction factor and normal stress acting on the natural fracture, causing shear slipping of natural fracture increases. In open-slipping stage: the pressure in natural fracture over the normal traction component of ground stress acting on the surface of the natural fracture, the natural fracture begins to open and the slipping return to the original state. In extend-slipping stage: the natural fracture propagates and the slipping of natural fracture increases rapidly. The slipping in the extend-slipping stage is the biggest and 4 times as much as the other two stages.

ABSTRACT: Fiber optic based distributed acoustic sensors (DAS) provide a new approach for monitoring signals of interest in the subsurface with unprecedented spatiotemporal resolution. These sensors produce measurements that are fundamentally different from their traditional counterparts, such as geophones, and produce significantly larger volumes of data. To interpret these data, we begin by using the physics-based thermal-hydraulic-mechanical (THM) model in the GEOS code to simulate synthetic DAS measurements for a range of subsurface conditions (fracture propagation, fault slip, etc.) and sensor configurations (e.g.: horizontal or vertical well deployments). These synthetic DAS measurements are then algorithmically labeled based upon features of interest within their parent models, such as the extent of any generated hydraulic fractures or the distribution of proppant particles, and are compiled into a database. The synthetic database can be used to train and test an initial deep neural network (DNN) representation of the subsurface, which can then be optimized by incorporating any available field measurements through transfer learning. This hybrid, physics informed DNN model is capable of interpreting DAS measurements in near-real time, making it a useful tool for decision making by field engineers, and works under both data-rich and data-poor conditions. To demonstrate this approach, we consider the problem of imaging hydraulic fracture propagation in an unconventional oil and gas reservoir. Our results indicate that we are can use a trained DNN model to accurately estimate the extents of a hydraulic fracture using the location information and DAS measurements for a single fiber-optic sensor as inputs.

ABSTRACT: With a specific case of Fuling shale gas reservoir, an integrated geomechanics workflow was proposed to investigate stress evolution during production and the complex hydraulic fractures propagation of infill well. In the integrated modelling, a natural fractures network was embedded in the geological model firstly. Secondly, a fracturing model was built to simulate the hydraulic fractures of parent wells. Thirdly, a flow-geomechanical coupling model was built to study the stress field evolution after long-time production. Finally, the complex hydraulic fractures propagation of the infill well was stimulated. It can be concluded from the simulation results that (1) the pre-existing complex fracture network exerts a considerable contribution on the pore pressure drop; (2) stress evolution is affected by the geomechanical heterogeneity; (3) the horizontal principal stresses difference is found to increase, and a weak stress re-orientation appears after production; (4) the stress field changes are much smaller near the infill well; (5) the hydraulic fractures initiate preferentially at the perforations with the high density of natural fractures during the infill fracturing; (6) closing to the early producing well fractured region, the fractures complexity of the infill well reduces sharply, and that is well matched with the microseismic monitor results.