Natural Fracture Network Research Articles

Numerical Simulation of the Propagation of Hydraulic and Natural Fracture Using Dijkstra’s Algorithm

Utilization of hydraulic-fracturing technology is dramatically increasing in exploitation of natural gas extraction. However the prediction of the configuration of propagated hydraulic fracture is extremely challenging. This paper presents a numerical method of obtaining the configuration of the propagated hydraulic fracture into discrete natural fracture network system. The method is developed on the basis of weighted fracture which is derived in combination of Dijkstra’s algorithm energy theory and vector method. Numerical results along with experimental data demonstrated that proposed method is capable of predicting the propagated hydraulic fracture configuration reasonably with high computation efficiency. Sensitivity analysis reveals a number of interesting observation results: the shortest path weight value decreases with increasing of fracture density and length, and increases with increasing of the angle between fractures to the maximum principal stress direction. Our method is helpful for evaluating the complexity of the discrete fracture network, to obtain the extension direction of the fracture.

A new production predicting model of fractured horizontal wells in dual-porosity gas reservoirs on non-Darcy flow conditions

Dual-porosity is a common method to model natural fractured reservoirs or complex fracture network after volume hydraulic fracturing. To analyze the productivity of fractured horizontal gas wells, a new volumetric source model with high velocity non-Darcy flow in hydraulic fractures is developed. The basic volumetric source function is solved by utilizing orthogonal transformation in real space, which solves the problem that the non-linear equation (indicating non-Darcy effect) cannot adopt Laplace transformation. The volumetric source model is verified by the tri-linear flow model and a field example. Results shows increasing width of hydraulic fractures and enlarging size of proppant have significant effect on weaken non-Darcy flow. The volumetric source model is a fast and accurate method to predict the productivity. In addition, this model can provide a more reasonable method to optimize hydraulic fracturing considering non-Darcy flow effect.

The interplay between natural fractures and stress as controls to hydraulic fracture geometry in depleted reservoirs

Pressure changes in the reservoir due to injection or production, lead to anisotropic changes in the magnitude and orientation of the stresses in the reservoir. The characteristics of the modified stress field can potentially lead to asymmetric fracture growth in infill wells stimulated by hydraulic fracturing, which in turn could potentially cause a detrimental interference between wells. The final geometry of the hydraulic fractures, however, will depend on the relative contributions of several other variables and not on changes in stress alone. Therefore, for the planning and optimization of infill wells, the interplay among these variables must be accounted for. In this paper we study via numerical simulations, the relative weight of rock fabric and depletion-induced stress in relation to the geometry and propagation of hydraulic fractures near a producing well. Our results indicate that the presence of a dense network of natural fractures can override the effect of depletion-induced stress, and limit the asymmetric growth of the fractures.

Integrated fracability assessment methodology for unconventional naturally fractured reservoirs: Bridging the gap between geophysics and production

Fracability evaluation in unconventional reservoirs is one of the most important initiatives for economic success. Most evaluation methods in geophysics and well logging are based on calculating rock mechanical properties, in which a frequently used term is brittleness. However, oil and gas production, mainly determined by effective natural fracture networks in unconventional low-permeability reservoirs, is the final goal of reservoir stimulation. In this work, a novel integrated methodology was proposed to correlate conventional post-stack seismic data to well production rate. It aims to pre-evaluate regional stimulation performance, facilitating investment decision-making in line with global oil prices and environmental consideration. Structural occurrence, seismic maximum curvature, and geomechanics parameters were combined in a physical model to evaluate underlying development and activation of natural fractures, result in the activation index F1. The potential of artificial induced fractures were quantified as normalized index F2 by integrating mechanical item based on fracture mechanics and fluid flow. Accordingly, a fracability sweetness index (Fsweet) model was built to correlate standardized well production rate (Qeff). A Case study of a naturally fractured igneous reservoir with 8 wells showed agreement between Fsweet and Qeff. A considerable part of highly active fractures with F1 of [0.9, 1] distributed over the area with lower curvature value. By contrast, the majority of fractures with lower F1 of [0.8, 0.9] located in zone with higher curvature value. The weight ratio α=0.06 indicated that in this case the overwhelming production contribution were from natural fractures, which were evidenced by well core picture. The field data demonstrates the prospect for predicting regional fracability variation, and suggests that it is possible to correlate fracability index with standardized well production rate. The insights contribute to well placement optimization and stimulation treatment design, breaking limitation of engineers' influence on individual wells, and hence reducing exploitation cost while enhancing ultimate recovery.

Organization, flow impact and modeling of natural fracture networks in a karstified carbonate bitumen reservoir: an example in the Grosmont Formation of the Athabasca Saleski leases, Alberta, Canada

Abstract The Grosmont Formation in Alberta contains one of the largest hydrocarbon accumulations of a carbonate reservoir in the world. It is also a highly fractured reservoir, where natural fracture networks have a key bearing on production and final recovery. The present fracture study focused on the Grosmont C and D units of the Saleski leases, where a steam injection pilot for the Grosmont was initiated in 2010 by Laricina Energy Ltd. and its partner, Osum Oil Sands Corp. This study aimed at characterizing the types, scales and organization of fractures in the reservoir units in order to build a representative fracture model and derive corresponding fracture properties to be used in dual porosity dynamic simulations. Detailed core and borehole image analyses revealed that fracturing in the Grosmont C and D units is organized into four sets of metre-scale joints and isotropic, centimetre-scale dissolution-related cracks. The joint density is controlled by facies. Dynamic data analysis revealed a link between mud losses, rock dissolution and facies types, especially in the Middle D unit. It also emphasized the fracture contribution to overall reservoir permeability. All of these findings were integrated to build a multiscale fracture model which, once dynamically calibrated, allowed computing fracture porosity, permeability tensor and matrix block sizes. These outputs are critical for thermal dual porosity dynamic simulations.

Recovery rates of fracturing fluids and provenance of produced water from hydraulic fracturing of Silurian Qusaiba hot shale, northern Saudi Arabia, with implications on fracture network

Geochemical fingerprinting of produced water from hydraulic fracturing projects is an essential tool to trace their provenance during the postfracturing period, to quantify recovery rates and volumes of fracturing fluids, and to visualize the geodynamic structure of natural or induced fracture networks. A total of 41 produced water samples from an exploration well in the Northern Arabia Exploration Area in Saudi Arabia were collected daily from the fracture-stimulated Qusaiba hot shale and analyzed for major ions and trace elements and partially for environmental isotopes. The postfracturing period shows an initial return of supply water and potassium chloride brine, subsequently replaced by the inflow of sodium chloride–type formation water with a stable plateau salinity of 50,000 mg/L. Less than 10% of the total injected fracturing fluids were recovered during postfracturing, whereas 78.8 vol. % of the total recovered fluid is composed of formation water (20,843 out of 26,446 bbls) during the study period. Coinciding values between logged reservoir temperature and calculated geothermometers confirm the provenance of pore water from the Qusaiba hot shale or from nearby units. The recharge of the Silurian sequence with meteoric surface water occurred during the early Holocene (6–6.7 ka), as evidenced by geochronological dating with the 14C method and δ18O/δ2H values close to the global meteoric water line. The inflow of formation water into the stimulated shale layer in the postfracturing stage could be originated by the natural occurrence of pore water within a naturally fractured, black shale layer or, more likely, by the rise of groundwater from the underlying Sarah sandstones via migration pathways of natural or newly formed, vertically induced hydraulic fractures. For this particular well site and the specific hydraulic fracturing project, chemical and isotopic fingerprinting confirms the absence of ascending migration pathways from the Silurian Qusaiba hot shale toward a shallower groundwater system, which are isolated through a lithological set of more than 900 m (3000 ft) of impermeable mudstone from the Qusaiba Member.

Efficient production estimation for a hydraulic fractured well considering fracture closure and proppant placement effects

It is important to accurately estimate performances of a hydraulic fractured well, because it will be utilized to evaluate various completion parameters and furthermore to establish a future development plan. Shale gas reservoirs with fracture networks have high initial production rates but show drastic production decline as reservoirs are depleted by production. One of the reasons behind this phenomenon is an increased effective stress during production resulting in fracture closures. Gas mainly flows through hydraulic and natural fracture networks, so the fracture closures cause permeability reduction in the flow areas. In typical hydraulic fracturing operations, proppants are injected with fracturing fluid and placed in the fracture networks. Proppants play a crucial role to keep an induced hydraulic fracture open and retain a well productivity. However, only small portion of the fracture networks are filled with proppants (propped fracture) and the rest exist without proppants (unpropped fracture). Therefore, fracture closures of these regions are quite different. In this article, we have investigated to identify the combined effect of fracture closure and proppant placement on production estimation of a shale gas well. A numerical model has been developed to mimic well performances in Horn River Basin, BC, Canada. We have used pressure-dependent correlations based on experiments to consider fracture permeability alteration with changing reservoir pressure. Proppant placements are described using a fracture propagation model and this enables to classify a whole reservoir into sub regions such as propped, unpropped fracture, and matrix. By comparing with different cases, this article shows that reasonable results on gas production estimation are accomplished when considering fracture closure and proppant placement effects together.

Using geomechanical modeling to quantify the impact of natural fractures on well performance and microseismicity: Application to the Wolfcamp, Permian Basin, Reagan County, Texas

We have evaluated workflows to quantify the mechanical impact of natural fractures (NFs) on the production performance of hydraulically stimulated stages in shale wells. Variations in fracture orientation and density can enhance or degrade the transport and effectiveness of fracturing fluids. Specifically, we studied the effect of a complex fault splay system on a horizontal Wolfcamp B reservoir well. A general workflow that combines geophysics, geology, and geomechanics (3G) was evaluated and applied to the well. The benefits of the 3G workflow are threefold. First, the quantitative impact of the NFs on the regional stress is provided through the differential horizontal stress variation, which impacts fracturing complexity. Then, the reservoir strain map, validated with microseismic data, gives insights into the stimulated drainage pathways. Finally, the ability of the [Formula: see text] integral to predict poor hydraulic fracturing stages as a function of fracture density along the wellbore or as a function of the energy required to propagate a fracture. Building on the validated 3G workflow, a well placement workflow that takes into account the quantitative impact of NFs on well performance was developed on the sample Wolfcamp well. By comparing the [Formula: see text] integral of the same completion stage in simulations with and without NFs, stages with similar [Formula: see text] integral values in both simulations were identified as those not being affected by the NF network. This allows the workflow to provide the optimal position of a well in the presence of NFs associated with a complex fault system that may produce undesirable water. The result is a validated 3G workflow that provides a geomechanical explanation for an empirical relationship showing that high oil production is achieved within a “Goldilocks” range of natural fracturing.

A Comprehensive Simulation Model of Kerogen Pyrolysis for the In-situ Upgrading of Oil Shales

Summary Oil shale, which is composed of abundant organic matter called kerogen, is a vast energy source. Pyrolysis of kerogen in oil shales releases recoverable hydrocarbons. Here, we describe the pyrolysis of kerogen with an in-situ upgrading process, which is applicable to the majority of oil shales. The pyrolysis is represented by six kinetic reactions resulting in 10 components and four phases. Expanding the Texas A&M Flow and Transport Simulator (FTSim), which is a variant of the TOUGH + simulator (Moridis 2014), we develop a fully functional capability that describes kerogen pyrolysis and accompanying system changes. The simulator describes the coupled process of mass transport and heat flow through porous and fractured media and includes physical and chemical phenomena of reservoir systems. The simulator involves a total of 15 thermophysical states and all transitions between them and computes a simultaneous solution of 11 mass- and energy-balance equations per element. The simulator solves the equations in a fully implicit manner by solving Jacobian matrix equations with the Newton-Raphson iteration method. To conduct a realistic simulation, we account for geological structure of oil-shale reservoirs and physical properties of bulk-oil shale rocks by considering phases and components in the pores. In addition, we involve interaction between fluids and porous media, diverse equations of state (EOSs) for computation of fluid properties, and numerical modeling of fractured media. We intensively reproduce the field-production data of Shell In-situ Conversion Process (ICP) implemented in the Green River formation by conducting sensitivity analyses for the diverse reservoir parameters, such as initial effective porosity of the matrix, oil-shale grade, and the spacing of the natural-fracture network. We analyze the effect of each reservoir parameter on the hydrocarbon productivity and product selectivity. The simulator provides a powerful tool to quantitatively evaluate production behavior and dynamic-system changes during in-situ upgrading of oil shales and subsequent fluid production by thoroughly describing a reservoir model, phases and components, phase behavior, phase properties, and evolution of porosity and permeability.

Productivity enhancement by stimulation of natural fractures around a hydraulic fracture using micro-sized proppant placement

Hydraulic fracturing in naturally fractured rocks interconnects a natural fracture network to the wellbore. Improving the connectivity between a hydraulically created fracture and the pre-existing natural fractures can significantly improve the hydraulic fracturing efficiency. In this study, a well stimulation method is proposed to enhance the conductivity of fracture system around the hydraulic fracture. This stimulation technique involves placing micro-sized proppant particles in the natural fracture system around the hydraulic fracture at the leak-off pressure condition in order to maintain the fracture systems' conductivity during the post-fracturing production.The equations for one-dimensional suspension flow around and perpendicular to the hydraulic fracture, accounting for rock deformation and particle capture, have been derived. The effects of permeability reduction due to particle straining are incorporated in the analytical model. The laboratory tests on the solid-particle suspension injection into the natural fractures of a coal core at elevated pressures are successfully matched by the model. The experimental results confirm there is an optimum concentration of placed particles whereby a maximum permeability is retained; this optimal proppant particle placement yields nearly a three-fold increase in permeability. The analytical model has been tuned from these experiments to calculate the optimum concentration of placed particles and predict the productivity improvement after stimulation of the fracture system around the hydraulic fracture.A case study is presented to demonstrate the productivity enhancement by applying the proposed technique in a coal-bed-methane (CBM) reservoir. The laboratory-based analytical model predicts a six-fold increase in the productivity index. Examples for the possible practical applications of the developed technology in hydraulic fracturing or stimulation treatments in coals are also presented.

A MIXED-FRACTAL FLOW MODEL FOR STIMULATED FRACTURED VERTICAL WELLS IN TIGHT OIL RESERVOIRS

Stimulated reservoir volume (SRV) with large fracture networks can be generated near hydraulic fractured vertical wells (HFVWs) in tight oil reservoirs. Statistics show that natural microfractures and fracture networks stimulated by SRV were self-similar in statistical sense. Currently, various analytical models have been presented to study pressure behaviors of HFVWs in tight oil reservoirs. However, most of the existing models did not take the distribution and self-similarity of fractures into consideration. To account for stimulated characteristic and self-similarity of fractures in tight oil reservoirs, a mixed-fractal flow model was presented. In this model, there are two distinct regions, stimulated region and unstimulated region. Dual-porosity model and single porosity model were used to model stimulated and unstimulated regions, respectively. Fractal geometry is employed to describe fractal permeability and porosity relationship (FPPR) in tight oil reservoirs. Solutions for the mixed-fractal flow model were derived in the Laplace domain and were validated among range of the reservoir parameters. The pressure transient behavior and production rate derivative were used to analyze flow regimes. The type curves show that the fluid flow in HFVWs can be divided into six main flow periods. Finally, effect of fractal parameters and SRV size on flow periods were also discussed. The results show that the SRV size and fractal parameters of fracture network have great effect on the former periods and fractal parameters of matrix mainly influence the later flow periods.

Investigation of Hydromechanical Mechanisms in Microseismicity Generation in Natural Fractures Induced by Hydraulic Fracturing

SummaryEconomic success in producing oil/gas from low-permeability shale often relies on pre-existing natural fractures (NFs) to be activated or connected by hydraulic-fracturing (HF) stimulation. In practice, the reactivated NF network is often identified with the microseismicity (MS) monitored during the stimulation. However, the fundamental mechanisms of MS generation and focal mechanisms inferred from geophysical analysis near HFs are not currently well-understood (e.g., it is not clear whether the MS observed in the field can be mainly attributed to local shear slip along NFs when leakoff occurs and/or induced by stress changes as a result of HF propagation or fluid leakoff). The exact slippage area and amount of slip displacement generating the microseismic event are not well-understood either, thus requiring a “bridge” between geomechanics and geophysics. To bridge this gap, a set of experiments is performed in a geomechanics laboratory to observe whether, when, where, and how the acoustic-emission events are generated during various scenarios. The experiments are designed with the guidance of the fracture-flow/discrete-element method (DEM), coupling geomechanical simulations. In this paper, the reliability and accuracy of the fracture-flow/DEM coupling approach is validated through solving a few fundamental problems and comparing the numerical-simulation results with the corresponding analytical solutions. The coupling approach is then applied to simulate and optimize two fundamental laboratory experiments. The simulations indicate that, despite the difference in the magnitude, one could induce the local slip along NFs by both fluid leakoff and stress changes.

Effect of Fracture Characteristics on Behavior of Fractured Shale-Oil Reservoirs by Cyclic Gas Injection

Summary The current technique to produce shale oil is to use horizontal wells with multistage stimulation. However, the primary oil-recovery factor is only a few percent. The low oil recovery and abundance of shale reservoirs provide a huge potential for enhanced oil-recovery (EOR) process. Well productivity in shale oil-and-gas reservoirs primarily depends on the size of fracture network and the stimulated reservoir volume (SRV) that provides highly conductive conduits to communicate the matrix with the wellbore. The fracture complexity is critical to the well-production performance, and it also provides an avenue for injected fluids to displace the trapped oil. However, the disadvantage of gasflooding in fractured reservoirs is that injected fluids may break through to production wells by means of the fracture network. Therefore, a preferred method is to use cyclic gas injection to overcome this problem. In this paper, we use a numerical-simulation approach to evaluate the EOR potential in fractured shale-oil reservoirs by cyclic gas injection. Simulation results indicate that the stimulated fracture network contributes significantly to the well productivity by means of its large contact area with the matrix, which prominently enhances the macroscopic sweep efficiency in secondary cyclic gas injection. In our previous simulation work, the EOR potential was evaluated in hydraulic planar-traverse fractures without considering the propagation of a natural-fracture network. In this paper, we examine the effect of fracture networks on shale oilwell secondary-production performance. The impact of fracture spacing and stress-dependent fracture conductivity on the ultimate oil recovery is investigated. The results presented in this paper demonstrate that cyclic gas injection has EOR potential in shale-oil reservoirs. This paper focuses on evaluating the effect of fracture spacing, the size of the fracture network, fracture connectivity (uniform and nonuniform), and stress-dependent fracture-network conductivity on well-production performance of shale-oil reservoirs by secondary cyclic gas injection.

Fracture properties analysis and discrete fracture network modelling of faulted tight limestones, Murge Plateau, Italy

The modelling of natural fracture in reservoirs requires, as input data, the results of previous detailed and accurate analysis of the 3D fracture network. These data could be derived from well logs and production tests (which however limit our understanding of the fracture geometry, intensity and distribution) and outcrop analogues. Data obtained applying scanline and scanarea methodologies on rocks exposed at the surface, in fact, allow the construction of more representative numerical models of natural fractured reservoirs. This paper focuses on with the (DFN) modelling of natural fractures associated to strike-slip faults crosscutting tight carbonates, which are exposed along vertical walls and pavements of an inactive quarry of the Murge area, southern Italy. The studied outcrops expose the inner structure of two conjugate fault zones striking WNW-ESE and NNW-SSE, respectively. DFN models were built according to the spatial and dimensional properties computed for the natural fracture network. The results of these models show that the overall fault permeability is 3-to-4 orders of magnitude higher than the host rock permeability. The fault damage zones form the main fluid conduits, with the highest permeability values computed for fault-parallel fluid flow. Such a pronounced permeability anisotropy obtained for the fault damage zone is mainly related to the fracture dimension, both lengths and heights, and their aperture values.

Simulation of proppant transport with gravitational settling and fracture closure in a three-dimensional hydraulic fracturing simulator

Abstract We implement proppant transport in a three-dimensional hydraulic fracturing simulator, including proppant settlement due to gravity, tip screen-out, and fracture closure. Constitutive equations are used that account for processes that can cause the flowing fraction of proppant to be different from the volumetric fraction of proppant. The constitutive equations capture the transition from Poiseuille flow to Darcy flow as the slurry transitions from dilute mixture to packed bed. We introduce new constitutive equations that allow the simulator to seamlessly describe the process of fracture closure, including a nonlinear joint closure law expressing fracture compliance and roughness and accounting for the effect of proppant accumulation into a packed layer between the fracture walls. We perform sensitivity analysis simulations to investigate the effect of fluid viscosity, proppant density, proppant size, and formation permeability. The simulations confirm that tip screen-out can limit fracture length, cause proppant banking, and increase injection pressure. Sensitivity analysis indicates that reasonably accurate results can be achieved without excessive mesh refinement. We also perform a simulation of hydraulic fracture propagation through a complex natural fracture network. In this simulation, proppant tends to accumulate at the intersections between natural and hydraulic fractures. Overall, the results suggest that in very low permeability formations, proppant settling is a major problem for proppant placement because proppant tends to gravitationally settle before fracture closure can occur. Because leakoff is so slow, proppant immobilization through bridging is critical for vertical proppant placement. Bridging can occur at aperture approximately three times greater than particle diameter, which will occur much sooner after shut-in than full mechanical closure. Even though larger diameter proppant settles more rapidly, it may lead to better proppant placement because it will bridge sooner, at a larger fracture aperture. These results also suggest that it is critical to optimize injection schedule in order to avoid tip screen-out, which leads to a shorter, wider fracture in which bridging is less likely to occur. Our modeling approach can be used practically for optimization of proppant placement through selection of fluid properties, proppant properties, and injection schedule.

Optimization-Based Unstructured Meshing Algorithms for Simulation of Hydraulically and Naturally Fractured Reservoirs With Variable Distribution of Fracture Aperture, Spacing, Length, and Strike

Summary Multistage hydraulically fractured wells are applied widely to produce unconventional resource plays. In naturally fractured reservoirs, hydraulic-fracture treatments may induce complex-fracture geometries that one cannot model accurately and efficiently with Cartesian and corner-point grid systems or standard dual-porosity approaches. The interaction of hydraulic and naturally occurring fractures almost certainly plays a role in ultimate well and reservoir performance. Current simulation models are unable to capture the complexity of this interaction. Generally speaking, our ability to detect and characterize fracture systems is far beyond our capability of modeling complex natural-fracture systems. To evaluate production performance in these complex settings with numerical simulation, fracture networks require advanced meshing and domain-discretization techniques. This paper investigates these issues by developing natural-fracture networks with fractal-based techniques. After a fracture network is developed, we demonstrate the feasibility of gridding complex natural-fracture behavior with optimization-based unstructured meshing algorithms. Then we can demonstrate that one can simulate natural-fracture complexities such as variable aperture, spacing, length, and strike. This new approach is a significant step beyond the current method of dual-porosity simulation that essentially negates the sophisticated level of fracture characterization pursued by many operators. We use currently established code for fractal discrete-fracture-network (FDFN) models to build realizations of naturally fractured reservoirs in terms of stochastic fracture networks. From outcrop, image-log, and core analysis, it is possible to extract fracture fractal parameters pertaining to aperture, spacing, and length distribution, including center distribution as well as a fracture strike. Then these parameters are used as input variables for the FDFN code to generate multiple realizations of fracture networks mimicking fracture clustering and randomly distributed natural fractures. After incorporating hydraulic fractures, complex-fracture networks are obtained for further reservoir-domain discretization. To discretize the complex-fracture networks, a new mesh-generation approach is developed to conform to nonorthogonal and low-angle intersections of extensively clustered discrete-fracture networks with nonuniform aperture distribution. Optimization algorithms are adopted to reduce highly skewed cells, and to ensure good mesh quality around fracture tips, intersections, and regions of extensive fracture clustering. Moreover, local grid refinement is implemented with a predefined distance function to control cell sizes and shapes around and far away from fractures. Natural-fracture spacing, length, strike, and aperture distribution are explicitly gridded, thus introducing a new simulation approach that is far superior to dual-porosity simulation. Finally, initial sensitivity studies are performed to demonstrate both the capability of the optimization-based unstructured meshing algorithms, and the effect of aforementioned natural-fracture parameters on well performance. This study demonstrates how to incorporate a fractal-based characterization approach into the current work flow for simulating unconventional reservoirs, and most importantly solves several issues such as nonorthogonal intersections, extensive clustering, and nonuniform aperture distribution associated with domain discretization with unstructured grids for complex-fracture networks. The proposed meshing techniques for complex fracture networks can be easily implemented in existing preprocessing, unstructured mesh generators. The sensitivity study and the simulation runs demonstrate the importance of fracture characterization as well as uncertainties associated with naturally fractured reservoirs on well-production performance.

Overview of numerical models for interactions between hydraulic fractures and natural fractures: Challenges and limitations

The intersection of natural fractures with hydraulic fractures results in formation of complex fracture networks, including non-planar fractures or multi-stranded fractures. On one hand, opening of these natural fractures improves productivity of the formation; on the other hand, coalescence of these fractures into a hydraulic fracture makes pressure analysis and prediction of fracture growth very complicated. Overall, interactions between natural fractures and hydraulic fractures pose more challenges in the fracturing design and its execution. Investigation and understanding of their interaction are crucial in achieving successful fracture treatments in formations with pre-existing natural fracture network. In this paper, we will review the numerical works that have been done in the last decade to model opening of natural fractures during hydraulic fracturing, focusing especially on mechanical models that address propagation of hydraulic fractures in naturally fractures reservoirs. Linear elastic fracture mechanics, cohesive element methods and continuum damage mechanics techniques utilized to understand interaction of hydraulic fractures with natural fractures are discussed here based on their capability to reproduce experimental results and field observations.

Numerical Analysis on the Optimization of Hydraulic Fracture Networks

The clear understanding of hydraulic fracture network complexity and the optimization of fracture network configuration are important to the hydraulic fracturing treatment of shale gas reservoirs. For the prediction of hydraulic fracture network configuration, one of the problems is the accurate representation of natural fractures. In this work, a real natural fracture network is reconstructed from shale samples. Moreover, a virtual fracture system is proposed to simulate the large number of small fractures that are difficult to identify. A numerical model based on the displacement discontinuity method is developed to simulate the fluid-rock coupling system. A dimensionless stress difference that is normalized by rock strength is proposed to quantify the anisotropy of crustal stress. The hydraulic fracturing processes under different stress conditions are simulated. The most complex fracture configurations are obtained when the maximum principle stress direction is perpendicular to the principle natural fracture direction. In contrast, the worst results are obtained when these two directions are parallel to each other. Moreover, the side effects of the unfavorable geological conditions caused by crustal stress anisotropy can be partly suppressed by increasing the viscous effect of the fluid.

Impact of Shale-Gas Apparent Permeability on Production: Combined Effects of Non-Darcy Flow/Gas Slippage, Desorption, and Geomechanics

Summary Permeability is one of the most fundamental reservoir-rock properties required for modeling hydrocarbon production. Many shale-gas and ultralow-permeability tight gas reservoirs can have matrix-permeability values in the range of tens to hundreds of nanodarcies. The ultrafine pore structure of these rocks can cause violation of the basic assumptions behind Darcy's law. Depending on a combination of pressure-temperature conditions, pore structure and gas properties, non-Darcy flow mechanisms such as Knudsen diffusion, and/or gas-slippage effects will affect the matrix apparent permeability. Even though numerous theoretical and empirical models were proposed to describe the increasing apparent permeability caused by non-Darcy flow/gas-slippage behavior in nanopore space, few literature sources have investigated the impact of formation compaction and the release of the adsorption gas layer upon shale-matrix apparent permeability during reservoir depletion. In this article, we first present a thorough review on gas flow in shale nanopore space and discuss the factors that can affect shale-matrix apparent permeability, besides the well-studied non-Darcy flow/gas-slippage behavior. Then, a unified shale-matrix apparent-permeability model is proposed to bridge the effects of non-Darcy flow/gas-slippage, geomechanics (formation compaction), and the release of the adsorption gas layer into a single, coherent equation. In addition, a mathematical framework for an unconventional reservoir simulator that was developed for this study is also presented. Different matrix apparent-permeability models are implemented in our numerical simulator to examine how the various factors affect matrix apparent permeability within the simulated reservoir volume. Finally, the impact of a natural-fracture network on matrix apparent-permeability evolution is investigated. The results indicate that, even though the conductive fracture network plays a vital role in shale-gas production, the matrix apparent-permeability evolution during pressure depletion cannot be neglected for accurate production modeling.

A Practical Simulation Method Capturing Complex Hydraulic-Fracturing Physics

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 172831, “Forecasting Production in Shale and Tight Reservoirs: A Practical Simulation Method Capturing the Complex Hydraulic-Fracturing Physics,” by Axelle Baroni, Matthieu Delorme, and Nina Khvoenkova, IFP Energies nouvelles, prepared for the 2015 SPE Middle East Oil and Gas Show and Conference, Manama, Bahrain, 8–11 March. The paper has not been peer reviewed. To understand production from shale reservoirs, the role of hydraulically induced fractures, natural fractures, and their interaction in a formation must be captured. Implementation of such approaches is data-intensive and is accurate only when the field is fully characterized. A model has been developed in which fractures are discretized explicitly and flow is coupled by use of simplified mechanics. It can be considered as an intermediate method between a fully developed discrete-fracture-network (DFN) model and simplified hydraulic-fracturing models. Introduction The current view is that many unconventional reservoirs comprise well-developed natural-fracture networks with multiple orientations within which complex hydraulic-fracture patterns develop, as suggested by microseismic data. The unconventional-reservoir modeling process follows a multidisciplinary integrated approach that includes specific aspects of geophysics, geology, laboratory work, and reservoir engineering. To understand the shale-deformation processes, the flow should be coupled with mechanics, yet the complexity of the involved mechanisms governing stimulation modeling precludes very fast simulations. Characterizing all parameters is a challenge because of the uncertainty of natural- fracture distribution, potential local stress changes, and the lack of reservoir description in three dimensions. The best practice able to capture the most-important phenomena, integrating while being accurately predictive, is not yet defined. The presented work flow (detailed in Fig. 1 and in the text of the complete paper) focuses on the entire stimulation process, describing a simplified yet physically sound model in a 3D discrete and deformable fracture network (DDFN). Flow Methodologies The first step of the work flow is the natural-fracture- network characterization. By use of image and classical logs coupled with other seismic and geological analysis, the natural-fracture model can be constructed. The overall fracture network (natural and hydraulically induced fractures) is defined by one or several fracture families, each being defined deterministically (faults and damaged zone) or by statistical laws (hydraulically induced and natural fractures) for orientation, density, and size. Overall connectivity and fracture hydraulic properties are more uncertain than geometrical ones, usually calibrated from dynamic data. By use of the fracture families’ statistical properties, the discrete network can be generated stochastically (depending on the random seed). Each perforation “shot” is represented by a highly conductive near-well damaged zone of a few meters.