Large Fracture Networks Research Articles

Effectiveness and time variation of induced fracture volume: Lessons from water flowback analysis

Characterizing the induced fracture network is crucial for evaluating and optimizing fracturing operations and for forecasting hydrocarbon production. In our previous paper [1], we developed a closed-tank material balance model to estimate effective fracture volume using rates and pressure data measured during early-time water flowback. In this paper, we extend this model to an open-tank model to estimate fracture-matrix interface area using rates and pressure data measured during late-time water flowback. We verify the proposed model against a 2D numerical model solved by a commercial software, and demonstrate the application of the proposed model to an eight-well pad completed in the gas shales of the Horn River Basin. Finally, we conduct a comparative analysis to investigate the time variation of effective fracture volume during water flowback. The results show that up to 30% of the effective fracture volume is lost due to pressure depletion and fracture closure during early-time water flowback. The rate of fracture volume reduction decreases during late-time flowback when gas from the matrix kicks into the fracture network and provides sufficient pressure support. However, the estimated fracture-matrix interface area is relatively low and cannot be explained by the estimated fracture volume. This result suggests that although a large fracture network is created by hydraulic fracturing operations, only a small fraction of the fracture network receives gas influx from the matrix. Overall, the results suggest that a large fraction of the fractures induced in gas shales does not contribute to hydrocarbon production due to fracture closure, permeability jail effect, and water blockage.

The study on fracture network development in shale fracturing with considering capillary effect

Natural fractures widely exist in shale reservoirs with different scales, ranging from nano scale to micro scale, even to macro and engineering scale. These multi-scale natural fractures have a great influence on the fracture network propagation during a fracturing treatment. Meanwhile, the fracturing fluid flowing into these natural fractures will result in the co-existence of fracturing fluid and natural gas. As a result, the capillary force occurs at the gas-liquid interface in natural fractures. If the sizes of these natural fractures are different, the capillary force in the natural fractures is different as well. In particular, when the natural fracture is small, the capillary force will be very large and even affect the natural fracture initiation and propagation. As a consequence, the fracturing fluid flowing in natural fractures and the fracture network development will be significantly affected by these multiscale natural fractures. In this paper, a model about fracture network propagation was built which considered natural fractures sizes and fracturing fluid wettability. Besides, different methods were adopted to calculate the stress intensity of hydraulic fracture and natural fracture, respectively. In addition, the competitive growth theory of multi fractures is considered to describe the fracture network propagation. The studies found that with long length, small width natural fractures and strong wettability fracturing fluid, natural fractures were more likely to propagate, which resulted in a large fracture network. Besides, when the sizes of natural fractures were different, a more complex fracture network was tended to come out. An experimental study about fracture network propagation in shale was introduced from Suarez-Rivera’s work, in which a “fish bone” shape fracture propagation was observed. By comparing the numerical simulation with Suarez-Rivera’s work, it could be concluded that the simulation was in accordance with shale fracturing experiments results.

High injection rate stimulation for improving the fracture complexity in tight-oil sandstone reservoirs

Successfully creating a large field fracture network is crucial for achieving economic production of tight-oil sandstone reservoirs. In this paper, the variations of in situ stress as well as the fracture network are studied based on a fully coupled flow and mechanics model. A high injection rate stimulation technique is extensively investigated as an effective method for improving the fracture complexity in single or multiple stages of horizontal well. Sensitivity studies are conducted for this stimulation method in improving the fracture complexity. The high injection rate stimulation cannot efficiently promote the fracture network area for ductile rocks. Initial in situ stress contrast plays an important role in the creation of fracture network. The fracture aperture as well as stress perturbation is controlled by the minimum in situ stress. The stress perturbation is accentuated in low permeability reservoirs, which is helpful to achieve a large field of fracture network. The area of new created fracture network in sequential fracturing is increasing with the fractures due to the arising of mechanical interaction between fractures. The results presented in this paper can be used in hydraulic fracturing design in tight-oil sandstone reservoirs to promote productivity.

Determination of RVE size based on the 3D fracture persistence

This paper presents an application of a 3D fracture network model and 3D persistence to confirm the representative volume element (RVE) in a fractured rock mass. Based on field fracture data collected from the Songta dam site, a large 3D fracture network is generated to analyse the RVE. The 3D persistence, which is governed by the comprehensive characteristics of fracture location, orientation, size and density, strongly affects the shear strength of fractured rock masses. Hence, it is valuable to confirm the RVE size considering the persistence, which combines the geometric and mechanical properties of a rock mass. The persistence values of the entire model and of cubes of different sizes, which are located in the centre of the model, are determined. A relative error of 10% is selected as the benchmark to evaluate the similarity between the cubes and the model. Finally, 15 m is confirmed as the size of the RVE in the study area.

Simulation of micro-seismicity in response to injection/production in large-scale fracture networks using the fast multipole displacement discontinuity method (FMDDM)

Analysis of fluid flow, permeability, and micro-seismicity in large fracture networks are essential for economical production from engineered geothermal and petroleum reservoirs. In this work, the fluid pressure change, as a result of injection and production inside a stochastic, deformable, non-propagating fracture network is modeled using the fast multipole displacement discontinuity method combined with the finite difference method. The former is employed to simulate the response of the fracture network to changes in the pressure due to fluid injection. In addition to pressure changes inside the fracture network, changes in fracture status with respect to normal (“joint” versus hydraulic fracture) and shear (stick versus slip) deformation, dilation, and friction coefficient are considered. Rate-and-state friction model and the Mohr-Coulomb criterion are used to model slip and potential micro-earthquakes and their seismic moments. Simulation results show that increase in pressure inside a fracture network leads to permanent slip and nucleation of micro-earthquakes which are mostly influenced by the orientation of the fractures and the magnitude of fluid pressure and the injection rate. Injecting the same volume of water over a longer time period decreases the number and magnitude of seismic events.

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.

The Virtual Element Method for large scale Discrete Fracture Network simulations: fracture‐independent mesh generation

AbstractWe consider the problem of underground flow simulations in fractured media. This is a large scale, heterogeneous multi‐scale phenomenon involving very complex geological configurations. Within the Discrete Fracture Network (DFN) model, we focus on the resolution of the steady‐state flow in large fracture networks. Exploiting the peculiarity of the Virtual Element Method (VEM), which allows the use of rather general polygonal mesh elements, we propose an approach for building a suitable mesh for representing the solution on DFNs. (© 2015 Wiley‐VCH Verlag GmbH & Co. KGaA, Weinheim)

Influence of host lithofacies on fault rock variation in carbonate fault zones: A case study from the Island of Malta

Relatively few studies have examined fault rock microstructures in carbonates. Understanding fault core production helps predict the hydraulic behaviour of faults and the potential for reservoir compartmentalisation. Normal faults on Malta, ranging from <1 m to 90 m displacement, cut two carbonate lithofacies, micrite-dominated and grain-dominated carbonates, allowing the investigation of fault rock evolution with increasing displacement in differing lithofacies. Lithological heterogeneity leads to a variety of deformation mechanisms. Nine different fault rock types have been identified, with a range of deformation microstructures along an individual slip surface. The deformation style, and hence type of fault rock produced, is a function of host rock texture, specifically grain size and sorting, porosity and uniaxial compressive strength. Homogeneously fine-grained micrtie-dominated carbonates are characterised by dispersed deformation with large fracture networks that develop into breccias. Alternatively, this lithofacies is commonly recrystallised. In contrast, in the coarse-grained, heterogeneous grain-dominated carbonates the development of faulting is characterised by localised deformation, creating protocataclasite and cataclasite fault rocks. Cementation also occurs within some grain-dominated carbonates close to and on slip surfaces. Fault rock variation is a function of displacement as well as juxtaposed lithofacies. An increase in fault rock variability is observed at higher displacements, potentially creating a more transmissible fault, which opposes what may be expected in siliciclastic and crystalline faults. Significant heterogeneity in the fault rock types formed is likely to create variable permeability along fault-strike, potentially allowing across-fault fluid flow. However, areas with homogeneous fault rocks may generate barriers to fluid flow.

Numerical Simulation of Complex Fracture Network Development by Hydraulic Fracturing in Naturally Fractured Ultratight Formations

The creation of large complex fracture networks by hydraulic fracturing is imperative for enhanced oil recovery from tight sand or shale reservoirs, tight gas extraction, and hot-dry-rock (HDR) geothermal systems to improve the contact area to the rock matrix. Although conventional fracturing treatments may result in biwing fractures, there is evidence by microseismic mapping that fracture networks can develop in many unconventional reservoirs, especially when natural fracture systems are present and the differences between the principle stresses are low. However, not much insight is gained about fracture development as well as fluid and proppant transport in naturally fractured tight formations. In order to clarify the relationship between rock and treatment parameters, and resulting fracture properties, numerical simulations were performed using a commercial discrete fracture network (DFN) simulator. A comprehensive sensitivity analysis is presented to identify typical fracture network patterns resulting from massive water fracturing treatments in different geological conditions. It is shown how the treatment parameters influence the fracture development and what type of fracture patterns may result from different treatment designs. The focus of this study is on complex fracture network development in different natural fracture systems. Additionally, the applicability of the DFN simulator for modeling shale gas stimulation and HDR stimulation is critically discussed. The approach stated above gives an insight into the relationships between rock properties (specifically matrix properties and characteristics of natural fracture systems) and the properties of developed fracture networks. Various simulated scenarios show typical conditions under which different complex fracture patterns can develop and prescribe efficient treatment designs to generate these fracture systems. Hydraulic stimulation is essential for the production of oil, gas, or heat from ultratight formations like shales and basement rocks (mainly granite). If natural fracture systems are present, the fracturing process becomes more complex to simulate. Our simulations suggest that stress state, in situ fracture networks, and fluid type are the main parameters influencing hydraulic fracture network development. Major factors leading to more complex fracture networks are an extensive pre-existing natural fracture network, small fracture spacings, low differences between the principle stresses, well contained formations, high tensile strength, high Young’s modulus, low viscosity fracturing fluid, and large fluid volumes. The differences between 5 km deep granitic HDR and 2.5 km deep shale gas stimulations are the following: (1) the reservoir temperature in granites is higher, (2) the pressures and stresses in granites are higher, (3) surface treatment pressures in granites are higher, (4) the fluid leak-off in granites is less, and (5) the mechanical parameters tensile strength and Young’s modulus of granites are usually higher than those of shales.

Determination of Geometrical and Structural Representative Volume Elements at the Baihetan Dam Site

A case study at the Baihetan dam site was undertaken to obtain a representative volume element (RVE) size. Two-dimensional fracture information in an exploration tunnel was used to generate a large three-dimensional fracture network. By dividing the entire modeled rock mass into cubes, the volumetric fracture density (P32) value of each cube was determined. The size effect can be determined by changing the cube size. The RVE was determined using P32 calculation and statistical tests, including Kolmogorov-Smirnov (KS) and Wilcoxon rank-sum tests. The P32 value depends on the geometrical parameters of fracture density and size; in this study, this value is called the geometrical RVE. P32 is dependent on fracture density and size, and cannot appropriately reflect certain data such as fracture dip or dip angle. Therefore, we propose a structural RVE (SRVE) considering fracture dip direction, dip angle, density, and size, which together constitute the available information about the fracture network. Therefore, the SRVE is more applicable for use in solving geological problems than the RVE. In this analysis, the KS and Wilcoxon rank-sum tests were used to determine the SRVE size.

Numerical Simulation of Shale Gas Production

Shale gas reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. The application of microseismic fracture mapping measurements requires estimation of the structure of the complex hydraulic fracture or the volume of the reservoir that has been stimulated by the fracture treatment. There are three primary approaches used to incorporate microseismic measurements into reservoir simulation models: discrete modeling of the complex fracture network, wire-mesh model, and dual porosity model. This paper discuss the different simulation model, the results provided insights into effective stimulation designs and flow mechanism for shale gas reservoirs.

Recognition of Fracturing by Stimulated Reservoir Volume (SRV) in Shale Gas Wells

Ultra-low permeability shale reservoir require a large fracture network to maximal well performance. In conventional reservoirs and tight gas sands, single fracture length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex fracture network are created, single fracture length and conductivity are insufficient to stimulate. This is the reason for the concept of using stimulated reservoir volume as a correlation parameter for well performance. This paper mainly illustrates perforation with interlaced row well pattern and multi-fracture fracturing technology and refracturing applied in vertical wells. Moreover, it establishes the seepage differential equation of multi-fracture.

The Relationship Between Fracture Complexity, Reservoir Properties, and Fracture-Treatment Design

Summary In many reservoirs, fracture growth may be complex because of the interaction of the hydraulic fracture with natural fractures, fissures, and other geologic heterogeneities. The decision whether to control or exploit fracture complexity has significant impact on fracture design and well performance. This paper investigates fracture-treatment-design issues as they relate to various degrees and types of fracture complexity (i.e., complex planar fractures and network fracture behavior), focusing on fracture-conductivity requirements for complex fractures. The paper includes general guidelines for treatment design when fracture growth is complex, including criteria for the application of water-fracs, hybrid fracs, and crosslinked fluids. The effect of proppant distribution on gas-well performance is examined for cases when fracture growth is complex, assuming that proppant was either concentrated in a primary planar fracture or evenly distributed in a fracture network. Examples are presented that show that when fracture growth is complex, the average proppant concentration will likely be too low to materially impact well performance if proppant is evenly distributed in the fracture network and unpropped-fracture conductivity will control gas production. Reservoir simulations illustrate that the network-fracture conductivity required to maximize production is proportional to the square root of fracture spacing, indicating that increasing fracture complexity will reduce conductivity requirements. The reservoir simulations show that fracture-conductivity requirements are proportional k1/2 for small networks and k1/4 for large networks, indicating much higher conductivity requirements for low-permeability reservoirs than would be predicted using classical dimensionless conductivity calculations (FCD) where conductivity requirements are proportionate to reservoir permeability (k). The results show that when fracture growth is complex, proppant distribution will have a significant impact on network-conductivity requirement and well performance. If an infinite-conductivity primary fracture can be created, network-fracture-conductivity requirements are reduced by a factor of 10 to 100, depending on the size of the network. The decision to exploit or control fracture complexity depends on reservoir permeability, the degree of fracture complexity, and unpropped-fracture conductivity. It can be beneficial to exploit fracture complexity when the permeability is on the order of 0.0001 md by generating large fracture networks using low-viscosity fluids (water fracs). As reservoir permeability approaches 0.01 md, fluid efficiency decreases, and fracture-conductivity requirements increase, fracture designs can be tailored to generate small networks with improved conductivity using medium-viscosity or multiple fluids (hybrid fracs). Fracture complexity should be controlled using high-viscosity fluids, and fracture conductivity should be optimized for moderate-permeability reservoirs, on the order of 1 md.

A parallel multigrid preconditioner for the simulation of large fracture networks

Computational modeling of a fracture in disordered materials using discrete lattice modelsrequires the solution of a linear system of equations every time a new lattice bond isbroken. Solving these linear systems of equations successively is the most expensive part offracture simulations using large three-dimensional networks. In this paper, wepresent a parallel multigrid preconditioned conjugate gradient algorithm to solvethese linear systems. Numerical experiments demonstrate that this algorithmperforms significantly better than the algorithms previously used to solve thisproblem.

What Is Stimulated Reservoir Volume?

Summary Ultralow-permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane-fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concepts of single-fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume (SRV) as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3D volume (stimulated reservoir volume) of the microseismic-event cloud. This paper briefly illustrates how the SRV can be estimated from microseismic-mapping data and is then related to total injected-fluid volume and well performance. While the effectively producing network could be smaller by some proportion, it is assumed that the created and the effective network are directly related. However, SRV is not the only driver of well performance. Fracture spacing and conductivity within a given SRV are just as important, and this paper illustrates how both SRV and fracture spacing for a given conductivity can affect production acceleration and ultimate recovery. The effect of fracture conductivity is discussed separately in a series of companion papers. Simulated-production data are then compared with actual field results to demonstrate variability in well performance and how this concept can be used to improve completion design, well spacing, and placement strategies.

Imaging Hydraulic-Fracture-Induced Seismic Deformation

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 102801, "Imaging Seismic Deformation Induced by Hydraulic-Fracture Complexity," by S.C. Maxwell, SPE, C.K. Waltman, SPE, N.R. Warpinski, SPE, M.J. Mayerhofer, SPE, and N. Boroumand, Pinnacle Technologies, prepared for the 2006 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 24– 27 September. Microseismic mapping is used extensively in the Barnett shale to map hydraulic-fracture complexity associated with interactions of the stimulation with pre-existing fractures. Previous studies have indicated a fair correlation between well performance and extent of the seismically active volume. In the full-length paper, the density of the total seismic moment release is used as an indication of the seismic deformation that may correlate to fracture density. Incorporating seismic-moment density with stimulated reservoir volume (SRV) improved correlation with well production. Introduction Microseismic mapping of hydraulic-fracture stimulations has become a common technique used to map fracture growth and geometry. Microseismic images provide details of fracture azimuth, height, length, and complexity resulting from interaction with pre-existing fractures. The resulting images can be used to calibrate numerical simulations of fracture growth, allowing more-confident modeling of other stimulations in the field and identification of the stimulated region that may be drained by the well. Microseismic mapping in the Barnett shale has demonstrated repeatedly extreme fracture complexity resulting from interaction between the injection and a pre-existing fracture network. The Barnett shale has very low intrinsic matrix permeability, and the permeability enhancement associated with the fracture stimulation results in permeable fracture networks sufficient for economic gas recovery. Previous studies have shown a correlation between the SRV, as measured by the volume of the reservoir that emits microseisms during the stimulation, and the production ultimately realized from the well. The correlation is attributed to larger fracture networks being stimulated in wells where a large microseismically active volume of the reservoir has been realized, resulting in more permeable fracture pathways connected to the well and hence a higher potential for gas flow to the well. Recently, many operators in the Barnett shale have attempted horizontal completions, which have enabled large volumes of the reservoir to be stimulated with large fracture networks. Many of these completions use perforated, cemented liners, and the microseismic images allow identification of improved perforation staging to maximize the SRV. Beyond the basic hypocentral locations of the microseisms used to calculate the SRV, additional seismic-signal characteristics allow investigation of the source of the mechanical deformation resulting in the microseisms. In particular, the seismic moment, a robust measure of the strength of an earthquake or microearthquake, can be used to quantify the seismic deformation.

Analysis of fluid flow and solute transport through a single fracture with variable apertures intersecting a canister: Comparison between fractal and Gaussian fractures

Canisters with spent nuclear fuel will be deposited in fractured crystalline rock in the Swedish concept for a final repository. The fractures intersect the canister holes at different angles and they have variable apertures and therefore locally varying flowrates. Our previous model with fractures with a constant aperture and a 90° intersection angle is now extended to arbitrary intersection angles and stochastically variable apertures. It is shown that the previous basic model can be simply amended to account for these effects. More importantly, it has been found that the distributions of the volumetric and the equivalent flow rates are all close to the Normal for both fractal and Gaussian fractures, with the mean of the distribution of the volumetric flow rate being determined solely by the hydraulic aperture, and that of the equivalent flow rate being determined by the mechanical aperture. Moreover, the standard deviation of the volumetric flow rates of the many realizations increases with increasing roughness and spatial correlation length of the aperture field, and so does that of the equivalent flow rates. Thus, two simple statistical relations can be developed to describe the stochastic properties of fluid flow and solute transport through a single fracture with spatially variable apertures. This obviates, then, the need to simulate each fracture that intersects a canister in great detail, and allows the use of complex fractures also in very large fracture network models used in performance assessment.

Effective constitutive properties for dense nonaqueous phase liquid (DNAPL) migration in large fracture networks: A computational study

Large‐scale capillary pressure [] and effective permeability‐saturation [knw] constitutive relationships for an incompressible, two‐phase system have been developed for a two‐dimensional, nonorthogonal fracture network utilizing numerical simulation. The simulations account for capillary, viscous, and gravity effects consistent with the Darcian approach adopted for this study, and were performed within the scale of the REV of the system which was consistent for both single and multiphase flow behavior. The large‐scale relationship for steady state flow conditions was found to be sensitive to the mean and the variance of the underlying aperture distribution as well as the nonwetting phase density. The overall effects of varying the aperture statistics on the relationships were found to be analogous to porous media, with an increased mean aperture leading to lower capillary pressures and an increased aperture variance leading to steeper curves. The large‐scale knw curves representative of flow in the vertical direction followed the general form of the underlying local‐scale Brooks‐Corey constitutive relationship and were relatively insensitive to a change in variance of the aperture distribution. The large‐scale knw curves representing flow in the horizontal direction due to an imposed gradient in the vertical direction, however, are significantly different than the underlying local‐scale relationships, showing maximum values at intermediate saturations. The ratio of vertical to horizontal effective permeability is saturation dependent.

Hydraulic Characterization of Fractured Reservoirs: Simulation on Discrete Fracture Models

SummaryAdvanced characterization methodology and software are now able to provide realistic pictures of fracture networks. However, these pictures must be validated against dynamic data like flow-meter, well-test, interference-test, or production data and calibrated in terms of hydraulic properties. This calibration and validation step is based on the simulation of those dynamic tests. What has to be overcome is the challenge of both accurately representing large and complex fracture networks and simulating matrix/fracture exchanges with a minimum number of gridblocks. This paper presents an efficient, patented solution to tackle this problem. First, a method derived from the well-known dual-porosity concept is presented. The approach consists of developing an optimized, explicit representation of the fractured medium and specific treatments of matrix/fracture exchanges and matrix/matrix flows. In this approach, matrix blocks of different volumes and shapes are associated with each fracture cell depending on the local geometry of the surrounding fractures. The matrix-block geometry is determined with a rapid image-processing algorithm. The great advantage of this approach is that it can simulate local matrix/fracture exchanges on large fractured media in a much faster and more appropriate way. Indeed, the simulation can be carried out with a much smaller number of cells compared to a fully explicit discretization of both matrix and fracture media. The proposed approach presents other advantages owing to its great flexibility. Indeed, it accurately handles the cases in which flows are not controlled by fractures alone; either the fracture network may be not hydraulically connected from one well to another, or the matrix may have a high permeability in some places. Finally, well-test cases demonstrate the reliability of the method and its range of application.