Complex Fracture Geometry Research Articles

Reservoir and Fracture-Flow Characterization Using Novel Diagnostic Plots

SummaryMultistage hydraulically fractured horizontal wells provide an effective means to exploit unconventional reservoirs. The current industry practice in the interpretation of field response often uses empirical decline-curve analysis or pressure-transient analysis/rate-transient analysis (PTA/RTA) for characterization of these reservoirs and fractures. These analytical tools depend on simplifying assumptions and do not provide a detailed description of the evolving reservoir-drainage volume accessed from a well. Understanding of the transient-drainage volume is essential for unconventional-reservoir and fracture assessment and optimization.In our previous study (Yang et al. 2015), we developed a “data-driven” methodology for the production rate and pressure analysis of shale-gas and shale-oil reservoirs. There are no underlying assumptions of fracture geometry, reservoir homogeneity, and flow regimes in the method proposed in our previous study. This approach depends on the high-frequency asymptotic solution of the diffusivity equation in heterogeneous reservoirs. It allows us to determine the well-drainage volume and the instantaneous recovery ratio (IRR), which is the ratio of the produced volume to the drainage volume, directly from the production data. In addition, a new w(τ) plot has been proposed to provide better insight into the depletion mechanisms and the fracture geometry. w(τ) is the derivative of pore volume with respect to τ.In this paper, we build upon our previous approach to propose a novel diagnostic tool for the interpretation of the characteristics of (potentially) complex fracture systems and drainage volume. We have used the w(τ) and IRR plots for the identification of characteristic signatures that imply complex fracture geometry, formation linear flow, partial reservoir completions, and fracture-interference/compaction effects during production. The w(τ) analysis gives us the fracture surface area and formation diffusivity, while the IRR analysis provides additional information on fracture conductivity. In addition, quantitative analysis is conducted using the novel w(τ) plot to interpret fracture-interference time, formation permeability, total fracture surface area, and stimulated reservoir volume (SRV).The major advantages of this current approach are the model-free analysis without assuming planar fractures, homogeneous formation properties, and specific flow regimes. In addition, the w(τ) plot captures high-resolution flow patterns not observed in traditional PTA/RTA analysis. The analysis leads to a simple and intuitive understanding of the transient-drainage volume and fracture conductivity. The results of the analysis are useful for hydraulic-fracturing-design optimization and matrix- and fracture-parameter estimation.

Semianalytical Solution for Modeling the Performance of Complex Multifractured Horizontal Wells in Unconventional Reservoirs

Summary Analytical models have evolved in their capacity to represent the transient response of multifractured horizontal wells producing from unconventional reservoirs. However, as is common with analytical solutions, they are based on simplified reservoir/well geometries and flow-pattern assumptions that inherently restrict their scope of application. Their use for analyzing flow scenarios that transcend their scope is thus prone to errors. This paper documents a semianalytical model that overcomes the aforementioned limitations, and thereby expands analysis to the realm of reservoir/well architectures that are inaccessible to analytical models. Our solution is based on the Laplace-transform boundary-element-method (BEM) implementation of the Green's function solution of the diffusivity equation. We represent the reservoir as a 2D composite system, with the outer boundaries and the interface between reservoir regions discretized appropriately. With the collocation procedure, the solution is distilled to a system of algebraic equations that is solved for the reservoir's transient response. The hydraulic fractures need not be regular (equidistant and/or isometric), as is required by most analytical models; instead, they can traverse arbitrary spatial orientations and dimensions with respect to the horizontal well. We demonstrate the application of our solution by modeling multifractured-horizontal-well performance with two verification cases and three synthetic examples. The first example showcases a multifractured horizontal well traversed by identical, evenly spaced, fully penetrating, vertical hydraulic fractures within a stimulated reservoir volume (SRV). The second example models an enhanced-permeability region local to each hydraulic fracture as opposed to a single SRV housing all the fractures. The last example typifies complex fracture geometries, where the fractures have different half-lengths, spacings, and orientations. Besides showing that all the verification and example cases are in excellent agreement with numerical solution, we demonstrate the utility of our solution for modeling variable-rate flow commonly observed in practical field-production scenarios, showing its potential for history matching and forecasting the performance of multifractured horizontal wells.

A semi-analytical model for simulation of fluid flow in tight rock with irregular fracture geometry

Numerous micro-seismic and laboratorial studies show that hydraulic fracture is usually with complex geometries, such as plugged fracture, asymmetry and non-plane. It is a challenging task to recognize the complex fracture and obtain reliable fracture parameters through transient pressure analysis. In this work, we extend the semi-analytical model by Zhou et al. (2013) to analyze transient pressure behavior of a fractured vertical well with complex fracture geometries. We verified the semi-analytical model by a numerical reservoir simulator on a planar fracture. Then, based on this model, we made a systematical discussion about the transient pressure behavior of the planar fracture with varying conductivity, asymmetric fracture and non-planar fracture. Results show that when the fracture conductivity is varying along the fracture path, the influence of fracture zone conductivity on the transient pressure behavior gradually decreases with the distance from the wellbore growing. Besides, we found that the fracture asymmetry is against for the fluid flow in the fracture, and it decreases the slope of transient pressure behavior curve and enlarge pressure drop. In addition, the non-planar fracture is usually with severe fracture width restriction around the wellbore, which will induce pseudo-radial flow in the fracture at early times and large pressure drop in the fracture. Furthermore, the influences of varying conductivity, fracture asymmetry and non-plane on transient pressure behavior are obvious for fracture with average small-to-middle conductivity (average dimensionless fracture conductivity ranging from 0.1 to 50); the influences become negotiable for fracture with average high-to-infinite conductivity (average dimensionless fracture conductivity ranging from 50 to 1000). This work can provide critical insights into understanding the effect of complex fracture geometry on transient pressure behavior of fractured vertical well in tight oil reservoir.

A multiscale model for methane transport mechanisms in shale gas reservoirs

We presented an efficient semi-analytical model-based analysis of methane transport in shale reservoirs including multiple horizontal wells with nanopores and complex hydraulic fractures. Multiple important gas transport mechanisms in nanopores such as gas desorption, gas slippage and diffusion and pressure-dependent fracture conductivity are fully incorporated in the model. Both simple and complex fractures in multiple shale-gas wells can be easily and effectively dealt with in accordance with the discretization approach, which does not require detailed gridding like numerical model. The superposition principle is utilized to capture the interactions between all fracture segments in order to accurately simulate real gas transport from matrix to fractures and finally from fractures to wellbores. We verified the semi-analytical model against a numerical compositional reservoir model for two shale-gas wells with multiple simple planar hydraulic fractures considering the gas desorption effect. The semi-analytical model was used to analyze ultimate gas recovery of different complex hydraulic fracture patterns in a two-well scenario, which were generated from a complex fracture propagation model with and without considering natural fractures. In addition, it was applied to perform field-scale simulation with multiple wells and complex fracture geometries in accordance with microseismic data. The simulation results show that multiple gas transport mechanisms, pressure-dependent fracture conductivity and complex fracture geometries play an important role in controlling well productivity and gas recovery, which should be properly accounted for in the physical model in order to achieve more accurate long-term production forecasting of multiple-fractured shale-gas horizontal wells.

A Practical Methodology for Production-Data Analysis of Single-Phase Unconventional Wells With Complex Fracture Geometry

Summary Forecasting coalbed-methane well performance in the Qinshui Basin is a key task for predicting future gas production. There is evidence suggesting that complex fracture geometry and multiple hydraulic-fracture networks might develop. Unfortunately, very limited work has been published on the production analysis of multiple-fractured vertical wells (MFVWs) in coalbed-methane reservoirs. To better understand the production performance of the MFVWs, a new, fast, and reliable methodology is presented in this paper. This semianalytical methodology is derived from an analytical reservoir solution and a numerical fracture solution. Dual-porosity, gas-diffusion, gas-adsorption, and stress-sensitivity effects are considered. Verification of the methodology is accomplished through comparison with synthetic-reservoir-simulation cases and with field-performance data. Good agreement is shown between results from the proposed methodology and those from a reservoir-simulation model. Results from this study indicate increasing transient-gas-production rate and cumulative gas recovery with increasing natural-fracture permeability, gas-storage coefficient, Langmuir volume, fracture conductivity, and fracture length. The transient gas-production rate and cumulative gas recovery were found to decrease with increasing stress-sensitivity coefficient. The parameters found to have the strongest and weakest effects on the gas-production rate were the natural-fracture permeability and the fracture conductivity, respectively. Results from this study on MFVWs in coalbed-methane reservoirs indicate fracture length is more important than fracture conductivity in terms of its effect on gas productivity.

Semi-analytical simulation of transient flow behavior for complex fracture network with stress-sensitive conductivity

The main object of this paper is to establish a benchmark model to investigate the transient flow behavior for complex fracture network with stress-sensitive conductivity. An associated semi-analytical solution is proposed by coupling reservoir-fracture flow model and incorporating stress sensitivity of fracture conductivity into coupled model, with sufficient flexibility to account for complex fracture geometry and stress sensitivity. A dimension transformation with multiple source terms is fully developed and extended to the case of complex fracture network, which renders the resulting nonlinear equations fully amenable to the linear treatment. An accurate, closed form iterative algorithm is subsequently provided and verified against numerical reservoir simulator. A set of synthetic simulations is utilized to investigate the physics of transient flow behavior and capture the interaction between fracture-production interference and conductivity decay by performing pressure transient analysis. The results show that the pressure response transitions from the initial condition (constant initial-conductivity) to the limited condition (constant minimum-conductivity) because of the loss of stress-sensitive conductivity, displaying a gradual increasing in the pressure drop. The magnitude of extra pressure drop is dependent on the complexity nature and conductivity decay of fracture network. In the condition of high flow resistance (i.e. low initial conductivity, small area connected to the reservoir), it is of great significance to take the effect of stress sensitivity into account to obtain correct simulation of transient pressure response. The findings in this paper could improve the understanding of flow mechanisms and facilitate the analysis of transient pressure/rate data for complex fracture network with stress-sensitive conductivity.

Investigation of Cyclic $$\text {CO}_{2}$$ CO 2 Injection Process with Nanopore Confinement and Complex Fracturing Geometry in Tight Oil Reservoirs

Carbon dioxide is one of the capable processes in improving oil recovery from low-permeable oil reservoirs. However, the evaluation of cyclic $$\text {CO}_{2}$$ injection process with nanopore confinement effect in tight reservoirs is deficient in the oil industry. The nanopores confinement plays a significant role in low-permeable formations, creating a high capillary pressure which substantially influences fluid phase behavior and fluid flow in tight reservoirs. In order to consider the effect of nanopore confinement in unconventional reservoirs, the conventional methods need to be modified. Thus, we evolve an effective model for cyclic $$\text {CO}_{2}$$ injection process considering the effect of complex fracture geometry with nanopore confinement on the production from tight formations. Firstly, the reservoir fluid properties with nanopore confinement are estimated. Secondly, the minimum miscibility pressure is measured and verified with experimental data. Lastly, the well performance of cyclic $$\text {CO}_{2}$$ injection process in unconventional tight reservoirs is evaluated based on few parameters such as $$\text {CO}_{2}$$ diffusivity and matrix permeability. The results show that the combined effect of capillary pressure and $$\text {CO}_{2}$$ dispersion has significantly influenced the oil production efficiency from tight oil reservoirs. The oil recovery factor of cyclic $$\text {CO}_{2}$$ injection process at five years boosts from 14.67% as primary recovery to 22.54% due to $$\text {CO}_{2}$$ molecular diffusion effect with overall 7.87% incremental recovery. Moreover, the incremental oil recovery of cyclic $$\text {CO}_{2}$$ injection process is increased further by 1.7% while taking into consideration the combine effect of capillary pressure and $$\text {CO}_{2}$$ diffusion on the oil recovery. This study provides an appropriate method for predicting the production of cyclic $$\text {CO}_{2}$$ injection process with a complex fracture geometry, considering the capillary pressure and $$\text {CO}_{2}$$ diffusion on well performance of tight oil reservoirs.

A 3-D model for simulation of weak interface slippage for fracture height containment in shale reservoirs

Shale formations often consist of multiple distinct layers with varying rock properties, in-situ stress states, and interface properties between layers. Weak horizontal interfaces often affect fracture height growth and induced complex fracture geometry. In this paper, a fully three-dimensional displacement discontinuity method is developed to investigate slippage of weak horizontal interfaces and understand the effects of the slippage on fracture height growth. Horizontal fracture segments are regarded as weak horizontal interfaces and vertical fractures would either be arrested or step over interfaces. Results indicate that a width jump of the vertical fracture occurs at the crossing position of the horizontal interface, as a result of shear displacement discontinuities along the horizontal fracture segment. The width jump hinders the vertical fracture growth in the height direction, which is regarded as a new mechanism of fracture height containment. Shear displacement discontinuities and width jump increase with the increment of the distance between the center of the vertical fracture and horizontal fracture segment. The larger the width jump, the more difficult the vertical fracture continues to propagate in the height direction, which implies that the vertical fracture tends to be arrested by the interface when the wellbore is far away from the interface.

Hydraulic fracturing initiation and near-wellbore nonplanar propagation from horizontal perforated boreholes in tight formation

Tight formations, which are rich in reserves in China, have a high economic development value. Perforated fracturing would need to be used widely to exploit these formations because of reservoir characteristics such as low permeability, low porosity and high density, resulting in high fracture pressure, limited fracture propagation, and complex fracture geometry. To address these issues, the mechanism of fracture propagation under different construction conditions must be understood and described. Therefore, the effect of different perforation parameters (shot density, shot length, shot diameter, shot phase, and shot interval spacing) and different horizontal stress contrasts on fracture geometry, initiation, and propagation from perforated horizontal wells in tight formations is studied based on numerous triaxial hydraulic fracturing simulation experiments. Three types of fracture geometry are observed in these experiments: A single flat fracture can be created by an initiated perforation or more initiated perforations with good connectivity, spiral-shaped fractures are generated by a large perforation diameter or high perforation density, and multiple-parallel fractures are induced by a high perforation phase. Moreover, each fracture type has certain pressure behaviors corresponding to a fracture curve shape. The perforations are likely to initiate when the angle between the perforation and maximum horizontal stress is small, and the initiation position is most likely at the base of the perforation. It is difficult to predict the initiation order of perforations; however, the first initiated perforation can be ensured by the profile of the relief pressure. In addition, a higher horizontal stress contrast value results in more initiated perforations, lower fracture pressure, and shorter breakage time. Ultimately, a large perforation diameter, high perforation density, and perforation phase of 60° should be chosen for fracturing at low fracture pressure and simple fracture geometry in tight formations.

A Comprehensive Model for Investigation of Carbon Dioxide Enhanced Oil Recovery With Nanopore Confinement in the Bakken Tight Oil Reservoir

Summary Carbon dioxide (CO2) injection is an effective enhanced-oil-recovery (EOR) method in unconventional oil reservoirs. However, investigation of the CO2 huff ’n’ puff process in tight oil reservoirs with nanopore confinement is lacking in the petroleum industry. The conventional models need to be modified to consider nanopore confinement in both phase equilibrium and fluid transport. Hence, we develop an efficient model to fill this gap and apply to the field production of the Bakken tight oil reservoir. Complex-fracture geometries are also handled in this model. First, we revised the phase equilibrium calculation and evaluated the fluid properties with nanopore confinement. An excellent agreement between this proposed model and the experimental data is obtained considering nanopore confinement. Afterward, we verified the calculated minimum miscibility pressure (MMP) using this model against the experimental data from a rising-bubble apparatus (RBA). We analyzed the MMP and well performance of CO2 EOR in the Bakken tight oil reservoir. On the basis of the prediction of the field data, the MMP is 450 psi lower than the MMP with bulk fluid when the pore size reduces to 10 nm. Subsequently, we examined the effects of key parameters such as matrix permeability and CO2 molecular diffusion on the CO2 huff ’n’ puff process. Results show that both CO2-diffusion and capillary pressure effects improve the oil recovery factor from tight oil reservoirs, which should be correctly implemented in the simulation model. Finally, we analyzed well performance of a field-scale horizontal well from the Bakken Formation with nonplanar fractures and natural fractures. Contributions of CO2-diffusion and capillary pressure effects are also examined in depth in field scale with complex-fracture geometries. The oil recovery factor of the CO2 huff ’n’ puff process with both CO2-diffusion and capillary pressure effects increases by as much as 5.1% in the 20-year period compared with the case without these factors. This work efficiently analyzes the CO2 huff ’n’ puff process with complex-fracture geometries considering CO2 diffusion and nanopore confinement in the field production from the Bakken tight oil reservoir. This model can provide a strong basis for accurately predicting the long-term production with complex-fracture geometries in tight oil reservoirs.

Numerical investigation of effect of natural fractures on hydraulic-fracture propagation in unconventional reservoirs

Field observations show that natural fractures are commonly presented in unconventional reservoirs, acting as planes of weakness that divert hydraulic fracture propagation and generate complex fracture geometry. We systematically investigated the impacts of natural fractures on net injection pressure, fracture geometry, fluid volume distribution, and induced stresses using a complex fracture propagation model. The model fully couples rock deformation and fluid flow in the fractures, perforations, and the wellbore. A simplified three-dimensional displacement discontinuity method is used to calculate multiple fracture interaction within stages as well as between stages and wells. Fluid volume distribution between each fracture is automatically calculated during pumping based on fluid resistance. The simulation results show that when a hydraulic fracture diverts into a natural fracture, the net injection pressure is elevated, resulting in width enlargement of the fracture segment before the natural fracture and reduction of total fracture length. Much less fluid flows into the fracture wing that diverts into the natural fracture. Due to a larger compressional stress exerting on the natural fracture, fracture width of the fracture segment on the natural fracture is restricted, which significantly affects proppant transport and distribution. Additionally, differential stress, approach angle, length of natural fractures, and relative position of natural fractures are critical parameters affecting elevation of net injection pressure as well as fracture width enlargement and restriction before and on natural fractures. As differential stress and approach angle increase, higher net injection pressure is required, shorter fracture length is created, and width enlargement and restriction before and on natural fractures are more severe. Deviation of fracture propagation from the original path is greatly affected by the length of natural fractures. The larger the natural fracture, the more deviation from the original path. This study highlights the behaviors of a hydraulic fracture diverting into a natural fracture and the final fracture geometry.

Investigation of Production-Induced Stress Changes for Infill-Well Stimulation in Eagle Ford Shale

Summary Heterogeneous stress has a great effect on fracture propagation and perforation-cluster efficiency of infill wells. Principal-stress reorientation induced by depletion of parent wells has been investigated by previous numerical studies assuming uniform biwing fracture geometry along the horizontal wells. However, recent field diagnostics indicate that fractures along the horizontal wells are generally nonuniformly developed. In this study, we investigated the impact of depletion of parent wells with complex fracture geometry on stress states, and analyzed stimulation efficiency of infill wells by using an in-house reservoir geomechanical model for Eagle Ford Shale. The model fully couples multiphase flow and rock deformation in three dimensions based on the finite-element method, incorporating complex fracture geometry and heterogeneity. We used this model to accurately characterize pressure distribution and to update stress states through history matching production data of parent wells in Eagle Ford Shale. Depletion of parent wells with nonuniform fracture geometries, which has not been researched thoroughly in the literature, is incorporated in the study. Results show that magnitude and orientation of principal stresses are greatly altered by depletion, and the alteration is uneven because of nonuniform fracture geometries. Stress reversal monitored at the center of the infill location starts after 1 year of production, and it takes another 8 months to be totally reversed for 90°. We also performed sensitivity studies to examine effects of parameters on changes of magnitude and orientation of stress at the infill location, and found that effects of bottomhole pressure (BHP), differential stress (DS), and fracture geometry of parent wells are all significant, whereas effects of the reservoir elastic property are limited. Effects of production time of parent wells are also noticeable in all sensitivity studies. This work analyzes stress-state change induced by depletion of parent wells in Eagle Ford Shale, and provides critical insights into the optimization for stimulation of infill wells.

An analytical model for fracture initiation from radial lateral borehole

Radial drilling-fracturing, the integration of radial drilling and hydraulic fracturing, is an innovative approach to develop low permeability, thin target layer and naturally fractured reservoirs, etc. Understanding the fracture initiation process is required in the practical application to avoid high fracture initiation pressure (FIP) and complex fracture geometries near the wellbore. In this paper, we develop an analytical model to determine FIP, location of rock failure zones and initial fracture direction from the radial lateral borehole. This model is based on the stress superposition induced by cased main wellbore and radial borehole, and the maximum tensile stress criterion is adopted. Then, we perform a series of sensitivity analysis by examining different effects of in-situ stress regime, lateral orientation (the included angle between borehole axis and maximum horizontal in-situ stress), lateral length, and lateral diameter. Besides, the effect of pre-existing weakness plane, across which the tensile strength is much lower than that of the intact rock, is also investigated, when the plane is drilled through by the radial borehole. Results show that for intact rock with no weakness plane, the in-situ stress regime and lateral orientation are main factors influencing FIP, location of rock failure zones, and initial fracture direction. Under the in-situ stress regime of normal fault, fracture initiates vertically, and FIP enlarges as lateral orientation increasing; under the in-situ stress regime of strike slip, fracture initiates vertically with small lateral orientation, while fracture initiates horizontally with large lateral orientation; and under the in-situ stress regime of reverse fault, fracture initiates horizontally with any lateral orientation, and FIP decreases as the lateral orientation increasing. It is also found that when the fracture initiates vertically, the location of rock failure zones is at the base of radial borehole on its top and bottom sides; and when the fracture initiates horizontally, the location of rock failure zone is at the remote region of radial borehole on its right and left sides. The lateral length has a minor effect on fracture initiation, and the influence of lateral diameter is negligible. When the weakness plane is drilled through by the radial borehole, fracture initiation pressure from weakness plane is affected by its occurrence, i.e., azimuth and inclination. FIP is determined by taking the minimum between fracture initiation pressure from rock matrix and the weakness plane. The key findings of this work could provide critical insights into understanding radial drilling-fracturing initiation characteristics.

3D observations of the hydraulic fracturing process for a model non-cemented horizontal well under true triaxial conditions using an X-ray CT imaging technique

To investigate the spatial evolution of fractures in non-cemented horizontal wells, cubic cement specimens were fractured in triaxial experiments to reproduce hydraulic fracturing in field applications. Systematic experiments were conducted on specimens with different azimuth angles (0°, 30°, 45°, 60° and 90°), horizontal principal stress anisotropies (10 MPa and 4 MPa) and fracturing fluid viscosities (60 mPa·s and 5 mPa·s). All the tests were performed by injecting fluid at a constant rate of 9 cc/min. High-resolution non-destructive 3D X-ray microtomography was used to record the internal evolution of the induced fractures. The X-ray computed tomography (CT) imaging technique can produce complex 3D images of fracture systems with little artificial noise. The complex fracture geometries observed are a result of the rapidly changing stress conditions at the wellbore wall during injection and of the mechanical interaction among the fractures. The magnitudes of the well azimuth angle, principal stress anisotropy and injection fluid viscosity play significant roles in the evolution of the induced fractures. For a high horizontal differential stress of 10 MPa, the fracture morphologies are primarily determined by the in situ stresses, and the fractures extend in the direction of the maximum principal stress. However, when the horizontal differential stress is 4 MPa, the fracture geometry is influenced by the combined effects of the induced stress from the open-hole wellbore, fracture internal pressure distribution, far-field stresses and azimuth angle. In general, an induced fracture is planar at both a low (0°) and high (90°) azimuth angles, while twisted fractures form at intermediate azimuth angles (30°, 45° and 60°). In addition, the injection fluid with a low viscosity of 5 mPa·s easily infiltrates the formation, inducing a fracture network, in contrast to the smooth fracture plane induced by the injection fluid with a high viscosity of 60 mPa·s. Finally, we propose a new parameter, called the dimensionless net pressure, which can reflect the combined effects of the principal horizontal stress difference, well azimuth angle and injection fluid parameters on the evolution of the hydraulic fractures. The complexity of the fracture geometries is strongly and positively correlated with the dimensionless net pressure.

A General Boundary Integral Solution for Fluid Flow Analysis in Reservoirs With Complex Fracture Geometries

Modeling fractured reservoirs, especially those with complex, nonorthogonal fracture network, can prove to be a challenging task. This work proposes a general integral solution applicable to two-dimensional (2D) fluid flow analysis in fractured reservoirs that reduces the original 2D problem to equivalent integral equation problem written along boundary and fracture domains. The integral formulation is analytically derived from the governing partial differential equations written for the fluid flow problem in reservoirs with complex fracture geometries, and the solution is obtained via solving system of equations that combines contributions from both boundary and fracture domains. Compared to more generally used numerical simulation methods for discrete fracture modeling such as finite volume and finite element methods, this work only requires discretization along the boundary and fractures, resulting in much fewer discretized elements. The validity of proposed solution is verified using several case studies through comparison with available analytical solutions (for simplified, single-fracture cases) and finite difference/finite volume finely gridded numerical simulators (for multiple, complex, and nonorthogonal fracture network cases).

Numerical study of complex fracture geometry effect on two-phase performance of shale-gas wells using the fast EDFM method

Increase in energy demand has played a significant role in the persistent exploitation and exploration of unconventional oil and gas resources. Shale gas reservoirs are one of the major unconventional resources. Advancements in horizontal drilling and hydraulic fracturing techniques have been the key to achieve economic rates of production from these shale gas reservoirs. In addition to their ultra-low permeability, shale gas reservoirs are characterized by their complex gas transport mechanisms and complex natural and induced (hydraulic) fracture geometries. Production from shale gas reservoirs is predominantly composed of two-phase flow of gas and water. However, proper modeling of the two-phase behavior as well as incorporating the complex fracture geometries have been a challenge within the industry. Due to the limitation of local grid refinement approach, hydraulic fractures are assumed to be planar (orthogonal), which is an unrealistic assumption. Although more flexible approaches are available, such as the use of unstructured grids, they require significantly high computational resources. In this paper, we introduce an embedded discrete fracture model (EDFM) to explicitly model complex fracture geometries. The EDFM efficient approach is capable of explicitly modeling complex fracture geometries without increasing the computational demand. Utilizing EDFM alongside a commercial simulator, we constructed a 3D reservoir model to investigate the effect of complex fracture geometries on the two-phase flow of a shale gas well. In our investigation, varying degrees of hydraulic fracture complexity with 1-set and 2-set of natural fractures were tested. The simulation results confirm the importance of properly modeling fracture complexity, highlighting that it plays an integral part in the estimation of gas and water recoveries. In addition, the simulation results hint to the pronounced effect of fracture interference as fracture complexity increases. Finally, variable fracture conductivities and initial water saturation values were analyzed to further assess their effect on the two-phase production behavior of the shale gas well. This study examines the effect of non-orthogonal complex fracture geometry on the two-phase flow of shale gas wells. The work can provide a significant insight toward understanding the extent to which fracture complexity can affect the performance of shale gas wells.

Development of Efficiently Coupled Fluid-Flow/Geomechanics Model To Predict Stress Evolution in Unconventional Reservoirs With Complex-Fracture Geometry

Summary Stress changes associated with reservoir depletion are often observed in the field. Stress evolution within and surrounding drainage areas can greatly affect further reservoir developments, such as completion of infill wells and refracturing. Previous studies mainly focus on biwing planar-fracture geometry, which limits the possibility of investigating stress evolution caused by complex-fracture geometry. In this paper, we have developed a novel and efficient coupled fluid-flow/geomechanics model with an embedding-discrete-fracture model (EDFM) to characterize stress evolution associated with depletion in unconventional reservoirs with complex-fracture geometry. Coupled geomechanics/fluid flow was developed using the well-known fixed-stress-split method, which is unconditionally stable and computationally efficient to simulate how stress changes during reservoir depletion. EDFM was coupled to the model to gain capability of simulating complex-fracture geometries using structured grids. The model was validated against the classical Terzaghi (1925) and Mandel (1953) problems. Local grid refinement was used as a benchmark when comparing results from EDFM for fractures with 0 and 45° angles of inclination. After that, the model was used to analyze stress distribution and reorientation in reservoirs with three different fracture geometries: planar-fracture (90° angle of inclination), 60° inclination, and nonplanar-fracture geometries. As the pressure decreases, reservoir stresses tend to change anisotropically depending on depletion area. The principal stress parallel to the initial fracture reduces faster than the orthogonal one as a function of time. The decrease rate of principal stresses is distinct for different shapes of depleted areas created by different fracture geometries. The rectangular shape produced by the planar-fracture geometry yields the largest stress-reorientation area for a variety of differential-stress (DS) values (difference between two horizontal principal stresses). The squared shape produced by nonplanar-fracture geometry yields stress reorientation only for low DS. The results indicate that created fracture geometry has a significant effect on stress distribution and reorientation induced by depletion. To the best of our knowledge, this is the first time a coupled fluid-flow/geomechanics model incorporated with EDFM has been developed to efficiently calculate stress evolution in reservoirs with complex-fracture geometry. Characterization of stress evolution will provide critical guidelines for optimization of completion designs and further reservoir development.

Dual Virtual Element Method for Discrete Fractures Networks

The accurate description of fluid flow and transport in fractured porous media is of paramount importance to capture the macroscopic behaviour of an oil reservoir, a geothermal system, or a CO2 sequestration site, to name few applications. The construction of accurate simulation model for flow in fractures is challenging due to the high ratios between a fracture's length and width, which makes modeling by lower-dimensional manifolds a natural option. In this paper we present a mixed-dimensional Darcy problem able to describe pressure and Darcy velocity in all the dimensions, i.e. in the rock matrix, in the fractures, and in their intersections. Moreover, we present a mixed-dimensional transport problem which, given the Darcy velocity, describes coupled advection and diffusion of a passive scalar into the fractured porous media. The approach can handle both conducting and blocking fractures. Our computational grids are created by coarsening of simplex tessellations that conform to the fractures surfaces. An accurate choice of the discrete approximation of the previous model, by virtual finite element and finite volume, allows us to simulate complex problem with a good balance in term of accuracy and computational cost. We illustrate the performance of our method by comparing to benchmark studies for two-dimensional fractured porous media, as well as a complex three-dimensional fracture geometry.

Investigate effects of weak bedding interfaces on fracture geometry in unconventional reservoirs

Shale formations often consist of multiple weak interfaces between layers, which is easily opened during hydraulic fracturing treatment and affect growth of fracture height. Fracture propagation in such formations usually induced complex fracture geometry with primary vertical fractures and horizontal fracture segments between layers. Although numerous numerical models have been developed to simulate fracture propagation in unconventional reservoirs, relatively few physical three-dimensional models exist to quantitatively simulate opening of fractures affected by weak interfaces. In this paper, we analyze width profile of fractures and interaction of vertical and horizontal fracture segments with predetermined fracture path under the assumption of neglecting the flow effect.A fully three-dimensional displacement discontinuity method (3D DDM) is introduced to model multiple fractures in a stage in three dimensions. The fracture geometry is prescribed, which combined with vertical and horizontal fractures. In each case, the horizontal fracture is regarded as opening of the bedding interface and vertical fracture would either be arrested or directly cross the interface. Interfacial sliding distance, defined as width jump of the vertical fracture at the interface, is regarded as a primary impact of fracture height containment. Analysis of fracture opening, shear displacements and interfacial sliding distance is given for both vertical and horizontal fracture segments. When multiple vertical fractures intersect with a horizontal interface, shear displacements are induced on the interface and vertical fractures have smaller width compared with the case without the horizontal interface, as a result of the interaction with the interface. We observed that both widths of fracture segments and interfacial sliding distance are positively correlated with the distance between the center of the vertical fracture and the horizontal interface, half-length of horizontal fracture segment, the net pressure within fracture segments. Conversely, Young's Modulus has a negative relationship with both width of fracture segments and interfacial sliding distance. This paper analyzes the effects of opening of weak interfaces and provides critical insights of fracture width distribution and its impacts on proppant transport.

A Numerical Model for Simulating Pressure Response of Well Interference and Well Performance in Tight Oil Reservoirs With Complex–Fracture Geometries Using the Fast Embedded–Discrete–Fracture–Model Method

Summary The effect of well interference through fracture hits in shale reservoirs needs to be investigated because hydraulic fracturing is abundantly used in the development of unconventional oil and gas resources. Although numerous pressure tests have proved the existence of well interference, relatively few physical models exist to quantitatively simulate the pressure response of well interference. The objective of the present study is to develop a numerical compositional model in combination with a fast embedded-discrete-fracture-model (EDFM) method to simulate well interference. Through nonneighboring connections (NNCs), the fast EDFM method can easily and properly handle complex-fracture geometries, such as nonplanar hydraulic fractures and a large amount of natural fractures. Using public data for Eagle Ford tight oil, we build a reservoir model including up to three horizontal wells and five fluid pseudocomponents. The simulation results show that the connecting hydraulic fractures play a more-important role than natural fractures in declining bottomhole pressure (BHP) of the shut-in well. Matrix permeability has a relatively minor effect on pressure drawdown, and well productivity remains only slightly affected by the overall low permeability used. The BHP pressure-decline profiles change from convex to concave when the conductivity of the connecting fractures increases. At early times, the BHP of the shut-in well decreases when the number of natural fractures increases. At later times, the natural-fracture density has a lesser effect on the pressure response and no clear trend. The opening order of neighboring wells affects the well-interference intensity between the target shut-in well and the surrounding wells. After a systematic investigation of pressure drawdown in the reservoir, we formulate practical conclusions for improved production performance.