Complex Fracture Geometry Research Articles

A Novel Method to Enhance Oil Recovery by Inter-Fracture Injection and Production Through the Same Multi-Fractured Horizontal Well

Abstract Conventional enhanced oil recovery (EOR) approaches are inefficient in unconventional reservoirs. This paper provides a novel approach to enhance oil recovery from unconventional oil reservoirs through synchronous inter-fracture injection and production (SiFIP) and asynchronous inter-fracture injection and production (AiFIP). The compartmental embedded discrete fracture model (cEDFM) is introduced to simulate complex fracture geometries to quantitatively evaluate the performance of SiFIP and AiFIP. EOR performances using multiple producing methods are investigated (i.e., depletion, fluid flood, fluid Huff and Puff, SiFIP, and AiFIP). Higher cumulative oil production rates can be achieved by AiFIP and SiFIP. AiFIP yields the highest oil recovery factor, two times higher than depletion. Compared with SiFIP, AiFIP may be a preferred method when CO2/water resources are short. The impacts of fracture and injection parameters on oil production are discussed. The feasible well completions for AiFIP and SiFIP are provided. AiFIP (CO2) achieves the best EOR performance among different producing methods. This paper demonstrates the feasibility of SiFIP and AiFIP to improve oil recovery. The proposed methods improve flooding performance by transforming fluid injection among wells to among hydraulic fractures from the same multi-fractured horizontal well (MFHW), which is a promising EOR approach in unconventional oil reservoirs. The proposed EOR method (AiFIP-CO2) can improve oil recovery and mitigate the emission of CO2 as well as reduce the waste of water resources.

Radar imaging of fractures and voids behind the walls of an underground mine

Two- and three-dimensional rock-penetrating-radar data were acquired on the wall of a pillar in an underground limestone mine. The objective was to test the ability of radar to image fractures and karst voids and to characterize their geometry, aperture, and fluid content, with the goal of mitigating mining hazards. Strong radar reflections in the field data correlate with fractures and a cave exposed on the pillar walls. Large pillar wall topography was included in the steep-dip Kirchhoff migration algorithm because standard elevation corrections are inaccurate. The depth-migrated 250 MHz radar images illuminate fractures, karst voids, and the far wall of the pillar up to approximately 25 m depth into the rock, with a spatial resolution of <0.5 m. Higher frequency radar improved the image resolution and aided in the interpretation, but at the cost of shallower depth of penetration and extra acquisition effort. Due to the strong contrast in physical properties between the rock and the fracture fluid, fractures with apertures as thin as a 50th of a radar wavelength were imaged. Water-filled fractures with mm-scale aperture and air-filled fractures with cm-scale apertures produce strong reflections at 250 MHz. A strong variation in the reflection amplitude along each fracture is interpreted to represent the variable fracture aperture and the nonplanar fracture structure. Fracture apertures were quantitatively measured, but distinguishing water from air-filled fractures was not possible due to the complex radar wavelet and fracture geometry. Two conjugate fracture sets were imaged. One of these fracture sets dominates the rock mass stability and water inrush challenges throughout the mine. All of the detected voids and a large cave are at the intersection of two fractures, indicating preferential water flow and dissolution along conjugate fracture intersections. Detecting, locating, and characterizing fractures and voids prior to excavation can enable miners to mitigate potential collapse and flood hazards before they occur.

Advantages of supercritical CO2 compound fracturing in shale on fracture geometry, complexity and width

Supercritical carbon dioxide (SC–CO2) fracturing has a great prospect for shale gas development, but the poor proppant carrying capacity hinders its effective application. In this paper, SC-CO2 compound fracturing method was proposed, which uses SC-CO2 as the pad fluid to generate complex fracture network and guar gum fluid as the carrier fluid to support and extend the fracture. Relevant tri-axial SC-CO2 compound fracturing experiments with shale specimens were designed to compare with SC-CO2 fracturing and guar gum fracturing. It was found that the breakdown pressure of SC-CO2 fracturing was on average 20.24% lower than that of guar gum fracturing. Both SC-CO2 fracturing and SC-CO2 compound fracturing could generate more complex fracture geometry than guar gum fracturing, especially in specimens with vertical bedding planes where SC-CO2 compound fracturing formed a complex three-dimensional fracture network. A dimensionless index fc was proposed to quantitatively evaluate the complexity of induced fractures. Results show that the fracture complexity of SC-CO2 compound fracturing was on average 20.64% larger than SC-CO2 fracturing, indicating that SC-CO2 induced fractures can be extended by guar gum fracturing. Digital microscope found that SC-CO2 induced fracture width was less than 0.01 mm while fracture width induced by SC-CO2 compound fracturing was 0.04 mm–0.12 mm, manifesting that the guar gum fracturing stage can increase the width by approximately an order of magnitude. The results prove the feasibility of compound fracturing technology, which is of great significance to shale gas development.

Evaluation of fracture closure and its contribution to total production for a well with non-planar asymmetrical vertical fracture based on bottom-hole pressure

Hydraulic-fracturing is an important well-stimulation technique, the fracture closure is inevitable during production. The existing pressure transient analysis models either ignore the length of fracture-closure segment that causes the explained fracture half-length to be smaller, or only use the fracture conductivity to evaluate fracture closure. To fully evaluate fracture closure and provide a reference for oilfield engineers determining whether need measures to improve the well performance, meanwhile considering the non-planar asymmetrical fracture is common met in low-permeability reservoirs, this paper proposes to use two parameters (flowrate proportion and conductivity of fracture-closure segment) to comprehensively evaluate fracture closure, and hence develops double-segment non-planar asymmetrical fracture model (DPAFM). Planar asymmetrical fracture model is simplified case of proposed model. The semi-analytical solution is obtained by using finite difference method (FDM) and Gonzalez-Chavez and Cinco-Ley (2006) model is used to verify the solution. The results of this work show that (a) The example of actual well simulation proves the model is more suitable for the actual field data, and the model established is better matched than the saphir software; (b) The proposed model can obtain production proportion and conductivity of fracture-closure segment to comprehensively evaluate fracture closure; (c) There are four typical flow regimes for the DPAFM, including bilinear flow, interference linear flow, formation linear flow, pseudo-radial flow. The interference linear flow regime with ‘V-shape’ characteristic is unique; (d) Conventional explanation thinks the ‘V-shape’ characteristic represents the secondary fracture developed (e.g., OFFN, TLFN and MOFN). However, this paper gives another possibility that the ‘V-shape’ reflects fracture closure. The findings of this study can help for better understanding of illustrating the practicability of proposed methodology in evaluating the fracture closure and reservoir parameters. This research provides guidance for technicians to formulate the next step to increase production plan and helps the oilfield engineers determine whether take measures to improve the well performance. • We present a double-segment non-planar asymmetrical fracture model (DPAFM) considering the effect of conditions inside fracture. • We provide an additional explanation about ‘V-shape’ characteristic on the pressure derivative curve besides the complex fracture geometries. • The field cases illustrate the practicability of proposed methodology in evaluating the reservoir parameters, fracture closure, fracture segment flow rate and fracture propagation.

Physical reconstruction and mechanical behavior of fractured rock masses

Physical modeling of rock masses containing complex fracture geometries is an important but very challenging task in rock mechanics and rock engineering. In this work, a novel integration of 3D printing and water-soluble casting is presented for the preparation of rock-model specimens with fracture networks, which is similar to the lost-wax casting process. The fracture network is created with water-soluble polyvinyl alcohol (PVA) material by 3D printing. The intact rock matrix is prepared with cement paste. Uniaxial compressive tests combined with the digital image correlation (DIC) technique are conducted to investigate the mechanical properties and failure process of the prepared rock-model specimens. The differentiation rate of the effective variance is defined to recognize the precursory anomalies during the loading process. The mechanical anisotropy is further investigated by a series of rotated models. The results show that the proposed methodology has distinct advantages for replicating rocks with complex fracture geometries in terms of high accuracy for fabricating fracture networks, high repeatability of mechanical properties, and high strength and brittleness of rock matrices. Due to the presence of complex fracture geometries, the nonlinear mechanical responses of the fractured rock-model specimens, including strain-softening and anisotropy, are observed in our experiments.

Optimization of Criterion for Rock Crack Propagation under Acid Izing Treatment

Since most of the conventional oil and gas resources have been intensively investigated, unconventional oil and gas resources such as deep marine carbonate reservoirs and heavy oil reservoirs have become the primary focus in the exploration and development of oil and gas. The oil and gas reservoirs with complex fracture geometries account for nearly 45% of the global oil and gas reserves, and the production of such complex fractured oil and gas reservoirs accounts for nearly 60% of the total natural gas production. Consequently, fractured oil and gas reservoirs have received considerable research attention in recent years. Further, fractures determine the permeability and productivity of petroliferous reservoirs. In this paper, we have investigated the current status of research on petroliferous rock under the action of acid etching. At the same time, we have summarized the existing rock fracture propagation criterion and crack propagation criterion theory, and selected the most common crack propagation criterion for setting simulation parameters. Subsequently, the Brazilian split test and the rock acidification sensitivity experiment are combined, and the comparative experiment method is used to obtain the hydrochloric acid concentration and acidification treatment time that can meet the DIC optical test. Through the DIC method, the expansion of rock cracks from the moment of loading of experimental species to the moment when the completion of splitting is recorded, the strain and displacement of each point on the rock surface during the Brazilian splitting test are obtained. Finally, through the ABAQUS software, different fracture propagation criteria are used to simulate the fracture propagation process in the rock samples in the Brazilian fracturing test, and the results are recorded. Then, the expansion model is selected that best fits the carbonate fracture before and after acid etching. The in-situ stress field of the fault zone in the Shunbei area is exceedingly complex. Based on the Shunbei area, the model is set up. Furthermore, the features of plane geomechanics are studied, and the fracture propagation laws of acid salt reaction are analyzed. The results provide the basis for optimizing the acid fracturing technology and construction parameters in the Shunbei area.

A semi-analytical pressure model of horizontal well with complex networks in heterogeneous reservoirs

The tight reservoirs have been successfully developed by horizontal wells with massive hydraulic fractures. The inherent heterogeneity along the wellbore, complex fracture networks generated due to the pre-existing natural fracture and stress isotropy, the difference of reservoir properties between the stimulated reservoir volume (SRV) and the unstimulated region all bring huge challenges in predicting pressure and rate transient responses. Previous study always simplified the whole reservoir as homogeneous or radial composite region, and treated the complex networks as orthogonal fracture networks. In the light of this situation, by using the source function, boundary element method and composite reservoir model, a rigorous semi-analytical model for a horizontal well with complex fracture networks in heterogeneous reservoirs was presented in this paper. A previous semi-analytical model and numerical model established by commercial simulator were both used to verify the feasibility of the proposed model. The effects of critical parameters on the transient pressure behaviors are discussed. The results show that heterogeneity of the reservoir has a significant influence on pressure behavior. The sensitivity analysis of fracture number, fracture geometry, storage coefficient and inter-porosity factor of SRV, reservoir sizes and relative position between SRV and the outer boundaries are conducted to further understand the transient pressure behaviors of volume fractured horizontal well. In this paper, both the heterogeneity along the horizontal well in the SRV and the heterogeneity between the SRV and the unstimulated region is brought into consideration. In addition, the complex fracture geometry is also captured. Therefore, our model can be capable of studying the transient pressure behaviors of volume fractured horizontal wells in heterogeneous reservoir. The research results provided by this work have some significance for well test interpretation of tight reservoirs.

Discrete fracture matrix modelling of fully-coupled CO2 flow – Deformation processes in fractured coal

CO2 interaction causes complex mechanical deformations and flow modifications in coal, depending on the spatial disposition of the fracture-matrix system. Sorption-induced matrix swelling reduces the local fracture aperture and correspondingly the fracture permeability, consequently influencing gas flow throughout the seam. Since these modifications are highly -heterogeneous and -localized, an explicitly-represented geometric model is essential for the accurate modelling of the fully-coupled process. In this study, the CO2 flow – coal deformation process is implemented in a numerical model at the scale of coal constituents (i.e. matrix blocks and cleats), through the inclusion of a spatially distributed 3D – discrete fracture matrix (DFM) network. Fracture geometry is generated from a stochastically simplified 2D fracture network obtained from micro-CT imaging. The approach is initially validated against experimental results from a single-fractured coal specimen and the analysis extended to the complex fracture geometry. The spatial and temporal evolutions of fracture/matrix pressure, adsorbed mass of CO2, adsorption-induced swelling, alterations in local fracture aperture and permeability, and contact modelling at fully fracture closure are specifically analysed with comparison against no-swelling behaviour. Results indicate that the high-permeability fracture pathways provide initial easy access for the CO2 to diffuse into the coal matrix, causing sorption-induced matrix swelling. Although the individual matrix blocks exhibit a slight shrinkage immediately upon injection of high fluid pressures within the fractures, sorption-induced swelling rapidly overcomes this, resulting in an overall volume expansion at full pressure equilibration. This is turn causes a significant reduction in fracture aperture and permeability. The magnitude of the local fracture aperture reduction depends on the swelling behaviour of the bounding matrix, that leads to essentially full-closure of small fractures, causing significant localized flow modifications to further CO2 injection in the vicinity of the particular fractures. The contact modelling approach identifies the timing and locations of fully-closing fractures in the complex geometry, where butt cleats exhibiting initial small apertures are prone to fully-close, compared to larger aperture face cleats that retain flow.

Numerical simulation of complex fracture geometry caused by hydrodynamics in shale with pre-existing weak planes

Three shale models with pre-existing weak planes (WPs) are established in this study based on three real shale outcrops with different weak planes characteristics. A global embedded 3D cohesive zone model (CZM) is used to simulate the fracture geometry of the hydraulic fractures with three structurally anisotropic shale models. The (Khristianovic-Geertsma-de Klerk) KGD model and Blanton's criterion are used to verify the reliability of the proposed model. Several simulation examples are established to study the effects of the stratification distribution, weak plane density, horizontal stress difference (HSD), injection rate, and fluid viscosity on the fracture geometry in the stratification plane and matrix. In addition, the effects of these variables on the stimulated reservoir volume (SRV) are analyzed. Structurally anisotropic shale has a symmetrical fan-shaped fracture network, a central symmetrically inclined fracture network, and an irregular fracture network along the weak plane direction. There are two types of hydraulic fracture (HF) networks: a fracture network composed of WP fractures and another fracture network composed of WP fractures and matrix fractures. A decrease in the weak-plane density, an increase in the approach angle, an increase in the HSD, an increase in the fracturing fluid viscosity, and an increase in the injection rate all contribute to the formation of MFs and a complex fracture network interlacing WP fractures and matrix fractures. In contrast, it is helpful to form WP fractures and fracture network that is only composed of the WP fracture. When WP fractures coexists with matrix fractures, the opening of the WP fracture is generally 2–4 times larger than that of the matrix fracture, which can easily form the main fracture. With an increase in the approach angle, the width of the SRV gradually increases whereas the length of the SRV decreases first and then increases. This study further supports our understanding of the geometry of complex fractures generated by a hydraulic drive in shale and has important reference significance for well completion design and hydraulic fracturing design in shale development.

Development of coupled two phase flow and geomechanics model to predict stress evolution in unconventional reservoirs with complex fracture geometry

Understanding stress changes associated with reservoir depletion is very important for developments of unconventional reservoirs such as completion of infill well. Fluid flow in reservoir often contains multiple phases mostly a mix of oil and water phase. Multiphase flow in porous media also involves in many applications including water injection. In this paper, we have upgraded our coupled fluid flow and geomechanics with Embedding Discrete Fracture Model (EDFM) to two phase flow using OpenFOAM, an open-source platform for CFD, in order to expand the model to wider range of applications including characterization of stress evolution associated with depletion of two-phase flow in unconventional reservoirs with complex fracture geometries. Coupled geomechanics and fluid-flow was developed based on well-known fixed-stress split, 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 two phase model is based on Implicit Pressure Explicit Saturation (IMPES) method. Validations of our single phase model and EDFM were conducted in our previous paper. Validation of two phase model was done against analytical solution of Buckley-Leverett and Capillary-gravity equilibrium problems. In addition, validation of EDFM part was conducted against local grid refinement. The model was used to run performance test on water injection-oil production problem with geomechanics and capillary effect. Non-planar fractures under production was also used to test for EDFM part. Finally, we applied our model in simulation of 3D multiple fractures under production in a fully 3D reservoir. The results indicate that created fracture geometries have a significant effect on stress distribution and reorientation induced by depletion. Characterization of stress evolution due to reservoir depletion in two phase flow will provide critical guidelines for optimization of completion designs especially in infill well drilling and further development in unconventional reservoirs.

A fracture upscaling method (FUM) for hydraulically fractured reservoirs: From discrete fracture modelling to finite difference simulations

Hydraulic fracturing creates a complex fracture geometry in heterogeneous formations which are frequently simulated using Finite Element based fracture propagation modelling tools. Representing this geometry in Finite Difference based multiphase flow simulators poses some challenges. In this study, a Fracture Upscaling Method (FUM) is developed to represent complex fracture systems generated by the finite element method. It is demonstrated that this method can capture complex fracture geometries even when using coarse grids. This upscaling method can be used as a coupling tool between the output of any discrete fracture model and any finite difference-based reservoir simulator. FUM is tested against a field case and simulation results show a reasonable match with 120 days of production data. This method is then used to investigate the impact that natural fractures have on production from shale gas wells. The results show that the effect of orientation, spacing and length of natural fractures, on propagating hydraulic fractures can reduce the recovery factor by 30%. Furthermore, the ability of FUM to combine highly complex fracture networks with realistic multiple layer models with complex distributions of reservoir properties is demonstrated.

A semianalytical model for transient pressure analysis of a horizontal well with non-uniform fracture geometry and shape-dependent conductivity in tight formations

Hydraulic fracture geometry greatly affects production performance of the fractured horizontal wells in a tight formation; however, limited attempts have been made to evaluate the performance of wells with non-uniform fracture geometries which are more close to the reality. In this work, a new slab source function was formulated and employed to accurately and efficiently evaluate the transient flow behaviour of a horizontal well with multiple non-uniform fracture geometries in a tight formation. More specifically, such a slab source function in the Laplace domain can assign a geometrical width for the source, which is usually neglected in the existing studies. Then, a semianalytical method is employed to solve the transient flow problem by dividing the non-uniform fracture into several segments, each of which can be assumed as a uniform-flux slab source. Thus, transient pressure behaviour considering complex fracture geometry can be taken into account with the slab source function using the superposition principle and the Stehfest inverse algorithm. The slab source function was validated with numerical and semianalytical solutions and then extended to field application. Also, effects of both the partially propped fractures and near-wellbore fracture damage are well examined and analyzed. It is found that the width of the fracture only affects the early time transient pressure response, while the pressure response at later time is identical to that of the line source solutions. The fracture geometry imposes a significant impact on the well response at the early and intermediate time period and the fracture with concave geometry results in the lowest pressure response, while the rectangular fracture has the largest pressure response. Both the length of the propped fractures and the damaged fracture zone mainly dominate the intermediate-stage pressure behaviour, while the width of the damaged zone will impose an important impact on the transient pressure response for the early and intermediate time period.

Digital quantification of fracture in full-scale rock using micro-CT images: A fracturing experiment with N2 and CO2

How to effectively and cleanly exploit unconventional resources is currently being widely concerned. Due to the unavoidable limitations of water-based fracturing, CO2 and N2 etc., are regarded as alternative fluids for some specific reservoirs such as the arid area or high clay swelling formation. To investigate the characteristics of fracture induced by nonaqueous fluid in unconventional tight formation, fracturing experiments on tight sandstone using different fluid of water, N2, liquid CO2(L-CO2) and supercritical CO2(SC-CO2) were conducted. A novel fracture analysis approach based on CT scanning is also proposed to quantitatively analyze the micromorphology of fractures including fracture network pattern, fractal dimension (FD), aperture, area ratio (AR) and fracture volume etc. Results show that water and N2 can only induce a relatively simple fracture pattern. Whereas, fractures induced by CO2-based fluid have more complex fracture geometry with many fracture branches and various propagation orientations. Quantitative analysis based on image processing and fracture reconstruction algorithm indicates that the CO2-based fluid has up to 4.4 times larger fracture-induced capacity and can create fracture with up to 2.6 times higher complexity and 23.4% higher roughness than that generated by water-based fracturing. Comparing to SC-CO2, L-CO2 and water, N2 has the least fracture-induced capacity (83% of water) and produces more smooth and uniform fractures. On the other hand, the distributions of deviation angle suggest that fracture propagation is not only influenced by stress state, but also significantly affected by the original bedding plane. This experimental study proposes a precise and effective approach for fracture characteristic quantification, which can be further implemented into fracture simulation model. It also provides theoretical reference and guidance for field operation of waterless fracturing in development of unconventional oil and gas.

Coupled compositional flow and geomechanics modeling of fractured shale oil reservoir with confined phase behavior

Shale oil flow is commonly affected by the confined phase behavior, complex fracture geometries, and geomechanical effect, which are not fully considered in the conventional compositional simulators. In this study, a coupled compositional flow and geomechanics model is presented to incorporate these effects for more accurate prediction on shale oil production performance. The compositional model considering the confined phase behavior is used to model the multiphase flow in shale formations, in which the capillary pressure is introduced into the workflows of phase stability test and flash calculation. The embedded discrete fracture model (EDFM) is adopted to explicitly describe the complex fracture geometries. The deformations of hydraulic fractures and natural fractures are handled by different constitutive models. A mixed finite-volume and finite-element (FVM-FEM) scheme is used to discretize the flow and geomechanics equations, and the coupled problem is iteratively solved by the fixed-stress splitting method. Based on the proposed model, simulations are conducted on a multi-stage fractured shale reservoir to evaluate the effects of confined phase behavior, hydraulic fracture deformation, and natural fracture network on the production performance. Results show that the bubble point pressure is suppressed by the confined phase behavior effect, which leads to higher oil production. The hydraulic fracture deformation takes effect only when the hydraulic fractures cannot be treated as infinite-conductivity under poorly-propped condition. The oil production is greatly promoted with the increase of natural fracture density due to the increase of interface area between matrix and fractures.

Coupling of fracture model with reservoir simulation to simulate shale gas production with complex fractures and nanopores

A novel integrated approach that couples hydraulic fracturing and production simulation was proposed for Marcellus shale gas reservoir. A discrete element method based hydraulic fracturing simulator was utilized for multi-stage hydraulic fracturing simulation. Moving tip clustering (MTC) and linear regression clustering (LRC) algorithms were proposed to characterize the complex fracture geometry. Embedded discrete fracture model method was used to transfer the complex geometry of multiple fractures into a third-party reservoir simulator for history matching of shale gas production and production forecasting. It was observed that the LRC algorithm can generate smooth fracture geometries and detect overall fracture paths reasonably. The MTC algorithm, however, can capture more branches of microcracks and recover zig-zag fracture paths with larger apparent fracture lengths. The zig-zag fractures contribute to larger stimulated reservoir volume and result in an extra shale gas production of 5.2% compared to the smooth fractures. The gas slippage effect increases apparent matrix permeability to 4.6 times of intrinsic permeability. Reduction of fracture conductivity and matrix permeability due to decreasing bottomhole pressure leads to 9.25% and 9.28% decrease of gas production respectively in 30 years and should be taken into account for long-term production prediction.

A model for elastic fracture closure on heterogeneous distribution of compressible solids and etched walls

Fracture elasticity problems become far nontrivial with complex fracture geometries or heterogeneity of surrounding medium. For closing fractures, which can be partly open, partly closed, and partly clamping the filling solids, the elasticity problem is even more complicated due to mixed boundary conditions and nonlinear stress-strain relationship of filling. Accurate modeling of fracture closure in such conditions requires development of a stable and computationally effective numerical model. It is important, for instance, in oilfield industry, to correctly evaluate conductivity of hydraulic fractures either heterogeneously filled by injected proppants or having residual apertures of walls etched by acidizing.In this work, we develop a computationally efficient numerical solver for such sorts of problems. Given the spatial distribution of filling solids, or fracture wall etching, we employ the iterative Displacement Discontinuity Method to solve for the opening shape of a 3D planar fracture. In addition to the applied stresses and inner fluid pressure, the fracture opening is shown to be sensitive to the elastic properties of filling solids, which may exhibit a nonlinear dependency between stress and strain. The model allows to deal with multiple solids of different elastic properties. Knowing the fact that computational time increases with increase of spatial fracture filling resolution, we employ the Fast Multipole Method to gain computational time in case of large number of grid cells. We verify the model correctness against exact analytical solutions of selected fracture problems.The developed model is shown to be practically useful for simulations of hydraulic fracture closure on heterogeneously distributed proppants or acid-etched fracture walls after the end of fracturing treatment, as well as for valid estimations of fractured well productivity sensitive to pressure drawdown.

Proppant placement in complex fracture geometries: A computational fluid dynamics study

Proppant transport in activated natural fractures and induced secondary fractures has been increasingly receiving attention. However, the roughness and the non-planarity of hydraulic fractures violate the assumption of a constant flow path during the proppant transport. Therefore, we utilized a computational fluid dynamics (CFD) approach to study the proppant transport in the complex fracture network while considering the non-planarity and the surface roughness. The fracturing fluid loaded with sands (proppant) is injected to the fracture at a synthesized field-guided pumping schedule. We used the Eulerian-Eulerian frame of the two-phase turbulent flow for modeling the transport processes of which are compared to the proppant transport experiments. The results reflect that our constructed model captures the essential transport mechanisms of the dispersed phase (proppant particles) with the help of the appropriate drag model. We also find that the surface roughness of the fracture deaccelerates the particle velocity during the early injection time, while the fracture non-planarity plays more essential role to the particle transport in the fracture than other geometrical and topographic factors. More importantly, we noticed that the propped fracture heights vary up to one fold with different secondary fracture orientations. This observation would potentially surprise the production performance diagnosis later on.

Simulation of mixed‐mode fracture using SPH particles with an embedded fracture process zone

SummaryThis paper focuses on the modelling of mixed‐mode fracture using the conventional smoothed particle hydrodynamics (SPH) method and a mixed‐mode cohesive fracture law embedded in the particles. The combination of conventional SPH and a mixed‐mode cohesive model allows capturing fracture and separation under various loading conditions efficiently. The key advantage of this framework is its capability to represent complex fracture geometries by a set of cracked SPH particles, each of which can possess its own mixed‐mode cohesive fracture with arbitrary orientations. Therefore, this can naturally capture complex fracture patterns without any predefined fracture topologies. Because a characteristic length scale related to the size of the fracture process zone is incorporated in the constitutive formulation, the proposed approach is independent from the spatial discretisation of the computational domain (or mesh independent). Furthermore, the anisotropic fracture responses of materials can be naturally captured thanks to the orientation of the fracture process zone embedded at the particle level. The performance of the proposed approach demonstrates its potentials in modelling mixed‐mode fracture of rocks and similar quasi‐brittle materials.

Mechanistic study of cyclic water injection to enhance oil recovery in tight reservoirs with fracture deformation hysteresis

As an effective enhanced oil recovery (EOR) technique in tight reservoirs, cyclic water injection has been extensively studied recently. However, very few studies have considered the impacts of loading-path dependent fracture deformation, i.e. deformation hysteresis. In this study, an efficient coupled two-phase flow and geomechanics model is developed to simulate cyclic water injection in a tight oil reservoir with the consideration of fracture deformation hysteresis. The embedded discrete fracture model (EDFM) is applied to handle complex fracture geometries. Different loading-path dependent constitutive models are used to describe the deformations of hydraulic fractures and natural fractures, respectively. Then simulation studies are performed to demonstrate the impacts of deformation hysteresis of hydraulic fractures and natural fractures on EOR performance. The sensitivities to injection rate, depletion pressure and soaking time are examined. The results show that the deformation hysteresis of hydraulic fracture has significant effect on oil production, while that of natural fracture has negligible impact. The effects of fracture deformation hysteresis are more pronounced under high injection rate and depletion pressure, but less sensitive to soaking time.

Pressure transient analysis in the child well with complex fracture geometries and fracture hits by a semi-analytical model

Recently, the model development of pressure transient analysis in wells with large-scale fracturing treatments has attracted more and more attention. However, a little work has involved the complex fracture networks with fracture hits. In this study, the transient pressure behaviors of a child well with complex fracture geometries and fracture hits are studied, using an efficient semi-analytical model. The semi-analytical model has the capability to simulate shale well performance by considering complex non-planar hydraulic fractures and fracture hits.The pressure transient solution of the semi-analytical model is obtained by the incorporation of nodal analysis and Laplace transforms. After the numerical verification of the proposed semi-analytical model, we apply it to analyze the pressure testing data of a child well and a parent well. Through conducting a series of history matching, the most likely fracture parameters of the child well is determined. Results show that the flow regimes of complex fracture geometries with fracture hits include wellbore storage, skin effect, fracture bilinear flow, “fluid feed”, pseudo-boundary dominated flow, unconnected fracture (UF) impact, and pseudo radial flow. During the flow regime of UF impact, the pressure derivative curves exist a second “V-shape”, as the UF improve the matrix permeability and the pressure depletion will be reduce once the flow reaches the UF. A case study in the Lucaogou shale oil reservoir from the Junggar Basin show that complex fracture geometries is developed along the child wellbore. After estimation, the fracture hits between the parent well and child well may via five hitting fractures. The length and conductivity of the hitting fractures are evaluated as 20 m and 120 mD∙m, respectively. This work could be beneficial to performance forecast and well spacing optimization in unconventional reservoirs.