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Successfully creating multiple hydraulic fractures in horizontal wells is critical for unconventional gas production economically. Optimizing the stimulation of these wells will require models that can account for the simultaneous propagation of multiple, potentially nonplanar, fractures.In this paper, a novel fracture-propagation model (FPM) is described that can simulate multiple-hydraulic-fracture propagation from a horizontal wellbore. The model couples fracture deformation with fluid flow in the fractures and the horizontal wellbore. The displacement discontinuity method (DDM) is used to represent the mechanics of the fractures and their opening, including interaction effects between closely spaced fractures. Fluid flow in the fractures is determined by the lubrication theory. Frictional pressure drop in the wellbore and perforation zones is taken into account by applying Kirchoff's first and second laws. The fluid-flow rates and pressure compatibility are maintained between the wellbore and the multiple fractures with Newton's numerical method. The model generates physically realistic multiple-fracture geometries and nonplanar-fracture trajectories that are consistent with physical-laboratory results and inferences drawn from microseismic diagnostic interpretations.One can use the simulation results of the FPM for sensitivity analysis of in-situ and fracture treatment parameters for shale-gas stimulation design. They provide a physics-based complex fracture network that one can import into reservoir-simulation models for production analysis. Furthermore, the results from the model can highlight conditions under which restricted width occurs that could lead to proppant screenout.

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Summary Because of interwell interference, the completion and production of infill wells in unconventional reservoirs often change established production profiles for parent wells and lead to infill-well production lower than expected. Parent-well injection has been used in some fields in an attempt to reduce interwell interference. However, mixed responses were received from these attempts, and few modeling studies have been presented to investigate the mechanisms of the mixed responses. This study investigates the effects of subsequent injection in parent wells with legacy production on interwell interference using a data set from Eagle Ford Shale. A numerical-modeling work flow is presented for the characterization of poroelastic behaviors of multiphase-fluid diffusivity and rock deformation using the finite-element method and multifracture propagation using the displacement discontinuity method. It solves for the spatial-temporal evolutions of pore pressure and in-situ stress because of parent-well production and injection and models the fracture propagation during infill-well completion on the basis of updated heterogeneous in-situ stresses. Thus, the approach obtains the interwell fracture network comprising parent-well fractures and fractures from infill-well completion and captures fracture hits, which are necessary for the analysis of the injection effectiveness. Numerical results indicate that subsequent injections in parent wells make infill-well fractures grow more transversely, denoting improved completion qualities of infill wells. Also, the required subsequent injection volume leading to transverse infill-well fractures is positively correlated with the volume of legacy production in parent wells. In addition to subsequent injection volume, locations of perforation clusters along the infill well are another key parameter affecting the associated interwell interference. Results show that it is easier to generate fracture hits after infill-well completion, when perforation-cluster locations along the infill wellbore are identical to those along parent wellbores. In contrast, certain infill-wellbore perforation-cluster locations different from those in parent wellbores guarantee transverse infill-well fractures and avoid fracture hits during/after infill-well completion. On the basis of the numerical results in this specific study, when infill-well perforation cluster locations are properly placed, the volume of parent-well subsequent injection should be at least 76.9% of the total depleted liquid volume during the legacy production of parent wells for subsequent injection to be effective in avoiding fracture hits. This value is on a case-by-case basis and should not be generalized. The contribution of this work lies in its analyses of the mixed performance by parent-well subsequent injection in the reduction of interwell interference using a reservoir-geomechanics/fracturing modeling work flow.

Summary Simultaneous multiple-fracture treatments in horizontal wellbores are becoming a prevalent approach to economically develop unconventional resources in shale reservoirs. One challenge to efficiently use the technique is the generation of effective hydraulic fractures from all perforation clusters. In this work, we conducted a fundamental study of physical mechanisms controlling simultaneous multiple-fracture propagation and discussed the potential approaches to improve nonuniform development of multiple fractures. This study was investigated by our recently developed 3D fracture-propagation model that captures the coupled elastic deformation of the rock with fluid flow in the horizontal wellbore and within the fractures. The model demonstrated that fracture geometry was controlled by both the stress-shadow effects and dynamic partitioning of flow rate. The analysis results indicated that the nonuniform development of a multiple-fracture array, for example, a three-fracture array in this study, was induced by the uneven partitioning of flow rate into each fracture, which was dependent on the flow resistance from wellbore friction, perforation friction, and fracture propagation. Furthermore, the stress shadowing from the exterior fractures exerted additional stress on the interior fractures and increased the resistance of fracture propagation, resulting in the interior fractures receiving much less fluid. To minimize the negative effects of stress shadowing and favor more-uniform fracture growth, we investigated potential approaches to promote uniform partitioning of flow rate through adjusting the flow resistance between multiple fractures. The results showed that adjusting perforation friction can provide an effective way to modify the partitioning of flow rate and mitigate the negative effects of stress shadowing. The mechanisms investigated in this study are consistent with field observations. Our approach can help field operators to improve the effectiveness of multiple fracturing treatments and maximize the production.

Summary Complex fracture networks have become more evident in shale reservoirs as a result of the interaction between pre-existing natural fractures (NFs) and hydraulic fractures (HFs). Accurate characterization of fracture complexity plays an important role in optimizing fracturing design, especially for shale reservoirs with high-density NFs. In this study, we simulated simultaneous multiple-fracture propagation within a single fracturing stage by use of a complex HF-development model. The model was developed to simulate complex fracture propagation by coupling rock mechanics and fluid mechanics. A simplified 3D displacement-discontinuity method (DDM) was implemented to more accurately calculate fracture displacements and fracture-induced dynamic-stress changes than our previously developed pseudo-3D model. The effects of perforation-cluster spacing, differential stress (SHmax – Shmin), and the geometry of various NF patterns on injection pressure and fracture complexity were investigated. The single-stage simulation results show that (1) higher differential stress suppresses fracture length and increases injection pressure; (2) there is an optimal choice for the number of fractures per stage to maximize effective fracture-surface contact area, beyond which increasing the number of fractures actually decreases effective fracture area; and (3) fracture complexity is a function of NF patterns (various regular-pattern geometries were investigated). NFs with small relative angle to HFs are more likely to control the fracture-propagation path. Also, NF patterns with more long fractures tend to increase the likelihood to dominate the preferential fracture trend of fracture trajectory. Our numerical model can provide a physics-based complex fracture network that can be imported into reservoir-simulation models for production analysis. The overall sensitivity results presented should serve as guidelines for fracture-complexity analysis.