Dynamic development of hydrofracture

Many natural examples of complex joint and vein networks in layered sedimentary rocks are hydrofractures that form by a combination of pore fluid overpressure and tectonic stresses. In this paper, a two-dimensional hybrid hydro-mechanical formulation is proposed to model the dynamic development of natural hydrofractures. The numerical scheme combines a discrete element model (DEM) framework that represents a porous solid medium with a supplementary Darcy based pore-pressure diffusion as continuum description for the fluid. This combination yields a porosity controlled coupling between an evolving fracture network and the associated hydraulic field. The model is tested on some basic cases of hydro-driven fracturing commonly found in nature, e.g., fracturing due to local fluid overpressure in rocks subjected to hydrostatic and nonhydrostatic tectonic loadings. In our models we find that seepage forces created by hydraulic pressure gradients together with poroelastic feedback upon discrete fracturing play a significant role in subsurface rock deformation. These forces manipulate the growth and geometry of hydrofractures in addition to tectonic stresses and the mechanical properties of the porous rocks. Our results show characteristic failure patterns that reflect different tectonic and lithological conditions and are qualitatively consistent with existing analogue and numerical studies as well as field observations. The applied scheme is numerically efficient, can be applied at various scales and is computational cost effective with the least involvement of sophisticated mathematical computation of hydrodynamic flow between the solid grains

Application of the Variational Fracture Model to Hydraulic Fracturing in Poroelastic Media

Hydraulic fracturing has persisted through the use of simple numerical models to describe fracture geometry and propagation. Field tests provide evidence of interaction and merging of multiple fractures, complex fracture geometry and propagation paths. These complicated behaviors suggest that the simple models are incapable of serving as predictive tools for treatment designs. In addition, other commonly used models are designed without considering poroelastic effects even though a propagating hydraulic fracture induces deformation of the surrounding porous media. A rigorous hydraulic fracturing model capable of reproducing realistic fracture behaviors should couple rock deformation, fracture propagation and fluid flow in the both the fracture and reservoir. In this dissertation, a fully coupled hydraulic fracturing simulator is developed by coupling reservoir-fracture flow models with a mechanical model for reservoir deformation. Reservoir-fracture deformation is modeled using the variational fracture model which provides a unified framework for simultaneous description of fracture deformation and propagation, and reservoir deformation. Its numerical implementation is based on a phase-field regularized model. This approach avoids the need for explicit knowledge of fracture location and permits the use of a single computational domain for fracture and reservoir representation. The first part of this work involves verification of the variational fracture model by solving the classical problem of fracture propagation in impermeable reservoirs due to injection of an inviscid fluid. Thereafter, the developed reservoir-fracture model is coupled to the mechanical model. Iterative solution of the variational fracture model and the coupled flow model provides a simplified framework for simultaneous modeling of rock deformation and fluid flow during hydraulic fracturing. Since the phase field technique for fracture representation removes the limitation of knowing a priori, fracture direction, the numerical solutions provide a means of evaluating the role of reservoir and fluid properties on fracture geometry and propagation paths. First, the proposed approach is validated for simple idealized scenarios for which closed form solutions exist in the literature. Further simulations highlight the role of fluid viscosity and reservoir properties on fracture length, fracture width and fluid pressure. Numerical results show stress shadowing effect on multiple hydraulic fracture propagation. Finally, the effect of in situ stress on fracture propagation direction is reproduced while the role of varying reservoir mechanical properties on fracture height growth is investigated

Modelling of hydraulic fracturing in unconventional reservoirs

Hydraulic fracturing (HF) is a process of fluid injection into the well in order to create tensile stresses in the rock to overcome the tensile strength of the formation. In this study, the development and application of a fuzzy model to predict the efficiency of hydraulic fracturing is presented with application in a coal mine as an unconventional reservoir. The most important parameters affecting the HF process of a coal seam are: dip, thickness, seam uniformity, roof and floor conditions, reserve of coal seam and coal strength. In the developed model, the efficiency of hydraulic fracturing of coal seams is calculated as a dimensionless numerical index within the range 0-100. The suggested numerical scale categorizes the efficiency of HF of seams to very low, low, medium, high and very high, each one being specified by a numerical range as a subset of the above range (0-100). HF in the coal bed in PARVADEH 4 Tabas mine in Iran is investigated as a case study. The results show that the developed model can be used to identify seams that have high potential for HF Moreover, a three-phase hydro-mechanical model is developed for simulating hydraulic fracturing. The three phases include: porous solid, fracturing fluid and reservoir fluid. Two numerical simulators (ANSYS Fluent for fluid flow and ANSYS Mechanical for geomechanical analysis) are coupled together to model multiphase fluid flow in hydraulically fractured rock undergoing deformations, ranging from linear elastic to large, nonlinear inelastic deformations. The two solvers are coupled, using system coupling in ANSYS Workbench. The coupled problem of fluid flow and fracture propagation is solved numerically. The fluid flow model involves solving the Navier-Stokes equations using the finite volume method. The flow model is coupled with the geomechanics model to simulate the interaction between fluid flow inside the fracture with rock deformations. For any time step, the pore pressures from the flow model are used as input for the geomechanics model for the determination of stresses, strains, and displacements. The strains derived from the gomechanics model are in turn used to calculate changes to the reservoir parameters that are fed as input to the flow model. This iterative process continues until both (fluid and solid) models are converged. The laboratory-scale study of hydraulic fracturing in the Second White Specks (SWS) shale was simulated using the developed model. The numerical and experimental results were compared. Comprison of the results shows that the numerical model can predict the behaviour of the shale under hydraulic fracturing with a good accuracy

A Review of Hydraulic Fracturing Simulation

Along with horizontal drilling techniques, multi-stage hydraulic fracturing has improved shale gas production significantly in past decades. In order to understand the mechanism of hydraulic fracturing and improve treatment designs, it is critical to conduct modelling to predict stimulated fractures. In this paper, related physical processes in hydraulic fracturing are firstly discussed and their effects on hydraulic fracturing processes are analysed. Then historical and state of the art numerical models for hydraulic fracturing are reviewed, to highlight the pros and cons of different numerical methods. Next, commercially available software for hydraulic fracturing design are discussed and key features are summarised. Finally, we draw conclusions from the previous discussions in relation to physics, method and applications and provide recommendations for further research

A Study of Interwell Interference and Well Performance in Unconventional Reservoirs Based on Coupled Flow and Geomechanics Modeling with Improved Computational Efficiency

Completion quality of tightly spaced horizontal wells in unconventional reservoirs is important for hydrocarbon recovery efficiency. Parent well production usually leads to heterogeneous stress evolution around parent wells and at infill well locations, which affects hydraulic fracture growth along infill wells. Recent field observations indicate that infill well completions lead to frac hits and production interference between parent and infill wells. Therefore, it is important to characterize the heterogeneous interwell stress/pressure evolutions and hydraulic fracture networks. This work presents a reservoir-geomechanics-fracturing modeling workflow and its implementation in unconventional reservoirs for the characterization of interwell stress and pressure evolutions and for the modeling of interwell hydraulic fracture geometry. An in-house finite element model coupling fluid flow and geomechanics is first introduced and used to characterize production-induced stress and pressure changes in the reservoir. Then, an in-house complex fracture propagation model coupling fracture mechanics and wellbore/fracture fluid flow is used for the simulation of hydraulic fractures along infill wells. A parallel solver is also implemented in a reservoir geomechanics simulator in a separate study to investigate the potential of improving computational efficiency. Results show that differential stress (DS), parent well fracture geometry, legacy production time, bottomhole pressure (BHP) for legacy production, and perforation cluster location are key parameters affecting interwell fracture geometry and the occurrence of frac hits. In general, transverse infill well fractures are obtained in scenarios with large DS and small legacy producing time/BHP. Non-uniform parent well fracture geometry leads to frac hits in certain cases, while the assumption of uniform parent well fracture half-lengths in the numerical model could not capture the phenomenon of frac hits. Perforation cluster locations along infill wells do not play an important role in determining whether an infill well hydraulic fracture is transverse, while they are important for the occurrence of frac hits. In addition, the implementation of a parallel solver, PETSc, in a fortran-based simulator indicates that an overall speedup of 14 can be achieved for simulations with one million grid blocks. This result provides a reference for improving computational efficiency for geomechanical simulation involving large matrices using finite element methods (FEM)

Recent comprehensive review for extended finite element method (XFEM) based on hydraulic fracturing models for unconventional hydrocarbon reservoirs

Hydraulic fracturing has been around for several decades since 1860s. It is one of the methods used to recover unconventional gas reservoirs. Hydraulic fracturing design is a challenging task due to the reservoir heterogeneity, complicated geological setting and in situ stress field. Hence, there are plenty of fracture modelling available to simulate the fracture initiation and propagation. The purpose of this paper is to provide a review on hydraulic fracturing modelling based on current hydraulic fracturing literature. Fundamental theory of hydraulic fracturing modelling is elaborated. Effort is made to cover the analytical and numerical modelling, while focusing on eXtended Finite Element Modelling (XFEM)

Numerical modeling of complex hydraulic fracture development in unconventional reservoirs

textSuccessful creations of multiple hydraulic fractures in horizontal wells are critical for economic development of unconventional reservoirs. The recent advances in diagnostic techniques suggest that multi-fracturing stimulation in unconventional reservoirs has often caused complex fracture geometry. The most important factors that might be responsible for the fracture complexity are fracture interaction and the intersection of the hydraulic and natural fracture. The complexity of fracture geometry results in significant uncertainty in fracturing treatment designs and production optimization. Modeling complex fracture propagation can provide a vital link between fracture geometry and stimulation treatments and play a significant role in economically developing unconventional reservoirs. In this research, a novel fracture propagation model was developed to simulate complex hydraulic fracture propagation in unconventional reservoirs. The model coupled rock deformation with fluid flow in the fractures and the horizontal wellbore. A Simplified Three Dimensional Displacement Discontinuity Method (S3D DDM) was proposed to describe rock deformation, calculating fracture opening and shearing as well as fracture interaction. This simplified 3D method is much more accurate than faster pseudo-3D methods for describing multiple fracture propagation but requires significantly less computational effort than fully three-dimensional methods. The mechanical interaction can enhance opening or induce closing of certain crack elements or non-planar propagation. Fluid flow in the fracture and the associated pressure drop were based on the lubrication theory. Fluid flow in the horizontal wellbore was treated as an electrical circuit network to compute the partition of flow rate between multiple fractures and maintain pressure compatibility between the horizontal wellbore and multiple fractures. Iteratively and fully coupled procedures were employed to couple rock deformation and fluid flow by the Newton-Raphson method and the Picard iteration method. The numerical model was applied to understand physical mechanisms of complex fracture geometry and offer insights for operators to design fracturing treatments and optimize the production. Modeling results suggested that non-planar fracture geometry could be generated by an initial fracture with an angle deviating from the direction of the maximum horizontal stress, or by multiple fracture propagation in closed spacing. Stress shadow effects are induced by opening fractures and affect multiple fracture propagation. For closely spaced multiple fractures growing simultaneously, width of the interior fractures are usually significantly restricted, and length of the exterior fractures are much longer than that of the interior fractures. The exterior fractures receive most of fluid and dominate propagation, resulting in immature development of the interior fractures. Natural fractures could further complicate fracture geometry. When a hydraulic fracture encounters a natural fracture and propagates along the pre-existing path of the natural fracture, fracture width on the natural fracture segment will be restricted and injection pressure will increase, as a result of stress shadow effects from hydraulic fracture segments and additional closing stresses from in-situ stress field. When multiple fractures propagate in naturally fracture reservoirs, complex fracture networks could be induced, which are affected by perforation cluster spacing, differential stress and natural fracture patterns. Combination of our numerical model and diagnostic methods (e.g. Microseismicity, DTS and DAS) is an effective approach to accurately characterize the complex fracture geometry. Furthermore, the physics-based complex fracture geometry provided by our model can be imported into reservoir simulation models for production analysis.Petroleum and Geosystems Engineerin

Numerical modeling of complex hydraulic fracture development in unconventional reservoirs

textSuccessful creations of multiple hydraulic fractures in horizontal wells are critical for economic development of unconventional reservoirs. The recent advances in diagnostic techniques suggest that multi-fracturing stimulation in unconventional reservoirs has often caused complex fracture geometry. The most important factors that might be responsible for the fracture complexity are fracture interaction and the intersection of the hydraulic and natural fracture. The complexity of fracture geometry results in significant uncertainty in fracturing treatment designs and production optimization. Modeling complex fracture propagation can provide a vital link between fracture geometry and stimulation treatments and play a significant role in economically developing unconventional reservoirs. In this research, a novel fracture propagation model was developed to simulate complex hydraulic fracture propagation in unconventional reservoirs. The model coupled rock deformation with fluid flow in the fractures and the horizontal wellbore. A Simplified Three Dimensional Displacement Discontinuity Method (S3D DDM) was proposed to describe rock deformation, calculating fracture opening and shearing as well as fracture interaction. This simplified 3D method is much more accurate than faster pseudo-3D methods for describing multiple fracture propagation but requires significantly less computational effort than fully three-dimensional methods. The mechanical interaction can enhance opening or induce closing of certain crack elements or non-planar propagation. Fluid flow in the fracture and the associated pressure drop were based on the lubrication theory. Fluid flow in the horizontal wellbore was treated as an electrical circuit network to compute the partition of flow rate between multiple fractures and maintain pressure compatibility between the horizontal wellbore and multiple fractures. Iteratively and fully coupled procedures were employed to couple rock deformation and fluid flow by the Newton-Raphson method and the Picard iteration method. The numerical model was applied to understand physical mechanisms of complex fracture geometry and offer insights for operators to design fracturing treatments and optimize the production. Modeling results suggested that non-planar fracture geometry could be generated by an initial fracture with an angle deviating from the direction of the maximum horizontal stress, or by multiple fracture propagation in closed spacing. Stress shadow effects are induced by opening fractures and affect multiple fracture propagation. For closely spaced multiple fractures growing simultaneously, width of the interior fractures are usually significantly restricted, and length of the exterior fractures are much longer than that of the interior fractures. The exterior fractures receive most of fluid and dominate propagation, resulting in immature development of the interior fractures. Natural fractures could further complicate fracture geometry. When a hydraulic fracture encounters a natural fracture and propagates along the pre-existing path of the natural fracture, fracture width on the natural fracture segment will be restricted and injection pressure will increase, as a result of stress shadow effects from hydraulic fracture segments and additional closing stresses from in-situ stress field. When multiple fractures propagate in naturally fracture reservoirs, complex fracture networks could be induced, which are affected by perforation cluster spacing, differential stress and natural fracture patterns. Combination of our numerical model and diagnostic methods (e.g. Microseismicity, DTS and DAS) is an effective approach to accurately characterize the complex fracture geometry. Furthermore, the physics-based complex fracture geometry provided by our model can be imported into reservoir simulation models for production analysis.Petroleum and Geosystems Engineerin

A New Multicontinuum Model for Compositional Gas Transport in a Deformable Shale Formation

A new multi-continuum compositional gas simulation model is presented for deformable organic-rich source rocks. The model describes the advective and diffusive mass balance equations for each hydrocarbon components in the organic and inorganic continua. It accounts for the presence of dispersed kerogen with sorbed-gas corrected dynamic porosity. Maxwell-Stefan theory is used to predict the pressure- and composition-dependence of molecular diffusion. The coupled nonlinear system of equations for the multi-component gas transport and geomechanics are discretized using the control volume finite element method, and linearized using the Newton-Raphson iteration scheme. Any fractures in the reservoir domain is modeled using the discrete fracture model. The simulation is based on a new multi-scale conceptual flow model, in which the kerogen is considered to be discontinuous and dispersed in the inorganic matrix at reservoir simulation scale. Scanning Electron Microscopy images, as well as the expected slow transport in the nanoporous organic matrix in comparison to the advective transport in the organic matrix form the basis for this new numerical model. A simple mass balance equation is introduced to enable kerogen to transfer reservoir fluids to the inorganic matrix that is collocated in the same grid-block. The advective-diffusive transport takes place between neighboring grid blocks only in the inorganic matrix. The simulation results indicate that the multi-scale nature of the rock is important and should not be ignored because this could result in an overestimation of the contribution of kerogen to production. Although the adsorbed fluid can contribute significantly to storage in these source rocks, its contribution to production could be severely limited by the lack of kerogen continuity at the reservoir scale and by a low degree of coupling between the organic and inorganic pores. The contribution of Maxwell-Stefan diffusion to the overall transport in organic-rich source rocks appears to be more significant at lower values of matrix permeability, and as the permeability decreases in response to pressure decline during production. The coupled geomechanics and flow simulation results indicate that production of reservoir fluids can induce higher compressive stresses that can in turn reduce fracture conductivity, and lead to faster production decline

Modelling Fracture Propagation in Shale Cap Rocks Cooled by CO2 Injection

Imperial Users onl