Pressure-Transient Behaviors of Wells in Fractured Reservoirs With Natural- and Hydraulic-Fracture Networks

SPE Journal ◽  
2018 ◽  
Vol 24 (01) ◽  
pp. 375-394 ◽  
Author(s):  
Zhiming Chen ◽  
Xinwei Liao ◽  
Wei Yu ◽  
Kamy Sepehrnoori
Keyword(s):  
Porous Media ◽  
Fractured Reservoirs ◽  
Fractured Porous Media ◽  
Fracture Networks ◽  
Computationally Efficient ◽  
Efficient Manner ◽  
Complex Fracture ◽  
Mesh Free ◽  
Petroleum Resources ◽  
Fluid Production

Summary Fracture networks are extremely important for the management of groundwater, carbon sequestration, and petroleum resources in fractured reservoirs. Numerous efforts have been made to investigate transient behaviors with fracture networks. Unfortunately, because of the complexity and the arbitrary nature of fracture networks, it is still a challenge to study transient behaviors in a computationally efficient manner. In this work, we present a mesh-free approach to investigate transient behaviors in fractured media with complex fracture networks. Contributions of properties and geometries of fracture networks to the transient behaviors were systematically analyzed. The major findings are noted: There are approximately eight transient behaviors in fractured porous media with complex fracture networks. Each behavior has its own special features, which can be used to estimate the fluid front and quantify fracture properties. Geometries of fracture networks have important impacts on the occurrence and the duration of some transient behaviors, which provide a tool to identify the fracture geometries. The fluid production in the fractured porous media is improved with high-conductivity (denser, larger) and high-complexity fracture networks.

Modified Extended Finite Element Methods for Gas Flow in Fractured Reservoirs: A Pseudo-Pressure Approach

2018 ◽  
Vol 140 (7) ◽  
Author(s):  
Youshi Jiang ◽  
Arash Dahi-Taleghani
Keyword(s):  
Finite Element ◽  
Porous Media ◽  
Fluid Flow ◽  
Gas Flow ◽  
Fractured Reservoirs ◽  
Tight Gas ◽  
Fracture Networks ◽  
Extended Finite Element ◽  
Gas Reservoirs ◽  
Complex Fracture

Fluid flow in fractured porous media has always been important in different engineering applications especially in hydrology and reservoir engineering. However, by the onset of the hydraulic fracturing revolution, massive fracturing jobs have been implemented in unconventional hydrocarbon resources such as tight gas and shale gas reservoirs that make understanding fluid flow in fractured media more significant. Considering ultralow permeability of these reservoirs, induced complex fracture networks play a significant role in economic production of these resources. Hence, having a robust and fast numerical technique to evaluate flow through complex fracture networks can play a crucial role in the progress of inversion methods to determine fracture geometries in the subsurface. Current methods for tight gas flow in fractured reservoirs, despite their advantages, still have several shortcomings that make their application for real field problems limited. For instance, the dual permeability theory assumes an ideal uniform orthogonal distribution of fractures, which is quite different from field observation; on the other hand, numerical methods like discrete fracture network (DFN) models can portray the irregular distribution of fractures, but requires massive mesh refinements to have the fractures aligned with the grid/element edges, which can greatly increase the computational cost and simulation time. This paper combines the extended finite element methods (XFEM) and the gas pseudo-pressure to simulate gas flow in fractured tight gas reservoirs by incorporating the strong-discontinuity enrichment scheme to capture the weak-discontinuity feature induced by highly permeable fractures. Utilizing pseudo-pressure formulations simplifies the governing equations and reduces the nonlinearity of the problem significantly. This technique can consider multiple fracture sets and their intersection to mimic real fracture networks on a plain structured mesh. Here, we utilize the unified Hagen–Poiseuille-type equation to compute the permeability of tight gas, and finally adopt Newton–Raphson iteration method to solve the highly nonlinear equations. Numerical results illustrate that XFEM is considerably effective in fast calculation of gas flow in fractured porous media.

scholarly journals PorePy: an open-source software for simulation of multiphysics processes in fractured porous media

2020 ◽  
Author(s):  
Eirik Keilegavlen ◽  
Runar Berge ◽  
Alessio Fumagalli ◽  
Michele Starnoni ◽  
Ivar Stefansson ◽  
...  
Keyword(s):  
Porous Media ◽  
Open Source ◽  
Open Source Software ◽  
Fractured Rocks ◽  
Fractured Reservoirs ◽  
Simulation Software ◽  
Coupled Processes ◽  
Fracture Networks ◽  
Flow And Transport ◽  
Multiphysics Problems

Abstract Development of models and dedicated numerical methods for dynamics in fractured rocks is an active research field, with research moving towards increasingly advanced process couplings and complex fracture networks. The inclusion of coupled processes in simulation models is challenged by the high aspect ratio of the fractures, the complex geometry of fracture networks, and the crucial impact of processes that completely change characteristics on the fracture-rock interface. This paper provides a general discussion of design principles for introducing fractures in simulators, and defines a framework for integrated modeling, discretization, and computer implementation. The framework is implemented in the open-source simulation software PorePy, which can serve as a flexible prototyping tool for multiphysics problems in fractured rocks. Based on a representation of the fractures and their intersections as lower-dimensional objects, we discuss data structures for mixed-dimensional grids, formulation of multiphysics problems, and discretizations that utilize existing software. We further present a Python implementation of these concepts in the PorePy open-source software tool, which is aimed at coupled simulation of flow and transport in three-dimensional fractured reservoirs as well as deformation of fractures and the reservoir in general. We present validation by benchmarks for flow, poroelasticity, and fracture deformation in porous media. The flexibility of the framework is then illustrated by simulations of non-linearly coupled flow and transport and of injection-driven deformation of fractures. All results can be reproduced by openly available simulation scripts.

A Proposed Model for Multiphase Flow Through Naturally Fractured Reservoirs

1982 ◽  
Vol 22 (05) ◽  
pp. 669-680 ◽  
Author(s):  
Ronald D. Evans
Keyword(s):  
Porous Media ◽  
Fractured Rock ◽  
Fractured Reservoirs ◽  
Fractured Porous Media ◽  
Naturally Fractured Reservoirs ◽  
Fracture Flow ◽  
Rock Matrix ◽  
Porous Rock ◽  
Matrix Blocks ◽  
Flow Through

Abstract A general mathematic model is derived that may be used to describe fluid movement through naturally fractured reservoirs. The model treats the reservoir as a double-porosity medium consisting of heterogeneous isotropic primary rock matrix blocks and an anisotropic. heterogeneous fracture matrix system. The fractured are assumed to have a general distribution in space and orientation called the fracture matrix function to represent their statistical nature. Simplifying assumptions are made concerning flow in individual fractures and a hemispherical volume integration of microscopic fracture flow equations is performed to arrive at a generalized Darcy-type equation, with a symmetric permeability tensor evolving to describe the flow in the fracture evolving to describe the flow in the fracture matrix. For flow in the primary rock matrix blocks. Darcy's law for an isotropic medium is assumed. Time-dependent porosity equations for the primary rock matrix and the fractures are derived and coupled with the conservation of mass principle for each system to arrive at a governing set of continuity equations. Each resulting continuity equation is coupled further by a fluid interaction term that accounts for fluid movement that can take place between rock matrix blocks and fractures. The resulting equations of continuity and the equations of motion are generalized for multiphase flow through the fractured medium with variable rock and fluid properties. To complete the model formulation, a general set of auxiliary equations are specified, which can be simplified to fit a particular application. Introduction Flow of fluid in fractured porous media was recognized first in the petroleum industry in the 1940's. Since that time, many researchers have added to the volume of literature on fractured media. An extensive bibliography on flow in fractured porous media is given in Ref. 1. When attempting to model fluid flow through any type of medium, the researcher must decide which kinds of fluids and the type of flow to model. In the case of fractured porous media where most of the flow takes place through fractures, the flow can become truly turbulent. However, as demonstrated for many encounters with fracture flow, the laminar flow regime probably prevails. The development of fracture flow models has proceeded along two different approaches: the statistical and the fractured rock mass is considered a statistically homogeneous medium consisting of a combination of fractures and porous rock matrix. The fractures are considered ubiquitous, and the system is called statistically homogeneous because the probability of finding a fracture at any given point in the system is considered the same as fining one an any other point. In the enumerative approach, a fractured rock medium is studied by attempting to mode the actual geometry of fractures and porous rock matrix. The locations, orientation, and aperture variations for each individual fracture must be considered in this approach. Statistical Approach Many researchers have developed models with the statistical approach. Elkins and Skov used this approach to study anisotropic fracture permeability associated with Spraberry field, TX. Considering the extensive system of orthogonal vertical joints as an anisotropic medium, from a number of drawdown tests they were able to construct permeability ellipsoids whose axes were aligned reasonably well with the observed fractured system. This is called a "one-medium statistical model" because flow in the porous rock matrix was not considered. A two-medium statistical model for transient flow in a fractured rock medium was developed by Barenblatt et al. SPEJ P. 669^

A New Approach to the Modeling of Hydraulic-Fracturing Treatments in Naturally Fractured Reservoirs

SPE Journal ◽  
2017 ◽  
Vol 22 (04) ◽  
pp. 1064-1081 ◽  
Author(s):  
Sanbai Li ◽  
Dongxiao Zhang ◽  
Xiang Li
Keyword(s):  
Tensile Strength ◽  
Hydraulic Fracturing ◽  
Fractured Reservoirs ◽  
Fracture Network ◽  
Injection Rate ◽  
Naturally Fractured Reservoirs ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Stress Anisotropy ◽  
Naturally Fractured

Summary A fully coupled thermal/hydromechanical (THM) model for hydraulic-fracturing treatments is developed in this study. In this model, the mixed finite-volume/finite-element method is used to solve the coupled system, in which the multipoint flux approximation L-method is used to calculate interelement fluid and heat flux. The Gu et al. (2011) crossing criterion is extended to a 3D scenario to delineate the crossing behaviors as hydraulic fractures meet inclined natural fractures. Moreover, the modified Barton et al. (1985) model proposed by Asadollahi et al. (2010) is used to estimate the fracture aperture and model the shear-dilation effect. After being (partially) verified by means of comparison with results from the literature, the developed model is used to investigate complex-fracture-network propagation in naturally fractured reservoirs. Numerical experiments show that the key factors controlling the complexity of the induced-fracture networks include stress anisotropy, injection rate, natural-fracture distribution (fracture-dip angle, strike angle, spacing, density, and length), fracture-filling properties (the degree of cementation and permeability), fracture-surface properties (cohesion and friction angle), and tensile strength of intact rock. It is found that the smaller the stress anisotropy and/or the lower the injection rate, the more complex the fracture network; a high rock tensile strength could increase the possibility of the occurrence of shear fractures; and under conditions of large permeability of fracture filling combined with small cohesive strength and friction coefficient, shear slip could become the dominant mechanism for generating complex-fracture networks. The model developed and the results presented can be used to understand the propagation of complex-fracture networks and aid in the design and optimization of hydraulic-fracturing treatments.

scholarly journals A semi-analytical two-phase flow model of fractured horizontal well with complex fracture networks in natural fractured reservoirs

2021 ◽  
pp. 014459872110417
Author(s):  
Mengmeng Li ◽  
Gang Bi ◽  
Yu Shi ◽  
Kai Zhao
Keyword(s):  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Flow Regimes ◽  
Dual Porosity ◽  
Phase Flow ◽  
Fracture Networks ◽  
Two Phase ◽  
Secondary Fracture ◽  
Complex Fracture ◽  
Main Fracture

Complex fracture networks are easily developed along the horizontal wellbore during hydraulic fracturing. The water phase increases the seepage resistance of oil in natural fractured reservoir. The flow regimes become more intricate due to the complex fractures and the occurrence of two-phase flow. Therefore, a semi-analytical two-phase flow model is developed based on the assumption of orthogonal fracture networks to describe the complicate flow regimes. The natural micro-fractures are treated as a dual-porosity system and the hydraulic fracture with complex fracture networks are characterized explicitly by discretizing the fracture networks into multiple fracture segments. The model is solved according to Laplace transformation and Duhamel superposition principle. Results show that seven possible flow regimes are described according to the typical curves. The major difference between the vertical fractures and the fracture networks along the horizontal wellbore is the fluid “feed flow” behavior from the secondary fracture to the main fracture. A natural fracture pseudo-radial flow stage is added in the proposed model comparing with the conventional dual-porosity model. The water content has a major effect on the fluid total mobility and flow capacity in dual-porosity system and complex fracture networks. With the increase of the main fracture number, the interference of the fractures increases and the linear flow characteristics in the fracture become more obvious. The secondary fracture number has major influence on the fluid feed capacity from the secondary fracture to the main fracture. The elastic storativity ratio mainly influences the fracture flow period and inter-porosity flow period in the dual-porosity system. The inter-porosity flow coefficient corresponds to the inter-porosity flow period of the pressure curves. This work is significantly important for the hydraulic fracture characterization and performance prediction of the fractured horizontal well with complex fracture networks in natural fractured reservoirs.

scholarly journals Study on Stress-Dependent Permeability of Fracture Networks in Fractured Porous Media

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-19
Author(s):  
Yueli Feng ◽  
Yuetian Liu ◽  
Gang Lei
Keyword(s):  
Porous Media ◽  
Analytical Model ◽  
Effective Stress ◽  
Principal Direction ◽  
Fractured Porous Media ◽  
Fracture Aperture ◽  
Fracture Networks ◽  
Equivalent Permeability ◽  
Principal Value ◽  
Stress Dependent

In order to investigate the stress-sensitive characteristics of fracture networks under reservoir actual stress condition and its influence on the seepage in fractured porous media, we carried out permeability tests on experimental models with fracture networks under constant-volume boundary condition. In addition, a novel analytical stress-dependent permeability model of fracture networks in different directions was derived. Based on the test results and the proposed analytical model, the effects of various parameters (e.g., initial fracture aperture, fluid pressure, rock elastic modulus, effective-stress coefficient, and fracture dip) on deformation characteristics of fracture networks and the corresponding permeability tensor of fracture networks were studied. The research results show that, for a fractured porous media with a single group of fractures, the principal value of permeability is always parallel to the fracture-development direction. With increasing effective stress, the principal value of permeability decreases; however, the principal value direction remains unchanged. Moreover, for the fractured porous media with multiple sets of fractures, the principal direction of equivalent permeability will be inclined to the fractures with larger fracture aperture. Specifically, for the fractured porous media with two sets of intersecting fractures, the principal direction of equivalent permeability is parallel to the angular bisector of these two sets of intersecting fractures. Furthermore, the greater the difference of the fracture aperture change rate under effective stress, the more obvious the deviation of the permeability principal direction. The derived analytical model is of great theoretical and scientific significance to deepen the understanding of the stress-sensitive permeability of fractured reservoirs.

Optimization-Based Unstructured Meshing Algorithms for Simulation of Hydraulically and Naturally Fractured Reservoirs With Variable Distribution of Fracture Aperture, Spacing, Length, and Strike

2015 ◽  
Vol 18 (04) ◽  
pp. 463-480 ◽  
Author(s):  
Jianlei Sun ◽  
David Schechter
Keyword(s):  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Natural Fracture ◽  
Fracture Networks ◽  
Complex Fracture ◽  
Naturally Fractured ◽  
Unstructured Meshing ◽  
Domain Discretization ◽  
Aperture Distribution ◽  
Spacing Length

Summary Multistage hydraulically fractured wells are applied widely to produce unconventional resource plays. In naturally fractured reservoirs, hydraulic-fracture treatments may induce complex-fracture geometries that one cannot model accurately and efficiently with Cartesian and corner-point grid systems or standard dual-porosity approaches. The interaction of hydraulic and naturally occurring fractures almost certainly plays a role in ultimate well and reservoir performance. Current simulation models are unable to capture the complexity of this interaction. Generally speaking, our ability to detect and characterize fracture systems is far beyond our capability of modeling complex natural-fracture systems. To evaluate production performance in these complex settings with numerical simulation, fracture networks require advanced meshing and domain-discretization techniques. This paper investigates these issues by developing natural-fracture networks with fractal-based techniques. After a fracture network is developed, we demonstrate the feasibility of gridding complex natural-fracture behavior with optimization-based unstructured meshing algorithms. Then we can demonstrate that one can simulate natural-fracture complexities such as variable aperture, spacing, length, and strike. This new approach is a significant step beyond the current method of dual-porosity simulation that essentially negates the sophisticated level of fracture characterization pursued by many operators. We use currently established code for fractal discrete-fracture-network (FDFN) models to build realizations of naturally fractured reservoirs in terms of stochastic fracture networks. From outcrop, image-log, and core analysis, it is possible to extract fracture fractal parameters pertaining to aperture, spacing, and length distribution, including center distribution as well as a fracture strike. Then these parameters are used as input variables for the FDFN code to generate multiple realizations of fracture networks mimicking fracture clustering and randomly distributed natural fractures. After incorporating hydraulic fractures, complex-fracture networks are obtained for further reservoir-domain discretization. To discretize the complex-fracture networks, a new mesh-generation approach is developed to conform to nonorthogonal and low-angle intersections of extensively clustered discrete-fracture networks with nonuniform aperture distribution. Optimization algorithms are adopted to reduce highly skewed cells, and to ensure good mesh quality around fracture tips, intersections, and regions of extensive fracture clustering. Moreover, local grid refinement is implemented with a predefined distance function to control cell sizes and shapes around and far away from fractures. Natural-fracture spacing, length, strike, and aperture distribution are explicitly gridded, thus introducing a new simulation approach that is far superior to dual-porosity simulation. Finally, initial sensitivity studies are performed to demonstrate both the capability of the optimization-based unstructured meshing algorithms, and the effect of aforementioned natural-fracture parameters on well performance. This study demonstrates how to incorporate a fractal-based characterization approach into the current work flow for simulating unconventional reservoirs, and most importantly solves several issues such as nonorthogonal intersections, extensive clustering, and nonuniform aperture distribution associated with domain discretization with unstructured grids for complex-fracture networks. The proposed meshing techniques for complex fracture networks can be easily implemented in existing preprocessing, unstructured mesh generators. The sensitivity study and the simulation runs demonstrate the importance of fracture characterization as well as uncertainties associated with naturally fractured reservoirs on well-production performance.

Sign in / Sign up

Export Citation Format

Share Document