Upscaling two-phase flow in naturally fractured reservoirs

AAPG Bulletin ◽  
2009 ◽  
Vol 93 (11) ◽  
pp. 1621-1632 ◽  
Author(s):  
Stephan K. Matthäi ◽  
Hamidreza M. Nick
Keyword(s):  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Phase Flow ◽  
Two Phase ◽  
Naturally Fractured

A MPFA-D Finite Volume Scheme for 2-D Simulation of Two-Phase Flow in Naturally Fractured Reservoirs Using a Lower-Dimensional Fracture Model

2017 ◽  
Author(s):  
Cavalcante, Túlio de M. ◽  
Angelim, Kelly C. L. ◽  
Brum, Braian S. ◽  
Contreras, Fernando R. L. ◽  
Lyra, Paulo R. M. ◽  
...  
Keyword(s):  
Finite Volume ◽  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Fracture Model ◽  
Finite Volume Scheme ◽  
Phase Flow ◽  
Two Phase ◽  
Volume Scheme ◽  
Lower Dimensional

Numerical Simulation of Water-Oil Flow in Naturally Fractured Reservoirs

1976 ◽  
Vol 16 (06) ◽  
pp. 317-326 ◽  
Author(s):  
H. Kazemi ◽  
L.S. Merrill ◽  
K.L. Porterfield ◽  
P.R. Zeman
Keyword(s):  
Finite Difference ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Phase Flow ◽  
Two Phase ◽  
Flow Equations ◽  
Difference Grid ◽  
Naturally Fractured ◽  
Matrix Blocks ◽  
The Matrix

Abstract A three-dimensional, multiple-well, numerical simulator for simulating single- or two-phase flow of water and oil is developed for fractured reservoirs. The simulator equations are two-phase flow extensions of the single-phase flow equations derived by Warren and Root. The simulator accounts for relative fluid mobilities, gravity force, imbibition, and variation in reservoir properties. The simulator handles uniformly and nonuniformly properties. The simulator handles uniformly and nonuniformly distributed fractures and for no fractures at all. The simulator can be used to simulate the water-oil displacement process and in the transient testing of fractured reservoirs. The simulator was used on the conceptual models of two naturally fractured reservoirs: a quadrant of a five-spot reservoir and a live-well dipping reservoir with water drive. These results show the significance of imbibition in recovering oil from the reservoir rock in reservoirs with an interconnected fracture network. Introduction Numerical reservoir simulators are being used extensively to simulate multiphase, multicomponent flow in "single-porosity" petroleum reservoirs. Such simulators generally cannot be used to petroleum reservoirs. Such simulators generally cannot be used to study flow behavior in the naturally fractured reservoirs that are usually classified as double-porosity systems. In the latter, one porosity is associated with the matrix blocks and the other porosity is associated with the matrix blocks and the other represents that of the fractures and vugs. If fractures provide the main path for fluid flow from the reservoir, then usually the oil from the matrix blocks flows into the fracture space, and the fractures carry the oil to the wellbore. When water comes in contact with the oil zone, water may imbibe into the matrix blocks to displace oil. Combinations of large flow rates, low matrix permeability, and weak imbibition may result in water fingering permeability, and weak imbibition may result in water fingering through the fractures into the wellbore. Once fingering of water occurs, the water-oil ratio may increase to a large value. None of the published theoretical work on multiphase flow in naturally fractured systems has been applied directly to the simulation of a reservoir as a whole. Usually, only a segment of the reservoir was simulated, and the results were extrapolated to the entire reservoir. To simulate a reservoir as a whole, we have developed a mathematical formulation of the flow problem that has been programmed as a three-dimensional, compressible, water-oil reservoir simulator. The simulator equations are two-phase flow extensions of the single-phase flow equations derived by Warren and Root. The theory is based on the assumption of double porosity at each point in a manner that the fractures form a continuum filled by the noncontinuous matrix blocks. In other words, the fractures are the boundaries of the matrix blocks. The flow equations are solved by a finite difference method. A typical finite-difference grid cell usually contains one or several matrix blocks. In this case, all the matrix blocks within the finite-difference grid cell have the same pressure and saturation. Gravity segregation within individual matrix blocks is not calculated, but the over-all gravity segregation from one grid cell to another is accounted for. In many practical problems, this approximation is acceptable. In some situations, a matrix block encloses several finite-difference grid cells. In this case, the gravity segregation within the matrix block is calculated. To include heterogeneity, a redefinition of local porosities and permeabilities provides a method for simulating situations where part of the reservoir is fractured and where part is not fractured. The above description points to the complexity of the situations that one encounters. Therefore, the judicious choice of the number of finite difference grid cells with respect to the number of matrix blocks becomes a critical engineering decision. Later sections will provide insight to alleviate such decisions. SPEJ P. 317

Numerical simulation of gas-liquid two-phase flow in the micro-fracture networks in fractured reservoirs

2021 ◽  
pp. 104101
Author(s):  
Xin Huang ◽  
Liehui Zhang ◽  
Ruihan Zhang ◽  
Xuezhong Chen ◽  
Yulong Zhao ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Phase Flow ◽  
Fracture Networks ◽  
Two Phase

Heat Transfer and Two-Phase Flow in Fractured Reservoirs

1992 ◽  
Author(s):  
Sumit Mukhopadhyday ◽  
Muhammad Sahimi
Keyword(s):  
Heat Transfer ◽  
Two Phase Flow ◽  
Fractured Reservoirs ◽  
Phase Flow ◽  
Two Phase

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.

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