A novel approach to modelling of flow in fractured porous medium

summary:There are many problems of groundwater flow in a disrupted rock massifs that should be modelled using numerical models. It can be done via “standard approaches” such as increase of the permeability of the porous medium to account the fracture system (or double-porosity models), or discrete stochastic fracture network models. Both of these approaches appear to have their constraints and limitations, which make them unsuitable for the large- scale long-time hydrogeological calculations. In the article, a new approach to the modelling of groudwater flow in fractured porous medium, which combines the above-mentioned models, is described. This article presents the mathematical formulation and demonstration of numerical results obtained by this new approach. The approach considers three substantial types of objects within a structure of modelled massif important for the groudwater flow – small stochastic fractures, large deterministic fractures, and lines of intersection of the large fractures. The systems of stochastic fractures are represented by blocks of porous medium with suitably set hydraulic conductivity. The large fractures are represented as polygons placed in 3D space and their intersections are represented by lines. Thus flow in 3D porous medium, flow in 2D and 1D fracture systems, and communication among these three systems are modelled together

Fine Scale Simulation of Fractured Reservoirs: Applications and Comparison

Imperial Users onl

Impact of anisotropy and fracture density on the approximation of the effective permeability of a fractured rock mass using 2D models

Imperial Users onl

Geomechanically coupled modelling of fluid flow partitioning in fractured porous media.

Naturally fractured reservoirs are characterised with complex hydro-mechanical dynamics. In these reservoirs, hydrocarbons can be stored and produced from the rock matrix, the fracture network, or both. Normally the fracture network is depleted much faster than the matrix blocks due to its increased hydraulic conductivity; consequently, the recovery factor is low for these reservoirs. Additionally, the in-situ stress profile changes with reservoir depletion and affects fluid flow dynamics of the fractured reservoir. Therefore, dynamic characterisation of fractured reservoirs is considered a challenging task, responsible for inefficient exploitation of their reserves. This dissertation focuses on characterising matrix-fracture fluid flow partitioning subjected to variable overburden stress loading. Understanding of the matrix-fracture hydro-mechanical interaction would assist in developing optimum production plans to maximize recovery from fractured reservoirs. Initially, three different fracture implementation techniques - (1) simulating fracture as an equivalent porous medium; (2) implementing it as a sub-dimensional feature within the porous matrix; and (3) considering fracture domain as an open channel - were evaluated using a set of published laboratory core flooding data. The best fracture simulation approach was identified to be fracture implementation as an open channel interacting with matrix block. This approach takes into consideration the coupling of Darcy flow equation in the matrix domain to Navier-Stokes flow formulation in the fracture. The efficiency of this fracture simulation approach was significantly enhanced when coupled further with poro-elasticity physics and stress dependent permeability. In the next step, the coupled open channel fracture simulation approach was applied to perform a sensitivity analysis on the effect of all parameters of the governing equations on fracture and matrix flow. The results of this analysis were statistically analysed, with specific attention to the analytical formulation of the governing equations, to develop coupled empirical flow models for fracture and matrix. These empirical models incorporate both flow physics of matrix and fracture, as well as mechanical loading impacts. An analysed multiphase flow scenario demonstrated the compatibility of the coupled simulation approach with multiphase flow investigations in fractured porous media. A novel core flooding set-up, capable of separated fracture and matrix flow measurement, was designed and built to enable laboratory evaluation of the developed empirical models. This set-up enabled monitoring of pressure front within matrix and fracture, taking the advantages of several differential pressure transducers along the core plug length. Variation of the matrix and fracture flow in response to different stress loading scenarios was investigated in the laboratory. Furthermore, laboratory validation indicated that the matrix flow model is capable of predicting laboratory measurements with an acceptable accuracy; however, the fracture flow model seemed to need more improvement. Probable factors that could have caused inaccuracy in the fracture flow model were discussed and actions for improving it were recommended as an extension to this research. Application of the empirical models in fractured porous medium characterisation simulations reduces the coupling-related numerical complexities. The coupled empirical models can predict flow dynamics of fractured reservoirs under various stress regimes. They demand much less computational effort and, as they incorporate geometrical factors, they can be up-scaled conveniently. In terms of production planning for fractured reservoirs, the empirical models can assist engineers to manage matrix and fracture production efficiently based on overburden stress variations

Coupled geomechanics and transient multiphase flow at fracture-matrix interface in tight reservoirs.

Fractured hydrocarbon reservoirs play a significant role in the world economy and energy markets. Fluid injection (normally water) forces the hydrocarbons out of the reservoirs. Geomechanics, externally applied stress on the rock, play a significant role in the oil recovery from fractured reservoirs. Subsurface fluid injection modifies pore pressure and in-situ stresses locally. In response to the pressure/stress combined effects, the pores and fracture regions undergo deformation. Similarly, it is a well-known fact that pore volume significantly impacts the absolute and relative permeability of fractured tight reservoirs. The governing factors that characterize multiphase fluid flow mechanisms in naturally-fractured tight reservoirs - such as wellbore stability, CO2 sequestration and improved hydrocarbon recovery - are relative permeability and capillary pressure. Although the effects of geomechanical parameters on single-phase fluid flow in naturally-fractured tight reservoirs are well documented, the interdependence between geomechanical and multiphase flows are severely lacking. This study aims to bridge this knowledge gap using advanced numerical techniques, focusing on accurately capturing complex flow phenomena at the fracture-matrix interface to enhance the accuracy of predicting oil recovery from naturally-fractured tight reservoirs, leading towards more efficient operations and reduced costs. Extensive sets of numerical investigations have been carried out in the present study, using an advanced Computational Fluid Dynamics (CFD) solver, to accurately capture transient multiphase flow (oil and water) phenomena within naturally-fractured tight reservoirs. Special attention has been paid towards accurate multiphase flow modelling and characterisation at the fracture-matrix interface. The numerical models have been validated against Berea Sandstone experimental data. Two separate numerical models have been developed with the aim to identify the most appropriate modelling technique for accurate numerical predictions of multiphase flow in naturally-fractured tight reservoirs. These two models are based on duct flow theory and flow through porous medium theory, respectively, while the Brooks and Corey method has been utilised to compute fluid saturation, relative permeability and capillary pressure at the fracture-matrix interface. The results obtained show that the difference between the numerical and experimental results is 30% when duct flow model is considered, while it is 2.57% when porous medium is considered. In order to critically evaluate the dependence of multiphase flow on the geomechanical parameters of naturally-fractured tight reservoirs, a one-way FEACFD coupling scheme has been implemented in the present study, not taking into consideration the pore pressure. The effects of externally applied stress loading on the geomechanical (porosity and fracture aperture) and multiphase flow characteristics (permeability, capillary pressure, relative permeability and fluid saturation) at the fracture-matrix interface have been thoroughly analysed. For accurate modelling and numerical predictions in naturally-fractured tight reservoirs, a viscous loss term has been incorporated in the momentum-conservation equations. The numerical predictions from the one-way coupled model matches well with Clashach core flooding experimental data, with 9% average difference between the two. The results obtained clearly indicate that external stress loading has significant impact on the geomechanical and multiphase flow characteristics at the fracture-matrix interface. Finally, a novel numerical model has been developed based on the full coupling scheme, with the aim to enhance the accuracy of the numerical predictions regarding oil recovery from naturally-fractured tight reservoirs for efficient and cost effective operations. The porous elasticity interface is coupled with multiphase flow in porous media where the mass conservation of each phase, and an extended Darcy's equation, underpin multiphase flow characteristics. The fully coupled model takes into consideration the pore pressure and has been validated against Clashach core flooding experimental data. The developed model has been shown to significantly enhance the prediction accuracy from 9%, for one-way coupled model, to 4%, and has the ability to capture complex multiphase flow phenomena at the fracture-matrix interface. Moreover, the novel model accurately predicts the effects of geomechanical parameters on multiphase flow characteristics. It is envisaged that the novel fully coupled model developed in this study will pave the way for future scientific research in the area of geomechanical-fluid flow coupling for enhanced oil recovery in naturally-fractured tight reservoirs