Characterization of Critically Stressed Fractures Using Fluid-Flow Models for Naturally Fractured Reservoirs

2021 ◽  
Author(s):  
Osman H. Hamid ◽  
Reza Sanee ◽  
Gbenga Folorunso Oluyemi

Abstract Fracture characterization, including permeability and deformation due to fluid flow, plays an essential role in hydrocarbon production during the development of naturally fractured reservoirs. The conventional way of characterization of the fracture is experimental, and modeling approaches. In this study, a conceptual model will be developed based on the structural style to study the fracture distributions, the influence of the fluid flow and geomechanics in the fracture conductivity, investigate the stress regime in the study area. Understanding the fracture properties will be conducted by studying the fracture properties from the core sample, image log interpretation. 3D geomechanical models will be constructed to evaluate the fluid flow properties; the models consider the crossflow coefficient and the compression coefficient. According to the model results, the fracture permeability decreases with increasing effective stress. The degree of decline is related to the crossflow coefficient and the compression coefficient. Most of these reservoirs are mainly composed of two porosity systems for fluid flow: the matrix component and fractures. Therefore, fluid flow path distribution within a naturally fractured reservoir depends on several features related to the rock matrix and fracture systems' properties. The main element that could help us identify the fluid flow paths is the critical stress analysis, which considers the in-situ stress regime model (in terms of magnitude and direction) and the spatial distributions of natural fractures fluid flow path. The critical stress requires calculating the normal and shear stress in each fracture plane to evaluate the conditions for critical and non-critical fractures. Based on this classification, some fractures can dominate the fluid-flow paths. To perform the critical stress analysis, fracture characterization and stress analysis were described using a 3D stress tensor model capturing the in-situ stress direction and magnitude applied to a discrete fracture model, identifying the fluid flow paths along the fractured reservoir. The results show that in-situ stress rotation observed in the breakouts or drilling induce tensile fractures (DITFs) interpreted from borehole images. The stress regime changes are probably attributed to some influence of deeply seated faults under the studied sequence. the flow of water-oil ratio through intact rock and fractures with/without imbibition was modeled based on the material balance based on preset conceptual reservoir parameters to investigate the water-oil ratio flow gradients

Geofluids ◽  
2019 ◽  
Vol 2019 ◽  
pp. 1-14 ◽  
Author(s):  
Chuanyin Jiang ◽  
Xiaoguang Wang ◽  
Zhixue Sun ◽  
Qinghua Lei

We investigated the effect of in situ stresses on fluid flow in a natural fracture network. The fracture network model is based on an actual critically connected (i.e., close to the percolation threshold) fracture pattern mapped from a field outcrop. We derive stress-dependent fracture aperture fields using a hybrid finite-discrete element method. We analyze the changes of aperture distribution and fluid flow field with variations of in situ stress orientation and magnitude. Our simulations show that an isotropic stress loading tends to reduce fracture apertures and suppress fluid flow, resulting in a decrease of equivalent permeability of the fractured rock. Anisotropic stresses may cause a significant amount of sliding of fracture walls accompanied with shear-induced dilation along some preferentially oriented fractures, resulting in enhanced flow heterogeneity and channelization. When the differential stress is further elevated, fracture propagation becomes prevailing and creates some new flow paths via linking preexisting natural fractures, which attempts to increase the bulk permeability but attenuates the flow channelization. Comparing to the shear-induced dilation effect, it appears that the propagation of new cracks leads to a more prominent permeability enhancement for the natural fracture system. The results have particularly important implications for predicting the hydraulic responses of fractured rocks to in situ stress fields and may provide useful guidance for the strategy design of geofluid production from naturally fractured reservoirs.


1969 ◽  
Vol 9 (04) ◽  
pp. 451-462 ◽  
Author(s):  
H. Kazemi

Abstract An ideal theoretical model of a naturally fractured reservoir with a uniform fracture distribution, motivated by an earlier model by Warren and Root, has been developed. This model consists of a finite circular reservoir with a centrally located well and two distinct porous regions, referred to as matrix and fracture, respectively. The matrix has high storage, but low flow capacity; the fracture has low storage, but high flow capacity. The flow in the entire reservoir is unsteady state. The results of this study are compared with the results of the earlier models, and it has been concluded that major conclusions of Warren and Root are quite substantial. Furthermore, an attempt has been made to study critically other analytical methods reported in the literature. In general, it may be concluded that the analysis of a naturally fractured reservoir from pressure transient data relies considerably on the degree and the type of heterogeneity of the system; the testing procedure and test facilities are sometimes as important. Nevertheless, under favorable conditions, one should be able to calculate in-situ characteristics of the matrix-fracture system, such as pore-volume ratio, over-all capacity of the formation, total storage capacity of the porous matrix, and some measure of matrix permeability. Introduction The analysis of flow and buildup tests for obtaining in-situ characteristics of oil and gas reservoirs has received considerable attention in the past decade. Most of the available techniques result in reliable conclusions in macroscopically homogeneous reservoirs or in the homogeneous reservoirs with only certain types of induced and/or inherent heterogeneity (such as wellbore damage, etc.).


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