A Generalized Varying Oil Compositions and Relative Permeability Screening Tool for Continuous Carbon Dioxide Injection in Naturally Fractured Reservoirs

2018 ◽  
Author(s):  
Hassan Hamam ◽  
Turgay Ertekin
Keyword(s):  
Carbon Dioxide ◽  
Relative Permeability ◽  
Screening Tool ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Carbon Dioxide Injection ◽  
Naturally Fractured

Numerical Investigation of Wettability Effects on Two-Phase Flow in Naturally Fractured Reservoirs Using Complex System Modelling Platform

2021 ◽  
Author(s):  
Mohammad Sedaghat ◽  
Hossein Dashti
Keyword(s):  
Complex System ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Wettability Alteration ◽  
System Modelling ◽  
Naturally Fractured ◽  
Relative Permeability Curves

Abstract Wettability is an essential component of reservoir characterization and plays a crucial role in understanding the dominant mechanisms in enhancing recovery from oil reservoirs. Wettability affects oil recovery by changing (drainage and imbibition) capillary pressure and relative permeability curves. This paper aims to investigate the role of wettability in matrix-fracture fluid transfer and oil recovery in naturally fractured reservoirs. Two experimental micromodels and one geological outcrop model were selected for this study. Three relative permeability and capillary pressure curves were assigned to study the role of matrix wettability. Linear relative permeability curves were given to the fractures. A complex system modelling platform (CSMP++) has been used to simulate water and polymer flooding in different wettability conditions. Comparing the micromodel data, CSMP++ and Eclipse validated and verified CSMP++. Based on the results, the effect of wettability alteration during water flooding is stronger than in polymer flooding. In addition, higher matrix-to-fracture permeability ratio makes wettability alteration more effective. The results of this study revealed that although an increase in flow rate decreases oil recovery in water-wet medium, it is independent of flow rate in the oil-wet system. Visualized data indicated that displacement mechanisms are different in oil-wet, mixed-wet and water-wet media. Earlier fracture breakthrough, later matrix breakthrough and generation and swelling of displacing phase at locations with high horizontal permeability contrast are the most important features of enhanced oil recovery in naturally fractured oil-wet rocks.

Tensor Analysis of the Relative Permeability in Naturally Fractured Reservoirs

SPE Journal ◽  
2019 ◽  
Vol 25 (01) ◽  
pp. 162-184
Author(s):  
Mohammad H. Sedaghat ◽  
Siroos Azizmohammadi ◽  
Stephan K. Matthäi
Keyword(s):  
Relative Permeability ◽  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Permeability Tensor ◽  
Absolute Permeability ◽  
Scalar Quantity ◽  
In Situ Conditions ◽  
Discrete Fracture ◽  
Naturally Fractured ◽  
The Absolute

Summary Fluid evidence shows that prediction of water breakthrough and oil recovery from fractured reservoirs cannot be performed accurately without upscaled relative permeability functions. Relative permeability is commonly assumed to be a scalar quantity, although the justification of that—specifically for naturally fractured reservoirs (NFRs)—is rarely attempted. In this study, we investigate the validity of this scalar-quantity assumption and how it affects fracture/matrix equivalent relative permeabilities, kri(Sw), achieved by a numerical simulation of unsteady-state waterflooding of discrete-fracture/matrix models (DFMs). Numerical determination of relative permeability requires a realistic model, a spatially adaptive simulation approach, and a sophisticated analysis procedure. To fulfil these requirements, we apply the discrete-fracture/matrix modeling to well-characterized outcrop analogs at the hectometer to kilometer scale. These models are parameterized with aperture and capillary entry pressure data, taking into account variations from fracture segment to segment, trying to emulate in-situ conditions. The finite-element-centered finite-volume method is used to simulate two-phase flow in the fractured rock, while also considering a range of wettability conditions from water-wet to oil-wet. Our results indicate that the fracture/matrix equivalent relative permeability is a weakly anisotropic property. The tensors are not necessarily symmetric, and the absolute-permeability tensor is the most influential factor, determining the level of anisotropy of kri. The anisotropy ratio (AR) changes with saturation, is influenced by the fracture/matrix-interface wetted area (Awf), and differs for each phase. In addition, the diagonal terms of the equivalent relative permeability tensor (krii), determined using our novel approach, can be different from those obtained using the assumption that kri is scalar. The magnitude of the difference is controlled by the absolute permeability, wettability, flow rate, and orientation of the fractures in the model. It is worth mentioning that the type and direction of imbibition can be determined by off-diagonal terms of the kri tensor. Furthermore, krii largely depends on the direction of the waterflood along the i-axis.

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