Fracture-matrix interactions during immiscible three-phase flow

Elfeel, Mohamed Ahmed; Al-Dhahli, Adnan; Geiger, Sebastian; Dijke, Marinus Izaak Jan Van

doi:10.1016/j.petrol.2016.02.012

Cited by 17 publications

(20 citation statements)

References 58 publications

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“…The gravity drainage process is one of the significant drive mechanisms in naturally fractured reservoirs, especially in the gas-oil system as a natural depletion or as a gravity-assisted process [9][10][11]. The contribution of the process has been evaluated qualitatively through the saturation profiles and the recovery speed.…”

Section: Discussionmentioning

confidence: 99%

“…It is represented by different physical phenomena such as diffusion, gravity drainage, imbibition, and capillarity, which are the main recovery mechanisms that control the flowing fluid between the matrix blocks and the surrounding fractures. In a gas-oil system, gravity drainage represents the major recovery mechanism in the reservoir during natural depletion or in gravity-assisted processes [9][10][11]. Therefore, it is necessary to understand the transfer function evolution before evaluating the effectiveness and performance of the various mathematical expressions of gravity drainage using the dual-porosity model.…”

Section: Introductionmentioning

confidence: 99%

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Gravity Drainage Mechanism in Naturally Fractured Carbonate Reservoirs; Review and Application

et al. 2019

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Gravity drainage is one of the essential recovery mechanisms in naturally fractured reservoirs. Several mathematical formulas have been proposed to simulate the drainage process using the dual-porosity model. Nevertheless, they were varied in their abilities to capture the real saturation profiles and recovery speed in the reservoir. Therefore, understanding each mathematical model can help in deciding the best gravity model that suits each reservoir case. Real field data from a naturally fractured carbonate reservoir from the Middle East have used to examine the performance of various gravity equations. The reservoir represents a gas–oil system and has four decades of production history, which provided the required mean to evaluate the performance of each gravity model. The simulation outcomes demonstrated remarkable differences in the oil and gas saturation profile and in the oil recovery speed from the matrix blocks, which attributed to a different definition of the flow potential in the vertical direction. Moreover, a sensitivity study showed that some matrix parameters such as block height and vertical permeability exhibited a different behavior and effectiveness in each gravity model, which highlighted the associated uncertainty to the possible range that often used in the simulation. These parameters should be modelled accurately to avoid overestimation of the oil recovery from the matrix blocks, recovery speed, and to capture the advanced gas front in the oil zone.

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Section: Discussionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Gravity Drainage Mechanism in Naturally Fractured Carbonate Reservoirs; Review and Application

et al. 2019

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“…Water-wet NFCRs are among the best examples of spontaneous capillary imbibition in nature (Peters, 2012). Many authors have assumed that fractures have small or negligible capillary pressure (Elfeel et al, 2016;Peters, 2012). At equilibrium condition, the capillary pressures in the fracture and matrix must be equal at their boundary (equation (64)).…”

Section: Discussionmentioning

confidence: 99%

New Semi‐Analytical Insights Into Stress‐Dependent Spontaneous Imbibition and Oil Recovery in Naturally Fractured Carbonate Reservoirs

Haghi

Chalaturnyk

Geiger

2018

Water Resources Research

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Fluid injection and withdrawal in a porous medium create changes in pore pressure that alter effective stresses within the medium. This leads to pore volume changes, which can be described by the poroelastic theory. These changes in pore volume can influence fluid flow processes, such as capillary diffusion and imbibition, potentially altering multiphase flow characteristics in subsurface reservoirs with a focus on oil recovery in the naturally fractured carbonate reservoirs. In this study, a semi‐analytical model is developed to analyze the impact of stress‐dependent spontaneous imbibition. The model allows us to study the influence of stress‐dependent effects on porosity, absolute permeability, relative permeability, and capillary pressure on the imbibition and oil recovery mechanisms of both intact rock and fracture in naturally fractured carbonate reservoirs. In order to capture the geomechanical interactions involved, pure compliance poroelastic definitions and nonlinear joint normal stiffness equations are used to assess the deformation of intact rock and fracture, respectively. The model shows that increasing effective confining stress shifts the imbibition capillary pressure curve upward, resulting in improved absorption of the wetting phase into the smaller pores and enhanced extraction of the nonwetting phase. Model calculations provide a rationale for how and why irreducible water saturation increases during compression of mixed‐wet carbonates and decreases in the case of initially strong water‐wet carbonates. It is also shown how higher relative permeability of the wetting phase leads to a greater diffusion of the wetting phase and improved oil recovery for the less deformed mixed‐wet rock.

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“…Hence, injected CO 2 can quickly travel through the fracture system, while its transfer to the rock matrix will occur at an usually slower time scale (Figure a). Fracture‐matrix transfer mechanisms were extensively studied through laboratory and numerical experiments (e.g., Ahmed Elfeel et al, ; Fernø et al, ; Lemonnier & Bourbiaux, ; Lu et al, ). Figure b summarizes the most relevant transfer mechanisms.…”

Section: Co2 Storage Dynamics In Nfr'smentioning

confidence: 99%

“…Most commercial simulators (e.g., Computer Modelling Group, ; Schlumberger, ) and scientific publications (e.g., Ahmed Elfeel et al, ; Al‐Kobaisi et al, ; Bech et al, ; Beckner et al, ) rely on the work of Gilman () to model gravity‐induced drainage transfer functions

{T_{w}, T_{n}}

(equation ), sometimes applying a discretization of the matrix blocks (Beckner et al, ; Pruess, ). These transfer functions model the matrix‐fracture flow as proportional to the potential difference between the two continua.…”

Section: Capacity and Drainage Time Scales For A Single Matrix Blockmentioning

confidence: 99%

Assessment of CO₂ Storage Potential in Naturally Fractured Reservoirs With Dual‐Porosity Models

March

Doster

Geiger

2018

Water Resources Research

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Naturally Fractured Reservoirs (NFR's) have received little attention as potential CO2 storage sites. Two main facts deter from storage projects in fractured reservoirs: (1) CO2 tends to be nonwetting in target formations and capillary forces will keep CO2 in the fractures, which typically have low pore volume; and (2) the high conductivity of the fractures may lead to increased spatial spreading of the CO2 plume. Numerical simulations are a powerful tool to understand the physics behind brine‐CO2 flow in NFR's. Dual‐porosity models are typically used to simulate multiphase flow in fractured formations. However, existing dual‐porosity models are based on crude approximations of the matrix‐fracture fluid transfer processes and often fail to capture the dynamics of fluid exchange accurately. Therefore, more accurate transfer functions are needed in order to evaluate the CO2 transfer to the matrix. This work presents an assessment of CO2 storage potential in NFR's using dual‐porosity models. We investigate the impact of a system of fractures on storage in a saline aquifer, by analyzing the time scales of brine drainage by CO2 in the matrix blocks and the maximum CO2 that can be stored in the rock matrix. A new model to estimate drainage time scales is developed and used in a transfer function for dual‐porosity simulations. We then analyze how injection rates should be limited in order to avoid early spill of CO2 (lost control of the plume) on a conceptual anticline model. Numerical simulations on the anticline show that naturally fractured reservoirs may be used to store CO2.

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Fracture-matrix interactions during immiscible three-phase flow

Cited by 17 publications

References 58 publications

Gravity Drainage Mechanism in Naturally Fractured Carbonate Reservoirs; Review and Application

Gravity Drainage Mechanism in Naturally Fractured Carbonate Reservoirs; Review and Application

New Semi‐Analytical Insights Into Stress‐Dependent Spontaneous Imbibition and Oil Recovery in Naturally Fractured Carbonate Reservoirs

Assessment of CO₂ Storage Potential in Naturally Fractured Reservoirs With Dual‐Porosity Models

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Fracture-matrix interactions during immiscible three-phase flow

Cited by 17 publications

References 58 publications

Gravity Drainage Mechanism in Naturally Fractured Carbonate Reservoirs; Review and Application

Gravity Drainage Mechanism in Naturally Fractured Carbonate Reservoirs; Review and Application

New Semi‐Analytical Insights Into Stress‐Dependent Spontaneous Imbibition and Oil Recovery in Naturally Fractured Carbonate Reservoirs

Assessment of CO2 Storage Potential in Naturally Fractured Reservoirs With Dual‐Porosity Models

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Assessment of CO₂ Storage Potential in Naturally Fractured Reservoirs With Dual‐Porosity Models