Thesis

Pore-scale dynamics of immiscible two-phase flow on porous and fractured media

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Awarding institution
  • University of Strathclyde
Date of award
  • 2019
Thesis identifier
  • T15369
Person Identifier (Local)
  • 201578086
Qualification Level
Qualification Name
Department, School or Faculty
Abstract
  • Pore-scale investigations of immiscible two-phase flow displacement dynamics in porous media provides crucial information to natural and industrial processes such as nonaqueous phase liquid (NAPL) contamination of groundwater, carbon dioxide injection and storage, and enhanced oil recovery (EOR) operations. It has the potential to transform our understanding of multiphase flow processes, to improve oil and gas recovery efficiency, and to facilitate safe carbon dioxide storage. However, the modelled porespace geometry is naturally complex for these fields of application. For directly simulating multiphase flow within the complex structure, the most widely-used approach isthe lattice Boltzmann method (LBM).In this thesis, the implementation of the state-of-the-art colour gradient two-phase LBMhas been validated against the theoretical solution for capillary filling, and analytical solutions for relative permeabilities in a cocurrent flow in a 2D channel. Then it is employed to investigate the effects of interfacial tension, wettability, and the viscosity ratio on displacement of one fluid by another immiscible fluid in a two-dimensional(2D) Berea sandstone.;Through invasion of the wetting phase into the porous matrix,it is observed that the viscosity ratio plays an important role in the non-wetting phase recovery. At the viscosity ratio (λ) of unity, the saturation of the wetting fluid is highest,and linearly increases with time. The displacing fluid saturation reduces drastically when λ increases to 20; however, when λ is beyond 20, the reduction becomes less significant for both imbibition and drainage. The front of the bottom fingers is finally halted at a position near the inlet as the viscosity ratio increases to 10. Increasing the interfacial tension generally results in higher saturation of the wetting fluid. Finally,the contact angle is found to have a limited effect on the efficiency of displacement in the 2D Berea sandstone. In addition, it has also been utilized to provide a better understanding of spontaneous imbibition, a key oil recovery mechanism in the fractured reservoir rocks. A pore-scale computational study of the water imbibition into an articially generated dual-permeability porous matrix with a fracture attached on top is conducted. Several factors affecting the dynamic counter-current imbibition processes and the resulting oil recovery have been analysed, including the water injection velocity, the geometry configuration of the dual permeability zones, interfacial tension, viscosity ratio of water to oil phases, and fracture spacing if there are multiple fractures.;By examining different water injection velocities and interfacial tensions, it is identified for the first time that the three distinct imbibition regimes exist: the squeezing regime, the jetting regime and the dripping regime, and they can be distinguished with different expelled oil morphologies in the fracture (piston-like plug, elongated liquid thread or isolated drops).The geometry configuration of the high and low permeability zones affects the amount of oil that can be recovered by the counter-current imbibition in a fracture-matrix system through transition of the different regimes. In the squeezing regime, which occurs at low water injection velocity, it is interestingly found that the built-up squeezing pressure upstream in the fracture enables more water to imbibe into the permeability zone closerto the fracture inlet thus increasing the oil recovery factor. A larger interfacial tension or a lower water-to-oil viscosity ratio is favorable for enhancing oil recovery and new insights into the effect of viscosity ratio are provided. Introducing an extra parallel fracture can effectively increase the oil recovery factor and there is an optimal fracture spacing between the two adjacent horizontal fractures to maximize the oil recovery.These findings can aid the optimal design of water-injecting oil extraction in fractured rocks in reservoirs of low permeability like oil-bearing shale or tight sandstone.We conclude that the pore-scale modelling can act as a reliable tool to assess andpredict oil and gas resources and facilitate more efficient oil and gas recovery
Advisor / supervisor
  • Zhang, Yonghao
  • Dempster, William
Resource Type
DOI
Date Created
  • 2019
Former identifier
  • 9912769990302996

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