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A two-phase flow theory for thermal-moisture-hydro-mechanical multi-physical coupling in fractured shale

Wang, H ORCID: 0000-0002-3188-3433 2021 , 'A two-phase flow theory for thermal-moisture-hydro-mechanical multi-physical coupling in fractured shale', PhD thesis, University of Tasmania.

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Abstract

Gas-liquid two-phase flow widely exists in nature and industrial processes. Due to the characteristics of non-linear flow, the complexity of the coupling process and the non-uniformity, the two-phase flow is a basic theoretical problem that needs further study. In energy engineering, the flow process in shale gas production and CO2 geological storage has an opposite target but shares the same scientific problem: two-phase flow coupling with multi-physical processes in the fractured shale. Therefore, a two-phase flow theory coupling with a multi-physical model in porous media with structural complexity should be developed for the fractured shale. This theory can reveal the flow mechanism of shale gas flowback and CO2 storage and thus this research is of important scientific background and engineering significance. In this thesis, experimental study, theoretical modelling and numerical simulations are integrated to investigate the thermal-moisture-hydro-mechanical coupling mechanisms. The model is verified using field data and compared with other conventional models. It is expected that the research outcomes can provide better theoretical guidance for engineering applications.
The shale immersion tests were conducted to reveal the variations of shale composition, surface morphology, internal pore structure and tensile strength under acid-base deterioration. First, the tests of dissolution effect on shale with three solutions were conducted. X-ray diffraction (XRD) was used to semi-quantitatively analyze the change of mineral composition. Results showed that the dissolution effect of three solutions on shale ranked: alkaline solution>acid solution>distilled water. Then the field emission electron microscopy (FE-SEM) was used to observe the change of shale surface morphology. It was found that the water-rock reaction had a significant impact on the shale surface morphology and mainly concentrated on micron-scale cracks and inter-particle pores. The adsorption experiments with nitrogen and CO2 were conducted to qualitatively analyze the internal microscopic pore structure of shale, and to quantitatively describe the fractal characteristics of pore size distributions. Finally, the Brazilian splitting experiment further revealed the change in the mechanical properties of shale under acid-base degradation. The average tensile strength of shale dropped significantly after being soaked in distilled water, reaching 27.4%.
A novel gas-water relative permeability fractal model was then derived by considering pore-structure parameters (pore-size distribution fractal dimension and tortuosity fractal dimension), water film, geometric correction factor, and real gas effect. This model was verified by comparing with two classic relative permeability models and several sets of experimental data. The effects of pore structure parameters, water film, geometric correction factors and real gas effects on the gas-water relative permeability were explored in detail. Results showed that the pore size distribution determined the flow pattern and the fractal dimension of the pore size distribution had more significant impacts on the change of gas-water effective permeability. The pore geometry directly affected the gas flow mechanism. When the irregularity of pore geometry increased, the Knudsen number decreased, the collision between gas molecules was strengthened, and the gas flow was gradually transitioned into a continuous medium flow.
A three-zone model with multi-scale flow-diffusion was further proposed to investigate the effect of water-based fracturing fluid on shale gas production. The effects of fracture parameters (such as fracture spacing, fracture width, fracture uniformity, and fracture geometry) on shale gas production were investigated. The contribution of multi-scale flow-diffusion and the gas exchange rate in different zones to shale gas production were carefully studied. It was found that the cumulative shale gas production of this two-phase flowback model decreased by 58.2% after the initial stage of flowback (230 days in our example). The permeability of the micro-fractures in the matrix gradually increased and approached the permeability of the fractured zone.
A moisture-hydro-mechanical multi-physical coupling model was established in shale gas flowback and the migration mechanism of water-based fracturing fluid after the two-phase flow stage was revealed. With the moisture transport, the effects of threshold pressure gradient under the residual water saturation, the water film evaporation on the fracture surface and the gas-liquid-solid mixed adsorption mechanism in the matrix were further investigated. It was found that the structure of the water film in the fracture was the main reason for the non-Darcy flow. The relationship of the gas adsorption decay coefficient, the water coverage factor and the amount of gas adsorption in the matrix was clarified.
A thermal-hydro-mechanical multi-physical coupling model was developed to investigate the coexistence of CO2 three phases in the CO2 critical-depth caprock. The effects of temperature and pressure on the sealing efficiency of a shallow caprock at the burial depth of 800 m were numerically studied. The physical properties of CO2 in the phase transition zone varying with gas partial pressure and formation temperature were discussed. By defining the CO2 penetration depth in the caprock, the sealing efficiency of the caprock was effectively evaluated. This study found that the CO2 penetration depth increased by 5.9% after considering the real gas effect in 400 years of storage.
The thermal effects (thermal stress and Joule-Thomson cooling) on the CO2 migration in deep saline aquifers were studied using the thermal-hydro-mechanical multi-physical and migration mechanisms. The variation of CO2 physical properties, the accumulation of pore pressure, adsorption expansion and thermal contraction were included in this porosity model. The evolution of temperature near the injection well was analyzed through the coupling of two-phase flow, porous medium deformation, heat transfer, and Joule-Thomson effect. Finally, the effect of capillary entry pressure on the distribution of CO2 plume was numerically investigated. The effect of injection boundary conditions on the CO2 accumulation pressure was explored. These results indicated that an appropriate injection rate was critical to the sealing efficiency of CO2 storage.

Item Type: Thesis - PhD
Authors/Creators:Wang, H
Keywords: Two-phase flow, multi-physical coupling, shale gas flowback, CO2 geological storage.
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Copyright 2021 the author

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