Australian contains one of the hottest granite on earth at reasonable drilling depth and Hot Dry Rock (HDR) geothermal energy is considered as a practical prospect in the future. This project aims to study the mechanical behaviours geothermal reservoir rock at the deeply buried earth. Temperature, pressure and fluid flow forms a complex mechanism that can be extremely differs from the surface rocks. A large amount of experimental works have carried out and the results will contribute information for the development of guidelines for engineering design at depth, including the rock physical property (mineralogy, grain size and porosity) dependence, temperature dependence and pressure dependence. Besides, a new multiphase high pressure and temperature controlled triaxial testing apparatus for geomaterials is designed and constructed in purpose of simulating the actual underground condition. This apparatus allows confining pressure up to 130 MPa, temperature up to 400 °C and fluid injection of 160 MPa, with axial loading capacity of 10 tonnes.


Shale reservoir has been proved to have large storage of energy resource. By the commonly-used hydraulic fracturing process, proppant is taking an essential role to keep the fracture open after pumping and its behaviour is strongly related to the hydraulic conductivity and production rate. However, several proppant impairment mechanisms, including proppant diagenesis, proppant embedment, proppant flowback and fine generation & migration, have strong detrimental effect on proppant behaviour, which directly causes the reduction fracture width and the subsequent influence on hydraulic conductivity and production rate. 

This study focus on major proppant impairment mechanisms to figure out the influence of different potential factors (like fracturing fluids, temperature, cyclic stress) on proppant behaviour. It is expected to achieve higher initial and lower reduction for both fracturing width and hydraulic conductivity by optimising the proppant behaviour.


Carbon dioxide (CO2) is one of the main greenhouse gases released to the atmosphere mainly from the burning of fossil fuels, such as coal, oil and natural gas, which currently supply around 85% of the world’s energy needs. Moreover, due to the low relative cost and abundance of fossil fuels, it is likely that fossil fuels will govern the economy for at least the next 25 to 50. Therefore, it is necessary to have proper CO2 emission control techniques to create a safer atmosphere for human beings. Geosequestration of carbon dioxide (CO2) in deep saline aquifers is one of the most feasible approaches to mitigate global warming. However, dissolution of injected CO2 in brine has some effects on chemical diffusion, failure strength and permeability in the reservoir rock. There is also a significant variation in the mineral composition of reservoir rock upon exposure to CO2, which changes the mineralogical and micrological structure of the rock mass and consequently changes the hydro-mechanical properties of the rock. Therefore, this research provides a comprehensive study of the potential changes in aquifer mechanical properties and permeability characteristics caused by injected CO2 under in situ conditions, highlighting the factors affecting the integrity of sedimentary rock properties.

In this research work, basically the following methods will be used;

  1. Laboratory experiments high temperature and high pressure tri-axial set up.
  2. Acoustic Emission (AE) to study crack propagation strength thresholds.
  3. Numerical modelling (COMSOL) to study the flow and strength behaviour of reservoir rock under different pressure and temperature conditions. These modelling results will be compared with laboratory experiments.
  4. Empirical modelling to improve the existing formula for reservoir rock failure strength, to suit deep underground conditions (pressure, temperature and fluid medium)


Today it has become a must requirement to have proper CO2 emission control techniques to create a safer atmosphere for human beings. Geosequestration of CO2 in deep saline aquifers is one of the promising measures due to its high storage capacity and ability to provide a longer life-span for the injected CO2. However, exposure to CO2 causes the mineral composition of the aquifer to be changed, which affects the mineralogical and micrological structure of the aquifer’s rock and consequently changes its flow and strength properties. Therefore, this study has been aimed to identify effect of CO2 sequestration on aquifers flow and mechanical properties with giving special consideration on the CO2 injection induced geo-chemical reactions in the aquifer.

This project is funded by Australian Research Council (ARC) and a high pressure core flooding apparatus (Fig:1) is used to determine the flow properties through Warwick sandstone cores taken from Brisbane Australia, as the representative of reservoir rock.. Either 25mm or 38mm in diameter rock cores up to 300 mm in length can be tested under in-situ temperature and stress conditions of deep saline aquifers (20 to 150oC temperature, up to 70 MPa overburden pressure and up to 42 MPa injection pressure). Injection of CO2, brine and water can be carried out either at a constant pressure or a constant flow rate conditions and the pressure development along the sample can be monitored. The preparation of samples and sample assembly which is placed in the core holder inside the oven of this apparatus has been shown in the Fig:2. Chemical reactions of sandstone samples are tested using SEM and XRD analysis conduct for the samples immerged in carbonated brine for long time period in pressure chambers.


In recent years, the extreme weather caused by global warming has induced a number of meteorological and environmental disasters. Geological storage of CO2 is widely accepted as an effective method for reducing greenhouse gas emissions. Suitable geological formations for CO2 capture and storage include saline aquifers, coal seams, and depleted oil/gas reservoirs. Saline aquifers are common worldwide and have great potential for CO2 storage. CO2 injection and storage in deep saline aquifers involves many types of phenomena, and the main trapping mechanisms in deep saline aquifers are stratigraphic and structural traps, residual gas traps, dissolution, mineral precipitation, and/or adsorption. CO2 injected into an aquifer will displace the brine but because of capillary forces, the groundwater will not be completely displaced by the injected CO2. This remnant water has an important influence on the potential capacity and security of geological storage reservoirs. Residual water saturation will not only have a strong influence on the residual gas traps but also diminish the trapping capacity of structural and stratigraphic traps. Therefore, it is essential to carefully investigate the properties of residual water to improve our understanding of the conditions relevant to those seen in deep saline acquires. We conduct core flooding experiments to define the kind of saline aquifers most suitable for the geological storage of CO2.


Shale gas has become a promising source of energy in recent years, especially in North America, giving rise to abundant of field applications and research. Compared with the oil or conventional gas reservoirs, shale reservoirs are usually deeper in depth, lower in permeability with higher clay content, resulting in its difficulty for exploration. Hydraulic fracturing is the most frequently used technique to stimulate the low-permeability shale reservoirs. And most of the fracturing fluids are water-based due to low cost. However the mechanism of the interaction between fracturing fluid and the gas-shale is not fully uncovered, like the fracture initiation and propagation, fracture geometry, evolution of reservoir permeability. Many field application results are unsatisfactory due to our poor understanding.

The effects of the hydro-fracturing is influenced by shale reservoir properties (TOC content, clay content, porosity and permeability, brittleness index), injection regime and in-situ stress field etc.. My PhD research concentrates on the optimization of fracture network formation based on hydro-fracturing. It involves to investigate the impacts of these influencing factors by literature review, lab tests and modelling, and to optimize the fracturing designs. The output of my research will contribute to the understanding of hydro-fracturing used in shale reservoirs and provide guidelines for the field trials.


The karst conduits and faults encountered in underground engineering maybe filled with various materials, such as clays, sands and gravels. The fluid flow and the mechanism of water inrush from these structures are ambiguous and complexity.

Water can diffusion in the clays with low permeability and flow in the sands with high permeability, whereas water fluid in the gravels maybe become turbulence flow. Different fluid laws, such as Darcy Law and Brinkman Equation, need be applied to describe the water fluid in these filling materials. In addition, the mechanisms of water inrush are also different. When the faults and karst conduits are filled with clays, the whole filling structure may be slipped under the high water pressure. When the faults and karst conduits are filled with sands, the filling structure would become instability whose modes may be similar to piping, contact scour and soil flow.

This project would develop a theory on the mechanism of water inrush from faults or karst conduits, as well as modify existing code and incorporated to the software. Especially, develop a software based on the MATLAB platform and the Lattice Boltzmann Method (LBM) to analyze the mechanism and process of water inrush. Compare the results derived by the developed software and others business software, such as COMSOL, UDEC and PFC, to verify the feasibility and accuracy of the developed software.


The widely used of hydraulic fracturing in unconventional gas reservoirs with ultra-low permeability has greatly increased the gas production. While there are two main problems associated with water-based fracturing fluid in shale reservoirs, formation damage and long cleanup time, which pose a threat to the shale gas production. In order to eliminate the disadvantages induced by viscous water-based fracturing fluid, liquid CO2 with very small viscosity has been successfully applied as a kind of fracturing fluid. As an inert gas, CO2 has little interaction with gas shale, so it effectively avoids the formation damage; and the gratification CO2 in reservoirs returns to the surface with a short cleanup time. The main aim is to investigate the performance of CO2 as a fracturing fluid in shale reservoirs and to compare the difference between water-based fluid and fluid CO2 in the fracturing effectiveness.


There is an enormous potential for power generation with geothermal energy however, at present commercial geothermal energy production is limited conventional geothermal resources. Enhanced or engineered geothermal systems (EGS) are considered unconventional geothermal resources which adapt engineering techniques to enhance the factors affecting geothermal energy production. Considering EGS systems, hot dry rock (HDR) systems are identified as potential geothermal resources which are primarily consist of granite with high temperature but very low permeability and little amount of stored fluid. Therefore stimulation techniques such as hydraulic fracturing, acid fracturing are adapted in order to enhance the permeability of the rock. Higher flow rate and thermodynamic efficiency of the circulation fluid determines the economics of the EGS. It is important to create interconnected fracture network with high transitivity for higher flow rate and sufficient residence time with contacting hot dry rocks. However, it is a real challenge to maintain both conditions together. Large volume of interconnected fracture network with small aperture and circulation fluid with favourable heat transmission characteristics is important to achieve this requirement. Considering the previous attempts of EGS development in the world, water has used as the fracturing and heat transmission fluid however, there are number of problems associated with water such as scarcity of water, contamination problems and higher solvent capacity of rock minerals at elevated temperatures which result reduction of fracture permeability with time. Therefore, non-water based fracturing fluids for reservoir stimulation has attracted geothermal community and supercritical CO2 has identified with favourable thermodynamic properties. Further, numerical simulations have confirmed that advantages of CO2 over water in terms of higher energy extraction rates. However, performs CO2 as fracturing fluid, geochemical issues as a result of aqueous solutions of CO2, structural changes associated with rock fluid interactions under geothermal conditions are poorly understood.

Therefore, this project aims to understand the coupled effects of hydro-thermo-mechanical and chemical behaviour of granite at geothermal conditions with hydraulic stimulation with water and super critical CO2 as a working fluid and further, to understand optimum conditions to enhance permeability with hydraulic stimulation with water and scCO2. This study is consist of a series of experimental works to address these issues; which utilize the newly developed advanced high pressure and high temperature tri-axial set up available in the 3GDeep Laboratory. Tri-axial experiments will be conducted for different granite rock, at various temperatures (20 to 300C), confining pressures (up to 150 MPa) and water and scCO2 injection pressures (up to 150 MPa) by simulating different geothermal conditions and rocks at different depths. In addition, to understand the chemical interactions between granite scCO2 and water at geothermal conditions, detail chemical and mineralogical study will be conducted with SEM, XRD, XRF and ICP-MS/ AES analysis. Also, the CT scanner and SEM analysis will be used to study the pore structure variation due to water and CO2 injection into the sample under various test conditions.

This knowledge is then used to develop theoretical and empirical equations for strength criteria and flow behaviour of fractured rock incorporating temperature and pressure influence. Firstly, a lab scale model will be developed to study the mechanical and flow behaviour of granite under tri-axial tests conditions and it will be extended to a more comprehensive coupled thermo-hydro-mechanical model which simulate the field condition. Findings of this study will contribute to unconventional EGS technology and Australian economy which seek novel approach for commercial EGS energy production.



Shale gas is an abundantly available natural gas around the world as well as in Australia and traditionally water based hydraulic fracturing is used to produce gas from deep shale plays. However, this practice fails to produce commercially viable amount of gas (Ex.: proppant, that are usually required to keep created fracture in open state, is hard to controlled by water based fracking fluids) and raises many environmental issues; large volume of fresh water consumption, and surface and ground water contamination. In this regards, foam based fracturing fluids provide solution to these problems through; a small volume of water consumption, low fluid loss,  reusable and recyclable, shear stable over a wide temperature range, low pressure drops due to friction and high capacity to transport proppants to deep and upper fracture surface. Generally foam based fluids consist with three major components; 1) external phase: water, alcohol and acid; 2) internal phase: Nitrogen and Carbon dioxide; 3) foaming surfactant to combined the two phases. Due to low water usage and high proppant carrying capacity, foam based hydraulic fracturing is environmental friendly as well as it is an economical solution for the shale gas extraction. The goal of this study is to investigate a new stimulation methodology for extraction of shale gas using foam based hydraulic fracturing.