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Experimental Investigation on Stress Dependent Permeability of Tight Gas Reservoirs: Case Study in Cooper Basin

Mohamad Zulhazri Iser and Wan Muhammad Syarafiz Wan Sulong - 2014

Australian School of Petroleum

University of Adelaide


Permeability in conventional reservoirs is an important rock property which is assumed to be constant during the production. However, for unconventional reservoirs such as tight gas, shale gas and coal seam gas, it is believed that permeability of these reservoirs may not be constant due to hydraulic fracturing, matrix shrinkage as well as the existence of microfractures and it is believed to be a function of effective stress (σ_e). In order to model permeability change, researchers tried to develop few models. Palmer & Mansoori succeeded developing this model for coal seam gas. However, this model should be investigated more on tight gas reservoirs. Terzaghi (1925) has introduced the equation below to investigate how pore pressure is affecting effective stress.

σ_e= σ_t- αp

From this equation, when the pore pressure is decreasing during the production life of reservoirs, the effective stress act on the reservoirs will increase and leads to the closure of pore throat or microfractures of the rock. Thus, significant modification to the porosity and permeability of the reservoirs will takes place. The changes in microfractures conductivity with changing effective stress occur due to the elasticity of the rock and shear dilation is one of the causes of this phenomenon, the phenomenon is called stress dependent permeability.

In this honours project, experimental investigation (laboratory work) is the key method to analyze if there is existence of stress dependent permeability for tight gas reservoirs in Cooper Basin. In order to prove stress dependent permeability, we use Mercury Injection Capillary Pressure (MICP) test to see the capillary pressure curves and pore throat sizes distribution of the rock in order to help us to identify the fundamental controls on the stress dependent permeability reservoir. We have tested two cores with MICP test and the results show that both of the core samples have a very narrow pore sizes distribution which suggests the possible existence of microfracture. The mercury will start to invade the core sample when the applied pressure is above 4000 psia for Core A and 900 psia for Core B. Drainage and imbibition curve shows that mercury is trapped inside the Core A during imbibition while in Core B show there is some withdrawal of mercury with 58.73% mercury still trapped inside the core. With high injection pressure is applied to the core, it is believed that microfracture inside the core starts to open and allow the invasion of mercury while during the imbibition, as the pressure is reduced, the microfracture starts to close and cause the mercury to remain trapped inside the core sample. With this behaviour, there is a possibility on the existence of stress dependent permeability in tight gas reservoir in Cooper Basin.

Finding of this investigation will contribute much for the development of the tight gas reservoirs especially for hydraulic fracturing design that suits better for tight gas reservoirs in Cooper Basin.


Australian School of Petroleum



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