Thermally-Induced Secondary Fracture Development in Shale Formations During Hydraulic Fracture Water Invasion and Clay Swelling
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AbstractCurrent trends in shale gas industry require an advanced-level understanding of fracturing water invasion into formation and the subsequent water-shale interactions. Previously, we studied osmosis and clay swelling effects on the permeability of the shale formation. Shale, with an average 50% clay content, could hold large cation-exchange-capacity and significantly improved membrane efficiency, which may promote swelling and changes in the stress. In addition, large temperature-gradient effects due to cold water contacting the formation has not been investigated in detail.A new geomechanically-coupled reservoir flow simulator is developed, which accounts for cold freshwater imbibition, osmosis and clay-swelling effects on the formation permeability under stress. The model includes aqueous and gaseous phases with three components: water, gas and salt. Governing geomechanical equation includes pore-pressure as well as temperature gradients. Volumetric strain (porosity changes) is calculated as a function of the mean normal stress, pore pressure and temperature. Imbibition occurs in water-wet inorganic part of the matrix, in the micro-cracks. Osmosis and clay swelling effects develop when the imbibed water in the micro-cracks interacts with the saline water in clay pores, which acts as a semi-permeable membrane to the water and experiences pore (osmotic) pressure changes and swelling of the clay in the formation.The effect of temperature is pronounced early during the shut-in when imbibition of cold water takes place rapidly. Cold water introduces a low-stress region near the fracture due to thermal expansion effect and pore pressure buildup. We used a criterion and discuss the potential for fracturing. It is anticipated that the fracturing develops during forced imbibition of cold water given that a large difference exists between the injected water and the formation temperatures.
