Thermally-Induced Secondary Fracture Development in Shale Formations During Hydraulic Fracture Water Invasion and Clay Swelling
- Vena F. Eveline (PERTAMINA, Jakarta, Indonesia) | Laura P. Santos (Texas A&M University, College Station, Texas) | I. Yucel Akkutlu (Texas A&M University, College Station, Texas)
- Document ID
- Society of Petroleum Engineers
- SPE Europec featured at 81st EAGE Conference and Exhibition, 3-6 June, London, England, UK
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- secondary fracture, osmosis, clay swelling, micro-crack, thermal shock
- 1 in the last 30 days
- 141 since 2007
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Current 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.
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Yan, Q., C. Lemanski, Z. T. Karpyn 2015. Experimental investigation of shale gas production impairment due to fracturing fluid migration during shut-in time. Journal of Natural Gas Science and Engineering 24: 99–105. //www.sciencedirect.com/science/article/pii/S187551001500116X.