(333d) Modeling Fracture Propagation and Fluid Flowback in Hydraulic Fractures Created Using High Viscosity Shear Thinning Gels

The contribution of shale gas to the total natural gas production in United States continues to increase. Nonetheless, the growing demand for natural gas calls for further increase in production of hydrocarbons from unconventional reservoirs, which is currently being carried out using hydraulic fracturing process^[1]. Amongst the numerous parameters that govern the production of shale gas from a fractured reservoir, the crucial ones are average fracture conductivity and propped fracture length. But the use of slick water as fracturing fluid produces fractures with low average fracture conductivity and low propped fracture length. These limitations of slick water can be overcome by using Non-Newtonian gels as fracturing fluids^[2-3].

The use of high viscosity Non- Newtonian gels as fracture fluid has many advantages like higher average fracture conductivity, longer propped fracture length and low wastewater production^[4]. While the most commonly used polymer gels in hydraulic fractures are shear-thinning fluids, there are some common drawbacks associated with these gels. These gels penetrate into the formation causing formation damage^[5-6]. The low shear rate at the fracture surface causes these gels to form a filter cake at the fracture face causing fracture damage^[7-8]. Also, the high yield stress of these gels makes their flowback during oil and gas production very difficult^[9-10]. Nonetheless, effective production of oil and gas from these fractures can still be obtained if proper flow back of the gel occurs at the inception of hydrocarbon production. Therefore, modeling fluid flow back in these damaged fractures is essential for production planning of unconventional fractured reservoirs.

In this work, a fracture propagation model was first developed by considering the Non-Newtonian flow of shear-thinning fluid inside the fracture. The proppant loading along with the proppant settling velocities were obtained from experimental results^[11]. The fracture geometry and fracture damage were obtained for a specified operation time from the model, which were then used as the initial condition to a flowback model to describe the flow of reservoir fluids in the fracture. The flowback model was then validated with experimental results obtained for shear-thinning fluids. The application of such a Non-Darcy flow model where a Non-Newtonian fluid displaces a Newtonian fluid is useful in predicting the oil and gas production from unconventional fractured reservoirs under formation damage. Finally, a sensitivity analysis was performed with respect to the power-law index and coefficient of the viscosity equation to determine the optimal viscosity of the gel to be used for achieving the maximum fluid flowback amount.

Literature Cited:

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[11] Yegin, Cengiz, et al. “Novel Hydraulic Fracturing Fluids with Improved Proppant Carrying Capacity and PH-Adjustable Proppant Deposition Behavior.” Journal of Petroleum Science and Engineering, vol. 145, 2016, pp. 600–608.