Production from shale reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. Cumulative experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. Nevertheless, shale reservoirs still bring challenges to stimulation engineers, due to the complex physics involving interactions with natural fractures, stress shadow effects and proppant transport in complex fracture network.

One of the challenges regards fluid and proppant selection, in particular, the issue is how to achieve the desired fracturing fluid viscosity inside the fracture for optimum proppant placement into an expanding complex fracture network. The rheological properties of the fracturing fluid depend on its temperature history, hence understanding the temperature distribution in the hydraulic fracture network is a key consideration for a successful treatment and a more accurate fracture prediction.

This paper investigates the relation between reservoir temperature, fracturing fluid properties and production through fracturing-to-production simulation workflow. The paper first presents a temperature model implemented into the UFM model, which is a comprehensive complex fracturing simulator for shale reservoirs, accounting for interaction with natural fractures, stress shadow effects, and proppant transport in a complex networks. Based on the fracture geometry, proppant placement, and reservoir properties, a semi-analytical production model UPM is used to estimate the production.

This workflow is used to first understand the temperature distribution in the expanding fracture network and understand its evolution as a function of several parameters such as reservoir temperature and rheological properties of the fracturing fluid. Then the associated production forecast provides guidelines on how to achieve optimum proppant and fluid selection based on the reservoir temperature for maximizing production.

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