For low-permeability formations, such as oil- and gas-bearing shales, hydraulic fracturing stimulation is a requisite to obtain commercial production. One of the key parameters for ensuring successful stimulation and prolonged production is the proper selection of stimulation fluid. The selection and optimization of the fracturing fluid is greatly dependent on the reservoir rock properties as well as the formation softening resulting from fluid-formation interaction.

In the past, slickwater treatment fluids often were adopted in tight shale plays for creating a complex fracture network for maximum production yield. Most often, the slickwater recipe is driven by formation fluid sensitivity analysis (e.g., effect of fresh water, salt, or acids on the formation). While this might work for a few formations, the rock mechanical properties, such as Young's modulus and Poisson's ratio, will determine the fracability and whether it is advantageous to use slickwater, linear gel, or crosslinked gel. Similarly, formation softening analysis using a Brinell hardness test and proppant embedment test will ensure that the formation does not close upon fluid treatment and will have conductive flow channels. This paper discusses the impact of different types of fracturing fluids on different shale formations. The paper also discusses processes involving fluid sensitivity tests, formation softening, and rock mechanical tests and shows their influence on the choice of the proper fluid formulation for hydraulic fracturing through data from a few test samples.

The formation rock, proppant, and fracturing fluid interaction can also cause diagenetic growth on proppant and formation faces, resulting in formation softening and a large decrease in fracture conductivity. This paper focusses on careful selection of the stimulation fluid based on rock parameters to ensure prolonged production in tight oil and gas shale plays.

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