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

A slickwater treatment fluid has often been adopted in the past 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 formation). While this might work for some 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 a slickwater, linear, or crosslinked gel. Similarly, analysis of formation softening using Brinell hardness testing and proppant embedment testing will help ensure the formation does not completely close on treatment completion and will have conductive flow channels. The formation rock, proppant, and fracturing fluid interaction can also result in diagenetic growth on proppant and formation faces, resulting in formation softening and large decrease in fracture conductivity. This paper describes test processes involving fluid sensitivity tests, formation softening, and rock mechanical tests, and compares data from a few representative shales to demonstrate the impact of choosing the proper fluid formulation for hydraulic fracturing.

This paper focusses on careful optimization of the stimulation fluid based on rock parameters to help ensure prolonged production in tight-oil and gas shale plays.

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