Development of a halite dissolution numerical model for hydraulically fractured shale formations (Part I)

Gas-shales are gas bearing organic-rich mudstone with extensive natural fractures. Matrix permeability is typically in the region of 10⁻⁴ mD or less, and pore throat sizes are in the vicinity of 100–1000 nm. Consequently, stimulation is required to achieve economic gas recovery rates. Horizontal wells combined with successful multi-stage hydraulic fracture treatments are currently the most established method for effectively stimulating such formations.

The injected fracture fluid typically contains 1–7% KCL for the purpose of clay stabilization. However chemical analysis of the flowback water shows that it contains 10–20 times more dissolved solids than the injected fluid; total dissolve solids (TDS) can be as high as 197,000 mg/L with chloride levels alone being as much as 1,510,000 mg/L (Haluszczak et al., 2013).

This paper outlines the development and validation of a fully implicit fluid transport and halite dissolution numerical model that is used to predict and analyze the ionic compositions of flowback water from hydraulically fractured shale formations. The simulator is designed to predict the concentration of Na⁺ and Cl⁻, which are the two most predominant ionic species in flowback water. The paper presents a method for numerically simulating halite dissolution using the dual porosity dual permeability paradigm (DPDP) as the foundation for fluid transport in fractured reservoir.