Numerical Analysis of the Source of Excessive Na+ and Cl– Species in Flowback Water From Hydraulically Fractured Shale Formations
- Maxian B. Seales (Pennsylvania State University) | Robert Dilmore (National Energy Technology Laboratory) | Turgay Ertekin (Pennsylvania State University) | John Yilin Wang (Pennsylvania State University)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- October 2016
- Document Type
- Journal Paper
- 1,477 - 1,490
- 2016.Society of Petroleum Engineers
- Flowback water, Shale gas, Total Dissolve Solids
- 2 in the last 30 days
- 276 since 2007
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Fracture fluid is composed of fresh water, proppant, and a small percentage of other additives, which support the hydraulic-fracturing process. Excluding situations in which flowback water is recycled and reused, the total dissolved solids (TDS) in fracture fluid is limited to the fluid additives, such as potassium chloride (1 to 7 wt% KCl), which is used as a clay stabilizer to minimize clay swelling and clay-particle migration. However, the composition of recovered fluid, especially as it relates to the TDS, is always substantially different from the injected fracture fluid.
The ability to predict flowback-water volume and composition is useful when planning for the management or reuse of this aqueous byproduct stream. In this work, an ion-transport and halite-dissolution model was coupled with a fully implicit, dual-porosity, numerical simulator to study the source of the excess solutes in flowback water and to predict the concentration of both Na+ and Cl– species seen in recovered water. The results showed that mixing alone, between the injected fracture fluid and concentrated in-situ formation brine, could not account for the substantial rise in TDS seen in flowback water. Instead, the results proved that halite dissolution is a major contributor to the change in TDS seen in fracture fluid during injection and recovery. Halite dissolution can account for as much as 81% of Cl– and 86.5% of Na+ species seen in 90-day flowback water; mixing, between the injected fracture fluid and in-situ concentrated brine, accounts for approximately 19% of Cl– and 13% of Na+.
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