Numerical analysis of the source of excessive Na+ and Cl- species in flowback water from hydraulically fractured shale formations

Maxian B. Seales, Robert Dilmore, Turgay Ertekin, John Yilin Wang

Research output: Contribution to journalArticle

2 Citations (Scopus)

Abstract

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 halitedissolution 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 C1- and 13% of Na+.

Original languageEnglish (US)
Pages (from-to)1477-1490
Number of pages14
JournalSPE Journal
Volume21
Issue number5
DOIs
StatePublished - Oct 1 2016

Fingerprint

Shale
Numerical analysis
shale
Fluids
fluid
Water
water
halite
Clay
clay
Sodium chloride
brine
dissolution
Dissolution
fluid injection
potassium chloride
dual porosity
Proppants
Hydraulic fracturing
analysis

All Science Journal Classification (ASJC) codes

  • Energy Engineering and Power Technology
  • Geotechnical Engineering and Engineering Geology

Cite this

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title = "Numerical analysis of the source of excessive Na+ and Cl- species in flowback water from hydraulically fractured shale formations",
abstract = "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 halitedissolution 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 C1- and 13{\%} of Na+.",
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Numerical analysis of the source of excessive Na+ and Cl- species in flowback water from hydraulically fractured shale formations. / Seales, Maxian B.; Dilmore, Robert; Ertekin, Turgay; Wang, John Yilin.

In: SPE Journal, Vol. 21, No. 5, 01.10.2016, p. 1477-1490.

Research output: Contribution to journalArticle

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AB - 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 halitedissolution 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 C1- and 13% of Na+.

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