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Fracturing fluid flow back 341

12.2 Field observations and experimental results on
flow back

The literature information about fracture fluid flow back and produc-
tion performance related to the flow back are summarized in this section.

12.2.1 Low flow back
The most commonly used fracturing fluid in the shale reservoir stimulation
is slick water due to the characteristics of low cost, easily creating complex
fracture networks and little reservoir damage (Waltman et al., 2005; Palisch
et al., 2010; Cuss et al., 2015). Thousands of barrels of fracturing fluid are
injected into the formation during hydraulic fracturing operation. However,
field data indicate that only a small fraction of the injected fluid is recovered
during the clean-up phase. Most of gas well is less than 50% of the total in-
jection volume (King, 2012; Vengosh et al., 2014; Singh, 2016). Some are
even less than 5% (Nicot and Scanlon, 2012). On average, only 6%e10% of
the injected water is recovered in the United States across all shale plays
(Vandecasteele et al., 2015; Mantell, 2013).

12.2.2 Flow back versus hydrocarbon production
There are no consistent observations or results regarding the effect of flow
back on gas or oil production. In some cases, gas production is good
when more water flows back. In other cases, gas production is good with
a small fraction of water flowing back. Yan et al. (2015) used tight rocks
(2e18 mD), and Chakraborty and Karpyn (2015) used shale cores
(10e200 nD) to experimentally prove that it was detrimental for water to
be further imbibed into shale matrix by capillary redistribution due to the
permeability impairment by clay swelling. Ibrahim and Nasr-El-Din
(2018) conducted similar experiments in tight sandstones (0.23 mD) and
in Marcellus shales (3 nD) showing similar results.
Ghabnari et al. (2013) compared the flow back efficiency with cumulative
gas production after 72 h of flow back for the wells drilled in Muskwa, Otter
Park, and Evie, as shown in Fig. 12.1. The cumulative water production after
72 h was considered because the majority of fluid flowed back during the first
72 h (Asadi et al., 2008). Overall, there was no clear relationship between the
gas production and water flow back. But Ghabnari et al. (2013) grouped the
wells into two groups. One group is low water flow back efficiency and high
gas production, and the other group is high water flow back efficiency and