Summary
Flowback aids are usually surfactants or cosolvents added to stimulation
treatments to reduce capillary pressure and water blocks. As the stimulated gas
reservoirs become tighter, the perceived value of these additives has grown.
This value must be balanced with the cost of the additives, which can be
significant in slickwater fracturing treatments. There is a range of different
flowback additives containing water-wetting nonionic to amphoteric,
microemulsion (ME), and oil-wetting components. Determining the best additive
for a specific reservoir is not a simple matter for the end user, and the
existing literature is full of conflicting claims as to which one is most
appropriate.
This paper compares four different flowback aids: ME, two water-wetting
flowback additives, and an oil-wetting additive. Careful laboratory testing was
conducted to evaluate surface tension and contact angle for each flowback aid,
using the recommended concentrations. Imbibition and drainage tests were
performed that allowed calculation of the capillary pressures for the three
additives. Drainage tests were performed on 1- to 3-md and 0.1-md cores.
Capillary-tube-rise testing was also conducted as a check of the coreflood
testing capillary pressures. This provided several different methods to
determine capillary forces for the flowback aids. In addition, fluid-loss
testing was conducted to determine if the flowback additives could improve
fluid loss.
All the flowback aids demonstrated low surface tension (approximately 30
mN/m), but each was different in terms of surface wettability and adsorption in
the rock. In all cases, the flowback aids reduced capillary pressure to similar
levels 70% lower than water alone. One of the water-wetting additives had much
stronger adsorption in the core material than the other additives. The ME and
the oil-wetting additive had improved fluid loss in a fully formulated
fracturing fluid. In spite of the low capillary pressures, the additives had
little effect on cleanup or return permeability on cores greater than 1 md.
There are several implications of these results for the operator. Different
flowback additives have a tradeoff of properties, and depending on the
reservoir, selecting one that leaves the formation with certain wettability may
be advantageous. Our testing indicated that understanding the reservoir is
important in selecting the appropriate flowback aid.
© 2010. Society of Petroleum Engineers
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History
- Original manuscript received:
27 March 2009
- Meeting paper published:
28 May 2009
- Revised manuscript received:
8 October 2009
- Manuscript approved:
15 December 2009
- Published online:
8 April 2010
- Version of record:
11 August 2010
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