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Chemical Technology •May 2016
the chemical composition. Flowback water produces a
higher flowrate over a shorter period of time, greater than
8m
3
/day. Produced water produces lower flow over a much
longer period of time, typically from 0,5 to 6,5 m
3
/day. The
chemical composition of flowback and produced water is
very similar so a detailed chemical analysis is recommended
to distinguish between flowback and produced water. As
hydraulic fractionating water spends an increasing amount
of time in the ground it transitions from fresh water to salty
brine, dissolving salt compounds in the earth. Over time,
volume decreases and TDS increases [7].
There are numerous shale gas bed areas in the USA and
an equal number of water sources and regulations govern-
ing the use of water for shale bed hydraulic fracturing. One
in particular is the Susquehanna River Basin Commission
located in the Marcellus Shale formation underlying an area
from West Virginia in the south to New York in the north,
approximately 250 000 km
2
[8]. Withdrawals for natural
gas extraction in the Marcellus and Utica shales, however,
are regulated separately [9].
States, local governments, and shale gas operators
seek to manage produced water in a way that protects
surface and ground water resources and, if possible,
reduces future demands for fresh water. By pursuing the
pollution prevention hierarchy of ‘Reduce, Re-use, and
Recycle’, these groups are examining both traditional and
innovative approaches to managing shale gas produced
water. This water is currently managed through a variety of
mechanisms, including underground injection, treatment
and discharge, and recycling.
Underground injection has traditionally been the primary
disposal option for oil and gas produced water. Injection of
the produced water is not possible in every play as suitable
injection zones may not be available. Similar to a producing
reservoir, there must be a porous and permeable formation
capable of receiving injected fluids nearby. If not locally
available, pipelines have been constructed to transport
produced water to injection well disposal sites; this mini-
mises trucking thewater.
Treatment of produced water may be feasible through
either self-contained systems at well sites, or commercial
treatment facilities. As in underground injection, transporta-
tion to treatment facilities may or may not be practical [10].
Re-use of fracturing fluids is being evaluated by operators
to determine the degree of treatment and make-up water
necessary for re-use [11]. The practical use of on-site, self-
contained treatment facilities and the treatment methods
employed will be dictated by flow rate and total water vol-
umes to be treated, constituents and their concentrations
requiring removal, treatment objectives and water reuse or
discharge requirements. In some cases it would be more
practical to treat the water to a quality that could be reused
for a subsequent hydraulic fracturing job, or other industrial
use, rather than treating to discharge to a surface water
body or for use as drinking water.
Powder River CBM
1 200 mg/L
San Juan CBM
4 500 mg/L
Greater Green River
8 000 mg/L
Fayetteville Shale
25 000 mg/L
Barnett Shale
60 000 mg/L
Woodford Shale
110 000 mg/L
Haynesville Shale
120 000 mg/L
Permian Basin
140 000 mg/L
Marcellus Shale
180 000 mg/L
Table 2: Typical TDS levels in some US produced water