Chemical Technology May 2016

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.

Table 2: Typical TDS levels in some US produced 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

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

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Chemical Technology •May 2016