A review of the issues and treatment options for wastewater from shale gas extraction by hydraulic fracturing

A review of the issues and treatment options for wastewater from shale gas extraction by hydraulic fracturing

Fuel 182 (2016) 292–303 Contents lists available at ScienceDirect Fuel journal homepage: www.elsevier.com/locate/fuel Review article A review of t...

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Fuel 182 (2016) 292–303

Contents lists available at ScienceDirect

Fuel journal homepage: www.elsevier.com/locate/fuel

Review article

A review of the issues and treatment options for wastewater from shale gas extraction by hydraulic fracturing José M. Estrada 1, Rao Bhamidimarri ⇑ Vice President (Development), London South Bank University, 103 Borough Road, London SE1 0AA, United Kingdom

g r a p h i c a l a b s t r a c t

a r t i c l e

i n f o

Article history: Received 14 April 2015 Received in revised form 9 May 2016 Accepted 10 May 2016

Keywords: Flowback Hydraulic fracturing Produced water Shale gas Wastewater

a b s t r a c t Since the beginning of this millennium, shale gas extraction by horizontal drilling and hydraulic fracturing has boosted U.S. gas production, changing the global energy markets and leading to low natural gas and oil prices. Following the expansion of this industry, other countries such as U.K., Poland or China are exploring and supporting its extraction as a way to secure energy independence in an increasingly unstable geopolitical context and as an effective transition substitute for coal while moving towards a renewable energy market. However, there are important environmental concerns associated to shale gas production including atmospheric pollution and air quality issues, risks of water pollution and nuisance to the population caused by road traffic and noise. Water management is one of the most challenging problems since hydraulic fracturing requires millions of liters of water and produces high volumes of liquid effluents at variable compositions and rates. The present review focuses on the characteristics of this wastewater and the options existing to minimize its environmental impacts. At the moment, deep well injection and re-use are the most commonly employed strategies for this wastewater in the U.S. but the stricter regulations in other regions will require further treatment. Partial treatment and reuse is the preferred option where feasible. Otherwise, techniques such as mechanical vapor compression, thermal distillation or forward osmosis may be needed in order to meet the requirements for discharge. Ó 2016 Elsevier Ltd. All rights reserved.

⇑ Corresponding author. 1

E-mail address: [email protected] (R. Bhamidimarri). Present address: Temple Group, Devon House, 58-60 St Katharine’s Way, London E1W 1LB, United Kingdom.

http://dx.doi.org/10.1016/j.fuel.2016.05.051 0016-2361/Ó 2016 Elsevier Ltd. All rights reserved.

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293

Contents 1. 2. 3.

4.

5.

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Hydraulic fracturing process and environmental risks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Wastewater from hydraulic fracturing and shale gas production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1. Flowback water vs produced water . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2. Wastewater pollutants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.1. Suspended solids (particulate matter). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.2. Organics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.3. Total dissolved solids (TDS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.4. Naturally occurring radioactive material (NORM) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.5. Iron and heavy metals . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Strategies and technologies for wastewater treatment and disposal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1. Water reuse . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2. Wastewater disposal and advanced treatment technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.1. Evaporation with mechanical vapor compression (MVC) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.2. Reverse osmosis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.3. Membrane distillation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.4. Forward osmosis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.5. Biological technologies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3. Summary of treatment options . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Conclusions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

1. Introduction Natural gas contained in low porosity, organic-rich shale formations is known as shale gas [1]. The development of the new horizontal drilling and hydraulic fracturing techniques has made the recovery of this resource both technically and economically feasible [2]. This form of unconventional gas has been described as an effective transition fuel, reducing carbon emissions in the short term by substituting coal-based energy and allowing a smooth transition from fossil fuels towards a future based on more environmentally friendly renewable energies [3]. Recent studies estimate that the greenhouse gas (GHG) emissions caused by shale gas for energy production over its lifecycle are 30–50% lower than those of coal [4–6]. The switch to gas from coal for electricity and heating has already been reported by the Intergovernmental Panel on Climate Change (IPCC) as being responsible for the recent reductions in GHG emissions in the USA, where the widespread extraction of shale gas has allowed the share of unconventional sources to more than double since the year 2000, reaching 67% of the total gas production in 2011 [7,8]. In addition, the current scenario of global political tensions affecting energy markets has promoted an increased support of many governments to develop shale gas production as a means to improve their energy security and independence [9–12]. Estimates of the volume of unconventional gas available in Europe are still uncertain and a ‘‘shale gas revolution” similar to the one seen in the USA appears to be unlikely, but exploration operations are or have been taking place in Poland, Germany, Denmark, Sweden, UK and Romania. Commercial production could start as early as 2015 or 2016 in Poland (5.3 trillion cubic meters (tcm, 1012 m3) estimated technically recoverable resources) and UK (0.57 tcm estimated technically recoverable resources) [13]. Besides European countries, China, Argentina and Australia with reported estimates of technically recoverable shale gas of 31, 22 and 11 tcm, respectively are increasingly perceived as potential producers [8,14]. However, the global impacts of the use of this resource worldwide are still subject to intense debate, with some authors claiming that its net effect reducing GHG emissions might not be positive and reporting the need for a better understanding of its environmental and social implications [15–17]. The generation of huge amounts of wastewater and its management is one of the

293 293 295 295 295 295 296 296 297 297 297 298 299 299 300 300 300 301 301 301 301

main concerns associated with hydraulic fracturing for shale gas extraction [18]. Despite the experience gained in this field during the expansion of the shale gas market in the USA and the possibility of importing technologies from other fields such as conventional oil and gas wastewaters, there are still specific challenges related to hydraulic fracturing to be addressed [19–21]. Hydraulic fracturing operations involve the generation of fluctuating volumes of liquid waste in time (high flowback rates of fracking fluid after fracturing and low flow rates of produced water during the production stage) with a variable composition in pollutants including suspended solids, high salinity and hardness, organic chemicals, naturally occurring radioactive materials (NORMs) and heavy metals [22]. In addition, environmental regulations in Europe might hinder the application of common practices employed so far such as open pit storage or deep well re-injection [2,23]. In view of this background, finding solutions to issues related to wastewater will play a key role in order to minimize the environmental impact of a shale gas market and to increase the public acceptance of the hydraulic fracturing technology. The present review describes the process of hydraulic fracturing and its environmental impact focusing on wastewater production and is intended to be used as a reference during technology selection and to identify key weaknesses where further research is needed. It summarizes recent literature in order to improve the understanding of the fundamentals underlying the wastewater production in hydraulic fracturing operations for shale gas production and, finally, the different options available for its treatment and reuse focusing on the UK regulations and experience are explored.

2. Hydraulic fracturing process and environmental risks While the extraction of conventional natural gas is normally carried out by means of vertical wells, shale gas development needs horizontal drilling (or directional drilling) and hydraulic fracturing [2]. Both technologies were developed separately, but it is their combination which played a key role in the rapid development of shale gas in the USA [19]. Horizontal drilling originated in the 1940s in the USA, but it remained a marginal technique until the decades of the 1970s

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Fig. 1. Schematic representation of a multi-well pad for shale gas extraction including 1 – wellhead, 2 – vertical wells, 3 – Horizontal drilling, 4 – fractures, 5 – aquifers at typical depths of hundreds of meters. Adapted from [1] and [26].

and 1980s when the early ‘‘modern” horizontal wells were drilled [24]. This technique consists of drilling a conventional vertical well that, when the depth of the formation of interest is reached (typically thousands of meters), turns in an angle to extend into the flat layer in which hydrocarbons are located. A horizontal well can in this way maximize the area of contact with the rocks allowing gas extraction from thousands of meters of shale, rather than the tens or hundreds of meters available with vertical wells [3]. One or more horizontal sections can be drilled from a single vertical well [25]. Nowadays, multiple wells are usually drilled from a single surface site, and each of them includes horizontal sections. This arrangement is commonly known as ‘‘multi-well pad” and allows the recovery of gas from around 1 km2, which minimizes the land requirements on the surface (Fig. 1) [26]. Wells are protected and isolated from the surrounding environment by the case, which is usually multilayer armour shielding of hollow steel pipe and cement. Up to four protecting layers can be placed between the well and the ground to prevent the escape of gas and liquid pollutants [26]. However, horizontal drilling alone is not enough to induce sufficient natural flow from shale formations to the well for the extraction to be economically feasible due to the low permeability of shale. Thus, hydraulic fracturing (or fracking) is mandatory for the extraction of shale gas [3]. This technique is not exclusive of the unconventional gas operations, and has been previously applied in the oil and gas industry for decades to stimulate the hydrocarbon production of wells with decaying rates. During hydraulic fracturing operations, a fluid carrying a proppant, such as sand, is injected into a well at high pressures to fracture the reservoir rocks [22,27]. During the hydraulic fracturing of shale gas reservoirs the process applied is known as ‘‘slick water treatment”, in which a drag-reducer compound is added to the waterbased fracturing fluid. Polymers to modify the viscosity of the suspension (used in other hydraulic fracturing applications) are not usually employed due to the low porosity of the shale plays, and thus, low concentrations of proppant can be transported in this fracturing fluid (25–250 g/L). This fluid is injected at high flow rates up to 0.3 m3 s 1 and high pressures (480–680 bar) [22,28]. Hydraulic fracturing is not a continuous process: wells are fractured once after drilling and this process is carried out in stages (8–10 single fracturing stages per well). Later in the well lifetime, the process can be repeated for re-stimulation as the production declines [1].

The most common proppant employed is sand, and its mission is to keep the fractures caused by the fracking process open. Other chemicals usually added to the fracturing fluid include surfactants, scale inhibitors, pH adjusting agents, corrosion inhibitors and biocides [29]. In recent years, there has been a continuous effort to substitute the most hazardous chemicals by less harmful compounds to develop more environmentally friendly fracturing fluids [30]. In fact, the only fracturing operation carried out to date in the UK (by Cuadrilla Resources in their Preese Hall-1 well, Bowland Shale, Lancashire) employed a fluid composed only of water (98%) sand (1.8%), a polyacrylamide emulsion in hydrocarbon oil (0.046%), and a sodium salt solution added as a tracer (0.006%) [31]. The company has obtained permission to employ hydrochloric acid (a scale inhibitor) and glutaraldehyde (a biocide) in future operations [31,32]. Hydraulic fracturing and shale gas production entail several environmental and social concerns including induced seismicity or intensive freshwater consumption among others. Problems associated to the increase of road traffic in areas with intense shale gas development have been reported [33]. Moreover, traffic and noise nuisance were the reasons underlying the Lancashire Development Control Committee recommendation to refuse fracking activity in the area in January 2015 [34]. Despite the social alarm caused by seismic events (especially those associated to the only well fractured so far in the UK in 2011) and a recently published work linking fracking to earthquakes in Ohio, USA [35], evidences show that these episodes present small relevance and are not common [36,37]. In terms of water consumption, high volumes of freshwater are needed during the fracturing operations, but after that, the requirements of shale gas production fall to minimal values for the rest of the well lifespan. In the UK, recent estimations report that the full development of the shale gas industry would require only about 0.2% of the total annual freshwater extracted for industrial use in the next 20 years [26]. However, water consumption should be taken into account as an impediment to shale gas development in areas with limited freshwater availability [1,30]. Alternatives such as the use of low salinity brackish groundwater (directly or blended with freshwater) have already been reported as options to minimize freshwater consumption [14]. Atmospheric pollution ranks among the most important impacts of the shale gas industry: it can be caused by shale gas production in different forms and coming from different sources [38]. Besides the CO2 generated when the gas is burned for power generation, greenhouse gases (mainly methane) can be emitted during gas exploration and production via fugitive emissions and venting. The assessment of the extent of these fugitive emissions is one of the most controversial points of shale gas development, playing a key role in the discussion surrounding the impact of this form of energy on climate change [4,39,40]. Methane emissions can take place throughout the lifetime of the well including drilling, venting, equipment leaks, liquid unloading operations, gas processing and transport, storage and distribution of the gas. However, these fugitive emissions do not differ much from those produced in conventional gas extraction with 1.3–7.9% of the total production being lost in shale gas compared to 1.3–6.0% in conventional gas [5,41]. Other important atmospheric pollutants commonly associated to shale gas extraction include volatile organic compounds (VOCs), NOx, H2S and particulate matter (PM). Potential sources of this pollution are the storage of liquid effluents (fracturing fluids saturated with gas and other pollutants present in the formation), gas venting, flaring, gas/liquid separation operations and condensate tanks. The combustion in diesel engines for power generation and the pollution caused by vehicles transporting materials to and from the well is another important source of atmospheric pollution contributing to the reduction of the air quality in nearby areas [38,42,43].

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Shale gas operations also present risks to ground water. The migration of fracturing fluid or gas from the deep shale formations to aquifers or groundwater is unlikely due to the low porosity of the shale and the distance separating the fractures and the typical aquifer depths (see Fig. 1) [44]. Studies from the US shale formations have revealed that even the longest fractures extending in vertical direction towards the surface still remain around 1200 m from the aquifers above them [45]. On the other hand, the main source of this water pollution is sealing failures in the case isolating the well from the surrounding environment [38]. There are different types of wellbore integrity failures (pores, cracks and gaps) which allow for the migration of fracturing fluid, to the nearby ground and pollute shallow groundwater. Despite the frequency of this failures is relatively low (1–3%), they pose a serious environmental risks for instance in densely drilled areas or in abandoned wells. Thus well integrity as well as the origin and methods to detect failures are subject to intense research [3,42]. The other main water pollution risk comes from the wastewater generated in the process. Failures in the lining of commonly used open storage ponds often result in leakages to underground waters. Disposal to water bodies of poorly treated wastewaters from public sewage treatment plants has also caused environmental problems in drinking water quality and rivers [46,47]. The nature of this wastewater produced during shale gas production by hydraulic fracturing and the possibilities to mitigate its environmental impact are addressed further in the following sections. 3. Wastewater from hydraulic fracturing and shale gas production As introduced earlier, hydraulic fracturing processes inject high volumes of water mixed with chemical additives that then return to the surface as liquid effluents. This section analyses the nature, flow rates and the different pollutants present in this wastewater and their changes over time from the fracking of the well to the production stage; and the challenges these characteristics pose for an adequate management. 3.1. Flowback water vs produced water Each shale gas fractured well requires between 7000 and 21,000 m3 of water and varying percentages (8–70%) of this water will return back to the surface during the lifetime of the well [2,42]. These values are highly variable from site to site and from one shale play to another, with most of the available data coming from the US. In the UK, the only available value in terms of the water required (8400 m3 per well) falls into the lower end of the range, but no data is available so far in terms of flowback ratio [31]. Estimations based on US data report a range of 1200–6600 m3 of wastewater produced per well in the UK [26]. Studies carried out in German shale plays report 17–25% recovery of the injected water in a period between 10 and 55 days after the fracturing operation estimating wastewater production in 2000–4600 m3 per well [23]. Many authors distinguish two different kinds of liquid effluents recovered when describing the wastewater from shale gas operations. The first of them is known as ‘‘flowback water” and it is produced right after the hydraulic fracturing process: it consists mainly of the injected fracturing fluid mixed with salts and possibly other chemicals present in the shale formation. On the other hand, the term ‘‘produced water” refers to the highly saline liquid that flows out of the well continuously along with gas in the production stage and during the lifetime of the well [18,22]. The distinction between both waters is sometimes diffuse and can be arbitrary, referring just to the operational stage of the well

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Fig. 2. Conceptual profiles of different parameters associated to wastewater production after hydraulic fracturing operations after data from [22,48,51–55].

(fracturing stage vs. gas production stage) [27] while other authors do not consider this difference at all, using both terms without making a distinction [1,48–50]. The main difference between these two types of wastewater is the flow rate at which they are recovered. This sometimes can make the selection of an appropriate management strategy difficult. Up to 60% of the total flowback water can be collected in the following days after the fracturing operation, which means that flow rates during the first few days can be as high as 1000 m3 day 1. Shortly after that, during the production stage, the water flow rate greatly decreases and remains stable at rates ranging from 2 to 8 m3 day 1 [1,26]. At the same time, the composition of this flowback water gradually changes from being very similar to the fracturing fluid injected to become more saline and rich in inorganic pollutants present in the shale formation (Fig. 2). The origin of this salinity can be the presence of underground brines within or adjacent to the shale formation or the salts present in the rock formation: thus, the more time the fluid remains in contact with the shale, the more solutes are present in the produced water [27,51,56]. Some studies have been performed to clarify how much of the flowback and produced water is actually fracturing fluid and how much is natural underground brine by studying different chemical markers [22,23,52]. However, as mentioned earlier, from the wastewater treatment viewpoint it is difficult to set a line between these and the main challenge is to manage effectively the high volumes of flowback initially generated, but also the low continuous flow of high salinity brine produced continuously over time. 3.2. Wastewater pollutants 3.2.1. Suspended solids (particulate matter) As mentioned earlier, proppant is an important component of the fracking fluid, necessary to keep the factures open allowing the flow of gas from the shale formation. Silica and quartz sand are typical agents employed [32]. Part of this proppant can be recovered after the hydraulic fracturing operations, together with solid particles from the rock formation, leading to total suspended solids (TSS) concentration ranging from 300 to 3000 mg L 1 in the flowback [57]. TSS content in Polish flowback water appears to be lower, with 168 mg L 1 reported [58]. Not much information is available in terms of TSS recovery or treatment, since solids are easily removed from the flowback water by means of relatively inexpensive filtration or sedimentation pre-treatments and research currently focuses on the treatment of dissolved pollutants [50,58].

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Table 1 Pollutants present in hydraulic fracturing fluids according, typical ranges in flowback waters and discharge limits according to UK regulations. Pollutant

Range in wastewater

Discharge limits

1

BOD5 COD Chloride Bromine

3–2070 mg O2 L 175–21,900 mg O2 L 1670–181,000 mg L 15.8–1600 mg L 1

Naphthalene

0.1–1400 lg L

Dimethyl phthalate



Diethyl phthalate

35 lg L

Dibuthyl phthalate

11–130 lg L

Benzylbuthyl phthalate



Dioctyl phthalate

15 lg L

Xylenes

15–5200 lg L

Nonylphenol



1 1

1

1

1

1

1

25 mg O2 L 1 UWWT 125 mg O2 L 1 UWWT 250 mg L 1 MAC 2 lg L 1 (AA, freshwater) 5 lg L 1 (MAC, freshwater) 10 lg L 1 (MAC, Saltwater) 2.4 lg L 1 (AA, inland surface freshwater) 1.2 lg L 1 (AA, other surface waters) 800 lg L 1 (AA, freshwater and saltwater) 4000 lg L 1 (MAC, freshwater and saltwater) 200 lg L 1 (AA, freshwater and saltwater) 1000 lg L 1 (MAC, freshwater and saltwater) 8 lg L 1 (AA, freshwater and saltwater) 40 lg L 1 (MAC, freshwater and saltwater) 20 lg L 1 (AA, freshwater and saltwater) 100 lg L 1 (MAC, freshwater and saltwater) 20 lg L 1 (AA, freshwater and saltwater) 40 lg L 1 (MAC, freshwater and saltwater) 30 lg L 1 (AA, inland surface freshwater) 30 lg L 1 (AA, coastal water and relevant territorial waters) 0.3 lg L 1 (AA, inland surface freshwater) 0.3 lg L 1 (AA, other surface waters) 2.0 lg L 1 (MAC, inland surface freshwater) 2.0 lg L 1 (MAC, other surface waters)

UWWT: Urban Waste Water Treatment (England and Wales) Regulations 1994. AA: Annual Average standard according to the Horizontal Guidance to Environmental Permitting in the UK (H1). MAC: Maximum Allowable Concentration according to the Horizontal Guidance to Environmental Permitting in the UK (H1).

3.2.2. Organics The first group of dissolved pollutants that can be found in flowback water (after solids separation) are those chemicals being part of the fracturing fluid itself. Typical fracturing fluids for shale gas operations can include acids, drag reducing agents, surfactants, scale inhibitors, corrosion inhibitors and biocides among others, besides the proppant agents [1]. Among the most employed chemicals in the US are methanol (biocide/corrosion inhibitor/anti freezing agent/surfactant), isopropanol (corrosion inhibitor/anti freezing agent/surfactant), petroleum distillates (solvents), ethylene glycol monobutyl ether (surfactant), naphthalene (biocide), or ethylene glycol (Scale inhibitor/anti-freezing agent/surfactant) [29,32]. Table 1 summarizes the pollutants present in hydraulic fracturing fluid with their concentrations in flowback waters [29,48,59] which are limited in effluent discharges in the UK by The Urban Waste Water Treatment (England and Wales) Regulations 1994, the Horizontal Guidance to Environmental Permitting in the UK (H1), Annex D for Basic Surface water discharges. As mentioned earlier, these organic chemicals emerge at the surface with the flowback water at concentrations initially in the order of mg L 1, and decrease sharply during the first 20 days after the hydraulic fracturing operation (Fig. 2). However, residual concentrations ranging from 10 to 250 lg L 1 can still be found in produced waters even after 250 days for some organics [48]. These compounds lead to TOC concentrations in flowback water that can reach values as high as 500 mg L 1, COD ranging from 175 to 21,900 mg L 1 and BOD5 concentrations between 3 and 2070 mg L 1 during the first 14 days after the fracturing [59]. After 20 days of operation, TOC concentrations remain stable at much lower concentrations (30–50 mg L 1). This continuous recovery of organics at low concentrations might be due to residual fracturing fluid and to the background concentrations of organics present in the shale formation enhanced by the solubilization of organic materials promoted by the hydraulic fracturing [48]. Unlike in the US, where the disclosure is voluntary, in the UK operators are required to disclose the composition of the hydraulic fracturing fluids to the environmental regulator under the Water

Resources Act 1991 and the use of non-hazardous additives will be ensured where possible [60]. For instance, polyacrylamide emulsion in hydrocarbon oil (not containing any reportable hazardous component) has been employed in the UK as friction reducer [31]. In addition, the EU European Chemicals Agency (ECHA) requires that companies register the chemicals they use under the REACH program, and if they are considered hazardous, a Chemical Safety Assessment (CSA) is required in order to guarantee that the risks to human health and to the environment are controlled for the specific use [32]. 3.2.3. Total dissolved solids (TDS) The main problem associated with the wastewater produced in shale gas extraction is the high salinity usually found in these liquid effluents, especially in produced water, with TDS concentration increasing with time after the fracturing operation (Fig. 2). As mentioned earlier, there are several hypothesis explaining the origin of those dissolved salts, including the presence of high salinity brines in the underground shale formations, and the dissolution of salts present in the rock matrix [56]. In addition, this concentration usually presents high geographic variability. Data from flowback and produced waters in the Marcellus Shale in Pennsylvania present concentrations of TDS ranging from 8000 to 360,000 mg L 1 with average values usually around 100,000 mg L 1 [1,2,22]. In Europe, a study carried out in Germany reports TDS values in agreement with those found in the US, reaching a maximum of 180,000 mg L 1 with average values around 100,000 mg L 1 [23]. Limited information is available from Polish wells, but according to conductivity levels the concentration range would be four times lower than the one observed in the Marcellus Shale [58]. In the UK, the maximum TDS concentration reached in the wastewater from the well fractured by Cuadrilla Resources in the Bowland shale formation in Lancashire was 130,000 mg L 1 [61]. Chloride is the most important ion in terms of concentration usually accounting for more than 50% of the total dissolved solids [27] (see Fig. 3). Chloride concentrations around 80,000 mg L 1 are typically achieved in wells worldwide and this concentration

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1 mSv year 1 (allowable annual exposure in the UK), and that the flux of radioactive material generated per unit of energy produced is lower for shale gas than for conventional oil and gas, coal fueled electricity and, of course, nuclear power [63]. Radionuclides can precipitate in the form of scale during the process or in further stages of the wastewater treatment (deliberately or not), and thus the possibility of the NORMs being present at higher concentration in solid wastes or sludge needs to be considered [64]. In the UK, waste from different industrial activities containing Ra-226 at concentrations exceeding 500 Bq kg 1 for solids or 1000 Bq L 1 for liquids is considered radioactive and has to be disposed of as such [65]. So far, no waste from hydraulic fracturing operations has been reported to exceed the limits on radioactive materials in the UK. Fig. 3. Time evolution of the concentration of relevant ions (chloride, sodium and bromide) in the flowback/produced water well fractured by Cuadrilla Resources in the Bowland shale formation (Lancashire, UK) according to the UK Environment Agency (EA 2011). Note the different scale employed for bromide (right Y axis).

appears to continuously increase during the lifetime of the well, or at least up to more than 100 days, where data from the produced water has been characterized [23,51,61]. Sodium is the second most abundant ion present in flowback and produced waters: its concentration also increases rapidly from almost negligible values in the fracturing fluid reaching typical concentrations of approximately 30,000 mg L 1 [1,23]. However, in the long term, the relative abundance of sodium decreases, being replaced by divalent cations such as calcium and magnesium [27]. Other ions such as calcium, magnesium, barium, strontium, potassium or bromide are present at variable concentrations and typically up to the order of thousands of milligrams per liter. Concentrations of these ions are highly variable from one shale play to another or even between different wells in the same area. For instance, Olsson et al. [23] report high differences in the calcium, strontium, barium and potassium concentration in waters from different wells in Lower Saxony (Germany). Variations in these concentrations and in the ratios between ions are used to characterize different brines and study their possible origins [22,27]. Total hardness (as CaCO3) usually ranges from 10,000 to 55,000 mg L 1 [1]. Recently, significant concentrations of iodide (up to 56 mg L 1) and ammonium (up to 420 mg L 1) have been detected in flowback fluids from the Marcellus and Fayetteville shales in the US for the first time. This suggests that these ions should not be ruled out as possible pollutants in discharge water bodies, posing specific risks to the environment and human health [62]. 3.2.4. Naturally occurring radioactive material (NORM) Wastewater from shale gas production will typically contain small amounts of radionuclides that are found naturally in shale formations. Among the radioactive isotopes found in the underground shales are uranium (U), Thorium (Th) and Radium (Ra226 and Ra-228). However, radium isotopes are most important at the wastewater level due to their higher solubility [30,63]. The Marcellus Shale in the US, as a Devonian shale, is considered to have high levels of NORMS with concentrations of Ra226 reaching 370 Bq L 1 in the saline brines of the formation. [51,64]. In the carboniferous Bowland Shale (UK) the concentration of Ra-226 found in flowback fluids has ranged from 14 to 90 Bq L 1 (Table 2) [12,61]. A recent study by Almond et al. [63] remarks that these values exceed by far the concentration of natural local groundwater. However, the same study also concludes that, even in the worst case scenario for 25 wells drilled in a year in the UK, the exposure level caused by these NORMs would never exceed the limit of

3.2.5. Iron and heavy metals Among the metals commonly found in flowback and produced water iron is the most important reaching maximum concentrations of 500 mg L 1 but with typical concentrations in the order of 10–200 mg L 1 [22,23,58]. Dissolved iron concentrations up to 106 mg L 1 have been reported in flowback waters in the UK [61]. Heavy metals such as nickel, aluminum, lead, zinc, copper, cadmium, mercury and arsenic are usually found at concentrations of lg L 1 (Table 2). These concentrations are, for instance, two to three orders of magnitude lower than those found in biosolids from municipal wastewater treatment plants [59]. As previously mentioned for other pollutants, their concentration is highly variable from shale to shale and from well to well. 4. Strategies and technologies for wastewater treatment and disposal In the US, wastewater management trends have gradually shifted in time from the initial disposal in wastewater treatment facilities to reuse and deep well injection mainly due to the development and enforcement of tighter environmental regulations [2,18]. These regulations have often been put in place after reported negative environmental effects of the management practices previously allowed [18,46]. However this ‘‘learning by doing” process is not expected to be repeated in other parts of the world: in January 2015 the UK Environment Agency granted Cuadrilla Resources the environmental permits to carry out hydraulic fracturing operations at the Preston New Road Exploration Site,

Table 2 Filtered concentrations of metals and relevant NORMs in the flowback water from the hydraulic fractured well by Cuadrilla Resources in the Bowland Shale formation in Lancashire, UK [61]. Pollutant

Minimum concentration

Maximum concentration

Iron Lead Mercury Cadmium Chromium Zinc Nickel Silver Aluminum Arsenic Cobalt Copper Vanadium Radium-226 Actinium-228 Lead-214 Bismuth-214

35.8 mg L 1 <2 lg L 1 <0.01 lg L 1 0.674 lg L 1 0.564 lg L 1 <50 lg L 1 <10 lg L 1 <1 lg L 1 <10 lg L 1 <1 lg L 1 <1 lg L 1 <10 lg L 1 <2 lg L 1 14.0 ± 2.1 Bq L 1 1.7 ± 0.4 Bq L 1 1.4 ± 0.2 Bq L 1 0.9 ± 0.2 Bq L 1

106.0 mg L 1 179 lg L 1 0.013 lg L 1 <5 lg L 1 40 lg L 1 411 lg L 1 <50 lg L 1 <50 lg L 1 <500 lg L 1 5.1 lg L 1 <50 lg L 1 <50 lg L 1 <50 lg L 1 90 ± 12 Bq L 1 12.0 ± 2.5 Bq L 50 ± 5.6 Bq L 1 41 ± 4.6 Bq L 1

1

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in Lancashire. The permit and annex documents explicitly mentioned that underground re-injection of hydraulic fracturing fluid would not be allowed, and that flowback fluid must be stored in enclosed steel containers within the site perimeter [66]. This way, two common practices in the US (deep well re-injection and open pond storage) are ruled out for the UK, at least during the exploratory stages. Similar strict environmental regulations are expected in other European countries [23]. Thus, efficient and environmentally friendly wastewater management will be a mandatory issue from the very early stages of shale gas extraction in Europe. 4.1. Water reuse At the moment, it is a common trend to re-use flowback and produced waters in subsequent hydraulic fracturing operations in what is commonly known as ‘‘internal reuse” [2]. The internal reuse minimizes the wastewater environmental impact and treatment costs while reducing the need for fresh water as fracking fluid, but on the other hand, the accumulation of high concentrations of dissolved solids can lead to operational problems as will be discussed below. This management strategy was initially convenient in areas where the local availability of freshwater was limited or where there are no other suitable alternatives for disposal [1]. Over time, this option has gained ground: for instance, reuse as hydraulic fracturing fluid has been recently reported to be the most common flowback management strategy in the Marcellus Shale, US, with up to 90% of the generated wastewater being reused [2,18]. Research is currently trying to solve logistic constraints and optimizing well location and drilling planning in order to maximize water reuse possibilities [14]. The strict environmental legislation in Europe makes internal reuse an attractive management strategy. However, it is important to note that the reuse is only possible if there is demand for this new fluid, which means an expanding industry with new wells drilled and fracked. Eventually, the shale gas industry will become a net producer of wastewater as the industry becomes mature and the drilling rate decreases and finally desalination processes will be necessary [2,3]. The first (and often controversial) information needed in order to evaluate water reuse options is to define which are the properties or water quality needed for the effluent to be suitable for reuse. No common accepted standards have been reported so far [56]. Recent data collected from full scale operations indicate that the TDS concentration in fracturing fluids containing reused water should not exceed 50,000–65,000 mg L 1. Specifically, chloride concentration should be kept under 20,000–30,000 mg L 1. Additionally, other parameters requiring control include: TSS content should be <50 mg L 1, pH levels between 6 and 8, Fe concentration <20 mg L 1, total hardness <2500 mg L 1, oil and soluble organics

<25 mg L 1, sulfate <100 mg L 1, and total bacteria count <100 per 100 mL [67–69]. The pre-treatment commonly applied to all returned water from hydraulic fracturing is filtration in order to remove the TSS which will be proppant and other solids coming from the underground. Direct reuse of flowback after filtration has been reported for low salinity produced waters with low scaling potential in the Fayetteville Shale (USA) [49]. This wastewater is blended with freshwater to render new hydraulic fracturing fluid with the acceptable quality as reported earlier. However, the subsequent reuse of water with significant TDS content will continuously increase its concentration, eventually leading to operational problems of scaling and reducing the lifespan of pumping equipment. For instance, problems in the fracking pump seal can become critical at high TDS content [69]. The efficiency of the friction reducers added to the blended fracturing fluid can also be reduced due to the presence of salts [70]. Alternatively to filtration, surface open impoundments for sedimentation and degreasing/deoiling have been used in the US [1,22]. However, this technique allows gaseous organic pollutants to escape to the atmosphere. Often, sedimentation and precipitation processes are needed in order to improve the quality of produced waters for reuse [1]. A recent study has shown how field flowback water can be treated by the addition of coagulants and flocculants significantly reducing the TOC concentration from 40 to 5 ppm, iron concentration from 22 to 4 ppm. Removal of hardness can be accomplished by chemical precipitation methods: lime softening (addition of CaOH2 for the precipitation of MgOH2 salts) and Na2CO3 addition (for the precipitation of CaCO3). These methods are able to reduce the total hardness to the concentration required for re-use under 2000 mg L 1 [68]. Thus, a general on-site treatment process in order to optimize flowback and produced waters might be similar to the one shown in Fig. 4. The pH of the wastewater is first adjusted and then treated treated by coagulation/flocculation processes in order to promote the precipitation of suspended solids, colloidal particles and NORM if needed. Degreasing and deoiling would also take place at this stage. Afterwards, a simple filtration of the remaining suspended solids would be carried out. Finally, the softening of the effluent can be carried out as described earlier leading to the precipitation of magnesium and calcium salts [69]. At this point, the TDS and chloride concentration in the effluent should be analyzed in order to evaluate the suitability for direct reuse by dilution with freshwater. It is possible for low TDS effluents that, after blending, requirements are met for reuse, otherwise advanced treatments addressing the desalination of the effluent will have to be considered [49]. Solids are produced in all the stages of the process and will have to be managed according to their properties, especially if they contain high concentration of NORM.

Fig. 4. Diagram of the process proposed for water pre-treatment prior to re-use as fracturing fluid including possible inputs and outputs. Note that not all the stages might be needed depending on the quality of the flowback/produced water.

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4.2. Wastewater disposal and advanced treatment technologies Flowback and produced water management besides reuse in the fracking industry is one of the most important challenges faced by the shale gas production industry. As mentioned earlier, there has been an evolution in the way this waste has been treated over time. The recent work by Lutz et al. [18] reflects the changes over time in the Marcellus shale: from treatment at municipal wastewater treatment plants, followed by an increase in the treatment in industrial wastewater treatment plants, then an increase in deep well injection and finally the present high reuse scenario [18]. When analyzing the options for the development of a shale gas industry in Europe or the UK, it is important to remark that industrial wastewater treatment facilities offer the possibility to treat metals and dissolved solids, but are often ill-equipped to deal with the high concentrations of salinity found in hydraulic fracturing wastewater. Costs for this disposal method in the Marcellus Shale in the US collected in 2010 ranged from 0.025 to 0.055 USD per gallon (6.6–14.6 USD m 3) [71]. Thus, according to the average volumes of wastewater generated in the hydraulic fracturing of a single well (5000 m3 of wastewater), the treatment costs of this wastewater could range from 33,000 to 73,000 USD per well. Deep well injection has traditionally been another acceptable practice for wastewater disposal in the US. The volume of water managed by this technique is currently decreasing for the shale gas industry, but data from 2007 revealed that 98% of the total produced water from onshore oil and gas wells was disposed of by underground injection. In addition, this technique is expected to remain relevant, since it allows the disposal of more concentrated waste brines after desalination technologies are applied [2,18]. Deep injection wells are only available where the deep underground formation has the adequate porosity and geology to accept the wastewater. Generally, wastewater is transported by trucks to tanks at the wells, which can be on-site and operated by the gas company or third party disposal wells [71]. The limited availability of injection wells often results in the transfer of wastewaters from one basin to another, increasing the overall impact by transport of the waste [18]. Deep well injection from onshore oil and gas production appears to be a low risk activity, since no major effects to the environment have been associated to it, but there are still many uncharacterized mechanisms and long term issues that are subject to monitoring, research and discussion [72]. For instance, it is known that deep well injection significantly contributes to the generation of seismic activity, being more important than hydraulic fracturing itself in terms of potential risks to induce earthquakes [73]. It is yet unclear if deep injection will be allowed as a disposal method in the UK at the production stage. It is mentioned as an option in reports by the Royal Academy of Engineering and the British Geological Survey [44,60], but the most recent information published by the Department of Energy and Climate Change (DECC) does not explicitly contemplate this option [74]. The liquid waste disposal method will ultimately depend on the environmental permit awarded to the companies extracting the gas under the UK Mining Waste Directive [60]. In Germany, deep injection of mining wastewater is considered the state of the art disposal method, but the permits within shale gas operations are to be reviewed on a case-by-case basis [23]. In order to minimize the concentration of TDS in wastewater for disposal into water bodies or reuse outside fracking operations, further treatment is needed beside the techniques previously described as options for water reuse. These techniques aim at the desalination of the liquid effluent and are often referred to as ‘‘advanced” treatment technologies [49]. The most relevant technologies available are discussed below.

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4.2.1. Evaporation with mechanical vapor compression (MVC) Evaporation techniques are based on the supply of thermal energy to the liquid stream in order to evaporate part of the water obtaining freshwater and a brine with a higher TDS concentration. Evaporation and crystallization techniques have been often mentioned as the only technology able to deal with the high volumes of wastewater and the high concentrations of salts to produce effluents under the increasingly strict regulations in the US [56]. Among the evaporation technologies, different designs and operational strategies seem to be especially suitable for the treatment of produced waters with high dissolved salts concentration optimizing the heat transfer: vertical tube, falling film and mechanical vapor recompression [20]. In a MVC system, the heat is provided to the brine by means of superheated compressed vapor in a tube evaporator (Fig. 5). The system is further energy-integrated using hot streams of condensates and brine to pre-heat the produced water streams. The main energy input to this system is the electricity required for the vapor compression. These systems are reliable and efficient and can operate at temperatures under 70 °C, which offers further opportunities for minimization of the energy requirements, since produced waters emerge at similar temperatures (65–100 °C) [2,68,75]. Vertical tube heat exchangers have been employed as a method to maximize the heat transfer optimizing the evaporation process. In this design, the tubes in the heat exchanger are vertically arranged and the feed stream flows as a film over the internal surface of the tubes, while the superheated vapor condensates in the outside surface [76] (see Fig. 6).

Fig. 5. Simplified flow diagram for a MVC process for desalination.

Fig. 6. Simplified diagram for a FO process for desalination including the second stage for draw solution re-concentration.

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MVC systems have been applied to standard seawater desalination scenarios with small to medium size capacities (500– 3000 m3 day 1). Under those conditions the energy consumption ranges from 7 to 12 kW h m 3 [77]. Similar capacities and energy consumptions have been obtained when applying this technology to produced waters containing TDS up to 64,000 mg L 1. However, the upper limit for the application of MVC to produced waters is usually set at 200,000 mg TDS L 1 due to the solubility of NaCl in water. Other recent estimations report energy requirements of 20 kW h m 3 for desalination of produced waters at mediumlarge scale [78]. The advantage of MVC compared to other alternatives is that it is not prone to clogging or fouling, however, pretreatment by deoiling and antiscaling dosing is common to prevent operating problems. If organics are present in the distillate, a further post-treatment might be required [2]. 4.2.2. Reverse osmosis Reverse osmosis (RO) has been widely applied for desalination of seawater and is often regarded as an alternative for produced water desalination. However, this technology is considered unfeasible at TDS concentrations above 40,000 mg L 1 [1]. Some alternatives such as vibration shear enhanced osmosis have been proposed to improve its performance at higher salts concentration for traditional oil and gas produced waters, however, the concentrations expected in shale gas production are much higher, which hinders the application of reverse osmosis [20]. Only those waters with very low TDS content (<30,000 mg TDS L 1) would be treatable by reverse osmosis, and in those cases, reuse after a partial pre-treatment is a more economic and environmentally friendly technique [49]. 4.2.3. Membrane distillation Membrane distillation (MD) is an emerging and promising technique for the desalination of high salinity waters. This separation process is a thermally driven technique in which the water stream is heated and the vapor molecules are allowed to pass through a porous hydrophobic membrane to the cold (or ambient temperature) side, becoming the permeate. The vapor pressure difference between the membrane surfaces facilitates the process allowing the operation at lower temperatures than traditional thermal methods. Generally the salty water does not need to be heated up to the boiling point and a temperature difference of 10–20 °C between both sides of the membrane is enough for a correct performance [79,80]. Different configurations are available for membrane distillation: in direct contact MD, a cold or ambient temperature distillate condenses the water vapor on the cold face of the membrane driving the vapor flux. Vacuum MD relies on pressure difference to facilitate the vapor flux. Air gap MD and sweeping gas MD introduce air or an inert gas, respectively, separating the cold solution from the cold side of the membrane [80,81]. Despite extensive research on MD has focused on desalination of sea water, the potential for its application to flowback and produced waters is significant, since the permeate fluxes obtained are not highly affected by increased salinity [2,81]. Recent studies have proven the feasibility of MD for waters with salinity levels similar to those reached in shale gas production. Minier-Matar et al. [79] tested MD at high salts concentration confirming little effect of salinity increases and obtaining >99.7% TDS rejection in real, low concentration shale gas produced waters (TDS = 48,000 mg L 1) and >99.9% salt rejection in a medium salinity brine (TDS = 71,000 mg L 1), maintaining temperatures of 70 and 30 °C in the hot and cold sides of the membrane, respectively. The desalinated fluxes obtained range from 20 to 25 L m 2 h 1 and a pilot scale system was operated for 12 days with stable performance and no membrane fouling was observed [79]. Another recent study

has tested MD under higher TDS concentration: Macedonio et al. [82] tested different membranes at 250,000 mg TDS L 1 maintaining temperatures of 50 and 25 °C in the hot and cold sides of the membrane, respectively. Rejection >99.7% of the TDS with three different membranes and fluxes ranging from 1 to 9 L m 2 h 1 were obtained. In addition, that work estimates the costs of the recovery of 70% of the water treated to range from 0.7 to 1.2 USD m 3 for produced water feeding temperatures from 50 to 70 °C [82]. Once again, it is important to remark how MD operates at temperatures close to those naturally found in produced water, with the subsequent potential for energy optimization. In both cases, TOC rejections higher than 90% were achieved. Despite this huge potential of MD, the presence of other pollutants besides TDS in the water stream to be treated can cause significant problems. More specifically, small VOCs can pass through the membrane polluting the permeate, and alcohols or surfactants can wet the membrane pores allowing the feed stream to flow across the membrane. Thus, effective pre-treatment reducing potential foulants and organics is critical for the successful performance of this technology [2,79,80]. Innovative MD process modifications include the use of solar energy as a source of heat for the hot flow [83]. However, most of the research available to date is based on lab scale and has been carried out under very controlled conditions. There is still a need to investigate the performance of MD at larger scale and under industrial conditions to assess potential opportunities and limitations of the technology [80]. 4.2.4. Forward osmosis In forward osmosis, the flux of water through a semi-permeable membrane is driven by the osmotic pressure difference between the wastewater treated and a highly concentrated solution which is usually referred to as ‘‘draw solution”. In these processes, the draw solution employed must possess a higher concentration in some component than the wastewater to be treated [84]. The forward osmosis process takes place in two stages: first, the water passes through the membrane, thus diluting the draw solution. In a second stage, this water must be separated from the draw solution, producing high quality water and re-concentrating the draw solution. This second stage is usually reverse osmosis or thermal distillation [85]. Despite being a more complex system, FO presents a series of advantages over other alternatives: the low pressure operation of FO makes the membrane less prone to fouling and can potentially reduce the pre-treatment needs before this stage, reduces the maintenance needs and improves the overall lifespan of the membrane [2]. The draw solution selection is the key to an efficient FO process. Draw solutions should be inexpensive, highly soluble to avoid scaling problems in the recovery stage and provide the required osmotic pressure to induce sufficient flux across the membrane. Many candidate solutions have been proposed, but thermolytic salts (which have the ability to change phase due to temperature changes, and do not rely in reverse osmosis for reconcentration) are claimed to be the most suitable alternative for the desalination of high salinity waters [2,85]. Otherwise, the energy needed to perform the post FO separation will be higher than the energy requirements of a single stage separation process [84]. FO systems using thermolytic salts as draw solutions have been tested with high salinity brines at pilot scale with positive results. For instance, McGinnis et al. [86] employed a NH3/CO2 draw solution to treat wastewaters containing 73,000 mg TDS L 1 and a total hardness of 17,000 mg CaCO3 L 1. The complex process employed, including a post-FO thermal distillation, RO and brine stripper, allowed to recover >60% of the fed water meeting surface discharge criteria and consuming 42% less energy than a conventional MVC process [86]. Modeling of FO process has shown that most of the

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energy input is required at the draw solution regeneration stage [78]. More recent studies have explored the possibilities of using trimethylamine/CO2 draw solutions in FO with promising preliminary results, but have not been yet tested with highly saline brines [87]. New advances in materials for membranes and in the development of draw solutions will help to make FO a competitive alternative for desalination of high salinity wastewaters [84]. 4.2.5. Biological technologies At the moment, there is an increasing amount of research aimed at providing innovative solutions to the challenges posed by wastewater generated in the fracking industry. Despite most of them are at very early stages of development (mainly laboratory scale), it is worth considering them since continuous innovation might be the key to future solutions in the field. Recent works have been published proposing the desalination of produced waters by microbial capacitive desalination cells. This technology is able to remove organic pollutants by microbial oxidation and uses the electrical potential generated in this process for capacitive desalination in a system combining electrodes, cation exchange membranes and adsorption. The technology has only been tested at a very small scale, but the authors claim that even an energy-positive desalination could be achieved [88,89]. The use of biological treatment is an attractive option which is not new and has also been explored in other reactor configurations [90]. For instance, treatment of organic chemicals in flowback waters by means of conventional activated sludge has been tested, but presents limitations mainly due to the high TDS concentrations which hinder biological activity [91]. Recently, the use of flowback water as a medium for the cultivation of commercial marine microalgae has also been proposed [92]. Although this technique would not treat the effluent, it would reduce the water needs for microalgae cultivation and probably decrease its costs. 4.3. Summary of treatment options The selection of the most adequate technology for produced/ flowback wastewater treatment will ultimately depend on the specific properties and pollutants of the effluent considered as well as the volume of wastewater to be treated in a single unit. MVC presents the advantage of not relying on any type of membranes, avoiding fouling problems and probably requiring less maintenance and reducing operating costs. MVC can deal with high salinity brines, but it may need post-treatment if volatile organics are present in the effluent. MD requires significant pre-treatment to eliminate organics, but it can operate at lower temperatures and benefits from the facts that its treatment capacity is not significantly affected by increased TDS content. Both MVC and MD benefit from the fact that produced waters emerge at temperatures close to those needed for their operation, which could be an opportunity for energy saving. RO can still be considered an option for those effluents containing low salinity (<30,000 mg TDS L 1), but these low concentrations are not expected in the UK according to the produced water analysis of produced waters so far. FO is a promising future alternative, but it is a more complex process, requiring two stages. More research at higher salinity is needed and efforts should focus on the optimization of draw solutions and the draw regeneration stage. 5. Conclusions The treatment of wastewaters produced in the shale gas production process poses a big challenge for the development of fracking industry. The questions to be considered to explore the best options in wastewater management include:

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1. Will the industry grow at a significant pace in order to accept the reuse of flowback water in the form of re-used hydraulic fracturing fluid? 2. Will the goal be a zero liquid effluent? 3. What will be the fate of high salinity brines produced by desalination technologies? 4. Will the treatment take place on-site by means of modular plants, or will centralized treatment plants be more efficient? In the absence of adequate operational experience, It is still too early to answer these questions for the shale gas industry via fracking. For now, there is a need to understand the composition and time-evolution of flowback and produced waters in the different shale plays where hydraulic fracturing takes place. Once these effluents have been characterized, it will be possible to select and optimize the most appropriate treatment technologies for each scenario. No single technology is likely to result in the effluent requirements for discharge or re-use in outside hydraulic fracturing. More likely, a combination of pre-treatment techniques and new desalination technologies available will have to be optimized in order to minimize the environmental impact of wastewaters from shale gas production by hydraulic fracturing.

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