1 The Background of Hydraulic Fracturing

1.1 Types of unconventional hydrocarbon resources

Oil sands

Extra heavy crude oil or bitumen trapped in unconsolidated sands. Examples include the Athabasca Basin tar sands in the McMurray Formation, Alberta, Canada, and the Orinoco Basin heavy oil belt in Venezuela. Oil sands are extracted using surface mining and in situ steam‐assisted gravity drainage (SAGD), and significant post‐extraction processing is required, which is energy-intensive.

Oil shale

Organic‐rich shales and fine‐grained rocks containing significant volumes of kerogen. Oil shale is extracted in open‐pit mines and in situ. An example of oil shale is the thick deposits of the Piceance Basin. Southwestern Wyoming, northwestern Colorado, and northeastern Utah host some of the largest oil shale deposits in the world. Significant post‐extraction processing is required, which is energy-intensive. The oil shale is heated up to about 500°C in the absence of oxygen as part of the energy‐intensive post‐extraction processing.

Coalbed methane

Natural gas associated with coal seams. Removal of methane prior to mining has been ongoing for decades. A standard method of extraction, hydraulic fracturing, and horizontal wells has been designed for coalbed methane projects to maximise the intersections of the natural fractures found in coal. Water is coproduced with the methane. In the early 1980s, methane was extracted from the bituminous coalbeds in the Black Warrior Basin in Alabama. Other areas of coalbed methane include the Powder River Basin in Wyoming, the San Juan Basin and Raton Basin in Colorado and New Mexico.

Residual oil zones (ROZs)

Well‐documented ROZs exist in the Permian Basin in West Texas in the San Andres dolomites as well as near Prudhoe Bay on the North Slope of Alaska. ROZ formations, which are now a target for unconventional oil production, appear in cores and geophysical logs as a partially produced oil field with a portion of residual oil left in place.

ROZs are frequently produced in areas with (i) existing oil production infrastructure and (ii) a large number of existing wells and geologic data, which lowers the exploration risk of a dry hole. In addition, the unconventional oil and gas production methods of horizontal drilling combined with high‐volume hydraulic fracturing using specialised chemicals can be used.

Tight oil

Light to medium crude oil trapped in shales and low‐permeability sands require hydraulic fracture stimulation, horizontal drain holes, and specialised extraction chemicals. The Bakken Formation in the Williston Basin in North Dakota, Montana, Saskatchewan, and Manitoba is an example.

Tight gas

Gas produced from regional sandstones and carbonate reservoirs with low porosity. These reservoirs contain the gas that migrated into the tight formation, generally having <0.1 millidarcy matrix permeability and <10% matrix porosity but were sourced from other formations. Horizontal drilling has been used successfully to extract the tight gas.

Shale gas

Thermogenic methane and natural gas in black shales with high organic content. The extraction of shale gas requires hydraulic fracture stimulation, horizontal drain holes, and specialised extraction chemicals. An example is the Marcellus Formation in Pennsylvania and several other states within the Appalachian Basin.

1.2 How does it work?

Hydraulic fracturing was commercially introduced by the U.S. company Statolind Oil in 1949 but had its origins in the use of explosive liquids to “shoot” (i.e., stimulate) oil wells in the 1860s (Montgomery & Smith, 2010, p. 27). Now commonly referred to as fracking, it has developed into a process that involves the pumping of “frac fluids”—a mixture of primarily freshwater, proppants such as silica sand and chemicals—under very high pressure into low permeable gas-bearing formations. This creates fractures that enable gas flow through these fractures to the well.

Figure 1. The general process of hydraulic fracturing. Source: https://doi.org/10.1016/j.envint.2019.02.019

The hydraulic fracturing process begins with finding water sources, stipulating the amount of water required, and conducting convenient wastewater management. The water obtained from the source is transported to fracking wells by a pipeline or truck and stored until used in chemical mixing. The posterior perforation process uses a mixture of water, sand, and exclusive drilling additives. During drilling, steel pipes used for casing the well should be implemented with cement to prevent entry by water, oil, or gas.

Once construction is completed, the obtained water is supplemented with additives to begin the fracturing process. The resulting fluid is injected into the well at a high pressure to fracture the rock deposit and release oil and gas. The flowback process happens before oil and gas production. It can recover the oil and gas initially generated utilising a high proportion of flowback water, which mostly contains injected water and some shale formation water [1]. Next, the process begins to produce formation water and hydrocarbons [2].

During the production phase, which lasts until re-fracturing or the well is abandoned, oil, gas, and generated water made up primarily (or totally) of formation water, arrive at the wellbore to be collected at the surface. Both the retrieved flowback and produced water undergo one of the following paths: (i) storage, (ii) disposal, (iii) treatment and reuse, and (iv) treatment and disposal. The fracking process continuously stimulates the production of oil and gas until the well is no longer productive. At this stage, the well is clogged or sealed with cement barriers and then abandoned. The process presented in Fig. 1 is a universal procedure, and some alternatives that are slightly different are adopted at various locations.

1.3 Why is it resisted?

Public acceptance is crucial for implementing energy technologies like hydraulic fracturing but currently finds strong public opposition worldwide, especially in Europe. Shale gas exploitation faces growing public opposition among individuals and civil organisations, who argue that granting permits infringes local water resource legislation that they were obtained without conducting environmental studies and that public information and participation are not allowed.

Though natural gas produces fewer carbon emissions than other fossil fuels when it burns, for some, it is questionably a “clean” energy source — especially when it comes via fracking. Moreover, as science increasingly shows, the extraction of natural gas or oil via fracking can release significant amounts of air and water contaminants that imperil the health of local communities and the environment. Consequently, many municipalities have rallied against fracking projects [3].

Shale gas development is a controversial subject, and the lessons learnt from recent negative experiences (France, Ireland, Wales, states of Washington and Maryland, the province of Mendoza, the Burgos province) can be vital for policymakers seeking to balance the needs of local communities grappling with unconventional oil/gas development with those of broader regional or national populations.

The decisive rejection for shale gas revealed in many communities at an individual level can be potentially explained by the proximity to the area, protection of rural areas, and mainly the lack of presentation of environmental compensation programs and practices. However, to date, the absence of comprehensive financial and impact compensation programs for the areas and communities where shale gas projects are likely to be developed can be understood as another relevant driver of public rejection.

Figure 2. Risks associated with fracking to the environment, human health, and climate Source: https://www.nrdc.org/stories/fracking-101

2 The Ecological Aspects of Fracking

2.1 Water-related risks

The attention given to water resources could point toward the most sensitively negative impact caused by shale gas exploration, which is also a well-known public concern.

The focus on water contamination, wastewater treatment requirements, and water resources allocation is predictable due to advancing practical industry experience and new legislation. Nevertheless, cost-effective wastewater treatment remains a challenge with no 100%-favourable solution soon [4].

There are five main stages for the water life cycle in the hydraulic fracturing process: (i) water acquisition, (ii) chemical mixing, (iii) well injection (fracking), (iv) flowback process and produced water manipulation, and (v) wastewater treatment and disposal.

Table 1. Potential risks on the different water life cycle stages. Adapted from https://doi.org/10.1016/j.envint.2019.02.019

Water allocation

The hydraulic fracturing process is widespread in Texas (U.S.) and Neuquen (Argentina), where most wells are located in regions facing moderate to extreme water stress. The climate of these areas varies from semiarid to sub-humid, and the state of Texas has faced exceptional or severe drought in recent years. Nevertheless, it can be expected that the water usage for hydraulic fracturing in these and other host areas will reach unprecedented levels.

The potential for water shortages is dependent on both the available water capacity of the system and the schedule of withdrawal [5]. Pennsylvania is another hotspot for shale practices. Recently, the state’s Department of Environmental Protection and a River Basin Commission have implemented strategies to avoid water stress due to fracking operations: tailoring the permitted volumes of water acquisition and maximum daily withdrawals according to the stream size, identifying the minimum requirements of daily pass-by flow based on the ecological functions, and encouraging recycling/reusing the wastewater.

Chemical mixing

The fracturing fluid consists of water (~94%), proppant (~5%), and various chemical additives (~1%) [6]. Sand is the most commonly used proppant — an agent that can maintain the fractures to release the hydrocarbons. Alternative proppants include resin-coated sand, intermediate-strength ceramics, and high-strength sintered bauxite and zirconium oxide. A commonly used formula of chemical additives consists of an acid, surfactant, biocide, corrosion inhibitor, breaker, crosslinker, friction reducer, clay stabiliser, gel, iron control, non-emulsifier, scale inhibitor, and pH-adjusting agent. To provide a general overview of the total amount of chemical additives used in fracking, the Council of Canadian Academies [7] reported that approximately 1000 kg of friction reducer, 0.3 m3 of corrosion inhibitor, 900 kg of disinfectant, 1.5 million kg of proppant, and 100 m3 of acid are used in a single fracturing operation per well in Canada.

Some organic components of the fluid could remain over a significant percentage of the initial concentrations at a transport distance of several meters, with an increased probability of exposure via groundwater based on mobility, persistence, toxicity, and frequency of use. Also, some biocides potentially transform into more toxic or environmentally persistent compounds, which may accumulate by adsorption onto soils and sediments.

The EPA has classified over a thousand chemicals used as fracturing additives. Nearly thirty of these were acknowledged or suspected to be carcinogens or recorded as dangerous contaminants of drinking water. What is more, fracturing additives, such as biocides, electrophilic monomers, and strong oxidants, were identified as primary risks to human health. In addition, the compositions of chemicals reaching the surface from the fracturing of the geologic formation, including petroleum hydrocarbons and metals/metalloids, are labelled as drivers of ecosystem toxicity.

Flowback and process water

The flowback and process water components that cause major concern are salt, oil and grease, natural organic and inorganic compounds, chemical additives, and naturally occurring radioactive materials (NORMs) from the shale formation. Spills and leakages could cause surface and groundwater pollution comparable to that during the chemical mixing and well injection phases.

Figure 3. An impoundment containing produced waters at a drilling operation in Texas. Source: https://www.americangeosciences.org/critical-issues/faq/what-produced-water

For example, the Texas Railroad Commission and the Commission on Environmental Quality identified that spills predominantly consisted of oil, gas, and liquid condensate rather than fracking [8]. Others observed that inorganic contamination (e.g., Cl, Na, Pb, Br, Se, V, NH4, Ra228, and Ra226) associated with spills of fracking wastewater in North Dakota is remarkably persistent up to four years following the spill events. Sadly, it has also been demonstrated that biodegradation of organic compounds in this wastewater could be inhibited in the presence of the biocide glutaraldehyde, which might be relevant for the fate and transport of potentially hazardous compounds due to accidental release or leakage.

During the last decade, many cases of pipeline leaks were documented in North Dakota, Colorado, New Mexico, and Pennsylvania, in which up to a fifth of these spills occurred within the surface water setback distance of current regulations. However, specific spill and leakage information for flowback and produced water is not easily reached by the public, hindering the risk assessment of this stage.

2.2 Carbon footprint

The climate change section will focus on the two main direct GHG resulting from shale gas exploration and exploitation, namely, methane and carbon dioxide. First, methane leakage rate is an extremely important value for GHG estimations, though widely contested in standards and the literature. Defined as the percentage of methane leaked over the total gas produced, methane leakage rate estimates vary from 0.42% to ranges of 0.66–3.9% and even as high as 3.6–7.9%.

Life cycle assessments (LCAs) are often performed for more accurate GHG emissions assessments. For example, a research study developed a systematic review of eight LCA and concluded that emissions from shale gas averaged approximately 488 CO2 equivalent/kWh [9]. With that being said, shale gas entire life cycle GHG emissions are still lower than coal for electricity generation and heating. Conflicting results were also reported for conventional versus shale gas operations for GHG emissions. The same study concluded similar emissions for this energy source, while other authors declare an increase of 1.8 to 17% for shale gas over conventional gas.

An essential aspect of unconventional carbon footprint is the proposed or implemented mitigation strategies to attenuate total GHG emissions. This focus has primarily been on initial well completion since methane leakage may be extremely high during this process. In order to mitigate these GHG emissions, a wide variety of technologies are available and are referred to as reduced emission completions (RECs).

One alternative option to venting is to recapture with the intention to sell. This option may be economically feasible considering that expected methane losses are much higher during well completion of shale gas than conventional gas because of hydraulic fracturing. From a regulatory standpoint, the USEPA defined that each well completion occurring after January 1, 2015, must employ REC in combination with a completion combustion device (flaring) [10].

Other technologies that may be considered are carbon capture and storage (CCS) in depleted shale gas reservoirs and the use of supercritical CO2 as a working fluid in hydraulic fracturing. However, studies on CCS in depleted shale gas reservoirs have yet to prove that the sequestration capacity is sufficient to offset overall GHG emissions from the industry. Supercritical CO2 has the potential to simultaneously reduce water requirements and sequester CO2, thereby reducing two critical aspects of shale gas production. However, additional tests are needed to determine the efficacy of this technology in the field.

2.3 Other environmental standards

Air quality

The fast development of shale gas in proximity to residential areas and heavily populated areas has raised concerns on the impact of local and regional air quality. Although there remains much uncertainty over this issue to date, it may be related to the fact that air pollution generated by the shale gas industry is challenging and costly to monitor. For example, sampling must take place over a long time to obtain robust results.

Therefore, it is not surprising that only a few relevant reports were found to report raw data emissions. Furthermore, of the published data, comparisons between the studies were limited due to the highly heterogeneous nature of the data collected, the number of samples taken, the type, and even the specific compounds analysed [11]. Nevertheless, some general trends are found through the analysis of available information.

Emissions are generally classified into the following categories: VOCs, PAHs, particulate matter (PMx), NOx, SOx, carbonyls—such as formaldehyde, and ozone, a secondary pollutant resulting from the reaction of NOx and VOC in the presence of solar radiation. One important contaminant that is hardly ever addressed is radon.

There is an excellent variety of equipment that may be considered a source of air pollution either through combustion or fugitive emissions. For combustion, an assortment of devices (generators, compressors, among others) utilise diesel engines during their operations since they are traditionally used in shale gas exploration and operational activities and emit various air pollutants listed above.

Land use

Land use can be defined as the conversion of land from one type of biome/management to another. Shale gas exploration and exploitation involves various building activities in the selected area. Following the successful identification of potential areas using different methodologies, well pad construction requires the removal of soil and vegetation and the transport, handling, and storage of chemicals and other materials for the building of gas pipelines, water extraction structures, and other operational facilities. These activities are liable to impact land use, cause habitat disruption, erosion, and increase noise pollution.

Figure 4. View of fracking from the air at Jonah field, Wyoming. Source: https://ecoflight.zenfolio.com/p648196342/h32638d19#h32638d19

Shale gas exploration and exploitation construction activities mainly result in risks to biodiversity due to the direct impact on habitat fragmentation and pollutant dispersion. However, these risks are still poorly reported in sustainability reports or investigated in the literature, which may be due to the required time to observe this type of impacts. Another aspect of land use relates to waste management and disposal.

Land use may also be a highly contested issue among stakeholders in highly populated areas. The European Academies Science Advisory Council highlighted that the latest multi-well pads and horizontal drilling techniques reduced building surface areas. These new methods are now commonplace in the industry, even in heavily populated areas such as Pennsylvania, which has a population density similar to most of Europe.

2.4 Requirements from governments and financing institutions

Command-and-control regulations are by far the most commonly used to minimise damage caused by unconventional extraction. As a result, they are most often used by countries where regulators are under-capacitated to police self-regulation, such as developing countries. Specialists, however, stress the importance of flexibility in environmental command-and-control regulations to optimise the environmental benefits of the regulated activities. In addition, command-and-control laws have been criticised for imposing high financial and administrative costs on companies.

In contrast, market-based regulations may impose a lower cost burden on companies and incentivise companies to implement specific regulatory measures. Some command-and-control rules can be executed voluntarily by O&G companies. In this case, companies usually pre-emptive respond to possible new regulations that may be implemented or avoid future surprises due to a sudden increase in standards or to gain competitive advantages. Voluntary code, in contrast, provides incentives but not mandates for pollution control.

Given the long-term nature of the risks that fracking poses to groundwater, operators must provide some form of financial security. This must at least be sufficient for the maintenance and continuous monitoring of wells in the long term and a contingency fund in the event of contamination, in which case the company may be required to compensate landowners financially for their losses. Financial security can be required in addition to any other financial provisioning requirements to ensure safe operations during shale extraction. In addition, the possibility of bankruptcy must be covered by adequate financial assurance, as governments mostly end up with the liabilities of bankrupt companies [12].

Finally, the sustainability transition in finance has primarily consisted of a taxonomic exercise that aims to label old finance under various declinations of sustainability (socially and/or environmentally responsible, green, ethical, etc.) designed to match multiple investors’ preferences. Although the merits of such advances have been somehow acknowledged, the sustainability transition in finance requires sustainable development goals to be embedded in the negotiation. The human and environmental aspects of fracking require a more hands-on engagement with the world of finance.

Even before COVID-19 pandemics, shale operators were facing financial challenges to maintain steady production. However, progressively stringent ESG frameworks and the decline in energy prices have reduced the revenue inflow. The debts are also escalating for some companies due to earlier taken loans. In addition, central banking institutions have shown reluctance to lend to the shale operators amid low economic activity and reputational concerns [13].

2.5 The human dimension

Anthropologists have studied the social and cultural aspects of unconventional gas developments since about 2010. This section reviews the published anthropological record and critically comments about how the topic has been addressed so far. The importance of qualitative anthropological research on the environment and fracking lies in that it can elucidate the human dimensions of contested developments otherwise largely discussed in terms of scientific risk calculations and engineering procedures.

Anthropologists have since published qualitative accounts, initially based on ethnographic fieldwork, especially in the United States and Australia, but now increasingly from places around the world. These accounts have focused on the diverse societal debates and consequences associated with unconventional gas developments and fracking. They have addressed, for example, neoliberal politics and powers of persuasion and community organising in response to fracking. Others examined the diverse social and economic impacts of unconventional gas developments on local communities, the consequences of environmental change and place-related identities, as well as debates about agricultural futures and Indigenous engagements with the gas industry.

Future anthropological research program on water and fracking might address historical diversity within communities, imaginaries and associated water values, the unfolding of epistemological tensions and fractious relationships at different scales, and variously envisioned environmental and economic futures that arise in the context of unconventional gas development. Interdisciplinary research collaboration among anthropologists, hydrogeologists, engineers and economists can assist in addressing these matters in mutually comprehensible ways and of potential value to policymakers.

A more humanistic view of natural resources surrounding fracking projects should also fuel the path of shale operators towards a more sustainable and socially engaged production.

3 Technological Challenges

3.1 The case of Vaca Muerta, Argentina

Argentina is home to the world’s second-largest shale gas prospective resources and fourth-largest shale oil prospective resources. Vaca Muerta is currently the leading commercially producing shale play outside North America.

The Vaca Muerta Formation lies beneath much of the Argentinian Neuquen Basin, which encloses a near-continuous Upper Triassic-Lower Cenozoic succession covering about 100,000 square kilometres. Thermal maturity data and modelling analysis has defined the oil and gas generation zones in Vaca Muerta. The formation comprises the following thermal maturity windows: Dry Gas, Wet Gas, Gas Condensate, Volatile Oil, Peak Oil, Early Oil, and Immature.

The conformation shown above leads to a transition zone (roughly the green zone) located between gas-rich and oil-rich districts; this, together with peak and early oil windows, contains crude oil with high molecular weight gas. Thus, enhanced oil recovery (EOR) is potentially promising in those, and some preliminary studies confirm the potential.

Local experts [14] have found the following parameters to describe auspicing reservoirs for EOR application:

  • Gas/liquid ratio (GLR) at 3kg/cm2/25°C to be 138.4 Sm3/am3
  • Gas/oil ratio (GOR) to be 141.3 Sm3/Sm3
  • GOR in tank (GOR-Tk) to be 7.4 Sm3/Sm3
  • LPG to be 210 ton/MMm3 (or 396 m3/MMm3)
  • Condensate to be 62 m3/MMm3

It is also crude rich in associated hydrocarbons (C3, C4, C5+), with an accompanying gas difficult to separate and deliver to commercial specification. These conditions cause extra venting at the tank level, excessive recycling, and a negative impact on carbon footprint due to excess methane (CH4) venting. Moreover, the gas from Vaca Muerta light oil separators has an undesired dew point for pipeline specifications [15].

3.2 Problems and common solutions

  • Security problems: venting in tanks with densities greater than that of air; gasoline with high Reid Vapour Pressure (RVP)
  • Environmental problems: reduced gas volumes not justifying LPG recovery, thus motivating venting and flaring; methane venting intensifies carbon footprint (its global warming potential is 25 times stronger than CO2); operation of devices at less than their rated maximum capability (derating) aggregating emissions from internal combustion engines.
  • Operational problems: curtailment to oil production to limit flaring; gas with a high dew point for compression and transport; high paraffine content.

Traditional solutions for these issues. Low-temperature separation (LTS) with mechanical refrigeration and reducing the dew point by Joule-Thomson (JT) expansion are common for lower flow rates of feed gas. Even combined approaches of these two can be performed, although recycling currents might turn these technologies impracticable. Even if LPG recovery was required, its storage might cause storage limitations and entangle transport logistics.

Another usual practice in the LNG industry is to use a scrub column or a C2+ recovery unit with a turbo-expander, which is comparatively higher in CAPEX and more challenging to operate. Summing up, all processes, including gas dehydration using mol sieves, heat transfer via plate heat exchangers (PHE), and LPG fractionation, contribute to raising capital expenditures.

Flow assurance is of great importance in the oil and gas industry, where the main aim is to supply and secure the transport of the well stream fluid from the reservoir to processing facilities. A root cause of many complications is paraffin wax, especially in cold fields such as Vaca Muerta. Hot oiling is one of the most popular methods of deposited wax removal in the flow lines and downhole [16]. Hot oil is heated to a temperature beyond the melting point for wax when pumped into the well.

3.3 Innovation through greener solutions

When addressing the most common challenges and limitations of shale reservoirs and their carbon footprint, a group of premises are to be considered. Firstly, one should avoid propane refrigeration. This gas can produce refrigeration at −40°C, which is not adequate for rich gas, such as shale gas, with a higher ethane content; here, a lower refrigerant temperature is required to comply with the pipeline gas-heating value specifications. Secondly, additional pressure or temperature changes needed for further separation to occur should be minimised due to safety concerns and high equipment costs associated with storing pressurised liquids. Thirdly, using recycled currents with high molecular weight is foreseen as a source of electricity for the well pad and an energy efficiency measure [15].

Electrifying well pads has many positive impacts on the environment and operational safety. The benefits of oilfield electrification are cutting GHG emissions, facilitating distributed information and remote control equipment (valves, AIB, manifolds, chemical injectors), accurate heating (electric), simplifying logistics for diesel distribution, compressors running on electricity are more efficient and less noisy, less physical space is required thanks to a more compact layout.

In North America, The USEPA Underground Injection Control (UIC) program governs more than 800,000 injection wells. To implement the UIC program, six classes of underground injection wells are established based on categories of materials injected into the ground by each type. Each class of wells also shares a similar design, construction, injection depth, and operating techniques. Wells within a class are required to meet a set of appropriate performance criteria for preserving underground sources of drinking water [17]. The UIC regulatory program includes the following broad elements: site characterisation, area of review, well construction, well operation, site monitoring, well plugging and post‐injection site care, public participation, and financial responsibility.

Oil and gas wells are conventionally abandoned once such wells are no longer deemed economically viable as production wells or enhanced production wells or have well integrity issues and problems that require closure. This class of wells historically has been more of an afterthought, but all oil and gas production states now have regulations that require the adequate plugging and abandonment of oil and gas wells no longer useful to essentially prevent migration of fluids and gas from migrating upward within or along with the well casing and potentially adversely impacting other formations and freshwater‐ bearing zones and allowing gas to migrate to the surface.

As an example of how state regulations have evolved into specific technical details, California’s plugging regulations require cement plugs to be placed at:

  • 200 ft plug straddling the surface casing shoe;
  • Plug across oil‐ and gas‐bearing strata that extend 100ft above the strata;
  • Plug rising from 50 ft below to 50 ft above the base of water‐bearing strata;
  • 50 ft plug at the surface of the wellbore

4 Conclusion

The potential impacts of the hydraulic fracturing process are categorised as follows: (i) water resources, (ii) atmospheric emissions, (iii) induced seismicity, (iv) land use, (v) occupational health and safety, and (vi) other impacts (e.g. air quality). The aspects and current consensus covered in the most relevant of these fields are discussed above, derived from previous studies’ conclusions. They are essential for facilitating more informed decisions by policymakers.

Recent studies investigated the impact of contaminated flowback waters on environmental quality, soil ecological health, and human health risk exposure to the surrounding soils of representative shale gas areas in the U.S., China, and Argentina.

Additional research and regulatory efforts are needed considering these potential risks since long-term direct measurements of air pollutants are incredibly scarce. Finally, there is growing recognition of the need to understand public attitudes to energy sources, such as shale gas, and to consider these views in policymaking.

5 References

[1] EPA, U. (2012). Study of the potential impacts of hydraulic fracturing on drinking water resources: progress report. EPA/601/R-12/011.

[2] Beckman, A., Ambulkar, A., Umble, A., Rosso, D., Husband, J., Cleary, J., … & Jeyanayagam, S. (2015). Considerations for accepting fracking wastewater at water resource recovery facilities. Water Environ. Fed.

[3] https://www.nrdc.org/stories/fracking-101#alternatives

[4] Torres, L., Yadav, O. P., & Khan, E. (2016). A review on risk assessment techniques for hydraulic fracturing water and produced water management implemented in onshore unconventional oil and gas production. Science of the Total Environment539, 478-493.

[5] Freyman, M. (2014). Hydraulic fracturing & water stress: Water demand by the numbers (p. 85). Boston, MA: Ceres.

[6] https://www.fracfocus.org/

[7] Xia, Y., & Boufadel, M. C. (2010). Environmental impacts of shale gas extraction in China. Adv Resour Environ Econ Res, 212-216.

[8] http://www2.epa.gov/sites/production/files/documents/hf-report20121214.pdf

[9] Heath GA, O’ Donoughue P, Arent DJ, Bazilian M (2014) Harmonisation of initial estimates of shale gas life cycle greenhouse gas emissions for electric power generation. Proc Natl Acad Sci U S A 111:E3167– E3176. doi:10.1073/pnas.1309334111

[10] https://www3.epa.gov/airquality/oilandgas/actions.html

[11] Costa, D., Jesus, J., Branco, D. et al. Extensive review of shale gas environmental impacts from scientific literature (2010–2015). Environ Sci Pollut Res 24, 14579–14594 (2017). https://doi.org/10.1007/s11356-017-8970-0

[12] Esterhuyse, S., Vermeulen, D., & Glazewski, J. (2019). Regulations to protect groundwater resources during unconventional oil and gas extraction using fracking. Wiley Interdisciplinary Reviews: Water. doi:10.1002/wat2.1382

[13] https://www.offshore-technology.com/comment/shale-oil-gas-trends/

[14] Evaluación de la Formación Vaca Muerta como Reservorio No Convencional: Estado Actual y Perspectivas, Manuel “Fantín” 9 de Junio de 2017

[15] https://www.wartsila.com/energy/pages/webinars/reduccion-de-huella-de-carbono-en-og-incrementando-la-rentabilidad

[16] Thota, S. T., & Onyeanuna, C. C. (2016). Mitigation of wax in oil pipelines. Int J Eng Res Rev4(4), 39-47.

[17] Surface and Groundwater Risks, Resource Quality Management, and Impacts. (2019). Environmental Considerations Associated with Hydraulic Fracturing Operations, 183–201. doi:10.1002/9781119336129.ch6