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Environmental Impacts of Shale Gas in the UK: Current Situation and Future Scenarios

Authors

  • Jasmin Cooper,

    1. School of Chemical Engineering and Analytical Science, The University of Manchester, The Mill, Room C16, Sackville Street, Manchester, M13 9PL (UK)
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  • Dr. Laurence Stamford,

    1. School of Chemical Engineering and Analytical Science, The University of Manchester, The Mill, Room C16, Sackville Street, Manchester, M13 9PL (UK)
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  • Prof. Adisa Azapagic

    Corresponding author
    1. School of Chemical Engineering and Analytical Science, The University of Manchester, The Mill, Room C16, Sackville Street, Manchester, M13 9PL (UK)
    • School of Chemical Engineering and Analytical Science, The University of Manchester, The Mill, Room C16, Sackville Street, Manchester, M13 9PL (UK)

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Abstract

This paper presents life cycle environmental impacts of UK shale gas used for electricity generation, in comparison with other fossil, nuclear and renewable options. Per kWh of electricity generated, shale gas has higher environmental impacts than the other options, except for coal. Thus, if it were to replace coal, most impacts would be reduced, including the global warming potential (GWP; by 2.3 times). However, if it were to compete with nuclear or some renewables most impacts would rise, with the GWP increasing by 5–123 times. Within a future UK electricity mix up to 2030, shale gas would make little difference to the environmental impacts of electricity generation, including the GWP, even for the most optimistic assumptions for its domestic production. This suggests that, in the medium term, shale gas cannot help towards meeting UK climate change targets and that certain renewables and nuclear power should be prioritized instead.

Introduction

Shale gas is natural gas extracted from shale rock, typically more than 1800 m below the surface, using a combination of horizontal drilling and hydraulic fracturing of the rock.1 As shale is one of the most abundant rocks globally, shale gas is an abundant resource in many world regions. Currently, it is estimated that 42 countries have significant shale gas reserves, many of which are not members of the Organization of the Petroleum Exporting Countries (OPEC).2 Of these, China has the largest share, with 15 % (31.6 trillion m3) of the world reserves, followed by Argentina (11 %), Algeria (10 %) and the USA (9 %).2 However, at present, only the latter is producing shale gas commercially, which in 2011 made up 34 % (0.22 trillion m3) of domestic production, and is predicted to increase to over 50 % (0.46 trillion m3) by 2037.3 This has resulted in low gas prices in the USA as well as plans to start exporting liquefied natural gas (LNG) by 2016; the country is expected to become a net exporter of gas by 2020.4

Outside the USA, many nations are also pursuing the exploration of shale gas; however, they face various obstacles. For example, China, despite having the largest resource, faces technological and geological difficulties because the resources are located in water-scarce areas with high population densities and the nation has little experience in onshore gas production.4 In Europe, many countries face social challenges as a result of environmental concerns and some, such as Bulgaria, France and Germany, have either banned or halted shale gas activity.5 Despite this, other nations, including the UK and Poland, are planning exploitation in the near future. For instance, the UK government has recently invited potential operators to apply for licenses to explore for shale gas.6

The UK is believed to have large resources of shale gas that could help improve its energy security significantly. The British Geological Society (BGS) estimates that the country has 36.8 trillion m3 of shale gas, the majority of which is in the North of England.7 If only 10 % of the estimated resources are recoverable, it would be enough to meet the UK’s entire gas demand for the next 50 years (based on consumption in 2012).7 However, one of the issues is that the continued use of fossil fuels, including shale gas, may prevent the UK from meeting the law-binding targets for reducing the emissions of greenhouse gases (GHG) by 80 % by 2050, based on 1990 levels.8 To reach this goal, electricity generation must be fully decarbonized by 2050.9 Given the high share of fossil fuels in the current electricity mix (∼70 %), achieving this objective appears unrealistic. Therefore, a bridging fuel is needed, to provide baseline generation capacity while coal is being phased out and nuclear and renewable capacity increases sufficiently to replace fossil fuels.9 The UK government plans to use gas as it is reliable and flexible, but this would increase gas demand, which in turn would affect energy prices as the UK is heavily dependent on gas imports.10 For this reason, the government intends to use shale gas as part of the bridging fuel, arguing that there would be a reduction in GHG emissions during the transitional period as it would be used to replace coal.9, 11

Some gas companies in the UK, such as Cuadrilla and IGas, have already invested in shale gas exploration, but development has been slow. Between 2011 and 2014, only three wells have been drilled and, of these, just one has been hydraulically fractured.12 This is largely due to the complex application and permitting system in the UK, in which operators must apply for permits to multiple bodies and organizations, including the Department of Energy and Climate Change (DECC), the Environment Agency and local authorities.12, 13

At the same time, public interest in—and opposition to—shale gas has been growing, making shale gas an increasingly contentious issue. Recent protests and unrest in the areas of England where fracking is proposed have further fuelled the controversy that surrounds shale gas.14, 15 One of the main reasons for the public opposition to shale gas is its perceived environmental impacts. However, in reality, they are still poorly understood, with most studies focusing on single issues such as air or water pollution, largely in the USA. For example, Anirban et al.16 and Kemball-Cook et al.17 found that there was an increase in the concentration of various air pollutants in the area in and around the well sites. Others also linked water contamination to shale gas extraction.1821

Several studies have considered the GHG emissions from shale gas used for electricity generation in the USA. One of the most cited, but also most controversial, studies found electricity generation from shale gas to have a higher global warming potential (GWP) than coal, ranging from 834–2225 gmath formula per kWh.22 This is in contrast to most other studies that estimate that the GWP of shale gas electricity is 36–63 % lower than that of coal with values of 206–732 gmath formula per kWh.2326

Therefore, the impacts of shale gas remain uncertain and, for many impact categories, still unknown. To broaden the understanding of the environmental consequences of shale gas, this paper considers a range of impacts which, in addition to the GWP, include acidification, eutrophication, resource and ozone-layer depletion, photochemical smog and human and eco-toxicity. Taking a life cycle approach, the impacts of shale gas used for electricity generation are estimated from “cradle to grave” and compared to other electricity sources such as conventional gas, coal, nuclear and renewables. The role that shale gas may play in the future and how that may affect the impacts from electricity generation in the UK is also considered.

Methodology

Life cycle assessment (LCA) has been used to estimate environmental impacts, following the ISO 14040/44 methodology.27, 28 LCA modeling has been carried out by using the GaBi v.6 software package.29 The goal of the study, data and the assumptions are defined below.

Goal and scope definition

The goal of the study is to estimate the life cycle environmental impacts of electricity generation from shale gas produced in the UK and compare it to the electricity sources that make up the current electricity mix in the UK: conventional gas and LNG, coal, nuclear, wind, solar photovoltaics (PV) and hydro. A further goal is to establish what effect shale gas may have on the impacts if used as part of a future UK electricity mix.

The functional unit is defined as the “generation of 1 kWh of electricity”. The scope of the study is from “cradle to grave” for all the electricity options considered (Figure 1). Specifically, the life cycle of electricity from shale gas involves the following stages:

Figure 1.

The life cycle of shale gas and other electricity options considered in the study (adapted from Stamford and Azapagic30). “Gas” represents the life cycles of shale, conventional gas and LNG. The stage unique to shale gas is indicated by the light gray box, stages unique to LNG are shown as dark gray boxes and white boxes apply to all three options. For shale gas, in addition to vertical, horizontal drilling is also needed (not shown in the figure). Broken lines denote optional stages.

  • exploration and site preparation;
  • well drilling and hydraulic fracturing;
  • well completion and gas production;
  • shale gas processing, distribution and electricity generation in a power plant (including plant construction and end-of-life decommissioning);
  • waste disposal; and
  • well closure.

These stages are described in turn next. This is followed by an overview of the other electricity options that contribute to the current UK electricity mix and a definition of future electricity scenarios to determine what effect the use of shale gas may have on the impacts. Note that, as the functional unit relates to generation rather than consumption of electricity, its distribution and end-use are outside the system boundary.

The life cycle of electricity from shale gas

Exploration and site preparation: This is the initial stage in which the area of interest is prepared for drilling activity. Typically, this involves land clearing and road construction to enable access to the site.

Well drilling and hydraulic fracturing: A well is created by vertical drilling to a depth of approximately 1500 m before deviating at an angle to form a horizontal section at least 1500 m long1 (Figure 2). A drilling fluid is used to aid the creation of the well and help carry the rock excavated by the drilling up to the surface. Many types of drilling fluid are used, but water-based fluids mixed with clay and chemicals such as barite are most common.31 After drilling, the entire length of the well is lined with steel casing to protect the surrounding rock and to improve the well’s integrity. The top section of the well has three additional layers of steel casing, to protect surface and ground water. After the well has been encased, the horizontal section of the well is perforated, typically using charges, to puncture holes in the casing.1 The well can now be fractured hydraulically.

Figure 2.

Typical shale gas well consisting of vertical and perforated horizontal sections. Inset: Injected fracking fluid fractures the rock to create a network through which the gas can travel to the well.

Hydraulic fracturing, colloquially referred to as fracking, is the pumping of high-pressure fluid into the well to create fractures in the shale layer. The fracking fluid used is typically a mixture of water, proppant (sand) and chemical enhancers.1, 32 The water pushes its way through the casing perforations to the shale, where it creates a complex network of fractures. The proppant keeps the fractures open after pumping has finished, allowing the gas to travel through them, from the shale to the gas well. The chemical enhancers improve the characterization and performance of the fracking fluid, for instance, by increasing its stability and reducing friction.

Well completion and gas production: After being fractured, the well is depressurized. The created pressure gradient allows the gas to flow from the rock into the well. However, before the gas can be extracted, the fracking fluid needs to be removed. This is also done by depressurizing, which pushes the fluid out of the well. The well is complete when the majority of liquid has been removed and shale gas flows freely and consistently.

Shale gas processing, distribution and electricity generation: The gas needs to be of a certain quality before it can be distributed and used for electricity generation. Impurities and heavy hydrocarbons are removed to produce a gas stream with a high methane concentration. The gas is then distributed through the gas network from the well site to the power plant to generate electricity.

Waste disposal and well closure: Waste from the well site consists primarily of waste fracking fluid and drilling waste. The former is treated in a water treatment plant and the latter is incinerated, spread on land, or landfilled. Finally, once the gas has been exhausted, the well is filled with cement and abandoned.

The life cycle of other electricity options

Electricity sources that currently contribute to the UK mix include conventional gas, LNG, coal, nuclear, wind, solar PV, hydro and biomass. Their respective life cycles from “cradle to grave” are shown in Figure 1 and encompass the extraction and processing of raw materials and fuels, transport of fuels (where relevant), generation of electricity, construction and decommissioning of power plants and waste management throughout the life cycle.

It can be noted from Figure 1 that conventional gas has essentially the same life cycle as shale gas, except that only vertical drilling is required and hydraulic fracturing is not necessary because of the high porosity of sandstone from where it is typically extracted (at 1500–1800 m below the surface).33 Similar applies to LNG, which is conventional gas that has been liquefied to allow it to be shipped over long distances rather than being distributed by pipelines, as is the case with conventional gas. Liquefaction is carried out by cooling the gas to under −161 °C at the place of export.34 LNG is then transported in special cryogenic ships and regasified at the point of import by gradually increasing the temperature to above 0 °C under high pressure.35 After regasification, the gas is distributed through pipelines to the power plant.

Inventory data and assumptions

Shale gas

As there is no commercial production of shale gas in the UK yet, in the absence of UK-specific data, the data for well preparation and the composition of shale gas are based on average USA data instead. However, wherever possible, these have been adapted to match UK conditions, as explained below. To determine the effect of data uncertainty on the results, three scenarios are considered: central, best and worst case. The central case represents an average-sized well that produces an average amount of gas. The best case relates to a small well that produces a large quantity of gas and the worst case represents a large well that produces a small amount of gas (Table 1 and Tables S1–S9, Supporting Information).

Table 1. Data for the shale gas well over the lifetime of the well.[a][36, 37, 39]

Factor

Central case (average)

Best case

Worst case

  1. [a] Based on shale gas production data for 2386 wells. [b] Normal m3 at standard conditions (1 bar and 15 °C).

steel [t]

513

162

823

cement [t]

702

222

1130

drilling fluid [kt]

17.3

10.6

21.7

hydraulic fracturing fluid [m3]

23 200

318

40 700

well length [m]

5080

3230

6290

estimated ultimate recovery [Mm3]

122

1260

10

fugitive methane emissions [Nm3][b]

207 400

2 142 000

17 000

drilling waste to landfill [kt]

12.9

7.8

16.4

drilling waste spread on land [kt]

2.7

1.6

3.4

drilling waste to incineration [kt]

2.3

1.4

3.0

The data for the well have been sourced from SONRIS36 and FracFocus37 (Tables S1–S9). SONRIS is a public database for oil and gas activities in the Haynesville shale play in Louisiana, USA. This is the deepest of the major US shale plays and, in that respect, most similar to the plays in the UK; therefore, it is likely that the well size and gas production statistics for Haynesville would be similar to UK shale gas wells.38 The shale well data assumed in this work are summarized in Table 1 for the central, best and worst cases based, respectively, on the average, minimum and maximum values, for the different parameters for 2386 wells in the Haynesville shale play.

The amount of drilling fluid has been calculated based on the American Petroleum Institute’s (API)39 data on the volume of drilling fluid used per volume of well. The ratio of 11 m3 of water-based drilling fluid per m3 volume of wellbore drilled has been assumed so that the total amount of drilling fluid is equal to 17 300 t (Table 1 and Table S10, Supporting Information). The assumed composition of the water-based drilling fluid is specified in Table 2. An oil-based fluid (Table S11, Supporting Information) is also considered in the sensitivity analysis later in the paper. The amount of drilling waste can be found in Table 1; for more details on the estimates of waste, see Equations (S1) and (S2) and Table S10 (Supporting Information).

Table 2. Composition of drilling fluid.[46]

Component

Composition [vol %]

water

29.3

barite

66.5

clay

1.36

thinner (acetone)

0.68

shale stabilizer (asphalt)

0.68

high temperature deflocculant (sodium carbonate)

0.54

surfactant (sodium persulfate)

0.41

fluid-loss-control polymer (methanol)

0.27

buffer agent (acetic acid)

0.20

caustic soda

0.07

The amount of fracking fluid used in each Haynesville well has been sourced from FracFocus,37 the USA fracking fluid registry. Its composition is based on the data provided by Cuadrilla,32 one of the main shale gas companies in the UK, with 99.95 % being water and sand and 0.05 % chemical enhancers (Table 3).

Table 3. Composition of shale gas.40

Component

Composition[a] [vol %]

  1. [a] At standard conditions (1 atm and 15 °C).

CH4

86.8

C2H6

8.23

C3H8

1.65

C4H10

0.94

C5H12

0.11

CO2

1.03

N2

1.24

The assumed composition of shale gas is given in Table 4. As there are no UK-specific data yet, this is based on the average composition of shale gas in the USA (Table S12, Supporting information).40 The amount of gas produced over the assumed 30-year lifetime of the well, known as the estimated ultimate recovery (EUR), has been calculated using a hyperbolic decline function [Eq. (S3), Supporting Information] and the data from SONRIS for the initial (first month’s) production of each of the 2386 gas wells considered. It was found that on average, the EUR is most typically in the range of 28–140 Mm3 (Figure S1). However, the minimum EUR was found to be five to six orders of magnitude smaller than the maximum and average values as a result of extremely low initial production rates recorded in SONRIS. For that reason, a literature value for the minimum economic or breakeven EUR41 has been used instead, which corresponds to the maximum size of the well, denoted as the worst case in Table 1. Similarly and as mentioned previously, the maximum (best case) EUR corresponds to the gas recovery from the minimum well size in the best case and the average EUR relates to the average well in the central case.

Table 4. Data for hydraulic fracturing.[32, 47]

Material

Amount per m3 of fracturing fluid

water [kg]

903

sand [kg]

155

polyacrylamide [g]

4.23

sodium salt [mg]

5.29

drilling electricity (diesel) [MJ]

44.7

The fugitive emissions of methane during the well’s operation have been estimated by assuming that 0.17 % of total gas production (EUR) is lost in this way.42 The total amount of drilling waste has been estimated based on the data for solid and liquid waste generation as summarized in Table 1 and detailed in Table S10 (Supporting Information).

It is assumed that shale gas is used in a combined cycle gas turbine (CCGT) plant with an average efficiency of 53 %, which is currently the case for electricity generation from natural gas in the UK.43, 44 The background LCA data have been sourced from the Ecoinvent V2.2 database45 and adapted for UK conditions (see Tables S13 and S14, Supporting Information).

Other electricity options and the current electricity mix

The current (2012) UK electricity mix is dominated by fossil fuels (68.7 %), with low-carbon sources making up the remaining 31.3 % (Table 5).10 Specifically:

Table 5. Current electricity mix and a future scenario up to 2030.[10, 49]

Electricity source (type of plant)

Current situation (2012)

Future scenario (2030)

 

[TWh]

[%]

[TWh]

[%]

  1. [a] CCGT: Combined cycle gas turbine. [b] LNG: Liquefied natural gas. [c] CCS: Carbon capture and storage; post-combustion CO2 capture. [d] PWR: Pressurized water reactor. [e] Anaerobic digestion: 94.9 %; plant biomass: 3.6 %; animal biomass: 2.4 %; landfill gas: 0.2 %.

coal (subcritical pulverized)

135.9

39.4

1.9

0.5

oil (steam turbine)

2.7

0.8

3.6

0.9

conventional gas (CCGT)[a]

83.5

24.2

59.1

15.3

LNG[b] (CCGT)

14.7

4.3

22.0

5.7

shale gas (CCGT)

0

0

3.4

0.9

coal and gas CCS (post combustion)[c]

0

0

33.3

8.7

nuclear (PWR)[d]

63.9

18.5

101.8

26.4

wind (offshore)

7.5

2.2

59.0

15.3

wind (onshore)

12.1

3.5

45.7

11.9

solar PV (crystalline silicon and thin film)

1.2

0.3

3.0

0.8

wave/tidal

0

0

5.3

1.4

hydro (run-of-river and reservoir)

5.3

1.5

8.5

2.2

hydro (pumped storage)

3

0.9

3.5

0.9

biomass[e] (gas turbine)

15.2

4.4

35.0

9.1

total

345

100.0

385.1

100.0

  • conventional natural gas supplies 24.2 % of electricity, of which 46 % is from the domestic supply in the North Sea and the rest is imported (Table 6 );
  • LNG provides 4.3 % and is largely imported from Qatar (98 %; Table 6);
  • coal generates 39.4 %, with most coal imported from Russia, Columbia and the USA;
  • nuclear power contributes 18.5 % using fuel sourced from Canada and Australia; and
  • wind and solar PV supply 5.7 and 0.3 %, respectively, with hydro providing 2.4 % (including 0.9 % of pumped storage) and biomass 4.4 %.
Table 6. Current gas mix and future scenarios up to 2030.[a] [10, 50]

Gas source

Current situation

Future scenario (2030)

 

(2012)

Pessimistic

Optimistic

 

[109 Nm3]

[%]

[109 Nm3]

[%]

[109 Nm3]

[%]

  1. [a] The figures include consumption for both heat and electricity generation; 25 % is used for electricity generation.

conventional gas

77.4

85.1

59

67.0

59

67.0

UK North Sea

41.7

45.8

16

18.2

16

18.2

Norway

27.2

29.9

33

37.5

33

37.5

Netherlands

7.2

7.9

10

11.4

10

11.4

Belgium

1.3

1.4

0

0

0

0

LNG (Qatar)

13.6

14.9

25

28.4

4

4.5

UK shale gas

0

0

4

4.5

25

28.4

Oil supplies only 0.8 % of electricity and is being phased out so that it is not considered here.

The assumptions made for the current and future electricity options are as follows:45, 48

  • conventional gas and LNG (CCGT): efficiency of 52.5 %;
  • coal (subcritical pulverized): 39.7 % efficiency; 90 % SO2 capture by flue gas desulfurization; 80 % NOx removal by selective catalytic reduction;
  • coal with carbon capture and storage (CCS): oxy-fuel combustion; CO2 injection into depleted gas fields and saline aquifers; efficiency of 37 % (including losses from CCS);
  • gas with carbon capture and storage: CCGT; CO2 injection into depleted gas fields; efficiency of 53 % (including losses from CCS);
  • nuclear (pressurized water reactor, PWR): 8 % mixed oxide (MOX) fuel, 8 % centrifuge enrichment and 92 % diffusion enrichment;
  • wind: 2.5 MW (onshore) and 4 MW (offshore) with 27.7 % capacity factor;
  • solar PV: 39 % monocrystalline, 60 % crystalline silicon and 1 % thin film; 67 % mounted on slanted roof, 17 % on flat roof and 16 % as building tiles;
  • wave/tidal: 7 MW with 46 % capacity factor; overtopping device such as “Wave Dragon”;
  • hydro: run-of-river and reservoirs with 82 % electrical efficiency, pumped storage with 70 % pump efficiency; and
  • biomass: anaerobic digestion (94.9 %), plant biomass (3.6 %), animal biomass (2.4 %) and landfill gas (0.2 %); gas turbine with an efficiency of 34 %.

End-of-life waste after plant decommissioning is assumed to be landfilled. The LCA data for the above options have been sourced from Ecoinvent45 and NEEDS48 and adapted to UK conditions by altering all the electricity and gas inputs to match the UK 2012 mix.

Future gas and electricity mix

As mentioned in the goal and scope definition section, the future UK electricity mix is also considered to explore the role shale gas could play in supplying electricity as well as its related contribution to environmental impacts. For these purposes, two electricity generation scenarios have been developed for the year 2030 based on projections by the UK government;49 these projections are specified in Table 5. The electricity scenarios are based on two equivalent scenarios for future sources of gas in the UK up to 2030: one based on projections by the Office of Gas and Electricity Markets (Ofgem)50 and another developed as part of this work. Ofgem’s assumptions for the extraction of shale gas in 2030 are conservative and its contribution to the overall gas mix is presumed small (4.5 %; Table 6). The second scenario takes a more optimistic approach to consider a situation in which shale gas extraction is more successful: in that case, the volumes of LNG and shale gas are swapped so that 28.4 % comes from shale gas and 4.5 % from LNG. The rationale for this is that domestic shale gas would be used preferentially over (more expensive) LNG imports. The rest of the mix is the same as that in Ofgem’s scenario. These two gas mix scenarios have been incorporated into the corresponding pessimistic and optimistic electricity scenarios, respectively, to consider the effect of different shale gas penetration on the overall impacts from electricity generation. As for the current situation, the LCA data for the electricity options in the scenarios have been sourced from Ecoinvent, making the same UK-specific adaptations as explained earlier. Future changes in technology efficiencies are not considered because of a lack of data.

Results and Discussion

The impacts of electricity from shale gas are discussed first in comparison to conventional gas and LNG because shale gas is expected to replace both domestic conventional gas and imported LNG in the future.51 This is then followed by a comparison of shale gas with the other options in the UK electricity mix with which it may also compete in the future. In a subsequent section, a sensitivity analysis explores the influence of some assumptions on the results. The final section examines the effect that shale gas could have on the impacts from electricity generation in the future, using the scenarios defined above.

Shale gas versus conventional gas and LNG

Abiotic depletion potential of elements (ADP elements)

The ADP elements for electricity from shale gas is estimated at 0.68 mgSb Eq. per kWh in the central case (Figure 3). This is almost three times higher than for electricity from conventional gas (0.24 mgSb Eq. per kWh) and LNG (0.26 mgSb Eq. per kWh). The reason for this is the chemicals used in the drilling fluid, particularly barite, which altogether contribute 98 % to this impact with the remaining 2 % being from the power plant (Figure 4). However, the depletion of elements from shale gas ranges widely, from 0.05 mgSb Eq. per kWh in the best case to 10 mgSb Eq. per kWh in the worst. Therefore, if the total amount of drilling fluid can be kept at the minimum of 10.6 kt or 0.4 L per MWh as in the best case scenario considered here (Table 1), the ADP elements from shale gas electricity would be almost five times lower than for conventional gas and LNG.

Figure 3.

Environmental impacts of shale gas in comparison with conventional gas and LNG. All impacts expressed per kWh of electricity generated. For shale gas, the height of the chart bars represents impacts for the central case. The error bars correspond to the best (minimum) and worst (maximum value) case, respectively, estimated using the values in Table 1 and the related data in the Supporting Information. Some impacts have been scaled to fit. To obtain the original values, multiply by the factor shown against relevant impacts. Impacts nomenclature: ADP elements: Abiotic depletion of elements; ADP fossil: Abiotic depletion of fossil; AP: Acidification potential; EP: Eutrophication potential; FAETP: Freshwater aquatic ecotoxicity potential; GWP: Global warming potential; HTP: Human toxicity potential; MAETP: Marine aquatic ecotoxicity potential; ODP: Ozone layer depletion potential; POCP: Photochemical oxidants creation potential; TETP: Terrestrial ecotoxicity potential.

Figure 4.

Contribution of different life cycle stages to the impacts from shale gas electricity. Drilling includes drilling fluid, equipment and waste disposal. Hydraulic fracturing comprises fracturing fluid, pumping power and equipment. For impacts nomenclature, see Figure 3.

Abiotic depletion potential of fossil fuels (ADP fossil)

In the central case, the depletion of fossil resources by shale gas is close to that of conventional gas (6.6 vs. 6.3 MJ per kWh). The slightly higher value is because of the longer drilling lengths and hydraulic fracturing, which both use diesel-powered equipment. The worst option is LNG, which has a 12–17 % higher impact than the other two electricity sources. This is due to the energy-intensive liquefaction and regasification processes. However, in the worst case, the impact from shale gas is 65 % higher than for LNG. This is largely because of the low EUR, which is to be expected given that this impact is mainly (96 %) caused by gas extraction (Figure 4). In the best case, at the maximum EUR, shale gas is slightly better (by 5 %) than conventional gas because of the larger EUR.

Acidification potential (AP)

Electricity from shale gas has the lowest AP of the three options considered in Figure 3: 0.4 gmath formula per kWh in the central case compared to 1.7 and 3.4 gmath formula per kWh for conventional and gas and LNG, respectively. This can be attributed to shale gas being less sour and of a higher quality than conventional gas, leading to lower emissions of acid gases from power plants, which contribute 45 % to this impact (Figure 4). The “sweetness” of shale gas is due to the greater depths of shale rock and higher temperature and pressure, which are unsuitable for the bacteria that decompose organic material to produce hydrogen sulfide, the process that takes place in conventional gas reservoirs.38, 52 At the top of the range, the AP is 66 % higher for shale than for conventional gas because of the low EUR value assumed in the worst case; however, it is still 17 % lower than for electricity from LNG. In the best case, the relative difference between conventional gas and LNG is much greater: 86 and 93 % in favor of shale gas, respectively.

Eutrophication potential (EP)

Shale gas electricity has an EP of 170 mgmath formula per kWh in the central case, which is 2.8 times higher than for conventional gas and LNG (Figure 3); in the worst case, it is 30 times higher. This can be attributed to the disposal of drilling waste, which contributes 38 % to this impact. The main reason is phosphorus in the soil extracted during drilling, which contains phosphorus naturally. However, if the amount of waste can be minimized, as in the best case (Table 1), shale gas becomes comparable to both conventional gas and LNG: 70 vs. 60 mgmath formula per kWh.

Freshwater aquatic ecotoxicity potential (FAETP)

The FAETP of shale gas is estimated in the central case at 13 gDCB Eq. per kWh (DCB=dichlorobenzene), which is five and three times higher than for conventional gas and LNG, respectively. In the worst case, the value for shale gas is 56 and 35 times higher, respectively. This is largely due to the toxicity of the drilling fluid after its disposal, which contributes 51 % to the FAETP. However, similar to the EP, for the minimum amount of drilling waste assumed in the best case for shale gas becomes comparable to conventional gas at 3 gDCB Eq. per kWh.

Global warming potential (GWP)

In the central case, electricity from shale gas has a GWP of 460 gmath formula per kWh; this is higher than for conventional gas (420 gmath formula per kWh) but lower than for LNG (490 gmath formula per kWh for LNG; Figure 3). Longer drilling lengths and hydraulic fracturing are the reasons for shale gas having a higher GWP than conventional gas. Conversely, the energy-intensive liquefaction and regasification lead to a greater impact from LNG than from shale gas. In the best case, shale gas is the best option with 420 gmath formula per kWh because of the high EUR assumed. In the worst case (low EUR), the impact is twice as high as for the other two options.

Despite the different assumptions and system boundaries, the GWP values estimated here (420–930 gmath formula per kWh) compare well with those reported in the literature, most of which fall in the range of 400–800 gmath formula per kWh.2326

Human toxicity potential (HTP)

At 54 gDCB Eq. per kWh in the central case, shale gas has a 37–43 % higher HTP than electricity from the other two gas options (Figure 3). This can be attributed to the disposal of drilling fluid, which contributes 21 % to the total impact (Figure 4) because of the toxic substances such as barite and acetone. Therefore, the results are sensitive to the amount of the drilling fluid considered—in the worst case, the HTP is seven times higher than in the best case, with the latter being almost the same as conventional gas and LNG (38 gDCB Eq. per kWh).

Marine aquatic ecotoxicity potential (MAETP)

A similar pattern is found for the MAETP as for the HTP, for which shale gas is the worst option by a large margin: 37 kgDBD Eq. per kWh in the central case versus 0.5 and 0.9 kgDBD Eq. per kWh for conventional gas and LNG, respectively. Like the HTP, the disposal of the drilling fluid is the main contributor to this impact (47 %). If the amount of the drilling fluid is at the maximum value considered in the worst case (Table 1), the impact is tenfold higher than in the central case; even for the minimum amount in the best case, the MAETP is still 13 times higher than for conventional gas and seven times greater than for LNG.

Ozone-layer depletion potential (ODP)

This impact is similar for shale and conventional gas (17 and 19 μgR11 Eq. per kWh, R11=trichlorofluoromethane), which is around three times higher than for LNG. This is because LNG is shipped, avoiding the need for flame retardants and coolants used in the pipeline distribution of conventional and shale gas; these contribute 77 % to the ODP of the shale gas (Figure 4). In the best case, the ODP of shale gas is still double that of LNG and in the worst, its impact is three times higher than for conventional gas.

Photochemical oxidants creation potential (POCP)

The POCP for shale gas ranges from 69–402 mgmath formula per kWh, with the central value estimated at 84 mgmath formula per kWh. The latter is 2.5 times higher than that of conventional gas, which is the best option, and 20 % greater than LNG. This is largely due to the fugitive emissions of methane (35 %) as well as the emissions of volatile organic compounds from the equipment used for well drilling. In the best case, in which the fugitive emissions are the lowest, the POCP value for shale gas approaches that of LNG; the impact from the latter is caused by refrigerants such as ethane and propane used in the liquefaction stage.

Terrestrial ecotoxicity potential (TETP)

Shale gas has the highest TETP: 1.7 gDCB Eq. per kWh in the central case versus 0.2 gDCB Eq. per kWh for the other two gas options. As for the other toxicity-related impacts, this is because of the disposal of the drilling waste, which contributes 87 % to this impact (Figure 4). However, in the best case, the TETP of shale gas is identical to that of conventional gas and LNG because of the lower amount of drilling waste assumed. In contrast, for the maximum value of the drilling waste in the worst case, the impact increases to 23.4 gDCB Eq. per kWh, which is 117 times higher than for the other two options.

In summary, the results for the central case suggest that electricity from shale gas has higher impacts than conventional gas and LNG. However, its GWP is lower than for LNG (by 7 %) so using shale gas instead of LNG could help reduce the GHG emissions. The main contributors to the impacts of the shale gas are the drilling stage (the fluid and its disposal) and the combustion of gas in power plants. By comparison, the contribution of hydraulic fracturing is small: 1–5 % for most impacts and 16 % for acidification (Figure 4). The contribution of fugitive emissions of methane is also significant for the POCP. The effect on the impacts of the assumptions for some of these parameters is explored in the sensitivity analysis in a subsequent section. First, however, shale gas is compared to other sources of electricity in the UK electricity mix.

Shale gas versus other electricity sources

The results for the central case shown in Figure 5 indicate that electricity from shale gas has lower environmental impacts than that from coal, except for the ADP elements and ODP. This is due to the impacts from coal mining and waste generated during both the mining and electricity generation. The ADP elements is 16 times higher for shale gas than coal because of the use of chemicals such as barite in the drilling fluid. However, solar PV is the worst option for this impact owing to the metallization coat used in the manufacture of solar cells. In addition, most other impacts from solar PV are higher than from shale gas, except for the ADP fossil, GWP, POCP and TETP. The ODP is three times higher for shale gas than for coal owing to the fire retardants and coolants used in transporting the gas, but nuclear power has a higher ODP still, whereas this impact from solar PV is equal to that of shale gas. In comparison with wind, shale gas is a better option for the FAETP, HTP and TETP because of the impacts associated with the materials used to manufacture wind turbines. Similarly, shale gas is a better option than biomass for the AP, EP, FAETP, HTP, MAETP, POCP and TETP because of the cultivation and processing of energy crops and their combustion in the power plant. The impacts of shale gas are all higher than those of nuclear power, except for the FAETP, HTP, MAETP and ODP because of uranium mining and fuel enrichment. Finally, the best option across all the categories is hydro-power, the impacts of which are 8–188 times lower than that from shale gas.

Figure 5.

Environmental impacts of shale gas in comparison with other electricity options in the UK. All impacts expressed per kWh of electricity generated. For shale gas, only the central values are shown. For the best- and worst-case values as well as the impacts nomenclature, see Figure 3. Some impacts have been scaled to fit. To obtain the original values, multiply by the factor shown against relevant impacts.

In the worst case (Figure 5), shale gas is still a better option than coal for six out of eleven impacts. In addition to the ADP elements, the other four impacts that are higher for shale gas than for coal are the ADP fossil (by 4 %), ODP (nine times higher), POCP (41 %) and TETP (13 times). For the former two, this is due to the low EUR; for the POCP it is because of high fugitive emissions of methane and for the TETP, it is because of the drilling waste assumed in the worst case. Compared to the other options, all impacts from shale gas are higher except for the ADP elements, which is slightly higher for solar PV (by 8 %).

In the best case, most of the impacts from shale gas are lower than for solar PV, except for the ADP fossil, GWP and POCP. These are also higher for shale gas than for wind, in addition to the AP, EP and ODP, with the remaining impacts being lower for shale gas. The ADP fossil, GWP and ODP are also worse for shale gas than for biomass in the best case, but the remaining eight impacts are lower for shale gas. In comparison to nuclear, shale gas is a better option for six impacts: ADP elements, FAETP, HTP, MAETP, ODP and TETP. Against coal, shale gas is a better option for most impacts in the central case, except for the ADP elements and ODP. However, unlike the central case, in the best case shale gas has three impacts lower than hydro: FAETP, MAETP and TETP.

Sensitivity analysis

Two parameters are examined in the sensitivity analysis: drilling fluid and fugitive methane emissions. The former is considered as it is a major contributor to most impacts (Figure 4) and the latter because these values are uncertain22, 53, 54 and influence the POCP significantly.

Drilling fluid

Different amounts of the water-based drilling fluid have already been considered above in the best, central and worst cases. Here, an alternative is considered instead: oil-based drilling fluid, which is more stable than the water-based fluid as well as being better suited for directional drilling.31 Despite these advantages, oil-based fluid is more expensive and, consequently, water-based fluids are often preferred and used. However, it is unclear which of the two options may be preferable environmentally and how the impacts from shale gas would be affected if oil-based fluid was used instead of water-based. These results are displayed in Figure 6 for the central case. The composition of the oil-based fluid is assumed to be the same as that used by IGas Energy at their Barton Moss site in the UK55 (Table S11, Supporting Information).

Figure 6.

Comparison of impacts of shale gas for water- and oil-based drilling fluids. The results refer to the central case. All impacts expressed per kWh of electricity generated. For impacts nomenclature, see Figure 3. Some impacts have been scaled to fit. To obtain the original values, multiply by the factor shown against relevant impacts.

The results suggest that the type of drilling fluid does not affect the impacts much, with the oil-based fluid having on average 5 % higher impacts, ranging from 1 % higher MAETP to 22 % greater TETP; the GWP and ODP are the same for both fluids. The exception is the ADP elements, which is 2.7 times higher for the water-based fluid because the oil-based liquid uses fewer chemical additives.

Fugitive emissions of methane

To assess the effect of fugitive emissions, the following two cases have been considered, in addition to the best, central and worst cases:

  • a maximum value of 312 200 Nm3 of methane emissions over the lifetime of the well as estimated by the US EPA,56 equivalent to a ∼0.26 % loss of shale gas for the EUR of 122 Mm3 in the central case; and
  • no fugitive emissions, whereby the methane is captured and separated from the rest of the fracking waste; known as “green completion”, operators will be required to use this technique for extraction of shale gas in the UK.57

For both emission values, all other assumptions are the same as in the central case in Table 1.

The results suggest that the only impact affected by the fugitive emissions of methane is the POCP, which increases by 17 % for the maximum emissions, relative to the central case. For the case with no fugitive emissions, the POCP is reduced by 35 %. Note that the GWP is not affected (<1 % change) as fugitive emissions contribute only 0.9 % to this impact; by comparison, the combustion of gas in the power plant contributes 87.1 %. As discussed above, these findings are based on the maximum loss rate of ∼0.26 % of the EUR as estimated by US EPA data.56 However, Howarth et al.22 found fugitive emissions to be more influential but they assumed unrealistically high emissions of 3.6–7.9 %, which have been refuted by several authors (e.g., Cathles et al.58).

Future gas and electricity scenarios

This section considers the role that shale gas could play in a future electricity supply in the UK and how this may affect the environmental impacts of electricity generation. First, the results for the future gas sources defined in Table 6 are considered, followed by the electricity mix as specified in Table 5.

Future gas scenarios

Two gas scenarios are considered to 2030: a pessimistic and an optimistic assumption on shale gas production in the UK, respectively. The results shown in Figure 7 suggest that for both scenarios the impacts are higher than they are today. This is due to a combination of two factors: the increase in gas imports that is required as domestic production continues to decline and the introduction of shale gas. On average, the impacts are 38 % higher for the pessimistic and 2.5 times higher for the optimistic scenario, compared to the current situation. The most affected categories in both scenarios are the ADP elements which increases by 2.3 and nine times, respectively and the toxicities, which are 13 % to four times higher across the two scenarios. This is largely due to the drilling waste disposal in the life cycle of shale gas as discussed previously.

Figure 7.

Environmental impacts of the future gas scenarios compared to the current situation. All impacts expressed per kWh of electricity generated. For the current situation and future scenarios, see Table 6. Some impacts have been scaled to fit. To obtain the original values, multiply by the factor shown against relevant impacts. For impacts nomenclature, see Figure 3.

If we compare the two scenarios, when shale gas replaces LNG (optimistic scenario), eight out of 11 impacts increase from 7 % to 3.9 times: the ADP elements, EP, FAETP, HTP, MAETP, ODP, POCP and TETP. Again, the toxicity-related categories are most affected. However, the remaining three impacts are reduced: the GWP, AP and ADP fossil, by up to 3 %. Therefore, although shale gas could help to reduce the GWP compared to LNG, toxicity as well as the depletion of elements and the ozone layer would increase.

Future electricity scenarios

Figure 8 shows that eight out of 11 impacts (the ADP fossil, AP, EP, FAETP, GWP, HTP, MAETP, POCP) from electricity generation decrease for both scenarios compared to the current impacts, which is largely due to the anticipated reduction in the use of coal and a growth in renewable and nuclear capacity (Table 5). The reductions in both scenarios range from 35 % for the HTP to 87 % for the MAETP; the GWP is lower by 73 % for both future scenarios. However, the ADP elements, ODP and TETP increase by 2.9–3.3 times, 10–15 % and 15–22 %, respectively. This is attributed to the higher penetration of wind and solar PV (ADP elements), gas (ODP) and wind (TETP).

Figure 8.

Environmental impacts of future (2030) electricity scenarios incorporating different contributions from shale gas specified in Table 5. All impacts expressed per kWh of electricity generated. For definition of the current and future scenarios see Table 5. The pessimistic and optimistic scenarios refer to the contribution of shale gas in 2030 as specified in Table 6. Some impacts have been scaled to fit. To obtain the original values, multiply by the factor shown against relevant impacts. For impacts nomenclature, see Figure 3.

Overall, it can be seen that there is little difference between the two scenarios, which suggests that the contribution of shale gas to the impacts of future electricity generation would be small. The greatest effect is found for the ADP elements which increases by 15 % for the high penetration of shale gas (optimistic scenario) compared with the low penetration (pessimistic). Most other impacts also increase but by a smaller rate (<6 %).

Conclusions

This paper has considered the life cycle environmental impacts of shale gas used for electricity generation in the UK. The impacts have been compared to a number of current electricity sources, including other fossil fuels, nuclear and renewables. Future gas and electricity scenarios have been considered up to 2030 to examine the role that shale gas could play in the future as well as its potential contribution to the impacts.

The results suggest that in the central case, shale gas has higher environmental impacts than conventionally-produced gas and liquefied natural gas (LNG), but has a lower global warming potential (GWP) than LNG (by 7 %). This means that if it is used to replace LNG, shale gas could help to reduce greenhouse gas (GHG) emissions.

Shale gas also has lower impacts in the central case than coal for all categories, except for the abiotic depletion potential of elements (ADP elements) and the ozone layer depletion potential (ODP). Therefore, if shale gas were to replace coal as suggested by the government, it would lead to a substantial reduction in most environmental impacts per kWh of electricity generated, with the GWP being reduced by 58 %. However, the ADP elements would be 16 times higher and the ODP three times higher. Most impacts for solar photovoltaics (PV) are also higher than those from shale gas, except for the ADP fossil, GWP, photochemical oxidants creation potential (POCP) and terrestrial ecotoxicity potential (TETP). Similarly, most impacts from biomass are higher, except the ADP elements, abiotic depletion potential of fossil fuels (ADP fossil), GWP and ODP. In comparison with wind, shale gas is a worse option for most impacts except for the freshwater aquatic ecotoxicity potential (FAETP), human toxicity potential (HTP) and TETP. It also has higher impacts than nuclear power, bar the FAETP, HTP, marine aquatic ecotoxicity potential (MAETP) and ODP. Overall, the best option across all the categories is hydro-power, for which the impacts are 8–188 times lower than those of shale gas.

In the best case, shale gas is a better option for nine impacts than electricity from coal and for eight impacts than solar PV and biomass. Against nuclear and wind, six and five impacts are lower for shale gas, respectively, whereas against hydro, it is better for three impacts. However, assuming the worst-case scenario, shale gas is the worst option across all the impacts. The exceptions are coal, against which shale gas is better for six impacts and solar PV, which has a higher ADP elements.

The main contributors to the impacts of shale gas are the drilling fluid and its disposal as well as the combustion of gas in the power plant; the contribution of hydraulic fracturing is small (5 %). The results indicate that minimizing the amount of drilling fluid used could reduce the impacts by 9–92 %. If oil-based drilling fluid was used instead of the more commonly used water-based fluid, the impacts would increase on average by 5 %. The exception is the ADP elements, which is 2.7 times higher for the water-based fluid. Fugitive emissions of methane have little effect on the impacts except for the POCP.

If shale gas were to replace LNG in a future gas mix in the UK, eight out of 11 impacts would increase by between 15 % and 3.9 times: the ADP elements, eutrophication potential (EP), FAETP, HTP, MAETP, ODP, POCP and TETP. However, the GWP, ADP fossil and acidification potential (AP) would be reduced by up to 3 %. Therefore, although shale gas can help reduce the GWP compared to LNG, the toxicities as well as the depletion of elements and the ozone layer would increase.

Within an electricity mix, shale gas would make little difference to the environmental impacts of electricity generation even for the most optimistic levels of penetration considered here. The greatest effect would be on the ADP elements, which would increase by 15 % for a high- compared to a low-penetration of shale gas. The other impacts would also increase by 1–6 %; the GWP would be unaffected.

Therefore, these results suggest that in the medium-term shale gas cannot help towards meeting the UK GHG emission targets even if it were to replace coal and LNG and that other options, such as certain renewables and nuclear power, must be prioritized instead. However, other drivers such as the security of energy supply and future costs of energy must also be taken into account—if, as argued by the government, shale gas can help improve these, then the future role of shale gas in the UK will depend on the perceived importance of these drivers against the climate change targets.

Acknowledgements

This work was funded by the UK Engineering and Physical Sciences Research Council and The University of Manchester’s Alumni Donor Society. This funding is gratefully acknowledged.

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