You're viewing our new website - find out more

Publication - Research Publication

Unconventional oil and gas: compatibility with Scottish greenhouse gas emissions targets

Published: 8 Nov 2016

Research into the compatibility of unconventional oil and gas with Scottish greenhouse gas emissions targets.

92 page PDF


92 page PDF


Unconventional oil and gas: compatibility with Scottish greenhouse gas emissions targets
Chapter 3: Emissions scenarios relating to unconventional oil and gas extraction

92 page PDF


Chapter 3: Emissions scenarios relating to unconventional oil and gas extraction

This chapter sets out estimates for the emissions relating to shale production in Scotland, reviews the available technologies and techniques to mitigate them and presents comparisons with lifecycle emissions of imported gas.

We focus here on the impact on Scottish emissions due to production, rather than combustion, transmission or distribution, on the basis that Scottish fossil energy consumption and methane leaks from the gas grid are unaffected by the development of an onshore industry.

In principle, changes in gas consumption could also affect the level of fugitive emissions from the transmission and distribution grid. These emissions are important and should not be ignored; we intend to return to these emissions as part of our future work programme.

In this chapter, we set out our analysis on the range for the potential emissions footprint of Scottish unconventional oil and gas production, opportunities to limit these emissions and how they compare to the emissions associated with imports, in three sections:

1. Sources of emissions relating to unconventional oil and gas production
2. Emissions mitigation opportunities and costs
3. The regulatory framework in Scotland

1. Sources of emissions relating to unconventional oil and gas production

Oil and gas wells are developed over four main stages: exploration, well development, production and well decommissioning and abandonment. Greenhouse gas emissions occur at each of these stages. We have included these emissions in our analysis in four categories:

  • Fugitive emissions, which include both vented emissions and unintentional leaks. Vented emissions are a result of planned releases, where permitted, as a result of maintenance operations and safety concerns. Unintentional methane leaks include those from valves and pipe joints, compressors, well heads and accidental releases above and below ground from the well through to injection into the grid or before being put to use.
  • Combustion emissions that occur from on-site burning of fossil fuels. The emissions come from engines, such as those used for drilling and hydraulic fracturing, as well as from any flaring of gas.
  • Indirect emissions that result from transporting materials and waste to and from site.
  • Land-use change emissions, which include the CO 2 released ( e.g. from the soil) when land is converted from one use to another, as well as any emissions relating to land remediation during decommissioning.

Top-down approaches to estimating methane emissions, via sampling of atmospheric methane concentrations, tend to produce higher estimates for the proportion of gas being released than bottom-up studies (Box 3.1). However, top-down studies cannot currently attribute emissions to particular sources ( e.g. shale gas production), nor do they allow detailed analysis of the opportunities for reducing these emissions.

We have therefore based our analysis on the best available bottom-up evidence base (Box 3.2), in order to estimate ranges for potential emissions in a Scottish context. We will keep top-down measurements under review to ensure that our estimates of methane emissions from onshore production reflect the available evidence as best as possible. The gap between top-down and bottom-up estimates for the US does, however, suggest there are risks of significant emissions from super-emitters. We reflect this in our consideration of regulatory issues below.

Box 3.1. Top-down vs. bottom-up estimates of methane emissions

There have been several recent studies aimed at further understanding fugitive methane emissions associated with onshore oil and gas production in the US. [34] A key focus of these studies has been regions with a recent increase in unconventional oil and gas production. The measurement surveys employed both 'top-down' and 'bottom-up' approaches. Top-down studies measure or estimate (from satellite remote sensing) the concentration of emissions in the atmosphere and use different modelling approaches to estimate the methane emitted from a region. Bottom-up studies measure or estimate the emissions from an individual component or facility directly. [35]

A recent series of top-down studies, which measure the methane concentration in the atmosphere, have found methane emissions from mainly shale gas producing regions of up to 2.8% of throughput. [36] In regions with a large proportion of oil production, as expected in Scotland, the fraction of methane production lost could be up to around 9% [37] (a higher proportion of a much smaller quantity of methane production). [38] This higher leakage rate is explained in part by gas not being the primary product, with some of the produced methane being flared (a proportion of methane will pass through the flare unburned) or vented due to the absence of gas infrastructure that would enable its productive use.

The KPMG scenarios assume that the co-producing wells produce a significant volume of gas, which would mean it would be likely that gas produced is put to effective use. However, it may turn out that some shale wells produce small volumes of gas and it is therefore uneconomic to put this gas to effective use. Techniques and technologies exist to ensure that a very small proportion of the methane produced in this way is released to atmosphere (section 3).

A recent study has further highlighted a 30% increase in atmospheric methane (both anthropogenic and biogenic) concentrations between 2002 and 2014 in the US. Although the paper does not attempt to identify the source of methane, [39] this period coincides with the development of unconventional oil and gas. A further study has estimated that 40% of recent growth in atmospheric methane between 2007 and 2014 can be attributed to oil and gas activities. [40]

Top-down studies do not yet have sufficient resolution to identify the source of emissions, so it is not possible to say whether these methane emissions are due to shale gas production. Attempts to reconcile top-down and bottom-up estimates suggest that the two approaches may not be inconsistent, although some increases to US inventory emissions factors may be necessary. [41] The factors which may enable top-down and bottom-up estimates to converge are: ensuring top-down studies report fossil methane only; having accurate facility counts for bottom-up analysis; and characterising the contribution of super-emitters accurately.

It is therefore important that top-down studies are integrated further with the bottom-up approach in order to reduce the gap between the two techniques. [42] , [43]

Box 3.2. Sources for the data on emissions

We have obtained estimates for the greenhouse gas emissions associated with unconventional oil and gas exploitation from various sources:

  • We have used various sources to estimate the emissions not currently covered by the UK greenhouse gas inventory, including emissions from unconventional oil and gas. The range of sources of unconventional oil and gas varies in quality and volume of information available.
  • A growing number of studies have been developed on the lifecycle analysis of natural gas supplies, with many comparing lifecycle emissions for shale gas to those for other sources of energy. Until recently the majority of these studies relied on engineering assumptions in the absence of primary data.
  • More recently, the Environmental Defense Fund, a US NGO, has funded a group of studies that measured both individual sites and entire regions.

In September 2015, the Sustainable Gas Institute ( SGI) produced a comprehensive literature review on the available evidence on GHG emissions from the exploitation of gas. We have used this as the basis for our emissions data, supplemented by a few more recent studies. We therefore use a combination of measured emissions data (primarily for methane) and modelled data (primarily for CO 2). Our supporting annex sets out how we have used the available data to produce our quantitative analysis for this report.

The emissions associated with production primarily come from the well development and production stages:

  • Exploration emissions are generally small, relating to transporting the seismic equipment and drilling the exploration well. Small volumes of gas may be generated during the development of the well, most of which is likely, at a minimum, to be burned in a flare. There is, however, little information available on emissions associated with exploration. [44] Most studies analysing the GHG emissions from exploiting unconventional oil and gas either ignore this phase or assume the emissions are negligible. [45] It should not be taken as a given that emissions from exploration will be low, especially for any extended well tests. Appropriate mitigation techniques should be employed where practical.
  • Pre-production / well development emissions result from site preparation, transporting the equipment and construction materials to site, and drilling and completing the well. The key emissions from this stage are expected to be from well completion and potentially land-use change:
    • Well completion. Once hydraulic fracturing is complete a period of 'flowback' follows over a period of three to ten days, during which some of the fluids return to the surface mixed with increasing volumes of oil and gas. In the US, the gas mixed in with the flowback fluid has historically been predominantly vented to the atmosphere. Emissions from this stage have been disputed, partly due to the use of modelled rather than measured emissions (Box 3.3). The volume of gas produced during completion is linked to the age of the formation, the pressure of the well and the initial flow rate, both of which are indirectly linked to the estimated ultimate recovery ( EUR) of the well (see Chapter 2). Therefore, the emissions associated with completion will be positively correlated with the EUR, although this relationship is unlikely to be directly proportional.
    • Land-use change. The SGI report indicates that the GHG emissions are small at all the stages up to well completion. However, a lifecycle analysis for the Scottish Government has highlighted a further potential key source of emissions, suggesting that land-use change emissions could be significant if development occurs on carbon-rich land. For grassland, land-use change emissions are estimated to be in the region of 920 tCO 2 per well or 1,800 tCO 2 per TWh. However, should production instead occur in an area with deep peat soil, estimated emissions are around 10 times higher, at around 10,000 tCO 2 per well or 20,000 tCO 2 per TWh. [46] Land-use change emissions may also be significant for other types of land.
  • Production. Emissions from UOG production result from the general operation of the well. For the gaseous element this includes gathering and compression equipment, and gas processing, before injection into the gas grid. For the liquid element, this includes onsite storage and transporting it for processing. [47] The key emissions come from workovers, liquid unloading, leaks and vents:
    • Workovers. After a period of time the production well generally requires significant maintenance, known as 'workovers'. This covers a range of tasks, such as fixing leaks, descaling the well, cleaning out the perforations, or creating new ones. It may also require some hydraulic fracturing work. The number of re-fracturing events varies considerably and is ultimately an economic decision to improve the productivity of the well. The frequency of workovers is estimated in the literature to be between one every six years and one every 30 years. [48]
    • Liquid unloading. The flow of gas through the well may become impeded due to a build-up of liquids that accumulate at the bottom of the well, especially if the gas is wet. Early in the well's life the flow of gas is sufficient to wash these out of the well, but when the flow of gas decreases liquids may begin to accumulate. The range of measured and estimated emissions from liquids unloading is extremely large, with little understanding for this variation and of how and why these emissions vary across wells in different regions and of various ages. [49] It is currently uncertain how many shale wells in Scotland would require liquid unloading.
    • Pneumatic devices. Pneumatic devices are used widely in the gas production stage for control or measurement. They typically use the pressure of the natural gas in the pipeline for the operation of valves, instruments and pumps, which results in a small release of methane. Although each pneumatic device emits a small volume of methane there is likely to be a large number of devices throughout the supply chain. The US Environmental Protection Agency ( US EPA) report that this contributes to 14% of gas supply-chain emissions in the US. [50]
    • Compressors. Compressors are also used throughout the gas production stage in order to boost the gas pressure. Compressors generally emit gas through seals and during blowdown, [51] and are estimated to be responsible for 20% of emissions in the US. [52]
    • Super-emitters. One of the major contributors to overall production emissions is found to be from what are referred to as super-emitters: significant leaks of methane left unchecked for significant periods of time. There is recent evidence [53] that 2% of oil and gas sites on the Barnett shale are responsible for half the methane emissions and that 10% are responsible for 90% of the emissions. This may help to explain some of the differences between 'top-down' and 'bottom-up' estimates of methane emissions (see Box 3.1 above). Locations of these super-emitters are hard to predict and change over time. Further work is required to understand the characteristics that cause individual sites to be a super-emitter. Although a complete avoidance of super-emitters may be unachievable, with suitable operational control and maintenance procedures these high emitters could be largely eliminated. [54] If the super-emitter sites could be brought in line with the average, then total supply chain emissions would be reduced by 65-87%. [55]
  • Well decommissioning and abandonment. Over time, the plugs intended to prevent further fluid migration can deteriorate, releasing to atmosphere the methane that has built up in the well. There is recent evidence to suggest that these emissions are low. [56]

Box 3.3. Measured as against modelled emissions

Based on modelling of emissions from 'flowback' it has been estimated that over 3% of the gas produced from a shale gas well could be vented to the atmosphere; [57] subsequently a large number of reports have produced modelled estimates for the completion emissions. Only recently have these emissions been measured. [58]

Table B3.3 shows the large discrepancy between the measured and modelled numbers over the range of literature as presented by the SGI. The SGI report suggests that this discrepancy is due to most of the modelled estimates being based on disputed engineering calculations based on initial gas production rates being constant throughout the well completion period. This assumption does not take into account fracturing fluid which returns during this process, which would limit the gas flow.

Table B3.3. Measured and modelled estimates of emissions from completion (m 3 methane)

Source Mean Median Min Max
Measured data 11,900 5,800 300 537,000
Modelled estimates 606,000 245,000 1,300 6,800,000

Source: SGI (2015), Methane and CO 2 emissions from the natural gas supply chain,

Notes: Table 1 in SGI reports the maximum measured data as 100,000 m 3 but later in the discussion gives a figure of 537,000 m 3.

2. Emissions mitigation opportunities and costs

The US natural gas STAR programme has investigated cost-effective technologies and practices that improve operational efficiency and reduce emissions of methane. [59] The programme has covered all the stages of the gas supply chain from production through to distribution, providing estimates for potential emissions mitigation, capital costs and payback relating to each mitigation technology.

The STAR programme is currently finalising its best management practices ( BMP) commitment framework, where partner companies will employ appropriate mitigation technologies across their operations. [60]

Measures to limit emissions can lead to cost savings, as they avoid leakage of product that could otherwise be sold. Those which incur net positive costs often save emissions at relatively low cost per tonne of CO 2-equivalent, due to the benefit of avoiding emissions of methane, which is a potent greenhouse gas (see Chapter 1). The evidence from the STAR programme shows that there is a range of ways to limit emissions from shale production at costs well below UK Government carbon values: [61]

  • Techniques and technologies. There is a large range of available techniques and technologies which can be employed to mitigate fugitive methane. These techniques often enable the methane that would have been lost to be put to productive use. These include, but are not limited to:
    • Reduced emissions completions ( REC). This is a series of processes that enables the capture of the gas associated with the 'flowback' fluid during well completion stage and it being put to productive use. REC can reduce the associated emissions from completion by between 90-99%. [62] Abatement costs are estimated to range from being cost-saving up to £22/tCO 2e saved. [63]
    • Liquid unloading plunger lift. Instead of blowing out the liquids that can accumulate in the well, it is possible to use a plunger lift system which fits into the well bore. This uses the gas pressure in the well to bring the liquids to the surface, while limiting the amount of venting. The plunger lift system has been estimated to reduce emissions from liquid unloading by around 90%. [64] Abatement costs are estimated to range from being cost- saving to £13/tCO 2e.
    • Vapour recovery units ( VRU). The oil from co-producing shale wells also contains some dissolved gas (which is likely to be primarily methane). As this liquid is stored, the gas is released and can be vented to the atmosphere. A VRU will collect and compress this gas so it can be put to productive use. It is estimated that a VRU would have an abatement cost of around £4/tCO 2e.
    • Low-flow pneumatic devices. Various types of pneumatic devices are used throughout the gas supply chain, including a 'high-bleed' device, which can emit up to 7,000m 3 of gas each year. Many of these high-bleed devices can be replaced with low-bleed devices which emit 1,500m [3] per year. Replacing an existing high-bleed device with a low-bleed is estimated to be cost-saving.
    • Dry seal compressors. The seal on a compressor allows the rotating shaft to move freely. Traditionally, compressors have used an oil seal through which gas can escape. Dry seals reduce the volume of gas which leaks to atmosphere by over 90%. The cost of replacing a wet seal with a dry seal has an abatement cost of around £12/tCO 2e.
  • Monitoring. A large proportion of the gas which is emitted has been found to come from a small group of 'super-emitters'. An effective leakage detection and repair ( LDAR) programme throughout the production stage would mitigate methane emissions. It is estimated that annual inspections could reduce leakage by 40%, semi-annual by 60% and quarterly by 80%. [65] Based on labour costs and equipment costs in Canada, it is estimated that it would cost around £20,000 to survey a gas pad and associated infrastructure for leaks and undertake repairs. For example, semi-annual monitoring could have an abatement cost of around £4/tCO 2e.

Opportunities to reduce emissions exist beyond those for which cost estimates are available. While it is not possible at this stage to judge their cost-effectiveness, reasonable attempts can be made to estimate their emissions savings:

  • Electrification of pneumatic devices. Pneumatic devices are used throughout the production stage, as they have a high response rate and can enable the system to be controlled independently. It is possible to use compressed air or a different compressed gas throughout the supply chain. This could result in an emission saving of between 200 and 2,000 tCO 2e/year per device, depending on the type of pneumatic device replaced.
  • Electrification of compressors. Many compressors use a gas-fired engine to drive the compressor. Electric motors can be used instead, which have been found to reduce the chance of methane leakage (by eliminating the need for fuel gas), require less maintenance, and improve operational efficiency. It has been estimated that this could reduce methane emissions by around 3,000 tCO 2e/year per compressor. [66]

Regulation cases for emissions analysis

There is clear evidence that regulation of shale production can lead to significant reductions in its greenhouse gas footprint. The US EPA has recently announced a programme of work to produce comprehensive regulations to reduce methane emissions from the oil and gas industry. [67]

In our UK advice on onshore petroleum, [68] we set out four cases for the regulation of shale gas production, based on the evidence about the efficacy and cost of the various technologies and techniques to limit emissions from shale production. One of those cases, which we called 'Current UK position' reflected the Environment Agency's view that reduced emissions completions would be required.

The regulatory framework in Scotland differs from that in the rest of the UK. There is currently a moratorium in place, during which the Scottish Government has pledged to look at further tightening of regulation (section 3). The measures that would be required under the existing framework are also relatively unclear. We have therefore not attempted to reflect the current position, and instead present three cases for the regulation of onshore oil and gas production:

  • No regulation. Under this case, no measures are implemented to limit greenhouse gas emissions. This does not reflect the current or anticipated framework, but rather acts as a baseline for comparison purposes in order to show the emissions reductions available through regulation.
  • Minimum necessary regulation. This further assumes deployment of mitigation options available at low cost, according to the evidence outlined above. As well as reduced emissions completions, this includes liquid unloading mitigation technologies ( e.g. plunger lift systems) and semi-annual monitoring. It does not, however, include technologies that are identified as cost-effective but where the quantity of abatement is uncertain due to the difficulty of estimating the quantity of devices ( e.g. low-flow pneumatic devices, dry seal compressors and vapour recovery units).
  • Fuller technical mitigation options. This further assumes deployment of mitigation options for which the emissions saving can be reasonably estimated. This includes electrification of control valves and some compressors, although this entails some estimation of the quantity of abatement relating to the number of devices. This case could also include measures for which costs per tonne of CO 2e saved are currently estimated to be higher than UK Government carbon values [69] , which we use as a comparison to judge cost-effectiveness. However, evidence on costs to make this assessment is currently lacking.

It is likely that the industry would employ at least those measures that are cost-saving, as the increased sales revenue would outweigh these costs. The UK onshore operators group ( UKOOG - the onshore oil and gas trade body) has guidelines that state that "operators should plan and then implement controls in order to minimise all emissions."

The results presented here include estimates of land-use change emissions that result from development of wells on grassland. Were the development of wells instead to occur in areas that have much greater potential for carbon release ( e.g. areas of deep peat soils), then land-use change emissions would be much greater and could dominate the results. Given the scale of such potential emissions, production on such land should not be allowed.

In our analysis we have assumed that gas produced in co-producing well will be put to productive use, as the levels of productivity in the KPMG scenarios is likely to make this economic. [70] Should the gas co-produced with liquids be flared or vented instead then the emissions footprint attributable to the liquids will be considerably higher. This will vary on a case-by-case basis.

For each of the three regulation cases we have used the available evidence to produce low, central and high estimates for emissions that might occur (Box 3.4). Our supporting annex described the various stages at which emissions can occur, some of which scale with the number of wells drilled (well preparation, completion, liquid unloading and workover), while others scale with the amount of gas produced (processing and normal operation) (Figures 3.1 and 3.2).

Combining these sets of emissions requires an assumption on average well productivity ( i.e. the energy produced per well). For consistency we have used a figure of 0.83 TWh/well for gas (for all wells) and 0.1 TWh/well for liquids (for 75% of wells) to combine these emissions (Figures 3.3 and Figure 3.4), based on data provided by KPMG. High levels of average productivity would imply lower emissions per unit of energy produced and also lower costs per unit energy (see Chapter 2), and conversely low productivity would lead to high unit emissions and unit costs.

Under central estimates, the 'Minimum necessary regulation' case saves 39% of emissions relative to the 'No regulation' case, compared with 58% savings under the 'Fuller Technical Mitigation Options' case (Figure 3.5).

Methane emissions dominate total greenhouse gas emissions in the cases with the highest emissions. These also have considerably greater potential to be abated than the CO 2 emissions, highlighting the importance of measures to limit methane emissions (Figure 3.6).

In these results, we present the emissions per TWh, treating oil and gas output equivalently. However, it is the gas production that leads to the large majority of the methane emissions and therefore the emissions per TWh produced will generally be higher for gas-only wells than for co-producing ones.

The results show that technologies and techniques to reduce emissions can have a substantial effect on the greenhouse gas footprint of production. For the high-end emissions estimates, the 'Minimum necessary regulation' case saves 54% of emissions relative to the 'No regulation' case, compared with 39% for central estimates and 25% for low-end estimates.

These results show that these measures to limit emissions are not only important in reducing central estimates for emissions, but are also essential in guarding against the risk of much higher emissions ( e.g. due to super-emitters). This underlines the importance of a regulatory approach that requires such an implementation of techniques and technologies, with clear consequences should these requirements be violated.

Box 3.4. Low, central and high emissions estimates

In order to produce our low, central and high emissions estimates for the median well in Scotland, we have applied, where possible, the measured range presented in literature from the recent bottom-up emission measurement campaigns. These have shown a large range in the measured results and represent only a small sample set when compared to scale of the industry in the US, so there is still a large degree of uncertainty surrounding them. It is also uncertain how applicable these emissions estimates are to any future industry in Scotland. This high degree of uncertainty necessitates a large range in our emission factors.

  • High emissions estimate. The high scenario is what we estimate to be the worse-case scenario for a typical Scottish shale well. It has been developed using a mix of both high and median data, depending on the extent and distribution of the available data.
  • Central emissions estimate. This represents our best estimate for a typical well in Scotland. It primarily uses the median emissions as presented in literature.
  • Low emissions estimate. The low estimate represents what we assess to be the best-case scenario for a typical well in Scotland. It uses a combination of low and median values that we consider relevant to Scotland.

The methane emissions as a proportion of throughput are shown for our three regulations cases, under high, central and low assumptions in Table B3.4.

Table B3.4. Range of methane emissions as a percentage of gas throughput

  No Regulation Minimum necessary regulation Fuller technical mitigation options
High 4.9% 0.9% 0.6%
Central 1.8% 0.5% 0.3%
Low 0.7% 0.3% 0.2%

Source: Various, with CCC calculations.

Notes: The 'No regulation' case does not reflect the current or anticipated framework, but rather acts as a baseline for comparison purposes in order to show the emissions reductions availablethrough regulation.

Figure 3.1. Emissions that scale with the number of wells under different regulation cases

Figure 3.1. Emissions that scale with the number of wells under different regulation cases

Source: CCC analysis.

Figure 3.2. Emissions that scale with energy production under different regulation cases

Figure 3.2. Emissions that scale with energy production under different regulation cases

Source: CCC analysis.

Notes: Processing is often required to ensure the necessary gas quality for gas grid injection. Normal Operation relates to operation of the well and gathering line ( i.e. pipes and pumps moving the gas to the processing plant).

Figure 3.3. Total emissions with central well productivity assumptions under different regulation cases

Figure 3.3. Total emissions with central well productivity assumptions under different regulation cases

Source: CCC analysis.

Notes: Data on per-well emissions (Figure 3.1) and per- TWh emissions (Figure 3.2) have been combined using a central assumption on median well productivity of 0.83 TWh gas (all wells) and 0.1 TWh liquids (75% of wells).

Figure 3.4. Total emissions depending on well productivity under different regulation cases

Figure 3.4. Total emissions depending on well productivity under different regulation cases

Source: CCC analysis.

Notes: Based on a range of 0.26-1.3 TWh (1-5 bcf) gas per well, with a central assumption of 0.83 TWh (3.2 bcf).

Figure 3.5. Differences between the regulation cases under central estimates

Figure 3.5. Differences between the regulation cases under central estimates

Source: CCC analysis.

Figure 3.6. Emissions of methane and carbon dioxide under different regulation cases

Figure 3.6. Emissions of methane and carbon dioxide under different regulation cases

Source: CCC analysis.

Notes: As discussed in Chapter 1, CO 2 and methane emissions are presented on a GWP100 basis. Use of a different metric for emissions (see Box 1.3) would lead to a change in the relative emissions of methane and CO 2.

Traded vs. non-traded emissions

Within the overall emissions footprint relating to shale production, some emissions are in the 'traded' sector ( i.e. covered by the EU emissions trading system - EU ETS), while other emissions are outside this and are therefore in the 'non-traded' sector:

  • Traded sector emissions. Emissions covered by the EU ETS include CO 2 emissions from flaring, gas processing and power generation. Within this, electricity generation is not eligible for the allocation of free allowances under carbon leakage rules, while the other sources are eligible.
  • Non-traded sector emissions. The EU ETS primarily covers CO 2 emissions, and all methane emissions are outside its scope.

The implications of this treatment of emissions for meeting Scotland's emissions targets are explored in Chapter 4. Given the vote to leave the EU, the UK's future role in the EU ETS is uncertain. We will publish a further assessment of the issues in the autumn.

3. The regulatory framework in Scotland

Left entirely unregulated, the emissions footprint of unconventional oil and gas production could be substantial. Any significant level of exploitation of domestic resources in this way would be inconsistent with Scottish emissions targets. However, as set out in section 2 above, there are technologies and techniques that are known to limit greenhouse gas emissions from shale production. Experience and data from the US provide estimates of the costs and effectiveness of many of these measures.

There is currently a moratorium in place, during which the Scottish Government has pledged to look at further tightening of regulation. [71] It is essential that this tightening does occur before any UOG production commences in Scotland.

The present regulatory regime in Scotland is unclear in relation to the respective roles of the different organisations in the permitting and planning process. There may also be gaps in relation to emissions occurring outside the production site ( e.g. from supporting infrastructure such as pipelines, processing facilities and gathering stations) and more generally in relation to emissions to the atmosphere, especially fugitive methane emissions. [72]

Before any production can occur, in order to ensure that domestic UOG production can be compatible with emissions targets:

  • The regulatory regime requires much greater clarity over the roles of the different actors (Health and Safety Executive, Scottish Environmental Protection Agency and local authorities), and that these be managed seamlessly.
  • The regulatory framework should ensure that regulation covers all emissions of both CO 2 and methane, requires strict limiting of these emissions and entails long-term monitoring.
  • It is also essential that the requirement for methane mitigation extends beyond the well pad to all associated infrastructure prior to the gas being injected into the grid or put to use ( i.e. encompassing not only the production site itself but also related infrastructure).

The minimum set of techniques and technologies required to limit emissions can do so at a cost comparable to the cost of reducing emissions elsewhere in the economy, consistent with the requirements of Scottish emissions targets. As evidence improves, it is likely to be cost-effective and necessary to require the inclusion of further emissions reduction measures.

The KPMG scenarios assume that the co-producing wells produce a significant volume of gas, which would mean it would be likely that gas produced is put to effective use. However, it may turn out that some shale wells produce small volumes of gas and it is therefore uneconomic to inject the gas into the grid or supply a customer directly. In this case, there may be available technologies ( e.g. gas-to-liquids) that would enable the gas to be put to productive use, but at a minimum this gas should be flared, in a well-operated flare ( i.e. one which continually combusts over 98% of the methane).

We have not considered in detail the possible implications for our analysis of the recent EU referendum result. To the extent that this weakens the regulatory framework on UOG production in Scotland then domestic regulations will be required to ensure that a strong system of regulation exists in Scotland for UOG exploitation.