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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

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92 page PDF

1.8MB

Contents
Unconventional oil and gas: compatibility with Scottish greenhouse gas emissions targets
Chapter 1: Implications for fossil fuel consumption and climate impacts of methane and CO2

92 page PDF

1.8MB

Chapter 1: Implications for fossil fuel consumption and climate impacts of methane and CO2

The Committee on Climate Change has a duty under the Infrastructure Act (2015) to advise the UK Government on the compatibility of exploiting domestic onshore petroleum, including shale gas, with UK carbon budgets and the 2050 emissions reduction target under the Climate Change Act (2008). We submitted our first advice under the Infrastructure Act in March 2016, which was released in June 2016. [1]

This report covers similar ground to the UK advice, in which we focused on shale gas, although there are important differences to consider between unconventional oil and gas in Scotland as compared to onshore petroleum for the UK as a whole. These include the coverage of shale oil as well as shale gas, allowing for the development of scenarios including shale oil by KPMG ( Chapter 2); the regulatory regime in Scotland, which differs to that elsewhere in the UK ( Chapter 3); and the more ambitious targets for emissions reduction in Scotland relative to those for the UK as a whole ( Chapter 4). In addition, the Scottish Government asked us to consider the potential impact of Scottish unconventional oil and gas production on EU and global emissions. We cover this in Chapter 5.

In this chapter, we set out the state of the evidence base on onshore petroleum, and considerations around how to compare the relative climate impacts of methane and carbon dioxide, in three sections:

1. Scottish sources of unconventional oil and gas
2. Implications for fossil fuel consumption of domestic unconventional oil and gas production
3. Comparing the climate effects of methane and carbon dioxide

Chapter 2 then considers the factors that would affect the size of a Scottish unconventional oil and gas industry over time, and presents scenarios for development of a Scottish industry. Chapter 3 analyses issues relating to the emissions footprint of domestic shale gas and shale oil production, including opportunities to mitigate emissions and a comparison with the lifecycle emissions of imported sources of gas.

The production scenarios and emissions footprint are brought together in Chapter 4, which presents emissions implications under different combinations of production scenarios and regulation cases. It then assesses the flexibility to accommodate these within Scottish emissions targets and draws out implications for the measures needed to limit emissions.

Chapter 5 then considers the impacts of exploitation of Scottish unconventional oil and gas resources on EU and global emissions.

1. Scottish sources of unconventional oil and gas

The sources of unconventional oil and gas pertinent to our advice are limited to those relevant to Scotland: shale gas, shale oil and coal bed methane ( CBM). Our advice therefore excludes consideration of production outside Scotland as well as offshore (North Sea) production. Underground coal gasification is being covered by a separate study, [2] while other excluded sources such as colliery gas, tight gas, oil sands, oil shale (which differs from shale oil) are considered unlikely to be developed in Scotland. However, to the extent that they contribute to Scottish fossil fuel supplies they will also contribute to its greenhouse gas emissions.

The oil and gas extracted from conventional and unconventional sources are almost the same. The main differences relate to where the oil and gas is found and how they are commercially extracted. Conventional oil and gas has migrated from its source and is found in porous formations, through which it flows easily. By contrast, unconventional hydrocarbons are trapped in source rocks with low porosity (Figure 1.1), and where the flow therefore needs to be stimulated through hydraulic fracturing or fracking (Box 1.1).

Figure 1.1. The geology of conventional and unconventional oil and gas

Figure 1.1. The geology of conventional and unconventional oil and gas

Source: US Energy Information Administration.

Notes: The schematic shows the various sources of conventional and unconventional sources of oil and gas. This is not to scale.

Box 1.1. Hydraulic fracturing

Hydraulic fracturing is a process in which a combination of water, a range of chemicals and a proppant (typically sand) are pumped down into the well at high pressure ( e.g. 80 bar). This high pressure breaks up the shale, creating fractures that can extend to over 500 metres in height. [3]

It is estimated that between 1,200 and 45,000 cubic metres of water per well is used in this process. [4] Hydraulic fracturing is carried out in stages, in which small sections of the well lateral (the horizontal section of well) are isolated before being hydraulically fractured, starting from the furthest point and proceeding backwards. Recent common practice in the US is to increase the number of stages, which has been found to result in increased well productivity.

Within the relevant sources of unconventional oil and gas, we have considered their potential to increase Scottish emissions, and the strength of the evidence base:

  • Shale gas. Shale gas refers to natural gas that has remained in the source rock. Recent advances in technology for drilling and hydraulic fracturing have made extraction more economic.
    • The British Geological Survey ( BGS) has studied the Midland Valley, the major shale basin in Scotland. [5] BGS reports an estimated gas-in-place resource in the range 1.4 to 3.8 trillion cubic metres (tcm), with a central value of 2.3 tcm.
    • Economically recoverable reserves will be a fraction of this estimate of total resource (Box 1.2). In order to start to ascertain the Scottish reserve, a period of exploration would be required to find the most productive areas in the shale formation. In the US thousands of exploration wells were drilled before the industry took off. Trial and error identified the 'sweet spots' where productivity was highest, but even within these locations well productivity varies. A more systematic approach to exploration would speed up the exploration phase; it has been estimated such a process would take over two years to ascertain the commercial viability of the industry, although some reports estimate that it could take as long as 10 years based on the US experience. [6] , [7]
  • Shale oil is similar in chemical composition to conventional crude oil. As with shale gas, it has remained in the source rock and has been made more economic by technological advances.
    • The BGS has produced a detailed study, using seismic data and boreholes to estimate the shale oil resource in the Midland Valley in Scotland. They estimate the oil in place from 3.2 to 11 billion barrels of oil, with a central figure of 6 billion barrels.
    • The BGS report stresses that their estimates refer to the shale oil resource ('oil in place') and not how much can be recovered.
    • As with shale gas, exploratory wells would need to be drilled across the basin to prove that oil can flow at economic levels before commercial viability of this resource can be established.
  • Coalbed methane ( CBM) is a gas formed as part of the process of coal formation, and is physically adsorbed by the coal. It can then be released when the pressure surrounding the coal is decreased.
    • CBM has been produced commercially since 1996 in Australia, providing over 10% of Australian gas production in 2013. [8] However, it is at an early development stage in the UK, and there is still a great deal of uncertainty whether the Australian experience is replicable in Scotland.
    • In Scotland, there have been some CBM wells drilled in Airth, with the first gas produced in 2007. In 2010, Dart Energy Ltd acquired Composite Energy and drilled a further three wells. In 2012, Dart submitted an expanded Field Development Plan to DECC and sought SEPA permits and local planning permission. [9]
    • Dart's planning application for 14 proposed wells went to a planning inquiry in 2014. It received around 2,500 objections from members of the public. There was a lack of clarity over the boundaries between consideration of environment impact under the planning process and the remit of SEPA through licensing controls ( e.g. on geology and hydrogeology). Before the application was resolved, the moratorium came into force; this application therefore remains unresolved, as does to the issue of the boundaries between the respective roles of the different actors.
    • There is little data surrounding the sources and quantities of greenhouse gas emissions associated with CBM extraction. At the present time, the evidence is insufficient to estimate the GHG emissions from developing CBM wells in Scotland.
    • In 2004, a BGS study suggested that UK coal beds suffered from widespread low seam permeability, and low gas content. With the continued lack of development, there is little evidence to indicate that CBM will be commercially developed in Scotland.
    • Resources estimates for CBM are uncertain and thought to be located in the same geographical areas as shale gas and associated liquids. Based on surface access, geology, development costs and estimated well recovery costs, analysis from KPMG concludes that CBM is currently unlikely to be a major product in Scotland. [10]

In this advice, we therefore consider shale oil and shale gas. Of the two, shale gas has considerably larger potential implications for emissions and is the source for which the evidence base on emissions and mitigation measures is best developed. The production scenarios provided by KPMG in a parallel study ( Chapter 2) include shale oil, enabling us also to include shale oil directly within our analysis.

The evidence on coalbed methane ( CBM) is more limited, both regarding the emissions footprint and potential size of a Scottish industry. If exploitation of CBM were proposed in any significant way for Scotland then we would come back to look at it in further detail.

Box 1.2. Getting from estimates of resource-in-place to economically recoverable reserves

The resource-in-place estimates produced by BGS do not indicate how much fossil fuel will be recovered. Several steps are required to translate these estimates of the resource into economically recoverable reserves:

  • Only a fraction of shale resources are technically recoverable with current technology. BGS do not currently provide an estimate for the fraction of resource that is technically recoverable, stating that exploration needs to take place before an estimate can be made. Based on US experience on shale gas, the US Energy Information Administration estimates this proportion to be around 20% of the gas in place. [11]
  • Of this technically recoverable resource some may be inaccessible, due to land-use constraints ( e.g. populated or protected areas). In a report for the European Commission, ICF [12] estimated that less than 50% of the UK's shale gas resource is likely to be accessible. This reduces the central estimate for technical recoverable resource further.
  • Although the factors affecting the recoverable fraction of the resource are mainly geological there are also non-geological factors that could affect the size of the reserve. These factors include: engineering design (such as the number of horizontal wells per pad and the techniques used for hydraulically fracturing); the effect of the new protocols for earthquake mitigation and monitoring; land access; and environmental permit constraints. [13]
  • The volume that is economically recoverable is likely to be smaller again than that which is technically recoverable, as it depends on market prices and production costs (see Chapter 2).

2. Implications for fossil fuel consumption of domestic UOG production

As we set out in our UK advice, in order to be compatible with emissions targets any domestic production of unconventional oil and gas should not affect domestic consumption and should instead displace imports.

This conclusion is also valid for Scotland - that unabated fossil fuel consumption must be consistent with the levels in our scenarios, unless reductions in emissions beyond those the Committee has identified can be found elsewhere. Therefore, any new sources of UK production must be used to displace imports. Allowing unabated consumption above these levels would not be consistent with the decarbonisation required under the Climate Change Act (Scotland).

The size of the domestic market for fossil fuels over the long term will be strongly affected by whether or not carbon capture and storage has a significant role in meeting the 2050 target. At the UK level, we analysed the level of natural gas and oil consumption that could be consistent with a 2050 target to reduce emissions by at least 80% on 1990 levels. This analysis showed that while there are ranges for the levels of consumption of oil and gas that could be consistent with meeting this target, the range is considerably wider for natural gas consumption and depends strongly on the availability of CCS:

  • Gas: under a 'no CCS' scenario that meets the 80% target, gas consumption in 2050 is around half the level under our Central scenario. Of the difference in gas consumption, around half is gas used directly with CCS, while the remainder is additional unabated use of gas allowed within the headroom created by using CCS in industry and with bioenergy (Figure 1.2);
  • Oil: under a 'no CCS' scenario, oil consumption in 2050 is around 14% below the level in our Central scenario.

The recent cancellation of the UK CCS Commercialisation Programme does not mean that CCS cannot play a role to 2050, but this cancellation has raised doubts about that role and may imply a substantial delay in its deployment at scale. A significant delay could lead to less feasible CCS deployment over the period to 2050, reducing its role in decarbonisation and implying a lower level of fossil fuel consumption compatible with meeting the 2050 target.

As well as providing a smaller market for fossil fuels, the greater pressure placed on UK emissions targets in the absence of CCS would also make it more difficult to accommodate the emissions associated with production, as there would be less scope to reduce emissions elsewhere in the economy to compensate ( Chapter 5).

A UK approach to delivery of carbon capture and storage ( CCS) is urgently needed.

Figure 1.2. Direct and indirect impacts of CCS availability on UK gas consumption to 2050

Figure 1.2. Direct and indirect impacts of CCS availability on UK gas consumption to 2050

Source: CCC (2016) The compatibility of UK onshore petroleum with meeting the UK's carbon budgets.

3. Comparing the climate effects of methane and carbon dioxide

The major component of natural gas is methane. Not only does this produce CO 2 when combusted, but methane is itself a greenhouse gas included in the Scottish emissions inventory. Methane is emitted to the atmosphere at various points along the lifecycle of gas use, from extraction to final use.

In this report we sum the total emissions of CO 2 and methane on a CO 2-equivalent (CO 2e) basis, assuming that a tonne of methane emitted is equal to 25 tonnes of CO 2e.

There are other possible ways to compare relative emissions, and a fixed multiplier of 25 has some limitations (Box 1.3). It overplays the relative importance of methane emissions for century-scale, irreversible temperature change, while underplaying the effect of methane on timescales up to a few decades. There are several potential alternative metrics for comparing different types of greenhouse gases, and each has its own characteristics. Whichever metric is chosen it is most important to be aware of its limitations and interpret results in light of those.

Our use of fixed multiplier of 25 reflects current standard practice under accounting for UK carbon budgets and Scottish emissions targets, as well as UN-agreed international emissions reporting.

Box 1.3. Climate effects of methane and carbon dioxide

Methane is a more potent greenhouse gas than carbon dioxide (CO 2), trapping more heat in the atmosphere molecule-for-molecule. But it is much shorter-lived: it decays on a timescale of around 12 years, whereas around a fifth of the effect from CO 2 remains even after 1,000 years. This means a unit emission of CO 2 today will affect the climate in 2100 and beyond. In contrast, the same unit emission of methane will have little effect on the climate in 2100, but a stronger effect on the climate of the next few decades (Figure B1.3).

Measuring the total effect of gas use (and comparing it to alternatives such as coal and renewables) requires a metric to put the climate effects of methane and CO 2 on a common scale. Various metrics exist (Table B1.3):

  • The 100-year Global Warming Potential ( GWP100) is the standard metric used in domestic and international climate policy. It compares the total heat trapped in the atmosphere over a 100-year period after a pulse emission of a given mass of greenhouse gas, relative to the same mass of CO 2. In essence it is the ratio of the two lines shown in the top panel of Figure B1.3 at year 100 after the time of the emission.
  • A GWP100 of 25 for methane is currently used in policy, indicating that a tonne emitted is equivalent to 25 tonnes of CO 2. This value comes from the Fourth Assessment of the Intergovernmental Panel on Climate Change ( IPCC AR4). However, GWP100 estimates are revised over time as scientific understanding improves and the composition of the atmosphere changes. The IPCC's more recent Fifth Assessment gave GWP100 for methane of 28, or 34 if the feedback of warming onto atmospheric CO 2 levels is accounted for. [14]
  • The metric value depends on the time horizon chosen. Some studies of unconventional gas [15] have chosen to use a shorter time horizon of 20 years ( GWP20), leading to a higher value for methane of 72.
  • Since the GWP100 measures time-integrated heating it does not relate directly to international policy goals, which are based on limiting global average temperature change ( e.g. to well below 2°C). If we look instead at the effect on global temperature, such as the Global Temperature Potential ( GTP), we find quite different values for methane than that suggested by the GWP (Figure B1.3 bottom panel). For example, methane is about four times stronger than CO 2 after 100 years. As with the GWP, the value varies with time horizon. After just 20 years, the effect of methane on temperature is 67 times stronger than that of CO 2.

Figure B1.3. Radiative forcing and temperature change for methane and carbon dioxide over different timescales

Figure B1.3. Radiative forcing and temperature change for methane and carbon dioxide over different timescales

Source: CCC calculations based on the IPCC Fifth Assessment Report ( AR5).

Notes: Total heat trapped in the atmosphere (top) and global average surface temperature change (bottom) from emission of carbon dioxide (CO 2) and methane ( CH4). The ratio of the curves in the top panel at 100 years gives the GWP100 value for methane, while the ratio of curves in the bottom panel gives the relative effect on temperature.

Table B1.3. Alternative metrics for assessing the climate effect of methane emissions relative to the same mass of CO 2 emissions

GWP 100
( IPCC AR4)
GWP 100
( IPCC AR5 excl. carbon cycle feedbacks)
GWP 100
( IPCC AR5 incl. carbon cycle feedbacks)
GTP 100
( IPCC AR5 excl. carbon cycle feedbacks)
GTP 100
( IPCC AR5 incl. carbon cycle feedbacks)
25 28 34 4 11

Source: IPCC 5th Assessment Report ( AR5) Working Group 1, Chapter 7.

Notes: The metric currently used for policy ( GWP 100) is highlighted in bold. GTP 100 stands for 100-year Global Temperature Potential, and measures the relative change in global temperature a century after emission. The set of metrics shown here is not exhaustive.


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