beta

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

1.8MB

92 page PDF

1.8MB

Contents
Unconventional oil and gas: compatibility with Scottish greenhouse gas emissions targets
Chapter 2: Production scenarios for Scottish unconventional oil and gas

92 page PDF

1.8MB

Chapter 2: Production scenarios for Scottish unconventional oil and gas

A Scottish shale industry has not been developed to date. Consistent well flow-rates of oil and gas across each of the basins can only be proved if there is a period of exploration. If flow-rate levels consistent with commercial exploitation can be established over a number of exploration wells the industry might then move on to development well drilling and the production phase of operations.

The rate at which a Scottish unconventional oil and gas industry might develop is uncertain, and depends on the rate at which the industry can feasibly be ramped up: economic factors affecting the profitability of production; the time required for and complexity of the planning and approval process; and, related to this, the extent to which public acceptability issues are a constraint.

This chapter considers the factors that would affect the size of a Scottish unconventional oil and gas industry over time, presents scenarios for development of a Scottish industry and considers the likely impact on gas prices, in three sections:

1. Factors affecting the growth of a Scottish unconventional oil and gas industry
2. Production scenarios
3. Impact on fossil fuel prices

1. Factors affecting the growth of a Scottish unconventional oil and gas industry

The profitability of the sector depends on the underlying costs of production, costs imposed by regulation and related policies, the composition of the gas produced, the productivity of the wells drilled, prevailing wholesale prices and the taxation regime:

  • Production costs. Of the significant components of production costs, some can be inferred approximately from experience elsewhere and some are a function of the specific circumstances in Scotland:
    • Drilling the well. The cost of drilling a well is related to the depth of the well and the length of lateral. The costs to drill wells in the US are decreasing, with recent cost estimates as low as $2.6m per well. [16] However, costs are likely to be significantly higher in Scotland due to tighter health and safety regulation and, at least in the initial stages, less competition in the supply chain.
    • Fracturing stages. The fracturing stage represents between 20% and 50% of overall well costs. [17] Over time the number of fracture stages has tended to increase, which has increased the volume of shale per unit lateral length. [18] It is expected that Scottish practice would reflect this increased number of fracturing stages per lateral length, which is becoming common practice in the US. Both the drilling and fracturing stages are likely to be carried out by oilfield service companies. Due to lower competition than in the US, costs for their services are likely to be higher in Scotland. [19]
    • Other costs. The UK shale industry has a voluntary scheme, under which the local community will be paid £100,000 when an exploratory well is hydraulically fractured and a further 1% of gross revenues for shale wells put into production. One operator, Ineos, has pledged to go further than this, with 6% of revenues going to homeowners, landowners and local communities. [20] The UK Government is currently consulting on the delivery method and priorities of a Shale Wealth Fund. [21] Each production site will also have to pay business rates and potentially pay to lease the land. This is different from the US where the industry pay royalties to the land owner based on revenues.
  • Costs relating to environmental, planning and safety regulations. Costs of environmental, planning and safety regulation are likely to be higher in Scotland than the US. Examples of this are already occurring:
    • Environmental. Groundwater monitoring is required a year before hydraulic fracturing. An environmental risk assessment is also required. Many of the techniques and technologies to limit the emissions footprint of production will also increase costs, although this cost should be compared to the benefit from the reduction in emissions when deciding on implementation ( Chapter 4).
    • Safety. Health and safety regulations are likely to increase costs of a Scottish well when compared to the US. Regulations mitigating the risk of well failure are stronger than they have historically been in the US, with greater numbers of casings [22] being required. On top of this, independent well examiners are required to review the design, construction and decommissioning of wells, in order to provide independent assurance. [23] Employment law is also stricter, with regulations on working time increasing the size of crews working on the rigs. [24]
    • Planning. Sites in Scotland could require security during the well development stage and potentially beyond, adding to the costs for the site. Planning permission can be difficult to obtain due to local impacts.
  • Composition. The composition of hydrocarbons extracted varies considerably between wells. Generally the composition is categorised into dry gas, wet gas, co-producing and oil- only: dry gas is mainly (greater than 90%) methane; wet gas contains a greater proportion of gases such as ethane, propane, butane and gas condensate; co-producing wells produce a wet gas and oil; and oil-only mainly produces oil, potentially with some associated gas. The longer hydrocarbons tend to have a greater value than methane and may be used as feedstocks in petrochemical plants rather than combusted for energy.
  • Well productivity. It is uncertain how relevant US data are in providing a guide to the productivity ( i.e. the amount of hydrocarbon that will be recovered) for Scottish onshore wells. In any case this is likely to vary significantly within Scotland (Box 2.1). A large proportion of production costs are fixed, so the unit costs of production are highly dependent on the quantity of output (Figure 2.1). There is a similar effect in relation to emissions per unit of production, as some sources of emissions relate to the number of wells rather than the quantity of energy produced (see Chapter 4).
  • Fossil fuel prices. Beyond the short term, prices in wholesale fossil fuel markets are difficult to predict with any confidence. The gas price in DECC's fossil fuel price scenarios ranges from 36 to 95 p/therm for 2025, while the oil price ranges from $71-155/barrel. [25] It is therefore difficult to state with any certainty now whether onshore extraction will be economic during the 2020s, even with good knowledge of well development costs. UOG production does have the advantage that a high proportion of a well's total hydrocarbon production occurs in the first two years, which reduces this risk significantly at the level of an individual well. Nevertheless, at the industry-wide level, this is an area of considerable importance and uncertainty.
  • Taxation regime. Should onshore production be profitable, the prevailing taxation regime will determine how much of the profits are retained by the producer and how much goes to the Government.

Box 2.1. Well productivity

The productivity of a well is dependent on its geologic characteristics, length of the lateral(s) drilled and the completion design, and could vary widely across a shale formation by a factor of up to ten. [26] , [27] As Scotland has no exploration flow data, let alone production data, it is too early to speculate on the likely productivity of Scottish wells, although we can look at US data to understand better how productivity varies across formations as well as between formations.

The way a well behaves over time varies between wells. Production generally declines rapidly over time due to loss of reservoir pressure, which makes it difficult to predict the well's overall production. A metric of estimated ultimate recovery ( EUR) has therefore been developed to estimate the production across a well's life. These use models based on historical data and assuming a defined decline curve over an assumed well life (Figure B2.1). Small changes to the assumptions behind this curve can increase or decrease the estimated EUR significantly, thus giving a wide range of potential in the predicted EUR for a given well.

The EUR of wells in the US has tended to increase over time, with developments targeting 'sweet spots' and longer laterals, which have more than doubled in length over the last decade of development. This has been helped by development of hydraulic fracturing techniques; in general, as the lateral length increases, fracturing stage spacing becomes smaller, increasing the extractable volume. [28] However, there is recent evidence that productivity per unit length in the US is declining. With the most productive areas in mature shale gas formations having been developed, the pace of improvement in the effectiveness of extraction is being outstripped by the need to drill in less productive areas. [29]

When assessing the economic case for developing a well, it is important to understand the EUR per unit length of lateral as well as the number of fracture stages. In theory, a well can be drilled to have any EUR assuming a sufficiently long lateral can be drilled, although this will increase the cost to drill and hydraulically fracture the well.

Figure B2.1. Modelled well production profile

Figure B2.1. Modelled well production profile

Source: CCC analysis.

Notes: This shows an indicative production profile for a shale gas well, generated using Arps formula.

Figure 2.1. Impact of well productivity on the unit costs of gas production

Figure 2.1. Impact of well productivity on the unit costs of gas production

Source: CCC analysis.

2. Production scenarios

For our UK advice, we used a range of scenarios for shale gas production, based on scenarios available in existing literature. Shale gas production in 2030 under those scenarios varied by a factor of around 10 between the highest and lowest, reflecting the large amount of uncertainty over the potential size of a UK unconventional fossil fuel industry. This is also likely to be true for shale oil production.

For this advice on Scotland, we base our analysis on three scenarios developed in a parallel study by KPMG on economic impacts and scenario development. The range represented by these scenarios is again very wide, varying by a factor of 18 between the lowest and highest in 2030 (Figure 2.2). These scenarios include both gaseous and liquid products, from a mix of gas-only and co-producing wells. [30]

The three scenarios reflect different assumptions regarding the number, productivity and timing of shale wells developed (Figure 2.3). For all scenarios, KPMG assumed that 75% of the wells would produce oil and gas, with the remaining 25% producing gas only. They further assumed production per well to consist of 0.83 TWh (3.2 bcf) of gas and 0.1 TWh of liquids for co- producing wells, and the same gas production rate of 0.83 TWh for gas-only wells. [31] We note that this is higher than the central assumption in our UK-level analysis of 0.52 TWh (2 bcf) per well, within a range of 0.26 to 1.3 TWh (1 to 5 bcf).

KPMG have produced three scenarios, which vary in terms of the number of wells and the timing of production:

  • KPMG Low scenario: In this scenario UOG well development is initially slow, with drilling commencing in 2026. Production volumes only reach 2 TWh per year by 2030, rising to around 8 TWh by 2035.
  • KPMG Medium scenario: Wells start to be drilled in 2023. Production volumes reach around 10 TWh per year in 2030, peaking at almost 25 TWh in the mid-2030s.
  • KPMG High scenario: In the high scenario wells start to be drilled in 2022. Production volumes rise rapidly over time, reaching around 25 TWh per year by 2030 and around 65 TWh in 2035.

Figure 2.2. KPMG scenarios for Scottish unconventional oil and gas production

Figure 2.2. KPMG scenarios for Scottish unconventional oil and gas production

Source: KPMG.

Notes: Comprises both gas and liquids production under the KPMG scenarios.

Figure 2.3. Wells drilled under the production scenarios (2022-35)

Figure 2.3. Wells drilled under the production scenarios (2022-35)

Source: CCC analysis, based on production scenarios supplied by KPMG.

3. Impact on fossil fuel prices

In the US, the emergence of a shale gas industry produced a substantial decline in gas prices. It is unlikely that such an impact would follow from new Scottish production:

  • In the US, shale gas production rose to around 50% of overall gas production in 2014. With little connectivity to international markets this added to supply for US consumption, and put downward pressure on prices.
  • Scotland is part of a highly connected gas network across Europe, which is the world's largest importing market. Additional Scottish production needs to be seen in the context of the overall size of the European system. Natural gas demand across the EU amounted to 471 bcm in 2013 and under the IEA 450 Scenario [32] would decline to 425 bcm by 2030. Even Scottish shale gas production at the upper end of our scenarios for 2030 would be around 1% of this demand. Production at the low end of our range would be only around 0.1%.

For oil, prices are set on world markets. Again the volume of shale oil produced in Scotland would have a negligible effect.

Our assessment is therefore that Scottish unconventional oil and gas production will do little to reduce energy bills, with prices set by international markets. This finding is consistent with those of other studies [33] , including that of KPMG. Production that bypasses wholesale markets could, however, reduce costs for some industrial consumers.

The weak downward pressure on wholesale prices does, however, mean that profitability of production is less likely to be undermined. This is in sharp contrast to the US experience, where the fall in gas prices acted to limit the profitability of further production.


Contact