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Publication - Research Publication

Unconventional oil and gas: Economic Impact Assessment and scenario development of unconventional oil and gas in Scotland

Published: 8 Nov 2016

Research into Economic Impact Assessment and scenario development of unconventional oil and gas in Scotland.

64 page PDF

1.7MB

64 page PDF

1.7MB

Contents
Unconventional oil and gas: Economic Impact Assessment and scenario development of unconventional oil and gas in Scotland
Appendix C: Assumptions underlying the scenarios

64 page PDF

1.7MB

Appendix C: Assumptions underlying the scenarios

C.1 Resources

C.1.1 Products considered

Three sources of unconventional of oil and gas are considered as part of this study namely:

  • Gas extracted from onshore sources using hydraulic fracturing;
  • Associated liquids extracted from onshore sources using similar recovery techniques; and
  • Coal bed methane.

The evidence base suggests that the focus for developers is shale gas development with associated liquids as a secondary priority. That is the reason why we have modelled shale gas and liquids together as liquids is a premium to gas.

The evidence base on coal bed methane is limited, especially in the Scottish context. Resource estimates for CBM are approximate [44] and thought to be located in the same geographical areas as shale gas/oil and liquids. Based on surface access, geology, development costs and estimated well recovery rates, CBM is currently unlikely to be a major product in Scotland. As such, we have assumed that only two CBM pads would be developed.

C.1.2 Location of resources and use of land

We have only considered resources in the Midland Valley for development as part of this study. The Midland Valley region appears to have the concentration of resources to support an integrated supply chain. We recognise that there are resources available in other parts of Scotland however many are comparatively small and may not individually be cost competitive to develop. A developable area is limited by urbanisation, faulting, water bodies, designated areas, etc. Exploration and production would therefore be limited to accessible areas within the basin as shown in Table C.1.

Production volumes scenarios are derived from the ability to develop pads within the Midland Valley. We also cross-reference the potential outputs of the pads against available resources. UKOOG and their members thought this approach was reasonable.

C.1.3 Resource availability

Assessments of resource availability are derived from BGS (2014) as shown in the Table C.2 below.

We have assumed production volumes based on the number of pads because in the Midland Valley (a highly populated area of Scotland) there are limits to the available space that can be used for UOG resource development. A 'developable' area is limited by urbanisation, faulting, water bodies, designated areas, etc. which limits the number of potential pad developments. We estimate that 20 pads could be developed in the Central scenario, while 31 and 10 could be developed in the High and Low scenarios respectively.

Table C.1 Potential developable area in the Midland Valley.

Developable area Central High Low
Share of basin Large part of the basin Large part of the basin Core of the basin
km 2 ~ 160 km 2 ~ 160 km 2 ~ 42 km 2

Table C.2 Potential total in-place shale oil, shale gas and coal bed methane in the Midland Valley in Scotland.

Scenario Central High Low
Shale gas (tcf) 80.3 134.6 49.4
Shale oil (billion Bbl) 6.0 11.2 3.2
Coal bed methane (tcf) 22.4 NA NA

Source: British Geological Survey (2014) & Independent Expert Scientific Panel (2014).

C.2 Development and production

The table below provides a summary of assumptions on the development and production of UOG across our scenarios.

Table C.3 Summary of the assumptions across our scenarios.

Scenario Central High Low
Resources
Shale gas tcf 80.3 134.6 49.4
Associated liquids MMBOE 6,000 11,200 3,200
CBM tcf 22.4 22.4 22.4
Development
Number of shale gas pads No. 20 31 10
Of which also producing associated liquids 15 23 8
Wells per shale pad 15 30 10
Number of CBM pads 2 2 2
Wells per CBM pad 15 15 15
Production
Expected output per pad
Shale gas bcf 47.3 94.7 31.6
Associated liquids MMBOE 1.2 2.4 0.1
CBM bcf 13.1 13.1 13.1
Percentage of shale gas pads also producing associated liquids % 75% 75% 75%
Production life of a shale gas well years 15 15 15
Production life of a CBM well years 12 12 12
Start of first production year 2024 2023 2028
End of production year 2048 2049 2049

C.3 Cost profiles

C.3.1 Capital costs

The study published by EY in 2014 on shale gas and its supply chain and skills requirements provides a breakdown of the costs of hydraulic fracturing, drilling and completions, waste disposal and storage and transportation. These costs were for a hypothetical pad of 10 vertical wells with four laterals each (total of 40 laterals). In this study, we used the costs provided in the EY study and scaled them in accordance with the number of wells assumed in each scenario.

Furthermore, we added a number of other costs to cover expenditure on planning and licensing, exploration, pad development, decommissioning and aftercare costs. We also added operating expenditure to cover the production phase of the pads. These additional cost categories do not seem to form part of other publicly available studies.

Table C.4 below provides a breakdown of costs for all scenarios. It is worth noting that the costs are allocated to shale gas and associated liquids respectively based on an energy equivalent basis ratio [45] .

The volumes of associated liquids produced in the low scenario are so low that associated costs are negligible.

Figure C.1 overleaf depicts total annual costs for shale gas and associated liquids on a per pad basis.

Table C.4 Cost breakdown for a given pad in each scenario (totals may not add up due to rounding)

Costs £m Central High Low
Shale gas and associated liquids CBM Shale gas and associated liquids CBM Shale gas and associated liquids CBM
1. Planning and licensing 1.2 1.2 2.5 1.2 0.8 1.2
2. Exploration 11.3 11.3 10.0 11.3 6.7 11.3
3. Development costs 40.0 40.0 40.0 40.0 20.0 40.0
4. Main capex
Drilling and Completion
Steel casing 8.6 8.6 17.3 8.6 5.8 8.6
Rig hire 8.1 8.1 16.3 8.1 5.4 8.1
Ancillary equipment and service 4.5 4.5 8.9 4.5 3.0 4.5
Cementing services 3.1 3.1 6.2 3.1 2.1 3.1
Directional drilling service 2.8 2.8 5.6 2.8 1.9 2.8
Drilling fluids and fluids engineering 2.1 2.1 4.3 2.1 1.4 2.1
Drill rig fuel 1.7 1.7 3.5 1.7 1.2 1.7
Hydraulic fracturing
Equipment 64 32.0 128.0 32.0 42.7 32.0
Propants 7.6 5.1 15.2 5.1 5.1 5.1
Other 2.8 2.8 5.6 2.8 1.9 2.8
Mobilisation/demobilisation 1.7 1.7 3.4 1.7 1.1 1.7
Miscellaneous 0.8 0.8 1.7 0.8 0.6 0.8
Waste disposal
Wastewater management 5.4 5.4 10.9 5.4 3.6 5.4
Drilling waste management 5.0 5.0 9.9 5.0 3.3 5.0
Storage and transportation
Waste transportation 2.8 2.8 5.6 2.8 1.9 2.8
Water storage and transportation 2.0 2.0 3.9 2.0 1.3 2.0
Sub-total (main capex) 123 89 246 89 82 89
Total Capex (items 1, 2, 3 & 4) 176 141 299 141 110 141
Decommissioning 7.7 7.7 17.5 7.7 5.1 7.7
Aftercare 0.8 0.9 0.8 0.9 0.8 0.9

C.3.2 Fixed and variable operating costs

The opex is based on a fixed and a variable element. The costs associated with the monitoring of carbon emissions are also included in the operating costs - these are estimated to be £100,000 [46] per year per pad for the duration of the pad's lifespan. We assume that the variable element is linked to production while the fixed element is linked to capex. A breakdown of the variable operating cost is provided below:

Table C.5 Variable operating costs

Variable opex All scenarios
Shale gas and CBM £0.25m/bcf
Associated liquids £1.65m/ MMBOE

The fixed operating cost is 2.5% of annual cumulative capex for shale gas, CBM and associated liquids.

C.3.3 Localisation

Key to assessing the economic impact of UOG development is the amount spent within the Scottish economy, i.e. localisation. Our assumption is that in the Central scenario (and CBM) 50% of spend is within the Scottish economy, i.e. £2.2 billion. For the High scenario, we would expect 60% of UOG spend to remain in Scotland, i.e. £6.5 billion and for the Low scenario, we would expect 30%, i.e. £0.5 million.

These assumptions are broadly in line with localisation figures used in other sectors, namely the offshore wind and nuclear industries (BVG Associates, 2015) and ( HM Government, 2012).

A North American market exists for construction, labour and procurement of equipment of shale gas and associated liquids. The extent to which the Scottish UOG sector will need to import materials and expertise will depend on how quickly the domestic supply chain can develop to meet the industry's needs and the amount of localisation that is expected to occur in Scotland. Should Scotland become a centre of excellence in shale, it could become self-reliant in expertise which could also provide some potential export opportunities in Europe and elsewhere.

Figure C.1 Shale gas and associated liquids cost profiles (per pad)

Figure C.1 Shale gas and associated liquids cost profiles (per pad)

Table C.6 Localisation assumptions

Scenario Central High Low CBM
Percentage of cost in Scotland 50% 60% 30% 50%

C.3.4 Efficiency

We assume that the UOG supply chain would develop as more pads are developed. We also assume there is an element of 'learning by doing' whereby it becomes cheaper to drill subsequent wells.

In terms of efficiency improvements, we assume that there are economies of scale in pad construction. The Central scenario (and CBM pads) benefits from a cost reduction of 5% of capex for five pads after the first pad is built. The High scenario benefits from a cost of reduction of 7% for five pads after the first pad is built. We assume a smaller cost reduction percentage in the Low scenario, i.e. only 3% for three pads after the first pad is built. These assumptions are in line with the approach used by the US Department of Energy for components of energy systems (U.S. Department of Energy, n.d.) A generating technology's learning rate is a weighted average of the learning rates of its component parts. We have not assumed any learning rate for opex.

C.3.5 Community benefits

In the Central, High and Low scenarios, we assume that 4% of total revenues are given to local communities. Table C.8 provides a summary of community benefits payments across our scenarios (including if CBM were to be developed).

C.4 Decommissioning and aftercare

As described in Figure C.10 on the previous page, we assume that the decommissioning and aftercare costs are 25% of drilling and completions costs. This assumption is broadly in line with the IoD study (2013) and industry estimates.

We assume that aftercare costs are £40,000 per year per pad which represent a very small percentage of total drilling completion. See Table C.11 on the previous page.

C.5 Pricing

We have used DECC's latest oil and gas wholesale fossil fuel price assumptions. Given current market prices, our scenarios are based on DECC's low projection scenarios ( DECC, 2015).

In our model, we assume that the volumes produced in Scotland are unlikely to result in movement in international prices. This implies that there is substitution between gas sources rather than gas for other sources. This is consistent with the CCC workstream in that overall usage of hydrocarbons is unchanged.

See Section 4.4.2 for more details.

Table C.7 Efficiency improvement assumptions

Scenario Central High Low CBM
Efficiency improvement assumptions 5% 7% 3% 5%

Table C.8 Total cumulative benefit payment under 4% Community benefits payments [47]

Central High Low
Shale gas and associated liquids £m 217 663 64
CBM £m 5 5 5
Total £m 222 668 69

Table C.9 depicts what community benefits payments may be if operators give 6% of total revenues to local communities.

Table C.9 Total cumulative benefit payment under 6% Community benefits payments [48]

Central High Low
Shale gas and associated liquids £m 325 994 95
CBM £m 7 7 7
Total £m 332 1,001 102

Table C.10 Summary of decommissioning and aftercare assumptions scenario

Scenarios Central High Low
Decommissioning cost as a % of drilling and completion % 24.85% 24.93% 24.68%
Aftercare cost per site per year (shale gas only) as a % of drilling and completion % 0.15% 0.07% 0.32%
Number of years to spread over decommissioning 3 2 5
Number of years to spread over aftercare 20 20 20

C.6 Financial assumptions

Table C.11 below provides a summary of our financial assumptions across all three production scenarios.

C.7 Carbon mitigation costs

The Climate change impact study has identified that a number of carbon mitigation technologies would be required in the Central, High and Low scenarios to ensure Scottish emissions targets are not exceeded. The carbon mitigation measures included in the CCC's 'Minimum Necessary Regulation' case are presented in Table C.12.

Table C.11 Summary of financial assumptions across all scenarios

Scenario Units
Depreciation years 30
Salvage value for depreciation £m 0
Corporate tax rate % 20%
Payroll costs as a percentage of Opex % 22%
Commercial interest rate % 5%
WACC % 10%

Table C.12 Carbon mitigation costs by scenario.

Carbon mitigation technologies Estimated cost of mitigation Unit Type of cost Central High Low Notes
Leak Detection and Repair ( LDAR) £20,300 /pad/year Opex £304,500 £304,500 £304,500 £20,300/pad/year for 15 years
Reduced emissions completions ( REC) (per use, equipment can be used numerous times) £12,500 /well Development costs £187,500 £375,000 £125,000 £12,500/well x number of wells
Liquids Unloading plunger lift (assumes operates for the final 10 years) Capex £22,900 /well Development costs £343,500 £687,000 £229,000 £22,900/well x number of wells
Liquids Unloading plunger lift (assumes operates for the final 10 years) Opex £1,000 /well Opex £150,000 £300,000 £100,000 1,000/well x number of wells for 10 years
Dry Seal Compressor £416,000 /compressor Development costs £416,000 £416,000 £416,000 1 compressor/pad
Low-flow pneumatic devices 2,480 /device Development costs £4,960 £9,930 £2,480 Central: 2 devices/ pad High: 4 devices/pad Low: 1 device/pad
Vapour recovery units ( VRU) £49,800 /pad Development costs £49,800 £49,800 £49,800 1 VRU/pad
Total (£m) per pad 1.5 2.1 1.2
Grand total (£m) for the scenario (all pads) 29.2 66.5 12.3

Source: Supporting Annex to CCC (2016) Scottish Unconventional Oil and Gas - Compatibility with Scottish Greenhouse Gas emissions targets

For more information on the techniques and technologies which can be employed to mitigate carbon emissions, please refer to the Supporting Annex to CCC (2016) Scottish Unconventional Oil and Gas - Compatibility with Scottish Greenhouse Gas emissions targets.


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