Draft Sectoral Marine Plans for Offshore Renewable Energy in Scottish Waters: Socio - Economic Assesment

The study reported here provides a high level socio-economic appraisal of the potential costs and benefits to activities that may arise as a result of offshore wind, wave or tidal development within the Draft Plan Options as part of possible future Scotti

B8. Oil and Gas

B8.1 Overview

This sector relates to the extraction of Oil and Gas in the sub-sea environment largely from offshore reserves. Oil reserves include both oil and the liquids and liquefied products obtained from gas fields, gas-condensate fields and from the associated gas in oil fields. Gas reserves are the quantity of gas expected to be available for sale from dry gas fields, gas-condensate fields and oil fields with associated gas. For this assessment, activity within this sector includes exploration, production, interconnectors and gas storage ( i.e. the 'upstream' Oil and Gas sector). The location of oil and gas infrastructure in relation to Draft Plan Option areas is shown in Figure B8. Information sources used in the assessment are listed in Table B8.1.

Table B8.1 Information Sources


Information Available




All pipelines and cables


SeaZone Solutions Ltd and UKDEAL


Oil pipelines - Subsea pipelines and umbilical's related to the petroleum industry.




Oil and gas employment


Oil and Gas UK 2010 Economic report: http://www.oilandgasuk.co.uk


Revenues and production from Scottish Sea areas (2005-2008). Oil, gas and NGL production and revenue (2005-2008) for all Scottish waters and regional breakdown.


Baxter et al (2011)

B8.2 Future Trends

Information on future trends relates to the UK and disaggregation of this data to regional (Scottish) level is not possible.

It has been estimated that in 2020, 70% of primary energy in the UK is still expected to come from oil and gas. The UKCS has the potential to satisfy about 50% of the UK's oil and gas demand in 2020, if the current rate of investment is sustained (Oil and Gas UK, 2012a). However, the amount of oil and gas imported into the UK is also likely to increase. By 2015, around 25% of the UK's annual gas demand is likely to be met by imports (increasing from 20% in 2008). Given the prediction for increasing dependence on imported gas, subsea gas storage facilities and associated pipelines are also likely to increase (Saunders et al, 2011), although no new gas storage is currently planned for Scottish waters.

Over 41 billion boe have been recovered so far from the UKCS, and a further overall recovery of 15 to 24 billion boe is forecast (Oil and Gas UK, 2012a). These are mainly in discoveries awaiting development, areas under current licence or regions where oil can be expected to be found but has not yet been explored (Baxter et al, 2011). Based on the average price of oil and gas forecast by the Energy Information Administration between 2009 and 2030, the wholesale gross value of these remaining reserves may be between £650 billion to £1.1 trillion (Baxter et al, 2011). A significant area of unexploited gas reserves lies to the West of Shetland and a new gas export pipeline from this area is currently being built to support output from the Laggan (about 125km West of Shetland) and Tormore (about 15km further South West) fields, scheduled to start production in 2014 (Baxter et al, 2011).

Image B8.1 shows oil and gas production levels in recent years and DECC's current (October 2012) projections ( DECC 2013). A substantial decrease in oil and gas production in the UK since 1998 and the projected 5% decrease from 2018 to 2030 ( DECC 2013) is seen. The production projections for 2013 -2018 are consistent with those published by DECC at http://www.gov.uk/oil-and-gas-uk-field-data.

Around 500 individual structures (including platforms and tie backs) will be decommissioned over the next three decades (Saunders et al, 2011, Oil and Gas UK, 2012a). However, some depleted oil and gas fields, and oil and gas infrastructure, may potentially be used in the emerging CCS sector (see Section B3). From 2012 onwards, decommissioning expenditure is projected to be £28.7 billion by 2040 for existing facilities (Oil and Gas UK, 2012a) and over the next five years, decommissioning and cleaning expenditure totals almost £190 m and the cost of disconnection phase activities is over £330m (Oil and Gas UK, 2012b).

Image B8.1 Actual and Projected UK Oil and Gas Production 1998-2030

Image B8.1 Actual and Projected UK Oil and Gas Production 1998-2030

Source DECC, 2013.

'The production projections for 2013-2018 are consistent with those published by DECC at https://www.gov.uk/oil-and-gas-uk-field-data.

B8.3 Potential for Interaction

Table B8.2 shows potential interaction pathways between oil and gas infrastructure and wind, wave and/or tidal arrays.

Explanation of column content:

Column 1: Describes the potential interaction between the activity and any renewable technology;

Column 2: Identifies the types of offshore renewable development (wind, wave or tidal) for which the interaction may arise;

Column 3: Identifies the potential socio-economic consequence associated with the interaction identified in Column 1;

Column 4: Indicates whether detailed assessment will or will not be required if activity is scoped in;

Column 5: Identifies how the socio-economic impact will be assessed.

Table B8.2 Potential for Interaction






Potential Interaction

Technology Relevance (Wind, Wave, Tidal)

Potential Socio-economic Consequence

Scoped in (√) or Out (X) of Assessment

How the Economic Impact Will be Assessed

Increased competition for space

All arrays, export cables

Increased costs associated with new pipeline laying operations

√ (arrays) - only where Draft Plan Option areas or export cable routes overlap or lie inshore of hydrocarbon fields

- Consultation with industry to determine any potential developments for which pipeline routes might require extension;

- Assessment of cost based on average cost per km for pipeline laying, based on ODIS/ data.

See Section B8.4 for detailed methodology

Cable/pipeline crossings

All arrays, export cables

Additional costs to construct cable/ pipeline crossings

X - costs of crossings will be borne by developer.

Not required.

Increased difficulty of access at crossing points

All arrays, export cables

Increased maintenance costs for pipeline owners; loss of revenue for asset owners; loss of revenue for dependent businesses/customers

X - the crossing agreements will generally make offshore energy developers liable for additional costs incurred by the existing asset owner. This essentially involves a transfer of the cost to the developer and therefore does not require assessment here. Consultation will be undertaken with oil & gas interests to identify any significant concerns.

Not required.

Qualitative assessment of potential issues undertaken (see Section B8.4)

B8.4 Scoping Methodology

B8.4.1 Increased Competition for Space

Wind, wave and tidal array development in Draft Plan Option areas, and export cable routes from Draft Plan Option areas have the potential to affect future oil and gas infrastructure development, resulting in increased costs associated with additional pipeline laying distance to deviate around Draft Plan Option areas or export cable corridor.

For the purpose of this assessment, this potential negative effect was only considered to be likely where Draft Plan Option areas or export cable corridors overlap or lie inshore of existing hydrocarbon. Using this assumption:

  • Draft Plan Option areas and/or cable corridors which do not overlap or lie inshore of existing hydrocarbon fields were scoped out of the assessment; and
  • Draft Plan Option areas and/or cable corridors which do overlap or lie inshore of existing hydrocarbon fields were considered to require a quantitative impact assessment.

Note where overlaps between existing oil and gas infrastructure and Draft Plan Option areas/cable corridors exist, these areas were not scoped into the assessment as it was assumed that:

i) Renewables development will not be permitted within a given 'corridor' either side of existing infrastructure such as pipelines (see Appendix C8.2 for further discussion) to enable existing infrastructure maintenance; and

ii) The cost of any required cable/pipeline crossings with existing infrastructure will be borne by the renewables developer (see Appendix C8.2 for further discussion).

The assessment has assumed constant prices in real terms based on 2012.

The results of the scoping exercise are presented in Appendix C8.

B8.5 Assessment Methodology

B8.5.1 Increased Competition for Space

In order to identify SORER regions and specific Draft Plan Option areas and/or cable corridors in which this negative interaction was likely to occur, based on any potential developments for which pipeline routes might require extension between before 2035, industry consultation was undertaken.

Where industry consultation identified an interaction between a Draft Plan Option area and future oil and gas pipeline development, the additional miles required for the future pipeline routes/extensions to deviate around the Draft Plan Option area of concern was estimated. Using the average cost of per km for pipeline laying ( ODIS, 2011), the cost impact to the sector was calculated as follows:

Length of deviation (km) x average cost pipeline laying per km (£/km)

It was assumed that the length of deviation around wave or tidal Draft Plan Option areas may be smaller compared to deviations around wind Draft Plan Option areas due to the lower proportion of Draft Plan Option areas that would be covered by those devices.

Given the current uncertainty surrounding the routes of the Draft Plan Option area export cable corridors, any assessment of the economic impacts of interactions between future interconnectors and cable corridors is difficult. As such, only a qualitative assessment of this issue was undertaken based on the output of the scoping phase and areas of concern highlighted by consultation with industry.

B8.5.2 Increased Difficulty of Access at Crossing Points

Maintenance barges for pipeline work are generally anchored and require a nominal working space either side of the pipeline. Such pipeline constraint issues at the proposed Triton Knoll offshore wind farm ( OWF) development resulted in the OWF site being split into two discrete regions either side of a 1 km buffer zone for three existing sub-sea pipelines (Infrastructure Planning Commission ( IPC), 2010). Comments from the Health and Safety Executive on Triton Knoll highlighted the need to ensure that the proposed development did not adversely interact with major accident hazard pipelines ( MAHPs) ( IPC, 2010). Exclusion zones for pipelines tend to be agreed at a site-specific level and may be less or more than the distance cited in the Triton Knoll case ( ABPmer and RPA, 2011).

Oil and Gas UK were consulted to ascertain whether this potentially negative interaction was likely to occur in relation to any of the proposed Draft Plan Option areas/export cable corridors and future oil and gas activities. The outcome of this scoping exercise and stakeholder consultation is provided in Appendix C8.


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