Infrastructure Bill [HL]

Written evidence submitted by United Kingdom Onshore Oil and Gas (IB 16)

Infrastructure Bill: Submission on the underground land access provisions

About United Kingdom Onshore Oil and Gas

1. United Kingdom Onshore Oil and Gas (UKOOG) is the representative body for the onshore oil and gas industry. Our aim is to facilitate the development of the UK-based onshore industry and supply chain for the long term, producing large quantities of natural gas and oil safely, with care for the environment and respect for local people.

2. Our objectives are to enhance the profile of the onshore industry; promote better and more open dialogue with key stakeholders; deliver industry wide initiatives and programmes; and ensure standards in health and safety, the environment and operations are maintained to the highest possible level. Membership is open to all companies active in the onshore industry including those involved in the supply chain, and our operational guidelines are mandatory for our members.

Why the land access provisions in the Infrastructure Bill are necessary

3. Natural gas and oil are vital sources of energy for the UK. Natural gas provides more than one third of the UK’s overall energy needs, [1] heating 83% of homes [2] and generating 28% of electricity. [3] Oil and natural gas liquids provide a further third of the UK’s energy needs, with around half being used for road transport. [4]

4. Thanks to offshore production, the UK has been largely self-sufficient in natural gas and oil for several decades, but output has fallen by around two thirds over the last decade and the pace of that decline is accelerating. This means that oil and gas imports are rising rapidly. Last year, the UK imported 43% of its oil and 52% of its gas. By 2030, the Department of Energy and Climate Change (DECC) expects the UK to rely on imports for three quarters of its natural gas and two thirds of its oil needs, even as the production of renewable energy increases. [5] In addition to the security of supply issues posed by such a heavy reliance on gas and oil imports, it also adds billions of pounds per annum to our balance of payments deficit.

5. Around 2,000 wells have already been drilled onshore in the UK, [6] and extraction of shale gas and oil using established horizontal drilling and hydraulic fracturing technologies could make possible a large increase in onshore production, reducing the UK’s growing dependence on imports and creating well-paid jobs, not least in areas of the country that have had historically high unemployment rates. Studies by the Institute of Directors in 2013 [7] and EY in 2014 [8] both indicated the potential for the shale industry to create tens of thousands of jobs. In addition, oil and natural gas are essential feedstocks for petrochemicals and other manufacturing industries, which themselves support several hundred thousand jobs in the UK.

6. The British Geological Survey has estimated that over 1,300 trillion cubic feet (tcf) of natural gas lies in shale rock in the North of England alone. [9] This should be compared with annual consumption of less than 3 tcf a year. While considerable exploration work needs to be carried out to assess the commercial potential of the resource, if 10% could be extracted, it would be sufficient to meet the UK’s overall gas needs for more than 40 years. According to the central scenario set out by the Institute of Directors, shale gas production has the potential eventually to reduce the UK’s projected import dependency by half, reducing the import bill by £8 billion a year. [10]

7. The current underground access regime for onshore hydrocarbons suffers from significant shortcomings. If permission to drill deep underground is not granted by all landowners under whose land the drilling is proposed to be carried out, and all reasonable attempts at negotiation fail, the current regime allows for a court order granting underground access (through the Mines (Working Facilities and Support) Act 1966, as applied by section 7 of the Petroleum Act 1998). This, however, is a lengthy and complex process, potentially meaning many years of court proceedings to secure the access required for a single horizontal well. Neither the landowners nor the company would benefit financially from the current system in the event of dispute. Following the principles laid down in the Bocardo SA v Star Energy case, the compensation likely to be awarded to a landowner for deep underground access rights would be nominal (around £82.50) on the basis that land at such depths has no real value to the landowner and any use made of it will not affect the owner. In addition, around 20% of land is not registered on the Land Registry, so identifying these landowners in the first place can prove complicated.

8. This is why other essential services and critical infrastructure have certain defined rights of underground and above-ground access. The water industry and Environment Agency, for example, have compulsory powers to lay new water and sewage pipes [11] . Crossrail access rights were acquired by compulsory purchase as set out in the Crossrail Act 2008. Licensed coal operators have a right of access to underground land for coal mining operations, with no compensation to landowners provided. And the 1982 Civil Aviation Act ruled that landowners do not have rights to restrict access to airspace above 305 metres.

9. It is worth noting that horizontal drilling for natural gas and oil from shale typically takes place at least a mile below the surface, with a typical horizontal well of just 6 to 9 inches in diameter. At this depth, hydraulic fracturing opens up cracks in the rock that are around 1mm in width – small enough to be held apart by grains of sand, injected with the fracturing fluid, so that the natural gas or oil can flow into the well. A strict traffic light monitoring regime will control hydraulic fracturing activities to limit any induced seismic events to 0.5ML – a level that can only be detected by seismic instruments. This activity deep underground will not be noticeable at the surface and will not impact on the enjoyment landowners have of their property at the surface. At this depth, the land is not in use, or capable of being put to use, by the landowner.

10. To accompany the changes set out in the Bill, the onshore oil and gas industry has committed to provide a public notification system that will set out the relevant area of underground land and the payment that will be made in return for underground access. For each unique horizontal well that extends by more than 200 metres laterally, the operator will make a one-off payment of £20,000. The payment will be made to a relevant local community body. Where horizontal wells are aligned vertically (in other words where one horizontal well is directly above another), payment will be made only once.

11. It is worth emphasising that these proposed changes do not alter surface access, planning or environmental permitting arrangements. Natural gas and oil companies will still need to obtain permission from the landowner for the use of their land for the construction of the drilling pad and vertical section of the well, and will negotiate directly over terms. Drilling and any hydraulic fracturing activities will still need regulatory approval from DECC, the Health and Safety Executive and the Environment Agency, and planning permission from the local Minerals Planning Authority. In particular the composition and individual components of any fracturing fluid will require prior assessment by and approval of the Environment Agency. The EA has stated that it will only approve fracturing fluid that it has assessed as non-hazardous to groundwater and fracturing fluid composition will be publically disclosed by the EA.

12. Individuals, landowners and communities can engage at six separate stages of the approvals process: pre-application consultation, environmental risk assessment (ERA), pre-planning notices, planning authority consultation, environmental impact assessment (EIA), and environmental permitting.

Appendix 1 – Additional information relating to financial capacity and environmental liability

13. It is important to highlight several other issues that are relevant to the Bill. Firstly, there are a number of measures in place to ensure that operators have adequate financial capacity.

14. The first set of these measures is at the licence approval stage. DECC’s guidance on operatorship states that the following assurances will be considered in applications for onshore operatorship: "In considering any request for operatorship, DECC will look at the competence of the company – more specifically the following factors: technical experience and capability to supervise, manage and undertake the proposed operation, their risk-assessment and hierarchy of decision-making, plans for public engagement and scope of relevant insurance coverage for operations and well abandonment activity. In some cases, DECC may request independent verification." [12]

15. The second set of assurances is at the well consent stage. DECC’s "UK Petroleum Licensing: Financial Guidance" document states: "DECC’s policy requirement is to ensure that no well consents are issued unless we are satisfied that the licensee(s) has (have) access to sufficient funds to meet its(their) share of the actual drilling costs, the plugging and abandonment of the well if it is proven to be ‘dry’ or otherwise non-viable and a minimum contingency of 50% of the drilling costs." [13]

16. Secondly, there are a number of measures with respect to environmental liabilities that are worth highlighting.

17. The Environmental Regulator (EA in England, SEPA in Scotland and NRW in Wales) has the power to enforce the conditions in the environmental permits for a well or wells until the point in time that it accepts a surrender of those permits – the operator is not simply at liberty to hand back the permit. For England and Wales, the permit surrender process is agreed with the Environmental Regulator, and for wells that are hydraulically fractured this is likely to include the need for a period of aftercare and monitoring of any potential residual environmental impacts. The regulator may require the operator to supply a financial bond or other form of security for performance of its permit obligations.

18. With respect to the Minerals Planning Authority, planning consent for the site may also include planning conditions (which are legally binding) designed to ensure that the site is restored to its original surface condition at the end of operations.

19. DECC's consent is required under the terms of the operator's petroleum licence before a well can be decommissioned. The decommissioning process must be done in accordance with a specification agreed with the HSE, with reference to the Oil & Gas UK best practice on well abandonment and with the oversight of the HSE and an appointed Well Examiner.

20. If a well is not decommissioned in line with the approved plan, the licence holder or well-operator at the time of decommissioning can be prosecuted by the HSE for non-compliance with HSE regulations, and this could be pursued even after the petroleum licence and environmental permits have ceased to exist.

21. Taken together, if a company causes damage, harm or pollution to the environment, they can be required under these regimes to remediate the effects and prevent further damage or pollution. This is the same approach that applies to other industries. Environmental regulators and planning authorities have the power to require upfront financial bonds to address these risks. The industry does not wish to leave this to the taxpayer or the landowner. As a less expensive alternative to upfront bonds, UKOOG is working with Government on the development of an industry scheme that will step in and pay for liabilities.

22. Finally, the Bill makes clear that landowners are not liable for any loss or damage which is attributed to the exercise of the right of underground access. This provision can be found in Clause 39, paragraphs 5-7, of the Bill as brought from the Lords.

Appendix 2 – Industry guidelines and regulation

23. The Committee should be aware of the following industry guidelines, best practice and current regulation with respect to the onshore oil and gas industry in the UK.

Planning guidance

24. Planning guidance states that in National Parks, the Broads and Areas of Outstanding Natural Beauty, planning permission for unconventional hydrocarbon developments should be refused "except in exceptional circumstances and where it can be demonstrated they are in the public interest". The guidance also states that "where a proposed development for unconventional hydrocarbons would lead to substantial harm to or loss of a World Heritage Site, mineral planning authorities should refuse consent unless wholly exceptional circumstances apply". [14]

25. It’s important to emphasise that planning guidance makes clear that use of land is not unrestricted outside of these areas: "Local planning authorities should set criteria based policies against which proposals for any development on or affecting protected wildlife or geodiversity sites or landscape areas will be judged. Distinctions should be made between the hierarchy of international, national and locally designated sites, so that protection is commensurate with their status and gives appropriate weight to their importance and the contribution that they make to wider ecological networks." [15]

Well integrity [16]

26. The Health and Safety Executive has responsibility for well regulation, and requires operators to appoint an independent well examiner to produce regular reports to the HSE on well integrity. The main UK regulations covering well design, construction and decommissioning are: Offshore Installations and Wells (Design and Construction Etc) Regulations 1996 (DCR); Borehole Sites & Operations Regulations 1995 (BSOR); Dangerous Substances and Explosive Atmospheres Regulations 2002 (DSEAR); Provision and Use of Work Equipment Regulations 1998 (PUWER).

27. Amongst other areas, these rules exist to: "Ensure that a well is so designed, modified, commissioned, constructed, equipped, operated, maintained, suspended and abandoned that – a) so far as is reasonably practicable, there can be no unplanned escape of fluids from the well; and b) risks to health and safety of persons from it or anything in it, or in strata to which it is connected, are as low as reasonable practicable."

28. To support this, operators have to assess the geological strata, fluids within them and any hazards within the rock – and in their assessments take into account all designs and operations. In addition, the regulations ensure independent well examinations take place. The paragraphs below provide further detail on the first two sets of regulations listed above.

29. Firstly, the Offshore Installations and Wells (Design and Construction Etc) Regulations 1996 (DCR) also apply to onshore wells. The main regulations concerning well design and construction (including fracturing operations) are summarised as follows:

30. DCR Regulation 13 (General duties of Well Operators in connection with wells). The Well Operator shall ensure that a well is so designed, modified, commissioned, constructed, equipped, operated, maintained, suspended and abandoned that – a) so far as is reasonably practicable, there can be no unplanned escape of fluids from the well; and b) risks to health and safety of persons from it or anything in it, or in strata to which it is connected, are as low as reasonable practicable.

31. DCR Regulation 14 (Assessment of Conditions Below Ground). 1) Before the design of a well is commenced the Well Operator shall cause – a) the geological strata and formations, and fluids within them, through which it may pass; and b) any hazards which such strata and formations may contain, to be assessed. 2) The Well Operator shall ensure that account is taken of the assessment required by paragraph (1) when the well is being designed and constructed. 3) The Well Operator shall ensure that while an operation (including the drilling of a well) is carried out in relation to the well, those matters described in sub-paragraphs (a) and (b) of paragraph (1) shall, so far as is reasonably practicable, be kept under review and that, if any change is observed in those matters, such modification is made where appropriate, to – a) The design and construction of the well; or b) Any procedures, as are necessary to ensure that the purposes described in regulation 13(1) will continue to be fulfilled.

32. DCR Regulation 16 (Materials). The Well Operator must ensure that every part of a well is composed of material which is suitable for achieving the purposes described in Regulation 13(1). (General Duties).

33. Regulation 20 (Co-operation). This regulation requires any person involved with a well operation to co-operate with the Well Operator in discharging his duties under Regulation 13(1). All companies involved in the well design and operations processes (e.g. contractors) need to be aware of this duty to cooperate so that the Well Operator can fulfil his general duties under Regulation 13(1) to prevent unplanned escapes of fluid

34. Secondly, the Borehole Sites & Operations Regulations 1995 (BSOR) apply to onshore well sites and to wells. The main regulations concerning well design and construction (including fracturing operations) are summarised as follows:

35. Regulation 9 and Schedule 2(7). The Borehole Site Operator and other employers must ensure that suitable well control equipment is provided for use during both drilling and fracturing/flow-back operations. Detailed guidance on well control equipment is provided in the BSOR, Schedule 2(7) guidance. Section 7.2 of these guidelines deals with surface well control equipment during fracturing and flow-back operations.

36. Regulation 9 and Schedule 2(3). When borehole operations are carried on, there shall be provided a sufficient number of competent persons with a view to enabling those operations to be carried on safely. Section 5.1 of these guidelines deals with management supervision and competence at the well design and construction phase. Section 7.3 of these guidelines deals with planning, management supervision and competence during fracturing/flow-back.

Cumulative impacts

37. Planning guidance for onshore oil and gas states: "Each application (or request for a screening opinion) should be considered on its own merits. There are occasions where other existing or approved development may be relevant in determining whether significant effects are likely as a consequence of a proposed development. The minerals planning authority should always have regard to the possible cumulative effects arising from any existing or approved phases of hydrocarbon extraction. There could also be circumstances where two or more applications should be considered together. For example, where the applications in question are not directly in competition with one another, so that both or all of them might be approved, and where the overall combined environmental impact of the proposals might be greater or have different effects than the sum of their separate parts." [17]

38. The guidance also states that "it is unlikely that cumulative impact will be an issue at the exploration phase of development, regardless of how close individual well pads are to each other." It is also worth noting that cumulative impacts should form part of the environmental impact assessment.

Environmental monitoring, impact assessment and working with water companies

39. The UK adopts a risk based and goal setting approach to the regulation of onshore hydrocarbon activities that requires operators to ensure, and demonstrate to regulators, that the risks of an incident occurring are reduced to ‘as low as reasonably practicable’ (ALARP). This encourages operators to move beyond minimum standards in a continuous effort for improvement. Environmental monitoring should form a key element in an operators’ environmental management system that seeks to identify and understand relevant environmental risks and reduce these to as low as reasonably practicable. The Source-Pathway- Receptor pollutant linkage concept is a key element in the UK’s assessment and management of environmental risks as developed in the Green Leaves III. [18] The identification of the significant pollutant linkages at a site forms the key element of the Baseline Desk Study.

40. UKOOG is currently finalising environmental monitoring guidelines, which are being peer-reviewed. These will include monitoring of receptors such as water (including methane in groundwater), air (including fugitive methane emissions) and ecology and will be mandatory for UKOOG members.

41. The document will provide best practice guidance for establishing environmental baselines for onshore oil and gas activities. It has been developed within the context of the current legislative framework and associated environmental monitoring requirements. This framework is risk- based and relies on objective, site specific monitoring, sampling, testing and scientific analysis, before, during and after the lifetime of the operations. The guidance will addresse the environmental monitoring requirements before operations commence to establish environmental baseline conditions.

42. These guidelines will align fully with the Environment Agency’s consultation on 'Draft Technical Guidance for Onshore Oil and Gas Exploratory Operations’ (August 2013) – – which identifies the need for a Site Condition Report to be established before site operations commence. Such a report will form the environmental baseline from which permit compliance will be measured. These guidelines will enable operators to comply with this draft requirement.

43. The potential complexities of the hydrogeology at a particular site mean that it is likely that the only way to obtain representative groundwater data is to install a suitable number of discrete groundwater monitoring wells into the appropriate strata. The site specific CSM should be used to inform the decisions on the appropriate geological formations to be targeted and the number and location of the monitoring wells to be installed, as part of the baseline programme. [19] [20]

44. This includes the installation of monitoring boreholes. The drilling of boreholes and installation of monitoring wells should be carried out by suitably qualified drilling contractors, in line with best practice. [21] [22] The boreholes should be logged by a qualified geo-environmental specialist and an accurate description recorded of: all soil and rock units recorded; water strikes and groundwater levels and; the monitoring well construction, including the response zone. The geological units, groundwater levels and the location of the response zones within the monitoring borehole completions should be presented on a geological cross-section drawn at a suitable scale.

45. Monitoring wells should be installed in sufficient time prior to groundwater monitoring commencing to allow newly constructed monitoring wells to be cleaned and purged to ensure that representative samples of groundwater can be obtained. Baseline groundwater data collection should be carried out before site activities commence. Groundwater quality can be affected by seasonal variations and other temporal factors. Tidal movements (close to the coast) and precipitation can have significant influence on groundwater levels, quality and flow. The baseline data collection programme should be informed by the CSM to ensure that temporal variations in groundwater conditions at the site are adequately characterised.

46. Methane levels in groundwater are highly unlikely to be affected by seasonal variations. Work on methane monitoring in groundwater by the British Geological Survey (BGS) has indicated that seasonal variation in natural methane concentrations in most aquifers is not apparent. Their ongoing study to look at temporal variation (quarterly sampling) will continue to be developed. Their work has shown that higher naturally occurring concentrations tend to exist in older, confined groundwaters.

47. The Mineral Planning Authority (MPA) will determine, through screening, if an Environmental Impact Assessment (EIA) will be required to accompany a planning application. Operators will need to engage with MPAs and other consultees when preparing EIAs to ensure that assessments are robust and compliant with relevant regulations. UKOOG has made a commitment that an EIA will be made for all sites where hydraulic fracturing takes place, regardless of whether they are greater than or less than 1 hectare in size (the threshold for EIAs for a "schedule 2" development, which applies here). [23]

48. UKOOG has signed a memorandum of understanding with Water UK, the representative body for the water industry. This agreement covers baseline monitoring requirements; plans relating to site water management; the expected volumes and chemical and biological composition of waste water; and preferred disposal routes. [24]

Disclosure of chemicals

49. In the UK, operators have to seek permission from the Environment Regulator (EA in England, SEPA in Scotland) before they can introduce any fluids or chemicals into the ground under rules designed to protect groundwater resources. This is part of a suite of up to eight environmental permits operators have to apply for, connected to 17 separate EU directives. The Environment Regulator is the statutory body that controls what chemicals can be used. The EA policy is detailed below.

50. "Under EPR Schedule 22, paragraph 6 we must take all necessary measures to: (a) prevent the input of any hazardous substance to groundwater; and (b) limit the input of non-hazardous pollutants to groundwater so as to ensure that such inputs do not cause pollution of groundwater. The Environment Agency would not authorise the use of a hazardous substance for an activity, including hydraulic fracturing.

51. "The pollutants the Environment Agency are concerned with for groundwater are: ‘hazardous substances’, which are substances or groups of substances that are toxic, persistent and liable to bioaccumulate, and other substances or groups of substances that give rise to an equivalent level of concern (EPR Schedule 22, paragraph 4); any non-hazardous pollutants, which is ‘any pollutant other than a hazardous substance (EPR, Schedule 22, paragraph 5)."

52. Substances on List I of the Groundwater Directive (80/68/EEC) are taken to be hazardous substances. These are not permitted under any circumstances. Substances on List 2 are taken to be non-hazardous, and are permitted for use as long as steps are made to avoid it.

53. UK operators, in applying for the separate permits they need to manage waste from what are considered 'mining operations', also have to declare the composition of any drilling muds and fracturing fluids they plan to use, along with the expected composition and quantity of any wastes. They also have to set out their arrangements for managing the same, and it is all a matter of public record – in fact, the public are even invited to consult on the permit applications. None of this is the case in the US.

54. The UK shale gas industry has committed to the full public disclosure of fracture fluid. UKOOG’s Shale Gas Well Guidelines, which are mandatory for UKOOG members, state: "Operators will disclose on the UKOOG website,, the chemical additives of fracturing fluids on a well-by-well basis. Information for fluid disclosure should include: any EA/SEPA authorisations for fluids and their status as hazardous/non-hazardous substances; Material Safety Data Sheets information; volumes of fracturing fluid, including proppant, base carrier fluid and chemical additives; the trade name of each additive and its general purpose in the fracturing process; maximum concentrations in percent by mass of each chemical additive."

December 2014

[1] Department of Energy and Climate Change, DUKES 2013, Table 1.1 (Primary energy demand) – data for 2012

[2] Department of Energy and Climate Change, United Kingdom housing energy fact file 2013, Tables 6a, 6b and 6d – data for 2011

[3] Department of Energy and Climate Change, DUKES 2013, Table 5.1 – data for 2012

[4] Department of Energy and Climate Change, DUKES 2013, Tables 1.1 and 3.2 – data for 2012

[5] Department of Energy and Climate Change, Production and demand projections

[6] The Royal Society and Royal Academy of Engineering, Shale gas extraction in the UK: a review of hydraulic fracturing, June 2012, p.17

[7] Institute of Directors, Getting shale gas working, May 2013

[8] EY, Getting ready for UK shale gas: Supply chain and skills requirements and opportunities, April 2014$FILE/EY-Getting-ready-for-UK-shale-gas-April-2014.pdf

[9] British Geological Survey, The Carboniferous Bowland Shale gas study: geology and resource estimation, 2013

[10] Institute of Directors, Getting shale gas working, May 2013

[11] Covered by the Water Industry Act 1991 and the Water Resources Act 1991

[12] See

[13] See

[14] Planning Practice Guidance, Paragraph 223

[15] Planning Practice Guidance, Paragraph 113

[16] For more detail, see UKOOG, Shale Gas Well Guidelines

[17] Department for Communities and Local Government, Planning practice guidance for onshore oil and gas, July 2013

[18] Green Leaves III, Guidelines for Environmental Risk Assessment and Management, prepared by Defra and the Collaborative Centre of excellence in Understanding and Managing Natural and Environmental Risks, Cranfield University, November 2011,

[19] Environment Agency (2013) Groundwater Protection: Principals and Practice (GP3), August 2013, Version 1.1

[20] Environment Agency (2011) H1 Annex J – Groundwater, v2.1 December 2011

[21] Environment Agency (2006) Guidance on the design and installation of groundwater quality monitoring points, Science Report SC020093

[22] British Standards Institution (2010) Water Quality – Sampling. Part 22: Guidance on the design and installation of groundwater monitoring points, BS ISO 5667-22:2010

[23] See: Also see: UKOOG, Shale Gas Well Guidelines

[24] See

Prepared 6th January 2015