Oil and gas – guidance

Oil and gas: fields and field development

Guidance on how operators can get approval for oil field development and how to apply for flaring and venting consent.

Overview

DECC expects companies to work their licences. In recent years, the amount of acreage left untouched, and those exclusive rights unexploited, has become a matter of concern. This led PILOT (formerly the Oil & Gas Industry Task Force) to instigate the Fallow Initiative, which incorporated a process to ensure UK Continental Shelf (UKCS) licences are optimally worked to maximise economic recovery of oil and gas.

Legislative framework

The Oil Taxation Act 1975 introduced and made provision for Petroleum Revenue Tax (PRT) to be levied on all oil and gas fields. Schedule 1 to the Act states that all fields are to be “determined” by a boundary drawn around them. Following debate around the Oil Taxation Bill, it became clear the boundary was to be drawn in accordance with geological criteria alone so the field could be defined as a single geological petroleum structure. Field boundaries may only cover an area that is part of a licensed area. Occasionally fields may have a top and a base, or overlie or abut one another.

The 1993 Finance Act abolished PRT for new fields and created two categories of field:

  • old fields: those given development consent before 16 March 1993 – are subject to PRT
  • new fields: not subject to PRT, but receive determinations and re-determinations as appropriate so all fields are defined in the same way. Determinations are still required for corporation tax purposes.

Field determination process

A proposed determination of a field must be made before DECC’s relevant minister can approve an oil field development.

The process for determination involves issuing a proposal (for the boundary) to all licensees with an interest in the licence (blocks in which the field is situated) and licensees in the adjacent blocks, so all parties can ensure their interests in the oil field will be recognised. The boundary is defined as:

  • offshore – by parallels of latitude and meridians joining the co-ordinate points
  • onshore – by grid lines of the UK National Grid

Licensees have 60 days from the date on which a proposal is issued to lodge any objection to it. They will then have an opportunity to present any specific concerns in more detail. The final determination will be made following all relevant discussion, and must be in place prior to first production.

Fields may be re-determined any time at the request of any party following the acquisition of new information – either seismic or from wells – that indicates the original determination is no longer valid. An identical procedure to that described above is followed in each case.

As all fields are determined as areas of which every part is, or is part of, an area licensed under the Petroleum Act 1998, it follows that when such a licensed area is relinquished the field must be re-determined to exclude that area.

List of UKCS field partners

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Redetermination of oil field boundaries on economic grounds: explanatory note and guidance for licensees

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Cluster Area Determinations

DECC may propose the determination of an area as a “Cluster Area” in accordance with the Supplementary charge: cluster area allowance provisions in Finance Bill 2015 (see https://www.gov.uk/government/publications/draft-legislation-corporation-tax-high-pressure-high-temperature-cluster-area-allowance). After Royal Assent to Finance Bill 2015, the relevant legislation will be in Chapter 9 of the Corporation Tax Act 2010. Cluster Areas are needed for capital expenditure to qualify for the Cluster Area allowance introduced at Autumn Statement 2014.

Process

A company or a group of companies may approach DECC to propose that an area containing one or more high pressure/high temperature (HPHT) discoveries should be determined as a Cluster Area. DECC will examine their proposal and may then organise a discussion to review the proposed Cluster Area. Alternatively, after consultation with the Treasury, DECC may decide to approach the companies with interests in an area to propose a Cluster Area.

Technical meetings will then be held by DECC with all parties with interests in the potential Cluster Area. When these technical meetings are complete and DECC and the companies have reached agreement, the companies will supply an agreed Cluster Area Description, Inventory and Timed Plan to DECC. Once DECC has accepted these and has the agreement of the Treasury, DECC may then issue a proposed Cluster Area determination. Such a determination will consist of a boundary defined by parallels of latitude and meridians joining the coordinate points - and may have a top and/or base specified (for example in metres below mean sea level). The Description, Inventory and Timed Plan for a Cluster Area will be subject to annual review. Progress will be monitored and necessary adjustments made after discussion between the Cluster Area participants and DECC.

The process for determining a Cluster Area involves issuing a proposal to all licensees with an interest in the proposed Cluster Area and to any other licensee whose interests appear to DECC to be affected. Details of the proposed Cluster Area will also be published here (see links below). This page is kept on behalf of the Secretary of State for Energy and Climate Change.

Companies have 30 days to make representations on it. They will have an opportunity to present any specific concerns in detail before DECC issues the final determination of a Cluster Area.

For Cluster Areas proposed before Royal Assent to Finance Bill 2015, capital expenditure incurred in relation to the Cluster Area will generate Cluster Area Allowance from the date of publication on this website of the proposed Cluster Area. After Royal assent the trigger date for capital expenditure incurred to generate the allowance will be the date of publication of the final determination.

Cluster Areas may be re-determined at any time at the request of any party following the acquisition of new information – either seismic or from wells – that indicates the original determination is no longer valid. An identical procedure to that described above will be followed in each case. Since Cluster Areas can include unlicensed acreage, and in contrast to the case of oil fields all parts of which have to be in licensed acreage, there is no need for Cluster Areas to be redetermined when part (or all) of the area becomes unlicensed.

Timing

A Cluster Area is treated as not including any field (or part of a field) that received authorisation of development prior to the publication of the proposed Cluster Area (pre-Royal Assent to Finance Bill 2015) or the publication of the final Cluster Area determination (post-Royal Assent).

List of Proposed Cluster Areas

  1. Culzean Cluster Area

Process for oil and gas field development plans

The powers of the Secretary of State in relation to development and production consents are set out in the Model Clauses incorporated into individual licences.

The documentation required for new oil and gas field authorisations is the Field Development Plan (FDP). The discussion leading to submission of the FDP is the process by which the Energy Development Unit (EDU) secures the department’s policy objectives. The aim of the process is to identify aspects of the development plan that relate to the Department’s objectives and on which the views of the department and licensees may diverge. These aspects will be examined more thoroughly with licensees, with the aim of reaching mutually satisfactory conclusions. The resulting FDP should provide a summary description of the actual development and the principles and objectives that will govern its management.

Operators considering a development should contact the department early in the appraisal stage of a field. A multi-disciplinary team from the EDU will be assigned to carry forward the technical discussion on the field, headed by a manager authorised to take technical decisions on behalf of the Department and to co-ordinate, where necessary, the department’s response on policy issues.

Assessment

Licensees should provide the department with sufficient opportunity and information to gain an understanding of the field and its conceptual development. The department’s team manager will provide notification of any aspects of the development where a conflict of interest is seen to exist and which may prevent authorisation of the programme. The department will then seek to agree a programme of work leading to their resolution and a timetable for its completion.

The Offshore Petroleum Production and Pipe-lines (Assessment of Environmental Effects) Regulations 1999 require an Environmental Impact Assessment for most new offshore oil and gas developments.

DECC considers the economics of field and incremental developments as part of the assessment of field development programmes. Operators should complete the Common Reporting Format (CRF) spreadsheet below to assist DECC in this process.

Common Reporting Format (CRF) spreadsheet

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Further information about the CRF and preparing the costs section of the FDP can be found in section 3.6 of the following guidance notes on procedures for regulating oil and gas field developments.

Guidance notes on procedures for regulating offshore oil and gas field developments

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Please email the completed CRF to mike.earp@decc.gsi.gov.uk

Brown Field Allowances

Following the announcement on 7 September 2012 that the government would introduce a Brown Field Allowance (BFA), HMT has circulated a note giving further information on the BFA qualification criteria and the process for BFA cost verification.

Brown Field Allowances: guidance

Companies undertaking incremental projects that might be eligible for a BFA are advised to ensure they are familiar with this process if they wish those projects to qualify for the allowance.

Approval

The development will be authorised (i.e. the necessary consent/approval granted pursuant to the applicable model clauses and/or EIA regulations) once the Secretary of State is satisfied of the following:

  • FDP meets the government’s policy objectives (set out in the guidance notes)
  • Environmental Impact Assessment process has been completed successfully
  • each licensee has approved funding sufficient for their share of the development costs
  • the department has approved a Production Operator for the development

Additional details for offshore fields can be found in sections 4 and 5 of the following guidance notes on procedures for regulating oil and gas developments.

Guidance notes on procedures for regulating offshore oil and gas field developments

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Development and production consents are issued via the UK Oil Portal. Additional information on the department’s requirements for Production Operatorship can be found in appendix 8 of the Guidance Notes.

Safety is the responsibility of the Health and Safety Executive, which is a separate government body. Safety cases must be submitted for all new installations; implementation is through the Offshore Installations (Safety Case) Regulations 1992.

Regulation following field development plan authorisation

The focus of the Department, once a development has been agreed, will be to ensure that the Field Development Plan is being followed or modified appropriately as the understanding of the field develops, and that the field is being managed in a manner that will maximise economic recovery of hydrocarbons.

The operator will be required to prepare, on behalf of all the Licensees, annual returns summarising key aspects of the field’s performance (additional details for offshore fields can be found in Section 6 of the guidance notes on procedures for regulating oil and gas developments. Appendices 11 and 12 give additional details of the Stewardship and Production Efficiency review processes)

Guidance notes on procedures for regulating offshore oil and gas field developments

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Cessation of production

Prior to permanently ceasing production from a field, Licensees will have to satisfy the department that all economic development opportunities have been pursued. To ensure that all issues are addressed thoroughly before agreement to CoP is required, Licensees should initiate discussions with the department in a timely manner which, in the case of a large platform-based development, may be up to three years before agreement to CoP is required. On the successful conclusion of these discussions, Licensees will submit a Cessation of Production document which will form the basis of the department’s agreement to CoP from the field. Additional details can be found in section 6.5 and appendix 7 of the guidance notes.

If production is to be suspended from a field for any length of time, the operator should contact the department to discuss what notifcations / approvals may be required

Guidance and documents for development plans

Guidance notes on procedures for regulating offshore oil and gas field developments

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Guidance notes for onshore oil and gas field development

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Guidance notes for Coalbed methane and Mines gas field development plans

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Guidance notes for gas storage in onshore oil and gas fields

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Petroleum measurement Guidelines

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Offshore gas storage project development plans

The Energy Act 2008 provides for a licensing regime governing the offshore storage and unloading of gas (natural gas consisting mainly of methane). The regime applies to storage and unloading within the offshore area comprising both the UK territorial sea and the area beyond the territorial sea that is designated a Gas Importation and Storage Zone (GISZ) under section 1(5) of that Act.

The Secretary of State for DECC is the licensing authority for offshore storage or unloading activities. In addition to gaining this authority, developers will also need to obtain a grant of the appropriate rights from the Crown Estate.

Documents for offshore gas storage development plans

Application form for an offshore gas storage Licence

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Gas storage application guidance

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Considerations for a gas storage development plan

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The offshore gas storage and unloading (licensing) regulations 2009

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Documents for offshore gas unloading

Gas unloading licence application form

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Gas unloading application guidance

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Considerations for a gas unloading development plan

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Operatorship

Gas unloading and storage operatorship guidance

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Contact information

Ricki Kiff
tel: 0300 068 6042
email: ricki.kiff@decc.gsi.gov.uk

Trans-boundary oil and gas fields with Norway

The guidance notes below are designed to help companies through the process of seeking government approval for the development of trans-boundary reservoirs that extend across the median line between the UK and Norway. They have been developed jointly with the Norwegian Petroleum Directorate and include links to both UK and Norwegian legislation and guidance. They should not be read in isolation from that legislation.

Guidelines for development of trans-boundary oil and gas fields

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Please direct any comments or queries to mark.simpson@decc.gsi.gov.uk or andrew.carr@decc.gsi.gov.uk

These DECC guidance notes have been issued to aid operators applying for i) flare and ii) vent consents. It should be read in conjunction with the appropriate flare or vent application.

Energy Act 1976 and Petroleum Act 1998

These two pieces of legislation have slightly different definitions of the gases emitted.

For vent consents under the Energy Act 1976, both the inert gas and hydrocarbon fraction obtained from the licensed area should be given, and the combined rate for both will be the consent basis.

For flaring under the Petroleum Act 1998, only the hydrocarbon fraction flared from the licensed area requires consent but DECC will require the inert gas content of the flare to be provided for information.

The objective of the i) flare and ii) vent consent applications is to prepare a realistic forecast based on these guidelines and the categorisation as indicated below. The performance for the current year from January to September and past performance should provide a starting point for this forecast.

DECC is committed to eliminating all unnecessary or wasteful flaring and venting of gas. Operators should seek to minimise this by implementing best practice at an early stage in the design of the development and by continuing to improve on this during the subsequent operational phase. The operator should consider carefully all operational activities in accordance with good oil field practices, taking into consideration plant uptime, efficient processing, handling, uses and transportation of gas.

The application must be submitted in mass units.

Installation and field diversity

In practice every individual production operation has some unique aspects. The categories below attempt to cover the widest range of scenarios from oil fields with gas lift and gas exports, to dry gas fields. For gas condensate fields, if gas export is not possible then the liquids production is normally shut down – thus little gas is flared.

There are some fields with multiple installations that have been issued with a single flare consent. In many cases, several fields are processed across a single installation and in some of these cases DECC has issued a ‘group consent ‘ covering the installation rather than the individual fields. This does not imply allocation back to a field is inapplicable, but was intended to represent a pragmatic and simpler operational approach. Such a consent is considered when all the fields and the installation have the same equity partners. Where the fields have different equity partners, DECC will issue separate consents unless prior agreement in writing is granted by all the partners in all the fields and the installation. Supporting documentation should be included in the application.

Flare and vent source categories

These have been rationalised into 4 categories:

Category 1 - base load flare

This includes all the gas used for safe and efficient operation of the process facility and flare system under normal operating conditions. This shall also include any gas that has to be discarded as part of the installation processes and is discharged to flare. Typical examples are all process purges and pilots, the off-gas from the glycol regeneration plants and acid gas discharged from MDEA and other gas treatment plants, where these are fed to the flare system for combustion.

This category also includes flaring from installations with no gas export facilities.

Category 2 – flaring from operational or mode changes

This includes gas flaring resulting from the start up and planned shut down of equipment during production, and will also include gas not meeting export specification, maintenance of equipment and equipment outages. This category also includes flaring that is caused by the temporary lack of access to a third-party gas export pipeline or similar.

Category 3 – emergency shut down/process trip

This includes any gas flared during an emergency shut down / process trip of equipment or the installation, including shut-in of the wells.

Category 4 – Unignited vents

This covers inert gases and hydrocarbons gases that may be discharged to an atmospheric vent. The Gas Act requires both the inert and hydrocarbon gases obtained from the licensed area that are vented to be covered by the consent.

This should also include venting of gases from onboard crude oil storage tanks eg for FPSOs during crude oil filling operations. However, this excludes inert gases that are generated onboard the installation for the purpose of providing an inert blanket for onboard oil storage tanks etc.

Vents may contain nitrogen, carbon dioxide, water vapour, hydrocarbons and possibly traces of sulphur compounds, etc. Operators should give an estimated annual average composition of vented stream(s) in the notes section of the vent application.

Approach to flare application

During the flare exercise, unless the flare is associated with a field whose production efficiency is below expectations for the field or there are other indications that an improvement could be made the department will not examine in detail applications for requested flare levels that do not exceed 40 tonnes a day, provided there is no request for an increase to the levels in the extant flare consent.

Applications can be made for flare consents an annual basis.

  • consents will continue to be issued on a field basis *(Where several fields tie-in into common facilities and the fields have the same operator and licensees, the operator may apply for a single, composite consent and the level of flaring permitted in this consent will be based on the sum of the individual field contributions to the total flare level which must not exceed a level of 40 tonnes a day. Where a single composite consent is not requested, regardless of the total level of flaring at the facilities individual field consents will be issued on an annual basis.)
  • usually separate consents will continue to be issued for individual fields that tie-in to common facilities if the fields have different operators and licensees – regardless of the total level of flaring at the facilities – and the consents will be issued on an annual basis should the tie back of a new field to a facility increase the total volume flared from the fields going through the facility to greater than 40 tonnes a day, then either a new joint flare consent application must be made for all of the fields now going through the facility or, if no agreement is reached on this, individual annual flare consent applications must be made for each of the fields now going through the facility – and individual annual field consents – that supersede the existing composite long-term consent
  • subject to the above conditions, one field flare consent will continue to cover a field where flaring takes place on a number of installations
  • if the licence term for a field expires before the end of 2015, (or expected cessation of production date is before then), the flare consent will be issued to the licence expiry date, (or expected cessation of production date, whichever is earliest), with the flare level being pro-rata where this date is during the year
  • in the case of a consent that includes a number of fields, the duration of the consent will not exceed the earliest expiry date of any of the licences
  • no carrying forward of flare from 1 year to the next will be permitted
  • the production facilities must have the capability to conserve all gas processed on them – in excess of that used for fuel – through such measures as export or gas re-injection
  • there must be a production consent in place that covers the duration of the application for each of the fields involved in the flare consent application - if this is not the case, then any flare consent duration will be capped by the earliest production consent expiry date
  • fields are not in the DECC stewardship process
  • if, due to unforeseen circumstances, it appears the annual flaring level permitted in any year covered by a long-term flare consent is likely to be breached, the Department (following submittal of a revision application) will consider issuing a consent revised to amend the flare level for the year in question. It is the operator’s responsibility to present a technical case to DECC in a timely manner in the event a revision is required
  • where a field is flaring more than 40 tonnes a day, the flare level will be reviewed and a flare consent issued for maximum of a year. These applications will need supporting details with medium- and long-term plans for flare reduction
  • new fields are subject to normal short-term commissioning flare consents until stable production is achieved, when a decision will be made as to what consent duration will be issued (depending upon flare level sought)
  • all fields will continue to report quantities via the PPRS
  • for flare consent applications below 40 tonnes a day, it is sufficient to complete only the minimum of information. However, operators must still exercise appropriate technical and operational diligence in estimating quantities
  • for flare consent applications above 40 tonnes a day, DECC considers it essential for the operator to include full details as requested in the application *(Operators must exercise a high level of technical and operational diligence in estimating quantities as these applications will be subjected to detailed review by DECC. This level of flare is considered to represent a potential opportunity for further reduction on flare levels. Operators must submit outline details of medium- and long-term plans for flare reduction.)

Approach to vent application

Consideration will be given to annual vent consent applications.

For applications below 4 tonnes a day, it is sufficient to complete only the minimum of information. However, operators must still exercise appropriate technical and operational diligence in estimating quantities.

For vent consent applications above 4 tonnes a day, DECC considers it essential for the operator to include full details as requested in the application. This should include an outline of the main sources of vent in the “Supporting Notes” section. Operators must exercise a high level of technical and operational diligence in estimating quantities, as these applications will be subject to detailed review by DECC. This level of vent is considered to represent a potential opportunity for further reduction in levels. Operators must submit outline details of medium- and long-term reduction plans.

Accuracy of flare measurement and reporting

There are a number of methods to quantify gas volume flared and likewise, a number of methods to convert this to a mass basis. Flare quantification is in accordance with the requirements for flaring associated with the EU-ETS Phase III. Operators should ensure the methodology they have in place meets or exceeds the necessary levels of accuracy.

Completion of application

All units are water dry metric tonnes.

Applications will need to be submitted via the UK Oil Portal.