Section 1 Introduction
Section 2 Policy objectives
2.1 Key objectives
2.2 Ensuring the recovery of all economic hydrocarbon resources
2.3 Ensuring adequate and competitive pipeline provision2.3.1 Pipeline provision
2.3.2 Third party access to offshore infrastructure2.4 Taking proper account of environmental issues and the interests of other users of the sea
2.4.1 Pollution
2.4.2 Gas flaring
2.4.3 Environmental impact assessments
2.4.4 Fishing2.5 Facilitating communications
2.5.1 Unitisation and co-operative development
Section 3 Considerations of good oilfield practice
Section 4 The field development programme process
4.1 Guidance on the content of the field development programme
4.2 Trans -boundary fields
4.3 Satellite tie -back development
4.4 Flexible approach to development proposals4.4.1 Extended Well Tests (EWTs)
4.4.2 Phased developments
4.4.3 Staged development for commercial or economic benefit
4.4.4 Flexibility in the selection of facilities option4.5 Intermediate decisions
4.6 Time frame
Section 5 Agreement to the Field Development Programme
5.1 Production
5.1.1 Simple oil or condensate fields and all dry gas fields
5.1.2 Other fields
5.1.3 Gas flaring and venting
5.1.4 Extension of licence terms5.2 The environmental impact assessment process
Section 6 Regulation following Field Development Programme authorisation
6.1 Divergence from the agreed Field Development Programme
6.2 Reporting
6.3 Auditing process
6.4 Fields authorised under earlier procedures
6.5 Cessation of production
6.6 Storage of field information following cessation of production
6.7 Decommissioning
Section 7 Changes of field operators and contracting-out of field management responsibilities
7.1 Changes of field operator
7.2 Leased facilities and contracting - out of field operations
Section 8 Organisation of oil and gas responsibilities in the Department of Trade and Industry
8.1 Oil and Gas directorate
8.2 Other government interests
Section 9 References
Appendices
Appendix 1 Flow - chart of the field development approval process
Appendix 2 Extracts from the model clauses
Appendix 3 Maximising economic recovery
Appendix 4 Preperation of a Field Development Programme
Appendix 5 Determination of fields
Appendix 6 Guidance on the preperation of a field report
Appendix 7 Guidelines for a cessation of production document
Appendix 8 Guidelines for application to become an oil production operator on the United Kingdom Continental Shelf (UKCS)
Appendix 9 Guidelines for gas flaring and venting during platform commissioning
Appendix 10 Health and safety executive role at the installation design stage
The development of and production from oil and gas fields on the land territory of Great Britain, in the United Kingdom's territorial waters and on the United Kingdom Continental Shelf (UKCS) is subject to a licensing regime overseen by the Oil and Gas Directorate of the Department of Trade and Industry (DTI). These Guidance Notes seek to make clear to Licensees preparing to develop an offshore field the purpose and practical application of the relevant model clauses incorporated into their petroleum production licences (see Appendix 2). They also cover the preparation of Field Reports for offshore oil and gas fields in production and applications for changes of Operatorship and for Cessation of Production. The Guidance Notes also explain the arrangements for dealing with fields which cross licence boundaries and the Department's approach where field operations are undertaken by a contractor on behalf of Licensees. They are intended as a working guide and not as a definitive explanation of the requirements of the model clauses or of the Secretary of State for Trade and Industry's powers under them.
The powers of the Secretary of State in relation to the development of and production from oil and gas fields were first set out in full in model clauses scheduled to the Petroleum and Submarine Pipe-lines Act 1975. Similar clauses are incorporated into every production licence and relevant extracts can be found in Appendix 2. The Petroleum (Current Model Clauses) Order 1999 (S.I. 1999/160) includes the full text of all current model clauses. It is available at http://www.hmso.gov.uk/si/si1999/19990160.htm. The licences prevent licence holders from installing facilities or producing hydrocarbons without the authorisation of the Secretary of State. When considering whether to authorise a proposal, the Secretary of State will take into account whether the proposed project accords with the Government's policy objectives (see Section 2) and whether the methods proposed to be used comply with good oilfield practice (see Section 3).
The processes described in these Guidance Notes are summarised in flow-chart form in Appendix 1. The Guidance Notes take into account relevant recommendations in A Template for Change, the September 1999 report of the Oil and Gas Industry Task Force [Reference 1].
Further information on the regulation of oil and gas developments, including the current version of these Guidance Notes, can be found on the Oil and Gas Directorate's Website at http://www.og.dti.gov.uk/. The DTI's Website can be found at http://www.dti.gov.uk/.
2.1 Key objectives
In reviewing Field Development Programmes, the Department's overall aim is to maximise the economic benefit to the UK of its oil and gas resources, taking into account the environmental impact of hydrocarbon development and the need to ensure secure, diverse and sustainable supplies of energy to UK businesses and consumers at competitive prices.
The Secretary of State will consider this aim in assessing proposals and, more specifically, will consider the following policy objectives:
a. ensuring the recovery of all economic hydrocarbon reserves;
b. ensuring adequate and competitive provision of pipelines and facilities; and
c. taking proper account of environmental impacts and the interests of other users of the sea.
The Department also seeks wherever possible to facilitate communication between Licensees. These policy objectives represent the current Departmental objectives applicable to the majority of field developments. No single objective routinely takes precedence and, where a conflict arises, the relative merits of each will be viewed in the light of the particular facts of the proposal. Circumstances may arise where the Department needs to be able to take into account wider issues or policies in other areas of Government.
2.2 Ensuring the recovery of all economic hydrocarbon reserves
The Department will work with Licensees to ensure that the development option agreed is that which is most likely to secure the full recovery of economic reserves. Economic reserves are those reserves which have a (pre-tax) market value greater than the (pre -tax) resource cost of their extraction, where costs include both capital and operating costs but exclude sunk costs and costs (like interest charges) which do not reflect current use of resources. In bringing costs and revenues to a common point for comparative purposes, the Department currently uses a 10% real discount rate.
In most cases there will be alignment between the outcome of the pursuit of commercial objectives and the objective that all reserves whose value exceeds their costs of production are made available to the market. The Department will need to be satisfied, however, that proposals address all the recoverable reserves of a field and do so over a long enough time period. It will also endeavour to ensure that, in selecting their preferred option, Licensees take into account implications for other developments in the area. A more detailed discussion of the Department's approach to maximising economic recovery is provided in Appendix 3.
2.3 Ensuring adequate and competitive provision of pipelines and facilities
The provision of infrastructure (processing facilities and pipelines) is crucial to maximising economic recovery, particularly for gas. Many UKCS fields do not contain sufficient reserves to justify their own infrastructure, but are economic as satellite developments utilising existing facilities. There is, therefore, a national interest in ensuring there is sufficient infrastructure constructed; for example, it may maximise national income to oversize pipelines beyond the immediate needs of the fields concerned to create the capacity for future tie -in developments. The Department is often in the best position to assess this, because it has a right of access to all the companies' information, whereas companies have only their own data and may, therefore, not be able to assess future potential correctly.
2.3.1 Pipeline provision
In reviewing Field Development Programmes which have implications for future pipeline applications, the Department will seek to:
a) Avoid the unnecessary proliferation of oil and gas pipelines. An additional pipeline may interfere with the rights or established practices of other users of the sea on the pipeline's route and may also have an impact on the environment. On the other hand, new pipelines, particularly those interconnecting with existing systems, may enhance competition, the security of supply and the pace of development.
b) Aid, where feasible, future field developments, including those outside the licence area. The Department's role will normally be to advise and encourage interested parties to co -operate in constructing and sizing lines according to future potential and making provision for tie -ins and risers for their mutual benefit. Licensees are also encouraged to consider the needs of the onshore petrochemicals industry when evaluating development options.
c) Ensure that those building and operating pipelines and other infrastructure compete on a level playing field and that the marketing of gas and oil reinforces the Government's efforts to promote open and competitive markets.
Subject to these aims, the evacuation route and destination of petroleum are essentially matters for the commercial judgement of the Licensees . Where oil or gas is to be exported to another country by means of a new pipeline, the pipeline will be subject to the negotiation of appropriate agreements between the Governments concerned.
2.3.2 Third party access to offshore infrastructure
The investment required to build the infrastructure needed to transport gas (and oil) from offshore oil and gas fields is characterised by significant costs and irreversibility. This can lead to conflict between the efficient use of resources and the wish for greater competition. The efficient use of resources requires no unnecessary duplication of infrastructure while greater competition requires alternative pipeline systems to be available to producers. Effective regulatory action can also prevent the exploitation of local monopoly positions where competing pipelines do not exist.
The evolution of offshore infrastructure on the UKCS has been characterised by companies developing pipelines for sole usage, followed by ullage (i.e. spare capacity) progressively being made more available for use by third parties on payment of a tariff (i.e. a payment for transportation and processing services). Field -dedicated lines are economically viable when fields are relatively large but become less viable as fields get smaller. As a consequence, there is scope for gains by all parties if the development of small fields is made viable by the owners allowing access to their existing infrastructure, with the infrastructure owners gaining additional revenue from the new users. Some of these gains would be lost if monopolistic behaviour were to deter the timely development of new small fields.
The more mature areas of the Southern North Sea, with large amounts of part - empty infrastructure, offer good opportunities for pipe on pipe competition. In other regions, notably the Central North Sea, there is less spare capacity and the additional complication of relatively small gas volumes associated with oil production. There is, therefore, more potential for commercial tension between the owners of infrastructure and the owners of third party fields seeking access to that infrastructure. The scope for tension between non - proliferation of infrastructure offshore and competition creates a need for regulation. If requested by a would - be user, the Secretary of State has powers (currently under the Petroleum Act 1998 [Reference 2], having considered the interests of all parties, to impose a solution to problems of pipeline sizing, connections or tariffs. These powers have, however, not so far been exercised.
A voluntary industry Offshore Infrastructure Code of Practice , available on the Oil and Gas Directorate's Website at http://www.og.dti.gov.uk , was introduced in January 1996 [Reference 3]. This seeks to streamline and facilitate the timely application of the processes of seeking, offering and negotiating third party access to offshore pipelines and processing facilities and onshore terminals and ensuring that access is easy and fair, with terms offered on a negotiated, non -discriminatory basis. The Code is currently being reviewed.
2.4 Taking proper account of environmental issues and the interests of other users of the sea
2.4.1 Pollution
High priority is given to the prevention of oil pollution from pipelines and facilities. In addition to the Petroleum Act 1998, other legislation, for example the Prevention of Oil Pollution Act 1971 [Reference 7], puts additional controls on the discharge of oil or contaminated water.
The Merchant Shipping (Oil Pollution Preparedness, Response and Co -operation Convention) Regulations 1998 [Reference 8] came into force on 15 May 1998 and cover contingency planning for offshore installations and pipelines.
The UK is currently introducing `Integrated Pollution Prevention & Control' (IPPC), as required by EU Directive 96/61/EC (September 1996). Consultation with interested parties has now taken place, and DTI is now in the final stages of drafting IPPC Regulations and Guidance for offshore emissions from gas turbines, diesels, and fired heaters - flaring and incineration are not covered.
The proposed Regulations will cover any offshore facility which has a thermal input of over 50 MW. New developments will require an IPPC permit with immediate effect, and also those existing facilities which undergo substantial change. Existing facilities which do not undergo substantial change will require permitting from 1 November 2007.
Applicants will need to demonstrate that they have employed Best Available Techniques (BAT) in designing and operating combustion installations.
Draft Regulations and Guidance are available on the OG Website (http://www.og.dti.gov.uk) under 'Environment' -final versions will also be placed on the Website when the parliamentary process is complete.
2.4.2 Gas flaring
It is recognised that during the appraisal, commissioning and production phases of a development, the flaring and venting of some gas is unavoidable. The Department requires that this flaring should be kept to the minimum that is technically and economically justified. Flaring and venting is also undesirable on environmental grounds.
The Department controls gas flaring in the UKCS through the requirement for Licensees to apply for consent to flare gas emitted by their oil and gas fields. The main purpose of this requirement is to ensure that gas is conserved where possible by avoiding unnecessary wastage during the production of hydrocarbons.
At the Earth Summit in Rio de Janeiro in 1992, the UK and other developed countries agreed a voluntary target of taking measures aimed at returning their emissions of carbon dioxide and other greenhouse gases to 1990 levels by the year 2000 under the Framework Convention on Climate Change. At Kyoto, in December 1997, a new Protocol was drawn up. This seeks to reduce developed country emissions of a basket of the six principal man-made greenhouse gases overall to 5.2% below 1990 levels over the period 2008 to 2012. In contrast to 1992, this target is a legally binding commitment. The UK's agreed target reduction is 12.5%. The UK has gone beyond its Kyoto commitment with a further domestic target to reduce carbon dioxide emissions by 20% from 1990 levels by the year 2010.
The Government is keen to ensure that industry makes every endeavour to help to reduce emissions. The overall aim is therefore to reduce gas flaring on an annual basis. The Department has proved successful in reducing flare emissions significantly over the last decade and for the meantime intends to maintain its current policy for controlling the flaring of gas offshore. However, it is recognised that there is much going on in the emissions arena and, because of this, the Department's approach will be reviewed on a regular basis
to ensure it is integrated fully with Government policy on greenhouse gas reductions. New ways of administering the flare consents process will also be examined in order to ensure that this process is kept efficient. A pilot study is under consideration to look into the possibility of flare trading as a more effective way of reducing emissions. The results of this study should be available towards the end of 2001.
2.4.3 Environmental impact assessments
The Offshore Petroleum Production and Pipe - lines (Assessment of Environmental Effects) Regulations 1999 [Reference 9] came into force on 14 March 1999. These Regulations implement the European Council Directive on the Assessment of the Effects of Certain Public and Private Projects on the Environment (85/337/EEC) as amended by Council Directive 97/11/EC insofar as it relates to the effects on the environment of certain offshore oil and gas projects. An environmental study, known as an Environmental Impact Assessment, must be carried out for most developments. A document describing the study, an Environmental Statement is submitted to the Department as a necessary part of the project approval process. The public has the right to comment on the Environmental Statement and the Secretary of State must be satisfied that the requirements of the Regulations as to publicity and consultation have been substantially complied with.
Further details of the Environmental Impact Assessment Regulations and the separate Guidance Notes on the Offshore Petroleum Production and Pipe -lines (Assessment of Environmental Effects) Regulations 1999 [Reference 4] can be obtained from the Oil and Gas Directorate's Website at http://www.og.dti.gov.uk/.
2.4.4 Fishing
When an offshore development is planned the Department will need to be assured that adequate consultation has taken place with the appropriate Fishery Department (see Section 8.2) and with those fishery organisations which operate in the area of the development.
2.5 Facilitating communications
The Department actively encourages co- operation between licence groups in field development where this furthers its policy goals of maximising the economic recovery of hydrocarbons, promoting efficient infrastructure and protecting the environment. The potential benefit of co -operation is a matter considered in the Department's assessment of development proposals. Accordingly, it will seek to ensure that when Licensees are planning a development they are aware of technical experience gained elsewhere and have reviewed with other Licensees in the area the potential for collaboration with existing or future projects. In pursuing this objective the Department will be sensitive to issues of commercial confidentiality.
2.5.1 Unitisation and co -operative development
Where a Field Development Programme is proposed for a field which extends into the area covered by a neighbouring license operated by different company, commercial and technical disputes may arise with regard to the optimum development plan. The Department needs to be satisfied in such cases that the ultimate recovery of petroleum is maximised and that unnecessary competitive drilling is avoided. The most efficient way to satisfy these requirements and therefore avoid any possible delay in the approval process is for the Licensees to discuss their plans with their neighbours at an early stage and propose an agreed Field Development Programme. The proposal, which could be either a unitised development or other commercial arrangement, should allow an optimum Field Development Programme and demonstrate that there would be no risk of unnecessary competitive drilling. Where such agreement is not reached or the proposed Field Development Programme does not demonstrably satisfy these requirements, the Department will wish to understand the circumstances and give all parties adequate opportunity to make representations.
The Secretary of State has powers to require a unitisation between Licensees. The grounds for the use of this power are that unitisation is needed in the national interest both in order to secure the maximum ultimate recovery of petroleum and in order to avoid unnecessary competitive drilling.
Licensees should be aware that:
a. The Secretary of State will not necessarily refuse to grant development consent to a particular group of Licensees who have not concluded an agreement with the Licensees of an adjacent block on the basis that they have not concluded a unitisation agreement. The Department does not consider that powers to require unitisation extend to issues of fairness and equity between groups of Licensees. The Department's position is that proprietary rights do not exist in unextracted hydrocarbons under the UKCS and ownership of hydrocarbons arises only once they have been extracted under appropriate regulatory consent.
b. The Department's acceptance or rejection of any Field Development Programme will, therefore, be on the basis of whether or not it is an optimum development in terms of maximising the economic recovery of oil and gas. If, in any intended development, there is a likelihood of claims or disagreement between adjacent licence groups related to the field's extent, the Department should be consulted at an early stage.
In order for the Licensees to understand what constitutes a Field for both Unit Development and tax purposes, the Department will issue a proposed Field Determination (see Appendix 5) at an early stage in the Field Development Programme approval process, utilising the geological information that is available to it at that time.
Good oilfield practice relates largely to technical matters within the disciplines of geology and reservoir, petroleum and facilities engineering and to the impact of the development on the environment.
The Department will ensure that practices harmful to future oil or gas recovery, or which conflict with the interests of other potential users of the licensed area, are avoided at all stages of planning and development. Harmful practices which relate to the environment, including the wasteful flaring of gas and oil pollution, have been noted above. Regulation of those aspects of good practice relating to the safety of personnel has been the responsibility of the Health and Safety Executive since 1991.
The Department will ensure that the Licensees have followed good practice in formulating plans for the development and management of a field. When considering what constitutes good practice, the Licensees proposals will be compared with the practice adopted in similar, successful developments.
During the appraisal phase good practice will normally require that information needed to determine the most appropriate development has been gathered and analysed properly. This will allow all realistic options for the field and area, including the application of new or innovative technology, to be considered properly. During the production stage the Department will seek to ensure that sufficient data are gathered to test the understanding of the reservoir and resolve uncertainties which have a material effect on the success of hydrocarbon recovery. This requires the continuing application of the most appropriate analytical methods, suitable research and the timely incorporation of improved understanding or innovative technology into the management of the field.
The Field Development Programme is the support document for development and production authorisations. Discussions with the Department prior to its submission are the process by which the
Government secures its policy objectives. The aim of the process is not the detailed review of every element of the development, but, rather, the identification and resolution of any aspects of the development which 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 the Licensees with the aim of reaching mutually satisfactory conclusions. Other aspects of the development will be subject to detailed examination only on a limited audit basis where this is considered necessary. The purpose of such an audit is to confirm the quality of the underlying technical basis of the development, not to uncover new issues. The resulting Field Development Programme is not required to provide a detailed description of the field or a comprehensive account of any issues resolved prior to its submission. It should provide only a summary of the information and requirements which led to the adoption of the proposed form of development, together with a more detailed account of the actual development and the principles and objectives which will govern its management.
Licensees are jointly and severally responsible for the Field Development Programme, which must represent a single view of all the Licensees. An Operator is usually appointed to be responsible for the production of the Field Development Programme and ensure that all necessary consents and authorisations are obtained. It is usual for the Department to conduct discussions with the Operator as the representative of all the Licensees.
Operators should contact the Department early in the appraisal stage of a field and a multi - disciplinary team from the Oil and Gas Directorate will be assigned to carry forward technical discussions on the field. Each team will be 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.
The Operator should ensure that the Department is aware of the generation of development concepts and screening studies so that aspects requiring detailed consideration by the Department can be identified. Once the Licensees have provided the Department with sufficient opportunity and information to gain an understanding of the field and its conceptual development, the Department's team manager will be able to provide a formal notification of any aspects of the development where a conflict of interest is seen which is likely to prevent the authorisation of the programme. Once issues are identified the Department will seek to agree a programme of work, or review, leading to their resolution and a timetable for completion.
4.1 Guidance on the content of the Field Development Programme
If the process set out above is followed, only a summary of the background and justification of the adopted development will need to be presented. The proposed form and management of the development will need to be described in greater detail to provide a basis for measuring performance following authorisation of the Field Development Programme. Appendix 4 sets out the approach in more detail and identifies the basic information which will need to be provided.
The norm for Field Development Programme documentation for all fields is a maximum of about 15 pages of text plus associated figures. More comprehensive or varied text, which some operators might for example choose to submit for partner reasons or internal preferences, will be accepted provided it covers the Departments information requirements. The key feature of the Field Development Programme should be an explanation of the commitments that the Licensees are making (in terms of facilities, number of wells, gas export etc.) to bring forward a sound development, rather than a detailed technical description of the reservoir or required infrastructure.
4.2 Trans -boundary fields
The development and operation of fields extending beyond the limits of the UKCS, or fields wholly on the UKCS which require new trans- boundary pipeline or control facilities to be developed, will require a formal agreement between the States concerned. The agreement may make part, or all, of the Field Development Programme subject to the approval of the parties to the agreement.
The issues to be addressed in any such inter -Governmental negotiations are likely to vary from project to project. However, a principal policy objective will be to seek to put in place a framework that ensures that the benefits arising from any such development are apportioned in a fair and equitable way
Licensees are advised to seek early, specific guidance from the Department during the screening stage for any development proposal that may have trans- boundary implications. The approval time-scale for trans -boundary fields will depend on the level of agreement needed between the States concerned.
4.3 Satellite tie-back development
There are an increasing number of small satellite developments which are tied back to existing host facilities. In these cases it is important that the Operator of the satellite development and the Operator of the host facility work together to ensure an agreed programme of works for necessary modification to the host facility. This programme should be endorsed by the Operator of the host facility and submitted to the Department at the same time as the final Field Development Programme for the satellite field.
4.4 Flexible approach to development proposals
For the majority of offshore fields it is expected that the Licensees will wish to put forward a programme covering the lifetime of the development, having first acquired a reasonably detailed understanding of the extent of the field by appraisal. It is, however, recognised that there may be valid reasons for more gradual or flexible approaches to some developments stemming from geological or engineering uncertainty, infrastructure constraints or the benefits of phasing expenditure. The Department will support such approaches provided that they are required to enable a development to progress or are likely to increase ultimate economic recovery.
The alternatives commonly used, and the criteria for their consideration, are set out below.
4.4.1 Extended Well Tests (EWTs)
The Department may authorise extended periods of test production from exploration or appraisal wells prior to development authorisation if it can be demonstrated that the Licensees will thereby gain the technical understanding or confidence in the performance of the field needed to progress towards a development. The EWT should have realistic and definable appraisal objectives essential to the success of a development and not be prejudicial to ultimate recovery. There are no strict criteria governing the maximum volume to be produced or the duration of an EWT and the duration may be extended if there is a technical justification, but it should be noted that EWTs are not an alternative to production under an approved Field Development Programme. There is no obligation to proceed with a development following an EWT.
The primary objective of an EWT is to obtain essential field information and it is recognised that this may necessitate the flaring of substantial quantities of gas and, possibly, oil. The test should be designed so that oil and gas flaring is kept to the minimum that is technically and economically justified and full consideration, in consultation with the Department, should be given to the potential for saving the produced oil. The Department considers any well test with a total flow duration of more than 96 hours or which produces a total of more than 2,000 tonnes of oil to be an EWT, which will require application for a specific EWT Consent. A formal Environmental Impact Assessment (EIA) is likely to be required if the oil and gas flared during the duration of the test is significant.
An EWT Consent requires a formal letter of application setting out the timetable and objectives of the test and the quantities of oil and gas to be produced saved or flared. Operators should note that if oil and gas are to be saved during the EWT, a Field Determination may be required for the field in question. In planning EWTs, Licensees should bear in mind that any necessary EIA will require formal public consultation which can take from 3 to 6 months. A Pipeline Works Authorisation may also be required for the subsea equipment used to carry out the EWT.
4.4.2 Phased developments
4.4.2.1 Phased development to improve confidence or understanding
For fields which do not appear to have the economic potential to sustain further appraisal, or where the best development method cannot be determined without substantial production experience, the Department will accept the phased development of a field. The form of the later phases is then dependent on the results of the earlier ones. The Licensees will need to demonstrate that phased development does not prejudice economic recovery and will need to state in the Management Plan of the Field Development Programme the more likely forms of further phases, the criteria which will need to be met and the time frame proposed for further appraisal or development. The production authorisation would normally be for the duration of the first phase only.
Phased developments of the type described above, like EWTs described in the previous section, have one objective in common, namely the improvement in understanding of the field. For some fields a choice must be made by the Licensees of which approach to propose. The differences between the two options which the Licensees and Department would need to consider are as follows:
- The prime purpose of an EWT is to gain reservoir understanding; little attention needs to be paid to the possible final forms of development other than to ensure that the reservoir is not being irreversibly harmed. A phased development, in contrast, will need to demonstrate at the outset how subsequent phases of development could be accomplished and how the information gathered in the first phase would be used to help determine the later phases.
- The duration of and production from an EWT are primarily set by its technical objectives and, for most tests, will be small in comparison to ultimate field life and recovery. Within the constraint that it should improve ultimate economic recovery, the duration and production of the first phase of a phased development will be determined by the usual development objectives and are likely to be significant in terms of field life and recovery.
- For a phased development, the production facility should be optimised for the likely requirements of the field during at least the first phase. For an EWT there is no need for the facility to be optimised beyond what is required for minimising environmental emissions and for the data collection objective.
4.4.2.2 Phased development for the purpose of early production
The Department will approve early production during the period needed for the construction of permanent facilities when this is appropriate as the first phase of a development.
4.4.3 Staged development for commercial or economic benefit
For some fields, although the final form of the development is known from the outset, it may be commercially or economically advantageous to stage expenditure, development or production. The Department is willing to accept such developments provided the Licensees can demonstrate that this staging is not detrimental to ultimate economic recovery. In these cases, depending on the complexity of the field, production authorisation could be for field life subject to conditions that the further stages are undertaken.
4.4.4 Flexibility in the selection of facilities option
Licensees may wish to retain flexibility in the final selection of the facilities option for a particular field in order to optimise their project schedule. Whilst the Department is prepared to indicate during the review stage which of the options may be technically acceptable, Field Development Programme authorisation can be given only when the final selection has been made.
In considering any proposal the Department recognises that the understanding of a field is necessarily incomplete at the time decisions are being made and that this may result in a less than optimal development. This is particularly likely to be the case where a flexible approach is being adopted. In proposing developments in these circumstances, Licensees should ensure whenever possible that reasonable provisions are made for effective recovery from a more optimistic field interpretation.
4.5 Intermediate decisions
The project planning process generally benefits if intermediate decisions can be made on technical aspects of the project before final commitment is made to the programme. The Department wishes to aid this process and, if it is necessary, the field development team manager will confirm when agreement has been reached on a broad conceptual proposal for the development or when all questions relating to a specific discipline have been addressed and agreed. Operators should note that "Letters of Assurance" to support intermediate decisions cannot fetter the Secretary of State's discretion to approve developments under the terms of a petroleum production licence and should not be taken as an indication that the final Field Development Programme will be approved.
4.6 Time frame
Provided that the interactive process described above has been fully implemented, the Department's aim, where there are no major unresolved issues, is to complete its review of the final submitted Field Development Programme within one month. The early review of draft sections of the Field Development Programme, as these become available, will help it to achieve this aim.
The Operator should note that the Field Development Programme will not be approved until the Environmental Impact Assessment process for the development has also been completed. The EIA and Field Development Programme should be prepared in parallel by the Operator and any choice of development concept must be made giving full weight to environmental concerns. The EIA process is regulated by The Offshore Petroleum Production and Pipe -lines (Assessment of Environmental Effects) Regulations 1999 (S.I. 1999/360) and detailed guidance on the EIA process is given in the Department's
Guidance Notes on the Offshore Petroleum Production and Pipe -Lines (Assessment Of Environmental Effects) Regulations 1999 [Reference 4]. For developments with trans-boundary implications, the trans-boundary issues are likely to take substantially longer to resolve than the Department's review of the programme.
The development will be authorised (i.e. the necessary consents will be granted pursuant to the applicable model clauses and/or EIA regulations) once the Secretary of State is satisfied that the Field Development Programme meets the Government's policy objectives set out above and the Environmental Impact Assessment process has been completed successfully.
5.1 Production
The Secretary of State's consent will cover both the construction of the facilities and other infrastructure, and the production of hydrocarbons from the field. The duration and the levels of production allowed will always depend on the particular circumstances of the field. The general principles outlined below will, however, be applied in each case.
5.1.1 Simple oil or condensate fields and all dry gas fields
Subject to the terms of the licence, agreement will usually be given for production over the forecast lifetime of the development with wide tolerances in the levels to be produced. Conditions may be attached to give the Department powers to require a review if performance falls outside these tolerances or if the field is found to differ from the initial perception to such an extent that there is a risk of a loss of significant economic reserves. For phased developments, agreement will normally be for the duration of the relevant phase.
5.1.2 Other fields
It is the Department's policy to provide Production Consents for as long a duration as possible, consistent with the duration of relevant licences, and the technical and investment uncertainties associated with future production. The duration of the initial period of agreed production will be proportional to the degree of understanding of the field: the more uncertain the performance, the shorter will be the duration. The tolerances on the level of production during this period will reflect this uncertainty and it is unlikely that these will be exceeded. Subject to the uncertainties involved, agreement to a duration of between five years and Life-of-Field are anticipated, with tolerances having an upper limit of up to 25% above the base case.
Unless demanded by circumstance, there will be no lower limit to the tolerance but the Department should be informed if production ceases for any significant period. Production should not cease permanently without justification being given in a Cessation of Production document (see Appendix 7).
5.1.3 Gas flaring and venting
The Department is committed to eliminating any unnecessary or wasteful flaring and venting of gas. For new developments the Department expects that where, over the life of the field, the value of the produced gas is higher than the costs of bringing it to the market, the Licensees will make provision for its processing and transportation to shore. In considering whether the gas should be brought to market, the Department will have regard to the overall costs and benefit; these may not reflect the commercial positions of individual Licensees.
Where the processing and transportation of gas involves the use of third party infrastructure, the distribution of value between the Licensees and the infrastructure owners is, in the first instance, a matter of commercial negotiation between the parties. Following negotiation with the infrastructure owners the Licensees may, however, apply to the Secretary of State to use his discretionary powers under the Petroleum Act 1998 to set charges or to require access to infrastructure. The Department encourages both infrastructure owners and users to adopt the principles of the industry's voluntary Offshore Infrastructure Code of Practice [Reference 3] in infrastructure access negotiations.
If it is not economic to bring the gas to shore, the Licensees should carefully consider all other options for its handling. These would include its use as fuel, as a means for improving oil recovery, for conversion to other fuels, injection for disposal, sale to a neighbouring development or flaring. As with other development alternatives, the option which maximises the economic recovery of the field would normally be selected. Where gas is to be disposed of by flaring, full consideration should be given in the design of the facility to providing for less wasteful alternatives should the economic or technical circumstances change.
For some developments flaring or venting will be necessary for safety or operational reasons. Licensees should seek to minimise this by implementing best practice at an early stage in the design of the development and continuing to improve on this during the subsequent operational phase
During the commissioning of production facilities flaring consents will usually be restricted in duration to between one and three months and will be for a fixed quantity of gas based on an auditable programme. Once stable operating conditions have been achieved the duration of the consent will be increased to twelve months and will be subject to an agreed cumulative maximum for the period. Detailed guidance on the procedures for dealing with gas flaring and venting during the commissioning phase of a new development is provided in Appendix 9.
5.1.4 Extension of licence terms
A number of problems might arise where a licence expires before production from a field is completed. There is no general right of extension. The licence term is set at the time of award to cover the likely period needed for exploration, appraisal and production. However, the Secretary of State does have discretion to extend a licence having regard to the merits of the case. The actions the Secretary of State might be prepared to take, and the time scale on which such action might be initiated, are set out in detail in a letter to the UK Offshore Operators Association dated 12 November 1990. Essentially, there are two stages to this process:
1) If, either at the time of approval of a Field Development Programme or during the period of production, it appears that production is likely to continue beyond the term of the licence, the Department will indicate formally that an extension will be granted subject to the continuing satisfactory performance of obligations under the licence.
2) The extension itself will be granted nearer the time of expiry if it continues to be the case that production will continue beyond the original licence term. The extension will cover the area of production and the time needed to complete production from it.
Licensees having concerns regarding licence expiry should bring them to the attention of the Department.
5.2 The Environmental Impact Assessment process
Under the Offshore Petroleum Production and Pipe -lines (Assessment of Environmental Effects) Regulations 1999, an Environmental Impact Assessment (EIA) is mandatory for all developments where the level of oil production is intended to exceed 500 tonnes a day (3,750 barrels/day) or the level of gas production is intended to exceed 500,000 cubic metres a day, regardless of the location of the development. It is, therefore, unlikely that there will be any new oil or gas developments in the UKCS where an Environmental Statement is not required to be prepared.
Where an Environmental Statement is prepared it will include details of any measures which the Licensees intend to take to mitigate the impact on the environment of the proposed development. All Environmental Statements are subject to a period of consultation during which time any person or body with an interest in the proposed development may make their views known to the Secretary of State. The Regulations also require that copies of the Environmental Statement be made available to certain environmental authorities and to the public at large.
In making his decision whether or not to give consent to a proposed project, the Secretary of State will take into account the Environmental Statement itself as well as any representations he has received. If the Secretary of State considers that a project would cause a significant negative impact on the environment, consent might be refused or conditions to mitigate or remedy any adverse effects might be imposed in the field development consent.
The Environmental Impact Assessment process generally proceeds in parallel with the preparation of the Field Development Programme. Licensees should bear in mind that the consideration of an Environmental Statement generally takes several months and can take significantly longer than this if substantial representations are made by any of the consultees.
Detailed guidelines on Environmental Statement preparation is given in the Department's Guidance Notes on the Offshore Petroleum Production and Pipe -Lines (Assessment Of Environmental Effects) Regulations 1999 [Reference 4] which can be found on the Oil and Gas Directorate's Website at http://www.og.dti.gov.uk/.
The focus of the Department, once a development has been agreed, will be to ensure that the Field Development Programme is being followed or modified appropriately as the understanding of the field develops. The Operator will be required to prepare a regular Field Report which will alert the Department to proposed deviations from, or alterations to, the agreed Management Plan within the Field Development Programme.
6.1 Divergence from the agreed Field Development Programme
All Field Development Programmes should contain an agreed Management Plan for the commissioning and production phases of the development. The Management Plan will set out the principles and objectives on which continuing technical analysis, data gathering and resulting field management decisions will be taken. In addition, the Field Development Programme itself will have objective criteria by which the successful development of the field can be judged.
The responsibility for continuing to develop the field in accordance with the Field Development Programme and Management Plan rests with the Licensees. In order that the Department can satisfy itself that this responsibility is discharged effectively the Licensees are required to inform the Department as soon as significant deviations from the programme are foreseen. Most fields will require a periodic Field Report (described below) which should be used to signal expected deviations from the agreed programme and, where necessary, propose revised approaches to field development and management. Within six weeks of receipt of the Field Report the Department will formally accept these proposals or indicate where it sees a divergence between the Licensees plans and its own objectives. By this means an agreed Field Development Programme for a field can, in most cases, be maintained naturally without the need for more formal and time -consuming revisions to the original programme.
Where a further phase of development is to be implemented with substantial alterations to the size, development strategy or understanding of the field, or where major new facilities are required, there may be a need for a more formal revision to the relevant sections of the Field Development Programme than could be provided by the Field Report.
It is possible that a change to the approved Field Development Programme may require Environmental Impact Assessment under the Offshore Petroleum Production and Pipe -lines (Assessment of Environmental Effects) Regulations 1999 [Reference 9]. This will also need to be discussed by the Licensees with the Oil and Gas Directorate's team manager.
6.2 Reporting
A Field Report will normally be required annually, but for simple or well - understood mature fields with minimal flaring the reporting should become less frequent. General guidelines for this report are set out in Appendix 6. These can be amended in discussion with the Department to meet the specific needs of individual fields and a single Field Report can be used to cover the development of several fields, particularly in the case of "Core-Area" developments with host platforms and satellite tie-backs.
In addition to the Field Report the Department will require limited monthly production data via the Petroleum Production Reporting System (PPRS). During the construction phase, deviations from the planned facilities completion programme should be reported. No other routine reporting will be required, other than that required of industry in general.
6.3 Auditing process
In addition to the reporting by exception outlined above there may be technical audits carried out periodically either on a random basis or as a result of concerns. These audits may be of a single aspect of the field management or of the field as a whole.
6.4 Fields authorised under earlier procedures
It is intended that field developments authorised under earlier procedures will continue to operate under existing consents or approvals until these expire or the Licensees request a revision. At that time the authorisation will be administered in accordance with these Guidance Notes: a revision to the Field Development Programme will not automatically be required although a Field Management Plan (Appendix 4) will be requested if this has not been generated in earlier Field Reports (Appendix 6).
6.5 Cessation of production
During the life of the field, the regular Field Reports will provide for reviews of the longer term development of the field and for reviews of the potential for further incremental activity. As the forecast end of field life approaches the Field Reports should be used to demonstrate that all economic development has been pursued and this will enable the Department to agree with the Licensees that Cessation of Production (COP) from the field is appropriate. In order to ensure that all aspects are thoroughly investigated, this process should start about five years prior to the Licensee's anticipated date for COP for large platform -based developments. Where the ongoing review of further development has been properly considered it can be expected that COP will be agreed quickly.
Some Operators may prefer to submit a stand -alone COP document and this is also acceptable. Guidelines for the contents of a stand -alone COP submission are provided in Appendix 7. However, this does not reduce the need for options for further development to have been considered in earlier Field Reports.
For fields with a limited economic life it may only be possible to submit the COP a few months before production is forecast to become uneconomic. In these cases greater emphasis will be placed on the review of options in earlier Field Reports.
The normal economic criterion for deciding when a field's production is no longer economic and that production should cease is that, taken over a reasonable period, the value of the hydrocarbons produced no longer covers the true costs of production. In normal circumstances this maximises the economic value of the development and is a relatively straightforward calculation. However, two issues, residual value and leasing costs, have given rise to complications. If the Licensees want the residual value of some or all of the production facility to be considered in the calculation, they will need to demonstrate that there is a definite opportunity to realise value which, if not realised at a specific time, will be forgone.
The treatment of leasing costs in the establishment of the economic cut -off has proved problematic and must be agreed in principle at the time of development approval. In general, the Department does not consider that unavoidable costs such as capital repayment and the costs of financing are true costs of production and they should, therefore, not be considered in the definition of the economic limit for Cessation of Production.
The procedure that should be adopted during the development approval process should be, first, for the Department and the Operator to work together to identify the true economic cut -off from estimates of the underlying production profile and operating cost. The Licensees should work with the potential Lessor(s) to reach a contractual agreement which will get as close to the theoretical economic limit as practicable, taking into account the need of the operator to manage the risk of the project. In cases where the Licensees are not able to achieve this objective the Department will wish to examine the position to establish if there are any genuine economic causes for this failure.
It is recognised that uncertainty in the performance of the development and other technical and economic factors may complicate this process and the Department is willing to work closely with the Operator to identify these risks and encourage the development of appropriate contractual frameworks which can take account of information gained during production.
6.6 Storage of field information following cessation of production
It is important that Operators retain sufficient information after COP to enable other interested potential operators to take a reasonably informed view about the potential for field redevelopment. Redevelopment may become feasible if, for example, new technology allows a significantly improved recovery factor.
The amount of information that should be retained will obviously depend on field size and complexity and this should be discussed with the Department on a case- by-case basis at the appropriate time. The intention is to minimise the data retention requirements to that which is strictly necessary. As a minimum the Department would expect operators to retain the final full -field reservoir simulation model, the final geological model and copies of the Field Development Programme, Field Reports and production and injection profiles on a well -by- well basis.
6.7 Decommissioning
The Petroleum Act 1998 provides that all parties with a decommissioning liability submit a Decommissioning Programme for the Secretary of State's approval at such time as he may specify. Guidelines on the preparation of Decommissioning Programmes are available from the DTI Oil and Gas Directorates Website at http://www.og.dti.gov.uk/ or can be obtained direct from the Offshore Decommissioning Unit in Atholl House, Aberdeen [Reference 10].
The Operator should discuss his plans with the Department's Offshore Decommissioning Unit before submitting a programme so that guidance can be given on what is likely to be acceptable. These discussions should commence well ahead of the forecast COP date and, in the case of a large field with multi -facilities, this may need to be three years or more in advance. The onus rests with the Operator to initiate these discussions.
In accordance with the UK's international obligations, all installations emplaced after 9 February 1999 must be completely removed to shore for reuse, recycling or final disposal on land. A statement to that effect should be included in the Field Development Programme.
7.1 Changes of field operator
There have been several changes of Operator for producing fields in recent years and this seems to be an increasing trend as the North Sea matures. The Department welcomes new Operators and experience has shown that the new ideas and approaches brought forward by a change in Operator can lead to significant extension in field life and result in increased reserves for mature reservoirs, helping to extend the life of the North Sea oil fields significantly beyond original expectation.
The North Sea is generally acknowledged to be one of most challenging areas for oil and gas production in the world. At the same time the track record of existing Operators in maximising hydrocarbon recovery through technical innovation is second to none. The Department is keen to maintain this record of excellence and prospective new Operators will be carefully screened to assess their ability to manage UKCS oil and gas fields to maximise economic oil recovery with due regard for the environment and with sound finances. The licence requires that only an approved Operator may manage or supervise the drilling and production phase of an oil or gas development. The objective of this requirement is to ensure that field operations are undertaken competently. Ministers do have the discretion to approve multiple Operators for a field but would need compelling evidence that a field could be developed competently under such a scheme.
The degree of scrutiny of a new prospective field Operator will naturally depend on their existing track -record, both in the UKCS and elsewhere, of technical, management and financial competence. Detailed guidance on the information required from a prospective Operator is given in Appendix 8.
To be appointed as an Operator a company will need to show that it understands the development and environmental responsibilities of the Operator and that it is competent, both financially and technically, to discharge these under its agreements with its co-Licensees. The company will need to be able to demonstrate a sound management structure staffed by an established group of experienced personnel. A prospective Operator would normally be expected to have a proven track record of success in the operatorship of comparable developments elsewhere and have an approach to field development compatible with the Department's objective of securing maximum economic recovery from each field. A substantial use of contracted staff would need to be justified.
7.2 Leased facilities and contracting-out of field operations
There is an increasing trend for some activities traditionally undertaken by the appointed Operator to be contracted out to third parties. The Department is aware of the potential benefits of this approach but is concerned that as a result of this contracting out the appointed Operator will lose the ability to discharge its responsibility for the overall supervision and management of the development. The Operator must retain sufficient expertise and resources to evaluate the quality of the work of a sub -contractor and be able to form an independent view as to whether the contractor's plans or activity accord with good oilfield practice and will result in the maximum recovery of economic hydrocarbons with due regard for the environment.
If a substantive part of the drilling or production operation is contracted out, the Operator will be responsible for ensuring that the contractor is obliged to work in accordance with good oilfield practice and have suitably qualified and experienced staff working under an effective management system. The Operator will need to supervise the work of the contractor, identify where obligations are not being met or where they require change and put in place an effective mechanism for the enforcement or modification of the contractor's obligations and actions.
Other than for unmanned developments, it is not currently anticipated that the Operator would normally be able to fulfil these expectations without having a permanent presence at the development. It is recognised, however, that on some facilities where activity is at a low level, a permanent presence might not be appropriate and it is open to Operators to discuss with the Department alternative means for ensuring that they are properly supervising and managing operations
It should be noted that matters relating to the safety of operations are covered by regulations operated by the Health and Safety Executive and are quite separate from the functions of the Operator described here.
An organogram of the Oil and Gas responsibilities of DTI staff is available on request from the Oil and Gas Directorate at:
1 Victoria Street,
LONDON SW1H 0ET
or
Atholl House
86 -88 Guild Street,
ABERDEEN AB11 6AR
Or on the Oil and Gas Directorate Website at http://www.og.dti.gov.uk/.
8.1 Oil and Gas directorate
The Oil and Gas Directorate has responsibility for developing and co - ordinating policy on the development of the oil and gas fields on the land territory of Great Britain, in the UK's territorial waters and on the UKCS and for regulating the licence regime. Within the Directorate, which has offices in London and Aberdeen, technical specialists have responsibility for the technical aspects of policy and regulation, including review of Field Development Programmes.
A technical team will be assigned to each field headed by a team manager whose relationship to the Department's senior management is similar to that of the project manager to the Operator's senior management. Members of these teams, which will be based either in London or Aberdeen, will be drawn from the following disciplines:
Others within the Directorate will be directly involved in the review of specific aspects of Field Development Programmes. They provide advice during the review but also have responsibility, under separate legislation, for regulation when the programme is executed. The Field Development Programme provides their initial point of contact for the execution phase.
The metering section, based in Aberdeen, is responsible for agreeing with the Licensees the method of measurement to be used for oil and gas metering. The principles are agreed during the Field Development Programme review process - reference is made to Petroleum Operations Notice 6, and to the Departments Guidance Notes for Standards of Petroleum Measurement (September 1997) [Reference 5].
The Directorate has, in addition to the petroleum engineering teams noted above, groups responsible for:
During the review and evaluation of a Field Development Programme the technical team will also be assisted by economists and statisticians from within the Department and will provide copies of the Field Development Programme to the Directorate's Oil and Gas Industry Development branch for information.
8.2 Other government interests
Other Government Departments and Ministries receive selected sections of the Field Development Programme for information purposes. Should they have specific concerns they will raise them directly with the Operator. These are:
The DTI and a number of other Government Departments are responsible for providing a range of consents and authorisations, under a variety of legislation, during the execution phase of a Field Development Programme. Licensees should note that authorisation for a Field Development Programme, given by the Secretary of State for Trade and Industry under the relevant model clause, is given in relation to that model clause only. It does not override, or imply any commitment in respect of, any other requirement to be satisfied under any other model clause or any provision in legislation. The Operator is responsible for ensuring legal compliance including that all necessary consents and authorisations are obtained as and when required. The Operator is advised to make contact with all other Government bodies at the earliest opportunity; they should not rely on the submission of the Field Development Programme to alert these bodies of their intentions or to set the time frame for their discussions.
Although the Health and Safety Executive's Offshore Division (OSD) is not involved in the approval of Field Development Programmes, the Safety Case for design to be submitted to the HSE will need to show how the general principles of risk evaluation and risk management have been applied from the earliest stages of design. This should include design concept selection. Operators will therefore find it beneficial to open an early dialogue with OSD in relation to concept selection and conceptual design. Appendix 10 briefly explains OSD's role in the design process and gives contact details for OSD offices.
Set out below are extracts from the model clauses most relevant to these Guidance Notes. All existing model clauses are reproduced in the Petroleum (Current Model Clauses) Order 1999.
Model clause 15 (part only)
Development 15.
(1) The Licensee shall not - and production
(a) erect or carry out any relevant works, either in the licensed area or elsewhere, for the purpose of getting petroleum from that area or for the purpose of conveying to a place on land petroleum got from that area; or
(b) get petroleum from that area otherwise than in the course of searching for petroleum or drilling wells,
except with the consent in writing of the Minister or in accordance with a programme which the Minister has approved or served on the Licensee in pursuance of the following provisions of this clause.
(2) The Licensee shall prepare and submit to the Minister, in such form and by such time and in respect of such period during the term of this licence as the Minister may direct, a programme specifying -
(a) the relevant works which the Licensee proposes to erect or carry out during that period for either of the purposes mentioned in paragraph (1)(a) of this clause;
(b) the proposed locations of the works, the purposes for which it is proposed to use the works and the times at which it is proposed to begin and to complete the erection or carrying out of the works;
(c) the maximum and minimum quantities of petroleum in the form of gas and the maximum and minimum quantities of petroleum in other forms which, in each calendar year during the period aforesaid or in such other periods during that period as the Minister may specify, the Licensee proposes to get as mentioned in paragraph (1)(b) of this clause.
Model clause 21 (complete)
Avoidance
21
(1) The Licensee shall maintain all apparatus and appliances and all wells in the licensed area which have not been abandoned and plugged as provided by working clause 17 hereof in good repair and condition and shall execute all operations in or in connection with the licensed area in a proper and workmanlike manner in accordance with methods and practice customarily used in good oilfield practice and, without prejudice to the generality of the foregoing provision the Licensee shall take all steps practicable in order-
(a) to control the flow and to prevent the escape or waste of petroleum discovered in or obtained from the licensed area;
(b) to conserve the licensed area for productive operations;
(c) to prevent damage to adjoining petroleum bearing strata;
(d) to prevent the entrance of water through wells to petroleum bearing strata except for the purposes of secondary recovery; and
(e) to prevent the escape of petroleum into any waters in or in the vicinity of the licensed area.
(2) The Licensee shall comply with any instructions from time to time given by the Minister in writing relating to any of the matters set out in the foregoing paragraph. If the Licensee objects to any such instruction on the ground that it is unreasonable he may, within fourteen days from the date upon which the same was given, refer the matter to arbitration in manner provided by clause 40 hereof.
(3) Notwithstanding anything in the preceding provisions of this clause, the Licensee shall not -
(a) flare any gas from the licensed area; or
(b) use gas for the purpose of creating or increasing the pressure by means of which petroleum is obtained from that area,
except with the consent in writing of the Minister and in accordance with the conditions, if any, of the consent.
(4) An application for consent in pursuance of paragraph (3) of this clause must be made in writing to the Minister and must specify the date on which the Licensee proposes to begin the flaring or use in question; and subject to paragraph (5) of this clause that date must not be before the expiration of the period of two years beginning with the date when the Minister receives the application.
(5) If the Minister gives notice in writing to the Licensee stating that, in consequence of plans made by the Licensee which the Minister considers are reasonable, the Minister will entertain an application for consent in pursuance of paragraph (3) of this clause which specifies a date after the expiration of a period mentioned in the notice which is shorter than the period mentioned in paragraph (4) of this clause, an application made in consequence of the notice may specify, as the date on which the applicant proposes to begin the flaring or use in question, a date after the expiration of that shorter period.
(6) Before deciding to withhold consent or to grant it subject to conditions in pursuance of paragraph (3) of this clause, the Minister shall give the Licensee an opportunity of making representations in writing to the Minister about the technical and financial factors which the Licensee considers are relevant in connection with the case and shall consider any such representations then made to him by the Licensee.
(7) Consent in pursuance of paragraph (3) of this clause shall not be required for any flaring which, in consequence of an event which the Licensee did not foresee in time to deal with it otherwise than by flaring, is necessary in order-
(a) to remove or reduce the risk of injury to persons in the vicinity of the well in question; or
(b) to maintain a flow of petroleum from that or any other well;
but when the Licensee does any flaring which is necessary as aforesaid he shall forthwith inform the Minister that he has done it and shall, in the case of flaring to maintain a flow of petroleum, stop the flaring upon being directed by the Minister to stop it.
(8) The Licensee shall give notice to the Minister of any event causing escape or waste of petroleum, damage to petroleum bearing strata or entrance of water through wells to petroleum bearing strata except for the purposes of secondary recovery forthwith after the occurrence of that event and shall, forthwith after the occurrence of any event causing escape of petroleum into the sea, give notice of the event to the Chief Inspector of Her Majesty's Coastguard.
(9) The Licensee shall comply with any reasonable instructions from time to time given by the Minister with a view to ensuring that funds are available to discharge any liability for damage attributable to the release or escape of petroleum in the course of activities connected with the exercise of rights granted by this licence; but where the Minister proposes to give such instructions he shall before giving them -
(a) give the Licensee particulars of the proposal and an opportunity of making representations to the Minister about the proposal; and
(b) consider any representations then made to him by the Licensee about the proposal.
Model clause 25 (part only)
Unit 25.-(1) If at any time in which this licence is in force the Minister shall be satisfied that the strata in the licensed area or any part thereof form part of a single geological petroleum structure or petroleum field (hereinafter referred to as "an oil field") other parts whereof are formed by strata in areas in respect of which other licences granted in pursuance of -
(a) the Act of 1934, or
(b) that Act as applied by the Act of 1964, or
(c) Part I of the Act of 1998,
are then in force and the Minister shall consider that it is in the national interest in order to secure the maximum ultimate recovery of petroleum and in order to avoid unnecessary competitive drilling that the oil field should be worked and developed as a unit in cooperation by all persons including the Licensee whose licences extend to or include any part thereof the following provisions of this clause shall apply.
The very high costs of developing an oil or gas field, which can only be recovered from significant production, mean that the national interest and commercial imperatives are generally similar in relation to maximising production. However, there may be cases where they could diverge. Some examples are:
a. Where a field covers more than one block, with different owners. Attempts to gain higher shares in total output (i.e. capturing other companies' reserves) could damage reservoirs and result in needless expenditure.
b. Where production is via a floating production system. These have high operating costs, so there is an incentive to cream off high early production and move to the next location, rather than produce all the economic oil.
c. Where company capital constraints point them towards a lower cost, but less economic, development option which could leave potentially economic reserves unproduced.
d. Where severe cash constraints lead Licensees to prefer options which emphasise the need for early cash at the expense of additional recovery, or result in additional gas flaring.
e. Where partners disagree amongst themselves. Almost all licences are held jointly by a number of partners, which introduces scope for disagreement between the licensees, though joint holding of licences is an important risk sharing device.
The approach taken by the Department is to ensure that, at the planning stage, the Licensees have examined those options which are most likely to secure the full recovery of the economic reserves of the area. In most cases the preferred commercial option will achieve this but, as explained above, cases can arise where wider UK interests and commercial interests differ. In such circumstances the Department will, in discussion with the operator, wish to obtain a full appreciation of the commercial factors and constraints involved, and explain why it believes wider UK interests are not being served by a particular option.
In examining Field Development Programmes for new fields, and significant departures proposed from authorised programmes for existing fields, the Department will in particular wish to be satisfied that the approach agreed does not lead to the permanent loss of reserves which could otherwise be recovered economically. In looking at the wider picture, the Department focuses on those options which are most likely to secure maximum economic recovery of hydrocarbon reserves from the reservoir in question, taking into account other potential reserves in the area. The welfare of the UK as a whole will be highest when the net present value (NPV) of field development is maximised, taking into account the effect on recovery in other fields. This is irrespective of the division of realised value between the Licensees and the Exchequer. In ranking options the Department thus focuses on pre -tax NPVs calculated using an appropriate discount rate (currently, 10 per cent real).
General approach
The approach taken by the Department to the process of field development authorisation is to establish whether there are any aspects of the proposed development which may conflict with the Department's objectives and to focus attention on resolving those aspects before the formal Field Development Programme is submitted. Where all issues have been resolved the Field Development Programme will contain only a summary of the field and choice of development, with a more detailed description of the form of the development, its management and expected production.
To assist this process it is expected that there will be a continuing dialogue and informal technical reviews as the description of the field and options for its development emerge during the development planning phase. There will not be routine, detailed examination of the Operator's technical work unless it is established that there may be substantive issues. If issues are identified then a more detailed investigation of the elements of the development essential for the resolution of these will be made, and the Licensees will be expected to work towards justifying the plans before the Field Development Programme is submitted. For some developments it is expected that there will be no substantive issues identified and accordingly there will be no detailed examination of the Licensees technical work.
If the process outlined above is followed the Field Development Programme documentation be prepared towards the end of the development planning process, require only minor revisions to reach its final form and should be approved within one month of submission of the final document.
Audits
In addition to the process described above, there may be a technical audit carried out on elements of the development. The purpose of the audit will be to confirm the general quality of work, not to identify areas of disagreement of interpretation. It will not be necessary to prepare any technical documentation, either for inclusion in the Field Development Programme or as background support, in the expectation of an audit. It is expected however that, if required for any aspect of the development, the Operator will be able to demonstrate a trail leading from uninterpreted data to statements in the Field Development Programme.
Alternative approaches
It is recognised that this approach, although favoured by the Department, may not suit Licensees wishing to use the Field Development Programme as a comprehensive reference document or who feel that the approach is unsuited to their internal organisation. In this case the submission of a different form of document, provided it covers the same issues, is acceptable. Licensees wishing to adopt an alternative approach should realise that a proposal that is not the result of a continuing dialogue with the Department will necessarily take longer to approve.
Content of the Field Development Programme
Set out below are suggested Field Development Programme section headings together with the topics which should be addressed in the Field Development Programme. The actual content of the document should be agreed with the Department's field team and will depend on the complexity of the field, the degree of interaction prior to the submission and the number of issues identified. The Field Development Programme should provide a clear explanation of the commitments that the Licensees are making (in terms of facilities, number of wells, gas export etc.) to bring forward a sound development, rather than a detailed technical description of the subsurface reservoir description or required infrastructure. It is anticipated that the norm for Field Development Programme documentation on all fields will be in the region of a maximum of 15 pages of text plus associated figures and tables. More comprehensive or varied text, which some Operators might for example choose to submit for partner reasons or internal preferences, will be accepted provided it covers the Department's information requirements.
Only very brief summaries will be required for reservoir description (section 2), although Operators will be expected to keep their own detailed record of how the reservoir model was arrived at as part of good oilfield practice.
The actual form of the development and the basis for field management should be described in section 3 and sufficient detail will be required to permit development and production performance to be measured. Operators are encouraged to refer to internal documents and studies in sections 2 and 3 to keep Field Development Programme documentation to a minimum.
Six copies of the Field Development Programme are required, preferably single spaced. The Oil and Gas Directorate distributes copies to other Government organisations, such as the Department of the Environment Transport and the Regions, and the Scottish Executive Industry Department, for information.
Field determination
Field Determinations are required under Schedule 1 to the Oil Taxation Act 1975 and will be based on geological grounds. The information necessary to define the structure and geological model of the field will normally be adequate for the Oil and Gas Directorate to make the Determination. Normally a proposed Field Determination will be issued prior to the authorisation of the Field Development Programme.
A field may need to be Determined prior to an Extended Well Test if a substantial quantity of hydrocarbon is to be won and saved. This should be discussed with the Department prior to EWT approval.
Development area
The Development Area identifies that part of the field to which the development proposals refer, which may coincide with area defined by the Field Determination. Some Licensees may, however, wish to consider a phased development and the Development Area in this instance will be limited to that part of the field addressed in the detailed first phase proposals. The Development Area will be extended with subsequent phases.
1. Executive summary
The Executive Summary should state the essential features of the development including:
2. Field description
The purpose of this section is to present the description of the field on which the development has been based and so provide a baseline for future modifications as development proceeds.
The description should be in summary form and only a brief statement, table or map of the results provided with references to more detailed company -held data where appropriate.
Figures, diagrams and data tables
Licensees are encouraged to submit only those maps, sections and tables necessary to define the field adequately but should include at minimum a table of in - place hydrocarbon volumes, a representative cross -section and top structure maps for each reservoir. Maps should be in subsea depth at appropriate scales and include co- ordinates in degrees of latitude and longitude and the standard U.T.M. grid, stating the central meridian used and datum.
2.1 Seismic Interpretation and Structural Configuration
A brief summary of the extent and quality of the seismic survey and the structural configuration of the field should be presented using appropriate figures and maps.
2.2 Geological Interpretation and Reservoir Description
The stratigraphy of the reservoirs, facies variations, the geological correlation within the reservoir and any other relevant geological factors that may affect the reservoir parameters (both vertically and horizontally) and thereby influence reservoir continuity within the field should be described in summary form. Figures and maps should be provided where appropriate.
The geological data provided should reflect the basis of reservoir subdivision, and correlations within the reservoir, and should include the relevant reservoir maps on which the development is based.
2.3 Petrophysics and Reservoir Fluids
A brief summary of the key field petrophysical parameters should be presented incorporating log, core and well test data.
A summary of the field PVT description should be included.
2.4 Hydrocarbons-In- Place
The volumetric and any material balance estimates of hydrocarbons -in -place for each reservoir unit should be stated together with a description of the cause and degree of uncertainty in these estimates.
The basis of these estimates should be available and referenced.
2.5 Well Performance
The assumptions used in the Field Development Programme for the productivity and injectivity of development wells should be stated. Where Drill Stem or Extended Well Tests have been performed the implications of these on production performance should be given. The potential for scaling, waxing, corrosion, sand production or other production problems should be noted and suitable provision made in the Field Management Plan (Section 3.7).
2.6 Reservoir Units and Modelling Approach
Where the reservoir has been subdivided for reservoir analysis into flow units and compartments the basis for division should be stated. A description of the extent and strength of any aquifer(s) should be given.
The means of representing the field, either by an analytical method, some form(s) of numerical simulation, or by a combination of these should be briefly described.
2.7 Improved Recovery Techniques
A summary of the alternative recovery techniques considered and the reasons for the final choice is required. For all oil or condensate reservoirs the potential for application of improved recovery techniques beyond conventional methods should be described. Where firm conclusions cannot be reached a programme for addressing these issues during production should be given in the Field Management Plan (Section 3.7).
2.8 Reservoir Development and Production Technology
The chosen recovery process should be described and the optimisation method summarised, including reference to the potential for artificial lift and stimulation. Any limitations on recovery imposed by production technology or by the choice of production facility or location should be indicated.
Remaining uncertainties in the physical description of the field which may have material impact on the recovery process should be described and a programme to resolve these should appear in the Field Management Plan (Section 3.7).
3. Development and management plan
The purpose of this section is to set out the form of the development, describe the facilities and infrastructure, and establish the basis for field management during the construction and production phases. For every element of the plan the description should be brief and related to the complexity of the facility or strategy concerned. Where a particular topic is not relevant to a development it should be omitted.
The general requirements for the section are set out below. Where an aspect of a development is simple the text should be correspondingly short and the entire section no more than five pages of text in length. Figures and tables should be used where appropriate and the referencing of existing documents is encouraged providing these are made available.
A statement confirming that all installations will be completely removed to shore for reuse, recycling or final disposal on land is required in accordance with the UK's international decommissioning obligations.
3.1 Preferred Development Programme, Reserves and Production Profiles
This section should describe the proposed reservoir development indicate the drilling programme, well locations, expected reservoir sweep and any provision for a better than expected geological outcome.
An estimate of the range of reserves for each reservoir should be given (excluding fuel and flare) with a brief explanation of how the uncertainty was determined and explicit statements of probability where appropriate. The assumed economic cut-off should be stated.
Expected production profiles, for total liquids, oil, gas, gas usage and flare, associated gas liquids and produced water for the life of the field are required. Where fluids are to be injected, annual and cumulative injection profiles should be provided. Quantities can be provided in either metric units or in standard oil field units (with conversions to metric equivalents provided). Information to allow calculation of sales quantities should be provided.
The anticipated date for Cessation-of-Production, together with the underlying assumptions, should be provided.
3.2 Drilling and Production Facilities
The drilling section should briefly describe the drilling package and well workover capability, and should include a description of the proposed well completion.
The production facilities section should describe the major equipment and infrastructure items and identify the design and operating parameters used as the basis of design. A clear indication of system bottle -necks and limitations that can give rise to production constraints should also be given together with details of the contingencies available to maintain production in the event of major equipment failure(s). The scope and flexibility for future modification and expansion to address any potential for upside, incremental and satellite field development should also be identified, including any spare capacity designed -in to the facilities / pipelines to allow for future development or third party tie -ins The studies forming the basis for the selection of the proposed development option should be referenced.
The section should include a diagram of the structures for the development, whether fixed, floating or subsea and should also include a description of the proposed hydrocarbon transportation system including, where appropriate, any onshore terminal facilities. Any limitations on offshore production resulting from constraints in the transportation and terminal facilities should be identified.
New transportation systems are often designed to service more than one development and may have a longer expected life than the originating field. In this instance a separate Field Development Programme for the transportation system may be necessary.
3.3 Process Facilities
A brief description of the operating envelope and limitations of the process plant should be provided. The use and disposal of separator gas should be described.
The section should also include:
3.4 Project Planning
Commissioning plans will be discussed in greater detail as the project develops, but it should be noted that the commissioning programme will need to demonstrate a commitment to preventing the unnecessary and wasteful flaring of associated gas.
3.5 Decommissioning
A very brief description of the proposed methods of decommissioning should be included to show the basis for the decommissioning expenditure estimates. Steps taken in the design to facilitate eventual decommissioning of the production facilities should be identified.
3.6 Costs
Cost information is required by the Department to assess the economics of the development and to allow forecasting of North Sea expenditure.
Capital (Capex) and Operational (Opex) expenditure profiles are required, phased by year, to a defined monetary base in UK pounds sterling.
Capex and Opex tabulations should be subdivided into:
Details are required of the tariffing arrangements and gas contracts where applicable and if these are different to those previously notified to the Department. Where these arrangements are commercially sensitive, a limited circulation 'side letter' will be acceptable.
The information on tariffs should include:
The information on Gas Contracts should include:
3.7 Field Management Plan
A Field Management Plan is required that sets out clearly the principles and objectives that the Licensees will hold to when making field management decisions and conducting field operations and, in particular, how economic recovery of oil and gas will be maximised over field life.
The rationale behind the data gathering and analysis proposed in order to resolve the existing uncertainties set out in Section 2 and understand dynamic performance of the field during both the development drilling and production phases should be outlined. The use of unmanned or subsea facilities may set restrictions on data gathering, these should be identified.
The potential for workover, re - completion, re-perforation and further drilling should be described. Where options remain for improvement to the development (Section 2.7) or for further phases of appraisal or development, the criteria and timetable for implementing these should be given.
Some developments will include common user facilities and may have capacity constraints; the methods to be used to set production priorities should be given. For gas reservoirs the criteria for installation of additional compression should be identified.
Legislative framework
Under Schedule 1 to the Oil Taxation Act 1975 all fields are "Determined", i.e. defined, as areas of which every part is, or is part of, a licensed area. Parliamentary debate during the passage of this Act made clear that these field areas would be Determined only on the basis of geological criteria and that an oil field would be as defined in the Petroleum (Production) Act 1934, that is a single petroleum geological structure. More recently, coalbed methane and mine gas projects, excepting those intended solely to make mine workings safe, have also been Determined as fields.
A Field Determination is therefore a boundary that encompasses the maximum extent of the field. This is taken as the maximum extent of all the hydrocarbons present, whether moveable or not, and regardless of whether the entire accumulation is in phase and/or pressure communication. It follows that for a hydrocarbon accumulation to be Determined as a field it must be physically separated from any other accumulations that might be present. This separation may be by means of a structural low below the lowest known hydrocarbon ("blue water") or by non - permeable rock e.g. a shale- out of the reservoir. Both structural and stratigraphic traps can therefore be Determined as fields.
The boundaries for offshore fields seaward areas (outwith the 3 nautical mile limit) east of the meridian 6 degrees west follow a latitude and longitude graticule based upon the geographical co -ordinate system ED50 (European Datum 1950).
The boundaries for offshore fields seaward areas (outwith the 3 nautical mile limit) west of the meridian 6 degrees west follow a latitude and longitude graticule based upon the geographical co -ordinate system ETRF89 (European Terrestrial Reference Frame 1989).
Onshore fields and those within the offshore landward 3 nautical mile limit, are defined in grid terms based upon the projected co-ordinate system OSGB National Grid/OSGB36.
The only exceptions to this are where a field either crosses an international boundary or extends from an offshore landward licence to areas beyond the 3 nautical mile limit.
Reference should be made to the DTI Gazette article published 21st December 1999 entitled "Co -ordinate systems for UKCS Petroleum Exploration and Production Licences" for details of the co -ordinate transformation parameters to be applied when transforming between ED50, ETRF89, OSGB36 and WGS 84.
Where fields overlap vertically as separate structures they have to be defined as "volumes" with a base and/or top to the determination. For coalbed methane and mine gas Determinations the boundary is drawn around the limit of permeable coal or the limit of worked out coal.
The Field Determination and Field Development Area are generally coincident although this is not mandatory.
Field determination process
A Field Determination is generally initiated by the submission of a Field Development Programme. A proposed Determination must have been issued before the Field Development Programme is approved.
The proposed Field Determination is issued by the Department to all Licensees involved in the field together with any others whose interests appear to be affected. The recipients of the proposed Determination have 60 days from the date of receipt to make any objections they may have to it in writing. Should objections be received the Licensees concerned are given the opportunity to put their case in more detail. All representations are considered but the final decision on the Determination rests with the Department acting on behalf of the Secretary of State. Once any objections have been resolved, a final Determination is issued. This must be in place before production commences from the field.
All Fields may be re-determined at any time at the request of any party should new geological and/or geophysical data indicate that the original Determination is no longer valid. An identical procedure to that described above is followed.
As all fields are Determined, i.e. defined, as areas of which every part is, or is part of, a licensed area it follows that when such a licensed area is relinquished the field in question must be re -determined to exclude that area.
These notes have been prepared to provide guidance to field operators engaged in preparing Field Reports on producing oil and gas fields.
The purpose of the Field Report is both to demonstrate that the field is being managed in a manner that will maximise economic recovery of hydrocarbons and to advise the Department of divergence from the approved Field Development Programme. The report should be used to propose revisions to either Section 2 (Field Description) or Section 3 (Development and Management Plan) of the original Field Development Programme as the understanding of the field improves. It is intended that this will reduce the need for more formal re -submissions of the Field Development Programme. Where radical changes to the Field Development Programme are proposed or where the timing of the field report is inappropriate a separate submission will need to be made.
Within six weeks of receipt the Department will formally accept proposals for changes to the Field Development Programme or indicate where it sees a divergence between the Licensee's plans and the Department's objectives. Any issues will be resolved following the procedure set out in these Guidance Notes.
It is anticipated that the Field Report will be produced annually in the first instance and address one year of operations, ideally coinciding with the Licensees own review process. The first report should be submitted about fourteen months after production start -up and cover the first year of production. For simple, or well -understood mature fields, it is intended that a reduced frequency of reporting can be agreed with the Department's field team.
For the guidance of Operators there is a check list attached which identifies the general requirements, but Operators are encouraged to agree an alternative form of report if this would be more appropriate to the individual field. Internal or partner documentation which satisfies or exceeds these requirements will also be acceptable. The Field Report is not intended as a detailed data source or account of activities carried out during the reporting period but should be used to identify departures from the expected performance and planned development.
Check -list for the contents of a field report
A specific contact in the Operator's organisation for enquiries relating to the report should be given.
1. Introduction
A brief review of the field operations and performance, with divergence from the Field Development Programme noted and discussed in more detail in later sections. Any changes in licence equity over the reporting period should be noted.
2. Field description
2.1 Hydrocarbons initially in place and recoverable reserves
Changes in estimates of hydrocarbons initially in place and reserves should be identified by reference to the Field Development Programme base case and to the case in the previous Field Report.
2.2 Well status and operations
A table summarising changes in well status (e.g. producer/injector, suspended/abandoned, perforated intervals, reservoir identifier, lift provision) should be included and should note any well operations carried out during the reporting period (e.g. drilling, workover, data gathering, perforating, stimulation).
2.3 Geology
Where drilling, seismic re-processing or other work has had a significant impact on the reservoir model a summary of the results should be provided together with a map in subsea depth giving the current interpretation of the top structure and showing well locations and fluid contacts (by reservoir if appropriate).
2.4 Field facilities and infrastructure
A brief report on the performance of the field production facilities highlighting features that have impeded operations and also valuable improvements. A forecast of the changes planned for the facilities, and where appropriate the related infrastructure, should be provided in Section 3.5 (see below).
3. Development and management plan
3.1 Field management
Changes in development strategy should be reviewed. Important reservoir monitoring results, reservoir monitoring limitations and specific production difficulties should be summarised. Where appropriate, plots of reservoir pressure and voidage replacement should be provided. Plans for reservoir monitoring in the coming year should be briefly discussed.
3.2 Studies
Results and relevance of geoscience, reservoir or facilities / pipeline engineering studies completed during the reporting period should be summarised. Plans and timescale for ongoing and future studies should be discussed.
3.3 Improved Oil Recovery (IOR)
Where improved recovery has not been addressed in the Field Development Programme or in previous reports, the potential should be reviewed, and the results of any studies or operations discussed.
3.4 Forecasting
A comparison between the current forecast and the Field Development Programme production and injection profiles (or those agreed revisions made in earlier Field Reports) should be provided, together with the current estimate of the Cessation - of-Production date.
3.5 Proposed changes to the Field Development Programme
This section provides the means for formally proposing revisions to the development and management plan set out in section 3 of the approved Field Development Programme. Proposed changes to explicit or implicit commitments or to conditions in the approval should be set out clearly as should plans to extend the development beyond the Development Area. The need to include other deviations should be discussed with the Oil and Gas Directorate's team manager.
Where appropriate a summary of longer term development opportunities within or around the field, including potential for recovering third party hydrocarbons, should be provided. Progress in developing opportunities already identified should also be reviewed.
Where changes in the facilities and infrastructure are planned the proposed modifications should be summarised, together with estimates of OPEX and CAPEX. Where an incremental project is planned the corresponding incremental production should be identified.
Where facility modifications on a host platform are planned for a satellite development, the proposed changes should be addressed in a Report for the host field and only a cross reference provided in the Report for the satellite field.
Available topsides or pipeline capacity for any potential future tie -in developments and any associated limiting factors should be described.
3.6 Field operating costs
CAPEX and OPEX profiles should be provided for the previous two year period, together with a three year projection of predicted expenditure; categorised as follows:
- New wells
- Workovers, side - tracks etc.
- Facilities routine maintenance
- Facilities upgrades/de-bottlenecks
- Major facilities modifications for third - parties etc.
Any large variations from the previous Field Report should be explained.
3.7 Preparation for Cessation - of-Production
Preparation for Cessation Of Production (COP) should be included commencing from about five years prior to the Licensee's anticipated date for COP. The contents of this section shall be similar to the information required for the stand-alone COP document as defined in Appendix 7.
The current estimate of Cessation-of-Production date should be provided, together with a discussion of any factors that would advance or postpone the economic limit so that the Department can form a view as to the main sensitivities and uncertainties involved.
Where a regular review of remaining outstanding development opportunities has been provided within the Field Report it can be expected that the COP will be agreed quickly with only minimal documentation required for the formal Cessation of Production document (see Appendix 7).
The amount of detail required in the Cessation-of-Production (COP) Document will depend on whether options to extend field life have been appropriately covered in previous Field Reports (see Appendix 6). If such options have already been discussed, the COP document can be very short, acting as a "close -out" of a process begun with earlier Field Reports.
The document should provide:
Executive summary
A management summary of what is in the body of the document. If the Operator has difficulty in composing the body of the text it may be sensible to discuss the contents of the Executive Summary with the Department before proceeding further.
Field economic limit criteria
This section should include a detailed analysis of:
Field life extension - options investigated
Outline of concepts and scope/timing of possible incremental activity investigated together with potential economics. Annual data for production, capital and operating costs should be provided for all projects, with summary economic indicators (Net Present Value and Internal Rate of Return) on a pre tax basis.
Examples could be:
It is important to record for potential future Operators why opportunities were not viewed as economic to pursue.
Final field status including third party -production processed/transported
A summary of the field surface layout in terms of platforms, wells, subsea wells and manifolds, intra - field flow lines, topside facilities, and transportation of products, e.g. pipelines and/or offshore loading.
Production and injection profiles together with projections through to economic limit and approximately 2 years beyond.
Brief details of any third party production that is processed and transported via the current facilities. This discussion should consider the impact of removal/alteration of platforms and subsea manifolds and the future handling of satellite and/or third party production.
Details of any remaining licence obligations.
The document should also contain appropriate reservoir maps indicating the estimated location and distribution of remaining technically recoverable oil/gas that will be undrained at the time of Cessation of Production. In addition some conception of likely changes in such distributions over time should be given for completeness of the record.
Additional developments status including third party
A summary of all nearby fields which can potentially be developed from the existing facilities and infrastructure should be listed. This should also include all third parties fields.
The following information will assist in making an assessment on the viability or otherwise of potential additional development.
Conceptual decommissioning plans
The decommissioning of offshore installations and pipelines are the subject of the Petroleum Act 1998. The Act provides the Secretary of State with powers to require those parties with a decommissioning liability for offshore oil and gas facilities to submit costed decommissioning programmes for his approval. This process is administered by the Department's Offshore Decommissioning Unit in Atholl House, Aberdeen. They should be contacted separately to discuss the necessary arrangements.
Such approval is separate from approval of the COP document. It will be important, however, to include in the COP document an indication of decommissioning plans. This should provide a general outline of the sequence of events which will take place from production cessation until complete decommissioning of wells, facilities and pipelines and include an estimate of the timetable and cost of such operations. It will be important to clarify in the COP document that all reasonable steps will be taken during the decommissioning stage to facilitate decommissioning, whether immediately or at some time in the future, and to ensure that any requirements related to decommissioning (including environmental considerations) will not be prejudiced. This is especially important when there is a considerable time delay between COP and actual decommissioning, e.g. a tariffing phase of operations involving the whole or part of the field facilities and pipelines.
Purpose of these guidelines
These guidelines are provided to aid companies who wish to become production Operators of oil or gas fields on the UKCS. In particular the guidelines are designed to help companies understand the information that the Department will require to consider an operatorship application.
The guidelines are applicable for the following range of operatorship transactions: