4 A Look Ahead

FUTURE UKCS DEVELOPMENTS/ACTIVITY

4.1 Demand for gas has risen in the last year and is expected to continue to rise with the growth in gas-fired power generation and access to EU gas markets via the Interconnector. Start-up of the Vesterled pipeline, with connection from the Heimdal field into the Frigg Norway pipeline, is planned for late 2001 and will see the first Norwegian grid gas supplied to the UK gas market.

4.2 The Leadon and Skene developments are expected to be brought into production in late 2001 or early 2002. This area is likely to see a range of strategic gas management schemes being devised for using associated gas effectively and enhancing the recovery of liquids.

4.3 Start up of the Central Graben Area High Pressure High Temperature gas condensate fields Elgin and Franklin and the restart at Shearwater will feed gas at up to 23 million cubic metres a day through the new SEAL line to Bacton.

4.4 With the development of the Jade field in 2000, further satellite developments in quadrant 30 are expected in the coming year.

4.5 Further activity in Outer Moray Firth and West of Shetland is anticipated over the next few years. The Clair project is one such example. With several billion barrels of oil, Clair is the largest known undeveloped hydrocarbon resource on the UKCS. Clair was discovered in the 1970s, but the complex reservoir geology has presented a major challenge in bringing forward development.

4.6 Designed to reduce the level of gas flared at more than 55 offshore fields, the pilot emissions trading scheme (mentioned in Chapter 1), which began operating in 2001, will continue to develop.

DRILLING INTENTIONS

4.7 In early 2001, the DTI conducted a survey of operators’ intentions to drill offshore exploration and appraisal wells. The survey covered the years up to 2003. Operators were asked to assess each well as certain, probable or unlikely to be drilled. The survey showed that, after allowing for probabilities, operators expect to drill some 47 E&A wells in 2001 and 39 in 2002 - see Chart 4.1 and Table 4.1.

Chart 4.1 E&A Drilling: Comparison of recent surveys with wells drilled

Table 4.1 Intentions to drill E&A wells: from DTI 2001 Survey

Note: The fall in intentions for 2003 reflects operators’ natural uncertainty about drilling so far in the future.

4.8 Total expectations are encouraging, showing increased intentions over the two previous surveys with 113 wells for the period 2001-03 against 92 for 2000-02. West of Shetland expectations show a fall on the 2000 figures, but increases are expected in the Southern Basin and the North & Central North Sea areas.

INVESTMENT INTENTIONS

4.9 For many years, DTI has conducted an annual survey of operators’ intentions to invest in oil and gas production on the UKCS. It has proved to be of considerable value to the Government and industry. For the 2000 survey, DTI agreed to ask for capital expenditure under the categories requested in the recently introduced UKOOA Field Database Survey, since PILOT had requested DTI and UKOOA to minimise the burden on companies caused by differing surveys.

4.10 The survey intentions up to 2005 are illustrated with results from previous surveys in Chart 4.2 and Table 4.2, under the categories (to which incremental projects have also been allocated):

	Sanctioned: fields in production or under development, including sanctioned incremental investment.
	Probable fields: potentially commercial and expected to move forward within 4-5 years.
	Possible fields: currently non-commercial, requiring new or innovative technology to move forward to sanction.

Chart 4.2 Intentions and recent investment

4.11 Intended expenditure declines sharply after the initial years of the survey. This has occurred in all previous surveys, since intentions do not include allowances for new discoveries, and are given only where sufficient knowledge exists for reasonable estimates to be made.

4.12 The survey results are encouraging, giving total intended expenditure (which does not include expenditure on exploration, appraisal or decommissioning) as £3.0 billion for 2000, rising strongly to £4.0 billion for 2001. Comparison with previous DTI surveys show a considerable increase in optimism compared with the 1999 survey, with total intentions in the future five years some 30% higher.

4.13 The investment intentions of £1.0 billion for 2005 are the first rise for some time seen in intentions for the last year of the survey period. The previous decline may have indicated a decline in future investment, but was also expected due to cost reduction initiatives and other factors, such as shorter planning horizons, shorter lead times, increased use of FPSOs and phased developments.

4.14 The survey now asks for the intentions to be split only between development drilling and ‘other capex’. This is the first time for some years that the percentage of expenditure due to development wells has fallen.

FURTHER LICENSING ROUNDS

4.15 The Government’s policy is to have a regular programme of licensing. It is hoped that a 20th Round, covering mature basins in the North Sea, will be launched by the end of 2001. Thereafter, it is intended that licensing rounds will be held annually as urged by the industry through PILOT.

4.16 A similar, annual licensing programme is also envisaged for landward areas. A 10th Round of landward licensing should also be held during 2001, inviting applications for unlicensed acreage within Great Britain.

The Viking B gas platform
Courtesy of Conoco (U.K.) Limited

4.17 Production of oil is expected to remain around current levels for the early part of the forecast period and decline later in this period (as shown above). These projections are presented as a range of possible outcomes. It is important to note that the pace and timing of the decline in production is dependent on a number of different factors, including the level of investment, the success of further exploration and the use of secondary recovery techniques on mature fields.

4.18 The projection for gas production relates to UKCS production available for sale. Gas production is expected to reach a peak at some point within the forecast period, most likely between 2002 and 2004. As with oil, the timing of the peak remains uncertain and is subject to a range of factors, including investment decisions and success in exploration.

RESERVES

Estimation of Reserves

4.19 Except where indicated otherwise, "reserves" are defined as initially recoverable reserves, also known as ultimately recoverable reserves. Over six weeks from January 2001, each UKCS field, each potential development and past discovery was reviewed by DTI with the operator, a total of 624 separate fields or drilled prospects offshore and onshore. The estimates for Undiscovered Reserves were reviewed separately.

4.20 For Discovered Recoverable Reserves the method is to sum the reserves for established fields plus those for which development is planned, and then subtract the cumulative production from the proven reserves to obtain the remaining discovered reserves as shown in the tables. From the component ranges for each row in the table the reserves are thus estimates at between the proven and maximum values listed. The likelihood that the true figure is outside this range is much smaller than for an individual field’s range of probability. Potential Additional Reserves in fields and drilled prospects for which there are no current plans for development are listed in a separate table. The oil table is presented in mass units (tonnes) to facilitate comparison with other energy resources and the incorporation of natural gas liquids. However, remaining oil reserves are also shown as volumes (i.e. million barrels).

OIL RESERVES

Initial Reserves

4.21 Oil reserves include both oil and the liquids and liquefied products obtained from gas fields, gas-condensate fields and from the associated gas in oil fields. Approximate proportions of these liquid condensates and NGLs in the initially recoverable reserves are 6% gas condensate liquids and 4% as NGLs. Initial reserves in decommissioned fields are now shown separately in the table.

Chart 4.3 Discovered Recoverable Reserves - Oil

Chart 4.4 Discovered Recoverable Reserves - Gas

4.22 New oil field developments have been included and reserves in established fields have been revised due to geological, reservoir engineering and economic re-assessments. Proven initially recoverable reserves have increased by 90 million tonnes. Reserves at the proven plus probable level are slightly higher this year at 3,580 million tonnes. Possible reserves have decreased due to reduced uncertainties in some established fields plus exploration and appraisal levels in 2000 not compensating for shifts in status of some fields and prospects between possible reserves and potential additional reserves.

Remaining Reserves

4.23 When cumulative oil production to the end of 2000 of 2,570 million tonnes is subtracted, remaining proven reserves stand at 630 million, which is 35 million tonnes less than at the end of 1999. Remaining proven plus probable oil reserves stand at 1,010 million tonnes compared with 1,120 million tonnes last year (production in 2000 was 126 million tonnes). The maximum possible remaining reserves combining all categories stand at 1,490 million tonnes. Oil reserves in all approved fields under first time development at 31 December 2000 are shown in Table 4.3.

Notes

* The terms ‘proven’, ‘probable’ and ‘possible’ are applied on a field by field basis and are given the following meanings in this context:

Proven - those reserves which on the available evidence are virtually certain to be technically and economically producible (i.e. having a better than 90 per cent chance of being produced).

Probable - those reserves which are not yet proven but which are estimated to have a better than 50 per cent chance of being technically and economically producible. Possible - those reserves which at present cannot be regarded as ‘probable’ but are estimated to have a significant but less than 50 per cent chance of being technically and economically producible.

** Maximum - the sum of the proven, probable and possible reserves.

(1) Includes onshore and offshore discoveries. All figures include condensates, gas liquids and liquefied products

(2) With the exception of the production figures, entries are rounded to the nearest five million tonnes. As a result, the sum of the constituent parts may not equal the totals.

(3) The initially recoverable reserves for fields in production or under development include 45 (65) proven, 40 (50) probable and 20 (25) possible million tonnes oil reserves in fields under first development.

GAS RESERVES

4.24 These are reserves expected to be available for sale from dry gas fields, gas condensate fields, oil fields with associated gas and a small amount from coalbed methane projects. Gas condensate fields contribute 22% of the total initially recoverable gas reserves (at proven plus probable level) and associated gas from oilfields contributes 15% -both unchanged from last year. The gas reserves in fields under first development at the end of 2000 are shown below in Table 4.4. Initial reserves in decommissioned fields are now shown separately.

Notes

* The terms ‘ proven’, ‘probable’, ‘possible’ and ‘maximum’ have the meanings defined in Table 4.3 with the associated comment. 1. Excludes flared gas and gas consumed in production operations.

2. Includes onshore and offshore discoveries.

3. Includes 50 (60) proven, 45 (45) probable and 30 (30) possible billion cubic metres gas reserves in fields under first development.

4. Except for the production figures which are rounded to the nearest bcm, all entries are rounded to the nearest 5 bcm. As a result, the sum of the constituent parts may not equal the totals.

Initial Reserves

4.25 Proven gas reserves increased by 85 billion cubic metres (bcm) to 2,255 bcm. At the proven plus probable level the initially recoverable reserves have increased by 45 bcm. Possible reserves decreased as reserves were confirmed.

Initial Dry Gas Reserves

4.26 The initially recoverable proven reserves of Southern Basin dry gas fields in production or under development have increased over the year with proved volumes from new approved field developments. However, probable and possible reserves decreased through revisions. Dry gas reserves in production or under development in areas outside the Southern Basin have increased at all probability levels. The dry gas reserves in fields under appraisal show opposing trends by area, making the subtotals change little.

Initial Gas Reserves in Gas Condensate Fields and Oil Fields

4.27 The initially recoverable gas reserves in gas condensate fields under production or development have increased at the proven level due to confirmation of former probable reserves and as a result of approving new fields. Reserves in fields under appraisal have increased slightly. Such fields are essentially gas fields but there are substantial levels of liquid condensates which contribute to oil reserves.

4.28 Reviews of a number of oil fields in production have resulted in an upward movement in the estimates of their associated gas reserves at most levels. This reverses the downward movement seen last year. Several UKCS fields have both oil and gas condensate reservoirs and gas reserves from these are split appropriately.

Remaining Reserves

4.29 After deducting the cumulative gas production to end 2000, remaining proven reserves stand at 735 bcm, which is slightly less than last year. The remaining recoverable proven plus probable gas reserves have decreased by 70 bcm (production in 2000 was 108 bcm). Remaining proven plus probable dry gas reserves (not dependent on oil handling) are now 510 bcm (560 bcm) compared to the remaining condensate plus associated gas reserves of 670 bcm (685 bcm).

4.30 The maximum possible remaining (discovered) reserves of all categories of gas now stand at 1,630 bcm.

POTENTIAL ADDITIONAL RESERVES

4.31 Potential Additional Reserves exist in discoveries which do not meet the criteria for inclusion as possible reserves, as defined in Table 4.3. The current estimates as at end 2000 are shown in Table 4.5.

Note:

(1) Totals have been rounded to 5 million tonnes of oil or 5 bcm of gas (2) Figures in brackets are as at end 1999

4.32 The ranges of reserves in this category may vary from to year. As additional data become available, some reserves may be transferred from this category to the Discovered Recoverable category. Similarly reserves may be transferred to this category from the Discovered Recoverable category.

4.33 The figures shown in Table 4.5 take account of all discoveries made up to the end of 2000 which do not justify inclusion in the Discovered Recoverable category.

4.34 The gas reserves are down from last year as some fields are now under consideration for possible development. Therefore these reserves are transferred to the Discovered Recoverable category. Oil reserves held have increased. The increase in oil reserves is due partly to an increase in evaluation activity identifying new potential from previous drilling. Work undertaken within PILOT and DTI’s Fallow Blocks and Discoveries initiatives have contributed to greater evaluation activity in 2000. Also, some fields are no longer under consideration for possible development. Therefore these reserves were transferred from the Discovered Recoverable category.

4.35 Starting this year a UKCS sector analysis is presented (Chart 4.5) with pie charts depicting the levels of oil and gas reserves categorised as discovered recoverable possible and potential additional in relation to the remaining recoverable proven plus probable reserves.

UNDISCOVERED RECOVERABLE RESERVES

4.36 The methodology for calculating this category of reserves remains unchanged from previous years. In areas where detailed mapping has been carried out, prospects are analysed by standard statistical techniques to obtain estimates of reserves within each basin.

4.37 The database has been modified to take account of the new drilling and mapping that took place in 2000. The changes to the Southern North Sea and West of Shetland areas are largely the result of 3D seismic mapping.

4.38 The Undiscovered Recoverable Oil Reserves are estimated to lie in the range 225 - 2,300 million tonnes. The Undiscovered Recoverable Gas Reserves are estimated to lie in the range 325 - 1,440 bcm.

4.39 The limits of these ranges should not be regarded as minima or maxima. Estimates of undiscovered reserves must be treated with caution. They provide only a broad indication of the ultimate remaining potential. No estimate is made of unconventional gas resources.

Notes

(1) Includes onshore and offshore assessments.

(2) Totals for each offshore area have been rounded to the nearest 10 million tonnes of oil or to 5 billion cubic metres of gas. Totals for each onshore area have been rounded to the nearest 5 million tonnes of oil or 1 billion cubic metres of gas.

(3) No account has been taken of projected fuel usage and flaring. (4)Gas associated with oil and condensate.

(5) Every offshore prospect included in the detailed analysis on which this table is based is estimated to contain reserves of at least 2 million tonnes of oil (15 million barrels) or 2.8 billion cubic metres of gas (0.1 trillion cubic feet).

(6) The lower end of the range is zero as a consequence of rounding.

* Areas where detailed studies have been carried out.

4.40 With cumulative production to date of 2,570 million tonnes of oil and 1,518 bcm of gas, the total remaining reserves (including the undiscovered) are estimated to lie in the range of some 940 - 4,320 million tonnes of oil and 1,125 - 3,300 bcm of gas. The approaches for assessing probabilities are necessarily different for each of the three categories of reserves listed in Table 4.7. Adding the ends of the ranges together, as done here, indicates the broad scope for the initial reserves. In particular, the upper limits of the ranges for the remaining reserves of oil and gas are only indicative of the remaining potential.

DECOMMISSIONING

4.41 Only a small number of offshore installations and pipelines have been decommissioned (see Appendix 15). However, as the UKCS continues to mature as a province this number will increase and the Government can expect a growing number of decommissioning proposals coming forward in future years.

4.42 As at spring 2001, decommissioning proposals for the Frigg field facilities are under consideration. Frigg is a median line field and the operator’s proposals are being considered jointly with the Norwegian Government.

4.43 The work of The Early Decommissioning Synergy (TEDS) Group, comprising those operators who are likely to be faced with major decommissioning projects in the near future, continued during 2000 with the aim of ensuring a co-ordinated approach to decommissioning whenever possible. Similarly, the PILOT-initiated North Sea Decommissioning Group (NSDG) is continuing to address some of the wider issues surrounding decommissioning. These include the potential for industry collaboration and encouraging the development of new technology; the aim is to identify cost savings of £2 billion over the next decade.

PROPOSED FURTHER CHANGES TO THE "BROWN BOOK"

Digital Version of "Brown Book"

4.44 As has been the case for the last two years, a digital version is available. This is a linked compilation of HTML (Hyper Text Mark-up Language) pages, tabulated data in MS Excel version 4 worksheets and comma delimited files (CSV) and graphic files (GIF and JPEG). The compilation can be accessed using any standard web browser, but Internet Explorer is recommended.

4.45 For further information on obtaining a copy of the Digital Brown Book please contact:

Data by Design Ltd,
Pinwydden,
Llanrwst Road,
Bryn-y-maen,
Colwyn Bay,
North Wales LL28 5EN.
Tel: +44 (0)1492 531020
Fax: +44 (0)1492 531016
E-mail: sga@databydesign.co.uk
Web: http://www.databydesign.co.uk

Oil and Gas Directorate Website

4.46 As occurred last year, shortly after publication, DTI intends to put the whole of the "Brown Book" on the Oil and Gas Directorate website which can be accessed at: http://www.og.dti.gov.uk. In addition, last year’s edition will remain on the OG website.

Future Changes

4.47 In line with the Government’s objective of increasing the level of its business conducted electronically, DTI intends to put all of the Appendices on the Oil and Gas Directorate Website, and have them dynamically updated. This means that, after this edition, it is likely that future printed editions of the "Brown Book" will not contain the actual Appendices, but will refer those wishing to access this information to the OG Website.

Tankers delivering crude to the Humber refinery via the Tetney Monobouy
Courtesy of Conoco (U.K.) Limited

Back | Title | Table of Contents
Chapter 1 | Chapter 2 | Chapter 3 | Chapter 4
Appendix 1 | Appendix 2 | Appendix 3 | Appendix 4 | Appendix 5 | Appendix 6 | Appendix 7 | Appendix 8 | Appendix 9
Appendix 10 | Appendix 11 | Appendix 12 | Appendix 13 | Appendix 14 | Appendix 15 | Appendix 16 | Appendix 17
Index Map | Plate 1 | Plate 2W | Plate 2E | Plate 3W | Plate 3E | Plate 4W | Plate 4E | Plate 5W | Plate 5E | Plate 6
Plate 7 | Plate 8W | Plate 8E | Plate 9W | Plate 9E | Plate 10W | Plate 10E | Plate 11 | Plate 12 | Legend
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