2 Main Events of 1999 and Early 2000

TRENDS AND FIELD HIGHLIGHTS

2.1 As evidence of the North Sea’s productivity, 1999 proved to be another record year for oil and gas production. However, approval of new development activity was limited, largely due to a combination of global factors, most significant of which was the lack of investment confidence surrounding uncertain oil prices.

2.2 Sanctioned development drilling and construction continued throughout 1999 and the trend in oil developments towards small sub-sea tie-backs to existing infrastructure is expected to continue. In the Southern North Sea, satellite gas accumulations are increasingly being developed utilising very small and simple unmanned surface facilities.

2.3 There was further development of the Outer Moray Firth with the approval of the Blake field as a sub-sea satellite to the Ross FPSO. The field is expected to start production in 2001. Cost sharing will help extend the economic life of the Ross field and will lead to a substantial increase in recoverable reserves. Blake has been a good example of co-operation between licence groups leading to the best use of infrastructure to achieve an overall optimum development. Further appraisal of this area is planned for 2000, which is expected to lead to development of the more gas prone part of the basin.

2.4 A notable highlight for 1999 was BP Amoco’s world record extended reach well in Wytch Farm. This established records for both the longest production well (measured depth of 11,278 metres) and also the greatest horizontal distance (10,728 metre step out).

OIL PRODUCTION

2.5 A total of 137.1 million tonnes of oil was produced in 1999.

Chart 2.1 shows details of the oil production by field. For more detailed information, see Appendix 9.

2.6 Production commenced at nine offshore oil/condensate fields during 1999: Egret (Jan), Pierce, Janice and Renee (Feb), Ross (Apr), Rubie (May), Gannet G (June), Buckland (Aug) and Orion (Sep). One onshore oil field came onstream: Newton-on-Trent (Jan).

OIL DISPOSAL

2.7 During 1999, 48.2 million tonnes of UKCS oil (including natural gas liquids) was delivered to UK refineries, representing 35.3% of total deliveries. Throughout the same period, 3.2 million tonnes was delivered to other UK sites such as petrochemical plants and storage depots. Exports of UKCS oil (including NGLs) in 1999 amounted to 85.1 million tonnes, compared to 35.2 million tonnes of imports. Exports were almost entirely to the markets of other member countries of the European Union or of the International Energy Agency. The majority of the remainder went to traditional markets. Table 2.1 shows the sources of UKCS crude oil received at UK terminals.

Table 2.1 - Oil Terminals Receiving UKCS Crude Oil in 1999

GAS PRODUCTION AND DISPOSAL

2.8 In 1999, gas produced from the UKCS increased to 105.0 billion cubic metres (3.71 trillion cubic feet). This includes gas used by operators for drilling, production and pumping operations. Production commenced at nine new offshore gas fields: Corvette (Jan), Bell, Dalton and Millom (Aug), Ketch, Sinope and Vampire (Sept), Neptune and Mercury (Dec), and at one new onshore gas field: Saltfleetby (Dec). Gas production data can be found at Appendix 10 (note: Neptune and Mercury are not included there as data for these fields was not available at the time of print). Additional supplies of gas associated with crude oil extraction also started coming ashore in 1999 from nine new oil fields. These additional fields have contributed to increased production of gas from the main pipeline systems seen during 1999.

2.9 After taking into account the 7.8 billion cubic metres of gas landed in the Netherlands from the UK share of the Markham transboundary field and from the Windermere field, of gas exported to the Irish Republic from Scotland, and gas exported to Belgium via the Interconnector from Bacton, total sales of UKCS gas to UK gas suppliers amounted to 90.9 billion cubic metres (3.21 trillion cubic feet) in 1999. (5.2 per cent higher than in 1998). In addition 1.1 billion cubic metres (0.04 trillion cubic feet) of gas were imported from the Norwegian Lille Frigg, East Frigg and Frøy fields and from the Bacton-Zeebrugge Interconnector. Imports made up 1.3 per cent of total gas supplies in the UK in 1999, compared to 1.0 per cent in 1998.

2.10 Details of the top ten gas producing fields in 1999 can be seen at Table 2.2. Chart 2.2 shows levels of gas production.

2.11 Table 2.3 shows detail of the sources of UKCS natural gas received at UK gas terminals. Terminals operating at Bacton accounted for 19 per cent of gas supplied into the UK in 1999.

(1) Excludes 0.8 billion cubic metres exported from the Markham and Windermere fields and 0.3 billion cubic metres produced at onshore fields.

PRODUCTION AND DISPOSAL OF NATURAL GAS LIQUIDS

2.12 NGLs continued to be brought ashore with crude oil supplies via major terminals and also through the Far-north Liquids and Associated Gas System (FLAGS), Fulmar, Frigg and Scottish Area Gas Evacuation (SAGE) pipeline systems to St Fergus. Small amounts of NGLs are also brought ashore via the Central Area Transmission System (CATS) terminal, and through the Norpipe system, to Teesside.

2.13 Production of NGLs in 1999 was 8.8 million tonnes, including 2.0 million tonnes of condensates. The largest quantities of NGLs were piped to Mossmorran and Kerse of Kinneil for fractionation.

OFFSHORE PIPELINES

2.14 During 1999 14 submarine pipeline works authorisations for the construction and use of 91 additional submarine pipelines were issued. As in previous years, the majority of these were infield flowlines associated with field development. Pipelines brought into use for the first time during 1999 included the Shearwater to Bacton trunk line and 25 interfield pipelines. Details of operating oil and gas pipelines are in Appendix 13.

2.15 The current trend is for the utilisation of existing infrastructure and further development of established fields. Many pipelines authorised in 1999 constitute tying back new wells and sub-sea manifolds to existing facilities, some of which are located in deep water. There is continued interest in Floating Production Storage and Offtake vessels (FPSOs) which are capable of carrying out short term well tests and enable crude oil to be saved rather than flared.

OFFSHORE EXPLORATION AND APPRAISAL

2.16 Five significant discoveries were announced in 1999 (listed in Appendix 5), representing a 30% success rate.

2.17 Overall, though, a number of factors, particularly uncertainty remaining after the fall in world oil prices, led to disappointing levels of exploration drilling. Only 16 exploration wells were started, compared with 47 in 1998. This is the lowest since 1965, which was the second year of drilling on the UKCS.

The number of new appraisal wells (20, compared with 33 in 1998) is the lowest figure since 1971. There were regional variations, though: the Moray Firth held up well and a well was drilled West of Shetland in a record water depth for NW Europe.

Northern North Sea (including East Shetland Platform)

2.18 During 1999, drilling in the Northern North Sea fell to a single exploration well and four appraisal wells. This is a considerable drop on 1998 when 10 exploration wells and 17 appraisal wells were drilled. But the exploration well encountered hydrocarbons, which is encouraging.

West of Shetland

2.19 Exploration drilling was at a low level with only two new wells. Interestingly, one well was located in a record water depth of 1,621 metres.

Moray Firth

2.20 The Moray Firth showed an increase in activity on the previous year. The five new exploration wells equalled the previous year’s total. Three of them fulfilled 14th and 18th Round drilling commitments. One was drilled on a Fallow Block. The number of appraisal wells jumped from two in 1998 to six in 1999. Most of them focused on the Lower Cretaceous sandstone fairway.

Central North Sea

2.21 Three significant discoveries were announced: one on a 1st Round licence and two which started drilling in 1998 under 11th and 12th Round drilling commitments. 

2.22 Five wells (including one sidetrack) were started in 1999, compared with twelve in the previous year. All but one of the wells fulfilled outstanding commitments. Appraisal drilling fell from twelve wells started in 1998 to five in 1999.

Chart 2.3 - Sedimentary Basins

Southern North Sea

2.23 The Vixen field, already approved for development, is the result of one of the three exploration wells that were started during 1999, all in the southern part of the Southern Basin where the Permian-age Rotliegendes sandstone is the main target. One of the wells was a 17th Round obligation.

2.24 Five appraisal wells were started, with some activity in the Carboniferous area. Two sidetracks made for geological reasons are included in the total figures.

English Channel

2.25 One well was drilled from an onshore drilling site to an offshore target - the first Channel exploration well since 1996.

ONSHORE EXPLORATION AND APPRAISAL

2.26 The number of onshore exploration wells was up, with six drilled in 1999, from five the previous year. Two of them made discoveries, one oil and one oil and gas. One of the 1999 wells was drilled to an offshore target in the English Channel (as mentioned above). Appraisal drilling was down, with only two wells started in 1999, compared with nine in 1998.

DEVELOPMENT DRILLING

Offshore areas

2.27 Drilling of offshore development wells was not far below the rate in previous years. A total of 225 wells (including 90 sidetracks) were drilled, compared with 281 in 1998 and 257 in 1997. This brings the total number of Development wells drilled on the UKCS to over 4000 since developments started in 1966. There is a regional breakdown at Appendix 4.

Onshore

2.28 Eleven development wells were drilled, five of which were side-tracks.

LICENSING

2.29 No seaward licensing rounds occurred during the period covered by this report.

2.30 A licence award over Block 98/11 was made ‘out of round’ in November 1999 to a consortium of companies led by BP Amoco (to test a possible extension to the Wytch Farm field).

2.31 The 9th Round of Landward Petroleum Licensing was announced in January 2000 in the Official Journal of the European Communities. The Round includes all unlicensed acreage in Great Britain above the Mean High Water Mark. The closing date for applications was 5 May 2000 and it is hoped that licence awards will be made soon.

NORTHERN IRELAND

2.32 Under the Petroleum (Production) Act (Northern Ireland) 1964, landward petroleum licensing in Northern Ireland is the responsibility of the Department of Enterprise, Trade and Investment (Minerals and Petroleum Unit, Netherleigh, Massey Avenue, BELFAST BT4 2JP).

2.33 At the end of 1999 there were 9 landward petroleum licences covering an area of some 3150 sq km. The Department operates an open licensing policy and is prepared to consider applications at any time.

FIELD APPROVALS/DEVELOPMENT PLANS

2.34 Under the terms of petroleum production licences, development work and the production of petroleum may be carried out only with the consent of the Secretary of State for Trade and Industry, or under a development and production programme approved by the Secretary of State.

2.35 In 1999 a total of 23 plans were authorised: 14 oil/condensate and 9 gas. These are listed in Appendix 3.

HYDROCARBONS ADDITIONAL RECOVERY PROGRAMME (HARP)

2.36 The DTI’s expenditure in 1999/2000 on the Hydrocarbons Additional Recovery Programme (HARP) was £2.2 million. This programme aims to provide the DTI with the technical support which it requires to fulfil its regulatory function of ensuring maximum recovery of economic oil and gas from UK fields, with due regard to the environment, and to foster and sponsor innovative recovery techniques.

2.37 Dissemination events, including an improved oil recovery research dissemination seminar, a number of workshops and publishing of generic studies undertaken by AEA Technology and the Universities, were carried out during 1999/2000. Further studies and research on improved oil recovery topics were carried out through Joint Industry Projects. The new Joint Industry Projects this year included data mining to justify and enable the management of reservoir-scale geochemical controls on fluid flow and recovery in the North Sea, uncertainty estimation for reservoir flow incorporating strain distribution and geomechanical changes constrained to production data, simulation of multiphase flow in porous media from pore scale to the reservoir scale and gas and hydrates and deep water drilling.

CLASSIFICATION OF RESERVES

2.38 UKCS reserves may be classified under two main categories - ‘discovered’ and ‘undiscovered’ - together with an intermediate category, ‘potential additional reserves’, which comprises discoveries about which little is known or which fail to meet the technical and economic criteria for entry into the main ‘discovered’ reserves tables. For each of these categories there is a different level of confidence. The greatest certainty is assigned to the discovered reserves which are calculated on a field by field basis from both well and seismic data. Each field is assigned reserves in one or more of the "proven", "probable" and "possible" categories according to their chance of being both technically and economically producible. Less certainty can be assigned to the Potential Additional Reserves (PARs) which are primarily single well discoveries. The least certain are the estimates of undiscovered reserves which are made by a statistical assessment of the likely number and size of mapped but undrilled prospects.

2.39 In this section, except where indicated otherwise, "reserves" means initially recoverable reserves in oil or gas fields, also known as ultimately recoverable reserves. Continuing previous practice, no proven reserves are assigned to fields without approved development plans. In January each year the estimates of discovered reserves of oil and gas for every field, including those discoveries not yet fully appraised and approved for development, are reviewed with the respective operating company to establish the current reserves levels in the categories listed. Each of the discoveries assigned as PARs is also reviewed with the current operating company every year with regard to current status. The estimates of undiscovered reserves are reviewed by area with regard to the additional information that has accrued.

DISCOVERED RECOVERABLE OIL RESERVES

2.40 Table 2.4 gives the estimates of initially recoverable oil reserves in discoveries to date together with the figures from last year for comparison. 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. The overall totals are simply the sum of the individual field figures. Specifications for liquid condensates from gas condensate fields and natural gas liquids (NGLs) vary across the industry but approximate proportions of these hydrocarbon liquids in the total initially recoverable reserves are now 7% as gas condensate liquids and 4% as natural gas liquids. Oil reserves in all approved fields under first time development at 31 December 1999 are shown below Table 2.4 and are slightly lower than last year. The total initially recoverable proven reserves have increased by 115 million tonnes. However when cumulative production to the end of 1999 of 2,444 million tonnes is subtracted, remaining proven reserves stand at 665 million (20 million tonnes less than at the end of 1998).

Table 2.4 - Estimates of discovered recoverable reserves of oil on the UKCS (1) as at 31 December 1999 (figures in brackets are for end 1998)

* 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.

As in previous years the reserves of individual fields have been summed arithmetically.

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 the individual component ranges.

(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 65 (70) proven, 50 (55) probable and 25 (30) possible million tonnes oil reserves in fields under first development.

(4) Both the total initially recoverable proven reserves and the cumulative oil production include 50 (20) million tonnes of oil from fields that have ceased production.

2.41 Initially recoverable reserves at the proven plus probable level are slightly lower this year at 3,565 million tonnes. New fields have been included, and reserves have also grown in a number of established producing fields and fields under development, but there have been downward revisions due to geological, reservoir engineering and economic re-assessments. After deducting cumulative production, remaining proven plus probable oil reserves stand at 1,120 million tonnes compared with 1,265 million tonnes last year.

2.42 Possible reserves have increased slightly due to limited exploration in 1999 and by shift in status of certain fields previously held as only having potential additional reserves (PARs). When combined with the proven and probable reserves, the resulting maximum possible remaining discovered reserves stand at 1,665 million tonnes, down from 1,800 million tonnes in 1999.

2.43 The 30 million tonne increase in reserves initially present in fields that have now ceased production is due to the cessation of production from the Maureen field and its satellites during 1999.

DISCOVERED RECOVERABLE GAS RESERVES

2.44 Table 2.5 gives the quantities of gas expected to be available for sale from dry gas fields, gas condensate fields and oil fields with associated gas. Equivalent figures from last year are provided for comparison. Gas which has been or is expected to be flared or used offshore is not included.

Table 2.5 - Estimates of discovered recoverable reserves of gas ⁽¹⁾ on the UKCS ⁽²⁾ at 31 December 1999 (figures in brackets are for end 1998)

2.45 Gas condensate fields now contribute 22 % of the total initially recoverable gas reserves (up from 19% in 1999) and associated gas from oilfields contributes 15 % (17% in 1999). The gas reserves in fields under first development at the end of 1999 are now shown below Table 2.5.

2.46 Initially recoverable proven gas reserves increased by 105 billion cubic metres (bcm) to 2,170 bcm. After deducting cumulative production of 1,410 bcm, remaining proven reserves stand at 760 bcm which is almost the same as last year. At the proven plus probable level the initially recoverable reserves have increased by 20 bcm but the remaining recoverable gas reserves have decreased by 75 bcm. The maximum possible remaining (discovered) reserves of gas now stand at 1,755 bcm.

Dry Gas

2.47 The initially recoverable proven reserves of Southern Basin dry gas fields in production or under development have increased over the year by shift from former probable reserves as volumes are confirmed. Otherwise there is little change in dry gas reserves in the Southern Basin from last year. Dry gas reserves in production or under development in areas outside the Southern Basin have decreased slightly at the probable and possible levels. For both categories the dry gas reserves in fields under appraisal have changed only slightly.

Gas from Gas Condensate Fields

2.48 The initially recoverable condensate gas reserves have increased in nearly all probability categories as a result of reviews of fields in production, delineation of fields under development and discoveries during 1999. Some of the increase also comes from stricter definition of gas types, in particular in categorising gas in deeper gas condensate reservoirs below conventional oil reservoirs as condensate gas rather than associated gas.

2.49 Reviews of a number of oilfields already in production have resulted in a decrease in the estimates of their probable associated gas reserves. The stricter application of gas type definitions mentioned in the previous paragraph has also  reduced associated gas totals.

POTENTIAL ADDITIONAL RESERVES (PARS)

2.50 Potential Additional Reserves exist in discoveries which do not meet the criteria for inclusion as possible reserves, as defined in Table 2.4. The current estimates as at end 1999 are shown in Table 2.6.

2.51 The ranges of reserves in this category may vary from year 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.

2.52 The figures shown in Table 2.6 take account of all discoveries made up to the end of 1999 which do not justify inclusion in the Discovered Recoverable category.

2.53 The upsides for the oil and gas reserves ranges are up from last year by 35 million tonnes and 10 bcm respectively. This is due to an increase in the potential reserves for some fields. Also, some fields are no longer under consideration for possible development. Therefore these reserves were transferred from the Discovered Recoverable category. Most reserves discovered in 1999 were allocated directly to the Discovered Recoverable category.

UNDISCOVERED RECOVERABLE RESERVES

2.54 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.

2.55 Additional reserves are likely in these areas as no account can be taken of potential new plays and potential traps that may exist beyond the resolution of current seismic penetration.

2.56 The data-base has been modified to take account of new drilling and mapping. Due to the low level of exploration and appraisal drilling in 1999, only two areas have a change in reported range of reserves. New mapping projects in the Southern North Sea have resulted in a slight increase in the upper end of the gas range in that area. The West of Shetland area now includes the acreage designated during 1999 (former ‘White Zone’). The ranges for both oil and gas in the West of Shetland area are reduced due to a revision of the success rates there.

2.57 The Undiscovered Recoverable Oil Reserves are now estimated to lie in the range 250 - 2,600 million tonnes compared with last year’s range of 275 - 2,550 million tonnes. Recoverable Gas Reserves are now estimated to lie in the range 355 - 1,465 bcm compared with last year’s range of 440 - 1,595 bcm.

2.58 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.

2.59 A study by the Economic Advisory Group of the Oil and Gas Industry Task Force’s Vision Workgroup (described in Chapter 1), published as a supplementary paper to the Task Force’s September 1999 Report A Template for Change, provided an alternative, P50 estimate of UKCS yet-to-find reserves potential based on "play" analysis. The study noted that the majority of the yet-to-find potential of some 1,750 million tonnes of oil equivalent which it identified was expected to be in fields of less than 15 million tonnes of oil equivalent. Over two thirds of the potential reserves were expected to lie within 50 kilometres of existing infrastructure. The study identified the frontier basins of the Atlantic Margin as offering the greatest potential for major new reserves.