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KonKraft report 2
Production development on the Norwegian continental shelf
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Table of ContentsSummary and conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
1 . Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111.1 Background and mandate. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111.2 Context. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 121.3 Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131.4 Content of the report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14
2 . History of and business environment for production on the NCS . . . . . . . . . . . . 152.1 Chapter summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152.2 The NCS is a maturing hydrocarbon province. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152.3 Exploration on the NCS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182.4 Level of activity increasing despite rising costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212.5 A number of key differences exist between the UK and Norwegian business environments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
3. Improving oil and gas recovery from existing fields . . . . . . . . . . . . . . . . . . . . . . . . 243.1 Chapter summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 243.2 The average ultimate recovery factor on the NCS is high . . . . . . . . . . . . . . . . . . . . . 253.3 Contingent resources in existing fields are still considerable, but reserves and contingent resources are declining rapidly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
3.3.1 Ensuring that activity and investment levels remain high in maturing fields will be challenging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273.3.2 Maintaining the track record for applying new technology will be challenging 293.3.3 A debate exists on the contribution of EOR to growing reserves in existing fields 303.3.4 IO can contribute significantly to increasing production and reserves . . . . . . . . 32
3.4 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
4 . Continuing to encourage exploration activity in currently accessible areas . . . . 394.1 Chapter summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 394.2 A significant undiscovered resource potential remains in currently accessible areas 404.3 The authorities have taken steps to boost exploration activity . . . . . . . . . . . . . . . . . 41
4.3.1 Action by the authorities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 414.3.2 Impact of action by he authorities to date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 42
4.4 It is too early to say that high exploration activity is sustainable and will translate into significant production and investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 434.5 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45
5. Building a “small field” development mindset . . . . . . . . . . . . . . . . . . . . . . . . . . . . 465.1 Chapter summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 465.2 Most future discoveries are expected to be small . . . . . . . . . . . . . . . . . . . . . . . . . . . 475.3 E&P companies in Norway have historically tended not to explore for and develop small discoveries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 485.4 An opportunity still exists to add to yet-to-be-found resources by making development of small discoveries more attractive . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51
5.4.1 Some early signs of success have been seen, but progress is far from secure . . 525.4.2 Exploring for and developing small prospects which depend on existing infrastructure is a matter of urgency, especially in the North Sea . . . . . . . . . . . . . . . . 53
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5.4.3 The potential price for reducing the minimum volume required for economic development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53
5.5 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 56
6 . Opening new areas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 586.1 Chapter summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 586.2 Production and investment levels are predicted to decline in existing areas. . . . . . . 596.3 Opening new areas can have a significant impact on long-term production and investment levels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 596.4 Why a decision in 2010 to open new areas is urgent . . . . . . . . . . . . . . . . . . . . . . . . . 616.5 Maintaining a robust petroleum industry. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 626.6 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
7 . Industry is adapting to the sharp rise in activity . . . . . . . . . . . . . . . . . . . . . . . . . . 667.1 Chapter summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 667.2 Coping with change . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66
7.2.1 Declining performance for well delivery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 667.2.2 Shortage of qualified mobile drilling rigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 687.2.3 Production-related activities on some older platforms have been delayed by growing maintenance requirements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71
7.3 The impact of the transitional period . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 717.3.1 The impact of the high level of activity on production. . . . . . . . . . . . . . . . . . . . 717.3.2 Other possible impacts from the increased level of activity . . . . . . . . . . . . . . . 72
7.4 What would help the industry to cope better with changes? . . . . . . . . . . . . . . . . . . . 73
8 . Attract, retain and make best use of the necessary people and expertise . . . . . . . 748.1 Chapter summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 748.2 Shortage of qualified labour on the NCS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 748.3 The impact of demographic change. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 758.4 The influx of new players has generated competition over personnel . . . . . . . . . . . 768.5 Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
Appendix 1: The project team’s modelling tool and assumptions . . . . . . . . . . . . . . 79A1.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79A1.2 Input assumptions for scenario modelling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79A1.3 Scenario description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86A1.4 Results of the scenario modelling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86
Appendix 2: Project team’s engagement with stakeholders . . . . . . . . . . . . . . . . . . . 88
Appendix 3: NPD resource classification . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89
Appendix 4: Assumptions for estimating contingent resources and a comparison with the NPD estimates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90A 4.1 Contingent resources in existing fields. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90A.4.2 Contingent resources in discoveries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 91
Terms and definitions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93
References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95
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Summary and conclusions
Production on the NCS is maturing After almost 40 years of virtually uninterrupted growth, total hydrocarbon production on the Norwegian continental shelf (NCS) has reached its highest level ever, with a daily output of 4-4.5 million barrels of oil equivalent per day. It is expected to remain at this level for the next 7 years. After 2015 or thereabouts, however, total oil and gas produc-tion is forecast to start declining. Oil production is already falling. Gas output has been increasing, but this is not expected to continue offsetting the drop in liquid production beyond 2015 or thereabouts if no action is taken.
Only half the combined oil and gas resources predicted by the Norwegian Petroleum Directorate (NPD) will have been produced in 2015. Remaining recoverable resources, including those expected to be found by further exploration, are currently estimated to be 38-77 billion barrels of oil equivalent (boe). This estimate could be 25-65 billion boe in 2015. Only 40 per cent of the total expected remaining hydrocarbon resources remains to be discovered today, which explains the wide range in the estimates. This huge potential must be managed well to avoid a sharp decline in production and to support a healthy level of long-term investment.
The report on production development on the Norwegian continental shelf is published at a time when major changes are taking place both inside and outside the petroleum indus-try. Several factors make a review of what can be done to address the production decline particularly urgent. Although the current level of activity in the Norwegian petroleum sector is high, assessing the long-term perspectives for the industry is very important. In many cases, the period between the award of licences and the start of production can be 15 years or more. Decisions taken now may have important implications for levels of production and activity in the 2020s.
Overview of production development on the NCS
The largest hydrocarbon accumulations were discovered in the 1970s and 1980s. •Many smaller discoveries were made in the course of the 1990s. An exception is Ormen Lange, found in 1997 as the last big discovery on the NCS.
Development of these large fields required high levels of investment and expertise as •well as extensive use of new technology. These new technologies were subsequently applied worldwide.
The recovery factor for fields on the NCS is amongst the highest in the world. This •is largely a result of the extensive use of new technology. Over the past 10 years, however, the addition of resources to replace the oil and gas produced has declined sharply.
The large fields which accounted for the bulk of oil production from the NCS are •now getting older. More than 60 per cent of their expected recoverable reserves has been recovered, and their output is declining rapidly. The remaining oil in these fields is more technically difficult to recover and therefore more labour-intensive and expensive. Limited time is also available for applying new technology to improve recovery from these fields. Debate exists, for example, over the extent and pace of
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the contribution which enhanced oil recovery (EOR) methods can make on the NCS. In addition, more attention needs to be paid to research into and development of improved oil recovery (IOR) methods.
An increasing share of production on the NCS comes from small and medium-•sized fields. Most of these have been developed as subsea tiebacks to existing infrastructure rather than as stand-alone projects. The ultimate recovery factor for small and subsea fields is lower on average, and extending the production life of these fields in a cost-effective way will be challenging.
Economic development of small fields often depends on the presence of existing •infrastructure in the vicinity. Since many platforms are approaching retirement, the time window for achieving full exploration of the North Sea is rapidly closing.
Future developments in areas currently accessible for petroleum activities are •expected to be small. However, the sum of these could have a significant impact on the level of investment. Economic development of future small fields will be costly, and require simple and standardised solutions.
The biggest impact on future production and investment levels is expected to •come from exploration success. The remaining exploration potential on the NCS is estimated to be 10-36 billion boe. These yet-to-be-found volumes are expected to lie in areas both currently accessible for petroleum activity and not yet opened. It is thus possible that more oil and gas could be found on the NCS than has already been produced.
The Norwegian authorities have been very successful in encouraging exploration •activities in accessible areas. Backed by high oil prices, these incentives have attracted many new companies to the NCS and the number of exploration wells has increased.
The discovery rate has been rising over the past 40 years. Over the past decade, every •second exploration well has found oil or gas. However, the number of economic discoveries has declined. Only 1 in 3 discoveries are considered to be worth developing, compared with 3 out of 4 before 1995.
This trend is expected to continue. Most future discoveries in accessible areas are •expected to be small. Many of these will not be attractive to develop under existing conditions. The impact of each small field on production will be low and short-lived.
Only a few new play concepts are left for testing in the accessible areas of the NCS. •When a new play concept is confirmed, it can result in a wave of discoveries, some of which may be large. The remaining new play concepts are complex and carry a high risk.
Large discoveries are needed to curb the decline in production and investment levels •in the long term. Areas such as Nordland VI and VII, Troms II, Barents Sea North and South-West, and the disputed zone are expected to have the greatest potential for making large discoveries. These areas are not currently open for petroleum activities.
Growth in the level of activity on the NCS has more rapid than ever over the past •2-3 years. Delays in the planned level of activity are being experienced because of a shortage of mobile rigs, declining performance in well delivery and generally lower volumes than expected from new production wells. On the other hand, high oil prices have extended the production life of several fields and has thereby boosted the maintenance and repair workload on older platforms.
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Opportunities to reduce the decline in production and maintain healthy investment
This report focuses on the opportunities which will have the biggest impact on future oil and gas production. In summary, these are:
making the most of fields and exploration acreage in the currently accessible areas, •which involves:
- maximising oil and gas recovery from existing fields, and particularly those which are aging
- ensuring that the level of exploration activity remains high in the areas currently accessible to the petroleum industry
- changing the mindset on developing small fields
opening new areas for oil and gas activities. •
Purposeful cooperation This report sets out specific remedial actions which can be initiated by the industry and the authorities to curb the expected sharp fall in production.
The industry needs to:Apply integrated operations (IO) more widely to improve recovery and reduce •operating costs in existing fields. This calls in particular for improved collaboration between operators and service providers.
Cooperate better over demonstrating key new technologies and testing these on •fields.
Continue to explore for small discoveries in the accessible areas, particularly the •more mature exploration regions such as the North Sea.
Place greater emphasis on finding simple technical and commercial solutions for •developing small fields more cost-effectively.
Put measures in place to make better use of existing personnel and to retain older •employees
Cooperate over more effective recruitment of employees and increasing the number •of students taking science subjects.
The authorities need to: Establish a framework for incentives to improve recovery from mature fields. These •should focus on projects which significantly increase recovery but which would not be pursued with today’s decision criteria or which have a significant downside risk.
Give financial backing to a more focused set of critical technology demonstration •projects in order to improve recovery from existing fields, rather than spreading such support thinly across a large number of pilot projects.
Award more acreage in forthcoming licensing rounds and hold such rounds •more frequently, so that unproven play concepts can be tested faster. These new play concepts carry a high risk but provide the opportunity to make some larger
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discoveries. Based on the successful results of the awards in predefined areas (APA) near existing infrastructure, the government should extend this model to all blocks on the NCS in areas currently accessible for petroleum activities.
Establish a contingency plan which can be used if exploration of small prospects and •development of small fields fail to pick up fast enough in relation to the remaining production life of existing infrastructure. This plan should include framework conditions to improve the economic attractiveness of developing small discoveries.
Agree to open new areas for petroleum activities as soon as possible. The areas •which it would be most logical to open first are Nordland VI and VII plus Troms II, since geological information is available about these areas and the government can make the decision to open them soon.
Consider a radically different approach to exploration in Barents Sea North and •South-West, Jan Mayen and the disputed zone with Russia. Over the next 10 years, the authorities and the industry should cooperate on obtaining more geological information in order to reduce uncertainties before making decisions on the award of licences.
The NPD should share data available from areas not yet opened for petroleum •activities with the industry.
The Petroleum Safety Authority Norway (PSA) and its UK counterpart, the Health •and Safety Executive (HSE), should work for better harmonisation of the way requirements for drilling rig prequalification are interpreted across the North Sea. This could help to overcome the tight mobile rig market on the NCS.
Conclusions
The proposed initiatives should be implemented now in order to map and deliver the huge potential hydrocarbon resources remaining on the NCS and to avoid a sharp decline in production. These measures are vital if the petroleum industry is to continue contributing sound levels of activity and investments well beyond 2040.
Fig 1 illustrates the potential impact of realising the opportunities identified by the project team on production up to 2040. This shows that most additional resources in the future are expected to come from exploration, but that these involve a high degree of uncertainty. Oil prices are also an important factor which needs considering. The analyses in this report assume that companies will make decisions concerning new activities on the basis of an oil price between USD 60 and USD 100 per barrel. However, these analyses were carried out before the significant drop in oil prices from mid-2008. Other important factors affecting the future level of activity include the choices made and pace adopted by the government with respect to opening new areas and subsequent exploration on the NCS. If the proposed initiatives for maximising production on the NCS are successfully implemented, the project team expects that plateau production could be extended towards 2020. Production and activity are also likely to be sustainable at healthy levels well beyond 2040 if new areas are opened up.
Up to 2030, the project team’s production forecast lies well above the NPD’s long-term production forecast (Langsiktigbane), which was made in 2002. Beyond 2030, a gap exists between the project team’s estimate and the NPD’s 2008 production forecast.
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ReservesContingent resources in existing fieldsContingent resources in discoveriesUndiscovered in currently open areas
Undiscovered resources in Nordland VI and VII, Troms II
Additional potential from undiscovered small fieldsAdditional potential contingent resources in existing fields
Langsiktig utviklingsbane (2002 RNB)NPD forecast - all sources
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2008 2012 2016 2020 2024 2028 2032 2036 2040
Pro
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ctio
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Source: Prognosis for reserves and contingent resources are data from OD prognosis for undicovered resources and additional potential is based on project teams modelling.
Fig 1: Production forecast on for the NCS. The project team’s view of the potential impact of identified measures on production.
The proposed measures will have a positive impact on activity and thus on investment levels at different times, and are complementary (Fig 2). Short- and mid-term activity and production are needed to curb the decline in production after 2015. Continued investment in existing fields and the development of discoveries will maintain the high levels of activity for the next 10 years. New opportunities to improve recovery from existing fields and to encourage exploration for small discoveries will have their greatest impact on the level of activity between 2015 and 2025. Opening new areas around 2012 will only have a positive effect on activity and investment levels after 2022 or thereabouts.
Fig 2: Predicted timing of an increased level of activity on the NCS.
Risks and opportunities for future production and investment levels
One of the main factors contributing to future production and investment levels will be exploration success. However, a wide range of possible exploration outcomes exists:
2008-2010 2010-2015 2015-2020 2020-2025 2025-2030 2030-2035
Planned Activity in Existing Fields and Discoveries
Activities fromUpside in ExistingFields
Activities from exploration successin accessible areas
Activities from exploration successin new areas
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The project team estimated a range of 8.1-14.3 billion boe for yet-to-be-found •resources in currently accessible areas. The expectation is some 11.4 billion boe. If exploration success in the currently accessible areas proves below expectation, the potential loss of production would be some 2-3 billion boe, mainly in the 2015-30 period. Should the higher case for exploration success be achieved, additional production of some 2-2.5 billion boe can be expected in the same period.
The project team has assumed that Nordland VI and VII plus Troms II will be •opened for exploration in 2012. If the opening of new areas is postponed until 2020, a significant reduction in the level of activity can be expected, so that investment in 2030 will be only some 20 per cent of the present figure and production will drop to around 1.6 million boe per day (boe/d). This would threaten the ability of the petroleum industry to retain capabilities and expertise in specialist areas.
Barents Sea North and South-West, the disputed zone with Russia and Jan Mayen •offer a huge oil and gas potential. These areas could therefore have a significant impact on long-term production and investment levels. The project team has not included these potential resources in its forecast, since sound estimates of their size cannot be made owing to a lack of data.
Unconventional hydrocarbon resources on the NCS, such as oil shales, gas hydrates •and gas from coal, could offer a significant potential. The NPD provides an overview of these unconventional resources in its report on the petroleum resources on the NCS for 2007. The project team has not considered them. Economic and environmentally responsible exploitation of these resources on the NCS would require considerable advances in technology and may well lie beyond 2040. Nor is a reliable estimate of such unconventional resources available.
Upside and downside scenarios also exist for production from existing fields:The project team has assumed that EOR methods will not make a significant •contribution to improving recovery from existing fields. Should cost-effective solutions be developed and piloted in time to be applied to the large but maturing oil fields on the NCS, however, production could be increased in the medium to long term. The technology target area 3 (TTA3) set up under the oil and gas in the 21st century (OG21) technology strategy estimates that 2.4 billion boe could be added to production if EOR methods are applied to the 20 largest oil fields on the NCS.
Further increases in operating costs could reduce levels of activity on existing fields. •In particular, spending on infill drilling, and modifications to small fields and on mature fields with a relatively low level of production would come under pressure. This could lead to early abandonment and thus to the loss of tail production.
If the shortage of mobile rigs and other resources continues beyond 2011, some •activities may be cancelled because they are no longer economically attractive.
Oil prices are a dominant factor for decisions on activities and investments. That applies particularly to activities on mature fields, to small discoveries and to exploration. Should an oil price of USD 50 per barrel or lower prevail over the next 5 years, the current high level of activity on the NCS is expected to decline. The result would be reduced produc-tion from existing fields.
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1. Introduction
1.1 Background and mandate
In the spring of 2007, Odd Roger Enoksen, the then Norwegian minister of petroleum and energy, initiated the establishment of a national strategy for the petroleum sector. This consists of 6 projects led by the industry and 1 led by the Ministry of Petroleum and Energy (structural changes in the petroleum industry). The projects are:
Energy nation NorwayI. Production development on the Norwegian continental shelfII. Structural changes in the petroleum industry III. Internationalisation IV. The petroleum industry and climate changeV. Oil and gas activities in the far north VI. Economic consequences of petroleum activities VII.
KonKraft mandated project II – production development on the Norwegian continental shelf – to provide insights and to recommend initiatives which will have a positive effect on oil and gas production on the NCS. The project team was asked to produce a descrip-tion of production history, identify constraints and make recommendations which can have a positive effect on production. This could include recommendations on effectively increasing production from existing fields, developing discoveries and pursuing explora-tion. Project II has many interfaces with the other projects, particularly project I – energy nation Norway – and project VI – oil and gas activities in the far north.
The reference group and project team for project II have represented a wide spectrum of the industry. The sponsor is David Loughman and the project leader is Marianne Goesten (both from Norske Shell). The project team comprised staff from Norske Shell, Gaz de France, Petro-Canada, Acergy, StatoilHydro, Hess and Talisman, and was supported by Cera Strategy Consulting. The NPD has participated as an observer and supported the project team by providing data and information. The reference group also represents a range of E&P companies, service providers, research institutes and the Norwegian Confederation of Trade Unions (LO). The Ministry of Petroleum and Energy (MPE) participated in the reference group as an observer. In addition, the project team has had many consultations with and input from various players and decision-makers to ensure the quality of the decision-making basis.
Project I on energy nation Norway finalised and submitted its report in May 2008 to Åslaug Haga, the then petroleum and energy minister. Project IV on internationalisation was submitted during the ONS oil show in August 2008. The other reports are due to be ready in early 2009.
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1.2 Context
Production on the NCS is maturing After almost 40 years of virtually uninterrupted growth in production and investment, with a remarkable history of technology development and innovation, total hydrocarbon production on the NCS has reached its highest-ever level at a daily figure of 4-4.5 million boe per day. Output is expected to remain at this level over the next 7 years, assuming that the oil price stays above USD 60 per barrel. After 2015 or thereabouts, however, total oil and gas production is expected to start declining. Oil output is already falling. Gas production has been increasing, but this is not expected to continue offsetting the drop in liquids output beyond 2015 or thereabouts.
The petroleum industry can continue to make a healthy contribution to Norway well beyond 2040. Only half the combined oil and gas resources estimated by the NPD to lie on the NCS will have been recovered when production starts to decline after 2015. By then, remaining hydrocarbon resources on the whole NCS are likely be 25-65 billion boe, of which 45 per cent is expected to lie in accumulations which have yet to be discovered. If this huge potential is well managed to avoid a steep production decline, and if invest-ment is maintained at a healthy level, it will form the basis of a robust and sustainable petroleum industry for decades.
Norway is a global leader for recovering a large percentage of the hydrocarbons in place in its fields. Over the past 10 years, however, the large oil fields which have been respon-sible for the bulk of production on the NCS have been getting older and their output is now declining rapidly.
No large discoveries have been made over the past decade. Although half the exploration wells drilled find some oil or gas, most discoveries are currently uneconomic to develop. The average size of discoveries is getting smaller and smaller, as can be expected in mature petroleum basins. Output from discoveries currently under development and from finds yet to be made is unlikely to compensate for the production decline. The number of fields approaching the end of their producing life is rising.
What more can be done to slow down the decline in production?KonKraft mandated project group II to provide insights and recommend initiatives which could have a positive effect on oil and gas production on the NCS. Since several initia-tives are already underway, the appropriate question is: what more can the industry and the authorities do to maximise oil and gas production most effectively on the NCS? It is important to recognise that a decline in output appears to be inevitable at some point after 2015. However, much can be done to avoid a steep fall in production and thereby main-tain activity at a level which would allow a robust petroleum industry to be sustained in Norway for much longer.
Why are we asking this question now?This report appears at a time of rapid change. Several factors make a review of what can be done to address the decline particularly urgent. This urgency is relevant for short- and long-term production. Decisions made today could have important implications for production and activity levels in the 2020s.
13
As mentioned above, production from the large oil fields is rapidly declining. The •opportunity to improve recovery economically and apply new technology on these fields is disappearing fast.
The window of opportunity for achieving full exploration of the North Sea is •narrowing as facilities age and approach retirement.
A decision on whether and how to open new areas for exploration is due in •2010. That will be very important for future activity and production. This report provides insights into the implications of opening new areas for production and investment levels. Other KonKraft projects are also defining their views on this issue –particularly project VI, which is evaluating options for developing technology and resources in new areas.
The Norwegian petroleum industry will continue to play a very important role in •European energy supply well beyond 2040. Gas is regarded in Europe as a relatively clean source of energy. A robust petroleum industry is viewed as the best basis for developing a diverse energy cluster in Norway where the focus on renewable energy will become increasingly important. This makes it essential that the industry and the authorities know what to expect in the long term for future petroleum production and activity on the NCS (see KonKraft project I).
1.3 Methodology
Throughout the project, the team has sought the greatest possible involvement by the industry in the form of E&P companies, service providers, government authorities, Petoro, R&D institutions, and KonKraft with its supporting organisations – the Norwe-gian Oil Industry Association (OLF), the Federation of Norwegian Industries, the Nor-wegian Shipowners Association and the LO. The aim has been to ensure that the results reflect the widest possible range of views among industry participants. The project team started in December 2007 by listing potential problem areas for effec-tive optimisation of production on the NCS. A number of hypotheses and counterhypoth-esis were defined for these challenges. These were then tested by interviewing a large number of companies active on the NCS (see Appendix 2). In addition, fact-finding and analysis were pursued with a large set of databases, particularly NPD data and analyses. To obtain an outside perspective, the project team made extensive use of comparisons between the NCS and the UK continental shelf (UKCS), while bearing in mind the differences in business environment in Britain and Norway (see chapter 2). To assist in this work, the project team visited the UK equivalent of the NPD – the BERR – and the counterpart of the OLF – Oil & Gas UK. A model was constructed by the project team to analyse the impact of some of its recom-mendations and the choices facing the petroleum industry or the authorities with regard to future production and investment levels. A number of assumptions on yet-to-be-found resources were adopted for this model on the basis of historical data for the NCS. These assumptions were compared with historical information for the UKCS in the central and northern North Sea, which was used as an analogue for the future position on the NCS. These analyses provided insights into the exploration potential for the NCS. This work was followed by interviews with a number of small, medium and large companies to obtain a wider view.
14
A substantial number of sessions were subsequently held with the petroleum industry to obtain support for the project team’s conclusions and recommendations. These included relevant OLF committees. Discussion topics included licensing policies, the fiscal framework and operations. One-to-one meetings and a workshop were also held with representatives from E&P companies, the service industry and consultants.
An important goal of this report has been to provide a solid starting point for constructive debate, both within the petroleum industry and between the industry and the authorities, on what more can be done to maximise production effectively in these waters. Great uncertainties exist in forecasting the development of production on the NCS. This report does not pretend to have the right answers for every aspect of maximising production. It merely tries to assess the impact on future production of the current reality on the NCS and, based on these analyses, to make recommendations and move the discussion on this subject forward. Some of the analyses and recommendations incorporate very consider-able uncertainties in such areas as future resource estimates and the potential impact of new technology. Where a broad range of opinion has been found, the project team has tried to reflect this and to identify what the key differences comprise.
Oil price assumptionsSince the project began, oil prices have fluctuated between USD 50 and USD 140 per barrel. A sharp fall in prices was experienced in October 2008, down to USD 60 per barrel, and they fell as low as USD 50 per barrel in November. This range illustrates the volatility and uncertainty of oil prices. In this study, the project team’s analyses assume that companies will base decisions about new activities on an oil price of USD 60-100 per barrel. The fall in oil prices occurred after these analyses had been completed. The report’s recommendations, which involve action to be taken over the next 1-5 years, are based on this. Some chapters indicate the likely impact of a further increase or decrease in oil prices. Should these fall below USD 50 for a prolonged period, or rise as high as USD 200, some of our recommendations would no longer be valid.
1.4 Content of the report
Chapter 2 investigates various aspects of the historical development of production on the NCS Chapters 3, 4, 5 and 6 provide insights into what more the petroleum industry and the authorities can do in existing fields, and for small discoveries, and to explore the NCS more extensively in order to manage the decline in production most effectively and to keep the level of petroleum activity on the NCS at a sustainable level.
Chapters 7 and 8 describe the recent rapid changes on the NCS and the impact of these developments on the level of production and activity. They also address issues and actions related to attracting and retaining the necessary people and expertise.
Appendix 1 describes and presents the assumptions applied in the project team’s scenario modelling tool, which is used to illustrate the impact of choices, decisions and recom-mendations. The results of the scenario modelling and uncertainties are also discussed. Appendix 2 presents the project team’s engagement with stakeholders Appendix 3 explains the NPD’s resource classificationAppendix 4 provides the project team’s estimates for contingent resources and compares these with NPD forecasts.
15
2. History of and business environment for production on the NCS
2.1 Chapter summary
The NCS is experiencing a period of rapid change.
Production from existing fields is maturing. This can be characterised as follows:
The 4 large fields on the NCS which have accounted for 50 per cent of the oil •produced are now starting to decline rapidly.
Gas production is increasing, but this is not expected to continue compensating for •the decline in oil output after 2015.
The past 10 years have seen a substantial reduction in the resource base, in terms of •both reserves and contingent resources.
No discoveries large enough to make a significant contribution to production and •investment levels have been found over the past decade.
Many fields in the North Sea are reaching the end of their production life, leading to •the shut-down of installations.
Compared with the UKCS, the NCS is less mature in terms of exploration. A large part of the NCS has yet to be opened for petroleum activities. Many more discoveries remain to be made in those areas of the NCS accessible for petroleum activity, but these are expected to be small.
The NCS has seen many changes over the past 3-4 years.
A recent surge in new players has been encouraged by exploration incentives and •high oil prices.
Levels of exploration activity have been rising since 2005, and this position is •expected to persist in the near future.
Investment in existing fields is increasing.•
Costs are growing in line with a global trend, and drilling costs in particular have •increased sharply.
Comparisons are made throughout this report between the NCS and the UKCS. Some important differences in the petroleum business environment in these 2 countries are presented in this chapter.
2.2 The NCS is a maturing hydrocarbon province
After almost 40 years of virtually uninterrupted growth, total oil and gas production on the NCS has reached a plateau of 4-4.5 million boe/d. Production is expected to remain at this level for the next 7 years, assuming that oil prices are above USD 60 per barrel. After 2015 or thereabouts, however, total oil and gas production should start declining (Fig 2.1).
16
Fig 2.1: Historical NCS production and the NPD’s production forecast (31 December 2007).
Oil production has been falling since 2002 (Fig 2.2). It is dominated by large fields which have been on stream for many years, but their production rates are now declining. This trend reflects such factors as declining reservoir pressure in fields which have been producing for a long time and the fact that remaining pools of oil to be accessed by new wells are small and often located at the fringes of a field.
Fig 2.2: Historical and forecast future production of liquids and gas from reserves and contingent resources in fields on the NCS.
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)Historic Forecast
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Source: NPD (RNB operator forecast autumn 2007)
Historic Forecast
17
Gas production has increased by 58 per cent since 2000 through the start-up of new developments such as Åsgard, Gullfaks South and Oseberg and improved recovery from existing fields. This trend is expected to continue as Ormen Lange and Snøhvit reach their full production potential. However, it will not be sufficient to offset the decline in liquids output for long. This is why overall hydrocarbon production on the NCS is expected to fall after 2015.
The production contribution from the 10 largest fields is rapidly declining. Most of them are now in a mature stage (Fig 2.3). Four large fields in the North Sea – Statfjord, Ekofisk, Oseberg and Gullfaks – were responsible for 50 per cent of oil output before 2007. They have now produced 60-90 per cent of their expected recoverable reserves (Fig 2.4).
Fig 2.3: Historical and forecast liquids and gas production from reserves in the 10 largest fields (Troll, Ekofisk, Oseberg, Heidrun, Snorre, Gullfaks, Statfjord, Ormen Lange, Åsgard and Snøhvit) compared with other producing fields.
Over the past 10 years, 19.6 billion boe were added to reserves while some 16 billion boe have been produced. This represents an average production replacement of some 123 per cent. Most of the additional reserves consisted of gas from further development of exist-ing fields and from new discoveries. Only a very limited volume was added by the new small discoveries. Remaining reserves plus contingent resources (recoverable petroleum which has been discovered, but which is not yet covered by a production decision) in fields and discover-ies have been reduced by 7.2 billion boe over the past decade. Eighty per cent of this decline reflects a reduction in liquid reserves and contingent resources. No discoveries made over the past 10 years contribute significantly to replacing reserves and contingent resource. Found in 1997, Ormen Lange was the last large discovery on the NCS and contains well over 2 billion boe in recoverable volumes. Since then, only
0
1
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6
1970 1975 1980 1985 1990 1995 2000 2005 2010 2015
Pro
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)
Top 10 fields Liquid Top 10 fields Gas Other fields Liquids Other fields Gas
Historic Forecast*
Source: NPD data * Forecasts are Operator RNB Autumn 2007
18
small discoveries have been made (in other words, with less than 300 million boe in recoverable volumes apiece). These contain mainly gas. Skarv (1998) and Goliat (2000) are the most significant discoveries regarded as economic for development. Discover-ies currently in the planning and development phases will not contribute significantly to production and investment levels over the next 5-10 years. Fig 2.4 demonstrates the dominance of aging oil fields in the production picture, and the lack of significant new discoveries to replace them.
Fig 2.4: Total expected recoverable reserves compared with the percentage of reserves produced. Fields currently in production are shown on the right. The stage of develop-ment for discoveries compared with expected recoverable reserves is shown on the left.
2.3 Exploration on the NCS
Fig 2.5 compares the creaming curve for the NCS with the one for the UKCS since exploration began. A creaming curve plots the cumulative size of discoveries in the order in which they were made. The shape of the curve reflects the general principle that a basin contains a small number of large discoveries and a large number of smaller to very small discoveries. The larger finds are generally discovered in the early stages (the cream of the crop) followed by a progressively greater number of smaller finds. The cream of the crop is usually the easiest to find. Once the large accumulations have been found and exploration progresses, the size of each additional discovery diminishes.
The creaming curves for the NCS and UKCS illustrate this pattern. Large discoveries were made in the 1970s and 1980s. During the 1990s, the creaming curve started to flat-ten off as discoveries become smaller and smaller. One difference between the NCS and UKCS is that more “giant” finds (discoveries with at least 2 billion boe of recoverable volumes) have been made on the NCS. The average economic volume per discovery is
100 000
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100
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1
To
tal R
eco
vera
ble
Res
erve
s(l
og
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n b
oe)
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Percentage of reserves produced
Discoveries Fields in production
Underdev.
Troll GasEkofisk
OrmenLange
Snøhvit
ÅsgardVictoria
Statfjord
PlanningNo Plans Likely 90%
Bubble size representsremaining reserves
Source: Wood Mackenzie data
19
Fig 2.5: NCS and UKCS creaming curves: cumulative resources added by commercial discoveries in 1965-2007.
significantly higher on the NCS than on the UKCS. Another difference is that the UKCS is much further along the creaming curve than the NCS. All areas of the UKCS have been made available for licensing rounds. Licences on the NCS have been awarded more gradually, and over 40 per cent of the area plus the disputed zone with Russia remain unopened for petro-leum activities (see Fig 2.6). Approximately 150 more discoveries have been made on the UKCS than on the NCS. These are mainly small. The creaming curve for the NCS also began to flatten off after 1980, but some larger discoveries were still made in the 1990s. Every time a new area was opened, a number of larger discoveries were made. This is reflected in the overall creaming curve by a number of small creaming curves. The discovery rate is the percentage of exploration
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e)
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Source: Wood Mackenzie data
Statfjord
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20°0°-10°-20°-30°-40° 40°
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Greenland
Opened for petroleum activityNot opened for petroleum activityActivity limited to existing licences Exploration drilling in reservoirs not permitted between 1 March and 31 August No petroleum activity will start during the term of the present ParliamentAssumed maximum extent of sedimentary rocks that may contain petroleum
Fig 2.6: Status of petroleum activities on the NCS.
20
wells drilled which find oil or gas. It has been increasing over time as operators acquire a better understanding of the geology. However, few of these discoveries contain sufficient hydrocarbons to justify an economic development. Since 1996, only 1 out of 3 discover-ies is considered worth developing under 2008 conditions (Fig 2.7). That compares with 3 out of 4 in the period before 1996.
Fig 2.7: Exploration drilling results 1966-2007: total number of discoveries versus discoveries considered economic for development under 2008 conditions.
When oil prices fell in 1986 and again in 1999, the level of exploration activity on the NCS and UKCS dropped dramatically. As prices began to rise again in 2003, the UK witnessed a rapid increase in exploration drilling (Fig 2.8). This reflected a number of measures adopted by the British government, including exploration-only licences.
Fig 2.8: Exploration wells drilled on the NCS and the UKCS compared with those drilled in 2000.
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Source: Wood Mackenzie data
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is 1
00%
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21
On the NCS, however, the number of exploration wells kept declining – from 17 drilled in 2000 to 8 in 2004. The Norwegian authorities then took steps to encourage explora-tion. Awards in predefined areas (APA) and tax incentives for exploration were among the measures introduced (see also chapter 4). These steps have so far proved successful in stimulating exploration activity, helped by high oil prices. The number of companies prequalified either as licensees or as operators on the NCS has increased from about 20 in 1999 to 66 at September 2008. Most of the new companies have applied for exploration licences. The number of exploration and appraisal wells increased to roughly 30 in 2007, and 50 can be expected in 2008.
2.4 Level of activity increasing despite rising costs
In addition to the growth in exploration and appraisal drilling, activity on existing fields has increased sharply and is expected to remain high for the next 3-4 years (Fig 2.9).
Fig 2.9: Historic and forecast capex on the NCS.
The high oil price has encouraged operators to accelerate production and to look for opportunities to improve recovery from existing fields. This is reflected in plans for more infill wells and a rise in platform modifications to improve uptime. A number of large-scale projects related to the redevelopment of the Valhall and Ekofisk fields are also being pursued. Several platforms will be removed and replaced. Some fields already shut in have now gained a second lease of life, including Yme and Frøy. This trend towards higher activity is expected to continue at least until 2012, assuming that oil prices remain above USD 60 per barrel. By contrast, the level of investment in development of new
Existing fieldsField development
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Cap
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7)
1975
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1980 1985 1990 1995 2000 2005 2010
22
fields has dropped drastically since 1997 because no new large discoveries have been made which can fill the project pipeline.
However, high oil prices and the elevated level of global petroleum activity have boosted costs. The latest upstream capital cost index from IHS/Cambridge Energy Research Associates (Cera) shows that the cost of developing a new oil or gas field has more than doubled on a global basis in 4 years (Fig 2.10). Norway is no exception. The actual cost of recently delivered development projects on the NCS have been 23 per cent higher on average than estimated in their plans for development and operation (PDOs). Develop-ment drilling costs in these waters have increased significantly since 2002, and by more than the global weighted index of upstream capital costs. The shortage of mobile rigs and restrictions on importing such units, as well as special requirements set for rigs operating on the NCS, had already driven up costs 2 years before the rise in the global index.
Fig 2.10: Index of nominal capital costs: NPD development drilling costs compared with the global upstream capital cost index.
Operating costs have also risen significantly over the past 2 years. Where extending field production life is concerned, high oil prices do not always offset the increase in operating cost. In other words, the production life of some aging fields with a relatively low level of output will not be prolonged even with high oil prices.
No sign has yet been seen of activities being discontinued because of rising costs. How-ever, it is important to recognise that costs will not necessarily follow oil prices down without a time lag. Should oil prices fall significantly, costs will remain high for some time afterwards. The industry and the authorities need to build the flexibility and adapt-ability to deal with high costs in a lower oil price world, so that activity levels do not drop dramatically.
502000
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ost
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23
2.5 A number of key differences exist between the UK and Norwegian business environments
The report draws comparisons throughout between the NCS and the UKCS. The latter has been used because its geology is comparable and because it is considered to be further along the maturity curve as a whole. The British government has also acted in recent years to promote petroleum activities on the UKCS. The impact of these measures is already visible, which creates potential learning opportunities. However, some key differences exist between the UK and Norwegian petroleum business environments.
As discussed above, the Norwegian government has taken a number of steps to stimulate activity . The tax regime on the NCS has featured high but stable rates, as well as incen-tives to encourage exploration and technology. In general, the intended approach of the UK authorities since the 1980s has been to encourage competition. This has had some degree of success in temporarily arresting the production decline on the UKCS. Measures have included proactively encouraging acquisition and divestment of equity in produc-ing fields and discoveries, and reducing barriers to entry for new exploration players. This approach has not been purely market-driven. From time to time, the UK govern-ment intervenes more directly. One example is the regular changes to the tax system in response to oil price fluctuations.
It is important to recognise that the market-driven approach taken by the UK authorities to encourage activity would not necessarily apply in Norway. Key differences which limit the impact of market forces are:
StatoilHydro operates 80 per cent of Norway’s output, so production performance on •the NCS is largely a reflection of this company’s performance.
The UK has no equivalent to Petoro. Although the BERR exercises some stewardship •of British oil and gas resources, this is not done from an ownership position.
Many of Norway’s working arrangements are unique, including the rotation schedule •of 2-4 weeks rather than 2-3 as in the UK, restrictions on night work and so forth
Prequalification criteria for licensees in the UK are more flexible. The introduction •of promote rounds enabled small players to qualify for exploration-only licences with fewer personnel – in other words, no more than the workforce which ensuresoperational safety. Nor do these personnel have to be located in the UK. To prequalify as a licensee on the NCS, new players are required to locate a certain number of geoscientists and engineers in Norway.
24
3. Improving oil and gas recovery from existing fields
3.1 Chapter summary Many large fields have been discovered and put into production on the NCS. The indus-try has delivered a world-class performance in recovering as much oil and gas as possible from Norway’s existing offshore fields. Operators on the NCS have been very successful in repeatedly increasing recoverable volumes. This is because companies working there continuously apply best practices and new technologies. Past success has created great expectations about growing recovery in the future.
A potential to grow the recovery base is indeed felt to exist, but continuing the success story faces major challenges. The first is to ensure that investment and activity levels in aging fields remain high. Most large oil fields have yielded more than 60 per cent of their estimated recoverable oil and gas, and their production is declining rapidly. Barrels left in these fields are more technically difficult to recover and therefore more labour-intensive and expensive to produce. Costs have increased, following oil prices and a rising level of petroleum activity globally. An increasing share of production on the NCS also comes from small to medium-sized fields and from subsea developments. On average, these have a lower level of ultimate recovery and extending their production life in a cost-effective way will be challenging. The second major challenge is to maintain the track record for applying new technolo-gies. Production is set to cease from many of the larger fields over the next 15 years, and limited time is accordingly available for developing and adopting new solutions to improve recovery. Small discoveries made in recent years provide insufficient incentive for further developing and applying new technology. In a world with high oil prices, companies tend to focus on short-term production rather than on the application of new technologies. Research into and development of methods to improve recovery are also falling short.
Adopting IO approaches could make a significant contribution to improving recovery in existing fields. The information technology and processes involved in IO permit such approaches as continuous monitoring of wells, quick decision-making by experts off-shore and on land, and greater reliability on the installations.
The project team believes that these are critical challenges, even in a world where oil prices exceed USD 100 per barrel. Debate exists, for example, over how far and how fast EOR can contribute to growing recovery on the NCS.
Recommendations from the project team include:The authorities should provide more frequent incentives for projects which would •significantly improve recovery from mature fields, but which would not be executed with today’s decision criteria or which have a significant downside risk.
Better industry cooperation is needed to demonstrate key new technologies and •test these on fields. The authorities also need to back a more focused set of critical technology demonstrations, instead of spreading their support thinly across a large number of projects.
25
The industry must apply IO more widely to improve recovery and reduce operating •costs. This calls in particular for improved collaboration between operators and service providers.
3.2 The average ultimate recovery factor on the NCS is high
Current estimates for the average ultimate recovery factor from Norwegian fields is 46 per cent for oil and 70 per cent for gas. The NCS ranks among the world’s offshore petroleum regions with the highest average recovery factors. An NPD study of 36 oil-producing fields on the NCS showed that 29 fields had doubled their reserves on average compared with the estimate in their PDO (Fig 3.1).
Fig 3.1: Growth in oil reserves compared with PDO estimates. Most fields have in-creased ultimate recovery expectations over time. Oil reserves are twice as high on average than in the PDO.
This has been achieved through such practices as:
The extensive use of methods like water and gas injection, often implemented from •the start of field production.
Operators on the NCS have concentrated on reservoir management throughout •the production life of fields, with a focus on data gathering, field reviews using state-of-the-art subsurface modelling techniques, and the use of 4-dimensional seismic surveys. This approach has been mainly driven by the high cost of offshore development and wells.
The use of new technologies. Historically, operators on the NCS have been quick to •pilot and adopt new technologies. Horizontal, extended reach and multilateral wells have played a prominent part in the continued development of existing fields.
It should be noted that, in the early days of the Norwegian oil industry, the operators were conservative in estimating recovery factors owing to limited knowledge, field informa-tion and experience. Very little know-how was available, for example, on the develop-ment of chalk fields such as Valhall and Ekofisk. Operators have subsequently looked to analogues and best practice in order to increase recovery from these fields.
Field size as of 31 Dec. 2006
> 100 million Sm³30 - 100 million Sm³10 - 30 million Sm³< 10 million Sm³
Volume-weighted average = 2.0Average = 1.7
0
4
3
2
1
Tro
ll II
Va
lha
ll
Tord
is
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fisk
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llfa
ks S
ør
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rg
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r
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dis
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rd N
ord
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rg Tor
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e
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ge
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a
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rg Ø
st
Alv
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im
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rg S
ør
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da
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y
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cto
r fo
r g
row
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n r
es
erv
es
Source: NPD
26
3.3 Contingent resources in existing fields are still considerable, but reserves and contingent resources are declining rapidly
Given the current reality of a maturing NCS, the project team believes that reserves and contingent resources in existing fields have only limited potential for growth, and that meeting the target for oil reserves set by the NPD in 2005 will be challenging even if the current high level of oil prices is sustained.
The NPD estimates contingent resources in existing fields at roughly 4.7 billion boe. Of these, 67 per cent are expected to come from liquids and 33 per cent from gas. Operators and licence partners have traditionally identified new opportunities for improving recov-ery in fields. Over the past 10 years, however, fewer and fewer opportunities have been found. Contingent resources in existing fields have declined by 5.4 billion boe, from 11 per cent of total resources to a current proportion of 4 per cent. Despite high oil prices over the past couple of years, this decline is expected to continue.
One example of an area where the NPD’s expectations are high is its goal for the growth of oil reserves. In 2005, the regulator set a growth target of 5 billion barrels in oil reserves alone between that year and 2015. Of this expansion, 75 per cent is expected to come from resources in existing fields and 25 per cent from new developments. The actual growth in reserves for 2007 as specified by the operators in the revised national budget (RNB) was just below operator forecasts (Fig. 3.2). It will be challenging to continue meeting this target year by year.
Fig 3.2: Status of the NPD’s target for growth in oil reserves of 5 billion barrels by 2015.
2004 2006 2008 2010 2012 2014
5
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row
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Target for reserves growth per yearActual reserves changesForecast from operatorsPreliminary reserves changes 2008
Source: NPD
27
3 .3 .1 Ensuring that activity and investment levels remain high in maturing fields will be challenging
To meet the NPD’s target for oil reserves and to grow contingent resources, the level of activity on existing fields must be sustained. This will be challenging for the following reasons:
Most of the larger oil fields are in a mature phase, having produced more than half •the reserves ultimately expected to be recovered (see Fig 2.4 in chapter 2). Getting out the second 50 per cent will be much harder. In 2007, 60 per cent of Norwegian liquids production came from the 10 largest fields, most of which are now in decline. Generally speaking, fields become more complex to produce and to continue developing as they mature. Reservoirs in mature fields, for example, contain zones with varying pressure and increased water production. New drilling targets also tend to lie in remoter and more complex parts of a field, and hydrocarbons often sit in small remaining pockets. This results in higher costs per barrel produced.
Mature fields thus require more intensive reservoir management than in the early •stages of production. Experienced staff to work on reservoir management and identification of opportunities in maturing fields are in increasingly short supply. This trend is reinforced by a shift of experienced staff from the larger operators to the smaller new exploration companies.
Fig 3.3: Total historical production from fields on the NCS with fixed platforms and subsea tiebacks.
Since the mid-1990s, the number of subsea tiebacks has increased. Many of the new •producing fields are small and developed with subsea wells tied back to existing platforms or floating production facilities. This has resulted in a steady growth in the percentage of production from subsea developments, which now stands at 32 per cent. (Fig 3.3). However, recovery from subsea fields is generally about 10 per cent lower than from the larger platform-based developments.
Source: OD
0
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)
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s
Production from subsea facilities Production from platforms Percent from subsea facilities
28
The higher cost of intervention in subsea wells makes it harder to improve the recovery factor in these fields and ultimately to extend their field life. The development of subsea technology, which can increase the cost effective development of subsea fields, will be key to address these challenges.
A backlog in activity has built up in recent years owing to a shortage of mobile rigs •and personnel (see chapter 7). If this position persists over a long period, measures to enhance production may be dropped altogether because their value diminishes over time. The added value of drilling an infill well to accelerate production, for example, falls as the field is depleted.
The percentage of production from the larger oil fields is declining, with the NCS •becoming more and more dependent on output from a large number of small fields (see Fig 2.3 in chapter 2). In general, ultimate recovery is lower from small developments than from large fields (Fig 3.4). Generally speaking, only a limited number of development wells can be justified in small fields. Parts of its reservoir will accordingly not be optimally drained. Should one of the few wells fail, moreover, this will have a major negative impact on total field production. And water and gas injection to maintain pressure in such reservoirs cannot often be economically justified.
The significant increase •in costs during recent years may hamper future investment in mature fields. No evidence has so far been found that the recent significant rise in facility costs and rig rates has hampered capital spending on mature fields. On the contrary, investment in producing fields on the NCS has risen since 2000, and this trend is expected to persist until 2012 providing oil prices remain above USD 60 per barrel (Fig 2.9 in chapter 2). Substantial investments are being made and planned, such as redevelopment projects for the large, mature Ekofisk and Valhall fields. Infill drilling in mature reservoirs like Gullfaks and Statfjord is also at an all-time high. However, a more worrying development can be observed across the border on the UKCS. The level of investment in existing fields showed a marked decline in 2007, and this trend is predicted to persist for the next 4 years (Fig 3.5). The significant increase in costs since 2005, combined with higher tax rates, has reduced profit margins and the level of investment – particularly in and around mature fields – is dropping. In May 2008, the UK government announced changes to the fiscal regime which could stimulate activity in undeveloped areas of older fields. If costs continue to rise globally, the NCS may experience a decline in investment levels in existing fields similar to that on the UKCS. In a scenario with sustained lower oil prices, the short-term level of activity and investment in mature fields are likely to decline. This is because costs are unlikely to follow oil prices quickly down.
100
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Source: NPD data
Fig 3.4: Expected recovery factor versus field size for liquids and gas.
29
Fig 3.5: Actual and predicted capital investment on the UKCS in 2002-2012.
3 .3 .2 Maintaining the track record for applying new technology will be challenging
Norway has been a world leader in developing and applying new petroleum technology. Historically, operators on the NCS – and not least Statoil and Hydro – spearheaded such innovation. From the late 1980s, state-of-the art drilling technologies such as horizontal wells have been applied in field developments. More recent examples are 4-D seismic surveying, subsea technology for deep water, IO and seismic imaging techniques. Technology development to address environmental issues has also made rapid progress in recent years. The service industry and E&P companies have used and are using the NCS as a test bed for new technology, and subsequently applying solutions and expertise developed in Norway to enhance their international business. Deepwater technology provides an example. Norwegian research institutes have acquired a worldwide reputa-tion. Conversely, medium-sized and large international petroleum companies and service providers have brought experience from abroad to the NCS in such areas as applying technology to low cost, high-well-density areas.
Extensive cooperation and cost sharing has been pursued by players in joint industry projects, both in licences and by the individual companies. Operators are also allowed to charge part of their research and development (R&D) expenditure to the licence budget. These 2 factors have further stimulated the development and application of new technology.
All of the above have yielded significant improvements in recovery from existing fields (see Fig 3.1) and in the development of discoveries in harsh environments. For the following reasons, the project team believes it will be harder in the future to maintain this good track record and to improve recovery by applying new technology:
7
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3
2
1
02002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
£ b
illio
n (
RT
07
fro
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007
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war
ds)
Possible new developmentsPossible in field
Probable new developmentsProbable in field
Sanctioned
Source: Data 2002-2006 BERR, data 2007 onwards Oil & Gas UK
30
The small discoveries made over the past 10 years do not provide sufficient financial •incentive to continue developing and applying new technology. Historically, new technology has been developed for the larger oil and gas fields.
Demonstration projects to test new technology have been in short supply. Research •institutes and the service industry are continuing to develop solutions. However, they are struggling to get access to fields where new technologies can be tested and qualified. Most companies give a high priority to production targets because oil prices are so high. Few of them want to risk production shortfalls and reduced reservoir performance by adopting new and untested technology. Cases exist where an operator proposes a demonstration project on a field, but its licence partners are not always willing to invest in and make the asset available for testing. In some cases, the trial has had to be funded from sources outside the licence before the partners approved the project.
The time window for applying new technology in large existing oil fields is •narrowing. With a few exceptions, such as Valhall, Ekofisk, Heidrun and Snorre, most of these fields are in a late-life phase and getting close to ceasing production.
A shortfall exists in R&D and the deployment of new subsurface technology related •to methods for improving oil recovery. Few joint industry projects cover this area. Some of the larger companies have in-house R&D projects or sponsor research institutes in Norway to do subsurface studies (with some 14 research projects sponsored by the Petromaks programme, for instance). In addition, few grants are awarded in Norway for subsurface R&D. Interest in science subjects amongst Norwegian students is fading, and competition over graduates between petroleum and other industry research institutes is growing. Foreign students nowadays often secure the grants available for geology and geophysics.
3 .3 .3 A debate exists on the contribution of EOR to growing reserves in existing fields
E&P companies across the globe have been experimenting with EOR methods for more than 25 years. These are advanced solutions for reducing the residual oil volume (defined as oil which is not mobile) in a reservoir. Such resources cannot be recovered with normal methods. EOR includes injection of chemicals, carbon dioxide or miscible gas. The introduction of microbes to the reservoir is a more recent technique. IOR is defined as covering the entire spectrum of methods aimed at pockets of movable oil left in a reservoir. The commonest IOR methods are water or gas injection, depressurisation and water alternating gas injection. While EOR is slowly but steadily progressing on land around the world, it has been slow to pick up offshore. A number of pilot projects exist globally, but no examples of full-field EOR applications can be seen so far. Some believe that EOR can boost production from the larger existing fields on the NCS in the medium to long term. However, others do not expect EOR to develop quickly enough to benefit maturing oil fields. The sceptics doubt whether EOR will make a major contribution to growing reserves, although they concede that such methods may be applied to a few fields. Their arguments include:
31
EOR on the NCS is very expensive • Applying EOR offshore is very expensive and has so far been uneconomic on a large scale. Pilot EOR projects have been only sporadically initiated – such as the microbes pilot in the Norne field. In many cases, EOR applied field-wide requires a full change-out of platform and well equipment. This means an extended shut-down. Not many operators are willing to exchange short-term output for possible long-term gain – particularly if a risk to reservoir performance exists, such as the deterioration of reservoir quality owing to interaction between formation rock and the chemicals used in EOR. A recent example is the study of carbon injection on Draugen, where the cost far exceeded the benefits. Similar examples are provided by Oseberg East and Brage. In addition, the well configuration on most NCS oil fields is designed for water injection, with the wells spaced a considerable distance apart. This means that even an EOR pilot in a restricted area would often call for the drilling of numerous wells. Even at very high oil prices, bridging the cost/benefit gap for EOR would be very difficult.
Development and application of EOR technology are not moving fast enough for •the large maturing oil fields The OG21 strategy identified a need to focus on encouraging improved recovery, and TTA3 was accordingly established. Its strategy was further detailed at a seminar in early 2007. A target was set to increase average ultimate oil recovery from 46 to 55 per cent. EOR methods are envisaged as playing a major role in achieving this vision. The TTA3 group has pointed out that major challenges remain to be addressed with regard to adopting EOR methods, including understanding the recovery process and environmental challenges. At the same time, few EOR pilot projects are being pursued to demonstrate and operationalise the technology and improve understanding of the benefits offered. TTA3 has identified a number of key technology development projects required to address these challenges. However, the E&P companies have so far failed to move these key projects actively forward. This may reflect the shortage of experienced personnel in the service industry and E&P companies. These challenges need to be addressed in good time before the larger oil fields have declined beyond the point where they could benefit from EOR methods.
The project team expects the biggest potential for growing resources in existing fields to lie in pushing conventional technology beyond its current limits and further developing and applying new technology to improve recovery from mobile oil pockets. Examples include continuous seismic monitoring, smart inflow control devices, intelligent well technology and improving reservoir simulation techniques. Dry gas injection, in combination with water and possibly foam injection, has a significant potential for improving recovery in existing fields if applied on a large scale. It is also essential to continue developing subsea technology, not only for the large fields but also for smaller subsea discoveries.
32
3.3.4 IO can contribute significantly to increasing production and reserves
The updated report on the potential value of IO on the NCS (OLF 2007) concludes that the petroleum industry can enhance value creation on the NCS by NOK 295 billion in 2005-2028. This requires commitment and a strong focus on new technology and collaboration models. Some 78 per cent of this potential can be attributed to accelerated production and increased reserves as a result of optimising output and plant availability. The cost of realising this value would be NOK 24 billion. It calls for aggressive implementation of IO across the entire NCS. If the companies choose a phased and less aggressive approach, the potential would be significantly reduced.
Fig 3.6 shows production profiles with and without IO for the fields studied in detail in the OLF report, which represent 33 per cent of the total accelerated production potential. Totalling 1.87 billion boe, the increase in recovery over the period is equivalent to depleting a large new field on the NCS.
Fig 3.6: Production with and without IO for the fields included in the OLF study.
The report identifies the value potential, measures, observations and findings. The following IO measures have been identified for accelerating production and improving recovery:
Real-time interaction between relevant activities and disciplines – engineers •monitoring compressors or wells from land, for example, and contacting the field if matters requiring action are discovered.
Use of analytical tools in critical work processes to extract and present available •information from operating data, both historical and real-time.
Use of collaboration rooms to support work processes between land and offshore and •between operator and supplier (this includes drilling, operations and maintenance on a round-the-clock basis). Many examples show how collaboration rooms increase production by implementing the right measures earlier – in other words, when the
160
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Source: OLF (2007)
33
involvement of support functions and experts is required. In some cases, work can be performed from such rooms which would otherwise have necessitated travel to the installation.
Improved well bore placement through the application of real-time drilling.•
Using permanent 4-D seismic grids to monitor reservoir performance continuously, •and thus permit continuous updating of reservoir models. In this way, everything is in place for taking reservoir management decisions at the right time on the basis of updated information.
Extending field production life by reducing operating costs through such means as •moving personnel from offshore installations to land, cutting logistics expenses and making more efficient use of chemicals.
Better management of well pressure and water injection through the use of downhole •sensors in combination with integrated facility models.
The industry has applied IO broadly over the past few years, and made good progress with technology. Several examples exist of fields where this approach has yielded meas-urable benefits. One case in point is the implementation of a complete IO package for the aging Brage field, which reduced staffing levels, increased production efficiency and improved health, safety and environmental (HSE) performance. However, companies are lagging behind in some areas, such as limited use of smart wells and downhole instru-mentation. Several of the key fields on the NCS are behind schedule for IO implementa-tion. Progress is being made in adjusting work processes and organisations to encourage interaction between the various disciplines, but this is taking longer than expected.
Petoro documented in a study from 2007 that the basis for implementing IO is largely in place, and that the value potential has been partly realised. However, the latter is yet to be achieved in full. The challenge lies in completing implementation and putting IO to use holistically on a large scale. OLF issued 2 reports in late 2007/early 2008 which could have a positive effect on development and implementation in this area. Issues such as IO for drilling rigs and IO in new development projects are considered. These reports will not be discussed further here.
Key criteria for success are collaboration between disciplines and intelligent use of real-time information for better and faster decision-making. These require a high degree of involvement and collaboration between operators and experts from the main service providers. Unfortunately, that does not usually happen. The main reasons are:
Established commercial models between operator and service providers are unsuited •for the IO environment. Generally speaking, the service provider will make more money the more equipment it supplies, the more people it involves and the longer things take. This is contrary to the goals of IO.
Established procurement processes are often an obstacle to successful •implementation of new technology and methods. Apart from cost sharing and proprietary rights, technology providers have a weak business case for participating in joint development programmes. An operator is under no obligation to involve the same technology provider in further implementation and an additional scope of work following a successful pilot. So the technology provider faces a traditional bidding
34
process, in which the operator will treat all bidders equally to ensure competition and the lowest possible price.
Successful collaboration cannot be procured, but is based on alignment of objectives •and mutual ownership of the challenges. Good ideas and initiatives from both service provider and operator often disappear in the traditional supply chain. Procurement is about getting the lowest price rather than the best value. Initiators and/or supporters of good initiatives at the operator often lose the internal fight with their own procurement organisations and with established systems and mindsets.
Good management initiatives and pilot projects fade away on their way to the •operational level when they run up against conventional thinking, procedures and contracts.
Involvement of key service providers in the design and implementation of the •operator IO centres is too little or too late. These companies are thereby often unable to influence work processes and the decision-making environment.
Operators may appear to be willing to increase their level of collaboration, but prefer •in practice to keep service providers at a distance in decision-making processes. Changing this mindset will take time.
Operators underestimate the main service providers as a source of expertise and •personnel to supplement their own resources
The idea that advanced new technology and the vast amount of available data affect •the decision-making process and require involvement and analysis by experts to realise their full potential value is not widely accepted in the operator’s organisation.
One of the major providers of drilling and production enhancement services has announced a corporate initiative in which it promises a 25 per cent reduction in non-productive time for well construction operations if it is given greater responsibility for operational planning and execution. It remains to be seen whether operators will accept such an invitation. Another aspect which needs to be addressed is the development of IO technology for small fields. This approach is applied to large fields by the big players. Most of Norway’s larger oil fields are in a mature stage. Developing and adopting technology for the more recently developed but smaller fields could further enhance the value of the IO concept.
35
3.4 Recommendations
The project team estimates contingent resources in existing fields at roughly 4.7 billion boe. This is consistent with the NPD’s assessments. If investment levels and the track record for applying new technology can be maintained, it expects that new opportuni-ties to improve recovery could potentially add a further 0.8-1.7 billion boe (see also Appendix 4). These additional opportunities are expected to have an effect on production beyond 2012 (Fig 3.7).
Fig 3.7: NCS production forecast. The project team’s view of the additional potential for increasing contingent resources in existing fields. The government should encourage further investment in mature fields High oil prices have made investment in existing fields more attractive. However, costs have risen significantly over the past couple of years, with mobile rig rates and facility costs as examples. These increases have had and will continue to have a strong impact, particularly on tail production where the unit cost per barrel is generally high. The project team recommends that the government provides more frequent incentives for projects which will improve recovery from mature fields, but which are financially unattractive with current oil prices or have a significant downside risk. In the past, the government has been willing to consider changes to the framework on a case-by-case basis, with a water injection project on Ekofisk as an example. However, this was done where the potential for increased recovery was large. The project team recommends that such incentives are also given to projects where the recovery improvement is smaller but the window of opportunity is narrow, such as projects on fields at the tail end of their production life.
Pro
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n (
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e/d
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Reserves Contingent resources in existing fieldsContingent resources in discoveries Additions to contingent resources in existing fields (high case)
0
1
2
3
4
5
2008 2012 2016 2020 2024 2028 2032 2036 2040
Source: NPD (reserves and contingent resources) and project team
36
Improve cooperation over pilot projects to demonstrate key new technologySome of the larger E&P companies with their own R&D laboratories are willing to cooperate with other companies to deploy new technology by sharing the cost of pilot projects. Such collaboration is simplified if all the participants own an equity share in the field and thus share the risks and benefits of the pilot. This would also permit a free exchange of data and learning. In reality, the interested companies seldom have an equity share in the pilot field. Five years ago, the Asset Forum addressed technology coopera-tion between companies. Several meetings were held on the subject but no specific proposals for joint technology demonstration projects were ultimately matured. The NPD also established the Force forum to bring together petroleum companies willing to invest in research and the application of IOR/EOR methods in the subsurface. This has yet to result in any specific collaboration. The petroleum industry, including E&P companies, service providers and R&D institutes, needs to make a concerted effort to remove the barriers to cooperation over deploying a selected number of key new technologies which could have a significant impact on production.
One model could be for the TTA groups in OG21 to provide support in preparing a shortlist of key new technologies which need to be tested before the window of oppor-tunity has become too narrow, and to consider which of these would work through a company cooperation scheme. Relevant operators should then be approached to set up such collaborations together with their licence partners and other interested parties. An essential requirement for such a model is to find a way to share the risks and costs of fully developing and demonstrating the technology between those interested now and potential future partners. This could be an interesting subject for further study and debate.
Another success model might be found in commercial arrangements for technology application. A recent example is the partnership deal by ExxonMobil, StatoilHydro and Shell with Badger Explorer to permit the testing of a new method for drilling exploration wells developed by the last of the 4. The 3 E&P companies involved see a significant strategic potential for this novel technology, and have therefore sponsored the Badger Explorer prototype development programme since 2005. They have now entered into a commercial deal with Badger Explorer, where a full-scale test of the technology repre-sents an important milestone. This agreement gives the E&P companies the first right of refusal to buy an equal share in the manufacturing and operational capacity of all Badger Explorer systems for a period of 3 years after commercialisation. In return, Badger Explorer will receive the necessary operational and technical support from the partners to access land-based and offshore facilities, equipment, technology, data and skills for completing its prototype.
Government support for selected pilot projectsThe government could provide financial support for demonstration projects for key new technologies which could unlock substantial additional reserves, such as EOR methods or cost-effective subsea interventions. This support should not be spread thinly across a large number of pilot projects, but focus on a few key schemes identified through the TTA forum.
37
Improve collaboration on IO between operators and service providersTo foster better collaboration between operators and service providers, particularly for pursuing wider deployment of IO, the project team recommends the following steps:
Make use of the OLF report on best practice for developing R&D contracts in •Norway. This contains philosophies and commercial models based on alignment of objectives and improved performance for key services.
Ensure management initiatives and programmes receive commitment at operational •and executive levels, backed up with an appropriate business case for the service provider.
Business cases are to be clearly defined for both operators and service and •technology providers. They need to be part of the joint development programmes for IO.
Operators must recognise the resource potential in the service industry, and exploit •this to fill the gaps in their organisation.
Key service providers must be more involved in implementing IO centres on land •and in planning and executing operations. A solution whereby the service provider supplies a back-office support service – from its own IO centre, for example – would permit round-the-clock and global expertise support. This often proves an optimal solution, providing it is supported by a commercial model.
Establish production enhancement teams, including operator plus service provider(s), •to evaluate and select well candidates, methods, technology and equipment, and to plan, schedule and execute projects.
No case seems to exist for encouraging increased acquisition and divestment activity A case does not appear to exist at present for encouraging more A&D activity on the NCS to boost production. It cannot be clearly demonstrated that a set of more “natural” owners is available which could increase production and improve recovery better than the current ones.
The UK government has taken a proactive approach to stimulating the A&D process for changing the ownership of maturing fields. This has taken the form of “nudging” larger companies to review their portfolios, and making it clear that asset transfer is welcomed by the authorities as a responsible activity. The expectation has been that the new opera-tors would invest further in the fields and thus boost recovery factors. However, proving that new operators have indeed added value through increased production and reserves is very difficult. The value which buyers have created derives from the fact that they expected a higher oil price than the sellers. That view has been fulfilled. However, this “value gap” has disappeared with record oil prices. No indications can be found on the NCS that operators are reducing their investment in maturing fields. The opposite is in fact the case: investment levels have been rising. StatoilHydro operates 80 per cent of production and has a strategy to improve recovery and maintain investment levels in maturing fields.
38
The appetite for transactions appears to be small among both buyers or sellers, given the current premium on production and the consequent high purchase price per barrel. Very few deals have involved producing fields. BP sold equity and the operatorship in Gyda and Ula to Talisman, which is now also redeveloping the Yme field. ExxonMobil has put the equity and operatorship of the Jotun field up for sale. Generally speaking, operators on NCS have much smaller equity shares compared with the UK. A new buyer often wishes to have as much control as possible in order to execute its plans, and thus the fewer partners the better. This position may well change in the future. So the project team would urge the authori-ties to communicate its position on A&D unambiguously. There seems to be an industry perception that selling assets is looked upon unfavourably by the authorities and could be damaging to company chances of future licence awards. This is understood not to be the case. So the project team suggests that the authorities communicates this clearly to ensure that ownership can be more easily transferred to the most appropriate owner if and when the level of activity in mature fields and the development of small fields drop off.
39
4. Continuing to encourage exploration activity in currently accessible areas
4.1 Chapter summary
The biggest impact on future production and investment levels is expected to come from future exploration successes. The remaining exploration potential on the NCS is still high. The NPD estimates yet-to-be-found volumes at 10-36 billion boe. These are expected to lie in both currently accessible and new areas. It is thus possible that more oil and gas may be found than has already been produced from the NCS. However, that requires a number of political decisions.
The accessible areas on the NCS have yet to be as extensively explored as other regions, such as the UKCS. The government has been successful during recent years in stimulat-ing exploration activity in currently accessible areas. The APA rounds have resulted in quick recycling of acreage, and exploration incentives have attracted many new players to the NCS. This led to a high level of exploration activity in 2007 and 2008, which is expected to continue for the next 3 years. However, it is very uncertain whether this increased level of activity will lead to oil and gas discoveries large enough to contribute significantly to slowing the decline in production and thus investment levels. In the areas currently accessible for petroleum activities, the large and “easy” discoveries have been made and no major finds have occurred over the past 10 years. Future discoveries in the currently accessible areas are likely to be small, and many will be unattractive to develop. The contribution to production from the small discoveries already made and to be found is expected to be limited and short-lived. This means that, although small discoveries can be good business for some companies, they do not make a difference to total production in the long term.
Only a few new play concepts remain to be tested in the mature areas of the NCS. Should a new play be tested successfully, it could result in a wave of further discoveries and some of these could be large. The remaining new play concepts in accessible areas are more complex and contain many uncertain geological factors. In a high oil price environ-ment, several E&P companies are nevertheless willing to test them. Current licensing policy, with the gradual award of new blocks, is a slow process and prevents companies getting access to the best acreage in order to test new play concepts within a reasonable time.
The project team recommends that the government awards more acreage in the next •licensing round and holds more frequent rounds so that unproven play concepts can be tested faster. Based on the successful results of the APA rounds near existing infrastructure, it is recommended that this model be extended to all blocks in areas of the NCS currently accessible for petroleum activities.
40
4.2 A significant undiscovered resource potential remains in currently accessible areas
The NPD and the industry expect that the biggest contribution to reducing a future decline in production on the NCS will come from undiscovered resources in currently accessible and new areas (Fig 2.1). The NPD estimates that these resources total 10-36 billion boe in the North Sea, Norwegian Sea and Barents Sea. Additional undiscovered resources in the disputed zone with Russia and around Jan Mayen are not included in this estimate. It is thus possible that more oil and gas may be found than has already been produced.
A significant hydrocarbon potential is still present in areas currently accessible to the petroleum industry. These areas are in a mature exploration phase but less extensively explored than similar parts of the UKCS. Fig 4.1 compares creaming curves for the NCS and the UKCS. It shows that the UKCS is much further along its creaming curve than the NCS. Approximately 150 more discoveries have been made on the UKCS than on the NCS. These additional discoveries are mainly small, which means that the UKCS creaming curve has flattened out. The NCS creaming curve has also started to flatten out, and discoveries over the past 10 years are small. Similarly, Fig 4.2 shows that exploration well density is 2.5 times higher on the UK side of the North Sea than in the Norwegian sector. The NCS has also been opened up more gradually than the UKCS, which is reflected in the creaming curve. More time has accordingly been available for exploring the entire UKCS.
Fig 4.1: Creaming curves on the NCS and the UKCS to 2007: number of commercial discoveries versus cumulative volume added.
It is reasonable to expect that the ultimate creaming curve for the NCS will resemble the one for the UKCS, particularly in the North Sea where the geology is similar across the median line. This means that opportunities still exist in accessible areas of the NCS for making a large number of discoveries, but their average size is expected to be relatively
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41
small. Within the accessible area, only the deepwater part of the Norwegian Sea retains some potential for large discoveries, but these are high risk. Over the next 2 years, a number of exploration wells will be drilled in this area which should clarify the potential for large discoveries.
Fig 4.2: Density of exploration wells in the UK and Norwegian North Sea sectors.
4.3 The authorities have taken steps to boost exploration activity
4 .3 .1 Action by the authorities Steps to encourage exploration in the areas currently accessible for petroleum activities have been taken by the Norwegian authorities over several years. These include:
A proactive invitation to companies to enter the NCS and the creation of a pre-•qualification process.
New players now receive a 78 per cent refund of their exploration costs. This puts •entrants with no income from producing assets on the NCS in the same position as established companies which can set exploration expenditure against revenue from fields in production.
Introduction of the APA. These rounds are held yearly and provide the opportunity •for companies to bid for predefined acreage close to existing infrastructure. In most cases, this acreage has been offered before and either received no bids or was subsequently relinquished by its licensees.
Continuing to ensure a large turn-around of licensed blocks. Licence fees were •increased substantially on 1 January 2007. For retained acreage without an exploration or appraisal programme or a PDO, the fee is now NOK 120 000 per square kilometre. This change is intended to encourage future activity in licences and
North Sea hydrocarbonfairway outline for Norwayand UK C/N North Sea
Low exploration drilling density inthe Norwegian part of the HC fairway:9 exploration wells / 1000 km2
High exploration drilling density inthe UK part of the HC fairway:25 exploration wells / 1000 km2
Source: Mapinfo
42
to ensure swift relinquishment of holdings so that other companies can access the acreage concerned.
The authorities have actively encouraged the development of new technology, •including exploration methods, through financial support and the opportunity to depreciate costs against licence expenditure.
4 .3 .2 Impact of action by he authorities to date
High oil prices and official measures have encouraged many new companies to enter the NCS, raising planned activity levels (Fig 4.3).
Fig 4.3: Number of exploration and appraisal wells drilled versus oil price changes and the number of companies active on the NCS. Many of the new players focus on exploration, as reflected in part by the APA rounds (Fig 4.4). In APA 2005, for instance, around 70 per cent of the awards were made to post-2000 entrants. The majority of these were small companies. APA 2007 involved the largest-ever number of licences awarded on the NCS. These were presented to 38 companies, most of them post-2000 entrants. The new participants are not limiting their activities to the North Sea. Of the 38 companies, 30 secured licences in the Norwegian Sea. The majority of these were in the shallow-water Halten Bank area.
The authorities have awarded almost 300 new licences since 2001. Many of these require exploration wells to be drilled within 2-6 years after their award. As a result, the number of exploration wells planned on the NCS has increased sharply over the past 3 years. The number of completed exploration and appraisal wells rose from 17 in 2004 to 30 in 2007 (Fig 4.3). A further increase is expected in 2008 to an estimated 50 wells, the majority of which will be drilled by StatoilHydro. In 2009, however, the majority of the exploration wells are likely to be drilled by new players who have now secured mobile drilling rigs.
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Fig 4.4: Type of company versus number of licences awarded in the North Sea awards and the APA rounds since 1999. New companies have been heavily represented in the APA rounds since 2003.
Norway does not have a fallow acreage problem. Generally speaking, the E&P companies on the NCS are not holding onto acreage for long periods without a work programme. More than 90 per cent of the acreage awarded before 2000 has now been relinquished (Fig 4.5). The bulk of the 10 per cent retained lies in blocks close to or above producing fields. The small quantity of retained acreage outside producing fields has changed hands many times over the past 10 years.
4.4 It is too early to say that high exploration activity is sustainable and will translate into significant production and investment
There is little doubt that the increase in exploration activity will result in a larger annual number of discoveries in coming years. However, whether these measures will result in a significant contribution to production and investment levels is doubtful for the following reasons:
The discovery rate is increasing but no significant finds have been made over the past 10 yearsThe discovery rate in the more mature exploration areas of the NCS has been increasing as the licensees acquire a better understanding of the geology. The average rate for the past 10 years has been almost 50 per cent (Fig 2.6). It has been as high as 60 per cent in 2007 and so far in 2008. StatoilHydro in particular has been very successful of late in
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Fig 4.5: Total awarded licence acreage, with acreage retained and relinquished. Status in early 2008.
making discoveries close to existing fields and infrastructure. However, most of the discoveries are small and only 1 in 3 is economically attractive for development. Since the discovery of Ormen Lange in 1997, no discoveries have been made which alone contribute significantly to production replacement and the level of investment. No large development projects are in the pipeline. Those discoveries which are economic to develop mostly involve subsea wells tied back to nearby production facilities. This has led to a marked drop in the level of development investment (Fig 2.9), and that trend is expected to continue. Chapter 5 explores the challenges of encouraging the development of these small discoveries.
Future discoveries in accessible areas are expected to be small The creaming curve for the NCS suggests that the larger accumulations have been found in the areas accessible for petroleum activities. The remaining prospectivity is likely to consist of many but relatively small prospects (see Appendix 1).
Testing new play concepts is too slow The current licensing policy of gradually opening and awarding acreage was very suc-cessful during the 1980s, when the “giant” fields were discovered. With the exception of Ormen Lange, acreage awarded since the 11th round has not yielded discoveries which can make a significant contribution alone to the level of production and investment. Because accessible areas on the NCS are maturing and the large discoveries have been made, exploration has become more risky and complex. In addition, only a few untested new play concepts remain. A play is a geological model for a specific geographical area and stratigraphic zone, where a combination of geological factors allows recoverable oil or gas volumes to be proven. New plays are tested by drilling an exploration well. . Should a new concept be proven, it could yield a wave of discoveries, some of which
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could be large. The remaining untested play concepts are generally complex and involve many geological uncertainties. Since Ormen Lange, testing new plays in the deepwater area of the Norwegian Sea has not lived up to expectations. More than 10 wells have been drilled on key prospects without success. A few wells remaining to be drilled in the Norwegian Sea in 2009 and 2010 may raise expectations, but these involve a large number of geological risks. In a high oil price environment, several E&P companies are willing to test these more speculative plays, but are hindered by slow access to the best locations for testing. The current licensing policy, with the gradual award of exploration acreage, is a slow process and prevents the E&P companies from securing access to the best locations for testing within a reasonable time frame. It is therefore essential that more and larger blocks are made available to the industry as soon as possible in order to test geological concepts across a wider area. If access is too slow, the remaining potential in the accessible areas will not be realised in time to reduce the decline in production and to maintain the level of investment in the next decade. It is also important to maintain the interest of the large and medium-sized international E&P companies active on the NCS. Their capabilities include knowledge of and experi-ence with new technological applications and operations in complex areas. These companies operate in other petroleum regions and need to rank Norwegian investments against their global opportunities. Keeping these companies engaged in exploration in the accessible areas will be a challenge.
4.5 Recommendations The project team recommends that the authorities adjust their licensing policy to the level of maturity in the various parts of the currently accessible areas on the NCS. More acreage should be awarded in licensing rounds, and the latter should be held more f requently. This is the only way in which untried plays with their large associated geological uncertainties can be tested and, in the event of success, be followed up quickly and efficiently. Given the successful results of the existing APA rounds, it is recom-mended that this concept be extended to all acreage currently open to the industry on the NCS.
46
5. Building a “small field” development mindset
5.1 Chapter summary
Small field developments are becoming the norm on the NCS. No large discoveries have been made there over the past 10 years. Based on the trend in all oil and gas basins, the project team expects that the bulk of the yet-to-be-found volumes in currently accessible areas will lie in small discoveries (with recoverable volumes below 300 million boe). Although some exceptions exist, E&P companies in Norway have historically assigned a low priority to exploring for and developing “small” discoveries. Given the expected mix of size, complexity, proximity to infrastructure and so forth, many future discoveries will be unattractive to develop under the current framework. This expectation feeds into the exploration decisions made by both large and small companies. They look for materiality and tend to avoid small prospects.
The historical trend suggests that the minimum volume needed for economic develop-ment in Norway is significantly larger than on the UKCS. The project team investigated this trend, which does not seem to be related to a substantial difference in development costs between these 2 areas. Analysis suggests that the value of developments for licen-sees is significantly higher in the UK than in Norway, owing to differences in their tax regimes.
The trend towards smaller discoveries requires a change in approach by both industry and the authorities to ensure that such finds are developed and brought into production. Historically, the industry on the NCS has been accustomed to developing large fields with high levels of investment. That has also stimulated the development of new technology. A number of small fields have now been successfully developed by oil companies which own nearby infrastructure, helped by high oil prices. To encourage this trend, industry and the authorities must continue to address the new challenges presented by small developments. A large number of platforms in the North Sea will be retired before 2025, so only a narrow time window is available to explore for and develop small discoveries dependent on being tied back to existing offshore facilities.
The project team sees a potential scope for adding up to 2 billion boe to the base produc-tion forecast before 2040 if the right conditions are achieved for small future discoveries. This corresponds to one field the size of Ormen Lange, but spread over 30-40 small discoveries. To realise this potential, the following action is recommended:
The industry should place more emphasis on finding simple technical and •commercial solutions for developing small fields more cost-effectively.
The authorities need to establish a contingency plan which can be used if exploration •for small prospects and development of small fields fail to pick up swiftly in relation to the remaining production life of existing infrastructure. This plan should include framework conditions to improve the economic attractiveness of developing small discoveries.
The industry must collectively share information with Gassco about future •exploration and development activities in relevant areas and the uncertainties relating
47
to these. This could include information on the chances of making a discovery and uncertainty in development timing. That will improve Gassco’s ability to ensure timely access to infrastructure and carbon dioxide management in potential future developments.
5.2 Most future discoveries are expected to be small
No new discoveries have been made over the past 10 years which can lead to large development projects with significant investment. Remaining yet-to-be-found resources in the areas currently accessible for exploration are expected to consist of many but relatively small prospects (Fig 5.1). However, observations indicate a limited appetite to explore for these small prospects. Signals from a significant number of large and small companies active in exploration on the NCS suggest that many of the prospects identified are small and economically unattractive for development should drilling result in a discovery. These small prospects are therefore not being chosen as an exploration target. The smaller companies in particular need to be successful in making discoveries which are economic to develop in order to stay in business. It also takes similar human resources to develop an exploration proposal for both small and large prospects. Where personnel are a constraint, therefore, most E&P companies will prefer to explore only for sizable prospects. If companies are not motivated to explore for the small prospects, a substantial share of the yet-to-be-found resources in the currently accessible areas will remain in the ground.
The project team’s predictions from its scenario modelling work (see Appendix 1) indicate that some 60 discoveries smaller than 40 million boe and another 30 of 40-320 million boe remain to be found in the currently accessible areas (Fig 5.1). These numbers are expected to be 50 per cent higher if the entire NCS is considered.
Fig 5.1: Historical and predicted discoveries versus discovery size in currently accessible areas.
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A significant percentage of these discoveries will be unattractive for development, particularly those at a considerable distance from existing infrastructure. The value of developing discoveries with small recoverable volumes is relatively low compared with larger discoveries. Their development is therefore not always considered economically attractive. The difference between “economic” and “uneconomic” is not determined by volume alone, but by a combination of many factors (such as water depth, complexity, costs, distance to infrastructure and so forth). The oil price also plays a key role in deci-sion-making. It is difficult to determine a single cut-off volume. The team has therefore assumed a percentage for yet-to-be-found discoveries in each field size class which are expected to be economic for development at an oil price between USD 60 and USD 100 per barrel and with the Norwegian tax regime (Fig 5.6 and appendix 1).
5.3 E&P companies in Norway have historically tended not to explore for and develop small discoveries
Fig 5.2 provides a historical picture of the size of fields developed on UKCS and NCS versus water depth. The figure shows, on a statistical basis, that a much bigger number of small discoveries have been developed on the UKCS than on the NCS. Some develop-ments in both the UK and Norway involve clusters of smaller finds or have been tied back to existing fields and are thus included in the latter. Examples include Gannet on the UKCS and Oseberg South on the NCS. However, the majority are single developments.
Fig 5.2: Size of fields historically developed on the UKCS and the NCS versus water depth. All fields developed up to the end of 2007 are included.
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The data include projects at a wide range of companies with different decision-making criteria, a broad time span, fields with varying challenges and degrees of complexity, periods of low and high oil prices, and differing tax regimes.
Statistically, however, the difference seems clear. The average minimum volume for field development in similar water depths is 3-6 times higher on the NCS than on the UKCS. Generally speaking, there accordingly seems to have been little incentive historically to develop fields in shallow waters with recoverable reserves below 60-100 million boe.
Over the past 2 years, a positive trend has been seen in the number of small discoveries reaching the PDO stage (Fig 5.3). Development of the smallest discoveries has been enabled because they are owned by the operators of nearby infrastructure, mainly Sta-toilHydro. Most new developments progressed over the past 2 years are in the 50-100 million boe range.
Fig 5.3: Discoveries smaller than 100 million boe which have reached the PDO stage and are in the development phase in 2006-2008.
Differences in development costs do not explain why larger volumes are required for an investment decision on the NCS than on the UKCSDevelopment costs have been the focus of several studies and initiatives over the past 15 years. These have sought to determine whether costs are higher on the NCS than in other offshore regions and whether local regulations on working practices boost costs.
Apart from drilling costs, however, it has been impossible for the project team to identify and find hard evidence for significant differences in development costs between the UK
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and Norway. The cost report prepared by KonKraft in 2003-2004 named drilling as one area where costs were significantly higher than on the UKCS. Generally speaking, this conclusion remains valid. The project team interviewed a number of companies on the cost of drilling, and responses indicated that the average is 20-30 per cent greater in Norway than in the UK, owing to higher rig rates and additional capex for modifications required if a rig is to operate on the NCS.
Overall average development costs are perceived to be higher in Norway than on the UKCS, but this is based largely on anecdotal evidence.
The NCS may have a tradition of more custom-built development concepts compared •with the UKCS, where wider use is made of standardised concepts.
A greater prevalence of unstaffed platforms in shallow water on the Danish •continental shelf and in the southern UKCS may give the impression that costs are higher in Norway.
Materials with higher specifications and more costly concepts are selected on the •NCS by comparison with the UKCS. The drivers for such choices are lower lifecycle costs (such as reduced modification and maintenance expenditures at a later stage of the field’s production life) and, in some cases, standardisation to reduce logistics cost.
It is difficult to demonstrate that cost differences underlie the differing appetite to develop small finds on the UKCS compared with the NCS. However, this does not reduce the pressure on the industry to find creative ways of reducing costs and thereby enabling developments which would otherwise not have happened.
Lessons are to be learnt from some UK operators who have started using a portfolio approach to developing small discoveries. Using standardised development concepts and processes, standard equipment and a batch drilling approach, these operators are develop-ing such fields in parallel and thus more quickly and cost-effectively. A similar approach could also be used by operators on the NCS with a portfolio of undeveloped discoveries.
In the late 1990s, the UKCS contained a large portfolio of undeveloped discoveries. Many of these were marginal and could not be developed under the traditional cost and risk-sharing regime. The UK government initiated a fallow discovery initiative, facilitated by a workgroup called Logic, to encourage the operators to accelerate devel-opment of marginal discoveries or else sell out or relinquish. Initiatives taken included new commercial collaboration models between service companies and/or operators. An example of such a collaboration model was used for the Beauly development. This field, estimated to contain 3 million boe, was developed with a single horizontal well drilled from a subsea location and tied back about 5 kilometres to the Balmoral floating produc-tion vessel.
The consortium adopted the following principles:
The work was to be performed on a pure cost basis without any profit and overhead •in order to reduce the initial cost to a minimum.
All operations were to be managed by an integrated team to maximise cost synergy. •
51
The consortium was to be paid in accordance with an agreed schedule to ensure a •healthy cash flow.
The consortium’s profit was to be an agreed share of the project performance •(development cost and field’s true production performance).
Compared with a traditional field development model, where each sub-contractor draws up a budget for its own overhead and profit, independent of possible synergies and opti-misation during the development, this model gave a significantly lower initial entrance cost for the development. In the Beauly case, initial development costs were reduced by 20-40 per cent. A collaboration model like this also encourages partners to find optimal field development solutions, such as reusing equipment and tailoring the development in accordance with functional requirements rather than “company best practice”. This has further reduced costs.
Analysis suggests that tax regime differences make similar discoveries twice as valu-able in the UK as in NorwayThe team compared the British and Norwegian tax regimes by taking all UK fields smaller than 200 million boe which have been or are being developed. Each of these was valued under the current UK and Norwegian tax regimes using Wood Mackenzie’s tax calculation tool.
The reduction in cash flow after tax (net present value – NPV) for these fields under a Norwegian tax regime rather than British fiscal conditions (Fig 5.4) shows that these developments have significantly greater value under the current UK fiscal framework, with the NPV generally twice as high as with the Norwegian tax regime. A number of discoveries developed on the UKCS would have had a negative NPV on the NCS.
This illustrates that, if a company requires a given cash flow after tax (or risked value, taking account of exploration well cost) for a decision to explore or develop a discovery, the minimum volume required to meet that decision criterion will be significantly higher under Norwegian fiscal terms. On the NCS, therefore, a significant volume of hydrocarbons in small discoveries will potentially be left in the ground.
One caveat is that the decisions to develop discoveries on the UKCS were taken in the past, when the British fiscal regime was even more attractive than the Norwegian. Lower oil prices at that earlier time would have enlarged the difference.
5.4 An opportunity still exists to add to yet-to-be-found resources by making development of small discoveries more attractive
If companies could be encourage to explore for and develop smaller discoveries by reducing the economic cut-off volume, significant additional volumes could be added to the production forecast.
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Fig 5.4: Reduction in the NPV for small developments on the UKCS using the Norwegian tax regime rather than the British.
5 .4 .1 Some early signs of success have been seen, but progress is far from secure
Exploration activity on the NCS is predicted to pick up significantly over the next few years. Most of the acreage near existing infrastructure has been awarded for exploration through the APA process. The authorities have been successful in encouraging new play-ers to explore on the NCS by creating exploration incentives for new entrants. Some of these new players may eventually explore for smaller prospects. Small players are under increasing pressure to achieve material results. The global financial crisis has made it harder to secure financing. Investors are less willing to take bets on companies with little or no production and reserves.
The increase in exploration will result in a larger annual number of discoveries. A considerable proportion of these are unlikely to be developed (see Appendix 4 and Fig 5.6). Unless exploring for and developing small, marginal opportunities are made more attractive, the increased exploration activity may simply create a large inventory of small prospects which remain undrilled or discoveries left undeveloped.
Higher oil prices could help to stimulate activity, but the question is whether that would yield the desired results. The NCS is in competition with other provinces, so higher prices are not the only factor which will influence its economic attractiveness. Companies with an international portfolio may see greater value in opportunities outside Norway.
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5 .4 .2 Exploring for and developing small prospects which depend on existing infrastructure is a matter of urgency, especially in the North Sea
Another risk is that insufficient time will be available for some companies to respond and execute developments before infrastructure is abandoned. If their exploration is success-ful, they will need to acquire personnel and capabilities quickly to ensure that they can deliver before the infrastructure closes down. Most small discoveries will be developed through either subsea tiebacks to or wells from existing platforms. As the NCS becomes more mature, the number of fields approaching abandonment is rising. Some 36 of 58 fields in the North Sea are expected to be shut down by 2025 (Fig 5.5). The project team does not expect small discoveries to extend the life of existing fields significantly. At best, they will reduce unit operating costs for the platforms. This creates a narrow time window for implementing measures which would make a larger proportion of the small and currently uneconomic discoveries attractive for development.
Fig 5.5: Expected timing of production cessation for fields on the NCS as a whole and in the North Sea.
5 .4 .3 The potential price for reducing the minimum volume required for eco-nomic development
If the economic cut-off value could be reduced to bring it more in line with the UKCS, exploring for and – in the event of success – developing a large number of small discoveries would become economically attractive. That could make more small prospects attractive exploration targets.
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Fig 5.6: Percentage of yet-to-be-found discoveries, assumed by the project team to be uneconomic under current conditions, which would become economic for development if the cut-off value were reduced, and which would remain uneconomic.
The project team did not assume a single cut-off value for economic development. Instead, the project reference scenario (see Appendix 1) assumes that 20 and 40 per cent of fields in size classes 0-40 and 40-320 million boe respectively will be developed under current economic conditions. To illustrate the significance of reducing the minimum volume required for economic development, an alternative scenario has been run in which the proportion developed is doubled to 40 per cent for field size classes 0-40 million boe and to 90 per cent for field size classes 40-320 million boe (Fig 5.6). This could represent an additional production volume of up to about 2 billion boe by 2040, as shown in Fig 5.7. That represents the volume in one field the size of Ormen Lange, but spread over 30-40 small fields. The level of activity would also increase significantly, and investment could consequently rise by some NOK 200-300 billion before 2040 – and particularly in 2015-2025 (Fig 5.8). In addition, the current discovery portfolio would benefit from reducing the minimum volume for economic development. The project team has included some 0.6 billion boe in its estimate of contingent resources for discoveries currently unlikely to be developed or under evaluation (see Appendix 4).
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Fig 5.7: Production forecast for the NCS. The project team’s view of the potential to increase production if developing small fields can be made more attractive.
Fig 5.8: Capex forecast. The project team’s view of potential additional investment if developing small fields can be made attractive.
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5.5 Recommendations
The authorities and the OLF should investigate contingency measures to improve the economic attractiveness of developing small discoveries As mentioned above, high oil prices may reduce the volumes needed for an economic development. However, periods of sustained high oil prices also experience significant increases in costs as a result of strong demand for services and materials. The project team recommends that the authorities establish a contingency plan to be used if explora-tion for small prospects and the development of small discoveries do not pick up swiftly enough in relation to the remaining production life of existing infrastructure. Such measures could include the adoption of a new set of depreciation rules by the govern-ment. Any potential solutions should be applied in sufficient time to address the limited window for field tieback to aging infrastructure in the North Sea. A good time would be no later than 2010, when the project team expects that the results of exploration cam-paigns by new players in the North Sea and in deep waters off mid-Norway should be available. The need for incentives for small discoveries can then be better assessed. Any such incentives must be systematic rather than ad-hoc to achieve the required effect on exploration for these small fields.
The project team proposes the creation of a discussion forum with representation from the authorities and the industry/OLF to share ideas on possible approaches which could have a positive effect on the development of small discoveries, and to resolve some of the issues around the portfolio approach and industry incentives.
The industry must consider cost-effective ways to develop small discoveries The industry can affect economic attractiveness by changing its mindset from big discov-eries to small developments. It has been accustomed to large developments on the NCS, which have not only generated high levels of investment but also justified innovative approaches and the development and application of new technology. The large discover-ies have now mostly been developed. The small fields faced today and in the future call for a different set of capabilities, simple solutions and standardisation, and creative commercial arrangements to ensure more cost-effective development.
The portfolio approach to the development of small discoveries applied by some opera-tors in the UK (see chapter 5.3), for example, could also be adopted by operators on the NCS with a portfolio of undeveloped discoveries. However, this will be more compli-cated for Norwegian operators because there is seldom a single licensee. Each discovery often involves a number of partners, and the composition of these joint ventures differs between discoveries. That will inevitably require a number of important commercial issues to be resolved first, which can make the process tedious and lengthy. A portfolio approach to small field development could be used in combination with a similar solu-tion for exploration. The remaining small prospects in parts of a mature area could be explored by drilling a string of exploration wells. Once a sufficient combined volume has been proven, it can be developed through a cluster of activities involving collaboration between the various operators and service providers. In this way, synergy savings can be achieved. Such an approach requires that the government awards more acreage in the APA rounds.
57
An incentive-based model or similar solutions for developing new fields could also be applied on the NCS. However, the current Norwegian tax regime imposes some limita-tions on service companies linking their profits directly to the net result of a field. It is therefore recommended that the OLF discusses what kinds of incentive schemes are acceptable to the Norwegian authorities.
Support Gassco in planning infrastructureGassco prepares plans for future infrastructure to avoid delays in developing new discov-eries owing to a lack of ullage in existing infrastructure or insufficient management of carbon dioxide removal from natural gas. Several communication channels exist between Gassco and the gas shippers and operators of both existing fields and undeveloped discoveries for sharing information about requirements for future pipeline capacity and carbon dioxide content in existing fields and discoveries. However, it is also very impor-tant that Gassco has access to information about future area development plans and the uncertainties related to these. The company needs, for example, an overview of expecta-tions for and timing of exploration and appraisal activities in a particular area, when the key decision points will occur, what the main uncertainties are in taking the decisions and so forth. Gassco currently gets this information separately from each company. However, Gassco would find it more useful to get plans for specific areas and possible outcome scenarios from the relevant operators jointly rather than individually. This is particularly important in areas where new large gas volumes are likely. The project team proposes the creation of a process to facilitate the sharing of information between relevant E&P companies about exploration and development plans for specific areas of the NCS, and for these data then to be communicated jointly to Gassco.
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6. Opening new areas
6.1 Chapter summary
As mentioned in chapters 4 and 5, no large discoveries have been made over the past 10 years and future discoveries in the accessible areas are likely to be mainly small even though exceptions may exist. Making larger discoveries is essential to ensure that the production decline is gradual and that the long-term level of investment is healthy. Areas currently not open to the petroleum industry are expected to offer the highest potential for such finds.
The project team has modelled the impact of exploration success in both accessible and unopened areas on production and investment levels. Based on an assessment of discov-eries made in past years and the exploration potential of currently accessible areas, this study predicts a substantial fall in production beyond 2015. If no new areas of the NCS are opened for petroleum activities, production will have fallen to around 1.6 million boe/d – a third of today’s level – by 2030 or thereabouts. A dramatic fall in investment is already expected from around 2012-15. If no new areas are opened, the project team expects the level of investment to fall to about 20 per cent of the current level in 2030, or roughly NOK 15-20 billion. That would represent a dramatic downscaling of activity on the NCS compared with today. The project team’s recommendations for maximising output in currently accessible areas could reduce the production decline over the next 15 years, but will not have a significant impact beyond 2025. If new areas are not continu-ally opened up, starting as soon as possible, it is doubtful whether activity will be suf-ficient to sustain a robust Norwegian petroleum industry for much longer.
The project team therefore recommends that areas not yet accessible for petroleum activi-ties are opened gradually and continuously. It takes at least 15 years on average between the award of a licence and first production from the area concerned. So even if licences in new areas are awarded in 2012, the earliest date that successful exploration will have a significant impact is 2022 for the level of investment and 2025 for production.
It is in Norway’s interests to minimise any delay for the following reasons:
The longer the period of low activity lasts, the harder it will be to retain the •capabilities and critical mass vital for a long-term and viable petroleum industry
A lengthy fall in gas supplies from Norway to European energy markets may lead to •the substitution of gas by other, more carbon-rich energy sources such as coal, which have a greater environmental impact. This trend would be hard to reverse in order to return to more environment-friendly gas.
The industry believes that Nordland VI and VII plus Troms II have a big potential for larger discoveries. The geology in these areas is known, and similar geological structures lie to the south in the Halten Bank region. In other areas not yet accessible, such as Bar-ents Sea North and South-West, around Jan Mayen and the disputed zone with Russia, the undiscovered resource potential is more uncertain. A better geological understanding of these areas at an early stage would improve planning for Norway’s industrial future and the continued role of the country as a gas provider. It would also allow the govern-
59
ment to make better decisions on future licensing of these areas and to focus on those with the biggest potential for discovering new larger fields. The project team recognises that the Norwegian government currently lacks full decision-making power over these areas, because political issues with other countries await resolution.
The project team recommends that:
Nordland VI and VII plus Troms II are opened in 2012. Geological conditions are •better known here than in other currently unopened areas, so the most logical move would be to open them first.
The authorities should consider a radically different process for exploring Barents •Sea North, Jan Mayen and the disputed zone with Russia. Over the next 10 years, they and the industry should cooperate to obtain more geological information in these areas and thereby reduce uncertainties before making decisions on licensing these areas.
The NPD should make geological data from areas not yet opened for petroleum •activities available to the industry.
6.2 Production and investment levels are predicted to decline in existing areas
Testing new plays with the potential for large discoveries has failed to live up to expecta-tions since 1997. Drilling in Nordland VI and VII, Troms II and parts of the Barents Sea has been constrained by the government’s decision to keep these areas closed for petro-leum activity (Fig 2.6). A significant resource potential therefore remains unavailable for testing by the oil companies. The project team and the industry expect that the biggest potential for large discoveries significant for total production on the NCS will be in areas currently closed for exploration. The government is due to reassess the entire manage-ment plan for the Barents Sea and the sea areas off Lofoten and Vesterålen in 2010. Since this plan was approved in 2006, many issues have been addressed in order to close identified knowledge gaps. Based in part on new information, the government will decide on opening areas in Nordland VI and VII, Troms II and the Barents Sea.
6.3 Opening new areas can have a significant impact on long-term production and investment levels
The project team has modelled the impact of exploration success in accessible and currently inaccessible areas on production and investment levels. Since no data were available on the split between accessible and currently inaccessible areas, the project team made its own assessment (see Appendix 1). Production and investment forecasts for reserves, future activities on existing fields and the development of discoveries are taken from the NPD and the MPE. The project team has analysed the impact on future production of opening and not opening a number of new areas (Fig 6.1). This analysis considered an opening of Nordland VI and VII plus Troms II. Opening the Barents Sea north of Bear Island instead of these areas could have a similar impact. Fig 6.2 illustrates the impact on future investment levels.
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If new areas are not opened for exploration, no further discoveries able to reduce the expected sharp decline in production on the NCS are likely to made. The result would be a probable decline in production below 1.6 million boe/d after 2030. Currently foresee-able investment on the NCS would be likely to fall rapidly from 2012 onwards, to about 60 per cent of the current level in 2020 and 20 per cent by 2030.
Opening Nordland VI and VII plus Troms II in 2012 could have a significant impact on production and investment levels from 2022 until long after 2030. Based on the assump-tion that an undiscovered resource base of 3.4 billion boe in Nordland VI and VII plus Troms II (see Appendix 1) will be made available to the industry from 2012, potential development opportunities from these areas could represent the investment of NOK 200-250 billion up to 2040. This could yield some 200 000 boe/d in additional produc-tion from 2025 onwards, rising to about 350 000 boe/d by 2030. That would represent a significant proportion of output from the NCS after 2030, perhaps in the order of 30-60 per cent. Some 30-60 per cent of investment after 2030 is also expected to come from field developments in these new areas.
Fig 6.1: NCS production forecast. The project team’s view of output from new discov-eries following an opening of Nordland VI and VII plus Troms II compared with no opening of new areas.
It should be noted that these analyses incorporate significant uncertainties. The scenarios described above are based on a risked resource expectation of 3.4 billion boe. If explo-ration in Nordland VI and VII plus Troms II proves highly successful, however, the resource base may become significantly larger. A “high case” resource estimate of 6 bil-lion boe has been assessed for these areas. Exploration results may also be disappointing, in which case lower production and investment must be attributed to these areas. If other new regions – such as Barents Sea North and South-West – are opened for petroleum
ReservesContingent resources in existing fieldsContingent resources in discoveries
New discoveries in open areasNew discoveries in Nordland VI, VII, Troms II
0
1
2
3
4
5
2008 2012 2016 2020 2024 2028 2032 2036 2040
Pro
du
ctio
n (
mill
ion
bo
e/d
)
Source: Forecast for reserves and contingent resources are NPD data, forecast for new discoveries is basedon project team´s modelling
61
activities during the next decade, the production and investment contribution from new areas after 2030 can be doubled.
Fig 6.2: NCS capital investment forecast. The project team’s view of investment (ex-cluding pipelines and land-based facilities) from new discoveries following an opening of Nordland VI and VII plus Troms II, compared with opening no new areas.
6.4 Why a decision in 2010 to open new areas is urgent
If the need to avoid a steep decline in the level of activity is accepted, new areas should be opened no later than 2012. The average lead time between a discovery and first pro-duction on the NCS has historically been about 14 years (Fig A1.4). Historical lead times from licence award to first production have averaged close to 20 years (Fig 6.3). For larger stand-alone developments, the average lead time from licence award is roughly 15 years. This illustrates that it may take 15-20 years from a decision to open new areas to the start of possible production. During that period, impact assessments must be carried out, licensing rounds initiated, acreage awarded, exploration wells drilled and possible discoveries developed.
Recent technology advances have reduced the time taken from discovery to first produc-tion for subsea developments. However, projects in areas currently closed for petroleum activity are unlikely to achieve significantly shorter lead times. These areas are remote from existing infrastructure. Sufficient volumes will have to be found to justify additional installations.
ReservesContingent resources in existing fieldsContingent resources in discoveries
New discoveries in open areasNew discoveries in Nordland VI, VII, Troms II
100
90
80
70
60
50
40
30
20
10
0
2008 2012 2016 2020 2024 2028 2032 2036 2040
Cap
ex (
bill
ion
NO
K)
Source: Forecast for reserves and contingent resources are NPD data, forecast for new discoveries is basedon project team´s modelling
62
Fig 6.3: Historical NCS data on lead times between licence award and start of production for platform/floating production systems and for subsea tie-backs/extended reach wells.
6.5 Maintaining a robust petroleum industry
Maintaining a sustainable level of Norwegian petroleum activity for as long as possible is assumed to be a key objective, along with avoiding an erosion of the technological expertise required for future development of a gradually maturing petroleum industry.
If significant new areas are not opened soon after 2010, a risk exists that some important technology clusters in Norway will be eroded – either closed down or moved to other parts of the world. These clusters may focus, for example, on challenging new field developments, such as major projects in deep water or ones in remote or environmentally challenging areas. Once eroded, these clusters may be hard to rebuild and the technology would then have to be sought elsewhere in the world.
A sustainable long-term petroleum industry is very important for maintaining the interna-tional position of the Norwegian oil service industry. The KonKraft report on internation-alisation notes that the NCS has been a breeding ground for innovation and technology development. This has allowed the Norwegian service sector to develop world-leading clusters. A healthy Norwegian service industry which remains capable of competing internationally requires a base-load level of activity on the NCS to continue building up its expertise.
As exploration and production activities move into Arctic regions, the technical chal-lenges presented by environmentally sound development and operation in these sensitive areas will provide valuable experience and further international opportunities for Norwe-gian technology clusters. By focusing from an early stage on challenges in areas such as Nordland VI and VII, Troms II and Barents Sea South, Norway could place itself at the forefront of such technology advances.
01 10 100 1000 10000
5
10
15
20
25
30
35
40
45
50
Field size (million boe)
Lea
d t
ime
(yea
rs)
Platform / FPSO Subsea / extended reach wells
Aver.: 24.0
Aver.: 15.5
Average all: 19.6
Source: Wood Mackenzie data
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Unless they are given interesting opportunities in Norway, some of the larger E&P companies could turn their exploration attention elsewhere. Their focus is on relatively substantial exploration prospects. These companies often have the expertise and technol-ogy to develop resources safely in sensitive and technically challenging areas.
Oil and gas are highly likely to continue playing a very important role in global energy supply for the foreseeable future. The KonKraft report on Norway as an energy nation points out that hydrocarbon output on the NCS is among the cleanest in the world. Continued production and export of hydrocarbons, and particularly the supply of gas to Europe, will have a positive impact on the environmental challenges facing the planet. A reduction in gas deliveries from Norway would be replaced to a large extent by energy produced from coal. This trend would be hard to reverse by returning to the use of more environment-friendly gas.
6.6 Recommendations
Opening new areas for petroleum activitiesMuch of the currently inaccessible areas on the NCS should be opened and awarded shortly after 2012 to ensure sustainable activity levels. Nordland VI and VII plus Troms II are the most logical areas to open first. The available information on the geology of Nordland VI and VII has given the industry confidence in the significant exploration potential of this region. The geology of these areas is known and analogue formations occur further south on the Halten Bank. The areas can also be opened relatively soon. The industry and the authorities should engage in a discussion about how to pursue activities in a manner which minimises their impact on the environment and on other industries. It would be helpful if the authorities can set timely targets and standards for the environmental challenges in the areas. This would allow the industry to develop technologies in good time and to demonstrate that it can conduct its activities in a respon-sible way.
The authorities should consider a radically different licensing policy for new areas Estimates for yet-to-be-found resources on the NCS contain many unknowns. That leaves a wide uncertainty range. Current licensing policy, with the gradual award of licences and the retention of several areas closed for petroleum activities, have largely contributed to this. After almost 40 years of petroleum activity on the NCS, the range of the undiscov-ered resource potential in such areas as the North Sea and the Halten Bank has narrowed. However, the resource potential and the relative proportions of gas and oil are virtually unknown in vast areas such as Troms, Barents Sea North and South-West, Jan Mayen and the disputed zone with Russia. The project team recognises that the government does not currently possess full decision-making power over some of these areas because political issues with other countries still await resolution. Its scenario modelling has assumed that these areas will not be opened for petroleum activities in the next decade.
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Over the coming 10 years, however, it will be very important for the future of Norway as a substantial energy supplier to secure more understanding of such issues as:
which areas have the biggest undiscovered resource potential?•
does this potential consist mainly of oil or gas?•
could another Shtokman field exist or will future discoveries be small? •
Answers to these questions will have an impact on government and industry decision-making. Examples include:
How long will Norway retain a potential for a healthy petroleum industry? What •more should be done to secure such an industry?
What can Norway as an energy nation contribute to world petroleum supply in the •longer term? Will this be mainly oil, or more clean gas which could reduce the use of coal? Could current gas supply contracts be extended?
Which region(s) of Norway has(have) the biggest potential to become another core •area for the petroleum industry in the medium to long term? Does it(they) have the necessary infrastructure in place? What are the employment considerations in these areas?
On what basis will E&P and service companies plan their long-term future in •Norway?
Should actual undiscovered resources prove disappointing, what are Norway’s plans •for the future, both nationally and internationally?
What environmental challenges are presented by new areas with a significant •hydrocarbon potential? What standards and regulations would be needed in order to operate in these areas? What technologies need developing?
If current licensing policy is retained, the remaining hydrocarbon resource potential on the NCS will continue to be highly uncertain and it will not be possible to answer the above questions for decades to come.
The project team therefore proposes that the government should consider a radically different structure for giving access to new exploration acreage in the various parts of the Barents Sea. This new approach is based on initially gathering information to increase the level of confidence in the undiscovered resource potential before the government makes its decisions. The main objectives of such an approach would be to minimise exploration activity in frontier areas by focusing exploration efforts on the areas with the biggest potential and thereby increase the chance that these exploration efforts will be success-ful. It would also enable the industry and the authorities to start preparing to address the environmental challenges, and allow official environmental standards to be set at an early stage.
This approach should be applied to those areas with a high degree of uncertainty con-cerning undiscovered resources – Barents Sea North and South-West, the disputed zone with Russia and Jan Mayen. Since the E&P companies have reasons to be confident about the resource estimates and potential for major developments in Nordland VI and VII
65
plus Troms II, these areas should be opened now and excluded from this recommended licensing structure.
An example of such a change in structure could be the formation of a joint venture by the authorities and a number of E&P companies which would initially gather key informa-tion on the undiscovered resource potential. This could include collecting and sharing data, joint basin studies and possibly joint drilling of wells. The objectives would be to increase the level of confidence in the resource potential and to make recommendations on which areas have the biggest potential for successful exploration. These findings would put the government in a better position to determine future licensing policy for the areas concerned. That could include opening parts of the most prolific areas for petroleum activity and the timing of prequalification and licensing rounds. The authori-ties would also have the option of imposing special terms in the bidding process for the timing and coordination of development and production.
The licensing stage should be open to all E&P companies prequalified to operate in these areas, but the authorities could consider giving some preferential rights to those compa-nies which participate and invest in the initial stage. A model similar to the one above is currently being used in north-east Greenland. A number of large international E&P players have formed a collaboration group with the Greenland state oil company aimed at joint evaluation of the exploration potential on the continental shelf in this region, which is covered in pack ice for most of the year.
The objective of the group is to achieve full understanding of where the hydrocarbon areas with the biggest potential are located, so that future exploration efforts are focused on a narrower region and have a greater chance of success. Another driver for the col-laboration is a desire by the E&P companies and the Greenland authorities to be well prepared for the environmental challenges of further petroleum activities in the area. The collaboration group will finance the joint work programme to identify the areas with the biggest potential. The Greenland authorities would then consider prequalification and licensing rounds for this acreage. Preferential rights for participants in the group are currently being discussed with the Greenland authorities.
The NPD must share available data on currently inaccessible areas with the industry A large amount of seismic data has been acquired by the NPD in areas not accessible to the industry at present. Only a limited part of this information has been made available to the industry. Giving companies access to all seismic and other data acquired offers considerable added value. It would provide the authorities with a range of different views about the potential of these areas. Access would also reduce the industry’s need to gather data.
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7. Industry is adapting to the sharp rise in activity
7.1 Chapter summary
The business environment on the NCS is changing rapidly. As mentioned in chapter 2, these waters have never witnessed such a rapid growth in the level of activity as they have over the past 2-3 years. Many new players have entered the NCS. In addition, high oil prices have extended the production life of fields.
Companies are quickly adapting to the rapid growth, but are nevertheless experiencing a delay in planned activity for a number of reasons:
a shortage of mobile drilling rigs •declining performance on well delivery •a growing need for work on aging platforms to keep these facilities up and •running, which takes priority over activities to increase production.
The deferment of production-enhancing activities has resulted in output delays.
These are transitional issues. Over the past year, the industry has acted to identify the causes of the constraints. Many measures have been put in place and their effects can already be seen. The project team expects the issues to be resolved over the next 2-3 years. A number of new rigs are due to arrive on the NCS. Several large subsea development projects will have been completed by 2012, which will also free up rig capacity. The industry has put measures in place to improve well delivery performance. Companies are also working hard to resolve personnel issues.
To manage the sharp growth in activity even better and to adapt more quickly to the changing business environment, the project team recommends the following:
The authorities must review the regulations to see whether more room exists for •flexibility without compromising safety. The PSA must collaborate with its British counterpart, the HSE, on better •harmonisation of the interpretation of requirements for drilling rig prequalification across the North Sea. This could help alleviate the tight mobile rig market.
7.2 Coping with change
7 .2 .1 Declining performance for well delivery
The time and cost of delivering a well has significantly increased on the NCS in recent years. Petoro carried out a study in 2007 on the portfolio it manages for the State’s Direct Financial Interest (SDFI). This showed that the delivery time for a well is 60 per cent higher on average than planned, and costs have increased accordingly. In the same year, ExxonMobil carried out a similar study for its operated and non-operated portfolio. This found that the average drilling time, and thus the cost, of development wells was typically 50 per cent higher than planned. The decline in well delivery is also occurring in other petroleum regions of the world.
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In interviews with the industry, the following reasons were given to the project team for the decline in well delivery performance:
Operators are drilling more complex wells, particularly on maturing fields. •
The risks of equipment failure during drilling and completion of complex wells are •not always taken properly into account during the planning phase. This can lead to unnecessary over-caution in the planning phase, with slower drilling and the addition of a safety margin (increasing circulation time, for example) in a bid to mitigate risk.
Demand for rigs is very high and units are accordingly used longer and harder. That •puts pressure on preventive maintenance. Deferring this for too long can result in rig shutdowns, with the unit sometimes needing to be moved off location for full repairs.
With new rigs coming to the NCS, competition over experienced drilling personnel •is tough for both new and existing units. The drilling contractors are fully focused on recruiting experienced crew.
A Petoro study of the SDFI portfolio found that the volume added by production •wells is typically 30 per cent lower than predicted. Reasons for this could be a shortage of experienced reservoir characterisation specialists, and thereby a limited understanding of reservoir risks. The result is in a reduction in ultimate recovery unless additional wells can be drilled.
The increased delivery time for wells is causing delays to other well activities and has a knock-on effect on subsequent wells in a sequence. This often means re-planning of wells, finding a new time when the rig can drill the well and, in some cases, negotiating new rig contracts. That puts even more pressure on the workforce and on rig availability.
The operators have recognised the challenges posed by well delivery performance, and are addressing them by focusing on the following areas for improvement:
Better risk-based planning, in which all relevant disciplines and key service providers •participate.
Identification of complex wells. One example is assigning a complexity index •to all wells, which can then be used to derive a subset of requirements, rules and procedures. Such classification will also help determine whether to drill a complex well or one or more simple wells.
The more complex the well, the more expertise the workforce needs to possess, both •on land and offshore.
A rigorous process of reviewing and challenging well design must be pursued at •functional management level.
Arrangements must be made for a number of experienced crew to be available during •each shift to train and share expertise.
Make optimum use of drilling units through integrated interdisciplinary planning, •including contingency planning. Other activities – such as data collection or short-duration well interventions – can be carried out while waiting on repairs or for equipment to arrive. The service industry could also improve its activity planning during shutdowns.
Operators and service providers must jointly pay more attention to defining •
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and implementing improvements in drilling and completion, such as upfront geomechanical modelling and real-time follow-up in complex reservoirs.
Operators could make more frequent use of a batch portfolio approach to drilling •and completing complex wells. Repeating the same operation builds up experience, ensuring that complex wells become standard.
7.2.2 Shortage of qualified mobile drilling rigs
Fig 7.1: The number of exploration, appraisal, development and injection wells drilled each year on the NCS.
A larger number of wells have been drilled on the NCS over the past 2-3 years, repre-senting a considerable increase from a low point in 2004 (Fig 7.1). A further increase in drilling activity is expected. High oil prices until mid-2008, exploration incentives, APA rounds and the arrival of new players have boosted exploration drilling and further development of existing fields. The number of subsea production fields has also increased significantly. This has generated a rapid rise in demand for mobile drilling rigs and intervention vessels.
Demand in 2006-2007 far exceeded the supply of mobile rigs and intervention vessels prequalified to operate in deeper water and rough weather conditions on the NCS. This has resulted in full utilisation of the current rig fleet and high rates. Many companies have had to defer production enhancement activities, exploration wells, well interven-tions and water injection activities. Combined with a decline in well delivery perform-ance, the outcome has been a large backlog of drilling activities.
0
50
100
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250
2000 2001 2002 2003 2004 2005 2006 2007
Nu
mb
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f w
ells
per
yea
r
Producer
Source: IHS data
Injector Appraisal Exploration
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Fig 7.2: Global demand versus supply of mobile drilling rigs. Demand for mobile drilling rigs both worldwide and on the NCS far exceeds supply.
This backlog is expected to build up further in coming years. It will take longer to adapt to the global shortage of mobile rigs in Norway. A lot of the newly built rigs are not being deployed to the NCS because their owners can find easier business and greater prospectivity elsewhere.
Fig 7.3: The number of mobile rigs drilling on the NCS each year and the forecast for units available to drill in these waters.
Companies with a large portfolio of well activities have been able to secure rigs under long-term contracts and are balancing priorities for production and exploration drilling.
300
250
200
150
100
50
0
Flo
ate
rs
2004 2005 2006 2007 2008 2009 2010
Existing Contracts, Standard floatersStandard RequirementsPossible DW Requirements
Existing Contracts, DWfloatersPossible Standard RequirementsFloater Supply
OptionsDeepwater Requirements
Source: Fearnley Offshore August 2007 Website Seadrill
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Nu
mb
er
of
Mo
bil
e R
igs
Not yet commited Contracted Historic number of rigs
0
10
20
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35
25
15
5
Source: NPD data
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It has been harder for the new and smaller players to gain access to units, since their individual portfolios are too small to permit a commitment to long-term contracts.
Fig 7.4: Rigs under contract on the NCS at the start of 2008.
The industry has responded to the problem in a number of ways:
The E&P companies have responded lately to capacity constraints by bringing in rigs •from other parts of the world and upgrading these to secure approval for operating on the NCS. Although the prequalification process is supposed to be harmonised across the North Sea, in practice even rigs coming from UK need to be checked for compliance with Norwegian requirements. An acknowledgement of compliance needs to be prepared and approved and, if required, modifications must be made to the rig. All this can take considerable time.
The small and medium-sized players have started combining their forces to make a •joint commitment to longer rig contracts. This allows them to move their exploration programmes forward. The scheme has been encouraged by the growing number of planned drilling activities in an environment of sustained high oil prices. These combined efforts have been successful in securing rigs for 2009 and 2010, and most exploration wells in 2009 are now due to be drilled by the smaller players.
The continued high level of demand for mobile rigs and the willingness to commit •to long-term contracts have given contractors sufficient incentive to build new units. Eight new rigs are under construction, and the first of these will become available to operate on the NCS in early 2009. Seven of the new rigs are already fixed under long-term contracts, and demand for the 8th unit is very high. The new rig fleet will be more flexible, and can operate in deeper water and tough weather conditions.
Given these responses by the industry to the capacity constraints, it will take some 2-3 years before the issue of mobile rig availability has been resolved because:
New rig contractors entering the market are competing for experienced drilling •crew, and it will take time for them to recruit experienced personnel and for trainees to build up experience. However, contractors with new rigs have some time left to recruit and build up expertise and experience before their units become operational. In the longer term, a new shortage of experienced staff will need to be addressed, given that the current average age of drilling crew is 49 years. A considerable number of experienced staff are expected to retire over the next 5 years (see chapter 8).
9%
StatoilHydro
Source: NPD data
StatoilHydro + Other
Other
26%
65%
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Several large subsea developments are in the execution phase and, under sustained •high oil prices, the number of exploration and infill wells will continue to grow. However, some large-scale subsea development projects – such as Skarv and Gjøa – are due to be completed in 2011 and 2012. This will free up rig capacity.
7 .2 .3 Production-related activities on some older platforms have been delayed by growing maintenance requirements
Over the past couple of years, a backlog of production enhancement activities has built up on some of the older platforms. Many of these installations were designed with a pro-duction life of some 20 years. Owing to the high oil prices, this period has been extended on several mature fields. However, maintenance and repairs represent a heavy workload on these installations. At the same time, high oil prices have prompted the identification of measures to accelerate output from these mature fields. The operators want to imple-ment these activities as soon as possible to extend field production life even further. Carrying out a heavy maintenance workload alongside measures to boost production calls for more people on the platforms. However, most of these older installations have limited accommodation and must therefore prioritise activities. The first priority is to maintain the integrity and availability of the installation. Production enhancement activities such as well repairs, infill drilling, debottlenecking and even the tie-back of 3rd-party fields are thereby deferred. On one particular field, delays to well interventions and other production-enhancing projects are estimated to be resulting in the deferment of some 12 000 bbl/d. If this continues over a longer period, the risk is that important activities may be dropped altogether for good reasons which may nevertheless result in a loss of production.
In the future, production operations will increasingly be on small and marginal discover-ies and fields at the tail end of their producing lives. This will create a different and greater need for flexibility, which also relates to staffing levels.
7.3 The impact of the transitional period
7 .3 .1 The impact of the high level of activity on production
The decline in liquids production is accelerating. In every year since 2004, actual oil out-put has been lower than the annual forecasts submitted by operators to the RNB (Fig 7.5). The 5-year oil forecasts from the operators for the RNB have also been reduced every year. This decline partly reflects problems with the timely start-up of new fields, delays in planning and executing development projects, and over-optimism about activities staying on schedule despite the overheated global market. In every year up to 2007, the operators predicted a very short-term dip in output followed by an upturn, presumably to reflect compensation in later years for production delays. It is a matter of concern that the 2007 operator forecasts show a delay of 5 years and do not seem to include a “catch-up” period even though the decline in oil production is less steep. Perhaps this reflects adjustments to operator expectations about mobile rig and personnel availability following years of consistent underperformance.
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Despite the delays, the area beneath the production curve has so far remained constant. This indicates that no loss of output has yet been seen.
Fig 7.5: Actual production and operator forecasts submitted annually for the RNB.
7 .3 .2 Other possible impacts from the increased level of activity
The project team investigated the impact of maturing production and the higher level of activity on average uptime for existing platforms, and concluded that this is not a major contributor to the short-term production decline. A Petoro study of uptime shows that deferment of annual production owing to downtime for fields in the SDFI portfolio has increased significantly since 2005. The project team received information from the NPD’s most recent performance indicator analysis for fields (Piaf) study. This shows that the rise in deferred production is related to a number of major field shutdowns over extended periods in 2005, 2006 and 2007, including those on Snorre and Kvitebjørn. In addition, several fields have suffered start-up delays – with Snøhvit and Kristin as examples. If these incidents are factored out, then average uptime on the NCS over the past 3 years has been stable. The project team has also investigated a possible relation-ship between maturing oil fields and uptime, but found no indication that mature fields in general have lower uptime. Apparently, the operators pay due attention to the reliability and availability of their aging platforms and equipment.
Oil
prod
uctio
n (m
illio
n bl
s/d)
2002
3.0
2.5
2.0
1.5
1.0
0.52004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 2026 2028 2030
Operators prognosis RNB 2007Preliminary 2008 (Operator)
Actual Production
Source: NPD data
Operators prognosis RNB 2005Operators prognosis RNB 2006
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7.4 What would help the industry to cope better with changes?
The backlog of activities will continue to build up over the coming 2 years, but is expected to be resolved by around 2012. The availability of mobile rigs is likely to improve as a number of new rigs arrive on the NCS, and as a series of large subsea development projects are completed. Companies are also working hard to resolve personnel challenges. Since many of the issues raised in this chapter are global in nature, opportunities to address them in Norway alone are limited. However, some local aspects can be tackled or investigated further by the appropriate parties.
It is important that the authorities review the regulations to assess where room could •exist for more flexibility without compromising safety.
The PSA and its British counterpart, the HSE, need to come up with a common •interpretation of the requirements. To make the rig prequalification process simpler and more effective, the project team recommends that these 2 regulators jointly review this process to arrive at a common interpretation. Although the prequalification process was harmonised across the North Sea some years ago, this did not have the desired effect in practice and qualification work still is time-consuming. That is because the PSA and the HSE have different interpretations of the requirements, so that a rig coming from the UKCS still requires considerable modifications and checks before it can operate on the NCS.
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8. Attract, retain and make best use of the necessary people and expertise
8.1 Chapter summary
The petroleum industry is a knowledge-based industry where access to the right people and expertise represents a critical success factor. That applies to both E&P companies and service providers. The labour market in Norway is currently tight. Combined with an aging workforce, the recent influx of new players is enhancing a global trend towards shortages in the petroleum industry. Accessing and utilising qualified personnel accord-ingly present a challenge.
Recommended areas for further work are:
The industry must put measures in place to retain older workers •
It must make more efficient use of the existing workforce •
The authorities and the industry must cooperate to make recruitment of talented •people, both nationally and from abroad, more efficient and effective.
The authorities and the industry must work together to increase the number of •students in science, geological and technical studies.
Although this challenge is being felt most acutely in the short term, a long-term perspec-tive should also be adopted. A key element will be clear messages from both government and industry to potential recruits about the long-term sustainability of the Norwegian petroleum industry.
8.2 Shortage of qualified labour on the NCS
The OLF published a survey in January 2007 which identified expected recruitment requirements for drilling and well service personnel over the next 5 years. Its findings were based on information collected from 11 members of the Norwegian Shipowners Association and 28 OLF members. They showed that the estimated annual recruitment requirement is roughly 700-800 for offshore jobs and around 200-250 for posts on land.
At the same time, the petroleum industry is witnessing the end of petroleum accumula-tions which are ”easy” to discover and recover. Existing mature fields are becoming more complex over time, while new oil and gas discoveries are being made in smaller reservoirs, greater water depths, harsher climates, more complex reservoirs and so forth. These developments increase the burden on and demand for technical and development personnel. At the same time, rising pressure on costs and time is stretching the existing workforce even further.
The need for qualified personnel is not a uniquely Norwegian problem. Other petroleum provinces are experiencing a similar trend. In order to address it in Norway, however, some unique factors need to be considered. Local regulations and demographics may
75
lengthen the time it takes for Norway to grow its workforce. Seeking people from abroad will make local demographics less of a limiting factor.
8.3 The impact of demographic change
Most developed countries are experiencing demographic trends which indicate that a growing percentage of the population will approach retirement age over the next few years. Only 8 per cent of the Norwegian population was aged 67 or over in 1950, com-pared with 13 per cent today. This proportion will be even higher by 2010 and is set to reach 18 per cent in 2030 and 21 per cent in 2050 (Fig 8.1).
Fig 8.1: The Norwegian population by age and gender, registered and projected.
The petroleum industry in Norway attracted a large proportion of talented local people during its growth period in the 1970s and 1980s. This pattern has changed significantly in recent years as a result of expansion in other parts of the economy, changing preferences among students, and the industry’s own efforts to enhance its internal efficiency and downsize personnel requirements. The result is that the average age of the petroleum workforce is higher than for Norwegian industry as a whole (Fig 8.2).
Fig 8.2: Age distributions for industry as a whole and for the petroleum sector in Nor-way in the 4th quarter of 2007.
Age90-
85-8980-8475-7970-7465-6960-6455-5950-5445-4940-4435-3930-3425-2920-2415-1910-14
5-90-4
5 4 3 2 1 0 0Percentage
Women
1950
Men
1 2 3 4 5
Age90-
85-8980-8475-7970-7465-6960-6455-5950-5445-4940-4435-3930-3425-2920-2415-1910-14
5-90-4
5 4 3 2 1 0 0Percentage
Women
2005
Men
1 2 3 4 5
Age90-
85-8980-8475-7970-7465-6960-6455-5950-5445-4940-4435-3930-3425-2920-2415-1910-14
5-90-4
5 4 3 2 1 0 0Percentage
Women
2050
Men
1 2 3 4 5
Source: Sentral Statistic Byrå
1 7
3 7
1 4
410
4 4
3 4 3 4
9
52
50
45
40
35
30
25
20
15
10
5
015-19 20-24 25-39 40-54 55-66 67-74
Petroleum Industry
Per
cen
tag
e
Norway Industry Total
Source: Sentral Statistic Byrå
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8.4 The influx of new players has generated competition over personnel
Chapter 2 noted that the number of companies active on the NCS has increased signifi-cantly, with some 66 qualified today compared with 20 in 2000. While medium-to-large international companies often bring in personnel from abroad, the smaller companies engaged exclusively in exploration, recruit from the existing pool of people in Norway. That has prompted a shift of personnel in Norway from reservoir management jobs to exploration. A shortage of sub-surface specialists is therefore building up. Companies with a portfolio of exploration, development and production activities are better able to set balanced priorities with their available personnel. However, most companies on NCS are small and currently involved only in exploration.
The NPD requires each of these companies to have a minimum of 8-9 Norway-based staff to be prequalified. This workforce must cover such skills as geology, geophysics, reservoir and well engineering, and other relevant technologies as well as HSE experi-ence. Beyond these minimum requirements for core skills, services can be sourced from other entities such as the parent company or contractors. The minimum staffing require-ment is difficult for some companies to meet, particularly those which are not operating but which are merely a partner in a couple of exploration licences. This is why some companies are not participating in licensing rounds, despite being prequalified.
8.5 Recommendations
Retain experienced staffPolicy on older personnel embraces a set of industry initiatives relating to the aging, experienced workforce. Research shows that policies directed towards the older members of the workforce tend to increase motivation and productivity and thereby enhance a desire to postpone retirement.
In the longer term, the industry needs to be mindful that the desire to retire early is influ-enced by people’s working conditions and experiences when they are in their 40s and 50s. Consideration must therefore be given to the overall working environment over time in order to be successful in creating a desire among personnel to extend their careers.
Making better use of the existing workforce
Increase the use of IO, automation and remote operation. This will permit a better •balance between land-based and offshore assignments. Land-based collaboration rooms enhance the transfer of expertise. IO could also be interesting for employees who are unable for various reasons to work offshore any more. These employees can now take key positions on land and make full use of their experience and expertise.
Create teams with a range of ages. Research has found that knowledge transfer is •most effective when new recruits and experienced personnel are combined in the same physical working environment.
Increase the exchange of personnel between land and offshore. ConocoPhillips •Norge has used something it calls “soft rotation”. This allows 1 out of 4 offshore personnel at any one time to occupy a land-based role over a period of 9-12 months
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and then return offshore. This scheme has so far included managers and jobs which call for key expertise. Benefits include improvements in knowledge transfer and understanding between the land-based and offshore workforces, better networking, managers with broader experience and a better basis for wider use of IO.
Attract more people to the petroleum industryWhile successful measures to defer personnel retirement can alleviate some of the resource constraints in the short term, longer-term solutions must include measures to tap into the talent pipeline over the next few decades.
Potential sources of new employeesAs mentioned above, the labour market in Norway is tight – especially in the technical skill pools relevant for the oil and gas industry. Compared with other countries, a high percentage of the adult population in Norway is in employment. This is mainly because the majority of Norwegian women have jobs.
Longer-term planning While access to people and expertise is currently regarded as a limiting factor for the level of activity on the NCS, the industry found itself in a very different position not too many years ago. Oil prices were radically lower, and companies felt a need to downsize. In order to boost the number of Norwegians with a relevant education in the longer term, the industry could give support to or strengthen the academic community – by sponsoring professorial chairs, for example.
From abroadA tight national labour market makes it natural to exploit opportunities for greater use of personnel from abroad, either by offering people jobs in Norway or by increased remote working. From the industry’s perspective, it is important for the authorities to ensure that processes related to labour immigration are not difficult or complex. The OLF has recently commented on a White Paper (Report no 18 (2007-2008) to the Storting) on labour immigration, and suggested initiatives which could simplify this process. These suggestions include:
granting residence and work permits for more than 1 year•
establishing a centre for foreign workers in Stavanger (a division of the centre in •Oslo)
granting companies advance approval to recruit key personnel from abroad•
simplifying the application process for families•
harmonising regulations and practices for reporting to the tax authorities•
considering whether the tax rules related to temporary labour in Norway can be •simplified.
Recruitment and communication The oil and gas industry is regarded by many young Norwegians as old fashioned, with a “roughneck” image. It is perceived as being in decline and as a contributor to climate change and global warming. This reduces interest in studying subjects relevant to the petroleum industry, such as geology and petroleum engineering.
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In addition to the efforts being made by the OLF, the companies could be more active and visible in schools, universities and other arenas where conversations can be conducted with younger people. It is vital that the industry continues to communicate its attractive and exciting aspects, especially to young Norwegians. The main messages should be:
The petroleum industry in Norway has a healthy long-term future. The government •can play a role alongside the industry in generating confidence in a secure, long-term and sustainable industry.
This is a modern, hi-tech industry which has witnessed enormous technical progress •in recent decades. IO could be presented as an example of the way the petroleum sector has become the biggest and most advanced technology industry in Norway.
Environmental challenges certainly relate to the petroleum industry, since the •production of oil and gas emits greenhouse gases. But this sector will also be an important player in identifying and implementing improvements and solutions to issues related to carbon emissions. Reducing greenhouse gases emissions requires a massive investment in science and technology and new modes of collaboration between industries, knowledge providers and the authorities. The industry is testing and working hard to find solutions for carbon capture and storage, which will hopefully be commercially viable in the future.
Particular attention should be given to enhancing the attractiveness of the petroleum industry to Norwegian women. They are underrepresented in the petroleum industry, and thus offer a potential for expanding the resource base while improving diversity across the industry. The project team recommends that the industry continues to build on exist-ing initiatives, such as the diversity policies in many companies and the Female Future project pursued by the OLF.
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Appendix 1: The project team’s modelling tool and assumptions
A1.1 Introduction
The project team has developed a number of scenarios to illustrate the impact on future production and investment levels of the choices and decisions which the industry and government may have to make to maximise production on the NCS. A scenario model-ling tool was constructed for this purpose. In the tool, production and investment fore-casts for remaining resources in existing fields and discoveries are based on the NPD’s forecasts. To model properly the impact on future production and investment levels of uncertainties and choices related to exploration, the project team carried out a detailed analysis of undiscovered resources. This appendix describes the modelling tool and the assumptions used in the model. Results from the modelling are presented in the main body of the report.
A1.2 Input assumptions for scenario modelling
To make robust forecasts of future production and investment levels, assessments were made of a range of key parameters:
Assessed parameter Source of information/assessment
Field size distribution Historical NCS and UK central and northern North Sea field size distributions and the project team’s assess-ment of the ultimate NCS distribution
Undiscovered resource estimates Estimates based on creaming curves, field size distribu-tions and input from a cross-section of E&P companies
Proportion of smaller fields which will be developed
The project team’s assessment, based on the percentage of fields developed historically in Norway and the UK
Model fields with production/capex phasing The project team’s assessment, based on production and capex profiles for typical field developments by field size
Unit development costs The project team’s assessment, based on recent trends in unit development costs for the NCS and input from a cross-section of E&P companies
Lead times The project team’s assessment, based on historical NCS lead times and consideration of recent trends
Level of exploration drilling The project team’s assessment, based on historical and current levels of exploration drilling on the NCS and expectations of accessible resources
Exploration success ratio The average historical technical success ratio for the NCS over the past 10 years
Access to new areas Scenarios for opening and retaining closed areas were run to identify the potential impact on production and investment levels
Values for these parameters and details of their sources are described below.
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Discovery size distributionThe future distribution of discovery sizes for the NCS was determined using the histori-cal discovery size distribution for the UK central and northern North Sea (UK C/N North Sea) as an analogue for discovery size on the NCS when these waters have ultimately been explored. Like the NCS, this analogue features many different play concepts but, unlike the NCS, is almost fully explored. The UK C/N North Sea has a very high explo-ration well density, and its creaming curve suggests that this basin is at a very mature stage.
Geological basins are all different. This is also the case for the UK C/N North Sea basin compared with the NCS. The main difference is that the proportion of very large discov-eries has been relatively bigger in Norway. If the number of discoveries and plays is high, however, it is reasonable to assume that a statistical basis exist for using this analogue British basin as a model for the ultimate distribution of discovery sizes on the whole NCS. The project team has accordingly assumed that the ultimate frequency distribution of discovery size on the NCS will be similar to that of the C/N North Sea. The ultimate frequency of discovery sizes on the NCS (red) for each size class is assumed to lie half way between the UKCS discovery frequency (green) and the historical discovery fre-quency (blue) for the NCS, as illustrated in Fig A1.1.
Fig A1.1: Calibration of the frequency distribution for discovery size in the scenario modelling, using the frequency distribution for field size in the mature UKCS (central/northern North Sea) as an analogue to obtain the ultimate frequency distribution for field size on the whole NCS.
The frequency distribution for future discovery size on the NCS was then derived from the difference between the ultimate discovery size distribution and the discovered field size distribution (Fig A1.2) in these waters. This was subsequently consolidated into 4 discovery size classes for easier use in scenario modelling. It should be noted that the
0%
5%
10%
15%
20%
25%
30%
<10 <20 <40 <80
Discovery size classes (million boe)
Dis
cove
ry s
ize
freq
uen
cy
<160 <320 <640 <1280 <2560 <5120 >5120
UK C/N North SeaDiscovery Size Distribution
NCS Historic DiscoverySize Distribution
NCS Ultimate DiscoverySize Distribution
81
frequency distribution for field size is regarded as a reasonable assumption, valid for the total ultimate resource potential on the NCS but not necessarily for individual sub-areas.
Fig A1.2: Expected field size frequency distribution on fields discovered, ultimately to be discovered and yet to be found.
Ranges for undiscovered resourcesTo assess properly the impact of choices such as the opening of areas currently inaccessi-ble for petroleum activities, the project team has prepared its own estimates of undiscov-ered resources on the NCS, including an assessment of such resources allocated to each sub-area of the Norwegian Sea and Barents Sea. This evaluation is based on published information from the NPD, the views of petroleum companies and other sources. Estimates for undiscovered resources are probabilistic and involve significant uncer-tainty. They are influenced by knowledge of the basin concerned. An unexplored basin will normally present greater uncertainty than one with a lot of exploration wells. Many variables are involved – E&P companies and the authorities derive their estimates from different datasets and methods. A divergence of views is therefore likely. The project team has accordingly prepared a range of possible outcomes using “high”, “low” and “base” assessments.
The assessment of yet-to-be-found resources by the project team is based on historical exploration results (volumes already discovered and field size distribution), and on how detailed the exploration of the basin has been (licensing history and drilling density). This study assumes that, generally speaking, the E&P companies will drill the “best” prospects first. This means that the larger discoveries are made in the early exploration period for each basin, with the average discovery size falling over time, and that a cream-ing curve will thereby develop. Analysis of creaming curves can be used to calibrate
0%
10%
20%
30%
40%
50%
60%
70%
80%
0-40 40-320 320-1280 >1280
Discovery size classes (million boe)
Dis
cove
ry s
ize
freq
uen
cy d
istr
ibu
tio
n
NCS discovered
NCS ultimate distributionNCS undiscovered
82
expectations for the percentage and volume of remaining undiscovered resources relative to those already found in a geological basin. This method has been particularly useful for assessing the remaining exploration potential in the North Sea.
The methodology and resulting assessment were presented for comment to a number of small, medium-sized and large petroleum companies actively exploring on the NCS. While they obviously all have their own views, their feedback indicated that the method used was sound and that the resulting assessment presented by the project team was reasonable. However, it must be said that the estimate does not represent the views of any individual company, but is to be regarded as a reasonable estimate of yet-to-be-found resources and the expected distribution of field size on the NCS.
The assessment and interview process focused on the following questions:
what is a reasonable resource range for the North Sea?•
what is a reasonable resource range for the Norwegian Sea?•
how much of the resource expectation for the Norwegian Sea should be allocated to •Nordland VI and VII plus Troms II?
what is a reasonable resource expectation for the Barents Sea south of Bear Island? •
When evaluating the exploration potential of the NCS, the project team found it difficult to arrive at a sound assessment of this potential in some areas – particularly those which have not been opened for petroleum activity. A large amount of information collected by NPD could be made available to the industry, so that various alternative views can be developed. The project team would encourage sharing of information between the NPD and the industry. A constructive debate about estimates for exploration potential on the NCS, based on all available information, is likely to improve assessments of the future of these waters and allow the companies to develop better justifications for continued exploration there.
Project team’s estimates of NCS exploration potential North Sea exploration potentialThe project team believes that a significant undiscovered resource potential remains in the North Sea, even though it is considered a mature exploration area. Most of the area has been licensed at least once, and few, if any, plays in this region are untested. This means the room for making new large discoveries is limited. The creaming curve for the North Sea indicates that future discoveries will have a significantly smaller average size than exploration has yielded so far, and that the likelihood of making discoveries larger than 500 million boe will be small (Fig A1.3).
The project team’s estimate for undiscovered resources in the North Sea ranges from 3 to 8 billion boe. The low estimate of 3 billion boe is obtained by extrapolating the creaming curve on the basis of the last 100 discoveries. The high estimate of 8 billion boe calls for 3-5 significant discoveries in the size range of 0.5-2 billion boe to accord with a reason-able field size distribution in the North Sea. Given the exploration maturity of the area, this seems a less likely outcome. The project team therefore used a reference resource of 5 billion boe in its scenario modelling. When the field size distribution is taken into account, this could mean that 1-2 significant discoveries can still be made in the North Sea.
83
The red line in Fig A1.3 illustrates the slope in the future section of the creaming curve based on the high end of the range in the scenario modelling. Similarly, the brown line represents the future creaming curve when the mean or reference range is applied. The bottom light blue line represents a simple extrapolation of the creaming curve from the last 100 discoveries.
Fig A1.3: Creaming curves for the NCS North Sea and the UK C/N North Sea. The forecast for Norway North Sea is based on the project team’s high (red) and reference resource (brown) estimates and an extrapolation of the creaming curve, representing project team’s low estimate (light blue).
Norwegian Sea exploration potentialThe project team applied a range of 2-9 billion boe in the Norwegian Sea. This again represents a considerable uncertainty range. In the areas currently open for exploration and development, the project team expects most discoveries in the shallow water of the Halten Bank to be small, but some potential still exists for large discoveries from explo-ration in the deepwater Norwegian Sea. Testing of new plays in the latter region after the discovery of Ormen Lange has so far yielded disappointing results. More than 10 wells have been drilled on key prospects without success. However, some important wells remain to be drilled over the next 3 years, which may change expectation for this area. But these have a low chance of success. The project group has used 7 billion boe as the reference estimate in its scenario modelling.
To investigate the impact of opening new areas, the project team assessed how much of the exploration potential in the Norwegian Sea should be allocated to Nordland VI and VII plus Troms II respectively. These areas are not currently open for exploration, and available seismic and other data there are limited. The resource estimate is thus highly uncertain. In a “maximum” case, up to 10 billion boe might be discovered in this area if
0
10
20
30
40
50
60
Cu
mu
lati
ve v
olu
me
add
ed (
bill
ion
bo
e)
Number of discovery
10 19 28 37 46 55 64 73 82 91 100
109
118
127
136
145
154
163
172
181
190
199
208
217
226
235
244
253
262
271
280
289
298
307
316
325
334
3431
NCS North Sea discovered NCS North Sea High undiscovered
UK C/N North Sea discovered NCS North Sea Reference case undiscovered
NCS North Sea creaming curve extended
Source: OD and project team
84
a volume density similar to the comparable Halten Bank region is assumed. The “low” case assumes that hardly any economic resources will be discovered. The reference case used in the scenario modelling assumes that a total of 3.5 billion boe will be discovered in Nordland VI and VII plus Troms II.
Barents Sea exploration potentialThe project group has developed a view for the Barents Sea south of Bear Island, where seismic and well data are available to the industry. It has used a range of 0.5 to 6 billion boe, with the expectation that some 3 billion boe might still be discovered in this area. A significant proportion of this expectation could be located in areas not yet accessible to the industry, such as Barents Sea South-West.
The Barents Sea north of Bear Island (around Svalbard) and in the disputed zone with Russia is not currently open for petroleum activities. The project team has no access to data, and has made no estimate for these areas. No resources have been allocated to these regions in its scenario modelling.
Field characteristics in the model Typical model fieldFor each field size class, a typical model field has been defined on the basis of several characteristics – including volume, lead time to discovery and so forth – to represent a commercial development in the scenario-modelling tool. Field size classes and the main characteristics of the typical model field used for each class are shown in Table A.1.1. The source and derivation of these parameters are described below.
Table A1.1: Typical values for fields in each of the 4 field-size classes.
Lead time between discovery and productionThe lead time assessments are based on historical performance on the NCS. The average time from discovery to the start of production on the NCS is 14 years. It is somewhat shorter for stand-alone developments, at 12 years, and rather longer for satellite develop-ments, at 16 years (Fig A1.4). It has been assumed that future lead times will not be better than the average historical performance for field developments in challenging areas. This has been taken into account in scenarios which include the opening of new areas. Smaller discoveries, which will form a high proportion of those made in the mature areas of the NCS, are expected to have shorter development lead times.
Very small Small Large Very largeField size class (mln boe) <40 40-320 320-1280 >1280Model Field average size (mln boe)
Proportion development with incentives for small fields
28 120 700 1500Lead time discovery to product ion start 6 8 10-14 10-14Unit capex ($/boe) 18 18 18 18Unit opex ($/boe) 12 12 12 12Proport ion developed, base case 20% 40% 100% 100%
40% 90% 100% 100%
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Fig A1.4: Lead time from discovery to production, based on historical data. Proportion of discoveries which will not be developedA basic assumption in the scenario modelling is that only a proportion of future discover-ies will be economic for development, and that the remainder will not be developed. Historically, a significant percentage of small discoveries have not been developed. The modelling assumes that a certain percentage of “small” and “very small” fields will not be developed. The base case scenario is that 20 per cent of the “very small” discoveries and 40 per cent of the “small” discoveries will be developed. The scenario selected to illustrate a reduction in the minimum volume required for economic development (see chapter 5) assumes that the above percentages rise to 40 per cent and 90 per cent respec-tively, as illustrated in Fig 5.6.
Unit development costThe modelling tool used unit costs to determine the level of capital investment for the development of future discoveries. The unit development cost assumed in all scenarios is NOK 100 per boe. The capex forecast for reserves and contingent resources utilised the NPD investment forecast. Pipeline costs are not included in the capex forecast.
Exploration drilling activity and success ratioIt has been assumed in all cases that 30 exploration wells per year will be drilled until 2010 at least. This is based on the current level of exploration activity. In the low activity case, the number of wells has been gradually reduced after 2010 to 15 per annum. The gradual reduction to this level in the high activity case starts after 2015. It is assumed that the current level of activity will continue only until 2010 if no decision is taken to open new areas, and until after 2015 at least if such areas begin to opened in 2012 (see Table A1.2).
The technical success ratio (disregarding whether the discovery is or will be developed) on the NCS over the past 10 years has averaged 50 per cent (see Fig 2.6 in chapter 2). The assumption used in all the scenarios is that the technical success ratio remains at 40 per cent until 2040.
0
5
10
15
20
25
30
35
40
45
Lea
d t
ime
in y
ears
Aver.: 12
Aver.: 16
0
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10
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20
25
30
35
40
45
1.0 10.0 100.0 1000.0 10000.0
Field size million boeSubsea / extended reach wellsPlatform/FPSO
Source: Wood Mackenzie data
Aver.: 12
Aver.: 16
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A1.3 Scenario description
The scenarios in Table A1.2 have been selected to illustrate the potential impact of choices to be made about opening areas currently closed to the petroleum industry and of a possible change in the conditions related to small field developments. They should not be regarded as predictions, but rather as illustrations of the magnitude and significance of different choices.
The key differences in the assumptions for the scenarios are shown in the Table A.1.2. It should be noted that undiscovered resource estimates for Barents Sea North and South-West, the disputed zone with Russia, Jan Mayen and the Skagerrak are not included in the scenario modelling because the industry does not have access to data in these areas.
A1.4 Results of the scenario modelling
Production forecasts On the basis of its scenario modelling, the project team has created a reference scenario for forecast production and investment related to undiscovered resources. This uses the project team’s expectations for undiscovered resources in the various areas, and assumes that Nordland VI and VII plus Troms II will be opened for petroleum activity in 2012. Comparisons between production and investment forecasts for the reference scenario and for the scenario which assumes incentives are put in place for small field development are made in chapter 5. Chapter 6 provides comparisons between the opening of Nordland VI and VII plus Troms II with the scenario where no new areas are opened.
The reference case uses the project team’s view of expected undiscovered resources. A comparison has also been made by the project team between production forecasts for undiscovered resources using the reference scenario and high and low resource scenarios. The high and low resources were derived by Monte Carlo simulations using the low and high estimates for undiscovered resources in all areas (see chapter A1.2), excluding the Barents Sea north of Bear Island, Barents Sea South-West, the disputed zone with Russia, the Skagerrak and Jan Mayen. That gives low case, reference and high case estimates for overall undiscovered resources in these areas of 10, 15 and 19 billion boe respectively. Production forecasts for the low, reference and high scenarios are given in Fig A1.6. These illustrate the substantial uncertainty involved in forecasting the undiscovered resource potential. It should be noted that the areas excluded from this analysis – Barents Sea North and South-West, the disputed zone and Jan Mayen – offer a huge potential for additional undiscovered resources and, when made accessible for petroleum activity, could have a significant impact on production levels.
87
Project Reference No New AreasSmall Fields
incentives
0.50.50.5aeS htroN
Mid Norway S. of Nordland VI 3.5 3.5 3.5
0.00.04.3II smorT ,IIV/IV dnaldroN
0.20.20.3htuoS aeS stneraB
lcxElcxElcxEhtroN aeS stneraB
lcxElcxElcxEkarregakS
Disputed area, Russia/Norway Excl Excl Excl
%59%59%59aeS htroN
Mid Norway S. of Nordland VI 60% 70% 70%
%0%0%0II smorT ,IIV/IV dnaldroN
%03%03%03htuoS aeS stneraB
010201022102aeS htroN
Mid Norway S. of Nordland VI 2012 2012 2012
Nordland VI/VII, Troms II 2014 Closed Closed
desolCdesolC4102htuoS aeS stneraB
Exploration drilling activity
30 w/yr until 2015, gradually reduced to
5 wells/yr
30 w/yr until 2010, gradually reduced to
5 wells/yr
30 w/yr until 2010, gradually reduced to
5 wells/yr
Proportion of discoveries < 40 mln %04%02%02depoleved eob
Proportion of discoveries 40-320 mln boe developed 40% 40% 90%
Un
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ou
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, b
ln b
oe
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ReservesContingent resources in existing fieldsContingent resources in discoveries
Project team low resource estimate undiscovered
Project team high resource estimate undiscovered
Source: Forecast for reserves and contingent resources based on OD data, forecast for undiscovered based on project team´s modelling
Project team reference resource estimate undiscovered
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2008 2012 2016 2020 2024 2028 2032 2036 2040
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Table A1.2: Assumptions used in each of the 3 scenarios.
Fig A1.6: NCS production forecast using the project team’s reference scenario for undiscovered resources compared with estimated low and high resources.
88
Appendix 2: Project team’s engagement with stakeholders
The project team would like to thank the following people and companies for their input, fruitful discussions and support in sharpening its findings and recommendations. Special thanks are due to the NPD for its extensive support in providing data and information.
Acergy GroupDepartment for Business Enterprise & Regulatory Reform (BERR), UKBG NorgeCeraCIPR, Arne SkaugeConocoPhillips SkandinaviaEcon ENI NorgeE.ON Ruhrgas NorgeExxonMobil Exploration and Production Norway Faroe Petroleum NorgeGasscoGaz de France, NorgeHalliburtonHess NorgeLambert Energy AdvisoryLundin NorwayMarathon Petroleum NorgeNorecoNorske Shell Norwegian Petroleum DirectorateNorwegian Shipowners AssociationOG21Oil & Gas UKOLF operations committeeOLF exploration committeeOLF tax committeePetoroPetro-Canada NorgePetromaksPetroleum Safety Authority NorwayH H RammResearch Council of Norway: A G KjelaasRevus EnergySandvold EnergySchlumberger Oilfield ResearchSeadrill Management Seawell ManagementShell E&PStatoilHydro Talisman Energy NorgeTotal E&P NorgeUniversity of Stavanger: Petter OsmundsenWood Mackenzie
89
Appendix 3: NPD resource classification
The resource account is based on the resource classification by the NPD. This classifica-tion covers the total recoverable volumes of petroleum, both discovered and undiscov-ered. These are divided into categories in accordance with their maturity in terms of production (Fig A3.1).
“Resources” is a collective term for technically recoverable petroleum volumes. The clas-sification divides these into the principal categories of reserves, contingent resources and undiscovered resources.
Reserves are remaining recoverable petroleum resources in deposits which the licensees have decided to develop. They are divided into various categories in accordance with the maturity of the projects: whether they are in production, being developed or sanctioned for development by the licensees.
Contingent resources are discovered volumes of petroleum not yet covered by a decision to develop. They are also divided into various categories in accordance with project maturity.
Fig A3.1: Classification of petroleum resources on the NCS,
Source: NPD
8
Prospects
7FNew discoveries
that have notbeen evaluated
6Recoverynot very
likely
5FRecovery
likely,but notclarified
5A
4FIn the
planningphase
4A
7APossible future
measures to improverecovery
3FDecidedby the
licensees
3A
2FApprovedplan for
developmentand operation
3A
1
Inproduction
0Sold anddeliveredpetroleum
Leads and unmappedresources
Undiscoveredresources
Contingentresources
Reserves Historicalproduction
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Appendix 4: Assumptions for estimating contingent resources and a comparison with the NPD estimates
The project team has made an independent assessment of contingent resources in existing fields and discoveries.
A 4.1 Contingent resources in existing fields
The project team and the NPD both estimate contingent resources in fields at some 4.7 billion boe. In the project team’s view, an additional potential of some 0.8-1.7 billion boe could be added to contingent resources in fields if investment in mature fields and the good track record for applying new technology can be maintained. Every year, the opera-tors firm up new opportunities for improving recovery from existing fields and include these in category 5A (recovery likely but not clarified). Other potential opportunities are identified, but involve substantial uncertainties and are therefore included by the opera-tors in resource category 7A (possible future measures for improved recovery). Potential opportunities also relate to such aspects as the application of new technology. These are undefined and yet to be included in the 7A category. Over the past 10 years, however, fewer and fewer potential opportunities have been firmed up, and volumes in the classes of contingent resources in fields have declined by some 5.4 billion boe, from 11 per cent to a current 4 per cent of total resources on the NCS. This decline is expected to continue in the future because the large fields are at a mature stage.
Fig A4.1: Comparison between project team and NPD estimates for contingent resources in existing fields. The project team has included some 1.4 billion boe in additional resources.
The 0.8-1.7 billion boe added from new opportunities in existing fields could represent the addition of some 150 million boe/year to production from contingent resources in 2012, gradually declining over the subsequent 10 years. The NPD does not provide an estimate for potential additions to its estimate of contingent resources in fields.
Vo
lum
e (b
illio
n b
oe)
Project team NPD
8.0
7.0
6.0
5.0
4.0
3.0
2.0
1.0
0.0
cat. 4A
2.0
1.7
1.5
2.0
1.7
1.5
1.4
6.7
5.2
cat. 5A cat. 7A additions
91
A.4.2 Contingent resources in discoveries
The project team investigated the portfolio of undeveloped discoveries in contingent resource categories 4F, 5F, 6F and 7F.
A4.2: Development status of existing discoveries by field size.
It found that operators are actively progressing discoveries both large and small in resource category 4F (in the planning phase), but that they are concentrating on the relatively large ones first. Discoveries in resource category 5F (development likely but not clarified) are also under review. However, a development decision for many discoveries in this category depends on successful appraisal drilling or near-field exploration, and a proportion of them may therefore never be developed.
33 per cent of the volumes in category 5F – covering 20 per cent of discoveries – •have not been developed yet because they are too small for stand-alone development. However, operators are actively exploring in the vicinity of these discoveries to find more (small) accumulations which could justify development in a cluster.
A further 37 per cent of the volume in category 5F discoveries is awaiting appraisal. •Most operators plan to conduct such appraisals during the next 2-3 years.
Some 20 per cent of the volume lies in discoveries awaiting ullage in the •infrastructure.
10 per cent of the volumes in category 5F seem to lie in discoveries which are very •small and unlikely to yield economic development. However, these may become economic at higher oil prices.
Most of the undeveloped discoveries are in resource category 6F (unlikely to be developed). These are mainly small.
0
5
10
15
20
25
30
35
40
45
50
<10 10-20 20-40 40-80 80-160 160-320 320-640
Discovery size (million boe)
Nu
mb
er o
f d
isco
veri
es
No plans
Development likely, but not clarified
Planning Phase
Under Development
Source: NPD data
92
The project team’s production forecast includes 4.1 billion boe of contingent resources in current discoveries, compared with the NPD’s 4.4 billion estimate. Given the level of uncertainty in estimates for contingent resources, this difference is very small.
It arises mainly from the assumptions applied for resource category 5F (likely to be developed). The project team assumes that most but not all of the volumes in this category will ultimately be developed, and has therefore included 2.1 billion boe. However, the project team expects several discoveries in category 6F (unlikely to be developed) to become attractive for development either through sustained high oil prices or through more cost-effective development (see chapter 5.5).
Fig A4.3: Comparison between project team and NPD estimates for contingent re-sources in discoveries.
Vo
lum
e (b
illio
n b
oe)
Project team NPD
5.0
4.0
3.0
2.0
1.0
0.0
cat. 4F
1.3
2.1
0.3
1.3
2.7
0.40.4
4.14.4
cat. 5F cat. 6F cat. 7F
93
Terms and definitions
A&D: acquisitions and divestments – the process of buying and selling petroleum assets such as fields, discoveries and licensed blocks.
Accessible areas: those parts of the NCS currently open for petroleum industry activities. A proportion of these have been awarded in APA or conventional licensing rounds. However, a substantial share has not been awarded.
APA: awards in predefined areas. APA rounds have been held annually on the NCS since 2003, and focus on the more mature areas in exploration terms where the geology is known and infrastructure is available in the vicinity.
Area fee: an annual fee paid by licensees on the NCS to the government for each square kilometre of acreage covered by their licence. The fee is not charged for acreage where satisfactory activity which meets specific requirements is shown to be taking place.
BOE: barrels of oil equivalent. Used when oil, gas, condensate and NGL are to be summed in order to express everything in a comparable unit. This study applies a conversion factor of 6.29 from standard cubic metres of oil to barrels of oil equivalent.
Contingent resources: recoverable petroleum volumes which have been discovered, but which are not covered by a development decision.
Creaming curve: plots the size of discoveries made so far against their number. The shape of the curve reflects the general principle that a basin contains a small number of larger finds (the cream of the crop) and a large number of small to very small finds. Large discoveries are usually made in an early stage. As exploration progresses, the size of each additional find diminishes.
Discovery rate: the percentage of exploration wells drilled which find hydrocarbons .
EOR: enhanced oil recovery. Refers to advanced methods which reduce residual oil saturation in fields. Residual oil is the oil trapped in the reservoir rock which cannot be recovered with the usual methods. Solutions include injection of carbon dioxide, chemicals or microbes, which will improve the mobility of otherwise immobile oil.
Inaccessible areas: parts of the NCS not yet opened for petroleum activities. These include Barents Sea North and South-West, parts of the Nordland and Troms areas, and the disputed zone with Russia.
IOR: improved oil recovery. Refers to methods aimed at pockets of mobile oil left behind in the reservoir. The most important methods are water and gas injection or a combination of both, such as water alternating gas (WAG) injection.
IO: integrated operations. A term used for the introduction of new collaboration models and innovative information technology. With real-time data transfer, experts on land can support operations on offshore installations. This permits better and faster decision-making and support.
Liquid production: production of oil, condensate and natural gas liquids (NGL).
NPV: net present value. Stands for the cumulative cash flow after tax.
NPD: Norwegian Petroleum Directorate.
OLF: Oljeindustriens Landsforening – Norwegian Oil Industry Association.
94
Piaf: performance indicator analysis for fields. Studies carried out by the NPD to analyse field performance.
Play: a specific geographical area in which many geological conditions occur together so that producible hydrocarbons can be proved.
Prequalification: a qualification system set up by the authorities to give E&P companies a means of assessing their own suitability for participating on the NCS, before the players invest resources in evaluating specific business opportunities.
Prospect: a potential hydrocarbon accumulation which has not been tested by drilling, but which can be mapped and potential volumes can be calculated.
PSA: Petroleumstilsynet – Petroleum Safety Authority Norway.
PDO: Plan for development and operation of petroleum deposits.
Production licence: confers the right to conduct investigations, exploration drilling and recovery of petroleum deposits within the geographical area specified in the licence. The licensees become owners of any petroleum produced .
Recovery factor: hydrocarbons which can be recovered from an accumulation as a percentage of the total hydrocarbon volumes in that accumulation.
Reserves: remaining producible and saleable hydrocarbon volumes in accumulations which the licensees have decided to develop or for which the authorities have approved a PDO.
Resources: a collective term for technically recoverable hydrocarbon volumes.
RNB: revised national budget. All operators on the NCS provide input to the NPD for the national planning budget in October. This consists of historical data and forecasts for reserves, contingent resources and costs. The input is collated by the NPD, and the RNB is issued in May the following year.
SDFI: State’s Direct Financial Interest in fields and licensed blocks. This portfolio is managed by Petoro.
TTA: technology target areas in the OG21 programme.
Unconventional hydrocarbon resources: hydrocarbons found in accumulations which are not dependent on a trap mechanism and geological structure, as in conventional oil and gas reservoirs. Examples are oil shales, gas hydrates, gas from coal or hydrocarbons in rocks with low permeability.
Undiscovered resources: potential petroleum resources which still have to be tested by drilling exploration wells.
Ultimate recovery: estimated proportion of the hydrocarbons in place which will have been recovered at the end of the field’s production life.
95
References
Cera (2008): GreY2K Shaping Tomorrow’s Workforce. Michael Wynne, Judson •Jacobs.
Cera (2007): New DOFF Operating Models to Address E&P Human Resource •Challenges, White Paper, Judson Jacobs, Richard Ward.
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Econ (2007): Newcomers. Norwegian Continental Shelf Quarterly.•
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Oil and Gas UK (2008): 2007 Activity Survey. •
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OLF (2006): Potential value of integrated operations on the NCS.•
OLF (2006): Presentation Portfolio Managers Meeting, 29 March 2006.•
OLF (2006): Rekrutteringsbehov innen boring og brønnservice – resultat av OLF/•NR spørreundersøkelse (Recruitment requirements in drilling and well service – results from an OLF/Norwegian Shipowners Association survey), December 2006.
OLF (2007): Updated potential value of integrated operations on the NCS.•
OLF (2008): Innspill til stortingsmelding om arbeidsmigrasjon (Contribution to •the White Paper on labour migration).
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OLF/NPD (2008): Rig availability study. •
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Selmer Research (2008): Oil Companies on the NCS, monthly update, February •2008.
Sintef HiT (2005): report on the consequences of large-scale adoption of •integrated operations on the Norwegian continental shelf for employees in the petroleum industry and the opportunities for creating new jobs in Norway.
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www.konkraft.no
KonKraft is a collaboration arena for:
Published December 2008 by KonKraft
Project team Marianne Goesten (project leader) Norske ShellStåle Thorsen (observer) NPD Atle Sonesen GazdeFranceJohn Magne Hvidsten Talisman Thore Grønvik AcergySvein Olav Nesse Norske ShellSteinar Mikkelsen Norske ShellErik Talleraas Norske ShellLine Røyksund Norske ShellBjørn Ivar Bergemo StatoilHydro, Trondheim Herman van Driel PetroCanadaMark Katrosh HessAslak Ogland Norske Shell Reidar Saugstad Norske Shell Adam Mitchell CERADuncan John CERA
Reference group Morten Dethloff HalliburtonTor Rasmus Skjærpe PetoroGisle Eriksen ConocoPhilipsThor Otto Lohne GasscoScott Kerr NorecoJan Kristian Haukeland AcergyÅre Gausla Norwegian Shipowners AssociationJone Hess EON RuhrgasAina Berg IrisAnn Kristin Sjøtveit KonkraftLars Arne Ryssdal OLF Lars Erik Åmot (observer) MPEØyvind Tuntland (observer) PSAGeir Heddeland LO
