From discovery to field

Resource-report-2011

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Introduction

Resources in discoveries without a decision to develop at 31 December 2010 represent five per cent of total expected resources on the NCS and nine per cent of remaining resources. This proportion has been stable for a number of years, but the average discovery size is smaller than before. History shows that most discoveries will be developed, but that this may take some time. Small discoveries often depend on access to spare capacity in processing and transport facilities to become commercial. In mature areas, as a rule, such discoveries are developed through a tie-in to stand-alone fields. This also contributes to extending the producing life for existing fields substantially beyond the original plans. Large discoveries under development may also be dependent on capacity in existing infrastructure. Coordinated development of several discoveries across production licences can reduce unit costs and make commercial discoveries even more profitable, or permit the development of commercially marginal finds.


Resource base

The total resource estimate for discoveries still without a decision to develop was 650 million scm oe at 31 December 2010. Growth from 16 discoveries during 2010 is estimated at about 80 million scm liquids and 40 billion scm gas. Since a number of the discoveries are still under evaluation, these estimates are uncertain. The discoveries vary in level of maturity and probability of being developed. The NPD’s resource classification is broken down into undiscovered resources, contingent resources, reserves and historical production. See the overview of the resource classification in chapter 1.

Liquids and gas are split more or less evenly in discoveries without a decision to develop. Most of the discoveries, which collectively account for the largest part of the resources, lie in the North Sea. See figure 4.1.

 

Figure 4.1 Resources in discoveries without a decision to develop at 31

Figure 4.1 Resources in discoveries without a decision to develop at 31 December 2010, broken down by area



A long time can pass before a discovery is considered sufficiently commercial to be developed. Figure 4.2 presents the total resources in discoveries without a decision to develop, broken down by the year of discovery. Reasons why the time from finding to development may be long include reservoir uncertainty, the size and location of the discovery, oil price trends, costs and technology. A number of discoveries made in the 1970s and 1980s are only now being developed. Examples include Valemon and Gudrun, currently under development, and 30/7-6 (“Hild”) which is approaching that stage. Factors contributing to a development of these discoveries include new information on the reservoir and geology, changes in licensee composition, operational experience, new technology and sufficiently high oil prices.

 

Figure 4.2 The maturity of discoveries without a decision to develop by

Figure 4.2 The maturity of discoveries without a decision to develop by discovery year at 31 December 2010



Some 100 million scm oe were matured from resources in discoveries to reserves during 2010. Three plans for development and operation (PDOs) were submitted, and four new field developments approved by the authorities. The proportion of discoveries in relation to remaining resources on the NCS has been stable at the present level in recent years. See figure 4.3. This shows that the resources are being matured and developed. However, a successful realisation – in other words, profitable development and production – calls for a big commitment to technology development and adoption, and to expertise.

 

Figure 4.3 Development of resources in discoveries versus total reserves

Figure 4.3 Development of resources in discoveries versus total reserves and resources on the NCS, excluding petroleum sold and delivered
 

PDO and PIO

Before the licensees can develop a discovery, a plan for development and operation (PDO) has to be approved by the authorities. This must explain how the licensees intend to develop and operate the field. A PDO or a plan for installation and operation (PIO) comprises a development/ installation section and an impact assessment. The MPE coordinates the administrative process for the plan and receives the NPD’s assessments. Developments costing more than a specified limit – currently NOK 10 billion – must be approved by the Storting (parliament).


PDO adviser

The adviser’s role includes advice on preparing a PDO/PIO to meet official requirements, explaining administrative procedures, and contributing to effective interaction between the licensee and the authorities. They are meant to simplify the developer’s job and make official requirements clear. The development concept must be documented when it has been chosen. With many new players on the NCS in recent years, the need for advice on legislation and government practice has increased.


Small discoveries

The average size of discoveries without a decision to develop is substantially smaller than for discoveries developed in recent years. See figure 4.4. The calculation of the average size for fields approved in 2004-10 excludes Ormen Lange, with 320 billion scm of gas, which was approved for development in 2004. Normally, the largest discoveries are developed first. Small finds often require different conditions from large ones if they are to be realised. Most discoveries lie in the North Sea, but are generally small. With many large developed fields, this provides opportunities for tie-back of the discoveries to existing production facilities – also known as field centres.

 

Figure 4.4 Average field and discovery sizes and the number of fields and

Figure 4.4 Average field and discovery sizes and the number of fields and discoveries by area

 


Location

The North Sea and parts of the Norwegian Sea have well-developed infrastructures. Being developed with fixed production installations can be cost-effective for the largest discoveries, and provides additional processing capacity for tie-back of new subsea wells.

Using existing infrastructure represents a cost-effective development solution for many of the remaining discoveries, which can help to ensure that they become sufficiently commercial to be developed. Figure 4.5 presents a picture of the distance from discoveries to suitable offshore infrastructure, broken down by discovery size. A large number of discoveries lie less than 50 kilometres from the nearest suitable infrastructure with liquids/gas processing.

Discoveries located up to 10 kilometres from a field centre can be accessed today by extended-reach wells. For longer distances, fixed installations or subsea wells tied back to the field centre represent the most appropriate solutions. Distance from a field centre is primarily important for discoveries which are so small that a commercial stand-alone development is not feasible. As a result, the biggest challenge is to achieve a commercial development for the smallest discoveries which lie relatively far from suitable infrastructure. See the circle in figure 4.5.

 

Figure 4.5 Resources in discoveries without a decision to develop at 31

Figure 4.5 Resources in discoveries without a decision to develop at 31 December 2010 and distance to the nearest suitable infrastructure with production facilities



Several examples exist of successful development with discoveries located a long way from infrastructure. One is Vega Sør, where gas and condensate are carried from a subsea template to the Gjøa installation through a 50-kilometre pipeline via the subsea template on Vega. This represents a substantial distance for multiphase flow transport. Reserves in the small Vega and Vega Sør fields, totalling some 12 and 11 million scm oe respectively, formed the basis for a commercial development together with the roughly 50 million scm oe in Gjøa. All made in the 1980s, these three discoveries were realised through a coordinated development. This shows that the maximum distance for wellstream transport from a subsea development to a field centre is determined by a combination of technology, resource base and costs. The solution for the Vega fields also demonstrates the gain obtained by integrating several small deposits.

Relatively new subsea technology, such as seabed separation and multiphase flow pumping, and further development of tools for simulating multiphase flow have helped to extend the distance from subsea wells to field centres or land-based plants. Wellstreams (comprising gas, condensate and water) are piped 143 and 120 kilometres respectively from subsea wells on Snøhvit and Ormen Lange to land-based plants. Opportunities for multiphase flow from a subsea field to a processing unit are challenged by such factors as transfer distance (horizontal and vertical), wellstream composition, pressure and temperature, and requirements for material quality.

Subsea gas compression represents a new and important technological leap which could help to secure the commercial development of discoveries in deep water and exposed areas, and to improve recovery from existing subsea fields. This technology is under development, and plans exist on a number of fields to implement subsea compression once it has been qualified.

Water depth has not so far been a barrier to developing large discoveries on the NCS. The development of Ormen Lange in 800-1 100 metres of water and far from land was complicated, but made possible by technological progress. The field’s resource base permitted an extensive subsea development despite deep water, a low seabed temperature, landslide challenges and a long distance from land. Only gas has so far been discovered in deepwater areas of the NCS. See figure 4.6.

 

Figure 4.6 Resources in discoveries without a decision to develop at 31

Figure 4.6 Resources in discoveries without a decision to develop at 31 December 2010 and water depth

 


Development solutions

A steadily growing number of discoveries on the NCS are being developed with subsea solutions – in other words, with petroleum recovered via seabed templates for processing on fixed installations or on land. A fixed installation is permanently positioned on the field throughout its producing life. A production ship can also be a fixed installation if it is intended to stay permanently on the field. Subsea wells can be tied back to fixed installations on other fields, known as third-party tie-backs, or installed in combination with floating fixed installations (as on Alvheim, Åsgard and Kristin). From 2005 to 2010, 19 of 22 fields were developed with subsea solutions. Eight further developments were approved by the authorities in 2010 and the first half of 2011. Gudrun and Valemon, for example, are being developed with fixed installations. Subsea wells on Knarr will be tied back to a production ship with storage. Marulk, Gaupe, Trym, Hyme and Visund Sør are subsea developments tied back to existing fixed installations on the NCS, the UKCS and the Danish continental shelf.

Considerable progress has been made with subsea and floating production facilities over the past 20 years, both technologically and in the number of developments. Subsea solutions have helped to make development more profitable. That applies particularly to small and deepwater discoveries. About half the output on the NCS comes today from subsea wells, and this proportion is rising. See figure 4.7.

 

Figure 4.7 Total output from subsea wells and fixed installations, 2000-

Figure 4.7 Total output from subsea wells and fixed installations, 2000- 2010

 

The trend towards a growing share of subsea developments is likely to continue. Among reasons for choosing a solution of this kind are the fact that the initial investment is often lower, suitable infrastructure is available, the reservoir extends over a wide area, and the water depth is considerable. However, drilling and maintenance costs may often be higher for a subsea development than with a fixed installation. Further development of technology for cost-efficient well maintenance and drilling of sidetracks through existing subsea wells could therefore make important contributions to profitable measures for improved recovery. FMC Technologies was awarded the NPD’s IOR prize in 2009 for developing technology for this purpose.

Fixed installations may offer greater flexibility for making modifications, a lower break-even price for improved recovery measures, and reduced operational risk. Such facilities provide opportunities for permanently installed drilling rigs. The advantages and disadvantages of investing in fixed drilling equipment rather than chartering mobile drilling units as required must be assessed for each development.

This means that the basis exists for studying both surface and subsea solutions for many discoveries.


Simpler, cheaper, faster

Until the 1990s, petroleum activity concentrated mainly on developing large deposits with correspondingly high costs for engineering, development and operation. The decreasing size of discoveries makes it necessary to think along new lines, simplify and do things more cheaply. The challenge for the industry is now to continue developing cost-effective models for both project execution and development solutions. A greater degree of standardisation for the latter and effective coordination of developments can contribute positively to profitability. However, reducing the time from discovery to production start must take account of applicable safety and environmental standards, and not be pursued at the expense of integrated area solutions and good resource management. Standardised development solutions appear to be the most relevant for discoveries where a subsea solution is planned.


Coordination

Creating new stand-alone field centres competes in a number of cases with development solutions which involve tie-backs to established infrastructure and utilisation of spare capacity on fields in the late phase. Long experience has been accumulated on the NCS with coordinated development of discoveries where this offers the most profitable solution. The Petroleum Activities Act requires the coordination of several deposits when this is clearly the rational approach.

Gjøa, Vega and Vega Sør provide an example of a recent coordinated development and production strategy. Coordinating these fields yielded larger expected value creation than three standalone developments.


Profitability of discoveries

During the autumn of 2010, the NPD conducted an analysis of exploration profitability in 2000-10. See chapter 3. This analysis also estimated value creation by discoveries during the period. The same economic assumptions were applied in both analyses.

A total of 149 discoveries were made during the period. Eight are included in other finds. Figure 4.8 provides an overview of the largest discoveries. The resource estimates are based on an expected estimate prepared in connection with the 2009 resource account. Where discoveries made in 2010 and the 6506/6-1 (“Victoria”) and 16/1-9 (“Draupne”) finds are concerned, the resource account for 2010 has been utilised.

 

Figure 4.8 Expected recoverable resources in the largest discoveries during

Figure 4.8 Expected recoverable resources in the largest discoveries during the 2000-2010 period



The total growth in resources from discoveries for the whole period was 333 billion scm of gas and 403 million scm of liquids, adding up to 736 million scm oe.

Most of the discoveries included in this analysis have still to be developed. Both the size of recoverable resources in each discovery and their production and cost profiles are therefore uncertain. Nor has a development and operating concept been chosen for many of the discoveries. When production will start, the level of costs, and oil and gas prices are also uncertain, which has a substantial impact on profitability expressed in net present value.

The total net present value of the discoveries is estimated at roughly NOK 710 billion in 2010 money. See figure 4.9. Oil discoveries account for a dominant share of the overall net present value.

 

Figure 4.9 Net present value distributed between oil and gas discoveries

Figure 4.9 Net present value distributed between oil and gas discoveries 

 

Things may take time

The NPD’s analysis shows that discoveries without a decision to develop represent substantial value. However, it often takes a long time for this value to be realised. The average lead time from discovery until production starts is 12 years.

Fixed installations have an average lead time of 11 years, while the figure for subsea fields tied back to existing field centres is 13 years. See figure 4.10. History also shows that gas discoveries have a longer lead time than oil finds. Lead times can probably be reduced with simpler and more standardised developments.

 

Figure 4.10 Average lead time for fields by year the field came on stream

Figure 4.10 Average lead time for fields by year the field came on stream

 

The NPD’s annual survey of conditions delaying the progress of discoveries towards development shows that commercial finds are usually developed. About a third of the project blockers reported to the NPD involve lack of capacity in the infrastructure or the absence of a gas solution. More than a third of reported project blockers involve uncertainty over the resource base and reservoir conditions. In addition come commercial assessments and strategic considerations for the companies.


Area perspective

Substantial resources have been realised by phasing output into a production installation with spare capacity. This is also often beneficial for the licensees of the host field through reduced unit costs and increased reserves, which provide opportunities to extend the production period.

Some field centres will have limited spare capacity to accommodate new discoveries, either owing to production from the main field or because nearby resources are being phased in. Figure 4.11 presents the planned producing life at the PDO date for fields with processing facilities and the extension in producing life based on current plans. As the figure shows, installations with opportunities for tie-backs have a clear tendency for their producing life to be extended beyond the original expectation.

 

Figure 4.11 Planned producing life at the PDO date for fields with processing

Figure 4.11 Planned producing life at the PDO date for fields with processing facilities, and extended producing life based on current plans

 

Clarifying the resource potential in the area around existing fields is important. The challenge is to lay integrated plans for an area in order to exploit the resource potential and processing and transport capacity in an optimum socio-economic manner. Differing ownership constellations for infrastructure and in nearby production licences often challenge coordinated area thinking.

 

Regulation on the use of installations by others
Based on considerations of good resource management, the purpose of the regulation is to ensure positive incentives for exploration, new field development and improved recovery through effective negotiating processes and appropriate profit-sharing over the use of existing installations. The introduction of the regulation has helped to ensure that timecritical resources close to planned and existing infrastructure can be more easily realised. The regulation establishes the principle that the profit from production should primarily be secured on the field with the resources. Tariffs and other conditions related to the use of installations owned by others must lie at a reasonable level and be calculated on the basis of the services offered.

 

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The resource report 2011
Main page Preface Status og utfordringer på norsk sokkel.. Uoppdagede ressurser Leting 4 Muligheter og utfordringer for felt i drift

09.11.2011