Recovery from producing fields

2.1 Production developments

Since Norwegian oil production began in 1971 with test production from Ekofisk, a number of large oil fields have been developed. The big fields, which were brought on stream in the 1970s and 1980s have eventually moved into a mature phase with declining oil rates. At the same time, new field developments have been smaller. The loss of production from the old fields has consequently been only partly offset by bringing new discoveries on stream. Production is now more diversified and spread across more fields than in the past. See figure 2.1.

 

Figure 2.1

Figure 2.1 Development of historical oil production and number of fields by level of production.

 

Figure 2.1 presents historical oil production broken down between fields with high, medium and low daily output. Oil production was dominated until well into the 1990s by a few fields with large outputs. Oil production in 1989 was at roughly the same level as in 2013. Fifteen oil-producing fields were on stream in 1989, and 81 per cent of production came from the four of these with daily rates of more than 100 000 barrels. By 2013, the number of oil-producing fields had risen to 72 and the two with production exceeding 100 000 barrels per day accounted for 15 per cent of output.

Oil production is expected to continue declining from fields which have been on stream for many years. Some fields have been revitalised in recent years through the development of new production facilities or an increase in drilling capacity. This will reduce the decline in output to some extent over the next few years. In addition, fields with a large production capacity are coming on stream/under development. As a result, the NPD expects the level of oil production to stabilise over the next few years.

Figure 2.2 presents developments in gas output, broken down by the level of production from the fields. Gas sales from the NCS began in 1977 with the opening of the gas pipelines from Ekofisk to Germany and from Frigg to the UK. Production has been growing steadily since 1996, with the number of fields contributing to this output doubling. The position for gas is that a few fields account for the bulk of output. Four fields provided 62 per cent of production in 2013, with Troll as the largest.

 

Figure 2.2

Figure 2.2 Development of historical gas production and number of fields by level of production.

 

2.2 Cost position

Development and operation of what has become an extensive infrastructure of facilities, pipelines and land-based plants call for large financial resources. Total expenditure, excluding exploration, came to about NOK 250 billion in 2013.

Cost trends on the NCS for operation, investment and other spending are presented in figure 2.3. The growth in expenditure over time reflects both increased activity and price inflation. The rise in the level of costs has been particularly marked since 2005. High oil and gas prices have led to an international boom in the petroleum sector, resulting in high capacity utilisation and a considerable growth in costs.

 

Figure 2.3

Figure 2.3 Development in costs (forecast 2013-18).

 

The increase in petroleum industry costs has exceeded price inflation in the general economy by a fairly substantial margin. Figures in this report present costs in fixed prices adjusted to the 2013 level on the basis of the consumer price index (CPI). Price rises over and above the general level inflation are included in the base figures.

Capital spending represents a large proportion of overall expenditure. Figure 2.4 presents investment profiles for field developments where spending began in the 1970s, 1980s and 1990s respectively and up to the present day. As the figure shows, investment in fields which were developed as early as the 1970s and 1980s continues to account for a substantial proportion of total capital spending. More fields in operation accordingly mean higher overall investment. New developments come on top of that.

 

Figure 2.4

Figure 2.4 Total annual investment in field development by the decade when spending began.

 

Figure 2.5 presents the development of operating costs and investment. The growth in costs has been substantial for fields on stream in 2000-2013. From 2005 to 2013, the average increase in operating costs and investment was seven and 15 per cent respectively, measured in nominal kroner. These rises were five and 23 per cent in nominal kroner during the final part of the period, from 2010 to 2013.

 

Figure 2.5

Figure 2.5 Development of investment and operating costs on fields on stream throughout the 2000-13 period.

 

Drilling new development wells has accounted for about 50 per cent of investment. Operating investment accounted for a further 20 per cent. The latter embraces various types of capital spending required to maintain operation on existing facilities. Costs associated with maintaining technical integrity and production capability are expected to increase on aging installations. The third large investment item is development spending. This has primarily involved the installation of new fixed platforms on fields already in production.

Increasing costs have at the same time been met by a decline in production. The decline has been partly offset by utilising spare production capacity on the facilities to phase in smaller discoveries nearby. Trends for costs, own output and production for others (third-party volumes) are presented in figure 2.6.

Figure 2.6

Figure 2.6 Cost and production developments for fields on stream throughout the 2000-13 period.

 

The NCS is maturing, and most fields are in a phase with declining production. Because a large proportion of operating costs for a field are independent of the quantity produced, unit costs – defined here as operating costs per unit produced – will rise.

Figure 2.7 illustrates the challenge posed by rising unit costs for fields which have not had third-party processing. The increase in unit costs has been particularly marked in recent years. Rising costs are a matter of concern. This is because the profitability of an individual project may be threatened if oil prices fall, and could cause the project to be shelved. Cost growth has been particularly strong in drilling.

Figure 2.7

Figure 2.7 Development in operating costs per unit produced for a selected field without third-party processing.

 

Figure 2.8 presents the trend for the average cost for new development wells drilled from mobile facilities. The average cost of drilling a well has more than doubled since 2002. Considerable variation exists in drilling expenditure per well, and many factors determine the cost of a well. A larger proportion of long and more complex wells could contribute to higher average costs.

 

Figure 2.8

Figure 2.8 Development of average rig rate and well cost for wells drilled from mobile units.

 

A substantial proportion of well costs are closely associated with the time taken. The speed of the drilling process, usually termed drilling efficiency, will have great significance for the cost of the well. One indicator of drilling efficiency is metres drilled per day. This has moved in a negative direction over time on a number of fields. Nevertheless, the most important cause of the cost increase is the rise in prices for the goods and services required to drill a well. Most development wells on the NCS are drilled from mobile units. Rig hire and various forms of well services account for the bulk of the cost of drilling such wells. Rig hire alone comprises 45 per cent of the cost of a well, with well services accounting for roughly another 30 per cent.

In addition to well costs, figure 2.8 illustrates the development in rig rates. These are fixed when contracts are entered into. A substantial time lag may occur between the signing of a contract to use a rig and the point when costs begin to be incurred. Threefour years normally elapses from the award of a newbuilding contract until the rig begins operations. In addition, due to longterm contracts market rates do not immediately affect well costs.

Developments in the level of costs on the NCS must be viewed in relation to international trends. Figure 2.9 shows three investment level indices – one global, one for offshore projects and one confined to deep water projects. According to these data, the level of costs has more than doubled since 2005. Little variation exists between the various indices.

Figure 2.9

Figure 2.9 Movements in global cost indices for development projects.

 

The increase reflects higher prices in various key market areas. Internationally, growth has been particularly strong in the drilling and well sector and in the cost of subsea equipment.

Available statistics are inadequate for comparing international trends with developments on the NCS. Økt bore- og brønnaktivitet på norsk sokkel (Increased drilling and well activity on the NCS), the 2012 report of a commission appointed by the MPE, describes cost trends in the drilling and well sector and identifies a number of factors which boost costs in this area on the NCS.

 

2.3 Projects on producing fields

New projects with associated investment are sanctioned by the licensees after a thorough evaluation. A number of projects are assessed on fields every year. The 2013 resource account includes 165 specific projects for increased oil and/or gas production and extended producing life. Some projects are approved and implemented, while others are subject to further study, postponed or shelved. The size of these projects varies substantially in terms of both production effects and costs.

Most of the unsanctioned projects on producing fields involve relatively small quantities compared with those which form the basis for new field developments. Many of the well projects which fall into this category have quantities below 2.5 million Sm3 oe. These embrace drilling of one or a few new development wells. Continuous efforts are pursued on the fields to evaluate the basis for new wells. The decision on whether to drill a specific well is based on an assessment of its profitability.

An overview of various types of unsanctioned projects for improving recovery on producing fields is presented in figures 2.10 and 2.11. While the first of these shows a specific project, the second covers possible but immature measures for improved recovery. Since the latter are considerably more uncertain, the NPD does not consider it appropriate to show them with resource estimates.

About a third of the quantities in the specific projects can be produced by drilling more development wells. See figure 2.10. More wells are also important for projects involving the injection of water and/or gas and further development of the fields. Such projects account for a further 25 per cent of the quantity. Further development of a field embraces major upgrades and projects where new installations are planned. Low-pressure production also represents an important measure for improving gas and oil recovery. The development of subsea compression technology in recent years on Åsgard and Ormen Lange is important for improving recovery on subsea developments.

 

Figure 2.10

Figure 2.10 Projects in resource categories 4A and 5A by type.

 

In the longer term, other types of projects which have been reported as possible future improved recovery measures could also yield substantial additional quantities. Advanced methods account for 19 of 146 possible measures identified, and contribute 22 per cent of the quantity in this category. See figure 2.11. Injection of CO2 is one example of such methods.

 

Figure 2.11

Figure 2.11 Projects in resource category 7A by type.

 

 

Potential for improved recovery

Work on ensuring the highest possible recovery from a field begins during development planning and installation design. Most oil fields on the NCS already incorporate pressure support through water and/or gas injection from the time they come on stream. Ever better tools for reservoir monitoring help to improve recovery strategies for the fields. Systematic data acquisition and use of production and reservoir information increase understanding of the reservoir’s properties throughout the production phase. Improved understanding of where oil and gas are located and where they flow is important for better well placement. New drilling targets are constantly being identified in this way, which means that additional wells need to be drilled.

Remaining reserves in a field are the quantity of oil and/or gas included in the approved plans at any given time. Figure 2.12 presents an overview of the recovery status for the 25 oil fields with the largest quantity of remaining oil in the ground at year end. When projects which improve recovery are sanctioned, reserves will increase and the remaining quantity (light green) will be somewhat reduced.

 

Figure 2.12

Figure 2.12 Resource overview for the 25 largest oil fields, quantities sold, reserves and remaining oil without new measures.

 

How much oil can be produced from a field is a function of such factors as reservoir conditions, development solutions, production strategies and available technology. Oil not covered by current production plans forms the basis for improved recovery methods. This oil may be divided into two categories – mobile and immobile. Mobile oil represents mobilisable oil not currently in contact with production wells or injection water/gas. In principle, it can be recovered with the aid of additional wells and longer-lasting use of water and/or gas injection. Immobile oil is stuck to the pore walls in the reservoir, and cannot be squeezed out of the pores and produced by injecting (more) water or gas.

Postponing gas production is an important measure for improved oil recovery (IOR) on some fields. Where fields contain both oil and gas in the same reservoir, the timing of gas production can affect overall oil recovery. As long as the gas is retained in the reservoir or injected back into it, the reservoir pressure can be maintained and more oil produced. When the gas is produced from the reservoir, the pressure will decline and oil will be left behind. On such fields, the deferred revenues from gas production must be weighed against the income from IOR. Deferred production of gas caps and continued gas injection are important IOR measures on fields such as Oseberg, Troll and Visund. The NPD estimates that gas injection in Oseberg has yielded more than 50 million Sm3 of additional oil.

IOR methods can be categorised as conventional or advanced. The latter (less mature) methods are often termed enhanced oil recovery (EOR). They involve advanced flooding methods intended to help mobilise part of the immobile oil. See figure 2.13.

 

Figure 2.13

Figure 2.13 Cross-section of a reservoir showing an example of oil and water distribution after waterflooding, and distribution of the liquids at pore level.

 

Advanced methods have been little used on the NCS. A good deal of research has been and is being conducted into different techniques, and there have been scattered pilot trials and field applications. A continued commitment in this area is important. The government established an IOR centre in 2013 to encourage further efforts. First awarded in 1998, the NPD’s IOR prize has been presented to some of the initiatives pursued.

Microbial EOR (Meor) is being utilised on Norne. This method involves giving bacteria the opportunity to change the interfacial tension between oil and water so that more of immobile oil is mobilised.

In addition to the oil left behind in parts of the reservoirs with effective displacement, areas will exist where flooding is less effective and where the sweep medium cannot penetrate. The effectiveness of displacement is governed by the form and extent of the reservoir, the quality of the reservoir rocks and the location of the development wells.

Even with good displacement, some oil will remain in the pores. The size of this residual saturation will depend on rock and oil properties. It is also dependent on the properties of the sweep substance being used. Displacement gas usually yields lower residual saturation (five to 15 per cent) than water (10-25 per cent). The proportion of oil recovered where displacement is effective is termed microscopic displacement efficiency.

The EOR methods which could be used to mobilise part of the immobile oil involve altering the surface tension between oil and water or changing wetting properties in the reservoir. The latter are determined by the physical and chemical properties of the liquids and the reservoir rocks, and determine in their turn whether oil or water lies like a film on the pore surface.

Adding surface-active agents (surfactants/tensides) to injection water can help to improve oil recovery by lowering the surface tension between oil and water, and thereby reducing local residual oil saturation. This method is challenging because it demands continuous chemical injection in specific concentrations. OG211 considers the technique to have a big potential on the NCS. Developments have so far been confined to laboratory work.

Recent research has established that changes in the salinity of injection water can also reduce immobile oil in flooded areas. However, most oil fields on the NCS inject seawater with a salinity lower than the formation water. As a result, low-salinity waterflooding does not appear to have a big potential in existing fields. Studying this effect with a view to optimising the salinity of injection water is nevertheless important, particularly for new fields. Low-salinity injection water will make polymer additives and surfactant flooding more effective.

Certain advanced methods are directed solely at mobile oil and at more effective displacement or sealing of areas already flooded. These techniques involve the use of chemicals (polymers) which increase the viscosity of injection water or block pore channels so that additional oil can be displaced. When channels are blocked, the water must take new routes and accordingly displaces more oil on the way. See figure 2.14.

 

Figure 2.14

Figure 2.14 Polymer flooding.

 

Polymer flooding seems to be the method under study by most licensees. It requires the handling of large quantities of chemicals and control of produced water. The technique speeds up oil production and enhances its efficiency. It has not so far been tested on the NCS. Total uses polymer flooding in parts of the Dalia oil field off Angola, where Statoil is a licensee.

Statoil tested silica gel as a water diversion method on Snorre in 2013. A silicate solution is injected and, under the right conditions, a plug forms which directs the injection water into new undrained areas. A ship normally used for well stimulation was deployed for the test. Fresh water and a silicate-containing injection fluid were produced on board and injected into the reservoir. The results are expected in late 2014.

IOR methods call for the development of technology and expertise in specialised disciplines. Research and technological advances are important for coming up with techniques which can improve recovery from producing fields in the years to come. The NPD is working to ensure that such solutions are developed, tested and implemented. Knowledge-sharing is important for accomplishing this efficiently. Through research programmes and other government support schemes, the emphasis is on transferring and applying knowledge and results from technology trials on one field to others on the NCS. Force is a collaboration forum for oil and gas companies and the government which works for better exploration and production solutions. The NPD serves as its secretariat. More information on this initiative can be found at www.force.org.

 

2.4 Target for reserve growth

To ensure that the necessary attention was paid to reserve growth while simultaneously keeping abreast of developments, the NPD’s 2005 resource report introduced a target of 800 million Sm3 (five billion barrels) for the growth in oil reserves up to 2015.

Annual reserve growth is recorded for fields and discoveries. When the decision is taken to develop a discovery, the quantities underpinning this decision are recognised as reserves. The field’s reserves change as more is learnt about the reservoir and new projects are sanctioned. Reserve growth represents the change from the previous year’s resource account. Figure 2.15 presents the status to date. The coloured areas in the graph illustrate overall reserve growth since 31 December 2004, while the lines indicate the plans which formed the basis for setting the target and for the way to reach it.

Figure 2.15 shows that reserve growth has been at its strongest in recent years, with a flattening out in 2013. The original fields in 2004 (dark green) have experienced the resource growth predicted in the 2004 forecast, but at a slower rate than expected. Contributions from discoveries known when the growth target was formulated have been larger than assumed. In addition, speedy decisions in recent years on developing discoveries made after the target was set have helped to ensure that the realised resource growth has come close to the target. As things currently stand, the target looks unlikely to be reached. A more detailed assessment of target attainment will be presented when the next resource account is published in the spring of 2015.

 

Figure 2.15

Figure 2.15 Development in oil reserve growth since 2004.

 

Since the current target period expires at the end of 2014, the NPD is now setting a new target for growth in oil reserves over the coming 10 years. The basis for this target is provided by the IOR projects for producing fields presented in figure 2.10, and discoveries reviewed in chapter 3. In the NPD’s view, decisions to implement these IOR projects and develop the discoveries could yield a growth of 950 million Sm3 in oil reserves by the end of 2023.

The NPD’s target for oil reserves in 2014-23 is a growth of 1 200 million Sm3. See figure 2.16. The gap between the forecast and the target is expected to be filled by the implementation of yet more measures on the fields, by further optimisation of forthcoming development plans and by continued commercial discoveries which are sanctioned for development during the period.

Figure 2.16

Figure 2.16 The NPD’s target for oil reserve growth in the 2014-23 period, with forecasts.

 

According to the resource account at 31 December 2013, remaining oil reserves totalled 834 million Sm3. Growth as described above would, with the current production forecast, mean that oil reserves will be larger at the end of the target period than they are today. Figure 2.16 provides a stylised presentation of the forecast for reserve growth and a possible way to reach the target. Relatively little growth is expected in the present year, with a big increase in 2015 – primarily because of an expectation that a development decision will be taken for Johan Sverdrup.

Progress of this order calls for a substantial effort, and many investment decisions need to be taken. To achieve the forecast growth of 950 million Sm3 in oil reserves, by far the greatest number of the projects planned on the fields must be implemented. Moreover, most of the discoveries currently under evaluation must be sanctioned for development during the period. In order for these decisions to be taken, the projects must be profitable. Developments in costs and prices will be important, but much could still be gained from optimising production methods and enhancing operational efficiency. The target involves an increase of 250 million Sm3 in oil reserves over and above the reserve growth which forms the basis for the NPD’s production forecast. 


2.5 Development wells

Drilling new development (production and injection) wells is crucial for production trends. Some NOK 50 billion was spent in 2013 to drill 142 new development wells on producing fields. That represented roughly 50 per cent of total investment on these fields.

Some trends

It will normally be the case that the most profitable resources are recovered from a field first, with their recovery described in the development plan. The further production has progressed, the less profitable an individual improved recovery project would normally be. It can be particularly demanding to achieve profitability for a project which calls for new facilities and extensive conversion and modification of existing installations.

Figure 2.17 shows a marked decline up to 2010 in the number of new development wells on fields which were on stream throughout the 2000-2013 period. In this context, “development wells” embrace new initial wells, sidetracks drilled from an existing well and individual laterals in a multilateral well.

 

Figure 2.17

Figure 2.17 Development in the number of new production wells.

 

The reduction has been greater than planned. Drilling new wells on older fields has proved more demanding than the plans assumed. Several factors account for this. On many fields, production and injection over time have affected pressure conditions both within and above the reservoir. The need to upgrade the permanent drilling rigs and their use for well maintenance represent other reasons. All available slots are in use on many fields, restricting opportunities to drill new wells. Another challenge is that residual reserves are located more peripherally in the field as it gets older. That means longer and more complex well paths if drilling is to be done by a permanent rig. A scarcity of mobile rigs has also caused the postponement of wells which could have been drilled on a field.

Before subsea technology was developed in the 1980s, all development wells – with only a few exceptions – were drilled by a rig permanently positioned on a fixed field installation. All the big oil fields developed during the 1970s, 1980s and early 1990s have installations with permanent rigs. Several large fields, such as Troll and Åsgard, have subsequently been developed with subseacompleted wells drilled from mobile units. More wells on fields with permanent rigs are also gradually being drilled from mobile units. Despite the trend towards an increasing proportion of wells drilled by mobile units, permanent rigs are still important for oil production on many large oil fields. That applies not only to drilling new wells but also to necessary maintenance of existing wells.

Wells drilled on fields which were on stream throughout 2000-13 increased again from 2010. Figure 2.18 shows that wells drilled from permanent rigs remained stable at around 35 per year, while new wells from mobile units rose. Growth from 2012 to 2013 primarily reflected drilling of more wells on the Balder, Ekofisk, Eldfisk, Oseberg Sør and Troll fields. The Balder increase related to a current drilling campaign. On Ekofisk and Eldfisk, the rise must be viewed primarily in relation to the Ekofisk Sør and Eldfisk II projects. The main reason on Oseberg Sør is the development of the Stjerne discovery, which is part of Oseberg Sør, while more laterals are being drilled on Troll by increasing the number of rigs on this field. A substantial improvement in the availability of new mobile units has been a precondition for the ability to drill more development wells.

Figure 2.18

Figure 2.18 Development in the number of new production wells for fields on stream in 2000 – drilled from fixed or mobile units.

 

Choosing a development solution with permanent or mobile rigs depends on such considerations as the extent of the reservoir, its complexity and the water depth. Differences in drilling efficiency between permanent and mobile rigs could also be significant for the choice of solution. The most recent field developed with a permanent rig is Kvitebjørn, which came on stream in 2004. Concepts based on mobile rigs have been chosen for all subsequent new developments.

The need for wells is related to their economic life. How long a well will produce depends on such considerations as reservoir properties, production strategy and its design and maintenance. Many of today’s production wells have a long producing history. Figure 2.19 presents active wells on a large oil field developed in the 1980s by age. This shows that a substantial proportion of the petroleum produced in 2012 originated from wells which were more than 10 years old.

Figure 2.19

Figure 2.19 Oil production in 2012 for a large oil field developed in the 1980s, by when the wells came on stream.

 

Production from future wells

The largest and most accessible drilling targets on a field are usually drilled first. Target size is defined by the petroleum production expected from the well. Over time, the targets drilled contain steadily smaller quantities. Distance to the drilling target is also important. The profitability of drilling for resources which are small and/or involve long well paths is accordingly crucial when deciding whether to drill more wells.

Figure 2.20 presents planned development wells on producing fields in 2014, including initial wells, sidetracks and multilaterals. Multilaterals are counted as one well. Wells drilled from both fixed installations and mobile units are included. Expected recoverable resources from the greater part of the wells are less than one million Sm3 oe. The median well is expected to yield 0.6 million Sm3 oe.

Combined with a trend towards smaller and more complex well targets, the substantial rise in costs in the drilling and well sector represent a particular challenge for future development on the NCS. 

Figure 2.20

Figure 2.20 The size of well targets due to be drilled on producing fields in 2014.

 

More wells – new infrastructure needed

Many projects on producing fields involve drilling wells to improve recovery. See figure 2.10. But new wells are also important for enhancing the effect of other improved recovery measures. Higher well density is an advantage, for example, with CO2 injection and polymer flooding. A shorter distance between wells shortens the time between injection and its effect on production. A reduction in response time can help to make this type of project profitable.

While more wells are desirable for improving recovery, problems have been experienced on a number of fields with drilling planned wells. No simple solutions exist for increasing the level of drilling activity, but many possible measures might add up to a substantial contribution. These include (new) methods for handling the technical and reservoir-related challenges faced when drilling on producing fields, and moves to enhance drilling efficiency.

New installations are required on a number of fields in order to boost drilling activity. Existing facilities are usually positioned centrally on the field, which makes it difficult to drill the outer flanks. Furthermore, there is a shortage of well slots on a number of fields. That limits opportunities to drill new wells. To increase drilling activity, new installations could be relevant to shorten wells and provide additional slots.

Additional facilities could be anything from new seabed templates and wellhead platforms to large installations with or without their own drilling rig. Good solutions which make provision for a long-term production strategy will call for substantial investment. Decisions based on a short-term perspective could impede long-term value creation.

Figure 2.21 shows that plans to invest in new facilities, either on the seabed or as wellhead platforms, have been reported for 10 fields in order to drill more wells. In addition, similar evaluations in an early phase for a number of fields. Choice of installation type will affect the production strategy. A platform will normally provide the flexibility to recover larger quantities from an area than a subsea solution.

Figure 2.21

Figure 2.21 Recovery from planned new installations and wells on fields.

 

2.6 Use of spare capacity in existing infrastructure

Substantial investments have been made in infrastructure on the NCS. Capital spending on offshore installations, pipelines and land facilities totals just under NOK 3 000 billion in 2013 money. New field developments can take advantage of existing facilities at nearby hubs, permitting even better use of infrastructure on the old field and extending its producing life.

This report uses the term “hub” for fields with significant joint operation of processing capacity – in other words, equipment for separating the various hydrocarbon types and water from petroleum. Allowing process equipment to be shared between several fields, joint operation is an efficient solution for reducing capital spending as well as operating and unit costs.

Many fields on the NCS are in a phase where production is declining. See Figure 2.1. Unit costs will thereby rise, since a large proportion of the cost of operating a field is independent of the quantity of production. This emerges from Figure 2.7. Unit costs for a hub provide a more accurate picture of costs in an area than the figures for an individual field. Figure 2.22 provides a simple presentation of the benefits of phasing-in nearby fields. The main field can produce for longer, and neighbouring discoveries are developed in a cost-efficient manner.

Figure 2.22 illustrates that, at an oil price of NOK 4 000 per Sm3 or just over USD 100 per barrel, profitable production from the hub is extended from 23 to 30 years. During this period, the tie-in field is produced and the main field can use the additional producing life to implement its own improved recovery measures. Without this opportunity, certain small discoveries would not have been developed or would have been considerably less profitable, while producing life for the main field would have been shorter.

 

Figure 2.22

Figure 2.22 Stylised example of cumulative production and unit costs for hubs and phased-in fields.

 

The number of producing fields has grown steadily since the late 1970s, with the strongest increase over the past 10 years. That partly reflects high oil prices, which have ensured profitable development, and the many new discoveries made in the period. More fields on the NCS, many with their own processing facilities, provide greater opportunities for profitable phasing-in of nearby discoveries large and small. The fact that the number of hubs in operation is not increasing as rapidly as producing fields means that the share of joint operation on the NCS is rising.

 

Figure 2.23

Figure 2.23 Development in the number of hubs, possible hubs and fields tied back to hubs.

 

The effect of securing larger quantities by sharing the cost of operating a facility is illustrated in figure 2.24. This presents the development in costs per unit produced under three different assumptions. The bars show how unit costs develop when new third-party quantities are included. If a field’s own production were to carry all expenditure, unit costs would increase. In the opposite case, unit costs would be lower had it been possible to maintain the same level of production as at the start of the period.

 

Figure 2.24

Figure 2.24 Development of unit costs for fields on stream throughout the 2000-13 period.

 

Production beyond the level originally planned means that the producing life of the field is extended. Figure 2.25 presents the average change in expected producing life for the individual fields, annually and in total, since 2002. The trend since 2002 is that expected producing life has increased by 12 months for each year that passes. The remaining expected producing life is now as long as it was 12 years ago.

 

 

Figure 2.25

Figure 2.25 Development of expected producing life for fields.

 

Gullfaks is a hub. Process capacity on this field means that it can also receive and treat production from surrounding fields. These are Gullfaks Sør, Gimle (which is produced through wells drilled from Gullfaks C), Tordis and Visund Sør. See figure 2.26.

 

Figure 2.26

Figure 2.26 Production from the Gullfaks installations, own and third-party quantities.

 

The government has been concerned to facilitate the use of spare processing capacity on existing platforms and transport capacity in pipelines. As a result, the MPE has issued a separate regulation on third-party use of facilities (TPA). This helps to make the negotiating process more efficient, and provides parameters for determining tariffs and other conditions. An important principle in agreements on third-party use of facilities is that profit from the production should primarily be taken out on the field. At the same time, such agreements must provide incentives for the owners to maintain capacity on the facility and to make investments in additional capacity.


22.04.2014