Opportunities and challenges for producing fields

Resource-report-2011

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Introduction

Oil production on the NCS has fallen in recent years. This decline was expected, but has been rather steeper than earlier assumed. Production has almost halved from its 2001 peak, and is now back at the 1991 level. However, the decline can be restricted through exploration, development of new oil discoveries and a strengthened commitment to IOR on existing fields.

On average, more than half the oil originally in place in the reservoirs will be left in the ground under current plans. Continuing IOR efforts on existing fields is therefore important. Injection as well as drilling and well maintenance are important for producing today’s reserves. They could also contribute to increasing reserves in the fields. Recovery could be further improved if advanced injection methods and new technology are developed and qualified through field trials. Close follow-up and facilitation by the authorities have historically proved useful in such processes, and will continue to play an important role in the future.


Development of production

At 31 December 2010, 3.62 billion scm of oil and 1 547 billion scm of gas had been sold and delivered from 82 fields on the NCS. Sixty-nine fields are currently in production, while 13 have ceased to produce. Petroleum activities in Norway began in the North Sea, and this area has been and remains responsible for the largest share of production.

Oil output from the big oil fields in the North Sea has declined since the end of the 1990s. See figure 5.1. This is a natural consequence of the fact that many of the fields were developed in a short space of time. However, production from the Norwegian Sea and a number of small North Sea fields has helped to dampen the declining trend. Forecasts for the next five years expect a further fall, but not one as steep as in recent years.

 

Figure 5.1 Historical oil production and the forecast to 2015. Output is shown in green for North Sea fields and blue for Norwegian Sea fields

Figure 5.1 Historical oil production and the forecast to 2015. Output is shown in green for North Sea fields and blue for Norwegian Sea fields

 

Gjøa, Vega and Vega Sør in the northern part of Norway’s North Sea sector came on stream in 2010, as did Morvin in the Norwegian Sea. All these fields contain a lot of gas and some oil, and all will be produced through pressure depletion. Trym came on stream in February 2011. This is the first Norwegian field to be tied back to a Danish installation. Skarv, Gaupe and Oselvar are due to begin production during the year.

The MPE approved the PDO for supplementary resources on Vigdis and Oseberg Sør, also known as Vigdis Nordøst and Stjerne, in September 2011. Further development of Ekofisk and new development of Eldfisk rank as the biggest investment decisions in 2011. Similar investment has earlier been made on both these fields as well as on Valhall. Ekofisk has been further developed in several stages with new installations, and underwent a major redevelopment in 1998. The recovery strategy was changed on Eldfisk, with a new water injection facility installed there in 2000. The Valhall field centre is currently being replaced, with an anticipated start-up in the first half of 2012. The NPD expects to see renewal activity on a number of fields in the Tampen area of Norway’s northern North Sea sector during the near future.

Figure 5.2 shows production developments for oil and the water cut in the liquids flow from wells – both subsea and on fixed installations – for the whole NCS in 2000-10. Overall oil output declined in this period, with the biggest reduction from wells on fixed installations. The produced water cut has increased as a natural consequence of large-scale water injection over a long time to maintain pressure and displace oil in the reservoirs. Subsea wells currently have a lower water cut, but experienced the greatest increase in the 2000-10 period. Producing more water is necessary in order to optimise oil recovery from the fields. That presents a challenge for the production facilities, and also involves environmental challenges. Techniques for sealing the reservoir zones or well sections with the highest water cut have been developed and to some extent adopted. An example of such innovations is provided by valves which automatically shut off sections of the well when water production becomes excessive.

 

Figure 5.2 Distribution of oil production and water cut from subsea wells and wells on fixed installations, 2000-2010

Figure 5.2 Distribution of oil production and water cut from subsea wells and wells on fixed installations, 2000-2010

 

About three-quarters of the produced gas is exported, with the rest being used for injection, processed into natural gas liquids (NGL) and condensate, flared or used as fuel for about 170 gas turbines on the NCS. Injecting gas has made and is continuing to make a substantial contribution to oil recovery. While gas output has risen, the volume used for injection, fuel, NGL, condensate and flaring has stayed more or less constant. The proportion of gas being exported has accordingly increased. See figure 5.3.

 

Figure 5.3 Total gas production on the NCS, 2000-2010

Figure 5.3 Total gas production on the NCS, 2000-2010

 

Remaining reserves and resources in fields

The expected recovery factor for fields on the NCS, based on existing plans, averages 46 per cent for oil and 70 per cent for gas. This factor varies considerably from field to field and between different reservoirs in the same field. It depends on such considerations as reservoir properties, recovery strategy and the flexibility of production facilities.

Figure 5.4 presents the development in the average recovery factor for fields of various sizes and for the NCS as a whole. As the figure shows, the largest fields have a higher recovery factor than smaller ones. This could be because large fields have a long producing life, making it possible to implement a number of measures over time to improve recovery. By and large, fields approved for development in recent years have been small. Limited reserves mean that the facilities installed normally lack the same flexibility as installations on a large field. A number of the small fields also have complex reservoirs, which contributes in turn to a lower oil recovery factor. Internationally, the average recovery factor for oil fields is estimated at 22 per cent. Good reservoir properties have made a strong contribution to the high factor on the NCS. In addition, extensive research, technology development and close regulatory followup have been important in improving recovery. Water and/or gas injection, three- and four-dimensional (3D and 4D) seismic surveys, systematic data acquisition for better reservoir understanding, and drilling more wells than planned when the field was developed have made big contributions to the high recovery factor. The relationship between produced resources, remaining reserves and contingent resources (see the resource classification in chapter 1) has developed since production began in 1971.

 

Figure 5.4 Development of the average recovery factor for fields of various sizes

Figure 5.4 Development of the average recovery factor for fields of various sizes

 

Figure 5.5 illustrates this development for total gas and liquid resources. It also presents the size relationship in 2010 and how the resources break down between the three sea areas. Undiscovered resources are excluded. The bulk of the remaining proven resources registered in the NPD’s database lie in the North Sea.

 

Figure 5.5 Development of proven resources in the resource account and status at 31 December 2010

Figure 5.5 Development of proven resources in the resource account and status at 31 December 2010

 

A high recovery factor is achieved on a number of fields through a combination of water and gas injection. On average, large fields have a higher recovery factor than small ones, but the variations are once again substantial. This is illustrated in table 5.1, which shows the original volume in place and recovery factor under current plans for the 12 largest oil fields. An increase in the recovery factor for a field could represent substantial value for society, depending on production costs and future price developments. Were the recovery factor to be increased by one per cent on important oil fields such as Heidrun and Snorre, for example, the gross value potential would be about NOK 16-18 billion per field at an oil price of NOK 570 per barrel.

 

The 12 largest oil fields ranked by reserves originally
in place at 31 December 2010
Field Oil resources
originally
in place
Mill scm
Oil reserves,
incl sold and
delivered
Mill scm
Recovery
factor

Per cent
Main drive mechanism
EKOFISK 1 099 534.6 49 Water injection, earlier pressure depletion and compaction drive
STATFJORD 860 567.3 66 Pressure depletion in the late phase. Earlier water, water alternating gas and some gas injection
TROLL 642 250.0 39 Pressure depletion with natural water and gas drive, some gas injection
GULLFAKS 642 365.4 61 Water injection. Some gas and water alternating gas injection
OSEBERG 592 377.2 64 Gas injection. Some water and water alternating gas injection
SNORRE 515 241.2 47 Water, gas and water alternating gas injection
ELDFISK 463 133.8 29 Water injection, earlier pressure depletion and compaction drive
VALHALL 435 145.5 33 Water injection, earlier pressure depletion and compaction drive
HEIDRUN 432 169.0 39 Water injection. Some gas injection and pressure depletion
GRANE 229 120.7 53 Gas injection, from 2011 water injection and gas reinjection
DRAUGEN 212 143.1 68 Natural water drive and water injection
OSEBERG SØR* 208 52.6 25 Water and gas injection. Some water alternating gas injection

*The Oseberg South field comprises several separate deposits and has been developed with a fixed steel platform tied to several subsea templates. These deposits have differing reservoir properties, and drive mechanisms vary from deposit to deposit.

Table 5.1 The 12 largest oil fields ranked by reserves originally in place at 31 December 2010


 

Target for reserve growth

The NPD set a target for reserve growth in 2005 which involved maturing 800 million scm of oil from resources to reserves by 2015. Such growth derives from developing new fields and increasing reserves in producing fields. Figure 5.6 presents gross reserve growth, write-downs and net reserve growth in relation to the target. Sufficient reserves have been matured on an annual basis to attain the target, but write-downs of reserves in fields have put reaching this goal behind schedule. Write-downs mean reducing the reserve estimate for certain fields. Reasons could include updating the reservoir model, a faster-than-expected decline in production, or drilling fewer wells than previously estimated. Oil earlier defined as reserves could thereby get reclassified as resources. Reversals of such write-downs could be possible if action is taken.

 

Figure 5.6 Gross reserve growth, write-downs and net reserve growth compared with the NPD’s target

Figure 5.6 Gross reserve growth, write-downs and net reserve growth compared with the NPD’s target

 

Licensees of producing fields identified specific projects and measures in 2010 which they believed could help to increase reserves. These projects and measures can be categorised on the basis of project type. The identified volume is 385 million scm of oil. Figure 5.7 presents identified projects for producing fields by category.

 

Figure 5.7 Reported resources in plans and methods for reserve growth in producing fields

Figure 5.7 Reported resources in plans and methods for reserve growth in producing fields

 

The biggest contribution to reserve growth for producing fields comes from well-related projects, such as drilling new wells or major well maintenance campaigns. Licensees report that new projects for injecting water, gas or water alternating gas (WAG) and enhanced recovery methods will contribute to a smaller proportion of the possible reserve growth.

The NPD estimates that about a quarter of the original oil in place cannot be produced by conventional recovery methods. That is because it cannot be freed from the rocks – in other words, it is immobile. To mobilise and produce this oil, enhanced oil recovery (EOR) methods must be adopted.

 

Enhanced oil recovery (EOR)

Enhanced oil recovery (EOR) EOR methods include injection of polymers, surfactants, CO2, low-saline water, silicates and miscible gas.

 

The NPD carried out a survey in 2007 of the relationship between mobile and immobile oil in the reservoirs. An updating in 2011 for the 12 largest fields shows that 43 per cent of the remaining oil is immobile. Because of differing reservoir properties, the quantity of immobile oil varies from field to field. Chalk fields often have a higher proportion than sandstone ones.

Reaching the NPD’s target for reserve growth calls for decisions to be taken on new projects and for write-downs to be minimised. Existing plans must be implemented if the reserves are to be produced. Further reserves could be added by developing and adopting new technology, developing discoveries, extending producing life, redeveloping fields and applying EOR methods.

 

Petroleum White Paper

The MPE appointed a team of experts – the Åm committee – in 2010 to consider measures for improving the recovery of petroleum resources from existing fields. White Paper no 28 An industry for the future – concerning petroleum activities contains a number of the committee’s recommended measures. In addition, the MPE has asked the petroleum industry, through the Konkraft collaboration, to assess the measures proposed. The White Paper includes a number of measures based both on the Åm committee’s report and on new proposals. Key action proposed on IOR includes:

  • intensify follow-up of fields in the late-life phase
  • assess the need to strengthen the regulations to ensure that adequate attention is paid to IOR and good resource management
  • approve applications to extend the duration of a production licence with the same licensee structure if this makes better resource utilisation more likely, and unless special considerations dictate another course
  • place greater emphasis on a majority of shares when determining voting rules on the award of new production licences
  • appoint a team of experts to clarify and identify obstacles which limit rig capacity on the NCS, and propose measures to improve the supply of vessels involved in drilling, while encouraging licensees on the NCS to establish rig pools
  • work together with key players on the NCS to secure an increased commitment to piloting new technology
  • assess the creation of an IOR research centre, based on open competition


Existing technology

Much of the remaining mobile oil in producing fields can in theory be recovered with known and tested technology. Injecting water and gas to maintain reservoir pressure and displace oil, drilling wells, and gathering data to improve reservoir descriptions will accordingly remain important. Data-gathering with 4D seismic surveys provides information on the location of residual petroleum and where production wells should be drilled.

Automation, remote control and condition-based maintenance help to reduce operating costs, which contributes in turn to a longer producing life for the fields. They also extend the time frame for phasing-in new discoveries and implementing additional measures which can improve recovery.

 

Valhall life-of-field seismic
The Valhall unit and operator BP was awarded the NPD’s IOR prize in 2003 for installing the world’s first full-scale life-of-field seismic facility. A total of 9 500 sensors linked by 120 kilometres of cable are spread over 35 square kilometres. This installation will help to increase reservoir knowledge, ensure safer and more cost-effective drilling, and give better access to remaining reserves.


Water and gas injection

Injecting water and gas to maintain reservoir pressure and displace oil or condensate is important for production on the NCS. If reservoir pressure declines too much, profitable oil and gas can be lost. Injection is particularly significant for improving liquids recovery. In many cases, injecting gas rather than water achieves better oil drainage.

Water and gas were injected in 30 and 18 fields respectively during 2010. A combination of water and gas injection is used on a number of these fields, while 33 are produced by pressure depletion. That category includes most of the gas and gas/condensate fields. Twenty-two new fields came on stream in 2005-10. Fifteen of them currently produce without injection. Continuous assessment of the drainage strategy for each field is important.

The quantity of water injected for pressure support has declined since 2004. See figure 5.8. That reflects several factors. Water injection was reduced by a total of 12 million cubic metres from 2004 to 2005 on Gullfaks and Draugen. In addition, the Statfjord late-life project began in 2008 with the aim of reducing pressure as far as possible by halting injection. This is being done to produce as much as possible of the gas which was previously injected, associated gas, and as much as possible of the remaining oil. Water injection was also reduced on other fields in 2004-10, but not to the same extent. Some of the decline reflects shut-in injection wells. This may be part of the drainage strategy on some fields, while injectors may be shut in for long periods on other fields owing to a lack of maintenance. Injection wells represent a long-term recovery measure which is important for prudent resource management and long-term value creation. Giving priority to drilling and maintaining injectors is therefore important.

 

Figure 5.8 Water injection from subsea wells and wells on fixed installations. Statfjord is shown separately

Figure 5.8 Water injection from subsea wells and wells on fixed installations. Statfjord is shown separately

 

Annual volumes of injection gas have fluctuated between 30 and 43 billion scm over the past 10 years. See figure 5.9. More gas has been injected in subsea wells than in wells on fixed installations since 2002. Total gas injection has declined since 2004, partly owing to its cessation on Sleipner Øst, Norne and Statfjord for production reasons. Injection has also been reduced on Njord, Oseberg and Åsgard. Gas injection on Tyrihans began in 2008. Grane ceased importing gas in 2010, and now injects only gas produced from the field. Water injection began on Grane in 2011.

 

Figure 5.9 Gas injection in subsea wells and wells on fixed installations

Figure 5.9 Gas injection in subsea wells and wells on fixed installations

 

Gas production has been deferred on a number of fields with a gas cap over the oil zone in order to recover more crude. Provision is also being made for drilling additional wells and for extending the time frame for other IOR measures. A good example is Oseberg, where increased gas exports have been deferred several times because maintaining gas injection creates higher value.


Drilling and wells

Most development wells were drilled earlier from fixed installations on the field, but a growing number are now being drilled from mobile units. This is a consequence of many fields being developed in recent years either with fixed installations without a drilling rig or with subsea facilities. However, drilling from fixed installations remains important for realising the resource potential of most large fields on the NCS.

Drilling of development wells peaked in 2001. The number drilled from both fixed installations and mobile units has since declined. See figure 5.10. The drilling peak partly reflected the completion of major developments such as Balder, Jotun, Gullfaks Sør and Åsgard around 2000. Another explanation for the reduction is that companies have failed to fulfil their planned drilling programmes in recent years.

 

Figure 5.10 Number of development wells spudded, including multilaterals

Figure 5.10 Number of development wells spudded, including multilaterals

 

Figure 5.11 presents four forecasts in 2007-10 for the number of wells due to be drilled in 2010 on the 12 largest oil fields. Expectations of the number of wells to be drilled in 2010 have declined year on year. New plans defer implementation of the wells. Several factors explain the build-up of this shortfall in drilling and well maintenance. Lack of rig capacity, shortage of personnel and technical equipment, and complex pressure conditions may have delayed or halted the drilling of planned wells.

 

Figure 5.11 Drilling plans for development wells in 2010 on the 12 largest oil fields

Figure 5.11 Drilling plans for development wells in 2010 on the 12 largest oil fields

 

High costs and lack of capacity have made it difficult to secure rigs for short assignments. Combined with the reluctance of operators to charter rigs unless the partnership commits to a work programme for the whole charter period, this may have contributed to the drilling of fewer wells. The permanent drilling facilities on a number of fields are more than 20 years old. Maintenance needs are growing and leading to greater costs and delays.

Prioritising rig capacity to meet a rising demand for well interventions and maintenance has meant fewer new development wells. Well slots are in short supply on a number of fields. To secure more wells there, they must be drilled as sidetracks from existing wells or slots must be reused. The latter approach can be time-consuming and expensive because existing wells have to be plugged and the slot readied for new drilling. Drilling sidetracks is cost-effective if the existing well path has the necessary quality. A growing amount of rig time is also being devoted to permanent abandonment of wells in order to meet safety and environmental standards. Such work may be at the expense of new development wells and well maintenance.

The resource-related and financial consequences of the drilling/ well maintenance backlog are difficult to estimate. Production can be recovered after a relatively short period for some wells, while recovering deferred output from others will mean that the field must produce for longer – which could boost costs. Nevertheless, more wells are generally drilled than were planned at the PDO date. The number of wells is often underestimated when preparing the PDO because future and more uncertain drilling targets are not included in the original plans.

As a result of the issues related to rig capacity, growing attention has been paid to improving the position. A gradual increase in the number of drilling units active on the NCS has accordingly occurred. Five new units are expected during 2011, and plans call for more in subsequent years. This is a positive trend. One challenge could be to retain the drilling units already operating on the NCS.

Because of complex geological conditions, such as sub-surface faults, most reservoirs comprise many “pockets” of oil which represent separate drilling targets. One reservoir may have many such targets. A number of these may be substantial, while others are small and marginally commercial.

The biggest and best drilling targets located closest to the installation are normally drilled first. That also yields the highest value creation for a development project. Over time, therefore, the targets drilled become increasingly marginal and this reduces average oil production per well. The distance from installation to drilling target is important for both costs and drilling complexity. Drilling problems can arise later in the field’s producing life. That applies particularly when pressure conditions in and above the reservoir change as a result of production. Drilling extendedreach wells to peripheral targets may then become challenging. Many of the large fields now face such challenges.

As wells age, the need for maintenance and the cost of such work rises. See figure 5.12. Maintaining subsea wells calls for mobile units or special vessels. Several operators are now working on specific plans to build “category B” rigs, which can meet the need for subsea well maintenance at a lower cost.

 

Figure 5.12 Share of well maintenance in ordinary operating costs

Figure 5.12 Share of well maintenance in ordinary operating costs

 

A considerable amount of rig time on fixed installations is devoted to well maintenance. Many permanent drilling facilities need upgrading in the next few years. This requirement has long been known, but it has taken considerable time to decide on the best solution for a specific installation. Upgrading could enhance drilling efficiency in the long term, but fewer wells will be drilled or maintained while such work is being carried out unless mobile drilling units or vessels are used as temporary replacements.

 

Category B rigs
This rig type is designed to perform well interventions year-round and to use technology for heavy intervention, high-pressure pumping and cementing, as well as light drilling methods such as through-tubing rotary (TTRD) and coiled tubing drilling.

 

Technology development

Substantial technology development and implementation are being pursued for well quality and for drilling and well operations. This has consequences for both drilling costs and the revenue potential of a well. An important motivation for technology development is that it will help to reduce drilling costs. These have increased substantially over time. The trend is illustrated in figure 5.13, which presents the average cost of development wells on the NCS adjusted for general price inflation. Higher rig rates and lower drilling efficiency make big contributions to cost growth.

 

Figure 5.13 The average cost of a development well on the NCS in 2000, 2005 and 2009

Figure 5.13 The average cost of a development well on the NCS in 2000, 2005 and 2009

 

Issues which arise as fields age also help to boost costs. One example is the need for pressure and underbalanced drilling to handle reservoirs with low pressure and/or big pressure differences. Intelligent wells can help to improve recovery and to reduce the need for later downhole maintenance, but contribute to higher well costs initially.

The work of drilling sidetracks and maintaining wells on fields without permanent drilling facilities is performed today by more or less the same units which drill new development and exploration wells. Mobile units are often built to carry out complex drilling operations in deep water and a tough climate. That makes them expensive to charter and over-dimensioned for this kind of job. A number of the simpler drilling and well maintenance operations can be conducted using developed and tested technology deployed on smaller units or other vessels designed for this purpose. That could make sidetracks and well maintenance cheaper.


Infrastructure challenges

The North Sea is a mature area with an extensive infrastructure, which costs a lot to maintain and operate. Remaining resources are large, and many of the big fields are in a late-life phase. Lower production and aging of parts of the infrastructure create a need to simplify and renew facilities on fields with resources for several decades to come, so that production can be extended. Small discoveries also require infrastructure if they are to be tied back as a satellite to an installation with production facilities.

Seabed subsidence in the Ekofisk area has contributed to the need for infrastructure renewal. The same applies to Eldfisk and Valhall. Decisions on substantial investment have been taken on all these fields to lay the basis for continued operation over a long period.

The Tampen area involves nine large installations with production facilities on Statfjord, Gullfaks, Snorre and Visund. In addition come a number of subsea installations. As production declines and the infrastructure ages, the need arises to simplify this infrastructure so that remaining resources in the area can be recovered profitably and cost-effectively. This requires in part that licensees coordinate their plans so that possible coordination gains can be achieved. The NPD will follow up possible gains of this kind.

 

The IOR prize for 2009

The IOR prize for 2009 was awarded by the NPD to FMC Technologies for developing a well control system which permits safe and pressure-controlled drilling of sidetracks through existing subsea wells. Together with Statoil, FMC has developed and tested this technology on Åsgard to produce the world’s longest TTRD sidetrack from a mobile rig. The ability to drill low-cost sidetracks opens great opportunities to improve recovery from fields with subsea wells dependent on mobile drilling units. The NPD praised FMC for its purposeful efforts since 1999 to develop cost-effective solutions for improved recovery from subsea wells. FMC has devoted substantial resources to achieving this goal without a guarantee of commercial success. Funds from oil companies and the Demo 2000 programme have covered part of the cost.

Read more here >>


New methods and technology

 

Subsea technology

Demand for technology which can help to improve recovery from fields developed with subsea installations is set to increase because a growing number of fields are being brought on stream in this way. Additional development with subsea solutions is also conceivable on a number of the large oil fields when they eventually move into late-life production. Two technologies which could contribute to improving recovery are subsea separation and subsea compression.

Subsea separation has already been qualified, and the world’s first commercial installation of this kind became operational on Tordis at the end of 2007. The concept is that water and sand are separated out on the seabed before piping the oil to the processing facility. Waste water is injected in a sub-surface aquifer. Separation was a success on Tordis. However, the project was halted in May 2008 when the injected water was found to be seeping back to the surface.

Seabed compression remains to be qualified. The Åsgard licensees have nevertheless resolved to adopt this technology to improve recovery from the Midgard reservoir and the nearby Mikkel field. That could represent the world’s first field application for such technology. Boosting wellstream pressure before piping to the processing facility avoids a number of flow-related challenges. Recovery from the field can also be increased because pressure in the wells can be reduced. Subsea compression is being considered for a number of fields, including Ormen Lange and Gullfaks Sør.


Production of immobile oil

Immobile oil offers a big potential. The most promising methods for producing it are injecting water with chemical additives or miscible gases such as hydrocarbon gas or CO2. Injecting lowsalinity water has also been identified as an interesting method.

Various EOR methods were evaluated for use on the NCS in the Spor (1985-91) and Ruth (1992-96) research programmes. A number of pilots were conducted, including ones involving WAG. This resulted in the definition of the latter as a conventional method. Gas and WAG injection have made substantial contributions to the high level of recovery, including on Oseberg and Statfjord.

Silicate gel and polymer-assisted surfactant flooding (PASF) have been tested on Gullfaks, and foam-assisted WAG (Fawag) was tried out on Snorre. Microbial EOR (Meor) formed part of the research programmes and is being used today on Norne. Low oil prices in the 1990s helped to make the use of new injection methods commercially unattractive. Despite today’s significantly higher oil prices, very few of the new injection methods have been tested on NCS fields since 2000.

Pilot projects play a key role in developing new drainage strategies. The use of EOR methods is field- or reservoir-specific, but mechanisms described after laboratory tests may have a transfer value between fields in a number of cases. Various types of risk are associated with testing and adopting new technology. These may boost costs, while the gain in terms of increased oil production is uncertain. In addition comes the risk of deferred and/or lost production.

Injecting CO2 for IOR has been assessed but not yet adopted on the NCS. Experience from fields on land in the USA and laboratory studies conducted for Norwegian fields show that this method has a substantial potential. Since all Norway’s oil is produced offshore, the technical challenges are great. They include corrosion of production facilities and access to adequate quantities of CO2. In addition, the effectiveness of carbon injection will vary considerable between the different reservoirs.

Full-field application of EOR methods has largely been confined so far to fields on land. That is partly because these do not suffer the space and weight restrictions faced offshore. Logistical challenges are also smaller. The barrier to adopting such technology on offshore fields is therefore higher than on land. However, Total has now initiated the world’s first full-scale polymer injection project on its Dalia offshore field.

 

Using EOR methods on offshore oil fields –
Total’s Dalia project

Polymer injection on Angola’s Dalia field is the first project of its kind in the world. The field lies in deep water (1 200-1 400 metres), comprises highly permeable sandstone (>1D) and contains oil of medium viscosity. It has been developed with subsea wells and produces via a floating production, storage and offloading (FPSO) vessel. The general drainage strategy is water injection via four lines and 31 wells. Production utilises four lines from 37 wells.

Project challenges have included the desire to start polymer injection as early as four years after coming on stream. Others are the wide well spacing, a high salt content and logistics related to injection procedures.

Four injection tests were conducted in 2009 with good results. On that basis, polymer began to be injected in 2010 via one of the four lines. An observation well is to be drilled so that the effect of polymer injection can be established more quickly.

 

Challenges for pilot projects

With high oil prices, recovery methods previously regarded as unprofitable or marginally commercial could yield commercial projects and represent substantial additional value. That includes some of the EOR methods aimed at producing part of the immobile oil remaining in the reservoir after water injection. Several such techniques need to be qualified, which could include conducting a pilot before a decision can be taken for a major fullfield project.

Norwegian oil history shows that pilot projects have created billions of kroner in value. An important example was testing of waterflooding on Ekofisk before the full-scale project was initiated. Another was test production from thin oil zones with horizontal wells before the decision to proceed with the Troll Oil development. Contributions from and involvement by the authorities were important for realising these projects, as well as for gas injection on Oseberg. (See the boxes on Troll Oil and Ekofisk waterflooding). As much as 500 million scm of oil may have been recovered as a result of decisions in these three projects. That represents very substantial value both for the companies concerned and for Norwegian society.

 

Troll Oil

Troll is Norway’s largest gas field, but also contains substantial volumes of oil in thin zones beneath the gas. The licensees believed it would be impossible to recover this oil commercially because drilling technology in the 1980s limited deviated drilling to a maximum angle of 60-70 degrees. This meant that producing the thin oil zones would require too many wells.

The authorities did not want the Troll oil to be lost, as had been the case on Frigg. They required the licensees from an early stage to conduct extensive studies of the recovery potential for the oil. In connection with the unitisation of the two biggest production licences, two operators were named – one for gas (Shell and later Statoil) and one for oil (Norsk Hydro).

New technology was needed for commercial oil recovery from Troll. The authorities accordingly became involved in the efforts to find good technological solutions, and proposed trials with horizontal wells. Hydro studied the method and drilled such a well on Oseberg in a successful trial which ranked as the first use of this technology on the NCS. The oil zones are thicker in Troll Vest than in the eastern section, and opportunities for oil recovery were accordingly regarded as better in this part of the field. A long-term test of oil production using horizontal wells in Troll Vest was conducted in 1989-90 from Petrojarl – initially in a 22-metre oil column and then in one 14 metres thick. This successful trial represented a technological breakthrough.

A PDO for the first phase of Troll Vest was approved in 1992, five years after the licensees had concluded that this would not be commercial. Oil production began in 1995, with gas output from Troll A starting the year after.

 

Ekofisk waterflooding

From Giant discovery, a history of Ekofisk through the first 20 years, Stig S Kvendseth, 1988.

“Work to find solutions which could maximise the degree of recovery for the field began right after the discovery had been made. The degree of recovery was originally estimated to lie between 15 and 19 per cent of the oil reserves. The main problems were concerned with whether the water in the reservoir would damage the production wells – and to what degree the chalk would manage to absorb the water so that more oil could find its way to the production wells. After a period of laboratory research, equipment for a test phase was installed on the 2/4 Bravo platform early in 1981.

“By the fall of 1982, there were sufficient data and prognoses to ascertain that, with the necessary investment, the project was only marginally profitable. The drop in oil prices and the uncertainty in that area which began in January 1983 reduced the economic outlook for the project to an unacceptable level from the point of view of practical economics. In terms of oil quantities, expectations for the project came to about 170 million barrels.

“In order that the water injection might have optimum effect, Phillips had arrived at a time schedule in 1982 that presupposed a positive decision during the summer of 1983. Based on the Phillips group’s conclusion that water injection into the lower reservoir – chalk – was not a profitable business venture, negotiations between the group and the [NPD/MPE] were begun in the spring of 1983. [The] NPD had for some time been interested in, and had worked to promote, water injection as a means of reservoir conservation. From the point of view of the Norwegian government, it was good national utilisation of resources to implement the project – plus it would give Norwegian industry welcome work during a difficult period. The agreement reached modifies the tax terms so as to make them better suited to the nature of the project.”

 

In addition come substantial spin-offs for other fields on the NCS. Based on the success of waterflooding on Ekofisk, this method has since been implemented on Eldfisk and Valhall and is contributing to a substantial increase in the expected recovery factor and producing life for these chalk fields. The method has also been assessed for full-field application on the Tor and Hod chalk fields. Although waterflooding in chalk fields has been successful, substantial quantities of immobile oil remain in them. Ekofisk is the chalk field with the highest expected recovery on the NCS. Even with full implementation of waterflooding and drilling of an ever growing number of wells, however, it will be difficult to achieve a recovery factor much above 50 per cent.

Spin-offs from the Oseberg gas injection project included the decision by Hydro and its partners to develop Grane and Fram with such injection, based on gas imported from other fields. That formed an important part of the strategy for achieving good resource utilisation on these fields. Gas and WAG injection were also adopted on Oseberg Sør.

Development of well technology in connection with Troll Oil has had big spin-offs for other fields, particularly in the use of multilateral wells. Figure 5.14 shows the trend for such wells on the NCS before and after the Troll development. Troll Oil operator Hydro extended this technology to Njord, Fram, Brage and Grane. Other operators have also adopted it. Several suppliers have developed their own solutions for this type of well. Baker Hughes and Halliburton were awarded the NPD’s IOR prize in 2006 for their contributions to these developments.

 

Figure 5.14 Trend for the use of multilateral wells

Figure 5.14 Trend for the use of multilateral wells

 

Long-term thinking and creativity

Two conditions in particular have laid the basis for success on such fields as Ekofisk, Oseberg and Troll: their size, which made it possible to develop new technology for an individual field, and the adoption of such solutions early in the field’s lifetime. Such conditions are not present to the same extent on the NCS today. But Norway still has a number of big fields expected to produce oil for many decades to come, such as Ekofisk, Eldfisk, Snorre and Heidrun. That will also apply to large new developments on the NCS.

Important historical decisions on field pilots and implementation have been very important, with substantial spin-offs. With hindsight, it can be seen that results from these projects were not a matter of course. A certain degree of boldness was required there and then from everyone involved. Oil prices are high today. Improved recovery from producing fields is a political goal. Much of the potential lies in the immobile oil which cannot be recovered unless new methods are adopted.

A bold approach is important for maintaining a high level of value creation. Getting as much as possible out of producing fields while infrastructure is still in place will be crucial. Close followup by the authorities has earlier proved useful when important decisions are to be taken. That will undoubtedly remain the case. At the same time, it will be crucial to have licensees who combine the willingness to take risks with long-term thinking, professional strength and creativity, and who thereby contribute to extending the limits of the attainable.

 


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09.11.2011