Chapter 5: A cauldron of innovation

Subsea plants enable small fields to be tied in to larger facilities and field centres, extending the life of existing platforms and infrastructure in the process while increasing the yield in the field areas and opening the way for development in ultra deep waters. In areas without any infrastructure subsea plants may be tied directly in to processing facilities onshore.

Subsea technology also contributes to more environmentally friendly development projects and operations offshore, as less ship and helicopter traffic in the operating phase helps cut emissions while remotely operated technology reduces the number of risky operations.

The subsea phenomenon is just one small example of the ways in which offshore oil and gas have made the Norwegian continental shelf, always the richest area of the North Sea, one of the world’s most advanced industrial laboratories, a cauldron of technological innovation. In recent years, these technological advances, underpinned by audacious management decisions, have cut development costs by a third to a half while squeezing billions of dollars’ worth of previously inaccessible oil out of the seabed.

Forty years plus
This creative process is more necessary than ever today, more than 40 years after the first exploration well was drilled in 1966. Since then, over a thousand exploration wells have been completed (or temporarily abandoned) on the NCS, proving over 60 billion barrels oil equivalent of recoverable resources. Undiscovered recoverable resources are thought to be at least equivalent to total production to date; but the demand for new technological solutions intensifies as extraction becomes increasingly challenging.

Three main petroleum “provinces” subdivide the Norwegian continental shelf: the North Sea, the Norwegian Sea and the Barents Sea. These areas differ in geology and exploration maturity, the North Sea being the most mature, with a well developed infrastructure for production and transportation, while the eastern part of the Norwegian Sea is relatively well known; but the deepwater areas are less so, qualifying as “frontier” exploration areas. Although the Barents Sea has been successfully explored in the south, there are vast virgin areas in the east and north where geological data indicate large structures with petroleum potential.

Hundreds of offshore drilling, production and supply companies have put their best minds and machines to work in Norwegian waters in hopes of sharing in the adventure  an adventure that is far from over, as total Norwegian oil and gas investments for 2009 are estimated at NOK 135 billion, perhaps a quarter or more of the country’s total real investments. Much of this money is earmarked for cutting-edge technology that will be adapted to other petroleum provinces in the years to come. By some calculations, revenues from various offshore enterprises now account for almost 50 per cent of Norwegian export income.

According to the 2010 budget statement, however, investment is expected to fall by 12-13 per cent in response to lower oil prices and the ongoing financial crisis. In any case, the Norwegian Petroleum Directorate is resigned to a slow decline in production, which has been relatively stable at around three million barrels per day since 1996. “Neither political nor economic conditions will be able to significantly increase the production from today’s level”, the directorate says; although new discoveries will increase production in five to ten years’ time, this will be from a much lower level.

	Petrol at the pump: the end result of a creative process....

The recovery challenge
A major technological issue facing the sector is the race for enhanced oil recovery (EOR), also known as improved oil recovery (IOR), or sometimes “tertiary” (as opposed to primary and secondary) recovery.

As we have seen, oil production from the Norwegian shelf is slowly declining even as global demand continues to grow. The estimated average recovery rate for oil from Norwegian fields, including improved plans, is currently 46 per cent. This means that more than half of the oil will be left in the ground, unless Norway works that much harder to get it out.

Addressing a seminar on improved oil recovery held in Stavanger, NPD Director General Bente Nyland posed the rhetorical question: “More to recover  what’s stopping us?” Although there are substantial remaining oil resources in the fields, representing a great opportunity for additional value creation, Norway, she warned, could all too easily run out of options on several of the large fields if the right decisions were not taken in time.

“Maximum recovery from already producing fields, as long as it is prudent from a socioeconomic and safety perspective is one of the most important tasks on the Norwegian shelf”, Ms Nyland declared. Although much good work had already been done to improve the recovery rate, she urged the oil companies to step up their programmes for testing and using new production technology and to further boost oil recovery rates.

Decisive factors
Injection of water or gas will often be decisive for achieving high oil recovery. Factors that are specific to particular fields will decide whether it is water injection, gas injection or a combination of these that is most effective. The number and placing of wells is also important for efficient recovery.

A well-known example of a tried-and-tested recovery measure is water injection on Ekofisk, which followed thorough investigations to find out whether this technique could be used in chalk fields. Combined with compaction of the reservoir, water injection has given a large increase in the recovery factor.

Another important technique involves drilling. The drilling of long, horizontal wells has now become conventional technology, and wells with several branches are now used on a number of fields. This has contributed significantly towards improving recovery on the Norwegian shelf. The development of such wells has been decisive for the oil recovery on Troll.

Injection of natural gas and the use of WAG (water-alternating-gas injection) have proven useful, as have better tools for reservoir visualization and well management. WAG is a technique where the positive effects of injected water and injected gas are combined in the reservoir. This can give very low residual oil saturation, and there is less need for gas, to which there may be limited access.

In addition to natural gas, it is also possible, as we know, to use CO2 (or in theory nitrogen and just plain air) as an injection gas. CO2 injection has been employed for many years in some countries, notably the US, where reservoirs containing pure CO2 gas are available. Injection of CO2 separated from the exhaust emitted by gas- or coal-fired power stations or other industry could be an important factor in any CCS project. However, the technique has so far not been employed to improve recovery on the Norwegian continental shelf because the cost is too high, while injection of nitrogen and air are not conventional methods and could pose serious environmental and safety risks.

Several unusual methods, like the use of foam combined with WAG (FAWAG) and of microbes (MIOR) which form chemicals in the reservoir, have also been tested on the Norwegian continental shelf. FAWAG is used in several wells on Snorre, and MIOR has been employed for some time on Norne. When oil prices are low, research on oil and gas recovery tends to focus on technology that can be applied within a short time: e.g. drilling and well management and mapping of oil-rich pockets in the reservoir where infill wells can be placed (seismic methods and visualization). Some extremely good results have helped to maintain Norwegian production levels for oil in recent years. Ideally, research and development should involve a wide range of methods so that alternatives can be found to fit as many conditions and situations as possible and to solve particular problems. The higher the price of oil, the more cost-effective such advanced methods become.

	October 2007: setting out from Melkoya with the first cargo of LNG, 145,000 cubic meters, on board...

Ambitious targets
In 2005, the NPD set a new, ambitious goal for oil recovery from the Norwegian continental shelf: to increase oil reserves by five billion barrels, or approximately 800 million Sm3, by 2015. The forecast was that about 580 million Sm3 of oil would be approved for production during the decade; the new goal calls for an additional 220 million Sm3 on top of that. Clearly, an improved recovery rate would be a very important factor in meeting the target.

The directorate reckons that some fields will be able to attain a recovery factor for oil that is well over 70 per cent, whereas others will experience great difficulty reaching 30 per cent. Much depends upon new possibilities future technology might offer.

An additional target for the recovery factor was intended “to reflect the situation that Norway still has an ambition to increase the recovery from the fields over and beyond present-day plans, and it is hoped this, too, will prove an inspiration for further research, development and implementation of new measures for enhanced recovery from the fields on the Norwegian continental shelf”.

In the long term, raising the average recovery factor for oil to 55 per cent  a large increase relative to the current 46 per cent  is seen as a realistic goal, but only if “all the parties in the Norwegian petroleum industry ... make a substantial effort”. There is no deadline for this objective, which is viewed independently of the directorate’s target of five billion extra barrels of oil reserves by 2015.

By and large, it is technology that has kept Norway competitive in the oil business despite such apparent handicaps as harsh weather, a relatively inflexible labour market and close government scrutiny. Many international partners believe the tough working conditions faced by Norwegian companies have given them a competitive edge in other “difficult” regions such as the Gulf of Mexico, West Africa, Brazil and the Caspian Sea.

Offshore dynamics
Three important developments further illustrate the dynamism of Norway’s offshore industry, characterized as it is by a national devotion to environmental protection and industry-wide pressure to trim costs:

• 3D seismic surveying of unparalleled clarity has simplified exploration planning and improved drilling results, while 4D seismic monitoring  basically, the use of time-lapse 3D imaging is fast becoming essential to reservoir management.
• The recovery rate of oil and gas resources has soared with advances in reservoir management and deviated drilling technologies.
• Exploration and production have shifted to deeper and harsher waters, where floating production units and a succession of subsea technology breakthroughs have made the Norwegian continental shelf a model for economical offshore field development worldwide.

Seismic survey technology has been a vital tool for the oil industry since operations began on the Norwegian continental shelf in the 1960s. Following large-scale investigations with two-dimensional seismic in the 1970s, a new breakthrough was achieved with three-dimensional mapping at the end of the decade. While a single hydrophone streamer is towed behind the survey vessel in 2D mapping, the 3D solution calls for many parallel streamers. These allow much larger areas to be covered more quickly and inexpensively while also producing a 3D image of the subsurface.

Four-dimensional (4D) surveys have been developed from the 3D technique by superimposing new data on existing information. With the aid of accurate positioning and efficient streamer deployment, seismic surveys can be repeated very precisely. This makes it possible to map field changes over time, which in turn provides an indication of how the field is being drained and supports optimal positioning of production and injection wells.

3D to 4C
The next step is four-component (4C) seismic, which replaces streamers towed by a survey ship with hydrophone cables or nodes on the seabed. As with 3D seismic, subsurface signals are picked up in three components. But putting hydrophones on the seabed also makes it possible to detect a fourth component: shear waves, which oscillate at right angles to the wave direction. These differ from pressure waves in part because they do not travel through water, and therefore cannot be picked up by surface streamers.

Pressure waves register geological phenomena called flat spots, which could indicate hydrocarbons. Shear waves do not detect oil or gas, so their uninterrupted passage through a flat spot would strengthen the view that it could be a discovery. This inference can be drawn if the flat spot “disappears” on the 4C seismic map, because that should indicate the presence of hydrocarbons.

Oslo-based Petroleum GeoServices (PGS) is an outstanding example of a Norwegian company providing an extensive range of seismic services and products for the petroleum industry, including data acquisition, processing, reservoir analysis and interpretation. The company also claims to possess the world’s most extensive multiclient data library.

The Ramforms
PGS has repeatedly pushed back the operational limits of seismic survey technology with its fleet of 16 offshore seismic vessels including the Ramforms  revolutionary triangular shaped vessels with unique stability characteristics and capacious holds that bristle with stunning electronic equipment. The production arm includes the company that defined effective, rough weather floating production technology and occupies a leading position in the North Sea FPSO (Floating Production, Storage and Offloading) market.

Listed on the Oslo stock exchange, the company also operates 10 onshore crews on three continents and has 23 data processing centres and offices in over 30 countries, with regional centres in London, Houston and Singapore.

During the 1990s, PGS set its mark on seismic exploration as the first to develop technology capable of towing five streamers behind a seismic ship. Even as towed equipment has increased dramatically, producing faster and more cost effective collection, the data grid has become tighter, increasing the resolution of the results. In May 2008, the PGS vessel Ramform Sovereign set a new industry record deployment of 17 streamers  following-up five months later with a high density industry record of 112 km of deployed streamers, 14 x 8 km, at 50 metres separation. This technology and similar evolutions for seafloor and onshore seismic are driving down exploration costs, bringing oil and gas projects on stream faster and reducing risk by improving the realism and resolution of geological models.

Exotic explorations
While PGS was founded in Oslo and maintains a headquarters there, the nature of the oil industry is such that, at any given time, its field of activities ranges from Alaskan tundra to the desert, from ecologically sensitive wetlands to deepwater ocean margins. With its emphasis on innovative technology and operational efficiency, no other company involved in petroleum exploration has done more to help clients find resources faster: accelerating identification of promising locations and reducing the cost of exploration by bringing value on stream earlier.

One of the more exotic contracts recently undertaken by PGS was with Borders & Southern Petroleum Plc to conduct a 3D survey of its South Falklands Basin Production Licences. Completed in early 2008, the contract represented one of the most southerly 3D surveys in the world, and “the most extensive seismic 3D study ever conducted in this area”, according to the Norwegian company. Using their vessel Ocean Explorer, PGS collected a total of 576 square miles (1492 sq km) of seismic data while an onboard specialist recorded wildlife activity.

PGS has developed two significant towed source and streamer technologies to be rolled out gradually across the PGS fleet. First, an automated source subarray steering technology improves lateral source position error caused by prevailing currents and vessel motion in standard operating conditions to typically less than ± 5 m. Obvious benefits include optimized source-receiver geometry repeatability for 4D surveys, improved farfield signature stability, and operational efficiency improvements. Second, a remote controlled dilt float allows the front-end of streamers to be adjusted in the depth range of 0 to 15 m. Obvious benefits are safer inspection, repair and towing, improved depth control accuracy, and efficiency improvements in both poor weather and standard towing conditions.

In October 2009 PGS announced plans to accelerate the roll out of its “flagship GeoStreamer technology” earlier than originally planned, converting half of the 3D fleet to GeoStreamer by the end of 2010. “Improved data quality, broader bandwidth, reduced noise, wider weather window and greater operational efficiency around the world, in well over twenty different countries so far, cement the business case for this new product”, the company said.
 
During 2010, three Ramforms are to become operational with GeoStreamer, bringing the 3D GeoStreamer fleet to four vessels and adding to the current four 2D vessels; another 3D vessel is to be upgraded in 2011. 

Oil companies that want to improve oil and gas recovery rates must begin by acquiring the means to anticipate a reservoir’s performance over time given various production strategies. As in the exploratory phase, seismic imaging and interpretation are key.

With survey data of the quality now standard in the North Sea, computer operators can model a reservoir in three dimensions, highlighting significant geological features and using colour to differentiate between water, oil and gas concentrations. The improved view allows engineers to pinpoint the ideal locations and depths for injection and production wells, while state-of-the-art simulation that enables engineers to wander through reservoirs in virtual reality.

An even clearer view of field structures and hydrocarbon saturation can be obtained through a full suite of technologies that PGS has developed for four-component (4C) seismic data processing. The cost is generally somewhat higher, but benefits include the ability to see through hydrocarbon masses to a reservoir’s substructure.

Thanks to advanced reservoir description and monitoring techniques, marginal fields that were passed over in the hunt for North Sea elephants can now be developed with the confidence that they are worth the effort. An example is Esso’s Balder field, which was discovered in 1974 but not developed until the technology of the late 1990s altered the calculus of profit.

	Gullfaks: crawling with pipelines

Time-lapse seismology
By repeating 3D seismic surveys over time while production is underway, oil companies can get a “4D” view of the effect their extraction strategy is having on drainage patterns. While permanent downhole sensors tell producers much about what is happening in the well itself, only seismic images repeated at intervals can show the movement of fluids and gases through an entire producing reservoir.

For example, a 3D survey in the mature Gullfaks field comparing the results against earlier records identified four reservoir niches that remained undrained after nine years of production. Thanks to the time-lapse seismology, the pockets of oil could be tapped by way of a long horizontal well.

With its various high-tech suppliers, Statoil is also a leader in nuclear magnetic resonance (NMR) and measurement while drilling (MWD) log interpretation to sniff out unswept oil ahead of the drill bit. Its progressive approach to technology is one reason for Statoil’s consistently high ranking among the world’s leading oil companies in operating profit per barrel of oil produced.

Postponing the inevitable
It’s the inevitable fate of fields everywhere to lose pressure and eventually give out. What has been special in offshore Norway is the extent to which the inevitable has been postponed.

One of several big, older fields in the North Sea whose lives have been extended through ambitious repressurization projects is the Oseberg field, where production began in 1988. Natural gas from a subsea module in the neighbouring Troll field is now piped 48 km for reinjection into the Oseberg reservoir, stimulating it dramatically. Injecting Troll gas into Oseberg made it possible to maintain a flow of 403,000 barrels per day from Oseberg’s 53 oil producing wells  and to double the original estimate of its recoverable reserves.. By the mid-1990s, Oseberg had become Norway’s most productive oil acreage, promising 66 per cent oil recovery; the ultimate aim was to re-extract three-quarters of the injected gas along with Oseberg’s native gas, this time to be piped ashore for processing and dispatch to Europe. Statoil and Saga have experienced the advantages of WAG injection as well as the use of silica gel and foam to reduce water and gas production where oil is the desired product.

Such methods combined with advanced seismology and smart, multilateral wells increased the recovery rate in some fields by almost ten per cent while enabling the Norwegian Petroleum and Energy Ministry to set a target of recovering half of all oil and 75 per cent of all gas on the continental shelf. In the massive but ageing Statfjord field, where estimated reserves stood at 4.4 billion barrels, the yield rate was upgraded to 70 per cent, mirroring progress that BP had made in the Forties field on the other side of the North Sea dividing line.

Production began at Statfjord in 1979, and after repeated extensions was expected to continue through 2020. Similarly, Norway’s oldest field, Phillips Petroleum’s Ekofisk, was given a new lease on life and even a new name, Ekofisk II. Thanks to rejuvenated field pressure and the latest in production technology  such as horizontal drilling, reaming while drilling, coiled tubing and multiple fractures  the Ekofisk area’s expected fruitful life was extended from 2011 to 2028.

Directional drilling
One of the most important Norwegian contributions to the science of petroleum recovery has been in the field of deviated and horizontal drilling. While Statoil set a world record for length of a horizontal well at Statfjord in 1991, Norsk Hydro performed an equally impressive feat in 1996, drilling three long multilateral wells, each with two horizontal branches extending some 2000 metres, from the Oseberg C platform. Thanks to its expertise in directional drilling, Norsk Hydro was also able to bring up some 250,000 barrels per day of high quality crude from the Troll field. Troll is known internationally as the world’s premiere offshore gas field, but it also includes thin oil layers that measure as little as 12 metres from top to bottom. Only a few years ago these deposits would have been considered unsweepable. To one degree or another, twisting, turning and branching are a part of daily life in drilling projects throughout offshore Norway. But the ease and precision with which the task is performed has continued to advance with rotary steerable technologies that save operators money by expanding the reach of existing infrastructure.

Making the most of existing infrastructure continues to be one of the industry’s highest priorities. Through the mini-boom of the mid1990s, oil companies active in Norway were chagrined that the government insisted they develop marginal fields within pipeline reach of old platforms before entering new, unexplored areas with more exciting potential. But the result was expertise in economical, subsea well construction that will serve Norwegian producers and suppliers well in an era of infrastructure minimalism at home and abroad.

Pipelines and satellites
The North Sea and Norwegian Sea floors are now crawling with pipelines and studded with hundreds of subsea satellite wellheads whose parent platforms can be hard to discern even on maps. Today, even the satellites have satellites. When Saga Petroleum brought its Tordis East oil field on stream in December 1998, the company explained that the new facility was a subsea satellite of the Tordis field proper, which in turn was a subsea satellite of Norsk Hydro’s Gullfaks C platform. Not incidentally, Saga also mentioned that Tordis East could break even at an oil price of $6 per barrel.

While the Norwegian government has been active in promoting cheaper field developments and tighter schedules through the NORSOK programme, the oil producers have needed no help to grasp the importance of leaner and meaner technologies and contracting procedures.

Statoil’s Njord field, where production started in 1997, is a good example of this process. By simplifying design concepts and streamlining the development process, Norsk Hydro became the first company in the Norwegian sector to acquire a production platform from a single contractor. And choosing Aker’s standardized but flexible P45 semisub platform cut costs at Njord by some 40 per cent from early estimates.

De profundis
As in other mature offshore provinces, such as the Gulf of Mexico, the most intriguing trend afoot in the North Sea may be the shift to deeper water. On the Norwegian continental shelf, this development involves heading north into waters that are not only deep but distinctly Arctic. Above the Arctic Circle in the blustery Norwegian Sea and the western Barents Sea, exploration, at water depths as great as 1500 metres, will require a tough breed of offshore personnel. Deep and ultra deep waters are nothing new to FMC Technologies, perhaps the pre-eminent specialist in subsea production, control, tie-in and multiflow metering systems.

Its classic HOST (Hinge Over Subsea Template) production system is composed of standardized building blocks installed from a normal drilling rig in waters down to 2500 metres. Each HOST template supports five to seven wells. The system has proven itself in almost every major North Sea field and in international projects from China to Africa and Canada; in the deep and ultra deep basins of the Gulf of Mexico, in Shell’s breakthrough Mensa field and BP Amoco’s King Peak. Operators in the North Sea and Norwegian Sea purchase more subsea equipment than their counterparts anywhere else, including the Gulf of Mexico. Norwegian subsea contractors provide billions of dollars’ worth each year, often breaking old moulds in the process.

	Åsgard: daring and complex

Floating facilities
With its long maritime tradition, Norway is uniquely qualified to meet deepwater production challenges with facilities that float. So far these have included innumerable semisubs as well as tension leg platforms and the world’s largest, most advanced and most flexible production ships. Among the members of the Norwegian Shipowners’ Association are companies that provide drilling services, well and reservoir management, flotels, crane vessels, standby and supply vessels, pipe laying vessels, ROVs and FPSOs in addition to oil tankers and highly specialized vessels for transporting liquefied petroleum gas (LPG) and chemicals.

Maritime offshore specialist Navion, for example, which boasts one of the world’s largest fleets of shuttle tankers, pioneered the construction and use of standardized “multipurpose vessels”. With modification, such vessels can serve as shuttle tankers, conventional tankers, ultra-deepwater drilling rigs or submerged turret production ships that can vacuum up small fields and move on to the next with little fanfare. Production costs can be as low as $5 per barrel.

The company’s flagship multipurpose vessel, the Navion Munin, began draining China’s Lufeng field in December 1997 after just 18 months of development by operator Statoil in conjunction with the China National Offshore Oil Corp. Navion is now a subsidiary of Teekay Shipping Corporation.

Among the most dramatic of the Norwegian floating production and storage systems to date is Statoil’s Norne ship, with its 160,000 barrel-per-day capacity. Anchors hold the ship over five subsea well templates (supplied by Kongsberg Offshore) in 370 metres of water, while thruster engines will automatically keep its bow pointed into the wind for a projected 25 years. The weathervane effect is made possible by the Norne’s most impressive feature: its 48-metre-high loading turret (from Kværner Rosenberg), through which a phalanx of riser pull-in tubes feed oil into the ship’s hull.

While the ship’s major hull sections were fabricated by Far East Levingston Shipbuilding (FELS) in Singapore, the Norne’s high-tech topside was engineered by Kværner Engineering and installed by Aker Stord on Norway’s west coast  paving the way for similar achievements in the years ahead as FPSOs expand their role worldwide.

The Norne is considered a prototype production system for waters as deep as 2500 metres. With a total development cost of just over Chapter 5: A cauldron of innovation billion, the project was designed to pay for itself in about a year. Even if oil prices were to plunge to $6 per barrel, the rate of return on Norne would work out at about eight per cent.

Dazzling heights
The year 1999 would see the FPSO trend pushed to dazzling heights, with Statoil bringing its Åsgard oil field on stream using an even larger production and storage ship than Norne. The ship Åsgard was to have a processing capacity of 200,000 barrels of oil per day and a storage capacity of 907,000 barrels. As with the Norne, oil was to be transferred by way of a loading system to shuttle tankers for transport to customers or terminals. The Åsgard project represented the most daring and complex subsea development in the world, with 60 wells in 15 templates atop a reservoir that was deep, hot and under high pressure. It was also to be among the world’s most environment-friendly petroleum projects, with fewer emissions per unit of production than any other facility off Norway. Statoil would eventually add natural gas production from a floating platform in the Åsgard field, with a pipeline connection to the Kårstø processing terminal ashore and further connections to continental Europe.

Small wonder that scores of floating production systems have been ordered internationally, making Norway a true world leader in the field. Typical products include a rugged deep draft floater (DDF), which can hold 25,000 tonnes of drilling and production equipment, and a floating, production, drilling, storage and offloading (FPDSO) vessel allowing personnel to drill or perform well maintenance through the turret while production is in full swing. Norwegian turnkey oil and gas contractors such as Aker Solutions (formerly Aker Kværner), Smedvig (acquired by Seadrill in 2006), ABB and PGS Production are just a few of the names to conjure with.

	Mongstad
	An interdependency of pipelines

Cooking with gas
Even if Norwegian oil production does begin to taper off in the next decade, rapidly increasing gas production will almost certainly more than compensate. Europe in the 21st century will gradually shed its dependence on coal and oil for power production and turn instead to clean-burning natural gas  much of it from Norway, but also from Russia and Algeria. The Norwegian petroleum industry has spent much of the past 15 years preparing for this monumental strategic responsibility, and in the process has become a global leader in gas processing technology, LPG maritime transport and pipeline systems. At Kollsnes, near Bergen, it is easy to find the world’s largest gas processing plant, where Troll gas is treated and pressurized for an 1150 km passage through the Zeepipe subsea pipeline system to Belgium. Zeepipe is part of the most extensive network of subsea pipelines anywhere.

One pipeline segment, Franpipe (formerly known as NorFra), carries gas 850 km from the Draupner E platform in the North Sea to Dunkerque in northern France, where it connects to the French grid and solidifies that country’s position as a major distribution hub in the European gas market. The Franpipe line also allows Norwegian gas producers to increase their share of the French gas market.

Integrated transport
As we have seen, Gassco is the government company responsible for operating Norway’s unique gas transport system: a 7800 km network of pipelines transporting Norwegian gas to continental Europe and the UK. Norwegian gas exports to Europe through the integrated transport system totalled 94.6 billion scm in 2008. In addition, 1.9 billion scm were delivered for injection into fields on the NCS, while 1.1 billion scm were supplied for domestic consumption.

Gassco’s role is conferred by the Norwegian Petroleum Act and operator agreements concluded with individual companies and joint ventures. The company stresses that it is “a neutral and independent operator of the transport system on the NCS”.

With effect from 1 January 2003, virtually all of these transport systems were integrated in a major new joint venture, known as Gassled, between oil and gas companies on the Norwegian continental shelf. Gassled has no employees and is organised through various committees with specific assignments. This partnership serves as the formal owner of the Norwegian gas transport infrastructure. Gassco describes the creation of Gassled, with its associated commercial changes, as “one of the most far-reaching changes to Norway’s gas business in recent times”.

The Skanled project
Equally impressive is the projected Skanled development, a planned gas transport system between Norway, Sweden and Denmark, with a total pipeline length of 853 km. Provision will also be made for possible spurs to Lista and Slagentangen in southern and southeastern Norway.

Industrial and energy companies in Norway, Sweden, Denmark, Germany and Poland are backing the financing and planning of the project, which will involve spending on new facilities at Rafnes south of Oslo, where ethane will be extracted from the gas for local industrial use.

With these and other associated developments, the scheme would rank as one of Norway’s largest industrial investments of recent years, costing NOK 10 billion or more.

“The Skanled project is complex, and challenges remain to be overcome before it can be given a green light”, says Gassco. These challenges include “gas purchases and sales, technical choices, and the economics of the associated projects as well as official approval processes in Norwegian, Sweden and Denmark”.

Missionaries for technology
Thanks to the resources of the North Sea and the astounding infrastructure that has been created to exploit it, analysts are agreed that Norway will probably retain its position as a major oil producer and exporter for at least the next couple of decades  even as it supplies a lion’s share of natural gas consumed in Germany, France, Belgium, and elsewhere in Europe.

In the meantime, Norwegian companies continue to produce oil and gas on various continents and to support the exploration, development and production operations of international partners. The Norwegians are fast becoming missionaries for technology that not only heightens productivity but keeps it clean: flare gases are recovered, air and water emissions are eliminated and worn-out offshore structures are disposed of in ways satisfactory to even the most committed of environmentalists.