NORWAY

Norway ranks as the No. 1 place to live in the world, according to the U.N. Human Development Report. Norwegians enjoy lifelong financial security, a pristine environment and an egalitarian society. Low crime rates, top-drawer health-care and exceedingly generous employee benefits make life for Norway's 4.5 million citizens prosperous and pleasant. The fount of Norway's prosperity is North Sea oil production. Prior to the discovery and development of its offshore fields, Norway was one of the poorest countries in Europe, its people eking out livings as fishermen, shipbuilders and farmers. Initially, exploration in the Norwegian sector of the North Sea was disappointing. Licenses were first awarded in 1965; by early 1969, some 30 wells had been drilled in Norwegian waters, with only one decent announced discovery. That find, Cod Field, was large enough to spark interest but too small to be commercially produced. In the latter half of 1969, Phillips Petroleum discovered Ekofisk Field-a 7.5-mile-long, north-south trending anticline, draped with limestone and chalk pays nearly 400 feet thick. Norway's fortunes took a dramatic upswing with first production from Ekofisk in 1971. Years of robust growth followed, most particularly between 1989 and 1996. During that time, oil production rocketed from 1.5- to 3 million barrels per day. Today, the country remains the world's third-largest crude oil exporter behind Saudi Arabia and Russia. In 2000, Norway sold 1.53 billion barrels of oil equivalent (BOE), and daily oil production averaged some 3.2 million barrels. The resource base has also been expanding-60% in the last 10 years, according to Erik Søndenå, principal engineer, forecasting and resource assessment, for the Norwegian Petroleum Directorate. Prodigious volumes of hydrocarbons certainly remain, both discovered and undiscovered. The NPD estimates the Norwegian continental shelf has a total resource base of 86.8 billion BOE; during the last 30 years the country has produced 18.9 billion BOE, just 22% of the total. The North Sea The North Sea is the cradle of Norway's oil and gas industry, with three-quarters of the country's production flowing from beneath its stormy waters. It is a rapidly maturing province, however, and the picture is cloudy for its future. The province once held some 29.4 billion barrels of recoverable oil, but almost half of that has been produced. The NPD estimates 3.8 billion barrels remain to be discovered in the North Sea; the rest lies in existing fields and discoveries. Further, the size of discoveries has been declining precipitously-in 2000, nine exploration wells were drilled in the Norwegian sector of the sea and three were productive. Their total reserves were less than 25 million barrels of oil. So, the days of halcyon growth are over. The NPD expects the country's production levels to plateau between 2002-05 at 4.8 million BOE per day, about 3.2 million of this as oil and condensate, and the remainder as gas. "Almost all of these volumes will flow from fields that are in production today," says Søndenå. It's likely the surge in its resource base Norway recently enjoyed was a one-time jump. A case in point: production from Statfjord Field, the most prolific oil-producing area in the North Sea, has greatly exceeded expectations, and recoverable reserves have burgeoned. In 2000, Statfjord produced an average of 187,500 barrels of oil per day; however, one-half of this was from wells drilled in the previous year. "One of our concerns is that the resource increase has come mainly from large fields with platforms, where it is very easy to drill additional wells," says Søndenå. The newer fields have subsea developments, making additional drilling very expensive. Too, modern fields already incorporate the latest technologies, so less oil has been left on the table. Still, the North Sea's inevitable decline could be cushioned by several factors. One focus of the NPD is to improve recovery factors. "Our goal is to recover half of the oil in place on the Norwegian continental shelf. We also hope to recover 75% of the gas in place." One of the sterling successes in this regard has been Ekofisk, a chalk reservoir that initially had a recovery factor of 17%. At the time of its discovery, its total recoverable reserves were estimated at a billion barrels. During the last decade, Ekofisk's expected recovery factor has risen to more than 40%. Today, the Ekofisk complex of fields is estimated to have contained total recoverable reserves of 5.35 billion BOE, of which 2 billion remain to be produced. In 2000, Ekofisk was the country's top oil producer, averaging 313,500 barrels per day. Presently, Norway's average recovery factor is 44%-up tremendously from an average of 34% in 1990. The momentum, however, has slowed markedly, much as with the growth in the resource base. "The recovery factor has remained at the same level for the last three years," says Søndenå. "Many of the fields seem to have reached the limits of current knowledge and technology." Part of the flattening may also be related to low oil prices and oil-industry restructuring in the late 1990s. Clearly, new technologies are required to reach the ambitious goal of 50% recoveries. The Norwegian government has also been aiding efforts to prolong the economic life of the older North Sea fields. It has granted royalty relief on Ekofisk, Heimdal, Tor and Murchison fields. Additionally, royalties are being gradually reduced on Statfjord, Ula and Valhall fields. A reduction is also under way on Oseberg and Gullfaks. Naturally, the major oil companies operating in the Norwegian sector of the North Sea are well aware of the challenges of operating in a maturing province. These companies have endured the conundrum of increasing depletion rates and shrinking field sizes in other parts of the world. They are responding with the time-honored strategies of focusing on core holdings and enhancing those holdings by decreasing costs, leveraging infrastructure, and bringing satellite fields and incremental barrels onstream. Statoil is one of the dominant operators in the Norwegian sector. The firm, which was 100% state-owned, has been partially privatized with the June 2001 sale of 17.5% to private investors. Presently producing 962,000 BOE per day from Norway, Statoil's target is to produce 1 million by 2004. The company has two core areas in the North Sea. The first is Tampen, in the northwestern part of the Norwegian sector. Three of Norway's 10 largest oil fields-Statfjord, Gullfaks and Snorre-are in this complex, as well as several smaller fields. By 2003, Statoil will operate all the fields in the Tampen area. Its second core area is gas-focused, and contains Troll, far and away Norway's largest gas accumulation. Its original recoverable reserves were 23.4 trillion cubic feet (Tcf) of gas and 1.34 billion barrels of oil; through the end of 2000 it had produced 3.1 Tcf and 480 million barrels. Troll offers size and flexibility for the sale of Statoil's gas from the Norwegian sector. Part of this core area also contains the Sleipner group of fields, gas-condensate accumulations in the southern North Sea. Statoil has a very strong operating position in these areas, and massive infrastructure. "We see a lot of spare capacity in these areas in the future, and we are actively bringing third parties into the process," says Tor Fjæran, senior vice president, exploration drilling and new ventures. Rationalization of interests is another avenue Statoil is pursuing. "We have initiated the process of equalizing interests across license boundaries. We can see a lot of synergies." Marginal field developments will be increasingly important as well. That's the case at Glitne, a 25-million-barrel oil field north of Sleipner. Glitne, from which production started in August 2001, is the smallest stand-alone development in Norway. To keep costs low, Statoil rented everything from the floating production, storage and offloading vessel to the Christmas trees. The company also is in the early phase of development on Kvitebjørn Field, a high-temperature, high-pressure gas accumulation in the Tampen area. The gas from this development, which is expected onstream in 2004, will be processed onshore. "The fields that are still to be found in the North Sea will be small, but we don't need big fields to be commercial in areas of established infrastructure," says Fjæran. Enhanced oil recovery and satellite developments are also the game plan for BP in its southern North Sea properties. BP is a heavyweight on the U.K. side of the sea, but has a smaller presence in Norwegian waters. The company produces 110,000 BOE per day net from Norway, up from 95,000 in 2000. "We'll be growing again in 2002," says Anne Drinkwater, Stavanger-based managing director. "We have the projects approved and under way to meet our growth projections." BP spent $300 million in Norway in 2001, and expects to spend the same this year. The company has a major project at Valhall Field in the southern North Sea, where it is instituting a waterflood. Valhall, a chalk reservoir similar to Ekofisk, is one of the most challenging fields in the world. BP has formed an alliance with Schlumberger to develop the water-injection project, which will begin in 2003. Currently, Valhall is producing about 100,000 barrels per day; BP estimates the water-injection program can add in the neighborhood of 260 million BOE to ultimate recovery. Additionally, a development on the flanks of the field will increase recoverable reserves another 127 million BOE. The Valhall project provides a good example of how aging fields can still hold surprises. When it was discovered in 1975, Valhall was thought to contain about 240 million BOE. "Today, we talk about reserves of just below 1 billion BOE," says Drinkwater. Reserves have grown from the application of such technologies as horizontal and extended-reach wells, 3-D seismic and advanced completion technologies. Just north, BP is also active in the Ula/Gyda area. In July it brought the 55.9-million-BOE Tambar Field on production. Tambar, an unmanned satellite field that is controlled from Ula, is expected to produce at peak rates of 30,000 barrels per day. The field was delivered on time and on budget, notes Drinkwater. Independent oil companies have not traditionally been prominent in Norway's offshore, but the fast maturing North Sea may open up new opportunities for smaller firms. That's the strategy Oslo-based Det Norske Oljeselskap (DNO) is pursuing. "We aim to be a company that is a desirable partner for the bigger firms. We're most interested in projects that are low-risk and can be put into production quickly," says Jan M. Drange, chairman. The company is focused on smaller oil fields. "We try to create value by extending the life of producing fields, by combining small discoveries into producing clusters, and by participating in exploration for satellite accumulations." DNO is active in the southern North Sea. It currently has interests in Jotun, Glitne and Tyr fields and in production licenses 103b, 203 and 148. Its ownership ranges from 3.25% in Jotun Field to 32.5% in PL 103b. Its partners include Statoil, Norsk Hydro, Conoco, TotalFinaElf, Amerada Hess and BP. In October, the firm was producing 6,200 barrels of oil per day from its Norwegian properties and expects to grow that total to more than 15,000 barrels per day. "Our goal is to have an operatorship in Norway within a year," says Drange. DNO has already proved that it can operate successfully in the North Sea, he notes-it owns and operates Heather Field on the U.K. side. It models its business on practices of like-minded independents in the U.S. Gulf of Mexico, including the extensive use of contractors. "Since taking over the operation of Heather Field from Unocal, we've cut operating costs by a quarter while maintaining very high standards for health, safety and environmental protection." DNO's U.K. production is 6,700 barrels per day, from both its 100%-owned Heather Field and a 3.7% interest in the Amerada Hess-operated Solan and Stratmore fields. Additionally, it operates two onshore licenses in Yemen. A gas-fired future Clearly, despite its status as one of the world's premier oil producers, Norway cannot rest on its past success in the North Sea. While the country will do all that it can to wring barrels from that province, to maintain robust exports it needs to turn to gas. Luckily, that's a resource it also holds in abundance, but one that has been far less developed. In 2000, Norway exported 1.7 Tcf of gas to the U.K., Germany, the Netherlands, Belgium, France, Spain, Austria and the Czech Republic. The country expects that, over time, it could export as much as 3.2 Tcf per year. Says BP's Drinkwater: "When we look at the sources of gas into the U.K. and into all of Northern Europe, Norway has both the resource potential and the price potential to readily compete for those markets." Of particular interest is the U.K. market, where there is a growing gap between supply and demand. "When that is put together with the liberalization of Norway's gas market, we see great opportunity in a gas-focused growth portfolio." Indeed, Norway has been hard at work restructuring its methods of selling gas to other countries. Due to pressure from the European Union, it is introducing gas-on-gas competition into its marketplace. Previously, Gassforhandlingsutvalget, a gas-sale negotiating committee, would negotiate the prices of all Norwegian gas available for export. The country is now transitioning to a free-market approach where companies will compete against each other to supply gas to customers. Norway's gas potential is considerable. The NPD estimates the continental shelf holds 248 Tcf of gas, of which less than 10% has been produced. And, the area with the greatest promise is the Norwegian Sea. The Norwegian Sea The Norwegian Sea is estimated to contain 80 Tcf of gas and almost 8 billion barrels of oil. More than half of the gas remains to be discovered, as well as about 2.5 billion barrels of oil. It is far less mature than the North Sea, and offers targets attractive to the world's largest companies. Size matters, and the mid-Norway area is home to several extremely large fields. "We see potential for additional discoveries larger than 10 Tcf in mid-Norway," says the NPD's Søndenå. "There are a lot of interesting prospects." Success rates are also encouraging: during the last three years, 20 exploration wells were drilled in the Norwegian Sea and half of those were successful. Only five fields produce in the Norwegian Sea, but these account for a quarter of all Norwegian oil production. The first development was Draugen, an oil field discovered and developed by Norske Shell. Draugen, which had original recoverable reserves of 750 million BOE, commenced production in 1993. Initially, the field was making 100,000 barrels per day; today, it produces 227,000 per day. Shell's partners in Draugen are BP, ChevronTexaco and Petoro. (The Norwegian government recently created Petoro to manage the State's Direct Financial Interest. Prior to its partial privatization, Statoil had been the caretaker of the SDFI.) "Mid-Norway is our core area because that's where we have our assets and where we see the big potential," says Anthony Charnley, Shell's Kristiansund-based operations manager. "Shell is very positive about Norway, and we believe it can compete favorably with other places around the world." Truly, Draugen has been a success story for Shell. The dramatic rise in its production has been linked to an equally dramatic rise in recoverable reserves. A unique monotower platform, Draugen produces from a combination of platform and subsea wells. Presently Shell is directing its efforts at extending the life of the field with subsea tie-backs to produce peripheral portions of the main accumulation. In 2001, it drilled wells at Garn West; this year it will drill wells at Rogn South. Shell expects Draugen to begin its decline around 2004, and continue producing until about 2020. The largest development in the Norwegian Sea is Åsgard, operated by Statoil. This complex contains 6.7 Tcf of gas and about 350 million barrels of oil in three fields: Smørbukk, Smørbukk South and Midgard. Oil production was brought onstream in 1999 and gas production began in late 2000. The $7.2-billion development is one of the most complicated in the world, with subsea wells producing into two floating processing facilities. The field has been fighting cost overruns and technical problems, and presently Statoil is repairing defective flowline welds on Åsgard B. That facility is expected to gradually come back onstream early this year. In addition to Åsgard, Statoil also operates Norne and Heidrun. Those are substantial oil fields with reserves of 641 million BOE and 1.2 billion BOE, respectively. The final Norwegian Sea producer is Njord, a relatively small 140-million-barrel oil field operated by Norsk Hydro. It lies about 30 kilometers west of Draugen Field. Two new developments are also under way. Statoil plans first production for Mikkel in 2003 and for Kirsten in 2005. Mikkel, which contains about 720 Bcf of gas, will be a subsea installation directly linked to Åsgard. Kristin is a very high-pressure, high-temperature accumulation that contains 1.2 Tcf of gas and 250 million barrels of condensate. Plans for its development call for a gas-processing platform, with gas exported to the Åsgard platform. The foremost project on the list of upcoming developments-not only for the Norwegian Sea, but for all of Norway-is Ormen Lange. This accumulation, discovered in 1997, is a giant gas field containing 14 Tcf in recoverable reserves. Norsk Hydro is operating the development phase of the field and Shell will be the operator of the production phase. "Ormen Lange is the second-largest gas field on the continental shelf of Norway," says Thor Tangen, Oslo-based senior vice president, Norsk Hydro. The field lies in 800 to 1,100 meters of water-extremely deep for a gas field. It will also be the first deepwater development in the Norwegian Sea. The cost of the project is estimated at about $4.4 billion, including investments in pipelines to move the gas to existing infrastructure in the North Sea. Start-up is slated for 2007. Production is forecast to total around 700 Bcf per year, which will add about 25% to Norway's export production. Ormen Lange sits in the Haltenbanken area, which endures some of the country's most ferocious weather, about 100 kilometers offshore Kristiansund. It is a large field, covering an area 60 kilometers long and 10 to 15 kilometers wide. The field, which translates as Long Dragon, offers myriad technical challenges. Nothing like it has been attempted. Foremost, Ormen Lange lies beneath the Storegga Slide, one of the largest submarine slides in the world, measuring 300 kilometers in length on its back wall and stretching 800 kilometers out into the Atlantic. It poses a geotechnical problem for the whole Haltenbanken area. Says Tangen, "We are trying to demonstrate that the slide, which occurred 8,000 years ago, is stable. We've been working on this since 1996, and so far we have not found any information that indicates there is any risk of a new slide." Additionally, the seafloor topography is very rough, rolling and swelling into 50-meter-high features. On top of the unusual terrain, the sea currents are extreme and the sea-floor temperatures are below freezing. "Flow assurance will be a huge hurdle. We also have to find a pipeline route from the slide area. Normal pipelaying barges are not capable of doing this work." To date, four wells have been drilled on Ormen Lange, and the partners-Norsk Hydro, Shell, ExxonMobil, Petoro, Statoil and BP-plan another test this year to confirm the gas in place and to gather information on compartmentalization of the reservoir. The companies aim to submit their plan of development to the Norwegian government in 2003. Absolutely, most explorationists believe the Norwegian Sea holds promise for more gas giants that could approach the size of Ormen Lange. Major companies that want a strong gas portfolio find the area very intriguing. The government controls the availability of acreage through its periodic licensing rounds. In May 2000, it awarded 14 production licenses in the Norwegian Sea in its 16th Licensing Round. The acreage was a balance between deepwater areas and the shallower Haltenbanken and Donna Terrace areas, and was the first round in four years to offer acreage in mid-Norway. BP did very well, being appointed operator of three licensed areas and also as operator of a discovery adjacent to Skarv. Norsk Hydro won three licenses; Statoil two; and Shell, Agip, ChevronTexaco, TotalFinaElf and ExxonMobil, one each. Additionally, Conoco, Enterprise, Fortum, Phillips and RWE-DEA were offered nonoperating interests in various licenses. "We haven't seen the results of all the drilling from the 16th round yet. We should definitely see some more discoveries on those blocks," says Shell's Charnley. Two very high-profile exploration wells are of particular interest. At press time, BP was ready to spud its Havsule prospect, in 1,500 meters of water on Block 6404/11 in Production License 254. The well, which is targeting a prospect with reserve potential similar to Ormen Lange, will set a deepwater drilling record for Norway. BP's partners are Statoil, Petoro, TotalFinaElf and Conoco. Shell is also close to kicking off its Tott East well on Block 6406/5. The prospect is the first of several it plans to drill on its very promising President PL 255, which was the most sought-after license in the 16th round. Its partners are Statoil, Petoro and TotalFinaElf. Additionally, the world oil community is eagerly awaiting awards from Round 17, expected in mid-2002. All of the tracts are in the Norwegian Sea, and some extend into deep water. In the rounds, which are held in two- to four-year intervals, the government invites companies to apply for licenses. Each firm makes its case, then waits for the awards. Cost leadership and value creation are important criteria. "We strive for a balance between interesting blocks and high-risk blocks," says the NPD's Søndenå. "We like to have a span of companies, and like to set up combinations of big and small companies. A lot of different factors influence the awards." Statoil intends to compete aggressively. It has formed a venture with Shell and Enterprise Oil for Round 17 evaluation and bidding. "We expect to see some good acreage from the round that will lead to more drilling programs and discoveries," says Charnley. For its part, BP, the big winner in the 16th Round, hopes to have similar luck in the 17th, says Drinkwater. "We will fight for new licenses in the 17th. The Norwegian Sea is a growth area for us," says Statoil's Fjæran. "In the long term, the mid-Norway is where the most new reserves will be discovered and developed." The Barents Sea Further into the future is Norway's development of the Barents Sea. Expectations are not as high here as they are for the Norwegian Sea: the NPD estimates Barents contains 31.4 Tcf of gas and 2.4 billion barrels of oil. The flagship project of the Barents Sea is Snøhvit, operated by Statoil. The accumulation includes the Snøhvit, Askeladd and Albatross fields, about 170 kilometers offshore Finnmark, Norway's northernmost county. The NPD estimates Snøhvit contains about 5.9 Tcf of gas and 200 million barrels of liquids. "We've been working with these fields for years," says Fjæran. Statoil proposes to land the gas and condensate from the fields at a small island just outside of the city of Hammerfest. There, it would build a liquefied natural gas processing plant and ship the LNG to the U.S. and southern Europe. The task will be daunting: there is no infrastructure in the Barents Sea. But, the partners-Statoil, Petoro, TotalFinaElf, Gaz de France, Norsk Hydro, Amerada Hess, RWE-DEA and Svenska Petroleum-are ready to push ahead. In September 2001, they approved a plan of development to be submitted to the government. This move shortly followed the government's decision to grant tax relief for the Snøhvit project. In October 2001, five of the Snøhvit partners signed separate long-term contracts for the sale of LNG; two of the other partners will lift their own gas from the field. U.S. firm El Paso Global LNG Co. and Spanish firm Iberdrola will purchase 85 Bcf and 60 Bcf per year, respectively. Deliveries will begin when Snøhvit comes onstream in 2006. In addition to being the first Barents Sea development, Snøhvit will be the first large-scale LNG project in Europe. Its cost, including the liquefaction plant and LNG carriers, is estimated at $5 billion. Work will start on the project this spring. The development plan envisions 21 subsea production wells which will be remotely operated from an onshore facility, the first such application in the world. Neighboring accumulations have not yet been found that approach the size of Snøhvit, but exploration drilling just resumed in 2000 after a six-year hiatus. "We've had some interesting discoveries in the last two years, especially in the geological sense," says Søndenå. Of the five Barents Sea wildcats drilled since 2000, three have been discoveries. Norsk Agip struck oil on Block 7122/7 at its Goliath prospect, finding about 50 million barrels in the Middle Jurassic. It made a second discovery at its Gamma well, on Block 7019/1, where it found gas. Unfortunately, the well tested large volumes of CO2 along the gas, and the NPD believes the discovery contains only 70 Bcf of recoverable reserves. The latest find is one by Statoil, on Block 7228/7. This well was particularly interesting because it was the first in the Nordkapp Basin and the first in the Barents Sea to target a salt dome. Statoil tested the well extensively but has not yet released any estimates of resource size. From end to end, Norway's prospects to remain a world-class exporter appear bright. Its North Sea giants will still yield prodigious quantities of oil, even as they decline at ever-steeper rates. The Norwegian Sea should be able to fill the supply gap with its great gas fields, both discovered and undiscovered. Even the ice-shrouded Barents Sea will contribute to the country's trade abroad. And, the legendary skills of Norwegian engineers, combined with the worldwide expertise of the major oil companies, should be able to solve the knotty technical problems posed by the extreme conditions, both in the high-pressure and high-temperature reservoirs and in the frigid, tempestuous deepwater seas.