Norway looks to natural gas for greater role in energy mix

Gas processing plant at Kollsnes in mid-Norway will process gas produced by Troll A platform when it goes on stream in April. From Kollsnes, gas will be sent in new pipelines to Norways offshore Block 16/11 gas transport hub, where it will join trunk lines to Germany, Belgium, and France. Photo courtesy of AS Norske Shell.

Norway, western Europes pacesetter in oil production, has its sights trained on gas as its source of rising export income.

North Sea oil and natural gas liquids production reached a high of 6.06 million b/d last October, buoyed by Norways yield of more than 3 million b/d for the first time.

Figures compiled by Wood Mackenzie Consultants Ltd., Edinburgh, show Norway produced an average 3.19 million b/d of oil and NGL in October, up 290,000 b/d from average production in September.

Odd Raustein, manager of development planning and operation for the Norwegian Petroleum Directorate (NPD), predicts Norway will be able to produce more than 3 million b/d beyond 2000.

There is lots of uncertainty over how long this level can be maintained, Raustein said. We may be able to increase oil production a little, but we currently expect to maintain this level for 5-6 years.

Norway is the North Seas second largest gas producer after the U.K., with Octobers flow averaging 2.58 bcfd. The largest average production for Norway in 1995 was 3.38 bcfd in January.

Industrys investment in the Norwegian petroleum sector reached a record 58 billion kroner ($8.9 billion) for 1993, the International Energy Agency reported.

Over the next few years a significant reduction in investments from the 1993 peak level is expected because there are fewer and smaller new oil fields to be developed, IEA said.

The agency expects the decline in investments in new oil fields to be partly offset by spending in new gas fields and gas pipelines.

Gas constituted about 18% of Norways total petroleum production in 1993, IEA said. The relative share of gas in total petroleum production and revenues will increase over time due to increased gas sales and to an expected drop in annual oil production.

Wood Mackenzie says reports of Norways imminent oil decline may be exaggerated, however. It points out that current producing fields consistently have outperformed expectations, although early production from new developments generally has fallen short of expectations.

Oil production

The late 1995 boost to Norways oil production came largely from two new sources.

Heidrun field in the Norwegian Sea made its first contribution during October, averaging 13,000 b/d for the month. In the North Sea, Troll fields oil platform made its first complete months contribution to the total, averaging 170,000 b/d after going on stream in mid-September.

Raustein said planned developments will help keep Norwegian oil flowing at a hefty volume. Njord and Norne oil fields are under development, while development plans have been submitted for Visund and Balder fields.

There also will be significant oil production from Aasgard fields, for which a development plan was recently submitted, although gas will be the main output there.

Raustein said the Hermod discovery, a heavy oil reservoir, is likely to be put forward in a year or two for development. Trolls oil reserves were upgraded last year, moving it up from a large oil field into the giant class.

All these discoveries, apart from Aasgard, are mainly gas, Raustein said, but Norway has plenty of gas discovered already. All the operators are aiming to find oil when they explore, but they are prepared to settle for gas.

Wood Mackenzie expects at least 19 field development projects off Norway during 1996-2000. They hold estimated total reserves amounting to almost 4 billion bbl of oil and more than 40 tcf of gas (Table 1 [33126 bytes]).

Energy production

Norways total energy output is about three times greater than domestic demand. The country exports about 90% of its oil and gas production.

In 1994 Norway consumed 22 metric tons of oil equivalent of energy: 44% produced from hydropower, 36% from oil, 9% from solid fuels, and 11% from natural gas, used mainly during oil and gas production. It delivered 24.2 million metric tons of oil equivalent of natural gas to other European countries, of which more than one third went to Germany (Table 2 [11541 bytes]).

IEA said Oslos oil and gas policy, as described in its long term program for 1994-97, is that ...resources should in the governments view be managed with the aim of maximizing value added and ensuring a high share of total petroleum revenues for the community as a whole, taking into account the needs of future generations.

The petroleum sector plays a large role in Norways economy, contributing 15% of gross national product in 1993 and 33% of export revenues.

Oil delays

Wood Mackenzie cited delays in placing Heidrun field on stream as an example of recent Norwegian early production problems. However, Statoil reported at yearend that Heidrun oil flow is increasing faster than expected when it went on production last October.

Current forecasts indicate that plateau output of 220,000 b/d could be achieved as early as the New Year, Statoil said in late December.

At first, Statoil expected Heidrun production for 1995 would amount to 3.8 million bbl of oil. Now it looks likely to exceed 6.3 million bbl.

Statoil is seeking ways to boost production from Heidrun still further and has set a target to achieve 250,000 b/d this year.

Wood Mackenzie said, The influence on overall oil and NGL production levels in Norway is expected to swing away from existing producing fields as a significant number of new fields are expected to be brought on stream during the next 5 years.

Beyond the initial start-up period the new fields will, however, probably outperform current production forecasts. As a result, oil and NGL production should not be expected to fall as steeply as forecast in the longer term.

Moreover, there is a portfolio of discoveries that have not been included in our analysisfor example, Sagas H structure and Essos Elli discoverieswhich could possibly come forward for development in the medium term.

In addition, new discoveries could potentially be tied in soon after discovery. However, the impact of production from fields without the current portfolio of probable developments and from new discoveries is considered to be minimal.

Oil developments

Among Norways recent oil discoveries, Norne is the largest. Many of the forthcoming field development projects involve discoveries drilled in the 1980s, only now becoming viable due to improved technology and use of floating production systems.

Norne, discovered in early 1993, holds estimated reserves of 440 million bbl of oil. It was hailed as the largest strike off Norway in 8 years.

Norne is being developed using the worlds largest production ship. It is to begin production in 1997.

Njord field, estimated by operator Norsk Hydro AS to hold 220 million bbl of oil and 5 billion cu m of gas, is another floater development. Hydro hopes to begin production in October 1997.

Hydro intends to develop Visund field, with reserves estimated by the Norwegian Petroleum Directorate (NPD) at 47 million cu m of oil and 50 billion cu m of gas, with a production semisubmersible.

Hydro last June disclosed a plan to develop a thin oil layer in the gas province of West Troll field, effectively doubling the fields oil reserves to more than 1 billion bbl.

Hydro began oil production from West Troll last year using a production semisubmersible and plans to develop the new oil zone using 54 wells with long horizontal sections. Some of those wells, in the south part of the gas province, will be produced using the existing semisubmersible platform. Wells in the north portion of the gas province will be produced using a new production semisubmersible.

The Aasgard project, made up of Smoerbukk, South Smoerbukk, and Midgard fields off mid-Norway, has estimated reserves of almost 800 million bbl of oil and 7 tcf of gas. Aasgard oil production is to begin in 1998, while gas production is to start in 2000.

Statoil operates Aasgard in conjunction with Norways Saga Petroleum AS. Early in development discussions, Statoil and Saga have decided to develop Aasgards oil reservoirs using a production ship with capacity to yield and process 175,000 b/d of oil.

Aasgards oil reserves are a key to early revenues from development of the three fields. The project is vital to building of export infrastructure to tap gas reserves in the Norwegian Sea (OGJ, Oct. 9, 1995, p. 29).

Esso Norge AS recently let contract to ABB Offshore Technology, Stavanger, and Coflexip Stena Offshore Ltd., Aberdeen, for subsea equipment to be installed in development of Balder field off Norway. Although Esso has not yet received government approval to develop the field, with a submission for development plan approval only being submitted to the Ministry of Industry & Energy in October, the company is looking to begin production late in 1996 or early in 1997.

Balder holds reserves estimated by NPD at 34.5 million cu m of oil. The field is too remote to be linked to existing infrastructure. So Esso has chosen to use a production vessel with tanker offloading.

Esso and license partner Enterprise Oil plc, London, have made a number of finds in the Balder vicinity in the past couple of years, however, so the Balder infrastructure may be used to speed their development.

Statoil in late December announced a plan to develop three discoveries near Gullfaks field in the Norwegian North Sea as subsea satellites of Gullfaks A platform.

South Gullfaks, Rimfaks, and the Delta discovery hold combined reserves estimated at 260 million bbl of oil and will be developed using a total of seven subsea templates and 23 wells at a total development cost of 6.5 billion kroner ($1 billion). Oil production is slated for late 1998, with peak output of 125,000 b/d expected to coincide with declining production from Gullfaks.

The Hermod discovery is, along with Norne, Norways other major find of the 1990s. NPD estimates reserves of Block 25/11 Hermod at 60 million cu m of oil. Operator Hydro is far more cautious, saying the reservoir holds 42.6 million cu m of recoverable oil.

NPD says Hermods oil is heavy and difficult to produce, so licensees are likely to consider a long term production test or early production scheme to gain reservoir experience.

Norwegian operators will draw little comfort from 1995 exploration results. Statoil reported in late December that hydrocarbons were found in 64% of wells drilled off Norway during the year, but that most of the strikes were small.

Statoil said total estimated reserves for discoveries in 1995 are 320 million bbl of oil and 75 billion cu m of gas, of which Statoils interests are about 44 million bbl of oil and 11 billion cu m of gas.

A Statoil official said, Although most of the proved resources are commercially recoverable, they will compensate for no more than about 22% of Statoils overall annual oil production.

One of the discoveries, near North Statfjord field, was made with an extended reach well from Statfjord field. It has been tied back and placed on production.

Two other discoveries are included in the development plan for Gullfaks satellites. Statoil expected to submit the plan to Ministry of Industry & Energy late last month.

Gas developments

Negotiated gas sales contracts are expected to boost Norways exports from 24.7 billion cu m in 1993 to 59 billion cu m in 2005. Norways gas negotiating committee of operators expects the countrys gas exports to reach 70-80 billion cu m/year long term.

Controversy has surrounded discussions this year over which Norwegian fields will be chosen to meet long term contracts.

Sleipner and Troll fields were developed with those contracts in mind, and Troll A gas production platform, currently being readied for operations, is the mainstay of Norways gas production plans. Troll A, due on stream next April, is the worlds largest gas production platform, with design capacity of 100 million cu m/day.

The recent furor has been over producers recommendation to Oslo that Aasgard fields be developed ahead of gas reserves in Oseberg field, which already is producing oil.

Aasgard development would not have been sanctioned by Statoil and Saga without gas contracts. Yet Oseberg oil production is likely to be affected if gas production does not begin after 2000.

The gas supply committee recommended development only of Aasgard in the most recent round of gas contracts discussions but said Oseberg would be first on the development list in the next round of sanctions (OGJ, Nov. 27, 1995, p. 28).

Statoil early last month announced it will use a production semisubmersible to develop the gas resources of Aasgard, earmarked to supply almost 11 billion cu m/year of gas to continental Europe.

A Statoil official said the Aasgard gas semisubmersible likely will be the worlds largest floating gas production unit, having design capacities to produce 36 million cu m/day of gas, 11,000 cu m/day of oil, and 14,000 cu m/day of condensate.

Statoil submitted a development plan for the three fields to government last month, estimating the cost of developing Aasgard at 26.7 billion kroner ($4.17 billion).

Statoil said besides having a gas production semi and an oil production ship, Aasgard would have the worlds most extensive subsea production facilities, with about 60 wells drilled through templates.

In other Norwegian Sea action, Saga recently spudded well 6406/2-2, south of a wildcat drilled early in 1995 which made last years biggest strike off Norway (OGJ, Nov. 27, 1995 p. 28).

Shortly after the strike, Saga said it hoped to prove up about 200 billion cu m of gas and 70 million cu m of condensate in the discovery. The new well will target the same structure.

In early December, Saga said five of seven planned tests are complete on the 6406/2-1 well, and it needs results from the two outstanding tests plus the second well before it can give a firm reserves estimate.

The tests have confirmed a large gas find with some condensate, Saga said, but results so far suggest a somewhat smaller find than was originally indicated. This is because the two deepest tests produced only water.

Saga plans to drill a third well on Block 6406/2 this year.

Despite the setback on gas sale allocations, Norsk Hydro submitted a plan for development of Oseberg gas reserves to the Ministry of Industry & Energy on Dec. 15. The plan calls for installation of a steel platform and export pipeline in a 3.6 billion kroner ($550 million) program.

Osebergs oil reserves were developed using three platforms, with bridge-linked process and drilling platforms forming the field center. The gas platform is to be bridge linked to this field center.

Hydro expects the gas platform and field installations to cost 2.5 billion kroner ($385 million), while construction of a pipeline to send gas to Heimdal field for export carries a 1.1 billion kroner ($165 million) price tag.

Oseberg oil production, which began in 1988, currently averages 500,000 b/d. Hydro estimates Oseberg gas reserves at 115 billion cu m and said export of gas can begin in 2000.

The gas platform is designed to enable exports of 4 billion cu m/year from Oseberg during 2000-10, after which production could be increased to 10 billion cu m/year.

Meanwhile, Statoil and partners operating two major pipelines from the Norwegian North Sea to continental Europe have submitted a plan to government for construction of loop to bypass Ekofisk field.

Ekofisk is to be redeveloped following subsidence, so Statoil has suggested a 15-20 km, 500 million kroner ($80 million) link between the existing Statpipe and Norpipe trunk lines.

The link, to be ready for operation in summer 1998, will carry Statfjord and Gullfaks gas on its way to Germany. Statoil hopes to have government approval of the link by Mar. 1.

Gas contracts

The first generation of Norwegian gas sales agreements was depletion contracts. The Troll contract was the first of a new type of contract that defines specific yearly deliveries.

IEA expects deliveries under depletion contracts to fall from 23.3 billion cu m in 1993 to 14 billion cu m in 2000 and 4.5 billion cu m in 2005.

IEA estimates gas reserves discovered off Norway amount to more than 2.8 trillion cu m, and production at current levels could be maintained for more than 100 years. With undiscovered resources estimated at more than 2.4 trillion cu m of gas, IEA reckons Norway could become a much bigger gas supplier in the future.

With this in mind, Norways operators are starting construction of more offshore trunk lines to carry gas to continental Europe from the end of the century. These will bring Norways total gas export capacity to 72 billion cu m/year.

The three existing trunk lines will be joined by two new lines. That will result in three of the five lines going to Emden, Germany, one to Zeebrugge, Belgium, and the fifth to Dunkerque, France (OGJ, Aug. 28, 1995, p. 67).

In Germany, Norways biggest gas customer, onshore distribution pipelines are being completed in anticipation of further Norwegian imports. Speaking at the inauguration of the Norddeutsche Erdgas Transversale (Netra) pipeline in Germany last Nov. 21, Klaus Liesen, chairman of Ruhrgas AG, Essen, said the new line is a manifestation of the growing importance of Norwegian gas for Europe (OGJ, Dec. 4, 1995, p. 42).

Liesen said, The share of Norwegian gas in western European gas supplies, currently about 10%, will increase by 50% in the next 10 years on the basis of contracts already concluded.

The prospect of increasing deliveries and a rising share of Norwegian gas in gas supply exists for Germany in particular. Deliveries to Germany will more than double within the next 10 years from just under 12 billion cu m/year at present to at least 30 billion cu m annually.

In that period, Norways share in the German gas market, currently 15%, will move up to 30%. On the German side, we believe and hope that this will not be the end of the road.

The decisive basis for this process and options for the future is the impressive and fortunate development of large gas reserves in the Norwegian North Sea, especially Troll field.

Without these significant reserves from a source marked by political stability and high technical and commercial expertise, the European energy industry and the energy policies of importing countries could not earnestly set such far-reaching goals in respect of gas as they rightly do at present.

Liesen said the Netra link is particularly important as a link to the former East Germany, including the Greater Berlin area. Although Russia is still the predominant gas supplier to eastern Germany, an agreement between Verbundnetz Gas AG of Leipzig and Norwegian producers has helped boost gas consumption there.

Over the last few years, Liesen said, the share of gas in energy supply for eastern Germany has virtually rocketed and will at the end of this year be higher than the share of gas in primary energy consumption in the former Federal Republic.

Heinrich L. Kolb, parliamentary state secretary at Germanys Federal Ministry of Economics, told the gathering the Netra line is an important step in achieving further diversification of gas supplies for eastern Germany and in reducing dependence on Russia.

Kolb said,Following the commissioning of the Europipe I offshore trunk line this autumn, it is now possible to transport over 30 billion cu m/year of gas from the Norwegian North Sea to Germany via the two existing pipeline systems.

The region around Emden and Etzel will thus become a major hub for gas transportation to the south and east. Its importance will grow still further when Europipe II comes into operation around 2000. Then some 45 billion cu m of Norwegian gas will reach Germanys North Sea coast annually.

The Wardenburg-Werne pipeline, also inaugurated today, permits large gas volumes to be carried to southern Germany as well, thus making a further important contribution to security of gas supply there.

Netra will also allow gas to be transported later to Poland and the Czech Republic, for example. This leads to a European dimension enabling central European countries to diversify their supply structure with the aid of gas imports from Norway.

Kolb said growth prospects for natural gas are good, with the European Commission estimating that members gas consumption will increase about 40%from 340 billion cu m in 1994 to 540 billion cu m in 2010.

The share of gas in Europes primary energy consumption is expected to reach 26% in 2010, with power generation expected to account for more than half of the volume increase.

German gas industry also anticipates a promising future for natural gas, Kolb said. Gas consumption is expected to rise to approximately 110 billion cu m by 2010, with the share of gas in primary energy consumption significantly higher than today.

Kolb said the German government welcomed the increasing use of Norwegian gas in Germany because it contributes to diversification of gas sources and security of supply.

Norway has always proved to be a reliable and competent supplier, Kolb said. We are certain this will continue to apply. Therefore, we do not need to worry about future gas supply, even with rising consumption.

Kold said IEA had shown that Norwegian gas reserves were able to match German demand forecasts, but further pipeline links with Norway will be needed.

The prospects for gas depends to a decisive extent on attractive pricing and competitiveness, he said. This is determined above all in relation to the prices of rival fuels, namely gas oil and heavy fuel oil. In both cases, the mineral oil industry does not anticipate a substantial rise in real prices over the next few years.

Eastern Europes market

Recent privatization of state gas concerns in Hungary also showed a way for increasing Norwegian gas exports after entering the eastern European market through the marketing efforts of German firms.

Early last month, VEW Energie AG, Dortmund, and Ruhrgas AG, Essen, secured a 39% interest in Budapest Gas Works (Fogaz) for $52 million. Fogaz supplies 85 bcf/year to 700,000 customers in the Hungarian capital.

VEW and Ruhrgas are seeking to expand their gas supply operations and view privatization of former Communist state firms in eastern Europe as a major opportunity.

A Ruhrgas official said Hungary provided the first of an anticipated number of gas industry privatizations: We had to take this chance. We are interested in other countries as well, including the Czech Republic, Slovakia, and Poland, but it will be a long time before privatization in those countries.

Fogaz currently receives half its gas from Russia and half from Hungarys state oil and gas production concern, MOL.

Fogaz, which wants to buy gas from Norway, recently agreed to buy 17.7 bcf/year from MOL. Fogaz gas supply contracts with Russia expire in 1998.

Wood Mackenzie said the Czech Republic is likely to be the next former Communist country to sell state owned gas firms. The analyst expects this to occur after elections next June.

Czech gas demand is expected to rise from 7.7 billion cu m last year to 13 billion cu m/year by 2010. State gas transmission company Transgas, which will not be sold because of its strategic importance, currently has capacity to import 42 billion cu m/year of Russian gas, most of which passes through to western Europe.

The Czech Republic has been completely dependent on this Russian gas for its own provision, Wood Mackenzie said, and this constitutes a major security of supply risk for the country.

Prague would like to diversify its gas supply sources away from the former Soviet Union and has been negotiating with Norwegians and others over future supply.

Norways competitors

Europes gas supplies come mainly from Russia, Algeria, Norway, and Netherlands (Table 3). Netherlands exports are expected to decline, but Russia, Algeria, and U.K. are vigorous competitors with Norway for further gas supply contracts.

Russias Gazprom has said it needs to invest more than $500 million/year until 2000 to upgrade its existingbut increasingly unreliablegas distribution grid.

Gazprom Director Vladimir Rezunenko said the findings of a study that cataloged the grids problems will be used to help the company market itself as a reliable gas producer and delivery partner (OGJ, Nov. 27, 1995, p. 31).

IEA said Russian gas reserves were estimated at 48-49 trillion cu m at the beginning of 1994, which is about 35% of world gas reserves.

Very soon, however, domestic politics and Gazproms ambitions to increase gas exports to former Soviet Union neighboring states are likely to keep ambitious expansions off the top of Gazproms agenda.

For the long term, Russia is expected to be a major force in Europes gas markets.

Algerias Sonatrach has been a consistent supplier of gas to Europe for many years. A recent deal with BP Exploration Operating Co. Ltd. showed it has ambitions to increase gas supplies to southern Europe.

BP and Sonatrach last month signed a contract for a $3.5 billion exploration and development program in the In Salah sector of Algerias District 3 (OGJ, Dec. 25, 1995 p. 26).

The companies said seven existing finds here have 5 tcf total gas reserves, while prospects in the In Salah license have been assigned a further estimated 5 tcf of reserves.

BP and Sonatrach have set up a joint marketing company to sell the gas in southern Europe. They hope to begin gas production in 2002 or 2003 and aim to export 350 bcf/year to Portugal, Spain, and Italy.

BP Chief Executive John Browne said the deal could open a new era of gas production in Algeria and, from the next decade onward, give European consumers greater choice in their sources of gas supply.

Ammar Makhloufi, Algerias industry and energy minister, said government wants to see two or three major gas projects emerge in the In Salah region, which he said holds promise of big gas discoveries. Algerias government is said to be particularly keen to attract U.S. and British oil and gas companies to Algeria.

Algeria also is said to be eager to expand its gas marketing beyond southern Europe, where it dominates, in pursuit of a share of Europes largest gas market, Germany.

Another competitor against Norway is U.K.s planned Interconnector gas pipeline to Belgium, which is intended to export as much as 20 billion cu m/year of gas to continental Europe starting in October 1998.

Statoil, one of many entities skeptical about the practicality of the project, says Interconnector start-up target is likely to be postponed because sales contracts with European customers have yet to be agreed.

Tor Martin Anfinsen, gas market analyst at Statoil, thinks the Interconnector will not be built until shippers secure long term take or pay deals with Belgian distributor Distrigaz SA.

Distrigaz is thought unlikely to build a required link to the German market until gas buyers in continental Europe sign purchase contracts. Viability of the Interconnector is said to depend on this link.

However, Jean Vermiere, director of Distrigaz gas supply and sales, told a recent conference Belgiums role is a gas transit hub, and Interconnector will enhance that role.

He said, As a hub of growing importance for European gas flows, Zeebrugge has the potential to facilitate new trading opportunities in an integrated European grid. Its strategic location and short connections to Europes politically most secure sources should appeal to countries wishing to diversify their supplies, particularly in eastern and southern Europe.

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