NORWEGIAN SAFETY ISSUES, RISING OIL FLOW TOP WEATHER WINDOW NEWS

Norway has shored up its position as the No. 1 offshore oil producer in northern Europe. Data disclosed in January put average Norwegian oil production ahead of the U.K. for the first time at 1.94 million b/d in 1991 vs. 1.84 million b/d. This year, Norway's production has been more than 2 million b/d most months, while the U.K.'s has stayed at less than that level. AU of Norway's oil production is offshore, while the U.K. figures include a small onshore volume.

Spending plans suggest Norway is poised to widen the gap with No. 2 European producer U.K. this decade.

By yearend, Norway will have almost caught up with the U.K. on new field development spending as well. An estimated total outlay of $8 billion expected off Norway this year compares with plans to spend $8.5 billion off the U.K.

Projected outlays for 1992 work are almost $2 billion off Netherlands and about $1 billion off Denmark.

The year's work was characterized by Norway making progress on a number of innovative projects, while the U.K. saw many of its remaining major projects completed or near completion.

Netherlands saw its first concrete platform installed and prepared for a development surge following a string of recent exploration successes. For the Danes, it was business as usual, with work continuing on existing installations.

For the second consecutive year, safety concerns involving a Norwegian project dominate this year's news of weather window activity in the region.

SAFETY CONCERNS

Last month the Norwegian Petroleum Directorate threatened Phillips Petroleum Co. Norway with shutting down Ekofisk field operations by the 1995-96 winter, if safe operation of the field's 2/4T concrete processing and storage tank could not be guaranteed (OGJ, Oct. 19, p. 42). Phillips and its Ekofisk partners presented their 2/4T safety plan to NPD just ahead of the directorate's Oct. 30 deadline (see story, p. 29).

Last year's sinking of the Sleipner gravity base structure (GBS) in a fiord near Norwegian Contractors' Stavanger yard, made NPD look hard at safety design criteria for offshore installations (OGJ, Oct. 28, 1991, p. 21). NPD did not criticize use of concrete in designs, giving the same scrutiny to steel structures under tightened safety rules. But the age of some structures and concerns about maintenance sent NPD on the offensive.

Early this year, NPD said, "There sometimes exist serious defects in the maintenance systems of some operators," noting that older installations, whether concrete or steel, were causing problems in meeting new safety regulations.

In July, NPD asked Norwegian operators to reassess designs of all concrete installations. This followed Norwegian Contractors' acknowledgment that the Draugen GBS, as designed for AS Norske Shell, could not withstand 100 year wave conditions.

Shell had asked for a study of Draugen after research showed changes were required to the Heidrun concrete hull. Heidrun operator Conoco Norway Inc. was told changes could be made easily and the project would meet scheduled installation in 1995.

FIELD DEVELOPMENTS

During the next 5 years, Norwegian operations will account for the biggest chunk of spending off northern Europe.

Plans call for outlays of 216 billion kroner ($31 billion) off Norway by 1998, according to County NatWest WoodMac, Edinburgh. It projects spending off Norway in 1993 at 46 billion kroner ($7 billion).

The U.K.'s Offshore Supplies Office (OSO) puts 1993 Offshore Norway spending higher, at $9 billion, while Netherlands offshore operations will account for a little more than $1 billion and Denmark $750 million.

Aberdeen University Petroleum and Economic Consultants said this year's $8.5 billion new development spending off the U.K. will fall to $5.1 billion by 1995, if oil prices remain at current levels. By 1997, Offshore U.K. outlays could plunge to $4.3 billion but perhaps rebound to more than $5 billion by 2000.

County NatWest said Dutch offshore investment will peak in 1992-93 at about 11.8 billion guilders ($6.8 billion)/year.

SNORRE

In the Norwegian offshore sector, Saga Petroleum AS started production in August from Snorre field, which is being developed from the world's largest tension leg platform (TLP).

The project also holds the record for the deepest water for a North Sea platform at 1,020 ft. The Snorre TLP was tethered in the field in April.

Saga placed Snorre on stream 6 weeks ahead of schedule (OGJ, Sept. 7, p. 33). At the end of October production was 3,000 b/d. It is expected to reach 100,000 b/d during November-December.

Early problems included seawater flooding of one of the TLP's legs during commissioning when a test valve was not completely closed. Then power generators failed and valve seals had to be replaced on the production line.

Current production is from four wells, with a fifth due on stream soon. The first subsea completion is due on stream in early December. This year's work is winding up with backfilling over export pipelines.

Next year, supply risers and subsea production equipment will be installed. Risers will be delivered in the summer, and seven Christmas trees for the subsea installation will be supplied at regular intervals until summer 1994.

HEIDRUN

Conoco installed a 2,300 metric ton drilling template in Heidrun field in early August. It has 56 slots and eight dedicated import/export pipeline connections.

Conoco spudded the first Heidrun well at the end of September. Drilling will continue during winter for completion and testing in spring 1993.

Next step will be installation of a guide frame for eight piles, two adjacent to each corner of the template. These will aid positioning of the four concrete tether foundations to be carried out in 1994. Tethering will be completed in December 1994.

DRAUGEN

Norwegian Contractors recommended increasing the height of Draugen field's 285 m tall monotower by 4 m, following independent research at the Danish Maritime Institute, Copenhagen. Shell resumed construction after studying the proposal and remains confident tow-out will take place in May 1993 with first production in the fall.

Topsides fabrication is almost complete, and the substructure is ready. Slipforming of the shafts was carried out in two parts to allow for modifications. The offshore loading system is more than half completed, and installation of flow lines is at the halfway mark.

Shell hired the Ross Isle semisubmersible on short term charter in March to probe for shallow gas hazards at the planned GBS site. A well was later drilled to determine which zone will be used to reinject gas. By yearend, Shell intends to begin drilling production wells.

A total 50 km of flexible flow lines and 30 km of control umbilicals connecting the five subsea locations to the main platform will be laid during 1993.

SLEIPNER

Last year's casualty, the Sleipner A development project, resumed with new plans to place the gas field on stream in October 1993. But 500 million kroner ($80 million) had to be spent to build a temporary support structure to allow Sleipner platform modules to be preassembled. The deck assembly was complete in February, when the last of the topsides modules was lifted into place.

In May, field partners led by operator Den norske stats oljeselskap AS agreed to a 1.7 billion kroner ($270 million) insurance settlement for the loss of the GBS last year.

The new GBS took shape during the year and is being readied for joining the two parts in May 1993, followed by tow-out in June and field installation in summer. Progress on the modules has slowed slightly, so some commissioning work may take place after tow-out.

STATFJORD

In March, Statfjord field production rose to 760,000 b/d, up 10% from 2 years ago and more than anyone had predicted. This was due to last year's extended reach and horizontal drilling campaign.

Production has been so strong from all platforms that Statoil may delay production from North and East Statfjord satellites because of processing capacity constraints.

Statoil was the only Norwegian operator with a major maintenance program during the year.

Statfjord was shut down for much of May for work, including tieback of Snorre. Shutdowns of Statfjord B and C platforms took place in August and September.

BRAGE

Norsk Hydro AS is carrying out a six well development drilling program in Brage field throughout the year, spudding the first in January and aiming to complete the last by late December.

Hydro hired Westminster Offshore AS to bury oil and gas pipelines connecting Brage with Oseberg field and the Statpipe pipeline system, respectively, starting in autumn for scheduled completion in spring 1993.

Hookup and commissioning of the Brage platform began this fall for completion late next year.

TROLL

Saga and partners began a 3-D seismic survey of East Troll reservoirs covering a subsurface area of 40,000 sq km, with a view to help set development plans for the eastern field reservoir.

This year Norwegian Contractors completed the concrete base section for the gas platform. It was towed out from Stavanger and installed in the field at the end of September.

Three modules and a flare tower for the Troll oil platform will be installed next summer.

NELSON

In the U.K. offshore sector, Enterprise Oil plc pushed Santa Fe Drilling Co. (North Sea) Ltd. to complete predrilling for Nelson field development 12 days ahead of schedule. Enterprise agreed to an incentive scheme that paid double the day rate for each day under the 352 day schedule and no pay for every day over it.

Template drilling began in October 1991. Although 25 days were lost because of bad weather, Santa Fe caught up again. One well achieved 3,600 ft in 24 hr, including surveying every 90 ft.

Santa Fe's Rig 135 was then moved 3 1/2 miles south to drill two South Nelson satellite wells as producers to be tied back to the platform in winter 1993. The main field jacket will be installed in April 1993, with topsides following in the summer. Production is to begin early in 1994.

TIFFANY

Agip U.K. Ltd. started Tiffany development before Cullen report recommendations on offshore safety were published. The U.K. government ordered the Cullen inquiry in the wake of the Piper Alpha platform explosion and fire in 1988. Engineering changes were allowed for in the design, but no major additions were required during construction. Thirty-five safety studies were made, while 50,000-75,000 man hr have been spent so far in preparing the Formal Safety Assessment for the U.K. Health and Safety Executive.

The 17,500 metric ton Tiffany jacket was launched Sept. 24. It was piled and grouted and the support frame for the modules installed. Process and utilities modules are being installed, to be followed by the drilling package and accommodation module.

Hookup and commissioning will begin later this month with a view to producing first oil in second quarter 1993. Total costs for the Tiffany field development are estimated at 421 billion ($1.7 billion).

MILLER

BP Exploration Operating Co. Ltd. started production in June from Miller field on Block 16/7.

First oil flowed at 2,000 b/d from a single well. Production will rise to a plateau of 113,000 b/d, which it should maintain for 4 years. Field life is estimated at 10 years.

The 1.3 billion ($2.2 billion) development included 35 million ($60 million) extra spending on post-Cullen safety measures and an extra 15 million ($25 million) on project management and overheads to implement them.

Start-up was delayed from March by bad weather. BP chartered a second flotel for the field to quarter extra crews brought in to speed hookup and commissioning.

PIPER/SALTIRE

Elf Enterprise Caledonia Ltd. oversaw the world's biggest two crane lifts for module installations on its Piper Bravo and Saltire platforms.

The 11,000 metric ton process/utilities/deck module for the Piper Bravo platform on Block 15/17 was lifted into place in December 1991. Saltire's 10,800 ton integrated deck was lifted into place Sept. 15.

Elf is working to restart Piper production by yearend at 75,000 b/d of oil and 34 MMcfd of gas. The 140 million bbl Saltire field will begin production in early 1993, sending 45,000 b/d of oil and 50 MMcfd of gas to Piper for passing on to the Flotta and St. Fergus terminals, respectively.

Once Piper is producing again, its facilities will be used to place Chanter satellite field on stream next year. This will add 5,000 b/d of liquids and 20 MMcfd of gas to Piper throughput.

GANNET

Shell U.K. Exploration & Production started oil flow from Gannet field Oct. 29.

Production will build gradually to 50,000 b/d. Gas production will begin 2 weeks later, with the peak estimated at 80 MMcfd.

During development of Gannet, the Shell/Esso U.K. plc operating joint venture prejudged many of the Cullen report recommendations and chose minimum manning, an approach it will use to update some producing fields.

"We have many offshore platforms that have been operating for more than 15 years," said Chris Fay, managing director of Shell Expro. "We are faced with a simple equation of either closing these fields prematurely, due to high operating costs, or redeveloping them using modern technology."

Shell/Esso has 17 southern gas basin fields, four of which are unmanned. By 1996 it will have added six platforms and reduced the number of manned installations to three. After 20 years operation, the huge Leman and Indefatigable fields, which together produced 1.2 bcfd in the mid-1980s, are down to 700 MMcfd.

SCOTT

Amerada Hess Ltd. had the drilling-production jacket for Scott field installed on schedule by McDermott Scotland Ltd., Inverness, Sept. 20.

Scott is likely to be the North Sea's largest oil field developed in the 1990s.

The 16,155 ton structure was fixed with 20 vertical skirt piles of 595 tons each, the heaviest in the North Sea.

A second jacket, for the accommodation-utilities platform, will be installed next March, with topsides for both platforms following in the summer. Production is scheduled for start-up in late 1993.

EVEREST/LOMOND

Amoco (U.K.) Exploration Co. pushed its North Everest and Lomond field developments along with installation of three jackets at the end of July (OGJ, Aug. 10, p. 28).

Due on stream in April 1993, the fields are part of a Fl billion ($1.7 billion) project that includes laying the Central Area Transmission System (CATS) pipeline to Teesside, England.

The three jackets will carry the 9,500 ton North Everest production platform, 9,500 ton Lomond production facilities, and 2,880 ton CATS riser topsides.

NINIAN SATELLITES

Chevron U.K. Ltd. saw first production from third party subsea fields processed in its Ninian complex on Block 3/3.

Lasmo plc placed Staffa field, 6 miles east on Block 3/8b, on stream in March, producing as much as 8,000 b/d of oil.

Conoco (U.K.) Ltd. installed the Lyell production manifold on Block 3/2. Production is due soon, with a peak of 18,000 b/d of oil next year.

Texaco Ltd. will install the Strathspey field manifold on Block 3/4a next year, with production scheduled to start in the fourth quarter.

NETHERLANDS ACTION

The first concrete GBS off Netherlands was installed in F/3 field in June for operator Nederlandse Aardolie Maatschappij (NAM) BV, a joint venture of Shell and Esso. The honeycomb structure can hold 190,000 bbl of oil.

The F/3 GBS is topped by three concrete shafts, on which the production deck will be installed in second quarter 1993. Production wells will be drilled through the two conductor shafts.

Elf Petroland BV began production in May from two gas fields on Block K/6, with maximum flow projected at 175 MMcfd. The company's K/5-6 wildcat flowed 1.84 MMcfd and was suspended as a future producer. Elf has two other discoveries on the K/5 Block.

Amoco Netherlands Petroleum Co. let contracts for construction and installation in P/15 and P/18 gas fields, scheduled for completion in July 1993. This $500 million development is to begin production in late 1993. Platform capacity will be 500 MMcfd of gas. Pipelaying will begin soon, including a 40 km export line to the coast near Rotterdam.

DENMARK ACTIVITY

Danish oil production will rise to an average of almost 164,400 b/d in 1994 under current development plans. The Danish Energy Agency forecast a peak of about 164,400-191,800 b/d in 2003, declining thereafter.

Monthly production records were smashed in January with 161,000 b/d of oil. This was due to continued development drilling in Dan field, which boosted production by 4,000 b/d to 37,000 b/d. In February the record fell again, as production rose to 163,000 b/d, thanks to tying in of new production wells in Dan and Gorm fields.

DUC installed the Dan FD Star platform in May and the Dan FE platform in August. It ordered a platform for Valdemar field for delivery in May 1993. This will be linked to East Tyra field by a 19.6 km, 8 in. oil and gas pipeline.

A new development plan for Tyra was presented this fall, while a plan for development of Skjold is expected soon.

Denmark's first subsea completion is planned for start of production in late 1993. This will be a single wellhead completion in Regnar field, tied back to the Dan production platform.

PIPELINE WORK

The Nogat gas pipeline, linking gas fields in the northern Dutch North Sea with southern fields and the mainland, was completed. By March the pipeline had been tested, commissioned, and handed over to operator NAM.

Two platforms are feeding gas into Nogat, L/2 and L/5, with total flow of about 70 MMcfd. Other platforms will be tied in next year, with F/3 to be the last.

Zeepipe construction was completed for Statoil off Norway. The 1,300 km Sleipner-Zeebrugge gas pipeline is awaiting valves to complete the receiving terminal at Zeebrugge. Then commissioning will begin with first gas in the system next April-May.

The Amoco operated CATS project off the U.K., a 386 km, 600 MMcfd capacity pipeline linking Everest and Lomond fields to Teesside, was completed. Testing and commissioning have begun in preparation for first gas in April.

DEVELOPMENT DRILLING

Statoil started a 3-4 year program of drilling and completing subsea wells in new fields in the Norwegian North Sea.

The program consists of 24 subsea wells drilled through eight templates: two in Loke, two in East Sleipner, 10 in North Statfjord, and 10 in East Statfjord.

Oryx U.K. Energy Co. estimated at least 39 horizontal wells, each with a horizontal section of at least 1,000 ft, will be drilled in the North Sea this year. Most are off the U.K., with Chevron's Alba, Conoco's Murdoch, Mobil's Lancelot, and Shell's Barque, Clipper, and Galleon fields all requiring at least three.

The total is up four from 1991, when Dansk Undergrunds Consortium (DUC) boosted the tally with 11 horizontal wells in Dan field and two in Tyra field.

Lasmo plc completed development drilling in the Dutch portion of Markham field in Blocks J/3-b and J/6, with a view to sending first gas ashore in the fourth quarter.

EXPLORATION

By midyear, U.K. exploratory drilling had plummeted, with wildcats and appraisal wells at the lowest levels since 1987.

Sixty-five wells were spudded in the first half, compared with 102 for the same period last year and 174 for all of 1991.

Norway saw 23 wells spudded in the first half, 17 exploratory wells and six appraisal. Operators said they definitely will drill 36 wildcats and appraisal wells through 1992, with another 16 possible.

Netherlands saw first half activity fall 45%. Ten wildcats were spudded, compared with 17 wildcats and an appraisal well in first half 1991. The predicted 47 well total is unlikely to be met by yearend.

Danish Energy Minister Anne Birgitte Lundholt said in July that exploration license terms off Denmark may be sweetened to encourage further participation from foreign operators but noted short term activity will focus on development. Five exploratory wells were spudded in the first half off Denmark: DUC wildcats on Adda and Lulita prospects, two appraisal wells in the Tyra area, and one appraisal at Dagmar.

BEB Ergas und Erdol GmbH drilled a wildcat off Germany targeting an upper Jurassic structure. It was plugged in mid-June as a dry hole.

BP Exploration completed its largest 3-D program. Four survey vessels began in April to collect 25,000 line km of seismic data in 6 months. This covered Magnus field and its satellites, Clyde, Fulmar, Bruce, and Clair on Blocks 9/24-29 and the Medaen discoveries on Blocks 23/22-27.

IRISH EXPLORATION

Relaxed tax regulations revived interest in gas prospects in the Celtic Sea off southern Ireland.

Marathon Petroleum Ireland Ltd. plugged a Block 48/30-2 wildcat in August and is evaluating results.

After Marathon had finished, the Ocean Liberator rig was hired by Bula Resources plc, Dublin, to drill the 48/19-2 wildcat in search of gas (OGJ, Aug. 17, p. 44). But the well flowed 100 b/d of 15 gravity crude.

Mobil North Sea Ltd. acquired a farmout on Bula's Blocks 50/13 and 50/14, completing a 102 km seismic survey as part of the deal. Further seismic surveys next year may tempt Mobil to take up its option to drill a well on each block.

Amoco Ireland Ltd. joined the exploration campaign, agreeing to a joint program with Marathon. Amoco will join Marathon in at least three out of seven wells planned in the Celtic Sea before 1996.

OTHER EXPLORATION

In frontier exploration action off northern Europe, Norsk Hydro AS drilled the northernmost well on the Norwegian continental shelf.

The Barents Sea Block 7316/5-1 wildcat was drilled by the Polar Pioneer semisubmersible 100 km southwest of Bear Island.

The well flowed dry gas from shallow Tertiary sandstone at a maximum flow rate of 19.874 MMcfd. NPD said the find was encouraging for further exploration in the area. County NatWest described the discovery as noncommercial.

Mobil Exploration Norway Inc. returned to the Statfjord area to drill the 33/9-15 wildcat. It hoped to prove a northern extension to a 1987 gas/condensate find made by the 35/11-2 well but was disappointed.

BP continued probing Clair field, west of Shetland, getting the best test results to date with its 206/8-9z well. A maximum stabilized flow of 7,300 b/d was said to be limited by equipment.

Esso had a rare solo outing to drill the 206/13a-2 appraisal well in the Clair area. It flowed 1,058 b/d through a 28/64 in. choke with 310 psi wellhead pressure. Flow peaked at 2,545 b/d through a 1 in. choke with 183 psi wellhead pressure. Esso said results reflected the complex nature of the reservoir.

ROGUE WELL

Saga Petroleum AS reentered its 2/4-16 well off Norway in June. The well blew out in 1991 at a depth of 16,400 ft and was out of control for a year. This earned Saga a reprimand from NPD over its high pressure drilling techniques.

After installing and testing the blowout preventer and casing, Saga drilled through the cement plug but found no gas accumulation. At 16,350 ft it began a sidetrack around fishing tools and drill bits in the original hole, then pushed the 6 in. hole a final 650 ft to total depth 17,000 ft in a new formation.

Saga found unexpected bottomhole pressures of 15,000 psi, so it plugged the well for safety reasons with NPD approval. A new well will be drilled on the prospect next year.

OUTLOOK

The U.K.'s OSO predicted Norwegian offshore development activity will peak in 1994-95.

Norway has 51 development plans under consideration, with 15 possible fixed installations, six floating systems, and the rest subsea. Sixteen fields are under development and 25 more are expected to be submitted for approval the next 3-4 years.

County NatWest identified 57 U.K. offshore fields that could be developed the next 5 years with reserves totaling 2.3 billion bbl of oil and 14.3 tcf of gas (OGJ, Aug. 17, p. 49).

Major developments off Netherlands, including Nogat fields, Markham, K/6, P/15, and P/18, are likely to be completed in 1993-94. After that smaller satellite developments will keep the sector going until the end of 1996. The most important new center of activity will be Block K/5, where Elf Petroland is developing a cluster of small to medium size gas discoveries.

Smith Rea Energy Analysts Ltd., Canterbury, said satellite oil fields now represent about 14% of U.K. continental shelf production. By the time committed developments are complete, this could be nearer 20%, and growth will continue.

Of 300 undeveloped discoveries off Northwest Europe, 65 are likely to be developed as satellites in the foreseeable future, said Smith Rea, while many more are likely to be commercial in the longer term.