Roger Vielvoye
International Editor
The cut in U.K. offshore production this quarter may be smaller than originally expected.
That could lend a measure of comfort to the fragile crude oil supply/demand balance during this critical period.
British offshore production could drop to less than 1.5 million b/d in November and December if the big Brent and Forties crude oil pipelines are shut down as scheduled to allow construction work. However, Shell U.K. Exploration & Production is considering a plan that would delay a shutdown of the Brent system until second quarter 1991.
And there are reports in North Sea circles that BP Exploration may postpone the tie-in of its new Forties pipeline until next spring.
With Brent and Forties pipelines open for business during the next 6 months, U.K. production could return to the 1.9 million b/d level-at least 450,000 b/d more than the pessimistic forecasts for production made during the summer.
In the Norwegian North Sea, production facilities are in good shape after summer maintenance shutdowns. Production is expected to average about 1.8 million b/d, exceeding the record level of 1.67 million b/d achieved earlier in the year.
Production from the Danish and Dutch North Sea is small in comparison, but this winter even small volumes of crude from secure sources have a beneficial effect on the supply demand/balance and the market's perception of crude oil supply from Northwest Europe. Danish production is expected to average about 120,000 b/d, with a further 50,000 b/d from the Dutch sector.
U.K. PROFILE
Until the 1990 maintenance period began in the late spring, U.K. offshore production had been running at about 1.9 million b/d. Oil flow during the summer was expected to face a sharper than normal seasonal decline because of an extensive program of emergency shutdown valve installations required in the northern and southern parts of the North Sea.
Complex schedules for installing the valves, along with normal weather window maintenance and construction work, were disrupted by a series of 1 day strikes called by the Oil Industry Liaison Committee (OILC) in support of union recognition, increased wages, and improved safety conditions.
Shell, which operates the Shell-Esso combine's fields in the U.K. sector, has the most demanding program of more than 60 valve installations. Hardest hit by 1 day strikes, it probably will not be able to meet a yearend deadline for completing the work ordered by the U.K. Department of Energy.
The company is confident that valves on all gas risers will be operational before the deadline. But there is a major question mark over oil valve installations, which would require a shutdown of the Brent pipeline system that serves 13 fields in the East Shetlands basin.
Shell is considering seeking a dispensation from DOE that would delay the work until second quarter 1991.
A dispensation for the oil valves would be sought on the basis that only dead crude would be shipped from Shell-Esso platforms. At present, live crude with a back pressure of 125 lb is exported to Sullom Voe terminal in the Shetland Islands.
TOUGH LINE
An application from Shell is not guaranteed an easy passage through DOE. The department is taking a tough line on enforcing the valve installation program.
Energy Minister Colin Moynihan recently told the U.K. Offshore Operations Association any disruption to installation programs caused by labor strikes could earn a dispensation.
Operators would have to submit a specific case for each pipeline, setting out the reason for delay, actions proposed to reduce risks, and plans to comply with the situation.
Moynihan said DOE inspectors would take a tough line with operators and would not hesitate to shut down operations where that was considered necessary for safety.
Industry sources said a desire to keep crude oil flowing at high prices will not be a reason for DOE to grant a dispensation.
Amoco U.K. Exploration was the first company to feel the effect of this uncompromising attitude toward safety. DOE ordered the company to improve safety on its Leman Alpha platform in the southern gas basin or face prosecution and shutdown of the unit.
The order was made after an inspection of the platform in September found an unsatisfactory management system.
DOE's concern centered on too few supervisors and too many working hours.
Amoco said its management system was not a risk to health and safety. It added it had been asked to document the system.
STRIKE ACTION
OILC has temporarily called off its series of unofficial 1 day strikes while the six official unions poll North Sea construction workers on full scale strike action.
However, the unions need to register at least 80% of the construction work force before final balloting can be held, a task that is proving difficult because of the diverse nature of the offshore work force. The official unions favor a longed strike in first quarter 1991 rather than 1 day strikes.
OILC reckons the unions have their timing wrong. It believes a long strike should be delayed until spring. That's when demand for contract personnel is much greater.
BP SHUTDOWNS
BP faces major cuts in its North Sea production during this quarter regardless of whether it shuts down Forties pipeline.
The company is in the final stages of a demanding valve installation program on its five platforms in big Forties field.
Forties Platform Delta was shut down at the end of last week for a 10 day program. When the unit is back in production, Platforms Alpha and Echo will be shut down, also for 10 days, for valve installation.
At that stage BP will have fitted 13 emergency shutdown valves. Three more will be installed during a field shutdown when the new Forties oil line is tied in.
BP has a program to install 14 valves in the U.K. North Sea before the yearend deadline. In addition to the 16 in Forties field, two have been installed in Magnus, four in Beatrice, and one in Buchan. The valve in Thistle field will be fitted during the Brent pipeline shutdown.
Platform shutdown will limit Forties production to 100,000-150,000 b/d in October and November, compared with as much as 200,000 b/d last spring.
Before yearend BP also is scheduled to shutdown Forties to tie in the new 36 in. pipeline that was laid this summer from the field to Cruden Bay, Scotland. Tie-in is expected to take about 10 days.
The line also serves Marathon U.K.'s Brae area fields, Amoco U.K. Exploration Ltd.'s Montrose and Arbroath fields, and Elf Aquitaine Norge's Heimdal field in the Norwegian sector.
Exact timing of the tie-in shutdown is subject to negotiations with BP's third party customers. There has been speculation that the closure could be delayed until early next year to ensure that the Forties lines is not out of action at the same time as the Brent system, farther north.
Production losses from the Forties shutdown would be about 260,000 b/d of U.K. oil and as much as 10,000 b/d of Norwegian oil.
In addition to the 220,000 b/d lost from the five Forties platforms, a further 140,000 b/d is piped from the Brae area, where Marathon operates platforms in North and South Brae fields and has a subsea production system on the Central Brae structure.
Elf Norge moves liquids from Heimdal gas field through a link into the Brae area. Production averages 8,000-10,000 b/d.
Valve installation has been given top priority this summer. Because of labor problems experienced throughout the summer BP was forced to downgrade its Forties gas lift project.
It still hopes to have the shallow gas lift operational by the end of this year, about 12 months behind the original schedule. The deep gas lift project is well advanced. The company hopes to complete the final phase of the program by the end of 1991, again 1 year behind the original schedule.
In the northern part of the North Sea, valve installation in Magnus field is complete, and the platform is ready to resume full production at about 160,000 b/d. However, the field has no gas injection facilities to offset the effects of the long shutdown of the Flags associated gas gathering system.
BP will require a DOE waiver to allow Magnus gas flaring. Without the waiver, Magnus production this quarter could be limited to about 80,000 b/d.
CHEVRON DECISION
Chevron North Sea has completed its platform valve program in Ninian field but postponed until next year its proposed installation of subsea valves on the in-field pipelines that link the three production platforms.
In the absence of legislation on subsea valves, there is no deadline for subsea valve work. Chevron said it will not proceed with subsea valve work this year because of the uncertain atmosphere created by 1 day strikes.
Without the commitment of contractors' employees, safety might be prejudiced during installation of the eight valves, which would be installed as four sets of two valves each.
Chevron also is concerned that strikes, once subsea lines had been cut to allow valve operations to begin, would make the field vulnerable to an extended shutdown.
The decision to postpone the subsea work was coordinated with BP, operator of the main Ninian oil line to Sullom Voe. BP also delayed installation of the subsea valve on this line until next year.
Production from Mobil North Sea's Beryl field was cut substantially during August for an extensive maintenance and hookup program. Beryl was to be back to its earlier year average of more than 100,000 b/d throughout the third quarter.
NORWEGIAN PRODUCTION
Production is to rise this quarter in the Norwegian North Sea.
In the biggest field, Statfjord, operator Den norkse stats oljeselskap AS said the summertime maintenance shutdown on Platform A is complete. Statfjord production this quarter is to average about 620,000 b/d, with another 115,000 b/d lifted by British partners in the field straddling the British-Norwegian line.
Statoil's other major producing operation, the three platform Gullfaks field, is expected to average about 280,000 b/d in this quarter.
Gullfaks oil flow has been reduced by sand production and minor problems with water breakthrough. Statoil has been dealing with the sand production through an extensive program of gravel packing. The program has concentrated on Gullfaks Platform A, where the company has drilled 19 of the field's scheduled 23 producing wells.
Statoil has drilled 10 of the scheduled 22 producers on Gullfaks Platform B and three of 23 producers on Gullfaks Platform C.
The company said not all the wells will need gravel packing. Many of the existing wells will be gravel packed, and most new wells will be gravel packed before production start-up.
Statoil's Veslefrikk field production is up to 70,000 b/d and will remain at that level this quarter. The company is also producing about 13,000 b/d of liquids from the Tommeliten subsea gas operation.
The two other major producing areas in the Norwegian North Sea are Norsk Hydro's Oseberg field and Phillips Petroleum Norway's Ekofisk complex.
Norsk Hydro shut down Oseberg for maintenance during the summer. The approved maximum production for second half 1990 is an average 320,000 b/d. During this quarter Oseberg will produce about 340,000 b/d in an effort to make up for oil lost to the summer shutdown.
Phillips said there had been no major maintenance work requiring shutdowns last summer. Production from the Ekofisk area is expected to average about 250,000 b/d throughout the winter.
Amoco Norway also produces its Valhall field through Ekofisk facilities. Production from the field is expected to average about 78,000 b/d this quarter.
BP Norway is increasing its production this quarter. Gyda field, which started up last July, is to average about 69,000 b/d this quarter.
BP has received permission from the Norwegian government to raise peak production from Ula field to 108,000 b/d from 94,000 b/d. An upgraded water injection system will be needed to reach the new peak, and the company expects to achieve that level in December.
Average production this quarter will be about 100,000 b/d. Ula's single platform should be able to produce at the higher peak rate throughout first quarter 1991.
ONSHORE FALLOUT
Effects of long shutdowns in Shell-Esso fields are felt onshore by European petrochemical manufacturers.
Hardest hit are the chemical offshoots of the Royal Dutch/Shell Group and Exxon Chemical Co., whose jointly owned ethylene cracker at Mossmoran, Scotland, relies heavily on North Sea feedstock.
The cracker, which started up early in September after a planned August shutdown, has been hit heavily by a reduced supply of gas liquids from Shell-Esso offshore fields. NGL moves ashore through the Flags pipeline system.
Shell said the Mossmoran cracker, operated by Exxon Chemical, is experiencing a 20-30% shortfall in feedstock.
Because the ethylene market in Europe is tight, it's not possible to make good the shortfalls from Mossmoran, where ultimate customers for low density polyethylene are on allocation.
Exxon is running its polyethylene plants at Meerhout and Zwijndrecht, Belgium, at reduced capacity. Customers have been told that shipments will be reduced for the next 3 months.
"We expect to return to normal conditions when problems in North Sea gas supply have been resolved," said John Taylor, Exxon Chemical International's vice-president, polymers.
The standoff in the Persian Gulf has had almost no effect on the European supply of polyethylene. The Kemya plant in Saudi Arabia, in which Exxon is a partner, is operating normally, Taylor said, but its production continues to be mainly exported to Asian markets.
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