Hamilton Oil Co. Ltd. has won a Health & Safety Executive approval for North Ravenspurn gas field installations in the southern North Sea.
Hamilton is the first company to win safety case approval for a platform under recent U.K. offshore legislation (OGJ, Feb. 14, p. 25).
Meantime, North Sea oil production will reach a record average of 5.33 million b/d this year, up from last year's record average 4.49 million b/d, predicts Wood Mackenzie Consultants Ltd., Edinburgh.
That compares with monthly record North Sea oil production in January of 5.18 million b/d, which broke the 5.08 million b/d monthly output record in November 1993.
As for the Norwegian continental shelf, Norwegian Petroleum Directorate (NPD) said the hydrocarbon resource outlook there is healthy, although more innovation is needed to keep development costs competitive.
FIRST SAFETY CASE
"Preparing the safety case cost us on the order of f:l million ($1.5 million)," Hamilton said. "However, spending related to the safety case will not stop with approval."
North Ravenspurn field was developed with a processing and accommodation platform incorporating the first concrete gravity base in the southern North Sea. This is linked to three conventional steel satellite wellhead platforms.
The Block 43/26a field started up in October 1990 and reached peak output of 340 MMcfd of gas in 1993. Original field reserves were estimated at 1.3 tcf of gas.
Processed gas is exported from North Ravenspurn to nearby Cleeton platform, operated by BP Exploration Operating Co. Ltd. From Cleeton the gas is sent to shore by pipeline to BP's Dimlington terminal.
PRODUCTION FORECAST
Wood Mackenzie attributes the projected 1994 production increase mainly to a 30% increase in U.K. output.
The analyst predicts U.K. offshore oil production will average 2.5 million b/d in 1994, up from an average 1.92 million b/d in 1993.
The expected surge in output is attributed to increasing production from fields that came on stream in 1993 and production from start-ups (OGJ, Nov. 1, 1993, p. 23).
"The majority of new production is being transported via the Forties pipeline," said wood Mackenzie. "As a result, Forties blend volumes will exceed 1 million b/d by the end of the year, compared with 1993 average throughput of 440,000 b/d."
It said Norwegian output will continue rising to an average 2.59 million b/d in 1994, up 9% from 1993 levels.
However, Norway will account for a smaller share of total North Sea oil production, down to 49% from 53% in 1993.
The analyst thinks Norway's production supremacy may be tested, noting, "By the end of 1994 the substantial increases forecast for U.K. output may result in production from the U.K. continental shelf reaching Norwegian levels."
Four Norwegian fields are due to start up this year, with their combined production of 80,000 b/d not expected to have a dramatic effect on Norway's production profile.
Scheduled maintenance closures in Norwegian fields are expected to total more than 300 field production days in 1994. This is almost double 1993's shut-in days. This is expected to result in deferment of 23 million bbl of oil production in 1994, compared with 16 million bbl in 1993. Much of the maintenance work will be during 2 weeks in August in Ekofisk field.
Wood Mackenzie said liquids production off Denmark will average 190,000 b/d in 1994, a record and a 14% increase from 167,000 b/d in 1993. The Danish increase stems from continued development work in established fields and growing production from fields that came on stream in late 1993.
Netherlands offshore fields are forecast to achieve an average 62,000 b/d in 1994, double the 1993 average. Most of the increase will come from fields that began production in fourth quarter 1993.
RECENT OUTPUT
Production of crude and liquids gained or held steady from December to January for the major North Sea producing nations.
Wood Mackenzie noted Norwegian producers increased output 4% from December to an average 2.62 million b/d in January, just below Norway's November peak average of 2.63 million b/d (OGJ, Jan. 17, p. 24).
Average U.K. offshore production rose from 2.29 million b/d in December to 2.31 million b/d in January. About 530,000 b/d of incremental production is from 15 U.K. fields that came on stream last year.
Danish production set a record of 197,000 b/d in January, up from 185,000 b/d in December. The increase was attributed to increased output from Regnar field, which came on stream last September.
Oil and condensate production off the Netherlands held steady month to month at 59,000 b/d.
Norwegian gas production also set a record at 3.39 bcfd in January, up from 3.03 bcfd in December.
U.K. offshore gas production fell to an average 9.3 bcfd in January from 9.17 bcfd in December. Wood Mackenzie said U.K. gas demand averaged 9.4 bcfd in January compared with 9.49 bcfd in December. Norwegian imports met 5% of U.K. gas requirements.
Dutch offshore gas production rose slightly to 2.72 bcfd in January from 2.71 bcfd in December.
Danish gas output fell to an average 578 MMcfd in January from 589 MMcfd in December. Irish gas production averaged 288 MMcfd in January, up from 273 MMcfd in December.
NORWAY'S POTENTIAL
New figures from NPD show Norway's total proven recoverable oil and gas reserves amount to almost 44 billion bbl of oil equivalent (BOE). Production to date totals 9.5 billion BOE.
North Sea fields are estimated to hold 84% of Norway's reserves, with 11% in the Norwegian Sea, and 5% in the Barents Sea. Almost all production to date has been from the North Sea area of Norway's shelf.
NPD said 1.9 billion BOE were added to, reserves in 1993, of which 72% was oil. This was greater than last year's production of 1 billion bbl equivalent, of which 82% was oil.
During 1990-93 Norway added 5.4 billion BOE to reserves, of which 85% was oil. Production during the period was 3.7 billion BOE, of which 80% was oil.
"A big share of recent reserves increases have been oil," said Arild Nystad, manager of resources at NPD. This is good strategically. The challenge is that some of the new reserves are not commercially viable at present."
Nystad set out these priorities for NPD: establishment of profitable projects with improved oil recovery, development of technical solutions to deplete small fields profitably, and establishment of cost efficient strategies to identify remaining undiscovered resources.
Nystad estimated total resources on the Norwegian shelf at 73 billion BOE. Of this, undiscovered reserves were put at 27 billion BOE in 200-400 small fields. Small field development projects accounted for 13.5 billion BOE in 105 fields.
Norway's oil reserves would last 45 years at an average production of 1.6 million b/d, said Nystad.
Gas reserves would last 80 years even if production is raised to a targeted 7.8 bcfd after 2000.
Nystad said Norway's exploration sector had another 45 years of life left, assuming discoveries of 584 million BOE/year. A total of 40 fields have been developed or are under development off Norway, with reserves amounting to 29.2 billion BOE. Another 80 fields and discoveries are under consideration with total reserves of 14.6 billion BOE.
NORWEGIAN POLICY
Nystad said the recent government white paper proposing new license conditions offshore Norway recognizes the difference in average field sizes of developed and undeveloped fields: 730 million BOE and 182.5 million BOE, respectively.
Three fourths of future reserves are expected to be discovered within 50 km of current infrastructure.
By 2000 Norway needs to begin bringing small fields into production, Nystad said. By about 2010 small fields combined may be producing as much as Norway's large fields.
Many of Norway's future small field developments are likely to use floating production ships, Nystad said. These would be used to deplete one field before moving along to another.
In the meantime, said Nystad, Norway's operators will have to cut new field development costs by 40-50%.
The number of pilot projects testing out new production methods will have to be raised drastically, Nystad said. This will require 3-5 years of planning but is vital if Norway is not to lose development capital to other regions such as Russia and Viet Nam.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
