Guntis Moritis
Production Editor
For this special report, the Journal has constructed two-dimensional schematic diagrams to aid in understanding the complex offshore oil and gas production infrastructure of the central North Sea.
The diagrams cover the region between the Hod field, near Ekofisk, in the south and the Magnus field in the north.
This region has been divided into seven areas as shown on the pipeline map.
Over the last few years, a large number of small satellite fields have been tied into existing production facilities. These additions create a very complex production network. Although this networking lowers development costs, often the development of discoveries is delayed until production through existing facilities falls sufficiently to handle the additional production streams.
More than fifty discoveries are thought to have potential of being phased into the production network by the year 2000.
The schematic diagrams, obviously, are not to scale and do not provide actual facility orientation on a platform. They do illustrate the main components of the production facility and show an approximate orientation between fields. A companion map, for each of the seven areas, locates the fields on the U.K. and Norway grid systems. Discoveries without published development plans are not included on the map.
To keep the diagrams simple, all of the flow and control lines running between facilities are not included. If several flow lines connect the same facilities, only one line is shown.
PIPELINES
To evacuate the new fields coming on stream, a number of new gas and oil pipelines have been installed or are being installed in both the U.K. and Norwegian waters.
OIL AND CONDENSATE
The 36-in. Brent/South Cormorant and 36-in. Ninian pipelines feed the Sullom Voe terminal. Each pipeline has a capacity of 1 million b/d. BP Exploration Operating Co. Ltd. operates the Ninian line while Shell UK Exploration & Production Ltd. is operator for the Brent/South Cormorant line. Both the Ninian and the South Cormorant lines were commissioned in 1978.
The oil from the Piper area moves through a 30-in. pipeline to Flotta, in the Orkney Isles. The pipeline operator is Elf Enterprises Caledonia Ltd. Designed line capacity is 500,000 b/d. The line was commissioned in 1976.
In 1992, a 36-in. line replaced the 32-in. Forties pipeline. The new line doubles the capacity to about 1 million b/d. BP Exploration Operating Co. Ltd. is the pipeline's operator. Tied into Forties are lines from the Brae, Buchan, and Montrose areas.
The remaining oil pipeline to the U.K. is the Norpipe, operated by Phillips Petroleum Co. Norway. The 34-in. line connects Ekofisk with Teesside, U.K., and has a capacity of about 700,000 b/d. The line was commissioned in 1975.
The 28-in. Oseberg Transportation System (OTS) transports oil from Oseberg to Sture, Norway. Norsk Hydro Produksjon AS is operator of the 700,000 b/d capacity line. The first oil arrived in Sture on Dec. 20, 1988.
Frostpipe, operated by Elf Petroleum Norge AS is an 18-in. line that will move liquids from Frigg to the Oseberg.
Start-up is planned for 1993. Line capacity is about 100,000 b/d.
Another pipeline moving liquids to Norway will be the Sleipner condensate line, also scheduled to be completed in 1993. Capacity of the Den norske stats oljeselska AS (Statoil) operated 20-in. line is about 200,000 b/d.
GAS AND NGL
The St. Fergus area is the main U.K. gas pipeline terminal for this sector of the North Sea. The five pipeline systems are Flags (Far North Liquids and Associated Gas System), Frigg, SAGE (Scottish Area Gas Evacuation), Miller, and Fulmar.
The 20-in., Shell-operated Flags gas and NGL line's first deliveries were in 1982 from the Brent field. Present inlet capacity is about 950 MMcfd.
Total Oil Marine U.K. operates the two 32-in. lines from Frigg to St. Fergus. The lines were put in service in August 1978. Line capacity is about 1.2 bcfd.
Initial deliveries on the SAGE line started in October 1992. This Mobil North Sea Ltd.-operated line transports rich gas from the Beryl and other fields. Initial deliveries were about 265 MMscfd (OGJ, Mar. 8). The gas in Beryl was previously reinjected, but now the field is in a blowdown stage.
Another recently installed line is the 30-in., BP-operated Miller pipeline installed in 1992.
The Fulmar line, operated by Shell, started up in 1986. The 20-in. line transports about 250 MMcfd.
Amoco U.K. Exploration Co.'s CATS pipeline went on stream in 1993. Capacity is about 1.4 bcfd for the 36-in. gas line from the Everest/Lomond area to Teesside, England.
The Statpipe system takes gas from fields in the north to Ekofisk where the gas enters the Norpipe line to Emden, Germany. Statoil is operator of Statpipe. The 18-in. and 36-in. pipeline system includes two riser platforms and the terminal at Karsto where gas liquids are separated. Operations started in 1981-D. The dry gas section between the riser platform in Block 16/11S and Ekofisk has a capacity of about 1.7 bcfd
Statoil's Zeepipe will connect the Sleipner field with Zeebrugge, Belgium. Plans are to put the 40-in. line in service in 1993. One leg of the line will also connect Sleipner with the Statpipe riser platform in Block 16/11S. Another leg of Zeepipe (not shown on the map) will connect Sleipner with the Troll field via Kollnes, Norway. Completion of this leg is expected in 1996. Zeepipe has a capacity of about 1.2 bcfd.
Europipe (not shown on the map) is a 40-in. line under construction. The line is being laid from the riser platform on Block 16/11S to Germany, largely paralleling the Statpipe/Norpipe line. The completion date of 1995 for the 1.2 bcfd capacity line will coincide with sales commitments of Troll gas. Statoil is the operator of Europipe.
The 36-in. Norpipe line from Ekofisk to Emden, Germany, started service in September 1977. Phillips is the operator of the 2 bcfd capacity line.
AREA 1
The release in late 1992 of the floating production vessel Deep Sea Pioneer, a converted semisubmersible, eliminated Hamilton Oil Co. Ltd.'s Argyll, Duncan, and Innes fields in block 30/4 from the schematic. The fields were abandoned earlier this year.
Argyll first produced on June 11, 1975. Argyll was also the first field to use a converted semisubmersible for production.
The Ekofisk area development includes seven fields. Not shown are four booster platforms on the pipeline to Teesside, England, and Emden, Germany. Phillips Petroleum Co. Norway operates Ekofisk.
The first oil discovered in Norway's sector of the North Sea was at Ekofisk in 1969.
In 1971, Ekofisk became the first North Sea field to produce commercial oil. The jack up Gulftide provided the initial production facilities for 18 months. The use of concrete for a platform and storage tank is another first at Ekofisk.
At present, field facilities are being modified to increase water injection and gas injection. A converted jack up drilling rig was installed for additional water injection capacity. Also, a new production platform is planned to increase safe operations.
Estimates are that Ekofisk will still be producing after the production license expires in 2011. Phillips plans to submit a proposal that is estimated to cost between $3-4 billion to change out the present facilities to allow production beyond the current production license term (OGJ, Aug. 30, 1993, p. 48).
Shell U.K. Ltd.-operated Auk field was the second oil field to start production in the U.K. from a fixed platform (December 1975). The field is nearing depletion, although recent facility upgrades and changing from tanker loading to a pipeline to Fulmar will extend the field's life.
In Shell's Fulmar field, a new turret loading system will allow for all-weather loading and eliminate the 1 need of a floating storage vessel (not shown on the schematic. The storage vessel is expected to be released in the fourth quarter of 1993.
Construction contracts for the Phillips-operated Judy and Joanne gas fields should be awarded in late 1993. Gas production from the two fields is expected to commence in 1996. The fields will be tied into the CATS pipeline.
AREA 2
The Forties facilities are expected to last at least until 2010 or about 35 years from the initial platform installation in June 1974. Production started in September 1975 from the BP Exploration Operating Co. Ltd.-operated field. About 25% of the estimated 2.5 billion bbl of recoverable oil remain to be produced, mostly by artificial lift with either gas lift or electric submersible pumps.
The collapse of oil prices in 1986 forced Shell to postpone the development of Kittiwake and Gannet fields until a lower cost design was completed.
Kittiwake was developed as a standalone facility using a slim-line jacket. Production started in 1990. Facility costs were reduced by installing the refurbished offshore loading terminal from the Auk field and reusing the accommodation modules originally intended for the Auk platform.
The revised development of the Gannet field includes minimum manning and facilities, single lift installation, and more subsea technology. Production started in October 1992.
The first phase of the Chevron U.K.-operated Alba field development includes a turret-moored floating storage vessel. A second phase development in the southern part of the reservoir will either have a second platform or use subsea technology.
The Nelson field is one of the largest oil fields recently discovered (OGJ, Aug. 30). Proved and probable reserves are about 480 million bbl of oil and 85 bcf of gas. Production is expected to start in early 1994. Shell was operator through the field's development stage while Enterprise Oil plc will become the operator during for the production stage.
Two horizontal wells produce the Cyrus field operated by BP. Production started in April 1990 through the production vessel Seillean, a 42,000 dwt tanker. In 1992, the vessel moved to test the Donan subsea well in Block 15/20.
Amoco U.K. Exploration Inc.-operated Arbroath field is produced through an unmanned minimum facility tied into the Montrose field. Arbroath, discovered in 1969, went on production only in 1990,
Sales contracts commit about 300 MMscfd of gas from the Everest and Lomond fields to the Teesside electric generation plant (OGJ, June 7). Gas will be transported through the recently completed CATS line.
AREA 3
The Piper B platform replaces the original Piper field platform that was destroyed by an explosion in 1988. Oil production from Piper B started in February 1993. Also, the satellite fields Saltire and Chanter went on stream in early 1993.
(in Statoil-operated Sleipner East field, the replacement platform was installed on June 16. This platform replaced the concrete gravity base that sank in August 1991 during trials. Two subsea wells went on stream in August.
The East Brae field production is forecast to start in December 1993. North Brae gas will be injected into East Brae while plans are to start sales of East Brae gas to the SAGE system in October 1994. Marathon Oil U.K. operates all four of the Brae fields. The fields produce condensate.
BP's Miller field started producing in June 1992. Water injection was also commenced.
When the Balmoral field started producing in 1986, some of the firsts for Sun Oil Britain Ltd.'s project included:
- A purpose-built floating semisubmersible production vessel
- A combination of working drilling derrick and flare tower
- The deployment of a glycol dehydration system on a floating vessel
- Large scale application of remotely controlled subsea chokes for production and gas lift
- The North Sea's first gravel pack in highly deviated (more than 60) wells.
The Amerada Hess Ltd.-operated Scott field is one of larger oil fields to come on stream in the U.K. North Sea in the last decade (OGJ, Aug. 30, p. 68). It should reach a plateau of about 180,000 b/d. Estimated reserves are 450 million bbl of oil and 287 bcf of gas.
AREA 4
As gas production declined on Elf Petroleum Norge A/S's operated Frigg field, a number of satellite fields have been brought on stream to fill the extra capacity. Frigg started production in 1977 and since 1987 has had a production decline from the plateau rate that started in 1979. Production is likely to end in 1997.
Esso Norge AS's Odin is another field that is likely to cease production by 1997. At the end of 1992, about 90% of the estimated 1 tcf of recoverable gas had been produced. A floating utility vessel serves to supply the simple production platform with utilities.
Mobil Oil North Sea Ltd. started oil production from the Beryl field in 1976. To increase oil recovery, gas was reinjected. Now with the completion of the SAGE pipeline to St. Fergus, gas sales commenced in October 1992.
The Tentech 850C floating, production, storage, and offloading vessel Gryphon Alpha will serve Kerr-McGee's Gryphon field. Production is expected to start this month.
BP's Bruce is another field that should commence production in October. Bruce is the largest gas field in the U.K. sector currently under development. Reserves are estimated at 2.6 tcf and 220 million bbl of liquids.
AREA 5
The Ninian platform, Chevron operated, is an older platform that ties in a number of smaller fields. Ninian started producing in 1978. The facilities have recently been up-graded to conform with new North Sea safety requirements and to allow other fields to use the production facilities.
The first three fields to take advantage of this availability are three subsea developments: Lasmo's Staffa, Conoco's Lyell, and Texaco North Sea U.K.'s Strathspey.
Staffa came on production in 1992 and Lyell in April 1993. Production from Strathspey should commence in this month.
The subsea wells on Sovereign's Emerald field are tied back to the converted the semisubmersible Alibaba, now named Emerald Producer. Oil is exported by shuttle tankers from a floating storage vessel. Production started in late 1990.
AREA 6
To improve oil recovery, gas from wells on a subsea template in the Troll field (TOGI project) is injected in the Oseberg field, operated by Norsk Hydro. Production from the first phase of the project, Platform A, began in 1988. The second phase, Platform C, was on stream in 1991. The estimated 1993 production is 450,000 bo/d.
Statoil-operated Veslefrikk field has a wellhead platform bridge-linked to the processing and accommodations areas located on the converted semisubmersible West Vision. Production started in 1990 and is currently about 65,000 bo/d.
The Barge field production is expected to commence in 1994 at a rate of about 85,000 bo/d. Norsk Hydro operates the field. The associated gas from Barge will act as an extra guarantee for Troll gas contracts. The.gas will be transported to Ekofisk for storage. Also for 2 years, starting October 1994, Troll will buy about one half of the Barge gas. The Ekofisk storage is planned to end in the fall of 1996.
The Troll field is being developed in several phases. Norsk Hydro is proceeding with developing the Troll oil leg in the west part of the field with subsea completions. Shell is operator for the development of Troll East gas that will have a Condeep SP4 platform. Both projects are expected to start production in 1996. A third phase, Troll West Gas, is also being considered and may commence production in 2005. Estimated recoverable reserves are about 46 tcf and 400 million bbl of oil. Production during Phase I is expected to be 20 bcfd.
AREA 7
Area 7 contains most of the large gravity-base platforms in the North Sea. These are located on the Gullfaks, Statfjord, Brent, Dunlin, and South Cormorant fields. Also, two of the North Sea's tension leg platforms are in this area: Snorre and Hutton.
Although Statoil-operated Statfjord field has been producing since November 1979 production has recently increased because of extended reach and horizontal drilling. The upgrade program has added about 500 million bbl to recoverable reserves and increased production to over 700,000 bo/d. Production from two subsea satellite fields, Statfjord North and East, is planned for 1994.
Production from Statoil's Gullfaks field started in 1987. The field produces about 400 bo/d. Horizonal wells from Gullfaks and subsea developments, such as Tordis, be used to develop a number of small prospects in the area.
The oil price of Shell's Brent field is used as the base North Sea crude price, although Brent is no longer the main oil producing field in the North Sea. Brent production is now less than half of the peak production of 416,000 bo/d in 1985-86.
To recover more oil and gas, the gas processing modules on three of the platforms will be replaced with ones that operate at lower pressures (OGJ, Aug. 30, p. 48). The $1.95 billion refurbishment over 5 years will make gas the more important production stream from Brent and extend the field's life another 10 years to about 2008.
Shell's Dunlin is another old platform (production started in 1978) that is being used to produce satellite fields. Shell's Osprey subsea development has a processing module on the Dunlin platform and the water for injection is supplied from the Dunlin field. Production from Osprey started in 1991.
BP's Don field was tied into the production facilities of the Thistle field in 1989.
The production from the Thistle field, also operated by BP, started in February 1978 and has declined to about 30,000 bo/d from a peak of 139,000 in 1982.
The Magnus field, operated by BP, has been in production since August 1983.
Shell's Eider platform is an unmanned platform that began producing in November 1988. Water injection began in 1989.
Production from Tern, also operated by Shell, commenced June 1989 with gas lift starting in September 1989 and water injection in February 1990.
Shell's South Cormorant platform has been producing since 1979. North Cormorant was brought on in 1982 and Central Cormorant in 1983. Water is injected in all three fields.
Conoco's Hutton was the first tension leg platform. Production from it started in August 1984. The pipelines from Hutton are tied into Amoco's Northwest Hutton platform that started producing in April 1983.
The Hudson field, operated by Amerada Hess, went on stream July 19 using the production vessel Petrojarl I. In 1994, the subsea wells will be tied back to the Tern platform.
Production from Saga Petroleum AS's Snorre tension leg platform commenced in August 1992.
Estimated reserves are about 750 million bbl of oil and 250 bcf of gas. Peak production in 1994 is expected to be 190,000 bo/d.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.
