David Knott
Senior Editor
Northwest Europe's offshore oil activity was troubled no more than usual by the region's turbulent weather this year.
However, public protest over a plan to dump an idle North Sea loading buoy hit operators like a hurricane.
Shell U.K, Exploration & Production was at the eye of the storm. It found itself under fire from an angry British government and even angrier antidumping campaigners across Europe.
At the center of the protest was Shell Expro's Brent spar loading buoy, boarded by members of environmental campaign group Greenpeace and held under siege for almost a month.
While other operators combed the wreckage of the Brent spar dumping plan for lessons for their own field abandonments, they ushered in the mature years of North Sea production by installing the last giant platforms.
While Europe's operators may one day look back on those giants and say "those were the days," they completed other smaller developments likely to typify the region's future projects.
Exploration has noticeably passed its peak off Northwest Europe, but Norway and U.K. continued to probe new plays. Ireland experienced a renaissance, and Denmark saw the first fruits of a more open licensing policy.
"GREEN" INVASION
Last March, Shell Expro, the operating joint venture of Shell U.K. Ltd. and Esso Exploration & Production U.K. Ltd., revealed a plan to dump the unused Brent spar loading buoy in deep water off Northwest Britain (OGJ, Mar. 20, p. 32).
U.K. Energy Minister Tim Eggar gave tile plan his seal of approval, having told operators that keeping down government's share of costs for abandonments-and therefore costs to tax- payers-was a priority.
Shell Expro's arguments in favor of dumping may have persuaded government, but Greenpeace mounted the most unusual offshore operation of the year by seizing control of the buoy,.
About noon Apr. 30, a flotilla of Greenpeace boats sailed to the spar, and a group of activists climbed up the structure's steel ladders. When the ladders ran out, Greenpeace protesters completed their journey to the top of the buoy using ropes and winches.
Greenpeace justified the action by saying it was concerned over toxic and radioactive waste remaining in the spar and claimed that Shell's inventory was likely to be a gross underestimate.
Later, Shell's account of the spar's contents proved more accurate (OGJ, Oct. 30, p. 17). In early May, however, protesters on the spar settled down for a long stay.
Like any platform operator, Green-peace organized crew changes and visits of supply boats and envisaged dragging out the protest until rough weather set in for the winter.
Shell Expro had other ideas. It entered a few minor skirmishes, with supply vessels pitted against Green-peace's boats and small craft, and with support ships regularly turning fire hoses on the buoy.
Shell Expro also chartered the Stadive construction semisubmersible from Rockwater Ltd., Aberdeen, to recover control of the buoy. Before dawn on May 22, Stadive was moved alongside the buoy with a basket rigged up on the end of a crane for removal of protesters.
In a rare break for bad weather during this season, Stadive had to pull away from the spar in high seas. But the seas soon subsided, allowing Shell, Rockwater, and Grampian police offi- cials to swarm the buoy and seize control of the Greenpeace activists.
By the evening of May 23 the offshore protest was effectively over, and Stadive cleared out everything that could be removed from the spar. After about 3 weeks Shell began to tow the buoy around the north of Britain toward the dump site.
By now, however, the protest campaign had gained momentum. European governments voiced strong objections to the dumping plan, and activists in Netherlands and Germany organized boycotts of Shell service stations.
In late June, the buoy was within 50 miles of the dump site when Shell aborted the dumping plan to the relief of Greenpeace and dismay of the British government.
Shell's about-face gave the British government what is likely to be its cheapest contribution to an abandonment. Immediately after the Shell announcement, Eggar declared the government would pay no more toward onshore dismantlement than it had intended toward dumping. Shell later dropped its claim for tax rebates, making government's contribution zero.
Brent spar then began a slow journey back around tile northern coast of Britain. Shell sought a mooring while it decided the future of the structure.
Britain has no port deep enough to accommodate the 300 ft high spar, which eventually found a temporary resting place at Erfjord, Norway, near Stavanger, where it is likely to stay until an alternative disposal plan is sanctioned.
While U.K. operators were stunned by the Greenpeace campaign while it was taking place, their thinking once the spotlight was off the industry suggested there may be similar show-downs to come.
In September, U.K. Offshore Operators Association (Ukooa) decided the protest campaign had occurred partly because the industry had not communicated its technical message successfully in the face of an emotional public response. So Ukooa appointed a public relations agency to solve the problem.
Meanwhile, three huge production units were being installed off Norway, representing what most likely will be the last giant North Sea platforms.
While Shell Expro was facing an unprecedented challenge with its Brent spar disposal, operators of two of the giant platforms were facing technical challenges in the final stages of their developments.
HEIDRUN TLP
Heidrun field in Block 6507/7 off Norway was developed using a tension leg platform (TLP) with produced oil loaded directly into one of three shuttle tankers.
In early May, development operator Conoco Norway Inc. hit a problem. The second of 16 tethers for the TLP was dropped by the contractor as it was being towed.
Straps holding the buoys that supported a 270 m steel tether broke during the move. The tether had to be laid on the seabed for later recovery.
However, Conoco was prepared with a spare tether already built. This enabled installation to continue without further bitches, and the dropped tether was recovered for inspection.
The field originally was due on stream in August, but Conoco then had difficulties completing a production well.
First oil was produced from Heidrun field in the Norwegian Sea Oct. 18. Norway's state owned Den norske stats oljeseiskap AS became operator of the field upon start-up.
One production well and six water injectors were completed before the field went on stream. Statoil plans to place further wells on production to build output to 220,000 b/d of oil next March.
Heidrun is expected to yield 3.8 million bbl of oil this year and 69 million bbl in 1996. Plateau production is to be 73 million bbl/year from estimated reserves of 840 million bbl of oil.
Heidrun associated gas is to be delivered to a methanol plant under construction by Statoil and Heidrun development operator Conoco Norway Inc. and due to begin operation in late 1996 or early 1997.
TROLL PROJECT
Troll oil project operator Norsk Hydro AS also suffered a setback early in June, when a mechanical failure of the tensioner aboard the Castoro 6 lay barge caused a section of the Troll oil export pipeline to drop.
The barge was then about 1 km from shore, having drawn the pipeline section through a landfall tunnel. The line had to be cut near the landfall and retrieved before laying could resume.
However, the incident did not significantly delay Troll's oil production schedule. In early July, the Troll B platform, the world's largest concrete semi-submersible production unit, was towed out to its position in the field in Block 31/2.
In mid-September Hydro began production of Troll oil from the first of eight predrilled wells intended to take early production to almost 190,000 b/d in 3 days. A total of 22 oil producers and gas injection wells will be used for this development.
Oil reserves in West Troll's oil province are estimated at 420 million bbl. At midyear Hydro announced a plan to develop a thin oil layer in West Troll's gas province, which effectively doubled the field's oil reserves.
This plan to deplete a 13 m thick oil zone below Troll's giant gas cap is estimated to raise West Troll's oil reserves to more than 1 billion bbl of oil.
Meanwhile, Norske Shell AS is working to bring East Troll gas reserves on stream by means of the world's tallest production platform, Troll A. East Troll reserves are estimated at 45 tcf of gas.
Troll's A platform was installed before Troll B, in mid-May. This four-legged concrete platform was billed as the largest object ever moved, standing 430 m tall and weighing 1.05 million metric tons.
In June, Troll A operator Norske Shell AS began a program to drill 40 development wells from the platform. Drilling is slated for completion by the end of 1997, and first gas is due Apr. 1, 1996.
BRITANNIA
A current development that carries echoes of the old style of large scale projects is Britannia, the largest undeveloped gas discovery in the U.K. It is under development by Britannia Oper- ator Ltd. (BOL), a joint venture of Chevron U.K. Ltd. and Conoco (U.K.) Ltd.
The emphasis on cost cutting during the development shows Britannia is very much a "new age" North Sea project. Britannia holds estimated reserves of 2.6 tcf of gas and 140 million bbl of condensate. The venture is working on a 1.5 billion development based around a steel platform in Block 16/26.
Britannia platform will be able to produce 740 MMcfd of gas and 60,000 b/d of condensate. Eighteen wells are being drilled in preparation for first gas, due October 1998 (OGJ, Dec. 26, 1994, p. 30).
Forty-five wells are believed necessary to deplete the reservoir, said Alan Leiper, project drilling superintendent. One third of the wells will be drilled in the field's subsea center.
Throughout much of this year BOL has had two rigs in the field, working on predrilled wells. Sedco 711 is drilling at the platform site, while the Sovereign Explorer is drilling at the subsea center 15 km away. They will remain in Britannia until first quarter 1997.
Earlier, BOL installed a template at the platform site to guide drilling of nine of the predrilled wells. This template also allows the blowout preventer (BOP) stack to remain on the template and to be latched onto each well in turn. This saves time compared with the traditional technique of lowering the BOP stack for each well and retrieving it when the well is complete.
Fields Placed On Stream Off Northwest Europe During 1995 Table (51463 bytes)
MORE DEVELOPMENTS
Much smaller in scale, although more likely than concrete giants to represent the future for North Sea operators, is a string of smaller developments for which most offshore activity took place this year.
Last May 16 Elf Petroleum Norge AS began production from Froey field in Norway's North Sea Block 25/2. Froey holds estimated reserves of 110 million bbl of oil and 106 bcf of gas.
A 5.7 billion kroner ($870 million) development involved installation of a wellhead platform tied into existing processing and export systems in Elf's Frigg field.
An oil processing module was installed on the Frigg TCP2 platform to treat Froey production. This was the first oil treated in the Frigg complex. Oil is exported to Norway's Sture terminal, while gas is sent to St. Fergus, Scotland.
Statoil's Yme field was expected to go on stream by September, but the company announced it had delayed start-up because of delays in converting the field's jack up rig for production.
Yme, in Norwegian North Sea Block 9/2, is now expected to produce first oil in mid-November. The Maersk Giant jack up finished drilling a water injection well in the field in April and was sent to the Verolme Botlek yard in Netherlands for installation of production and water inject!on units.
Maersk Giant is under contract for duration of development, expected to be about 4 years. The rig will send processed oil to be stored in the Poly-saga tanker prior to offloading into shuttle tankers.
Yme reserves are estimated at 36 million bbl of oil. An 11 million bbl satellite reservoir, Beta East, was discovered this year and earmarked for development.
Statoil envisages developing the new find, Yme Beta East reservoir, using two wells tied back to the Maersk Giant via a subsea template over Beta East, with first oil slated for May 1996. Statoil has identified three other prospects in the Yme area, which it views as candidates for satellite development.
U.K. FLURRY
U.K. operators completed a wave of subsea and minimum facilities projects, demonstrating the growing trend to make best use of existing infrastructure.
Lasmo North Sea plc, London, placed U.K. North Sea Birch field on stream Sept. 15 as a subsea satellite of South Brae field.
Birch fluids move by pipeline 14 km to Brae platform, operated by Marathon Oil U.K. Ltd., for processing. Crude oil and natural gas liquids are then exported through the Brae and Forties pipelines to Kinneil terminal. Gas is sold to the Brae license group and enters the Scottish Area Gas Evacuation (SAGE) export pipeline from Brae to St. Fergus.
Block 16/12a Birch holds estimated reserves of 47 million bbl of oil equivalent and is intended to produce 23,000 b/d of oil and 60 MMcfd of gas.
In late September ARCO British Ltd. announced first production from Gawain field in the U.K. North Sea southern gas basin. The field, in Blocks 49/24 and 49/29a, has estimated reserves of 130-190 bcf. Early production is at a rate of 75 MMcfd, with peak flow expected to be 112 MMcfd.
Amerada Hess Ltd. produced first oil from South Scott field Oct. 2. TILe field lies in Blocks 15/2la and 15/22 and holds estimated reserves of 60 million bbl of oil. It was placed on stream using one subsea well tied back to Scott platform 4 1/2 km away on Block 15/21a.
Conoco (U.K.) Ltd. produced first gas from Ganymede and Callisto fields Oct 1.
Ganymede development involved an unmanned wellhead platform on Block 49/22 handling gas from five wells. Ganymede reserves are estimated at 250 bcf of gas. Callisto field was developed as a single well subsea tie-back to Ganymede platform 13 km away. Callisto lies on Block 49/22 and is estimated to hold 70 bcf of gas.
Gas from Ganymede and Callisto moves through a 20 km, 18 in. pipeline to join the Lincolnshire Offshore Gas Gathering System (Loggs), which transports gas ashore at Theddlethorpe terminal.
Combined production from Ganymede and Callisto is expected to average 300 MMcfd. Development cost for the two fields was 120 million ($190 million).
Conoco also began gas production from the Kx reservoir Oct 8. Kx, in Block 49/16, is one of two reservoirs known officially as Alison field, although the main reservoir in Block 49/11a was developed by operator Phillips Petroleum Co. U.K. Ltd.
Phillips and Conoco developed Alison and Kx using a three slot subsea manifold, with Phillips' field going on stream first on Oct. 4. Alison and Kx were connected to export infrastructure via a subsea tee installed earlier by Phillips during development of nearby Ann field.
Alison is expected to produce 400 MMcfd of gas. The Alison production well is the first trilateral well in the U.K. North Sea. Development cost was 22 million ($35 million).
The Kx reservoir holds estimated reserves of 30 bcf of gas, which makes it Conoco's smallest development in the North Sea. Kx production is expected to average 20 MMcfd
FIRST MONOTOWERS
Amoco (U.K.) Exploration Co. started production from two southern North Sea gas fields developed using a minimum facilities platform design that may be copied for other projects.
The platforms in Block 49/30a Davy field and Block 49/23e Bessemer are the first monotower units installed in the U.K. North Sea. Development cost for the two fields was 84 million ($130 million).
Davy and Bessemer went on stream Oct. 1. The fields are expected to produce a combined 220 MMcfd, with production sent through two pipelines to Amoco's Indefatigable platform on Block 49/23a.
Amoco plans to use the same platform design on three other prospects in the same area, due to be drilled this year. These are North Indefatigable, West Davy, and Bell (OGJ, Mar. 27, p. 30).
Mobil North Sea Ltd, began production Nov. 1 from Galahad gas field in U.K, North Sea Blocks 48/12a and 48/13b. Mobil developed Galahad using Amoco's monotower concept. Galahad reserves are estimated at 153 bcf of gas, and production is expected to reach a peak of 120 MMcfd.
NORWAY'S NEW PLAYS
While developed areas off Northwest Europe enter maturity, work has been gathering momentum in new plays.
The Norwegian Sea off mid-Nor-way is growing as an oil producing region, and government approval of development of the Aasgard gas discoveries could turn the area into a major gas play (OGJ, Oct. 9, p. 29).
Development of Aasgard, made up of the Midgard, Smoerbukk, and South Smoerbukk discoveries, is the key to tapping gas reserves of the Norwegian Sea.
So far, Statoil and development partner Saga Petroleum AS have decided that a production ship will be the best means to produce Aasgard oil, but the decision on whether to use a pro- duction semisubmersible or a fixed platform for Aasgard's gas production has yet to be made.
Statoil reported recently that the most noteworthy discovery of the year so far off Norway has been Saga's Block 6406/2 strike south of Aasgard.
Saga spudded the 6406/2-1 wildcat Oct. 31, 1994, but had to suspend operations because of environmental restrictions in the license that forbid drilling during April-June.
Saga reentered the hole Aug. 20 using the Ross Isle semisubmersible rig. On Sept. 21, Saga announced the well had reached a vertical depth of 5,768 m, making it the deepest well by 226 m drilled in the Norwegian Sea. Now, Saga plans to log and conduct extended tests.
Saga hopes reserves may be shown to be about 200 billion cum of gas and 70 million cum of condensate. Testing is expected to be finished by the end of November.
In late September, Esso Norge AS disclosed another oil strike in Block 25/8 off Norway in the vicinity of its Balder discovery which is being evaluated for development. The 25/8-8S strike was said by license partner Enterprise Oil plc, London, to have found hydrocarbons in Paleocene sediments.
The well was drilled to 2,343 m in Jurassic sands. Enterprise said the well flowed 6,700 b/d of oil and 2.7 MMcfd of gas through a 2 in. choke. Last year, Enterprise achieved similar flow rates at a nearby discovery (OGJ, Oct. 3, 1994, p. 30). Esso is preparing to further evaluate the new discovery with a side- track to the south.
In September, Conoco disclosed it had found oil in Block 25/7 in the Norwegian North Sea with its 25/7-2 wildcat. Norwegian Petroleum Directorate (NPD) said the well was drilled to 2,571 m vertical depth by the Deepsea Bergen semisubmersible operating in 125 m of water.
Conoco tested a pay zone in Paleocene sandstone. The well flowed 740 cu m/day of oil and 29,000 cu m/day of gas through a 25 mm choke. NPD said the discovery may be part of a reservoir found earlier by Conoco with its 25/8-5S well.
WEST OF SHETLAND
Britain's West of Shetland hotspot has dominated U.K. exploration activity, with most of the work carried out by BP Exploration Operating Co. Ltd. to appraise its Foinaven and Schiehallion fields. Other operators drilling in the play were Amoco, Texaco Ltd., Conoco, and Amerada Hess.
Wells in the region have been designated tight holes, but the lack of public announcements suggests some of the heat may have been taken out of the play for now.
Meanwhile, BP has been pressing development of Foinaven in Block 204/20a. The hull of the Petrojarl Foinaven production ship, a rebuilt support vessel, has taken shape. A top-sides able to produce 95,000 b/d will be added during the winter to the hull, which can store 300,000 bbl of oil for shuttle tanker export.
The ship is expected in the field in spring 1996, but BP is racing to complete subsea installations by the end of this year's weather window.
Three production wells, each expected to produce 15,000- 20,000 b/d, have been completed in readiness for first production in spring 1996. The Norlift reel barge has laid 11 flow lines on the seabed, and the Flex Installer reel barge has laid the flexible risers.
IRISH REVIVAL
The Irish Sea and the Atlantic Ocean west of ireland have been unusually busy this year, with U.K. operators completing one development and carrying out further drilling and operators returning to Ireland for the first time in years.
In early September, BHP Petroleum Ltd. finished installation of Liverpool Bay development platforms in U.K. Irish Sea Block 110/13. The DB102 heavy lift barge placed a 9,100 metric ton deck on the jacket of the Douglas field central processing platform.
Four fields will send oil and gas to this platform, with oil processed prior to tanker storage for offshore loading and gas sent by pipeline to Point of Ayr terminal in North Wales to feed a power plant (OGJ, Aug. 28, p. 60).
In September, Statoil U.K. Ltd. announced completion of acquisition of 2,500 line km of seismic data in the Erris Slyne basin, 70 km northwest of Ireland. Statoil operates Block 5/94, one of a number awarded in March 1994 in what is said to be an underexplored Mesozoic sedimentary basin. The Geco Rho seismic ship collected the data and is due to acquire further 2D data for Statoil in the Porcupine basin, also recently reopened for explo- ration.
NETHERLANDS, DENMARK
Dutch and Danish activity levels were again relatively quiet this year, although one small field was brought into production by Elf Petroland in tile Netherlands, and Denmark saw drilling by companies attracted by new licensing terms announced last year.
Nederlandse Aardolie Mij. BV (NAM), the Shell-Esso joint venture for Netherlands, announced plans to explore the northern extent of its Groningen license in a shallow water area.
Western Geophysical Corp., London, carried out the survey on behalf of NAM, using a small fleet of vessels to lay out receivers and sources in a shah low water survey rarely seen in the North Sea.
The survey was conducted just to the north of a string of islands separating the North Sea from the inshore Waddenzee area, an environmentally sensitive region where NAM is working on an exploration proposal.
Elf Petroland was the only other operator with plans to drill in the Waddenzee. It pulled out this year because of limited prospects and the high cost of meeting environmental requirements for drilling.
Elf also secured an unusual agreement for the North Sea, in which it drilled an extended reach well from the Markham J6-A platform in the Dutch sector, operated by Lasmo.
A discovery in Block J3a was the result of the well. J3 Charlie field, as it was called, is expected to be tied back to Markham for processing of gas and export of production to shore. Elf hopes to secure a license to begin production by yearend.
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