Tiebacks boost efficiency

2001 has been a year of satellite success stories in the North Sea.

A raft of new projects has come forward to the development stage - many either incremental, stepout or so-called satellite tie-ins - that offer rewards for operators and contractors able to make otherwise stranded reserves pay their way while the prices of oil and gas are relatively high.
Common to many of these projects has been the desire on the part of asset owners to make the most money out of infrastructure already in place.
Since January, the list includes: Angus, Blane, Blake, Beuly, Don, Don West, Enoch, Ettrick, Halley, Hamilton East, Kestrel, Little Dotty, Nevis South, North Davy, Parliament, Perth and Penguins, to name but 17.
One of the best examples of operators' determination to make the maximum use of existing infrastructure has been Conoco's decision to move ahead with up to seven satellites designated Caister-Murdoch (CMS) Phase III. The plan involves tapping a number of gas pockets in the Southern Gas Basin in the North Sea and tying them via subsea wells and flow lines into the Caister-Murdoch platforms. Two new facilities, a compression platform and a new accommodation platform, are necessary to make the scheme a reality, and bidding for these facilities was launched earlier this year. It was one of the few jobs the dwindling UK offshore fabrication industry was able to compete for.
Similarly, Shell has identified several prospects it wants to tie into its own platforms in stages. One will tap the Penguins accumulations in the northern North Sea.
A year ago Shell unveiled plans to invest US $1.2 billion (£800 million) in the North Sea, and Goosander and Penguins were mentioned then as part of those plans. Another major player, Talisman Energy, is making the most of the assets it has bought into, permitting BG Group to develop its Blake field via subsea wells tied back to the Talisman-operated Ross floating production, storage and offloading vessel (FPSO) Bleo Holm.
For Conoco, the CMS III project is its biggest investment priority in the UK sector. Potential recoverable reserves are worth up to 500 MMcf/d of gas production, and the K prospect, discovered earlier this year, is thought to contain about 80 Bcf of reserves.
The K prospect is undergoing an approval process by Conoco and its partners. First gas from the field is expected in the fourth quarter of 2002, if approved.
"It has been a slow business getting agreement to drill the well," area manager Ayers Kyle said, "due to all of the original partners exiting during the last 18 months. But now we have reserves confirmed, the development will press ahead for first gas in 2002."
The success of the K well bolsters the economics of the CMS III project. Caister-Murdoch infrastructure straddles blocks 44/22a and 23a, and K has helped boost the chances of unlocking additional prospects in the area.
CMS III is in Conoco's quadrant 44 area and comprises Errol, McAdam, H, K, Q, Hunter and Rita. Plans envisage subsea wellheads installed on each of the five reservoirs tied back to the Murdoch platform and CMS export system. A compression module will be fitted to the existing Murdoch platform, with a new accommodation platform alongside. Engineering, procurement, installation and construction bids were due to Conoco in the early summer for the provision of field facilities.
The K discovery was the third success for Conoco in the North Sea in 4 months. In December 2000, it confirmed two finds in the Central North Sea: Kappa (oil) in Block 15/29b and its extension into Block 21/4a, 16 miles (26 km) from the joint Conoco- and Chevron-operated Britannia field. Conoco's second, unnamed find last year was in Block 21/3a-7, also close to Britannia.
"The UK southern North Sea has been important to Conoco for more than 30 years," said Dr. George Watkins, chairman and managing director of Conoco UK. "We've been exploring there since the 1960s, and producing natural gas nonstop since 1972. The latest success reaffirms to province's status as a core business area for Conoco."
Steve Whiteside, Conoco UK's southern North Sea subsurface manager, said K is a cornerstone for CMS III. "We are delighted by its success. It's our first discovery in 2001 for Conoco UK, and it kicks off what we hope to be a very successful exploration program," he said. "It is important because we have a strategy to grow our southern North Sea business, and the K discovery and CMS III are integral to that."
With extensive infrastructure in the North Sea, it was logical that Shell would want to use its own facilities to tap its prospects. This is the case with the five-field Penguins cluster.
These fields have been on the backburner with Shell Expro in the United Kingdom but are set to become a tieback to the Brent Charlie platform.
Shell's new plan for the project entails developing four of the five Penguin constituents with up to nine wells if plans with the UK Department of Trade and Industry are approved. Daly production is forecast at up to 3,650 b/d of oil.
But it will be pushing the boundaries of tieback technology by linking Penguins to Brent C, about 43 miles (70 km) away. Penguins is on the northernmost edge of the UK Continental Shelf, in blocks 211/13a and 211/14. Selection of a semisubmersible rig to drill the new wells is under way, and first work on the three-phase project is due to begin later this year.
Further opportunity lies in the provision of a 16-in. subsea pipeline inside a 22-in., 42-mile (67-km) casing that will connect the five Penguin well centers with Brent C, and the installation of an electrohydraulic umbilical to provide power, control and chemical injection to the Penguins reservoirs.
Interfield pipelines connecting the Penguin drill centers will comprise 10-in. within 16-in. lines. Shell Expro is indicating plans for a further 4-in. or 8-in. gas injection line from Brent C to the drilling centers, which may be required in the period 2004 to 2005 with further topsides modifications.
From Brent C, Penguins oil will be exported to the Flotta terminal on Orkney, and gas will go via the Far North Liquids and Associated Gas Gathering System to the St. Fergus terminal.
Three prospects within the cluster - A, C and D - contain oil, with large amounts of associated gas, and the other two contain gas and condensate.
Plans for Chevron's 10 million-bbl Parliament oil prospect are being brought forward with a target first oil date by the third quarter of 2002.
With the completion of a front-end engineering and design (FEED) study by Kværner this quarter, Chevron is aiming for project sanction soon.
If the field passes all the other hurdles it still has to jump - including internal and partner approval - government sanction is to be sought for the fourth quarter, and the operator aims to begin development drilling by the second quarter of 2002.
Although Parliament is estimated to contain 10 million bbl of oil, the range is between 5 million and 20 million bbl, or 35 million to 70 million bbl of oil initially in place. The plan involves drilling a single development well, 16/26-25, targeting an area of known reservoir quality.
Thereafter it would be tied back to Alba or Britannia, in the heart of Chevron's UK Continental Shelf asset base. Chevron favors Alba - it holds a bigger stake there. It has only 50% of Britannia, which is half-owned by Conoco.
A lot of work has been done on the field since June 2000. "A year ago we were talking about a full field development, which had a 40% chance of losing money, (and) nobody wanted to know," said Chris Cox, business development manager for Chevron in the UK.
Since then, the company has succeeded in eliminating 75% of the reservoir risk by re-examining data with particular reference to aquifer support for production wells. This work concluded there was a 75% chance of having aquifer support for the project, avoiding the need for water injection.
If the project becomes reality, it could produce up to 20,000 b/d of oil, Cox said.
Parliament represents a first for Chevron because it is probably the smallest field it has ever tackled in the United Kingdom. Management apathy toward the prospect was the only way to describe it, Cox said, and it was an uphill battle to persuade senior management to consider it. "They didn't want to hear about Parliament."
Tariff negotiations over an export route are well advanced. A pipeline export route selection should have been selected by now, and Cox's "gut feeling" is that the project will go ahead. And he promised similar schemes will follow. "We have a number of bumps on the map that look a lot like Parliament that we have not drilled yet," Cox said at a conference earlier this year. "They are pretty low-risk and similar in size to Parliament.
"As soon as we have done this, we have two or three others that are right behind it that are ready to go."
Financing Parliament is one of the remaining hurdles. Another is what type of contracting strategy to adopt. A third is obtaining all the necessary regulatory approvals. Despite these factors, Parliament has a lot more certainty than it did a year ago.
For Ranger Oil - taken over by Canadian Natural Resources in April - the Kyle oil field represented a major investment that also saw Shell Expro's Mærsk Curlew FPSO being used as the tieback facility. Kyle came onstream in April at an initial rate of 16,000 b/d of oil. Two wells are producing the field initially at a stabilized rate of 22,500 b/d of oil and 18.5MMcf/d of gas. But the field partners want to tap an even bigger flow from the field and have agreed on a third development well, drilling of which was due to begin in June.
This new well is to be drilled horizontally to target a Paleocene sand horizon overlying the existing producing zone, Ekofisk Chalk.
Bow Valley Energy, which holds a 12.5% stake in the field, said this Ekofisk Chalk tested at up 4,549 b/d of oil with the 29/2c-11z appraisal well drilled in 1994. "A successful well would be tied in shortly after completion with production commencing by the beginning of the fourth quarter," Bow Valley said. Furthermore, the Canadian independent indicated Kyle reserves had increased by a third its end-of- year reserves statement due to the successful drilling of a second appraisal well, 29/2c-13, in October 2000, and completion of a 160-day extended well test on the 29/2c-12z well, which used the Petrojarl I floating production vessel. This test resulted in the production of 1.5 million bbl of oil and 1.7 Bcf of gas during 2000.
BG's development of the Blake field with the Talisman Energy-operated Ross FPSO is another example of a UK FPSO being used as a production platform for another field. While Blake is a separate and distinct field from Ross, it was determined the Ross FPSO Bleo Holm could provide a production platform for both fields. Ross production is in decline, and Blake could not have come at a better time for Talisman, allowing the company to make maximum use of its facility.
Ross came onstream in April 1999 in Block 13/28a with reserves originally estimated at 54 million bbl. Production from Ross in its peak year, also 1999, was 8.69 million bbl - meaning the field was heading for depletion by 2005 had the Bleo Holm not been offered. Ross production is about 25,000 b/d, and the design for Blake is for 40,000 b/d of oil production. "We expect the production level to be around 100,000 b/d from both fields," said Ruud Zoon, vice president for floating production at Bluewater, which leases the Bleo Holm to Talisman Energy. The two fields are expected to stay in production until 2010.
The Bleo Holm is one of three units operating for Bluewater. The others are the Uisge Gorm, which is working for Amerada Hess, and the Glas Dowr, also leased by Hess but due to relocate to South Africa.
Extensive modification was necessary before Bleo Holm could start taking production from Blake (Table 1). The ship was removed from the Ross field after the production risers and anchors were pulled in the early summer, and the ship underwent an intensive 42-day refit - a schedule set by Bluewater - at Aker McNulty as part of an EPIC contract won by Coflexip Stena in 2000.
A restart to Ross - and Blake first production - was due by late June.
Three new modules have been installed on the ship to increase its liquid-handling capacities.
The field is in a water depth of 312 ft (95 m), 6 miles (9 km) north of Ross in the Moray Firth in the northern North Sea. Operated by BG International with Talisman UK and Paladin Resources, Ross production is projected to continue at about 25,000 b/d, and the addition of Blake plateau production of 44,000 b/d was seen as a natural development for Ross.
Blake is being developed with six production wells around a 200-tonne manifold and two satellite water-injection wells 2 miles (3 km) either side of the main well cluster to maintain aquifer pressure and production rates. The gravity-base manifold will house all pipeline headers and diversion valves, distributing gas lift, injection water, control functions and chemicals to the wells, as well as routing the well streams to the 10-in. and 12-in. production lines to Ross.
Coflexip said flow assurance is critical to Blake, ensuring hydrocarbons during the critical early production period and turndown conditions reach Ross above the temperature of wax appearance. As the flowing wellhead temperature is close to the wax formation temperature, high levels of insulation are required on production lines to prevent wax formation. To overcome this, Coflexip has opted for a 10-in. within 16-in. pipe-in-pipe system to maintain the necessary hydrocarbon temperature when it arrives at the FPSO.
Downhole gauges and multiphase flow meters will be used on the Blake manifold to provide well and reservoir data, because the test separator on the Bleo Holm will be used to handle lower Ross production volumes. Gross Blake output, at a maximum of 100,000 b/d, will be routed to the production separator. The lower Ross volumes will go through the test separator.
As it is imperative to maintain reservoir pressure, injection water has to be provided at a maximum flow rate of 120,000 b/d, with a maximum of 70,000 b/d to an individual well, Coflexip said.
Each subsea tree will have a dedicated control module operating valves, receiving and transmitting data back to the FPSO.
First oil from Blake was expected by the end of June.
But the Bleo Holm may become a platform for a further satellite tie-in following the confirmation of the Neso find with the 13/29b-7 exploration well - just 3 miles (5 km) north of Ross - drilled by the Ocean Princess semisubmersible and completed by Talisman in May. This well produced 2,200 b/d of oil on test, and Talisman said at the time, "Well data indicates that this well has pushed the northern extension of the Ross field into the adjoining acreage." The company said discussions would take place between the Ross field owners - Talisman owns 80% of the license that covers the Ross field, and Paladin Expro holds the remaining 20% - and the owners of the license covering Block 13/29b with a view to bringing Neso into Ross.
Talisman's relationship with Shell has been enhanced by the Canadian-based operator's intention to use another Shell platform, Fulmar, to accommodate a further satellite project. This is to tap the 11 million-boe Halley oil field via two extended-reach wells. One is a production well, stretching 2 miles (4 km) from Fulmar, and the second, a water injector, will be drilled 3 miles (5 km) away. A third production well may be drilled, but not before mid-2003.
First-phase production - aimed for by the middle of this year - will tap only the Halley Gamma reservoir, leaving two other reservoirs, Alpha and Beta. Production is expected to be 18,000 b/d of oil. The development, in blocks 30/11b and 30/12b, is expected to cost $7/boe, and the field life is put at 5 years.
During development screening, Talisman ruled out the use of a dedicated or minimal facilities platform for Halley on the basis that the construction of new facilities would "significantly increase" the risk to personnel, disrupt the environment and impact a previously undeveloped site.
Still with Talisman, another 20 million to 50 million bbl of oil is to be tapped by exploiting its Lucy prospect, possibly as a tieback to the Piper Bravo platform 5 miles (8 km) away.
Lucy was located with the 15/12b-4 well, drilled on 16th Licensing Round acreage - also by the Ocean Princess - earlier this year, and encountered a 68-ft (21-m) pay zone in Jurassic Piper sandstone with high permeability.
Although the well was not flow-tested, "excellent reservoir quality" and an extensive sampling program led Talisman to suggest the find was capable of flowing at up to 15,0000 b/d of oil.
With stepout drilling and further planned 3-D seismic work over the entire Flotta terminal catchment area, Talisman is confident it has a commercial discovery.
Lucy lies north of the Talisman-operated Piper, Chantire and Saltire fields in Block 15/17. Finalization of a development plan is due later this year, with a target onstream date for Lucy set for 2002 via one or two horizontal stepout wells from Piper Bravo.
Talisman President James Buckee said, "Although the size is uncertain, the Lucy exploration well is clearly a commercial discovery. With additional seismic under way, we would hope to justify stepout drilling."
Lucy was one of nine exploration wells planned by Talisman this year, on top of 46 development wells.
The $204 million (£145 million) Shell Otter project will use the operator's Tern and Eider platforms as hosts for injection and production facilities for five wells in Block 211/5a.
Otter will have a projected field life of 7 to 10 years and peak production of 30,000 b/d of oil starting in the fourth quarter of 2002 from a reserves base thought to be in the region of 35 million bbl.
Coflexip has been contracted to provide offshore construction for installation of production and water-injection pipelines, as well as three electrical cables. FMC is contracted to supply the subsea hardware, including wellheads, trees, manifolds and umbilicals.
After a FEED was finished in July 2000, it was decided Otter would comprise three new horizontal producers, one new reinjection well and recompletion of 210/15a-5 as an injector. Oil will be exported from Otter via a 10-in., 13-mile (21-km) production flow line to the Eider platform and then to North Cormorant through the existing 12-in. pipeline to Sullom Voe. A 10-in., 13-mile (21-km) pipe from Tern will supply injection water to Otter, which was discovered in October 1977 with the 210/15-2 well and drilled by what was then Fina.
Conversely, TotalFinaElf (TFE) chose to use its own infrastructure when it considered a solution for the four-cluster Northern Underwater Gas Gathering and Transmission System (Nuggets) project.
Although the cluster was discovered in 1974, project manager Didier Bertrane said debottlenecking on the Alwyn North field allowed Nuggets to move forward.
The UK Department of Trade and Industry in July 2000 gave development consent for the N1 reservoir, with reserves at 300 Bcf. Consent for two other accumulations, N2 and N3, has since been given also.
One of the key technological boundaries that had to be overcome was the distance for sending electric and hydraulic power. To achieve this, TFE will lay a 12-mile (19-km) umbilical from its Dunbar platform to Alwyn North, so that Alwyn North can control the four Nuggets wells.
Assuming the project schedule is met, N1 should be producing by October, and N2 and N3 are due to follow in November.
Gas from Nuggets will be processed on Alwyn North.
Using the Frigg pipeline system, gas will be exported to St. Fergus and liquids via Shell's Cormorant facility to the Sullom Voe terminal.
While some of the latest projects are tapping into new finds, Amerada Hess has decided to revitalize one it abandoned 8 years ago.
Better oil prices and new technologies are making it possible for the company to revisit the Angus field, which was shut down in 1993 when 10 million bbl of oil was produced.
Angus, in blocks 31/26a and 31/21, is being redeveloped with a new production well drilled by the Glomar Adriatic IV jackup, which will be tied back 11 miles (8 km) to the Uisge Gorm FPSO operating on Amerada's Fife, Fergus and Flora fields. Output from these three is about 28,000 b/d, and Angus is expected to add about 5,000 b/d. An 8-in. production flow line and 3-in. gas lift line will have to be laid, and Amerada hopes to have first oil (again) by the fourth quarter this year.
The new well will access another 4 million bbl of oil, extending the life of the Uisge Gorm production facility up to 2 years, it is hoped.
Norway
And while all this been happening in the UK sector, Norway-based operators have seen the sense in maximizing infrastructure as well.
TotalFinaElf is finally planning to develop its Byggve and Skirne gas finds in the North Sea by hooking them up to the Heimdal field, which is projected to cost $122 million (NKr 1.1 billion).
The operator will submit a development plan to the Ministry of Petroleum and Energy this summer. However, license partners have not made a final decision to move the project forward.
The two finds will be developed with one subsea installation each, tied back to the Heimdal platform farther west operated by Norsk Hydro.
Both discoveries are in PL 102, Block 25/5, awarded in 1985. Skirne, estimated to hold 148 Bcf of gas and 5.7 million bbl of condensate, was found in 1990. Byggve, found in 1991, is thought to hold 84.8 Bcf of gas and 4.4 million bbl of condensate.
Statoil is lining up its Sigyn field for a tie-in having signed a deal earlier this year with Esso Exploration and Production that will pave the way for developing Sigyn via subsea wells linked to Statoil's Sleipner A facility.
Development of Sigyn will cost an estimated $170 million (NKr 1.5 billion). It is scheduled to start producing in late 2002 with recoverable reserves estimated at 67 million boe to be tapped over 10 to 12 years.
PL 072 covers part of Block 16/7, and the Sigyn reservoir is about 7 miles (12 km) southeast of the Sleipner East.
Statoil also is aiming to use Åsgard B to tie in its Mikkel gas discovery in the Norwegian Sea in a scheme estimated at $230 million.
Mikkel will be tapped from four production wells via the Midgard field to the Åsgard B platform. This solution will make it possible to begin production of 706 Bcf of gas and 30 million bbl of condensate in October 2003.
Gas will be piped via the Åsgard transport pipeline and landed at the Kårstø facility before being routed to Europe.
Statoil also considered tapping Mikkel via Shell's Draugen platform under a $460 million scheme to extract up to 848 Bcf of gas.
The Mikkel field consists of the two licenses, 092 and 121, for which a coordination agreement was signed Feb. 16.
Contracts for developing Mikkel were issued in May, with FMC Konsgberg Subsea securing the largest deal, worth about $44 million (NKr 400 million) for design and manufacture of the subsea production systems, including templates and wellheads.
Kværner Oil and Gas has secured a $3.3 million (NKr 30 million) agreement for modifications of the Åsgard B platform, and it is responsible for engineering and procurement activities for this part of the development. It also holds options for prefabrication and offshore installations valued at $5.5 million (NKr 50 million).
Reinertsen Engineering has been contracted to design subsea systems involving pipelines and control cables in a $655,000 (NKr 6 million) deal.