Update on UKCS Field Development Projects - Intsok

<strong>Update</strong> on UKCS Field 

Development Projects 

| April 2010 | 

| Underlining denotes new information | 

Prepared for INTSOK by BRITBOSS 

www.intsok.com

1 Approved projects 

2 new approved projects. 

Field Burghley 

Area Central North Sea 

Operator Talisman 

Development concept Subsea 

Transport concept 10.4km pipeline to Balmoral 

Start-up Q4 2010 

Comments: Approved Oct 2009. Talisman is developing Burghley as a subsea tieback to the 

Balmoral floater, which is operated by Premier. It will be produced through a single well, a new 

sidetrack in appraisal well 16/22-9 which was drilled and completed by semisub Ocean 

Princess in Sept-Nov 2009. The well will be tied back to Balmoral by a 10in production pipeline 

with a 4in lift-gas line piggybacked on it; Technip is due to lay these lines in May. FMC 

supplied the subsea tree, RRC the subsea controls and Duco the umbilical. 

Field *Laggan/Tormore 

Area West of Shetland 

Operator Total 

Development concept Subsea to shore 

Transport concept 2 x 140km pipelines to Sullom Voe, 15km inter-field pipeline, 

224km pipeline from Sullom Voe to Frigg UK line 

Start-up Mid 2014 

Comments: Approved Mar 2010. The development of the Laggan and Tormore 

gas/condensate fields west of the Shetlands will benefit from a tax allowance worth up to 

£160m per field for deepwater WoS developments. Start-up is scheduled for 2014. Basic 

engineering was awarded to a joint venture between ODE and Doris. FMC will supply subsea 

equipment and Corus line-pipe, a volume of 150,000t. Other awards are expected shortly. 

Subsea equipment will be installed in 2011 to allow drilling to start in 2012 – there will be up to 

five wells on Laggan and three on Tormore. Recoverable reserves in the two fields are 

estimated at 1.5 tcf. Gas and condensate will be sent to the terminal via two 140km multiphase 

pipelines. From there gas will be transported to the mainland via the East of Shetland pipeline 

– a 225km, 30in line linking into the Frigg UK pipeline at the MCP-01 location. The gas line 

from Laggan will have 665 MMcf/d capacity, enabling it to act as a hub for third-party gas: 100 

MMcf/d from Chevron’s Rosebank/Lochnagar field and 65 MMcf/d from BP’s Clair North, in 

addition to 500 MMcf/d from Laggan/Tormore. Total plans to install subsea gas compression 

facilities within five years of start-up. In around 600m of waters, Laggan and Tormore will be 

the deepest developments yet undertaken in the UK sector. Total has also become operator of 

the Tobermory gas discovery some 130 km to the north, with a view to bringing it on stream 

through the Laggan infrastructure in 2016.

Field *Maule 


Operator Apache 

Development concept Extended-reach drilling 

Transport concept -- 


Comments: Approved Mar 2010. Apache is develop Maule, which has reserves of 2.9m boe, 

with an extended-reach well drilled from Forties A platform. Drilling by contractor Seawell is 

under way, Apache said in Apr. The field could therefore be on stream by mid year. The well 

will be fitted with dual electric submersible pumps supplied by Schlumberger. Depending on 

results, a further two wells may be drilled. The company is also seeking approval to develop 

the nearby Bacchus field as a subsea tieback to Forties A. 

www.intsok.com 

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2 Projects on the move or likely to move 

2 new entries (marked **), 3 entries promoted from Section 3 (marked *). 

Field Andrew Area 


Operator BP 


Transport concept 28km pipeline to Andrew 


Comments: BP has issued the environmental statement for the Andrew Area development, 

involving the subsea tieback of Kinnoull and further development of Andrew’s Lower 

Cretaceous reservoir. Start-up on Kinnoull is scheduled for early 2012. There will be three 

horizontal wells tied into a 150t, four-slot manifold. The wells will be drilled by semisub Byford 

Dolphin starting in Q4. The manifold will be tied back to Andrew by a 28km, 14in production 

pipeline in corrosion resistant alloy, plus a 6in lift-gas line and a 3in methanol line. The 

pipelines may be bundled, in which case there will be four bundle sections. They will be routed 

via the Arundel field where a two-slot manifold will be installed for future use. The lines will tie 

into a 100t, gravity-base pipeline end manifold at the platform. A 44in caisson riser will be 

installed on the jacket and a 750t reception module will be cantilevered on the topsides. The 

following contracts have been placed: topside engineering services for modifications on 

Andrew to Wood Group; subsea engineering services to JP Kenny; subsea trees to Cameron; 

subsea controls to GE/Vetco; and subsea ball and gate valves to BEL. Tendering is also under 

way for subsea construction, umbilicals, heavy-lift services, flotel support and module/caisson 

fabrication. Conceptual engineering has been performed by Xodus. 

Field 

Athena 


Operator Ithaca 

Development concept FPSO 

Transport concept 2km in-field pipeline bundle 


Comments: The relaunched Athena project will have the BW Carmen FPSO as its production 

facility; Ithaca issued a letter of intent to BW Offshore for it in Mar. The vessel will be 

lengthened to include a submerged turret loading (STL) system. According to a new 

environmental statement, there will be a single drilling centre connected to the FPSO by a 

2km, 29in pipeline bundle containing an 8in production pipeline, 8in injection water line and 3in 

service line. There will be four subsea production wells, of which three of which will be 

recompleted appraisal wells, plus one water injector. They will be tied into a manifold 

integrated into the bundle towhead. Drilling is due to start in Q4. Engineering support is being 

provided by Petrex. Orders have been placed for long-lead items including subsea trees, which 

are expected to be supplied by GE, and downhole electric submersible pumps (ESPs). Ithaca 

intends to lease the subsea facilities. Reserves are 15.7m bbl, but the company is considering 

adding two producers and a second water injector, which would double recovery. 


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Auk Redevelopment 



Development concept Platform upgrade 


Start-up 2012 

Comments: Talisman is seeking approval to redevelop the main Auk field, installing a new 

drilling rig, living quarters and power generation facilities and drilling up to nine new wells. 

Living quarters fabrication is understood to have been awarded to Consafe. Start-up is 

scheduled for 2012. In parallel the company is implementing the development of the Auk North 

reserves as a subsea tieback to the Fulmar platform. This project is due to come on stream in 

2011. 

Field Bacchus 




Transport concept 6.5 km pipeline to Forties A 


Comments: Apache is applying for approval to develop Bacchus (35m bbl) as a subsea 

tieback to the Forties A platform with start-up in spring 2011. There will be three wells which 

will be drilled by jackup Rowan Gorilla VII starting in early 2011. These will be connected to a 

four-slot manifold integrated in the towhead of a pipeline bundle to be supplied by Subsea 7. 

The 37.5in bundle will contain two 6in production lines, a 6in water line and a 4in heating line 

plus return line, to be used when production has to be shut down and then restarted. The 

project will use GE subsea trees which Apache already has in stock. In parallel Apache is 

developing Maule with an extended-reach well from Forties A – this project has just been 

approved. 


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Bains Gas Storage 

Area Morecambe Bay 

Operator Centrica 

Development concept Platform 

Transport concept 32km pipeline to Barrow terminal 

Start-up 2013/14 

Comments: Centrica has rescheduled its plans to convert the Bains gas reservoir into a gas 

storage facility – storage operations are not now expected to start until 2013/14, rather than in 

early 2012, as previously planned. The final investment decision, originally due in 2009, will 

now be taken in early 2011. An environmental statement for the offshore part of the project is 

ready to be released but has to wait while some legislative adjustments are made by DECC. 

The project was approved by Barrow Borough Council in 2009. Bains, which produces through 

a single subsea well, last produced in Feb 2009, so production appears to have already 

ceased. For storage purposes an unmanned platform will be installed together with a pipeline 

to the Barrow terminal, where additional gas processing facilities will be required. Storage 

capacity will be 20 bcf. 


*Baird Gas Storage 

Area Southern North Sea 



Transport concept 100km pipeline to Bacton 


Comments: Centrica is moving ahead with plans to convert the Baird field into a gas storage 

facility, with a final investment decision scheduled for Q3. The facility, which will cost about 

£1.7 bn, will have 60 bcf storage capacity. A new platform, 14-16 wells, a 38in pipeline to shore 

plus a possible MEG line, and onshore facilities will be required. Genesis is performing FEED, 

while ESR Technology is providing safety services during this phase. Drilling is due to start 

through a predrilling template in early 2011, pipelay will take place in Q1/12 and the platform 

will be installed in 2012. Baird produces through a single well drilled from Perenco’s Inde D 

platform. Reserves are largely depleted. 


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Field Barbara/Phyllis 


Operator Dana 


Transport concept 40km pipeline to Everest? 


Comments: A host has been selected and commercial terms agreed for the subsea tieback of 

the Barbara and Phyllis gas/condensate fields, Dana reports. Production will be exported by a 

40km, 12in pipeline – which suggests the host will be BG’s Everest platform to the north. Startup 

has slipped a little further to late 2012. The next step will be a detailed FEED study, leading 

to project sanction in Q4. While Phyllis is wholly owned by Shell and ExxonMobil, Barbara lies 

on three different licences and a unitisation agreement has been reached. Combined reserves 

are 230 bcf. 

Field Bentley 

Area Northern North Sea 

Operator Xcite 

Development concept Production facility + storage 

Transport concept Offshore loading 

Start-up EPS 2011/12 

Comments: Xcite is planning a phased development of the Bentley heavy-oil field in block 

9/3b. The next step is an appraisal well, 9/3b-R, to be drilled and tested this year – if 

successful, first oil could possibly come as early as 2011, the company says. By April it 

expects to sign a contract with ADTI for a jackup rig to drill the well. Challenger Minerals will 

farm into the field, taking a 4% stake and contributing $4m to the well costs. The financial 

burden will be eased to a degree by tax advantages offered in the 2009 budget. In Dec Fugro 

drilled a geotechnical test well which showed that a jackup can be used to drill the appraisal 

well, which at 110m water depth is at the limit for jackups. The same bore will be used for the 

appraisal well, which will also be drilled by Fugro. The contractor was the first member of the 

Bentley alliance, which Xcite envisages as a group of suppliers willing to take some risk in the 

development in return for appropriate reward. ADTI, which, like Challenger, is owned by 

Transocean, is also a member. Amec will help to plan the production test and provide 

development services. BP will provide services for the offtake and sale of the crude, and assist 

with securing $20m of financing for the development. Full field development will call for 50 plus 

wells and a fixed platform, but for the EPS an FPSO is one of the options. In all phases oil will 

be exported by shuttle tanker, so storage in some form will be required. Base-case reserves 

are estimated by RPS at 122m bbl. 


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Field Blackbird 


Operator Nexen 


Transport concept 6km flexible pipeline to Ettrick 


Comments: Nexen says it intends to develop the Blackbird oil discovery as a subsea tieback 

to Ettrick. Blackbird was discovered in 2008 by exploration well 20/2a-8. It tested 3,800 b/d and 

was suspended for possible recompletion as a producer. An appraisal well is planned for 2010. 

Another possible Ettrick tieback is the Polecat discovery in 20/4a to the east, on which semisub 

GSF Arctic IV is expected to spud an appraisal well in the next couple of months. 

Field Breagh 


Operator RWE Dea 


Transport concept 110km, 20in pipeline to Teesside 


Comments: Project sanction for the Breagh gas field is now looked for in June and start-up in 

Q2 2012, RWE Dea reports. The first phase of development, which will cost £350-400m, will 

call for a production platform with 800-900t topsides and 2,000t jacket, from which up to nine 

wells will be drilled. Platform FEED will be performed by Genesis. Fabrication is an option on 

the Clipper South platform contract for which bids have been submitted. Wet gas will be 

exported through a 110km, 20in pipeline (10 km will be overland) to a processing plant on 

Teesside. FEED for the pipeline has been performed by Genesis. Bids for pipelay have been 

submitted by Allseas and Saipem. There are likely to be further stages of development 

involving more platforms and possibly offshore compression facilities. Three successful 

appraisal wells have been suspended to serve as future producers. There is nearby potential 

which will be investigated – exploration wells are planned on the Airidh and Macanta 

prospects. 


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Field Bressay 


Operator Statoil 



Start-up H2 2015 

Comments: Despite tax advantages offered in the budget, Statoil is sticking to its decision to 

postpone development of Bressay by a year – it aims to seek sanction in mid 2011. Earliest 

start-up is 2015. In the interim the project has not been shelved but slowed. Concept selection 

is due to be made in Q3 with FEED getting under way late this year. Development will require 

capital spending of $1.8 bn on facilities and $1.4 bn on drilling. In 2008 StatoilHydro performed 

a two-week production test programme on the heavy-oil field – according to Xcite, which 

exchanged data with StatoilHydro on the Bentley and Bressay fields, the operator 

subsequently concluded that the field was commercial. The well-test was part of a work 

programme which also includes seismic and sub-surface surveys. Development is expected to 

call for a fixed platform and offshore loading. Bressay could serve as a hub gathering 

production from neighbouring heavy-oil fields. 

Field *Bugle/Black Horse 




Transport concept 25km pipeline to Scott 

Start-up 2012 

Comments: In late Feb Nexen spudded appraisal well 15/23d-15 to test the northern 

extension of the Bugle discovery. The well, which is being drilled by semisub GSF Arctic IV, is 

located on the border with 15/23c, and the two licence groups are sharing the cost. According 

to partner Premier, if the well is successful, development approval for a subsea tieback to Scott 

will be targeted for end-year. Bugle lies about 25 km from Scott and Black Horse, another 

discovery which could be developed jointly with it, about 12 km in the same direction. Nexen is 

operator of the Bugle and Black Horse licences and of Scott, while Premier is a partner in all 

three licences. The 15/23c licence group is led by Nippon. 


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Field **Carna 



Development concept Subsea? 

Transport concept 11 km pipeline to Kilmar or 30 km pipeline to Trent? 

Start-up 2012 

Comments: Project sanction for Carna, which was discovered by Venture in 2009 before it 

was taken over by Centrica, is looked for in late 2010/early 2011 and start-up in 2012. The 

base case for development is two subsea wells, though a platform has not been ruled out. No 

decision has yet been taken on the host – both ATP’s Kilmar and Perenco’s Trent are under 

consideration. Other prospects have been identified in the area which are likely to be drilled. 


Causeway 


Operator Antrim 


Transport concept 9km pipeline to Dunlin 


Comments: The lengthy delay in the development of the Causeway oil field should come to an 

end with an agreement whereby Antrim will transfer part of its stake and the operatorship to 

partner Valiant. Valiant’s first task will be to review and optimise the modified field development 

plan and submit it to DECC. The new plan will incorporate significant time and cost savings, 

mainly resulting from a tie-in into existing subsea infrastructure rather than directly back to 

Dunlin. The project is also expected to benefit from measures in the 2009 budget. But whether 

start-up is still achievable in 2011, as previously planned, is unclear. The $113m first phase 

involves the development of the eastern part of the field with one subsea producer and one 

water injector – these will be based on existing wells. A second producer will be added after a 

year. Overall reserves are estimated at 21.6m bbl, of which 8m will be produced in the first 

phase. The 2006 discovery well and five appraisal wells have all been suspended. Antrim 

contracted Senergy to assist with preparation of the plan and CSL to perform subsea project 

management and assist with selection of the host facility. 


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Field Cheviot 


Operator ATP 

Development concept Semi-submersible drilling, production and storage platform 

Transport concept Offshore loading + gas export pipeline 

Start-up 2012 

Comments: In 2008 ATP submitted a draft plan for redeveloping Cheviot. However, the 

environmental statement will only be issued when an export route for the gas has been 

negotiated – hopefully by mid year, ATP said in Apr. Start-up is scheduled for 2012. ATP will 

use Moss Maritime’s Octobuoy concept, a semi-submersible platform with drilling and storage 

facilities. Production capacity will be 25,000 b/d of oil and 50 MMcf/d of gas. Storage capacity, 

which is required as the crude is too acidic to be transported by pipeline and will be exported 

by shuttle tanker, will be 200,000 bbl. There will be an amine unit for CO2 and H2S removal. 

The installed cost of the platform is $600m. Hull construction at the Cosco yard in China is 

50% complete and on track for completion in 2011, ATP reported in Feb. Dockwise has been 

contracted to transport the hull to the North Sea. In Oct ATP reported that it had agreed a deal 

with Cosco to defer $99m in construction costs for the hull. Topsides construction is due to 

start this year. Twelve to 15 horizontal and high-angle wells will be required. Reserves, 

including the small nearby Peter discovery which will be included in the development, are 

estimated at 22.7m bbl and 113 bcf. Cheviot was formerly known as Emerald. 

Field Christian/Bligh/Selkirk 




Transport concept Pipelines: 5 km Christian/Bligh to Mallard, 25 km Selkirk to Bligh 


Comments: The next development in the greater Kittiwake area – one of the Venture assets 

acquired last year by Centrica – is likely to be a joint project involving three HP/HT fields - 

Christian, Bligh and Selkirk. Implementation, however, could be phased. According to Centrica 

the project is unlikely to be sanctioned for a year or two. An appraisal/development well on 

Christian is planned for this year – it will be extended to explore the underlying Christian Deep 

prospect and also clarify whether part of Bligh underlies Christian. The three fields will be 

developed with subsea facilities - Christian and Bligh will be tied into the Mallard pipeline, while 

Selkirk, which is remotely located, will be tied back to Bligh. The fields may be among the eight 

HP/HT fields which stand to benefit from tax concessions offered in the pre-budget report in 

Dec. 


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Clair Ridge 

Area West of Shetlands 

Operator BP 

Development concept Platform(s) 

Transport concept 10-15km oil pipeline to Clair, 35km gas pipeline to Laggan 


Comments: BP has revealed its plans for the development of oil and gas reserves on Clair 

Ridge, in the north of the main Clair field. This is a £4 bn project calling for two bridge-linked 

platforms, one for drilling and processing functions, the other for quarters and utilities, with a 

combined weight of 70,000t and production capacity of 120,000 b/d. Bids have been invited for 

jackets, topsides and predrilling template, BP said in Apr. Start-up is scheduled for 2015. 

FEED for development options was performed by Amec and KCA Deutag subsidiary RDS is 

contracted for design of the drilling facilities, including detailed design. There will be at least 28 

wells, some of which will be pre-drilled. Oil will be exported via Clair and gas via the Laggan 

pipeline. BP has confirmed that its two-well appraisal campaign on Clair Ridge in 2006 and 

2007 was successful; an appraisal on Clair North in 2006 also found oil. A third stage of 

development, focusing on reserves in the south of the field, is said to be in the early stages of 

preparation. 

Field Clipper South 


Operator RWE Dea 


Transport concept 20km pipeline to Loggs 


Comments: Project sanction for the Clipper South gas field is now looked for in June and 

start-up in Q2 2012, RWE Dea reports. Three wells will be drilled in the first phase, followed by 

up to another three. They will be hydraulically fractured, for which reason the platform will be 

manned for at least three years before switching to unmanned. Genesis has performed FEED 

for the platform, which will have a 2,000t topsides and accommodation for 40 personnel. 

Fabrication bids have been submitted by three yards. Gas will be exported via Loggs. Tenders 

for pipelay and platform installation are expected to be issued by mid year. RWE is likely to 

seek to coordinate the drilling programme with that for Breagh, looking for synergies. 

Schlumberger will provide fracture and stimulation services under a long-term contract 

negotiated with the previous operator Fairfield, now RWE’s partner, using the specialised 

vessel Siem Sailor. Reserves are estimated at 200 bcf. 


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Field Columbus 


Operator Serica 


Transport concept 6km pipeline to Lomond 

Start-up 2013 

Comments: Serica plans to submit a modified field development plan covering the whole of 

the Columbus gas/condensate field later in the year. This follows discussions with BG whose 

23/21-7 appraisal well in late 2008/early 2009 proved an extension of the field from Serica’s 

23/16f into BG’s 23/21. The field will be developed with three-four horizontal subsea production 

wells tied back to BG’s Lomond platform, six km to the south-east – BP’s Marnock was the 

other option for the host. The export pipeline will be 12-14 inches. Reserves in Serica’s block 

are estimated at 17.7m boe; the volume in BG’s block is smaller. Start-up has probably been 

pushed back to 2013, Serica says. 

Field Crawford II 


Operator Fairfield 

Development concept Subsea or jackup platform 

Transport concept 30km pipeline to East Brae or offshore loading 


Comments: Fairfield aims to decide the concept for redeveloping Crawford and sanction the 

project by mid year. It is evaluating two alternatives; a jackup drilling rig with production 

facilities and offshore loading or a subsea tieback to Marathon’s East Brae. In Dec it completed 

a joint feasibility study with Marathon and BP for the subsea tieback of Crawford and Devenick 

to the East Brae platform. There are likely to be four wells, one of them an outlier located about 

1.2 km distant from the drilling centre. In the subsea scenario the wells would be tied into a 

manifold, and production would be exported through a 10in multiphase pipeline and lift-gas 

imported through a 4in line. Genesis is responsible for FEED and detailed design of a subsea 

development. Wells will need to be fracced - a long-term contract for fracture and stimulation 

services has been signed with Schlumberger, which will use the specialised vessel Siem 

Sailor. Recoverable reserves are estimated at 26m bbl. 


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Field Cygnus 


Operator GDF Suez 

Development concept Platform(s) 

Transport concept Pipeline to McAdam? 

Start-up Q4 2011? 

Comments: GDF Suez, which had expected to receive DECC approval for the first phase of 

development of the Cygnus gas field in May, has revised its plans. It will now develop the field 

in two phases, of which the first phase will cover the development of the whole eastern area 

and the second phase the western area. Full details will be released when the revised plans 

have been completed. It is unclear whether start-up will still take place in late 2011. A final 

decision on the export route is also outstanding – the proposal in the environmental statement 

was to tie the field back to Murdoch via the McAdam subsea template by a 27km, 12in pipeline 

with a 3in chemical supply line piggybacked on it. But Perenco’s Tyne platform 20 km to the 

south-east represents a alternative route. Fabrication bids for the first unmanned wellhead 

platform under the previous scheme were delivered in Feb. Pipelay and platform installation 

have yet to be tendered. Development drilling will be carried out by jackup Ensco 100, which is 

currently drilling two appraisal wells in the west of the field. In Apr GDF announced that the first 

well had tested 28 MMcf/d of gas from an undrilled block. Reserves in eastern Cygnus are 

estimated at more than 500 bcf. According to partner Endeavour, reserves for the whole field 

may be as high as 2 tcf. FEED for the previous scheme was performed by Genesis. Wells 

require pressure-fracturing. Overall reserves may be as high as 1.3tcf. 


Darwin 




Transport concept 28km pipeline to Dunlin A? 

Start-up 2013? 

Comments: Fairfield has entered into an agreement to acquire Darwin, formerly Hutton North- 

West, from the current owners. It plans to appraise it and then bring it back on stream; the 

base-case is a subsea development tied back to its own Dunlin platform. Conceptual options 

are still under study, it said in Mar. Sanction will probably not come until H2 2011, so start-up 

looks unlikely before 2013. According to current operator BP, some 80m bbl of oil and 250 bcf 

of gas would become available if the recovery factor could be raised to 45% from the 26% 

achieved so far from the field, where the original production facilities are being 

decommissioned. In a second phase Fairfield plans to explore and produce prospects on 

adjacent acreage it gained in the 25 th round; two appraisal wells are due to be drilled here next 

year. 


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Devenick 


Operator BP 


Transport concept 33.5km pipeline to East Brae 


Comments: BP has confirmed plans to develop the Devenick HPHT gas/condensate field as a 

subsea tieback to Marathon’s East Brae. In the environmental statement issued in Mar, it 

reveals that there will be two subsea wells located separately and tied back to a manifold by 

pipelines of 1.3 km. A further two producers may be drilled in a second phase. Both the in-field 

lines and the export line will be pipe-in-pipe systems – 8in/14in for the former and 10in/16in or 

12in/20in for the latter. The export line may be laid by a reelship or a lay-barge. There will be 

one new well, to be drilled by semisub Paul B Loyd Jr, and one converted appraisal well on 

which an intervention operation will be performed either by the same drilling rig or a light well 

intervention vessel. Drilling/well work is due to start in mid year and offshore construction and 

pipelay is scheduled for 2011. Devenick is scheduled to move through sanction into execution 

in July. A joint feasibility study of the tieback with Marathon was completed in Dec when BP 

confirmed that FEED was being performed by Petrofac. Subsea engineering services have 

been contracted to JP Kenny, subsea trees to Cameron, subsea controls to GE/Vetco and 

subsea ball and gate valves to BEL. Tendering is also under way for subsea construction and 

umbilicals. Also involved in the East Brae study was Fairfield, which may tie Crawford back to 

the platform. Devenick may be one of the eight HP/HT fields which stand to benefit from tax 

concessions offered in the pre-budget report in Dec. 


Ensign 




Transport concept 15km pipeline to Audrey B 


Comments: Centrica is looking for project sanction for Ensign, a former Venture asset, in July 

and start-up by end 2011as export capacity becomes available in ConocoPhillips’ Loggs 

system. Gas will be transported to Loggs via the Audrey B platform. Ensign will be developed 

with an unmanned wellhead platform – this may still be built by SLP under a frame agreement 

signed with Venture, if the yard, which went into receivership in Dec, finds a new owner in time. 

FEED is being performed by Genesis and Heerema. Long-lead items were secured some time 

ago. There will be two or three production wells which will be hydraulically fractured. Subsea 7 

will perform pipelay, also under a frame agreement awarded by Venture. Reserves are 

estimated at 97 bcf. In 2009 Venture discovered gas in the nearby Andrea prospect, but it is 

unclear whether the find is commercial. If it is, it could be developed as a subsea tieback to 

Ensign. 


| 15

Field Falcon/Tern North 


Operator Taqa 


Transport concept Pipeline(s) to Tern 


Comments: Taqa plans to develop Falcon and Tern North as subsea tiebacks to the Tern 

platform which it operates. First, however, it has to prove they contain hydrocarbons – this will 

be done by semisub Stena Spey which started a four-well programme in early Apr with an 

appraisal well on Tern North. Start-up could take place in 2011 or 2012. Combined reserves 

are estimated at 5-25m bbl. 

Field Forties 



Development concept 2 wellhead platforms 


Start-up 2011 

Comments: Apache plans the further development of the Forties field with the installation of 

two satellite wellhead platforms. Each 18-slot platform will have a 2,000t topsides, 4,600t 

jacket and 3,700t of piles. An EPCI tender for the first was issued in Dec. A FEED contract has 

now been awarded to SLP North Sea, part of the SLP group which is not in administration; 

assuming the project is sanctioned, this will lead into fabrication, which will take place at SLP’s 

Tyneside yard. The platform, which is due to be installed in 2011, will be bridge-linked to 

Forties Delta and the second to Forties Alpha. Drilling is likely to be carried out by a jackup as 

the water depth is just over 100 metres. 


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Field Franklin West 




Transport concept 6.2km pipeline to Elgin 


Comments: Total has revealed plans for a second phase of development of the Franklin West 

HP/HT field, involving the installation of a wellhead platform. EPCI bids have been invited for 

the four-leg, 2,800t jacket, which is due to be installed in Q3 2011, while the 12-slot topsides 

will be tendered in Q4 2010 and installed in summer 2013 – hook-up will require flotel support. 

Three wells will be drilled before start-up and a possible fourth afterwards. Drilling by jackup 

Rowan Gorilla V is due to begin in Q2 through a pre-drilling template which will be installed by 

Subsea 7 dsv Seven Sisters. Production will be sent by two 12in production pipelines to the 

Elgin field centre for processing – these lines, plus an umbilical and a power cable, may be 

housed within a 30in pipeline bundle. A Hipps – high-integrity pressure protection system – 

and a multiphase flow meter will be installed on the platform. The wellstream will pass over the 

Elgin wellhead platform on which a pig launcher/receiver will be installed. 

Field Fyne 


Operator Antrim 

Development concept FPSO or subsea 

Transport concept Offshore loading or pipeline 


Comments: Having agreed to sell some of its interest in Causeway to Valiant, which will also 

become operator, Antrim has concentrate on Fyne, which it calls its core UK asset. It aims to 

select the concept and ‘progress submission’ of a field development plan for the heavy-oil field 

this year (previously H1 2010). In its latest statement, in Mar, it makes no mention of a start-up 

date (previously its target was mid 2011). It is still searching for a partner to take on part of its 

75% stake and capex commitment. Development will entail either an FPSO or a subsea 

tieback to existing infrastructure at 7 or 21 km distance, which corresponds to an indirect or 

direct tieback to the Triton FPSO. This solution could be facilitated by an upcoming 

debottlenecking project on the FPSO. Capex for drilling, completion and tieback is $140m. 

Three production wells are required, two of which will be recompleted appraisal wells drilled in 

2008. At 25º API, the oil is moderately heavy. 2P reserves are 21m bbl. The company also 

operates the nearby Dandy heavy-oil discovery, which it has talked of producing in a second 

phase, also with three wells. Next year it plans to drill on nearby acreage which it believes 

contains substantial potential. 


| 17

Field Gateway Gas Storage 

Area Morecambe Bay 

Operator Stag 


Transport concept 2 x 24km pipelines to Barrow 

Start-up 2014 

Comments: In Feb the £600m Gateway Gas Storage project, which is due on stream in 2014, 

received a gas storage licence from the government. The project involves the development of 

1.5 bcm of gas storage capacity in Morecambe Bay block 110/3b some 24 km from Barrow. 

The project, which is managed by Stag Energy, was granted a licence for the offshore works 

and had its environmental impact assessment approved last year, when it also received 

planning approval to build a gas compression station at Barrow. Amec, Parsons Brinkerhoff 

and Senergy have been engaged to perform FEED in the lead-up to the investment decision 

which has been rescheduled to late 2010. Major supplies and services have been tendered to 

provide a good grip on costs. Twenty man-made storage caverns will be created by a leaching 

process conducted through boreholes drilled from the surface by a jackup rig. Each well will be 

completed on a 150-200t unmanned monopod wellhead platform. Gas will be transported to 

and from shore via a 36in pipeline loop running out to the storage complex, around all the 

monopods and back to shore. Each monopod will be connected to the ring main by a short 

10in feeder pipe. A 4in methanol line will be strapped to one of the lines. The pipeline sections 

between the shore and the complex will be trenched. Power will be supplied from shore via a 

66kV cable. 

Field Golden Eagle Area 



Development concept Fixed platform or floater, + subsea tiebacks 

Transport concept Pipelines and/or offshore oil loading 

Start-up 2014 

Comments: With three finds in close proximity in block 20/1 – Golden Eagle, Pink and Hobby 

– Nexen is planning a joint development involving stand-alone facilities – this could be a fixed 

platform or a floater. There will be three or more drilling centres, the farther ones involving 

subsea tiebacks, Nexen says. For export all options are open – it could involve new or existing 

infrastructure or offshore loading. Project sanction is scheduled for 2010 but start-up will not 

take place until 2014. Reserves in the area are estimated at 150m bbl or higher, according to a 

Feb statement, and development is economic at $40/bbl. RDS has been contracted for drilling 

facilities conceptual design services. Drilling activity was intense last year. Hobby was 

discovered in Feb 2009, after which three appraisals were drilled on it, while an appraisal was 

also drilled on Pink. Further wells are planned, including one on the Lily prospect. Golden 

Eagle was discovered in 2007 and Pink in 2008. 


| 18

Field Harrison 


Operator ConocoPhillips 

Development concept Platform or subsea 

Transport concept 10km pipeline to Kelvin? 

Start-up 2012 

Comments: The target start-up date for Harrison, a small gas field, has been put back to 

2012, according to partner Tullow. The field is expected to de developed with a single well, 

either housed on a minimum facilities platform or completed subsea, and tied back to the 

Kelvin platform, which itself is connected to the Murdoch field centre. The small K4 field, which 

could be developed in the same way, does not appear to be under consideration for 

development at present. Harrison is about 10 km from Kelvin and K4 five km. Timing will have 

to fit in with other Murdoch tiebacks such as Cygnus. 

Field Hood 


Operator Iranian Oil Company (IOC) 

Development concept Subsea or floater 



Comments: IOC is pushing ahead with plans to develop the Hood field following a successful 

appraisal well in mid 2008. The drilling campaign included an exploration well on a nearby 

Paleocene prospect. Both wells were suspended. Senergy is analysing the well results and 

development options; the development concept is due to be decided within a few months, 

according to IOC. The company, which is sole licensee, will then resolve the issue of a partner 

which it plans to take on to operate the development. Development options for Hood, whose 

reserves prior to the appraisal were estimated at 21m bbl, include a floater and a subsea 

tieback of some 20 km to Piper. 


| 19


Huntington 


Operator E.ON Ruhrgas 

Development concept FPSO or subsea facilities 

Transport concept Offloading or pipeline to host 

Start-up 2012 

Comments: According to Premier, the choice of development concept is imminent, and will be 

followed by project sanction in Q3 and the submission of a development plan later in the year, 

aiming at start-up in 2012. Unitisation across two licences also has to be agreed. The concept 

choice is between an FPSO and a subsea tieback. Bids from FPSO contractors are under 

review, while negotiations also continue for a tieback to one of BP’s ETAP platforms, 

presumably Marnock. Huntington consists of a Forties reservoir and Fulmar/Triassic reservoirs. 

For Huntington Forties three to five development wells will be required, according to partner 

Noreco, which estimates the Forties reserves at 59m boe and Fulmar/Triassic reserves at 

109m bbl. An appraisal well is planned into the Fulmar/Triassic horizons, but it appears it will 

not be drilled this year. This part of the field will probably be developed in a second phase. 

Huntington extends into 22/14a, the owners of which are involved in development and 

unitisation discussions. Oilexco, the former operator now taken over by Premier, also 

participated in BG’s Mallory discovery on the 22/14a licence in 2007. A joint development with 

Mallory is a possibility. 

Field Islay 




Transport concept 3km pipeline to Jura? 

Start-up 2011 

Comments: In late Apr Total was understood to be close to issuing the environmental 

statement for the development of Islay, suggesting the gas/condensate field could be brought 

on stream in 2011. Islay was discovered by exploration well 3/15-12 in 2008. The well, which 

tested 43 MMcf/d of gas, was completed for production and suspended. It will presumably be 

tied into the Jura subsea infrastructure three km to the west; Jura is itself tied into the Forvie 

North manifold. More than one well may be required. In Mar Total spudded an exploration well 

on the nearby Laphroaig prospect. 


| 20

Field *Jackdaw 


Operator BG 


Transport concept Pipeline to Judy? 

Start-up 2015 

Comments: Start-up of the HP/HT Jackdaw field is provisionally set for 2015, according to BG. 

The next step will be an appraisal well spudding in Q3. Following the 14-month 30/2a-7 

appraisal and two sidetracks in 2007-08, partner OMV said the well confirmed the significant 

potential of the field. BG, which following discovery said that Jackdaw could be one of the 

largest finds of recent years, did not comment. A platform tied back to Judy could be the 

development solution – this is also ConocoPhillips’ plan for developing the HP/HT Jasmine 

field in the same area, with start-up scheduled for late 2012. Jackdaw may be one of the eight 

HP/HT fields which stand to benefit from tax concessions offered in the pre-budget report in 

Dec. 

Field Jasmine 


Operator ConocoPhillips 

Development concept 3 platforms 

Transport concept 8.5km pipeline to Judy 


Comments: ConocoPhillips aims to bring Jasmine on stream by late 2012, according to the 

environmental statement. Plans call for a 24-slot wellhead platform bridge-linked to a 38-bed 

accommodation platform and delivering production via a 16in/20in multiphase pipe-in-pipe 

system to Judy for processing – here it will access the existing platform over a new riser 

platform. The pipeline may be integrated into a bundle with a carrier pipe of some 33 inches, in 

which case it will be divided into two 4.1km sections. The riser platform will also provide 

separation facilities for Jasmine and a 12-slot wellbay for additional Judy wells. Power will be 

provided to the two Jasmine platforms by subsea cable from Judy. A flotel will be required at 

Judy to house the modification crew. Last year FEED optimisation was performed by 

WorleyParsons, which has now been contracted for FEED definition and advanced 

procurement services, with an option for detailed engineering. Bids have been delivered for the 

wellhead platform jacket, which will weigh some 5-6,000t; the topsides have also been 

tendered. The jacket of this platform will be installed in 2011 after which drilling by a heavyduty 

jackup will begin. The topsides, along with the other two platforms, which are options on 

the wellhead platform tender, will be installed in 2012. Jasmine was discovered in 2006; a 

further drilling campaign in 2007-08 found a second structure known as North Terrace and 

appraised both fields. The hydrocarbons are gas and condensate in HPHT reservoirs. Jasmine 

may be one of the eight HP/HT fields which stand to benefit from tax concessions offered in 

Dec’s pre-budget report. ConocoPhillips has described Jasmine as one of the largest recent 

finds on the UKCS, but gives no indication of reserves in the ES. 


| 21

Field Juliet 


Operator GDF Suez 


Transport concept 10-15km pipeline to Amethyst? 

Start-up 2011 

Comments: First gas from Juliet is expected in 2011, according to GDF Suez, so the approval 

process should take place this year. In Apr the company reported that FEED studies were in 

the process of being contracted and approval for procurement of long-lead items was in place. 

There will be two subsea wells, with a possible third to follow. Juliet lies just south of BP’s 

Amethyst West field facilities. The discovery well, 47/14b-10, was suspended in early 2009. 


Kessog 


Operator BP/Total 


Transport concept 20km pipeline to Elgin? 


Comments: In 2009 Total performed an extended well test on BP’s Kessog HP/HT field with 

semisub Sedco 714. The test was performed on appraisal well 30/1c-9 which was drilled by 

Total in 2006-07. The results are under evaluation, according to BP – the next decision gate 

comes in Q3. If the test was successful, it will open the way to full development, which could 

probably come on stream in 2011 or 2012. This is likely to involve subsea wells tied back to 

Total’s Elgin HP/HT facilities. Drilling the appraisal well and performing the EWT were parts of 

a farm-in deal whereby Total will gain a 50% stake in the field and take over the operatorship 

from BP. Kessog may be one of the eight HP/HT fields which stand to benefit from tax 

concessions offered in the pre-budget report last Dec. 


| 22

Field Kew 




Transport concept 3km pipeline to Chiswick or 14km pipeline to Markham? 


Comments: Centrica, as Venture has now become, plans to develop the Kew gas field 

following a successful appraisal well in 2009 – project sanction is scheduled for this year and 

start-up could be achieved by late 2011. Its base-case solution is a single subsea well. This 

may be tied back either to the nearby Chiswick platform or the Markham field centre in the 

Dutch sector – previously there were doubts that Chiswick, which is itself tied back to 

Markham, would have sufficient export capacity. 

Field Kraken 


Operator Nautical 

Development concept FPSO 



Comments: Nautical aims to select the concept for the development of the Kraken heavy oil 

field and submit a development plan by year-end following an appraisal well and an exploration 

well this summer. These wells will be drilled from the same tophole by semisub Ocean Nomad 

under the management of SPD. AGR and Senergy are assisting with concept evaluation. 

Development will be phased, with six wells initially to give production of 30,000b/d. These will 

be tied back either directly to an FPSO or to a fixed drilling/wellhead platform combined with an 

FPSO for processing. In either case export will be through offshore loading. Downhole pumps 

will be required. A CSEM – controlled source electromagnetic – survey was run over the field 

by OHM last autumn. An appraisal well in 2007 showed that, at 18ºAPI, the crude is 

substantially lighter than expected. A second appraisal in 2008 failed to find additional 

reserves. Nautical believes it can achieve the 30m bbl of recoverables which would make 

development economic – oil in place is estimated at 370m-1.2 billion bbl. The value of the 

asset has been substantially enhanced by tax advantages offered in the 2009 budget, the 

company said. 


| 23


Mariner 


Operator Statoil 




Comments: Despite tax advantages offered in the 2009 budget, Statoil has stuck to its 

decision to delay development of the Mariner heavy-oil field by a year – it now aims to seek 

sanction in mid 2011. Earliest start-up is 2015. In the interim the project has not been shelved 

but slowed. Concept selection is due to be made in Q3 after which FEED will begin. 

Development will require capital spending of $1.8 bn on facilities and $1.4 bn on drilling. 

According to a partner, the benefits of an early production system are enhanced by the budget 

proposals, and this is one of the scenarios under discussion. In 2009 semisub Stena Spey 

plugged and abandoned Broch exploration well 9/11e-14 without comment – the prospect is a 

possible satellite to Mariner. Development is expected to involve a fixed platform combined 

with export by offshore loading. Moreover, it could perhaps act as a hub platform serving 

several fields, according to Statoil. The company has acquired a 30% interest in three licences 

covering 9/12e and other nearby blocks through funding exploration activities – the Broch well 

was part of this deal. 

Field Montrose Satellites 




Transport concept Pipelines to Montrose: Cayley 10 km, Godwin 8 km; Shaw 8 km to 

Arbroath 

Start-up 2013? 

Comments: In Jan Talisman said it was examining development options for the Cayley, 

Godwin and Shaw discoveries in the Montrose area. Fiddich, which it previously planned to 

develop jointly with Cayley, has therefore dropped out of the frame. Subsea tiebacks to the 

Montrose/Arbroath infrastructure are presumably planned. A new platform is likely to be 

installed at Montrose to accommodate the tiebacks, and Talisman says that the 

Montrose/Arbroath facilities will be upgraded. 


| 24


Moth 


Operator BG 


Transport concept 2km pipeline to Lomond? 


Comments: In 2008 Oilexco North Sea made a significant oil/gas/condensate discovery with 

Moth exploration well 23/21-6 and a sidetrack, drilled by semisub Ocean Guardian. The well 

was drilled under a farm-in deal whereby Oilexco gained a 50% stake in the licence though BG 

remains the operator. The company said the field was capable of producing 44 MMcf/d of gas 

and 4,400 b/d of liquids. Premier, which has taken over Oilexco, says it is studying the Triassic 

potential in 23/22b to the east. An appraisal well on Moth is planned but it seems this will only 

come in 2011, thus pushing back likely start-up to 2012 or beyond. Moth is likely to be tied 

back two km to Lomond, also a gas/condensate field, where BG has taken over from BP as 

operator as part of an asset swap. A subsea solution seems most likely. 

Field Pi (NOR) 


Operator BG 


Transport concept Pipelines to Armada 

Start-up Oct 2011 

Comments: BG is seeking approval to develop the Pi field in the Norwegian sector as a 

subsea tieback to its Armada platform in the UK sector. Two wells will be drilled, one on Pi 

North and one on Pi South, and each will be tied back separately to a seabed manifold 

weighing about 100t close to the platform. The pipelines will be 8in/12in pipe-in-pipe systems, 

with the inner pipes made from 22Cr or 13Cr steel. The Pi North line will be 8.2 km long and Pi 

South 5.6 or 7.2 km depending on the route chosen. The manifold will be fitted with subsea 

multiphase flowmeters and a subsea isolation valve. A new 30in riser caisson will be installed 

on the platform jacket. Drilling and subsea installation are both scheduled to start in spring 

2011, and start-up is scheduled for the following Oct. 


| 25

Field Rochelle/Rubie II/Renee 


Operator Endeavour 


Transport concept 30km pipeline to Scott 

Start-up July 2011 

Comments: Endeavour has filed a field development plan for the Rochelle gas/condensate 

field with start-up scheduled for July 2011. It may not itself see the project through to 

completion as it is also considering selling off its North Sea assets. There will be two subsea 

wells, though the second is contingent on the first. These will be connected to a 100t, four-slot 

manifold which will be tied back to Nexen’s Scott platform by a 10in pipe in a 14/15in carrier 

pipe. The pipeline and umbilical will be separately trenched. Reserves are 161bcf of gas and 

4.3m bbl of condensate. Scott could also be the new host for Endeavour’s Renee and Rubie 

fields – these were previously tied back to Hess’s AH001 floater where production ceased in 

last year (see Ivanhoe/Rob Roy entry in Section 4). Endeavour says it will look at 

redevelopment of these fields when Rochelle is on stream. It previously planned to drill a new 

well on Rubie, for which it is understood that Cameron supplied a subsea tree. It also plans to 

drill an appraisal well on Renee. Renee lies about 10 km north-east of Rochelle. In Jan Nexen 

plugged and abandoned tight an exploration well on the Deacon prospect in the Rubie block, 

15/28. 


| 26

Field Rosebank/Lochnagar 


Operator Chevron 

Development concept FPSO? 

Transport concept Offshore oil loading + 45km gas pipeline to Laggan 


Comments: Chevron is preparing to develop the Rosebank/Lochnagar field west of the 

Shetlands. FEED is planned for 2011 and start-up looks likely around 2014 or 2015. The 

preferred development solution is in the process of being chosen. Chevron has confirmed that 

some kind of floater will be required, along with horizontal and high-angle production wells. The 

project will benefit from the government’s decision to grant an allowance worth £160m a field to 

deepwater WoS developments – water depth is 1,100 metres. Last year a contract for facilities 

engineering services was awarded to Houston-based Intecsea and a study for the application 

of its cylindrical FPSO to Sevan Marine. Metocean has been contracted to monitor sea and 

wind conditions on the field. Meanwhile appraisal is still under way: in 2009 drillship Stena 

Carron drilled exploration well 213/27-3 on Rosebank North and an exploration sidetrack on 

Lochnagar North, followed by Rosebank appraisal well 213/27-4 with three sidetracks of which 

the last was suspended. A further well is planned later this year. When it discovered the field in 

2004, Chevron hinted that it looked large, though it has released little information since. Of a 

three-well programme carried out in 2006-07, it has revealed only that one well, 205/1-1, tested 

light oil at a rate of 6,000b/d. Situated close to the UK/Faroes border, far from any 

infrastructure, and in deeper waters than any other commercial find in the UK sector, 

Rosebank/Lochnagar looks like a candidate for offshore oil loading. Gas will be exported via 

the Laggan multiphase pipeline (see Laggan entry). Peak gas volume will be 100 MMcf/d. 

Field Solan 

Area West of Shetlands 

Operator Chrysaor 

Development concept Articulated tower + subsea wells 



Comments: Chrysaor drilled a successful appraisal well on Solan in 2009, which increased 

reserves to 45m bbl of oil and has been suspended for use as a producer. The start-up target 

has been put back to Q3 2011. In Dec the environmental statement was published and the 

field development plan submitted. Contracts will be awarded once approval has been given. 

Semisub Byford Dolphin, which drilled last year’s well, is lined up for development drilling. 

There will be one subsea producer and one water injector at start-up, with a second producer 

and possibly a second injector to follow. The producers will be equipped with dual electric 

submersible pumps to lift the 27 deg API crude. The wells will be tied back to an articulated 

tower via a manifold and flexible riser. Oil will be exported by offshore loading. The platform will 

have a 750t topsides, and the tower, which will be roughly 130m tall, will be connected to a 

300,000 bbl seabed storage tank by means of a universal joint. The platform will be assembled 

in a Norwegian fjord and towed to the field. 


| 27

Field Staffa Redevelopment 




Transport concept 10 km pipeline to Ninian Southern? 


Comments: The Staffa oil field has been relicensed to Fairfield which plans to redevelop it 

almost certainly by means of a subsea tieback rather than with an FPSO. Discussions have 

been held with three potential hosts. The concept is due to be decided and sanction given by 

mid year. The closest platform is CNR’s Ninian Southern, at 10 km, which was Staffa’s original 

host. Total’s Alwyn platform is 15 km distant. Staffa’s original producing life was cut short when 

the pipeline was twice blocked by wax, asphaltene and emulsions. Fairfield has conducted flow 

assurance studies and is confident it can deal with potential blockages by pipeline insulation. 

Start-up looks likely in 2011 or 2012. 

Field Stella/Harrier/Hurricane 



Development concept Platform or subsea centre plus subsea tiebacks 

Transport concept 10km pipelines from Harrier and Hurricane to Stella 

Export pipelines from Stella to? 


Comments: In Apr Ithaca announced that it had successfully tested its appraisal well on the 

Stella HP/HT gas/condensate discovery in block 30/6a which flowed 2,850b/d; estimated 

reserves have been significantly increased – the pre-drilling reserves estimate was 18m boe. 

Prior to the well Ithaca already considered the field to be commercial. In late Apr it was 

preparing to drill a sidetrack, after which it would press ahead with development, it said. Ithaca 

has two HP/HT satellites lined up for tieback to Stella – Harrier (23m boe) to the south in 30/6 

and Hurricane (4.9m boe) to the west in 29/10b. Of possible hosts, ConocoPhillips’ Judy 

platform lies about 20 km to the south-east and Total’s Elgin about 25 km to the north-west. 

But neither may have ullage for several years, so Ithaca may have to provide its own 

production facility, such as a jackup platform, presumably on a leased basis. 


| 28

Field Vulcan East 


Operator Silverstone 


Transport concept Pipeline to Viking B? 


Comments: Silverstone’s project to develop the Vulcan East gas field will be launched this 

spring, with start-up scheduled for late 2011. Development calls for a single horizontal subsea 

well which will be hydraulically fractured. It will be tied back to nearby infrastructure in the V- 

Fields area, possibly the Viking B complex. In-place gas reserves are estimated at 160 bcf. At 

a later stage development will also be considered for the Vanquish discovery in the same 

region. 

Field Western Isles (ex Rinnes/Melville) 


Operator Dana 

Development concept Floater 

Transport concept Offshore oil loading 


Comments: Following its discovery of Melville, Dana’s exploration campaign on the Rinnes 

prospects led to significant finds at Rinnes East, Rinnes West and Rinnes South-East. These 

fields have been renamed Lewis, Harris, Uist and Barra and will be developed in a joint project 

known as the Western Isles development. The target start-up date is late 2012. Subsurface 

studies and conceptual engineering have been accelerated; both Genesis and Xodus are 

involved in this work. Production will take place through a floating production facility. There will 

be 12 subsea wells – six producers and six water injectors. The producers will be gas-lifted. 

Project sanction is now scheduled for late 2010. According to Dana, reserves are 65m boe. 

Field West Wick 



Development concept Extended-reach drilling 



Comments: Centrica is in discussions with Chevron about developing the West Wick oil 

discovery in the Outer Moray Firth – part of the Venture portfolio which it acquired last year – 

by drilling an extended-reach well from the Captain wellhead platform. The feasibility of such a 

well has been established. If agreement can be reached, the well could presumably get under 

way this year. 


| 29

Field **Wingate 


Operator Wintershall 


Transport concept 20km pipeline to D15-FA-1 (NL) 

Start-up October 2011 

Comments: Wintershall is seeking approval to develop the Wingate discovery in part-block 

44/24b with an unmanned platform with six well-slots. The field, which contains reserves of 116 

bcf, will be brought on stream through the discovery well recompleted as a producer. Then one 

well will be drilled a year until all slots are utilised. Production will be exported across the 

median line to GDF Suez’ D15-FA-1 platform in the Dutch sector by a 12in flowline with a 2in 

methanol line piggybacked on it. 

Field York 




Transport concept 0.5km pipeline to Cleeton trunkline 

Start-up Q4 2011/Q1 2012 

Comments: Having acquired the major stake and operatorship in the York gas field, Centrica 

plans to bring it on stream in late 2011/early 2012. Gas will be exported through a short link 

into the Cleeton trunkline. A hot-tap will be required to tie in the spur line, which will consist of 

six lengths of spoolpiece. The field, which consists of a southern and an eastern reservoir, will 

be developed with a small platform for which bids have been submitted. Two wells will be 

drilled, starting in July 2011. The platform and pipeline will be installed in spring/summer 2011. 

Conceptual studies have been performed by Genesis. Reserves are 115 bcf. 


| 30

3 Possible future projects 

One new entry (marked *). 

Field Alder 


Operator Chevron 


Transport concept 27km pipeline to Britannia 


Comments: Chevron has evaluated the development of Alder, an HP/HT oil and gas field, as 

a subsea tieback to Britannia. In recent presentations it has suggested start-up would take 

place in 2012, while according to partner ConocoPhillips, start-up is scheduled for 2014. Two 

subsea wells are planned as part of the $500m project. It is expected that Alder will be part of 

the second phase of the Britannia Satellites development. Alder may be one of the eight 

HP/HT fields which stand to benefit from tax concessions offered in the pre-budget report last 

Dec. 

Field Caledonia Redevelopment 


Operator Premier 


Transport concept Existing pipeline to Britannia 

Start-up -- 

Comments: Premier appears to have shelved plans to redevelop Caledonia in favour of 

divestment. In Jan it said it had agreed to sell its 100% stake to Velo Energy, which is headed 

by the former head of Oilexco. The Canadian company’s application to become a UK licensee 

was turned down by DECC in the first instance, but it has now been accepted as a non 

operating partner. So redevelopment of the field, as planned by Oilexco North Sea, which 

Premier acquired last year, is for the time being on the back-burner. Last year Premier held 

negotiations with Chevron concerning tariffs for the redevelopment of the field, which is tied 

back to Britannia, but whether an agreement was reached is not known. Oilexco’s plan was to 

redrill the existing well and drill one-three new producers. 


| 31


Culzean 


Operator Maersk 

Development concept Platform or subsea? 

Transport concept Pipeline to nearby infrastructure 


Comments: In 2009 Maersk announced a ‘promising’ discovery at Culzean, an HP/HT 

gas/condensate field. Assessment of possible development options was ongoing, it said in 

Dec. The field lies in part-block 22/25a, about 20 km from BP’s Marnock and Lomond platforms 

and 25 km from Shell’s Shearwater. Water depth is 92 metres, so a wellhead platform or 

subsea facilities could be relevant options. Culzean may be one of the eight HP/HT fields 

which stand to benefit from tax concessions offered in Dec’s pre-budget report. 


Flyndre UK/NOR 


Operator Maersk 


Transport concept 18 or 30km pipeline to Janice or Affleck? 

Start-up 2012 

Comments: Maersk is drawing up plans to develop the Flyndre oil field which straddles the 

UK/Norwegian median line in blocks 30/14 and 30/13a (UK) and 1/5 and 1/6 (Norway). In Feb, 

according to partner Noreco, the three licences were close to agreeing on a joint study to 

clarify the commercial potential and preferred development scenario. The concept will be 

selected in H1 and a development plan submitted in H2, Noreco says. Maersk says only that 

several development options are being considered. A subsea tieback to the Janice FPU, 

possibly via the Affleck subsea facilities, looks likely. 


Foinaven South-West 


Operator BP 


Transport concept 11km pipeline to Foinaven FPSO 


Comments: BP discovered oil with Foinaven South-West exploration well 204/23-2 in 2008. In 

Apr it confirmed it was still looking at a two-well subsea tieback to the Petrojarl Foinaven 

FPSO. The discovery well, which was drilled in a water depth of 168 metres by semisub Paul B 

Loyd Jr, was plugged and abandoned. Separately GE is studying the introduction of subsea 

processing and power from shore on Foinaven. In Apr Teekay announced that the FPSO lease 

had been extended to 2021. 


| 32


Maureen Redevelopment 




Transport concept Pipeline – 21 km to Andrew or 14 km to Varg 

Start-up 2011/12? 

Comments: Fairfield’s 16/29a-17 appraisal well on Maureen North-East last year failed to find 

commercial quantities of hydrocarbons. This may spell the end of redevelopment plans - the 

company said it would have to evaluate whether it still had a commercial project on its hands. 

This process was still under way in Mar. Development was previously planned to begin with 

Maureen North-East, which was believed to hold an estimated 27m bbl of oil in place, together 

with the underlying Morag reservoir. Funding of the well was largely taken on by Endeavour 

and Challenger Minerals under a farm-in deal. Fairfield also sees potential in the nearby Mary 

and Mabel fields – Mary has already been in production while Mabel is an undeveloped 

discovery. Fairfield’s preferred development solution was subsea facilities tied back either to 

BP’s Andrew hub or Talisman’s Varg in the Norwegian sector. Stand-alone mobile solutions 

were also evaluated. Maureen was originally developed by Phillips; it ceased production in 

1999 when 226m bbl had been produced. 

Field Monkwell 


Operator Dana 


Transport concept 10km pipeline to Cleeton? 

Start-up 2011 

Comments: Dana seems to be confident of developing the small Monkwell gas field – it has 

ordered a subsea tree and control system from DrilQuip which the supplier put on display at 

Offshore Europe last year. Start-up is scheduled for 2011. But first comes a crucial appraisal 

well, which jackup GSF Labrador looks like spudding in May. Assuming the well is successful, 

Monkwell will be developed as a subsea tieback to a nearby host – an agreement has been 

reached with the host, according to Dana. The leading candidate appears to be Cleeton, some 

10 km to the south-east, which already hosts several satellites. 


| 33

Field **Platypus 


Operator Dana 


Transport concept 25 km pipeline to Cleeton? 

Start-up 2012 

Comments: Dana has discovered some 130 bcf of gas with the Platypus exploration well in 

48/1a. In late Apr it planned to suspend the well and consider development options. The most 

likely host appears to be BP’s Cleeton field centre which lies about 25 km to the north-west. A 

simple development could probably be brought on stream by 2012. 


Polly 

Area Moray Firth, central North Sea 


Development concept Subsea or ERD 

Transport concept If subsea, 3km pipeline to Beatrice B 


Comments: Ithaca is preparing to develop the Polly discovery in the Inner Moray Firth using 

the Beatrice infrastructure. Whether development goes ahead depends on the results of an 

appraisal well to be drilled probably in Q3 – this may either be a subsea well or an extendedreach 

well from Beatrice B platform. The well will double as the single producer – if subsea it 

will be tied back to Beatrice B by a 6in pipeline. The northern part of Polly may be developed 

by a subsea well tied back to the Jacky platform. 


| 34

Field Sheryl 


Operator Sterling 


Transport concept 8km pipeline to Pict 


Comments: According to Sterling, which last year took back the operatorship of Sheryl from 

Oilexco North Sea, development has been awaiting capacity in Petro-Canada’s Pict pipeline 

system. Pict, which lies about 8 km from Sheryl, is tied into Hess’s Triton FPSO. A 

debottlenecking project on Triton, including an increase in the capacity of pipelines linking 

Petro-Canada’s fields to the FPSO, is due to be implemented this year, which will perhaps 

open the way for Sheryl. Other offtake options will be investigated, according to Sterling, 

though apart from other points of entry into the Triton infrastructure, there is nothing else 

nearby. Reserves are understood to be around 3m bbl, so the field could benefit from the tax 

break for marginal fields announced in the 2009 budget. Oilexco’s 65% stake is now held by 

Premier, which has agreed to sell it to Canadian independent Velo Energy. DECC has now 

given Velo, which is headed by the former head of Oilexco, permission to become a non 

operating partner in UK licences. 

Field Thoresby 


Operator Hansa 


Transport concept 12-35km pipeline to Waveney, Lancelot or Amethyst 


Comments: Hansa has acquired Serica’s interest in the Thoresby gas field, formerly known as 

Chablis, along with the operatorship. Subsurface studies are under way – Gardline has 

acquired high-resolution 2D seismic data and this, along with exiting 3D data, is being 

reprocessed to provide better understanding of the extent of the gas accumulations. CSL is 

assisting with concept selection. Development will involve a subsea tieback, either to an entry 

point into Perenco’s Lancelot pipeline system or to BP’s Amethyst – the Waveney platform lies 

some 12 km to the east and Lancelot 18 km to the north-east, while Amethyst is about 35 km 

to the north-west. A development decision is expected this summer. There is a small chance 

start-up could be achieved in late 2011, but 2012 is more likely. 


| 35


Triton Debottlenecking 


Operator Hess, Petro-Canada 


Transport concept 3km pipeline to Beatrice B 

Start-up 2011 

Comments: A debottlenecking project is being prepared for the Hess-operated Triton FPSO to 

enable increased production to be received from Petro-Canada fields which are tied back to it. 

The project is due to be sanctioned in H1. A new first-stage separator and sand management 

equipment will be installed and the control system upgraded. A new riser and riser base, plus a 

new umbilical and umbilical base, will also be installed – these will serve a new 8in pipeline 

which will be laid from Petro-Canada’s DC6 drilling centre to the FPSO. A 12in pipeline already 

runs between DC6 and the ship, carrying production from the Guillemot West western 

extension and the Clapham, Pict and Saxon satellites. The project may provide capacity for 

new tiebacks such as Antrim’s Fyne and Sterling’s Sheryl. The Triton FPSO also processes 

production from Shell’s Bittern field. 


| 36

4 Decommissioning projects 

No new entries. 


Don 


Operator BP 

Field facilities Seven subsea wells (five producers, two water injectors) clustered 

around a 52t manifold, 17.3km, 8in production pipeline to Thistle, 

8in water line, control umbilical, chemical injection umbilical 

Production end Jan 2003 

Comments: In Oct last year BP issued the second draft of the Don decommissioning 

programme for consultation. It proposes removing the subsea installations including the 

manifold and spoolpieces, leaving the pipelines and umbilicals in situ except where sections 

protrude above the seabed, and leaving the drill cuttings pile in situ. The indicative schedule 

sees well abandonment taking place between mid 2010 and end 2011 and removal operations 

and clean-up during 2011. Formal cessation of production was approved by the DTI in Jan 

2005. The first draft of the decommissioning plan was submitted in July 2008. 

Field Fife, Fergus, Flora and Angus 


Operator Hess 

Field facilities Leased FPSO, nine subsea wells (six producers, three water 

injectors), in-field pipelines and umbilicals 

Production end May 2008 

Comments: Production of Fife and the satellite Fergus and Flora fields through Bluewater’s 

Uisge Gorm FPSO ceased in May 2008. Angus, which is tied back to the FPSO via Flora, had 

already been shut down since 2006. The final cargo offload took place in June 2008, subsea 

and process equipment was flushed and the FPSO left the field in Sept. In Oct 2008 Technip 

support rig Orelia removed some flexible risers and umbilicals. In Nov-Dec 2009 Acergy 

subsea construction vessel Acergy Eagle removed some subsea items. The remaining scope 

will be combined with that for Ivanhoe/Rob Roy where production ceased in Mar 2009 – but no 

time-frame has been set for the work. Hess has taken ownership of the flowlines, umbilicals 

and risers which previously belonged to Bluewater. While preparing a decommissioning plan, 

Hess will leave the wells suspended for about three years in case another company sees value 

in redeveloping the fields. Premier says it is performing conceptual studies into redevelopment 

– Hess is not participating in these. If no-one takes up the opportunity, the wells will be plugged 

and abandoned. The final decommissioning plan will not be submitted until the possibility of 

redevelopment has been considered, Hess has said. 


| 37

Field Inde 


Operator Shell 

Field facilities 6 platforms, 26 wells, 4 pipelines, 2 hose bundles 

Production end Jan 2006 

Comments: Decommissioning plan approved Aug 2007. Shell has contracted AF Gruppen for 

onshore disposal and Seaway Heavy Lifting for platform removal, though it has only signed a 

full contract, worth £23m, with AF. The onshore disposal site has not yet been revealed. The 

subsea decommissioning contract has been awarded to Subsea 7. Dsv Toisa Polaris made a 

couple of visits to the field in H2 2009. Offshore removals will start this summer using SHL’s 

newbuild lift-vessel Oleg Strashnov. The topsides of the four smaller platforms – JP, L, M and 

N – will be removed by single lift, and those of the two larger platforms, JD and K, by multiple 

lift. The largest platform, JD, has a 3,028t topsides supported by a 1,108t jacket. There are two 

export pipelines, of 20in and 24in diameter, two infield pipelines and two infield hose bundles. 

The pipelines will be left in situ and the hose bundles retrieved; they have been disconnected 

from the platforms in preparation. Last autumn Dutch company HAK, assisted by BW Offshore 

production ship BW Carmen, performed pipeline cleaning. Abandonment of the 16 wells on the 

JD, K and N platforms has been completed by Halliburton using a rigless method. Offshore 

operations, including well abandonment, are being supported by Seafox jackup Seafox 1, 

which was fitted with a 300t crane for the assignment. Seafox 4 has also provided support. The 

four M wells were abandoned in 2006 by jackups GSF Britannia and Noble George 

Sauvageau, and the six L wells in 2007 by jackup GSF Monarch. 


Ivanhoe/Rob Roy 


Operator Hess 

Field facilities AH001 semisubmersible production platform, nine flexible risers. 

Each field has subsea wells – Ivanhoe five producers and three 

water injectors, Rob Roy six and three respectively – tied into a 

manifold. Both manifolds are tied back to a riser base manifold. 

Oil export by 41km, 14in pipeline to Claymore, gas export/import 

by 23km, 8in line to Tartan. 

Production end Mar 2009 

Comments: Production from the Ivanhoe and Rob Roy oil fields came to an end in Mar 2009. 

Decommissioning will be jointly planned with that for Fife and its satellite fields, though no timeframe 

yet exists for submitting the plan or performing the work. In July 2009 Petrofac bought 

the AH001 production platform, which is now parked at the McNulty yard. The platform, which 

has been renamed FPF-1, also served Hess’s one-well Hamish satellite, from which production 

has also ceased, and Endeavour’s Renee and Rubie fields, which may be redeveloped (see 

Rochelle entry in Section 2). 


| 38


Kittiwake SAL System and Pipeline 



Field facilities SAL system, weighs 200t, held in place by four built-in suction 

buckets. The pipeline consists of two lengths of flexible flowline 

totalling 2.9 km. 

Production end -- 

Comments: In 2009 Venture, now taken over by Centrica, received permission to remove the 

Kittiwake single anchor loading (SAL) system and pipeline. The equipment is on lease from 

Nordic Troll and Trym until Nov 2010, but the operator wished to start work last year with the 

retrieval of the flowline by Subsea 7 layship Seven Navica, which has duly taken place. The 

SAL system itself will be removed this year: it will be released from the seabed by pumping 

water into the suction buckets until they lift clear of the seabed, and then lifted to the surface by 

a crane-vessel. 


Miller 


Operator BP 

Field facilities PDQ platform with 28,100t topsides supported by 17,500t, eightleg 

jacket. 22 wells drilled. Three pipelines: oil export 8km, 14in to 

Brae A, gas export 242km, 30in to St Fergus, gas import 9km, 

16in from Brae B. 

Production end Sept 2007 

Comments: In Feb BP submitted the first draft of its decommissioning progamme, in which it 

proposes to leave the jacket footings in place. The programme is expected to come out to 

public consultation in about May. Comparative studies of decommissioning and disposal 

options have been prepared and these have been reviewed by consultant Xodus. Well 

abandonment was performed by the incumbent drilling contractor KCA Deutag between 

summer 2008 and May 2009; Schlumberger was contracted to provide cement services, Expro 

for plugs and perforating services and Norse Cutting & Abandonment to cut all casing and 

conductors. The platform was installed in 1992 – the jacket was barge-launched and the 

topsides lifted on in eight major lifts, the largest being the 6,500t cellar deck. The field officially 

ceased production in Sept 2007. 


| 39


Shelley South 


Operator Premier 

Field facilities FPSO Sevan Voyageur, two subsea wells, a 38t mini-manifold 

with 122t protection structure, a 2km, 8in production pipeline, 

control umbilical and flexible riser.. 

Production end Q3 2010 

Comments: Although the field only came on stream last Aug, production has been 

disappointing and Premier expects it soon to become sub-economic – production will cease in 

Q3, according to Sevan. When this happens, Sevan, as owner of the FPSO and its mooring 

system, will be responsible for removing the platform from the field. Premier proposes 

retrieving all the subsea equipment but leaving the pipeline, which is trenched and rockdumped, 

in place. It recommends retrieving the umbilical in several sections. Offshore 

operations are expected to take place this year and in summer 2011. 


Tristan North-West 


Operator Silverstone 

Field facilities One subsea production well, 15km, 6in production pipeline with 

umbilical piggybacked on it, to Davy platform. 

Production end 2010 

Comments: Silverstone has decided to end production at Tristan North-West. In the draft 

decommissioning programme submitted in Feb, it proposes retrieving the tree, wellhead, 

spoolpieces, jumpers and sections of the pipeline and umbilical lying above the seabed, while 

leaving in place the buried pipeline and umbilical, which is the case for most of their length. 

Offshore operations are scheduled for Aug and Sept. A turnkey decommissioning contract has 

been awarded to CSL. Helix Well Ops has been subcontracted for well intervention, 

abandonment engineering and diving services, using its well intervention vessel Seawell, while 

BMT Cordah is responsible for environmental management services. In addition to the 

production well, there is a suspended well to be abandoned, which is the 1987 discovery well. 

Tristan NW was expected to continue producing until 2013, but has performed disappointingly 

since it came on stream in April 2008. 


| 40

Field Welland 


Operator Perenco 

Field facilities 1,000t topsides, 570t jacket, two platform wells, three subsea 

wells, in-field flowlines and umbilicals, 18km export pipeline 

Production end 2002 

Comments: Although production from Welland ceased in 2002, decommissioning did not take 

place under the then operator ExxonMobil as some reuse possibilities existed. In 2007 the 

platform passed to Perenco’s ownership. Reuse is no longer viable as the export pipeline has 

been disconnected at Thames. Perenco, which has extensive southern basin assets, is 

preparing an overall decommissioning strategy before deciding what to do with Welland. The 

abandonment of the two platform wells, one of which was drilled into the Tristan field, may take 

place this year. The platform and subsea equipment will have to be removed but the pipelines 

and umbilicals could be left in place. 


| 41

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INTSOK, Stavanger 

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NO-4068 Stavanger, Norway 


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Update on UKCS Field Development Projects - Intsok

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