North Sea rolls on

Strong prices spur investment in North Sea prospects.

The North Sea anticipates one of the busiest years in its history with a host of projects ranging from huge development off Norway to consolidation off the United Kingdom.
Some of the North's Sea's major players have strongly indicated they intend to be here for some time. BP promises to put at least US $750 million (£500 million) into the Clair project. During 2000, the company pledged to spend $4 billion (£2.85 billion) offshore the United Kingdom, Norway and the Netherlands during the next 4 years. Shell will spend more than $1.2 billion (£800 million) in 2001, and Conoco has committed to $1 billion (£713 million)
this year.
Some big schemes have been completed, and in the case of TotalFinaElf's (TFE's) Elgin/Franklin project, some pretty big challenges surrounding high-pressure, high-temperature (HP/HT) reservoirs have been tackled as well. Sadly the same cannot be said for Shell's prestigious Shearwater project nearby, which was still not back in production after 8 months of work to control an HP/HT well.
Engineers at Phillips Petroleum held their breath at the end of June as the Maureen platform, designed to be refloated, did just that in a successful operation. The 110,000-tonne facility is back at Aker Stord in Norway, where the company awaits a decision on reusing the platform.
Environmentally friendly
UK Energy Minister Brian Wilson recently was appointed to head a review of UK energy policy. He said a reduction in carbon emissions is a key aim of the policy review. Wilson conceded gas could become an increasingly important element in UK energy supply but added emissions must be cut.
UK Offshore Operators Association (UKOOA) members have created a trading scheme for flaring emissions transfers involving 10 operators and 55 fields in the North Sea. And in Oslo, a white paper is encouraging more power generation onshore and reduction of emissions on platforms.
Further progress has been made on other sustainable issues through talks exploring t prospect of operating the North Sea as one single offshore industry, rather than several sectors operated and separated by companies split across national boundaries.
At the beginning of the year, a report from the Pilot project said an extra 2 billion to 4 billion bbl of oil could be won from existing UK Continental Shelf fields and production sustained at 3 billion boe until 2010 by re-engineering existing production platforms and enhancing oil recovery. The report - titled "What's Possible?" - spelled out future targets during the next 9 years and listed several initiatives designed to extract more oil and gas from existing infrastructure.
Investment
The latest edition of the UK Department of Trade and Industry's (DTI's) Brown Book featured projections of future expenditure levels, based on information supplied by operating companies.
These figures indicate a 75% fall in spending on sanctioned, probable and possible field developments on the UK Continental Shelf from about $6 billion (£4 billion) this year to $1.5 billion (£1 billion) by 2004. However, spending intentions exclude allowances for new discoveries, new exploration and appraisal and decommissioning costs.
"Comparison with previous DTI surveys shows a considerable increase in optimism compared with the 1999 survey, with total intentions in the future 5 years some 30% higher," the book reported.
In the total expenditure forecast, however, is a $7.9 million (£5.6 million) market in the offing for sanctioned field developments, $17.3 million (£12.3 million) if the figures for sanctioned, probable and possible fields during the 5 years are taken together.
Future projects
Turning to the projects themselves, European-based contractors were watching the market for a host of new bids coming out at the start of the year.
Several were expected from Shell, including Kestrel, a gas-lift line for another Guillemot satellite, Skye, Penguins and Goosander. Not all have materialized as firm projects, although Shell's subsea solutions group is working on Kestrel, having first tried the Satellite Accelerator approach.
A year ago, Shell unveiled plans to invest $1.2 billion (£800 million) in the North Sea during the coming year, and Goosander and Penguins were mentioned then as part of those investment plans.
BP is still big on the UK Continental Shelf too, and it has a clutch of discoveries
rolling forward.
Redevelopment of the Forties field has been mooted with suggestions of a fifth new steel platform being discussed, and the company is also working on linking its North Sea platforms by fiber-optic cable. This could be the biggest North Sea opportunity this year from BP, but the company has other projects.
Two HP/HT fields, Rhum and Devenick, have been successfully drilled, and the company added the Atlantic gas and condensate discovery in the Outer Moray Firth to its portfolio this year.
In the same strategy briefing in which he indicated intentions to redevelop the Forties field last year, Sir John Browne, the BP chief executive, suggested the company could spend $1 billion (£713 million) a year on new projects in the North Sea during the next 4 years.
BP drilled an appraisal well on Rhum earlier this year, and it will test Devenick this summer. Devenick followed success with an Outer Moray Firth well on the Atlantic gas and condensate prospect.
These three finds will underpin BP's North Sea spending during the next 4 years. Up to 1 Tcf of gas could be contained in these finds, the operator said, including gas in surrounding areas.
Devenick is 7 miles (12 km) southeast of Harding in blocks 9/24a and 9/29a. It is undergoing appraisal with a well in Block 9/24a drilled by the Paul B Loyd semisubmersible for which Brøvig Production Services was awarded a $1.5 million (£1 million) production test contract earlier this year
BP completed a well in February on Rhum in Block 3/29a with the Paul B Loyd semisubmersible. Later, after 5 months of drilling and testing at up to 45 MMcf/d of gas from Upper Jurassic sands at a depth of 15,421 ft (4,700 m), BP said: "Recent re-evaluation of the potential of the reservoir, technical advances in high-pressure, high-temperature drilling and support from the Iranian Oil Co. has led to this successful appraisal of the field."
Moreover, the company will consider Rhum for satellite development tied to an existing platform later this year, after further evaluation of well data. Bruce is the nearest BP-operated platform, directly south in Block 9/9.
Following the $157 million (£100 million) takeover of Petrobras' UK assets, it seemed likely from the statement issued by new owner Enterprise Oil that several of the fields in the Petrobras portfolio could come forward.
Blane, Ettrick, Enoch and J1 have been the subject of talks and discussions for several years. Petrobras UK had been moving slowly toward turning those four prospects into firm projects with appraisal drilling planned for next year.
Blane has undergone two flow tests: the first produced 5,400 b/d of oil with the 30/3a-1 well, and a second produced 6,900 b/d from good quality sands in the primary Forties sandstone. Field reserves are put at 37 million bbl on a P10 potential basis, and 24 million bbl on a P50 probable basis.
At the same time, talks over unification of the field are awaiting a settlement with the owners of the field's Norwegian sector.
On the Enoch/J1 prospect, asset partner Bow Valley said BP and Marathon, owners of the Miller and Brae platforms, have expressed interest in providing a host facility for subsea development of Enoch.
Blane and Ettrick were due to be developed by 2005, according to statements by field partner Bow Valley.
Walter DeBoni, president and chief executive of Bow Valley, said previously that despite the decision of Petrobras UK to sell its assets, work on the four discoveries is still active. "I would not be surprised to see a Blane well drilled before the end of this year," he said. DeBoni added development planning on Enoch and J1 was under way and that the technical work completed on Ettrick had "led us to be very upbeat about the potential there."
Amerada Hess stepped into the news in April when it farmed into a 50% stake in the Chestnut heavy oil field and took over as operator from Premier Oil just as an extended well test on the field was due to start.
Drilling of a further water injection well at the field in Block 22/2a is being considered to enhance oil recovery and allow full production through a floating production, storage and offloading (FPSO) vessel supplied by Brøvig Production Services.
TFE is in the frame for another new North Sea project too. It confirmed it was looking for a stand-alone solution for its 100 million-boe Glenelg prospect because the HP/HT field was too technically challenging to be tied back to the nearby Central Graben Elgin field, which came onstream in the summer.
Michael Contie, managing director of TFE UK, revealed a stand-alone facility would be necessary if Glenelg were to be exploited, and a first production date of 2005 was mooted as part of a 4-year, $1.5 billion (£1 billion) investment forecast.
Another prospect, West Franklin, is targeted for drilling next year and will form part of the French major's investment plans for the North Sea .
Norway
Invitations to tender for Statoil's complex HP/HT $1.6 billion (NKr 14.9 billion) Kristin project have been issued with a bid deadline set for September. A contract award then can be signed after the development plan is approved Dec. 17.
The topsides on the Kristin platform look to be split into three contracts. Statoil will award engineering, procurement and construction (EPC) contracts for the process and utility modules, in addition to the flare stack.
Statoil then will go out with separate tender invites for EPC contracts for the riser balcony module, which will weigh 4,100 tonnes, in addition to one contract for the 1,560-tonne living quarter. The deck will weigh 17,700 tonnes. The operator will contract the 13,700-tonne hull to a yard in the Far East. It will have an operational displacement of 55,000 tonnes.
However, the project depends on being granted gas deliveries under existing contracts in competition with BP's Skarv development, which is also targeting an onstream date in 2005.
Kristin will be produced via a semisubmersible platform hooked up to 12 wells on four subsea templates, with each template having a spare slot for future satellites. Gas will be exported to the Åsgard B platform and condensate piped to the Åsgard C storage vessel.
The semisubmersible platform will take in two satellites to prolong field life. These include Tyrihans, Lavrans and Ragnfrid. Ten riser connections will be set aside on the platform for this purpose.
Engineering of the subsea equipment will start in November and finish by April 30, 2002, according to plans presented by Statoil project engineer Roald Sirevaag.
Fabrication of the templates is due for completion March 30, 2003, and installation by May 30, 2003.
Eight of the 12 producers will have to be drilled in advance due to problems with pressure dropping. The last four wells will be drilled later. Two mobile units will be used to drill the wells.
The first phase of predrilling will start at the end of May 2003, using one drilling unit, and continue until April 30, 2004. Manifolds, flow lines and umbilicals will be installed between May 1 and July 31, 2004.
The second phase of the predrilling is scheduled for completion by Sept. 30, 2005. Installation of risers will take place between March 1 and June 30, 2005.
Kristin will require 23 miles (37 km) of flow lines, 6 miles (9 km) of 3-in. service lines, 15 miles (24 km) of 12-in. carbon steel condensate export pipelines and 17 miles (27 km) of 18-in. carbon steel gas export pipelines. The need for umbilicals will total 13 miles (21 km).
Pipelines will have to be designed for a production of 177 Mcf/d of gas and condensate for each of the six pipelines in addition to 53 Mcf/d of water.
Prequalification documents have been issued for flexible risers.
Reservoir temperature in Kristin is about 328°F (165°C), and pressure is 13,050 psi. The development will therefore require a minimum of 4 miles (6 km) of pipelines in order to cool the well stream to 265°F (130°C).
The valve tree and Christmas tree will have a maximum shut-in pressure of 10,730 psi and a well kill pressure of 11,600 psi. Operational pressure for the downhole valve will be 13,258 psi.
The valve tree and Christmas tree are being qualified for capacities of 15,000 psi and 350°F (176°C). Various choke valves have been tested, and other parts of the control system are being tested.
Production startup is aimed for June 1, 2005, with gas deliveries starting Oct. 1, 2005.
Kvitebjørn
Statoil's Kvitebjørn field project looks to be bigger than planned with the reserves and development costs being adjusted upward.
The operator wants to recover gas and condensate volumes in the field's flank areas discovered after a remapping and include them in the development. In the original plan, Statoil estimated Kvitebjørn held recoverable reserves of 1.7 Tcf of gas and 105 million bbl of condensate, but it adjusted those figures to 1.8 Tcf and 135 million bbl.
According to Statoil project manager Bjarne Bakken, the increase means 11 wells will be drilled instead of nine. These also will be placed differently. "We also need more time to prepare each well because the well tracks will be longer," Bakken said.
This brings the investments for the project up by $57 million (NKr 500 million) in 1999 value, but the platform concept will not be changed, Bakken said.
Total investment in the Kvitebjørn field, including oil and gas trunk lines and hookup to the gas treatment facilities at Kollsnes in western Norway, is $1.15 billion
(NKr 10 billion).
The operator submitted a revised development plan to the Norwegian Ministry of Petroleum and Energy (MPE) Feb. 16.
ABB Offshore Systems (Umoe Oil & Gas) won the $230 million (NKr 2 billion) EPC contract for the 9,000-tonne Kvitebjørn deck in June 2000, while Aker Verdal secured the $70 million (NKr 600 million) EPC contract for the jacket.
First gas from Kvitebjørn will be delivered in October 2004.
Possibly by 2007, gas from Norsk Hydro's $2.7 billion to $3.3 billion (NKr 25 billion to NKr 30 billion) Ormen Lange project in the Norwegian Sea could be onstream.
This summer it was delayed by a year following the need to carry out more assessments before a concept choice is made.
The operator was aiming to submit a development plan to MPE next summer but has delayed this until autumn 2003. First gas is scheduled in autumn 2007.
Further details of the project, including types of contract and schedules, were presented at a briefing in mid-June.
Three development concepts are being evaluated:
• a subsea solution with gas piped directly to land;
• a deepwater platform with minimum processing facilities linked to a land terminal; and
• a deepwater platform with full processing facilities.
However, common to all the concepts is a need to find a solution for installing a gas export pipeline. This 30-in. carbon steel line will have to be installed in the Storegga slide area in water depths ranging from 2,800 ft to 3,280 ft (850 m to 1,000 m) with slide blocks up to 330 ft (100 m) high. Pipeline costs are estimated at $133 million (NKr 1.2 billion).
Hydro is considering a pipeline to Poland in order to sell Ormen Lange gas, but the United Kingdom also is a likely export option. A screening study is examining the possibility of taking Ormen Lange gas through the CATS system and the Theddlethorpe gas terminal because the United Kingdom is forecast to experience growing need for gas from 2010.
Studies carried out for the Ormen Lange project include a feasibility study by ABB Offshore Systems on the use of subsea processing. ABB also is studying the use of lightweight risers.
Coflexip Stena Offshore is looking at using flexible pipe, while Reinertsen Engineering is working on the gas trunk line.
Kværner Oil & Gas is investigating use of a semisubmersible platform with either full or minimal processing offshore. Installing a semisubmersible in shallow water is another option.
Aker Maritime has been looking at the use of a spar buoy, including full and minimum processing, and a tension-leg platform with minimum processing, while Saipem and Heerema Marine Contractors are studying pipeline installation options.
Total reserves are estimated at 13.8 Tcf of gas, but two wells lined up to be drilled on Ormen Lange this year could add significantly to the reserves. This includes oil, which was discovered in a thin layer in August 2000.
Another major ongoing platform project in Norway is Hydro's $1.5 billion (NKr 14 billion) Grane development in the northern North Sea.
Kværner is fabricating a topsides and utility modules for the project at its Rosenberg yard in Stavanger. The contractor's Egersund yard is building the 11,000-tonne production module.
Aker Maritime has been contracted to build the jacket and piles at the Aker Verdal yard and the drilling package at the Stord yard.
European Marine Contractor came out on top of the battle to win the $44 million (NKr 400 million) installation contract for the Grane pipeline. The plan involves an 18-in., 31-mile (50-km) gas pipeline between the Heimdal and Grane platforms and a 28-in., 127-mile (204-km) oil pipeline between the Grane and the landfall tunnel at Hjartøy in Øygarden, 25 miles (40 km) north of Bergen.
EMC will use its Castoro Sei installation vessel for the job, which will be carried out next summer and autumn. Grane is estimated to hold 700 million bbl of oil and will reach a maximum output of 214,000 b/d in 2005. Capital investments in the project are estimated to be $1.6 billion (NKr 15 billion).
Meanwhile, BP was due to award a concept screening study for its $1.4 billion (NKr 13 billion) Skarv oil and gas development in the Norwegian Sea by the end of June.
A front-end engineering and design contract is aimed for signing late this summer. Contract awards for the project, for which the base case scenario involves using a production vessel, have been envisaged for the second quarter of 2002.
The positive outcome of the recent Skarv appraisal firmed up the reserves in the area and boosted the likelihood of using an FPSO to tap the field.
BP is keen to start producing Skarv oil by 2004 and gas in 2005 with a stand-alone solution. However, the project faces a fierce fight with Statoil's Kristin project for gas allocation and for an export route through the Åsgard Transport system. The Åsgard pipeline, stretching to the Kårstø treatment plant north of Stavanger, will reach its maximum capacity with either of the two projects going through. But it is possible to increase the pipeline capacity by boosting and rerouting the gas.
BP is pushing its project ahead, trying to beat Statoil to first production.
The operator's base case scenario for Skarv involves an FPSO with 25 to 30 wells tied back to the vessel, using wet trees to tap reserves of 117 million bbl of oil, 1.7 Tcf of gas and 40 million bbl of condensate. But this could be altered, depending on results from ongoing and upcoming appraisal wells.
Nine wells will be predrilled before production startup. Peak production would be 100,000 b/d of oil, which would be offloaded via shuttle tankers. Gas would be sent through the Åsgard Transport pipeline.
Skarv (oil and gas) and Gråsel (oil) will be tapped via 13 oil producers, five gas producers and four injectors. The Snadd (gas) structure will be produced from two wells.
Capital investment stands at $1.44 billion (NKr 13 billion), of which 50% will be plowed into the FPSO and the remainder split between the subsea part and drilling.
Another subsea development concept under evaluation would involve using Statoil's Heidrun platform, 28 miles (45 km) south of Skarv, as a tieback host.
The Skarv area is in water depths between 984 ft and 1476 ft (300 m and 450 m) and consists of Skarv A, Skarv C, Gråsel and the Snadd structure.
BP is looking at spudding two new wells in the southern part of Snadd. It also is evaluating a new well on Snadd Nord if the partners in the 212 and 262 licenses agree. Tying Statoil's nearby Idun discovery to an eventual Skarv FPSO also is under consideration.
BP applied for gas allocation in late 2000, and a firm decision on the development concept could be made this autumn, with a development plan being submitted to the MPE in early 2002.
Norsk Hydro is working hard to get the second phase of its $466 million (NKr 4.2 billion) Fram/Fram West development in the North Sea up and running. This project, which involves tapping 100 million bbl
of oil and 124 Bcf of gas that will be reinjected into the reservoir for the first 6 years, is estimated to hold half of the reserves in the Fram area.
Hydro believes the remaining reserves are in three reservoirs: Gjøa, which holds oil and gas, and Camilla and Belinda, both high-temperature reservoirs.
Gjøa might be developed using a two-phase separation with gas piped to the Kollsnes treatment plant onshore and oil and gas piped 4 miles (6 km) to the operator's Troll C platform.
The Camilla and Belinda gas structures then could be tied to Gjøa later.
Furthermore, Hydro is working to develop the Fram East Sognefjord and C West Sognefjord (Etive) structures, which could become a stand-alone development with wells tied to Troll C.
The Fram West pipeline will be routed across the rest of the Fram field, paving the way for a subsea tie-in solution for the Gjøa, Belinda and Camilla structures.
However, if all of the above are developed, it will take up 40% to 45% of the gas capacity on Troll C, which can produce 353 MMcf/d.
The Fram reservoirs Sognefjord and Etive probably can be developed without new technology, but the Sognefjord reservoir might require multiphase pumping.
Subsea power distribution will be a primary challenge. But subsea gas-boosting facilities for gas injection will increase the field's development flexibility.
ABB, Alsthom, Kværner, Roxar and Halliburton are involved in the process of qualifying equipment. Kværner Eureka has been prequalified to deliver multiphase pumps and gas compressors.
The second phase of Fram will require capital investments of about $537 million to $645 million (NKr 5 billion to NKr 6 billion). Hydro evaluated several development concepts for the Fram area, also called Sogn, involving a Visund- or Njord-type platform and subsea concepts, but this proved uneconomical.
Aker Maritime came out on top of the battle to modify the Troll C platform and fabricate a module for Fram West in a deal worth $56 million (NKr 500 million).
The contractor will carry out engineering, construction and installation of the production module to be fitted on the Troll C platform, which will process oil from Fram West.
Aker's agreement is the first of several contracts to be awarded for the $451 million (NKr 4.2 billion) Fram West project, which the operator aims to have onstream in October 2003.
Fram West is 12 miles (20 km) north of the Troll C platform in 1,181-ft (360-m) waters. It will be developed with two subsea well templates and four wells. The templates will be connected to Troll C with two flow lines, one for gas injection and one for production, and a control cable. The well stream will be sent to a three-phase separator on Troll C.
Mærsk moves Halfdan forward
A.P. Møller (Maersk) is in the midst of awarding contracts for Phase 3 of its Halfdan project on the Danish shelf under a development estimated to need investments of $525 million (DKr 4.2 billion).
The third phase involves expansion of the field facility, installation of three platforms and drilling of 22 additional wells. This will increase the field's production capacity from 31,000 b/d to a peak of 100,000 b/d in 2005, with the number of wells being increased from 24 to 46.
The work for this fast-track project involves extending the central platform at the field with a facility for processing and compression of gas and a facility for processing produced water. This 5,200-tonne process module will be fitted on top of the jacket installed last year.
Invitations to tender for the process module were issued at the end of April with contract signing taking place this summer. It is due to delivered in early 2003.
A new 5,000-tonne wellhead platform (WHP) also will be installed about 1 mile (2 km) northeast of the central platform. Invitations to tender for the WHP landed on contractor desks in mid-March, and a contract was due for signing this summer. This contract involves fabrication of a deck with manifolds weighing 2,000 tonnes, a 1,000-tonne jacket and piles weighing 2,000 tonnes. Delivery is planned for mid-2002 if the contract is signed this summer.
A new accommodation platform and a flare tower tripod bridge-linked to the central platform also will be required for the third phase.
The accommodation platform will weigh 1,600 tonnes and is planned for delivery in early 2003.
The third phase involves 11 additional wells with 9,843-ft to 16,405-ft (3,000-m to 5,000-m) horizontal sections for oil production and 11 related water-injection wells.
Several exploration and appraisal wells have been drilled at the Halfdan field and surrounding area during the past year, including the Halfdan-1X oil discovery well and Skjold-30, Lily-1X and Valdemar-5 probes.
Production on the 3,500-tonne, four-legged Halfdan platform started at the end of 2000. However, first oil began flowing in March 2000 from three wells producing temporarily via facilities on the Mærsk Endeavour drilling rig.
Halfdan was discovered in spring
1999, and it took less than 18 months to plan, construct and install the first facilities.
Bladt Industries was contracted to build the 3,000-tonne jacket and 1,000-tonne minimal deck at its Ålborg yard in Denmark under a $173 million (DKr 1.5 billion) deal. The platform contains a wellhead area fitted to take in 32 wells, which are to be remotely controlled from the Gorm platform.
The future
In 10 years it's conceivable North Sea production totals might not be too far from what they are today.
So many new schemes coming forward in the Norwegian and UK sectors will seek to exploit oil or gas deposits that have been newly found or have needed some new technology to become economic.
Admittedly many are smaller projects - the average discovery size in the North Sea is about 30 million boe. And many are hostile reservoirs with HP/HT features, such as Phillips Petroleum's Jade project, due onstream by the end of 2001.
Other phased projects will take small steps forward.
Ormen Lange gas could be delivered to markets by 2006. Clair, Fram West, Goldeneye, Goosander, Kestrel and Rev could be up and running by then.
And given the amount of exploration effort under way in the United Kingdom, Norway, Denmark, the Netherlands, the Faeroes, off Ireland and west of Britain - backed by a healthy oil price - it's likely that still more discoveries in the coming years will keep operators and contractors busy with project bids.