OFFSHORE EUROPE: Deepwater gas developers studying subsea separation and compression

Aug. 1, 2001
Subzero conditions and submarine slide path
Local bottom topography taken from ROV survey.
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Although Ormen Lange will not come onstream for several years, this giant gas field in the inhospitable Norwegian Sea already commands an immense work effort to prepare the way for development. In June, the schedule was extended by the best part of a year. This means that the plan for development and operation will now likely be submitted in 3Q 2003, and startup will take place at the earliest in 2007.

This year, no less than 350 man-years will be devoted to the project, according to Thor Tangen, project director and senior vice president at Norsk Hydro, which has responsibility for the development phase. Hydro is working closely with Norske Shell, which will operate the production phase and take over responsibility for subsurface activities once the project is approved. Shell personnel form part of the project team, which has adopted an integrated reservoir-to-market approach to its task. Cooperation between the two companies is going well, Tangen says.

Ormen Lange, discovered in 1997, contains some 390 bcm of gas, making it Norway's second largest gas field, after Troll. Development is estimated to cost $2.7-3.2 billion, plus an additional $0.5-1.6 billion in related infrastructure. Daily gas production will be of the order of 50 MMcm. Stretching some 50 km north to south, the field lies in the M re Basin off Mid-Norway in water depths of 850-1,100 meters, more than twice the depth of any field developed to date in the Norwegian sector. The temperature of the water in the 300-400 meters above the seabed is less than zero, thus creating flow assurance challenges.

The field lies directly under the path of the Storegga slide, which occurred some 8,000 years ago, when a large land mass, estimated at 6,000 cu meters, slid from the Mid-Norwegian mainland 800 km into the sea. Therefore, there are concerns about the stability of the seabed and the risk of future slides.

Development concepts

Possible development concepts have now been narrowed down to two, neither at present carrying special preference, Tangen says. The options are:

  • Processing platform located on the field and exporting processed gas
  • Subsea facilities, possibly combined with a small platform, tied back to a processing plant onshore.

Technology development will be crucial to the chosen scheme's success. Hydro is sponsoring no fewer than 12 relevant technology projects, all of which are also receiving funding from the Norwegian government's Demo 2000 program. Hydro alone has an Ormen Lange-related R&D budget this year of NKr 50 million. - Location of Ormen Lange field.

A processing platform on the field, which would have to be some kind of floater, would export processed gas and condensate separately, thus bypassing flow assurance problems in pipelines, though not in the risers carrying the wellstream from the seabed up to the platform. Deepwater risers also are subject to phenomena such as vortex-induced vibration.

This solution, unlike the subsea option, means that the gas would not be landed in Norway. Landing the gas has the advantage that the costs of an onshore processing terminal could be shared with other users. There would clearly also be economic and social benefits for the region where the terminal would be located.

Problems with flow assurance could be minimized by removing the water from the wellstream before sending it ashore. This could be done by a minimum facilities platform, or possibly by the emerging technology of subsea separation. A key question facing the project, Tangen says, is the advancement and credibility of the new technology by the time the decision has to be made whether to use it. Stretching out the project timetable allows more time for the technology to mature.

Hydro has the only installed subsea separation system in the world, in the shape of the Troll Pilot, but owing to problems in the power supply, operational experience with this unit has so far been limited. Subsea separation on a larger scale is also dependent on the subsea supply and distribution of large amounts of power. The technology is being developed but is at present unproven.

As reservoir pressure decreases over time, a subsea solution will also require subsea compression, another unproven technology. The recent award of a contract to Kværner to develop and supply a subsea compression module for Hydro's Fram West development in the North Sea is a move of direct relevance to Ormen Lange.

Even if these various developments create sufficient confidence in the new technologies, a subsea solution will also have to provide a better economic solution than the alternatives. At present, no one really knows what subsea separation and compression will cost, Tangen points out.

Pipeline installation

Running a large-diameter export pipeline - probably sized at around 30 in. - from Ormen Lange also presents challenges, as the seabed in the vicinity of the field is both rugged and rolling, with "hills" up to 60 meters high. Various novel solutions have been proposed, such as a pipeline kept afloat with buoyant foam, and tethered to the seabed at intervals. Three pipelay contractors - Coflexip Stena Offshore, Heerema Marine Contractors, and Saipem - currently are conducting studies of the pipelay requirements and their ability to meet them.

One solution could be to take a winding route avoiding the seabed hills and valleys and minimizing the number and lengths of free span. The most suitable installation method appears to be the J-lay technique, which could achieve the short lay-radii required. As this technique also involves lower tension in the pipe during installation, power requirements on the lay-vessel would be reduced, along with the cost.

A tunnel through the seabed could also be part of the solution. This has been proposed for a section at the top of the ridge formed by the Storegga slide, where the water depth is about 300 meters. Here the seabed topography is difficult and the area is important for fishing. The feasibility of a tunnel, and in particular the drilling technology involved, is being studied.

The fact that drilling will take place and facilities will be installed on the seabed in the slide area makes it important to eliminate the possibility, however remote, that a further slide could take place, perhaps triggered by development activity. Geological models have been made of the area, and the seabed has been charted with the aid of echo sounders, 2D and 3D seismic models, side-scan sonar, and geological and geotechnical drilling. A dedicated group within the project team is responsible for calculating stability and risk, and documenting that the area is safe for development.

Potential landfall locations for a pipeline to shore are being studied. In June, a shortlist of four locations was drawn up from an original 14 possibilities. Whether gas is processed offshore or onshore, a pipeline will be required to deliver it to the market. This could link in with the existing network in the North Sea, or go all the way to consuming countries, either in Continental Europe or in the UK - or both.

Whatever the solution, a large investment will be required, but again Hydro sees an opportunity for synergy with other users. The only gas export route from the Norwegian Sea at present is the Åsgard Transport System, but with capacity in this line already largely accounted for, it is not an option either for Ormen Lange or for future gas developments yet to take shape.

Marketing framework

Location of Ormen Lange field.
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The marketing framework for Ormen Lange changed in June with the government's decision to abolish the Gas Negotiating Committee (GFU) and pass marketing responsibility to licensees. This change was expected to come sooner or later, following the introduction of the European Union's gas liberalization directive, and Hydro, which markets energy products such as crude and electricity, sees no problems in adapting to the new system.

However, the directive creates pressure in favor of short-term contracts rather than the long-term deals under which Norway has sold its gas in the past. For such a large field as Ormen Lange, involving a huge capital expenditure, it is clear that a certain level of commitment on the part of purchasers is required if the licensees are to have the confidence to undertake the investment. A significant proportion of the gas will have to be sold in advance even though it is not necessary to sell it all to make the project fly, Tangen says.

Another appraisal well is to be drilled by semisubmersible Scarabeo 5. This was due to be spudded in July or August, but because of the rig's other commitments, now looks unlikely before the turn of the year. The objective is partly to confirm that Ormen Lange is one continuous field.

Seismic data indicates a number of faults, and it is important to know whether these faults seal, Tangen says. It is thought unlikely, but if it were the case, the number of production wells might have to be increased. At present, the total number of producers is expected to be between 16 and 25, with about 10 completed when the field comes onstream.

Another aim of the upcoming well is to provide more knowledge about the geological layers between the top of the reservoir and the seabed. This knowledge will be important in the event of a major blowout, Tangen says.

Meanwhile, the three licenses on which Ormen Lange lies - PL 209, PL 208, and PL 250 - make up a new provisional unitization. Interests are currently shared as follows: Hydro 17.96%, Shell 17.20%, BP 10.89%, ExxonMobil 7.18%, Petoro (formerly the State's Direct Financial Interest) 36%, and Statoil 10.77%.