Phillips makes integrated platform available to interested parties

Recycling tankers or semisubs has become commonplace for short-term floating production. But now operators are being invited to take the concept a step further: have used platform, will travel. Conoco started the process this spring by advertising its Kotter and Logger platforms for sale in Offshore's pages. No takers have been reported yet for the four Dutch sector installations, although Conoco's own Banff development in the UK was thought at one point to be in the running.

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The Maureen platform during the towout to the field in 1983.


Recycling tankers or semisubs has become commonplace for short-term floating production. But now operators are being invited to take the concept a step further: have used platform, will travel.

Conoco started the process this spring by advertising its Kotter and Logger platforms for sale in Offshore's pages. No takers have been reported yet for the four Dutch sector installations, although Conoco's own Banff development in the UK was thought at one point to be in the running.

At 13,000 tons, however, these structures are puny compared with Phillips UK's Maureen platform which weighs 110,000 tons in its entirety. And it is available in its entirety, or in sections, to any open-minded oil company.

Maureen is unique in the North Sea as a steel, gravity-based production platform with integral storage. There are three steel gravity storage structures operating in the Arabian Gulf and one steel gravity production unit off Angola, but none were designed for re-use as Maureen was from the outset.

That decision was taken in 1978, based on designs by Tecnomare and Brown and Root's Hi-deck, at a time when North Sea oil prospects were more buoyant. Currently there are no new UK discoveries which might require large platforms, although the situation may alter west of Shetland by the time Maureen becomes available in 1998.

Maureen's triangular supporting structure with oil storage tanks.


Re-use rationale

The platform was designed with integrated storage because at that time, no export infrastructure existed close to the location in block 16/29 near the Norwegian median line. It came onstream in 1983 at 80,000 b/d, exporting to tankers via a 42 meter high articulated loading column sited 1.5 miles away from the platform. Output peaked at 100,000 b/d, and so far over 200MM bbl of oil have been processed.

However, production has tailed off over the last few years sinking to 10,000 b/d currently, and there is an overall water cut of 88%. This means for every barrel of oil produced, 7 bbl of water must also be handled - most of it reinjected into the Palaeocene reservoir. To improve field economics, an infill well is being drilled from the platform to exploit a crestal area of the reservoir which came to light following processing of new 3D seismic: this should realize a further 2 million bbl.

Electric submersible pumps are fitted to two of the existing 19 wells, and more are being considered, along with numerous other techniques that might improve oil recovery. But so far none has proven suitable technically or economically. There are other prospects nearby for tiebacks such as Morag and Mabel, but these appear too gas laden for a platform with limited gas processing capability.

In theory, output could be maintained at today's low levels by somehow restraining production costs, but realistically, Phillips is viewing two options: re-use, or decommissioning. Removal/disposal suggestions are currently being evaluated.

Re-sale would be preferable to Phillips. It has no candidate fields of its own in the North Sea, although conceivably it could swing re-use by buying into someone else's discovery. The main limiting feature for North Sea application is the water depth range constraint of 90-98 meters. This could be extended to 125 meters by adding concrete plinths, gravel islands or new leg sections.

Alternately, there are other areas of the world where wave conditions are less severe which could allow the platform to be used in deeper waters, perhaps as a floater. Phillips' list includes the North American Atlantic seaboard, the south Atlantic, West Africa and North West Australia. Towing studies suggest even the remotest region could be reached without damage to the platform. During the original 455 mile tow-out to the field in 1983, Phillips points out, it withstood safely a force 10 storm.

The platform's designed operating life was 25 years from 1983, but this could easily be enhanced, Phillips claims. Maureen's recent Safety Case was accepted with minimal need for new investment. Re-use options include its current mode as a drilling, production, quarters and storage facility; as a host platform for satellite fields or a subsea development; or as the base for a bridge-linked gas production platform. But the structure could also be split up, with the topsides and storage unit sold separately for new installations.

Vital statistics

Maureen's platform, which extends 235 meters from the flare tower top downwards, comprises an 18,000-ton, three-level integrated floatover deck with 24 well slots and a 92,000-ton triangular substructure featuring oil storage cylinders, gravity base and deck support. The three tanks, resting on the seabed, can store up to 580,000 bbl of oil. Tank height is 74 meters with 26m diameter cylinders. Each tank is divided into two cylinders by an internal hemispherical cupola which purportedly eases installation and towage.

Gas processing capacity is 9 million cf/d with produced water capacity of 60,000 b/d. There is a test separator, first and second stage separators for oil production and accommodation for 150 people in two-berth rooms.

Whether the platform is re-used or decommissioned, the crucial task will be the re-float. Studies by Tecnomare in 1992 suggested it could be managed in one piece. Recently, however, Phillips commissioned UK consultants Offshore Design Engineering and Reverse Engineering to perform more detailed studies using non-linear simulation modeling.

The aims were to develop detailed structural, hydrodynamic and naval architecture models to ascertain what stress levels the facility might sustain during the re-float. Results were also used to develop a re-float simulator enabling real-time visualization of this operation under variable external conditions: analysis software employed was Moses and Offshore-Dyna 3D. Re-float would be performed by blowing air into the storage tanks to make them buoyant, then floating the facility off the seabed.

Phillips has to decide whether the platform could be raised without damage; whether one tank skirt might break earlier than others, and if so, how to overcome this. It also must establish the conditions needed to maintain platform stability during the re-float. Modeling predictions so far suggest the process would be manageable, even though the triangular base is of a different orientation to the square topsides.

The re-float is thought likely to cost around $45 million. The loading column, which is also buoyant and in good condition, would be brought ashore too for possible re-use.

DSV Seaway Pelican taking some of the load off the North East Frigg articulated column.


Frigg rides out

Another North Sea installation being re-used, but not in its original role, is Elf Norge's North East Frigg. The field was shut down in 1992, but the facilities had lain dormant for three years while Norway's parliament debated the ethics of disposal. An environmentally palatable removal solution was eventually entrusted to the Kvaerner Stolt Alliance, which performed most of the work this June.

North East Frigg's offending structure, weighing 11,000 tons, was a 126 meters high steel column, fixed to a concrete base, supporting a deck that housed field control facilities. This was used to operate a six-well tenplate, 300 meters away, via umbilicals and a 2-in. methanol line. Gas from the wells was piped to the Frigg TCP2 platform.

Kvaerner Stolt's operation involved removing all the hardware bar the template. Initially, hydraulic oil was flushed from the umbilicals onto tanks on a DSV. The umbilicals were cut at the base and the methanol line was also cut: these and the spool piece were then transported onto the DSV. An electrical cable taking power from TCP2 was also cut, but left on the seabed.

Next, the column was lifted from the seabed vertically using ballast water in the column and the concrete base. The column was then towed to an inshore location near Stavanger and anchored in a vertical position. It was disconnected from the base and tilted to a horizontal position. Now it is being re-used along with the base as a breakwater in a nearby marina.

The deck, with the control room and helipad, was also severed from the column and lifted onto a pre-installed foundation onshore at Tau. It will be used for offshore fire and evacuation training. Next year Kvaerner Stolt will complete the work by removing the 390-ton steel template and six wellheads for demolition and subsequent recycling. The hydraulic umbilicals will also be brought ashore and broken up.

North East Frigg was Norway's first field abandonment. Now the spotlight is on Esso's Odin facility, currently being removed by Aker and Saipem. This March, Norway's authorities recommended removal of the entire platform for onshore disposal: Esso had hoped to topple the jacket in situ for use as an artificial reef. The removal is estimated to cost around NKr200 million.

Crane barge S7000 is bringing the platform ashore to Norway, with Aker managing the disposal of the various pieces. No decision has been taken yet, however, on abandoning the intra-field pipelines either at Odin or North East Frigg.

Statoil is considering offering equipment from its Tommeliten Gamma subsea field for re-use to interested parties. Otherwise, the next major Norwegian decommissioning exercise will be Ekofisk, where production from four fields with five platforms is due to cease by 1998.

Spar solutions

Kvaerner Stolt are also one of 21 contracting groups bidding to decommission the Brent Spar, currently anchored at Erfjord in Norway. Shell has recently published 30 schemes put forward by 19 offshore contracting consortia. Its next step is to whittle that list down to around six later this year: chosen contractors will then have to produce detailed proposals for further discussion before Shell decides on its preferred environmental option. This will be submitted to the UK government some time next year.

A new structural analysis performed for Shell by WS Atkins underlines the difficulty of any removal option. The analysis, based on finite and linear finite element techniques, defines the stresses caused by differential water pressures on the Spar's structural components which would occur at sea during any reversal of the original installation sequences. The main findings are:

  • although the spar is stable and robust in its normal vertical operating stance, reversing the installation procedure could be tricky, as the spar was highly stressed -close to failure- during the original installation

  • previous concepts employed for onshore dismantling will not be feasible, necessitating new solutions.

Ballast tanks near the top of the spar provide the buoyancy to keep it afloat and control its 109 meter draught. Solid iron ore ballast maintains its stability in a vertical position. The walls of the six storage tanks are designed as thin stiffened membranes to separate the contents of the tanks from each other and the sea.

The spar could either be raised higher in the water in its vertical position, then cut into slices for removal onto a barge, or rotated to a horizontal position for barge loading or towaway. To do either, water must be pumped from the storage tanks, two of which are damaged. As the volume of tank water is reduced, the pressure difference between this water and the seawater outside would rise, increasing the external loads on the tank walls - possibly causing the tanks to collapse, with water surging back into the spar, in turn sinking it and likely creating further damage.

With two tanks already unsound, water would have to be pumped out of three tanks initially to raise the spar evenly. But the new analysis suggests that even at this stage, the inner tank walls might be liable to buckle. The two damaged tanks could be repaired first - a risky underwater operation - allowing all six tanks to be evacuated at the start of the lift operation. But this could lead to serious stresses on the outer tank walls, suggests the analysis.

Deballasting without attendant over-pressure might necessitate assisted buoyancy in the form of a crane, airbags or polystyrene balls. This would obviously vary according to how many tanks were deballasted. Removing the spar's 1,250t topsides would help achieve the required weight loss, but a lift of several thousand tonnes would still have to be undertaken, and strong points in the structure identified.

However, the spar's shoulder, where the diameter widens from 17 to 29.1 meters, can only sustain safely water pressure up to 17.8 meters. This means, according to the analysis, that the spar could only be lowered safely to a draught of 110.8 meters from its normal draught of 109m. This action might be necessary first before a crane could extract the topsides.

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