Snorre Tie-in

Plans called for two 30-kilometre pipelines to transfer the natural gas liquids and the partly processed mix of oil and gas to Statfjord A. These lines would have diameters of 20 inches for oil and 10 ¾ inches for gas, and the tie-in to Statfjord was planned for the spring of 1992.

Because Statfjord A production had declined from its peak, the platform had spare capacity. No particular need was accordingly seen in 1987 for significant modifications in order to receive output from Snorre. All such projects nevertheless require extensive planning and coordination.

In the middle of this work, a new challenge suddenly emerged. The Piper A platform in the UK North Sea exploded in July 1988, with the loss of 167 lives. A British investigation into this disaster was launched. One result of this inquiry was that the UK opted with effect from 1989 to apply the safety design principles adopted by Norway for Statfjord B in 1976-77. (See the article on the Statfjord B letter.) This prompted Statoil in turn to launch a safety assessment of the installations it was operating on the Norwegian continental shelf (NCS). Since the Statfjord A design was very similar to Piper A’s, Statoil concluded that the platform failed to meet its own safety standards in significant areas. A safety programme which ultimately cost almost NOK 1 billion was thereby initiated. Much of this upgrading work occurred in the summer and autumn of 1991, in parallel with the modifications required to receive stabilised crude from Snorre A.

Snorre tie-in

Work on the platform was extremely complex, with two conversion projects underway while production of oil and gas continued as normal. Getting the pipelines from Snorre onto Statfjord A also posed major problems. The platform had not been constructed with such requirements in mind. In order to tie into the topside production system, the risers had to be attached to the outside of the storage cells and up one of the platform shafts. But using external pipelines of this kind in the splash zone, where the shaft emerges from the sea, would leave them particularly exposed to waves and the risk of damage.

The solution was accordingly to cut a hole in the concrete wall, well beneath the lowest level of wave action, pull in the pipelines and then seal the opening around them. But extending the risers all the way up the shaft would make it difficult to access the process trains on the platform – not least because of space shortages on the lowest or cellar deck. The answer was to cut another hole just beneath the topside and pull the risers out into the open air, where they could be guided to the main deck.

Conversion had come so far by the end of November 1991 that the platform was shut down for a few days to connect the new equipment for receiving oil and gas from Snorre.  Although this work appeared to go well, problems started when production was to be resumed at the end of the first week of December. It proved impossible to get the process going again properly. Statfjord A simply refused to function as it should and remained shut down – at a cost of roughly NOK 30 million per day.

Efforts to put matters right over the next couple of weeks demanded a heavy commitment from the whole operations organisation. In a struggle with complex technology and against a reluctant and not entirely modern platform, all system components were gone through and checked. People worked day and night, on land and offshore. Everyone joined in the effort, and people with long experience on the platform and who were familiar with its innermost “soul” were called in from far and near to overcome the problems. It slowly proved possible to get production started again, and Statfjord A was back in normal operation by Christmas.

Snorre tie-in

The Snorre licensees noticed none of this drama. Their primary concern was to get their own platform built and ready to start producing. As early as the beginning of 1992, it was evident that Snorre A would be able to come on stream several months ahead of the original schedule. Although the modifications on Statfjord were not due to be completed before the end of the year, the final adjustments could be made as early as the scheduled turnaround that May.

The Snorre licensees faced their own challenge. Since the field was not due to start producing until late 1992/early 1993, the field lacked export opportunities for its associated gas. No equipment for gas injection existed on Snorre A, and the gas volumes were so large that flaring was an unacceptable solution. That would moreover have been very expensive. The Norwegian government had introduced a tax on carbon dioxide emissions for the country’s offshore fields from 1 January 1991, and this carbon tax applied directly to gas flaring. During the May turnaround, operations and maintenance personnel on Statfjord became strongly involved in overcoming this problem. They quickly – and virtually without preliminary planning – managed to expand gas treatment capacity on Statfjord A by about a million cubic metres per day, or almost 10 per cent. That made it possible for Snorre to commence oil production long before the scheduled start-up date, and Statfjord A could overcome the gas problem.

Although this directly benefited Snorre and allowed its licensees to earn revenues long before they had expected, this led to a lengthy quarrel with Statoil. The dispute concerned who should pay for the modifications and for the cost to Statfjord of handling the gas so that the other field could produce oil earlier than planned.

Snorre tie-in

This wrangle demonstrates that a strong concern – as on Statfjord – with solving day-to-day problems quickly, and worrying about formalities afterwards, is not necessarily the best form of collaboration.

Snorre A began producing on 2 August 1992, and nobody mentioned the disagreement over the gas on that occasion.