Operators are battling to manage cost overruns on larger projects, was the message that emerged from an event on “Large Oil & Gas Projects” held at the Royal Geographical Society in London in June, organized by the Norwegian British Chamber of Commerce.
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The Goliat FPSO (from ENI Norge) |
“The industry is actually struggling to manage these projects, including the most sophisticated operators,” says Alan Williams, regional director in the UK for Granherne (a KBR company). “Where companies were making 20-25% margins, it is steadily reducing to 10%, 15% and even losses on individual projects.”
He said that there was no shortage of discoveries. “The real problem is getting it out economically. Deepwater projects are now two to three times the cost of eight years ago. As a result, many projects are being revisited worldwide. Many aren’t getting through to sanction.”
Apart from inflation, other economic drivers affecting deepwater projects were geological, geographical and geophysical. From a geological point of view there was more uncertainty. It wasn’t just that deepwater was deeper, with reservoirs up to 5mi below the seabed, but in many areas there were salt canopies, making it difficult to characterize the sub-salt reservoirs, or high-pressure, high-temperature reservoirs, which posed their own challenges.
In terms of geography, the industry was looking further afield and discovering reserves, where it had not previously operated, off South Africa, in the Falklands, the Barents Sea. Even west of Shetlands was still a frontier region. These areas lack infrastructure.
On the geophysical side, many potential deepwater developments are in countries with quite onerous local content requirements, such as Brazil, and to some extent Norway. Some have less favorable production sharing agreements. Regulatory requirements have also toughened in many areas post-Macondo.
“A lot of things are conspiring to work against these projects,” Williams says. “The reality is that few of them are actually capable of meeting their performance matrix.” There is the subsurface execution complexity/uncertainty; the supply chain is stretched; the logistical aspects of the new frontiers, but also the technological challenges, especially for deepwater.
High cost of appraisal wells
The high cost of appraisal wells meant that there was an element of rushing the “appraise and select” phase, in the hope of gaining a swift return on the outlay of say US$400 million on an appraisal well. As a consequence, the service facilities were not necessarily designed properly. They might be under-designed, or over-designed, with the same applying to the sub-surface programs. About 15% of the deepwater reservoirs were discovered by independents, and the pressure was on them even more, because they lacked the resources of the majors.
To reduce the risk it was important to spend time in the early stages of the project, not just on designing the facilities, but understanding the reservoir, and maximizing the understanding between the reservoir risk and facilities design teams. Quite often, there was a disconnect between different companies with different cultures.
He said that the skills gap was quite sobering, with about half the UK oil and gas industry due to retire in the next 10 years–that is 125,000 people. Another generation needed to be brought in. “I go to universities regularly, and oil and gas isn’t the high tech industry it was when I was at university,” Williams says. “We have to sell it now. Schools are now advising girls not to become medics, because it is highly competitive, but actually to become engineers.” Unfortunately this advice often came too late, when they had taken the wrong subjects at secondary school level. He concluded that the industry needed to get the message out that there was a very well paid industry out there.
Jan Erik Berre, senior vice president with Norway’s DNB banking group, was also concerned about cost escalation, citing the recent statement from Eni that its Barents Sea Goliat development had been further delayed, and now had a cost increase of 50% over the original budget, which, according to Eni was “in line with the norm for the North Sea.” He agreed that “in this environment of cost escalation there are a number of fields that will not be developed.” As a bank they had to be cautious, focusing on those companies that had a lot of experience.
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