Escalating cost facing the global upstream sector was a recurring theme in presentations on the challenges facing new E&P developments during IP Week in London in mid-February. Meg Chesshyre reports.
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| An aerial view of the Laggan-Tormore development. Photo from Total E&P UK. |
“In recent years the complexity and the scale of exploration activities have resulted in tremendous cost pressures in the industry in terms of both operating cost and capital expenditure,” said John Martin, senior vice president, World Petroleum Council, who chaired the event. “The recent postponement of many large projects, which were rendered uneconomic, seems to me at least, to be more driven by the scale of the capex involved rather than the current low commodity prices."
“Today costs have become unacceptably high,” agreed Yves-Louis Darricarrère, president upstream with Total. “A number of projects have been postponed, redefined, suspended or even stopped world-wide…Our industry has to react. Total is no exception. In 2015 we will accelerate and deepen the major group-wide cost-cutting initiative launched last year. We plan to reduce operating expenditure by $1.2 billion; the capital expenditure by 10% from $26 billion in 2014.” Total has also announced that it plans to reduce its exploration budget by 30%.
He cited Total’s Edradour project, west of Shetland, as a recent example of creating value through cost reduction and capital discipline. Total had been able to cut the initial cost by a third. Edradour is a subsea tie-back to the Laggan-Tormore development.
“Until 2011, the steady increase in the prices of crude oil offset rising costs,” he said, “But, with prices at a standstill from 2011 to mid-2014 and today with the sharp drop in the last months, there is no longer any offsetting. Cost inflation has contributed to a significant erosion of operating margins and project returns in our industry.”
He said that all Total’s assets were being scrutinized including projects currently in the development phase and even more so those under study. There could be sales of less profitable assets, and project postponement as had been the case with the Canadian oil sands.
“We are operating at 60% efficiency,” commented Antoine Rostand, managing director, Schlumberger Business Consulting. “There is no other industry in the world that can operate at 60%.” He also said that despite having the largest computers outside the defense industry, the technology was out of date. “We are using technology of the 90s to design our platforms and fields.”
The upstream industry needs to look for less complex and shallower plays, urged Tullow Oil’s Exploration Director Angus McCoss. The onus “falls upon ourselves as frontier explorers to look for frontier plays which are less complex, plays with which there is a higher resource density of light oil that is easily produced in shallower water,” he said.
“We’re using advanced seismic methods to look into the shelf edge, and to look at some of the plays that might have been overlooked by the first pass over the shelf,” he added. “The industry has worked over the shelf and moved out to deepwater, but we contest that there are still low cost, highly profitable plays to be had on the shelf edge break, and indeed onshore.” There had been great progress in the use of seismic inversion, he added, and “innovative use of seismic inversion methodologies, which allow us to locate the hidden upside within our global assets.”
He described 2014 as a year of reset in the industry and said that the reset continues. “We would suggest that you can actually attempt to find oil in simpler geologies, keep the complexity down, keep the margin down, and keep that profitability in sight.” This type of oilfield was already being looked for in the 1950s, but the industry now had the advantage of new technologies and collective knowledge, so that it was still possible to look for simpler plays despite it being 2015.
Tullow’s own finds offshore Ghana, and onshore in the East African basin had been highly profitable. The Jubilee and TEN fields, offshore Ghana, were easy fields with large, high oil reserve turbidites in reasonable water depths. The company is currently focusing on its high margin field exploration in and around its producing fields, but also building long-term options for strategic growth for when the industry rebounds.
The need to continue to pursue frontier plays was emphasized by Malcolm Brown, executive vice-president, exploration, BG Group. “I recognize that frontier plays are not top of the list for many companies in today’s oil environment, but in 10 years’ time they will be. We need 10 years lead time.”
The first requirement was innovative thinking. “We need to challenge accepted wisdom. Can there be things where we thought there weren’t before?” He cited some examples of BG successes in the Nile Delta, in the Santos Basin offshore Brazil and onshore Bolivia.
He also called for increased use of 3D and longer licensing terms. “We’ve had 3D for quite a long time, but we haven’t had 3D basin wide over many basins in the world at all, and that’s really where you need to reduce the risk before you go any further.” A step change was under way in seismic acquisition technology, which could reduce time and price – acquisition times by 50% and costs by 30-40%. A recent multi-client survey in the Barents Sea had had 10 participants, reducing the cost down to less than $1000 per sq km.
Asked about the outlook for UK exploration, Brown said that “the UK needs the terms to encourage explorers.” There may be stratigraphic traps still to be found. The deeper HPHT area in the central Graben is probably the least explored area, but exploration there also needs fiscal encouragement. Coss added that Norway’s 78% rebate incentivized frontier exploration in the sector.
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