Cost-cutting technology to tap 'small but many opportunities' in UK North Sea

Shell Expro Managing Director Malcolm Brinded has followed up his welcome recent announcement of the oil company's enlarged $1.2 billion capital expenditure program for the UK sector of the North Sea with a confident vision of a domestic offshore oil industry prolonging its productive life through new technologies and further cost-cutting.


Darius Snieckus
OGJ Online

ABERDEEN�Malcolm Brinded, managing director of Shell Exploration & Production PLC, today followed up his welcome recent announcement of the oil company's enlarged $1.2 billion capital expenditure program for the UK North Sea with a confident vision of a domestic offshore oil industry prolonging its productive life through new technology and further cost-cutting.

The Shell Expro chief, addressing an audience of some 350 at an UK Offshore Operators Association (UKOOA) energy forum in Aberdeen, tipped reservoir-optimizing 4D seismic�likely to "transform the future of our industry"�intelligent well technology or "smart wells," expandable tubulars and sand screens, as well as Shell's own gas separation "Twister" system as technologies that would help "get the most value out of what we've already got" in the North Sea.

Brinded said North Sea companies would have to leverage their technologies along with "what they had going for them"�existing infrastructure, a "quality" service sector, and ready-made gas market�to answer the rigors of the region's "maturity, small field size, and global competition."

Given the "small but many" untapped reservoirs on the UK Continental Shelf, further cost reduction, which through industry initiatives such as now-defunct Cost Reduction in the New Era (CRINE) program became a pride of the UK offshore sector, could widen the net so that many of the most marginal central North Sea's fields could be exploited economically as subsea tiebacks.

"Remember," stressed Brinded, "that 60% of Shell's equity production comes from subsea wells, and 75% of undeveloped discoveries [on the UKCS] are less than 25 million boe�the large majority of which are within 30 km of existing infrastructure�and that is what we know about today, [and doesn't include] what we haven't discovered.

"What if we could halve today's costs? Then 5 million bbl [reservoirs] become economic at 25-30 km, and we could technically go beyond 50 [km] to exploit one as a satellite," he said. The radius from existing infrastructure could, according to Shell calculations, be expanded by a factor of five, equal to "25 times the area" in which a 5 million bbl subsea tieback prospect becomes viable.

To enlarge coverage of tieback targets by this multiple, Brinded added, was "not at all unreasonable."

"If you are talking about five times the number of targets, then surely you are talking about turning [this industry] from a one-off project based business into a production line business with simplification, standardization, and very quick commercial negotiations," resulting in an industry that can bring this scale of development on stream at "high speed," he suggested.

"There are so many installations covering the North Sea that most of the potential future discoveries will be able to be hooked into [infrastructure] that is already there," Brinded stated.

The pan-industry "change in behavior" required, however, he added, is a fundamental hurdle in a mature basin such as the UKCS.

Brinded put forward the central North Sea's high-pressure, high-temperature (HPHT) Central Graben Area as "the biggest remaining play in the North Sea and one in which we see very exciting opportunities," though HPHT prospects are "high-risk, high-cost, albeit high-reward."

"If we can bring down the cost and de-risk the exploration, then there is a great deal we would like to do in the area," he said.

Shell's New Business Development Director Lynda Armstrong said the company is currently sizing up as many as 12 HPHT structures in the area around its groundbreaking Shearwater field, four of which might be brought forward for formal development approval if sufficiently "de-risked," though no decision would be taken for 6-12 months.

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