Industry and government bodies think there is still a strong future in the UK North Sea, but they are not complacent about the challenges the basin faces.
After more than 40 years of production from the North Sea, with declining output and an ever-more complex and costly operating environment, it would be easy to view the basin with a “glass half empty” attitude.
Industry and authorities are taking the opposite view. Investment is high, driven by a number of mega-projects and sustained high oil prices. To ensure the longer term health of the basin, increasing focus is falling on the prize that could be had from eking-out the mostly smaller pockets of remaining resources and increasing production from mature fields.
A number of fiscal and technological initiatives are underway on the UK Continental Shelf (UKCS). The role of independent oil companies in stimulating regional exploration activity and how players evolve from explorers to developers and producers will be discussed at the Offshore Europe conference in Aberdeen this September.
The UK Department of Energy and Climate Change (DECC) is leading a PILOT group that has been looking at the lack of funding for development activities accessible to smaller players, as banks remain unwilling to lend.
New tax allowances were introduced last year, aimed at improving the commerciality of small fields, ultra heavy oil, shallow-water gas fields and brown field investment. This mitigated a tax increase on oil and gas producers made by the UK Treasury in 2011.
Most new fields approved since 2012 have benefited from the small field allowance, says Simon O’Toole, head of exploration, licensing, and development at DECC. The brownfield allowance has also encouraged investment in facilities to extend field life and unlock otherwise stranded fields, with 15 projects totaling about £3billion of Capex either agreed or soon to be agreed.
Projects involving technology, such as enhancing oil recovery (EOR) and increasing production efficiency, are not as well promoted.
“We have kicked off, in PILOT, a project to see if industry as a whole can up its game in production efficiency,” O’Toole said at the SPE London annual conference in May.
“We are trying to get engineers to work on existing fields to increase production efficiency. It is a real problem offshore at the moment. We are losing a great deal of production simply through unplanned stoppages and unplanned maintenance.”
Another effort to prolong field life and increase production is a PILOT project to encourage EOR technologies. The UKCS has produced just over 41billion boe. The recovery rate averages 40% and is on track to reach 46%, says ConocoPhillips’ Ian Walker, who recently finished a secondment to DECC.
“With a global average of 30%, it could be easy to say it is expensive to go further in the offshore environment with high well costs,” he says. “We have done a good job using water flood; it went in when it was required. But at the same time, it is asked ‘Why are we leaving so much behind?’ There is more that can be done in EOR.” An EOR work group screened North Sea fields to see which technologies could be applied most effectively.
The group looked at miscible hydrocarbon flood, nitrogen and flue gas, miscible CO2, surfactant with polymer, polymer, in situ combustion, steam drive, bright water (“strong gel”), lowsalinity water, and colloid dispersal gel (CDG, weak gel).
“When you look at it, and look at the geographies technologies might apply to, there are a few technologies that come to the fore,” says Walker. These were miscible hydrocarbon flood, miscible CO2, surfactant with polymer, polymer, and low salinity.
“Low-salinity (water injection) lends itself to early adoption; chemical EOR would come a bit later because it is less easy to implement; and miscible gas would be later too,” he said. “But in the North Sea there are examples of all these technologies at work.”
BP, a leading proponent of low-salinity EOR technology, is planning the first offshore, full-field deployment of its LoSal EOR technology on the West of Shetland Clair Ridge development. This will be a secondary waterflood, expected in 2016. BP may try it next in the Gulf of Mexico, for Mad Dog Phase 2. Shell and Statoil have also been looking at low-salinity water in other areas of the world.
The group identified North Sea cluster areas deemed optimal for EOR, around Taqa Bratani’s northern North Sea assets, near BP’s central North Sea assets, and around Nexen’s facilities in the Moray Firth. The research so far, despite being “a bit coarse,”showed the prize could be 6 billion bbl, says Walker, a significant sum when the estimated remaining recoverable resource has been put at 10-20 billion bbl.
Industry workshops have been held with 12 operators, and Walker sees “an appetite” for low-salinity technology. However, there are still uncertainties and a need to share information, provide guidelines, and encourage cooperation.
“It is low cost and there is scope for standardization and scope for shared projects,” he says. “But there is also nervousness.”
EOR chemistry isn’t fully understood and mixed core results may unnerve investors.
The work group is developing guidelines for core testing and participants are being encouraged to share data, and consider joint facilities in cluster areas.
“Creating a common core flood protocol and building a larger database of results would help tie down screening parameters,” says Walker. “Sharing lab results within clusters would encourage other operators.”
One operator involved in the work is Taqa Bratani. Peter Brand, asset development manager at Taqa, told DEVEX: “There is a need for speed if we are going to get anything done using these technologies, which is why sharing information, which is not a habit in the past, is going to be key to faster progress in future.
“We have done core experiments in Pelican and Tern so far with lowsalinity flooding. The results have not been spectacular but we do feel it has potential.”
He said it was considered that a green-field approach would be needed to “kick-start” implementation of lowsalinity EOR in the northern North Sea, offering lower costs and having the added benefit of avoiding scale and H2S, which would encourage its use even when the incremental increase in production is fairly low.
At the DEVEX 2013 conference (Aberdeen, May), Walker warned that the industry is running out of time, with production declining (at 1.5mm boe/d in 2012), threatening the life of “core pieces of infrastructure.”
Speaking at the SPE conference, Mark Tandy, commercial and exploration director at Taqa, says: “We believe [that] in the northern North Sea alone, there are over 20 billion bbl—something in the order of three quarters of a billion of that will be stranded as infrastructure pulls back.”
O’Toole says: “We are going to lose some infrastructure in the next 10-15 years. In the southern North Sea we can expect there will be fewer infrastructure systems in 2025. There will not be a complete dearth of infrastructure, most areas will have some, but most of it will not be full. We need the right assessment of rewards and risks so people who own infrastructure are willing to take production across at a reasonable rate.”
Together, with the efforts being made to improve or strengthen fiscal and regulatory incentives alongside technology development and use, the industry and government are both hoping the North Sea will continue to be a glass half full basin. OE
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