Finding a way to tap the North Sea’s estimated 3.4 billion of resources currently locked up in marginal pools has become a perennial problem. Elaine Maslin looks at a past solution and ideas for today outlined at an SUT Aberdeen event earlier this year.
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An original brochure, from when SWOPS was first unveiled. OE Staff photo. |
More than 300 discovered fields are sitting untapped across the basin, more than 150 of which are unlicensed. Many contain just 0-3 MMboe (150), with 80 containing only 4-6 MMboe. But, most of them are close to existing infrastructure, says Gordon Drummond, project manager, National Subsea Research Institutive (NSRI).
Some of it is about development cost. According to NSRI research into small pools, based on a US$60/bbl oil price, the minimum viable field size that could be produced economically was 11.1 MMboe. If the capex could be reduced by 25%, fields as small as 9.1 MMboe could be produced, and even 5-8 MMboe, with 50% cost reduction.
However, small fields have been produced before. Indeed, Centrica’s Chestnut field was thought to contain just 7 MMbbl when the Hummingbird Spirit FPSO started up in 2008, and the field is still producing today, now that data suggests the field is larger than previously thought.
Another earlier and more radical solution for marginal fields was the single well oil production system (SWOPS), developed and deployed by BP in the 1980s and very nearly an option for Chestnut.
It was technically advanced for its time and arguably the first floating offshore production system (FPSO), before FPSOs were invented. But, its commercial model didn’t stack up. The unit, named Seillean, Gaelic for “honey bee,” spent too much time transiting its oil cargo to shore and not enough producing to make it pay.
Seillean started work for BP in 1989, on the Donan and Cyrus fields. It was then sold in 1993 to Reading & Bates, under a move by BP to rent rather than own assets. Next, the unit moved to Brazil to perform deepwater well tests (following some modification work) for Petrobras.
After being acquired by Noble Drilling – and renamed Noble Seillean – she was sold to Paragon Offshore, and renamed Paragon FPS01, and moved to the US Gulf of Mexico. Paragon decided to scrap her, along with three other units, early 2016.
A honey bee
Sandy Meldrum, who worked on the system, outlined SWOPS at a Society of Underwater Technology (SUT) event in Aberdeen earlier this year.
“It (Seillean) was a means of producing oil from small offshore fields that would be uneconomic to be developed through conventional means, fixed or floating,” he says. It was a production system with a riser system and storage capacity.
The 250m-long, 37m-beam fully DP unit, for 75-200m water depth, and 4.5m significant wave height, was built at Harland & Wolff in Belfast. It had 51,000cu m storage tanks (320,000 bbl) and 15,000 b/d process equipment – later upgraded to 25,000 b/d. The unit had two moonpools, for the riser system and remote operated vehicle (ROV – a low spec work class Scorpio), and a derrick for riser handling, and a tensioning system.
The riser system was a 5.5in outer diameter bore drill pipe made up of 32ft long pipe joints, with 5000psi operating pressure. This was new and meant the safety joint was needed – and was indeed used. It was later upgraded when it went to Brazil, Meldrum says.
Pipe handling and tensioning facilities were in one moonpool, with a surface tree on a wireline BOP system, with a swivel joint for 360 vessel rotation. This connected to a connection package, a flex joint, to allow 15-degree offset, and a safety joint.
The riser connect package didn’t need guidelines, and comprised a collet connector for connection to the tree assembly (a flowline stab base, production tree, and re-entry hub installed using a drilling rig on the wellhead), a conical O-ring interface, providing flow paths for hydraulic transfer between the riser and tree assembly, valves for isolation and flushing, and shearing the wireline, and a diver panel for recovery of the riser connector package if the safety joint got separated. A re-entry hub would fit on top of the production tree via the collet connector, and incorporated a mandrel onto which the riser connector package locks.
If a second well was being produced it could be connected to the flowline stab base with a flowline and control umbilical. Direct hydraulic controls via an umbilical (with 23 hydraulic lines and two riser flushing cores) were used in conjunction with the riser package. Acoustic monitoring was used to relay pressure information from the tree/flowline back to the vessel.
In the early days, the plan was for the vessel to go between 4-5 fields. But, some of the wells didn’t live up to expectations, Meldrum says. BP, at the time, was in the process of moving from using its own rigs to using contractors instead.
Meldrum says that compared with an FPSO that stays on station, the SWOPS vessel had to leave once it was full to offload. “There was a lot of down time,” he says. Gas was dealt with through flaring.
Other options
Other existing ideas for how to produce these fields have included production buoys, “FPSO light” concepts, such as Amplus’ versatile production unit (VPU) (OE: May 2016 – Small is beautiful), subsea production systems with subsea storage, such as Kongsberg’s subsea storage system concept (OE: August 2016 – Tanked up), now owned by NOV. According to an NSRI study, out of these, production buoys were deemed as having the potential to be profitable after five years. Subsea production was thought to have the potential to get “above the line” after five years, while FPSO light struggled to wash its face – based on $60/bbl prices.
Ian Dring, an executive at Sea Captaur, which has developed a production buoy concept (OE: August 2016), says there’s an opportunity for such a technology. He says, of 347 undeveloped fields on the UKCS, 130 contain more than 6 MMboe and 155 are currently unlicensed. He suggests using an unmanned buoy type system, with subsea oil storage and a shuttle tanker to offload oil periodically. It could also be used for late life field extension, when larger facility such as an FPSO is no longer viable, or as an early production system for a larger field.
John Woods, of Aberdeen-based Offshore Production Buoy (OPB), says: “There are a lot of assets (fields) out there that need these solutions.” OPB has a ca.28m-diameter, 12m-high column shaped buoy design for 30,000 bo/d (40,000 b/d liquids) process capacity, and 9 MMcf/d gas handling, for work in 100-400m water depth via catenary or tension tethers.
The buoy would contain controls, power generation (including for up to six ESPs and water reinjection if needed) and de-gassing equipment, with a typically 200,000 bbl subsea tank and offloading system. Gravity and temperature-based separation would be used, with the liquids heated and degassed. Gas would be used for heating the tank and process equipment space to reduce corrosion. But, this limits the system to 9MMcf/d, Woods says. “There’s a gas oil ratio sweet spot. This would be for fields where you’re not sure what the production will be, they are stranded, end of life production or a stand in for an FPSO,” Woods says.
While the buoy has been designed to be reusable, the subsea storage system would be unlikely to be reused, says Woods. With the design assessed and review by design house ODE, OPB is now looking for field studies in the North Sea.
Commerciality
While some of the issues are around technology – including flaring, water handling, sand management – ultimately, one of the biggest blockers, as with Seillean, will be the commercial model. With the existing small pools, there’s little incentive for those that hold them, or those without infrastructure, to go after them. With 120 players on the UKCS, finding commercial alignment is difficult, compared to the Dutch shelf, where there are four players, one of which is the national oil company, says Chris Pearson, from the Oil & Gas Technology Centre in Aberdeen. “It’s classic market failure,” Drummond adds. “It’s now 80% owned by 20%, it’s lots of people owning a few and no appetite that’s killing us.”
There could be a change. Pearson says that the UK regulator, the Oil and Gas Authority, is starting to take a “use it or lose it” approach to those sitting on these assets and not doing anything with them. One operator was said to have half a dozen of these opportunities but would not put them across infrastructure other than their own. “This could help us, but it’s a big challenge,” Pearson says.
Back to the future
A concern on the UK Continental Shelf is that untapped fields could be stranded, if existing infrastructure, such as export pipelines, is removed.
The situation could have applied to a new hub being developed by Independent Oil & Gas (IOG), if not for a decision to recommission a 90km-long decommissioned southern North Sea (SNS) gas pipeline – saving £100 million and two years’ work, IOG CEO Mark Routh told an East of England Energy (EEEGR) event in Norwich.
IOG is acquiring the Thames Gas pipeline, which took gas into Bacton, England, to transport some 500 Bcf from its Blythe, Elgood, and Vulcan gas hubs. IOG plans to drill 10 wells, lay over 70km of new connector pipelines and install up to five new platforms for these hubs. The Harvey asset, between Blythe and Vulcan, is likely to also be part of the project.
“We saw a pipeline was empty and, if we recommissioned it, we would have a pipeline that could start to unlock these stranded assets,” Routh said. Acquiring the pipeline from Perenco, Centrica and Tullow cost £1, with IOG taking on all future liabilities, which amount to several million pounds.
Environmental surveys started in February, and in July, a field development plan was submitted.
Work to recommission a 60km section of the 24in Thames pipeline is underway, with plans to send intelligent pigs down it to assess its condition. A solution to any problems could be a 16in run through the current pipeline, which would be subject to more rigorous inspection than many other pipelines in the SNS, Routh said. “Pipelines are usually over-engineered – some of the 1960s pipelines are still flowing gas safely more than 20 years beyond their initial design life.”
The project will be the first recommissioning of a decommissioned SNS pipeline. IOG is inviting the supply chain to work on the basis of payment on production, estimated at 150 MMcf/d at its peak by 2020.
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