Subsea oil storage solutions could help unlock marginal fields; how easy would it be? Elaine Maslin reports from a workshop that assessed the issue.
The Solan subsea tank prior to installation.Photo from Atkins. Photo from Bibby Offshore.
How to tackle the North Sea’s small pools – discovered fields containing under 15 MMbbl – has been under sharp focus in Aberdeen.
According to a study, there are 210 “small pools” of hydrocarbons on the UK Continental Shelf, totaling some 1.5 billion boe.
A hunt is on to find economic ways to produce these deposits and for some the answer lies in producing fields without the use of umbilicals to topsides facilities or even export pipelines (OE: December 2015, “Cutting the Umbilical”).
Producing power on the seafloor (to power subsea equipment) and wireless communication for controls (via a buoy at the surface) are seen as being feasible, if not already proven. Subsea chemical injection solutions are also being worked on... But, how do you get the produced fluids to market?
Subsea storage is an option and the topi was the subject of a one-day workshop run by the National Subsea Research Institute (NSRI) near Aberdeen.
The Solan facilities with the Bibby Polaris.
For some, it’s a proven concept. There are examples in the North Sea and elsewhere, including the Prinos oil field, offshore Greece, and the 500,000 bbl Khazzan subsea storage tanks. The latter were installed 60mi off Dubai in 154ft water depth in 1969, to store oil from the Fateh field. Both are still operating.
“Over the last 40 years, subsea storage tanks have figured into [North Sea] oil and gas production,” said Graham Whitehead, field development manager at EnQuest and a part of the UK’s Technology Leadership Board’s small pools team, during the NRSI event. “In 1978, Thistle was storing oil in the steel legs of a jacket, with export of crude over a SAL (single anchor loading assembly), because there was no infrastructure in place at the time. The Brent pipeline was still being built. Other examples in the 1970s include Kittiwake. It was the first asset that had subsea storage over the platform base.”
There was also Harding in the mid-1990s; Siri, in the Danish sector, in the late 1990s, and most recently, Premier Oil’s Solan. “That is excluding gravity-based structures and big concrete structures, or spars,” he says.
The two main drivers for use of subsea oil storage have been remoteness and a lack of oil export solutions, Whitehead says. But, other reasons could include field size, and fluid and field complexity – Harding produced a fairly heavy oil and it wasn’t possible to just put it in a common network, he says – as well as the succession plan for when existing infrastructure becomes too costly to operate.
Most recently, Premier Oil used a steel subsea oil storage tank on its not normally manned Solan facility, west of Shetland, as a way of compensating for the lack of infrastructure in the area. The Solan subsea tank is a beast, using 10,000-tone of steel, and measuring 25m-tall, 45m-wide, and 45m-long, with a capacity of about 300,000 bbl. The tank features a honeycomb of small chambers, containing anodes, to ensure integrity as waves pass over and to prevent corrosion on the steel, the event heard. Biocides and biopenetrants will also be used to prevent corrosive bacteria and marine life from forming. The tank is offset from the steel jacket-supported platform and connected by flowlines. Premier’s initial plans estimated that tanker offloading will occur every 7-10 days, taking 24-36 hours each time.
SeaCaptaur’s monocolumn unit.Image from SeaCaptaur.
However, something the size of the Solan tank, which was fabricated in Dubai, would not be needed or economical for a “small pool.” More crucially, most subsea tanks, to date, have been for use with processed fluids. Storing unprocessed fluids offers significant challenges.
Considerations for subsea oil storage designs for small fields include fluid co-mingling, differential pressure in the tank, gas dispersal on fields with gas content, slugs dispersal, low energy fields and dealing with corrosive fluids, Whitehead says.
Steve Howell, technical director at Aberdeen-based engineering simulation firm Abercus, suggested the storage process could be used to settle out multiphase fluids – as a crude separator. But, he says, some processing would likely still be needed and if water ballasting is used to even out the differential pressure during filling and periodic offloading, then flow assurance issues would need to be addressed in case emulsions form.
Others issues raised include how to handle produced gas and water. Water could be handled, potentially, through treatment and re-injection, but gas separation and handling remains a primary technology challenge, according to a post-event report. Depending on the fluids, it could also be that the tank would have to be heated to prevent wax or slurry formation.
One potential solution was to have tank farms. David Sinclair, engineering manager, Bibby Offshore, suggests, for small pools, having several small tanks, which would be easier to fabricate and install and then recover for offloading or reuse.
“With quicker decline rates on small pools, they could also be designed to be recoverable for reuse elsewhere,” Sinclair says, using construction support vessels instead of heavy lift vessels. It would also mean local fabrication could be easier, with fewer issues relating to concerns around internal integrity, he says. This could also mean decommissioning would be easier than it has been for some of the large existing storage tanks.
A new business model?
Such a concept could offer the potential for a new business model. Part of the problem around small pools is that they are small and fairly widely distributed, so that not one operator has “enough skin in the game” said Gordon Drummond, NSRI manager.
Designing one and building many would enable standardization and simplification, he suggests. Having a subsea tank as a business akin to shipping containers may also address unprocessed fluids, moving the problem from subsea to onshore where it can be cheaper and easier, albeit it is accepted this would lose the benefits of processing closer to the reservoir and would mean transporting at least some product with little or no value.
Kongsberg’s subsea oil storage tank concept. Image from Kongsberg.
Norway’s Kongsberg has been designing a solution – the Kongsberg flexible storage unit. It would store part-processed oil within a flexible membrane, inside a protective structure, providing a double barrier with integral leakage control and monitoring, says Astrid Kristoffersen, vice president subsea products.
The flexible membrane helps overcome differential pressure concerns and also prevents emulsion layers from forming, he says.
The flexible bag would be made from a coated fabric membrane with a hatch at the top with an inlet and outlet. The bag, containing up to 150,000 bbl in a reference case, is attached to the top and bottom of a center pipe, and both are inside a ballasted solid protection structure, into which seawater is allowed to flow, filling or exiting the structure, never in contact with the oil. The bag and center pipe can be retrieved.
Kongsberg designs the SSU (subsea storage unit) system from the riser, from a topsides facility where it has been through separation, to offloading via shuttle tanker, to ensure that the time it takes to export the oil and heat management meets the requirements of the specific field. The SSU has integrated sensors, barrier philosophy and operational management ensuring full overview of filling, discharge and thermal performance of the system, says Kongsberg.
The project was given Demo 2000 funding and is part of a joint industry project with Statoil, Det Norske, Lundin, and the Research Council of Norway. As part of the DEMO 2000 funding, testing was carried out on a 1/9 scale model.
Kongsberg is looking to offer similar technology for subsea chemical storage and produced water storage.
Australian firm SeaCaptaur has another solution. Alan Roberts, the firm’s managing director, and Max Begley, of Matrix Composites & Engineering, joined forces to create a system to develop small pools.
SeaCaptaur is focusing on fields containing 5-15 MMbbl recoverable in 10-300m water depth. Roberts says there’re around 2000 small pools around the world, but to develop them at US$50/bbl you need a solution that has 50% of the capex and opex cost of present day FPSOs (floating production, storage and offloading vessels). SeaCaptaur thinks the North Sea has the most potential in terms of producing its small pools. But, Roberts says, “there’s a cultural problem. They [North Sea operators] only understand big. They need to scale down right down to small and basic.”
SeaCaptaur has drawn on the Apache (Australia) and Sasol (South Africa) control buoy systems, the Khazzan oil storage tanks and the Prinos tank. It has a base case 50,000 bbl oil storage tank on the seafloor. The tank would be floated out using a tug and then ballasting for positioning. The tank would be connected, using tethers, to a rigid monolithic production spar buoy, which pierces the surface for gas flaring and offtake. The buoy would contain four levels, or decks, containing the processing systems – which could support electric submersible pumps. Access for maintenance would be via an access gangway, the like those being used in the offshore wind industry.
The system would require a specialized, 65,000 bbl capacity shuttle tanker for offtake. SeaCaptaur has designed a DP shuttle tanker for this job, complete with motion compensated gangway, which could in effect do a milk round of several facilities and take the crude straight to the terminal, to avoid third party lifting charges or tariffs.
“It is still cheaper than a FPSO,” but, you have to have a number of small pools running, say 2-3, to maintain a production rate of 10-11,000/d, to make it work, Robert says.
Relying on infrastructure
While there is a large prize to be had in the UK North Sea’s small pools, individually it’s hard to make these small reservoirs pay their way.
According to a University of Aberdeen report looking at the possible profitability of small pools (containing 3-15 MMbbl recoverable), at $60/bbl, the smallest size pool that becomes economic is 11 MMbbl.
The current technology to develop such a field is a single well, with a single flowline, a single umbilical for tieback to a host. But, “if we could cut the cost by 25%, it would take the field size to 9 MMbbl. If we could reduce it by 50%, it would be 6 MMbbl,” says Peter Blake, chairman of the National Subsea Research Institute, part of Subsea UK. “Obviously we are not operating in a $60/bbl world, it is $42 today [at the time of the NRSI event in April]. There is a considerable challenge to get capex down if we want small pools to be developed.”
Another study, by the UK’s Oil and Gas Authority, found that many of these small pools are tantalizingly close to near infrastructure, however. Many of the pools containing less than 50 MMbbl, are within 50km of a pipeline – although what type of pipeline this was needs defining in further work. Some 80% contained less than 20 MMbbl but were less than 10km from a pipeline.
By far, most of the opportunities are in the central North Sea, followed by west of Shetland and then the northern North Sea. “The central North Sea and northern North Sea is where there is already a lot of infrastructure,” Blake says. “There is not a lot of infrastructure west of Shetland.”
“There is a possibility to hook this stuff into other things or hook it together,” Blake says. “The scope for standalone infrastructure isn’t as big as expected.” But, “there is [also] a valid concern this infrastructure could disappear. In this environment can subsea storage be competitive and what does the overall system around that system look like?” And it’s not just a UK North Sea opportunity. Blake thinks subsea storage could be used in shallow water basins elsewhere around the globe. “But it cannot be technology for technology sake, it needs to be at a price that can make developments happen.”