Open water coiled tubing drilling has been used offshore Norway in an industry first. Elaine Maslin found out more.
Island Offshore’s Island Constructor. Images from Centrica Norge
Coiled tubing drilling (CTD) isn’t a new concept. But, it is one that has struggled to gain traction, not least offshore.
The attraction to CTD, which has been used onshore since renewed interest in the technology in the 1990s, is that it could enable continuous drilling – you don’t need to connect drill pipe – reducing handling and increasing safety, as well as offering continuous hardwired telemetry down hole. Being able to continuously drill and pump also enables underbalanced drilling operations to be performed and the smaller footprint means that it can be deployed from smaller vessels, instead of requiring a full blown rig.
The downsides are that because you cannot rotate the pipe, drilling depths could be limited and it’s not so easy to circulate out cuttings. The entire tubing string also becomes a single consumable, instead of being able to recut or surface individual connections in rotary drill pipe.
For Centrica, which believes it was the first oil and gas operator to use open water CTD offshore last year, from a light well intervention vessel, the technique was an ideal solution and one with further future potential.
Centrica wanted to drill a pilot hole, as part of pre-development drilling work on Butch subsea tieback project in the Norwegian sector of the North Sea. The pilot hole was needed to test for shallow gas deposits at the planned drilled center location for the Butch field. Using a CTD spread on a light well intervention vessel meant the firm didn’t have to use a rotary drilling rig, likely on a semisubmersible.
Well kill with vessel moved.
The Butch field was discovered in 2011, in the Norwegian part of the North Sea, about 13km east of the Ula field. Recoverable reserves are estimated to be between 27-61 MMboe. The development concept is a subsea tieback to the BP-operated Ula platform, with a final investment decision expected late this year (2016). First oil is planned for 2019, with a peak production of about 35,000 boe/d.
The subsea injector and ROV in operation.
“If we hadn’t checked for shallow gas and started doing development work three years from now, and we placed subsea infrastructure and had a jackup here, and then had shallow gas, we would have had to move the infrastructure and the rig etc.,” says Espen Kopperud, project manager at Centrica Norway. “We could save several hundred million Norwegian Krone avoiding that scenario.”
Centrica looked at using a semisubmersible, but with higher day rates, despite lower prices in the current environment, the total project cost worked out at about 30-50% lower, Kopperud says. The flexibility of the coiled tubing string has an added benefit that a well kill operation can be performed via the coiled tubing with the vessel at a distance, in the event of a blowout. “This is new, we don’t have option to do this with semisubmersible,” Kopperud says.
Island Offshore and Baker Hughes, which worked for Centrica on the Butch pilot hole, have used the technique offshore Norway already, just not in oil and gas. In 2014, the pair used the technique to take core samples from areas around Rogaland County, where road tunnels were due to be built underneath fjords as part of the Rogfast project.
The subsea guide base
“We more or less made a few small tweaks [to the system they had developed] and added another layer of operation specific procedures and assurance to be able to drill on the Butch location in the North Sea,” Kopperud says. “The main difference was the unconsolidated sands and clay formations we had to drill through. Rogfast had hard rock. So we had to optimize the drilling method around avoiding wellbore collapse and stuck pipe prevention. Apart from that, the main difference was that we had a chance of hitting shallow gas.”
For this eventuality, the team did “a lot of contingency planning. We were the first ones to do this and as part of oil and gas regulations in Norway, we had to fulfill quite a bit to achieve regulatory approval of the new drilling method,” Kopperud says. A lot of time was also spent qualifying the method, which would involve spooling out the coil on the seabed, doing a dynamic kill and cutting the coil downhole.
The ROV control room.
With a mixed crew, comprising Island Offshore staff, who have done a lot of wire line work, and Baker Hughes staff, with coiled tubing experience, Centrica was conscious to do a lot of training around chain of command and to make sure the teams worked efficiently together.
For the operation, Island Offshore’s Island Constructor was kitted out with a coiled tubing drilling unit, with 1100m-length of 2 7/8in coiled tube on a 4-5m tall coil tubing reel. Full system testing was carried out near Stavanger before the vessel sailed out to the Butch location, in 66m water depth. Once on site and positioned, the 50-60-tonne subsea guide base was lowered and positioned. A 15m lubricator pipe was then set up as a conductor to penetrate the sea bed in the center of the guide base.
The vessel’s tower was then lined up above the lubricator, and the subsea injector was landed. The subsea injector, with electric and hydraulic controls and power supplied via the ROV, is installed on top of the lubricator.
The 6 ½in bit, rotating with a mud motor on the end of the coiled tubing, was then jetted down 8m into the seabed, before the lubricator is locked into place using an ROV. Then a 50m rat hole was drilled before pulling out of the hole then running back in with a 50m-long bottom hole assembly, comprising of mud motor, rotary steerable system, logging while drilling tools, and a 5 7/8in bit.
Subsea lubricator diagram
The challenge with CTD is around hole cleaning, to get solids and sediment out of well. But, procedures were designed to deal with this, Kopperud says. Drilling continued to 420m below the seabed and then the hole was circulated and logging carried out to find any shallow gas. There wasn’t any so the hole was plugged with a 125m cement plug – more a precaution to avoid communication with future development wells, than a regulatory requirement.
“We pulled out of the hole, removed the lubricator and guide base, cleared the seabed, and sailed away. It had taken four days, six hours. That was really optimum with no issues,” Kopperud says. “It was a good job, managed ahead of time and budget, with no issues. We have started and proved this method and it is now available to the industry.”
But there could be more possibilities to use open water CTD. “Island Offshore also proved in 2014 that you can drill high inclination wells at really shallow formations,” Kopperud says. “There are a few fields in the Barents Sea where that’s a requirement, [with reservoirs] a few 100m below the seabed. With conventional drilling, horizontal wells in shallow reservoir zones could be very hard to achieve. . It’s a challenge and CTD is more flexible. But you still need to be sure you can run casing. There needs to be a trade-off. Formations sediment and hole stability also need to be managed with special procedures, because you don’t have a spinning drill string to circulate them out. These are important to manage properly.”
Industry has recognized the method developed by Baker Hughes and Island Offshore. In August 2015, Island Offshore received a technology award for this exact technology during the Deepwater Intervention Forum, presented by OE, in Galveston, Texas.
For Island Offshore, the aim is to use the same principle within light well intervention, plug and abandonment as well as other types of well intervention.