Last summer’s helicopter crash off Shetland, which killed four oil workers, was the latest reminder of the dangers facing those who work offshore.
Given such fatalities, it is unsurprising operators are searching for ways to minimise the dangers their staff face.
The reason for us developing our remote operations capability is safety
ABB’s Ian Holden
Increasingly, the solution being sought is to minimise people’s exposure to these dangers by having as few people working offshore as possible.
As a result, more and more fields are beginning to adopt technology common in other areas such as oil pipelines and the water industry – that of running operations remotely.
“The reason for us developing our remote operations capability is safety,” says ABB oil & gas technology manager Ian Holden.
His firm supplies remote control room functionality for a number of fields in the North Sea, including Shell’s Draughen oil field and Ormen Lange gas field on the Norwegian Continental Shelf.
The solution enables ABB experts to operate, monitor and manage the sites’ automation and safety systems from three dedicated ABB remote monitoring and operations rooms (ARMOR) located onshore in Norway.
Through ARMOR and a 24/7 service desk, ABB is able to respond rapidly to field alerts, optimise, upgrade and evolve the systems, and collaborate on projects with Shell and authorised third parties, regardless of where personnel are located.
While safety is the main driver, remote working also brings cost and skills advantages, says Holden.
“It makes it cheaper, there’s a much lower operational cost (with fewer offshore staff),” he says.
“Another driver in the industry is that there are fewer skilled people in certain areas, and how do you make those fewer people do more across a number of assets, and big enabler for that is remote operations.”
The market drivers of safety concerns and skill shortages are now combining with the greater availability of low cost technology, he adds.
“The great enabler is fibre optics and the low cost to install them,” says Holden.
“The more data you can get, and especially in real time, the more you can do with it.”
The capability of monitoring devices and automation technology is now at such a level where it is possible to run unmanned platforms.
Typically such platforms are found within clusters, with several smaller platforms feeding back to a main platform with a centralised control room.
However, there are also now unmanned fields in development. Emerson Process Management is working to deliver an automation and safety solution that will allow the production and process platform for Premier Oil’s Solan field on the UK Continental Shelf to run completely unmanned, controlled remotely from an office in Aberdeen.
The integrated solution will use Emerson’s PlantWeb digital plant architecture, including its DeltaV digital automation system, DeltaV SIS process safety system, CSI 6500 Machinery Health Monitor, and AMS Suite predictive maintenance software.
Other elements will include Emerson’s Rosemount pressure, temperature, radar level, and vortex flow transmitters; Micro Motion Coriolis flowmeters; and Roxar sand monitors and multiphase flowmeters.
The Solan field is expected to produce approximately 40 million barrels of oil, with an estimated initial production rate of 24,000 barrels a day by the end of 2014.
As a relatively small and marginal field, a heavily manned platform would have made the project uneconomic “It’s a marginal oilfield, not the biggest of reserves, but this solution made it viable,” says Emerson Process Management strategic proposal manager, Europe Stuart Chisholm.
“[This technology] makes it possible to develop accumulations that would otherwise be too small for commercial development.”
As North Sea reserves continue to dwindle, the ability to produce smaller fields economically will likely become ever more important.
The only challenge, says Rockwell Automation UK manager for Industries Martin Walder, will be to challenge the traditional views held within the oil & gas industry.
“It’s not a constraint of the technology, it’s more the mindset of the operators,” says Walder.
While the technology is available, most still prefer the comfort of having some workers on the platforms.
“What we are seeing is more of a half-way house,” says Walder.
“People are pushing things to reduce manning, because remotely you can have specialists looking at devices on the rig giving expert advice to someone on the rig. Gradually you start taking people off and having more of a skeleton staff.”
It may also not be possible to run older platforms completely unmanned, he says.
“It’s far easier to build new assets with the capability to be run unmanned,” says Walder.
“[However] most operators of ageing North Sea assets are not able to practically run un-manned. The primary issue is that without major re-engineering the equipment is not designed to start-up automatically after a trip. There can be many different reasons why a system is tripped and dropping power at different points can leave the plant in an array of states. Older assets tend to trip more often and then take quite some human intervention to switch and sequence the start-up. Continual upgrade and renewal of control and safety systems can however make onshore monitoring easier and potentially allow a reduction of the number of operational support staff required on platform at any time.”
Looking to the future, Walder says the likelihood is that rather than unmanned platforms, fields with no platforms at all will become the common mode of production. “If I look at some of the subsea projects we have worked on, subsea compressors effectively run remotely, and everything is fed back to shore, “The thinking there of course is that eventually you get to a point where all equipment is on the subsea and there are no platforms.”