PDA on the drillfloor

Elaine Maslin

April 1, 2016

The lack of automation in the oil and gas industry is a puzzle to Brian Evans from Curtin University, Australia. Elaine Maslin learned how he hopes to redress the situation.

Professor Brian Evans. Photo from University of Aberdeen. 

Brian Evans is not your traditional academic – he worked offshore in the North Sea in the 1970s, working on various vessels and production platforms, so he has an understanding of the challenges.

His more recent work has involved predictive data analytics (PDA) and it’s something he feels should be applied to offshore drilling.

“The concept is to take any form of drilling rig and retrofit by adding sensors and automation, which could detect and transmit changes in pressure, vibration, temperature and location to a local relay station, for onward transmission to a command control room,” he told Subsea Expo, in Aberdeen, earlier this year. “This data would then reduce manning levels and allow remote control with limited autonomous operations.”

But, to do PDA properly, all equipment data, historic and current is needed, including service history, component parts, and over lays of 2D and 3D displays of manufacture and installation. To these, business planning tools are added, plus engineering alternatives and data visualization tools, as well as economics and supply chain information with predicted money market movements providing an analytics tool for what Evans calls “tomorrow’s smart remote control room operator.”

Sounds simple? Maybe not, and Evans admits it wouldn’t be easy. To achieve the goal would require a sensor on every valve – when in some plant there are more than 10,000 valves onboard, which would need retrofitting, Evans says. “It also requires a fundamental belief in security and sustainability of autonomous systems that are fail safe,” he adds.

To date, moves towards automation haven’t been as strong as in other industries. For the North Sea, it amounts to unmanned monotower gas facilities. “It is pretty pathetic, this is how automated we have got in the North Sea,” Evans says.

Slightly more is being done offshore Australia. Woodside’s Angel unmanned platform, the operator’s first unmanned facility, produces 50,000 b/d. It has been unmanned for 15 years, but it does require maintenance for 2-3 days in every 45 days with temporary board accommodation.

Woodside wants to do more, however. Woodside’s CEO Peter Coleman has said all offshore facilities will ideally be automated within 10 years, Evans says. The company has over 80 analysts trying to do the basic work to make a start to fit-out platforms, on the North West Shelf alone.

It’s a big job and would be an even bigger job applied to existing drilling rigs, Evans says. What’s more, the people required to man the retrofitted equipment would need to be different, “not the blue collar worker of today, but someone who understands data, computers, and sensors, and can understand the economics and business consequences of making a decision on the fly.”

Instead, “a new paradigm is required,” he says. Evans proposes reducing the number of components requiring sensors by reducing the wellbore size. “If the rig is for exploration only, this reduction can be dramatic. Reduced rig size minimizes footprint.” Taking it a step further, the drilling rig could be moved to the seafloor, controlled from surface using umbilicals.

The coiled tubing drill rig prototype modified for use with flexible H-Coil, a potentially more durable, alternative to steel tubing, last year. Photo from Deep Exploration Technologies CRC.

Evans further proposes using small bore, composite coiled tube drilling, with a 2in-diameter borehole, drilling using a downhole turbine. Remote operated vehicles would be used for blowout preventer placement and removal and the entire unit would be mounted on a tracked vehicle for movement on the seabed. The composite tubing would contain integrated circuit (IC) chips for logging while drilling. Reverse circulation drilling would allow closed loop for drilling muds with real-time sensing and display of cuttings during drilling.

Carbon fiber drill rod is about 35% weight of conventional steel, he points out. The data from the chips could be transmitted by light through fiber or Wi-Fi when onshore.

It might sound far-fetched, but over AU$56 million (US$42.4 million) is being spent on a current long-term project with a view to its being used in onshore exploration and mine site drilling. A coiled tube rig has been built and has been working at mine sites in Australia by the world’s largest mining research project known as the Deep Exploration Technology Cooperative Research Centre (DET CRC), alongside specialist lab facilities at Curtin University in Western Australia for drilling and flow loop experiments, coiled tubing material testing and cuttings return and borehole stability studies. Composite rod development has also been underway, with the aim to someday develop built in sensors which take many more bending cycles with 24 Mpa (3500psi) water pressure than is conventionally possible.

Composite condition monitoring sensors are being researched to place on the equipment for monitoring and transmission to the control unit, in order to provide data on location, excessive vibration, stress, pressure, and temperature changes using ICs.

“We look forward to the DET CRC launch of a new prototype land-based rig (with two operators controlling it) in November this year, complete with a mud circulation, cleaning and automated sampling system,” Evans says. “Then Curtin hopes to fully automate it for operational control through the use of data analytics and the Curtin remote control room.”

The next steps then would be to take it subsea, which Bergen University College hopes to achieve, by adapting the fully automated Curtin University drilling system. In such a system, the rig would walk around the seabed, controlled by umbilicals from a single vessel on the surface. This would allow drilling to continue whether a storm is occurring on the surface or when drilling under ice.

Even just taking it offshore, replacing expensive semisubmersible exploration rigs, would have multiple benefits not just financial, but health, safety and the environment also, Evans says. Using coiled tubing would reduce the amount of pipe stored on board the rig deck, allowing a reduction in rig floor size and the dramatic reduction in number of personnel needed on the rig. But, the trick is also to use sensors embedded in the composite coiled tube, including electronic chips, which could operate during drilling, with on board real-time automated cuttings, separation and sampling.

“You have to start from the bottom and build up,” Evans says. Or indeed start from the surface and work towards the seafloor. We are someway from that at present.