Machine over Man
Gone are the days when manual labour drove the bulk of the work in oil and gas exploration. In a post-peak-oil era, in which resources are harder to extract and oil prices continue to plunge, the race towards automation means higher profitability — and less human error.
by William M. Glenn
Out on the oil patch, opportunity comes to the firm that can do the job more safely, cheaply and quickly. “The motivation for technical innovation has always been threefold,” says Mark Salkeld, president and chief executive officer of the Petroleum Services Association of Canada (PSAC) in Calgary. “First and always foremost, companies are striving to improve safety. Second, to reduce costs and improve margins, and third, to gain the edge that will win them the next contract.”
Salkeld served in the oil and gas business for 36 years before joining PSAC, the national trade association of the upstream petroleum industry. He started as a mechanic on drilling rigs before working his way up the ranks through maintenance, human resources, safety, operations, procurement and back to school for business and management degrees. He has seen oil at $20 a barrel and at $150 a barrel; he has also witnessed the oil business at its height and nadir.
When Salkeld started in the sector, crews would set up around drilling rigs in their campers and school buses for the whole summer. “It was like a gypsy camp,” he recounts. “Many men brought their families along.” Today, with modern drill bit technology, high-tech rigs can eat through 2,500 metres in two-and-a-half days, and crews are always on the move. “I expect we will see totally robotic rigs in the field in the not-too-distant future.”
Not like the old days
“It is rare to see a worker even touch a piece of pipe on one of our automated drilling rigs,” says Bob Geddes, president and chief operating officer of Ensign Energy Services Inc. in Calgary. Ensign’s design team has worked to engineer out any manual intervention in the drilling process. For example, an automated skate-catwalk system brings the drill pipe up to rig floor, where the top drive grabs it and pulls it up, and an “iron-roughneck” makes the connection and lowers the pipe back to drilling.
Founded in Western Canada in the late 1980s, Ensign currently runs some 200 rigs across North America and around the world. Ten years ago, the company launched a $4 billion building program, adding state-of-the-art rigs, better controls and new features. “We design them to be faster and safer by testing technical innovations in the field and then make them part of the next generation of rigs,” Geddes says. “An $8 million old-style rig costs $20-to-25 million today, but drills a well in a quarter of the time of conventional rigs.”
The modern Automated Drilling Rig (ADR®) is not only highly mechanized; it is also more versatile. Using a hydraulic system, the self-walking ADR can crawl along the well pad to drill a series of wells 25 feet apart. And if relocation to a different site is necessary, the rig can be broken down and set up two to three times faster than the old models, cutting well-construction costs and improving safety.
“We have entered the mechanized age of oil and gas drilling,” Geddes says. “Over the last year, half the Ensign rigs around the world didn’t report a single lost-time accident.”
Oil and gas companies still need the same-sized crew — trained, experienced and safety-savvy — but now, they come equipped with a new skill set. “The average driller is likely more adept at wielding a joystick than using a sledgehammer,” Geddes says. “Working on one of the old rigs was like flying a Cessna. The new rigs are very instrument-driven; it is more like flying a jumbo jet.”
Think outside the box
In order to succeed these days in oil and gas exploration, mining or some other form of resource extraction, “you have to achieve much higher levels of productivity than you did in the past,” says Professor Scott Dunbar, Ph.D., department head of the Norman B. Keevil Institute of Mining Engineering at the University of British Columbia in Vancouver. It is not simply a matter of slashing staff and payroll. “Any workers freed by technical innovation should be reassigned to other jobs,” he says.
That means training has to keep up with changing technology. “You have got to keep learning, mastering new skills, if you want to be successful,” Prof. Dunbar suggests. “Oil and gas production is no exception. You need trained people to understand how to run and take advantage of technical innovations.”
As head of the Institute, Prof. Dunbar spends a lot of time visualizing the mines and oil fields of the future. “With oil at $50 a barrel, you have to look at boosting efficiencies,” he says. “You have to start thinking outside the box.”
That is why some companies are investing in the next generation of self-driving trucks, automated drilling rigs, advanced sensors, digital technology or big data analytics to help locate viable reserves. In addition to the need to boost profitability, Prof. Dunbar sees several factors driving innovation. One of them is resource extraction, which is a huge consumer of water and energy. As such, it is worthwhile to consider ways to conserve and recycle to shrink the sector’s environmental and carbon footprints.
There is also a need to work harder to win the support of local communities and indigenous populations that might oppose wasteful or environmentally intrusive resource-extraction methods. Thirdly, because it is harder to find rich deposits, new ways need to be developed to exploit low-grade deposits, even abandoned tailing piles, profitably.
“All efforts to revamp the sector start with the twin objectives of improving productivity and upgrading training,” Prof. Dunbar says.
Machines, not men
Modern drilling practices “really lend themselves to the industrialization of the process,” says Kevin Neveu, president and chief executive officer of Precision Drilling Corp. in Calgary. “There are two things happening at the same time: we are replacing people with machines, and we are applying computer controls to the resulting mechanized system,” he says.
Precision operates some 255 land-drilling rigs, primarily in Canada and the United States, as well as in Mexico, Kuwait and Saudi Arabia. Over the last six years, the company has added 150 rigs to its fleet at an estimated cost of $20 million each, while 100 older rigs have been upgraded to incorporate advanced drilling technologies. It has also retired 250 older, lower-specification rigs.
“Once you have mechanized much of the [drilling] operation, you can start replacing manual controls with automated systems,” Neveu says. The company is planning to have a drilling operator in the control room to provide operational oversight, while the control software manages routine operations.
“It can be challenging for even the best drillers to remain fully focused over a 12-hour shift,” Neveu points out. All of the driller’s decisions and adjustments may be within acceptable parameters, but still exhibit individual variances that are less than optimum. “Computer control eliminates not only human error, but human variance as well,” he says. “This is a very important element when drilling the same well over and over again.”
While replacing men with machines on a rig does not reduce the “head count” on the drilling site, increased mechanization and automation means increased routine maintenance. This requires a revamped skill set and more in-house training. “Most of this maintenance work is conducted in a controlled environment while the rig is idle,” which Neveu thinks is much safer than the heavy labour work previously undertaken prior to mechanization.
Once an array of oil or gas wells has been drilled, Precision moves on to the next site, and other companies move in to conduct the hydraulic fracturing and other wellsite operations. “We sometimes find ourselves spending more time moving rigs than drilling,” Neveu says. The logistics of moving people and all that equipment around are enormous, and the risks of being on the road are much higher than the risks of working on the rig itself, he notes.
With increased automation comes heightened concerns about cyber-hacking and sabotage. “I probably spend as much time talking about cyber-intrusions with my Board as I do about any other outside risk,” Neveu says.
Fortunately, all the operationally critical functions — including those controlling the flow of pressure and energy in the system — are closed systems, not connected to the Internet and cannot be accessed through outside portals.
Some data-monitoring information is transmitted from the drilling site back to corporate headquarters, but “there is no capability to control operations remotely,” Neveu explains. That should eliminate the risk of cyber-hacking.
“Absolutely everything we do is screened through our commitment to safety,” Neveu says. He also stresses that improved safety is a function of mechanization and automation, prescriptive written procedures, ongoing training and intensive process management “that are all part of our corporate culture.”
As a result, the company is closing in on its targeted zero-accident rate. Over the last year, 98 per cent of its rigs were incident-free. “We have achieved unheard-of levels of safety on drilling rigs. Our safety performance is on par with the incident rates only experienced in a highly controlled factory environment,” he adds.
Automation is occurring not only in the increasing control of operations by computer systems; trucks that are widely used on the ground are also going driverless. For the last three years, Suncor Energy has been field-testing a small fleet of six Komatsu driverless trucks at its base-plant oilsands operation near Fort McMurray, Alberta. That number will increase to 19 as the company moves into a commercial scale evaluation over the next six to 12 months. “Eventually, we anticipate that Suncor is going to replace all of its heavy trucks, a total of 200 vehicles,” says Ken Smith, president of Unifor Local 707A, the union that represents some 3,400 workers at the site.
Since 2008, Komatsu America Corp. has offered an “autonomous haulage system” (AHS) on its Frontrunner series of electric-powered mining trucks. According to a statement from the company, these driverless vehicles are operated by a supervisory computer through vehicle controllers, a global positioning system (GPS) and a wireless network and supported by a sophisticated obstacle-detection and collision-avoidance system. Whenever the sensors detect a person, manned vehicle or other obstruction inside its hauling course, the vehicle automatically slows down and comes to a stop. “There are a lot of safety features built into the truck,” Smith says. “They seem to work quite well — at least, they have through the test phase.”
While the automated equipment is already being used elsewhere in the world, including several fleets at hard rock mines in Australia and Chile, there is nothing in place on the scale that Suncor plans. The company’s website lists several advantages that AHS technology offers over existing truck-haul operations. They include enhanced safety performance, decreased equipment stoppages, reduced maintenance requirements and reduced environmental impact through better fuel efficiency as well as lower greenhouse-gas emissions.
But Smith’s biggest safety worry is cyber-hacking. “These systems are not infallible, and a 430-tonne truck would be a great toy to play with for some hacker hiding in his basement,” he cautions. A few months ago, all the trucks onsite came to a complete halt when the Northern Lights interfered with their control signals. “Somebody more sophisticated than me might be able to do the same or worse.”
Suncor’s primary motivation for going driverless is to improve its bottom line, according to Smith. Those big trucks run 24-7, and each requires four five-man crews working 12-hour shifts, three days a week. “By going driverless, eliminating work time, downtime and coffee-break time, Suncor estimates it will eliminate some 800 jobs and save $200 million a year in salaries,” he says. In addition to the drivers, the company will not need as many supervisors, managers and human-resources or other support personnel.
But the transition to self-driving transportation will require an increase in support services. The roads where the driverless vehicles travel will have to be more carefully graded and maintained. “In winter, huge clumps of frozen bitumen can spill from the back of a heavily loaded truck,” Smith says “A driverless truck will stop dead if it detects anything in the road ahead.” Spring breakup and heavy rains during warmer months can also play havoc with the roads.
“While a few more people will be employed monitoring the vehicles during the phase-in period, that number will fade as the company gets better at it,” Smith predicts.
The potential labour savings are too enticing for the company to back off. Once Suncor goes entirely driverless at its Fort McMurray base plant, one can expect its big fly-in-flyout operation in Fort Hill to follow suit. “That means another 600 to 700 drivers, as well as all the people that feed, house and support them,” Smith says. If the other big producers, including Syncrude, CNRL and Shell, do the same, “we will lose tens of thousands of oilsands and spin-off jobs in Fort McMurray.”
According to Suncor’s Report on Sustainability 2016, the company recognizes that “any new technology means changes to the required skill sets for workers.” While Suncor admits finding skilled labour continues to be “a challenge” in the Fort McMurray area, the driverless technology could create different kinds of employment opportunities. “It is something we will work through with our employees if and when we decide to implement this technology,” the report says.
“When these companies came to northern Alberta, they were awarded leases on the understanding they would provide good, sustainable jobs,” Smith notes. “In turn, they have made a lot of money. That is only fair, but this move to automation is swinging that deal out of balance.”
Paving the cow path
While a self-driving truck is a particularly enticing idea from a cost-savings perspective, simply replacing manned vehicles with a driverless version can be a little like “paving the cow path,” essentially making a cosmetic improvement to the old way of doing things, Prof. Dunbar suggests. “It might be better to invest in a fleet of smaller trucks. They are cheaper, easier to maintain, and when one breaks down, it does not disrupt the whole production line.”
One pertinent question is whether automating some systems should even be considered at all, when employers could explore alternative ways of getting resources out of the ground. Dunbar can envision a day when a mine or a well does not mean a hole in the ground. “It could have a zero footprint. No one would even know it was there.”
With the advent of in-situ or near-situ mining, processing using directional drilling and distributed processing systems perhaps using biotechnologies, “the actual resource extraction might all be undertaken by a large number of smaller, less expensive machines or systems, all automated and coordinated to work together by some central A.I.,” Dunbar speculates. “These systems could be owned by individuals or small companies leading to the ‘uberization’ of resource extraction one day.”
Taken to the extreme, one may not even need miners to work underground or in large pits. Small or independent operators could be sitting in a control room in front of computer screens, running systems to produce resources. “A company of the future would become a supply company providing resources from these operators to best satisfy demand for a particular product,” he suggests.
Salkeld points out that following the collapse in oil prices, “the first strategy of many producers was to tell all their contractors to slash their invoices by 30 to 40 per cent.” As investments in the research and development that spawns technical innovation comes out of healthy margins, “we are concerned that there will be a gap in R&D spending until the industry gets back on its feet.”
Nevertheless, Salkeld has faith in the dozens of small and medium-sized companies that make up a big part of the service sector. “While the broader industry is not doing as much as it could through this downturn, individual oilpatch workers are still working on innovative ideas, sometimes on their own time, in their garages and their backyards,” he says. “You are always trying to identify the most dangerous job on the oil patch and then find a better way of doing it.”
Just five years ago, he recalls, there would be 15 to 30 trucks parked around a fracking site. Each one would have a person wearing headphones handling the pump, working independently to adjust the pressure and fluid movement at the direction of staff in the control room. “If anything goes wrong, the last place you want to be is standing next to a pump under 10,000 to 15,000 pounds of pressure,” he says.
Today, there are just two guys in the control trailer, coordinating all those pumps with AC drive motors and programmable logic controllers. “It is all about separating the worker from the risk,” Salkeld notes.
William M. Glenn is a writer in Toronto.