Control Centers at the Heart of Innovation, Advancement

By Richard Nemec

A well-read retired banking consultant in Chicago who wouldn’t know a frack crew from a cricket team sent me a serious article on automation and the future global workforce in the venerable British publication The Guardian. It was an interview with Oxford University Economist Daniel Susskind, talking about his latest book, “A World without Work.”

In a nutshell, Susskind doesn’t think the industrialized world is taking seriously enough the prospect for tens or hundreds of thousands of jobs disappearing in the wake of the technological advances that are occurring but hidden for the most part in plain sight.

(photo: Edmonton Control Center)

According to the U.K. economics professor, it isn’t the case that robots are stealing all the jobs. They are not, Susskind maintains. Further, entire jobs are not so much being gobbled up as are various human tasks previously thought to be beyond any form of automation. “The technologies that are really very powerful don’t look, think, or reason like us,” he told The Guardian’s Ian Tucker in mid-January. If there were artificial boundaries placed on machines in the last half of the 20th century, they have all been exceeded in the first two decades of this century, Susskind said, citing driverless autos, computer-driven medical diagnoses and identifying flying objects at a momentary glance.

The oil and natural gas sector is no different in its fascination with artificial intelligence (AI) and technology advances, but it is not clear at times what is being done cohesively and efficiently to harness these work-altering tools. However, just as technology advances have helped drive U.S. oil/gas producers to world-leading heights, operators of the energy highways – the pipelines and their sophisticated control centers – are managing to increasingly harness innovation into more efficiency.

While artificial intelligence applied to making a medical diagnosis on a cancerous tumor can be done seamlessly, robotically, and is done all the time, the diagnosis of cracks in a 36-inch- (914.4-mm-) diameter steel pipeline also can be completed that way. Management’s role then becomes a matter of determining what parts of a construction or operations or safety test absolutely need to have human intervention. The distinction increasingly is not going to be very clear cut or obvious.

“There is a precision and timeliness of some of our interactions that automation could bring to the table, but for now we have a hydraulic system, which is under development so humans can operate it with an adequate level of skill and timeliness for very good to excellent operations results. And, I think we have some seeds planted for longer-term automation,” said Frank Maxwell, the senior manager for the San Francisco-based combination utility giant Pacific Gas and Electric Co.’s (PG&E) state-of-art distribution/transmission pipeline integrated control center in North California’s suburban East Bay Area.

In 2020, after an all-out sprint the last 10 years to modernize its natural gas system, PG&E relies on an in-house developed pipeline transmission simulator technology to identify breaks in a complex pipeline system, Maxwell said. “We are doing a number of big data-related things to identify irregular paths in our regulator stations, but we leave it up to people to interpret that information and make operating decisions. I think we will rely on automation to bring information to people for a long time yet before we would ever rely just on technology [instead of people],” he said.

Chris Wu, PG&E’s manager of gas control center technology integration, thinks his utility has climbed a steep curve the last five years to adopt all the technological advances he could muster while trying to assure all the “new stuff” was being used to the maximum extent possible.

“We have more data than ever coming into the control center,” Wu said. “It is hard to say exactly where we are in terms of cutting edge, but we’re definitely not done; we’re sort of in a transition period in some ways.” He and Maxwell related this to the current demand for big data in the energy sector. It applies to what’s going on at PG&E, at least indirectly. Maxwell’s reference to finding the “bad actors on the system” before they find you, relies on big data, Wu said. There are almost unlimited data points on the system, which is indicative of the role big data now plays.

Mirroring some of the thoughts of Susskind, Maxwell and PG&E aren’t ready in 2020 to abandon the need for human intervention. Maxwell labels this as for the foreseeable future – five or 10 years ahead. “In 10 years, we most likely will be poised to do more automation; it will take that amount of time before we think it will be [viable] for a control room environment,” he said. “But to say that automation isn’t in our future would be foolish, given the level of technology advancement we have experienced over the last 20 years.”

Rest a Factor

For control rooms, the human factor of fatigue in workers gazing into computers is a continuing issue, and automation may offer some answers. “In control rooms, automation potentially can provide a back-up layer,” said Washington, D.C.-based Interstate Natural Gas Association of America’s (INGAA) CJ Osman, vice president for operations, safety and integrity. “It’s not a replacement for having people monitor the system, but the automation provides the additional layers of protection we all want to have. Like all things we are doing in the pipeline space, the drivers are safety, economics, security and the environment.”

Big operators like PG&E, major North American pipeline operators like Plains All American or global energy giants like BP  are magnets for new technology, including automation and AI. Plains operates control centers in Alberta, Canada, and Midland, Texas, the energy centers of the continent, continuously monitoring pipeline operations spread across both nations, offering safety and environmental protections.

“All of our U.S. pipeline systems are remotely controlled and monitored by the control centers,” Plains explains on its website, noting that the Midland center is operated 24/7 year-round connected to more than 850 remotely sited monitors via what’s commonly called a SCADA (supervisory control and data acquisition) system, and yes, using satellite communications, too. “We can continuously monitor conditions as we schedule and transport more than 1 billion bbls of liquids annually.

Plains touts the immense authority it gives the company’s pipeline controllers as the prime source for shutting down and restarting pipelines. “They have the authority, responsibility and obligation to shut down a pipeline when it is believed to have an integrity problem. The pipeline can only be restarted when whatever issues shut it down have been corrected, following authorization from operating and control center management, and even then, the controller has the authority to refuse to restart the pipeline if there is any remaining doubt about the line’s integrity.”

A look inside BP’s Chicago-based U.S. Pipelines and Logistics business paints a similar picture as befits the global major’s transportation and delivery hub for BP’s many business and third-party entities across the United States. This is a logistics center for one of the world’s major economic engines. It includes 3,200 miles (5,150 km) of pipelines transporting 1.1 million boe/d, carrying crude oil, natural gas liquids and refined products. Pipelines are operated from control centers in Oklahoma and Washington state, and BP holds interests that involve joint ventures and third-party-operated control centers.

(photo: Remote Operations Center)

U.S. BP officials consider the American pipelines some of the most regulated operators in the nation with the U.S. Department of Transportation (DOT) and its Pipeline and Hazardous Materials Safety Administration (PHMSA), along with the Federal Energy Regulatory Commission, all involved. “BP adheres to the highest standards of safety, and [we] have taken comprehensive steps to meet current state and federal safety and environmental regulations.

In addition to the operators on the ground, various sources throughout the oil and gas space can influence, refine and apply parts of the AI and automation world to the control room/pipeline space. Consulting, research, trade and government organizations take different bites of the automation apple, and it is left to industry to stitch together pieces from all these sources.

PHMSA, the regulator of long-line transmission pipelines, establishes minimum requirements for control room management and leak detection, but is not viewed within the oil/gas sector as particularly effective in encouraging innovation through new technology applications.

The American Petroleum Institute (API), a respected industry source for operating standards, has several applicable recommended practices covering areas in which automation increasingly can play a role: leak detection management (RP 1175), computer-based pipeline monitoring (RP 1130) and pipeline cybersecurity (RP 1164). An API official notes that the latter standard dealing with electronic security is being revised this year and is expected to emerge as a leading means of protecting pipeline SCADA systems.

In the new and modified pipeline arena, PHMSA also early this year issued a notice of proposed rulemaking (NOPR) establishing standards for gas and liquids pipelines operating to install automated shut-off valves (ASV) or remote control valves (RCV) under the title “Valve Installation and Minimum Rupture Detection Notice.”

The proposed new requirement applies to pipelines of at least 6 inches (152.4 mm) in diameter and at least 2 miles (3.2 km) in length of contiguous pipe – new or replacement. Any of these pipes need ASV/RCVs installed under the proposed regulations. According to the American Gas Association (AGA) summary of the new PHMSA requirements, valve automation, emergency response and design/maintenance requirements are included in the proposed regulations. The industry’s chance to provide input ended with a 60-day period in April.

Automation Boost

At INGAA, Osman cites the new proposed PHSMA rulemaking as a boost for eventually more automation and innovation. The goal is obviously quicker responses to incidents with more limited, benign consequences, Osman said. “I think this is one example of how automation is going to continue to accelerate.”

In addition, API officials stressed that they expect there will continue to be a lot of research/development in “technologies surrounding leak detection that will further transform the industry.” Separately, the inspection part of the business continues to evolve through application of advanced technologies and innovations.

Inline inspection (ILI) tools remain the foremost advanced technology for inspections of long-line transmission pipelines, which can accommodate the ILI technology far more widely than gathering or distribution pipelines. According to API, the tools are becoming more accurate, detecting smaller defects with increasingly greater certainty. “Operators can use this information to prioritize and fix defects before they turn into leaks or ruptures,” said a Washington, DC-based API spokesperson. “Unfortunately [although some researchers now disagree], most gathering pipeline systems are not suitable for the use of ILI tools as the pipes generally are too small [for internal inspections] and they lack pig launcher/receivers.”

API has identified alternatives available in the gathering space, including new technologies such as erosion prevention, corrosion control and plastic pipe location equipment as well as methods of creating better public awareness and damage prevention. In this year’s PHMSA research/development forum in February, new technologies for the gathering sector were one of five major topics covered.

A peek at the future of oil/gas operations can be found in a recent public speaking engagement given by Sean Donegan, CEO of his own satellite data-gathering company. In the talk, Donegan explained the latest in remote sensing and AI to a health care industry conference in Austin, Texas. His presentation laid out how his satellite technology can be applied to forward-looking threat monitoring for oil and gas pipelines. His team at Toledo, Ohio-based Satelytics Inc. uses AI to “sift through billions of pixels of data to provide our customers with feedback to challenging problems they face in the field. Our AI means you can save on costs associated with employees reviewing imagery or field monitoring.”

Helping operators in the Bakken and Permian Basin, Satelytics promotes itself as a cloud-based geospatial analytics software suite. Multi- or hyper-spectral imagery is gathered from satellites, drones (or “unmanned aerial vehicles”), planes, and fixed cameras and processed to provide both alerts and qualitative results. Providing daily data if needed, the output identifies specific problems and locations, with both magnitude and qualitative information.

For operators tied to Canada’s considerable long-line pipeline network, the sky’s the limit for innovation, too. Besides the growing use of satellite-imaging technology, the Canadian Energy Pipeline Association (CEPA) tracks and incents increased technological advances by its member pipeline companies. An example is the CEPA Innovation Award-winning Calgary-based firm Hifi Engineering, which is “set to become the new global standard for pipeline monitoring,” according to CEPA officials.

According to CEPA, high-fidelity density sensing (HDS) uses specialized fiber optics (not to be confused with telecom fiber optics), fully distributed along the pipeline to sense every centimeter, so operators can know exactly where a leak occurred or where there’s potential for a leak. HDS sensing is a 24/7 activity, with a level of accuracy that can detect a pinhole leak, the Canadians said.

In Canada, CEPA is also pointing to more innovation in the nation’s burgeoning petrochemicals space, citing the massive Heartland Petrochemical complex under construction as the nation’s first industrial site to combine production of propane dehydrogenation (PDH) and polypropylene (PP), which can be found in the auto, medical and telecommunications industries. Any modern consumer is likely to be using a product that includes PDH or PP. Calgary-based global energy infrastructure company, InterPipeline, is developing the petrochemical center for opening in 2021.

“It will be able to convert locally sourced, low-cost propane into 525,000 tons (476,272 tonnes) annually of polypropylene – a high-value, recyclable, easy-to-transport plastic used to make a vast range of finished products,” according to InterPipeline’s website. CEPA cites these projects as ones in which automation and innovation are helping to continue to make North American transmission pipelines and related facilities like Heartland among “the safest, most responsible way to transport energy in Canada and the world.” In 2020, they expect more industry developments that underscore their contentions.  

Back in the United States, INGAA officials keep tabs on the technology shifts by their pipeline operating members and various equipment manufacturers. Mike Isper, director of security, reliability and resilience, sees in the future big data being more of an influence over various inspections for anomalies and ILI tests. “Some of the manufacturers are incorporating various new technologies, and the sector is getting really robust data management capabilities from the increased digital protocol now being applied to operations,” said Isper, adding it is part of the push for big data. “You’re just capturing any and all data points out there that you can.”

Isper’s colleague C.J. Osman concurs. “We’re starting to see that with the data acquisition capabilities we have now that we didn’t have five or 10 years ago. It can analyze inspection data and identify trends,” he said. Another example is satellite-based leak detection technology.

Multiple companies are pursuing it, Osman said. AI is another area where companies are looking for what Isper calls “more predictive analysis and system behavior awareness.” For INGAA members, the opportunities are almost endless, they said.

‘Different World’

In the prolific Bakken Shale play in North Dakota there is a university-based, industry-supported program addressing automation and innovation called the Intelligent Pipeline Integrity Program (iPIPE) in which energy industry and academic research engineers work closely on projects such as satellite monitoring and inspecting of pipelines. Led by the industry, iPIPE’s mission at the University of North Dakota-based Energy and Environmental Research Center (EERC) is “advancement of near-commercial, emerging technologies to prevent and detect leaks from gathering pipelines.”

EERC officials recognize that automation is broadly creeping into pipeline construction and operations/maintenance more and more, particularly in the U.S. gathering systems that have not had much in the past. “If we’re talking about transmission pipelines, that’s a different world from gathering,” said Jay Almlie, principal engineer at the EERC in Grand Forks, North Dakota. “Both have only become important in North Dakota in the last four years.” He adds that North Dakota was the first state nationally to begin regulating gathering pipelines – small-diameter, nonpiggable pipes.

“Now you have these two worlds with different regulators, and automation is becoming increasingly important in both,” Almlie said. “The reason I make the distinction is because in the transmission pipeline sector, automation has been important for years because they are handling a lot of dollars flowing through those pipelines. In smaller pipelines where the economics are smaller, automation has been slower to creep in. It certainly is happening now, especially with a little bit of pressure from regulators.”

Almlie stresses that gathering sector automation mostly involves valves and regulators. Also, like the sector’s counterparts in transmission and distribution, control centers operate most large gathering systems, and those centers are applying more automation.

Almlie said monitoring of the pipelines is becoming more automated. “Instead of having a team of live operators staring at screens in a giant control room, you might have more AI applied to cut down that workload and help the human operators stay focused on what absolutely needs human intervention. In many flavors, automations continue to creep in across the board, and much of it is being boosted by technologies, such as AI,” Almlie said.

The need in the industry to optimize costs and safety with a relatively low global oil price is helping drive automation, Almlie believes. That’s why this year he expects iPIPE-backed satellite efforts will be prevalent in the Bakken. “And I think that is going to be duplicated in [other oil/gas-producing states like] Texas, Pennsylvania, Oklahoma, Colorado, Louisiana and elsewhere. My ‘lowest hanging fruit’ right now are satellites for work not just with pipelines, but also well sites.

“Some of this new work is going to spill into transmission,” said Almlie, noting that two of iPIPE’s latest members are major pipeline developer/operators, TC Energy and Energy Transfer Pipeline (Dakota Access Pipeline), because they have an interest in what we’re doing at EERC. A third major, Enbridge Pipeline, joined the EERC program in 2019 for the same reason,” he said. “They all joined because they saw what we were doing originally in just the gathering space.”

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