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The oil and gas industry’s shift towards automation and digitisation in order to improve efficiency is starting to yield results, writes Anna Kachkova in Houston

What: The oil and gas industry has started to recognise the need for automation and other technological advances.
Why: Such technology is being found to bring down costs and increase efficiency.
What next: Bringing about a culture change among industry personnel remains the main challenge.

The oil and gas industry is increasingly turning to automation and digitisation – a shift that has been accelerated by the collapse in oil and gas prices. With cost-cutting and efficiency gains being pursued far more aggressively in a low crude price environment, oil and gas companies have become ever willing to consider new options, and automation features prominently among these.

Such technological advances were one of the topics discussed at the CERAWeek by IHS Markit conference, held in Houston earlier this month. Indeed, IHS Markit’s vice chairman and the chairman of CERAWeek, Daniel Yergin, observed that the main takeaway from one March 6 plenary session was that “big data” was going to be the next technological breakthrough for the industry after shale drilling.

During the plenary, Schlumberger’s executive vice president of technology, Ashok Belani, said that data usage was much more helpful as far as advances go than the most recent efficiency gains made in shale drilling, such as variations in the number of frack stages.

Other speakers at the conference also touched on the subject, but noted that the industry was still in the initial stages of harnessing big data and still had much to learn about this.

Capital project crisis

The increased willingness to embrace digital technologies is already starting to yield results, though, officials from Emerson told NewsBase on the sidelines of CERAWeek.

Emerson’s group president of systems and solutions, Jim Nyquist, said that in recent years, the oil and gas industry had undergone a capital project crisis. “The research we’d had said that 65% of the capital projects over US$1 billion failed. And that’s either 25% over budget or 50% late,” he said. Once the oil price fell below US$50 per barrel, this became even more of a critical issue, according to Nyquist.

Emerson’s research showed that the top operators spent half the money and took half the time to build a facility compared with the worst-performing companies. Emerson collaborated with companies including ExxonMobil, Royal Dutch Shell and BP, as well as smaller independents, to identify numerous technologies and processes that could address this.

“We really focused on three things. One was eliminating or automating work,” Nyquist said. “The second was reducing the complexity of projects.” During the era of high oil prices the trend had been towards customisation, but as companies sought to cut costs, there was a shift towards standardisation.

“The third area we worked on was reducing the impact of late-stage changes,” Nyquist said, adding that such changes would always happen. “We typically wind up, from an automation standpoint, on the critical path during the commissioning.”

These technologies were already being rolled out – in Emerson’s case over the past five years. Operators and engineering, procurement and construction (EPC) companies have been seeking a 30-40% reduction in total installed costs, Nyquist said. “And we’re meeting that target,” he added, citing ExxonMobil and Shell as examples of the companies benefiting from this.

“I’ve been in this business a long time, but I’ve never before seen a time when we’ve had such an inflection point, where we could drive this kind of transformational change.” He noted that resistance to change was still a challenge when things had always been done a certain way, but said the awareness and the need to change was also now there.

“And it’s not just the automation system that we’re trying to have an impact on, we’re really using the automation as a lever to other parts of the project,” Nyquist added, citing the elimination of engineering hours and wiring costs as examples.

Operational gains

The benefits of automation and other technologies can extend well beyond the capital investment stage of a project. Emerson’s chief strategic officer, Peter Zornio, cited sensors, control valves and software applications that could all be used to boost operational decision-making once a project has started up. With producers chasing cost savings across the board, there is a considerable amount that can be automated on the operational side as well.

“When we come in and we automate it, we put in sensors – that’s always the first step,” Zornio said. “You can’t really do anything unless you replace intermittent data with reliable, real-time digital data.” Once such sensors are installed, this allows for the data to be pulled together, and reduces the need for people to be in the oilfield themselves carrying out monitoring, Zornio said, adding that this was particularly important offshore, from a safety point of view.

“Second, we put in controls,” he said, citing the need for controls on separators, valves and pumps. “So we’ve pulled people out, we’ve automated to make it run better and produce more, then we’ll put in sensors to monitor the actual equipment, not just the process.” This includes, for instance, monitoring vibration on pumps, corrosion and the presence of hazardous gases.

For producers that operate large oilfields or multiple offshore rigs, all the data can be brought back to an integrated operating centre, Zornio said. And operators are seeing this as a “strong, reproducible lever to get costs down and increase production”. He added that using an integrated operating centre provided an opportunity to speed up decision-making because of the multiple disciplines present in such a facility.

But perhaps the biggest benefit, according to Zornio, is the availability of real-time production data that the producer can then compare to its initial reservoir model and plan for developing a given field, readjusting the plan and model if necessary to increase recoveries. “And that’s more of a long cycle thing – 10, 20, 30 years – but that’s really big dollars if you’re looking at something like a field in the North Sea or in the Gulf of Mexico where you’ve made a big investment in a lot of assets.”

Zornio cited a further benefit of digitisation – with the industry concerned over the impacts of a potential brain drain as its most experienced people retire, the ability to process data remotely rather than having to be in the oilfield could allow some of these retired experts to continue working part-time to analyse data remotely.

Asked whether oil and gas automation is a risk to jobs, Nyquist said that it actually creates new jobs, but of a different type and requiring different skills.

“I don’t think we can lose sight of the fact that in countries like the UK and the US, without automation you’re not going be globally competitive against emerging economies that have much lower labour costs,” Zornio added.

Culture change

Zornio cautioned, however, that while progress had been made, a number of challenges still remained. He cited Shell, BP, ExxonMobil and Statoil as examples of companies that had brought in some of these processes and technologies, but noted that they had done this internally, inside their own computing networks. Meanwhile, he suggested that it could be more beneficial for producers to turn to third parties with outside expertise to analyse their data for them. “That’s not a model most of these companies are used to,” he said, but noted that as the most experienced people retire from the industry and expertise is lost, there was an opportunity for a third-party service to come in and help.

Now, one of the challenges for companies such as Emerson is making producers more comfortable sharing data with them. Zornio noted that data around equipment was not so proprietary, and companies could be more willing to share that than data around production from a particular field, which is highly proprietary. Once again, though, the oil price downturn has increased the degree of acceptance around the idea of sharing data with third parties in order to cut costs and boost output, he noted.

Companies are not as far along in the digitisation process as the super-majors, especially those with older assets. “Offshore is probably the biggest target because there is the biggest potential for returns,” Zornio said. “The cost and safety implications for the people out there are the highest.”


Another challenge is cyber-security, which is increasingly in the spotlight as the industry adopts the “Industrial Internet of Things” (IIoT). “There are a lot of technologies you can apply to cyber-security,” Zornio said. He noted that when people thought of cyber-security, they often thought of technological aspects such as firewalls to protect data. “But the hardest thing in cyber-security is people, again,” he said. According to Zornio, penetration testing on Emerson’s systems found that if the testers get in, it was through social engineering every time.

“That is really the biggest thing that’s got to change in our experience,” he said. “When you look at safety, people have done a fantastic job of drilling that into everyone’s head. Nobody is going to walk out into the oilfield without putting a hard hat on, or their protective gear, but they still think nothing of writing their password on a sticky note and putting it on the control screen.” But in the same way oilfield safety practices have been instilled into industry workers, cyber-security practices can also eventually be instilled, through monitoring and training.

“In the power industry in North America there is actually legislation requiring a certain amount of cyber-security defences in place around control systems,” Zornio said. “That hasn’t come to oil and gas or other industries yet, but it likely will. I think it’s only a matter of time.”

What next?

Emerson, like many of the upstream players talking at CERAWeek, is confident that an oil industry revival is under way. “We see work coming back,” Nyquist said, adding that certain projects that had been delayed during the downturn were already being revived. “We can see it in terms of what we call our project pursuit funnel of jobs that we might be pursuing. That funnel is up and we’re doing a lot more proposals.” In line with the industry’s shift away from mega-projects, Nyquist said he anticipated fewer mega-jobs in the industry, but a lot more smaller jobs and phased jobs. “There will still be a lot of projects, I think, especially where we can get low-cost production,” he added. While he said he expected the Permian Basin in particular to rebound quickly, he also anticipated a global recovery over the next 2-3 years.

Though both Zornio and Nyquist agreed that the industry will not be seeing prices above US$100 per barrel again in the near future, they noted the industry had become much responsive to price fluctuations and was better placed to operate at lower prices. Comments from various speakers at CERAWeek seem to back this up, and efforts to automate and standardise have played a part in this.

Speaking at one of the conference sessions, Shell’s executive vice president of commercial and new business development, Edward Daniels, talked about how the super-major had re-engineered deepwater Gulf projects such as Vito to bring down costs, for example by implementing a phased approach like the one Nyquist talked about. Daniels also noted the company’s efforts to standardise well design and components in order to bring down the cost of the recently sanctioned Kaikias deepwater project.

Onshore, operators are also embracing new ways of working, with Range Resources’ chairman, president and CEO, Jeff Ventura, saying the company was trying to use data better for completions, efficiency gains and improved decision-making.