Energy producers look to Industry 4.0 for new ideas on automation, use of sensors, big data and remote monitoring, creating opportunities for tech startups.
After petroleum prices collapsed in the mid-2010s, shale oil and gas producers responded to the down-swing by borrowing techniques and technology from the energy sector’s offshore well operations, manufacturing, and even the medical industry to increase efficiency.
The energy producers looked to Industry 4.0 for new ideas on automation, use of sensors, big data, and remote monitoring. In the process, they created opportunities for technology startups such as unmanned aerial vehicle inspection companies. From medicine, major energy producers such as ConocoPhillips borrowed DNA sequencing and mathematics used in MRI scanning to rely less on core sampling and drilling blind in their quest to squeeze more oil and gas out of rock.
“Based on our discussions with companies, I would say prior to the collapse in oil prices they were not so concerned with looking for all possible ways to maximize efficiency,” said Artem Abramov, vice president of shale research for Rystad Energy (Oslo, Norway), an independent energy research and business intelligence company providing data, tools, analytics and consultancy services to the global energy industry. “It created technology startups within the last two years, and I expect to see more.”
At the start of 2018, there were about 750,000 producing shale and conventional oil and gas wells in the United States. Of those, 207,000 were horizontal hydraulic fracturing wells and 115,000 of them were traditional horizontal wells, according to Rystad Energy data. The data show that among 23,000 new producing wells expected this year, 15,000 will be horizontal drills with an estimated cost of $6.45 million for each one, although there are significant cost differences across basins.
With increased efficiency, the industry would normally expect to see a decrease in employment. But other forces have created a paradoxical effect on the demand for shale oil and gas workers, ranging from truck drivers to petroleum engineers. “On one hand, any automation should have a negative impact on employment,” Abramov said. “But since the shale industry is ramping up, the demand for skilled and even less-skilled workers is high.” As a result, unemployment is at record lows in areas such as west Texas, site of big deposits and drilling activity in the Permian Basin.
Unskilled workers aren’t the only ones in short supply. When petroleum prices collapsed in 2015, enrollment in petroleum engineering university programs fell. This has made engineers, hard to find, Abramov said.
Shell invents ‘Shale Field of the Future’
In the midst of its ramp up, Royal Dutch Shell (The Hague, Netherlands) realized that in order to pump 11 billion barrels of discovered and prospective oil in shale deposits it needed to do things differently. Company leaders challenged the organization to either increase revenue or reduce costs while maintaining a steady capital investment. As a result, the producer borrowed heavily from manufacturing and Industry 4.0.
“When we framed the iShale program, we very carefully and intentionally looked outside of the usual exploration and production industry alliances at some of the innovative players that had been active in automation, digitalization, and so forth, in manufacturing,” said Frederic Wasden, iShale project manager. “And that was a real head start for us because in Manufacturing 4.0 there are a number of industries that have been at this for quite some time. Before developing anything new, our goal was to leverage existing technology that is commercially available. With this approach, we feel that the risk of the technology from a hardware perspective is relatively low.”
To build the shale field of the future, Shell formed alliances with companies that could help the energy producer with automation, remote monitoring, use of sensors, robotics, data collection and analysis, cloud computing and use of solar energy and energy storage batteries to reduce operating costs.
Dozens of different kinds of sensors that feed information to an advanced analytics center will be deployed for critical functions: cameras to detect methane leaks; infrared to confirm tank levels and spot intruders; and acoustics to determine if a pipe is eroding. “We are the beneficiaries of the work that’s been done by the broader manufacturing business in adopting those sensors and therefore enabling the providers to scale these up,” Wasden said.
The first phase of iShale is to demonstrate in the Permian Basin asset that Shell can achieve cost savings, production improvements, and safety enhancements by modifying the way it works. As a result, it can take advantage of the data that’s available in its operations and combine that information with advanced analytics to figure out how to optimize its production and maintenance practices.
Remote support for well drilling and maintenance is one of the cornerstones of the program. Shell personnel monitored and advised on a new well being drilled in Argentina from its monitoring center in Calgary, Alberta. Once a well is operating, maintenance personnel supplied with remote surveillance information can arrive equipped with the right safety equipment and parts, which demonstrates another advantage. The objective is to avoid overspending by doing unnecessary maintenance while also eliminating operational shutdowns because a critical part or piece of machinery has failed.
The energy giant has also transferred technology used in its own deepwater operations to its onshore wells.
“Offshore, weight and space are at an absolute premium,” said Wasden. “Industry has figured out how to separate gas, oil, and water in a very small vessel. That same technology brought onshore enables us to put our separation equipment on a truck-mounted skid as opposed to building a more conventional separation plant or central processing facility.”
Greg Guidry, executive vice president of Shell’s unconventional business, told the RigZone website in October 2017 the desired outcomes for iShale include: automated and integrated wells and completions; scalable, modular central facilities designs; intelligent well pads and wireless communications enabling multi-phase flow and separation; digitization and automation-enabled management by exception or standard field surveillance; and an “organization of the future” with “broad skill base” personnel who are digitally connected and cross-trained.
Eyes in the Sky Depends on Library of Data
The downturn in oil prices and subsequent hunt for cost savings by producers turned out to be very good for companies like PrecisionHawk (Raleigh, NC), a remote sensing company that uses unmanned aerial vehicles to do inspections for 10 of the top 20 largest oil and gas exploration and production companies.
Various regulatory bodies at the state and federal level demand many types of inspection of oil and gas production assets on different schedules from monthly to annually. While producers can build in sensing technology to monitor new well sites, the cost of retrofitting that measurement equipment is much higher than using drones to perform the same type of inspections for legacy fields.
“The problem is they have lots of well sites that have been up for years; it doesn’t make sense to add a $10,000 sensor to each one,” said Patrick Lohman, vice president of energy for PrecisionHawk. “That’s where drones really come in.”
There’s a good reason that drones are a good fit for the job. Well pads can be situated up to the length of two football fields away from each other, and local roads usually offer an indirect route from one to another. As a result, a technician can drive to up to 10 sites a day to do inspections, Lohman said. In contrast, a trained drone operator can send his aerial vehicle to 100-125 well pads in a day, depending on density.
Not only is a drone more efficient, there may be no loss of quality in the inspection process to look for anomalies. “In a lot of cases, a drone can detect anything a person can detect,” Lohman said.
That includes cameras to see if vegetation is encroaching on the well pad; thermal imagers to detect methane leaks or overheated components; methane lasers to measure concentrations; and multi-spectral sensors to detect pooled water.
“We are focusing on stacking applications in order to deliver clients depth in geospatially tagged information,” Lohman said. “With a depth of structured data, PrecisionHawk will be able to work with clients to use artificial intelligence applications to lower maintenance costs.”
PrecisionHawk is developing visual learning tools that will work in coordination with AI applications to use drone-collected, geospatial data to recommend preventative maintenance and predict equipment failure. As they collect more data economically, their toolset improves.
Going Medical Prescribes Where to Drill
At ConocoPhillips, geoscientists are borrowing techniques used with medical magnetic resonance imaging for assembling and analyzing data obtained from seismic readings for a proprietary process known as compressive seismic imaging, according to a transcript of a November 2017 analyst and investor meeting. Their target is the Permian Basin.
With compressive seismic imaging, “instead of an orderly sampling pattern like you normally have in seismic, there is a random sampling and then we use mathematics that come from the medical field,” Al Hirshberg, ConocoPhillips executive vice president of production, drilling, and projects, said during the meeting.
Mathematics applied to tomographic (i.e., by sections) imaging give a 10-fold increase in definition. The same mathematics can be applied to seismic point data to give a similar increase in definition.
“… or of course, you can shoot less seismic points and get the same resolution you had before for a much lower cost,” Hirshberg said.
Shale operators also employ DNA sequencing that’s become essential in medicine. But the energy producers’ sequencing targets are the microbes that live in the pore spaces and fracture networks of rocks. They use the results to assess the potential and movement of oil in order to optimize well placement, monitor well connectivity, and measure production over time for completions, according to the website of Biota Technology (Houston).