Walking the exhibit floor earlier this week at the SPE Hydraulic Fracturing Technology Conference seemed weirdly normal. During the coffee breaks, the number of people networking, checking out booths, and filling the show floor felt like the old normal.
The new normal has its differences. The number of COVID-19 cases is declining but remains high, and the unconventional oil business is defined by a relatively small group of big, cost-conscious operators whose slow-growth approach is benefitting from high oil and gas prices.
The opening sessions reflected other changes with a panel discussing the role of fracturing in a carbon-conscious new energy economy, from opening flow paths for geothermal heating to electric-powered pressure pumping.
The moderator of the panel, Chris Wright, the CEO of one of the biggest pressure pumping companies, Liberty Oilfield Services, acknowledged that the drive to lower carbon dioxide emissions is backed by plenty of environmental groups who would like to see oil and gas phased out.
And that has been the case as long as this conference has been running. “We were not popular then, and we are less popular today,” he said.
He explained that sentence by saying he needed to “wake everyone up,” and to make the point that those who have believed in fracturing have overcome the opposition of outsiders and the doubts of insiders who did not realize the potential production that fracturing could yield.
The panel focused on electric-powered pressure pumping as an example of an innovation that offers lower emissions and needs to show it can offer equally strong economic benefits.
Carbon impacts matter to oil companies due to pressure by investors on companies to pay more attention to their ESG scores—a measure of their performance based on environmental, social, and governance criteria measured by various rating agencies.
As with many new things, there’s no agreed standard for this seemingly objective measure.
A study showed that “of the five top ESG rating agencies—their scores were uncorrelated for any particular company,” said a panelist, John Dabbar, managing director for low-carbon technology at ConocoPhillips.
Still, reductions in emissions matter, but only if the innovation delivers financial benefits as well.
“Our industry works every day on real work in the field. It needs superior-performing innovations that drive economics,” said Michael Segura, senior vice president for completions and production at Halliburton.
His presentation focused on electric-powered fracturing which has grown from a research project that began in 2016 to a commercial offering in 2019 to something in 2022 that might be on the cusp of taking off.
Electric-powered fracturing equipment makers have had to prove they could provide powerful, reliable service that could reduce emissions, depending on the power sources. In the future it may smooth the transition to automated fracturing equipment that could adjust on the fly.
Now with fracturing activity steadily rising and the supply of usable, idle, old pressure pumping equipment dwindling, there is an opportunity for new equipment makers.
What customers order will be telling. Segura said the “the pace of change will be determined by the economics of the industry.”
While Halliburton has made a large commitment to the development of equipment and enabling technology, such as grid-powered fracturing, “We are not building anything on spec,” he said.
Some Up, Some Not
Exhibitors said they were happy to be talking to so many people, but their moods were mixed.
For Paul Tubel, chief executive and namesake for his downhole sensor company, Tubel Energy, it felt great to have booked as much business by February as he did last year.
Granted, last year was awful. But this year he is receiving interest from big companies looking for an alternative supplier at a time when unconventional engineering is more focused on data and diagnostics, as evidenced by the conference’s technical program.
Sand suppliers also appear to be on the cusp of some good times. Growing demand for sand for fracturing—with more wells completed, including a significant number that are 3 miles long—is beginning to exceed the capacity of local mines.
Supply shortages began cropping up late last year. Local mines, whose output once far exceeded demand, now are struggling to do so because their capacity has been reduced by years of cost cutting and deferred maintenance during the bad times, said Hunter Wallace, chief operating officer at Atlas Sand.
It will take time, and millions of dollars of outside cash, for mine owners to restore some mines, said Wallace, who is hoping for some longer-term contracts for what Atlas has available to sell.
A chemical supplier pointed out it is not doing as well as sand suppliers. Meeting the demand in this competitive sector has required dealing with a difficult supply chain where some key chemicals are impossible to find, forcing the company to look for substitutes. What can be found costs more.
For Chris Jackson, who oversees sales for Tiger Industrial in Victoria, Texas, the problem is that good pumps are hard to find. While the equipment rental service could rent more pumps, the supply is limited, and many used ones need repairs. Customers who have rented pumps hang on to them, knowing that when returned, they are often rented out within hours.
Aiming for Direct Hits
Longer term, fracturing is a tool that could prove indispensable in geothermal energy development. Doing so will require solving a new generation of fracturing challenges. Essentially what is valuable in geothermal is the opposite of the goal when putting shale formations into production.
While hard, direct, well-to-well hits are often (but not always) an undesirable side effect in oil and gas, the US Department of Energy’s Forge geothermal test site in Utah is an example of similar hits being desirable. The goal there is to create long, high-capacity, well-to-well flow pathways through hot granite to form what amounts to a huge heat exchanger to warm large volumes of injected water.
Specifically, they need to fracture granite, an unfamiliar rock, in ways that consistently create fractures with high connectivity and conductivity between wells up to 600 ft apart, said John McLennan, an associate professor of chemical engineering at The University of Utah, a panelist involved in the project.
A test using wells 300 ft apart will try fracturing one well, mapping the fractures created, and using that information to design a stimulation plan for the second well that completes those pathways.
If this government-funded test shows this to be a workable approach, McLennan said there will be “so many opportunities for the stimulation community and geothermal community.”
