Permian Resource Solutions
Quick Permian Rebound Takes Proppant Supplies From Excess to Scarcity
By Tim Beims and Colter Cookson
The Merriam-Webster dictionary defines cyclicity as the state of occurring or moving in cycles. It could have saved some ink and simply written “see oil and gas.”
Less than a year after an historic collapse in demand led to excess supplies of everything from diesel to drill pipe, the word “shortage” is suddenly finding its way back to the industry’s vocabulary as global inventories draw down and operators return to the work of drilling and completing wells. In few areas is the shift in sentiment more pronounced than in the U.S. fracturing sand market.
Even with frac sand consumption in onshore shale plays skyrocketing from 42 million tons in 2016 to 116 million tons in 2019, supply grew so fast that analysts began warning two years ago that the influx of sands from new in-basin mines was “crushing” the supply/demand balance. According to one count, some two dozen frac sand mines opened in the Permian, seven each in the Eagle Ford and Haynesville, and five in the Mid-Continent, bumping total U.S. supply to nearly 225 million tons in 2019.
The message was clear: Even though the volume of sand being pumped per well was jumping off the chart, frac sand supplies were so plentiful that prices were being eroded, pressuring the margins of sand suppliers. But that was then, and this is now. While prices have remained subdued, the supply imbalance with demand may be swinging decisively back in the opposite direction.
In January, Kpler issued research that likely caught more than a few by surprise by declaring U.S. shale plays would face constraints following a strong activity recovery at the start of 2021. Specifically, Kpler’s report stated, “Frac sand, a critical-path component in fracs, could be a chokepoint for the industry’s rally in the first quarter of 2021 as fleets compete to stay sanded in a weakened supply chain.”
So, how did the industry so quickly go from supply abundance to potential scarcity? Alexandre Andlauer, senior global energy analyst at Kpler, explains that frac sand supply is following the same trend line as U.S. oil and gas production output for the same basic reason: underinvestment. “Many sand mining companies were underinvested because of low prices, and a lot of mines were shut down or idled last year,” he states. “I am hearing that between one-third and one-half of the total frac sand capacity we had two years ago has disappeared.”
Hit first with diminishing economic returns from falling frac sand prices, and then by the abrupt halt to completion activity during the depths of the COVID-19 downturn, some proppant suppliers have been forced into bankruptcy, restructuring and mine shutdowns, Andlauer goes on. That includes both in-basin regional mines as well as Northern White mines in the Upper Midwest, many of which had debt-laden balance sheets from borrowing capital a few years ago to expand capacity when soaring demand bolstered sand prices.
“Some mines will never come back, but some eventually will be reopened and return to production,” he comments. “My view is that that the ramp up in drilling and completion activity has occurred so much faster than what anyone had expected–from 250 rigs and 60 frac spreads in July to 380 rigs and 170 frac spreads in January–that the sand market is challenged to respond.”
Consequently, a major roadblock that could impede a further activity response to strengthening oil and gas prices appears to be moving into place. “It looks as if supply chain disruptions will be unavoidable,” Andlauer says. “They involve more than frac sand, but that will be one of the biggest challenges in the months ahead as prices recover. U.S. shale oil production ended 2020 down 20% from 2019. Technical constraints are making it very unlikely to reach 2019 levels again in the next 18 months, even if oil rises to $70/bbl.”
Powered By People
The industry may run on capital and technology, but it is powered by people. And that introduces another potential problem: repopulating a workforce that was downsized drastically in 2020. A case in point is one of the most basic, but logistically critical jobs in the oil patch: delivering millions of tons of sand and other consumables to the well pad. “I am hearing more and more that a shortage of truck drivers could be an even bigger constraint than frac sand in U.S. shale plays,” Andlauer reveals.
He points to two issues that are compounding the problem. “I have friends that have made a lot of money driving trucks in the Permian, but they have left the industry and do not want to come back because of its volatility. They had been laid off multiple times over the past seven or eight years. Demand for truck drivers is strong everywhere, so they have options outside the industry.”
Money talks, of course, and the opportunity to earn a bigger paycheck than in other sectors always has been the industry’s calling card. “The trucks are available, but you have to bring drivers back from other sectors. To do that, you need to offer salaries high enough to make up for the volatility and their lack of confidence in the industry,” he points out. “But with producers trying to implement capital discipline, nobody wants to hear about cost increases for trucking or anything else.”
When it comes to the Permian labor market, no one knows the score better than Willie Taylor, who has led the Permian Basin Workforce Development Board as chief executive officer since its inception in 1996 and been involved in workforce development in the region for 48 years.
“The Permian is in better shape going forward than any other basin,” he assesses. “It may take a little time, but oil field activity will come back. Companies are going to be cautious, especially with the new administration, but we are going to have to go outside the area and do some heavy recruiting as activity returns and unemployment falls.”
In December 2019, with the previous administration in the White House and coronavirus still an unfamiliar term to Americans, the unemployment rate in Midland was among the lowest in the country at 2.0%. Odessa was just behind at 2.9% and Texas unemployment was at 3.3%, a touch better than the all-time low U.S. average of 3.4%. After ballooning during the summer and fall, Taylor reports that the unemployment rate in December 2020 had improved to 8.0% in Midland and 11.5% in Odessa, lagging the state and national averages of 7.1% and 6.5%, respectively.
“Our region is so dependent on oil and gas,” he remarks. “That is a blessing and a curse. You can be a high school dropout and still earn $80,000 or more a year. Our salaries have been higher than the statewide average, but our education attainment also has been lower than the statewide average. As long as the industry is doing well, the workforce is doing well.”
But, of course, the opposite also is true. The past year has been rough, but as activity picks up and the unemployment rate in the Permian labor market improves, the need to recruit workers from outside the basin will re-emerge, according to Taylor. “We have work to do in the Permian Basin, but we have a large workforce base and the infrastructure in place to support future growth,” he notes.
With booming oil and gas development spurring some of the strongest population growth in the nation between 2015 and 2019, Taylor adds that local residential neighborhoods, commercial facilities and municipal infrastructures all have been expanded to the point where Midland-Odessa can comfortably accommodate moderate workforce growth as needed.
“We are hoping we do not have housing capacity shortages and some of the other negative issues we saw in the past, and that people will come into the region and find affordable housing and good wages,” he elaborates. “Once they get here, they will realize the Permian is a nice region in which to live and work.”
Looking specifically at industry trucking, Taylor agrees that driver availability is tight and a shortage of experienced drivers is a possibility. “Truck driving is on our targeted occupations list, and you do not get on that list unless you have average local openings of 50-100 jobs statewide and are paying at least $17.00 an hour,” he offers.
But truck driving has been on the Permian Basin Workforce Development Board’s priority list almost constantly over the years, he adds, noting the organization is always recruiting and training new drivers. “The thing about the oil and gas industry is that it’s willing to pay high wages to attract talent, and higher wages in the oil industry tend to increase wages across the entire region. A workforce shortage will do that. As oil and gas companies become more active, wages and incentives tend to increase and bring in new workers.”
Tight Sand Ahead
As completion activity rebounds, operators may have trouble getting frac sand, warns Hunter Wallace, chief operating officer of Atlas Sand, which owns two sand mines in West Texas. He predicts 40/70 proppant will be especially tight.
“Even when they were brand new, most in-basin sand plants had downtime or other issues that caused them to miss deliveries,” he recalls. “Now that they are three or four years old, those issues may be worse, especially since many of their owners had to defer maintenance and lay off employees during 2020.”
Atlas is the only company with two sand plants that managed to keep both open throughout 2020, reports John Turner, the company’s chief financial officer. “We have lower operating expenses and a better capital structure than most of our peers, so although the volumes we sold dropped significantly, we were able to keep our plants open and our shifts active,” he explains.
With less need to produce sand, Wallace says the company’s employees spent four months focusing on making its plants near Kermit and Monahans, more efficient. “We built the plants with automation in mind, so we had a pool of data to look at on almost every piece of equipment,” he reports. “However, we did not have the time to fully leverage that data until last year.”
To illustrate how valuable the data can be, Wallace offers a sand dryer. “From the data, we know exactly when and how long that dryer was down. By looking at data points around those failures, such as moisture readings or the amount of sand in the surge bins, we can identify each failure’s root cause. By doing that over a month, we can spot the most common problems and find ways to address them.”
One of the most impactful changes Atlas made during 2020 was converting from traditional yellow iron mining to dredge mining. Yellow iron mining requires as many as a dozen men running diesel-powered heavy equipment, such as excavators, dozers and haul trucks, to mine, transport, stockpile and feed sand from the mine to the plant for processing. In contrast, Wallace describes, the new process only requires one person to run an electric-powered dredge that sucks up the sand and water and transports it straight into the plant.
Each plant’s dredge floats peacefully in a pond that formed naturally in the depression created by their sand mine, Wallace says. He reports that upgrading to dredging cut mining costs at both plants 75%.
“We are uniquely capable of implementing the dredging process because our deposits are the only ones in the Permian Basin with water naturally available,” he says. “Instead of ending 20-50 feet below the surface, our deposits extend as far as 145 feet. These large underground depressions filled with extremely porous sand act like giant tanks, collecting water from the area.”
Atlas uncovered water only a few feet below the surface while constructing its two plants but needed to verify the water supply would be stable before upgrading to dredging, Wallace relates.
Another major improvement Atlas made last year was moving its on-site loading teams to a command center in Austin, Tx. Wallace notes that costs much less than housing people in man camps in West Texas and paying for their transportation home when their shifts end. It also means workers can spend more time with their friends and families.
“Moving both plants teams’ to the same facility gives us several efficiencies,” he adds. “Before, if Monahans had an hour of heavy traffic while Kermit was slow, the loaders at Kermit would be idle. Now they can help the Monahans team keep trucks moving in and out as efficiently as possible.”
The command center makes it easier to pair truckers with loaders who have the knowledge to help them, Wallace mentions. For example, if a driver who struggles with English has a complex issue, his initial contact can transfer him to a Spanish-speaking colleague so they can resolve that issue more quickly.
According to Wallace, the command center has allowed Atlas to maintain an average total time on the mine site of 10 minutes while reducing its operating costs and improving truckers’ experience.
Wallace admits, “Every sand plant has its issues. After all, sand is one of the most destructive things you can put into a machine, and it is all our equipment deals with 24/7/365.” However, he also expresses pride in Atlas’s performance, proclaiming, “Since we fired up our plants in 2018, we have yet to cancel or miss an order that was placed with us, and I don’t think many or any of the other Permian sand plants can say that.”
That is partly because the company’s plants include enough redundancy to compensate for equipment downtime, but it also reflects a disciplined approach to sales, Wallace says. “Because of unexpected delays or other issues on the well site, customers often end up pulling less sand than they ask plants to allocate to them,” he relates. “To ensure all their sand gets sold and maximize their profits, it is tempting for plants to overbook their capacity.
“We do not do that,” Wallace assures. “We are willing to accept lower short-term sales to ensure we can keep our promises even when operators hit their stride and need exactly what they expect to need.”
According to Wallace, that approach has helped the company build strong relationships with customers. “Our customers know we are going to deliver what we say we are going to deliver, so when we ask what they expect to need over the next 30-60 days, they give us a straight answer,” he reports.
Atlas uses this information to secure capacity from its trucking partners. “Through preplanning and communication, we have gotten enough truckers to make deliveries even in a market where truckers are in short supply,” Wallace says. “I cannot say we are entirely insulated from trucking issues, but we should be able to manage as long as our customers continue to give us a clear line of sight into their needs.”
In their quest for efficiency and lower costs, many operators are moving from zipper fracs to simultaneous fracs, observes Charley E. McIntyre, director of business development and shared services at Cudd Energy Services. “Instead of switching wells in between stages, operators are completing both wells at once,” he clarifies. “This requires more equipment but saves enough time that in surveys, most completion engineers rank simultaneous fracturing as the innovation that will have the most impact in 2021.”
Rocky Shields, Cudd’s director of operations, points out that simulfracs requires strong supply chains. “If everything goes as planned, the pad will need twice as much water, sand and chemical every day,” he explains. “Those supplies need to arrive consistently enough that the blenders and sand unloading systems can keep pace with the frac.”
There’s enough extra equipment on site that optimizing footprints is critical, Shields reports. He mentions that in 2019 and 2020, Cudd retired many of its oldest spreads while purchasing 3,000 horsepower fleets.
“Compared with the industry-standard 2,500-horsepower spreads, these new fleets pack more horsepower into a smaller footprint, which means we need less equipment on site,” he says. “The pumps also are more efficient and reliable because they use less of their capacity for many jobs. For example, pumping at 1,800 horsepower only requires 60% capacity, which reduces fuel burn and places less strain on the equipment.”
These new pump trucks use engines that meet the Environmental Protection Agency’s Tier IV standard, so they generate fewer emissions per horsepower during operation and manufacturing, McIntyre notes. He says they also run quieter than many of the Tier II engine-based pumps often seen in the field.
“To support our customers’ environmental, social and governance goals, we are converting diesel-fired equipment to dual-fuel systems that can burn natural gas. In addition to reducing emissions, this will let operators use a more affordable fuel source,” McIntyre reports. “To limit emissions and fuel consumption even more, we are testing technologies that reduce engine idling.”
The 3,000-horsepower fleets’ modern engines, transmissions and pumps provide more detailed information about operational status metrics, such as internal pressures and temperatures, that can be used to diagnose problems, Shields says. “We understand the benefits of listening to our equipment, so for the past three years, we have been installing control systems that collect data from it, then analyzing that data to see why failures occur and what we can do to improve run time,” he relates.
“Today, we are putting better transmission equipment on location so we can get data closer to real time,” Shields continues. “Ultimately, we’d like to have enough real-time data and historical analogs to use machine learning algorithms to spot problems as they occur. That will let us resolve issues before they disrupt operations or reduce efficiency.
Meeting Diverse Needs
“I am excited about the investments we are making in high-horsepower equipment that can perform large completions more efficiently, but we also take pride in servicing customers who might only need to stimulate a vertical well or a short lateral here and there,” Shields says.
McIntyre indicates these customers often use intricate fluid systems for their completions. “We pride ourselves on retaining employees who have the chemical expertise to meet their needs,” he says.
Over time, Shields predicts that horizontal wells’ completion designs will become more nuanced. “Right now, many companies are concentrating on delivering returns to investors as quickly and reliably as possible, which often means controlling costs and using conservative designs,” he says. “As prices improve, I think we will hear more conversations about tweaking proppant selection, stage placement and fluid systems to flatten decline curves and boost each well’s long-term production. Ideally, these changes also will reduce total costs.”