Frack Sand: Chesapeake’s Sand Strategy

[Editor's note: This story previously ran on HartEnergy.com. A version of this story also appears in the August 2019 edition of Oil and Gas Investor. Subscribe to the magazine here.]

For a company that pumps about 4 million tons of sand per year—enough to fill Oklahoma City’s Chesapeake Arena six times—it’s no wonder that thoughts turned to self-sourcing when free-cash-flow neutrality and reducing debt were goals.

“We have saved over this last year $100 million by supplying our own sand. That’s massive for us,” Jason Pigott, executive vice president of operations and technical services for Chesapeake Energy Corp., told attendees at Hart Energy’s DUG Sand conference in April. Added benefits included reducing nonproductive time (NPT) by 92% in the last few months with no negative impact on production, he said.

The accomplishments didn’t require adding another division to the company’s supply chain group as he originally feared. They came by adding two people with expertise to the organization, forming valuable partnerships and lots of planning. Although the Oklahoma-based company does not have any assets in the Permian Basin, Pigott said the company’s sand story is universal to everyone in the E&P business.

The story was shared as operators continue to focus on costs and efficiency as they try to add value from unconventional oil and gas assets in the U.S. Chesapeake is cutting costs and shaving nonproductive time by opting to self-source sand instead of using third-party suppliers.

With assets in the Powder River Basin, Midcontinent, Marcellus, Haynesville and the Eagle Ford, among other spots, the company does not take a one-solution-fits-all approach when it comes to sand sourcing. In the Powder River and Appalachia, for example, northern white sand by rail is self-sourced, while regional sand—also self-sourced—is used in the Midcontinent, South Texas and Brazos Valley. The company uses regional sand in the Haynesville, but it is vendor managed.

For Chesapeake, the number of rigs running is a factor in determining whether to self-source in a basin. In the Haynesville, for example, the company runs one to two rigs, compared to four each in South Texas and Brazos Valley.

“If you’ve got one rig, it’s [self-sourcing] probably not going to be for you. … You have to have mass to make it work,” he said.

A hybrid strategy is something companies should think about if they are considering self-sourcing, taking into account the location of sand mines, which facilities can handle spikes in demand and trucking expenses, according to Pigott.

Another big consideration is an obvious one—reservoir properties, along with the potential impact on EURs and completion designs.

Chesapeake began testing regional sand in 2013, looking at the supply of Northern White, Pigott said, adding “it never quite worked out” as market conditions prevented a full transition. But the opportunity surfaced again five years later, in 2017, as regional sand mines came onstream, prompting Chesapeake to carry out regional sand testing in various assets to determine the impact of regional sand use on production.

“We felt comfortable that regional sand in an area like the Eagle Ford was not going to be detrimental to our production. So that caused us to make that shift,” Pigott said.

By mid-2018, Chesapeake was decoupling its frack services and lining up partners for logistics and sand. The company started its direct-sourcing transition in fourth-quarter 2018, pumping regional sand and managing final mile transport, he said.

The change has resulted in 50% cost savings vs. traditional northern white sand and a 92% drop in sand-related NPT, according to Pigott, who called it a game changer for the company.

“As we’ve gone to this micro supply chain, it’s a lot of clarity,” Pigott said. There have been times when a vendor would say it was waiting on sand while down fixing pumps, he said, noting you couldn’t really tell whether time was needed to fix pumps or for sand to arrive. “Now they are no longer waiting on sand. … We have clarity into what’s really going on.”

It also helps that Chesapeake acquired the Burleson Sand Mine as part of its purchase of WildHorse Resource Development Corp. that closed in February.

“We are not only supplying sand; we are operating a mine,” Pigott said. “That mine is up and running today. It supplies about half our sand.”

Meanwhile, other vendors in the region supply the rest. “Those things are really moving the costs down,” he said.

Session moderator Richard Mason, chief technical director for Hart Energy, pointed out the evolution taking place within the industry. “We’ve gone from an industry where we have specialized E&Ps, specialized service companies. Are we going back to a vertically integrated industry?” he asked.

For Chesapeake, “the big thing is clarity,” Pigott responded. “Everybody was taking a slice of the profit and getting margin along the way. When we started to decouple, we knew exactly what sand costs. … Are we going to decouple everything? No, but when you’re pumping 8 billion pounds of sand, that’s a big ticket item that you may want more clarity into.”

Velda Addison can be reached at vaddison@hartenergy.com.

[SIDEBAR]

Frack Sand Forecast

Frack sand demand could reach 107 million tons in 2019, and a lot of it is coming from the Permian Basin.

“We expect about 40% of that [demand] to be in the Permian and then increasing the Permian Basin’s activity in 2020, moving to close to 45%,” said Todd Bush, principal at Energent Group, at the DUG Sand conference in April.

Bush noted that when you think about frack sand demand, you have to think about its key drivers: proppant per foot, lateral lengths, horsepower and what’s happening with the number of frack crews.

“Every grain of sand has to be pumped through some of the horsepower that’s out there in the field. So we’re actively watching what the crew count is doing, what the supply and demand of horsepower is doing to then show those constraints within our frack sand forecast,” Bush said.

Energent is tracking 145 frack crews in the Permian, accounting for 38% (383) of frack crews right now. By tracking the frack crews, Bush said, the firm is able to see what the cycle times look like.

“One thing that we’re watching closely are all the [sand] mines that are coming online, where they’re located and what that means for cycle time and costs,” said Bush.

About 23 sand mines are scheduled to come online in 2019, resulting in 80 million tons of frack sand supply, he said.

In the Permian, “we’re looking at more in the 42- to 45 million tons of frack sand demand for 2019, and with the locations of the mines within that central Midland-based scenario, you get pretty good access to any side of the Permian,” Bush said.

“This essentially gives you about an hour, hour and a half drive toward any area within the Delaware Basin or within the southern Midland Basin. … This is a good presentation of what it takes to drive from mine to the well site.”

—Brandy Fidler, Oil and Gas Investor