Earning The Title FRACN8R

When it comes to fracking in the Bakken, there’s not much that Monte Besler—the FRACN8R—hasn’t seen or done.
By Patrick C. Miller | May 02, 2017

A FRACN8R might be described as someone who innately understands the relationships between fluids, proppants and rock mechanics, an engineer who can envision what’s happening in geology two miles underground and a person who’s lived the history and witnessed the evolution of hydraulic fracturing because he’s been involved in it for more than 35 years.

Following a career of working for some of the biggest names in the oil and gas industry, Monte Besler founded FRACN8R Consulting LLC in Williston, North Dakota, in 2010. His company, and now his personal brand, has been so successful he doesn’t even have a website. His business provides completion consulting and supervision services for operators, primarily in the Williston Basin. FRACN8R isn’t just name of Besler’s company. It’s also his nickname, his license plate and a registered trademark.

The FRACN8R’s Wisdom
Besler has been in the industry long enough that there’s almost no topic he won’t discuss in a straightforward manner. For example, he doesn’t necessarily see the slowdown in oil and gas industry caused by low prices as totally negative. It’s provided time to study well data in detail and more closely examine the results of experiments at a controlled pace.

“For me, they can never do enough of that because I’m a big believer that if you don’t know what actually made the well do better, you’re doing what I call ‘close-ology,’” he says. “In other words, they want to do something close to what some other guys did because they had a good well. The chances of repeating it aren’t any better than going to Vegas and throwing money in a slot machine because you’re just guessing.

“That was a lot easier to do three or four years ago when people were gambling with OPM—other peoples’ money,” he continues. “Now that things have slowed down and a lot of them are having to use their own capital, it’s forced them to be a little more critical of what they do.”

Besler’s first job out of college was with the Western Company of North America where he served as a district engineer—first in Bryan, Texas, and then in Dickinson, North Dakota. He fracked his first well in Texas.

“I actually fracked an Eagle Ford vertical well back then,” he recalls. “I don’t remember how it turned out, but I remember going out and fracking that well.”

Halliburton hired Besler in 1984 where he spent nearly 15 years as a district engineer working at various locations within the Williston Basin. From there, he served four years as a production engineer for Hess before becoming a senior consulting engineer for Hohn Engineering PLLC in Williston from 2002 to 2010.

During the past seven years as owner of FRACN8R Consulting, Besler has seen many changes in the fracking process and how wells are completed. Some of the techniques that originated with light, tight shale oil in the Williston Basin are now being employed in the Permian, Eagle Ford and other shale basins.

Mega-Fracks and Refracks
Two trends that Besler considers problematic in some cases are mega-fracks and refracking. On the mega-fracks, in which 10 to 20 million pounds of sand are used, he says results can be misleading in the Bakken because not all information about a well makes it into the public record. 

“When people have done more science and looked at the big data, they’re finding that there’s a critical volume of fluid and sand at which there’s diminishing returns for these large jobs,” Besler explains. “In other words, they perform in line with almost every other kind of treatment that’s been done up to a certain volume of proppant. Once you get above that volume, they can pump as much proppant as they want and the wells don’t necessarily cue more oil, but they have high IPs.”
The problem from Besler’s perspective is that some rely on 90- and 180-day cumulative production rates using a model based on a previous treatment technique to extrapolate a mega-fracked well’s estimated ultimate recovery (EUR).
Although much attention has been given to refracking, Besler says it’s a mistake to assume that all wells fracked a certain way are good candidates for refracking.

“The biggest hurdle with refracturing is finding good candidates,” he says. “If you can find a good candidate, you can have some really good steals. Finding those good candidates is a lot more difficult than people thought it would be. You shouldn’t just go out and arbitrarily buy wells that were fracked 10 or 20 years ago with previous technology and assume that they’re all going to be much better when you go back and refrack them. There’s a lot more to it than that.The key, he says, is being selective and avoid buying 20 wells from an operator simply because they were all fracked the same way.

“If I were a company saying that I have a whole bunch of bad wells that I think you should buy from me for refracking, then you’d kind of wonder about the company,” he laughs.
There are examples of operators buying wells at low prices and having great success with them, Besler notes.

“In those cases, it was errors of omission in the people owning the wells not knowing what they had,” he explains. “And that may be what we see today, too. People holding on to bad horizontal wells and not doing anything with them and not knowing what they have. Someone makes an offer to take the well off their hands and will be successful at it.”

Diverter Adoption
The use of diverter technology is a trend gaining momentum in the Bakken that Besler believes will also prove successful in other shale basins.

“There’s been a movement here probably in the last six months that’s starting to take off to augment plug and perf with intra-stage diversion using particulate diverters,” he says. “When they had multiple sets of perforations or multiple ports open, there really wasn’t anything other than possibly some pressure—what they call limited-entry techniques—used to ensure complete coverage of all the intervals.”

The technique works, but Besler says there are factors that can interfere with it working efficiently, such as erosion, poor cement jobs in cemented wells with plug and perf, the presence of numerous natural fractures in an open-hole completion or large fractures that can prevent the treatment from stimulating the entire interval efficiently.

“What they’re doing now is running these particulate diverters and pumping stages within stages,” Besler says. “Where they might have pumped all ceramic proppant from 150,000 to 200,000 pounds in one frack job—or up to 1 or 2 million on some of these mega-fracks with sand—it was all going into one interval that was isolated in a well bore, but within that interval in the case of plug and perf, there were multiple entry points. If they weren’t all taking fluid, then you didn’t stimulate those other sets.”

Particulate diverters drive the proppant up into the ends of smaller ramps. When it gets to the formation, the perforation plugs and forces the proppant into all of the sets. Everything gets some amount of proppant and nothing is bypassed.
“There’s a lot of effort being put toward this right now,” Besler says. “There’s been some pretty significant results—20, 30 or 40 percent improvement in production. If you can attribute all of that to the fact that they’re more efficiently covering perforations due to that internal diversion within the stages, then it means that we were doing a pretty bad job before. Now we’re ensuring that we get even better distribution within the stage—more contact area with the reservoir and better production.”

The particulate diverters are made of materials that degrade after they’ve been downhole, which means they’re not plugging the formation.

“It’s gaining momentum and the attractive thing about it is that we’re not necessarily having to make a lot of other changes—proppant or anything like that,” Besler says. “We’re just more efficiently delivering it. As a consequence, you’re getting more bang for your buck.”

Differences in The Bakken
One advantage that Besler sees for the Bakken over other shale plays has been North Dakota’s adoption of 1,280-acre spacing units that led to more efficient pad drilling and the creation of energy corridors.

“All of the infrastructure—like roads, pipelines, gathering lines and power lines—tend to run linear in all these areas,” he says. “The pads are located along that line. In between for four miles, there’s almost nothing other than a few orphaned wells predating the order.”

North Dakota’s established section and township ranges have enabled the state to approach oil development in a more organized and standardized manner than some other states.  

“Parts of Texas were surveyed prior to the advent of section townships and ranges,” Besler notes. “Some of their land ownership isn’t quite as conventional as it is up here, which makes it a little more difficult to have something end up in units like we’ve got here as a standard. Section townships don’t fit the actual land ownership, which means they end up drilling a few more wells in different orientations.”

In the future, Besler sees enhanced oil recovery moving the Bakken toward unitization, although barriers remain because of competing philosophies regarding the rate of return on investment.

“We had a lot of external money coming into the oil business and a lot of that was looking at how much money can we make quickly,” he explains. “Unitizing is about how much oil can we produce and maximize the recovery profitably from this resource. One approach is looking two to three years down the line and the other is looking at 20 years or more. down the line. A lot of the injection processes aren’t going to reach their total fruition for 10 to 15 years. You have to have that different outlook on how you’re spending your money and how you’re getting it back.”

Besler is optimistic that research on the use of ethane for tertiary oil recovery rather than CO2 will be a boon to the Bakken.

“North Dakota has a very good case for using ethane because of the fact that we have a lot of it that we can’t sell it for a profit, but we can reinject it into the wells,” Besler says.

He cites research showing that ethane is almost twice as effective at CO2 for enhanced oil recovery. In addition, the upfront investment for handling CO2 is greater because its properties require the installation of corrosion-resistant tubulars.
“Whether it’s CO2 or ethane injection, you’ll need to be unitized,” Besler states. “Once you unitize, lease ownership boundaries don’t really mean anything within the unit. You can drill any direction you want and get a much more organized pattern.”

That would require bringing all the interested parties into the unit—royalty owners, landowners, producers and other companies.

“The state gets involved because they have to make special rules regarding drilling and production within the unit,” Besler says. “You no longer have the boundary issues you have in conventional production.”

For the past two or three years, Besler says the Bakken was the focus of new fracking and well-completion techniques, but he see this coming to an end as other shale plays mature. He believes that in the future, more technology development will occur simultaneously in other basins. Maybe then, every U.S. shale play will have its own FRACN8R.

Author: Patrick C. Miller
Staff Writer, North American Shale magazine