Page 1

ISSUE 2 2017

Diverting Trends Demand For Diverters Pours Into Industry Page 18

Plus Well Completion Insight, Predictions From The FRACN8R Page 12

And Streamlined Drilling Styles For Shale Page 24 Printed in USA


IN THE SPECIALTY CHEMISTRY INDUSTRY. At Flotek, we treat our client’s reservoir and their capital like they were our own. Our dedication to formulation customization provides prescriptive chemistry designed to improve your well’s performance.



ISSUE 2 2017



12 Earning the Title FRACN8R

EXPLORATION & PRODUCTION BY PATRICK C. MILLER Monte Besler has been involved with hydraulic fracturing for 35 years across multiple basins. His success and unique insight has enabled Besler to start a consultancy and use a license plate with the same term: FRACN8R.

12 18 Inside the Business of Shale Diverters PRODUCTS & TECHNOLOGY

BY LUKE GEIVER The introduction of biodegradable materials by diverter developers and distribution companies offers solutions for the shale industry’s quest for enhanced completions, and prosperity.



6 9 11


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Flotek Chemistry






North American Shale magazine


Wanzek Construction Inc.

Oil’s other hot commodity: Mineral Rights Policy shifts could increase E&P jobs by 25 percent All pipes lead to Permian



Faces From The Latest Shale Trends BY LUKE GEIVER





Streamlining Shale Drilling

How ExxonMobil’s new Drilling Advisory System improves drilling results

ON THE COVER: Fracking crews are deploying biodegradable diverter material to enhance the fracture network. Diverters come in bead, fiber or small particle forms and are added directly into the pumping infrastructure. PHOTO: NORTH AMERICAN SHALE MAGAZINE



Faces From The Latest Shale Trends To gain insight into the leading shale well completion trends happening throughout the North American shale scene, we reached out to an industry veteran who drives a truck with a vanity license plate that reads FRACN8R. We also checked in with the founder of a biodegradable plastics development and distribution company from Indiana that was so busy serving oil and gas clients during the downturn Luke Geiver that he has since started a new oil and gas division. And, to EDITOR ensure we were complete in our coverage on the advent of North American Shale magazine a new downhole material that has become popular in every shale play, we spoke with another oil industry veteran that has found success in Duncan, Oklahoma, testing and designing new biodegradable material for shale clients. Monte Besler, a 35-year industry veteran turned completion consultant that operates mainly out of the Williston Basin using the trademarked name FRACN8R, highlighted the good that has come from a period of reduced well completion and drilling activity. The industry has been able to reexamine well completion designs and strategies—like slickwater jobs or high-intensity sand placements—to gain a more accurate sense of why, how or if approaches tried during the past two years have enhanced production. “For me, they can never do enough of that [analyze well completions and production results] 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.’ In other words,” he told us, “they want to do something close to what some other guys did because they had a good well.” The full story on Besler, “Earning The Title FRACN8R,” written by Staff Writer Patrick C. Miller, can be found on page 12. Besler expounds on refracks, megafracks, differences he’s experienced between basins and the industry’s move to diverting materials. Diverters, as the shale industry calls them, have been mentioned in multiple exploration and production investor updates in recent quarters. The biodegradable materials play a large role in enhancing completion designs to boost productivity while also reducing overall completion costs. John Moisson, founder of Jamplast Inc., remembers the first time he drove a flat-bed truck to Texas from Indiana to deliver pallets of his unique diverter material to an operator’s field operations facility. Since that trek, his team has been serving clients from Texas to Pennsylvania. His product has become so popular, Jamplast now has an oil and gas division and its own truck and trailer specifically for one-day diverter deliveries. Brad Todd, founder of Oklahoma-based Completion Science, has a similar success story with diverters. His team has grown—and is still growing—due to their unique know-how on designing and distributing biodegradable materials. For our piece into this emerging trend, “Inside The Business of Shale Diverters,” Todd even ran a special lab test for us that illustrates how the small diverter material works downhole. The next time you hear an oil or gas producing company speak of enhanced completions or operational efficiencies in general terms, think of the people mentioned in this issue. Each helps to put a face to an important story happening in shale today, and each acts as a reminder of how strong the unconventional shale industry has become. For every cycle—from a downturn to an upturn—there will be advances in strategy and technology despite how good or bad things seem to be. You need look no further than the Jamplasts, Completion Sciences and FRACN8Rs of the world.

VOLUME 1 ISSUE 2 EDITORIAL Editor Luke Geiver Staff Writer Patrick C. Miller Copy Editor Jan Tellmann

PUBLISHING & SALES Chairman Mike Bryan CEO Joe Bryan President Tom Bryan Vice President of Operations Matthew Spoor Vice President of Content Tim Portz Marketing & Sales Director John Nelson Business Development Manager Bob Brown Circulation Manager Jessica Tiller Marketing & Advertising Manager Marla DeFoe

ART Art Director Jaci Satterlund

Subscriptions Subscriptions to North American Shale magazine are free of charge to everyone with the exception of a shipping and handling charge of $49.95 for any country outside the United States. To subscribe, visit www. or you can send your mailing address and payment (checks made out to BBI International) to: North American Shale magazine/ Subscriptions, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. You can also fax a subscription form to 701-7465367. Reprints and Back Issues Select back issues are available for $3.95 each, plus shipping. Article reprints are also available for a fee. For more information, contact us at 866-746-8385 or Advertising North American Shale magazine provides a specific topic delivered to a highly targeted audience. We are committed to editorial excellence and high-quality print production. To find out more about North American Shale magazine advertising opportunities, please contact us at 866-746-8385 or Letters to the Editor We welcome letters to the editor. If you write us, please include your name, address and phone number. Letters may be edited for clarity and/or space. Send to North American Shale magazine/Letters, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203 or email to lgeiver@

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Shale’s Other Hot Commodity:

Mineral Rights

Why Invest In Minerals -No capex -No environmental liability -Good vehicle for yields -Immediate cash flow from wells -Passive income

Longpoint Minerals is considered a startup in the relatively new business of mineral and royalty investment. Will Cullen, vice president of the Denver-based firm, helped form the company in 2016 and to date has raised more than $800 million to acquire mineral and royalty rights in shale plays throughout the U.S. Longpoint is one of a handful of firms that is now working to buy mineral rights

The Risk With Mineral Investing

What To Look For In Mineral Assets

-Lack of control -Development timing -No access to operator data -You can stare at dead money sitting in the ground

-Large, continuous acreage blocks -Large mineral ownership percentages -Active fields with rig count trending up -Ability to work with midstreams, service companies

*Mineral investment firms are most concerned about buying acreage only to see it be left undeveloped or passed over for another area.





from individual owners or large entities with the future in mind. Mineral investment firms, starting in 2014, recognized the opportunity in shale oil and gas development. Purchasing acreage blocks that include mineral rights can give investors a consistent yield for many years to come, and in return to mineral rights owners who sell, a chance at a major guaranteed cash payment in exchange for their mineral rights. Advances in drilling, completion technology, well site optimization and a general increase in reservoir understanding have created a positive scenario for mineral investment firms. Outside investors can not only recoup a consistent yield on an investment into minerals without exposure to the cost of drilling or production that working interest owners in wells have to experi-

ence, but they can also potentially reap the benefits of new technology or oilfield strategies that bring more wells or better production online in a certain mineral acreage position that many may not have thought possible in the recent past. Cullen believes the market for minerals is in the billions but the business is still in the early stages. “Most mineral owners base the value of their minerals off the value of their current checks,” he said. Mineral owners sell minerals for various reasons, but timing is the biggest reason Cullen’s clients sell. Before he starts negotiating with mineral owners, Cullen expects that 90 percent of his talks will end without a deal, however. People sell for various reasons, he said, and many understand that their acreage could yield better payouts in the future. In most cases, Cullen said, large acreage holders are very savvy, some even employ geologists or consul-

Private Equity Interest In Royalties/Minerals 1859-2004=No Interest 2004-2010=Minimal Interest 2010-2014=High Interest 2014-2017=Very Strong Interest Brensike believes 2010 to 2014 was a period that could be classified as the golden years of shale. Technology development, implementation and know-how grew during the period and helped investors realized the value of mineral and royalty interests. Today, there are more than 20 private equity firms involved with buying mineral interests.

tants to keep them informed on the value of the mineral rights. Bradon Fikes, vice president of Santa Elena Minerals LP, a Texas-based mineral and royalty investment firm, agreed with Cullen on the importance of timing in acquiring mineral rights. Fikes hears from many mineral owners that they were told never to sell their mineral rights because someday they would be worth something. “That someday is now,” he said. Cullen and Fikes will both perform transactions within a wide range, paying out at $20,000 or $100 million depending on the amount of acreage or mineral rights included in a deal. Karl Brensike, CEO of Haymaker Minerals, was an early believer and pioneer in the minerals space. In 2014, he worked to solidify the business case for minerals investments to private equity firms. “We had to convince them that the industry [oil and gas] was

going to evolve,” he said. Prior to Brensike’s work to educate investors on the value of minerals and the long-term yield potential of owning minerals in places like the Permian Basin or the SCOOP/STACK, Brensike said private equity firms didn’t want to invest in the space because they viewed it as a price play. “Investors didn’t want to invest in managers guessing the price of oil,” he said. Essentially, investors didn’t want to rely on the price of oil to entirely dictate when or to what extent they might recoup an investment. But, with the new approach of E&Ps to manufacture or develop fields at mass scales, along with constantly improving completion technology that is yielding more oil per well, the price of oil—at least at prices as low as $35/b—doesn’t matter to the same extent it once did.

Why Invest In Minerals? „ Total Cash Flow „ Well Investment Cash Flow „ Mineral Royalty Cash Flow


LIFETIME OF A WELL Cumulative cash flow over time ROYALTY OWNER Immediate positive cash flow


WELL OWNER Starts at negative position due to well costs




THREE-MINUTE UP-TIME: In roughly 3 minutes, a silo storage unit can be erected and ready for multiple trucks to begin offloading sand. PHOTO: SOLARIS OILFIELD INFRASTRUCTURE

Solaris Goes From Frack Facility To IPO Market in Under 3 Years

SOLARIS SIX-PACK: The mobile proppant storage systems can provide three times more storage using roughly half of the space of systems not optimized for vertical storage. PHOTO: SOLARIS OILFIELD INFRASTRUCTURE



To meet customer demand for its mobile frack sand supply units, Texas-based Solaris Oilfield Infrastructure has filed an initial public offering valued at $100 million. Funds from the IPO will be used to purchase new units, fund its capital program and for some general corporate purposes. After forming in 2014, Solaris has expanded its mobile supply fleet from two to 33. “We have increased our total system revenue days, defined as the combined number of days our systems earned revenues, in nine of the last 10 quarters,” the company said in its securities and exchange commission filing. “The increase in total systems revenue days is attributable to both an increase in the number of systems available for rental and an increase in the rate at which our systems are utilized.”

Greg Garcia, executive vice president of sales and marketing for Solaris, said the units can provide triple the amount of sand storage on the well pad using only half the space as a normal operation. The silos are erected through electric generators and controlled by a single computer. Each system is fully enclosed, he added, in an effort to cut down on silica dust. In roughly three minutes, a unit can be set-up and multiple trucks can begin offloading sand into the silos for future use. In 2014, the company purchased a manufacturing facility in Early, Texas, to design and build the mobile silo systems. By the end of the year, Solaris expects to have 64 systems in operations throughout the Permian Basin, the SCOOP/STACK and the Eagle Ford.


Jobs From Exploration & Production

Drilling & Production

North Dakota

Distribution & Collection

Gas Refining

Leasing & Development

13 $1,664,200 $97,554,500

498 $55,426,700 $97,465,700


6,375 601 $840,354,500 $119,366,400 $4,057,821,000 $214,055,700


WYOMING Colorado


4,342 235 $566,098,100 $69,792,500 $2,641,798,700 $105,379,900

560 547 $79,602,300 $51,734,500 $2,418,290,700 $104,524,400



5,347 937 $880,277,700 $1,126,374,500 $2,646,755,400 $827,979,000

611 $104,760,900 $974,698,200

3,928 $409,096,300 $806,678,200


4,753 520 $482,416,700 $95,244,400 $2,140,891,800 $189,186,500

691 1,559 $71,682,500 $132,519,800 $2,025,190,100 $271,713,900

Policy Shifts Could Increase E&P Jobs By 25 Percent The Western Energy Alliance, an organization representing 300 companies, has pinpointed the job growth potential for the oil and gas sector in 13 western states. If the Trump administration continues its shift to pro-domestic energy production policies, 19,363 new production- or

drilling-related jobs could be added in states such as North Dakota, Colorado and New Mexico. “The Trump administration and Congress are addressing overreaching regulations from the Obama administration, which means we can get on with responsible develop-

ment of American oil and gas,” said Kathleen Sgamma, president of the WEA. “President Trump has clearly signaled a shift away from punishing the industry to actually encouraging domestic production.” Policy changes on federal land leasing or the elimination of redundant regulations

related to venting and flaring could each help increase production in western states by as much as 25 percent, according to John Dunham & Associates, a research and data team that compiled a jobs report for WEA.



60 Longer-term backwardation has increased recently possibly exacerbated by producer hedging 1 MONTH AGO

The Oil Futures Curve

NOW 55


Forward curve has changed dramatically in the past 6 months... from steep contango to backwardation starting mid-2017

Brent Futures, $/bbl


45 Feb. 2017

Feb. 2018

Feb. 2019

Feb. 2020

Energy Analyst Explains Connection Between Oil Price, Supply/Demand Curve Oil prices should not be used to explain the global oil supply and demand picture, according to Dave Pursell, managing director and head of macro research at Tudor, Pickering, Holt & Co. As to why oil prices shouldn’t drive the global oil supply and demand narrative, Pursell noted that demand wasn’t that great when oil was trading in the $130/b range in the late 2000s. Instead, analysts and onlookers should follow the forward oil futures curve. The shape of the curve and the trajectories of oil inventories are more important than the current price of oil, he said. The shape of the curve creates incentives for buyers and sellers to hold or move product. The current curve shows that by the end of the third quarter, inventories could

be back to normal as buyers look to purchase and utilize stock. According to Pursell, the demand for oil is getting better at the same time inventories are being drawn down. “This isn’t a faith-based argument,” he said, “this is a fact-based argument.” Global events that receive media attention are also another variable that often has little impact on the supply and demand picture. When Greece was undergoing a time of major economic and country stability turmoil some believed the country’s distress would disrupt the price of oil. Through internal research, Pursell’s team showed that Greece was only slightly more important to the global oil picture than the state of Rhode Island was.


Understanding The Oil Futures Curve For Dave Pursell, the oil futures curve can be used to determine future oil prices. Because of contago and backwardation, oil prices appear to be trending towards the $65/b range by the end of the year. Backwardation occurs when the price of an oil futures contract is currently trading below the expected spot price at the time when the contract will mature or expire. Contago is a term used by traders to explain a scenario that futures contracts will rise in the future. For example, when an oil market experiences contago, it is expected that a contract to buy crude one month from now costs more than the current price of oil.


FUTURE PIPELINES COULD BRING DRONES: The SkyX drone can fly 90 mph for 70 minutes detecting leaks, vandalism, vegetation encroachment and other problems. Designed specifically for the oil and gas industry, the unit can be leased along with a data analytics software. PHOTO: SKYX

All Pipes Lead To Permian No shale play has received more new pipeline additions or new buildouts then the Permian this year. After waiting more than 18-months to find the right set of assets and storage terminals in West Texas, NuStar Energy LLP found its answer in Navigator Energy Services LLC. For $1.475 billion, NuStar was able to enter the Permian. “It has been no secret that we have been actively searching for a way to break into the Permian Basin,” said Brad Barron, president and CEO of NuStar. To pay for the Permian assets, NuStar intends to go to the equity and debt markets. It has also issued 12.5 million com-

mon units. Of the 16 producers already committed to ship-orpay contracts, half are publicly traded and the other half are Permian pure-play producers. Phillips 66 is also eyeing the Permian. The refining and logistics giant has announced plans for its Rodeo Project, a pipeline system originating in the Texas Counties of Reeves and Odessa. New injection and storage terminals will be built near Midland and Odessa, Texas. The system, set to be operational in 2018, could initially move up to 130,000 barrels of oil per day before eventually moving 450,000 barrels of oil per day.

Enterprise Products Partners LP may not be focused on piping oil, but the company has announced plans to build a 571mile pipeline to move natural gas liquids from the Permian Basin to its NGL fractionation and storage complex in Mont Belvieu, Texas. “The Permian Basin is currently the hottest play in North America and is expected to continue its strong growth for years to come,” said A.J. Teague, Enterprise CEO. The pipeline will start in Gaines County, Texas, and initially hold a capacity of 250,000 barrels of NGLs per day. The project already has shipper commitment and could be in service in 2019.

Should the pipelines need next-generation tech for monitoring and inspection, a Canadian-based company has a purpose-built drone. SkyX, based in Toronto and led by a former Israeli Air Force captain, has built a vertical-take-off-andlanding drone specifically for the oil and gas industry. The system can fly for 70 minutes at 90 miles per hour. The SkyX can detect leaks, vandalism, vegetation encroachment and other potential problems.



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

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 Besler 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.




FAMILIAR SIGHT: Monte Besler has worked on wells from the Eagle Ford to the Bakken. He currently focuses on the Williston Basin. PHOTO: NORTH AMERICAN SHALE MAGAZINE



DRIVEN TO FRACK: Monte Besler's license plate bears the name of his business, his nickname and his registered trademark. PHOTO: FRACN8R CONSULTING

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 14 NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2017

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 90and 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




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

AVOIDING CLOSE CONNECTIONS: A slowdown in fracking activity was good for the industry, Besler says. The period allowed experts to analyze why completion strategies were working. Such analysis allows operators to avoid spending money based on what happened to wells in neighboring areas. PHOTO: NORTH AMERICAN SHALE MAGAZINE

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


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 701-738-4923



READY TO SHIP: After experiencing a demand increase for biodegradable material used in diverters, the Jamplast team has started a new division dedicated to oil and gas clients. PHOTOS: JAMPLAST INC.






DIVERTERS Among the hottest trends in the shale industry, diverting agents can improve production with out increasing completion costs. These companies have experienced firsthand the rise—and the profits available—of biodegradable diversion material

By Luke Geiver Jamplast Inc., a raw plastic material and biopolymer developer and distributor, has two U.S. locations, each of them hundreds of miles away from the country’s most active shale oil and gas plays. But, since 2014, the company has been at the center of an emerging trend present now from Texas to North Dakota. Jamplast produces biopolymer-based diverting agent materials for oilfield services and exploration and production companies. Diverters, as they are often referred to in oil and gas speak, are used during the hydraulic fracturing process to plug holes or perforations and allow fluid flow to transfer past or be diverted towards other sections of a well bore. Over time, heat and pressure downhole hydrolyze the diversion material and perforations that had been plugged with the diverting agent, allowing for the perfs to flow freely. Without diverters, mechanical operations involving plugs are required. As John Moisson, president of Jamplast can attest, diverters have become extremely popular since the market downturn began in 2014. While many oilfield services and equipment vendors were financially struggling the past few years, Moisson and his team were trying simply to keep up with customer demand. Since first entering the oilfield diverter manufacturing and distribution market three years ago, Jamplast has created an entirely new division for its diverter-based services, separate from the raw plastic services it provides for food packagers and others. In those three years, the company has shipped specialized diverter product to Texas, North Dakota, Canada and the Middle East. “We’ve had a really good acceptance in the market for these degradable diverters,” Moisson says.


THE SCIENCE OF COMPLETIONS: From their lab in Duncan, Oklahoma, the Completion Science team tests new diverter materials and mixes for clients. The slot test shows a failure where smaller diverter particles were not sized correctly and the big particles bridged but failed to hold the smaller particles. The second test (right) shows a successful test of diverters and highlights the importance of having the particle size distribution of the diverter properly sized. PHOTOS: COMPLETION SCIENCE LLC

Listen to nearly any of the investor updates provided by operators targeting shale oil or gas resources the past three years and it is easy to see that Moisson is right. From the Bakken to the Delaware to the Marcellus, operators who were or still can tout improved completion designs that generate increased production without significant cost increases have typically had one thing in common: the use of biodegradable diverting agents. Now, as the shale industry is ramping up production and activity due to stabilized oil prices, Moisson and others who stayed busy during the downturn by supplying diverters—a downhole alternative cheaper, more efficient and more flexible—must face a new reality: the diverting business could be set for a boom.

Mastering The Art Of Fluid Dynamics The use of biodegradable diverters in shale wells today is a combination of equal parts science experiment and proven formula. Moisson’s team can custom design its material into different-sized-beads or flake consistencies. In most cases, clients prefer to have packages 20 NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2017

delivered directly to a well site or a supply house with a clearly marked company logo on all diverter packages. No matter the markings, there are several use-cases popular in the field today. In most cases, a diverting agent is used to create a better fluid-flow scenario downhole. When a well is fracked, often a small percentage of the perforations made in a well bore will receive most the fluid and sand mix pumped into the well. On a 30-stage frack, Moisson says, you may have 10 perf holes that are taking 70 to 80 percent of the water and sand. Diverting material can be pumped in between fracks to minimize the unevenness of fluid flow by temporarily plugging certain perf holes to allow others to receive greater volumes of fluid. “You don’t need mechanical clean-outs. It is a very efficient way of controlling fluid dynamics,” Moisson says. Brad Todd, a 30-year industry veteran who formed Completion Science LLC in 2012 out of Duncan, Oklahoma, knows very well the impact of diverters. Todd also stayed busy during the downturn due to work requests for diverting materials and designs. “One of the things we got busy with during the downturn was people using divert-


ers on wells that weren’t fracked very well during initial fracture procedures,” Todd says. With low oil prices pinching operating budgets, many operators wanted to refrack wells to gain production—without the cost of drilling a new well—and diverters allowed them to do so without spending on mechanical operations and clean-outs. Using diverters, operators could section off previously perforated areas of the well, run new fractures into the well and pump new sand fluid mixtures downhole. Along with refracks, Todd says, operators quickly learned that diverter materials can be used during new completion procedures to improve the fracture network near the well bore through better sand retention and placement. The interstage diversion techniques are largely responsible for greater production totals that have been reported by operators in the previous quarters. For those operators looking to reach the toe section of a wellbore too long for coiled tubing, diverter agents can be used to frack the furthest, hard-to-reach areas of the horizontal. And, if an acid job is necessary, biodegradable diverters can be pumped to plug sections that are not to be treated with the acid mixture, Todd says. “They will drill the lateral longer than they feel they can get to, and then they will use diverters to frack

Understanding the Diverter Trend What diverters do: Material (bead, flake or powder) is pumped to seal off a section of the well bore to redirect a subsequent fluid stage to a different section.

Designing a Diverter Treatment: 1. Know what type of pressure differential is needed to get the fluid redirection. 2. Design the system for the downhole situation (rock face sealing, perforation bridging, slot bridging). 3. Work out the volume of fluid needing redirection and the amount of diverter material needed. 4. Decide if diverter is going to be a separate stage or included in the treatment volume (something called continuous diverting).

Equipment Needed to Pump Diverters: Most treatments require only a few hundred pounds per stage. Material can be added directly into blender tub. Given the concentrations and rates recommended, the rate addition would be one to two sacks of material per minute.

Diverter Degradation Rates The chart shows the degradation rate of what might be considered a midtermperatue range PLA and a high temperature range PLA.



the long part of the well,” he says. “The diverter has the mechanical competency to bridge and hold different pressures.” On spacing units that will have multi-well pads with several wells, operators are now looking to diverters as a length limiter on perforations that could impact neighboring wells. “Here lately,” Todd says, “diverters have been used to minimize the frack hits where there is a risk of fracturing into an existing well bore.”

Diverter Specifics Despite the proven positives of diverters, clients of both Moisson and Todd are always asking for tweaks. At his lab in Duncan, Todd and his team are testing new biodegradeable materials or mixes based on client requests. Todd will test his own formulas or others provided by a client. Moisson is doing the same. The material can be made in many sizes but the 4 to 8 mesh sizes are most popular. Moisson estimates it takes roughly six pounds of diversion material to plug a perforation. When his team receives an order from the plastics industry, clients typically give Moisson’s Indiana-based team three to five days leniency to receive the material. “Oil clients will give us an order and they want it the next day,” he says. Last year, Jamplast invested in a hotshot logistics truck and a 32-foot gooseneck trailer to deliver material across the U.S. The truck has been to nearly every part of every North American shale play, Moisson says. Duncan is also expanding. This summer, he will hire more chemists and lab techs. Clients are starting to request testing on other materials that can degrade downhole over time, including tools that haven’t yet been designed to degrade. Some clients are even looking to Todd’s team to find materials that will expand downhole. The key parameters both Jamplast and Completion Science start with are downhole temperatures and pressures. The temperature downhole will help determine the chemical make-up of a diverting material. Operators will choose varying size or form of diverting agent based on pressures. In some cases, beaded diverters are too large for pressure pumps and they need to be used on an isolated pump. Both Todd and Moisson say they have been on the well site during a frack job involving a diverting agent. “As soon as it [the diverting agent in the fluid] hits bottom hole you will see a pressure response,” Todd says on the amount of time it takes to see the impact of a diverter downhole. With their respective client lists growing and staff numbers increasing from necessity, Moisson and Todd both speak with enthusiasm about the future of biodegradable diversion technology and their place in providing unique material and know-how to the evolving shale industry. “There is a lot of opportunity for material science to make completions cheaper, simpler and more effective,” Todd says. “Looks like we are going to stay pretty busy.” Author: Luke Geiver Editor, North American Shale magazine 701-738-4944


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DRILL FLOOR DETAILS: Data sourced from the drilling rig is used to enhance the rig operator’s ability to maintain an efficient rate of penetration downhole to minimize the need for trips due to tool damage. PHOTO: EXXONMOBIL

HOT DATA: The heat-map shows the drilling performance surface. The bit icon and star indicate the current and recommended drilling parameters. PHOTO: EXXONMOBIL


STREAMLINING DRILLING DATA ADVISER: Since its inception, Erika Biediger has led ExxonMobil’s upstream research team’s efforts to help a drilling rig save energy and time downhole. PHOTO: EXXONMOBIL

SHALE DRILLING Oil majors and startups have unleashed new advanced drilling aids for quicker, cheaper and more efficient operations

By Luke Geiver ExxonMobil system makes every driller better

CAREER DRILLER: Jeff Moss has worked on ExxonMobil drilling operations across the world. He believes the new Drilling Advisory System can make any driller better in minutes. PHOTO: EXXONMOBIL

A single drilling rig capable of creating the long-reach laterals present in North America’s major shale plays can drill roughly the same number of wells today as two or three drilling rigs operating two years A single drilling rig currently deployed in one of North America’s major shale plays can drill double the footage in the same amount of time as a rig could in service two years ago. That drilling efficiency increase, present in plays from Texas to Pennsylvania, can be attributed to greater reservoir knowledge and modeling, rig deck communications gains and to technology like ExxonMobil’s recently released Drilling Advisory System (DAS). The trademarked DAS combines high-end modeling of drilling physics with structured well planning to maximize performance while drilling a well. Jeff Moss, a career driller for ExxonMobil who is currently a senior technical professional at its Upstream Research Co., helped to oversee the development and implementation of DAS. “The system takes real-time measurements and presents them to the rig operator, the one with his hand on the controls, so that he can be more efficient,” Moss says. “The system will tell the rig operator the optimum place to operate to maximize the rate of penetration and to help reduce the number of trips needed due to downhole tool damage,” he says. The system is part of the company’s Fast Drill technology suite, which has improved ExxonMobil’s drilling rate by more than 80 percent since it was first introduced more than a decade ago. With the addition of DAS, the company says it has been able to improve its drilling performance at nine fields.



Determining Trip Points – Well 1 – Well 2



Trip Points

Measured Depth



10k 0












TRIP DECISIONS: The Mobilize dashboard allows drilling engineers to compare trip points from multiple wells and pads. The analytics uses on-bottom days vs depth slopes compared to offset wells. SOURCE: MOBILIZE

Making life easier for drilling engineers Mobilize, a data aggregation and analytics provider, is committed to making the lives of drilling engineers easier. The Texas-based firm has created several data interface solutions that take machine-based information and analyze the intel before repackaging into an easyto-read format capable of pushing decisions or driving infield actions. According to Chris James, customer service manager for Mobilize, as drilling rig activity picks up, the time of drilling engineers becomes more valuable. Mobilize has created an interface system that compares drilling performance from well-to-well or pad-to-pad.

Erika Biediger, drilling and subsurface technology manager for ExxonMobil Upstream Research Company, helped design and lead the global roll-out of the process. “With its automation, it [DAS] is doing math behind the scenes for the driller. It can eliminate the need for the driller to figure out on his or her own the inefficiencies down hole,” Biediger says. Reducing the inefficiencies that occur 8,000 feet below surface helps to streamline the drilling process by reducing the time to reach from spud to total depth, and, according to Biediger, it saves the rig operations energy. “We found that if you drill more efficiently,” she says, “you are able to consume less energy to drill the same hole.

The system allows engineers and interested parties to monitor rig performance. “If a system is underperforming, an engineer will get an alert and then be able to inform the rig crew,” James says. In addition to helping the engineers understand the best times to trip pipe, the system can also indicate how to reduce slide percentages when drilling the lateral. Today, the data is only specific to individual companies, but in the future, Mobilize hopes to form drilling consortiums so that may provide a more comprehensive set of data explaining trends and norms for drilling operations in the U.S. generated from rig-centric data.

If you have less vibrations downhole, you have less tool vulnerability.” Although the system is highly complex and uses unique algorithms to enhance the drilling process, the system is rig agnostic and can be added to nearly any set-up. Training for the system is also relatively simple. In matter of minutes, a rig operator can learn how to utilize the system. If a rig team wants to better understand why the DAS is telling the team to perform certain actions, the system and training can be tweaked to do so, Moss says. “We can scale it based on a drilling experience. It can make a good driller very good and a bad driller pretty darn good,” Moss says. ExxonMobil has chosen to license its


DAS. Earlier this year, Pason Systems Inc., a drilling data provider, purchased a license. Pason worked with ExxonMobil through the development and field demonstration of the system. Marcel Kessler, president and CEO of Pason, says the DAS can significantly improve the efficiency and effectiveness of drilling operations. Author: Luke Geiver Editor, North American Shale magazine 701-738-4944

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Issue 2 2017 - North American Shale magazine  

The North American Shale magazine is the #1 Source of news and information about shale energy business and communities in North America.

Issue 2 2017 - North American Shale magazine  

The North American Shale magazine is the #1 Source of news and information about shale energy business and communities in North America.