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ISSUE 4 2018



Swing Why The Bakken Is Primed To Renew The Boom Page 16

Plus Modern-Day Energy Servicer: Restructured To Refocused Page 22

And Trends In Tight Oil ReďŹ ning Page 25 orthAmericanShaleMaga ine Printed in USA




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ISSUE 4 2018






The Bakken Better Than Ever

22 Field-Driven Upgrading


BY LUKE GEIVER C&J Energy Services president of strategic planning explains the changing trends and requirements of a modern-day energy service company.

BY PATRICK C. MILLER In the midst of Permania, Bakken entities have achieved well netback dynamics and infrastructure build-outs that show the play is back and primed to boom again.


2018 Bakken Conference & Expo



ATEC Steel


Eldred Environmental & Export Company, LTD.


Fox Thermal Instruments




Rock Flow Dynamics


Stellar Industries


Wanzek Construction


From frack sand to water, Solaris expands growing empire again Basin-specific pipeline plans show shale play differences


Shale Season Is Here BY LUKE GEIVER

ON THE COVER: Hess Corp. is one of several major Bakken operators excited about the netbacks-per-well in the Bakken. PHOTO: HESS CORP.




Q&A: Refining Mergers Show Ongoing Trend BY PATRICK C. MILLER


EDITORIAL Editor Luke Geiver

Shale Season Is Here

Staff Writer Patrick C. Miller Copy Editor Jan Tellmann


Luke Geiver EDITOR North American Shale magazine

CEO Joe Bryan

Early summer is definitely shale season. Pressure pumpers, hotshot drivers, water haulers, pipeliners, engineers and just about any other sector of the industry is active, on-site or driving from field site to field site. Staff writer and

President Tom Bryan Marketing & Sales Director John Nelson Business Development Manager Bob Brown

photographer, Patrick C. Miller, witnessed this season’s activity first hand during a recent photoshoot held near the heart of the Bakken shale play. According to Miller,

Circulation Manager Jessica Tiller Marketing & Advertising Manager Marla DeFoe

areas of the Bakken that he hadn’t considered busy during past trips were noticeably different—and ART

undoubtedly active—this year.

Art Director Jaci Satterlund

In this issue, we offer a special look at the Bakken, taking advantage of a major May event held biennially in North Dakota that brings together an impressive number of Bakken-focused personnel. (Two years ago then-presidential candidate Donald Trump was the keynote). Based on his interviews and notes from the event, Miller reports the Bakken is officially back. On a well-to-well basis, many operators leveraged to the Williston believe netbacks from a Bakken well are as good, or usually better, than any well—anywhere in North America. In North Dakota, many operators are generating a netback equivalent to the price of West Texas Intermediate plus about $2. In the Permian, where investors and companies have been focused the past two years, netbacks are typically WTI minus $9 due to infrastructure bottlenecks. This summer, production records for both oil and gas will be broken in the Bakken. Major entities are talking—or building—huge, high-dollar processing facilities or even enhanced oil recovery that could take even more oil from the ground utilizing associated gas rich with ethane, methane and propane as an EOR injection fluid. With oil prices, netbacks and enough infrastructure in place (for now) to help stay ahead of major bottlenecks, operators have even expanded the core of the Bakken again. The rig count has been steadily increasing all summer and when the rigs go to work, they aren’t just going up in the main two counties of the play. According to the state’s lead oil regulator and all-world Bakken expert, “the entire Bakken is at play again.” There is no doubt, from the upper reaches of the North Dakota Bakken in Divide County, to Atascosa County, Texas, activity has ramped up to a pace that is anything but slow and steady. It is shale season,

Subscriptions Subscriptions to North American Shale magazine are free of charge to everyone with the exception of a shipping and handling charge 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@

after all, and, the season is just getting started. COPYRIGHT © 2018 by BBI International


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Niobrara Ward Energy Parnters, a leading operator in the play since the company was founded in 2014, has sold assets in Adams and Weld Counties, Colorado, to an undisclosed buyer. The assets are prospective for the Codell and Niobrara reservoirs in the DJ Basin.


Permian Whitewater Midstream is doing its part to move shale gas in the Delaware Basin. The company recently announced plans to add long-term transportation service agreements with two major producers from the region. The agreements will give it 1.1 Bcf/d of committed gas. Agreements have already been formed with Brazos Midstream, Crestwood Midstream Partners, EnLink Midstream and Medallion Midstream.

Eagle Ford Black Mountain Sand is bringing a larger in-basin sand operation to the Eagle Ford. After starting in the Permian, demand in South Texas was too great to ignore, according to the company. At its third Texas mine (first in the Eagle Ford), Black Mountain will produce 2.2 million tons of sand annually. The facility should be operational by the end of 2018.



SCOOP/STACK EcoStim Energy Solutions, an energy service provider that utilizes natural gas-powered pressure pumping equipment, is creating what it calls a super fleet in the STACK. The company’s main client is preparing to complete more mutli-well pads and zipper fracks this year and the combination of equipment from EcoStim’s two fleets is required to make the operator’s plans possible. “In reviewing the super fleet concept, we believe the plan will allow the company to deliver more efficiencies, better margins and stronger near-term cash flow,” said Chris Boswell, EcoStim’s CEO.

Bakken Hess recorded a 12 percent production increase in Q1 2018 due to a new completion strategy. The approach includes 60-stages and 8.4 million pounds of proppant. The previous approach involved only 50 stages and 3.5 million pounds of proppant. The Bakken is Hess’ largest operated asset with more than 500,000 net acres in the play’s core. The company plans to add a fifth rig there in the third quarter and a sixth rig in the fourth quarter. Whiting Petroleum, another major Bakken producer, is finding great success in 2018. The company has already recorded discretionary cash flow that is greater than capital expenditures expected to this point. In the second half of the year, Whiting will shift all of its attention to the Bakken. DUCs in Colorado will be left untouched as it ramps up activity levels in North Dakota.

Marcellus/Utica Range Resources is working to change the understanding many have of the shale gas-focused producer. CEO Jeff Ventura said that as the company works to high-grade its portfolio through asset sales, it is also changing the company’s narrative through longer laterals and efficient execution on acreage that some believe—in disagreement with Range—is not complete with proven reserves. The SEC definition of proved reserves excludes thousands of top-tier acreage Range holds, according to Ventura. “I believe this represents one of the largest disconnects in value in E&P today,” he told investors earlier in the year. The company is also talking about its longer laterals that are reaching 17,000 feet. Increased EURs on the laterals are yet to be proven, but if or when they are, Range hasn’t yet accounted for the better numbers in its five-year outlook.

RS Energy offering in-house, play-specific data

Looking for better data? Check out the news from RS Energy Group. The energy intelligence and investment team from Calgary is now offering up the same data it uses to generate intel. The company is offering its trademarked RS Core, a digitized data set that shows 20 years of RSEG-gathered and utilized intelligence. The core set of data can be used to generate type curves, well costs and other field-specific analysis. “There’s an enormous market need for trusted, highly technical advanced analytics and we are excited to lead the charge,” said RSEG co-CEO Manuj Nikhanj “It wasn’t about a race to the finish with this solution,” Nikhanj said. “It was a methodical process that started with ensuring we had the absolute best and most complete data before building the advanced and predictive analytics on top of it.”



From frack sand to water, Solaris expands growing empire again Bill Zartler, CEO of Solaris, a Texas-based company that has built a unique frack sand handling, storage and tracking system, is building a new service, this time with a focus on water. The company has formed Solaris Water Midstream LLC to serve producers in the Delaware Basin. Infrastructure to be built and operated by Solaris will help producers in Eddy and Lea Counties of New Mexico and Culberson and Loving Counties of Texas, including gathering, transporting, recycling and the disposal of produced water. Included in the first phase of the project, which was recently completed, is a 50-mile


stretch of 12- and 16-inch water line that connects to multiple disposal-well facilities or other connections. “We believe we are building the premier water infrastructure system in the Delaware Basin,” said Bill Zartler, CEO. “Our system offers operators shared infrastructure to multiple disposal wells and recycling facilities with built-in redundancies to save capital and lower costs.” Build-out of the remaining system—which will feature more than 300-miles of high-capacity gathering and distribution pipelines—will continue throughout the year.


THE PECOS STAR: Running through the heart of the Delaware Basin, the new water gathering, supply, disposal and recycling system will be built in phases. Phase one is complete with more construction on the way.


GHG Mitigation Investments in North America 2000-2016 (Total Investment=$598 billion, 2016$)

Leading GHG Mitigation Investments in North America (2000-2016, 2016$)

325 300 275 250 225 200 175

ATV 17%

Other 20%

Enabling Non-Hydrocarbon End Use Fuel Substitution w/o Shale Shale Gas Wind 9%

150 125 100

Total Investment = $597.8 Billion Top Five = $469.7 Billion

Ethanol 6%


Efficiency, Lighting, Heating, AC, etc. 15%

50 25 0 Oil and Other Natural Gas Private Industry Industry

Federal Gov.



How does the oil and gas industry compare in carbon reductions?

A new report shows the oil and gas industry's commitment to reducing the amount of carbon it produces through investments in zero-emission and low-carbon tech. The study, “Key Investments in Greenhouse Gas Mitigation Technologies,” was completed by Thomas Tanton, president of T2 and Associates, an energy and technology consulting firm.

Key points from the study: - The oil and gas industry is a leading investor in zero and low-carbon technology, investing more than $108 billion between 2000-2016—more than double the investments of each of the next two industries. - In 2016, the oil and gas industry reported the largest greenhouse gas (GHG) reduction

nologies in the North American market. The U.S. based oil and gas industry invested $301.5 billion ($108.2 billion without shale gas), 50 percent of the $597.8 billion total, in end-use, fuel substitution, non-hydrocarbon, and enabling technologies. Other private companies invested an estimated $143.6 billion or 24 percent of the total, predominantly in end-use and non-hydrocarbon technologies. During the same period, the federal government invested in The report also a wide array of greenhouse gas addressed basic How much has the private mitigation technologies, with questions: sector and the U.S. federal expenditures of approximately $152.7 billion ($151.4 without government invested in What are the top shale gas), or 26 percent of the GHG mitigation carbon-reducing total North American investment. technology? technology investments? This does not include state and loU.S.-based companies and The five leading emission cal expenditures nor investments. mitigation technologies for private the federal government invested approximately $597.8 billion (2016 and public-sector investment, as dollars) from 2000 to 2016 on measured by expenditure share, greenhouse gas mitigating techare: shale gas, 33 percent ($194.6

to date compared to the previous year—a reduction of more than 57 million tons of carbon equivalent. It’s the amount of carbon captured by 5.4 billion, 10-yearold evergreen and pine trees. - U.S. carbon dioxide emissions are at 25-year lows because of increased natural gas use. Global emissions have risen 50 percent during the same timeframe.

billion); advanced technology vehicles (ATV), 17 percent ($100.0 billion); efficiency, 15 percent ($86.9 billion); wind, 9 percent ($53.4 billion); and ethanol, 6 percent ($34.7 billion). These top five technologies commanded 79 percent of the estimated total investments, or $469.7 billion over the 2000-2016 period in the North American market. All other technologies combined comprised 21 percent of the estimated total investments.



Jagged Peak Energy: 13 percent improvement in completions reason for best quarter Jagged Peak Energy achieved its best quarter to date in early 2018 thanks to a 13 percent improvement in efficiency throughout its Delaware Basin wells. The company credits its ability to design a completion strategy that perfs more stages per day per crew. A licensing agreement with a 3D seismic company has also helped the company place longer and more precise laterals. The combination of better completion numbers and better lateral placement equates to a 13 percent improvement over previous quarters, according to the company. The end-result helps the company spend wiser and maintain its original 2018 plan. For the full year, Jagged Peak will invest up to $615 million, with $590 million going towards drillings and completion costs. Nearly $10 million will be spent on 3D seismic and another $25 million is scheduled for water infrastructure.

Late 2017 through early 2018:



3.1 stages

per crew

per crew

stages per day

Average lateral length:


per day

9,300 feet


Niobrara operator adds gas-to-liquids tech SandRidge Energy Inc. has a new advantage in the Niobrara shale play. The exploration and production company has partnered with Dallasbased Advantage Midstream on a project that will turn produced gas into liquid fuel. Advantage has created a unique process that converts various sources—natural gas, ethane, flare gas or CO2—into syngas. The synthetic gas is then converted into ultra clean, low-emission synthetic diesel fuel, gasoline or hydrogen. In Colorado, Advantage will setup its system and process SandRidge gas through its skid-mounted offering before marketing the resulting liquids. “Advantage is pleased to utilize our unique set of tools to provide a value and net-back-driven service to SandRidge Energy’s assets in the North Park Basin of Colorado,” said John Stephenson, CEO. Along with the recently announced operations in Colorado, Advantage said it is also active in talks with producers in the Permian, Bakken and Midcontinent.



Basin-specific pipeline plans show shale play differences At the heart of every active shale play in North America today is an evolving matrix of gathering and takeaway infrastructure that is crucial to each play’s long-term viability. News of new projects or advanced regulatory and technological requirements shows the state of infrastructure from region to region.

Delaware Basin 3 Bear Energy LLC, a Denver-based midstream provider, has opened a call to producers for a crude gathering line in New Mexico. The crude line could span 60-miles in Lea County, New Mexico. The Hat Mesa System, according to 3 Bear Delaware Operating-NM LLC, already has one major shipper willing to make a long-term acreage dedication. Additional shippers will have the option to commit through volume or acreage. EPIC Midstream Holdings has also announced a pipeline project that already has major shippers lined up. Apache Corp. and Noble Energy have each agreed to ship crude on a 730-mile pipeline that will move crude from southeastern New Mexico to Corpus Christi, Texas. Apache plans to move 75 mbl/d and Noble will ship 100 mbl/d. The pipeline truly is epic. Once complete, the line could move 590,000 barrels of oil per day through the Permian, Eagle Ford and onto the Texas Gulf Coast. Right-of-way is 100 percent secured for the first two phases of the system, and construction is expected to commence in the fourth quarter of 2018. The crude system is expected to be in service in the latter half of 2019. “Noble Energy’s strategic agreement with EPIC provides longterm flow assurance for our rapidly growing Delaware Basin oil volumes. With this agreement, we have further diversified our onshore marketing outlets with access to the Gulf Coast and global markets,” said Gary W. Willingham, Noble Energy’s executive vice president, operations. 12


Bakken In the Bakken, pipeline buildout is still crucial to the play, but the play’s main regulatory state—North Dakota—is working to create a next-generation approach to pipeline construction and long-term viability. The state’s Industrial Commission recently approved a project led by Hess Corp., Oasis Midstream Partners, Statoil, ONEOK and Goodnight Midstream. Through the North Dakota Oil and Gas Research Council, the group involved in the Intelligent Pipeline Integrity Program will be allowed $1.6 million to advance emerging technology designed to prevent and detect gathering pipeline leaks. The iPIPE consortium hopes to amass funds needed to facilitate development and demonstration of emerging technology, promote industry engagement or participation and encourage industry-wide adoption of what it believes will be worthy technologies.

SCOOP/STACK In the SCOOP/STACK, Cardinal Midstream III LLC has formed a deal with Camino Natural Resources for its Iron Horse gathering and takeaway system. Along with Travis Peak Resources LLC, the deal will bring more than 150,000 acres to the system. “As we broaden the rich natural gas system, we are also evaluating ways to add complimentary crude and dry gas gathering services,” said Tim Roberts, president of Cardinal. Cardinal expects to complete the construction of approximately 150 miles of high- and low-pressure natural gas gathering pipeline by the end of 2018. The system also includes multiple compressor stations and the Iron Horse cryogenic gas processing plant. Located in Grady County, the Iron Horse plant is expected to come into service in October 2018



Canadian midstreams making US moves For $1.12 billion, AL Midcoast Holdings LLC has acquired the Texas, Oklahoma and Louisiana midstream assets of Enbridge Inc. The businesses included in the deal are natural gas gathering, treating, processing and transportation, as well as NGL transportation assets located in the east Texas, western Anadarko and Barnett shale plays and consist of approximately 11,200 miles of natural gas gathering and transportation pipelines, 2.075 million cubic feet per day (MMcf/d) of natural gas processing capacity and 1,330 MMcf/d of treating capacity. Al Monaco, president and CEO of Enbridge, said the sale will help Enbridge shift towards a “pure regulated pipeline and utility model.”

The deal should close in Q3. Prior to the sale, the newly formed AL Midcoast had been in charge of operating and running the assets. According to AL Midcoast, the workforce and team running the assets will be maintained. Another Canadian-based energy company has also made U.S. moves. Calgary-based Ke-


yera Corp. has announced plans to build a 4.5 million crude storage and blending facility at Cushing, Oklahoma. Keyera currently operates an integrated Canadian-based midstream business with interconnected assets and expertise in midstream solutions. The Wildhorse Terminal in Cushing will feature 12 above-ground tanks. “The

Wildhorse terminal is a strategic investment for Keyera as it expands our midstream infrastructure in the U.S. at once of the largest crude oil storage and trading hubs in North America,” said David Smith, Keyera’s president and CEO.

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BETTER Than Ever Emerging from the downturn, optimism from Bakken-industry players highlights why most see the play as another opportunity waiting to happen

Story and Photos By Patrick C. Miller




The rising tide of oil prices has lifted the Bakken shale play to the lofty position of No. 1 in netback per well drilled, which has not only resulted in predictions of a new oil production record for North Dakota this summer, but also a renewed sense of optimism among industry insiders about the play’s future. The annual Williston Basin Petroleum Conference—sponsored by the North Dakota Petroleum Council—attracted more than 2,500 people from 40 states, three countries and six Canadian provinces. Many of the event’s participants outlined their plans while explaining why they considered the Bakken one of the top plays in the U.S.

Presenting The Mood “The conference speakers and enthusiasm by the attendees sent a valuable message that our industry has a bright future and that the Williston Basin’s oil and gas resources play a critical role in the world’s energy future,” noted Ron Ness, NDPC president. Echoing the conference’s “Bakken now” theme, Lynn Helms, director of the North Dakota Department of Mineral Resources, said, “The Bakken is now, and we need to be thinking about what’s next because the Bakken is going to go on for decades and generations.” Throughout the conference, speakers made comparisons between the Bakken and the nation’s hottest shale play, the Permian Basin in Texas and New Mexico. Helms said attention had become so focused on the Permian that some referred to the condition as “Permania.” “Two or three years ago, you couldn’t get investors’ attention on the Bakken,” said Greg Hill, chief operating officer of Hess, which has a 50-year history of Williston Basin operations. “Everybody had turned to the Permian. All people wanted to talk about was, ‘When are you going to get in the Permian? What’s your position in the Permian? How come you don’t have a position in the Permian?’ We kept returning people back to the Bakken, saying the Bakken has as good or better economics as a large part of the Permian.”

According to Hill, the Permian Basin is suffering from many of the growing pains that plagued the Bakken several years ago, which include lack of infrastructure, the high cost of acreage, an insufficient workforce, bottlenecks in moving oil and gas to market and traffic congestion. “What that means now is that the Bakken is the place to be,” he said. “If you look at netbacks alone, WTI plus about $2 is what’s going on in the Bakken. If you look at the Permian, it’s WTI minus $9 or $10 because of all those bottlenecks. We’ve got the infrastructure, we’ve got a great regulatory framework here and we’ve got higher netbacks. So, the Bakken is the place to be.” Brad Holly, president and CEO of Whiting Petroleum, gave a talk titled “Why the Bakken?” in which he proceeded to answer his own question. Noting that the Bakken accounts for 10 percent of U.S. oil production, he cited a regulatory environment in North Dakota that provides certainty to investors. Whiting is bullish on moving oil out of the Williston Basin, Holly said, but also added that additional investment is needed to respond to the challenge of increased gas production. “The Bakken has performed very nicely on oil differentials compared to the Permian,” Holly stressed, adding that Whiting expects differentials in the play to steadily improve. Holly was one of three producers on a panel with Ness who discussed the next moves for the Williston Basin. Erec Isaacson, vice president of the ConocoPhillips Rockies Business Unit, said that by reducing costs and spending, improving efficiencies and focusing on its best resources, the company is moving forward from its low point two years ago. In spite of the improvement in oil prices, he noted that the industry remains in a period of volatility. “The key takeaway is that we need to maintain resilience in the face of volatility,” he emphasized. Thomas Nusz, chairman and CEO of Oasis Petroleum, said the 15 years of experience in the Willison Basin helped the company become one of the first producers to go cash-flow positive during the downturn. As the fourth largest producer in the basin,



MORE OIL, MORE GAS: Lynn Helms, director of the North Dakota Department of Mineral Resources, expects a new state production record this summer. However, record levels of gas production have also renewed concerns about whether producers can meet the Nov. 1 gas capture goal of 88 percent.

Nusz said Oasis plans to spend $1 billion in id—a fluid that will mix with oil—to create a the Bakken this year, 75 percent on upstream higher displacement of oil. Working with the University of North Dakota Energy & Enviand 25 percent on downstream. ronmental Research Center, Liberty will test a technique that could recover 40 percent or Field-Level Opportunities One of the key opportunities for the more oil the Bakken’s oil resources. “That is Bakken lies in enhanced oil recovery (EOR) the opportunity for the Bakken,” Pearson said. The problem with using CO2 for EOR is technology. Helms revealed that there will be four EOR projects in the Williston Basin this that it’s expensive. “It’s a big project that small summer testing the technology. Mark Pearson, companies like mine could never take on,” president and CEO of Liberty Resources, dis- Pearson explained. “You’ve got to drill the cussed the company’s Stomping Horse EOR wells for the resource. You’ve got to pipeline it Project which is expected to begin in July north in chrome alloy pipes because of corrosion isof Tioga, North Dakota. He used long straws sues. And you have to change out all your tubuand two two-liter bottles of “conventional” lars in your injection wells because of carbonic Coke and “unconventional” Diet Coke to acid and corrosion that go on there,” he said. demonstrate the process. What the Bakken offers is gas with high Pearson noted that the Bakken has greater levels of natural gas liquids (NGL) that can be oil reserves than Saudi Arabia. The difference used as a miscible liquid instead of CO2. Pearis that currently, only a small portion of the son said Liberty’s gas is typically 80 percent Bakken’s reserves are considered economically methane, 20 percent ethane and 10 percent recoverable. In the 1970s, experiments began propane. using carbon dioxide (CO2) as a miscible flu“It’s those components of ethane and 18


propane that excite us about the potential for enhanced oil recovery in the Bakken,” he said. “We have the potential to take the produced gas—with the NGLs in it—and reinject it back into the ground to increase the oil production coming out. “I don’t know what the results are going to be, but it definitely has the potential of being a gamechanger in terms of our total recovery,” Pearson continued. “I think the future is bright for the Bakken, but I think it’s time for what I would call some EBOR— enhanced Bakken oil recovery.”

Exporting From North Dakota According to Brady Cook, Koch Industries Inc. senior vice president for oil and trading, the Bakken is ripe to benefit from export opportunities. While U.S. shale oil production is surging, refinery capacity in the U.S. is growing slowly. In contrast, Asian refining capacity for sweet, light crude is rapidly expanding. U.S. refiners will continue


to import quantities of medium and heavy crude to meet their needs. “Lighter crude will grow in value versus heavier grades,” Cook predicted. “Bakken oil is well-positioned for this compared to common water-borne crudes for refiners in Europe and Asia. The market is recognizing the scale of the refining problem coming its way. The value for Bakken goes up compared to refiners’ other crude alternatives.” Both Hill and Helms emphasized that beginning with the oil price downturn, investment in the oil and gas industry has lagged far behind where it should be to keep pace with demand. To catch up, an annual investment of $540 billion is needed through 2040, according to Hill. Helms labeled the $1 trillion underinvestment in the oil and gas industry that’s occurred since the downturn began in 2015 a huge concern. “What that means is that sometime not too long after 2020, prices have to make a correction to bring that investment back and bring that production back,” he noted. “But in 2021 when we see that price correction, we see rigs coming back really, really intensely.”



Another Bakken Rush Looming

THE BAKKEN IS BACK: Left, a Continental Resources well being drilled north of Manning, North Dakota. Above, Mark Pearson, Liberty Resources president and CEO, demonstrates enhanced oil recovery during the Williston Basin Petroleum Conference.


Helms expects North Dakota to set a new production record this summer, eclipsing the previous record of nearly 1.23 million barrels per day set in December 2014. With that comes record levels of gas production as well. In North Dakota, Helms said lack of infrastructure to capture and process gas will likely be a problem this year when state regulations raise the level of gas capture required from 85 percent to 88 percent. Although the oil and gas industry has invested $127 billion in the state, he estimates that another $350 billion of investments will be needed over the next 20 years. While the state now has excess railroad and pipeline capacity to ship the crude it produces, Helms expects that situation to change by 2020 when even an expanded Dakota Access Pipeline will reach full capacity. That means either increased crude by rail or planning for another oil pipeline. “My message to you—you’re mainly upstream and midstream folks—is when somebody comes to you with a proposal for an export pipeline, commit barrels. Get the pipeline built because there is no time to get that project started and permitted,” Helms stressed. In addition, he emphasized the need to build more gas gathering pipelines and gas processing plants to deal with an increas-


ing gas-to-oil ratio. Since 2016, the industry has laid between 700 and 900 miles of new gas pipeline annually, a trend Helms said must be reversed. ”If we go back to the number of completions that we anticipate, then we need to be building 2,000 miles of pipeline every single year from now to 2025,” Helms stated. “There is no time like the present to get your right-of-ways.” In addition, even though five new gas processing plants representing a $3 billion investment should come online in late 2018 and 2019, Helms said they’re expected to meet industry’s needs only through 2020 or 2021. Another $6 billion of investments in gas processing plants will soon be needed to handle increasing production, he said. More infrastructure to transport NGL will also be needed in the next three years, Helms noted. Expanded oil and gas production, combined with the need for more infrastructure, means that the workforce will also need to expand. Helms estimates that the 56,000-people employed by the industry at its peak in 2014 will need to grow from the current 36,000 jobs to 63,000 by 2020. “We need to be talking to our western communities about how they’re planning for these people to come back because they’re all coming back—plus another 7,000,” Helms said. “These people are young and they’re diverse. We used to be a state that was No.1 in retired people—growing older and a shrinking population. We are now No. 1 in millennials.”

Core Expansion The good news Helms brought to the conference was that increasing oil prices have enabled Bakken producers to once again begin operating outside the play’s core areas. “At today’s oil prices, the economics reach way beyond the core and all the way to the Canadian border,” he said. “The entire Bakken is at play again. Sixty-five rigs are drilling today. In less than a week, we’ve added five rigs in the state of North Dakota. That’s great news for the royalty owners, for the working-interest owners and to the operators out in those parts of the world.” Hill said that despite predictions of electric cars reducing the demand for oil, the demand for petrochemicals and the need for longhaul fuels for trucks, ships, trains and aircraft ensures that oil and other fossil fuels will continue to meet 75 percent of the world’s energy needs through 2040. “Not only is the Bakken helping the state of North Dakota, it’s helping the United States of America,” Hill said. “And more importantly, it’s helping to change the lives of millions of people around the world as they come into prosperity—prosperity that so many of us have enjoyed.” Author: Patrick C. Miller Staff Writer, North American Shale magazine 701-738-4923


Dependable liquid storage and spill containment products for over

60 years




Field-Driven Upgrading

For modern-day energy service providers competing for the biggest clients in the hottest plays, the push for the next best thing is a constant—and a requirement

By Luke Geiver Tim Wallace believes the shale energy services industry is on a path to make better use of data to improve performance, much like artificial intelligence applications with predictive analytics and IBM’s Watson computer. Wallace, who served as president of completion services for C&J Energy Services and recently transitioned to president of strategic planning, notes that his company has been steadily implementing technological improvements that enable predictive analytics to improve performance. In an ever-changing industry, knowing when technology upgrades

are needed (or when equipment will require downtime) to support efficient and quality execution is critical to being competitive in the shale world. C&J, based in Houston, is all too aware of this necessity. Currently active in all major shale plays in the continental U.S., C&J has executed an aggressive growth strategy, both organically and through multiple acquisitions and other strategic transactions, domestically and internationally, to transform into an industry powerhouse. After enduring difficult conditions during the historic industry downturn that ultimately resulted in a management change and Chapter 11 financial restructuring, C&J is one of several energy service firms that have


reinvigorated their presence in the new wellfocused services sector with improved offerings and a strong focus on constant and continuous improvement. Wallace and his team have honed their approach to thriving as a modern-day shale service provider to operators in multiple basins. For them, it’s all about combining field-driven technology enhancements with premium service—and, like Watson, an element of predictability. We spoke with the C&J team to find out what it takes to succeed with a business that is linked to the price of oil, requires anticipating evolving client needs and, as Wallace says, “is intense and hard on equipment.”


See the Whole Picture The major strength of C&J, Wallace believes, is its broad focus. “We’re active across different parts of the well life cycle,” Wallace says. “We offer a very broad base of services. I like that model.” C&J operates in three reporting segments led by a president of completions services, well construction, well support and interventions services. In addition to the multi-leader focus, the company relies on a research and technology (R&T) team, based in Houston with a state-of-the-art facility, that helps create solu-

tions to problems that arise in the field. “We can be very responsive to industry trends and customer needs because of our R&T capabilities,” says John Swift, C&J’s director of marketing. “We have the luxury of using expertise across multiple product lines. It makes it easier to have an integrated approach to completions,” Wallace says, adding that his team can bring a total engineering package to the well. “We know this is important to the operator.” During a time when the term “enhanced completion” dominates the list of buzz terms used in investor calls or E&P presentations, Wallace says C&J’s whole-picture approach enables C&J to deliver to its customers new products designed to bring better performance or efficiency to the completions process at a quicker and more-effective rate. En-

ergy service firms looking to evolve with the industry must constantly look to the future. As Wallace and Swift both explain, it is not enough to simply be a dependable, qualitydriven service provider. The demand for new technology and need for efficient operations are the drivers behind Wallace’s belief in predictive analytics. In the near term, he believes C&J will be able to predict when equipment is about to require downtime and maintenance. Knowing in advance is a variable that can save operators money while adding revenue for service providers. “We’re looking to do that with our frack equipment,” he says. “We want to predict when it’s likely to fail and stay on top of preventive maintenance to avoid any unplanned downtime.”



Preparing for The Future With predictive capabilities for pressure pumping units in the works, C&J is also working on several other tech upgrades, offerings and workforce strategies. The company now offers the trademarked LateralScience process, an engineered completion modeling service that relies on drilling data to create a hardness profile for the rock along the entire lateral wellbore. Their new trademarked GameChanger perforating system, developed by an in-house team of engineers, features a semi disposable gun assembly designed to eliminate the misruns and resulting NPT associated with traditional gun systems. And, as more operators are working to reduce their carbon footprints, C&J has announced new technology that reduces fuel consumption at the wellsite. C&J has 16 horizontal (or horizontal equivalent) hydraulic fracturing fleets deployed in the field now. By the end of 2018, the current plan is to roll out at least three more fleets, with another two fleets expected to come to market in late 2018 or early 2019. Wallace is optimistic about the industry in general and says C&J’s new well businesses are growing across every major U.S. basin. Working in conjunction with the R&T team, Wallace says alleviating industry challenges starts in two main areas: perforating misruns and blending problems. These two areas—that is, when the perforating guns are run to perform downhole perforations, and the frack blending process used to mix sand with water—pose a high risk of giving operators headaches and causing downtime. “We are working on some big improvements in each area,” Wallace says. Along with wellsite operational challenges, both Wallace and Swift say there are still personnel and hiring hurdles in the sec-

MEET THE TEAM: Using insight from field operation managers, the research and technology team is constantly working to create new in-field tech upgrades. C&J, like many energy service firms, isn't only focused on service, they also want to bring new products to market. PHOTO: C&J ENERGY SERVICES

tor. Although they say they’ve had success in staying ahead of shortages, both recognize the challenge is significant, it’s real, and it requires constant attention. Like C&J’s indevelopment projects for new technologies, they were unwilling to fully divulge the strategies used by C&J to maintain the proper workforce, indicating only that one area that has provided success is C&J’s support of our military veterans. In general, the number of stages and perforation clusters used by operators in most wells in U.S. basins is only going higher, Wallace says. He believes laterals will only continue to get longer as new coiled-tubing options enable engineers to reach further distances in the quest to optimize recovery. C&J is working on new technology in this area as well.

“It’s amazing how much technology has grown and advanced,” Wallace says. For modern-day energy service firms that are competing for the largest clients in the biggest and most competitive shale plays, it is now a requirement of existence to emphasize a look to the future, both Wallace and Swift say. New technology and approaches “have pushed service companies like us to keep looking for breakthroughs in how to do things better on multiple levels,” Wallace says. “It is, and I believe will continue to be, fun to watch and participate in this dynamic industry.” Author: Luke Geiver Editor, North American Shale magazine 701-738-4944

CHARGED WITH EFFICIENCY: Reducing non-productive time stemming from misruns during the perf process, C&J Energy created a new perf gun that is semi disposable and ensures firing. 24 NORTH AMERICAN SHALE MAGAZINE ISSUE 4 2018



FLEXIBLE REFINING: The merger of Marathon Petroleum and Andeavor is part of an ongoing trend of refiners leveraging their logistical assets. It began with deregulation in the 1980s. PHOTO: MARATHON PETROLEUM CORP.

Q&A: John Auers Refining Mergers Show Ongoing Trend While the $23.3 billion merger agreement announced earlier this year between Marathon Petroleum Corp. and Andeavor won’t go down as one of the biggest mergers in the history of the oil business, it will be the biggest downstream industry deal to date, according to John Auers, executive vice president of Turner, Mason & Co. We asked the go-to refinery and fuels market consultant about the impact of the deal to the country, consumers and the shale world. Auers noted that the merger between Exxon and

Mobil was worth $74 billion, BP and Amoco was $48 billion and Chevron and Texaco was $45 billion. Auers said the merger also confirms the trend of refiners seeking to leverage their logistics assets. For example, he said, “both Andeavor and Marathon have been active in developing and capturing value from midstream facilities, particularly those that allow their refineries to more cost-effectively access crude oil, particularly the growing volumes coming from U.S. tight oil basins.”

Is there any reason to think the merger between Marathon and Andeavor won’t be approved? I would be shocked if it didn’t go through. It doesn’t seem like there are any impediments from the FTC or another standpoint that would cause it not to go through. You have an administration that’s friendly to the energy business. Maybe in a different administration, you might have some questions asked in that direction. The refining operations aren’t located in the

same regions, so they’re complementary. I just don’t see any FTC issues. Do you think U.S. consumers are generally aware of how trends in the refining industry have affected them? I don’t think the average consumer really knows what’s gone on with the business side of refining from majors to independents. You still see the major brands out there—the Exxon and Chevron brands. You still see Shell out there, even though



LEADERS OF THE PACK: Engineering consultant John Auers with Turner, Mason & Co. said the U.S. refining industry has grown more efficient than in other countries because mergers, free markets and competition. PHOTO: MARATHON OIL CORP.

Shell has definitely shrunk. BP has shrunk the most from a refining standpoint. Consumers mostly buy gasoline at their neighborhood gas stations. I don’t know that they know what’s been happening in the industry. In general, I think it’s had a positive effect on consumers. The refineries are more efficient, although the competition is still there. The whole refining industry has changed its mode of operation. It’s much more responsive, as a result, to market trends and market developments. Refiners

will cut back runs or increase runs to respond to the market quicker and more efficiently than they used to. That’s been a positive trend overall. It’s certainly been positive for the performance of the business. Now, the companies that can’t compete, we’ve had a lot of refineries shut down in the last 30 years. It really has been a survivalist kind of environment. That breeds strong and efficient survivors, and that’s what we have. Even the majors have moved toward operating their refining divisions as an independent segment,


much more so than it used to be some companies and entities that survive purely on government in the ’80s and into the ’90s. subsidies. When you remove those protections, some refinerYou wrote in your blog that an attractive part of ies shut down. Half the refineries that were open in the 1980s the planned Marathon are shut down, but our capacity and Andeavor merger is higher. We’re much more efis the synergy between ficient and more competitive. Andeavor’s crude When you deregulate markets, gathering and delivery it’s almost inevitable that you’re assets in the Permian going to come up with a more Basin and Marathon’s competitive industry. It’s going to Gulf Coast refineries. be constantly adjusting to market Why is that important? Marathon and Andeavor trends and reacting to them. both have significant logistics assets as part of their portfolios. Why haven’t the refining That’s a synergistic part of this industries in other merger that’s very complemen- countries been as tary. Andeavor’s got significant successful at crude gathering assets out in implementing the U.S. west Texas and the Permian that model? The big reason is that there they use to support their El Paso refinery. Those are also going aren’t many places in the world to fit in well with the Marathon where you have truly deregulated markets. Governments have a Texas City refinery. finger in the pie there in terms of prices, subsidies and taxes. It’s How did it come about part of the reason that shale oil that the refining has taken off in the U.S. and it industry has developed hasn’t in other places like China such a flexible response to market forces? Was it and Russia where they have the same geology. They don’t have planned or a happy the same free-market ownership coincidence? Deregulation was one of incentives to develop those rePresident Ronald Regan’s most sources properly in the same fiunder-appreciated moves. He did nancial markets to help support a lot of things that he is remem- investors. With refining, there’s bered for—like beefing up the some similarities, but having the defense budget and getting the free market underpinning is most Iron Curtain to fall and cutting important. Other countries, such taxes—but deregulation of the as Brazil and Japan, are moving oil business was a very substan- toward reform. It’s making Japative and important accomplish- nese refiners more efficient. In ment for Reagan. If you’re a free- the long run, it makes the indusmarket economist, you would try more competitive. The U.S. say this is exactly what happens was way ahead of the game when when you open markets. You we deregulated our oil business definitely have some losers in back in 1982. a protected market. There are


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Take Three Steps to High-quality, Low-cost Recycled Water With the HzO Trio water management program from Hydrozonix

The Hydrozonix HzO Trio program uses ozone and innovative technology to replace conventional chemical programs. The result: more effective control of bacteria, iron and sulfide at a much lower cost.

1 2 3

Step One: The HYDRO3CIDE automated oxidation system treats produced and flowback water in gathering systems. Step Two: The portable Hydro-Air Aeration System aerates and mixes water in storage pits and tanks to maintain water quality and prevent bacteria buildup. Step Three: The HZ80 oxidation system provides the final polish by disinfecting water without chemicals that can be incompatible with frac fluids. Operators that recycle with the HzO Trio combination have achieved higher quality water for a fraction of the cost of chemical programs—less than $0.20/bbl. 28 NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

Issue 4 2018 North American Shale magazine  

Creating the Digital Oilfield>> The digital oilfield idea has become one of the hottest talking points in the industry. In this issue, we’ll...

Issue 4 2018 North American Shale magazine  

Creating the Digital Oilfield>> The digital oilfield idea has become one of the hottest talking points in the industry. In this issue, we’ll...