Page 1

ISSUE 4 2017

Positioned For

The Future Global Energy Brand Halliburton Explains Shale Trends and New Tech Page 14

Plus Factors Impacting Emerging Shale Plays Page 20

And Special Insight: Tribes, Energy Producers and Pipelines Page 24

ND Governor's Challenge To Operators Page 8 Printed in USA




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ISSUE 4 2017





Growing the Shale Brand

BY LUKE GEIVER Halliburton explains its views and investment approach on developing, releasing and collaborating on new unconventional oil and gas production technology.

20 Finding the Next Big Shale Play EXPLORATION & PRODUCTION


BY PATRICK C. MILLER Analysts, geologists and researchers explain where, when or why the next North American shale play could happen.

CONTRIBUTION Working Effectively with Tribes 24 on Energy Projects

BY TROY EID Energy producers and midstreams need to understand the role and process Native American tribes can play in building or modifying oil or gas pipelines.


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Industry Reps explain the Bakken Interior, BLM working on major changes to energy development



Exciting Times in Shale BY LUKE GEIVER



ON THE COVER: A Halliburton team prepares downhole tooling for an application in the Permian Basin of West Texas. PHOTO: HALLIBURTON



Exciting Times In Shale

Luke Geiver EDITOR North American Shale magazine

When global energy giant Halliburton reached out to our team to learn if we would be interested in speaking with them about some of their work in unconventionals, we were excited, but we also knew there was a challenge ahead.

Editor Luke Geiver Staff Writer Patrick C. Miller Copy Editor Jan Tellmann

PUBLISHING & SALES CEO Joe Bryan President Tom Bryan Vice President of Operations Matthew Spoor

The opportunity to tell a portion of a world-recognized brand’s

Vice President of Content Tim Portz

story—Halliburton is essentially the Nike or Microsoft of the

Marketing & Sales Director John Nelson

oil and gas world—was one we couldn’t pass up. But, we also

Business Development Manager Bob Brown

knew it would be difficult to narrow down their perspectives and product descriptions into a magazine-

Circulation Manager Jessica Tiller

style piece. We knew some serious information condensing lay ahead. So, we narrowed our focus to two

Marketing & Advertising Manager Marla DeFoe

areas: trends Halliburton has encountered or is planning, and the technologies and strategies the company is investing in specifically for shale energy producers. Check out the full story, “Growing the Shale Brand,” on page 14.

ART Art Director Jaci Satterlund

Although there is plenty of exciting or valuable storylines to follow in the major shale plays (Permian, Eagle Ford, Bakken, etc.), we chose to cover some of the other emerging areas that could be the next big thing in unconventional development—depending of course, on a range of factors. Patrick C. Miller spoke with multiple researchers and experts on potential plays in North America that aren’t currently grabbing headlines or drawing investment. The resulting piece offers some exceptional insight and perspective on the topic of emerging plays, and, it does more than that. While we aren’t about to get into oil price predictions or calendar guesses at when a major upcycle will begin, we feel confident in saying there is an excitement brewing in the industry. Companies large and small have developed new and better tech offerings suited for lower priced oil. Operators have found the messaging and strategies necessary to gain funding and investment dollars to maintain a fairly consistent drilling, completion and production schedule. And, as we should know by now, there is always something favorable (like new plays yet to be developed) on the horizon. These are exciting times for shale. They may be a bit of a rollercoaster ride, but that isn’t necessarily a bad thing. After all, don’t people pay good money or give their time to experience the elements of the ride every day of the year?

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@

COPYRIGHT © 2017 by BBI International


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North American Shale magazine will be distributed at the following events:


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Executive Oil Conference November 6-7, 2017 Midland, Texas

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Energy Generation Conference January 23-25, 2018 Bismarck, North Dakota

Issue 6 North American Shale magazine

NAPE Summit

February 5-9, 2018 Houston, Texas Issue 6 North American Shale magazine

North American Shale Conference & Expo

February 12-14, 2018 Oklahoma City, Oklahoma Issue 1, 2018 North American Shale magazine

For a complete list of North American Shale magazine event distributions, please visit pages/advertising




Industry Reps Explain The Bakken The Bakken shale play’s rate of return is currently on par with returns from the Delaware Basin, says Robert Watson, CEO of an exploration and production company active in both plays. Watson delivered a special presentation to hundreds gathered in North Dakota earlier this summer to learn about the current opportunities and challenges of the Bakken and Three Forks plays. The 2017 Bakken Conference & Expo included attendees and exhibitors from across the country. When North Dakota Gov. Doug Burgum asked the crowd to raise their hands if they were from his state, only half revealed they called North Dakota home. The three-day event helped to reveal how the Bakken—and other shale plays—are and will evolve in the months ahead.

DRILLING COSTS Abraxas Petroleum’s CEO Watson says Bakken wells cost $6 million to drill. The cost in the Delaware is higher—at or above $6.3 million. Geology is the reason. Harder rock requires more water during drilling and fracking. FOCUSED VIEW: North Dakota Governor Doug Burgum believes the Bakken will benefit from innovation, not regulation. PHOTO: PATRICK C. MILLER, NORTH AMERICAN SHALE MAGAZINE





Well Targeting Mike Filloon, founder and analyst at Hartstreet LLC, said most Bakken wells are still focused on the core of the play with 8,000 to 12,000 foot laterals. Enhanced completion designs include more than 10 million pounds of proppant. Ceramics are falling out of favor, while slickwater fracks are becoming the norm.

Another Bakken Burgum issued a four-part call to industry during his Refinery

energized opening statements. Oil production in North Dakota should rise to 2 million barrels of oil per day, oil spills should total zero, partnerships with the state’s coal industry to develop a carbon capture storage system capable of enhancing oil recovery needs to take place, and, natural gas production should be enhanced to produce more value-added products. “It looks like a big order, but you guys have done so much in the last 10 years that we know this industry is capable of doing more,” he said. “And, you’re going to have a partner in North Dakota that will be focused on innovation—not regulation—while you’re getting it done.”

At some point in 2018, another Bakkeninfused refinery will be operating. William Prentice, CEO of Meridian Energy—the company working to build a 55,000 barrel-per-day refinery in Billings County, North Dakota—said the crude sourced from the Bakken is a “refiner’s dream,” due to its physical qualities and abundance.

GEOLOGICALLY SPEAKING: Stephanie Gaswirth, senior research geologist with the U.S. Geological Survey, covered assessments of oil resources in the Williston and Permian basins. PHOTO: PATRICK C. MILLER, NORTH AMERICAN SHALE MAGAZINE

Talk On World Oil Prices Daniel Fine, associate director of the New Mexico Center for Energy Policy and longtenured energy expert, explained how Saudi Arabia thinks about production- and price-planning. “The Saudi mind is not the Bakken,” he said.

“The operators here [in the Bakken] go for very short-term results. Their balance sheet is quarter to quarter. Saudi Aramco and the OPEC producers are taught to think in five-year ranges.” According to Fine, the Saudi’s underestimated

the American producers’ capacity to resist and function in a lower-oil price environment. Fine, who predicted correctly the low-oil-price-bottom in 2015, believes there will be little movement with prices in the remainder of the year.

ECONOMICS BY PLAY ($337,270.21) Eagle Ford $1,425,567.75 Eagle Ford Core ($542,828.09) Midland $2,035,664.67 Midland Core $1,071,002.12 Delaware $1,763,825.60 Delaware Core $22,430.80 Bakken $545,136.13 Bakken Core



OIL PRODUCERS AND ENVIRONMENTALISTS During a three-person panel on the lessons learned by industry following the Dakota Access Pipeline protests, each panelist shared a similar sentiment to that of Troy Eid, attorney and Native American law specialist with Greenberg Trauig law FIRST-HAND EXPERIENCE: Brent Sanford, former mayor of Watford City, N.D., helped lead the Bakken region through its growth. Now, Sanford is the lieutenant governor for the state. PHOTO: PATRICK C. MILLER, NORTH AMERICAN SHALE MAGAZINE

BETTER DAYS STILL AHEAD? Cindy Sanford, customer service office manager for the Williston Job Service office, told attendees her team is still amid a growing community. While Willis-

ton and other Bakken-central towns are not as busy as they were when drilling operations were running to hold acreage, Sanford says oil and gas activity is strong again.

Infrastructure improvements to the region have helped retain workers and better living conditions are attracting more long-term residents.

EQUAL OPPORTUNITY ACROSS SHALE PLAYS Diverters Plus, an exhibiting entity at the event, was mentioned multiple times by multiple entities speaking on new approaches to production in the Bakken and other

plays. The company manufactures one of the hottest products in shale right now: diverters. According to multiple speakers at the event, diverter materials that help to

isolate fractures during pressure pumping and flowback are one of the best innovations in the industry throughout the Bakken and beyond.


firm in Denver. “We have to think differently about how we get projects built,” he said. “I don’t think DAPL was a one-time adventure. I think that’s probably the world that we live in and that the world is changing.”


CONTINUOUS OPERATIONS: Industry participants benefit from the Methane Detectors Challenge by learning which technologies can optimally provide continuous methane monitoring and potentially eliminate the need for scheduled monitoring operations that include thermal image capture. PHOTO: SHELL

Shell adds Canadian shale assets to methane detection challenge Shell is the latest major energy producer to join the Methane Detectors Challenge. The multi-stakeholder initiative run by the Environmental Defense Fund is now helping Shell to track and monitor possible methane emissions at Canadian shale gas wells. Shell already has voluntary leak detection and repair programs at all of its shale operations, but with the help of technology provider Quanta3, the energy giant will now be

able to continuously monitor emissions without the need for the random use of optical gas imaging cameras. Quanta3, a Colorado-based company, has developed a laser-based sensor that monitors infrastructure 24/7 through a connection to the cloud. A solar array powers to sensors and accompanying hardware. According to the EDF, a new generation of technology could be proven in Canada. Pacific Gas and Electric

Co. has also participated in the challenge. In Northern California, PG&E has installed a laser-based system at a natural gas storage facility. Statoil, another participant in the challenge, is already installing solar-powered methane detection systems at its shale sites. “The U.S. oil and gas industry loses about $2 billion of natural gas a year from leaks at dispersed sites, much of them undetected for months due

to lack of continuous monitoring,” said Aileen Nowlan, manager of the Methane Detectors Challenge. “By building bridges between innovators and customers that need scalable solutions, EDF is accelerating technologies that can help the oil and gas industry improve operations and forging solutions that build safer communities and let the planet thrive.”



Interior, BLM working on major changes to energy development The 2015 U.S. Bureau of Land Management rule on hydraulic fracturing—currently caught up in litigation—may never be implemented. The BLM has announced plans to rescind the rule. The public has until September 25 to comment on the rule. “Our proposal to rescind the 2015 final rule responds to the president’s call to reduce regulatory burdens, foster job growth and serve the energy needs of America’s families, small businesses and manufacturers,” said Katharine MacGregor, acting assistant secretary for land and minerals management at BLM. 12

Ryan Zinke, Interior secretary, ordered the review and removal of the BLM’s fracking rule for two main reasons, according to the BLM. All 32 states with federal oil and gas leases currently have regulations to address hydraulic fracturing, and, since the 2015 final rule was published, more oil and gas production companies are using databases, such as FracFocus, to disclose the chemical content of hydraulic fracturing fluids. The disclosure of the materials used in the fracking process had been an argument for the federal government to implement regulations on federal lands.


The review and potential removal of its hydraulic fracturing regulations isn’t the only action the BLM and Department of Interior has taken on oil and gas this summer. Zinke has also signed an order to streamline the process for obtaining federal oil and gas leasing permits. Although a statute exists requiring the Interior Department and BLM to review and process drilling permit applications within 30 days, the average time was 257 days in 2016. The goal of Zinke’s order is to improve the Federal Onshore Oil and Gas Leasing Program and the Federal Solid

Mineral Leasing Program—major sources of income for the federal government. DOI has also renewed its commitment to holding federal lease sales, a move welcomed by several oil-producing states, including North Dakota. Congressman Kevin Cramer, R-N.D., said, “Considering the Interior has held more federal lease sales in the first six months than the Obama administration did all of last year, it’s clear the Trump administration and Secretary Zinke are making American energy a priority.”


From 2014 to 2016 From 2012 to 2016 From 2014 to 2021




Oil Price

Rig Count

Drilling Days







Water Use

Sand Usage


Well IP




Permian IP Increase

Shale Oil Drilling &

U.S. Shale Oil





US shale production could reach 9 million barrels by 2025 By 2025, North American shale producers could be pumping 9 million barrels of oil per day, according to a production estimate report compiled by data analytics firm McKinsey Energy Insights. If oil trades at $60 to $70/b from 2019 on, MEI believes shale well drilling and completion activity will grow by 20 percent. The report states that operational enhance-

ments that have been realized in shale from 2014 to 2016 will soon make drilling profitable beyond the most resource-rich shale basins. Operational improvements include increased drilling efficiency, better completion designs and asset high-grading. The report also highlights some of the major changes in the shale patch that have occurred since 2012.



FLOWBACK DIAGNOSTICS: In the Permian Basin, Halliburton has rolled out a service to help operators tweak flowback chokes and initial production rates to maximize long-term production capabilities. PHOTO: HALLIBURTON



GROWING THE SHALE BRAND Halliburton explains its focus on shale, new technologies and reasons for excitement

By Luke Geiver Stephen Ingram does not manage the design or manufacturing of high-end luxury vehicles or popular basketball sneakers, but he does play an integral part in furthering the success of a global brand. As Vice President of Technology Solutions in Halliburton's North America Operations, Ingram has been a key figure in Halliburton’s work to expand and better understand the unconventional oil and gas industry. Like so many of the world’s leading brands, Ingram and his team have an incredible opportunity—and challenge—to shape the way the industry they serve evolves. North American Shale magazine went behind the scenes with Halliburton, Ingram and others to explain the trends and priorities that one of the biggest names in unconventional oil and gas development has invested in.

Trends In Shale For the past 15 years, Ingram has been with Halliburton’s U.S. operations. During that time, he’s seen how individual basins have developed. While commodity prices and moods or pace of development have been in flux, Ingram says the one constant that has driven the shale energy industry forward is its desire to repeat a process over and again: design

or find new technology, implement that tech into the field and repeat. The everpresent and engrained thought process of shale players to innovate has helped Ingram and his team claim several major industry firsts or accomplishments through new product deployments or unique field operation strategies. The industry’s thirst for the new has also placed a real-time understanding of every basin at a premium for Ingram and his team, who value basin-specific knowledge. As each major basin has changed, Ingram says it is clear that one trend has remained constant from Pennsylvania to Texas: longer laterals are the goal. “Technology continues to develop,” he says. “Extending laterals helps drive higher and higher returns on capital employed for the oil or gas operator.” Pushing the toe of the horizontal further away from the heel is feasible depending on the maturity of a basin in many cases. In the newer plays like the Delaware or SCOOP/STACK, Ingram believes there is more running room for extended laterals. Operators in mature basins are now more set on their development plans and have already established leaseholds, however. Extending laterals in established plays can also require an alteration of surface infrastructure. In addition to the desire for



THE SAND EQUATION: To reduce demurrage fees and other sand-related costs, Halliburton has invested in a new delivery strategy that is saving its customers major downtime and money. PHOTO: HALLIBURTON

ger laterals, operators are now designing and planning surface strategies through a lens of efficiency. If they see an option to increase efficiency or decrease field-costs, they will plan for it before purchasing and designing a system, Ingram says. Although some areas still feature individual wells on single well pads necessitated by HBP drilling, the majority of operators are looking at multi-well pads. “What we absolutely see in the future is higher and higher well counts per pad to take on the efficiencies and economies of scale,” Ingram says. On the high-end, well pads in the future will house 20 to 25 wells per pad. Well pad operations, including pressure pumping, looks strong to service providers, he adds. “During the downturn, most service providers found themselves to be in an area of excess supply for available demand. We see demand outstripping supply now,” he says. Halliburton is now expanding the typical norms of its field operations to benefit its operator clients and better utilize its equipment. The company looks to work on multi-well

pads and in some instances, run operations 24 hours per day. “That is driving returns that we expect in this marketplace.” For pressure pumping applications, no basin is declining in its use of proppant per well, Ingram says, and the amount of fluid injected per well is also generally increasing across all basins. With the increase of sand and fluid volumes per well, Halliburton has had to deal with increased wear and tear on equipment, a challenge Ingram believes his team will overcome because they’ve already proven how to overcome industry challenges in the past. During the last industry upcycle—roughly 2012 to 2014—there were large inflation costs incurred by service providers. Halliburton was not immune to those, Ingram says. One of the main negative economic issues faced by Halliburton was linked to sand. To move sand from a transload facility into a storage container that could then be trucked to a well site, a pneumatic blower had to push the sand into the container in roughly 20 minutes.

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In many cases, pneumatic trucks and delivery trucks were left waiting at the transload facility due to an efficient and time-consuming process that was hindered by the timing on incoming sand loads and the distance of well sites from the transload site. According to Ingram, trucking providers contracted to move sand would charge Halliburton demurrage costs for non-productive time. “It was a massive cost that the industry bore the burden of,” he says. To limit the company’s exposure to demurrage charges, Halliburton teamed up with U.S. Silica—the nation’s largest provider of frack sand—and Sandbox on a containerized sand solution that can bypass the waiting and streamline the sand movement, storage and utilization. The new approach to sand logistics has saved Halliburton and the industry significantly, he says. The story of Halliburton’s sand supply problem-solving abilities is a bridge Ingram uses to explain how the company is continually trying to innovate. Because the

company is so infused into the day-to-day and fiscally sensitive operations of the industry, the company has the opportunity to gauge what the industry will benefit from— or need—next. The increase in sand volumes ushered in a new regulatory requirement that Halliburton and others had to consider. “One of the new costs that has come to the industry in the past year has been around dust capture,” he says. The U.S. EPA has imposed a regulation requiring a fully engineered solution for capturing dust related to frack sand. Because the company was dealing with such high levels of sand around the country, it knew of the issue and has already designed a solution into its containerized sand solution. The EPA’s requirement for the solution to dust won’t actually be imposed for another four years when the grace period of the regulation expires. Halliburton isn’t the only shale entity that sees the value in placing an extreme importance on knowing the trends and needed

LONG-TERM VIEW: Halliburton’s operator clients have shifted interest and investment into fi guring out why production enhancements are working and how to mitigate production declines. PHOTO: HALLIBURTON

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changes in the field. Despite a period in the industry when few dollars were being spent by operators to understand why wells were or are producing better than previous versions, Ingram says today there has been an emergence in investment towards diagnostics. “They [operators] want to know what has changed and why.”

Answers On Advancements Neha Sahdev is a Halliburton expert working with the Production Enhancement group. Sahdev is excited for the fruit of his team’s labors on Integrated Sensor Diagnostics (ISD). The team has developed a suite of services that help operators understand well fracture placement, bypassed reserves and the optimal method for completing and optimizing field development. “What we are trying to do is to accelerate the learning curve that an operator might have in their basin,” Sahdev says. Acceleration involves the implementa-

tion of sensors—including fiber-optic material—that can be placed downhole. According to Ingram, Halliburton has invested heavily in developing, deploying and driving down the cost of field ISDs. Although operators were installing random and one-off ISD systems that mainly consisted of fiber optics temporarily deployed by wireline units in a field, the trend now is that many are looking to install fiber optics permanently across wider areas. In the next three to five years, Ingram believes every well pad will have at least one well with permanent fiber optics. “There is an entire level of fracture design optimization that can occur because of that,” he says. In 2012, the price for permanent fiber optic material installed was roughly $1 million. Today, the price is closer to—and needs to be—$100,000, Ingram says. Fiber optics can explain production in a lateral for every three feet. The fiber cable is installed on the outside of a casing string and

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stays for the life of the well giving 24/7 monitoring capabilities to the surface. “I think the industry, even with the volatile times, has come to understand that the drill bit way of optimizing is not the most efficient way,” Sahdev. In fact, Sahdev’s team is now working with multiple operators that are asking Halliburton to deploy every ISD tool they have in an effort to better understand early production parameters and how they will impact long-term well productivity depletion rates. Sahdev doesn’t like to deploy the entire toolbox at first, however, opting first to understand the parameters or fiscally critical optimization challenges the operator is looking to understand. Through a one-off, custom consulting process, his team will create a solution that helps clients find what they are looking for. In most cases, the Halliburton team asks the operator to rank which elements of optimization are most important. “Let’s say an operator is going with an infill development plan. It is important to understand what happens when a new well bore is placed on an existing pad,” he says. In the past a number of operators have been able to utilize the ISD approach. The high reliability on deployment due to design improvements, high fidelity data and new analyses techniques paired with reductions in cost of deploying these systems, has also played a large part in the fiber optics uptick. Daryl Tompkins, a reservoir evaluations technical advisor for Halliburton, is also heavily involved in helping operators better understand the long-term nature or possibilities of their unconventional wells. Tompkins has helped lead the integration of diagnostics into the well flow-back process. In 2014, the team began the integration process and is now helping clients in the Permian understand the plausible outcomes that will occur when various flowback strategies are deployed. “Everyone flows back their well, but not everybody utilizes the data collected on it,” he says. After following the well flowback strategies of operators and collecting what data he could, Tompkins learned that there was very little science applied to that part of


bilities. “You may get a the well’s life. “At the high IP but you will lose critical moment of the production out of that well’s life, operators were well,” Tompkins says. just turning it over to a By utilizing a colthird-party flowback laborative workflow becompany with little or tween our reservoir enno consideration for gineering team and the the well's performance,” well testing field personhe says. Many problems nel, Tompkins was able stem from such a pracMANAGING EXPECTATIONS: to assess data during tice, he adds. The metric Stephen Ingram, completions and production division flowback to determine for the success of a well director for Halliburton, has helped match the company’s how certain flowback was measured by how current and existing tech with a and choke strategies high the initial producchanging operator mindset. PHOTO: HALLIBURTON were impacting a well’s tion period volume was. long-term production. “When we started lookThe data can also be ing at a couple of years’ used to inform future worth of data on wells completion decisions on achieving high IPs, we multi-well pads. could see operators try“When I go to meet ing to achieve high IP's with customers, they will had steep decline rates,” say that they've heard Tompkins says. other operators are ripThe issue with open- Stephen Ingram, Director of the Completions ping wells wide open ing wells on aggressive and Production Division, Halliburton and getting great results. choke schedules early on Rumors spread throughto achieve a high IP was out the industry and that the high initial flow rates caused an excessive amount of sand to people only hear half the story. What operabe washed out of the fractures. The loss of tors need to do,” Tompkins says, “is gather sand reduces near wellbore conductivity and the right data to evaluate their own wells.” Ingram knows that operators and serlimits the well's long-term production capa-

‘We want to drive an environment where at any price of oil or gas, we have a robust industry.’

vice companies have always altered which entity leads and which one follows. The ability and responsibility to both listen or lead the industry puts pressure on Halliburton, he also says, but despite the challenges of a commodity-linked industry, the company has always responded. “We want to drive an environment where at any price of oil or gas, we have a robust industry,” he says. “In the unconventional industry, there is no shortage of amazing people or companies that are constantly coming up with new technologies, innovations or improvements.” In addition to pushing the shale space towards better diagnostics, Halliburton has also continued its investment in shale by remaining active with TAP—its technology acquisition process. “Even though we are unique in having such a large footprint, we are not arrogant to think that all great technology comes from Halliburton labs,” Ingram says. For the unconventional space—which for Halliburton has become a major point of focus whether it is in North Dakota or New Mexico—the future from the global shale brand’s perspective is clear, according to Ingram. “We are excited about what we are doing.” Author: Luke Geiver Editor, North American Shale magazine 701-738-4944

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SHALE PLAY Can the U.S. capitalize on its experience to keep the shale revolution going? The answer depends on three factors

By Patrick C. Miller The global transformation of energy supplies brought about by the success of oil and gas from U.S. shale plays such as the Permian, the Bakken, the Eagle Ford, the Marcellus and the Niobrara is well known. But are there other shale plays in the U.S. that could provide additional reserves and future energy stability? In early August, BP announced a significant new source of natural gas from the Mancos Shale play in New Mexico’s San Juan Basin. A highly productive well was brought online that achieved an average 30-day initial production rate of 12.9 million cubic feet per

day, the highest in the past 14 years within the basin. “This result supports our strategic view that significant resource potential exists in the San Juan Basin, and gives us confidence to pursue additional development of the Mancos Shale, which we believe could become one of the leading shale plays in the U.S.,” said Dave Lawler, CEO of BP’s U.S. Lower 48 onshore business. Not everyone was surprised by BP’s results. The Mancos was among the emerging U.S. shale plays studied under the unconventional resources program of the Research Partnership to Secure Energy for America (PRSEA)—an organization headquartered in Houston that supports oil and gas development. “These projects were basically looking at what you can do to add reserves,” says Tom Williams, RPSEA president. “There’s a lot more than just the rock that’s going to make


‘It’s the companies, it’s the commercial conditions and then it’s the quality of the rock. When we look at a shale play to understand if it’s got legs underneath it for large commercial development, those are the three most important factors.’ - Robert Clarke, Lower 48 upstream research director for Wood Mackenzie


SHALE'S NEXT HOT SPOT: The Mancos, Mississippi Lime or a handful of other plays in the U.S. could be developed next, according to researchers, analysts and experts. PHOTO: USGS

emerging shales work. We’ve been putting together a project and proposal team to really look at all the factors. It could be economics, infrastructure, regulations—all kinds of variables.” In addition to the Mancos, the other shale plays studied by RPSEA include the Rogersville in Kentucky and West Virginia; the Black Warrior in western Alabama and northern Mississippi; the Tuscaloosa Marine in Louisiana and Alabama; the New Albany in Illinois, Indiana and Kentucky; and parts of the Eastern Great Basin in Utah and Colorado. All of RPSEA’s studies and reports are publicly available on the organization’s website at Robert Clarke, Lower 48 upstream research director for Wood Mackenzie, has spent years studying exploratory shales for the Houston-based analytics firm. The Mancos Shale Play has been on Wood Mackenzie’s radar as one to watch. Clarke says that unlike many companies

strapped for exploration capital in the low-oil price environment, BP is different because of its acreage position in the Mancos Shale and its focus on trying different well completion techniques there. “Out of the gate, BP is ripping and roaring,” Clarke notes. “They’re off to a great start, but we’ll have to give it six to 18 months to have a firm external panelist opinion on how the Mancos will unfold.”

Three Key Factors What are the key factors to consider in evaluating a shale play? “You’ve got to have the geology before anything else,” Williams says. “If you have the geology, what other factors could either allow you to make the play commercial or what could you do to impact those?” Clarke lists three primary factors Wood Mackenzie considers in determining a shale play’s potential.

“It’s the companies, it’s the commercial conditions and then it’s the quality of the rock,” he says. “When we look at a shale play to understand if it’s got legs underneath it for large commercial development, those are the three most important factors.” The competency and experience of the companies exploring the play are key considerations. “If it’s a Chesapeake or a Devon or an EOG all in the same basin—all drilling exploratory wells and sharing data to some degree— that’s a much more positive sign than if it’s just three or four micro-cap companies trying to drill on the fly,” Clarke explains. For successful commercial operations, he says a basin with an existing supply chain, available infrastructure, good inter-basin differentials and favorable fiscal terms—such as royalty rates and taxes—all work to keep costs manageable. Finally, access to core samples and empirical geological data on pressure



gradients, minerology and hydrocarbons are key to determining the quality of the rock, according to Clarke. The Powder River Basin in Wyoming and Colorado is one shale play in the U.S. that he says comes the closest to meeting these criteria. “There are some areas of the Powder River Basin that are oilier that we think can break even around $40 a barrel,” he relates. “People got excited about the Powder River Basin about a year ago when it got branded as a Permian lookalike in the sense that you have six or seven intervals that are stacked in the strat column. When you model it in three dimensions, you can see the depth.”

Targets of Opportunity Vello Kuuskraa, president of Advanced Resources International Inc. in Arlington, Virginia, examined emerging U.S. shale plays in his presentation at the 2017 Unconventional Resource Technology Conference. He listed the Mowry Shale of the Powder River Basin

and the Mancos Shale in the San Juan Basin as two of the most promising plays. “In my view, the great bulk of new shale reserve and resource additions for the next decade will come from searching for additional production horizons in existing basins, pushing the technology envelope and turning from vertical to horizontal drilling.” Kuuskraa lists the Alpine High—a liquids-rich, wet gas play—in the southwestern Delaware Basin as one of the most recent, high-visibility exploration successes. Others shale plays showing potential are: the Moorefield in the Arkoma Basin of Oklahoma and Arkansas; the Cotton Valley in western Louisiana and eastern Texas; the Spraberry tight oil formation in the Midland Basin of Texas; the Haynesville in Texas and Louisiana; and the Meramec and the Cana-Woodford in Oklahoma’s Anadarko Basin. The Rogersville Shale Play that stretches from eastern Kentucky into West Virginia provides an example of a formation with potential, but lacks the three key factors of

strong E&P company support, sound commercial conditions and reliable data on the resource. Williams says Kentucky is eager to develop the Rogersville to replace lost coal mining jobs.

Data-Driven Decisions David Harris with the Kentucky Geological Survey and head of the energy and minerals section at the University of Kentucky explains why the Rogersville Shale— despite showing promise—has yet to thrive. What’s known as the Rome Trough of the Rogersville was the subject of a 2002 scientific study based on a single core drilled by Exxon in the 1970s. “We knew we had a likely source rock that was mature and that had generated hydrocarbons,” Harris says. “We determined that we had a new petroleum system in the deeper part of the section sourced by the Rogersville Shale.” When the shale boom took off in 2009, some E&P companies looked at the earlier


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study and considered the Rogersville a potential unconventional play. Although a number of wells have been drilled in Kentucky and West Virginia, the cores and much of the data from them remains confidential. “The take-home point is that there’s really not much hard information on this play that’s been released yet,” Harris notes. “It will be released through the state regulatory agency five years from whenever it was completed for the stratigraphic test permit.” Most of the wells drilled in the Rogersville are depleted or have been shut in, according to Harris. The one well for which production data is available shows a steep decline rate for gas and no natural gas liquids produced. Harris says the Rogersville is a technical success because E&Ps have recovered hydrocarbons from the play. However, between the lack of solid data and low oil prices, he doesn’t foresee substantial development in the near future. “We’re still sort of hoping that it works

out and is successful,” he says, “But right now, it’s too early to say for sure.” Williams points out that well-production data with disappointing results doesn’t necessarily mean a shale play lacks potential. “For example, some of the wells drilled in the Tuscaloosa Marine Shale showed low recovery rates,” he notes. “We know that the wells they drilled and produced didn’t have a good completion strategy. What can you do to increase the recovery? Maybe it’s a different sand volume or frack volume or spacing or orientation—all those variables. It’s like trying to solve a puzzle.” State policies are another factor impacting shale play development. “You can’t even get a permit in the Illinois Basin to do hydraulic fracturing,” Williams says. “On the New York side of the Marcellus, they’re trying to keep people from doing fracking. It doesn’t matter how good the rock is in those two states if you can’t get a permit.” Clarke says there’s much to be learned

from the experience of developing successful shale plays. “The simple way to say it is that you get really good at drilling wells in a basin by drilling wells in a basin,” he explains. “I don’t think anything trumps field learning in an unconventional play. If it’s a play with fantastic rock, but there’s only one company there drilling one or two wells a year with no one else to share data with, it’s going to go at a snail’s pace compared to other plays.” Clarke concludes that for an emerging shale play to be successful, it takes “lots of rigs, lots of companies, lots of consortia, lots of knowledge and lots of information that flows to the service companies” to overcome the steep learning curve that accompanies the development of unconventional oil and gas. Author: Patrick C. Miller Staff Writer, North American Shale magazine 701-738-4923

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‘Supporting tribal consultation is an effective way for the energy industry to manage business risk in post-DAPL America.’ - Troy Eid, Attorney, Mediator with Greenberg Traurig LLP, Co-chair of the firm’s American Indian Law Practice

PANEL TALK: During the 2017 Bakken Conference & Expo, Troy Eid delivered a presentation on the lessons learned from the DAPL pipeline controversy. PHOTO: NORTH AMERICAN SHALE MAGAZINE

WORKING EFFECTIVELY WITH TRIBES ON ENERGY PROJECTS By Troy Eid Pipelines and Native America The United States depends on 2.4 million miles of pipeline systems to transport fossil fuels across the country, but none has triggered more attention than the Dakota Access Pipeline (DAPL). This $3.8 billion, 1,172-mile crude-oil pipeline, owned and operated by Houston-based Energy Transfer Partners, L.P., entered service last June after months of construction delays— in part, due to concerns from Native American tribes—and now moves nearly half the total daily oil production in North Dakota. Litigation, politicking and protests delayed the project’s completion. By December 2016, delays were costing DAPL’s investors $83.3 million per month and totaled $450 million. Post-DAPL, tribes are scrutinizing projects even more closely, including new pipelines as well as right-of-way renewals for existing systems.

to “make their own laws and be ruled by them.” The term “tribal consultation” means the federal government’s legal responsibility to consult with tribes on a government-to-government basis whenever energy projects need federal approval both on and off Indian reservation lands. President Barack Obama expanded the executive branch’s consultation policies to give tribes more say in decision-making, establishing detailed consultation requirements at both the cabinet and sub-cabinet department level. President Trump has not yet issued any policies on tribal consultation, but those on the books remain. As federal agencies have adopted more sweeping consultation guidelines, tribes are seeking to enforce them in the federal courts. This gives tribes more leverage to influence energy infrastructure projects.

Federal Consultation Policies Give Tribes More Leverage

Supporting Tribal Consultation as a Risk-Management Strategy for the Energy Industry

Indian tribes—the third sovereign recognized in the U.S. Constitution, along with states and the federal government—are protected as “domestic dependent nations,” in the words of the U.S. Supreme Court, with the inherent power

Supporting the consultation process between federal and tribal officials (or states and tribes, as the case may be) has distinct practical advantages for the energy industry. The more informed tribal officials’ understanding of a

proposed project, the more effectively they can consider and comment on that project as federal law requires. Regardless whether tribes support or oppose a project, it is imperative that their concerns be actually considered by decisionmakers and documented for potential review by the courts. As a former senior federal and state official who has participated in many tribal consultations, I know how critical it is for energy companies to support tribal consultation. Companies can strengthen the process by understanding agencies’ consultation policies. Most officials conscientiously approach their duties to tribes, but unfortunately some do not. Companies should monitor the process and encourage individualized interaction with tribal officials—not group informational meetings, mass-mailings or unfocused “outreach.” Under federal law, consultation must be “meaningful” to stand up in court. If officials just go through the motions and don’t actually consider tribes’ views in decision-making, a project can be delayed or worse. Some project proponents—an interstate pipeline company and a public utility, to give just two recent examples—also support the process by providing financial and in-kind support so

CONTRIBUTION: The claims and statements made in this article belong exclusively to the author(s) and do not necessarily reflect the views of North American Shale magazine or its advertisers. All questions pertaining to this article should be directed to the author(s). 24 NORTH AMERICAN SHALE MAGAZINE ISSUE 4 2017


lands of various tribes. The late David Lester, executive director of the Council of Energy Resource Tribes, a non-profit tribal advocacy organization, assisted Ruby’s owner, El Paso Corp. (since acquired by Kinder Morgan), in strengthening tribes’ ability to participate more effectively in tribal consultation. Prior EFFECTIVE EXPERIENCE: to construction, Ruby entered As the Co-chair of Greenberg into funding agreements that Traurig LLP American Indian Law Practice, Troy Eid has been tribes used to retain their own leinvolved with several high-profile gal and ethnographic experts to Native American and energy industry-related matters. document cultural resources for PHOTO: GREENBERG TRAURIG LLP Best Practice: El Paso federal consultation purposes. The tribes also worked with Corporation’s Ruby Ruby to create a tribal monitoring program, paid Pipeline An example of the energy industry’s effec- for by the company, which trained more than tive support of tribal consultation is the Ruby 100 tribal members to assist archaeological teams Pipeline Project—a 700-mile interstate pipeline prior to, during and after construction. At tribes’ that delivers natural gas produced in the Rockies request, the Ruby pipeline was rerouted—includBasin to the West Coast. As with DAPL, Ruby ing more than 900 “micro-reroutes” to avoid does not cross any Indian reservation lands but culturally important sites—at a total cost of appasses through former treaty and aboriginal proximately $11 million. Traditional plants were tribes can retain their own attorneys, engineers and other experts to evaluate projects. Such arrangements may take the form of confidential mitigation agreements between companies and tribes to supplement government-to-government programmatic agreements among federal, state and tribal officials. Funding agreements can benefit tribes and companies if structured and monitored to avoid any actual or perceived conflicts of interests.

harvested for seeds and preserved in greenhouses prior to ground-disturbing activity and replanted post-construction in the reclaimed right-of-way. Ruby also worked with tribes to develop a tribal employment program. Because skilled pipeline construction jobs typically require union membership, Ruby supported tribes’ requests to pay union dues and apprenticeships for tribal members seeking work on the project. A later internal review by the company found that such reroutes and tribal capacity-building measures saved the company at least $250 million in avoided project delay costs from potential tribal litigation and protests. Wherever and whenever it happens, managing the next Standing Rock controversy—better yet, mitigating or avoiding it—should be on every energy developer’s agenda. Supporting tribal consultation is an effective way for the energy industry to manage business risk in postDAPL America. Author: Troy Eid Attorney, Mediator with Greenberg Traurig LLP, Co-chair of the firm’s American Indian Law Practice



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Issue 4 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 4 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.