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ISSUE 3 2017

Issues With Frack Sand How these firms overcame supply, increased volume requirements Page 20

Plus Special Study: The Impact Of Shale Development On Texas Page 14

And Understanding The Digital Oilfield Concept Page 26

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A PREMIER NORTH DAKOTA SHALE OIL EVENT Focused on Bakken Play Technologies and Efficiencies



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ISSUE 3 2017





Studies In Texas Shale

BY LUKE GEIVER A two-year, first-of its-kind assessment on the impact of shale energy development in Texas provides insight on water, land, air, transportation, community and seismicity issues.

20 A Mammoth Frack Sand Expansion EXPLORATION & PRODUCTION


BY PATRICK C. MILLER With the increasing demand and volume requirements for frack sand, Mammoth Energy shows why and how energy service providers are dealing with the current frack sand market’s challenges.


24 Economies Of Shale

EXPLORATION & PRODUCTION BY MARK HILL The new shale era that upstream oil and gas producers are entering is centered on a digital oilfield design featuring data crucial to low-oil environment operations.


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Shale play activity continues upward trend Shale oil export operations expanding along Gulf Coast EQT’s $6.7B purchase shows benefit of longer laterals



What is the Issue? BY LUKE GEIVER

ON THE COVER: Mammoth Energy acquired a Wisconsin frack sand mine earlier this year to ensure supply to clients in Oklahoma and Texas. PHOTO: MAMMOTH ENERGY







Petro Waste Environmental Shows How To Transition Between Basins Reserve Base Lending’s Past— and Future—In Shale Production



What is the issue? Many issues were present in the unconventional oil and gas development industry when 2017 opened. Frack sand was in heavy demand but short in supply. A second OPEC decision on production curtailments was looming. Global oil stockpiles—depending on the week—

Luke Geiver EDITOR North American Shale magazine

VOLUME 1 ISSUE 3 EDITORIAL Editor Luke Geiver Staff Writer Patrick C. Miller Copy Editor Jan Tellmann


were either trending down or at a stalemate. Drilling rig and

Chairman Mike Bryan

completion companies were signing contracts but scrambling

CEO Joe Bryan

to sign staff. Now, halfway through 2017, the storylines linked to those issues have mostly been resolved without a drastic impact on shale. Production is rising, drilling rig counts have

President Tom Bryan Vice President of Operations Matthew Spoor

risen for at least 21 straight weeks, drilled but uncompleted

Vice President of Content Tim Portz

wells do not garner the same buzz they did a year ago and,

Marketing & Sales Director John Nelson

global stockpiles are still seesawing depending on the report you read to describe their current state. Today, with some issues still lingering and new issues starting to emerge, one could argue the real question is this: Is there an issue that the shale industry simply won’t be able to overcome? Based on our work in this month’s magazine, our team would lean towards responding, “no.” As Patrick C. Miller, the always detailed staff writer and photographer for North American Shale magazine, highlighted in his piece on frack sand, the shale industry does well at finding solutions to issues. Miller spoke in-depth with Mammoth Energy Services, an Oklahoma City-based energy services company that has made many moves this year regarding frack sand. As you’ll read in Miller’s piece, “A Mammoth Frack Sand Expansion,” any notion that a frack sand shortage could become a major issue in shale development this year was dismantled by Mammoth. Of course, this issue of frack sand supply did impact some in the industry and pushed certain groups to build more capacity, but as Mammoth’s example shows, great shale firms will find a way to overcome the issue of the day. In Texas, the issue of shale—specifically the impact of production efforts on the environment and communities—was the focus of a year-plus research effort led by the state’s premier research organization. We spoke with the shale task force responsible for putting together a 204-page report on the impacts of shale energy development on Texas and broke down or highlighted the major findings from the unique report. Check out the story, “Studies in Texas Shale,” on page 14 to learn what the team of subject-matter experts had to say about shale in relation to the state’s water, land, environment, transportation sector, geology and communities. And, to demonstrate that our team isn’t always lured into the sexy stories on the latest in drilling or completion trends, we profiled the rise—and transition—of a special oilfield waste company. The story pro-

Business Development Manager Bob Brown Circulation Manager Jessica Tiller Marketing & Advertising Manager Marla DeFoe

ART Art Director Jaci Satterlund

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

vides a glimpse at what it means to be nimble in the shale world and how many entities have embraced a multi-basin focus that could spread their operations from North Dakota to New Mexico.

COPYRIGHT © 2017 by BBI International


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NORTH AMERICAN SHALE NEWS H20 Midstream was selected as the midstream operator of choice to purchase, operate and grow produced water infrastructure for Encana Oil & Gas Inc. Through the deal between the Houston-based midstream firm and the E&P, H20 expects to have 140,000 barrels per day of disposal capacity, 2 million barrels of water storage and 200 miles of gathering pipeline to serve Encana and future clients in the Permian.

Occidental Petroleum has further committed to future Texas and New Mexico oil opportunities. For $600 million, Oxy has acquired the enhanced oil recovery assets previously owned and operated in part by Hess Corp. The largest of all Permian producers said the CO2 EOR assets and fields it will now have operatorship of will be its largest EOR unit.


Keane Group Inc. has agreed to acquire RockPile Energy Services LLC—giving the energy service company 1.2 million in total hydraulic fracturing horsepower assets. For roughly $285 million, Keane said it will now have access to Bakken customers through RockPile’s existing client base in the Williston Basin. In January, Keane paid roughly $250 million for the U.S. assets of Trican Well Services.



PERMIAN Less than one year after exiting the Midland Basin through an asset sale to Concho Resources, Peregrine Petroleum Partners Ltd., is back in the Texas shale fields. The E&P will now focus on developing assets in the southern Permian.

SCOOP/STACK Permian / Delaware Basin

PERMIAN Howard Midstream Energy Partners has signed a jointventure agreement with WPX Energy that will give the Howard team a major shipper—and partner—on multiple crude or gas gathering and processing assets in New Mexico. The producer-backed midstream With it’s first move into shale, entity will also finish Chisholm Energy Holdings constructing a 50-mile LLC is using a $500 million gathering system started by line of equity from Warburg WPX. Pincus to develop its New DELAWARE BASIN Mexico acreage in the Delaware Basin. Mark Whitley, who is leading Chisholm, was previously an adviser for Warburg and worked to amass large acreage blocks in the Barnett and Marcellus for Range Resources.



Eagle Ford MAJOR U.S. SHALE PLAYS *Informa on based on U.S. Energy Informa on Administra on (January 2017), Baker Hughes (January 2017) and Rystad Energy (October 2016)

Wildhorse Resources has become the second largest Eagle Ford-focused producer through the purchase of 111,000 net acres for $625 million from Anadarko Petroleum Corp. The move will help Wildhorse optimize field operations with fewer limitations.


EnLink Midstream Partners LP can now count on ONEOK Inc. to move its natural gas liquids sourced and stored in Oklahoma’s STACK play to the Gulf Coast. ONEOK intends to expand its NGL takeaway capacity by 2018 to move EnLink’s product via existing pipeline to EnLink’s NGL hub—Cajun-Sibon—on the Gulf Coast.



Tesoro Corp., an owner of two Bakken-linked refineries, is rebranding. The San Antonio-based company is changing its name to Andeavor, a custom-created word that signifies the company’s current place amongst refining and logistics entities and its plans to grow in the future.


Noble Energy is moving on from the Marcellus. For $1.2 billion, the company has sold its upstream assets in West Virginia and Pennsylvania. The company will now focus on its Delaware and DJ Basin asset portfolio.

A shale gas production giant has been born. Through the $6.7 billion acquisition of Rice Energy Inc., EQT Corp. will now have 670,000 core net acres in the Marcellus shale gas play, including 3,700 undeveloped locations. Daniel Rice, CEO of Rice Energy, said the combination of the two companies “creates an unparalleled leader in shale gas development.”




U.S. Oil Production & Rig Count U.S. crude oil production Million barrels/day

U.S. oil rig count Active Rigs








1,100 March 9.10


900 May 722



5 3 2013

500 2014





300 2019

NOTES: Dashed line shows the forecast as of 6/6/17. Rig count series shows the last weekly count each month. SOURCES: BAKER HUGHES; ENERGY INFORMATION ADMINISTRATION

The Carlyle Group has agreed to back EOG Resources Oklahoma efforts. Through the company’s Energy Mezzanine Opportunities Group, Carlyle will provide up to $400 million into a mezzanine financing option that could turn from an investment in drilling and production into an ownership or equity stake in the oil and gas assets.


Shale play activity continues upward trend In the midst of an ongoing oil market turmoil, a rush of merger and acquisition activity and the realized benefits of oilfield operational efficiencies, shale play business activity has remained robust from Pennsylvania to New Mexico throughout the first half of the year. Nearly every major sector of

the unconventional oil and gas development industry has been marked by a major deal, announcement or headline in the past few months. While the Permian remains the most active shale play in the U.S., other announcements highlight an active spring for shale that has seen an increase in both production and rig count.



MEET ANNE: At 1,093 feet, the Very Large Crude Carrier Anne could be used to move 2-million barrels of shale oil to Europe or Asia. PHOTO: PORT OF CORPUS CHRISTI

BIG DOCKS GET BIGGER: The SemGroup has purchased oil terminal infrastructure near Houston due in part to expansion efforts planned or already underway there. PHOTO: SEMGROUP

Shale oil export operations expanding along Gulf Coast Momentum is building for U.S. shale oil producers looking to increase exports. At the end of May, a 2-million-barrel Very Large Crude Carrier docked at the Port of Corpus Christi for a testing and verification exercise. The docking exercise was used to ensure the VLCC could successfully be loaded with shale oil produced from the U.S. Occidental Petroleum was behind the exercise. “Permian Basin crude is being exported to Asia, Europre and elsewhere around the world,” said Vicki Hollub, Oxy president. “The arrival of the VLCC at our terminal continues to build on our position as the Permian’s largest oil producer, enabling

us to load the largest ships with our crude and the crude of other producers.” Anne, the ship owned by Belgiumbased Euronav, is 1,093 feet long and can hold more than 2 million barrels of oil. Because the depth at the Port of Corpus Christi is only 47 feet, the VLCC has to dock, be partially loaded, and then moved back to deeper water where a different vessel can finish filling the ship. In 2015, the Port of Corpus Christi was the first used in the U.S. after the decades long export ban on U.S.-produced crude was lifted. The largest export vessel to move shale oil from the U.S. was the Suezmax ship that held 930,000 barrels of crude oil.


Charles Zahn, chairman of the Port of Corpus Christi, said his team has a vision to be the energy port of the Americas. In the next decade, the Port intends to invest $1 billion on upgrades, including the widening out of the main channel from 47 feet to 54 feet. And, the construction of the longest cablestayed bridge in the Western Hemisphere is also underway. The bridge provides increased air draft clearance up to 205 feet. Oklahoma-based SemGroup is also looking to capitalize on push by U.S. producers to export shale oil. The company has entered into an agreement to purchase the Houston Fuel Oil Terminal Co.’s 16.8 million barrel oil storage terminal located on the Houston ship channel. Carlin Conner, CEO of SemGroup, said the $2.1 billion deal gives the company a larger footprint and better position in the shale oil export business. “With the addition of HFOTCO, SemGroup will be uniquely positioned to capture the future trends in exporting crude oil and refined products resulting from the near- and long-term anticipated growth in U.S. shale production,” Conner said. SemGroup already has 7.6 million barrels of oil storage capacity in Cushing and another 8.7 million barrels in the U.K. The Houston terminal has pipeline connectivity to local refining complexes, deep water marine access and inbound pipeline along with rail and truck receipt capabilities from all of the major U.S. basins.


Energy Survey Business Activity Diffusion index 100 80 60 40


Q4 2016

Q1 2017


20 0

40.1 26.7

Q1 2016

Q2 2016

Q3 2016

-20 -40 -60


-80 -100

NOTES: Index is the percentage of firms reporting an increase in activity since the prior quarter minus the percentage reporting a decrease. Positive values reflect expansion in oil and gas activity, negative values reflect contraction and zero reflects no change since last quarter. SOURCE: FEDERAL RESERVE BANK OF DALLAS

Permian, Bakken info experts say optimism is strong The oil and gas markets research team at the Federal Reserve Bank of Dallas has always worked to provide interested parties from Texas, New Mexico and surrounding states with current information on the health of the regional oil and gas markets. Starting this year, Kunal Patel, the oil and gas markets insight leader for FRBD, has helped bring more information more often to the region. Through a series of slide decks, reports and information offerings, Patel and his team provide energy indicators and trends to those wanting basic information—what is a DUC—and those wanting complex insight—which factors are impacting oil prices this week.

Since the start of the year, Patel said one trend has been obvious: Activity in the region of the Permian has increased and it is looking strong for the future. Because Patel and his team conduct a 200-person survey every month, they know what businesses are thinking about hiring, activity levels and breakeven pricing. “Our contacts are increasingly having guarded optimism,” he said. Participants in the FRBD keep providing insider insight to the team for one major reason. “There are a variety of surveys that the Fed uses to understand business conditions,” Patel said. But the energy-based survey is important for the team to use in its monetary decision-making process. “By

being a part of the process [survey] they help to inform monetary policymaking,” he said. In North Dakota, the Department of Mineral Resources often tries to collaborate with industry to stay current on industry trends and potential future issues. Lynn Helms, director of the DMR, also said Bakken-focused operations are optimistic about the current state of shale. “Industry appears confident that the fundamentals are there,” he said of the Bakken’s economics. “Regardless of what you’re seeing short-term on oil prices, fundamentally, inventories are going to come down, OPEC production cuts are going to do their job and we will see stron-

ger prices out into the future,” he said. In fact, some Bakken producers are already proving his point. Accroding to Helms, some producers are now opening their wells “to their full potential,” he said. For the Bakken, the current issue is related to the availability of frack crews. Drilling rigs—now more than 55 operating—are outpacing the frack crews. Because of that, the DUC inventory could start to creep up again until more pressure pumping services are brought into the world-class play.



Oklahoma’s STACK play set for multi year activity increase A new study on Oklahoma’s STACK shale play forecasts a 46 percent increase this year in the number of wells drilled in the formation, a trend expected to continue into 2018. Dan Debelius, an analyst with The Freedonia Group, provided North American Shale with additional information on the study’s findings. What are the breakeven costs in the STACK play? How do they compare to other Oklahoma plays? We believe that in some of the most economical portions of the STACK ANALYST: Dan Debelius is an analyst with The Freedonia STACK that breakeven prices fall Group, author of a recent study that predicted increased activity in near $30 per barrel. This makes the the Oklahoma shale oil play in the STACK one of the most econominext few years. PHOTO: THE FREEDONIA GROUP cal plays in the U.S., behind only certain core areas of the Permian Basin. Contributing to the low breakeven price are the STACK’s geology, which is characterized by multiple stacked layers of resource-bearing rocks, and low transportation costs, in part resulting from its proximity to Cushing, Oklahoma. The STACK seems to be the most promising play in the state. Outside of the STACK, the SCOOP is another promising play with formations like the Woodford and Springer shales. How do breakeven costs in the STACK compare to the Permian in Texas and the Bakken in North Dakota? It would appear that breakeven costs in the Permian Basin are the best in the U.S., given the amount of investment occurring in the past year—over $30 billion dollars in acreage transactions have occurred during that time span. The Bakken would likely fall behind the STACK in terms of favorable breakeven costs, but it is still a high-quality play. 12


When do you see oilfield services companies in Oklahoma beginning to raise prices again? We believe prices have already started to increase as a result of the recent rebound in activity. One concern is a potential shortage of labor as employees who were laid off during the downturn may not return to the industry. Has the export market opening up for U.S. crude created more opportunities for STACK producers? Crude exports have begun to provide an important market for US oil producers, with the EIA reporting exports exceeding 1 million barrels per day for the first time ever in February. Also important is the emergence of liquefied natural gas (LNG) exports, which we expect will support domestic gas prices in the Gulf Coast region and translate to better wellhead prices for producers of associated gas. What completion techniques are preferred by STACK producers? Companies are still experimenting with well spacing, lateral lengths and the optimization of their completion designs. Most seemed to have settled on proppant loading of over 2,000 pounds per foot. Some have cited success with zipper frack designs on multi-well pads. To some extent, this reflects similar advancements in drilling and completion practices that have been seen across the U.S.


ASSET FOCUS: After working to create a massive and contiguous acreage block capable of targeting the Marcellus, EQT will now shift its focus to improving the operations and production of its newly formed asset group, the company said. PHOTO: EQT

EQT’s $6.7B purchase shows benefit of longer laterals

LONGER LATERAL BENEFITS: By gaining access to Rice Energy’s contiguous acres in Pennsylvania, EQT will now be able to increase lateral lengths to 12,000 feet instead of 8,000 feet. The change could yield initial rates of return on the longer lateral wells up to 70 percent or 137 percent depending on the number of wells drilled and completed on the pad. PHOTO: EQT


EQT Corp. was already one of SOURCE: EQT CORPORATION Improving Economics - Marcellus the leading natural gas producers in SW PA laterals extend from 8,000’ to 12,000’ - dramatically increasing returns the U.S. before it agreed to acquire 160% $3.00 the assets of Rice Energy for nearly $2.50 $7 billion. Through its acquisition, 140% $2.00 expected to close by in Q4, EQT 120% will now be the largest natural gas producer in the U.S. A breakdown of 100% the deal shows why EQT will remain 80% busy for years to come and how its rates of returns for new wells should 60% increase because of the transaction. 40% Because Rice’s Pennsylvania acreage is contiguous with EQT’s, 20% the Pittsburgh-based E&P will now 0% be able to drill longer laterals. In the 5 Well Pad 6 Well Pad 8 Well Pad 12 Well Pad 5,500’ Lateral 6,000’ Lateral 8,000’ Lateral 12,000’ Lateral Pennsylvania-counties of Greene and Washington, EQT will be able to acreage, EQT will also increase its ability to transport product to the add Rice’s technical data into its well planning and more importantly, it can drill laterals out to 12,000 feet. Gulf Coast through the acquisition of Rice-controlled infrastructure. And, EQT will become the fourth largest gas gathering infrastrucLonger laterals targeting the Marcellus at $3 NYMEX gas pricing will improve ROR from 52 percent to 70 percent, according to EQT. ture operator in the U.S. In 2018, cash flow per share could increase by 20 percent due For a 12-well pad with laterals reaching 12,000 feet, the IRR can to the deal and in 2019, it could be worth an additional 30 percent, improve to 137 percent. according to the company. In addition to the benefits gained by purchasing contiguous




TEXAS SHALE In a first-of-its-kind report, a group of Texas subjec-matter experts has created a complex, considerate and semi-complete assessment on shale energy development in Texas

By Luke Geiver

LONG-TERM VIEW: Shale plays like the Eagle Ford (pictured here) or the Permian have had both positive and negative impacts on Texas, according to the 204-page report. The general consensus among researchers is that Texas shale development is a major net positive for Texas. PHOTO: STATOIL



For more than a year, Texas-focused subject-matter experts analyzed data sets, reports and publicly available documents to better understand the environmental and communitylinked impacts of shale energy development. During that time, the research team—known as the shale task force—met three times as a whole. At their in-person gatherings, seismic engineers spoke with landfocused law professors, air quality specialists talked with hydrology experts and any issue that may have seemed specialized for one subject group was made important to the whole. The result of all the research and all the meetings is a first-of-its-kind study targeting shale energy development in Texas. The 204-page report, “Environmental and Community Impacts of Shale Development in Texas,” provides a look at Texas shale energy like never before, according to Christine Ehlig-Economides, task force chair (and petroleum engineer) at the University of Houston. Designed to provide a science-based consensus on shale for Texas legislators, elected officials and decision makers at all levels, the task force believes the report is viable outside of the Lone Star state as well.

Shale Task Force Findings Mimicking the National Academies approach to creating research reports and topic-specific assessments, the shale task force team set a goal from its beginning to utilize information and data already available. The strength and importance of their work would not be linked to new research, but rather to the multi expert examination of several areas that impact the way shale has transformed Texas. Researchers focused on six areas: seismicity and geology, water, air quality, land, transportation and community and social impacts. Michael Young, the associate director for environment and a senior research scientist at the Bureau of Economic Geology at the University of Texas who worked on the water focus of the study, says the researchers knew early on in the process their work was going to be unique and beneficial. “We had very candid discussions on how different topics overlapped each other,” he says. “It is not common to have all of these people in the same room in a very open way. It gave us perspective we didn’t have before we started.” The group of researchers learned that their individual focus areas impacted other focus areas and that describing the impact of shale energy development—though overall was a positive for Texas and other states that have it—is complex. To describe the trade-offs in shale energy development, the researchers included a section in the concluding remarks of the report that helps to highlight the complexities they see. “Construction of additional pipeline infrastructure could reduce truck traffic and related road impacts and emissions. At the same time, this could fragment ecosystems and land resources on properties that pipelines traverse,” the researchers wrote. And, in another example of the trade-offs that need to be considered, they said, “shale development often produces better paying jobs and a stronger tax base in a given community, but enhanced industrial activity has negatively affected affordability of housing, air quality, roads, communities and schools.”


Texas Shale Details:

Report Considerations:

In 2015, Texas produced more oil than all but six countries in the world.

Seismicity: Before 2008, Texas recorded 2 earthquakes per year. Since then, there have been 12 to 15 per year.

In 2016, 1.1 billion barrels of oil were produced in Texas. Nearly 250,000 oil and gas wells are operating in Texas. Texas schools received more than $1.7 billion from oil- and gasrelated property taxes in 2016.

Land: 95 percent of Texas lands are privately-owned, making data and study information hard to obtain. Air: For most sources, 5 percent of emitters account for more than 50 percent of emissions. Water: Fracking uses 1 to 5 million gallons on average per well. Fracking accounts for less than 1 percent of water used in Texas. Transportation: Each year, road damage from oil and gas development costs between $1.5 to $2 billion. Community Impacts: Although there are likes and dislikes on shale in Texas, the overall attitude is positive.

In addition to the team’s consensus that shale energy development is a complex issue to explain, the group also shared a view on data. Common among every focus-area research team was the call for more data. Each group said they need better access to current and future data provided by academic, governmental and industrial entities. And, because of the complexities in trying to understand variables in shale development including wastewater injection’s link to earthquakes or the funding appropriation models used from shale-based tax revenue, each research team called for greater inspection on at least one area of focus within their main focus area.

fault line, allowing it to move and create a seismic shift. The added fluid instead places added stress on a fault line. That distinction is crucial to understanding the research team’s recommendations for working on seismicity in Texas. Texas needs to continue to increase its seismic monitoring stations in order to collect more data on when, where and why earthquakes have increased. Currently, the state has 18 stations with plans to reach 43. And, the state needs to continue to require special approval from wastewater injection well developers prior to their drilling in order to ensure they aren’t selecting a site that is near a fault area that could be altered due to added pressure from water volumes injected below surface.

Focus-Area Breakdown Seismicity:


Brian Stump, the lead researcher for the seismicity focus, says that Texas has faults running across the state and that all of them are poorly or incorrectly characterized. Some of those faults can be impacted by oil- and gas-produced wastewater injection. Hydraulic fracturing does not impact the faults—or play a part in seismic activity at earthquake scale in Texas. According to the report, before 2008, Texas recorded roughly two earthquakes per year. After 2008, the state has recorded 12 to 15 events per year, some of which could be related to wastewater injection. There is a misconception about wastewater injections and their role in seismic events, the report noted. Wastewater injection wells do not lubricate a

Melinda Taylor, a senior lecturer at the University of Texas Law School lead the land focus. The main focus area for her team was split into two areas: environmental and surface owner rights. Because Texas has very little public land, public data on environmentally-linked topics was hard to come by. The research team said new data on plant and animal species was needed as a baseline from which to compare shale energy development changes. Because landowners in Texas who do not own the mineral rights have very limited control over oil and gas operations, the research team recommended the state consider adopting more robust surface owner




rights. “With no mineral rights, surface owners have little leverage over producers,” Taylor says. “We are recommending Texas explore a surface owner statute.”

Air: Because air quality related impacts linked to shale oil and gas development can occur over periods that range from hours to decades, the study authors say there is still much to learn. But, the researchers do want people to know about the reality of super emitters. In some cases, 5 percent of emitters account for more than 50 percent of all emission for a given category—such is the case in the oil and gas space in Texas. Pneumatic controllers run by natural gas, for instrance, were found to have produced 95 percent of all emissions at natural gas sites, the researchers pointed out. While the federal government has created more regulations recently that have helped to decrease emissions, new technology is being implemented or is on the way to Texas to help researchers better understand the emissions profile at shale energy developments. Infrared cameras, for instance, are now being used in the state to better locate and identify emissions. And, in a greater context, the researchers reminded people that although the production of natural gas can and does create emissions, the use of natural gas for power and other items creates a net decrease in emissions state-wide.

Water: Water used for fracking accounts for less than 1 percent of total statewide water use, according to the study. In the future, more research should be done to increase the usage of poor-quality waters instead of freshwater. And, more should be done—through technology or regulations—to better prevent leaks and spills of produced water. Young says that his team has recommended a better recording and spill volume tracking system across the state. Currently, the Railroad Commission oversees spill volume recording levels on a district by district basis. More uniform reporting would help to better identify the source of surface water spills.

Transportation: From Texas A&M University, John Barton played the lead research role for the transportation focus. Barton says that most highways in Texas shale country were never designed to handle the type of truck traffic they are currently getting. On a per-well basis, 1,000 to 1,500 trucks are needed in Texas. Single axle truck equivalents are in the 5,000 to 15,000 range. The cost to repair shale development area infrastructure—mainly roads—is roughly $1.5 billion, Barton says. And, for industry, the cost of not improving transportation infrastructure is in the $1.5 to $3 billion range due to equipment damage cause by the poor roads or the lower operating speeds that would result from no improvements.

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TASK FORCE TALKS: Over the course of 18 months, the shale task force met in person. The meetings helped push debate and create consensus on the main focus areas of the report. PHOTO: THE ACADEMY OF MEDICINE, ENGINEERING & SCIENCE OF TEXAS




Along with stable or enhanced funding mechanisms for oilfield roadways, Barton says his research team suggested the industry be more forthcoming with data. Transportation officials can use that data to help plan for future bottlenecks and areas that will need repair, he says. The data needed will have to indicate trends or the direction industry is headed geographically.

Economic and Social: No research group highlighted or touched on the tradeoffs associated with shale energy development as much as the team responsible for looking at the economic and social variables. Omar Garcia, lead researcher from the South Texas Energy And Economic Roundtable, says that there is no question fracking has positive value to the Texas economy and community. But, he says, there is limited data on the benefits and costs of development. Public schools and universities benefit immensely from shale

energy development, but the funding gained is not distributed evenly across the state, an area that the research team recommended be further considered. Although there is no one-size-fits-all outreach effort that can yield overarching conclusions on the impact of shale development on communities, the study did find that communities in shale regions like the economic benefits to property values, schools and medical services. Communities disliked the impacts on traffic, public safety, environmental concerns and noise. “Overall, shale oil and gas development primarily contributes positively to local, regional and state economies,� the report group said. Author: Luke Geiver Editor, North American Shale magazine 701-738-4944





EXPANSION Recent acquisitions and expansions have helped Mammoth Energy Services greatly increase its ability to serve shale oil producers in the U.S. and Canada

By Patrick C. Miller New well completion techniques with longer laterals and mega-fracks using much larger quantities of sand— combined with an uptick in oil and gas activity—have led to reports of U.S. shale oil producers experiencing frack sand shortages. However, Mammoth Energy Services Inc.—an integrated oilfield services company based in Oklahoma City—has not only responded to the challenge, but also has expanded its frack sand operations to meet the increased demand. Mammoth's line of services includes pressure pumping, well services, natural sand proppant, contract land, directional drilling and other remote accommodation energy services. “We have positioned the company to capitalize on the tightness the industry is seeing and ensure that our clients are able to complete their wells in a timely manner,” says Don Crist, Mammoth’s director of investor relations. Active in the Utica, Permian, Eagle Ford and the SCOOP/ STACK shale plays, Mammoth recently completed the acquisition of Chieftain Sand and Proppant LLC in New Auburn, Wisconsin, which now operates as Piranha Proppant. This gives Mammoth access to the Union Pacific railway with unit train capabilities to Texas where the demand for frack sand remains high. “We have mines located on all of the major rail lines, allowing for low cost transportation into every major basin in the U.S. and the Montney in Canada,” Crist notes. “We plan to sell into every major basin going forward.” 20 NORTH AMERICAN SHALE MAGAZINE ISSUE 3 2017

Earlier in the year, Mammoth also acquired Taylor Frac LLC in Taylor, Wisconsin, which owns a sand mine and a 700,000-ton-per-year processing plant. Combined with Muskie Proppant LLC, Mammoth’s frack sand operation in Pierce County, Wisconsin, the company expects to expand its sand processing capacity from 700,000 tons per year in 2016 to 4 million tons by the end of 2017. Mammoth will have about 75 million tons of frack sand reserves.


As a result of the acquisitions and expansions, Crist says Mammoth’s pressure pumping fleet hasn’t experienced any disruptions because of frack sand shortages. In fact, he says the company’s fracking calendar is fully booked into the fourth quarter and discussions for 2018 have begun. “While Mammoth does sell sand into every market, the majority of our recent sales have been in the northeast— Marcellus and Utica,” he says. “The majority of our current

TAYLOR STOCKPILE: After acquiring Taylor Frac LLC in Taylor, Wisconsin, earlier this year, Mammoth expects to have a frack sand reserve of 75 million tons. PHOTO: MAMMOTH ENERGY SERVICES INC.



BOUND FOR TEXAS: To meet its sand demand in Texas and Oklahoma, Mammoth Energy Services Inc. acquired Chieftan Sand and Proppant LLC this year. Most of the sand pictured here is headed to the Permian. PHOTO: MAMMOTH ENERGY SERVICES INC.

sand production is utilized by our pressure pumping fleets, with a smaller portion sold to third parties.” Once its sand mines are operating at full capacity, Crist says Mammoth’s six pressure pumping fleets will use 2.1 million tons per year. Another 1 million tons will be contracted to third-parties and the remaining tonnage will be sold on spot markets.

Changes in fracking techniques have not only changed frack sand volumes, but also sand grades. “Over the past two years, there has been a big shift to finer grades of sand,” he says. “The highest demand grade is 40/70, which is a shift from past years when 20/40 was in highest demand. This was facilitated by a shift in slickwater completions, which has become the preferred

completion method. We have looked at ways to increase the production of the higher-demand, fine-grade sands and move away from producing the coarser grades.” The concentration of sand has been increasing over the past several years with the industry pumping around 2,000 pounds per lateral foot today, which has increased significantly within the past few years. “The rig count increases since the

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A rising tide raises interest in Hexion’s solutions Hexion Inc.—a global provider of coated sand proppants and technology-based solutions to the oil and gas industry—hasn’t experienced any difficulty in obtaining sand for its products. Jerry Kurinsky, senior vice president and general manager of Hexion’s Oilfield Technology Group, says there are two reasons why the company hasn’t been affected by sand shortages. “We’re not integrated on the raw sand side,” he explains. “It’s one of the raw materials we buy to develop technical products that we sell into the marketplace.” The advantage of this approach is that Hexion—headquartered in Columbus, Ohio—can buy sand from any provider, which enables it to optimize the logistics of getting the sand to where it’s needed. “The disadvantage is that we’re buying at a market price, but we’ve been able to manage that,” Kurinsky says. The second reason is that Hexion

doesn’t require the same volume of sand as oil and gas operators, which gives the company great flexibility in determining who and where it buys sand from. Because of increased drilling and fracking activity in U.S. shale plays—particularly in the Permian Basin—Kurinsky notes that Hexion is seeing renewed interest in some of its sandrelated products, such as OilPlus proppant and the Sentinel dust suppressant system. “What we’re finding now is that the discussion is trending back toward technology and getting the best value out of their assets,” he explains. “They’re not just thinking about near-term costs; they’re also thinking about long-term performance of the well.” Although Hexion’s OilPlus proppant has been on the market for some time, Kurinsky says its sales have increased over the last two quarters. It changes the relative permeability of the proppant to improve oil flow and increase production.

“We’ve had customers tell us that they’ve generated $1 million of additional revenue on a well in a year by using that product,” he says. Meeting OSHA regulations that go into effect next year on permissible exposure to respirable silica dust creates a challenge for frack sand producers and users. Hexion’s Sentinel solution is a chemical treatment to reduce silica dust

Kurinsky says. “With the work we’ve done so far, it stays effective all the way from start to finish. So handling the sand in between different points in the value chain doesn’t degrade its performance.” Overall, Kurinsky expects oil prices to trend slowly upward into 2018, a trend he believes will cause producers to be more interested in long-term technological solutions rather than the bottom line of initial production.

“It’s very easy to apply at the sand mine or the frack site,”



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low-point in the second quarter of 2016 have occurred primarily in the basins that have the highest demand for sand,” Crist explains. “As a direct result, for every rig that is added, you can roughly calculate the demand that rig will have on the sand market. “For example,” he continues, “if one rig is added in the SCOOP/STACK and it is expected to drill one well per month—12 wells per year—with lateral lengths of 10,000 feet each and sand concentrations of about 2,100 pounds of proppant per lateral foot, then we can expect sand demand of roughly 252 million pounds—or 126,000 tons.” With 22 sand trucks serving the Appalachian Basin, 20 trucks on order for the Permian Basin, 20 on order for the SCOOP/STACK and more than 2,000 leased rail cars, Crist says Mammoth hasn’t experienced any difficulties with logistics in getting its frack sand to where it’s needed. “We have internal logistics as part of our integrated model, so we are not


dependent on third-parties to move our sand,” Crist notes. “The trucking side of the business—last-mile—has gotten very tight and given the increased concentrations of sand required per well, we expect this to continue. We are positioned well to adequately supply our needs and provide trucking for other companies as well. “ In the next few years, Crist expects the demand for frack sand to increase significantly as sand concentrations continue to increase across the oil and gas industry. “Oil prices, which influences the rig count, is the biggest driver of demand,” he says. Author: Patrick C. Miller Staff Writer, North American Shale magazine 701-738-4923



ECONOMIES OF SHALE How Shale 2.0 is paving the way for the digital oilfield

By Mark Hill The upstream industry loves a good dust-up. From crashing oil prices to Saudi over-production, the past two years have tested that tenacity like never before. The scraps have come thick and fast. But where the boom years saw a frenzied battle to see who could out-drill and out-spend rivals, the days of luxury camps feeding lobster to roughnecks while Learjets circled overhead are over. Today’s shale producers are thinking leaner and longer. The new watchword is frugality–and it’s energizing a very different kind of shale revolution.

From mechanical to digital, innovation is shale’s DNA It’s almost 10-years since advances in hydraulic fracturing technology kicked off the first shale boom. Gas from shale rocks went from almost zero to current levels of around 50bn cubic ft/day . It killed off coal-burning power and gave American businesses a huge advantage in operating costs. Extending fracking to unconventional oil plays, lifted U.S. production by 3 million barrels a day and compelled the Saudis to try to flood the market in an attempt to drive American producers out of business.

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). 26 NORTH AMERICAN SHALE MAGAZINE ISSUE 3 2017


SCREEN SERVICES: P2 Energy Solutions is one of several data-based firms providing upstream entities with software offerings that can help shale players better utilize and understand data.

FIELD IMPORTANCE: Field-level data has been important for operators to utilize in gaining better knowledge on what others are doing or might do.

NO OPTION: Better data utilization has been crucial for operators to improve efficiency as oil prices have declined.




Development of digital oilfield technology has been happening for at least 15 years, but it’s only in the past few that E&P companies focused on unconventionals have started to trust and apply it.

That, combined with weakening global demand crashed oil prices and has kept crude hovering at around $50 per barrel. Yet the fall and flood haven’t had the expected outcomes. Of course some production has been trimmed back but the real story is how unintended consequences have pushed the U.S. shale industry to embrace new data gathering, analytical and mobile technologies. More producers are using tech to get more from their wells. A digital oilfield revolution is now underway.

Necessity: the mother of invention Development of digital oilfield technology has been happening for at least 15 years, but it’s only in the past few that E&P companies focused on unconventionals have started to trust and apply it. The industry’s financials when oil prices began to fall left it exposed. Output surged between 2012 and 2014 in part because of heavy spending. Producers borrowed heavily, bid-up land rights and drilled, drilled and drilled. Investors pushed the envelope when making valuations, while derivative bets taken when prices were high, threatened to hurt future cash flow. So when prices crashed, learning to do more with less became a rule of survival. There was nothing to stop that happening across the upstream sector, but the unique challenges of data management in unconventional operations made digital adoption something close to business critical. The high-decline rates and higher number of wells that typically need to be managed in shale fields also have a direct practical impact on the life cycle of any field data collected, and that affects data quality, availability, integration, analytics, and regulatory compliance—in other words, how effectively that data can be put to work to improve profitability. Some industry watchers have noted that shale production is different from traditional E&P, with the high levels



Do you have: • Conflicting well, land, and JV data in multiple places? • Multiple versions of the truth?

• Challenges with regulatory filings, prior period adjustments, or inefficiencies with monthly, quarterly, or annual close?

• Silos between production and revenue accounting? • Difficulty delivering the right information in the right format?

Whether in the field on a mobile device or automatically via SCADA systems, massive volumes of information are now being captured at the well head that must be processed and turned into actionable information for surveillance, operational accounting, and HSEQ compliance. of repeatability you might associate with a factory. As that lends itself over time to ever-increasing efficiency through the cascading effect of small, ongoing improvements, it also suits the modern management philosophy of ‘continuous improvement’, which is closely aligned these days with advances in software and mobile tech.

How shale is leading the way in digital Digital oilfield tech has manifested itself most visibly in the mobile devices shale engineers use for capturing well data in the field, and communicating it back to head office for analysis. The adoption of SCADA (supervisory control


• Lost data and costly delays? • Higher operating costs due to inefficient use of field personnel?

• Challenges identifying which wells to focus your efforts on?

and data acquisition) systems has made it possible to monitor wells around the clock and alert engineers to possible signs of failure. With so many wells under management, however, it can still be hard for staff in the field and in the office to constantly monitor every single one. So those tedious and time-consuming tasks have become perfect candidates for predictive monitoring and automation. That’s thrown up some compelling benefits. For one, shale producers have been able to move from preventative to predictive maintenance. Production and HSE incidents are being averted before a failure to minimise expensive downtime for rigs. These systems can also monitor production targets on a well-by-well basis and alert in advance if a well is unlikely to hit its expected production target. Course adjustments or fixes can now be made before a well’s output has been seriously diminished. The impact on industry-wide production and bottom lines have been impressive, but it doesn’t mean digital haav arrived in the shale industry without facing challenges. Whether in the field on a mobile device or automatically via SCADA systems, massive volumes of information are now being captured at the well head that must be processed and turned into actionable information for surveillance, operational accounting, and HSEQ compliance. It’s a flood of data that can hide critical knowledge, so the data management systems being adopted have had to get better at surveillance by exception, with functionality to identify problems and events automatically. Such large volume of automation data also can’t be stored indefinitely. So filtering and data-reduction techniques have had to adapt to improve archiving, and decide what information should stay and what should go.

Operators who deploy a complete production solution: • Broadly understand their strategic, financial, and operational health

• Quickly integrate new assets

• Make smart, risk-advised decisions

• Jump on opportunities

The oil patch is optimistic by nature, but a dose of wellearned realism now permeates the industry. Sensible folks can see that prices may never return to the heady days of 2014, and that without profound change the industry faces an even harder landing, with more job losses, rig closures, company defaults, and asset sell-offs. It’s good news that shale producers are leading the way in E&P innovation, drill-

• Equip teams to work together for the good of the whole

• Create fast closing and accurate regulatory filings

ing through data in order to emerge leaner, meaner and more productive than before. Author: Mark Hill Senior Vice President Sales and Marketing P2 Energy Solutions


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THE CLEAR MOVE: After starting and operating in the Eagle Ford since 2012, Petro Waste Environmental recognized the changing shale market. This year, PWE opened its first facility to serve the Permian. PHOTO: PETRO WASTE ENVIRONMENTAL

Petro Waste Environmental

transition between basins By Patrick C. Miller Petro Waste Environmental LP was fortunate that when the company launched in 2012 with the goal of providing nonhazardous waste services to shale oil producers in the Eagle Ford, it also had an eye on the Permian basin’s potential. Based in San Antonio, Texas, the company was started by George Wommack who now serves as PWE’s CEO. The company’s short history provides a good ex-

ample of how quickly things can change in the oil and gas industry and how being nimble is the key to surviving. “The reason I felt this was a good opportunity was that I’d been active in the saltwater disposal space in the Eagle Ford shale in south Texas and found that many of our customers were contacting us in search of locations to dispose of their mud and cuttings,” Wommack says. “At that time, there was no infrastructure capable of handling those types of waste


streams. We identified the need coming from some of the large E&P companies developing the Eagle Ford.” According to Wommack, the Eagle Ford was being overwhelmed with the waste streams produced from horizontal drilling and hydraulic fracturing. “There were huge lines and trucks had to drive long distances to get to the few facilities that were able to take that material,” he recalls. “It was an enormous bottleneck in the petroleum production process.”


To serve the Eagle Ford, PWE built two landfills in McMullen and DeWitt counties, a saltwater disposal facility at Carizzo Springs and a satellite facility at Cuero. The company planned to use the south Texas facilities to become well-established in the market and develop customer relationships “That was the original plan, but what happened when we went into the downturn was that the rig count in the Eagle Ford virtually went to nothing,” Wommack says. “The market just dried up—almost overnight. Fortunately, the company had also recognized the Permian’s potential and was ready with Plan B. “We made the decision at that point to mothball those processing facilities and shift our focus to the Permian Basin where the fundamentals were better,” Wommack explains. “We knew at the time that when the market came back, it was going to come back in the Permian before the Eagle Ford because the breakevens in the Permian just kept getting lower. The returns looked better and better as more and more development occurred.” PWE had earlier begun the process of exploring locations in the Permian where facilities could be permitted to accommodate the solid waste from horizontal drilling and the production completion process. Because it had permits for two facilities, the company shifted its construction and development plans to two sites in the Permian. In April, PWE opened its first facility in the Permian, the 217-acre Orla Landfill in Reeves County. As with the company’s other sites, the Orla Landfill accepts oiland water-based mud, oil- and water-based drill cuttings, contaminated soil and RCRA exempt non-hazardous E&P waste. It also provides washouts and other ancillary services. Work is also underway on a second facility in Howard County, in the northern Midland basin just outside the town of

NEXT DEVELOPMENT: Petro Waste Environmental knew the Permian market was so strong it would need to offer multiple oilfield waste facilities. Later this year, the company will open a site outside of Midland, Texas. PHOTO: PETRO WASTE ENVIRONMENTAL

Midland. That facility is expected to open in August. Wommack says the change in plans has worked out well for PWE. “The economics in the Permian have continued to get better,” he notes. “There’s a lot of efficiencies still left to capture in the drilling and production process on the drilling side as they increase laterals further and services continue to get more efficient.” PWE’s goal is to have facilities within 30 miles of all drilling activities in the Permian Basin. “There’s nothing more important than being in the right place. If you’re not close enough to the drilling activity, you’re going to be priced out of the market and you’ll never be a major player in our industry,” Wommack says. As a company that places great emphasis on community relations, safety and protecting the environment, Wommack stresses that PWE wouldn’t be successful if it didn’t have the right people to operate its facilities. The past two years, the company has been named one of the best places to work by the San Antonio Business Journal. “We want to make sure that everybody enjoys working for our company,” Wommack explains. “That’s key to us. It flows through the activities and services that our


employees provide. If it’s a better work environment, people are more productive. It’s just the right way to live life.” Author: Patrick C. Miller Staff Writer, North American Shale magazine 701-738-4954



MOVING TOWARDS NEW RATES: Increasing interest rates could alter the financing methods used by shale energy production entities in their quest to grow and expand field operations, according to a new report by the Center On Global Energy Policy. PHOTO: NORTH AMERICAN SHALE MAGAZINE, PATRICK C. MILLER

Reserve Base Lending’s

Past—and Future—in Shale Production By Luke Geiver

Interest rates could play a large role in the future of North American shale oil and gas production. Efficiency gains and operational improvements achieved by North American shale oil and gas producers during the oil price downturn that started in 2014 and ended in late 2016 have solidified shale production as a multi-generational industry. But, a new report indicates that fluctuating interest rates could partially overtake those gains and improvements as a major factor driving growth in the industry. Amir Azar, a fellow at the Center on

Global Energy Policy—an independent, balanced, data-driven analytics group that provides information to policymakers looking to navigate a complex world of energy—analyzed the role interest rates have played and will play in the health of the North American shale production industry. Azar documented how interest rates have impacted the practice of reserve base lending (RBL) for energy producers and offered insight into how lenders have changed their practices towards energy producing borrowers following the low oil price environment.


Easy access to low-cost debt helped fuel the shale revolution, Azar said. Many small- and medium-sized producers have relied on RBL to receive bank debt financing for the drilling and expansion of oil and gas reserves. Without deep-pockets or cash-on-hand as larger, traditional oil production firms typically have, RBL is needed to help below-investment-grade and investment grade firms start and grow their own production. RBL financing is linked to the value of the oil or gas reserves that an exploration and production company owns. His study, released this spring, “Reserve


Aggregated Debt Vs. Interest Expense ($MM) 25,000

Oil and gas reserves are classified into three categories: proved reserves, probable reserves and possible reserves. Lenders only extend credit against a company’s proved reserves. An independent reserve and production engineer calculates how much the bank can lend based on the value of the proved reserves. Up to 2015, RBL financing was the borrowing method of choice, in part because of the low interest rates associated with the debt and the strategic nature of many small- and mid-size operators. Between 2005 and 2015, E&P aggregate debt increased by 300 percent, from $50 billion to $200 billion, according to Azar’s report. At the same time, interest expenses related to the debt increased by only 150 percent, from $4 billion to $10 billion. “Therefore, debt increased twice as fast as interest expense, indicating a gradual decline in borrowing cost,” the report says, or, “Simply put, low interest rates incentivized higher debt to boost the return per share.” Because low-cost debt was easy to obtain, shale industry entities became accustomed to outspending cash flow to fund growth with new debt instead of utilizing a combination of debt and cash on hand. Revenue generated from oil production was not, in some cases, enough to fund operational growth or acquistions. The issue with that strategy appeared when oil prices began to fall. Through SEC rules, companies can only book or count reserves that are scheduled to be developed or produced within five years. But, as the study says, in a low-oil price environment, corporate cuts in capital spending can alter the development time line of certain reserves beyond the SEC’s five-year window. The sustained low oil price period ruined roughly $160 billion of book equity value for E&Ps that was linked to their proved reserves that they had planned on developing with oil prices at a higher range.

The History of Debt and Shale Growth










0 2005











DEBT MOVED FASTER: For much of the shale boom period, the amount of debt issued to E&P firms rose faster than the interest rate associated with that debt. The situation allowed many producers to acquire needed capital to grow or maintain operations. If interest rates rise, growing through debt may be harder to achieve. SOURCE: CAPITAL IQ, FINANCIAL REPORTING

EBITDA & Free Cash Flow Deficit Vs. Net Debt 250,000

 Free Cash Flow Deficit  EBITDA (Total)  Aggregate Net Debt

200,000 Interest Expense ($MM)

RBL Basics and Complexities

Interest Expense ($MM)


 CCC B  BB  Investment Grade Interest Expense  Aggregate Net Debt

Aggregated Net Debt ($MM)

Base Lending And The Outlook For Shale Oil And Gas Finance,” explains how RBL shaped shale production up to 2015 and how things will be different in the future.

150,000 100,000 50,000 0

2,005 2,006


2,008 2,009







-50,000 DEBT FILLED THE GAP: Because debt was cheap to attain, producers used new debt to grow instead of utilizing revenues generated from production. Growth brought higher proved reserves, which could also fetch greater borrowing amounts. SOURCE: CAPITAL IQ, FINANCIAL REPORTING

North American E&Ps Impairments ($MM) 180,000 160,000 140,000

 CCC B  BB  BBB - and above (Investment Grade)

120,000 100,000 80,000 60,000 40,000 20,000 0 2005











RBL’s CHALLENGING STRUCTURE: With the collapse of oil prices, more than $160 billion of book equity was wiped out by impairments because proven reserves used to formulate the borrowing bases were taken off the books. SOURCE: CAPITAL IQ, FINANCIAL REPORTING

For shale producers who lost the value of



Lifting Costs Fall To Lowest Level Since 2009 $25 $/boe


 Production-related G&A  Taxes other than income  Shipping and transporation expense  Production expense

$15 $10 $5 $0

2006 2007 2008 2009 2010






EFFICIENCY GAINS VS. INTEREST RATES: Although efficiency gains were achieved during the downturn, the impact of higher interest rates on the ability of producers to attain financing is still unclear. SOURCE: HIS HEROLD 2016 GLOBAL UPSTREAM REVIEW

their reserves due to low oil prices, some were forced into bankruptcy. Others were able to redo or renegotiate the stipulations placed on their loan repayments or in the way they could spend the borrowed money. Since 2015, many banks have added new stipulations to the covenants that come with RBL financing packages for shale producers, Azar noted. Most RBL financing packages now include hoarding language, deposit account control agreements and minimum hedge requirements. Because some shale producers foresaw an impending bankruptcy, many took all of the remaining credit and cash from their revolving credit facilities in a move that would help them pay for legal fees and restructuring during a bank-

ruptcy proceeding, Azar said. Because of that, banks will no longer allow the debtor to hoard cash for those purposes. In addition, banks are also asking producers to hedge more of their production to ensure and entrench their position on a producer. The account control agreements limit what money can be spent on to a greater extent. Because interest rates played such a large part in allowing RBL financing to thrive during the shale boom of 2008 through 2014, Azar believes interest rate hikes are very important to the future growth opportunities of U.S. shale energy production. Although many producers have opted to grow or maintain operations by investing or using only cash-on-hand, many producers still need to utilize debt to stay relevant. “With the expectation the Fed will continue to increase rates, oil hovering at $50 a barrel, and higher credit spreads, small and midsize North American E&Ps may face the same old challenge of high cost of capital,” Azar said. Author: Luke Geiver Editor, North American Shale magazine 701-738-4944

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Deploying d-Limonene, an industry-proven bio-based solvent extracted from oranges, and various surfactant platforms, we develop prescriptive chemistry solutions unique to every reservoir, field and well. This transformative portfolio of chemistries consistently increases a client’s estimated ultimate recovery (EUR), leveraging the power of nature.

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Throughout the Entire Fluid Lifecycle. FLOTEKIND.COM y





Profile for BBI International

Issue 3 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 3 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.