Issue 2 2018 - North American Shale magazine

ISSUE 2 2018

The

Efficiency

Bit

How Drill Bit Developers Are Redefining Better Oilfield Operations Page 20

Plus

The True Limit To Shale’s Growth Page 14

And

Permian Frack Designs Page 8 NorthAmericanShaleMagazine.com Printed in USA

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INSIDE

VOLUME 2

ISSUE 2 2018

14

20

FEATURES

14

EXPLORATION & PRODUCTION

The Limit To Shale’s Growth

BY LUKE GEIVER After years of asset, portfolio and production growth, E&Ps could begin making money for investors in the near-term as new executive strategies are implemented into an advantageous oilfield market.

ADVERTISER INDEX 2 & 27

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Eldred Environmental & Export Company, LTD.

28

Hydrozonix

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STV

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Wanzek Construction Inc.

20 Drilling At The Sharp End

PRODUCTS & TECHNOLOGY

BY PATRICK C. MILLER Ulterra Drilling Technologies grew during the downturn by helping engineers drill faster, more efficient wells at a time when their jobs were on the line.

NEWS & TRENDS The frack design behind QEP’s asset sell-off 10 With gas production rising, Bakken flare task force reunites 8

DEPARTMENTS 4 EDITOR’S NOTE

A Bit Of Shale Efficiency

BY LUKE GEIVER

ON THE COVER: Ulterra Drilling Technology grew during the downturn by providing drill bit technology that was more efficient than the norm.

5 EVENTS CALENDAR

PHOTO: ULTERRA DRILLING TECHNOLOGIES

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3

EDITOR'S NOTE NorthAmericanShaleMagazine.com VOLUME 2 ISSUE 2 EDITORIAL

A Bit Of Shale Efficiency Luke Geiver

EDITOR North American Shale magazine lgeiver@bbiinternational.com

Of all the talked-about-topics in the shale industry since 2014 (excluding OPEC), none has been discussed more than this term that touches every segment of the industry: efficiency. To bring that term to life, and turn it into a tangible story, we reached out to a Fort Worth drilling technology firm that grew its operations during the height of the downturn.

Ulterra Drilling Technologies designs and fabricates

unique drill bits for unconventional and conventional wells. From Fort Worth, Ulterra serves an array of firms that includes oil majors in Saudi Arabia to small wildcatters that drill one well every three months.

Customer growth, and the company’s financials, started to increase during the downturn because that

Editor Luke Geiver lgeiver@bbiinternational.com Staff Writer Patrick C. Miller pmiller@bbiinternational.com Copy Editor Jan Tellmann jtellmann@bbiinternational.com

PUBLISHING & SALES CEO Joe Bryan jbryan@bbiinternational.com President Tom Bryan tbryan@bbiinternational.com Marketing & Sales Director John Nelson jnelson@bbiinternational.com Business Development Manager Bob Brown bbrown@bbiinternational.com Circulation Manager Jessica Tiller jtiller@bbiinternational.com Marketing & Advertising Manager Marla DeFoe mdefoe@bbiinternational.com

ART Art Director Jaci Satterlund jsatterlund@bbiinternational.com

is when operators needed to start realizing efficiencies, says Maria Mejia, chief financial officer. “The downturn was definitely helpful to us because decision making became a question of ‘Who can make a difference for me now?’ and not ‘Who can make a difference for me two months from now,’” she says.

Ulterra's team harnessed the push for speed in reaching total depth. Five years ago, drillers could drill 20 to 40 feet an hour, but today, one hour of drill time with a bit from Ulterra or others that feature similar designs, can make it through 200 to 300 feet. To ensure faster drill times were not bogged down by the presence of increased drill cuttings, Ulterra increased the efficiency of their bits to move the cuttings. As you’ll find in the story, “Drilling At The Sharp End,” by Patrick C. Miller, the company’s success provides a real-life case study in what efficiency in the oilfield can look like.

Also this issue, we included perspective from energy analysts and experts that helped to define what the prospect of growth in shale energy production could be in the near- and long-term. While the future of shale energy production is on track for expansion, experts believe operator strategies used in the past will have to change. For growth, new ideas on appeasing a new investor sentiment, combined with the continued adoption of new technology is necessary, the experts say. Of course, the most talked about topic in shale—OPEC—will influence the future, but the idea of efficiency will continue to matter. In the end, the basics of global supply and demand appear to once again be in favor of shale’s expansion. In the story, “The Limit To Shale’s Growth,” on page 12, we led the piece with an image of the sky on purpose. After reading the story, you’ll see why.

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.

NorthAmericanShaleMagazine.com 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 service@bbiinternational.com.

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 service@bbiinternational.com. 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@ bbiinternational.com.

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8

NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

The frack design behind QEP’s asset sell-off QEP Resources’ plan to become a Permian Basin pure-play operator are linked to the Denverbased E&P’s frack strategy. Using it’s “tank-style” development, QEP’s methodology attempts to create a pressure wall separating producing wells from wells undergoing completion. The wall—or buffer—minimizes the interference between the wells, and is created by the geologic rock formation and distance present in the stacked pay zones of the Midland. The tank style approach reduces drilling costs by keeping the drilling rig on a pad for longer as it works to drill out all of the well bores planned for a single geologic formation before moving on to a new formation. Wells in a single tank are also completed in full before being brought onto production.

The goal of the tank style top-down completion method is also to maintain reservoir pressure in each geologic pay zone.

The approach helps to keep the rock “super-charged,” according to QEP, as additional laterals are placed below existing laterals.

Microseismic data has shown that QEP’s wells that were developed in a tank style featured higher initial flowing pressure with additional frack complexity downhole. Beyond day 120, oil rates in high-density Spraberry units exceeded that of parent wells, the company said.

Although the cost to drill and complete a Permian well versus a Williston Basin well are nearly identical, there are more pay zones in the Permian. According to QEP, the company can drill at least six zones from a single pad. In the Williston Basin, most producers are currently targeting between two and four zones.

As of march, QEP held 50,000 acres in the Permian and planned to sell more than 100,000 acres in the Williston Basin.

In-basin sand strategies create new mines, more tech To better serve its clients in south Texas, Pennsylvania-based Preferred Sands recently opened the Atascosa County sand mine.

The new facility designed to serve the Eagle Ford, Michael O’Neil said, represents a significant event for the company’s new location strategy. Once a sand provider with northern white plants in Minnesota and Wisconsin, Preferred chose to match the in-basin needs of its clients like other sand providers had before. In Monahans, Texas, the company will open a second in-basin plant.

The Minnesota and Wisconsin plants once owned and operated

by Preferred have been sold.

Hexion Inc., another sandlinked entity, has also entered the in-basin sand game happening in Texas. The company recently unveiled a mobile resin-coated proppant manufacturing facility for clients that want to alter their proppant without paying for shipping and handling costs.

The mobile units come complete with a lab and silo storage and can be placed anywhere along the logistics line. Jerry Kurinksy, senior vice president and general manager of Hexion’s Oil Technology Group, said the mobile manufacturing system matches the new need of Permian clients

ENTER THE VOYAGER: Deployed in the Permian, the Voyager mobile resincoated proppant system can produce an entire well’s sand volume in two days.

An onsite lab ensures the quality of coated product and silo storage allows trucks to enter and exit efficiently with new product.

PHOTO: HEXION INC.

while giving them more economical access to higher-quality proppants.

“The potential savings of in-basin sand are huge—as long as operators are satisfied that it meets their technical requirements, they could save up to 50 percent on frack sand hauled from Wisconsin,” said Todd Bush, founder of Energent, an oil and gas research and consultancy firm that released a study on inbasin sand.

“Assuming a 50 percent adoption rate of locally mined sand, incumbent suppliers will see a material decline in noncontracted volumes by the third

Benefits of Resin-Coated Proppant Created In-Basin

“The primary benefit of resin-coated proppant is to prevent flowback,” Kurinsky said. “When proppant is coated, the grains bond together and form a pack that doesn’t flow back into the well. When fractures start to close in, the pressure shears off untreated-sand more easily, which reduces the permeability and the ability of oil to flow properly.

quarter. It will also focus attention on logistics within the basin itself—the truck fleet, retaining drivers and transport technology—which will also drive well economics,” he said.

Numbers of the In-Basin Rush Permian Basin Operators Active Pressure Pumper Companies Active Sand Producers Drilled But Uncompleted Wells E&P Capital Commitment Expected Sand Demand Growth By 2019

800 25 30 2,430 Trending Higher 2.5 million tons per quarter

NorthAmericanShaleMagazine.com

9

NA SHALE NEWS

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With gas production rising, Bakken flare task force reunites Four years after creating a flaring task force designed to help producers, midstreams and mineral owners reduce the volume of associated gas produced during the shale oil retrieval process, more than 60 industry and state stakeholders are reconvening.

With gas and NGL prices now profitable for Bakken producers and areas of the state falling short of capture goals, members of the task force believe now is the time

to discuss the future needs, challenges and opportunities for the gas resource.

Through the initial efforts of the task force, industry and state leaders agreed to follow a flarecapture goal that would slowly increase the amount of gas captured year over year before reaching a 90 percent capture goal in 2020.

Failure by operators to meet the goal for their assets would result in potential production curtail-

ments. Low oil and gas prices in 2016 and 2017 made gas in the Bakken less attractive for major infrastructure project investments from producers and midstreams.

But, times have changed and the future of the Bakkenâ&#x20AC;&#x2122;s gas production potential will only grow, state leaders believe.

The North Dakota Petroleum Council task force has already held meetings through six subcommittees created to examine

challenges, including: additional infrastructure buildout, right-of-way and tribal regulatory challenges, H2S contamination, remote capture technologies, new operator engagement and reworking of the gas capture plan requirements to better reflect a changing oilfield.

By mid-May, the group intends to have a new plan on gas capture for the Bakken.

New directions on tribal right of ways

Lynn Helms, director of the North Dakota Oil and Gas division, hopes a spring meeting with the U.S. Bureau of Indian Affairs and Secretary Ryan Zinke from the Department of the Interior, will help right an easement issue in the Bakken that seems to be continuing down the wrong path.

The stepsâ&#x20AC;&#x201D;and timeâ&#x20AC;&#x201D;required to obtain a right-of-way on the Fort Berthold Indian Reservation where nearly one-third of all

Bakken oil is produced, are both long and difficult. A recent meeting with the Three Affiliated Tribes, the governing group of the FBIR, helped both the tribes and the state realize the issue was at the federal level. According to Helms, the structure of BIAâ&#x20AC;&#x2122;s system is greatly slowing the process and causing issues with infrastructure necessary to economically capture the gas produced in the region.

10 NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

November 2017 Gas Capture

YELLOW NUMBERS: The Fort Berthold Indian Reservation, highlighted in 6285&( 1257+ '$.27$ '(3$570(17 2) 0,1(5$/ 5(6285&(6 yellow, is struggling to capture associated gas produced in the Bakken due to issues at the Federal level.

SOURCE: NORTH DAKOTA DEPARTMENT OF MINERAL RESOURCES

NA SHALE NEWS

KEEP IT IN THE PLAY: MMEX Resources and Pilot Thomas Logistics will refine and resell diesel produced from Texas-sourced hydrocarbons to drilling rig operations in the state.

PHOTO: MMEX RESOURCES CORP.

Permian refiner, distributor agreement to keep crude in closed-loop Diesel produced at a proposed Pecos County, Texasrefinery could someday go fullcircle. Fort Worth-based Pilot Thomas Logistics, a national provider of fuel, lubricants and chemicals to multiple industries, has agreed to acquire diesel produced from the MMEX Resources Corp. facility. After

obtaining the diesel, the plan is to provide drilling rigs in the region with the product that they helped to retrieve. â&#x20AC;&#x153;We are excited to enter this relationship with MMEX to expand our local supply in the Permian,â&#x20AC;? said Dennis Cassidy, president and CEO of Pilot Thomas. The company

provides products to drilling rigs including oil change services for mud motors and fluid analysis and testing. For frack fleets, the company provides frack fuel management to ensure a job is not interrupted.

Midstream and compression clients also use Pilot Thomas.

MMEX Resources intends

to build a 10,000 per day production facility using crude sourced from the region. The new site will feature truck and rail access for Pilot Thomas and others to easily access processed crude.

NorthAmericanShaleMagazine.com

11

STATOIL'S NEW VISION: To better reflect its heritage and new focus on renewable energy production, STATOIL is changing its name.

PHOTO: STATOIL

Statoil changes name to indicate future goals To capture the essence of its Norwegian origin and better reflect its new focus as a broader energy company, Statoil is changing its name to Equinor.

The name is formed by combining “equi,” the starting point for words like equal, equality and equilibrium along with “nor,” signaling a company proud of its Norwegian origin.

Eldar Saetre, president and CEO of the Scandinavia-backed energy giant, said the company still considers the Norwegian continental shelf the backbone of its company and it will continue growing internationally within both oil, gas and renewable energy.

The goal in the future is to maintain oil and gas productions that are carbon-efficient operations while Equinor ramps up renewable energy—mainly wind—production offshore. By 2030, up to 30 percent of capex issued by Equinor will be put towards renewable energy.

12

NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

EXECUTIVE VIEW: Eldar Saetre, president and CEO, said the entire board of directors is on board with the name change.

PHOTOS: STATOIL

“Equinor is a name that is forward-looking, and creates a strong platform for engagement and dialogue with a broad set of stakeholders. We believe it will create internal alignment and pride, and help attract capital, partners and talents,” said Reidar Gjærum, senior vice president for corporate communication in Statoil.

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Customer satisfaction in the oil and gas industry is worth more than $2 billion. A new study completed by Texas A&M Universityâ&#x20AC;&#x2122;s Mays Business School and Rice Universityâ&#x20AC;&#x2122;s Jones Graduate School of Business, shows that oil and gas companies looking to increase sales during times of higher oil prices would do well to consider customer satisfactionâ&#x20AC;&#x201D;in addition to technical solutions. The study found that customers with extremely dissatisfied customers netted $6.4 billion in sales while companies with extremely satisfied customers recorded sales of $8.5 billion.

Conducted by surveying more than 1,200 energy managers, the surveyâ&#x20AC;&#x2122;s goal was to provide an evidence-based approach to understanding drivers of sales, margins and earnings, according to the authors.

Vikas Mittal, professor of marketing at Rice, said oil and gas companies need to emphasize customer experience now more than ever. â&#x20AC;&#x153;Energy companies routinely embrace the product features and pricing fallacy,â&#x20AC;? Mittal said. â&#x20AC;&#x153;To increase sales, they offer products with more technology and presumably better features at reduced prices. These technology investments, in many cases, only increase their costs and reduce margins, such that every bit of incremental sales only reduces margins and earning.â&#x20AC;? â&#x20AC;&#x153;Meanwhile,â&#x20AC;? he added, â&#x20AC;&#x153;customers only demand more features and become accustomed to lower prices.â&#x20AC;?

The research team simulated results for five companies in the energy sectorâ&#x20AC;&#x201D;Targa Resources, Amec Foster Wheeler, Technip FMC, Conoco Phillips and Sunoco. For each company, sales increased by at least half a billion dollars when customers moved from their current satisfaction level to being extremely satisfied.

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Study: Oilfield customer satisfaction could equal billions

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NorthAmericanShaleMagazine.com

13

EXPLORATION & PRODUCTION

THE LIMIT

TO SHALE'S GROWTH Energy analysts and economists believe that, despite a new investor mindset, shale production is primed for progress

By Luke Geiver

Shale companies are about to get profitable, says Jan Stuart, global energy economist at Cornerstone Macro LLC. Although most shale oil and gas producers have not made money

in the past eight years, a shift in oil industry fundamentals—from the markets to the boardroom—started in 2017, and the result, Stuart says, has him and other industry analysts bullish on shale.

Paul Sankey, managing director and senior analyst at Wolfe Research, says 2017 will mark the year when shale producers shifted their thesis on growth. In the past, Sankey says, producers believed the goal was to grow production reserves while waiting to be acquired by a larger oil entity. The underlying premise of the model was that oil prices would always rise and the value of the proven reserves would rise at the same time. “In 2017, that model broke down,” Sankey says. Everyone realized you can’t rely on oil prices. Because of that, investors are now asking oil producers to become cash-return focused. According to Sankey, investors are now looking for a return on investment plus 10 percent, a metric he believes few existing shale producers can currently provide shareholders. But, there are several firms that could meet those metrics in the near future, especially those that have changed executive pay structures.

BIG SKY LIMITS: Shale production can continue to grow in the U.S. due to favorable global supply and demand models. To become highly attractive to investors, producers need to rethink their normal operation strategies.

14 NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

EXPLORATION & PRODUCTION

NorthAmericanShaleMagazine.com

15

EXPLORATION & PRODUCTION

Executives, once incentivized for growing production and the portfolio, are now going to be viewed on their ability to provide the returns to investors that had been lacking in previous years. Already in 2018 updates, several E&Ps have made special note of their new executive pay structures.

Along with Sankey and Stuart, several other energy analysts explained the near-term outlook for tight oil production during a recent energy think-tank gathering in Washington D.C. The talks were centered on a key question: what will impact the near-term production of U.S. tight oil?

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GROWTH SCENARIOS: Operators looking to keep shareholders happy need to operate within cash flow in the near-term and consider all options to ensure shareholder payouts in the long-term.

SOURCE: CORNERSTONE MACRO LLC

16

NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

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Robert Kleinberg, leader of unconventional resource research and development for the worldâ&#x20AC;&#x2122;s largest energy service companyâ&#x20AC;&#x201D; Schlumbergerâ&#x20AC;&#x201D;believes there are three things that will change in shale. More efficient fracking techniques will help to recover a greater portion of original oil in place, permeability enhancement will help do the same, and tertiary recovery methods (enhanced oil recovery) will prolong the life of current shale plays.

In most cases, energy service firms have already proven, are testing or are in the lab developing new approaches that will undoubtedly improve oil production efficiency. Producers are not yet in need, or willing to pay, for such technology yet, Kleinberg says, even if it is ready for deployment.

As an example, Kleinberg points to a new measurement process used to inspect and determine the amount of organic matter along various sections of a horizontal well bore prior to stimulation.

Under current practice, fracture treatments are only fracking two-

thirds of the horizontal. The organic material measurement technology could help operators reduce the unfracked number down to 10 percent per horizontal, he says.

Another solution being tested is a fluid that once pumped downhole can increase rock permeability.

The solutions is impressive, Kleinberg says, but not yet in use. And, there is also enhanced oil recovery.

Although there are research and strategy decisions yet to be made, Kleinberg is excited about what is already happening in shale. EOG Resources has found great success by injecting field gas into existing wells. According to Kleinberg, the best solution industry thought it could use for the EOR approach was with CO2 injected downhole.

Such a solution can help the oil move through the rock and flow to the surface again. But, in the Eagle Ford, EOG has used field gas for its injections. The mixture is laden with ethane and propane, two gases that Kleinberg said are even better than CO2. â&#x20AC;&#x153;I now believe that EOG might be injecting the optimal mixture,â&#x20AC;? he says.

Funding Shale Production

Although low oil prices may have hindered cash flow for U.S. E&Ps during the past few years, the capital markets were always ready to fund shale. The same can be said today, says Roger Diwan, vice president of financial services at IHS Markit. â&#x20AC;&#x153;Capital is abundantly available,â&#x20AC;? he says, and shale will be well-funded for years to come. The linkage between a sophisticated financial sector, and a very large and entrepreneurial energy sector means that shale resources will be funded as long as returns remain positive, he says. The price of oil to keep returns positive, he believes, is

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NorthAmericanShaleMagazine.com

17

EXPLORATION & PRODUCTION

FUTURE TECH READY NOW: According to Schlumberger, technology designed to help fully frack a lateral or improve permeability is available today.

IMAGES: SCHLUMBERGER

in the $45/b range within the context of todayâ&#x20AC;&#x2122;s cost structure. In the future, private equity investors will look to management teams that are experienced at running a shale operation in manufacturing mode instead of those that are looking to wildcat wells and explore.

With funding available for the foreseeable future, shale production growth should continue through 2019. If oil reaches and stays at $65/b, production will continue to rise past 2020 at or above 1 million barrels per day. Oil at $50/b will help the U.S. grow production at

600,000 to 900,000 barrels per day through 2020.

Possibilites For Growth

The only certainty in the oil industry is that oil prices are uncertain, Sankey says. But given the general lack of confidence he and others like Stuart have in making bold predictions, each believes the oil supply and demand curve shows the world is undersupplied. â&#x20AC;&#x153;We think we have a good idea of the balances and we think we are in a

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NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

EXPLORATION & PRODUCTION

The Endemic Overspend by Mid and Small E&Ps

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US E&Ps Hedged on the Rally, then Prices Kep Rising

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E&Ps Stuart Hedged thethink Rally, Prices Rising supply says.on â&#x20AC;&#x153;We wethen will end 2018Kep in an oil defi3URSRUWLRQ RI )RUZDUG 3URGXFWLRQ +HGJHG DW 7KLUG 4XDUWHU (DUQLQJV cit.â&#x20AC;? Shale production from the U.S. will not be too great for global oil 5HOHDVHG IRU E\ 2SHUDWRU 6L]H demand, he believes. Because shale producers have multiple years of 4 running room, Inves the opportunity for growth in shale is present.

4 tors and analysts who follow Stuartâ&#x20AC;&#x2122;s line of thought, believe shale

is a good investment right now because producers are getting more

production out of their wells than they previously did. â&#x20AC;&#x153;There is al most as much growth potential now as there was in 2014 when oil was

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$100/b,â&#x20AC;? he says. â&#x20AC;&#x153;There is an insane inventory of really good wells.â&#x20AC;?

Author: Luke Geiver Editor, North American Shale magazine 701-738-4944 lgeiver@bbiinternational.com

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Efficiency Through Engineering and Design STV Energy Services, Inc., provides engineering, design, procurement, project management and construction management services to the natural gas, liquid petroleum, and pipeline transportation markets for projects from concept to completion.

Strategically located in Denver and Bismarck, we deliver innovative solutions to meet our clientsâ&#x20AC;&#x2122; needs. â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘ â&#x20AC;˘

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NorthAmericanShaleMagazine.com

19

PRODUCTS & TECHNOLOGY

A BIT FOCUSED: A decentralized decision-making process is part of the culture at Ulterra Drilling Technologies, enabling it to develop solutions for E&P companies, directional shale drillers and drilling mud companies.

PHOTO: ULTERRA DRILLING TECHNOLOGIES

20 NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

PRODUCTS & TECHNOLOGY

Born in the shale oil fields of Canada and the U.S., Ulterra Drilling Technologies emerged from the latest oil downturn stronger than ever.

The Fort Worth firm is now a prime source of where drilling efficiencies come from

By Patrick C. Miller

DRILLING AT T H E

SHARP

END

In military circles, the soldiers in the field who see their enemies eye-to-eye and engage in fierce close-quarters combat are known as the sharp end of the spear. If there’s an oilfield technology equivalent

for shale operators, it’s the drill bit.

The well-known challenge with shale oil and gas is to drill vertically through thousands of feet of hard rock and then transition to horizontal drilling through a formation where the drill bit is directionally steered to create the lateral where fracking occurs. A drill bit problem can compromise the entire operation.

Based in Fort Worth, Texas, Ulterra Drilling Technologies LP has described itself as “the rock destruction company.” It focuses on the sharp end of drilling technologies by designing, manufacturing and renting polycrystalline diamond compact (PDC) drill bits for oil and gas drilling operations around the world. It was formed in 2005 by combining two companies—Canada-based United Diamond located in Leduc, Alberta, and Ulterra in Texas.

“If the drill bit doesn’t work, you don’t make holes, you don’t drill,” says Aron Deen, Ulterra’s director of marketing and business development— who also has an engineering background. Since its founding, Ulterra has remained what Deen calls a “pure play” company, steadfastly focused on providing industry with improved drill bits and downhole tools to drill faster and more efficiently while lowering costs. “It’s really about making sure we have the technology on the end of the drill string that allows all the rest of the technology in the string to do its job,” he explains.

“Something that costs so little in relative terms has a huge impact on the overall cost of drilling the

NorthAmericanShaleMagazine.com

21

PRODUCTS & TECHNOLOGY

THE TIP OF THE SPEAR: Ulterra manufactures a wide variety of drill bits at its facilities in the U.S. and Canada. From the top left clockwise: a FastBack bit for enhanced rate of penetration; a CounterForce bit for vibration control; a bit developed for drilling in China; and a SplitBlade bit for improved cuttings evacuation.

PHOTOS: ULTERRA DRILLING TECHNOLOGIES

‘Something that costs so little in relative terms has a huge impact on the overall cost of drilling the well.’

- Aron Deen, Marketing & Business Development, Ulterra Drilling Technologies LP

well,” Deen notes. “It’s gotten a lot of attention the last couple of years, especially as everyone has become cost-conscious and as drilling engineers have really been able to focus on performance improvement.”

More to the point, the last couple of years is in reference to the low-oil-price environment which severely impacted the North American shale oil and gas industry.

Ulterra not only weathered that storm, but also emerged from it as one of the fastest growing drill bit manufacturers in the world. The company has continued its expansion into international markets, increasing its manufacturing output by 60 percent and last year doubling its workforce. It’s worked with more than 600 different operators in the past year and has customers in 25 different countries.

According to Maria Mejia, Ulterra’s chief financial officer, this can be attributed to a company culture that stresses finding solutions for every customer individually, no matter how big or how small. Those customers range from national oil companies in the Middle East and Latin America

22 NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

to major global producers to top technology-focused, independent E&P companies in North America to companies that occasionally operate a drilling rig in one county of the U.S. “Our only interest is to drill faster,” she explains. “We don’t have daily rental rates coming from anywhere else in the drill string. We have no other interest other than to help customers reach their goal faster and drill faster. That’s what helped us during the downturn. Capital efficiency and drilling efficiency has increasingly become a focus for all our E&P customers. Making sure they remain competitive has allowed us to become one of the market leaders, especially in the U.S. shale plays.”

Another aspect that’s helped Ulterra through difficult times has been maintaining low product inventories, which means it isn’t stuck trying to sell products industry no longer needs. This enables the company to remain flexible and focused on developing new technologies specifically tailored to meet customers’ needs and solve problems as they arise.

PRODUCTS & TECHNOLOGY

“In some cases, the most forward-looking operators don’t come to us with a pre-defined problem,” Deen explains. “They come to us with a goal of wanting to drill faster and wanting to know what we think. Being primarily a drill bit company, we work collaboratively with directional companies and with mud companies. We’ve worked with a whole host of companies that are trying to develop more rotary steerable options that make sense in North American shale plays. We’ve become the drill bit of choice.”

Not all Ulterra solutions involve technology. “Some of the innovations that have popped up industrywide in North American shale are new to the rest of the world,” Deen says. “We worked with an operator in another country to implement a rental model into their procurement method to really change the way they do things. They now rent drill bits and save millions of dollars annually because we converted them from a purchase model to a rental model. We really look at innovation holistically. It’s not just technology driven, it’s value driven.”

Using the latest in social networking and IT technology enables Ulterra to use its global reach to its advantage. “Our engineers in Thailand can to talk to our engineers in Fort Worth who are talking to people in the Delaware Basin or talking to people inhouse working with engineers at Chevron,” Deen relates.

“They can work on a problem such as trying to drill an 8 ¾ inch hole with an AC top-drive rig through 15,000 PSI carbonate with dolomite collaborating with anyone who has dealt with these kinds of things.”

Bit Building

Ulterra has manufacturing centers in Fort Worth and Leduc. The company offers a suite of products that includes: Matrix PDC, a proprietary mold technology; steel PDC shankless, single-piece bits; TorkBuster, which reduces bit-related torque and stick-slip problems; and TruGauge, a short, near-bit stabilizer that reduces hole spiraling and increases directional control.

Deen says Ulterra’s technology is developed to address drilling disfunctions identified by its engineers and customers. Some of the most common problems relate to drill-

DRILLING DOWN TO THE BASICS: Ulterra focuses on PDC drill bits and downhole tools that help customers large and small drill faster to lower costs and improve efficiencies.

PHOTO: ULTERRA DRILLING TECHNOLOGIES

ing vibration, lateral vibration and bit whirl.

“We have applications engineers in most of the major basins around the world who really understand everything from the geology to the drilling application to the experience and abilities of the drilling engineers and the directional drillers,” he explains. “That’s key to unconventional shale in North America.”

Designed specifically to address drilling vibration, CounterForce is one of Ulterra’s more recent technologies. “Drilling vibration is a destructive energy loss that causes damage to expensive downhole tools and potential damage to the well bore,” Deen says. “We designed and built a drill bit that actually harnesses otherwise wasted drilling vibration energy into proactively making hole and reducing vibrational damage on downhole tools.

That’s been our showcase technology. We’re right at the threshold of drilling 100 million feet with CounterForce technology.”

As the speed of drilling continues to increase, another disfunction Ulterra identi-

‘The downturn was definitely helpful to us because decision making became a question of “Who can make a difference for me now?” and not “Who can make a difference for me two months from now?”

- Maria Mejia, CFO, Ulterra Drilling Technologies LP

fied is cuttings evacuation from the well bore.

“Shale laterals are being drilled at such fast penetration rates they’re at nearly an order of magnitude faster than they were five or 10 years ago,” Deen relates. “Where they were drilling 20 to 40 feet an hour, now they’re drilling instantaneously at 200 or 300 feet per NorthAmericanShaleMagazine.com

23

PRODUCTS & TECHNOLOGY

Shale drilling activity rises in the U.S., falls in Canada Although rising oil prices have led to increased drilling rig activity and a rise in U.S. rig counts, it’s been a mixed bag of news for some drilling companies.

Located in Calgary, Alberta, Trinidad Drilling announced earlier this year that it’s transferring eight rigs—including three from Saudi Arabia—to the Permian basin in Texas, noting that the upward momentum seen in the U.S. is not occurring to the same extent in the Canadian industry.

“By moving under-utilized rigs to the Permian Basin, we are able to continue to drive improved activity levels and better profitability,” said Brent Conway, Trinidad’s president and CEO. Trinidad reported that it has 39 rigs (59 percent) from its fleet operating in the U.S—nearly 80 percent of those in the Permian Basin. Because of flat activity in Canada, the company launched a strategic review process to consider alternatives such as a selected asset sale, a merger, a corporate sale, a strategic partnership or capital re-deployment opportunities.

Another Calgary-based company, Akita Drilling, announced the transfer of its Rig 90—designed for deep-capacity, ultra-high specification drilling—from the gas basin of western Canada to the Permian where it will work for a major operator. The company said it expects to find more work opportunities in the U.S., citing low activity and low profit margins prevailing in the Canadian market.

Conway said Canadian drilling companies are facing the issues of trapped oil and gas, as well as wide differentials. “They're living in a world where their costs are going up, our costs are going up in terms of just drilling contractors and what we are being asked to do with our workforce,” he explained.

ConocoPhillips announced its three-year plans for its U.S. shale assts.

The company expects to increase production by 25 percent in the Eagle Ford where it will operate six rigs through 2020. In the Delaware, ConocoPhillips plans to increase production to more than 85,000 barrels per day with the three-rig program. The company plans to grow its Bakken production to more than 400,000 barrels per day with an 11-rig program.

In another development, Tally Energy Services of Houston acquired Texas-based Premier Directional Drilling complement its portfolio of oil field services companies. Premier provides directional drilling services to U.S. land-based and Gulf Coast offshore markets.

24 NORTH AMERICAN SHALE MAGAZINE ISSUE 2 2018

hour. Getting all those new cuttings and formation out of the hole requires new thinking.”

To deal with the problem, the company recently introduced its SplitBlade technology. “SplitBlade is completely focused on cuttings to increase the rate of penetration (ROP). We’ve seen case studies in multiple basins now where we’ve been able to increase instantaneous rates of penetration by 30 to 50 percent—in some cases just by making sure the cuttings being generated are exiting the bit and removed from the hole efficiently.”

Dealing With A Downturn

As Deen notes, the oil price downturn that hit the U.S. shale oil and gas industry primarily in 2015 and 2016 had a negative impact on producers and related businesses around the world. But it wasn’t the first time Ulterra had to cope with a downturn. It was around for and survived the oil price collapse of 2008 and 2009. The most recent downturn provided the company with an opportunity to demonstrate how its approach was not only different, but also better.

“What a downturn does in oil and gas is separate the wheat from the chaff,” Deen says. “We were able to keep doing what we were doing. It’s a little bit of a different take on risk aversion.” In other words, rather than going the route with drilling solutions from what Deen refers to as “the big-box brands,” E&P companies began looking to the faster and nimbler Ulterra for solutions.

“One of the things that happened that we’re most proud of is that as we grew through the downturn, drilling engineers started to see us in a different light,” Deen notes. “These are individuals whose jobs may have been on the line when they had to make decisions based on what was best for them and what was best for their company. That’s when things really started swinging toward Ulterra. When drilling engineers had to make decisions, every single decision counted, and they started trusting us more.”

PRODUCTS & TECHNOLOGY

Mejia says it was Ulterra’s decentralized decision-making culture that enabled it not just to survive, but to thrive.

“If you look at our market share and financial performance through the downturn, that’s when we made our biggest strides,” she states. “It happened when it became important to realize efficiencies, drill faster and bring new products to the field. When the majors were dealing with stopped production, layoffs and trying to sell what they had to conserve some cash, we were innovating and bringing the latest technologies to develop some economic value for the customer.

“The downturn was definitely helpful to us,” Mejia continues, “because decision making became a question of ‘Who can make a difference for me now?’ and not ‘Who can make a difference for me two months from now?’ When we could realize efficiencies faster and save money faster, that’s when we became one of the market leaders. We became a true partner with our customers to help them deliver efficiencies and savings at the local level.”

Last year’s uptick in oil and gas activity in North America helped Ulterra to further expand its business to overseas markets. “It’s made sense for us to do that in international markets where we sowed seeds up to 10 years ago,” Deen says. “A lot of that growth is re-

ally just a response to this. We’ve been very excited, not only keeping up with the market rebound and drilling activity in North America, but growing significantly faster in our own right.”

But, as Deen also notes, Ulterra’s success has provided it with new and different issues.

“One of the things we’re struggling with is to scale up as fast as our customers are demanding while maintaining our culture. That’s really the biggest challenge that we’re facing right now.”

Mejia describes Ulterra’s new challenge as both fun and exciting. “The challenge from an administrative perspective becomes trying to keep up with the growth and trying to build the legal framework and infrastructure that we need to service the client with the same level of speed that we do in North America,” she says. “That’s the goal. Once we penetrate a new market, we don’t want to sacrifice the quality. We want to make sure our manufacturing capabilities have the same ISO and API certificates in Saudi Arabia that we have in North America.”

Providing solutions to technical problems is the easy part because, according to Deen, it’s how Ulterra is hard-wired to operate. “The subterranean lithology doesn’t know the political boundaries that we’ve drawn up top,” Deen relates. “What’s harder

to deal with are the corporate and geopolitical cultures. How do we do business with Saudi Aramco or the Kuwaiti Oil Co. or the Chinese National Oil Co. and do business with XTO and a small company that has one rig running three months out of the year? How do we serve each one of those clients in a way that makes sense to them and still be true to who we are? We struggle more on the side of dealing with really big, bureaucratic companies and very small companies and the challenges that go along with those.”

For 2018 and 2019, Deen says Ulterra plans to continue moving forward as the oil and gas markets catch up and recover from the most recent downturn. “We plan on doing more of the same,” he says. “To us, that means continually changing and evolving and solving the problems of today that didn’t exist yesterday.”

However, Deen’s also realistic about the future, knowing that it’s a matter of time before the industry experiences another market slump. Once again, he believes operators will look to Ulterra’s experience and technology to deliver the drilling optimization that’s yet to be done.

Author: Patrick C. Miller Staff Writer, North American Shale magazine 701-738-4923 pmiller@bbiinternational.com

NorthAmericanShaleMagazine.com

25

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

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Step One: The HYDRO3CIDE automated oxidation system treats produced and flowback water in gathering systems.

Step Two: The portable Hydro-Air Aeration System aerates and mixes water in storage pits and tanks to maintain water quality and prevent bacteria buildup.

Step Three: The HZ80 oxidation system provides the final polish by disinfecting water without chemicals that can be incompatible with frac fluids.

Operators that recycle with the HzO Trio combination have achieved higher quality water for a fraction of the cost of chemical programsâ&#x20AC;&#x201D;less than $0.20/bbl.

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