Issue 1 2017 - North American Shale magazine by BBI International

ISSUE 1 2017

Notice The Change Activity Levels, Service Costs and Market Forces Deﬁne New Era Page 12

Plus Oilﬁeld Majors Explain Next Gen Lifts Page 22

And How Midstream Services Prep For Round 2 Page 28

NorthAmericanShaleMagazine.com Printed in USA

INSIDE

ISSUE 1 2017

VOLUME 1 ISSUE 1

FEATURES

12 The State of Shale

EXPLORATION & PRODUCTION BY LUKE GEIVER After two years in a downturn, the North American shale industry is entering a new era of activity increases, breakeven prices and market variables.

22Pumping Up Shale Pumping Tech PRODUCTS & TECHNOLOGY

BY PATRICK C. MILLER GE Oil & Gas and Weatherford explain why artificial lift technology is better than ever.

28Preparing For Round 2: Lessons Learned INFRASTRUCTURE & CONSTRUCTION

From A Midstream Service

BY LUKE GEIVER As Goodnight Midstream prepares for a new wave of oilfield activity, it exemplifies what midstream companies face in today’s market, and, everything investors are after.

NEWS & TRENDS

28 ADVERTISER INDEX 34

2017 The Bakken Conference & Expo

Applied Air Systems

Baker Huges Inc.

BD Diesel Performance

Flotek Chemistry

Hydrozonix

KLJ

North American Shale magazine

Summit ESP

Wanzek Construction Inc.

Williston Basin Petroleum Conference

Oil Surveys Show Change 10 Bakken Primed For New Round Of Activity 11 Talking With Producers 6

DEPARTMENTS 4

EDITOR’S NOTE

Trust What You See In Shale BY LUKE GEIVER

EVENTS CALENDAR

SPONSORED CONTENT

100 Events in 10 years BY HART ENERGY

ON THE COVER: A drilling rig operates in the Permian Basin. Since the start of the year, rig count in Texas has been steadily rising with renewed interest in the Delaware Basin. PHOTO: NORTH AMERICAN SHALE MAGAZINE

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EDITOR'S NOTE NorthAmericanShaleMagazine.com

Trust What You See In Shale If it feels like you have seen this before, you are right—and wrong. Major shale plays in Texas, Oklahoma, North Dakota and Colorado are ramping up. There are talks of workforce shortages again. Service costs are trending higher. The rig count arrow is pointing up with no indication of change. The term “boom” hasn’t officially resurfaced as a catchphrase chosen to label the state of shale energy production, but in West Texas, there have been new, creative terms Luke Geiver like “Permania” used to describe the new pace of investment EDITOR and field work taking place. North American Shale magazine All of this feels similar to the pre-shale-downturn that lgeiver@bbiinternational.com preceded the period of 2014-'16 when oil prices took a historic roller coaster ride, dipping into the $20/b range. But, we all know this round of renewed activity, this era of shale energy’s brief history will be different (at least we hope). In our inaugural issue, we focused on the variables—from play-specific breakeven prices to the elements that will impact service prices—that will guide the new narrative of shale. In, “The State of Shale,” on page 12, we included insight from operators, frack sand providers, service companies, analysts and researchers on what’s different or the same this time around in the many shale patches of North America. It seemed like the perfect time to produce such a massive, allencompassing piece on the health and trajectory of the unconventional oil and gas production industry in the U.S., just like it felt appropriate (and exciting) to launch this print and online offering. As I said to start, given the enormity of the industry and the familiarity the world now has with the presence of shale energy development, it is as if North American Shale magazine has always existed and been available as an important resource. Our efforts are the natural expansion of The Bakken magazine, published by BBI International, since April 2013 to the present. As our view of where the Bakken play fits into the continent’s larger shale story matured, it became clear that we can better serve all our constituents by expanding the scope of our coverage. We’ll be writing stories on the interconnected, fast-paced changes, challenges and opportunities present in the Permian, Eagle Ford, and other plays, as well as those in the Bakken. We welcome current and new readers to North American Shale. With a new era kicking-off this year, it seemed fitting to concentrate on revamped technology and operating strategies that have evolved to meet the altered demands of oilfield entities. Patrick C. Miller, staff writer, spoke with two oilfield majors—Weatherford and GE Oil & Gas—to gain insight into their respective artificial lift advances designed specifically for shale pumping sites. For a global entity as large as GE Oil & Gas to tell Miller it brings the full weight of its global research and development team to its shale-based equipment upgrades, there is clearly a push to upgrade and improve the way the industry works. Goodnight Midstream, a Dallas-based water handling and service provider that got its start in the Bakken circa 2011 and is now expanding into the Permian, was our way in to revealing how service firms have altered their mindset in this new period of unconventional oil and gas production. The feature, on page 28, was a fitting way to highlight the changes we’ve all seen or experienced in the past two years and also more recently. Time will tell if what we are seeing now is truly close to something we’ve seen before, or, if our times ahead in June, July, August and well beyond that, will be a uniquely prosperous period in the history of North American shale. Trust us, we’ll be there to cover what happens. We, like you and millions more, are part of the story.

VOLUME 1 ISSUE 1 EDITORIAL Editor Luke Geiver lgeiver@bbiinternational.com Staff Writer Patrick C. Miller pmiller@bbiinternational.com Copy Editor Jan Tellmann jtellmann@bbiinternational.com

PUBLISHING & SALES Chairman Mike Bryan mbryan@bbiinternational.com CEO Joe Bryan jbryan@bbiinternational.com President Tom Bryan tbryan@bbiinternational.com Vice President of Operations Matthew Spoor mspoor@bbiinternational.com Vice President of Content Tim Portz tportz@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

Subscriptions Subscriptions to North American Shale magazine are free of charge to everyone with the exception of a shipping and handling charge of $49.95 for any country outside the United States. To subscribe, visit www. 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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NORTH AMERICAN SHALE NEWS

NEWS & TRENDS

Oil Surveys Show Change Niloufar Molvai is quick to point out that the CEO survey her teams helps to run has been around for 20 years. The survey, conducted by PricewaterhouseCoopers, can indicate trends to come and in some cases, Molvai says, how accurately past CEO predictions and thoughts were over time. As the Global Energy Leader for PwC, Molvai pays attention to input from Molvai oil and gas CEOs. This year’s survey showed that oil and gas executives are moving past survival mode and into growth planning. “I think the tide is shifting,” Molvai said. “People are a lot more confident and there is some stability in prices. The cost-cutting measures have changed and now the focus is on growth.” According to the survey, 69 percent of oil and gas CEOs believe organic growth this year is the No. 1 priority. Innovation is also an area where oil execs are focused.

The Path To Growth 2017 FUNDING GROWTH

10%

M&A AND PARTNERSHIPS

10%

DIGITAL AND TECH

10%

HUMAN CAPITAL

13% 18%

INNOVATION INFORMATION: PRICEWATERHOUSECOOPERS DESIGN: BBI INTERNATIONAL

“The industry feels strongly that we will continue to have more automation and we will continue to use technology differently,” Molvai said. “The type of resources you will need will look very different and the skills you will need in the industry will also look very different in the future.” New technology or automated processes won’t necessarily reduce headcount, however. According to the survey, 41 percent of CEOs intend to increase headcount this year while 27 percent may actually decrease headcount. As an experienced accountant who has

worked with major energy clients across the globe, Molvai said that despite the recent industry downturn, many companies have emerged with strong balance sheets. Oil prices are not yet where most want or need them, she added, but stability in pricing has given most the ability to chart an operational course this year. “Overall, I think the industry looks pretty healthy. Strong balance sheets are only going to get stronger as we go through the upturn,” she said.

1998 Years of Change

1st successful shale gas well drilled by Mitchell Energy Annual average gasoline price $1.07/gal UN extends “Oil-for-food” initiative with Iraq Annual average gasoline price $1.24/gal

NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

1997

The Federal Reserve Bank of Dallas performs multiple surveys per year to gauge the mood and health of the region’s oil and gas industry. The Dallas team frequently asks industry participants about general market forces, headcount plans and perceived challenges and opportunities. Early this year, the Dallas team offered a new data set to illuminate the changing health of the oil and gas industry as it pertains to the Permian Basin.

NA SHALE NEWS

Home Sales and Building Permits: In 2014, home sales in Odessa and Midland, Texas, were on the decline. Since oil prices—and activity—have increased, the trend has changed.

Energy Survey Business Activity

From Q1 2016 to Q4 2016, respondents to the Federal Reserve Bank of Dallas

quarterly survey changed their answer on activity levels by nearly 100 percent. Number of permits issued* Diffusion index

Number of homes*

330 310

Permits

120

290

100

270 250

Sales

230

210

190 20

170 150

'09

'10

'1 1

'12

'13

'14

'15

'16

100 80 60 40 20 0 -20 -40 -60 -80 -100

13.8 Q1 2016

40.1

26.7

Q2 2016

Q3 2016

Q4 2016

42.1

*SIX-MONTH MOVING AVERAGE. SOURCE: TEXAS A&M UNIVERSITY REAL ESTATE CENTER.

Breakeven Prices For New Wells

Home Inventories After rising for several months, home inventories in Odessa, Texas, are now declining with an increase in oil-related activity. Months*

Active rigs

Permian Basin rig count

Odessa inventories 6

500

400 Midland inventories

300 3 200

100 0

1 '10

'1 1

'12

'13

'14

'15

'16

In early 2016, many operators believed oil prices needed to be in the $70/b range to reach breakeven operation levels. The Dallas survey shows much has changed in 2017. Dollars per barrel 100 90 80 70 Louisiana 60 $50 50 40 30 20 10 0 3

Onshore Gulf Coast Permian Eagle Ford Other U.S. Other Texas Oklahoma Basin $51

$53

$55

$56

$62

Number of responses

*SEASONALLY ADJUSTED, SIX-MONTH MOVING AVERAGE. SOURCES: TEXAS A&M UNIVERSITY REAL ESTATE CENTER; BAKER HUGHES.

OPEC agrees to cut its overall production by 1.2 million barrels a day

2008 Crude oil prices break $100 for ﬁrst time in history

Annual average gasoline price $2.25/gal

2016

Oil prices start dramatic decline due in part to excess global supply Annual average gasoline price $3.44/gal

2014 2006

Crude oil traded over $79/b, setting an all-time record high Annual average gasoline price $2.62/gal NorthAmericanShaleMagazine.com

NA SHALE NEWS

CAVERNS OF OIL: The Bryan Mound site near Freeport, Texas, is the largest Strategic Petroleum Reserve facility. Managed by Fluor Corp., it is the largest man-made oil storage container in the world. PHOTO: FLUOR CORP.

US Strategic Petroleum Reserve undergoes changes For the first time since 2014—and only the third time since 2005—the U.S. Department of Energy has sold a portion of its stockpiled oil from the Strategic Petroleum Reserve this year. The sale of 8 million barrels of sweet crude will be used to pay for maintenance and infrastructure upgrades to the SPR’s storage facilities. Starting in 2015, the DOE began a $2 billion modernization effort. The sale of crude is used to pay for the modernization work. Outside of sales completed for maintenance and infrastructure updates, the SPR’s stock is rarely tweaked. In 2011, the president directed 8

Past sales for the SPR include

2014 - March 2011 - June

IEA Coordinated Release - 30,640,000 barrels

2005 - September 1996 - October 1996 - April

Test Sale: 5 million barrels

Hurricane Katrina Sale - 11 million barrels

Budget Deﬁcit Reduction Sale - 10.2 million barrels

Budget Deﬁcit Reduction Sale - 12.8 million barrels

1996 - January Weeks Island Decommissioning Sale - 5.1 million barrels 1991 - January

Desert Storm IEA Coordinated Sale - 17.3 million barrels

1990 - September 1985 - November

Desert Shield Test Sale - 4 million barrels

Test Sale - 1.0 million barrels

the sale of 30 million barrels of crude to offset disruptions to the oil supply due to unrest in the Middle East. According to the SPR, the 713.5 million barrels in its series of salt

NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

cavern storage facilities located along the Gulf of Mexico (where several refineries can have quick access to the crude) can help the US withstand 149 days of oil import disruptions.

The idea for the SPR started in the 1950s following the 1956 Suez Crisis.

NA SHALE NEWS

POWERING PAST THE IMPOSSIBLE: From high-tech astronaut suits to lipstick, the American Petroleum Institute’s new campaign is focused on highlighting the role oil and gas plays in creating many of the newest materials or products used today. SOURCE: AMERICAN PETROLEUM INSTITUTE

Light tight oil in the SPR? The U.S. Energy Information Administration, a division of the DOE, believes that by 2040 tight oil will make up for the majority of any production increases. Troy Cook, senior global upstream analyst (and petroleum engineer by training) helped to create the EIA’s projections on light tight oil. “The application of two existing older technologies, horizontal drilling and hydraulic fracturing, combined with the higher prices within the past decade, made the experimentation and then full scale application of these technologies possible,” Cook said. “In the future, cost reductions based on learning by doing and optimization of both drilling and completion practices will continue to allow development in the current lower-cost environment that this development helped create.” Technologies and strategies utilized to retrieve light tight oil in the known formations of today could evolve, according to Cook. “I believe the idea of a previously known but generally discounted resource could spring to life and at such high volumes in such a short period of time,” he said. “The proven reality of light, tight oil and available resources of the same type not yet exploited, has been substantial enough to alter expectations of future U.S. oil production.”

Why API says, “This ain’t your daddy’s oil” After a decade spent urging Americans to vote for domestic oil and gas production—due to its job creation and foreign oil independence ability—the American Petroleum Institute is telling a new story. During this year’s Super Bowl, API unveiled a new campaign that attempts to explain how oil- and gas-based products are unable to make the impossible, possible. The Super Bowl ad, and subsequent marketing campaign that has hit print, digital and other outlets, used a slogan to relay a change API believes we should recognize when thinking about oil, “This ain’t your daddy’s oil.” The commercial used images of lipstick, prosthetic limbs, pumping hearts, futuristic

sports cars and astronauts. Jack Gerard, API president and CEO, said the campaign included the products and technological advances to show what has been made possible by oil and gas. “From lifesaving medical devices to cosmetics at the drug store from plastics in our toys and cell phones to 3D printers, Power Past Impossible demonstrates how natural gas and oil provide value well beyond just transportation fuels or cooking and heating,” he said. “Just five years ago,” he added, “no one would have imagined the U.S. could increase production and refining of oil and natural gas while cutting greenhouse gas emissions, which today are near 25 year lows.”

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NA SHALE NEWS

Bakken primed for new round of activity A coalition of businesses, leaders, workers and citizens believe the Bakken is well positioned to handle increased activity. “Industry has been spending billions of dollars on infrastructure in North Dakota,” said Dean Bangsund, an economist at North Dakota State University, who studies the impact of the oil and gas industry on the state. “It bodes well for what industry feels is available to them in North Dakota. I don’t think we’d see this investment if things were going the opposite direction.” Bangsund joined other speakers during a one-day event held in March in North Dakota’s capital city Bismarck. The event is organized by Bakken Backers. Steve Johnson, vice president of government relations at ONEOK and ONEOK Partners, added credence to Bangsund’s statements. In the past five to seven years, ONEOK has invested $3.5 billion in North Dakota pipelines, gathering

systems and processing plants. “Our focus in 2017 is to expand gathering systems to meet completed and uncompleted wells. In the last seven years or so, we’ve been trying to catch up with everything that’s been going on,” he said. “Now we’re almost at the point where we can keep up. We’re willing to invest hundreds of millions more dollars as needed.” Trey Wilson, CEO of MBI Energy Services, said that although the low-oil-price environment forced his company to drop roughly 1,300 employees, he sees a change coming. “We will be adding hundreds of jobs and our competitors will be doing the same thing,” he said. “Drilling activity is a huge drive for the need of oilfield services.” In March, the state had roughly 44 rigs running, up 10 from the same time in 2016. As the rig count continues to increase and frack crews work down drilled but yet to be completed wells, Wilson believes

Petroleum Industry Investment in Infrastructure 2011 - 2015 Billions (2015$)

2011 = $2.8 billion 2013 = $3.4 billion 2015 = $2.6 billion

Gas Midstream Processing (excluding Plants above)

Crude Oil Crude Oil Gathering Pipelines Rail Loading Systems

Water Housing Related Treatment and Lodging Facilities Office and

Misc.

*INFORMATION FROM NORTH DAKOTA STATE UNIVERSITY AGRIBUSINESS AND APPLIED ECONOMICS

ND vs TX: The Gross Value of Oil Gross Value of Oil North Dakota

Texas

$16,881,920,400

$52,428,850,800 ND TX

Value of Oil Per Capita $22,273

$1,882

*INFORMATION FROM THE NORTH DAKOTA TAX COMMISSIONER

North Dakota is in a better position now than it was the last time activity levels ramped. “I’m tremendously impressed with the growth of infrastructure; this is a wonderful place to live and

work,” Wilson said. “We have to do a better job of telling the rest of the country what’s going on here, why it’s a good place to work and raise a family. North Dakota has a lot to offer.”

50,000 bpd, $450 million refinery slated for Permian West Texas could be home to the newest oil refinery in the U.S. MMEX Resources Corp., has proposed a 50,000 barrel per day processing facility near Fort Stockton, Texas. For $450 million, MMEX intends to build on a 250-acre plus site near the Sulfur Junction spur of the

Texas Pacifico Railroad. The site will allow MMEX to export diesel, gasoline, jet fuel, liquefied natural gas and crude to western Mexico and South America. “The existing facilities and pipeline networks are largely unequipped to handle this growth [happen-

10 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

ing in the Permian] and are limiting where products can be transported,” said Jack Hanks, president and CEO of MMEX. Construction could begin starting early next year. Roughly 400 workers will be needed to build the facility and it could take 18 months. The team has already

amassed 30 years of experience building and managing multi-million dollars processing, pipelines, power plants, refinery and oil and gas operations in both the U.S. and Peru.

NA SHALE NEWS

Permian database uncovers undocumented wellbores To map-out the world’s hottest shale play, TGS, a global provider of geoscientific data products, had to put forth a monumental effort. A team of data entry experts, geologists and software developers relocated and redigitized well logs, processed directional surveys, digitized mud, lithology and stratigraphy data, picked formation tops, developed three basin temperature models, created GIS polygons of fields, pools and formations, and, aggregated production volumes for different geologic layers in each field. “Tens of millions of dollars of investment later, we have the most complete, top-to-bottom, basin-wide view of the Permian available,” the company said. TGS, which historically has processed and sold spatially and rotationally directional surveys to individual clients, said that it has found that thousands of wellbores within well file documentation and directional survey reports do not match up with well logs and other wellbore related data. “As the industry moved more and more rapidly toward horizontal drilling and directional drilling, more and more data came through our operational facilities showing similar anomalies,” TGS said. “In fact, we found a significant number of the well-

bores in the shale plays to be wellbores Crude Layers not previously identified elsewhere.” The newly identified data has helped operators working to put in hori0 zontal boreholes in mature fields with a legacy of vertical wells like the Permian. “The health, safety and environment risks alone were enough to make com2,000 panies take pause and think about what might be down there they may not be OIL AND aware of.” GAS DEPOSITS With files on more than 430,00 4,000 wells, including thousands of previDELAWARE ously unidentified wellbores, the TGS MOUNTAIN team believes it now has a subsurface GROUP geological framework for a wide variety 6,000 of users, including E&Ps, A&D teams, engineers, financial companies and service companies. The process utilized to sift through 8,000 the data and create the database has AVALON also helped TGS prove a repeatable approach to creating a similar offering BONE in other places. “Through the Permian SPRING project, we have established a complete 10,000 model and workflow of how to approach the next area of interest,” they WOLFCAMP said. To date, the team is almost done with an Anadarko Basin database. A 12,000 product for the Eagle Ford and Bakken is also in the works.

Talking with Producers Western Reﬁning Logistics is also working to capitalize on the growing production rates in the Permian. The company’s board has set aside $27 million for 2017 gathering line construction projects in the region. Jeff Stevens, president and CEO, said WRL is already in advanced talks with producers targeting the Delaware Basin. “We continue to believe that particular growth opportunities exist, particularly in the Permian. As producers announce more production growth, we’ll have the opportunity to build more.

NorthAmericanShaleMagazine.com

EXPLORATION & PRODUCTION

THE STATE OF SHALE After years of historic growth, followed by two years of downturn, the North American shale energy industry is on the brink of a new, unprecedented era. By Luke Geiver DAWN OF NEW ERA: The scene today in the Permian Basin includes heightened activity levels to complete DUC wells and to drill new wells. PHOTO: NORTH AMERICAN SHALE MAGAZINE

12 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

EXPLORATION & PRODUCTION

In the brief history of the North American shale energy industry, there have already been both boom and bust years, but today, in early 2017, the shale world is on the precipice of an entirely new eraâ&#x20AC;&#x201D;one not clearly linked to any period of the past. After buzzword talking points focused on low-price-environments or breakeven costs dominated discussions on the health and stability of unconventional drillers and frackers for the past twoplus years, a new storyline is emerging. The industry is

not booming in the way it once did when drilling rig numbers were double what they are today. The industry is not, however, caught in stagnancy or suffering in a downturn. Technological gains, industry know-how and the evolution of world oil markets have evolved quickly. In 2017, the state of shale appears to be approaching significant activity level ramp-ups that could redefine the way the industry is described, how it thrives or even survives in the years to come. NorthAmericanShaleMagazine.com

EXPLORATION & PRODUCTION

Paying To Play Is Paying Off From 2015-’16, merger and acquisition activities for shale acreage or assets skyrocketed by 117 percent compared to the previous Some energy service companies are tweakyear. Efforts by operators, drillers and service companies during the ing customer retention strategies; others downturn (2014-’16) paved the way for the massive shift in investment, are buying up used horsepower. according to Brian Lidsky, managing director at PLS Inc., a Houstonbased information and transaction advisory firm. The industry focused Rethinking market share – Halliburton on three areas, Lidsky says, including: decreasing operational costs, inachieved a company-level record market creasing recoveries and practicing capital discipline or spending only share in 2014-’16. In recent months, the based on incoming cashflow. Rig counts have risen across most major global energy services firm has ceded plays since mid-2016, including the Bakken, Permian, Eagle Ford and some of that share for strategic purposes. Marcellus, thanks in large part to those efforts and a leveled-off oil price. Those efforts to focus on operations, efficiencies and spending habInstead of contracting to firms looking for its have greatly altered the price of oil at which E&Ps need to make a lower service fees, Halliburton is keeping 10-percent-plus return on the investment required to retrieve a barrel of oil equipment available for customers lookfrom West Texas to Western North Dakota. For comparison’s sake, many ing to ramp-up at higher costs. oil analysts believe $60 oil is the new $100 oil. Andrew Dittmar, an upstream analyst at PLS, said M&A activity and general drilling and completion activConfident with the FRAC symity in several shale plays looks bright this year because of the real ramificabol – After acquiring the North Ameritions linked to the efforts of E&Ps to change in the downturn. can assets of Trican, Houston-based No shale region has seen more investment or rebound in activity than energy service firm Keane Group has the Delaware Basin located in West Texas and Eastern New Mexico. The $18 gone public on the New York Stock Exbillion in new equity that was invested in the sub-play of the greater Permian change using the ticker symbol FRAC. Basin earned it “the play of the year” moniker from Dittmar’s team. NewspaWith the purchase of Trican’s assets in pers from the Odessa and Midland, Texas, regions have run headlines with the 2016, Keane now has 950,000 horseterm Permania (the Delaware Basin resides on the western edge of the greater power available for pressure pumping. Permian Basin). “People knew there was a lot of oil in place there,” he says, In mid-2016, Liberty Oilfield Services noting that it took experts longer to crack the geologic and technological code acquired the North American assets for economically retrieving the oil there. “In 2016, it looks like they cracked the of Canadian-based pressure pumper code.” Sanjel Corp. In one year’s time, acreage costs increased from $10,000/acre to $30,000/ acre in the Permian. Daniel Fine, a noted oil and gas expert who has worked The right time to buy – Basic Enfor multiple New Mexico research institutions and the New Mexico governor’s ergy Services and Mammoth Energy budget office, says an oil and gas auction in Roswell, New Mexico, three months Services have purchased additional ago included land deals in the $50,000/acre range. “Everybody is excited and oppressure pumping horsepower and timistic there [in the Delaware Basin],” he says. “The outlook is good. Even at $40 additional fracking equipment. Basic oil, the rate of return would still be above 10 percent.” purchased 74,000 hp and additional Private equity investors might currently be funneling capital and equity into equipment for $28.5 million—or just the Delaware Basin because of a new operational model created by large oil prounder $400/hp. Mammoth chose ducers during the downturn, but Dittmar expects activity to spread. In both the to buy new and purchased 57,500 Bakken and Eagle Ford, deal activity climbed in 2016. “We expect those plays to be hp and associated equipment for big winners when we come into 2017,” he said. “As confidence builds in oil prices under $500/hp. Mammoth said that we are going to be above $50/b, we are going to see more interest in those oil buying new was a better option to plays. There will be less to buy in the Delaware.” meet the requirements and perforInvestors have already regained their confidence in shale, says Stephen Berman, mance standards it has. Basic was senior equity research manager at Canaccord Genuity. After two years of market content with its equipment—built fluctuations created by OPEC production actions, Berman believes both OPEC and between 2013 and 2014—and investors understand why shale is a long-term venture even after two-years in a downwill add software upgrades to all turn. “OPEC realized after two years they weren’t going to put U.S. shale as an industry pumps to fit Basic’s sophisticated processes.

Pressure Pumper Activity

14 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

out of business,” he says. “Now, we compete very effectively in a $50/b oil world. I think OPEC and the rest of the world see that the U.S. shale industry is here to stay and I think investors realize that now too.” Mangesh Hirve, chief operating officer for global oil and gas research firm 1Derrick, believes it’s not only U.S. investors who are back onboard with U.S. shale. Investors in Europe and Asia are eyeing positions in the U.S., currently with a focus on the Permian. Some have taken creeping positions as they wait to pounce on attractive acreage or companies. Early investors have already made good money, he says. According to Hirve, international investors want to see oil plays at the discovery or near production stage that they can enter and quickly experience production or production gains. European and Asian investors don’t want long-cycle projects, he says. Many pay in cash and want to diversify their portfolios. In the Permian, he says, “you can start production and in two months’ time the money hits your bank.”

The New Reality of Production Trish Curtis, president of oil and gas research and economic analysis firm PetroNerds LLC, knows why investors and E&Ps are ramping up activity plans at $50/b oil. Curtis has performed extensive research on the shale energy production industry, traveling from London to Saudi Arabia to North Dakota to speak on her research. For the Oxford Institute for Energy Studies, she outlined why cheerful and hopeful talk from many operators in 2015 and 2016 was not merely fluff. In her research paper, “Unravelling the US Shale Productivity Gains,” Curtis was able to dissect and highlight just how far operators have come the past three years on the production front. “You know companies are very bullish about their own operations,” Curtis says. “You can’t just believe them, though. You have to actually look at what they are doing.” “When you started looking at production figures for several companies, individual well production was looking good. You could see a pretty distinct change,” Curtis says. “What was impressive is that you weren’t just seeing it in one spot. You were seeing it with all kinds of companies in all types of basins.” During the downturn, the forced requirement by operators to spend within cashflow and the need to produce more with less helped the industry change course. According to Curtis, not everyone totally grasps the level of change that has occurred or the

RISING DEMAND: Workover rig demand has increased this year as operators work to put previously drilled but uncompleted wells onto first production. PHOTO: ENCANA CORP.

NorthAmericanShaleMagazine.com

The Mood On Sand Two of the biggest frack sand suppliers to the North American shale industry are experiencing the effects of improved market activity rates and a broad industry push to pump more sand downhole than it did three years ago. Wells completed in most U.S. shale plays today versus three years ago pump roughly three to 10 times as much sand downhole. HiCrush Partners LP said that, beginning in January, the Houston-based sand supplier with four mines spread throughout Wisconsin, has been sold out of every grain and every grade of frack sand it sells. “It is undeniable that we are seeing a substantial increase in demand for our products and services even though we are only in the early stages of a market recovery,” Robert Rasmus, CEO of Hi-Crush said. Gary Kolstad, CEO of Carbo Ceramics, is also optimistic about the prospects for 2017. Revenue projections for 2017 appear on track for a 40 percent to 50 percent increase compared to the previous year. Like Hi-Crush, the Carbo team believes industry will continue to contract for sand over the more expensive engineered ceramic proppant. “The current commodity price environment continues to lead E&P operators to generally focus on the lowest upfront completion cost,” Kolstad said. In addition to its oil and gas sand and ceramic supply business, Carbo will continue consulting for fracture stimulation jobs this year. Other industries will garner some outreach from Carbo as well.

long-term impact it could have on activity levels in the industry and the global oil supply picture. The well productivity gains achieved in the downturn have been outstanding, Curtis says, pointing to well production type curves in nearly every basin that reveal wells drilled and put onto production today will produce more during initial production periods and decline less over time than previously drilled wells fracked in the same areas. “I think a lot of folks did not realize how these new wells were actually performing. I think people sort of discounted that and thought operators were just highgrading or putting more sand down the well. But, when you look at the decline curves, it is clear the gains are real,” Curtis says. The implications from the gains are also real, and not yet fully understood, she adds. People don’t truly understand what the productivity gains mean yet because they happened so fast at a time when the focus was on depressed oil prices and OPEC actions. “You can’t really unlearn this stuff. The fact that they are getting more oil out of these wells is very impressive,” she says. “That has very significant and long-term ramifications for U.S. production.” 16 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

M&A in U.S. Unconventional (in $ million) SOURCE: 1DERRICK

In 2016 UP

DOWN

71%

26%

from 2015 ’08

’16 ’16

ASIA PACIFIC BUYERS ’08

In 2015 UP

405% from 2014

’16

EUROPEAN BUYERS

’08

DEAL VALUE

356 million In 2016, Carbo sold 356 million pounds of ceramic proppant and 311 million pounds of northern white sand

819 million In 2015, Carbo sold 819 million pounds of northern white sand and 818 million pounds of ceramic proppant

$40/ton Already this year, Hi-Crush is seeing $40/ton pricing at the mine gate. Rasmus believes the price for sand will not dip below this price for the remainder of the year.

$275 million In the heart of the Permian Basin, Hi-Crush has paid $275 million to acquire a 1,226-acre sand reserve that holds more than 55 million tons of 100 mesh sand. For $50 million, Hi-Crush intends to build a processing facility that will produce 3 million tons of sand per year, starting in Q4 this year.

DUC Inventories in Key Shale Liquids Basins vs. WTI SPOT Price Dec. 2014: Point at which accumulation of DUC inventory is more likely to be driven by oil prices, $120 as opposed to pressure pumping blacklogs and other operational factors. Eagle Ford DUC

1,800 1,600

$100

DUC Inventory

1,400

WTI Cushing Avg. Spot Price, USD/bbl

1,200 800

Permian DUC

$80

Bakken DUC

$60

600 Niobrara DUC

400 200

False Price Rally #1: Early Permian & Bakken DUCs get completed

False Price Rally #2: Fewer DUCs completed

$40

$20

WTI Cusing Monthly Avg. Spot Price, USD/bbl

Aggregated Well Productivity and Per Well Costs Index, 2005 = 100

Index, 2005 = 100 Cost (2005 $ / Well Index)

160

400

140

350

120

300

100

250

200

150

100

20 0

Productivity (boe/well index) Jan 86

Jan 88

Jan 90

Jan 92

Jan 94

Jan 96

Jan 98

Jan 00

Jan 02

Jan 04

Jan 06

Jan 08

Jan 10

Jan 12

Jan 14

Jan Nov 16 16

SOURCE: RICE UNIVERSITY’S BAKER INSTITUTE FOR PUBLIC POLICY

Dec Feb Apr Jun Aug Oct Dec Feb Apr Jun Aug Oct Dec Feb Apr Jun Aug Oct 13 14 14 14 14 14 14 15 15 15 15 15 15 16 16 16 16 16 SOURCE: RICE UNIVERSITY’S BAKER INSTITUTE FOR PUBLIC POLICY

NorthAmericanShaleMagazine.com

EXPLORATION & PRODUCTION

Operator Spotlight Curtis is specifically impressed with new completion designs and strategies used in the past two years. Operators today are attempting to keep fractures closer to the well bore to drain the surrounding reservoir more efficiently. With fractures closer to the well bore, more well bores can be drilled without fear of a nearby well bore’s fracture network bleeding into a neighboring well. More drillable locations (that don’t impact production for a neighboring well) means the recovery factor of a field increases.

Production Gains Have Chance To Shine With oil prices steady at or above the $50/b mark, private equity backing and a new leaner and meaner approach to operational efficiency, producers and their bullish talk will now be put to the test in 2017 and beyond. Already, capital spending and budget plans are distinctly up from the previous year. Kenneth Medlock, senior director for the Center of Energy Studies at the Baker Institute of Public Policy at Rice University, spoke with completion engineers, drilling contractors and analysts to reveal the true ability of shale producers to scale-up activity in 2017. “The recent increase in oil prices on the heels of OPEC’s agreement for production cuts stimulated a lot of commentary on how rapidly U.S. shale pro-

Early-year capital spending plans by many operators targeting a North American shale play are up from 2015 and 2016 budgets. The trend among most is an increase in capital for drilling rigs and completing drilled but uncompleted wells. Some E&Ps are even setting aside capital for future land purchases, midstream build-out projects or other activities. The following is a brief snapshot of operator plans for 2017, all of which have increased numbers for their respective rig programs, well completion plans and capital budgets from the previous year.

WPX Energy Rig program: 2 Williston Basin; 5 Permian; 1 San Juan Completion/Well Plans: Bakken (42); Wolfcamp (100) Capital plans: $260 million Williston Basin; $510 million Permian; $170 million San Juan Of Note: WPX Energy used the release of a multi-year growth plan to its advantage in forming service contracts before it incurred service prices increases. Through 2017, roughly 70 percent of all contracts for drilling and completions have been locked in.

Encana Corp Rig Program: 5 Permian Basin; 2 Eagle Ford; 1 Montney Completion/Well Plans: Permian Basin (145); Eagle Ford; Montney Capital Plans: $800 million Permian Basin; $250 million Eagle Ford; $460 Montney Of Note: Using intel and completion know-how from one basin, Encana has found a way to effectively implement completion and production changes into a different basin in less than 12 weeks to enhance completion designs and overall production across multiple basins.

Cimarex Energy Co Rig Program: 8 Permian Basin; 10 Mid-Continent Completion/Well Plans: Wolfcamp; Meramec Capital Plans: $1.2 billion total, with 66 percent headed toward Texas operations. Of Note: The possibility of rising services costs may require Cimarex to pump less sand downhole per well, but that scenario does not bother the Cimarex team. The company does not focus on pounds of sands per foot, but instead analyzes how effective sand is pumped and placed per frack cluster—or entry point—into the horizontal well bore.

Whiting Petroleum Corp Rig Program: 5 Williston Basin; 1 DJ Basin Completion/Well Plans: Bakken, Three Forks; Niobrara Capital Plans: $580 million Williston Basin; $420 million DJ Basin Of Note: Well productivity gains experienced by Whiting in the Williston Basin are not related to geology, the company said. Production increases—which are spread out across Whiting’s entire basin position—are now the norm.

Decline Curves in North American Basins

2011

2012

Permian Basin - New Mexico - Wolfcamp b/d

2013

2014

2015

2016

Permian Basin - Texas - Wolfcamp b/d

1,000

600

800

500

600

400

300

200

200 100

0 3 6 9 12 15 18 21 2427 30333639424548 51 5457606366 Months

0 3 6 9 12 15 18 21 24 27 30 33 36 3942 4548 51 54 57 60 63 66 Months

SOURCE: PETRONERDS, RAW DATA DRILLINGINFO

18 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

Marathon Oil Rig Program: 10 SCOOP/STACK; 6 Eagle Ford; 6 Williston Basin Completion/Well Plan: SCOOP/STACK (100); Eagle Ford (170); Bakken (75) Capital Plans: $660 million SCOOP/STACK; $660 million Eagle Ford; $660 million Williston Basin Of Note: Marathon is shifting its focus to U.S. onshore opportunities where it believes it can grow production by 20 percent from Q4 2016 to Q4 2017.

Anadarko Petroleum Corp Rig Program: 14 Permian Basin; 6 DJ Basin Completion/Well Plans: Delaware, DJ Basin Capital Plans: $820 million Delaware Basin; $840 million DJ Basin Of Note: Oil production in the company’s Delaware Basin position will increase by roughly 80 percent year over year. Al Walker, CEO of APC, called the company’s Permian/Delaware asset “easily the most exciting.”

Antero Resources Corp Rig Program: 7 Marcellus/Utica Completion/Well Plans: Marcellus/Utica (170-with another 30 DUCs) Capital Plans: $1.3 billion Marcellus/Utica Of Note: With ﬁve completion crews contracted this year already, Antero expects more may be needed. And In 2018, the number of frack crews needed should double.

Continental Resources Corp Rig Program: 5 Williston Basin; 11 SCOOP/STACK Completion/Well Plans: 131 gross Bakken DUCs; 17 new Bakken wells; 132 new SCOOP/STACK wells Capital Plans: $1.9 billion Bakken, SCOOP/STACK Of Note: For the investment into completing DUCS, Continental believes it will receive a 100 percent rate of return. This year, Continental intends to invest $230 million into land acquisitions, facilities or other activities.

Williston Basin b/d

600 500 400 300

PROVIDING COMPREHENSIVE SERVICES FOR ALL OF YOUR OILFIELD NEEDS INCLUDING SURVEY, RIGHT-OF-WAY AND ENVIRONMENTAL EXPERTISE.

200 100 0 3 6 9 12 15 18 21 24 27 30 33 36 39 42 45 48 51 54 57 6063 66 Months

NorthAmericanShaleMagazine.com

ARE WORKERS READY, OR AVAILABLE: The ability of drilling rig contractors to rehire or fill open positions needed to operate rigs in Texas, North Dakota or Oklahoma has not yet been an issue, according to most operators and drilling teams. PHOTO: ENCANA CORP.

ducers would respond,” Medlock says. “We have been tracking the changes in costs for upstream activity in the U.S. and have noted both productivity changes as well as renegotiations with upstream service providers,” adding that “disentangling the two issues is fundamental to understanding how domestic production will respond.” Medlock’s team examined which challenges producers will face during ramp-up efforts that will come in two phases: completing previously drilled but uncompleted wells and drilling new wells. Revamped activity levels could put a crunch on service company equipment and manpower availability, which in return could increase—if it hasn’t already—the price operators pay for pressure pumping and other well-related services. An increase in prices may impact breakeven prices, driving them higher and reducing operators’ chances at reaching acceptable rates of return at oil in the $50 to $60 range. Production gains achieved during the downturn could offset the service cost in-

creases expected with higher oil prices, but to what extent Medlock’s team is uncertain. From 2014 to 2016, the dollar-per-barrel cost declined by 63 percent and the dollarper-well cost declined by 34 percent. This indicates the production per well increased during that two-year span, and, of the perbarrel cost reductions that took place in 2014-’16, 69 percent came from productivity gains and 31 percent came from service cost reductions. If productivity gains do not persist at the same time service-costs rise, Medlock’s team questions how breakeven pricing will look at current oil strip prices. “The degree to which productivity persists is a critical element in understanding the responsiveness of shale to price increases,” the team said in its report. Operators in the Bakken, Permian, Eagle Ford and Marcellus shale have offered a clear indication that production, and any gains made in the past two years will be tested this year. Both the messages to investors and contracts signed with service companies

20 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

and rig providers show 2017 will be a massive departure from the 2014 to 2016 downturn. Rig counts are up and rising in most plays, sand providers are counting on revenue growth from contracts or conversations already had with operators and, as Medlock says, what hasn’t killed existing shale players has made them stronger. “Those who have weathered the last couple of years will take no solace in this, but many firms in the industry had built up a good bit of internal redundancy as things ramped up through 2014,” he says. “To the extent that this redundancy was unnecessary, going through a downturn will force firms to rationalize all of their costs. So, as they shale industry emerges into 2017, it is in many ways reflective of survival of the fittest.” Author: Luke Geiver Editor, North American Shale magazine 701-738-4944 lgeiver@bbiinternational.com

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PLEASE VISIT WBPC.CA

2-4 2017

MAY

E V R A Z

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PRODUCTS & TECHNOLOGY

PUMPING UP

SHALE

Structural Bearings 1 Counterweights 2

PUMPING TECH Weatherford and Lufkin—two giants in the artificial lift field—have introduced technology innovations to make crude extraction safer, less costly and more efficient By Patrick C. Miller

The well-known song about the city of New York proudly proclaims that if you can make it there, you can make it anywhere. The same concept might also apply to artificial lift technology used in the Bakken shale formation of western North Dakota. If it works there, it can also be deployed successfully in the Permian, Eagle Ford and other shale plays around the U.S. The Bakken is known for its extreme weather conditions. Summer temperatures can soar above 100 degrees Fahrenheit and plunge to -30F in the winter. The geology ranges from sandy, silty soils on high elevations to bog-like clays in low elevations. The remoteness of many wells

Cranks

Crank Shaft 4

makes maintenance and logistics a major challenge. Well depths below 10,000 feet, multiwell pads and the corrosive nature of the fluids and frack sand also present difficulties in the Bakken. Among the most recognized names in the artificial lift systems business operating in this region are two Texas-based companies—Weatherford Corp. and Lufkin Industries Inc. Their names are a common sight on the pumps dotting the landscape of the plains, hills and valleys throughout the Williston Basin. Years of experience operating in the basin have spawned innovations and technology modifications to cope with a multitude of challenges created by the climate, geology

22 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

Gear Reducer 5

and remoteness.

GE’s Gen2 Solutions GE Oil & Gas acquired Lufkin in 2013 to add artificial lift systems to its energy industry portfolio. John Mart, business operations leader for coproduction solutions, came to Lufkin from the energy generation side of GE where he worked with gas turbines. He sees the advantages of calling upon the considerable resources of GE. For example, in the Bakken and the Permian, a common concern among operators is the variety of impurities from frack sand and flow-back that scratches and erodes the metal at the top of the

PRODUCTS & TECHNOLOGY

6 Walking Beam 7 Horsehead

8 Samson Post 9 Crank Pins

10 Unit Assembly 11 Unit Base

THE NEXT GENERATION: The new Lufkin Pumping Unit Gen 2 from GE Oil & gas is designed to be lighter, safer and more efficient. SOURCE: GE OIL & GAS

‘We brought the full weight of our global research and development team to redesign and almost reimagine this product.’ - John Mart, business operations leader for coproduction solutions, GE Oil & Gas

pumping unit, resulting in a reduced production rate. Mart says GE provided an off-the-shelf solution. “We’ve been able to take this really tough Dura Plus coating—it’s the same stuff that comes from our aviation business and is used on our electric submersible pumps—and we’re able to bring that to our sucker rod pumps downhole as well,” Mart explains. Lufkin works with its oil and gas customers to identify problems, then filters them back through GE’s engineering organization for potential solutions. “When you see a problem, you get enough people to get the sparks going

to bring that creativity and those onthe-shelf technology solutions to bear on whatever problem the industry’s having,” he says. According to Mart, Bakken operating conditions were specifically considered in designing a new rod lift system called the Lufkin Pumping Unit Gen2 technology recently released to the market. “We brought the full weight of our global research and development team to redesign and almost reimagine this product,” he says. “We started with problems we heard in the field. Some of our key customers listed safety as a top priority. Anything we can do to protect NorthAmericanShaleMagazine.com

SOLID FOUNDATIONS: Weatherford and Lufkin have adapted the installation of their artificial lift systems to the conditions of North Dakota's Bakken where soil conditions and temperature extremes can cause the pump units to shift over time. PHOTO: NORTH AMERICAN SHALE MAGAZINE

the crews and reduce lost-time events, we knew customers were interested in.” One improvement enables the use of a torque wrench to precisely tighten nuts rather than what Mart calls the archaic and less safe method of using a hammer wrench. Reliability has been improved with a redesigned, heavy duty gearbox to deal with well depths in the Bakken and the wear and tear it creates. “It’s really a beefier product that can handle the load that you’re going to see up here,” Mart says. “A nice benefit of this is that when you scale up some of the pieces that handle the critical loads and the safety factors—from an engineering standpoint—those all get improved across the system.” The new pump weighs about 10,000 pounds less than previous artificial lifts, reducing logistics costs. To minimize sagging problems in the Bakken, loading has been optimized to lower the weight on the front near the wellhead. “You can use a smaller concrete pad and it’s going to perform better in what can be soggy conditions,” Mart notes. Another industry trend Lufkin is addressing is a move away from simple controllers—essentially an on/off switch on a timer. “Folks are looking for a more connected oilfield,” Mart explains. “In response to this we’re releasing the Lufkin Well Manager 2.0 rod pump controller. It’s a brand new controller that actually uses the same internals as the GE platform that controls gas turbines and wind turbines. It’s a consistent control platform with totally rewritten software. We’re able to do things to optimize around the way the pump unit works.” Mart says Lufkin redesigned its new pumps as a complete system. “It’s not just the pumping unit topside,” he explains. “It’s the controller, the pumping unit and then the downhole pump as well. That’s really what you need to make this thing work.”

Weatherford’s Advanced Options Weatherford develops artificial lift products and production optimization capabilities by applying its specific technology, understanding and expertise, not only to help operators develop new oil 24 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

DUC OPPORTUNITY: With hundreds of previously drilled but uncompleted wells set to go on first production this year in several shale plays, the need for pumpjacks will be great in 2017. PHOTO: NORTH AMERICAN SHALE MAGAZINE

and gas resources, but also to assist them in maximizing recovery from producing reservoirs. Jordan Binstock, Weatherford’s U.S. product line manager for sucker rods and rod pumps, says the company’s approach centers on evolving artificial lift technology—whether it’s rod lifts, jet pumps or gas lifts—to meet the unique challenges of the Bakken and to help operators solve problems.

PRODUCTS & TECHNOLOGY

“A lot of what we’ve focused on is identifying the right application for the right type of pumping unit, and increasing the efficiency and the uptime of the unit itself by optimizing routine maintenance schedules, any repairs, any oil changes—anything like that to where we can keep that pumping unit running at its highest efficiency for those operators to reduce their costs,” he says. Over the past six or seven years, Binstock says Weatherford’s Maximizer II has become the artificial lift system of choice because of a phase-crank geometry that provides more rotation on the upstroke and more efficient fluid movement. Another change he’s seen in the Bakken is the result of advanced well completion techniques. Because of increases in initial production, the installation of rod pumps, which once occurred in the first three to six months of a well’s life, now occur in six to 24 months. James Wagener, Weatherford’s U.S. artificial lifts sales manager, says automation has been one of the largest areas of advancement for artificial lift equipment—an area in which the company is heavily involved with its Field Office software suite. “The advantage of automation isn’t in the reduction of workforce, but the redirection of workflow,” he notes. “If you have a pumper that has a route with 60 wells on it, you don’t want him to get to the problem well at 3:30 on Friday afternoon. You’d like to be able to see in from your office which wells have warnings and which ones have flags that you need to check out first. You get those problem wells taken care of to increase your up time.” Weatherford is currently in the pilot phase of a remote terminal unit (RTU) called the WellPilot ONE, which can monitor and control multiple wells using different lift types. “We’re extremely excited because this is going to drastically reduce the cost to the operator,” Wagener says. “You can be on three forms of lift before you get to your final form of lift on a Bakken well. Instead of having to buy three different controllers and three different RTUs, you can by one controller—the WellPilot ONE system—and just change out the licenses within that same controller.” Binstock says Weatherford’s system of installing artificial lift systems in the permafrost of Canada was imported to cope with the Bakken’s difficult geology. Ten to 15 steel pipes are driven into the ground until they begin to grip the soil and reach a precise loadbearing capacity. The pipes are cut off level and a concrete or steel pad is placed on top of them. “No matter what the ground does—frost heave, load changes or anything—our pumping unit is going to maintain a 100 percent alignment throughout the life of the well,” Binstock says. “That has saved operators a lot of money because previously you would have to go in and redo that gravel pad and take down and rebuild the pumping unit every time it began to settle into the ground.” When Weatherford introduced this system, it installed two or three a month. Now Binstock says the company is doing much more. NorthAmericanShaleMagazine.com

PRODUCTS & TECHNOLOGY

LONG-DISTANCE CONTROL: Automation enables Weatherford to provide its oil and gas operators with the ability to monitor and control multiple artificial lift system from a single desktop.

PUMPING EVOLVED: Weatherford has relied on the experience it gained operating in the Bakken and other shale plays to evolve its artificial lift systems, making them easier to maintain, more efficient to operate and more automated.

PHOTO: WEATHERFORD

PHOTO: NORTH AMERICAN SHALE MAGAZINE

The operating conditions in the Bakken that begin with climate extremes on the surface and extend to the geologic conditions two miles underground have provid-

ed Lufkin and Weatherford with a wealth of knowledge and experience that they can apply to artificial lift systems in other shale plays around the U.S.

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

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T R U S T W O R T H Y • R E S P O N S I V E • R E L I A B L E • E X P E R I E N C E D • I N N O VAT I V E 26 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

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INFRASTRUCTURE & CONSTRUCTION

CHECKING FOR PERFECTION: Goodnight Midstream's team has earned contracts with several major Bakken producers. The relationships built in the Bakken could lead to expansions in Texas. PHOTO: GOODNIGHT MIDSTREAM

28 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

INFRASTRUCTURE & CONSTRUCTION

PREPARING FOR ROUND 2:

LESSONS LEARNED FROM A MIDSTREAM SERVICE Goodnight Midstream found success during pre-low-oil years. Now, the water gathering and disposal firm believes it knows how to thrive again while expanding into new basins. By Luke Geiver The midstream water gathering and handling business is not as simple as moving fluid from A to B. Midstream service companies must deal with many of the same challenges faced by operators, including easement acquisitions, finding and staffing qualified field personnel or contractors, weather constraints and accessing capital for new construction. As well completion and production activity has increased in most plays throughout the first half of 2017, midstream firms are once again in demand. Goodnight Midstream, a company built in the Bakken that has plans of expansion into Texas and Wyoming, offers a glimpse into the challenges and continued opportunities in the fluids movement business.

The Fluid Investment Patrick Walker, CEO of Goodnight Midstream, built-up his company’s reputation and project portfolio in the Williston Basin. The team is headquartered in Dallas. In 2011, Walker and team recognized the need for water gathering and handling services after reviewing water handling costs for a handful of potential nonoperated well working interests. “The costs were exceeding that of what we were seeing in Texas,” Walker says, noting that in some cases, water was being trucked hundreds of miles away into Wyoming due to the lack of infrastructure. Much has changed since then, he says now, but his team’s vision then still holds true today. “We saw that water was going to become an issue and we knew the life of the wells were going to be long.” After forming a midstream water handling and disposal service in 2011, the Goodnight team—formerly 1804 Operating—had its first gathering system and pipeline connection working a year later. Today, Goodnight has 19 saltwater disposal wells and 160 miles of produced water pipelines serving some of the Bakken’s largest producers. NorthAmericanShaleMagazine.com

INFRASTRUCTURE & CONSTRUCTION

Investors have taken note of the opportunity present in midstream infrastructure, and Goodnight, in particular. In August 2016, Tailwater Capital LLC, an energy-focused private equity firm, announced an initial commitment of $80 million to Goodnight. The funding was provided in part to help the company expand into other operating locations, including Texas and Wyoming while it grew in the Bakken. The company recently hired Coby Washburn to act as vice president of business development for Texas and New Mexico. Washburn previously worked for Energy Transfer Partners, the company responsible for the massive Dakota Access Pipeline, originating in the Bakken.

Maintaining Positive Revenue Operations

MORE PIPELINE NEEDED: New pipeline infrastructure is needed in the U.S. because more than half of it was built during the 1950s and, 60s, according to information from Miller/Howard Investments. PHOTO: GOODNIGHT MIDSTREAM

NAME OF THE BUSINESS: After operating under a business name closely linked to the Williston Basin, Goodnight changed its name to show investors and partners it was willing to serve other markets. PHOTO: GOODNIGHT MIDSTREAM

30 NORTH AMERICAN SHALE MAGAZINE ISSUE 1 2017

For Walker, it all comes down to reliability. Goodnight says it tells customers that 99 percent of the time, its pipelines will be online. And, when systems are down for more than 72 hours, Goodnight will cover any costs incurred. With an expansive system of gathering lines and disposal wells in North Dakota, Walker says it is important to have a network of field staff oncall. During the recent winter, one employee had to bring a malfunctioning pump in for repairs— and back to the SWD site—during the holidays. The repair, and transport was performed in less than a day, something Walker was proud to bring up. Walker knows how important the water handling and disposal process is to its operator clients. In most cases, water is the most expensive portion of lease operating expenses and with the competition for services always present, insuring reliability is paramount. “If you are in the oil and gas business and you must shut a well in because somebody can’t take oil out due to water issues, that production is lost forever. You don’t get to produce twice as much oil,” Walker says. But providing a reliable service isn’t just about keeping staff on-call in the field or providing weekly reminders to team members about the importance of their job to their respective customers. Shale plays, including the Bakken and the Permian, are different, and changing. “I think our customers have different needs now,” he says. While many wells in the Bakken can be connected to pipeline systems, some wells there will

Miles of Operating Crude Oil Pipeline in 2013 14,000

More miles of U.S. crude oil pipeline were built in the 1950s than in any other decade.

12,000 10,000 8,000 6,000 4,000 2,000 0

93+ yrs 83+ yrs 73+ yrs 63+ yrs 53+ yrs 43+ yrs 33+ yrs 23+ yrs 13+ yrs 3+ yrs 0+ yrs Pre-1920 1920-’29 1930-’39 1940-’49 1950-’59 1960-’69 1970-’79 1980-’89 1990-’99 2000-’09 2010-’19

The Case For Greater Investment Miller/Howard Investments Inc., a New York ﬁrm, has detailed the case for investing in oil and gas infrastructure—especially pipeline related infrastructure. Struck by the perceived notion that infrastructure work was not ideal for investors in 2016, the team put together a study showing why such investments made sense and why entities like Tailwater Capital that invested $80 million into Goodnight Midstream, were right to do so. “This has become an emotional topic, with people taking sides based on headlines and celebrity attention,” Steve Chun, Miller/Howard’s director of marketing and product development said of oil and gas pipelines, including the DAPL. “It is important to start with the facts, which in this case, are not easy to ﬁnd.”

always be in remote areas that require truck transportation. Goodnight also caters to truck traffic because of that reality, Walker says. Pressure pumpers are also more evolved in their processes within the Williston Basin, he says, a fact that also requires different water takeaway requirements than the Permian.

Activity is evolving at a different pace in the Permian as well. In some cases, infrastructure in certain parts of the massive basin is already in place. But, Walker says, producers are still trying to evaluate what they are doing with water handling and gathering options. “It is in a different stage of develop-

ment there. Operators are still trying to evaluate the water profile and what their needs are going to be,” he says. Well site engineers and completion consultants are just now working to figure out optimal designs. Such decisions will impact the investments or business decisions Walker’s team makes in the future, although Walker and his team were asked to expand into the Permian and the Powder River Basins at the request of current operator clients focused on the Bakken. In the Bakken, his team is already working on 2017 projects. Harsh winter conditions—and several feet of snowfall—highlighted the continued need for Goodnight’s services. “If you don’t have your produced water in pipelines and you rely on trucks, you must keep those roads open and that isn’t easy or cheap,” he says. With activity in the Bakken and Permian noticeably increasing—albeit in different ways—Walker says that success in the midstream business, particularly the water handling and disposal side, cannot be found as it was five years ago. “Today, it is about making sure we are adding value to our customers and not just providing a service,” he says. Author: Luke Geiver Editor, North American Shale magazine 701-738-4944 lgeiver@bbiinternational.com

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