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Programming The Bakken

Design Solutions & Integration, a software developer and automation specialist, exemplifies why the Bakken is using controllable, automated systems on the well site. And why programmers are flocking to the Bakken. BY LUKE GEIVER


Finding The Next Innovation


Resource Regulators One day with the North Dakota Department of Mineral Resources: predictions, perspectives and the full-story of the DMR’s role in regulating the Bakken. BY LUKE GEIVER

Where innovation is needed in the Bakken and Three Forks shale plays and where it will come from will be the focus of more than 80 industry experts, researchers, CEOs and decision makers at The Bakken-Three Forks Shale Oil Innovation Conference & Expo, to be held in Grand Forks, N.D., Feb. 10-12. BY THE BAKKEN MAGAZINE STAFF

6 Editor’s Note

The Ultimate Bakken Resources BY LUKE GEIVER

8 ND Petroleum Council THE DIRECTOR: Lynn Helms has flourished in his role as N.D. Department of Mineral Resources. He is now considered the go-to source on many Bakken-related topics. PHOTO: GLASSER IMAGES

CORRECTION: In the December 2013 story, “Water Recycling’s New Reality,” all references, or usage of the term “partnership,” involving the relationship between Halliburton and Nuverra Envinornmental Solutions should instead be noted or replaced with the term, “contractual relationship.”

New Rules on Pipeline Infrastructure BY TESSA SANDSTROM

10 Bakken News

Bakken News and Trends




The Ultimate Bakken Resources Luke Geiver

Editor The Bakken magazine

The North Dakota Department of Mineral Resources has led the state’s oil and gas industry into unprecedented territory. Led by Lynn Helms, an oil industry veteran with an undeniably impressive resume and an unmatched understanding of the Williston Basin’s oil and gas operational, economical and geographical environment, the DMR will very soon be regulating a state that produces one million barrels of oil per day, second only to Texas. As the play has evolved, so too has the DMR’s status. Helms, and several of the other DMR decision makers, have become go-to industry experts, speakers and borderline celebrities. National oil groups and gatherings, the Lyons Club and every type of group in-between wants to hear from Helms and his staff about the latest on the Bakken and Three Forks shale plays. In December, I had the opportunity to spend an entire day with the main members of the DMR team at their facilities in Bismarck for a story that could fulfill the January feature theme of policy. As the feature story, "Resource Regulators," shows, it was a busy day. I tried to capture the important moments and perspectives gleaned from my time with the DMR crew, including: Helm’s 2014 predictions; Alison Ritter, public information officer, and her efforts to communicate with industry and the public; Bruce Hicks, assistant director, and his ability to help other state’s regulate up-and-coming shale plays; State Geologist Ed Murphy’s role in finding the next Bakken; and Permit Manager Todd Holweger’s constant quest to stay consistent with permitting, even after his office has seen an increase in permits from two or three per day in 2006, to the present number of 20 permits per day. There are many ways to describe the entire DMR staff: busy, intuitive, respected, challenged. I would argue that the best way to describe the DMR’s abilities in the Bakken impressive. Helm’s thoughts about what he believes is the DMR’s story at the end of the feature prove why. Within the impressive category is another North Dakota-based Bakken team that is making major impacts on the play. If you attend The Bakken-Three Forks Shale Oil Innovation Conference & Expo, Feb. 10-12 in Grand Forks, N.D., you’ll understand why the University of North Dakota’s Department of Petroleum Engineering is quickly becoming a major player in the Bakken. The event will feature more than 80 presentations delivered from industry experts on topics ranging from exploration and production trends to transportation and logistics advancements. Without revealing too much bias, the main-stage presentation, which will include Steve Benson, chair of the petroleum engineering department, has me and other industry representatives I’ve talked with about the event excited. Benson will be speaking on innovation in the Bakken, and, more specifically, how his team is working to find new technologies or strategies applicable to the future of the Bakken and which areas of the play’s operations will benefit from such innovation.





2014 Williston Basin Petroleum Conference



Editor Luke Geiver


AE2S Water Solutions

Copy Editor Jan Tellmann


American Hospitality Management Inc.



AmeriPride Serivces Inc.

Chairman Mike Bryan


CEO Joe Bryan President Tom Bryan Vice President of Operations Matthew Spoor Vice President of Content Tim Portz

Avitus Group


Bakken Park, LLC - Value Place


Bartlett & West


Building Business in the Bakken Seminar


Capps Van & Truck Rental


Gamajet Cleaning Systems, Inc.

Business Development Manager Bob Brown


Account Manager Tami Pearson

Grand Forks Region Econimic Development Corporation - Bakken Initiative


Greystone Construction

Marketing Director John Nelson


Highland Projects LLC

Circulation Manager Jessica Beaudry


Advertising Coordinator Marla DeFoe

33 International Road Dynamics Inc. 24



Art Director Jaci Satterlund

Subscriptions Subscriptions to The Bakken 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, Canada and Mexico. To subscribe, visit www. or you can send your mailing address and payment (checks made out to BBI International) to: The Bakken magazine/Subscriptions, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203. You can also fax a subscription form to 701-746-5367. Reprints and Back Issues Select back issues are available for $3.95 each, plus shipping. Article reprints are also available for a fee. For more information, contact us at 866-746-8385 or Advertising The Bakken 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 The Bakken magazine advertising opportunities, please contact us at 866-746-8385 or Letters to the Editor We welcome letters to the editor. If you write us, please include your name, address and phone number. Letters may be edited for clarity and/or space. Send to The Bakken magazine/Letters, 308 Second Ave. N., Suite 304, Grand Forks, ND 58203 or email to

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46 The Bakken Magazine 19

The Bakken-Three Forks Shale Oil Innovation Conference & Expo 2014


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New Rules on Pipeline Infrastructure By Tessa Sandstrom

The 63rd Legislative Session ended more than seven months ago, but the work as a result of the session hasn’t stopped. Over the

led to the drafting of new rules include House Bill 1333 and HB 1147. Both will aid in building pipeline infrastructure more efficiently and quickly to better address major challenges facing course of the legislative interim, the Bakken today, including the North Dakota Petroleum reducing truck traffic and dust, Council has continued working capturing more natural gas and with landowners groups, regulamaking our roads safer. tors and other key stakeholders Building pipeline to provide input in 47 new rules infrastructure can be a timethat will help increase transparconsuming process, and minor ency and efficiency in siting and locating new pipelines, processing changes to the proposed route of a pipeline could cause facilities, treating and disposal sites, and in reducing truck traffic construction delays of several days to several months, leading and flaring. Many of these new to continued flaring and truck rules were drafted as a result of traffic. The permitting process legislative directives. enacted as a result of HB 1147, Two bills that were passed however, will help eliminate into law last session and that



unnecessary delays in building pipelines by allowing companies and landowners the flexibility to work together and make minor route variations within or slightly outside a pipeline’s permitted corridor at the request of a landowner or farmer during pipeline construction. Strengthening the relationship between the industry and landowners was a key component in HB 1333, a bill that included many provisions, including expanded mediation, funding for an abandoned well fund, and a comprehensive location system for underground gathering pipelines that would be accessible to landowners and regulators, and creation of a

regulatory structure for oil and saltwater gathering lines. North Dakota will be the only state to regulate these lines. The NDPC worked with landowners groups and others to expand the North Dakota Mediation Service to include disputes related to easements to help the industry and landowners avoid litigation, save time and money, and resolve issues. Previously limited to construction of roads and well pads related to oil


development, the service, which is operated by the North Dakota Department of Agriculture, will now assist landowners and companies in resolving differences in the siting and construction of pipeline infrastructure, including water and saltwater lines, natural gas and crude pipelines and gathering systems. Among the common concerns expressed by landowners in relation to pipelines is assurance of reclamation should the

pipeline ever be decommissioned or in the case of a pipeline spill or leak. To help quell these concerns, additional funding is being directed to the Abandoned Oil and Gas Well Plugging and Site Reclamation Fund, bringing the Fund’s total from $2 million to $75 million. While companies are still responsible for reclamation and clean-up of their facilities, the measure permanently brings the fund into the law and ensures landowners can get spills

cleaned up should the company no longer exist or not have the funds. Finally, gas and liquid gathering pipelines will be submitted into a mapping system to allow landowners or lessees to see the infrastructure that may underlie their properties. All gathering pipelines put into service after Aug. 1, will be included in the map by early 2015. The system will increase transparency and ensure efficient monitoring of all pipelines. A third bill, HB 1348, allowed for new rules to move well-site equipment further from an occupied home. Under the rules, landowners may request that safety flares, holding tanks and treaters be moved further away from the home if the wells are located within 1,000 feet of the dwelling. The Legislative Session included a number of bills that

will have many positive outcomes for the responsible development of North Dakota’s oil and gas resources. Those related to pipeline infrastructure, however, remain the most important in alleviating the concerns expressed by most in western North Dakota, including truck traffic, dust and flaring. The rules and regulations proposed by the Department of Mineral Resources are comprehensive and will further enhance the safety, monitoring and locating standards of the buildout of North Dakota’s pipeline infrastructure. This is good for landowners, good for regulators, and good for the industry. Author: Tessa Sandstrom Communications Manager, North Dakota Petroleum Council 701-557-7744




2014 Bakken Budgets


Marathon Oil Corp. $1 Billion

Enerplus Continental Corp. $760 Resources Inc. Million SM Energy $2.2 Billion Corp. $350 Million

A new year means new budgets, and for the Bakken, that means big numbers. The following is a breakdown of the 2014 spending and operational plans of some Williston Basin operators both large and small. Note: Numbers reflect available budget numbers at press time

Marathon Oil Corp. Continental Resources Inc. $1 Billion

Of the company’s 2014 North American operational budget total of $9 billion, Marathon will spend $1 billion in the Bakken shale for the year. The company intends to increase current rig activity by 20 percent. For 2014, drilling plans include 80 to 90 net wells or 200 to 220 gross wells (75 to 85 of which will be company-owned). Marathon intends to invest $3.6 billion in the Eagle Ford Shale of south Texas.


$2.2 Billion

SM Energy Co.

$350 Million

The Denver-based exploration and producThe largest leasetion company will spend holder in the Williston Basin with 1.2 million net $350 million of its $1.9 billion 2014 budget in acres (Q3 2013), Contithe Bakken and Three nental Resources plans Forks shale plays. Of the to spend $2.2 billion in $350 million planned for the Williston Basin to the Williston Basin, SM develop its assets. The Energy will invest roughly company will spend an additional $300 million on 80 percent of that capital exploratory efforts in the in its already operating properties, resulting in Williston Basin as well. 45 gross flowing compleThe company estimated tions using three drilling that by the end of 2013, 98 percent of its derisked rigs. acreage would be held by production (HBP), and that 96 percent of its derisked and exploratory acreage would be HBP by 2017.


Enerplus Corp.

$760 Million

Enerplus Corp. has budgeted for a spending program of $760 million for 2014, an 11 percent increase from 2013. Roughly $506.7 million of that will be used to continue activities in the Bakken and Three Forks plays. The Fort Berthold region will continue to see Enerplus’ main focus. Roughly 20 net wells will be drilled in 2014.

Triangle Petroleum Corp.

$430 to $465 Million

The Denver-based firm with three main subsidiaries, TUSA (the drilling arm of the company), RockPile Energy Services and Caliber Midstream, has proposed a 2014 budget of $430 million to $465 million. No matter the amount, Triangle intends to spend its entire 2014 budget in the Williston Basin. Sixtysix percent will be put toward drilling, 26 percent toward land spending and 4 percent will be spent on both infrastructure and RockPile Energy Services.


Kodiak Oil & Gas Corp. Triangle Petroleum Corp. $940 Million $430-$460 Million

Halcon Resources Corp. American Eagle Energy $65 Million

Baytex Energy Corp. $82.5 Million

$400 Million


Conoco Phillips $3.5 Billion


BILLION Kodiak Oil and Gas Corp.

Baytex Energy Corp.

American Eagle Energy

The exploration and production firm with primary assets in the North Dakota portion of the Williston Basin will invest $940 million in 2014. The investment should increase year-over-year production volumes for the company by 45 percent. Roughly $890 million of the total 2014 budget will be put towards the drilling and completion of 100 net wells. Another $50 million will be spent on infrastructure buildout and small acreage acquisitions. In 2014, the company has budget for seven drilling rigs and one full-time completions crew working 24/7 with another crew possible on an as-needed basis.

The Canadian exploration and production company has allocated $485 million for its 2014 budget. Roughly $82.5 million will be spent on Baytex’s Bakken and Three Forks assets. The company intends to drill 15 gross wells.

The Colorado-based exploration and production firm may not have the budget of Marathon Oil, but in 2014 it will invest $65 million in the Williston Basin to drill 18 gross wells with one or two drilling rigs.

$940 Million

$82.5 Million

$65 Million

Halcon Resources Corp.

Roughly $400 Million

The Texas firm is actually lowering its 2014 drilling and completions budget by 14 percent to $950 million. But, by divesting conventional non-core assets, the exploration and production firm will add another $300 million to $400 million. Of the company’s core assets, the Bakken and Three Forks plays ranks as the largest portion of those assets on an acre basis.

Conoco Phillips

Roughly $3.5 Billion

In total, ConocoPhillips will spend nearly $9 billion in 2014 on its North American operations. Global investments will reach $16.7 billion. According to the company, 39 percent of its North American budget will be spent on the Bakken, Eagle Ford and Niobrara shale. The company will spend another 13 percent of its exploration budget in the Permian Basin and the Niobrara shale, but none in the Bakken.




Takeaways from EIA’s 2014 Outlook U.S. Shale energy production this year will make 2014 feel more like 1970. In the U.S. Energy Information Administration’s Annual Energy Outlook, the major highlight of the outlook indicates that growing domestic production of crude oil and natural gas not only continues to reshape the energy economy, crude oil production is starting to approach the historical high of 9.6 million barrels per day (MMbd) achieved in 1970. Although crude oil production reached 6.5 MMbd in 2012, the EIA estimates production totals will reach 9.6 MMbd by 2019, a 22 percent total production volume increase assessment more than the EIA’s 2013 estimates. Through 2040, the EIA estimates crude oil production will remain at or above 7.5 MMbd. “Higher production volumes result mainly from increased onshore oil production, predominantly from tight, very-low permeability formations,” EIA said. Offshore production will account for 1.6 MMbd to 2 MMbd between 2015 and 2040.


Comparison of projections in the AEO 2014 and AEO 2013 Reference cases, 2011-2040 Energy and economic factor






















Brent spot crude oil (dollars per barrel)







West Texas Intermediate spot crude oil (dollars per barrel)







Natural gas at Henry Hub (dollars per million Btu)







Primary energy production (quadrillion Btu)

Crude oil and natural gas plant liquids

Net imports (quadrillion Btu) Petroleum and other liquid fuelsa

Petroleum and other liquid fuels (million barrels per day) Domestic crude oil production

Prices (2012 dollars)




Includes petroleum-derived fuels and non-petroleum-derived fuels, such as ethanol and biodiesel, and coal-based synthetic liquids. Petroleum coke, which is a solid, is included. Also included are natural gas plant liquids and crude oil consumed as a fuel. a


Oil-directed drilling pace is much stronger in the 2014 AEO versus the 2013 version, mainly due to producers locating and targeting sweet spots of plays currently under development while also finding additional tight formations that can be developed using the newest technologies available to the industry including


horizontal drilling and hydraulic fracturing. As of 2012, tight oil production accounted for 51 percent, or 4.8 MMbd, of total U.S. crude production. The growing presence of shale energy development is also affecting the use of energy imports by the U.S. According to the EIA, imported petroleum and

other liquid fuels as a share of total U.S. use reached 60 percent in 2005 before dipping below 50 percent in 2010. By 2012, imported petroleum and other liquids as a share of total U.S. use fell to 40 percent, and, by 2016, the imported share will fall to 25 percent. While energy imports are


Average annual Brent spot crude oil prices in three cases, 1987-2040 (2012 dollars per barrel)

U.S. energy production by fuel, 1980-2040 (quadrillion Btu)









Natural gas


38% 150






Crude oil and natural gas plant liquids











0 1980









Reference Low Oil Price


0 1987








going down, energy exports continue to rise. The 2014 AEO indicates that exports are occurring faster than the EIA had estimated in its 2013 outlook. By 2016, the U.S. will become a net exporter of liquefied natural gas (LNG). By 2018, the U.S. will be a net exporter of natural gas, two years before the EIA had predicted it would happen in its 2013 outlook. “The net import share of

High Oil Price

total U.S. energy consumption is 4 percent in 2040, compared with 16 percent in 2012 and about 30 percent in 2005,” the EIA said. Although shale energy development is one of the main drivers of change for the U.S. energy outlook, the EIA does point to crude oil prices along with gasoline and diesel demand as variables that affect energy use. In 2012, U.S. gasoline prices

will decline to around $3.03 per gallon before reaching $3.90 per gallon by 2014. In 2013, EIA predicted 2040 gasoline prices would reach $4.40 per gallon. Diesel prices follow a similar trajectory, although demand for diesel will rise in the coming years. “Increasing demand for diesel puts pressure on refiners to increase diesel yields and results in a rising difference between

diesel prices and gasoline prices from 2017 to 2025,” EIA said. Other key highlights of the 2014 AEO were linked to natural gas production in the U.S., including the fact that natural gas prices are boosting natural gas-intensive industries, and higher natural gas production supports increased exports of LNG.




Federal Oil, Gas Permitting Streamlined Oil and gas permitting on federal lands in western North Dakota has been officially streamlined. The U.S. Senate has passed The Bureau of Land Management Streamlining Act, legislation authored by N.D. Sens. John Hoeven and Heidi Heitkamp. The bill has expanded the service area of the Miles City, Mont., office to include North Dakota, a service expansion that will help to address backlogs and delays in the federal permitting process that has created a nine-month delay for federal permit approval. In May 2013, N.D. Rep. Kevin Cramer authored a similar bill. Cramer’s bill has already passed. “This legislation is about helping to cut red tape and making the federal permitting process more timely and efficient,” Hoeven said. “Right now, it takes about 180 to 270 days to permit an oil well on BLM land in


North Dakota, compared to about 10 days on private lands. There are currently about 525 permits awaiting approval,” he added, “This will help us to alleviate the backlog and other delays that are costing us jobs and economic growth.” Heitkamp said that for too long, a lack of federal resources and coordination in western North Dakota has led to excessive drilling permit wait times. “We must continue to make commonsense fixes like this to help North Dakota reach its full energy potential,” she said of the bill. Following the passage of his bill in May, Cramer said the bill was “rather benign,” but had “major implications.” A 2005 bill had established the Federal Permit Streamlining Pilot Project within the Bureau of Land Management that was aimed at improving the handling of


oil and gas permits on BLM land. At the time, North Dakota was not part of the pilot project. Cramer’s bill worked to include North Dakota in the pilot project by forming the Miles City office into the Montana/Dakotas State Office. The new office can work on North Dakota permits. In late 2013, another bill passed the House that would affect the federal pemitting process for energy developments. The Federal Lands Jobs and Energy bill (HR 1965), sponsored by Doug Lamborn, R-Colo., focuses on two main areas of federal lands energy development: leasing and permitting. For leasing, the bill would require the Interior Secretary to conduct new lease sales in areas identified with the greatest energy potential, prohibit the Interior Secretary from taking away leases

already sold, set firm timeliness for the Secretary to issue leases, and, according to the U.S. House of Representatives’ Committee on Natural Resources, prohibit the Secretary from changing the rules after the leases and contracts have been finalized. On permitting, the bill would set firm timelines on the Interior Secretary to act on a permit to drill. According to the Committee on Natural Resources, the average time to get a well permitted on state land is roughly 12 to 15 days, while the average time to permit a well on federal land is 307 days. The bill would also direct a portion of the permitting processing fees to the local office where they were collected to ensure the permitting office has the appropriate staff, expertise and resources.


Sleeping Giant Shallow Gas Project Approved Strata-X Energy is taking its first-mover philosophy to south central North Dakota. The exploration and production firm with offices in Canada and Australia has been granted the necessary permits to drill and explore for shallow gas in the counties of Emmons and McIntosh. The North Dakota Department of Mineral Resources has permitted four wells and a drilling company has already been contracted for what the company is calling its Sleeping Giant Project. The wells will target the gas-rich Niobrara formation. “Strata-X Energy strives to be the first mover or early mover on opportunities it pursues. This strategy tends to lead the company away from the main

pack of the industry where leases can be prohibitively expensive for a small company,” Strata-X said. “We can lead the industry into the next hot area.” Although Strata-X will be working to prove out the Sleeping Giant Project, the DMR said in a statement on the rare permits that it will be a long time before the area, and the project, is proven to be economical. In 2006, Staghorn Energy looked into the same region in search of shallow gas resources but determined retrieving the resources would not be economical. The site in question is located within a flat agriculture land area. According to StrataX, there has been relatively little drilling in the area and the

drilling that has occurred has been performed away from the main structures that Strata-X will target. Previous drilling targeted the Cretaceous and Paleozoic formations. “The Niobrara formation in this area has been overlooked despite gas shows and small flares being reported,” the company said. After drilling commences on the project, Strata-X has a period of six months before the wells, and the results, are taken off confidential status. Following that period, the DMR can release the name of the operator, well name, well location, spacing or drilling unit description, drilling date and production sold.

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Contained* vs. Not Contained**


*Contained releases are those that remain within the boundaries of the production or exploration facility ** Not contained releases are those that overflow the boundaries of the facility or leak from a facility pipeline





All Oil Salt Water Other



552 391


245 178


104 45



Not Contained


Pipeline Industry Goes Transparent The pipeline industry in North Dakota is becoming more transparent. The N.D. Industrial Commission recently approved rules that will increase pipeline regulations and reporting requirements. “The Legislature saw a need for greater pipeline enforcement, due to the growth in pipelines to move all fluids in western North Dakota,” said Wayne Stenehjem, attorney general, following an announcement that the NDIC had approved several new rules and regulations created by the Department of Mineral Resources. Stenehjem said the rules will require operators to submit data to the Industrial Commission in an effort to track construction and reclamation of pipelines. In addition, the new regulations will require the tracking of pipeline locations for use by surface owners. The rules will go to the Legislature’s Administrative Rules Committee for approval and are expected to take effect April 1. Gov. Jack Dalrymple called the approved rule changes a sign that NDIC is committed to the oversight of the oil and gas industry. Although Ron Ness, president of the North Dakota Petroleum Council, called the regulations good for landowners, regulators and the industry, he did note that an influx of new regulations over the past

two years could potentially slow the efforts of the oil and gas industry. “We must be mindful of the effects some rules may have on creating burdens or bureaucratic red tape,” he said, adding that, “technology has allowed us to develop more of our natural resources while reducing our impact. But, overburdening the industry with regulations could inhibit innovation needed to further enhance technologies and responsible operations.” While the state’s regulators are working to make the pipeline industry (related to the movement of oil and saltwater safer), the N.D. Department of Health, Environmental Health Section is also helping anyone in the state stay abreast of all oil or saltwater spills. The Department of Health has created a spill report webpage that provides information on the types of spills, amounts released, dates of incidents, locations and incident summaries—all related to the spills reported to the department. Prior to the website, the information was publically available upon request, but the new approach provides better access to the public, according to the department. Data on the site is broken down into incidents within the past 12 months, and incidents older than that. Data will be updated weekly.


Montana’s Leading Energy Conference and Trade Show

FIRST RUN: The first crude oil train moving through the Wyoming terminal. PHOTO: STROBEL STAROSTKA TRANSFER

Wyoming Builds Terminal To Handle Bakken Crude Roughly 400 miles separates Guernsey, Wyo., from the Bakken shale formation. The distance has not hindered the Wyoming community from utilizing Bakken crude as a main driver for its recently opened crude oil unit train facility near the town. The facility was designed to handle varying crude types and is the first in the surrounding area capable of loading multiple crude types, including crude from the Bakken, Powder River Basin, Niobrara, Southwest Wyoming, Big Horn Basin and Canada. For example, Western Canadian Select crude oil with an API gravity of 20 and 3 percent sulfur content can be loaded on one train, while Bakken crude with an API gravity of 40 and .20 percent sulfur content can be loaded on another. “This flexibility allows for more optionality as producers ship their products to markets throughout the East, West and Gulf coasts and along the Mississippi River,” said Strobel Starostka

Transfer, the company responsible for building and now operating the facility. “This is such a unique facility and we are so pleased to have been able to join the project at its inception, design it, construct it and see it all the way through to continual operation,” said Steve Strobel, CEO of SST. “Because this terminal has been designed to handle multiple crude types, we are confident in its long-term viability, something we are truly excited about.” Strobel Starostka Construction built the facility owned by Eighty Eight Oil. The facility has three loop tracks with entry and exit from each direction. Roughly 80,000 barrels per day of crude oil can be loaded. Following the construction of the facility, SST was awarded the contract to operate the facility, including the hiring and training portion of the facility. The facility currently employs 20 but SST plans to hire another 40 employees in 2014.

Registration is now open for attendees, exhibitors and sponsors. Register online at:






REGULATORS The inside story of the N.D. Department of Mineral Resources By Luke Geiver

When Lynn Helms became Director of the North Dakota Department of Mineral Resources in 1998, the drilling rig count was at zero and oil prices had recently plummeted only seven months after taking the position.

TOP REGULATORS: From left, Alison Ritter, Todd Holweger, Bruce Hicks, Lynn Helms, Ed Murphy, Dave Hvinden, Rich Suggs.

“We were doing emergency rulings to allow operators to shut wells in. Everybody thought the price of oil would recover, but no one knew when,” Helms told me on a cold, bright December day from his Bismarck office. Roughly seven months after taking the Directors job in 1998, light sour crude from Bottineau County, N.D., was going for less than $4 per barrel, he explained to me with his arms and legs crossed while leaning back in his chair, a concerned look on his face and the December sun shining through the cracks of his window blinds onto the leaves of his impressive office plant collection. “But, things have changed,” he added, leaning forward in his chair, uncrossing his arms, his bearded cheeks high on his face as he smiled. Over that December day, I held one-on-one sessions with many of the DMR’s top regulators— including Helms, the face of the department—to learn how the regulatory agency responsible for overseeing one of the most important energy developments in the world has dealt with extreme industry change, overcome challenges and formed a process to deal with new issues directly related to the state’s oil and gas industry. Although portions of every conversation that day included discussions of hometowns,





'Horizontal drilling was also one of the biggest changes ever. Much of the oil [in the Williston Basin] laid in wait for a technology like horizontal drilling to come along.'

alma maters and trips––Helms of German heritage and his wife of more than 30 years visited Norway last summer––each regulator expressed the sense that the DMR has a serious story to know, one that will continue to affect how shale energy resources are developed in North Dakota and the rest of the country.

- Lynn Helms, Director

Helms on Helms “A lot of what is involved with this position is about protecting the environment and human safety,” Helms said, when asked about his role with the Department of Mineral Resources. Because of that, he made a point early in our conversation to explain the early portions of his life in northwestern South Dakota, “riding horses, chasing cows and hunting on the prairie.” The son of a cattle rancher, Helms grew up adjacent to U.S. Forest Service land that the family ran cattle on. “It set a tone for how I view the world,” he said. Between his days living and working within the open country, extreme rural setting and his time as North Dakota’s top oil and gas regulator, Helms developed an impressive resume that seems tailor-made for his current position. Following his time in Rapid City, S.D., at the School of Mines and Technology, he took a job with Texaco in Billings, Mont., as a production engineer that included duties related to drilling operations. “That was an introduction by immersion. I supervised drilling rigs and more. I got a hands-on lesson,” he said. While Helms was in Montana working in the declining Cut Bank oilfield discovered in 1928, Williston, N.D., was experiencing an oil boom. Helms took a job in Tioga, N.D., with Hess Corp. to get in on the action. Eventually, Helms became an asset team leader for Hess, leading a team that included a geologist, physicist and production engineer. “We put together budgets and presented them to John Hess,” he said. 22


“One of the biggest things that came out of that that influenced this job is the testifying I did before the Industrial Commission. When those guys sit on the other side of the table and their attorneys are asking them questions, I know what they are up to.” During his early days with Hess in the '80s, he was also on a team responsible for plugging and reclaiming the Clarence Iverson well, the first well to recoup oil in North Dakota. By the '90s, Helms was faced with a dilemma. To remain at Hess, Helms needed to move to Houston. “The buzz word at the time was global mobile, if you were going to move up the ladder you took jobs in Kazakhstan or Equatorial Guinea,” he explained with a laugh. “I didn’t want to leave


North Dakota. This job opened up and what a blessing it has been.” Since taking over the position, Helms believes one of the biggest changes he has dealt with has been the use of hydraulic fracturing by industry to recover oil and gas. “Horizontal drilling was also one of the biggest changes ever,” he said. “Much of the oil [in the Williston Basin] laid in wait for a technology like horizontal drilling to come along.” He remembers distinctly when the practice became a reality in the Bakken. After watching Halliburton and a handful of other companies apply the technique in the Elm Coulee field in Montana, Helms said his team began wondering if the process could work in North Dakota. In 2006, EOG

OFFICE GEOLOGY: The DMR offices feature a representation of the geologic layers present in North Dakota.

Resources hit on a Parshall, N.D., well and then Bud Brigham, founder of Brigham Resources, an exploration and production firm bought out by Norwegian-owned Statoil, started experimenting with multiple stage fracks and increased proppant on a well southeast of Williston. The well came in fantastic, he said, “and the rest is history.” Horizontal drilling may have ushered in a new era for N.D.'s oil development, but Helms and his team have also issued regulatory measures that have reshaped the way the play has been, and will be, developed for decades to come. One of Helm’s proudest achievements has been to limiting the amount of what he calls Tetris in the oilfields. “Right at the end of 2009, all of sudden, we started to see all of these company proposals for random horizontal drilling spacing units of all shapes and sizes,” he said. If approved, the random units would have made the development of the Williston Basin appear incredibly cluttered and chaotic. “I told the staff that we were starting to play Tetris, a game of Tetris with 15,000 square miles of people’s minerals. And, if you have ever played Tetris, you know you can never win, the pieces just keep coming.” The DMR staff analyzed the development happening in the Bakken and estimated that if the Tetris game continued, the amount of land consumed and the pipeline footprint in western North Dakota, would be 10 times as much as what was actually needed. Helms brought together all of the big oil companies operating in the state to explain the DMR’s order and new plan with 1,280 acre spacing units. By implementing a scheme that put all spacing units at 1,280 acre units oriented north and south, the DMR was able to reduce the number of gravel roads needed from 60,000 to 6,000 miles. And, the pipeline




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footprint was equally impressive, decreasing from 300,000 to 30,000 miles. Although the industry did react with some negative kickback, Helms said the role of DMR director requires the ability to issue regulations that can not only affect the entire industry, but, to understand and predict where the industry is headed. “I remember in 2008 saying that what was happening here would take us 12 years to drill all of the wells, and people said I was nuts, that oil booms never last that long. They said I was wildly optimistic,” adding that, “In 2010, I said it’s not going to take us 12 years, it is going to take us 20 years. And then they said I was grossly pessimistic.” Changes in the industry is not something Helms dislikes, however. It’s the main perk of his job. “My job is so fun because I sit in the middle of all of it,” he said, “No two days are ever alike.”

Outside Communicator Alison Ritter doesn’t have an oil industry background, but if you spoke with her for 10 minutes, you would think she did. “I have to have a working knowledge of what is going on,” she said. Her role as Public Information Officer may not seem as crucial to the DMR’s ability to regulate the industry as others


in the Bismarck office, but after listening to her perspectives on the DMR and its role to both the industry and the general public, it was clear that Ritter is the multi-tasking DMR liason the team couldn’t do without. Ritter’s exuberance and authentic interest in her work was obvious. She spoke with an enthusiastic expression the entire session and paused before answering nearly every question, a vocal clue that her intent was to provide the same accuracy to my questions as she would to a mineral owner from Tioga, a drilling supervisor near Dickinson or yet another reporter from a national media outlet looking for the true story of the Bakken. “I came with an outsider’s perspective. I can bring a new perspective to things, help the department understand what the average person thinks,” she said, speaking on her background in communications and news media production. Ritter frequently fills in for Helms at public gatherings to give presentations on the state of the Bakken, and every day, she fields several media-related calls that had previously been handled by Helms. In 2013, Ritter filled in for Helms at the Williston Basin Petroleum Conference in Regina, Saskatchewan, (while pregnant) delivering a presentation on par with something Helms could have delivered. Ritter accompanied me during the day at the DMR facilities, and during each sit-down session, she added snippets of information to our conversations ranging from drilling permit trends to well pad designs. Ritter also helps mineral owners with questions of their own, and has an incredible grasp on the DMR’s website functions that allow users to predict everything from future drilling activity to the hottest fields in the play. While there, Ritter provided a shortened version of an interactive electronic wall display presentation on par with something seen on ESPN, and at the general computer in the lobby of the facility, she explained a mapping tool available to track future oil production based on the days until an oil lease expires.

'I came with an outsider’s perspective. I can bring a new perspective to things, help the department understand what the average person thinks.' - Alison Ritter, Public Information Officer


“We are trying to prepare people for what’s ahead. We are trying to minimize environmental impacts while maximizing the economic and social impacts of all of this,” she said. When it comes to industry, most calls she fields are from industry representatives in search of a rule clarification. She also helps the operators in some instances herself, or directs a question to the appropriate person in the office if the industry

representative or the respective company has a question regarding compliance with a rule. In any given day, Ritter could field five or more calls requesting information for the same story (when I was there the hot topic was weather’s role on production). Of all the DMR staff members, Ritter best embodies the constant change and learning experience each member has gone through since the development of the Bak-




ken began, she said. The change and learning process is an element of the team she believes is important for the industry and the general public to recognize. “These people really care about what is going on. I see people work really hard and work lots of hours that go unnoticed,” she said. In the 2011-'13 biennium, the DMR staff was also increased by 30 percent with another 20 percent increase expected in the current biennium. Being at the center of the Williston Basin isn’t something Ritter is afraid of though. In her own words, it’s fun.

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In an 18-month period that included 2012, the DMR’s Geological Survey brought in as many core and sample boxes to its Grand Forks-based core library as it had in the past 10 years, according to Ed Murphy, state geologist. “We are going through record activity up there [the core library] from companies coming in to look at core and companies that are providing core,” Murphy said. In 2012, the core library received 12,000 feet of core (rock samples taken from North Dakota). “We always say you could lay the core samples and reach from Grand Forks to Fargo.” Murphy held a core sample of the Middle Bakken in his hand as he explained the incredible growth the Geological Survey team has seen in the past five years. “We love companies to core,” he said, pointing to the small pinhole openings in the rock that could have held hydrocarbons. Although Murphy’s team’s more glamorous task is to research new geologic opportunities available to potential industries (recently the team helped a company in its quest for diamonds near Drayton), it also has to track core sample submissions. For every well drilled in North Dakota, a drilling team must provide a cutting sample taken from the well. is important for the industry and the general public to recognize. Generally, an operator is given three to six months to send in the core sample to the DMR. But, there is such a backlog at the labs right now that the time before the Grand Forks library receives the samples is much longer. Once the core library receives the samples, University of North Dakota students are hired to photograph the samples for online viewing. According to Murphy, the core library’s online option for core viewing is second to none in the entire country. “This is the nicest site in the country by far,” he said, scrolling through the images as we viewed the site on a screen at his desk. “We are told that over and over again.” The site allows geologists from Houston to review samples before flying to North Dakota, he added. “They love looking at others, but, of course, they don’t like others looking at theirs,” he said. But, information is a boon to the development of the play because people are still learning. For the past four years, Murphy’s three oil and gas geologists have been focused on the Middle Bakken and Upper Three Forks


'There are questions that we can answer now more than ever before. I think that the important thing is that there are still other units out there that with new technology hold promise.' - Ed Murphy, State Geologist


formation, he said, but it’s now time to learn about other formations and provide that information to industry. “We try to anticipate what industry’s needs are.” Or, in some cases, the team tries to reveal where industry can look for new developments. “There are questions that we can answer now more than ever before. I think that the important thing is that there are still other units out there that with new technology hold promise,” he said. For example, Murphy pointed to the Tyler formation as well as others below the Three Forks. “We are saying to take another look at the Tyler, and companies are. We had a lot of vertical success in other units, and some we didn’t. We are saying regardless of that, think about going back to other formations, the Birdbear and others below the

Three Forks. Rethink all of these using this horizontal and fracking technology,” he said with a look, a slight smirk, that implied he knew something the rest of us non-geologists didn’t.

Born To Regulate High school vacation was an important time for Bruce Hicks. Because his father worked for a small oil and gas company, most of his vacation days were spent pumping and doing roustabout work. “I didn’t really enjoy most of it, but it got me interested in oil and gas.” His interest has blossomed into a 33-year career with the DMR. His main job today is as assistant director to Helms, supervising the oil and gas division. There may be no better person to focus on regulating the oil and gas



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industry than Hicks. He has the physical demeanor and presence of someone with serious intent, and he isn’t afraid to make tough decisions. At one point early in his career, he said, “I actually had to regulate my dad, something he was not real fond of.� Hicks has been integral in the DMR’s efforts to add staff to its offices in Dickinson, Minot and Williston. The frantic hiring effort, in addition to the massive case load increase over the past five years, has added a new dimension to Hick's job. Five years ago, the DMR may have heard 200 to 300 cases a year, but today, Hicks and the team hear roughly 200 to 300 cases per month. The DMR has expanded from one building to two, and the conference room once used for

for safety and environment 28


case hearings has been scrapped for a new, much larger room where Hicks, Helms and others hear cases. Helms also performs his monthly Director’s Cut webinars from this the room. For the field staff, the evolution of the Williston Basin from a play solely focused on the Middle Bakken, to a multiformation play that now includes several layers of the Three Forks formation, has presented new challenges. “We have to keep track of where these wells are and in what formation they are in,� Hicks said, a task that may sound trivial but becomes difficult when a four-well pad could be drilling into four different formations. New field inspectors require training before they can be released to their own wells. Inspectors with engineering

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'We have people coming in nearly every day saying that they can put a new well pad together better than before. I’ve learned to be patient. I think we need to do the right thing rather than do the quick things.' - Dave Hvinden, Field Supervisor


and geology degrees are placed on drilling rigs and new inspectors with math or environmental backgrounds are tasked with inspecting facilities, tank batteries and disposal systems. The business dealings and acquisitions are a challenging aspect of the oilpatch to monitor, Hicks said, but he follows every activity closely because when technology or ownership changes, plans typically change. In addition to his monitoring efforts, Hicks believes in the power of education. “We have shown other state regulators what we are doing. It has been very helpful to


them to see how we took this play and got it more developed on a uniform pattern to minimize the impacts.” Hicks recognizes the relatively new state of plays such as the Bakken, and because of that, he knows that his job is no longer only about case hearings and compliance issues. It’s also about setting an example for other resource plays. “If you look at some of the other resource plays, they have Bakken-like potential in place there. Almost every sedimentary basin has a source rock there like the Bakken that you could drill into. What we are trying to do is teach everybody and


show them what we have learned here and try and avoid some of the early mistakes.” Hicks shared Helm's sentiment on developing spacing units, stating and restating his satisfaction with the ability of the DMR to help the industry see the benefit of energy corridors.

Dave Hvinden Has 2 Smartphones Dave Hvinden is in tune with the day-to-day activity in the Williston Basin. As the Field Supervisor, he has to be. Before we started talking, he set both of his smartphones to silent, and after the email alert on his computer beeped multiple times in the first few minutes of our talk, he closed his email down. Hvinden is no stranger to pressure from outside voices; he has been a football referee for nearly 30 years. At his position in Bismarck, he tries to communicate what the field staff is seeing throughout the state to the office staff. And, as the play evolves, he is constantly trying to maintain an understanding of the new technologies being used. When asked about the technologies he’s excited about, he laughed, telling me there were too many. But, the use of multipad drilling techniques has his entire team excited, even if there will be new rules and regulations needed to ensure the safety of the new technologies. “We have people coming in nearly every day saying that they can put a new well pad together better than before,” he said. “I’ve learned to be patient. I think we need to do the right thing rather than do the quick things.” Although Hvinden’s role is to help with the field staff ’s ability to perform their jobs, he also said his entire team has been helping young industry engineers. “We do a lot of troubleshooting for them because


'Once they set casing and then run cement, they run cement bond logs and I review all of those. That is one of the critical elements of preserving safety in the Williston Bain and from preventing contamination' - Rich Suggs, Petroleum Resource Geologic Analyst

the amount of air or fluid present between the casing and cement. The wave readings can indicate if an adequate amount of cement is present. If the cement is shown to be inadequate, there are various options for the operator, Suggs said. “We may require remedial work. They may have to go in, perforate and punch holes in the casing and pump cement back in to fix the problem. In some situations we can allow the well bore to be monitored based on which formations are open.” Of the approximate 200 new wells per month that Suggs monitors, remedial work will only be requested on roughly three to four wells. In addition to monitoring cement bond logs, Suggs is also busy making sure operators are sending their core samples to Grand Forks. Because production is not slowing down, Suggs foresees much of the same for his role with the DMR in 2014. But, for Suggs, that is not a bad thing as geology is a very natural part of his life. His wife is also a geologist.

Todd Holweger Is Permitting PHOTO: GLASSER IMAGES

they are young in their careers.” For his new field staff, Hvinden typically makes new DMR hires spend a month with experienced field techs, going on ride-alongs and gaining an understanding of how the experienced technicians manage their areas. In total, Hvinden manages 31 field staff. As his phones and email frequency showed that day, he is never idle.

Rich Suggs Lives Geology To ensure the integrity of a well bore, North Dakota requires cement to be pumped behind the well casing to eliminate

fluid migration from the well bore into the surrounding area. As the Petroleum Resource Geologic Analyst, it's Rich Suggs job, to monitor the process. “Once they set casing and then run cement, they run cement bond logs and I review all of those,” Suggs said. “That is one of the critical elements of preserving safety in the Williston Basin and from preventing contamination.” There are multiple ways to provide Suggs with a cement bond log, but all tool versions essentially provide the same information. Usually, a sonic tool is used to present sound waves into the cement to detect

In 2006, Todd Holweger was only managing himself. In 2014, Holweger is managing six other oil and gas permitters as the permit manager for the DMR. When a permit for a well pad, seismic procedure or other oil facility is received electronically at Holweger’s office for a new well pad, the permitting team has four individuals who can issue permits and another three that prep the permits for review. The prepping team is tasked with making sure the applications are filled out correctly and include any necessary attachments that document, for example, why an operator has chosen one particular location versus another. If filled out properly with all of the appropri-




ate accompanying information, Holweger’s staff can turn-around a permit in roughly 30 days. “In 2006, I received two to three permits per day. Now, I’m getting 20 permits per day. It is up to 100 permits per week,” Holweger said. The office staff will issue permits based on a case-by-case basis, a point Holweger made several times during our discussion. And, the entire team insists on being consistent and looking for the same elements in each permit. After the office staff reviews a permit, a field inspector will also review a proposed well site and add more stipulations if necessary. The idea of efficiency isn’t only big in the drilling and completions world. Holweger preaches the same ideals in his office, and, he even urges those submitting applications to practice what they preach as well. An attention to detail can minimize the number of days for any operator who has issued a permit. As an example, he points to cases that require an affidavit allowing a surface location to be placed outside of a spacing unit. Operators that don’t submit the affidavit with the original permit application will then have to be called by Holweger’s staff and obtain or send in the proper documentation before the team can proceed in the permitting review. In the event that a potential well site is environmentally challenged, Holweger said an operator should provide a simple, onepage Word document explaining why the well pad has been placed in a certain location. “The operator might just state briefly that they checked four other spots and this was the best one. Without that, the only thing that we really see is the rough area and we don’t know that they have evaluated other sites,” he said. Although four is currently the average number of wells per pad in North Dakota, Holweger expects that number to rise. “You are going to see a lot more wells on a pad, but, just because you have more wells doesn’t mean the pad is going to be huge,” he said. “The most wells on a pad in the state is currently 14. We’ve got a couple of 32

'The most wells on a pad in the state is currently 14. We’ve got a couple of pads with future wells noted on the pad for up to 22' - Todd Holweger, Permit Manager

pads with future wells noted on the pad for up to 22,” a number Holweger recited with a hint of excitement and exhaustion behind his voice, and a tone that implied to me that it was time to stop talking and to get back to permitting.

Predictions for 2014 Numbers from Holweger’s permitting office make it easy to see where the Williston Basin is headed. For 2013, 58 percent of all permits were for wells on multi-well pads, a 10 percent increase from the previous year. The same rough increase will continue in 2014. “You are going to see more


and more wells on existing pads where they have to enlarge the pad just a little bit,” Holweger said. And, the entire staff is starting to see a new spacing unit era taking shape. Using 1,280-acre spacing units has been a major success so far, but Helms, Hicks and Holweger all believe it is time to start 2,560 acre spacing units. “We will strand roughly 4 billion barrels of oil if we go by 1,280 acre spacing units,” Holweger said. Hicks believes technology, and a move towards infill drilling is driving permits to be redone. “From what I’m seeing,” Hicks said, “we are getting so many infill wells drilled that it is getting pretty complicated


WORTH THE VISIT: The DMR facilities house more than just office space. Fossils and other historic findings or artifacts are on display for visitors to understand the full scope of the DMR.

on spacing units and the sizing and who gets paid for what wells,” adding that, “when we start having a lot of overlapping spacing units, it is probably best to see if someone will come in an unitize a certain portion so that wells can be drilled out to their maximum extent.” The spacing unit change will result from greater use of multi-well pads, the biggest change set to happen in the Williston Basin in 2014, Helms said. “The exciting thing is that they will be able to drill more wells with less trucks and less rigs,” he said. “Economically, it is going to be a challenging year for oil companies, but by multi-well pad drilling and reducing construction that is going on in the frontend of the well pad, costs will go down. Multiwell pads are going to save the prairie. It will make it possible to drill more wells with less rigs and it will make it more economic.” The evolution of the oil and gas play and the move to unitization and multi-well pads is exciting to Helms and the entire DMR team, but it isn’t unexpected. During his Hess days, Helms said he learned that in the oil business, innovation must be constant. Spend a day with any of the DMR team members, and that theme shows up again and again. When I asked

Helms about the DMR story, what it means, what is important to know about the group at the center of a shale energy proving

grounds that has garnered global attention both good and bad, he stuck to that theme of innovation. “I would like people to know how hard we work and how focused on performance and continuous improvement we are. We never stop thinking about the next session, the next rule, the next improvement on how we regulate or publish information. We aren’t just working hard on what we’ve learned,” he said from his office that December day, his bearded cheeks tense from the serious tone he had taken to the question. “We are working to improve on what we can do in the future,” he said, the bearded smile returning to his face as the word future exited his mouth. Author: Luke Geiver Managing Editor, The Bakken magazine 701-738-4944








the Bakken Automation Companies are bringing efficiency, and programmers, to the oilpatch By Luke Geiver

Programmable logic controllers (PLC) are changing the way a well pad is run, monitored and maintained. Typi-

cally housed in a industrial control panel located on a well pad and operated by a touchscreen interface system similar to a tablet, the PLC can route oil into a storage tank, run a pump jack or warn a work crew about the presence of dangerous gas built up on a site. Once connected to a wireless or wired network, the PLC can send a message to an accountant at a desk with information detailing oil tank levels at multiple locations. The PLC is made to automate virtually any process. “Automation can do as little or as much as you want it to do,” says Craig Pistulka, president of Design Solutions and Integration, a programming, UL508A panel shop and electrical company with offices in Stanley and Grand Forks, N.D., and Sioux Falls, S.D. “The reason why PLCs and automation is advancing so fast in the oil industry,” he says, “is because the technology and the applications for it are advancing just as fast.” Over the past five years, several automation companies have entered and grown in the Bakken shale play. DSI started in the Bakken roughly seven years ago after servicing the water, wastewater, grain and ethanol industries with PLCs and automated systems. DSI isn’t the

THE PANEL SHOP: The Sioux Falls, S.D., DSI panel shop can build customizable automated control panels for well sites in the Williston Basin. PHOTO: DESIGN SOLUTIONS & INTEGRATION




only company that has thrived through programmable automation. In June of 2012, Flow Data Inc., which installs and supplies instrument and electrical needs on the well pad, opened a 6,000 squarefoot facility in Dickinson, N.D. The company also has field offices and employee housing in Watford City, N.D., and Crosby, N.D. The same month Flow Data expanded its N.D. operations, the company did the same in Pennsylvania in the Appalachian Basin. In 2008, Industrial Automation, a division of widely recognized Williston, N.D.based Triangle Electric, opened an automation and programming service. Industrial Automation can install, build and design PLC and automation systems. In 2012, Tarpon Energy Services LLC acquired Schmidt Electric Inc. of Killdeer, N.D., in a move that Tarpon explained would give the company the ability to offer electrical instrumentation in North Dakota and the prolific Bakken play. No one understands the demand for well site automation systems better than DSI. In 2001, he was working out of his bedroom


WIRED AND READY: DSI has expanded from a programming, panel-making operation. The company can now offer the electrical hook-up services need to bring an automated well site online. PHOTO: DESIGN SOLUTIONS & INTEGRATION

on programming and panel designs. One year later, he hired his first employee, Brian Evans, who is still with DSI today. Today, he oversees a panel production shop in South Dakota and more than 30 programmers dedicated to the oil and gas industry.


Establishing an Elite Team The breakout year for DSI came in 2010. Pistulka was able to land jobs with several major operators in the Bakken, and several other projects. The company is currently installing a 300-plus radio site system for a pipeline.


ELECTRICITY BOOM: In addition to the panel shop, DSI has also added electrical services to its offerings, allowing customers to utilized DSI for an entire well site automation system and hook-up. PHOTO: DESIGN SOLUTIONS & INTEGRATION

Multiple DSI programmers are working on projects that consist of automating well pads to pipelines and transloading facilities for a range of operators and infrastructure firms. Finding work was not difficult for DSI, Pistulka says. Assembling the right group of programmers was, however. To get 30 programmers capable of working in the style DSI has created, Pistulka had to go through more than 50 programmers and countless

resumes and interviews. “We are still looking for more,” he says. The current group is made up of programmers from throughout the U.S., including Texas, Florida, North Carolina, Georgia, Utah, Arizona, Ohio, South Dakota and North Dakota. “There is a lot that goes on beyond the scenes that people don’t realize anymore,” he says, “it is not just about punching holes into the ground. The oil companies are very de-

manding—and rightfully so—they are investing billions of dollars. They expect A-plus service and technology.” To ensure DSI is meeting the needs of the oil industry, a programmer undergoes a multilevel training program that could take up to one year to complete. “We want someone that not only knows how to program a PLC but also knows the instrumentation that they are monitoring and all of the equipment that


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Award-Winning Tracking Technology Global consulting firm Frost & Sullivan recognizes the role of software in the Bakken. In 2013, Fargo-based Pedigree Technologies was awarded the North American Customer Value Enhancement award for its oil and gas software. Pedigree, a company that has seen tremendous growth, has a created a machineto-machine software package that can track equipment, including trucks, tanks, generators and other products used in the field. “The idea is that you know what condition your equipment is in or where it is. You can coordinate a very streamlined operation,” says Alex Warner, Pedigree’s CEO. “If you are a rental operation and you identify that your skid steer has a diagnostic code error, you could dispatch and find out where a maintenance technician is in the field in relation

to that equipment piece,” Warner says, “and then be able to show up with the right part at the right time.” Pedigree’s technology can be used with tablets and smartphones. The system allows any user to see multiple data sets taken from a well site or a truck. In certain cases, a truck driving team can assess the best time to visit a well site for oil pickup based on information from a Pedigree technology package installed on oil storage sites. “There is a pressing need for a platform that can amass data from these assets, along with data from their back-end business systems, to further streamline operations and improve overall efficiency,” Frost & Sullivan said of the need for systems such as Pedigrees.



PROVEN METHODS: DSI will take base programs from previous projects and revise or tweak them to meet the needs of new customers, a process that helps clients receive an automated service faster. PHOTO: DESIGN SOLUTIONS & INTEGRATION

they are controlling,” he says, adding that, “We have found some guys that are really good at programming but are kind of shy at knowing the instrumentation. We train them so that they know what they are hooking up to and how it should be run.” If DSI is able to find a senior level programmer with oil or gas experience—which isn’t often—the training period can end after 8 weeks. Since DSI first started serving the Bakken, he has noticed an increased emphasis on safety options in many of the program requests and the automated processes that the programs run. Dawn Pistulka, operations coordinator for DSI and wife of Craig, says that DSI’s programs are vastly more complex than they were five years ago, “because in addition to new safety options, we are trying to make every program and system better than the last.”



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DSI Programmer Duties Not all programming and automation service providers operate the same, but DSI's team has found a way to utilize existing programs built in the past to streamline the well site automation process. When an customer requests service, a programmer will be assigned to a well site. The programmer will receive all applicable engineering and electrical design drawings. Using a base model program from a previous site, or, an entirely new program design, the programmer will build a program to run any process the operator requests, however the programs that are created are proprietary to each individual customer. After each program has been tested to 95 percent in-house, the programmer will meet the operators commissioning team on the well site to install, finish testing and start the automation process. After the system is tested, including all safety sensors, the well can be put on flowback or production. After the well site is brought onto production, the programmer will stay at the site and monitor everything to make sure the software and the site is working correctly. Although the well sites are starting to be more standardized, Pistulka says, many are still one-off sites that could feature a varying amount of equipment. Since opening the PLC panel shop in Sioux Falls, and the addition of an electrical installation team in June, DSI can now supply every service or product a client looking for automation would need. The use of automation is allowing oil companies to manage multiple wells much more efficiently, and according to Pistulka, it pays for itself pretty fast. Automation can cut down on the inperson monitoring that is needed at remote well sites, and, it can help operators stop a problem before it starts. “Say for example you aren’t monitoring your wells and one shuts down. The only way you know it shut down is if someone drives out there. What happens if that operator only checks that well every two or three days?” he says. “You can see the amount of money they lose in two to three days.” Companies that can provide a widerange of services, such as DSI, will have an

advantage, Pistulka says. When an issue arises, it is easier to call one provider rather than six. Automated pump jacks, LACT units or other well site equipment packages aren’t the only thing DSI has programmed PLCs for. The company recently started offering video monitoring of well sites, another option that helps to reduce the amount of in-person monitoring needed at a site. He is proud of the role automation is playing in the Bakken, and he is thankful for the oil industry’s role in turning his bedroom-based company

into an automation giant that is still growing. “We need a bigger staff, we need more programmers, more electricians that want to further their education. We need those that are willing to run a computer and download programs,” he says. “Any place that there is drilling, there is work.” Author: Luke Geiver Managing Editor, The Bakken magazine 701-738-4944

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For three days in February, the future of the Bakken and Three Forks shale plays will be in Grand Forks, N.D. The


Bakken-Three Forks Shale Oil Innovation Conference & Expo, a collaborative event created by The Bakken magazine and the University of North Dakota’s College of Engineering, and Mines, the Department of Petroleum Engineering and the Harold Hamm School of Geology and Geological Engineering, will feature industry CEOs, water experts, completion design managers, flaring specialists, engineers and some of the play’s leading researchers. The event will combine main stage presentations with dedicated breakout track panels, all focused on a singular theme: innovation. Steve Benson, chair of UND’s Department of Petroleum Engineering, will headline a panel of speakers who are at the forefront of the Williston Basin’s future. Benson will discuss the research efforts that his staff and students have undertaken in the past three years—efforts that are a direct result of industry requests and partnership proposals. According to Benson, the research work will help to meet industry needs of the present, and change the way Bakken-focused firms operate in the future. Joining Benson on the panel, “Finding The Next Innovation,” will be Jim Sorensen, senior research manager for the Energy & Environmental Research Center, and John Staub, team leader of exploration and production for the U.S. Energy Information Agency’s Office of Petroleum. Sorensen will deliver a presentation and an update on the EERC’s efforts to utilize

INNOVATION Top researchers, industry experts, executives and technology providers will address the future of the Bakken-Three Forks Shale play at an event aimed at the Bakken’s global impact and potential for innovation. By The Bakken Magazine Staff





CO2 in the oil industry. His presentation, “Potential to Use CO2 for Enhanced Oil Recovery in the Bakken,” will reveal how the EERC and industry partners have been able to tackle the Holy Grail of the Bakken’s future, EOR. One of EERC’s partners, Denbury Resources, has already purchased property in the Cedar Creek anticline of both Montana and North Dakota for more than $1 billion. In his presentation, Staub will explain why the EIA has created and is now perfecting a better way to track shale oil production. Earlier this year, Staub and his team unveiled a tracking method that accounts for drilling rig efficiency, initial production rates, decline curves and other metrics that are calculated to better assess North America oil production that is largely driven by horizontal drilling. Lynn Westfall, EIA’s director, calls the new oil reporting method exciting from an intellectual standpoint and for the industry. Joeseph Hartmann, director of the Harold Hamm School of Geology and Geological Engineering, will present on the current state of the school’s research efforts since Hamm


and Continental Resources Inc. invested a total of $14 million in the school. Hartmann will also provide a list of benefits associated with the school’s resources, including the Continental Resources High Resolution Virtual Core Library. Will Gosnold, another researcher from the Harold Hamm School, will discuss his efforts to make geothermal heat an alternative to well site power in the Bakken. A poster session on display for the entire event will offer the most promising young researchers two days to offer insight to the most promising research projects. Some of the student presentations have been delivered to Houston-based executives through private meetings. For those interested in the use of water in the Williston Basin, an all-star group of experts will provide an update on several major projects or technologies recently deployed in the play. Members from Halliburton, AE2S Water Solutions and GE Power & Water will all discuss efforts to recycle frack water, pipe recycled water from the well site or decrease disposal costs by treating frack water. To highlight the innovation approaches


used to create some of the highest producing Bakken wells to date, Liberty Resources will lead a panel focused on explaining the methods used to turn a potential well site into a record-breaking well. In July 2013, Liberty Resources sold its Bakken assets, but prior to the asset sale, the Denver-based completion and production company, had proven that its approach to completing a Bakken well was second to none. According to Liberty, the company’s unique completion design was pumped on a total of 86 company-operated and partner company wells, “resulting in the highest production rates per well among operators in the Bakken formation.” Liberty will be joined by a Canadian-based company, NCS Energy Services LLC, that has quietly been completing wells with three-mile laterals and over 50 discrete fracture stages per well using an innovative down hole tool. To answer any questions regarding the future of proppant usage in the Williston Basin, Carbo Ceramics Global Engineering Advisor Terry Palisch will present on the ins and outs of proppant selection in the Williston Basin,



including new products and operator trends. Scott Greenbauer, technical product manager from Texas-based Santrol, will unveil a newly created self-suspending proppant technology that offers better production without increased cost. The proppant technology has just started to break into the Bakken, according to Greenbauer. Both will be speaking on the panel, “The Proppant Push: Trends in Size, Placement, Type and Volume.” For an update on the overall North American oil energy industry, the American Petroleum Institute’s Chief Economist, John Felmy, will deliver a speech on the policies, economics and regulations that are worth noting in 2014. North Dakota is responsible for the two most recent refinery projects since the '70s, and members from the Dakota Prairie Refinery under development near Dickinson, N.D., and the Thunder Butte Refinery under development on the Fort Berthold Indian Reservation, will each provide an update and overview of the respective projects. Patrick Montalban, president and CEO

of Mountainview Energy, a Montana-based exploration and production company, will provide an all-access glimpse into the world of a small, independent operator and what it takes to finance, contract, complete and operate a Bakken well in the past and into the future.

Building Business in the Bakken Innovation in the oil patch isn’t linked solely to energy-related technology. And, a one-day preconference seminar aimed at helping businesses of all kinds understand, expand or maintain operations in the Bakken, will show why. The preconference seminar has brought together many of the play’s leading minds and decision makers responsible for developing economic success. The seminar will include the following multi-presentation panels: The New Boom: Emerging Markets and New Opportunities in the Bakken; Accessing Bakken Business: Case Studies in Successful Company Entries and Sustainable Business Models; The Case for Place: Why Companies Operate From Within the Bakken. The emerging markets panel will include

presentations from Tom Rolfstad, director for the Williston Area Development Foundation, Jerry Chavez, president and CEO, Minot Area Development Corp. and Darick Franzen, president, Watford City Chamber of Commerce. Keith Lund, vice president of the Grand Forks Region Economic Development Corp., will deliver a keynote presentation explaining his team’s success at bringing major Bakkenbusiness entities to the region. Lund was recently elected to the Greater North Dakota Chamber board of directors. Sponsors for the entire three-day event range from the quickly growing pipeline firm, Chaznline Construction, to Coil Chem LLC, an Oklahoma-based chemical provider. The event has also drawn interest from several media partners, including among many, The Williston Herald. The North Dakota Association of Oil and Gas Producing Counties highlights a list of supporting organizations involved with the event.


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January 2014 - The Bakken magazine  

The Bakken magazine is the #1 trusted source of essential, comprehensive insight about Bakken region professionals, companies and communitie...

January 2014 - The Bakken magazine  

The Bakken magazine is the #1 trusted source of essential, comprehensive insight about Bakken region professionals, companies and communitie...