Page 1


New From The Field Promising Tech Here Now Or Coming Soon Page 16



Crude Export Operator Transfers Destinations Bring New Players Page 22

Page 14 Printed in USA





Pg 22


Bakken Export Expectations

Early reactions from the oil industry and the best markets for light tight oil. BY THE BAKKEN MAGAZINE STAFF

4 Editor’s Note

Pg 16

Focus On Technology Underscores Main Bakken Theme


New Bakken Oilfield Tech

From wellsite infrastructure to the subsurface, new technology products are entering the Bakken play for reasons that have nothing to do with oil prices.


6 ND Petroleum Council

Expectations For The 24th Williston Basin Petroleum Conference BY TESSA SANDSTROM

5 Events Calendar


ADVERTISER INDEX 28 AE2S 10 Bartlett & West ON THE COVER: Energy Recovery Inc.'s pressure pump could reduce the number of units on the well site from 20 to 3. The VorTeq was tested and proven in the Bakken. Schlumberger has agreed to license the technology. IMAGE: ENERGY RECOVERY INC.

14 ISCO Industries 11 J-W Energy Company

15 Convey-All USA

25 KLJ

12 Dunlop Protective Footwear

24 Matrix Service

21 Evoqua Water Technology LLC

19 Protego USA, Inc.

13 Gibson Environmental Services

27 Texas Classic Productions

5 Hotsy Water Blast Manufacturing LP 26 iLevel Digital

2 The Bakken Conference & Expo 20 United Piping, Inc.




Focus On Technology Underscores Main Bakken Theme An under told, sometimes untold, story has emerged from this month’s issue on oilfield technology in the Bakken. Despite the activity-related realities of

low oil prices, new entities are entering the Bakken. Luke Geiver Oil prices aren’t low enough to gloss over the apparEditor The Bakken magazine ent opportunities several segment specific entities believe exist in the Williston Basin circa 2016. New-tothe-Bakken operators from Iowa, Minnesota, Colorado and Texas are taking over both legacy wells and undeveloped leaseholds with an eye on both the near- and long-term. Former oil executives are raising private capital to acquire existing assets and production. Private equity groups are forming just to partake in the Bakken play. As we found out in our efforts to detail some of the more interesting or promising technologies coming soon or recently launched there are numerous reasons why companies are eyeing the Bakken. Low oil prices are certainly a reason to push a new product to upstream or midstream entities. As existing companies work to cut costs, any product or service that can change the bottom-line dynamic is welcome. In many cases, however, new products are entering the Bakken despite the price of oil. New products and technology packages come from the competitive nature of an unconventional play. Continued revenue requires constant innovation and a better offering, we were told. There are simply too many entities that offer a similar service or product in the massive oil and gas space to remain idle and keep product lines stagnant. The quest for more efficient operations in the field or the boardroom is also a gigantic reason why new products are being brought to the Bakken. New regulations, which always seem to be part of the Bakken, are also a reason new tech hits the Bakken market. In the end, we learned the negative of a low oil price is not enough to deter the product developer or the potential client from researching or investing in a new product or a producing well or field-related asset. Following the work put into this issue looking at oilfield technology offerings, I expected to comment on some of the impressive or unique things coming to the Bakken. You can read about a few of them in our page 16 feature. The real theme for this issue, one that was certainly unforeseen but also one we should have expected, is instead about the reality that low oil prices simply do not have the ability to overshadow one of the things the Bakken is, and always has been about: innovation and opportunity.

VOLUME 4 ISSUE 1 EDITORIAL Editor Luke Geiver Staff Writer Patrick C. Miller Staff Writer Ann Bailey Copy Editor Jan Tellmann

PUBLISHING & SALES Chairman Mike Bryan CEO Joe Bryan President Tom Bryan Vice President of Operations Matthew Spoor Vice President of Content Tim Portz Marketing & Sales Director John Nelson Business Development Manager Bob Brown Account Manager Austin Maatz Circulation Manager Jessica Beaudry Marketing & Advertising Manager Marla DeFoe

ART Art Director Jaci Satterlund Graphic Designer Lindsey Noble

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. To subscribe, visit 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 866746-8385 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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Expectations For The 24th Williston Basin Petroleum Conference By Tessa Sandstrom

We recently bid farewell to 2015, and for many in the oil and gas sector, ushering in a new year was welcome. The year presented many challenges and these challenges were highlighted often. What was not highlighted, however, was just how well the industry was able to manage. In reading through a write-up from last year, I had lauded the fact that industry was figuring out how to produce oil economically at $70 and even less. Today, prices are under $40, but production has continued as industry has gotten better and better at recovering more oil with less. This is thanks in part to advancements in technology, which will be a major focus of this year’s Williston Basin Petroleum Conference in Bismarck, N.D., May 24-26. The WBPC began as a hydraulic fracturing symposium and explored the technologies that have since unlocked the Bakken, defining our region as one of the top energy pro6

ducers in the world. This is a feat that more than a decade ago may not have seemed plausible. At that time, the retrieving Bakken crude was still considered uneconomic. The relentless work of industry pioneers led to the innovation and combinations of technologies that have since made the Bakken shale play a worldclass resource. The conference has evolved since its early days to focus on more efficient oil drilling and completion methods that are helping us recover more than 1 million bopd from the Williston Basin. This year, we are pleased to welcome many prominent industry and company leaders to discuss the technologies and efficiencies that are changing the way we develop our vast natural resources. Among them will be SM Energy’s president and CEO Jay Ottoson. Ottoson has more than 28 years’ experience in the industry and will share his knowledge and experience in optimization. Also joining him on this topic will be Gerbert


THE NEW LEVEL: The last time the Williston Basin Petroleum Conference took place in North Dakota, oil prices were trading much higher. Producers have shown their ability to take operations to a new level, however, as production has remained above 1 million barrels of oil per day despite the price of oil.

Schoonman vice president for Hess Corp.’s Bakken assets, to talk about the company’s work with efficiency, lean manufacturing and the future of the Bakken in the current conditions. One of the bright spots of 2015 was the passage of a provision that lifts the ban on

crude oil exports. For more than 40 years, the U.S. was victim of price fixing by OPEC. This ban prevented the U.S. from participating in what is otherwise a global market, but Congress wisely voted to lift that ban in December. While the benefits of lifting this ban won’t be immediate,


TECHNOLOGY FOCUS: Along with several speeches delivered from oilfield executives, the 2016 WBPC schedule will include a look at unique technology.

it does present an opportunity for Bakken crude to find new markets with our allies in Europe and Asia. To discuss these new market opportunities will be Lian Yok Tan from K&L Gates out of Singapore. Ms. Tan has more than 20 years of experience in energy, including serving as an advisor to companies on joint ventures and mergers, project development, financing and operation and oil and gas exploration and commercialization among other areas of expertise. Attendees will also hear a keynote address from Don Hrap, president of Lower

48 for ConocoPhillips. Hrap leads the development, operations and services related to the company’s exploration and production business in the Lower 48 region of the U.S. and will offer valuable insight into the future of the Bakken and ConocoPhillips’ involvement as one of the largest producers in North Dakota. Encouraging our industry’s best and brightest to find these new opportunities will require leadership, especially during these more difficult times. To inspire current and future leaders, legendary coach Lou Holtz will provide the keynote address the

final day of the conference. Deemed “the master of the turnaround,” Holtz’s experiences and lessons learned as a coach can be applied outside of sports, especially when and where leadership is needed most. We also want to thank this year’s participants and sponsors. We recognize that there are many shows each year focused on the oil and gas industry, but your continued support ensures that we can continue the WBPC and its reputation as one of the best and biggest conferences dedicated to the Bakken and shale plays overall.

A few years back, the motto for the WBPC was “The best is yet to come.” We still believe that’s true. We look forward to the discussions that will grow out of the 24th Annual WBPC and continue the momentum we have seen in the Williston Basin well into 2016 and beyond. Author: Tessa Sandstrom Communications Manager, North Dakota Petroleum Council 701-557-7744





Dakota Access pipeline receives approvals from SD, Illinois A $3.8 billion pipeline capable of carrying nearly half the Bakken’s daily production to tank farms in Illinois has received approval from regulatory agencies in South Dakota and Illinois and is expected to receive approval from the North Dakota Public Service Commission (PSC) in January. The 1,134-mile-long Dakota Access Pipeline crosses North Dakota, South Dakota, Iowa and Illinois to connect the Bakken with the Patoka Hub in southern Illinois. From there, it ties in with the Energy Transfer Crude Oil Pipeline to the Sunoco Logistics terminal in Nederland, Texas. The 30-inch pipeline will initially transport 450,000 barrels of oil per day, but can be expanded to 570,000 barrels. The pipeline is being constructed by Dakota Assess LLC, a partner with Texas-based Energy Transfer LP, one of the largest limited partnerships in the United States. It operates approximately 71,000 miles of natural gas, natural gas liquids (NGLs), refined products and crude oil pipelines. In Iowa, where the Dakota Access pipeline met opposition from landowners, farm groups and environmental organizations, the Iowa Utilities Board concluded the public hearing process in December, but was not expected to make a decision until February. However, Lisa Dillinger, Dakota Access spokesperson, says the company hopes for an earlier decision to maintain a construction schedule that would enable the pipeline and its related facilities to be ready for service by late 2016. “We appreciate the IUB moving skillfully through the hearings that have now concluded,” she said. “We will do all that we can to support the IUB in its decision-making process to meet this 8

timeframe.” Near the end of 2015, Dakota Access had secured 77 percent of the voluntary easements needed in Iowa, compared to 85 percent in North Dakota, 91 percent in South Dakota and 83 percent in Illinois. Overall, the company had 83 percent of the total easements along the pipeline’s route. In North Dakota Julie Fedorchak, Public Service Commission (PSC) chair, said the agency could make a decision on the Dakota Access project as early as Jan. 20 during its regularly scheduled meeting. “Barring any unforeseen problems at this point, we hope that we can get this thing wrapped and taken care of within a month,” she said. Fedorchak said there are two issues left to be resolved before the PSC can render a decision. The first involves shared working space between Dakota Access and the Enbridge Inc. Sandpiper pipeline project and which company will be responsible for reclamation on the right of way. The other issue involves reports to the State Historic Preservation Office. Fedorchak said Dakota Access is required to provide reports on how the pipeline route will impact historic sites and what mitigation measures it will use. “That’s a pretty important piece of the siting process because one of our main reviews is on cultural impacts,” she explained. “I’m hopeful that all that is going to be taken care of.” In December, the South Dakota Public Utilities Commission approved a permit for the Dakota


North Dakota

South Dakota

If this pipeline is constructed, it is imperative and nonnegotiable that construction and reclamation be conducted in a manner that allows farmers and ranchers impacted by the pipeline to very quickly get back to their business of producing food for the world in a manner uninhibited by the pipeline






Barring any unforeseen problems at this point, we hope that we can get this thing wrapped and taken care of within a month


Access pipeline on a 2 to 1 vote. PUC Chairman Chris Nelson introduced more than 50 conditions he says were Near the end of 2015, Dakota Access intended to protect the land and landhad secured 77 percent of the voluntary owners during the construction and easements needed in Iowa operation of the pipeline. All but one of the conditions To move Bakken crude from Illinois to the were unanimously approved Gulf Coast, an existing 678 mile stretch by the commission. of natural gas pipeline will be converted. “If this pipeline is conIowa Another 66 miles of new pipeline will structed, it is imperative and also be built. The entire project will be non-negotiable that concomplete by the end of 2016 struction and reclamation be conducted in a manner that allows farmers and ranchers Illinois impacted by the pipeline to very quickly get back to their business of producing food for Missouri the world in a manner uninhibited by Kentucky the pipeline,” says Nelson. Commissioner Gary Hanson Tennessee opposed the approval, saying Dakota Access had not selected a route that Arkansas prevented the pipeline from interfering with development in the Sioux Falls area and surrounding communities. In addition, he said Georgia Dakota Access was not a good Alabama corporate citizen because it sued some landowners before it had a permit to build the pipeline. He suggested that the company apologize to those landowners and reimLouisiana burse them for legal expenses. “I don’t want to stop Dakota Delivery Points Access from eventually getOrigin Sites ting its permit,” said Dakota Access Pipeline Hanson. “I simply Energy Transfer Crude Oil Pipeline want it done right.” Bayou Bridge Pipeline Nederland Terminal Approved States

Acting commissioner Rich Sattgast, South Dakota state treasurer, cast the deciding vote in favor of granting a permit to Dakota Access, saying he believed the company will be a good steward and that it has met the burden required for permit approval. Sattgast and Nelson agreed that the silence from most government entities along the pipeline’s route indicated that they had no problem with its location. Nelson noted that Dakota Access had made changes to the route when the city of Sioux Falls and Lincoln County voiced concerns. Nelson said the decision to approve the Dakota Access pipeline wasn’t based on “whims of PUC, but based on complying with all applicable laws.” In his view, the pipeline doesn’t pose a risk to or substantially impair health and safety, and that it won’t interfere with development along the route. “Dakota Access has demonstrated that they have a legal right to have the permit issued to them,” said Nelson.




Saltwater research efforts explore different remediation strategies North Dakota’s two largest universities are conducting research projects in an effort to generate long-term solutions to reclaiming former Bakken oil field sites negatively impacted by salt water. North Dakota State University and the University of North Dakota Energy and Environmental Research Center, funded by the North Dakota Industrial Commission, are conducting the research on legacy or old brinecontaminated sites. The pits are several decades old, formed before the practice was outlawed in 1983. “The idea of the project is to try to come up with a means


of returning those lands to productive use,” said John Harju, EERC vice president for strategic partnerships.

Drain tile

The EERC, which received $500,000 from the North Dakota Industrial Commission, is focusing its research on a saltwater pit in northern North Dakota near Bottineau. The EERC researchers who began studying the area this past fall discovered that the contaminated area is nearly nine acres, more than double the four that it had previously been characterized as, Harju said. The increase in size may be the result of an inaccurate initial


NEW SOLUTIONS TO OLD PROBLEMS: Brine contaminated sites found within the legacy brine study will offer new remediation approaches a perfect place for testing. PHOTO: NORTH DAKOTA STATE UNIVERSITY

characterization, groundwater moving through the drilling pit and broadening the distribution of the salt water or a combination of both of those things, Harju said. Because the contaminated area is larger than previously thought, returning the land to production will require a different approach than the one EERC originally planned to take and the reclamation project will take lon-

ger than the one or two years the EERC had anticipated it would take, Harju said. One approach the EERC is considering includes the use of drain tile to stop the migration of salt, flushing water through the impacted area into a shallow sump, and then removing the saltwater with a pump and disposing of it in a deep saltwater injection and disposal well.


Bringing salt to the surface At NDSU, researchers, led by Aaron Daigh, a soil scientist, are studying whether it is feasible to use the chemical iron (3) hexacyanoferrate to reclaim oilfield land that has been damaged by storing of salt water or salt water spills. The iron (3) hexacyanoferrate brings the salt to the soil surface so it can be removed, said Kevin Sedivec, an NDSU range management professor who is coordinating the research project. In contrast, other chemicals bind with the salt particles and are pushed further into the soil when it rains, Sedivec said. “It’s a fix, but over time you have the same problem,”

he said. “What we wanted to do was look at something that brings salt to the surface, and then remove it from the surface.” The salt that rises to the surface is removed by either a machine that power sucks the salt or scrapes it off with a tractor/loader, Sedivec said. The salt would need to be disposed or injected into an approved site that is already approved for brine products, he said. Laboratory research conducted at NDSU showed that application of the iron (3) hexacyanoferrate, which is mixed with water and ammonia, brought nearly 70 percent

of the salt on high-salt soil, to the top, Sedivec said. The NDSU research team believes that the chemical could be applied shortly after a salt water spill, before the salt penetrates deeply into the soil, he said. The legacy or old brine contaminated sites will present more of a challenge because the salt in those locations is deep in the soil, Sedivec said. Some of the sites are from the 1970s, Sedivec noted. On those old sites, additional techniques may be needed in addition to the application of the iron (3) hexacyanoferrate, he said. An advantage of using the iron (3) hexacyanoferrate on salt spills or storage sites is that it is available on the market and is non-proprietary so anyone can buy it, Sedivec said. Using

the chemical is a more affordable option than hiring a company to remove the soil that has been ruined by the salt, and then hauling in new soil to replace it, Sedivec said. Meanwhile, using the chemical is a more sustainable option than the “dig and haul” technique because it doesn’t involve replacing the ruined soil with good soil from another location, he said. Next summer, Sedivec will plant grass on sites in which the salt has been removed. The research team has been experimenting in the laboratory with different breeds of grasses and is looking at planting species which are native to the area, he said.


ND rail update to improve efficiency, accessibility, safety The last time North Dakota’s rail plan was updated was in 2007. Oil and gas development in western North Dakota has greatly increased rail traffic in the state since then, but agriculturebased commodity movement has also increased. The amounts of agricultural commodities and oil shipped within the state have risen sharply during the past eight years, said Ben Ehreth, of the North Dakota Department of Transportation. The new rail plan will comply with the requirements of the federal Passenger Rail Investment and Improvement Act, which was enacted in 2008, Ehreth said. The NDDOT is leading a team of six state agencies working to develop the new state

rail plan. The goal of the state agencies is to draft a plan that will provide efficient, accessible service to rail customers and improve rail safety. The new rail plan is expected to give guidance to the rail systems and services that North Dakota freight shippers and passengers use for at least the next 20 years. Besides the NDDOT the other North Dakota agencies working to develop the plan are: the Public Service Commission, the Department of Commerce, the Department of Emergency Services, the Pipeline Authority and the Upper Great Plains Transportation Institute. The team developing the plan will look at several topics, including how the state rail

network has changed over time, how the network meets the needs of its users , and how it impacts the residents, the state economy, freight and passenger reliability, safety and the environment. The first major task of the

team is to gather stakeholder and public input. That will include public meetings and interviews with individuals. A public internet survey also is being developed and is expected to be launched in the next several months.

condition, including crossings and rail lines 1Railroad

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12 Dunlop_201505_OGM_03_USA_v10.indd The BAKKEN MAGAZINE JANUARY/FEBRUARY 2016 1



18-06-15 23:47


The rail plan is being developed in three phases, beginning with establishing the current rail system’s baseline. Phase one work began in September 2015 and is expected to continue through early 2016. Phase Two will iden-

Dakota’s emergency 4 North response procedure

tify North Dakota rail needs and opportunities, and has a target completion date of May. Phase three, which will look at rail service and investment, is scheduled for completion by late fall. The new rail plan under

development may be the most important since the original was drafted in 1980, said Denver Tolliver, Upper Great Plains Transportation Institute director, noting that safe, cost-effective and reliable rail service is es-

sential to North Dakota’s, energy, agricultural and manufacturing industries.

5 Tank car specifications

railroad freight, 3 Existing passenger demands and future needs

safety and environmental impacts on the state, including “tradeoffs” with other types of transportation 6 Economic, such as highways, pipelines and air

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Low oil prices attract new players to Bakken


The low oil price environment is opening the door for new Bakken entities. From the wellsite to the refinery, new-to-the-Bakken companies are working to become a long-term staple of the Williston Basin. Backed with $100 million in funding from Post Oak Energy Capital, a team of former Houston oil executives has announced their efforts to acquire acreage, wells or assets in the Bakken. The UpCurve team is led by Denis Pone who is responsible for ConocoPhillips’ horizontal refracturing program. According to the UpCurve

team, the Bakken and other main unconventional basins “not only harbor thousands of refract opportunities due to the presence of older, less advanced completions, but also possess equally attractive undeveloped opportunities.” Angelus Private Equity Group may not have the same type of experience as the UpCurve team, but that hasn’t stopped the recently formed equity group from entering the Bakken. In late December, the company announced it had acquired 9,750 net acres including undeveloped leaseholds in Montana and North Dakota

from Emerald Oil Inc. for roughly $10 million. Not every new entrant into the Bakken is focused on extracting oil from the ground. A team from Texas and California has announced its plans to build a diesel refinery near Belfield, N.D. Meridian Energy Group Inc. intends to break ground on a facility this summer. The proposed location offers several advantages, the team believes, including its proximity to transportation infrastructure, low-cost natural gas in the region that can be used to fuel the plant and favorable policies and proce-

dures with local permitting authorities. And, according to Frederick Bloom, business development vice president, the downturn in oil prices has created a golden age for refineries. Lower prices can potentially increase profit margins for refineries, he said.

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Operator Transfers

Low oil prices are increasing the number of operator transfers. As current operators look to realign operational strategies, new operators are seizing the opportunity to take over existing assets. The North Dakota Department of Mineral Resources has been updating its list of operator transfers more frequently this year. The list shows operator transfers from 2014 to current.

Legacy Oil & Gas ND Inc. Crescent Point Energy U.S. Corp. Enduro Operating LLC Solutions Energy LLC American Eagle Energy Corp. Resource Energy Can-Am LLC Oxy Little Knife LLC Lime Rock Resources III-A, LP Oxy USA Inc. Lime Rock Resources III-A, LP Whiting Oil & Gas Corp. Foundation Energy Management Whiting Oil & Gas Corp. Cobra Oil & Gas Corp. EOG Resources Inc. Parshall SWD LLC High Roller Wells LLC NGL Water Solutions Bakken LLC Whiting Oil & Gas Corp. White Rock Oil & Gas LLC Executive Drilling LLC Core 54 Oil & Gas LLC Saul Azar DBA Illinois Energy LLC Leland Oil & Gas LLC Whiting Oil &Gas Corp. North Plains Fidelity Inc. Scout Energy Management Whiting Oil & Gas Corp. True Oil LLC Fidelity Kaiser - Francis Oil Co. Key Energy Services, LLC Swanson Oilfield Services Inc.

# of wells 92 8 87 4 342 103 42 1 1 80 1 2 53 63 53 99 1

Blue = New to the Bakken from Texas Orange = New to the Bakken from Colorado Green = New to the Bakken from Iowa




New Bakken Oilfield Tech Offerings in the play today, or slated for arrival soon, show low oil prices aren't the only reason new technology continues to enter the Bakken. By Luke Geiver

Any perceived, or real, activity slowdown in the Bakken hasn’t affected the influx of new oilfield technology. New offer-

ings are entering the Bakken for a myriad of reasons, including: in-field operational gains, regulatory requirements, cost savings or at the most basic level, just for the sake of doing things better. To underscore the continued arrival of technology into the Bakken or the greater unconventional oil and gas industry, our team has detailed a handful of new tech offerings that are impacting the Bakken today or could soon be operating in the play.

Technology Coming Soon

GroundMetrics, a full-service survey and monitoring company spun out of the U.S. Department of Defense, may not be in the Bakken yet, but the company’s proven approach to tracking hydraulic fracture

fluids or finding bypassed pay in mature fields should have exploration and production teams interested. The California-based firm has already been contracted to perform a refracture survey of a mature oilfield in the Barnett Shale. The GroundMetric’s team has developed a system to create a multimile resistivity map that shows more data on fluid properties, distribution and movement up to 11,000 feet below surface. The key to the system, according to Mark Wilkinson, vice president of unconventionals and a geophysicist for the company, is the capacitive sensor used to obtain the data. As long as the team can put the sensor in contact with the ground, it can be deployed on sand, frozen ground, wet ground or rocky ground. Typical electrical sensors on the surface can only penetrate to 1,000 meters, Wilkinson says. Through the

FIELD OFFICE DATA: The GroundMetrics team utilizes sensors placed on nearly any surface, including frozen ground. The sensors explain changes in the earth below the surface that can help show where missed pay still exists. PHOTO: GROUNDMETRICS







GroundMetrics approach, a well bore casing is used as an antenna to send a signal from the sensor further down into the earth and capture data at the depth of a typical fracture event. The sensors, originally designed to find tunnels in the ground for the DOD, can actually detect changes in the earth while materials are being injected, Wilkinson says. No other method, including seismic, can track where fluid is going directly. Due to the system’s ability to track fluid, GroundMetrics has also used the system for waterflood and CO2 injection projects. Before the team partakes in a project, a field team performs a simple modeling of the survey area at no cost to the client. Then, the team creates a 3D model of how the survey project is expected to go.


SUSPENDED PROPPANT BENEFITS: FairmountSantrol's suspended proppant product has clearly displayed a production up tick versus offset wells. IMAGE: FAIRMOUNT-SANTROL

A Wyoming frack job helps to illustrate the predictive power of the sensors, Wilkinson says. Using the GroundMetrics system, the team was monitoring seven stages of a frack job. The fluid used on the job included fracture tracers capable of showing where the fluid was ending up. On one of the stages, the team gained data that suggested the frack fluids broke into a preexisting fracture. “We predicted to the client that the fluid had traversed across two laterals to the west,” he said. Although the team showed the data to the client, they weren’t interested. But, the client became very interested in the data and predictive power of the system after they detected the tracer chemicals two wells over from the original survey well. “Though commodity prices are down, clients are seeing the value in what we bring to the table. We are busy,” Wilkinson says. “We are backlogged into the beginning of the year.”

New Regulations Bring New Approaches

DEEP REACH: The sensors designed by GroundMetrics are capable of collecting data to more than 10,000 feet below surface. PHOTO: GROUNDMETRICS



An April 2015 North Dakota Industrial Commission rule requiring the total vapor pressure of Bakken crude to be verified before transport set a Bismarck technology developer in motion. The rule, intended


to ensure the volatility of Bakken crude, mimicked that of other high-volume liquid shipments like refined gasoline, requires all North Dakota producers to utilize a verification technology. The majority have relied on heater treaters installed on the well site to test the Reid vapor pressure numbers of the crude. But, heater treater units can suffer from the climate in the Bakken, experiencing operational difficulties in extreme cold temperatures or high winds. In mid-December, the NDIC approved a request by Hellervick to test a prototype capable of exceeding the operational capabilities of the commonly used heater treater. The company has also setup a pilot test with an undisclosed operator at an undisclosed location. “The main difference between current heater treaters and the Hellervik oil conditioning unit is that the Hellervik unit is able to continuously measure the vapor pressure of the crude oil in the vessel,” says Lowell Hellervik, CEO and founder. “It is then able to control the temperature and pressure within the vessel dynamically to achieve the pre-selected vapor pressure that the well operator desires.” The technology relies on tempera-

ture distribution through oil agitation and nozzle configuration. An onboard computer can adjust those control parameters and adjust accordingly for external factors such as weather.

Expected Segments For Upgrades

As the unconventional oil and gas industry evolves, frack sand and proppant suppliers are not content to sell basic products used in the past, no matter the price of oil. Many continue to tweak the size, strength, source and overall effectiveness of their offering. Changing frack fluids also creates new opportunities to bring new offerings to the market. Fairmount-Santrol, a Texas-based proppant manufacturer, exemplifies the constant quest of proppant suppliers and developers to offer a new and exciting product. In the Bakken and Three Forks formation last year, Santrol completed a sixwell field trial of its suspended proppant product for Enerplus Corp. When compared to offset wells, the six wells hydraulically fractured with the suspended proppant recorded a production increase of 39 percent. The proppant is made with a hydrogel polymer wrapped around a proppant piece. The design, once added to wa-

MADE FOR THE BAKKEN: Hellervik's crude conditioning technology is made to operate in cold, windy conditions. A computer mounted on the unit can take outside variables like weather and temperature into its measurements. IMAGE: HELLERVICK




SET-UP FOR THE FRACK: In the Barnett Shale, GroundMetrics has been contracted to verify the benefits of a proposed refrack project. PHOTO: GROUNDMETRICS

ter at temperatures starting at 35 degrees Fahrenheit or above, swells and suspends itself in the water. The Propel system allows for faster fracks and less water, according to Santrol. Each well used the same volume of proppant per lateral foot. Each well was a horizontal well that reached roughly 10,000 feet. The pump rate for the suspend product, Propel SSP, wells was 60 barrels per minute compared to the 35 bpm for the crosslinked, white sand wells. To frack the Propel infused wells, it took roughly 75 hours. The offset wells required nearly 87 hours to complete. Enerplus saved nearly $1.00 per barrel of water and the system paid for itself in roughly four months at $45 West Texas Intermediate oil prices.

Transformative Bakken Technology

Joel Gay, president and CEO of Energy Recovery Inc., is happy that the story of the VorTeq pump follows many narratives. The pumpâ&#x20AC;&#x2122;s unique design can save pressure pumping firms maintenance and per-barrel pumping costs. A VorTeq-infused pump set-up is also more efficient than most traditional pressure pumping layouts. And, the system 20



The success of ERI can be duplicated, he says, and it will be seen in the future. Low oil prices have essentially forced the industry to adopt and streamline practices of maintaining existing infrastructure, he says. “I see a renaissance of efficiency. We didn’t develop the VorTeq because we saw an opportunity in a downturn,” Gay says. “We developed it because we saw values across all elements of the cycle.” On the topic of other entities following ERI’s lead into the greater oil

not only helps during a time of low oil prices, it also holds promise as the basis for the fracture infrastructure blueprint of the future. Last year, Schlumberger agreed to a license agreement for the VorTeq pump. Liberty Resources has already used and tested the system for more than a year. Through a clause in the Schlumberger agreement, the global energy services firm and Liberty will be able to continue using or add the VorTeq pump to Bakken frack sites. The system, built of tungsten carbide, can reduce the number of plunger pumps needed on the frack job site from 20 to 3 centrifugal pumps. The pumps can also last roughly 60,000 hours before maintenance is required. Pumps used today typically last 6,000 to 8,000 hours. “We isolate the pumps from the proppant,” Gay says. “Pumps break down due to the erosive nature of the frack proppant in the pumps.” From a company standpoint, Gay believes the success of the VorTeq shows how his team has completed a case study on how small and nimble firms can entreanch itself in an established industry.

industry during the near-term, Gay is also positive. “I think you will see a lot of interesting technologies and innovations that will lower the operating expenses for the entire value chain." Author: Luke Geiver Editor, The Bakken magazine 701-738-4944


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Bakken Export Expectations Industry reaction and destination possibilities By The Bakken Magazine staff

VOLUME SHIPMENTS: Most tankers capable of moving light tight oil from the U.S. will range in size from 300,000 to 600,000 barrels. PHOTO: THE BAKKEN MAGAZINE

It didn’t take long for NuStar Energy L.P., one of the largest independent liquid terminal and pipeline operators in the U.S., to become a crude exporter. Shortly after Congress approved a bill to remove the 40-year old ban on exporting U.S. crude in early December, NuStar went to work for ConocoPhillips. From its North Beach Terminal in the Port of Corpus Christi, NuStar loaded and shipped Eagle Ford light crude retrieved by ConocoPhillips through a contract with international trading company Vitol. The destination or 22

volumes shipped have not been disclosed, but Vitol does own and operate a refinery in Switzerland. Enterprise Product Partners, which ships through a contract with Vitol, also announced it would begin exporting crude shortly after the ban was lifted. Although industry leaders have been unable to describe in detail how the ban’s exit will impact the shale energy industry in the short-term, the majority believe the ban’s removal is a boon to the industry over the long-term. “Modernizing our nation’s energy policy to reflect


this new era of energy abundance is a win for consumers, is a win for small business owners who support the energy supply chain, is a win for our economy and is a win for our allies and trading partners,” said George Baker, executive director of Producers for American Crude Oil Exports. “Now that we have leveled the playing field, the U.S. finally has an opportunity to compete and realize our nation’s full potential as a global energy super power.” Lifting the ban will provide long-term benefits to North Dakota, said Ron Ness, presi-

dent of the North Dakota Petroleum Council, even if there is no immediate impact on oil prices. Energy producers and midstream companies are both exploring and executing on new strategies and investments that can make exporting U.S. crude possible. Pioneer Natural Resources, a large independent oil and gas exploration company, has already said it is actively working with its midstream partners to secure export facilities along the U.S. Gulf Coast for future export deals. NuStar has already made investments in


additional storage tanks, dock space and automated systems at its Corpus Christi port. The company is also planning to build a second dock at the port. The new dock would bring NuStar’s total to four, and once built, would allow the company to load crude simultaneously at a maximum rate of 90,000 barrels of crude per hour. Crude oil tankers are classified into several categories. Tankers capable of shipping refined products are typically smaller, in the 70,000 barrel size range. Tankers most suitable to ship light crude oil, however, could move as much as 550,000 barrels per tanker. A tanker’s capacity is measured in deadweight tons. Its capacity in barrels is calculated by estimating 90 percent of the ships deadweight tonnage and multiplying that by a per barrel conversion factor specific to each type of petroleum product, according to the U.S. Energy Information Administration.

HISTORIC SHIP: The vessel, THEO T, departs Corpus Christi with the first US export shipment of crude oil in 40 years. PHOTO: PORT CORPUS CHRISTI

Average Freight Rate Assessment (AFRA) Scale - Fixed Cargo type Vessel class, capacity (thousand deadweight metric tons) Refined products

10,000 to 25,000

MR (Medium Range)

Crude Locations

Pioneer Natural Resources will initially focus on exporting crude to Europe, Asia and Latin America. The majority of its crude will come from the Eagle Ford or Permian Basin. Experts from Turner Mason & Co., a Dallas-based engineering and consulting firm, believe most exports will reach Mexico or other parts of Latin America in the near-term. Some will also reach Europe. In the future, the Atlantic Basin—not China— could be the top market for American producers, says John Auers, executive vice president at TMC. “Europe wants to reduce

GP (General Purpose)

LR1 (Long Range 1)

Refined products or crude oil


25,000 to 45,000 45,000 to 80,000

80,000 to 120,000

LR2 (Long Range 2)

VLCC (Very Large Crude Carrier)

80,000 to 160,000

160,000 to 320,000

Crude oil

ULCC (Ultra-Large Crude Carrier)

320,000 to 550,000




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LATIN AMERICA â&#x20AC;˘ Home to 2 OPEC members, Venezuela and Ecuador â&#x20AC;˘ Region is net long crude, but quality is "mismatched" with refinery capability â&#x20AC;˘ Have not been able to execute projects to fix "mismatch" â&#x20AC;˘ Light crude has market as diluent for blending with very heavy

TOTAL LATIN AMERICA 22 Countries 70 Refineries 7.4 MMBPD MEXICO 6 Refineries 1.5 MMBPD BRAZIL 13 Refineries 1.9 MMBPD

REST OF LATIN AMERICA 20 Countries 51 Refineries 3.9 MMBPD

U P S T R E A M . M I D S T R E A M . D OW N S T R E A M .






its energy dependence on Russian and other undependable sources such as Africa,â&#x20AC;? he said. â&#x20AC;&#x153;Having access to at least another source of crude that fits well with their refineries is a plus.â&#x20AC;? The majority of crude exported from the U.S. will be shipped from the Gulf Coast,

Auers also said, but for the Bakken, that isnâ&#x20AC;&#x2122;t a bad thing. As more barrels are moved from Texas to the coast to non-U.S. markets, market space onshore in the U.S. will open for more Bakken crude. Since passing the bill to repeal the export ban, Congress has already discussed the


EUROPEAN REGION • 3 distinct regions: Northwest, Mediterranean, Eastern. • Total crude runs of 14.5 MMBPD in 2014 • Limited and declinging regional production; 60% is imported • EU has over 70% imports NORTHWEST EUROPE 12 Countries 56 Refineries 8.4 MMBPD

MEDITERRANEAN EUROPE 10 Countries 43 Refineries 5.5 MMBPD

TOTAL EUROPE 31 Countires 127 Refineries 16.7 MMBPD

EASTERN EUROPE 9 Countries 28 Refineries 2.8 MMBPD


possibility of implementing a tax break for U.S. refiners that were utilizing cost-advantaged crude from U.S.-based shale plays. Ports along the Gulf Coast expect to see increased activity moving Eagle Ford crude. Port Corpus Christi already has deep water, dock space and abundant storage but it plans to deepen the channel near the port to accommodate some of the

world's largest tankers. "Infrastructure improvements at Port Corpus Christi have placed our port in a unique position as a critical component in the export of U.S. crude and condensate," says John LaRue, the port's executive director.

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The Bakken Magazine January/February 2016  

Oilfield Technology

The Bakken Magazine January/February 2016  

Oilfield Technology