Page 1



Waterless Fracking Page 30


Inside The Flare Tech Business Page 24


Coiled Tubing Realities Page 38 Printed in USA

Above Ground Clarity

Options For Operators Looking To Streamline, Cut Costs Page 50







Mechanical Products




pg 30

Pg 30


Waterless Fracking

Could future Bakken wells be fracked without water? Although it might seem unlikely, these companies highlight why compressed natural gas or CO2 could someday replace water. BY EMILY AASAND

Pg 38


Classifying Coiled Tubing

Coiled tubing-based fracks offer pinpoint fracture assurance and faster well cycle times, but not without challenges. BY LUKE GEIVER



48 Bakken Plastics Plant

pg 24

Pg 24


Breaking Into The Flare Business

LPP Combustion’s efforts to prove out its innovative flare capture technology reveals the challenges for companies trying to supply flare equipment to the industry. BY PATRICK C. MILLER

Natural gas feedstocks sourced from the Bakken are slated for North Dakota’s most expensive materials production plants ever. BY PATRICK C. MILLER


50 Searching For Unconventional Savings

Accenture and Melissa Stark have spent two years compiling information for operators looking for above-ground savings. BY LUKE GEIVER

6 Editor’s Note

Waterless Fracking, Coiled Tubing and Cost Savings BY LUKE GEIVER

8 ND Petroleum Council

Impact Funding For Western North Dakota BY TESSA SANDSTROM

ON THE COVER: Pumpjacks operating in McKenzie County, North Dakota. PHOTO: JESSIE SCOFIELD

10 Events Calendar 14 Bakken News

Bakken News and Trends




Waterless Fracking, Coiled Tubing and Cost Savings Waterless fracking may not be as improbable as it sounds. For our November issue, staff writer Emily Aasand explored the many Luke Geiver

Editor The Bakken magazine

challenges of hydraulic fracturing minus the use of water as a proppant and pressure dispersant vehicle. In her story, “Waterless Fracking,” Aasand explains its many benefits and highlights two alternatives to water: metacritical (cryogenically treated) natural gas and CO2. Each option decreases the volume of water needed pre-frack as well as the volume that requires handling post-frack. Proponents for each option claim the merits of waterless fracking are linked to the logistical process reductions needed per well, but each also include the potential for greater well productivity. Neither is currently viable for Williston Basin wells due to equipment or technology availability. Both companies Aasand spoke to, however, said that while energy service firms and exploration and production companies are always in favor of investing in proven technology, they are also looking to deploy the next best thing. LPP Combustion, like many companies attempting to enter business in the Bakken, believes its flare capture and utilization technology is the next best thing. The past few months, the company has traveled North Dakota, visiting the communities of Fargo, Bismarck, New Town and Tioga, to demonstrate a system designed to capture and create power from Bakken flare gas. Staff writer Patrick Miller was in communication with the LPP team during its efforts and documents, in “Breaking Into The Flare Business,” the trials and tribulations of a single company working to prove that its technology can meet the unique demands of capturing and utilizing Bakken-produced gas. The team also made a few unplanned stops to demonstrate the technology to undisclosed, interested companies at undisclosed locations. Miller tells of the realities present for any firm looking to provide a solution for—and financially capitalize upon—one of the Bakken’s many challenges. Guided by the broad focus on products and technology, we’ve also included a feature on coiled tubing fracks, a method gaining popularity in the Bakken due to its ability to offer precise fracture placement and quicker well completion and production start times. The method uses coiled tubing to place 90-plus fracks per well with unique bottom hole tools and placed mechanical fracture sleeves. For operators looking to save money on costs associated with above-ground options, we also detailed the work of Melissa Stark, managing director of New Energy Business for the global consulting firm Accenture. Stark reveals four areas of above-ground operations associated with unconventional shale plays, like the Eagle Ford and Bakken, where operators can save money. Her team also offered a profile of each type of operator working in unconventionals, to highlight the areas in which each operator type could look for savings during a time when crude prices are unstable. I hope you learn as much as we did.

For the Latest Industry News: Follow us: 6



VOLUME 2 ISSUE 11 EDITORIAL Editor Luke Geiver Staff Writer Emily Aasand Staff Writer Patrick C. Miller Copy Editor Jan Tellmann





Bakken Directory


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President Tom Bryan


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CEO Joe Bryan


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Miller Insulation


NCS Energy Services, Inc.


Presto Geosystems


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Quality Mat Company


Traffic & Marketing Coordinator Marla DeFoe

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Rossco Crane


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Steffes Corporation



Steptoe & Johnson

Art Director Jaci Satterlund


Taylor Power Systems


2015 The Bakken Conference & Expo


The Biosolve Company

Graphic Designer Lindsey Noble

4 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 service@bbiinternational. com. 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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Impact Funding For Western North Dakota


By Tessa Sandstrom

I remember my family’s first mobile phone. It

was a bag phone that had to be plugged into the cigarette lighter and a big magnetic antenna was placed on the top of the vehicle. It was archaic by today’s standards, and some would argue could hardly be considered a mobile phone, but back then, it was pretty neat. As a farming family, we could call home to make sure no one needed anything else from town. And our parents could rest easy knowing that if we got stuck during the 14mile drive to town, we were a phone call away from help. As phones became more mobile and affordable, the benefits of convenience and security only became more evident. In the book, “How We Got to Now,” that I wrote about in last month’s column, author Steven Johnson talks about the unintended consequences of Google. Similarly, I doubt many of us who had one of the early cell phones ever could have anticipated the unintended consequences we have come to see: texting and driving, the disconnect we have from actual verbal and personal communication, or the “electronic leash”―the inability to get away from work email or phone calls after hours or while on vacation.


COMMON VIEW: Drilling rigs operating in North Dakota can finish the vertical and horizontal portions of a well in roughly two to three weeks. PHOTO: JESSIE SCOFIELD

Oil and gas technology is no different. When oil and gas development really took off following the 2006 Bakken discovery well near Parshall, North Dakota, state and local leaders did anticipate some of the consequences they would see as a result—a growing population, the need for more housing, hotels, restaurant or retail, a chance to see communities grow. What they did not anticipate—nor did the industry—was the extent to which we would see this growth.


Like Google founders, the industry did not, and could not foresee the social impacts shale development would bring to the state because shale development was, and still is, a modern technological marvel. As well after well would soon show, however, oil and gas development would become so successful that North Dakota would be catapulted to the national and world spotlight as an economic miracle. Young people who had been leaving the state in droves were staying

or coming back to North Dakota for plentiful and lucrative jobs and careers. Rural communities that had been slowly dying were growing. For those who remembered past boom and bust cycles, making major investments was hard in those early stages of development, but today, we know oil and gas development is here to stay and is generating billions of dollars every year in tax revenues. The positive news is that the impacts or consequences from development we


face today should only be temporary, but it will require using those tax revenues to invest in our impacted communities. Returning more of these dollars to western North Dakota will be the North Dakota Petroleum Council and its members’ No. 1 priority when the 64th Legislative Session convenes Jan. 6, 2015. The first step in this will be to urge for the expedient passage of $800 million in surge funding for oil and gas producing counties so they may begin crucial infrastructure projects as soon as possible next spring. Subsequent efforts will be focused on redrafting the formula so western counties and local governments get more oil and gas tax revenues from the start to meet needs, rather than waiting until the next session. This will be critical over the next few years as employees make decisions on whether to make these communities their home. Adequate affordable housing is important to this, especially as attracting workers becomes more difficult as the demand for qualified workers and job opportunities elsewhere in the country improve. More and more, a solid quality of life gained from good schools, public services, and amenities like entertainment, restaurants

and shopping, is essential to attracting and retaining employees and their families. Workforce remains a primary challenge for the petroleum industry, but improved roads are also important to continuing oil and gas development, which, in turn, protects the state’s tax revenue stream. Impacts from shutting wells down due to poor road conditions are felt over a longer period of time. Many nonpumping wells require rig intervention to get them flowing again, which ultimately adds more trucks on the roadways. A one-day shutdown can result in an oil well being down for a week or more. A well shutdown will impact overall production, which impacts taxes that are needed to continue investing in schools, roads, law enforcement and other services for our communities. This is important because new housing and road infrastructure will vastly improve the quality of life in western North Dakota and benefit the entire state as communities catch up and continue their contribution to a growing, diversified statewide economy. Of course, oil and gas development has many other impacts that we must continue to work through, but many of these, such as building pipeline

WELL INTO THE FUTURE: To fully utilize the hydrocarbon resources present in North Dakota's Williston Basin, total well count could exceed 50,000. PHOTO: JESSIE SCOFIELD

infrastructure, are challenges that the industry can and will meet through time and investments. The underlying challenges, however, are tied to the resources needed for western North Dakota: more homes for employees to build a stronger road and pipeline infrastructure for our state. We have seen many improvements over the course of the year with many small towns voting to expand or build new schools, new retail and restaurants opening every day, and the opening of the by-pass around Watford City, but there is still much more needed. We encourage you to join us this

legislative session in advocating for more resources for western North Dakota. Together, we can turn those unintended consequences into additional opportunities for progress and growth. Author: Tessa Sandstrom Communications Manager, North Dakota Petroleum Council 701-557-7744




The Bakken magazine

will be distributed at the following events: Facilities Design Western Canada 2014 December 9-10, 2014 Calgary, Canada Issue: November 2014 The Bakken magazine

Bakken Flaring Alternatives & Gas Capture 2014 December 9-10, 2014 Denver, Colorado Issue: November 2014 The Bakken magazine

Energy Generation Conference

January 27-29, 2015 Bismarck, North Dakota Issue: January 2015 The Bakken magazine

Williston Basin Petroleum Conference April 28-30, 2015 Regina, Saskatchewan Issue: April 2015 The Bakken magazine

The Bakken Oil Conference & Expo

July 27-29, 2015 Grand Forks, North Dakota Issue: July 2015 The Bakken magazine



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North Dakota saw an overall traffic increase of



The maximum legal weight per axle is

34,000 lbs.

10% axle overload increases road damage by 44%


North Dakota saw a increase in traffic in western North Dakota


ND State Legislature appropriated

$2.3 billion for road repair from 2013 to 2015

ND DOT Bakken progress report North Dakota saw a 22 percent increase in traffic statewide and a 53 percent increase in the oil producing counties according to a progress report from the North Dakota Department of Transportation for a period between 2010 to 2012. “What we’re seeing is growth in transportation, so there’s an awful lot of challenges ahead of all of us in the transportation business in the cities, counties, and state,” said Grant Levi, North Dakota DOT director. 14

The state legislature appropriated roughly $2.3 billion to rebuild and repair state highways, city, county and township roads, bypass routes and other infrastructure upgrades in every region of the state, for the 2013 to 2015 biennium. “We’re very fortunate to have had the state’s governor propose that our state legislative body provide $2.3 billion worth of resources,” Levi said. With the funds, the North Dakota DOT was able to produce two of the largest


construction years in history. The report showed the state allotted approximately $409 million to cover all costs for the construction of truck bypass routes for Williston, Watford City, Dickinson, Newton and Alexander. “We’re building infrastructure that is essential to serve the industries in the state,” Levi said. “One of the projects we’re working on is the U.S. Highway 85 construction project connecting Alexander to Williston. I’m happy to report that the stretch from Watford

City to Alexander is open and functioning.” Taking the trucks out of the communities to “restore and maintain quality of life in those communities” was a high priority for the DOT team, when they sought funding, Levi said. A particular project he and the team have been concerned about and are working on is turning U.S. 85 into a four-lane highway from Watford City to U.S. Interstate 94. Levi has addressed his concern about the level of


North Dakota's Average Daily Traffic 480,000 460,000 440,000 420,000


400,000 380,000 360,000 340,000 320,000 300,000


















Information Provided By N.D. Department Of Transportation

federal funding coming into the state for highway infrastructure. “We are concerned that when you look at the federal picture in the future that resources just won’t be there,” he said. There is no federal highway investment happening unless Congress is able to pass the funding, he said. Although the funding for the four-lane highway is uncertain, Levi and team expect a bypass around Watford City, involving U.S. Highway 23 and 85 to be complete by the end of the year.

The North Dakota DOT is currently drafting an environmental document for another four-lane highway project that Levi said, “will take some time,” to go over with relevant parties and could cost close to $1 billion. Larger loads are also making Levi and his team rethink the road system. Any time there’s an increase in axle weight, he said, road damage goes up at an exponential rate. The DOT’s freight plan, released in June, maps out the DOT’s plan to help create a

road system that can handle greater weights. North Dakota’s unforgiving winters and the DOT’s lack of staffing, are also concerns on top of road damage for Levi’s team and have the department looking for help from outside the department. Outsourcing snow and ice control to private companies has been considered but the department hasn't had any luck securing a provider, Levi said.




WPX Energy to boost Bakken rig count, enhance completion design WPX Energy released its five-year plan to simplify its geographic focus and expand returns, margins and cashflow in its three core resource plays in North Dakota, New Mexico and Colorado. In the three plays, WPX has approximately 16,000 remaining drillable locations on a gross basis, more than 14 trillion cubic feet of proved, probable and possible reserves at the end of last year and approximately 480,000 net acres, the company said.

EXECUTIVE VIEW: New leader Rick Muncrief is outlining a five-year plan. PHOTO: WPX ENERGY

“We’re confident we have the right building blocks in the Williston, San Juan and Piceance basins. We have upside in all three. Our strategy accelerates our oil development and capitalizes on what we can gain from technical excellence, new technology and greater economies of scale,” said Rick Muncrief, president and CEO.


WPX is already executing its strategy by implementing six million pound completions in the Williston Basin. The company says early results from doubling the stimulation size showed a 14 percent production increase from three Bakken shale wells and a 13 percent increase from three wells in the Three Forks formation. The company anticipates its five-year plan will allow for increased oil production five-fold and a chance to triple its operating margins and company value by 2020 compared to its results last year. WPX, in its spinoff of Williams E&P two years ago, had assets in eight areas—seven domestic plays along with South American interests, but after divesting its properties in Texas, its narrowing its strategy to focus on half of its properties—the Williston, San Juan and Piceance basins. The company’s second quarter results show oil comprised 14 percent of WPX’s equivalent production, which is almost double from its 8 percent in 2012. In the same period, the company reported its oil sales have risen from 23 percent to 37 percent. Muncrief said the question he hears most often is, ‘Are you a gas company or are you going to be an oil company?’ His answer is simple, “For WPX, it’s not either or. We’re both.” “With the depth we have


FUTURE VIEW: WPX Energy will focus on its Williston Basin well completion designs in the next five years. PHOTO: WPX ENERGY

in our gas reserves, we like the optionality it gives us. We also believe that our gas is going to be advantaged on pricing because of the access we have to premium western markets,” Muncrief said. “At the same time, increasing our oil output brings significant value to our stockholders. Ideally, oil will account for more than 25 percent of our total volumes as we execute our strategy. That’s going to require us to achieve a five-fold increase in our oil production compared to what we did domestically last year.” Company plans are to improve its drilling economics in the Williston Basin before boosting its rig count there. It aims to optimize completion practices, increase initial production rates and estimated ultimate recoveries in the basin. WPX has more than 220,000 net acres and more than 4,600 wells in the Piceance Basin, and has taken its Gallup Sandstone oil exploration project in the San Juan Basin from

zero locations to more than 400 in less than 18 months, cutting average well costs by 26 percent during the first half of 2014. “The value in our strategy comes down to how well we execute. Changing how we think about our assets and how we manage our business are critical to our success,” said Muncrief. “The greatest change at WPX may very well come from within.” “Our mission is aggressive and measurable. By casting a vision and setting out our strategy, we’re defining what success looks like and providing a means to track our progress. This is part of creating a high accountability culture at WPX and focusing on our long-term value proposition.”


US Surface Transportation Board requires rail transparency Sen. Heidi Heitkamp, D-N.D., announced the U.S. Surface Transportation Board has taken action that will require transparency from all railroads by revealing more data about their rail shipment delays for all products including Bakken crude. This spring, Heitkamp testified before the STB during a field hearing in Fargo where she discussed the need to continue holding the railroads accountable for agriculture shipment delays across the state. Heitkamp also pointed out Burlington Northern Santa Fe and Canadian Pacific each reported nearly 3,000 past-due cars in North Dakota. The order requires all Class I railroads, including BNSF and Canadian Pacific, to release data

including average speeds, dwell times, number of cars loaded and emptied weekly, number of grain cars ordered, loaded, billed, overdue and cancelled by state. According to Heitkamp, this will allow the STB to see any changes in delays of agriculture shipments and if there are delays of other products, such as crude oil and coal. “For more than eight months, our farmers and grain elevators have lost out because of serious agriculture shipment delays across the state,” said Heitkamp. “To stop these delays, prevent them in the future, and help our farmers do their jobs, we need to hold the railroads accountable. Over the past several months, I’ve been in regular contact with STB Chairman Daniel Elliot and

pressed him to look at the delays in our state and determine if there’s anything the agency can do.” According to the STB, the board currently monitors various metrics of railroad performance, but it agrees there is a need for broader standardized performance data from the railroad industry as it continues to address existing service challenges. According to Heitkamp, the STB is taking needed action to hold the railroads accountable, requiring more transparency from the railroads on all products shipped on the rails, and making sure all products—whether grain, oil, coal, or anything else—be treated equally and fairly in how they are transported.

“Chairman Elliot understands the serious consequences of delays on the rails, and he and I will continue to work together to make sure we can reduce this backlog so our nation’s producers, processors, and their families continue to thrive,” said Heitkamp. In July, the U.S. Department of Transportation announced proposed rules for the transportation of flammable materials in the form of a Notice of Proposed Rulemaking and a companion Advanced Notice of Proposed Rulemaking.




New transmission line will serve Bakken electrical demand An electric transmission line project intended to provide reliability and stability in the Williston Basin is set to begin construction after receiving final approval from two federal agencies. Karl Aaker, engineering manager at McKenzie Electric Cooperative in Watford City, North Dakota said the Basin Electric Power Cooperative transmission line is vital to the region’s rural electric cooperatives, which supply electricity to the growing industrial, commercial and residential demand resulting from oil and gas production in the Bakken. “It’s going to be our stiff backbone for supporting the base loads that we keep growing on our system,” he ex-


plained. “It’s everything from the continued growth of oil wells, gas plants, oil processing and even the commercial development and residential development in some of the cities in the area, such as Watford City.” Basin Electric will build a 200-mile, 345-kilovolt transmission line from its Antelope Valley Station north of Beulah to Tioga. The line is expected to be in service by 2017. In separate decisions, the U.S. Forest Service and the Rural Utilities Service gave the go-ahead to the Bismarckbased cooperative. Although approval is still needed from the Western Area Power Administration and the U.S. Army Corps of Engineers,


Basin Electric said the project can start construction in areas outside the two agencies’ areas of authority. “The approval of this line is a significant step forward in serving the tremendous growth in the Williston Basin and beyond,” said Paul Sukut, Basin Electric CEO and general manager. “This transmission project, coupled with our current and upcoming generation projects in the area, will help strengthen the grid, facilitate the delivery of electricity and bring reliability and voltage support to the area.” Forecasts by Basin Electric and its member cooperatives in the Williston Basin region predict that an additional 1,800 megawatts

of generation capacity will be needed by 2035 to serve growing electrical needs. In response, Basin Electric is also expanding two of its natural gas-based peaking stations in the region. “It supports some base load, but it also helps with reliability in the event that any of the transmission lines coming into this area are taken out of service for maintenance or there’s some kind of outage,” Aaker said. “That generation in this area will keep our reliability high and keep the power on to supply power to the increasing growth.”


ND Port Services aim to improve region’s intermodal transportation North Dakota Port Services Inc. is attempting to convince BNSF railroad that transportation costs can be lowered and efficiency improved by increasing intermodal container shipping from its Minot, North Dakota facility. “BNSF railroad doesn’t think we have the market demand up here to quantify having a container service,” says Tawnya Bernsdorf, NDPS director of public relations. NDPS contends that between the imports and exports of products, materials and equipment to serve the oil and gas industry in the Bakken and agricultural exports, the region can support and benefit from improved intermodal transportation services. To accomplish its objective, NDPS hosted a meeting

in Minot on Oct. 27-28. The event provided an opportunity for importers and exporters to meet one-on-one with BNSF, which services the railway’s Northern Tier Intermodal Line, and other freight carriers. In addition to meeting with BNSF executives, shippers were also able to meet privately with individual ocean carriers. The meeting helped BNSF quantify market demand and verify ocean carrier support for intermodal service to the region. Bernsdorf says that improved intermodal transportation would enable shipments of equipment and materials to the Bakken to arrive by rail at Minot and then be trucked to their destinations. Currently, the nearest intermodal

PORT SERVICES SCENE: A planned expansion of the 120-acre Minot facility will allow more pipe needed for new wells to flow through Minot. PHOTO: NORTH DAKOTA PORT SERVICES

transportation facilities are in Seattle and Minneapolis, she notes. Located in the region's agricultural and energy sector, NDPS serves areas 250 miles or more around Minot, including eastern Montana, northern South Dakota, northwestern Minnesota, southern Manitoba, and southeastern Saskatchewan. Examples of import products shipped to the oil and gas industry include heavy equipment, building supplies, pipe, proppants, diesel fuel, gasoline, crane mats and other

well completion materials. Bakken exports include crude, propane, butane and condensate. The privately owned NDPS is serviced by BNSF's Northern Tier Intermodal Line, adjacent to the railroad’s Gavin Yard (main-line switch yard) with daily service and four-lane highway access. Located on a 120-acre site, NDPS is planning an expansion. NDPS can handle a full intermodal unit train along with approximately 80 manifest rail cars.

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Low Brent crude prices reveal complexities of Bakken production With crude prices trading at yearly lows and global supply potentially outpacing demand, consider this: Bakken operators consider two main factors when determining the financial breakeven point for new or existing wells: initial production rates and water production, said Lynn Helms, director of North Dakota’s Oil and Gas Division. IP rates can change depending on multiple factors, including: the drilling or completion company’s ability to execute a pre-determined drilling or fracking plan; well location within the Williston Basin; targeted formation; and, the manipulation of a well choke to increase or decrease well pressure. Depending on the size

of choke, a well’s IP rate can go up or down as a larger choke allows more hydrocarbons and pressure to flow to the surface. Operators use IP rates of previous wells to estimate future production in new wells that will be brought online in similar conditions as the previously completed wells. Based on a well’s IP rate, an operator can determine how long it will take the well to break even under a wide range of oil prices. But IP rates are not always exact. Although the geographical formation and surface location for a given well are always the basis for understanding possible IP rates, completion methodologies can alter production.

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In some cases, new fracking designs that utilize higher volumes of sand and water can increase a well’s IP rate above other wells brought online in the same geographic formation and surface location. Operators must determine the economics of increased completion investments and the correlation to better IP rates. Water production can increase the amount of operating costs associated with a given well or field. If the total amount of liquids retrieved from below ground includes a high percentage of water to oil, operators are forced to dispose of the water.

Doing so adds costs and cuts into the overall profits of the well. In areas with high water cuts and average IP rates, low oil prices do not offer an attractive enough financial incentive to invest the $7 million to $12 million it takes to bring a well online. For the North Dakota portion of the Williston Basin, low oil prices could potentially slow oil production in roughly 10 percent of the play, Helms said. Areas that offer IP rates on the low-end of the entire play and also produce high water cuts will not be economical if oil trades in the $70/barrel range.

Operations costs—the cost to power a well site or transport produced water—will be the first area operators look to for cost cutting measures. After that, some may consider laying drilling rigs down, but in most cases, operators have already contracted out for long-term drilling rig use. If oil prices continue to decrease, the state of North Dakota could implement tax triggers designed to keep oil production happening in times of low oil prices. If the price of West Texas Intermediate falls below $52.06 per barrel for five consecutive months, the

state will implement a trigger that that drops the tax rates for horizontal wells in the Bakken or Three Forks formations down to 2 percent instead of the current 6.5 percent. “That would be the most significant tax trigger in terms of incentive for the oil and gas industry to continue drilling and producing but it would be an enormous impact on state revenue,” Helms said. “If it triggers, then it’s in place for a minimum of five months.”


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Energy commodity marketer enters pipeline business Asset Risk Management offers producers marketing services for crude oil, natural gas and natural gas liquids in many of the major basins of the U.S. Through the formation of ARM Midstream, the company has been able to utilize its market knowledge of energy production to help producers with infrastructure needs specifically with oil and gas gathering and processing. Zavanna LLC, a Williston Basin pure-play operator, is now working with ARM Midstream. The company recently unveiled plans to develop a crude oil gathering system spanning from McKenzie County, North Dakota, to various interconnections, downstream pipelines and rail takeaway facilities. Zavanna has signed a letter of intent to be the anchor shipper on the system.

Bakken Hunter divests Divide County acreage

“ARM’s decade of experience in helping oil and gas producers assess and manage commodity risks and issues will be invaluable as we jointly develop this region,� said William Coleman, Zavanna president. ARM believes that the proposed pipeline can provide clients like Zavanna more flow insurance and a greater possible netback for its hydrocarbons produced in North Dakota. “We are looking to provide our producers with better access to more firm markets,� said Paul Williams, vice president of business development for ARM Midstream. At press time, ARM Midstream had not yet announced dates for the start of an open season call to gauge shipper interest for producers looking to move oil.

Bakken Hunter LLC may have picked a good time to divest certain non-core, nonoperated working interests in Divide County, North Dakota. Bakken Hunter, a wholly-owned subsidiary of Houston-Based Magnum Hunter Resources Corp., has sold $84.7 million worth of assets to an undisclosed independent exploration and production company. The properties in Divide County include 720 barrels of oil equivalent along with 105,661 gross leasehold acres. During his monthly Director’s Cut, Lynn Helms, director of the North Dakota Oil and Gas Division noted the role decreasing crude prices may play in a handful of the state’s oil producing counties. Divide County, commonly known to produce high water cuts and average initial production rates compared to the core of the Bakken and Three Forks formations, was mentioned by Helms as a county that could be negatively impacted by falling crude prices. In the announcement on the sale, Magnum Hunter did not mention crude oil prices. The company’s remaining North Dakota assets include 151 gross producing wells constituting 2,577 bopd with an additional 800 bopd increase expected by year’s end. The proceeds of the divestiture have reduced the company’s indebtedness to its growing operations in the Marcellus and Utica Shale plays. “We anticipate the announcement of additional divestitures of non-core assets, which we are currently negotiating, throughout the remainder of the year,� said Gary Evans, company CEO.











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NDOSH Consultation Program 23 THEBAKKEN.COM





BREAKING INTO THE FLARE BUSINESS LPP Combustion’s quest to build, prove and provide the Bakken with an innovative flare capture technology By Patrick C. Miller

North Dakota isn’t the only place in which LPP Combustion LLC is receiving interest in its gas capture technology, but the Bakken is where company CEO Richard Roby hopes the system will prove its commercial worth.

After wrapping a month-long tour of its Lean, Premixed, Prevaporized liquid fuels system around North Dakota, the company will take its demonstration unit to Colorado and then Texas. Roby says LPP is in discussions with major New England utilities and also presented its technology at a flare management and reduction conference in Dubai of the United Arab Emirates. “There are a number of places around the world dealing with similar kinds of problems, and our technology is seen as having international implications,” Roby says. “But we’d love to be able to say that it was first proven in North Dakota.”

Toward that end, the Columbia, Maryland, company spent much of October and part of November demonstrating its LPP system around the state, especially in western North Dakota where it caught the attention of oil and gas operators and oil service companies in the Bakken. Chris Broemmelsiek, LPP’s vice president of sales and marketing, says the North Dakota marketing blitz paid off with two requests for proposals from potential customers who want LPP systems operating at their sites within six months. With the potential to help address flaring, logistical, environmental, safety and economic concerns in the Bakken, it’s no surprise that LPP’s demonstrations attracted the attention of industry, the news media and politicians, including state legislators, and members of North Dakota’s congressional delegation and the state Public Service Commission.

UP CLOSE AND PERSONAL: To get Bakken producers and oil services companies interested in its gas capture technology, Maryland-based LPP Combustion built a demonstration unit that it trucked to North Dakota for on-site demonstrations. PHOTO: PATRICK C. MILLER




HAPPY TO BE THERE: North Dakota Public Service Commissioner Julie Fedorchak attended a demonstration in Bismarck and is shown with LPP senior consultant Sylvan Melroe (left) and Mac Holton, LPP project engineer. PHOTO: LPP COMBUSTION

“With any new technology, there’s always this hurdle you have to get over—you have to find the first adopter,” says Roby, co-inventor of the patented LPP system. “That’s always the toughest part, getting someone to take the risk of being the first customer.”

Investing In The Demonstration

To LPP, the issue of gas flaring in the Bakken represented a major opportunity to help potential customers overcome their reluctance to try something new. “All this fuel was going up in smoke because nobody knew how to properly burn it in a combustion engine to generate electricity,” Roby says. “We had this technology, and there was a huge economic driver, as well as an environmental driver.” Given the declining price of Bakken crude, LPP’s tech-


nology also provides a way for operators to cut costs. “Typically, diesel fuel is being used to power operations in the Bakken. It cost about $5 a gallon delivered,” Roby says. “You put a significant premium on even the market price of diesel fuel. We can reduce the fuel waste and pollution. We can also create an economic value for the drillers, for the operators and for the oil producers because we can give them power to run their operations.” When LPP tried calling potential customers in the Bakken, Roby says the skeptical response they received wasn’t unexpected. “We talked to a number of people who said, ‘Yeah, we’ve got some of those engines and they’re collecting dust in our back lot. They all failed because they couldn’t run on the hot gas,’” he relates. However, the reaction wasn’t entirely negative with


RAW FEATURE: The unique aspect of Lean, Premixed, Prevaporized (LPP) combustion of liquid fuels is its ability to use the entire raw gas stream to produce electricity more cleanly and cheaply than a diesel generator. PHOTO: PATRICK C. MILLER

some saying that they might be interested if LPP could demonstrate its system using flare gas on site. “Ultimately, we took a lot of time, effort and expense to put together this demonstration system,” Roby says. “Now that we’ve come out and done that, we’re getting the response that we expected.” What’s unique about LPP’s technology is its ability to use any combination of light hydrocarbons in the natural gas liquids of Bakken crude which include ethane, propane, butane, pentane and hexane. By increasing or reducing the nitrogen level, the process can be adjusted to

work with the changing composition of crude throughout a well’s production life. “There are different combinations at different wells and within a well,” Roby says. “As a well ages, the composition of the gases changes. You have to have a system that’s robust enough to handle those changing compositions. That’s what we can do.” The system typically operates with a 6 MW generator, but can run a generator up to 30 MW. The cost of running a diesel-powered generator is 35 to 44 cents per kWh while LPP says its system is about 12 cents per kWh.


In the harsh world of oilfield operation,


THE TOUR: LPP Combustion began its month-long tour in North Dakota with a demonstration in Fargo at North Dakota State University's College of Engineering. PHOTO: PATRICK C. MILLER

Knowing the company needed someone in the state familiar with the business landscape, LPP added a key member to its team by bringing on legendary North Dakota entrepreneur Sylvan Melroe as a consultant. He served as the Melroe Co.’s vice president of international marketing and helped make the renowned Bobcat skid steer loader a global success. “Syl Melroe has just been fantastic for us,” Roby says. “He immediately understood the value our technology had for North Dakota. He’s been really helpful in opening doors for us and helping us with the planning of the demonstrations. I just can’t thank him enough.” However, all the demonstrations, business connections and marketing in the world wouldn’t matter if LPP’s technology didn’t work as advertised. What sets it apart from

other gas flaring solutions is its ability to cleanly and efficiently use raw or “hot” gas that has a significantly higher heating value than natural gas. According to Roby, this type of gas is what typically causes problems for conventional natural gas-burning combustion systems. “What we do is modify that fuel stream and bring it back to a heating value of natural gas on a volumetric basis, which is what these gas turbine combustion systems are designed to operate on. That’s the unique aspect of our system,” Roby explains. A gas turbine can’t tell the difference between pipelinequality natural gas and the raw natural gas that’s been heated and diluted to look like natural gas. The gas turbine is attached to an electrical generator to meet electricity needs on site.

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The heat produced can also be used to make hot water for fracking operations. Currently, many drilling sites use diesel-powered generators to produce electricity. Not only is trucking in diesel fuel expensive, but it also increases traffic congestion and the generators create air pollution. Roby says that during the demonstrations, LPP consistently heard three positive comments from potential customers. Besides lower power production costs and reduced air pollution, “They liked the fact that we can use the entire energy content of the flare stream,” he notes. “We don’t have to do any kind of separation, and they don’t have to figure out how to get rid of what they can’t use.” In addition to solving the gas flaring issue, LPP’s technology provides the reliability of a gas turbine, which has longer periods between overhauls than a diesel engine. Roby believes LLP’s solution can also help the oil and gas industry with the issue of Bakken crude’s volatility for rail shipment. He says the volatile organic compounds are left in the crude to reduce flaring and to recover the value of the light liquids.



“If we can provide the economic value for those light liquids at the well site, then that reduces the need to put it into the crude, and the crude doesn’t have to be as volatile,” he explains.

The History Of LPP

Roby, who has more than 35 years of experience in combustion technology related to energy emissions and power production, says that it’s taken 10 years to bring LPP’s system to the commercialization phase. “It’s been a long, arduous process,” he relates. “This wasn’t some backyard mechanic kind of a deal.” The development of LPP technology is one of those serendipitous events that sometimes occurs during research. Roby was part of a team trying to solve the fire safety problem of gases in the headspace of liquid fuel storage tanks being ignited by a lightning strike or static spark. “The idea we hit on is that instead of taking these liquid fuels and vaporizing them into hot air where they can start combusting, we’d take the oxygen out of the air so the mixture couldn’t burn,” he explains. “We took the nitrogen that was left and vaporized the fuel into hot nitrogen, using


the nitrogen both to help in the vaporization and also to dilute it back down.� Years of experience in designing gas turbine combustions systems sparked the idea of trying to trick a gas turbine into acting as if it was burning something other than natural gas. “We knew that gas turbine combustion systems looked for a certain volumetric heating value,� Roby says. “If we could keep all those liquids in the vapor phase and dilute them down enough so that the heating value looked like natural gas, then the gas combustor should perform like it was running on natural gas.� That led to a bench-top experiment. It worked, but more research and testing was needed to convince gas turbine manufacturers that the lean, pre-mixed, pre-vaporized combustion process wouldn’t harm their turbines. LPP followed the same rigorous testing and development process used by gas turbine OEMs such as GE, Siemens, Westinghouse and Pratt and Whitney. To prove the concept, they ran the LPP process on a Solar Turbines Taurus 70 gas turbine using kerosene and No. 2 heating oil. “The next step was to publish our results in the peer-reviewed literature of


the American Society of Mechanical Engineers,� Roby says. “The gas turbine combustion community could examine this and say ‘Yes, their data is right.’ At that point, we could go back to the original equipment manufacturers and, more or less, get their blessing that it would be OK to put this on the front end of their gas turbine.� As Roby pointed out during a demonstration at North Dakota State University, “The beauty of our technology is that our gas turbine doesn’t do anything different. It runs exactly the same as it does running on natural gas. In that sense, it’s boring, but this is a place where boring is good.� Although it’s too soon to know how much of an impact LPP Combustion will have on oil and gas operations in the Williston Basin, Roby is optimistic about the future. “We’ve learned from experience that necessity is often the mother of invention,� he says. “When there’s a big economic driver, risk is reduced because of a big economic payoff. And that’s what we’re seeing in the Bakken.� Author: Patrick C. Miller Staff Writer, The Bakken magazine 701-738-4945










WATERLESS FRACKING New technologies and methods could replace the need for water in hydraulic fracturing By Emily Aasand

The thought of hydraulically fracturing a well without the use of water as the main pressure and proppant-delivery vehicle could someday be realized. New technologies and proven methodologies

based on waterless fracture approaches are giving exploration and production companies and completion crews a water reduction option and in some cases, an option for more productive wells. With oil and gas service companies working to finding an alternative to water-based hydraulic fracturing for water-constrained areas, the possibility of waterless fracking is becoming closer to reality. Praxair and Expansion Energy LLC are two industry suppliers working to prove out the economic, production and water-reduction merits of waterless fracking systems. Efforts of each could eliminate the need for water at well sites and reduce the need to dispose of large volumes of fracturing wastewater.

Expansion Energy Debuts VRGE

Expansion Energy has developed VRGE, a unique, patented waterless fracturing and enhanced oil recovery technology that uses natural gas from nearby wells as the fracturing fluid. â&#x20AC;&#x153;In comparison to water-based fracturing, VRGE can lower total completion costs by as much as $2 million per well, is more resource-efficient and environmentally prudent, and can

THE UTILIZATION OF CO2: DryFrac eliminates water from the fracking process and eliminates issues with water sourcing and flowback that comes with traditional hydraulic fracking. PHOTO: PRAXAIR TECHNOLOGY INC.




VRGE Process Schematic Proppant Storage

Proppant Blender + Slurry Pumps (trailer-mounted) Environmentally Benign Foaming Vaporization & Fluid Heat Exchangers (trailer-mounted)

CCNG Plant - e.g., VX Cycle Cryogenic (skid-mounted) CCNG Pumps (trailer-mounted)

Truck delivery of Oil and/or LNG to market

High-Pressure CNG + Foam + Proppant

LNG/CCNG Storage Tank (can be mobile)

NG pipeline to market

Oil- and/or Gas-Bearing Formation- e.g., shale (~5,000-10,000 ft. sub-surface)

Extracted Oil and/or Gas


increase oil and gas production per well substantially,” says Jeremy Dockter, co-founder and managing director of Expansion Energy. VRGE uses a dense, cryogenic nonliquid fluid phase of natural gas that Expansion Energy calls Metacritical (Meta-NG). Metacritical natural gas is synonymous with cold compressed natural gas (CCNG) that is used as the fracturing medium as well as part of a safe, proprietary proppant-carrying foam. Meta-NG is almost as dense as liquid. VRGE can use produced gas from a an oil or gas well as the main feedstock for the proppant dispersal system. Like injected water, the natural gas used by VRGE eventually resurfaces and can be sold to the market or used for further VRGE fracturing. Extracted oil, natural gas and natural 32

gas condensates evacuate the well bore the same way they exit a hydraulically fractured well, the company says. “Our objective was to develop a non-water fracturing and EOR process where the working fluid, which delivers the pressure and the proppant, would be a material that is widely available in oil and gas fields and is compatible with the hydrocarbon formation in terms of production, as opposed to water, which can actually restrict the flow of oil and gas by causing the shale to swell and increasing surface tension,” says Dockter. “In the case of VRGE, that working fluid is natural gas itself.”

How VRGE Works

Natural gas, potentially supplied from a nearby well, is converted to CCNG by an onsite cryogenic LNG or CCNG production


plant and is then pumped to high pressure with a cryogenic natural gas pump. The high pressure CCNG is then vaporized with heat exchangers into high-pressure, compressed natural gas. The high-pressure, CNG is then blended with a high-pressure proppant-carrying slurry and foaming agent. The combined mixture is injected down-hole to the well bore as an “energized” foam, similar to CO2 and nitrogen foam fracturing fluids. The high-pressure CNG and foam create, extends and holds open fissures in the underground formation while moving proppant into the fissures. Following the fracturing process, the pressure in the well bore is reduced, leaving the proppant to hold open the fissures, thus allowing for the flow of oil and natural gas like a traditionally waterfracked well.


The process is repeated for each stage of fracturing to be completed per well. VRGE can also thermal shock a well. The CNG, foam and proppant can be injected down-hole at temperatures as low as -20 degrees Farehenheit because the slurry is not an actual liquid. The extreme temperatures can shock the warm formation, making it brittle and creating extending fissures. “This LNG plant produces the cryogenic working fluid that VRGE uses to carry pressure and proppant into the well bore to conduct the fracturing,” says Dockter. “Producing CCNG onsite is far less expensive than trucking in LNG from a remote LNG plant. Therefore, the VRGE process optimally produces and uses CCNG instead of LNG.” The design of the system is also based on best practice safety concepts within the industry. “VRGE's safety protocols are compatible with existing oil and gas well safety protocols,” says Dockter.

Dockter, “substantially reduces costs for chemical and fluid additives and biocides.” Like other energized foam-based fracturing systems, VRGE well performance can exceed typical well production rates by 1.5 times or more. The system may also produce shallower decline curves. The technology can be used in fracturing new wells, recompletions, lifting and even for enhanced oil recovery. VRGE has not been deployed yet, but

Dockter says the company plans on getting VRGE into producing fields by 2015 and has strategic partnering discussions underway with several large fracturing services companies considering licensing VRGE before offering it to their producer clients. Forming a new energy services firm able to deploy the VRGE system is also an option, Dockter says. “Our vision is that VRGE will be a transformational technology for the oil and

Advantages The advantage of using VRGE or other waterless fracturing technologies is the plethora of environmental, safety, economic, performance and efficacies they offer, according to the New York-based firm. VRGE eliminates the need for transportation, treatment and disposal of flowback water and chemicals. It eliminates truck water deliveries and reduces the number of pressure pumping trucks and trailers typically needed during a traditional frack job. The reduced traffic helps improve highway safety, which Dockter recognized as a major concern in producing regions. “VRGE’s onsite LNG/CCNG plant allows capture and sale of associated gas instead of flaring, and can also be used to strip NGLs from the gas stream,” Dockter says. VRGE also has economic advantages for oil and gas producers. The waterless fracturing technology reduces well costs when compared to water-based fracturing by eliminating the cost for water consumption and transportation. It reduces the need for new disposal wells and according to




VRGE vs. Other Fracturing Technologies Hydraulic Fracturing (Water + Chemicals

CO2 Foam


Requires "Importing" Fracturing Fluids to Well Site




Significant Truck Traffic/Costs







Water Consumption



None (or Low)

Requires Waste Fluid Disposal



None (or Low)

Viable Where Water is Scarce




Cost for Consumption of Fracturing Fluid

Liquid Used for Foaming



Safe, Non-Aqueous Liquid (or Water)

Recycling of Foaming Liquid




"Contamination" of Produced Hydrocarbons




Requires Chemicals to Mitigate Effects of Water






Temperature & Physical State

On-Site LNG Production + Separation of NGLs




Requires Pipeline to Get Natural Gas to Market




Viscosity Control




gas industry—not just an incremental improvement—which brings many benefits to producers, but without requiring drastic changes in the way producers operate,” says Dockter.

Praxair Utilizes CO2

Unlike Expansion Energy’s waterless technology, Praxair’s DryFrac waterless fracking technology replaces water with liquid carbon dioxide to fracture new wells and for enhanced oil recovery. A blender mixes carbon dioxide and proppant together, the mixture is then pumped at high pressure through frack pumps. “Our technology increases the conventional water blender with a blender that mixes pure carbon dioxide with the sand in precise concentrations necessary for fracturing,” says Mark Weise, business development director of oil and gas services for Praxair.

FINDING A NICHE: Jeremy Dockter and his team's experience in cryogenics and the processing of gases has led to the development of VRGE. PHOTO: EXPANSION ENERGY

According to Weise, the DryFrac waterless technology is exciting for the industry because, “It provides a practical means to use a dry fracturing fluid.” “It maximizes the productivity of the well and it will improve the sustainability of the offering because you don’t

need to source the water and you don’t have to worry about processing the frack water that flows back,” says Weise. “From reliability and a safety point of view, carbon dioxide is a nonflammable gas and therefore it eliminates some of those safety hazards that might be associated with other types of technologies that eliminate water from the fracturing process.” Praxair conceptualized the idea a few years ago, and has since worked to build the equipment and run it through a pilot testing phase before finally proving it down hole with the carbon dioxide and sand mixtures. The equipment controls were the main components needed to make the process a reality, Weise says. Unlike Expansion Energy’s VRGE approach, Praxair’s DryFrac technology is being used in the field, however, the technology has not been used in the Bakken yet.

“It’s certainly an area that everybody has their eyes on,” Weise says. “Right now, we’ve found a reception where people have been looking at being concerned with the water sensitive oil formations out there. The Bakken, I think, would meet those criteria as well.” Author: Emily Aasand Staff Writer, The Bakken magazine 701-738-4976







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COILED TUBING The Bakken’s quickest, surest completion approach brings benefits, and, of course, challenges. By Luke Geiver

Coiled tubing is taking the guess work out of the high-stakes hydraulic-fracturing game happening every day in the Bakken shale play. When used to deploy fracture isolating tools known as bottom hole assemblies, coiled tubing allows completion crews certainty, allowing them to better understand when and where discrete fractures are placed along the lateral of the well bore. Many exploration and production firms have implemented the use of coiled tubing-based fracks in 2014 operations, including Whiting Petroleum. When the Bakken’s largest operator unveiled its second-quarter results earlier this year, the company announced that due to better-thanexpected well results, its 2014 production guidance had increased. Instead of the 18 percent production increase over 2013 it had expected in 2014, newly implemented well completion technologies used in early 2014, including coiled tubing, had caused Whiting’s production guidance to increase for 2014, versus the previous year, to 20 percent. The exploration and production firm specifically called to attention its use of a coiled tubing frack system for producing a record number of frack stages. NCS En-

ergy Services was responsible for the record. (In its Q3 announcement, Whiting again pointed out its success with coiled tubing fracks). The record breaking frack job reached 93 discrete fracture stages, a number nearly double, (sometimes triple), of that capable by other methods. But, although coiled tubing deployed frack systems can offer operators pinpoint stimulation, improved completion cycle time efficiencies, faster screen out recoveries and record breaking wells, there are drawbacks.

Anatomy Of A Coiled Tubing Frack Job

Coiled tubing spools are transported via truck to the well site. The spools house thousands of feet of metal tubing with diameters ranging from one to four inches. Unlike wireline, coiled tubing can be pumped down a well bore. Coiled tubing doesn't depend on the weight of gravity for downward movement. For a coiled tubing-based frack job, a bottom hole assembly (BHA) or tool is commonly attached to the end of a coiled tubing string. The

TOOLS OF THE TRADE: NCS Energy Services uses a bottom hole assembly (pictured here) to perform coiled tubing-based fracks. PHOTO: NCS ENERGY SERVICES




Location Access










Typical Location Layout






3 P


















SIMPLE SET-UP FOR COMPLEX PROCESS: Although a coiled tubing set-up requires a smaller equipment footprint on the well pad, the process can be more complex than other fracture jobs. SOURCE: WHITING PETROLEUM CORP.


tubing procedure requires a lubricator, injector head, tubing reel, support pumps and a specialized well head tree. The overall well footprint of a coiled tubing operation can be less than that of other fracture methods. To create Whiting’s record-breaking well, NCS Energy deployed its Multistage Unlimited frack-isolation system that was recently awarded 2014’s best for completion technology by World Oil. The system included cemented casing sleeves. According to the company, the full-drift casing sleeves are equipped with the same specifications as the host casing and are all identical for a given


well. They are handled like casing joints and are made up into the casing string at planned frack-initiation points. Using coiled tubing equipped with an NCS BHA, the process includes many steps. After the coiled tubing moves the BHA into the well, a resettable bridge plug in the BHA is pulled into the frack sleeves already placed in the well casing. The weight of the coiled tubing and pressure present in the annulus push the frack ports in the casing sleeves open. A fracture fluid is then pumped down the annulus, exiting out of ports on the BHA and through the opened


energy service firm running the coiled tubing string can inject the string deeper into the well or retrieve it upward to place the BHA in a desired position. Proppant and water is pumped down the annulus between the coiled tubing and the casing. Although cemented liners are not necessary for a coiled tubing frack job, many Bakken operators have chosen to add cement to the well bore. Coiled tubing frack sleeves with frack ports can also be placed in the well bore casing string to give the BHA a predetermined segment of the well to situate in. Along with the BHA, a coiled


Quick Comparison

Plug & Perf Based on 4.5 inch (114.3-mm) Casing Multistage Unlimited (five clusters/stage) Unlimited stages Yes Yes Single-trip Yes No Less than 1 hour per stage Yes No Exact frack location Yes No Required frack flowrates, bpm 25-35 85-100 Number of frack units required 3-5 12-14 Circulate fluids to frack zone Yes No Water and chemicals conservation Yes No Remove sand from screenouts Yes No Real-time frack zone pressure reading Yes No Full-open, production-ready wellbore Yes No Eliminates rig-up-rig-down between stages Yes No Cemented annulus Yes Yes Coiled tubing required Yes Yes

Ball-Sleeves No Yes Yes No 85-100 12-14 No No No No No Yes No Yes


frack ports into the rock formation. Following the pressure pumping for the individual stage of the fracture job, a pull on the coiled tubing then opens an equalizing valve in the BHA that retracts the bridge plug. With the bridge plug retracted, the tool string can be relocated to the next preplaced frack sleeve for the next frack. The BHA includes a frack sleeve locater that matches the profile of a receptacle in the casing sleeves helping the coiled tubing operators to locate with certainty each fracture initiation point along the casing. And, for operators who want to add unplanned fractures into the wellbore, the BHA includes a standby jet perforating system through which frack fluid can be pumped into the casing. NCS is also able to measure pressure readings to determine the placement of each frack.

The Coiled Tubing Advantage

Monte Madsen, operations manager for Whitingâ&#x20AC;&#x2122;s Northern Rockies unit, says the NCS coiled tubing frack approach is a new


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tool in Whiting’s arsenal and that although technology like NCS’s has been available since 2011, the ability and adoption of it is still growing. Madsen talked about Whiting's use of coiled tubing during the North Dakota Petroleum Council's annual meeting in September. The advantages of the completion method are already undeniable. Because the system doesn’t require the use of dissolvable balls or plugs, when completions in a well are finished, there is no need to millout existing plugs. “There is nothing to run in the well between fracks, nothing left in the well and nothing to drill out, just a full-open, production-ready wellbore,” he says of its system. When used with frack

sleeves, the BHA assembly can be placed into predetermined sections of the well with certainty, an element of the system that isn’t as present with other techniques. The single point injection system built into the BHA also allows operators to control frack volume which helps to prevent fracture growth into neighboring wells, water zones or other formations where no natural frack barriers exist. To relocate the BHA and shift the frack sleeves open takes roughly 9 minutes, according to the company. Madsen says that for plug and perf operations, the rule of thumb for the number of completed fracture stages per day is 8 to 9 stages. “We have easily done 16 to 18 sleeves opened, pumped and completed

in a 24-hour period,” he says of the company’s use of the NCS system. Because the system pumps liquid down the annulus of the coiled tubing, it also reduces the amount of water that needs to be introduced into the well, an element of the approach that cuts water volume needed and water costs associated with each well. Although production increases will vary from well to well, one feature of the coiled tubing frack that most operators favor, including Whiting, is the time savings. “A key benefit of coiled tubing fracks are cycle-time efficiencies in high well density areas,” the company says. “Without the need to drill out

the plugs, we have been able to accelerate production by five to seven days per pad.” The use of coiled tubing is not without flaws. To date, one of the main limiting factors for operators looking to deploy it in the Williston Basin is the length offerings available for coiled tubing spools. Because laterals are surpassing the 2-mile mark in some cases, coiled tubing cannot be used due to the length limits of some systems. Well path variability is also an issue. A well’s path, Madsen says, is not a level line. Instead, he says, think of using coiled tubing like pushing rope through a tube. Because the path of the well varies, it can be difficult to navigate the tubing through the well. Erosion from sand slurry-induced friction can

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24 Months On Production



4 to 10 stages

11 to 20 stages

21 to 30 stages

31 to 71 stages

Well Count

Well Count

Well Count

Well Count

Number of Wells in Each Group

Total Oil (bbl )

Production Type Curve, Stages/Well






LOOK FOR THE GREEN: The coiled tubing injector, painted green, pushes the coiled tubing into the well head. The injector allows the tubing to reach 10,000 feet or more. PHOTO: NCS ENERGY SERVICES



also occur on the well bore and tubing. Coiled tubing frack jobs arenâ&#x20AC;&#x2122;t less expensive than most jobs either. Several coiled tubing providers exist in the Williston Basin, with more on the way, however. From Minot, North Dakota Halliburton offers coiled tubing services along with Integrated Production Services and Coiled Tubing Solutions. C&J Energy Services operating out of Williston, North Dakota and Dickinson, North Dakota also offer the service along with several others. For operators looking to increase well-cycle efficiency or in some cases production, technologies like NCSâ&#x20AC;&#x2122;s have proven themselves. Although every operator may not be look-

ing to place 93-plus discrete fracture stages in an individual horizontal, there are three main elements of a record-breaking well for NCS. First, an operator needs to commit to undertaking completion activities that have the highest probability of a known result. Second, the process of completing a well must involve diagnostics to measure and quantify any downhole activities that may produce variable results. And, third, an operator must separate what it knows from what it thinks it knows. Author: Luke Geiver Managing Editor, The Bakken magazine 701-738-4944



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LEADERSHIP APPEAL: Members from Badlands NGL and leaders from North Dakota posed for a photo following the announcement of the facility. PHOTO: NORTH DAKOTA GOVERNOR JACK DALRYMPLE

Bakken Plastics Plant By Patrick C. Miller

A $4 billion manufacturing plant—the largest private investment in North Dakota’s history—will provide up to 500 jobs, help the state’s oil and gas industry achieve gas capture goals in the Bakken and create new markets for products and byproducts. 48

North Dakota Gov. Jack Dalrymple and William Jeffrey Gilliam, CEO of Badlands NGL LLC, last month announced that Badlands and its partners will invest $4 billion in a manufacturing plant that will produce polyethylene used for consumer and industrial plastics. “North Dakota elected officials and agencies have provided Badlands with by far the most business-friendly and pro-


development environment in the United States,” Gilliam says. “We have been fortunate to attract many of North Dakota’s leading business and community leaders as Badlands investors, and we continue to discuss debt and equity capital markets needs with major financial institutions.” The manufacturing plant will tap into the Bakken’s supplies of liquid natural gas for

ethane used to produce polyethylene for consumer and industrial plastics. Locations and byproduct marketing opportunities are being considered for the plant. “We’re still going to need the pipelines in the ground to get that resource to the plant rather than transporting it to Canada or down to the Gulf,” says Tessa Sandstrom, North Dakota Petroleum Council communica-


tions manager. “But that facility will be right here, creating more jobs in North Dakota.” The plant will produce 1.5 million metric tons of polyethylene, or 3.3 billion pounds annually, and will employ 500 people in manufacturing, marketing, administrative, safety, financial and executive positions. The project will take at least three years for full development. “This project is fully aligned with our goals to reduce flaring, add value to our energy resources right here in North Dakota and create diverse job opportunities across the state,” Dalrymple says. “By advancing the responsible development of our energy resources and by adding value to all of our resources, the opportunities in North Dakota are boundless.” Alison Ritter, public information officer with the North Dakota Oil and Gas Division, notes that the timing for the plant’s completion should coincide well with the state’s requirement to reduce flaring to 15 percent by the first quarter of 2016. “This comes at a good point for companies that are already looking for ways to reduce flaring, but then may have an additional need to put excess ethane somewhere else,” she explains. “It’s just a good fit and a good timeline based on North Dakota’s needs. We reach another capture goal in 2016, and so this 2017 timeline fits well with capture goals that are already set. Now instead of flaring, it will have a place to go.” Badlands NGL intends

to market the majority of the polyethylene products domestically, but will also reach markets in Asia, South America and Europe. Project developers say the plant’s location in North Dakota will enable them to efficiently ship to world markets from the Pacific Northwest and from Atlantic ports. “Badlands is proud to bring this manufacturing facility to North Dakota,” Gilliam says. “We are committed to maximizing the value of Bakken ethane for producers, their midstream partners and all gas processors. This facility is the solution needed to add value to North Dakota’s ethane supply and make it a commercially marketable product. In doing so, there will actually be a market advantage for North Dakota polyethylene products.” Gilliam says it makes sense for the plant to be located just east or to the south of the Williston Basin and near the oil and gas activity in the Bakken formation. “We’re not closing the door on any options right now,” says Shane Goettle, a Badlands NGL spokesperson who heads the public affairs division at Odney, a Bismarck-based marketing, public relations and advertising firm. “The location will be dependent upon how we route the ethane to the plant,” Goettle explains. “We’re working with all of the midstream companies—as well as the pipeline companies—to see how we source it and how we best get it to the plant. That will ultimately determine location—along with

access to rail—which is another factor.” Goettle says Badlands NGL’s plan is to break ground for the plant by next summer, which means the decision for the location could be announced any time between now and then. Access to a water supply will not play a major role in determining the plant site, Goettle says. “We’ll need water for cooling as one of the processes, but the water can be reconditioned and recycled through the plant,” he explains. “Water’s not going to be an issue for us. There will be no wastewater out of this plant at all.” Goettle says the polyethylene plant is designed to be environmentally friendly. “In fact, we’re looking at technology for the capture of CO2 to market as a byproduct,” he noted. The most likely market would be for food-grade CO2. However, Goettle didn’t rule out the possibility that the CO2 could also be sold for enhanced oil recovery, for which it’s currently used in Canada. Another potential byproduct is hydrogen, used by oil refineries and by fertilizer plants for the production of anhydrous ammonia. “There are also some other things we can do with hydrogen, and we’re taking a look at what the market will be for that,” Goettle adds. Badlands is working with two strategic partners, Tecnicas Reunidas, based in Madrid, Spain, and Vinmar Projects of

PIPELINES ARE THE PLAY: Although produced gas from the Williston Basin can be trucked to a future facility, Badlands NGL is looking for pipelines to transport the gas. PHOTO: CALIBER MIDSTREAM

Houston, Texas. TR, one of the largest petrochemicals and polymers contractors in the world, is working on a preliminary engineering analysis for Badlands NGL, scheduled for completion in 2014. It will include technology evaluations, engineering and planning, and final site selection. Vinmar provides services in support of project finance for the development partners. Vinmar and Badlands NGL have signed a mutually binding, 15-year memorandum of understanding for 100 percent of the polyethylene to be produced by the Badlands project. Also participating in the plant announcement at the State Capitol in Bismarck were Agriculture Commissioner Doug Goehring and Attorney General Wayne Stenehjem, who serve with Dalrymple on the North Dakota Industrial Commission. U.S. Sen. John Hoeven, R-N.D., also took part in the event.




TYPICAL SCENE: Disorganized well pads featuring multiple contractors waiting on materials may be typical today, but Accenture has the answer to fix the problem for future wells. PHOTO: THE BAKKEN MAGAZINE

Searching For Unconventional Savings By Luke Geiver

Operators in search of above-ground cost savings need to talk with Melissa Stark. As

the managing director of Accenture’s New Energy Business, Stark has led a two-year team-effort to identify ways various-sized operators can reduce expenses related to well construction, drilling, completion, logistics and material man50

agement. Stark’s team has spent the past two years researching the unconventional oil industry, talking with operators working in the Eagle Ford and analyzing data and interview recordings for a new report applicable to all shale plays, “Achieving High Performance In Unconventional Operations: integrated planning, services, logistics and materials management.”


Of the report’s many findings, operators that deploy the practices proven to be successful in the report, could decrease well costs by $1.3 million to $2.6 million on a $6.5 million well. “Operators can achieve these savings by adopting a more integrated planning process, better management of service contractors, and improved logistics and materials management for

fresh and reused water, proppant and installed equipment,” the report says. “A lot has been said and written about the manufacturing approach, but overall, we had a feeling that there are still above ground opportunities to improve operational efficiency and effectiveness to reduce costs,” Stark says. “We wanted to drill down. We wanted to un-


derstand what has been done— especially around standardization, consistency of crew, configuration of productionline type operations, implementations of LEAN-productiontype initiatives—and what the leading players were working on to further improve. We believe,” she adds, “that integrated planning, the management of services, logistics and materials management are still areas of improvement for the industry that become even more important in a falling oil price environment.” To gain insight into the industry, Stark’s team worked with operators in the Eagle Ford including EOG Resources and Anadarko Petroleum. “The Eagle Ford interviews helped us narrow down to four topic areas, but the drill-down into each area came largely from the project experiences of our global shale teams who have worked in either shale gas, tight oil or coal bed methane in the U.S., Canada, Australia and China,” she says. By the end of the data- and information-gathering process, the team knew there were significant opportunities through improved planning, management of service providers, improved logistics and materials management. They also came to understand that companies need to balance their investments in technology, continuous improvement and people. “Depending on the issue being solved, the solution may require more of one than the other two, and it’s important to know

which lever is the most relevant. You cannot afford to focus on all three. Trade-off decisions must be made,” she says. To help clarify how the trade-off decisions can and have been made, the team included a description of the type of operator working in most plays similar to the Eagle Ford. The study examined three operator types: conventional players who have significant unconventional investments,

large dependents that primarily have an unconventional focus and smaller independents. Conventional players are those that show a strong bias toward technology. Large independents have a bias towards continuous improvement in all phases and small independents focus on getting the people part of operations right. All three groups shared commonalities including: using optimal rigs equipped with

top drives and high horsepower draw works and pumps; signing rig contracts and completion crew contracts for 2 to 3 years; standardization of well pad design; using multi-well pads and batch drilling; producing a standard set of drilling metrics based on well data; and, increasing the use of scanners, bar codes and tablets. Conventional operators look to solve challenges in their unconventional resource

MATERIAL MANAGEMENT: Operators of all size should focus on how and when materials arrive at the well pad. The management of materials can help save on operations costs. PHOTO: BOB BROWN




Different segments of operators and their attitudes towards technology, continuous improvement and people


Structured continuous improvement

Predominately conventional operators

Large independents

Small independents

Leader Capital budget allows for technology innovation

Fast follower Technology investments based on field tested results

Lagger Capital budget constraints

Mature IT frameworks enable operational efficiencies

Missed opportunity to create step change in productivity and efficiency

Lagger Data and technology not leveraged to drive continuous improvement

Leader Strong continuous improvement culture embedded throughout all parts of the organization

Lagger Collaboration enables some continuous improvement

Fast follower Enabled through structured process and operating model

Leader Strong people and collaborative culture

Missed opportunity to make informed trade-off decisions People/culture

Lagger Collaboration challenged by operating model constraints

Missed opportunity to take a more structured, scaleable, and measurable approach


plays with new rig technology, network connectivity and advanced software. For example, the report noted, they use Wi-Fi and smartphones for logging drilling data in the field and have developers for mobile well applications. Conventional operators also are moving towards rig automation technologies to reduce the headcount on location and leverage off site experts to make decisions about drilling techniques and technologies to use. Large independents are focused more on unconventional resources in the U.S. and have significant experience in shale and tight oil formations, the report said. Many 52

are working towards aggressive growth targets, with 2012 capital expenditures ranging anywhere from 33 percent to more than 100 percent of their annual revenues. These operators do not spend time or money on technology that does not contribute to their returns, but instead rely on oilfield service firm’s own work in research and development. They are, however, fast followers in applying new technologies. Although large independents look at the latest and greatest rig technologies, they also analyze the trade-off of investment versus return. This class of operator uses drilling performance and well metrics


to inform decision making. “One leading large independent in our study said it pushed for incremental gains to save 1 percent on its well costs and was able to then hone in on shaving 15-minute increments off high-cost areas in the drilling lifecycle,” the report said. Because most large independents found success in the U.S. unconventional plays, they already have the right organizational structure to enable cross-functional communication and decision making at the asset level. “A leading independent operator interviewed for our study had managers overseeing no more than 7 to 10 rigs and a person respon-

sible for profit and loss statements, including production operations, but not burdened with support services.” Small independents, according to the study, manage operations with an emphasis on strong people and a culture that empowers those people to make decisions. They are able to compensate for weakness in technology and process in their operation by hiring experts, collaborating with service providers and maintaining a tight group of people they can rely on to overcome the learning curve of each basin, the report said. With smaller budgets, small independents are not as


Technology, Continuous Improvement and People - relative importance in improving integrated planning, management of service contractors, logistics and materials management Improvement areas

Technology Continuous improvement Long-term step change in Sustained and creative, performance but often incremental, improvements

People (culture) Focus on empowering the best people on the front lines

Integrated planning

Planning tools at field, well and supply chain levels

Need to overcome silos in organization and involve service providers

Management of services

Required to support process Even small improvements in handovers and reduction in Mobile, tracking and duplication of effort will collaboration technology add up

Think of service providers as a teaming relationship. Incentivize competition and team performance

Logistics management

Control tower required to optimize scheduling of fleet and manage HSE

Data and analytics will continue to provide incremental improvement opportunities

Need to work with logistics providers

Materials management

ERP backbone material visibility tool, access to supplier information

Small improvements in handovers, sharing of demand and supply information, optimization

Need to work with vendors across wells and facilities

Planning process should be as simple as possible. One version of drilling schedule


advanced when it comes to rig technology. “The big challenge for the small independent operation is that, despite its strength in collaboration and clear alignment on the direction in the operation, there will come a time when it will need stronger systems and processes to scale up beyond a certain threshold,” the report said. No matter the size or type of operator, the report unveiled common characteristics found with most leading operators. Many take a holistic approach to managing contractors at multiple sites, developing plans flexible enough to accommodate short-term changes and stable enough to

provide long-term accountability. They make plans based on rig projections as far as three years into the future. Streamlining interactions with contractors via financial controls and standardized procedures also helps. Logistics management is a huge focus for leading operators. Successful operators take into account an end-to-end view of water and strategic use of technology considering flows of commodities require transport and which modes of transport will be applicable, all in consideration of where a potential storage facility may be located to offer the most flexibility. Some operators are

also tracking materials and service function in real-time. Stark’s team can provide services to work with operators on integrated planning, logistics, materials management, services management, water management, drilling analytics, unconventional finance and unconventional IT. Although the study offered the team a chance to help unconventional players find areas to save money, Stark and crew aren’t finished. “We want to do a report on big data and analytics and the application in a high well count environment. We think there is a lot of potential to apply statistical techniques used

in other industries to mine the vast amounts of data being produced,” she says. The team has already worked with MIT on the effort. “It’s still in the early stages,” she says, “but there are definitely some tools out there that can be used to enable companies to use the vast amounts of data being generated to support decision making.”



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The Bakken Magazine November 2014  

The Bakken Magazine November 2014

The Bakken Magazine November 2014  

The Bakken Magazine November 2014