Page 1

MAY 2015

Core Beliefs

'Rockstar' Kathy Neset Explains Drilling, Fracking Evolution Page 34


Cost Savings Through Frack Fluid Changes Page 24


WBPC Review: Oil Price History, Basin Region Updates Page 42 Printed in USA

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MAY 2015


Pg 30


A Geologist To The Core

Kathy Neset, one of the Bakken’s most prominent figures, explains the state of directional drilling and fracking in the Williston Basin. BY PATRICK C. MILLER

Pg 42


Conference 2015 Highpoints: Oil Prices, Basin Updates

Williston Basin Petroleum

The Bakken’s mainstay event provides production updates for North Dakota, Saskatchewan and Manitoba, along with oil price impact predictions, possible changes in the Williston Basin BY LUKE GEIVER

Pg 24


Frack Fluid Focus

New technologies for hydraulic fracturing-based processes are providing cost-reduction alternatives to traditional methods. BY EMILY AASAND

6 Editor’s Note

Focusing On Frack BY LUKE GEIVER

8 ND Petroleum Council

ND Oil, Gas Legislative Review BY ALEXIS BRINKMAN-BAXLEY

10 Events Calendar 12 Bakken News

Bakken News and Trends

ON THE COVER: Kathy Neset, owner of Neset Consulting Services based in Tioga, North Dakota, has built a successful oilfield consultantcy firm that serves several major exploration and production companies. PHOTO: THE BAKKEN MAGAZINE




Focusing On Frack If you’ve never seen Kathy Neset demonstrate how directional drilling works using a bendable straw, add it to your to-do list. Founder of Neset Consulting Luke Geiver

Editor The Bakken magazine

Service Inc., Neset has become a prominent participant in the massive growth and evolution of the Bakken shale play. On any given day, she’ll be found in a small community explaining myths of the Bakken, or in Houston, discussing well results with executivesfrom many of the Bakken’s largest oil producers. One of the most recognizable participants linked to the play, Neset can, with her bendable-straw demonstration, communicate the complexities of the Williston Basin to a wide audience. The progression of her NCS operation epitomizes the life-changing opportunity present in the Bakken. For the better part of a sunny spring day, Patrick Miller, staff writer for The Bakken magazine, was fortunate enough to join Neset at her Tioga, North Dakota, headquarters before riding with her to various oilfield locations. Our plan was for his story to provide a unique perspective on the evolution of hydraulic fracturing in the Williston Basin over the past few years, and who better to speak with for the story than Neset, we thought. As you’ll see in “A Geologist To The Core” on page 34, we got much more of a story than we had hoped for. I wish I could have been with Miller that day. The same can be said for “Frack Fluid Focus,” Emily Aasand’s page-24 feature on several frack-based technologies or applications new to the Bakken market. An assignment of this type can be difficult because most new tech or service providers we talk with throughout the year are heavy on the hype and light on real-world results. Aasand found three companies willing to share more than just their newproduct-offering excitement, however, and she writes that innovation is in action in the play and why, in the case of fracking, processes in use today will be done differently tomorrow Technology was a hot topic at the Williston Basin Petroleum Conference in Regina, Saskatchewan, but not as hot as oil prices. The WBPC, now in its 23rd year, is a mainstay industry event and, depending on the year and the price of oil, attendance and company participation is massive, attracting several thousand attendees and an expo hall filled wall-to-wall with every type of energy-related company. We noted several themes at this year’s event, one perhaps a bit surprising. Being in the midst of low oil prices, one might expect the mood of the WBPC majority to be suppressed, however, while the prices are down for most producers, we found all are optimistic on Bakken, for a different reason: The rebound.

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27 API Bakken Chapter


16 Bartlett & West


21 Blackmer

Editor Luke Geiver

38 Brock White Company

Staff Writer Emily Aasand

19 Convey-All USA

Staff Writer Patrick C. Miller

49 Corval Group

Copy Editor Jan Tellmann



23 FMC Technologies Inc.

Chairman Mike Bryan

10 iLevel Digital

CEO Joe Bryan

20 Johnson Controls, Inc.

President Tom Bryan

53 LPP Combustion

Vice President of Operations Matthew Spoor

17 Matrix Service

Vice President of Content Tim Portz

32 MBI Energy Services

Marketing & Sales Director John Nelson

41 Midwest Industrial Supply, Inc.

Business Development Manager Bob Brown

48 Miller Insulation

Account Manager Austin Maatz


Circulation Manager Jessica Beaudry

2 NOV Fiber Glass Systems

Traffic & Marketing Coordinator Marla DeFoe

40 Peak Oilfield Service Company, LLC 11 Pentair Flow Technologies

ART Art Director Jaci Satterlund

22 Port of Longview

Graphic Designer Lindsey Noble

31 Port of Vancouver USA 56 Quality Mat Company 18 SBG Energy Services LLC

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

55 The Bakken Conference & Expo 4 Tyco Fire Protection Products 52 Unconventional Resources Technology Conference (URTeC) 51 Valley Industries LLC 26 Wells Concrete 29 Wood Group PSN 3 Worthington Industries 28 Zeeco, Inc.

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BILL TRACKER: Alexis Brinkman-Baxley monitors and works with the North Dakota legislature for the North Dakota Petroleum Council. PHOTO: THE BAKKEN MAGAZINE

ND Oil, Gas Legislative Review By Alexis Brinkman-Baxley

64th Legislative Assembly of the State of North Dakota wrapped up April 29. While this session did not take as many days as the 2013 session, most would argue it was as jam-packed with significant and controversial issues. As usual, this session covered a multitude of issues relating to every aspect of the oil and gas industry, but none more impactful than those of a financial nature. Impact funding and declining oil prices were the hot topics of hallway chatter from day one, and played a role in nearly every decision that was made. Revised revenue forecasts in February and March were an attempt to give legislators a base to work from, but it took all the way to day 71 8

and a major reform of North Dakota’s oil tax structure for there to be any certainty. Likewise, work for the North Dakota Petroleum Council continued to the very end. Following is a breakdown of the results of some of the top oil and gas industry issues addressed this session:

Western Infrastructure and Impact Issues

Just like last session, increased funding for oil-impacted cities, counties and townships was one of most pressing issues. Two proposals from the governor and Senate Majority Leader Rich Wardner (R-Dickinson) were among the first bills heard when the session kicked off, and committees in



both bodies worked quickly to put together and approve a package in time for the 2015 construction season. SB 2103, Sen. Wardner’s Surge Bill, was signed by Gov. Dalrymple on Feb. 24, and included $240 million for the big 10 oil producing counties, $100 million for cities in the big 10 that collect $5 million or more per year in gross production tax, $172 million for hub cities and Watford City, $10 million for boundary cities, $112 million for cities, counties and townships outside of the big 10 counties, $450 million for state highways and county road construction requirements. Securing additional funding for the communities in western North Dakota was again a top priority for the NDPC. We believe this historic legislation should provide impacted communities with the resources they need. HB 1176, the funding formula bill, took considerably longer to work out. Proposed by the North Dakota Association of Oil and Gas Producing Counties and supported by the Gov. the bill changed the production tax distribution formula and increased the local share to 30 percent. Amendments to an additional bill, HB 1377, increased the local share by another four percent depending on the counties’ use of additional road-use fees. NDPC also worked to support additional staffing for many of the state agencies affected by oil and gas development, including the North Dakota Industrial Commission, North Dakota Department of Health, and the Highway Patrol.


Major reform to the oil and gas tax structure will likely turn out to be the most talked-about issue of the session. HB 1476 was proposed April 17. The initial bill implemented a flat tax of 9.5 percent and eliminated the current tax structure if the current system’s “big trigger” went on. Legislators worked quickly to move the bill in an effort to provide some stability and predictability for the next biennium. Following negotiations with the MHA Nation and Democrats, significant changes were made to the bill and the final version was passed one week after the bill’s introduction. The final version does the following: • Regardless of whether or not the big trigger takes effect, the extraction tax will go to 5% on January 1, 2016 (total effective tax rate of 10%). The triggers will be eliminated from the tax policy. This gives industry a potential of 5 months to complete wells that would qualify for the triggered rate. Any well eligible for any exemption will only be able to take advantage of the incentivized rate until Dec. 1. • If the average price of a barrel of oil is above $90 (indexed for inflation) for 90 consecutive days, the extraction tax will increase to 6 percent, for a total effective tax rate of 11 percent. The rate will trigger back down to 5 percent following 90 consecutive days below $90. Essentially, the language creates a reverse trigger. • Section 6 of the amended bill would allow the Gov. to negotiate a tax agreement with the MHA


Nation if that agreement is based on the changes in this bill. Currently, the Governor has the authority to negotiate such agreements, but additional legislation has been approved (SB 2226) that will remove that authority and require approval from the legislative body, limiting those agreements to every two years when the legislature meets. This provision sunsets Dec. 31, 2016 and is meant to allow the Tribes to work with the state on the agreement between now and when SB 2226 goes into effect. • Section 6 also allows MHA Nation to implement a tax sharing agreement on bulk delivery of dyed and undyed special fuels. This is not a new tax, just sharing of an existing tax, and an agreement that all the other reservations in the state are already have. That tax would be subject to the tax compact between the MHA Nation and state. • Section 7 in a legislative study of the state-tribal tax agreement and allocation of those revenues including centrally assessed property and PILT taxes. The study must report back with findings and suggested legislation next session. This section is the result of a request from the Tribe. Currently, industry is making a payment in lieu of property tax (PILT) to the state on pipelines. The state then redistributes that money back to the county in which the pipeline is located. The county does not distribute any of those monies back to the MHA Nation if those pipelines pass through the Reservation. The MHA Nation has made statements about implementing a pass through tax if this doesn’t change. At this time, we are not sure whether MHA Nation will choose

to remain in the tax compact with the State. NDPC will be preparing a white paper on the new tax trigger in the coming months. Other tax issues important to industry this session include a bill changing the corporate income tax apportionment structure (SB 2292) and incentives for enhanced oil and gas recovery using CO2 (SB 2318 and SB 2015).

Pipelines, Easements and Reclamation

All things pipeline were another major focus for industry this session. A number of bills dealing with pipelines, easement and reclamation passed this session. SB 2271, a result of work between industry, landowners and the N.D. Agriculture Department, develops a pipeline reclamation ombudsman program. The program will be run through the Ag Department, and local ombudsman will be tasked with working with landowners and companies to resolve pipeline reclamation issues and help educate the public on related issues. HB 1358 is the most comprehensive pipeline legislation in recent history. The main focus of the bill was to address gathering lines, but it included a number of other pipeline-related issues. The legislation does the following: • Requires operators provide NDIC with the following information for crude oil and produced water gathering lines placed into service after Aug. 1, upon request: o Engineering construction design drawings and specifications. o A list of independent inspectors expected to inspect the pipeline. o A plan for leak protection and monitoring. • Requires operators file an

independent inspector’s certificate of hydrostatic or pneumatic testing within 60 days of placing crude oil and produced water gathering lines into service. • Makes land or water impacted by oil and gas development before Aug. 1, 1983 eligible for reclamation through the abandoned oil and gas well plugging fund and authorizes the expenditure of $1.5 million from the abandoned oil and gas well plugging and site reclamation fund to do so. • Allows NDIC to require a bond on crude oil and produced water gathering lines. • Allows a surface owner to request a review of the temporarily abandoned status of a well on that status for seven years or more. • Allows the NDIC to release the previously confidential information: o Volumes injected into a saltwater injection well. o Information from a spill report on a well site at which more than 10 non-contained barrels were released. • Allows a surface owner to share GIS information pertaining to facilities on his/her land. • Creates and funds a study of crude oil and produced water pipelines and the construction, monitoring and reclamation of them. (Includes a $1.5 million appropriation from the abandoned oil and gas well plugging and site reclamation fund). • Authorizes the NDIC to adopt rules regarding crude oil and produced water gathering lines following the study. • Creates and funds a pilot project to determine the best techniques for remediating salt and any other soil contamination from legacy spills (Includes a $500,000

appropriation from the abandoned oil and gas well plugging and site reclamation fund). Additional bills increasing funding for the oil and gas well plugging and site reclamation fund (HB 1032), pertaining to pipeline 10-year plans, siting and fees (HB 1124, SB 2120 and SB 2123) and relating to one-call issues (SB 2347) were also passed this session.

Regulatory Issues

As usual, numerous regulatory issues were also worked on this session. Legislation addressing the disposal of solid waste and TENORM (HB 1113 and HB 1114), federal environmental issues like the Clean Water Act and Endangered Species Act (HB 1432), and NDIC orders (HB 1068 and SB 2343) was passed. Additionally, the legislature approved HB 1390, creating a pilot project that will focus on commercial recycling of drill cuttings or water from a drilling operation. Following the pilot project, the Department of Health will have the authority to adopt rules governing operations of commercial drill cutting recycling facilities. The bill also removes the liability for recycled cuttings from the well operator.

Additional Issues

A number of other industryrelated issues were addressed this session. A resolution encouraging Congress to repeal the ban on crude-oil exports was passed, and legislators spent time debating water, Tribal and Legacy Fund issues as well. Author: Alexis Brinkman-Baxley North Dakota Petroleum Council



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BAKKEN NEWS North Sea Brent crude oil prices in three cases, 2005-40 (2013 dollars per barrel)


U.S. tight oil production in four cases, 2005-40 (million barrels per day)

EIA's Oil Price Scenarios Reference case

Real gross domestic product grows at an average rate of 2.4 percent from 2013 to 2040, under the assumption that current laws and regulations remain generally unchanged throughout the projection period. North Sea Brent crude oil prices rise to $141 per barrel in 2040.

High Oil and Gas Resource

Estimated ultimate recovery (EUR) per shale gas, tight gas, and tight oil well is 50 percent higher and well spacing is 50 percent closer than in the Reference case. Tight oil resources are added to reflect new plays or the expansion of known tight oil plays, and the EUR for tight and shale wells increases by 1 percent per year more than the annual increase in the Reference. Other energy market assumptions are the same as in the Reference case.


EIA’s Annual Energy Outlook 2015 The U.S. Energy Information Administration has released its Annual Energy Outlook 2015 evaluating a range of trends and issues that could have major implications for U.S. energy markets. The outlook presents the AEO2015 Reference case and compares it with multiple alternative cases. The AEO2015 considered various factors related to the uncertainty of crude oil prices, including changes in worldwide demand for petroleum products, crude oil production and supplies of other liquid fuels. The North Sea Brent (Brent) crude oil price reflects the market price for light sweet crude oil free on board at the Sullen Voe oil terminal in Scotland. The Reference case reflects global oil market trends through the end of 2014, and the market conditions are expected to continue throughout the case. The 12

Reference case sees the average Brent price dropping from $109 per barrel in 2013 to $56 per barrel in 2015, before increasing to $76 per barrel in 2018. After 2018, growth in demand from non-Organization for Economic Cooperation and Development countries pushes the Brent price to $141 per barrel in 2040, according to the AEO2015. The High Oil Price case assumes higher world demand for petroleum products, less upstream investment by OPEC, and higher non-OPEC exploration and development costs. These factors have Brent crude priced at roughly $252 per barrel in 2040, which is 78 percent higher than the Reference case. The reverse is true in the Low Oil Price case and projects Brent to average $76 per barrel in 2040. In the Reference case, the EIA predicts world production


will be 99.1 million barrels of oil per day (bopd) in 2040. “Total liquid fuel supplies and OPEC’s market share are higher in the Low Oil Price case and lower in the High Oil Price case” the outlook stated. As increased OPEC production depresses world oil prices in the Low Oil Price case, some non-OPEC resources that are viable in the Reference case become uneconomical. As a result, non-OPEC production increases only slightly in the Low Oil Price case from 45.3 million bopd in 2013 to 46.8 million bopd in 2040. In the High Oil Price case, non-OPEC production totals 63.8 million bopd in 2040, according to the AEO2015. Overall, the prices charged for petroleum products and other liquid products in the U.S. reflect the price that refiners pay for crude oil inputs, as well as

operation, transportation, and distribution costs, and the margins that refiners receive. According to the EIA, a 30 percent rise in the Brent crude oil spot price from 2013 to 2040 in the Reference case results in the weighted average U.S. petroleum product price rising by 15 percent, from $3.16 per gallon to $3.62 per gallon. In the High Oil Price case, higher demand for crude oil in non-OECD countries and lower supply of OPEC crude oil push world crude oil prices up. As a result, the AEO2015 found that the weighted average price for U.S. petroleum products increased by 84 percent, from $3.16 per gallon in 2013 to $5.81 per gallon in 2040. In the Low Oil Price case, with lower non-OECD demand and higher OPEC supply pushing world oil prices down, the weighted average price for U.S. petroleum


U.S. total crude oil production in four cases, 2005-40 (million barrels per day)

High Oil Price

U.S. net crude oil imports in four cases, 2005-40 (million barrels per day)

Results from a combination of higher demand for liquid fuels in non-Organization for Economic Cooperation and Development (OECD) nations and lower global crude oil supply. The Organization of Petroleum Exporting Countries’ (OPEC) liquids market share averages 32 percent throughout the projection. Brent crude prices rise to $252 per barrel in 2040. Other energy market assumptions are the same as in the Reference case.

Low Oil Price

Result from a combination of low demand for petroleum and other liquids in nations outside OECD and higher global supply. OPEC increases its liquids market share from 40 percent in 2013 to 51 percent in 2040. Light, sweet (Brent) crude oil prices remain around $52 per barrel through 2017, then slowly rises to $76 per barrel in 2040. Other energy market assumptions are the same as in the Reference case.

products drops by 26 percent, from $3.16 per gallon in 2013 to $2.32 per gallon in 2040.

Energy production: imports and exports EIA’s 2015 outlook found that net U.S. imports of energy declined from 30 percent of total energy consumption in 2005 to 13 percent in 2013, as a result of strong growth in domestic oil and dry natural gas production from tight formations and slow growth of total energy consumption, the EIA says. The decline in net energy imports is expected to continue at a slower rate with energy imports and exports coming into balance around 2028. According to the Reference case, from 2035 to 2040, energy exports should account for about 23 percent of total annual U.S. energy production. “Economic growth has a major influence on U.S. energy consumption, imports and exports,” the outlook says. According to the High Economic Growth Case, the U.S. remains


a net energy importer through 2040, with net imports equal to about 3 percent of consumption in 2040. “Higher world oil prices place downward pressure on consumption while making domestic production more profitable,” the EIA said. “In the Low Oil Price case, with lower domestic production and higher U.S. energy consumption, the U.S. remains a net energy importer, with imports increasing every year from 2033 to 2040. In the High Oil Price case, with stronger growth in production and more incentives for energy efficiency, the U.S. becomes and remains a net energy exporter starting in 2019, with net export increases peaking at 11 percent in 2032.” Oil production from tight formations leads the growth in U.S. crude oil production across all AEO2015 cases. Projected crude production varies across the cases with total U.S. crude oil production reaching high points of 10.6 million bopd in the Reference case (in 2020), 16.6

million bopd in the High Oil and Gas Resource case (in 2039), 13 million bopd in the High Oil Price case (in 2026), and 10 million bopd in the Low Oil Price case (in 2020). Production varies depending on crude oil prices, the use of CO2-enhanced oil recovery technologies, closer well spacing, and the development of new tight oil formations or additional layers within known tight oil formations, the EIA said. “Most of the difference in total crude oil production levels between the Reference and Low Oil Price cases reflects changes in production from tight oil formations. However, all sources of U.S. oil production are adversely affected by low oil prices,” the report says.

Tapping into natural gas

Total dry natural gas production in the U.S. increased by 35 percent from 2005 to 2013, with the natural gas share of total U.S. energy consumption rising from 23 percent to 28 percent. According to the outlook,

future dry natural gas production depends primarily on the size and cost of tight and shale gas resources, technology improvements, domestic natural gas demand, and the relative price of oil. “Tight gas accounts for a smaller, but still significant, portion of the increase in U.S. dry natural gas production compared to shale gas. Most tight gas production growth occurs in the Gulf Cost, the Dakotas and Rocky Mountains regions,” the EIA says. In all the AEO2015 cases, net natural gas imports continue to decline through 2040, as they have since 2007. Gross exports of natural gas increase over the period, and gross imports decline. In all of the cases, the outlook reports that the U.S. would become a net exporter of natural gas in 2017, driven by liquefied natural gas (LNG) exports, increased pipeline exports to Mexico, and reduced imports from Canada.




Crude-by-rail movements (2014) Canada PADD2 PADD4


chairman, sent a 10-page letter to Timothy Butters, acting administrator of PHMSA, containing PADD5 four primary recommendations to improve the safety of tankers carrying Bakken crude and other PADD3 Class 3 flammable liquids. “Crude oil rail traffic is 1 100 400 800 increasing exponentially,” Hart thousand barrels per day said. “That is why this issue is on our most wanted list of safety imSOURCE: U.S. ENERGY INFORMATION ADMINISTRATION provements. The industry needs to make this issue a priority and expedite the safety enhancements, otherwise, we continue to put our communities at risk.” Hart called for all rail tank The U.S. Energy Informaof the STB as well as Canada’s would “better protect American cars carrying Class 3 flamtion Administration has creNational Energy Board in making communities along the tracks.” mable liquids to be equipped with ated a tracking tool that provides these data accessible.” Called “The Crude-By-Rail thermal protection systems and monthly data on rail movements Total crude-by-rail moveSafety Act of 2015,” the bill reof crude oil. The data on crudements in the U.S. between the quires the Pipeline and Hazardous appropriately sized pressure relief by-rail movements can be found U.S. and Canada were more than Materials Safety Administration to devices that meet or exceed current standards. in the EIA’s monthly petroleum 1 million barrels of oil per day draft new regulations to mitigate Hart said there should be an supply statistics, which already (bopd) in 2014, up from 55,000 the volatility of gases in crude oil includes crude oil movements by bopd in 2010. The regional distri- shipped via tank car and immedi- aggressive schedule for replacing the cars, such as a 20 percent pipeline, tanker and barge. bution of these movements has ately halt the use of older-model “The new crude-by-rail data also changed over this period, the tank cars that have been shown to replacement rate over a five-year provides a clearer picture on a EIA added. be at high risk for puncturing and period for the legacy DOT-111 and CPC-1232 tank cars. He also mode of oil transportation that The data set on tracking catching fire in derailments. recommended a publicly available has experienced rapid growth crude-by-rail movements came “Every new derailment in recent years and is of great after the topic of shipping crude- increases the urgency with which annual report that monitors progress on retrofitting and replacing interest to policy makers, the by-rail safety sparked discussion in we need to act,” said Cantwell, the tank cars. public and industry,” said Adam Washington D.C., last month with ranking member on the Senate PHMSA has plans to issue Sieminski, EIA administrator. the introduction of legislation in Energy and Natural Resources “EIA expects that the new data the U.S. Senate and the release of Committee. “This legislation will new tank car safety standards and it has developed using informaa report on oil properties by the help reduce the risk of explosion regulations for the phase-out of tion provided by the U.S. Surface U.S. Department of Energy. in accidents, take unsafe tank cars older tank cars this month. With crude transportation Transportation Board along U.S. Sens Maria Cantwell, off the tracks, and ensure first safety in question, Burlington with data from other third-party D-Wash., Patty Murray, D-Wash., responders have the equipment Northern Santa Fe Railway execusources and our own survey data, Tammy Baldwin, D-Wisc., and they need. We can’t afford to tive chairman Matt Rose outlined will provide key insights into Dianne Feinstein, D-Calif., had wait for 10 accidents per year, as the company’s plans to implement oil-by-rail movements, including introduced legislation setting new estimated by the Department of additional measures for improved shipments to and from Canada. safety standards for trains hauling Transportation.” rail safety during a recent conferWe welcome the cooperation volatile crude oil, which they said Christopher Hart, NTSB

Now tracking: crude by rail volumes, destinations




Annual Rail Traffic Data Annual U.S. Class | Rail Tons Crude petroleum 40

Tons (in millions)

35 30 25 20 15 10 5 0 2004












Average Weekly Rail Carloads United States | Petroleum and Petroleum Products 2013



16 15 14 13 12 11 10 9 8

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb

Carloads and/or Intermodal Units (in thousands)

Monthly Rail Traffic Data


ence call with North Dakota Gov. Jack Dalrymple. Safety measures include new operating procedures for trains that carry crude oil, including reduced-speed requirements, work with BNSF customers to remove all DOT-111 tank cars from crude oil service, enhancements to the company’s railcar electronic monitoring program and increased track inspections.

“Railroad operations, equipment and maintenance are critical elements in our overall goal to improve rail safety, and I commend BNSF for taking these significant steps,” said Dalrymple. “At the same time, we must move forward on other important aspects of rail safety including the need for new federal tank car standards and greater pipeline capacity.” BNSF recently began

requiring that its crude oil trains reduce speed to 35 miles per hour through all communities of 100,000 residents or more. The railway said it would work with its customers to transition all DOT111 tank cars from crude oil service within a year. “The oldermodel tank cars will be replaced with next generation tank cars and CPC 1232 tank cars modified to meet pending changes

in federal safety standards,” the railway said. BNSF also said it would enhance its electronic monitoring program to more quickly identify tank cars that may need repairs. Dalrymple has urged the railway to adopt new operation procures for improved rail safety and to enhance rail and tank car maintenance. BNSF officials said they plan to invest more than $335 million on track maintenance and capital improvement projects in North Dakota this year alone. “Any tank cars flagged by electronic monitors for possible defects will be taken out of service immediately,” said Rose. Along with visiting with BNSF officials, Dalrymple and the North Dakota Public Service Commission have proposed establishing a state-run railroad safety program as well as a pipeline integrity program that would complement federal oversight in North Dakota. According to Dalrymple, the proposal calls for roughly $1.4 million in state funding for three positions to enhance railroad track inspections in North Dakota and another three positions for stepped-up inspections of pipelines that transport crude oil and other liquids to market. PHMSA has plans to issue new tank car safety standards and regulations for the phase-out of older tank cars.




ND revises oil tax revenue to $3.4B for 2015-‘17 The North Dakota Office of Management and Budget has revised the oil tax revenue forecast for the 2015-‘17 biennium. The updated forecast was created with the help of Moody’s Analytics and shows that the state’s total oil tax revenue during the 2015-‘17 biennium will be roughly $3.4 billion. In January, the North Dakota legislature predicted that oil tax revenue for the biennium would total $4.2 billion. In total, the March revenue forecast shows a difference of nearly $870 million less compared to the January forecast. The total revenue generated by the state in the upcoming biennium will be roughly $5.1 billion, according to the OMB’s update forecast. The North Dakota OMB’s forecast update was based on several assumptions.



For the remainder of the 2013-‘15 biennium, along with the entire 2015-‘17 biennium, the state will produce 1.1 million barrels of oil per day (bopd), OMB said. Pam Sharp, director for OMB, said the forecasts were created using NYMEX future prices provided by CME Group. Because of that, the OMB’s March forecast shows that North Dakota oil prices—always discounted 15 percent from West Texas Intermediate by the OMB—will range between $42 and $52 per barrel, a number more conservative than the legislature assumed in its January revenue forecast revision, Sharp said. Both oil production tax triggers—the small and the large trigger—will impact parts of the current and upcoming biennium. For the past five months of the 2013-‘15 biennium, the small tax trigger will be in effect if legislators do not pass new tax laws. The small trigger provides a reduction to producers in the extraction tax for new horizontal wells

drilled in the month after the previous month averaged less than $57.50 per barrel for West Texas Intermediate. “There have been so many things going on with the price of oil lately and no one can say where it is going to lead,” Sharp said. “Earlier, we didn’t know if the large trigger was going to be in place, but now it looks like it is definitely going to happen.” The large trigger—a tax reduction applied to all wells for the first 24 months of all wells in production—would also be in effect for the first 11 months of the 2015‘17 biennium, the OMB predicts. The large trigger is only turned off when WTI trades above $55.09 per barrel for five consecutive months. The large tax trigger has potential to be in place from May 2015 until April 2016, according to the OMB. The presence of the large tax trigger impacts several budget allocations and it impacts the resources trust fund. “That is funded by



The assumption that the state will produce 1.1 million barrels of oil per day throughout the remaining 2013-‘15 biennium and throughout all of the upcoming biennium

just the extraction tax,” Sharp said. “Once the big trigger is kicked on, we don’t have any extraction tax for 11 months. It funds all of the statewide water projects. That is clearly something that is problematic when they were counting on a lot more money.” The House and the Senate have to pass a vote on the OMB’s budget before they can use the numbers for further spending legislation in the next two years. In December, North Dakota Gov. Jack Dalrymple issued a revenue forecast and budget for the upcoming biennium that assumed the state’s oil tax revenue would be closer to $8 billion. Despite low commodity prices and a reduction in the revenue generated from oil and gas, North Dakota should still see an increase in sales and use tax, according to the OMB’s budget. In the upcoming biennium, sales and use tax revenues will total $2,869,079,000. The 2013-‘15 biennium revenue from sales and use tax will total only $2,498,566,100.


North Dakota oil prices remain between $42 and $52 per barrel

2 3 4

Small tax trigger remains in effect

Large tax trigger takes effect


Oil states say new BLM fracking rule creates unnecessary duplication After four years in the making, the U.S. Department of Interior Bureau of Land Management released its final rule on hydraulic fracturing on public and tribal lands. The new federal regulations generated a critical response from North Dakota officials and other states that already have similar regulations in place, as well as energy organizations. “This long-awaited rule will finally provide some certainty to producers in an already unstable time,� Lynn Helms, director of the North Dakota Industrial Commission’s Oil and Gas Division, said. “However, the content of the rule itself still generates concerns of necessity and duplicity.� Roughly 30 percent of all North Dakota oil production occurs on federal or tribal lands. As of February, 120 wells were awaiting completion, 390 were approved for drilling and another 1,948 wells were in the planning stages. The Independent Petroleum Association of America and the Western Energy Alliance each submitted a lawsuit against the DOI in Wyoming. North Dakota’s Industrial Commission met to discuss the possibility of suing

the DOI to stop the final rule and has since decided to do so. “Hydraulic fracturing has revolutionized energy development in our country, and states have led the way. We encourage the BLM to work with states and defer to the regulatory programs they have put in place with a long and successful track record,� said Sen. John Hoeven, R-N.D. Through the final rule, the DOI said that states and tribes may request variances from provisions “for which they have an equal or more protective regulation in place,� all to avoid duplication. “We know how important it is to get this right,� said Janice Schneider, assistant secretary for land and minerals management at DOI. Sen. Heidi Heitkamp, D-N.D., suggested another alternative. “As I review this new rule and seek input from North Dakota regulators, at the very least, I hope it enables states like North Dakota to opt-out, if they are already implementing their own regulations that effectively reflect local geological and environmental issues,� she explained. The American Petroleum Institute

DRILLING IMPACT: With the drilling rig count well below 100, North Dakota oil production could be hurt if federally imposed regulations on horizontal drilling add another hurdle to production. PHOTO: THE BAKKEN MAGAZINE

said the BLM rule would impose new costs and delays on energy development without improving on existing state and federal regulations “A duplicative layer of new federal regulation is unnecessary, and we urge the BLM to work carefully with the states to minimize costs and delays created by the new rule to ensure that public lands can still be a source of job creation and economic growth,� said Erik Milito, API director of upstream and industry operations.


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Schlumberger CEO: industry needs to change Schlumberger, a globally-focused energy service provider, believes it has a major opportunity for future growth despite its first-quarter revenue showing. For the quarter, Schlumberger reported a 19 percent revenue decline “driven by the severe decline in North American land activity and associated pricing pressure,” the company said. Nearly three-fourths of that decline was due to lower activity and pricing, with the remainder related to currency effects. “Despite the severity of the sequential revenue decline, we have been able to minimize its impact on our margins through prompt and proactive cost management as well as through acceleration of our transformation program across product lines,” said Paal Kibsgaard, chairman and CEO. “These actions have successfully improved financial performance compared to previous industry cycles.” Regardless of its ability to withstand the current downturn in oil prices, Kibsgaard is pushing a message of change. “We see the current industry challenges, and the subsequent need for the industry to change, as a huge opportunity for Schlumberger,” he said during his recent industry presentation. During the same presentation, Kibsgaard

outlined the way Schlumberger sees the oil and gas industry evolving. The combination of escalating costs for new and existing oil fields, flat global oil production and unstable commodity prices have put pressure on exploration and production firm profitability and free cash flow, he added. In the tight oil sector, exploration and production firms will be operated with greater financial prudence, and make investments based on cash flow from production. This means that production increases will be directly linked to the cost-per-barrel. To date, Schlumberger believes it has done much to help increase production while driving down costs, but, it is still not significant enough. “After having doubled the horizontal length and number of stages per well in the past five years, while also significantly increasing volumes of water and proppant per stage, the average well production has still not improved noticeably,” Kibsgaard said. To reduce costs while increasing production, Schlumberger believes wells need to go through an engineered completion process that includes formation evaluation data and completion modelling before the well is ever touched. Along with a greater emphasis on

data and modeling, the company believes it can maintain its place in the industry as a leading energy service firm through its unique fracture methodology and fluid that is used as part of the BroadBand completion technique package. The fluid contains proppant modules and fibers that help to increase well conductivity, according to the company. In North Dakota, the BroadBand Sequence was recently used to stimulate a 901-foot and 2,553-foot open hole toe section in two Bakken wells. The system created higher pressures and initial production rates when compared with direct offset wells. “Our scientific solutions continue to deliver well production that consistently outperforms a brute force approach,” he said. But, even with unique production and drilling technology, Schlumberger cannot help to increase production without industry input. According to Kibsgaard, “change must include closer collaboration between the operators and the large service companies to jointly create technical solutions that can reduce costs and increase project value, in particular tightoil and Deepwater developments.”






Halcón Resources, Triangle Petroleum find efficiencies, opportunities in Bakken Two Bakken producers—Halcón Resources Corp. and Triangle Petroleum Corp.— delivered positive results in their recent end-ofquarter reports. Houston-based Halcón said its well completion costs in the Bakken have declined by 30 percent during the first quarter of 2015 compared to costs in the previous quarter. The company made significant progress negotiating lower costs with its service providers and will continue to modify its drilling and completion techniques to improve recoveries and reduce costs. Jon Samuels, president and CEO of Denver-based Triangle, said it’s positioned to take advantage of opportunities in the Bakken. “Triangle has the balance sheet and a business model that will see us to the other side, and not everyone out there does,” he said, while

E&P Non- Op Drilling Program 3% E&P

RockPile presenting Triangle’s fourth-quarter and yearOperated 10% Drilling end report. The company’s 2015 fiscal year (2) Program ended Jan. 31. 88% In its report, Halcón noted record production increases in its Bakken operations because of positive results from downspacing. The company’s report said it brought six Bakken wells online spaced 660 to 770 feet apart drilled from a single pad with a cumulative On the Fort Berthold Reservation during capital budget there issued were on February 2015.spud IP rate of 21,131 barrels of oil equivalent(1) per FY2016 the last quarter, seven5,wells (2) E&P Operated Drilling Program does not include the RockPile and other day (Boe/d), one of which was a new Halcón level.and six wells put online withcapex an average Actual E&P operated incurred will likelyIP be rate reduced by elimin (3) Subject to commodity and gaps in RockPile third-party complet record at 5,248 Boe/d. of 3,522 Boe/d,prices an increase ofthe38.2 percent 16 Halcón operated an average of two rigs over the previous quarter. One well went in the Williston Basin during the last quarter. online in Williams County with 1,977 Boe/d. Overall, the company operates 172 producing Halcón also said that it is currently selling Bakken wells and 53 Three Forks wells. It has about 83 percent of its gas production in the 11 Bakken wells and five Three Forks wells Williston Basin and is continuing to increase its completed or awaiting completion on its oper- gas capture. ated acreage. Triangle operates Triangle USA Petro-

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Represents a 71% year-over-year reduction 119 gross operated horizontal wells currently producing Primary focus on protecting the balance sheet, and 20 wells waiting on completion(1) maintaining adequate liquidity, return on capital leum, which focuses on developline with full-year budget guid- and Approximately 90% of operated wells hooked up $573 to gas positioning forForks growth post-recovery ing the Bakken and Three ance. Triangle generated formations—and RockPile million consolidated revenue sales(1) , as compared to 0% at the of Q1 FY’14 Drilling plan contemplates <2ofend operated rigs on Energy Services, a wholly owned with $285 million from TUSA average for FY2016 All operated wells hooked up to Caliber are in subsidiarySpud providing hydraulic andNDIC $289 million from RockPile. ~25-27 gross operated wells compliance with amended oil handling guidelines fracturing services. It’s also “This will be the fourth Complete grossanticipate operated wells released ~27-29 in December; being in compliance for involved in Caliber Midstream, quarter in a row that we have (3) 2015 Deferring May 1, analyst 2015 all other completions wells before theuntil rules take effect in April a joint venture that provides hit or exceeded street Anticipate having 20-24 wells waiting on Ongoing downspacing tests indicate potential for (early gathering, transportation, treating estimates on adjusted EPS completion, which could represent a source of and processing services in the production system) and cash 8 – 12+ locations per DSU incremental growth with a further Williston Basin. flow containing per share,”middle BliffenBakken said.  Multiple operated DSUs in commodity prices For the year,improvement Triangle According to Samuels, Triwells spaced ~600’ apart Select Tests produced 4.2 million barrels of angle’s balance sheet and capital 1) OAS  Nearby operators undergoing 12 and 16 well density oil equivalent (BOE) or 11,441 structure remains strong despite 2) WLL r eliminations that reduce capital expenditures at the DSU Parent Company in a single targeting the Middle Bakken 3) WLL BOE per day andtests 1.4 million or Triangle the downturn in oil prices. nations. 4) OAS and Lower Three Forks benches “Where we stand now, we tion schedule14,747 BOE per day during the 5) OAS 6) CLR fourth quarter. are in a good and stable position 7) CLR DETAILS TPLM CORE “This is the third year in when we're pleased with our 8) WLL 9) OAS Core ~86,000 by a row weNet have hit Acreage or exceeded current liquidity, as evidenced 10) OAS analyst estimates on production,” our recent ability to repurchase 59% Percent Operated (%)(2) 11) WLL 12) WLL said Justin Bliffen, Triangle CFO. nearly $100 million of our own 77% Percent Held By Production (%) Total capital expenditures securities at discounted prices,” 66 OPERATED DSUS(2) for the year were $672 million, in he said. TOTAL OPERATED LOCATIONS REMAINING(3) (1) (2)



re he

23 4 5





11 1

TPLM Acreage

Bakken & Three Forks Density Test



TPLM Operated DSU Select Lower Three Forks Wells

As of March 9, 2015. Triangle’s operatorship in North Dakota has been confirmed through title and permits. In Montana, operatorship has been confirmed through title and permits or assumes 30% or greater working interest. Gross Operated Locations Remaining assumes six Bakken and four Three Forks wells per DSU. Supported by recent density tests near Triangle’s core acreage.

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From water heaters to long-life span pumps, frack-based service providers have options to reduce well completion costs. By Emily Aasand TORRID'S TAKE: The Torrid team is reinventing how well site operators heat water used in fracturing a well with the manufacturing of its direct contact frack water heaters. PHOTO: TORRID TECHNOLOGIES GROUP







Next-gen Water Heaters

Hydraulic fracturing a well requires 2 million to 9 million gallons of water. Some fracking experts believe water temperature is also important and that heated water ensures a better crude extraction possibility. â&#x20AC;&#x153;Cold water mixing with hot crude in the ground makes a coagulation, whereas if you have hot water mixing with hot crude in the ground, itâ&#x20AC;&#x2122;ll increase the rate in which operators are able to pull out the crude,â&#x20AC;? says Dax Cornelius, CEO and managing partner of Torrid Technologies Group. Torrid Technologies Group, a frack water heater manufacturer, got its start after recognizing a need for water heater services amongst energy service providers. Cornelius and his team have developed a series of frack water heaters that are direct contact systems that typically prove a 99 percent efficient transfer of heat into water. There are two kinds of

water heaters being used in the industry. The current approach relies on heating metal coiled tubing, which then heats the water flowing through it. Torridâ&#x20AC;&#x2122;s system takes out the middleman [coiled tubing] and directly heats the water causing an immediate transfer so thereâ&#x20AC;&#x2122;s nearly a 100 percent efficiency, according to Cornelius. Since the company manufactures direct contact water heaters, there is nothing over 5 psi inside the systems. â&#x20AC;&#x153;We were looking at these massive diesel trailers with these huge coil systems that could be very dangerous,â&#x20AC;? Cornelius added. â&#x20AC;&#x153;The current systems are almost like a pressure boiler with regards to heating water at such a high level, and those systems arenâ&#x20AC;&#x2122;t as safe as what we have designed.â&#x20AC;? Torrid offers four sizes of propane-run frack water heaters: The 10 mm Btu Achillies, the 15 mm Btu Spartacus, the 30 mm Btu Hannibal and the 45 mm Btu Vulcan. All of which have a

500 GPM and vary from a 40 degrees Fahrenheit water temperature up to a 180 degree F water temperature. The Montana-based company opened its doors in July 2014 and has four frack water heaters deployed in western North Dakota. â&#x20AC;&#x153;While researching, we saw there was a huge gap in safety, there was a huge gap in the amount of emissions these units were emitting, and there was a huge gap in the amount of operation costs that it took to heat the water,â&#x20AC;? says Cornelius. After looking into the water heating needs of the Bakken, the Torrid team found that in the summer, even if it is hot outside, operators are continuing to heat the water because the engineers want the water temperature going down the well at the same temperature no matter the season. â&#x20AC;&#x153;We saw the demand, we saw the need, and thatâ&#x20AC;&#x2122;s when we decided to start Torrid Tech-

nologies and provide a next generation frack water heater for the market,â&#x20AC;? Cornelius says.

Thriving Market

With oil producers looking to cut costs at the well site, Torrid sees the price commodity as a perfect growth opportunity for the company. Cornelius says with the industry in the shape itâ&#x20AC;&#x2122;s in, Torrid has been able to be the answer to many of the marketsâ&#x20AC;&#x2122; questions. â&#x20AC;&#x153;Everyone is looking for faster, cheaper, smarter, more cost-effective, lower carbon foot printing ways to heat water for fracks.â&#x20AC;? â&#x20AC;&#x153;Weâ&#x20AC;&#x2122;ve probably seen a 35 percent increase because everyone is looking for that cheaper solution,â&#x20AC;? says Cornelius. â&#x20AC;&#x153;Everyone has to work harder and smarter to earn the business and make things better, not only from a profitability standpoint, but for the greater good of the exploration and production industry as a whole.â&#x20AC;? Cornelius adds that as the











market corrects itself, Torrid could nearly double its business by next winter. “Our goal is to be identified as the next generation of frack water heaters for the industry. We’re tenacious on our growth game plan, we’re well funded and we’re in this market to stay because we believe we bring [a technology] to the table that every oil company would want under their operation.” Cornelius says there are roughly seven to eight major frack water heating companies that provide services to the major oil groups in the Bakken and says his team is getting ready to launch its own frack water service to supplement its manufacturing this upcoming winter.

Under Pressure

For hydraulic fracturing engineers, a big problem on the job site is pump failure. Fracking currently requires multiple high-pressure pumps forcing a mixture of water, proppants and chemicals downhole to fracture

TESTING THE FIELD: This month, Energy Recovery has begun field trails for VorTeq with its partner Liberty Oilfield Services, who will conduct trials at various well sites throughout the Bakken formation. PHOTO: ENERGY RECOVERY

the rock. Until now, the industry has been using reciprocating, positive displacement plunger pumps because it has been the only technology that has been rugged enough to process the high velocity, abrasive frack fluid. Energy Recovery Inc., a pump provider, got its start in the water desalination industry and developed the company’s Cadillac piece of technology, the Pressure Exchanger. In 2008, Energy Recovery began to research markets in which its in-

dustrial fluid-flow applications could be prevalent and decided to target the oil and gas industry. Joel Gay, president CEO of Energy Recovery, says the company saw an opportunity for its technology to act as a pump where there was existing hydraulic energy that was being wasted at well sites. “What we did was invent a solution exchanger that would replace the traditional hydraulic manifold, or missile,” says Gay. “Harnessing pressure energy the

way we have in our other technologies, our solution ratchets frack fluid up to the required treating pressure, as high as 15,000 psi, without requiring the high-pressure water pumps to handle sand. This prevents the regular occurrence of pump failure, and has several immediate and profound impacts for operations, not the least of which is a dramatic reduction in maintenance.” Roughly 18 months ago, Energy Recovery’s engineers

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CARBON COPY: Since 2014, Statoil has worked with Ferus Natural Gas Fuels and GE on a process to capture, compress and fuel drilling rigs with associated gas from the Bakken. PHOTO: STATOIL

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Through a recently awarded contract, Murray Reynolds and his team at Denver-based Ferus LP, an energized fluid provider for the oil and gas industry, will have the chance to prove why the number of U.S. unconventional wells that are completed with nitrogen or carbon dioxide (CO2) could, or should, be much higher than the current two to three percent. Ferus has been contracted by Statoil, an international exploration and production company run by Norway, to use liquid CO2 to complete an unconventional well in the Bakken shale play. The well completion will take place in June and will help evaluate the potential production uplift and replacement option of water in multi-stage frack jobs. Although there are many forms of CO2 or nitrogen-style completions happening in western Canada, the approach is usually the same for all wells, Reynolds says. In place of water, CO2 is mixed with proppant and the necessary chemicals and pumped downhole. Typically, the energized foam contains 70 to 80 percent gas with the remaining percentage consisting of proppant, chemicals and water. On a water-based pressure pumping operation, the well site will have proppant tanks, water tanks, proppant blenders and high-horsepower pumps, but for Ferus’ operations, CO2 tanks are added to the lineup. In Canada, the CO2 used by Ferus has been supplied from industrial producers near the wells. For the project in North Dakota, Ferus will source CO2 otherwise vented from a fertilizer plant in Saskatchewan and truck the gas in liquid form to the well site. For most wells, Reynolds says, roughly 2,500 to 4,500 liquid tons of CO2 would be needed. The Ferus team has completed a well using 6,500 liquid tons of CO2 preciously, a world record, according to Reynolds. By comparison, 1 liquid barrel of CO2 is equivalent to one liquid barrel of water.

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“With this slowdown, people are going to question what they are doing and why they have been doing it,” says Reynolds. For Bakken operators, the adoption of slickwater-based fracture methodologies has greatly increased in the past two years. In some cases, slickwater volumes per well have increased from 1 million gallons to a range of 6 to 8 million gallons per well. Reynolds believes it is time to question those num-


WATER ALTERNATIVE: For the Ferus CO2 completion project starting in June, Ferus will truck in CO2 from a fertilizer plant in Saskatchewan for use in the well. PHOTO: STATOIL






bers given the studies and proven work completed on CO2-based fracks. â&#x20AC;&#x153;Are we getting the best bang for our buck or are we just spending more money on larger fracks?â&#x20AC;? he added. Part of the intrigue of CO2-based fracks is related to the frack size reduction possibility. Based on studies from the Montney field in Alberta where Ferus performed CO2 fracks, energized foams provided a 100 percent initial production increase over slickwater jobs, Reynolds says. The cumulative recovery, roughly the first 12 months, also increases by 30 percent and the estimated ultimate recovery rates also increase by 30 percent. The production increases were also accomplished with a 25 percent well completion cost reduction. According to Reynolds, the process allows completion engineers to reduce the size of the fracture job needed to reach previously expected levels of production. The overall frack job can be reduced by roughly 30 to 40 percent and require roughly 50 percent less proppant. â&#x20AC;&#x153;Slickwater canâ&#x20AC;&#x2122;t carry proppant through the well bore as efficiently to the upper portions of the frack,â&#x20AC;? he says. â&#x20AC;&#x153;The foam jobs are more efficient at carrying proppant and keeping it in the upper part of the frack.â&#x20AC;? The proppant carrying ability helps to increase production because a greater percentage of the fracture highways are kept open to allow hydrocarbon flow. â&#x20AC;&#x153;With a big slickwater job, you are flooding the formation. You are displacing hydrocarbons from the near frack area and you are filling that porosity with water and altering the hydrocarbon saturation mix,â&#x20AC;? he says. â&#x20AC;&#x153;So the hydrocarbons are allowed to flow better and any liquids in the areas are being lifted to the surface much better.â&#x20AC;? Another advantage of CO2-based approach is the reduction of waterâ&#x20AC;&#x201D;slickwater or otherâ&#x20AC;&#x201D; needed to complete the well and the amount of water that will be drawn back to the surface and require disposal during production. Roughly 25 percent of all water injected into a well will return during production and require disposal. Although Reynolds is confident of the pending result of the project, Statoil has agreed to a single well first. Should the outcome be positive, Reynolds says future use of CO2 for well completion could utilize Ferus and General Electricâ&#x20AC;&#x2122;s ability to capture and recycle rich gas sourced from the Bakken. Gas could be piped or trucked to current or future well locations where it could be used to complete wells, Reynolds says.




HOT COMMODITY: Torrid Technologies Group sees the current oil price commodity as an opportunity to become established among operators and anticipates business will double by winter. PHOTO: TORRID TECHNOLGIES GROUP

conceptualized the VorTeq hydraulic pumping system that could use the company’s Pressure Exchanger to re-route abrasive proppants away from highpressure pumps to ensure only pure water touches the pumps, expanding pump life spans. Energy Recovery takes the hydraulic energy from the pumps—so they are only pumping clean water—and sends it at the desired treating pressure into the VorTeq missile, which will transfer that pressure energy to low-pressure frack fluid that goes directly to the missile from the blender and sends it down hole. “The positive displacement pumps will no longer process proppant, they will only pump clean water,” says Gay. “Hydraulic fracturing engineers are going to be rebuilding the fluid end of their pumps far less frequently than they are today due 30

to the fact that they are no longer pumping sand.” The company believes that there are three distinct orders of value creation for this product. The first is the reduced repair and maintenance costs—clients use existing pumps and don’t have to rebuild them as frequently. The second is the opportunity for the service providers to reduce levels of excess capacity, which Gay says providers can use to outfit new fleets. The final value is that from a pumping model standpoint, Energy Recovery believes the VorTeq can redesign and redefine how fracking is done today. This new technology allows operators to reduce current 15 to 20 positive displacement pumps down to three centrifugal pumps, Gay says. Centrifugal pumps are powered by a natural gas turbine generator set, which Gay says operators are already


migrating to, to power existing pumps. “You have a natural gas turbine generation set powering three centrifugal pumps and then you have the VorTeq, which is the gateway technology that allows you to cut pump numbers,” says Gay. Gay adds that the life expectancy of the centrifugal pumps should be between 50,000 and 60,000 hours, compared to existing pumps, which could range from 6,000 to 8,000 hours. Energy Recovery currently has its VorTeq deployed in a sixmonth exclusive field trial. Gay says after the field trials have been successfully completed, the company will be able to better determine when the technology could go commercial. “We’re very bullish on the value creation that is represented by this technology,” says Gay. “We’re going to approach the

field trials diligently and we’re going to make sure that it integrates seamlessly with your typical frack ecosystem.” The California-based company’s first-generation tech will handle slickwater only, and its second-generation, which is currently in the process of being developed, will be frack chemistry agnostic: slickwater, gels and hybrids. “To develop a solution that’s capable of withstanding the abrasion, viscosity and pressure cycles that you see at the wellhead is a challenge,” Gay says. “We’re developing a solution that would have a material impact on the cost per barrel to frack a well. We’re quite enthusiastic about the months and years ahead.” Author: Emily Aasand Staff Writer, The Bakken magazine 701-738-4976


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A Geologist To The Core Kathy Neset has become a Bakken rockstar by working with multiple stakeholders ranging from community leaders to major exploration and production companies. Her story parallels the evolution of the play. By Patrick C. Miller

Kathy Neset, owner of Neset Consulting Service in Tioga, North Dakota, speaks with clarity and conviction in describing how the combination of advancements in horizontal drilling and fracking have turned the Bakken into a world-class oil play and why it’s good for the region. But as a geologist, she can’t help but give Mother Nature proper credit for why those technologies have revolutionized oil and gas production in the Bakken. “The geology of North Dakota is incredibly unique,” Neset explains. “It is so special as to how the Bakken formation is laid down and how it is separated from our water zones and how all the fracking down-hole technology takes place. The concept of horizontal drilling coupled with this geology works beautifully. And then you do fracking in a safe, efficient, effective way and we have success. It’s those three components, but being a geologist, I always go back to the rocks.” Neset’s knowledge of the bowl-shaped Williston Basin’s layered rock formations and skill as a mud logger are what helped establish NeGEOLOGY 101: In her office at Neset Consulting Service, owner and geologist Kathy Neset is surrounded by artifacts and images from the history of North Dakota’s oil and gas industry, awards she’s received and the props she uses during her presentations on fracking and horizontal drilling. PHOTO: THE BAKKEN MAGAZINE



set Consulting’s 30-year relationship with Hess Corp. It also led to the company’s work with other Bakken producers such as Continental Resources Inc., Whiting Petroleum Corp., Statoil Oil and Gas LP, Sinclair Oil and Gas, PetroHunt LLC and Murex Petroleum Corp. “My true love of this job and the passion is the geology itself,” she says. “With that, we’ve been able to refine the horizontal drilling and fracking to maximize the natural resource of the geology.” Neset and her late husband Roy started an independent consulting business in Tioga in 1980. They had two sons who grew up in the business. “The oilfield was a little different then,” Neset recalls. “I was able to bring the babies out to the rig with me. Our two boys grew up washing samples and learning the oil field firsthand.” Her sons are part of the business today. RC Neset, a petroleum geologist, is in charge of researching and designing gas analyzers for the company’s gas detection division. Son Randy Neset is a petroleum engineer for Neset Con-





REPORTING FOR DUTY: Joanne Enger of Neset Consulting runs the print room where data from the mud logs of each well are printed out, assembled into reports and provided to producers and the state of North Dakota. PHOTO: THE BAKKEN MAGAZINE

sulting and vice president of operations for SHD Oil & Gas LLC. Geosteering—the practice of keeping the drill bit located in the correct rock formation during drilling—and mud logging— the analysis of the drill cuttings, gas, oil and other fluids that come out of the ground with the drilling mud—are the areas in which Neset Consulting specializes and excels. “We’re analyzing that material to geologically tell the story of what’s happening while a well is being drilled,” Neset says. Because oil producers target a specific formation for their lateral bores, Neset stresses that it’s critical for the drill bit to hit the right spot when the curve is landed and keep it there. “Right now, we’re talking 36

the Bakken and Three Forks formations as the big kings of the energy industry here in North Dakota,” Neset says. Drilling two miles down before curving the bore horizontally into the Middle Bakken—a rock formation that can be less than 10 feet thick—is the reason producers want to have a team of geologists and mud-loggers from Neset Consulting on site. “We have to help the oil company see what the rock units are doing—waving or going up and down in the structure,” Neset says. “We land in the right unit and then keep the bit in that zone. Those are the key components of what today’s geo-steering geologist does.” When drilling sideways at 300 feet an hour, even a small mistake can cost hundreds of


FACILITIES UPGRADE: Before moving into its current facilities northeast of Tioga in 2013, Neset Consulting Service operated out of a small home in the town with a doublewide trailer attached. The new building features offices, labs, conference rooms, a shop and the Little Rocks daycare center. PHOTO: THE BAKKEN MAGAZINE

thousands of dollars, according to Neset. The mud logger’s analysis of the rock, the liquids and the gases provide information on which key decisions are made to accurately steer the drill bit. “If you don’t make those decisions incrementally as you go, you’re going to be in trouble, and you may run out of your zone or you may run into the Bakken shale, which we don’t want to do,” she explains. “We want to stay in the Middle Bakken between the two shales. If you get into the wrong lithofacies, that’s very expensive.” When Neset first came to North Dakota in 1979 a year

out of college, well bores were strictly vertical and only about one in three drilled produced oil. The first site she worked on was southeast of Bismarck. “When you look at it now in the grand scheme of things, what a wildcat that was!” she laughs. The combination of geology, horizontal drilling and fracking has changed all that. “Nearly all of these wells are economically successful because this tight rock holds the oil,” Neset explains. “You may have a better area or a poorer area, but almost every single well is a successful well bore in North Dakota. Anybody who drills here


is going to have some degree of success.” When horizontal drilling started in the late 1990s, it was with one lateral completion and recovering as much oil as possible. “The steps have evolved to today where we have multiple horizons that are targeted within the Middle Bakken,” Neset says. “So you have to stay within the right rock layer.” The objective of horizontal drilling was to drill in a manner than enables more oil to drain out of the rock, but it wasn’t enough. The practice of fracking began in the early 2000s, and it’s taken time and a good deal of trial and error to realize its potential. “I’ll never forget the work I did on one of the early wells,”

Neset remembers. “I’m trying to look at the samples and steer this well precisely, exactly where the geologist had planned it. They finally said to me, ‘Kathy, lighten up a little bit. We don’t have to be quite that exact because we’re just going to frack the heck out of it anyway.’ And I said, ‘Oh. Ok.’ And they were right; they did.” Once again, it took a number of years to learn more effective ways to frack a well effectively. “Most of your frack goes to the heel of the well bore,” Neset says. “Out to the toe, the rock was not being treated. So even though you drilled out there and had all this rock exposed, most of the energy of the frack went into the first 500 or 800 or 1,000

IT’S A GAS: RC Neset, a petroleum geologist, is in charge of the company’s gas detection division. He researches and designs gas analyzers, as well as machining parts for them. PHOTO: THE BAKKEN MAGAZINE

feet of the well bore. You’ve actually drilled and not tapped into that out at the toe.” And there was still more to learn. “One well bore does not drain all the oil,” Neset notes. ”We’ve learned that. We have to put well bores closer together, side by side and we have to stack them on top of one another. So you penetrate a lateral into different portions of a spacing unit and that creates a very defined drainage pattern, which increases the amount that comes out of the rock.” While oil producers are improving their engineering of wells, Neset Consulting focuses

on the process of evaluation from the geology and geophysical side of the operation. “The companies want the process to be absolutely the best, most high-tech-method so the mistakes are minimized and the good outcomes are maximized,” Neset says. Her company owns sixwheeled trailers that contain laboratories, living quarters, sleep quarters and a kitchenette. Small and highly mobile, the trailers can be moved quickly and easily by pickup. In addition, Neset says they take up little room on a drilling site where space is often at a premium. Another technological ad-




vance thatâ&#x20AC;&#x2122;s made todayâ&#x20AC;&#x2122;s fracking and horizontal drilling possible is the speed with which information from the mud logs is transmitted, usually to a producerâ&#x20AC;&#x2122;s geologist far from western North Dakota. The rigs have Internet connections and satellite uplinks that enable everything to be sent in real-time to a producerâ&#x20AC;&#x2122;s data center. â&#x20AC;&#x153;We staff a data center on a special pilot program with the Hess Corp.,â&#x20AC;? Neset says. â&#x20AC;&#x153;We are actually geosteering and helping to assist in uploading data, continuously communicating in real time because the decisions have to be made immediately. It doesnâ&#x20AC;&#x2122;t matter it if itâ&#x20AC;&#x2122;s two in the morning or two in the afternoon. There is a full crew on duty steering these wells, which most companies do.â&#x20AC;?

Neset is confident that despite low oil prices that have led to an industry slowdown, the Bakken and other untapped rock formations in the Williston Basin continue to offer enormous energy potential. â&#x20AC;&#x153;The hardest part of any oil field is finding it,â&#x20AC;? she states. â&#x20AC;&#x153;Weâ&#x20AC;&#x2122;ve found the Bakken. Weâ&#x20AC;&#x2122;ve found the Three Forks. Itâ&#x20AC;&#x2122;s all the Bakken oil system. Now itâ&#x20AC;&#x2122;s a matter of increasing the percent of recovery because weâ&#x20AC;&#x2122;re very low on that. Weâ&#x20AC;&#x2122;re only 7 to 8 percent of the oil in place being recovered. Weâ&#x20AC;&#x2122;d like to get that up to 12 percent, 18 percent or maybe 20 percent, but that will take a lot of work.â&#x20AC;?

Neset's Backstory

How Nesetâ&#x20AC;&#x201D;who grew up with eight brothers in New Jersey


and graduated from Brown University in Rhode Islandâ&#x20AC;&#x201D;ended up in western North Dakota is a story that Hollywood couldnâ&#x20AC;&#x2122;t make up. She started her college career as a math major, but became interested in geology. â&#x20AC;&#x153;I went from pure math and all these numbers and all this dry complicated stuff to going on a field trip with a group and a dynamic geology instructor. And I think, â&#x20AC;&#x2DC;Wait a second. Youâ&#x20AC;&#x2122;re allowed to drink a beer on the bus on the way home? I donâ&#x20AC;&#x2122;t have to go back to the science library and bury myself to study imaginary numbers?â&#x20AC;&#x2122; My decision was made. I fell in love with geology.â&#x20AC;? That led to a job with Core Laboratories where she was trained as a mud logger. â&#x20AC;&#x153;When I took the job, I really did not know what a mud

logger was, but it sure sounded neat to me,â&#x20AC;? she smiles. The job took her from east Texas to Wyoming and then to the well site near Bismarck where she first met Roy. When she moved to Tioga to work on a well there, Roy looked her up and the two were married. The oil boom of the '80s helped their consulting business take off, but it didnâ&#x20AC;&#x2122;t last. â&#x20AC;&#x153;There were some pretty lean times here,â&#x20AC;? Neset says. â&#x20AC;&#x153;Farming was what kept us alive, and farming was also a struggle during the '80s and '90s. They were difficult days. We were one slip away from bankruptcy.â&#x20AC;? Between substitute teaching and working on the farm, the family survived, and gained an appreciation for the land. â&#x20AC;&#x153;I was very fortunate,â&#x20AC;? Ne-








FIELD PREP: Crystal Moorhead cleans and prepares the kits that Neset Consultingâ&#x20AC;&#x2122;s geologists and mud loggers take into the field when working on drilling rigs.

set says. My late husband Roy was really a very good teacher in the sense of sharing his farming knowledge. Our little boys and I learned how to farm along with him.â&#x20AC;? On a sunny spring day on the edge of the Tioga Municipal Airport, Neset points out that from here she can see the Neset family farm, the Hess gas processing plant and the edge of Tioga, a town in the heart of the Bakken surrounded on all sides by oil and gas activity that calls itself the Oil Capital of North Dakota. â&#x20AC;&#x153;I canâ&#x20AC;&#x2122;t in my wildest dreams think of myself anywhere else in the world,â&#x20AC;? Neset says. â&#x20AC;&#x153;I truly do say that this was a God-driven designed path because you couldnâ&#x20AC;&#x2122;t make this up. When I say I am the luckiest person in the world, I truly live that and believe it.â&#x20AC;? And while some might question whether the oil and gas industry has been good for Tioga and other towns in western North Dakota, thereâ&#x20AC;&#x2122;s no doubt in her mind that it has. Neset tells about Bree Hanson, the daughter of a Neset Consulting employee, who last year had to be rushed

to Mayo Clinic in Rochester, Minnesota, for a heart transplant in under four hours. â&#x20AC;&#x153;Without this big resource of the Bakken and the oil industry, you wouldnâ&#x20AC;&#x2122;t have planes like that here in Tioga, readily available to help Bree,â&#x20AC;? she notes. To Neset, itâ&#x20AC;&#x2122;s about finding the right balance between respecting the land and using natural resources to improve the quality of life. â&#x20AC;&#x153;I think we have the responsibility to give back to our communities and share what weâ&#x20AC;&#x2122;ve learned so people can understand that there is a balance in this world and in this life,â&#x20AC;? she says. â&#x20AC;&#x153;You do have to balance the good of this industry with doing it correctly. That is the balance that we have to strive to maintain.â&#x20AC;? Author: Patrick C. Miller Staff Writer, The Bakken magazine 701-738-4923















WBPC 2015 HIGHPOINTS: OIL PRICES, BASIN UPDATES The Bakkenâ&#x20AC;&#x2122;s main event delivers oil price predictions and region-specific reviews By Luke Geiver

The Williston Basin Petroleum Conference has reflected the activity level of the basin since its inception 23 years ago. Once

a small gathering of petroleum engineers and geologists, the WBPC has become a massive yearly event bringing together energy service firms, exploration and production companies, logistics providers and every other business entity linked to oil and gas production. What happens in the Bakken throughout the year can be felt at the WBPC in early spring. In the recent past, major presentations had been centered on production-increase plans and Basin-wide expansion. This year the mood of the show was heavily influenced by low oil prices and keynote talks focused on commodity prices. Attendance and exhibitor numbers were still significant. Conversations on the show floor, at the tables of the main general session or in the refreshment break lines were all connected to the reality of the low oil price environment and its direct connection to a slowdown in activity. And, despite the ever-present low price cloud lingering over the event, conversations and presentations that started on low oil prices ended with talk of the impending rebound.

INDUSTRY MAIN EVENT: The Williston Basin Petroleum Conference alternates show locations between Bismarck, North Dakota and Regina, Saskatchewan. The mood at the 23rd version of the WBPC was different from the previous year, when oil was trading much higher. PHOTO: THE BAKKEN MAGAZINE







Major Oil Corrections Since 1980 Date Event 1986 Saudi Market Share War 1988 Oil Glut 1991 Global Recession/End of Gulf War 1998 Asian Crisis 2001 Global Recession 2008 Great Recession Average Current

% Change in Oil Price -67.2% -43.7% -57.2% -59.6% -53.1% -78.4% -59.9% -57.2%

Length of Oil Price Decline 82 295 90 484 290 119 227

% Increase in Oil Price 1 Year Post - Low 79.0% 58.4% 5.4% 134.5% 46.2% 134.8% 76.4%



(in trading days)


History of Oil Declines, Rebounds

Tony Cadrin, president of the Canadian Society of Petroleum Geologists, knows oil price declines in the Williston Basin. Cadrin spoke at the event on his experiences during each of the previous six oil price decline situations dating back to 1986. “Our industry has survived each and every one [of the cycles] and come out stronger through optimization and innovation,” he said. To prove his point, Cadrin documented each price decline since 1986 and how the price, and industry, rebounded. According to Cadrin, each price decline situation marked an industry milestone of innovation that helped oil and gas production excel. In 1986, the Saudi market share war caused oil prices to collapse. After the Saudis realized oil produced from outside their region was hitting the market and decreasing their market share, the decision was made to decrease the price per barrel sold to customers around the 44

world. The Saudi-induced price drop eliminated some producers, but it also emphasized the need for non-Saudi producers to deploy new technology. “What came out of this price shock was that the industry started to improve technology. They developed a much more reliable method of directional drilling,” he said. Two years later, global oil supply had exceeded demand and another price decline had happened. Roughly one year after the 1988 price drop situation, the industry had figured out how to drill near horizontally onshore after using the method offshore. The Gulf War in 1991 was the cause of the next price drop and the resulting technology innovation still used today was 3D seismic imaging. In 1998, a lack of oil buyers in the Asian market caused another price drop, but forced geologists to use better imaging to prove where hydrocarbons existed below the surface. The global recession of 2001 pushed prices down, but


‘Every time we have to pause and think and we aren’t running crazy, we come up with some better ideas’ Tony Cadrin, president of the Canadian Society of Petroleum Geologists

upon the price rebound, companies making $10 per barrel quickly saw $100 per barrel profits without any process changes. The fifth downturn cycle also marked the true industry realization of horizontal drilling. “We were really staying in the zone reliably and accurately,” Cadrin said. Doing so allowed companies to open up zones featuring rock permeability that didn’t previously work with vertical drilling. The next global recession, in 2008, marked the sixth downturn cycle and the breakout of multi-stage horizontal fracturing, the process responsible for the unprecedented growth in U.S. unconventional oil and gas production. The current oil price de-

cline situation is much like Cadrin’s first. As they did in 1986, the Saudi’s have adopted a strategy to retain market share in the face of pressure from other producers around the world, particularly in the U.S. When the current low oil price situation ends, the industry will better understand enhanced oil recovery methods, Cadrin said. For now, oil prices appear to have hit bottom, and within 6 to 12 months, prices should recover. The longer it takes for oil to find its bottom, the higher the price rebound will be. Patricia Mohr, vice president of economics and commodity markets for Scotiabank, shared Cadrin’s view on oil price bottoms. Mohr provided a glimpse into future commodity


THREE FORKS NAME CHANGE: Over the past five years, the Three Forks formation has been the target of roughly 3,000 wells. Geologists are now considering a name change of the formations discrete zones to ensure zone detail accuracy and eliminate confusion between drillers and geologists. PHOTO: THE BAKKEN MAGAZINE


Peter Budgell of the Saskatchewan National Energy Board says his team is not about picking winning oil plays, it only tries to calculate how much oil is in the ground. The NEB team recently released an assessment of the unconventional petroleum resources in the Bakken. At the WBPC, Budgell explained the findings. In Saskatchewan, there is roughly 835 million to 2.2 billion barrels of marketable oil in place—oil that can make it to market. The highest concentrations of oil in place reside in the Viewfield

formation and North Dakota/Saskatchewan border areas. “The Bakken is likely one of the largest accumulations of tight oil in Canada,” Budgell says. To assess the oil in place, the NEB team used a distribution of distributions approach, meaning the team relied on in-place volumes calculated with standard volumetric equations where the variables were determined from map grids of geological data. The findings show that 1.2 billion barrels of future production is still left in the Saskatchewan portion of the Bakken.

Ultimate potential for Bakken unconventional oil in Saskatchewan Oil - million m3 (million barrels)

Low 8,420 (52,984)

In-Place Expected 11,279 (70,970)

High 14,627 (92,033)

Low 132 (835)

Marketable Expected 223 (1,401)

High 345 (2,173)


Expected ultimate potential for unconventional oil resources by assessment zone. Oil - million m3 (million barrels) Viewfield Border Continuous Transition









838 (5,429) 414 (2,604) 7,144 (44,951)

1,144 (7,200) 573 (3,606) 9,562 (60,164)

1,487 (9,359) 750 (4,717) 12,390 (77,957)

43 (273) 22 (139) 67 (423)

74 (464) 38 (240) 111 (697)

114 (717) 61 (385) 170 (1,071)





Three Forks terms used by geologists

ND Strat Column MS-91

Dymonceaux 1984 - - Bo jer 2011

#19918—CRI—Charlo e 1-22H

Con nental Resources / Industry

Christopher 1961 - - LeFever, Nordeng , 2008, GI-65

Petroleum Geologists are contemplating a name change for the Three Forks formation located within the Williston Basin. The formation has become a staple target for exploration and production firms looking to increase well counts in geologic zones outside of the Bakken. Steve Nordeng, distinguished professor at the Harold Hamm School of Geology and Geological Engineering at the University of North Dakota, explained the reasoning behind the possible name change in his presentation, “A Plea For A Standardized Three Forks Stratigraphy.” Although the Three Forks was originally worked on and described in 1961, Nordeng and Julie LeFever, geologist with the North Dakota Geological Survey, created a new stratigraphy of the formation in 2010. Since that time, there has been a great deal of confusion between directional drillers and petroleum geologists, according to Nordeng. “There is a mismatch in nomenclature,” Nordeng says.

To describe the Three Forks formation, Nordeng and LeFever dissected the formation into six units, with the top of the formation labeled as six, following in descending order. Others, however, have referred to the Three Forks as having three benches, the top portion of the formation known as the first bench, following in ascending order. Issues arise when drillers claim they are drilling into the first unit and they are actually referring to the sixth, Nordeng says. “Is the Three Forks sufficiently important enough to warrant formal designation of beds and or members?” Nordeng asks. In the past five years, the Three Forks formation has produced 30 million barrels of oil from 2,919 wells. During the current period of relaxed drilling activity, this may be a good time to change the name of the Three Forks formation’s discrete zones so that detail in each zone is captured and drillers and geologists can avoid terminology confusion, Nordeng says. Formal/Informal named units (to be named ?)




Middle Bakken Lower

Three Forks terms used by drillers







Upper TF


Middle TF

U-5 U-4



Name? Three Forks


B-3 Name?



Lower TF






prices, including the perspective that oil prices have officially hit bottom. In 2015, West Texas Intermediate will average $58 per barrel, she believes. Mohr is in charge of providing price forecasts for Scotiabank along with leading a team that tracks commodity prices. By the end of the year, prices should begin to average $65 per barrel, a number she said could represent the price point when major activity could ramp back up in the U.S. At $65/b, drilled wells yet to be completed could undergo a status change. “I think at $65 crude, prices will be high enough to encourage further development and reramp activity in some of the shales,” she said. Although the supply and demand curves for oil consumption in the world are fairly well-defined and should not undergo a massive shift, Mohr did point to several factors that could positively impact crude prices. The U.S. is expected to record a massive spring and summer driving season. The expectation also comes at a time when vehicle manufacturing in the U.S. will break its previous record set in 2000. Consumers in Europe are also increasing their driving and even China, where motor bikes are popular, numbers indicate that gasoline powered vehicles are in greater demand than ever. The positive signs, however, will not push oil prices past the $70 range until 2017, Mohr said. Global economic activity in 2015 should be 3.2 percent, a rate high enough to sustain the current global economy, but not enough to change the global oil market.

REBOUND TRAFFIC: At $65 per barrel, energy and commodity analysts believe many shale-focused producers will start to ramp-up activity. PHOTO: THE BAKKEN MAGAZINE

Basin-Wide Updates

Explaining the Bakken can no longer be done during a short elevator ride, according to Alison Ritter, public information director for the North Dakota Department of Mineral Resources. Ritter took the place of Lynn Helms, director of the DMR, to explain the current state of the North Dakota portion of the Bakken, with Helms unable to leave Bismarck, N.D., during the final days of the legislative session. Today, inquiries to Ritter

include questions on oil prices, policy changes and legislative updates. The DMR has recently added to its informational offerings by tracking drilled but uncompleted wells because DUCs are now a popular topic of interest, she said. In North Dakota, there are currently 900 wells drilled but uncompleted. The DUC term is not unique just to the Bakken, however, as many wells in the Eagle Ford and Permian are also under that label. In the North Dakota por-

tion of the Bakken, wells must be economically producing one year after total depth on a well was reached, according to state law. But, operators do have the option of putting an uncompleted well that has surpassed the one-year timeline into a temporarily abandoned status. The status requires the operators to maintain and continuously test the wells. Until prices recover, operators will not want to bring wells online and forego the high production levels that occur early in the well’s life.




INDUSTRY SCENE: The collective mood of the expo hall floor was one of anticipation. Most exhibitors are planning for an oil price rebound. PHOTO: THE BAKKEN MAGAZINE


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When oil prices do recover, it could take roughly 10 months for the rigs that have left the state to move back into operation. But, despite the current rig count, North Dakotaâ&#x20AC;&#x2122;s oil production should remain above 1 million barrels of oil per day in 2015. Roughly 2,400 wells will be drilled this year. For Manitoba in 2014, 464 wells were drilled by 28 companies. Of those wells, 61 were drilled into the Bakken formation that lies within Manitoba. Keith Lowdon from the Manitoba Mineral Resources, said that during the past year, the provinceâ&#x20AC;&#x2122;s sentiment on the Williston Basin has waned after being very optimistic. This year, roughly $700 million will be spent on oil and gas expenditures to drilling and complete 280 wells for approximately 47,000 barrels of oil production per day. Drilling could be down by 25 percent compared to the previous year. In Saskatchewan, 2,700 wells will be drilled in 2015, according to Melinda Yurkowski, senior research geologist for the Saskatchewan Ministry of the Economy. The southeastern portion of


the province, which includes the Bakken and Torquay formations of the Williston Basin, will record 800 to 900 drilled and completed wells. Of the 575 wells drilled in the province this year, 200 have been in the Williston Basin. Like all areas of the Bakken, drilling activity in the Saskatchewan province has been down. Through the first three months of this year, 575 wells have been drilled, compared to 970 for the same period last year. Although the Bakken and Three Forks (Torquay) plays will continue to receive attention and produce at high levels in 2015, Yurkowski believes more activity is shifting to the Viking play on the western border. But, in the Torquay, there are two areas receiving significant attention that

she said she will be monitoring over the next year. In the Ryerson, on the eastern edge of the province, the lower Bakken is missing and the Torquay sits right under the middle Bakken, making the play an attractive, shallower formation to target. In the Flatlake area, the lower Bakken formation is present and separated from the Torquay, and is showing a very noticeable uptick in activity. Author: Luke Geiver Editor, The Bakken magazine 701-738-4944

COMMODITY EXPERT: Patricia Mohr advises Toronto-based Scotiabank on commodity trends from Canada to China. PHOTO: THE BAKKEN MAGAZINE













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ROCK drill site



MAT drill site


Disadvantages - Damaging native farm land - Loss work time due to unsafe work surface - Delays in drilling - Unable to access due to bad weather - Wasting unnecessary amounts of rock - Unnecessary extra cost - High reclamation expense



Advantages - No reclamation cost - Reduce the environmental impact - Reduce the amount of rock on native farm lands - Minimize unnecessary accidents - Mats provide a safe and stable work surface - 24/7 all-weather access with no down time - Potential to drill one to two more additional wells per year - Reduce the amount of truck traffic on roads - No additional cost - Protect existing flowlines


The Bakken Magazine - May 2015  

Hydraulic Fracturing, Williston Basin Petroleum Conference Review

The Bakken Magazine - May 2015  

Hydraulic Fracturing, Williston Basin Petroleum Conference Review